Conversion of whole crude oil to value-added petrochemicals using integrated reactor process

Abstract

An integrated process and associated system for converting crude oil to value-added petrochemicals. The process includes separating the crude oil into light and heavy crude oil fractions and treating the heavy fraction in a solvent deasphalting unit and a delayed coker unit, and then providing the light fraction and selected effluents of the solvent deasphalting unit and the delayed coker unit to a hydrogenator. The process further includes separating the effluent of the hydrogenator to produce a C1 fraction passed to the methane cracker, a C2 fraction passed to the ethane steam cracker, a C3-C4 fraction passed to the dehydrogenation reactor, a hydrotreated light fraction passed to the aromatization unit, and a hydrotreated heavy fraction passed to the steam enhanced catalytic cracking unit. The process further includes separating the effluent of each unit operation into a product stream including a BTX stream and a light olefin stream.

Description

[0001] Cross - reference to related applications

[0002] This application claims the benefit of priority of U.S. Patent Application Serial No. 17 / 947,744, filed on September 19, 2022, entitled "Conversion of Whole Crude Oil to Value-Added Petrochemicals Using an Integrated Reactor Approach", the entire content of which is incorporated herein by reference. Technical Field

[0003] The present disclosure relates to an integrated method and associated system for converting crude oil into value-added petrochemicals. Background Art

[0004] Aromatics such as BTX (benzene, toluene, and xylene) and olefins are valuable chemicals that are frequently used in the production of many materials and the formulation of many consumer products. For example, BTX compounds are often used in the processing or production of petroleum products and in the production of consumer products such as paints and lacquers, thinners, fuels, rubber products, adhesives, inks, cosmetics, and pharmaceuticals. Similarly, light olefins are the base materials for many modern plastic products. Thus, it is generally desirable to produce both light olefins and BTX in large quantities, efficiently, and economically.

[0005] Given the current and expected increased 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 from crude oil streams and result in the production of undesirable amounts of low-value products in the production of light olefins and BTX. Summary of the Invention

[0006] Accordingly, there is a long-felt and unmet need for an efficient and economic method for producing light olefins and BTX from a feedstock comprising a large amount of whole crude oil. The methods and systems of the present disclosure meet this long-felt and unmet need by optimizing the feedstock provided to each unit operation within the integrated system and utilizing methods and systems dedicated to 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.

[0007] According to one or more embodiments of the present disclosure, an integrated method for converting crude oil into value-added petrochemicals 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 heavy components and asphaltenes having a boiling point higher than 300 °C are removed from the heavy crude oil fraction to produce an asphaltene product containing asphaltenes and residual heavy components and a deasphalted oil product; (iii) providing the asphaltene product to a delayed coking unit, wherein the asphaltene product undergoes a thermal cracking reaction to obtain solid petroleum coke and a delayed coking unit product stream containing C1-C4 light gases, coker naphtha, and coker gas oil; (iv) providing the light crude oil fraction boiling at a first temperature or lower, the deasphalted oil product, and the delayed coking unit product stream to a hydrotreater, wherein the light crude oil fraction, the deasphalted oil product, and the delayed coking unit product stream are hydrotreated to remove heteroatoms and saturate carbon-carbon bonds, thereby producing a hydrotreater product stream; (v) providing the hydrotreater product stream to a first separator unit, wherein the hydrotreater product stream is separated into a C1 fraction, a C2 fraction, a C3-C4 fraction, a hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling at a second temperature, and a hydrotreated heavy fraction containing hydrocarbons boiling at the second temperature or higher, 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 fraction to an ethane steam cracker, wherein the C2 fraction is cracked to produce an ethane steam cracker product stream containing light olefins and aromatics; (viii) providing the C3-C4 fraction to a dehydrogenation reactor, wherein the C3-C4 fraction is dehydrogenated to produce a dehydrogenation product stream containing propylene and butene produced from propane and butane in the C3-C4 fraction; (ix) providing the hydrotreated light fraction containing 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 produce an aromatization product stream; (x) providing the hydrotreated heavy fraction containing hydrocarbons boiling at the second temperature or higher to a steam enhanced catalytic cracking unit, wherein the hydrotreated heavy fraction is cracked to produce an SECC product stream containing light olefins;and (xi) providing the ethane steam cracker product stream, the dehydrogenation product stream, the aromatization product stream, and the SECC product stream to a second separator unit, wherein the second separator unit splits the ethane steam cracker product stream, the dehydrogenation product stream, the aromatization product stream, and the SECC product stream into: a hydrogen fraction, a C1 stream, a C2 stream, a C3-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylene, and a residue stream comprising cracked naphtha, light cycle oil, and heavy cycle oil.;

[0008] In additional embodiments, one or more of the hydrogen fraction, the C1 stream, the C2 stream, the C3-C4 alkane stream, and the residue stream can be recycled as feed streams to one or more unit operations within the integrated process for further processing.

[0009] According to one or more embodiments of the present disclosure, an integrated system for converting crude oil into value-added petrochemicals 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 or below a first temperature and a heavy crude oil fraction boiling above 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 above the first temperature, wherein residual heavy components and asphaltenes having a boiling point above 300°C are removed from the heavy crude oil fraction to produce an asphaltene product containing asphaltenes and residual heavy components and a deasphalted oil product; (iii) a delayed coking unit fluidly connected to the solvent deasphalting unit to receive the asphaltene product, wherein the asphaltene product undergoes a thermal cracking reaction to obtain solid petroleum coke and a delayed coking unit product stream containing 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 or below the first temperature, the deasphalted oil product, and the delayed coking unit product stream, wherein the light crude oil fraction, the deasphalted oil product, and the delayed coking unit product stream are hydrotreated to remove heteroatoms and saturate carbon-carbon bonds, thereby producing a hydrotreater product stream; (v) a first separator unit fluidly connected to the hydrotreater to receive the hydrotreater product stream, wherein the hydrotreater product stream is separated into a C1 fraction, a C2 fraction, a C3-C4 fraction, a hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling below a second temperature, and a hydrotreated heavy fraction containing hydrocarbons boiling at or above the second temperature; (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) an ethane steam cracker fluidly connected to the first separator to receive the C2 fraction, wherein the C2 fraction is cracked to produce an ethane steam cracker product stream containing light olefins and aromatics; (viii) a dehydrogenation reactor fluidly connected to the first separator to receive the C3-C4 fraction, wherein the C3-C4 fraction is dehydrogenated to produce a dehydrogenation product stream containing propylene and butene produced from propane and butane in the C3-C4 fraction; (ix) 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 aromatics to produce an aromatization product stream; (x) a steam enhanced catalytic cracking unit fluidly connected to the first separator to receive the hydrotreated heavy fraction containing hydrocarbons boiling at or above the second temperature, wherein the hydrotreated heavy fraction is cracked to produce an SECC product stream containing light olefins;and (xi) a second separator fluidly connected to the ethane steam cracker, dehydrogenation reactor, aromatization unit, and steam enhanced catalytic cracking unit to receive the ethane steam cracker product stream, dehydrogenation product stream, aromatization product stream, and SECC product stream, wherein the second separator unit splits the ethane steam cracker product stream, dehydrogenation product stream, aromatization product stream, and SECC product stream into: a hydrogen fraction, a C1 stream, a C2 stream, a C3-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylene, and a residual stream comprising cracked naphtha, light cycle oil, and heavy cycle oil.;

[0010] In additional embodiments, one or more of the hydrogen fraction, C1 stream, C2 stream, C3-C4 alkane stream, and residual stream may be recycled as feed streams to one or more unit operations within the integrated system for further processing.

[0011] Additional features and advantages of the described embodiments will be set forth in the detailed description which follows. The additional features and advantages of the described embodiments will in part be readily apparent to those skilled in the art from the description, or may be learned by practice of the described embodiments including the detailed description which follows, the drawings, and the claims.

[0012] Brief description of the drawings

[0013] 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:

[0014] Figure 1 is a schematic diagram of one or more embodiments of the integrated refinery process of the present disclosure, including an aromatization reactor;

[0015] Figure 2 is a schematic diagram of one or more embodiments of the integrated refinery process of the present disclosure, including recycling one or more product streams as additional feeds to one or more unit operations of the integrated refinery process; and

[0016] Figure 3 is Figure 2 a schematic diagram of the integrated refinery process of, having optional additional streams separated into separate unit operations.

[0017] For the purposes of these simplified schematic diagrams and this specification, many valves, temperature sensors, electronic controllers, etc. that are commonly used in certain refinery operations and well known to those of ordinary skill in the art are not included. Additionally, accompanying components in traditional refinery operations, such as air supply, hydrogen supply, catalyst hoppers, and flue gas treatment, are not necessarily shown.

[0018] It should also be noted that the arrows in the drawings refer to pipes, ducts, channels, or other physical transmission lines that connect one or more system devices to one or more other system devices through fluid communication. Additionally, the arrows connected to the system devices define the inlets and outlets of each given system device.

[0019] Reference will now be made in more detail to various embodiments, some of which are shown in the drawings. Wherever possible, the same reference numbers will be used throughout the drawings to refer to the same or like parts. Detailed Description

[0020] Reference will now be made in detail to embodiments of the present disclosure for an integrated method and associated system for converting crude oil into value-added petrochemicals. Although Figure 1 and Figure 2 systems for converting crude oil into value-added petrochemicals are provided as examples, it should be understood that the systems and methods of the present disclosure include other configurations.

