Process for treating hydrocarbon oil feed stream using gasification unit, dehydrogenation unit, steam-enhanced catalytic cracking unit and aromatics compounding unit

Abstract

An integrated process for upgrading a hydrocarbon oil feed stream includes subjecting a hydrocarbon oil stream to solvent deasphalting; treating the heavy residual hydrocarbons in a gasification unit to form a syngas and a gasification residue; hydrotreating the deasphalted oil stream to form a C3-C4 hydrocarbon stream, a light C5 + hydrocarbon stream, and a heavy C5 + hydrocarbon stream; subjecting the C3-C4 hydrocarbon stream to dehydrogenation to form propylene and butene; subjecting the light C5 + hydrocarbon stream to steam enhanced catalytic cracking; subjecting the heavy C5 + hydrocarbon stream to steam enhanced catalytic cracking; passing at least a portion of the light steam enhanced catalytic cracking stream, the heavy steam enhanced catalytic cracking stream, or both to a product separator to produce an olefin product stream, a naphtha product stream, and a BTX product stream; and treating the naphtha product stream in the aromatics compounding unit to produce benzene and xylenes.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to U.S. Non-Provisional Application No. 17 / 866,035, filed on July 15, 2022, which is incorporated herein by reference in its entirety. Technical Field

[0003] Embodiments of the present disclosure relate generally to refining and upgrading hydrocarbon oils, and particularly to integrated processes and systems for upgrading hydrocarbon oil streams, including heavy hydrocarbon residues. Background Art

[0004] Olefins and aromatic compounds (such as ethylene, propylene, butylene, butadiene, benzene, toluene and xylene) are basic intermediates for many petrochemical industries. These olefins and aromatic compounds are usually obtained by thermal cracking (or steam pyrolysis) of petroleum gas and distillates (such as naphtha, kerosene or gas oil). These compounds are also produced by the refinery fluid catalytic cracking (FCC) process, in which standard heavy feedstocks (such as gas oil or residual oil) are converted. Typical FCC feedstocks range from hydrocracking bottom materials to heavy feed fractions, such as vacuum gas oil and atmospheric residue. However, these feedstocks are limited. Currently, another source of propylene production is refinery propylene from FCC units. With the continuous growth of demand, FCC unit owners are increasingly looking to the petrochemical market to increase their profits by taking advantage of economic opportunities emerging in the propylene market.

[0005] The growing global demand for light olefins remains a major challenge for many integrated refineries. In particular, the production of some valuable light olefins such as ethylene, propylene and butenes has attracted increasing attention, as pure olefin streams are considered as building blocks for polymer synthesis. The production of light olefins depends on several process variables, such as feed type, operating conditions and catalyst type. Summary of the invention

[0006] Although there are a number of options for producing higher yields of propylene and other light olefins, there is still intensive research activity in this area. It would be desirable to produce light olefins and / or benzene, toluene, and xylenes, collectively referred to as "BTX," directly from a crude oil source. However, such processes can be problematic because crude oils often contain heavy residual hydrocarbons and other impurities, which can interfere with refining processes, such as during hydrocracking, steam cracking, and fluid catalytic cracking.

[0007] For example, these heavy residual hydrocarbons (such as asphaltenes) can affect previous processes by producing a large amount of petroleum coke on the catalyst used in the refining process. This accumulation of coke can deactivate the catalyst used, resulting in an increase in the cost of recovering or replacing the deactivated catalyst, or a reduction in light olefin / BTX conversion. Impurities can also have a negative impact on the refining process by reducing its efficiency. The negative impact of nitrogen as an impurity in refining processes is well known, contributing to various problems, such as but not limited to colloid formation, catalyst inhibition and deactivation, acid-base pair-related corrosion, metal complexation or its combination.

[0008] Therefore, it may be desirable to first treat the crude oil stream to upgrade the heavy residual hydrocarbons and remove impurities and heavy residual hydrocarbons before refining the crude oil stream to avoid these negative effects.

[0009] An integrated method and system for producing light olefins (e.g., C2-C4 olefins) and / or BTX from crude oil is described herein while providing the above benefits. Heavy hydrocarbon residues (e.g., asphaltenes) can be processed in a solvent deasphalting unit and a gasification unit to produce a deasphalted oil stream, syngas, and a gasification residue. The deasphalted oil stream can be further upgraded to light olefins and BTX. These crude oil fractions as deasphalted oil streams can be refined in a hydroprocessing unit and separated into at least four fractions, which are processed separately. Then, C 5+ The hydrocarbon fraction can be processed in a steam enhanced catalytic cracking unit to produce light olefins, naphtha and BTX. The naphtha can then be processed in an aromatics complex to produce mainly benzene and xylene as BTX. In this way, the entire crude oil is used to produce at least synthesis gas, olefins, BTX, gasification residues and petroleum coke.

[0010] According to one embodiment of the present invention, an integrated method for upgrading a hydrocarbon oil feed stream comprises: subjecting the hydrocarbon oil stream to solvent deasphalting to form at least a deasphalted oil stream and heavy residual hydrocarbons, wherein the heavy residual hydrocarbons contain at least asphaltenes; treating the heavy residual hydrocarbons in a gasification unit to produce synthesis gas and a gasification residue; and hydrotreating the deasphalted oil stream to form a C3-C4 hydrocarbon stream, a light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon stream; dehydrogenating the C3-C4 hydrocarbon stream to form propylene and butene; 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form a light steam enhanced catalytic cracking product comprising olefins, BTX, naphtha or a combination thereof; the heavy C 5+The invention relates to a process for producing a hydrocarbon stream by steam enhanced catalytic cracking to form a heavy steam enhanced catalytic cracking product comprising olefins, BTX, naphtha or a combination thereof; transferring at least a portion of the light steam enhanced catalytic cracking stream, the heavy steam enhanced catalytic cracking stream or both to a product separator to produce an olefin product stream, a naphtha product stream and a BTX product stream; and treating the naphtha product stream in the aromatics complex to produce benzene and xylenes.

[0011] According to another embodiment of the present invention, an integrated system for converting a hydrocarbon oil feed stream comprises: a solvent deasphalting unit, the solvent deasphalting unit separating the hydrocarbon oil stream into at least a deasphalted oil stream and heavy residual hydrocarbons, the heavy residual hydrocarbons comprising at least asphaltenes; a gasification unit fluidly connected to the solvent deasphalting unit and treating the heavy residual hydrocarbons to form synthesis gas and a gasification residue; a hydroprocessing unit fluidly connected to the solvent deasphalting unit and hydroprocessing at least the deasphalted oil stream to form a C3-C4 hydrocarbon stream, a light C 5+ Hydrocarbon streams and heavy C 5+ a dehydrogenation unit, the dehydrogenation unit being fluidly connected to the hydroprocessing unit and configured to dehydrogenate the C3-C4 hydrocarbon stream to form propylene and butenes; a first steam-enhanced catalytic cracking unit, the first steam-enhanced catalytic cracking unit being fluidly connected to the hydroprocessing unit, for at least a portion of the light C 5+ The hydrocarbon fraction is cracked to form a light steam enhanced catalytic cracking product; a second steam enhanced catalytic cracking unit, the second steam enhanced catalytic cracking unit is fluidly connected to the hydrotreating unit to treat at least a portion of the heavy C 5+ The hydrocarbon fraction is cracked to form a heavy steam enhanced catalytic cracking product; a product separator, which is fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit to produce an olefin product stream, a naphtha product stream and a BTX product stream; and an aromatics complex unit, which is fluidly connected to the product separator and processes the naphtha product stream to produce benzene and xylene.

[0012] Additional features and advantages of the embodiments described herein will be set forth in the detailed description that follows, and in part will be apparent to those skilled in the art from that description, or may be learned by practicing the described embodiments, including the detailed description and claims provided below.

[0013] BRIEF DESCRIPTION OF THE DRAWINGS

[0014] The following detailed description of specific embodiments of the present disclosure may be best understood when read in conjunction with the following drawings, in which:

[0015] Figure 1 A method flow diagram is shown of an exemplary method according to embodiments described herein.

[0016] Figure 2 A method flow diagram is shown of an exemplary method according to embodiments described herein.

[0017] For the purpose of describing the simplified schematic diagram and the description of the related drawings, numerous valves, temperature sensors, electronic controllers, etc. that are available and well known to those of ordinary skill in the art of certain chemical processing operations are not included. Further, accompanying components that are typically included in typical chemical processing operations, such as air supply devices, catalyst feed hoppers, and flue gas treatment systems, are not described. Accompanying components in the hydroprocessing unit (such as bleed streams, spent catalyst discharge subsystems, and catalyst replacement subsystems) are also not shown. It should be understood that these components are within the spirit and scope of the disclosed embodiments. However, operating components such as those described in the present disclosure can be added to the embodiments described in the present disclosure.

[0018] It should be further noted that the arrows in the accompanying drawings refer to process streams. However, arrows may equivalently refer to a delivery line that can be used to transport process streams between two or more system components. In addition, the arrows connected to the system components define the inlet or outlet in each given system component. The arrow direction generally corresponds to the main direction of movement of the material of the stream contained in the physical delivery line represented by the arrow. In addition, arrows that do not connect two or more system components represent the product stream of the system leaving the description or the system inlet stream of the system entering the description. The product stream can be further processed in the accompanying chemical processing system, or it can be commercialized as an end product. The system inlet stream can be a stream transferred from the accompanying chemical processing system, or it can be an unprocessed raw material stream. Some arrows may represent a recycle stream, which is an effluent stream of the system component that is recycled back to the system. However, it should be understood that in some embodiments, any recycle stream represented can be replaced by the system inlet stream of the same material, and a part of the recycle stream can leave the system as a product.

[0019] Additionally, arrows in the figures may schematically depict process steps that convey streams from one system component to another system component. For example, an arrow pointing from one system component to another system component may represent "transferring" a system component effluent to another system component, which may include "leaving" or "removing" the contents of a process stream from one system component and "introducing" the contents of a product stream to another system component.

[0020] It should be understood that, depending on the embodiment presented in the relevant figure, an arrow between two system components may indicate that the stream is not processed between the two system components. In other embodiments, the streams represented by the arrows may have substantially the same composition throughout their transport between the two system components. In addition, it should be understood that, in embodiments, the arrows may indicate that at least 75% by weight, at least 90% by weight, at least 95% by weight, at least 99% by weight, at least 99.9% by weight, or even 100% by weight of the stream is transported between the system components. Therefore, in some embodiments, less than all of the streams represented by the arrows may be transported between the system components, for example, if there is a slipstream.

[0021] It should be understood that two or more process streams are "mixed" or "combined" when two or more lines in the schematic flow diagram of the related figure intersect. Mixing or combining can also include mixing by introducing two streams directly into similar reactors, separation units or other system components. For example, it should be understood that when two streams are described as being combined directly before entering a separation unit or reactor, in embodiments, the streams can be equally introduced into a separation unit or introduced into a reactor and mixed in the reactor. Alternatively, when two streams are depicted as entering a system component independently, in embodiments, they can be mixed together before entering the system component.

[0022] Reference will now be made in more detail to various embodiments, some of which are illustrated in the accompanying drawings. Whenever possible, the same reference numerals will be used throughout the drawings to refer to the same or like parts. DETAILED DESCRIPTION

[0023] Embodiments of the present disclosure are directed to integrated methods and systems for producing light olefins (eg, C2-C4 olefins) and / or BTX from crude oil while providing the benefits described above.

[0024] As used herein, "asphaltene" generally refers to the heaviest and most polar compounds naturally occurring in crude oil. Asphaltenes are a mixture of high molecular weight polycyclic aromatic hydrocarbons and heterocyclic compounds, primarily containing carbon, hydrogen, nitrogen, oxygen, and sulfur, as well as trace amounts of vanadium and nickel. In asphaltenes, the atomic ratio of hydrogen to carbon is about 1.2:1.0. Asphaltenes are generally insoluble in n-pentane or n-heptane, but soluble in toluene, and are typically the sticky, black, highly viscous residue of the distillation process.

[0025] As used herein, "catalyst" refers to any substance that increases the rate of a particular chemical reaction. The catalysts described in the present disclosure can be used to promote various reactions, such as, but not limited to, cracking (including cracking of aromatic compounds), demetallization, desulfurization, and denitrogenation. As used herein, "cracking" generally refers to a chemical reaction in which a carbon-carbon bond is broken. For example, a molecule having a carbon-carbon bond is broken into more than one molecule by breaking one or more carbon-carbon bonds, or a compound including a cyclic portion (such as cycloalkanes, cycloalkanes, naphthalene, aromatic compounds, etc.) is converted into a compound that does not include a cyclic portion or contains less cyclic portions than before cracking.

[0026] As used herein, "catalytic reforming" refers to a conversion process in the petroleum refining and petrochemical industries. The reforming process typically catalytically converts low-octane naphtha distilled from crude oil into a higher-octane reformate containing aromatic compounds with a large amount of BTX. Generally, four major types of reactions occur in the reforming process: (1) dehydrogenation of cycloalkanes to aromatic compounds; (2) dehydrocyclization of paraffins to aromatic compounds; (3) isomerization; and (4) hydrocracking.

[0027] As used herein, the term "crude oil" is understood to mean a mixture of petroleum liquids, gases, or combinations of liquids and gases, which include some impurities, such as sulfur compounds, nitrogen compounds, and metallic compounds that have not undergone significant separation or reaction processes. Crude oil is different from crude oil fractions. As used herein, crude oil can be a crude oil that has been minimally treated to provide a hydrocarbon oil feedstock having a total metal (nickel+vanadium) content of less than 5 parts by weight per million parts by weight (ppmw) and a Conradson carbon residue of less than 5 weight %. This minimally treated material can be considered as crude oil as described herein.

