RU2793939C1 - Configuration for olefins production - Google Patents

Abstract

FIELD: petrochemicals.

SUBSTANCE: inventions relate to processes for the production of petrochemical products. Described are processes for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, including separating the hydrocarbon feedstock in a first in-line separation device into at least a light-boiling fraction, a medium-boiling fraction and a high-boiling residue fraction and then converting them.

EFFECT: production of petrochemical products.

30 cl, 4 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 refinery. 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 450°F is separated from the rest of the feed and then sent with steam into the high temperature portion of the steam cracker and subjected 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 hydrodesulphurization 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 larger than 100 Å in diameter and other characteristics discussed below. The second catalyst, located downstream of the first catalyst, is characterized by the main proportion of its pore volume in pores with a diameter of less than 100 Å.

[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] 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

[0013] A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes: separating a hydrocarbon feedstock in a first in-line separator into at least a light boiling fraction, a medium boiling fraction, and a high boiling fraction remainder; hydrocracking the high-boiling residue fraction and the pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent; separating the hydrocracked effluent in a second in-line separating device to obtain a heavy fuel oil fraction and a partially conditioned fraction; destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream; feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[0014] A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes: separating a hydrocarbon feedstock in a first in-line separator into at least a light boiling fraction, a medium boiling fraction, and a high boiling fraction remainder; hydrocracking the high-boiling residue fraction in a first vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent; solvent deasphalting of the hydrocracked effluent with separation of pitch and deasphalted oil fraction; hydrocracking the deasphalted oil fraction and the pyrolysis oil in a second vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a second hydrocracked effluent; separating the hydrocracked effluent and the second hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction; destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream; feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[0015] A process for converting an entire crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes: separating a hydrocarbon feedstock in a first in-line separation device into at least a light boiling fraction, a medium boiling fraction, and a high boiling fraction remainder; hydrocracking the high-boiling residue fraction and the pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent; separating the hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction; hydrodesulfurizing the vacuum residue fraction to produce an ultra-low sulfur diesel fuel fraction; destructive hydrogenation of the medium-boiling fraction in a third conditioning unit to produce an effluent of a third conditioning unit; separating the outlet stream of the third air conditioning unit in the third built-in separating device into a light boiling conditioned fraction, a medium boiling conditioned fraction and a high boiling fraction; destructively hydrogenating the partially conditioned fraction, the medium-boiling conditioned fraction, and the diesel fuel fraction in the fourth conditioning unit to obtain an effluent of the fourth conditioning unit; separating the effluent of the fourth conditioning unit in the fourth built-in separating device into a light conditioned fraction and a diesel fuel fraction; feeding the high-boiling fraction, the light conditioned fraction, the light-boiling fraction and the light-boiling conditioned fraction to a steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[0016] Other aspects and advantages will be apparent from the description below and the appended claims.

Brief description of the drawings

[0017] FIG. 1-4 are simplified flow diagrams of systems and methods for converting all crude oil and/or streams containing heavy hydrocarbons, in accordance with embodiments of the invention.

Detailed description

[0018] 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 regard to the petrochemical subgroup, the term "chemicals" as used herein refers to ethylene, propylene, butadiene, 1-butene, isobutylene, benzene, toluene, and para-xylenes.

[0019] 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. Therefore, light feedstocks are typically hydrotreated under less severe reaction conditions, while heavy feedstocks require higher reaction pressures and temperatures.

[0020] 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.

[0021] "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 cleavage of hydrocarbon molecular bonds in the hydrocarbon and the concomitant saturation of the remaining hydrocarbon fragments with hydrogen, which can create stable lower boiling liquid petroleum products and can include both hydrocracking and hydrotreating.

[0022] "API gravity" refers to the density of a crude oil or petroleum product relative to water, as determined by ASTM D4052-11.

[0023] 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 produce 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 may 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 substantially improves conversion over with low conversion of petrochemicals of the methods of the prior art.

[0024] 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.

[0025] Hydrocarbon mixtures useful in the embodiments disclosed in the invention may include various hydrocarbon mixtures having a certain boiling point 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.

[0026] 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 by a 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).

[0027] Methods and systems in accordance with the embodiments described herein for converting crude oil as a feedstock and for producing petroleum products and low sulfur fuel oil may include a feedstock preparation section, a crude oil conditioning section, an optional aromatics processing unit, and steam cracker. The raw material preparation section may include, for example, a desalination plant. The crude oil is conditioned and processed in such a way that the cracked feedstock is sent to steam crackers to maximize chemical yields while maintaining a reasonable frequency of furnace decoking. 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 chemicals while reducing the formation of heavy polycyclic aromatic compounds (TPACs).

[0028] 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.

[0029] 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. Therefore, 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, the problem today is the conversion of the vacuum residue without significant formation of TPAS, which are detrimental to the furnaces of the steam cracker located downstream of the process. Methods and systems in accordance with embodiments of the invention can overcome these problems.

[0030] 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 cope with 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 through the use of one or more inline separation devices (ISDs) and/or a solvent deasphatization unit in crude oil conditioning processes.

[0031] Methods in accordance with embodiments of the present invention are aimed at converting the majority of crude oil into a suitable feedstock for a steam cracker. Efficient conversion of vacuum residues in accordance with the embodiments described in the invention can maximize the conversion of chemicals and maintain a low tendency to coke. This is achieved by integrating one or both of the following processes into the overall process configuration: (1) adding a hydrocracking reactor to the crude oil conditioning process, which allows the conversion of high boiling compounds to compounds that boil below 540°C; and/or (2) adding a solvent deasphalting unit to remove asphaltenes from the heavy cut of the crude oil, which in turn will increase catalyst life in fixed bed hydrotreating reactors and reduce coke formation in steam cracker furnaces. This allows all or substantially all of the processed oil to be sent to the steam cracker, reducing the overall process yield of low value fuel oil and increasing the yield of high value olefins, diolefins and benzene, toluene and xylenes (BTX).

[0032] Separation of various fractions, such as low boiling fraction (for example, 160°C-fraction) and high boiling fraction (160°C+ fraction), or such as low, medium and high boiling fractions (for example, 160°C-fraction, 160-490°C fraction and 490°C+ fraction) can increase the capital and operating cost efficiency of the methods and systems described in the invention. With respect to the three cuts in many embodiments, the inventors of the present invention recognize that condensates having generally low amounts of high boiling components and all crude oils having higher amounts 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.

[0033] 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, the 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, 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.

[0034] 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 all 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 the 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.

[0035] Thus, in some embodiments, the light cut may include hydrocarbons having a boiling point up to about 90°C (e.g., a 90°C cut), 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.

[0036] 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 fraction may have a 95% initial boiling point, for example, in the range of about 500 to 565°C.

[0037] 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.

[0038] 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% - 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 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 and/or below the temperature of the "cutting point of the fraction", respectively.

[0039] 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.

[0040] Depending on the fractionation mechanism, the heavy hydrocarbon "cut" may be relatively pure, meaning 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”.

[0041] 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.

[0042] 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.

[0043] 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. stream that is acceptable for the production of aromatic compounds.

[0044] 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.

[0045] Processing heavy hydrocarbons, such as 490° C.+ hydrocarbons, in the heavy component conditioning unit and the optional solvent deasphalting unit can increase the conversion of low value streams to high value products. When used, a solvent deasphalting unit can additionally provide benefits such as the ability to match the cycle times of conditioning reactors with a steam cracker, as well as the ability to process a wider range of feedstocks and different types of crude oil, allowing the operator to fine-tune the process. The resulting solvent deasphalted oil can then be further processed by conditioning the deasphalted oil for use in the steam cracker system. In addition, the periodic separation of NH ₃ and H ₂ S can increase the life of hydrotreating catalysts.

[0046] The crude oil conditioning section is designed 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 540°C. And fourth, the conditioning section can minimize the vacuum residue fraction of the crude oil.

[0047] Embodiments of medium and/or heavy (deasphalted oil) conditioning may focus on converting heavier hydrocarbons to produce, for example, hydrocarbons lighter than diesel fuel. Hydrotreating and hydrocracking catalysts and operating conditions can thus be chosen to direct the conversion of hydrocarbons or hydrocarbons in appropriate fractions preferentially (>50 wt %) to hydrocarbons in the naphtha range. 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 chemicals.