[0021] The methods and systems of the present disclosure provide an integrated method and system for converting crude oil into value-added products (primarily light olefins and BTX (benzene, toluene, and xylene)). Specifically, the methods and systems of the present disclosure split crude oil into C1 fraction, C2 fraction, C3-C4 fraction, light liquid fraction, and heavy liquid fraction, which can then be cracked in suitable reactors (such as methane crackers, ethane steam crackers, dehydrogenation reactors, aromatization units, or steam enhanced catalytic cracking units) to maximize the yield of petrochemicals. Thus, the integrated system and method produce increased yields of light olefins and BTX.

[0022] In one or more embodiments, an integrated method for converting crude oil into value-added petrochemicals includes providing a hydrocarbon stream 110 containing crude oil. A feed separator 10 separates the hydrocarbon stream 110 into a light crude oil fraction 120 that boils at or below a first temperature and a heavy crude oil fraction 130 that boils at a temperature higher than the first temperature, wherein the first temperature is between 190°C and 210°C. The integrated method further includes providing the heavy crude oil fraction 130 from the feed separator 10 to a solvent deasphalting unit 20, wherein residual heavy components and asphaltenes having a boiling point higher than 300°C are removed from the heavy crude oil fraction to produce an asphaltene product 140 (which contains asphaltenes and residual heavy components) and a deasphalted oil product 150. The asphaltene product 140 is then provided to a delayed coking unit 30, wherein the asphaltene product 140 undergoes a thermal cracking reaction to obtain solid petroleum coke 170 and a delayed coking unit product stream 160 containing C1-C4 light gases, coker naphtha, and coker gas oil. The light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking unit product stream 160 are then provided to a hydrotreater 40, wherein the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking unit product stream 160 are hydrotreated to remove heteroatoms and saturate carbon-carbon bonds, thereby producing a hydrotreater product stream 180. The hydrotreater product stream 180 is then provided to a first separator unit 50, wherein the hydrotreater product stream 180 is separated into a C1 fraction 190, a C2 fraction 200, a C3-C4 fraction 205, a hydrotreated light fraction 210 containing C5 hydrocarbons to hydrocarbons that boil below a second temperature, and a hydrotreated heavy fraction 220 containing hydrocarbons that boil at or above the second temperature, wherein the second temperature is between 200°C and 215°C. The C1 fraction 190 is provided to a methane cracker 60, wherein the C1 fraction 190 is converted into a hydrogen stream 230 and a fixed carbon stream 240. The C2 fraction 200 is provided to an ethane steam cracker 70, wherein the C2 fraction 200 is cracked to produce an ethane steam cracker product stream 250 containing light olefins and aromatics. The C3-C4 fraction 205 is provided to a dehydrogenation reactor 75, wherein the C3-C4 fraction 205 is dehydrogenated to produce a dehydrogenation product stream 255, which contains propylene and butene produced from propane and butane in the C3-C4 fraction 205. The hydrotreated light fraction 210 is provided to an aromatization unit 80, wherein the aromatization unit 80 converts aliphatic hydrocarbons in the hydrotreated light fraction 210 into aromatics to produce an aromatization product stream 260. The hydrotreated heavy fraction 220 containing hydrocarbons that boil at or above the second temperature is provided to a steam enhanced catalytic cracking unit 90, wherein the hydrotreated heavy fraction 220 is cracked to produce an SECC product stream 270 containing light olefins.The ethane steam cracker product stream 250, the dehydrogenation product stream 255, 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 splits the steam cracker product stream 250, the dehydrogenation product stream 255, the aromatization product stream 260, and the SECC product stream 270 into: a hydrogen fraction 280, a C1 stream 290, a C2 stream 300, a C3-C4 alkane stream 305, a light olefin stream 310, a BTX stream 320 containing benzene, toluene, and xylene, and a residual stream 330 containing cracked naphtha, light cycle oil, and heavy cycle oil.

[0023] In one or more embodiments, an integrated system for converting crude oil into value-added petrochemicals includes: a feed separator 10 for separating a hydrocarbon stream 110 containing crude oil into a light crude oil fraction 120 boiling at or below a first temperature and a heavy crude oil fraction 130 boiling at a temperature above 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 residual heavy components and asphaltenes having a boiling point above 300 °C are removed from the heavy crude oil fraction 130 to produce an asphalt product 140 (which contains asphaltenes and residual 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 solid petroleum coke 170 and a delayed coking unit product stream 160 containing C1-C4 light gases, coker naphtha, and coker gas oil. A hydrotreater 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 or below the first temperature, the deasphalted oil product 150, and the delayed coking unit product stream 160, wherein the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking unit product stream 160 are hydrotreated to remove heteroatoms and saturate carbon-carbon bonds, thereby producing a hydrotreater product stream 180. A first separator unit 50 is fluidly connected to the hydrotreater 40 to receive the hydrotreater product stream 180, wherein the hydrotreater product stream 180 is separated into a C1 fraction 190, a C2 fraction, a C3-C4 fraction 205, a hydrotreated light fraction 210 containing C5 hydrocarbons to hydrocarbons boiling below a 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. A 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. An ethane steam cracker 70 is fluidly connected to the first separator 50 to receive the C2 fraction 200, wherein the C2 fraction 200 is cracked to produce an ethane steam cracker product stream 250 containing light olefins and aromatics. A dehydrogenation reactor 75 is fluidly connected to the first separator 50 to receive the C3-C4 fraction 205, wherein the C3-C4 fraction 205 is dehydrogenated to produce a dehydrogenation product stream 255 containing propylene and butene produced from propane and butane in the C3-C4 fraction 205. An 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 produce an aromatization 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 or above a second temperature, wherein the hydrotreated heavy fraction 220 is cracked to produce an SECC product stream 270 comprising light olefins. The second separator 100 is fluidly connected to the ethane steam cracker 70, the dehydrogenation reactor 75, the aromatization unit 80, and the steam enhanced catalytic cracking unit 90 to receive the ethane steam cracker product stream 250, the dehydrogenation product stream 255, the aromatization product stream 260, and the SECC product stream 270, wherein the second separator unit 100 splits 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 stream 300, a C3-C4 paraffin stream 305, a light olefin stream 310, a BTX stream 320 comprising benzene, toluene, and xylene, and a residue stream 330 comprising cracked naphtha, light cycle oil, and heavy cycle oil.

[0024] After disclosing the basic operations of an integrated method and associated system for converting crude oil into value-added petrochemicals, each step and unit operation of an embodiment of the integrated method and associated system are now provided in more detail.

[0025] Hydrocarbon feed stream

[0026] The hydrocarbon stream 110 comprises crude oil. In various embodiments, the crude oil in the hydrocarbon stream 110 can be Arab extra light crude oil (AXL), Arab light crude oil (AL), Arab heavy crude oil (AH), atmospheric residue, or a combination thereof.

[0027] Feed separator

[0028] In one or more embodiments, the hydrocarbon stream 110 comprising crude oil is provided to the feed separator 10 to separate the hydrocarbon stream 110 into a light crude oil fraction 120 boiling at or below a first temperature and a heavy crude oil fraction 130 boiling at a temperature above the first temperature. In various embodiments, the first temperature can be between 190 °C and 210 °C, between 195 °C and 205 °C, between 198 °C and 202 °C, or about 200 °C.

[0029] The feed separator 10 can be any unit configured to separate a hydrocarbon stream 110 into a light crude oil fraction 120 that boils at a temperature of 200 °C or lower and a heavy crude oil fraction 130 that boils at a temperature higher than 200 °C. In one or more embodiments, the feed separator 10 is a flash tank. The flash tank operates based on the flash distillation principle, which refers to the process in which liquid hydrocarbons are immediately converted to vapor when moving from high pressure to low pressure, thereby allowing the separation of the liquid hydrocarbon feed. The flash tank can operate at a temperature of 200 °C to 500 °C and an appropriate pressure such that separation into the light crude oil fraction 120 and the heavy crude oil fraction 130 is enabled.

[0030] Solvent deasphalting unit

[0031] In one or more embodiments, the heavy crude oil fraction 130 that boils at a temperature higher than the first temperature from the feed separator 10 is provided to the solvent deasphalting unit 20. Thus, referring to Figure 1 and Figure 2 , the solvent deasphalting unit 20 is fluidly connected to the feed separator 10. The solvent deasphalting unit 20 removes residual heavy components and asphaltenes having a boiling point higher than 300 °C from the heavy crude oil fraction 130 to produce an asphaltene product 140 containing asphaltenes and residual heavy components. The resulting stream produced from the removal of asphaltenes and residual heavy components is a deasphalted oil product 150.

[0032] It should be understood that solvent deasphalting performed in the solvent deasphalting unit 20 is a separation method in which certain species are selectively separated by molecular type by mixing with an alkane solvent and precipitating asphaltenes and other residual heavy components from the solution. Since light hydrocarbons can be used as solvents to dissolve aliphatic compounds rather than asphaltenes, the solvent deasphalting unit 20 separates the asphaltene product 140 containing asphaltenes and residual heavy components from the feedstock of the heavy crude oil fraction 130.

