RU2799453C2 - Olefin and aromatic production configuration - Google Patents

Abstract

FIELD: oil production.

SUBSTANCE: invention relates to a process of converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics. The method includes separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction; hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy oil fraction; destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent; destructively hydrogenating the hydrocracked fraction of vacuum residues to obtain a second destructively hydrogenated effluent; mixing the first and second destructively hydrogenated effluents to form a mixture, and hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent; feeding the hydrotreated and hydrocracked effluent and the low-boiling fraction to at least one of the steam cracker and the aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO). The invention also concerns a system of converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics.

EFFECT: conversion of all crude oil, including heavier fractions of crude oil, into high-value petrochemical products.

22 cl, 7 dwg

Description

Field of invention

[0001] The embodiments described herein relate to methods and systems for producing petrochemicals such as olefins and aromatics from crude oil and low value heavy hydrocarbon streams.

State of the art

[0002] High-boiling compounds in crude oil can create major operational problems if sent to a steam cracker. High-boiling compounds tend to form coke largely due to their high asphaltene content. Consequently, high boiling compounds are typically removed before the lighter ends are sent to various oil production units such as a steam cracker or an aromatics complex. However, the removal process increases the capital cost of the entire process and reduces profitability, since the removed high boiling compounds can only be sold as low value heavy oil fuels. In addition, until now it has been a challenge to convert the vacuum residue without significant formation of heavy polycyclic aromatic compounds (HPNA) which are detrimental to downstream process steam cracker furnaces.

[0003] US Pat. No. 3,617,493 describes a process in which crude oil is sent to the convection section of a steam cracker and then to a separation zone where a portion of the feed boiling below about 450ºF is separated from the remainder of the feed and then sent with steam to a high temperature part of a steam cracker and exposed to cracking conditions.

[0004] US Pat. No. 4,133,777 describes a process in which feed oil first flows down in a thin jet stream through a fixed bed of hydrodemetalation (HDM) catalysts and then passes down through a fixed bed of promoted catalysts containing selected Group VI and Group VIII metals, with a very slight hydrocracking occurring in such a combined process.

[0005] US Pat. No. 5,603,824 discloses a process for upgrading a mixture of waxy hydrocarbon feedstocks containing sulfur compounds that boil in the distillate range to reduce the sulfur content and 85% temperature while maintaining the high octane number of the by-product naphtha and maximizing distillate yield. . This method uses a single downflow reactor having at least two catalyst beds and an interbed redistributor between the beds. The top layer contains a hydrocracking catalyst, preferably a beta-type zeolite, and the bottom layer contains a dewaxing catalyst, preferably ZSM-5.

[0006] US Pat. No. 3,730,879 discloses a two-layer catalytic process for the hydrodesulfurization of crude oil or a reduced fraction, in which at least 50% of the total pore volume of the catalyst of the first layer is pores with a diameter in the range of 100-200 angstroms.

[0007] US Pat. No. 3,830,720 discloses a two-layer catalytic process for hydrocracking and hydrodesulphurization of residual oils in which a fine pore catalyst is positioned above a large pore catalyst.

[0008] US Pat. No. 3,876,523 describes a novel catalyst and process for the catalytic demetallization and desulfurization of petroleum oils containing tailings. The process described uses a catalyst containing a hydrogenation component such as cobalt and molybdenum oxides supported on alumina. Although this catalyst is highly effective for tailings demetallization and has good stability over time in operation, its usefulness is greatly enhanced when this catalyst is used in a particular manner in combination with a second catalyst having different critical characteristics. A catalyst of the type described in US Pat. No. 3,876,523 will be referred to as the first catalyst, it being understood that this first catalyst should be placed upstream of a second catalyst having different characteristics.

[0009] U.S. Patent 4,153,539 discloses that improved hydrogen utilization and/or higher desired product conversions are obtained in hydrotreating or hydrocracking processes using amphora particles for light hydrocarbon hydrotreating, catalytic reforming, fixed bed alkylation, and the like.

[0010] US Pat. No. 4,016,067 discloses that petroleum oils, preferably tails, are catalytically hydrotreated to remove both metals and sulfur very efficiently, and with particularly slow aging of the catalyst system by contacting the petroleum oil sequentially with two different catalysts. characteristics. The first catalyst, located upstream of the second catalyst, has at least 60% of its pore volume in pores with a diameter greater than 100 Å and other characteristics discussed below. The second catalyst, downstream of the first catalyst, has a major proportion of its pore volume in pores less than 100 Å in diameter.

[0011] The dual catalyst apparatus of US Pat. No. 4,016,067 is used to demetallize and/or desulfurize any petroleum oil that has an undesirably high metal and/or sulfur content for a particular application. The dual catalyst apparatus is particularly effective for producing low metal and/or low sulfur feedstocks for catalytic cracking or coking. When refining to remove metals and sulfur, petroleum oil is also enriched with hydrogen at the same time, making it an even more suitable feedstock for any of these processes.

[0012] US Patent 10017702 discloses a process for thermal cracking of whole crude oil. The entire crude oil may be partially separated into a plurality of fractions and the individual fractions may be fed to the steam cracker through separate radiant coils.

[0013] US Patent Provisional Publication 2019-0023999 A1 discloses the separation of oil into light cuts and heavy cuts. The light cut is then fed to a steam cracker and the entire heavy cut is hydrotreated and/or hydrocracked.

[0014] In general, these and other prior art crude oil conversion processes typically convert less than 50% of the crude oil to more desirable end products, including, for example, petrochemicals such as ethylene, propylene, butenes, pentenes, and light aromatics. Typically, 20% of all crude oil is eliminated before processing, removing the heaviest components that are difficult to convert. Approximately another 20% of all crude oil is usually converted into pyrolysis oil and about 10% is processed into methane.

The essence of the invention

[0015] A process for converting an entire crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the method includes: separating the entire crude oil into at least a light-boiling fraction, a medium-boiling fraction, and a high-boiling residue fraction; hydrocracking the high-boiling residue fraction to form a hydrocracked effluent, and separating the hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy fuel oil fraction; destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent; destructively hydrogenating the hydrocracked fraction of vacuum residues to obtain a second destructively hydrogenated effluent; mixing the first and second destructively hydrogenated effluents to form a mixture, and hydrocracking the mixture to form a hydrotreated and hydrocracked effluent; and feeding the hydrotreated and hydrocracked effluent and the low-boiling fraction to at least one of the steam cracker and the aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra-low sulfur heavy fuel oil ( ULSFO).

[0016] A system for converting total crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the system includes: a separation system for separating the total crude oil into at least a light-boiling fraction, a medium-boiling fraction, and a high-boiling residue fraction; a hydrocracking unit for hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy fuel oil fraction; a first conditioning reactor for destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent; a second conditioning reactor for destructive hydrogenation of the hydrocracked vacuum residue fraction to produce a second destructively hydrogenated effluent; a mixer for mixing the first and second destructively hydrogenated effluents to form a mixture, and a hydrocracking unit for hydrocracking the mixture to form a hydrotreated and hydrocracked effluent; one or more process lines for supplying a hydrotreated and hydrocracked effluent and a low-boiling fraction to at least one of a steam cracker and an aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO).

[0017] Other aspects and advantages will be apparent from the description below and the appended claims.

Brief description of the drawings

[0018] FIG. 1 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0019] FIG. 2 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0020] FIG. 3 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0021] FIG. 4 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0022] FIG. 5 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0023] FIG. 6 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0024] FIG. 7 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

Detailed description

[0025] As used in the description, the term "petrochemicals" refers to hydrocarbons, including light olefins and diolefins and C ₆ -C ₈ aromatic compounds. Petrochemicals thus refer to hydrocarbons including ethylene, propylene, butenes, butadienes, pentenes, pentadienes, as well as benzene, toluene and xylenes. With respect to the subgroup of petrochemicals, the term "chemicals" as used herein refers to ethylene, propylene, butadiene, 1-butene, isobutylene, benzene, toluene, and para-xylenes.

[0026] Hydrotreating is a catalytic process, typically carried out in the presence of free hydrogen, whose main purpose, when used to process hydrocarbon feedstocks, is to remove various metallic contaminants (e.g., arsenic), heteroatoms (e.g., sulfur, nitrogen, and oxygen) from the feedstock and aromatic compounds. Typically, in hydrotreating operations, the cracking of hydrocarbon molecules (ie, the splitting of larger hydrocarbon molecules into smaller hydrocarbon molecules) is kept to a minimum. As used herein, the term "hydrotreating" refers to a refining process whereby a feed stream is reacted with hydrogen gas in the presence of a catalyst to remove impurities such as sulfur, nitrogen, oxygen and/or metals (e.g. nickel or vanadium) from a feed stream (eg bottoms of an atmospheric column) through recovery processes. Hydrotreating methods can vary significantly depending on the type of feedstock for the hydrotreating unit. For example, light feedstocks (eg, naphtha) contain very few and few types of impurities, while heavy feedstocks (eg, atmospheric column bottoms (ATB)) typically contain many of the different heavy compounds present in crude oil. In addition to the presence of heavy compounds, impurities in heavy feedstocks are more problematic and difficult to process than impurities present in light feedstocks. Consequently, light feedstocks are typically hydrotreated under less severe reaction conditions, while heavy feedstocks require higher reaction pressures and temperatures.

[0027] Hydrocracking refers to a process in which hydrogenation and dehydrogenation accompany the cracking/fragmentation of hydrocarbons, such as the conversion of heavier hydrocarbons to lighter hydrocarbons, or the conversion of aromatics and/or cycloparaffins (naphthenes) to non-cyclic branched paraffins.

[0028] "Conditioning" and like terms used herein refer to the conversion of hydrocarbons through one or both of the hydrocracking and hydrotreating processes. "Destructive hydrogenation" and similar terms refer to the splitting of hydrocarbon molecular bonds in the hydrocarbon and the concomitant saturation of the remaining hydrocarbon moieties with hydrogen, which can create stable lower boiling liquid petroleum products and can involve both hydrocracking and hydrotreating.

[0029] "API gravity" refers to the density of a crude oil or petroleum product relative to water, as determined by ASTM D4052-11.

[0030] Embodiments of the invention relate to methods and systems that take crude oil and/or low value heavy hydrocarbons as feedstock and produce petrochemicals such as light olefins and diolefins (ethylene, propylene, butadiene and/or butenes) and aromatic connections. More specifically, embodiments of the invention are directed to methods and systems for producing olefins and aromatics by thermally cracking preconditioned crude oil or condensate. The processes of the invention can condition the bottoms fraction of total crude oil and natural condensates to produce a feedstock suitable as a steam cracker feedstock.

[0031] The integration of conditioning, fractionation, and steam cracking can provide a highly efficient plant and, in some embodiments, can convert greater than 55%, greater than 60%, greater than 65%, greater than 70%, greater than 75%, greater than 80% or more than 85% of all crude oil into petrochemicals. In other embodiments, the integration of conditioning, fractionation, and steam cracking may result in a highly efficient plant and, in some embodiments, may convert greater than 55%, greater than 60%, greater than 65%, greater than 70%, greater than 75%, greater than 80 % or more than 85% of all crude oil into chemical products. Embodiments of the invention can thus provide systems and methods for conditioning feedstocks, including even the heaviest, most undesirable bottoms components, to components that can be vaporized and passed to the radiant section of a steam cracker, which greatly improves conversion over with low conversion of petrochemicals of the methods of the prior art.

[0032] Hydrocarbon mixtures useful in the embodiments disclosed in the invention may include various hydrocarbon mixtures having a certain boiling range, where the final boiling point of the mixture may be greater than 500°C, for example, greater than 525°C, 550° C or 575°C. The amount of high-boiling hydrocarbons, such as hydrocarbons boiling above 550°C, may be as low as 0.1% wt., 1% wt. or 2% wt., but can be up to 10% wt., 25% wt., 50% wt. or more. The description is explained in relation to crude oil, such as all crude oil, but any hydrocarbon mixture with a high final boiling point can be used. However, the methods described in the invention can be applied to crude oils, condensates and hydrocarbons with a wide boiling curve and final boiling points above 500°C. Such hydrocarbon blends may include whole crude oil, crude crude oil, hydrotreated crude oil, gas oil, vacuum gas oil, heating oil, jet fuel, diesel fuel, kerosenes, gasolines, synthetic naphtha, reformer raffinates, Fischer-Tropsch fluids, Fischer-Tropsch gases , natural gas gasolines, distillates, straight-run naphtha, natural gas condensates, atmospheric tubular bottoms, vacuum tube streams including bottoms, wide boiling range naphtha to gas-oil condensates, indirect-run heavy hydrocarbon streams from refineries, vacuum gas oil, heavy gas oils , atmospheric residues, hydrocracking wax and Fischer-Tropsch wax, among others. In some embodiments, the hydrocarbon mixture may include hydrocarbons boiling from naphtha or lighter to vacuum gas oil or heavier.

[0033] When the final boiling point of the hydrocarbon mixture is high, for example, above 550°C, the hydrocarbon mixture cannot be processed directly in the steam pyrolysis reactor to produce olefins. The presence of such heavy hydrocarbons results in the formation of coke in the reactor, which coking may occur in one or more preheat or convection zone superheat coils, radiant coils, or pump line heat exchangers, and such coking may occur rapidly, for example, within a few hours. All crude oil is generally not industrially cracked as it is not economical to do so. It is usually fractionated and only certain fractions are used in the steam pyrolysis heater for the production of olefins. The rest is used in other processes. The cracking reaction proceeds according to the free radical mechanism. Therefore, a high yield of ethylene can be achieved by cracking at high temperatures. Lighter feedstocks such as butanes and pentanes require a high reactor temperature to obtain a high yield of olefins. Heavy feedstocks such as gas oil and vacuum gas oil (VGO) require lower temperatures. Crude oil has a distribution of compounds from butanes to VGO and residue (a material having a normal boiling point above 550°C). Exposure of all crude oil, without separation, to high temperatures produces a high yield of coke (a by-product of hydrocarbon cracking under very severe conditions) and clogs the reactor. The steam pyrolysis reactor must be periodically shut down and the coke cleaned by steam/air decoking. The time between two purification periods when olefins are produced is referred to as cycle time. When crude oil is cracked without separation, coke can settle on the convection section coils (which evaporate the liquid), in the radiant section (where olefins are formed) and/or in the pump line heat exchangers (where the reactions are quickly stopped by cooling to preserve the olefins yield).

[0034] Methods and systems in accordance with the embodiments described herein may include a feed preparation section, a crude oil conditioning section, an aromatics production complex, and a steam cracker. The raw material preparation section may include, for example, a desalination plant.

[0035] The desalted oil is then conditioned and processed so as to send the cracked feedstock to a steam cracker and/or an aromatics complex. The conditioning section can allow the operator to maximize chemical output while maintaining a reasonable frequency of decoking in the furnaces. Another objective of the crude oil conditioning unit is to ensure complete or substantially complete (95%+) conversion of asphaltenes to lower boiling point components, which increases the yield of chemical products, while reducing the formation of heavy polycyclic aromatic compounds (TPACs).

[0036] Methods in accordance with embodiments of the invention can thus convert heavier fractions of crude oil into high value petrochemicals and can minimize the amount of hydrocarbons sent to the HFO reservoir, which greatly improves profitability. The resulting HFO in a small tank can also be upgraded to IMO 2020 compliant low sulfur fuel oil, further adding value to the products.

[0037] As noted above, high-boiling compounds in crude oils can create major operational problems if sent to a steam cracker due to their propensity to form coke, especially due to their high asphaltene content. Consequently, high boiling compounds are typically removed before the lighter ends are sent to various refinery units such as the steam cracker and the aromatics complex. The removal process increases the capital cost of the entire process and reduces profitability, since the removed high boiling compounds can only be sold as low value heavy oil fuels. In addition, it is currently a problem to convert the vacuum residue without significant formation of TPAS, which are detrimental to the furnaces of the downstream steam cracker. Methods and systems in accordance with embodiments of the invention can overcome these problems.

[0038] The configurations of systems and methods for converting all crude oil and heavy hydrocarbons in accordance with the embodiments described in the invention can effectively handle the conversion of vacuum residues, while minimizing the conversion of petrochemicals and maintaining a lower tendency to coke in a steam cracker . This is achieved by integrating the vacuum residue hydrocracking reactor into the oil conditioning process, which makes it possible to convert high-boiling compounds into lighter components. In various embodiments, vacuum residue hydrocracking units according to embodiments of the invention may include fixed bed vacuum residue hydrocracking units, fluidized bed vacuum residue hydrocracking reactors, such as slurry bed vacuum residue hydrocracking reactors.

