Process for upgrading hydrocarbon feed

Abstract

A method of upgrading a hydrocarbon mixture includes providing a hydrogenation feed comprising a hydrocarbon mixture, the hydrocarbon mixture comprising hydrocarbons and an organic component; introducing the hydrogenation feed together with a hydrogen stream to a hydrotreating device to hydrogenate at least the organic component and produce a hydrotreated stream at an elevated temperature; introducing a dilution steam into the hydrotreated stream, thereby forming a hydrotreated stream / dilution steam mixture; preheating the hydrotreated stream / dilute steam mixture; and upgrading the hydrotreated stream / dilute steam mixture in a hydrocarbon upgrading furnace to form a cracked gas effluent wherein the hydrocarbons in the hydrocarbon mixture comprise naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensate, C1-C4 hydrocarbons, or combinations thereof, the organic component is selected from one or more of an olefin, an alkylaromatic compound or an alcohol, and the hydrocarbon mixture comprises 0.01 wt% to 25 wt% of the organic component, based on the weight of the hydrocarbon mixture.

Description

TECHNICAL FIELD

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

[0002] Ethylene is widely used as an intermediate in the petrochemical industry, and its production exceeds that of any other intermediate organic. Most of the ethylene production is used to make ethylene oxide, ethylene dichloride, and polyethylene, which are precursors to a variety of everyday consumer products. Despite various improvements in process design, reliability, and safety over the years, steam crackers for forming hydrocarbons, such as ethylene, still rely heavily on a narrow range of flammable fossil fuels to provide process heat and energy, resulting in significant greenhouse gas emissions, including preheating feed compositions that are processed in steam crackers. However, the energy required for the steam cracking process to produce ethylene is about half that of competing processes (e.g., direct C1 conversion technologies), and is projected to remain the most energy efficient process.

[0003] Additionally, the feedstock for ethylene (olefins and aromatics) is traditionally limited, such that new sources of ethylene from hydrocarbons with compositions outside the typical range of feedstock, such as ethanol-rich ethane, with higher content of aromatics, olefins, diolefins, and heavier fractions such as C 15+ a liquid hydrocarbon fraction. SUMMARY

[0004] Accordingly, there is a need for methods that reduce the energy required to preheat feed in systems utilizing hydrocarbon upgrading furnaces. In particular, there is a need for methods that reduce the energy input to preheat and convert hydrocarbons in hydrocarbon upgrading furnaces utilizing flue gas as an energy source. Such methods would also ideally be compatible with the wider and heavier range of feedstock required for ethylene production, such as aromatics-rich, naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensates, C1-C5 hydrocarbons, alcohols, and C 15+ a feed of hydrocarbons.

[0005] However, liquid feeds with higher aromatics content are generally considered to be materials that result in lower ethylene yields and higher fouling tendencies. Additionally, crude C4-C5 hydrocarbons are generally rich in diolefins and olefins, often resulting in increased coking and fouling in hydrocarbon upgrading furnaces. Pyrolysis gasoline can contain diolefins, olefins, as well as aromatics. Additionally, processing of alcohols, such as ethanol, can result in a range of oxygenates in the feed that exceeds the acceptable range for hydrocarbon upgrading furnaces. Therefore, to convert previous feeds into a form that is acceptable for use in a hydrocarbon upgrading furnace, such as a steam cracker, pre-treatment in a separate upstream chemical plant is often required.

[0006] The systems and methods herein achieve the foregoing objectives by utilizing heat integration through the recycling of heat generated from the radiant section of a flue gas driven hydrocarbon reformer in one or more heat exchangers used to preheat the feed prior to reforming. The heat integration of the system can be achieved by capturing and utilizing all available heat in the process to efficiently produce the desired products. This should ideally be done under other process constraints, particularly to minimize fouling and side reactions that have a detrimental impact on the overall yield of the desired products. For example, conventional systems can only process a limited amount of C 15+ hydrocarbon fractions, as partial gasification can form fouling on the hot surfaces of the heat exchangers. This limits the processability of C 15+ hydrocarbon fractions.

[0007] Furthermore, the provision of an upstream hydroprocessor and associated feed containing a specific ratio of organic components to hydrocarbon feed reduces the reliance on the preheating of the partially gasified feed in the feed preheater. This can minimize or eliminate the need for a separate upstream standalone unit to modify the chemical composition of the hydrocarbon reforming feed prior to being subjected to the hydrocarbon reformer. Specifically, the reaction of the organic components in the hydroprocessor generates excess heat, thereby reducing the preheating burden of the associated feed preheater / heat exchanger, reducing the CO2 emissions of the hydrocarbon reformer and / or increasing the amount of excess preheating energy that can be used to drive other downstream processes. Furthermore, the upstream hydroprocessor can be operated at an elevated pressure compared to other units in the system. This elevated operating temperature will also increase the heat transfer between the organic components and the rest of the feed, thereby providing additional benefits.

[0008] The foregoing solution is also contrary to established ideas in the art, as the provision of additional refining units is generally considered to increase the energy consumption and load of the overall system, rather than reduce it.

[0009] Finally, the additional heat provided by the exothermic reaction of hydrogen with the reactive organic components of the feed in the hydroprocessor can also allow for the processing of a greater amount of heavy hydrocarbons (C 15+ ) in the hydrocarbon feed than in equivalent systems, as the hydrogenation of the organic components can aid in the gasification of these heavy hydrocarbons. For example, and as explained in further detail below, the hydroprocessor can convert alkyl aromatics to cycloalkanes, thereby resulting in a higher ethylene yield while reducing the formation of fouling from the aromatics. Furthermore, while olefins can result in a lower amount of ethylene, the hydrogenation of olefins and dienes eliminates the risk of fouling and results in a higher ethylene yield. Finally, the large amount of oxygenates present in alcohols such as ethanol, which are generally not directly processable in conventional hydrocarbon reformers, can be converted hydrocarbons and high temperature water that can be used as dilution steam.

