Process for converting whole crude oil to value-added petrochemical products in integrated reactor

Abstract

An integrated process and associated system for converting crude oil to value-added petrochemical products. The process includes separating the crude oil into a light crude oil fraction and a heavy crude oil fraction, and treating the heavy fraction in a solvent deasphalting unit and a delayed coking unit, and then providing the light fraction and the effluent of the selected solvent deasphalting unit and delayed coking unit to a hydrotreatment unit. The method further includes separating the effluent of the hydrotreatment unit to produce a C1 fraction to the methane cracker, a C2-C4 fraction to the steam cracker, a hydrotreated light fraction to the aromatization unit, and a hydrotreated heavy fraction to the steam enhanced catalytic cracking unit. The process also includes separating the effluents of the methane cracker, the steam cracker, the aromatization unit, and the steam-enhanced catalytic cracking unit into a product stream including a BTX stream and a light olefin stream.

Description

[0001] This application claims priority to U.S. patent application serial number 17 / 842,000, filed on June 16, 2022, entitled “CONVERSION OF WHOLE CRUDE OIL INTO VALUE-ADDED PETROCHEMICAL PRODUCTS IN AN INTEGRATED REACTOR PROCESS,” the entire contents of which are incorporated herein by reference. Technical Field

[0002] The present disclosure relates to integrated processes and associated systems for converting crude oil into value-added petrochemical products. Background Art

[0003] Aromatic hydrocarbons, such as BTX (benzene, toluene and xylene) and olefins, are valuable chemicals frequently used in the production of many materials and in the formulation of many consumer products. For example, BTX compounds are frequently used in the processing or production of petroleum products and in the production of consumer products such as paints and varnishes, thinners, fuels, rubber products, adhesives, inks, cosmetics and pharmaceuticals. Similarly, light olefins are the building blocks of many modern plastic products. Therefore, there is a general need to produce light olefins and BTX in large quantities, efficiently and economically.

[0004] Given the current and expected increasing demand for such valuable chemicals, it is desirable to be able to efficiently convert whole crude oil into light olefins and BTX. However, existing refining systems and processes do not maximize the market value of crude oil streams and result in the production of large amounts of unwanted, low-value products in the process of producing light olefins and BTX. Summary of the invention

[0005] Therefore, it has long been clear that there is a need to provide an efficient and economical method for producing light olefins and BTX from a feedstock containing a large amount of whole crude oil. The method and system of the present disclosure meets this clear and long-standing need by optimizing the feedstock provided to each unit operation in the integrated system, thereby utilizing a method and system specifically for producing light olefins and BTX from crude oil. Specifically, the hydrocarbon stream is separated or split, and each fraction is sent to a reactor or other unit operation that can most effectively convert the feed provided to the reactor into BTX or light olefins or precursor chemicals to form BTX or light olefins.

[0006] According to one or more embodiments of the present disclosure, an integrated method for converting crude oil into value-added petrochemical products is disclosed. The method includes (i) providing a hydrocarbon stream containing crude oil to a feed separator to separate the hydrocarbon stream into a light crude oil fraction boiling at a first temperature or lower and a heavy crude oil fraction boiling at a temperature higher than the first temperature, wherein the first temperature is between 190°C and 210°C; (ii) providing the heavy crude oil fraction boiling at a temperature higher than the first temperature from the feed separator to a solvent deasphalting unit, wherein residual oil heavy components and asphaltene having a boiling point higher than 300°C are removed from the heavy crude oil fraction to generate an asphalt product containing asphaltene and residual oil heavy components and a deasphalted oil product; (iii) providing the asphalt product to a delayed coking unit, wherein the asphalt product undergoes a thermal cracking reaction to obtain a solid (iv) providing a light crude oil fraction, a deasphalted oil product, and a delayed coking product stream boiling at a first temperature or lower to a hydroprocessor, wherein the light crude oil fraction, the deasphalted oil product, and the delayed coking product stream are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds, thereby generating a hydroprocessor product stream; (v) providing the hydroprocessor product stream to a first separator unit, wherein the hydroprocessor product stream is separated into a C1 fraction, a C2-C4 fraction, a hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature, and a hydrotreated light fraction comprising hydrocarbons boiling at the second temperature. (vi) providing the C1 fraction to a methane cracker, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (vii) providing the C2-C4 fraction to a steam cracker, wherein the C2-C4 fraction is cracked to produce a steam cracker product stream comprising light olefins and aromatics; (viii) providing the hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature to an aromatization unit, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction into aromatic hydrocarbons to produce an aromatization product stream; (ix) providing the C1 fraction to a methane cracker, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (vii) providing the C2-C4 fraction to a steam cracker, wherein the C2-C4 fraction is cracked to produce a steam cracker product stream comprising light olefins and aromatics; (viii) providing the hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature to an aromatization unit, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction into aromatic hydrocarbons to produce an aromatization product stream; (x) providing the steam cracker product stream, the aromatization product stream, and the SECC product stream to a second separator unit, wherein the second separator unit separates the steam cracker product stream, the aromatization product stream, and the SECC product stream into a hydrogen fraction, a C1 stream, a C2-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylenes, and a residual stream comprising cracked naphtha, light cycle oil, and heavy cycle oil, wherein the hydrogen fraction and the C1 stream can be a single combined stream.

[0007] In additional embodiments, one or more of the hydrogen fraction, the C1 stream, the C2-C4 alkane stream, and the residual stream may be recycled as a feed stream to one or more of the unit operations within the integrated process for further processing.

[0008] According to one or more embodiments of the present disclosure, an integrated system for converting crude oil into value-added petrochemical products is disclosed. The system includes (i) a feed separator for separating a hydrocarbon stream containing crude oil into a light crude oil fraction boiling at a first temperature or lower and a heavy crude oil fraction boiling at a temperature higher than the first temperature, wherein the first temperature is between 190°C and 210°C; (ii) a solvent deasphalting unit, which is fluidly connected to the feed separator to receive the heavy crude oil fraction boiling at a temperature higher than the first temperature from the feed separator, wherein residual oil heavy components and asphaltene having a boiling point higher than 300°C are removed from the heavy crude oil fraction to generate an asphalt product and a deasphalted oil product containing asphaltene and residual oil heavy components; (iii) a delayed coking unit; (iv) a hydroprocessor fluidly connected to the feed separator, the solvent deasphalting unit and the delayed coking unit to receive a light crude oil fraction boiling at a first temperature or lower, a deasphalted oil product and a delayed coking product stream, wherein the light crude oil fraction, the deasphalted oil product and the delayed coking product stream are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds, thereby generating a hydroprocessor product stream; and (v) a hydroprocessor fluidly connected to the feed separator, the solvent deasphalting unit and the delayed coking unit to receive a light crude oil fraction boiling at a first temperature or lower, a deasphalted oil product and a delayed coking product stream. a separator unit fluidly connected to the hydroprocessor to receive the hydroprocessor product stream, wherein the hydroprocessor product stream is separated into a C1 fraction, a C2-C4 fraction, a hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature below a second temperature, and a hydrotreated heavy fraction comprising hydrocarbons boiling at a second temperature or above, wherein the second temperature is between 200° C. and 215° C.; (vi) a methane cracker fluidly connected to the first separator unit to receive the C1 fraction, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (vii) a steam cracker fluidly connected to the first a steam-enhanced catalytic cracking unit fluidly connected to the first separator to receive a hydrotreated heavy fraction comprising hydrocarbons boiling at a second temperature or above, wherein the hydrotreated heavy fraction is cracked to generate a SECC product stream comprising light olefins and aromatic hydrocarbons; (viii) an aromatization unit fluidly connected to the first separator to receive the hydrotreated light fraction, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction into aromatic hydrocarbons to generate an aromatized product stream; (ix) a steam-enhanced catalytic cracking unit fluidly connected to the first separator to receive a hydrotreated heavy fraction comprising hydrocarbons boiling at a second temperature or above, wherein the hydrotreated heavy fraction is cracked to generate a SECC product stream comprising light olefins;and (x) a second separator fluidly connected to the steam cracker, the aromatization unit and the steam enhanced catalytic cracking unit to receive the steam cracker product stream, the aromatization product stream and the SECC product stream, wherein the second separator unit separates the steam cracker product stream, the aromatization product stream and the SECC product stream into a hydrogen fraction, a C1 stream, a C2-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene and xylenes, and a residual stream comprising cracked naphtha, light cycle oil and heavy cycle oil.;

[0009] In additional embodiments, one or more of the hydrogen fraction, the C1 stream, the C2-C4 alkane stream, and the residual stream may be recycled as a feed stream to one or more of the unit operations within the integrated system for further processing.

[0010] Additional features and advantages of the described embodiments will be set forth in the following detailed description. Additional features and advantages of the described embodiments will be apparent to those skilled in the art in part from this description, or will be learned by practicing the described embodiments, including the following detailed description, as well as the accompanying drawings and claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0011] 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:

[0012] Figure 1 is a schematic diagram of one or more embodiments of an integrated refinery process of the present disclosure including an aromatization reactor; and

[0013] Figure 2 is a schematic diagram of one or more embodiments of an integrated refinery process of the present disclosure that includes recycling one or more product streams as additional feed to one or more unit operations of the integrated refinery process; and

[0014] Figure 3 yes Figure 2 Schematic diagram of an integrated refining process where optional additional streams are separated into separate unit operations.