[0039] Upgraded crude oil streams from an oil conditioning unit, such as a fixed bed crude oil conditioning unit, and from a hydrocracking unit are suitable feedstocks for a steam cracker as well as an aromatics complex. This can lead to lower overall process yields of low value HFOs and higher yields of high value olefins and aromatics such as benzene, toluene and xylenes (BTX).

[0040] Separation of various fractions, such as a low boiling fraction (for example, 160°C-fraction), a medium-boiling fraction (for example, 160-490°C fraction) and a high-boiling fraction (for example, 490°C+ fraction), can improve the efficiency of capital and operating costs of the methods and systems described in the invention. With regard to the three cuts in many embodiments of the invention, the authors of the present invention recognize that condensates, having, as a rule, a small amount of high boiling components, and all crude oil, having a large amount of high boiling components, can be processed differently. Accordingly, in the case of a wide boiling range petroleum feedstock, one, two, three or more separate cuts can be obtained, and each cut can be processed separately under optimal conditions.

[0041] The separation of all crude oil into the desired fractions can be performed using one or more separators (distillation columns, flash tanks, etc.). In some embodiments, separation of the crude oil may be carried out in an inline separation device (ISD), such as the device disclosed in US 2013/0197283, which is incorporated herein by reference. In the WSP, in order to separate the desired vapor fraction from the liquid, the initial separation of the low-boiling fraction is carried out in the WSP based on a combination of centrifugal and cyclone effects. An additional separation step can then be used to separate the medium boiling fraction from the high boiling components.

[0042] As a rule, hydrocarbon components boiling above 490°C contain asphaltenes and Conradson carbon residue, and therefore must be processed accordingly, as also described below. Although embodiments of the invention are described as including a fraction below about 90-250°C, such as a 160°C-fraction, and a fraction above about 400-560°C, such as a 490°C+ fraction, it is noted that the actual boiling ranges of the fractions may be changed depending on the type of total crude oil or other processed heavy fractions. For example, for crude oils having a low metal or nitrogen content, or a large amount of "easy processing" components, boiling, for example, at temperatures up to 525°C, 540°C or 565°C, it may be possible to increase the medium/high boiling range fraction, while still achieving the positive effects of embodiments of the invention. Likewise, the lower/middle boiling point of the fraction can reach up to 220°C in some embodiments, or up to 250°C in other embodiments. In addition, it has been found that a lower/mid cut cut of about 160° C. can provide an advantage in sizing and operating reactors, such as a fixed bed conditioning reactor, for conditioning middle cut hydrocarbons (middle cut). In addition, for certain feedstocks, such as condensates, the lower/middle boiling range of the fraction can be up to 565°C. The ability to vary the boiling ranges of the fractions can add flexibility to process flowsheets in accordance with embodiments of the invention, allowing a wide range of feedstocks to be processed to produce the desired mixture of products.

[0043] Thus, in some embodiments, the light cut may include hydrocarbons having a boiling point 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, about up to 190°C, up to approx. 200°C, up to approx. 210°C, up to approx. 220°C, up to approx. 230°C, up to approx. 240°C, up to approx. 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. Embodiments of the invention also contemplate a light cut which is hydrocarbons having boiling points up to temperatures intermediate between the aforementioned ranges.

[0044] Depending on the fractionation mechanism used, the light hydrocarbon "cut" may be relatively pure, which means that the light fraction may not have any significant amount (>1% wt., as used herein) of compounds boiling above expected target boiling point. For example, a 160°C- cut may not have any significant amount of hydrocarbon compounds boiling above 160°C (ie, >1% wt.). In other embodiments, the intended target "cutoff" temperatures may be 95% initial boiling point, or in other embodiments, 85% initial boiling point, such as measured using ASTM D86 or ASTM D2887, or, for example, at True Boiling Point (TBP) analysis according to ASTM D2892, or ASTM D7169 for heavy streams such as streams boiling above about 400°C. In such embodiments, the implementation in this case may be up to 5% of the mass. or up to 15% of the mass. compounds above the expected temperature of the “cutting edge of the fraction”. For many types of all crude oils, the lower/middle boiling point of the fraction may be such that the light fraction has a 95% initial boiling point in the range of approximately 90 to 250°C. For other feedstocks, however, such as condensate, the low boiling point may have a 95% initial boiling point, for example, in the range of about 500 to 565°C.

[0045] In some embodiments, the implementation of the average cut may include hydrocarbons having a boiling point from the lower limit at the upper temperature of the light cut (for example, 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 hydrocarbons having a boiling point 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, about up to 520°C, up to about 540°C, up to about 560°C or up to about 580°C. As used in the description, for example, a middle cut having a lower limit of 160°C and an upper limit of 490°C may be referred to as a cut or fraction from 160 to 490°C. Embodiments of the invention also contemplate a middle cut which is hydrocarbons having boiling points from and/or up to temperatures intermediate between the aforementioned ranges.

[0046] Depending on the fractionation mechanism, the hydrocarbon "cut" in the case of the middle cut may be relatively pure, which means that the middle cut may not have any significant amount (>1% wt.) compounds boiling below, and / or may not have any significant amount (>1% wt.) compounds boiling above the boundaries of the intended target boiling points. For example, a 160 to 490°C cut may not have any significant amount of hydrocarbon compounds boiling below 160°C or above 490°C. In other embodiments, the intended target "cut" temperatures noted above may be 5% (wt.) or 15% (wt.) the initial boiling point at the lower boundary and / or 95% or 85% - the initial boiling point at the upper limit, which can be measured using ASTM D86 or ASTM D2887, or, for example, in the analysis of true boiling point (TBP) in accordance with ASTM D2892, or ASTM D7169 for heavy flows, such as streams boiling above about 400°C. In such embodiments, the implementation in this case may be up to 5% of the mass. or up to 15% of the mass. compounds above and/or below the temperature of the "cutting edge of the fraction", respectively.

[0047] In some embodiments, the heavy cut may include hydrocarbons having a boiling point above about 350°C, above about 375°C, above about 400°C (e.g., a 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 (eg, fraction 600°C+) or above about 700°C. Embodiments of the invention also contemplate a heavy cut which is hydrocarbons having boiling points above temperatures intermediate to the aforementioned temperatures.

[0048] Depending on the fractionation mechanism, the heavy hydrocarbon "cut" may be relatively pure, which means that the heavy fraction may not have any significant amount (>1 wt %) of compounds boiling below the intended target boiling point. For example, a 490°C+ cut may not have any significant amount of hydrocarbon compounds boiling below 490°C. In other embodiments, the intended target "cutoff" temperatures noted above may be 95% initial boiling point, or in other embodiments, 85% initial boiling point, for example, which may be measured using ASTM D86 or ASTM standards. D2887, or, for example, true boiling point (TBI) analysis according to ASTM D2892, or ASTM D7169 for heavy streams, such as streams boiling above about 400°C. In such embodiments, the implementation in this case may be up to 5% of the mass. or up to 15% of the mass. compounds, respectively, below the temperature of the “cutting edge of the fraction”.

[0049] Although the following are examples of relatively limited temperature ranges, it is believed that any of the temperature ranges provided above can be used in the methods described in the invention. In addition, with regard to the boiling ranges of the fractions, the ranges indicated below in the examples may be exact as described above, or may refer to 5% or 15% boiling points for the lower limits, or may refer to 85% - or 95% boiling points for the upper limits.

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

[0051] The middle range hydrocarbon cut may be conditioned using one or more fixed bed reactors, such as hydrotreating and/or hydrocracking reactors, each of which can destructively hydrogenate the hydrocarbons in the middle cut. Conditioning reactors may include catalysts for metal removal, sulfur removal and nitrogen removal, and conditioning in these reactors may result in adding hydrogen to the hydrocarbon components, facilitating their processing downstream to produce petrochemicals. Fixed bed catalyst systems in the middle draw conditioning zone, for example, may contain different beds of demetallization catalysts, destructive hydrogenation catalysts, and mesoporous zeolite hydrocracking catalysts to optimize the conversion of heavy materials to a balance between a highly paraffinic stream that is acceptable for olefin production and rich in aromatics. a stream that is suitable for the production of aromatic compounds.

[0052] In some embodiments, it may be desirable to further separate the middle cut into a lower middle cut and an upper middle cut. For example, a middle draw having a boiling range of 160 to 490°C can be divided into a lower middle draw having a boiling range of about 160 to 325°C and an upper middle draw having a boiling range of about 325 to 490 °C. Therefore, the conditioning lines can be configured to more selectively convert the hydrocarbon components in their respective lower and upper middle cuts to the desired conditioned effluents, where each line can be configured to destructively hydrogenate the hydrocarbons therein based on preferred catalysts, sizing the reactor for expected feed volumes and catalyst life; and operating conditions to achieve the desired conversion in the naphtha-containing steam cracker feedstock. Similarly, the division of the middle shoulder strap into three or more sub- shoulder straps is also implied.

[0053] Heavy cut hydrocarbons can also be conditioned using one or more fixed bed, slurry, or fluidized bed reactors. Conditioning of the heavy end product, such as 490°C+ hydrocarbons, can be carried out, for example, in a residue hydrocracker and can enhance the conversion of low value streams to high value refined products through steam cracking. Hydrocracking of vacuum residues can be carried out, for example, in a fixed bed hydrocracking unit, in a fluidized bed reactor such as the LC-FINING or LC-MAX reactor system, and in slurry reactors such as LC-SLURRY reactors, each of which available from Chevron Lummus Global. However, it is recognized that the lifetime of destructive hydrogenation and/or hydrocracking catalysts can be adversely affected by heavier components, for example when the feedstock includes components boiling above 565°C. Similarly to the middle shoulder strap, the division of the heavy shoulder strap into one or more sub- shoulder straps is also implied.

[0054] The crude oil conditioning section, including conditioning of medium and heavy fractions, is intended to achieve four (4) objectives. First, the crude oil conditioning section can be used to increase the concentration of paraffins and naphthenes in the crude oil. Secondly, the conditioning section can reduce the concentration of polycyclic aromatic hydrocarbons (PAS (PNA)) in the crude oil. Thirdly, the conditioning section can lower the end boiling point (FBP) of the crude oil to below 540ºC. And fourth, the conditioning section can minimize the vacuum residue fraction of the crude oil.

[0055] Embodiments of medium and heavy fraction conditioning may focus on converting heavier hydrocarbons to produce, for example, hydrocarbons lighter than diesel fuel. Destructive hydrogenation catalysts and operating conditions can thus be chosen to direct the conversion of hydrocarbons or hydrocarbons in appropriate fractions predominantly (>50% wt.) to hydrocarbons of the naphtha range, for example, to more than 60% wt. hydrocarbons of the naphtha range, or, for example, up to more than 70% of the mass. hydrocarbons of the naphtha interval. The use of catalysts and operating conditions in the conditioning section to target lighter hydrocarbon products can improve the processability of the steam cracker and increase the production of petrochemicals.

[0056] In some embodiments, conditioning a heavy headstock, such as a 490°C+ headstock, may result in a conversion of at least 70% of the mass. compounds boiling over 565°C into lighter-boiling compounds. Other embodiments may result in a conversion greater than 75% wt., greater than 80% wt. or more than 85% of the mass. compounds boiling over 565°C into lighter-boiling compounds.

[0057] In some embodiments, conditioning the middle headstock, such as the headstock from 160 to 490°C, may result in a conversion of greater than 50 wt%. hydrocarbons in it into hydrocarbons of the naphtha interval. In other embodiments, conditioning the middle headstock may result in a conversion of greater than 55 wt. %, greater than 60 wt. %, greater than 65 wt. %, or greater than 70 wt. hydrocarbons in it into hydrocarbons of the naphtha interval.

[0058] In some embodiments, the co-conditioning of the middle and heavy ends may result in a total conversion greater than 50% by weight. hydrocarbons in them into hydrocarbons of the naphtha interval. In other embodiments, conditioning the middle and heavy ends may result in a conversion of greater than 55% by weight, greater than 60% by weight. or more than 65% of the mass. hydrocarbons in them into hydrocarbons of the naphtha interval.

[0059] As a result of these initial separations and conditioning, in some embodiments, the steam cracker feedstock can be fed directly to the steam cracker without further processing. A light cut having preferred properties including one or more boiling points, API gravity, BMCI, hydrogen content, nitrogen content, sulfur content, viscosity, MCRT, or total metals, in some embodiments, after separations, can be sent directly to the steam cracker. The effluents from middle bottom conditioning according to embodiments of the invention may also be fed directly to a steam cracker. Likewise, in some embodiments, the effluents from the heavy end conditioning may be fed directly to the steam cracker.

[0060] Conditioning the appropriate fractions, as described in the invention, can operate a steam cracker, even when processing multiple feeds with varying boiling ranges, for an extended period of time. In some embodiments, the steam cracker may be capable of operating for a continuous operating cycle of at least three years, in other embodiments, at least four years, and in still other embodiments, at least five years. .

[0061] In addition, initial hydrocarbon boiling point limits, reactor sizes, catalysts, etc. can be adjusted or selected so that the operating time of the steam cracker and the conditioning processes can be synchronized. Catalysts, reactor sizes and conditions can be selected so that the period of operation of the conditioning unit is synchronized with the period of operation of the steam cracker. Catalyst volumes, catalyst types, and severity of reaction conditions can all play a role in determining the run times of the conditioning unit. In addition, the degree of conditioning of the heavier hydrocarbons in the crude oil can affect coking in the thermal steam cracker. To maximize uptime, in embodiments, the design and configuration of the entire system is designed such that the air conditioning system has the same expected run time as a steam cracker for a given feedstock or range of feedstocks to be considered. In addition, the embodiments involve adjusting the reaction conditions (T, P, space velocity, etc.) in the conditioning section and/or steam cracker depending on the feedstock being processed so that the period of operation of the conditioning section and the steam cracker is comparable or synchronized.

[0062] Synchronization of periods of operation can lead to minimal downtime, for example, when the replacement of the catalyst in the conditioning reactor is carried out simultaneously with the decoking of the steam cracker. When the air conditioning system includes multiple reactors or types of reactors, the timing of the periods of operation may be based on the expected throughput of the steam cracker. In addition, when, for example, the hydrotreater may have a substantially longer run time than the hydrocracking unit in the conditioning section, parallel reactor lines and/or bypass processing may be used so that the overall run times of the conditioning and steam cracking units can be synchronized.

[0063] Bypass processing may include, for example, temporary processing of a heavy (eg, 490° C.+) cut in a reactor that typically processes a lighter feedstock, such as a middle cut or heavy cut cut. Heavier feedstocks are expected to have harsher conditions and shorter catalyst life, and therefore, temporary processing of heavier components in the mid-range hydrocarbon conditioning reactor during heavy component catalyst replacement can allow all of the crude oil to be continuously fed to steam cracking. - installation without shutdown, at the same time replacing the catalyst of the reactor for conditioning heavy components. When designing the entire system to synchronize operation periods, the configuration of the middle fraction conditioning reactors can also take into account the expected bypass processing.

[0064] Recognizing that fixed bed conditioning can be detrimental to the low-boiling cuts of some feedstocks, it may be desirable to conduct the initial separation so that the heavier components are conditioned for feed to the steam cracker while the lighter components already acceptable for feeding into the steam cracker is not further conditioned. FIG. 1 shows a simplified process flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0065] A hydrocarbon feed with a wide boiling range, such as desalted oil 1, may be fed into the separation system 3. The separation system 3 may be, for example, an inline separation device (ISD) described above, and including separation and thermal integration. In the separation system 3, the desalinated oil 1 can be separated into three fractions, including: (a) a light cut, such as 160°C - fraction 5, which does not require any conditioning and can be used as feed for the steam cracking section - unit 7, (b) a middle draw, such as a 160-490° C. fraction 9, which can be upgraded in the conditioning section 11 to produce lighter hydrocarbons, such as a highly paraffinic stream 13, suitable for processing in the steam cracker section 7; and (c) a heavy cut, such as the 490°C+ cut 15, which contains the most refractory materials in the crude oil and which can be upgraded in the residue hydrocracker 17. Other boiling point temperatures can also be used to direct the desired cuts and hydrocarbons to the desired conditioning and/or steam cracking units. The residue hydrocracking unit can produce an ultra low sulfur heavy oil fuel 19 and a stream 21 that is suitable for feeding into the conditioning system for post-conditioning and for producing additional hydrocarbons suitable for conversion to petrochemicals in the steam cracker section 7. The unit may produce one or more petrochemical product streams 23 such as ethylene, propylene and butenes, among others, as well as a higher-boiling pyrolysis oil fraction 25.

