Process for conversion of whole crude oil to chemicals by crude oil conditioning and steam cracking to maximize petroleum chemical yield

Abstract

The process herein can be used to thermally crack various hydrocarbon feeds and can completely eliminate refineries while making the crude oil to chemical process very flexible in crude oil. In embodiments herein, crude oil is gradually separated into at least a light fraction and a heavy fraction. These fractions are directed to one of three upgrading operations, according to the mass of the light fraction and the heavy fraction, including a fixed bed hydroconversion unit, a fluidized catalytic conversion unit, or a residue hydrocracking unit that may utilize an ebullated bed reactor. The product from the upgrading operation may be used as a feed to a steam cracker.

Description

Technical Field

[0001] Examples of this article relate to methods and systems for producing petrochemicals such as olefins and aromatics from crude oil and low-value heavy hydrocarbon streams. Background Technology

[0002] If high-boiling-point compounds in crude oil are fed to a steam cracker, they can cause significant operational problems. These compounds readily form coke, largely due to their high asphaltenes content. Therefore, high-boiling-point compounds are typically removed before the lighter fractions are fed to different petrochemical units, such as steam crackers or aromatics complexes. However, this removal process increases the overall capital costs and reduces profitability, as the removed high-boiling-point compounds can only be sold as low-value fuel oil. Furthermore, converting vacuum residue without forming large amounts of HPNA (heavy polynuclear aromatics) that are harmful to downstream steam crackers has been a challenge to date.

[0003] USP 3,617,493 describes a method in which crude oil is fed to the convection section of a steam cracker and then to a separation zone, wherein a portion of the feed with a boiling point below about 450℉ is separated from the remainder of the feed and is then fed together with steam into the high-temperature section of the steam cracker to undergo cracking conditions.

[0004] USP 4,133,777 teaches a method in which feed oil first flows down in a trickle through a fixed bed of HDM catalyst and then down through a fixed bed of promoting catalyst containing selected Group VI and Group VIII metals, in which very little hydrocracking occurs.

[0005] USP 5603824 discloses a method for upgrading a waxy hydrocarbon feed mixture containing sulfur compounds boiling within the distillate oil range to reduce sulfur content and 85% boiling point, while maintaining the high octane number of naphtha byproducts and maximizing distillate oil yield. The method employs a single downflow reactor with at least two catalyst beds and an interbed redistributor between them. The top bed contains a hydrocracking catalyst, preferably zeolite β, and the bottom bed contains a dewaxing catalyst, preferably ZSM-5.

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

[0007] USP 3,830,720 discloses a dual-bed catalytic method for hydrocracking and hydrodesulfurization of residual oil, wherein a microporous catalyst is positioned upstream of a macroporous catalyst.

[0008] USP 3,876,523 describes a novel catalyst and a method for catalytic demetallization and desulfurization of hydrocarbon oils containing residual fractions. The method described utilizes a catalyst comprising hydrogenation components (such as cobalt oxide and molybdenum oxide) compounded on alumina. While this catalyst is highly efficient for demetallization of residual fractions and exhibits good stability over operating time, its effectiveness is significantly enhanced when it is combined in a specific manner with a second catalyst possessing different key properties. The type of catalyst described in US Patent 3,876,523 will be referred to as the first catalyst, and it should be understood that the first catalyst will be located upstream of the second catalyst with different properties.

[0009] USP 4,153,539 discloses improved hydrogen utilization and / or higher conversion of desired products during hydrorefining or hydrocracking processes when using *Dendrobium nobile* particles for hydrorefining, catalytic reforming, fixed-bed alkylation, etc., of light hydrocarbon fractions.

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

[0011] The dual-catalyst unit, as specified in USP 4,016,067, is used for demetallization and / or desulfurization of any hydrocarbon oil with excessively high metal and / or sulfur content for a particular application. Dual-catalyst units are particularly effective for preparing low-metal and / or low-sulfur feedstocks for catalytic cracking or coking. In processes involving the removal of metals and sulfur, the hydrocarbon oil is also enriched in hydrogen, making it an even more suitable feedstock for either of these processes.

[0012] Generally, these and other previous processes used for converting whole crude oil typically convert less than 50% of the crude oil into more desirable end products, such as petrochemicals like ethylene, propylene, butene, pentene, and light aromatics. Typically, 20% of the whole crude oil is pre-removed during processing to remove the heaviest, most difficult-to-convert components. Approximately another 20% of the whole crude oil is usually converted to pyrolysis oil, while about 10% is partially converted to methane. Summary of the Invention

[0013] On one hand, the embodiments disclosed herein relate to a method for converting whole crude oil and other heavy hydrocarbon streams to produce olefins and / or aromatics. The method includes: separating a hydrocarbon feedstock into at least a light-boiling fraction, a medium-boiling fraction, and a high-boiling residue fraction in a first integrated separation unit; hydrocracking the high-boiling residue fraction and pyrolysis oil in a first conditioning unit including a residue hydrocracking system to produce a hydrocracking effluent; feeding at least a portion of the hydrocracking effluent to a second conditioning unit to produce a steam cracker feed stream; performing destructive hydrogenation on the medium-boiling fraction in the second conditioning unit to produce additional hydrocarbons in the steam cracker feed stream; and feeding the steam cracker feed stream and the light-boiling fraction to a steam cracker to convert the hydrocarbons therein, thereby producing a steam cracker effluent.

[0014] Other aspects and advantages will become apparent from the following description and the appended claims. Attached Figure Description

[0015] Figures 1 to 4 This is a simplified process flow diagram of systems and methods for converting whole crude oil and / or heavy hydrocarbon streams according to embodiments of this document. Detailed Implementation

[0016] As used herein, the term "petrochemicals" refers to hydrocarbons including light olefins and dienes, as well as C6-C8 aromatics. Therefore, petrochemicals refer to hydrocarbons including ethylene, propylene, butene, butadiene, pentene, pentadiene, benzene, toluene, and xylene. For a subset of petrochemicals, the term "chemicals" as used herein refers to ethylene, propylene, butadiene, 1-butene, isobutene, benzene, toluene, and p-xylene.

[0017] Hydrorefining is a catalytic process, typically carried out in the presence of free hydrogen, where the primary objective when processing hydrocarbon feedstocks is to remove various metallic contaminants (e.g., arsenic), heteroatoms (e.g., sulfur, nitrogen, and oxygen), and aromatics from the feedstock. Generally, in hydrorefining operations, the cracking of hydrocarbon molecules (i.e., the breakdown of larger hydrocarbon molecules into smaller ones) is minimized. As used herein, the term "hydrorefining" refers to a refining process in which the feed stream reacts with hydrogen in the presence of a catalyst to remove impurities such as sulfur, nitrogen, oxygen, and / or metals (e.g., nickel, vanadium, etc.) from the feed stream through a reduction process. Hydrorefining processes can vary considerably depending on the type of feedstock for the hydrorefining unit. For example, light feedstocks (e.g., naphtha) contain very few and few types of impurities, while heavy feedstocks typically contain many different heavy compounds present in crude oil. In addition to containing heavy compounds, the impurities in heavy feedstocks are more complex and difficult to handle than those present in light feedstocks. Therefore, hydrorefining of light feedstocks is usually carried out at lower reaction intensities, while heavy feedstocks require higher reaction pressures and temperatures.

[0018] Hydrocracking refers to the process of hydrogenation and dehydrogenation accompanied by hydrocarbon cracking / fragmentation, such as converting heavier hydrocarbons into lighter hydrocarbons, or converting aromatics and / or cycloalkanes (cycloalkanes) into acyclic branched alkanes.

[0019] As used herein, “conditioning” and similar terms refer to the conversion of hydrocarbons by one or both of hydrocracking and hydrorefining. “Destructive hydrocracking” and similar terms refer to the breaking of hydrocarbon molecular bonds and the associated hydrogen saturation of the remaining hydrocarbon fragments, which can produce stable, lower-boiling hydrocarbon oil products and may include both hydrocracking and hydrorefining.

[0020] "API specific gravity" refers to the specific gravity of petroleum feedstock or product relative to water, as determined by ASTM D4052-11.

[0021] The integration of conditioning, fractionation, and steam cracking can create highly efficient facilities, and in some embodiments, can convert greater than 55%, 60%, 65%, 70%, 75%, 80%, or 85% of whole crude oil into petrochemicals. In other embodiments, the integration of conditioning, fractionation, and steam cracking can create highly efficient facilities, and in some embodiments, can convert greater than 55%, 60%, 65%, 70%, 75%, 80%, or 85% of whole crude oil into chemicals. Therefore, the embodiments described herein provide systems and methods for conditioning feeds, even those including the heaviest and least desirable residue components, into components that can be vaporized and delivered to the radiant section of a steam cracker, thereby achieving significant improvements over the low petrochemical conversion rates of existing methods.

[0022] The embodiments described herein relate to methods and systems that use crude oil and / or low-value heavy hydrocarbons as feedstock to produce petrochemicals such as light olefins and dienes (ethylene, propylene, butadiene, and / or butene) and aromatics. More specifically, the embodiments described herein relate to methods and systems for producing olefins and aromatics through the thermal cracking of pre-conditioned crude oil or condensate. The methods described herein can condition the residual fractions of whole crude oil and natural condensate to produce feedstocks that can be used as feedstocks for steam crackers.

[0023] The hydrocarbon mixtures that can be used in the embodiments disclosed herein may include a variety of hydrocarbon mixtures having a boiling point range, 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 (e.g., hydrocarbons with a boiling point 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 greater. This description is illustrative of crude oil (such as whole crude oil), but hydrocarbon mixtures with any high-boiling-point endpoint can be used. However, the processes disclosed herein are applicable to crude oils, condensates, and hydrocarbons having broad boiling profiles and endpoints 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, raffinate reformate, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gas gasoline, distillate oils, virgin naphtha, natural gas condensate, atmospheric pipeline distillate bottoms, and vacuum pipeline distillate streams, which include bottoms distillate, naphtha to gas oil condensate with a wide boiling range, heavy non-primary hydrocarbon streams from refineries, vacuum gas oil, heavy gas oil, atmospheric residue, hydrocracker wax, and Fischer-Tropsch wax, etc. In some embodiments, the hydrocarbon mixture may include hydrocarbons boiling from naphtha range or lighter ranges to vacuum gas oil ranges or heavier ranges.

[0024] When the final boiling point of a hydrocarbon mixture is very high, such as above 550°C, the mixture cannot be directly processed in a steam cracking reactor to produce olefins. The presence of these heavy hydrocarbons leads to the formation of coke in the reactor, which can occur in one or more of the preheating or superheating coils in the convection zone, in the radiant coils, or in the transfer line exchangers, and this coking can occur very quickly (e.g., within a few hours). Whole crude oil is generally not commercially cracked because it is uneconomical. It is usually fractionated, and only specific fractions are used in the steam cracking heater to produce olefins. The remainder is used in other processes. The cracking reaction proceeds via a free radical mechanism. Therefore, high ethylene yields can be obtained when cracked at high temperatures. Lighter feedstocks, such as butane and pentane, require high reactor temperatures to obtain high olefin yields. Heavy feedstocks, such as gas oil and vacuum gas oil (VGO), require lower temperatures. Crude oil contains a distribution of compounds from butane to VGO and residues (materials with boiling points above 550°C). Exposing whole crude oil to high temperatures without separation produces high yields of coke (a byproduct of high-intensity cracking of hydrocarbons) and clogs the steam cracking reactor. The steam cracking reactor must be shut down periodically and the coke cleaned by steam / air decoking. The time between two clean-up periods when olefins are produced is called the run length. When whole crude oil is cracked without separation, coke deposits in the convection section coils (evaporation fluid), the radiant section (where olefin production reactions occur), and / or the transfer line exchangers (where the reaction is rapidly stopped by cooling to maintain olefin yield).

[0025] Methods and systems for converting crude oil as feedstock to produce petrochemicals and low-sulfur fuel oil, according to embodiments of this document, may include a feed preparation section, a crude oil conditioning section, an optional aromatics complex, and a steam cracker. For example, the feed preparation section may include a desalter. The crude oil is conditioning and processed so that the crackable feedstock is fed to the steam cracker to maximize chemical yields while maintaining a reasonable decoking frequency in the furnace. Another objective of the crude oil conditioning section is to achieve maximum conversion of asphaltenes, such as complete or substantially complete (95%+) conversion to lower-boiling-point components, thereby increasing chemical yields while reducing the formation of heavy polynuclear aromatics (HPNAs).

