Integrated production of hydrogen, petrochemicals and power

Abstract

A processing facility is provided, the processing facility including an asphaltene and metals (AM) removal system configured to process a feed stream to produce a power generation stream, a hydroprocessing feed stream, and an asphaltene stream. The power generation system is supplied with the power generation feed stream. The hydroprocessing system is configured to process the hydroprocessing feed stream to form a gas stream and a liquid stream. The hydrogen production system is configured to produce hydrogen, carbon monoxide, and carbon dioxide from the gas feed stream. The carbon dioxide conversion system is configured to produce synthetic hydrocarbons from carbon dioxide, and the cracking system is configured to process the liquid feed stream.

Description

[Technical Field]

[0001] [Claiming priority] This application claims priority to U.S. Patent Application No. 16 / 701,760, filed on 3 December 2019, the entire contents of which are incorporated herein by reference. [Background technology]

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

[0003] Embodiments described herein provide a treatment facility. The treatment facility includes an asphaltenes and metals (AM) removal system configured to process a feedstream to produce a power generation stream, a hydrogenation feedstream, and an asphaltenes stream. The power generation system is supplied by the power generation feedstream. The hydrogenation system is configured to process the hydrogenation feedstream to form a gaseous and a liquid stream. A hydrogen generation system is configured to produce hydrogen, carbon monoxide, and carbon dioxide from the gaseous feedstream. A carbon dioxide conversion system is configured to produce synthetic hydrocarbons from carbon dioxide, and a cracking system is configured to process the liquid feedstream.

[0004] Another embodiment described herein provides a method for producing power and petrochemicals in an integrated system. The method includes removing asphaltenes and metals (AMs) from a feedstream in an AM removal system to form a power generation stream, a hydrogenation feedstream, and an asphaltene stream. The power generation stream is supplied to the power generation system. The hydrogenation feedstream is processed in the hydrogenation system to form a gaseous stream and a liquid stream, the gaseous stream being supplied to a hydrogen generation system. The liquid stream is supplied to a cracking system. [Brief explanation of the drawing]

[0005] [Figure 1] Figure 1 shows an example of a processing facility that utilizes a supply flow for direct supply to a power generator (power generating device) and for converting the supply flow into petrochemical products including aromatic petrochemicals.

[0006] [Figure 2A] Figure 2A is a flowchart of a process that uses a supply flow to directly power a generation system while generating petrochemical products. [Figure 2B] Figure 2B is a flowchart of a process that uses a feed flow to directly power a generation system while generating petrochemical products. [Modes for carrying out the invention]

[0007] Hydrogenation and cracking processes, as part of an integrated system with a power generation system, are provided in the embodiments described herein. These processes directly process a feedstream containing crude oil or condensate to produce power, hydrogen, and petrochemicals, including aromatic petrochemicals such as benzene, toluene, and paraxylene. In addition to power, these technologies can be used to produce synthesis gas and potentially hydrogen. When targeting low-carbon footprint fuels, CO2 from steam reforming technologies can be captured, used, or stored.

[0008] The supply flow is processed in an asphalt and metal removal system to form three flows, including a first flow that is deasphaltized and demetallated to form a power generation flow. The power generation flow can be used directly to supply power to a turbine generation system and has performance similar to, for example, diesel fuel. Thus, the power generation flow replaces the diesel flow from the refinery, reducing the cost of the refining process.

[0009] A second flow formed from the feed flow is deasphaltized, but may contain some metal, and is used as the hydrogenation feed flow. A third flow, containing mostly asphalt and metal, may be used to supply the asphalt product flow, or it may be processed in a heavy oil conversion system, coker, heavy metal extraction unit, or any combination thereof. Depending on the embodiment, the third flow is supplied to a gasifier or partial oxidation unit for hydrogen production, synthetic hydrocarbon production, or both.

[0010] As used herein, the term "crude oil" refers to all crude oil from conventional sources, including crude oil that has undergone some pretreatment. For example, crude oil can refer to a material that has been subjected to one or more of water-oil separation, gas-oil separation, desalting, and stabilization. As used herein, naphtha boiling range materials can have a boiling point of less than about 300 °C. Materials with a boiling range above diesel can have a boiling point above about 180 °C.

[0011] As used herein, a system or processing system is an integrated group of processing equipment configured to perform specific functions such as power generation (production), separation, hydrotreating, cracking, hydrogen production, etc. Further, a system often includes vessels and other equipment to perform multiple functions. For example, a hydrotreating system can include a separation vessel for separating an effluent into multiple streams. A processing system can include a single vessel, or multiple vessels, and all associated catalysts, pumps, valves, compressors, and processing equipment used to perform the designated functions. Similarly, a power generation system can include one or more turbine-driven generators, each of which includes one or more combustors, an air supply system, a cooling system, etc.

[0012] Figure 1 shows an example of a processing facility 100 that utilizes a feed stream 102 to directly supply fuel to a power generator and converts the feed stream into petrochemicals including hydrogen and aromatic petrochemicals. The feed stream 102, which may be crude oil or condensate, is received by an asphaltene and heavy metal (AM) removal system 106. Generally, the feed stream 102 has a distillation curve in the range of about 0°C to about 900°C, or about 30°C to about 600°C. The AM removal system 106 may be a solvent deasphalting system that makes lighter hydrocarbons soluble, leaving less soluble asphaltenes and associated metals behind. The solvent deasphalting unit typically operates at 45°C to 250°C and pressures of about 15 bar (1.5 MPa) to about 50 bar (5.0 MPa). The solvent-to-crude oil ratio (solvent:crude oil) is about 4:1 to about 13:1.

