Method and system for producing chemicals from hydrocarbon streams

Abstract

A system and methods converting hydrocarbons in a petrochemicals complex are provided. An exemplary method includes separating a butadiene product stream from a raw C4 stream to form a C4 stream. Hydrocarbon reactant feeds including (i) a gaseous hydrocarbon stream including the C4 stream and (ii) a liquid hydrocarbon stream are introduced into a combustion reactor. The gaseous hydrocarbon stream and the liquid hydrocarbon stream are converted within the combustion reactor to form a converted hydrocarbon product. The converted hydrocarbon product is removed from the combustion reactor and a product stream is separated from the converted hydrocarbon product.

Description

METHOD AND SYSTEM FOR PRODUCING CHEMICALS FROM HYDROCARBON STREAMSTechnical Field

[0001] This disclosure relates to methods of producing chemicals from hydrocarbon streams.Background

[0002] Conventional crude-to-chemicals industrial complexes use crude distillation to produce various fractions, such as light hydrocarbons (e.g., C1-C4), naphtha, kerosene, diesel, gasoil, and residue. Each of these streams are processed separately or differently, such as hydrotreating or hydrocracking, naphtha reforming, fluid catalytic cracking, and / or used as a feedstock for steam cracking, aromatic complex, and / or naphtha reforming to produce the higher value products of light olefins and aromatics. These methods of processing feedstocks produce significant quantities of C4 alkanes (N-butanes, Iso-butanes), liquefied petroleum gas (LPG, which includes propane and butane mixtures) and some off gases. In current processes, the crude-to-chemicals complex makes other chemicals like oxygenates (methyl, tertiary butyl ether (MTBE), butadienes, etc.) to improve profitability. The value or profit margin of these products bring are subjected to market dynamics of these low volume chemicals and derivatives.

[0003] FIG. 1 shows a schematic of an exemplary conventional crude-to-chemicals system and process flow for such system. As shown, the system comprises a desalter feeding a crude separation unit, where crude oil is fractionated to atmospheric residue and naphtha, along with kerosene and diesel cuts. The naphtha cut is optionally hydrotreated and may be split to light and heavy naphtha. A light naphtha fraction is sent to a steam cracker. The naphtha reformate is a feedstock to the aromatics complex, which produces paraxylene and benzene. The C5+ and pygas from the steam cracker is also fed to the aromatics complex to produce paraxylene and benzene. As used herein, pygas or pyrolysis gasoline is a product that includes aromatics, olefins, and paraffins with Cs to C12 carbons.

[0004] The vacuum residue from the distillation column can be sent to a residue hydrocracker (slurry or ebullated process) to produce ultra-low sulfur fuels (ULSFO)and a vacuum gas which is hydrocracked to form products that are fed to the steam cracker. A number of product streams are isolated from effluents from the steam cracker, and further processed to for final products.

[0005] As can be seen multiple processing units and steps are required to process the various individual products to produce light olefins and aromatics. In the present disclosure, light olefins and chemical intermediates are produced using the raw C4 hydrocarbons, LPG and off gases from the crude-to-chemicals complex with high carbon efficiency, low capital intensity, and simpler operational procedure.

[0006] Conventional thermal cracking technologies such as steam cracking generates C4 - C9 olefins as byproducts. The C4 olefins are typically routed to a butadiene recovery unit followed by an MTBE unit and then to other processes such as butene-1 recovery or metathesis, among others. Remaining C4 olefins are typically hydrogenated and recycled back to the cracker unit.

[0007] MTBE is a gasoline blending component that is used to boost octane. However, as gasoline demand decreases, more C4 olefins will be available for conversion to more value-added products. The conventional route of hydrogenation and recycle to a cracker has a relatively higher CAPEX / OPEX, H2 loss, additional energy requirement, and a lower carbon retention.

[0008] Similarly, after aromatics recovery, a C5-C9 olefin rich stream is hydrotreated and mixed with gasoline in a conventional cracker complex. As gasoline demand declines, the expected route for a C5-C9 olefin rich streams will be hydrogenated and recycled to a cracker. This would again result in relatively higher CAPEX / OPEX, H2 loss, additional energy requirement, and lower carbon retention.

[0009] Thus, a better strategy is needed to manage C4-C9 olefins when gasoline demand erodes. The strategy should consider a wide feed composition flexibility and high yield of high value chemicals (HVC).Summary

[0010] An embodiment described herein provides a method of converting hydrocarbons in a petrochemicals complex. The method includes separating a butadiene product stream from a raw C4 stream to form a C4 stream. Hydrocarbon reactant feeds including (i) a gaseous hydrocarbon stream including the C4 stream and (ii) a liquid hydrocarbon stream are introduced into a combustion reactor. The gaseoushydrocarbon stream and the liquid hydrocarbon stream are converted within the combustion reactor to form a converted hydrocarbon product. The converted hydrocarbon product is removed from the combustion reactor and a product stream is separated from the converted hydrocarbon product.

[0011] In an aspect, combinable with any other aspect, the method includes separating a crude oil feedstock into a gas stream, a liquid stream, and a heavies stream and separating the gas stream into a first raw C4 stream and a lights stream. The heavies stream is cracked to form a heavy liquid stream. The liquid stream, the lights stream, and the heavy liquid stream are cracked to form a product stream, a second raw C4 stream, and a pygas stream. The first raw C4 stream and the second raw C4 stream are combined to form the C4 stream. In an aspect, the method includes separating aromatics from the pygas stream forming an intermediate liquid stream and feeding the intermediate liquid stream to the combustion reactor.

[0012] In an aspect, combinable with any other aspect, the liquid hydrocarbon stream includes 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 liquefied plastic, a liquefied plastic waste with impurities, and a heteroatomcontaining hydrocarbon liquid.

[0013] In an aspect, the liquid hydrocarbon stream makes up from 0.5 wt% to 99 wt% of the hydrocarbon reactant feeds.

[0014] In an aspect, the liquid hydrocarbon stream makes up from 5 wt% to 70 wt% of the hydrocarbon reactant feeds.

[0015] In an aspect, combinable with any other aspect, the raw C4 stream includes at least one of butane, n-butane, i-butane, butene, 1 -butene, 2-butene, cis-2-butene, trans-2-butene, 2- methylpropene, butadiene, 1 -2-butadiene, 1-3 -butadiene, butyne, 1- butyne, and 2-butyne.

[0016] In an aspect, combinable with any other aspect, the converted hydrocarbon product includes 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.

[0017] In an aspect, combinable with any other aspect, the method includes separating at least a portion of any one or more of a C2 to Ce alkane, a xylene, benzene, and toluene from the converted hydrocarbon product to form a separated stream, andrecycling at least a portion of the separated stream to form at least a portion of the hydrocarbon reactant feeds.

[0018] In an aspect, combinable with any other aspect, the liquid hydrocarbon stream includes a 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.

[0019] In an aspect, combinable with any other aspect, at least one of the gaseous hydrocarbon stream and liquid hydrocarbon stream is mixed with steam.

[0020] In an aspect, combinable with any other aspect, the combustion reactor includes a central axis, a feed assembly, and a reactor vessel that defines a reaction chamber.