[0033] In various embodiments, the solvent used in the solvent deasphalting unit 20 can be propane, butane, or pentane. The choice of the light hydrocarbon solvent affects the yield and quality of the resulting deasphalted oil product 150. For example, compared to using pentane, using propane in the solvent deasphalting unit 20 can produce a deasphalted oil product 150 with higher quality but lower yield, while using pentane can triple or quadruple the yield at the cost of lower quality due to greater residual contamination of metal and carbon residues.

[0034] A variety of processing parameters are considered suitable for the operation of the solvent deasphalting unit 20. For example, the solvent deasphalting unit 20 can operate at a temperature and pressure below the solvent critical pressure and critical temperature of the solvent used. Additionally, the yield of the asphalt product 140 containing asphaltenes and residual heavy components and the yield of the deasphalted oil product 150 can be adjusted by varying 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 from 2 to 20, or from 5 to 10, or from 6 to 8. Further, in one or more embodiments, the solvent deasphalting unit 20 operates at a temperature in the range of 120 °C to 160 °C and a pressure in the range of 1 bar to 40 bar.

[0035] In one or more embodiments, the solvent deasphalting unit 20 additionally removes metals from the heavy crude oil fraction 130. The solvent deasphalting process ultimately produces the metal containing hydrocarbons of the treated stream, as well as the asphaltenes and residual heavy components in the asphalt product 140 of the solvent deasphalting unit 20. U.S. Patent No. 7,566,394 is incorporated herein by reference, which teaches the details of the solvent deasphalting process.

[0036] The deasphalting carried out in the deasphalting unit 20 produces a deasphalted oil product 150 in which many of the contaminants present in the heavy crude oil fraction 130 are removed. Most of the contaminants present in the heavy crude oil fraction 130 are removed as part of the asphalt product 140. These contaminants include metal contaminants (such as nickel and vanadium) and carbon residues.

[0037] Delayed coking unit

[0038] In one or more embodiments, the asphalt product 140 from the solvent deasphalting unit 20 is provided to the delayed coking unit 30. Thus, with reference to Figure 1 and Figure 2 , 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 unit product stream 160. The delayed coking unit product stream 160 includes C1 - C4 light gases, 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 its thermal cracking temperature in a furnace having a plurality of parallel channels. This heating cracks the heavy, long - chain hydrocarbon molecules of the various components of the asphalt product 140, the solid petroleum coke 170, and the delayed coking unit product stream 160.

[0039] In one or more embodiments, the delayed coking unit product stream 160 is split into a first delayed coking unit product stream 162 and a second delayed coking unit product stream 164. The second delayed coking unit product stream 164 includes C5 to hydrocarbons boiling at 343 °C from the delayed coking unit product stream 60, and the first delayed coking unit product stream 162 includes the remainder of the delayed coking unit product in the first delayed coking unit product stream.

[0040] In one or more embodiments, the coke drums in the delayed coking unit operate at a temperature in the range of 470 °C to 505 °C and a pressure in the range of 1 bar to 2 bar to process the asphalt product 140 from the solvent deasphalting unit 20.

[0041] The delayed coking unit 30 may include at least two parallel drums operating in a swing mode. When one coke drum is filled with coke, the feed of the asphalt product 140 is switched to the new empty drum, and the filled drum is cooled. It should be understood that various inlet and outlet valves may be provided to control the flow into and out of the delayed coking unit 30. The coke remaining in the drum is generally cooled with water and then removed from the coke drum by conventional methods (e.g., using hydraulic or mechanical techniques or both) to remove the solid coke from the drum wall, thereby recovering it as solid petroleum coke 170.

[0042] Hydrogenator

[0043] 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 unit product stream 160 from the delayed coking unit 30 are provided to the hydrogenator 40. Thus, referring to Figure 1 and Figure 2 , the hydrogenator 40 is fluidly connected to the solvent deasphalting unit 20. In one or more embodiments, referring to Figure 3 , the first delayed coking unit product stream 162 is provided to the hydrogenator in place of the delayed coking unit product stream 160. Inside the hydrogenator 40, the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking unit product stream 160 are hydrotreated to remove heteroatoms and saturate the carbon-carbon bonds, thereby producing the hydrogenator product stream 180. It should be understood that the hydrotreating carried out in the hydrogenator 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.

[0044] Saturate the carbon-carbon bonds of the hydrocarbons in the light crude oil fraction 120, the deasphalted oil product 150, and the delayed coking unit product stream 160, and remove heteroatoms (such as nitrogen, sulfur, and chlorine) by separately producing ammonia, hydrogen sulfide, and HCl that can be separated out in the hydrotreater waste stream 182. In one or more embodiments, the hydrotreater product stream 180 exiting the hydrotreater 40 contains less than 800 ppm of nitrogen and less than 900 ppm of sulfur. In various further embodiments, the hydrotreater product stream 180 contains less than 750 ppm of nitrogen, less than 650 ppm of nitrogen, less than 550 ppm of nitrogen, less than 500 ppm of nitrogen, or 370 ppm to 750 ppm of nitrogen. In various embodiments, the hydrotreater product stream 180 contains less than 850 ppm of sulfur, less than 750 ppm of sulfur, less than 500 ppm of sulfur, less than 300 ppm of sulfur, or 150 ppm to 820 ppm of sulfur.

[0045] 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 unit 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 denitrified hydrocarbons, and chlorine-containing compounds to HCl and dechlorinated compounds. In one or more embodiments, the hydrotreater 40 may comprise a CoMo / alumina or NiMo / alumina catalyst.

[0046] In one or more embodiments, the hydrotreater 30 may be operated at a temperature of 280 °C to 450 °C. In one or more embodiments, the hydrotreater 30 may be operated at a pressure of 5 bar to 160 bar and hydrogen is introduced through the hydrogen inlet. In various further embodiments, the hydrotreater 40 may be operated at a temperature of 280 °C to 425 °C, 280 °C to 400 °C, or 280 °C to 350 °C and a pressure 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 hydrotreater 30 may be operated at a hydrocarbon space velocity of 1 h -1 to 10 h -1 of the hydrocarbon space velocity.

[0047] The first separator unit

[0048] In one or more embodiments, the hydrotreater product stream 180 from the hydrotreater 40 is provided to the first separator unit 50. Thus, referring to Figure 1 and Figure 2, the first separator unit 50 is fluidly connected to the hydrotreater 40. The first separator unit 50 splits the hydrotreater product stream 180 into a C1 fraction 190, a C2 fraction 200, a C3-C4 fraction 205, a hydrotreated light fraction 210 comprising C5 hydrocarbons to hydrocarbons boiling below a second temperature, and a hydrotreated heavy fraction 220 comprising hydrocarbons boiling at or above the second temperature. In various embodiments, the second temperature can 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.

[0049] The first separator unit 50 can comprise 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. The atmospheric distillation unit utilizes fractional distillation (by heating the feed to a temperature at which one or more fractions of the mixture will vaporize while leaving the other fractions as liquids) to separate the feed stream. Additionally, in various embodiments, the first separator unit 50 can be a simple flash column or a true boiling point distillation with at least 15 theoretical plates.

[0050] In one or more embodiments, the first separator unit 50 comprises a plurality of separation units. For ease of illustration, the Figure 1 and Figure 2 shows a single unit operation, but it should be understood that such unit operations can include multiple separate separator units to produce the disclosed product streams.

[0051] Methane cracker

[0052] In one or more embodiments, the C1 fraction 190 from the first separator unit 50 is provided to a methane cracker 60. Thus, referring to Figure 1 and Figure 2 , the methane cracker 60 is fluidly connected to the first separator unit 50. Inside the methane cracker 60, the C1 fraction 190 is converted into a hydrogen stream 230 and a fixed carbon stream 240. Specifically, the methane cracker 60 operates by heating the C1 fraction 190 provided as a feed stream from the first separator unit 50 to decompose methane into hydrogen (forming the hydrogen stream 230) and carbon (forming the fixed carbon stream 240).

[0053] 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 H 2Gas. However, due to kinetic limitations and the high activation energy required to break the stable C-H bonds of methane molecules, non-catalytic thermal decomposition of methane cannot achieve a reasonable yield below approximately 1200 °C. Therefore, in one or more embodiments, a methane cracking catalyst is used in the methane cracker 60 to reduce the activation energy for breaking the C-H bonds. Catalytic methane decomposition achieves a reasonable yield at temperatures as low as 700 °C.

[0054] In various embodiments, the methane cracking catalyst used in the methane cracker 60 is a nickel, cobalt, or iron-based catalyst. These catalysts are desirable due to their low cost and availability. Additionally, in one or more embodiments, a support and a promoter can be added to the metal catalyst to improve its catalytic performance. The common supports used are Al 2 O 3 , MgO, and SiO 2 . In various embodiments, the methane cracking catalyst used in the methane cracker 60 is Ni / CeO 2 , NiLa 2 O 3 , Ni / SiO 2 , Fe / CeO 2 , Fe / La 2 O 3 , Fe / SiO 2 , Ni / SiO 2 , Fe / SiO 2 , Co / SiO 2 , Ni / Mg-O-Al, Rh / Al 2 O 3 , or Rh / Al 2 O 3 -10 wt% Nd 2 O 3 .

