Reactor and process for converting liquid hydrocarbons to higher value chemicals

Abstract

A process and reactor for converting hydrocarbons uses a reactor having an inlet configured as a convergent-divergent conduit having a central axis. A feed assembly of the reactor has a central chamber in fluid communication with the convergent-divergent conduit. The feed assembly has an annular flow channel for introducing a fuel gas feed and an oxidant gas feed into the central chamber in a swirl fluid flow pattern, the fuel gas feed and the oxidant gas feed combusting to form a swirl hot combustion gas. A liquid hydrocarbon feed having a dynamic viscosity of 0.1 cP to 1000 cP is introduced into the central chamber as a liquid spray having a Soxt Mean Diameter (SMD) of 1 [mu] m to 250 [mu] m. The hydrocarbon feed is mixed with the swirl hot combustion gas to form a swirl heated mixture that passes from the central chamber through the convergent-divergent conduit and into the reaction chamber to react to form a converted hydrocarbon product.

Description

Cross-reference to related applications

[0001] This application claims priority to the following patents: European patent application No. 23187528.7, filed on July 25, 2023, European patent application No. 23187529.5, filed on July 25, 2023, European patent application No. 23187530.3, filed on July 25, 2023, European patent application No. 23196604.5, filed on September 11, 2023, Indian Patent Application No. 202341050195, filed on July 25, 2023, the contents of which are incorporated herein by reference. Technical Field

[0002] This disclosure relates to the production of high-value chemical products from liquid hydrocarbons such as crude oil. Background Technology

[0003] Conventional crude oil to chemical industrial complexes use crude oil distillation to produce various fractions, such as light hydrocarbons (e.g., C1-C4), naphtha, kerosene, diesel, gas oil, and residue. Each of these streams can be processed individually, such as by hydrotreating or hydrocracking, fluidized bed catalytic cracking, steam cracking, aromatic compound complexation, and / or naphtha reforming, to produce light olefins and aromatic compounds. These process methods typically result in (i) low carbon and energy efficiency, (ii) high operating and total capital costs, and (iii) operational complexity. In variations of these processes, crude oil can be flashed to remove light hydrocarbon fractions as liquids, which can then be vaporized and fed into a steam cracker. The heavier or bottom product from the crude oil flashing vessel is sent to a conventional refinery for further processing.

[0004] Figure 1A schematic diagram of an example conventional crude oil to chemicals system and its process flow is shown. As illustrated, the system includes a crude oil distillation unit where crude oil is fractionated into atmospheric residue and naphtha, as well as kerosene and diesel fractions. The naphtha fraction is optionally hydrotreated and fractionated into light naphtha and heavy naphtha. The heavy naphtha is reformed in a naphtha reformer, while the light naphtha fraction is fed to a steam cracker. The naphtha reformate is the feedstock for an aromatics complex that produces paraxylene and benzene. C5+ and pyrolysis gasoline (i.e., cracked gasoline) from the steam cracker are also fed into the aromatics complex to produce paraxylene and benzene. The atmospheric residue is vacuum distilled to produce light vacuum gas oil and heavy vacuum gas oil. The produced vacuum gas oil is hydrocracked, while the residue from the vacuum distillation undergoes hydrocracking and is produced into a diesel-range fraction, which is then hydrocracked again to produce light and heavy naphtha. Light and heavy naphtha are processed as described above. Gas oil may optionally be fed into a fluidized catalytic cracking (FCC) unit. Light olefins are separated from aromatic middle distillates. Light cycle oils that are typically difficult to process in the hydroprocessing unit are sent to the catalytic cracker.

[0005] It can be seen that conventional crude oil-to-chemicals systems and processes cannot process crude oil without significant preprocessing in multiple unit operations, nor can such systems convert a significant percentage of crude oil into higher-value chemicals. This disclosure addresses the aforementioned problems. Summary of the Invention

[0006] A method for converting hydrocarbons is carried out in a reactor system comprising a central axis, a feed assembly, and a reactor vessel defining a reaction chamber. Fuel gas feed and oxidant gas feed are introduced into the feed assembly to create a swirling fluid flow pattern around the central axis. The fuel gas feed and oxidant gas feed are combusted in the feed assembly to form a swirling combustion gas. A hydrocarbon reactant feed containing liquid hydrocarbons to be converted is introduced into the feed assembly. The liquid hydrocarbons have a dynamic viscosity of 0.1 cP to 1000 cP and are introduced into the feed assembly as a liquid spray with a droplet SMD of 1 μm to 250 μm in a flow pattern not perpendicular to the central axis. The hydrocarbon reactant feed is mixed with the swirling combustion gas to form a swirling heated mixture. The heated mixture from the feed assembly is transferred to the reaction chamber. The heated mixture reacts in the reaction chamber under reaction conditions suitable for converting the hydrocarbons of the hydrocarbon reactant feed into the converted hydrocarbon product. The converted hydrocarbon product is removed from the reaction chamber.

[0007] In certain embodiments, liquid hydrocarbons may include crude oil, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, and C2C2. 20 To C 40The hydrocarbons include at least one of the following: hydrocarbons, biomass-derived oils, pyrolysis oils from plastics, liquefied plastics, liquefied plastic waste containing impurities, and hydrocarbon liquids containing heteroatoms. Liquid hydrocarbons may comprise from 0.5% to 100% by weight of the hydrocarbon reactant feed. Liquid hydrocarbons may include crude oil that has not been pretreated or refined, except where at least one of asphaltenes, resins, sulfur compounds, and trace metals has been optionally removed.

[0008] In some applications, the hydrocarbon reactant feed may also contain gaseous hydrocarbons. These gaseous hydrocarbons can be liquefied natural gas and C1 to C2 hydrocarbons. 20 At least one of the hydrocarbons. In some cases, the hydrocarbon reactant feed of at least one of the gaseous hydrocarbons and liquid hydrocarbons may be mixed with steam.

[0009] In some embodiments, the converted hydrocarbon products may include at least one of olefins, C2 to C6 olefins, ethylene, propylene, butene, acetylene, C3 to C6 alkynes, butadiene, aromatic compounds, xylene, benzene, toluene, and ethylbenzene. In some cases, a portion of any or more of the C2 to C6 alkanes, xylene, benzene, and toluene in the reactor product stream may be separated from and recovered from the reactor product stream containing the converted hydrocarbon products to form at least a portion of the hydrocarbon reactant feed. Hydrogen (H2) in the reactor product stream may also be separated from and recovered from the reactor product stream to form at least a portion of the fuel gas feed.

[0010] A reactor system for converting hydrocarbons is also provided, comprising a reactor vessel defining a reaction chamber. The inlet of the reaction chamber is configured as a smoothly tortuous convergent-divergent conduit having a central axis extending along an upstream and downstream end of the conduit, where upstream and downstream refer to their relative positions with respect to the direction of overall fluid flow through the reactor system. A feed assembly in fluid communication with the conduit has a central chamber through which the central axis passes. The feed assembly has a flow channel configured to introduce fuel gas feed and oxidant gas feed in a swirling fluid flow pattern around the central axis into the central chamber of the feed assembly, where the fuel gas feed and oxidant gas feed are combusted to form swirling thermal combustion gases. The reactor system also includes at least one spray nozzle at the upstream end of the feed assembly, the spray nozzle being configured to introduce a hydrocarbon reactant feed containing the liquid hydrocarbon to be converted into the central chamber of the feed assembly. At least one spray nozzle is oriented and configured to introduce liquid hydrocarbons as a liquid spray into the central chamber in a flow pattern not perpendicular to the central axis. The introduced liquid hydrocarbons mix with swirling hot combustion gases within the central chamber to form a swirling heated mixture, which exits the central chamber through a convergent-divergent conduit and enters the reaction chamber, where the liquid hydrocarbons are converted into converted hydrocarbon products. The reaction chamber has an outlet for removing the converted hydrocarbon products from the reaction chamber.

[0011] The reactor system can be an annular jet vortex reactor chamber (ANJEVOC) reactor system. In some embodiments, the spray nozzle can be a two-fluid spray nozzle. The spray nozzle can provide a spray pattern with a spray angle of 40° or less. In some applications, the diverging portion of the convergent-divergent conduit can have a total divergence angle of 25° to 55° relative to the central axis. Attached Figure Description

[0012] To gain a more complete understanding of the implementation schemes and their advantages described herein, please now refer to the following description in conjunction with the accompanying drawings, wherein: Figure 1 This is a schematic diagram of an existing crude oil to chemical processing system and the process flow of such a system; Figure 2 This is a front cross-sectional view of a reactor system for converting liquid hydrocarbons according to various embodiments of this disclosure; Figure 3 It is based on the various implementation schemes of this disclosure. Figure 2 An exploded perspective view of the feed assembly of the reactor system; Figure 4 yes Figure 2 A cross-sectional perspective view of the feed assembly and upstream end of the reaction chamber of the reactor system; Figure 5 In such as Figure 2 In the reactor system, the vaporization time as a function of droplet size is plotted using simplified calculations under approximate conditions. Figure 6 It is shown in such as Figure 2 A graph of computational fluid dynamics (CFD) calculations for spray evaporation in a reactor, where all liquid vaporizes within 5 mm of the injection point; Figure 7 FLOWMAX uses liquid water and air. ® The graph of the test results for the FM3A dual-fluid nozzle shows various droplet sizes under various flow conditions; Figure 8 The adoption of various embodiments of this disclosure Figure 2 A schematic diagram of a reactor system for converting liquid crude oil into hydrocarbon processing systems and a process flow diagram; Figure 9 The adoption of various embodiments of this disclosure Figure 2 A schematic diagram of the reactor system for converting liquid crude oil into another hydrocarbon processing system and process flow; Figure 10 It is based on the adoption of certain embodiments of this disclosure Figure 2A schematic diagram of the reactor system and the hydrocarbon processing system and process flow that utilizes the front-end propane dehydrogenator to convert liquid crude oil; Figure 11 The adoption of various embodiments of this disclosure Figure 2 A schematic diagram of a reactor system for converting liquid crude oil that has not yet been processed to remove asphaltenes and / or resins from liquid crude oil, and a hydrocarbon processing system and process flow. Figure 12 This is a chart of the selectivity of light olefins and aromatic compounds by weight percentage during the conversion of 20% liquid crude oil feed and a wide range of naphtha in the ANJEVOC reactor. Figure 13 This is a graph showing the percentage conversion and bulk gas temperature when converting 20% ​​by weight of liquid crude oil feed and a wide range of naphtha in an ANJEVOC reactor. Figure 14 This is a chart showing the selectivity of approximately 40% by weight of Khuff gas condensate (KGC) crude oil with butane, light olefins, and aromatic compounds in the ANJEVOC reactor; and Figure 15 This is a selective chart, by weight percentage, of approximately 40 wt% Arabian Ultra Light (AXL) crude oil with butane, light olefins, and aromatic compounds in the ANJEVOC reactor. Detailed Implementation

[0013] In various embodiments of this disclosure, unique reactor technologies are used to convert liquid hydrocarbons, such as liquid crude oil, with or without gaseous hydrocarbons, into high-value chemicals, such as light olefins and aromatic compounds. Liquid hydrocarbons may include a full range of crude oils, various fractions of crude oil, and / or heavy hydrocarbon liquids from other sources. Compared to conventional crude oil-to-chemicals processing systems, this conversion can be accomplished in a single processing step, or with fewer or minimal processing steps and equipment. More specifically, the conversion can be achieved using ANJEVOC (Annular Jet Vortex Chamber) cracking reactor technology, which produces an annular swirling jet of feed gas, where hydrogen (or other fuels, such as natural gas, recycled syngas, etc.) and oxygen are used to generate the heat required for hydrocarbon cracking. Examples of such ANJEVOC reactors are described in U.S. Patents 11,020,719 and 11,123,705; and International Publications WO2022 / 010821A1, WO2022 / 010822A1 and WO2022 / 010823A1, each of which is incorporated herein by reference in its entirety for all purposes, including illustrating the configuration, construction and operation of such ANJEVOC reactors and their various components.

[0014] The following includes definitions of various terms and phrases used throughout the specification.

[0015] For the purposes of this disclosure, if a numerical value, concentration, or range is given, each numerical value should be interpreted as being modified once by the term "about" (unless explicitly so), and then again as not so, unless otherwise indicated in the context. Furthermore, it should be understood in the specification that listing or describing a range of quantities as useful, suitable, etc., is intended to imply that any and every value within that range, including endpoints, has been stated. For example, "a range from 1 to 10" should be interpreted as indicating every possible number along the continuum between about 1 and about 10. Therefore, even if a specific point within the range is explicitly identified or mentioned, or even if no point within the range is explicitly identified or mentioned, it should be understood that the inventor comprehends and understands that any and all points within the range are considered to have been specified, and that the inventor owns the entire range and all points within it.

