Processing facilities to produce hydrogen and petrochemicals

Abstract

A processing facility is provided that includes a feedstock separation system configured to separate a feed stream into a light stream and a heavy stream, a hydrogen production system configured to produce hydrogen and carbon dioxide from the light stream, and a carbon dioxide conversion system configured to produce synthetic hydrocarbons or carbon dioxide. The processing facility also includes a hydrotreating system configured to process the heavy stream, and a hydrotreater separation system configured to separate the hydrotreating system effluent into a separator tops stream and a separator bottoms stream, the separator bottoms stream being fed to the hydrogen production system.

Description

[Technical Field]

[0001] [Priority Claim] This application claims priority to U.S. Patent Application No. 16 / 701,796, filed December 3, 2019, the entire contents of which are incorporated herein by reference. [Background technology]

[0002] Olefins, such as ethylene, propylene, butylene, and butane, and aromatics, such as benzene, toluene, and xylene, are basic intermediates widely used in the petrochemical and chemical industries. Steam cracking (cracking) and steam reforming (reforming) are used to form olefins and aromatics from feedstocks such as petroleum gas and distillates such as naphtha, kerosene, and gas oil (diesel). Summary of the Invention

[0003] Embodiments described in the Examples herein provide a processing facility that includes a feedstock separation system configured to separate a feed stream into a light stream and a heavy stream, a hydrogen production system configured to produce hydrogen and carbon dioxide from the light stream, and a carbon dioxide conversion system configured to produce synthetic hydrocarbons or carbon dioxide. The processing facility also includes a hydrotreating system configured to process the heavy stream, and a hydrotreater separation system configured to separate the hydrotreating system effluent into a separator tops stream and a separator bottoms stream, the separator bottoms stream being fed to the hydrogen production system.

[0004] Another embodiment described in the Examples herein provides a method comprising separating a feed stream into a light fraction and a heavy fraction, treating the light fraction in a hydrogen production system to form hydrogen and carbon dioxide, and treating the heavy fraction in a hydrotreating system. The hydrotreated effluent from the hydrotreating system is separated into a separator tops stream and a separator bottoms stream. The separator tops stream is treated in a reformer, and the separator bottoms stream is fed to the hydrogen production system. [Brief explanation of the drawings]

[0005] [Figure 1] FIG. 1 is an example of a processing facility that converts crude oil directly into petrochemicals, including both olefins and aromatic petrochemicals.

[0006] [Figure 2A] FIG. 2A is a flow chart of a process for converting crude oil into petrochemicals. [Figure 2B] FIG. 2B is a flow chart of a process for converting crude oil into petrochemicals.

[0007] [Figure 3] FIG. 3 is an example of a processing facility that directly processes a feed stream, such as crude oil or condensate, to form petrochemical products, including both olefinic and aromatic petrochemicals.

[0008] [Figure 4A] FIG. 4A is a flow chart of a process for converting crude oil into petrochemicals. [Figure 4B] FIG. 4B is a flow chart of a process for converting crude oil into petrochemicals. DETAILED DESCRIPTION OF THE INVENTION

[0009] An integrated hydrotreating and cracking process is provided in the examples described herein. In this process, crude oil or condensate is directly converted to hydrogen and petrochemical products, including olefin petrochemicals such as ethylene, propylene, butylene, and butene, and aromatic petrochemicals such as benzene, toluene, and xylene. In this process, the feed stream is split into a light fraction or stream and a heavy fraction or stream. The light fraction, consisting primarily of naphtha boiling range materials, is processed to produce hydrogen. The heavy fraction, consisting primarily of diesel and above boiling range materials, can be cracked to produce various chemicals or petrochemical feedstocks. In one embodiment, the heavy fraction is cracked in a catalytic cracker. In another embodiment, the light fraction is processed in a steam reformer to enhance aromatics production.

[0010] As used herein, the term "crude oil" refers to all crude oil from conventional sources, including crude oil that has undergone some pre-processing. Crude oil can refer to material that has been subjected to one or more of water-oil separation, gas-oil separation, desalting, and stabilization. As used herein, the boiling range of light distillate materials can have boiling points below about 370°C. The boiling range of heavy distillate materials can have boiling points above about 180°C.

[0011] FIG. 1 illustrates an example processing facility 100 that directly converts crude oil into petrochemical products, including both olefins and aromatic petrochemicals. Inputs to and outputs from the processing facility are indicated by bold lines. A crude oil or condensate feed stream 102 is received by a feed separation system 104 of the processing facility 100. The feed separation system 104 separates the feed stream 102 into a light fraction or light stream 106, such as a gas, and a heavy fraction or heavy stream 108, such as a liquid. In some embodiments, the light stream 106 may be a naphtha fraction. In some embodiments, the light stream 106 may have a boiling point below about 180° C., below about 220° C., or below about 370° C. In some embodiments, the heavy stream 108 may have a boiling point above about 180° C., above about 220° C., or above about 370° C.

[0012] In some examples, the feed separation system 104 can be a flash separation device, such as a flash drum. For example, the feed separation system 104 can be a single-stage separation device, such as a flash separator, with a cut point between about 150°C and about 400°C. In various embodiments, the cut point is about 180°C, about 220°C, or about 370°C. In some embodiments, the feed separation system 104 can operate without a flash zone. For example, the feed separation system 104 can include a cyclone-type separation device, a splitter, or another type of separation device based on physical or mechanical separation of vaporized gas and liquid. In a cyclone separation device, the vaporized gas and liquid enter the device through a cyclone geometry. The vaporized gas is swirled in a circular pattern, creating a force that captures heavier droplets and liquid and directs them to a liquid outlet. The vaporized gas is then directed to a vaporized gas outlet. A cyclone separation device operates isothermally with a very short residence time. The cut point of the feed separation system 104 can be adjusted based on factors such as the vaporization temperature, fluid velocity, or both of the material entering the feed separation system 104, or other factors. Further description of separation equipment can be found in U.S. Patent No. 8,337,603, the contents of which are incorporated herein by reference in their entirety.

[0013] The heavy stream 108 is sent to a hydroprocessing system 110 for processing by removal of impurities such as sulfur, metals, nitrogen, or other impurities. In some embodiments, the hydroprocessing system 110 performs a hydrocracking function to form additional products from the heavy stream 108.

