Conversion of ultra-light crude oil, extra-light crude oil, and condensate oil to chemicals

Abstract

The present disclosure provides methods and systems for converting wide boiling hydrocarbon mixtures to chemicals, where the methods and systems heat a hydrocarbon feedstock to form a heated hydrocarbon feedstock. The heated hydrocarbon feedstock is separated to recover a vaporized light portion and a remaining liquid portion. The vaporized light portion is superheated and thermally cracked to recover a first cracked effluent, and the remaining liquid portion is heated and stripped to recover a stripped vapor mixture and a residual liquid portion. The stripped vapor mixture is separated to recover a vapor comprising the stripping medium and a stream comprising volatilized hydrocarbons. The volatilized hydrocarbons are heated and mixed with hydrogen and then hydrotreated to form crackable heavy hydrocarbons. The hydrotreated effluent is separated to recover a hydrotreated liquid stream comprising the crackable heavy hydrocarbons and a hydrotreated vapor stream comprising unreacted hydrogen. The hydrotreated liquid is overheated and thermally cracked to recover a second cracked effluent.

Description

TECHNICAL FIELD

[0001] Embodiments of the present disclosure generally relate to converting extra-light crude oil, ultra-light crude oil, and condensate to chemicals. BACKGROUND

[0002] Traditionally, crude oil is separated into various fractions in the crude and vacuum distillation section of a refinery. Each fraction separated from the crude oil is then routed to separate processing units, such as hydro-treaters, hydro- crackers, and residue hydro- crackers, and then the fraction oil products from these secondary units are routed to a steam cracker or aromatics plant for conversion to chemicals.

[0003] Extra-light and ultra-light crude oils, as well as condensates, have very low residue content and are less sulfur and other contaminants, such as metals. It is not feasible to process the entire crude oil directly in a steam cracker without any residue separation because even extra-light and ultra-light crude oils, as well as condensates, contain small amounts of asphaltenes and heavy polynuclear aromatics that would foul the heater tubes in the steam cracker, and especially the transfer line exchanger (TLE).

[0004] Current practice involves separating the lighter fractions from these extra-light and ultra-light crude oils in a separation unit or column into a light fraction that is sent to a steam cracker to produce olefins. The heavy fraction is rejected as a low sulfur fuel oil. If the separation unit or column, including the crude column or vacuum column, is to be bumped to a nominal residue true distillation cut point of 540°C or below, thermal cracking of such a wide boiling range mixture will result in lower olefin yields and faster fouling of the thermal cracking heaters and transfer line exchanger. Splitting the crude oil into two fractions will slightly improve the olefin selectivity, but the heavier fraction will result in accelerated fouling of the heaters and TLE and result in the production of a larger amount of pyrolysis oil.

[0005] The entire crude oil can be hydro-treated, but this will quickly deactivate the hydro-treating catalyst, resulting in excessive capital and operating costs.

[0006] Various patents and applications provide for using different hydro-treating schemes to convert crude oil and other wide boiling point mixtures to chemicals. While such methods are effective for converting crude oil to chemicals, they can be excessive (and capital intensive) for efficiently processing extra-light, ultra-light, and condensate crude oils.

[0007] In view of the above challenges, the current practice of crude oil distillation units that hydro-treat various fractions remains the standard practice for processing even extra-light, ultra-light, and condensate crude oils. The hydro-treated fractions are then routed to an olefin unit or recovered as fuel. SUMMARY

[0008] In one aspect, embodiments disclosed herein relate to a method for converting a wide boiling point hydrocarbon mixture into chemicals. The method includes heating a hydrocarbon feedstock to form a heated hydrocarbon feedstock, the hydrocarbon feedstock comprising extra-light crude oil, ultra-light crude oil, light crude oil, or condensate. The heated hydrocarbon feedstock is separated to recover a vaporized light portion and a remaining liquid portion. The vaporized light portion is superheated and thermally cracked to recover a first cracked effluent, and the remaining liquid portion is heated and stripped to recover a stripped vapor mixture comprising a stripping medium and volatilized hydrocarbons and a residual liquid portion. The stripped vapor mixture is separated to recover a vapor comprising the stripping medium and a condensed hydrocarbon stream comprising condensed volatilized hydrocarbons. The condensed volatilized hydrocarbons are heated and mixed with hydrogen to form a reactant feed stream, which is fed to a hydroprocessing reactor to convert hydrocarbons therein, thereby forming an effluent comprising crackable heavy hydrocarbons and an effluent gas comprising unreacted hydrogen. The effluent is separated to recover a hydroprocessed liquid stream comprising the crackable heavy hydrocarbons and a hydroprocessed vapor stream comprising the unreacted hydrogen. The hydroprocessed liquid stream is superheated and thermally cracked to recover a second cracked effluent.