[0048] 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.

[0049] 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.

[0050] In some embodiments, co-conditioning of the middle and heavy ends can result in a total conversion of 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.

[0051] 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.

[0052] 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. .

[0053] 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. For example, in the configuration of FIG. 1, also described below, the entire crude oil may be conditioned, and the conditioned oil may then be steam cracked. 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 cracker. To maximize uptime, in embodiments, the design and configuration of the overall 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.

[0054] 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.

[0055] Bypass processing may include, for example, temporary processing of the 490°C+ cut in a reactor that typically processes lighter feedstocks. 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 of conditioning of heavy components. When designing the entire system for synchronization of operating periods, the configuration of the middle fraction conditioning reactors can also take into account the expected bypass processing.

[0056] The following is a brief description of the configurations for the production of olefins and/or aromatics disclosed in the invention. Process flow diagrams for various detailed configurations are further described with reference to FIG. 1-3.

[0057] In some embodiments, using the general configuration of thermal conversion of crude oil to chemical products in accordance with embodiments of the invention, it is possible to first separate a hydrocarbon feedstock with a wide boiling range to obtain a light fraction, such as a 160 ° C-fraction, a medium-boiling fraction, such as the 160-490°C fraction, and the heavy component fraction such as the 490°C+ fraction using an in-line separator. The medium boiling fraction can then be conditioned in a fixed bed reactor system with a hydrotreating catalyst system. The heavy component fraction, optionally with pyrolysis oil produced by a steam cracker, can be conditioned in a residue hydrocracking unit, for example in an LC-FINING or LC-SLURRY process. The resulting conditioned heavy components stream can then be separated to form a light conditioned cut, such as the 490° C.- cut, and a heavy conditioned cut, such as the 490° C.+ cut. The 490° C. fraction of the residual hydrotreated product can then be further conditioned together with the medium boiling fraction in a fixed bed reactor system. The resulting conditioned crude oil fractions can then be submitted to steam cracking in varying severity steam crackers in accordance with the preferred cracking temperatures for the respective fractions. The unconverted fraction from the vacuum bottoms upgrade process can be further hydrotreated to produce ultra low sulfur heavy fuel oil (ULSFO).

[0058] In other embodiments, using the general configuration of thermal conversion of crude oil to chemical products in accordance with embodiments of the invention, it is possible to first separate a hydrocarbon feedstock with a wide boiling range to obtain a light fraction, such as a 160 ° C-fraction, a medium-boiling fraction, such as the 160-490°C fraction, and the heavy component fraction such as the 490°C+ fraction using an in-line separator. The medium boiling fraction can then be conditioned in a fixed bed reactor system with a hydrotreating catalyst system. The heavy component fraction can be conditioned in a residue hydrocracking unit, for example in an LC-FINING or LC-SLURRY process. The resulting conditioned heavy components stream can then be separated to form a light conditioned cut, such as the 490° C.- cut, and a heavy conditioned cut, such as the 490° C.+ cut. The 490° C. fraction of the residual hydrotreated product can then be fed to a solvent deasphalting unit to separate the pitch from the deasphalted oil fraction. The deasphalted oil and pyrolysis oil from the steam cracker can be conditioned in a residue hydrocracking unit, for example in the LC-FINING or LC-SLURRY process. The light conditioned cut from each of the first and second stage residue hydrocracking units can be further conditioned together with the medium boiling cut in a fixed bed reactor system. The resulting conditioned crude oil fractions may then be submitted to steam cracking in varying severity steam crackers in accordance with the preferred cracking temperatures for the respective fractions.

[0059] In still other embodiments, using the general configuration of thermal conversion of crude oil to chemical products in accordance with embodiments of the invention, it is possible to first separate a hydrocarbon feedstock with a wide boiling range to obtain a light fraction, such as a 160 ° C-fraction, a medium-boiling fraction , such as the 160-490°C fraction, and the heavy component fraction, such as the 490°C+ fraction, using an in-line separation device. The medium boiling fraction can then be conditioned in a fixed bed reactor system with a hydrotreating catalyst system. The heavy component fraction, optionally with pyrolysis oil from a steam cracker, can be conditioned in a residue hydrocracking unit, for example in an LC-FINING or LC-SLURRY process. The resulting conditioned heavy components stream can then be separated to form a light conditioned cut, such as the 490° C.- cut, and a heavy conditioned cut, such as the 490° C.+ cut. The conditioned medium-boiling fraction can also be subjected to separation operations to remove ammonia and/or hydrogen sulfide, and then can be separated, for example, using an in-line separation device, into two or more fractions, including a light fraction, such as a 160 ° C-fraction, a medium a fraction such as a 160 to 360° C. fraction; and an unconverted residue (UCO) fraction. The 490°C - residual hydrotreated product fraction (conditioned heavy components fraction) and the middle fraction (160-360°C fraction from conditioning in the medium boiling range) can then be fed to a third fixed bed conditioning unit for additional conditioning of medium and heavy hydrocarbons intervals for steam cracking. The resulting effluent can also be separated into a light and heavy cut, such as a 160°C- cut and a 160°C+ cut, where the heavy cut can be returned to a third fixed bed conditioning unit to form additional naphtha range hydrocarbons suitable for thermal cracking. . In the third fixed bed conditioning unit, the streams can be reacted to reduce the aromatic content of the hydrocarbons they contain. The light conditioned cut from each of the first and third stage conditioning units can then be fed together with the straight run light cut and NPO for steam cracking in varying severity steam crackers according to the preferred cracking temperatures for the respective cuts. The unconverted fraction from the vacuum residue upgrade process can be further hydrotreated to produce ultra-low sulfur heavy fuel oil (ULSFO).

[0060] FIG. 1 is a simplified flow diagram of a total crude oil and heavy hydrocarbon conversion system in accordance with embodiments of the invention.

[0061] A heavy hydrocarbon feed with a wide boiling range, such as desalinated 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 fraction, such as 160°C - fraction 5, which does not require any conditioning and can be used as feedstock for the steam cracking section - unit 7, (b) a medium range fraction, such as 160-490°C fraction 9, and (c) a heavy fraction, such as 490°C+ fraction 11. Other boiling point temperatures can also be used to direct the desired fractions and those in them hydrocarbons to the desired units for conditioning and/or cracking. The steam cracker section 7 can be used to thermally crack the 160°C fraction, along with other feeds discussed below, to form chemical products 13 such as ethylene, propylene and butenes, which can be recovered together or as separate streams. , as well as fractions of higher-boiling pyrolysis oil 15.

[0062] The 490°C+ cut (fraction 11) and the pyrolysis oil cut 15 may be fed to the first conditioning system 17, which may include one or more hydrotreating and/or hydrocracking reactors to at least partially convert the 490°C + fraction and pyrolysis oil to produce a conditioned hydrocarbon stream 19. For example, a 490°C+ stream can be processed in a residue hydrocracking reactor system 17, which may include one or more reactors, for example, using a fluidized bed of catalyst extrudate or catalyst slurry, to convert hydrocarbons in them at 490 ° C - boiling compounds. Stream 19 may then be fed to a second separation system 21, such as a second VUR, which may separate lighter, conditioned hydrocarbons in stream 19 from heavier hydrocarbons, such as a vacuum residue fraction, which may not be suitable for steam cracking. installation. The vacuum residue fraction may be separated from separation system 21 via flow line 23 and may be upgraded in an inline hydrotreater 25, such as a fixed bed hydrodesulfurization unit, to form an ultra low sulfur heavy oil (ULSFO) stream 27. Separation system 21 may also produce a light cut 29, such as a hydrocarbon cut having a fraction end point in the range of about 160 to 490°C, where the heavy component stream 23 may have an appropriate initial boil, eg 490°C+ hydrocarbons.

[0063] The medium-boiling cut 9 and the light cut 29 can be fed to the second conditioning section 31 to produce a highly waxy stream 33 suitable for processing in the steam cracker section 7 to produce chemical product streams 13 such as ethylene, propylene and butenes, along with others, as well as fractions of higher boiling pyrolysis oil 15, as noted above. The first conditioning section 17 and the second conditioning section 31 may be the same or different and may include one or more hydrotreating and/or hydrocracking reactors.