[0014] As used herein, a system is an integrated grouping of processing equipment configured to perform a specific function, such as separation, hydrotreating, hydrogen production, etc. Additionally, some systems may include vessels for performing multiple functions. For example, a hydrotreating system may include a separation vessel for separating products into multiple streams. A system may include a single vessel, or multiple vessels, and all associated catalysts, pumps, valves, compressors, and process equipment used to perform the specified function.

[0015] For example, the hydroprocessing system can include a single hydroprocessing vessel with a single catalytic zone or multiple catalytic zones. In other examples, the hydroprocessing system can include multiple vessels, multiple zones, or both, where each reactor or zone may use a different catalyst and conditions to perform a different function, such as hydrodesulfurization, hydrodemetallization, hydrocracking, etc. Hydroprocessing system 110 is described further herein. Hydrogen stream 112 is provided to hydroprocessing system 110.

[0016] In some examples, the selective hydrotreating or hydrotreating process can increase the paraffin content or reduce the viscosity, as measured by the feedstock's Bureau of Mines Correlation Index (BMCI). For example, the heavy stream 108 separated from the feedstock stream 102 can be improved by hydrotreating to saturate multiple carbon-carbon bonds, followed by mild hydrocracking of aromatic compounds, particularly polycyclic aromatic compounds. When hydrotreating crude oil, contaminants such as metals, sulfur, and nitrogen can be removed by passing the feedstock through a series of layered catalysts that perform one or more of the catalytic functions of demetallization, desulfurization, and denitrification. In some examples, the catalyst sequence for performing hydrodemetallization (HDM) and hydrodesulfurization (HDS) can include a hydrodemetallization catalyst, an intermediate catalyst, a hydrodesulfurization catalyst, and a final catalyst.

[0017] The catalyst in the HDM section is approximately 140m 2 / g ~ approx. 240m 2 The catalyst may be based on a gamma alumina support having a surface area of ​​about 1 cm / g. 3The catalyst has a very large pore volume, such as a pore volume exceeding 1 / g. The pore size can be primarily macroporous, providing a large capacity for the incorporation of metals and, optionally, dopants on the catalyst surface. The active metal on the catalyst surface can be nickel (Ni) sulfide, molybdenum (Mo) sulfide, or both, with the Ni:(Ni + Mo) molar ratio being less than about 0.15. The nickel concentration is lower on the HDM catalyst than on other catalysts because some of the nickel and vanadium are expected to deposit from the feedstock itself and subsequently act as a catalyst. The dopant can be one or more of phosphorus, boron, silicon, and a halogen, as described, for example, in U.S. Patent Application Publication No. 2005 / 0211603, the entire contents of which are incorporated herein by reference. In some examples, the catalyst can be in the form of alumina extrudates or alumina beads. For example, alumina beads can be used to facilitate unloading of the catalyst HDM bed in the reactor, as metal uptake can range from 30 to 100% at the top of the bed.

[0018] An intermediate catalyst can be used to transition between the hydrodemetallization and hydrodesulfurization functions. The intermediate catalyst can have an intermediate metal loading and pore size distribution. The catalyst in the HDM / HDS reactor can be an alumina-based support in the form of extrudates, at least one catalytic metal from Group VI (e.g., molybdenum, tungsten, or both), or at least one catalytic metal from Group VIII (e.g., nickel, cobalt, or both), or a combination of any two or more thereof. The catalyst can contain at least one dopant, such as one or more of boron, phosphorus, halogen, and silicon. The intermediate catalyst can be about 140 m 2 / g~about 200m 2 / g surface area of ​​at least about 0.6 cm 3 / g and mesoporous pores with a size of about 12 nm to about 50 nm.

[0019] The catalyst in the HDS section is approximately 180m2 / g ~ approx. 240m 2 The larger surface areas of HDS catalysts can include gamma alumina-based support materials with surface areas near the upper end of the HDM range, such as about 1 cm / g. 3 This results in a relatively smaller pore volume, such as a pore volume of less than 1 / g. The catalyst includes at least one element from Group VI, such as molybdenum, and at least one element from Group VIII, such as nickel. The catalyst also includes at least one dopant, such as one or more of boron, phosphorus, silicon, and a halogen. In some examples, cobalt (Co) can be used to provide a relatively high level of desulfurization. The metal loading for the active stage increases with the desired activity, such that the molar ratio of Ni:(Ni + Mo) is about 0.1 to about 0.3 and the molar ratio of (Co + Ni):Mo is about 0.25 to about 0.85.

[0020] The final catalyst may perform feed hydrogenation rather than having the primary function of hydrodesulfurization. In some instances, the final catalyst may replace the intermediate catalyst and the catalyst in the HDS section. The final catalyst may be promoted with nickel and the support may be wide pore gamma alumina. The final catalyst may be approximately 180 m 2 / g ~ approx. 240m 2 The higher the surface area of ​​the final catalyst, the smaller the pore volume, e.g., a pore volume of about 1 cm. 3 / g or less.

[0021] In some configurations of the processing facility 100, such as that shown in FIG. 1, the lights stream 106 is sent to a hydrogen production system 114. In the hydrogen production system 114, the lights stream 106 can be used to produce a hydrogen product stream 116, for example, using a steam reforming system, a gasification system, or both. A water or steam stream 118 can be added to provide make-up water for the aqueous shift reaction. In the steam reforming process, hydrocarbons are contacted with steam, for example, in a steam reforming reactor, over a nickel catalyst at about 700° C. to about 1000° C. to produce H, CO, and CO. In a second vessel, for example, a separation vessel, the CO is reacted with more steam to form H and CO in the aqueous shift reaction.

[0022] In the gasification process, hydrocarbons from the lights stream 106 are also converted to H, CO, and CO. In gasification, the hydrocarbons are reacted with controlled amounts of oxygen, steam, or both in a gasification reactor, e.g., without combustion, at temperatures above about 700°C. The process is exothermic and can generate heat for use in other parts of the process. In a second vessel, such as a separation vessel, the CO can react with more steam to form H and CO in an aqueous shift reaction.