[0021] In an aspect, the method includes introducing a fuel gas feed, an oxidizer gas feed, the gaseous hydrocarbon stream, and the liquid hydrocarbon stream into the feed assembly, wherein the gaseous hydrocarbon stream and the liquid hydrocarbon stream form a swirling fluid flow pattern about the central axis. The fuel gas feed and oxidizer gas feed are combusted to form swirling combustion gases, wherein the gaseous hydrocarbon stream and the liquid hydrocarbon stream are mixed with the swirling combustion gases to form a heated mixture. The heated mixture is passed from the feed assembly into the reaction chamber. The heated mixture is reacted within the reaction chamber under reaction conditions suitable to convert the hydrocarbon reactant feeds into the converted hydrocarbon product.

[0022] In an aspect, the method includes separating at least a portion of any hydrogen gas (H2) from the converted hydrocarbon product 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.

[0023] In an aspect, the liquid hydrocarbon stream is introduced into the feed assembly as a spray including a Sauter Mean Diameter (SMD) of droplets between from 1 pm and 250 pm.

[0024] In an aspect, the liquid hydrocarbon stream is introduced into the feed assembly as a spray and the liquid hydrocarbon stream includes a dynamic viscosity from 0.1 cP to 1000 cP.

[0025] In an aspect, combinable with any other aspect, the combustion reactor is an annular jet vortex reactor chamber (ANJEVOC) reactor system.

[0026] In an aspect, combinable with any other aspect, the gaseous hydrocarbon stream and the liquid hydrocarbon stream are converted to form a converted hydrocarbon product within the combustion reactor without use of a catalyst.

[0027] Another embodiment described herein provides a petrochemicals complex. The petrochemicals complex includes a combustion reactor. The combustion reactor includes a gaseous hydrocarbon inlet fluidically coupled to the combustion reactor, a liquid hydrocarbon inlet fluidically coupled to the combustion reactor, and a converted hydrocarbon outlet. The petrochemicals complex includes a butadiene recovery unit. The butadiene recovery unit includes a butadiene separation system, an inlet coupled to a raw C4 stream, a butadiene outlet, and a BD raffinate outlet including a BD raffinate. The petrochemicals complex includes a fluidic coupling from the BD raffinate outlet to the gaseous hydrocarbon inlet and a fluidic coupling from a liquid hydrocarbon stream to the liquid hydrocarbon inlet.

[0028] In an aspect, combinable with any other aspect, the raw C4 stream includes at least one of butane, n-butane, i-butane, butene, 1 -butene, 2-butene, cis-2-butene, trans-2-butene, 2- methylpropene, butadiene, 1 -2-butadiene, 1-3 -butadiene, butyne, 1- butyne, and 2-butyne.

[0029] In an aspect, combinable with any other aspect, the BD raffinate includes at least one of butane, n-butane, i-butane, butene, 1 -butene, 2-butene, cis-2-butene, trans- 2-butene, 2- methylpropene, butyne, 1 -butyne, and 2-butyne.

[0030] In an aspect, combinable with any other aspect, the liquid hydrocarbon stream includes 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 heteroatomcontaining hydrocarbon liquid.Brief Description of Drawings

[0031] FIG. 1 shows a schematic of an exemplary conventional crude-to-chemicals system and process flow for such system.

[0032] FIG. 2 is an elevational cross-sectional view of an ANJEVOC reactor system for the conversion of liquid hydrocarbons.

[0033] FIG. 3 is a block diagram of a crude to chemicals complex with a steam cracker and a combustion reactor, such as the ANJEVOC reactor described with respect to FIG. 2.

[0034] FIG. 4 is a block diagram of a combustion reactor complex, for example, using the ANJEVOC reactor described with respect to FIG. 2.

[0035] FIG. 5 is a drawing of another hydrocarbon processing system and process flow for the conversion of liquid crude oil employing the reactor complex in combination with a crude-to-chemicals conversion system.

[0036] FIG. 6 is a process flow diagram of a method for recycling hydrocarbon streams in a chemical process.Detailed Description

[0037] As described herein, a typical crude to chemicals comprises a crude distillation unit, where crude oil is fractionated to naphtha, diesel cut, and atmospheric residue. The naphtha cut is optionally hydrotreated and send to steam cracker. The diesel cut is hydrotreated to remove sulfur compounds, then fed to a hydrocracker to make naphtha range material which is fed to a steam cracker. The atmospheric residue cut along with the pyoil from the steam cracker is sent to a residue hydrocracker (slurry or ebullated process) and the product is further processed in hydrocracker to make naphtha range material which is again fed to steam cracker. The steam cracker unit effluent stream is separated into various fractions as shown in FIG. 1.

[0038] As shown in FIG. 1, a C4 raw stream formed in the cracker is routed to a butadiene recovery unit to recover high value butadiene product. Raffinate from this unit is routed to an MTBE unit to consume isobutylene to form a more valuable product, MTBE, which is used as a gasoline octane booster. The raffinate from MTBE unit can be directly processed in a conventional catalytic olefin cracking process or hydrogenated and recycled back to the steam cracker.

[0039] The C5+ and pygas from the steam cracker is fed to the aromatics complex (BTX extraction) to extract benzene, toluene, and xylenes (BTX). A C5+ olefin stream remaining after BTX extraction can be hydrotreated for gasoline blending or hydrotreated and saturated before recycling back to the steam cracker.

[0040] As fuel producing refineries are expected to have excess C4-C9 olefins when gasoline demand starts eroding, C4 olefins which are currently sent to MTBE oralkylation units will be available. Further, C5-C9 olefins from catalytic cracking units which are currently hydrotreated and blended in a gasoline pool will also be available. Adding a combustion reactor as described herein, will help refineries to use these olefins and crack to high value chemicals (HVCs) with minimum investments and without (or minimum) impact on existing assets. Small refiners can also make on purpose HVCs from heavier olefins produced on purpose using processes such as a methanol to olefins process.

[0041] FIG. 2 is an elevational cross-sectional view of a reactor 10 for the conversion of liquid hydrocarbons. The reactor 10 is a combustion reactor that combusts hydrogen or natural gas or fuel and oxygen to crack hydrocarbons. In this embodiment, the reactor 10 uses an annular jet vortex, termed an ANJEVOC reactor, to achieve extremely fast mixing and minimize contact time. The ANJEVOC reactor serves as a combustor to generate heat, a cracker, and a single processing unit for crude oil fractions to produce light olefins. As described below, the ANJEVOC reactor is a very high throughput millisecond reactor with near adiabatic operations with internal cooling. It provides high light olefins yields and is able to process difficult and mixed feedstocks with very high per-pass conversions. Further, various embodiments of the ANJEVOC reactor eliminate tube coking issues present in conventional steam crackers, by operating without the use of narrow and long process tubes.

[0042] The ANJEVOC reactor can produce ethylene, propylene, butenes, and BTX from a feed comprising of liquid crude and gaseous ethane, propane, or butane. The expected capacity of a single unit, furnace equivalent, is 200-500 kTA ethylene. The feed to the ANJEVOC reactor typically does not need the hydrotreating and hydroprocessing generally used in the state-of-the-art crude to chemical complex (FIG. 1). Due to low residence time, olefins, unsaturated compounds, and aromatics are subject to few combination reactions and thus coke formation due to these compounds is minimal. The hydrocarbon molecules are cracked preferably to light olefins with some breakthrough of aromatics. Crude oil in its liquid form is directly injected into the ANJEVOC reactor with or without pre-heating. The liquid injection is typically carried out by a single phase or optionally by a two-phase spray nozzle where the liquid is crude oil and the vapor phase in the spray is steam. The ANJEVOC reactor uses hydrogen (H2), natural gas, carbon monoxide (CO), a fossil gas mixture, or acombination thereof as fuel and an oxidant (such as oxygen (O2)) with appropriate steam dilution to provide the heat for the endothermic cracking reactions.