[0016] The term “about” or “approximately” is defined as close to as understood by one of ordinary skill in the art. In one non-limiting embodiment, the term is defined as within 10%, preferably within 5%, more preferably within 1%, and most preferably within 0.5%.

[0017] For the purposes of this disclosure, “X, Y and / or Z” can be interpreted as only X, only Y, only Z, or any combination of two or more items X, Y and Z (e.g., XYZ, XY, XZ, YZ). Similarly, “at least one of X, Y and Z” can be interpreted as only X, only Y, only Z, or any combination of two or more items X, Y and Z (e.g., XYZ, XY, XZ, YZ).

[0018] When used in conjunction with the terms “comprising,” “including,” “containing,” or “having” in the claims or description, the word “a” or “an” may mean “a”, but it is also consistent with the meanings of “one or more,” “at least one,” and “one or more.”

[0019] The words “comprising” (and any form of inclusion, such as “comprise” and “comprises”), “having” (and any form of having, such as “have” and “has”), “including” (and any form of including, such as “includes” and “include)”), or “containing” (and any form of containing, such as “contains” and “contain)”) are inclusive or open-ended and do not exclude additional, unlisted elements or method steps.

[0020] The terms "weight%" or "molar%" refer to the weight percentage or molar percentage of a component based on the total weight or total number of moles of the material including the component, respectively. In a non-limiting example, 10 moles of component in 100 moles of material is 10 molar% of the component.

[0021] refer to Figure 2 The image shows a front cross-sectional view of a reactor system 10 for converting liquid hydrocarbons. The reactor system 10 is configured to convert liquid hydrocarbons such as crude oil, crude oil fractions, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, and C6O2. 20 To C 40 Hydrocarbons, etc. Reactor system 10 can also be used to convert gaseous hydrocarbons together with liquid hydrocarbons. Reactor system 10 can constitute an ANJEVOC reactor and includes a reactor vessel 12 having a reactor wall 14 defining an internal reaction chamber 16. The reactor wall 14 may have a cylindrical configuration with a constant diameter for all or part of its length, which may constitute the majority of its length (i.e., >50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%). In most cases, reactor vessel 12 is vertically oriented such that the cylindrical reactor wall 14 is oriented in an upright orientation with downward flow. However, the reactor may have other orientations (e.g., horizontal, inclined, or upright with upward flow) because the process is controlled by centrifugal force, which exceeds gravity by several orders of magnitude. Reactor vessel 12 can be configured to provide a length-to-diameter ratio (L / D) of at least 2. In specific applications, the L / D ratio may range from 2 to 10, more particularly from 2 to 5.

[0022] Reactor vessel 12 may be formed of steel. In some embodiments, a cooling jacket may be provided around all or part of reactor vessel 12, wherein a second steel wall 18 is positioned around and spaced apart from the inner reactor wall 14, and a cooling fluid, such as water, can circulate through the jacket formed between walls 14, 18. In other embodiments, reactor wall 14 may be formed of one or more layers of refractory material, which are lined inside the outer steel wall to reduce heat loss and maintain the high temperature of reactor 10. Due to the unique design and operation of reactor 10, reactor wall 14 is internally cooled by a high-speed near-wall airflow propelled against reactor wall 14 by centrifugal force, so that in some applications an external cooling jacket is not required. This also allows for the use of refractory material inside reactor wall 14. Due to the high temperatures (e.g., 2000°C to 2800°C), refractory material (without cooling) is generally not suitable for use with conventional cracking reactors with pure oxygen. The reaction temperatures for converting liquid hydrocarbons, such as crude oil, in reactor system 10 are typically in the range of 800°C to 2500°C.

[0023] Outlet 20 is located at the lower or downstream end of reactor vessel 12 for removing or discharging pyrolysis products from reaction chamber 16. The outlet diameter may be the same as the diameter of reactor wall 14, or the outlet diameter may be reduced to accelerate flow before quenching and downstream collection.

[0024] Reactor 10 includes a reactor inlet assembly 22, which is coupled or joined to the upper or upstream end of the reactor wall 14 of reactor vessel 12. Here, reactor vessel 12 is vertically oriented, with inlet assembly 22 located above reactor vessel 12. This allows any downstream liquid quenching fluid (e.g., water) used to quench the reaction gas within reaction chamber 16 to be carried by gravity to outlet 20, rather than upstream toward inlet assembly 22.

[0025] Inlet assembly 22 defines a convergent-divergent conduit 24, which is defined by a circumferential wall 26 surrounding the central axis 28 of reactor 10. The central axis 28 of reactor 10 may be the same as or coincident with the central axis of either inlet assembly 22 or conduit 24 and reactor vessel 12. The circumferential wall 26 extends from opposite upstream and downstream ends of the convergent-divergent conduit 24. As used herein, the terms “upstream” and “downstream” or similar expressions used to describe the various components of reactor system 10 shall refer to the position of the component relative to the overall direction of fluid flow through reactor 10 along the central axis 28.

[0026] As from Figure 2As can be seen, the width or diameter of the circumferential wall 26 smoothly tapers or converges from the upstream end to define an annular constriction neck portion located between the downstream and upstream ends of the converging-diverging conduit 24. At the annular constriction neck portion, the circumferential wall 26 of the conduit 24 transitions from converging or narrowing to diverging or widening. Then, downstream of the annular constriction neck portion, the circumferential wall 26 smoothly expands or diverges in width or diameter. The interior of the circumferential wall 26 may have a circular vertical transverse cross-section relative to the axis 28, in whole or in part, along its length. The circumferential wall 26 defines the internal flow path of the inlet assembly 22, wherein the constriction neck portion is part of the smoothly curved and streamlined converging-diverging nozzle of the inlet assembly 22.

[0027] The nozzle geometry of the convergent-divergent conduit 24 is constructed based on theories related to swirling conical jets of viscous, incompressible fluids. This phenomenon is described in the journal article “Novel Annular Jet Vortex Reactor for High-Temperature Thermochemical Conversion of Hydrocarbons to Acetylene” published in ACS Engineering in 2022 (Pannala, S. et al., ACS Engineering, 2022, Vol. 2, No. 5, pp. 406-420). The downstream or divergent portion of the conduit 24 is configured for non-supersonic fluid flow. Conduits or nozzles configured for supersonic flow, such as Laval nozzles, are configured differently from conduit 24 to provide supersonic flow downstream to form a shock wave. In various embodiments, the divergent conduit 24 does not form such supersonic flow or shock waves. Conversely, duct 24 has a geometry that facilitates the recirculation and reflux of gas within the internal reaction chamber 16 near the central axis 28, combined with an annular swirling jet stream adjacent to the internal reactor wall 14. Therefore, duct 24 will have a larger divergence angle than is typically used in Laval nozzles, which have a divergence angle of 15° or less. In some embodiments, the total divergence angle "A" relative to axis 28 is... Figure 2The divergence angle A can be 25° or greater. In certain cases, the divergence angle A of the diverging portion of the conduit 24 discussed herein is 25° to 55°. In some embodiments, the divergence angle A is at least, equal to, and / or between any two of the following: 25°, 26°, 27°, 28°, 29°, 30°, 31°, 32°, 33°, 34°, 35°, 36°, 37°, 38°, 39°, 40°, 41°, 42°, 43°, 44°, 45°, 46°, 47°, 48°, 49°, 50°, 51°, 52°, 53°, 54°, and 55°. Because the upstream swirling flow is connected to the converging-diverging conduit 24, a large divergence angle results in the recirculation of fluid flow at the reactor wall 14.

[0028] The downstream end of the diverging portion of the conduit 24 joins the reactor wall 14 around its periphery at the inlet of the reaction chamber 16, thereby enabling fluid communication between the conduit 24 and the reaction chamber 16 of the reactor vessel 12. The upstream end of the converging portion of the conduit 24 forms the inlet of the reactor vessel 12.

[0029] The reactor system 10 is equipped with a feed assembly 32. A perspective view of the feed assembly 32 is shown in... Figure 3 As shown in the diagram, the feed assembly 32 engages and is in fluid communication with the upstream end of the conduit 24, with the central axis 28 passing through the feed assembly 32. The feed assembly 32 includes a downstream feed assembly wall 34 that extends circumferentially around and engages the upstream end of the converging portion of the conduit 24. The feed assembly wall 34, or its circumferential portion thereof, is oriented perpendicular to or substantially perpendicular to the central axis 28 (i.e., when it extends radially from the central axis, the angle between its circumferential direction and the vertical direction is ≤5 degrees).

[0030] Along the central axis 28, axially spaced between the upstream and downstream walls 34, is the upstream feed assembly wall 36. The upstream wall 36, or its circumferential portion thereof, is oriented perpendicular to or substantially perpendicular to the central axis 28 (i.e., when it extends radially from the central axis, the angle between its circumferential direction and the vertical direction is ≤5 degrees).

[0031] The upstream gas partition wall 38 and the downstream gas partition wall 40 are axially spaced apart from and from each other between the downstream feed assembly wall 34 and the upstream feed assembly wall 36, with the upstream partition wall 38 positioned upstream of the downstream partition wall 40. The partition walls 38, 40, or their circumferential portions, are also each oriented perpendicular to or substantially perpendicular to the central axis 28 (i.e., when extending radially from the central axis, their circumferential direction forms an angle ≤5 degrees with the vertical direction). Each of the partition walls 38, 40 has a central opening 42, 44, which surrounds the central axis 28 and is concentric with the convergent-divergent conduit 24. The inner ends of the partition walls 38, 40 defining the openings 42, 44 terminate upstream of the convergent-divergent conduit 24. The central openings 42, 44 each have a circular configuration. Other continuously curved shapes (e.g., elliptical) for the central openings 42, 44 may also be used, provided that such configuration facilitates gas swirling to provide the desired swirling flow pattern described herein. This shape can also correspond to the cross-sectional shape of the circumferential wall 26 of the converging-diverging conduit 24. However, in most applications, the central openings 42, 44 will be circular. The central openings 42, 44 may have the same or slightly different (smaller or larger) diameter or width as the constriction neck of the converging-diverging conduit 24 at its narrowest point.

[0032] refer to Figure 2 The upstream partition wall 38 defines an annular flow channel 46 located between the upstream feed assembly wall 36 and the upstream side of the upstream partition wall 36. In the illustrated embodiment, the flow channel 46 constitutes an upstream annular hydrocarbon reactant feed inlet flow channel for introducing gaseous hydrocarbons to be converted into high-value chemicals such as light olefins and aromatic compounds. Similarly, the annular flow channel 48 is defined by the downstream side of the downstream partition wall 40 and the downstream feed assembly wall 34. In the illustrated embodiment, the flow channel 48 may constitute an annular steam or water inlet flow channel.

[0033] An intermediate partition wall 50 is axially spaced between the downstream gas partition wall 40 and the upstream gas partition wall 38 to define a downstream intermediate annular gas inlet flow channel 52 and an upstream intermediate annular gas inlet flow channel 54. The intermediate partition wall 50 also has a central opening 56 that surrounds a central axis 28 and is concentric with the convergent-divergent conduit 24. The inner end of the partition wall 50 defining the opening 56 terminates upstream of the convergent-divergent conduit 24. The central opening 56 may have a circular configuration. Other shapes for the central opening 56 (e.g., elliptical) may also be used, provided that such a configuration facilitates gas swirling to provide the desired swirling flow pattern described herein.

[0034] The intermediate partition wall 50, or its circumferential portion, is also oriented perpendicular to or substantially perpendicular to the central axis 28 (i.e., when extending radially from the central axis, its circumferential direction forms an angle ≤5 degrees with the vertical direction). In the illustrated embodiment, the annular flow channel 52 can constitute an oxygen or oxidizing gas flow channel to promote combustion. The annular flow channel 54 can constitute a fuel gas (e.g., H2, CH4, syngas, or combinations thereof) flow channel for introducing fuel gas for combustion.

[0035] A central chamber 58 of the feed assembly 32 is formed around a central axis 28 in the region between the downstream feed assembly wall 34 and the upstream feed assembly wall 36 and radially spaced inward from the central openings 42, 44, 56 of the partition walls 38, 44, 50, respectively. The central axis 28 is also formed by merging the central chamber 58 and the central axis of the feed assembly 32.

