Methods for upgrading a hydrocarbon feed

Abstract

A method of upgrading a hydrocarbon mixture comprises providing a hydrogenation feed comprising a hydrocarbon mixture, the hydrocarbon mixture comprising a hydrocarbon and an organic component; introducing the hydrogenation feed to a hydrotreater with a hydrogen stream to hydrogenate at least the organic component and produce a hydroprocessed stream at an increased temperature; introducing dilution steam to the hydroprocessed stream, thereby forming a hydroprocessed stream / dilution steam mixture; preheating the hydroprocessed stream / dilution steam mixture; and upgrading the hydroprocessed stream / dilution steam mixture in a hydrocarbon upgrading furnace to form a cracked gas effluent, wherein the hydrocarbon in the hydrocarbon mixture comprises naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensates, C1-C4 hydrocarbons, or combinations thereof, the organic component is selected from one or more of olefins, alkyl-aromatics, or alcohols, and the hydrocarbon mixture comprises from 0.01 wt.% to 25 wt.% organic component by weight of the hydrocarbon mixture.

Description

METHODS FOR UPGRADING A HYDROCARBON FEEDFIELD

[0001] Embodiments of the present disclosure generally relate to the field of refining and upgrading hydrocarbons, and pertain particularly to a method of upgrading hydrocarbons utilizing a hydrotreater, hydrocarbon upgrading furnace, and a feed comprising a hydrocarbon and an organic component.BACKGROUND

[0002] Ethylene is widely used as an intermediate in the petrochemical industry and its production exceeds that of any other intermediate organic. Much of ethylene production goes to the manufacture of ethylene oxide, ethylene dichloride and polyethylene, which are precursors to a multitude of everyday consumer products. Despite various improvements over the years in process design, reliability and safety, steam cracking furnaces used to form hydrocarbons such as ethylene remain heavily reliant on a narrow range of combustible fossil fuels to provide process heat and energy, leading to substantial greenhouse gas emissions, including to pre-heat feed composition being processed in the steam cracker. However, steam cracking process to produce ethylene requires roughly half the energy required of competing processes (e.g., direct Ci conversion technologies) and are projected to remain as the most energy efficient process.

[0003] Moreover, feedstocks for ethylene (olefins and aromatic compounds) have traditionally been limited, such that new sources of ethylene produced from hydrocarbons with compositions beyond the typical range of feedstocks, such as ethanol rich ethane, liquids with a higher content of aromatics, olefins, diolefins, and heavier fractions such as C 15+ hydrocarbon fractions, are also desired.SUMMARY

[0004] Accordingly, methods to reduce the energy required to preheat feeds in systems utilizing hydrocarbon upgrading furnaces are desired. Particularly, methods are desired to reduce the energy input to preheat and convert hydrocarbons in a hydrocarbon upgrading furnace utilizing flue gas as the energy source. Such methods would also ideally be compatible with the wider and heavierrange of feedstocks (such as feeds high in aromatics, naphthas, gas oils, pyrolysis gasolines, Fischer-Tropsch derivatives, natural gas condensates, C1-C5 hydrocarbons, alcohols, and C15+ hydrocarbons) that are desired for ethylene production.

[0005] However, liquid feeds with a higher content of aromatics are typically seen as materials leading to lower ethylene yields and higher fouling tendency. Further, crude C4-C5 hydrocarbons are typically rich in dienes and olefins, often leading to increased coking and fouling in hydrocarbon upgrading furnaces. Pyrolysis gasoline may contain dienes, olefins, as well as aromatics. Moreover, processing of alcohols such as ethanol may produce a range of oxygenates in the feed that exceeds the acceptable range for hydrocarbon upgrading furnaces. Accordingly, to transform the previous feeds into forms acceptable for use in a hydrocarbon upgrading furnace, such as a steam cracker, preprocessing in standalone upstream chemical plants is often required.

[0006] Systems and methods herein accomplish the aforementioned goals by the utilization of heat integration through recycling of heat generated from the radiant section of a flue gas-driven hydrocarbon upgrading furnace in one or more heat exchangers that are utilized to preheat the feed prior to upgrading. Heat integration of the system may occur by capturing and utilizing all available heat within the process to effect the creation of the desired products. This should ideally be done within other process constraints, notably the minimization of fouling and side-reactions that have a deleterious effect on the total yield of desired products. For example, conventional systems can process only a limited amount of C15+ hydrocarbon fractions as partial vaporization may form fouling on hot surfaces of heat exchangers. This limits the processability of C15+ hydrocarbon fractions.

[0007] Moreover, the provision of an upstream hydrotreater and an associated feed containing a specified ratio of organic component to hydrocarbon feed reduces the reliance on the preheating duty of the feed preheater to partially vaporize the feed. This may minimize or eliminate the need for separate upstream stand-alone plants to upgrade the chemical composition of the hydrocarbon upgrading feed prior to being subjected to the hydrocarbon upgrading furnace. Particularly, the reaction of the organic component in the hydrotreater generates excess heat, reducing the preheating burden of associated feed preh eaters / h eat exchangers, reducing CO2 emissions of the hydrocarbon upgrading furnace and / or increasing the amount of excess preheat energy that may be used to drive other downstream processes. Further, the upstream hydrotreater may run at an elevated pressure compared to the other units in the system. This increased operating temperaturewill also increase the heat transfer between the organic component and the rest of feed, providing additional benefits.(0008] The aforementioned solutions are also contrary to established thought in the field, as the provision of an additional refining unit would normally be thought to increase energy consumption and load of the system as a whole, rather than reduce the same.

[0009] Finally, the additional heat provided by the exothermic reaction of hydrogen with the reactive organic components of the feed in the hydrotreater may also allow the treatment of hydrocarbon feeds with greater amounts of heavy hydrocarbons (C 15+) than for equivalent systems, as the hydrogenation of the organic component may contribute to vaporization of these heavy hydrocarbons. For example, and as explained in further detail below, the hydrotreater may convert alkyl-aromatics to naphthenes, resulting in higher ethylene yields while at the same time reducing the fouling formation induced by aromatics. Further, while olefins may produce a smaller amount of ethylene, hydrogenation of olefins and diolefins eliminates the risk of fouling and produces higher yields of ethylene. Finally, large amounts of oxygenates present in alcohols such as ethanol that normally cannot be directly processed in a conventional hydrocarbon upgrading furnace, can be converted hydrocarbons and high temperature water that can be used as dilution steam.