[0010] According to one embodiment, a method for modifying a hydrocarbon mixture includes providing a hydrogenation feed comprising a hydrocarbon mixture containing hydrocarbons and an organic component; introducing the hydrogenation feed along with a hydrogen stream into a hydrotreating processor to hydrogenate at least the organic component and generate a hydrotreated feed stream at an elevated temperature; introducing dilution vapor into the hydrotreated feed stream to form a hydrotreated feed stream / dilution vapor mixture; preheating the hydrotreated feed stream / dilution vapor mixture; and modifying the hydrotreated feed stream / dilution vapor mixture in a hydrocarbon modification furnace to form a cracked gas effluent, wherein the hydrocarbons in the hydrocarbon mixture comprise naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensate, 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 contains 0.01% to 25% by weight of the organic component based on the weight of the hydrocarbon mixture.

[0011] Additional features and advantages of the embodiments described herein will be set forth in the following detailed description, and will in part will be apparent to those skilled in the art from the description or will be recognized by practice of the embodiments described herein, including the detailed description and claims provided below. Attached Figure Description

[0012] The following detailed description of specific embodiments of this disclosure can be best understood when read in conjunction with the accompanying drawings, in which:

[0013] Figure 1 A process flow diagram of an exemplary process according to the embodiments described herein is shown;

[0014] Figure 2 The organic components and C shown in the embodiments described herein are presented. 15+ The mass vapor fraction of the feed at the inlet of the second heat exchanger at different ratios of hydrocarbon fractions, and the same case in a comparative design without a hydrogenation processor;

[0015] Figure 3 The paper presents a comparison of the temperature of different compositions of feed at the inlet of the second heat exchanger with the dew point of the feed, according to the embodiment described herein.

[0016] Figure 4 The paper demonstrates a comparison between the temperature of different feed compositions at the inlet of the second heat exchanger and the dew point of the feed, according to the embodiment described herein; and

[0017] Figure 5 The paper demonstrates the variation of heat transfer of a given hydrogenation feed with exposure length for both countercurrent and cocurrent hydrogenation processors, according to the implementation scheme described herein. Detailed Implementation

[0018] The embodiments described herein relate to methods for modifying hydrocarbon mixtures, such as those comprising hydrocarbons, organic components, and optional C. 15+ A mixture of hydrocarbon fractions.

[0019] For the purpose of simplifying the schematic diagrams and illustrations of the accompanying drawings, numerous valves, temperature sensors, electronic controllers, and other components well-known to and likely employed by those skilled in the art in certain chemical processing operations are not included. Furthermore, ancillary components commonly included in typical chemical processing operations, such as air supply systems and catalyst hoppers, are not depicted. Ancillary components in typical upgrading units, such as venting systems, spent catalyst discharge subsystems, and catalyst replacement subsystems, are also not shown in the figures. It should be understood that these components are within the spirit and scope of the disclosed embodiments of the invention. However, operating components (such as those described in this disclosure) may be added to the embodiments described in this disclosure.

[0020] It should be further noted that the arrows in the accompanying drawings refer to process streams. However, arrows can also refer equivalently to delivery lines used to transfer process streams between two or more system components. Furthermore, arrows connected to system components define the inlet or outlet of each given system component. The direction of the arrows generally aligns with the primary direction of movement of the material contained within the physical delivery line represented by the arrow. Additionally, arrows not connected to two or more system components represent product streams leaving the depicted system or system inlet streams entering the depicted system. Product streams may be further processed in an accompanying chemical processing system or may be commercialized as a final product. System inlet streams may be streams transferred from an accompanying chemical processing system or may be unprocessed raw material streams. Some arrows may indicate circulating streams, which are outflows from system components and are recycled back into the system. However, it should be understood that in some embodiments, any illustrated circulating stream may be replaced by a system inlet stream of the same material, and a portion of the circulating stream may leave the system as a product.

[0021] Furthermore, the arrows in the accompanying drawings can schematically depict process steps for transferring material streams from one system component to another. For example, an arrow pointing from one system component to another can indicate the "transfer" of effluent from one system component to another, which may include the "discharge" or "removal" of process stream contents from one system component and the "introduction" of the product stream contents into another system component.

[0022] It should be understood that, according to the embodiments presented in the relevant figures, the arrow between two system components can indicate that the material flow is unprocessed between the two system components. In other embodiments, the material flow represented by the arrow can have substantially the same composition throughout the transport process between the two system components. Furthermore, it should be understood that, in embodiments, the arrow can indicate that at least 75% by weight, at least 90% by weight, at least 95% by weight, at least 99% by weight, at least 99.9% by weight, or even 100% by weight of the material flow is transported between the system components. Therefore, in embodiments, not all of the material flow represented by the arrow is transported between the system components, such as when there is a side flow.

[0023] It should be understood that in the schematic flow diagrams of the relevant accompanying figures, the intersection of two or more lines indicates that two or more process streams are "mixed" or "merged". Mixing or merging may also include mixing by directly introducing two streams into a similar reactor, separation unit, or other system component. For example, it should be understood that when two streams are depicted as being merged directly before entering a separation unit or reactor, in embodiments these streams may be equivalently introduced into the separation unit or reactor and mixed in the reactor. Alternatively, when two streams are depicted as entering a system component independently, in embodiments they may be mixed together before entering the system component.

[0024] However, it should also be understood that when two or more process streams enter the heat exchanger, these streams do not mix. Instead, they exchange heat through heat transfer, meaning heat is transferred from one stream to another without direct contact.

[0025] In this document, a range can be expressed as "within a range" from one specific value to another. When expressing such a range, another embodiment includes from this specific value and / or to another specific value. It should be further understood that the endpoint values ​​of each range are meaningful relative to and independent of the other endpoint value.

[0026] Additional features and advantages of the described embodiments (some of which are shown in the accompanying drawings) will be set forth in the detailed description below, and some of these will be apparent to those skilled in the art from the description, or will be recognized by practice of the described embodiments (including the detailed description below and the claims).

[0027] As used in this article, pressure values ​​expressed in "bar", "pascal" or any equivalent pressure unit can be understood as absolute pressure units, not gauge pressure units.

[0028] As previously described, embodiments thereof relate to a method for modifying a hydrocarbon mixture 102. The hydrocarbon mixture 102 may comprise hydrocarbons and organic components. Hydrocarbons may include naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensate, or C1-C4 hydrocarbons or combinations thereof. C1-C4 hydrocarbons may include methane, ethane, propane, propylene, butane, butadiene, or combinations thereof. Organic components may include olefins, alkyl aromatic compounds, or alcohols. Alcohols may include ethanol. Alkyl aromatic compounds may include BTX, such as, but not limited to, benzene, toluene, or xylene. The hydrocarbon mixture 102 may comprise 0% to 25% by weight of organic components, such as 0% to 10% by weight, 10% to 11% by weight, 11% to 15% by weight, 15% to 20% by weight, 20% to 24% by weight, 24% to 25% by weight, or combinations of the foregoing ranges or smaller ranges thereof, such as 14% to 21% by weight.