[0064] In some embodiments, conditioning reactors 17, 31 may include hydrotreating catalysts (first conditioning stage) and/or hydrocracking catalysts (second conditioning stage). In addition, in some embodiments, the first conditioning stage may include a reactor zone containing a residue desulfurization catalyst. The hydrotreating and/or hydrocracking reactors may include catalysts for metal removal, nitrogen removal, and the hydrotreating in these reactors may generally add hydrogen to the conditioned hydrocarbon components, facilitating their processing downstream to produce chemicals. The conditioning zone fixed bed system, for example, may contain different beds of demetallization catalysts, hydrotreating catalysts, and mesoporous zeolite hydrocracking catalysts to optimize the conversion of heavy materials to a balance between a highly paraffinic stream, which is acceptable for olefin production, and an aromatics-rich stream, which suitable for the production of aromatic compounds.

[0065] In some embodiments, the 490°C+ cut 11 may be fed to the residue hydrocracker 17. Processing the 490°C+ hydrocarbons in the residue hydrocracker may increase the conversion of low value streams to high value products.

[0066] The additional 490° C. material in stream 29 may be processed in a fixed bed hydrotreating reactor, which may be the same reactor used to condition the middle draw 9, or in some embodiments, may be a separate hydrotreating reactor with a fixed bed, which may contain a catalyst specifically designed for the efficient conditioning of singly converted hydrocarbons obtained from the hydrocracking of residues. The reaction products 33 from the hydrotreated 160-490° C. stream 9 and the hydrotreated 490° C. effluent of the vacuum residue hydrocracker 29 can then be processed in a fixed bed hydrocracking reactor, yielding a feedstock 33 suitable for processing in the steam cracker section 7 for conversion to light olefins and other valuable chemicals.

[0067] 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 is separated to form a light cut 5, a medium cut 9, and a heavy cut 11. In this embodiment, the heavy cut 11 is fed to the first stage of the residue hydrocracking system 17A and the pyrolysis oil stream 15 is fed to the second stage of the residue hydrocracking system 17B for co-processing. with deasphalted oil recovered from the deasphalting system by solvent 37.

[0068] A heavy hydrocarbon feed with a wide boiling range, such a desalinated oil 1, may be fed into a separation system 3. The separation system 3 may be, for example, an inline separation device (ISD) as described above. In the separation system 3, the desalinated oil 1 can be separated into three fractions, including: (a) a light fraction, such as 160°C - fraction 5, which does not require any conditioning and can be used as feedstock for the steam cracking section - unit 7, (b) a medium range fraction such as 160-490°C fraction 9, and (c) a heavy fraction such as 490°C+ fraction 11. Other boiling point temperatures can also be used to direct desired fractions and are in them hydrocarbons to the desired units for conditioning and/or cracking. The steam cracker section 7 can be used to thermally crack the 160°C fraction, along with other feeds discussed below, to form chemical products 13 such as ethylene, propylene and butenes, which can be recovered together or as separate streams. , as well as fractions of higher-boiling pyrolysis oil 15.

[0069] The 490°C+ fraction (fraction 11) may be fed to the first conditioning system 17A, which may include one or more hydrotreating and/or hydrocracking reactors, to at least partially convert the 490°C+ fraction to produce conditioned hydrocarbon stream 19A. For example, a 490°C+ stream may be processed in a Residue Hydrocracking Reactor System 17A, which may include one or more reactors, for example using a fluidized bed of catalyst extrudate or catalyst slurry, to convert their hydrocarbons to 490°C-boiling compounds.

[0070] The pyrolysis oil cut 15 may be fed to a second conditioning system 17B, which may include one or more hydrotreating and/or hydrocracking reactors, to at least partially convert the pyrolysis oil cut to produce conditioned hydrocarbon stream 19B. For example, the pyrolysis oil stream may be processed in a Residue Hydrocracking Reactor System 17B, which may include one or more reactors, for example using a fluidized bed of catalyst extrudate or catalyst slurry, to convert their hydrocarbons to 490° C.-boiling compounds.

[0071] Streams 19A and 19B may then be fed to a second separation system 21, such as a second VUR, which may separate lighter, conditioned hydrocarbons in streams 19A and 19B from heavier hydrocarbons, such as a vacuum residue fraction, which may be unusable. for processing in a steam cracker. The vacuum residue fraction may be recovered from the separation system 21 via flow line 23 and may be fed to the solvent deasphalting unit 37. In the deasphalting unit 37, the vacuum residue fraction 23 may be processed to recover the deasphalted oil 39 and the pitch fraction 41. In some embodiments, the fraction pitch 41 may be fed to an inline hydrotreater (not shown), such as a fixed bed hydrodesulfurization unit, to produce an ultra low sulfur heavy oil (ULSFO) stream. The deasphalted oil fraction 39 may be fed to the second stage of the vacuum bottoms hydrocracking reactor system 17B for conversion along with the pyrolysis oil to produce additional upgradable hydrocarbons.

[0072] Separation system 21 may also produce a light cut 29, such as a hydrocarbon cut, having a fraction end point boiling point in the range of about 160 to 490° C., where the heavy component stream 23 may have a corresponding initial boiling point, for example, 490° C. + hydrocarbons. The medium-boiling cut 9 and the light cut 29 can be fed to the second conditioning section 31 to produce a highly paraffinic stream 33 suitable for processing in the steam cracker section 7 to produce chemical product streams 23 such as ethylene, propylene and butenes, among others. , as well as fractions of higher-boiling pyrolysis oil 15, as noted above. The first conditioning section 17 and the second conditioning section 31 may be the same or different and may include one or more hydrotreating and/or hydrocracking reactors.

[0073] In some embodiments, conditioning reactors 17A, 17B, 31 may include hydrotreating catalysts (first conditioning stage) and/or hydrocracking catalysts (second conditioning stage). In addition, in some embodiments, the first conditioning stage may include a reactor zone containing a residue desulfurization catalyst. Hydrotreating and/or hydrocracking reactors may include catalysts for metal removal, nitrogen removal, and hydrotreating in these reactors may generally add hydrogen to the conditioned hydrocarbon components, facilitating their processing downstream to produce chemicals. A fixed bed catalyst system, for example, may contain different beds of demetalation catalysts, hydrotreating 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 an aromatics-rich stream that is acceptable for production. aromatic compounds.

[0074] In some embodiments, the 490° C.+ cut 11 may be fed to the residue hydrocracker 17. Processing the 490° C.+ hydrocarbons in the residue hydrocracker may increase the conversion of low value streams to high value products. Vacuum residue hydrocracking can be carried out in a fixed bed residue hydrocracking unit, in a fluidized bed reactor such as the LC-FINING or LC-MAX reactor system available from Lummus Technology, and LC-SLURRY reactors available from Chevron Lummus Global .

[0075] The additional 490° C. material in stream 29 may be processed in a fixed bed hydrotreating reactor, which may be the same reactor used to condition the middle draw 9, or in some embodiments, may be a separate hydrotreating reactor with a fixed bed, which may contain a catalyst specially adapted for efficient conditioning of the singly converted hydrocarbons obtained from the hydrocracking of residues. The reaction products 33 from the hydrotreated 160-490° C. stream 9 and the hydrotreated 490° C. effluent from the vacuum residue hydrocracker 29 can then be processed in a fixed bed hydrocracking reactor, yielding a feedstock 33 suitable for processing in the steam cracker section 7 for conversion to light olefins and other valuable chemicals.

[0076] FIG. 3 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. Heavy hydrocarbon feed with a wide boiling range, such as desalted oil 1, can be fed into the separation system 3. Similar to processing in the embodiments of FIG. 1 and 2, the separation system 3 may be an inline separation device (ISU) as described above, in which the desalinated oil 1 may be separated into three fractions, including: does not require any conditioning and can be used as feedstock for steam cracker section 7; and (b) a middle fraction such as 160-490° C. fraction 9; and (c) a heavy cut, such as the 490°C+ cut 11. Other boiling point temperatures may also be used to direct the desired cuts and their hydrocarbons to the desired conditioning and/or cracking sites. The steam cracker section 7 can be used to thermally crack the 160°C fraction, along with other feeds discussed below, to form chemical products 13 such as ethylene, propylene and butenes, which can be recovered together or as separate streams. , as well as fractions of higher-boiling pyrolysis oil 15.