[0026] Therefore, the methods according to the embodiments of this article can convert heavier fractions of crude oil into high-value petrochemicals and minimize the amount of hydrocarbons sent to fuel oil pools, which significantly improves profitability. The resulting small-scale fuel oil pools can also be upgraded to low-sulfur fuel oil that meets IMO 2020 standards, thereby further increasing the value of the product.

[0027] As mentioned above, if high-boiling compounds in crude oil are fed to a steam cracker, they can cause significant operational problems because they tend to form coke, primarily due to their high asphaltenes content. Therefore, high-boiling compounds are typically removed before the lighter fractions are fed to different petrochemical units, such as steam crackers and aromatics complexes. This removal process increases the overall capital costs and reduces profitability, as the removed high-boiling compounds can only be sold as low-value fuel oil. Furthermore, converting vacuum residue without forming large amounts of HPNA, which is harmful to downstream steam crackers, has been a challenge to date.

[0028] The configurations of the systems and methods for converting whole crude oil and heavy hydrocarbons according to the embodiments described herein can efficiently handle residue conversion while maximizing chemical conversion rates and maintaining a low coking tendency in the steam cracker. This is achieved by adding one or more integrated separation units (ISD) and / or catalytic cracking units during crude oil conditioning.

[0029] The methods according to embodiments of this disclosure aim to convert a majority of crude oil into a viable feedstock for a steam cracker. The efficient residue conversion according to embodiments herein maximizes chemical conversion and maintains a low tendency to coke. This is achieved by integrating one or both of the following processes throughout the method configuration: (1) adding a hydrocracking reactor during crude oil conditioning, enabling high-boiling compounds to be converted to compounds with boiling points below 540°C; and / or (2) adding a catalytic cracking unit, which enhances the catalyst lifespan in the fixed-bed hydrotreatment reactor and reduces coke formation in the steam cracker. This allows all or substantially all of the processed crude oil to be fed to the steam cracker, thereby reducing the overall process yield of low-value fuel oils and increasing the yields of high-value olefins, dienes, and benzene, toluene, and xylene (BTX).

[0030] The separation of various fractions, such as low-boiling fractions (160°C- fractions) and high-boiling fractions (160°C+ fractions), or such as low, intermediate, and high-boiling fractions (e.g., 160°C- fractions, 160°C to 490°C fractions, and 490°C+ fractions), can improve the capital efficiency and operating costs of the methods and systems disclosed herein. Although three fractions are mentioned in many embodiments herein, the inventors recognize that condensate oil, which typically has a small amount of high-boiling components, and whole crude oil, which has a larger amount of high-boiling components, can be processed differently. Therefore, oil feedstocks with a wide boiling range can be separately classified once, twice, three times, or more, and each fraction can be processed separately under optimal conditions.

[0031] Whole crude oil can be separated into desired fractions using one or more separators (distillation columns, flash tanks, etc.). In some embodiments, the separation of the oil feed can be carried out in an integrated separation unit (ISD), such as disclosed in US20130197283, which is incorporated herein by reference. In an ISD, initial separation of low-boiling fractions is performed based on a combination of centrifugal and cyclone effects to separate the desired vapor fraction from the liquid. An additional separation step can then be used to separate the intermediate-boiling fraction from the high-boiling components.

[0032] Typically, hydrocarbon fractions with boiling points above 490°C contain asphaltenes and Conradson carbon residues, and therefore require appropriate processing, as further described below. While the examples are described as including fractions below about 90°C to 250°C (such as the 160°C fraction) and fractions with boiling points above about 400°C to 560°C (such as the 490°C+ fraction), it should be noted that actual classification points may vary depending on the type of whole crude oil or other heavy fraction being processed. For example, for crude oils containing low metal or nitrogen content, or those with significant amounts of “processable” components, such as those boiling at temperatures up to 525°C, 540°C, or 565°C, it is possible to increase the medium / high classification points while still achieving the advantages of the examples described herein. Similarly, in some examples, low / medium classification points may be as high as 220°C, or in others as high as 250°C. Furthermore, it has been found that low / medium classification points of about 160°C can provide benefits for the size design and operation of reactors, such as fixed-bed conditioning reactors for conditioning medium-quality hydrocarbon fractions (medium fractions). Furthermore, for some feedstocks, such as condensate oil, the low / medium fractionation point can be as high as 565°C. According to the embodiments described herein, the ability to change the fractionation point increases the flexibility of the process, allowing for the processing of multiple feedstocks while still producing the desired product mixture.

[0033] Therefore, in some embodiments, the light fraction may include hydrocarbons with boiling points up to about 90°C (e.g., 90°C-fraction), up to about 100°C, up to about 110°C, up to about 120°C, up to about 130°C, up to about 140°C, up to about 150°C, up to about 160°C, up to about 170°C, up to about 180°C, up to about 190°C, up to about 200°C, up to about 210°C, up to about 220°C, up to about 230°C, up to about 240°C, up to about 250°C (e.g., 250°C-fraction), up to about 300°C, up to about 350°C, up to about 400°C, up to about 500°C, or up to about 565°C. The embodiments herein also contemplate light fractions as hydrocarbons with boiling points up to the middle of the above ranges.

[0034] Depending on the fractionation mechanism used, the light hydrocarbon “fraction” can be relatively clean, meaning that the light fraction may not have any significant (as used herein, >1 wt%) of compounds with boiling points above the target boiling temperature. For example, the 160°C fraction may not have any significant amount of hydrocarbon compounds with boiling points above 160°C (i.e., >1 wt%). In other embodiments, the aforementioned target “fraction” temperature may be a 95% boiling point temperature, or in other embodiments, an 85% boiling point temperature, such as those measured using ASTM D86 or ASTM D2887, or by measuring the heavy flows, such as those with boiling points above about 400°C, according to true boiling point (TBP) analysis, such as ASTM D2892 and ASTM D7169. In such embodiments, up to 5 wt% or up to 15 wt% of compounds may be present above the indicated “fraction” point temperature. For many whole crude oils, low / medium fractionation points can result in light boiling fractions having 95% boiling point temperatures in the range of about 90°C to about 250°C. However, for other feedstocks, such as condensate oil, the light boiling fraction can have a 95% boiling point temperature, for example, in the range of about 500°C to about 565°C.

[0035] In some embodiments, the medium fraction may include hydrocarbons whose boiling points range from the lower limit of the upper limit temperature of the light fraction (e.g., 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 400°C) to the upper limit of boiling points up to about 350°C, up to about 375°C, up to about 400°C, up to about 410°C, up to about 420°C, up to about 430°C, up to about 440°C, up to about 450°C, up to about 460°C, up to about 480°C, up to about 490°C, up to about 500°C, up to about 520°C, up to about 540°C, up to about 560°C, or up to about 580°C. For example, as used herein, a medium fraction having a lower limit of 160°C and an upper limit of 490°C can be referred to as a 160°C to 490°C fraction or distillate. The embodiments herein also envision medium fractions as hydrocarbons with boiling points from temperatures midway through the aforementioned range and / or up to temperatures midway through the aforementioned range.

[0036] Depending on the fractionation mechanism, the hydrocarbon “fraction” of the middle fraction may be relatively clean, meaning that the middle fraction may not contain any significant (>1 wt%) of compounds with boiling points below the target limit of the expected boiling temperature and / or may not contain any significant (>1 wt%) of compounds with boiling points above the target limit of the expected boiling temperature. For example, the 160°C to 490°C fraction may not contain any significant amount of hydrocarbon compounds with boiling points below 160°C or above 490°C. In other embodiments, the aforementioned expected target “fraction” temperature may be a lower limit of 5 wt% or 15 wt% boiling point temperature and / or an upper limit of 95% or 85% boiling point temperature, such as those measured using ASTM D86 or ASTM D2887, or measured according to true boiling point (TBP) analysis, such as ASTM D2892 and ASTM D7169, for heavy streams, such as those with boiling points above about 400°C. In such embodiments, up to 5 wt% or up to 15 wt% of compounds may be present above and / or below the “fraction” point temperature, respectively.

[0037] In some embodiments, the heavy fraction may include hydrocarbons with boiling points above about 350°C, above about 375°C, above about 400°C (e.g., 400°C + fraction), above about 420°C, above about 440°C, above about 460°C, above about 480°C, above about 490°C, above about 500°C, above about 510°C, above about 520°C, above about 530°C, above about 540°C, above about 560°C, above about 580°C, above about 590°C, above about 600°C (e.g., 600°C + fraction), or above about 700°C. The embodiments herein also envision heavy fractions as hydrocarbons with boiling points above the intermediate temperatures described above.

[0038] In one or more embodiments, it may be desirable to use fewer fractionation points. In one example, light crude oil may be separated into a 250°C- fraction and a 250°C+ fraction. The 250°C- fraction may be suitable for steam cracking, and the 250°C+ fraction may be suitable for processing in one or more conditioning processes.

[0039] Depending on the fractionation mechanism, a heavy hydrocarbon “fraction” can be relatively clean, meaning that the heavy fraction may not contain any significant (>1 wt%) of compounds with boiling points below the target boiling temperature. For example, the 490°C+ fraction may not contain any significant amount of hydrocarbon compounds with boiling points below 490°C. In other embodiments, the aforementioned target “fraction” temperature may be the 95% boiling point temperature, or in other embodiments, the 85% boiling point temperature, as can be measured using ASTM D86 or ASTM D2887, or by measuring the heavy flows, such as those with boiling points above about 400°C, according to true boiling point (TBP) analysis, such as ASTM D2892 and ASTM D7169. In such embodiments, up to 5 wt% or up to 15 wt% of compounds may be present below the “fraction” point temperature, respectively.

[0040] While the examples below are given for finite temperature ranges, it is foreseeable that any temperature range specified above can be used in the process described herein. Furthermore, regarding the gradation points, those mentioned in the examples below can be clean, as described above, or can refer to 5% or 15% of the boiling temperature as a lower limit, or 85% or 95% of the boiling temperature as an upper limit.

[0041] After fractionation, light fractions, such as the 160°C fraction, can be fed into the system's steam cracker section with or without further processing. The light fractions fed into the steam cracker section may include, for example, light naphtha and lighter hydrocarbons, and in some embodiments may include heavy naphtha boiling range hydrocarbons.

[0042] The middle-range hydrocarbon fraction can be conditioned using one or more fixed-bed reactors, such as hydrorefining reactors and / or hydrocracking reactors, each of which can destructively hydrogenate the hydrocarbons in the middle fraction. The conditioning reactors can include catalysts for metal removal, sulfur removal, and nitrogen removal, and conditioning in these reactors can generally add hydrogen to the hydrocarbon components, making them more readily processed downstream to produce petrochemicals. For example, the fixed-bed catalyst system in the middle fraction conditioning zone can contain layers of demetallizing catalysts, destructive hydrogenation catalysts, and mesoporous zeolite hydrocracking catalysts to optimize the conversion of heavy materials, thereby achieving a balance between a highly alkane stream suitable for olefin production and an aromatics-rich stream suitable for aromatics production.

[0043] In some embodiments, it may be desirable to further separate the medium grade fraction into low-to-medium and high-to-medium grades. For example, a medium grade fraction having a boiling range of 160°C to 490°C may be divided into a low-to-medium grade fraction having a boiling range of about 160°C to about 325°C and a high-to-medium grade fraction having a boiling range of about 325°C to about 490°C. Thus, the conditioning sequences can be configured to more selectively convert hydrocarbon components in the respective low-to-medium and high-to-medium grades into the desired conditioned effluent, wherein each sequence can be configured based on a preferred catalyst for destructive hydrogenation of the hydrocarbons therein, reactor size settings for the expected feed volume and catalyst lifetime, and operating conditions to achieve the desired conversion to a naphtha range containing steam cracker feedstock. Similarly, it is also envisioned that the medium grade fraction be divided into three or more sub-fractions.

[0044] Processing heavy hydrocarbons (such as 490°C+ hydrocarbons) in heavy hydrocarbon conditioning units can improve the conversion of low-value streams to high-value products.

[0045] The heavy and medium fraction conditioning sections are designed to achieve four (4) objectives. First, the crude oil conditioning section can be used to increase the concentration of alkanes and cycloalkanes in the crude oil. Second, the conditioning section can reduce the concentration of polynuclear aromatics (PNAs) in the crude oil. Third, the conditioning section can lower the final boiling point (FBP) of the crude oil to below 540°C. And, fourth, the conditioning section can minimize the vacuum residue fraction of the crude oil.

[0046] For example, when conditioning medium and / or heavy fractions, the embodiments described herein can aim to convert heavier hydrocarbons into hydrocarbons lighter than diesel. Therefore, hydrorefining catalysts and hydrocracking catalysts, as well as operating conditions, can be selected to target the conversion of hydrocarbons in the corresponding fractions into predominantly (>50 wt%) naphtha-range hydrocarbons. Using catalysts and operating conditions in the conditioning section to obtain lighter hydrocarbon products can improve the operability of the steam cracker and the production of chemicals.