[0010] According to one embodiment, A method of upgrading a hydrocarbon mixture comprises providing a hydrogenation feed comprising a hydrocarbon mixture, the hydrocarbon mixture comprising a hydrocarbon and an organic component; introducing the hydrogenation feed to a hydrotreater with a hydrogen stream to hydrogenate at least the organic component and produce a hydroprocessed stream at an increased temperature; introducing dilution steam to the hydroprocessed stream, thereby forming a hydroprocessed stream / dilution steam mixture; preheating the hydroprocessed stream / dilution steam mixture; and upgrading the hydroprocessed stream / dilution steam mixture in a hydrocarbon upgrading furnace to form a cracked gas effluent, wherein the hydrocarbon in the hydrocarbon mixture comprises naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensates, C1-C4 hydrocarbons, or combinations thereof, the organic component is selected from one or more of olefins, alkylaromatics, or alcohols, and the hydrocarbon mixture comprises from 0.01 wt.% to 25 wt.% organic component by weight of the hydrocarbon mixture.

[0011] Additional features and advantages of the embodiments described herein will be set forth in the detailed description which follows, and in part will be readily apparent to those skilledin the art from that description or recognized by practicing the embodiments described, comprising the detailed description and the claims which are provided infra.BRIEF DESCRIPTION OF THE DRAWINGS

[0012] T he following detailed description of specific embodiments of the present disclosure can be best understood when read in conjunction with the following drawings in which:

[0013] FIG. 1 illustrates a process flow diagram for an exemplary process in accordance with embodiments described herein;

[0014] FIG. 2 illustrates the mass vapor fraction of a feed at the inlet of the second heat exchanger for varying ratios of organic component to C15+ hydrocarbon fraction according to embodiments herein, as well as the same for comparative designs without the hydrotreater;

[0015] FIG. 3 illustrates the temperature of a feed at the inlet of the second heat exchanger for varying compositions, as compared to the dew point of the same, according to embodiments herein;

[0016] FIG. 4 illustrates the temperature of a feed at the inlet of the second heat exchanger for varying compositions, as compared to the dew point of the same, according to embodiments herein; and

[0017] FIG. 5 illustrates the heat transfer for a given hydrogenation feed as a function of length of exposure for a counter-current hydrotreater versus a co-current hydrotreater, according to embodiments herein.DETAILED DESCRIPTION

[0018] Embodiments described herein relate to methods of upgrading a hydrocarbon mixture, such as a mixture comprising a hydrocarbon, an organic component, and optionally C15+ hydrocarbon fractions.

[0019] For the purpose of describing the simplified schematic illustrations and descriptions of the relevant figures, the numerous valves, temperature sensors, electronic controllers and the like that may be employed and well known to those of ordinary skill in the art of certain chemical processing operations are not comprised. Further, accompanying components that are often comprised in typical chemical processing operations, such as air supplies, and catalyst hoppers,are not depicted. Accompanying components that are in typical upgrading units, such as bleed streams, spent catalyst discharge subsystems, and catalyst replacement sub-systems are also not shown. It should be understood that these components are within the spirit and scope of the present embodiments disclosed. However, operational components, such as those described in the present disclosure, may be added to the embodiments described in this disclosure.

[0020] It should further be noted that arrows in the drawings refer to process streams. However, the arrows may equivalently refer to transfer lines, which may serve to transfer process streams between two or more system components. Additionally, arrows that connect to system components define inlets or outlets in each given system component. The arrow direction corresponds generally with the major direction of movement of the materials of the stream contained within the physical transfer line signified by the arrow. Furthermore, arrows, which do not connect two or more system components, signify a product stream, which exits the depicted system, or a system inlet stream, which enters the depicted system. Product streams may be further processed in accompanying chemical processing systems or may be commercialized as end products. System inlet streams may be streams transferred from accompanying chemical processing systems or may be non-processed feedstock streams. Some arrows may represent recycle streams, which are effluent streams of system components that are recycled back into the system. However, it should be understood that any represented recycle stream, in some embodiments, may be replaced by a system inlet stream of the same material, and that a portion of a recycle stream may exit the system as a product.

[0021] Additionally, arrows in the drawings may schematically depict process steps of transporting a stream from one system component to another system component. For example, an arrow from one system component pointing to another system component may represent “passing” a system component effluent to another system component, which may comprise the contents of a process stream “exiting” or being “removed” from one system component and “introducing” the contents of that product stream to another system component.

[0022] It should be understood that according to the embodiments presented in the relevant figures, an arrow between two system components may signify that the stream is not processed between the two system components. In other embodiments, the stream signified by the arrow may have substantially the same composition throughout its transport between the two system components. Additionally, it should be understood that in embodiments, an arrow may represent that at least 75 wt.%, at least 90 wt.%, at least 95 wt.%, at least 99 wt.%, at least 99.9 wt.%, oreven 100 wt.% of the stream is transported between the system components. As such, in embodiments, less than all of the stream signified by an arrow may be transported between the system components, such as i f a slip stream is present.

[0023] It should be understood that two or more process streams are “mixed” or “combined” when two or more lines intersect in the schematic flow diagrams of the relevant figures. Mixing or combining may also comprise mixing by directly introducing both streams into a like reactor, separation unit, or other system component. For example, it should be understood that when two streams are depicted as being combined directly prior to entering a separation unit or reactor, that in embodiments the streams could equivalently be introduced into the separation unit or reactor and be mixed in the reactor. Alternatively, when two streams are depicted to independently enter a system component, they may in embodiments be mixed together before entering that system component.

[0024] However, it should also be understood that when two or more process streams enter a heat exchanger, the streams are not mixed. Instead, the streams may communicate in terms of heat transfer from one stream to the other while not directly contacting one another.

[0025] Ranges can be expressed herein as from “in the range of’ one particular value to another particular value. When such a range is expressed, another embodiment comprises from the one particular value and / or to the other particular value. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint.

[0026] Additional features and advantages of the described embodiments, some embodiments of which are illustrated in the accompanying drawings, will be set forth in the detailed description, which follows, and in part will be readily apparent to those skilled in the art from that description or recognized by practicing the described embodiments, comprising the detailed description, which follows, as well as the claims.

[0027] As used herein, references to pressure in “bar,” “pascals,” or any equivalent pressure units may be understood to be in absolute pressure units, rather than in gauge pressure units.

[0028] As previously stated, embodiments herein are directed to methods of upgrading a hydrocarbon mixture 102. The hydrocarbon mixture 102 may comprise a hydrocarbon and an organic component. The hydrocarbon may comprise naphtha, gas-oil, pyrolysis gasoline, Fischer- Tropsch derivatives, natural gas condensates, or C1-C4 hydrocarbons, or combinations thereof. TheC1-C4 hydrocarbons may comprise methane, ethane, propane, propylene, butane, butadiene, or combinations thereof. The organic component may comprise olefins, alkyl-aromatics, or alcohols. The alcohols may comprise ethanol. The alkyl-aromatics may comprise BTX, such as but not limited to, benzene, toluene, or xylene. The hydrocarbon mixture 102 may comprise from 0 wt.% to 25 wt.% organic component by weight of the hydrocarbon mixture 102, such as from 0 wt.% to 10 wt.%, from 10 wt.% to 1 1 wt.%, from 1 1 wt.% to 15 wt.%, from 15 wt.% to 20 wt.%, from 20 wt.% to 24 wt.%, from 24 wt.% to 25 wt.%, or combinations of the preceding ranges or smaller ranges therein, such as from 14 wt.% to 21 wt.%.

