Process for converting liquid and gaseous hydrocarbons to higher value chemicals

Abstract

A process for converting hydrocarbons utilizes a reactor including a central axis, a feed assembly, and a reactor vessel defining a reaction chamber. A fuel gas feed and an oxidant gas feed are introduced into the feed assembly in a swirling fluid flow pattern, which combust to form a swirling combustion gas. A raw C4 hydrocarbon stream received from an upstream hydrocarbon processing system and a hydrocarbon reactant feed of liquid hydrocarbons are introduced into the central chamber. The liquid feed is introduced as a liquid spray in a flow pattern that is not perpendicular to the central axis. A hydrocarbon feed is mixed with the swirling combustion gas to form a swirling heated mixture that passes from the central chamber through convergent-divergent conduits 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 all these patent applications are incorporated herein by reference. Technical Field

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

[0003] Conventional crude oil-to-chemicals 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 via hydrotreating or hydrocracking, fluidized bed catalytic cracking, steam cracking, aromatics complexes, and / or naphtha reforming, to produce higher-value products of light olefins and aromatics. These processes typically produce significant amounts of C4 alkanes (e.g., n-butane and isobutane), liquefied petroleum gas (LPG) (e.g., a mixture of propane and butane), and some waste gases. To enhance profitability, crude oil-to-chemicals complexes produce additional chemicals, such as oxygenated compounds (e.g., methyl tert-butyl ether (MTBE) and butadiene). The value and profit margins of these products are subject to market fluctuations.

[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 a 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 resulting 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 naphtha and heavy naphtha. Light naphtha 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 recycled oil is sent to the catalytic cracker.

[0005] It can be seen that multiple processing units and steps are required to process various individual products to produce light olefins and aromatic compounds. In this disclosure, valuable light olefins and chemical intermediates are produced using crude oil to chemical complexes derived from C4 hydrocarbons, LPG, and exhaust gases, which have high carbon efficiency, low capital intensity, and simpler operating procedures. It also eliminates the need for hydrotreating or hydrocracking equipment, naphtha reformers, catalytic crackers, and other processing facilities. 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 to form a swirling combustion gas. A hydrocarbon reactant feed comprising (i) a stream of primary C4 hydrocarbons to be converted received from an upstream hydrocarbon processing system and (ii) liquid hydrocarbons to be converted is introduced into the feed assembly. The liquid hydrocarbons are introduced into the feed assembly as a liquid spray 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 is transferred from the feed assembly to the reaction chamber and reacted within 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] Liquid hydrocarbons can include those derived from upstream processes, and include crude oil, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, C60, etc. 20 To C40 Hydrocarbons, biomass-derived oils, pyrolysis oils from plastics, liquefied plastics, liquefied plastic waste containing impurities, and hydrocarbon liquids containing heteroatoms. Upstream hydrocarbon processing systems may include at least one of crude oil to chemical processing systems, crude oil refining systems, gas facilities, steam crackers, hydrocrackers, distillate hydrocrackers, and residue hydrocrackers. In some embodiments, liquid hydrocarbons may comprise 0.5% to 99% by weight of the hydrocarbon reactant feed. In other cases, liquid hydrocarbons may comprise 5% to 70% by weight of the total hydrocarbon reactant feed. The surface mean diameter (SMD) of the droplets in the liquid spray may be from 1 μm to 250 μm. The dynamic viscosity of the liquid hydrocarbons forming the liquid spray may be from 0.1 CP to 1000 CP. The liquid hydrocarbons may be crude oil that has not been pretreated or refined, except optionally with the removal of asphaltenes, resins, sulfur compounds, and / or trace metals.

[0008] The original C4 hydrocarbon stream may include at least one of butane, n-butane, isobutane, butene, 1-butene, 2-butene, cis-2-butene, trans-2-butene, 2-methylpropene, butadiene, 1-2-butadiene, 1-3-butadiene, butyne, 1-butyne and 2-butyne.

[0009] 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. At least a portion of any or more of the C2 to C6 alkanes, xylene, benzene, and toluene in the reactor product stream containing the converted hydrocarbon products may be separated from the reactor product stream to form a separated stream, at least a portion of which is recovered to form at least a portion of the hydrocarbon reactant feed. In some cases, at least a portion of any hydrogen (H2) in the reactor product stream containing the converted hydrocarbon products may be separated from the reactor product stream to form a separated hydrogen stream, at least a portion of which may be recovered to form at least a portion of the fuel gas feed.