[0009] In another aspect, embodiments disclosed herein relate to a system for converting a wide boiling point hydrocarbon mixture into chemicals. The system includes a heat exchanger for heating a hydrocarbon feedstock to form a heated hydrocarbon feedstock, the hydrocarbon feedstock comprising extra-light crude oil, ultra-light crude oil, light crude oil, or condensate. A separator is provided for separating the heated hydrocarbon feedstock to recover a vaporized light portion and a remaining liquid portion. A heating coil, such as a convection coil and a radiant coil of a cracking furnace, is provided for superheating and thermally cracking the vaporized light portion to recover a first cracked effluent. Included in the system are a heat exchanger for heating the remaining liquid portion and a stripper for stripping the remaining liquid portion to recover a stripped vapor mixture comprising a stripping medium and volatilized hydrocarbons and a residual liquid portion. The system further includes a separator for separating the stripped vapor mixture to recover a vapor comprising the stripping medium and a condensed hydrocarbon stream comprising condensed volatilized hydrocarbons, and a heat exchanger for heating the condensed volatilized hydrocarbons and mixing the condensed volatilized hydrocarbons with hydrogen to form a reactant feed stream. A flow line is provided for feeding the reactant feed stream to a hydroprocessing reactor, and the hydroprocessing reactor converts hydrocarbons therein, thereby forming an effluent comprising crackable heavy hydrocarbons and an effluent gas comprising unreacted hydrogen. The system also includes a separator for separating the effluent to recover a hydroprocessed liquid stream comprising the crackable heavy hydrocarbons and a hydroprocessed vapor stream comprising the unreacted hydrogen. Further, the system includes a heating coil for superheating and thermally cracking the hydroprocessed liquid stream to recover a second cracked effluent.

[0010] Other aspects and advantages will be apparent from the following description and the appended claims. BRIEF DESCRIPTION OF DRAWINGS

[0011] The figure illustrates a simplified process flow diagram for a system for producing chemicals according to one or more embodiments disclosed herein. DETAILED DESCRIPTION

[0012] Embodiments of the present disclosure generally relate to converting extra-light, ultra-light, and condensate liquids into chemicals. Embodiments herein can also be used to convert low-sulfur light crude oils into chemicals.

[0013] The properties of various types of crude oils and condensate liquids are summarized in Table 1. While these properties can vary greatly, depending on the reservoir from which the crude oil or condensate is produced, the values in Table 1 provide a rough guide for defining feedstocks suitable for use in embodiments.

[0014] Table 1.

[0015]

[0016] The various grades of crude oil described above can vary from low sulfur (low sulfur content) to high sulfur (high sulfur content). Embodiments herein can be used to convert low-sulfur crude oils into chemicals, but also have the ability to effectively process high-sulfur crude oils. Extra-light, ultra-light, and light crude oils can contain, for example, 1 wt% to 5 wt% of residue (hydrocarbons having a boiling point greater than 540°C). Various crude oils can contain greater amounts of residue, such as up to or over 20 wt%, and those typically classified as medium or heavy crude oils are generally not suitable for the methods herein. Embodiments herein are particularly suitable for crude oils having no more than 5% of material boiling above 540°C; greater amounts of 540°C+ material can also be processed, but at an economic penalty rather than a process penalty.

[0017] Similar to crude oils, condensate liquids can also vary greatly. Condensate liquids produced from a well can be referred to as “poor / lean,” “medium,” or “rich.” A “poor” condensate liquid generally has a large amount of methane and ethane, and a small amount of medium (C3-C11) or heavy (C12+) hydrocarbons. For example, a poor condensate liquid can have 1.5 wt% to 15 wt% of medium hydrocarbons and less than 2 wt% of heavy hydrocarbons. A medium condensate liquid can have, for example, 7 wt% to 20 wt% of medium hydrocarbons and 2 wt% to 4 wt% or 5 wt% of heavy hydrocarbons. A rich condensate liquid can have, for example, 15 wt% to 25 wt% of medium hydrocarbons and 4 wt% or 5 wt% to 9 wt% or 10 wt% of heavy hydrocarbons.

[0018] After separation of the methane and ethane (natural gas), the remaining condensate liquid is typically much lighter than the crude oil. For example, the condensate liquid can include about 0.1 wt% to about 5 wt% C4-, 40 wt% to 65 wt% naphtha range hydrocarbons, 20 wt% to 40 wt% jet fuel or diesel fuel range hydrocarbons, 1 wt% to 10 wt% vacuum gas oil range hydrocarbons, and up to 20 wt% residue, such as 1 wt% to 5 wt% residue. Similar to crude oil, the condensate liquid can be low sulfur or high sulfur, and the amount of residue (compounds with boiling points higher than 540°C) in the condensate liquid can vary significantly. Embodiments herein can treat both low sulfur and high sulfur condensate liquids, as well as condensate liquids recovered from lean condensate, medium condensate, or rich condensate. Embodiments herein are suitable for condensate having 5% or less residue components with boiling points higher than 540°C.

[0019] Crude oil and condensate feedstocks that can be used in various embodiments herein can have an API gravity greater than 32°, in other embodiments greater than 35°, in other embodiments greater than 40°, and in yet other embodiments greater than 45° or greater than 50°.

[0020] In various embodiments, the crude oil and condensate feedstocks have a residue content or content of material with boiling points higher than 540°C of less than 10 wt%, in other embodiments less than 8 wt%, in other embodiments less than 5 wt%, in other embodiments less than 4 wt%, in other embodiments less than 3 wt%, and in yet other embodiments less than 2 wt%.