[0043] As described, the reactor 10 is configured for the conversion of liquid hydrocarbons. As used herein, liquid hydrocarbons include crude oil, crude oil fractions, gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, a C20 to C40 hydrocarbon, and like. The reactor 10 can also be used to convert gaseous hydrocarbons in conjunction with the liquid hydrocarbons. The reactor 10 constitutes a combustion reactor. As used herein, a combustion reactor is a chemical reactor that receives hydrocarbon, fuel, and oxidizer feeds and sustains a chemical reaction using oxidation of the fuel feed through the process of combustion. The combustion reactor commingles the hydrocarbon, fuel, and oxidizer feeds and at least partially cracks the hydrocarbon feed using the heat generated by the process of combustion. In some embodiments, the combustion reactor 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.

[0044] The reactor vessel 12 may be formed from steel and alloys of steel, such as Inconel and other corrosion resistant allows. In certain embodiments, a cooling jacket can be provided around all or portions of the reactor vessel, wherein a second steel wall 18 is positioned around and spaced from the reactor wall 14 and a cooling fluid, such as water may be circulated through the jacket formed between the walls 14 and 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-velocitynear- 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 10 will typically range from 800 °C to 2500 °C.

[0045] 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 the 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.

[0046] The reactor 10 includes a reactor feed assembly 22 that is coupled or joined to the upper or upstream end of the reactor wall 14 of the reactor vessel 12. In the view of FIG. 2, the reactor vessel 12 is oriented vertically with the reactor feed assembly 22 located above the reactor vessel 12. This is so that any downstream liquid quenching fluids (e.g., water) that are used within the reaction chamber 16 to quench the reaction gases are carried by gravity to the outlet 20 and not towards the upstream end towards the reactor feed assembly 22.

[0047] The reactor feed assembly 22 has a converging-diverging conduit 24 defined by a circumferential wall 26 that surrounds a central longitudinal axis 28 of the reactor 10, which, in various embodiments, is the same or coincides with the central longitudinal axis of each of the reactor feed assembly 22 the conduit 24, and / or 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 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.

[0048] As can be seen in FIG. 2, the circumferential wall 26 smoothly tapers in width or diameter from the downstream and upstream ends of the convergingdiverging conduit 24 to an annular constricted neck portion located between the downstream and upstream ends where the circumferential wall 26 of the conduit 24transitions from converging or narrowing to diverging or widening. 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 reactor feed assembly 22, with the constricted neck portion forming a smoothly curved and streamlined converging-diverging nozzle of the reactor feed assembly 22.

[0049] 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. 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. De Laval nozzles are convergent divergent nozzles that are carefully designed to choke at the throat (Mach # 1) and create supersonic conditions downstream without separation by limiting the angle of the expansion zone. In various embodiments, the diverging conduit 24 does not form such supersonic flow or 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 longitudinal axis 28 in combination with annular swirling jet gas flow adjacent to the inner surface of the 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. 2) relative to the axis 28 may be from 25° or more. In particular instances, the angle of divergence A for the diverging portion of the conduit 24 discussed herein is from 25° to 55°. In some embodiments, the angle of divergence A is of from at least, equal to, and / or between any two of 25°, 26°, 27°, 28°, 29°, 30°, 31°, 32°, 33°, 34°, 35°, 36°, 37°, 38°, 39°, 40°, 41°, 42°, 43°, 44°, 45°, 46°, 47°, 48°, 49°, 50°, 51°, 52°, 53°, 54°, and 55°. The large divergence angle leads to recirculation of fluid flow at the walls of the reactor 14, as a result of the upstream swirling flow coupled with the converging-diverging conduit 24.

[0050] The downstream end of the diverging portion of conduit 24 joins the reactor wall 14 at an inlet of the reaction chamber 16 around its perimeter so that the conduit 24 is in fluid communication with the reaction chamber 16 of the reactorvessel 12. The upstream end of the converging portion of conduit 24 forms an inlet for the reactor vessel 12.

[0051] The reactor feed assembly 22 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 22. The reactor feed assembly 22 includes a downstream feed assembly wall 34 that extends circumferentially around and joins the upstream end of the converging portion of conduit 24.

[0052] Axially spaced upstream from the downstream wall 34 along the central axis 28 is an upstream feed assembly wall 36.

[0053] 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. 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.

[0054] Referring to FIG. 2, the upstream partition wall 38 defines an annular gas flow passage 46 located between the upstream feed assembly wall 36 and the upstream side of the upstream partition wall 36. In the embodiment shown, the flow passage 46 constitutes an upstream annular hydrocarbon reactant feed inlet flow passage for introducing a gaseous hydrocarbon to be converted. 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 48may constitute an annular steam or water inlet flow passage. 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.

[0055] In the embodiment shown, the annular flow passage 52 may constitute an oxygen or oxidizing gas flow passage to facilitate combustion. The annular flow passage 54 may constitute a fuel gas (e.g., H2, CH4, syngas or a combination of these) flow passage for introducing a fuel gas for combustion.

[0056] 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 reactor feed assembly 22 that surrounds the central axis 28. The central axis 28 also coincides with and forms a central axis of the central chamber 58 and reactor feed assembly 22.

[0057] This configuration provides flow passages through which feeds, including gas feeds to be cracked, steam, oxygen gas, and / or hydrogen-rich fuel for providing combustion heat, can each be separately introduced. The feeds are passed through the flow passages 46, 48, 52, 54, respectively, and into the central chamber 58 of the feed assembly 22 in a swirling fluid flow pattern about the central axis 28. The feeds combust in the central chamber 58 to form swirling combustion gases. The feeds are introduced into the central chamber in a direction that is non-parallel, substantially perpendicular, or perpendicular to the central axis 28.

[0058] In some embodiments, the upstream flow passage 46 will constitute a gaseous hydrocarbon feed inlet flow passage. A fuel gas feed comprised of an hydrogen-rich gas feed (i.e. , H2) may be introduced into one of the first and second adjacent annular fuel gas inlet flow passages 52, 54, with an oxidizer (i.e., O2) or oxy gen-containing gas feed being introduced into the other of the flow passages 52, 54. Typically, the fuel and oxygen gas feeds will be introduced into flow passages thatare immediately adjacent to one another to facilitate rapid combustion. In certain applications, the downstream flow passage 52 may be used for delivering the oxidizer or oxy gen-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 reversed or altered in other sequences within the flow passages 46, 48, 52, 54. 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 oxygen containing gas feed, or the hydrocarbon gas feed.

[0059] In certain embodiments, one or more of the flow passages 46, 48, 52, 54 may remain idle or be eliminated in the construction of the reactor feed assembly 22. If eliminated, this may be achieved by removal or elimination of one of the partition walls 38, 40, 50 to reduce the number of flow passages. In such instances, certain feeds may be combined and introduced together, such as the steam feed previously discussed.

[0060] The 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.