[0047] In some embodiments, adjustment of the heavy fraction (such as the 490°C+ fraction) may result in at least 70% by weight of compounds with boiling points above 565°C being converted to lighter-boiling compounds. Other embodiments may result in greater than 75% by weight, greater than 80% by weight, or greater than 85% by weight of compounds with boiling points above 565°C being converted to lighter-boiling compounds.

[0048] In some embodiments, adjustment of the medium fraction (such as the 160°C to 490°C fraction) may result in greater than 50% by weight of hydrocarbons therein being converted to naphtha range hydrocarbons. In other embodiments, adjustment of the medium fraction may result in greater than 55% by weight, greater than 60% by weight, greater than 65% by weight, or greater than 70% by weight of hydrocarbons therein being converted to naphtha range hydrocarbons.

[0049] In some embodiments, the combined adjustment of the medium and heavy fractions may result in greater than 50% by weight of the total hydrocarbons being converted to naphtha-range hydrocarbons. In other embodiments, the adjustment of the medium and heavy fractions may result in greater than 55% by weight, greater than 60% by weight, or greater than 65% by weight of the hydrocarbons being converted to naphtha-range hydrocarbons.

[0050] Due to this initial separation and conditioning, in some embodiments, the feed to the steam pyrolyzer can be fed directly into the steam pyrolyzer without further processing. In some embodiments, light fractions 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 into the steam pyrolyzer after separation. Effluent from the medium fraction conditioning can also be fed directly into the steam pyrolyzer according to embodiments herein. Similarly, in some embodiments, effluent from the heavy fraction conditioning can be fed directly into the steam pyrolyzer.

[0051] Even when processing multiple feeds with different boiling point ranges, the adjustment of the corresponding fractions, as described herein, can allow for extended periods of operation of the steam pyrolyzer. In some embodiments, the steam pyrolyzer may be able to operate for at least three years of uninterrupted operation; in other embodiments, at least four years; and in still other embodiments, at least five years.

[0052] Furthermore, the initial hydrocarbon fractionation point, reactor size, catalyst, etc., can be adjusted or configured to ensure consistent operating and regulation times for the steam cracker. For example, in Figure 1 In the configuration, as further described below, whole crude oil can be conditioned and subsequently steam-cracked. The catalyst, reactor size, and conditions can be configured such that the operating time of the conditioning unit is consistent with that of the steam cracker. Catalyst volume, catalyst type, and reaction intensity can all play a role in determining the operating time of the conditioning unit. Furthermore, the degree of conditioning of heavier hydrocarbons in the crude oil may affect coking in the thermal cracker. To maximize plant uptime, the embodiments described herein envision the design and configuration of the entire system such that, for a given feedstock or multiple anticipated feedstocks, the conditioning system has a similar anticipated operating time to the steam cracker. Furthermore, the embodiments described herein envision adjusting the reaction conditions (T, P, space velocity, etc.) in the conditioning section and / or steam cracker based on the feedstock being processed, such that the operating times of the conditioning section and the steam cracker are similar or consistent.

[0053] Adjusting operating times can minimize downtime, such as when catalyst turnover in the regulating reactor occurs simultaneously with decoking in the steam cracker. When the regulating system comprises multiple reactors or reactor types, consistent operating times can be based on anticipated steam cracker performance. Furthermore, for example, where the hydrorefining unit may have significantly longer operating times than the hydrocracker in the regulating section, parallel hydrocracking reactor sequences and / or bypass processing can be used to synchronize the total operating times of the regulating and steam cracking units.

[0054] Bypass processing may include, for example, the temporary processing of the 490°C+ fraction in a reactor that typically processes lighter feedstocks. Heavier feedstocks are anticipated to have more demanding conditions and shorter catalyst lifetimes; therefore, temporary processing of heavy feedstocks in a mid-range hydrocarbon conditioning reactor during heavy catalyst replacement can allow the entire crude oil feedstock to continue being fed to the steam cracker without downtime while the heavy conditioning reactor catalyst is being replaced. The configuration of the mid-range conditioning reactor can also take into account anticipated bypass processing when designing the entire system to achieve consistent uptime.

[0055] The following is a brief description of the configurations disclosed herein for the production of olefins and / or aromatics. (The following is in conjunction with...) Figures 1 to 4 A block flowchart further describes the various configurations.

[0056] In some embodiments, the overall hot crude oil to chemicals configuration according to the embodiments herein can use an integrated separation unit to initially separate a hydrocarbon feedstock with a wide boiling range to produce light fractions (such as 160°C- fractions), medium-boiling fractions (such as 160°C to 490°C fractions), and heavy fractions (such as 490°C+ fractions). The medium-boiling fractions can then be conditioned in a fixed-bed reactor system with a hydrotreating catalyst system. The heavy fractions, optionally together with pyrolysis oil from a steam cracker, can be conditioned in a residue hydrocracking unit, such as an LC-FINING or LC-SLURRY process. The resulting conditioned heavy stream can then be separated to form light conditioned fractions (such as 490°C- fractions) and heavy conditioned fractions (such as 490°C+ fractions). The 490°C- fraction of the residue hydrorefining product can then be further conditioned together with the medium-boiling fractions in a fixed-bed reactor system. Then, based on the preferred cracking temperature of the corresponding fraction, the resulting fractions from the regulated crude oil can be fed for steam cracking in steam cracking furnaces of varying intensity. Unconverted fractions from the residue upgrading process can be further hydrotreated to produce ultra-low sulfur fuel oil (ULSFO).

[0057] In other embodiments, the overall hot crude oil to chemicals configuration according to the embodiments herein can use an integrated separation unit to initially separate a hydrocarbon feedstock with a wide boiling range to produce light fractions (such as 160°C- fractions), medium-boiling fractions (such as 160°C to 490°C fractions), and heavy fractions (such as 490°C+ fractions). The medium-boiling fraction can then be conditioningd in a fixed-bed reactor system with a hydrotreating catalyst system. The heavy fraction can be conditioningd in a residue hydrocracking unit, such as an LC-FINING or LC-SLURRY process. The resulting conditioning heavy stream can then be separated to form light conditioning fractions (such as 490°C- fractions) and heavy conditioning fractions (such as 490°C+ fractions). The 490°C- fraction of the residue hydrorefining product can then be fed to one or more catalytic cracking units for further conversion to steam-crackable hydrocarbons. Light, regulated fractions from each of the first-stage and second-stage residue hydrocracking units can be further regulated in a fixed-bed reactor system along with medium-boiling fractions. The resulting fractions from the regulated crude oil can then be fed for steam cracking in steam cracking furnaces of varying intensity, depending on the preferred cracking temperature of the respective fraction.

[0058] In other embodiments, the overall hot crude oil to chemicals configuration according to the embodiments herein can use an integrated separation unit to initially separate a hydrocarbon feedstock with a wide boiling range to produce light fractions (such as 160°C- fractions), medium-boiling fractions (such as 160°C to 490°C fractions), and heavy fractions (such as 490°C+ fractions). The medium-boiling fractions can then be conditioned in a fixed-bed reactor system with a hydrotreating catalyst system. The heavy fractions, optionally together with pyrolysis oil from a steam cracker, can be conditioned in a residue hydrocracking unit, such as an LC-FINING or LC-SLURRY process. The resulting conditioned heavy stream can then be separated to form light conditioned fractions (such as 490°C- fractions) and heavy conditioned fractions (such as 490°C+ fractions). The moderately boiling fraction can be further separated to remove ammonia and / or hydrogen sulfide, and subsequently separated into two or more fractions, such as using an integrated separation unit, including light fractions (e.g., the 160°C- fraction), medium fractions (e.g., the 160°C to 360°C fraction), and unconverted oil (UCO) fraction. The 490°C- fraction (after conditioning the heavy fraction) and the medium fraction (from the moderately boiling 160°C to 360°C fraction) of the residue hydrorefining product can then be fed to a third fixed-bed conditioning unit for further conditioning of medium-range and heavy-range hydrocarbons for steam cracking. The resulting effluent can also be separated into light and heavy fractions (e.g., the 160°C- and 160°C+ fractions), with the heavy fraction being returned to the third fixed-bed conditioning unit to form additional naphtha-range hydrocarbons suitable for thermal cracking. In the third fixed-bed conditioning unit, the stream can undergo reactions to reduce the aromatic content of the hydrocarbons therein. Then, depending on the preferred cracking temperature of the respective fraction, the light regulated fractions from each of the first and third regulating units can be fed together with the straight-run light fractions and UCO for steam cracking in steam cracking furnaces of varying severity. Unconverted fractions from the residue upgrading process can be further hydrotreated to produce ultra-low sulfur fuel oil (ULSFO).

[0059] To produce increased quantities of high-value chemicals while reducing the amount of low-value ULSFO, catalytic cracking can be used to further process a portion of the unconverted oil. In principle, any type of catalytic cracker can be used. Fluid catalytic crackers (FCCs) are common in industry. This can be a riser reactor. Fluidized bed crackers can also be considered. Packed bed reactors can also be used. In the FCC process, the catalyst deactivates rapidly and therefore must be regenerated continuously or periodically. FCC uses continuous regeneration. Fixed bed reactors can use periodic regeneration. In this embodiment, the catalytic reactor system is illustrated in fixed bed operation. However, it is not limited to fixed beds and any type of reactor can be used. Due to the rapid deactivation of the catalyst, multiple packed bed reactors may be required. Due to the lower intensity of thermal cracking, it may operate for months before requiring cleaning (decoking). Product distribution may also vary over time due to catalyst deactivation. To minimize fluctuations in product composition, packed beds can be staggered (timely) between the start of cracking and the start of decoking. For example, a four-reactor system is assumed, with three reactors for cracking and one for decoking. The first reactor will be in near-clean conditions (catalyst at initial activity), the second reactor at approximately 33% activity, and the third reactor at approximately 67% activity. The fourth reactor, having reached its permissible catalyst activity limit, is removed and regenerated. Therefore, when the fourth reactor is clean, it will replace the first reactor, and the first reactor will act as the old second reactor, and the old second reactor will act as the old third reactor, which will then be decoked. This cycle is repeated. Additional backup reactors may be required if the cycles are out of sync.

[0060] When using FCC or fluidized bed reactors, there is no recirculation. In the FCC method, all catalyst is sent to a regenerator for recycling. For fluidized bed reactors, a portion of the catalyst is removed, regenerated, and returned to the fluidized bed. In packed bed, conventional fluidized bed, or FCC-type reactors, space velocity, catalyst circulation, and other key parameters can be optimized for the cracking of pyrolysis effluents containing olefins. When using fixed bed reactors, they can be placed in flame heaters and / or operated adiabatably. The heat of reaction will determine the optimal operating mode and design. Typically, a combustion environment is preferred because it is more compact. After the catalytic reactor, the effluent can be quenched and the products recovered.

[0061] Many commercially available catalysts are available for catalytic cracking. Any suitable catalyst can be used. Typically, Y-type zeolites, with or without additives, are used for heavy feedstocks. ZSM-5 is added to retain lower olefins (C3H6, C4H8) and prevent them from further reacting into aromatics (within the naphtha boiling range), coke, or paraffin. A higher or optimal concentration of ZSM-5 catalyst in the catalyst mixture is preferred to meet the desired olefin composition in the product. ZSM-5 selectively converts higher olefins to lower olefins and retains them by preventing further reaction into aromatics or coke. However, any catalyst that favors catalytic cracking can be used.

[0062] Now for reference Figure 1 A simplified process flow diagram of a system for converting crude oil and heavy hydrocarbons according to embodiments herein is shown.

[0063] Heavy hydrocarbon feeds with a wide boiling range, such as desalted crude oil 1, can be fed to separation system 3. Separation system 3 can be an integrated separation unit (ISD) as described above and includes, for example, separation and thermal integration. In separation system 3, desalted crude oil 1 can be separated into three fractions, including: (a) a light fraction, such as 160°C- fraction 5, which requires no conditioning and can be used as feed to steam cracker section 7; (b) a mid-range fraction, such as 160°C to 490°C fraction 9; and (c) a heavy fraction, such as 490°C+ fraction 11. Other classification points can also be used to convey desired fractions and hydrocarbons therein to desired units for conditioning and / or cracking. Steam cracker section 7 and cracker product recovery unit 25 can be used for thermal cracking of the 160°C- fraction and other feeds discussed below to form chemicals 13 (such as ethylene, propylene, and butene, which can be recovered collectively or as separate streams), and higher boiling pyrolysis oil fraction 27.