[0010] In another approach, hydrocarbons are converted in an annular jet vortex reactor chamber (ANJEVOC) reactor system, which includes (i) a reactor vessel defining a reaction chamber, (ii) a smoothly curved convergent-divergent duct with a central axis at the inlet of the reaction chamber, and (iii) a feed assembly with a central chamber through which the central axis passes, the feed assembly being in fluid communication with the convergent-divergent duct. Fuel gas and oxidizer gas feeds are introduced into the central chamber of the feed assembly to create a swirling fluid flow pattern around the central axis. The fuel gas and oxidizer gas feeds are combusted in the central chamber to form swirling combustion gases. A hydrocarbon reactant feed comprising (i) a stream of primary C4 hydrocarbons to be converted received from an upstream hydrocarbon processing system and (ii) liquid hydrocarbons to be converted is introduced into the central chamber of the feed assembly. The liquid hydrocarbons are introduced into the central chamber as a liquid spray in a flow pattern not perpendicular to the central axis. Liquid hydrocarbons include crude oil, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, and C2C2. 20 To C 40 The hydrocarbon reactant feedstock may 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. Optionally, the hydrocarbon reactant feedstock may also include gaseous hydrocarbons, including vaporized C2O4. 10 To C 20 At least one of the hydrocarbons. The hydrocarbon reactant feed is mixed with swirling combustion gas to form a swirling heated mixture. The heated mixture enters the reaction chamber from the central chamber through a convergent-divergent conduit. 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. Attached Figure Description

[0011] 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 A 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 2In 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 This is a schematic diagram of a processing system and process flow utilizing a combination of upstream crude oil to a chemical complex and a reactor complex, according to various embodiments of this disclosure, wherein the reactor complex employs... Figure 2 A reactor used for converting raw C4 hydrocarbons and liquid crude oil; Figure 9 The adoption of various embodiments of this disclosure Figure 2 A schematic diagram of a reactor complex and process flow for converting crude C4 hydrocarbons and liquid crude oil. Figure 10 This is a schematic diagram of a processing system and process flow utilizing a combination of upstream crude oil to a chemical complex and a reactor complex, according to various embodiments of this disclosure, wherein the reactor complex employs... Figure 2 A reactor used to convert raw C4 hydrocarbons and liquid crude oil, wherein all raw C4 hydrocarbons are processed in the reactor system; Figure 11 This is a chart of selectivity, by weight percentage, for the conversion of light olefins and aromatics in a wide range of naphtha feedstocks at 20 wt% in the ANJEVOC reactor. Figure 12 This is a graph showing the conversion percentage and bulk gas temperature for 20% by weight liquid crude oil feed and a wide range of naphtha in the ANJEVOC reactor. Figure 13 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 14 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

[0012] In various embodiments of this disclosure, unique reactor technologies are used to convert primary C4 hydrocarbons from upstream hydrocarbon processing systems, such as crude oil to chemicals complexes, along with liquid hydrocarbons, such as liquid crude oil, into high-value chemicals, such as light olefins and aromatics. 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, the conversion can be completed in a single processing step, or with fewer or minimal processing steps and equipment. Liquid hydrocarbons may include crude oil, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, C4 hydrocarbons, and other hydrocarbons. 20 To C 40 Hydrocarbons, biomass-derived oils, pyrolysis oils from plastics, liquefied plastics, liquefied plastic waste containing impurities, and hydrocarbon liquids containing heteroatoms. Upstream hydrocarbon processing systems may include, but are not limited to, crude oil to chemical processing systems, crude oil refining systems, gas facilities, steam crackers, hydrocrackers, distillate hydrocrackers, and residue hydrocrackers.

[0013] More specifically, the conversion can be achieved using ANJEVOC (Annular Jet Vortex Chamber) reactor technology, which generates an annular swirling jet of feed gas, in which 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 useful, suitable, or similar range of quantities 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 40Hydrocarbons, 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 2 As 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 2 The 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 3As 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., at <5 degrees to the vertical around its circumference when it extends radially from the central axis).