[0013] The AM removal system provides a power generation flow 108 that is sent to the power generation system 104 and can be burned in the combustor 110 to supply power to the gas turbine. In various embodiments, the turbine is an advanced and future gas turbine having an E-class, F-class, H-class, J-class, or higher turbine inlet temperature. The power generation flow 108 is a high-purity oil flow with very little or no asphaltene and low content of heavy metals such as vanadium and nickel. In various embodiments, asphaltene is absent in the power generation flow 108 or is less than about 1 ppm, less than about 5 ppm, or less than about 10 ppm. In various embodiments, the power generation flow 108 has a temperature of less than about 0.5 ppmv, or about 0.5 ppmv to about 0.7 ppmv, or about 0.7 ppmv to 1.2 ppmv.

[0014] The levels of heavy metals such as vanadium in the power generation stream 108 can be controlled to meet the requirements of the power generation system 104 in order to maximize power generation while reducing operating costs, for example, by chemical injection for maintenance, water injection, or corrosion mitigation. Higher efficiency in the gas turbine within the power generation system 104 can be obtained by raising the firing temperature of the combustor compared to heavier oils or oils containing heavy metals. The power generation stream 108 can include light fractions up to a boiling point corresponding to heavy naphtha or kerosene ranges having a boiling point up to about 260°C.

[0015] Furthermore, during the processes of decoking and demetallization, the sulfur level in the treated streams, such as the power generation stream 108 and the hydrotreating feed stream 112, is reduced. The reduction is typically in the range of about 20% to about 30% compared to the feed stream 102. This reduces the SOx emissions from the power generation system 104 and the need for desulfurization.

[0016] The hydrotreating feed stream 112 is, for example, a medium purity stream that either does not contain asphaltenes or has a low asphaltene content, such as less than about 5 wt%, less than about 7 wt%, or less than about 10 wt%. Furthermore, the hydrotreating feed stream 112 can have a moderate heavy metal content. For example, the heavy metal content can range from about 0.5 ppmv to about 100% of the heavy metal content of the feed stream 102. The hydrotreating feed stream 112 can include middle and heavy fractions having a boiling point above, for example, 180°C.

[0017] The hydrogenation feed stream 112 is sent to the hydrogenation system 114 to remove impurities such as sulfur, metals, nitrogen, or other impurities. In some embodiments, the hydrogenation system 114 performs a hydrocracking function to form additional products from the hydrogenation feed stream 112. As shown in Figure 1, in some embodiments, a portion of the hydrogenation feed stream 112 can be combined with a power generation stream 108 to control, for example, the level of impurities in the power generation stream 108. This can be done when the feed stream 102 has a lower asphaltene or metal content, allowing more of the feed stream 102 to be sent to the power generation system 104.

[0018] The hydrogenation system 114 may include a single catalyst zone or a single hydrogenation vessel having multiple catalyst zones. In other examples, the hydrogenation system may include multiple vessels, each of which may use different catalysts and conditions to perform different functions such as hydrodesulfurization, hydrodemetallation, and hydrocracking. The hydrogenation system 114 is further described herein. A hydrogen stream 116 is supplied to the hydrogenation system 114.

[0019] In some cases, selective hydrogenation or hydrogenation processes can be improved by increasing the paraffin content or decreasing the viscosity, as measured by the Bureau of Mines Correlation Index (BMCI) of the feedstock. For example, a hydrogenation feedstream 112 may be improved by hydrogenating to saturate multiple carbon-carbon bonds, followed by gentle hydrocracking of aromatic compounds, particularly polycyclic aromatic compounds. When hydrogenating crude oil, contaminants such as metals, sulfur, and nitrogen can be removed by passing the feedstock through a series of layered catalysts performing one or more catalytic functions of demetallization, desulfurization, and denitrification. In some cases, a sequence of catalysts for carrying out hydrodemetallization (HDM) and hydrodesulfurization (HDS) may include a hydrodemetallization catalyst, an intermediate catalyst, a hydrodesulfurization catalyst, and a final catalyst.

[0020] The catalyst in the HDM section is approximately 140m 2 / g ~ approx. 240m 2 This catalyst can be based on a gamma alumina support having a surface area of ​​approximately 1 cm². 3It has very large pore volumes, such as pore volumes exceeding / g. The pore size can be mainly macroporous, which provides a large capacity for the uptake of metal 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 a Ni:(Ni+Mo) molar ratio of less than about 0.15. The concentration of nickel is lower on HDM catalysts than on other catalysts, as some nickel and vanadium are expected to deposit from the feed material itself and consequently act as catalysts. The dopants can be one or more of phosphorus, boron, silicon, and halogens, as described, for example, in U.S. Patent Application Publication 2005 / 0211603, the entire contents of which are incorporated herein by reference. In some examples, the catalyst may be in the form of alumina extruded or alumina beads. For example, alumina beads can be used to facilitate the unloading of the catalyst HDM bed in the reactor, because metal uptake can range from 30% to 100% at the top of the bed.

[0021] An intermediate catalyst can be used to facilitate the transition between the hydrodemetallation and hydrodesulfurization functions. The intermediate catalyst may have a distribution of intermediate metals and pore sizes. The catalyst in the HDM / HDS reactor may be an alumina-based carrier in the form of an extruded material, at least one catalyst metal from group VI (e.g., molybdenum, tungsten, or both), or at least one catalyst metal from group VIII (e.g., nickel, cobalt, or both), or any two or more combinations thereof. The catalyst may contain at least one dopant, such as one or more of boron, phosphorus, halogens, and silicon. The intermediate catalyst is approximately 140 m 2 / g~about 200m 2 Surface area per g, at least about 0.6 cm² 3 It can have a pore volume of 1 / g and mesoporous pores with a size of approximately 12 nm to 50 nm.