[0029] For example, and in embodiments, when the hydrocarbon is naphtha, the organic component may be an alkyl-aromatic or olefins. Further, when the hydrocarbon is pyrolysis gasoline, the organic component may be an alkyl-aromatic or olefins. Further yet, when the hydrocarbon is ethane, the organic component may be an alcohol, and may particularly be ethanol. These combinations are explained in further detail at least in the examples.

[0030] Now referring to FIG. 1 , the system may at least comprise a first mixer 202, a hydrotreater 208, one or more heat exchangers, and a hydrocarbon upgrading furnace 220. Methods herein may comprise providing a hydrogenation feed 106, the hydrogenation feed comprising at least the hydrocarbon mixture. The method may also comprise mixing the hydrocarbon mixture 102 with a C15+ hydrocarbon fraction 104 to provide the hydrogenation feed 106. The hydrocarbon mixture 102 and the C 15+ hydrocarbon fraction 104 may be mixed in the first mixer 202. As used herein a “mixer” may be any suitable mixer known in the art, such as a simple mixing tee, ultrasonic device, a small continuous stir tank reactor (CSTR), or another known mixer. The hydrogenation feed 106 may comprise from 0 wt.% to 45 wt.% C15+ hydrocarbon fraction 104 by weight of the hydrogenation feed 106, such as from 0 wt.% to 5 wt.%, from 5 wt.% to 6 wt.%, from 6 wt.% to 10 wt.%, from 10 wt.% to 20 wt.%, from 20 wt.% to 30 wt.%, from 30 wt.% to 40 wt.%, from 40 wt.% to 44 wt.%, from 44 wt.% to 45 wt.%, or combinations of the preceding ranges or smaller ranges therein, such as from 21 wt.% to 41 wt.%.

[0031] The hydrogenation feed 106 may then be introduced to a first heat exchanger 204 to initially preheat the hydrogenation feed 106. The hydrogenation feed 106 may be preheated to a temperature of from 30 °C to 200 °C, such as from 30 °C to 35 °C, from 35 °C to 50 °C, from 50 °C to 100 °C, from 100 °C to 150 °C, from 150 °C to 180 °C, from 180 °C to 195 °C, from 195 °Cto 200 °C, or any combination of the preceding ranges or smaller ranges therein, such as from 40 °C to 120 °C.

[0032] The hydrogenation feed 106 may then be introduced to the hydrotreater 208 with a hydrogen stream 108 to hydrogenate at least the organic component to produce a hydroprocessed stream 1 10. Hydrogenating the organic component in the hydrogenation feed 106 with the hydrogen stream 108 may produce the hydroprocessed stream 1 10 at an increased temperature than prior to entry into the hydrotreater 208. For example, assuming a hydrogenation feed 106 containing naphtha (1 14 g / mol average molecular weight) with 8.5 mol.% alkyl-aromatic benzene, hydrogenation with 0.26 mole of hydrogen per 1 mole of naphtha may generate approximately 19.4 kJ of heat per mole of feed. Accordingly, the heating capacity of the hydrotreater 208 may be approximately 0.2547 kJ / mol.K, resulting in an increase in feed temperature of from 100 °C to 173 °C.

[0033] The hydrotreater 208 may operate at a temperature of from 70 °C to 140 °C, such as from 80 °C to 120 °C, such as for an alkyl-aromatic-containing or olefin-containing hydrogenation feed 106. The hydrotreater 208 may also operate at a pressure of from 20 bar to 200 bar, such as from 20 bar to 50 bar, from 50 bar to 100 bar, from 100 bar to 150 bar, from 150 bar to 200 bar, or any combination of the preceding ranges or smaller range therein. The hydrotreater 208 may also operate at a temperature sufficient to hydrogenate the organic components in the hydrogenation feed 106. Without being limited by theory, producing the hydroprocessed stream 1 10 at the increased temperature may vaporize at least a portion of the hydroprocessed stream 1 10, thereby reducing the heating duty of at least the initial heat exchanger, but also the downstream heating duty of the downstream heat exchangers, as explained in further detail hereinbelow. Further, producing the hydroprocessed stream 1 10 at the increased temperature may also reduce the chance for film boiling as the hydroprocessed stream 1 10 is mixed with dilution steam 1 16, as explained in further detail hereinbelow.

[0034] For example, and as illustrated in FIG. 2, the hydrogenation of increasing amounts of organic components (benzene as the alkyl-aromatic organic component in FIG. 2) may increase the temperature of the feed, and thereby the mass vapor fraction (vaporization percentage of the hydroprocessed stream 1 10) prior to being mixed with the dilution steam 1 16. Also as illustrated in FIG. 2, an increasing amount of organic components may also increase the amount of C15+ hydrocarbon fraction 104 able to be mixed with the hydrogenation feed 106 and yet still achievecomplete vaporization prior to mixing with the dilution steam 1 16. This may reduce the preheating burden on the one or more heat exchangers, and by proxy, the hydrocarbon upgrading furnace 220, reducing CO2 emissions of the hydrocarbon upgrading furnace 220.

[0035] Further, in embodiments herein, inclusion of increasing amounts of organic components in the hydrocarbon mixture 102 may also increase the amount of C15+ hydrocarbon fraction 104 that may be included in the hydrogenation feed 106 and still achieve sufficient vaporization. As used herein “sufficient vaporization”, is a quality of a feed referring to the feed being at least 90 wt.% in the vapor phase, such as from 90 wt.% to 91 wt.%, from 91 wt.% to 95 wt.%, from 95 wt.% to 99 wt.%, from 99 wt.% to 100 wt.%, or any combination of the previous ranges or smaller range therein, such as from 90 wt.% to 100 wt.%. The relationship between the weight ratio of organic component in the hydrocarbon mixture 102 and the weight ratio of the C 15+ hydrocarbon fraction 104 in the hydrogenation feed 106 may be shown with reference to FIG. 2. Particularly, FIG. 2 illustrates that, for embodiments herein, maintaining the weight percent of organic component at least half that of the weight percent C 15+ hydrocarbon fraction 104 will result in a hydroprocessed stream 1 10 with sufficient vaporization. Particularly, maintaining the weight percent of organic component by weight of the hydrocarbon mixture 102 at least half that of the weight percent C 15+ hydrocarbon fraction 104 by weight of the hydrogenation feed 106 will still result in a hydroprocessed stream 1 10 with sufficient vaporization.