[0029] For example, and in the embodiments, when the hydrocarbon is naphtha, the organic component may be an alkyl aromatic compound or an olefin. Furthermore, when the hydrocarbon is pyrolytic gasoline, the organic component may be an alkyl aromatic compound or an olefin. Moreover, when the hydrocarbon is ethane, the organic component may be an alcohol, and may be particularly ethanol. These combinations are explained in further detail, at least in the examples.

[0030] Now for reference Figure 1 The system may include at least a first mixer 202, a hydrogenation processor 208, one or more heat exchangers, and a hydrocarbon reforming furnace 220. The method described herein may include providing a hydrogenation feed 106 comprising at least a hydrocarbon mixture. The method may also include reacting the hydrocarbon mixture 102 with C... 15+ Hydrocarbon fraction 104 is mixed to provide hydrogenation feed 106. Hydrocarbon mixture 102 and C... 15+ Hydrocarbon fraction 104 may be mixed in a first mixer 202. As used herein, "mixer" may be any suitable mixer known in the art, such as a simple mixing tee, ultrasonic device, small continuous stirred tank reactor (CSTR), or another known mixer. Hydrogenation feed 106 may contain 0% to 45% C based on the weight of hydrogenation feed 106. 15+ Hydrocarbon fraction 104, such as 0 wt% to 5 wt%, 5 wt% to 6 wt%, 6 wt% to 10 wt%, 10 wt% to 20 wt%, 20 wt% to 30 wt%, 30 wt% to 40 wt%, 40 wt% to 44 wt%, 44 wt% to 45 wt%, or combinations of the foregoing ranges or smaller ranges, such as 21 wt% to 41 wt%.

[0031] The hydrogenated feed 106 can then be introduced into the first heat exchanger 204 for initial preheating. The hydrogenated feed 106 can be preheated to a temperature of 30°C to 200°C, such as 30°C to 35°C, 35°C to 50°C, 50°C to 100°C, 100°C to 150°C, 150°C to 180°C, 180°C to 195°C, 195°C to 200°C, or any combination of the foregoing ranges or smaller ranges, such as 40°C to 120°C.

[0032] The hydrogenated feed 106 can then be introduced into the hydrotreating processor 208 along with the hydrogen stream 108 to hydrogenate at least the organic components to produce a hydrotreated feed stream 110. Hydrogenating the organic components in the hydrogenated feed 106 with the hydrogen stream 108 can produce the hydrotreated feed stream 110 at a higher temperature than before it enters the hydrotreating processor 208. For example, assuming the hydrogenated feed 106 contains naphtha (average molecular weight 114 g / mol) and 8.5 mol.% alkyl aromatic benzene, hydrogenating 1 mole of naphtha with 0.26 moles of hydrogen can generate approximately 19.4 kJ of heat per mole of feed. Therefore, the heating capacity of the hydrotreating processor 208 can be approximately 0.2547 kJ / mol.K, resulting in an increase in feed temperature from 100°C to 173°C.

[0033] The hydrogenation processor 208 can operate at temperatures ranging from 70°C to 140°C, such as 80°C to 120°C, for hydrogenation feeds 106 containing alkyl aromatic compounds or olefins. The hydrogenation processor 208 can also operate at pressures ranging from 20 bar to 200 bar, such as 20 bar to 50 bar, 50 bar to 100 bar, 100 bar to 150 bar, 150 bar to 200 bar, or any combination of the foregoing ranges or smaller ranges. The hydrogenation processor 208 can also operate at temperatures sufficient to hydrogenate the organic components in the hydrogenation feed 106. Without being theoretically limited, generating the hydrogenation process feed stream 110 at elevated temperatures can vaporize at least a portion of the hydrogenation process feed stream 110, thereby reducing the heating load at least on the initial heat exchanger and also reducing the downstream heating load on the downstream heat exchanger, as explained in further detail below. Furthermore, generating the hydrotreated feed stream 110 at an elevated temperature can reduce the chance of film boiling when the hydrotreated feed stream 110 is mixed with dilution vapor 116, as explained in further detail below.

[0034] For example, such as Figure 2 The increased amount of organic components (benzene as shown) Figure 2 Hydrogenation of the alkyl aromatic organic components in the feed can increase the feed temperature, thereby increasing the mass vapor fraction (the percentage of vaporization of the hydrotreated feed stream 110) before mixing with dilution vapor 116. Similarly, as... Figure 2 As demonstrated, increasing the amount of organic components can also increase the C content that can be mixed with the hydrogenation feed 106. 15+The amount of hydrocarbon fraction 104 is still fully vaporized before being mixed with dilution steam 116. This reduces the preheating load on one or more heat exchangers, and consequently also reduces the preheating load on the hydrocarbon reformer 220, thereby reducing CO2 emissions from the hydrocarbon reformer 220.

[0035] Furthermore, in the embodiments described herein, including an increased amount of organic component in the hydrocarbon mixture 102 may also increase the C content that may be included in the hydrogenation feed 106. 15+ The amount of hydrocarbon fraction 104, and still achieving sufficient vaporization. As used herein, “sufficient vaporization” refers to the mass of the feed, which means that the feed is at least 90 wt% in the vapor phase, such as 90 wt% to 91 wt%, 91 wt% to 95 wt%, 95 wt% to 99 wt%, 99 wt% to 100 wt%, or any combination of the foregoing ranges or smaller ranges, such as 90 wt% to 100 wt%. The weight ratio of the organic components in hydrocarbon mixture 102 to the C in hydrogenated feed 106. 15+ The relationship between the weight ratios of hydrocarbon fraction 104 can be referenced. Figure 2 Shown. Specifically, Figure 2 As shown, for the implementation scheme described in this paper, the weight percentage of the organic components is maintained at C. 15+ At least half of the weight percentage of the hydrocarbon fraction 104 will produce a hydrotreating stream 110 with sufficient vaporization. Specifically, the weight percentage of the organic component based on the weight of the hydrocarbon mixture 102 will be maintained at C based on the weight of the hydrotreating feed 106. 15+ At least half of the weight percentage of the hydrocarbon fraction 104 will still produce a feed stream 110 with sufficient gasification for hydrotreating.