[0055] In one or more embodiments, the methane cracker 60 operates at a temperature in the range of 700 °C to 1200 °C. In a further embodiment, the methane cracker 60 operates at a temperature in the range of 700 °C to 1000 °C.

[0056] Ethane steam cracker

[0057] In one or more embodiments, the C2 fraction 200 from the first separator unit 50 is provided to the ethane steam cracker 70. Thus, referring to Figure 1 and Figure 2, the ethane steam cracker 70 is fluidly connected to the first separator unit 50. Inside the ethane steam cracker 70, the C2 fraction 200 is cracked to produce an ethane steam cracker product stream 250 that contains light olefins and aromatics. Generally, steam cracking is a petrochemical process in which saturated hydrocarbons are broken down into smaller, usually unsaturated hydrocarbons. In operation, the C2 fraction 200 is diluted with steam and briefly heated in a furnace of the ethane steam cracker 70 in the absence of oxygen. The reaction occurs rapidly, with a residence time in the millisecond range, and after reaching the cracking temperature, the stream is rapidly quenched to stop the cracking reaction. Specifically, the ethane steam cracker 70 operates by heating the C2 fraction 200 provided as a feed stream from the first separator unit 50 with steam to thermally crack the saturated hydrocarbons of the C2 fraction 200 into light olefins, and mainly ethylene. For the purposes of this disclosure, light olefins are considered to be C2-C4 olefins, including ethylene, propylene, and butene.

[0058] In one or more embodiments, the ethane steam cracker 70 operates at a temperature in the range of 800 °C to 950 °C. It should be understood that compared to a lower severity of operation, a higher cracking temperature (also known as severity) favors the production of shorter-chain hydrocarbons because a greater degree of cracking occurs.

[0059] In one or more embodiments, the ethane steam cracker 70 operates at a hydrocarbon-to-steam ratio in the range of 0.2 to 0.8. In one or more further embodiments, the ethane steam cracker 70 operates at a hydrocarbon-to-steam ratio in the range of 0.2 to 0.5. It should be understood that the hydrocarbon-to-steam ratio represents the ratio of the hydrocarbons provided in the C2 fraction 200 from the first separator unit 50 to the steam that is simultaneously provided to the ethane steam cracker 70.

[0060] Table 1 shown below provides a summary of the steam cracker yields based on the composition of the feed stream to the ethane steam cracker 70. The yield of ethane, the major constituent of the C2 fraction 200, is provided in weight percent, as well as the yields of propane, butane, naphtha, and gas oil (in weight percent) that may be present in small amounts in the C2 fraction 200 due to imperfect separation in the first separator unit 50.

[0061] Table 1: Theoretical Steam Cracker Yields for Various Feeds

[0062]

[0063] Dehydrogenation Reactor

[0064] In one or more embodiments, the C3-C4 fraction 205 is provided to the dehydrogenation reactor 75. Thus, with reference to Figure 1 and Figure 2, the dehydrogenation reactor 75 is fluidly connected to the first separator unit 50. Inside the dehydrogenation reactor 75, the C3-C4 fraction 205 is dehydrogenated to produce a dehydrogenation product stream 255 containing propylene and butene produced from propane and butane in the C3-C4 fraction 205.

[0065] In one or more embodiments, the dehydrogenation reactor 75 has a dehydrogenation catalyst disposed therein to dehydrogenate the C3-C4 fraction 205, thereby producing a dehydrogenation product stream 255 containing propylene and butene. In one or more embodiments, the catalytic bed reactor of the dehydrogenation reactor 75 can operate as a fixed bed reactor. In a further embodiment, the catalytic bed reactor of the dehydrogenation reactor 75 can operate as a moving bed reactor.

[0066] The dehydrogenation catalyst can be selected to effectively dehydrogenate the C3-C4 fraction 205 and produce propylene and butene. According to various embodiments, the dehydrogenation catalyst can be of the zeolite type or the chlorinated alumina type, each containing a noble metal, such as Pt or Pd or a combination of noble metals. Additionally, in various embodiments, the catalyst can comprise an active phase metal supported on a support containing ultrastable (US) Y zeolite, beta zeolite, or mordenite. In the various disclosed embodiments, the zeolite is referred to as USY zeolite, but in these disclosed embodiments, beta zeolite or mordenite can be substituted.

[0067] In one or more embodiments, the dehydrogenation catalyst can comprise an active phase metal supported on a support containing ultrastable (US) Y zeolite, wherein a portion of the aluminum atoms in the USY zeolite framework is replaced by one or more of zirconium, titanium, and hafnium atoms. In one or more embodiments, the support is alumina that acts as a binder. In one or more embodiments, the zeolite can account for 5 wt% to 80 wt% of the total catalyst.

[0068] In one or more specific embodiments, the USY zeolite is framework-modified to contain zirconium and titanium atoms to replace a portion of the aluminum atoms in the framework of the USY zeolite. In one or more embodiments, the USY zeolite can contain 1 wt% to 5 wt% of zirconium and titanium (based on the zeolite).

[0069] In various embodiments, the active phase metal supported on a support containing USY zeolite can be selected from Ru, Rh, Pd, Ag, Os, Ir, Pt, and Au. In one or more embodiments, the active phase metal supported on a support containing USY zeolite is particularly Pt. In one or more embodiments, the active phase metal can account for 0.1 wt% to 1.5 wt% of the total catalyst.

[0070] In one or more embodiments, according to various configurations, the C3-C4 fraction 205 is at 1h -1 to 10h-1 The liquid hourly space velocity (LHSV) is provided to the dehydrogenation reactor 40. In various further embodiments, the C3-C4 fraction 205 is at 1 h -1 to 15 h -1 、1 h -1 to 10 h -1 、2 h -1 to 15 h -1 、3 h -1 to 10 h -1 、3 h -1 to 8 h -1 or about 5 h -1 of LHSV is provided to the dehydrogenation reactor 40.

[0071] In one or more embodiments, according to various configurations, the dehydrogenation reactor 75 can be operated at a reaction temperature of 575 °C to 620 °C. In various embodiments, the dehydrogenation reactor 75 can be operated at a reaction temperature of 590 °C to 620 °C, 600 °C to 620 °C, 575 °C to 600 °C or about 575 °C. It should be understood that as the temperature decreases, the reactivity decreases, but as the temperature increases, the formation of coke also increases.

[0072] In one or more embodiments, according to various configurations, the dehydrogenation reactor 75 can be pressurized. The pressurization can be achieved with hydrogen. In various embodiments, the dehydrogenation reactor 75 is operated at a pressure of 1 bar to 5 bar, 1.5 bar to 5 bar, 2 bar to 5 bar or about 3 bar.

[0073] Aromatization unit

[0074] In one or more embodiments, a hydrotreated light fraction 210 containing C5 hydrocarbons to hydrocarbons boiling below a second temperature is provided to the aromatization unit 80. Thus, referring to Figure 1 and Figure 2 , the aromatization unit 80 is fluidly connected to the first separator unit 50. Within the aromatization unit 80, the aliphatic hydrocarbons in the hydrotreated light fraction 210 are converted to aromatic hydrocarbons through dehydrogenation and dehydrogenation cyclization processes to produce an aromatized product stream 260. The aromatization unit 80 includes at least one aromatization reactor in which an aromatization catalyst is disposed and operable to produce a liquid product stream with an increased aromatic hydrocarbon content in the form of the aromatized product stream 260.

[0075] According to various embodiments, the aromatization catalyst may include a metal oxide component dispersed on the surface of a zeolite support. The metal oxide component may include one or more oxides of metal elements selected from Groups 4 to 13 of the International Union of Pure and Applied Chemistry (IUPAC) Periodic Table (such as Groups 8 to 13 of the IUPAC Periodic Table). In one or more embodiments, the metal element of the one or more metal oxides may be a metal element selected from Groups 4 to 13 and Periods 4 to 6 of the IUPAC Periodic Table (such as Period 4 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 the one or more metal oxides may include gallium, zinc, iron, hafnium, or a combination of these. In one or more embodiments, the metal oxide may be gallium oxide.

[0076] In one or more embodiments, the aromatization catalyst may comprise a gallium-modified H-MFI type zeolite. Specifically, the aromatization catalyst may comprise a catalyst formed by incorporating gallium into an H-MFI type zeolite. Such a catalyst may comprise 1 wt% to 5 wt% of gallium (Ga) (based on the total catalyst). For example, in various embodiments, the gallium-modified H-MFI type zeolite catalyst may comprise 1 wt% to 4 wt% of gallium, 1 wt% to 3 wt% of gallium, 1.5 wt% to 2.5 wt% of gallium, 1.8 wt% to 2.2 wt% of gallium, or about 2 wt% of gallium. It should be understood that other ratios of gallium incorporated within the broadest range are also contemplated, but are not explicitly described for simplicity. As previously mentioned, in various embodiments, gallium may be replaced with alternative metal elements while maintaining the remaining parameters of the disclosed gallium-modified H-MFI type zeolite. In various embodiments, the silica to alumina ratio of the H-MFI type zeolite may vary from 20 to 100, 20 to 80, 20 to 50, or 20 to 30.