[0036] Without being limited by theory, this is contrary to established thought in the field, as the inclusion of heavier hydrocarbons in the feed would traditionally be thought to increase the pre-heating burden of the one or more heat exchangers to pre-heat the feed to achieve sufficient vaporization, as well as the energy burdens of the system as a whole to maintain desired yields. Further, in the event of an existing hydrocarbon upgrading furnace, the inclusion of heavier hydrocarbons in the feed would traditionally lead to higher fouling in the convection section if the preheater cannot sufficiently vaporize the heavier molecules. This can be illustrated with respect to FIGS. 2-4, as inclusion of increasing amounts of C 15+ hydrocarbon fraction 104 increased the dew point of the mixture (FIG. 3) as well as reduced the degree of vaporization prior to mixing with the dilution steam 1 16 for the design without the hydrotreater 208. However, referring to FIG. 4, for the embodiments including the hydrotreater 208, the hydroprocessed stream 1 10 still achieved complete vaporization by having a mixture temperature above the mixture dew point.

[0037] In FIGS. 3 and 4, mixture temperature was simulated at the inlet of a second heat exchanger 216, with 500 kilograms of dilution steam 1 16 per metric ton of hydroprocessed stream 1 10. Assumed in FIGS. 3 and 4 was a naphtha feed containing approximately 10 wt.% benzene as alkyl-aromatic by weight of the naphtha feed, the average molecular weight of the naphtha being 1 14 g / mol. Also assumed was that the hydrogenation feed 106 entered the hydrotreater 208 at a temperature of 100 °C with 0.26 moles of hydrogen per 1 mole of hydrogenation feed 106. As previously described, benzene hydrogenation generates approximately 19.4 kJ of heat per mole of naphtha, increasing the temperature of the hydrogenation feed 106 to the hydroprocessed stream 1 10 from approximately 100 °C to 176 °C. In FIG. 4, 200 normal cubic meters per cubic meter of unreactaed hydrogen stream 108 to naphtha (Nm3 / m), (corresponding to approximately 22.5 kilograms hydrogen per metric ton of hydrogenation feed 106) also reduced the partial pressure of the rest of the hydroprocessed stream 1 10, further reducing the mixture dew point for the last example.

[0038] Still referring to FIG. 1 , the hydrogen stream 108 and the hydrogenation feed 106 may be mixed within the hydrotreater 208, or may be pre-mixed in a second mixer 206. While not illustrated, the hydrotreater 208 may also flow the hydrogen stream 108 counter to the flow of the hydrogenation feed 106, i.e., the hydrotreater 208 may be a counter-current hydrotreater 208. For example, and in embodiments, the hydrogen stream 108 may be introduced from a lower portion of the hydrotreater 208 and flow upwards to an upper portion of the hydrotreater 208, whereas the hydrogenation feed 106 may be introduced from the upper portion of the hydrotreater 208 and flow downwards to the lower portion of the hydrotreater 208. In embodiments, and as illustrated in FIG. 5, the inclusion of the counter-current hydrotreater 208 may result in increased heat transfer along the length of the hydrotreater 208 as compared to a co-current hydrotreater 208. In FIG. 5, the simulated feed was 50 wt.% olefins as organic component with the balance Ci 5+ hydrocarbons and pyrolysis gasoline as hydrocarbon. Without being limited by theory, the increased heat transfer in the counter-current hydrotreater 208 may result in increased transfer of heat from the hydrogenated organic component to the remainder of the hydrogenation feed 106, smoothening the temperature gradients across the hydrotreater 208 for highly reactive feeds, such as those containing alkyl-aromatics and / or olefins.

[0039] Without being limited by theory, a further benefit of the counter-current hydrotreater 208 may be to limit the presence of corrosive species, including but not limited to ammonia saltsand hydrochloric acid, in the hydroprocessed stream 1 10. Particularly, flowing the hydrogen stream 108 counter to the hydrogenation feed 106 may operate to separate gaseous species, including the corrosive species, from the liquid effluent of the hydroprocessed stream 1 10. Should desired hydrocarbons be present in a sufficient amount in the hydrogen stream 108 carrying the gaseous corrosive species, said stream may be further separated to recover the desired hydrocarbons before being reintroduced to the hydroprocessed stream 1 10.

[0040] in embodiments, dimethyl-disulfide may also be introduced to the hydrotreater 208 along with the hydrogenation feed 106. Without being limited by theory, the presence of dimethyldisulfide in the hydrogenation feed 106 may operate to preferentially form H2S on a hydrogenation catalyst in the hydrotreater 208, passivating the downstream heat exchangers of the hydrotreater 208 as well as the coils in the hydrocarbon upgrading furnace 220. A conventional upgrading furnace would form H2S at higher temperature, therefore H2S would have passivated only the coils, rather than the heat exchangers in addition. The direct conversion of dimethyl-disulfide to H2S also decreases the formation of CS2 in the coils of the hydrocarbon upgrading furnace 220. The hydrogenation catalyst used in the hydrotreater 208 may be any hydrogenation catalyst known in the art.

[0041] After exiting the hydrotreater 208, the dilution steam 1 16 may be introduced to the hydroprocessed stream 1 10 to form a hydroprocessed stream / dilution steam mixture 120. Introducing the hydroprocessed stream 1 10 to the dilution steam 1 16 may operate to vaporize the remaining portion of the hydroprocessed stream 1 10, as the temperature of the hydroprocessed stream / dilution steam mixture 120 may be above the dew point of the hydroprocessed stream / dilution steam mixture 120.

[0042] However, before being introduced to the dilution steam 1 16, the hydroprocessed stream 1 10 may enter a separator 210. The separator 210 may separate the hydroprocessed stream 110 into a vapor fraction 1 12 and a liquid phase 1 14. The separator 210 may also operate to depressurize the hydroprocessed stream 1 10. Without being limited by theory, depressurizing the hydroprocessed stream 1 10 in the separator may contribute to additional vaporization of the hydroprocessed stream 1 10. The hydroprocessed stream 1 10 may exit the hydrotreater 208 at a pressure of from of from 10 bar to 200 bar exiting the hydrotreater 208, such as from 20 bar to 30 bar, from 30 bar to 40 bar, from 40 bar to 50 bar, from 50 bar to 100 bar, from 100 bar to 150 bar, from 150 bar to 200 bar, or any combination of the preceding ranges or smaller range therein. Thehydroprocessed stream J 10 may then be depressurized to a pressure of from 1 .5 bar to 4 bar, such as from 1 .5 bar to 1 .7 bar, from 1 .7 bar to 2.3 bar, from 2.3 bar to 2.5 bar, from 2.5 bar to 3 bar, from 3 bar to 3.3 bar, from 3.3 bar to 4 bar, or any combination of the preceding ranges or smaller ranges therein, in the separator 210.

[0043] Without being limited by theory, a further benefit of depressurizing the hydroprocessed stream 1 10 in the separator 210 may be to limit the formation of corrosive species, including but not limited to ammonia salts and hydrochloric acid, which are known to have the potential to form at high pressure in the hydroprocessed stream 1 10.