[0036] This configuration provides a flow channel through which the gas feed to be cracked, steam, oxygen, and hydrogen-rich fuel for providing combustion heat can be introduced individually and delivered to the central chamber 58 of the feed assembly 32 via flow channels 46, 48, 52, and 54 in a swirling fluid flow pattern around the central axis 28, causing the feed to combust in the central chamber to form swirling combustion gas. The feed is introduced into the central chamber in a direction not parallel to the central axis 28. For this purpose, one or more of the feed assembly wall 34, upstream wall 36, partition walls 38 and 40, and intermediate partition wall 50 (or their circumferential portions) are configured to introduce the feed into the central chamber 58 of the feed assembly 32 in a swirling fluid flow pattern around the central axis 28, causing the feed to combust in the central chamber to form swirling combustion gas. The feed assembly wall 34, upstream wall 36, partition walls 38 and 40, and intermediate partition wall 50 (or their circumferential portions) can be oriented in a direction not parallel to the central axis 28. In some embodiments, one or more of the feed assembly wall 34, upstream wall 36, partition walls 38 and 40, and intermediate partition wall 50 (or its circumferential portion) may be oriented at an angle of less than or equal to 5 degrees, less than or equal to 10 degrees, less than or equal to 20 degrees, less than or equal to 30 degrees, or less than or equal to 40 degrees to the direction perpendicular to the central axis 28.

[0037] The upstream flow channel 46 can be used as a gaseous hydrocarbon feed inlet flow channel. A fuel gas feed consisting of a hydrogen-rich gas feed (i.e., H2) can be introduced into one of a first adjacent annular fuel gas inlet flow channel 52 and a second adjacent annular fuel gas inlet flow channel 54, wherein an oxidant (i.e., O2) or oxygen-containing gas feed is introduced into the other of the flow channels 52 and 54. Typically, fuel and oxygen feeds are introduced into flow channels adjacent to each other to promote rapid combustion. In some applications, the downstream flow channel 52 can be used to deliver an oxidant or oxygen-containing gas, and the upstream flow channel 54 will be used to deliver hydrogen-rich fuel gas. Steam feed can be introduced into the downstream annular steam inlet flow channel 48. In other cases, various feeds can be sequentially changed within the flow channels 46, 48, 52, and 54. For example, any of the flow channels 48, 52, and 54 can be used as a gaseous hydrocarbon feed inlet flow channel. In some applications, steam feed can be introduced in combination with or together with one or more of the other feeds. This can include combining steam feed with fuel gas feed, oxygen-containing gas feed, or hydrocarbon gas feed.

[0038] In some implementations, one or more of the flow channels 46, 48, 52, and 54 may remain idle or be omitted from the feed assembly 32. If the flow channels are omitted, one of the partition walls 38, 40, and 50 is not required, and the number of flow channels is reduced. In this case, some feeds may be combined and introduced together, such as the steam feed discussed earlier.

[0039] In the illustrated reactor system 10, flow channels 46, 48, 52, and 54 are configured such that different feeds pass through the flow channels in an inward swirling fluid flow pattern perpendicular to or substantially perpendicular to the central axis 28, causing the feeds to flow around the central axis 28 within the central chamber 58. The swirling fuel gas and oxidant feeds are combusted within the central chamber 58.

[0040] In the illustrated reactor system 10, in many cases, the walls 34, 36, 38, 40, and 50 forming the different flow channels 46, 48, 52, and 54 are parallel to each other. However, in other cases, the walls 34, 36, 38, 40, and 50 may not be parallel to each other. The walls 34, 36, 38, 40, and 50 are axially spaced to provide the desired volume and flow characteristics for the gases flowing through them. This can be based on the desired flow rate or linear velocity of each of the feed gases and their relative amounts. For example, the relative volume of oxygen required for combustion is typically smaller than the volume of hydrogen-rich fuel gas required for combustion. Therefore, the partition wall 50 can be spaced further downstream of the partition wall 40, making the flow channel 54 for hydrogen fuel larger and accommodating more fuel gas flow. The specific spacing can depend on the combination of fuel gas and oxidant, the desired combustion volume, and the nature of the hydrocarbon feed.

[0041] Annular gas manifolds 60, 62, 64, and 66 are arranged around the outer periphery of flow channels 46, 48, 52, and 54, respectively. In this example, gas manifold 60 may be fluidly connected to a gaseous hydrocarbon feed source. Manifold 62 may be fluidly connected to a steam source. Manifold 64 may be fluidly connected to an oxygen-containing gas source, such as pure O2 feed. And manifold 66 may be fluidly connected to a hydrogen-rich or fuel feed source, such as H2. Manifolds 60, 62, 64, and 66 are provided with feed assemblies 32 to facilitate the introduction of feed gas into flow channels 46, 48, 52, and 54. In other embodiments, the feed source to each manifold may be changed.

[0042] Generally, the gas inlets from manifolds 60, 62, 64, and 66 are oriented to generate an inward swirling flow of gas within the central chamber 58. In other words, the gas inlets guide the incoming gas flow along a path extending inward from the wall of the central chamber 58, but not directly towards the central axis 28 along the radius of the central chamber 58. This generates an inward swirling flow of gas from the inlets, rather than a series of flows traversing the central chamber 58 via the shortest radial path and intersecting at the central axis 28. Incidentally, one or more inlets may be provided for each flow channel 46, 48, 52, and 54. Furthermore, the walls 34, 36, 38, 40, and 50 forming the different flow channels of the feed assembly 32 prevent axial flow of gas along the direction of the central axis 28 as they are contained within the flow channels 46, 48, 52, and 54. Manifolds 60, 62, 64, and 66 may be constructed as standard manifolds (e.g., snail-shaped), as is commonly used in vortex devices.

[0043] refer to Figure 3In some embodiments, one or more or all of the flow channels 46, 48, 52, 54 may be provided with a plurality of circumferentially spaced guide vanes 68, 70, 72, 74 (e.g., 10 to 60 guide vanes per flow channel). Each guide vane 68, 70, 72, 74 may be a planar member oriented in a plane parallel to the central axis 28 and extending between the walls 34, 36, 38, 40, and 50. The guide vanes 68, 70, 72, 74 may be circumferentially spaced from each other by an equal distance. In some embodiments, the guide vanes 68, 70, 72, 74 may be fixed in place, wherein the upper and lower edges of these guide vanes engage along their length or a portion thereof with the walls 34, 36, 38, 40, and 50, such that there is no air gap between the side edges of the vanes 68, 70, 72, 74 and the walls 34, 36, 38, 40, and 50. However, in other embodiments, the guide vanes are movable. In such cases, the upper and lower edges of blades 68, 70, 72, and 74 may be closely spaced from walls 34, 36, 38, 40, and 50 to provide a small clearance that allows movement. The close spacing minimizes the air gap through which gas can pass. Seals can also be used to effectively close these spaces or gaps while allowing movement. In other cases, blades 68, 70, 72, and 74 may be oriented such that the plane of the blade is in a non-parallel or inclined orientation relative to the central axis 28. In such cases, the side edges may be fixed to walls 34, 36, 38, 40, and 50, or kept closely spaced from walls 34, 36, 38, 40, and 50 to minimize the air gap. In some applications, guide blades 68, 70, 72, and 74 may be configured as airfoils, as described in U.S. Patent No. 11,123,705.

[0044] In the illustrated reactor system 10, guide vanes 68, 70, 72, 74 are arranged adjacent to the outer periphery of flow channels 46, 48, 52, 54 and spaced apart in annular or circular pattern near the manifold inlet. In other reactor systems, they may be arranged in annular pattern at other locations radially inward or further within flow channels 46, 48, 52, 54. Alternatively, one or more additional annular guide vane assemblies may be positioned radially inward from those guide vanes positioned along the outer periphery to facilitate inward swirling fluid flow.

[0045] Feed gas from manifolds 60, 62, 64, and 66 is delivered almost tangentially to the outer periphery of the central chamber 58, where guide vanes 68, 70, 72, and 74 can guide the airflow within the central chamber 58 in an inward swirling or spiral fluid flow pattern. In some embodiments, the inlets from manifolds 60, 62, 64, and 66 can be oriented or guided to impart a fully inward swirling fluid flow without the use or need of guide vanes. In other embodiments, such as when gas from the manifold inlets can be guided radially toward the central axis 28 or does not impart the fully desired swirling flow, guide vanes 68, 70, 72, and 74 can impart a fully swirling flow to the introduced gas. In such cases, guide vanes 68, 70, 72, and 74 prevent direct gas flow toward the central axis 28 and guide the flowing gas almost tangentially relative to the inner wall of the central chamber 58 to provide an inward swirling or spiral fluid flow pattern.

[0046] The guide vanes 68, 70, 72, and 74 of each flow channel 46, 48, 52, and 54 can be mounted on an actuator (not shown) so that they can be selectively moved to various positions to provide a selected inward spiral flow pattern. The guide vanes 68, 70, 72, and 74 can pivot about an axis parallel to the central axis 28, allowing the vanes 68, 70, 72, and 74 to be moved to various positions.

[0047] The orientation of the blades 68, 70, 72, 74 in each flow channel and / or the orientation of the inlets of the manifolds 60, 62, 64, 66 will provide a swirling or helical fluid jet flow in the same direction of rotation about axis 28 (i.e., clockwise or counterclockwise). Therefore, the gas within each flow channel in the flow channels will flow clockwise or counterclockwise about axis 28. Generally, the blades 68, 70, 72, 74 will all introduce gas inward at the same angle relative to the wall of the central chamber 58 to provide the desired swirling fluid flow characteristics. If the blades 68, 70, 72, 74 are movable, they will typically be actuated to move uniformly or nearly uniformly.

[0048] In the example, oxygen and hydrogen fuel gas from flow channels 52 and 54, gaseous hydrocarbon feed from flow channel 46, and vapor from flow channel 48 can be discharged into the central chamber 58 of the feed assembly 32. Since the oxygen-containing gas and hydrogen-rich fuel gas are introduced separately rather than as a mixture, this eliminates the safety concerns that would arise if these gases were premixed before being introduced into the feed assembly 32. Furthermore, the combustion reaction occurs rapidly, with most of the combustion taking place within a small space within the central chamber 58, where the two streams of oxygen-containing gas and hydrogen-rich fuel gas from flow channels 52 and 54 mix after being discharged from flow channels 52 and 54. The combustible mixture can be ignited, for example, using a spark, chemicals, or an ignition flame extending across the bottom or side surfaces of the reactor. The suction from the swirling flow can transfer heat from the ignition device to the combustion zone of the central chamber 58 to initiate ignition.

[0049] Gaseous hydrocarbon feed from upstream flow channel 46 and steam from flow channel 48 are discharged into central chamber 58, causing the gaseous hydrocarbon feed, steam, and heated combustion gases to mix together and form a swirling gas mixture within central chamber 58. This swirling gas mixture then passes through convergent-divergent duct 24 and enters reaction chamber 16 of reactor vessel 12.

[0050] A liquid feed inlet 76 is also formed in the upstream feed assembly wall 36 for introducing all or part of the liquid hydrocarbons to be converted by the reactor system 10, such as high-value chemicals like light olefins and aromatic compounds, into the feed assembly 32. In some embodiments, more than one or more liquid feed inlets 76 may be present. The liquid feed inlet 76 may be formed as a conduit of a certain length engaging the feed assembly wall 36. The conduit may include an inlet axis aligned with and / or parallel to the central axis 28, such that liquid feed or a majority (i.e., >50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%) of liquid feed introduced through inlet 76 may be introduced axially or at a non-perpendicular angle relative to the central axis 28 into the central chamber 58. In other words, the liquid feed introduced through inlet 76 is not introduced perpendicular to the central axis 28. A liquid feed manifold 80 may be used to introduce liquid feed through the liquid feed inlet 76. The manifold 80 is fluidly coupled to a liquid feed source containing the liquid hydrocarbons to be converted. Manifold 80 includes one or more spray nozzles 78 for introducing liquid feed as a liquid droplet spray into central chamber 58. In the case of multiple liquid feed inlets 76, manifold 80 may include multiple spray nozzles 78 positioned and oriented to introduce liquid feed as multiple droplet sprays into central chamber 58 through the liquid feed inlets 76. In some embodiments, droplets in the liquid feed define a non-swirling spray and / or a radially extending fan-shaped pattern, such that all or part of the droplets are not parallel to the central axis, but have both axial and radial velocity components. Furthermore, the droplet pattern may be centered on or near a central axis 28 in which the swirling velocity is lowest. In some embodiments, one or more spray nozzles 78 introduce liquid into central chamber 58 of feed assembly 32, wherein the swirling velocity of the swirling fluid flow during operation of reactor 10 is less than 5 m / s. One or more spray nozzles may be located within a certain placement radius (“PR”) defined by the point where the central axis 28 intersects the plane defined by the upstream wall 36 of the feed assembly 32. In one embodiment, the radius PR is no greater than 30% of the radius of the central chamber 58. In other embodiments, the radius PR is no greater than 20% of the radius of the central chamber 58. As described below in various embodiments, using nozzles that produce specific droplet sizes and placing the nozzles at a central location within the feed assembly of the reactor system described below (i.e., aligned with or near the central axis) results in hydrocarbon conversion efficiencies not seen in conventional reactor systems. As described below, the central location of the nozzles injects liquid hydrocarbon reactant feed into the region of the reactor at a low swirling velocity (e.g., less than 5 m / s). This location, along with the droplet size, allows the liquid droplets to vaporize before entering the region of the feed assembly at a higher swirling velocity, thereby preventing rapid coking of the reactor.Therefore, the combination of nozzle position and droplet size produced by the nozzle at that position offers certain unique advantages.