[0015] For the sake of simplicity of these schematic diagrams and this description, many valves, temperature sensors, electronic controllers, etc., which are commonly used and known to one of ordinary skill in the art of certain refining operations are not included. In addition, attendant components in conventional refining operations, such as air supply, hydrogen supply, catalyst hoppers, and flue gas handling, are not necessarily shown.

[0016] It should also be noted that the arrows in the drawings refer to pipes, conduits, channels or other physical transport lines that connect one or more system devices to one or more other system devices through fluid communication. In addition, the arrows connected to the system devices define the inlets and outlets in each given system device.

[0017] 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

[0018] Reference will now be made in detail to embodiments of the integrated process and associated systems of the present disclosure for converting crude oil into value-added petrochemical products. Figures 1 to 3 The system for converting crude oil into value-added petrochemical products is provided as an example, but it should be understood that the system and method include other configurations.

[0019] The method and system of the present disclosure provide an integrated method and system for converting crude oil into value-added products, mainly light olefins and BTX (benzene, toluene and xylene). Specifically, the method and system of the present disclosure separate crude oil into a C1 fraction, a C2-C4 fraction, a light liquid fraction and a heavy liquid fraction, which can then be cracked in an appropriate reactor, such as a methane cracker, a steam cracker, an aromatization unit or a steam enhanced catalytic cracking unit to maximize the yield of petrochemical products. In this way, the integrated system and method increase the yield of light olefins and BTX.

[0020] In one or more embodiments, an integrated process for converting crude oil into value-added petrochemical products includes providing a hydrocarbon stream 110 comprising crude oil to a feed separator 10 to separate the hydrocarbon stream 110 into a light crude oil fraction 120 boiling at a first temperature or lower and a heavy crude oil fraction 130 boiling at a temperature higher than the first temperature, wherein the first temperature is between 190° C. and 210° C. The integrated process also includes providing the heavy crude oil fraction 130 from the feed separator 10 to a solvent deasphalting unit 20, wherein a residua heavy component having a boiling point higher than 300° C. and asphaltenes are removed from the heavy crude oil fraction to generate an asphalt product 140 comprising asphaltene and residua heavy components and a deasphalted oil product 150. The asphalt product 140 is then provided to a delayed coking unit 30, wherein the asphalt product 140 undergoes a thermal cracking reaction to obtain a solid petroleum coke 170 and a delayed coking product stream 160 comprising C1-C4 light gas, coker naphtha, and coker gas oil. The light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking product stream 160 are then provided to the hydroprocessor 40, wherein the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking product stream 160 are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds, thereby generating a hydroprocessor product stream 180. The hydroprocessor product stream 180 is then provided to the first separator unit 50, wherein the hydroprocessor product stream 180 is separated into a C1 fraction 190, a C2-C4 fraction 200, a hydrotreated light fraction 210 containing C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature, and a hydrotreated heavy fraction 220 containing hydrocarbons boiling at or above the second temperature, wherein the second temperature is between 200° C. and 215° C. The C1 fraction 190 is provided to the methane cracker 60, wherein the C1 fraction 190 is converted into a hydrogen stream 230 and a fixed carbon stream 240. The C2-C4 fraction 200 is provided to the steam cracker 70, wherein the C2-C4 fraction 200 is cracked to generate a steam cracker product stream 250 comprising light olefins and aromatic hydrocarbons. The hydrotreated light fraction 210 is provided to the aromatization unit 80, wherein the aromatization unit 80 converts aliphatic hydrocarbons in the hydrotreated light fraction 210 into aromatic hydrocarbons to generate an aromatized product stream 260. The hydrotreated heavy fraction 220 comprising hydrocarbons boiling at the second temperature or higher is provided to the steam enhanced catalytic cracking unit 90, wherein the hydrotreated heavy fraction 220 is cracked to generate a SECC product stream 270 comprising light olefins.The steam cracker product stream 250, the aromatization product stream 260, and the SECC product stream 270 are provided to the second separator unit 100, wherein the second separator unit 100 separates the steam cracker product stream 250, the aromatization product stream 260, and the SECC product stream 270 into a hydrogen fraction 280, a C1 stream 290, a C2-C4 alkane stream 300, a light olefin stream 310, a BTX stream 320 comprising benzene, toluene, and xylene, and a residual stream 330 comprising cracked naphtha, light cycle oil, and heavy cycle oil.

[0021] In one or more embodiments, an integrated system for converting crude oil into value-added petrochemical products includes a feed separator 10 for separating a hydrocarbon stream 110 comprising crude oil into a light crude oil fraction 120 boiling at a first temperature or lower and a heavy crude oil fraction 130 boiling at a temperature higher than the first temperature, wherein the first temperature is between 190° C. and 210° C. A solvent deasphalting unit 20 is fluidly connected to the feed separator 10 to receive the heavy crude oil fraction 130, wherein resid heavy components having a boiling point higher than 300° C. and asphaltenes are removed from the heavy crude oil fraction 130 to generate an asphalt product 140 comprising asphaltene and resid heavy components and a deasphalted oil product 150. A delayed coking unit 30 is fluidly connected to the solvent deasphalting unit 20 to receive the asphalt product 140, wherein the asphalt product 140 undergoes a thermal cracking reaction to obtain a solid petroleum coke 170 and a delayed coking product stream 160 comprising C1-C4 light gas, coker naphtha, and coker gas oil. The hydroprocessor 40 is fluidly connected to the feed separator 10, the solvent deasphalting unit 20, and the delayed coking unit 30 to receive the light crude oil fraction 120 boiling at a first temperature or lower, the deasphalted oil product 150, and the delayed coking product stream 160, wherein the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking product stream 160 are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds to generate a hydroprocessor product stream 180. The first separator unit 50 is fluidly connected to the hydroprocessor 40 to receive the hydroprocessor product stream 180, wherein the hydroprocessor product stream 180 is separated into a C1 fraction 190, a C2-C4 fraction 200, a hydrotreated light fraction 210 containing C5 hydrocarbons to hydrocarbons boiling at a temperature lower than a second temperature, and a hydrotreated heavy fraction 220 containing hydrocarbons boiling at a second temperature or higher, wherein the second temperature is between 200° C. and 215° C. The methane cracker 60 is fluidly connected to the first separator unit 50 to receive the C1 fraction 190, wherein the C1 fraction 190 is converted into a hydrogen stream 230 and a fixed carbon stream 240. The steam cracker 70 is fluidly connected to the first separator 50 to receive the C2-C4 fraction 200, wherein the C2-C4 fraction 200 is cracked to generate a steam cracker product stream 250 comprising light olefins and aromatics. The aromatization unit 80 is fluidly connected to the first separator 50 to receive the hydrotreated light fraction 210, wherein the aromatization unit 80 converts aliphatic hydrocarbons in the hydrotreated light fraction 210 into aromatics to generate an aromatized product stream 260. The steam enhanced catalytic cracking unit 90 is fluidly connected to the first separator 50 to receive the hydrotreated heavy fraction 220 comprising hydrocarbons boiling at a second temperature or higher, wherein the hydrotreated heavy fraction 220 is cracked to generate a SECC product stream 270 comprising light olefins.The second separator unit 100 is fluidly connected to the steam cracker 70, the aromatization unit 80 and the steam enhanced catalytic cracking unit 90 to receive the steam cracker product stream 250, the aromatization product stream 260 and the SECC product stream 270, wherein the second separator unit 100 separates the steam cracker product stream 250, the aromatization product stream 260 and the SECC product stream 270 into a hydrogen fraction 280, a C1 stream 290, a C2-C4 alkane stream 300, a light olefin stream 310, a BTX stream 320 comprising benzene, toluene and xylene, and a residual stream 330 comprising cracked naphtha, light cycle oil and heavy cycle oil.

[0022] Having disclosed the basic operations of an integrated process and associated system for converting crude oil to value-added petrochemical products, each step and unit operation of an embodiment of the integrated process and associated system is now provided in more detail.

[0023] Hydrocarbon feed stream

[0024] The hydrocarbon stream 110 comprises crude oil. In various embodiments and with reference to Figures 1 to 3 The crude oil in the hydrocarbon stream 110 may be Arabian Extra Light (AXL), Arabian Light (AL), Arabian Heavy (AH), atmospheric residue, or a combination thereof.

[0025] Feed separator

[0026] In one or more embodiments and with reference to Figures 1 to 3 , a hydrocarbon stream 110 including crude oil is provided to a feed separator 10 to separate the hydrocarbon stream 110 into a light crude oil fraction 120 boiling at a first temperature or lower and a heavy crude oil fraction 130 boiling at a temperature higher than the first temperature. In various embodiments, the first temperature may be between 190° C. and 210° C., between 195° C. and 205° C., between 198° C. and 202° C., or about 200° C.

[0027] The feed separator 10 can be any unit configured to separate the hydrocarbon stream 110 into a light crude oil fraction 120 boiling at a temperature of 200° C. or lower and a heavy crude oil fraction 130 boiling at a temperature above 200° C. In one or more embodiments, the feed separator 10 is a flash tank. The flash tank operates based on the principle of flash evaporation, which refers to the process in which liquid hydrocarbons are immediately converted into steam when moving from high pressure to low pressure, thereby allowing the feed of liquid hydrocarbons to be separated. The flash tank can operate at a temperature range of 200° C. to 500° C. and at an appropriate pressure to separate into the light crude oil fraction 120 and the heavy crude oil fraction 130.