[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 circumference 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., forming a <5 degree angle with the vertical around their circumference when extending radially from the central axis). Each of the partition walls 38, 40 has a central opening 42, 44, which is concentric with the convergent-divergent conduit 24 around the central axis 28. 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, it forms a <5-degree angle with the vertical around its circumference). In the illustrated embodiment, the annular flow channel 52 can constitute an oxygen or oxidizing gas flow channel to facilitate 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 individually introduced and delivered through flow channels 46, 48, 52, and 54 in a swirling fluid flow pattern around the central axis 28 into the central chamber 58 of the feed assembly 32, 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, the various feeds can be reversed or changed in a different order 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, the walls 34, 36, 38, 40, and 50, forming different flow channels 46, 48, 52, and 54, are parallel to each other in many cases. 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 reactor 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 3 In 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 patterns near the manifold inlet. In other reactor systems, they may be arranged in annular patterns at other locations radially inward or further within the 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. When employing 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 liquid 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 where 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 nozzle 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 would otherwise lead to coking. In certain embodiments, the spray pattern may have a spray angle of 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 may 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 may 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 pyrolysis 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... 32The size is defined as the ratio of droplet volume to droplet surface area in the spray. Droplet measurements can be determined using phase Doppler interferometry (PDI) technology. In a particular embodiment, the spray nozzle at the liquid feed inlet 76 can provide a liquid hydrocarbon feed with an SMD size at least equal to and / or between any two of the following: 1 μm, 2 μm, 3 μm, 4 μm, 5 μm, 6 μm, 7 μm, 8 μm, 9 μm, 10 μm, 11 μm, 12 μm, 13 μm, 14 μm, 15 μm, 16 μm, 17 μm, 18 μm, 19 μm, 20 μm, 21 μm, 22 μm, 23 μm, 24 μm, 25 μm, 26 μm, 27 μm, 28 μm. 29μm, 30μm, 30μm, 31μm, 32μm, 33μm, 34μm, 35μm, 36μm, 37μm, 38μm, 39μm, 40μm, 41μm, 42μm, 43μm, 44μm, 4 5μm, 46μm, 47μm, 48μm, 49μm, 50μm, 55μm, 60μm, 65μm, 70μm, 75μm, 80μm, 85μm, 90μm, 95μm, 100μm, 105μm, 1 10μm, 115μm, 120μm, 125μm, 130μm, 135μm, 140μm, 145μm, 150μm, 155μm, 160μm, 165μm, 170μm, 175μm, 180 μm, 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 6 The graph shows the vaporization time as a function of droplet size in the reactor under simplified calculations under approximate conditions. Figure 7 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 the droplet, which is 50% of the total droplet volume 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.l It was found that 10% of the total droplet volume was less than its diameter. In some implementations, the spray's Dv 0.lIt 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 micrometers 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 0.9It can be at least, equal to, and / or between any two of the following: 20 μm, 21 μm, 22 μm, 23 μm, 24 μm, 25 μm, 26 μm, 27 μm, 28 μm, 29 μm, 30 μm, 30 μm, 31 μm, 32 μm, 33 μm, 34 μm, 35 μm, 36 μm, 37 μm, 38 μm, 39 μm, 40 μm, 41 μm, 42 μm, 43 μm, 44 μm, 45 μm, 46 μm, 47 μm, 48 μm, 49 μm, 50 μm, 55 μm, 60 μm, 65 μm, 70 μm, 75 μm, 80 μm, 85 μm, 90 μm, 95 μm, 100 μm, 105 μm, 110 μm, 115 μm, 120 μm, 125 μm, 130 μm, 135 μm, 140 μm, 145 μm, 150 μm, 155 μm, 160 μm, 165 μm, 170 μm, 175 μm, 180 μm, 185 μm, 190 μm, 195 μm, 200 μm, 205 μm, 210 μm, 215 μm, 220 μm, 225 μm, 230 μm, 235 μm, 240 μm, 245 μm, 250 μm, 255 μm, 260 μm, 265 μm, 270 μm, 275 μm, 280 μm, 285 μm, 290 μm, 295 μm, 300 μm, 305 μm, 310 μm, 315 μm, 320 μm, 325 μm, 330 μm, 335 μm, 340 μm, 345 μm, 350 μm, 355 μm, 360 μm, 365 μm, 370 μm, 375 μm, 380 μm, 385 μm, 390 μm, 395 μm, 400 μm, 405 μm, 410 μm, 415 μm, 420 μm, 425 μm, 430 μm, 435 μm, 440 μm, 445 μm, and 450 μm. In a specific embodiment, the spray nozzle is configured to form Dv 0.9 droplets of 20 micrometers to 100 micrometers.

[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 the spray nozzle is equal to the pressure drop across the nozzle multiplied by the flow velocity. To achieve the desired droplet size distribution, the choice between a single-phase or two-phase nozzle depends on the nozzle's pressure drop. The choice also depends on various requirements (e.g., (i) spray angle, (ii) hollow vs. full spray cone, and (iii) internal and external mixing to address fouling, which can be achieved using a two-phase nozzle). Furthermore, for current applications involving hydrocarbons, the choice of spray nozzle may depend on high-temperature operability, coking and fouling characteristics, erosion, the ability to detect and remove the nozzle's narrow opening, etc. 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] Biomass-derived oils may include uneaten edible oil (UCO), palm fatty acid distillate (PFAD), uneaten vegetable oil (UVO), hydrogenated vegetable oil (HVO), tall oil, and other biomass-derived oils.

[0065] 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, liquid hydrocarbons 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, liquid hydrocarbons can be untreated crude oil that has not been pretreated or refined to remove any materials.

[0066] The liquid hydrocarbons converted by reactor system 10 will typically account for 0.5% to 99% 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, 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 and 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 and 99% by weight.

[0067] In many applications, liquid hydrocarbons will be converted together with gaseous hydrocarbons in reactor system 10. As used herein, “gaseous hydrocarbons” or similar expressions are 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 would be 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 streams, primary C4 hydrocarbon streams, and gaseous C1 to C2 hydrocarbons. 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, proto-C4 hydrocarbon streams comprise hydrocarbons having four carbon atoms (C4 material) or mixtures of C4 material, including olefinic C4 material such as butadiene, butene, isobutene, etc., such as those C4 olefins produced during steam cracking operations. By way of example, a typical proto-C4 hydrocarbon stream may contain 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.

