Process for treating hydrocarbon oil feed stream using delayed coker and steam enhanced catalytic cracking unit

Abstract

An integrated process for upgrading a hydrocarbon oil feed stream using a delayed coker and a steam enhanced catalytic cracking unit includes solvent deasphalting the hydrocarbon oil stream to form at least a deasphalted oil stream and heavy residual hydrocarbons, the heavy residual hydrocarbons including at least asphaltenes; subjecting the heavy residual hydrocarbons to delayed coking to form petroleum coke and a delayed coker product stream; hydrotreating the delayed coker product stream and the deasphalted oil stream to form a light C5 + hydrocarbon stream and a heavy C5 + hydrocarbon stream; subjecting the light C5 + hydrocarbon stream to steam enhanced catalytic cracking to form a light steam enhanced catalytic cracking product stream comprising olefins, benzene, toluene, xylenes, naphtha, or a combination thereof; and subjecting the heavy C5 + hydrocarbon stream to steam enhanced catalytic cracking to form a heavy steam enhanced catalytic cracking product including olefins, benzene, toluene, xylene, naphtha, or a combination thereof.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to U.S. Non-Provisional Application No. 17 / 865,751, 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 is also desirable to produce light olefins and / or benzene, toluene, and xylenes, collectively referred to as "BTX," directly from crude oil sources. 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 and 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 heavy residual hydrocarbons and remove impurities before refining the crude oil stream to avoid these negative effects. In addition, it may be desirable to further refine the upgraded heavy residual hydrocarbons to fully utilize the crude oil stream into light olefins and BTX.

[0009] An integrated process and system for producing light olefins (e.g., C2-C4 olefins) and / or BTX from crude oil while providing the above benefits is described herein. Heavy hydrocarbon residues (e.g., asphaltenes) can be upgraded in a solvent deasphalting unit and a delayed coking unit to produce crude oil fractions that can be upgraded to light olefins, BTX, and one-shot petroleum coke. These crude oil fractions can then be refined in a hydrotreating unit and separated into at least four fractions that are processed separately. Then, C 5+ The hydrocarbon fraction can be processed in a steam enhanced catalytic cracking unit to produce olefins and BTX. In this way, the entire crude oil is used to produce at least olefins, BTX 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; subjecting the heavy residual hydrocarbons to delayed coking to form petroleum coke and a delayed coker product stream; and subjecting the delayed coker product stream and the deasphalted oil stream to hydrotreating to form light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon stream; the light C 5+ The steam enhanced catalytic cracking of the hydrocarbon stream to form a light steam enhanced catalytic cracking product stream comprising olefins, benzene, toluene, xylenes, naphtha or a combination thereof; and 5+ The hydrocarbon stream is subjected to steam enhanced catalytic cracking to form a heavy steam enhanced catalytic cracking product stream comprising olefins, benzene, toluene, xylenes, naphtha, or combinations thereof.

[0011] According to another embodiment of the present invention, an integrated system for converting a hydrocarbon oil feed stream includes: 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 at least containing asphaltenes; a delayed coking unit, the delayed coking unit being fluidly connected to the solvent deasphalting unit and decoking the heavy residual hydrocarbons into at least petroleum coke and a delayed coking unit product stream; a hydrotreating unit, the hydrotreating unit being fluidly connected to the solvent deasphalting unit and the delayed coking unit and hydrotreating at least the deasphalted oil stream and the delayed coking unit product 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 being fluidly connected to the hydrotreating 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; and a second steam enhanced catalytic cracking unit, the second steam enhanced catalytic cracking unit is fluidly connected to the hydrotreating unit in parallel with the first steam enhanced catalytic cracking unit to treat at least a portion of the heavy C 5+ The hydrocarbon fraction is cracked to form heavy steam enhanced catalytic cracking products.

[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] Figure 3 A method flow diagram is shown of an exemplary method according to embodiments described herein.

[0018] Figure 4 A method flow diagram is shown of an exemplary method according to embodiments described herein.

[0019] 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.

[0020] 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.

[0021] In addition, 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.

[0022] 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.

[0023] 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.

[0024] 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

[0025] 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.

[0026] As used herein, "asphaltenes" generally refer 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 comprising 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.

[0027] 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.

[0028] 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 per million (ppmw) by weight and a Conrad carbon residue of less than 5 weight %. This minimally treated material can be considered as crude oil as described herein.

[0029] 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.

[0030] 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.

[0031] 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.

[0032] 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.

[0033] 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.

[0034] 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.

[0035] 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.

[0036] 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".

[0037] 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 the major component of the stream (e.g., comprising 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 comprising the component is disclosed as passing from the system component to another system component, the component of the stream is disclosed as passing from one system component to another system component. 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.

[0038] First reference Figure 1 , shows an integrated system 100 for converting a 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 delayed coking unit 106, a hydrotreating unit 108, and a steam enhanced catalytic cracking unit 114. Although Figure 1It appears 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, particularly 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.

[0039] 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.

[0040] Still refer to Figure 1 , the solvent deasphalting unit 104 separates the hydrocarbon oil stream 2 into at least a deasphalted oil stream 10 and heavy residual hydrocarbons 8. The heavy residual hydrocarbons 8 may include at least asphaltenes in the form of asphalt. In an embodiment, the solvent deasphalting unit may include a solvent. The solvent may 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. In an embodiment, the heavy residual hydrocarbons 8 may further include non-hydrocarbon components and impurities. In this way, the solvent deasphalting unit 104 may 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 may remove nitrogen-containing compounds, sulfur-containing compounds, Conradson carbon residue (CCR), and metal compounds (such as nickel and vanadium). In an embodiment, removing non-hydrocarbon components and impurities as just before can improve the efficiency of downstream processing units by reducing the coking deactivation rate of various catalysts used therein.