[0051] The combination of the axial and radial velocity components defines a spray pattern with a low spray angle, and keeps this pattern close to the central axis 28. Therefore, the droplets are primarily guided axially (e.g., to define a spray angle of 40° or less). Such a spray angle helps ensure that the liquid droplets are vaporized before being trapped in the swirling gas flow and forced against the reactor wall by centrifugal force, which could otherwise lead to coking. In certain embodiments, the spray angle of the spray pattern can be at least, equal to, and / or between any two of the following: 5°, 6°, 7°, 8°, 9°, 10°, 11°, 12°, 13°, 14°, 15°, 16°, 17°, 18°, 19°, 20°, 21°, 22°, 23°, 24°, 25°, 26°, 27°, 28°, 29°, 30°, 31°, 32°, 33°, 34°, 35°, 36°, 37°, 38°, 39°, and 40°. In some embodiments, the spray pattern can be a solid cone, a hollow cone, a linear flow, or a flat spray pattern. In various embodiments, the liquid feed inlet 76 does not include guide vanes, such as vanes 68, 70, 72, 74, or other structures that can impart swirling fluid flow to the liquid hydrocarbons before they enter the central chamber 58.

[0052] By introducing liquid hydrocarbons axially, the atomized spray with liquid droplets is primarily concentrated near the central axis 28 of reactor 10, where the swirling velocity is lowest. In effect, the liquid droplets concentrate at the "eye" of the swirling fluid flow. Further away from the central axis 28 or centerline and closer to the wall, higher swirling velocities are encountered. These higher swirling velocities can deposit the atomized droplets on the walls and guide vanes, leading to coking and fouling. The small droplets interact with the countercurrent flow of high-temperature gases from combustion and strong recirculation, causing the droplets to vaporize and follow other hydrocarbon gases, increasing heat and cracking within reactor 10.

[0053] The spray nozzle 78 can be selected and / or configured to provide a specific droplet size. The spray nozzle can be structured or configured to provide a Sauter Mean Diameter (SMD) or D under selected flow conditions (e.g., pressure, velocity). 32 Droplets ranging from 1 μm to 250 μm. As used herein, SMD or D... 32Size is defined as the ratio of droplet volume to droplet surface area in a spray. Droplet measurements can be determined using phase Doppler interferometry (PDI) technology. In a particular embodiment, the nozzle at the liquid feed inlet 76 can provide the liquid hydrocarbon feed with an SMD size at least equal to and / or between any two of the following: 1μm, 2μm, 3μm, 4μm, 5μm, 6μm, 7μm, 8μm, 9μm, 10μm, 11μm, 12μm, 13μm, 14μm, 15μm, 16μm, 17μm, 18μm, 19μm, 20μm, 21μm, 22μm, 23μm, 24μm, 25μm, 26μm, 27μm, 28μm, 29μm, 30μm, 30μm, 30μm, 30μm, 32μm, 33μm, 34μm, 35μm, 36μm, 37μm, 38μm, 39μm, 40μm, 41μm, 42μm, 43μm. m, 44μm, 45μm, 46μm, 47μm, 48μm, 49μm, 50μm, 55μm, 60μm, 65μm, 70μm, 75μm, 80μm, 85μm, 90μm, 95μm, 100μm, 105μm, 110μm, 115μm, 120μm, 125μm, 130μm, 135μm, 140μm m, 145μm, 150μm, 155μm, 160μm, 165μm, 170μm, 175μm, 180μm, 185μm, 190μm, 195μm , 200μm, 205μm, 210μm, 215μm, 220μm, 225μm, 230μm, 235μm, 240μm, 245μm and 250μm.

[0054] Smaller droplet sizes result in faster vaporization and a lower likelihood of the droplets entering the higher swirl regions of the reactor. However, smaller droplet sizes also lead to higher pressure drops across the nozzle and limit the fineness of atomization achievable with the nozzle. Therefore, droplet size represents a trade-off between two competing requirements. Figure 5 The graph shows the vaporization time as a function of droplet size, obtained using simplified calculations under approximate conditions in the reactor. Figure 6 The computational fluid dynamics (CFD) calculations for spray evaporation in a reactor are shown, where all liquid vaporizes within 5 mm of the injection point. The graph shows the volume fraction of the liquid in the spray, ranging from approximately 2.5 × 10⁻⁶ at introduction. -5 It becomes 0 (this indicates that all the liquid has been vaporized).

[0055] Other characteristics of the droplets produced by the spray nozzle 78 may include the weighted average droplet size. The weighted average droplet size may include the median mass (volume) or the 50% diameter (DV). 0.5The diameter (DV) is the diameter of a droplet whose total volume is 50% contained within a particle with a smaller diameter. In some embodiments, the droplet's DV... 0.5 It can be at least, equal to, and / or between any two of the following: 10μm, 11μm, 12μm, 13μm, 14μm, 15μm, 16μm, 17μm, 18μm, 19μm, 20μm, 21μm, 22μm, 23μm, 24μm, 25μm, 26μm, 27μm, 28μm, 29μm, 30μm, 30μm, 31μm, 32μm, 33μm, 34μm, 35μm, 36μm, 37μm, 38μm, 39μm, 40μm, 41μm, 42μm, 43μm, 44μm, 45μm, 46μm, 47μm, 48μm, 49μm, 50μm m, 55μm, 60μm, 65μm, 70μm, 75μm, 80μm, 85μm, 90μm, 95μm, 100μm, 105μm, 110μm, 115μm, 120μm, 125μm, 130μm, 135μm, 140μm, 145μm, 150μm, 155 μm, 160μm, 165μm, 170μm, 175μm, 180μm, 185μm, 190μm, 195μm, 200μm, 2 05μm, 210μm, 215μm, 220μm, 225μm, 230μm, 235μm, 240μm, 245μm and 250μm. In a specific embodiment, the spray nozzle is configured to form a DV 0.5 The droplets range from 10 micrometers to 50 micrometers.

[0056] DV 0.1 It was found that 10% of the total droplet volume was less than its diameter. In some implementations, the spray's DV 0.1It can be at least, equal to, and / or between any two of the following: 5μm, 6μm, 7μm, 8μm, 9μm, 10μm, 11μm, 12μm, 13μm, 14μm, 15μm, 16μm, 17μm, 18μm, 19μm, 20μm, 21μm, 22μm, 23μm, 24μm, 25μm, 26μm, 27μm, 28μm, 29μm, 30μm, 30μm, 31μm, 32μm, 33μm, 34μm, 35μm, 36μm, 37μm, 38μm, 39μm. m, 40μm, 41μm, 42μm, 43μm, 44μm, 45μm, 46μm, 47μm, 48μm, 49μm, 50μm, 55μm, 60μm, 65μm, 70μm, 75μm, 80μm, 85μm, 90μm, 95 μm, 100μm, 105μm, 110μm, 115μm, 120μm, 125μm, 130μm, 135μm, 140μm, 145μm, 150μm, 155μm, 160μm, 165μm, 170μm, 175μm. In a specific embodiment, the spray nozzle is configured to form a DV 0.1 Droplets ranging from 5 to 25 micrometers in size.

[0057] DV 0.9 It was found that 90% of the total droplet volume was lower than its diameter. In some cases, the spray's DV 0.9can be at least, equal to, and / or between any two of the following: 20μm, 21μm, 22μm, 23μm, 24μm, 25μm, 26μm, 27μm, 28μm, 29μm, 30μm, 30μm, 31μm, 32μm, 33μm, 34μm, 35μm, 36μm, 37μm, 38μm, 39μm, 40μm, 41μm, 42μm, 43μm, 44μm, 45μm, 46μm, 47μm, 48μm, 49μm, 50μm, 55μm, 60μm, 65μm, 70μm, 75μm, 80μm, 85μm, 90μm, 95μm, 100μm, 105μm, 110μm, 115μm, 120μm, 125μm, 130μm, 135μm, 140μm, 145μm, 150μm, 155μm, 160μm, 165μm, 170μm, 175μm, 180μm, 185μm, 190μm, 195μm, 200μm, 205μm, 210μm, 215μm, 220μm, 225μm, 230μm, 235μm, 240μm, 245μm, 250μm, 255μm, 260μm, 265μm, 270μm, 275μm, 280μm, 285μm, 290μm, 295μm, 300μm, 305μm, 310μm, 315μm, 320μm, 325μm, 330μm, 335μm, 340μm, 345μm, 350μm, 355μm, 360μm, 365μm, 370μm, 375μm, 380μm, 385μm, 390μm, 395μm, 400μm, 405μm, 410μm, 415μm, 420μm, 425μm, 430μm, 435μm, 440μm, 445μm, and 450μm. In a particular embodiment, the spray nozzle is configured to form DV 0.9 droplets that are from 20 microns to 100 microns.

[0058] To facilitate the formation of a suitable fine spray of liquid hydrocarbon feed with such small droplet size, the liquid hydrocarbon can be modified to have a dynamic viscosity of 0.1 cP to 1000 cP before or at introduction, as measured using ASTM D445, but at the operating temperature (i.e., the temperature at which the liquid hydrocarbon passes through the nozzle). For example, as discussed below, in some cases the liquid hydrocarbon feed can be preheated to a temperature between 25°C and 400°C, and the viscosity measured at this temperature. Droplet size is approximately proportional to the 0.2 power of dynamic viscosity, therefore lower dynamic viscosity results in smaller droplet size. Typically, fluids with lower dynamic viscosity also have lower surface tension, and droplet size is approximately related to the 0.5 power of surface tension. In some embodiments, the liquid hydrocarbon may be modified to have a dynamic viscosity of at least, equal to, and / or between any two of the following: 0.1 cP, 0.2 cP, 0.3 cP, 0.4 cP, 0.5 cP, 0.6 cP, 0.7 cP, 0.8 cP, 0.9 cP, 1 cP, 2 cP, 3 cP, 4 cP, 5 cP, 6 cP, 7 cP, 8 cP, 9 cP, 10 cP, 15 cP, 20 cP, 30 cP, 40 cP, 50 cP, 60 cP, 70 cP, 80 cP, 90 cP, 100 cP, 150 cP, 200 cP, 250 cP, 300 cP, 350 cP, 400 cP, 450 cP, 500 cP, 550 cP, 600 cP, 650 cP, 700 cP, 750 cP, 800 cP, 850 cP, 900 cP, 950 cP, and 1000 cP. Modification of hydrocarbons may include heating the hydrocarbons to sufficient temperatures and / or combining liquid hydrocarbons with solvents or low-viscosity components such as aromatic compounds (e.g., xylene, benzene, toluene, and ethylbenzene, which may be part of a recovery stream) to reduce dynamic viscosity.