[0044] The vapor fraction 1 12 may also be sent to a pressure reducing valve / turbo-expander 212 before being pre-mixed with the dilution steam 116 to form a vapor-phase / dilution steam 1 16 mixture 1 18, whereas the liquid phase 1 14 may be sent to a third mixer 214 to be mixed with the vapor-phase / dilution steam 1 16 mixture 1 18 and form the hydroprocessed stream / dilution steam mixture 120. Without being limited by theory, mixing the vapor and liquid phases of the hydroprocessed stream 1 10 may reduce the likelihood of film boiling in the third mixer 214 as well as the various other transfer lines within the system.

[0045] As used herein, “film boiling” generally refers to a phenomenon that occurs when heat flux from a hot to cold stream across the wall of a heat exchanger causes a film of remaining liquid of the fluid being heated to form and at least partially cover the heating surface This film of liquid becomes trapped between the majority of the fluid and the heating surface, and thereby significantly increases the residence time of the boiling liquid leading to initiating thermal reactions which cause fouling”. For example herein, film boiling may cause fouling of the hydroprocessed stream 1 10 to form within the heat exchangers when uncontrolled or unplanned for, thereby reducing the effectiveness of the heat exchangers, and in severe instances, critical failure of the materials of the heat exchanger.

[0046] Still referring to FIG. 1 , the method may further comprise preheating the hydroprocessed stream / dilution steam mixture 120. The hydroprocessed stream / dilution steam mixture 120 may be preheated by introducing the hydroprocessed stream / dilution steam mixture 120 to the second heat exchanger 216 to preheat the hydroprocessed stream / dilution steam mixture 120 to a temperature in the range of 200 °C to 450 °C. The hydroprocessed stream / dilution steam mixture 120 may be further preheated by introducing the hydroprocessed stream / dilution steammixture 120 to a third heat exchanger 2 ) 8 to further preheat the hydroprocessed stream / dilution steam mixture 120 to a temperature in the range of 400 °C to 700 °C.

[0047] Still referring to FIG. 1 , the method may further comprise upgrading the hydroprocessed stream / dilution steam mixture 120 in a hydrocarbon upgrading furnace 220 to form a cracked gas effluent 124. The hydrocarbon upgrading furnace 220 may comprise one or more coils configured to transport the hydroprocessed stream / dilution steam mixture 120 through the hydrocarbon upgrading furnace 220 as well as a radiant section 222 configured to ignite a flue gas 122 and heat the one or more coils. In embodiments, and as shown in FIG. 1 at least one of the heat exchangers of the system may be positioned within the hydrocarbon upgrading furnace 220. Without being limited by theory, positioning the heat exchangers within the hydrocarbon upgrading furnace 220, may further reduce energy consumption of the system as well as the methods utilizing the system, as the ignited flue gas 122 may transfer excess heat to the heat exchangers.

[0048] The cracked gas effluent 124 may then be introduced to a fourth heat exchanger 224, wherein the cracked gas effluent 124 may be cooled to a lower temperature. For example, and in embodiments, the cracked gas effluent 124 may be cooled by the fourth heat exchanger 224 to a temperature in the range of 300 °C to 500 °C. The cracked gas effluent 124 may then be further treated to form a cracked gas. Without being limited by theory, the primary purpose of cooling the cracked gas effluent 124 may be to prevent further undesired reactions.

[0049] For example, and in embodiments, the temperature of the cracked gas effluent 124 exiting the fourth heat exchanger 224 may be generally chosen to be high enough so that substantial fouling due to condensation of heavy components in the cracked gas effluent 124 does not occur, but also low enough that undesired side reactions and fouling are reduced.

[0050] Methods herein may also comprise a heat transfer fluid, as well as a storage medium for a heat transfer fluid. The heat transfer fluid may comprise steam 134. The storage medium may comprise a steam drum 226 for the steam 134. The steam drum 226 may be fluidly connected to the fourth heat exchanger 224 for transferring steam condensate 126 to the fourth heat exchanger 224 and saturated steam 128 back to the steam drum 226. Introducing the steam condensate 126 to the fourth heat exchanger 224 may heat the steam condensate 126, thereby forming the saturated steam 128 (saturated mixture of steam and water).

[0051] Steam condensate feed 126 for the steam drum 226 may be introduced through a makeup water stream 130. The make-up water stream 130 may be introduced to a fifth heat exchanger228, wherein the fifth heat exchanger 228 may heat the make-up water stream to produce the steam condensate 126. The steam drum 226 may also further comprise a purge valve, which may also be commonly referred to as a “blowdown valve.” As will be understood in the art, the purge valve may operate to intentionally waste or ‘bleed’ water and steam from the steam drum 226 through the purge valve as blowdown steam 132 to avoid concentration of impurities during continued use and evaporation of the steam 134.

[0052] In embodiments, the method may also comprise exporting steam 134 from the steam drum 226 to a sixth heat exchanger 232 to form a superheated steam 138 for export. Without being limited by theory, the steam 134 may be superheated by the sixth heat exchanger 232 by the sixth heat exchanger 232 being placed in proximity to the radiant section 222 within the hydrocarbon upgrading furnace 220, thereby utilizing the excess heat of the ignited flue gas 122 to superheat the steam 134. The superheated steam 138 may be exported for use in any one of a number of further downstream units, including for process heating and shaft work applications. The sixth heat exchanger 232 may heat the steam 134 from the steam drum 226 to a temperature in the range of 350 °C to 550 °C.

[0053] As shown in the Examples below, embodiments herein may contribute to increased vaporization of the stream 120, as well as reducing the pre-heating energy burden of the various heat exchangers and the hydrocarbon upgrading furnace. The embodiments herein may also due so while processing a hydrocarbon feed with significant quantities of C15+ hydrocarbon fraction 104, increasing the range of feedstocks possible to produce ethylene. Without being limited by theory, the embodiments herein may also due so while processing a hydrocarbon feed with significant quantities of molecules such as aromatics, olefins and alcohols.EXAMPLES

[0054] Simulations of the feed stream upgrading process, according to the embodiments herein, were performed using ASPEN PLUS® V 12.1 software, utilizing the PSRK property method and the NBS method for steam properties. The simulation of the process was then compared to a comparative design without the hydrotreater 208 for various feeds. Example 1 used a combination of naphtha (hexane) as the hydrocarbon and benzene as the organic component, with a hexane / benzene weight ratio of 90: 10. Example 2 was similar to Example 1 in all aspects exceptthat hydrotreated vegetable oil was added as the C ; 5+ hydrocarbon fraction 104 with a hydrocarbon mixture 102 to C15+ hydrocarbon fraction 104 weight ratio of 77.5:22.5. Example 3 used a combination of ethane as the hydrocarbon and ethanol as the organic component with an ethane / ethanol ratio of 90: 10.