[0021] Crude oil and condensate feedstocks treated according to embodiments herein can also have a low sulfur content, such as less than 2 wt%, in other embodiments less than 1 wt%, in other embodiments less than 0.5 wt%, and in yet other embodiments less than 0.2 wt%. In particular embodiments, the crude oil and condensate used as feedstocks herein are "low sulfur" containing less than 0.2 wt% sulfur. Crude oil and condensate feedstocks treated according to embodiments herein can also have a low content of metals and Conradson Carbon Residue (CCR).

[0022] In some embodiments, for example, the hydrocarbon feedstock can have an API gravity greater than 32° and a sulfur content less than 0.5 wt%. In other embodiments, the hydrocarbon feedstock has: an API gravity greater than 45°, greater than 46°, greater than 47°, greater than 48°, or greater than 49°; a sulfur content less than 0.5 wt%, less than 0.2 wt%, less than 0.1 wt%, or less than 0.07 wt%; less than 200 ppm nitrogen, less than 150 ppm nitrogen, less than 100 ppm nitrogen; a Conradson Carbon Residue (CCR) content less than 1 wt%, less than 0.7 wt%, less than 0.5 wt%, or less than 0.4 wt%; and a content of hydrocarbons with boiling points greater than 540°C less than 5%, less than 4%, less than 3%, or less than 2 wt%. As an example, Arab Extra Light Crude Oil and the like can be suitable feeds that meet one or more of the above properties in combination.

[0023] The above feedstock can be fed to a desalter, resulting in a desalted crude or condensate feedstock. The desalted feedstock is then heated, such as in a convection coil located in the convection section of the thermal cracker furnace. In some embodiments, the desalted feedstock is split into multiple streams and fed to two or more heaters or convection coils to increase the temperature of the desalted feedstock. For example, the desalted feedstock can be heated to a temperature in the range of about 135°C to about 210°C, such as 150°C to 180°C.

[0024] The heated feedstock is then fed to a separation system to separate the lighter paraffinic fraction or fractions recovered as vapor from the separation system from the heavier hydrocarbons in the desalted feedstock recovered as liquid from the separation system. The separation system can include, for example, an advanced separation device (ASD), such as described in US11407950. In some embodiments, the separation system is a simple flash tank that recovers hydrocarbons that are volatilized in the heating coil. As another example, the separation system can include a heavy oil processing scheme (HOPS), such as described in US10208257. The ASD or HOPS is preferred over a simple flash tank due to the fouling tendency of the heavier hydrocarbons in order to limit the entrainment of liquid droplets that can contain the heavier hydrocarbons. Since the initial boiling point material is highly enriched in paraffins, it is referred to as a light paraffinic fraction, and it will contain paraffins, olefins, naphthenes, and aromatics. The light paraffinic fraction recovered as vapor from the separation system can have, for example, a final boiling point in the range of 135°C to 225°C, such as about 160°C to about 180°C.

[0025] The light paraffinic fraction can then be further heated and superheated using one or more heat exchangers. The heaters used to superheat the light paraffinic fraction can be located outside the cracking furnace, within the convection section of the cracking furnace, or both. In some embodiments, the external heaters used can be electric heaters, or steam or other heat transfer fluids can be used to increase the temperature of the light paraffinic fraction.

[0026] The light paraffin fraction is then fed to a radiant coil of a cracking furnace to rapidly increase the temperature of the hydrocarbons therein to a cracking temperature, such as greater than 700°C to about 1100°C, to thermally crack the hydrocarbons to produce lighter hydrocarbons, such as ethylene, propylene, and butylenes, among others. The effluent from the radiant coil is then fed to a transfer line exchanger to rapidly quench the cracking effluent to a temperature below the cracking temperature. Additional heat can then be recovered from the cracking effluent, and the cooled effluent is fed to a fractionation zone to separate the cracking effluent into various hydrocarbon fractions. The separation systems associated with the thermal cracking system can vary and can be used to separate the cracking effluent into wide fractions, such as a hydrogen fraction, a Ci, C2-, C3-, or C4- fraction, a naphtha range fraction, a diesel or jet fuel range fraction, a gas oil range fraction, and a pyrolysis oil (heavy oil / residual oil) fraction. Some of the separation systems used in embodiments of the fractionation zone herein can include a demethanizer, a deethanizer, a depropanizer, and separators for recovering various olefins, such as a deethenizer for separating ethylene from ethane, a depropenizer for separating propane from propylene, and a debutanizer, a deisobutenizer, or other various separators and distillation columns or extractive distillation columns known in the art for recovering specific hydrocarbons or hydrocarbon fractions from a mixture of hydrocarbons.

[0027] The end boiling point of the light fraction can range up to about 350°C depending on the aromaticity, sulfur content, or fouling tendency of the medium boiling components in the crude or condensate feedstock. In some embodiments, a first separator, such as an ASD or HOPS, can be used to recover a light boiling point fraction, such as having an end boiling point in the range of 160°C to 180°C, as described above, and after heating the remaining heavier hydrocarbons, a second separator, such as an ASD or HOPS, can be used to recover a medium boiling range hydrocarbon fraction, such as having an initial boiling point in the range of 160°C to 180°C and an end boiling point in the range of 280°C to 350°C. The medium fraction can be superheated and fed to a radiant coil to produce chemicals, such as ethylene and propylene, among others, and the cracking medium fraction effluent can be quenched in a common or independent transfer line exchanger, fed to a heat recovery unit, and then to a fractionation zone to recover various hydrocarbon fractions, among other cracking effluents.

