Configurations for olefins and aromatics production

Abstract

The method of this paper can be used for the various hydrocarbon feeds of thermal cracking, and can save oil refinery completely, and makes the technology of crude oil to chemicals very flexible in crude oil simultaneously.In the embodiment of this paper, crude oil is progressively separated into light fraction and heavy fraction at least.According to the quality of light fraction and heavy fraction, they are sent to one of three upgrading operations, comprise fixed-bed hydroconversion unit, fluidized catalytic conversion unit or can utilize the residual oil hydrocracking unit of ebullating bed reactor.The product from upgrading operation can be used as the charging of steam cracker.

Description

Technical Field

[0001]

[0013] Embodiments herein relate to methods and systems for producing petrochemical products, such as olefins and aromatics, from crude oil and low-value heavy hydrocarbon streams. Background Art

[0002] If the high boiling point compounds in crude oil are sent to a steam cracker, significant operational problems may result. High boiling point compounds have a tendency to form coke, which is largely due to their high asphaltene content. Therefore, high boiling point compounds are usually removed before the lighter fractions are sent to different petrochemical units (such as steam crackers or aromatics complexes). However, the removal process increases the capital cost of the entire process and reduces profitability because the removed high boiling point compounds can only be sold as low-value fuel oil. In addition, the conversion of vacuum residues has been a challenge so far without the formation of large amounts of HPNAs that are harmful to the steam cracking furnace downstream of the process.

[0003] USP 3,617,493 describes a process in which crude oil is fed to the convection section of a steam cracker and then to a separation zone where a portion of the feed having a boiling point below about 450°F is separated from the remainder of the feed and then fed along with steam to the high temperature section of the steam cracker and subjected to cracking conditions.

[0004] USP 4,133,777 describes a process in which feed oil initially trickles downwardly through a fixed bed of HDM catalyst and then passes downwardly through a fixed bed of a promoting catalyst containing selected Group VI and Group VIII metals, with very little hydrocracking occurring in this combined process.

[0005] USP 5603824 discloses a process for upgrading a waxy hydrocarbon feed mixture containing sulfur compounds, which mixture boils in the distillate range to reduce the sulfur content and the 85% point, while maintaining a high octane number of the naphtha byproduct and maximizing the distillate yield. The process employs a single downflow reactor having at least two catalyst beds and an inter-bed redistributor between the beds. The top bed contains a hydrocracking catalyst, preferably zeolite beta, and the bottom bed contains a dewaxing catalyst, preferably ZSM-5.

[0006] USP 3,730,879 discloses a two-bed catalytic process for the hydrodesulfurization of crude oil or reducing fractions, wherein at least 50% of the total pore volume of the first bed catalyst consists of pores having diameters in the range of 100 to 200 angstroms.

[0007] USP 3,830,720 discloses a two-bed catalytic process for hydrocracking and hydrodesulfurization of residual oil, wherein a small pore catalyst is arranged upstream of a large pore catalyst.

[0008] USP 3,876,523 describes a novel catalyst and a method for catalytically demetallizing and desulfurizing hydrocarbon oils containing residual fractions. The method described therein utilizes a catalyst comprising hydrogenation components (such as cobalt and molybdenum oxides) composited on alumina. Although this catalyst is very effective for demetallizing residual fractions and has good stability over time, its effectiveness is significantly improved when this catalyst is used in a particular manner in combination with a second catalyst having different critical properties. A catalyst of the type described in US Pat. No. 3,876,523 is referred to as a first catalyst, and it is understood that the first catalyst will be located upstream of a second catalyst having different properties.

[0009] USP 4,153,539 discloses that improved hydrogen utilization and / or higher conversion of desired products can be obtained when using amphora particles to hydrotreat light hydrocarbon fractions, catalytic reforming, fixed bed alkylation processes, etc. during hydrotreating or hydrocracking.

[0010] USP 4,016,067 discloses that hydrocarbon oils, preferably residual fractions, are catalytically hydrotreated to remove both metals and sulfur very effectively by contacting the oil successively with two catalysts of different characteristics, and that aging of the catalyst system is particularly slow. The first catalyst, located upstream of the second catalyst, is characterized in that at least 60% of its pore volume is in pores with a diameter greater than 100 angstroms, and the other characteristics are specified hereinafter. The second catalyst, located downstream relative to the first catalyst, is characterized in that the major part of its pore volume is in pores with a diameter less than 100 angstroms.

[0011] The dual catalyst apparatus of USP 4,016,067 is used to demetallize and / or desulfurize any hydrocarbon oil whose metal and / or sulfur content is undesirably high for a particular application. The dual catalyst apparatus is particularly effective for preparing low metal and / or low sulfur feedstocks for catalytic cracking or coking. In the process of removing metals and sulfur, the hydrocarbon oil is also simultaneously enriched in hydrogen, making it an even more suitable feed for any of these processes.

[0012] USP 10,017,702 discloses a process for thermal cracking of whole crude oil. Whole crude oil can be partially separated into multiple fractions and the individual fractions can be fed to a steam cracker through separate radiant coils.

[0013] US PG PUB 2019-0023999 A1 discloses separating crude oil into a light cut fraction and a heavy cut fraction. The light cut fraction is then fed to a steam cracker, and the entire heavy cut fraction is hydrotreated and / or hydrocracking.

[0014] Generally speaking, these and other previous methods for converting whole crude oils typically convert less than 50% of the crude oil into more desirable end products, including petrochemical products such as, for example, ethylene, propylene, butenes, pentenes, and light aromatics. Typically, 20% of the whole crude oil is removed in advance during processing to remove the heaviest components that are difficult to convert. Another approximately 20% of the whole crude oil is typically converted into pyrolysis oil, and approximately 10% of the whole crude oil is over-converted into methane. Summary of the invention

[0015] A method for converting whole crude oil and other wide boiling point hydrocarbon streams to produce olefins and / or aromatics, the method comprising: separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction; hydrocracking the high boiling point residual fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residue hydrocracking fraction and a fuel oil fraction; destructively hydrogenating the medium boiling point fraction to form a first destructive hydrogenation effluent; destructively hydrogenating the residue hydrocracking fraction to produce a second destructive hydrogenation effluent; mixing the first destructive hydrogenation effluent and the second destructive hydrogenation effluent to form a mixture and hydrocracking the mixture to form a hydrotreated and hydrocracked effluent; and feeding the hydrotreated and hydrocracked effluent and the low boiling point fraction to at least one of a steam cracker and an aromatics complex to convert the hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra-low sulfur fuel oil (ULSFO).

[0016] A system for converting whole crude oil and other wide boiling point hydrocarbon streams to produce olefins and / or aromatics, the system comprising: a separation system for separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction; a hydrocracker for hydrocracking the high boiling point residual fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residual oil hydrocracking fraction and a fuel oil fraction; a first regulating reactor for destructively hydrogenating the medium boiling point fraction to form a first destructive hydrogenation effluent; a second regulating reactor for hydrocracking the residual oil hydrocracking fraction; The invention relates to a process for destructively hydrogenating the first destructive hydrogenation effluent and the second destructive hydrogenation effluent to produce a second destructive hydrogenation effluent; a mixer for mixing the first destructive hydrogenation effluent and the second destructive hydrogenation effluent to form a mixture, and a hydrocracker for hydrocracking the mixture to form a hydrotreated and hydrocracked effluent; and one or more flow lines for feeding the hydrotreated and hydrocracked effluent and the low boiling point fraction to at least one of a steam cracker and an aromatics complex to convert the hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0017] Other aspects and advantages will become apparent from the following description and appended claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0018] Figure 1 is a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to embodiments herein.

[0019] Figure 2 is a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to embodiments herein.

[0020] Figure 3 is a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to embodiments herein.

[0021] Figure 4 is a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to embodiments herein.

[0022] Figure 5 is a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to embodiments herein.

[0023] Figure 6 is a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to embodiments herein.

[0024] Figure 7 is a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to embodiments herein. DETAILED DESCRIPTION

[0025] As used herein, the term "petrochemicals" refers to hydrocarbons including light olefins, diolefins, and C6-C8 aromatics. Thus, petrochemicals refer to hydrocarbons including ethylene, propylene, butylenes, butadiene, pentenes, pentadienes, as well as benzene, toluene, and xylenes. Referring to a subset of petrochemicals, the term "chemicals" as used herein refers to ethylene, propylene, butadiene, 1-butene, isobutylene, benzene, toluene, and p-xylene.

[0026] Hydroprocessing is a catalytic process, usually carried out in the presence of free hydrogen, and when used to process hydrocarbon feedstocks, its main purpose is to remove various metal contaminants (such as arsenic), heteroatoms (such as sulfur, nitrogen and oxygen) and aromatics from the feedstock. Typically, in hydroprocessing operations, the cracking of hydrocarbon molecules (i.e., breaking down larger hydrocarbon molecules into smaller hydrocarbon molecules) is minimized. As used herein, the term "hydroprocessing" refers to a refining process in which a feed stream is reacted with hydrogen in the presence of a catalyst to remove impurities such as sulfur, nitrogen, oxygen and / or metals (such as nickel or vanadium) from the feed stream (such as atmospheric tower bottoms) through a reduction process. The hydroprocessing process can vary greatly depending on the type of feed to the hydroprocessor. For example, light feeds (such as naphtha) contain very small amounts and types of impurities, while heavy feeds (such as ATB) typically have many different heavy compounds present in crude oil. In addition to having heavy compounds, the impurities in heavy feeds are more complex and more difficult to handle than those present in light feeds. Therefore, hydroprocessing of light feeds is usually carried out at lower reaction severity, while heavy feeds require higher reaction pressures and temperatures.

[0027] Hydrocracking refers to the hydrogenation and dehydrogenation of hydrocarbons accompanied by cracking / cracking, for example, the conversion of heavier hydrocarbons to lighter hydrocarbons, or the conversion of aromatics and / or cycloalkanes (cycloalkanes) to non-cyclic branched alkanes.

[0028] As used herein, "conditioning" and similar terms refer to the conversion of hydrocarbons by one or both of hydrocracking and hydrotreating. "Destructive hydrogenation" and similar terms refer to the cracking of hydrocarbon molecular bonds of hydrocarbons, and the associated hydrogen saturation of the remaining hydrocarbon fragments, which can create a stable low boiling hydrocarbon oil product, and can include both hydrocracking and hydrotreating.

[0029] "API Gravity" means the specific gravity of a petroleum feed or product relative to water as determined by ASTM D4052-11.

[0030] Embodiments herein relate to methods and systems for producing petrochemical products such as light olefins (ethylene, propylene and / or butenes) and aromatics using crude oil and / or low-value heavy hydrocarbons as feedstock. More specifically, embodiments herein relate to methods and systems for producing olefins and aromatics by thermal cracking of pre-conditioned crude oil or condensate. Methods herein can regulate the residual fraction of whole crude oil and natural condensate to produce useful raw materials as steam cracker feedstock.

[0031] The integration of conditioning, fractionation and steam cracking can produce efficient facilities, and in some embodiments, can be greater than 55%, greater than 60%, greater than 65%, greater than 70%, greater than 75%, greater than 80% or greater than 85% of the whole crude oil converted into petrochemical products. In other embodiments, the integration of conditioning, fractionation and steam cracking can produce efficient facilities, and in some embodiments can be greater than 55%, greater than 60%, greater than 65%, greater than 70%, greater than 75%, greater than 80% or greater than 85% of the whole crude oil converted into chemicals. Therefore, the embodiments herein can provide systems and methods for conditioning feeds including even the heaviest, most undesirable residue components to components that can be vaporized and enter the radiant section of the steam cracker, greatly improving the low petrochemical product conversion of previous methods.

[0032] Hydrocarbon mixtures useful in the embodiments disclosed herein may include various hydrocarbon mixtures having the following boiling ranges, wherein the final boiling point of the mixture may be greater than 500°C, such as greater than 525°C, 550°C, or 575°C. The amount of high boiling hydrocarbons, such as hydrocarbons with boiling points exceeding 550°C, may be as low as 0.1 wt%, 1 wt%, or 2 wt%, but may be as high as 10 wt%, 25 wt%, 50 wt%, or more. This specification is explained with respect to crude oil, such as whole crude oil, but any high boiling endpoint hydrocarbon mixture may be used. However, the methods disclosed herein may be applied to crude oils, condensates, and hydrocarbons having a broad boiling point curve and an endpoint above 500°C. Such hydrocarbon mixtures may include whole crude oil, virgin crude oil, hydrotreated crude oil, gas oil, vacuum gas oil, heating oil, jet fuel, diesel, kerosene, gasoline, synthetic naphtha, resid reformate, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasoline, distillate oils, virgin naphtha, natural gas condensate, atmospheric still bottoms, vacuum still streams including bottoms, wide boiling range naphtha to gas oil condensate, heavy non-virgin hydrocarbon streams from refineries, vacuum gas oil, heavy gas oil, atmospheric residue, hydrocracked wax, Fischer-Tropsch wax, etc. In some embodiments, the hydrocarbon mixture may include hydrocarbons boiling from the naphtha range or lighter to the vacuum gas oil range or heavier.

[0033] When the final boiling point of the hydrocarbon mixture may be high, such as in some embodiments when more than 550 ℃, the hydrocarbon mixture cannot be directly processed in the steam pyrolysis reactor to produce olefins. The presence of these heavy hydrocarbons leads to the formation of coke in the reactor, wherein coking may occur in one or more convection zone preheating coils or superheating coils, radiation coils or transmission line heat exchangers, and this coking may occur quickly, such as within a few hours. Commercially, whole crude oil is usually not cracked because it is not economical. It is usually fractionated, and only a specific cut fraction is used for steam pyrolysis heater to produce olefins. The remainder is used for other processes. The cracking reaction is carried out by a free radical mechanism. Therefore, high ethylene yields can be obtained when it is cracked at high temperatures. Lighter feeds, such as butane and pentane, require high reactor temperatures to obtain high olefin yields. Heavy feeds, such as gas oil and vacuum gas oil (VGO), require lower temperatures. Crude oil contains a distribution of compounds from butane to VGO and residual oil (material boiling point exceeds 550 ℃). Subjecting whole crude oil to high temperatures without separation produces high yields of coke (a byproduct of cracking hydrocarbons at high severity) and plugs the reactor. Steam pyrolysis reactors must be shut down periodically and cleaned of coke by steam / air decoking. The time between two cleaning cycles during olefin production is called the run cycle. When whole crude oil is cracked without separation, coke is deposited in the convection section coils (vaporizing fluid), the radiant section (where olefin production reactions occur), and / or the transfer line heat exchangers (where reactions are quickly stopped by cooling to maintain olefin yields).

[0034] Methods and systems according to embodiments herein may include a feed preparation section, a crude conditioning section, an aromatic complex, and a steam cracker. The feed preparation section may include, for example, a desalter.

[0035] The desalted crude is then conditioned and processed so that a crackable feed is sent to the steam cracker and / or aromatics complex. The conditioning section allows the operator to maximize the yield of petrochemical products while maintaining a reasonable decoking frequency of the furnace. Another goal of the crude conditioning unit is to ensure complete or substantially complete (95%+) conversion of asphaltenes to lower boiling components, thereby increasing the yield of petrochemical products while reducing the formation of heavy polynuclear aromatics (HPNA).

[0036] Therefore, the method according to the embodiments of the present invention can convert the heavier fractions of crude oil into high-value petrochemical products and can minimize the amount of hydrocarbons sent to the fuel oil pool, which greatly improves profitability. The small fuel oil pool produced may also be upgraded to low-sulfur fuel oil that complies with IMO 2020, further increasing the value of the product.

[0037] As mentioned above, the high boiling point compounds in crude oil may cause significant operational problems if they are sent to a steam cracker, because they have a tendency to form coke, mainly due to their high asphaltene content. Therefore, high boiling point compounds are usually removed before the lighter fractions are sent to different petrochemical units (such as steam crackers and aromatics complexes). The removal process increases the capital cost of the entire process and reduces profitability because the removed high boiling point compounds can only be sold as low-value fuel oil. In addition, the conversion of vacuum residues has been a challenge to date in the industry without forming a large amount of HPNAs that are harmful to the steam cracking furnace downstream of the process. The method and system according to the embodiments herein can overcome these challenges.

[0038] The configuration of the system and method for converting whole crude oil and heavy hydrocarbons according to the embodiments described herein can effectively process residual oil conversion while maximizing petrochemical product conversion and maintaining a lower coke tendency in the steam cracker. This is achieved by integrating the residual oil hydrocracking reactor into the crude oil conditioning process so that high boiling point compounds can be converted into lighter components. In various embodiments, the residual oil hydrocracking unit according to the embodiments herein may include a fixed bed residual oil hydrocracking unit, an ebullating bed residual oil hydrocracking reactor, and a slurry bed residual oil hydrocracking reactor.

[0039] Upgraded crude oil streams from crude conditioning units, such as from fixed bed crude conditioning units and hydrocrackers, are suitable feedstocks for steam crackers as well as aromatic complexes. This can result in a decrease in the overall process yield of low value fuel oils, while increasing the yield of high value olefins and aromatics, such as benzene, toluene and xylenes (BTX).

[0040] Separation of various fractions, such as low boiling hydrocarbon fractions (e.g., 160°C- fractions), medium boiling fractions (e.g., 160°C to 490°C fractions), and high boiling fractions (e.g., 490°C+ fractions), can improve the capital efficiency and operating costs of the methods and systems disclosed herein. Although three cut fractions are mentioned in many embodiments herein, the inventors of the present application recognize that condensate oil, which generally has a small amount of high boiling point components, and whole crude oil, which has a larger amount of high boiling point components, can be processed in different ways. Therefore, for a wide boiling range petroleum feed, one, two, three or more separate cuts can be performed, and each cut fraction can be processed independently under optimal conditions.