[0055] EXAMPLE 1

[0056] The following assumptions were made for Example 1. The flue for the hydrocarbon upgrading furnace 220 was methane provided at 25 °C. Air is also introduced at 25°C (relative humidity 0%), the air flow rate being adjusted so that oxygen volumetric fraction is 2% in the flue gas (methane). The radiant section 222 absorbs 3.15 GJ / h to transfer heat to the process coils, with a fixed heat rate regardless of the feed. This heat transfer was assumed based on an average heat consumption of 25 GJ / ton of ethylene for naphtha furnaces, 30 wt% ethylene yield, and 42% thermal efficiency for the firebox. The cracked gas effluent 124 conditions were set to 850°C and 1 .7 bar. The composition of the cracked gas relies on the article of Sandrameli et al: Systematics and modeling representations of naphtha thermal cracking for olefin production. J. Anal. AppL Pyrolysis 73 (2005) 305-313. The same provides detailed composition for a cracked gas produced at 856°C. The composition is presented in Table 1 . The cracked gas is quenched at the fourth heat exchanger 224 to obtain a temperature of 350 °C at 1.7 bar. Boiler feed water is supplied to the steam drum 226 at 120 °C and 120 bar, preheated by fifth heat exchanger 228, with 2% of the steam / water withdrawn as blowdown steam 132. The fifth heat exchanger and the hydrocarbon upgrading furnace 220 are sized so that the flue gas temperature over the fifth heat exchanger is approximately 280 °C. The saturated steam 128 exiting the fourth heat exchanger 224 reaches a temperature of 325 °C at 120 bar and is sent to sixth heat exchanger 232 to be heated to form superheated steam 138 for export. The sixth heat exchanger 232 and the hydrocarbon upgrading furnace 220 are sized to provide 1 .06 GJ / h of fixed heat to the sixth heat exchanger 232 for a final temperature of approximately 500 °C at 120 bar. Karimzadeh et al. (Flowsheeting of steam cracking furnaces, chemical engineering research and design. 87 (2009) 36-46), was used to define the heat duty for the sixth heat exchanger. Hydrogen inflow to the hydrotreater 208 is at 35 °C and 30 bar.

[0057] Table 1 : Cracked Gas Effluent Composition for Examples ] and 2 per Sandrameli et al.

[0058] As previously stated, the hydrocarbon feed in Example 1 is naphtha with 90 wt.% hexane and 10 wt.% benzene at 100 °C and 6 bar. The dilution steam 1 16 is provided at 220 °C and 6 bar. The dilution steam 1 16 to hydroprocessed steam ratio was approximately 0.5: 1 by weight. The hydrocarbon feed is first preheated in the first heat exchanger 204 prior to being hydrogenated with the hydrogen stream 108. The second and third heat exchangers preheat the feed to an outlet temperature of 600 °C. The heating duty of the comparative design and the design according to FIG. 1 are shown below in Tables 2 and 3, respectively.

[0059] Table 2: Heating Duty of Example 1 ; Comparative Design (no hydrotreater)

[0060] Table 3: Heating Duty of Example I : FIG. 1 Design (with hydrotreater)[0061J As shown in Tables 2 and 3, inclusion of the hydrotreater 208 resulted in reductions of the required heating duty of the third heat exchanger 218 over the comparative design. This lower heating duty may in turn be utilized by the fifth heat exchanger 228 to pre-heat a greater amount of the make-up water stream 130, as well as in the exporting of a greater amount of the superheatedsteam 138 for export to other downstream units. Further, it can be observed that the temperature of the feed entering the second heat exchanger 216 is noticeably higher for that of the design including the hydrotreater 208 vs. the comparative design. It is noted that this energy analysis does not include the energy footprint of producing hydrogen.

[0062] EXAMPLE 2

[0063] As previously mentioned, Example 2 is identical to Example 1 except that a hydrotreated vegetable oil was added for the Ci 5+ hydrocarbon fraction 104 with a hydrocarbon mixture 102 to C 15+ hydrocarbon fraction 104 weight ratio of 77.5:22.5. The composition of the hydrotreated vegetable oil is shown in Table 4, assumed from Kiefel et al. Conceptual Process Design: Production of Hydrotreated Vegetable Oil as an Additive for Petro-Diesel. December 30, 2018, RWTH Aachen University.

[0064] Table 4: Composition of Hydrotreated Vegetable Oil (HVO)

[0065] The heating duty of the comparative design and the design according to FIG. 1 are shown below in Tables 5 and 6, respectively. Initially, it can be observed that the temperature of the feed entering the second heat exchanger 216 is noticeably higher for that of the design including the hydrotreater 208 vs. the comparative design. Further, as shown in Tables 5 and 6, inclusion of the hydrotreater 208 resulted in an increase of the vapor fraction of the stream 120 upstream the heat exchanger 216. Further yet, as shown in Tables 5 and 6, inclusion of the hydrotreater 208 resulted in reductions of the required heating duty of the third heat exchanger 218 over the comparative design. This lower heating duty may in turn be utilized by the fifth heat exchanger 228 to pre-heat a greater amount of the make-up water stream 130, as well as in the exporting of a greater amount of the superheated steam 138 for export to other downstream units.

[0066] Table 5: Heating Duty of Example 2: Comparative Design (no hydrotreater)

[0067] Table 6: Pleating Duty of Example 2: FIG. 1 Design (with hydrotreater)

[0068] EXAMPLE 3

[0069] As previously mentioned, Example 3 utilizes a combination of ethane as the hydrocarbon and ethanol as the organic component with an ethane / ethanol ratio of 90: 10. It is known from literature (Platts, S&P Global, Specifications Guide, Europe and Africa Refined Oil Products, 2023) that feeds of hydrocarbon upgrading furnaces tolerate up to 100 ppm ofoxygenates. In the current example ethanol hydrogenation in the hydrotreater 208 will decrease ethanol content within the hydrocarbon upgrading furnace 220 from 10% to approximately 0%,1.e. trace amounts. Further, the comparative design only utilizes ethane as feed. The following assumptions were made for Example I . The conditions for the flue gas 122, hydrocarbon upgrading furnace 220, and the cracked gas effluent 124 were identical to that for Examples 1 and2. The composition of the cracked gas relies on the article of Zimmermann et al: Ethylene. ULLMANN’s Encyclopaedia of industrial chemistry, 2012 Wiley-VCH Verlag GmbH & Co. KGaA, Weinheim. A yields reactor was also set up in Aspen Plus in order to estimate the heat (4.04 GJ / h) required to convert ethane to the composition of Table 7 below and increase the temperature of the feed from 600 °C to 850 °C. Thermal efficiency was assumed as 42%.