[0061] The walls 34, 36, 38, 40, and 50 forming the different flow passages 46, 48, 52, 54 may be parallel to one another in many cases, but may be non-parallel to one another in certain cases. 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 that 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 to accommodate the greater flow of fuel gas. The particular spacing may depend on fuel gas and oxidizer combination, the desired volume for combustion, and hydrocarbon feeds.

[0062] In some embodiments, annular gas manifolds 60, 62, 64, 66 are provided around the outer periphery of the flow passages 46, 48, 52, 54, respectively. In an example, the gas manifold 60 may be fluidly coupled to a gaseous hydrocarbon feed source. The manifold 62 may be fluidly coupled to a steam source. The manifold 64 may be fluidly coupled to an oxygen-containing-gas source, such as a pure O2 feed. And the manifold 66 is fluidly coupled to a hydrogen-rich or fuel feed source, such as H2. The manifolds 60, 62, 64, 66 are provided with the reactor feed assembly 22 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. One or more or all of gas inlets from the manifolds 60, 62, 64, 66 are configured to impart to an inwardly swirling flow pattern within one or more of the flow passages 46, 48, 52, 54. One or more or all of gas inlets from the manifolds 60, 62, 64, 66 may be directed nearly tangentially with respect to the central axis 28 into the flow passages 46, 48, 52, 54 so that the gases are not directed only radially toward the central axis 28 from the inlets, but instead are directed mostly tangentially around the central axis 28 to provide an inwardly swirling flow pattern within the flow passages. One or more inlets may be provided for each flow passage 46, 48, 52, 54. Furthermore, the walls 34, 36, 38, 40, and 50 forming the different flow passages of the reactor feed assembly 22 keep the gases introduced from the manifolds 60, 62, 64, 66 from flowing axially along the 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., snaillike) as may be typically used in vortex devices.

[0063] 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.

[0064] The orientation of the guide 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.

[0065] In an example, oxygen and hydrogen fuel gases from flow passages 52, 54, respectively, gaseous hydrocarbon feed from flow passage 46 and steam from flow passage 48 may be discharged into the central chamber 58 of the reactor feed assembly 22. Because the oxygen containing gas and hydrogen-rich fuel gas are introduced separately from one another into the adjacent flow passages 52, 54, respectively, and not as a mixture, this nearly eliminates the probability of ignition prior to the introduction into the reactor feed assembly 22. Furthermore, the combustion reaction takes place rapidly wherein most of the combustion occurs within a small space within the central chamber 58 where the two streams of oxy gen-containing gas and hydrogenrich fuel gas from the flow passages 52, 54 are mixed immediately after being discharged from the flow passages 52, 54. The combustible mixture can be ignited through spark or chemicals or pilot flame through bottom surface or side surfaces of the reactor as the suction from the strong swirling flow will transport the hot gases from the ignition device to the combustion zone 58 to initiate the ignition.

[0066] 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.

[0067] A liquid feed inlet 76 is also formed in the upstream feed assembly wall 36 for introducing all or a portion of the liquid hydrocarbons to be converted by the reactor 10 into the reactor feed assembly 22. 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 non- perpendicularly with respect to the axis 28 into the central chamber 58. 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 liquid mist or spray into thecentral chamber 58 in a flow pattern that is non-perpendicular to the central axis 28. In some embodiments, the liquid feed is introduced into the central chamber 58 in a direction that is within less than or equal to 15 degrees, less than or equal to 20 degrees, less than or equal to 25 degrees, or less than or equal to 35 degrees of the central axis 28.

[0068] Where multiple liquid feed inlets 76 are employed, the manifold 80 may comprise multiple spray nozzles 78 positioned and oriented for introducing the liquid feed as a liquid mist or spray into the central chamber 58 through the liquid feed inlets 76. In some embodiments, the liquid feed is introduced as non-swirling liquid mist or spray and / or in a radially -extending fanned pattern so that all or a portion of the liquid spray flow pattern may be non-parallel to the central axis but will have axial flow velocity components or an overall axial flow velocity greater than zero. Moreover, the flow pattern may be centered on or close to the central axis where the swirl velocities are lowest.

[0069] The spray pattern may also have a low spray angle to keep the pattern close to the central axis 28 so that the pattern is directed primarily axially (e.g., a spray angle of 40° or less). Such a spray angle helps prevent any existing liquid droplets that are not vaporized and that may remain in the spray from 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 also not configured or provided with any 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.

[0070] 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 the lowest. As explained above, higher swirl velocities are encountered away from the central axis 28 or centerline and closer to the walls, and such higher swirl velocities could centrifuge the atomized droplets and lead to deposition of the 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.

[0071] 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 a liquid spray or mist under the selected flow conditions (e.g., pressure, velocity) having a Sauter Mean Diameter (SMD) or D32 of droplets 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 spray sample. 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. 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. Other characteristics of the spray 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 (DV0.5), which is the diameter at which 50% of the total volume of droplets are contained in particles with smaller diameters. In certain embodiments, the DV0.5 of the spray 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, 40pm, 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.

[0072] The DVO.1 is the diameter below which 10% of the total volume of droplets are found. In certain embodiments, the DV0.1 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.

[0073] The DVO.9 is the diameter below which 90% of the total volume of droplets are found. In certain instances, the DVO.9 of the spray may be from at least, equal to, and / or between any two of 20 pm, 21 pm, 22 pm, 23 pm, 24 pm, 25 pm, 26 pm, 27 pm, 28 pm, 29 pm, 30 pm, 30 pm, 31 pm, 32 pm, 33 pm, 34 pm, 35 pm, 36 pm, 37 pm, 38 pm, 39 pm, 40 pm, 41 pm, 42 pm, 43 pm, 44 pm, 45 pm, 46 pm, 47 pm, 48 pm, 49 pm, 50 pm, 55 pm, 60 pm, 65 pm, 70 pm, 75 pm, 80 pm, 85 pm, 90 pm, 95 pm, 100 pm, 105 pm, 110 pm, 115 pm, 120 pm, 125 pm, 130 pm, 135 pm,140 pm, 145 pm, 150 pm, 155 pm, 160 pm, 165 pm, 170 pm, 175 pm, 180 pm, 185 pm, 190 pm, 195 pm, 200 pm, 205 pm, 210 pm, 215 pm, 220 pm, 225 pm, 230 pm, 235 pm, 240 pm, 245 pm, 250 pm, 255 pm, 260 pm, 265 pm, 270 pm, 275 pm, 280 pm, 285 pm, 290 pm, 295 pm, 300 pm, 305 pm, 310 pm, 315 pm, 320 pm, 325 pm, 330 pm, 335 pm, 340 pm, 345 pm, 350 pm, 355 pm, 360 pm, 365 pm, 370 pm, 375 pm, 380 pm, 385 pm, 390 pm, 395 pm, 400 pm, 405 pm, 410 pm, 415 pm, 420 pm, 425 pm, 430 pm, 435 pm, 440 pm, 445 pm, and 450 pm.

[0074] To facilitate forming a suitable fine spray or mist 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 usedherein, the dynamic viscosity is measured by ASTM D445. 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 or the benzene, toluene, xylene, and ethylbenzene, which may be part of a recycle stream) to lower the dynamic viscosity.