[0077] In one or more embodiments, the hydrotreated light fraction 210 from the first separator unit 50 is provided to the aromatization unit 80 at a liquid hourly space velocity (LHSV) of 0.1 h -1 to 10 h -1 . In various further embodiments, the hydrotreated light fraction 210 is provided at a LHSV of 0.1 h -1 to 8 h -1 , 0.3 h -1 to 10 h -1 , 0.5 h -1 to 5 h -1 , 0.8 h -1 to 3 h -1 , 0.8 h -1 to 2 h-1 or about 1 h -1 The LHSV of -1 or about 1 h is provided to the aromatization unit 80. It should be understood that a larger LHSV results in a lower aromatic yield, while a smaller LHSV favors the formation of less desirable heavy aromatics.

[0078] In one or more embodiments, the aromatization unit 80 can be operated at a reaction temperature of 400 °C to 600 °C. In various embodiments, the aromatization unit 80 can be operated 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 a lower temperature results in a lower conversion rate, while a higher temperature results in faster catalyst deactivation.

[0079] In one or more embodiments, the aromatization unit 80 can be operated at a pressure of 1 bar to 35 bar, 5 bar to 35 bar, or 10 bar to 35 bar. It should be understood that a lower pressure favors the aromatization reaction, but actual operation requires a minimum level of positive pressure.

[0080] Steam enhanced catalytic cracking unit

[0081] In one or more embodiments, the hydrotreated heavy fraction 220 containing hydrocarbons boiling at or above a second temperature from the first separator unit 50 is provided to the steam enhanced catalytic cracking unit 90. Thus, referring to 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 produce an SECC product stream 270 containing light olefins. In one or more embodiments, the deasphalted oil product 150, the second delayed coking unit product stream 164, or both are additionally provided to the steam enhanced catalytic cracking unit 90 to produce a combined SECC feed stream 222. Thus, referring to Figure 3 , the steam enhanced catalytic cracking unit 90 can be fluidly connected to the solvent deasphalting unit 20, the delayed coking unit 30, or both.

[0082] Catalytic cracking is a known conversion process used in petroleum refining and is used to convert high-boiling, high-molecular-weight hydrocarbon fractions of petroleum crude oil or other hydrocarbon streams into more valuable gasoline, olefin gases, and other products. Similarly, steam cracking is a known conversion process used in petroleum refining, in which a gaseous or liquid hydrocarbon feed (such as naphtha) is diluted with steam and briefly heated in a furnace under oxygen-free conditions to crack saturated hydrocarbons into smaller, usually unsaturated hydrocarbons, such as olefins. The process according to the present disclosure is steam-enhanced catalytic cracking, which combines the advantages of both catalytic cracking and steam cracking to maximize the production of light olefins. Specifically, it is noted that the steam-enhanced catalytic cracking unit 90 differs from a conventional fluidized catalytic cracking reactor in that they operate in a higher temperature range and the feed also contains a higher steam content. The excess steam and higher temperature convert the feed hydrocarbons of the hydrotreated heavy fraction 220 into a relatively greater amount of light olefins, such as ethylene and propylene. Specifically, it is noted that the steam-enhanced catalytic cracking process carried out in the steam-enhanced catalytic cracking unit 90 allows the heavy stream (such as the hydrotreated heavy fraction 220) to be effectively cracked into light olefins.

[0083] The steam-enhanced catalytic cracking unit 90 can operate 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 comprise a fluidized bed reactor in the form of an upflow reactor (riserreactor) or a downflow reactor (downer reactor) to convert the hydrotreated heavy fraction 220 into a SECC product stream 270 comprising light olefins having carbon atom numbers 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 typically flow in a downward direction, such as entering the top of the reactor and exiting the bottom of the reactor. Similarly, the term "upflow" refers to a catalytic cracking reactor, such as a fluidized bed reactor, in which the reactants typically flow in an upward direction, such as entering the bottom of the reactor and exiting the top of the reactor.

[0084] In one or more embodiments, since the steam enhanced catalytic cracking unit 90 uses 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 fuel and is at least partially coked. Further, as used herein, "regenerated catalyst" refers to a catalyst that exits the catalyst regenerator and is at least partially or substantially free of coke, and "fresh catalyst" refers to a catalyst that newly enters the system and is at least partially or substantially free of coke. The hydrotreated heavy fraction 220 is doped and intimately contacted with an effective amount of heated fresh or regenerated steam enhanced cracking catalyst particles that catalyze the cracking of hydrocarbon molecules within the hydrotreated heavy fraction 220 by breaking carbon-carbon bonds. The SECC product stream 270 and the steam enhanced cracking catalyst are separated, wherein the steam enhanced cracking catalyst is recycled to the regeneration vessel for regeneration of the steam enhanced cracking catalyst.

[0085] Generally, the operating conditions of the steam enhanced catalytic cracking unit 90 configured as a downflow or upflow FCC unit include: a reaction temperature of from about 600 °C to about 750 °C, in certain embodiments from about 625 °C to about 725 °C, and in further embodiments from about 650 °C to about 700 °C; a reaction pressure of from about 1 bar to about 20 bar, in certain embodiments from about 1 bar to about 10 bar, and in further embodiments from about 1 bar to about 2 bar; a contact time in the reactor of from about 0.1 second to about 30 seconds, in certain embodiments from about 0.1 second to about 20 seconds, and in further embodiments from about 0.1 second to about 10 seconds; a catalyst-to-feed ratio (by weight) of from about 3:1 to about 60:1, in certain embodiments from about 4:1 to about 50:1, and in further embodiments from about 6:1 to about 40:1; and a steam-to-feed ratio (by weight) of from about 1:5 to about 1:1, in certain embodiments from about 1:4 to about 1:1, and in further embodiments from about 1:4 to about 2:3. It is noted that the flow rate of the 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 determines the catalyst-to-feed ratio, and the flow rate of the 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 determines the steam-to-feed ratio.

[0086] 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, beta zeolite, 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 for its high hydrothermal stability.

[0087] Second Separator Unit

[0088] In one or more embodiments, the ethane steam cracker product stream 250, the dehydrogenation product stream 255, the aromatization product stream 260, and the SECC product stream 270 are provided to the second separator unit 100. Thus, referring Figure 1 and Figure 2 , the second separator unit 100 is fluidly connected to the ethane steam cracker 70, the dehydrogenation reactor 75, the aromatization unit 80, and the steam enhanced catalytic cracking unit 90. The second separator unit 100 splits the ethane steam cracker product stream 250, the dehydrogenation product stream 255, the aromatization product stream 260, and the SECC product stream 270 into: a hydrogen fraction 280, a C1 stream 290, a C2 stream 300, a C3-C4 alkane stream 305, a light olefin stream 310, a BTX stream 320 containing benzene, toluene, and xylene, and a residue stream 330 containing cracked naphtha, light cycle oil, and heavy cycle oil.

[0089] The second separator unit 100 can 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 utilizes fractional distillation (by heating the feed to a temperature at which one or more fractions of the mixture will vaporize while leaving other fractions as liquids) to separate the feed stream. Additionally, in various embodiments, the second separator unit 100 can be a simple flash tower or a true boiling point distillation with at least 15 theoretical plates.

[0090] 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 should be understood that such unit operations can include multiple individual separator units to produce the disclosed product streams.

[0091] Further Processing

[0092] In one or more embodiments, referring Figure 2 , the hydrogen stream 230 from the methane cracker 60 is provided to the hydrogenator 40. Additionally, in one or more embodiments, the hydrogen fraction 280 from the second separator unit 100 is provided to the hydrogenator 40. Thus, referring Figure 2, the hydrogenator 40 can be fluidly connected to the methane cracker 60. It should be understood that recycling hydrogen generated from the methane cracker 60, the second separator unit 100, or other unit operations within the integrated system to the hydrogenator 40 reduces the need to supply supplemental hydrogen from outside the integrated process to operate the hydrogenator 40.

[0093] In one or more embodiments, referring to Figure 2 , 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 advantageously be supplied to the hydrogenator 40 to increase and reduce the need for any external hydrogen source to operate the hydrogenator 40. Additionally, in one or more embodiments, the hydrogen fraction 280 from the second separator unit 100 is also supplied to the methane cracker 60. It should be understood that supplying 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 supplied as a single combined stream, thereby reducing the separation requirements and complexity of the second separator unit 40. Since a portion of the hydrogen stream 230 from the methane cracker 60 is supplied to the hydrogenator 40, any hydrogen supplied to the methane cracker 90 can simply be depleted. Thus, referring to Figure 2 , the methane cracker 60, the hydrogenator 40, or both can be fluidly connected to the second separator unit 100.

[0094] In one or more embodiments, instead of supplying the hydrogen stream 230 from the methane cracker 60, the hydrogen fraction 280 from the second separator unit 100, or both to the hydrogenator 40, one or both of the hydrogen stream 230 and the hydrogen fraction 280 can be collected or supplied for a fuel cell vehicle. Similarly, hydrogen from one or both of the hydrogen stream 230 and the hydrogen fraction 280 can be supplied to a fuel cell to generate heat and electricity.

[0095] In one or more embodiments, referring to Figure 2 , the C2 stream 300 from the second separator unit 100 is recycled to the ethane steam cracker 70 for further conversion to light olefins, more particularly ethylene. Thus, referring to Figure 2 , the ethane steam cracker 70 can be fluidly connected to the second separator unit 100.