[0028] As used herein, "distillate" refers to oils having a boiling point between 204°C and 343°C. 5+ A fraction of crude oil containing hydrocarbons. Distillates may also consist primarily of diesel and kerosene.

[0029] It should be understood that "effluent" generally refers to the stream leaving a system component (such as a separation unit, reactor, or reaction zone) after a particular reaction or separation, and that the "effluent" generally has a different composition (at least proportionally) than the stream entering the separation unit, reactor, or reaction zone.

[0030] As used herein, "heavy cycle oil" refers to C 5+ As used herein, "light cycle oil" refers to a hydrocarbon crude oil fraction having a boiling point between 343°C and 426°C. 5+ The hydrocarbon fraction of crude oil.

[0031] As used herein, the terms "hourly space velocity," "gas hourly space velocity," and "liquid hourly space velocity" may collectively refer to the rate at which a feed stream travels through the processing units, reactors, and separators discussed herein. In addition, the hourly space velocity may also be inversely proportional to its residence time, i.e., the residence time may be expressed as the reciprocal of the hourly space velocity (one over the hourly space velocity). As used herein, "residence time" refers to the amount of time it takes for a feed stream to enter and then leave the processing units, reactors, and separators discussed herein.

[0032] As used herein, the term "naphtha" refers to crude oil mainly including C5 to C 11 As used herein, "light naphtha" is a fraction of naphtha that includes primarily C5 to C6 hydrocarbons. As used herein, the term "heavy naphtha" refers to a fraction of naphtha that includes primarily C7 to C 11 A fraction of naphtha, a hydrocarbon fraction.

[0033] As used herein, the term "steam / oil ratio" or "steam to oil ratio" or "steam to hydrocarbon oil ratio" or "steam to feed ratio" refers to a standard measure of the volumetric rate of steam circulating through a reactor relative to the volume of feed. The steam / oil ratio can be determined by comparing the flow volume of a steam stream to the flow volume of a hydrocarbon oil feed or the flow volume of a second steam stream to the flow volume of a hydrocarbon product stream.

[0034] As used herein, "reactor" refers to a container in which one or more chemical reactions can occur between one or more reactants, optionally in the presence of one or more catalysts. For example, the reactor may include a kettle or tubular reactor (configured to operate as a batch reactor), a continuous stirred tank reactor (CSTR), or a plug flow reactor. Exemplary reactors include packed bed reactors, such as fixed bed reactors and fluidized bed reactors. One or more "reaction zones" may be provided in the reactor. As used herein, "reaction zone" refers to an area in which a specific reaction occurs in the reactor. For example, a packed bed reactor having multiple catalyst beds may have multiple reaction zones, wherein each reaction zone is defined by the area of ​​each catalyst bed.

[0035] As used herein, a "separation unit" or "separator" refers to any separation device that at least partially separates one or more chemicals mixed in a process stream from each other. For example, a separation unit can selectively separate materials of different chemical species, phases, or specific sizes from each other to form one or more chemical fractions. Examples of separation units include, but are not limited to, distillation towers, flash tanks, separation drums, separation tanks, centrifuges, cyclone separators, filtration devices, collectors, scrubbers, expansion devices, membranes, solvent extraction devices, and the like. It should be understood that the separation methods described in the present 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 the present disclosure "at least partially" separate different chemical components from each other, and even if it is not explicitly stated, it should be understood that the separation may only include partial separation. As used herein, one or more chemical components can be "separated" from a process stream to form a new process stream. Typically, a process stream can enter a separation unit and be divided or separated into two or more process streams of desired components. In addition, in some separation processes, a "lower boiling point fraction" (sometimes referred to as a "light fraction" or "light fraction stream") and a "higher boiling point fraction" (sometimes referred to as a "heavy fraction", "heavy hydrocarbon fraction" or "heavy hydrocarbon fraction stream") may leave a separation unit, wherein, on average, the contents of the lower boiling point fraction stream have a lower boiling point than the higher boiling point fraction stream. Other streams may fall between the lower boiling point fraction and the higher boiling point fraction, such as an "intermediate boiling point fraction".

[0036] It is further understood that a stream can be named after a component of the stream, and the component used to name the stream can be a major component of the stream (e.g., including from 50 weight percent (wt%), from 70 wt%, from 90 wt%, from 95 wt%, from 99 wt%, from 99.5 wt%, or even from 99.9 wt% of the contents of the stream to 100 wt% of the contents of the stream). It is also understood that when a stream containing the component is disclosed as passing from the system component to another system component, the component of the stream is disclosed as passing from one system component to another system component. By way of non-limiting example, reference to a "C2-C4 hydrocarbon stream" passing from a first system component to a second system component should be understood to be equivalent to disclosing a "C2-C4 hydrocarbon stream" passing from a first system component to a second system component. 2- C4 hydrocarbons" are transferred from a first system component to a second system component, and so on.

[0037] First reference Figure 1 , shows an integrated system 100 for converting hydrocarbon oil feedstock. As used herein, "feedstock" may also be used to refer to a "feed stream". The integrated system 100 includes a solvent deasphalting unit 104, a gasification unit 106, a hydrotreating unit 108, a steam enhanced catalytic cracking unit 114, a product separator, and an aromatics complex 118. Although Figure 1It seems that only one steam enhanced catalytic cracking unit is shown, but it should be understood that 114 is intended to illustrate multiple steam enhanced catalytic cracking units, in particular, a first steam enhanced catalytic cracking unit and a second steam enhanced catalytic cracking unit, which together comprise (encompass) the steam enhanced catalytic cracking unit 114. The illustration of one steam enhanced catalytic cracking unit 114 is intended to simplify Figure 1 flow pattern.

[0038] Further, it should be understood that the use of "light" and "heavy" as identifiers for the steam enhanced catalytic cracking unit 114 is only for the purpose of referencing the feed streams that may enter the steam enhanced catalytic cracking unit 114. For example, a light steam enhanced catalytic cracking unit may be understood as a lighter hydrocarbon feed having a lower boiling point than the feed for a heavy steam enhanced catalytic cracking unit. Similarly, a heavy steam enhanced catalytic cracking unit may be understood as a heavier hydrocarbon feed having a higher boiling point than the feed for a light steam enhanced catalytic cracking unit.

[0039] Still refer to Figure 1 , the solvent deasphalting unit 104 can separate the hydrocarbon oil stream 2 into at least a deasphalted oil stream 12 and heavy residual hydrocarbons 10. The heavy residual hydrocarbons 10 can include at least asphaltenes in the form of asphalt. In an embodiment, the solvent deasphalting unit can include a solvent. The solvent can be a light paraffinic hydrocarbon, such as, but not limited to, n-propane, n-butane, n-pentane, n-hexane, n-heptane, or a combination thereof. The gasification unit 106 is fluidly connected to the solvent deasphalting unit 104 and processes the heavy residual hydrocarbons 10 to form a synthesis gas 16 and a gasification residue 14. In an embodiment, the heavy residual hydrocarbons 10 can further include non-hydrocarbon components and impurities. In this way, the solvent deasphalting unit 104 can remove asphaltenes, non-hydrocarbon components, impurities, or a combination thereof from the hydrocarbon oil stream 2 to form a deasphalted oil stream 10. For example, the solvent deasphalting unit 104 can remove nitrogen-containing compounds, sulfur-containing compounds, Conradson carbon residue (CCR), and metal compounds (such as nickel and vanadium). In embodiments, the removal of non-hydrocarbon components and impurities as just previously described may improve the efficiency of downstream processing units by reducing the coking deactivation rates of the various catalysts used therein.

[0040] In embodiments, solvent deasphalting unit 104 may be operated at a temperature of 40° C. to 100° C., 40° C. to 90° C., 40° C. to 70° C., 40° C. to 60° C., 60° C. to 100° C., 60° C. to 90° C., 60° C. to 70° C., 70° C. to 100° C., 70° C. to 90° C., or 90° C. to 100° C. Solvent deasphalting unit 104 may be operated at a pressure of 0.1 MPa to 0.4 MPa.

[0041] In an embodiment, treating the heavy residual hydrocarbons 10 in the gasification unit 106 may include exposing the heavy residual hydrocarbons to air at high temperature and pressure to convert the heavy residual hydrocarbons into synthesis gas 16 and gasification residue 14. In an embodiment, the gasification unit 106 may be operated at a temperature of less than or equal to 1100°C, less than or equal to 900°C, less than or equal to 600°C, or even less than or equal to 400°C. The gasification unit 106 may be operated at a temperature of 400°C to 1100°C, 400°C to 900°C, 400°C to 600°C, 600°C to 1100°C, 600°C to 900°C, or 900°C to 1100°C. The gasification unit 106 may be operated at a pressure of 0.1 MPa to 6.2 MPa. The gasification unit 106 may also be operated at a pressure of 1 MPa to 6.2 MPa. In embodiments, the gasification unit 106 may also operate in a low oxygen environment (e.g., less than 10 mol%, less than 5 mol%, less than 2.5 mol%, less than 1 mol%, less than 0.5 mol%, or even less than 0.1 mol% O2).

[0042] Still refer to Figure 1 In an embodiment, hydrocarbon oil stream 2 may include whole crude oil, crude oil fractions, or a combination thereof. Whole crude oil may include crude oil as described above. As used herein, "topped crude oil" is understood to mean a crude oil fraction having a boiling point of less than 160°C. Although the present specification and examples may specify hydrocarbon oil 2 as a feedstock stream, it should be understood that the description of Figure 1 The system 100 described in the embodiment can be applicable to the conversion of various crude oils that may be present in the hydrocarbon oil stream 2. The hydrocarbon oil stream 2 may also include one or more non-hydrocarbon components, such as one or more heavy metals, sulfur compounds, nitrogen compounds, inorganic components or other non-hydrocarbon compounds.

[0043] In embodiments, hydrocarbon oil stream 2 can be heavy crude oil, which includes crude oil with an American Petroleum Institute (API) gravity less than 35°, 34.5°, 34° or 33°. In these embodiments, the sulfur content of the crude oil can be greater than or equal to 1.5 weight % (wt.%), such as greater than or equal to 1.6 weight %, 1.7 weight %, 1.75 weight %, 1.8 weight %, 1.9 weight % or 2.0 weight %, based on the gross weight of the crude oil. As a non-limiting example, hydrocarbon oil stream 2 can be Arabian heavy crude oil, which has an API gravity of about 28° and a sulfur content of about 2.8 weight %. In embodiments, hydrocarbon oil stream 2 can be light crude oil, which includes crude oil with an American Petroleum Institute (API) gravity greater than 35°, 36°, 37° or 38°. In these embodiments, light crude oil can also be classified as acidic light crude oil, which includes crude oil with a sulfur content of less than 1.5 weight percent (wt%) based on the gross weight of crude oil, such as less than or equal to 1.4 wt%, 1.3 wt%, 1.2 wt%, 1.1 wt% or 1.0 wt%. As a non-limiting example, hydrocarbon oil stream 2 can be an Arab light crude oil, which has an API gravity of about 33° and a sulfur content of about 1.77 wt%. As another non-limiting example, hydrocarbon oil stream 2 can be an Arab ultra-light crude oil, which has an API gravity of about 39° and a sulfur content of about 1.1 wt%. In embodiments, hydrocarbon oil stream 2 can be a combination of crude oils, such as a combination of Arab light crude oil and Arab ultra-light crude oil. It should be understood that, as used herein, "hydrocarbon oil stream" can refer to crude oil that has not been previously treated, separated or otherwise refined. Table 1 below lists the performance of the Arab light crude oil that can be used for embodiments of this paper.

[0044] Table 1: Composition of Arabian Light Crude Oil

[0045] performance Arabian Light Crude Oil density 0.8537 Sulfur (ppmw) 1.94 Nitrogen (ppmw) 830 Nickel (ppmw) 3.1 Vanadium (ppmw) 10.2 Sodium (ppmw) 0.9 Conradson carbon residue (wt.%) 4.25

[0046] In embodiments, hydrocarbon oil stream 2 may have a density below 0.89 g / mL. In embodiments, hydrocarbon oil stream 2 may have a density of 0.75 g / mL to 0.92 g / mL, 0.75 g / mL to 0.89 g / mL, 0.75 g / mL to 0.87 g / mL, 0.75 g / mL to 0.84 g / mL, 0.84 g / mL to 0.92 g / mL, 0.84 g / mL to 0.89 g / mL, 0.84 g / mL to 0.87 g / mL, 0.87 g / mL to 0.92 g / mL, 0.87 g / mL to 0.89 g / mL, or 0.89 g / mL to 0.92 g / mL.

[0047] In an embodiment, the hydrocarbon oil stream 2 may have a hydrocarbon fraction having a boiling point greater than 300° C., measured by the total weight of the hydrocarbon oil stream 2, of 44.92 wt % to 66.0 wt %. The hydrocarbon oil stream may have a hydrocarbon fraction having a boiling point less than or equal to 300° C., measured by the total weight of the hydrocarbon oil stream 2, of 30.65 wt % to 55.08 wt %. The hydrocarbon oil stream 2 may also have a remaining non-hydrocarbon component.