[0064] The 490°C+ fraction 11 and the pyrolysis oil fraction 27 can be fed to a first conditioning system 17, which may include one or more hydrorefining reactors and / or hydrocracking reactors to at least partially convert the 490°C+ fraction and the pyrolysis oil to produce a conditioned hydrocarbon stream 19. For example, the 490°C+ stream can be processed in a residue hydrocracking reactor system 17, which may include one or more reactors, such as those utilizing fluidized bed extruder catalysts or slurry catalysts, to convert the hydrocarbons therein to 490°C-fluidized compounds. A portion of stream 19 (stream 19A) can then be fed to a second conditioning section 31 to produce a highly alkane stream 33 suitable for processing in a steam cracking section 7. A second portion of stream 19 (stream 19B) can be fed to an FCC unit 21 for further processing of the unconverted oil in stream 19. A third portion of stream 19 (stream 19C) can be fed to a residue hydrorefining unit 22. The residue hydrorefining unit 22 can convert the heaviest residue in stream 19 into ultra-low sulfur fuel oil (ULSFO) 26. Light to medium fractions can be recovered from FCC unit 21 via flow line 29 and can be combined with stream 19A and sent to a second conditioning section 31 to produce additional high-alkanes in stream 33. FCC unit 21 can also produce a waste stream 23 with hydrocarbons in the C1 to C8 range (such as hydrocarbon fractions ending at approximately 160°C to approximately 490°C), and a heavy FCC oil stream 28 with corresponding initial boiling points (such as 490°C+ hydrocarbons). A portion of the heavy FCC oil stream 28 can be fed to the residue hydrorefining unit 22 to produce additional ULSFO 26.

[0065] The medium-boiling fraction 9 can be fed to the second conditioning section 31 to produce additional high-chain alkanes in stream 33, which is suitable for processing in the steam cracking section 7 to produce chemical stream 13 (such as ethylene, propylene, and butene) and higher-boiling pyrolysis oil fraction 27, as described above.

[0066] In some embodiments, conditioning reactor 31 may include a hydrorefining catalyst (first-stage conditioning) and / or a hydrocracking catalyst (second-stage conditioning). Further, in some embodiments, the first-stage conditioning may include a reactor zone containing a residual desulfurization catalyst. The hydrorefining reactor and / or the hydrocracking reactor may include catalysts for metal removal and nitrogen removal, and the hydrotreating in these reactors may generally add hydrogen to the conditioned hydrocarbon components, making them more readily processed downstream to produce chemicals. For example, the fixed-bed catalyst system in the conditioning zone may contain layers of demetallizing catalyst, hydrorefining catalyst, and mesoporous zeolite hydrocracking catalyst to optimize the conversion of heavy materials, thereby achieving a balance between a highly alkane stream suitable for olefin production and an aromatics-rich stream suitable for aromatics production.

[0067] In some embodiments, the 490°C+ fraction 11 can be split into a first fraction and a second fraction. The second fraction (stream 12) can bypass the residue hydrocracker 17 and be fed directly to the residue hydrorefining unit 22. Depending on the amount of 490°C+ hydrocarbons in the desalted crude oil 1, processing the 490°C+ hydrocarbons in the residue hydrorefining unit 22 allows for a longer operating time of the catalyst in the residue hydrocracker 17. Residue hydrocracking can be carried out in a fixed-bed residue hydrocracker, a fluidized-bed reactor (such as the LC-FINING or LC-MAX reactor systems available from Lummus Technology), or the LC-SLURRY reactor available from Chevron Lummus Global.

[0068] The additional 490°C material in stream 29 can be processed in a fixed-bed hydrorefining reactor, which may be the same reactor used for conditioning the medium fraction 9, or in some embodiments, it may be a separate fixed-bed hydrorefining reactor containing a catalyst suitable for efficiently conditioning the hydrocarbons from the primary conversion received from the residue hydrocracking. The reaction product 33 from the 160°C to 490°C stream 9 of the hydrorefining and the 490°C light-to-medium fraction recovered from FCC unit 21 can then be processed in a second conditioning section 31 to produce feedstock 33 suitable for processing in the steam cracker section 7 to convert to light olefins and other valuable chemicals.

[0069] The effluent 15 from the steam pyrolysis section 7 can be fed to the pyrolysis product recovery unit 25. The pyrolysis product recovery unit 25 can produce a chemical stream 13 (such as ethylene, propylene, and butene) and a higher boiling point pyrolysis oil fraction 27, as described above.

[0070] As described above, FCC unit 21 can also produce a heavy FCC oil stream 28 with hydrocarbons at 490°C+. The pyrolysis oil fraction 27 and the heavy FCC oil stream 28 can be combined and recycled back to the residue hydrocracker 17. In one or more embodiments, a portion of the combined pyrolysis oil fraction and heavy FCC oil stream can be carried to the residue hydrorefining unit 22 via recirculation line 30. Similar to bypass 12, processing the 490°C+ hydrocarbons in the pyrolysis oil fraction and heavy FCC oil stream in the residue hydrorefining unit 22, depending on the amount of 490°C+ hydrocarbons in the desalted crude oil 1, allows for longer operating times of the catalyst in the residue hydrocracker 17.

[0071] Now for reference Figure 2 A simplified process flow diagram of a system for converting crude oil and heavy hydrocarbons according to embodiments herein is shown, wherein the same reference numerals denote the same components.

[0072] Heavy hydrocarbon feeds with a wide boiling range, such as desalted crude oil 1, can be fed to separation system 3. Desalted crude oil 1 can be desalted light crude oil, such as hydrocarbons with an API specific gravity greater than 20°. Separation system 3 can be an integrated separation unit (ISD) as described above and includes, for example, separation and thermal integration. In separation system 3, desalted crude oil 1 can be separated into two fractions: (a) a 250°C fraction 55, which requires no conditioning and can be used as feed to steam cracker section 7; and (b) a 250°C+ fraction 58, which can be upgraded in conditioning section 57 to produce lighter hydrocarbons, such as a high-alkanes stream 54 suitable for processing in steam cracker section 7. Other classification points can also be used to convey desired fractions and hydrocarbons therein to desired units for conditioning and / or cracking. Treatment of the feed to the steam cracker section can produce one or more chemical streams 23 (such as ethylene, propylene, and butene), and a higher-boiling pyrolysis oil fraction 25.

[0073] The higher boiling point pyrolysis oil fraction 25 can be recycled to the separation system 3 as part of the desalting crude steam 1. This recycling of the higher boiling point pyrolysis oil fraction 25 can serve as a diluent stream for the desalted crude oil stream, or it can be used to further increase the amount of high-value products in the chemical stream 23.

[0074] In one or more embodiments, a portion of the 250°C+ fraction may be removed from the system via discharge stream 10. Discharge stream 10 may be used in embodiments where the desalted crude oil 1 contains a large amount of high-boiling compounds.

[0075] Now for reference Figure 3 A simplified process flow diagram of a system for converting crude oil and heavy hydrocarbons according to embodiments herein is shown, wherein the same reference numerals denote the same components.

[0076] Heavy hydrocarbon feeds with a wide boiling range, such as desalted crude oil 1, can be fed to separation system 3. Desalted crude oil 1 can be desalted light crude oil. Separation system 3 can be an integrated separation unit (ISD) as described above and includes, for example, separation and thermal integration. In separation system 3, desalted crude oil 1 can be separated into two fractions: (a) a 250°C fraction 55, which requires no conditioning and can be used as feed to steam cracker section 7; and (b) a 250°C+ fraction 58, which can be upgraded in conditioning section 57 to produce lighter hydrocarbons, such as a high-alkanes stream 54 suitable for processing in steam cracker section 7. Other classification points can also be used to convey desired fractions and hydrocarbons therein to desired units for conditioning and / or cracking. Treatment of the feed to the steam cracker section can produce one or more chemical streams 23 (such as ethylene, propylene, and butene), and a higher-boiling pyrolysis oil fraction 25.

[0077] The higher boiling point pyrolysis oil fraction 25 can be recycled to the separation system 3 as part of the desalting crude steam 1. This recycling of the higher boiling point pyrolysis oil fraction 25 can serve as a diluent stream for the desalted crude oil stream, or it can be used to further increase the amount of high-value products in the chemical stream 23.

[0078] In one or more embodiments, a portion of the 250°C+ fraction may be fed via feed stream 60 to a second hydrotreating unit 40. Similar to the hydrotreating unit described above, the second hydrotreating unit 40 may convert the heaviest residue in stream 60 into ultra-low sulfur fuel oil (ULSFO) 41.

[0079] As mentioned above, various feedstocks can allow for increased classification points, such as raising the medium / high classification point from 490°C to 545°C in some embodiments. However, regarding the processing of high-boiling fractions (e.g., 490°C+ or 545°C+ fractions) in catalytic cracking units, it has been found that lower classification points may be more advantageous, as excessively high classification points may necessitate the use of fractionated oils to produce ULSFO.

[0080] Other low-value refinery streams can also be processed according to the embodiments herein to produce higher-value final products. Such streams include some or all of the following types of hydrocarbons: (i) light cycle oils (LCOs), such as LCOs produced from FCC units, which can be processed with fractions from 160°C to 490°C; (ii) slurries, such as slurries produced from FCC units, which can be processed with hydrocarbons at 490°C+; and / or (iii) pyrolysis fuel oils, such as pyrolysis fuel oils from stream crackers, including pyrolysis fuel oil stream 25 from steam cracker 7, which can be processed with hydrocarbons at 490°C+. Various other hydrocarbon streams with similar boiling ranges can also be co-processed in the systems disclosed herein to produce petrochemicals, wherein such streams may include light naphtha, heavy naphtha, crude oil, atmospheric residue, vacuum residue, synthetic crude oil, and other hydrocarbon streams containing heavy hydrocarbons. The grading points in any of the ISDs may also vary to account for different feedstock qualities (i.e., metals, asphaltenes, and CCRs). In embodiments where the desalted crude oil has low contaminant content, the initial grading point can be higher (i.e., above 160°C), thereby reducing the operating load on the catalyst in one or more condition systems. Alternatively, in embodiments where the desalted crude oil has high contaminant content, the initial grading point can be lower (i.e., below 160°C), thereby allowing more hydrocarbon feed through multiple condition systems and a second ISD for hydrorefining and / or removal of unwanted heavy components, and thus increasing the amount of naphtha-range hydrocarbons fed to steam cracking.

[0081] As briefly described above, the embodiments described herein can allow for the direct cracking of crude oil into chemicals in an economically viable manner, resulting in light hydrocarbons such as ethylene and propylene, without the need for conventional refining steps. Furthermore, as the shale gas revolution drives an increasing shift towards cracking lighter feedstocks, directly converting crude oil into chemicals could help narrow the widening supply-demand gap for key building blocks typically produced as byproducts (propylene, butadiene).

[0082] The integration of processing units according to the embodiments herein can provide unique potential for upgrading whole crude oils (such as Arabian Light and Arabian Extra Light) and low-value refinery streams (such as pyrolysis oil, slurry, and light cycle oil (LCO)) into higher-value chemical products. While the feed conditioning according to the embodiments herein adds hydrogen to the feed components, and hydrogen consumption is an additional cost to the plant, the overall benefit of producing chemicals rather than fuel outweighs this increased cost. The foregoing will also apply to other types of crude oil, such as desalted oil, condensate, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, recycled crude oil, and bitumen-derived oil.

[0083] In other embodiments, an optional aromatics complex may be included. For example, an aromatics complex may be used to convert 160°C to 490°C fractions, or a portion thereof, into aromatics. For example, medium fractions (such as 160°C to 240°C fractions) may be processed to convert a portion of their hydrocarbons into aromatics, while heavy fractions may be fed to a steam cracker to be converted into chemicals. The aromatics complex feedstock generated via initial processing and conditioning according to the embodiments herein may allow individual processors to stop importing whole-fraction naphtha (FRN).

[0084] Furthermore, in some embodiments, the pyrolysis oil generated in the steam cracking unit can be separated to recover pyrolysis gasoline fractions and one or more heavy fractions, such as pyrolysis gas oil fractions and pyrolysis fuel oil fractions. As described above, the lighter pyrolysis gasoline fractions can be fed into the aromatics unit, while the heavier fractions can be used to form ULSFO.

[0085] Such as about Figure 1 As described, separation system 3 can be as follows Figure 4 The process, as shown, includes separation and thermal integration. After desalting, crude oil 1 can be further preheated in the convection section of heater 500 to produce preheated crude oil 502. The preheated crude oil 502 can be fed to separator 504, which facilitates the separation of 160°C fraction 5 from the heavier components recovered in stream 506.

