Reactor and method for converting liquid hydrocarbons to higher value chemicals

Abstract

A method and reactor for converting hydrocarbons uses a reactor having an inlet configured as a converging-diverging conduit having a central axis. A feed assembly of the reactor has a central chamber in fluid communication with the converging-diverging conduit. The feed assembly has annular flow passages for introducing a fuel gas feed and an oxidizer gas feed into the central chamber in a swirling fluid flow pattern that combust to form swirling hot combustion gases. A liquid hydrocarbon feed having dynamic viscosity from 0.1 cP to 1000 cP is introduced as a liquid spray having a Sauter Mean Diameter (SMD) of droplets from 1 μm to 250 μm into the central chamber. The hydrocarbon feed mixes with the swirling hot combustion gases to form a swirling, heated mixture that passes from the central chamber through the converging-diverging conduit and into the reaction chamber to react to form converted hydrocarbon products.

Description

REACTOR AND METHOD FOR CONVERTING LIQUID HYDROCARBONS TO HIGHER VALUE CHEMICALSCROSS-REFERENCE TO RELATED APPLICATIONSThis application claims the priorities of:European patent application no. 23187528.7, filed 25 July 2023, European patent application no. 23187529.5, filed 25 July 2023, European patent application no. 23187530.3, filed 25 July 2023, European patent application no. 23196604.5, filed 11 September 2023, India patent application no. 202341050195, filed 25 July 2023, the contents of all of which are incorporated herein by reference.TECHNICAL FIELD

[0001] The present disclosure is directed to the production of high value chemical products from liquid hydrocarbons, such as crude oil and the like.BACKGROUND

[0002] Conventional crude-to-chemicals industrial complexes use crude distillation to produce various fractions, such as light hydrocarbons (e.g., C1-C4), naphtha, kerosene, diesel, gasoil, and residue. Each of these streams can be processed separately, such as via hydrotreating or hydrocracking, fluid catalytic cracking, steam cracking, aromatic complexing, and / or naphtha reforming to produce light olefins and aromatics. These process methods often result in (i) low carbon and energy efficiency, (ii) high operational and overall capital costs, and (iii) operational complexity. In variations of these processes, the crude oil can be flashed to remove the light hydrocarbon fractions as liquid, which can then be vaporized and fed to a steam cracker. The heavy or bottoms from the crude flash vessel are sent to conventional refinery processing.

[0003] FIG. 1 shows a schematic of an example conventional crude-to-chemicals system and process flow for such system. As shown, the system comprises a crude distillation unit, where crude oil is fractionated to atmospheric residue and naphtha, along with kerosene and diesel cuts. The naphtha cut is optionally hydrotreated and split to light and heavy naphtha. Heavy naphtha is reformed in a naphtha reformer, whereas light naphtha fraction is sent to a steam cracker. The naphtha reformate is a feedstock to the aromatics complex, which produces p-xylene and benzene. The Cs+ and pyrolysis gasoline (i.e., pygas) from the steam cracker is also fed to the aromatics complex to produce p-xylene and benzene. The atmospheric residue is vacuum distilled to produce light and heavy vacuum gas oils. The produced vacuum gas oils are hydrocracked, whereas residue from the vacuum distillation undergoes hydrocracking and made to diesel range cut, which then is hydrocracked again to produce light and heavy naphtha. The light and heavy naphtha are processed as mentioned before. Gas oils can optionally be fed to fluid catalytic cracking (FCC) unit. The light alkenes are separated from aromatic middle distillates. The light cycle oil, which is usually difficult for the hydroprocessing units to process, is sent to the catalytic crackers.

[0004] As can be seen, conventional crude-to-chemicals systems and processes are not able to process crude without significant preprocessing in multiple unit operations, nor are such systems able to convert significant percentages of crude oil to higher value chemicals. The present disclosure addresses the above issues.SUMMARY

[0005] A method of converting hydrocarbons is carried out in a reactor system comprising a central axis, a feed assembly, and a reactor vessel that defines a reaction chamber. A fuel gas feed and an oxidizer gas feed are introduced into the feed assembly to produce a swirling fluid flow pattern about the central axis. The fuel gas feed and oxidizer gas feed are combusted in the feed assembly to form swirling combustion gases. A hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted is introduced into the feed assembly. The liquid hydrocarbon has a dynamic viscosity from 0.1 cP to 1000 cP and is introduced as a liquid spray having a Sauter Mean Diameter (SMD) of droplets from 1 pm to 250 pm into the feed assembly in a flow pattern that is non-perpendicular to the central axis. The hydrocarbon reactant feed is mixed with the swirling combustion gases to form a swirling, heated mixture. The heated mixture from the feed assembly is passed into the reaction chamber. The heated mixture is reacted within the reaction chamber under reaction conditions suitable to convert the hydrocarbons of the hydrocarbon reactant feed into a converted hydrocarbon product. The converted hydrocarbon product is removed from the reaction chamber.

[0006] In particular embodiments, the liquid hydrocarbon may include at least one of crude oil, gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, a C20 to C40 hydrocarbon, a biomass-derived oil, a pyoil from plastic, a liquified plastic, a liquified plastic waste with impurities, and a heteroatom-containing hydrocarbon liquid. The liquid hydrocarbon maymake up from 0.5 wt% to 100 wt% of the hydrocarbon reactant feeds. The liquid hydrocarbon may include a crude oil that has not been pretreated or refined other than to optionally remove at least one of asphaltene, resin, sulfur compounds, and trace metals.

[0007] In certain applications, the hydrocarbon reactant feed may further comprise a gaseous hydrocarbon. The gaseous hydrocarbon may be at least one of a natural gas liquid and a Ci to C20 hydrocarbon. The hydrocarbon reactant feed of at least one of the gaseous hydrocarbon and liquid hydrocarbon may be mixed with steam in some cases.

[0008] In some embodiments, the converted hydrocarbon product may include at least one of an olefin, a C2 to Ce olefin, ethylene, a propylene, a butene, acetylene, a C3 to Ce alkyne, a butadiene, an aromatic compound, a xylene, benzene, toluene, and ethyl benzene. In certain instances, a portion of any one or more of a C2 to Ce alkane, a xylene, benzene, and toluene in the reactor product stream may be separated from a reactor product stream containing the converted hydrocarbon product and recycled to form at least a portion of the hydrocarbon reactant feeds. Hydrogen gas (H2) in the reactor product stream may also be separated from the reactor product stream and recycled to form at least a portion of the fuel gas feed.

[0009] A reactor system for converting hydrocarbons is also provided and includes a reactor vessel that defines a reaction chamber. An inlet of the reaction chamber is configured as a smoothly-curved, converging-diverging conduit having a central axis that extends along upstream and downstream ends of the converging-diverging conduit, wherein upstream and downstream refers to the relative position with respect to the direction of overall fluid flow through the reactor system. A feed assembly having a central chamber through which the central axis passes that is in fluid communication with the converging-diverging conduit. The feed assembly has flow passages configured to introduce a fuel gas feed and an oxidizer gas feed into the central chamber of the feed assembly in a swirling fluid flow pattern about the central axis that combust in the central chamber to form swirling hot combustion gases. The reactor system also includes at least one spray nozzle at an upstream end of the feed assembly configured to introduce a hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted into the central chamber of the feed assembly. The at least one spray nozzle at is oriented and configured for introducing the liquid hydrocarbon as a liquid spray into the central chamber in a flow pattern that is non-perpendicular to the central axis. The introduced liquid hydrocarbon mixes with the swirling hot combustion gases within the central chamber to form a swirling, heated mixture that passes from the central chamber through the convergingdiverging conduit and into the reaction chamber where the liquid hydrocarbon is converted intoa converted hydrocarbon product. The reaction chamber has an outlet for removing the converted hydrocarbon product from the reaction chamber.

[0010] The reactor system may be an annular jet vortex reactor chamber (ANJEVOC) reactor system. In certain embodiments, the spray nozzle may be a two-fluid spray nozzle. The spray nozzle may provide a spray pattern with a spray angle of 40° or less. In some applications, the diverging portion of the converging-diverging conduit may have an overall angle of divergence from 25° to 55° relative to the central axis.BRIEF DESCRIPTION OF THE DRAWINGS

[0011] For a more complete understanding of the embodiments described herein, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying figures, in which:

[0012] FIG. 1 is schematic representation of a prior art crude-to-chemicals processing system and process flow for such system;

[0013] FIG. 2 is an elevational, cross-sectional view of a reactor system for the conversion of liquid hydrocarbons in accordance with various embodiments of the disclosure;

[0014] FIG. 3 is an exploded perspective view of a feed assembly of the reactor system of FIG. 2 in accordance with various embodiments of the disclosure;

[0015] FIG. 4 is cross-sectional perspective view of the feed assembly and upstream end of a reaction chamber of the reactor system of FIG. 2;

[0016] FIG. 5 is a plot of the vaporization times as a function of droplet size using a simplified calculation with approximate conditions in a reactor system, such as that of FIG. 2;

[0017] FIG. 6 is a plot showing the Computational Fluid Dynamics (CFD) calculations of spray evaporation in a reactor, such as that of FIG. 2, wherein all the liquid was vaporized within 5 mm from the injection point;

[0018] FIG. 7 is a plot of the results of testing of a FLOWMAX® FM3A two-fluid nozzle using liquid water and air showing the various droplet sizes under various flow conditions;

[0019] FIG. 8 is a schematic of a hydrocarbon processing system and process flow for the conversion of liquid crude oil employing the reactor system of FIG. 2, in accordance with various embodiments of the disclosure;

[0020] FIG. 9 is a schematic a further hydrocarbon processing system and process flow for the conversion of liquid crude oil employing the reactor system of FIG. 2, in accordance with various embodiments of the disclosure;

[0021] FIG. 10 is a schematic of a hydrocarbon processing system and process flow for the conversion of liquid crude oil employing the reactor system of FIG. 2 and utilizing a front-end depropanizer in accordance with certain embodiments of the disclosure;

[0022] FIG. 11 is a schematic of a hydrocarbon processing system and process flow employing the reactor system of FIG. 2 for the conversion of liquid crude oil that has not been treated to remove asphaltenes and / or resins from the liquid crude oil in accordance with various embodiments of the disclosure;

[0023] FIG. 12 is a plot of selectivity in weight percent of light olefins and aromatics for the conversion of a 20 wt% liquid crude feed and wide range naphtha in an ANJEVOC reactor;

[0024] FIG. 13 is a plot of the conversion percentage and bulk gas temperature for the conversion of a 20 wt% liquid crude feed and wide range naphtha in the ANJEVOC reactor;

[0025] FIG. 14 is a plot of selectivity in weight percent of light olefins and aromatics for approximately 40 wt% Khuff gas condensate (KGC) crude oil with butane in the ANJEVOC reactor; and

[0026] FIG. 15 is a plot of selectivity in weight percent of light olefins and aromatics for approximately 40 wt% Arab extra light (AXL) crude oil with butane in the ANJEVOC reactor.DETAILED DESCRIPTION

[0027] In various embodiments of the present disclosure, a unique reactor technology is used to convert liquid hydrocarbons such as liquid crude oil, with or without gaseous hydrocarbons, into high value chemicals, such as light olefins and aromatics. The liquid hydrocarbons may include full range crude oil, various fractions of crude oil, and / or heavy hydrocarbon liquids from other sources. This conversion may be accomplished in single step of processing or with reduced or minimal processing steps and equipment, as compared to conventional crude-to- chemical processing systems. More specifically, the conversion may be achieved using ANJEVOC (ANnular JEt VOrtex Chamber) cracking reactor technology that produces annularly swirled jets of feed gases where hydrogen (or other fuels such as natural gas, recycled syngas, etc.) and oxygen gases are used to generate the heat required for cracking of hydrocarbons. Examples of such ANJEVOC reactors are described in U.S. Patent Nos. 11,020,719 and 11,123,705; and International Publication Nos. W02022 / 010821A1; W02022 / 010822A1, and W02022 / 010823A1, each of which is incorporated herein by reference in its entirety for all purposes, including the purpose of illustrating the configuration, construction and operation of such ANJEVOC reactors, and their various components.