[0075] 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 or mist. Such two-fluid nozzles also provide internal mixing of the two fluids to prevent clogging, as well as providing a fine atomized spray having the above-stated droplet size. 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. 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 sources, such as steam and / or gaseous hydrocarbons. The range of pressures for the liquid feed versus vapor feed depend on the design of the nozzle. The liquid hydrocarbon converted with the reactor 10 willtypically 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%, and 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.

[0076] In many applications, the liquid hydrocarbon will be converted in the reactor 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 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 10. The gaseous hydrocarbon may include, but is not limited to, natural gas liquids (NGL), a natural gascondensate, 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, iso-butane and n-butane 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%.

[0077] In particular applications, the gaseous hydrocarbon is a raw C4 hydrocarbon stream that is delivered from an upstream crude processing system, as well as other hydrocarbon processing systems. The raw C4 hydrocarbons may include butane, n-butane, isobutane, butene, 1 -butene, 2-butene, cis-2-butene, trans-2-butene, 2-methylpropene, butadiene, 1-2- butadiene, 1-3-butadiene, butyne, 1 -butyne, and 2- butyne, and mixtures and combinations of these. The upstream hydrocarbon processing system from which the raw C4 hydrocarbons are delivered may include one or more of a crude-to-chemicals processing system, a crude refinery system, a gas plant, a steam cracker, a hydrocracker, a distillate hydrocracker, and a residue hydrocracker. These upstream processing systems may also provide other non-C4 hydrocarbons, liquid and / or gas, which can be processed along with the raw C4 hydrocarbons in the reactor 10.

[0078] 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 or mist. 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.

[0079] In many applications, all, or a portion of the gaseous hydrocarbon feed to be converted by the reactor 10 is introduced through one of the annular gas flowpassages 46, 48, 52, 54 of the reactor feed assembly 22. Typically, this will be the upstream flow passage 46, which is immediately adjacent to the liquid feed inlet 76.

[0080] 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 reactor feed assembly 22 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 or mist. Steam may also be separately introduced into the reactor feed assembly 22 through one of the annular flow passages, such as the downstream flow passage 48.

[0081] In an example of operation of the reactor 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 / or CO / syngas or a combination of these. Here, the CH4 is used as fuel for combustion. In certain embodiments where a combination of hydrogen gas and methane are used, the methane may be present in the fuel gas in an amount of from 20 mol%, 15 mol%, 10 mol%, 5 mol% or less. Greater amounts of methane may impact the desired selectivity. In other embodiments, however, greater amounts of methane may be used, including 100% methane for the fuel gas. Natural gas may also be used as fuel gas.

[0082] 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.

[0083] 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 oxy gen-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 substoichiometric (below 1) to allow for additional exothermic reactions in the mixing zone. The oxygen feed may provide an oxygen equivalent-to-fuel mole ratio of from 0.125 to 0.50. Furthermore, the ratio between the hydrocarbon feeds to hydrogen fuel will typically range from 1.0 to 15 based on mass depending on the hydrocarbon feed.

[0084] 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 10. The introduced steam also facilitates reducing 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.

[0085] In practice, all of the oxygen gas and at least a portion of the hydrogencontaining fuel gas are typically combusted to form heated combustion products that are almost entirely mixed with the other feeds prior to exiting the convergingdiverging 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 resultsin a back flow of the gas mixture within the reaction chamber 16. This mixture flows upstream and radially inward from the thin, outer annular mixed gas flow layers circulating within the reaction chamber 16. Internal cooling of the walls may occur due to the high swirling steam delivered through flow passage 48 in FIG. 2. Additional cooling (if necessary) occurs by a water jacket located between walls 14 and 18 in FIG. 2.

[0086] The liquid hydrocarbon feed introduced through the inlet 76 from nozzle 78 as a spray or mist is immediately vaporized. The low liquid viscosity and resulting 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 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.

[0087] 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 from 20, 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).

[0088] 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 combustion reactor, the swirling gas mixture facilitates keeping thewalls of the reactor much cooler than in such conventional cracking reactors. The use of such higher temperatures also allows a shorter residence or contact times 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.

[0089] 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 10 or they may be quenched exterior to the reactor 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.

[0090] 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 10 or they may be quenched exterior to the reactor 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 herein with respect to FIGS. 3-6.

[0091] FIG. 3 is a block diagram of a crude to chemicals complex 90 with a steam cracker and a combustion reactor, such as the reactor 10 described with respect to FIG. 2. As shown in FIG. 3, this crude to chemicals complex eliminates the MTBE unit, a slurry hydrogenation unit, and a C4 hydrogenation units.

[0092] Instead, the raffinate from a BD extraction unit is mixed with a C4 stream from a gas plant and fed to a combustion reactor. A separate combustion reactor is not required for this change due to similar feed properties. Further, a Cs olefin recycle stream from a depentanizer and a Ce olefin rich stream from a benzene extraction unit are mixed with C7-C9 olefin rich stream from C7+ extraction unit post aromatic recovery. The combined stream, which is C5-C9, olefin rich, and non-aromatic, can be sent to a reactor complex 130, for processing in a combustion reactor, such as a reactor 10. The streams are discussed in further detail below.

[0093] The crude-to-chemicals conversion system 90 is just one example of a conversion system that may be used with the reactor 10 to convert liquid and gaseous hydrocarbons. Other systems are described with respect to FIGS. 4 and 5. Further,upstream processing systems for the crude-to-chemicals conversion system 90 can include a crude refinery system, a gas plant, a steam cracker, a hydrocracker, a distillate hydrocracker, and a residue hydrocracker.

[0094] In this embodiment, the crude oil 92 used as the liquid hydrocarbon feed may be any crude oil typically extracted from subterranean formations. In the system 90, the crude oil 92 is introduced into distillation unit 94, which may include a combination of an atmospheric crude distillation unit (CDU) and a vacuum distillation unit (VDU) 94, with the bottom residues of the CDU being processed by the VDU. As used herein, the lines between units, such as the crude oil 92, represent fluidic couplings that carry fluids, including gasses and liquids between units. In the embodiment shown, products from the distillation unit 94 are the products resulting from the CDU distillation and VDU distillation of the CDU bottoms, which are conveyed by fluidic couplings to further process units. The overheads 96 of distillation unit 94 is liquid petroleum gas (LPG), which typically includes C2 to C4 hydrocarbons, and is delivered to gas plant 98, for separating raw C4 hydrocarbons from the C2 and C3 hydrocarbons, as product streams 100 and 102, respectively.

[0095] The VDU bottoms or vacuum residue 104 from the distillation unit 94, which typical has an API gravity ~5, average molecular weight 800, and typical distillation cut ASTM DI 160, 540-980 °C, may be introduced into a residue hydrocracker 106. A gas oils hydrocarbon fraction 108 is separated out in unit 94, and includes heavy, medium, and light vacuum gas oils with typical distillation cuts ASTM DI 160, 440-590 °C, 360-520 °C, and 270-340 °C, respectively. A gas oils hydrocarbon fraction 108 from the distillation unit 94, has atypical API gravity of about 17 to about 32, and an average molecular weight of about 250 to about 550. The gas oils hydrocarbon fraction 108 can be delivered to a distillate hydrocracker 110.

[0096] A naphtha fraction 112 from the distillation unit 94 has a typical API gravity of about 60, and an average molecular weight of 110, with typical distillation cuts of 40-205 °C, as measured by ASTM D86. The naphtha fraction 112 can be delivered to a steam cracker 114.