[0059] In some applications, the spray nozzle 78 can be configured or selected as a two-fluid nozzle. Such a two-fluid nozzle allows the introduction of two different fluids, each with different properties. For example, the liquid may include a liquid phase fluid and a gas phase fluid, each simultaneously ejected through the nozzle 78. The two-fluid nozzle 78 may have a mixing chamber in which the two fluids are mixed before being discharged as a spray. This two-fluid nozzle also provides internal mixing of the two fluids to prevent clogging, and provides a fine atomized spray with the aforementioned droplet size. Such a two-liquid spray nozzle is described, for example, in U.S. Patent Application Publication No. US2020 / 0147624, the entire contents of which are incorporated herein by reference for all purposes, including a description of the construction and use of such nozzles. Two-fluid nozzles can facilitate rapid diffusion of the mixture from the outlet, atomization, and droplet formation, which can be easily conveyed by the atomizing gas. Two-fluid nozzles can aid in the atomization and dispersion of high-viscosity liquids by allowing the gas phase to flow together with the high-viscosity liquid phase. This can reduce liquid deposition at the mixed gas outlet and prevent clogging. Suitable commercially available dual-fluid nozzles for use as spray nozzle 78 may include those available from Spraying Systems Co., Tokyo, Japan, such as FLOWMAX. ® X series or FLOWMAX ® FM3A nozzles are dual-fluid nozzles for sale.

[0060] The energy input to a spray nozzle equals the pressure drop across the nozzle multiplied by the flow velocity. The choice between single-phase and two-phase nozzles depends on the pressure drop to achieve the same droplet size distribution. Besides pressure drop, the choice between single-phase and two-phase nozzles may be limited by factors such as achieving the desired droplet size distribution, spray angle, hollow vs. full cone configuration. For example, there are options for internal to external mixing to address fouling, compared to two-phase nozzles. Furthermore, for current applications involving hydrocarbons, the correct selection of a spray nozzle may depend on high-temperature operability, coking and fouling characteristics, erosion, and the ability to detect and remove the nozzle's narrow opening. Generally, two-fluid nozzles offer a wide range of control over droplet size distribution and self-cleaning capabilities because the gas phase can be vapor. A disadvantage may be that slight changes in the gas or liquid phase flow rate or pressure can significantly alter droplet and spray characteristics.

[0061] In various embodiments of this disclosure, liquid hydrocarbons may be introduced into the liquid feed inlet 76 via a dual-fluid spray nozzle 78, together with gaseous hydrocarbons and / or steam (i.e., superheated steam) as a second fluid. The spray nozzle 78 is coupled to one end of a spray manifold 80, which is fluidly connected to a separate upstream source of liquid hydrocarbons and gaseous feed (i.e., steam and / or gaseous hydrocarbons). The pressure range of the liquid feed and steam feed depends on the nozzle design. For example, Figure 7 The diagram shows the different flow conditions and various droplet sizes (i.e., D).32 Dv 0.9 Dv 0.99 FLOWMAX uses liquid water and air. ® Test results for the FM3A dual-fluid nozzle. Under a constant gas pressure of 4.14 barg, the liquid pressure varied from 1 barg to 3 barg. The corresponding liquid flow rate ranged from 1 L / min to -11 L / min, and the air velocity was between 80 Nm. 3 / hr to 100Nm 3 The flow rate is between 10 μm and 55 μm. For these conditions, the surface area density (SMD) varies between 20 μm and 55 μm. Therefore, in this type of dual-fluid nozzle, these parameters can be adjusted according to any specific hydrocarbon used as the liquid feed and steam or other gas used as the gas phase.

[0062] If the desired droplet characteristics are not achieved, the droplets may take significantly longer to vaporize. The vaporization time is proportional to the square of the droplet diameter. Furthermore, the droplets may encounter higher swirling velocities, resulting in high centrifugal accelerations (e.g., 100g to 100,000g forces), leading to droplet deposition on the walls and coking and fouling of the reactor. This creates a positive feedback loop where any deposits will disrupt the desired hydrodynamics and accelerate additional uneven distribution and deposition. This results in coking and clogging of the reactor. Therefore, droplet characteristics such as droplet size and spray angle are important for robust operation of reactors with liquid feed.

[0063] In various embodiments of this disclosure, the liquid hydrocarbon feed that can be converted by reactor system 10 may include a variety of liquid hydrocarbons. These include liquid hydrocarbons that cannot be directly used in a steam cracker due to their high boiling point, and which cannot be vaporized without coking the preheater. These may include one or more of the following: crude oil, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, C 20 To C 40 Hydrocarbons, or mixtures of two or more of them, biomass-derived oils, pyrolysis oils from plastics, liquefied plastics, liquefied plastic waste with impurities, heteroatom-containing hydrocarbon liquids, and combinations of these liquid hydrocarbons.

[0064] Crude oil can be used as is or pretreated in flash tanks, crude oil distillation, or other processing systems to remove certain materials, such as asphaltenes, resins, sulfur compounds, and / or trace metals, where the presence of such materials is undesirable or may lead to coking within the reactor. In many applications, the liquid hydrocarbon can have a wide range of molecular weights or boiling points, resulting in a dynamic viscosity in the range of 0.1 cP to 1000 cP, allowing for fine atomization through commercially available single-phase or two-phase nozzles. In some applications, the liquid hydrocarbon can be untreated crude oil that has not been pretreated or refined to remove any materials.

[0065] The liquid hydrocarbons converted by reactor system 10 will typically account for 0.5% to 100% by weight of the total weight of the hydrocarbon reactant feed (i.e., liquid and gaseous hydrocarbons). In a particular embodiment, the liquid hydrocarbons may account for at least, equal to, and / or between any two of the following based on the total weight of the hydrocarbon reactant feed: 0.5% by weight, 0.6% by weight, 0.7% by weight, 0.8% by weight, 0.9% by weight, 1.0% by weight, 1.1% by weight, 1.2% by weight, 1.3% by weight, 1.4% by weight, 1.5% by weight, 1.6% by weight, 1.7% by weight, 1.8% by weight, 1.9% by weight, 2.0% by weight, 2.1% by weight, 2.2% by weight, and 2.3% by weight. %, 2.4 wt%, 2.5 wt%, 2.6 wt%, 2.7 wt%, 2.8 wt%, 2.9 wt%, 3.0 wt%, 3.1 wt%, 3.2 wt%, 3.3 wt%, 3.4 wt%, 3.5 wt%, 3.6 wt%, 3.7 wt%, 3.8 wt%, 3.9 wt%, and 4.0 wt%, 4.1 wt%, 4.2 wt%, 4.3 wt%, 4.4 wt%, 4.5 wt%, 4.6 wt%, 4.7 wt%, 4.8 wt%, 4. 9% by weight, 5.0% by weight, 5.1% by weight, 5.2% by weight, 5.3% by weight, 5.4% by weight, 5.5% by weight, 5.6% by weight, 5.7% by weight, 5.8% by weight, 5.9% by weight, 6.0% by weight, 6.1% by weight, 6.2% by weight, 6.3% by weight, 6.4% by weight, 6.5% by weight, 6.6% by weight, 6.7% by weight, 6.8% by weight, 6.9% by weight, 7.0% by weight, 7.1% by weight, 7.2% by weight, 7.3% by weight, 7.4% by weight 7.5% by weight, 7.6% by weight, 7.7% by weight, 7.8% by weight, 7.9% by weight, 8.0% by weight, 8.1% by weight, 8.2% by weight, 8.3% by weight, 8.4% by weight, 8.5% by weight, 8.6% by weight, 8.7% by weight, 8.8% by weight, 8.9% by weight, 9.0% by weight, 9.1% by weight, 9.2% by weight, 9.3% by weight, 9.4% by weight, 9.5% by weight, 9.6% by weight, 9.7% by weight, 9.8% by weight, 9.9% by weight, and 10%.0% by weight, 11% by weight, 12% by weight, 13% by weight, 14% by weight, 15% by weight, 16% by weight, 17% by weight, 18% by weight, 19% by weight, 20% by weight, 21% by weight, 22% by weight, 23% by weight, 24% by weight, 25% by weight, 26% by weight, 27% by weight, 28% by weight, 29% by weight, 30% by weight, 31% by weight, 32% by weight, 33% by weight, 34% by weight, 35% by weight, 36% by weight, 37% by weight, 38% by weight, 39% by weight, and 40% by weight, 41% by weight, 42% by weight, 43% by weight, 44% by weight, 45% by weight, 46% by weight, 47% by weight, 48% by weight, 49% by weight, 50% by weight, 51% by weight, 52% by weight, 53% by weight, 54% by weight, 55% by weight Weight percentage, 56% by weight, 57% by weight, 58% by weight, 59% by weight, 60% by weight, 61% by weight, 62% by weight, 63% by weight, 64% by weight, 65% by weight, 66% by weight, 67% by weight, 68% by weight, 69% by weight, 70% by weight, 71% by weight, 72% by weight, 73% by weight, 74% by weight, 75% by weight, 76% by weight, 77% by weight, 78% by weight, 79% by weight, 80% by weight, 81% by weight, 82% by weight, 83% by weight, 84% by weight, 85% by weight, 86% by weight, 87% by weight, 88% by weight, 89% by weight, 90% by weight, 91% by weight, 92% by weight, 93% by weight, 94% by weight, 95% by weight, 96% by weight, 97% by weight, 98% by weight, 99% by weight, and 100% by weight.

[0066] In many applications, liquid hydrocarbons will be converted together with gaseous hydrocarbons in reactor system 10. As used herein, “gaseous hydrocarbons” is intended to include those hydrocarbons in a gaseous or superheated state at temperatures and pressures such as with or without added steam dilution. This can include those hydrocarbons that are liquid under standard atmospheric conditions but at elevated temperatures and / or reduced pressures, such that they are vaporized before being introduced into reactor system 10. Gaseous hydrocarbons can include, but are not limited to, natural gas liquids (NGL), natural gas condensate, associated petroleum gas, C4 stream, primary C4 stream, and gaseous C1 to C2 streams. 20Hydrocarbons, or a mixture thereof, and combinations thereof. For example, gaseous hydrocarbons may have boiling points not exceeding 450°C, 250°C, or 150°C at one atmosphere. As used herein, a primary C4 stream comprises a mixture of C4 materials, including olefinic C4 materials such as butadiene, butene, isobutene, etc., such as those C4 olefins produced during steam cracking operations. By way of example, a typical primary C4 stream may have 15% to 35% by weight of each of 1,3-butadiene, 1-butene, and isobutene, 5% to 15% by weight of each of 2-butene and n-butene, and 0.1% to 5% by weight of 1,2-butadiene, vinylacetylene, and ethylacetylene.

[0067] In some cases, all or part of the gaseous hydrocarbons may be fed together with the liquid hydrocarbon feed through the liquid feed inlet 76 and the spray nozzle 78. When introducing liquid hydrocarbons using a two-fluid nozzle 78, the gaseous hydrocarbons may be mixed with the liquid hydrocarbons within the nozzle 78 itself, such as in the nozzle's mixing chamber, before being discharged as a spray. Where the spray nozzle 78 is not a two-fluid nozzle, the liquid and gaseous hydrocarbons may be mixed and combined upstream of the nozzle 78, where they can both be discharged together through the spray nozzle 78. In other cases, the gaseous hydrocarbons may be introduced separately from the liquid hydrocarbons through the liquid feed inlet 76.

[0068] In many applications, all or part of the gaseous hydrocarbon feed to be converted by reactor system 10 is introduced through one of the annular flow channels 46, 48, 52, and 54 of feed assembly 32. Typically, this will be the upstream flow channel 46 immediately adjacent to the liquid feed inlet 76.

[0069] One or both of the liquid hydrocarbon feed and / or gaseous hydrocarbon feed can be mixed with steam. This is typically superheated steam, which is combined with and fed together with the hydrocarbon feed before it is introduced into the feed assembly 32 or the central chamber 58. In the case of introducing liquid hydrocarbons using a two-fluid nozzle 78, the steam can be mixed with the liquid hydrocarbons within the nozzle 78 itself before it is discharged as a spray. Steam can also be introduced separately into the feed assembly 32 through one of the annular flow channels, such as the downstream flow channel 48.

[0070] In an example of the operation of reactor system 10, a gaseous hydrocarbon feed, such as those previously discussed, is introduced from manifold 60 through an inlet into flow passage 46. A hydrogen-containing fuel gas is introduced from manifold 66 into flow passage 54. The hydrogen-containing fuel gas can be hydrogen (H2), methane (CH4), and / or CO / syngas, or a combination thereof. Here, CH4 is used as the fuel for combustion. In some embodiments using a combination of hydrogen and methane, methane may be present in the fuel gas in amounts of 20 mol%, 15 mol%, 10 mol%, 5 mol%, or less. Larger amounts of methane may affect the desired selectivity. However, in other embodiments, larger amounts of methane can be used, including 100% methane for the fuel gas. Natural gas may also be used as the fuel gas.