[0041] 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.

[0042] Still refer to Figure 1, the delayed coking unit 106 is fluidly connected to the solvent deasphalting unit 104 and decokes the heavy residual hydrocarbons 8 into at least petroleum coke 42 and a delayed coking unit product stream 12. As used herein, "decoking" may also refer to "delayed coking", i.e., the delayed coking unit 106 may decoke or remove coke from the input stream. In an embodiment, the decoking of the heavy residual hydrocarbons 8 may allow the heavy residual hydrocarbons 8 to be further upgraded to the desired product stream, i.e., olefins and BTX. This may increase the total volume of available oil and hydrocarbon products recovered from the hydrocarbon oil stream 2. Removing petroleum coke 42 from the heavy residual hydrocarbons 8 may also reduce the amount of coke precursors present in the delayed coking unit product stream 12. Removing coke precursors may also reduce the coking deactivation rate of various catalysts used in the downstream processing units discussed herein. As used herein, "coke precursors" are crude oil fractions that are generally known to have a tendency to form coke on the catalyst during crude oil refining, thereby increasing the deactivation rate of the catalyst.

[0043] The delayed coker 106 may also produce hydrogen as a byproduct of the delayed coking reaction. It is expected that the hydrogen produced by the delayed coker 106 may have the additional benefit of at least partially reducing the need for an external hydrogen source for the hydrotreater 108. In one non-limiting example, operating the delayed coker 106 within the operating ranges disclosed herein may produce 0.1 wt% hydrogen by weight of the delayed coker product stream 12.

[0044] In embodiments, the delayed coker 106 may be operated at a temperature of less than or equal to 600° C., less than or equal to 550° C., less than or equal to 500° C., or even less than or equal to 485° C. The delayed coker 106 may be operated at a temperature of 450° C. to 600° C., 450° C. to 550° C., 450° C. to 500° C., 450° C. to 485° C., 485° C. to 600° C., 485° C. to 550° C., 485° C. to 500° C., 500° C. to 600° C., 500° C. to 550° C., or 550° C. to 600° C. The delayed coker 106 may be operated at a pressure of 0.1 MPa to 0.4 MPa.

[0045] In the implementation scheme, Figure 1 As shown, the delayed coker 106 may also be fluidly connected to the steam enhanced catalytic cracking unit 114, the final product separator 116, or both. In embodiments where the hydrotreater 108 is deactivated or shut down for maintenance, the delayed coker 106 may send the delayed coker product stream 12 directly to the steam enhanced catalytic cracking unit 114, the final product separator 116, or both. In particular, this may include the delayed coker 106 sending the delayed coker product stream 12 to a second steam enhanced catalytic cracking unit. In embodiments, this may allow the delayed coker product stream 12 to be directly converted to a light steam enhanced catalytic cracking unit product stream.

[0046] Still refer to Figure 1 In an embodiment, hydrocarbon oil stream 2 may include whole crude oil, topped crude oil, 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 as a feedstock stream, it should be understood that the description of Figure 1 and Figure 2 The systems 100 and 200 described in the embodiments 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 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.

[0047] 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.

[0048] Table 1: Composition of Arabian Light Crude Oil

[0049] 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

[0050] 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.

[0051] In an embodiment comprising an Arabian ultra-light crude oil, the hydrocarbon oil stream 2 may have a hydrocarbon fraction with a boiling point greater than 300°C of 44.9% by weight, measured by the total weight of the hydrocarbon oil stream 2. The hydrocarbon oil stream may have a hydrocarbon fraction with a boiling point less than or equal to 300°C of 52.7% by weight, measured by the total weight of the hydrocarbon oil stream 2. The hydrocarbon oil stream 2 may also have a remaining non-hydrocarbon component. In an embodiment comprising an Arabian light crude oil, the hydrocarbon oil stream 2 may have a hydrocarbon fraction with a boiling point greater than 300°C of 55.69% by weight, measured by the total weight of the hydrocarbon oil stream 2. The hydrocarbon oil stream may have a hydrocarbon fraction with a boiling point less than or equal to 300°C of 44.31% by weight, measured by the total weight of the hydrocarbon oil stream 2. The hydrocarbon oil stream 2 may also have a remaining non-hydrocarbon component. In an embodiment comprising an Arabian light crude oil, the hydrocarbon oil stream 2 may have a hydrocarbon fraction with a boiling point greater than 300°C of 66.1% by weight, measured by the total weight of the hydrocarbon oil stream 2. The hydrocarbon oil stream may have 32.4 wt% of hydrocarbon fractions having a boiling point less than or equal to 300° C. measured by the total weight of the hydrocarbon oil stream 2. The hydrocarbon oil stream 2 may also have remaining non-hydrocarbon components.

[0052] 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.

[0053] In an embodiment, the heavy residual hydrocarbons 8 may include C 5+Hydrocarbons. As previously described, the heavy residual hydrocarbons 8 may be an asphalt product that includes asphaltenes in part. The heavy residual hydrocarbons may also be atmospheric residue, vacuum residue, or both. In an embodiment, the deasphalted oil stream 10 may include C1 to C2 hydrocarbons having a boiling point between -162°C and 650°C. 5+ Hydrocarbons.

[0054] In an embodiment, the delayed coker product stream 12 may include C 5+ The delayed coker product stream 12 may be naphtha, gas oil, or both. The petroleum coke 12 may be needle coke, sponge coke, honeycomb coke, shot coke, or a combination thereof. The petroleum coke 12 may be composed primarily of carbon and lesser amounts of non-hydrocarbon components. The petroleum coke may also be composed primarily of C with a boiling point greater than 650°C. 5+ Hydrocarbon composition.