[0022] The catalyst in the HDS section is approximately 180m2 / g ~ about 240 m 2 / g, and can include a gamma - alumina - based support material having a surface area close to the upper limit of the HDM range. A larger surface area of the HDS catalyst results in a relatively smaller pore volume, such as a pore volume of less than about 1 cm 3 / 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 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 as the desired activity increases such that the molar ratio of Ni:(Ni + Mo) is from about 0.1 to about 0.3 and the molar ratio of (Co + Ni):Mo is from about 0.25 to about 0.85.

[0023] The final catalyst is not for the main function of hydrodesulfurization but can hydrogenate the feedstock. In some examples, the final catalyst can replace the intermediate catalyst and the catalyst in the HDS section. The final catalyst can be promoted by nickel, and the support can be macroporous gamma - alumina. The final catalyst can have a surface area close to the upper limit of the HDM range, such as about 180 m 2 / g ~ about 240 m 2 / g. The larger the surface area of the final catalyst, the relatively smaller the pore volume, for example, the pore volume is less than about 1 cm 3 / g.

[0024] As described herein, the hydrogenation system 114 processes the hydrogenation feed stream 112 with hydrogen from a hydrogen stream 116. The hydrogen stream 116 can be generated, for example, in another system of the treatment facility 100 and transferred to the hydrogenation system 114. Hydrogen may be added as a percentage of the hydrogenation feed stream 112 of 0.1 mol%, 0.5 mol%, 1 mol%, 5 mol%, or more. This can improve the product from the cracker, as cracking of materials with a higher hydrogen content yields a better product. The hydrogenation system 114 also increases the amount of feed available for cracking or power generation via conversion.

[0025] As described herein, the hydrogenation system 114 can generally carry out one or more of the following processes in separate reaction zones: hydrogenation demetallation, hydrogenation dearomaticization, hydrogenation denitrification, hydrogenation desulfurization, and hydrogen cracking. The process(s) can be carried out in a single reactor having multiple zones, or in multiple reactors. The hydrogenation system 114 can include one or more beds containing an effective amount of hydrogenation catalyst. The hydrogenation system 114 can include one or more beds containing an effective amount of hydrogenation catalyst having one or more functions of hydrogenation dearomaticization, hydrogenation denitrification, hydrogenation desulfurization, and hydrogen cracking. In some examples, the hydrogenation system 114 can include multiple catalyst beds, such as two, three, four, five, or another number of catalyst beds. In some examples, the hydrogenation system 114 can include multiple reaction vessels, each containing one or more catalyst beds having the same or different functions.

[0026] The hydrogenation treatment system 114 can operate at temperatures ranging from approximately 300°C to approximately 450°C, for example, approximately 300°C, approximately 350°C, approximately 400°C, approximately 450°C, or other temperatures. The hydrogenation treatment system 114 can operate at pressures ranging from approximately 30 bar to approximately 180 bar, for example, approximately 30 bar (3 MPa), approximately 60 bar (6 MPa), approximately 90 bar (9 MPa), approximately 120 bar (12 MPa), approximately 150 bar (15 MPa), approximately 180 bar (18 MPa), or other pressures. The moisture treatment system 114 operates for approximately 0.1 hours. -1 ~about 10h -1 The liquid space velocity, for example, about 0.1h -1 , about 0.5h -1 Approximately 1 hour -1 , about 2h -1 , about 4h -1 , about 6h -1 , about 8h -1 , about 10h -1 Alternatively, it can be operated at a different liquid space velocity. The liquid space velocity is the ratio of the flow rate of the reaction liquid through the reactor to the volume of the reactor.

[0027] The products from the hydrogenation system 114 include a liquid stream 118 and a gas stream 120. The liquid stream 118 and gas stream 120 may be generated from the hydrogenated effluent by a separator within the hydrogenation system 114. The separator may be a high-pressure low-temperature or high-temperature separator. In some examples, the effluent may be cooled in a heat exchanger before the separator. The separator separates the hydrogenated effluent into a gas stream 120 containing liquids with lower carbon numbers (e.g., C4 and below) generally having boiling points up to about 180°C, and a liquid stream 118 generally having boiling points higher than about 180°C (e.g., materials with C5 and above). In some embodiments, the separator is a flash separation device such as a flash drum, followed by a heat exchanger or condenser. In some embodiments, the separator operates without a flash zone. In these embodiments, the separator may include a cyclone phase separator, a splitter, or another type of separation device based on the physical or mechanical separation of vaporized gas and liquid. With respect to the flash separator, a heat exchanger or condenser for condensing the gas flow 120 may be provided following these devices.

[0028] In a processing facility 100 configured as shown in Figure 1, the gas stream 120 is sent to a hydrogen production system 122. In the hydrogen production system 122, the gas stream 120 can be used to generate a hydrogen stream 124 using, for example, a steam reforming system, a gasification system, a partial oxidation system, or a combination thereof. Water or a steam stream 126 can be added to provide makeup water for the aqueous shift reaction. For partial oxidation or gasification, an air or oxygen stream can also be supplied to the reactor of the hydrogen production system 122. In the steam reforming method, hydrocarbons are brought into contact with steam at about 700°C to about 1000°C on a nickel catalyst, for example, in a steam reforming reactor, to produce H2, CO, and CO2. In a second vessel, for example, a separation vessel, the CO is reacted with more steam in the aqueous shift reaction to form H2 and CO2. In some embodiments, the stream is supplied to a hydrogen separation process that effectively separates hydrogen from the remaining CO and CO2 without going through the aqueous shift reaction. Next, the flow containing CO / CO2 is supplied to unit 136, which converts CO and CO2 into synthetic fuels or chemical substances.