[0066] In some embodiments, a middle cut, such as a 160-490°C stream, may be first processed in a fixed bed destructive hydrogenation reactor 27. The 490°C+ stream may be processed in a residue hydrocracking reactor system 17, which may include one or more reactors, for example, using a fluidized bed extrudate catalyst or catalyst slurry, which converts some of the hydrocarbons into lighter hydrocarbons, such as 490° C. hydrocarbons. Additional lighter hydrocarbons may be processed in a fixed bed destructive hydrogenation reactor, which may be the same reactor used to condition the middle draw, or, as shown, a separate fixed bed destructive hydrogenation reactor 29, which may contain a catalyst designed to efficient conditioning of singly converted hydrocarbons obtained from residue hydrocracking. Reaction products 31, 33 from hydrotreated middle drawdown (for example, 160-490°C stream 9) and hydrotreated lighter material (for example, 490°C - vacuum residue hydrocracking effluent), respectively, from destructive fixed-bed hydrogenation reactors 27, 29 can then be combined and co-processed in a fixed bed hydrocracking reactor 35 to produce a feedstock 13 suitable for processing in the steam cracker section 17 for conversion to light olefins and other valuable oils. The unconverted portion of the vacuum residue hydrocracking reactor effluent may be processed, for example, in a fixed bed hydrodesulfurization unit (not shown) to produce ultra low sulfur heavy oil fuel (ULSFO).

[0067] In some embodiments, conditioning reactors 27 and 29 may include destructive hydrogenation catalysts (first conditioning stage), while conditioning reactors 35 include hydrocracking catalysts (second conditioning stage). In addition, the first conditioning stage may, in some embodiments, include catalysts designed to reduce polycyclic aromatic hydrocarbons, thereby conditioning the feedstock for easier processing in the steam cracker.

[0068] FIG. 2 is a simplified flow diagram of a whole crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention, where like reference numbers refer to like parts. In this embodiment, the desalted whole crude oil 1 is processed in the same manner as described above for FIG. 1. In this embodiment, a heavy cut such as 490°C+ stream 15 and pyrolysis oil stream 25 are combined and processed in the vacuum residue hydrocracking reactor(s) to convert some of the hydrocarbons in the streams to 490°C- hydrocarbons, which are also processed in a fixed bed destructive hydrogenation reactor 29.

[0069] As described above, destructive hydrogenation reactors 27, 29 can be used to condition the middle draw, such as 160-490°C stream 9, and the effluent (such as 490°C-) stream 21 from the vacuum bottoms hydrocracking system 17. In some embodiments, the streams may be processed in the same destructive hydrogenation reactor. However, it has been found that due to the nature of the feed compounds for different types of crude oils, processing in a single reaction line can result in a stream with molecules that contain more aromatic rings than molecules in the straight-run fraction of Arab Light or Arab Extra Light crude oils, including same boiling range. As a result, more stringent hydrotreating conditions may be necessary to sufficiently saturate the molecules, which has a negative impact on hydrotreating catalyst life and/or capital investment. If previously converted materials in stream 21 are co-processed with straight-run middle end material in stream 9, the cycle time for a single destructive hydrogenation line may fall below the cycle time of the steam cracker section and/or a spare destructive hydrogenation line will be required to ensure a steady flow of feed to the steam cracking section while the destructive hydrogenation catalyst system is being regenerated and/or replaced. The above also applies to other types of crude oil such as desalted oil, condensate, biogenetic oil, synthetic oil, tight oil, heavy hydrocarbons, recovered crude oil and bitumen derived oil.

[0070] To alleviate catalyst life/cycle time issues, the fixed bed destructive hydrogenation step can be separated into separate lines as shown in FIG. 1 and 2. One line may be provided to process straight-run middle cut (eg 160-490°C) crude oil and a second line may be provided to process (eg 490°C-) effluent from the hydrocracking reactor(s). vacuum residues. Typically, the reactors 27 in the first destructive hydrogenation stage may have cycle times longer than those of the steam cracker furnace, and a spare reactor may not be required to maintain continuous operation. Second line reactors 29 may have more frequent turnaround times for catalyst replacement, but their feed could be diverted to the first line via flow line 37 during catalyst change, so they would also not require a spare reactor line for continuous operation. Due to the temporary diversion of feedstock, the impact on the reactor line 27 will be minimal, and therefore the reactor lines 27 can be designed such that their repair periods can be synchronized with the repair periods of the steam cracker furnaces.

[0071] As noted above, different feedstocks may allow for an increase in the boiling range of the fractions, for example, in some embodiments, the implementation of an increase in the average/high boiling range of the fraction from 490 to 545°C. The same may be true of the hydrocracking treatment of vacuum residues, where the higher boiling hydrocarbons may possibly be fed into a destructive hydrogenation reactor to be converted into a feedstock suitable for steam cracking. However, regarding the processing of a high boiling fraction (e.g. 490°C+ or 545°C+ fraction) in a vacuum bottoms hydrocracking system, it has been found that a lower fraction boiling point may be more optimal, since too high boiling points may require the use of a distillate oil to produce ULSFO category fuel.

[0072] FIG. 3 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0073] A heavy hydrocarbon feed with a wide boiling range, such as desalted oil 10, may be fed into separation system 12. Separation system 12 may be, for example, an inline separation device (ISD) as described above. In the separation system 12, the desalinated oil 10 can be separated into three fractions, including: (a) a light cut, such as 160°C - fraction 14, which does not require any conditioning and can be used as feed for the steam cracking section - installation 16 and the site of the complex for the production of aromatic compounds 18; (b) a middle cut, such as a 160-490° C. cut 20, which can be upgraded in the fixed bed conditioning section 22 to produce two types of lighter streams, including a waxy stream 24 suitable for steam cracking system 16, which can produce a light olefins stream 46, and an aromatics-enriched stream 26 that is suitable for aromatics production, which can produce an aromatics stream 36 that can include benzene and para-xylenes; and (c) a heavy cut, such as the 490° C.+ cut 28, which contains the most refractory materials in the crude oil, which can be upgraded in the fluidized bed vacuum residue hydrocracker 30. Other boiling point temperatures can also be used to direct the desired cuts. and their hydrocarbons to the desired conditioning and/or cracking units. The fluidized bed vacuum residue hydrocracking unit can produce, for example, ultra-low sulfur heavy fuel oil 32 and a stream 34 that is suitable for feeding into a fixed bed conditioning system to produce the above two streams (steam cracker feed 24 and aromatics complex feed). 26). As noted above, streams 20 and 34 may be processed in separate conditioning lines to advantageously provide similar catalyst and steam cracker operating cycles.

[0074] Other low-value refinery streams may also be processed in accordance with embodiments of the invention to ultimately produce higher value products. Such streams include some or all of the following types of hydrocarbons: (i) light cycle oil (LCO), such as FCC-produced LCO, which may be fed through flow line 40 and processed in an oil conditioning system with a fixed bed 22 together with a middle cut, such as 160-490° C. fraction 20; (ii) a heavy catalytic cracking residue, such as a heavy catalytic cracking residue obtained from an FCC unit, which can be fed through flow line 42 and processed in fluidized bed reactor 30 along with a heavy cut, such as 490° C.+ hydrocarbons, in stream 28 ; (iii) pitch, such as pitch obtained from the solvent deasphalting unit, which may be fed through the same or different production line 42 and processed in the fluidized bed reactor 30 along with a heavy end product (such as 490°C+ hydrocarbons), in a stream 28; and/or (iv) a pyrolysis heavy fuel (Pyoil) such as a pyrolysis heavy fuel obtained from a steam cracker, including a pyrolysis heavy fuel stream 44 from a steam cracker 16, and this stream can be processed in a reactor fluidized bed 30 along with heavy end product (e.g., 490°C+ hydrocarbons) in streams 28 and/or 42. Various other hydrocarbon streams with similar boiling ranges can also be co-processed to produce petrochemicals in the systems described in the invention, where such streams may include light naphtha, heavy naphtha, crude oil, atmospheric residues, vacuum residues, synthetic crude oil, and other hydrocarbon streams containing heavy hydrocarbons.

[0075] After conditioning with a fixed bed of the middle cut fraction from stream 20, the effluent of the vacuum bottoms hydrocracking system 30 and/or LRG from stream 40 in the line(s) of the fixed bed conditioning reactor 22, the effluent(s) 48 of the reactor may/may be fed to a separation system 50, such as a VUR, to recover a light fraction 52 suitable for processing in a steam cracker 16 and an aromatics processing unit 18, as well as a heavy fraction 54. Heavy fraction 54 may be fed into the vacuum residue hydrocracking system 30 to continue processing and conversion to lighter hydrocarbons such as 490° C. compounds. In some embodiments, separator 50 may produce a light cut 52 having a fraction boiling point in the range of about 160 to 220°C and produce a heavy cut 54 having a corresponding lower cut cut, such as 160°C+ or 220°C+ hydrocarbons.

[0076] Similarly, after processing a heavy end product such as a 490° C.+ cut 28 in a vacuum bottoms hydrocracker 30, the vacuum bottoms hydrocracker reactor effluent 60 may be fed to a separation system 62, such as a VUR, to recover the low-boiling cut 34, containing reformates suitable for processing in a fixed bed conditioning system 22; and a heavy fraction 64. The heavy fraction 64 may be fed to an inline hydrotreater or hydrodesulfurization reactor 66 to produce a ULSFO stream 32. In some embodiments, separator 62 may produce a light fraction 34 having a fraction boiling point in the range of approximately 490 to 520° C. and give a heavy cut 64 having a corresponding fraction boiling point, eg 490° C.+ hydrocarbons.

[0077] Light naphtha fractions 14 may be fed to a separator 58 to separate components, for example into a light naphtha fraction 24 and a heavy naphtha fraction 26. how components of the heavy naphtha range can be processed, for example, in the complex for the production of aromatics 18 to obtain benzene, toluene and xylenes.

[0078] In some embodiments, the heavy naphtha cut 26 may be treated upstream of the aromatics complex 18, such as with a hydrogen sulfide scrubber (not shown), to further prepare the feed for conversion in the aromatics complex. Similarly, the pyrolysis oil stream 44 may be subjected to a pyrolysis oil stabilization step (corresponding flowchart not shown) prior to processing in a vacuum residue hydrocracking reactor.

[0079] As briefly described above, embodiments of the invention can allow direct cracking of crude oil to petrochemicals to form light hydrocarbons such as ethylene, propylene, and light aromatics in a cost-effective manner without the need to go through conventional purification steps. In addition, the direct conversion of crude oil to petrochemicals could help close the growing gap between supply and demand for key building blocks commonly produced as by-products (propylene, butadiene) through a growing shift towards cracking of lighter feedstocks caused by the shale revolution. gas.

[0080] The integration of processing units in accordance with embodiments of the invention can provide a unique opportunity to upgrade all crude oils, such as Arab Light oil and Arab Extra Light oil, together with low-value refinery streams, such as pyrolysis oil (PyOil) ), heavy catalytic cracking residue and light cycle oil (LRG (LCO)), to more valuable petrochemicals. Although feed conditioning in accordance with embodiments of the invention adds hydrogen to the feedstock components, and hydrogen consumption is an additional cost to the plant, the overall benefits of producing petrochemicals rather than fuels outweigh these additional costs. The above also applies to other types of crude oil such as desalinated oil, condensate, biogenetic oil, synthetic oil, tight oil, heavy hydrocarbons, recovered crude oil and bitumen derived oil.

[0081] In various embodiments, an optional aromatics production complex may be included, as noted above. For example, an aromatics complex can be used to convert the 160-490° C. fraction or a portion thereof into aromatics. For example, a cut, such as a 160 to 240°C cut, may be processed to convert some of its hydrocarbons to aromatics, while the heavy components may be sent to a steam cracker for conversion to petrochemicals. The aromatics complex feed obtained through initial processing and conditioning in accordance with embodiments of the invention may allow various processors to stop importing crude naphtha (FRN).

[0082] In addition, in some embodiments, the pyrolysis oil produced in the steam cracker may be separated to recover a pyrolysis gasoline fraction and one or more heavy component fractions such as a pyrolysis gas oil fraction and a pyrolysis heavy fuel fraction. The lighter cut of the pyrolysis gasoline can be fed to the aromatics unit, while the heavier cuts can be used to produce the ULSFO grade fuel as noted above.

[0083] The embodiments described in the invention offer a strategic combination of crude oil treatment, crude oil separation, crude oil conditioning, and steam cracking technology to maximize the yield of high value petrochemicals. The crude oil conditioning section uses a combination of fixed bed circulating fluid hydrotreatment and fluidized bed or slurry bed hydrocracking to condition crude oil into a suitable steam cracker feed and upgrade low value refinery streams. Embodiments of the invention can provide, for example, the yield of petrochemical products in the range from 60 to 90% based on the entire original crude oil.

[0084] As described above, after desalting, the oil can be separated into three cuts, including: a light cut (such as a 160°C-flow), which can then be further divided into 90°C- and 90-160°C cuts for supply to the heater of the steam cracker and the complex for the production of aromatic compounds, respectively; middle cut (such as 160-490° C. flow); and heavy duty (such as 490°C+ flow). A light cut (such as a 160°C stream) does not require upgrading and therefore can be sent directly as a feedstock to a steam cracker and an aromatics complex. The middle draw (e.g., 160-490° C. stream) is easily processed in a (destructive fixed bed hydrogenation)/conditioning reaction system in which the feedstock is hydrotreated and converted to naphtha, producing an ideal steam cracker 24 feedstock and an ideal feedstock. raw material for the complex for the production of aromatic compounds 26.

[0085] The heavy cut (eg, 490°C+ stream) contains the most problematic compounds in processed crude oil, including asphaltenes, metals, and CCR (Conradson Carbon Residue). In downflow fixed bed reactors, catalyst conversion and cycle time are typically limited by the metal, CCR, and asphaltene content of the residual feed, resulting in rapid catalyst fouling and increased pressure drop. In the embodiments described in the invention, an expanded bed upflow reactor can be used to overcome pressure drop problems and allow the process to operate at continuous flow for extended periods at high conversions. The heavy end product itself, such as a 490° C.+ stream, may in some embodiments be processed in a fluidized bed reactor with liquid circulation, such as LC-FINING technology available from Lummus Technology LLC. The LC-SLURRY reactor technology available from Chevron Lummus Global can also be used to process even heavier streams such as pitch.

[0086] The crude oil conditioning section may include four reaction stages including fluidized bed reactors (such as LC-FINING reactors), first and second stage hydrocracking reactors, and a destructive heavy residue hydrogenation reactor. These four reaction stages can be operated in one common recycle gas circuit. The integration of these crude oil conditioning stages fulfills the key technological challenges of upgrading low-value refinery streams, eliminating the need to import crude naphtha (FRN) and providing feedstock for the steam cracker to produce additional ethylene, while minimizing hydrogen consumption, investment and operating costs.

[0087] FIG. 4 is a simplified flow diagram of processes for the production of olefins and aromatics in accordance with embodiments of the invention, where like reference numbers refer to like parts. As a typical feedstock, Arab Light 100 crude oil can be processed to produce enough light naphtha (110) to produce additional ethylene as part of stream 118 in a mixed feed steam cracker (MFC) 120, as well as feedstock 112 for the complex aromatics production 122. Other mixed feed steam cracker feeds may include, for example, raffinate-2 stream 123, propane 124, reactive organic gas (ROG) 125, and the mixed feed steam cracker may produce pyrolysis oil ( PyOil) 102, pyrolysis gas oil 127, mixed C ₄ 128, propylene 129 and ethylene 118, among other products. FIG. 4 is a drawing of the entire process highlighting the main equipment and flow directions for one possible configuration in accordance with embodiments of the invention. Although Arab Light oil is given as an example, the above also applies to other types of crude oil such as desalted oil, condensate, biogenetic oil, synthetic oil, tight oil, heavy hydrocarbons, recovered crude oil and bituminous oil.

[0088] Feed streams to the feed conditioning section 101 may include, for example, Arab Light crude oil 100, pyrolysis oil 102 (PyM), which can be produced in a blended feed cracker 120, heavy cat-cracking residue 104, and light cycle oil 106 (LRG). In embodiments such as those shown in FIG. 4, the following products can be produced in the conditioning section: steam cracker feedstock (eg, 90° C. hydrocarbons) 110; aromatic complex feedstock (eg, 90-160° C. hydrocarbons) 112; and ultra low sulfur heavy fuel oil (ULSFO) 114. Conditioning can produce a variety of by-products such as fuel gas, sour water, rich amine and desalination plant brine, and ancillary systems may be required, such as systems for hydrogen, stripped sour water , lean amine, steam, power, cooling water, fuel gas, nitrogen, boiler feed water (BFW), and a feed preparation section which may include desalting (all not shown).

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

[0090] Conditioned compounds, such as 490° C. compounds produced in vacuum residue hydrocracking unit 30, may be fed via stream 34 for additional conditioning to conditioning section 22. If desired, other crude naphtha feedstock may be fed to the aromatics unit. , for example, along the production line 105.