[0036] This is not limited by theory, contrary to established ideas in the field, because the inclusion of heavier hydrocarbons in the feed has traditionally been considered to increase the preheating burden on one or more heat exchangers to preheat the feed for sufficient gasification, and to increase the overall system energy burden to maintain the desired yield. Furthermore, in the case of existing hydrocarbon reformers, the inclusion of heavier hydrocarbons in the feed has traditionally led to more severe fouling in the convection section if the preheater cannot adequately gasify the heavier molecules. This can be compared to... Figures 2 to 4 To demonstrate, because for a design without hydrogen processor 208, it includes an increased amount of C 15+ Hydrocarbon fraction 104 increased the dew point of the mixture. Figure 3 ), and the degree of gasification was reduced before mixing with dilution steam 116. However, reference Figure 4 In embodiments including the hydrogenation processor 208, the hydrogenation process of the feed stream 110 still achieves complete vaporization by bringing the temperature of the mixture above the mixture dew point.

[0037] exist Figure 3 andFigure 4 In the process, the temperature of the mixture is simulated at the inlet of the second heat exchanger 216, wherein each metric ton of hydrogenated feed 110 has 500 kg of dilution steam 116. Figure 3 and Figure 4 It is assumed that the naphtha feed contains approximately 10% by weight of benzene as an alkyl aromatic compound, and the average molecular weight of the naphtha is 114 g / mol. It is also assumed that the hydrogenation feed 106 enters the hydrotreating processor 208 at a temperature of 100°C, wherein each mole of hydrogenation feed 106 contains 0.26 moles of hydrogen. As previously stated, benzene hydrogenation generates approximately 19.4 kJ of heat per mole of naphtha, raising the temperature of the hydrogenation feed 106 to the hydrotreating stream 110 from approximately 100°C to 176°C. Figure 4 In the process, the 200 standard cubic meters per cubic meter of unreacted hydrogen stream 108 and naphtha (Nm3 / m) (corresponding to approximately 22.5 kg hydrogen per metric ton of hydrogenation feed 106) also reduced the partial pressure of the remaining hydrotreated feed stream 110, further reducing the dew point of the mixture in the last embodiment.

[0038] Still referencing Figure 1 The hydrogen stream 108 and the hydrogenated feed 106 can be mixed within the hydrogenation processor 208, or premixed in the second mixer 206. Although not shown, the hydrogenation processor 208 can also allow the hydrogen stream 108 to flow in the opposite direction to the flow of the hydrogenated feed 106; that is, the hydrogenation processor 208 can be a countercurrent hydrogenation processor 208. For example, and in an embodiment, the hydrogen stream 108 can be introduced from the lower part of the hydrogenation processor 208 and flow upwards to the upper part of the hydrogenation processor 208, while the hydrogenated feed 106 can be introduced from the upper part of the hydrogenation processor 208 and flow downwards to the lower part of the hydrogenation processor 208. In an embodiment, and as... Figure 5 As demonstrated, including a countercurrent hydrogen refueling processor 208 can result in increased heat transfer along the length of the hydrogen refueling processor 208 compared to a parallel-flow hydrogen refueling processor 208. Figure 5 In the simulation, the feed consisted of 50% by weight olefins as the organic component, with the balance being C. 15+ Hydrocarbons and pyrolytic gasoline are considered hydrocarbons. Without being limited by theory, the increased heat transfer in the countercurrent hydrotreating processor 208 can lead to increased heat transfer from the hydrogenated organic components to the remainder of the hydrogenated feed 106, thereby smoothing the temperature gradient on the hydrotreating processor 208 for highly reactive feeds (such as those containing alkyl aromatic compounds and / or olefins).

[0039] Beyond theoretical limitations, another benefit of the countercurrent hydrogenation processor 208 can be limiting the presence of corrosive substances in the hydrogenation feed stream 110, including but not limited to ammonium salts and hydrochloric acid. Specifically, the hydrogen stream 108 can be operated to flow in the opposite direction to the hydrogenation feed 106 to separate gaseous substances (including corrosive substances) from the liquid effluent of the hydrogenation feed stream 110. If the desired hydrocarbon is present in sufficient quantities in the hydrogen stream 108 containing gaseous corrosive substances, the stream can be further separated to recover the desired hydrocarbon before being reintroduced into the hydrogenation feed stream 110.

[0040] In this embodiment, dimethyl disulfide may also be introduced into the hydrotreating processor 208 along with the hydrogenation feed 106. Without being theoretically limited, the presence of dimethyl disulfide in the hydrogenation feed 106 can be operated to preferentially form H2S on the hydrogenation catalyst in the hydrotreating processor 208, thereby passivating the downstream heat exchanger of the hydrotreating processor 208 and the coils in the hydrocarbon reformer 220. Conventional reformers would form H2S at higher temperatures, so the H2S would only passivate the coils, not the heat exchanger. The direct conversion of dimethyl disulfide to H2S also reduces the formation of CS2 in the coils of the hydrocarbon reformer 220. The hydrogenation catalyst used in the hydrotreating processor 208 can be any hydrogenation catalyst known in the art.

[0041] After exiting the hydrotreating processor 208, dilution vapor 116 can be introduced into the hydrotreating feed stream 110 to form a hydrotreating feed stream / dilution vapor mixture 120. It is operable to introduce dilution vapor 116 into the hydrotreating feed stream 110 to vaporize the remainder of the hydrotreating feed stream 110, because the temperature of the hydrotreating feed stream / dilution vapor mixture 120 may be above the dew point of the hydrotreating feed stream / dilution vapor mixture 120.