[0023] In embodiments in which the hydrogen production system 114 includes both steam reforming and gasification systems, the separation section and the aqueous shift system may be integrated. System integration can be achieved using a membrane reformer, in which a hydrogen-selective membrane is used in combination with a reforming catalyst, such as a nickel catalyst or a combination of nickel and a precious metal, such as rhodium and gold, among others. Commercially available steam reforming catalysts may also be used. This allows for the combination of reforming and the water-gas shift action, enabling process intensification of the hydrogen production process. As used herein, the water-gas shift reaction is the reaction of carbon monoxide (CO) with water to form CO and hydrogen. The water-gas shift reaction can use a Cu-Zn-based low-temperature water-gas shift catalyst or an Fe-based high-temperature water-gas shift catalyst.

[0024] As used herein, process intensification is the combination of multiple processes to increase efficiency and improve overall process economics. In embodiments described herein, process intensification can be achieved by combining steam reforming, water-gas shift, and hydrogen separation or purification, which is typically performed in a pressure swing adsorption system in a conventional hydrogen production process. In some embodiments, a membrane reactor integrates these processes into a single reactor by integrating a high-temperature hydrogen-selective membrane, such as a palladium alloy membrane. The membrane separates the produced hydrogen from the reaction environment, which overcomes the thermodynamic equilibrium for the reforming reaction. Simultaneously, CO2 and hydrogen are separated within the reactor. For example, CO2 is removed on the high-pressure side of the membrane reactor, and hydrogen is removed on the low-pressure side.

[0025] In some embodiments, the hydrogen product stream 116 may be used as the source of the hydrogen stream 112 provided to the hydroprocessing system 110 .

[0026] In embodiments in which the hydrogen production system 114 includes a gasification process, gases generated in the gasifier may be aqueous shifted in a membrane reactor, which may operate at about 250°C to about 300°C using a hydrogen-selective membrane and a water-gas shift catalyst, such as a nickel catalyst, integrated within the membrane reactor. This also allows for the separation of CO2 formed on-site, which is removed as CO2 stream 120. In a conventional reforming or gasification process configuration, a pressure swing adsorption (PSA) system may be included in the hydrogen production system 114 for hydrogen purification, including a raw hydrogen stream 126 produced in a steam cracking system 128 and separated in a product separation system 130. The raw hydrogen stream 126 contains hydrogen and methane and is supplied from a demethanizer within the product separation system 130. In some embodiments, a renewable hydrogen stream 127 is combined with the raw hydrogen stream 126. As used herein, renewable hydrogen stream 127 includes hydrogen obtained from renewable energy sources such as hydrogen produced by electrolysis using electricity generated by a solar energy plant, a wind energy plant, a geothermal energy plant, or a biomass reactor, among others.

[0027] The raw hydrogen stream 126 is sent to a PSA system within the hydrogen production system 114. The PSA system may include two columns filled with zeolite absorbent, one active column, and one regenerator column. The hydrogen streams are combined and flow through the active column, which absorbs impurities from the hydrogen stream. In embodiments, the purity of the hydrogen in the product hydrogen stream 116 is greater than about 80 vol%, greater than about 90 vol%, greater than about 95 vol% or higher.

[0028] The CO2 stream 120 is sent to a CO2 conversion system 122 to convert the CO2 to synthetic hydrocarbons or other useful products. Conversion can be achieved by hydrogenation or by further reforming with lighter hydrocarbons under dry or wet conditions. If wet conditions are used, a steam stream 124 can be added. It can be appreciated that CO formed in the hydrogen production system 114 can be sent to the CO2 conversion system 122 along with or instead of the CO2. The CO2 conversion reaction can optionally include a steam reaction to convert the CO2 to H2 and CO. The feedstock can then be fed to a Fischer-Tropsch reactor to convert the hydrogen and carbon monoxide to hydrocarbons. In the Fischer-Tropsch reactor, the H2 and CO are passed over a catalyst at a temperature of about 150°C to about 300°C. Lower temperatures favor higher carbon numbers. The catalyst can be a cobalt-based catalyst, an iron-based catalyst, a ruthenium-based catalyst, or a combination thereof.

[0029] In some embodiments, CO conversion system 122 can produce a product stream 132 comprising methane or syngas, for use as furnace fuel for other systems, such as hydroprocessing system 110 or steam cracking system 128, among others. In some embodiments, product stream 132 is used as a make-up stream for a sales gas pipeline. In some embodiments, product stream 132 is used as a feedstock for a number of chemicals or synthetic fuel streams. In some embodiments, CO may be hydrogenated using hydrogen from hydrogen product stream 116 to form, for example, dimethyl ether (DME), methanol, or other oxygenated compounds as part of product stream 132. Using renewable hydrogen in this process reduces the amount of CO that would otherwise be produced at the processing facility.

[0030] The cut point, i.e., separation temperature, between the lights stream 106 and the heavy stream 108 is adjusted based on economic and technical considerations. In some embodiments, the cut point may be set at about 180° C., about 220° C., or about 370° C. As described herein, the lights stream 106 is expected to be the primary feed to the hydrogen production system 114. Therefore, the cut point may be adjusted based on the need for hydrogen, among other parameters such as composition and feedstock variations.

[0031] As described herein, the hydrotreating system 110 processes the heavy stream 108 using hydrogen from the hydrogen stream 112. The hydrogen stream 112 can be generated in another system and transferred to the hydrotreating system 110, for example, or can be supplied from the hydrogen product stream 116 produced in the hydrogen production system 114. Hydrogen can be added as a proportion of the heavy stream 108 at 0.01 mol%, 0.1 mol%, 0.5 mol%, 1 mol%, 5 mol%, or more. This improves the product from the steamcracking system 128, as steam cracking of materials with higher hydrogen content yields better products. Additionally, removing polynuclear aromatics reduces the tendency for coking in the steamcracker coils. The hydrotreating system 110 also increases the feed available to the steamcracking system 128 by converting heavy hydrocarbon components to lighter hydrocarbons.

[0032] The hydroprocessing system 110 can perform one or more of the following processes, typically in separate zones: hydrodemetallization, hydrodearomatization, hydrodenitrogenation, hydrodesulfurization, and hydrocracking. The hydroprocessing system 110 can include one or more beds containing an effective amount of a hydrodemetallization catalyst. The hydroprocessing system 110 can include one or more beds containing an effective amount of a hydrotreating catalyst having one or more of the functions of hydrodearomatization, hydrodenitrogenation, hydrodesulfurization, and hydrocracking. In some examples, the hydroprocessing system 110 can include multiple catalyst beds, such as two, three, four, five, or another number of catalyst beds. In some examples, the hydroprocessing system 110 can include multiple reactors, each containing one or more catalyst beds of the same or different functions.