[0077] The 490°C+ cut (fraction 11) and the pyrolysis oil cut 15 may be fed to the first conditioning system 17, which may include one or more hydrotreating and/or hydrocracking reactors to at least partially convert the 490°C + fraction and pyrolysis oil to produce a conditioned hydrocarbon stream 19. For example, a 490°C+ stream can be processed in a residue hydrocracking reactor system 17, which may include one or more reactors, for example, using a fluidized bed of catalyst extrudate or catalyst slurry, to convert hydrocarbons in them at 490 ° C - boiling compounds. Stream 19 may then be fed to a second separation system 21, such as a second VUR, which may separate lighter, conditioned hydrocarbons in stream 19 from heavier hydrocarbons, such as a vacuum residue fraction, which may not be suitable for steam cracking. installation. The vacuum residue fraction can be removed from separation system 21 via flow line 23, and can be upgraded in an inline hydrotreater 25, such as a fixed bed hydrodesulfurization unit, to produce an ultra low sulfur heavy oil (ULSFO) stream 27. Separation system 21 may also produce a light cut 29, such as a hydrocarbon cut, having a fraction end point in the range of about 160 to 490° C., where the heavy component stream 23 may have an appropriate initial boiling point, e.g., 490° C.+ hydrocarbons.

[0078] The medium boiling fraction 9 can be fed to the fixed bed conditioning system 45 to produce a highly paraffinic stream 47 containing hydrocarbons suitable for processing in the steam cracker section 7 to produce additional chemicals 13. After conversion, the effluent from the reaction zone 45 may pass through one or more intermediate separation stages 49 which may be used to separate ammonia and/or hydrogen sulfide 51 from the effluent. The hydrocarbons in the effluent may then be directed through flow line 53 to inline separator 55.

[0079] The separation system 55 can be used to separate upgraded mid-range hydrocarbons into three fractions, including: (a) a light cut, such as the 160°C cut 57, which does not require any conditioning and can be used as a feedstock for steam cracker section 7; (b) a middle fraction such as 160-360° C. fraction 59; and (c) a heavy cut, such as the 360°C+ cut 61, which may include unconverted hydrocarbons from the mid range cut 9. Other boiling point temperatures may also be used to direct the desired cuts and the hydrocarbons therein to the desired conditioning units and/ or cracking.

[0080] The light cut 29 and the unconverted residue cut 61 may be fed to the second conditioning section 63 to produce a highly waxy hydrocarbon stream 65 comprising hydrocarbons suitable for processing in the steam cracker section 7 to produce additional chemicals recovered through streams 13 , such as ethylene, propylene and butenes, among others, as well as fractions of higher boiling pyrolysis oil 15, as noted above.

[0081] After conditioning in the second conditioning section 63, the effluent 65 may be fed to another separation system 67, such as a VUR, to separate the upgraded hydrocarbons into at least two fractions, including: (a) a light fraction, such as 160 °C - fraction 69, which does not require any conditioning and can be used as a raw material for the steam cracker section 7; and (b) a heavy cut, such as the 160° C.+ cut 71, which may include the unconverted hydrocarbons from cuts 29, 61. Other cuts boiling point temperatures may also be used to direct the desired cuts and their hydrocarbons to the desired conditioning units, and /or cracking.

[0082] In some embodiments, conditioning reactors 17, 45, 63 may include hydrotreating catalysts (first conditioning stage) and/or hydrocracking catalysts (second conditioning stage). In addition, in some embodiments, the first conditioning stage may include a reactor zone containing a residue desulfurization catalyst. Hydrotreating and/or hydrocracking reactors may include catalysts for metal removal, nitrogen removal, and the hydrotreating in these reactors may generally add hydrogen to the conditioned hydrocarbon components, facilitating their processing downstream to produce chemicals. A fixed bed catalyst system, for example, may contain different beds of demetalation catalysts, hydrotreating 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 an aromatics-rich stream that is acceptable for production. aromatic compounds.

[0083] In some embodiments, the 490° C.+ fraction 11 may be fed to the residue hydrocracker 17. Processing the 490° C.+ hydrocarbons in the residue hydrocracker may increase the conversion of low value streams to high value products. Hydrocracking of vacuum residues can be carried out in a fixed bed hydrocracking unit, in a fluidized bed reactor such as the LC-FINING or LC-MAX reactor system available from Lummus Technology, as well as LC-SLURRY reactors available from Chevron Lummus Global. .

[0084] As described above for FIG. 1, fixed bed conditioning systems can be used to condition the 490° C.+ fraction 11 separately from the 160-490° C. middle draw stream 9, wherein a second fixed bed conditioning system 32 can be used to condition the combined 160-490° C. middle drawdown. and partially conditioned and separated 490°C+ fraction 29, which may have a similar boiling range, 160-490°C. In some embodiments, streams 9, 29 may be processed in the same or similar hydrotreating and/or hydrocracking reactors in conditioning systems 31. However, it has been found that due to the nature of the feed compounds for different types of crude oil, processing in a single reaction line may 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 in the 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 the partially conditioned cut 29 is co-processed with the straight run 160-490°C cut 9 in the first conditioning system 31, the cycle time for the single hydrotreating line may be undesirably reduced and/or a spare hydrotreating line will be required to ensure a steady stream of feed to the steam cracker. while the hydrotreating catalyst system is being regenerated and/or replaced. 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.

[0085] To alleviate problems associated with catalyst life/cycle time, the fixed bed hydrotreating stage can be separated. For example, a first conditioning system 31 may be provided to process the straight-run 160-490° C. fraction 9, and a second conditioning system 31 may be provided to process the partially conditioned fraction 29. Typically, the reactors in the first conditioning system may have less frequently recurring cycle times, than the cycle time of the reactors in the second conditioning system, which may have more frequent repair periods for catalyst replacement, but the straight-run 160-490°C fraction and the partially conditioned fraction can be combined with the first conditioning system, for example, so that for continuous operation no spare reactor line was required. Due to the temporary diversion of feedstock, the impact on any reactor line will be minimal, and therefore conditioning systems can be designed to hydrotreat and/or hydrocrack both the 160-490°C straight-run fraction and the partially conditioned fraction such that process downtime during the repair period or in the first or second air conditioning systems can be reduced. In addition, the cycle time for the first conditioning system can be adjusted to be synchronized with the cycle time of the furnaces of the steam cracker.

[0086] 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 processing in a solvent deasphalting system, where higher boiling hydrocarbons can be recovered with the deasphalted oil and fed to a hydrotreating reactor to be converted into a feed suitable for steam cracking. However, regarding the processing of a high boiling fraction (e.g., 490°C+ or 545°C+ fraction) in a solvent deasphalting system, it has been found that a lower boiling point fraction may be more optimal, as too high boiling limits may require the use of a distillate oil to produce ULSFO category fuel.

[0087] 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 can be processed with a 160-490°C cut; (ii) a heavy catalytic cracking residue, such as a heavy catalytic cracking residue obtained from an FCC unit, which can be processed with 490°C+ hydrocarbons; (iii) pitch, such as pitch obtained from the solvent deasphalting unit, which can be processed in the first conditioning system with 490°C+ hydrocarbons; 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 25 from a steam cracker 7, and this stream can be processed with 490°C+ hydrocarbons . Other various hydrocarbon streams with similar boiling ranges may also be co-processed to produce petrochemicals in the systems described herein, where such streams may include light naphtha, heavy naphtha, crude oil, atmospheric residues, vacuum residues, synthetic crude oil, and other hydrocarbon streams. streams containing heavy hydrocarbons. The boiling ranges of the fractions can also be changed in any of the WURs to account for the changing quality of the feedstock (ie metals, asphaltenes and CCRs). In embodiments where the desalinated oil has few contaminants, the initial boiling ranges of the fractions may be higher (ie, greater than 160° C.), resulting in reduced operating load on the catalyst in one or more conditioning systems. On the other hand, in embodiments where the desalinated oil has a high contaminant content, the initial boiling ranges of the fractions can be lowered (i.e., below 160°C), resulting in more hydrocarbons being fed through a plurality of conditioning systems and a second HPS for hydrotreating and/ or removing unwanted heavy components and increasing the amount of naphtha range hydrocarbons fed to the steam cracker.