[0042] However, before introducing dilution vapor 116, the hydrotreated feed stream 110 may enter separator 210. Separator 210 may separate the hydrotreated feed stream 110 into a vapor fraction 112 and a liquid phase 114. Separator 210 may also be operated to depressurize the hydrotreated feed stream 110. Without theoretical limitations, depressurizing the hydrotreated feed stream 110 in the separator may facilitate additional vaporization of the hydrotreated feed stream 110. The hydrotreated feed stream 110 may exit the hydrotreatment processor 208 at pressures ranging from 10 bar to 200 bar, such as 20 bar to 30 bar, 30 bar to 40 bar, 40 bar to 50 bar, 50 bar to 100 bar, 100 bar to 150 bar, 150 bar to 200 bar, or any combination of the foregoing ranges or smaller ranges. The hydrotreated feed stream 110 can then be depressurized in separator 210 to 1.5 bar to 4 bar, such as 1.5 bar to 1.7 bar, 1.7 bar to 2.3 bar, 2.3 bar to 2.5 bar, 2.5 bar to 3 bar, 3 bar to 3.3 bar, 3.3 bar to 4 bar, or any combination of the foregoing ranges or smaller ranges.

[0043] Not limited by theory, another benefit of depressurizing the hydrotreated feed stream 110 in separator 210 is to limit the formation of corrosive substances, including but not limited to ammonium salts and hydrochloric acid, which are known to have the potential to form in the hydrotreated feed stream 110 under high pressure.

[0044] Vapor fraction 112 may also be fed to pressure reducing valve / turbine expander 212 before being premixed with dilution vapor 116 to form vapor phase / dilution vapor 116 mixture 118, while liquid phase 114 may be fed to third mixer 214 to mix with vapor phase / dilution vapor 116 mixture 118 and form hydrotreated feed / dilution vapor mixture 120. Without theoretical limitations, mixing the vapor and liquid phases of hydrotreated feed 110 reduces the likelihood of film boiling in third mixer 214 and various other transfer lines within the system.

[0045] As used herein, “film boiling” generally refers to the phenomenon that occurs when a hot feed stream flows from a hot feed stream through the heat exchanger wall to a cold feed stream, causing residual liquid in the heated fluid to form a film that at least partially covers the heated surface. This liquid film becomes trapped between the bulk fluid and the heated surface, significantly increasing the residence time of the boiling liquid and triggering thermal reactions that lead to scaling. For example, in this paper, when film boiling is uncontrolled or unplanned, it can cause scaling in the hydrotreated feed stream 110 within the heat exchanger, reducing heat exchanger efficiency and, in severe cases, leading to critical failure of the heat exchanger material.

[0046] Still referencing Figure 1The method may further include preheating the hydrotreated feed / dilution vapor mixture 120. The hydrotreated feed / dilution vapor mixture 120 can be preheated to a temperature in the range of 200°C to 450°C by introducing it into a second heat exchanger 216. The hydrotreated feed / dilution vapor mixture 120 can be further preheated to a temperature in the range of 400°C to 700°C by introducing it into a third heat exchanger 218.

[0047] Still referencing Figure 1 The method may further include reforming the hydrotreated feed / dilution steam mixture 120 in a hydrocarbon reformer 220 to form a cracked gas effluent 124. The hydrocarbon reformer 220 may include one or more coils configured to convey the hydrotreated feed / dilution steam mixture 120 through the hydrocarbon reformer 220; and a radiant section 222 configured to ignite the flue gas 122 and heat the one or more coils. In embodiments, and as... Figure 1 As shown, at least one of the heat exchangers in the system can be located within the hydrocarbon reformer 220. Without being theoretically limited, locating the heat exchanger within the hydrocarbon reformer 220 can further reduce the energy consumption of the system and the method of utilizing the system, because the ignited flue gas 122 can transfer excess heat to the heat exchanger.

[0048] The cracked gas effluent 124 can then be introduced into a fourth heat exchanger 224, where it can be cooled to a lower temperature. For example, and in an embodiment, the cracked gas effluent 124 can be cooled to a temperature in the range of 300°C to 500°C via the fourth heat exchanger 224. The cracked gas effluent 124 can then be further processed to form cracked gas. Without being theoretically limited, the primary purpose of cooling the cracked gas effluent 124 may be to prevent further adverse reactions.

[0049] For example, and in an embodiment, the temperature of the cracked gas effluent 124 leaving the fourth heat exchanger 224 can typically be selected to be high enough that no significant scaling occurs due to the condensation of heavy components in the cracked gas effluent 124, but can also be selected to be low enough to reduce undesirable side reactions and scaling.

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

[0051] Steam condensate feed 126 for steam drum 226 can be introduced via makeup water flow 130. Makeup water flow 130 can be introduced into a fifth heat exchanger 228, which heats the makeup water flow to produce steam condensate 126. Steam drum 226 may also include a vent valve, which is also commonly referred to as a "blowout valve". As understood in the art, the vent valve can be operated to intentionally discharge or "discharge" water and steam from steam drum 226 as blowout steam 132 to prevent the concentration of impurities during the continuous use and evaporation of steam 134.

[0052] In an embodiment, the method may further include outputting steam 134 from steam drum 226 to a sixth heat exchanger 232 to form superheated steam 138 for output. Without being theoretically limited, by placing the sixth heat exchanger 232 near the radiant section 222 within the hydrocarbon reformer 220, the steam 134 can be superheated via the sixth heat exchanger 232, thereby utilizing the waste heat of the ignited flue gas 122. The superheated steam 138 can be output for any of a plurality of additional downstream units, including for process heating and shaft power applications. The sixth heat exchanger 232 can heat the steam 134 from steam drum 226 to a temperature in the range of 350°C to 550°C.

[0053] As illustrated in the following examples, the embodiments described herein can help increase the gasification of the feed stream 120 and reduce the preheating energy burden on various heat exchangers and hydrocarbon reformers. The embodiments described herein can also be used in processing materials with large amounts of C... 15+ This is true for hydrocarbon feedstocks of hydrocarbon fraction 104, thereby increasing the range of feedstocks that can potentially produce ethylene. Without being limited by theory, the embodiments described herein can also be used when processing hydrocarbon feedstocks with a large number of molecules, such as aromatics, olefins, and alcohols.

[0054] Example

[0055] Using ASPEN PLUS ®Using V12.1 software, simulations of the feedstream reforming process according to the embodiments described herein were performed using the PSRK property method and the NBS method for vapor properties. The simulations were then compared with comparative designs of various feeds without the hydrotreating processor 208. Example 1 used a combination of naphtha (hexane) as the hydrocarbon and benzene as the organic component, wherein the hexane / benzene weight ratio was 90:10. Example 2 was similar to Example 1 in all respects, except that a hydrotreated vegetable oil was added as the C244. 15+ Hydrocarbon fraction 104, of which hydrocarbon mixture 102 and C 15+ The weight ratio of hydrocarbon fraction 104 is 77.5:22.5. Example 3 uses ethane as the hydrocarbon and ethanol as the organic component, wherein the ethane / ethanol ratio is 90:10.