[0055] Still refer to Figure 1 The hydroprocessing unit 108 is fluidly connected to the solvent deasphalting unit 104 and the delayed coking unit 106, and hydroprocesses at least the deasphalted oil stream 10 and the delayed coking unit product stream 12 to form light C 5+ The hydrocarbon stream 22 and the heavy C 5+ In an embodiment, the hydrotreater may also hydrotreat at least the deasphalted oil stream 10 and the delayed coker product stream 12 to additionally form a C1 hydrocarbon stream 14 and a C2-C4 hydrocarbon stream 18. In an embodiment, the C1 hydrocarbon stream, the C2-C4 hydrocarbon stream, the light C 5+ Hydrocarbon streams and heavy C 5+ The hydrocarbon streams may be collectively referred to as hydroprocessing product streams. In other embodiments, the hydroprocessing unit may additionally form C 9+ A heavy residual hydrocarbon stream which may be recycled back to the delayed coker to produce additional delayed coker product stream 12 and petroleum coke.

[0056] 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.

[0057] 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.

[0058] 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.

[0059] In an embodiment, the C2-C4 hydrocarbon stream 18 may generally include C2-C4 hydrocarbons, including C2-C4 paraffins, C2-C4 olefins, C2-C4 alkynes, or combinations thereof. The C2-C4 hydrocarbon stream may include ethane, propane, butane, ethylene, propylene, butene, acetylene, propyne, butyne, or combinations thereof. In an embodiment, the light C 5+ The hydrocarbon stream 22 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 24 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 22 and the heavy C 5+ The temperature cut point between the hydrocarbon stream 24 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.

[0060] In an embodiment, the heavy C 5+ The hydrocarbon stream 24 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 ) of the standard liquid density of hydrocarbon residues. However, it is expected that the heavy C 5+ The amount of hydrocarbon residue present in the hydrocarbon stream 24 may generally depend on the efficiency of the delayed coker 106 .

[0061] 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 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 may 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 stream 26, the heavy steam enhanced catalytic cracking product stream 28, or both may include olefins, BTX, 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.

[0062] 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 22 may need to be heavier than C 5+ Longer residence time of hydrocarbon stream 24 to fully process and convert light C 5+ The light components of hydrocarbon stream 22. In addition, the heavy C 5+ The hydrocarbon stream 24 may require a shorter residence time to avoid heavy C 5+ Components of hydrocarbon stream 24 are excessively coked.

[0063] The first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit can also produce differently distributed hydrocarbon products and their product streams. For example, the first steam enhanced catalytic cracking unit can produce a larger proportion of olefins than naphtha series products (including naphtha and gasoline). In an embodiment, the first steam enhanced catalytic cracking unit can produce a ratio of olefins to naphtha products of about 5.5:1 (olefins: naphtha) or about 6.5:1 (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).

[0064] Similarly, 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 8:9 or about 3:4 (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).

[0065] However, if two SECs are unavailable, the light C 5+ The hydrocarbon stream 22 and the heavy C 5+ The hydrocarbon stream 24 may be processed in a steam enhanced catalytic cracking unit under different conditions, but with different distributions of hydrocarbon products.

[0066] 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.

[0067] 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.

[0068] 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. In an embodiment, the steam enhanced catalytic cracking unit 114 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.

[0069] 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.

[0070] 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.

[0071] 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.

[0072] In embodiments, the steam in the steam enhanced catalytic cracking unit can reduce the hydrocarbon partial pressure, which can have the dual effect of increasing the output of light olefins and / or BTX hydrocarbons 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.

[0073] 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 22 or heavy C 5+ The ratio of the flow rate (gas hourly space velocity) of the hydrocarbon stream 24) 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.

[0074] 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 Up to 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 Up to 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 Up to 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 Up to 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 Up to 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 Up to 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.

[0075] In an embodiment, the feed (light C 5+ Hydrocarbon stream 22 or heavy C 5+ The hydrocarbon stream 24) 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.

[0076] 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 22 may require a lower hourly space velocity to allow more time for the light C 5+ The hydrocarbon stream 22 is cracked into desired products. In another non-limiting example, heavy C 5+ The hydrocarbon stream 24 may require a greater hourly space velocity to prevent heavy C 5+ Overcracking of hydrocarbon stream 24 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 .

[0077] 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.

[0078] 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.

[0079] 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).

[0080] Still refer to Figure 1 In an embodiment, the integrated system 100 may include a final product separator 116. The final product separator 116 may be fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit 114, and may separate at least a portion of the light steam enhanced catalytic cracking products 26 and the heavy steam enhanced catalytic cracking products 28 into at least one or more product streams and one or more recycle streams.

[0081] In an embodiment, one or more recycle streams may include a methane recycle stream 30, a steam cracking unit recycle stream 32, a hydrotreater recycle stream 34, a delayed coker recycle stream 36, or a combination thereof. The steam cracking unit recycle stream 32 may include C2-C4 hydrocarbons. The steam cracking unit recycle stream 32 may include C2-C4 paraffins, C2-C4 alkynes, or both. The steam cracking unit recycle stream 32 may include ethane, propane, butane, acetylene, propyne, butyne, or a combination thereof. The hydrotreater recycle stream 34 may include cracked naphtha, light cycle oil, heavy cycle oil, or a combination thereof. The delayed coker recycle stream 36 may include heavy cycle oil. In an embodiment, the cracked naphtha may have an initial boiling point (IBP) of between 25°C and 204°C. The light cycle oil may have a boiling point between 343°C and 426°C. The heavy cycle oil may have a boiling point greater than 426°C.

