Method and reactor for converting liquid hydrocarbons to higher value chemicals

Abstract

A method for converting hydrocarbons utilizes 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 in a swirling fluid flow pattern that combust to form swirling combustion gases. Hydrocarbon reactant feeds of natural gas liquid (NGL), natural gas condensate, or associated petroleum gas and a liquid hydrocarbon are introduced into the central chamber. The liquid feed is introduced as a liquid spray in a flow pattern that is non-perpendicular to the central axis. The hydrocarbon feed mixes with the swirling 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

METHOD AND REACTOR 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] Light olefins are an important chemical intermediate for producing a multitude of chemicals and plastics. They are produced by steam cracking of ethane, propane butane, natural gas liquids or light naphtha or heavier condensates or gas oils in steam crackers. The feedstocks mentioned for the steam cracker are generally obtained from either crude oil wells or natural gas wells. FIG. 1 shows a schematic of the current processing scheme of products from crude oil and natural gas wells. The crude output goes to a gas / oil separation plant where the gaseous components (associated petroleum gas) are fed- along with natural gas well output- to a gas fractionation unit. The gas fractionation unit separates methane and other non-condensable gases or inerts. The natural gas liquids (NGLs) are fed to a steam cracker to produce light olefins. The crude oil liquid from the gas / oil separator is the feedstock to an oil refinery or to an integrated refinery crude-to-chemical complex. The light naphtha produced from the refinery is sent to steam crackers. In addition, propylene and aromatics are also produced from fluid catalytic cracking of gas oils and heavy naphtha reforming, respectively. Conventionally these complexes (steam cracker / petrochemical complex and refinery) are not closely integrated.

[0003] In the modem crude-to-chemicals complex, the steam crackers and refinery units are integrated. FIG. 2 shows a schematic of an example conventional crude-to-chemicals systemand 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 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 slurry hydrocracking and made to diesel range cut, which then is hydrocracked again to produce light and heavy naphtha. The light and heavy naphthas are processed as mentioned before. Gas oils can optionally be fed to a 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. There are no existing reactor units that can simultaneously receive both liquid crude and gaseous feedstocks, such as NGLs, natural gas condensates, and associated petroleum gas, and make olefins and aromatics.

[0004] The typical output from a crude oil well includes liquid crude and associated gas. The associated gas is rich in C1-C4 alkanes with small amounts of pentane and hexane. These are typically fed into a gas fractionation plant along with the output of a natural gas well. Except for methane, the rest of the products, NGLs (i.e., ethane, propane, butane, and condensate) are fed to a steam cracker to make light olefins and aromatics. The NGLs (to steam cracker) and crude (to crude-to-chemicals complex) are sent to different processing systems to make the same product, i.e., light olefins and aromatics. The liquid crude can also be sent to a refinery where fuels and light olefins are produced, along with aromatics. The refineries that produce fuels have low return on investment and net margin compared with crude-to-chemicals complex. The crude-to-chemicals complex total fixed capital cost is quite high, however, due to a multitude of operations and hydroprocessing steps.SUMMARY

[0005] Illustrative embodiments of the present disclosure are directed to methods and systems for processing almost all products from an oil well as feedstocks to a single unit. Various methods and systems described herein obviate the need for conventional crude-to-chemicals and steam cracker systems and thus reduce complexity of operations, increase processingefficiency, and reduce capital expenditures.

[0006] 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 to form swirling combustion gases. Hydrocarbon reactant feeds comprising (i) at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas to be converted and (ii) a liquid hydrocarbon to be converted are 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 feeds are 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 and reacted within the reaction chamber under reaction conditions suitable to convert the hydrocarbons of the hydrocarbon reactant feeds into a converted hydrocarbon product. The converted hydrocarbon product is removed from the reaction chamber.

[0007] In certain applications, 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 may make up from 0.5 wt% to 99 wt% of the total hydrocarbon reactant feeds to the reactor in some applications. In others, the liquid hydrocarbon may make up from 5 wt% to 70 wt% of the hydrocarbon reactant feeds.

[0008] The liquid spray may be introduced as a two-fluid spray through a two-fluid nozzle so that the liquid hydrocarbon is introduced through the two-fluid nozzle with a second fluid. The second fluid of the two-fluid spray may be a gas.

[0009] The natural gas liquid (NGL), natural gas condensate, and / or associated petroleum gas of the reactant feed may be introduced as a gas.