[0056] Example 1

[0057] The following assumptions were made for Example 1. The flue gas of the hydrocarbon reformer 220 was supplied with methane at 25°C. Air was also introduced at 25°C (0% relative humidity), with the airflow rate adjusted to ensure an oxygen volume fraction of 2% in the flue gas (methane). The radiant section 222 absorbed 3.15 GJ / h to transfer heat to the process coils, with a constant heat rate regardless of the feed. This heat transfer was assumed based on an average heat consumption of 25 GJ / tonne ethylene from the naphtha furnace, an ethylene yield of 30% by weight, and a combustion chamber thermal efficiency of 42%. The cracked gas effluent 124 was set at 850°C and 1.7 bar. The composition of the cracked gas relied on the article by Sandrameli et al.: "Systematics and modeling representations of naphtha thermalcracking for olefin production. J. Anal. Appl. Pyrolysis 73 (2005) 305–313." This article provides a detailed composition of the 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 achieve a temperature of 350°C at 1.7 bar. Boiler feedwater is supplied to the steam drum 226 at 120°C and 120 bar, preheated by the fifth heat exchanger 228, with 2% steam / water being extracted as blowdown steam 132. The fifth heat exchanger and the hydrocarbon reformer 220 are sized such that the flue gas temperature at 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 the sixth heat exchanger 232 to be heated to form superheated steam 138 for output. The sixth heat exchanger 232 and the hydrocarbon reformer 220 are sized to provide a fixed heat of 1.06 GJ / h to the sixth heat exchanger 232 to achieve 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) used this method to define the heat load of the sixth heat exchanger. The flow rate of hydrogen into the hydrogen refueling processor 208 was 35°C and 30 bar.

[0058]

[0059] As previously described, the hydrocarbon feed in Example 1 was naphtha containing 90 wt% hexane and 10 wt% benzene at 100°C and 6 bar. Dilution vapor 116 was provided at 220°C and 6 bar. The weight ratio of dilution vapor 116 to hydrotreatment vapor was approximately 0.5:1. The hydrocarbon feed was first preheated in the first heat exchanger 204 before hydrogenation with the hydrogen stream 108. The second and third heat exchangers preheated the feed to an outlet temperature of 600°C. Comparison of designs and... Figure 1 The designed heating loads are shown in Tables 2 and 3 below.

[0060]

[0061]

[0062] As shown in Tables 2 and 3, compared to the comparative design, including the hydrogen refueling processor 208 results in a reduced heating load required for the third heat exchanger 218. This lower heating load can then be utilized by the fifth heat exchanger 228 to preheat a larger volume of the makeup water stream 130 and to output a larger volume of superheated steam 138 to other downstream units. Furthermore, it can be observed that the feed temperature entering the second heat exchanger 216 is significantly higher for the design including the hydrogen refueling processor 208 compared to the comparative design. It should be noted that this energy analysis does not include the energy footprint of hydrogen production.

[0063] Example 2

[0064] As previously mentioned, Example 2 is the same as Example 1, except that for C 15+ Hydrocarbon fraction 104, with added hydrogenated vegetable oil, wherein hydrocarbon mixture 102 and C 15+ The weight ratio of hydrocarbon fraction 104 was 77.5:22.5. Table 4 shows the composition of the hydrotreated vegetable oil, as hypothesized by Kiefel et al., Conceptual Process Design: Production of Hydrotreated Vegetable Oil as an Additive for Petro-Diesel. December 30, 2018, RWTH Aachen University.

[0065]

[0066] Comparative design and based on Figure 1The heating loads of the designs are shown in Tables 5 and 6 below. Initially, it can be observed that the feed temperature entering the second heat exchanger 216 is significantly higher for the design including the hydrogenation processor 208 compared to the comparative design. Furthermore, as shown in Tables 5 and 6, including the hydrogenation processor 208 results in an increase in the vapor fraction of the feed stream 120 upstream of heat exchanger 216. Moreover, as shown in Tables 5 and 6, including the hydrogenation processor 208 results in a lower required heating load for the third heat exchanger 218 compared to the comparative design. This lower heating load can then be utilized by the fifth heat exchanger 228 to preheat a larger volume of the makeup water stream 130 and to output a larger volume of superheated steam 138 to other downstream units.

[0067]

[0068]

[0069] Example 3

[0070] 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 the literature (Platts, S&P Global, Specifications Guide, Europe and Africa Refined Oil Products, 2023) that the feed to the hydrocarbon reformer can tolerate up to 100 ppm of oxygenated compounds. In this example, the hydrogenation of ethanol in the hydroprocessor 208 will reduce the ethanol content in the hydrocarbon reformer 220 from 10% to approximately 0%, i.e., trace amounts. Furthermore, the comparative design utilizes only ethane as the feed. The following assumptions were made for Example 1. The conditions for flue gas 122, hydrocarbon reformer 220, and cracked gas effluent 124 were the same as in Examples 1 and 2. The composition of the cracked gas relied on the article by Zimmermann et al.: Ethylene. ULLMANN's Encyclopaedia of industrial chemistry, 2012 Wiley-VCH Verlag GmbH & Co. KGaA, Weinheim. A yield reactor was also set up in AspenPlus to estimate the heat required (4.04 GJ / h) to convert ethane to the composition shown in Table 7 below, and the feed temperature was increased from 600 °C to 850 °C. The thermal efficiency was assumed to be 42%.

[0071]

[0072] Similar to Examples 1 and 2, the cracked gas is quenched at the fourth heat exchanger 224. Boiler feedwater and blowdown are also similar to Examples 1 and 2. The dimensions of the fifth heat exchanger and the hydrocarbon reformer 220 are configured such that the flue gas temperature at 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 the sixth heat exchanger 232 to be heated to form superheated steam 138 for output. The dimensions of the sixth heat exchanger 232 and the hydrocarbon reformer 220 are configured to provide a fixed heat of 1.26 GJ / h to the sixth heat exchanger 232 to achieve a final temperature of approximately 500°C at 120 bar.