[0028] The following includes definitions of various terms and phrases used throughout this specification.

[0029] For the purposes of this disclosure, if a numerical value, concentration or range is presented, each numerical value should be read once as modified by the term "about" (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the description, it should be understood that an amount range listed or described as being useful, suitable, or the like, is intended that any and every value within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific points within the range, or even no point within the range, are explicitly identified or referred to, it is to be understood that the inventors appreciate and understand that any and all points within the range are to be considered to have been specified, and that inventors possess the entire range and all points within the range.

[0030] The terms “about” or “approximately” are defined as being close to as understood by one of ordinary skill in the art. In one non-limiting embodiment the terms are defined to be within 10%, preferably, within 5%, more preferably, within 1%, and most preferably, within 0.5%.

[0031] For the purposes of this disclosure, “X, Y, and / or Z” can be construed as X only, Y only, Z only, 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 construed as X only, Y only, Z only, or any combination of two or more items X, Y, and Z (e.g., XYZ, XY, XZ, YZ.

[0032] The use of the words “a” or “an” when used in conjunction with the term “comprising,” “including,” “containing,” or “having” in the claims or the specification may mean “one,” but it is also consistent with the meaning of “one or more,” “at least one,” and “one or more than one.”

[0033] The words “comprising” (and any form of comprising, 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, unrecited elements or method steps.

[0034] The terms “wt%” or “mol%” refer to a weight or molar percentage of a component, respectively, based on the total weight or the total moles of material that includes thecomponent. In a non-limiting example, 10 moles of component in 100 moles of the material is 10 mol% of component.

[0035] Referring to FIG. 2, an elevational cross-sectional representation of a reactor system 10 for the conversion of liquid hydrocarbons is shown. The reactor system 10 is configured for the conversion of liquid hydrocarbons, such as crude oil, crude oil fractions, gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, a C20 to C40 hydrocarbon, etc. The reactor system 10 can also be used to convert gaseous hydrocarbons in conjunction with the liquid hydrocarbons. The reactor system 10 may constitute an ANJEVOC reactor and includes a reactor vessel 12 having a reactor wall 14 that defines an interior reaction chamber 16. The reactor wall 14 may have a cylindrical configuration with a constant diameter along all or a portion of its length, which may constitute a maj ority (i.e., > 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%) of its length. In most instances, the reactor vessel 12 is oriented vertically so that the cylindrical reactor wall 14 is oriented in an upright orientation with downward flow. The reactor can have other orientations (e.g., horizontal, sloped, or upright with upward flow), however, because the process is controlled by the centrifugal force, which exceeds the gravitational force by several orders of magnitude. The reactor vessel 12 may be configured to provide a length to diameter ratio (L / D) of at least 2. In particular applications, the L / D ratio may range from 2-10, more particularly from 2-5.

[0036] The reactor vessel 12 may be formed from steel. In certain embodiments, a cooling jacket can be provided around all or portions of the reactor vessel 12, wherein a second steel wall 18 is positioned around and spaced from the inner reactor wall 14 and a cooling fluid, such as water, may be circulated through the jacket formed between the walls 14, 18. In other embodiments, the reactor wall 14 may be formed from one or more layers of refractory material that line the interior of an outer steel wall to reduce heat loss and sustain the high temperatures of the reactor 10. Because of the unique design and operation of the reactor 10, the reactor wall 14 is cooled internally by the high-velocity near- wall gas flow pushed by centrifugal forces against the reactor wall 14 so that in some applications no exterior cooling jacket is required. This also allows refractory materials to be used for the interior of the reactor wall 14. Refractory materials (without cooling) typically cannot be used with conventional cracking reactors with pure oxygen due to the higher temperatures (e.g., from 2000 °C to 2800 °C). Reaction temperature for the conversion of liquid hydrocarbons, such as crude oil, in the reactor system 10 will typically range from 800 °C to 2500 °C.

[0037] An outlet 20 is provided at a lower or downstream end of the reactor vessel 12 for removing or discharging cracked products from the reaction chamber 16. The outlet diameter can be same as the diameter of the reactor wall 14 or the outlet diameter may be reduced to accelerate the flow before quenching and collection downstream.

[0038] The reactor 10 includes a reactor inlet assembly 22 that is coupled or joined to the upper or upstream end of the reactor wall 14 of the reactor vessel 12. Here, the reactor vessel 12 is oriented vertically with the inlet assembly 22 located above the reactor vessel 12. This is so that any downstream liquid quenching fluids (e.g., water) that are used within the reaction chamber 16 to quench the reaction gases are carried by gravity to the outlet 20 and not towards the upstream end towards the inlet assembly 22.

[0039] The inlet assembly 22 defines a converging-diverging conduit 24 defined by a circumferential wall 26 that surrounds a central axis 28 of the reactor 10. The central axis 28 of the reactor 10 may be the same or coincides with the central axis of each of the inlet assembly 22 or conduit 24 and reactor vessel 12. The circumferential wall 26 extends from opposite upstream and downstream ends of the converging-diverging conduit 24. As used herein, the terms “upstream” and “downstream” or similar expressions with respect to describing various components of the reactor system 10 shall refer to the position of the component with respect to the direction of overall fluid flow through the reactor 10 along the central axis 28.

[0040] As can be seen in FIG. 2, the circumferential wall 26 smoothly tapers or converges in width or diameter from the upstream ends to define an annular constricted neck portion located between the downstream and upstream ends of the converging-diverging conduit 24. At the annular constricted neck portion, the circumferential wall 26 of the conduit 24 transitions from converging or narrowing to diverging or widening. The circumferential wall 26 then smoothly expands or diverges in width or diameter downstream from the annular constricted neck portion. The interior of the circumferential wall 26 may have a circular perpendicular transverse cross section with respect to the axis 28 along all or a portion of its length. The circumferential wall 26 defines an interior flow path of the inlet assembly 22, with the constricted neck portion being part of the smoothly curved and streamlined convergingdiverging nozzle of the inlet assembly 22.

[0041] The nozzle geometry of the converging-diverging conduit 24 is configured based upon the theory relating to swirling conical jets of a viscous incompressible fluid. This phenomenon is described in the journal article by Pannala et al., entitled "Novel Annular Jet Vortex Reactor for High-Temperature Thermochemical Conversion of Hydrocarbons to Acetylene," publishedin ACS Engineering in 2022 (Pannala, S. et al. ACS Engineering 2022, 2(5), 406-420). The downstream or diverging portion of the conduit 24 is configured for non-supersonic fluid flow. Conduits or nozzles configured for supersonic flow, such as de Laval nozzles, are configured differently from the conduit 24 to provide supersonic flow downstream to form a shockwave. In various embodiments, the diverging conduit 24 does not form such a supersonic flow or a shockwave. Instead, the conduit 24 has a geometry that facilitates a recirculation and backflow of gases within the interior reaction chamber 16 near the central axis 28 in combination with annular swirling jet gas flow adjacent to the inner reactor wall 14. As such, the conduit 24 will have a greater angle of divergence than the angle of divergence typically used in de Laval nozzles, which have an angle of divergence of 15° or less). In, certain embodiments, the overall angle of divergence “A” (FIG. 2) relative to the axis 28 may be from 25° or more. In particular instances, the angle of divergence A for the diverging portion of the conduit 24 discussed herein is from 25° to 55°. In some embodiments, the angle of divergence A is of from at least, equal to, and / or between any two of 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°. The large divergence angle leads to recirculation of fluid flow at the reactor wall 14, as a result of the upstream swirling flow coupled with the convergent divergent conduit 24.

[0042] The downstream end of the diverging portion of conduit 24 joins the reactor wall 14 at an inlet of the reaction chamber 16 around its perimeter so that the conduit 24 is in fluid communication with the reaction chamber 16 of the reactor vessel 12. The upstream end of the converging portion of conduit 24 forms an inlet for the reactor vessel 12.

[0043] A feed assembly 32 is provided with the reactor system 10. A perspective view of the feed assembly 32 is shown in FIG. 3. The feed assembly 32 joins the upstream end of conduit 24 and is in fluid communication with 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 joins the upstream end of the converging portion of conduit 24. The feed assembly wall 34 or circumferential portions thereof are oriented perpendicularly or substantially perpendicularly (i.e., < 5 degrees from perpendicular about its circumference as it extends radially from the central axis) to the central axis 28.

[0044] Axially spaced upstream from the downstream wall 34 along the central axis 28 is an upstream feed assembly wall 36. The upstream wall 36 or circumferential portions thereof are oriented perpendicular to or substantially perpendicularly (i.e., < 5 degrees from perpendicular about its circumference as it extends radially from the central axis) to the central axis 28.

[0045] An upstream gas partition wall 38 and a downstream gas partition wall 40 are axially spaced between the downstream and upstream feed assembly walls 34, 36 and are axially spaced from one another, with the upstream partition wall 38 being positioned upstream from the downstream partition wall 40. The partition walls 38, 40 or circumferential portions thereof are also each oriented perpendicularly to or substantially perpendicularly (i.e., < 5 degrees from perpendicular about its circumference as it extends radially from the central axis) to the central axis 28. Each of the partition walls 38, 40 has a central opening 42, 44, respectively, that surrounds the central axis 28 and is concentric with the converging-diverging conduit 24. The inner ends of the partition walls 38, 40 defining the openings 42, 44 terminate at a position upstream of the converging-diverging conduit 24. The central openings 42, 44 each have a circular configuration. Other continuously-curved shapes for the central openings 42, 44 (e.g., oval) may also be used provided such configuration facilitates the swirling of gases to provide the required swirling flow patterns described herein. This shape may also correspond to the cross-sectional shape of the circumferential wall 26 of the converging-diverging conduit 24. In most applications, however, the central openings 42, 44 will be circular in shape. The central openings 42, 44 may have a diameter or width that is the same or slightly different (smaller or larger) than the diameter or width of the constricted neck of the converging-diverging conduit 24 at its narrowest point.

[0046] Referring to FIG. 2, the upstream partition wall 38 defines an annular gas flow passage 46 located between the upstream feed assembly wall 36 and the upstream side of the upstream partition wall 36. In the embodiment shown, the flow passage 46 constitutes an upstream annular hydrocarbon reactant feed inlet flow passage for introducing a gaseous hydrocarbon to be converted, e.g., into high value chemicals such as light olefins and aromatics. Likewise, an annular gas flow passage 48 is defined by the downstream side of the downstream partition wall 40 and the downstream feed assembly wall 34. In the embodiment shown, the flow passage 48 may constitute an annular steam or water inlet flow passage.

[0047] An intermediate partition wall 50 is axially spaced between the downstream gas partition wall 40 and the upstream gas partition wall 38 to define downstream and upstream intermediate annular gas inlet flow passages 52, 54. The intermediate partition wall 50 also has a central opening 56 that surrounds the central axis 28 and is concentric with the converging-diverging conduit 24. The inner ends of the partition wall 50 defining the opening 56 terminate at a position upstream of the converging-diverging conduit 24. The central opening 56 may have a circular configuration. Other shapes for the central opening 56 (e.g.,oval) may also be used provided such configuration facilitates the swirling of gases to provide the required swirling flow patterns described herein.

[0048] The intermediate partition wall 50, or circumferential portions thereof, is also oriented perpendicularly to or substantially perpendicularly (i.e., < 5 degrees from perpendicular about its circumference as it extends radially from the central axis) to the central axis 28. In the embodiment shown, the annular flow passage 52 may constitute an oxygen or oxidizing gas flow passage to facilitate combustion. The annular flow passage 54 may constitute a fuel gas (e.g., H2, CH4, syngas or a combination of these) flow passage for introducing a fuel gas for combustion.