[0091] Referring to FIG. 5, the desalinated oil 100 may be separated in a first inline separation device (ISU) 158, recovering a 160° C. fraction 113. The inline separation device 158 may be operated at 200° C. and 8 barg, for example, to improve the efficiency of vapor-liquid separation. The overhead of the VUR steam product 113 (such as the 160° C.-crude cut) is sent to the product separation column 160. In the product separation column 160, 160° C. as 30°C- or 35°C-) stream 110, light naphtha stream (eg 30-90°C stream) 120 and heavy naphtha stream (eg 90-160°C) 122. Light stream 110 and light naphtha stream 120 can then be used as feedstock for steam cracker 111 to produce additional ethylene or other petrochemicals 113. Heavy naphtha 122 can be used as feedstock 122A for aromatics production complex 112. In some embodiments, at least , a portion 112B of the heavy naphtha 122 may be combined with the light naphtha stream 120 and fed to a steam cracker to produce additional petrochemicals 113 and/or pyrolysis oil 191. In other embodiments, all of the heavy naphtha 122 may be fed to a steam cracker 111 when the aromatics complex needs to be shut down for maintenance or when there is not enough benzene, toluene, and/or xylenes (BTX) in streams 113 and/or 316. Heavy naphtha feed routing may also be based on demand, for example.

[0092] The remaining 160° C.+ oil cut 114 from WUR 158 may be fed to a second separation system, such as a hydrogen hot stripper 166, where the 160° C.+ oil cut is further separated into a middle cut, such as 160-490° C. cut 168 , and a heavy cut such as 490°C+ cut 170.

[0093] The heavy cut 170 (such as the 490°C+ cut) contains the most problematic compounds that must be processed in oil, including asphaltenes, metals, and CCR. Excess metals, CCRs, and asphaltenes in the high-boiling bottoms fraction can lead to rapid catalyst fouling and increased pressure drop in downflow fixed bed reactors, limiting both conversion and catalyst life. The expanded bed upflow reactor embodiment can overcome pressure drop problems and allow the process to operate at continuous flow for extended periods at high residue conversions. The heavy cut itself, eg, 490°C+ stream 170, in some embodiments, can be processed in a fluidized bed reactor system with liquid circulation.

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

[0095] The effluent from the fluidized bed reactor system 202 may be flashed in a high pressure/high temperature (HP/HT) separator 204. Vapors 206 from the HP/HT separator 204 may be combined with one or more streams. from the midstream 168 from the second HPS 166, the vapors 208 from the HP/HT separator 210 of the heavy residue hydrotreatment (HOHDT), and fed to the first stage of the fixed bed conditioning section 176. The liquid 214 from the HP/HT separator 204 can be processed in the reactor destructive hydrogenation of heavy residues 222. The effluent of the destructive hydrogenation of heavy residues reactor 223 may be separated in a HOHDT separator 210. The liquid HOHDT effluent 115 may be combined with a fraction of the bottoms of the product separator 300 (300A) to form ULSFO 301.

[0096] The primary function of the first stage of the reaction system 176 is to hydrotreat the mixed feed to reduce the levels of sulfur and nitrogen in the feed, partially convert to product, and prepare the feed for further processing in the second stage of the reactor 178. The liquid feed for the first stage of the reaction system 176 can be a mixture of straight cut (SG (SR)), middle cut, 160-490°C oil fraction 166, fluidized bed reactor distillates 206, vapor 208 from HOHDT separator 210 and LWG 106.

[0097] To achieve the technology goal of removing sulfur and nitrogen from the feedstock and partially converting it into a suitable steam cracker feedstock, the first stage reactor 176 may be loaded with a catalyst system consisting of demetalation, destructive hydrogenation, and hydrocracking catalysts. To control temperature rise due to exothermic reactions, the catalysts can be separated into multiple layers within the reactor or into separate reactor vessels. Cold cycle gas may be introduced between beds or reactors to cool the reacting liquids and control the amount of temperature rise and reaction rate.

[0098] First stage reactor effluent 250 may consist of unconverted residue, distillates, naphtha, overheads, and excess hydrogen not consumed in first stage reactor 176. First stage reactor effluent 250 may be fed to a high pressure low temperature separator ( HP/LT) 266. Any recovered sour water 274 containing NH ₃ and/or H ₂ S may be removed from the system. Hydrogen-enriched vapor 276 from HP/LT separator 266 may be sent to a gas compression and distribution system 277. The gas compression and distribution system may purify and pressurize the hydrogen, and recycle hydrogen gas to a common hydrogen manifold 400. Although not shown, hydrogen from the common hydrogen collector 400 may be fed to one or more of fluidized bed conditioning system 200, first stage reaction system 176, second stage reaction system 178, heavy residue destructive hydrogenation reactor 222.

[0099] Hydrocarbon liquid 290 exiting the HP/LT separator 266 may be pumped to the reaction section of the second stage 178 for additional conditioning focused on maximizing naphtha production. The purpose of the second stage reaction system 178 is to break down the unconverted residue (UCO) from the first stage reaction section into lighter products. By itself, the second stage reactor can be loaded with a highly active hydrocracking catalyst. A portion of the product separator bottoms 300 (300B) may also be sent to the second stage reaction system 178 for additional conditioning.

[00100] Second stage reactor effluent 180 may be fed to high pressure/high temperature (HP/HT) separator 314. HP/HT liquid product 316 may be fed to product separation column 160 and vapor product 320 mixed with hydrogen-enriched steam 276 in the gas compression and distribution system 277. The recovered hydrogen and fresh hydrogen, if necessary, can then be directed from the gas compression and distribution system 277 to different conditioning reactors, as needed.

[00101] The 160° C. product 113 from the inline separator 158 along with the HP/LT liquid product 316 may be sent to a product separator column 160. The product separator column 160 may separate the reactor effluent products into a light fraction 110, a light naphtha fraction 120 and heavy naphtha 122. The light naphtha product 110 is sent as a feedstock to a steam cracker 111.

[00102] The heavy naphtha product 122 may be withdrawn as a side stream from the product separation column 160. A portion 112A of the heavy naphtha product 122 may be pumped to the aromatics complex 112, and a portion 112B of the heavy naphtha product 122 may be combined with the light naphtha 120 and fed to steam cracker 111.

[00103] As described above in connection with FIG. 1 and 2, the separation system 3 may be as shown in FIG. 6, The separation system 3 may be as described above and includes separation and thermal integration. After desalting, the oil 1 may be further heated in the convection section of the heater 500 to produce heated oil 502. The heated oil 502 may be directed to a separator 504, which may assist in separating the 160°C fraction 5 from the heavier components recovered in stream 506.

[00104] The remaining 160°C+ oil fraction 506 may be fed to pump 508, which produces a pressurized 160°C+ oil fraction 510, which may be fed to heat exchanger 512. Heat exchanger 512 may preheat 160°C+ oil fraction 510 relative to bottoms 520 hydrogen hot stripper, yielding a pressurized and heated 160°C+ oil cut 514. The pressurized and heated 160°C+ oil cut 514 can then be fed back to heater 500 where it is heated to facilitate separation of 160-490°C fraction from the heavier 490°C+ fraction. The 160°C+ heated oil cut 516 can then be fed to the hydrogen hot stripper 518. In the 160°C+ hydrogen hot stripper 518, the oil cut is further separated into a 160-490°C fraction 9 and hydrogen hot stripper bottoms 520, which contain heavier 490°C+ hydrocarbons. The bottoms 520 of the hydrogen hot stripper after cooling through indirect heat exchange in heat exchanger 512 relative to the 160°C+ pressurized oil fraction 510 can be removed from separation system 3 as 490°C+ fraction 15.

[00105] The hydrogen hot stripper 518 may use the hydrogen feed 522 as the stripping medium. The hydrogen hot stripper 518 can be put into operation to provide wide flexibility depending on the nature of the crude oil being processed. The stripper overheads, which are 160-490° C. fraction 9, can be cooled to recover hydrogen and, if necessary, sent to intermediate hydrotreating reaction steps as described in connection with FIG. 1 and 2. The recovered hydrogen may be fed to a downstream pressure swing adsorption (PSA) unit (not shown) after treatment with an amine (not shown) to improve the purity of the hydrogen. The hydrogen product of the FTA unit may be compressed in a make-up hydrogen compressor (not shown) to make make-up hydrogen for one or more hydrotreating reactors (FIGS. 1 and 2) as well as hot hydrogen feed 522.

[00106] Hydrogen hot stripper bottoms 520 (such as a 490° C.+ cut) contains the most problematic compounds to be processed into crude oil, including asphaltenes, metals, and CCR (Conradson Carbon Residue). Excess metals, CCRs and asphaltenes in the high-boiling bottoms fraction results in rapid catalyst fouling and increased pressure drop in downflow fixed bed reactors, limiting both conversion and catalyst life. After cooling against the pressurized 160°C+ oil fraction 510, the 490°C+ stream (stream 11) can be recovered and processed in a liquid circulating fluidized bed residue hydrocracker as described in FIG. 1 and 2, along with any additional low value refinery streams such as a pyrolysis oil stream and/or a heavy catalytic cracking residue stream.

[00107] By controlling the amount of hydrogen 522 supplied to the hydrogen hot stripper 518, as well as the operating conditions in the hydrogen hot stripper 518 and heater 500, the boiling range of the hydrocarbon fractions can be adjusted so that the light cut 5 can be sent directly to a downstream steam cracker, and middle cut 9 may contain little to no harmful compounds that would rapidly foul fixed bed conditioning reactors. Thus, the separation system 3 (with hydrogen hot stripper 518) can concentrate the most problematic hydrocarbons to process in the heavy end product 11, which can be directed to the most severe fluidized bed reactors.

[00108] As described above with respect to FIG. 3 and 4, the separation system 12 may be as shown in FIG. 7. The separation system 312 may be as described above and includes separation and thermal integration. After desalting, the crude oil 100 may be further heated in the convection section of the heater 500 to produce heated crude oil 502. The heated crude oil 502 may then be fed to a separator 504, which may facilitate separation of the 160°C-fraction 5 in the in-line separation system 3.

[00109] The remaining 160°C+ oil fraction 506 may be fed to pump 508, which produces a pressurized 160°C+ oil fraction 510, which may be fed to heat exchanger 512. Heat exchanger 512 may preheat 160°C+ oil fraction 510 relative to bottoms 520 hydrogen hot stripper, yielding a pressurized and heated 160°C+ oil cut 514. The pressurized and heated 160°C+ oil cut 514 can then be fed back to heater 500 where it is heated to facilitate separation of 160-490°C fraction from the heavier 490°C+ fraction. The 160°C+ heated oil cut 516 can then be fed to the hydrogen hot stripper 518. In the 160°C+ hydrogen hot stripper 518, the oil cut is further separated into a 160-490°C cut 20 and hydrogen hot stripper bottoms 520, which contain heavier 490°C+ hydrocarbons. The bottoms 520 of the hydrogen hot stripper after cooling through indirect heat exchange in heat exchanger 512 relative to the 160°C+ pressurized oil fraction 510 can be removed from separation system 3 as 490°C+ fraction 28.

[00110] The hydrogen hot stripper 518 may use the hydrogen feed 522 as the stripping medium. The hydrogen hot stripper 518 can be put into operation to provide wide flexibility depending on the nature of the crude oil being processed. The stripper overheads, which are 160-490° C. fraction 20, can be cooled to recover hydrogen and, if necessary, sent to intermediate hydrotreating reaction steps as described in connection with FIG. 3 and 4. The recovered hydrogen may be fed to a downstream pressure swing adsorption (PSA) unit (not shown), after treatment with an amine (not shown) to improve the purity of the hydrogen. The hydrogen product of the FTA unit may be compressed in a make-up hydrogen compressor (not shown) to make make-up hydrogen for one or more hydrotreating reactors (FIGS. 3 and 4) as well as hot hydrogen feed 522.

[00111] The bottom product 520 of a hydrogen hot stripper (such as a 490°C+ cut) contains the most problematic compounds that must be processed into crude oil, including asphaltenes, metals, and CCR (Conradson Carbon Residue). Excessive amounts of metals, CCRs and asphaltenes in the high-boiling bottoms fraction results in rapid catalyst fouling and increased pressure drop in downflow fixed bed reactors, limiting both conversion and catalyst life. After cooling against the pressurized 160° C.+ oil fraction 510, the 490° C.+ stream (stream 28) can be recovered and processed in a circulating fluid bed fluidized bed hydrocracking unit as described in FIG. 3 and 4, along with any additional low value refinery streams such as a pyrolysis oil stream and/or a heavy catalytic cracking residue stream.

[00112] By controlling the amount of hydrogen 522 supplied to the hydrogen hot stripper 518, as well as the operating conditions in the hydrogen hot stripper 518 and heater 500, the boiling range of the hydrocarbon cuts can be adjusted so that the light cut 5 can be sent directly to a downstream steam cracker, and middle cut 20 may contain little to no harmful compounds that would rapidly foul fixed bed conditioning reactors. Thus, the separation system 12 (with hydrogen hot stripper 518) can concentrate the most problematic hydrocarbons to process in the heavy end product 28, which can be sent to the fluidized bed reactors.

[00113] Referring to FIG. 1-7 above, the light, medium and heavy fractions are given with limited examples of 160°C-, 160-490°C and 490°C+. Boil cut limits can be adjusted so that the light cut can be sent directly to the steam cracker with little or no intermediate processing, and the medium and heavy cuts can be efficiently processed to their respective reactor lines.

[00114] Steam crackers comprising ethylene complexes useful in the embodiments described herein may include various typical operations. For example, the ethylene complex may include a cracker such as a steam cracker. Other cracking operations may also be used. The ethylene complex may also include an olefin recovery unit, a butadiene extraction unit, an MTBE (MTBE) unit, a _C4 selective hydrogenation unit, a pyrolysis gasoline hydrotreating unit, an aromatics extraction unit, a metathesis unit, and/or a disproportionation unit, among others that are useful in production and isolation of olefins and other light hydrocarbons. The ethylene complex products may include, for example, ethylene, propylene, butadiene, benzene, MTBE, and mixed xylenes, among others.

[00115] In some embodiments, the cracked hydrocarbon streams may be sent directly to a steam cracker. In other embodiments, the cracked hydrocarbon streams, as noted above, may be separated into multiple fractions for separate processing (eg, for cracking at the preferred temperatures, pressures, and residence times for each respective fraction).

[00116] The hydrocarbon feedstock, which may be a single hydrocarbon or a mixture of hydrocarbons, may be introduced into a heating coil located in the convection section of the steam pyrolysis heater. In the heating coil, the hydrocarbon feed may be heated and/or vaporized by convective heat exchange with the exhaust gases.

[00117] If desired, the heated hydrocarbon feed may then be mixed with steam or an inert compound such as nitrogen, carbon dioxide, or any other inorganic gases. Low temperature or saturated steam may be used in various parts of the process, or in additional processes in the plant, while others may use high temperature superheated steam. Steam that is used within the process or elsewhere in the plant can be heated or superheated using a heating coil (not shown) located in the convection zone of the steam pyrolysis heater.

[00118] The heated hydrocarbon mixture(s) may/may be fed(s) to a heating coil, which may be located at the lower elevation of the steam pyrolysis heater and therefore at a higher temperature than the convection heating coil. zones noted above. The resulting superheated mixture may then be fed to one or more coils located in the radiant zone of a steam pyrolysis heater operating at a partial conversion temperature by thermally cracking the hydrocarbon mixture. The cracked hydrocarbon product can then be recovered.

[00119] In some embodiments, a plurality of heating and separation steps may be used to separate the cracked hydrocarbon mixture(s) into two or more hydrocarbon fractions, if desired. This can provide optimal conditioning and optimal steam cracking of each cut so that throughput, steam to oil ratios, heater inlet and outlet temperatures, and other variables can be adjusted to the desired level to achieve desired reaction outcomes, such as desired product profile, by limiting while coking in radiant coils and associated downstream equipment. Since different cuts are separated and cracked depending on the boiling point of hydrocarbons in different feed streams, coking in radiant coils and pump line heat exchangers can be controlled. As a result, heater cycle times can be extended to weeks instead of hours with higher olefin production.

[00120] After cracking in radiant coils, one or more pump line heat exchangers can be used to cool products very quickly and generate (super) high pressure steam. One or more coils can be combined and connected to each heat exchanger. The heat exchanger(s) may/may be a tube-in-tube heat exchanger or a shell and tube heat exchanger.

[00121] Instead of indirect cooling, direct quenching can also be used. In such cases, oil may be injected at the outlet of the radiant coil. After oil quenching, water quenching can also be used. Instead of oil quenching, full water quenching is also acceptable. After hardening, the products are sent to the extraction section.