[0073] Compared to Examples 1 and 2, the first heat exchanger 204 transfers 0.72 GJ / h of heat to the ethane and ethanol feedstock, with inlet conditions of approximately 35°C and 30 bar. The second heat exchanger 216 transfers 0.61 GJ / h of heat from the ignited flue gas 122 to the hydrocarbon mixture 102. Finally, the third heat exchanger 218 heats the hydrocarbon mixture 102 to a temperature of approximately 600°C.

[0074] Comparative design and based on Figure 1 The heating loads of the designs are shown in Tables 8 and 9 below. As previously mentioned, the comparative designs do not include ethanol as feed. Without theoretical limitations, ethanol, and generally alcohols, is not traditionally used as feed for steam crackers because the upper limit for oxygenated compounds still producing the desired conversion is typically around 100 ppm. However, by including a hydrotreating processor 208 prior to the hydrocarbon reformer 220, ethanol can be converted to ethane and water, while also generating waste heat associated with the chemical reaction. Furthermore, by producing water as a product, a reduction in the amount of dilution steam 116 is possible, where Table 9 reduces the ratio of dilution steam 116 to the hydrotreating feed stream 110 from approximately 0.3:1 to 0.26:1.

[0075]

[0076]

[0077] It should be noted that, unlike descriptions of intended use, descriptions in this disclosure of components being "operable" or "sufficient" in a particular manner to embody a particular characteristic or function in a particular way are structural descriptions. More specifically, references in this disclosure to a manner in which a component is "operable" or "sufficient" indicate the existing physical conditions of the component and are therefore to be regarded as explicit descriptions of the structural features of the component.

[0078] Unless the context clearly indicates otherwise, the singular forms “a (kind),” “one (kind),” and “the” include multiple referents.

[0079] Ranges are provided throughout the disclosure. It is envisioned that each discrete value covered by these ranges is also included. Furthermore, the ranges formed by each discrete value covered by the explicitly disclosed ranges are equally predictable.

[0080] As used in this disclosure and the appended claims, the words “comprising,” “having,” and “including,” and all their grammatical variations, are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

[0081] As used in this disclosure, terms such as “first,” “second,” and “third” are arbitrarily designated and are intended only to distinguish two or more instances or components. It should be understood that the terms “first,” “second,” and “third” are not used for any other purpose, are not part of the component names or descriptions, and do not necessarily limit the relative position, orientation, or order of the components. Furthermore, it should be understood that the mere use of the terms “first,” “second,” or “third” does not require the existence of any “fourth” component, although such a possibility is considered within the scope of this disclosure.

[0082] For the purposes of describing and defining embodiments of the invention, it should be noted that the terms "substantially" and "about" are used herein to indicate an inherent uncertainty attributable to any quantitative comparison, value, measurement, or other representation. The terms "substantially" and "about" are also used herein to indicate the extent to which a quantitative representation may differ from the stated reference without causing a fundamental change in the function of the subject matter.

[0083] According to a first aspect, a method for modifying a hydrocarbon mixture includes providing a hydrogenation feed comprising a hydrocarbon mixture containing hydrocarbons and an organic component; introducing the hydrogenation feed along with a hydrogen stream into a hydrotreating processor to hydrogenate at least the organic component and generate a hydrotreated feed stream at an elevated temperature; introducing dilution vapor into the hydrotreated feed stream to form a hydrotreated feed stream / dilution vapor mixture; preheating the hydrotreated feed stream / dilution vapor mixture; and modifying the hydrotreated feed stream / dilution vapor mixture in a hydrocarbon modification furnace to form a cracked gas effluent, wherein the hydrocarbons in the hydrocarbon mixture comprise naphtha, gas oil, pyrolysis gasoline, Fischer-Tropsch derivatives, natural gas condensate, 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 contains 0.01% to 25% by weight of the organic component based on the weight of the hydrocarbon mixture.

[0084] The second aspect may include the first aspect, wherein the hydrocarbon mixture comprises 10% to 25% by weight of organic components based on the weight of the hydrocarbon mixture.

[0085] The third aspect may include the second aspect, and may also include mixing the hydrocarbon mixture with C 15+Hydrocarbon fractions are blended to provide a hydrogenation feed, wherein the hydrogenation feed contains 5% to 45% C by weight of the hydrogenation feed. 15+ Hydrocarbon fraction.

[0086] The fourth aspect may include the third aspect, wherein the weight percentage of organic components based on the weight of the hydrocarbon mixture is C based on the weight of the hydrogenation feed. 15+ At least half of the hydrocarbon fraction by weight; and at least 90% by weight of the hydrotreated feed / dilution vapor mixture is vaporized before preheating.

[0087] The fifth aspect may include any of the foregoing aspects, wherein introducing dilution vapor into the hydrotreating stream further includes separating the hydrotreating stream into a vapor-phase hydrotreating stream and a liquid-phase hydrotreating stream; introducing dilution vapor into the vapor-phase hydrotreating stream to form a vapor-phase / dilution vapor mixture; introducing the vapor-phase / dilution vapor mixture and the liquid-phase hydrotreating stream into a mixer; and mixing the vapor-phase mixture and the liquid-phase hydrotreating stream in the mixer to form the hydrotreating stream / dilution vapor mixture.

[0088] The sixth aspect may include any of the foregoing aspects, wherein the hydrocarbons include naphtha, pyrolytic gasoline, or both; and the organic components include alkyl aromatic compounds, olefins, or both.

[0089] The seventh aspect may include any one of the first to fifth aspects, wherein the hydrocarbon includes ethane and the organic component is ethanol.

[0090] The eighth aspect may include any of the foregoing aspects, and may also include initially preheating the hydrocarbon mixture or hydrogenated feed to a temperature of 30°C to 200°C in a first heat exchanger before hydrogenating the hydrocarbon mixture or hydrogenated feed.

[0091] The ninth aspect may include any of the foregoing aspects, wherein preheating the hydrotreated feed / dilution vapor mixture includes introducing the hydrotreated feed / dilution vapor mixture into a second heat exchanger to preheat the hydrotreated feed / dilution vapor mixture to a temperature in the range of 200°C to 450°C; introducing the hydrotreated feed / dilution vapor mixture into a third heat exchanger downstream of the second heat exchanger to further preheat the hydrotreated feed / dilution vapor mixture to a temperature in the range of 400°C to 700°C; or both.