[0070] Table 7: Cracked Gas Effluent Composition for Example 3 per Zimmermann et al.[00711 The cracked gas was quenched at the fourth heat exchanger 224 similar to Examples 1 and 2. Boiler feed water and blowdown was also similar to Examples I and 2. The fifth heat exchanger and the hydrocarbon upgrading furnace 220 are sized so that the flue gas temperature over the fifth heat exchanger is approximately 360 °C. The saturated steam 128 exiting the fourth heat exchanger 224 reaches a temperature of 325 °C at 120 bar and is sent to sixth heat exchanger 232 to be heated to form superheated steam 138 for export. The sixth heat exchanger 232 and the hydrocarbon upgrading furnace 220 are sized to provide 1.26 GJ / h of fixed heat to the sixth heat exchanger 232 for a final temperature of approximately 500 °C at 120 bar.

[0072] Contrasting with Examples 1 and 2, the first heat exchanger 204 transfers 0.72 GJ / h of heat to the ethane and ethanol feed, with inlet conditions at approximately 35 °C and 30 bar. The second heat exchanger 216 transfers 0.61 GJ / h heat from the ignited flue gas 122 to the hydrocarbon mixture 102 120. Finally, the third heat exchanger 218 heats the hydrocarbon mixture 102 to a temperature of approximately 600 °C.

[0073] The heating duty of the comparative design and the design according to FIG. 1 are shown below in Tables 8 and 9, respectively. As previously stated, the comparative design does not include ethanol as feed. Without being limited by theory, ethanoi, and in general alcohols, are not traditionally included as feeds into steam crackers as the upper bound of oxygenates that still result in the desired conversion is typically in the order of 100 ppm. However, by including the hydrotreater 208 prior to the hydrocarbon upgrading furnace 220, ethanol may be converted to ethane and water, while also producing the excess heat associated with the chemical reaction. Further, by the generation of water as a product, reduction of the amount of dilution steam 1 16 is possible, with Table 9 reducing the dilution steam 1 16 to hydroprocessed stream 1 10 ratio from approximately 0.3: 1 to 0.26: 1.

[0074] Table 8: Heating Duty of Example 3, Comparative Design (no hydrotreater)

[0075] Table 9: Heating Duty of Example 3, FIG. I Design (with hydrotreater)

[0076] It is noted that recitations in the present disclosure of a component of the present disclosure being “operable” or “sufficient” in a particular way, to embody a particular property, or to function in a particular manner, are structural recitations, as opposed to recitations of intended use. More specifically, the references in the present disclosure to the manner in which a component is “operable” or “sufficient” denotes an existing physical condition of the component and, as such, is to be taken as a definite recitation of the structural characteristics of the component.

[0077] The singular forms “a,” “an” and “the” comprise plural referents, unless the context clearly dictates otherwise.|0078] I hroughout this disclosure ranges are provided. It is envisioned that each discrete value encompassed by the ranges are also comprised. Additionally, the ranges which may be formed by each discrete value encompassed by the explicitly disclosed ranges are equally envisioned.

[0079] As used in this disclosure and in the appended claims, the words “comprise,” “has,” and “comprise” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

[0080] As used in this disclosure, terms such as “first”, “second”, “third”, etc. are arbitrarily assigned and are merely intended to differentiate between two or more instances or components. It is to be understood that the words “first”, “second”, “third”, etc. serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location, position, or order of the component. Furthermore, it is to be understood that the mere use of the term “first”, “second”, or “third” does not require that there be any “fourth” component, although that possibility is contemplated under the scope of the present disclosure.

[0081] For the purposes of describing and defining the present embodiments it is noted that the terms “substantially” and “approximately” are utilized herein to represent the inherent degree of uncertainty that may be attributed to any quantitative comparison, value, measurement, or other representation. The terms “substantially” and “approximately” are also utilized herein to represent the degree by which a quantitative representation may vary from a stated reference without resulting in a change in the basic function of the subject matter at issue.

[0082] According to a first aspect, a method of upgrading a hydrocarbon mixture comprises providing a hydrogenation feed comprising a hydrocarbon mixture, the hydrocarbon mixture comprising a hydrocarbon and an organic component; introducing the hydrogenation feed to a hydrotreater with a hydrogen stream to hydrogenate at least the organic component and produce a hydroprocessed stream at an increased temperature; introducing dilution steam to the hydroprocessed stream, thereby forming a hydroprocessed stream / dilution steam mixture; preheating the hydroprocessed stream / dilution steam mixture; and upgrading the hydroprocessed stream / dilution steam mixture in a hydrocarbon upgrading furnace to form a cracked gas effluent, wherein the hydrocarbon in the hydrocarbon mixture comprises naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensates, C1-C4 hydrocarbons, or combinations thereof, the organic component is selected from one or more of olefins, alkyl-aromatics, or alcohols, and the hydrocarbon mixture comprises from 0.01 wt.% to 25 wt.% organic component by weight of the hydrocarbon mixture.

[0083] A second aspect may comprise the first aspect, wherein the hydrocarbon mixture comprises from 10 wt.% to 25 wt.% organic component by weight of the hydrocarbon mixture.

[0084] A third aspect may comprise the second aspect, and may further comprise mixing the hydrocarbon mixture with a C15+ hydrocarbon fraction to provide the hydrogenation feed, wherein the hydrogenation feed comprises from 5 wt.% to 45 wt.% Cm hydrocarbon fractions by weight of the hydrogenation feed.

[0085] A fourth aspect may comprise the third aspect, wherein the weight percent organic component by weight of the hydrocarbon mixture is at least half that of the weight percent C15+ hydrocarbon fraction by weight of the hydrogenation feed; and the hydroprocessed stream / dilution steam mixture is at least 90 wt.% vaporized prior to being preheated.

[0086] A fifth aspect may comprise any previous aspect, wherein introducing the dilution steam to the hydroprocessed stream further comprises separating the hydroprocessed stream into a vaporphase hydroprocessed stream and a liquid-phase hydroprocessed stream; introducing dilution steam to the vapor-phase hydroprocessed stream to form a vapor-phase / dilution steam mixture; introducing the vapor-phase / dilution steam mixture and the liquid-phase hydroprocessed stream to a mixer; and mixing the vapor-phase mixture and the liquid-phase hydroprocessed stream in the mixer, thereby forming the hydroprocessed stream / dilution steam mixture.

[0087] A sixth aspect may comprise any previous aspect, wherein the hydrocarbon comprises naphtha, pyrolysis gasoline, or both; and the organic component comprises alkyl-aromatics, olefins, or both.

[0088] A seventh aspect may comprise any one of the first through fifth aspects, wherein the hydrocarbon comprises ethane and the organic component is ethanol.

[0089] An eighth aspect may comprise any previous aspect, and may further comprise initially preheating the hydrocarbon mixture or the hydrogenation feed in a first heat exchanger to a temperature of from 30 °C to 200 °C prior to hydrogenating the hydrocarbon mixture or the hydrogenation feed.