[0048] In embodiments, the hydrocarbon oil stream 2 may have from 1 wt% to 20 wt%, from 1 wt% to 16 wt%, from 1 wt% to 14 wt%, from 1 wt% to 10 wt%, from 1 wt% to 8 wt%, from 1 wt% to 4 wt%, from 4 wt% to 20 wt%, from 4 wt% to 16 wt%, from 4 wt% to 14 wt%, from 4 wt% to 10 wt%, from 4 wt% to 8 wt%, from 8 wt% to 20 wt%, from 8 wt% to 16 wt%, from 8 wt% to 14 wt%, from 8 wt% to 10 wt%, from 10 wt% to 20 wt%, from 10 wt% to 16 wt%, from 10 wt% to 14 wt%, from 14 wt% to 20 wt%, from 14 wt% to 16 wt%, or from 16 wt% to 20 wt% of a hydrocarbon fraction boiling at greater than 540°C.

[0049] In an embodiment, the heavy residual hydrocarbons 10 may include C 5+ Hydrocarbons. As previously mentioned, the heavy residual hydrocarbons 10 may be an asphalt product that includes asphaltenes in part. The heavy residual hydrocarbons 10 may also be atmospheric residue, vacuum residue, or both. In an embodiment, the deasphalted oil stream 12 may include C1 to C2 hydrocarbons having a boiling point between -162°C and 650°C. 5+ Hydrocarbons.

[0050] In an embodiment, the synthesis gas 16 may include mainly hydrogen and carbon monoxide. However, the synthesis gas 16 may also include carbon dioxide. The gasification residue 14 may include residues such as char particles, ash, slag and tar. The tar can be used as a marine fuel or a furnace fuel in turn. The ash or slag may also be petroleum coke. As used herein, "petroleum coke" may be needle coke, sponge coke, honeycomb coke, shot coke or a combination thereof. Petroleum coke may be mainly composed of carbon and a smaller amount of non-hydrocarbon components. Petroleum coke may also be mainly composed of C with a boiling point greater than 650°C. 5+ Hydrocarbon composition.

[0051] As previously described, the gasification unit 106 can produce hydrogen as a product of the gasification reaction. In an embodiment, the gasification unit 106 can produce hydrogen and carbon monoxide, and the weight percentage ratio of hydrogen to carbon monoxide is 1:5 to 1:2. This can also include any weight percentage ratio between 1:5 and 1:2, such as, for example, 1:4, 1:3, 1:4.5, 1:3.5 or 1:2.5, and any combination of ratios therein. It is expected that if the hydrogen from the gasification unit 106 is sent to the hydroprocessing unit 108, the hydrogen produced by the gasification unit 106 can have the additional benefit of at least partially reducing the demand for external hydrogen sources for the hydroprocessing unit 108.

[0052] Still refer to Figure 1 The hydroprocessing unit 108 is fluidly connected to the solvent deasphalting unit 104 and hydroprocesses at least the deasphalted oil stream 12 to form light C 5+ The hydrocarbon stream 26 and the heavy C 5+ Hydrocarbon stream 28. In an embodiment, the hydrotreater 108 may also hydrotreat at least the deasphalted oil stream 12 to additionally form a C1 hydrocarbon stream 18 and a C2-C4 hydrocarbon stream 22. In an embodiment, the C1 hydrocarbon stream 18, the C2-C4 hydrocarbon stream 22, the light C 5+ The hydrocarbon stream 26 and the heavy C 5+ The hydrocarbon stream 28 may be collectively referred to herein as a hydroprocessed product stream. In other embodiments, the hydroprocessing unit may additionally form a C 9+ A heavy residual hydrocarbon stream which can be recycled back to the gasification unit to produce additional synthesis gas and a gasification residue.

[0053] In embodiments, the hydrotreater 108 may be operated at a temperature of 370°C to 500°C. The hydrotreater 108 may be operated at a temperature of 370°C to 500°C, 370°C to 480°C, 370°C to 450°C, 370°C to 420°C, 370°C to 400°C, 370°C to 390°C, 370°C to 380°C, 380°C to 500°C, 380°C to 480°C, 380°C to 450°C, 380°C to 420°C, 380°C to 400°C, 380°C to 390°C, 390°C to 500°C. The hydrotreater 108 may be operated at a temperature of 0° C., 390° C. to 480° C., 390° C. to 450° C., 390° C. to 420° C., 390° C. to 400° C., 400° C. to 500° C., 400° C. to 480° C., 400° C. to 450° C., 400° C. to 420° C., 420° C. to 500° C., 420° C. to 480° C., 420° C. to 450° C., 450° C. to 500° C., 450° C. to 480° C., or 480° C. to 500° C. The hydrotreater 108 may be operated at a pressure of 0.1 MPa to 0.2 MPa.

[0054] In embodiments, the hydrotreater 108 may have a 0.2 h -1 To 0.7h -1 The hydroprocessing unit 108 may have a liquid hourly space velocity of 0.2 h -1 To 0.7h -1 , 0.2h -1 To 0.6h -1 , 0.2h -1 Up to 0.5h -1 , 0.2h -1 To 0.4h -1 , 0.2h -1 To 0.3h -1 、0.3h -1 To 0.7h -1 、0.3h -1 To 0.6h -1 、0.3h -1 Up to 0.5h -1 、0.3h -1 To 0.4h -1 、0.4h -1 To 0.7h -1 、0.4h -1 To 0.6h -1 、0.4h -1 Up to 0.5h -1 , 0.5h -1 To 0.7h -1 , 0.5h -1 To 0.6h -1 or 0.6h -1 To 0.7h -1 Liquid hourly space velocity.

[0055] In an embodiment, the hydrotreating unit 108 may include a hydrotreating catalyst. The hydrotreating catalyst may include an active phase metal on a carrier. The active phase metal may include nickel, molybdenum, tungsten, platinum, palladium, rhodium, ruthenium, gold, or a combination thereof. In an embodiment, the carrier may include amorphous alumina, crystalline silica-alumina, alumina, silica, and a combination thereof. The hydrotreating catalyst may include MoNi on Al2O3, MoCo on Al2O3, MoS2, hematite, Fe3O4, nickel, NiO, TiO2, ZrO2, CeO2, or a combination thereof.

[0056] In embodiments, the C2-C4 hydrocarbon stream 22 may generally include C2-C4 hydrocarbons, including C2-C4 paraffins, C2-C4 olefins, C2-C4 alkynes, or combinations thereof. The C2-C4 hydrocarbon stream 22 may include ethane, propane, butane, ethylene, propylene, butene, acetylene, propyne, butyne, or combinations thereof. In embodiments, the light C 5+The hydrocarbon stream 26 may include a hydrocarbon stream having a T of less than 200°C. 95 The boiling point (i.e., the temperature at which more than 95% of the components in a hydrocarbon composition boil) is 5+ Hydrocarbons. Heavy C 5+ The hydrocarbon stream 28 may include hydrocarbons having a T5 boiling point (ie, the temperature at which less than 5% of the components in the hydrocarbon composition boil) greater than or equal to 200°C. 5+ Hydrocarbons. Therefore, light C 5+ The hydrocarbon stream 26 and the heavy C 5+ The temperature cut point between the hydrocarbon stream 28 may be 200°C. However, depending on the components in the hydrocarbon oil stream 2, the light C 5+ Hydrocarbon streams and heavy C 5+ The temperature split points between the hydrocarbon streams may also be greater or less than 200°C.

[0057] In an embodiment, the heavy C 5+ The hydrocarbon stream 28 may generally include a hydrocarbon stream having an API gravity of at least 8.0° and / or a hydrocarbon stream having an API gravity of at least 1000 kg / m3 (kg / m 3 ) is a residue of the standard liquid density.

[0058] As previously described, the steam enhanced catalytic cracking unit 114 includes a first steam enhanced catalytic cracking unit and a second steam enhanced catalytic cracking unit. The first steam enhanced catalytic cracking unit is fluidly connected to the hydroprocessing unit 108 and cracks at least a portion of the light C 5+ The second steam enhanced catalytic cracking unit is fluidly connected to the hydrotreater 108 and cracks at least a portion of the heavy C 5+ The hydrocarbon stream 28 is used to form a heavy steam enhanced catalytic cracking product 32. The first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit are connected in parallel to each other and are located downstream of the hydrotreating unit 108. In an embodiment, the steam enhanced catalytic cracking unit may also be fluidly connected to the deasphalting unit 104. In this configuration, the deasphalting unit 104 can send at least a portion of the deasphalted oil stream 10 to the steam enhanced catalytic cracking unit 114. In an embodiment, the light steam enhanced catalytic cracking product 30, the heavy steam enhanced catalytic cracking product 32, or both may include olefins, aromatic compounds, naphtha, or a combination thereof. The olefins may include ethylene, propylene, butene, or a combination thereof. In an embodiment, the olefins may additionally include gasoline.

[0059] In embodiments, it may be desirable to process the light C in the SEC unit 114 under different conditions. 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon stream to maximize the yield of the desired product. In a non-limiting example, light C 5+The hydrocarbon stream 26 may need to be heavier than C 5+ Longer residence time for hydrocarbon stream 28 to fully process and convert light C 5+ The light components of hydrocarbon stream 26. In addition, the heavy C 5+ The hydrocarbon stream 28 may require a shorter residence time to avoid heavy C 5+ The components of hydrocarbon stream 28 are excessively coked. However, if two SEC units are not available, the light C 5+ The hydrocarbon stream 26 and the heavy C 5+ The hydrocarbon stream 28 may be processed in a steam enhanced catalytic cracking unit under various conditions.

[0060] The first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit can also produce hydrocarbon products and product streams thereof with different distributions. For example, as shown in the examples herein, the first steam enhanced catalytic cracking unit can produce a larger proportion of olefins than naphtha series products (including naphtha and gasoline). In embodiments, the first steam enhanced catalytic cracking unit can produce a ratio of olefins to naphtha products of about 5:3 (olefins: naphtha) or about 11:6 (olefins: naphtha). The first steam enhanced catalytic cracking unit can also produce a ratio of olefins to naphtha products of 2:1, 3:1, 4:1, 5:1, 6:1 or 7:1 (olefins: naphtha).

[0061] Similarly, as shown in the examples herein, the second steam enhanced catalytic cracking unit may produce a greater proportion of naphtha and gasoline series products rather than olefins. In embodiments, the second steam enhanced catalytic cracking unit may produce a ratio of olefins to naphtha products of about 4:3 or about 7:5 (olefins: naphtha). The second steam enhanced catalytic cracking unit may also produce a ratio of olefins to naphtha products of 1.5:1, 1.3:1, 1.1:1, 1:1, 0.9:1 or 0.8:1 (olefins: naphtha).

[0062] The steam enhanced catalytic cracking unit 114 can be an upward or downward cracking unit. As used herein, an "upward" reactor or unit refers to a reactor or unit in which the feed enters from the bottom of the reactor and leaves from this type. As used herein, a "downward" reactor or unit refers to a reactor or unit in which the feed enters from the top of the reactor and leaves from the bottom. For an upward cracking unit, due to the back-mixing of the feed stream when it rises in the upward cracking unit, the expected residence time is generally longer than that of a downward cracking unit. On the contrary, for a downward cracking unit, due to the influence of gravity on the feed stream, the expected residence time is generally shorter than that of an upward cracking unit. Therefore, in an embodiment, the first steam enhanced catalytic cracking unit can be an upward cracking unit, and the second steam enhanced catalytic cracking unit can be a downward cracking unit to utilize the relative residence time of the two. However, any combination of various types of cracking units can be used herein, such as upward-upward, downward-downward, downward-upward, etc.

[0063] In embodiments, the steam enhanced catalytic cracking unit 114 can operate within a residence time of 0.5 seconds to 10 seconds. The steam enhanced catalytic cracking unit 114 can operate within a residence time of 0.1 seconds to 20 seconds, 0.1 seconds to 15 seconds, 0.1 seconds to 10 seconds, 0.1 seconds to 5 seconds, 0.1 seconds to 1 second, 0.1 to 0.5 seconds, 0.5 seconds to 20 seconds, 0.5 seconds to 15 seconds, 0.5 seconds to 10 seconds, 0.5 seconds to 5 seconds, 0.5 seconds to 1 second, 1 second to 20 seconds, 1 second to 15 seconds, 1 second to 10 seconds, 1 second to 5 seconds, 5 seconds to 20 seconds, 5 seconds to 15 seconds, 5 seconds to 10 seconds, 10 seconds to 20 seconds, 10 seconds to 15 seconds, or 15 seconds to 20 seconds. As previously described, the residence time of the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit can be different. In embodiments, the first steam enhanced catalytic cracking unit may have a residence time of 3 seconds to 10 seconds, or any narrower range therein. The second steam enhanced catalytic cracking unit may have a residence time of 1 second to 3 seconds, or any narrower range therein.

[0064] In an embodiment, the steam enhanced catalytic cracking unit 114 can be a fixed bed catalytic cracking reactor, which can include steam and a cracking catalyst disposed in a steam cracking catalyst zone. The steam enhanced catalytic cracking unit can include a porous filler, such as a silica carbide filler, located upstream of the steam cracking catalyst zone. The porous filler can ensure that the C 5+The steam enhanced catalytic cracking system 114 is used to process a large amount of steam as used in steam enhanced catalytic cracking.

[0065] In an embodiment, the cracking catalyst can be a nano zeolite cracking catalyst including nano zeolite particles. Various nano zeolites are suitable for the steam enhanced catalytic cracking reaction in the steam enhanced catalytic cracking reaction unit 114. The nano zeolite cracking catalyst can include structured zeolites, such as MFI, GIS or BEA structured zeolites. In an embodiment, the nano zeolite cracking catalyst can include nano ZSM-5 zeolite, nano BEA zeolite, nano USY zeolite and combinations thereof. In an embodiment, the nano zeolite cracking catalyst can be loaded with phosphorus and heavy metals (e.g., having a content greater than 5g / cm 3 The nano zeolite (such as nano ZSM-5 zeolite, nano β zeolite, nano USY or a combination thereof) may be in hydrogen form. In hydrogen form, the zeolite Acid sites (also called bridging OH-H groups) can form hydrogen bonds with other framework oxygen atoms in the zeolite framework.