[0010] 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. 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 toform at least a portion of the hydrocarbon reactant feeds. A portion of any hydrogen gas (H2) in the reactor product stream may be separated from the reactor product stream and recycled to form at least a portion of the fuel gas feed.

[0011] In particular embodiments, 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. Any one of the natural gas liquid (NGL), natural gas condensate, and / or associated petroleum gas and / or liquid hydrocarbon of the reactant feeds may be mixed with steam.

[0012] A further method of converting hydrocarbons is carried out 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 defining a central chamber through which the central axis passes that is in fluid communication with the converging-diverging conduit. A fuel gas feed and an oxidizer gas feed are introduced into the central chamber defined by 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 central chamber to form swirling combustion gases. Hydrocarbon reactant feeds comprising (i) at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas to be converted and a (ii) liquid hydrocarbon to be converted are introduced into the central chamber, wherein (i) the liquid hydrocarbon has a dynamic viscosity from 0.1 cP to 1000 cP, (ii) the liquid hydrocarbon is introduced as a liquid spray having a Sauter Mean Diameter (SMD) of droplets from 1 pm to 250 pm into the central chamber in a flow pattern that is non-perpendicular to the central axis, and (iii) the liquid hydrocarbon comprises at least one of crude oil, gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, and a C20 to C40 hydrocarbon. The hydrocarbon reactant feeds are mixed with the swirling combustion gases to form a swirling, heated mixture. The heated mixture is passed from the central chamber through the converging-diverging conduit and into the reaction chamber. The heated mixture reacts within the reaction chamber under reaction conditions suitable to convert the hydrocarbons of the hydrocarbon reactant feeds into a converted hydrocarbon product. The converted hydrocarbon product is removed from the reaction chamber.BRIEF DESCRIPTION OF THE DRAWINGS

[0013] For a more complete understanding of the embodiments described herein, and theadvantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying figures, in which:

[0014] FIG. 1 is schematic representation of a prior art processing system and process flow for producing products from crude oil and natural gas wells;

[0001] FIG. 2 is a schematic representation of a prior art crude-to-chemicals processing system and process flow for such system;

[0002] FIG. 3 is an elevational, cross-sectional view of a reactor system for the conversion of liquid hydrocarbons in accordance with various embodiments of the disclosure;

[0015] FIG. 4 is a perspective view of a feed assembly of the reactor system of FIG. 3 in accordance with various embodiments of the disclosure;

[0016] FIG. 5 is cross-sectional perspective view of the feed assembly and upstream end of a reaction chamber of the reactor system of FIG. 3;

[0017] FIG. 6 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. 3;

[0018] FIG. 7 is a plot showing the Computational Fluid Dynamics (CFD) calculations of spray evaporation in a reactor, such as that of FIG. 3, wherein all the liquid was vaporized within 5 mm from the injection point;

[0019] FIG. 8 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;

[0020] FIG. 9 is a schematic of a hydrocarbon processing system and process flow for the conversion of liquid crude oil and natural gas liquid (NGL), natural gas condensate, and associated petroleum gas employing the reactor system of FIG. 3, 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 and natural gas liquid (NGL), natural gas condensate, and associated petroleum gas employing the reactor system of FIG. 3 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 for the conversion of liquid crude oil and natural gas liquid (NGL), natural gas condensate, and associated petroleum gas employing the reactor system of FIG. 3 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 theconversion 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, along with associated petroleum gas produced along with such liquid crude oil, as well as natural gas liquids (NGL) and / or natural gas condensates that may be produced from natural gas wells) 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 a 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) 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 / 010823 Al, 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 rangelisted 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 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 the component. In a non-limiting example, 10 moles of component in 100 moles of the material is 10 mol% of component.

[0035] Referring to FIG. 3, 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. Thereactor 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 majority (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 32 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 isso 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 coincide 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. 3, 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," published in 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 withannular 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 utilized in de Laval nozzles, which have an angle of divergence of 15° or less. In, certain embodiments, the overall angle of divergence “A” (FIG. 3) 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 walls of the reactor chamber 14, as a result of the upstream swirling flow coupled with the convergent divergent nozzle 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 reactor 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 reactor feed assembly 32 is provided with the reactor 10. A perspective view of the feed assembly 32 is shown in FIG. 4. The reactor 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 reactor 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 centralaxis 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. 3, 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 gasflow 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 oxygen-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 oroxygen-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, the walls 34, 36, 38, 40, and 50 forming the different flow passages 46, 48, 52, 54 are parallel to one another. 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 and accommodates 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 feedsource, such as H2. The manifolds 60, 62, 64, 66 are provided with the reactor 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. 4, 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 allow movement. 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 the 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 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 dischargedinto 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 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 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.