[0068] In certain applications, gaseous hydrocarbons are primary C4 hydrocarbon streams delivered from upstream crude oil processing systems and other hydrocarbon processing systems. Primary C4 hydrocarbons may include butane, n-butane, isobutane, butene, 1-butene, 2-butene, cis-2-butene, trans-2-butene, 2-methylpropene, butadiene, 1-2-butadiene, 1-3-butadiene, butyne, 1-butyne, and 2-butyne, as well as mixtures and combinations thereof. Upstream hydrocarbon processing systems delivering primary C4 hydrocarbons may include one or more of crude oil to chemical processing systems, crude oil refining systems, gas facilities, steam crackers, hydrocrackers, distillate hydrocrackers, and residue hydrocrackers. These upstream processing systems may also provide other liquid and / or gaseous non-C4 hydrocarbons, which may be processed together with the primary C4 hydrocarbons in reactor 10.

[0069] 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.

[0070] 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.

[0071] 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.

[0072] 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.

[0073] 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.

[0074] 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.

[0075] 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.

[0076] 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).

[0077] 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.

[0078] 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).

[0079] 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.

[0080] 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.

[0081] 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.

[0082] 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.

[0083] In some implementations, multiple reactor inlet assemblies and corresponding feed assemblies can be set in a single reactor while maintaining high performance.

[0084] The reactor system 10 described herein can be used to convert gaseous and liquid hydrocarbons, such as crude oil, to produce higher-value products, such as light olefins and aromatics. In addition to gaseous hydrocarbons such as proto-C4 hydrocarbons, liquid crude oil and other liquid hydrocarbons can be directly introduced into reactor system 10 to increase olefin yields and reduce capacity requirements for crude oil to chemical complexes or other processing systems. Pretreatment of the introduced liquid crude oil, such as hydrotreating, hydroprocessing, or aromatics removal, as occurs in conventional crude oil processing, is unnecessary. Preheating of crude oil or other liquid hydrocarbons is not required. This system is characterized by high feed conversion and higher selectivity for olefins and aromatics in a single step. This results in the elimination of multiple unit operations and feedstocks that would otherwise be required in conventional crude oil to chemical processing systems. Due to the short residence time, the olefin, unsaturated, and / or aromatic content in the feedstock will not hinder cracking or conversion, nor will it produce excessive coking behavior during the reaction, as these will simply pass through the reactor unchanged.

[0085] Reactor system 10, using liquid and gaseous hydrocarbon feedstocks such as primary C4 hydrocarbons received from upstream hydrocarbon processing systems, can be used to provide a variety of higher-value products. These include any or 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 or 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 feedstock. The ANJEVOC reactor can crack a wide range of hydrocarbons, with a very narrow product composition, primarily forming C2+C3 products, with a certain amount of carbon lost as CO and CO2.

[0086] refer to Figure 8 This diagram illustrates a hydrocarbon processing system 90 and process flow for converting liquid crude oil using reactor 10 within a reactor complex. System 90 shown is a crude oil-to-chemicals conversion system. This crude oil-to-chemicals conversion system is merely one example of a conversion system that can be used in conjunction with reactor 10 to convert both liquid and gaseous hydrocarbons. Other upstream processing systems include crude oil refining systems, gas facilities, steam crackers, hydrocrackers, distillate hydrocrackers, and residue hydrocrackers.

[0087] The crude oil 92 used as the liquid hydrocarbon feed can be any crude oil typically extracted from underground formations. In system 90, crude oil 92 is introduced into distillation unit 94, which may include a combination of an atmospheric crude oil distillation unit (CDU) and a vacuum distillation unit (VDU) 94, wherein the bottom residue of the CDU is processed by the VDU. In the illustrated embodiment, the product from distillation unit 94 is the product obtained by CDU distillation and VDU distillation of the CDU bottoms. The overhead product 96 of distillation unit 94 is liquefied petroleum gas (LPG) typically containing C2 to C4 hydrocarbons and is delivered to gas facility 98 for separating the original C4 hydrocarbons from the C2 and C3 hydrocarbons, which are respectively distributed as product streams 100 and 102.

[0088] The VDU bottoms or vacuum residue 104 from distillation unit 94 may have a typical API specific gravity of about 5, an average molecular weight of about 800, and a typical distillation fraction of 540–980 °C according to ASTM D1160. The VDU bottoms or vacuum residue 104 may be introduced into the residue hydrocracker 106. Gas oil from unit 94 (e.g., heavy, medium, and light vacuum gas oils with typical distillation fractions according to ASTM D1160, 440–590 °C, 360–520 °C, and 270–340 °C, respectively) hydrocarbon fractions 108 (typical API specific gravity of about 17–32 and average molecular weight of 250–550) may be delivered to the distillate hydrocracker 110. The naphtha fraction 112 from distillation unit 94 (typically with an API specific gravity of about 60 and an average molecular weight of 110, having typical distillation fraction ASTM D86 40-205°C) can be delivered to steam pyrolyzer 114.