[0049] The area between the downstream and upstream feed assembly walls 34, 36 and spaced radially inward from the central openings 42, 44, 56 of the partition walls 38, 44, 50, respectively, forms a central chamber 58 of the feed assembly 32 that surrounds the central axis 28. The central axis 28 also coincides with and forms a central axis of the central chamber 58 and feed assembly 32.

[0050] This configuration provides flow passages through which gas feeds to be cracked, steam, oxygen gas, and hydrogen-rich fuel for providing combustion heat can each be separately introduced and passed through the flow passages 46, 48, 52, 54, respectively, into the central chamber 58 of the feed assembly 32 in a swirling fluid flow pattern about the central axis 28 such that the feeds combust in the central chamber to form swirling combustion gases. The feeds are introduced into the central chamber in a direction that is non-parallel to the central axis 28. To this end, one or more of the feed assembly wall 34, the upstream wall 36, the partition walls 38, and 40 the intermediate partition wall 50 (or circumferential portions thereof) are configured to introduce the feeds into the central chamber 58 of the feed assembly 32 in a swirling fluid flow pattern about the central axis 28 such that the feeds combust in the central chamber to form swirling combustion gases. The feed assembly wall 34, the upstream wall 36, the partition walls 38, and 40 the intermediate partition wall 50 (or circumferential portions thereof) may be oriented in a direction that is non-parallel to the central axis 28. In some embodiments, one or more of the feed assembly wall 34, the upstream wall 36, the partition walls 38, and 40 the intermediate partition wall 50 (or circumferential portions thereof) may be oriented 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, less than or equal to 40 degrees from a direction perpendicular the central axis 28.

[0051] The upstream flow passage 46 can act as a gaseous hydrocarbon feed inlet flow passage. A fuel gas feed comprised of an hydrogen-rich gas feed (i.e. , H2) may be introduced into one of the first and second adjacent annular fuel gas inlet flow passages 52, 54, with an oxidizer (i.e., O2) or oxy gen-containing gas feed being introduced into the other of the flow passages 52, 54. Typically, the fuel and oxygen gas feeds will be introduced into flow passages that are immediately adjacent to one another to facilitate rapid combustion. In certain applications, the downstream flow passage 52 may be used for delivering the oxidizer or oxygen-containing gas and the upstream flow passage 54 will be used for delivering the hydrogen-rich fuel gas. The steam feed may be introduced into the downstream annular steam inlet flow passage 48. In other instances, the various feeds may be altered in sequence within the flow passages 46, 48, 52, 54. For example, any of flow passages 48, 52, 54 can act as a gaseous hydrocarbon feed inlet flow passage. In certain applications, the steam feed may be combined or introduced with one or more of the other feeds. This may include combining the steam feed with the fuel-gas feed, the oxy gen-containing gas feed, or the hydrocarbon gas feed.

[0052] In certain embodiments, one or more of the flow passages 46, 48, 52, 54 may remain idle or be omitted from the feed assembly 32. If a flow passage is omitted, one of the partition walls 38, 40, 50 need not be present and the number of flow passages will be reduced. In such instances, certain feeds may be combined and introduced together, such as the steam feed previously discussed.

[0053] In the illustrated reactor system 10, flow passages 46, 48, 52, 54 are configured so that the different feeds pass through flow passages perpendicularly or substantially perpendicularly to the central axis 28 in an inwardly swirling fluid flow pattern within said flow passages so that the feeds flow about the central axis 28 within the central chamber 58. The swirling fuel gas and oxidizer feeds combust within the central chamber 58.

[0054] In the illustrated reactor system 10, walls 34, 36, 38, 40, and 50 forming the different flow passages 46, 48, 52, 54 are parallel to one another in many cases. However, in other cases, walls 34, 36, 38, 40, and 50 may be non-parallel to one another. The walls 34, 36, 38, 40, and 50 are axially spaced apart to provide the desired volume and flow characteristics for the gases flowing through them. This may be based upon the desired flow rates or linear velocities of each of the feed gases and their relative amounts. For instance, the relative volume of oxygen gas needed for the combustion is typically smaller than the volume of the hydrogen-rich fuel gas needed for the combustion. Therefore, the partition wall 50 may be spaced closer to the downstream partition wall 40 so that the flow passage 54 for the hydrogen fuel is larger andaccommodates the greater flow of fuel gas. The particular spacing may depend on fuel gas and oxidizer combination, the desired volume for combustion, and nature of the hydrocarbon feeds.

[0055] Annular gas manifolds 60, 62, 64, 66 are provided around the outer periphery of the flow passages 46, 48, 52, 54, respectively. In an example, the gas manifold 60 may be fluidly coupled to a gaseous hydrocarbon feed source. The manifold 62 may be fluidly coupled to a steam source. The manifold 64 may be fluidly coupled to an oxygen-containing-gas source, such as a pure O2 feed. And the manifold 66 is fluidly coupled to a hydrogen-rich or fuel feed source, such as H2. The manifolds 60, 62, 64, 66 are provided with the feed assembly 32 to facilitate introduction of feed gases into the flow passages 46, 48, 52, 54. In other embodiments, the different feed sources to each manifold may be varied.

[0056] In general, the gas inlets from the manifolds 60, 62, 64, 66 are oriented to generate an inwardly swirling flow of gases within central chamber 58. In other words, the gas inlets direct the incoming flow of gases along paths that extend inwardly from the walls of central chamber 58 but not along a radius of central chamber 58 directly toward the central axis 28. An inwardly swirling flow of gases from the inlets is created, rather than a series of flows that traverse central chamber 58 by the shortest, radial path and intersect at central axis 28. As an aside, one or more inlets may be provided for each flow passage 46, 48, 52, 54. Furthermore, the walls 34, 36, 38, 40, and 50 that form the different flow passages of the feed assembly 32 prevent the gases from flowing axially along the direction of central axis 28 while they are contained within the flow passages 46, 48, 52, 54. The manifolds 60, 62, 64, 66 can be configured as standard manifolds (e.g., snail-like) as may be typically used in vortex devices.

[0057] Referring to FIG. 3, in some embodiments, one or more or all of the flow passages 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 for each flow passage). Each guide vane 68, 70, 72, 74 may be a planar member that is oriented in a plane that is parallel to the central axis 28 and extends between the walls 34, 36, 38, 40, and 50. The guide vanes 68, 70, 72, 74 may be circumferentially spaced an equal distance from one another. In certain embodiments, the guide vanes 68, 70, 72, 74 may be fixed in place, with the upper and lower side edges of the guide vanes being joined along their lengths or a portion of their lengths to the walls 34, 36, 38, 40, and 50 so that there are no air gaps between the side edges of the vanes 68, 70, 72, 74 and the walls 34, 36, 38, 40, and 50. In other embodiments, however, the guide vanes are movable. In such cases, the upper and lower side edges of the vanes 68, 70, 72, 74 may be closely spaced from the walls 34, 36, 38, 40, and 50 to provide a small clearance to allowmovement. The close spacing may minimize air gaps through which gases may pass. Seals may also be used to effectively close these spaces or clearances while allowing movement. In other instances, the vanes 68, 70, 72, 74 may be oriented so that the plane of the vane is in a non-parallel or slanted orientation relative to the central axis 28. In such cases, the side edges may be fixed to the walls 34, 36, 38, 40, and 50 or remain closely spaced from walls 34, 36, 38, 40, and 50 to minimize air gaps. In certain applications, the guide vanes 68, 70, 72, 74 may be configured as airfoils, such as described in U.S. Patent No. 11,123,705.

[0058] In the illustrated reactor system 10, the guide vanes 68, 70, 72, 74 are provided adjacent to the outer perimeter of the flow passages 46, 48, 52, 54 and are spaced in an annular or circular ring pattern near the manifold inlets. In other reactor systems, they may be provided in an annular pattern at other positions located radially inward or further within the interior of the flow passages 46, 48, 52, 54. Alternatively, one or more additional annular sets of guide vanes may be located radially inward from those located along the outer periphery to facilitate inwardly swirling fluid flow.

[0059] Feed gases from the manifolds 60, 62, 64, 66 are delivered nearly tangentially to the outer perimeter of central chamber 58, where the guide vanes 68, 70, 72, 74 may direct the gas flow in an inwardly swirling or spiraling fluid flow pattern within the central chamber 58. In some embodiments, the inlets from the manifolds 60, 62, 64, 66 may be oriented or directed to impart the full inwardly swirling fluid flow without the use of or need for guide vanes. In other embodiments, the guide vanes 68, 70, 72, 74 may impart the full swirling flow of the introduced gases, such as in instances where the gas from the manifold inlets may be directed radially toward the central axis 28 or do not impart the full desired swirling flow. In such cases the guide vanes 68, 70, 72, 74 prevent flow directly toward the central axis 28 and direct the flowing gases nearly tangentially with respect to the inner walls of central chamber 58 to provide the inwardly swirling or spiraling fluid flow pattern.

[0060] The guide vanes 68, 70, 72, 74 of each flow passage 46, 48, 52, 54 may be mounted on actuators (not shown) so that they can be selectively movable to various positions to provide a selected inwardly spiraling flow pattern. The guide vanes 68, 70, 72, 74 may be pivotal about an axis that is parallel to the central axis 28 so that the vanes 68, 70, 72, 74 may be moved to various positions.

[0061] The orientation of the vanes 68, 70, 72, 74 and / or the orientation of the inlets of the manifolds 60, 62, 64, 66 of each flow passage will provide swirling or spiraling fluid jet flow that is in the same rotational direction about the axis 28, i.e., clockwise or counter-clockwise.Thus, gases within each of the flow passages will flow clockwise or counterclockwise about the axis 28. In general, the vanes 68, 70, 72, 74 will all introduce gases at the same angle inner relative to the walls of central chamber 58 to provide the desired swirling fluid flow characteristics. If the vanes 68, 70, 72, 74 are movable, then they will typically be actuated to move in unison or close to unison.

[0062] In an example, oxygen and hydrogen fuel gases from flow passages 52, 54, gaseous hydrocarbon feed from flow passage 46 and steam from flow passage 48 may be discharged into the central chamber 58 of the feed assembly 32. Because the oxy gen-containing gas and hydrogen-rich fuel gas are introduced separately from one another and not as mixture, this eliminates safety issues that would otherwise occur if these gases were premixed prior to their introduction into the feed assembly 32. Furthermore, the combustion reaction takes place rapidly, with most of the combustion occurring within a small space within the central chamber 58 where the two streams of oxygen-containing gas and hydrogen-rich fuel gas from the flow passages 52, 54 are mixed after being discharged from the flow passages 52, 54. The combustible mixture can be ignited, e.g., using a spark, chemicals, or pilot flame that extends through the bottom surface or side surfaces of the reactor. Suction from the swirling flow can transport heat from an ignition device to the combustion zone of the central chamber 58 to initiate the ignition.

[0063] The gaseous hydrocarbon feed from the upstream flow passage 46, and steam from flow passage 48 are discharged into the central chamber 58 so that gaseous hydrocarbon feed, steam and heated combustion gases are mixed together and form a swirling gas mixture within the central chamber 58. This swirling gas mixture then passes through the converging-diverging conduit 24 and into the reaction chamber 16 of the reactor vessel 12.