[0086] The remaining 160°C+ crude oil fraction 506 can be fed to pump 508, which produces a pressurized 160°C+ crude oil fraction 510. This pressurized crude oil fraction can then be fed to heat exchanger 512. ISD heat exchanger 512 can preheat the 160°C+ crude oil fraction 510 relative to the bottom product 520 of the hot hydrogen stripper, thereby 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 heater 500, where it is heated to promote the separation of the 160°C to 490°C fraction from the heavier 490°C+ fraction. The heated 160°C+ crude oil fraction 516 can then be fed to 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 9 and a hot hydrogen stripper bottom product 520, which contains heavier 490°C+ hydrocarbons. The hot hydrogen stripper bottom product 520, after being cooled via indirect heat exchange with the pressurized 160°C+ crude oil fraction 510 in heat exchanger 512, can be removed from the separation system 3 as a 490°C+ fraction 11.

[0087] The hot hydrogen stripper 518 can utilize hydrogen feed 522 as the stripping medium. Based on the properties of the crude oil feedstock being processed, the hot hydrogen stripper 518 can be operated to provide a wide range of flexibility. The stripper overhead distillate, i.e., the 160°C to 490°C fraction 9, can be cooled to recover hydrogen and, if necessary, directed to the intermediate hydrotreating reaction stage, and as per relevant regulations. Figure 1 As described. Following amine treatment (not shown), the recovered hydrogen can be fed to a downstream pressure swing adsorption (PSA) unit (not shown) to improve hydrogen purity. The PSA hydrogen product can be compressed in a supplementary hydrogen compressor (not shown) for use in one or more hydrotreating reactors (…). Figure 1 It provides supplemental hydrogen and serves as a hot hydrogen feed 522.

[0088] The bottom product 520 of the hot hydrostripper (such as the 490°C+ fraction) contains some of the most difficult compounds to deal with in crude oil, including asphaltenes, metals, and CCRs. Excess metals, CCRs, and asphaltenes in high-boiling residue fractions can cause rapid catalyst fouling and increase pressure drop in fixed-bed downflow reactors, thus limiting both conversion and catalyst run-length. After cooling relative to the pressurized 160°C+ crude oil fraction 510, the 490°C+ stream 11 can be recovered and processed in a liquid circulation, fluidized-bed residue hydrocracker, along with any other low-value refinery streams (such as tar streams and / or slurry streams). Figure 1 As described in [the text].

[0089] By adjusting the amount of hydrogen 522 fed into the hot hydrogen stripper 518 and the operating conditions of the hot hydrogen stripper 518 and the heater 500, the hydrocarbon fractionation point can be adjusted so that the light fraction 5 can be directly fed to the downstream steam cracker, and the medium fraction 9 can be almost free of or contain no harmful compounds that would cause rapid fouling in the fixed-bed conditioning reactor. In this way, the separation system 3 (with the hot hydrogen stripper 518) can concentrate the most difficult-to-process hydrocarbons in the heavy fraction 11, which can be fed to the fluidized bed reactor that can operate under the most severe conditions, thereby preserving the catalyst in the steam cracker and the fixed-bed conditioning reactor.

[0090] Figure 2 and Figure 3 The embodiments regarding separation system 3 can be compared with those regarding... Figure 1 The embodiments are similar. However, the separation system can be configured to produce light fractions at 250°C and one or more heavy streams at 250°C+.

[0091] The embodiments described herein provide a strategic combination of crude oil feedstock preparation, crude oil separation, crude oil conditioning, and steam cracking technologies to maximize the yield of high-value chemicals. The crude oil conditioning section employs a combination of fixed-bed hydrotreatment and liquid recirculation to condition the crude oil into a suitable steam cracker feed and to upgrade low-value refinery streams. For example, the embodiments described herein can achieve chemical yields ranging from 60% to 90% of the total crude oil feedstock.

[0092] After desalting, the crude oil can be separated into three fractions: 160°C- stream; 160°C to 490°C stream; and 490°C+ stream. The 160°C- steam does not require upgrading and can therefore be directly directed to the steam cracker. The 160°C to 490°C stream is readily handled in a fixed-bed hydrotreating reaction system, where the feed is hydrorefined and converted to naphtha, making it an ideal feedstock for the steam cracker.

[0093] The embodiments described herein may employ one or more hydrorefining and / or hydrocracking reactions, along with integrated separation units, to remove bitumen (asphaltite) and metals, thereby increasing the run time of the conversion process without causing reactor fouling. In some embodiments, bitumen, asphaltite, and metals may be fed into a delayed coking unit to recover carbon contained in these streams.

[0094] The embodiments described herein provide upstream processing for processing whole crude oil and other hydrocarbons with a wide boiling range in a steam cracker, wherein embodiments of the integrated process can be configured to have a common uptime. This can be accomplished by failover or switching from one regulation system to another to minimize total system downtime during catalyst regeneration, maintenance, or cleaning. Furthermore, such embodiments can eliminate the need for parallel reaction sequences or redundant process units in both the processing of mid-range hydrocarbons and the processing of high-boiling residues used during catalyst regeneration.

[0095] Furthermore, the hydrorefining reactor and hydrocracking reactor in each of the first and second conditioning systems can be sized to have similar operating times to the steam cracking unit. Since cleaning, maintenance, and catalyst regeneration can be performed simultaneously across multiple reaction systems, this configuration can additionally reduce downtime. Without such design considerations, operation could increase downtime, for example, when the reactor in the first conditioning system is offline for catalyst regeneration while the catalyst in the second conditioning system still has >50% of its lifetime.

[0096] Furthermore, avoiding entrainment of heavy materials in the front-end separation process can reduce costs and enable less complex process schemes as shown and described herein. Moreover, avoiding entrainment ensures operability and processability in the crude oil conditioning system and steam cracker, allowing for lower total capital expenditure while achieving high chemical yields. As described above, the embodiments described herein can separate desalted crude oil or other broad-boiling hydrocarbons into various fractions to effectively condition the corresponding fractions, thereby forming feedstocks suitable for conversion in a steam cracker. Given the wide range of feedstocks that can be processed according to the embodiments described herein, depending on the feedstock, conditioning catalyst, reactor volume, and other factors of a given unit, it may be more preferable to determine the specific grading point based on one or more additional properties of the feedstock. For example, the specific grading point can be adjusted based on one or more properties or additional properties of the crude oil feedstock, such as API specific gravity, Minerals Bureau Related Index (BMCI), hydrogen content, nitrogen content, sulfur content, viscosity, microcarbon residue (MCRT), and / or total metals, as well as other feedstock properties.

[0097] Various feedstocks that can be used in the embodiments herein, such as crude oil, desalted oil, condensate oil, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, recycled crude oil, and bitumen-derived oil, may have one or more of the following properties, including: API specific gravity between 4° and 60°, BMCI of 20 to 85, hydrogen content of 9.0 wt% to 14.5 wt% (or 90,000 ppm to 145,000 ppm), nitrogen content of 0.02 wt% to 0.95 wt% (or 200 ppm to 9,500 ppm), sulfur content of 0.009 wt% to 6.0 wt% (or 90 ppm to 60,000 ppm), viscosity of 95 centipoise to 5500 centipoise (cSt) at 40°C, MCRT of 5 wt% to 35 wt%, and / or may have a total metal content of <1 ppm to 1000 ppm.

[0098] Initial crude oil separation can be performed and adjusted to impart specific properties to the light, medium, and heavy fractions, allowing the light fraction to enter the steam cracker with little or no intermediate processing. Furthermore, the medium to heavy fractions can be adjusted to provide appropriate and / or favorable feed properties and hydrocarbon types, enabling effective and efficient conditioning in the medium and heavy conditioning reactors.

[0099] BMCI

[0100] In some embodiments, the light fraction may have a BMCI of less than 20. In other embodiments, the light fraction may have a BMCI of less than 15. In still other embodiments, the light fraction may have a BMCI of less than 10 or even less than 5. In some embodiments, the medium fraction 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 fraction 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.

[0101] Therefore, in some embodiments, light fractions comprising hydrocarbons with boiling points up to about 90°C to about 300°C may, for example, have a BMCI of less than 20; in other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 110°C or up to about 250°C, for example, the light fraction may have a BMCI of less than 10; in still other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 130°C or up to about 220°C, for example, the light fraction may have a BMCI of less than 5. In some embodiments where the light fraction comprises hydrocarbons with boiling points below about 160°C, the light fraction may have a BMCI of less than 5. While the BMCI of different feeds may vary at any given fraction temperature, it has been found, for example, that low BMCIs, such as less than 10 or less than 5, can improve the processability of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, the light fraction of the Arab Light crude oil processed in the embodiments of this article may be targeted at, for example, a BMCI of less than 10, and for the Arab Extra Light crude oil may be targeted at, for example, a BMCI of less than 6 or less than 5.5.

[0102] In some embodiments, a medium fraction comprising hydrocarbons having a low boiling point in the range of about 90°C to about 300°C and a high boiling point in the range of about 400°C to about 600°C may have a BMCI between about 5 and 50. For example, a medium 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 by using relatively moderately destructive processing conditions in the medium fraction conditioning section of the methods described herein, a medium fraction with a BMCI between 10 and 30 can be converted into a steam cracker feed. The medium fraction of Arab Light crude oil processed according to the embodiments described herein may be targeted with a BMCI in the range of, for example, about 20 to about 30, and for Arab Extra Light crude oil, a BMCI in the range of, for example, about 15 to about 30.

[0103] In various embodiments, heavy fractions comprising hydrocarbons with boiling points greater than about 300°C can have a BMCI greater than 30. When the heavy fraction comprises hydrocarbons with boiling points above about 350°C, the heavy fraction can have a BMCI greater than 40. When the heavy fraction comprises hydrocarbons with boiling points above about 400°C, the heavy fraction can have a BMCI greater than 50. In embodiments where the heavy fraction comprises hydrocarbons with boiling points above about 490°C, the heavy fraction can have a BMCI greater than 55. For example, it has been found that using more stringent destructive hydrogenation conditions in the heavy fraction conditioning section of the methods described herein, heavy fractions with a BMCI greater than about 40 can be converted to steam cracker feed. The heavy fraction of Arab Light crude oil processed according to the embodiments described herein can be targeted to have a BMCI in the range of, for example, about 50 to about 60, and for Arab Extra Light crude oil, a BMCI in the range of, for example, about 25 to about 40.

[0104] API

[0105] In some embodiments, the lightweight fraction may have an API specific gravity greater than 10°. In other embodiments, the lightweight fraction may have an API specific gravity greater than 15°. In still other embodiments, the lightweight fraction may have an API specific gravity greater than 20°, greater than 30°, or even greater than 40°. In some embodiments, the medium-weight fraction may have an API specific gravity greater than 10° and less than 40°, such as from the lower limit of 10°, 15°, 20°, 25°, or 30° to the upper limit of 25°, 30°, 35°, 40°, 45°, or 50°. In some embodiments, the heavy-weight fraction may have an API specific gravity less than 40°, such as less than 35°, less than 25°, less than 20°, less than 15°, or less than 10°.

[0106] Therefore, in some embodiments, a light fraction comprising hydrocarbons with boiling points up to about 300°C may, for example, have an API gravity greater than 10°; in other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 250°C, for example, the light fraction may have an API gravity greater than 20°; in still other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 220°C, the light fraction may have an API gravity greater than 40°. In some embodiments where the light fraction comprises hydrocarbons with boiling points below about 160°C, the light fraction may have an API gravity greater than 60°. While the API gravity of different feeds may vary at any given fraction temperature, it has been found, for example, that API gravity greater than 40°, greater than 50°, or greater than 60° can improve the processability of light hydrocarbons in a steam pyrolysis unit without requiring intermediate processing. The light fraction of Arab Light crude oil processed according to the embodiments herein can be targeted at, for example, an API specific gravity greater than 65°, and for Arab Ultra Light crude oil, an API specific gravity greater than 60° can be targeted.

[0107] In some embodiments, a medium fraction comprising hydrocarbons having a low boiling point in the range of about 90°C to about 300°C and a high boiling point in the range of about 400°C to about 600°C may have an API gravity between about 5° and 50°. For example, a medium fraction may have an API gravity between the lower limit of 5°, 10°, 15°, 20°, or 25° and the upper limit of 10°, 15°, 20°, 25°, 30°, 40°, or 50°. For example, it has been found that by using relatively moderate destructive processing conditions in the medium fraction conditioning section of the methods described herein, a medium fraction having an API gravity between 20° and 40° can be converted into a steam cracker feed. The medium fraction of Arab Light crude oil processed according to the embodiments described herein may be targeted to have an API gravity in the range of, for example, about 30° to about 35°, and for Arab Ultra Light crude oil, an API gravity in the range of, for example, about 35° to about 40° can be targeted.