[0071] The hydrogen-containing fuel gas can be a hydrogen-rich stream consisting primarily of hydrogen, which can be a recycled stream from downstream processing or additional hydrogen. The hydrogen-rich stream may contain other components such as methane, CO, steam, inert gases, and CO2. In some embodiments and applications, other hydrocarbons may also be used as fuel gases. Additionally, small amounts of N2 may be present. Sulfur may also be present in the fuel gas or other feed streams. If sulfur is present, additional upstream or downstream separation may be required. The reactor and process are robust enough to accommodate the presence of sulfur, especially since no catalyst is used. Based on mass, the ratio between hydrocarbon feed (i.e., the total amount of liquid and gaseous hydrocarbons) and hydrogen-containing fuel is typically in the range of 1 to 15, more specifically 1 to 10.

[0072] An oxidant or oxygen-containing gas is introduced as an oxidant feed into flow channel 52 through inlet via manifold 64. This oxidant or oxygen-containing gas can be concentrated or pure oxygen, such as from an air separation unit (not shown). The oxygen-containing gas is introduced through downstream flow channel 52 to further separate it from any hydrocarbon gas introduced through liquid feed inlet 76 and flow channel 46, to eliminate or minimize any combustion of the introduced hydrocarbon reactant feed. In some applications, the H2 / O2 molar ratio can be in the range of 2 to 9, more particularly 2 to 5, and even more particularly 2 to 4. The oxygen feed can provide an oxygen equivalent to fuel molar ratio of 0.2 to 1.0. Excess hydrogen also helps to remove free radicals (e.g., O, OOH, OH) that would otherwise react with the hydrocarbon feed. In some cases, the H2 / O2 molar ratio can be less than 2 to compensate for other fuel gases, or to have excess O2 in the mixing zone to release heat to counteract endothermic cracking reactions. In some cases, hydrogen is supplied at a substoichiometric level (below 1) to allow for additional exothermic reactions in the mixing zone. An oxygen feed can provide an oxygen equivalent to fuel molar ratio of 0.125 to 0.50. Furthermore, the ratio between hydrocarbon feed and hydrogen fuel is typically in the range of 1.0 to 15, depending on the hydrocarbon feed, based on mass.

[0073] Steam or water can be introduced into the flow channel 48 through manifold 62 and inlet. Steam can be introduced upstream of other feeds and can be used to cool the walls of the convergence-divergence duct 24 and reactor vessel 12. The introduced steam also lowers the reaction temperature within reactor 10. Steam can also be premixed with various feeds, such as liquid hydrocarbon feeds and gaseous hydrocarbon feeds, fuel gases, and / or oxygen-containing feeds. In some applications, steam can be used at a steam-to-fuel mass ratio greater than 0 to 10.0, more particularly 0 to 2.0.

[0074] In practice, all oxygen and at least a portion of the hydrogen-containing fuel gas are typically burned to form heated combustion products, which are almost completely mixed with the other feed before leaving the convergent-divergent duct 24 and entering the reaction chamber 16. Due to the high centrifugal force of the swirling gas, denser gases (e.g., pyrolysis feed) flow closer to the reactor walls, while the hotter combustion products tend to flow through the center of the reactor. The device geometry and the swirling gas mixture from the central chamber 58 result in a backflow of the gas mixture within the reaction chamber 16. This mixture flows upstream and radially inward from a thin outer annular layer of mixed gas circulating within the reaction chamber 16. This backflow is due to the... Figure 2 The high-swirling steam delivered through flow channel 48 may cause internal cooling of the wall. This is achieved through the location... Figure 2 Additional cooling is provided by the water jacket between walls 14 and 18 (if necessary).

[0075] The liquid hydrocarbon feed introduced as a droplet spray from nozzle 78 through inlet 76 is immediately vaporized. The low liquid viscosity and small droplet size increase the rate at which the liquid feed is heated and vaporized. In various embodiments, it is not necessary to preheat the liquid hydrocarbon before introducing it into reactor system 10. In some cases, the liquid hydrocarbon may be preheated. This can reduce the viscosity to the previously discussed viscosity range to promote optimal droplet formation. Typical temperatures for preheating the liquid can range from 25°C to 400°C.

[0076] The operating conditions of reactor 12 can vary depending on the type of hydrocarbon feed. The gas residence time within reactor 10 can range from 50 milliseconds or less, more particularly from 20 milliseconds or less. In a particular embodiment, the residence time range can be 20, 19, 18, 17, 16, 15, 14, 13, 12, 11, 10, 9, 8, 7, 6, 5, 4, 3, 2, 1 milliseconds or less, where 10 microseconds is an approximate minimum residence time. The pressure at the reactor outlet can vary. A suitable pressure at the reactor outlet can range from 0 kPa(g) to 10,000 kPa(g), more particularly from 0 kPa(g) to 1,000 kPa(g).

[0077] The reaction temperature can range from 800°C to 2500°C, with the lowest temperature found at the reactor outlet when all endothermic reactions are complete, and the highest temperature encountered in the combustion zone (flame) of the reactor. The reaction temperature within the reactor and recirculation zone can range from 900°C to 1300°C. In certain embodiments, the temperature within the reactor and recirculation zone can range from 1000°C to 1300°C, more specifically from 1200°C to 1250°C. In some embodiments, the reactor temperature is higher than that achieved in conventional cracking reactors, such as tubular furnace reactors, which typically operate at 800°C to 900°C. This is due to the temperature limitations of the metallic materials used in such conventional reactors, as discussed earlier. In the ANJEVOC reactor, the swirling gas mixture keeps the reactor walls cooler than in such conventional cracking reactors. Using this higher temperature also allows for shorter residence or contact times, resulting in better selectivity and conversion without the formation of unwanted products. The operating temperature for the reactor can be selected to avoid the excessive production of such unwanted compounds, such as CO and CO2, or to optimize the olefin to acetylene ratio, since acetylene is generally undesirable.

[0078] The gas flow entering the central chamber 58 through flow channels 46, 48, 52, 54 is tailored such that the axial velocity (i.e., along the same direction as the central axis 28) is zero or close to zero. The orientation of inlets (not shown) and / or guide vanes 68, 70, 72, 74 can be provided for each flow channel 46, 48, 52, 54 to achieve a selected azimuth-to-radial velocity ratio for each feed stream flowing through the flow channels 46, 48, 52, 54, wherein the azimuth direction and the radial direction are defined in a cross-section perpendicular to the central axis 28 of the reactor 10. Specifically, for each inlet, the radial direction is along a line extending from the inlet to the axis 28. The azimuth direction is perpendicular to both the radial direction and the axial direction (i.e., the direction of the axis 28). Returning to the azimuth-to-radial velocity ratio, in certain embodiments, it can range from greater than 0 to 30 or greater, more specifically from >0, 1, or 2 to 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, or 30. In some applications, the azimuth-to-radial velocity ratio can range from >0 to 5, more specifically from 2 to 4. However, a particular azimuth-to-radial velocity ratio can vary depending on the specific reactor configuration and the composition of various flows. This is more closely related to the flow rates of the fuel and feedstock used for pyrolysis, the mixing time of the composition, and the reaction time.

[0079] The converted hydrocarbon products generated in the reactor are removed from reactor vessel 12 through outlet 20. The converted hydrocarbon products may be quenched within the quenching zone of reactor vessel 12, or they may be quenched outside reactor vessel 12 in a quenching unit, such as a water spray quenching container or other suitable gas quenching device. The quenched products may be further processed and recovered, as discussed later.

[0080] In the described variant of the reactor, the location can be at the midpoint along the length of the reactor vessel 12, such as at inlet 82 ( Figure 2 Additional hydrocarbon feed gas is introduced as a secondary feed stream at the feed assembly 32. One or more such inlets 82 can be located at various positions and within the reactor vessel 12, and can be spaced apart circumferentially and longitudinally. The inlets 82 can be oriented or configured such that the gas is also introduced at an angle to promote swirling fluid flow, similar to the fluid flow delivered from the inlet of the feed assembly 32. Feed assemblies similar to feed assembly 32, disposed on the reactor vessel 12, can be used to introduce such cracked feed gas, such that the cracked feed is introduced as a swirling fluid flow.

[0081] In some implementations, multiple reactor inlet assemblies and corresponding feed assemblies can be set in a single reactor while maintaining high performance.

[0082] The reactor system 10 described herein can be used to convert both gaseous and liquid hydrocarbons, such as crude oil, to produce higher-value products, such as light olefins. This system is characterized by high feed conversion and higher selectivity for olefins in a single step. No pretreatment of the crude oil or other hydrocarbons, such as hydrotreating, hydroprocessing, or aromatics removal, is required before introducing them into the reactor, as occurs in conventional crude oil processing. Preheating of the crude oil or other liquid hydrocarbons is not required. Due to the short residence time, the olefin, unsaturated, and / or aromatic content in the feedstock will not hinder cracking or conversion, nor will excessive coking behavior occur during the reaction, as these will simply pass through the reactor unchanged.

[0083] Reactor systems 10 with liquid hydrocarbon feeds, with or without gaseous hydrocarbon feeds, such as those previously described, can be used to provide a variety of higher-value products. These include any and more of the following: olefins, C2 to C6 olefins, ethylene, propylene, butene, acetylene, C3 to C6 alkynes, butadiene, aromatic compounds, xylene, benzene, toluene, and ethylbenzene. Furthermore, at least a portion of any and more of these products in the reactor product stream, such as C2 to C6 alkanes, xylene, benzene, and toluene, can be separated from the reactor product stream and recovered to form at least a portion of the hydrocarbon reactant feed. The ANJEVOC reactor can crack a wide range of hydrocarbons and has a very narrow product composition, primarily forming C2+C3 products, with a certain amount of carbon lost as CO and CO2.

[0084] refer to Figure 8 A schematic diagram of a hydrocarbon processing system 90 and process flow employing reactor system 10 to convert liquid crude oil is shown. The crude oil 92 used as the liquid hydrocarbon feed can be any crude oil typically extracted from underground formations. Crude oil 92 may undergo minimal (if any) processing. In the illustrated embodiment, the only processing that crude oil 92 may undergo is initial flash evaporation or crude oil distillation in a flash tank or unit 94 to remove asphaltenes and / or resins. Overhead liquid crude oil 98 from unit 94 is injected directly into the axial liquid inlet 76 of reactor 10. Asphaltenes and / or resins can be removed from the liquid crude oil bottoms 96 of unit 94 to form a heavy crude oil stream 100. The heavy crude oil stream 100, from which asphaltenes and / or resins have been removed, can be combined with the overhead liquid crude oil 98 to form a combined liquid feed stream 102.

[0085] Conventional steam or naphtha cracker systems cannot use liquid crude oil because the higher boiling points of the fractions coke within the furnace tubes. Furthermore, due to coking, liquid crude oil cannot be fed into the preheaters of such steam or naphtha crackers. Therefore, in conventional systems, crude oil must be processed by distillation to remove the heavier fractions.

[0086] Oxygen and hydrogen fuel feedstocks 104 and 106 are introduced into reactor 10 to form swirling heated combustion gases, providing the elevated reaction temperature required for the conversion. Steam 108 may also be introduced into reactor 10 along with various feedstocks or as its own feed stream, as previously described.

[0087] Liquid hydrocarbons in the combined liquid feed stream 102, introduced as a fine spray, are immediately vaporized and mixed with swirling hot combustion gases. The hydrocarbon reactant feed, consisting of crude oil and any other liquid or gaseous hydrocarbon feed, is mixed with swirling hot combustion gases to form a swirling heated mixture, which is emitted from the central chamber 58 ( Figure 2The mixture passes through the convergent-divergent conduit 24 and enters the reaction chamber 16 of the reactor system 10. The heated mixture reacts within the reaction chamber 16, causing the hydrocarbons in the hydrocarbon feed to be converted into the converted hydrocarbon products.

[0088] The conversion products 110 are typically hydrogen, vapor, oxygen-containing compounds, some heavy substances (>C4), aromatic compounds, and products such as olefins and alkynes. Typically, the products will include C2 to C6 olefins, ethylene, propylene, butene, acetylene, C3 to C6 alkynes, butadiene, and aromatic compounds such as xylene, benzene, toluene, and ethylbenzene.

[0089] Water 112 from quench water and / or condensate steam is separated from the converted hydrocarbon products to form a separated conversion product 114. The conversion product 114 can then be introduced into a fractionator 116, where the product is fractionated to remove fuel oil 118. The fuel oil can be further processed in an aromatic compound complex 120 to produce benzene, toluene, and xylene products.