[0066] In an embodiment, nano ZSM-5 zeolite, nano Beta zeolite, nano USY zeolite or a combination thereof may have a molar ratio of silica to alumina to provide sufficient acidity to the nano zeolite cracking catalyst for steam enhanced catalytic cracking reaction. The molar ratio of silica to alumina of nano ZSM-5 zeolite, nano Beta zeolite, nano USY zeolite or a combination thereof may be 10 to 200, 15 to 200, 20 to 200, 10 to 150, 15 to 150 or 20 to 150. The total acidity of the nano ZSM-5 zeolite, nano beta zeolite, nano USY zeolite or a combination thereof may be in the range of 0.2 mmol / g to 2.5 mmol / g, 0.3 mmol / g to 2.5 mmol / g, 0.4 mmol / g to 2.5 mmol / g, 0.5 mmol / g to 2.5 mmol / g, 0.2 mmol / g to 2.0 mmol / g, 0.3 mmol / g to 2.0 mmol / g, 0.4 mmol / g to 2.0 mmol / g or 0.5 mmol / g to 2.0 mmol / g. The nano ZSM-5 zeolite, nano beta zeolite, nano USY zeolite or a combination thereof may have an average crystal size of 50 nanometers (nm) to 600 nm, 60 nm to 600 nm, 70 nm to 600 nm, 80 nm to 600 nm, 50 nm to 580 nm or 50 nm to 550 nm.

[0067] The nano zeolite cracking catalyst may also include an alumina binder, which can be used to consolidate nanoparticles of nano ZSM-5 zeolite, nano beta zeolite, nano USY zeolite or a combination thereof to form a nano zeolite cracking catalyst. The nano zeolite cracking catalyst can be prepared by combining nano ZSM-5 zeolite, nano beta zeolite, nano USY zeolite or a combination thereof with an aluminum binder, and extruding the nano zeolite cracking catalyst to form a spherical or other catalyst shape. The nano zeolite cracking catalyst may contain 10 weight percent (wt.%) to 80 weight percent, 10 weight percent to 75 weight percent, 10 weight percent to 70 weight percent, 15 weight percent to 80 weight percent, 15 weight percent to 75 weight percent or 15 weight percent to 70 weight percent of an alumina binder based on the total weight of the nano zeolite cracking catalyst. The mesopore to micropore volume ratio of the nano zeolite cracking catalyst may be in the range of 0.5 to 1.5, 0.6 to 1.5, 0.7 to 1.5, 0.5 to 1.0, 0.6 to 1.0, or 0.7 to 1.0.

[0068] In embodiments, the steam in the steam enhanced catalytic cracking unit 114 can reduce the hydrocarbon partial pressure, which can have the dual effect of increasing the output of light olefins and / or BTX and reducing the formation of coke. Light olefins such as propylene and butene are mainly produced by the catalytic cracking reaction following the carbocation mechanism, and since these are intermediate products, they can carry out secondary reactions such as hydrogen transfer and aromatization (causing coke to form). Steam can improve the yield of light olefins by suppressing these secondary bimolecular reactions, and reduce the concentration of reactants and products, which is conducive to the selectivity towards light olefins. Steam can also suppress the secondary reaction that causes the formation of coke on the catalyst surface, which is conducive to the catalyst maintaining a high average activity. These factors can show that large steam and oil weight ratio can be conducive to the production of light olefins.

[0069] In an embodiment, as previously described, increasing the steam to feed ratio can increase the light olefin yield of the steam enhanced catalytic cracking unit. The flow rate (gas hourly space velocity) of the steam is proportional to the feed (light C 5+ Hydrocarbon stream 26 or heavy C 5+ The ratio of the flow rate (gas hourly space velocity) of the hydrocarbon stream 28) can be 0.1 to 1.1 times, 0.1 to 0.8 times, 0.1 to 0.5 times, 0.1 to 0.2 times, 0.2 to 1.1 times, 0.2 to 0.8 times, 0.2 to 0.5 times, 0.5 to 1.1 times or 0.5 to 0.8 times or 0.8 to 1.1 times (feed: steam) to improve the steam enhanced catalytic cracking process. In an embodiment, the ratio of steam to feed can be different for the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit. For example, the ratio of steam to feed for the second steam enhanced catalytic cracking unit can be 0.8 to 1.0 (feed: steam), while the ratio of steam to feed for the first steam enhanced catalytic cracking unit can be 0.2 to 0.8. In an embodiment, a higher ratio of steam to feed can be beneficial to heavy fractions because it is necessary to reduce the viscosity of the heavier crude oil fractions and atomize the heavy fractions.

[0070] In an embodiment, the steam may be heated to a temperature greater than or equal to 0.1 h. -1 , greater than or equal to 0.5h -1 , greater than or equal to 1h -1 , greater than or equal to 5h -1 , greater than or equal to 6h -1 , greater than or equal to 10h -1 or even greater than or equal to 15h -1 The steam can be injected into the steam enhanced catalytic cracking unit 114 at a gas hourly space velocity of less than or equal to 100h -1 , less than or equal to 75h -1 , less than or equal to 50h -1 , less than or equal to 30h-1 or less than or equal to 20h -1 The steam can be introduced into the steam enhanced catalytic cracking unit 114 at a gas hourly space velocity of 0.1 h -1 Until 100h -1 , 0.1h -1 Up to 75h -1 , 0.1h -1 Up to 50h -1 , 0.1h -1 Up to 30h -1 , 0.1h -1 Until 20h -1 , 1h -1 Until 100h -1 , 1h -1 Up to 75h -2 , 1h -1 Up to 50h -1 , 1h -1 Up to 30h -1 , 1h -1 Until 20h -1 , 5h -1 Until 100h -1 , 5h -1 Up to 75h -1 , 5h -1 Until 50h -1 , 5h -1 Up to 30h -1 , 5h -1 Until 20h -1 , 6h -1 Until 100h -1 , 6h -1 Up to 75h -1 , 6h -1 Up to 50h -1 , 6h -1 Up to 30h -1 , 6h -1 Until 20h -1 , 10h -1 Until 100h -1 , 10h -1 Up to 75h -1 , 10h -1 Up to 50h -1 , 10h -1 Up to 30h -1 , 10h -1 Until 20h -1 , 15h -1 Until 100h -1 , 15h -1 Up to 75h -1 , 15h -1 Up to 50h-1 , 15h -1 Up to 30h -1 or 15h -1 Until 20h -1 The gas hourly space velocity is introduced into the steam enhanced catalytic cracking unit 114.

[0071] In an embodiment, the feed (light C 5+ Hydrocarbon stream 26 or heavy C 5+ The hydrocarbon stream 28) is greater than or equal to 0.1 per hour (h -1 ) or greater than or equal to 0.25h -1 The feed can be injected into the steam enhanced catalytic cracking unit 114 at a gas hourly space velocity of less than or equal to 50h -1 , less than or equal to 25h -1 , less than or equal to 20h -1 , less than or equal to 14h -1 , less than or equal to 9h -1 , or less than or equal to 5h -1 The feed can be injected into the steam enhanced catalytic cracking unit 114 at a gas hourly space velocity of 0.1 h -1 Up to 50h -1 , 0.1h -1 Until 25h -1 , 0.1h -1 Until 20h -1 , 0.1h -1 Until 14h -1 , 0.1h -1 Until 9h -1 , 0.1h -1 Until 5h -1 , 0.1h -1 Up to 4h -1 , 0.25h -1 Up to 50h -1 , 0.25h -1 Until 25h -1 , 0.25h -1 Until 20h -1 , 0.25h -1 Until 14h -1 , 0.25h -1 Until 9h -1 , 0.25h -1 Until 5h -1 , 0.25h -1 Up to 4h -1 , 1h -1 Up to 50h -1 , 1h -1 Until 25h -1 , 1h -1 Until 20h-1 , 1h -1 Until 14h -1 , 1h -1 Until 9h -1 or 1h -1 Until 5h -1 The gas hourly space velocity is injected into the steam enhanced catalytic cracking unit 114.

[0072] In an embodiment, the hourly space velocity of a light steam enhanced catalytic cracking unit may be different than that of a heavy steam enhanced catalytic cracking unit. In one non-limiting example, the light C 5+ The hydrocarbon stream 26 may require a lower hourly space velocity to allow more time for the light C 5+ The hydrocarbon stream 26 is cracked into desired products. In another non-limiting example, heavy C 5+ The hydrocarbon stream 28 may require a greater hourly space velocity to prevent heavy C 5+ Overcracking of hydrocarbon stream 28 and preventing excessive formation of petroleum coke. In an embodiment, the hourly space velocity of the light steam enhanced catalytic cracking unit may be 0.1 h -1 Up to 1h -1 In the embodiment, the hourly space velocity of the heavy steam enhanced catalytic cracking unit can be 9h -1 Up to 40h -1 .

[0073] In embodiments, the steam enhanced catalytic cracking unit 114 may operate at a temperature greater than or equal to 525°C, greater than or equal to 550°C, or greater than or equal to 575°C. The steam enhanced catalytic cracking unit 114 may operate at a temperature less than or equal to 750°C, less than or equal to 675°C, less than or equal to 650°C, or even less than or equal to 625°C. The steam enhanced catalytic cracking unit 114 may operate at a temperature of 650°C to 750°C, or 675°C to 750°C. The steam enhanced catalytic cracking unit 114 may operate at a temperature of 525°C to 750°C, 525°C to 675°C, 525°C to 650°C, 525°C to 625°C, 550°C to 675°C, 550°C to 650°C, 550°C to 625°C, 575°C to 675°C, 575°C to 650°C, or 575°C to 625°C. The steam enhanced catalytic cracking unit 114 may operate at a pressure of 0.1 MPa to 0.2 MPa.

[0074] As previously mentioned, the steam enhanced catalytic cracking unit 114 can produce olefins, particularly light olefins, such as ethylene, propylene and butene. In an embodiment, the steam enhanced catalytic cracking unit can additionally produce gasoline as an olefin. In an embodiment, the ratio of the produced olefins (gasoline) to the light olefins can vary according to the operating temperature used in the steam enhanced catalytic cracking unit 114. For example, the operating temperature between 500°C and 650°C can mainly produce propylene and gasoline, more than ethylene. As the operating temperature increases, the ratio is further changed to mainly produce ethylene, more than propylene and gasoline. For example, the operating temperature between 650°C and 680°C can produce equal parts of ethylene and propylene and less gasoline. When the operating temperature exceeds 680°C, for example, from 680°C to 750°C, the reaction changes to mainly produce ethylene.

[0075] In embodiments, temperatures at the higher end of the operating range (>650°C) may be used to preferentially produce light olefins over heavier olefins, e.g., to produce ethylene and propylene over gasoline). Thus, this may cause gasoline to be a byproduct of the steam enhanced catalytic cracking reaction compared to the main product. Further temperature increases (>680°C) may minimize the amount of gasoline produced, producing primarily ethylene and propylene as byproducts. It is expected that the above changes may be related to the reactions in the steam enhanced catalytic cracking unit, which are transformed from being primarily catalytic cracking at lower temperatures (500°C to 650°C) to being primarily thermal cracking at the higher end operating temperatures (>680°C).

[0076] Still refer to Figure 1, the integrated system 100 includes a product separator 116. The product separator 116 is connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit 114 fluid, and produces one or more product streams. The product stream may include an olefin product stream 42, a BTX product stream 44, and a naphtha product stream 46. As described in further detail below, one or more product streams may also include a reformate stream 48 and an aromatics complex stream 50. The olefin product stream 42 may include olefins, such as light olefins including ethylene, butene, and propylene. The olefin product stream 42 may also include gasoline. The BTX product stream 44 may include aromatic compounds, such as benzene, toluene, xylene, or a combination thereof (also collectively referred to as "BTX"). Xylene may include o-xylene, m-xylene, and p-xylene. The naphtha product stream 46 may include naphtha, which includes light naphtha and heavy naphtha. The naphtha product stream 46 may also include cracked naphtha. In embodiments, product streams may also include fuel oil (also referred to as heavy oil, bunker fuel or heating oil), naphtha, tail gas products (C1-C4 hydrocarbons) or combinations thereof. Alternatively, fuel oil and tail gas products may be included as a part of one or more recycle streams. In embodiments, product streams may include at least 50% by weight of C2-C4 light olefins. Product streams may also include at least 25% by weight of BTX. In embodiments, one or more product streams may be combined into a single product stream.

[0077] In an embodiment, the product separator 116 may also produce one or more recycle streams. One or more recycle streams may include a methane cracker recycle stream 34, a steam cracker recycle stream 36, a hydrotreater recycle stream 38, or a combination thereof. The methane cracker recycle stream 34 may include C1 hydrocarbons, which may be methane. The steam cracker recycle stream 36 may include C2-C4 hydrocarbons. The steam cracker recycle stream 36 may include C2-C4 paraffins, C2-C4 alkynes, or both. The steam cracker recycle stream 36 may include ethane, propane, butane, acetylene, propyne, butyne, or a combination thereof. The hydrotreater recycle stream 38 may include cracked naphtha, light cycle oil, heavy cycle oil, or a combination thereof. The hydrotreater recycle stream 38 may include all cracked naphthas that would otherwise be included in the naphtha product stream 46. The cracked naphtha may have an initial boiling point (IBP) between 25°C and 204°C. Light cycle oil may have a boiling point between 343° C. and 426° C. Heavy cycle oil may have a boiling point in excess of 426° C.