[0001] A liquid feed inlet 76 is also formed in the upstream feed assembly wall 36 for introducing, into the feed assembly 32, all or a portion of the liquid hydrocarbons to be converted by the reactor system 10 into, e.g., high value chemicals such as light olefins and aromatics. In certain embodiments, there may be more than one or multiple liquid feed inlets 76. The liquid feed inlet 76 may be formed as a length of conduit that joins the feed assembly wall 36. The conduit may include an inlet axis that is aligned with and / or parallel to the central axis 28 so that the liquid feeds or a majority (i.e. , > 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90%, or 95%) of the liquid feeds introduced through the inlet 76 may be introduced axially or at a non-perpendicular angle with respect to the central axis 28 into the central chamber 58. In other words, the liquid feeds introduced through the inlet 76 are not introducedperpendicularly to the central axis 28. A liquid feed manifold 80 may be used to introduce liquid feeds through the liquid feed inlet 76. The manifold 80 is fluidly coupled to a liquid feed source comprising the liquid hydrocarbon to be converted. The manifold 80 comprises one or more spray nozzles 78 that may be used to introduce the liquid feed as a spray of liquid droplets into the central chamber 58. Where multiple liquid feed inlets 76 are employed, the manifold 80 may comprise multiple spray nozzles 78 positioned and oriented for introducing, into the central chamber 58 through the liquid feed inlets 76, the liquid feed as multiple sprays of droplets. In some embodiments, the droplets in the liquid feed define a non-swirling spray and / or a radially-extending fanned pattern so that all or a portion of the droplets are not parallel to the central axis, but will have both axial and radial flow velocity components. Moreover, the droplet pattern may be centered on or close to the central axis 28 where the swirl velocities are lowest. In some embodiments, one or more spray nozzles 78 introduce liquid into the central chamber 58 of the feed assembly 32 where the swirl velocity of the swirling fluid flow is less than 5 m / s during operation of the reactor 10. One or more spray nozzles may be located within a certain placement radius (“PR”) defined from a point where the central axis 28 intersects a 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 a nozzle that creates a particular droplet size and placing the nozzle in a central location within the feed assembly of the reactor system described below (i.e., aligned with or close to the central axis) results in hydrocarbon conversion efficiencies not seen in conventional reactor systems. As described below, the central location of the nozzle injects the liquid hydrocarbon reactant feed into an area of a reactor with a low swirl velocity (e.g., swirl velocity of less than 5 m / s). The location along with the droplet size allows the liquid droplets to vaporize before the droplets enter an area of the feed assembly with higher swirl velocities, thereby preventing rapid coking of the reactor. The combination of a location for the nozzle and a droplet size generated by the nozzle at that location thus provides certain unique advantages.

[0064] The combination of axial and radial flow velocity components defines a spray pattern that has a low spray angle and keeps the pattern close to the central axis 28. As a result, the droplets are directed primarily axially (e.g., to define a spray angle of 40° or less). Such a spray angle helps ensure that liquid droplets are vaporized before being caught in the swirling gas flow and forced by centrifugal forces against the reactor wall, which can lead to coking. Inparticular embodiments, the spray pattern may have a spray angle of at least, equal to, and / or between any two of 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 certain embodiments, the spray pattern may be a solid conical, hollow-conical, linear stream, or flat spray pattern. In various embodiments, the liquid feed inlet 76 does not include guide vanes, such as the vanes 68, 70, 72, 74, or other structures that may impart a swirling fluid flow to the liquid hydrocarbon before it enters the central chamber 58.

[0065] By introducing the liquid hydrocarbon axially, the atomized spray with liquid droplets is primarily concentrated close to the central axis 28 of the reactor 10 where the swirl velocity is lowest. In effect, the liquid droplets are concentrated at the “eye” of the swirling fluid flow. Higher swirl velocities are encountered away from the central axis 28 or centerline and closer to the walls. These higher swirl velocities could deposit the atomized droplets on the walls and guide vanes, causing coking and fouling. The small droplets interact with the counter current flow of the high temperature gases from the combustion and strong recirculation to vaporize the droplets and follow the other hydrocarbon gases to increase heat and crack in the reactor 10.

[0066] The spray nozzle(s) 78 may be selected and / or configured to provide a particular droplet size. The spray nozzle(s) may be constructed or configured to a provide droplets under the selected flow conditions (e.g., pressure, velocity) having a Sauter Mean Diameter (SMD) or D32 from 1 pm to 250 pm. As used herein, the SMD or D32 size is defined as the ratio of droplet volume to the surface area of the droplets in a spray. Droplet measurements may be determined using phase doppler interferometer (PDI) techniques. In particular embodiments, the spray nozzle(s) at the liquid feed inlet 76 may provide a SMD size for the liquid hydrocarbon feed of from at least, equal to, and / or between any two of 1 pm, 2 pm, 3 pm, 4 pm, 5 pm, 6 pm, 7 pm, 8 pm, 9 pm, 10 pm, 11 pm, 12 pm, 13 pm, 14 pm, 15 pm, 16 pm, 17 pm, 18 pm, 19 pm, 20 pm, 21 pm, 22 pm, 23 pm, 24 pm, 25 pm, 26 pm, 27 pm, 28 pm, 29 pm, 30 pm, 30 pm,31 pm, 32 pm, 33 pm, 34 pm, 35 pm, 36 pm, 37 pm, 38 pm, 39 pm, 40 pm, 41 pm, 42 pm,43 pm, 44 pm, 45 pm, 46 pm, 47 pm, 48 pm, 49 pm, 50 pm, 55 pm, 60 pm, 65 pm, 70 pm,75 pm, 80 pm, 85 pm, 90 pm, 95 pm, 100 pm, 105 pm, 110 pm, 115 pm, 120 pm, 125 pm,130 pm, 135 pm, 140 pm, 145 pm, 150 pm, 155 pm, 160 pm, 165 pm, 170 pm, 175 pm, 180 pm, 185 pm, 190 pm, 195 pm, 200 pm, 205 pm, 210 pm, 215 pm, 220 pm, 225 pm, 230 pm, 235 pm, 240 pm, 245 pm, and 250 pm.

[0067] The smaller the droplet size, the faster the vaporization and less likely the droplets will enter the higher swirl regions of the reactor. The smaller the droplet size, however, there is a higher pressure drop across the nozzle and there is a limit to how fine an atomization can be achieved with the nozzle. Droplet size is therefore a compromise between the two competing requirements. The plot of FIG. 5 shows the vaporization times as a function of droplet size using a simplified calculation with approximate conditions in the reactor. FIG. 6 shows the Computational Fluid Dynamics (CFD) calculations of spray evaporation in the reactor, wherein all the liquid was vaporized within 5 mm from the injection point. The plot shows the volume fraction of liquid of the spray that ranges from approximately 2.5 xlO'5at its introduction and goes to 0, (which indicates that all the liquid was vaporized).

[0068] Other characteristics of the droplets generated by the spray nozzle(s) 78 may include the weighted average droplet size. Weighted average droplet size may include a mass (volume) median or 50% diameter (Dvo.s), which is the diameter at which 50% of the total volume of droplets are contained in particles with smaller diameters. In certain embodiments, the Dvo.s of the droplets may be from at least, equal to, and / or between any two of 10 pm, 11 pm, 12 pm, 13 pm, 14 pm, 15 pm, 16 pm, 17 pm, 18 pm, 19 pm, 20 pm, 21 pm, 22 pm, 23 pm, 24 pm, 25 pm, 26 pm, 27 pm, 28 pm, 29 pm, 30 pm, 30 pm, 31 pm, 32 pm, 33 pm, 34 pm, 35 pm, 36 pm, 37 pm, 38 pm, 39 pm, 40 pm, 41 pm, 42 pm, 43 pm, 44 pm, 45 pm, 46 pm, 47 pm, 48 pm, 49 pm, 50 pm, 55 pm, 60 pm, 65 pm, 70 pm, 75 pm, 80 pm, 85 pm, 90 pm, 95 pm, 100 pm, 105 pm, 110 pm, 115 pm, 120 pm, 125 pm, 130 pm, 135 pm, 140 pm, 145 pm, 150 pm, 155 pm, 160 pm, 165 pm, 170 pm, 175 pm, 180 pm, 185 pm, 190 pm, 195 pm, 200 pm, 205 pm, 210 pm, 215 pm, 220 pm, 225 pm, 230 pm, 235 pm, 240 pm, 245 pm, and 250 pm. In one specific embodiment, the spray nozzle is configured to form droplets with a DV0.5 from 10 microns to 50 microns.

[0069] The Dvo.i is the diameter below which 10% of the total volume of droplets are found. In certain embodiments, the Dvo.i of the spray may be from at least, equal to, and / or between any two of 5 pm, 6 pm, 7 pm, 8 pm, 9 pm, 10 pm, 11 pm, 12 pm, 13 pm, 14 pm, 15 pm, 16 pm, 17 pm, 18 pm, 19 pm, 20 pm, 21 pm, 22 pm, 23 pm, 24 pm, 25 pm, 26 pm, 27 pm, 28 pm, 29 pm, 30 pm, 30 pm, 31 pm, 32 pm, 33 pm, 34 pm, 35 pm, 36 pm, 37 pm, 38 pm, 39 pm, 40 pm, 41 pm, 42 pm, 43 pm, 44 pm, 45 pm, 46 pm, 47 pm, 48 pm, 49 pm, 50 pm, 55 pm, 60 pm, 65 pm, 70 pm, 75 pm, 80 pm, 85 pm, 90 pm, 95 pm, 100 pm, 105 pm, 110 pm, 115 pm, 120 pm, 125 pm, 130 pm, 135 pm, 140 pm, 145 pm, 150 pm, 155 pm, 160 pm, 165m, 170 pm, 175 pm. In one specific embodiment, the spray nozzle is configured to form droplets with a DV0.1 from 5 microns to 25 microns.

[0070] The Dvo.9 is the diameter below which 90% of the total volume of droplets are found. In certain instances, the Dvo.9 of the spray may be from at least, equal to, and / or between any two of 20 pm, 21 pm, 22 pm, 23 pm, 24 pm, 25 pm, 26 pm, 27 pm, 28 pm, 29 pm, 30 pm, 30 pm, 31 pm, 32 pm, 33 pm, 34 pm, 35 pm, 36 pm, 37 pm, 38 pm, 39 pm, 40 pm, 41 pm, 42 pm, 43 pm, 44 pm, 45 pm, 46 pm, 47 pm, 48 pm, 49 pm, 50 pm, 55 pm, 60 pm, 65 pm, 70 pm, 75 pm, 80 pm, 85 pm, 90 pm, 95 pm, 100 pm, 105 pm, 110 pm, 115 pm, 120 pm, 125 pm, 130 pm, 135 pm, 140 pm, 145 pm, 150 pm, 155 pm, 160 pm, 165 pm, 170 pm, 175 pm,180 pm, 185 pm, 190 pm, 195 pm, 200 pm, 205 pm, 210 pm, 215 pm, 220 pm, 225 pm, 230 pm, 235 pm, 240 pm, 245 pm, 250 pm, 255 pm, 260 pm, 265 pm, 270 pm, 275 pm, 280 pm,285 pm, 290 pm, 295 pm, 300 pm, 305 pm, 310 pm, 315 pm, 320 pm, 325 pm, 330 pm, 335 pm, 340 pm, 345 pm, 350 pm, 355 pm, 360 pm, 365 pm, 370 pm, 375 pm, 380 pm, 385 pm,390 pm, 395 pm, 400 pm, 405 pm, 410 pm, 415 pm, 420 pm, 425 pm, 430 pm, 435 pm, 440 pm, 445 pm, and 450 pm. In one specific embodiment, the spray nozzle is configured to form droplets with a DVO.9 from 20 microns to 100 microns.

[0071] To facilitate forming a suitable fine spray of the liquid hydrocarbon feed having such small droplet sizes, the liquid hydrocarbon may be modified to have a dynamic viscosity from 0.1 cP to 1000 cP prior to or at its introduction, as measured using ASTM D445, but at the temperature of operation (i.e., the temperature of the liquid hydrocarbon when passed through the nozzle(s)). For example, as discussed below, the liquid hydrocarbon feed may in some cases be preheated to a temperature between 25 °C to 400°C and viscosity measured at this temperature. The droplet size is approximately proportional to dynamic viscosity to the power of 0.2 and thus lower dynamic viscosity leads to smaller droplet size. Typically, fluids with lower dynamic viscosity also have lower surface tension and the droplet size is approximately correlated to surface tension to the power of 0.5. In certain embodiments, the liquid hydrocarbon may be modified to have a dynamic viscosity from at least, equal to, and / or between any two of 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 the hydrocarbon may include heating the hydrocarbon to a sufficient temperature and / or combining the liquid hydrocarbon with a solvent or low viscosity component such as aromatics(e.g. , xylene benzene, toluene, and ethylbenzene, which may be part of a recycle stream) to lower the dynamic viscosity.