[0088] As briefly described above, embodiments of the invention may allow direct cracking of crude oil to chemical products to form light hydrocarbons such as ethylene, propylene, and light aromatics in a cost-effective manner without the need to go through conventional refining steps. In addition, direct conversion of crude oil to chemical compounds 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.

[0089] Integrating process nodes in accordance with embodiments of the invention may provide a unique opportunity to upgrade all crude oils such as Arab Light and Arab Extra Light oils, along with low value refinery streams such as pyrolysis oil (PyOil), heavy catalytic cracking residue and light cycle oil (LCO) to higher value chemicals. Although feed conditioning according to embodiments of the invention adds hydrogen to the feedstock components, and hydrogen consumption is an additional cost to the plant, the overall benefits in producing chemicals 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.

[0090] In other embodiments, an optional aromatic processing complex may be included. For example, an aromatics processing complex can be used to convert the 160-490° C. cut or part of it into aromatics. For example, a medium cut, such as a 160 to 240°C cut, may be processed to convert some of the hydrocarbons therein to aromatics, while the heavy components may be sent to a steam cracker for conversion to chemicals. An aromatics complex feed obtained through initial processing and conditioning in accordance with embodiments of the invention may allow various refiners to stop importing crude naphtha (FRN).

[0091] 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.

[0092] As described with respect to FIG. 1-3, separation system 3 may be the separation system shown in FIG. 4 including separation and thermal integration. After desalting, oil 1 may be further heated in the convection section of heater 500 to produce heated oil 502. Heated oil 502 may be sent to separator 504, which may assist in separating the 160°C fraction 5.

[0093] 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. VUR heat exchanger 512 may preheat 160°C+ oil fraction 510 relative to bottom residues 520 of the 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 the 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 11.

[0094] 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. 1-3. The recovered hydrogen can 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. 1-3) as well as hot hydrogen feed 522.

[0095] The bottom product 520 of a hydrogen hot stripper (such as a 490° C.+ cut) contains the most problematic compounds in processed 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 circulating liquid bed fluidized bed hydrocracking unit as described in FIG. 1-3, along with any additional low value refinery streams such as a pyrolysis oil stream and/or a heavy catalytic cracking residue stream.

[0096] 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 the middle stream 9 may contain little to no harmful compounds that would rapidly foul the fixed bed conditioning reactors. Thus separation system 3 (with hydrogen hot stripper 518) can concentrate the most problematic hydrocarbons in the heavy end product 11, which can be sent to fluidized bed reactors that can operate under the most severe conditions, thereby keeping the catalysts in the steam cracker. plant and in fixed bed conditioning reactors.

[0097] 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 chemicals. The crude oil conditioning section uses a combination of fixed bed hydrotreating and circulating fluid to condition the crude oil into a suitable steam cracker feed and upgrade low value refinery streams. Embodiments of the invention may provide, for example, a yield of chemicals in the range of 60 to 90% based on the entire original crude oil.

[0098] After desalting, the crude oil can be separated into three cuts, including: 160° C. flow, 160-490° C. flow, and 490° C.+ flow. The 160°C flow does not require upgrading and can therefore be sent directly to the steam cracker. The 160-490° C. stream is easily processed in a fixed bed hydrotreating reaction system in which the feedstock is hydrotreated and converted to naphtha, creating an ideal steam cracker feedstock.

[0099] Embodiments of the invention can use one or more hydrotreating and/or hydrocracking reactions and an inline separation device to remove pitch (asphaltenes) and metals, thereby increasing the run time of the conversion process without fouling the reactors. In some embodiments, pitch, asphaltenes, and metals may be fed into a delayed coking unit to recover the carbon that is in these streams.

[00100] Embodiments described herein may provide for upstream processing to process all of the crude oil and other wide-boiling hydrocarbons in a steam cracker, where embodiments of common integrated processes may be configured to have a common work period. This can be accomplished by having a switchover, or shutdown, from one A/C system to another to minimize overall system downtime during catalyst regeneration, maintenance or cleaning. In addition, such embodiments can eliminate the need for parallel reaction lines or redundant process units during catalyst regeneration in both mid-range hydrocarbon processing and high-boiling bottoms processing.

[00101] In addition, the hydrotreating and hydrocracking reactors in each of the first and second conditioning systems can be sized to have the same operating times as the steam cracking unit. Such configurations can further reduce downtime since cleaning, maintenance, and catalyst regeneration can all be performed simultaneously in multiple reaction systems. Without such design considerations, these operations can result in increased downtime when the reactors in the A/C system, for example, are turned off to regenerate the catalyst, while the catalysts in the second A/C system still retain >50% life.

[00102] In addition, the prevention of carryover of heavy materials at the forefront of separation processes can reduce costs and can lead to less complex flowsheets, as shown and described in the invention. In addition, carry-over prevention can ensure operability and processability in crude oil conditioning systems and steam crackers, which can reduce overall capital costs while achieving high chemical yields. 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 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.

[00103] 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.

[00104] The initial separation of the crude oil can be carried out and adjusted so that the light, medium and heavy cuts have certain 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. .

[00105] Mining Bureau Correlation Index (BMCI)

[00106] 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.

[00107] 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 still other embodiments, for example, when 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, can target an ICGB of less than 10, and in the case of Arab extra light oils can target, for example, an ICGB of less than 6 or less than 5.5.

[00108] 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.

[00109] 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 into 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.

[00110] API Gravity

[00111] 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°.

[00112] Accordingly, in some embodiments, a light cut comprising 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 the 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°.

[00113] 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 to 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°.

[00114] 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°.

[00115] Hydrogen content

[00116] 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.

[00117] 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 be oriented, for example, to 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.

[00118] 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.

[00119] In various embodiments, the implementation of a heavy shoulder strap, including hydrocarbons having a boiling point greater than about 300°C, may have a hydrogen content of less than about 13% of the mass. 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.

[00120] Nitrogen content

[00121] 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.

[00122] 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 .

[00123] 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.

[00124] 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.

[00125] Sulfur content

[00126] 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.

[00127] Accordingly, in some embodiments, the implementation of a light shoulder strap, including hydrocarbons having a boiling point up to about 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 .

[00128] 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 be oriented, for example, to a sulfur content in the range from about 6000 to 12000 ppm and in the case of Arab extra light oils, can be oriented, for example, to a sulfur content in the range approximately 5000 to 10000 ppm.

[00129] 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 product 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.

[00130] Viscosity

[00131] In some embodiments, the light shoulder strap may have a viscosity, measured at 40° C. in accordance with ASTM D445, of 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.

[00132] 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 .

[00133] 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.

[00134] Microcarbon Residue (MCRT)

[00135] In some embodiments, the light cut may have only trace amounts, or undetectable amounts, of micro carbon 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.

[00136] 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.

[00137] 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.

[00138] Metal content

[00139] 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.

[00140] 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.

[00141] 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.

[00142] By way of example, an Arab 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 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 may be a 490° C.+ cut with 5% of the fraction having a boiling point below 490° C. and 95% of the fraction having a boiling point below 735° C. (only 5% of the fraction 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.

[00143] As another example, an Arab Extra 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 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.

[00144] 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.

[00145] 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 oil 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.

[00146] 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.

[00147] In each of the embodiments described above, as an exemplary feedstock, Arab Light oil can be processed to produce sufficient light naphtha and other feedstock to produce additional ethylene in a mixed feed cracker (MFC). The desalination may include pumping Arab Light (AL) crude oil through one or more preheater heat exchangers, raising the temperature of the crude oil to, for example, 140° C. to maximize the efficiency of the desalination unit. The desalination plant may be, for example, a two-stage electrostatic desalination system that rids the crude oil of salts, solids, and water that would otherwise cause corrosion and fouling problems in downstream equipment. Water and demulsifying chemicals can be mixed with the crude oil to dissolve the salts in a concentrated brine, which is then electrostatically coagulated and separated from the oil. The first stage can remove almost all of the salt from the oil, and the second stage can remove the remainder of the salt and dehydrate the oil.