[00122] As described above, embodiments of the invention may separate desalted crude oil or other high-boiling hydrocarbons into various fractions to effectively condition the respective fractions to produce a feedstock suitable for conversion in a steam cracker. Due to the wide range of feedstocks that can be processed in accordance with embodiments, depending on feedstocks, conditioning catalysts, reactor volumes, and other factors, it may be preferable for a given plant to justify specific boiling ranges of fractions based on one or more additional properties of the feedstock. For example, specific fraction boiling limits can be adjusted based on one or more properties or additional properties of the crude oil, such as API gravity of crude oil (API gravity), Bureau of Mines Correlation Index (BMCI) ), hydrogen content, nitrogen content, sulfur content, viscosity, microcarbon residue (MCRT) and/or total metal content, among other feedstock properties.

[00123] Various feedstocks useful in embodiments of the invention, such as crude crude oil, desalted oil, condensate, biogenetic oil, synthetic oil, tight oil, heavy hydrocarbons, recovered oil, and bitumen-derived oil, may have one or more of the following properties, including: density in degrees API between 4 and 60 °, ICGB from 20 to 85, hydrogen content from 9.0 to 14.5% of the mass. (or from 90,000 to 145,000 ppm), nitrogen content from 0.02 to 0.95% of the mass. (or from 200 to 9500 ppm), sulfur content from 0.009 to 6.0 wt%. (or 90 to 60,000 ppm), a viscosity at 40°C of 95 to 5500 centistokes (cSt), an MCRT of 5 to 35% by weight, and/or may have a total metal content of <1 to 1000 ppm.

[00124] The initial separation of the crude oil can be carried out and adjusted so that the light, medium and heavy cuts have certain desired initial properties so that the light cut can go to the steam cracker without processing or with minimal intermediate processing. In addition, medium to heavy cuts can be produced and adjusted so that the medium and heavy cuts have the appropriate and/or preferred feed properties and hydrocarbon species so that they can be efficiently and effectively conditioned in medium and heavy cut conditioning reactors. .

[00125] Mining Bureau Correlation Index (BMCI)

[00126] In some embodiments, a light shoulder strap may have an ICGB of less than 20. In other embodiments, a light shoulder strap may have an ICGB of less than 15. In still other embodiments, a light shoulder strap may have an ICGB of less than 10 or even less than 5. In some embodiments, a light shoulder strap may have an ICGB of less than 10 or even less than 5. embodiments, a medium shoulder strap may have an ICGB less than 40, such as less than 35, less than 30, or less than 25. In some embodiments, a heavy shoulder strap may have an ICGB greater than 30, such as greater than 35, greater than 40, greater than 45, greater than 50, or greater than 55.

[00127] Accordingly, in some embodiments, a light cut comprising hydrocarbons having a boiling point of about 90 to 300° C., for example, may have an ICGB of less than 20; in other embodiments, for example, when the light cut includes hydrocarbons having a boiling point up to about 110°C or up to about 250°C, for example, the light cut may have an ICGB of less than 10; in yet other embodiments, for example, where the light cut includes hydrocarbons having a boiling point up to about 130° C. or up to about 220° C., for example, the light cut may have an ICGB of less than 5. In some embodiments, where the light cut includes hydrocarbons having a boiling point below about 160°C, a light cut may have an ICGB of less than 5. Although an ICGB may vary for different feedstocks at any given distillation temperature, a low ICGB, such as less than 10 or less than 5, has been found to improve processability. light hydrocarbons in the steam pyrolysis unit without the need for intermediate treatment. Light cuts for Arab light oils processed in accordance with embodiments of the invention, for example, may target an ICGB of less than 10, and in the case of Arab extra light oils, may target, for example, an ICGB of less than 6 or less than 5.5.

[00128] In some embodiments, a middle cut comprising hydrocarbons having a lower boiling point in the range of about 90 to 300°C and an upper boiling point in the range of about 400 to 600°C may have an ICGB between about 5 and 50. For example , a medium shoulder strap may have an ICGB ranging from a lower limit of 5, 10, 15, 20, or 25 to an upper limit of 10, 15, 20, 25, 30, 40, or 50. A medium shoulder strap, for example, having an ICGB between 10 and 30, as found to be converted to a steam cracker feed using relatively mild destructive hydrogenation conditions in the middle bottom conditioning section of the processes described herein. Average cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, an ICGB in the range of about 20 to 30, and in the case of Arab extra light oils, may target, for example, an ICGB in the range of about 15 up to 30.

[00129] In various embodiments, a heavy cut including hydrocarbons having a boiling point greater than about 300°C may have an IBGB greater than 30. 40. When the heavy cut includes hydrocarbons having a boiling point above about 400°C, the heavy cut may have an IBGB greater than 50. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490°C, the heavy cut may have an IBGB greater than 55. A heavy cut, for example, having an ICGB greater than about 40, has been found to be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described in the invention. Heavy cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, an ICGB in the range of about 50 to 60, and in the case of Arab extra light oils, may target, for example, an ICGB in the range of about 25 up to 40.

[00130] API Gravity

[00131] In some embodiments, the light shoulder strap may have an API gravity greater than 10°. In other embodiments, the light shoulder strap may have an API gravity greater than 15°. In still other embodiments, the light shoulder strap may have an API gravity greater than 20°, greater than 30°, or even greater than 40°. In some embodiments, the middle cut may have an API gravity greater than 10° and less than 40°, for example, from a lower limit of 10°, 15°, 20°, 25°, or 30° to an upper limit of 25°, 30°, 35°, 40°, 45° or 50°. In some embodiments, the heavy shoulder strap may have an API gravity of less than 40°, such as less than 35°, less than 25°, less than 20°, less than 15°, or less than 10°.

[00132] Accordingly, in some embodiments, a light cut including hydrocarbons having, for example, a boiling point up to about 300° C., may have an API gravity greater than 10°; in other embodiments, for example, when the light cut includes hydrocarbons having a boiling point, for example, up to about 250° C., the light cut may have an API gravity greater than 20°; in still other embodiments, for example, when the light cut includes hydrocarbons having a boiling point, for example, up to about 220° C., the light cut may have an API gravity greater than 40°. In some embodiments, where the light cut includes hydrocarbons having a boiling point below about 160° C., the light cut may have an API gravity greater than 60°. While API gravity may vary for different feedstocks at any given temperature, API gravity, such as greater than 40°, greater than 50°, or greater than 60°, has been found to improve processability of light hydrocarbons in the steam pyrolysis unit without the need for intermediate treatment. . Light cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, an API gravity greater than 65° and in the case of Arab extra light oils, may target, for example, an API gravity greater than 60°.

[00133] In some embodiments, a middle cut comprising hydrocarbons having a lower boiling point in the range of about 90 to 300°C and an upper boiling point in the range of about 400 to 600°C may have an API gravity between about 5 and 50°. For example, a middle shoulder strap may have an API gravity from a lower limit of 5°, 10°, 15°, 20°, or 25° to an upper limit of 10°, 15°, 20°, 25°, 30°, 40°, or 50° . A middle draw having, for example, an API gravity between 20° and 40° has been found to be converted into a steam cracker feed using relatively mild destructive hydrogenation conditions in the middle draw conditioning section of the processes described herein. Average cuts for Arab light oils processed in accordance with embodiments of the invention may refer to, for example, API gravity in the range of approximately 30° to 35°, and in the case of Arab extra light oils, may refer to gravity in degrees API, for example, in the range of approximately 35° to 40°.

[00134] In various embodiments, a heavy cut comprising hydrocarbons having a boiling point greater than about 300° C. may have an API gravity less than about 40°. When the heavy cut includes hydrocarbons having a boiling point above about 350° C., the heavy cut may have an API gravity of less than about 20°. When the heavy cut includes hydrocarbons having a boiling point above about 400° C., the heavy cut may have an API gravity of less than about 10°. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490°C, the heavy cut, for example, may have an API gravity of less than 7°. A heavy cut having, for example, an API gravity of less than about 20° has been found to be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described in the invention. Heavy cuts for Arab light oils processed in accordance with embodiments of the invention may be oriented, for example, to API gravity in the range of approximately 5° to 10° and in the case of Arab extra light oils, may be oriented, for example, to density in API degrees in the range of approximately 10° to 20°.

[00135] Hydrogen content

[00136] In some embodiments, the implementation of a light shoulder strap may have a hydrogen content of more than 12% of the mass. In other embodiments, the implementation of a light shoulder strap may have a hydrogen content of more than 13% of the mass. In yet other embodiments, the implementation of a light shoulder strap may have a hydrogen content of more than 13.5 wt. -%, more than 14% of the mass. or even more than 15% of the mass. In some embodiments, the middle cut may have a hydrogen content greater than 11% by weight. and less than 14% wt., for example, from the lower limit of 11, 11.5, 12.0, 12.5 or 13.0% of the mass. up to the upper limit of 12.0, 12.5, 13.0, 13.5, 14.0 or 14.5% of the mass. In some embodiments, the implementation of the heavy shoulder strap may have a hydrogen content of less than 13% wt., for example, less than 12.5% wt., less than 12% wt., less than 11.5% wt. or less than 11% of the mass.

[00137] Accordingly, in some embodiments, a light cut comprising hydrocarbons having, for example, a boiling point up to about 300° C., may have a hydrogen content of greater than 13% by weight; in other embodiments, for example, when the light cut includes hydrocarbons having, for example, a boiling point up to about 250° C., the light cut may have a hydrogen content of greater than 13.5% by weight; in still other embodiments, for example, when the light cut includes hydrocarbons having, for example, a boiling point up to about 220° C., the light cut may have a hydrogen content of greater than 14.0% by weight. In some embodiments, where the light cut includes hydrocarbons having a boiling point below about 160° C., the light cut may have a hydrogen content greater than 14.5% by weight. Although the hydrogen content may vary for different feedstocks at any given temperature, the hydrogen content is, for example, greater than 13% wt., greater than 14% wt. or more than 14.5 wt. -%, as found to improve the processability of light hydrocarbons in the steam pyrolysis unit without the need for intermediate processing. Light cuts for Arab light oils processed in accordance with embodiments of the invention can focus, for example, on a hydrogen content of more than 14.5% of the mass. and in the case of oil grades Arab extra light can focus, for example, on a hydrogen content of more than 14% of the mass.

[00138] In some embodiments, a middle cut comprising hydrocarbons having a lower boiling point in the range of about 90 to 300°C and an upper boiling point in the range of about 400 to 600°C may have a hydrogen content between about 11.5 and 14.5% wt. A middle draw having, for example, a hydrogen content between 12 and 13.5 wt % has been found to be converted into a steam cracker feed using relatively mild destructive hydrogenation conditions in the middle draw conditioning section of the processes described in the invention. Average cuts for Arab light oils processed in accordance with embodiments of the invention may be oriented, for example, to a hydrogen content in the range from about 12.5 to 13.5 wt%, and in the case of Arab extra light oils, may be oriented, for example, the hydrogen content in the range from about 13.0 to 14.0% of the mass.

[00139] In various embodiments, a heavy cut comprising hydrocarbons having a boiling point greater than about 300° C. may have a hydrogen content of less than about 13% by weight. When the heavy cut includes hydrocarbons having a boiling point above about 350° C., the heavy cut may have a hydrogen content of less than about 12.5% by weight. When the heavy cut includes hydrocarbons having a boiling point above about 400° C., the heavy cut may have a hydrogen content of less than about 12.0% by weight. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490° C., the heavy cut may have, for example, a hydrogen content of less than 11% by weight. A heavy end having, for example, a hydrogen content of less than about 12% by weight has been found to be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described herein. Heavy cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, a hydrogen content in the range of about 10 to 11% by weight, and in the case of Arab extra light oils, may target, for example, a hydrogen content hydrogen in the range from about 11 to 12% of the mass.

[00140] Nitrogen content

[00141] In some embodiments, the light cut 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 cut may have a nitrogen content of less than 25 ppm. In still other embodiments, the light cut 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 middle cut may have a nitrogen content greater than 1 ppm and less than 1000 ppm, such as from a lower limit of 1, 5, 10, 50, 100, 250, or 500 ppm to an upper limit of 50, 100, 250, 500, or 1000ppm. In some embodiments, the heavy cut may have a nitrogen content greater than 10 ppm, such as greater than 25 ppm, greater than 50 ppm, greater than 100 ppm, greater than 150 ppm, greater than 200 ppm, greater than 250 ppm, greater than 500 ppm, greater than 1000 ppm, greater 1500 ppm, over 2000 ppm or over 2500 ppm.

[00142] Accordingly, in some embodiments, the implementation of a light shoulder strap, including hydrocarbons having a boiling point up to about 300°C, may have, for example, a nitrogen content of less than 0.01% of the mass. or 100ppm; in other embodiments, for example, when the light cut includes hydrocarbons having a boiling point up to about 250°C, the light cut may have a nitrogen content of less than 0.001% by weight. or 10ppm; in still other embodiments, for example, when the light cut includes hydrocarbons having a boiling point up to about 220° C., for example, the light cut may have a nitrogen content of less than 0.0001% by weight. or 1ppm. In some embodiments, where the light cut includes hydrocarbons having a boiling point below about 160° C., the light cut may have a nitrogen content of less than about 0.00003% by weight. or 0.3 ppm. Although the nitrogen content may vary for different feedstocks at any given temperature, a nitrogen content of, for example, less than about 100 ppm, less than 10 ppm, or less than 1 ppm has been found to improve the light hydrocarbon conversion capability of the steam pyrolysis unit without the need for intermediate processing. Light cuts for Arab light oils processed in accordance with embodiments of the invention can target, for example, a nitrogen content of less than 1 ppm, and in the case of Arab extra light oils, can also target, for example, a nitrogen content of less than 1 ppm .

[00143] In some embodiments, the implementation of the middle distillate, including hydrocarbons having a lower boiling point in the range from about 90 to 300°C and an upper boiling point in the range from about 400 to 600°C, may have a nitrogen content, for example, between about 10 and 250 ppm. A middle draw having, for example, a nitrogen content between 20 and 250 ppm has been found to be converted into a steam cracker feed using relatively mild destructive hydrogenation conditions in the middle draw conditioning section of the processes described in the invention. Average cuts for Arab light oils processed in accordance with embodiments of the invention may be oriented, for example, to a nitrogen content in the range of from about 200 to 300 ppm and in the case of Arab extra light oils, may be oriented, for example, to a nitrogen content in the range approximately 100 to 150 ppm.

[00144] In various embodiments, the implementation of a heavy shoulder strap, including hydrocarbons having a boiling point of more than about 300°C, may have a nitrogen content of more than about 0.001% of the mass. or 10ppm. When the heavy cut includes hydrocarbons having a boiling point above about 350° C., the heavy cut may have a nitrogen content greater than about 0.005% by weight. or 50ppm. When the heavy cut includes hydrocarbons having a boiling point above about 400° C., the heavy cut may have a nitrogen content greater than about 0.01% by weight. or 100ppm. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490° C., the heavy cut may have a nitrogen content of, for example, greater than 2500 ppm. A heavy end having a nitrogen content, for example, greater than about 100 ppm, has been found to be converted into a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described herein. Heavy cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, a nitrogen content in the range of about 2000 to 3000 ppm and in the case of Arab extra light oils, may target, for example, a nitrogen content in the range approximately 1000 to 2000.

[00145] Sulfur content

[00146] In some embodiments, the light cut 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 cut may have a sulfur content of less than 750 ppm. In still other embodiments, the light cut may have a sulfur content of less than 500 ppm, less than 250 ppm, or even less than 100 ppm. In some embodiments, the middle cut may have a sulfur content greater than 500 ppm and less than 10,000 ppm, for example, from a lower limit of 500, 750, 1000, 1500, 2000, 2500 or 5000 ppm to an upper limit of 1000, 2000, 5000, 10000, 15000 or 20000 ppm. In some embodiments, the heavy cut may have a sulfur content greater than 1000 ppm, such as greater than 2500 ppm, greater than 5000 ppm, greater than 10,000 ppm, greater than 15,000 ppm, greater than 20,000 ppm, greater than 25,000 ppm, greater than 30,000 ppm, greater than 35,000 ppm, greater 40,000 ppm, over 45,000 ppm, or over 50,000 ppm.

[00147] Accordingly, in some embodiments, the implementation of a light distillate, including hydrocarbons having a boiling point up to approximately 300°C, for example, may have a sulfur content of 1% of the mass. or 10000 ppm; in other embodiments, for example, when the light cut includes hydrocarbons having, for example, a boiling point up to about 250°C, the light cut may have a sulfur content of less than 0.5 wt%. or 5000 ppm; in still other embodiments, for example, when the light cut includes hydrocarbons having, for example, a boiling point up to about 220° C., the light cut may have a sulfur content of less than 0.1% by weight. or 1000ppm. In some embodiments, where the light cut includes hydrocarbons having a boiling point below about 160° C., the light cut may have a sulfur content of less than about 750 ppm or less than 500 ppm. Although the sulfur content may vary for different feedstocks at any given temperature, a sulfur content of, for example, less than about 600 ppm has been found to improve the light hydrocarbon conversion capability of the steam pyrolysis unit without the need for intermediate treatment. Light cuts for Arab light oils processed in accordance with embodiments of the invention can target, for example, a sulfur content of less than 750 ppm, and in the case of Arab extra light oils can also target, for example, a sulfur content of less than 500 ppm .