[0082] In an embodiment, one or more product streams may include a first product stream 38 and a second product stream 40. The first product stream 38 may include light olefins, such as ethylene, propylene, butene, or a combination thereof. The first product stream may also include olefins, such as gasoline. The second product stream 40 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. In an embodiment, the first product stream or the second product stream may also include fuel oil (also referred to as heavy oil, bunker fuel, or heating oil), naphtha, tail gas products (C1-C4 hydrocarbons), or a combination thereof. Alternatively, fuel oil and tail gas products may be included as part of one or more recycle streams. In an embodiment, one or more product streams may include at least 45% by weight of C2-C4 olefins. One or more product streams may include at least 30% by weight of naphtha. One or more product streams may include at least 55% by weight of C2-C4 olefins. In an embodiment, one or more product streams may also include at least 20% by weight of naphtha. In an embodiment, one or more product streams may be combined into a single product stream.

[0083] 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 final product separator 116. The methane cracking unit 110 may crack the C1 hydrocarbon stream 14, the methane recycle stream 30, 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 1 bar to 2 bar. 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.

[0084] 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 the feed (deasphalted oil stream 10 and delayed coker product stream 14) of 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.

[0085] 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 final product separator 116, and may crack the C2-C4 hydrocarbon stream 18, the steam cracking unit recycle stream 32, or both to form a steam cracking product stream 20. The steam cracking product stream 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 cracking product stream 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., or 900° 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.

[0086] In an embodiment, the hydrotreater 108 may be further fluidly connected to the final product separator 116 and may hydrotreat the hydrotreater recycle stream 34 to produce an additional hydrotreater product stream. The delayed coker 106 may be further fluidly connected to the final product separator 116 and may decoke the delayed coker recycle stream 36 to form additional petroleum coke 42 and a delayed coker product stream 12. In an embodiment, the final product separator 116 may send the methane recycle stream 30 to the methane cracking unit 110, the steam cracking unit recycle stream 32 to the steam cracking unit 112, the hydrotreater recycle stream 34 to the hydrotreater 108, the delayed coker recycle stream 36 to the delayed coker 106, or a combination thereof.

[0087] Reference now Figure 3 and Figure 4 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 18, the C3-C4 portion of the steam cracking unit recycle stream 33 (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 a C3-C4 hydrocarbon stream 66, a 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 18, 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.

[0088] 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.

[0089] 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.

[0090] 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. The feed separator 102 may be fluidly connected to the solvent deasphalting unit 104 and the steam enhanced catalytic cracking unit 114. The feed separator 102 may first separate the hydrocarbon oil stream 2 into a light oil fraction stream 6 and a heavy oil fraction stream 4. The feed separator 102 may then feed the light oil fraction stream 6 to the steam enhanced catalytic cracking unit 114. In these embodiments, the solvent deasphalting unit 104 may separate the heavy oil fraction stream 4 into at least heavy residual hydrocarbons 8 and a deasphalted oil stream 10. In addition, in these embodiments, the first steam enhanced catalytic cracking unit may crack the light oil fraction stream 6 into a light steam enhanced catalytic cracking product 26.

[0091] Reference now Figure 2 , an integrated system 200 for converting a hydrocarbon oil feedstock is shown. The integrated system 200 may include any integrated system 100 discussed previously or below and additional components. The integrated system 200 may also include any hydrocarbon oil stream 2 discussed previously or below. In an embodiment, the integrated system 200 may also include a first product separator 118. Figure 2 As shown, the first product separator 118 can be fluidly connected to the hydroprocessing unit 108, the methane cracking unit 110, the steam cracking unit 112, the first steam enhanced catalytic cracking unit, and the second steam enhanced catalytic cracking unit. The first product separator 118 can separate the hydroprocessed product stream into a C1 hydrocarbon stream 14, a C2-C4 hydrocarbon stream 18, a light C 5+ The hydrocarbon stream 22 and the heavy C 5+ The first product separator 118 can also send the C1 hydrocarbon stream 14 to the methane cracking unit 110, send the C2-C4 hydrocarbon stream 18 to the steam cracking unit 112, and send the light C 5+ The hydrocarbon stream 22 is sent to the first steam enhanced catalytic cracking unit, and the heavy C 5+ The hydrocarbon stream 24 is sent to a second steam enhanced catalytic cracking unit.

[0092] In an embodiment, the system 100 and the system 200 may further include a hydrocracking unit. The hydrocracking unit may be used in place of the hydrotreating unit 108 to upgrade the delayed coker product stream, the deasphalted oil stream, or both 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 delayed coker product stream 14, the deasphalted oil stream 10, or both to form olefins, BTX, and naphtha, similar to the function of a second steam enhanced catalytic cracking unit.

[0093] 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 final 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 24 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.

[0094] Still refer to Figure 1 and Figure 2 , 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 and 200 described above. The method includes solvent deasphalting a hydrocarbon oil stream 2 to form at least a deasphalted oil stream 10 and heavy residual hydrocarbons 8. The method further includes delaying coking the heavy residual hydrocarbons 8 to form petroleum coke 12 and a delayed coker product stream 14. The method further includes hydrotreating the delayed coker product stream 14 and the deasphalted oil stream 10 to form light C 5+ The hydrocarbon stream 22 and the heavy C 5+ The method further comprises converting the light C 5+ The hydrocarbon stream 22 is subjected to steam enhanced catalytic cracking to form a light steam enhanced catalytic cracking product stream 26. The method further comprises converting the heavy C5+ The hydrocarbon stream 24 is subjected to steam enhanced catalytic cracking to form a heavy steam enhanced catalytic cracking product stream 28 .

[0095] In an embodiment, the method may further include passing at least a portion of the light steam enhanced catalytic cracking stream 26, the heavy steam enhanced catalytic cracking product stream 28, or both to a final product separator 116 to produce one or more product streams and one or more recycle streams. In an embodiment, the method may further include hydrotreating the delayed coker product stream 14 and the deasphalted oil stream 10 to additionally form a C1 hydrocarbon stream 14 and a C2-C4 hydrocarbon stream 18.