[0089] Gas oil 108 from distillation unit 94 is cracked in distillate hydrocracker 110 to form LPG overhead 116, middle fraction 118, and bottom fraction 120. Middle fraction 118 consists primarily of naphtha composition. Bottom fraction 120 consists primarily of hydrocarbons in the diesel range (typical API specific gravity of about 40-50, average molecular weight of 170 to 230, and typical distillate ASTM D86 200-380°C). LPG fraction 116 may be combined with C2 and C3 hydrocarbons from gas facility 98 and fed to steam cracker 114. Alternatively, LPG fraction 116 may be fed to gas facility 98 for C4 hydrocarbon removal. Middle fraction 118 is fed to stream cracker 114, and bottom fraction 120 is fed to residue hydrocracker 106 or diesel pool.

[0090] Vacuum residue 104, together with bottoms 120 from distillate cracker 110, is cracked in residue hydrocracker 106 for further cracking and to form various hydrocarbon fractions. LPG 122 from residue hydrocracker 106 can be fed to gas facility 98. Kerosene-range hydrocarbon fraction 124 can be combined with gas oil 108 and / or delivered to distillate hydrocracker 110 for further cracking. Heavy naphtha fraction 126 from residue hydrocracker 106 can be delivered to steam cracker 114 together with middle fraction 118 from distillate hydrocracker 110. Bituminous or residue hydrocracker bottoms are removed from residue hydrocracker 106 as stream 128.

[0091] like Figure 8 As shown, in gas facility 98, the original C4 hydrocarbon 100 is separated from the C2 and C3 hydrocarbons and delivered to reactor complex 130. See later. Figure 9 A more comprehensive description of an example of reactor complex 130 is provided. Reactor complex 130 utilizes a reactor, such as reactor 10 previously described, which can be configured as an ANJEVOC reactor. Proto-C4 hydrocarbons are introduced into reactor complex 130 as a gaseous feed. Proto-C4 feed recovered from the C4 and aromatic compound complex is not an ideal feed for conventional steam crackers. Conventionally, they are first hydrogenated in a total hydrogenation unit and then sent to a steam cracker. Most of these streams contain significant amounts of isobutane, which is not a desirable feed for steam crackers. The ANJEVOC reactor can efficiently crack these mixtures of n-butane and isobutane without significant coking, thereby effectively improving cracking efficiency and reducing the coking tendency of the entire complex. This, in turn, provides the complex with a high uptime.

[0092] Liquid crude oil 132, typically processed in a crude oil-to-chemicals complex, can be directly introduced and processed in reactor complex 130 without any pretreatment or distillation. The only possible processing of crude oil 132 may be initial flash evaporation or crude oil distillation in a flash tank or unit (not shown) to remove asphaltenes and / or resins. Reactor 10 of reactor complex 130 directly injects liquid crude oil 132. Figure 2 The axial liquid inlet 76 contains other liquid hydrocarbons such as gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, and one or more C44 hydrocarbons. 20 To C 40 Hydrocarbons, biomass-derived oils, pyrolysis oils from plastics, liquefied plastics, liquefied plastic waste containing impurities, and hydrocarbon liquids containing heteroatoms can also be used with or in place of liquid crude oil, and processed together with the original C4 hydrocarbon gas feed in reactor complex 130.

[0093] The original C4 hydrocarbon stream 100 can be combined with liquid crude oil 132 and / or other liquid hydrocarbons as an axial gas inlet 76 through reactor 10. Figure 2 The combined hydrocarbon gas / liquid reactant feed is introduced. In other embodiments, the original C4 hydrocarbon stream 100 may be introduced separately from the liquid crude oil 132, such as through an axial inlet 76 or through an annular flow channel, such as the upstream annular flow channel 46 of the feed assembly 32. If introduced through the axial inlet 76, the original C4 hydrocarbon stream 100 may also be introduced together with the liquid crude oil through a spray nozzle 78, wherein the nozzle 78 constitutes a two-fluid nozzle.

[0094] Oxygen and hydrogen fuel feedstocks 134 and 136 are introduced into the reactor of reactor complex 130 to form swirling heated combustion gases, providing the elevated reaction temperature required for conversion. Steam may also be introduced into the reactor of reactor complex 130 along with or as its own feed stream 138, as previously described.

[0095] C2 and C3 from gas facility 98, LPG 116 from distillate hydrocracker 110, and feeds 112, 118, and 126 can be introduced into steam cracker 114 to produce various olefins and aromatic compounds. Ethylene 140 and propylene 142 products are removed from cracker 114 and collected for further processing, use, or storage. Pyrolysis oil 210 removed from the steam cracker can be recovered and delivered as feed 146 to distillate hydrocracker 110.

[0096] exist Figure 8 In one embodiment, the original C4 hydrocarbons 148 from the steam cracker 114 can be delivered to the butadiene extraction unit 150. The 1,3-butadiene produced in unit 150 is removed as stream 152 for further processing, storage, or use. The remaining C4 hydrocarbons are delivered to the MTBE unit 154, where methanol 156 reacts with isobutylene to form methyl tert-butyl ether (MTBE) 158. The MTBE 158 from the MTBE unit 154 is recycled for further processing, use, or storage.