[0096] In one or more embodiments, referring to Figure 2 , the C3 - C4 alkane stream 305 from the second separator unit 100 is recycled to the dehydrogenation reactor 75 for further conversion to propylene and butene. Thus, referring to Figure 2 , the dehydrogenation reactor 75 can be fluidly connected to the second separator unit 100.

[0097] In one or more embodiments, with reference to Figure 2 , a residual stream 330 from the second separator unit 100, which contains cracked naphtha, light cycle oil, and heavy cycle oil, is recycled to the hydrotreater 40 for further processing. Thus, with reference to Figure 2 , the hydrotreater 40 can be fluidly connected to the second separator unit 100.

[0098] In one or more embodiments, the feed separator 10 may additionally produce a waste gas stream 340 containing 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 vapor pressure or other parameters to provide a methane stream to be transferred to the methane cracker 60, a C2 gas stream to be transferred to the ethane steam cracker 70, and a C3-C4 gas stream to be transferred to the dehydrogenation reactor 75.

[0099] Examples

[0100] The following examples illustrate the features of the present disclosure but are not intended to limit the scope of the present disclosure.

[0101] To demonstrate that the methods and systems according to the present disclosure primarily produce value-added petrochemicals (such as benzene, toluene, xylene, and light olefins), the simulated yields formed by each processing unit within the integrated method were calculated. It should be understood that laboratory-scale operations of the integrated method with its complex and multi-unit nature are not practical, and its computer simulation provides a reasonable representation of full-scale industrial implementation. The integrated method as Figure 3 shown was developed for the examples of the present invention.

[0102] The hydrocarbon stream 110 used in the examples of the present invention is Arab Extra Light (AXL) crude oil, and its composition is shown in detail in Table 2.

[0103] Table 2: Hydrocarbon feed stream (AXL) for the examples of the present invention

[0104]

[0105] The hydrocarbon stream 110 is provided to the feed separator 10 to produce a light crude oil fraction 120 and a heavy crude oil fraction 130. Additionally, a waste gas stream 340 is produced. The light crude oil fraction 120 contains AXL-naphtha, which represents hydrocarbons boiling at 200 °C or lower, and the heavy crude oil fraction 130 contains AXL-heavy oil, which represents hydrocarbons boiling at temperatures above 200 °C. The waste gas stream 340 contains C1-C4 gases. Table 3 provides the product yield details from the feed separator 10.

[0106] Table 3: Product yields from the feed separator

[0107]

[0108]

[0109] The heavy crude oil fraction 130 is supplied to the solvent deasphalting unit 20. The yield of the deasphalting unit 20 is 94.1 wt% of the deasphalted oil product 150 (DAO) and 5.9 wt% of the asphalt product 140.

[0110] The resulting asphalt product 140 is supplied to the delayed coking unit 30 to produce solid petroleum coke 170, a first delayed coking unit product stream 162, and a second delayed coking unit product stream 164. The second delayed coking unit product stream 164 includes hydrocarbons having a boiling range from C5 hydrocarbons to 343 °C, and the first delayed coking unit product stream 162 includes the residue of this component. Details of the product yields of the delayed coking unit 30 from the first delayed coking unit product stream 162 and the second delayed coking unit product stream 164 are provided in Table 4. Fuel gas represents light gases containing less than C2, including C2. Liquefied petroleum gas represents C3 and C4 light gases, including both olefins and paraffins. The split between fuel gas and liquefied petroleum gas is at 15 °C. It should be noted that the resulting solid petroleum coke 160 is ignored from the product yields.

[0111] Table 4: Delayed Coking Unit Product Yields

[0112] Component Weight (%) Fuel gas (FG) 10.9 Liquefied petroleum gas (LPG) 6.1 C5 to 350°F (176.7°C) hydrocarbons 18.4 Hydrocarbons from 350°F (176.7°C) to 650°F (343.3°C) 25.1 650°F+ (343.3°C+) hydrocarbons 39.4

[0113] The light crude oil fraction 120 and the delayed coking unit product stream 160 are supplied to the hydrotreater 40 to produce a hydrotreater product stream 180. Table 5 provides details of the product yields from the hydrotreater 40.

[0114] Table 5: Hydrotreater Product Yields

[0115]

[0116]

[0117] The hydrotreater product stream 180 is passed through a first separator unit 50 to produce: a C1 fraction 190, a C2 fraction 200, a C3 - C4 fraction 205, a hydrotreated light fraction 210 containing C5 hydrocarbons to hydrocarbons boiling below 200 °C, and a hydrotreated heavy fraction 220 containing hydrocarbons boiling at 200 °C or higher.

[0118] The C1 fraction 190 is supplied to the methane cracker 60 to produce a hydrogen stream 230 and a fixed carbon stream 240. Table 6 provides details of the product yields from the methane cracker 60.

[0119] Table 6: Methane Cracker Product Yields

[0120] Component Weight (%) <![CDATA[H 2 > 25.0 Carbon 75.0

[0121] The C2 fraction 200 is provided to the ethane steam cracker 70 to produce an ethane steam cracker product stream 250 mainly containing light olefins. The C3-C4 fraction 205 is provided to the dehydrogenation reactor 75 to produce a dehydrogenation product stream 255 containing propylene and butene produced from propane and butane in the C3-C4 fraction 205. Details of the product yields of the combined stream formed by the ethane steam cracker product stream 250 and the dehydrogenation product stream 255 are provided in Table 7.

[0122] Table 7: Product Yields of Ethane Steam Cracker and Dehydrogenation Reactor

[0123] Component Weight (%) <![CDATA[C1 and H 2 > 18.56 Ethylene 57.52 Propylene 9.63 Butadiene 2.74 C5+ 8.24 Benzene 2.17 Toluene 0.39 Fuel oil 0.76

[0124] The hydrotreated light fraction 210 is provided to the aromatization unit 80 to produce an aromatization product stream 260. Details of the product yields from the aromatization unit 80 are provided in Table 8.

[0125] Table 8: Product Yields of Aromatization Unit

[0126] Component Weight (%) <![CDATA[C1 and H 2 > 5.0 C2 - C5 10.0 Benzene 2.0 Toluene 15.0 Xylene 28.0 C9, C10 aromatics 25.0

[0127] The hydrotreated heavy fraction 220 and the deasphalted oil product 150 are provided to the steam enhanced catalytic cracking unit 90 to produce an SECC product stream 270 containing light olefins. Details of the product yields from the steam enhanced catalytic cracking unit 90 are provided in Table 9.

[0128] Table 9: Product Yields of Steam Enhanced Catalytic Cracking Unit

[0129] Component Weight (%) <![CDATA[C1 and H 2 > 3.0 C2 - C4 alkanes 9.2 C2 - C4 alkenes 41.0 Gasoline 27.6 C5-221℃ Light cycle oil (LCO) 8.0 221℃-343℃ Heavy cycle oil (HCO) 5.9 343℃+ Coke 5.2

[0130] The ethane steam cracker product stream 250, the dehydrogenation product stream 255, the aromatization product stream 260, and the SECC product stream 270 are provided to the second separation unit 100 to produce various product streams. Hydrogen and C1 hydrocarbons from the second separation unit 100 are recycled as feed streams back to the methane cracker 60 for methane cracking and H 2Recovery. The C2 hydrocarbons from the second separation unit 100 are recycled as a feed stream back to the ethane steam cracker 70 for further conversion to light olefins. The C3-C4 alkanes are recycled as a feed stream back to the dehydrogenation reactor 75 for further conversion to propane and butane. The residual stream containing cracked naphtha, light cycle oil, and heavy cycle oil is recycled as a feed stream back to the hydrogenator 40 for further processing therein and in downstream unit operations. Additionally, the light olefin stream as a product stream from the second separation unit 100 and the BTX stream containing benzene, toluene, and xylene are collected as desired value-added petrochemicals. Table 10 provides a breakdown of the product yields from the overall system. "Others" includes bottom products such as light cycle oil and heavy cycle oil.

[0131] Table 10: Overall Product Yields

[0132]

[0133] It is noted that embodiments of the present invention show that the value-added petrochemicals in the form of BTX and light olefins are the main products produced by the integrated method and system. Specifically, the products produced are 42.8 wt% light olefins and 24.9 wt% BTX, which together account for more than 65 wt% of the products.

[0134] It should now be understood that various aspects of an integrated method and system for converting crude oil to value-added petrochemicals have been described, and these aspects can be used in combination with various other aspects.