[0096] In an embodiment, the method may further include delaying coking the delayed coker recycle stream 36 to form an additional delayed coker product stream 14, hydrotreating the hydrotreater recycle stream 34 to form an additional hydrotreated product stream, methane cracking the C1 hydrocarbon stream 14, 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 32, or both to form a steam cracker product stream 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 product stream 20 to the final separator 116 to produce one or more product streams and one or more recycle streams.

[0097] 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 32, 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 32, 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.

[0098] 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 14, the C2-C4 hydrocarbon stream 18, the light C 5+ Hydrocarbon stream 22, heavy C 5+ The hydrocarbon stream 24 or a combination thereof.

[0099] In embodiments 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 a heavy hydrocarbon fraction 4 and a light hydrocarbon fraction 6. The method may further include solvent deasphalting the heavy hydrocarbon fraction 4 to form at least a deasphalted oil stream 10 and heavy residual hydrocarbons 8. The method may further include steam enhanced catalytic cracking at least the light hydrocarbon fraction 6 in a first steam enhanced catalytic cracking unit to form light steam enhanced catalytic cracking products 26.

[0100] Example

[0101] 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.

[0102] Example 1

[0103] 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.

[0104] Table 2: Composition of Arab Super Light, Arab Light and Arab Heavy Crude Oils

[0105] Feed AXL AL AH Density at 15.6°C 0.8412 0.8658 0.8871 Percentage of C1-C4 hydrocarbon fraction 5.49 4.46 3.25 The percentage of hydrocarbon fractions with boiling points less than 300°C 49.59 39.85 30.65 Percentage of hydrocarbon fractions with boiling points greater than 300°C 44.92 55.69 66.0

[0106] Table 3: Composition of Arab Super Light, Arab Light and Arab Heavy Crude Oils

[0107]

[0108] Table 4 below shows the simulation results using Arabian ultra light crude oil and Arabian heavy crude oil as raw materials. Figure 1 and Example 2 Figure 2 Similarly, according to Figure 1 Comparative Example 1 was conducted without a solvent deasphalting unit or a delayed coking unit. Figure 2 Comparative Example 2 was performed without a delayed coker.

[0109] For Example 3 of the present invention, according to Figure 3 The configuration shown is simulated. Figure 3 Comparative Example 3 was carried out without the dehydrogenation unit. Figure 3Comparative Example 4 was conducted without a delayed coker or deasphalting unit. Inventive Examples 1 and 3 and Comparative Examples 1, 3 and 4 used Arabian extra light crude oil. Inventive Example 2 and Comparative Example 2 used Arabian heavy crude oil.

[0110] Table 4: Test of the total yield of the embodiment of the present invention

[0111]

[0112] 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.

[0113] In Table 4 above, it is expected that the greater amount of olefins in Comparative Example 1 compared to Inventive Example 1 is due to the exclusion of the delayed coker and deasphalting units. Because the deasphalting unit and delayed coker are excluded in Comparative Example 1, the heavy stream that is usually processed in the delayed coker and deasphalting units 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 a smaller amount of naphtha 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 xylenes). However, this phenomenon may also depend on the selected crude oil feed. For example, Inventive Example 2 and Comparative Example 2 process Arab heavy crude oil. When the solvent deasphalting unit and delayed coker are not included, Arab heavy crude oil (which has a larger amount of heavier (higher boiling point) hydrocarbon components) shows a significantly reduced production of both olefins and naphtha. This can illustrate the particular applicability of the system discussed herein to the processing and upgrading of heavier grades of crude oil.

[0114] Table 5 below shows the simulation results using Example 1 of the present invention as the raw material. Figure 1 The configuration shown was simulated without the recycle flow from the final product separator.

[0115] Table 5: Product yield of the processing unit of Example 1 of the present invention

[0116]

[0117] Referring to Table 5, except for petroleum coke, all delayed coking unit products are sent to the hydrotreating unit. With respect to the hydrotreating unit, methane and hydrogen are sent to the methane cracking unit for the main production of hydrogen. Liquefied petroleum gas is sent to the steam cracking unit to be converted into steam cracking unit products. Naphtha from the hydrotreating unit is sent to the first steam enhanced catalytic cracking unit to be converted into the first steam enhanced catalytic cracking unit products. Distillate oil, gas oil, heavy cycle oil and atmospheric residue are sent to the second steam enhanced catalytic cracking unit to be converted into the second steam enhanced catalytic cracking unit products. Distillate oil is mainly composed of diesel and kerosene boiling point hydrocarbon fractions. All steam cracking unit products are sent to the product separator. All products from the two steam enhanced catalytic cracking units are also sent to the product separator.

[0118] Table 6 below shows the simulation results for Comparative Example 1. The simulation was performed similarly to the simulation for Inventive Example 1, but without a delayed coker or deasphalting unit.

[0119] Table 6: Product yield of the processing unit of Comparative Example 1

[0120]

[0121]

[0122] As shown in Tables 4, 5 and 6 above, when processing Arabian ultra-light crude oil, including a delayed coker results in a higher concentration of products in the naphtha boiling range for each processing unit and in the final product stream. For example, including a delayed coker unit results in an increase of 1.3 wt % and 2.5 wt % in the hydrotreater product stream and the final product stream, respectively. If naphtha is processed in, for example, an aromatization unit, it is expected that a higher percentage of naphtha may also result in a higher percentage of BTX in the product stream. As shown in Tables 7 and 8 below, this higher concentration of products in the naphtha boiling range effect is further amplified due to the inclusion of a greater amount of heavy fractions (hydrocarbons with a boiling point of >300°C) in the crude stream.

[0123] Table 7 below shows the simulation results using Arabian heavy crude oil as the feedstock. Figure 2 The configuration shown was simulated without the recycle stream from the final product separator. The products of each process unit in Table 5 below are allocated to the other units in a similar manner as in Table 4 above.