[0041] One or more separators (distillation towers, flash tanks, etc.) can be used to separate the whole crude oil into the desired fractions. In some embodiments, the separation of the petroleum feed can be carried out in an integrated separation device (ISD), such as disclosed in US20130197283, which is incorporated herein by reference. In the ISD, the low boiling point fraction is initially separated in the ISD based on a combination of centrifugal and cyclonic effects to separate the desired vapor fraction from the liquid. Additional separation steps can then be used to separate the medium boiling point fraction from the high boiling point component.

[0042] Typically, hydrocarbon components boiling above 490°C contain asphaltenes and Conradson carbon residues and therefore require appropriate processing, as further described below. Although embodiments are described as including fractions below about 90°C to 250°C, such as a 160°C- fraction and above about 400°C to 560°C, such as a 490°C+ fraction, it should be noted that the actual cut point may vary depending on the type of whole crude oil or other heavy fraction being processed. For example, for crude oils containing low levels of metals or nitrogen, or a large amount of "easier to process" components that boil at temperatures of up to 525°C, 540°C, or 565°C, for example, the medium / high cut point can be increased while still achieving the benefits of the embodiments herein. Similarly, in some embodiments, the low / medium cut point can be as high as 220°C, or in other embodiments up to 250°C. In addition, it has been found that a low / medium cut point of about 160° C. may be advantageous for the sizing and operation of a reactor (such as a fixed bed conditioning reactor) for conditioning the middle fraction hydrocarbons (middle cut). In addition, for certain feeds, such as condensate, the low / medium cut point may be as high as 565° C. According to embodiments herein, the ability to vary the cut point may increase the flexibility of the process scheme, allowing a variety of feeds to be processed while still producing a desired product mixture.

[0043] Thus, in some embodiments, the light cut fraction may include hydrocarbons having a boiling point of at most about 90° C. (e.g., 90° C.-fraction), at most about 100° C., at most about 110° C., at most about 120° C., at most about 130° C., at most about 140° C., at most about 150° C., at most about 160° C., at most about 170° C., at most about 180° C., at most about 190° C., at most about 200° C., at most about 210° C., at most about 220° C., at most about 230° C., at most about 240° C., at most about 250° C. (e.g., 250° C.-fraction), at most about 300° C., at most about 350° C., at most about 400° C., at most about 500° C., or at most about 565° C. Embodiments herein also contemplate that the light cut fraction is hydrocarbons having a boiling point of at most intermediate temperatures of the above ranges.

[0044] Depending on the fractionation mechanism used, the light hydrocarbon "cut fraction" may be relatively clean, meaning that the light fraction may not have any substantial amount (as used herein>1 weight %) of compounds with a boiling point higher than the expected boiling temperature target value. For example, the 160°C-cut fraction may not have any substantial amount of hydrocarbon compounds with a boiling point higher than 160°C (i.e.>1 weight %). In other embodiments, the expected target "cut fraction" temperature mentioned above may be the 95% boiling point temperature, or in other embodiments, the 85% boiling point temperature, such as can be measured using ASTM D86 or ASTM D2887, or for example, true boiling point (TBP) analysis according to ASTM D2892, and ASTM D7169 is used for heavy streams (such as those with a boiling point higher than about 400°C). In these embodiments, there may be up to 5 weight % or up to 15 weight % of compounds higher than the indicated "cut fraction" point temperature. For many whole crude oils, the low / medium cut point may be such that the 95% boiling point temperature of the low boiling fraction is in the range of about 90°C to about 250°C. However, for other feeds, such as condensate, the 95% boiling point temperature of the low boiling fraction may be in the range of, for example, about 500°C to about 565°C.

[0045] In some embodiments, the middle cut fraction may include hydrocarbons having a boiling point ranging from the lower limit of the temperature of the light cut fraction (e.g., such as 90°C, 100°C, 110°C, 120°C, 130°C, 140°C, 150°C, 160°C, 170°C, 180°C, 190°C, 200°C, 210°C, 220°C, 230°C, 240°C, 250°C, 300°C, 350°C or 40 The boiling point of hydrocarbons is at most about 350°C, at most about 375°C, at most about 400°C, at most about 410°C, at most about 420°C, at most about 430°C, at most about 440°C, at most about 450°C, at most about 460°C, at most about 480°C, at most about 490°C, at most about 500°C, at most about 520°C, at most about 540°C, at most about 560°C, or at most about 580°C. As used herein, for example, a mid-cut fraction having a lower limit of 160°C and an upper limit of 490°C may be referred to as a 160°C to 490°C cut fraction or fraction. Embodiments herein also contemplate that the mid-cut fraction is hydrocarbons having a boiling point of at least and / or at most an intermediate temperature of the above ranges.

[0046] According to the fractionation mechanism, the hydrocarbon "cut" of the middle cut may be relatively clean, which means that the middle cut may not have any substantial amount (>1 weight %) of compounds with boiling points below the expected boiling temperature target limit and / or may not have any substantial amount (>1 weight %) of compounds with boiling points above the expected boiling temperature target limit. For example, a cut of 160°C to 490°C may not have any substantial amount of hydrocarbon compounds with boiling points below 160°C or above 490°C. In other embodiments, the expected target "fractionation" temperature mentioned above can be a 5 weight % or 15 weight % boiling point temperature at the lower limit and / or a 95% or 85% boiling point temperature at the upper limit, such as can be measured using ASTM D86 or ASTM D2887, or for example, true boiling point (TBP) analysis according to ASTM D2892, and for heavy streams, such as streams with boiling points above about 400°C, ASTM D7169 can be used. In such embodiments, up to 5% or up to 15% by weight of the compound may be above and / or below the "fractionation" point temperature, respectively.

[0047] In some embodiments, the heavy cut fraction may include hydrocarbons having a boiling point greater than about 350° C., greater than about 375° C., greater than about 400° C. (e.g., 400° C. + fraction), greater than about 420° C., greater than about 440° C., greater than about 460° C., greater than about 480° C., greater than about 490° C., greater than about 500° C., greater than about 510° C., greater than about 520° C., greater than about 530° C., greater than about 540° C., greater than about 560° C., greater than about 580° C., greater than about 590° C., greater than about 600° C. (e.g., 600° C. + fraction), or greater than about 700° C. Embodiments herein also contemplate that the heavy cut fraction is hydrocarbons having boiling points at intermediate temperatures greater than the above temperatures.

[0048] According to the fractionation mechanism, the heavy hydrocarbon "cut fraction" may be relatively clean, which means that the heavy fraction may not have any substantial amount (>1 wt%) of compounds with boiling points below the expected boiling temperature target value. For example, the 490°C+ cut fraction may not have any substantial amount of hydrocarbon compounds with boiling points below 490°C. In other embodiments, the expected target "cut fraction" temperature mentioned above can be the 95% boiling point temperature, or in other embodiments, the 85% boiling point temperature, such as can be measured using ASTMD86 or ASTM D2887, or for example, true boiling point (TBP) analysis according to ASTM D2892, and for heavy streams, such as streams with boiling points above about 400°C, ASTM D7169 can be used. In such embodiments, there may be up to 5 wt% or up to 15 wt% of the compounds below the "cut fraction" point temperature, respectively.

[0049] Although the following examples are given with respect to a limited temperature range, it is contemplated that any temperature range specified above can be used in the methods described herein. In addition, with respect to the cut point, the cut points mentioned in the following examples may be clean, as described above, or may refer to the 5% or 15% boiling temperature as a lower limit, or may refer to the 85% or 95% boiling temperature as an upper limit.

[0050] After fractionation, the light cut fraction, such as the 160°C-cut fraction, can be fed to the steam cracker section of the system with or without further processing. For example, the light cut fraction fed to the steam cracker section can include light naphtha and lighter hydrocarbons, and in some embodiments can include heavy naphtha boiling range hydrocarbons.

[0051] The mid-range hydrocarbon cut fraction can be conditioned using one or more fixed bed reactors, such as hydrotreating and / or hydrocracking reactors, each of which can destructively hydrogenate the hydrocarbons in the mid-range cut fraction. The conditioning reactors can include catalysts for removing metals, removing sulfur, and removing nitrogen, and the conditioning in these reactors can generally add hydrogen to the hydrocarbon components, making them easier to process downstream to produce petrochemical products. For example, a fixed bed catalyst system in the mid-range cut fraction conditioning zone can contain different layers of demetallization, destructive hydrogenation, and medium-pore zeolite hydrocracking catalysts to optimize the conversion of heavy materials to achieve a balance between a highly paraffinic stream suitable for olefin production and an aromatics-rich stream suitable for aromatic production.

[0052] In some embodiments, it may be desirable to further separate the mid-cut fraction into a low-mid-cut fraction and a high-mid-cut fraction. For example, a mid-cut fraction having a boiling range of 160°C to 490°C may be divided into a low-mid-cut fraction having a boiling range of about 160°C to about 325°C and a high-mid-cut fraction having a boiling range of about 325°C to about 490°C. Thus, the conditioning series of units may be configured to more selectively convert the hydrocarbon components in the corresponding low-mid-cut fraction and the high-mid-cut fraction into the desired conditioned effluent, wherein each series of units may be configured based on a preferred catalyst for destructive hydrogenation of the hydrocarbons therein, reactor sizing and catalyst life for the expected feed volume, and operating conditions for achieving the desired conversion into a steam cracker feedstock containing a naphtha range. Similarly, it is also contemplated to divide the mid-cut fraction into three or more seed cut fractions.

[0053] The hydrocarbons in the heavy cut fraction can also be adjusted using one or more fixed bed reactors, slurry reactors or ebullating bed reactors. For example, the adjustment of the heavy cut fraction (such as 490°C+ hydrocarbons) can be carried out in a residue hydrocracker, and the conversion rate of low-value streams to high-value petrochemical products can be increased by steam cracking. For example, residue hydrocracking can be carried out in a fixed bed residue hydrocracker, an ebullating bed reactor (such as an LC-FINING or LC-MAX reactor system) and a slurry reactor (such as an LC-SLURRY reactor), each of which can be purchased from Chevron LummusGlobal. However, it should be recognized that the life of the destructive hydrogenation and / or hydrocracking catalyst may be negatively affected by heavier components, such as when the feed includes a component with a boiling point higher than, for example, 565°C. Similar to the middle cut fraction, it is also considered to divide the heavy cut fraction into one or more sub-cut fractions.

[0054] The crude oil conditioning section (including the middle cut and heavy cut conditioning) is designed to achieve four (4) goals. First, the crude oil conditioning section can be used to increase the concentration of paraffins and cycloalkanes in the crude oil. Second, the conditioning section can reduce the concentration of polynuclear aromatics (PNA) in the crude oil. Third, the conditioning section can reduce the final boiling point (FBP) of the crude oil to below 540°C. And fourth, the conditioning section can minimize the vacuum residual fraction of the crude oil.

[0055] For example, when conditioning the middle and heavy fractions, embodiments herein may target the conversion of heavier hydrocarbons to hydrocarbons lighter than diesel. Thus, destructive hydrogenation catalysts and operating conditions may be selected to target the conversion of hydrocarbons or hydrocarbons in the corresponding fractions to hydrocarbons that are primarily (>50 wt%) naphtha range, such as greater than 60 wt% naphtha range, or such as greater than 70 wt% naphtha range. Using catalysts and operating conditions in the conditioning section to target lighter hydrocarbon products may improve the operability of the steam cracker and the productivity of petrochemical products.

[0056] In some embodiments, adjustment of the heavy cut (such as 490°C+cut) can result in conversion of at least 70% by weight of compounds having a boiling point in excess of 565°C to lower boiling compounds. Other embodiments can result in conversion of greater than 75%, greater than 80%, or greater than 85% by weight of compounds having a boiling point in excess of 565°C to lower boiling compounds.

[0057] In some embodiments, adjustment of the mid-cut fraction (such as a 160° C. to 490° C. cut fraction) may result in greater than 50% by weight of the hydrocarbons therein being converted to naphtha-range hydrocarbons. In other embodiments, adjustment of the mid-cut fraction may result in greater than 55%, greater than 60%, or greater than 65%, or greater than 70% by weight of the hydrocarbons therein being converted to naphtha-range hydrocarbons.

[0058] In some embodiments, the adjustment of the middle cut fraction and the heavy cut fraction together can result in greater than 50% by weight of the hydrocarbons therein being converted to naphtha range hydrocarbons overall. In other embodiments, the adjustment of the middle cut fraction and the heavy cut fraction can result in greater than 55%, greater than 60%, or greater than 65% by weight of the hydrocarbons therein being converted to naphtha range hydrocarbons.

[0059] In some embodiments, as a result of such initial separation and adjustment, the feed to the steam cracker can be fed directly to the steam cracker without further processing. In some embodiments, after separation, a light cut fraction having preferred properties, including one or more of boiling point, API, BMCI, hydrogen content, nitrogen content, sulfur content, viscosity, MCRT, or total metal content can be fed directly to the steam cracker. According to embodiments herein, the effluent from the adjustment of the medium cut fraction can also be fed directly to the steam cracker. Similarly, in some embodiments, the effluent from the adjustment of the heavy cut fraction can be fed directly to the steam cracker.

[0060] Adjustment of the respective fractions as described herein can allow the steam cracker to operate for extended periods of time, even when processing a variety of feeds of different boiling point ranges. In some embodiments, the steam cracker may be able to operate uninterrupted for at least three years; in other embodiments at least four years; and in still other embodiments at least five years.

[0061] In addition, the initial hydrocarbon fractionation point, reactor size, catalyst, etc. can be adjusted or configured so that the operation time of the steam cracker operation and the adjustment process are consistent. Catalyst, reactor size and conditions can be configured to make the operation time of the adjustment unit consistent with the operation time of the steam cracker. Catalyst volume, catalyst type and reaction severity may all play a role in determining the operation time of the adjustment unit. In addition, the adjustment degree of heavier hydrocarbons in crude oil may affect the coking in the thermal steam cracker. In order to maximize the normal operation time of the equipment, the embodiment of this article considers the design and configuration of the entire system so that for a given raw material or a plurality of expected raw materials, the adjustment system has an expected operation time similar to that of the steam cracker. In addition, the embodiment of this article considers adjusting the reaction conditions (fractionation point, T, P, space velocity, etc.) in the adjustment section and / or the steam cracker based on the raw material being processed, so that the operation time of the adjustment section and the steam cracker is similar or consistent.

[0062] The harmonization of run times can result in minimal downtime, such as when catalyst turnover in a conditioning reactor is performed simultaneously with decoking of a steam cracker. Where the conditioning system includes multiple reactors or reactor types, the harmonization of run times can be based on the desired steam cracker performance. In addition, for example, where the run time of a hydrotreater may be much longer than that of a hydrocracker in the conditioning section, parallel reactor trains and / or bypass processing can be used so that the total run times of the conditioning unit and steam cracking unit can be harmonized.

[0063] Bypass processing can include, for example, temporarily processing a heavy (such as 490°C+) cut in a reactor that normally processes lighter feedstocks (such as a mid cut and a heavy mid cut). Heavier feedstocks are expected to have more severe conditions and shorter catalyst life, so temporarily processing the heavies in a midrange hydrocarbon conditioning reactor during heavy catalyst replacement can allow whole crude feed to continue to be fed to the steam cracker without shutting down while the heavy conditioning reactor catalyst is replaced. The configuration of the midrange conditioning reactor can also take into account the expected bypass processing when designing a consistent run time for the entire system.

[0064] Recognizing that fixed bed conditioning may be detrimental to the light fractions of some feedstocks, it may be desirable to perform an initial separation so that the heavier components are conditioned for steam cracker feed, while the lighter components already suitable for steam cracker feed are not further conditioned. Figure 1 , illustrates a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to an embodiment of the present invention.

[0065] A wide boiling range hydrocarbon feed, such as a desalted crude oil 1, may be fed to a separation system 3. The separation system 3 may be an integrated separation device (ISD) as described above, and include, for example, separation and heat integration. In the separation system 3, the desalted crude oil 1 may be separated into three fractions, including (a) a light cut fraction, such as a 160°C- fraction 5, which does not require any conditioning and may be used as a feed to a steam cracker section 7; (b) a medium cut fraction, such as a 160°C to 490°C fraction 9, which may be upgraded in a conditioning section 11 to produce lighter hydrocarbons, such as a highly paraffinic hydrocarbon stream 13 suitable for processing in a steam cracking section 7; and (c) a heavy cut fraction, such as a 490°C+ fraction 15, which contains the most difficult materials in the crude oil and may be upgraded in a residue hydrocracker 17. Other fractionation points may also be used to send the desired fractions and hydrocarbons therein to the desired units for conditioning and / or steam cracking. The residue hydrocracker can produce ultra low sulfur fuel oil 19 and a stream 21 suitable for feeding to a conditioning system for further conditioning and production of additional hydrocarbons suitable for conversion to petrochemical products in the steam cracker section 7. Processing of the feed in the steam cracker section can produce one or more petrochemical product streams 23, such as ethylene, propylene and butenes, etc., and a higher boiling pyrolysis oil fraction 25.