[0028] The heavier hydrocarbons recovered from the separation system still contain residue, and the residue portion is removed from the heavy hydrocarbons, after which the residue-free heavy hydrocarbons are hydrotreated to improve the crackability of the feedstock, and the hydrotreated heavy oil is fed to the radiant coils of the cracking furnace to produce chemicals. The hydrotreatment according to embodiments herein can include one or more of hydrodesulfurization, hydrodemetallization, hydrodenitrogenation, hydrogenation, and ring opening to remove sulfur, nitrogen, and metals, reduce CCR, or otherwise enhance the crackability of the heavier hydrocarbons. Although there is no specific limit on CCR, for economic reasons, it is preferred that the CCR be less than 2 wt%. In some embodiments, the hydrotreatment does not include hydrocracking of the heavy oil. The hydrotreated heavy oil is then superheated and fed to the radiant coils to produce chemicals, such as ethylene and propylene, and the cracked heavy fraction effluent can be quenched in a common or separate transfer line exchanger, fed to a heat recovery unit, and from there to a fractionation zone to recover various hydrocarbon fractions along with other cracking effluents.

[0029] To separate residue and improve the crackability of the heavy hydrocarbons, the heavier hydrocarbons recovered from the separation system are heated, such as in the convection coils of the cracking furnace, and then fed to a hot hydrogen or hot natural gas stripper. One or more additional heavy, difficult to crack feeds, such as gas oil or vacuum gas oil (VGO), can optionally be combined with the heavier hydrocarbons prior to heating or stripping.

[0030] In the stripper, the heavy hydrocarbons are contacted with hot hydrogen or hot natural gas (methane, ethane, or mixtures thereof) to separate the heavy vaporizable hydrocarbons from the residue. The hydrogen or natural gas can be superheated, and at a temperature sufficient to vaporize and lift the hydrocarbons having a standard boiling point of up to 480°C, up to 500°C, up to 520°C, or up to 540°C using the stripping medium. The remaining residue can be recovered as a bottom fraction from the stripper, and a mixture of hydrogen and vaporized heavy hydrocarbons can be recovered as a top fraction from the stripper. It should be noted that while a standard boiling point is noted, the actual conditions used in the stripper can vary, and can be less than the noted cut point where the stripper is operated at a partial vacuum. The residue recovered as a bottom fraction can be recovered as an ultra-low sulfur fuel oil, or can be combined with a pyrolysis oil fraction from a fractionation zone used to separate cracking effluents to produce an ultra-low sulfur fuel oil.

[0031] The overheads from the stripper are then condensed to separate the volatilized heavy hydrocarbons from the stripping medium, which can be compressed, reheated, and recycled for continued use in the stripper. A portion of the condensed heavy hydrocarbons can be used as reflux to the feed to the stripper. The remaining condensed heavy hydrocarbons are heated, mixed with hydrogen (or mixed with hydrogen and then heated), and fed to a hydrotreating reactor. The hydrotreating reactor can contain one or more catalyst beds suitable for carrying out one or more of the following reactions: conversion of sulfur and nitrogen in the hydrocarbons to hydrogen sulfide and ammonia; hydrogenation of aromatic compounds; and promoting ring opening reactions to open cyclic, aromatic, or naphthenic compounds. Optionally, the catalyst can include cracking functionality, and cracking can be minimal or maximal, and the need or desire for cracking functionality can depend on the feedstock being processed.

[0032] The hydrotreating reactor effluent is then cooled and separated from any unreacted hydrogen, as well as hydrogen sulfide and ammonia produced in the reactor. Cooling can be performed by one or more feed / effluent exchangers, such as heating of the condensed heavy hydrocarbons from the stripper, or heating of the hydrogen feed for the hydrotreating reactor. The hydrotreated heavy oil (conditioned to an improved cracking feed) is then recovered, mixed with dilution steam, and fed to the radiant coils of a cracking furnace to produce chemicals, as described above.

[0033] In some embodiments, the hydrotreated heavy oil is mixed with water to promote removal of polar compounds. In such embodiments, the cooled hydrotreated heavy oil can be separated to recover high-sulfur water, a vapor fraction comprising hydrogen, hydrogen sulfide, and ammonia, and a hydrotreated heavy oil product that is fed to a cracking furnace as described previously.

[0034] The separated vapor can then be treated to recover unreacted hydrogen. For example, one or more separation systems can be used to separate the unreacted hydrogen from the hydrogen sulfide and ammonia, providing a recycle hydrogen stream that can be compressed, heated, and fed to the hydrotreating reactor. Make-up hydrogen is provided to the system as needed.