[0033] The hydrotreating system 110 can be operated at a temperature between about 300°C and about 450°C, e.g., about 300°C, about 350°C, about 400°C, about 450°C, or another temperature. The hydrotreating system 110 can be operated at a pressure between about 30 bar and about 180 bar, e.g., about 30 bar (3 MPa), about 60 bar (6 MPa), about 90 bar (9 MPa), about 120 bar (12 MPa), about 150 bar (15 MPa), about 180 bar (18 MPa), or another pressure. The hydrotreating system 110 can be operated at a pressure between about 0.1 h and about 180 bar (18 MPa). -1 ~about 10h -1 Liquid hourly space velocity, for example, about 0.1 h -1 , about 0.5h -1 , about 1 hour -1 , about 2h -1 , about 4h -1 , about 6h -1 , about 8h -1 , about 10h -1 , or another liquid hourly space velocity. The liquid hourly space velocity is the ratio of the flow rate of the reaction liquid through the reactor to the volume of the reactor. Products from hydrotreating system 110 include hydrotreater effluent 134 and a light hydrocarbon stream 136. Light hydrocarbon stream 136, which includes, for example, materials having carbon numbers C1-C5, is fed to product separation system 130 for further separation and processing.

[0034] For example, hydrotreater effluent 134, which includes materials having a carbon number of C5 or greater, exits hydrotreater system 110 and is directed to a hydrotreater separation system 138, such as a high-pressure low-temperature or high-temperature separator. In some examples, hydrotreater effluent 134 may be cooled in a heat exchanger (not shown) prior to hydrotreater separation system 138. Hydrotreater separation system 138 separates hydrotreater effluent 134 into a separator top stream 140, which are lower carbon number liquids, such as C8 and below, generally having boiling points up to about 180°C, and ... above about 180°C. 10 and a separator bottoms stream 142, such as materials having a carbon number above 100. In some embodiments, hydrotreater separation system 138 is a flash separation device, such as a flash drum, followed by a heat exchanger or condenser. In some embodiments, hydrotreater separation system 138 operates without a flash zone. In these embodiments, hydrotreater separation system 138 can include a cyclone phase separation device, a splitter, or another type of separation device based on physical or mechanical separation of vaporized gas and liquid. For flash separation devices, these devices can be followed by a heat exchanger or condenser to condense separator tops stream 140.

[0035] The separator top stream 140 is sent to a steam cracking system 128. The steam cracking system 128 is a combination of a gas furnace and a liquid furnace. The steam stream 118 may be fed to one or more furnaces of the steam cracking system 128. The furnaces may be flexible or customized for the portion of the feed sent to the steam cracking system 128. The flow through the steam cracking furnace of the steam cracking system 128 may provide a total exposure time of about 1 millisecond (ms), about 2 milliseconds, about 5 milliseconds, or about 10 milliseconds. A quench tower may be provided immediately after the steam cracking furnace to cool the effluent from the steam cracking furnace and prevent further reaction from occurring. A recycle stream 144 from the product separation system 130 may be used as a secondary feed. The recycle stream 144 typically contains fully saturated hydrocarbons with low carbon numbers, such as ethane and propane. Thus, the recycle stream 144 may be provided to the hydrogen production system 114 or the steam cracking system 128, depending on the economics of hydrogen production or chemical production, for example. The steam cracker product stream 146 is provided from the steam cracking system 128 to the product separation system 130. The steam cracker product stream 146 may include low carbon number compounds such as ethylene, propylene, butene, butadiene, and aromatic compounds such as benzene, toluene, and xylene.

[0036] Separator tops stream 140 from hydrotreater separation system 138 contains hydrocarbons that have previously been desulfurized and processed by hydrotreater system 110. For example, separator tops stream 140 can include naphtha. Separator tops stream 140 can include hydrocarbons having initial and final boiling points between about 150°C and about 230°C, such as about 150°C, about 160°C, about 170°C, about 180°C, about 190°C, about 200°C, about 210°C, about 220°C, about 230°C, or another temperature.

[0037] The separator bottoms stream 142, which includes the heavy bottoms of the hydrotreater effluent 134, has a reduced content of contaminants such as metals, sulfur, or nitrogen, increased paraffinicity, a reduced Bureau of Mines Correlation Index (BMCI), and an increased American Petroleum Institute (API) gravity compared to the crude oil heavy stream 108 input to the hydrotreater system 110. In some examples, the hydrotreater separation system 138 may be a flash separation device such as a flash drum. In some examples, the hydrotreater separation system 138 may operate without a flash zone. For example, the hydrotreater separation system 138 may include a cyclone phase separation device, a splitter, or another type of separation device based on physical or mechanical separation of vaporized gases and liquids. The hydrotreater separation system 138 may include one or more separation devices capable of fractionating hydrocarbon cuts similar to the naphtha range and broader ranges, such as hydrocarbon cuts rich in aromatic precursors.

[0038] The separator bottoms stream 142 is fed to a heavy oil conversion system 148. The separator bottoms stream 142 may include hydrocarbons having an initial boiling point between about 150°C and about 230°C, e.g., about 150°C, about 160°C, about 170°C, about 180°C, about 190°C, about 200°C, about 210°C, about 220°C, about 230°C, or other temperatures; and a final boiling point of 540°C or greater. The initial and final boiling points of the separator tops stream 140, the separator bottoms stream 142, or both, may depend on the type of feed stream 102 input to the processing facility 100. The heavy oil conversion system 148 may also be fed a pyoil (pyrolysis oil) stream 150 from the product separation system 130. A hydrogen stream 112 , which may be sourced from a hydrogen product stream 116 of a hydrogen production system 114 , may be added to a heavy oil conversion system 148 for cracking and hydrogenation of a separator bottoms stream 142 and a pie oil stream 150 .

[0039] In this heavy oil conversion system 148, cracking, hydrogenation, or both are used to reduce the molecular weight of feed streams such as separator bottoms stream 142 and pie oil stream 150. A cracked product stream 152 is fed to product separation system 130. The remaining heavy oil may be combined with a portion of pie oil stream 150 to form a fuel oil product stream 154.