[0090] The remaining gaseous fraction 122 from fractionator 116 can be pressurized in compressor 124 and delivered to amine treatment unit 126 for removal or washing of CO2 and / or H2S from the converted hydrocarbon products.

[0091] The washed hydrocarbon product 128 from the amine treatment unit 126 is then delivered to separation sequence 130, where the various products are separated from each other. This may require the separation of hydrogen, which can be recovered as a hydrogen recovery stream 132, and this hydrogen recovery stream can be combined with fresh hydrogen 134 to form hydrogen feed 106. Carbon monoxide (CO) and methane (CH4) 136 can be separated from the products in the membrane-based separation system of separation sequence 130. Fuel oil and cracked gasoline from separation sequence 130 can be delivered to aromatic compound complex 120 to produce benzene, toluene, and xylene products.

[0092] All or part of the remaining hydrocarbon products (e.g., C2-C6 hydrocarbons) can be recovered back to reactor system 10 as a recovery stream 140 to form part of the liquid hydrocarbon reactant feed (e.g., the combined liquid feed stream 102). Butane 142 or other gaseous hydrocarbons, such as those previously described, can be used as a gaseous hydrocarbon feed. Gaseous hydrocarbon feed 142 can also be added in combination with or separately from recovery stream 140 to form part of the liquid hydrocarbon reactant feed. This can be introduced along with liquid crude oil feed 98 and / or fed as a swirling gas flow through one of the annular flow channels of reactor 10, such as annular flow channel 46. Any non-recovered hydrocarbon products 144 can be delivered elsewhere for further storage, processing, and / or use. All or part of the benzene, toluene, and / or xylene product stream 146 from aromatic compound complex 120 can also be recovered back to reactor system 10 as a recovery stream 148 to form part of hydrocarbon reactant feed 102. Any remaining benzene, toluene, and / or xylene products from stream 146 may be delivered elsewhere for storage, processing, and / or use.

[0093] Figure 9 A schematic diagram of an additional hydrocarbon processing system 150 and process flow for converting liquid crude oil using reactor system 10 is shown. System 150 is similar to the previously described system 90, with similar components labeled using the same reference numerals. System 150 provides additional downstream system components for processing the converted hydrocarbon products.

[0094] As shown, the washed hydrocarbon product 128 from the amine treatment unit 126 is further pressurized in the compressor 152 and delivered to a cold box or other heat exchanger 154 for cooling the hydrocarbon product 128. The cooled product 156 is then delivered to the hydrogen separator 158, where hydrogen is removed and delivered to the reactor 10 as hydrogen recovery 132 for fuel, just like in system 90.

[0095] In the illustrated embodiment, the hydrogen-free hydrocarbon product 160 from separator 158 is first delivered to a front-end demethanizer 162, where overhead methane and carbon oxides (i.e., CO, CO2) can be removed via membrane separation as stream 164. The carbon oxides from stream 164 can be hydrogenated in converter unit 166. The resulting methane can then be recovered as fuel, such as for boilers or other applications.

[0096] The demethanizing product 168 can be further processed in the deethanizer 170 to remove C2 hydrocarbons, including ethane, ethylene, and acetylene. The C2 compounds are removed as stream 172. This can be fed to the acetylene converter unit 174, where acetylene is hydrogenated to form ethylene and / or ethane. The ethylene and ethane products 176 can be further separated in the C2 splitter 178 into ethane product stream 180 and ethylene product stream 182, respectively, for further processing, use, or storage.

[0097] The deethanized product 184 from deethanizer 170 can be fed to depropanizer 186 to remove C3 hydrocarbons such as propane, propylene, methylacetylene, and propadiene. The removed C3 hydrocarbons 188 can be further processed to hydrogenate methylacetylene and propadiene (MAPD) ​​in MAPD converter 190 to form propane and / or propylene. The propane and propylene products 192 from MAPD converter 190 can be separated into propane product stream 196 and propylene product stream 198, respectively, in C3 separator 194 for further processing, use, or storage.

[0098] The depropanizing product stream 200 from the depropanizer 186 can be fed to the debutanizer 202 to remove C4 hydrocarbons 204, such as butane and various unsaturated C4 isomers (e.g., butene, butyne, butadiene, etc.). The butane from the product stream 204 can be separated from the unsaturated C4 isomers in the C4 splitter 206 to form a butane product stream 208 and an unsaturated C4 isomer product stream 210, respectively, for further processing, use, or storage. In the illustrated embodiment, the butane product stream 208 can be recovered and combined with the gaseous hydrocarbon or butane feed 142, which is then fed to the reactor 10.

[0099] The butane product 212 from the butane de-butane tower 202 consists primarily of aromatic compounds or pyrolytic gasoline (i.e., cracked gasoline), which can be delivered to the aromatic compound complex 120 to produce benzene, toluene, and xylene products. Heavy oil, unreacted sulfur, and heavy metal compounds can be removed from the aromatic compound complex 120 as stream 214.

[0100] Figure 10 A schematic diagram of another hydrocarbon processing system 220 and its process flow is shown, employing a reactor system 10 using a front-end depropanizer to convert liquid crude oil. System 220 is similar to the previously described systems 90 and 150, with similar components labeled using the same reference numerals. Figure 9Unlike system 150, after the washed hydrocarbon product 128 from amine processing unit 126 is pressurized in compressor 152, the product is first delivered to high-pressure depropanizer 222. The front-end depropanizer is not conducive to the initial removal of CH4, CO, and H2, resulting in a lower partial pressure of C2H2. The lower partial pressure of C2H2 (e.g., less than 15 psig) helps prevent explosive decomposition. Therefore, the front-end depropanizer scheme is more suitable for high C2H2 production conditions.

[0101] C1-C2 hydrocarbons are removed as overhead stream 224 from the high-pressure propane dehydrogenator 222. Bottom stream 226 from the high-pressure propane dehydrogenator 222 contains C3 or higher hydrocarbons. The C1-C2 overhead stream 224 is fed to an acetylene converter unit 228, where the acetylene in stream 224 is hydrogenated to form ethylene and / or ethane. The hydrogenation product 230 from the acetylene converter 228 is fed to a cold box or other heat exchanger 232 for cooling the hydrocarbon product 230. The cooled product 234 is then fed to a hydrogen separator 236, where hydrogen is removed and the recovered hydrogen 238, intended for use as fuel, is fed to reactor 10, as in systems 90 and 150.

[0102] A separated, hydrogen-free product 240, consisting of methane, ethane, and ethylene, is fed to a demethanizer 242, where overhead methane and carbon oxides (i.e., CO, CO2) are removed via membrane separation as stream 244. The carbon oxides from stream 244 can be hydrogenated in converter unit 246. The resulting methane stream 248 can then be recovered as methane fuel, such as for boilers or other applications.

[0103] The demethanizing product 250 can be further processed in the deethanizer 252. The C2 compounds of ethane and ethylene from the deethanizer 252 are removed as stream 254. This can be delivered to the C2 splitter 256 as ethane product stream 258 and ethylene product stream 260, respectively, for further processing, use, or storage.

[0104] Bottom product 226 from high-pressure depropanizer 222, containing C3 or higher hydrocarbons, is fed to low-pressure depropanizer 264. C3 product stream 266 is removed from low-pressure depropanizer 264 as overhead. C3 product stream 266 is further processed in MAPD converter 268, where methylacetylene and propadiene are hydrogenated to form propane and / or propylene. The combined propane and propylene products 270 from MAPD converter 268 can be separated into propane product stream 274 and propylene product stream 276, respectively, in C3 splitter 272 for further processing, use, or storage.

[0105] The bottoms 278 from the low-pressure propane stripper 264, containing C4 or higher hydrocarbons, are fed to the butane stripper 280 for removal of C4 hydrocarbons as product stream 282. Butane from the C4 product stream 282 can be separated from unsaturated C4 isomers in a C4 splitter 284 to form butane product stream 286 and unsaturated C4 isomer product stream 288, respectively, for further processing, use, or storage. In the illustrated embodiment, butane product stream 286 can be recovered and combined with gaseous hydrocarbon or butane feed 142, which is then fed to reactor 10.

[0106] The butane product 290 from the butane de-butane tower 280 consists primarily of aromatic compounds or pyrolytic gasoline (i.e., cracked gasoline), which can be delivered to the aromatic compound complex 120 to produce benzene, toluene, and xylene products. Heavy oil, unreacted sulfur, and heavy metal compounds can be removed from the aromatic compound complex 120 as stream 214, similar to systems 90 and 150 discussed previously.

[0107] refer to Figure 11 Another schematic diagram of the hydrocarbon processing system 300 and its process flow is shown. System 300 is similar to the previously described systems 90, 150, and 220, with similar components labeled using the same reference numerals. System 300 is most similar to system 220, utilizing a front-end depropanizer, but differs in that it lacks a flash tank or other separation unit, such as unit 94 of systems 90, 150, and 220, to remove asphaltenes and / or resins from the liquid crude oil before it is introduced into reactor 10. Instead, unpyrolyzed asphaltenes and resins are removed downstream of ANJEVOC reactor 10 as stream 302. The asphaltenes and resins are knocked out by water quenching and condensed together with the water.

[0108] System 300 also shows a hydrocarbon reactant feed 304, which contains liquid crude oil and various gaseous hydrocarbons such as ethane, propane, LPG, naphtha, etc. These gaseous hydrocarbons can pass through the liquid feed inlet 76 (… Figure 2 A second fluid, such as a two-fluid spray nozzle 78, may be introduced along with liquid crude oil. Alternatively or additionally, gaseous hydrocarbons may be introduced into reactor 10 in a helical fluid flow pattern through one or more annular flow channels, such as flow channel 46, as previously discussed.

[0109] The product stream from reactor 10 undergoes downstream processing in process system 300, and the resulting products are substantially the same as those described for process system 220 utilizing a front-end propane dehydrogenator. The butane recovery stream 286 can be combined with reactant feed 304 to form a combined reactor feed 306.

[0110] The following examples are provided to further illustrate various implementation schemes and applications. Example

[0111] In the following embodiments, various experimental runs were conducted using a variety of liquid and gaseous hydrocarbons in the ANJEVOC reactor system 10 as described herein. Each experimental run is shown as follows: Figures 12 to 15 Different data points on the x-axis. Example 1

[0112] Experiments were conducted using 20 wt% liquid hydrocarbons and gaseous hydrocarbons to simulate the conversion of liquid and gaseous products. The liquids included distilled Arabian Light (AL) crude oil (with approximately 35 wt%–40 wt% heavy matter removed) and a broad range of naphtha (WRN). Each of the AL and WRN liquid feedstocks (in…) Figure 12 The AL crude oil (shown as oil) is fed into the ANJEVOC reactor 10 along with n-butane as a gaseous hydrocarbon. The n-butane gas is introduced through flow channel 46 of the ANJEVOC reactor 10, while the liquid feed is introduced through a single-fluid nozzle 78. The dynamic viscosity of the AL crude oil is less than 10 cP and is introduced as a spray through the liquid inlet, non-perpendicular to the central axis of the central chamber of the reactor's feed assembly. During injection, the liquid's SMD size is 10 μm to 130 μm. Hydrogen is used as fuel, and pure oxygen diluted with nitrogen (N2) is used as the oxidant. The fuel and oxidant are combusted in the central chamber of the reactor's feed assembly to form a swirling thermal combustion gas for the cracking reaction. The flow rates of hydrogen, n-butane, oxygen, and distilled AL or WRN are approximately 4.2 lb / hr, 13.0 lb / hr, 14.6 lb / hr, and 3 lb / hr, respectively. The n-butane is preheated to approximately 350°C, and the liquid hydrocarbons of AL and WRN are preheated to approximately 80°C. The n-butane is fed along with approximately 5 lb / hr of steam.

[0113] Figure 12 The selectivity, by weight percentage, for approximately 20% by weight of distilled AL crude oil and WRN with butane, light olefins, and aromatic compounds in Example 1 is shown. Selectivity for olefins and aromatic compounds (high-value chemicals) varies from 58% to 66%, while selectivity for C2 olefins (ethylene and acetylene) varies from 52% to 62%, depending on operating conditions. Acetylene can be converted to ethylene via an acetylene converter, as in systems 150, 220, and 300, as previously described.