[0064] 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 axis 28 into the central chamber 58. In other words, the liquid feeds introduced through the inlet 76 are not introduced perpendicularly to 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 sprayand / 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 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 placement radius PR is no greater than 30% of the radius of the central chamber 58. In other embodiments, the placement 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.

[0065] 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. In particular 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 is 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.

[0066] 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.

[0067] 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.

[0068] 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. 6 shows the vaporization times as a function of droplet size using a simplified calculation with approximate conditions in the reactor. FIG. 7 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 volumefraction 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).

[0069] 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 Dvo.s from 10 microns to 50 microns.

[0070] 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, 165 pm, 170 pm, 175 pm. In one specific embodiment, the spray nozzle is configured to form droplets with a Dvo.i from 5 microns to 25 microns.

[0071] 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, 125m, 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.

[0072] 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.

[0073] 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 twofluids 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.

[0074] The energy input to the spray nozzle is equal to the pressure drop across the nozzle multiplied by the flow rate. To obtain a targeted droplet size distribution, the choice of singlephase or two-phase nozzle depends on the pressure drop of the nozzles. The selection of a single-phase or two-phase nozzle also depends on various requirements (e.g., (i) spray angle, (ii) hollow vs. full spray cone, and (iii) internal mixing and external mixing to address fouling, which can be achieved using a two-phase nozzle). Furthermore, for the current application with hydrocarbons, spray nozzle selection 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.

[0075] 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 a gaseous 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. 8 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 minuteand 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.

[0076] If the desired droplet characteristics are not achieved, the droplets can take a 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.

[0077] 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.

[0078] Biomass-derived oils may include used cooking oil (UCO), palm fatty acid distillate (PF AD), used vegetable oil (UVO), hydrotreated vegetable oil (HVO), and tall oil, as well as other biomass-derived oils.

[0079] With respect to crude oil, 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 the range 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.

[0080] The liquid hydrocarbon converted with the reactor system 10 will typically make up from 0.5 wt% to 99 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%, and 99 wt% by total weight of the hydrocarbon reactant feedstock.

[0081] In various embodiments of the present disclosure, the liquid hydrocarbon will be converted in the reactor system 10 along with a gaseous hydrocarbon. As used herein, “gaseous hydrocarbon” or similar expressions 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. For example, the gaseous hydrocarbon may have a boiling point at 101.325 kPa (one atmosphere) no greater than 450 °C, no greater than 250°C, or no greater than 150°C. 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. 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 -butene, 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%.

[0082] 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.

[0083] In many instances, 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.

[0084] 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.

[0085] 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 flow passage 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 / orCO / 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 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.

[0086] 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.

[0087] 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 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.

[0088] 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 premixed with the various feeds, such as with the liquid and gaseous hydrocarbon feeds, fuel gas, and / or oxy gen-containing 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.

[0089] 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 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. 3. Additional cooling (if necessary) occurs by a water jacket located between walls 14 and 18 in FIG. 3.

[0090] 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.

[0091] Based upon the type of hydrocarbon feeds, the operational conditions of the reactor 10 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 at the 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).

[0092] 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.

[0093] 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 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 mixing times and reaction times depending on the flow rates, composition of the fuel and feedstocks used for cracking.

[0094] 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 10 or they may be quenched exterior to the reactor vessel 10 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.

[0095] 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. 3). 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.

[0096] 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.