[0092] The tenth aspect may include any of the foregoing aspects, wherein the hydrogenation processor is configured to cause the hydrocarbon mixture or hydrogenation feed to flow in the opposite direction to the hydrogen stream.

[0093] The eleventh aspect may include any of the foregoing aspects, wherein the hydrogenated feed stream is depressurized before the dilution steam is introduced.

[0094] The twelfth aspect may include any of the foregoing aspects, wherein the hydrocarbon reformer includes one or more coils configured to convey a hydrotreated feed / dilution steam mixture through the hydrocarbon reformer; and a radiant section configured to ignite flue gas and heat the one or more coils.

[0095] The thirteenth aspect may include any of the foregoing aspects, and may also include introducing cracked gas effluent into a fourth heat exchanger to cool the cracked gas effluent to a temperature in the range of 300°C to 500°C, wherein the steam drum is fluidly connected to the fourth heat exchanger for transferring steam condensate to the fourth heat exchanger and transferring saturated steam back to the steam drum.

[0096] The fourteenth aspect may include any of the foregoing aspects, and may also include introducing a makeup water stream into a fifth heat exchanger to generate steam condensate; introducing the steam condensate into a steam drum; and introducing saturated steam from the steam drum into a sixth heat exchanger to form superheated steam for output.

[0097] The fifteenth aspect may include any of the foregoing aspects, wherein at least one of the first heat exchanger, the second heat exchanger, the third heat exchanger, the fourth heat exchanger, or the fifth heat exchanger is located within the hydrocarbon reforming furnace.

[0098] The subject matter of this disclosure has been described in detail and with reference to specific embodiments. It should be noted that the various details disclosed herein should not be construed as implying that such details relate to elements that are essential components of the various embodiments described herein. Furthermore, it will be apparent that modifications and variations may be made without departing from the scope of this disclosure, including but not limited to the embodiments defined in the appended claims.

Claims

1. A method for modifying a hydrocarbon mixture, the method comprising: A hydrogenation feed comprising a hydrocarbon mixture, the hydrocarbon mixture comprising hydrocarbons and organic components is provided; The hydrogenated feed is introduced into the hydrogenation processor along with a hydrogen gas stream to hydrogenate at least the organic components and generate a hydrogenated feed stream at an elevated temperature; Diluting vapor is introduced into the hydrotreated feed stream to form a hydrotreated feed stream / dilution vapor mixture; Preheat the feed stream / dilution vapor for the hydrogenation treatment; as well as The hydrotreated feed stream / dilution steam is modified in a hydrocarbon reformer to form a cracked gas effluent, wherein The hydrocarbons in the hydrocarbon mixture include naphtha, gas oil, pyrolytic gasoline, Fischer-Tropsch derivatives, natural gas condensate, C1-C4 hydrocarbons, or combinations thereof. The organic component is selected from one or more of olefins, alkyl aromatic compounds, or alcohols, and The hydrocarbon mixture comprises 0.01% to 25% by weight of organic components based on the weight of the hydrocarbon mixture.

2. The method of claim 1, wherein the hydrocarbon mixture comprises 10% to 25% by weight of organic components based on the weight of the hydrocarbon mixture.

3. The method according to claim 2, further comprising: The hydrocarbon mixture with C 15+ Hydrocarbon fractions are blended to provide the hydrogenated feed, wherein the hydrogenated feed comprises 5% to 45% C by weight of the hydrogenated feed. 15+ Hydrocarbon fraction.

4. The method according to claim 3, wherein: The weight percentage of organic components based on the weight of the hydrocarbon mixture is C based on the weight of the hydrogenation feed. 15+ At least half of the hydrocarbon fraction by weight; and The hydrogenation process involves vaporizing at least 90% by weight of the feed / dilution vapor mixture before preheating.

5. The method according to any preceding claim, wherein introducing the dilution vapor into the feed stream of the hydrotreating process further comprises: The hydrogenated feed stream is separated into a vapor-phase hydrogenated feed stream and a liquid-phase hydrogenated feed stream; Diluting vapor is introduced into the feed stream of the vapor phase hydrogenation treatment to form a vapor phase / dilution vapor mixture; The vapor phase / dilution vapor mixture and the liquid phase hydrogenation treatment feed stream are introduced into the mixer; as well as The vapor phase mixture and the liquid phase hydrogenation process feed stream are mixed in the mixer to form the hydrogenation process feed stream / dilution vapor mixture.

6. The method according to any of the preceding claims, wherein: The hydrocarbons include naphtha, pyrolytic gasoline, or both; and The organic components include alkyl aromatic compounds, olefins, or both.

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

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

9. The method according to any preceding claim, wherein preheating the hydrotreating feed / dilution vapor mixture comprises: The hydrotreated feed / dilution vapor mixture is introduced into a second heat exchanger to preheat the hydrotreated feed / dilution vapor mixture to a temperature in the range of 200°C to 450°C; The hydrotreated feed / dilution vapor mixture is introduced into a third heat exchanger downstream of the second heat exchanger to further preheat the hydrotreated feed / dilution vapor mixture to a temperature in the range of 400°C to 700°C; or Both.

10. The method according to any of the preceding claims, wherein the hydrogenation processor is configured to reverse the flow of the hydrogenation feedstock from the hydrogen gas stream.

11. The method according to any of the preceding claims, wherein the hydrogenation process feed stream is depressurized before the dilution vapor is introduced.

12. The method according to any preceding claim, wherein the hydrocarbon reforming furnace comprises: One or more coils configured to convey the hydrotreated feed / dilution vapor mixture through the hydrocarbon reformer; as well as A radiant section, configured to ignite flue gas and heat the one or more coils.

13. The method according to any preceding claim, further comprising introducing the cracked gas effluent into 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 transferring saturated steam back to the steam drum.

14. The method according to claim 13, further comprising: The makeup water flow is introduced into the fifth heat exchanger to produce the steam condensate; The steam condensate is introduced into the steam drum; as well as Saturated steam from the steam drum is introduced into a sixth heat exchanger to form superheated steam for output.

15. The method according to any of the preceding claims, wherein at least one of the first heat exchanger, the second heat exchanger, the third heat exchanger, the fourth heat exchanger, or the fifth heat exchanger is located within the hydrocarbon reforming furnace.

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