[0028] Solvent Deasphalting Unit

[0029] In one or more embodiments, the heavy crude oil fraction 130 boiling at a temperature above the first temperature is provided from the feed separator 10 to the solvent deasphalting unit 20. Figures 1 to 3 , the solvent deasphalting unit 20 is fluidly connected to the feed separator 10. The solvent deasphalting unit 20 removes the residual oil heavy components and asphaltenes having a boiling point above 300° C. from the heavy crude oil fraction 130 to generate an asphalt product 140 comprising asphaltenes and residual oil heavy components. The resulting stream generated by removing the asphaltene and residual oil heavy components is a deasphalted oil product 150.

[0030] It should be understood that solvent deasphalting performed in the solvent deasphalting unit 20 is a separation process in which certain components are selectively separated by molecular type by mixing them with a paraffinic solvent and precipitating asphaltenes and other resid heavy components from the solution. The solvent deasphalting unit 20 separates the asphalt product 140 containing asphaltenes and resid heavy components from the feedstock of the heavy crude oil fraction 130 because light hydrocarbons can act as a solvent to dissolve aliphatic compounds but cannot dissolve asphaltenes.

[0031] In various embodiments, the solvent utilized in the solvent deasphalting unit 20 may be propane, butane, or pentane. The choice of light hydrocarbon solvent affects the yield and quality of the resulting deasphalted oil product 150. For example, the use of propane in the solvent deasphalting unit 20 produces a deasphalted oil product 150 of higher quality but lower yield than the use of pentane, which may double or triple the yield at the expense of lower quality due to greater residual contamination from metal and carbon residues.

[0032] Various process parameters suitable for operating the solvent deasphalting unit 20 are contemplated. For example, the solvent deasphalting unit 20 can be operated at a pressure and temperature below the solvent critical pressure and temperature of the solvent used. In addition, the yield of the asphalt product 140 and the deasphalted oil product 150 containing asphaltene and resid heavy components can be adjusted by changing the ratio of the solvent and the heavy crude oil fraction 130 provided to the solvent deasphalting unit 20. In one or more embodiments, the weight ratio of the solvent to the heavy crude oil fraction 130 is 2 to 20, or 5 to 10, or 6 to 8. In addition, in one or more embodiments, the solvent deasphalting unit 20 is operated at a temperature range of 120° C. to 160° C. and a pressure range of 1 bar to 40 bar.

[0033] It will be appreciated that during steady state operation, when both the solvent composition and the extraction pressure are fixed, the yield and quality of the various products recovered in the solvent deasphalting unit 20 are controlled by adjusting its operating temperature. Increasing the extraction temperature reduces the solubility of the heavier components of the feedstock, which results in an increase in quality, but a decrease in the yield of the deasphalted oil product 150. Subsequent increases in the extractor temperature can further improve the quality of the deasphalted oil product 150 by causing further rejection of the asphaltene components. However, it will be appreciated that when the temperature changes rapidly, especially near the critical region, it may become difficult to control the process because the rate of change of solubility is very high under conditions close to the critical point. For practical applications, the lower operating temperature limit is set by the viscosity of the asphaltene phase, and the upper limit is set to remain below the critical temperature while maintaining the desired yield of the deasphalted oil product 150 and stable operation.

[0034] In one or more embodiments, the solvent deasphalting unit 20 additionally removes metals from the heavy crude fraction 130. The solvent deasphalting process results in metal-containing hydrocarbons of the process stream that ultimately combine with asphaltenes and resid heavy components in the asphalt product 140 of the solvent deasphalting unit 20. U.S. Patent No. 7,566,394, incorporated by reference, teaches details of the solvent deasphalting process.

[0035] The deasphalting performed in the deasphalting unit 20 produces a deasphalted oil product 150, which removes many of the contaminants present in the heavy crude fraction 130. Most of the contaminants present in the heavy crude fraction 130 are removed as part of the asphalt product 140. These contaminants include metal contaminants such as Ni and V, nitrates, sulfonates, and oxygenates.

[0036] Delayed coking unit

[0037] In one or more embodiments, the asphalt product 140 from the solvent deasphalting unit 20 is provided to the delayed coking unit 30. Figures 1 to 3 , the delayed coking unit 30 is fluidly connected to the solvent deasphalting unit 20. Within the delayed coking unit 30, the asphalt product 140 undergoes a thermal cracking reaction to obtain solid petroleum coke 170 and a delayed coking product stream 160. The delayed coking product stream 160 includes C1-C4 light gas, coker naphtha and coker gas oil. Specifically, the delayed coking unit 30 operates by heating the asphalt product 140 provided as a feed stream to a thermal cracking temperature in a furnace having multiple parallel passes. This heating cracks the heavy long-chain hydrocarbon molecules of the asphalt product 140, the solid petroleum coke 170 and the various components of the delayed coking product stream 160.

[0038] In one or more embodiments, the delayed coking product stream 160 is divided into a first delayed coking product stream 162 and a second delayed coking product stream 164. The second delayed coking product stream 164 includes C5 hydrocarbons to hydrocarbons boiling at 343°C from the delayed coking product stream 60, and the first delayed coking product stream 162 includes the remaining portion of the delayed coking product stream in the first delayed coking product stream.

[0039] In one or more embodiments, the coke drum in the delayed coking unit operates at a temperature range of 470° C. to 505° C. and a pressure range of 1 bar to 2 bar to process the asphalt product 140 from the solvent deasphalting unit 20 .

[0040] The delayed coking unit 30 may include at least two parallel drums operating in a swing mode. When one coke drum is full of coke, the feed of the pitch product 140 is switched to a new empty drum and the full drum is cooled. It should be understood that various inlet valves and outlet valves may be provided to control the inflow and outflow of the delayed coking unit 30. The coke remaining in the drum is typically cooled with water and then removed from the coke drum by conventional methods, such as using hydraulic or mechanical techniques or both, thereby expelling the solid coke from the drum wall for recovery as solid petroleum coke 170.

[0041] Hydroprocessor

[0042] In one or more embodiments, the light crude oil fraction 120 from the feed separator 10, the deasphalted oil product 150 from the solvent deasphalting unit 20, and the delayed coking product stream 160 from the delayed coking unit 30 are provided to the hydroprocessor 40. Figure 1 and Figure 2 , the hydroprocessor 40 is fluidly connected to the solvent deasphalting unit 20. In one or more embodiments and with reference to Figure 3 , the first delayed coking product stream 162 is provided to the hydroprocessor in place of the delayed coking product stream 160. In the hydroprocessor 40, the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking product stream 160 are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds, thereby generating a hydroprocessor product stream 180. It should be understood that the hydroprocessing performed in the hydroprocessor 40 is a reaction of organic compounds in the presence of high-pressure hydrogen to remove oxygen and other heteroatoms such as nitrogen, sulfur, and chlorine by saturating the carbon-carbon bonds of the organic compounds in the feed stream.

[0043] The carbon-carbon bonds of hydrocarbons in the light crude fraction 120, the deasphalted oil product 150, and the delayed coking product stream 160 are saturated to remove heteroatoms such as nitrogen, sulfur, and chlorine by generating ammonia, hydrogen sulfide, and HCl, respectively, which can be separated in the hydroprocessor waste stream 182. In one or more embodiments, the hydroprocessor product stream 180 leaving the hydroprocessor 40 contains less than 800 ppm nitrogen and less than 900 ppm sulfur. In various further embodiments, the hydroprocessor product stream 180 contains less than 750 ppm nitrogen, less than 650 ppm nitrogen, less than 550 ppm nitrogen, less than 500 ppm nitrogen, or 370 to 750 ppm nitrogen. In various embodiments, the hydroprocessor product stream 180 contains less than 850 ppm sulfur, less than 750 ppm sulfur, less than 500 ppm sulfur, less than 300 ppm sulfur, or 150 to 820 ppm sulfur.

[0044] The operation of the hydrotreater 40 includes mixing the feed streams of the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking product stream 160 with hydrogen, heating and pressurizing the resulting mixture, and passing it over a catalyst to convert sulfur-containing compounds to hydrogen sulfide and desulfurized hydrocarbons, nitrogen-containing compounds to ammonia and denitrogenated hydrocarbons, and chlorine-containing compounds to HCl and dechlorinated compounds. In one or more embodiments, the hydrotreater 40 can include a CoMo / alumina or NiMo / alumina catalyst.

[0045] In one or more embodiments, the hydroprocessor 30 can be operated at a temperature range of 280°C to 450°C. In one or more embodiments, the hydroprocessor 30 can be operated at a pressure range of 5 bar to 160 bar, with hydrogen introduced through a hydrogen inlet. In various further embodiments, the hydroprocessor 40 can be operated at a temperature range of 280°C to 425°C, 280°C to 400°C, or 280°C to 350°C and a pressure range of 5 bar to 100 bar, 5 bar to 50 bar, 20 bar to 160 bar, 20 bar to 100 bar, or 20 bar to 50 bar. In one or more embodiments, the hydroprocessor 30 can be operated at a pressure range of 1 to 10 h. -1 The hydrocarbon space velocity is operated.