[0066] In some embodiments, the middle cut fraction (such as a 160°C to 490°C stream) may be initially processed in a fixed bed destructive hydroprocessing reactor 27. The 490°C+ stream may be processed in a residue hydrocracking reactor system 17, such as using an ebullating bed extrudate catalyst or a slurry catalyst, which may include one or more reactors that convert some of the hydrocarbons to lighter hydrocarbons, such as 490°C- hydrocarbons. Additional lighter hydrocarbons may be processed in a fixed bed destructive hydroprocessing reactor, which may be the same reactor used to condition the middle cut fraction, or, as shown, may be a separate fixed bed destructive hydroprocessing reactor 29, which may contain a catalyst specifically for effectively conditioning the primary converted hydrocarbons obtained from residue hydrocracking. The reaction products 31, 33 of the hydrotreated middle cut (e.g., 160°C to 490°C stream 9) and the hydrotreated lighter material (e.g., 490°C-residue hydrocracker effluent) from the fixed bed destructive hydroprocessing reactors 27, 29, respectively, can then be combined and processed together in a fixed bed hydrocracking reactor 35 to produce a feedstock 13 suitable for processing in the steam cracker section 17 for conversion to light olefins and other valuable petrochemical products. For example, the unconverted portion of the residue hydrocracking reactor effluent can be processed in, for example, a fixed bed hydrodesulfurization unit (not shown) to produce ultra low sulfur fuel oil (ULSFO).

[0067] In some embodiments, conditioning reactors 27 and 29 may include a destructive hydrogenation catalyst (first stage conditioning), while conditioning reactor 35 includes a hydrocracking catalyst (second stage conditioning). Additionally, in some embodiments, first stage conditioning may include a catalyst designed to reduce the content of polynuclear aromatic compounds, thereby conditioning the feed for easier processing in a steam cracker.

[0068] Reference now Figure 2 , illustrates a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to an embodiment of the present invention, wherein like numbers represent like components. In this embodiment, the processing of desalted whole crude oil is similar to that described above for Figure 1 In this embodiment, the heavy cut fractions, such as 490°C+ stream 15 and pyrolysis oil stream 25 are combined and processed in a residue hydrocracking reactor to convert some of the hydrocarbons in the streams to 490°C- hydrocarbons, which are further processed in a fixed bed destructive hydroprocessing reactor 29.

[0069] As described above, destructive hydrogenation reactors 27, 29 can be used to adjust the middle cut fraction (such as 160 ° C to 490 ° C stream 9) and the effluent (such as 490 ° C-) stream 21 from the residue hydrocracking system 17. In some embodiments, these streams can be processed in the same destructive hydrogenation reactor. However, it has been found that due to the nature of the feed compounds for various crude oils, processing in a single reaction series unit may result in molecules in the stream containing more aromatic rings than molecules of straight-run Arab light crude oil or Arab ultra-light crude oil of the same boiling range. Therefore, in order to fully saturate the molecules, more severe conditions may be required, which has an adverse effect on the life and / or capital investment of the destructive hydroprocessing catalyst. If the previously converted materials in stream 21 are processed together with the straight-run middle cut fraction materials in stream 9, the turnover time of a single destructive hydrogenation series unit may be reduced to less than the turnover time of the steam cracking section, and / or when the destructive hydrogenation catalyst system undergoes regeneration and / or replacement, a spare destructive hydrogenation series unit is required to provide a stable feedstock flow to the steam cracking section. The foregoing also applies to other types of crude oils, such as desalted oil, condensate, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, reconstituted crude oil, and oils derived from asphalt.

[0070] To alleviate the catalyst life / turnaround time issue, the fixed bed destructive hydrogenation step can be split into separate trains, e.g. Figure 1 and Figure 2As shown. A series of units can be provided for processing a cut fraction (e.g., 160°C to 490°C) from a straight run of crude oil, and a second series of units can be provided for processing (e.g., 490°C-) effluents from one or more residue hydrocracking reactors. In general, the turnover time of the reactor 27 in the first destructive hydrogenation step can be longer than the turnover time of the steam cracking furnace, and a spare reactor may not be required to maintain normal operating time. The reactor 29 in the second series of units may have more frequent turnovers to replace the catalyst, but during catalyst replacement, it can redirect its feed to the first series of units, such as through flow line 37, so it also does not require a spare reactor series unit to maintain normal operating time. As a temporary diversion of the feed, the impact on the reactor series unit 27 is minimal, so the reactor series unit 27 can be designed to synchronize its turnover with the turnover of the steam cracking furnace.

[0071] As described above, in some embodiments, various feedstocks may allow for increased cut points, such as increasing the mid / high cut point from 490° C. to 545° C. This may also be true for processing in a residue hydrocracking system, where higher boiling hydrocarbons may be able to be fed to a destructive hydrogenation reactor to be converted into a feedstock suitable for steam cracking. However, for processing high boiling point fractions (e.g., 490° C.+ or 545° C.+ fractions) in a residue hydrocracking system, it has been found that a lower cut point may be more advantageous, as a cut point that is too high may require the use of cutter oil to produce ULSFO.

[0072] Reference now Figure 3 , illustrates a simplified process flow diagram of a system for converting whole crude oil and heavy hydrocarbons according to an embodiment of the present invention.

[0073] A wide boiling range heavy hydrocarbon feed, such as desalted crude oil 10, may be fed to a separation system 12. The separation system 12 may be, for example, an integrated separation device (ISD) as described above. In the separation system 12, the desalted crude oil 10 can be separated into three fractions, including (a) a light cut fraction, such as a 160°C- fraction 14, which does not require any conditioning and can be used as a feed to a steam cracker 16 and an aromatics integration unit 18; (b) a medium cut fraction, such as a 160°C to 490°C fraction 20, which can be upgraded in a fixed bed conditioning section 22 to produce two types of lighter streams, including a high paraffin stream 24 and an aromatics-rich stream 26, the high paraffin stream 24 being suitable for use in the steam cracking system 16, which can produce a light olefin stream 46, and the aromatics-rich stream 26 being suitable for use in the production of aromatics, which can produce an aromatics stream 36, which can include benzene and paraxylene; and (c) a heavy cut fraction, such as a 490°C+ fraction 28, which contains the most difficult-to-handle materials in the crude oil, which can be upgraded in an ebullated bed residue hydrocracker 30. Other fractionation points may also be used to send the desired fractions and hydrocarbons therein to the desired units for conditioning and / or cracking. For example, an ebullated bed residue hydrocracker may produce ultra low sulfur fuel oil 32 and stream 34, which is suitable for feeding to a fixed bed conditioning system to produce the above two streams (steam cracker feed 24 and aromatics complex feed 26). As described above, stream 20 and stream 34 may be processed in separate conditioning train units to advantageously provide similar catalyst and steam cracker life cycles.

[0074] Other low value refinery streams may also be processed according to embodiments herein to ultimately produce higher value products. Such streams include some or all of the following types of hydrocarbons: (i) light cycle oil (LCO), such as LCO produced from an FCC unit, which may be fed via flow line 40 and processed in fixed bed crude conditioning section 22 with a medium cut fraction (such as 160°C to 490°C fraction 20); (ii) slurry oil, such as slurry oil produced from an FCC unit, which may be fed via flow line 42 and processed in ebullating bed reactor 30 with a heavy cut fraction (such as 490°C+) hydrocarbons in stream 28; (iii) Bitumen, such as produced from a solvent deasphalting unit, which may be fed through the same or different flow line 42 and processed in the ebullated bed reactor 30 with the heavy cut (e.g., 490°C+) hydrocarbons in stream 28; and / or (iv) pyrolysis fuel oil (Pyoil), such as pyrolysis fuel oil produced from a steam cracker, including pyrolysis fuel oil stream 44 from steam cracker 16, which may be processed in the ebullated bed reactor 30 with the heavy cut (e.g., 490°C+) hydrocarbons in streams 28 and / or 42. Various other hydrocarbon streams having similar boiling ranges may also be co-processed to produce petrochemical products in the systems disclosed herein, where such streams may include light naphtha, heavy naphtha, crude oil, atmospheric residue, vacuum residue, synthetic crude oil, and other hydrocarbon streams containing heavy hydrocarbons.

[0075] After fixed bed conditioning of the middle cut fraction from stream 20, the effluent stream from the residue hydrocracking system 30, and / or the LCO from stream 40 in the fixed bed conditioning reactor train unit 22, the reactor effluent 48 may be fed to a separation system 50 (such as an ISD) to recover a low boiling fraction 52 suitable for processing in the steam cracker 16 and the aromatics complex 18, as well as a high boiling fraction 54. The high boiling fraction 54 may be fed to the residue hydrocracking system 30 for further processing and conversion into lighter hydrocarbons, such as 490°C- compounds. In some embodiments, the separator 50 may provide a light fraction 52 having a cut point in the range of about 160°C to about 220°C, and provide a heavy fraction 54 having a corresponding lower cut point, such as 160°C+ or 220°C+ hydrocarbons.

[0076] Similarly, after processing the heavy cut fraction (such as the 490°C+ fraction 28) in the residue hydrocracking unit 30, the residue hydrocracker reactor effluent 60 may be fed to a separation system 62 (such as an ISD) to recover a low boiling fraction 34 containing conversion products suitable for processing in the fixed bed conditioning system 22, and a high boiling fraction 64. The high boiling fraction 64 may be fed to an integrated hydrotreater or hydrodesulfurization reactor 66 to produce ULSFO 32. In some embodiments, the separator 62 may provide a light fraction 34 having a cut point in the range of about 490°C to about 520°C, and provide a heavy fraction 64 having a corresponding cut point, such as 490°C+ hydrocarbons.

[0077] The low boiling range fractions 14, 52 may be fed to a separator 58 to separate the components into, for example, a light naphtha fraction 24 and a heavy naphtha fraction 26. The light naphtha range components may then be processed in a steam cracker system 16 to produce petrochemical products, while the heavy naphtha range components may be processed in an aromatics complex 18 to produce benzene, toluene, and xylenes, for example.

[0078] In some embodiments, the heavy naphtha 26 fraction may be processed upstream of the aromatics complex 18, such as a hydrogen sulfide processor (not shown) to further prepare the feed for conversion in the aromatics complex. Likewise, the pyrolysis oil stream 44 may undergo a pyrolysis oil stabilization step (the corresponding flow diagram is not shown) before processing in the residue hydrocracking reactor.

[0079] As briefly described above, embodiments of the present invention may allow direct cracking of crude oil into petrochemical products in an economically viable manner to form light hydrocarbons (e.g., ethylene, propylene) and light aromatics without conventional refining steps. In addition, as the shale gas revolution has led to an increasing shift toward cracking lighter raw materials, direct conversion of crude oil into petrochemical products may help prevent the expansion of the supply and demand gap of key components that are usually produced as by-products (propylene, butadiene).

[0080] The integration of processing units according to embodiments of the present invention can provide unique potential for upgrading whole crude oil (such as Arab light crude oil and Arab ultra-light crude oil) and low-value refinery streams (such as pyrolysis oil (PyOil), slurry oil and light cycle oil (LCO)) to higher-value petrochemical products. Although hydrogen is added to the feed components according to embodiments of the present invention, and hydrogen consumption is an additional cost for the plant, the comprehensive benefits of producing petrochemical products rather than fuels exceed this additional cost. The above also applies to other types of crude oil, such as desalted oil, condensate, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, reconstituted crude oil and oil derived from asphalt.

[0081] In various embodiments, an aromatics complex may be included, as described above. For example, an aromatics complex may be used to convert a 160°C to 490°C fraction or a portion thereof into aromatics. For example, a cut fraction, such as a 160°C to 240°C fraction, may be processed to convert a portion of the hydrocarbons therein into aromatics, while the heavies may be fed to a steam cracker for conversion into petrochemical products. According to embodiments herein, the aromatics complex feedstock produced by initial processing and conditioning may allow various processors to stop importing full range naphtha (FRN).

[0082] In addition, in some embodiments, the pyrolysis oil produced in the steam cracking unit can be separated to recover a pyrolysis gasoline fraction, and one or more heavy fractions, such as a pyrolysis gas oil fraction and a pyrolysis fuel oil fraction. As described above, the lighter pyrolysis gasoline fraction can be fed to the aromatics unit, while the heavier fraction can be used to form ULSFO.

[0083] Embodiments herein provide a strategic combination of crude feed preparation, crude separation, crude conditioning and steam cracking technologies to maximize the yield of high-value petrochemical products. The crude conditioning section uses a combination of fixed-bed hydroprocessing and liquid circulation, and ebullating bed or slurry bed residue hydrocracking to condition crude oil into a suitable steam cracker feed and upgrade low-value refinery streams. Embodiments herein, for example, can achieve a yield of petrochemical products in the range of 60% to 90% of the full crude feed.

[0084] As described above, after desalting, the crude oil can be separated into three cuts, including: a light cut (such as a 160°C-stream), which can then be further separated into 90°C- and 90°C to 160°C cuts to be fed to the steam cracking heater and the aromatics complex, respectively; a medium cut (such as a 160°C to 490°C stream); and a heavy cut (such as a 490°C+ stream). The light cut (such as a 160°C-stream) does not require upgrading and can therefore be sent directly as a steam cracker and aromatics complex feedstock. The medium cut (e.g., a 160°C to 490°C stream) is easily processed in a fixed bed destructive hydrogenation / conditioning reaction system, in which the feed is hydrotreated and converted into naphtha, becoming an ideal steam cracker feedstock 24 and an aromatics complex feedstock 26.

[0085] The heavy cut fraction (e.g., 490°C+ stream) contains the most difficult compounds to process in crude oil, including asphaltenes, metals, and Conradson carbon residue (CCR). In a fixed bed downflow reactor, conversion and catalyst operating cycle are typically limited by the metal, CCR, and asphaltene content in the residual oil feed, which can cause rapid fouling of the catalyst and increase pressure drop. The embodiments herein may employ an upflow expanded bed reactor to overcome the pressure drop problem and allow the method to operate uninterruptedly for a long time at a high residual oil conversion rate. Similarly, in some embodiments, the heavy cut fraction (e.g., 490°C+ stream) can be processed in a liquid circulation, ebullating bed reactor, such as the LC-FINING technology available from Lummus Technology LLC. The LC-SLURRY reactor technology available from ChevronLummus Global can also be used to process even heavier streams, such as asphalt.

[0086] The crude conditioning section may contain four reaction stages, including an ebullated bed reactor (such as an LC-FINING reactor), first and second stage hydrocracking reactors, and a heavy oil destructive hydrogenation reactor. These four reaction stages may be operated in a single, common recycle gas circulation loop. The integration of these crude conditioning stages achieves the key processing goals of upgrading low-value refinery streams, eliminating the need to import full range naphtha (FRN), and providing steam cracker feed for the production of incremental ethylene, while minimizing hydrogen consumption, investment and operating costs.

[0087] Reference now Figure 4 , illustrates a simplified flow diagram of a method for producing olefins and aromatics according to an embodiment of the present invention, wherein like numbers represent like components. As an exemplary feed, Arabian light crude oil 100 can be processed to produce enough light naphtha (110) to produce incremental ethylene as part of stream 118 in a mixed feed steam cracker (MFC) 120 in addition to feed 112 for an aromatics complex 122. Other feeds to the mixed feed steam cracker may include, for example, a raffinate-2 stream 123, propane 124, a reactive organic gas (ROG) 125, and the mixed feed steam cracker may produce pyrolysis oil 102, pyrolysis gas oil 127, mixed C4 128, propylene 129, and ethylene 118, among other products. Figure 4 An overall process schematic is provided, highlighting the major equipment and flow paths for one possible configuration according to embodiments herein. Although Arabian light crude oil is used as an example, the above also applies to other types of crude oils, such as desalted oil, condensate, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, reconstituted crude oil, and oil derived from asphalt.

[0088] For example, the feed stream of the feed conditioning section 101 may include Arabian light crude oil 100, pyrolysis oil 102 (PyOil) (such as pyrolysis oil that can be produced in a mixed feed cracker 120), slurry oil 104, and light cycle oil 106 (LCO). Figure 4 As shown, the following products may be produced from the conditioning section: steam cracker feedstock (such as 90°C- hydrocarbons) 110; aromatics complex feedstock (such as 90°C to 160°C hydrocarbons) 112; and ultra-low sulfur fuel oil (ULSFO) 114. Conditioning may also result in the production of various by-products, such as fuel gas, sour water, rich amine liquid, and desalted brine, and may require utilities such as hydrogen, stripping sour water, lean amine liquid, steam, electricity, cooling water, fuel gas, nitrogen, BFW, and a feed preparation section, which may include desalting (all not shown).

[0089] Similar to other embodiments herein, the desalted crude oil 100 may be initially fed to a separator, such as an ISD 12. In the separation system 12, the desalted crude oil 100 may be separated into three fractions, including (a) a light cut fraction, such as a 160°C- fraction 14, (b) a medium cut fraction, such as a 160°C to 490°C fraction 20, which may be upgraded in a fixed bed conditioning section 22, which may include a fixed bed hydrotreating and / or hydrocracking reactor, and (c) a heavy cut fraction, such as a 490°C+ fraction 28, which contains the most difficult materials in the crude oil and may be upgraded in an ebullated bed residue hydrocracker 30.

[0090] Conditioned compounds, such as 490°C-compounds, produced in the residue hydrocracker 30 may be fed via stream 34 for further conditioning in the conditioning section 22. Other full boiling range naphtha feedstocks may be fed to the aromatics unit, such as via flow line 105, if desired.