[0124] Table 7: Product yield of the processing unit of Example 2 of the present invention

[0125]

[0126]

[0127] Table 8 below shows the simulation results for Comparative Example 2. The simulation was performed similarly to the simulation of the present invention example, but without the delayed coking unit.

[0128] Table 8: Product yield of the processing unit of Comparative Example 2

[0129]

[0130] As shown in Table 7 and Table 8 above, when processing Arab heavy crude oil, including delayed coking unit, causes the concentration of the product in the range of naphtha boiling point of each processing unit and in the final product stream to be higher.For example, including delayed coking unit causes the naphtha in hydrotreater product stream and the final product stream to increase by 6.7 % by weight and 2.8 % by weight respectively.Further, including delayed coking unit unit also causes the concentration of light olefins (such as, ethylene, propylene and butenes etc.) to be higher.As previously mentioned, when using heavier crude oil, the product concentration in the range of naphtha is further expanded.If naphtha is handled in, for example, aromatization unit, it is estimated that the higher percentage of naphtha also can cause the higher percentage of BTX in the product stream.

[0131] Table 9 below shows the simulation results using Example 3 of the present invention as the raw material. Figure 3 The configuration shown was simulated without the recycle stream from the final product splitter. Although not listed in Table 9 below, the C3 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 3 of the present invention

[0133]

[0134] As shown in the above Table 4 for Inventive Example 3 and Comparative Example 3, including a dehydrogenation unit results in a higher concentration of olefins in the final product stream without affecting the yield of naphtha series products. For example, comparing Inventive Example 3 to Comparative Example 3, including a dehydrogenation unit results in an increase of about 3.9 weight percent in the yield of olefins in the final product stream.

[0135] The present application discloses several technical aspects. One aspect is an integrated method for upgrading a hydrocarbon oil feed stream using a delayed coking unit and a steam enhanced catalytic cracking unit, the method 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; subjecting the heavy residual hydrocarbons to delayed coking to form petroleum coke and a delayed coking unit product stream; and subjecting the delayed coking unit product stream and the deasphalted oil stream to hydrotreating to form light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon stream; the light C 5+The steam enhanced catalytic cracking of the hydrocarbon stream to form a light steam enhanced catalytic cracking product stream comprising olefins, benzene, toluene, xylenes, naphtha or a combination thereof; and 5+ The steam enhanced catalytic cracking of the hydrocarbon stream to form a heavy steam enhanced catalytic cracking product stream comprising olefins, benzene, toluene, xylenes, naphtha or a combination thereof, and wherein the gas hourly space velocity of the steam in the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit is equal to 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).

[0136] The second aspect may include the first aspect and may further include passing at least a portion of the light steam enhanced catalytic cracking stream, the heavy steam enhanced catalytic cracking stream, or both to a final product separator to produce one or more product streams and one or more recycle streams.

[0137] The third aspect may include the first aspect or the second aspect, wherein the one or more product streams include: a first product stream, the first product stream comprising ethylene, propylene, butene or a combination thereof; and a second product stream, the second product stream comprising benzene, toluene, xylene or a combination thereof.

[0138] The fourth aspect may include any one of the first to third aspects, 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.

[0139] The fifth aspect may include any one of the second to fourth aspects, wherein the delayed coking unit product stream and the deasphalted oil stream are 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;

[0140] The sixth aspect may include the fifth 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 stream comprising light olefins, naphtha and BTX; and passing the steam cracking product stream to the final separator to produce the one or more product streams and the one or more recycle streams.

[0141] The seventh aspect may include the sixth aspect, wherein the one or more recycle streams comprise a methane recycle stream, a steam cracking unit recycle stream, a hydrotreating unit recycle stream, a delayed coking 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 and light cycle oil having a boiling point between 185°C and 426°C; and the delayed coking unit recycle stream comprises heavy cycle oil having a boiling point between 426°C and 650°C.

[0142] The eighth aspect may include the seventh aspect, further comprising: delaying coking the delayed coking unit recycle stream to form another delayed coking unit product stream; 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 an additional steam cracking product stream; and passing the hydrogen to the hydrotreater for recycling in the hydrotreater.

[0143] The ninth aspect may include the eighth aspect, 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 stream; 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 passing the propylene and butenes to a final separator to produce one or more product streams.

[0144] The tenth aspect may include the ninth aspect, further comprising transferring the hydroprocessed product stream to a first product separator to separate the C1 hydrocarbon stream, the C2-C4 hydrocarbon stream, the light C 5+ The hydrocarbon stream and the heavy C 5+ Hydrocarbon streams.

[0145] The eleventh aspect may include any one of the first to tenth aspects, further comprising: first passing the hydrocarbon oil stream through a feed separator to separate the hydrocarbon oil stream into a heavy hydrocarbon fraction and a light hydrocarbon fraction; subjecting the heavy hydrocarbon fraction to solvent deasphalting to at least the deasphalted oil stream and the heavy residual hydrocarbons; and in the first steam-enhanced catalytic cracking unit, subjecting at least the light hydrocarbon fraction to steam-enhanced catalytic cracking to form the light steam-enhanced catalytic cracking product.

[0146] A twelfth aspect may include any one of aspects 1 to eleven, wherein the hydrocarbon oil stream comprises whole crude oil or a crude oil fraction.

[0147] The thirteenth aspect may include any one of the sixth to twelfth 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 delayed coking unit is operated at a temperature of 450°C to 600°C and a pressure of 0.1MPa to 0.4MPa; 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; 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.

[0148] A fourteenth aspect may include any one of aspects one to thirteen, wherein the deasphalted oil stream comprises C1 to C 5+ Hydrocarbons; the heavy residual hydrocarbons contain hydrocarbons C having a boiling point between 426°C and 650°C 5+ Hydrocarbons; the delayed coking unit oil stream contains C1 to C having a boiling point of less than 650°C 5+ Hydrocarbons; and the petroleum coke contains hydrocarbons having a boiling point greater than 650°C.