[0046] First separator unit

[0047] In one or more embodiments, the hydroprocessor product stream 180 from the hydroprocessor 40 is provided to the first separator unit 50. As such and with reference to Figures 1 to 3, the first separator unit 50 is fluidly connected to the hydroprocessor 40. The first separator unit 50 separates the hydroprocessor product stream 180 into a C1 fraction 190, a C2-C4 fraction 200, a hydrotreated light fraction 210 comprising C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature, and a hydrotreated heavy fraction 220 comprising hydrocarbons boiling at the second temperature or higher. In various embodiments, the second temperature may be between 200°C and 215°C, between 200°C and 210°C, between 204°C and 210°C, about 204°C, or about 210°C.

[0048] The first separator unit 50 may include any unit operation or system known to those skilled in the art for separating hydrocarbon streams by vapor pressure. An example first separator unit 50 is an atmospheric distillation unit. An atmospheric distillation unit separates a feed stream by fractional distillation by heating the feed to a temperature at which one or more fractions of the mixture will evaporate while leaving other fractions as liquids. Additionally, in various embodiments, the first separator unit 50 may be a simple flash column or a true boiling point distillation having at least 15 theoretical plates.

[0049] In one or more embodiments, the first separator unit 50 includes a plurality of separation units. For ease of illustration, the provided figures show a single unit operation, but it is understood that such a unit operation can include multiple individual separator units to generate the disclosed product streams.

[0050] Methane cracker

[0051] In one or more embodiments, the C1 fraction 190 from the first separator unit 50 is provided to the methane cracker 60. Figures 1 to 3 , the methane cracker 60 is fluidly connected to the first separator unit 50. In the methane cracker 60, the C1 fraction 190 is converted into a hydrogen gas stream 230 and a fixed carbon stream 240. Specifically, the methane cracker 60 is operated in the following manner: the C1 fraction 190 provided as a feed stream from the first separator unit 50 is heated to decompose methane into hydrogen forming the hydrogen gas stream 230 and carbon forming the fixed carbon stream 240.

[0052] Methane cracking is an endothermic reaction that occurs at high temperatures, and according to thermodynamics, once the temperature reaches 300° C., methane theoretically begins to decompose into solid carbon particles and H2 gas without any catalyst. However, due to kinetic limitations and the high activation energy required to break the stable CH bonds of methane molecules, non-catalytic thermal decomposition of methane cannot achieve reasonable yields below about 1200° C. Thus, in one or more embodiments, a methane cracking catalyst is utilized in the methane cracker 60 to reduce the activation energy for breaking the CH bonds. Catalytic methane decomposition achieves reasonable yields at temperatures as low as 700° C.

[0053] In various embodiments, the methane cracking catalyst utilized in the methane cracker 60 is a nickel-based, cobalt-based or iron-based catalyst. Such catalysts are ideal due to their low cost and availability. In addition, in one or more embodiments, carriers and promoters may be added to the metal catalyst to enhance its catalytic performance. Commonly used carriers are Al2O3, MgO and SiO2. In various embodiments, the methane cracking catalyst utilized in the methane cracker 60 is Ni / CeO2, NiLa2O3, Ni / SiO2, Fe / CeO2, Fe / La2O3, Fe / SiO2, Ni / SiO2, Fe / SiO2, Co / SiO2, Ni / Mg-O-Al, Rh / Al2O3 or Rh / Al2O3-10wt% Nd2O3.

[0054] In one or more embodiments, the methane cracker 60 operates at a temperature range of 700°C to 1200°C.

[0055] Steam cracker

[0056] In one or more embodiments, the C2-C4 fraction 200 from the first separator unit 50 is provided to the steam cracker 70. Figures 1 to 3 , the steam cracker 70 fluid is connected to the first separator unit 50. In the steam cracker 70, the C2-C4 fraction 200 is cracked to generate a steam cracker product stream 250 containing light olefins and aromatics. In general, steam cracking is a petrochemical process in which saturated hydrocarbons are decomposed into smaller hydrocarbons that are usually unsaturated. In operation, the C2-C4 fraction 200 is diluted with steam and briefly heated in the furnace of the steam cracker 70 in the absence of oxygen. The reaction occurs rapidly in a residence time of about a few milliseconds, and after reaching the cracking temperature, the flow is quickly quenched to stop the cracking reaction. Specifically, the steam cracker 70 is operated by heating the C2-C4 fraction 200 provided as a feed stream from the first separator unit 50 with steam to thermally crack the saturated hydrocarbons of the C2-C4 fraction 200 into light olefins. For the purpose of this disclosure, light olefins are considered to be C2-C4 olefins, including ethylene, propylene and butene.

[0057] In one or more embodiments, the steam cracker 70 operates at a temperature range of 800° C. to 950° C. It will be appreciated that higher cracking temperatures (also referred to as severities) favor the production of shorter chain hydrocarbons as greater cracking occurs compared to lower severity operations.

[0058] In one or more embodiments, the steam cracker 70 operates at a steam to hydrocarbon ratio in the range of 0.2 to 0.8. It should be understood that the steam to hydrocarbon ratio represents the ratio of hydrocarbons provided in the C2-C4 fraction 200 from the first separator unit 50 to steam simultaneously provided to the steam cracker 70. In addition, it should be noted that lighter feeds generally utilize smaller steam to hydrocarbon ratios than heavier feeds.

[0059] Table 1, shown below, provides generalized steam cracker yields generated based on the composition of the feed stream to the steam cracker 70. The yields of ethane, propane, and butane, which represent the major consistency components of the C2-C4 fraction 200, as well as the yields of naphtha and light oil, which may be provided in small amounts in the C2-C4 fraction 200 due to imperfect separation in the first separator unit 50, are provided, expressed as weight percent.

[0060] Table 1: Theoretical steam cracker yields for various feedstocks

[0061]

[0062]

[0063] Aromatization unit

[0064] In one or more embodiments, the hydrotreated light fraction 210 comprising C5 hydrocarbons to hydrocarbons boiling at a temperature below the second temperature is provided to the aromatization unit 80. Figures 1 to 3 , the aromatization unit 80 is fluidly connected to the first separator unit 50. In the aromatization unit 80, the aliphatic hydrocarbons in the hydrotreated light fraction 210 are converted into aromatic hydrocarbons to generate an aromatized product stream 260 through a dehydrogenation and dehydrocyclization process. The aromatization unit 80 includes at least one aromatization reactor having an aromatization catalyst disposed therein, which is used to generate a liquid product stream having an increased aromatic content in the form of the aromatized product stream 260.

[0065] According to various embodiments, the aromatization catalyst may include a metal oxide component dispersed on the surface of the zeolite carrier. The metal oxide component may include one or more oxides of metal elements selected from the 4th to 13th groups of the International Union of Pure and Applied Chemistry (IUPAC) periodic table (e.g., the 8th to 13th groups of the IUPAC periodic table). In one or more embodiments, the metal element of one or more metal oxides may be a metal element selected from the 4th to 13th groups of the IUPAC periodic table and the 4th to 6th periods (e.g., the 4th period of the periodic table). The metal element of the metal oxide may include, but is not limited to, titanium, vanadium, chromium, manganese, iron, cobalt, nickel, copper, zinc, gallium, molybdenum, palladium, silver, hafnium, tungsten, platinum, gold, or a combination of these metal elements. In one or more embodiments, the metal element of one or more metal oxides may include gallium, zinc, iron, hafnium, or a combination of these metals. In one or more embodiments, the metal oxide may be gallium oxide.

[0066] In one or more embodiments, the aromatization catalyst may include a gallium-modified H-MFI zeolite. Specifically, the aromatization catalyst may include a catalyst formed by gallium incorporated into the H-MFI zeolite. Based on the total catalyst, this catalyst may include 1 to 5 wt% of gallium (Ga). For example, in various embodiments, the gallium-modified H-MFI zeolite catalyst may include 1 to 4 wt% of gallium, 1 to 3 wt% of gallium, 1.5 to 2.5 wt% of gallium, 1.8 to 2.2 wt% of gallium, or about 2 wt% of gallium. It should be understood that it is also possible to envision integrating gallium in other proportions within the widest range, but for the sake of brevity, it is not explicitly described. As previously mentioned, in various embodiments, gallium may be substituted with an alternative metal element while maintaining the remaining parameters of the disclosed gallium-modified H-MFI zeolite. In various embodiments, the ratio of silica to alumina of the H-MFI zeolite may be 20 to 100, 20 to 80, 20 to 50, or 20 to 30.

[0067] In one or more embodiments, the hydrotreated light fraction 210 from the first separator unit 50 is heated to 0.1 to 10 h. -1 The aromatization unit 80 is provided with a liquid hourly space velocity (LHSV) of 0.1 to 8 h. -1 , 0.3 to 10h -1 , 0.5 to 5 hours -1 , 0.8 to 3h -1 , 0.8 to 2h -1 or about 1h -1 The LHSV of is provided to the aromatization unit 80. It will be appreciated that a larger LHSV results in a lower aromatics yield, while a smaller LHSV favors the formation of less desirable heavy aromatics.

[0068] In one or more embodiments, the aromatization unit 80 can operate at a reaction temperature of 400° C. to 600° C. In various embodiments, the aromatization unit 80 can operate at a reaction temperature of 400° C. to 550° C., 425° C. to 550° C., 450° C. to 600° C., or 450° C. to 550° C. It should be understood that lower temperatures result in less conversion, while higher temperatures result in faster catalyst deactivation.