[0029] In the gasification process, hydrocarbons from gaseous flow 120 are also converted to H2, CO, and CO2. In gasification or partial oxidation, hydrocarbons react with controlled amounts of oxygen, steam, or both in a gasification reactor at a temperature higher than approximately 700°C, for example, without combustion. 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, CO can react with more steam to form H2 and CO2 in an aqueous shift reaction.

[0030] In embodiments where the hydrogen production system 122 includes both a steam reforming and a gasification system, 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 together with a reforming catalyst such as a nickel catalyst. This allows for the combination of reforming and aqueous gas shifting actions, enabling process enhancement of the hydrogen production process. In some embodiments, the hydrogen stream 124 is used as a source for the hydrogen stream 116 supplied to the hydrogenation system 114.

[0031] In embodiments of the hydrogen production system 122 that include a gasification process, the gas generated in the gasifier may be aqueous-shifted in a membrane reactor, which can be operated at approximately 250°C to approximately 300°C using a hydrogen-selective membrane and an aqueous-gas shift catalyst, such as a nickel catalyst, integrated within the membrane reactor. This also allows for the separation of CO2 formed in situ, which is removed as a CO2 stream 128.

[0032] In a conventional reforming or gasification process configuration, a pressure swing absorption (PSA) system may be included in a hydrogen production system 122 for hydrogen purification and includes a raw hydrogen stream 130 produced in a cracking system such as a reformer 132 and separated in a product separation system 134. The raw hydrogen stream 130 contains hydrogen and methane and is supplied from a demethaner inside the product separation system 134. The raw hydrogen stream 130 is sent to a PSA system in the hydrogen production system 122. The PSA system may include two columns filled with zeolite absorbent, one active column, and one regenerating column. The hydrogen streams are combined and flow through the active column, which absorbs impurities from the hydrogen stream. In the embodiment, the purity of hydrogen in the hydrogen stream 124 is greater than about 80 vol%, greater than about 90 vol%, greater than about 95 vol%, or higher.

[0033] The CO2 stream 128 is sent to the CO2 conversion system 136 to convert the CO2 into synthetic hydrocarbons or other useful products. The conversion can be carried out by hydrogenation or by further modification under dry or wet conditions using lighter hydrocarbons. When wet conditions are used, a steam stream may be added. It can be understood that the CO formed in the hydrogen production system 122 may be sent to the CO2 conversion system 136 together with or instead of the CO2. The CO2 conversion reaction may, if necessary, include a steam reaction to convert the CO2 into H2 and CO. The feedstock can then be supplied to a Fischer-Tropsch reactor to convert the hydrogen and carbon monoxide into hydrocarbons. In the Fischer-Tropsch reactor, H2 and CO are flowed over the catalyst at a temperature of about 150°C to about 300°C. Lower temperatures are favorable for higher carbon numbers. The catalyst may be a cobalt-based catalyst, an iron-based catalyst, a ruthenium-based catalyst, or a combination thereof.

[0034] In some embodiments, the CO2 conversion system 136 can produce a product stream 138 containing methane or synthesis gas as furnace fuel for other systems, such as the hydrogenation system 114 or the reformer 132. In some embodiments, the product stream 138 is used as a feed stream for a sales gas pipeline. In some embodiments, the product stream 138 is used as a feedstock for many other chemical or synthetic fuel streams. In some embodiments, the CO2 is hydrogenated using hydrogen from the hydrogen stream 116 to form dimethyl ether (DME), methanol, or other oxygenated compounds, for example, as part of the product stream 138. In some embodiments, the CO2 stream 128 is supplied to the CO2 pipeline for enhanced oil recovery or sequestration.

[0035] A portion of the liquid flow 118 from the hydrogenation system 114 can be blended with the power generation flow 108 to form a blended flow. Using the blend of hydrogenated liquid flow 118, the Wobbe index of the fuel supplied to the power generation system 104 can be adjusted, thereby reducing its sulfur content. As used herein, the Wobbe index is a measure of the energy output that can be obtained from the combustion of a fuel, and is calculated by dividing the calorific value obtained from the combustion of the fuel by the square root of the fuel's specific gravity. For example, lighter hydrocarbons with fewer carbon atoms generally have a lower Wobbe index than heavier hydrocarbons. For example, the Wobbe index of methane is approximately 50 MJ / Nm³. 3 Therefore, the Wobbe index for inbutan is approximately 88 MJ / Nm 3 That is the case.

[0036] The remaining liquid flow 118 from the hydrogenation system 114 is sent to a reformer 132, such as a naphtha reforming system. The reformer 132 may be a continuous catalytic reforming (CCR) system. In some embodiments, the reformer 132 is replaced by a cracking system, for example, a steam cracking furnace. Since the liquid flow 118 has been treated in the hydrogenation system 114 upstream of the reformer 132, no further hydrogenation treatment of the liquid flow 118 takes place before it is supplied to the reformer 132. The reformer 132 converts the liquid flow 118 into a reformed flow 140 or effluent rich in aromatic compounds such as benzene, toluene, and xylene (BTX). In addition to aromatic compounds, the reformed flow 140 may include hydrogen, liquid propane gas, and paraffinic raffinates. In some examples, the reformer 132 allows for a high production of xylene at the expense of a lower production of benzene.

[0037] The reformer 132 includes one or more reactors that convert the liquid flow 118 into a reformed flow 140 using reactions such as hydrocracking, isomerization, dehydrogenation cyclization, and dehydrogenation. The reformer 132 may include a catalyst that is suited to a catalytic process that maximizes the production of aromatic compounds. For example, the catalyst may be a monofunctional or bifunctional metal catalyst comprising one or more of platinum, palladium, rhenium, tin, gallium, bismuth, or other metal catalysts. The catalyst may also be a halogen-containing catalyst, a catalyst using a zeolite such as zeolite L or ZSM-5 zeolite, a catalyst using a mesoporous or microporous crystalline or amorphous support such as alumina, silica, or an alumina-silica support, or another type of catalyst that can maximize aromatic products. Furthermore, the catalyst may include a hydrogenation catalyst as described herein.