[00148] Part of the water supply for the desalination plant (not shown), which may be approximately 2% vol. to the crude oil feed, for example, may be injected into the cold crude crude oil feed to protect the crude crude oil preheat heat exchangers from scale deposits. Demulsifier injection points at the suction and discharge of each crude oil pump prevent emulsion formation while the oil passes through the preheating system.

[00149] The water used for desalination (desalination plant feed water, DFW)) may be stripped sour water (not shown). For desalting, between 6 and 10% by volume, eg 8% by volume, of the RTO may be needed to feed the crude crude oil. A make-up water line (not shown) with a sequencing valve may be provided to maintain the proper amount of RTO in the event that the amount of sour water stripped becomes insufficient. The WWTP can be collected in a storage tank, pumped and separated. Some of this separation, for example 2% by volume, can be used for injection into cold oil, and the rest can be used for injection into the desalination unit. This last amount may be heated to within about 10° C. of the operating temperature of the desalination unit before injection. The mixing valve can help to thoroughly mix the HSR with the first stage effluent. The effluent from the second stage can be pumped and cascaded back to the first stage where another mixing valve thoroughly mixes it with the heated crude oil and demulsifying agent. The enriched outgoing water from the first stage can be cooled relative to the incoming RTO, and before that it is cooled relative to air and cooling water.

[00150] Each desalination stage can be equipped with a dirt flushing system to remove any solids that may settle and accumulate in the desalination vessel. The mud flush system can operate by taking water from the same vessel and injecting it back at a higher pressure to fluidize the solids and suspend them in the aqueous phase for further removal by the water flow.

[00151] The remaining 160° C.+ crude oil fraction is collected in an RTS settler where it is pumped by RTS liquid pumps through a heat exchanger and stripper feed/bottoms heater to a hydrogen hot stripper. In a 160°C+ hydrogen hot stripper, the crude oil fraction is further separated into a l60-490°C fraction and a heavier 490°C+ fraction using hot hydrogen as the stripping medium.

[00152] The 160-490°C fractions obtained from the process flowsheets can be directed to common or separate fixed bed conditioning sections. Each fixed bed crude oil conditioning section can contain up to four reaction stages, including fluidized bed reactors (such as LC-FINING reactors), second stage hydrocracking reactors, and a heavy residue hydrotreating 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.

[00153] In some embodiments, the 490°C+ fraction can be processed in a slurry or fluidized bed reactor. The 490°C+ stream contains the most problematic compounds in the 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 residue conversions. For example, a 490°C+ stream can be processed in a fluidized bed reactor with liquid circulation, for example, by LC-FINING technology available from Lummus Technology LLC. Slurry reactor technology can also be used to process even heavier refinery streams such as pitch from a solvent deasphalting unit.

[00154] In other embodiments, the heavy 490° C.+ fraction can be recovered from the first stage fluidized or slurry bed reactor effluent and processed in a solvent deasphalting unit (SDA). The resulting deasphalted oil (DM (DAO)) from the DR unit can be processed in conditioning reactors, including, for example, a second reaction stage with a slurry or fluidized bed. The pitch fraction, if desired, can be upgraded to IMO 2020 compliant low sulfur heavy fuel oil, further adding value to the products.

[00155] 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.

[00156] 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).

[00157] 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 pyrolysis heater. In the heating coil, the hydrocarbon feed may be heated and/or vaporized by convective heat exchange with the exhaust gases.

[00158] 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. Water vapor 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 pyrolysis heater.

[00159] The heated hydrocarbon mixture(s) may/may be fed(s) to a heating coil, which may be located at the lower elevation of the pyrolysis heater and therefore at a higher temperature than the convection zone heating coil noted above. The resulting superheated mixture can then be fed to one or more coils located in the radiant zone of a pyrolysis heater operating at a partial conversion temperature by thermally cracking the hydrocarbon mixture. The cracked hydrocarbon product can then be recovered.

[00160] 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 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 the desired reaction results, such as the desired product profile, while limiting coking to 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 increased to weeks instead of hours with higher olefin production.

[00161] 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.

[00162] Instead of indirect cooling, direct quenching can also be used. In such cases, oil may be introduced 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.

[00163] As described above, embodiments of the invention can be used to convert heavy oil fractions into high value chemicals 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.

[00164] As described above, the embodiments contemplated by the invention may refer to one or more of the following embodiments.

[00165] Embodiment 1: A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the hydrocarbon feedstock in the first in-line separating device 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 pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent;

separating the hydrocracked effluent in a second in-line separating device to obtain a heavy fuel oil fraction and a partially conditioned fraction;

destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream;

feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[00166] 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.

[00167] 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.

[00168] Embodiment 4: The method of any one of Embodiments 1-3, wherein the high-boiling residue 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.

[00169] 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.

[00170] 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.

[00171] Embodiment 7: The method of any one of Embodiments 1-6, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise the destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in a common destructive hydrogenation unit.

[00172] Embodiment 8: The method of any one of Embodiments 1-7, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise:

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

destructive hydrogenation of the partially conditioned fraction in the second destructive hydrogenation unit; And

combining the outgoing streams of the first and second nodes of destructive hydrogenation.

[00173] Embodiment 9: The method of Embodiment 8 also comprising destructive hydrogenation of the partially conditioned fraction in the first destructive hydrogenation unit for a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

[00174] Embodiment 10: The method of any one of Embodiments 1-9, further comprising hydrodesulfurizing the heavy fuel oil fraction to produce an ultra low sulfur heavy fuel oil.

[00175] Embodiment 11: The process of Embodiment 1 wherein the total production of chemical products from raw materials is approximately 60 to 85 wt%. based on the total amount of produced olefins in comparison with the total feedstock volume.

[00176] Embodiment 12: The process of Embodiment 1 wherein the residue hydrocracking reactor comprises a slurry bed reactor or a fluidized bed reactor.

[00177] Embodiment 13: The method of Embodiment 1 wherein separating all of the crude oil comprises:

supplying all of the crude oil to a heater to produce a heated hydrocarbon feedstock;

separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction;

feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction;

feeding a stream of hydrogen to a hydrogen hot stripper;

separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper; And

cooling the bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to the intermediate fraction to obtain a high-boiling residue fraction.

[00178] Embodiment 14: A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the hydrocarbon feedstock in the first in-line separating device into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction;

hydrocracking the high-boiling residue fraction in a first vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent;

solvent deasphalting of the hydrocracked effluent with separation of pitch and deasphalted oil fraction;

hydrocracking the deasphalted oil fraction and the pyrolysis oil in a second vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a second hydrocracked effluent;

separating the hydrocracked effluent and the second hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction;

destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream;

feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[00179] Embodiment 15: The method of Embodiment 14 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.

[00180] Embodiment 16: The method of Embodiment 14 or Embodiment 15 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.

[00181] Embodiment 17: The method of any one of Embodiments 14-16, wherein the high-boiling residue 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.

[00182] Embodiment 18: The method of any one of Embodiments 14-17, wherein:

the second hydrocracked effluent has a 95% initial boiling point in the range of approximately 400 to 560°C.

[00183] Embodiment 19: The method of any one of Embodiments 14-18, wherein the high boiling residue fraction has a 5% initial boiling point greater than about 545°C.

[00184] Embodiment 20: The method of any one of embodiments 14-19, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise the destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in a common destructive hydrogenation unit.

[00185] Embodiment 21: The method of any one of Embodiments 14-20, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise:

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

destructive hydrogenation of the partially conditioned fraction in the second destructive hydrogenation unit; And

combining the outgoing streams of the first and second nodes of destructive hydrogenation.

[00186] Embodiment 22: The method of Embodiment 21 also comprising destructive hydrogenation of the partially conditioned fraction in the first destructive hydrogenation unit for a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

[00187] Embodiment 23: The method of Embodiment 14 wherein the total production of chemical products from raw materials is approximately 60 to 85% by weight. based on the total amount of produced olefins in comparison with the total feedstock volume.