[0108] In various embodiments, the heavy fraction comprising hydrocarbons with boiling points greater than about 300°C can have an API gravity of less than about 40°. When the heavy fraction comprises hydrocarbons with boiling points greater than about 350°C, the heavy fraction can have an API gravity of less than about 20°. When the heavy fraction comprises hydrocarbons with boiling points greater than about 400°C, the heavy fraction can have an API gravity of less than about 10°. In embodiments where the heavy fraction comprises hydrocarbons with boiling points greater than about 490°C, the heavy fraction can have an API gravity of, for example, less than 7°. For example, it has been found that by using more stringent destructive hydrogenation conditions in the heavy fraction conditioning section of the methods described herein, heavy fractions with API gravity of less than about 20° can be converted into steam cracker feed. The heavy fraction of Arab Light crude oil processed according to the embodiments described herein can be targeted to have an API gravity in the range of, for example, about 5° to about 10°, and for Arab Ultra Light crude oil, an API gravity in the range of, for example, about 10° to about 20° can be targeted.

[0109] hydrogen content

[0110] In some embodiments, the light fraction may have a hydrogen content greater than 12% by weight. In other embodiments, the light fraction may have a hydrogen content greater than 13% by weight. In still other embodiments, the light 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 fraction may have a hydrogen content greater than 11% by weight and less than 14% by weight, such as from the lower limit of 11% by weight, 11.5% by weight, 12.0% by weight, 12.5% ​​by weight, or 13.0% by weight to the upper limit of 12.0% by weight, 12.5% ​​by weight, 13.0% by weight, 13.5% by weight, 14.0% by weight, or 14.5% by weight. In some embodiments, the heavy 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.

[0111] Therefore, in some embodiments, a light fraction comprising hydrocarbons with boiling points up to about 300°C may, for example, have a hydrogen content greater than 13% by weight; in other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 250°C, for example, the light fraction may have a hydrogen content greater than 13.5% by weight; in still other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 220°C, the light fraction may have a hydrogen content greater than 14.0% by weight. In some embodiments where the light fraction comprises hydrocarbons with boiling points below about 160°C, the light fraction may have a hydrogen content greater than 14.5% by weight. Although the hydrogen content of different feeds may vary at any given fraction temperature, it has been found, for example, that hydrogen contents such as greater than 13% by weight, greater than 14% by weight, or greater than 14.5% by weight can improve the processability of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, the light fraction of Arab Light crude oil processed according to the embodiments herein may be targeted to have a hydrogen content of, for example, greater than 14.5% by weight, and the hydrogen content of Arab Ultra Light crude oil may be targeted to have a hydrogen content of, for example, greater than 14% by weight.

[0112] In some embodiments, a medium fraction comprising hydrocarbons having a low boiling point in the range of about 90°C to about 300°C and a high boiling point in the range of about 400°C to about 600°C can have a hydrogen content between about 11.5 wt% and 14.5 wt%. For example, it has been found that by using relatively moderately destructive processing conditions in the medium fraction conditioning section of the methods described herein, a medium fraction with a hydrogen content between 12 wt% and 13.5 wt% can be converted into a steam cracker feed. Medium fractions of Arab Light crude oil processed according to embodiments herein can be targeted to have a hydrogen content in the range of, for example, about 12.5 wt% to about 13.5 wt%, and for Arab Extra Light crude oil, a hydrogen content in the range of, for example, about 13.0 wt% to about 14.0 wt%.

[0113] In various embodiments, the heavy fraction comprising hydrocarbons with a boiling point greater than about 300°C may have a hydrogen content of less than about 13% by weight. When the heavy fraction comprises hydrocarbons with a boiling point greater than about 350°C, the heavy fraction may have a hydrogen content of less than about 12.5% ​​by weight. When the heavy fraction comprises hydrocarbons with a boiling point greater than about 400°C, the heavy fraction may have a hydrogen content of less than about 12.0% by weight. In embodiments where the heavy fraction comprises hydrocarbons with a boiling point greater than about 490°C, the heavy fraction may have, for example, a hydrogen content of less than 11% by weight. For example, it has been found that by using more stringent destructive hydrogenation conditions in the heavy fraction conditioning section of the method described herein, a heavy fraction with a hydrogen content of less than about 12% by weight can be converted into a steam cracker feed. The heavy fraction of Arab Light crude oil processed according to the embodiments herein may be targeted with a hydrogen content in the range of, for example, about 10% by weight to about 11% by weight, and the hydrogen content of Arab Ultra Light crude oil may be targeted with a hydrogen content in the range of, for example, about 11% by weight to about 12% by weight.

[0114] Nitrogen content

[0115] In some embodiments, the light fraction may have a nitrogen content of less than 100 ppm, such as less than 50 ppm or less than 30 ppm. In other embodiments, the light fraction may have a nitrogen content of less than 25 ppm. In still other embodiments, the light fraction may have a nitrogen content of less than 20 ppm, less than 15 ppm, less than 10 ppm, less than 5 ppm, less than 3 ppm, less than 1 ppm, or even less than 0.5 ppm. In some embodiments, the medium fraction may have a nitrogen content of greater than 1 ppm and less than 1000 ppm, such as from the lower limit of 1 ppm, 5 ppm, 10 ppm, 50 ppm, 100 ppm, 250 ppm, or 500 ppm to the upper limit of 50 ppm, 100 ppm, 250 ppm, 500 ppm, or 1000 ppm. In some embodiments, the heavy fraction 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.

[0116] Therefore, in some embodiments, a light fraction comprising hydrocarbons with boiling points up to about 300°C may, for example, have a nitrogen content of less than 0.01 wt% or 100 ppm; in other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 250°C, for example, the light fraction may have a nitrogen content of less than 0.001 wt% or 10 ppm; in still other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 220°C, the light fraction may have a nitrogen content of less than 0.0001 wt% or 1 ppm. In some embodiments where the light fraction comprises hydrocarbons with boiling points below about 160°C, the light fraction may have a nitrogen content of less than about 0.00003 wt% or 0.3 ppm. While the nitrogen content of different feeds may vary at any given fraction temperature, it has been found, for example, that nitrogen contents such as less than about 100 ppm, less than 10 ppm, or less than 1 ppm can improve the convertibility of light hydrocarbons in a steam pyrolysis unit without requiring intermediate processing. For example, the light fraction of Arab Light crude oil processed according to the embodiments herein may be targeted with a nitrogen content of, for example, less than 1 ppm, and the nitrogen content of Arab Ultra Light crude oil may also be targeted with a nitrogen content of, for example, less than 1 ppm.

[0117] In some embodiments, the medium fraction comprising hydrocarbons having a low boiling point in the range of about 90°C to about 300°C and a high boiling point in the range of about 400°C to about 600°C can have a nitrogen content, for example, between about 10 ppm and 250 ppm. For example, it has been found that by using relatively moderate destructive processing conditions in the medium fraction conditioning section of the methods described herein, a medium fraction with a nitrogen content between 20 ppm and 250 ppm can be converted into a steam cracker feed. The medium fraction of Arab Light crude oil processed according to the embodiments described herein can be targeted to have a nitrogen content in the range of about 200 ppm to about 300 ppm, and for Arab Extra Light crude oil, a nitrogen content in the range of about 100 ppm to about 150 ppm can be targeted, for example.

[0118] In various embodiments, the heavy fraction comprising hydrocarbons with boiling points greater than about 300°C may have a nitrogen content greater than about 0.001 wt% or 10 ppm. When the heavy fraction comprises hydrocarbons with boiling points higher than about 350°C, the heavy fraction may have a nitrogen content greater than about 0.005 wt% or 50 ppm. When the heavy fraction comprises hydrocarbons with boiling points higher than about 400°C, the heavy fraction may have a nitrogen content greater than about 0.01 wt% or 100 ppm. In embodiments where the heavy fraction comprises hydrocarbons with boiling points higher than about 490°C, the heavy fraction may have a nitrogen content, for example, greater than 2500 ppm. For example, it has been found that using more stringent destructive hydrogenation conditions in the heavy fraction conditioning section of the method described herein, a heavy fraction with a nitrogen content greater than about 100 ppm can be converted into a steam cracker feed. The heavy fraction of Arab Light crude oil processed according to the embodiments herein can be targeted with a nitrogen content in the range of about 2,000 ppm to about 3,000 ppm, and for Arab Ultra Light crude oil, a nitrogen content in the range of, for example, about 1,000 ppm to about 2,000 ppm can be targeted.

[0119] Sulfur content

[0120] In some embodiments, the light fraction may have a sulfur content of less than 10,000 ppm, such as less than 5,000 ppm or less than 1,000 ppm. In other embodiments, the light fraction may have a sulfur content of less than 750 ppm. In still other embodiments, the light fraction may have a sulfur content of less than 500 ppm, less than 250 ppm, or even less than 100 ppm. In some embodiments, the medium fraction may have a sulfur content greater than 500 ppm and less than 10,000 ppm, such as from the lower limit of 500 ppm, 750 ppm, 1,000 ppm, 1,500 ppm, 2,000 ppm, 2,500 ppm, or 5,000 ppm to the upper limit of 1,000 ppm, 2,000 ppm, 5,000 ppm, 10,000 ppm, 15,000 ppm, or 20,000 ppm. In some embodiments, the heavy fraction 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.

[0121] Therefore, in some embodiments, a light fraction comprising hydrocarbons with boiling points up to about 300°C may, for example, have a sulfur content of 1 wt% or 10,000 ppm; in other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 250°C, for example, the light 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 fraction comprises hydrocarbons with boiling points up to about 220°C, the light fraction may have a sulfur content of less than 0.1 wt% or 1,000 ppm. In some embodiments where the light fraction comprises hydrocarbons with boiling points below about 160°C, the light fraction may have a sulfur content of less than about 750 ppm or less than 500 ppm. While the sulfur content of different feeds may vary at any given fraction temperature, it has been found, for example, that a sulfur content of less than 600 ppm can improve the convertibility of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, the light fraction of Arab Light crude oil processed according to the embodiments herein may be targeted to have a sulfur content of, for example, less than 750 ppm, and for Arab Ultra Light crude oil, it may be targeted to have a sulfur content of, for example, less than 500 ppm.

[0122] In some embodiments, the medium fraction comprising hydrocarbons having a low boiling point in the range of about 90°C to about 300°C and a high boiling point in the range of about 400°C to about 600°C can have a sulfur content, for example, between about 1,000 ppm and 20,000 ppm. For example, it has been found that by using relatively moderate destructive processing conditions in the medium fraction conditioning section of the methods described herein, medium fractions with a sulfur content between 2,000 ppm and 15,000 ppm can be converted into steam cracker feed. The medium fraction of Arab Light crude oil processed according to the embodiments of this invention can be targeted to have a sulfur content in the range of about 6,000 ppm to about 12,000 ppm, and for Arab Extra Light crude oil, a sulfur content in the range of about 5,000 ppm to about 10,000 ppm can be targeted.

[0123] In various embodiments, the heavy fraction comprising hydrocarbons with boiling points greater than about 300°C can have a sulfur content greater than about 0.1 wt% or 1,000 ppm. When the heavy fraction comprises hydrocarbons with boiling points higher than about 350°C, the heavy fraction can have a sulfur content greater than about 0.5 wt% or 5,000 ppm. When the heavy fraction comprises hydrocarbons with boiling points higher than about 400°C, the heavy fraction can have a sulfur content greater than about 1 wt% or 1,000 ppm. In embodiments where the heavy fraction comprises hydrocarbons with boiling points higher than about 490°C, the heavy fraction can have a sulfur content, for example, greater than 25,000 ppm. For example, it has been found that using more stringent destructive hydrogenation conditions in the heavy fraction conditioning section of the method described herein, a heavy fraction with a sulfur content greater than about 10,000 ppm can be converted into a steam cracker feed. The heavy fraction of Arab Light crude oil processed according to the embodiments herein can be targeted with a sulfur content in the range of about 30,000 ppm to about 50,000 ppm, and for Arab Ultra Light crude oil, a sulfur content in the range of, for example, about 20,000 ppm to about 30,000 ppm can be targeted.