[0038] The operating conditions of the reformer 132 can be selected to maximize aromatic products. The reformer 132 can operate at pressures ranging from approximately 0.01 bar to approximately 50 bar, for example, approximately 0.01 bar (0.001 MPa), approximately 0.1 bar (0.01 MPa), approximately 0.5 bar (0.05 MPa), approximately 1 bar (0.1 MPa), approximately 5 bar (0.5 MPa), approximately 10 bar (1 MPa), approximately 20 bar (2 MPa), approximately 30 bar (3 MPa), approximately 40 bar (4 MPa), approximately 50 bar (5 MPa), or other pressures. The molar ratio of hydrogen to hydrocarbons in the reformer 132 can range from approximately 1:1 to approximately 10:1, for example, approximately 1:1, approximately 2:1, approximately 4:1, approximately 6:1, approximately 8:1, approximately 10:1, or other ratios. The reformer 132 can operate at temperatures of approximately 400°C to approximately 600°C, for example, approximately 400°C, approximately 450°C, approximately 500°C, approximately 550°C, approximately 600°C, or other temperatures. The reformer 132 operates for approximately 0.1 hours. -1 ~about 5h -1 The liquid space velocity, for example, about 0.1h -1 , about 0.5h -1 Approximately 1 hour -1 , about 2h -1 , about 3h -1 , about 4h -1 , about 5h -1 Alternatively, it can operate at a different liquid space velocity.

[0039] In some embodiments, the product separation system 134 includes an aromatic extraction system for separating aromatic compounds from the reformed flow 140 using an extraction technique such as solvent extraction, extractive distillation, or other extraction techniques. The aromatic extraction system receives the reformed flow 140 and other product flows produced herein to generate aromatic and non-aromatic product flows. In various embodiments, the aromatic product flows include a benzene product flow 142, a toluene product flow 144, a paraxylene product flow 146, and a heavy aromatic product flow 148. Non-aromatic flows that may be generated from the product separation system 134 generally include a recycled flow 150 containing fully saturated light hydrocarbons such as ethane and propane. Other flows that may be generated from the product separation system 134 may include a pyrolytic gasoline flow, a heavy fuel oil flow, and the like. The recycled flow 150 may be supplied to the reformer 132, the hydrogen production system 122, or split between them, depending on the economics of hydrogen production or chemical production.

[0040] In various embodiments, the reformer 132 can be replaced with another type of cracking system for processing the liquid flow 118. For example, a steam cracking system can be used instead of the reformer 132. A steam cracking system is a combination of a gas furnace and a liquid furnace. The steam feed is supplied to one or more furnaces of the steam cracking system. The furnaces may be flexible or customized to accommodate some of the feed sent to the steam cracking system. The flow through the steam cracking furnace of the steam cracking system can provide a total exposure time of about 1 millisecond (ms), about 2 ms, about 5 ms, or about 10 ms. A quench tower can be provided immediately after the steam cracking furnace to cool the effluent from the steam cracking furnace and stop further reactions. With respect to the reformer 132, the steam cracking system can use the recycled flow 150 from the product separation system 134 as a secondary feed.

[0041] Similar to the reformed flow 140 from the reformer 132, the product flow from the steam cracking system is supplied to the product separation system 134. The product flow from the steam cracking system may include low carbon number compounds, such as ethane and propane, as well as aromatic compounds, such as benzene, toluene, and xylene.

[0042] The AM removal system 106 produces an asphaltene stream 152 containing asphaltenes and heavy metals from the feed stream 102. In some embodiments, the asphaltene stream 152 is used internally in other units of the treatment facility 100, for example, blended with diesel or kerosene to 180 cSt (180 mm). 2 / s) or 380cSt (380mm 2 It produces heavy oil having a specific viscosity such as 1 / s. Furthermore, the asphaltene flow 152 can be supplied as fuel to the cement industry or as a product flow for asphalt production. Depending on the embodiment, the asphaltene flow 152 may be used to form other products in a heavy oil conversion system (HOCS) 154 or coker 156. The asphaltene flow 152 has a theoretical boiling point above about 600°C, but asphaltene is a solid or softened solid at commonly used processing temperatures.

[0043] In HOCS154, the asphaltene stream 152 can be reacted with the hydrogen stream 116 to form a decomposition product stream 158 containing lighter hydrocarbons than the asphaltene stream 152. The decomposition product stream 158 is supplied to the product separation system 134. The decomposition product stream 158 can have a boiling point of about 150°C to about 205°C. A portion of the decomposition product stream 158 can be supplied to the reformer 132, as shown in Figure 1. At least a portion of the heavy aromatic product stream 148 can be returned to HOCS154 for further processing. HOCS154 can produce a fuel oil product stream 160.

[0044] The fuel oil product stream 160 may contain heavy hydrocarbons that cannot be converted in the hydrogen generation system 122, the reformer 132, or recycled to the hydrotreatment system 114. The fuel oil product stream 160 may also be a purge stream if a portion of the pyoil (pyrolysis oil) stream is recycled to the HOCS 154. In the embodiments described herein, since the fuel oil product stream 160 is produced from the asphaltene stream 152, it can be a high-sulfur, low-viscosity, and high-density fuel oil. The aromaticity of the fuel oil product stream 160 is approximately 200 centistokes (cSt) (200 mm). 2 Less than / s, less than approximately 180 cSt, approximately 150 cSt (150 mm 2 It provides a viscosity of less than or equal to 1 / s. Therefore, the fuel oil product stream 160 can be used as bunker oil for transport. However, the economic value of this fuel oil can be adjusted by changing the flow used to form the fuel oil product stream 160 and by adjusting the operating conditions in different systems. In some embodiments, a higher proportion of the heavy aromatic product stream 148 from the product separation system 134 can be used in the HOCS 154 to reduce the sulfur content. In some embodiments, the fuel oil product stream 160 may be supplied to the coker 156 for further processing, for example, to increase the yield of lower molecular weight hydrocarbons.