[0135] According to a first aspect, an integrated method for converting crude oil into value-added petrochemicals 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 or below a first temperature and a heavy crude oil fraction boiling above 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 above the first temperature from the feed separator to a solvent deasphalting unit, wherein residual heavy components and asphaltenes having a boiling point above 300 °C are removed from the heavy crude oil fraction to produce an asphaltene product containing asphaltenes and residual heavy components and a deasphalted oil product; (iii) providing the asphaltene product to a delayed coking unit, wherein the asphaltene product undergoes a thermal cracking reaction to obtain solid petroleum coke and a delayed coking unit product stream containing C1-C4 light gases, coker naphtha, and coker gas oil; (iv) providing the light crude oil fraction boiling at or below the first temperature, the deasphalted oil product, and the delayed coking unit product stream to a hydrotreater, wherein the light crude oil fraction, the deasphalted oil product, and the delayed coking unit product stream are hydrotreated to remove heteroatoms and saturate carbon-carbon bonds, thereby producing a hydrotreater product stream; (v) providing the hydrotreater product stream to a first separator unit, wherein the hydrotreater product stream is separated into a C1 fraction, a C2 fraction, a C3-C4 fraction, a hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling at a second temperature, and a hydrotreated heavy fraction containing 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 fraction to an ethane steam cracker, wherein the C2 fraction is cracked to produce an ethane steam cracker product stream containing light olefins and aromatics; (viii) providing the C3-C4 fraction to a dehydrogenation reactor, wherein the C3-C4 fraction is dehydrogenated to produce a dehydrogenation product stream containing propylene and butene produced from propane and butane in the C3-C4 fraction; (ix) providing the hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling below 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 hydrotreated heavy fraction containing hydrocarbons boiling at or above the second temperature to a steam enhanced catalytic cracking unit, wherein the hydrotreated heavy fraction is cracked to produce an SECC product stream containing light olefins;and (xi) providing the ethane steam cracker product stream, dehydrogenation product stream, aromatization product stream, and SECC product stream to a second separator unit, wherein the second separator unit splits the ethane steam cracker product stream, dehydrogenation product stream, aromatization product stream, and SECC product stream into: a hydrogen fraction, a C1 stream, a C2 stream, a C3-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylene, and a residual stream comprising cracked naphtha, light cycle oil, and heavy cycle oil.;

[0136] A second aspect includes the method of the first aspect, wherein the hydrogen stream from the methane cracker is provided to a hydrogenator.

[0137] A third aspect includes the method 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.

[0138] A fourth aspect includes the method of any one of the first to third aspects, wherein the hydrogen fraction from the second separator unit is recycled to the methane cracker or the hydrogenator.

[0139] A fifth aspect includes the method of any one of the first to fourth aspects, wherein the C2 stream from the second separator unit is recycled to the ethane steam cracker for further conversion to light olefins.

[0140] A sixth aspect includes the method of any one of the first to fifth aspects, wherein the C3-C4 alkane stream from the second separator unit is recycled to the dehydrogenation reactor for further conversion to propylene and butene.

[0141] A seventh aspect includes the method of any one of the first to sixth aspects, wherein the residual stream comprising cracked naphtha, light cycle oil, and heavy cycle oil from the second separator unit is recycled to the hydrogenator for further processing.

[0142] An eighth aspect includes the method of any one of the first to seventh aspects, wherein the solvent deasphalting unit operates at a temperature in the range of 120°C to 160°C and a pressure in the range of 1 bar to 40 bar.

[0143] A ninth aspect includes the method of any one of the first to eighth aspects, wherein the coke drums in the delayed coking unit operate at a temperature in the range of 470°C to 505°C and a pressure in the range of 1 bar to 2 bar.

[0144] A tenth aspect includes the method of any one of the first to ninth aspects, wherein the hydrogenator 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.

[0145] The eleventh aspect includes the method of any one of the first to tenth aspects, wherein the methane cracker operates at a temperature in the range of 700 °C to 1000 °C.

[0146] The twelfth aspect includes the method of any one of the first to eleventh aspects, wherein the ethane steam cracker operates at a temperature in the range of 800 °C to 950 °C.

[0147] The thirteenth aspect includes the method of any one of the first to twelfth aspects, wherein the dehydrogenation reactor operates at a temperature in the range of 575 °C to 620 °C and a pressure in the range of 1 bar to 5 bar.

[0148] The fourteenth aspect includes the method of any one of the first to thirteenth aspects, wherein the aromatization unit operates at a temperature in the range of 400 °C to 600 °C and a pressure in the range of 1 bar to 35 bar.

[0149] The fifteenth aspect includes the method of any one of the first to fourteenth aspects, wherein the steam enhanced catalytic cracking unit operates at a temperature in the range of 600 °C to 750 °C and a pressure in the range of 1 bar to 20 bar.

[0150] The sixteenth aspect includes the method of any one of the first to fifteenth aspects, wherein the hydrogenator product stream contains less than 800 ppm of nitrogen and less than 900 ppm of sulfur.

[0151] The seventeenth aspect includes the method of any one of the first to sixteenth aspects, wherein the first separator unit includes a plurality of separation units.

[0152] The eighteenth aspect includes the method of any one of the first to seventeenth aspects, wherein the second separator includes a plurality of separation units.

[0153] The nineteenth aspect includes the method of any one of the first to eighteenth aspects, wherein the deasphalted oil product is supplied to the steam enhanced catalytic cracking unit.

[0154] The twentieth aspect includes the method of any one of the first to nineteenth aspects, wherein the delayed coking unit product stream is separated into a first delayed coking unit product stream and a second delayed coking unit product stream, the second delayed coking unit product stream contains C5 hydrocarbons to hydrocarbons boiling at 343 °C, the residue of the delayed coking unit product stream in the first delayed coking unit product stream, the first delayed coking unit product stream is supplied to the hydrogenator, and the second delayed coking unit product stream is supplied to the steam enhanced catalytic cracking unit.

[0155] According to the twenty - first aspect, an integrated system for converting crude oil into value - added petrochemicals includes: (i) a feed separator for separating a hydrocarbon stream containing crude oil into a light crude oil fraction boiling at or below a first temperature and a heavy crude oil fraction boiling above 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 above the first temperature, wherein residual heavy components and asphaltenes having a boiling point above 300 °C are removed from the heavy crude oil fraction to produce an asphaltene product containing asphaltenes and residual heavy components and a deasphalted oil product; (iii) a delayed coking unit fluidly connected to the solvent deasphalting unit to receive the asphaltene product, wherein the asphaltene product undergoes a thermal cracking reaction to obtain solid petroleum coke and a delayed coking unit product stream containing 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 or below the first temperature, the deasphalted oil product, and the delayed coking unit product stream, wherein the light crude oil fraction, the deasphalted oil product, and the delayed coking unit product stream are hydrotreated to remove heteroatoms and saturate carbon - carbon bonds, thereby producing a hydrotreater product stream; (v) a first separator unit fluidly connected to the hydrotreater to receive the hydrotreater product stream, wherein the hydrotreater product stream is separated into a C1 fraction, a C2 fraction, a C3 - C4 fraction, a hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling below a second temperature, and a hydrotreated heavy fraction containing hydrocarbons boiling at or above the second temperature; (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) an ethane steam cracker fluidly connected to the first separator to receive the C2 fraction, wherein the C2 fraction is cracked to produce an ethane steam cracker product stream containing light olefins and aromatics; (viii) a dehydrogenation reactor fluidly connected to the first separator to receive the C3 - C4 fraction, wherein the C3 - C4 fraction is dehydrogenated to produce a dehydrogenation product stream containing propylene and butene produced from propane and butane in the C3 - C4 fraction; (ix) 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 aromatics to produce an aromatization product stream; (x) a steam - enhanced catalytic cracking unit fluidly connected to the first separator to receive the hydrotreated heavy fraction containing hydrocarbons boiling at or above the second temperature, wherein the hydrotreated heavy fraction is cracked to produce an SECC product stream containing light olefins;and (xi) a second separator fluidly connected to the ethane steam cracker, the dehydrogenation reactor, the aromatization unit, and the steam enhanced catalytic cracking unit to receive the ethane steam cracker product stream, the dehydrogenation product stream, the aromatization product stream, and the SECC product stream, wherein the second separator unit splits the ethane steam cracker product stream, the dehydrogenation product stream, the aromatization product stream, and the SECC product stream into: a hydrogen fraction, a C1 stream, a C2 stream, a C3-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylene, and a residue stream comprising cracked naphtha, light cycle oil, and heavy cycle oil.

[0156] A twenty-second aspect includes the system of the twenty-first aspect, wherein the hydrogen stream from the methane cracker is fluidly connected to a hydrogenator such that the hydrogen stream is provided to the hydrogenator as a feed stream.

[0157] A twenty-third aspect includes the system of the twenty-first or twenty-second aspect, 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.

[0158] A twenty-fourth aspect includes the system of any one of the twenty-first to twenty-third aspects, wherein the C2 stream from the second separator unit is fluidly connected to the ethane steam cracker such that the C2 stream is recycled to the ethane steam cracker for further conversion to light olefins.

[0159] A twenty-fifth aspect includes the system of any one of the twenty-first to twenty-fourth aspects, wherein the C3-C4 alkane stream from the second separator unit is fluidly connected to the dehydrogenation reactor such that the C3-C4 alkane stream is recycled to the dehydrogenation reactor for further conversion to propylene and butene.

[0160] A twenty-sixth aspect includes the system of any one of the twenty-first to twenty-fifth aspects, wherein the residue stream comprising cracked naphtha, light cycle oil, and heavy cycle oil from the second separator unit is fluidly connected to the hydrogenator such that the residue stream is recycled to the hydrogenator for further processing.

[0161] It should be apparent to those skilled in the art that various modifications and variations can be made to the described embodiments without departing from the spirit and scope of the claimed subject matter. Accordingly, this specification is intended to cover various modifications and variations of the described embodiments, provided they are within the scope of the appended claims and their equivalents.