[0072] In certain applications, the spray nozzle(s) 78 may be configured or selected as a two- fluid nozzle. Such two-fluid nozzles may allow for the introduction of two different fluids, each having different properties from the other. For example, the liquids could include a liquid phase fluid and vapor phase fluid that are each sprayed simultaneously through the nozzle 78. The two-fluid nozzle 78 may have a mixing chamber where the two fluids are mixed prior to being discharged as a spray. Such two-fluid nozzles also provide internal mixing of the two fluids to prevent clogging, as well as providing a fine atomized spray having the above-stated droplet size. Such two-liquid spray nozzles are described, for example, in U.S. Pat. App. Pub. No. US2020 / 0147624, which is incorporated herein in its entirety for all purposes, including the description of the construction and use of such nozzles. Two-fluid nozzles may facilitate rapid diffusion of the mixture from the outlet, atomization, and the formation of droplets that can be conveyed easily by the atomization gas. Two-fluid nozzles can help to atomize and disperse high viscosity liquids by flowing a gaseous phase with the high viscosity liquid phase. This can reduce liquid deposition on the mixed gas outlet and prevent clogging. A suitable commercially available two-fluid nozzle for use as the spray nozzle(s) 78 may include that marketed as the FLOWMAX® X-Series or FLOWMAX® FM3A nozzle, available from Spraying Systems Co., Tokyo, Japan.

[0073] The energy input to the spray nozzle is equal to the pressure drop across the nozzle multiplied by the flow rate. To obtain the same droplet size distribution, the choice of singlephase or two-phase nozzle depends on pressure drop. In addition to pressure drop, to obtain a targeted droplet size distribution, spray angle, hollow vs. full cone, etc., the choice might be limited in terms of a single or two-phase nozzle. For example, with respect to two-phase nozzles, there are options from internal mixing to external mixing to address fouling. Furthermore, for the current application with hydrocarbons, the right choice of spray nozzle may depend on high temperature operability, coking and fouling characteristics, erosion, ability to detect and unplug the narrow openings of the nozzles, etc. In general, two-fluid nozzles provide a broad range of control over the droplet size distribution and ability to self-clean as the vapor phase can be steam. A disadvantage may be that slight variations in vapor phase or liquid phase flow rates or pressures can dramatically vary the droplet and spray characteristics.

[0074] In various embodiments of the present disclosure, the liquid hydrocarbon may be introduced into the liquid feed inlet 76 through the two-fluid spray nozzle 78 along with agaseous hydrocarbon and / or steam (i.e., superheated steam) as the second fluid. The spray nozzle 78 is coupled to one end of the spray manifold 80 that is fluidly coupled to separate upstream liquid hydrocarbon and gas feed (i.e., steam and / or gaseous hydrocarbons) sources. The range of pressures for the liquid feed versus vapor feed depend on the design of the nozzle. For example, FIG. 7 shows the results of testing of a FLOWMAX® FM3A two-fluid nozzle using liquid water and air under different flow conditions and the various droplet sizes (i.e., D32, DVO.9, Dvo.99). The liquid pressure was varied in the range of 1-3 barg at a constant gas pressure of 4.14 barg. The corresponding liquid flow was in the range of 1 - 11 liters per minute and air flow rate was between 80-100 Nm3 / hr. For these conditions, the SMD varied between 20 pm to 55 pm. Thus, these parameters may be tuned for any particular hydrocarbon used as liquid feed and paired with steam or other gas as the vapor phase in such two-fluid nozzles.

[0075] If the desired droplet characteristics are not achieved, the droplets can take significantly longer time to vaporize. Droplet vaporization time is proportional to square of the droplet diameter. In addition, the droplets may encounter higher swirl velocities leading to high centrifugal acceleration (e.g., 100 g to 100,000 g forces), resulting in deposition of the droplets onto the walls and coking and fouling of the reactor. This creates a positive feedback loop where any deposits will disrupt desirable hydrodynamics and accelerate additional maldistribution and deposition. This leads to coking and plugging of the reactor. For robust operations of the reactor with liquid feed, the droplet characteristics in terms of droplet size, spray angle, etc. are thus important.

[0076] In various embodiments of the present disclosure, the liquid hydrocarbon feed that can be converted by the reactor system 10 can include a variety of liquid hydrocarbons. These include liquid hydrocarbons that cannot be directly used in a steam cracker because of the high boiling point where they cannot be vaporized without coking the preheaters. These can include one or more of crude oil, gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, any one of a C20 to C40 hydrocarbon or mixtures or two or more thereof, a biomass-derived oil, a pyoil from plastic, a liquified plastic, a liquified plastic waste with impurities, a heteroatomcontaining hydrocarbon liquid, and combinations of these liquid hydrocarbons.

[0077] Crude oil may be used as is or pretreated in a flash drum, crude distillation or other processing system 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 inside the reactor. In many applications, the liquid hydrocarbons may have a broad range of molecular weights or boiling point so that the resulting liquid has dynamic viscosity in therange of 0.1 cP to 1000 cP so that fine atomization can be generated through commercially available single- or two-phase nozzles. In certain applications, the liquid hydrocarbon may be an untreated crude oil that has not been pretreated or refined to remove any materials.

[0078] The liquid hydrocarbon converted with the reactor system 10 will typically make up from 0.5 wt% to 100 wt% of the total weight of the hydrocarbon reactant feeds (i.e. , both liquid and gas hydrocarbons). In particular embodiments, the liquid hydrocarbon may make up from at least, equal to, and / or between any two of 0.5 wt%, 0.6 wt%, 0.7 wt%, 0.8 wt%, 0.9 wt%, 1.0 wt%, 1.1 wt%, 1.2 wt%, 1.3 wt%, 1.4 wt%, 1.5 wt%, 1.6 wt%, 1.7 wt%, 1.8 wt%, 1.9 wt%, 2.0 wt%, 2.1 wt%, 2.2 wt%, 2.3 wt%, 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 wt%, 5.0 wt%, 5.1 wt%, 5.2 wt%, 5.3 wt%, 5.4 wt%, 5.5 wt%, 5.6 wt%, 5.7 wt%, 5.8 wt%, 5.9 wt%, 6.0 wt%, 6.1 wt%, 6.2 wt%, 6.3 wt%, 6.4 wt%, 6.5 wt%, 6.6 wt%, 6.7 wt%, 6.8 wt%, 6.9 wt%, 7.0 wt%, 7.1 wt%, 7.2 wt%, 7.3 wt%, 7.4 wt%, 7.5 wt%, 7.6 wt%, 7.7 wt%, 7.8 wt%, 7.9 wt%, 8.0 wt%, 8.1 wt%, 8.2 wt%, 8.3 wt%, 8.4 wt%, 8.5 wt%, 8.6 wt%, 8.7 wt%, 8.8 wt%, 8.9 wt%, 9.0 wt%, 9.1 wt%, 9.2 wt%, 9.3 wt%, 9.4 wt%, 9.5 wt%, 9.6 wt%, 9.7 wt%, 9.8 wt%, 9.9 wt%, and 10.0 wt%, 11 wt%, 12 wt%, 13 wt%, 14 wt%, 15 wt%, 16 wt%, 17 wt%, 18 wt%, 19 wt%, 20 wt%, 21 wt%, 22 wt%, 23 wt%, 24 wt%, 25 wt%, 26 wt%, 27 wt%, 28 wt%, 29 wt%, 30 wt%, 31 wt%, 32 wt%, 33 wt%, 34 wt%, 35 wt%, 36 wt%, 37 wt%, 38 wt%, 39 wt%, and 40 wt%, 41 wt%, 42 wt%, 43 wt%, 44 wt%, 45 wt%, 46 wt%, 47 wt%, 48 wt%, 49 wt%, 50 wt%, 51 wt%, 52 wt%, 53 wt%, 54 wt%, 55 wt%, 56 wt%, 57 wt%, 58 wt%, 59 wt%, 60 wt%, 61 wt%, 62 wt%, 63 wt%, 64 wt%, 65 wt%, 66 wt%, 67 wt%, 68 wt%, 69 wt%, 70 wt%, 71 wt%, 72 wt%, 73 wt%, 74 wt%, 75 wt%, 76 wt%, 77 wt%, 78 wt%, 79 wt%, 80 wt%, 81 wt%, 82 wt%, 83 wt%, 84 wt%, 85 wt%, 86 wt%, 87 wt%, 88 wt%, 89 wt%, 90 wt%, 91 wt%, 92 wt%, 93 wt%, 94 wt%, 95 wt%, 96 wt%, 97 wt%, 98 wt%, 99 wt%, and 100 wt% by total weight of the hydrocarbon reactant feedstock.

[0079] In many applications, the liquid hydrocarbon will be converted in the reactor system 10 along with a gaseous hydrocarbon. As used herein, “gaseous hydrocarbon” is meant to include those hydrocarbons that are at conditions, such as temperature and pressure with or without addition of steam dilution, where the hydrocarbon is in a gaseous or superheated state prior to its introduction into the reactor system 10. This may include those hydrocarbons that may be liquids at standard atmospheric conditions but are at elevated temperatures and / or reduced pressures, such that they are vaporized prior to their introduction into the reactor system 10.The gaseous hydrocarbon may include, but is not limited to, natural gas liquids (NGL), a natural gas condensate, an associated petroleum gas, a C4 stream, a raw C4 stream, and any one or more of a gaseous Ci to C20 hydrocarbon or mixtures thereof, and combinations of these. For example, the gaseous hydrocarbon may have a boiling point at one atmosphere no greater than 450 °C, no greater than 250°C, or no greater than 150°C. As used herein, the raw C4 stream includes mixtures of C4 materials, including olefinic C4 materials, such as butadiene, butene, isobutylene, etc., such as those C4 olefins produced during steam cracking operations. By way of example, a typical raw C4 stream may have 1,3 butadiene, 1-buten, and isobutene in an amount from 15 wt% to 35 wt% each, 2-butene and n-butene in an amount from 5 wt% to 15 wt% each, and 1,2 butadiene, vinyl acetylene, and ethyl acetylene in an amount from 0.1 wt% to 5 wt%.

[0080] In certain instances, all or a portion of the gaseous hydrocarbon can be fed together with the liquid hydrocarbon feed through the liquid feed inlet 76 and spray nozzle 78. In the case of the liquid hydrocarbon that is introduced using the two-fluid nozzle 78, the gaseous hydrocarbon may be mixed with the liquid hydrocarbon within the nozzle 78 itself, such as in a mixing chamber of the nozzle, prior to it 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 both may be discharged together through the spray nozzle(s) 78. In still other instances, the gaseous hydrocarbon may be introduced separately from the liquid hydrocarbon through the liquid feed inlet 76.

[0081] In many applications, all or a portion of the gaseous hydrocarbon feed to be converted by the reactor system 10 is introduced through one of the annular gas flow passages 46, 48, 52, 54 of the feed assembly 32. Typically, this will be the upstream flow passage 46, which is immediately adjacent to the liquid feed inlet 76.

[0082] One or both of the liquid hydrocarbon feed and / or gaseous hydrocarbon feed may be mixed with steam. This is typically superheated steam that is combined with and fed with the hydrocarbon feed prior to its introduction into the feed assembly 32 or central chamber 58. In the case of the liquid hydrocarbon that is introduced using the two-fluid nozzle 78, the steam may be mixed with the liquid hydrocarbon within the nozzle 78 itself prior to it being discharged as a spray. Steam may also be separately introduced into the feed assembly 32 through one of the annular flow passages, such as the downstream flow passage 48.