[0045] In some embodiments, the asphaltene flow 152 is supplied to a coker 156. As used herein, a coker is a processing unit that converts heavy hydrocarbons, such as the asphaltene flow 152, into low molecular weight hydrocarbons, including hydrocarbon gases, naphtha, light and heavy gas oils, and petroleum coke. The coker 156 may include any type of commercially available coking unit, such as a delayed coker or a fluid coker. In the coker 156, the light hydrocarbon flow 162 is produced by the thermal decomposition of the asphaltene flow 152. The light hydrocarbon flow 162 may have a boiling point between about 150°C and about 205°C. In some embodiments, steam may be injected into the coker 156 to accelerate the reaction. The light hydrocarbon flow 162 is supplied to a product separation system 134. At least a portion of the heavy aromatic product flow 148 can be returned to the coker 156 for further processing. The petroleum coke product flow 164 is supplied from the coker 156 as a product flow. In the embodiments described herein, the petroleum coke product stream 164 is generally fuel-grade and contains high levels of sulfur and metals, for example. The petroleum coke product stream 164 may be further treated, for example, in a rotary kiln, to remove residual volatile hydrocarbons. The composition of the petroleum coke product stream 164 may be as shown in Table 1. Table 1. Examples of petroleum coke composition Density: 688kg / m 3 C: 85.9% wt dry H: 3.6% wt dry N: 0.94% wt dry O(calculated value): 0.2% wt dry S: 9.18% wt dry Ash: 0.2%wt dry Metal: 800mg / kg dry Moisture: 7.4%wt

[0046] The product separation system 134 comprises all systems for generating chemical products from the conversion process. In various embodiments, the product separation system 134 includes a demethane, quench column, hydrogenation reactor, primary fractionation column, compressor, and set of columns, enabling the generation of benzene product stream 142, toluene product stream 144, paraxylene product stream 146, heavy aromatic product stream 148, and other product streams including, in particular, ethylene, propylene, mixed C4s, and pyrolysis gasoline. The product separation system 134 further includes a high-distillation temperature (HDT) and aromatic separation section to process pyrolysis gasoline and separate BTX from this stream. The present invention also includes a selective hydrogenation system for saturating triolefins produced in a steam cracking furnace. The product separation system 134 is supplied with a reformed stream 140 from the reformer 132. This is also supplied with a decomposition product stream 158 from HOCS 154 and a light hydrocarbon stream 162 from coker 156. As described herein, the product separation system 134 generates a heavy aromatic product stream 148, which can be recycled to HOCS 154 or provided to other processes as a product stream.

[0047] Figures 2A and 2B are flowcharts of process 200, which uses a feed stream to directly supply power to a power generation system while generating petrochemical products. This process begins in block 202, where a feed stream, such as crude oil or condensate feed, is supplied to an asphaltene and metal (AM) removal system. In block 204, a high-purity oil stream is supplied from the AM removal system to the power generation system, as described herein.

[0048] In block 206, the medium-purity flow is supplied to the hydrogenation system. In block 208, the gas flow from the hydrogenation system is supplied to the hydrogen production system. In block 210, the hydrogen product flow is supplied from the hydrogen production system. A portion of the hydrogen product flow can be used as feedstock for the hydrogenation system, the heavy oil conversion system, or the carbon dioxide conversion system.

[0049] CO and carbon dioxide from the hydrogen production system in block 208 are processed in the carbon dioxide conversion system in block 212 to form synthetic fuels and other chemicals. In block 214, these are provided as a stream of synthetic products and can be used as fuel or in downstream processes.

[0050] In block 216, the liquid flow from the hydrogenation system is supplied to the cracking system. As described herein, the cracking system may be a reformer, a steam cracker, or another type of cracking system.

[0051] In block 218, the effluent from the cracking system is supplied to the product separation system. In block 220, the benzene product stream is supplied from the product separation system. In block 222, the toluene product stream is supplied from the product separation system. In block 224, the paraxylene product stream is supplied from the product separation system. In block 226, the heavy aromatic product stream is supplied from the product separation system. In block 228, the recycled stream containing light hydrocarbons is supplied from the product separation system to the hydrogen production system, the cracking system, or both. In block 230, the hydrogen-rich gas from the product separation system is supplied to the hydrogen production system. The hydrogen-rich gas may be further purified, for example, in a pressure swing absorption (PSA) system incorporated into the hydrogen production system.

[0052] In block 232, the asphaltene product flow is supplied from the AM removal system. In block 234, the asphaltene product flow is supplied to the heavy oil conversion system. In block 236, the heavy oil product flow is supplied from the heavy oil conversion system. In block 238, the light hydrocarbon spill flow is supplied from the heavy oil conversion system to the product separation system.

[0053] In block 240, the asphaltene product flow is supplied to the coker. In block 242, the petroleum coke product flow is supplied from the coker. In block 238, the light hydrocarbon spill flow is supplied from the coker to the product separation system.

[0054] Depending on the composition of the crude oil flow or the economics of the process, the heavy oil conversion system, coker, or both may be omitted. For example, if the crude oil or condensate flow does not contain high levels of high-carbon materials such as light crude oil, the heavy oil conversion system may not be necessary. Furthermore, if the economics of the process are not favorable to the fuel oil product flow, the heavy oil conversion system may be bypassed or eliminated. In some embodiments, the heavy oil conversion system may be present but configured to be bypassed.