[0040] The product separation system 130 includes all systems for producing chemical products from the conversion process. In various embodiments, the product separation system 130 includes a quench column, a primary fractionation column, a compressor, and a set of columns that enable the production of ethylene 156, propylene 158, mixed C4s 160, and BTX 162. As described herein, BTX refers to benzene, toluene, and xylenes. The product separation system 130 also includes a high-distillation temperature (HDT) and aromatics separation section to process pyrolysis gasoline (pygas) and separate BTX from this stream. The present invention also includes a selective hydrogenation system to saturate triolefins produced in the steam cracking furnace. The product separation system 130 is fed by a light hydrocarbon stream 136 from the hydrotreating system 110, which includes C1-C5 hydrocarbons. Also provided are a steam cracker product stream 146 from the steam cracking system 128 and a cracked product stream 152 from the heavy oil conversion system 148 .

[0041] As described herein, product separation system 130 produces a pie oil stream 150 that can be recycled to heavy oil conversion system 148 or provided as a component of fuel oil product stream 154. Fuel oil product stream 154 can also contain heavy hydrocarbons that cannot be converted in hydrogen production system 114, steam cracking system 128, or heavy oil conversion system 148 or recycled to hydrotreating system 110. Fuel oil product stream 154 can also be a purge stream if a portion of the pie oil is recycled to heavy oil conversion system 148. Fuel oil product stream 154 is expected to be a low sulfur, low viscosity, and high density fuel oil. As used herein, high density fuel oil is defined as a fuel oil having a viscosity of about 750 to about 950 kg / m 3 The conditioning provided in the hydroprocessing system 110 removes sulfur and provides a sulfur content of less than about 5 wt.%, less than about 3.5 wt.%, or less than about 2 wt.%, or even lower. The aromaticity of the fuel oil product stream 154 may be less than about 200 centistokes (cSt) (200 mm 2 / s), approximately 180cSt (180mm 2 / s), approximately 150cSt (150mm 2 / s) or even lower. The high density is due to the high aromaticity of the pie oil formed in the steam cracking system 128. The economic value of this fuel oil can be adjusted by varying the streams used to form the fuel and by adjusting the operating conditions of the different systems.

[0042] 2A and 2B are a flowchart of a process 200 for converting crude oil to petrochemicals. The process begins at block 202, where a crude oil or condensate feed is separated into a light fraction (e.g., gas) and a heavy fraction (e.g., liquid). In block 204, the light fraction is processed to form hydrogen and carbon dioxide, for example, in a reforming process as described herein.

[0043] At block 206, the heavy fraction is processed in a hydrotreating system for removal of impurities such as sulfur, metals, nitrogen, or other impurities, and for hydrocracking. At block 208, the light hydrocarbons from the hydrotreating system, such as the C1-C5 hydrocarbon gases described herein, are sent to a product separation system.

[0044] In block 210, the hydrotreated effluent from the hydrotreating system is separated into a generally gaseous separator tops stream and a substantially liquid separator bottoms stream. In block 212, the separator tops stream is processed in a steam cracker. In block 214, the steam cracking product is fed to a product separation system.

[0045] At block 216, the separator bottoms stream is processed in a heavy oil conversion system. At block 218, cracked hydrocarbons from the heavy oil conversion system are fed to a product separation system. At block 220, an outlet stream from the heavy oil conversion system, the product separation system, or a combined outlet stream of both can be used to provide a fuel oil product stream.

[0046] 2B, a hydrogen product stream is provided from the hydrogen production system at block 222. A portion of the hydrogen product stream is used as a feedstock for the hydrotreating system at block 206, the heavy oil conversion system at block 216, or the carbon dioxide conversion system at block 224. Carbon dioxide from the hydrogen production system at block 204 is processed in the carbon dioxide conversion system at block 224 to form synthetic fuels and other chemicals, which are provided as a carbon dioxide synthesis product stream at block 226, which can be used in downstream processes.

[0047] In block 228, a product separation system separates product and feed streams from the steam cracker product in block 214, the cracked hydrocarbons in block 218, and the light hydrocarbons in block 208. In block 230, a hydrogen stream from the product separation system is fed to a hydrogen production system for further purification, for example, in a pressure swing adsorption (PSA) system integrated into the hydrogen production system. In block 232, heavy oil is fed from the product separation system to a heavy oil conversion system. At least a portion of the heavy oil can be used as a fuel oil product stream in block 220. In block 234, light hydrocarbons can be fed from the product separation system to the hydrogen production system in block 204 or the steam cracker in block 212. In block 236, an ethylene product stream is fed from the product separation system. In block 238, a propylene product stream is fed from the product separation system. In block 240, a mixed C4 product stream is fed from the product separation system. At block 242, a BTX product stream is provided from a product separation system.

[0048] Depending on the composition of the crude oil stream or the economics of the process, the heavy oil conversion system may be omitted. For example, if the crude oil or condensate stream does not contain a high content of high carbon number materials, such as light crude oil, the heavy oil conversion system may not be needed. Furthermore, if the economics of the process do not favor a fuel oil product stream, the heavy oil conversion system may be bypassed or eliminated. In some embodiments, the heavy oil conversion system is present but configured to be bypassed.

[0049] FIG. 3 is an example of a processing facility 300 that directly processes a feed stream 102, such as crude oil or condensate, to form petrochemical products, including both olefins and aromatic petrochemicals. Numbered items are similar as described with respect to FIG. 1 . In this processing facility 300, the heavy oil conversion system 148 is omitted. Instead, the separator bottoms stream 142 is sent to the hydrogen production system 114, and the separator tops stream 140 from the hydrotreater separation system 138 is sent to a catalytic cracker or reformer 302, such as a naphtha reforming system. Because the separator tops stream 140 was processed in the hydrotreating system 110 upstream of the reformer 302, no further hydroprocessing of the separator tops stream 140 occurs before the separator tops stream 140 is fed to the reformer 302. The reformer 302 converts the separator tops stream 140 to a reformate rich in aromatics, such as benzene, toluene, and xylenes (BTX). In some instances, the reformer 302 allows for higher production of xylenes at the expense of lower production of benzene. The reformer 302 may also produce hydrocarbon by-products, such as hydrogen gas and light hydrocarbon gases. The intentional generation of aromatics by processing the separator tops stream 140 in the reformer 302 may increase the overall yield of aromatics from the processing facility 100.