[00148] In some embodiments, the implementation of the middle distillate, including hydrocarbons having a lower boiling point in the range from about 90 to 300°C and an upper boiling point in the range from about 400 to 600°C, may have a sulfur content, for example, between about 100 and 20000 ppm. A middle draw having a sulfur content of, for example, between 2000 and 15000 ppm has been found to be converted into a steam cracker feed using relatively mild destructive hydrogenation conditions in the middle draw conditioning section of the processes described herein. Average cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, a sulfur content in the range from about 6000 to 12000 ppm and in the case of Arab extra light oils, may target, for example, a sulfur content in the range approximately 5000 to 10000 ppm.

[00149] In various embodiments, the implementation of a heavy shoulder strap, including hydrocarbons having a boiling point of more than about 300°C, may have a sulfur content of more than about 0.1% of the mass. or 1000ppm. When the heavy cut includes hydrocarbons having a boiling point above about 350° C., the heavy cut may have a sulfur content greater than about 0.5% by weight. or 5000 ppm. When the heavy cut includes hydrocarbons having a boiling point above about 400° C., the heavy cut may have a sulfur content greater than about 1% by weight. or 10000 ppm. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490° C., the heavy cut may have a sulfur content of, for example, greater than 25,000 ppm. A heavy end having a sulfur content of, for example, greater than about 10,000 ppm has been found to be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described herein. Heavy cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, a sulfur content in the range of about 30,000 to 50,000 ppm and, in the case of Arab extra light oils, may target, for example, a sulfur content in the range approximately 20,000 to 30,000.

[00150] Viscosity

[00151] In some embodiments, the implementation of a light shoulder strap may have a viscosity, measured at 40°C in accordance with ASTM D445, less than 10 cSt. In other embodiments, the light cut may have a viscosity, measured at 40° C., of less than 5 cSt. In still other embodiments, the light cut may have a viscosity, measured at 40° C., of less than 1 cSt. In some embodiments, the heavy shoulder strap may have a viscosity, measured at 100°C in accordance with ASTM D445, greater than 10 cSt, such as greater than 20 cSt, greater than 35 cSt, greater than 50 cSt, greater than 75 cSt, or greater than 100 cSt. In various embodiments, the middle cut may have a viscosity intermediate between the light and heavy cuts.

[00152] Accordingly, in some embodiments, a light cut comprising hydrocarbons having a boiling point up to about 300°C, for example, may have a viscosity, measured at 40°C, of less than 10 cSt; in other embodiments, for example, when the light cut includes hydrocarbons having a boiling point up to about 250°C, for example, the light cut may have a viscosity, measured at 40°C, of less than 5 cSt; in still other embodiments, for example, when the light cut includes hydrocarbons having a boiling point up to about 220°C, for example, the light cut may have a viscosity, measured at 40°C, of less than 1 cSt. In some embodiments, where the light cut includes hydrocarbons having a boiling point below about 160°C, the light cut may have a viscosity, measured at 40°C, of less than 0.75 cSt. Although viscosity may vary for different feedstocks at any given temperature, low viscosity, eg less than 10 cSt, has been found to improve processability of light hydrocarbons in the steam pyrolysis unit without the need for intermediate treatment. Light cuts for Arab light oils processed in accordance with embodiments of the invention may target, for example, a viscosity of less than 0.55 cSt and in the case of Arab extra light oils, may target, for example, a viscosity of less than 0.6 cSt .

[00153] In various embodiments, a heavy cut comprising hydrocarbons having a boiling point greater than about 300°C may have a viscosity, measured at 100°C, greater than 10 cSt. When the heavy cut includes hydrocarbons having a boiling point above about 350°C, the heavy cut may have a viscosity, measured at 100°C, greater than 50 cSt. When the heavy cut includes hydrocarbons having a boiling point above about 400°C, the heavy cut may have a viscosity, measured at 100°C, greater than 100 cSt. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490° C., the heavy cut may have a viscosity greater than 375 cSt, for example. A heavy end having a viscosity, for example, greater than about 40 cSt, has been found to be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described herein.

[00154] Microcarbon Residue (MCRT)

[00155] In some embodiments, the light cut may have only trace amounts, or undetectable amounts, of microcarbon residue (MCRT). In some embodiments, the implementation of the average shoulder strap may have an MCRT of less than 5% wt., for example, less than 3% wt., less than 1% wt. or less than 0.5% of the mass. In some embodiments, the heavy shoulder strap may have an MCRT greater than 0.5% wt., for example, greater than 1% wt., greater than 3% wt., greater than 5% wt. or more than 10% of the mass.

[00156] In some embodiments, a middle cut comprising hydrocarbons having a lower boiling point in the range of about 90 to 300° C. and an upper boiling point in the range of about 400 to 600° C. may have an MCRT between about 0% wt. (trace or unmeasurable amount) and 1% of the mass. A middle draw having a negligible MCRT, for example, has been found to be converted to a steam cracker feed using relatively mild destructive hydrogenation conditions in the middle draw conditioning section of the processes described herein.

[00157] In various embodiments, a heavy cut comprising hydrocarbons having a boiling point greater than about 300° C. may have an MCRT greater than 0.5 wt%. When the heavy cut includes hydrocarbons having a boiling point above about 350° C., the heavy cut may have an MCRT greater than 1% by weight. When the heavy cut includes hydrocarbons having a boiling point above about 400° C., the heavy cut may have an MCRT of greater than 5% by weight. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490° C., the heavy cut may have an MCRT of, for example, greater than 15% wt. A heavy end having an MCRT of, for example, greater than about 1 wt % has been found to be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described herein.

[00158] Metal content

[00159] In some embodiments, the light cut may have only trace amounts, or undetectable amounts, of metals. In some embodiments, the middle cut may have a metal content of up to 50 ppm, such as less than 30 ppm, less than 10 ppm, or less than 1 ppm. In some embodiments, the heavy cut may have a metal content greater than 1 ppm, such as greater than 10 ppm, greater than 20 ppm, greater than 35 ppm, or greater than 50 ppm.

[00160] In some embodiments, a middle cut comprising hydrocarbons having a lower boiling point in the range of about 90 to 300°C and an upper boiling point in the range of about 400 to 600°C may have a metal content of between about 0 ppm (trace or non-measurable quantities) and 5 ppm, for example, from more than 0 to 1 ppm. A middle draw having a negligible metal content, for example, has been found to be converted into a steam cracker feed using relatively mild destructive hydrogenation conditions in the middle draw conditioning section of the processes described herein.

[00161] In various embodiments, a heavy cut comprising hydrocarbons having a boiling point greater than about 300° C. may have a metal content greater than 1 ppm. When the heavy cut includes hydrocarbons having a boiling point above about 350° C., the heavy cut may have a metal content greater than 10 ppm. When the heavy cut includes hydrocarbons having a boiling point above about 400° C., the heavy cut may have a metal content greater than 50 ppm. In embodiments where the heavy cut includes hydrocarbons having a boiling point above about 490° C., the heavy cut may have, for example, a metal content greater than 75 ppm. A heavy end having a metal content of, for example, greater than about 10 ppm has been found to be converted to a steam cracker feed using more severe destructive hydrogenation conditions in the heavy end conditioning section of the processes described herein.

[00162] By way of example, an Arab Light crude oil stream may be separated into initial separation steps to produce the desired light, medium, and heavy cuts. Without wishing to be bound by any particular theory, it is believed that the light cut could be the 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 will have a boiling point above 160°C). The light shoulder strap may have an API gravity of approximately 65.5°, may have an ICGB of approximately 5.2, may have a hydrogen content of approximately 14.8% by weight. (or 148,000 ppm), may have a nitrogen content of less than 0.00003 wt%. (or 0.3 ppm), may have a sulfur content of approximately 0.0582% of the mass. (or 582 ppm), may have a viscosity at 40°C of approximately 0.5353 centistokes (cSt) and may have only trace amounts of MCRT and total metal content. The middle cut can be a fraction from 160 to 490°C with 5% of the fraction having a boiling point below 173°C and 95% of the fraction having a boiling point below 474°C (only 5% of the fraction will have a boiling point above 474°C ). The middle cut may have an API gravity of approximately 33.6°, may have an ICGB of approximately 25, may have a hydrogen content of approximately 12.83% by weight. (or 128300 ppm), may have a nitrogen content of less than 0.0227% of the mass. (or 227 ppm), may have a sulfur content of approximately 0.937% of the mass. (or 9370 ppm), may have a viscosity at 100°C of approximately 1.58 centistokes (cSt), may have an MCRT of 0.03 wt%. and may only have trace amounts of total metal content. The heavy cut can be a 490°C+ cut with 5% of the cut having a boiling point below 490°C and 95% of the cut having a boiling point below 735°C (only 5% of the cut will have a boiling point above 735°C). The heavy cut may have an API gravity of approximately 8.2°, may have an ICGB of approximately 55, may have a hydrogen content of approximately 10.41% by weight. (or 104100 ppm), may have a nitrogen content of less than 0.2638% of the mass. (or 2368 ppm), may have a sulfur content of approximately 3.9668% of the mass. (or 39668 ppm), may have a viscosity at 100°C of approximately 394.3 centistokes (cSt), may have an MCRT of 17.22 wt%. and may have a total metal content of 79.04 ppm.

[00163] As another example, an Arab Extra Light crude oil stream can be separated into initial separation steps to produce the desired light, medium, and heavy cuts. Without wishing to be bound by any particular theory, it is believed that the light cut could be the 160° C. fraction with 5% of the fraction having a boiling point below 54° C. and 95% of the fraction having a boiling point below 160° C. (only 5% fraction will have a boiling point above 160°C). The light cut may have an API gravity of approximately 62°, may have an ICGB of approximately 9.09, may have a hydrogen content of approximately 14.53% by weight. (or 145300 ppm), may have a nitrogen content of less than 0.00003% of the mass. (or 0.3 ppm), may have a sulfur content of approximately 0.0472% of the mass. (or 472 ppm), may have a viscosity at 40°C of approximately 0.58 centistokes (cSt) and may have only trace amounts of MCRT and total metal content. The middle cut can be a fraction from 160 to 490°C with 5% of the fraction having a boiling point below 169°C and 95% of the fraction having a boiling point below 456°C (only 5% of the fraction will have a boiling point above 474°C ). The middle cut may have an API gravity of approximately 36.1°, may have an ICGB of approximately 21.22, may have a hydrogen content of approximately 13.38% by weight. (or 133800 ppm), may have a nitrogen content of less than 0.01322% of the mass. (or 1322 ppm), may have a sulfur content of approximately 0.9047 wt%. (or 9047 ppm), may have a viscosity at 100°C of approximately 1.39 centistokes (cSt) and may have only trace amounts of MCRT and total metal content. The heavy cut can be a 490°C+ cut with 5% of the cut having a boiling point below 455°C and 95% of the cut having a boiling point below 735°C (only 5% of the cut will have a boiling point above 735°C). The heavy cut may have an API gravity of approximately 15.1°, may have an ICGB of approximately 33.28, may have a hydrogen content of approximately 11.45% by weight. (or 114500 ppm), may have a nitrogen content of less than 0.1599% of the mass. (or 1599 ppm), may have a sulfur content of approximately 2.683 wt%. (or 26830 ppm), may have a viscosity at 100°C of approximately 48.79 centistokes (cSt), may have an MCRT of 9.53 wt%. and may have a total metal content of 58.45 ppm.

[00164] Although different properties are described with respect to Arab Light and Arab Extra Light oils, the above also applies to other types of crude oil such as desalted oil, condensate, biogenetic oil, synthetic oil, tight oil, heavy hydrocarbons, recovered crude oil, and bituminous oil. oil.

[00165] Embodiments of the invention involve the regulation of different boiling ranges of fractions and reactor conditions based on one or more of the aforementioned properties. Methods in accordance with embodiments of the invention may evaluate the petroleum feedstock to be used by measuring one or more of various properties of the incoming feedstock. Based on one or more properties of the boiling range of the fractions, catalyst types (for moving bed reactors), pressure, temperatures, space velocity, hydrogen feed rate and other variables can be adjusted to more effectively and efficiently use the reactor configuration to maintain the primary, close to optimal or optimal conditioning of the feedstock and various cuts to the desired feedstock for the steam cracker.

[00166] For example, a fluidized bed that receives a heavy cut may have the ability to process some hydrocarbon having a sulfur content of less than 40,000 ppm. If a particular 490°C+ heavy cut has a sulfur content greater than 40,000 ppm, fluidized bed performance may be reduced. Accordingly, the boiling range of the heavy cut can be lowered to 465°C+, for example, to have a sulfur content of less than 40,000 ppm. In addition, if a particular fraction of 160-490°C average shoulder strap has, for example, a hydrogen content of more than 14% of the mass. and the content of nitrogen, sulfur, MCRT and all metals is acceptably low, the light cut fraction can be expanded (for example, from 160°C- to 190°C-) to direct more of the total crude oil directly to the steam cracker. On the other hand, if the middle cut contains, for example, little hydrogen and/or the content of sulfur, nitrogen, MCRT and/or all metals is not low enough, the light cut can be narrowed (for example, from 160°C- to 130°C- ) so that the additional middle cut can be processed in the fixed bed conditioning steps.

[00167] The methods described in the invention provide the necessary flexibility to maintain a high conversion of feedstock to petrochemicals. A person skilled in the art who is aware that the types of hydrocarbon components, sulfur content, nitrogen content, etc. can vary greatly among different types of feedstock (Arab extra light oil is very different from West Texas medium oil (West Texas Intermediate) ) and that a given plant can process feedstock from different sources on any given day, week, month or year, recognizes the advantages of the methods described in the invention for the flexible production of petroleum products from a variety of different feedstocks.

[00168] As described above, embodiments of the invention can be used to convert all crude oil, including heavier fractions of crude oil, into high value petrochemicals and can minimize the amount sent to the HFO tank, which improves profitability. HFO from the tank can also be upgraded to IMO 2020 compliant HFO, further adding value to products.

[00169] Embodiments of the invention may first separate a wide boiling range hydrocarbon feedstock into light, medium, and heavy cuts. Dividing the feedstock into different cuts can provide optimal processing conditions, reactor size, and other factors not achievable in flowsheets that teach one skilled in the art to hydrotreat or otherwise condition the entire crude oil, or even a heavy portion, such as a single 200 °+ shoulder strap The ability to prepare steam cracker feedstock from separate medium cuts and heavy cuts under reaction conditions more suitable for the hydrocarbons in these respective fractions provides primarily improved production of petrochemicals as described in the invention and provides one or more of the following advantages: service life of the middle run conditioning catalyst; economic reactor size for each of the respective cuts; the agreed periods of operation of the middle run conditioning system and the steam cracker; the ability to condition the respective fractions under preferred conditions; the ability to orient the catalyst for preferential conditioning of the respective fractions; and other advantages that can be easily determined by a person skilled in the art based on the above description.

[00170] As described above, the embodiments contemplated by the invention may refer to one or more of the following embodiments.

[00171] Embodiment 1: A process for converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy oil fraction;

destructive hydrogenation and hydrocracking of the medium-boiling fraction and the hydrocracked fraction of vacuum residues to obtain a hydrotreated and hydrocracked effluent;

feeding the hydrotreated and hydrocracked effluent and the lighter fraction to at least one of the steam cracker and aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO ).

[00172] Embodiment 2: The method of Embodiment 1 wherein the light-boiling fraction has two or more of the following properties:

95% initial boiling point in the range from about 130 to 200°C;

a hydrogen content of at least 14% by weight;

ICGB less than 5;

API gravity greater than 40°;

sulfur content is less than 1000 ppm;

nitrogen content is less than 10 ppm;

viscosity measured at 40°C less than 1 cSt;

less than 1% of the mass. MCRT; And

less than 1 ppm of all metals.

[00173] Embodiment 3: The method of Embodiment 1 or Embodiment 2, wherein the medium boiling fraction has two or more of the following properties:

5% initial boiling point in the range from about 130 to 200°C;

95% initial boiling point in the range from about 400 to 600°C;

a hydrogen content in the range of about 12 to 14% by weight;

ICGB in the range from about 5 to less than 50;

API gravity in the range of approximately 10° to 40°;

sulfur content in the range from about 1000 to 10000 ppm;

nitrogen content in the range from about 1 to 100 ppm;

viscosity, measured at 40°C, greater than 1 cSt;

less than 5% of the mass. MCRT; And

less than 50 ppm all metals.