[0035] Dilution steam can be added to aid in the separation and heating of the desalted feed, as well as to limit or prevent fouling during heating of the desalted feed, upstream of separation in the separation system, or during heating in the separation system. Thus, for example, steam can be added directly to the separation system (flash drum, ASD, or HOPS) or downstream of the separation system (flash drum, ASD, or HOPS) and upstream of the superheat heater or convection coils at one or more locations, such as downstream of the desalter and upstream of the convection heating coils, downstream of the convection heating coils and upstream of the separation system (flash drum, ASD, or HOPS). Similarly, steam can be added to the hydrotreated fraction upstream of the superheat coils prior to cracking of the hydrotreated fraction within the radiant coils of the cracking furnace.

[0036] A simplified process flow diagram of the above described system for converting condensate and extra light, very light, or light crude oil into chemicals is shown in the provided figure.

[0037] For example, a feedstock 10, such as an extra light, very light, condensate, or low sulfur light crude oil, can be fed to a desalter 12 to produce a desalted crude or condensate feedstock 14. The desalted feedstock 14 is then heated in a convection coil 16 located in a convection section 18 of a thermal cracker 20. The heated feedstock 22 is then fed to a separation system 24 to separate a light paraffin fraction or fractions recovered from the separation system as a vapor 26 from heavier hydrocarbons in the desalted feedstock recovered from the separation system as a liquid 28.

[0038] The light paraffin fraction 26 can then be further heated and superheated using one or more heat exchangers 29. The top of the separator stream 26 can also be heated in the convection section of the heater (not shown in the figure) instead of in the exchanger and can then enter the radiant section. The heat exchangers 29 used to superheat the light paraffin fraction can be located outside the cracker, within the convection section of the cracker, or both. In some embodiments, the external heater used can be an electric heater or steam or other heat transfer fluid can be used to increase the temperature of the light paraffin fraction.

[0039] The superheated light paraffin fraction 30 is then fed to a radiant coil 32 located in a radiant section 34 of the cracker 20 to rapidly increase the temperature of the hydrocarbons therein to a cracking temperature to thermally crack the hydrocarbons to produce lighter hydrocarbons, such as ethylene, propylene, and butylenes, among others. The effluent from the radiant coil is then fed to a transfer line exchanger 36 to rapidly quench the cracking effluent to a temperature below the cracking temperature. Additional heat can then be recovered from the quenched cracking effluent 38 and the cooled effluent is fed to a fractionation zone (not shown) to separate the cracking effluent into various hydrocarbon fractions.

[0040] The liquid 28, i.e., the heavier hydrocarbons recovered from the separation system 24, still contains residuals. The liquid 28 is heated, such as in a convection coil 40 of the cracker 20, and the heated liquid 42 is then fed to a hot hydrogen or hot natural gas stripper 44. One or more additional heavy, difficult to crack feedstocks 46 can optionally be combined with the heavier hydrocarbons 28 prior to heating or stripping. The heavy feedstock can be heated in the same furnace in which the light feedstock is heated or in a separate furnace in which the heavy feedstock will be cracked in a radiant coil.

[0041] In stripper 44, the heavy hydrocarbons are contacted with a stripping medium 48, such as hot hydrogen or hot natural gas (methane, ethane or mixtures thereof) to separate the heavy vaporizable hydrocarbons from the residue. The hydrogen or natural gas can be superheated and at a temperature sufficient to vaporize and lift the hydrocarbons having a normal boiling point up to 540°C, for example, using the stripping medium. The remaining residue can be recovered as a bottoms fraction 50 from the stripper and a mixture of hydrogen and vaporized heavy hydrocarbons can be recovered as an overhead fraction 52 from the stripper. The residue recovered as bottoms fraction 50 can be combined with a pyrolysis oil fraction 54 recovered from a fractionation zone (not shown) used to separate the cracked effluent to produce an ultra-low sulfur fuel oil 56.

[0042] The overhead fraction 52 from the stripper is then condensed to separate the volatilized heavy hydrocarbons from the stripping medium 48A, which can be compressed, reheated and recycled for continued use in the stripper. A portion of the condensed heavy hydrocarbons can be used as reflux 58 to the feed to the stripper 44. The remaining condensed heavy hydrocarbons 60 are mixed with hydrogen 62 and then heated in one or more heat exchangers 64 and / or heaters 66 to heat the hydrocarbons therein to appropriate hydroprocessing conditions. The heated heavy oil 68 is then fed to a hydroprocessing reactor 70. The hydroprocessing reactor 70 can be a fixed bed reactor containing one or more catalyst beds 72 suitable for carrying out the desired hydroprocessing reactions. In other embodiments, the hydroprocessing reactor 70 can include one or more ebullated bed, fluidized bed or fixed bed reactors arranged in series or in parallel to carry out the desired hydroprocessing reactions.

[0043] The hydroprocessing reactor effluent 74 is then cooled in feed / effluent exchangers 64, 76, 78 and one or more additional exchangers 80, 82. The cooled hydroprocessed effluent 84 is then separated to recover a hydroprocessed heavy oil stream 86 and an effluent gas 88, including any unreacted hydrogen, as well as hydrogen sulfide and ammonia produced from the reactions in the reactor. The hydroprocessed heavy oil 86, conditioned as an improved cracking feed, is then recovered, mixed with dilution steam and fed to the radiant coils (not shown) of a cracking furnace to produce chemicals, as described above. If desired or necessary, the hydroprocessed heavy oil can be fed to a stabilizer 90 to remove any dissolved or entrained gases 92 and the stabilized hydroprocessed heavy oil 94 can be fed to the radiant coils (not shown) of a cracking furnace. The gases 92 are fed to a recovery unit (not shown), such as a pressure swing adsorption (PSA) unit for recovering hydrogen. The effluent gas 88 can be fed to one or more adsorbers or separation units 96 to separate the unreacted hydrogen 97 from the ammonia and hydrogen sulfide and the recovered hydrogen 97 can be compressed and fed to the hydrogen heaters 76, 78, along with any make-up hydrogen 98, and from there to the hydroprocessing reactor 70.