[0091] Reference now Figure 5, the desalted crude oil 100 can be separated in a first integrated separation device (ISD) 158 to recover a 160°C- fraction 113. For example, the integrated separation device 158 can be operated at 200°C and 8 barg to improve the vapor liquid separation efficiency. The ISD overhead vapor product 113 (such as a 160°C- cut fraction of the crude oil) is conveyed to a product splitter 160. In the product splitter 160, the 160°C- hydrocarbons together with the hydroprocessed product 316 or a portion thereof can be separated into a light (such as a 30°C- or 35°C-) stream 120, a light naphtha stream (e.g., a 30°C to 90°C stream) 120, and a heavy naphtha (e.g., a 90°C to 160°C) stream 122. The light stream 110 and the light naphtha stream 120 can then be used as a feedstock for a steam cracker 111 to produce an incremental amount of ethylene or other product petrochemical products 113. The heavy naphtha 122 may be used as a feedstock 122A for the aromatics complex 112. In some embodiments, at least a portion 112B of the heavy naphtha 122 may be combined with the light naphtha 120 and fed to a steam cracker to produce additional petrochemical products 113 and / or pyrolysis oil 191. In other embodiments, all of the heavy naphtha 122 may be fed to the steam cracker 111 when the aromatics complex needs to be taken offline for maintenance, or when there is not enough benzene, toluene, and / or xylenes (BTX) in streams 113 and / or 316. For example, the heavy naphtha feed route may also be based on demand.

[0092] The remaining 160°C+ crude oil fraction 114 from ISD 158 can be fed to a second separation system, such as a hot hydrogen stripper 166, in which the 160°C+ crude oil fraction is further separated into a mid-cut fraction (such as a 160°C to 490°C fraction 168) and a heavy-cut fraction (such as a 490°C+ fraction 170).

[0093] The heavy cut fraction 170 (such as the 490°C+ cut fraction) contains the most difficult compounds to process in the crude oil that must be handled, including asphaltenes, metals, and CCRs. Excessive metals, CCRs, and asphaltenes in the high-boiling residual fraction may cause rapid fouling of the catalyst and increase the pressure drop in the fixed-bed downflow reactor, thereby limiting both conversion and catalyst run cycle. The use of an upflow expanded bed reactor can overcome the pressure drop problem and allow the process to operate uninterrupted for a long time at high residue conversion. Similarly, in some embodiments, the heavy cut fraction, 490°C+ stream 170 can be processed in a liquid circulation, ebullating bed reactor system 200.

[0094] The heavy cut fraction 170 can be processed in the ebullated bed reactor system 200 along with one or more additional feeds, such as slurry oil 192 and / or pyrolysis oil 191. In some embodiments, the ebullated bed reactor system 200 can include a first ebullated bed reactor and a second ebullated bed reactor. In embodiments where not all of the pyrolysis oil 191 is recycled to the ebullated bed reactor system 200, the pyrolysis oil can be removed from the system via stream 193.

[0095] The ebullated bed reactor system effluent 202 may be flashed in a high pressure, high temperature (HP / HT) separator 204. The vapor 206 from the HP / HT separator 204 may be combined with one or more of the cut fraction 168 from the second ISD 166, the vapor 208 from the heavy oil hydrotreating (HOHDT) HP / HT separator 210, and fed to the first stage fixed bed conditioning section 176. The liquid 214 from the HP / HT separator 204 may be processed in a heavy oil destructive hydrotreating reactor 222. The heavy oil destructive hydrotreating reactor effluent 223 may be separated in the HOHDT separator 210. The HOHDT liquid effluent 115 may be combined with a portion of the product separator bottoms 300 (300A) to produce the ULSFO product 301.

[0096] The primary objective of the first stage reaction system 176 is to hydrotreat the blended feed to reduce feed sulfur and nitrogen levels, partially convert to products, and prepare the feed for further processing in the second stage reactor 178. The liquid feed to the first stage reaction system 176 can be a blend of a 160°C to 490°C crude oil fraction 166 cut from a straight run (SR), an ebullated bed reactor distillate 206, vapor 208 from a HOHDT separator 210, and LCO 106.

[0097] To meet the processing objectives of removing feed sulfur and nitrogen and partially converting to a suitable steam cracker feedstock, the first stage reactor 176 can be loaded with a catalyst system consisting of demetallization, destructive hydrogenation, and hydrocracking catalysts. To control the temperature rise due to the exothermic reaction, the catalyst can be separated into multiple beds within the reactor or separate reactor vessels. A cold recycle gas (not shown) can be introduced between beds or reactors to quench the reaction fluids and control the temperature rise and reaction rate.

[0098] The first stage reactor effluent 250 may consist of unconverted oil, distillate, naphtha, light fractions, and excess hydrogen not consumed in the first stage reactor 176. The first stage reactor effluent stream 250 may be fed to a high pressure low temperature (HP / LT) separator 266. Any recovered acidic water 274 containing NH3 and / or H2S may be removed from the system. The hydrogen-rich vapor 276 from the HP / LT separator 266 may be sent to a gas compression and distribution system 277. The gas compression and distribution system may clean and pressurize the hydrogen and recycle the hydrogen to a common hydrogen header 400. Although not shown, the hydrogen in the common hydrogen header 400 may be fed to one or more of the ebullating bed conditioning system 200, the first stage reaction system 176, the second stage reaction system 178, and the heavy oil destructive hydrogenation reactor 222.

[0099] The hydrocarbon liquid 290 leaving the HP / LT separator 266 can be pumped to the second stage reaction section 178 for further conditioning, with the goal of maximizing naphtha production. The goal of the second stage reaction system 178 is to crack the unconverted oil (UCO) from the first stage reaction section into lighter products. Similarly, the second stage reactor can be loaded with a high activity hydrocracking catalyst. A portion of the product separator bottoms 300 (300B) can also be fed to the second stage reaction system 178 for additional conditioning.

[0100] The second stage reactor effluent 180 may be fed to a high pressure low temperature (HP / LT) separator 314. The HP / LT liquid product 316 may be fed to the product splitter 160, and the vapor product 320 may be mixed with the hydrogen-rich vapor 276 in the gas compression and distribution system 277. Recovered hydrogen and fresh hydrogen, if desired, may be delivered from the gas compression and distribution system 277 to the various conditioning reactors as needed.

[0101] The 160°C-product 113 from the integrated separation device 158 can be fed to the product splitter 160 together with the HP / LT liquid product 316. The product splitter 160 can separate the reactor effluent product into a light fraction 110, a light naphtha fraction 120, and a heavy naphtha 122. The light naphtha product 110 is transported to the steam cracker 111 as a feedstock.

[0102] The heavy naphtha product 122 may be taken as a side draw from the product splitter 160. A portion 112A of the heavy naphtha product 122 may be pumped to the aromatics complex 112, while a portion 112B of the heavy naphtha product 122 may be combined with the light naphtha fraction 120 and fed to the steam cracker 111.

[0103] As about Figure 1 and Figure 2 As described, the separation system 3 can be as follows Figure 6 As shown. Separation system 3 can be as described above and include separation and heat integration. After desalting, crude oil 1 can be further preheated in the convection section of heater 500 to produce preheated crude oil 502. Preheated crude oil 502 can then be fed to separator 504, which can facilitate the separation of 160°C-fraction 5 from heavier components, which are recovered to stream 506.

[0104] The remaining 160°C+ crude oil fraction 506 can be fed to a pump 508, which produces a pressurized 160°C+ crude oil fraction 510, which can then be fed to a heat exchanger 512. The heat exchanger 512 can preheat the 160°C+ crude oil fraction 510 with the hot hydrogen stripper bottoms 520, producing a pressurized and preheated 160°C+ crude oil fraction 514. The pressurized and preheated 160°C+ crude oil fraction 514 can then be fed back to the heater 500, where it is heated to facilitate the separation of the 160 to 490°C fraction from the heavier 490°C+ fraction. The heated 160°C+ crude oil fraction 516 can then be fed to a hot hydrogen stripper 518. In the hot hydrogen stripper 518, the 160°C+ crude oil fraction is further separated into a 160 to 490°C fraction 9 and a hot hydrogen stripper bottoms 520 containing heavier 490°C+ hydrocarbons. The hot hydrogen stripper bottoms 520 is cooled by indirect heat exchange with the pressurized 160°C+ crude oil fraction 510 in the heat exchanger 512 and can be removed from the separation system 3 as a 490°C+ fraction 15.

[0105] The hot hydrogen stripper 518 can utilize hydrogen feed 522 as the stripping medium. The hot hydrogen stripper 518 can be operated to provide wide flexibility depending on the nature of the crude feedstock being processed. The stripper overhead (160 to 490°C fraction 9) can be cooled to recover hydrogen and sent to an intermediate hydroprocessing reaction stage as appropriate, such as with respect to Figure 1 and 2 The recovered hydrogen can be fed to a downstream pressure swing adsorption (PSA) unit (not shown) after amine treatment (not shown) to increase the hydrogen purity. The PSA hydrogen product can be compressed in a make-up hydrogen compressor (not shown) to feed one or more hydroprocessing reactors ( Figure 1 and 2 ) provides supplemental hydrogen and serves as hot hydrogen feed 522.

[0106] The hot hydrogen stripper bottoms 520 (such as the 490°C+ cut) contain the most difficult compounds in crude oil that must be handled, including asphaltenes, metals, and CCRs. Excessive amounts of metals, CCRs, and asphaltenes in the high boiling residual fraction can cause rapid catalyst fouling and increase pressure drop in fixed bed downflow reactors, limiting both conversion and catalyst run cycle. After being cooled by the pressurized 160°C+ crude fraction 510, the 490°C+ stream 11 can be recovered and processed in a liquid recycle, ebullating bed residue hydrocracker, such as a pyrolysis oil stream, or a slurry oil stream, along with any additional low value refinery streams (such as a pyrolysis oil stream and / or an oil slurry stream). Figure 1 and Figure 2 described.

[0107] By adjusting the amount of hydrogen 522 fed to the hot hydrogen stripper 518, as well as the operating conditions of the hot hydrogen stripper 518 and the heater 500, the hydrocarbon cut point can be adjusted so that the light cut fraction 5 can be fed directly to the downstream steam cracker, and the medium cut fraction 9 may have little or no harmful compounds that quickly foul the fixed bed conditioning reactor. In this way, the separation system 3 (with the hot hydrogen stripper 518) can concentrate the most difficult hydrocarbons into the heavy cut fraction 11, which can be fed to the ebullating bed reactor operating under severe conditions.

[0108] If targeted Figure 3 and Figure 4 As described above, the separation system 12 may be as follows Figure 7 The separation system 312 can be as described above and include separation and heat integration. After desalting, the crude oil 100 can be further preheated in the convection section of the heater 500 to produce a preheated crude oil 502. The preheated crude oil 502 can then be fed to the separator 504, which can facilitate the separation of the 160°C-fraction 5 in the integrated separation system 3.

[0109] The remaining 160°C+ crude oil fraction 506 may be fed to a pump 508, which produces a pressurized 160°C+ crude oil fraction 510, which may then be fed to a heat exchanger 512. The heat exchanger 512 may preheat the 160°C+ crude oil fraction 510 via a hot hydrogen stripper bottoms 520 to produce a pressurized and preheated 160°C+ crude oil fraction 514. The pressurized and preheated 160°C+ crude oil fraction 514 may then be fed back to the heater 500, where it is heated to facilitate separation of the 160°C to 490°C fraction from the heavier 490°C+ fraction. The heated 160°C+ crude oil fraction 516 may then be fed to a hot hydrogen stripper 518. In the hot hydrogen stripper 518, the 160°C+ crude oil fraction is further separated into a 160°C to 490°C fraction 20 and a hot hydrogen stripper bottoms 520 containing heavier 490°C+ hydrocarbons. The hot hydrogen stripper bottoms 520 is cooled by indirect heat exchange with the pressurized 160°C+ crude oil fraction 510 in the heat exchanger 512 and can be removed from the separation system 3 as a 490°C+ fraction 28.

[0110] The hot hydrogen stripper 518 can utilize hydrogen feed 522 as the stripping medium. The hot hydrogen stripper 518 can be operated to provide wide flexibility depending on the nature of the crude feedstock being processed. The stripper overhead (160 to 490° C. fraction 20) can be cooled to recover hydrogen and sent to an intermediate hydroprocessing reaction stage as appropriate, such as with respect to Figure 3 and 4 The recovered hydrogen can be fed to a downstream pressure swing adsorption (PSA) unit (not shown) after amine treatment (not shown) to increase the hydrogen purity. The PSA hydrogen product can be compressed in a make-up hydrogen compressor (not shown) to feed one or more hydroprocessing reactors ( Figure 3 and 4 ) provides supplemental hydrogen and serves as hot hydrogen feed 522.

[0111] The hot hydrogen stripper bottoms 520 (such as the 490°C+ cut) contains the most difficult compounds in crude oil that must be handled, including asphaltenes, metals, and CCRs. Excessive amounts of metals, CCRs, and asphaltenes in the high boiling residual fraction can cause rapid catalyst fouling and increase pressure drop in fixed bed downflow reactors, limiting both conversion and catalyst run cycle. After being cooled by the pressurized 160°C+ crude fraction 510, the 490°C+ stream 28 can be recovered and processed in a liquid recycle, ebullating bed residue hydrocracker, such as a pyrolysis oil stream, and / or a slurry oil stream, along with any additional low value refinery streams (such as a pyrolysis oil stream and / or a slurry oil stream). Figure 3 and Figure 4 described.

[0112] By adjusting the amount of hydrogen 522 fed to the hot hydrogen stripper 518, as well as the operating conditions of the hot hydrogen stripper 518 and the heater 500, the hydrocarbon cut point can be adjusted so that the light cut fraction 5 can be fed directly to the downstream steam cracker, and the medium cut fraction 20 may have little or no harmful compounds that quickly foul the fixed bed conditioning reactor. In this way, the separation system 12 (with the hot hydrogen stripper 518) can concentrate the most difficult hydrocarbons into the heavy cut fraction 28, which can be fed to the ebullating bed reactor.

[0113] Regarding the above Figure 1-7 , the light cut, the middle cut and the heavy cut are given as limited examples of 160°C -, 160°C to 490°C and 490°C +. The cut points can be adjusted so that the light cut can be fed directly to the steam cracker with little intermediate processing and the middle cut and the heavy cut can be efficiently processed within their respective reactor train units.

[0114] The steam cracker comprising the ethylene complex used in embodiments herein may include various unit operations. For example, the ethylene complex may include a cracker, such as a steam cracker. Other cracking operations may also be used. The ethylene complex may also include an olefin recovery unit, a butadiene extraction unit, an MTBE unit, a C4 selective hydrogenation unit, a pyrolysis gasoline hydroprocessing unit, an aromatics extraction unit, a metathesis unit and / or a disproportionation unit and other units for producing and recovering olefins and other light hydrocarbons. For example, the product from the ethylene complex may include ethylene, propylene, butadiene, benzene, MTBE and mixed xylenes etc.

[0115] In some embodiments, the hydrocarbon stream to be cracked can be fed directly to a steam cracker. In other embodiments, the hydrocarbon stream to be cracked can be separated into multiple fractions for separate processing (cracking, for example, cracking at a preferred temperature, pressure and residence time for each respective fraction).

[0116] The hydrocarbon feedstock, which may be a single hydrocarbon or a mixture of hydrocarbons, may be introduced into a heating coil disposed in a convection section of a steam pyrolysis heater, wherein the hydrocarbon feedstock may be heated and / or vaporized by convection heat exchange with the exhaust gas in the heating coil.

[0117] If desired, the heated hydrocarbon feedstock may be mixed with steam or an inert compound such as nitrogen, carbon dioxide or any other inorganic gas. Parts of the process or additional processes in the plant may use low temperature or saturated steam, while other parts may use high temperature superheated steam. Steam used elsewhere in the process or plant may be heated or superheated by heating coils (not shown) disposed in the convection zone of the steam pyrolysis heater.

[0118] The heated hydrocarbon mixture may then be fed to a heating coil, which may be located at a lower position in the steam pyrolysis heater than the convection zone heating coils described above, and therefore at a higher temperature than the convection zone heating coils described above. The resulting superheated mixture may then be fed to one or more coils located in the radiant zone of the steam pyrolysis heater, operated at a temperature to partially convert the hydrocarbon mixture by thermal cracking. The cracked hydrocarbon product may then be recovered.

[0119] In some embodiments, if desired, multiple heating and separation steps may be used to separate the hydrocarbon mixture to be cracked into two or more hydrocarbon fractions. This will allow each cut to be optimally regulated and steam cracked so that the yield, steam to oil ratio, heater inlet and outlet temperatures, and other variables can be controlled at desired levels to achieve the desired reaction results, such as desired product characteristics while limiting coking in the radiant coils and associated downstream equipment. Since the various cuts, depending on the boiling points of the hydrocarbons in the various feed streams, are separated and cracked, coking in the radiant coils and transfer line heat exchangers can be controlled. Thus, the operating cycle of the heater can be increased to many weeks, rather than a few hours, thereby increasing the yield of olefins.

[0120] After cracking in the radiant coils, one or more transfer line heat exchangers can be used to cool the product very quickly and generate (ultra) high pressure steam. One or more coils can be combined and connected to each exchanger. The exchangers can be double tube or multi-shell and tube exchangers.

[0121] Instead of indirect cooling, direct quenching can also be used. In this case, oil can be injected at the outlet of the radiant coil. After the oil quench, water quenching can also be used. Instead of oil quenching, full water quenching is also acceptable. After quenching, the product is sent to the recovery section.

[0122] As described above, embodiments of the present invention can separate desalted crude oil or other wide boiling hydrocarbons into various fractions to effectively adjust the corresponding fractions to form a feedstock suitable for conversion in a steam cracker. Since the range of feedstocks that can be processed according to embodiments of the present invention is very wide, depending on the feedstock, adjustment catalyst, reactor volume, and other factors of a given device, it may be more preferable to determine a specific fractionation point based on one or more additional properties of the feedstock. For example, a specific fractionation point can be adjusted based on one or more properties or additional properties of the crude feedstock, such as API gravity, Bureau of Mines Correlation Index (BMCI), hydrogen content, nitrogen content, sulfur content, viscosity, microcarbon residue (MCRT) and / or total metals and other feedstock properties.