[0078] Still refer to Figure 1 The system 100 includes an aromatics complex 118. The aromatics complex 118 is fluidly connected to the product separator 116 and processes the naphtha product stream 46 to produce benzene and xylene. Figure 1As shown, the benzene and xylene produced by the aromatics complex 118 may also be collectively referred to herein as an "aromatics complex product stream" 50. In an embodiment, the aromatics complex 118 may further include a catalytic reforming unit 120 and a transalkylation unit 122.

[0079] In an embodiment, the catalytic reformer 120 can be fluidly connected to the product separator 116 and can catalytically reform the naphtha product stream 44 to produce a reformate stream 48. The reformate stream 48 can include benzene, toluene, and xylenes. In an embodiment, catalytic reforming of cracked naphtha that may be present in the naphtha product stream 44 can produce additional coke on the catalyst in the catalytic reformer. The catalytic reformer can be operated at an operating temperature in the following ranges: 450°C to 600°C, 460°C to 600°C, 470°C to 600°C, 480°C to 600°C, 490°C to 600°C, 500°C to 600°C, 510°C to 600°C, 520°C to 600°C, 530°C to 600°C, 540°C to 600°C, 550°C to 600°C, 560°C to 600°C, 570°C to 600°C, 580°C to 600°C, ℃ to 600 ℃, 590 ℃ to 600 ℃, 450 ℃ to 590 ℃, 450 ℃ to 580 ℃, 450 ℃ to 570 ℃, 450 ℃ to 560 ℃, 450 ℃ to 550 ℃, 450 ℃ to 540 ℃, 450 ℃ to 530 ℃, 450 ℃ to 520 ℃, 450 ℃ to 510 ℃, 450 ℃ to 500 ℃, 450 ℃ to 490 ℃, 450 ℃ to 480 ℃, 450 ℃ to 470 ℃ or 450 ℃ to 460 ℃. In an embodiment, the catalytic reformer 120 can be operated at an operating pressure in the range of 0.7 MPa to 7 MPa.

[0080] In an embodiment, the transalkylation unit 122 can be connected to the catalytic reforming device 120 fluid, and the toluene in the reformate stream 48 can be upgraded to produce additional benzene, xylene or both. The transalkylation unit 122 can also include a transalkylation catalyst. The transalkylation unit 122 can contact the reformate stream 48 (particularly the toluene in the reformate stream 48) with hydrogen and a transalkylation catalyst to produce benzene and xylene. In an embodiment, the transalkylation catalyst can have a mesostructure including at least one disordered mesophase and at least one ordered mesophase. As used in the present disclosure, the term "ordered mesophase" can refer to a crystalline zeolite with uniformly arranged mesopores, wherein the average pore size of the "mesopores" is between 2nm and 50nm. The term "disordered mesophase" can refer to an uneven arrangement of mesopores, wherein the average pore size of the mesopores is between 2nm and 50nm. The term "ordered / disordered phase" can refer to a surface having a combination of at least one ordered mesophase and at least one disordered mesophase. Introducing the ordered / disordered phase into the zeolite structure increases the likelihood that larger molecules in the feed will enter the active sites within the transalkylation catalyst 146 .

[0081] In embodiments, the transalkylation catalyst may include a solid zeolite composite and a metal. The solid zeolite composite may include ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, mordenite (MOR) skeleton zeolite, NES topological zeolite, EU-1, MAPO-36, SAPO-5, SAPO-11, SAPO-34, SAPO-41 or a combination thereof. The solid zeolite composite may include a medium pore mordenite (MOR) zeolite and a medium pore ZSM-5 zeolite in a weight ratio of 1:1 to 5:1. The Si / Al molar ratio of the medium pore mordenite (MOR) zeolite may be at least 20, 20 to 300, 20 to 100, 25 to 50 or 28 to 32. In an embodiment, the Si / Al molar ratio of the medium pore ZSM-5 zeolite can be at least 5, e.g., 5 to 500, 10 to 100, 20 to 75, 30 to 50, 35 to 45, or 38 to 42. The transalkylation catalyst can further include a metal. The metal can include molybdenum, platinum, rhenium, nickel, or a combination thereof. In an embodiment, the transalkylation unit 122 can operate at an operating temperature in the range of 350°C to 500°C, 400°C to 500°C, 350°C to 450°C, or 400°C to 450°C. The transalkylation unit 112 can operate at an operating pressure of 1 MPa to 5 MPa.

[0082] In an embodiment, the aromatics complex 118 may further include one or more extractive distillation units. The one or more extractive distillation units may include a solvent, such as, but not limited to, N-methylpyrrolidone or dimethylformamide. The one or more extractive distillation units may be connected in parallel, in sequence, or in combination thereof. The one or more extractive distillation units may be fluidly connected to the catalytic reforming unit 120 and the transalkylation unit 122. The one or more extractive distillation units may separate benzene, toluene, and xylene from the reformate stream 48 and produce a C1-C4 hydrocarbon recycle stream 52 and a C 9+ Hydrocarbon stream 54. The C1-C4 hydrocarbon recycle stream may typically include methane and C2-C4 hydrocarbons. 9+ The hydrocarbon stream 54 may generally include hydrocarbons having greater than 9 carbon atoms.

[0083] In an embodiment, the one or more extractive distillation units may also send the C1-C4 hydrocarbon recycle stream 52 to the product separator 116 to produce an additional methane recycle stream 34, an additional steam cracking unit recycle stream 36, or both. 9+ The hydrocarbon stream 54 is sent to the hydroprocessing unit 108 to produce another C1 hydrocarbon stream 18, a C2-C4 hydrocarbon stream 22, and a light C 5+ Hydrocarbon stream 26, heavy C 5+ The hydrocarbon stream 28 or a combination thereof.

[0084] In embodiments, one or more extractive distillation units may also be located downstream of transalkylation unit 122. In these embodiments, the one or more extractive distillation units may separate the benzene and xylenes produced by transalkylation unit 122. In these embodiments, the one or more extractive distillation units downstream of the transalkylation unit may also produce a C1-C4 hydrocarbon recycle stream, a C1-C4 hydrocarbon recycle stream, and a C1-C4 hydrocarbon recycle stream. 9+ hydrocarbon streams or both.

[0085] In embodiments, the systems discussed herein may include additional components for converting hydrocarbon oil feedstocks. For example, the integrated system 100 may further include a methane cracking unit 110 fluidly connected to the hydrotreating unit 108 and the product separator 116. The methane cracking unit 110 may crack C1 hydrocarbon stream 16, methane cracking unit recycle stream 34, or both to produce hydrogen 16. The hydrogen 16 may be recycled and reused in the hydrotreating unit 108. In embodiments, the methane cracking unit may be operated at a temperature of 850°C to 1200°C and a pressure of 0.1MPa to 0.2MPa. Without being bound by theory, the hydrogen produced by methane cracking may also be incorporated into applications (such as fuel cells) that require pure hydrogen without carbon monoxide.

[0086] As previously mentioned, in embodiments, the hydrotreater 108 may include hydrogen 16. Although the hydrogen 16 is discussed as coming from the methane cracker 110, it is also contemplated that the hydrogen 16 may come from additional sources, wherein these additional sources may be the primary source of hydrogen used in the operation of the hydrotreater. In embodiments, the ratio of hydrogen 16 to feed (deasphalted oil stream 10) for the hydrotreater 108 may be 800 L / L to 1200 L / L. The ratio of hydrogen 24 to feed for the hydrotreater 108 may be 800 L / L to 1200 L / L, 800 L / L to 1100 L / L, 800 mL / L to 1000 L / L, 800 L / L to 900 L / L, 900 L / L to 1200 L / L, 900 L / L to 1100 L / L, 900 L / L to 1000 L / L, 1000 L / L to 1200 L / L, 1000 L / L to 1100 L / L, 1100 L / L to 1200 L / L, or 1100 L / L to 1200 L / L.

[0087] In an embodiment, the system 100 may further include a steam cracking unit 112. The steam cracking unit 112 may be fluidly connected to the hydrotreating unit 108 and the product separator 116, and may crack the C2-C4 hydrocarbon stream 18, the steam cracking unit recycle stream 36, or both to form a steam cracked product 20. The steam cracked product 20 may include a mixture of cracked hydrocarbon-based materials, which may be separated into one or more petrochemical products contained in the first product stream or the second product stream. For example, the steam cracked product may include C2-C4 olefins, benzene, toluene, xylene, naphtha, or a combination thereof, and optionally fuel gas, butadiene, C 5+ Hydrocarbons, fuel oils, or combinations thereof. In an embodiment, the steam cracking unit 112 may be operated at a temperature of 700° C. to 950° C. (e.g., 800° C. to 950° C.) and a pressure of 0.1 MPa to 0.2 MPa. The steam cracking unit may be operated with a residence time of 0.05 seconds to 2 seconds. The mass ratio of steam to the C2-C4 hydrocarbon fraction 106 may be from about 0.3:1 to about 2:1.

[0088] In an embodiment, the hydrotreater 108 may be additionally connected to a product separator 116 fluid, and the hydrotreater recycle stream 38 may be hydrotreated to produce an additional hydrotreater product stream. In an embodiment, hydrotreating the cracked naphtha in the hydrotreater recycle stream 38 may saturate the olefins and diolefins in the cracked naphtha, and remove impurities such as sulfur and nitrogen (if still present). This may have the additional benefit of increasing the yield of the olefins of the product stream, which otherwise would be converted into coke in the catalytic reformer 120 by direct treatment of the cracked naphtha. In an embodiment, the product separator 116 may deliver the methane recycle stream 30 to the methane cracking unit 110, the steam cracking unit recycle stream 36 to the steam cracking unit 112, the hydrotreater recycle stream 38 to the hydrotreater 108, or a combination thereof.

[0089] Reference now Figure 2 In an embodiment, the integrated system 100 may further include a dehydrogenation unit 130. The dehydrogenation unit 130 may be fluidly connected to the hydroprocessing unit 108 and the final product separator 116. The dehydrogenation unit 130 may dehydrogenate the C3-C4 portion 66 of the C2-C4 hydrocarbon stream 22, the C3-C4 portion of the steam cracking unit recycle stream 36 (also referred to herein as the C3-C4 hydrocarbon recycle stream 70), or both to form propylene and butenes 72. In this configuration, the hydroprocessing unit 108 may be additionally configured to produce the C3-C4 hydrocarbon stream 66, the C2 hydrocarbon stream 64, or both. The dehydrogenation unit 130 may then send the propylene and butenes 72 to the final product separator 116, where the propylene and butanes 72 may be separated into one or more product streams. In these embodiments, the steam cracking unit 112 can crack the C2 portion 64 of the C2-C4 hydrocarbon stream 22, the C2 portion of the steam cracking unit recycle stream 32 (also referred to herein as the C2 hydrocarbon recycle stream 68), or both to form light olefins, naphtha, and BTX.

[0090] In an embodiment, the dehydrogenation unit 130 can be operated at a temperature of 300°C to 800°C, for example, 300°C to 400°C, 400°C to 500°C, 500°C to 600°C, 600°C to 700°C, 700°C to 800°C, or any combination thereof. The dehydrogenation unit 130 can also be operated at a pressure of 0.001MPa to 1MPa. Without being bound by any particular theory, it is believed that since the dehydrogenation of hydrocarbons is an endothermic reaction and the conversion level is limited by chemical equilibrium, it may be necessary to operate at a relatively high temperature and a relatively low hydrogen partial pressure to achieve a higher conversion rate. However, for reactions under harsh conditions, it may be difficult to maintain high activity and high selectivity for a long time because undesirable side reactions (such as aromatization, cracking, isomerization, coke formation, or a combination thereof) may increase. Therefore, the reaction conditions can be selected according to maximizing one or more of the catalytic activity, catalytic selectivity, and catalyst stability.

[0091] In an embodiment, dehydrogenation unit 130 may also include a catalyst system for hydrocarbon conversion. The catalyst system may include a zinc silicate support material, one or more alkali metals or alkaline earth metals and one or more platinum group metals. The zinc silicate support material may further include an MFI framework structure at least incorporated with silicon and zinc. As used herein, "MFI framework structure" may sometimes be referred to as a ZSM-5 framework structure. Zeolite framework types (such as MFI framework types) are disclosed in "Atlas of Zeolite Framework Types, Fifth Edition" by Baerlcher, Meier and Olson, the contents of which are incorporated herein by reference in their entirety. Dehydrogenation of C3-C4 hydrocarbons may further include contacting C3-C4 hydrocarbons with a catalyst system to dehydrogenate at least a portion of C3-C4 hydrocarbons into propylene and butenes.

[0092] In an embodiment, the system 100 may further include a feed separator 102. The feed separator 102 may be a series of gas-liquid separators, such as a flash tank or flash drum (also known as a breakpot, a separation drum, a separation tank, a compressor suction tank, or a compressor inlet tank). It should be understood that a variety of fractionation separators may be utilized, such as a distillation column, etc.

[0093] The feed separator 102 can be fluidly connected to the solvent deasphalting unit 104, the light steam enhanced catalytic cracking unit 114, and the aromatics complex unit 118. The feed separator can first separate the hydrocarbon oil stream 2 into a heavy oil fraction stream 4 and a light oil fraction stream. The feed separator 102 can then further separate the light oil fraction stream into at least a feed middle distillate oil stream 6 and a feed naphtha stream 8. The heavy oil fraction 4 can include hydrocarbons having a boiling point greater than 300°C. The light oil fraction can include hydrocarbons having a boiling point less than 300°C. The feed middle distillate oil stream 6 can include hydrocarbons having a boiling point between 204°C and 300°C, in particular distillate oils. The feed naphtha stream 8 can include hydrocarbons having a boiling point between 185°C and 204°C, in particular naphtha. In an embodiment, the hydrocarbon oil stream 2 can include 40% to 70% by weight of the heavy hydrocarbon oil fraction 4. The hydrocarbon oil stream 2 may include 36 wt% to 72 wt% of a light oil fraction. The hydrocarbon oil stream 2 may include 30 wt% to 60 wt% of a middle distillate oil stream. The hydrocarbon oil stream 2 may include 6 wt% to 12 wt% of a naphtha feed stream 8.