[0097] The gas oils 108 from unit 94 are cracked in the distillate hydrocracker 110 to form LPG overheads 116, intermediate fraction 118 and bottoms 120. The intermediate fraction 118 is composed primarily of hydrocarbons with a naphtha composition. The bottoms 120 is mainly composed of hydrocarbons in the dieselrange, typically having an API gravity of about 40 to about 50, average molecular weight of about 170 to about 230, and with typical distillation cuts of about 200- 380 °C as measured by ASTM D86. The LPG fraction 116 may be combined with the C2 and C3 hydrocarbons from gas plant 98 and delivered to the steam cracker 114. Alternatively, the LPG fraction 116 can be delivered to the gas plant 98 for C4 removal. The intermediate fraction 118 is fed to stream cracker 114 and the bottoms 120 is fed to a residue hydrocracker 106.

[0098] The vacuum residue 104 along with the bottoms 120 from the distillate hydrocracker 110 is cracked in the residue hydrocracker 106 to further crack and form various hydrocarbon fractions. The LPG 122 from the residue hydrocracker 106 may be fed to the gas plant 98. The kerosene range hydrocarbon fraction 124 may be combined with the gas oils 108 and / or be delivered to the distillate hydrocracker 110 for further cracking. The naphtha fraction 126 from the residue hydrocracker 106 may be delivered to the steam cracker 114, along with the intermediate fraction 118 from distillate hydrocracker 110. Pitch or residue hydrocracker bottoms is removed from unit 106 as stream 128.

[0099] As shown in FIG. 3, in the gas plant 98, the raw C4 hydrocarbons 100 are separated from the C2 and C3 hydrocarbons and delivered to a reactor complex 130. An example of the reactor complex 130 is described more fully later on with respect to FIG. 4. The reactor complex 130 utilizes a combustion reactor, such as the reactor 10, previously described, which can be an ANJEVOC reactor. The raw C4 hydrocarbons are introduced into the reactor complex 130 as a gas feed. A raw C4 feed that is recycled from a C4 and aromatic complex is not an ideal feed for a conventional steam cracker. Accordingly, these recycle streams are first hydrogenated in a total hydrogenation unit and sent to a steam cracker. Most of these streams have significant quantities of isobutanes, which are not a desirable feed for steam crackers. The combustion reactor can effectively crack these mixtures of the n- and iso-butanes without significant coking, as compared to a steam cracker, thus effectively increasing the cracking efficiency, and reducing the coking tendencies of the overall complex. This in turn provides a high on-stream factor for the complex.

[0100] The liquid crude oil 132 that would typically be processed in a crude-to- chemicals complex can be introduced and processed directly in the reactor complex 130 without any pretreatment or distillation. For example, the only processing thecrude oil 132 may undergo may be an initial flashing or crude oil distillation in a flash drum or unit (not shown) to remove asphaltenes and / or resins. In some embodiments, the liquid crude oil 132 is injected directly into the axial liquid inlet 76 of the reactor 10 (as described with respect to FIG. 2) of the reactor complex 130. Other liquid hydrocarbons, such as gas oil, kerosene, diesel, naphtha, heavy naphtha, light naphtha, one or more C20 to C40 hydrocarbons, biomass-derived oil, pyoil from plastic, liquified plastic, liquified plastic waste with impurities, heteroatom-containing hydrocarbon liquids, may also be used with or instead of liquid crude and can be processed in the reactor complex 130, along with the raw C4 hydrocarbon gas feed.

[0101] In some embodiments, the raw C4 stream 100 may be combined with the liquid crude oil 132 and / or other liquid hydrocarbon as a combined hydrocarbon gas / liquid reactant feed that is introduced through the axial gas inlet 76 (FIG. 2) of the reactor 10. In other embodiments, the raw C4 stream 100 may be introduced separately from the liquid crude oil 132, such as through the axial inlet 76 or through an annular flow passage, such as the upstream annular flow passage 46 of reactor feed assembly 22. If introduced through the axial inlet 76, the raw C4 stream 100 may also be introduced through the spray nozzle 78 along with the liquid crude, where the nozzle 78 constitutes a two-fluid nozzle.

[0102] Oxygen and hydrogen gas fuel feeds 134 and 136 are introduced into the reactor of the reactor complex 130 to form swirling heated combustion gases to provide the elevated reaction temperature necessary for conversion. Steam may also be introduced, with the various feeds 100, 132, 134, 136, or as its own feed stream 138, into the reactor of the reactor complex 130, as described previously.

[0103] The C2 and C3 from the gas plant 98 and the LPG 116 from distillate hydrocracker 110, along with the feeds 112, 118, 126, may be introduced into the steam cracker 114 to produce various olefins and aromatics. Ethylene 140 and propylene 142 products are removed from the steam cracker 114 and collected for further processing, use or storage. Pyoil 144 removed from steam cracker may be recycled and delivered as a feed 146 to the distillate hydrocracker 110.

[0104] In the embodiment of FIG. 3, raw C4 hydrocarbons 148 from steam cracker 114 may be delivered to a butadiene extraction unit 150. The raw C4 hydrocarbons 148 may include 1,3 Butadienes, 1-Butene, 2-Butenes, iso-butene, and / or C4 paraffins. In some embodiments, the raw C4 hydrocarbons 148 comprise 1,3 Butadienes (35-45wt.%); Iso Butene (15-20 wt.%); 1-Butene (15-20 wt.%); 2-Butene (5-10 wt.%); C4 paraffins (nC4 + iC4) (10-15 wt.%) and C5+ (< lwt.%), in each case based on total wt. of the stream. The 1,3 butadiene produced in unit 150 is removed as stream 152 for further processing, storage, or use. All or a portion of the C4 hydrocarbons in the raffinate 154 from butadiene extraction unit 150, including any hydrogenated C4 hydrocarbons, can be recycled and combined with the raw C4 hydrocarbon stream 100 from gas plant 98 to be fed as a hydrocarbon reactant feed to reactor complex 130. The raffinate (154) is comprises the hydrocarbons of the raw C4 hydrocarbons 148, but without the Butadienes. In some embodiments, the raffinate (154) comprises Iso Butene (25-35 wt.%); 1-Butene (25-35 wt.%); 2-Butene (10-20 wt.%); C4 paraffins (nC4 + iC4) (20-25 wt.%); and / or C5+ (1-2 wt.%), in each case based on total wt. of the stream.

[0105] In some embodiments, the removal of the MTBE, slurry hydrogenation, and C4 hydrogenation units is a permanent change, for example, in a plant built specifically for lower gasoline production. In other embodiments, the MTBE, slurry hydrogenation, and C4 hydrogenation units may be bypassed, but left in place for swing capacity during periods of higher gasoline demand.

[0106] Aromatics and pyrolysis gasoline (pygas) 156 produced in steam cracker 114 may be delivered to a depentanized hydrotreated gasoline unit or depentanizer 158. The Cs hydrocarbons 160 removed from the depentanizer 158 can be combined with other streams and recycled to the combustion. The C10+ hydrocarbons 162 from the depentanizer 158 can be recycled to distillate hydrocracker unit 110. The Ce to C9 hydrocarbons 164 from the depentanizer 158 are fed to C7+ hydrocarbon extraction unit 166 where a C7+ and gas blend stream 168 is extracted. The C7+ and gas blend stream 168 is processed in a toluene / xylenes extraction unit 170 from which a toluene / xylenes stream 172 is extracted for further processing or storage. The raffinate 174 from the toluene / xylenes extraction unit 170 is a C7-C9 olefins stream which is combined with other streams and returned to the reactor complex 130.