[0149] A fifteenth aspect may include any one of the first to fourteenth aspects, and may include an integrated system for converting a hydrocarbon oil feedstock using a delayed coking unit and a steam enhanced catalytic cracking 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 comprising at least asphaltenes; a delayed coking unit being fluidly connected to the solvent deasphalting unit and configured to decoke the heavy residual hydrocarbons into at least petroleum coke and a delayed coking unit product stream; and a hydrotreating unit being fluidly connected to the solvent deasphalting unit and the delayed coking unit and configured to hydrotreat at least the deasphalted oil stream and the delayed coking unit product 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+ The hydrocarbon fraction is cracked to form a light steam enhanced catalytic cracking product; and a second steam enhanced catalytic cracking unit, the second steam enhanced catalytic cracking unit is fluidly connected to the hydrotreating unit in parallel with the first steam enhanced catalytic cracking unit and is configured to treat at least a portion of the heavy C5+ The hydrocarbon fraction is cracked to form a heavy steam enhanced catalytic cracking product, and wherein the gas hourly space velocity of steam in the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit is 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).

[0150] The sixteenth aspect may include the fifteenth aspect, further comprising a final product separator, which is fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit, and is configured to separate at least a portion of the light steam enhanced catalytic cracking products and the heavy steam enhanced catalytic cracking products into at least one or more product streams and one or more recycle streams, and wherein: the one or more recycle streams include a methane recycle stream, a steam cracking unit recycle stream, a hydrotreating unit recycle stream, and a delayed coking unit recycle stream; the steam cracking unit recycle stream includes C2-C4 hydrocarbons; the hydrotreating unit recycle stream includes cracked naphtha, light cycle oil, or both; and the delayed coking unit recycle stream includes heavy cycle oil.

[0151] 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 final 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 final 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 stream comprising light olefins, naphtha, and BTX for separation in the final 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 final 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 delayed coker is fluidly connected to the final product separator and is further configured to decoke the delayed coker recycle stream to form additional petroleum coke and a delayed coker product stream; and the final 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, the hydrotreating unit recycle stream to the hydrotreating unit, and the delayed coker recycle stream to the delayed coker.

[0152] The eighteenth aspect may include the seventeenth aspect, further comprising a dehydrogenation unit connected to the hydrotreating unit and the final product separator fluid, and 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 light olefins, naphtha and BTX; the dehydrogenation unit is further configured to send propylene and butenes to the final product separator.

[0153] The nineteenth aspect may include the eighteenth aspect, further comprising a first product separator, the first product separator being fluidly connected to the hydrotreating unit, the methane cracking unit, the steam cracking unit, the first steam enhanced catalytic cracking unit, and the second steam enhanced catalytic cracking unit, and wherein the first product separator is configured to separate the hydrotreated product stream into the C1 hydrocarbon stream for the methane cracking unit; the first product separator is further configured to separate the hydrotreated product stream into the C2-C4 hydrocarbon stream for the steam cracking unit; the first product separator is further configured to separate the hydrotreated product stream into the light C1 hydrocarbon stream for the first steam enhanced catalytic cracking unit. 5+ and the first product separator is further configured to separate the hydroprocessed product stream into heavy C for the second steam enhanced catalytic cracking unit 5+ Hydrocarbon streams.

[0154] The twentieth aspect may include any one of aspects 15 to 19, further comprising a feed separator, the feed separator being fluidly connected to the solvent deasphalting unit and the first steam enhanced catalytic cracking unit and configured to separate the hydrocarbon oil stream into a light oil fraction stream and a heavy oil fraction stream, and wherein: the solvent deasphalting unit is configured to separate the heavy oil fraction into at least the heavy residual hydrocarbons and the deasphalted oil stream; and the first steam enhanced catalytic cracking unit is configured to crack the light oil fraction stream into the light steam enhanced catalytic cracking product.

[0155] 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).

[0156] The twenty-second aspect may include any one of the first to fourteenth aspects, wherein the lightweight C5+ 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.

[0157] 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.

[0158] 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.

[0159] 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.”

[0160] 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.

[0161] The singular forms "a," "an," and "the" include plural referents unless the context clearly dictates otherwise.

[0162] 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.

[0163] 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.

[0164] 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 method for upgrading a hydrocarbon oil feed stream using a delayed coking unit and a steam enhanced catalytic cracking unit, the method 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; delaying coking the heavy residual hydrocarbons to form petroleum coke and a delayed coker product stream; The delayed coker product stream and the deasphalted oil stream are hydrotreated to form light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon streams; 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, benzene, toluene, xylenes, naphtha or a combination thereof; and 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, benzene, toluene, xylenes, naphtha or a combination thereof, 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 related to 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).

2. The process of claim 1, further comprising passing at least a portion of the light steam enhanced catalytic cracking products, the heavy steam enhanced catalytic cracking products, or both to a final product separator to produce one or more product streams and one or more recycle streams, the one or more product streams comprising: a first product stream comprising ethylene, propylene, butenes, or a combination thereof; and A second product stream comprising benzene, toluene, xylenes, or a combination thereof.

3. A method according to any one of the preceding claims, 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.

4. The method according to claim 2 or 3, further comprising: The C1 hydrocarbon stream is subjected to methane cracking to form hydrogen, wherein the delayed coker product stream and the deasphalted oil stream are hydrotreated to further form the 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; steam cracking the C2-C4 hydrocarbon stream to form a steam cracked product stream comprising light olefins, naphtha, and BTX; and The steam cracked product stream is passed to the final separator to produce the one or more product streams and the one or more recycle streams.