[0090] A ninth aspect may comprise any previous aspect, wherein preheating the hydroprocessed stream / dilution steam mixture comprises introducing the hydroprocessed stream / dilution steam mixture to a second heat exchanger to preheat the hydroprocessedstream / dilution steam mixture to a temperature in the range of 200 °C to 450 °C; introducing the hydroprocessed stream / dilution steam mixture to a third heat exchanger downstream of the second heat exchanger to further preheat the hydroprocessed stream / dilution steam mixture to a temperature in the range of 400 °C to 700 °C; or both.

[0091] A tenth aspect may comprise any previous aspect, wherein the hydrotreater is configured to flow the hydrocarbon mixture or the hydrogenation feed counter to the hydrogen stream.

[0092] An eleventh aspect may comprise any previous aspect, wherein the hydroprocessed stream is depressurized prior to introducing the dilution steam.

[0093] A twelfth aspect may comprise any previous aspect, wherein the hydrocarbon upgrading furnace comprises one or more coils configured to transport the hydroprocessed stream / dilution steam mixture through the hydrocarbon upgrading furnace; and a radiant section configured to ignite a flue gas and heat the one or more coils.

[0094] A thirteenth aspect may comprise any previous aspect, and may further comprise introducing the cracked gas effluent to a fourth heat exchanger to cool the cracked gas effluent to a temperature in the range of 300 °C to 500 °C, wherein a steam drum is fluidly connected to the fourth heat exchanger for transferring steam condensate to the fourth heat exchanger and saturated steam back to the steam drum.

[0095] A fourteenth aspect may comprise any previous aspect, and may further comprise introducing a make-up water stream to a fifth heat exchanger to produce the steam condensate; introducing the steam condensate to the steam drum; and introducing saturated steam from the steam drum to a sixth heat exchanger to form a superheated steam for export.

[0096] A fifteenth aspect may comprise any previous aspect, wherein at least one of the first, second, third, fourth, or fifth heat exchangers are located within the hydrocarbon upgrading furnace.

[0097] Having described the subject matter of the present disclosure in detail and by reference to specific embodiments, it is noted that the various details disclosed in the present disclosure should not be taken to imply that these details relate to elements that are essential components of the various embodiments described in the present disclosure. Further, it will be apparent that modifications and variations are possible without departing from the scope of the present disclosure, comprising, but not limited to, embodiments defined in the appended claims.

Claims

CLAIMS1 . A method of upgrading a hydrocarbon mixture, comprising: providing a hydrogenation feed comprising a hydrocarbon mixture, the hydrocarbon mixture comprising a hydrocarbon and an organic component; introducing the hydrogenation feed to a hydrotreater with a hydrogen stream to hydrogenate at least the organic component and produce a hydroprocessed stream at an increased temperature; introducing dilution steam to the hydroprocessed stream, thereby forming a hydroprocessed stream / dilution steam mixture; preheating the hydroprocessed stream / dilution steam; and upgrading the hydroprocessed stream / dilution steam in a hydrocarbon upgrading furnace to form a cracked gas effluent, wherein the hydrocarbon in the hydrocarbon mixture comprises naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensates, C1-C4 hydrocarbons, or combinations thereof, the organic component is selected from one or more of olefins, alkyl-aromatics, or alcohols, and the hydrocarbon mixture comprises from 0.01 wt.% to 25 wt.% organic component by weight of the hydrocarbon mixture.

2. The method of claim 1 , wherein the hydrocarbon mixture comprises from 10 wt.% to 25 wt.% organic component by weight of the hydrocarbon mixture.

3. The method of claim 2, further comprising: mixing the hydrocarbon mixture with a C15+ hydrocarbon fraction to provide the hydrogenation feed, wherein the hydrogenation feed comprises from 5 wt.% to 45 wt.% C15+ hydrocarbon fractions by weight of the hydrogenation feed.

4. The method of claim 3, wherein:the weight percent organic component by weight of the hydrocarbon mixture is at least half that of the weight percent C15+ hydrocarbon fraction by weight of the hydrogenation feed; and the hydroprocessed stream / dilution steam mixture is at least 90 wt.% vaporized prior to being preheated.

5. The method of any previous claim, wherein introducing the dilution steam to the hydroprocessed stream further comprises; separating the hydroprocessed stream into a vapor-phase hydroprocessed stream and a liquid-phase hydroprocessed stream; introducing dilution steam to the vapor-phase hydroprocessed stream to form a vapor- phase / dilution steam mixture; introducing the vapor-phase / dilution steam mixture and the liquid-phase hydroprocessed stream to a mixer; and mixing the vapor-phase mixture and the liquid-phase hydroprocessed stream in the mixer, thereby forming the hydroprocessed stream / dilution steam mixture.

6. The method of any previous claim, wherein: the hydrocarbon comprises naphtha, pyrolysis gasoline, or both; and the organic component comprises alkyl-aromatics, olefins, or both.

7. The method of any one of claims 1 -5, wherein the hydrocarbon comprises ethane and the organic component is ethanol.

8. The method of any preceding claim, further comprising initially preheating the hydrogenation feed in a first heat exchanger to a temperature of from 30 °C to 300 °C prior to hydrogenating the hydrogenation feed.

9. The method of any preceding claim, wherein preheating the hydroprocessed stream / dilution steam mixture comprises:introducing the hydroprocessed stream / dilution steam mixture to a second heat exchanger to preheat the hydroprocessed stream / dilution steam mixture to a temperature in the range of 200 °C to 450 °C; introducing the hydroprocessed stream / dilution steam mixture to a third heat exchanger downstream of the second heat exchanger to further preheat the hydroprocessed stream / dilution steam mixture to a temperature in the range of 400 °C to 700 °C; or both.

10. The method of any preceding claim, wherein the hydrotreater is configured to flow the hydrogenation feed counter to the hydrogen stream.1 1. The method of any preceding claim, wherein the hydroprocessed stream is depressurized prior to introducing the dilution steam.

12. The method of any preceding claim, wherein the hydrocarbon upgrading furnace comprises: one or more coils configured to transport the hydroprocessed stream / dilution steam mixture through the hydrocarbon upgrading furnace; and a radiant section configured to ignite a flue gas and heat the one or more coils.

13. The method of any preceding claim, further comprising introducing the cracked gas effluent to a fourth heat exchanger to cool the cracked gas effluent to a temperature in the range of 300 °C to 500 °C, and wherein a steam drum is fluidly connected to the fourth heat exchanger for transferring steam condensate to the fourth heat exchanger and saturated steam back to the steam drum.

14. The method of claim 13, further comprising: introducing a make-up water stream to a fifth heat exchanger to produce the steam condensate; introducing the steam condensate to the steam drum; andintroducing saturated steam from the steam drum to a sixth heat exchanger to form a superheated steam for export.

15. The method of any preceding claim, wherein at least one of the first, second, third, fourth, or fifth heat exchangers are positioned within the hydrocarbon upgrading furnace.

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