[0055] Embodiments described herein provide a treatment facility. The treatment facility includes an asphaltene and metal (AM) removal system configured to process a feed stream to produce a power generation stream, a hydrogenation feed stream, and an asphaltene stream. The power generation system is supplied by the power generation feed stream. The hydrogenation system is configured to process the hydrogenation feed stream to form a gaseous stream and a liquid stream. A hydrogen generation system is configured to produce hydrogen, carbon monoxide, and carbon dioxide from the gaseous feed stream. A carbon dioxide conversion system is configured to produce synthetic hydrocarbons from carbon dioxide, and a cracking system is configured to process the liquid feed stream.

[0056] In one embodiment, the supply stream includes crude oil. In another embodiment, the supply stream includes condensate.

[0057] In one embodiment, the power generation system includes a gas turbine. In one embodiment, the gas turbine is of E-class, F-class, or H-class, or higher.

[0058] In one embodiment, the hydrogen production system includes a steam reforming reactor. In another embodiment, the hydrogen production system includes a gasification reactor. In another embodiment, the hydrogen production system includes a pressure swing adsorption system. In another embodiment, the hydrogen production system includes an aqueous shift system that converts carbon monoxide to carbon dioxide.

[0059] In one embodiment, the carbon dioxide conversion system includes a Fischer-Tropsch reactor. In one embodiment, the carbon dioxide conversion system includes a dry reforming process. In one embodiment, the treatment facility includes a hydrogen separation system configured to purify hydrogen and send carbon monoxide and carbon dioxide to the carbon dioxide conversion system.

[0060] In one embodiment, the hydrogenation treatment system includes a hydrogenation demetallation zone, a hydrogenation dearomatic zone, a hydrogenation denitrification zone, a hydrogenation desulfurization zone, or a hydrocracking zone, or any combination thereof.

[0061] In one embodiment, the cracking system includes a reformer. In one embodiment, at least a portion of the hydrogen produced in the hydrogen generation system is supplied to the reformer. In one embodiment, the reformer includes an isomerization reactor, a hydrocracking reactor, a dehydrogenation cyclization reactor, or a dehydrogenation reactor, or any combination thereof. In one embodiment, the cracking system includes a steam cracker.

[0062] In one embodiment, the processing facility includes a heavy oil conversion system. In another embodiment, the processing facility includes a coker.

[0063] In one embodiment, the processing facility includes a product separation system configured to separate product flows from a cracking system, a heavy oil conversion system, or a coker, or any combination thereof. In one embodiment, the product separation system is configured to supply a raw hydrogen flow to a hydrogen production system. In one embodiment, the product separation system is configured to supply a light hydrocarbon flow to a cracking system, or a hydrogen production system, or both. In one embodiment, the product separation system includes an aromatic separation system. In one embodiment, the product separation system is configured to produce a benzene product flow, a toluene product flow, a paraxylene product flow, or a heavy aromatic flow, or any combination thereof. In one embodiment, the product separation system is configured to supply at least a portion of the heavy aromatic flow to a heavy oil conversion system, or a coker, or both.

[0064] Another embodiment described herein provides a method for the production of power and petrochemical products in an integrated system. The method includes removing asphaltenes and metals (AMs) from a feedstream in an AM removal system to form a power generation stream, a hydrogenation feedstream, and an asphaltene stream. The power generation stream is supplied to the power generation system. The hydrogenation feedstream is processed in the hydrogenation system to form a gaseous stream and a liquid stream, the gaseous stream being supplied to a hydrogen generation system. The liquid stream is supplied to a cracking system.

[0065] In one embodiment, the method includes the steps of blending at least a portion of the hydrogenation treatment feed stream with a power generation stream to form a blended stream, and supplying the blended stream to a power generation system. In another embodiment, the method includes the steps of blending at least a portion of the liquid stream with a power generation stream to form a blended stream, and supplying the blended stream to a power generation system.

[0066] In one embodiment, the method includes supplying a hydrogen stream from a hydrogen generation system to a hydrogenation treatment system. In one embodiment, the method includes the steps of separating hydrogen from carbon monoxide and carbon dioxide, and supplying carbon monoxide and carbon dioxide to a carbon dioxide conversion system. In one embodiment, the hydrogen product stream is supplied from the hydrogen generation system. In one embodiment, carbon dioxide is supplied from the hydrogen generation system to the carbon dioxide conversion system. In one embodiment, the synthesis product stream is supplied from the carbon dioxide conversion system. In one embodiment, the effluent is supplied from a cracking system to a product separation system.

[0067] In one embodiment, the method includes supplying an asphaltene flow from an AM removal system. In one embodiment, the asphaltene flow is supplied to a heavy fuel oil conversion system (HOCS). In one embodiment, a light hydrocarbon spill flow from the HOCS is supplied to a product separation system. In one embodiment, a heavy fuel oil product flow is supplied from the HOCS.

[0068] In one embodiment, the method includes supplying an asphaltene flow to a coker. In one embodiment, a petroleum coke product flow is supplied from the coker. In one embodiment, a light hydrocarbon spill flow is supplied from the coker to a product separation system.

[0069] In one embodiment, the method includes supplying a light hydrocarbon stream from a product separation system to a hydrogen production system. In another embodiment, the method includes supplying a light hydrocarbon stream from a product separation system to a cracking system.

[0070] In one embodiment, the method includes the step of sending a raw hydrogen stream from a product separation system to a hydrogen generation system.

[0071] In one embodiment, a product separation system including an aromatic extraction system is included in the processing facility. 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 paraxylene product stream is provided from the product separation system.