[0097] The remaining C4 hydrocarbons from MTBE unit 154 are fed into slurry hydrogenation (selective hydrogenation) unit 162 to form 1-butene, which is then removed as stream 164 for further processing, use, or storage. In some embodiments, the remaining C4 hydrocarbons 166 from unit 162 are delivered to C4 hydrogenation unit 168, where the C4 hydrocarbons are further hydrogenated. All or part of the hydrogenated C4 hydrocarbons 170 from hydrogenation unit 168 can be recovered and combined with the original C4 hydrocarbon stream 100 from gas facility 98 to be fed into reactor complex 130 as hydrocarbon reactant feed.

[0098] Aromatic compounds and pyrolysis gasoline (cracked gasoline) 172 produced in steam cracker 114 can be fed to depentane hydrotreating gasoline unit 174. C5 hydrocarbons removed from unit 174 can be combined with feeds 118 and 126 and recycled back to steam cracker 114. C5 hydrocarbons from unit 174... 10 +Hydrocarbon 178 can be recycled to distillate hydrocracking unit 110. C6 to C9 hydrocarbons 180 from unit 174 are fed to C7+ hydrocarbon extraction unit, where the C7+ and gaseous mixed stream is removed for further processing, use or storage.

[0099] C6 hydrocarbons from extraction unit 182 are fed into benzene extraction unit 188. Benzene 190 is recovered for further processing, use, or storage, while the remaining C6 hydrocarbons 192 can be recovered and fed into steam cracker 114.

[0100] refer to Figure 9 It shows more details Figure 8 A schematic diagram of reactor complex 130 and its process flow for converting crude C4 hydrocarbons and liquid crude oil is provided. Other hydrocarbons (gaseous and liquid) can also be converted in reactor complex 130 along with C4 hydrocarbons and liquid crude oil. Reactor complex 130 includes reactor 10 ( Figure 2 (This can be an ANJEVOC reactor, as previously described.)

[0101] From liquid crude oil 92 ( Figure 8 The crude oil 132 delivered to reactor 10 of reactor complex 130 is used as a liquid hydrocarbon feed. The raw C4 hydrocarbon gas feed 100 from gas facility 98 can be combined with the liquid crude oil 132 as a combined hydrocarbon gas / liquid reactant feed introduced through axial inlet 76 of reactor 10. In other embodiments, the C4 hydrocarbon gas feed 100 can be introduced separately from the liquid crude oil 132, such as through axial inlet 76 or through an annular flow channel, such as the upstream annular flow channel 46 of feed assembly 32. If introduced through axial inlet 76, the C4 gas feed 100 can also be introduced together with the liquid crude oil through a spray nozzle 78, wherein nozzle 78 constitutes a two-fluid nozzle.

[0102] Oxygen and hydrogen fuel feedstocks 194 and 196 are introduced into reactor 10 to form swirling heated combustion gases, providing the elevated reaction temperature required for the conversion. Steam 198 may also be introduced into reactor 10 along with various feedstocks or as its own feed stream, as previously described.

[0103] As already described, the liquid crude oil introduced as a fine spray as reactant feed 132 is immediately vaporized and mixed with the swirling hot combustion gas. The hydrocarbon reactant feed, consisting of crude oil and raw C4 gas from gas facility 98, is mixed with the swirling hot combustion gas to form a swirling heated mixture, which is emitted from central chamber 58 ( Figure 2 The 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.

[0104] The conversion products 200 are typically hydrogen, steam, 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.

[0105] Unpyrolyzed asphaltenes and resins can be removed from ANJEVOC reactor 10 as stream 200. The asphaltenes and resins are knocked out by water quenching and condensed together with the water. In other embodiments, crude oil 132 may pass through a preliminary flash tank or other separation unit (not shown) to remove asphaltenes and / or resins from the liquid crude oil before it is introduced into reactor 10 of complex 130.

[0106] Water 204 from quench water and / or condensate steam is separated from the converted hydrocarbon products 200 to form a separated conversion product 206. The conversion product 206 can then be introduced into a fractionator 208, where the product is fractionated to remove fuel oil 210. The fuel oil 210 can be further processed in an aromatic compound complex 212 to produce benzene, toluene, and xylene products 214 for further use, processing, or storage. In some embodiments, the benzene, toluene, and xylene products 214 can be delivered as a recovery stream (not shown) for recycling back to reactor 10.

[0107] The remaining gaseous fraction 216 from fractionator 208 can be pressurized in compressor 218 and delivered to amine treatment unit 220 for removal or washing of CO2 and / or H2S from the converted hydrocarbon products.

[0108] The washed hydrocarbon product 222 from the amine treatment unit 220 is further pressurized in compressor 224, and the product is first delivered to high-pressure depropanizer 226. l -C2 hydrocarbons are removed as overhead stream 228 from the high-pressure propane stripper 226. Bottom stream 230 from the high-pressure propane stripper 226 contains C3 or higher hydrocarbons.