[0083] In an example of operation of the reactor system 10, a gaseous hydrocarbon feed, such as those discussed previously, is introduced from manifold 60 through an inlet into flowpassage 46. A hydrogen-containing fuel gas is introduced from manifold 66 into flow passage 54. The hydrogen-containing fuel gas may be hydrogen gas (H2), methane (CH4), and / or CO / syngas or a combination of these. Here, the CH4 is used as fuel for combustion. In certain embodiments where a combination of hydrogen gas and methane are used, the methane may be present in the fuel gas in an amount of from 20 mol%, 15 mol%, 10 mol%, 5 mol% or less. Greater amounts of methane may impact the desired selectivity. In other embodiments, however, greater amounts of methane may be used, including 100% methane for the fuel gas. Natural gas may also be used as fuel gas.

[0084] The hydrogen-containing fuel gas may be a hydrogen-gas-rich stream composed primarily of hydrogen gas, which may be a recycled stream from downstream processing, or additional hydrogen gas. The hydrogen-gas-rich stream may contain other components such as methane, CO, steam, inert gases, and CO2. Other hydrocarbons can also be used as the fuel gas in certain embodiments and applications. Additionally, small amounts of N2 can also be present. Sulfur can also be present in the fuel gas or other feed streams. If sulfur is present, additional separation upstream or downstream may be required. The reactor and process are sufficiently robust to accommodate the presence of sulfur, particularly since no catalyst is used. The ratio between the hydrocarbon feed (i.e., the total of liquid and gaseous hydrocarbons) to hydrogen-containing fuel will typically range from 1 to 15, more particularly from 1 to 10, based on mass.

[0085] An oxidizer or oxygen-containing gas, which may be a concentrated or pure oxygen gas, such as from an air separation unit (not shown), is introduced as the oxidizer feed through manifold 64 through inlets into the flow passage 52. Having the oxygen-containing gas introduced through the downstream flow passage 52 spaces it further from liquid feed inlet 76 and any hydrocarbons gas introduced through flow passage 46 to eliminate or minimize any combustion of the introduced hydrocarbon reactant feeds. In certain applications, the mole ratio of H2 / O2 may range from 2 to 9, more particularly from 2 to 5, and still more particularly from 2 to 4. The oxygen feed may provide an oxygen equivalent-to-fuel mole ratio of from 0.2 to 1.0. An excess of hydrogen also helps to scavenge free radicals (e.g., O, OOH, OH) formed that would otherwise react with the hydrocarbon feeds. In some cases, a mole ratio of H2 / O2 may be less than 2 to compensate for other fuel gases or to have excess O2 in the mixing region to release heat to counter endothermic cracking reactions. In some cases, hydrogen is sub- stoichiometric (below 1) to allow for additional exothermic reactions in the mixing zone. The oxygen feed may provide an oxygen equivalent-to-fuel mole ratio of from 0.125 to 0.50.Furthermore, the ratio between the hydrocarbon feeds to hydrogen fuel will typically range from 1.0 to 15 based on mass depending on the hydrocarbon feed.

[0086] Steam or water may be introduced through manifold 62 and through inlets into the flow passage 48. Steam may be introduced upstream of the other feeds and may be used to cool the walls of the converging-diverging conduit 24 and reactor vessel 12. The introduced steam also reduces the reaction temperatures within the reactor 10. Steam may also be pre-mixed with the various feeds, such as with the liquid and gaseous hydrocarbon feeds, fuel gas, and / or oxy gencontaining feed. Steam may be used in a mass ratio of steam-to-fuel from greater than 0 to 10.0, more particularly from 0 to 2.0, in certain applications.

[0087] In practice, all of the oxygen gas and at least a portion of the hydrogen-containing fuel gas are typically combusted to form heated combustion products that are almost entirely mixed with the other feeds prior to exiting the converging-diverging conduit 24 and entering the reaction chamber 16. With the high centrifugal force of the swirling gases, the denser gases (e.g., cracking feed) flow closer to the reactor wall, 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 results in a back flow of the gas mixture within the reaction chamber 16. This mixture flows upstream and radially inward from the thin, outer annular mixed gas flow layers circulating within the reaction chamber 16. Internal cooling of the walls may occur due to the high swirling steam delivered through flow passage 48 in FIG. 2. Additional cooling (if necessary) occurs by a water jacket located between walls 14 and 18 in FIG. 2.

[0088] The liquid hydrocarbon feed introduced through the inlet 76 from nozzle 78 as a spray of droplets is immediately vaporized. The low liquid viscosity and small droplet size increase the speed with which the liquid feed is heated and vaporized. In various embodiments, there is no need for preheating the liquid hydrocarbon prior to its introduction into the reactor system 10. In certain instances, the liquid hydrocarbon may be preheated. This may be to reduce the viscosity to the viscosity range, previously discussed, to facilitate optimal droplet formation. Typical temperatures for the preheated liquid may range from 25 °C to 400 °C.

[0089] Based upon the type of hydrocarbon feeds, the operational conditions of the reactor 12 may vary. The gas residence time within the reactor 10 may range from 50 milliseconds or less, more particularly from 20 milliseconds or less. In particular embodiments, the residence time may range from20, 19, 18, 17, 16, 15, 14, 13, 12, 11, 10, 9, 8, 7, 6, 5, 4, 3, 2, 1 millisecond or less, with 10 microseconds being the approximate lowest residence time. The pressure atthe reactor outlet may vary. A suitable pressure at the reactor outlet may range from 0 kPa (g) to 10,000 kPa (g), more particularly from 0 kPa (g) to 1,000 kPa (g).

[0090] Reaction temperatures may range from 800 °C to 2500 °C where the lowest temperatures are found at the reactor exit when all the endothermic reactions are completed, and the highest temperatures are encountered in the combustion regions of the reactor (flame). The reaction temperature within the reactor and recirculation zone may range from 900 °C to 1300 °C. In particular embodiments, the temperature within the reactor and recirculation zone may range from 1000 °C to 1300 °C, more particularly from 1200 °C to 1250 °C. In some embodiments, the reactor temperature is higher than what is achieved in conventional cracking reactors, such as tube furnace reactors, which typically operate at 800 °C to 900 °C. As discussed earlier, this is due to the temperature limitations of the metallic materials used for such conventional reactors. In the ANJEVOC reactor, the swirling gas mixture keeps the walls of the reactor cooler than in such conventional cracking reactors. The use of such higher temperatures also allows a shorter residence or shorter contact times, resulting in better selectivity and conversion without formation of unwanted products. Operating temperatures for the reactor may be selected to avoid excess production of such unwanted compounds, such as CO and CO2, or optimize the olefm-to-acetylene ratio, as acetylene is typically not desired.

[0091] The flow of gases into the central chamber 58 through the flow passages 46, 48, 52, 54 is tailored so that the axial velocity (i.e., along the same direction as the central axis 28) is zero or nearly zero. The inlets (not shown) and / or the orientation of the guide vanes 68, 70, 72, 74 may be set for each flow passage 46, 48, 52, 54 so that a selected azimuthal-to-radial velocity ratio for each of the feed streams that flow through the flow passages 46, 48, 52, 54 is achieved, wherein the azimuthal and radial directions are defined in a cross-section perpendicular to the central axis 28 of the reactor 10. In particular, for each inlet, the radial direction is along a line that extends from the inlet to axis 28. The azimuthal direction is perpendicular to both this radial direction and the axial direction (i.e., the direction of axis 28). Returning to the azimuthal-to-radial velocity ratio, in particular embodiments, it may range from greater than 0 to 30 or more, more particularly 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 azimuthal- to-radial velocity ratio may range from > 0 to 5, more particularly from 2 to 4. The particular azimuthal-to-radial velocity ratio may vary depending upon the particular reactor configuration and composition of the various streams, however. This is more intimately related to the mixingtimes and reaction times depending on the flow rates, composition of the fuel and feedstocks used for cracking.

[0092] Converted hydrocarbon products produced in the reactor are removed from the reactor vessel 12 through outlet 20. The converted hydrocarbon products may be quenched within a quench zone of the reactor vessel 12 or they may be quenched exterior to the reactor vessel 12 in a quenching unit, such as a water-droplet-spray quench vessel, or other suitable gas quench device. The quenched products may be further processed and recycled, as discussed later on.

[0093] In a variation of the reactor described, additional hydrocarbon feed gas can be introduced as a secondary feed stream at an intermediate position along the length of reactor vessel 12, such as at inlet 82 (FIG. 2). One or more such inlets 82 may be provided at various locations and in the reactor vessel 12, which may be circumferentially and longitudinally spaced apart. The inlets 82 may be oriented or configured so that gases are introduced at an angle, as well, to facilitate swirling fluid flow, similar to that delivered from the inlets of the feed assembly 32. Feed assemblies provided on the reactor vessel 12 similar to the feed assembly 32 may be used for the introduction of such cracking feed gas so that the cracking feed is introduced as a swirling fluid flow.

[0094] In some embodiments, a plurality of reactor inlet assemblies and corresponding feed assemblies can be provided in a single reactor while maintaining the high performance.

[0095] The reactor system 10 described herein can be used to convert both gaseous and liquid hydrocarbons, such as crude oil, to produce higher value products, such as light olefins. The system features high conversion of the feed and higher selectivity for olefins in a single step process. There is no need for pretreatment, such as hydrotreating, hydroprocessing or removal of aromatics, of the crude oil or other hydrocarbons, such as occurs in conventional crude processing, prior to their introduction into the reactor. There is no need to preheat the crude or other liquid hydrocarbons. Due to the short residence time, olefins, unsaturates and / or aromatic content in the feedstock will not hinder cracking or conversion nor create excessive coking behaviors during the reaction, as these will merely pass through the reactor unchanged.

[0096] The reactor system 10 utilizing the liquid hydrocarbon feed with or without the gaseous hydrocarbon feed, such as those described previously, can be used to provide a variety of higher value products. These include any one or more of olefins, C2 to Ce olefins, ethylene, propylenes, butenes, acetylene, C3 to Ce alkynes, butadienes, aromatic compounds, xylenes, benzene, toluene, and ethyl benzene. Furthermore, at least a portion of any one or more of these products, such as C2 to Ce alkanes, xylenes, benzene, and toluene, in the reactor productstream may be separated from the reactor product stream and recycled to form at least a portion of the hydrocarbon reactant feeds. The ANJEVOC reactor can crack a broad range of hydrocarbons and the product slate is very narrow with primarily C2 + C3 products being formed, with some amount of carbon lost as CO and CO2.

[0097] Referring to FIG. 8, a schematic of a hydrocarbon processing system 90 and process flow for the conversion of liquid crude oil employing the reactor system 10 is shown. Crude oil 92 used as the liquid hydrocarbon feed may be any crude oil typically extracted from subterranean formations. The crude oil 92 may undergo minimal, if any, processing. In the embodiment shown, the only processing the crude oil 92 may undergo is an initial flashing or crude oil distillation in flash drum or unit 94 to remove asphaltenes and / or resins. An overheads liquid crude oil 98 from the unit 94 is injected directly into the axial liquid inlet 76 of the reactor 10. Asphaltenes and / or resins may be removed from a liquid crude oil bottoms 96 of the unit 94 to form a heavy crude oil stream 100. The heavy crude oil stream 100 with asphaltenes and / or resins removed may be combined with the overheads liquid crude oil 98 to form a combined liquid feed stream 102.

[0098] Conventional steam or naphtha cracker systems cannot use liquid crude oil due to the higher boiling point fractions that create coking within the furnace tubes. Moreover, liquid crude cannot be fed into preheaters of such steam or naphtha crackers because of coking, as well. Thus, the crude oil must be processed through distillation to remove the heavier fractions in conventional systems.

[0099] Oxygen and hydrogen gas fuel feeds 104, 106 are introduced into the reactor 10 to form swirling heated combustion gases to provide the elevated reaction temperature necessary for conversion. Steam 108 may also be introduced into the reactor 10, with the various feeds, or as its own feed stream, as described previously.