[0050] The reformer 302 includes one or more reactors, such as a hydrocracking reactor, an isomerization reactor, a dehydrocyclization reactor, or a dehydrogenation reactor, or any combination thereof, that convert the separator top stream 140 into a reformate rich in aromatic compounds, such as benzene, toluene, and xylenes (BTX). The reformer 302 can also generate hydrocarbon by-products, such as hydrogen and light hydrocarbon gases. The reformer 302 can include a catalyst compatible with catalytic processes that maximize aromatic compound production. For example, the catalyst can be a monofunctional or bifunctional metal catalyst including one or more of platinum, palladium, rhenium, tin, gallium, bismuth, or other metal catalysts. The catalyst can also be a halogen-containing catalyst, a catalyst using a zeolite, such as zeolite L or ZSM-5 zeolite, a catalyst using a crystalline or amorphous support that is mesoporous or microporous, such as an alumina, silica, or alumina-silica support, or another type of catalyst capable of maximizing aromatic compound production. Additionally, the catalyst may include a hydrotreating catalyst, as described herein.

[0051] The operating conditions of the reformer 302 can be selected to maximize aromatic compound production. The reformer 302 can be operated at a pressure between about 0.01 bar and about 50 bar, e.g., about 0.01 bar (0.001 MPa), about 0.1 bar (0.01 MPa), about 0.5 bar (0.05 MPa), about 1 bar (0.1 MPa), about 5 bar (0.5 MPa), about 10 bar (1 MPa), about 20 bar (2 MPa), about 30 bar (3 MPa), about 40 bar (4 MPa), about 50 bar (5 MPa), or another pressure. The molar ratio of hydrogen to hydrocarbons (hydrogen-to-hydrocarbon molar ratio) in the reformer 302 can be between about 1:1 and about 10:1, e.g., about 1:1, about 2:1, about 4:1, about 6:1, about 8:1, about 10:1, or another ratio. The reformer 302 can be operated at a temperature between about 400°C and about 600°C, for example, about 400°C, about 450°C, about 500°C, about 550°C, about 600°C, or another temperature. The reformer 302 can be operated for about 0.1 h. -1 ~about 5h -1 The liquid hourly space velocity between, for example, about 0.1 h -1 , about 0.5h-1 , about 1 hour -1 , about 2h -1 , about 3h -1 , about 4h -1 , about 5h -1 , or other liquid hourly space velocities.

[0052] In some embodiments, product separation system 130 includes an aromatics extraction system for separating aromatic compounds from the reformate and pyrolysis gasoline using extraction techniques such as solvent extraction, extractive distillation, or other extraction techniques. The aromatics extraction system receives reformate-containing liquid stream 304 from product separation system 130, as well as other product streams generated herein, and produces aromatic product streams. In various embodiments, the aromatic product streams include benzene product stream 306, toluene product stream 308, and xylene product stream 310. The pyrolysis gasoline and other products from reformer 302 and light hydrocarbon stream 136 can be combined with fuel oil product stream 312.

[0053] 4A and 4B are a flowchart of a process 400 for converting crude oil to petrochemicals. The process begins at block 402, where a crude oil or condensate feed is separated into a light fraction, such as gas, and a heavy fraction, such as liquids. In block 404, the light fraction is processed to form hydrogen and carbon dioxide, for example, in a reforming process, as described herein.

[0054] At block 406, the heavy fraction is processed in a hydrotreating system for removal of impurities, such as sulfur, metals, nitrogen, or other impurities, and for hydrocracking. At block 408, the light hydrocarbons from the hydrotreating system, such as the C1-C5 hydrocarbon gases described herein, are sent to a product separation system.

[0055] At block 410, the hydrotreated effluent from the hydroprocessing zone is separated into a separator tops stream, which is generally gaseous, and a separator bottoms stream, which is substantially liquid. At block 412, the separator bottoms stream is sent to the hydrogen production system of block 404.

[0056] The separator top stream is processed in a steam reformer in block 414. In block 416, the reformate from the steam reformer is fed to a product separation system.

[0057] 4B, a hydrogen product stream is provided from the hydrogen production system at block 418. A portion of the hydrogen product stream can be used as a feedstock for the hydrotreating system at block 406, the steam reformer at block 414, or the carbon dioxide conversion system at block 420. Carbon dioxide from the hydrogen production system at block 406 is processed in the carbon dioxide conversion system at block 420 to form synthetic fuels and other chemicals, which can be provided as a synthetic product stream from the carbon dioxide conversion system at block 422 and used in downstream processes.

[0058] In block 424, a product separation system separates the product streams from the steam reformer in block 414 and the hydrotreating system in block 406. In block 426, the hydrogen stream from the product separation system is fed to a hydrogen production system for further purification, for example, in a pressure swing adsorption (PSA) system integrated into the hydrogen production system. In block 428, light hydrocarbons may be fed from the separation system to the hydrogen production system in block 404 or to the steam reformer in block 414.

[0059] As described herein, the product separation system of block 424 can include an aromatics refinery system. At block 430, a benzene product stream is provided from the product separation system. At block 432, a toluene product stream is provided from the product separation system. At block 434, a xylene product stream is provided from the product separation system. At block 436, a fuel oil product stream is provided from the product separation system.

[0060] Embodiments described in the Examples herein provide a processing facility that includes a feedstock separation system configured to separate a feed stream into a light stream and a heavy stream, a hydrogen production system configured to produce hydrogen and carbon dioxide from the light stream, and a carbon dioxide conversion system configured to produce synthetic hydrocarbons or carbon dioxide. The processing facility also includes a hydrotreating system configured to process the heavy stream, and a hydrotreater separation system configured to separate the hydrotreating system effluent into a separator tops stream and a separator bottoms stream, the separator bottoms stream being fed to the hydrogen production system.

[0061] In one embodiment, the feed stream comprises crude oil. In one embodiment, the feed stream comprises condensate.

[0062] In one aspect, the feed separation system comprises a flash drum. In one aspect, the feed separation system comprises a cyclone phase separation device.

[0063] In one aspect, the hydrogen production system comprises a steam reforming reactor. In one aspect, the hydrogen production system comprises a gasification reactor. In one aspect, the hydrogen production system comprises a pressure swing adsorption system.

[0064] In one embodiment, the carbon dioxide conversion system comprises a Fischer-Tropsch reactor. In one embodiment, the carbon dioxide conversion system comprises a dry reforming process.