[0123] Various feedstocks useful in embodiments herein, such as crude oil, desalted oil, condensate, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, reconstituted crude oil, and oil derived from asphalt may have one or more of the following properties, including: an API gravity between 4 and 60°, a BMCI of 20 to 85, a hydrogen content of 9.0 to 14.5 wt % (or 90,000 to 145,000 ppm), a nitrogen content of 0.02 to 0.95 wt % (or 200 to 9,500 ppm), a sulfur content of 0.009 to 6.0 wt % (or 90 to 60,000 ppm), a viscosity at 40° C. of 95 to 5500 centistokes (cSt), a MCRT of 5 to 35 wt %, and / or may have a total metal content of <1 to 1000 ppm.

[0124] Initial crude oil separation can be performed and adjusted to provide the light cut, the middle cut, and the heavy cut with specific desired initial properties so that the light cut can enter the steam cracker without or with minimal intermediate processing. In addition, fractionation of the middle to heavy fractions can be performed and adjusted so that the middle and heavy cuts have appropriate and / or favorable feed properties and hydrocarbon species for effective and efficient conditioning in the middle and heavy fraction conditioning reactors.

[0125] BMCI

[0126] In some embodiments, the light cut may have a BMCI of less than 20. In other embodiments, the light cut may have a BMCI of less than 15. In still other embodiments, the light cut may have a BMCI of less than 10 or even less than 5. In some embodiments, the medium cut may have a BMCI of less than 40, such as less than 35, less than 30, or less than 25. In some embodiments, the heavy cut may have a BMCI of greater than 30, such as greater than 35, greater than 40, greater than 45, greater than 50, or greater than 55.

[0127] Thus, in some embodiments, the light cut, including hydrocarbons having a boiling point of up to about 90°C to about 300°C, for example, may have a BMCI of less than 20; in other embodiments, such as when the light cut includes hydrocarbons having a boiling point of up to about 110°C or up to about 250°C, for example, the light cut may have a BMCI of less than 10; in still other embodiments, such as when the light cut includes hydrocarbons having a boiling point of up to about 130°C or up to about 220°C, for example, the light cut may have a BMCI of less than 5. In some embodiments where the light cut includes hydrocarbons having a boiling point below about 160°C, the light cut may have a BMCI of less than 5. While the BMCI may vary for different feeds at any given fractionation temperature, it has been found that a low BMCI, such as, for example, less than 10 or less than 5, may improve the processing properties of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, for Arabian light crude processed according to embodiments herein, the light cut fraction may target a BMCI of less than 10, and for example, for Arabian ultra-light crude, the light cut fraction may target a BMCI of less than 6 or less than 5.5.

[0128] In some embodiments, the mid-cut fraction, including hydrocarbons having a lower boiling point in the range of about 90°C to about 300°C and an upper boiling point in the range of about 400°C to about 600°C, may have a BMCI between about 5 and 50. For example, the mid-cut fraction may have a BMCI between a lower limit of 5, 10, 15, 20, or 25 and an upper limit of 10, 15, 20, 25, 30, 40, or 50. For example, it has been found that a mid-cut fraction having a BMCI between 10 and 30 can be converted into a steam cracker feed using relatively mild destructive hydrogenation conditions in the mid-cut fraction conditioning section of the process herein. For example, for an Arabian light crude processed according to embodiments herein, the mid-cut fraction may target a BMCI in the range of about 20 to about 30, and for example, for an Arabian ultra-light crude, the mid-cut fraction may target a BMCI in the range of about 15 to about 30.

[0129] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, may have a BMCI greater than 30. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the heavy cut may have a BMCI greater than 40. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the heavy cut may have a BMCI greater than 50. In embodiments where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut may have a BMCI greater than 55. For example, it has been found that a heavy cut having a BMCI greater than about 40 can be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein. For example, for an Arabian light crude processed according to embodiments of the present invention, the heavy cut fraction can target a BMCI in the range of about 50 to about 60, and for example, for an Arabian extra light crude oil, the heavy cut fraction can target a BMCI in the range of about 25 to about 40.

[0130] API

[0131] In some embodiments, the light cut fraction may have an API gravity greater than 10°. In other embodiments, the light cut fraction may have an API gravity greater than 15°. In still other embodiments, the light cut fraction may have an API gravity greater than 20°, greater than 30°, or even greater than 40°. In some embodiments, the medium cut fraction may have an API gravity greater than 10° and less than 40°, such as from a lower limit of 10°, 15°, 20°, 25°, or 30° to an upper limit of 25°, 30°, 35°, 40°, 45°, or 50°. In some embodiments, the heavy cut fraction may have an API gravity less than 40°, such as less than 35°, less than 25°, less than 20°, less than 15°, or less than 10°.

[0132] Thus, in some embodiments, the light cut, including hydrocarbons having a boiling point of up to about 300°C, for example, can have an API gravity of greater than 10°; in other embodiments, such as when the light cut includes hydrocarbons having a boiling point of up to about 250°C, for example, the light cut can have an API gravity of greater than 20°; in still other embodiments, such as when the light cut includes hydrocarbons having a boiling point of up to about 220°C, for example, the light cut can have an API gravity of greater than 40°. In some embodiments where the light cut includes hydrocarbons having a boiling point of less than about 160°C, the light cut can have an API gravity of greater than 60°. While the API gravity may vary for different feeds at any given fractionation temperature, it has been found that an API gravity, such as, for example, greater than 40°, greater than 50°, or greater than 60°, can improve the processing properties of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, for Arabian light crude processed according to embodiments herein, the light cut fraction may target an API gravity greater than 65°, and for example, for Arabian extra light crude, the light cut fraction may target an API gravity greater than 60°.

[0133] In some embodiments, the mid-cut fraction, including hydrocarbons having a lower boiling point in the range of about 90°C to about 300°C and an upper boiling point in the range of about 400°C to about 600°C, can have an API gravity between about 5° and 50°. For example, the mid-cut fraction can have an API gravity between a lower limit of 5°, 10°, 15°, 20°, or 25° and an upper limit of 10°, 15°, 20°, 25°, 30°, 40°, or 50°. For example, it has been found that a mid-cut fraction having an API gravity between 20° and 40° can be converted into a steam cracker feed using relatively mild destructive hydrogenation conditions in the mid-cut conditioning section of the process herein. For example, for Arabian light crude oil processed according to embodiments of the present invention, the mid-cut fraction can target an API gravity in the range of about 30° to about 35°, and for example, for Arabian extra light crude oil, the mid-cut fraction can target an API gravity in the range of about 35° to about 40°.

[0134] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, can have an API gravity of less than about 40°. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the heavy cut can have an API gravity less than about 20°. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the heavy cut can have an API gravity less than about 10°. For example, in an embodiment where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut can have an API gravity less than 7°. For example, it has been found that a heavy cut having an API gravity less than about 20° can be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein. For example, for an Arabian light crude processed according to embodiments herein, the heavy cut fraction may target an API gravity in the range of about 5° to about 10°, and, for example, for an Arabian extra light crude, the heavy cut fraction may target an API gravity in the range of about 10° to about 20°.

[0135] Hydrogen content

[0136] In some embodiments, the light cut fraction may have a hydrogen content greater than 12% by weight. In other embodiments, the light cut fraction may have a hydrogen content greater than 13% by weight. In still other embodiments, the light cut fraction may have a hydrogen content greater than 13.5% by weight, greater than 14% by weight, or even greater than 15% by weight. In some embodiments, the medium cut fraction may have a hydrogen content greater than 11% by weight and less than 14% by weight, such as from a lower limit of 11, 11.5, 12.0, 12.5, or 13.0% by weight to an upper limit of 12.0, 12.5, 13.0, 13.5, 14.0, or 14.5% by weight. In some embodiments, the heavy cut fraction may have a hydrogen content less than 13% by weight, such as less than 12.5% ​​by weight, less than 12% by weight, less than 11.5% by weight, or less than 11% by weight.

[0137] Thus, in some embodiments, the light cut, including hydrocarbons having a boiling point of up to about 300° C., for example, may have a hydrogen content of greater than 13 wt %; in other embodiments, such as when the light cut includes hydrocarbons having a boiling point of up to about 250° C., for example, the light cut may have a hydrogen content of greater than 13.5 wt %; in still other embodiments, such as when the light cut includes hydrocarbons having a boiling point of up to about 220° C., for example, the light cut may have a hydrogen content of greater than 14.0 wt %. In some embodiments where the light cut includes hydrocarbons having a boiling point of less than about 160° C., the light cut may have a hydrogen content of greater than 14.5 wt %. While the hydrogen content may vary for different feeds at any given fractionation temperature, it has been found that a hydrogen content, such as, for example, greater than 13 wt %, greater than 14 wt %, or greater than 14.5 wt %, may improve the processing properties of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, for Arabian light crude processed according to embodiments herein, the light cut fraction may target a hydrogen content greater than 14.5 wt %, and, for example, for Arabian extra light crude, the light cut fraction may target a hydrogen content greater than 14 wt %.

[0138] In some embodiments, the mid-cut fraction, including hydrocarbons having a lower boiling point in the range of about 90°C to about 300°C and an upper boiling point in the range of about 400°C to about 600°C, may have a hydrogen content between about 11.5 wt% and 14.5 wt%. For example, it has been found that using relatively mild destructive hydrogenation conditions in the mid-cut fraction conditioning section of the process herein, a mid-cut fraction having a hydrogen content between 12 wt% and 13.5 wt% can be converted into a steam cracker feed. For example, for an Arabian light crude processed according to embodiments of the present invention, the mid-cut fraction can target a hydrogen content in the range of about 12.5 wt% to about 13.5 wt%, and, for example, for an Arabian ultra-light crude, the mid-cut fraction can target a hydrogen content in the range of about 13.0 wt% to about 14.0 wt%.

[0139] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, may have a hydrogen content of less than about 13% by weight. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the heavy cut may have a hydrogen content of less than about 12.5% ​​by weight. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the heavy cut may have a hydrogen content of less than about 12.0% by weight. For example, in an embodiment where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut may have a hydrogen content of less than 11% by weight. For example, it has been found that using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein, a heavy cut having a hydrogen content of less than about 12% by weight can be converted into a steam cracker feed. For example, for an Arabian light crude processed according to embodiments herein, the heavy cut fraction may target a hydrogen content in the range of about 10 wt % to about 11 wt %, and, for example, for an Arabian extra light crude, the heavy cut fraction may target a hydrogen content in the range of about 11 wt % to about 12 wt %.

[0140] Nitrogen content

[0141] In some embodiments, the light cut fraction may have a nitrogen content of less than 100ppm, such as less than 50ppm or less than 30ppm. In other embodiments, the light cut fraction may have a nitrogen content of less than 25ppm. In still other embodiments, the light cut fraction may have a nitrogen content of less than 20ppm, less than 15ppm, less than 10ppm, less than 5ppm, less than 3ppm, less than 1ppm or even less than 0.5ppm. In some embodiments, the medium cut fraction may have a nitrogen content greater than 1ppm and less than 1000ppm, such as from a lower limit of 1, 5, 10, 50, 100, 250 or 500ppm to an upper limit of 50, 100, 250, 500 or 1000ppm. In some embodiments, the heavy cut may have a nitrogen content greater than 10 ppm, such as greater than 25 ppm, greater than 50 ppm, greater than 100 ppm, greater than 150 ppm, greater than 200 ppm, greater than 250 ppm, greater than 500 ppm, greater than 1000 ppm, greater than 1500 ppm, greater than 2000 ppm, or greater than 2500 ppm.

[0142] Thus, in some embodiments, the light cut fraction, including hydrocarbons having a boiling point of up to about 300° C., for example, may have a nitrogen content of less than 0.01 wt % or 100 ppm; in other embodiments, such as when the light cut fraction includes hydrocarbons having a boiling point of up to about 250° C., for example, the light cut fraction may have a nitrogen content of less than 0.001 wt % or 10 ppm; in still other embodiments, such as when the light cut fraction includes hydrocarbons having a boiling point of up to about 220° C., for example, the light cut fraction may have a nitrogen content of less than 0.0001 wt % or 1 ppm. In some embodiments where the light cut fraction includes hydrocarbons having a boiling point below about 160° C., the light cut fraction may have a nitrogen content of less than about 0.00003 wt % or 0.3 ppm. Although the nitrogen content may vary for different feeds at any given fractionation temperature, it has been found that nitrogen contents, such as, for example, less than about 100 ppm, less than 10 ppm, or less than 1 ppm, can improve the conversion of light hydrocarbons in a steam pyrolysis unit without intermediate processing. For example, for an Arabian light crude processed according to embodiments herein, the light cut fraction can be targeted to have a nitrogen content of less than 1 ppm, and, for example, for an Arabian ultra-light crude, the light cut fraction can also be targeted to have a nitrogen content of less than 1 ppm.

[0143] In some embodiments, the middle cut fraction, including hydrocarbons having a lower boiling point in the range of about 90°C to about 300°C and an upper boiling point in the range of about 400°C to about 600°C, for example, may have a nitrogen content between about 10 ppm and 250 ppm. For example, it has been found that using relatively mild destructive hydrogenation conditions in the middle cut fraction conditioning section of the process herein, a middle cut fraction having a nitrogen content between 20 and 250 ppm can be converted into a steam cracker feed. For example, for an Arabian light crude processed according to embodiments of the present invention, the middle cut fraction can target a nitrogen content in the range of about 200 to about 300 ppm, and, for example, for an Arabian ultra-light crude, the middle cut fraction can target a nitrogen content in the range of about 100 to about 150 ppm.

[0144] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, may have a nitrogen content greater than about 0.001 wt% or 10 ppm. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the heavy cut may have a nitrogen content greater than about 0.005 wt% or 50 ppm. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the heavy cut may have a nitrogen content greater than about 0.01 wt% or 100 ppm. For example, in an embodiment where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut may have a nitrogen content greater than 2500 ppm. For example, it has been found that using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein, a heavy cut having a nitrogen content greater than about 100 ppm can be converted into a steam cracker feed. For example, for an Arabian light crude processed according to embodiments of the present invention, the heavy cut fraction can target a nitrogen content in the range of about 2000 to about 3000 ppm, and for example, for an Arabian extra light crude oil, the heavy cut fraction can target a nitrogen content in the range of about 1000 to about 2000.

[0145] Sulfur content

[0146] In some embodiments, the light cut fraction may have a sulfur content of less than 10000ppm, such as less than 5000ppm or less than 1000ppm. In other embodiments, the light cut fraction may have a sulfur content of less than 750ppm. In still other embodiments, the light cut fraction may have a sulfur content of less than 500ppm, less than 250ppm or even less than 100ppm. In some embodiments, the medium cut fraction may have a sulfur content greater than 500ppm and less than 10000ppm, such as from a lower limit of 500, 750, 1000, 1500, 2000, 2500 or 5000ppm to an upper limit of 1000, 2000, 5000, 10000, 15000 or 20000ppm. In some embodiments, the heavy cut may have a sulfur content greater than 1000 ppm, such as greater than 2500 ppm, greater than 5000 ppm, greater than 10000 ppm, greater than 15000 ppm, greater than 20000 ppm, greater than 25000 ppm, greater than 30000 ppm, greater than 35000 ppm, greater than 40000 ppm, greater than 45000 ppm, or greater than 50000 ppm.

[0147] Thus, in some embodiments, the light cut fraction, including hydrocarbons having a boiling point of up to about 300°C, for example, may have a sulfur content of 1 wt% or 10,000 ppm; in other embodiments, such as when the light cut fraction includes hydrocarbons having a boiling point of up to about 250°C, for example, the light cut fraction may have a sulfur content of less than 0.5 wt% or 5,000 ppm; in still other embodiments, such as when the light cut fraction includes hydrocarbons having a boiling point of up to about 220°C, for example, the light cut fraction may have a sulfur content of less than 0.1 wt% or 1,000 ppm. In some embodiments where the light cut fraction includes hydrocarbons having a boiling point of less than about 160°C, the light cut fraction may have a sulfur content of less than about 750 ppm or less than 500 ppm. While the sulfur content may vary for different feeds at any given fractionation temperature, it has been found that a sulfur content, such as, for example, less than about 600 ppm, may increase the conversion of light hydrocarbons in a steam pyrolysis unit without intermediate processing. For example, for Arabian light crude processed according to embodiments herein, the light cut fraction may target a sulfur content of less than 750 ppm, and for example, for Arabian extra light crude, the light cut fraction may also target a sulfur content of less than 500 ppm.

[0148] In some embodiments, the middle cut fraction, including hydrocarbons having a lower boiling point in the range of about 90°C to about 300°C and an upper boiling point in the range of about 400°C to about 600°C, for example, may have a sulfur content between about 1000 ppm and 20000 ppm. For example, it has been found that using relatively mild destructive hydrogenation conditions in the middle cut fraction conditioning section of the process herein, a middle cut fraction having a sulfur content between 2000 and 15000 ppm can be converted into a steam cracker feed. For example, for an Arab light crude processed according to embodiments of the present invention, the middle cut fraction can target a sulfur content in the range of about 6000 to about 12000 ppm, and, for example, for an Arab ultra-light crude, the middle cut fraction can target a sulfur content in the range of about 5000 to about 10000 ppm.