5. The method according to any one of claims 2 to 4, wherein: The one or more recycle streams include a methane recycle stream, a steam cracker recycle stream, a hydrotreater recycle stream, and a delayed coker recycle stream, and the method further comprises: subjecting the delayed coker recycle stream to delayed coking to form a further delayed coker product stream, the delayed coker recycle stream comprising a heavy cycle oil having a boiling point between 426°C and 650°C; 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 426°C; subjecting the methane recycle stream to methane cracking to form additional hydrogen; steam cracking the steam cracker recycle stream to form a further steam cracked product stream, the steam cracker recycle stream comprising C2-C4 hydrocarbons; passing hydrogen to the hydroprocessing unit for recycle within the hydroprocessing unit; and The hydroprocessed product stream is transferred to a first product separator to separate the C1 hydrocarbon stream, the C2-C4 hydrocarbon stream, the light C 5+ The hydrocarbon stream and the heavy C 5+ Hydrocarbon streams.

6. The method according to any one of claims 2 to 5, further comprising: First, passing the hydrocarbon oil stream through a feed separator to separate the hydrocarbon oil stream into a heavy hydrocarbon fraction and a light hydrocarbon fraction; 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.

7. The method according to any one of claims 2 to 6, wherein: The hydrocarbon oil stream comprises whole crude oil or a crude oil fraction.

8. The method according to any one of claims 4 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 delayed coking unit operates at a temperature of 450°C to 600°C and a pressure of 0.1 MPa to 0.4 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; and The steam cracking zone operates at a temperature of 800°C to 950°C and a pressure of 0.1 MPa to 0.2 MPa.

9. A method according to any one of the preceding claims, wherein: The deasphalted oil stream contains C1 to C 5+ Hydrocarbons; The heavy residual hydrocarbons include hydrocarbons C having a boiling point between 426°C and 650°C. 5+ Hydrocarbons; The delayed coker oil stream comprises C1 to C2 having a boiling point of less than 650°C. 5+ Hydrocarbons; and The petroleum coke contains hydrocarbons having a boiling point greater than 650°C.

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 hydrocarbon oil feedstock using a delayed coking unit and a steam enhanced catalytic cracking unit, 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 delayed coker fluidly connected to the solvent deasphalting unit and configured to decoke the heavy residual hydrocarbons into at least petroleum coke and a delayed coker product stream; a hydroprocessing unit fluidly connected to the solvent deasphalting unit and the delayed coking unit and configured to hydroprocess at least the deasphalted oil stream and the delayed coking unit product stream to form a light C 5+ Hydrocarbon streams and heavy C 5+ hydrocarbon streams; a first steam enhanced catalytic cracking unit, the first steam enhanced catalytic cracking unit being fluidly connected to the hydrotreating unit and configured to crack at least a portion of the light C 5+ a hydrocarbon fraction to form a light steam enhanced catalytic cracking product comprising olefins, benzene, toluene, xylenes, naphtha or a combination thereof; 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 crack at least a portion of the heavy C 5+ a hydrocarbon fraction to form a heavy steam enhanced catalytic cracking product comprising olefins, benzene, toluene, xylenes, naphtha or a combination thereof, 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).

12. The integrated system of claim 11, further comprising a final product separator, the final product separator being fluidly connected to the first steam enhanced catalytic cracking unit and the second steam enhanced catalytic cracking unit and configured to separate at least a portion of the light steam enhanced catalytic cracking products and the heavy steam enhanced catalytic cracking products into at least one or more product streams and one or more recycle streams, and wherein: The one or more recycle streams include a methane recycle stream, a steam cracker recycle stream, a hydrotreater recycle stream, and a delayed coker recycle stream; The steam cracking unit recycle stream comprises C2-C4 hydrocarbons; The hydrotreater recycle stream comprises cracked naphtha, light cycle oil, or both; and The delayed coker recycle stream comprises heavy cycle oil.

13. The integrated system of claim 12, further comprising: a methane cracking unit fluidly connected to the hydrotreater and the final product separator and configured to crack a C1 hydrocarbon stream, the methane recycle stream, or both to form hydrogen for recycling in the hydrotreater; and a steam cracking unit fluidly connected to the hydrotreating unit and the final product separator and configured to crack a C2-C4 hydrocarbon stream, the steam cracking unit recycle stream, or both to form a steam cracked product stream comprising light olefins, naphtha, and BTX for separation in the final product separator; and wherein, 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 final product separator and is further configured to hydrotreat the hydrotreater recycle stream to produce an additional C1 hydrocarbon stream, C2-C4 hydrocarbon stream, light C 5+ Hydrocarbon stream, heavy C 5+ hydrocarbon streams or combinations thereof; The delayed coker is fluidly connected to the final product separator and is further configured to decoke the delayed coker recycle stream to form additional petroleum coke and a delayed coker product stream; and The final product separator is configured to route the methane recycle stream to the methane cracker, the steam cracker recycle stream to the steam cracker, the hydrotreater recycle stream to the hydrotreater, and the delayed coker recycle stream to the delayed coker.

14. The integrated system of claim 13, further comprising a first product separator, the first product separator being fluidly connected to the hydrotreater, the methane cracker, the steam cracker, the first steam enhanced catalytic cracker, and the second steam enhanced catalytic cracker, and wherein The first product separator is configured to separate the hydroprocessed product stream into the C1 hydrocarbon stream for the methane cracking unit; The first product separator is further configured to separate the hydroprocessed product stream into the C2-C4 hydrocarbon stream for the steam cracking unit; The first product separator is further configured to separate the hydroprocessed product stream into the light C for the first steam enhanced catalytic cracking unit. 5+ hydrocarbon streams; and The first product separator is also configured to separate the hydroprocessed product stream into the heavy C for the second steam enhanced catalytic cracking unit. 5+ Hydrocarbon streams.

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

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