[00188] Embodiment 24: The process of Embodiment 14 wherein the residue hydrocracking reactor comprises a slurry bed reactor or a fluidized bed reactor.

[00189] Embodiment 25: The method of Embodiment 14 wherein separating all of the crude oil comprises:

supplying all of the crude oil to a heater to produce a heated hydrocarbon feedstock;

separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction;

feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction;

feeding a stream of hydrogen to a hydrogen hot stripper;

separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper; And

cooling the bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to the intermediate fraction to obtain a high-boiling residue fraction.

[00190] Embodiment 26: A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

separating the hydrocarbon feedstock in the first in-line separating device 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 pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent;

separating the hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction;

hydrodesulfurizing the vacuum residue fraction to produce an ultra-low sulfur diesel fuel fraction;

destructive hydrogenation of the medium-boiling fraction in a third conditioning unit to produce an effluent of a third conditioning unit;

separating the outlet stream of the third air conditioning unit in the third built-in separating device into a light boiling conditioned fraction, a medium boiling conditioned fraction and a high boiling fraction;

destructively hydrogenating the partially conditioned fraction, the medium-boiling conditioned fraction, and the diesel fuel fraction in the fourth conditioning unit to obtain an effluent of the fourth conditioning unit;

separating the effluent of the fourth conditioning unit in the fourth built-in separating device into a light conditioned fraction and a diesel fuel fraction;

feeding the high-boiling fraction, the light conditioned fraction, the light-boiling fraction and the light-boiling conditioned fraction to a steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[00191] Embodiment 27: The method of Embodiment 26 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.

[00192] Embodiment 28: The method of Embodiment 26 or Embodiment 27 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.

[00193] Embodiment 29: The method of any one of Embodiments 26-28, wherein the high boiling residue 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.

[00194] Embodiment 30: The method of Embodiment 26 wherein separating all of the crude oil comprises:

supplying all of the crude oil to a heater to produce a heated hydrocarbon feedstock;

separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction;

feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction;

feeding a stream of hydrogen to a hydrogen hot stripper;

separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper; And

cooling the bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to the intermediate fraction to obtain a high-boiling residue fraction.

[00195] Embodiment 31: A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

feeding the hydrocarbon feedstock to the heater to form a heated hydrocarbon feedstock;

separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction;

feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction;

feeding a stream of hydrogen to a hydrogen hot stripper;

separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper;

cooling a bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to an intermediate fraction to obtain a high-boiling residue fraction;

hydrocracking the high-boiling residue fraction and the pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent;

separating the hydrocracked effluent in a second in-line separating device to obtain a heavy fuel oil fraction and a partially conditioned fraction;

destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream;

feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[00196] Embodiment 32: The method of Embodiment 31 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.

[00197] Embodiment 33: The method of Embodiment 31 or Embodiment 32, 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.

[00198] Embodiment 34: The method of any one of Embodiments 31-33, wherein the high-boiling residue 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.

[00199] Embodiment 35: The method of any one of Embodiments 31-34, wherein:

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

[00200] Embodiment 36: The method of any one of Embodiments 31-35, wherein the high boiling residue fraction has a 5% initial boiling point greater than about 545°C.

[00201] Embodiment 37: The method of any one of embodiments 31-36, wherein the destructive hydrogenation of the medium boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprises destructive hydrogenation of the medium boiling fraction and the partially conditioned fraction in a common destructive hydrogenation unit.

[00202] Embodiment 38: The method of any one of Embodiments 31-37, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise:

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

destructive hydrogenation of the partially conditioned fraction in the second destructive hydrogenation unit; And

combining the outgoing streams of the first and second nodes of destructive hydrogenation.

[00203] Embodiment 39: The method of Embodiment 38 also comprising destructive hydrogenation of the partially conditioned fraction in the first destructive hydrogenation unit for a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

[00204] Embodiment 40: The method of any one of Embodiments 31-39, further comprising hydrodesulfurizing the heavy fuel oil fraction to produce an ultra low sulfur heavy fuel oil.

[00205] Embodiment 41: The method of Embodiment 31, in which the total production of chemical products from raw materials is approximately 60 to 85% of the mass. based on the total amount of produced olefins in comparison with the total feedstock volume.

[00206] Embodiment 42: The process of Embodiment 31 wherein the residue hydrocracking reactor comprises a slurry bed reactor or a fluidized bed reactor.

[00207] Embodiment 43: A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

feeding the hydrocarbon feedstock to the heater to form a heated hydrocarbon feedstock;

separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction;

feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction;

feeding a stream of hydrogen to a hydrogen hot stripper;

separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper;

cooling a bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to an intermediate fraction to obtain a high-boiling residue fraction;

hydrocracking the high-boiling residue fraction in a first vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent;

solvent deasphalting of the hydrocracked effluent to recover pitch and deasphalted oil fraction;

hydrocracking the deasphalted oil fraction and the pyrolysis oil in a second vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a second hydrocracked effluent;

separating the hydrocracked effluent and the second hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction;

destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream;

feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[00208] Embodiment 44: The method of Embodiment 43 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.

[00209] Embodiment 45: The method of Embodiment 43 or Embodiment 44 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.

[00210] Embodiment 46: The method of any one of Embodiments 43-45, wherein the high-boiling residue 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.

[00211] Embodiment 47: The method of any one of Embodiments 43-46, wherein:

the second hydrocracked effluent has a 95% initial boiling point in the range of approximately 400 to 560°C.

[00212] Embodiment 48: The method of any of embodiments 43-47 wherein the high boiling residue fraction has a 5% initial boiling point greater than about 545°C.

[00213] Embodiment 49: The method of any one of embodiments 43-48, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise the destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in a common destructive hydrogenation unit.

[00214] Embodiment 50: The method of any one of Embodiments 43-49, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise:

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

destructive hydrogenation of the partially conditioned fraction in the second destructive hydrogenation unit; And

combining the outgoing streams of the first and second nodes of destructive hydrogenation.

[00215] Embodiment 51: The method of Embodiment 50 also comprising destructive hydrogenation of the partially conditioned fraction in the first destructive hydrogenation unit for a period of time when the catalyst in the second destructive hydrogenation unit is replaced.

[00216] Embodiment 52: The method of Embodiment 43, in which the total production of chemical products from raw materials is approximately 60 to 85% of the mass. based on the total amount of produced olefins in comparison with the total feedstock volume.

[00217] Embodiment 53: The process of Embodiment 43 wherein the residue hydrocracking reactor comprises a slurry bed reactor or a fluidized bed reactor.

[00218] Embodiment 54: A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes:

feeding the hydrocarbon feedstock to the heater to form a heated hydrocarbon feedstock;

separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction;

feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction;

feeding a stream of hydrogen to a hydrogen hot stripper;

separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper;

cooling a bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to an intermediate fraction to obtain a high-boiling residue fraction;

hydrocracking the high-boiling residue fraction and the pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent;

separating the hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction;

hydrodesulfurizing the vacuum residue fraction to produce an ultra-low sulfur diesel fuel fraction;

destructive hydrogenation of the medium-boiling fraction in a third conditioning unit to produce an effluent of a third conditioning unit;

separating the outlet stream of the third air conditioning unit in the third built-in separating device into a light boiling conditioned fraction, a medium boiling conditioned fraction and a high boiling fraction;

destructively hydrogenating the partially conditioned fraction, the medium-boiling conditioned fraction, and the diesel fuel fraction in the fourth conditioning unit to obtain an effluent of the fourth conditioning unit;

separating the effluent of the fourth conditioning unit in the fourth built-in separating device into a light conditioned fraction and a diesel fuel fraction;

feeding the high-boiling fraction, the light conditioned fraction, the light-boiling fraction and the light-boiling conditioned fraction to a steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil.

[00219] Embodiment 55: The method of Embodiment 54 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.

[00220] Embodiment 56: The method of Embodiment 54 or Embodiment 55 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.