[0097] By utilizing the reactor system 10, the total product from an oil well can be converted into high value chemicals, such as light olefins, in a single unit. This obviates the need for conventional crude-to-chemicals and steam cracker complex. In particular embodiments, the oil well product may exclude methane, which may become separated or removed from other petroleum gases. The reactor system 10 described herein can be used to convert both liquid hydrocarbons (i.e., crude) and gaseous hydrocarbons, such as NGLs, natural gas condensates, associated petroleum gases, as hydrocarbon reactant feeds that may be produced in an oil well in a single step to produce higher value products, such as light olefins. A typical NGL may contain from 0.5 mol% to 2 mol% methane, from 25 mol% to 45 mol% ethane, from 15 mol% to 35 mol% propane, from 1 mol% to 15 mol% each of n-butane and iso-butane, from 1 mol% to 5 mol% each of n-pentane and iso-pentane, and from 1 mol% to 10 mol% of higher alkanes, which will typically be hexane. A typical natural gas condensate may contain from 0. 1 wt% to 1 wt% Ci to C4, from 30 wt% to 40 wt% naphtha at a cut temperature of 185 °C, from 10 wt% to 20 wt% kerosene at a cut temperature from 185 °C to 245 °C, gasoil from 20 wt% to 35 wt% at a cut temperature from 245 °C to 365 °C, vacuum gas oil from 10 wt% to 25 wt% at a cut temperature from 365 °C to 565 °C, and residue from 1 wt% to 5 wt% at a cut temperature from 565 °C or higher. Such hydrocarbon reactant feeds (i.e., liquid and gas) maybe those produced and delivered from the same oil well(s). 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 hy dr otr eating, 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.

[0098] The reactor system 10 utilizing the hydrocarbon reactant feeds, 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 product stream 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.

[0099] Referring to FIG. 9, a schematic of a hydrocarbon processing system 90 and process flow for the conversion of both liquid crude oil and associated gas from a crude petroleum oil well 92 and, optionally, gas (i.e., NGLs and natural gas condensates) from a natural gas well 94, employing the reactor system 10 is shown. The crude oil well produces both liquid crude and associated petroleum gas as stream 96. The associated petroleum gas 98 may be separated from the produced liquid crude in gas / oil separator 100. In the embodiment shown, the associated gas 98 is combined with gas 102, which may be composed of methane, NGLs and natural gas condensates, produced from natural gas well 94 to produce hydrocarbon gas stream 104. In other embodiments, the hydrocarbon gas stream 104 is formed solely from the associated petroleum gas 98 produced from oil well 92.

[0100] The hydrocarbon gas stream 104 is delivered to a gas fractionator 106 where methane gas 108 is separated from the remaining associated petroleum gases, NGLs and gas condensates as gaseous hydrocarbon feed 110. This may be combined with a recycle stream 112 of gaseous hydrocarbons produced from downstream processes, as discussed later on.

[0101] The liquid crude 114 from gas / oil separator 100 may undergo minimal, if any, processing. In the embodiment shown, the only processing the crude oil 114 may undergo is an initial flashing or crude oil distillation in flash drum or unit 116. The heavies 118 from the bottom of unit 116 are sent to unit 120 to remove asphaltenes and / or resins via 119.

[0102] The heavy crude oil 121 with the asphaltenes and resins removed may be combined with the light liquid crude oil 122 from unit 116, along with the hydrogen gas feed 124 from combined hydrocarbon gas streams 110, 112, as a combined hydrocarbon gas / liquid reactant feed 126 that is introduced through the axial gas inlet 76 of the reactor 10. In other embodiments, the hydrocarbon gas feed 124 may be introduced separately from the light liquid crude oil 122, such as through the axial inlet 76 or through an annular flow passage, such as the upstream annular flow passage 46 of feed assembly 32. If introduced through the axial inlet 76, the hydrocarbon gas feed 124 may also be introduced through the spray nozzle 78 along with the liquid crude, where the nozzle 78 constitutes a two-fluid nozzle. Heavy crude oil stream 121 from top of asphaltene / resin removal unit 120 may be introduced along with the light liquid crude oil 122 or stand alone as the liquid feed to the nozzle 78.

[0103] Oxygen and hydrogen gas fuel feeds 130, 132 are introduced into the reactor 10 to form swirling heated combustion gases to provide the elevated reaction temperature necessary for conversion. Steam 134 may also be introduced, with the various feeds, or as its own feed stream into the reactor 10, as described previously.

[0104] The liquid crude introduced as the reactant feed 126 as a fine spray, as described previously, is immediately vaporized and mixed with the swirling hot combustion gases. The hydrocarbon reactant feed composed of the crude oil and the hydrocarbon gases from one or more of NGL, natural gas condensate, and associated petroleum gas from oil and gas wells 92, 94 mixes with the swirling hot combustion gases to form a swirling, heated mixture that passes from the central chamber 58 (FIG. 3) 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.

[0105] The converted products 136 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.

[0106] Water 138 from quench water and / or condensed steam is separated from the converted hydrocarbon products 136 to form separated conversion products 140. The conversion products 140 may then be introduced into a fractionator 142, where the products are fractionated to remove fuel oil 144. The fuel oil 144 may be further processed in aromatics complex 146 to produce benzene, toluene and xylene products 148. In certain embodiments, the benzene, toluene and xylene products 148 may be delivered to recycle stream 112 for recycling to the reactor 10.