[0149] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, may have a sulfur content greater than about 0.1 wt% or 1,000 ppm. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the sulfur content of the heavy cut may be greater than about 0.5 wt% or 5,000 ppm. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the heavy cut may have a sulfur content greater than about 1 wt% or 1,0000 ppm. For example, in an embodiment where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut may have a sulfur content greater than 25,000 ppm. For example, it has been found that using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein, a heavy cut having a sulfur content greater than about 10,000 ppm can be converted into a steam cracker feed. For example, for an Arabian light crude processed according to embodiments herein, the heavy cut fraction may target a sulfur content in the range of about 30,000 to about 50,000 ppm, and, for example, for an Arabian extra light crude, the heavy cut fraction may target a sulfur content in the range of about 20,000 to about 30,000 ppm.

[0150] Viscosity

[0151] In some embodiments, the viscosity of the light cut fraction measured at 40°C according to ASTM D445 may be less than 10 cSt. In other embodiments, the light cut fraction may have a viscosity measured at 40°C of less than 5 cSt. In still other embodiments, the light cut fraction may have a viscosity measured at 40°C of less than 1 cSt. In some embodiments, the heavy cut fraction may have a viscosity greater than 10 cSt, such as greater than 20 cSt, greater than 35 cSt, greater than 50 cSt, greater than 75 cSt, or greater than 100 cSt measured at 100°C according to ASTM D445. In various embodiments, the medium cut fraction may have an intermediate viscosity between the light cut fraction and the heavy cut fraction.

[0152] Thus, in some embodiments, the light cut fraction, including hydrocarbons having a boiling point of up to about 300°C, for example, may have a viscosity measured at 40°C of less than 10 cSt; in other embodiments, such as when the light cut fraction includes hydrocarbons having a boiling point of up to about 250°C, for example, the light cut fraction may have a viscosity measured at 40°C of less than 5 cSt; in still other embodiments, such as when the light cut fraction includes hydrocarbons having a boiling point of up to about 220°C, for example, the light cut fraction may have a viscosity measured at 40°C of less than 1 cSt. In some embodiments where the light cut fraction includes hydrocarbons having a boiling point of less than about 160°C, the viscosity of the light cut fraction measured at 40°C is less than 0.75 cSt. While the viscosity may be different for different feeds at any given fractionation temperature, it has been found that low viscosity, such as less than 10 cSt, can improve the processing properties of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, for Arabian Light crude processed according to embodiments herein, the light cut fraction may target a viscosity of less than 0.55 cSt, and for example, for Arabian Extra Light crude, the light cut fraction may target a viscosity of less than 0.6 cSt.

[0153] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, may have a viscosity greater than 10 cSt measured at 100°C. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the viscosity of the heavy cut measured at 100°C may be greater than 50 cSt. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the viscosity of the heavy cut measured at 100°C may be greater than 100 cSt. For example, in an embodiment where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut may have a viscosity greater than 375 cSt. For example, it has been found that using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein, a heavy cut having a viscosity greater than about 40 cSt can be converted to a steam cracker feed.

[0154] MCRT

[0155] In some embodiments, the light cut fraction may have only a trace or undetectable amount of trace carbon residue (MCRT). In some embodiments, the medium cut fraction may have a MCRT of less than 5 wt%, such as less than 3 wt%, less than 1 wt%, or less than 0.5 wt%. In some embodiments, the heavy cut fraction may have a MCRT greater than 0.5 wt%, such as greater than 1 wt%, greater than 3 wt%, greater than 5 wt%, or greater than 10 wt%.

[0156] In some embodiments, the mid-cut fraction, including hydrocarbons having a lower boiling point in the range of about 90° C. to about 300° C. and an upper boiling point in the range of about 400° C. to about 600° C., can have a MCRT between about 0 wt % (trace or unmeasurable) and 1 wt %. For example, it has been found that using relatively mild destructive hydrogenation conditions in the mid-cut conditioning section of the process herein, a mid-cut fraction with a negligible MCRT can be converted to a steam cracker feed.

[0157] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, may have a MCRT greater than 0.5 wt%. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the heavy cut may have a MCRT greater than 1 wt%. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the heavy cut may have a MCRT greater than 5 wt%. For example, in an embodiment where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut may have a MCRT greater than 15 wt%. For example, it has been found that using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein, a heavy cut having a MCRT greater than about 1 wt% can be converted into a steam cracker feed.

[0158] Metal content

[0159] In some embodiments, the light cut fraction may have only trace or undetectable amounts of metals. In some embodiments, the medium cut fraction may have a metal content of up to 50 ppm, such as less than 30 ppm, less than 10 ppm, or less than 1 ppm. In some embodiments, the heavy cut fraction may have a metal content greater than 1 ppm, such as greater than 10 ppm, greater than 20 ppm, greater than 35 ppm, or greater than 50 ppm.

[0160] In some embodiments, the mid-cut fraction, including hydrocarbons having a lower boiling point in the range of about 90° C. to about 300° C. and an upper boiling point in the range of about 400° C. to about 600° C., can have a metal content between about 0 ppm (trace or unmeasurable) and 5 ppm, such as greater than 0 ppm to 1 ppm. For example, it has been found that using relatively mild destructive hydrogenation conditions in the mid-cut conditioning section of the process herein, a mid-cut fraction having a negligible metal content can be converted to a steam cracker feed.

[0161] In various embodiments, the heavy cut, including hydrocarbons having a boiling point greater than about 300°C, may have a metal content greater than 1 ppm. When the heavy cut includes hydrocarbons having a boiling point greater than about 350°C, the heavy cut may have a metal content greater than 10 ppm. When the heavy cut includes hydrocarbons having a boiling point greater than about 400°C, the heavy cut may have a metal content greater than 50 ppm. For example, in an embodiment where the heavy cut includes hydrocarbons having a boiling point greater than about 490°C, the heavy cut may have a metal content greater than 75 ppm. For example, it has been found that using more severe destructive hydrogenation conditions in the heavy cut conditioning section of the process herein, a heavy cut having a metal content greater than about 10 ppm can be converted into a steam cracker feed.

[0162] As an example, an Arabian light crude oil stream may be separated in an initial separation step to produce the desired light cut, medium cut, and heavy cut fractions. Without intending to be bound by theory, the light cut fraction may be a 160°C-fraction, wherein 5% of the fraction has a boiling point below 36°C, and 95% of the fraction has a boiling point below 160°C (only 5% of the fraction has a boiling point above 160°C). The light cut fraction may have an API gravity of about 65.5°, may have a BMCI of about 5.2, may have a hydrogen content of about 14.8 wt% (or 148,000 ppm), may have a nitrogen content of less than 0.00003 wt% (or 0.3 ppm), may have a sulfur content of about 0.0582 wt% (or 582 ppm), may have a viscosity at 40°C of about 0.5353 centistokes (cSt), and may have only trace amounts of MCRT and total metal content. The mid-cut fraction may be a 160°C to 490°C fraction, with 5% of the fraction having a boiling point below 173°C, and 95% of the fraction having a boiling point below 474°C (with only 5% of the fraction having a boiling point above 474°C). The mid-cut fraction may have an API gravity of about 33.6°, may have a BMCI of about 25, may have a hydrogen content of about 12.83 wt% (or 128,300 ppm), may have a nitrogen content of less than 0.0227 wt% (or 227 ppm), may have a sulfur content of about 0.937 wt% (or 9,370 ppm), may have a viscosity at 100°C of about 1.58 centistokes (cSt), may have a MCRT of 0.03 wt%, and may have only trace amounts of total metal content. The heavy cut fraction may be a 490°C+ fraction, wherein 5% of the fraction has a boiling point below 490°C, and 95% of the fraction has a boiling point below 735°C (only 5% of the fraction has a boiling point above 735°C). The heavy cut fraction may have an API gravity of about 8.2°, may have a BMCI of about 55, may have a hydrogen content of about 10.41 wt% (or 104,100 ppm), may have a nitrogen content of less than 0.2638 wt% (or 2,368 ppm), may have a sulfur content of about 3.9668 wt% (or 39,668 ppm), may have a viscosity at 100°C of about 394.3 centistokes (cSt), may have a MCRT of 17.22 wt%, and may have a total metal content of 79.04 ppm.

[0163] As another example, an Arabian ultra-light crude oil stream may be separated in an initial separation step to produce the desired light cut, medium cut, and heavy cut fractions. Without intending to be bound by theory, the light cut fraction may be a 160°C-fraction, wherein 5% of the fraction has a boiling point below 54°C, and 95% of the fraction has a boiling point below 160°C (only 5% of the fraction has a boiling point above 160°C). The light cut fraction may have an API gravity of about 62°, may have a BMCI of about 9.09, may have a hydrogen content of about 14.53 wt% (or 145,300 ppm), may have a nitrogen content of less than 0.00003 wt% (or 0.3 ppm), may have a sulfur content of about 0.0472 wt% (or 472 ppm), may have a viscosity at 40°C of about 0.58 centistokes (cSt), and may have only trace amounts of MCRT and total metal content. The mid-cut fraction may be a fraction from 160°C to 490°C, with 5% of the fraction having a boiling point below 169°C and 95% of the fraction having a boiling point below 456°C (only 5% of the fraction having a boiling point above 474°C). The mid-cut fraction may have an API gravity of about 36.1°, may have a BMCI of about 21.22, may have a hydrogen content of about 13.38 wt% (or 133,800 ppm), may have a nitrogen content of less than 0.01322 wt% (or 132.2 ppm), may have a sulfur content of about 0.9047 wt% (or 9,047 ppm), may have a viscosity at 100°C of about 1.39 centistokes (cSt), and may have only trace amounts of MCRT and total metal content. The heavy cut may be a 490°C+ fraction, with 5% of the fraction having a boiling point below 455°C, 95% of the fraction having a boiling point below 735°C (only 5% of the fraction having a boiling point above 735°C). The heavy cut may have an API gravity of about 15.1°, may have a BMCI of about 33.28, may have a hydrogen content of about 11.45 wt% (or 114,500 ppm), may have a nitrogen content of less than 0.1599 wt% (or 1,599 ppm), may have a sulfur content of about 2.683 wt% (or 26,830 ppm), may have a viscosity at 100°C of about 48.79 centistokes (cSt), may have a MCRT of 9.53 wt%, and may have a total metal content of 58.45 ppm.

[0164] While various properties are described with respect to Arabian Light and Arabian Extra Light, the foregoing also applies to other types of crude oils such as desalted oil, condensate, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, reconstituted crude oil, and asphalt-derived oils.

[0165] Embodiments herein contemplate adjusting various fractionation points and reactor conditions based on one or more of the above-mentioned properties. Methods according to embodiments herein can test the petroleum feed to be used, measuring one or more of the various properties of the incoming feed. Based on one or more properties, fractionation point, catalyst type (for moving bed reactors), pressure, temperature, space velocity, hydrogen feed rate and other variables can be adjusted to more effectively and efficiently utilize the reactor configuration, thereby maintaining the best, near-optimal or optimal adjustment of the feed and various cuts to the desired steam cracker feed.

[0166] For example, an ebullated bed receiving a heavy cut may have the capacity to process a certain amount of hydrocarbons having a sulfur content of less than 40,000 ppm. If a particular 490°C+ heavy cut has a sulfur content greater than 40,000 ppm, the capacity of the ebullated bed may be reduced. Thus, the heavy cut point may be lowered to, for example, 465°C+ to have a sulfur content less than 40,000 ppm. In addition, if a particular 160°C to 490°C medium cut has a hydrogen content greater than 14 wt%, for example, and nitrogen, sulfur, MCRT, and total metals are suitably low, the light cut may be expanded (e.g., from 160°C- to 190°C-) to send more whole crude oil directly to the steam cracker. Alternatively, if the mid cut has a lower hydrogen content, for example, and / or is inappropriately low in sulfur, nitrogen, MCRT, and / or total metals, the light cut may be reduced (e.g., from 160°C- to 130°C-) so that additional mid cut may be processed in the fixed bed conditioning stage.

[0167] The process herein provides the flexibility needed to maintain high conversion rates of various feedstocks to petrochemicals. Those skilled in the art who know that the type of hydrocarbon components, sulfur content, nitrogen content, etc., can vary greatly between various feed types (Arabian Super Light Crude Oil is very different from West Texas Intermediate Crude Oil) and that feeds from various resources may be processed at a given plant in any given day, week, month, or year will recognize the benefits of the process herein to flexibly produce petrochemicals from many different feedstocks.

[0168] As described above, embodiments herein can be used to convert crude oil (including heavier fractions of whole crude oil) into high-value petrochemical products and can minimize the amount sent to the fuel oil pool, which increases profitability. The fuel oil pool can also be upgraded to low-sulfur, IMO 2020-compliant fuel oil, thereby further increasing the value of the product.

[0169] Embodiments herein may initially separate a broad boiling range hydrocarbon feedstock into a light cut, a medium cut, and a heavy cut. Separating the feedstock into various cuts may allow for advantageous processing conditions, reactor sizing, and other factors not available in the flowsheet that teach those skilled in the art to hydrotreat or otherwise condition the entire whole crude oil or even its heavy portion (such as a single 200°+ cut). The ability to prepare a steam cracker feed from separate medium and heavy cuts under reaction conditions more suitable for the hydrocarbons in these respective cuts advantageously provides for enhanced production of petrochemical products as described herein, and provides one or more of the following advantages: extended life of the catalyst used to condition the medium cut; economical reactor sizing for each respective cut; matching of medium cut conditioning to steam cracker run time; the ability to condition the respective cuts at preferred conditions; the ability to customize the catalyst for the preferred conditioning of the respective cuts; and other advantages that those skilled in the art may readily foresee based on the disclosure herein.

[0170] As mentioned above, embodiments herein may relate to one or more of the following embodiments:

[0171] Embodiment 1: A method for converting whole crude oil and other wide boiling point hydrocarbon streams to produce olefins and / or aromatics, the method comprising:

[0172] separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0173] hydrocracking the high boiling residual fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0174] destructively hydrogenating and hydrocracking the mid-boiling fraction and the residual hydrocracked fraction to produce a hydrotreated and hydrocracked effluent;

[0175] The hydrotreated and hydrocracked effluent and the low boiling fraction are fed to at least one of a steam cracker and an aromatics complex to convert hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0176] Embodiment 2: The method according to embodiment 1, wherein the low boiling point fraction has two or more of the following properties:

[0177] 95% boiling point temperature in the range of about 130°C to about 200°C;

[0178] a hydrogen content of at least 14% by weight;

[0179] BMCI less than 5;

[0180] API gravity greater than 40°;

[0181] Sulfur content less than 1000 ppm;

[0182] Nitrogen content less than 10ppm;

[0183] Viscosity measured at 40°C of less than 1 cSt;

[0184] Less than 1 wt% MCRT; and

[0185] Less than 1ppm total metals.

[0186] Embodiment 3: The method according to embodiment 1 or embodiment 2, wherein the medium boiling point fraction has two or more of the following properties:

[0187] a 5% boiling point temperature in the range of about 130°C to about 200°C;

[0188] 95% boiling point temperature in the range of about 400°C to about 600°C;

[0189] a hydrogen content in the range of about 12 wt % to about 14 wt %;

[0190] a BMCI ranging from about 5 to less than 50;

[0191] API gravity in the range of about 10° to about 40°;

[0192] a sulfur content in the range of about 1000 ppm to about 10,000 ppm;

[0193] a nitrogen content in the range of about 1 ppm to about 100 ppm;

[0194] Viscosity measured at 40°C greater than 1 cSt;

[0195] Less than 5 wt% MCRT; and

[0196] Less than 50 ppm total metals.

[0197] Embodiment 4: The method according to any one of embodiments 1-3, wherein the high boiling point fraction has two or more of the following properties:

[0198] a 5% boiling point temperature in the range of about 400°C to about 600°C;

[0199] A hydrogen content of less than 12% by weight;

[0200] BMCI greater than 50;

[0201] API gravity less than 10°;

[0202] Sulfur content greater than 10,000 ppm;

[0203] Nitrogen content greater than 100 ppm;

[0204] A viscosity greater than 100 cSt measured at 100°C;

[0205] Greater than 5 wt% MCRT; and

[0206] Greater than 50 ppm total metals.

[0207] Embodiment 5: The method according to any one of embodiments 1-4, wherein:

[0208] The residue hydrocracked fraction has a 95% boiling point temperature in the range of about 400°C to about 560°C.

[0209] Embodiment 6: The process according to any one of Embodiments 1-5, wherein the high boiling residual fraction has a 5% boiling temperature greater than about 545°C.

[0210] Embodiment 7: A method according to any one of Embodiments 1-6, wherein hydrocracking the high boiling point residual fraction comprises contacting the high boiling point residual fraction and the pyrolysis oil with an extrudate or slurry catalyst under conditions sufficient to convert at least a portion of the high boiling point residual fraction hydrocarbons into lighter hydrocarbons.

[0211] Embodiment 8: The method according to any one of Embodiments 1-7, wherein hydrocracking the high boiling point residual fraction comprises converting more than 70% of hydrocarbons having a boiling point greater than 565°C.

[0212] Embodiment 9: A method according to any one of embodiments 1 to 8, wherein the destructive hydrogenation and hydrocracking of the middle boiling point fraction and the residue hydrocracking fraction includes destructive hydrogenation of the middle boiling point fraction and the residue hydrocracking fraction in a common destructive hydrogenation unit, and hydrocracking the effluent from the common destructive hydrogenation unit in the hydrocracking unit.