[0044] In some embodiments, the hydrotreated heavy oil is mixed with water 100 to facilitate removal of polar compounds. In such embodiments, the cooled hydrotreated heavy oil can be separated to additionally recover high sulfur water 102.

[0045] Dilution steam 104 can be added to aid in the separation and heating of the desalted feed and to limit or prevent fouling during heating of the desalted feed. While steam 104 is shown in combination with the desalted feed in the figure, dilution steam 104 can be added directly to the separation system (flash drum, ASD, or HOPS) or downstream of the separation system (flash drum, ASD, or HOPS) and upstream of the superheat heater or convection coils in one or more locations such as downstream of the desalter and upstream of the convection heat coils, downstream of the convection heat coils and upstream of the separation system (flash drum, ASD, or HOPS), or downstream of the separation system (flash drum, ASD, or HOPS) and upstream of the superheat heater or convection coils. Similarly, steam can be added to the hydrotreated fraction 86, 94 upstream of the superheat coils before the hydrotreated fraction is cracked within the radiant coils of the cracking furnace.

[0046] As noted above, embodiments herein can be used to process extra light, very light, and light crude oils and condensates. Low sulfur, extra light, very light, and light crude oils and condensates can contain very low levels of sulfur, nitrogen, and metals. As a result, these crudes can be economically converted to chemicals without the need for a crude distillation column. These crudes can also have lower residue content (fraction boiling points above about 540°C) and due to the low sulfur nature of the crude or condensate, the residue fraction is suitable for making fuel oil that meets IMO sulfur standards. The lighter portion of the crude or condensate feed is separated into two fractions using a separator such as an advanced separation device (ASD) or a heavy oil processing scheme (HOPS). The lighter fraction is sent directly to a conventional olefins heater for thermal cracking and the heavier fraction is sent to a hydrogenation reactor after removal of the residue using hot hydrogen gas stripping. After hydrotreating, all fractions are thermally cracked in an olefins production reactor.

[0047] Although extra light and very light crude oils and condensates can have very low amounts of residue, it is not recommended to thermally crack any residue fraction for olefin production as residue does not produce any significant amount of olefins. Also, residue will quickly coke the cracking reactor. Therefore, to thermally crack the crude oil for olefins, the residue portion must be removed from the feed to the cracker. Since residue has a high boiling point, to remove residue by fractionation, the crude oil must be heated to a high temperature. This consumes energy. In the embodiments herein, a high-end separation unit or HOPS is used to obtain the light fraction. Extra light and very light crude oils and condensates have very high amounts of naphtha and lighter components. This fraction is rich in paraffins and produces a higher olefin yield. In some embodiments, the 180°C fraction is removed in the first stage of the separator (ASD or HOPS). This can be removed using an external heat source such as medium pressure (MP) or high pressure (HP) steam, or mixed with superheated dilution steam and vaporize the fluid. By mixing with dilution steam, the hydrocarbon partial pressure is significantly reduced and therefore the boiling point is reduced. This is the advantage of direct injection of dilution steam. In any case, the thermal cracking of this fraction requires the addition of dilution steam. Therefore, the light portion of the crude oil is removed in an energy efficient manner without going through the crude distillation column. The heavy portion still contains residue which must be removed. For this, the embodiments herein employ a hot hydrogen stripper. As shown, the resid from the high-end separation unit is fed to the hot hydrogen stripper. Here, hot hydrogen is used instead of steam to separate the heavy vaporizable hydrocarbons from the residue. Hydrogen is used as one of the reactants in the hydrotreating. By superheating the hydrogen, enough energy is supplied to the heavy crude oil to lift the 500°C and lower boiling materials. The vapor mainly contains the 180°C to 500°C fraction hydrocarbons from the crude oil and hydrogen used as the stripping medium. This mixture and any additional hydrogen needed for the hydrotreating will go to the hydrotreating reactor. Here, sulfur and nitrogen will be converted to hydrogen sulfide and ammonia and aromatics will be hydrogenated to naphthenes. The catalyst system will open the naphthene rings to increase the olefin potential in the steam cracker downstream of the hydrotreating section. Depending on the catalyst used, minimal or maximum hydrocracking reactions will occur. The product of the hydrotreating unit will be separated to recover the hydrogen-rich vapor and the remaining hydrocarbon-rich mixture. The hydrocarbon portion is sent to thermal cracking to produce olefins. This fraction has a higher hydrogen content than the original hydrocarbons present in the crude oil. Therefore, the olefin yield will be higher in the thermal cracking of this portion than the yield of the straight-run heavy hydrocarbons in the crude oil or condensate without hydrotreating. The vapor from the hydrotreating is sent to a pressure swing absorption (PSA) unit to recover the unreacted hydrogen and additional hydrogen is added before heating and sent to the hot hydrogen stripper. The bottom of the hot hydrogen stripper (liquid) mainly contains residue and is sold as an ultra-low sulfur fuel oil. In this way, the entire crude oil or condensate is processed. The light fraction is thermally cracked as a straight-run feed and the heavy fraction is hydrotreated and thermally cracked. The residue is sold as fuel.All of this is achieved without using a crude distillation column. Superheated steam and hydrogen are used as heat sources and they also form the reactants for thermal cracking and hydrotreating, respectively. This reduces the overall energy consumption. Thus, the embodiments herein reduce capital expenditure and energy consumption for producing olefins from these feedstocks. The olefin yield is also increased since a portion of the heavy fractions of the crude oil are upgraded by hydrogenation. Only a small amount of hydrogen is required compared to hydrotreating of the whole crude oil. This reduces the pyrolysis oil produced in the cracking reactor. The pyrolysis oil produced in the thermal cracking can also be hydrocracked and recovered to the heater or blended with the residue to make very low sulfur fuel oil. All the products from the hydrotreating section are typically fed to the steam cracker, but optionally diesel meeting the Euro VI specification can be produced. The hydrotreating section can also produce heavy naphtha suitable for aromatics production catalytic reforming. The naphtha cut point (180°C) or the residue initial boiling point (525°C) are typical, but these cut points can be varied depending on the requirements and the feedstock being processed.