[0100] The liquid hydrocarbons in the combined liquid feed stream 102 introduced as a fine spray are immediately vaporized and mixed with the swirling hot combustion gases. The hydrocarbon reactant feed composed of the crude oil, and any other liquid or gaseous hydrocarbon feeds, mixes with the swirling hot combustion gases to form a swirling, heated mixture that passes from the central chamber 58 (FIG. 2) through the converging-diverging conduit 24 and into the reaction chamber 16 of the reactor system 10. The heated mixture reacts within the reaction chamber 16 so that the hydrocarbons of the hydrocarbon reactant feed are converted into a converted hydrocarbon product.

[0101] The converted products 110 will typically be a mixture of hydrogen gas, steam, oxygenates, some heavies (>C4), aromatics, and product olefins and alkynes. Typically, the products will include C2 to Ce olefins, ethylene, propylenes, butenes, acetylene, C3 to Ce alkynes, butadiene, and aromatic compounds, such as xylenes, benzene, toluene, and ethyl benzene.

[0102] Water 112 from quench water and / or condensed steam is separated from the converted hydrocarbon products to form separated conversion products 114. The conversion products 114 may then be introduced into a fractionator 116, where the products are fractionated to remove fuel oil 118. The fuel oil may be further processed in aromatics complex 120 to produce benzene, toluene and xylene products.

[0103] The remaining gaseous fraction 122 from fractionator 116 may be pressurized in compressor 124 and delivered to an amine treatment unit 126 for the removal or scrubbing of CO2 and / or H2S from the converted hydrocarbon products.

[0104] The scrubbed hydrocarbon products 128 from amine treatment unit 126 are then delivered to a separation train 130 where the various products are separated from one another. This may entail the separation of hydrogen gas, which may be recycled as hydrogen recycle stream 132, which may be combined with fresh hydrogen gas 134 to form hydrogen gas feed 106. Carbon monoxide (CO) and methane (CH4) 136 may be separated from the products in a membrane-based separation system of the separation train 130. Fuel oil and pygas from separation train 130 may be delivered to the aromatics complex 120 for the production of benzene, toluene and xylene products.

[0105] All or portions of the remaining hydrocarbon products (e.g., C2-C6 hydrocarbons) may be recycled as recycle stream 140 back to the reactor system 10 to form part of the liquid hydrocarbon reactant feed (e.g., the combined liquid feed stream 102). Butane 142 or other gaseous hydrocarbons, such as those previously described, may serve as a gaseous hydrocarbon feed. The gaseous hydrocarbon feed 142 may also be combined with the recycle stream 140 or added separately to form part of the liquid hydrocarbon reactant feed. This may be introduced with the liquid crude feed 98 and / or be fed through the one of the annular flow passages of the reactor 10, such as annular flow passage 46, as a swirling gas flow. Any nonrecycled hydrocarbon products 144 may be delivered elsewhere for further storage, processing, and / or use. All or portions of the benzene, toluene and / or xylene product stream 146 from aromatics complex 120 may also be recycled as recycle stream 148 to the reactor system 10 toform part of the hydrocarbon reactant feed 102. Any remaining benzene, toluene and / or xylene product from stream 146 may be delivered elsewhere for storage, processing, and / or use.

[0106] FIG. 9 shows a schematic of a further hydrocarbon processing system 150 and process flow for the conversion of liquid crude oil employing the reactor system 10. The system 150 is similar to the system 90 previously described, with similar components labeled with the same reference numerals. The system 150 provides additional downstream system components for processing of the converted hydrocarbon products.

[0107] As shown, the scrubbed hydrocarbon products 128 from the amine treatment unit 126 are further pressurized in compressor 152 and delivered to a cold box or other heat exchanger 154 for cooling hydrocarbon products 128. The cooled products 156 are then delivered to a hydrogen separator 158 where hydrogen gas is removed and delivered as hydrogen recycle 132 for fuel to the reactor 10, as with the system 90.

[0108] In the embodiment shown, the hydrogen-free hydrocarbon products 160 from separator 158 are first delivered to a front-end demethanizer 162 where overhead methane and carbon oxides (i.e., CO, CO2) can be removed by membrane separation as stream 164. The carbon oxides from stream 164 may be hydrogenated in converter unit 166. The resulting methane can then be recovered as fuel, such as for boilers or other uses.

[0109] The demethanized product 168 may be further processed in a deethanizer 170 to remove C2 hydrocarbons of ethane, ethylene and acetylene. The C2 compounds are removed as stream 172. This may be delivered to an acetylene converter unit 174, where the acetylene is hydrogenated to form ethylene and / or ethane. The ethylene and ethane product 176 may be further separated in C2 splitter 178 into ethane and ethylene product streams 180, 182, respectively, for further processing, use or storage.

[0110] The deethanized product 184 from deethanizer 170 may be delivered to a depropanizer 186 for the removal of C3 hydrocarbons, such as propane, propylene, methyl acetylene and propadiene. The removed C3 hydrocarbons 188 may be further processed to hydrogenate the methyl acetylene and propadiene (MAPD) in MAPD converter 190 to form propane and / or propylene. Propane and propylene products 192 from MAPD converter 190 may be separated in C3 separator 194 into propane and propylene product streams 196, 198, respectively, for further processing, use or storage.[OlH] The depropanized product stream 200 from depropanizer 186 may be delivered to a debutanizer 202 for the removal of C4 hydrocarbons 204, such as butane and the various unsaturated C4 isomers (e.g., butene, butyne, butadiene, etc.). Butane from product stream 204may be separated from the unsaturated C4 isomers in C4 splitter 206 to form butane and unsaturated C4 isomer product streams 208, 210, respectively, for further processing, use or storage. In the embodiment shown, the butane product stream 208 may be recycled and combined with the gaseous hydrocarbon or butane feed 142, which is delivered to reactor 10.

[0112] The debutanized product 212 from debutanizer 202, which is mainly composed of aromatics or pyrolysis gasoline (i. e. , pygas), may be delivered to the aromatics complex 120 to produce benzene, toluene and xylene products. Heavy oils, unreacted sulfur and heavy metal compounds may be removed from the aromatics complex 120 as stream 214.

[0113] FIG. 10 shows a schematic of another hydrocarbon processing system 220 and process flow for the conversion of liquid crude oil employing the reactor system 10 that uses a front-end depropanizer. The system 220 is similar to the systems 90 and 150, previously described, with similar components labeled with the same reference numerals. Unlike the system 150 of FIG. 9, after the scrubbed hydrocarbon products 128 from amine treatment unit 126 are pressurized in compressor 152, the products are first delivered to a high-pressure depropanizer 222. A front-end depropanizer does not facilitate the initial removal of CH4, CO, and H2, which leads to a lower partial pressure of C2H2. A lower partial pressure of C2H2 (e.g., less than 15 psig) helps prevent explosive decomposition. A front-end depropanizer scheme is therefore more suitable for high C2H2 production conditions.

[0114] The C1-C2 hydrocarbons are removed from the high-pressure depropanizer 222 as overhead stream 224. The bottoms 226 from the high-pressure depropanizer 222 contain C3 or greater hydrocarbons. The C1-C2 overheads 224 are delivered to an acetylene converter unit 228, where the acetylene in stream 224 is hydrogenated to form ethylene and / or ethane. The hydrogenated product 230 from acetylene converter 228 is delivered to a cold box or other heat exchanger 232 for cooling the hydrocarbon products 230. The cooled products 234 are then delivered to a hydrogen separator 236 where hydrogen gas is removed and delivered as hydrogen recycle 238 to be used as for fuel to the reactor 10, as with the systems 90 and 150.

[0115] The separated hydrogen-free products 240, which are composed of methane, ethane and ethylene hydrocarbons, are delivered to a demethanizer 242, where overhead methane and carbon oxides (i.e., CO, CO2) can be removed by membrane separation as stream 244. The carbon oxides from stream 244 may be hydrogenated in converter unit 246. The resulting methane stream 248 can then be recovered as methane fuel, such as for boilers or other uses.

[0116] The demethanized product 250 may be further processed in a deethanizer 252. The C2 compounds of ethane and ethylene from deethanizer 252 are removed as stream 254. Thismay be delivered to a C2 splitter 256 into ethane and ethylene product streams 258, 260, respectively, for further processing, use or storage.

[0117] The bottoms 226 from high-pressure depropanizer 222 that contains C3 or greater hydrocarbons is delivered to a low-pressure depropanizer 264. A C3 product stream 266 is removed as overheads from low-pressure depropanizer 264. The C3 product stream 266 is further processed in a MAPD converter 268 where methyl acetylene and propadiene are hydrogenated to form propane and / or propylene. The combined propane and propylene products 270 from MAPD converter 268 may be separated in C3 splitter 272 into propane and propylene product streams 274, 276, respectively, for further processing, use or storage.

[0118] The bottoms 278 from low-pressure depropanizer 264, which contains C4 or greater hydrocarbons, is delivered to debutanizer 280 for the removal of C4 hydrocarbons as product stream 282. Butane from C4 product stream 282 may be separated from the unsaturated C4 isomers in C4 splitter 284 to form butane and unsaturated C4 isomer product streams 286, 288, respectively, for further processing, use or storage. In the embodiment shown, the butane product stream 286 may be recycled and combined with the gaseous hydrocarbon or butane feed 142, which is delivered to reactor 10.

[0119] The debutanized product 290 from debutanizer 280, which is mainly composed of aromatics or pyrolysis gasoline (i. e. , pygas), may be delivered to the aromatics complex 120 to produce benzene, toluene and xylene products. Heavy oils, unreacted sulfur and heavy metal compounds may be removed from the aromatics complex 120 as stream 214, as with systems 90 and 150, previously discussed.

[0120] Referring to FIG. 11, another schematic of a hydrocarbon processing system 300 and process flow is shown. The system 300 is similar to the systems 90, 150, 220, previously described, with similar components labeled with the same reference numerals. The system 300 is most similar to the system 220, utilizing a front-end depropanizer, but differs in that there is no flash drum or other separation unit, such as the unit 94 of systems 90, 150, 220, to remove asphaltenes and / or resins from the liquid crude oil prior to its introduction into the reactor 10. Instead, the asphaltenes and resins that are not cracked are removed downstream from the ANJEVOC reactor 10 as stream 302. The asphaltenes and resins are knocked out through the water quench and condensed out with the water.

[0121] The system 300 further shows a hydrocarbon reactant feed 304 comprising liquid crude oil along with different gaseous hydrocarbons, such as ethane, propane, LPG, naphtha, etc. These gaseous hydrocarbons can be introduced with the liquid crude oil through the liquidfeed inlet 76 (FIG. 2), such as the second fluid of the two-fluid spray nozzle 78. Alternatively, or in addition, the gaseous hydrocarbons can be introduced into the reactor 10 through one or more of the annular flow passages, such as the flow passage 46, in a spiraling fluid flow pattern, as discussed previously.

[0122] The downstream processing of the product stream from reactor 10 in process system 300, and the products formed, is essentially the same as that described for the process system 220, utilizing the front-end depropanizer. The butane recycle stream 286 may be combined with the reactant feed 304 to form combined reactor feed 306.