[0109] C l-C2 overhead 228 is fed to acetylene converter unit 232, where acetylene in stream 228 is hydrogenated to form ethylene and / or ethane. Hydrogenation product 234 from acetylene converter 232 is fed to a cold box or other heat exchanger 236 for cooling the hydrocarbon product 234. The cooled product 238 is then fed to hydrogen separator 240, where hydrogen is removed and delivered as hydrogen recoverable 242, which can be combined with fresh hydrogen 244 to form hydrogen feed 136 for use as fuel in reactor 10.

[0110] A separated, hydrogen-free product 246, consisting of methane, ethane, and ethylene, is fed to a demethanizer 248, where overhead methane and carbon oxides (i.e., CO, CO2) are removed via membrane separation as stream 252. The carbon oxides from stream 252 can be hydrogenated in converter unit 254. The resulting methane stream 256 can then be recovered as methane fuel, such as for boilers or other applications.

[0111] Demethanizing product 258 can be further processed in deethanizer 264. The C2 compounds of ethane and ethylene from deethanizer 264 are removed as stream 262. This can be delivered to C2 splitter 264 as ethane product stream 266 and ethylene product stream 268, respectively, for further processing, use, or storage. In some cases, all or part of ethane 266 can be recovered as part of recovery stream 270, which is recycled back to reactor 10 to form part of the gaseous hydrocarbon reaction feed.

[0112] Bottom product 230 containing C3 or higher hydrocarbons from high-pressure depropanizer 226 is fed to low-pressure depropanizer 274. C3 product stream 276 is removed from low-pressure depropanizer 274 as overhead. C3 product stream 276 is further processed in MAPD converter 278, where methylacetylene and propadiene are hydrogenated to form propane and / or propylene. The combined propane and propylene products 280 from MAPD converter 278 can be separated into propane product stream 284 and propylene product stream 286, respectively, in C3 splitter 282 for further processing, use, or storage. All or part of propane 284 can be recovered as part of recovery stream 270.

[0113] The bottoms 288 from the low-pressure propane stripper 274, containing C4 or higher hydrocarbons, are fed to the butane stripper 290 for removal of C4 hydrocarbons as product stream 292. Butane from the C4 product stream 292 can be separated from unsaturated C4 isomers in the C4 splitter 294 to form butane product stream 296 and unsaturated C4 isomer product stream 298, respectively, for further processing, use, or storage. All or part of the butane product stream 296 can be recovered as part of the recovery stream 270.

[0114] The butane product 300 from the butane de-butane tower 290 consists primarily of aromatic compounds or pyrolytic gasoline (i.e., cracked gasoline), which can be delivered to the aromatic compound complex 212 to form benzene, toluene, and xylene products 214. Heavy oil, unreacted sulfur, and heavy metal compounds can be removed from the aromatic compound complex 212 as stream 302.

[0115] exist Figure 9 In an alternative configuration of reactor complex 130, demethanization of the washed hydrocarbon product 222 from amine unit 220 can occur at the front end, and depropanization occurs downstream. This configuration is described in a co-filed and co-pending application entitled “Method of Converting Liquid Hydrocarbons to Higher Value Chemicals”, identified by Agent’s File No. SABI-31840 (22T&I0045), the entire contents of which are incorporated herein by reference for all purposes, including descriptions of various hydrocarbon processing systems.

[0116] Figure 10 A schematic diagram of another hydrocarbon processing system 310 and process flow is shown, employing a combination of reactor complex 130 and a crude oil-to-chemicals conversion system for the conversion of liquid crude oil. System 310 is similar to that previously described. Figure 8 System 90, in which similar components are labeled with the same reference numerals. System 310 differs from System 90 in that: the primary C4 hydrocarbons from steam cracker 114 are combined with the primary C4 hydrocarbon feed 100 from gas facility 98 to form part of the gaseous hydrocarbon reactant feed of reactor complex 130.

[0117] The following examples are provided to further illustrate various implementation schemes and applications. Example

[0118] 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 11 to 14 Different data points on the x-axis. Example 1

[0119] Experiments were conducted using 20 wt% liquid and gaseous hydrocarbons to simulate the conversion of proto-C4 hydrocarbons, such as those that can be produced in crude oil-to-chemicals complexes or other upstream hydrocarbon processing systems. Liquids included distilled Arabian Light (AL) crude oil (with approximately 35 wt%–40 wt% heavy crude removed) and a broad range of naphtha (WRN). Each of the AL and WRN liquid feedstocks (in…) Figure 11The 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 spray'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.

[0120] Figure 11 The selectivity, by weight percentage, for approximately 20% by weight distilled Arab Light crude oil and a broad range of naphtha with butane, light olefins, and aromatics in Example 1 is shown. Selectivity for olefins and aromatics (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.