[0048] While described above with respect to a single cracking furnace, the embodiments herein can utilize two or more cracking furnaces to process various cracker feeds, including paraffinic light ends and hydrotreated liquids, and provide heat to various streams and generate useful steam, such as dilution steam, medium pressure steam, and high pressure steam.

[0049] As outlined above, the embodiments herein efficiently and effectively convert extra-light, very light, and condensate crude oils into chemicals in a highly efficient and cost effective manner. One skilled in the art would typically propose a whole crude cracking scheme based on the high paraffin and high hydrogen content and lack of contaminants, such as sulfur, nitrogen, and metals, in the very light and condensate crudes. However, it is only after a very detailed analysis of the molecular types of the various fractions present in the heavy and extra-heavy fractions and the resulting impact on olefin yield and heater and transfer line exchanger (TLE) fouling rates that the present scheme was developed that maximizes olefin yield, minimizes fouling, and minimizes capital.

[0050] The embodiments herein do not require crude distillation columns and vacuum distillation columns and associated equipment. There is no proposal for residual hydrotreating or residual hydrocracking of the heaviest fraction of the feedstock. There is no need for deasphalting to isolate asphaltenes and minimal or no hydrocracking is included. In this way, the embodiments herein reduce capital expenditure and reduce energy consumption. Only the hydrogen deficient portion of the crude oil is hydrotreated to maximize olefin production and increase heater run length and reduce fouling of transfer line exchangers. Thus, the embodiments herein are a low capital and highly efficient way to convert light sweet and condensate crudes to chemicals with no low value products from the crude conversion. The crude to chemicals conversion according to the embodiments herein is cheaper and more energy efficient than competing technologies and can be tailored specifically to low sulfur light sweet and light crudes.

[0051] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which these systems, devices, methods, processes and compositions belong.

[0052] As described herein, various streams are mixed or combined upstream or downstream of a processing unit. Mixing can occur in a mixing device, such as a vessel, stirred vessel, pump, or in a flow line, such as a tee or Y connection that blends two streams, with or without a static mixer or other device to enhance mixing of the two streams. Other types of mixing devices known in the art can also be used.

[0053] The singular forms "a," "an," and "the" include plural referents unless the context clearly dictates otherwise.

[0054] As used herein and in the appended claims, the words "comprise," "have," and "include" and all grammatical variations thereof are each intended to have an open, non- limiting meaning that does not preclude additional elements or steps.

[0055] "Optionally" means that the subsequently described event or circumstance can or can not occur. This description includes instances where the event or circumstance occurs and instances where it does not.

[0056] When the word "about" or "approximately" is used, the term can mean that ±10%, up to 5%, up to 2%, up to 1%, up to 0.5%, up to 0.1%, or up to 0.01% variation from a given value can exist.

[0057] Ranges can be expressed as from about one value to about another, including the values. When such ranges are expressed, it is to be understood that another embodiment is from one particular value to another particular value, as well as through all the particular values within the ranges, and combinations thereof.

[0058] While the present disclosure includes a limited number of embodiments, those skilled in the art having the benefit of the present disclosure will appreciate that other embodiments can be devised without departing from the scope of the present disclosure. Accordingly, the scope should be limited only by the appended claims.