[00174] Embodiment 4: The method of any one of Embodiments 1-3, wherein the heavy boiling fraction has two or more of the following properties:

5% initial boiling point in the range from about 400 to 600°C;

the hydrogen content is less than 12% wt.;

ICGB more than 50;

API gravity less than 10°;

sulfur content is more than 10000 ppm;

nitrogen content is more than 100 ppm;

viscosity, measured at 100°C, greater than 100 cSt;

more than 5% of the mass. MCRT; And

more than 50 ppm all metals.

[00175] Embodiment 5: The method of any one of Embodiments 1-4, wherein:

the hydrocracked vacuum residue fraction has a 95% initial boiling point in the range of approximately 400 to 560°C.

[00176] Embodiment 6: The process of any one of Embodiments 1-5, wherein the high-boiling residue fraction has a 5% initial boiling point greater than about 545°C.

[00177] Embodiment 7: The method of any one of Embodiments 1-6 wherein hydrocracking the high boiling residue fraction comprises contacting the high boiling residue fraction and the pyrolysis oil with an extrudate or catalyst slurry under conditions sufficient to convert at least a portion of hydrocarbons of the high-boiling residue fraction into lighter hydrocarbons.

[00178] Embodiment 8: The process of any one of Embodiments 1-7 wherein the hydrocracking of the high boiling residue fraction comprises converting over 70% of hydrocarbons having a boiling point greater than 565°C.

[00179] Embodiment 9: The process of any one of Embodiments 1-8, wherein the destructive hydrogenation and hydrocracking of the medium-boiling fraction and the hydrocracked vacuum residue fraction comprises destructive hydrogenation of the medium-boiling fraction and the hydrocracked vacuum residue fraction in a common destructive hydrogenation unit and hydrocracking the effluent from common site of destructive hydrogenation in the site of hydrocracking.

[00180] Embodiment 10: The process of any one of Embodiments 1-9, wherein the destructive hydrogenation and hydrocracking of the medium-boiling fraction and the hydrocracked vacuum residue fraction comprises:

destructive hydrogenation of the medium-boiling fraction in the first node of destructive hydrogenation;

destructive hydrogenation of the hydrocracked fraction of vacuum residues in the second node of destructive hydrogenation; And

combining the effluents from the first and second destructive hydrogenation units; and hydrocracking the combined effluents in the hydrocracking unit.

[00181] Embodiment 11: The process of Embodiment 10 further comprising destructively hydrogenating the hydrocracked fraction of the vacuum residues in the first destructive hydrogenation unit at the time that the catalyst in the second destructive hydrogenation unit is replaced.

[00182] Embodiment 12: The method of any one of Embodiments 1-11, further comprising hydrodesulfurizing the heavy fuel oil fraction to produce an ultra low sulfur heavy fuel oil.

[00183] Embodiment 13: The method of any one of Embodiments 1-12, wherein the total production of petrochemicals is at least 65% by weight. based on the total amount of olefins and aromatics produced compared to the total amount of input feedstock, including all crude oil and any additional feedstock.

[00184] Embodiment 14: The process of any one of Embodiments 1-13, wherein feeding the hydrotreated and hydrocracked effluent and the lighter fraction to at least one of the steam cracker and the aromatics complex includes:

separating the hydrotreated and hydrocracked effluent and the light-boiling fraction in a separator to obtain a light naphtha fraction and a heavy naphtha fraction;

feeding the light naphtha fraction to the steam cracker unit; And

feeding the heavy naphtha fraction to the complex for the production of aromatic compounds.

[00185] Embodiment 15: The process of any one of Embodiments 1-14, comprising feeding the hydrotreated and hydrocracked effluent and the lighter fraction directly to the steam cracker.

[00186] Embodiment 16: A process for converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy oil fraction;

destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent;

destructive hydrogenation of the hydrocracked fraction of vacuum residues to obtain a second destructively hydrogenated effluent

mixing the first and second destructively hydrogenated effluents to form a mixture, and hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent;

feeding the hydrotreated and hydrocracked effluent and the lighter fraction to at least one of the steam cracker and aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO ).

[00187] Embodiment 17: A process for converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy oil fraction;

destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent;

destructively hydrogenating the hydrocracked fraction of vacuum residues to obtain a second destructively hydrogenated effluent;

mixing the first and second destructively hydrogenated effluents to form a mixture, and hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent;

feeding the hydrotreated and hydrocracked effluent and the lighter fraction to at least one of the steam cracker and aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO ).

[00188] Embodiment 18: The method of Embodiment 17 wherein the light-boiling fraction has two or more of the following properties:

95% initial boiling point in the range from about 130 to 200°C;

a hydrogen content of at least 14% by weight;

ICGB less than 5;

API gravity greater than 40°;

sulfur content is less than 1000 ppm;

nitrogen content is less than 10 ppm;

viscosity measured at 40°C less than 1 cSt;

less than 1% of the mass. MCRT; And

less than 1 ppm of all metals.

[00189] Embodiment 19: The method of Embodiment 17 or Embodiment 18 wherein the medium boiling fraction has two or more of the following properties:

5% initial boiling point in the range from about 130 to 200°C;

95% initial boiling point in the range from about 400 to 600°C;

a hydrogen content in the range of about 12 to 14% by weight;

ICGB in the range from about 5 to less than 50;

API gravity in the range of approximately 10° to 40°;

sulfur content in the range from about 1000 to 10000 ppm;

nitrogen content in the range from about 1 to 100 ppm;

viscosity, measured at 40°C, greater than 1 cSt;

less than 5% of the mass. MCRT; And

less than 50 ppm all metals.

[00190] Embodiment 20: The method of any one of Embodiments 17-19, wherein the heavy boiling fraction has two or more of the following properties:

5% initial boiling point in the range from about 400 to 600°C;

the hydrogen content is less than 12% wt.;

ICGB more than 50;

API gravity less than 10°;

sulfur content is more than 10000 ppm;

nitrogen content is more than 100 ppm;

viscosity, measured at 100°C, greater than 100 cSt;

more than 5% of the mass. MCRT; And

more than 50 ppm all metals.

[00191] Embodiment 21: The method of any one of Embodiments 17-20, wherein:

the hydrocracked vacuum residue fraction has a 95% initial boiling point in the range of approximately 400 to 560°C.

[00192] Embodiment 22: The method of any one of Embodiments 17-21 wherein the high boiling residue fraction has a 5% initial boiling point greater than about 545°C.

[00193] Embodiment 23: The method of any one of embodiments 17-22, wherein hydrocracking the high-boiling residue fraction comprises contacting the high-boiling residue fraction and the pyrolysis oil with an extrudate or catalyst slurry under conditions sufficient to convert at least a portion of hydrocarbons of the high-boiling residue fraction into lighter hydrocarbons.

[00194] Embodiment 24: The process of any one of Embodiments 17-23, wherein the hydrocracking of the high boiling residue fraction comprises converting over 70% of hydrocarbons having a boiling point greater than 565°C.

[00195] Embodiment 25: The method of any one of embodiments 17-24, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the hydrocracked vacuum residue fraction comprise the destructive hydrogenation of the medium-boiling fraction and the hydrocracked vacuum residue fraction in a common destructive hydrogenation unit.

[00196] Embodiment 26: The method of any one of Embodiments 17-25, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the hydrocracked vacuum residue fraction comprise:

destructive hydrogenation of the medium-boiling fraction in the first node of destructive hydrogenation;

destructive hydrogenation of the hydrocracked fraction of vacuum residues in the second node of destructive hydrogenation; And

combining the effluents from the first and second destructive hydrogenation units.

[00197] Embodiment 27: The method of Embodiment 26 further comprising destructively hydrogenating the hydrocracked fraction of the vacuum residues in the first destructive hydrogenation unit at the time that the catalyst in the second destructive hydrogenation unit is replaced.

[00198] Embodiment 28: The method of any one of Embodiments 17-27, further comprising hydrodesulfurizing the heavy fuel oil fraction to produce an ultra low sulfur heavy fuel oil.

[00199] Embodiment 29: The method of any one of Embodiments 17-28, wherein the total production of petrochemicals is at least 65% by weight. based on the total amount of olefins and aromatics produced compared to the total amount of input feedstock, including all crude oil and any additional feedstock.

[00200] Embodiment 30: The process of any one of Embodiments 17-29, wherein feeding the hydrotreated and hydrocracked effluent and the light fraction to at least one of the steam cracker and the aromatics complex includes:

separating the hydrotreated and hydrocracked effluent and the light-boiling fraction in a separator to obtain a light naphtha fraction and a heavy naphtha fraction;

feeding the light naphtha fraction to the steam cracker unit; And

feeding the heavy naphtha fraction to the complex for the production of aromatic compounds.

[00201] Embodiment 31: The process of any one of Embodiments 17-30, comprising feeding the hydrotreated and hydrocracked effluent and the lighter fraction directly to the steam cracker.

[00202] Embodiment 32: A process for converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the entire crude oil into at least a first fraction, a second fraction and a third fraction, where:

the first fraction has an ICGB of less than 20 and a hydrogen content of more than 13% by weight;

the third fraction has an ICGB greater than 30 and a hydrogen content of less than 13% by mass;

and the second fraction has an ICGB and a hydrogen content intermediate between the corresponding values for the first and third fractions;

hydrocracking the third fraction to form a hydrocracked effluent and separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy fuel oil fraction;

destructive hydrogenation and hydrocracking of the second fraction and the hydrocracked vacuum residue fraction to produce a hydrotreated and hydrocracked effluent;

feeding the hydrotreated and hydrocracked effluent and the first fraction to at least one of the steam cracker and aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO ).

[00203] Embodiment 33: A process for converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

hydrocracking the high-boiling residue fraction and the heavy fraction to form a hydrocracked effluent, and separating the hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy fuel oil fraction;

destructive hydrogenation and hydrocracking of the medium-boiling fraction and the hydrocracked fraction of vacuum residues to obtain a hydrotreated and hydrocracked effluent;

separating the hydrotreated and hydrocracked effluent to obtain a light fraction and a heavy fraction;

supplying a light fraction and a low-boiling fraction in a separator to recover a light naphtha fraction and a heavy naphtha fraction;

feeding the light naphtha fraction to a steam cracker for converting the light naphtha fraction into petrochemicals including ethylene, propylene and butenes; And

feeding the heavy naphtha fraction to the complex for the production of aromatic compounds for the conversion of hydrocarbons contained in them into petrochemical products, including benzene, toluene and xylenes.

[00204] Embodiment 34: The process of Embodiment 33 further comprising mixing the heavy catalytic cracking residue with the high boiling residue fraction prior to hydrocracking the high boiling residue fraction.

[00205] Embodiment 35: The process of Embodiment 33 or 34 further comprising blending the light cycle oil with a medium-boiling fraction prior to destructive hydrogenation and hydrocracking of the medium-boiling fraction.

[00206] Embodiment 36: A process for converting whole crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating all of the crude oil in the first separating device into a low-boiling fraction and a residual fraction;

separating the residual fraction in the second separation device into a medium boiling fraction and a high boiling residue fraction;

hydrocracking the high-boiling residue fraction to form a hydrocracked effluent;

separating the hydrocracked effluent to obtain a first converted fraction and a first heavy fraction;

hydrocracking the first heavy fraction to form a second hydrocracked effluent;

separating the second hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy fuel oil fraction;

destructive hydrogenation of the medium-boiling fraction, the first converted fraction and the hydrocracked fraction of the vacuum residues to obtain a hydrotreated effluent;

separating the hydrotreated effluent stream to obtain a light component fraction containing hydrogen and hydrogen sulfide, an acidic water stream, and a hydrotreated fraction;

hydrocracking the hydrotreated fraction and the pyrolysis oil fraction to produce a second hydrocracked effluent;

separating the second hydrocracked effluent to recover a light component fraction containing hydrogen and a hydrocracked fraction;

feeding the light fraction and the hydrocracked fraction to the separator to recover the light naphtha fraction and the heavy naphtha fraction;

feeding the light naphtha fraction to a steam cracker for converting the light naphtha fraction into petrochemicals including ethylene, propylene and butenes; And

feeding the heavy naphtha fraction to the complex for the production of aromatic compounds for the conversion of hydrocarbons contained in them into petrochemical products, including benzene, toluene and xylenes.

[00207] Embodiment 37: The embodiments of any one of Embodiments 1-36, wherein the light-boiling fraction or the first fraction, respectively, has two or more of the following properties:

95% initial boiling point in the range from about 90 to 300°C;

a hydrogen content of at least 13% by weight;

ICGB less than 20;

API gravity greater than 10°;

the sulfur content is less than 1% wt.;

nitrogen content is less than 100 ppm;

viscosity measured at 40°C less than 10 cSt;

less than 1% of the mass. MCRT; And

less than 1 ppm of all metals.

[00208] Embodiment 38, Embodiments of any one of Embodiments 1-36, wherein the light-boiling fraction or the first fraction, respectively, has two or more of the following properties:

95% initial boiling point in the range from about 110 to 250°C;

a hydrogen content of at least 13.5% by weight;

ICGB less than 10;

API gravity greater than 20°;

sulfur content is less than 5000 ppm;

nitrogen content is less than 10 ppm;

viscosity measured at 40°C less than 5 cSt;

less than 1% of the mass. MCRT; And

less than 1 ppm of all metals.

[00209] Embodiment 39: The embodiments of any one of Embodiments 1-36, wherein the light-boiling fraction or the first fraction, respectively, has two or more of the following properties:

95% initial boiling point in the range from about 130 to 200°C;

a hydrogen content of at least 14% by weight;

ICGB less than 5;

API gravity greater than 40°;

sulfur content is less than 1000 ppm;

nitrogen content is less than 1 ppm;

viscosity measured at 40°C less than 1 cSt;

less than 1% of the mass. MCRT; And

less than 1 ppm of all metals.

[00210] Embodiment 40: The embodiments of any one of Embodiments 1-36, wherein the medium boiling fraction or the second fraction, respectively, has two or more of the following properties:

5% initial boiling point in the range from about 130 to 200°C;

95% initial boiling point in the range from about 400 to 600°C;

a hydrogen content in the range of about 12 to 14% by weight;

ICGB in the range from about 5 to less than 50;

API gravity in the range of approximately 10° to 40°;

sulfur content in the range from about 1000 to 10000 ppm;

nitrogen content in the range from about 1 to 100 ppm;

viscosity, measured at 40°C, greater than 1 cSt;

less than 5% of the mass. MCRT; And

less than 50 ppm all metals.

[00211] Embodiment 41: The embodiments of any one of Embodiments 1-36, wherein the medium boiling fraction or the second fraction, respectively, has two or more of the following properties:

5% initial boiling point in the range from about 110 to 250°C;

95% initial boiling point in the range from about 350 to 650°C;

a hydrogen content in the range of about 12 to 14% by weight;

ICGB in the range from about 5 to less than 50;

API gravity in the range of approximately 10° to 40°;

sulfur content in the range from about 1000 to 10000 ppm;

nitrogen content in the range from about 1 to 100 ppm;

viscosity, measured at 40°C, greater than 1 cSt;

less than 5% of the mass. MCRT; And

less than 50 ppm all metals.

[00212] Embodiment 42: The embodiments of any one of Embodiments 1-36, wherein the medium boiling fraction or the second fraction, respectively, has two or more of the following properties:

5% initial boiling point in the range from about 90 to 300°C;

95% initial boiling point in the range from about 300 to 700°C;

a hydrogen content in the range of about 12 to 14% by weight;

ICGB in the range from about 5 to less than 50;

API gravity in the range of approximately 10° to 40°;

sulfur content in the range from about 1000 to 10000 ppm;

nitrogen content in the range from about 1 to 100 ppm;

viscosity, measured at 40°C, greater than 1 cSt;

less than 5% of the mass. MCRT; And

less than 50 ppm all metals.

[00213] Embodiment 43: The embodiments of any of Embodiments 1-36, wherein the heavy boiling fraction or the third fraction, respectively, has two or more of the following properties:

5% initial boiling point in the range from about 300 to 700°C;

the hydrogen content is less than 13% wt.;

ICGB more than 30;

API gravity less than 40°;

sulfur content is more than 1000 ppm;

nitrogen content is more than 10 ppm;

viscosity, measured at 100°C, greater than 10 cSt;

more than 0.5% of the mass. MCRT; And

greater than 1 ppm of all metals.

[00214] Embodiment 44: The embodiments of any of Embodiments 1-36, wherein the heavy boiling fraction or the third fraction, respectively, has two or more of the following properties:

5% initial boiling point in the range from about 350 to 650°C;

the hydrogen content is less than 12.5% wt.;

ICGB more than 40;

API gravity less than 20°;

sulfur content is more than 5000 ppm;

nitrogen content is more than 50 ppm;

viscosity, measured at 100°C, greater than 50 cSt;

more than 1% of the mass. MCRT; And

more than 10 ppm of all metals.