[0069] In one or more embodiments, the aromatization unit 80 can operate at a pressure range of 1 bar to 35 bar, 5 bar to 35 bar, or 10 bar to 35 bar. It should be understood that lower pressures favor the aromatization reaction, but a minimum level of positive pressure is required for practical operation.

[0070] Steam Enhanced Catalytic Cracking Unit

[0071] In one or more embodiments, the hydrotreated heavy fraction 220 comprising hydrocarbons boiling at or above the second temperature from the first separator unit 50 is provided to the steam enhanced catalytic cracking unit 90. Figure 1 and Figure 2 , the steam enhanced catalytic cracking unit 90 is fluidly connected to the first separator unit 50. Within the steam enhanced catalytic cracking unit 90, the hydrotreated heavy fraction 220 is cracked to generate a SECC product stream 270 comprising light olefins. In one or more embodiments, the deasphalted oil product 150, the second delayed coking product stream 164, or both are additionally provided to the steam enhanced catalytic cracking unit 90 to generate a combined SECC feed stream 222. As such and with reference to Figure 3 , the steam enhanced catalytic cracking unit 90 may be fluidly connected to the solvent deasphalting unit 20, the delayed coking unit 30, or both.

[0072] Catalytic cracking is a known conversion process for oil refineries, and is used to convert high boiling point, high molecular weight hydrocarbon fractions of petroleum crude oil or other hydrocarbon streams into more valuable gasoline, olefinic gases and other products. Similarly, steam cracking is a known conversion process for oil refineries, in which gaseous or liquid hydrocarbon feeds such as naphtha are diluted with steam and briefly heated in a furnace without oxygen to crack saturated hydrocarbons into smaller hydrocarbons that are usually unsaturated, such as olefins. The process according to the present disclosure is steam enhanced catalytic cracking, which combines the benefits of catalytic cracking and steam cracking to maximize the production of light olefins. Specifically, it should be noted that the difference between the steam enhanced catalytic cracking unit 90 and the traditional fluidized catalytic cracking reactor is that they operate in a higher temperature range and also include more steam content in the feed. Excess steam and higher temperatures convert the feed hydrocarbons of the hydroprocessing heavy fraction 220 into relatively more light olefins, such as ethylene and propylene. It should be particularly noted that the steam enhanced catalytic cracking process carried out in the steam enhanced catalytic cracking unit 90 allows heavy streams, such as the hydrotreated heavy fraction 220, to be efficiently cracked into light olefins.

[0073] The steam enhanced catalytic cracking unit 90 can be operated as a fluidized bed reactor, a fixed bed reactor, or a moving bed reactor. In one or more specific embodiments, the steam enhanced catalytic cracking unit 90 can include a fluidized bed reactor in the form of a riser reactor or a downer reactor to convert the hydrotreated heavy fraction 220 into a SECC product stream 270 containing light olefins having carbon atoms of C2-C4. As used herein, the term "downer" refers to a catalytic cracking reactor, such as a fluidized bed reactor, in which the reactants flow in a generally downward direction, such as entering the top of the reactor and leaving the bottom of the reactor. Similarly, the term "riser" refers to a catalytic cracking reactor, such as a fluidized bed reactor, in which the reactants flow in a generally upward direction, such as entering the bottom of the reactor and leaving the top of the reactor.

[0074] In one or more embodiments, since the steam enhanced catalytic cracking unit 90 utilizes a steam enhanced cracking catalyst, the steam enhanced catalytic cracking unit 90 may include a reactor / separator and a regeneration vessel for regenerating the spent catalyst. As used herein, "spent catalyst" refers to a catalyst that has reacted with the fuel and at least partially coked. In addition, as used herein, "regenerated catalyst" refers to a catalyst that leaves the catalyst regenerator and is at least partially or substantially free of coke, while "fresh catalyst" refers to a catalyst that is newly entered into the system and is at least partially or substantially free of coke. The hydrotreated heavy fraction 220 is mixed and closely contacted with an effective amount of heated fresh or regenerated steam enhanced cracking catalyst particles, which catalytically crack the hydrocarbon molecules in the hydrotreated heavy fraction 220 by breaking carbon-carbon bonds. The SECC product stream 270 is separated from the steam enhanced cracking catalyst, wherein the steam enhanced cracking catalyst is circulated to the regeneration vessel for regeneration of the steam enhanced cracking catalyst.

[0075] Typically, the operating conditions of the steam enhanced catalytic cracking unit 90 configured as a downcomer or riser FCC unit include: a reaction temperature of about 600° C. to about 750° C., in certain embodiments, about 625° C. to about 725° C., and in further embodiments, about 650° C. to about 700° C.; a reaction pressure of about 1 bar to about 20 bar, in certain embodiments, about 1 bar to about 10 bar, and in further embodiments, about 1 bar to about 2 bar; a contact time in the reactor of about 0.1 seconds to about 30 seconds, in certain embodiments, about 0.1 seconds to about 20 seconds, and in further embodiments, about 0.1 seconds to about 10 seconds; a catalyst to feed ratio by weight of about 3:1 to about 60:1, in certain embodiments, about 4:1 to about 50:1, and in further embodiments, about 6:1 to about 40:1; and a steam to feed ratio by weight of about 1:5 to about 1:1, in certain embodiments, about 1:4 to about 1:1, and in further embodiments, about 1:4 to about 2:3. It should be noted that the flow rate of catalyst entering the steam-enhanced catalytic cracking unit 90 divided by the flow rate of the hydrotreated heavy fraction 220 entering the steam-enhanced catalytic cracking unit 90 defines the catalyst-to-feed ratio, and the flow rate of steam entering the steam-enhanced catalytic cracking unit 90 divided by the flow rate of the hydrotreated heavy fraction 220 entering the steam-enhanced catalytic cracking unit 90 defines the steam-to-feed ratio.

[0076] In various embodiments, the steam enhanced cracking catalyst provided in the steam enhanced catalytic cracking unit 90 can be a fluid catalytic cracking catalyst based on USY, zeolite beta, or ZSM-5. In one or more specific embodiments, the steam enhanced cracking catalyst provided in the steam enhanced catalytic cracking unit 90 can be a ZSM-5 formulated catalyst selected due to high hydrothermal stability.

[0077] Second separator unit

[0078] In one or more embodiments, the steam cracker product stream 250, the aromatization product stream 260, and the SECC product stream 270 are provided to the second separator unit 100. Figures 1 to 3 , the second separator unit 100 is fluidly connected to the steam cracker 70, the aromatization unit 80 and the steam enhanced catalytic cracking unit 90. The second separator unit 100 separates the steam cracker product stream 250, the aromatization product stream 260 and the SECC product stream 270 into a hydrogen fraction 280, a C1 stream 290, a C2-C4 alkane stream 300, a light olefin stream 310, a BTX stream 320 comprising benzene, toluene and xylene, and a residual stream 330 comprising cracked naphtha, light cycle oil and heavy cycle oil.

[0079] The second separator unit 100 may include any unit operation or system known to those skilled in the art for separating hydrocarbon streams by vapor pressure. An example second separator unit 100 is an atmospheric distillation unit. As previously described, an atmospheric distillation unit separates a feed stream by fractional distillation by heating the feed to a temperature at which one or more fractions of the mixture will evaporate while leaving other fractions as liquids. Additionally, in various embodiments, the second separator unit 100 may be a simple flash column or a true boiling point distillation having at least 15 theoretical plates.

[0080] In one or more embodiments, the second separator unit 100 includes a plurality of separation units. For ease of illustration, the provided figures show a single unit operation, but it is understood that such a unit operation can include multiple individual separator units to generate the disclosed product streams.

[0081] Further processing

[0082] In one or more embodiments and with reference to Figure 2 and Figure 3 , the hydrogen stream 230 from the methane cracker 60 is provided to the hydroprocessor 40. In addition, in one or more embodiments, the hydrogen fraction 280 from the second separator unit 100 is provided to the hydroprocessor 40. Figure 2 and Figure 3 , the hydroprocessor 40 may be fluidly connected to the methane cracker 60. It should be appreciated that recycling the generated hydrogen from the methane cracker 60, the second separator unit 100, or other unit operations within the integrated system to the hydroprocessor 40 reduces the need for supplemental hydrogen provided from outside the integrated process for operating the hydroprocessor 40.

[0083] In one or more embodiments and with reference to Figure 2 and Figure 3 , the C1 stream 290 from the second separator unit 100 is recycled to the methane cracker 60 for further methane cracking. As previously described, cracking methane in the methane cracker 60 produces hydrogen, which can be advantageously provided to the hydroprocessor 40 to increase and reduce the need for hydrogen from any external hydrogen source for operating the hydroprocessor 40. In addition, in one or more embodiments, the hydrogen fraction 280 from the second separator unit 100 is also provided to the methane cracker 60. It should be understood that providing both the hydrogen fraction 280 and the C1 stream 290 from the second separator unit 40 to the methane cracker 60 allows the hydrogen fraction 280 and the C1 stream 290 to be provided as a single combined stream, thereby reducing the separation requirements and complexity of the second separator unit 40. Any hydrogen provided to the methane cracker 90 can be simply discharged from the methane cracker 60 to the hydroprocessor 40 as part of the hydrogen gas stream 230. As such and with reference to Figure 2 , the methane cracker 60 , the hydrotreater 40 , or both may be fluidly connected to the second separator unit 100 .