[0121] Figure 12 The 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 12 The bulk gas temperature shown is represented by measurements indicated by circular data points closer to the reactor's central axis. Example 2

[0122] Figure 13The selectivity, by weight percentage, for approximately 40 wt% Khuff Gas Condensate (KGC) crude oil with butane, light olefins, and aromatics is shown in ANJEVOC reactor 10. 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. Selectivity by weight percentage for olefins and aromatics (high-value chemicals) varies from 60% to 67%, while selectivity by weight percentage 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

[0123] Figure 14 The selectivity, by weight percentage, for approximately 40 wt% Arab Ultra Light (AXL) crude oil with butane, light olefins, and aromatics is shown in ANJEVOC reactor 10. 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 SMD size of the spray 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.

[0124] 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.

[0125] 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 feed and oxidant gas feed are introduced into the feed assembly to reach the central axis to generate a swirling fluid flow pattern around the central axis of the reactor system; The fuel gas feed and oxidant gas feed are used to form a swirling combustion gas; Multiple hydrocarbon reactant feeds are introduced into the feed assembly, the multiple hydrocarbon reactant feeds including i) The original C4 hydrocarbon stream to be converted, and ii) Liquid hydrocarbon to be converted, wherein the liquid hydrocarbon is introduced into the feed assembly as a liquid droplet spray, wherein the spray is in a flow pattern not perpendicular to the central axis; The plurality of hydrocarbon reactant feeds are mixed with the swirling combustion gas to form a swirling heated mixture in the feed assembly; 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 with the plurality of 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 99% by weight of the hydrocarbon reactant feed.

4. The method according to any one of claims 1 to 2, wherein the liquid hydrocarbon accounts for 5% to 70% by weight of the hydrocarbon reactant feed.

5. The method according to any one of claims 1 to 4, wherein the droplets in the liquid spray have a Sotter mean diameter (SMD) of 1 μm to 250 μm.

6. The method according to any one of claims 1 to 5, wherein the liquid hydrocarbon has a dynamic viscosity of 0.1 cP to 1000 cP at the temperature at which the liquid hydrocarbon is introduced into the feed assembly.

7. The method according to any one of claims 1 to 6, wherein the original C4 hydrocarbon stream comprises at least one of butane, n-butane, isobutane, butene, 1-butene, 2-butene, cis-2-butene, trans-2-butene, 2-methylpropene, butadiene, 1-2-butadiene, 1-3-butadiene, butyne, 1-butyne, and 2-butyne.

8. The method according to any one of claims 1 to 7, the method further comprising receiving the crude C4 hydrocarbon stream from an upstream hydrocarbon processing system, and optionally wherein the upstream hydrocarbon processing system comprises at least one of a crude oil to chemical processing system, a crude oil refining system, a gas facility, a steam cracker, a hydrocracker, a distillate hydrocracker, and a residue hydrocracker.

9. The method according to any one of claims 1 to 8, 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.

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

11. The method according to any one of claims 1 to 10, wherein: 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.

12. The method according to any one of claims 1 to 11, 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.

13. The method according to any one of claims 1 to 12, wherein at least one of the gaseous hydrocarbon and the liquid hydrocarbon is mixed with steam.

14. The method according to any one of claims 1 to 13, wherein the reactor system is an annular jet vortex reactor chamber (ANJEVOC) reactor system.

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

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

17. The method of claim 15, wherein the plurality of hydrocarbon reactant feeds further comprises a gaseous hydrocarbon feed, and wherein the second fluid is the gaseous hydrocarbon.

18. A method for converting hydrocarbons in an annular jet vortex reactor chamber (ANJEVOC) 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 the 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 reach the central axis, thereby generating 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; Multiple hydrocarbon reactant feeds are introduced into the central chamber, the multiple hydrocarbon feeds including i) The original C4 hydrocarbon stream to be converted, and ii) the liquid hydrocarbon to be converted, wherein the liquid hydrocarbon is introduced into the central chamber as a liquid spray in a flow pattern not perpendicular to the central axis; and iii) Gaseous hydrocarbons, said gaseous hydrocarbons comprising C 10 hydrocarbons to C 20 At least one of the hydrocarbons; The plurality of hydrocarbon reactant feeds are mixed with the swirling combustion gas to form a swirling heated mixture in the central chamber; The heated mixture is directed from the central chamber through the convergent-divergent conduit and into the reaction chamber; The heated mixture is reacted in the reaction chamber under reaction conditions suitable for converting the hydrocarbon feedstock into the converted hydrocarbon product; and The converted hydrocarbon product is removed from the reaction chamber.

19. The method of claim 18, wherein the original C4 hydrocarbon stream comprises at least one of butane, n-butane, isobutane, butene, 1-butene, 2-butene, cis-2-butene, trans-2-butene, 2-methylpropene, butadiene, 1-2-butadiene, 1-3-butadiene, butyne, 1-butyne, and 2-butyne.

20. The method according to any one of claims 18 to 19, wherein the liquid hydrocarbon comprises crude oil, gas oil, kerosene, diesel oil, naphtha, heavy naphtha, light naphtha, C 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.

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