[0213] Embodiment 10: The method according to any one of embodiments 1 to 9, wherein destructively hydrogenating and hydrocracking the middle boiling point fraction and the residue hydrocracking fraction comprises:

[0214] Destructively hydrogenating the medium-boiling fraction in a first destructive hydrogenation unit;

[0215] destructively hydrogenating the residue hydrocracked fraction in a second destructive hydrogenation unit; and

[0216] The effluents from the first destructive hydroprocessing unit and the second destructive hydroprocessing unit are combined and the combined effluents are hydrocracked in a hydrocracking unit.

[0217] Embodiment 11: The method according to Embodiment 10, further comprising destructively hydrogenating the residue hydrocracked fraction in the first destructive hydrogenation unit during a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

[0218] Embodiment 12: The method according to any one of Embodiments 1-11, further comprising hydrodesulfurizing the fuel oil fraction to produce ultra-low sulfur fuel oil.

[0219] Embodiment 13: A method according to any of Embodiments 1-12, wherein the total petrochemical product production is at least 65 weight percent based on the total amount of olefins and aromatics produced compared to the total feedstock feed rate, and the total feedstock feed rate includes whole crude oil and any additional feeds.

[0220] Embodiment 14: The method according to any of Embodiments 1-13, wherein feeding the hydrotreated and hydrocracked effluent and the low boiling fraction to at least one of a steam cracker and an aromatics complex comprises:

[0221] separating the hydrotreated and hydrocracked effluent and the low boiling point fraction into a separator to produce a light naphtha fraction and a heavy naphtha fraction;

[0222] feeding the light naphtha fraction to a steam cracker; and

[0223] The heavy naphtha fraction is fed to the aromatics complex.

[0224] Embodiment 15: The method according to any of Embodiments 1-14, comprising feeding the hydrotreated and hydrocracked effluent and the low boiling fraction directly to a steam cracker.

[0225] Embodiment 16: A method for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the method comprising:

[0226] separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0227] hydrocracking the high boiling point residual fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0228] destructively hydrogenating the mid-boiling fraction to form a first destructively hydrogenated effluent;

[0229] destructively hydrogenating the residual hydrocracked fraction to produce a second destructively hydrogenated effluent;

[0230] combining the first destructive hydroprocessing effluent and the second destructive hydroprocessing effluent to form a mixture and hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent;

[0231] The hydrotreated and hydrocracked effluent and the low boiling fraction are fed to at least one of a steam cracker and an aromatics complex to convert hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0232] Embodiment 17: A method for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the method comprising:

[0233] separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0234] hydrocracking the high boiling point residual fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0235] destructively hydrogenating the mid-boiling fraction to form a first destructively hydrogenated effluent;

[0236] destructively hydrogenating the residual hydrocracked fraction to produce a second destructively hydrogenated effluent;

[0237] combining the first destructive hydrogenation effluent and the second destructive hydrogenation effluent to form a mixture and hydrocracking the mixture to form a hydrotreated and hydrocracked effluent;

[0238] The hydrotreated and hydrocracked effluent and the low boiling fraction are fed to at least one of a steam cracker and an aromatics complex to convert hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0239] Embodiment 18: The method according to Embodiment 17, wherein the low boiling point fraction has two or more of the following properties:

[0240] 95% boiling point temperature in the range of about 130°C to about 200°C;

[0241] a hydrogen content of at least 14% by weight;

[0242] BMCI less than 5;

[0243] API gravity greater than 40°;

[0244] Sulfur content less than 1000 ppm;

[0245] Nitrogen content less than 10ppm;

[0246] Viscosity measured at 40°C of less than 1 cSt;

[0247] Less than 1 wt% MCRT; and

[0248] Less than 1ppm total metals.

[0249] Embodiment 19: The method according to Embodiment 17 or Embodiment 18, wherein the medium boiling point fraction has two or more of the following properties:

[0250] a 5% boiling point temperature in the range of about 130°C to about 200°C;

[0251] 95% boiling point temperature in the range of about 400°C to about 600°C;

[0252] a hydrogen content in the range of about 12 wt % to about 14 wt %;

[0253] a BMCI ranging from about 5 to less than 50;

[0254] API gravity in the range of about 10° to about 40°;

[0255] a sulfur content in the range of about 1000 ppm to about 10,000 ppm;

[0256] a nitrogen content in the range of about 1 ppm to about 100 ppm;

[0257] Viscosity measured at 40°C greater than 1 cSt;

[0258] Less than 5 wt% MCRT; and

[0259] Less than 50 ppm total metals.

[0260] Embodiment 20: The method according to any one of embodiments 17-19, wherein the high boiling point fraction has two or more of the following properties:

[0261] a 5% boiling point temperature in the range of about 400°C to about 600°C;

[0262] A hydrogen content of less than 12% by weight;

[0263] BMCI greater than 50;

[0264] API gravity less than 10°;

[0265] Sulfur content greater than 10,000 ppm;

[0266] Nitrogen content greater than 100 ppm;

[0267] A viscosity greater than 100 cSt measured at 100°C;

[0268] Greater than 5 wt% MCRT; and

[0269] Greater than 50 ppm total metals.

[0270] Embodiment 21: The method according to any one of Embodiments 17-20, wherein:

[0271] The residue hydrocracked fraction has a 95% boiling point temperature in the range of about 400°C to about 560°C.

[0272] Embodiment 22: The process according to any one of Embodiments 17-21, wherein the high boiling residual fraction has a 5% boiling temperature greater than about 545°C.

[0273] Embodiment 23: A method according to any one of Embodiments 17-22, wherein hydrocracking the high boiling point residual fraction comprises contacting the high boiling point residual fraction and the pyrolysis oil with an extrudate or slurry catalyst under conditions sufficient to convert at least a portion of the high boiling point residual fraction hydrocarbons to lighter hydrocarbons.

[0274] Embodiment 24: The method according to any of Embodiments 17-23, wherein hydrocracking the high boiling point residual fraction comprises converting more than 70% of hydrocarbons having a boiling point greater than 565°C.

[0275] Embodiment 25: The method according to any one of Embodiments 17 to 24, wherein destructively hydrogenating the medium boiling point fraction and destructively hydrogenating the residue hydrocracking fraction comprises destructively hydrogenating the medium boiling point fraction and the residue hydrocracking fraction in a common destructive hydrogenation unit.

[0276] Embodiment 26: The method according to any one of embodiments 17-25, wherein destructively hydrogenating the middle boiling point fraction and destructively hydrogenating the residue hydrocracking fraction comprises:

[0277] Destructively hydrogenating the medium-boiling fraction in a first destructive hydrogenation unit;

[0278] destructively hydrogenating the residue hydrocracked fraction in a second destructive hydrogenation unit; and

[0279] The effluents from the first destructive hydrogenation unit and the second destructive hydrogenation unit are combined.

[0280] Embodiment 27: The method according to Embodiment 26, further comprising destructively hydrogenating the residue hydrocracked fraction in the first destructive hydrogenation unit during a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

[0281] Embodiment 28: The method according to any one of Embodiments 17-27, further comprising hydrodesulfurizing the fuel oil fraction to produce ultra-low sulfur fuel oil.

[0282] Embodiment 29: A method according to any of Embodiments 17-28, wherein the total petrochemical product production is at least 65 weight percent based on the total amount of olefins and aromatics produced compared to the total feedstock feed rate, and the total feedstock feed rate includes whole crude oil and any additional feeds.

[0283] Embodiment 30: The method according to any one of Embodiments 17-29, wherein feeding the hydrotreated and hydrocracked effluent and the low boiling fraction to at least one of a steam cracker and an aromatics complex comprises:

[0284] separating the hydrotreated and hydrocracked effluent and the low boiling point fraction into a separator to produce a light naphtha fraction and a heavy naphtha fraction;

[0285] feeding the light naphtha fraction to a steam cracker; and

[0286] The heavy naphtha fraction is fed to the aromatics complex.

[0287] Embodiment 31: The method according to any of Embodiments 17-30, comprising feeding the hydrotreated and hydrocracked effluent and the low boiling point fraction directly to a steam cracker.

[0288] Embodiment 32: A method for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the method comprising:

[0289] The whole crude oil is separated into at least a first fraction, a second fraction and a third fraction, wherein:

[0290] The first fraction has a BMCI of less than 20 and a hydrogen content of greater than 13 wt %;

[0291] The third portion has a BMCI greater than 30 and a hydrogen content less than 13 wt %;

[0292] and the second fraction has a BMCI and a hydrogen content between the corresponding values ​​of the first fraction and the third fraction;

[0293] hydrocracking the third fraction to form a hydrocracked effluent, and separating the hydrocracked effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0294] destructively hydrogenating and hydrocracking the second fraction and the residual hydrocracked fraction to produce a hydrotreated and hydrocracked effluent;

[0295] The hydrotreated and hydrocracked effluent and the first fraction are fed to at least one of a steam cracker and an aromatics complex to convert hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0296] Embodiment 33: A method for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the method comprising:

[0297] separating the whole crude oil into at least a high boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0298] hydrocracking the high boiling residual fraction and the heavy fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0299] destructively hydrogenating and hydrocracking the mid-boiling fraction and the residual hydrocracked fraction to produce a hydrotreated and hydrocracked effluent;

[0300] separating the hydrotreated and hydrocracked effluent to produce a light fraction and a heavy fraction;

[0301] feeding the light fraction and the low boiling point fraction to a separator to recover a light naphtha fraction and a heavy naphtha fraction;

[0302] feeding the light naphtha fraction to a steam cracker to convert the light naphtha fraction into petrochemical products including ethylene, propylene, and butenes; and

[0303] The heavy naphtha fraction is fed to an aromatics complex to convert the hydrocarbons therein into petrochemical products including benzene, toluene and xylenes.

[0304] Embodiment 34: The method according to Embodiment 33, further comprising mixing the slurry oil with the high boiling point residual fraction before hydrocracking the high boiling point residual fraction.

[0305] Embodiment 35: The method according to Embodiment 33 or 34, further comprising mixing light cycle oil with the mid-boiling fraction prior to destructively hydrogenating and hydrocracking the mid-boiling fraction.

[0306] Embodiment 36: A method for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the method comprising:

[0307] The whole crude oil is separated into a low boiling point fraction and a remaining fraction in a first separation device;

[0308] separating the remaining fraction into a medium-boiling fraction and a high-boiling residual fraction in a second separation device;

[0309] hydrocracking the high boiling residual fraction to form a hydrocracking effluent;

[0310] separating the hydrocracking effluent to produce a first converted fraction and a first heavy fraction;

[0311] hydrocracking the first heavy fraction to form a second hydrocracking effluent;

[0312] separating the second hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0313] destructively hydrogenating the mid-boiling fraction, the first converted fraction, and the residue hydrocracked fraction to produce a hydroprocessing effluent;

[0314] separating the hydroprocessing effluent to produce a light fraction including hydrogen and hydrogen sulfide, a sour water stream, and a hydroprocessed fraction;

[0315] hydrocracking the hydrotreated fraction and the pyrolysis oil fraction to produce a second hydrocracking effluent;

[0316] separating the second hydrocracking effluent to recover a light fraction including hydrogen and a hydrocracked fraction;

[0317] feeding the light fraction and the hydrocracked fraction to a separator to recover a light naphtha fraction and a heavy naphtha fraction;

[0318] feeding the light naphtha fraction to a steam cracker to convert the light naphtha fraction into petrochemical products including ethylene, propylene, and butenes; and

[0319] The heavy naphtha fraction is fed to an aromatics complex to convert the hydrocarbons therein into petrochemical products including benzene, toluene and xylenes.

[0320] Embodiment 37: An embodiment according to any one of embodiments 1 to 36, wherein the low boiling point fraction or the first fraction suitably has two or more of the following properties:

[0321] 95% boiling point temperature in the range of about 90°C to about 300°C;

[0322] a hydrogen content of at least 13% by weight;

[0323] BMCI less than 20;

[0324] API gravity greater than 10°;

[0325] A sulfur content of less than 1% by weight;

[0326] Nitrogen content less than 100 ppm;

[0327] A viscosity measured at 40°C of less than 10 cSt;

[0328] Less than 1 wt% MCRT; and

[0329] Less than 1ppm total metals.

[0330] Embodiment 38, according to any one of embodiments 1-36, wherein the low boiling point fraction or the first fraction suitably has two or more of the following properties:

[0331] 95% boiling point temperature in the range of about 110°C to about 250°C;

[0332] a hydrogen content of at least 13.5 wt. %;

[0333] BMCI less than 10;

[0334] API gravity greater than 20°;

[0335] Sulfur content less than 5000ppm;

[0336] Nitrogen content less than 10ppm;

[0337] A viscosity measured at 40°C of less than 5 cSt;

[0338] Less than 1 wt% MCRT; and

[0339] Less than 1ppm total metals.

[0340] Embodiment 39: An embodiment according to any one of embodiments 1 to 36, wherein the low boiling point fraction or the first fraction suitably has two or more of the following properties:

[0341] 95% boiling point temperature in the range of about 130°C to about 200°C;

[0342] a hydrogen content of at least 14% by weight;

[0343] BMCI less than 5;

[0344] API gravity greater than 40°;

[0345] Sulfur content less than 1000 ppm;

[0346] Nitrogen content less than 1ppm;

[0347] Viscosity measured at 40°C of less than 1 cSt;

[0348] Less than 1 wt% MCRT; and

[0349] Less than 1ppm total metals.

[0350] Embodiment 40: An embodiment according to any one of embodiments 1 to 36, wherein the medium boiling fraction or the second fraction suitably has two or more of the following properties:

[0351] a 5% boiling point temperature in the range of about 130°C to about 200°C;

[0352] 95% boiling point temperature in the range of about 400°C to about 600°C;

[0353] a hydrogen content in the range of about 12 wt % to about 14 wt %;

[0354] a BMCI ranging from about 5 to less than 50;

[0355] API gravity in the range of about 10° to about 40°;

[0356] a sulfur content in the range of about 1000 ppm to about 10,000 ppm;

[0357] a nitrogen content in the range of about 1 ppm to about 100 ppm;

[0358] Viscosity measured at 40°C greater than 1 cSt;

[0359] Less than 5 wt% MCRT; and

[0360] Less than 50 ppm total metals.

[0361] Embodiment 41: An embodiment according to any one of embodiments 1 to 36, wherein the medium boiling fraction or the second fraction suitably has two or more of the following properties:

[0362] 5% boiling point temperature in the range of about 110°C to about 250°C;

[0363] 95% boiling point temperature in the range of about 350°C to about 650°C;

[0364] a hydrogen content in the range of about 12 wt % to about 14 wt %;

[0365] a BMCI ranging from about 5 to less than 50;

[0366] API gravity in the range of about 10° to about 40°;

[0367] a sulfur content in the range of about 1000 ppm to about 10,000 ppm;

[0368] a nitrogen content in the range of about 1 ppm to about 100 ppm;

[0369] Viscosity measured at 40°C greater than 1 cSt;

[0370] Less than 5 wt% MCRT; and

[0371] Less than 50 ppm total metals.

[0372] Embodiment 42: An embodiment according to any one of embodiments 1 to 36, wherein the medium boiling fraction or the second fraction suitably has two or more of the following properties:

[0373] a 5% boiling point temperature in the range of about 90°C to about 300°C;

[0374] 95% boiling point temperature in the range of about 300°C to about 700°C;

[0375] a hydrogen content in the range of about 12 wt % to about 14 wt %;

[0376] a BMCI ranging from about 5 to less than 50;

[0377] API gravity in the range of about 10° to about 40°;

[0378] a sulfur content in the range of about 1000 ppm to about 10,000 ppm;

[0379] a nitrogen content in the range of about 1 ppm to about 100 ppm;

[0380] Viscosity measured at 40°C greater than 1 cSt;

[0381] Less than 5 wt% MCRT; and

[0382] Less than 50 ppm total metals.

[0383] Embodiment 43: An embodiment according to any one of embodiments 1 to 36, wherein the high boiling point fraction or the third fraction suitably has two or more of the following properties:

[0384] 5% boiling point temperature in the range of about 300°C to about 700°C;

[0385] A hydrogen content of less than 13% by weight;

[0386] BMCI greater than 30;

[0387] API gravity less than 40°;

[0388] Sulfur content greater than 1000 ppm;

[0389] Nitrogen content greater than 10 ppm;

[0390] A viscosity measured at 100°C greater than 10 cSt;

[0391] Greater than 0.5 wt% MCRT; and

[0392] Greater than 1 ppm total metals.

[0393] Embodiment 44: An embodiment according to any one of embodiments 1 to 36, wherein the high boiling point fraction or the third fraction suitably has two or more of the following properties:

[0394] a 5% boiling point temperature in the range of about 350°C to about 650°C;

[0395] A hydrogen content of less than 12.5% ​​by weight;

[0396] BMCI greater than 40;

[0397] API gravity less than 20°;

[0398] Sulfur content greater than 5000 ppm;

[0399] Nitrogen content greater than 50 ppm;

[0400] A viscosity measured at 100°C greater than 50 cSt;

[0401] Greater than 1 wt% MCRT; and

[0402] Greater than 10 ppm total metals.

[0403] Embodiment 45: An embodiment according to any one of embodiments 1 to 36, wherein the high boiling point fraction or the third fraction suitably has two or more of the following properties:

[0404] a 5% boiling point temperature in the range of about 400°C to about 600°C;

[0405] A hydrogen content of less than 12% by weight;

[0406] BMCI greater than 50;

[0407] API gravity less than 10°;

[0408] Sulfur content greater than 10,000 ppm;

[0409] Nitrogen content greater than 100 ppm;

[0410] A viscosity greater than 100 cSt measured at 100°C;

[0411] Greater than 5 wt% MCRT; and

[0412] Greater than 50 ppm total metals.