[00221] Embodiment 57: The method of any one of Embodiments 54-56, wherein the high-boiling residue 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.

[00222] In addition, as described above, embodiments of the invention may relate to a system for carrying out the methods in accordance with one or more of Embodiments 1-57.

[00223] 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 (161)

1. A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes: separating the hydrocarbon feedstock in the first in-line separating device 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 pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent; separating the hydrocracked effluent in a second in-line separating device to obtain a heavy fuel oil fraction and a partially conditioned fraction; destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream; feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil. 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; ICGB (Mining Bureau Correlation Index) 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 (micro carbon residue); 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; BCI (Bureau of Mines Correlation Index) ranging from about 5 to less than 50; density in degrees API in the range from about 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 (micro carbon residue); And less than 50 ppm all metals. 4. Process according to claim 1 or 2, wherein the high-boiling residue 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 (micro carbon residue); And more than 50 ppm all metals. 5. The method according to claim 1 or 2, in which: the hydrocracked vacuum residue fraction has a 95% initial boiling point in the range of approximately 400 to 560°C. 6. The process of claim 1 or 2, wherein the high boiling residue fraction has a 5% initial boiling point greater than about 545°C. 7. The process according to claim 1 or 2, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprises destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in a common destructive hydrogenation unit. 8. The process according to claim 1 or 2, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprises: destructive hydrogenation of the medium-boiling fraction in the first node of destructive hydrogenation; destructive hydrogenation of the partially conditioned fraction in the second destructive hydrogenation unit; And combining the outgoing streams of the first and second nodes of destructive hydrogenation. 9. The process of claim 8, further comprising destructive hydrogenation of the partially conditioned fraction in the first destructive hydrogenation unit for a period of time when the catalyst in the second destructive hydrogenation unit is replaced. 10. The process of claim 1 or 2, further comprising hydrodesulfurizing the heavy fuel oil fraction to produce ultra low sulfur heavy fuel oil. 11. The method according to p. 1, in which the total production of chemical products from raw materials is in the range from 60 to 85% of the mass. based on the total amount of produced olefins compared to the total amount of supply of feedstock. 12. The process of claim 1, wherein the residue hydrocracking reactor comprises a slurry bed reactor or a fluidized bed reactor. 13. The method of claim. 1, in which the separation of all crude oil includes: supplying all of the crude oil to a heater to produce a heated hydrocarbon feedstock; separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction; feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction; feeding a stream of hydrogen to a hydrogen hot stripper; separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper; And cooling the bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to the intermediate fraction to obtain a high-boiling residue fraction. 14. A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and the process includes: separating the hydrocarbon feedstock in the first in-line separating device into at least a light boiling fraction, a medium boiling fraction and a high boiling residue fraction; hydrocracking the high-boiling residue fraction in a first vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent; solvent deasphalting of the hydrocracked effluent with separation of pitch and deasphalted oil fraction; hydrocracking the deasphalted oil fraction and the pyrolysis oil in a second vacuum residue conditioning unit including a vacuum residue hydrocracking system to produce a second hydrocracked effluent; separating the hydrocracked effluent and the second hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction; destructive hydrogenation of the medium-boiling fraction and the partially conditioned fraction in the second conditioning unit to form a steam cracker feed stream; feeding the steam cracker feed stream and the low-boiling fraction to the steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil. 15. The method according to claim 14, in which 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; ICGB (Mining Bureau Correlation Index) 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 (micro carbon residue); And less than 1 ppm of all metals. 16. The method according to claim 14 or 15, 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; BCI (Bureau of Mines Correlation Index) ranging from about 5 to less than 50; density in degrees API in the range from about 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 (micro carbon residue); And less than 50 ppm all metals. 17. The process according to claim 14 or 15, wherein the high-boiling residue 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 (Mining Bureau Correlation Index) greater 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. 18. The method according to claim 14 or 15, in which: the second hydrocracked effluent has a 95% initial boiling point in the range of approximately 400 to 560°C. 19. The process of claim 14 or 15, wherein the high boiling residue fraction has a 5% initial boiling point greater than about 545°C. 20. The method according to claim 14 or 15, wherein the destructive hydrogenation of the medium boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprise the destructive hydrogenation of the medium boiling fraction and the partially conditioned fraction in a common destructive hydrogenation unit. 21. The process according to claim 14 or 15, wherein the destructive hydrogenation of the medium-boiling fraction and the destructive hydrogenation of the partially conditioned fraction comprises: destructive hydrogenation of the medium-boiling fraction in the first node of destructive hydrogenation; destructive hydrogenation of the partially conditioned fraction in the second destructive hydrogenation unit; And combining the outgoing streams of the first and second nodes of destructive hydrogenation. 22. The process of claim 21 further comprising destructively hydrogenating the partially conditioned fraction in the first destructive hydrogenation unit for a period of time while the catalyst in the second destructive hydrogenation unit is being replaced. 23. The method according to p. 14, in which the total production of chemical products from raw materials is approximately from 60 to 85% of the mass. based on the total amount of produced olefins in comparison with the total feedstock volume. 24. The process of claim 14 wherein the residue hydrocracking reactor comprises a slurry bed reactor or a fluidized bed reactor. 25. The method of claim 14 wherein separating all of the crude oil comprises: supplying all of the crude oil to a heater to produce a heated hydrocarbon feedstock; separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction; feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction; feeding a stream of hydrogen to a hydrogen hot stripper; separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper; And cooling the bottoms fraction of the hydrogen hot stripper by indirect heat exchange with respect to the intermediate fraction to obtain a high-boiling residue fraction. 26. A process for converting all crude oil and other heavy hydrocarbon streams to produce olefins and/or aromatics, and this process includes: separating the hydrocarbon feedstock in the first in-line separating device 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 pyrolysis oil in a first conditioning unit including a vacuum residue hydrocracking system to produce a hydrocracked effluent; separating the hydrocracked effluent in a second in-line separator to obtain a vacuum residue fraction and a partially conditioned fraction; hydrodesulfurizing the vacuum residue fraction to produce an ultra-low sulfur diesel fuel fraction; destructive hydrogenation of the medium-boiling fraction in a third conditioning unit to produce an effluent of a third conditioning unit; separating the outlet stream of the third air conditioning unit in the third built-in separating device into a light boiling conditioned fraction, a medium boiling conditioned fraction and a high boiling fraction; destructively hydrogenating the partially conditioned fraction, the medium-boiling conditioned fraction, and the diesel fuel fraction in the fourth conditioning unit to obtain an effluent of the fourth conditioning unit; separating the effluent of the fourth conditioning unit in the fourth built-in separating device into a light conditioned fraction and a diesel fuel fraction; feeding the high-boiling fraction, the light conditioned fraction, the light-boiling fraction and the light-boiling conditioned fraction to a steam cracker to convert the hydrocarbons therein into one or more light olefins and pyrolysis oil. 27. The method of claim 26, 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; ICGB (Mining Bureau Correlation Index) 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 (micro carbon residue); And less than 1 ppm of all metals. 28. The method according to claim 26 or 27, 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; BCI (Bureau of Mines Correlation Index) ranging from about 5 to less than 50; density in degrees API in the range from about 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 (micro carbon residue); And less than 50 ppm all metals. 29. The process according to claim 26 or 27, wherein the high-boiling residue 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 (Mining Bureau Correlation Index) greater 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 (micro carbon residue); And more than 50 ppm all metals. 30. The method of claim 26 wherein separating all of the crude oil comprises: supplying all of the crude oil to a heater to produce a heated hydrocarbon feedstock; separating the heated hydrocarbon feedstock in a separator into a low-boiling fraction and an intermediate fraction; feeding the intermediate fraction back to the heater to obtain a heated intermediate fraction; feeding a stream of hydrogen to a hydrogen hot stripper; separating the heated intermediate fraction in the hydrogen hot stripper into a medium-boiling fraction and a bottoms fraction of the hydrogen hot stripper; And cooling the bottoms fraction of the hydrogen hot stripper by means of indirect heat exchange with respect to the intermediate fraction to obtain a high-boiling residue fraction.

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