[0094] The feed separator 102 may send the feed middle distillate stream 6 to a steam enhanced catalytic cracking unit 114, the heavy oil fraction stream 4 to a solvent deasphalting unit 104, the feed naphtha stream 8 to an aromatics complex 118, or a combination thereof. The solvent deasphalting unit 104 may separate the heavy oil fraction stream 4 into at least heavy residual hydrocarbons 10 and a deasphalted oil stream 10. The first steam enhanced catalytic cracking unit may crack the light oil fraction stream 6 into light steam enhanced catalytic cracking products 26. The aromatics complex 118 may process the naphtha feed stream 8 to produce additional benzene and xylenes.

[0095] In an embodiment, the system may further include a hydrocracking unit. The hydrocracking unit may be used in place of the hydrotreating unit 108 to upgrade the deasphalted oil stream 12 to produce a hydrocracking unit product stream in place of the hydrotreating unit product stream. In an embodiment where the hydrotreating unit 108 is replaced with a hydrocracking unit, the hydrocracking unit may provide an additional advantage of cracking the heaviest hydrocarbon components in the deasphalted oil stream 12 to form olefins, BTX, and naphtha, similar to the function of a second steam enhanced catalytic cracking unit.

[0096] In other embodiments, a hydrocracking unit may be included in addition to the hydrotreating unit 108. In these embodiments, the hydrocracking unit may be located downstream of the hydrotreating unit 108 and fluidly connected to the hydrotreating unit 108. The hydrocracking unit may also be fluidly connected to the product separator 116. The hydrotreating unit 108 may be further configured to separate at least a portion of the heavy C 5+ The hydrocarbon stream 28 is the heaviest C 5+ The hydrocarbon stream is sent to the hydrocracking unit. 5+The hydrocarbon stream may include C with a boiling point of 540°C to 640°C. 5+ In the embodiment, as described above, the heaviest C 5+ The hydrocarbon stream may also typically include a hydrocarbon stream having an API gravity of at least 8.0° and / or a hydrocarbon stream having an API gravity of at least 1000 kg / m3 (kg / m 3 ) of standard liquid density. The hydrocracking unit can crack the heaviest C 5+ The hydrocracking unit may also be configured to send olefins, BTX and naphtha to a product separator 116.

[0097] Still refer to Figure 1 , embodiments of the present disclosure also include integrated methods for upgrading hydrocarbon oil feed streams. These methods may include any of the integrated systems 100 described above. The method includes solvent deasphalting a hydrocarbon oil stream 2 to form at least a deasphalted oil stream 12 and heavy residual hydrocarbons 10. The method further includes treating the heavy residual hydrocarbons 10 to form a gasification residue 14 and a synthesis gas 16. The method further includes hydrotreating at least the deasphalted oil stream 12 to form light C 5+ The hydrocarbon stream 26 and the heavy C 5+ The method further comprises converting the light C 5+ The hydrocarbon stream 26 is subjected to steam enhanced catalytic cracking to form light steam enhanced catalytic cracking products 30. The method further comprises converting the heavy C 5+ The hydrocarbon stream 28 is subjected to steam enhanced catalytic cracking to form a heavy steam enhanced catalytic cracking product 32. The method further includes passing at least a portion of the light steam enhanced catalytic cracking stream 26, the heavy steam enhanced catalytic cracking unit product stream 32, or both to a product separator 116 to produce an olefin product stream 42, a naphtha product stream 46, and a BTX product stream 44. The method further includes processing the naphtha product stream 46 in an aromatics complex 118 to produce benzene and xylene as part of an aromatics complex product stream 50.

[0098] In an embodiment, processing the naphtha product stream 46 in the aromatics complex 118 may further include catalytically reforming the naphtha product stream 46 to produce a reformate stream 48, and upgrading the toluene in the reformate stream 48 in the transalkylation unit 122 to form additional benzene, xylenes, or both. Processing the naphtha product stream 46 in the aromatics complex 118 may also include passing at least a portion of the reformate stream 48 through one or more extractive distillation units to separate benzene, toluene, and xylenes to produce a C1-C4 hydrocarbon recycle stream 52, and to produce C 9+ Hydrocarbon stream 54. In an embodiment, the previous step may be performed prior to upgrading the toluene in reformate stream 48 in transalkylation unit 122.

[0099] In an embodiment, the method may further include hydrotreating the hydrotreater recycle stream 38 to form an additional hydrotreated product stream, methane cracking the C1 hydrocarbon stream 16, the methane recycle stream 30, or both to form hydrogen 16, and steam cracking the C2-C4 hydrocarbon stream 18, the steam cracker recycle stream 36, or both to form steam cracker products 20. The method may further include passing the hydrogen 16 to the hydrotreater 108 for recycling in the hydrotreater 108, and passing the steam cracker products 20 to the final separator 116 to produce one or more product streams and one or more recycle streams.

[0100] In an embodiment, the method may further include passing the C1-C4 hydrocarbon recycle stream 52 to a product separator to produce an additional methane recycle stream 34, an additional steam cracking unit recycle stream 36, or both. 9+ The hydrocarbon stream 54 is passed to a hydroprocessing unit to produce another C1 hydrocarbon stream 18, a C2-C4 hydrocarbon stream 22, a light C 5+ Hydrocarbon stream 26, heavy C 5+ The hydrocarbon stream 28 or a combination thereof.

[0101] In an embodiment including a dehydrogenation unit, the process may further include steam cracking the C2 portion of the C2-C4 hydrocarbon stream 18, the C2 portion of the steam cracker recycle stream 36, or both to form light olefins, naphtha, and BTX. The process may further include dehydrogenating the C3-C4 portion of the C2-C4 hydrocarbon stream 18, the C3-C4 portion of the steam cracker recycle stream 36, or both to form propylene and butenes. The process may further include passing the propylene and butenes to a final separator 116 to produce one or more product streams.

[0102] In an embodiment including a first product separator 118, the method may further include passing the hydroprocessed product stream to the first product separator 118 to separate the C1 hydrocarbon stream 16, the C2-C4 hydrocarbon stream 18, the light C 5+ Hydrocarbon stream 26, heavy C 5+ The hydrocarbon stream 28 or a combination thereof.

[0103] The method may further include solvent deasphalting the heavy hydrocarbon fraction 4 to form at least a deasphalted oil stream 12 and heavy residual hydrocarbons 10. The method may further include steam enhanced catalytic cracking of at least the light hydrocarbon fraction 6 in a first steam enhanced catalytic cracking unit to form light steam enhanced catalytic cracking products 26. In an embodiment including a feed separator 102, the method may further include first passing the hydrocarbon oil stream 2 through the feed separator 102 to separate the hydrocarbon oil stream 2 into the heavy hydrocarbon fraction 4, the light hydrocarbon fraction 6, and a feed naphtha stream 8. The method may further include solvent deasphalting the heavy hydrocarbon fraction 4 to form at least a deasphalted oil stream 12 and heavy residual hydrocarbons 10. The method may further include steam enhanced catalytic cracking of at least the light hydrocarbon fraction 6 in a first steam enhanced catalytic cracking unit to form light steam enhanced catalytic cracking products 30. The method may further include processing the feed naphtha stream 8 in an aromatics complex 118 to produce additional benzene and xylenes.

[0104] Example

[0105] Various embodiments of the methods and systems for converting hydrocarbon oils will be further illustrated by the following examples. These examples are illustrative in nature and should not be construed as limiting the subject matter of the present disclosure.

[0106] Example 1

[0107] use Figure 1 and Figure 2 The system shown processes Arabian Light Crude Oil (AL), Arabian Extra Light Crude Oil (AXL) and Arabian Heavy Crude Oil (AH) in a simulation program. The compositions of the crude oils used in the examples are shown in Tables 2 and 3 below.

[0108] Table 2: Composition of Arab Super Light, Arab Light and Arab Heavy Crude Oils

[0109]

[0110] Table 3: Composition of Arab Super Light, Arab Light and Arab Heavy Crude Oils

[0111]

[0112] Table 4 below shows the simulation results using Arabian ultra light crude oil as the feed hydrocarbon oil. Figure 1 and Example 2 of the present invention Figure 2 Similarly, according to Figure 1 Comparative Example 1 was carried out without a solvent deasphalting unit or a gasification unit. Figure 2 Comparative Example 2 was carried out without the dehydrogenation unit. Comparative Example 3 was also carried out according to Figure 2 is carried out, but without a gasification unit or a deasphalting unit.

[0113] Table 4: Test of the total yield of the embodiment of the present invention

[0114]

[0115] In Table 4 above, "Purge and other products" may include crude oil fractions not mentioned in the above components. Purge and other products may also include waste or unusable streams. For example, purge and other products may include light cycle oil, heavy cycle oil, distillate oil, and C1 and C2 fractions. 2- C4 paraffin. Heavy cycle oil can be used as fuel oil for boilers, for example.

[0116] In the above Table 4, it is expected that the presence of a greater amount of olefins in Comparative Example 1 compared to Example 1 of the present invention is due to the exclusion of the deasphalting unit and the gasification unit. Because the deasphalting unit and the gasification unit are excluded in Comparative Example 1, the heavy stream that is usually processed in the gasification unit and the deasphalting unit is sent to the steam enhanced catalytic cracking unit instead. This increases the throughput in the steam enhanced catalytic cracking unit, thereby increasing the olefin production. However, this configuration also results in less naphtha and synthesis gas in the product stream, which may in turn reduce the yield of BTX if the naphtha is subsequently processed and upgraded to aromatic compounds (such as benzene, toluene and xylene). However, this phenomenon may also depend on the selected crude oil feed. For example, it is expected that the processing of Arab heavy crude oil with a larger amount of heavier (higher boiling point) hydrocarbon components will show that when the solvent deasphalting unit and the gasification unit are not included, the production of both olefins and naphtha is significantly reduced. This can illustrate the particular applicability of the system discussed herein to the processing and upgrading of heavier grades of crude oil.

[0117] The following Tables 5 and 6 show the simulation results of Example 1 of the present invention. Figure 1 The configuration shown was simulated without the recycle flow from the product separator.

[0118] Table 5: Product yield of the processing unit of Example 1 of the present invention

[0119]

[0120] Table 6: Product yield of the processing unit of Example 1 of the present invention (continued)

[0121]

[0122] Referring to Tables 5 and 6 above, the Arabian ultra-light crude oil shown in Table 3 is first sent to a deasphalting unit, wherein the heavy residual hydrocarbons are sent to a gasification unit, and all other components are sent to a hydrotreating unit. With respect to the hydrotreating unit, methane and hydrogen are sent to a methane cracking unit for the main production of hydrogen. The liquefied petroleum gas is sent to a steam cracking unit to be converted into a steam cracking unit product. The naphtha from the hydrotreating unit is sent to a first steam-enhanced catalytic cracking unit to be converted into a first steam-enhanced catalytic cracking unit product. Distillate oil, gas oil, heavy cycle oil and atmospheric residue are sent to a second steam-enhanced catalytic cracking unit to be converted into a second steam-enhanced catalytic cracking unit product. The distillate oil is mainly composed of diesel and kerosene boiling point hydrocarbon fractions.

[0123] All steam cracker products are sent to the product separator. All products from the two steam enhanced catalytic crackers are also sent to the product separator. The naphtha and gasoline streams are then sent to the catalytic reformer, which sends its products to the transalkylation unit.

[0124] The following Tables 7 and 8 show the simulation results of Comparative Example 1. The simulation was performed similarly to Inventive Example 1, but without the deasphalting unit or the gasification unit.

[0125] Table 7: Product yield of the processing unit of Comparative Example 1

[0126]

[0127] Table 8: Product yield of the processing unit of Comparative Example 1 (continued)

[0128]

[0129]

[0130] As shown in Tables 4-8 above, separation of heavy residual hydrocarbons in the hydrotreater prior to processing Arabian Super Light Crude Oil results in a higher concentration of products in the naphtha boiling range of the hydrotreater, approximately 5.1 wt%.

[0131] Tables 9 and 10 below show the simulation results of Example 2 of the present invention. Figure 2 (Right now Figure 1 ) was simulated, but with a dehydrogenation unit and no recycle stream. Although not listed in Tables 9 and 10 below, the C3 hydrocarbons and C4 hydrocarbons entering the dehydrogenation unit have approximately 100% conversion of propylene and butenes, respectively.

[0132] Table 9: Product yield of the processing unit of Example 2 of the present invention

[0133]

[0134] Table 10: Product yield of the processing unit of Example 2 of the present invention (continued)

[0135]

[0136]

[0137] As shown in Example 2 of the present invention and Comparative Example 2 in Table 4 above, the inclusion of a dehydrogenation unit results in a higher concentration of olefins in the final product stream without affecting the yield of BTX. For example, comparing Example 2 of the present invention to Comparative Example 2, the inclusion of a dehydrogenation unit results in an increase of about 6.0 weight percent in the yield of olefins in the final product stream.