[0413] Embodiment 46: A system for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the system comprising:

[0414] A separation system for separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0415] a hydrocracking reaction zone for hydrocracking the high boiling residual fraction to form a hydrocracking effluent, and a separation system for separating the hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0416] a reaction zone for destructively hydrogenating and hydrocracking the mid-boiling fraction and the residual hydrocracked fraction to produce a hydrotreated and hydrocracked effluent;

[0417] Steam cracker and optional aromatics complex for converting the hydrotreated and hydrocracked effluents and low boiling fractions into petrochemicals and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0418] Embodiment 47: The system of Embodiment 46, wherein the hydrocracking reaction zone for hydrocracking the high boiling point residual fraction comprises a slurry reactor or an ebullated bed reactor.

[0419] Embodiment 48: A system according to any of Embodiments 46-47, wherein the reaction zone for destructive hydrogenation and hydrocracking of the middle boiling point fraction and the residue hydrocracking fraction includes a common destructive hydrogenation unit for destructive hydrogenation of the middle boiling point fraction and the residue hydrocracking fraction, and a hydrocracking reactor for hydrocracking the effluent from the common destructive hydrogenation unit.

[0420] Embodiment 49: The system according to any one of Embodiments 46-48, wherein the reaction zone for destructively hydrogenating and hydrocracking the middle boiling point fraction and the residual oil hydrocracking fraction comprises:

[0421] a first destructive hydrogenation unit for destructively hydrogenating the medium-boiling fraction;

[0422] a second destructive hydrogenation unit for destructively hydrogenating the residue hydrocracked fraction; and

[0423] A mixer for combining the effluents from the first destructive hydrogenation unit and the second destructive hydrogenation unit.

[0424] Embodiment 50: The system according to Embodiment 49, further comprising a flow guide for transferring the residue hydrocracking fraction to the first destructive hydrogenation unit during a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

[0425] Embodiment 51: The system of any of Embodiments 46-50, further comprising a reactor for hydrodesulfurizing the fuel oil fraction to produce ultra low sulfur fuel oil.

[0426] Embodiment 52: A system according to any one of embodiments 46-51, further comprising:

[0427] a separator for separating the hydrotreated and hydrocracked effluent from the low boiling point fraction to produce a light naphtha fraction and a heavy naphtha fraction;

[0428] a flow line for feeding the light naphtha fraction to a steam cracker unit; and

[0429] Flow line for feeding the heavy naphtha fraction to the aromatics complex.

[0430] Embodiment 53: A system for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the method comprising:

[0431] A separation system for separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0432] a hydrocracker for hydrocracking the high boiling point residual fraction to form a hydrocracking effluent, and a separator for separating the hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0433] a first conditioning unit for destructively hydrogenating the medium boiling fraction to form a first destructively hydrogenated effluent;

[0434] a second conditioning unit for destructively hydrogenating the residual hydrocracked fraction to produce a second destructively hydrogenated effluent;

[0435] a mixer for mixing the first destructive hydroprocessing effluent and the second destructive hydroprocessing effluent to form a mixture, and a hydrocracker for hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent;

[0436] A flow line for feeding the hydrotreated and hydrocracked effluent and the low boiling fraction to at least one of a steam cracker and an aromatics complex to convert the hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0437] Embodiment 54: A system for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the system comprising:

[0438] A separation system for separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0439] a hydrocracker for hydrocracking the high boiling point residual fraction to form a hydrocracked effluent and separating the hydrocracked effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0440] a first conditioning reactor for destructively hydrogenating the medium boiling point fraction to form a first destructively hydrogenated effluent;

[0441] a second conditioning reactor for destructively hydrogenating the residual hydrocracked fraction to produce a second destructively hydrogenated effluent;

[0442] a mixer for mixing the first destructive hydroprocessing effluent and the second destructive hydroprocessing effluent to form a mixture, and a hydrocracker for hydrocracking the mixture to form a hydrotreated and hydrocracked effluent;

[0443] One or more flow lines for feeding the hydrotreated and hydrocracked effluent and low boiling fractions to at least one of a steam cracker and an aromatics complex to convert hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0444] Embodiment 55: The system of Embodiment 54, wherein the hydrocracker for hydrocracking the high boiling point residual fraction comprises a slurry reactor or an ebullated bed reactor.

[0445] Embodiment 56: The system of Embodiment 55, further comprising a flow line for transferring the residue hydrocracked fraction to the first destructive hydroprocessing unit during a period of time when the catalyst in the second destructive hydroprocessing unit is replaced.

[0446] Embodiment 57: The system of any of Embodiments 54-56, further comprising a reactor for hydrodesulfurizing the fuel oil fraction to produce ultra low sulfur fuel oil.

[0447] Embodiment 58: A system according to any one of embodiments 54-57, comprising:

[0448] a separator for separating the hydrotreated and hydrocracked effluent and the low boiling point fraction to produce a light naphtha fraction and a heavy naphtha fraction;

[0449] a flow line for feeding the light naphtha fraction to a steam cracker unit; and

[0450] Flow line for feeding the heavy naphtha fraction to the aromatics complex.

[0451] Embodiment 59: A system for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the system comprising:

[0452] A separation system for separating whole crude oil into at least a first fraction, a second fraction and a third fraction, wherein:

[0453] The first fraction has a BMCI of less than 20 and a hydrogen content of greater than 13 wt %;

[0454] a third fraction having a BMCI greater than 30 and a hydrogen content less than 13 wt %;

[0455] and the second fraction has a BMCI and a hydrogen content between the corresponding values ​​of the first fraction and the third fraction;

[0456] a hydrocracker for hydrocracking the third fraction to form a hydrocracked effluent, and a separator for separating the hydrocracked effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0457] a conditioning zone for destructively hydrogenating and hydrocracking the second fraction and the resid hydrocracked fraction to produce a hydrotreated and hydrocracked effluent;

[0458] One or more flow lines for feeding the hydrotreated and hydrocracked effluent and the first fraction to at least one of a steam cracker and an aromatics complex to convert hydrocarbons therein into petrochemical products and pyrolysis oil and / or ultra low sulfur fuel oil (ULSFO).

[0459] Embodiment 60: A system for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the system comprising:

[0460] A separation system for separating the whole crude oil into at least a low boiling point fraction, a medium boiling point fraction and a high boiling point residual fraction;

[0461] a hydrocracker for hydrocracking the high boiling residual fraction and the heavy fraction to form a hydrocracking effluent, and a separator for separating the hydrocracking effluent to produce a residue hydrocracked fraction and a fuel oil fraction;

[0462] a conditioning zone for destructively hydrogenating and hydrocracking the mid-boiling fraction and the residual hydrocracked fraction to produce a hydrotreated and hydrocracked effluent;

[0463] a separator for separating the hydrotreated and hydrocracking effluents to produce light and heavy fractions;

[0464] a separator for separating the light fraction and the low boiling point fraction to recover the light naphtha fraction and the heavy naphtha fraction;

[0465] a steam cracker for converting the light naphtha fraction into petrochemical products including ethylene, propylene and butenes; and

[0466] Aromatics complex to convert heavy naphtha into petrochemical products including benzene, toluene and xylenes.

[0467] Embodiment 61: The system according to Embodiment 60, further comprising a mixer for mixing the slurry oil with the high boiling point residual fraction upstream of the hydrocracker for hydrocracking the high boiling point residual fraction.

[0468] Embodiment 62: The system of Embodiment 60 or 61, further comprising a mixer for mixing the light cycle oil with the mid-boiling fraction.

[0469] Embodiment 63: A system for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the system comprising:

[0470] a separation system for separating the whole crude oil into a low boiling point fraction and a remaining fraction in a first separation device;

[0471] a separation system for separating the remaining fraction into a medium boiling point fraction and a high boiling point residual fraction in a second separation device;

[0472] a hydrocracker for hydrocracking the high boiling residual fraction to form a hydrocracking effluent;

[0473] a separator for separating the hydrocracking effluent to produce a first converted fraction and a first heavy fraction;

[0474] a hydrocracker for hydrocracking the first heavy fraction to form a second hydrocracking effluent;

[0475] a separator for separating the second hydrocracking effluent to produce a residue hydrocracking fraction and a fuel oil fraction;

[0476] a conditioning reactor for destructively hydrogenating the medium boiling fraction, the first conversion fraction, and the residue hydrocracking fraction to produce a hydroprocessing effluent;

[0477] a separator for separating the hydroprocessing effluent to produce a light fraction including hydrogen and hydrogen sulfide, a sour water stream, and a hydroprocessed fraction;

[0478] a hydrocracker for hydrocracking the hydrotreated fraction and the pyrolysis oil fraction to produce a second hydrocracking effluent;

[0479] a separator for separating the second hydrocracking effluent to recover a light fraction including hydrogen and a hydrocracked fraction;

[0480] a separator for separating the light fraction and the hydrocracked fraction to recover a light naphtha fraction and a heavy naphtha fraction;

[0481] a steam cracker for converting the light naphtha fraction into petrochemical products including ethylene, propylene and butenes; and

[0482] Aromatics complex for converting heavy naphtha fractions into petrochemical products including benzene, toluene and xylenes.

[0483] Embodiment 64: A system according to any one of Embodiments 46-63, wherein the separation system for separating whole crude oil comprises:

[0484] a heater for heating the whole crude oil to produce heated whole crude oil;

[0485] a separator for separating the heated whole crude oil to recover a first fraction and a remaining fraction;

[0486] a heater for heating the remaining fraction to produce a heated remaining fraction;

[0487] A hot hydrogen stripper is used to separate the heated remaining fraction to produce an overhead comprising hydrogen and a second fraction and a bottoms comprising a third fraction.

[0488] Embodiment 65: The system of Embodiment 64, further comprising a heat exchanger for exchanging heat between the remaining fraction and the overhead fraction.

[0489] While the present disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the present disclosure.

Claims

1. A process for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the process comprising: The whole crude oil (1, 10, 100) or a hydrocarbon stream with a final boiling point greater than 500° C. is separated into at least a low boiling point fraction (5, 14), a medium boiling point fraction (9, 20) and a high boiling point residual fraction (15, 28); hydrocracking the high boiling point residual fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residue hydrocracking fraction (21) and a fuel oil fraction (19); Destructively hydrogenating the middle boiling point fraction to form a first destructively hydrogenated effluent (31); destructively hydrogenating the residual oil hydrocracking fraction to produce a second destructively hydrogenated effluent (33); combining the first destructively hydrogenated effluent and the second destructively hydrogenated effluent to form a mixture and hydrocracking the mixture to form a hydrotreated and hydrocracked effluent (13); The hydrotreated and hydrocracked effluent and the low boiling fraction are fed to at least one of a steam cracker and an aromatics complex to convert hydrocarbons therein into petrochemical products (23) and pyrolysis oil (25, 44) and / or ultra low sulfur fuel oil (ULSFO) (32).

2. The method according to claim 1, wherein the low boiling point fraction has two or more of the following properties: 95% boiling point temperature in the range of about 130°C to about 200°C; a hydrogen content of at least 14% by weight; BMCI less than 5; API gravity greater than 40°; Sulfur content less than 1000 ppm; Nitrogen content less than 10ppm; Viscosity measured at 40°C of less than 1 cSt; Less than 1% by weight of MCRT; and Less than 1ppm total metals.

3. The method according to claim 1, wherein the middle boiling point fraction has two or more of the following properties: a 5% boiling point temperature in the range of about 130°C to about 200°C; 95% boiling point temperature in the range of about 400°C to about 600°C; a hydrogen content in the range of about 12 wt % to about 14 wt %; a BMCI ranging from about 5 to less than 50; API gravity in the range of about 10° to about 40°; a sulfur content in the range of about 1000 ppm to about 10,000 ppm; a nitrogen content in the range of about 1 ppm to about 100 ppm; Viscosity measured at 40°C greater than 1 cSt; Less than 5% by weight of MCRT; and Less than 50 ppm total metals.

4. The method according to claim 1, wherein the high boiling residual fraction has two or more of the following properties: 5% boiling point temperature in the range of about 400°C to about 600°C; A hydrogen content of less than 12% by weight; BMCI greater than 50; API gravity less than 10°; Sulfur content greater than 10,000 ppm; Nitrogen content greater than 100 ppm; A viscosity greater than 100 cSt measured at 100°C; Greater than 5 wt% MCRT; and Greater than 50 ppm total metals.

5. The method according to claim 1, wherein: The residue hydrocracked fraction has a 95% boiling point temperature in the range of about 400°C to about 560°C.

6. The process of claim 1, wherein the high boiling residual fraction has a 5% boiling temperature greater than about 545°C.

7. The method of claim 1, wherein hydrocracking the high boiling residual fraction comprises contacting the high boiling residual fraction and the pyrolysis oil with a catalyst under conditions sufficient to convert at least a portion of the high boiling residual fraction hydrocarbons into lighter hydrocarbons.

8. The method of claim 1, wherein hydrocracking the high boiling residual fraction comprises converting more than 70% of hydrocarbons having a boiling point greater than 565°C.

9. The method of claim 1, wherein destructively hydrogenating the middle boiling point fraction and destructively hydrogenating the resid hydrocracking fraction comprises destructively hydrogenating the middle boiling point fraction and the resid hydrocracking fraction in a common destructive hydrogenation unit.

10. The method according to claim 1, wherein destructively hydrogenating the middle boiling point fraction and destructively hydrogenating the residual oil hydrocracking fraction comprises: Destructively hydrogenating the medium boiling point fraction (9) in a first destructive hydrogenation unit (27); Destructively hydrogenating the residual oil hydrocracked fraction (21) in a second destructive hydrogenation unit (29); as well as The effluents from the first destructive hydrogenation unit and the second destructive hydrogenation unit are combined.

11. The method of claim 10, further comprising destructively hydrogenating the resid hydrocracked fraction in the first destructive hydrogenation unit during a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

12. The method of claim 1, further comprising hydrodesulfurizing the fuel oil fraction (64) to produce ultra low sulfur fuel oil (32).

13. The process of claim 1 wherein the total petrochemical production rate is at least 65 wt. % based on the total amount of olefins and aromatics produced compared to the total feedstock feed rate, wherein the total feedstock includes the whole crude oil and any additional feeds.

14. The method of claim 1, wherein feeding the hydrotreated and hydrocracked effluent and the low boiling fraction to at least one of a steam cracker (7, 16) and an aromatics complex (18) comprises: separating the hydrotreated and hydrocracked effluent (52) and the low boiling fraction (14) into a separator (58) to produce a light naphtha fraction (24) and a heavy naphtha fraction (26); feeding the light naphtha fraction to the steam cracker unit; and The heavy naphtha fraction is fed to the aromatics complex.

15. The process of claim 1 comprising feeding the hydrotreated and hydrocracked effluent and the low boiling fraction directly to the steam cracker.

16. The method of claim 1, wherein the whole crude oil is condensate, and wherein the low boiling point fraction has a 95% boiling point temperature in the range of about 500°C to about 565°C.

17. A system for converting whole crude oil and other wide boiling hydrocarbon streams to produce olefins and / or aromatics, the system comprising: A separation system (3, 12) for separating the whole crude oil (1) into at least a low boiling point fraction (5), a medium boiling point fraction (9) and a high boiling point residual fraction (15); a hydrocracker (17) for hydrocracking the high boiling point residual fraction to form a hydrocracking effluent, and separating the hydrocracking effluent to produce a residue hydrocracking fraction (21) and a fuel oil fraction (19); a first conditioning reactor (27) for destructively hydrogenating the medium boiling point fraction to form a first destructively hydrogenated effluent (31); a second conditioning reactor (29) for destructively hydrogenating the residual oil hydrocracking fraction to produce a second destructively hydrogenated effluent; a mixer (35) for mixing the first destructive hydrogenated effluent and the second destructive hydrogenated effluent to form a mixture, and a hydrocracker for hydrocracking the mixture to form a hydrotreated and hydrocracked effluent (13); One or more flow lines for feeding the hydrotreated and hydrocracked effluent and the low boiling fraction to at least one of a steam cracker (7, 16) and an aromatics complex (18) to convert the hydrocarbons therein into petrochemical products (23) and pyrolysis oil (24, 44) and / or ultra low sulfur fuel oil (ULSFO) (32).

18. The system of claim 17, wherein the hydrocracker for hydrocracking the high boiling point residual fraction comprises a slurry reactor or an ebullated bed reactor.

19. The system of claim 18, further comprising a flow line (37) for transferring the resid hydrocracking fraction to the first destructive hydrogenation unit during a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

20. The system of claim 17, further comprising a reactor for hydrodesulfurizing the fuel oil fraction to produce ultra low sulfur fuel oil.

21. The system of claim 17, comprising: a separator (77) for separating the hydrotreated and hydrocracked effluent (52) and the low boiling point fraction to produce a light naphtha fraction (24) and a heavy naphtha fraction (26); a flow line for feeding said light naphtha fraction to said steam cracker unit; and A flow line for feeding the heavy naphtha fraction to the aromatics complex.

22. The system of claim 17, wherein the separation system for separating the whole crude oil comprises: a heater (500) for heating the whole crude oil to produce heated whole crude oil; A separator (502) for separating the heated whole crude oil to recover a first fraction (5, 14) and a remaining fraction (506, 510, 514); a heater for heating the remaining fraction to produce a heated remaining fraction (516); A hot hydrogen stripper (518) is used to separate the heated remaining fraction to produce an overhead product including hydrogen and the second fraction (9, 20) and a bottom product (520) including the third fraction (15, 28).

23. The system of claim 22, further comprising a heat exchanger for exchanging heat between the remaining fraction and the bottoms.

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