[00215] Embodiment 45: The embodiments of any one of Embodiments 1-36, wherein the heavy boiling fraction or the third fraction, respectively, has two or more of the following properties:

5% initial boiling point in the range from about 400 to 600°C;

the hydrogen content is less than 12% wt.;

ICGB more than 50;

API gravity less than 10°;

sulfur content is more than 10000 ppm;

nitrogen content is more than 100 ppm;

viscosity, measured at 100°C, greater than 100 cSt;

more than 5% of the mass. MCRT; And

more than 50 ppm all metals.

[00216] Embodiment 46: A system for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and this system includes:

a separation system for separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

a hydrocracking reaction zone for hydrocracking the high-boiling residue fraction to form a hydrocracked effluent; and a separation system for separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy fuel oil fraction;

a reaction zone for destructive hydrogenation and hydrocracking of the medium-boiling fraction and hydrocracked fraction of vacuum residues to obtain a hydrotreated and hydrocracked effluent;

a steam cracker; and optionally an aromatics complex for converting the hydrotreated and hydrocracked effluent and lighter fraction into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO).

[00217] Embodiment 47: The system of Embodiment 46 wherein the hydrocracking reaction zone for hydrocracking the high boiling residue fraction includes a slurry or fluidized bed reactor.

[00218] Embodiment 48: The system of any one of embodiments 46-47, wherein the reaction zone for destructive hydrogenation and hydrocracking of the medium-boiling fraction and the hydrocracked residue fraction includes a common destructive hydrogenation unit for the destructive hydrogenation of the medium-boiling fraction and the hydrocracked residue fraction and a reactor hydrocracking unit for hydrocracking the effluent from the common destructive hydrogenation unit.

[00219] Embodiment 49: The system of any one of Embodiments 46-48, wherein the reaction zone for destructive hydrogenation and hydrocracking of the medium-boiling fraction and the hydrocracked vacuum residue fraction comprises:

a first destructive hydrogenation unit for destructive hydrogenation of the medium-boiling fraction;

a second destructive hydrogenation unit for destructive hydrogenation of the hydrocracked fraction of vacuum residues; And

a mixer for combining the outlet streams from the first and second destructive hydrogenation units.

[00220] Embodiment 50: The system of Embodiment 49 further including a diverter for diverting the hydrocracked fraction of the vacuum residues to the first destructive hydrogenation unit at the time that the catalyst in the second destructive hydrogenation unit is replaced.

[00221] Embodiment 51: The system of any one of embodiments 46-50, further comprising a reactor for hydrodesulfurizing a heavy fuel oil fraction to produce an ultra low sulfur heavy fuel oil.

[00222] Embodiment 52: The system of any one of Embodiments 46-51, further comprising:

a separator for separating the hydrotreated and hydrocracked effluent and the low-boiling fraction to obtain a light naphtha fraction and a heavy naphtha fraction;

a flow line for supplying a light naphtha fraction to a steam cracker assembly; And

a production line for supplying the heavy naphtha fraction to the complex for the production of aromatic compounds.

[00223] Embodiment 53: A system for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and this system includes:

a separation system for separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

a hydrocracking unit for hydrocracking the high-boiling residue fraction to form a hydrocracked effluent, and a separator for separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy fuel oil fraction;

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

a second conditioning unit for destructively hydrogenating the hydrocracked vacuum residue fraction to produce a second destructively hydrogenated effluent;

a mixer for mixing the first and second destructively hydrogenated effluents to form a mixture, and a hydrocracking unit for hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent;

a flow line for supplying a hydrotreated and hydrocracked effluent and a low-boiling fraction to at least one of the steam cracker and the aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra-low sulfur heavy oil fuel (ULSFO).

[00224] Embodiment 54: A system for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and this system includes:

a separation system for separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

a hydrocracking unit for hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy oil fraction;

a first conditioning reactor for destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent;

a second conditioning reactor for destructive hydrogenation of the hydrocracked vacuum residue fraction to produce a second destructively hydrogenated effluent;

a mixer for mixing the first and second destructively hydrogenated effluents to form a mixture, and a hydrocracking unit for hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent;

one or more flow lines for supplying hydrotreated and hydrocracked effluent and low-boiling fraction to at least one of the steam cracker and aromatics complex for converting hydrocarbons therein into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO).

[00225] Embodiment 55: The system of Embodiment 54 wherein the hydrocracking unit for hydrocracking the high boiling residue fraction includes a slurry or fluidized bed reactor.

[00226] Embodiment 56: The system of Embodiment 55 further comprising a flow line for diverting a hydrocracked fraction of the vacuum residues to the first destructive hydrogenation unit at a time when the catalyst in the second destructive hydrogenation unit is replaced.

[00227] Embodiment 57: The system of any one of embodiments 54-56, further comprising a reactor for hydrodesulfurizing a heavy fuel oil fraction to produce an ultra low sulfur heavy fuel oil.

[00228] Embodiment 58: The system of any one of Embodiments 54-57, comprising:

a separator for separating the hydrotreated and hydrocracked effluent and the low-boiling fraction to obtain a light naphtha fraction and a heavy naphtha fraction;

a flow line for supplying a light naphtha fraction to a steam cracker assembly; And

a production line for supplying the heavy naphtha fraction to the complex for the production of aromatic compounds.

[00229] Embodiment 59: A system for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and this system includes:

a separation system for separating the entire crude oil into at least a first fraction, a second fraction and a third fraction, where:

the first fraction has an ICGB of less than 20 and a hydrogen content of more than 13% by weight;

the third fraction has an ICGB greater than 30 and a hydrogen content of less than 13% by mass;

and the second fraction has an ICGB and a hydrogen content intermediate between the corresponding values for the first and third fractions;

a hydrocracking unit for hydrocracking the third fraction to form a hydrocracked effluent and a separator for separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy oil fraction;

a conditioning zone for destructive hydrogenation and hydrocracking of the second fraction and the hydrocracked vacuum residue fraction to produce a hydrotreated and hydrocracked effluent;

one or more flow lines for supplying the hydrotreated and hydrocracked effluent and the first fraction to at least one of the steam cracker and the aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO).

[00230] Embodiment 60: A system for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and this system includes:

a separation system for separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

a hydrocracking unit for hydrocracking the high-boiling residue fraction and the heavy fraction to form a hydrocracked effluent, and a separator for separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy fuel oil fraction;

a conditioning zone for destructive hydrogenation and hydrocracking of the medium-boiling fraction and hydrocracked fraction of vacuum residues to obtain a hydrotreated and hydrocracked effluent;

a separator for separating the hydrotreated and hydrocracked effluent into a light fraction and a heavy fraction;

a separator for separating the light fraction and the low-boiling fraction with the extraction of the light naphtha fraction and the heavy naphtha fraction;

a steam cracker for converting light naphtha fraction into petrochemical products including ethylene, propylene and butenes; And

complex for the production of aromatic compounds for the conversion of heavy naphtha into petrochemical products, including benzene, toluene and xylenes.

[00231] Embodiment 61: The system of Embodiment 60 further including a mixer for mixing the heavy catalytic cracking residue with the high boiling residue fraction upstream of the hydrocracking unit for hydrocracking the high boiling residue fraction.

[00232] Embodiment 62: The system of Embodiment 60 or 61 further including a mixer for mixing light cycle oil with a medium-boiling fraction.

[00233] Embodiment 63: A system for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, and this system includes:

a separation system for separating all of the crude oil in the first separation device into a low-boiling fraction and a residual fraction;

a separation system for separating the residual fraction in the second separation device into a medium boiling fraction and a high boiling residue fraction;

a hydrocracking unit for hydrocracking the high-boiling residue fraction to form a hydrocracked effluent;

a separator for separating the hydrocracked effluent to obtain a first converted fraction and a first heavy fraction;

a hydrocracking unit for hydrocracking the first heavy fraction to form a second hydrocracked effluent;

a separator for separating the second hydrocracked effluent stream to obtain a hydrocracked vacuum residue fraction and a heavy fuel oil fraction;

a conditioning reactor for destructively hydrogenating the medium-boiling fraction, the first converted fraction, and the hydrocracked vacuum residue fraction to produce a hydrotreated effluent;

a separator for separating the hydrotreated effluent stream to obtain a light component fraction containing hydrogen and hydrogen sulfide, an acidic water stream, and a hydrotreated fraction;

a hydrocracking unit for hydrocracking the hydrotreated fraction and the pyrolysis oil fraction to produce a second hydrocracked effluent;

a separator for separating the second hydrocracked effluent stream to recover a light component fraction containing hydrogen and a hydrocracked fraction;

separator for separation of light fraction and hydrocracked fraction with extraction of light naphtha fraction and heavy naphtha fraction;

a steam cracker for converting light naphtha fraction into petrochemical products including ethylene, propylene and butenes; And

complex for the production of aromatic compounds for the conversion of heavy naphtha fraction into petrochemical products, including benzene, toluene and xylenes.

[00234] Embodiment 64: The system of any one of Embodiments 46-63, wherein the separation system for separating the entire crude oil includes:

a heater for heating the entire crude oil to obtain a heated entire crude oil;

a separator for separating the heated entire crude oil with the extraction of the first fraction and the residual fraction;

a heater for heating the residual fraction to obtain a heated residual fraction;

a hydrogen hot stripping column for separating the heated residual fraction to produce overheads containing hydrogen and a second fraction and bottoms containing a third fraction.

[00235] Embodiment 65: The system of Embodiment 64 further including a heat exchanger for heat exchange between the bottoms fraction and bottoms.

[00236] While the description includes a limited number of embodiments, one skilled in the art taking advantage of this invention will appreciate that other embodiments may be devised that do not depart from the scope of the present invention. Therefore, the scope of the invention is to be limited only by the appended claims.

Claims (76)

1. A process for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, comprising: separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction; hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to obtain a hydrocracked vacuum residue fraction and a heavy oil fraction; destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent; destructively hydrogenating the hydrocracked fraction of vacuum residues to obtain a second destructively hydrogenated effluent; mixing the first and second destructively hydrogenated effluents to form a mixture, and hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent; feeding the hydrotreated and hydrocracked effluent and the lighter fraction to at least one of the steam cracker and aromatics complex to convert their hydrocarbons into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO ). 2. The method according to claim 1, wherein the low-boiling fraction has two or more of the following properties: 95% initial boiling point in the range from about 130 to 200°C; a hydrogen content of at least 14% by weight; BMCI (Bureau of Mines Correlation Index (BMCI)) less than 5; API gravity ((API) greater than 40°; sulfur content is less than 1000 ppm; nitrogen content is less than 10 ppm; viscosity measured at 40°C less than 1 cSt; less than 1% of the mass. MCRT (microcarbon residue (MCRT)); And less than 1 ppm of all metals. 3. The method according to claim 1 or 2, in which the medium-boiling fraction has two or more of the following properties: 5% initial boiling point in the range from about 130 to 200°C; 95% initial boiling point in the range from about 400 to 600°C; a hydrogen content in the range of about 12 to 14% by weight; ICGB in the range from about 5 to less than 50; API gravity in the range of approximately 10° to 40°; sulfur content in the range from about 1000 to 10000 ppm; nitrogen content in the range from about 1 to 100 ppm; viscosity, measured at 40°C, greater than 1 cSt; less than 5% of the mass. MCRT; And less than 50 ppm all metals. 4. The method according to any one of paragraphs. 1-3, wherein the heavy fuel oil fraction has two or more of the following properties: 5% initial boiling point in the range from about 400 to 600°C; the hydrogen content is less than 12% wt.; ICGB more than 50; API gravity less than 10°; sulfur content is more than 10000 ppm; nitrogen content is more than 100 ppm; viscosity, measured at 100°C, greater than 100 cSt; more than 5% of the mass. MCRT; And more than 50 ppm all metals. 5. The method according to any one of paragraphs. 1-4, in which: the hydrocracked vacuum residue fraction has a 95% initial boiling point in the range of approximately 400 to 560°C. 6. The method according to any one of paragraphs. 1-5, in which the high-boiling residue fraction has a 5% initial boiling point greater than about 545°C. 7. The method according to any one of paragraphs. 1-6, in which the hydrocracking of the high-boiling residue fraction includes contacting the high-boiling residue fraction and pyrolysis oil with an extrudate or catalyst slurry under conditions sufficient to convert at least a portion of the hydrocarbons of the high-boiling residue fraction to lighter hydrocarbons. 8. The method according to any one of paragraphs. 1-7, in which the hydrocracking of the high boiling residue fraction includes the conversion of over 70% of hydrocarbons having a boiling point greater than 565°C. 9. The method according to any one of paragraphs. 1-8, in which the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the hydrocracked fraction of the vacuum residues include: destructive hydrogenation of the medium-boiling fraction in the first node of destructive hydrogenation; destructive hydrogenation of the hydrocracked fraction of vacuum residues in the second node of destructive hydrogenation; And combining the outgoing streams from the first and second nodes of destructive hydrogenation. 10. The method of claim 9, further comprising destructive hydrogenation of the hydrocracked fraction of the vacuum residues in the first destructive hydrogenation unit during the time period when the catalyst in the second destructive hydrogenation unit is replaced. 11. The method according to any one of paragraphs. 1-10 further comprising hydrodesulfurizing the heavy fuel oil fraction to produce ultra low sulfur heavy fuel oil. 12. The method according to any one of paragraphs. 1-11, in which the total production of petrochemical products is at least 65% of the mass. based on the total amount of olefins and aromatics produced compared to the total amount of input feedstock, including all crude oil and any additional feedstock. 13. The method according to any one of paragraphs. 1-12, in which the supply of hydrotreated and hydrocracked effluent and low-boiling fraction to at least one of the steam cracker and aromatics complex includes: separating the hydrotreated and hydrocracked effluent and the light-boiling fraction in a separator to obtain a light naphtha fraction and a heavy naphtha fraction; feeding the light naphtha fraction to the steam cracker unit; And feeding the heavy naphtha fraction to the complex for the production of aromatic compounds. 14. The method according to any one of paragraphs. 1-13, which includes feeding the hydrotreated and hydrocracked effluent and the low-boiling fraction directly to the steam cracker. 15. The process of claim 1, wherein all of the crude oil is a condensate and wherein the light-boiling fraction has a 95% initial boiling point in the range of about 500 to 565°C. 16. A system for converting all crude oil and other high-boiling hydrocarbon streams to produce olefins and/or aromatics, comprising: a separation system for separating the entire crude oil into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction; a hydrocracking unit for hydrocracking the high-boiling residue fraction to form a hydrocracked effluent and separating the hydrocracked effluent to produce a hydrocracked vacuum residue fraction and a heavy oil fraction; a first conditioning reactor for destructively hydrogenating the medium-boiling fraction to form a first destructively hydrogenated effluent; a second conditioning reactor for destructive hydrogenation of the hydrocracked vacuum residue fraction to produce a second destructively hydrogenated effluent; a mixer for mixing the first and second destructively hydrogenated effluents to form a mixture, and a hydrocracking unit for hydrocracking the mixture to produce a hydrotreated and hydrocracked effluent; one or more flow lines for supplying hydrotreated and hydrocracked effluent and low-boiling fraction to at least one of the steam cracker and aromatics complex for converting hydrocarbons therein into petrochemicals and pyrolysis oil and/or ultra low sulfur heavy fuel oil (ULSFO). 17. The system of claim 16, wherein the hydrocracking unit for hydrocracking the high-boiling residue fraction comprises a slurry or fluidized bed reactor. 18. The system of claim 17, further comprising a flow line for diverting the hydrocracked fraction of vacuum residues to the first destructive hydrogenation unit during the time period when the catalyst in the second destructive hydrogenation unit is replaced. 19. The system according to any one of paragraphs. 16-18 further comprising a reactor for hydrodesulfurizing the heavy fuel oil fraction to produce ultra low sulfur heavy fuel oil. 20. The system according to any one of paragraphs. 16-19, including: a separator for separating the hydrotreated and hydrocracked effluent and the low-boiling fraction to obtain a light naphtha fraction and a heavy naphtha fraction; a flow line for supplying a light naphtha fraction to a steam cracker assembly; And a production line for supplying the heavy naphtha fraction to the complex for the production of aromatic compounds. 21. The system according to any one of paragraphs. 16-20, in which the separation system for separating the entire crude oil includes: a heater for heating the entire crude oil to obtain a heated entire crude oil; a separator for separating the heated entire crude oil with the extraction of the first fraction and the residual fraction; a heater for heating the residual fraction to obtain a heated residual fraction; a hydrogen hot stripping column for separating the heated residual fraction to produce overheads containing hydrogen and a second fraction and bottoms containing a third fraction. 22. The system according to claim 21, further including a heat exchanger for heat exchange between the residual fraction and bottoms.

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