[0162] For the purposes of the present 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 and embodiments in which there are intermediate systems or units between the units that may substantially change the composition of the stream or effluent. As used in the present disclosure, transferring a stream or effluent “directly” from one unit to another means transferring the stream or effluent from the first unit to the second unit without passing the stream or effluent through an intermediate reaction system or separation system that substantially changes the composition of the stream or effluent. Similarly, an indication that two systems are “fluidly connected” indicates that a stream can be transferred directly between the systems. Heat transfer devices (such as heat exchangers, preheaters, coolers, condensers, or other heat transfer equipment) and pressure devices (such as pumps, pressure regulators, compressors, or other pressure devices) are not considered intermediate systems that change the composition of the stream or effluent. Combining two streams or effluents together is also not considered to include an intermediate system that changes the composition of one or both of the combined streams or effluents.

[0163] It should be further understood that a stream can be named according to the components of the stream, and the named component of the stream can be the major component of the stream (such as comprising from 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 comprising a component is disclosed as being transferred from one system component to another system component, that component of the stream is disclosed as being transferred from that system component to the other system component. For example, a disclosed “hydrocarbon stream” being transferred to or from a first system component should be understood as equivalently disclosing “hydrocarbon” being transferred to or from the first system component.

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

[0165] Ranges are provided throughout the present disclosure. It is contemplated that each discrete value encompassed by the range is also included. Additionally, it is equally contemplated that ranges can be formed from each discrete value encompassed by the explicitly disclosed range. For the sake of brevity, no explicit indication is provided after each disclosed range, but a general indication of the present disclosure is provided.

[0166] As used in the present disclosure and the appended claims, the words “comprising,” “having,” and “including” and all grammatical variations thereof each are intended to have an open, non-limiting meaning, excluding no other elements or steps.

Claims

1. An integrated method for converting crude oil into value-added petrochemicals, the method comprises: (i) providing a hydrocarbon stream containing 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) 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 heavy components and asphaltenes having a boiling point higher than 300 °C are removed from the heavy crude oil fraction to produce a deasphalted oil product containing components having a boiling point lower than 300 °C and an asphalt product containing the asphaltenes and residual 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 unit product stream containing C1-C4 light gases, coker naphtha and coker gas oil; (iv) providing the light crude oil fraction boiling at the first temperature or lower, the deasphalted oil product and the delayed coking unit product stream to a hydrotreater, wherein the light crude oil fraction, the deasphalted oil product and the delayed coking unit product stream are hydrotreated to remove heteroatoms and saturate carbon-carbon bonds, thereby producing a hydrotreater product stream; (v) providing the hydrotreater product stream to a first separator unit, wherein the hydrotreater product stream is separated into a C1 fraction, a C2 fraction, a C3-C4 fraction, a hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling at a second temperature, and a hydrotreated heavy fraction containing hydrocarbons boiling at the second temperature or higher, 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 fraction to an ethane steam cracker, wherein the C2 fraction is cracked to produce an ethane steam cracker product stream containing light olefins and aromatics; (viii) providing the C3-C4 fraction to a dehydrogenation reactor, wherein the C3-C4 fraction is dehydrogenated to produce a dehydrogenated product stream containing propylene and butene produced from propane and butane in the C3-C4 fraction; (ix) providing the hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling below the second temperature to an aromatization unit, wherein the aromatization unit converts aliphatic hydrocarbons in the hydrotreated light fraction into aromatics to produce an aromatization product stream; (x) providing the hydrotreated heavy fraction containing hydrocarbons boiling at the second temperature or higher to a steam enhanced catalytic cracking unit, wherein the hydrotreated heavy fraction is cracked to produce an SECC product stream containing light olefins; and (xi) Feed the ethane steam cracker product stream, the dehydrogenation product stream, the aromatization product stream, and the SECC product stream to a second separator unit, wherein the second separator unit splits the ethane steam cracker product stream, the dehydrogenation product stream, the aromatization product stream, and the SECC product stream into: a hydrogen fraction, a C1 stream, a C2 stream, a C3-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylene, and a residue stream comprising cracked naphtha, light cycle oil, and heavy cycle oil.

2. The method according to claim 1, wherein, feed the hydrogen stream from the methane cracker to the hydrogenator.

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

4. The method according to any one of claims 1 to 3, wherein, recycle the hydrogen fraction from the second separator unit to the methane cracker or to the hydrogenator.

5. The method according to any one of claims 1 to 4, wherein, recycle the C2 stream from the second separator unit to the ethane steam cracker for further conversion to light olefins.

6. The method according to any one of claims 1 to 5, wherein, recycle the C3-C4 alkane stream from the second separator unit to the dehydrogenation reactor for further conversion to propylene and butene.

7. The method according to any one of claims 1 to 6, wherein, recycle the residue stream comprising cracked naphtha, light cycle oil, and heavy cycle oil from the second separator unit to the hydrogenator for further processing.

8. The method according to any one of claims 1 to 7, wherein, the solvent deasphalting unit operates at a temperature in the range of 120 °C to 160 °C and a pressure in the range of 1 bar to 40 bar.

9. The method according to any one of claims 1 to 8, wherein, the coke drums in the delayed coking unit operate at a temperature in the range of 470 °C to 505 °C and a pressure in the range of 1 bar to 2 bar.

10. The method according to any one of claims 1 to 9, wherein, the hydrogenator 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.

11. The method according to any one of claims 1 to 10, wherein, the steam enhanced catalytic cracking unit operates at a temperature in the range of 600 °C to 750 °C and a pressure in the range of 1 bar to 20 bar.

12. The method according to any one of claims 1 to 11, wherein, directly feed a portion of the deasphalted oil product to the steam enhanced catalytic cracking unit.

13. The method according to any one of claims 1 to 12, wherein, The product stream of the delayed coking unit is separated into a first delayed coking unit product stream and a second delayed coking unit product stream. The second delayed coking unit product stream contains hydrocarbons boiling from C5 hydrocarbons to hydrocarbons boiling at a temperature of 343 °C. The remainder of the delayed coking unit product stream in the first delayed coking unit product stream. The first delayed coking unit product stream is provided to the hydrogenator, and the second delayed coking unit product stream is provided to the steam enhanced catalytic cracking unit.

14. An integrated system for converting crude oil into value-added petrochemicals, the system comprising: (i) A feed separator for separating a hydrocarbon stream containing 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 heavy components and asphaltenes having a boiling point higher than 300 °C are removed from the heavy crude oil fraction to produce a deasphalted oil product containing components having a boiling point lower than 300 °C and an asphalt product containing the asphaltenes and residual heavy components; (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 unit product stream containing C1-C4 light gases, coker naphtha, and coker gas oil; (iv) A hydrogenator 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 lower, the deasphalted oil product, and the delayed coking unit product stream. Wherein, the light crude oil fraction, the deasphalted oil product, and the delayed coking unit product stream are hydrotreated to remove heteroatoms and saturate carbon-carbon bonds, thereby producing a hydrogenator product stream; (v) A first separator unit fluidly connected to the hydrogenator to receive the hydrogenator product stream. Wherein, the hydrogenator product stream is separated into a C1 fraction, a C2 fraction, a C3-C4 fraction, a hydrotreated light fraction containing C5 hydrocarbons to hydrocarbons boiling at a temperature lower than a second temperature, and a hydrotreated heavy fraction containing hydrocarbons boiling at the second temperature or higher; (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) An ethane steam cracker fluidly connected to the first separator to receive the C2 fraction. Wherein, the C2 fraction is cracked to produce an ethane steam cracker product stream containing light olefins and aromatics; (viii) A dehydrogenation reactor fluidly connected to the first separator to receive the C3-C4 fraction, wherein the C3-C4 fraction is dehydrogenated to produce a dehydrogenated product stream comprising propylene and butene produced from propane and butane in the C3-C4 fraction; (ix) 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 produce an aromatized product stream; (x) 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 produce an SECC product stream comprising light olefins; and (xi) A second separator fluidly connected to the ethane steam cracker, the dehydrogenation reactor, the aromatization unit, and the steam enhanced catalytic cracking unit to receive the ethane steam cracker product stream, the dehydrogenated product stream, the aromatized product stream, and the SECC product stream, wherein the second separator unit separates the ethane steam cracker product stream, the dehydrogenated product stream, the aromatized product stream, and the SECC product stream into: a hydrogen fraction, a C1 stream, a C2 stream, a C3-C4 alkane stream, a light olefin stream, a BTX stream comprising benzene, toluene, and xylene, and a residual stream comprising cracked naphtha, light cycle oil, and heavy cycle oil.

15. The system according to claim 14, wherein: the hydrogen stream from the methane cracker is fluidly connected to the hydrogenator such that the hydrogen stream is provided to the hydrogenator as a feed stream, 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, the C2 stream from the second separator unit is fluidly connected to the ethane steam cracker such that the C2 stream is recycled to the ethane steam cracker for further conversion to light olefins, the C3-C4 alkane stream from the second separator unit is fluidly connected to the dehydrogenation reactor such that the C3-C4 alkane stream is recycled to the dehydrogenation reactor for further conversion to propylene and butene, the residual stream from the second separator unit comprising cracked naphtha, light cycle oil, and heavy cycle oil is fluidly connected to the hydrogenator such that the residual stream is recycled to the hydrogenator for further processing, or a combination thereof.

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