[0124] Viscosity

[0125] In some embodiments, the light fraction may have a viscosity of less than 10 cSt as measured at 40°C according to ASTM D445. In other embodiments, the light fraction may have a viscosity of less than 5 cSt as measured at 40°C. In still other embodiments, the light fraction may have a viscosity of less than 1 cSt as measured at 40°C. In some embodiments, the heavy fraction may have a viscosity greater than 10 cSt as measured at 100°C according to ASTM D445, such as greater than 20 cSt, greater than 350 cSt, greater than 50 cSt, greater than 75 cSt, or greater than 100 cSt. In various embodiments, the medium fraction may have a viscosity between that of the light and heavy fractions.

[0126] Therefore, in some embodiments, a light fraction comprising hydrocarbons with boiling points up to about 300°C may, for example, have a viscosity of less than 10 cSt measured at 40°C; in other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 250°C, for example, the light fraction may have a viscosity of less than 5 cSt measured at 40°C; in still other embodiments, such as when the light fraction comprises hydrocarbons with boiling points up to about 220°C, the light fraction may have a viscosity of less than 1 cSt measured at 40°C. In some embodiments where the light fraction comprises hydrocarbons with boiling points below about 160°C, the light fraction may have a viscosity of less than 0.75 cSt measured at 40°C. While the viscosity of different feeds may vary at any given fraction temperature, it has been found, for example, that low viscosity, such as less than 10 cSt, can improve the processability of light hydrocarbons in a steam pyrolysis unit without the need for intermediate processing. For example, the light fraction of Arab light crude oil processed according to the embodiments herein may be targeted to have a viscosity of, for example, less than 0.55 cSt, and the viscosity of Arab ultralight crude oil may be targeted to have a viscosity of, for example, less than 0.6 cSt.

[0127] In various embodiments, heavy fractions comprising hydrocarbons with boiling points greater than about 300°C can have a viscosity greater than 10 cSt measured at 100°C. When the heavy fraction comprises hydrocarbons with boiling points above about 350°C, the heavy fraction has a viscosity greater than 50 cSt measured at 100°C. When the heavy fraction comprises hydrocarbons with boiling points above about 400°C, the heavy fraction has a viscosity greater than 100 cSt measured at 100°C. In embodiments where the heavy fraction comprises hydrocarbons with boiling points above about 490°C, the heavy fraction can have a viscosity, for example, greater than 375 cSt. For example, it has been found that using more stringent destructive hydrogenation conditions in the heavy fraction conditioning section of the method described herein, heavy fractions with a viscosity greater than about 40 cSt can be converted into steam cracker feed.

[0128] MCRT

[0129] In some embodiments, the light fraction may have only trace or undetectable amounts of microcarbon residue (MCRT). In some embodiments, the medium fraction may have less than 5% by weight, such as less than 3% by weight, less than 1% by weight, or less than 0.5% by weight of MCRT. In some embodiments, the heavy fraction may have more than 0.5% by weight, such as more than 1% by weight, more than 3% by weight, more than 5% by weight, or more than 10% by weight of MCRT.

[0130] In some embodiments, a medium fraction comprising hydrocarbons having a low boiling point in the range of about 90°C to about 300°C and a high boiling point in the range of about 400°C to about 600°C can have a MCRT between about 0% by weight (trace or immeasurable) and 1% by weight. For example, it has been found that using relatively moderately destructive processing conditions in the medium fraction conditioning stage of the methods described herein, a medium fraction with a negligible MCRT can be converted into a steam cracker feed.

[0131] In various embodiments, the heavy fraction comprising hydrocarbons with boiling points greater than about 300°C can have a MCRT greater than 0.5% by weight. When the heavy fraction comprises hydrocarbons with boiling points higher than about 350°C, the heavy fraction can have a MCRT greater than 1% by weight. When the heavy fraction comprises hydrocarbons with boiling points higher than about 400°C, the heavy fraction can have a MCRT greater than 5% by weight. In embodiments where the heavy fraction comprises hydrocarbons with boiling points higher than about 490°C, the heavy fraction can have, for example, a MCRT greater than 15% by weight. For example, it has been found that by using more stringent destructive hydrogenation conditions in the heavy fraction conditioning stage of the method described herein, a heavy fraction with a MCRT greater than about 1% by weight can be converted into a steam cracker feed.

[0132] Metal content

[0133] In some embodiments, the light fraction may contain only trace or undetectable amounts of metal. In some embodiments, the medium 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 fraction may have a metal content of greater than 1 ppm, such as greater than 10 ppm, greater than 20 ppm, greater than 35 ppm, or greater than 50 ppm.

[0134] In some embodiments, a medium fraction comprising hydrocarbons having a low boiling point in the range of about 90°C to about 300°C and a high boiling point in the range of about 400°C to about 600°C may have a metal content between about 0 ppm (trace or immeasurable) and 5 ppm, such as greater than 0 ppm to 1 ppm. For example, it has been found that by using relatively moderately destructive processing conditions in the medium fraction conditioning stage of the methods described herein, medium fractions with negligible metal content can be converted into steam cracker feed.

[0135] In various embodiments, the heavy fraction comprising hydrocarbons with boiling points greater than about 300°C can have a metal content greater than 1 ppm. When the heavy fraction comprises hydrocarbons with boiling points higher than about 350°C, the heavy fraction can have a metal content greater than 10 ppm. When the heavy fraction comprises hydrocarbons with boiling points higher than about 400°C, the heavy fraction can have a metal content greater than 50 ppm. In embodiments where the heavy fraction comprises hydrocarbons with boiling points higher than about 490°C, the heavy fraction can have a metal content, for example, greater than 75 ppm. For example, it has been found that by using more stringent destructive hydrogenation conditions in the heavy fraction conditioning stage of the method described herein, a heavy fraction with a metal content greater than about 10 ppm can be converted into a steam cracker feed.

[0136] For example, the Arab Light crude oil stream can be separated in the initial separation step to produce the desired light, medium, and heavy fractions. Without being bound by theory, the light fraction can be a 160°C fraction, with 5% of the fraction having a boiling point below 36°C and 95% of the fraction having a boiling point below 160°C (only 5% of the fraction having a boiling point above 160°C). The light fraction can have an API gravity of approximately 65.5°, a BMCI of approximately 5.2, a hydrogen content of approximately 14.8 wt% (or 148,000 ppm), a nitrogen content of less than 0.00003 wt% (or 0.3 ppm), a sulfur content of approximately 0.0582 wt% (or 582 ppm), a viscosity of approximately 0.5353 centitrile (cSt) at 40°C, and may contain only trace amounts of MCRT and total metals. The medium fraction can be a fraction from 160°C to 490°C, of ​​which 5% of the fraction has a boiling point below 173°C and 95% of the fraction has a boiling point below 474°C (only 5% of the fraction has a boiling point above 474°C). The medium fraction can have an API gravity of about 33.6°, a BMCI of about 25, a hydrogen content of about 12.83 wt% (or 128,300 ppm), a nitrogen content of less than 0.0227 wt% (or 227 ppm), a sulfur content of about 0.937 wt% (or 9,370 ppm), a viscosity of about 1.58 centitrile (cSt) at 100°C, a MCRT of 0.03 wt%, and may contain only trace total metals. The heavy fraction can be a 490°C+ fraction, of which 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 fraction can have an API gravity of about 8.2°, a BMCI of about 55, a hydrogen content of about 10.41 wt% (or 104,100 ppm), a nitrogen content of less than 0.2638 wt% (or 2,368 ppm), a sulfur content of about 3.9668 wt% (or 39,668 ppm), a viscosity of about 394.3 centitrate (cSt) at 100°C, a MCRT of 17.22 wt%, and a total metal content of 79.04 ppm.

[0137] As another example, Arab ultralight crude oil streams can be separated in an initial separation step to produce the desired light, medium, and heavy fractions. Unbound by theory, the light fraction can be a 160°C fraction, with 5% of the fraction having a boiling point below 54°C and 95% having a boiling point below 160°C (only 5% of the fraction having a boiling point above 160°C). The light fraction can have an API gravity of approximately 62°, a BMCI of approximately 9.09, a hydrogen content of approximately 14.53 wt% (or 145,300 ppm), a nitrogen content of less than 0.00003 wt% (or 0.3 ppm), a sulfur content of approximately 0.0472 wt% (or 472 ppm), a viscosity of approximately 0.58 centitrile (cSt) at 40°C, and may contain only trace amounts of MCRT and total metals. The medium fraction can be a fraction from 160°C to 490°C, of ​​which 5% of the fraction has a boiling point below 169°C and 95% of the fraction has a boiling point below 456°C (only 5% of the fraction has a boiling point above 474°C). The medium fraction can have an API gravity of about 36.1°, a BMCI of about 21.22, a hydrogen content of about 13.38 wt% (or 133,800 ppm), a nitrogen content of less than 0.01322 wt% (or 132.2 ppm), a sulfur content of about 0.9047 wt% (or 9,047 ppm), a viscosity of about 1.39 centitrate (cSt) at 100°C, and may contain only trace amounts of MCRT and total metals. The heavy fraction can be a 490°C+ fraction, of which 5% of the fraction has a boiling point below 455°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 fraction can have an API gravity of about 15.1°, a BMCI of about 33.28, a hydrogen content of about 11.45 wt% (or 114.00 ppm), a nitrogen content of less than 0.1599 wt% (or 1,599 ppm), a sulfur content of about 2.683 wt% (or 26,830 ppm), a viscosity of about 48.79 centitrile (cSt) at 100°C, a MCRT of 9.53 wt%, and a total metal content of 58.45 ppm.

[0138] While various properties have been described for Arab Light and Arab Ultra Light crudes, the above also applies to other types of crude oil, such as desalted oil, condensate, bio-oil, synthetic crude oil, tight oil, heavy hydrocarbons, recycled crude oil, and bitumen derivatives.

[0139] The embodiments described herein envision adjusting various stagement points and reactor conditions based on one or more of the properties described above. The methods described in the embodiments of this paper can analyze the petroleum feed to be used while simultaneously measuring one or more of the various properties of the incoming feed. Based on one or more of these properties, stagement points, catalyst type (for moving bed reactors), pressure, temperature, space velocity, hydrogen feed rate, and other variables can be adjusted to utilize the reactor configuration more effectively and efficiently, thereby maintaining the initial, near-optimal, or optimal conditioning of the feedstock and various stages to obtain the desired steam cracker feedstock.

[0140] For example, a fluidized bed receiving heavy fractions can have the capacity to process a certain amount of hydrocarbons with a sulfur content of less than 40,000 ppm. If the sulfur content of a particular 490°C+ heavy fraction is greater than 40,000 ppm, the capacity of the fluidized bed may be reduced. Therefore, the heavy fractionation point can be lowered, for example, to 465°C+ to reduce the sulfur content to less than 40,000 ppm. Furthermore, if a particular 160°C to 490°C medium fraction has a hydrogen content greater than 14% by weight, and nitrogen, sulfur, MCRT, and total metals are suitably low, the light fraction can be expanded (e.g., from 160°C to 190°C) to direct more whole crude oil directly to the steam cracker. Alternatively, if the medium fraction has a low hydrogen content, and / or sulfur, nitrogen, MCRT, and / or total metals are not suitably low, the light fraction can be reduced (e.g., from 160°C- to 130°C-), allowing additional medium fractions to be processed in the fixed-bed conditioning stage.

[0141] In association with each of the embodiments described above, as an exemplary feedstock, Arab Light crude oil may be processed to produce sufficient light naphtha and other feedstocks to produce incremental ethylene in a mixed feed cracker (MFC). Desalting may include pumping raw Arab Light (AL) crude oil through one or more preheating heat exchangers while raising the crude oil to a temperature such as 140°C to maximize the effectiveness of the desalter. The desalter may be, for example, a two-stage electrostatic desalting system that removes salts, solids, and water from the untreated crude oil that would otherwise cause corrosion and scaling problems in downstream equipment. Water and demulsifying chemicals may be mixed with the untreated crude oil to dissolve its salts in a brine solution, which is then separated from the oil by electrostatic coalescence. The first stage can remove almost all the salts from the crude oil, and the second stage can remove the remaining salts and dehydrate the crude oil.

[0142] A portion of the desalter feedwater (not shown) (which may be, for example, about 2% by volume of the untreated crude oil feed) may be injected into the cold untreated crude oil feed to protect the untreated crude oil preheater from salt deposition. Demulsifier injection points at the suction and discharge points of each crude oil pump prevent the crude oil from forming an emulsion as it passes through the preheating system.