[0065] In one embodiment, the hydroprocessing system comprises a hydrodemetallization zone, a hydrodearomatization zone, a hydrodenitrogenation zone, a hydrodesulfurization zone, or a hydrocracking zone, or any combination thereof.

[0066] In one aspect, the processing facility includes a reformer configured to process the separator top stream. In one aspect, at least a portion of the hydrogen produced in the hydrogen production system is supplied to the reformer.

[0067] In one aspect, the hydrotreater separation system includes a flash drum. In one aspect, the hydrotreater separation system includes a cyclone phase separation device. In one aspect, the reformer includes an isomerization reactor. In one aspect, the reformer includes a hydrocracking reactor. In one aspect, the reformer includes a dehydrocyclization reactor. In one aspect, the reformer includes a dehydrogenation reactor.

[0068] In one aspect, the processing facility includes a product separation system configured to separate a product stream from a hydrotreating system, a reformer, a heavy oil conversion system, or any combination thereof. In one aspect, the product separation system is configured to provide a raw hydrogen stream to a hydrogen production system.

[0069] Another embodiment described in the Examples herein provides a method comprising separating a feed stream into a light fraction and a heavy fraction, treating the light fraction in a hydrogen production system to form hydrogen and carbon dioxide, and treating the heavy fraction in a hydrotreating system. The hydrotreated effluent from the hydrotreating system is separated into a separator tops stream and a separator bottoms stream. The separator tops stream is treated in a reformer, and the separator bottoms stream is fed to the hydrogen production system.

[0070] In one aspect, light hydrocarbons formed in the hydroprocessing system are fed to a product separation system. In one aspect, a hydrogen product stream is provided from a hydrogen production system. In one aspect, a hydrogen stream is provided from a hydrogen production system to the hydroprocessing system.

[0071] In one embodiment, the steam reformer effluent is fed to a product separation system. In one embodiment, a fuel oil product stream is provided from the product separation system. In one embodiment, a light hydrocarbon stream is fed from the product separation system to a hydrogen production system. In one embodiment, a light hydrocarbon stream is fed from the product separation system to a steam cracker.

[0072] In one aspect, the carbon dioxide is processed in a carbon dioxide conversion system. In one aspect, a synthesis product stream is provided from the carbon dioxide conversion system. In one aspect, the raw hydrogen stream from the product separation system is sent to a hydrogen production system. In one aspect, light hydrocarbons from the product separation system are fed to a hydrogen production system, a reformer, or both.

[0073] In one embodiment, a product separation system is included that includes an aromatics extraction system. In one embodiment, a benzene product stream is provided from the product separation system. In one embodiment, a toluene product stream is provided from the product separation system. In one embodiment, a mixed C4 product stream is provided from the product separation system.

[0074] Other implementations are also within the scope of the following claims. [First Phase] A processing facility that: a feed separation system configured to separate the feed stream into a light stream and a heavy stream; a hydrogen production system configured to produce hydrogen and carbon dioxide from the lights stream; a carbon dioxide conversion system configured to produce synthetic hydrocarbons from the carbon dioxide; a hydroprocessing system configured to process the heavy stream; a hydrotreater separation system configured to separate a hydrotreater system effluent into a separator tops stream and a separator bottoms stream, the separator bottoms stream being supplied to the hydrogen production system; Processing facility. [Second Phase] the feed stream comprises crude oil; 10. The processing facility according to the first aspect. [Third Phase] the feed stream comprises a condensate; 10. The processing facility according to the first aspect. [Fourth Phase] the feed separation system comprises a flash drum. 10. The processing facility according to the first aspect. [Fifth Phase] the feed separation system comprises a cyclone phase separation device; 10. The processing facility according to the first aspect. [Sixth Phase] the hydrogen production system comprises a steam reforming reactor. 10. The processing facility according to the first aspect. [Seventh Phase] the hydrogen production system comprises a gasification reactor; 10. The processing facility according to the first aspect. [Eighth Phase] the hydrogen production system comprises a pressure swing adsorption system. 10. The processing facility according to the first aspect. [9th Phase] the carbon dioxide conversion system comprises a Fischer-Tropsch reactor; 10. The processing facility according to the first aspect. [10th Phase] the carbon dioxide conversion system comprises a dry reforming process; 10. The processing facility according to the first aspect. [11th Phase] the hydroprocessing system comprises a hydrodemetallization zone, a hydrodearomatization zone, a hydrodenitrogenation zone, a hydrodesulfurization zone, or a hydrocracking zone, or any combination thereof; 10. The processing facility according to the first aspect. [12th Phase] a reformer configured to process the separator top stream; 10. The processing facility according to the first aspect. [13th Phase] At least a portion of the hydrogen generated in the hydrogen generation system is supplied to the reformer. 12. A processing facility according to aspect 1. [14th Phase] the hydrotreater separation system comprises a flash drum; 12. A processing facility according to aspect 1. [15th Phase] the hydrotreater separation system comprises a cyclone phase separation device; 12. A processing facility according to aspect 1. [16th stage] The reformer comprises an isomerization reactor. 12. A processing facility according to aspect 1. [17th Phase] The reformer comprises a hydrocracking reactor. 12. A processing facility according to aspect 1. [18th stage] The reformer comprises a dehydrocyclization reactor. 12. A processing facility according to aspect 1. [19th stage] The reformer comprises a dehydrogenation reactor. 12. A processing facility according to aspect 1. [20th Phase] a product separation system configured to separate a product stream from the hydroprocessing system, the reformer, the heavy oil conversion system, or any combination thereof; 12. A processing facility according to aspect 1. [21st Phase] the product separation system is configured to provide a raw hydrogen stream to the hydrogen production system. A processing facility according to the twentieth aspect. [22nd stage] 10. A method comprising: separating the feed stream into a light fraction and a heavy fraction; processing the light distillate in a hydrogen production system to form hydrogen and carbon dioxide; treating the heavy fraction in a hydrotreating system; separating the hydrotreated effluent from the hydrotreating system into a separator tops stream and a separator bottoms stream; treating the separator top stream in a reformer; and supplying the separator bottoms stream to the hydrogen production system. method. [23rd Phase] feeding light hydrocarbons formed in the hydrotreating system to a product separation system; A method according to the twenty-second aspect. [24th Phase] providing a hydrogen product stream from the hydrogen production system. A method according to the twenty-second aspect. [25th Phase] providing a hydrogen stream from the hydrogen production system to the hydroprocessing system; A method according to the twenty-second aspect. [26th stage] feeding the steam reformer effluent to a product separation system; A method according to the twenty-second aspect. [27th stage] providing a fuel oil product stream from a product separation system; A method according to the twenty-second aspect. [28th stage] providing a light hydrocarbon stream from a product separation system to the hydrogen production system; A method according to the twenty-second aspect. [29th stage] providing a light hydrocarbon stream from the product separation system to a steam cracker; A method according to the twenty-second aspect. [30th Phase] treating the carbon dioxide in a carbon dioxide conversion system; A method according to the twenty-second aspect. [31st Phase] providing a synthesis product stream from the carbon dioxide conversion system. A method according to the thirtieth aspect. [32nd stage] delivering a raw hydrogen stream from a product separation system to the hydrogen production system; A method according to the twenty-second aspect. [33rd Phase] feeding light hydrocarbons from a product separation system to the hydrogen production system, the reformer, or both; A method according to the twenty-second aspect. [34th Phase] a product separation system having an aromatics extraction system; A method according to the twenty-second aspect. [35th Phase] providing a benzene product stream from the product separation system. A method according to the thirty-fourth aspect. [36th stage] providing a toluene product stream from the product separation system. A method according to the thirty-fourth aspect. [37th Phase] providing a mixed C4 product stream from the product separation system. A method according to the thirty-fourth aspect.