[0072] In one embodiment, the heavy aromatic product stream is supplied from a product separation system. In one embodiment, the heavy aromatic product stream is supplied to a heavy oil conversion unit. In one embodiment, the heavy aromatic product stream is supplied to a coker.

[0073] Other implementations also fall within the scope of the following claims.

Claims

1. 1. A processing facility comprising: an asphaltene and metals (AM) removal system configured to process the feedstream to produce a power generation stream, a hydroprocessing feedstream, and an asphaltene stream; a power generation system provided with a power generation feed stream; a hydroprocessing system configured to process the hydroprocessing feed stream to form a gas stream and a liquid stream; a hydrogen production system configured to produce hydrogen, carbon monoxide, and carbon dioxide from the gas feed stream; a carbon dioxide conversion system configured to produce synthetic hydrocarbons from the carbon dioxide; a cracking system configured to process the liquid feed stream; Processing facility.

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

3. the feed stream comprises a condensate; The treatment facility of claim 1 .

4. the power generation system comprises a gas turbine. The treatment facility of claim 1 .

5. The gas turbine is an E-class, F-class, or H-class or higher class. The treatment facility of claim 4.

6. the hydrogen production system comprises a steam reforming reactor. The treatment facility of claim 1 .

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

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

9. the hydrogen generation system includes an aqueous shift system that converts carbon monoxide to carbon dioxide; The treatment facility of claim 1 .

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

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

12. a hydrogen separation system configured to purify the hydrogen and send carbon monoxide and carbon dioxide to the carbon dioxide conversion system; The treatment facility of claim 1 .

13. 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 .

14. the cracking system comprises a reformer; The treatment facility of claim 1 .

15. At least a portion of the hydrogen generated in the hydrogen generation system is supplied to the reformer.

15. The treatment facility of claim 14.

16. the reformer comprises an isomerization reactor, a hydrocracking reactor, a dehydrocyclization reactor, or a dehydrogenation reactor, or any combination thereof; 15. The treatment facility of claim 14.

17. The cracking system comprises a steam cracker. The treatment facility of claim 1 .

18. Equipped with a heavy oil conversion system, The treatment facility of claim 1 .

19. Equipped with a coker, The treatment facility of claim 1 .

20. a product separation system configured to separate a product stream from the cracking system, the heavy oil conversion system, or the coker, or any combination thereof; The treatment facility of claim 1 .

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

21. The treatment facility of claim 20.

22. the product separation system is configured to supply a light hydrocarbon stream to the cracking system, or to the hydrogen production system, or both; 21. The treatment facility of claim 20.

23. the product separation system comprises an aromatics separation system.

21. The treatment facility of claim 20.

24. the product separation system is configured to produce a benzene product stream, a toluene product stream, a para-xylene product stream, or a heavy aromatics stream, or any combination thereof.

24. The treatment facility of claim 23.

25. the product separation system is configured to supply at least a portion of the heavy aromatics stream to the heavy oil conversion system, or to the coker, or to both; 25. The treatment facility of claim 24.

26. 1. A method for producing power and petrochemicals in an integrated system comprising: removing asphaltenes and metals (AM) from the feed stream in an AM removal system to form a power generation stream, a hydroprocessing feed stream, and an asphaltene stream; supplying the power generation stream to a power generation system; processing the hydroprocessing feed stream in a hydroprocessing system to form a gas stream and a liquid stream; providing the gas stream to a hydrogen production system; providing the liquid stream to a cracking system; Methods for producing power and petrochemicals.

27. blending at least a portion of the hydroprocessing feed stream with the power generation stream to form a blended stream; supplying the blended stream to the power generation system.

27. The method of claim 26.

28. blending at least a portion of the liquid stream with the power generation stream to form a blended stream; supplying the blended stream to the power generation system.

27. The method of claim 26.

29. providing a hydrogen stream from the hydrogen production system to the hydroprocessing system; 27. The method of claim 26.

30. separating the hydrogen from the carbon monoxide and carbon dioxide; supplying the carbon monoxide and carbon dioxide to a carbon dioxide conversion system; 27. The method of claim 26.

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

27. The method of claim 26.

32. providing carbon dioxide from the hydrogen production system to a carbon dioxide conversion system; 27. The method of claim 26.

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

33. The method of claim 32.

34. feeding an effluent from the cracking system to a product separation system; 27. The method of claim 26.

35. providing an asphaltene stream from the AM removal system; 27. The method of claim 26.

36. feeding the asphaltene stream to a heavy oil conversion system (HOCS); 27. The method of claim 26.

37. providing a light hydrocarbon effluent stream from the HOCS to a product separation system.

37. The method of claim 36.

38. providing a heavy oil product stream from the HOCS.

37. The method of claim 36.

39. feeding the asphaltene stream to a coker; 27. The method of claim 26.

40. providing a petroleum coke product stream from said coker; 40. The method of claim 39.

41. providing a light hydrocarbon effluent stream from the coker to a product separation system.

40. The method of claim 39.

42. providing a light hydrocarbon stream from a product separation system to the hydrogen production system; 27. The method of claim 26.

43. feeding a light hydrocarbon stream from a product separation system to said cracking system; 27. The method of claim 26.

44. delivering a raw hydrogen stream from a product separation system to the hydrogen production system; 27. The method of claim 26.

45. a product separation system having an aromatics extraction system; 27. The method of claim 26.

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

46. ​​The method of claim 45.

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

46. ​​The method of claim 45.

48. providing a para-xylene product stream from the product separation system.

46. ​​The method of claim 45.

49. providing a heavy aromatic product stream from a product separation system; 46. ​​The method of claim 45.

50. providing the heavy aromatic product stream to a heavy oil conversion unit.

50. The method of claim 49.

51. a coker comprising the heavy aromatic product stream; 50. The method of claim 49.

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