[0107] The remaining gaseous fraction 150 from fractionator 142 may be pressurized in compressor 152 and delivered to an amine treatment unit 154 for the removal or scrubbing of CO2 and / or H2S from the converted hydrocarbon products.

[0108] The scrubbed hydrocarbon products 158 from amine unit 154 are further pressurized in compressor 160 and delivered to a cold box or other heat exchanger 162 for cooling hydrocarbon products 158. The cooled products 164 are then delivered to a hydrogen separator 166 where hydrogen gas is removed and delivered to form all or a portion of hydrogen gas stream 132 for use as fuel to the reactor 10.

[0109] In the embodiment shown, the hydrogen-free hydrocarbon products 168 from separator 166 are first delivered to a front-end demethanizer 170 where overhead methane and carbon oxides (i.e., CO, CO2) can be removed by membrane separation as stream 172. The carbon oxides from stream 172 may be hydrogenated in converter unit 174. The resulting methane can then be recovered as fuel, such as for boilers or other uses.

[0110] The demethanized product 176 may be further processed in a deethanizer 178 to remove C2 hydrocarbons of ethane, ethylene and acetylene. The C2 compounds are removed as stream 180. This may be delivered to an acetylene converter unit 182, where the acetylene is hydrogenated to form ethylene and / or ethane. The ethylene and ethane product 184 may be further separated in C2 splitter 186 into ethane and ethylene product streams 188, 190, respectively, for further processing, use or storage. In the case of ethane 188, this may be used to form part of the recycle stream 112 as part of the gaseous hydrocarbon reactor feed 126.[OlH] The deethanized product 192 from deethanizer 178 may be delivered to a depropanizer 194 for the removal of C3 hydrocarbons, such as propane, propylene, methyl acetylene and propadiene. The removed C3 hydrocarbons 196 may be further processed to hydrogenate the methyl acetylene and propadiene (MAPD) in MAPD converter 198 to form propane and / or propylene. Propane and propylene products 200 from MAPD converter 198 may be separated in C3 separator 202 into propane and propylene product streams 204, 206, respectively, forfurther processing, use or storage. In the case of propane 206, this may be used to form part of the recycle stream 112 as part of the gaseous hydrocarbon reactor feed.

[0112] The depropanized product stream 208 from depropanizer 194 may be delivered to a debutanizer 210 for the removal of C4 hydrocarbons 212, such as butane and the various unsaturated C4 isomers (e.g., butene, butyne, butadiene, etc.). Butane from product stream 212 may be separated from the unsaturated C4 isomers in C4 splitter 214 to form butane and unsaturated C4 isomer product streams 216, 218, respectively, for further processing, use or storage. In the case of butane 216, this may be used to form part of the recycle stream 112 as part of the gaseous hydrocarbon reactor feed.

[0113] The debutanized product 220 from debutanizer 210, which is mainly composed of aromatics or pyrolysis gasoline (i. e. , pygas), may be delivered to the aromatics complex 146 to form additional benzene, toluene and xylene products 148. Heavy oils, unreacted sulfur and heavy metal compounds may be removed from the aromatics complex 146 as stream 222.

[0114] FIG. 10 shows a schematic of a further hydrocarbon processing system 230 and process flow for the conversion of liquid crude oil from an oil well, along with associated petroleum gases, and NGLs and a natural gas condensates, such as from gas well 94. The system 230 is similar to the system 90, previously described, with similar components labeled with the same reference numerals. The system 230 employs the reactor system 10 but unlike the system 90 of FIG. 9, after the scrubbed hydrocarbon products 158 from amine unit 154 are pressurized in compressor 160, the products are first delivered to a high-pressure depropanizer 232. 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.

[0115] The C1-C2 hydrocarbons are removed from the high-pressure depropanizer 232 as overhead stream 234. The bottoms 236 from the high-pressure depropanizer 232 contain C3 or greater hydrocarbons. The C1-C2 overheads 234 are delivered to an acetylene converter unit 238, where the acetylene in stream 234 is hydrogenated to form ethylene and / or ethane. The hydrogenated product 240 from acetylene converter 238 is delivered to a cold box or other heat exchanger 242 for cooling the hydrocarbon products 240. The cooled products 244 are then delivered to a hydrogen separator 246 where hydrogen gas is removed and delivered as hydrogen recycle 248 where it may be combined with fresh hydrogen 250 to form hydrogen feed 132 to be used for fuel to the reactor 10, as with the system 90.