[0123] The following examples serve to further illustrate various embodiments and applications.EXAMPLES

[0124] In the Examples below, different experimental runs were made in an ANJEVOC reactor system 10 as described herein using various liquid hydrocarbons with gaseous hydrocarbons. Each experimental run is shown as a different data point along the x-axes of Figures 12-15.EXAMPLE 1

[0125] Experiments were conducted with 20 wt% of liquid hydrocarbons with gaseous hydrocarbons to simulate the conversion of liquid and gas products. The liquids included distilled Arab light (AL) crude oil (approximately 35-40 wt% heavies removed) and wide range naphtha (WRN). Each of the liquid feeds of AL and WRN (shown in FIG. 12 as Oil) were fed with N-butane as the gaseous hydrocarbon into the ANJEVOC reactor 10. The N-butane gas was introduced through the flow passage 46 of the ANJEVOC reactor 10, while the liquid feed was introduced through a single-fluid nozzle 78. The AL crude oil had a dynamic viscosity of less than 10 cP and was introduced through the liquid feed inlet as a spray non-perpendicularly to the central axis of the central chamber of the feed assembly of the reactor. The liquid had a SMD size from 10 pm to 130 pm during injection. Hydrogen gas was used as the fuel and pure oxygen gas diluted with nitrogen (N2) was used as the oxidizer. The fuel and oxidizer were combusted in the central chamber of the feed assembly of the reactor to form swirling hot combustion gases for carrying out the cracking reactions. Flow rates of hydrogen, N-butane, oxygen and distilled AL or WRN were approximately 4.2, 13.0, 14.6, and 3 Ib / hr, respectively. The N-butane was preheated to approximately 350 °C and liquid hydrocarbons of AL andWRN were preheated to approximately 80 °C. The N-butane was fed together with approximately 5 Ib / hr of steam.

[0126] FIG. 12 shows selectivity in weight percent of light olefins and aromatics for approximately 20 wt% distilled AL crude oil and WRN with butane for Example 1. The selectivity for olefins and aromatics (high value chemicals) varied from 58%-66%, whereas for C2 olefins (ethylene and acetylene) selectivity varied from 52-62% depending on the operating conditions. Acetylene can be converted to ethylene via acetylene converter, as with the systems 150, 220, and 300, as described previously.

[0127] FIG. 13 shows conversion in percent and bulk gas temperatures in the ANJEVOC reactor for the 20 wt% feeds of AL crude oil and WRN as liquid with butane for Example 1. The carbon conversion (“C Conversion”) varied typically between 70% to 90% depending on experimental conditions. Bulk gas temperatures were measured at different locations in the reactor ranged between 600 °C-750 °C. The bulk gas temperatures shown in FIG. 13 were measured using different thermocouples located a plane perpendicular relative to the central axis of the reactor, with the measurements represented by the circular data points being located closer to the central axis of the reactor.EXAMPLE 2

[0128] FIG. 14 shows selectivity in weight percent of light olefins and aromatics for approximately 40 wt% Khuff gas condensate (KGC) crude oil with butane in an ANJEVOC reactor, such as the reactor 10 described herein. The butane gas was introduced through the flow passage 46 of the ANJEVOC reactor 10, while the liquid KGC crude oil was introduced through a two-fluid nozzle 78 with nitrogen gas as an atomizing gas. The KGC crude oil was introduced as a spray non-perpendicularly to the central axis of the central chamber of the feed assembly of the reactor. The spray had a SMD size from 10 pm to 130 pm during injection. The selectivity in weight percent for olefins and aromatics (high value chemicals) varied from 60%-67%, whereas for C2 and C3 olefins (ethylene and acetylene and propylene) varied from 56%-61% depending on the operating conditions. H2 flow rate was fixed at 4.2 Ib / hr and O2 flow ranged from 14.4 to 17.6 Ib / hr. Total hydrocarbons including KGC and N-butane varied between 16 and 20 Ib / hr. Nitrogen (as an atomizing gas) was introduced into the two-fluid nozzle 78 at 20 to 40 psig.EXAMPLE 3

[0129] FIG. 15 shows selectivity in weight percent of light olefins and aromatics for approximately 40 wt% Arab extra light (AXL) crude oil with butane in an ANJEVOC reactor, such as the reactor 10 described herein. The butane gas was introduced through the flow passage 46 of the reactor, while the AXL crude oil was introduced through a two-fluid nozzle 78 with nitrogen gas as an atomizing gas. The AXL crude oil and nitrogen were introduced as a spray non-perpendicularly to the central axis of the central chamber of the feed assembly of the reactor. The spray had a SMD size from 10 pm to 130 pm during injection. The weight % selectivity for olefins and aromatics (high value chemicals) varied from 63%-66%, whereas for C3 olefins (ethylene and acetylene and propylene) varied from 57-59% depending on the operating conditions. H2 flow rate was fixed at 4.2 Ib / hr and O2 flow ranged from 14.4 to 17.6 Ib / hr. Nitrogen (as an atomizing gas) was introduced into the two-fluid nozzle 78 at 20 to 40 psig. Total hydrocarbons including AXL and n-butane varied between 16 and 20 Ib / hr.

[0130] These examples show that heavy molecules are rapidly cracked and converted mainly into high value chemicals such as ethylene, acetylene and propylene in an ANJEVOC reactor. Product slates are much cleaner compared to conventional steam crackers. These examples also show that the reactor can directly process high boiling liquid up to ~40 wt%.

[0131] While the disclosure has been shown in some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes and modifications without departing from the scope of the disclosure based on experimental data or other optimizations considering the overall economics of the process. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the disclosure.

Claims

CLAIMSWe claim:

1. A method of converting hydrocarbons in a reactor system comprising a central axis, a feed assembly, and a reactor vessel that defines a reaction chamber, the method comprising: introducing a fuel gas feed and an oxidizer gas feed into the feed assembly to produce a swirling fluid flow pattern about the central axis, combusting the fuel gas feed and oxidizer gas feed in the feed assembly to form swirling combustion gases; introducing, into the feed assembly, a hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted, wherein the liquid hydrocarbon comprises a dynamic viscosity from 0.1 cP to 1000 cP at the temperature at which it is introduced and is introduced as a liquid spray having droplets with a Sauter Mean Diameter (SMD) from 1 pm to 250 pm, wherein the spray is introduced into the feed assembly in a flow pattern that is non-perpendicular to the central axis; mixing the hydrocarbon reactant feed with the swirling combustion gases to form a swirling, heated mixture in the feed assembly; passing the heated mixture from the feed assembly into the reaction chamber; reacting the heated mixture within the reaction chamber under reaction conditions suitable to convert the hydrocarbons of the hydrocarbon reactant feed into a converted hydrocarbon product; and removing the converted hydrocarbon product from the reaction chamber.

2. The method of claim 1, wherein the liquid hydrocarbon comprises at least one of crude oil, gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, a C20 to C40 hydrocarbon, a biomass-derived oil, a pyoil from plastic, a liquified plastic, a liquified plastic waste with impurities, and a heteroatom-containing hydrocarbon liquid.

3. The method of any of claims 1-2, wherein the liquid hydrocarbon makes up from 0.5 wt% to 100 wt% of the hydrocarbon reactant feed.

4. The method of any of claims 1-3, wherein the hydrocarbon reactant feed further comprises a gaseous hydrocarbon.

5. The method of claim 4, wherein the gaseous hydrocarbon comprises at least one of a natural gas liquid and a Ci to C20 hydrocarbon.

6. The method of any of claims 1-5, wherein the converted hydrocarbon product comprises at least one of an olefin, a C2 to Ce olefin, ethylene, propylene, butene, acetylene, a C3 to Ce alkyne, butadiene, an aromatic compound, xylene, benzene, toluene, and ethyl benzene.

7. The method of any of claims 1-6, further comprising: separating at least a portion of any one or more of a C2 to Ce alkane, xylene, benzene, and toluene from a reactor product stream containing the converted hydrocarbon product from the reactor product stream to form a separated stream; and recycling at least a portion of the separated stream to form at least a portion of the hydrocarbon reactant feed.

8. The method of any of claims 1-7, further comprising: separating at least a portion of any hydrogen gas (H2) in a reactor product stream containing the converted hydrocarbon product from the reactor product stream to form a separated hydrogen gas stream; and recycling at least a portion of the separated hydrogen gas stream to form at least a portion of the fuel gas feed.

9. The method of any of claims 1-8, wherein the liquid hydrocarbon is crude oil that has not been pretreated or refined other than to remove any of at least one of asphaltene, resin, sulfur compounds, and trace metals.

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

11. The method of any of claims 1-10, further comprising mixing steam with the fuel gas feed, the oxidizer gas feed, or the hydrocarbon reactant feed.

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

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

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

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

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

17. A method of converting hydrocarbons in a reactor system comprising i) a reactor vessel that defines a reaction chamber, ii) a smoothly-curved converging-diverging conduit having a central axis at an inlet of the reaction chamber, and iii) a feed assembly surrounding a central chamber through which the central axis passes that is in fluid communication with the converging-diverging conduit, the method comprising: introducing a fuel gas feed and an oxidizer gas feed into the central chamber surrounded by the feed assembly to produce a swirling fluid flow pattern about the central axis; combusting the fuel gas feed and oxidizer gas feed in the central chamber to form swirling combustion gases; introducing, into the central chamber through a two-fluid nozzle, a hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted and a second fluid, wherein the liquid hydrocarbon has a dynamic viscosity from 0.1 cP to 1000 cP at the temperature at which it is introduced and is introduced, into the central chamber, as a liquid spray of droplets with a Sauter Mean Diameter (SMD) from 1 pm to 250 pm in a flow pattern that is non-perpendicular to the central axis; mixing the hydrocarbon reactant feed with the swirling combustion gases to form a swirling, heated mixture in the central chamber; passing the heated mixture from the feed assembly into the reaction chamber;reacting the heated mixture within the reaction chamber under reaction conditions suitable to convert the hydrocarbons of the hydrocarbon reactant feed into a converted hydrocarbon product; and removing the converted hydrocarbon product from the reaction chamber.

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

19. The method of any of claims 17-18, wherein the hydrocarbon reactant feed further comprises a gaseous hydrocarbon, and wherein the second fluid is the gaseous hydrocarbon.

20. A reactor system for converting hydrocarbons, the reactor system comprising: a reactor vessel that defines a reaction chamber; a smoothly-curved converging-diverging conduit having a central axis at an inlet of the reaction chamber, the central axis extending along upstream and downstream ends of the converging-diverging conduit, wherein upstream and downstream refer to the relative position with respect to the direction of an overall fluid flow through the reactor system; a feed assembly surrounding a central chamber through which the central axis passes that is in fluid communication with the converging-diverging conduit; flow passages couplable and configured to introduce a fuel gas feed and an oxidizer gas feed into the central chamber to produce a swirling fluid flow pattern about the central axis; a liquid feed manifold couplable and configured to introduce, into the central chamber through a liquid feed inlet, a hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted; at least one spray nozzle within the liquid feed manifold and at an upstream end of the feed assembly, wherein the at least one spray nozzle is configured to introduce the liquid hydrocarbon as a liquid spray having a Sauter Mean Diameter (SMD) of droplets from 1 pm to 250 pm into the central chamber; and an outlet from the reaction chamber for removing the converted hydrocarbon product from the reaction chamber.

21. The reactor system of claim 20, wherein the at least one spray nozzle is further couplable and configured to introduce the liquid hydrocarbon into the central chamber in a flow pattern that is non-perpendicular to the central axis.

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

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

24. The reactor system of any of claims 20-23, further comprising a flow passage couplable and configured to introduce, into the central chamber of the feed assembly, a gaseous hydrocarbon to be converted.

25. The reactor system of any of claims 20-24, wherein the flow passages that are couplable and configured to introduce the fuel gas feed and the oxidizer gas feed are configured such that the fuel gas feed and the oxidizer gas feed pass through flow spaces in an inwardly swirling fluid flow pattern within said flow spaces so that the feeds flow about the central axis within the central chamber.

26. The reactor system of any of claims 20-25, wherein the liquid feed inlet is formed as a length of conduit that joins a feed assembly wall, wherein the conduit include an inlet axis that is aligned with and / or parallel to the central axis so that > 50% of the liquid hydrocarbon is introduced axially and non-perpendicularly with respect to the axis into the central chamber.

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

28. The reactor system of any of claims 20-27, wherein refractory materials are used for the interior of the inner reactor wall.

29. The reactor system of any claims 20-28, wherein the diverging portion of the converging-diverging conduit has an overall angle of divergence from 25° to 55° relative to the central axis.

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

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