[0114] Figure 13The conversion and bulk gas temperature, in percentage terms, are shown for a feed of 20% by weight of AL crude oil and WRN as liquid in the ANJEVOC reactor of Example 1. Carbon conversion (“C conversion”) typically varies between 70% and 90%, depending on experimental conditions. Bulk gas temperatures were measured at different locations within the reactor, ranging from 600°C to 750°C. Measurements were taken using different thermocouples located in a plane perpendicular to the central axis of the reactor. Figure 13 The bulk gas temperature shown is represented by measurements indicated by circular data points closer to the reactor's central axis. Example 2

[0115] Figure 14 This paper illustrates the weight percentage selectivity of approximately 40 wt% Khuff Gas Condensate (KGC) crude oil for butane, light olefins, and aromatic compounds in an ANJEVOC reactor, such as reactor 10 described herein. Butane gas is introduced through flow channel 46 of ANJEVOC reactor 10, while liquid KGC crude oil is introduced through a two-fluid nozzle 78 with nitrogen as the atomizing gas. The KGC crude oil is introduced as a spray non-perpendicular to the central axis of the central chamber of the reactor's feed assembly. During injection, the spray SMD size ranges from 10 μm to 130 μm. The weight percentage selectivity for olefins and aromatic compounds (high-value chemicals) varies from 60% to 67%, while the weight percentage selectivity for C2 and C3 olefins (ethylene, acetylene, and propylene) varies from 56% to 61%, depending on operating conditions. The H2 flow rate is constant at 4.2 lb / hr, and the O2 flow rate ranges from 14.4 lb / hr to 17.6 lb / hr. Total hydrocarbons, including KGC and n-butane, varied between 16 lb / hr and 20 lb / hr. Nitrogen (as atomizing gas) was introduced into the two-fluid nozzle 78 at 20 psig to 40 psig. Example 3

[0116] Figure 15This paper illustrates the weight percentage selectivity of approximately 40 wt% Arab Ultra Light (AXL) crude oil with butane, light olefins, and aromatics in an ANJEVOC reactor, such as reactor 10 described herein. Butane gas is introduced through flow channel 46 of the reactor, while the AXL crude oil is introduced through a two-fluid nozzle 78 with nitrogen as the atomizing gas. The AXL crude oil and nitrogen are introduced as a spray non-perpendicular to the central axis of the central chamber of the reactor's feed assembly. During injection, the spray SMD size ranges from 10 μm to 130 μm. The weight percentage selectivity for olefins and aromatics (high-value chemicals) varies from 63% to 66%, while the weight percentage selectivity for C3 olefins (ethylene, acetylene, and propylene) varies from 57% to 59%, depending on operating conditions. The H2 flow rate is constant at 4.2 lb / hr, and the O2 flow rate ranges from 14.4 lb / hr to 17.6 lb / hr. Nitrogen gas (as atomizing gas) is introduced into the two-fluid nozzle 78 at 20 psig to 40 psig. Total hydrocarbons, including AXL and n-butane, vary between 16 lb / hr and 20 lb / hr.

[0117] These examples demonstrate that heavy molecules are rapidly cracked in the ANJEVOC reactor and primarily converted into high-value chemicals such as ethylene, acetylene, and propylene. The product composition is cleaner compared to conventional steam crackers. These examples also show that the reactor can directly process up to approximately 40% by weight of high-boiling-point liquids.

[0118] While this disclosure has been shown in certain forms, it will be apparent to those skilled in the art that it is not limited thereto, but that various changes and modifications may be made based on experimental data or other optimizations considering the overall economics of the process without departing from the scope of this disclosure. Therefore, it is appropriate that the appended claims be interpreted broadly and in a manner consistent with the scope of this disclosure.

Claims

1. A method for converting hydrocarbons in a reactor system, said reactor system comprising a central shaft, a feed assembly, and a reactor vessel defining a reaction chamber, said method comprising: Fuel gas and oxidizer gas are introduced into the feed assembly to generate a swirling fluid flow pattern around the central axis. The fuel gas feed and oxidant gas feed are combusted in the feed assembly to form a swirling combustion gas; A hydrocarbon reactant feed containing liquid hydrocarbons to be converted is introduced into the feed assembly, wherein the liquid hydrocarbons have a dynamic viscosity of 0.1 cP to 1000 cP at the temperature at which they are introduced, and are introduced as a liquid spray with droplets having a Sotter mean diameter (SMD) of 1 μm to 250 μm, wherein the spray is introduced into the feed assembly in a flow pattern not perpendicular to the central axis. In the feed assembly, the hydrocarbon reactant feed is mixed with the swirling combustion gas to form a swirling heated mixture; The heated mixture is transferred from the feed assembly to the reaction chamber; The heated mixture is reacted in the reaction chamber under reaction conditions suitable for converting the hydrocarbons fed as hydrocarbon reactants into converted hydrocarbon products; as well as The converted hydrocarbon product is removed from the reaction chamber.

2. The method according to claim 1, wherein the liquid hydrocarbon includes crude oil, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, and C2C2. 20 To C 40 The hydrocarbon, biomass-derived oil, pyrolysis oil from plastics, liquefied plastics, liquefied plastic waste containing impurities, and hydrocarbon liquids containing heteroatoms are at least one of these.

3. The method according to any one of claims 1 to 2, wherein the liquid hydrocarbon accounts for 0.5% to 100% by weight of the hydrocarbon reactant feed.

4. The method according to any one of claims 1 to 3, wherein the hydrocarbon reactant feed further comprises gaseous hydrocarbons.

5. The method of claim 4, wherein the gaseous hydrocarbon comprises liquefied natural gas and C1 to C2 hydrocarbons. 20 At least one of the hydrocarbons.

6. The method according to any one of claims 1 to 5, wherein the converted hydrocarbon product comprises at least one of olefins, C2 to C6 olefins, ethylene, propylene, butene, acetylene, C3 to C6 alkynes, butadiene, aromatic compounds, xylene, benzene, toluene, and ethylbenzene.

7. The method according to any one of claims 1 to 6, further comprising: Separating at least a portion of any or more of C2 to C6 alkanes, xylene, benzene, and toluene from a reactor product stream containing hydrocarbon products from the reactor product stream of the said transformation to form a separated stream; and At least a portion of the separated stream is recovered to form at least a portion of the hydrocarbon reactant feed.

8. The method according to any one of claims 1 to 7, further comprising: Separating at least a portion of any hydrogen (H2) from the reactor product stream containing the converted hydrocarbon products from the reactor product stream to form a separated hydrogen stream; and At least a portion of the hydrogen separation stream is recovered to form at least a portion of the fuel gas feed.

9. The method according to any one of claims 1 to 8, wherein the liquid hydrocarbon is crude oil that has not been pretreated or refined except for the removal of at least one of asphaltenes, resins, sulfur compounds and trace metals.

10. The method according to any one of claims 1 to 9, wherein the hydrocarbon reactant feed further comprises gaseous hydrocarbons, and wherein at least one of the gaseous hydrocarbons and the liquid hydrocarbons is mixed with steam.

11. The method according to any one of claims 1 to 10, further comprising mixing steam with the fuel gas feed, the oxidant gas feed, or the hydrocarbon reactant feed.

12. The method according to any one of claims 1 to 11, wherein the reactor system is an annular jet vortex reactor chamber (ANJEVOC) reactor system.

13. The method according to any one of claims 1 to 12, wherein the liquid hydrocarbon is introduced into the feed assembly at a spray angle of 40° or less relative to the central axis.

14. The method according to any one of claims 1 to 13, wherein the liquid hydrocarbon, together with the second fluid, is introduced into the feed assembly as a two-fluid spray through a two-fluid nozzle.

15. The method of claim 14, wherein the second fluid is steam.

16. The method of claim 14, wherein the hydrocarbon reactant feed further comprises gaseous hydrocarbons, and wherein the second fluid is the gaseous hydrocarbons.

17. A method for converting hydrocarbons in a reactor system, the reactor system comprising i) a reactor vessel defining a reaction chamber, ii) a smoothly curved convergent-divergent conduit having a central axis at the inlet of the reaction chamber, and iii) a feed assembly surrounding a central chamber, the central axis passing through the central chamber, the feed assembly being in fluid communication with the convergent-divergent conduit, the method comprising: Fuel gas feed and oxidant gas feed are introduced into the central chamber surrounded by the feed assembly to generate a swirling fluid flow pattern around the central axis; The fuel gas feed and oxidant gas feed are combusted in the central chamber to form a swirling combustion gas; A hydrocarbon reactant feed comprising liquid hydrocarbon to be converted and a second fluid is introduced into the central chamber via a dual-fluid nozzle. The liquid hydrocarbon has a dynamic viscosity of 0.1 cP to 1000 cP at the temperature at which it is introduced and is introduced into the central chamber as a liquid spray of droplets with a Sotter mean diameter (SMD) of 1 μm to 250 μm in a flow pattern not perpendicular to the central axis. In the central chamber, the hydrocarbon reactant feed is mixed with the swirling combustion gas to form a swirling heated mixture; The heated mixture is transferred from the feed assembly to the reaction chamber; The heated mixture is reacted in the reaction chamber under reaction conditions suitable for converting the hydrocarbons fed as hydrocarbon reactants into converted hydrocarbon products; as well as The converted hydrocarbon product is removed from the reaction chamber.

18. The method of claim 17, wherein the second fluid is steam.

19. The method according to any one of claims 17 to 18, wherein the hydrocarbon reactant feed further comprises gaseous hydrocarbons, and wherein the second fluid is the gaseous hydrocarbons.

20. A reactor system for converting hydrocarbons, the reactor system comprising: A reactor vessel that defines a reaction chamber; A smoothly curved convergent-divergent conduit is located at the inlet of the reaction chamber and has a central axis extending along the upstream and downstream ends of the convergent-divergent conduit, wherein upstream and downstream refer to their relative positions with respect to the direction of overall fluid flow through the reactor system. A feed assembly surrounding a central chamber, the central axis passing through the central chamber, and the feed assembly in fluid communication with the convergent-divergent conduit; A flow channel, which can be connected and configured to introduce fuel gas feed and oxidant gas feed into the central chamber to generate a swirling fluid flow pattern around the central axis; A liquid feed manifold, which can be connected and configured to introduce a hydrocarbon reactant feed containing liquid hydrocarbons to be converted into the central chamber through a liquid feed inlet; At least one spray nozzle, located within the liquid feed manifold and upstream of the feed assembly, wherein the at least one spray nozzle is configured to introduce the liquid hydrocarbon as a liquid spray with a droplet SMD of 1 μm to 250 μm into the central chamber; and The outlet of the reaction chamber is used to remove the converted hydrocarbon products from the reaction chamber.

21. The reactor system of claim 20, wherein the at least one spray nozzle is further capable of being coupled and configured to introduce the liquid hydrocarbon into the central chamber in a flow pattern not perpendicular to the central axis.

22. The reactor system according to any one of claims 20 to 21, wherein the at least one spray nozzle is capable of being coupled and configured to provide a spray pattern having a spray angle of 40° or less relative to the central axis.

23. The reactor system according to any one of claims 20 to 22, wherein the at least one spray nozzle is a two-fluid nozzle, the two-fluid nozzle being coupled and configured to introduce the liquid hydrocarbon and a second fluid as a two-fluid spray into the central chamber of the feed assembly.

24. The reactor system according to any one of claims 20 to 23, further comprising a flow channel capable of being connected and configured to introduce the gaseous hydrocarbon to be converted into the central chamber of the feed assembly.

25. The reactor system according to any one of claims 20 to 24, wherein the flow passages capable of being coupled and configured to introduce the fuel gas feed and the oxidant gas feed are configured such that the fuel gas feed and the oxidant gas feed pass through the flow space in an inward swirling fluid flow pattern, such that the feed flows around the central axis in the central chamber.

26. The reactor system according to any one of claims 20 to 25, wherein the liquid feed inlet is formed as a conduit of a certain length engaging the wall of the feed assembly, wherein the conduit includes an inlet axis aligned with and / or parallel to the central axis, such that >50% of the liquid hydrocarbons are introduced into the central chamber axially and non-perpendicularly relative to the axis.

27. The reactor system according to any one of claims 20 to 26, wherein the liquid feed manifold is fluidly connected to a liquid feed source.

28. The reactor system according to any one of claims 20 to 27, wherein the refractory material is used for the interior of the internal reactor wall.

29. The reactor system according to any one of claims 20 to 28, wherein the diverging portion of the convergent-divergent conduit has a total divergence angle of 25° to 55° relative to the central axis.

30. The reactor system according to any one of claims 20 to 29, wherein the reactor system is an annular jet vortex reactor chamber (ANJEVOC) reactor system.

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