[0138] The present application discloses several technical aspects. One aspect is an integrated method for upgrading a hydrocarbon oil feed stream using a gasification unit, a steam enhanced catalytic cracking unit and an aromatics complex unit, the method comprising: solvent deasphalting the hydrocarbon oil stream to form at least a deasphalted oil stream and heavy residual hydrocarbons, the heavy residual hydrocarbons comprising at least asphaltenes; treating the heavy residual hydrocarbons in the gasification unit to form synthesis gas and a gasification residue; hydrotreating the deasphalted oil stream to form light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon stream; the light C 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form a light steam enhanced catalytic cracking product comprising olefins, BTX, naphtha or a combination thereof; the heavy C 5+ The invention relates to a method for preparing a first steam enhanced catalytic cracking unit and a second steam enhanced catalytic cracking unit, wherein the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit are provided with a steam enhanced catalytic cracking unit, wherein the steam enhanced catalytic cracking unit comprises a first hydrocarbon stream, a first hydrocarbon stream, a second ... 5+ The ratio of the gas hourly space velocity of the hydrocarbon stream is 0.1 to 1.1 times (steam: C 5+ hydrocarbon stream).

[0139] The second aspect may include the first aspect, wherein the naphtha product stream is processed in the aromatics complex, further comprising catalytically reforming the naphtha product stream to produce a reformate stream comprising benzene, toluene and xylenes; and upgrading the toluene in the reformate stream in the alkyl transfer unit to form additional benzene, xylenes or both.

[0140] The third aspect may include any one of the first aspect to the second aspect, wherein the lightweight C 5+ The hydrocarbon fraction contains 95 Boiling point C 5+ Hydrocarbons; and the heavy C 5+ The hydrocarbon fraction contains C 5+ Hydrocarbons.

[0141] The fourth aspect may include any one of the first to third aspects, wherein the deasphalted oil stream is hydrotreated to further form a C1 hydrocarbon stream and a C2-C4 hydrocarbon stream; and the C1 hydrocarbon stream, the C2-C4 hydrocarbon stream, the light C 5+ The hydrocarbon stream and the heavy C 5+ The hydrocarbon streams together constitute a hydroprocessing product stream;

[0142] The fifth aspect may include the fourth aspect, further comprising methane cracking the C1 hydrocarbon stream to form hydrogen; steam cracking the C2-C4 hydrocarbon stream to form a steam cracking product comprising light olefins, naphtha and BTX; and passing the steam cracking product to the final separator to produce the one or more product streams and the one or more recycle streams.

[0143] The sixth aspect may include the fifth aspect, wherein the one or more recycle streams comprise a methane recycle stream, a steam cracking unit recycle stream, a hydrotreating unit recycle stream, or a combination thereof; the steam cracking unit recycle stream comprises C2-C4 hydrocarbons; the hydrotreating unit recycle stream comprises cracked naphtha, light cycle oil, and heavy cycle oil having a boiling point between 185°C and 650°C.

[0144] The seventh aspect may include the sixth aspect, further comprising: hydrotreating the hydrotreating unit recycle stream to form another C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+ hydrocarbon stream or a combination thereof; methane cracking the methane recycle stream to form additional hydrogen; steam cracking the steam cracking unit recycle stream to form additional steam cracking products; and passing the hydrogen to the hydrotreater for recycling in the hydrotreater.

[0145] The eighth aspect may include the seventh aspect, further comprising: processing the naphtha product stream in the aromatics complex, further comprising catalytically reforming the naphtha to produce a reformate stream comprising benzene, toluene, and xylenes, passing at least a portion of the reformate stream through one or more extractive distillation units to separate the benzene, toluene, and xylenes to produce a C1-C4 hydrocarbon recycle stream, and producing a C 9+a hydrocarbon stream, and upgrading toluene in a transalkylation unit to form additional benzene, xylenes, or both; passing the C1-C4 hydrocarbon recycle stream to the product separator to produce additional methane recycle stream, additional steam cracking unit recycle stream, or both; and transferring the C 9+ The hydrocarbon stream is transferred to the hydroprocessing unit to produce another C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+ hydrocarbon streams or combinations thereof.

[0146] The ninth aspect may include any one of aspects 6 to 8, further comprising: steam cracking the C2 portion of the C2-C4 hydrocarbon stream, the C2 portion of the steam cracking unit recycle stream, or both to form a steam cracking product; and dehydrogenating the C3-C4 portion of the C2-C4 hydrocarbon stream, the C3-C4 portion of the steam cracking unit recycle stream, or both to form propylene and butenes; and transferring the propylene and butenes to a final separator to produce one or more product streams.

[0147] The tenth aspect may include any one of the first to ninth aspects, further comprising: first passing the hydrocarbon oil stream through a feed separator to separate the hydrocarbon oil stream into at least a heavy hydrocarbon fraction, a feed middle distillate oil stream and a feed naphtha stream; subjecting the heavy hydrocarbon fraction to solvent deasphalting to at least the deasphalted oil stream and the heavy residual hydrocarbons; in the first steam-enhanced catalytic cracking unit, subjecting at least the feed middle distillate oil stream to steam-enhanced catalytic cracking to form the light steam-enhanced catalytic cracking product; and processing the feed naphtha stream in the aromatics complex to produce additional benzene and xylene.

[0148] An eleventh aspect may include any one of the first to tenth aspects, wherein the hydrocarbon oil stream comprises whole crude oil or a crude oil fraction.

[0149] The twelfth aspect may include any one of the sixth to eleventh aspects, wherein the solvent deasphalting unit is operated at a temperature of 60°C to 90°C and a pressure of 0.1MPa to 0.4MPa; the gasification unit is operated at a temperature of 600°C to 1100°C and a pressure of 1MPa to 6.2MPa; the hydroprocessing zone is operated at a temperature of 370°C to 500°C and a pressure of 0.1MPa to 0.2MPa; the steam enhanced catalytic cracking system is operated at a temperature of 525°C to 750°C and a pressure of 0.1MPa to 0.2MPa; the methane cracking zone is operated at a temperature of 850°C to 1200°C and a pressure of 0.1MPa to 0.2MPa; the dehydrogenation unit is operated at a temperature of 300°C to 800°C and a pressure of 0.001MPa to 1MPa; and the steam cracking zone is operated at a temperature of 800°C to 950°C and a pressure of 0.1MPa to 0.2MPa.

[0150] A thirteenth aspect may include any one of the first to twelfth aspects, wherein the deasphalted oil stream comprises C1 to C 5+ Hydrocarbons; the heavy residual hydrocarbons contain C having a boiling point between 426°C and 650°C 5+ hydrocarbons; the synthesis gas comprises hydrogen, carbon monoxide, carbon dioxide or a combination thereof; and the gasification residue comprises carbon particles, ash, slag, tar or a combination thereof.

[0151] The fourteenth aspect may include any one of the first to thirteenth aspects, and may include an integrated system for converting a hydrocarbon oil feedstock using a gasification unit, a steam enhanced catalytic cracking unit, and an aromatics complex unit, the system comprising: a solvent deasphalting unit, the solvent deasphalting unit being configured to separate a hydrocarbon oil stream into at least a deasphalted oil stream and heavy residual hydrocarbons, the heavy residual hydrocarbons at least containing asphaltenes; a gasification unit, the gasification unit being fluidly connected to the solvent deasphalting unit and configured to treat the heavy residual hydrocarbons to form synthesis gas and a gasification residue; a hydroprocessing unit, the hydroprocessing unit being fluidly connected to the solvent deasphalting unit and configured to at least hydroprocess the deasphalted oil stream to form light C 5+ Hydrocarbon streams and heavy C 5+ a first steam enhanced catalytic cracking unit, the first steam enhanced catalytic cracking unit is connected to the hydroprocessing unit fluid and is configured to at least a portion of the light C 5+ a second steam enhanced catalytic cracking unit, the second steam enhanced catalytic cracking unit being fluidly connected to the hydrotreating unit in parallel with the first steam enhanced catalytic cracking unit and configured to treat at least a portion of the heavy C 5+The invention relates to a method for cracking a hydrocarbon fraction to form a heavy steam enhanced catalytic cracking product; a product separator, the product separator is fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit and is configured to produce an olefin product stream, a naphtha product stream and a BTX product stream; and an aromatics complex unit, the aromatics complex unit is fluidly connected to the product separator and is configured to process the naphtha product stream to produce benzene and xylene, and wherein in the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit, the gas hourly space velocity of steam is C 5+ The ratio of the gas hourly space velocity of the hydrocarbon stream is 0.1 to 1.1 times (steam: C 5+ hydrocarbon stream).

[0152] The fifteenth aspect may include the fourteenth aspect, further comprising: a catalytic reforming unit, which is fluidly connected to the product separator and configured to catalytically reform the naphtha product stream to produce a reformed oil stream containing benzene, toluene and xylenes; and an alkyl transfer unit, which is fluidly connected to the catalytic reforming unit and configured to upgrade the toluene in the reformed oil stream to produce additional benzene, xylenes or both.

[0153] The sixteenth aspect may include the fifteenth aspect, wherein the product separator is further configured to produce one or more product separator recycle streams; the one or more product separator recycle streams comprise: a methane recycle stream, a steam cracking unit recycle stream, a hydrotreating unit recycle stream or a combination thereof; the steam cracking unit recycle stream comprises C2-C4 hydrocarbons; the hydrotreating unit recycle stream comprises cracked naphtha, light cycle oil, heavy cycle oil or a combination thereof.

[0154] The seventeenth aspect may include the sixteenth aspect, further comprising a methane cracking unit, the methane cracking unit being fluidly connected to the hydrotreating unit and the product separator and configured to crack a C1 hydrocarbon stream, the methane recycle stream, or both to form hydrogen for recycling in the hydrotreating unit; and a steam cracking unit being fluidly connected to the hydrotreating unit and the product separator and configured to crack a C2-C4 hydrocarbon stream, the steam cracking unit recycle stream, or both to form a steam cracking product comprising light olefins, naphtha, and BTX for separation in the product separator; and wherein the hydrotreating unit is additionally configured to form the C1 hydrocarbon stream and the C2-C4 hydrocarbon stream; the hydrotreating unit is fluidly connected to the product separator and is additionally configured to hydrotreat the hydrotreating unit recycle stream to produce another C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+hydrocarbon stream or a combination thereof; the gasification unit is fluidly connected to the product separator and is further configured to form additional synthesis gas and a gasification residue; and the product separator is configured to send the methane recycle stream to the methane cracking unit, the steam cracking unit recycle stream to the steam cracking unit, and the hydrotreating unit recycle stream to the hydrotreating unit.

[0155] The eighteenth aspect may include the seventeenth aspect, further comprising a catalytic reforming unit, the catalytic reforming unit being fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit, and configured to catalytically reform the naphtha product stream to produce a reformate stream comprising benzene, toluene, and xylene; one or more extractive distillation units, the one or more extractive distillation units being fluidly connected to the catalytic reforming unit, the product separator, and the hydrotreating unit, and configured to separate the benzene, toluene, and xylene to produce a C1-C4 hydrocarbon recycle stream, and to produce a C 9+ a hydrocarbon stream; and a transalkylation unit fluidly connected to the one or more extractive distillation units and configured to upgrade the toluene to produce additional benzene, xylenes, or both, and wherein the one or more extractive distillation units are further configured to pass the C1-C4 hydrocarbon recycle stream to the product separator to produce additional methane recycle stream, additional steam cracker recycle stream, or both; and the one or more extractive distillation units are further configured to pass the C1-C4 hydrocarbon recycle stream to the product separator to produce additional methane recycle stream, additional steam cracker recycle stream, or both. 9+ The hydrocarbon stream is sent to the hydroprocessing unit to produce another C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+ hydrocarbon streams or combinations thereof.

[0156] The nineteenth aspect may include the eighteenth aspect, further comprising a dehydrogenation unit, which is fluidly connected to the hydrotreating unit and the product separator and is configured to dehydrogenate the C3-C4 portion of the C2-C4 hydrocarbon stream, the C3-C4 portion of the steam cracking unit recycle stream, or both to form propylene and butenes, and wherein the steam cracking unit is configured to crack the C2 portion of the C2-C4 hydrocarbon stream, the C2 portion in the steam cracking unit recycle stream, or both to form the steam cracking product; and the dehydrogenation unit is further configured to send propylene and butenes to the product separator.

[0157] The twentieth aspect may include any one of aspects fifteen to twentieth, further comprising a feed separator, the feed separator being fluidly connected to the solvent deasphalting unit, the first steam-enhanced catalytic cracking unit and the aromatics complex unit, and configured to separate the hydrocarbon oil stream into at least a heavy oil fraction stream, a feed middle distillate oil stream and a feed naphtha stream, and wherein the solvent deasphalting unit is further configured to separate the heavy oil fraction into at least the heavy residual hydrocarbons and the deasphalted oil stream; the first steam-enhanced catalytic cracking unit is further configured to crack the feed middle distillate oil stream into the light steam-enhanced catalytic cracking product; and the aromatics complex unit is further configured to process the feed naphtha stream to produce additional benzene and xylenes.

[0158] Aspect 21 may include any one of aspects 15 to 20, wherein the first steam enhanced catalytic cracking unit is further configured to form an olefin and naphtha ratio of 2:1 to 7:1 (olefin:naphtha); and the second steam enhanced catalytic cracking unit is further configured to form an olefin and naphtha ratio of 1.5:1 to 0.8:1 (olefin:naphtha).

[0159] The twenty-second aspect may include any one of the first to fourteenth aspects, wherein the lightweight C 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form olefins and naphtha, wherein the ratio of the olefins to the naphtha is from 2:1 to 7:1; and the heavy C 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form olefins and naphtha, wherein the ratio of olefins to naphtha is from 1.5:1 to 0.8:1.