[0116] The separated hydrogen-free products 252, which are composed of methane, ethane and ethylene hydrocarbons, are delivered to a demethanizer 254, where overhead methane and carbon oxides (i.e., CO, CO2) can be removed by membrane separation as stream 256. The carbon oxides from stream 256 may be hydrogenated in converter unit 258. The resulting methane stream 260 can then be recovered as methane fuel, such as for boilers or other uses.

[0117] The demethanized product 262 may be further processed in a deethanizer 264 The C2 compounds of ethane and ethylene from deethanizer 264 are removed as stream 266. This may be delivered to a C2 splitter 268 into ethane and ethylene product streams 270, 272, respectively, for further processing, use or storage. In certain instances, all or a portion of the ethane 270 may be recycled as part of recycle stream 112.

[0118] The bottoms 236 from high-pressure depropanizer 232 that contains C3 or greater hydrocarbons is delivered to a low-pressure depropanizer 274. A C3 product stream 276 is removed as overheads from low-pressure depropanizer 274. The C3 product stream 276 is further processed in a MAPD converter 278 where methyl acetylene and propadiene are hydrogenated to form propane and / or propylene. The combined propane and propylene products 280 from MAPD converter 278 may be separated in C3 splitter 282 into propane and propylene product streams 284, 286, respectively, for further processing, use or storage. All or a portion of the propane 284 may be recycled as part of recycle stream 112.

[0119] The bottoms 288 from low-pressure depropanizer 274, which contains C4 or greater hydrocarbons, is delivered to debutanizer 290 for the removal of C4 hydrocarbons as product stream 292. Butane from C4 product stream 292 may be separated from the unsaturated C4 isomers in C4 splitter 294 to form butane and unsaturated C4 isomer product streams 296, 298, respectively, for further processing, use or storage. All or portion of the butane product stream 296 may be recycled as part of recycle stream 112.

[0120] The debutanized product 300 from debutanizer 290, which is mainly composed of aromatics or pyrolysis gasoline (i.e., pygas), may be delivered to the aromatics complex 146 to form benzene, toluene and xylene products 148. Heavy oils, unreacted sulfur and heavy metal compounds may be removed from the aromatics complex 146 as stream 222, as with system 90, previously discussed.

[0121] Referring to FIG. 11, another schematic of a hydrocarbon processing system 310 is illustrated. The system 310 is similar to the systems 90, 230, previously described, with similar components labeled with the same reference numerals. The system 310 also employs the reactor system 10. The system 310 is most similar to the system 230 of FIG. 10, utilizing afront-end depropanizer, but differs in that there is no flash drum or other separation unit, such as the unit 116 of systems 90, 230, to remove asphaltenes and / or resins from the liquid crude oil and hydrocarbon gas feed stream(s) 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 312. The asphaltenes and resins are knocked out through the water quench and condensed out with the water.

[0122] The downstream processing of the product stream from reactor 10 in process system 310, and the products formed, is essentially the same as that described for the process system 230, utilizing the front-end depropanizer.

[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 (e.g., NGLs, natural gas condensate, and an associated petroleum gas) produced from oil and gas wells. 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. The N-butane gas was introduced through the gas feed 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 defined by the feed assembly of the reactor. The spray 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 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 and WRN 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 Arab light crude oil and wide range naphtha 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.

[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 in 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 gas feed 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 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 gas feed 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 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 this reactor can directly process high boiling liquid up to approximately 40wt%.

[0131] While the invention 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 invention 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 invention.

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 to form swirling combustion gases; introducing a plurality of hydrocarbon reactant feeds into the feed assembly, the plurality of feeds comprising i) a first hydrocarbon reactant feed comprising at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas to be converted and ii) a second hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted, 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 as a liquid spray having droplets with a Sauter Mean Diameter (SMD) from 1 pm to 250 pm into the feed assembly in a flow pattern that is non-perpendicular to the central axis; mixing the first hydrocarbon reactant feed and the second 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 feeds 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 99 wt% of the hydrocarbon reactant feeds.

4. The method of any of claims 1-2, wherein the liquid hydrocarbon makes up from 5 wt% to 70 wt% of the hydrocarbon reactant feeds.