Claims

1. A method for converting a wide boiling point hydrocarbon mixture into chemicals, the method comprising: heating a hydrocarbon feedstock to form a heated hydrocarbon feedstock, the hydrocarbon feedstock comprising extra light crude oil, ultra light crude oil, light crude oil, or condensate; separating the heated hydrocarbon feedstock to recover a vaporized light portion and a remaining liquid portion; superheating and thermal cracking the vaporized light portion to recover a first cracking effluent; heating the remaining liquid portion; stripping the remaining liquid portion to recover a stripped vapor mixture comprising a stripping medium and volatilized hydrocarbons and a residual liquid portion; separating the stripped vapor mixture to recover a vapor comprising the stripping medium and a condensed hydrocarbon stream comprising condensed volatilized hydrocarbons; heating the condensed volatilized hydrocarbons and mixing the condensed volatilized hydrocarbons with hydrogen to form a reactant feed stream; feeding the reactant feed stream to a hydroprocessing reactor to convert hydrocarbons therein, thereby forming an effluent comprising crackable heavy hydrocarbons and an effluent gas comprising unreacted hydrogen; separating the effluent to recover a hydroprocessed liquid stream comprising the crackable heavy hydrocarbons and a hydroprocessed vapor stream comprising the unreacted hydrogen; superheating and thermal cracking the hydroprocessed liquid stream to recover a second cracking effluent.

2. The method of claim 1, further comprising separating the first cracking effluent and the second cracking effluent to recover one or more hydrocarbon fractions.

3. The method of claim 2, wherein the one or more hydrocarbon fractions comprise a pyrolysis oil fraction, the method further comprising mixing the pyrolysis oil fraction with the residual liquid portion to form an ultra low sulfur fuel oil.

4. The method of claim 1, further comprising mixing dilution steam with one or more of the hydrocarbon feedstock, the heated hydrocarbon feedstock, the vaporized light portion, and the hydroprocessed liquid stream.

5. The method of claim 1, wherein the stripping medium comprises hydrogen.

6. The method of claim 1, wherein the stripping medium comprises methane, ethane, or natural gas.

7. The method of claim 1, wherein the hydroprocessing comprises one or more of hydrodesulfurization, hydrodenitrogenation, hydrodemetallization, hydrogenation, and ring opening.

8. The method of claim 7, wherein the hydroprocessing does not comprise hydrocracking.

9. The method of claim 1, wherein the vaporized light portion has an end boiling point in the range of 150°C to 200°C.

10. The method of claim 9, wherein the volatilized hydrocarbons have an end boiling point in the range of 480°C to 540°C.

11. The method of claim 10, wherein the separating the heated hydrocarbon feedstock to recover a vaporized light portion and a remaining liquid portion further comprises recovering a mid boiling fraction having an end boiling point in the range of 150°C to 350°C.

12. The method of claim 1, wherein the hydrocarbon feedstock has an API gravity greater than 32° and a sulfur content less than 0.5 wt.%.

13. The process of claim 1, wherein the hydrocarbon feedstock has an API gravity greater than 45°, a sulfur content less than 0.1 wt%, nitrogen less than 150 ppm, a Conradson Carbon (CCR) content less than 0.5 wt%, and a content of hydrocarbons with boiling points greater than 540°C less than 5%.

14. A system for converting a wide boiling point hydrocarbon mixture into chemicals, the system comprising: a heat exchanger for heating a hydrocarbon feedstock to form a heated hydrocarbon feedstock, the hydrocarbon feedstock comprising extra-light crude oil, light crude oil, or condensate; a separator for separating the heated hydrocarbon feedstock to recover a vaporized light fraction and a remaining liquid fraction; a heating coil for superheating and thermal cracking the vaporized light fraction to recover a first cracked effluent; a heat exchanger for heating the remaining liquid fraction; a stripper for stripping the remaining liquid fraction to recover a stripped vapor mixture comprising a stripping medium and volatilized hydrocarbons and a residual liquid fraction; a separator for separating the stripped vapor mixture to recover a vapor comprising the stripping medium and a condensed hydrocarbon stream comprising condensed volatilized hydrocarbons; a heat exchanger for heating the condensed volatilized hydrocarbons and mixing the condensed volatilized hydrocarbons with hydrogen to form a reactant feed stream; a flow line for feeding the reactant feed stream to a hydroprocessing reactor, and the hydroprocessing reactor converts hydrocarbons therein, thereby forming an effluent comprising crackable heavy hydrocarbons and an effluent gas comprising unreacted hydrogen; a separator for separating the effluent to recover a hydroprocessed liquid stream comprising the crackable heavy hydrocarbons and a hydroprocessed vapor stream comprising the unreacted hydrogen; a heating coil for superheating and thermal cracking the hydroprocessed liquid stream to recover a second cracked effluent.

15. The system of claim 14, further comprising a separation system for separating the first cracked effluent and the second cracked effluent to recover one or more hydrocarbon fractions.

16. The system of claim 15, wherein the one or more hydrocarbon fractions comprise a pyrolysis oil fraction, the system further comprising a mixing device for mixing the pyrolysis oil fraction with the residual liquid fraction to form an ultra-low sulfur fuel oil.

17. The system of claim 14, further comprising one or more flow lines for mixing dilution steam with one or more of the hydrocarbon feedstock, the heated hydrocarbon feedstock, the vaporized light fraction, and the hydroprocessed liquid stream.

18. The system of claim 14, further comprising a flow line for feeding hydrogen as the stripping medium to the stripper.

19. The system of claim 1, further comprising a flow line for feeding a stripping medium comprising methane, ethane, or natural gas to the stripper.

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