Claims

1. 1. A processing facility comprising: a feed separation system configured to separate a crude oil stream into two streams, a light stream and a heavy stream, said feed separation system being a flash separator or a cyclone separator; a line connecting the feed separation system to a hydrogen production system and conveying the lights stream to the hydrogen production system; the hydrogen production system configured to produce hydrogen and carbon dioxide from the lights stream, the hydrogen production system comprising a steam reforming reactor; a carbon dioxide conversion system configured to produce synthetic hydrocarbons from the carbon dioxide; a hydroprocessing system configured to process the heavy stream; a hydrotreater separation system configured to separate a hydrotreater system effluent into a separator tops stream and a separator bottoms stream, the separator bottoms stream being supplied to the hydrogen production system; Processing facility.

2. the crude oil stream comprises crude oil; The treatment facility of claim 1 .

3. the crude oil stream comprises condensate; The treatment facility of claim 1 .

4. the feed separation system comprises a flash drum. The treatment facility of claim 1 .

5. the feed separation system comprises a cyclone phase separation device; The treatment facility of claim 1 .

6. the hydrogen production system comprises a gasification reactor; The treatment facility of claim 1 .

7. the hydrogen production system comprises a pressure swing adsorption system. The treatment facility of claim 1 .

8. the carbon dioxide conversion system comprises a Fischer-Tropsch reactor. The treatment facility of claim 1 .

9. the carbon dioxide conversion system comprises a dry reforming reactor; The treatment facility of claim 1 .

10. the hydroprocessing system comprises a hydrodemetallization zone, a hydrodearomatization zone, a hydrodenitrogenation zone, a hydrodesulfurization zone, or a hydrocracking zone, or any combination thereof; The treatment facility of claim 1 .

11. a reformer configured to process the separator top stream; The treatment facility of claim 1 .

12. At least a portion of the hydrogen generated in the hydrogen generation system is supplied to the reformer. The treatment facility of claim 11.

13. the hydrotreater separation system comprises a flash drum; The treatment facility of claim 11.

14. the hydrotreater separation system comprises a cyclone phase separation device; The treatment facility of claim 11.

15. The reformer comprises an isomerization reactor. The treatment facility of claim 11.

16. The reformer comprises a hydrocracking reactor. The treatment facility of claim 11.

17. The reformer comprises a dehydrocyclization reactor. The treatment facility of claim 11.

18. The reformer comprises a dehydrogenation reactor. The treatment facility of claim 11.

19. a product separation system configured to separate a product stream from the hydroprocessing system, the reformer, or a combination thereof; The treatment facility of claim 11.

20. the product separation system is configured to provide a raw hydrogen stream to the hydrogen production system.

20. The treatment facility of claim 19.

21. 1. A method comprising: separating the crude oil stream into two fractions, a light fraction and a heavy fraction, in a flash separator or a cyclone separator; feeding the light distillate directly to a hydrogen production system comprising a steam reforming reactor; processing the light distillate in the steam reforming reactor of the hydrogen production system to form hydrogen and carbon dioxide; treating the heavy fraction in a hydrotreating system; separating the hydrotreated effluent from the hydroprocessing system into a separator tops stream and a separator bottoms stream; treating the separator top stream in a reformer; supplying the separator bottoms stream to the steam reforming reactor of the hydrogen production system. method.

22. feeding light hydrocarbons formed in the hydrotreating system to a product separation system; 22. The method of claim 21.

23. providing a hydrogen product stream from the hydrogen production system.

22. The method of claim 21.

24. providing a hydrogen stream from the hydrogen production system to the hydroprocessing system; 22. The method of claim 21.

25. feeding the product of the reformer to a product separation system; 22. The method of claim 21.

26. The method of claim 1, further comprising providing a fuel oil product stream from the product separation system.

26. The method of claim 25.

27. The method of claim 26, further comprising the step of: supplying a light hydrocarbon stream from the product separation system to the hydrogen production system.

26. The method of claim 25.

28. The method of claim 27, further comprising the step of supplying a light hydrocarbon stream from the product separation system to the reformer.

26. The method of claim 25.

29. treating the carbon dioxide in a carbon dioxide conversion system; 22. The method of claim 21.

30. providing a synthesis product stream from the carbon dioxide conversion system.

30. The method of claim 29.

31. The method of claim 30, further comprising the step of delivering a raw hydrogen stream from the product separation system to the hydrogen production system.

26. The method of claim 25.

32. feeding light hydrocarbons from the product separation system to the hydrogen production system, the reformer, or both; 26. The method of claim 25.

33. the product separation system having an aromatics extraction system; 26. The method of claim 25.

34. providing a benzene product stream from the product separation system.

34. The method of claim 33.

35. providing a toluene product stream from the product separation system.

34. The method of claim 33.

36. providing a mixed C4 product stream from the product separation system.

34. The method of claim 33.

Images