5. The method of any of claims 1-4, wherein the liquid spray is introduced as a two- fluid spray through a two-fluid nozzle so that the liquid hydrocarbon is introduced through the two-fluid nozzle with a second fluid.

6. The method of claim 5, wherein the second fluid is a gas.

7. The method of any of claims 1-6, wherein the at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas is introduced as a gas.

8. The method of any of claims 1-7, wherein the converted hydrocarbon product comprises 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.

9. The method of any of claims 1-8, further comprising: separating at least a portion of any one or more of a C2 to Ce alkane, a 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 feeds.

10. The method of any of claims 1-9, 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.

11. The method of any of claims 1-10, 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.

12. The method of any of claims 1-11, further comprising: mixing the at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas and / or liquid hydrocarbon with steam.

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

14. The method of any preceding claim, wherein: the first hydrocarbon reactant feed is introduced into the feed assembly through an inlet flow passage; and the second hydrocarbon reactant feed is introduced into the feed assembly through a liquid feed inlet.

15. The method of any preceding claim, further comprising modifying the liquid hydrocarbon of the second hydrocarbon reactant feed to have a dynamic viscosity from 0.1 cP to 1000 cP prior to or at its introduction.

16. The method of claim 15, wherein modifying the liquid hydrocarbon comprises heating the liquid hydrocarbon or combining the liquid hydrocarbon with a solvent or low viscosity component to lower the dynamic viscosity.

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 defining 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 through 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 formswirling combustion gases; introducing a plurality of hydrocarbon reactant feeds into the central chamber, the plurality of feeds comprising i) a first hydrocarbon reactant feed comprising at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas to be converted and ii) a second hydrocarbon reactant feed comprising liquid hydrocarbon to be converted into the central chamber, wherein the liquid hydrocarbon has a dynamic viscosity from 0.1 cP to 1000 cP at the temperature at which it is introduced, the liquid hydrocarbon is introduced as a liquid spray having droplets of a Sauter Mean Diameter (SMD) from 1 pm to 250 pm into the central chamber in a flow pattern that is non-perpendicular to the central axis, and the liquid hydrocarbon comprises at least one of crude oil, gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, and a C20 to C40 hydrocarbon; mixing the first hydrocarbon reactant feed and the second hydrocarbon reactant feed with the swirling combustion gases to form a swirling, heated mixture in the central chamber; passing the swirling, heated mixture from the central chamber through the converging-diverging conduit and into the reaction chamber; reacting the heated mixture within the reaction chamber under reaction conditions suitable to convert the hydrocarbons of the hydrocarbon reactant feeds into a converted hydrocarbon product; and removing the converted hydrocarbon product from the reaction chamber.

18. The method of claim 14, wherein the liquid spray is introduced as a two-fluid spray through a two-fluid nozzle so that the liquid hydrocarbon is introduced through the two-fluid nozzle with a second fluid.

19. A 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; and a feed assembly defining a central chamber through which the central axis passes that is in fluid communication with the converging-diverging conduit, the system comprisingflow passages couplable and configured to introduce a fuel gas feed and an oxidizer gas feed into the central chamber of the feed assembly to produce a swirling fluid flow pattern about the central axis; a flow passage couplable and configured to introduce, into the central chamber via the feed assembly, a first hydrocarbon reactant feed comprising at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas to be converted; and a liquid feed inlet couplable and configured to introduce, into the central chamber via the feed assembly, a second hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted.

20. The reactor system of claim 19, comprising a two-fluid nozzle couplable and configured to introduce, into the central chamber via the feed assembly, liquid spray as a two- fluid spray so that the liquid hydrocarbon is introduced through the two-fluid nozzle with a second fluid.

21. The reactor system of claim 20, comprising a second two-fluid nozzle couplable and configured to introduce, into the central chamber via the feed assembly, liquid spray as a two- fluid spray so that the liquid hydrocarbon is introduced through the second two-fluid nozzle.

22. The reactor system of any of claims 19-21, wherein the flow passages that are couplable and configured to introduce the fuel gas feed, the oxidizer gas feed and the first hydrocarbon reactant feed are configured such that the fuel gas feed, the oxidizer gas feed and the first hydrocarbon reactant feed pass through flow passages in an inwardly swirling fluid flow pattern within said flow passages so that the feeds flow about the central axis within the central chamber.

23. The reactor system of any of claims 19-22, 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 of the second hydrocarbon reactant feed is introduced axially and non-perpendicularly with respect to the axis into the central chamber.