[0084] In one or more embodiments, instead of providing the hydrogen gas stream 230 from the methane cracker 60, the hydrogen fraction 280 from the second separator unit 100, or both to the hydroprocessor 40, one or both of the hydrogen gas stream 230 and the hydrogen fraction 280 can be collected or provided for use in a fuel cell vehicle. Likewise, hydrogen from one or both of the hydrogen gas stream 230 and the hydrogen fraction 280 can be provided to a fuel cell for use in generating heat and electricity.

[0085] In one or more embodiments and with reference to Figure 2 and Figure 3 , the C2-C4 alkane stream 300 from the second separator unit 100 is recycled to the steam cracker 70 for further conversion into light olefins. Figure 2 , the steam cracker 70 can be fluidly connected to the second separator unit 100.

[0086] In one or more embodiments and with reference to Figure 2 and Figure 3 The residual stream 330 from the second separator unit 100 comprising cracked naphtha, light cycle oil and heavy cycle oil is recycled to the hydrotreater 40 for further processing. Figure 2 and Figure 3 , the hydroprocessor 40 can be fluidly connected to the second separator unit 100.

[0087] In one or more embodiments, the feed separator 10 can additionally generate a waste gas stream 340 comprising C1-C4 gases. The waste gas stream 340 can be separated in any unit operation or system known to those skilled in the art for separating hydrocarbon streams by steam pressure or other parameters to provide a methane stream sent to the methane cracker 60 and a C2-C4 gas stream sent to the steam cracker 70.

[0088] Example

[0089] The following examples illustrate features of the present disclosure but are not intended to limit the scope of the present disclosure.

[0090] To demonstrate the production of value-added petrochemical products such as benzene, toluene, xylenes and light olefins using the methods and systems according to the present disclosure, simulated yields of various processing units in the integrated process were calculated. It should be understood that laboratory scale operation of the complex and multi-unit nature of the integrated process is impractical and that computer simulations thereof provide a reasonable representation of full-scale industrial implementation. Simulations such as Figure 3 An integrated approach is shown to develop embodiments of the present invention.

[0091] The hydrocarbon stream 110 used in the embodiment of the present invention is Arabian ultra-light crude oil, and its composition is shown in Table 2.

[0092] Table 2: Hydrocarbon feed stream (AXL) of the present invention

[0093]

[0094]

[0095] The hydrocarbon stream 110 is provided to the feed separator 10 to generate a light crude oil fraction 120 and a heavy crude oil fraction 130. In addition, an offgas stream 340 is generated. The light crude oil fraction 120 contains AXL-naphtha, which represents hydrocarbons boiling at 200° C. or less, and the heavy crude oil fraction 130 contains AXL-heavy, which represents hydrocarbons boiling at a temperature above 200° C. The offgas stream 340 contains C1-C4 gases. Table 3 provides a breakdown of the product yields from the feed separator 10.

[0096] Table 3: Feed separator product yields

[0097] Components weight(%) Exhaust 2.4 Light crude oil fraction [AXL-Naphtha (200℃-)] 32.5 Heavy crude oil fraction [AXL-Heavy (200℃+)] 65.0

[0098] The heavy crude oil fraction 130 is provided to the solvent deasphalting unit 20. The yield of the deasphalting unit 20 is a deasphalted oil product 150 (DAO) of 94.1 wt.% and an asphalt product 140 of 5.9 wt.%.

[0099] The generated asphalt product 140 is provided to the delayed coking unit 30 to generate solid petroleum coke 170, a first delayed coking product stream 162, and a second delayed coking product stream 164. The second delayed coking product stream 164 includes C5 hydrocarbons to 343°C boiling range hydrocarbons, and the first delayed coking product stream 162 includes the remaining components. Table 4 provides a breakdown of the product yields of the delayed coking unit 30 from the first delayed coking product stream 162 and the second delayed coking product stream 164. Fuel gas represents light gases less than C2 (inclusive). Liquefied petroleum gas represents C3 and C4 light gases, including both olefins and paraffins. It should be noted that the generated solid petroleum coke 160 is omitted from the product yield.

[0100] Table 4: Delayed Coking Unit Product Yields

[0101] Components weight(%) Fuel gas (FG) 10.9 Liquefied Petroleum Gas (LPG) 6.1 C5 to 350F (176.7℃) hydrocarbons 18.4 350F (176.7°C) to 650F (343.3°C) hydrocarbons 25.1 650F+(343.3℃+) Hydrocarbons 39.4

[0102] The light crude oil fraction 120 and the delayed coking product stream 160 are provided to the hydrotreater 40 to generate a hydrotreater product stream 180. Table 5 provides a breakdown of the product yields from the hydrotreater 40.

[0103] Table 5: Hydroprocessor Product Yields

[0104]

[0105]

[0106] The hydroprocessor product stream 180 is passed through the first separator unit 50 to generate a C1 fraction 190, a C2-C4 fraction 200, a hydrotreated light fraction 210 comprising C5 hydrocarbons to hydrocarbons boiling at less than 210°C, and a hydrotreated heavy fraction 220 comprising hydrocarbons boiling at 210°C or higher.

[0107] The C1 fraction 190 is provided to the methane cracker 60 to generate a hydrogen stream 230 and a fixed carbon stream 240. Table 6 provides a breakdown of the product yields from the methane cracker 60.

[0108] Table 6: Methane cracker product yields

[0109] Components weight(%) <![CDATA[H2]]> 25.0 carbon 75.0

[0110] The C2-C4 fraction 200 is provided to the steam cracker 70 to generate a steam cracker product stream 250 comprising primarily light olefins. Table 7 provides a breakdown of the product yields from the steam cracker 70.

[0111] Table 7: Steam cracker product yields

[0112] Components weight(%) <![CDATA[C1 and H2]]> 23.38 Ethylene 44.45 Propylene 14.54 Butene 2.93 C5+ 11.11 benzene 2.17 Toluene 0.39 Fuel oil 1.03

[0113] The hydrotreated light fraction 210 is provided to the aromatization unit 80 to generate an aromatized product stream 260. Table 8 provides a breakdown of the product yields from the aromatization unit 80.

[0114] Table 8: Aromatization unit product yields

[0115] Components weight(%) <![CDATA[C1 and H2]]> 5.0 C2-C5 10.0 benzene 2.0 Toluene 15.0 Xylene 28.0 C9, C10 aromatics 25.0

[0116] The hydrotreated heavy fraction 220 and the deasphalted oil product 150 are provided to the steam enhanced catalytic cracking unit 90 to generate a SECC product stream 270 comprising light olefins. Table 9 provides a breakdown of the product yields from the steam enhanced catalytic cracking unit 90.

[0117] Table 9: Steam Enhanced Catalytic Cracking Unit Product Yields

[0118]

[0119]

[0120] Steam cracker product stream 250, aromatization product stream 260 and SECC product stream 270 are provided to the second separator unit 100 to generate various product streams. Hydrogen and C1 hydrocarbons from the second separator unit 100 are recycled back to the methane cracker 60 as feed stream for methane cracking and H2 recovery. C2-C4 alkanes are recycled back to the steam cracker 70 as feed stream to further convert into light olefins. The residual stream comprising cracked naphtha, light cycle oil and heavy cycle oil is recycled back to the hydroprocessor 40 as feed stream for further processing therein and in downstream unit operations. In addition, light olefin streams and BTX streams comprising benzene, toluene and xylene are collected as required value-added petrochemical products to be used as product streams from the second separator unit 100. Table 10 provides a detailed description of product yields from the entire system. "Others" includes all other products from the system, including bottom products, such as light cycle oil and heavy cycle oil.

[0121] Table 10: All product yields

[0122]

[0123] It should be noted that the present examples demonstrate that value-added petrochemical products in the form of BTX and light olefins are the main products generated by the integrated method and system. Specifically, the products generated are 40.0 wt.% light olefins and 25.2 wt.% BTX, totaling more than 65 wt.% of the products.

[0124] It should now be appreciated that various aspects of an integrated method and system for converting crude oil into value-added petrochemical products have been described and that these aspects can be used in conjunction with various other aspects.

[0125] According to a first aspect, an integrated method for converting crude oil into value-added petrochemical products comprises (i) providing a hydrocarbon stream comprising crude oil to a feed separator to separate the hydrocarbon stream into a light crude oil fraction boiling at a first temperature or lower and a heavy crude oil fraction boiling at a temperature higher than the first temperature, wherein the first temperature is between 190° C. and 210° C.; (ii) providing the heavy crude oil fraction boiling at a temperature higher than the first temperature from the feed separator to a solvent deasphalting unit, wherein residual oil heavy components and asphaltenes having a boiling point higher than 300° C. are removed from the heavy crude oil fraction to generate an asphalt product comprising asphaltenes and residual oil heavy components and a deasphalted oil product; and (iii) providing the asphalt product to a delayed coking unit, which (iv) providing the light crude oil fraction, the deasphalted oil product and the delayed coking product stream boiling at the first temperature or lower to a hydroprocessor, wherein the light crude oil fraction, the deasphalted oil product and the delayed coking product stream are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds, thereby generating a hydroprocessor product stream; (v) providing the hydroprocessor product stream to a first separator unit, wherein the hydroprocessor product stream is separated into a C1 fraction, a C2-C4 fraction, a hydrotreated light hydrocarbon fraction containing C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature, and a deasphalted product stream containing C1-C4 light gases, coker naphtha and coker gas oil. (vi) providing the C1 fraction to a methane cracker, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (vii) providing the C2-C4 fraction to a steam cracker, wherein the C2-C4 fraction is cracked to generate a steam cracker product stream comprising light olefins and aromatics; (viii) providing the hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature to an aromatization unit, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction into aromatics to generate an aromatized product stream; (ix) ) providing a hydrotreated heavy fraction comprising hydrocarbons boiling at a second temperature or above the second temperature to a steam enhanced catalytic cracking unit, wherein the hydrotreated heavy fraction is cracked to generate a SECC product stream comprising light olefins; and (x) providing the steam cracker product stream, the aromatization product stream, and the SECC product stream to a second separator unit, wherein the second separator unit separates the steam cracker product stream, the aromatization product stream, and the SECC product stream into a hydrogen fraction, a C1 stream, a C2-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylenes, and a residual stream comprising cracked naphtha, light cycle oil, and heavy cycle oil, wherein the hydrogen fraction and the C1 stream may be a single combined stream.