[0107] The Ce hydrocarbons 176 from extraction unit 166 are fed to benzene extraction unit 178. Benzene 180 is recovered for further processing, use or storage, while the remaining Ce hydrocarbons 182 may be combined with streams 160 and 174 and recycled to the combustion reactor 130 as a C5-C9 olefins stream 184.

[0108] FIG. 4 is a block diagram of a reactor complex 130, for example, using the reactor 10 described with respect to FIG. 2. Like numbered items are as described with respect to previous figures. In some embodiments, the example reactor complex 130 is incorporated into a larger petrochemicals complex, such as the crude to chemicals complex 90 of Fig. 3. or the hydrocarbon processing system 280 of Fig. 5. In other embodiments, the reactor complex 130 is a stand-alone processing system that uses an ANJEVOC reactor without the need for separate cracking reactors, such as in the embodiment shown in FIG. 4.

[0109] As described in more detail below, a debutanizer overhead stream is sent for butadiene recovery and the raffinate stream from the butadiene recovery is mixed with ethane from a C2 splitter and a raw C4 feed then sent to a combustion reactor. Further, the debutanizer bottoms stream is routed to a depentanizer column to remove Cs olefin rich stream and the resulting Ce+ stream is provided to an aromatic complex. The raffinate from the aromatic complex, including a non-aromatic Ce-Cs or C6-C9 olefin rich stream, is mixed with the overhead stream from a depentanizer and a mixed stream i.e., Cs-Cs or C5-C9 olefin rich stream is fed to the combustion reactor.

[0110] Other hydrocarbons, both gaseous and liquid, can also be converted in the reactor complex 130 along with the C4 hydrocarbons and liquid crude. The reactor complex 130 includes the reactor 10 (described with respect to FIG. 2), which may be an ANJEVOC reactor, as has been previously described.

[0111] In this embodiment, crude oil 132 is used as a liquid hydrocarbon feed to the reactor 10. The raw C4 hydrocarbon gas feed 100 from the gas plant 98 (described with respect to FIG. 3 may be combined with the liquid crude oil 132 as a combined hydrocarbon gas / liquid reactant feed that is introduced through the axial inlet 76 of the reactor 10. In the embodiment shown, the C4 hydrocarbon gas feed 100 is introduced separately from the liquid crude oil 132, such as through the axial inlet 76 or through an annular flow passage, such as the upstream annular flow passage 46 of reactor feed assembly 22. If introduced through the axial inlet 76, the C4 gas feed 100 may also be introduced through the spray nozzle 78 along with the liquid crude, where the nozzle 78 constitutes a two-fluid nozzle.

[0112] Oxygen and hydrogen gas fuel feeds 134 and 136 are introduced into the reactor 10 to form swirling heated combustion gases to provide the elevated reactiontemperature necessary for conversion. Steam 138 may also be introduced, with the various feeds, or as its own feed stream into the reactor 10, as described previously.

[0113] The liquid crude 132 introduced as the reactant feed as a spray and is immediately vaporized and mixed with the swirling hot combustion gases. The hydrocarbon reactant feed composed of the crude oil and the raw C4 gases 100 from the gas plant 98 (FIG. 3) mixes with the swirling hot combustion gases to form a swirling, heated mixture that passes from the central chamber 58 (FIG. 2) through the converging-diverging conduit 24 and into the reaction chamber 16 of the reactor 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.

[0114] The converted products 186 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.

[0115] Asphaltenes and resins that are not cracked may be removed from the reactor 10 in stream 188. The asphaltenes and resins are knocked out through the water quench and condensed out with the water. In other embodiments, the crude 132 may go through a preliminary flash drum or other separation unit (not shown), to remove asphaltenes and / or resins from the liquid crude oil prior to its introduction into the reactor 10.

[0116] Water 190 from quench water and / or condensed steam is separated from the converted products 186 to form separated conversion products 192. The conversion products 192 may then be introduced into a fractionator 194, where the products are fractionated to remove fuel oil 196. The fuel oil 196 may be further processed in aromatics complex 198 to produce benzene, toluene, and xylene products (BTX) 200 for further use, processing, or storage. A C5-C9 non-aromatic olefins stream 184 is recycled to the reactor 10. A C10+ product stream 202 is removed from the aromatics complex for further use, processing, or storage.

[0117] The remaining gaseous fraction 204 from the fractionator 194 may be pressurized in compressor 206 and delivered to an amine treatment unit 208 for the removal or scrubbing of CO2 and / or H2S from the converted hydrocarbon products. The scrubbed hydrocarbon products 210 from the amine treatment unit 208 are furtherpressurized in compressor 212 and the products are first delivered to a high-pressure depropanizer 214. The C1-C2 hydrocarbons are removed from the high-pressure depropanizer 214 as a C1-C2 overhead stream 216. The bottoms 218 from the high- pressure depropanizer 214 contain C3 or greater hydrocarbons.

[0118] The C1-C2 overheads 216 are delivered to an acetylene converter unit 220, where the acetylene in stream 216 is hydrogenated to form ethylene and / or ethane. The hydrogenated product 222 from acetylene converter unit 220 is delivered to a cold box or other heat exchanger 224 for cooling the hydrogenated product 222. The cooled products 226 are then delivered to a hydrogen separator 228 where hydrogen gas is removed and delivered as hydrogen recycle 230, where it may be combined with fresh hydrogen gas 232 to form hydrogen feed 136 to be used for fuel to the reactor 10.

[0119] The separated hydrogen-free products 234, which are composed of methane, ethane, and ethylene hydrocarbons, are delivered to a demethanizer 236, where overhead methane and carbon oxides (i.e. , CO, CO2) can be removed by membrane separation as stream 238. The carbon oxides from stream 238 may be hydrogenated in converter unit 240. The resulting methane stream 242 can then be recovered as methane fuel, such as for boilers or other uses.

[0120] The demethanized product 244 may be further processed in a deethanizer 246. The C2 compounds of ethane and ethylene from deethanizer 246 are removed as stream 248. This may be delivered to a C2 splitter 250 into ethane and ethylene product streams 252 and 254, respectively, for further processing, use or storage. In certain instances, all or a portion of the ethane 252 may be recycled as part of a recycle stream 256, which is recycled back to the reactor 10 to form part of the gaseous hydrocarbon reaction feed.

[0121] The bottoms 218 from the high-pressure depropanizer 214 that contains C3 or greater hydrocarbons is delivered to a low-pressure depropanizer 258. A C3 product stream 260 is removed as overheads from the low-pressure depropanizer 258. The C3 product stream 260 is further processed in a methylacetylene-propadiene (MAPD) converter 262, where methyl acetylene and propadiene are hydrogenated to form propane and / or propylene. The combined propane and propylene products 264 from the MAPD converter 262 may be separated in C3 splitter 266 into propane and propylene product streams 268 and 270, respectively, for further processing, use orstorage. All or a portion of the propane 268 may be recycled as part of recycle stream 256.