[0143] The water used for desalting (desalter feedwater, DFW) can be stripped acid water (not shown). Desalting may require 6% to 10% by volume of DFW, such as 8% by volume, on the untreated crude oil feed. A makeup water line (not shown) with a sequence control valve can be installed to maintain an adequate DFW volume if the amount of stripped acid water becomes insufficient. The DFW can be collected in a pressure regulating tank for pumping and diversion. A portion of the diversion, such as 2% by volume, can be injected into the cold crude oil, and the remainder can be injected into the desalter. The latter volume can be preheated to within about 10°C of the desalter operating temperature before injection. A mixing valve can facilitate thorough mixing of the DFW with the first-stage effluent. The effluent from the second stage can be pumped and cascaded back to the first stage, where another mixing valve thoroughly mixes it with the preheated crude oil and demulsifying chemicals. The rich effluent from the first stage can be cooled relative to the incoming DFW and previously cooled relative to air and cooling water.

[0144] Each desalination stage can be equipped with a sludge washing system to remove any solids that may settle and accumulate in the desalination vessel. The sludge washing system can be operated by taking water from the same vessel and injecting it back at a higher pressure to fluidize the solids and suspend them in the aqueous phase for further removal with the water flow.

[0145] The remaining 160°C+ crude oil fraction is collected in the ISD storage tank and pumped from there through the stripper feed bottom exchanger and heater to the hot hydrogen stripper by the ISD bottom pump. In the hot hydrogen stripper, using hot hydrogen as the stripping medium, the 160°C+ crude oil fraction is further separated into 160°C to 490°C fractions and a heavier 490°C+ fraction.

[0146] The 160°C to 490°C fractions generated in the process can be fed into a common or separate fixed-bed conditioning section. Each fixed-bed conditioning section can contain up to four reaction stages, including a fluidized bed reactor (such as the LCFINING reactor), a second-stage hydrocracking reactor, and a heavy oil hydrorefining reactor. These four reaction stages can operate within a single common recycle gas loop. The integration of these conditioning stages achieves key processing objectives for upgrading low-value refinery streams, while eliminating the need for imported FRNs and providing steam cracker feed for incremental ethylene production, while minimizing hydrogen consumption, investment, and operating costs.

[0147] In some embodiments, the 490°C+ fraction can be processed in a slurry or fluidized bed reactor. The 490°C+ stream contains some of the most difficult-to-process compounds in crude oil, including asphaltenes, metals, and Conradson carbon residue (CCR). In fixed-bed downflow reactors, conversion and catalyst run length are typically limited by the metal, CCR, and asphaltenes content in the residue feed, leading to rapid catalyst fouling and increased pressure drop. The embodiments described herein utilize upflow expanded bed reactors to overcome the pressure drop problem and allow the process to operate continuously for extended periods at high residue conversions. Therefore, the 490°C+ stream can be processed in a liquid circulating fluidized bed reactor, such as LC-FINING Technology, available from Lummus Technology LLC. Slurry reactor technology can also be used to process even heavier refinery streams, such as bitumen from solvent deasphalting machines.

[0148] In other embodiments, the heavy 490°C+ fraction can be recovered from the effluent of the first-stage fluidized bed or slurry bed reactor and processed in a solvent deasphalting (SDA) unit. The resulting deasphalted oil (DAO) from the SDA unit can be processed in a conditioning reactor, including, for example, a second slurry or fluidized bed reaction stage. If desired, the bituminous fraction can be upgraded to low-sulfur fuel oil conforming to IMO 2020 standards, thereby further increasing the value of the product.

[0149] The steam cracker comprising an ethylene complex that may be used in the 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 units such as olefin recovery units, butadiene extraction units, MTBE units, C4 selective hydrogenation units, pyrolysis gasoline hydrorefining units, aromatics extraction units, metathesis units, and / or disproportionation units for the production and recovery of olefins and other light hydrocarbons. Products from the ethylene complex may include, for example, ethylene, propylene, butadiene, benzene, MTBE, and mixed xylenes.

[0150] In some embodiments, the hydrocarbon stream to be cracked can be fed directly into a steam cracker. In other embodiments, the hydrocarbon stream to be cracked can be separated into multiple fractions for individual processing (cracking, e.g., at preferred temperatures, pressures, and residence times for each respective fraction).

[0151] Hydrocarbon feedstocks, which may be single hydrocarbons or mixtures of hydrocarbons, can be introduced into heating coils located in the convection section of a pyrolysis heater. In the heating coils, the hydrocarbon feedstocks can be heated and / or vaporized via convective heat exchange with the exhaust gas.

[0152] If necessary, the heated hydrocarbon feedstock can then be mixed with steam or an inert compound such as nitrogen, carbon dioxide, or any other inorganic gas. Various sections of the process or supplementary processes within the plant may use cryogenic or saturated steam, while other sections may use high-temperature superheated steam. Steam used in the process or elsewhere in the plant may be heated or superheated by heating coils (not shown) located in the convection zone of the pyrolysis heater.

[0153] The heated hydrocarbon mixture can then be fed into a heating coil, which can be positioned at a lower height within the pyrolysis heater, thus operating at a higher temperature compared to the convection zone heating coil described above. The resulting superheated mixture can then be fed into one or more coils located in the radiant zone of the pyrolysis heater, operating at temperatures used for partial conversion via the thermal cracking of the hydrocarbon mixture. The cracked hydrocarbon products can then be recovered.

[0154] In some embodiments, if desired, multiple heating and separation steps can be used to separate a hydrocarbon mixture to be cracked into two or more hydrocarbon fractions. This allows for optimal cracking of each fraction, enabling the yield, steam-to-oil ratio, heater inlet and outlet temperatures, and other variables to be controlled at desired levels to achieve the desired reaction outcomes, such as the desired product distribution, while limiting coking in the radiant coils and associated downstream equipment. Because the various fractions (based on the boiling points of the hydrocarbons in the various feed streams) are separated and cracked, coking in the radiant coils and delivery line exchangers can be controlled. Therefore, heater operating lengths can be increased to weeks rather than hours, while olefin yields also increase.

[0155] After a radiant coil ruptures, one or more transfer line exchangers can be used to very rapidly cool the products and generate (ultra) high-pressure steam. One or more coils can be combined and connected to each exchanger. The exchangers can be two-tube or multi-tube shell-and-shell exchangers.

[0156] Direct quenching can also be used instead of indirect cooling. In this case, oil can be injected at the outlet of the radiant coil. After oil quenching, water quenching can also be used. Alternatively, full water quenching is acceptable. After quenching, the product is sent to the recovery section.

[0157] As described above, the embodiments described herein can be used to convert heavier fractions of crude oil into high-value chemicals and minimize the amount sent to fuel oil pools, thereby increasing profitability. The fuel oil pools can also be upgraded to low-sulfur fuel oils that meet IMO 2020 standards, further increasing the value of the products.

[0158] Unless otherwise defined, all technical and scientific terms used shall have the same meaning as commonly understood by one of ordinary skill in the art to which these systems, devices, methods, processes and compositions pertain.

[0159] Unless the context clearly indicates otherwise, the singular forms “a”, “an”, and “the” contain plural indicators.

[0160] As used herein and in the appended claims, the words “comprising,” “having,” and “including,” and all their grammatical variations, are each intended to have an open, non-limiting meaning and do not exclude additional elements or steps.

[0161] "Optional" means that the event or situation described below may or may not occur. The description includes both scenarios in which the event or situation occurs and scenarios in which the event or situation does not occur.

[0162] When the terms “approximately” or “about” are used, the term may indicate a value that varies by up to ±10%, up to 5%, up to 2%, up to 1%, up to 0.5%, up to 0.1%, or up to 0.01%.

[0163] A range can be expressed as from about one particular value to about another particular value, including endpoints. When expressing such a range, it should be understood that another embodiment is from one particular value to another particular value, as well as all particular values ​​within the range and combinations thereof.

[0164] While this disclosure contains a limited number of embodiments, those skilled in the art who benefit from it will understand that other embodiments can be devised without departing from the scope of this disclosure. Therefore, the scope should be limited only by the appended claims.

[0165] Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily understand that many modifications may be made to the exemplary embodiments without materially departing from the invention. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined by the following claims. In the claims, any means-plus-function clause is intended to cover the structures described herein that perform the functions and equivalents of those structures. Similarly, any steps-plus-function clause in the claims is intended to cover the actions described herein that perform the functions and equivalents of those actions. The applicant expressly disclaims any limitation thereof imposed on any claim herein by Section 112(f) of 35 USC, except for those limitations imposed by the express use of “means for” or “steps for” and the associated functions.

Claims

1. A method for converting crude oil and other heavy hydrocarbon streams to produce olefins and / or aromatics, the method comprising: In the first integrated separation unit, the hydrocarbon feedstock is separated into at least a light-boiling fraction, a medium-boiling fraction, and a high-boiling residue fraction; The high-boiling residue fraction and pyrolysis oil are hydrocracking in a first regulating unit, which includes a residue hydrocracking system, to produce a hydrocracking effluent. At least a portion of the hydrocracking effluent is fed into a second conditioning unit to generate a steam pyrolysis feed stream; In the second regulating unit, the intermediate-boiling fraction is subjected to destructive hydrogenation to generate additional hydrocarbons in the steam cracker feed stream; The steam pyrolyzer feed stream and the light boiling fraction are fed into the steam pyrolyzer to convert the hydrocarbons therein, thereby producing the steam pyrolyzer effluent.

2. The method according to claim 1, further comprising feeding the pyrolyzer effluent to a pyrolyzer product recovery unit to generate a chemical product stream and a pyrolysis oil stream.

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

4. The method according to claim 1 or claim 2, wherein the intermediate-boiling fraction has two or more of the following properties: 5% boiling point temperature is in the range of about 130°C to about 200°C; 95% of the boiling point temperature is in the range of approximately 400°C to approximately 600°C; The hydrogen content is in the range of about 12% by weight to about 14% by weight; BMCI is in the range of approximately 5 to less than 50; API specific gravity ranges from approximately 10° to approximately 40°; The sulfur content is in the range of approximately 1,000 ppm to approximately 10,000 ppm; Nitrogen content ranges from about 1 ppm to about 100 ppm; Viscosity measured at 40°C is greater than 1 cSt; Less than 5% by weight of MCRT; and Total metals less than 50 ppm.

5. The method according to any one of claims 1 to 3, wherein the high-boiling residue fraction has two or more of the following properties: 5% boiling point temperature is in the range of about 400°C to about 600°C; Hydrogen content less than 12% by weight BMCI greater than 50; API weight is less than 10°; Sulfur content greater than 10,000 ppm; Nitrogen content greater than 100 ppm; Viscosity measured at 100°C is greater than 100 cSt; Greater than 5% by weight of MCRT; and Total metals greater than 50 ppm.

6. The method according to any one of claims 1 to 5, wherein destructive hydrogenation of the intermediate-boiling fraction and destructive hydrogenation of the hydrocracked effluent comprises destructive hydrogenation of the intermediate-boiling fraction and the hydrocracked effluent in a common destructive hydrogenation unit.

7. The method according to any one of claims 1 to 6, wherein destructive hydrogenation of the intermediate-boiling fraction and destructive hydrogenation of the hydrocracking effluent comprises: The intermediate-boiling fraction is subjected to destructive hydrogenation in the first destructive hydrogenation unit; The hydrocracking effluent is subjected to destructive hydrogenation in a second destructive hydrogenation unit; as well as The effluents from the first destructive hydrogenation unit and the second destructive hydrogenation unit are combined.

8. The method according to any one of claims 1 to 7, further comprising hydrodesulfurizing a second portion of the hydrocracking effluent to produce ultra-low sulfur fuel oil.

9. The method according to any one of claims 1 to 8, further comprising feeding a third portion of the hydrocracked effluent into [unit 21] to produce additional hydrocarbons in the hydrocracked effluent, waste gas stream, and heavy FCC oil stream.

10. The method according to any one of claims 1 to 9, further comprising recirculating the pyrolysis oil stream to the first regulating unit and generating additional hydrocracking effluent.

11. The method of claim 9, further comprising feeding the waste gas stream to the pyrolysis product recovery unit to generate additional chemical products and pyrolysis oil.

12. The method of claim 11, further comprising feeding at least a portion of the heavy FCC oil stream to a hydrodesulfurization step.

13. The method of claim 1, wherein the total chemical productivity of the feedstock is in the range of 60% to 85% by weight, based on the total amount of olefins produced relative to the total feedstock rate.

14. The method according to claim 1, wherein the residue hydrocracking reactor comprises a slurry bed reactor or a fluidized bed reactor.

15. The method of claim 8, further comprising bypassing a portion of the high-boiling-point residue fraction from the first regulating unit and feeding the bypassed portion of the high-boiling-point residue fraction to the hydrodesulfurization step.

16. The method of claim 2, further comprising feeding a portion of the pyrolysis oil to a hydrodesulfurization step.

Images