[0126] A second aspect includes the method of the first aspect, wherein a hydrogen stream from a methane cracker is provided to a hydrotreater.

[0127] A third aspect comprises the process of the first or second aspect, wherein the C1 stream from the second separator unit is recycled to the methane cracker for further methane cracking.

[0128] A fourth aspect includes the method of any one of aspects 1 to 3, wherein the hydrogen fraction from the second separator unit is recycled to the methane cracker or hydrotreater.

[0129] A fifth aspect includes the process of any one of aspects 1 to 4, wherein the C2-C4 alkane stream from the second separator unit is recycled to the steam cracker for further conversion to light olefins.

[0130] A sixth aspect includes the method of any one of aspects 1 to 5, wherein the residual stream from the second separator unit comprising cracked naphtha, light cycle oil, and heavy cycle oil is recycled to the hydrotreater for further processing.

[0131] A seventh aspect includes the process of any one of aspects 1 to 6, wherein the solvent deasphalting unit operates at a temperature range of 120°C to 160°C and a pressure range of 1 bar to 40 bar.

[0132] An eighth aspect includes the process of any one of aspects 1 to 7, wherein the coke drum in the delayed coking unit operates at a temperature range of 470°C to 505°C and a pressure range of 1 bar to 2 bar.

[0133] A ninth aspect includes the method of any one of aspects 1 to 8, wherein the hydrotreater operates at a temperature in the range of 280°C to 450°C and a pressure in the range of 5 bar to 160 bar.

[0134]

[0013] A tenth aspect includes the method of any one of aspects 1 to 9, wherein the methane cracker is operated at a temperature in the range of 700°C to 1200°C.

[0135]

[00113] An eleventh aspect includes the method of any one of aspects one to ten, wherein the steam cracker operates at a temperature in the range of 800°C to 950°C.

[0136] A twelfth aspect includes the process of any one of aspects 1 to eleven, wherein the aromatization unit operates at a temperature range of 400°C to 600°C and a pressure range of 1 bar to 35 bar.

[0137] A thirteenth aspect includes the method of any one of aspects one to twelve, wherein the steam enhanced catalytic cracking unit operates at a temperature range of 600°C to 750°C and a pressure range of 1 bar to 20 bar.

[0138] A fourteenth aspect includes the method of any one of aspects one to thirteen, wherein the hydroprocessor product stream comprises less than 800 ppm nitrogen and less than 900 ppm sulfur.

[0139] A fifteenth aspect includes the method of any one of aspects one to fourteen, wherein the first separator unit includes a plurality of separation units.

[0140] A sixteenth aspect includes the method of any one of aspects one to fifteen, wherein the second separator includes a plurality of separation units.

[0141] A seventeenth aspect includes the method of any one of aspects one to sixteen, wherein the deasphalted oil product is provided to a steam enhanced catalytic cracking unit.

[0142] The eighteenth aspect comprises the method of any one of aspects one to seventeen, wherein a delayed coking product stream is separated into a first delayed coking product stream and a second delayed coking product stream comprising C5 hydrocarbons to hydrocarbons boiling at 343°C, the remainder of the delayed coking product stream being located in the first delayed coking product stream, wherein the first delayed coking product stream is provided to a hydroprocessor and the second delayed coking product stream is provided to a steam enhanced catalytic cracking unit.

[0143] According to a nineteenth aspect, an integrated system for converting crude oil into value-added petrochemical products comprises (i) a feed separator for separating a hydrocarbon stream comprising crude oil into a light crude oil fraction boiling at a first temperature or lower and a heavy crude oil fraction boiling at a temperature higher than the first temperature, wherein the first temperature is between 190° C. and 210° C.; and (ii) a solvent deasphalting unit fluidly connected to the feed separator to receive the heavy crude oil fraction boiling at a temperature higher than the first temperature from the feed separator, wherein a residual oil heavy component and asphaltenes having a boiling point higher than 300° C. are removed from the heavy crude oil fraction to generate an asphalt product comprising asphaltenes and the residual oil heavy component. and a deasphalted oil product; (iii) a delayed coking unit fluidly connected to the solvent deasphalting unit to receive the asphalt product, wherein the asphalt product undergoes a thermal cracking reaction to obtain solid petroleum coke and a delayed coking product stream comprising C1-C4 light gas, coker naphtha and coker gas oil; (iv) a hydrotreater fluidly connected to the feed separator, the solvent deasphalting unit and the delayed coking unit to receive a light crude oil fraction boiling at a first temperature or lower, the deasphalted oil product and the delayed coking product stream, wherein the light crude oil fraction, the deasphalted oil product and the delayed coking product stream are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds to generate a hydrotreater. (v) a first separator unit fluidly connected to the hydroprocessor to receive the hydroprocessor product stream, wherein the hydroprocessor product stream is separated into a C1 fraction, a C2-C4 fraction, a hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature lower than a second temperature, and a hydrotreated heavy fraction comprising hydrocarbons boiling at a second temperature or higher, wherein the second temperature is between 200°C and 215°C; (vi) a methane cracker fluidly connected to the first separator unit to receive the C1 fraction, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (vii) a steam cracker fluidly connected to the first separator unit to receive the C1 fraction, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (viii) an aromatization unit fluidly connected to the first separator to receive the hydrotreated light fraction, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction into aromatic hydrocarbons to generate an aromatized product stream; (ix) a steam enhanced catalytic cracking unit fluidly connected to the first separator to receive a hydrotreated heavy fraction comprising hydrocarbons boiling at a second temperature or above, wherein the hydrotreated heavy fraction is cracked to generate a SECC product stream comprising light olefins;and (x) a second separator fluidly connected to the steam cracker, the aromatization unit and the steam enhanced catalytic cracking unit to receive the steam cracker product stream, the aromatization product stream and the SECC product stream, wherein the second separator unit separates the steam cracker product stream, the aromatization product stream and the SECC product stream into a hydrogen fraction, a C1 stream, a C2-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene and xylenes, and a residual stream comprising cracked naphtha, light cycle oil and heavy cycle oil.;

[0144] A twentieth aspect includes the system of aspect nineteen, wherein the hydrogen stream from the methane cracker is fluidly connected to the hydroprocessor such that the hydrogen stream is provided as a feed stream to the hydroprocessor.

[0145] A twenty-first aspect includes the system of aspect twentieth or twenty-first, wherein the C1 stream from the second separator unit is fluidly connected to the methane cracker such that the C1 stream is recycled to the methane cracker for further methane cracking.

[0146] The twenty-second aspect includes the system of any one of aspects 20 to 21, wherein the C2-C4 alkane stream from the second separator unit is fluidly connected to the steam cracker such that the C2-C4 alkane stream is recycled to the steam cracker for further conversion to light olefins.

[0147] A twenty-third aspect includes the system of any of aspects 20 to 22, wherein a residual stream from the second separator unit comprising cracked naphtha, light cycle oil, and heavy cycle oil is fluidly connected to the hydroprocessor such that the residual stream is recycled to the hydroprocessor for further processing.

[0148] Those skilled in the art will appreciate that various modifications and changes may be made to the described embodiments without departing from the spirit and scope of the claimed subject matter. Therefore, this specification is intended to cover modifications and changes to the various described embodiments, as long as these modifications and changes are within the scope of the appended claims and their equivalents.

[0149] For purposes of this disclosure, it is expressly noted that an indication that a stream or effluent is transferred or provided from one unit to another includes embodiments in which the stream or effluent is transferred directly from one unit to another, as well as embodiments in which there are intervening systems or units that may substantially change the composition of the stream or effluent between units. As used in this disclosure, transferring a stream or effluent "directly" from one unit to another refers to transferring the stream or effluent from a first unit to a second unit without passing the stream or effluent through an intervening reaction system or separation system that substantially changes the composition of the stream or effluent. Similarly, an indication that two systems are "fluidically connected" indicates that the stream can be transferred directly between the systems. Heat transfer equipment, such as heat exchangers, preheaters, coolers, condensers or other heat transfer equipment, and pressure equipment, such as pumps, pressure regulators, compressors or other pressure equipment, are not considered to be intervening systems that change the composition of a stream or effluent. Combining two streams or effluents together is also not considered to include intervening systems that change the composition of one or both of the combined streams or effluents.