24. The reactor system of claim 23, wherein the liquid feed inlet uses a liquid feed manifold to introduce the liquid of the second hydrocarbon reactant feed, wherein the manifold is fluidly coupled to a liquid feed source and comprises one or more spray nozzles that may be used to introduce the liquid of the second hydrocarbon reactant feed as a liquid spray into the central chamber in a flow pattern that is non-perpendicular to the central axis.

25. The reactor system of claim 24, wherein the one or more spray nozzles are configured to provide a Sauter Mean Diameter (SMD) or D32 of droplets from 1 pm to 250 pm under flow conditions of the reactor system.

26. The reactor system of any of claims 19 to 25, wherein the reactor vessel is formed from steel.

27. The reactor system of any of claims 19 to 26, comprising a cooling jacket provided around all or portions of the reactor vessel, wherein the cooling jacket is a second steel wall positioned around and spaced from an inner reactor wall.

28. The reactor system of claim 27, wherein refractory materials are used for the interior of the inner reactor wall.

29. The reactor system of any of claims 19 to 28, wherein the reactor system is an annular jet vortex reactor chamber (ANJEVOC) reactor system.

30. The reactor system of any of claims 19 to 28, further comprising: a source of the first hydrocarbon reactant feed, wherein the source of the first hydrocarbon reactant feed is coupled to the flow passage that is couplable and configured to introduce the first hydrocarbon reactant feed into the central chamber; and a source of the second hydrocarbon reactant feed, wherein the source of the second hydrocarbon reactant feed is coupled to the liquid feed inlet.

31. A method of converting hydrocarbons in a reactor system comprising a central axis, an 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 to form swirling combustion gases; introducing, through different inlets, a plurality of hydrocarbon reactant feeds into the feed assembly, the plurality of feeds comprising i) a first hydrocarbon reactant feed comprising at least one gaseous hydrocarbon to be converted having a boiling point at 101.325 kPa (one atmosphere) no greater than 450 °C and ii) a second hydrocarbon reactant feed comprising a liquid hydrocarbon to be converted; mixing the first hydrocarbon reactant feed and the second 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 feeds into a converted hydrocarbon product; and removing the converted hydrocarbon product from the reaction chamber.

32. The method of claim 31, 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.

33. The method of any of claims 31-32, wherein the liquid hydrocarbon makes up from 0.5 wt% to 99 wt% of the hydrocarbon reactant feeds.

34. The method of any of claims 31-32, wherein the liquid hydrocarbon makes up from 5 wt% to 70 wt% of the hydrocarbon reactant feeds.

35. The method of any of claims 31-34, wherein the liquid spray is introduced as a two- fluid spray through a two-fluid nozzle so that the liquid hydrocarbon is introduced through the two-fluid nozzle with a second fluid.

36. The method of claim 35, wherein the second fluid is a gas.

37. The method of any of claims 31-36, wherein the at least one gaseous hydrocarbon comprises at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas.

38. The method of any of claims 31-37, wherein the converted hydrocarbon product comprises at least one of an olefin, a C2 to C6 olefin, ethylene, a propylene, a butene, acetylene, a C3 to C6 alkyne, a butadiene, an aromatic compound, a xylene, benzene, toluene, and ethyl benzene.

39. The method of any of claims 31-38, further comprising: separating at least a portion of any one or more of a C2 to C6 alkane, a 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 feeds.

40. The method of any of claims 31-39, 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.

41. The method of any of claims 31-40, 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.

42. The method of any of claims 31-41, further comprising: mixing the at least one of a natural gas liquid (NGL), a natural gas condensate, and an associated petroleum gas and / or liquid hydrocarbon with steam.

43. The method of any of claims 31-42, wherein the reactor system is an annular jet vortex reactor chamber (ANJEVOC) reactor system.

44. The method of any of claims 31-43, wherein: the first hydrocarbon reactant feed is introduced into the feed assembly through an inlet flow passage; and the second hydrocarbon reactant feed is introduced into the feed assembly through a liquid feed inlet.

45. The method of any of claims 31-44, further comprising modifying the liquid hydrocarbon of the second hydrocarbon reactant feed to have a dynamic viscosity from 0.1 cP to 1000 cP prior to or at its introduction.

46. The method of claim 45, wherein modifying the liquid hydrocarbon comprises heating the liquid hydrocarbon or combining the liquid hydrocarbon with a solvent or low viscosity component to lower the dynamic viscosity.

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