[0122] The bottoms 272 from the low-pressure depropanizer 258, which contains C4 or greater hydrocarbons, is delivered to debutanizer 274 for the removal of C4 hydrocarbons as product stream 276. The C4 product stream 276 may be fed to a butadiene recovery unit 150 where a butadiene product stream 152 is separated. The raffinate stream 154 from the butadiene recovery unit 150 is combined with other product streams, such as the ethane stream 252 from the C2 splitter 250, and, in some embodiments, the propane stream 268 from the C3 splitter 266. The combined stream is recycled to the reactor 10 as part of recycle stream 256.

[0123] The debutanized product 278 from debutanizer 274, which is mainly composed of aromatics or pyrolysis gasoline (i.e. , pygas), may be delivered to the aromatics complex 198 to form benzene, toluene, and xylene products 200. Heavy oils, unreacted sulfur and heavy metal compounds may be removed from the aromatics complex 198 with stream 202. In an alternative configuration to the reactor complex 130 of FIG.4, demethanization of the scrubbed hydrocarbon products 210 from the amine treatment unit 208 can occur at the front end, with depropanization occurring downstream.

[0124] FIG. 5 is a drawing of another hydrocarbon processing system 280 and process flow for the conversion of liquid crude oil employing the reactor complex 130 in combination with a crude-to-chemicals conversion system. Like numbered items are as described with respect to previous figures. In this embodiment, the high value butadiene 152 is recovered from the raw C4 hydrocarbons 148 from the steam cracker 114 in a butadiene recovery unit 150. The raffinate 154 from the BD recovery unit 150 is mixed with the C4 stream 100 from the gas plant 98 and routed to the reactor complex 130.

[0125] Pygas 156 is passed through a depentanizer 158 to recover Cs olefins 160 from overhead and the Ce to C9 hydrocarbons 164 from the bottoms are routed to an aromatics unit 282. Cs olefins 160 from the overhead of the depentanizer 158 and Ce- C9 olefins 284 from the aromatic unit 282 are recycled back to the reactor complex 130. The BTX 200 from the aromatics unit 282 can be sent for further use, processing, or storage.

[0126] As described with respect to FIGS. 3-5, a combustion reactor, such as an ANJEVOC reactor, is highly flexible for feed and gives very high yields of high value compounds. For example, a C4-C9 olefin rich feed of about 500 KTA can be made available to process in a combustion reactor, such as an ANJEVOC reactor. This can increase the production of HVC by 15-20%.

[0127] FIG. 6 is a process flow diagram of a method 600 for recycling hydrocarbon streams in a chemical process. The method starts at block 602 when a butadiene product stream is separated from a raw C4 stream to form a C4 stream.

[0128] At block 604 hydrocarbon reactants including a gaseous hydrocarbon stream that includes the C4 stream and a liquid hydrocarbon stream are introduced into a combustion reactor. This may be, for example, the ANJEVOC reactor described with respect to FIG. 2.

[0129] At block 606 the gaseous hydrocarbons stream and the liquid hydrocarbon stream are converted to form a converted hydrocarbon product stream. At block 608 the converted hydrocarbons product stream is removed from the combustion reactor.At block 610, product streams are separated from the converted hydrocarbon product stream.

[0130] Other implementations are also within the scope of the following claims.

Claims

Claims1. A method of converting hydrocarbons in a petrochemicals complex, the method comprising: separating a butadiene product stream from a raw C4 stream to form a C4 stream; introducing hydrocarbon reactant feeds comprising (i) a gaseous hydrocarbon stream comprising the C4 stream and (ii) a liquid hydrocarbon stream into a combustion reactor; converting the gaseous hydrocarbon stream and the liquid hydrocarbon stream within the combustion reactor to form a converted hydrocarbon product; removing the converted hydrocarbon product from the combustion reactor; and separating a product stream from the converted hydrocarbon product.

2. The method of claim 1, further comprising: separating a crude oil feedstock into a gas stream, a liquid stream, and a heavies stream; separating the gas stream into a first raw C4 stream and a lights stream; cracking the heavies stream to form a heavy liquid stream; cracking the liquid stream, the lights stream, and the heavy liquid stream to form a product stream, a second raw C4 stream, and a pygas stream; and combining the first raw C4 stream and the second raw C4 stream to form the C4 stream.

3. The method of claims 1 or 2, wherein the liquid hydrocarbon stream 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 liquefied plastic, a liquefied plastic waste with impurities, and a heteroatom-containing hydrocarbon liquid.

4. The method of any of claims 1 to 3, wherein the liquid hydrocarbon stream makes up from 0.5 wt% to 99 wt% of the hydrocarbon reactant feeds.

5. The method of any of claims 1 to 4, wherein the raw C4 stream comprises at least one of butane, n-butane, i-butane, butene, 1 -butene, 2-butene, cis-2-butene, trans-2-butene, 2- methylpropene, butadiene, 1 -2-butadiene, 1-3 -butadiene, butyne, 1 -butyne, and 2-butyne.

6. The method of any of claims 1 to 5, 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.

7. The method of any of claims 1 to 6, further comprising: separating at least a portion of any one or more of a C2 to Ce alkane, a xylene, benzene, and toluene from the converted hydrocarbon product 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.

8. The method of any of claims 1 to 7, wherein at least one of the gaseous hydrocarbon stream and liquid hydrocarbon stream is mixed with steam.

9. The method of any of claims 1 to 8, wherein the combustion reactor comprises a central axis, a feed assembly, and a reactor vessel that defines a reaction chamber.

10. The method of any of claims 1 to 9, wherein the combustion reactor is an annular jet vortex reactor chamber (ANJEVOC) reactor system.

11. A petrochemicals complex, comprising: a combustion reactor, comprising: a gaseous hydrocarbon inlet fluidically coupled to the combustion reactor; a liquid hydrocarbon inlet fluidically coupled to the combustion reactor; and a converted hydrocarbon outlet; a butadiene recovery unit, comprising: a butadiene separation system; an inlet coupled to a raw C4 stream;a butadiene outlet; and a BD raffinate outlet comprising a BD raffinate; a fluidic coupling from the BD raffinate outlet to the gaseous hydrocarbon inlet; and a fluidic coupling from a liquid hydrocarbon stream to the liquid hydrocarbon inlet.

12. The petrochemicals complex of claim 11, wherein the raw C4 stream comprises at least one of butane, n-butane, i-butane, butene, 1 -butene, 2-butene, cis-2- butene, trans-2-butene, 2- methylpropene, butadiene, 1 -2-butadiene, 1-3 -butadiene, butyne, 1 -butyne, and 2-butyne.

13. The petrochemicals complex of claims 11 or 12, wherein the BD raffinate comprises at least one of butane, n-butane, i-butane, butene, 1 -butene, 2- butene, cis-2-butene, trans-2-butene, 2- methylpropene, butyne, 1 -butyne, and 2- butyne.

14. The petrochemicals complex of any of claims 11 to 13, wherein the liquid hydrocarbon stream 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.

15. The petrochemicals complex of any of claims 11 to 14, wherein the combustion reactor comprises: 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; a feed assembly having a central chamber through which the central axis passes that is in fluid communication with the converging-diverging conduit; a fuel line fluidically coupled to the feed assembly; and an oxygen line fluidically coupled to the feed assembly.

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