[0150] It should be further understood that a stream can be named after a component of the stream, and the component of the named stream can be the major component of the stream (e.g., comprising 50 weight percent (wt.%), 70 wt.%, 90 wt.%, 95 wt.%, 99 wt.%, 99.5 wt.%, or even 99.9 wt.% to 100 wt.% of the content of the stream). It should also be understood that when a stream including the component is disclosed as being transferred from one system component to another system component, the component of the stream is disclosed as being transferred from the system component to the other system component. For example, a "hydrocarbon stream" disclosed as being transferred to a first system component or from a first system component to a second system component should be understood to be equivalently disclosed as being transferred to the first system component or from a first system component to a second system component.

[0151] The singular forms "a," "an," and "the" include plural referents unless the context clearly dictates otherwise.

[0152] Ranges are provided throughout this disclosure. It is contemplated that each discrete value encompassed by a range is also included. Additionally, it is also contemplated that a range is formed by each discrete value encompassed by an explicitly disclosed range. For the sake of brevity, no explicit indication is provided after each disclosed range, but rather this general indication is provided.

[0153] As used in this disclosure and 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.

Claims

1. An integrated process for converting crude oil into value-added petrochemical products, the process comprising: (i) providing a hydrocarbon stream comprising the crude oil to a feed separator to separate the hydrocarbon stream into a light crude oil fraction boiling at a first temperature or lower and a heavy crude oil fraction boiling at a temperature higher than the first temperature, wherein the first temperature is between 190° C. and 210° C.; (ii) supplying the heavy crude oil fraction boiling at a temperature higher than the first temperature from the feed separator to a solvent deasphalting unit, wherein residual oil heavy components and asphaltenes having a boiling point higher than 300° C. are removed from the heavy crude oil fraction to generate a deasphalted oil product and an asphalt product comprising the asphaltenes and residual oil heavy components; (iii) providing the asphalt product to a delayed coking unit, wherein the asphalt product undergoes a thermal cracking reaction to obtain solid petroleum coke and a delayed coking product stream comprising C1-C4 light gas, coker naphtha, and coker gas oil; (iv) providing the light crude oil fraction, the deasphalted oil product, and the delayed coking product stream boiling at the first temperature or less to a hydroprocessor, wherein the light crude oil fraction, the deasphalted oil product, and the delayed coking product stream are hydroprocessed to remove heteroatoms and saturated carbon-carbon bonds, thereby generating a hydroprocessor product stream; (v) providing the hydroprocessor product stream to a first separator unit, wherein the hydroprocessor product stream is separated into a C1 fraction, a C2-C4 fraction, a hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature below a second temperature, and a hydrotreated heavy fraction comprising hydrocarbons boiling at or above the second temperature, wherein the second temperature is between 200° C. and 215° C.; (vi) providing the C1 fraction to a methane cracker, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (vii) providing the C2-C4 fraction to a steam cracker, wherein the C2-C4 fraction is cracked to generate a steam cracker product stream comprising light olefins and aromatics; (viii) providing the hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature lower than the second temperature to an aromatization unit, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction to aromatic hydrocarbons to produce an aromatized product stream; (ix) providing the hydrotreated heavy fraction comprising hydrocarbons boiling at or above the second temperature to a steam enhanced catalytic cracking unit, wherein the hydrotreated heavy fraction is cracked to generate a SECC product stream comprising light olefins; as well as (x) providing the steam cracker product stream, the aromatization product stream, and the SECC product stream to a second separator unit, wherein the second separator unit separates the steam cracker product stream, the aromatization product stream, and the SECC product stream into a hydrogen fraction, a C1 stream, a C2-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylenes, and a residual stream comprising cracked naphtha, light cycle oil, and heavy cycle oil, wherein the hydrogen fraction and the C1 stream may be a single combined stream.

2. The process of claim 1, wherein the hydrogen stream from the methane cracker is provided to the hydrotreater.

3. The process according to claim 1 or 2, wherein the C1 stream from the second separator unit is recycled to the methane cracker for further methane cracking.

4. The process according to any one of claims 1 to 3, wherein the hydrogen fraction from the second separator unit is recycled to the methane cracker or the hydrotreater.

5. The process according to any one of claims 1 to 4, wherein the C2-C4 alkane stream from the second separator unit is recycled to the steam cracker for further conversion into light olefins.

6. The process according to any one of claims 1 to 5, wherein the residual stream comprising cracked naphtha, light cycle oil and heavy cycle oil from the second separator unit is recycled to the hydrotreater for further processing.

7. The process according to any one of claims 1 to 6, wherein the deasphalted oil product is provided to the steam enhanced catalytic cracking unit.

8. The method according to any one of claims 1 to 7, wherein the delayed coking product stream is separated into a first delayed coking product stream and a second delayed coking product stream comprising hydrocarbons boiling from C5 to 343°C, the remainder of the delayed coking product stream being located in the first delayed coking product stream, wherein the first delayed coking product stream is provided to the hydroprocessor, and the second delayed coking product stream is provided to the steam enhanced catalytic cracking unit.

9. The process according to any one of claims 1 to 8, wherein the aromatization unit is operated at a temperature range of 400 to 600°C and a pressure range of 1 to 35 bar.

10. The process according to any one of claims 1 to 9, wherein the steam enhanced catalytic cracking unit is operated at a temperature range of 600°C to 750°C and a pressure range of 1 bar to 20 bar.

11. An integrated system for converting crude oil into value-added petrochemical products, the system comprising: (i) a feed separator for separating a hydrocarbon stream comprising the crude oil into a light crude oil fraction boiling at a first temperature or lower and a heavy crude oil fraction boiling at a temperature higher than the first temperature, wherein the first temperature is between 190° C. and 210° C.; (ii) a solvent deasphalting unit fluidly connected to the feed separator to receive the heavy crude oil fraction boiling at a temperature higher than the first temperature from the feed separator, wherein residual oil heavy components and asphaltenes having a boiling point higher than 300° C. are removed from the heavy crude oil fraction to generate an asphalt product comprising the asphaltenes and residual oil heavy components and a deasphalted oil product; (iii) a delayed coking unit fluidly connected to the solvent deasphalting unit to receive the asphalt product, wherein the asphalt product undergoes a thermal cracking reaction to obtain solid petroleum coke and a delayed coking product stream comprising C1-C4 light gases, coker naphtha, and coker gas oil; (iv) a hydrotreater fluidly connected to the feed separator, the solvent deasphalting unit, and the delayed coking unit to receive the light crude oil fraction boiling at the first temperature or less, the deasphalted oil product, and the delayed coking product stream, wherein the light crude oil fraction, the deasphalted oil product, and the delayed coking product stream are hydrotreated to remove heteroatoms and saturated carbon-carbon bonds to generate a hydrotreater product stream; (v) a first separator unit fluidly connected to the hydroprocessor to receive the hydroprocessor product stream, wherein the hydroprocessor product stream is separated into a C1 fraction, a C2-C4 fraction, a hydrotreated light fraction comprising C5 hydrocarbons to hydrocarbons boiling at a temperature below a second temperature, and a hydrotreated heavy fraction comprising hydrocarbons boiling at or above the second temperature, wherein the second temperature is between 200° C. and 215° C.; (vi) a methane cracker fluidly connected to the first separator unit to receive the C1 fraction, wherein the C1 fraction is converted into a hydrogen stream and a fixed carbon stream; (vii) a steam cracker fluidly connected to the first separator to receive the C2-C4 fraction, wherein the C2-C4 fraction is cracked to generate a steam cracker product stream comprising light olefins and aromatics; (viii) an aromatization unit fluidly connected to the first separator to receive the hydrotreated light fraction, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction to aromatic hydrocarbons to produce an aromatized product stream; (ix) a steam enhanced catalytic cracking unit fluidly connected to the first separator to receive the hydrotreated heavy fraction comprising hydrocarbons boiling at or above the second temperature, wherein the hydrotreated heavy fraction is cracked to generate a SECC product stream comprising light olefins; as well as (x) a second separator fluidly connected to the steam cracker, the aromatization unit and the steam enhanced catalytic cracking unit to receive the steam cracker product stream, the aromatization product stream and the SECC product stream, wherein the second separator unit separates the steam cracker product stream, the aromatization product stream and the SECC product stream into a hydrogen fraction, a C1 stream, a C2-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene and xylenes, and a residual stream comprising cracked naphtha, light cycle oil and heavy cycle oil.

12. The system of claim 11, wherein the hydrogen stream from the methane cracker is fluidly connected to the hydroprocessor such that the hydrogen stream is provided as a feed stream to the hydroprocessor.

13. The system of claim 11 or 12, wherein the C1 stream from the second separator unit is fluidly connected to the methane cracker so that the C1 stream is recycled to the methane cracker for further methane cracking. [The hydrogen fraction may also be included].

14. The system according to any one of claims 11 to 13, wherein the C2-C4 alkane stream from the second separator unit is fluidly connected to the steam cracker such that the C2-C4 alkane stream is recycled to the steam cracker for further conversion into light olefins.

15. The system of any one of claims 11 to 14, wherein the residual stream from the second separator unit comprising cracked naphtha, light cycle oil, and heavy cycle oil is fluidly connected to the hydroprocessor such that the residual stream is recycled to the hydroprocessor for further processing.

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