[0160] It is worth noting that statements in the present disclosure that a component of the present disclosure is "operable" or "sufficient" in a particular manner to exhibit a particular performance or function in a particular manner are structural statements, rather than statements of intended use. More specifically, references in the present disclosure to the manner in which a component is "operable" or "sufficient" represent the existing physical conditions of the component and, therefore, should be regarded as explicit statements of the structural characteristics of the component.

[0161] It should also be noted that when used herein, terms such as "preferably", "usually" and "typically" are not intended to limit the scope of the claimed invention, nor to imply that certain features are critical, essential or even important to the structure or function of the claimed invention. Rather, these terms are merely intended to identify specific aspects of the embodiments of the present disclosure, or to emphasize alternative or additional features that may or may not be used in a particular embodiment of the present disclosure.

[0162] It is noted that one or more of the claims utilize the term “wherein” as a transitional phrase. For the purpose of defining the present invention, it is noted that this term is introduced in the claims as an open transitional phrase to introduce a series of features of the structure and should be interpreted in a similar manner to the more commonly used open-ended term “comprising.”

[0163] Having described the subject matter of the present disclosure in detail and with reference to specific embodiments, it is noteworthy that the various details disclosed in the present disclosure should not be considered as implying that these details are related to the essential components of the various embodiments described in the present disclosure. In addition, it is apparent that modifications and changes can be made without departing from the scope of the present disclosure, including but not limited to the embodiments defined in the appended claims.

[0164] The singular forms "a," "an," and "the" include plural referents unless the context clearly dictates otherwise.

[0165] Ranges are provided throughout this disclosure. It is contemplated that each discrete value contained within a range is also included. In addition, it is also contemplated that a range is formed by each discrete value contained within an explicitly disclosed range.

[0166] As used herein and in the appended claims, the words "comprising," "having," and "including" and all grammatical variations thereof are intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

[0167] As used herein, terms such as "first" and "second" are arbitrarily assigned and are intended only to distinguish between two or more instances or components. It should be understood that the words "first" and "second" are not used for other purposes, are not part of the component name or description, and do not necessarily define the relative position, orientation, or order of the components. In addition, it should be understood that the use of the terms "first" and "second" alone does not require the existence of any "third" component, although such a possibility is contemplated within the scope of the present disclosure.

Claims

1. An integrated process for upgrading a hydrocarbon oil feed stream, the process comprising: subjecting the hydrocarbon oil stream to solvent deasphalting to form at least a deasphalted oil stream and heavy residual hydrocarbons, the heavy residual hydrocarbons comprising at least asphaltenes; processing the heavy residual hydrocarbons in a gasification unit to form synthesis gas and a gasification residue; The deasphalted oil stream is hydrotreated to form a C3-C4 hydrocarbon stream, a light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon streams; dehydrogenating the C3-C4 hydrocarbon stream to form propylene and butenes; The light C 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form a light steam enhanced catalytic cracking product comprising olefins, BTX, naphtha or a combination thereof; The heavy C 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form a heavy steam enhanced catalytic cracking product comprising olefins, BTX, naphtha or a combination thereof; passing at least a portion of the light steam enhanced catalytic cracking stream, the heavy steam enhanced catalytic cracking stream, or both to a product separator to produce an olefin product stream, a naphtha product stream, and a BTX product stream; and The naphtha product stream is processed in an aromatics complex to produce benzene and xylenes.

2. The method according to claim 1, wherein: The lightweight C 5+ The hydrocarbon fraction contains 95 Boiling point C 5+ Hydrocarbons; and The heavy C 5+ The hydrocarbon fraction contains C 5+ Hydrocarbons.

3. The method according to any one of the preceding claims, further comprising: The C1 hydrocarbon stream is subjected to methane cracking to form hydrogen, wherein the deasphalted oil stream is subjected to hydroprocessing to further form the C1 hydrocarbon stream and a C2-C4 hydrocarbon stream, wherein the C1 hydrocarbon stream, the C2-C4 hydrocarbon stream, the light C 5+ The hydrocarbon stream and the heavy C 5+ The hydrocarbon streams together constitute a hydroprocessing product stream; steam cracking the C2-C4 hydrocarbon stream to form a steam cracked product comprising olefins, naphtha, and BTX; and The steam cracking products are passed to the product separator to separate the olefins, the naphtha, and the BTX and to generate the one or more product separator recycle streams.

4. A method according to any one of the preceding claims, wherein: The one or more recycle streams comprise a methane recycle stream, a steam cracker recycle stream, a hydrotreater recycle stream, or a combination thereof, and the method further comprises: subjecting the methane recycle stream to methane cracking to form additional hydrogen; passing the hydrogen to the hydroprocessing unit for recycle in the hydroprocessing unit; steam cracking the steam cracker recycle stream to form a further steam cracked product stream, the steam cracker recycle stream comprising C2-C4 hydrocarbons; and The hydrotreater recycle stream is hydrotreated to form another C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+ A hydrocarbon stream or a combination thereof, the hydrotreater recycle stream comprising cracked naphtha and light cycle oil having a boiling point between 185°C and 650°C.

5. The method according to any one of the preceding claims, further comprising: The process of processing the naphtha product stream in the aromatics complex comprises catalytically reforming the naphtha to produce a reformate stream comprising benzene, toluene and xylenes, passing at least a portion of the reformate stream through one or more extractive distillation units to separate the benzene, toluene and xylenes, producing a C1-C4 hydrocarbon recycle stream, and producing a C 9+ a hydrocarbon stream, and upgrading toluene in a transalkylation unit to form additional benzene, xylenes, or both; passing the C1-C4 hydrocarbon recycle stream to the product separator to produce an additional methane recycle stream, an additional steam cracker recycle stream, or both; and The C 9+ The hydrocarbon stream is transferred to the hydroprocessing unit to produce another C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+ hydrocarbon streams or combinations thereof.

6. The method according to any one of the preceding claims, further comprising: first passing the hydrocarbon oil stream through a feed separator to separate the hydrocarbon oil stream into a heavy hydrocarbon fraction, a light hydrocarbon fraction, and a feed naphtha stream; subjecting the heavy hydrocarbon fraction to solvent deasphalting to form at least the deasphalted oil stream and the heavy residual hydrocarbons; and In the first steam enhanced catalytic cracking unit, at least the light hydrocarbon fraction is subjected to steam enhanced catalytic cracking to form the light steam enhanced catalytic cracking product; and The feed naphtha stream is processed in the aromatics complex to produce additional benzene and xylenes.

7. A method according to any one of the preceding claims, wherein: The hydrocarbon oil stream comprises whole crude oil or a crude oil fraction.

8. The method according to any one of claims 5 to 7, wherein: The solvent deasphalting unit is operated at a temperature of 60°C to 90°C and a pressure of 0.1 MPa to 0.4 MPa; The gasification unit operates at a temperature of 600°C to 1100°C and a pressure of 1 MPa to 6.2 MPa; The hydroprocessing zone is operated at a temperature of 370°C to 500°C and a pressure of 0.1 MPa to 0.2 MPa; The steam enhanced catalytic cracking system operates at a temperature of 525°C to 750°C and a pressure of 0.1 MPa to 0.2 MPa; The methane cracking zone is operated at a temperature of 850°C to 1200°C and a pressure of 0.1 MPa to 0.2 MPa; The dehydrogenation unit operates at a temperature of 300°C to 800°C and a pressure of 0.001 MPa to 1 MPa; The steam cracking zone is operated at a temperature of 800°C to 950°C and a pressure of 0.1 MPa to 0.2 MPa; The catalytic reformer is operated at a temperature of 450°C to 600°C and a pressure of 0.7 MPa to 7 MPa; and The transalkylation unit operates at a temperature of 350°C to 450°C and a pressure of 1 MPa to 5 MPa.

9. A method according to any one of the preceding claims, wherein: The deasphalted oil contains C1 to C 5+ Hydrocarbons; The heavy residual hydrocarbons include C with a boiling point between 426°C and 650°C. 5+ Hydrocarbons; The syngas comprises hydrogen, carbon monoxide, carbon dioxide or a combination thereof; and The gasification residue includes char particles, ash, slag, tar or a combination thereof.

10. A method according to any one of the preceding claims, wherein: The light C 5+ steam enhanced catalytic cracking of a hydrocarbon stream to form olefins and naphtha, wherein the ratio of the olefins to the naphtha is from 2:1 to 7:1; and The heavy C 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form olefins and naphtha, wherein the ratio of olefins to naphtha is from 1.5:1 to 0.8:

1.

11. An integrated system for converting a hydrocarbon oil feedstock, the system comprising: a solvent deasphalting unit configured to separate a hydrocarbon oil stream into at least a deasphalted oil stream and heavy residual hydrocarbons, the heavy residual hydrocarbons comprising at least asphaltenes; a gasification unit fluidly connected to the solvent deasphalting unit and configured to process the heavy residual hydrocarbons to form syngas and a gasification residue; A hydroprocessing unit is fluidly connected to the solvent deasphalting unit and is configured to hydroprocess at least the deasphalted oil stream to form a C3-C4 hydrocarbon stream, a light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon streams; a dehydrogenation unit fluidly connected to the hydrotreater and configured to dehydrogenate the C3-C4 hydrocarbon stream to form propylene and butenes; a first steam enhanced catalytic cracking unit, the first steam enhanced catalytic cracking unit being fluidly connected to the hydrotreating unit and configured to treat at least a portion of the light C 5+ The hydrocarbon fraction is cracked to form light steam enhanced catalytic cracking products; and a second steam enhanced catalytic cracking unit, the second steam enhanced catalytic cracking unit being fluidly connected to the hydrotreating unit in parallel with the first steam enhanced catalytic cracking unit and configured to treat at least a portion of the heavy C 5+ The hydrocarbon fraction is cracked to form heavy steam enhanced catalytic cracking products; a product separator fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit and configured to produce an olefin product stream, a naphtha product stream, and a BTX product stream; and an aromatics complex fluidly connected to the product separator and configured to process the naphtha product stream to produce benzene and xylenes, and wherein: In the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit, the gas hourly space velocity of steam is C 5+ The ratio of the gas hourly space velocity of the hydrocarbon stream is 2 to 10 times (steam: C 5+ hydrocarbon stream).

12. The integrated system according to claim 11, wherein: The aromatics composite device comprises: a catalytic reformer fluidly connected to the product separator and configured to catalytically reform the naphtha product stream to produce a reformate stream comprising benzene, toluene, and xylenes; and A transalkylation unit is fluidly connected to the catalytic reformer and configured to upgrade toluene in the reformate stream to produce additional benzene, xylenes, or both.

13. The integrated system according to claim 11 or 12, further comprising: a methane cracking unit fluidly connected to the hydrotreater and the product separator and configured to crack a C1 hydrocarbon stream, a methane recycle stream, or both to form hydrogen for recycling in the hydrotreater; and a steam cracking unit fluidly connected to the hydrotreater and the product separator and configured to crack a C2-C4 hydrocarbon stream, a steam cracking unit recycle stream comprising C2-C4 hydrocarbons, or both to form a steam cracked product comprising light olefins, naphtha, and BTX for separation in the product separator; and wherein, The product separator is further configured to produce one or more product separator recycle streams, the one or more product separator recycle streams comprising: the methane recycle stream, the steam cracker recycle stream, and a hydrotreater recycle stream comprising cracked naphtha, light cycle oil, heavy cycle oil, or a combination thereof; The hydrotreating unit is further configured to form the C1 hydrocarbon stream and the C2-C4 hydrocarbon stream; The hydrotreater is fluidly connected to the product separator and is further configured to hydrotreat the hydrotreater recycle stream to produce an additional C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+ a hydrocarbon stream or a combination thereof; and The product separator is configured to route the methane recycle stream to the methane cracker, route the steam cracker recycle stream to the steam cracker, and route the hydrotreater recycle stream to the hydrotreater.

14. The integrated system according to claim 12 or 13, wherein: The aromatics composite device further comprises: a catalytic reformer fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit and configured to catalytically reform the naphtha product stream to produce a reformate stream comprising benzene, toluene, and xylenes; one or more extractive distillation units, the one or more extractive distillation units are fluidly connected to the catalytic reforming unit, the product separator and the hydrotreating unit and are configured to separate the benzene, toluene and xylene to produce a C1-C4 hydrocarbon recycle stream and to produce C 9+ hydrocarbon streams; and a transalkylation unit fluidly connected to the one or more extractive distillation units and configured to upgrade the toluene to produce additional benzene, xylenes, or both, and wherein The one or more extractive distillation units are further configured to send the C1-C4 hydrocarbon recycle stream to the product separator to produce an additional methane recycle stream, an additional steam cracker recycle stream, or both; and The one or more extractive distillation units are further configured to convert the C 9+ The hydrocarbon stream is sent to the hydroprocessing unit to produce another C1 hydrocarbon stream, a C2-C4 hydrocarbon stream, a light C 5+ Hydrocarbon stream, heavy C 5+ hydrocarbon streams or combinations thereof.

15. The integrated system according to any one of claims 11 to 14, further comprising a feed separator, the feed separator being fluidly connected to the solvent deasphalting unit, the first steam enhanced catalytic cracking unit and the aromatics complex unit, and configured to separate the hydrocarbon oil stream into a light oil fraction stream, a heavy oil fraction stream and a feed naphtha stream, and wherein, The solvent deasphalting unit is further configured to separate the heavy oil fraction into at least the heavy residual hydrocarbons and the deasphalted oil stream; The first steam enhanced catalytic cracking unit is further configured to crack the light oil fraction stream into the light steam enhanced catalytic cracking product; and The aromatics complex is further configured to process the feed naphtha stream to produce additional benzene and xylenes.

Images