Hydrocarbon conversion process

Abstract

Methods and systems for upgrading hydrocarbons. In some embodiments, the method can include feeding molecular hydrogen, utility fluid, and a hydrocarbon feed including a Group I lube oil extract to a first hydroprocessing stage. The method can also include hydroprocessing in the first hydroprocessing stage to produce a first hydroprocessing effluent. The method can also include separating a middle distillate product and a bottoms product from the first hydroprocessing effluent. The method can also include feeding molecular hydrogen and at least a portion of the bottoms product to a second hydroprocessing stage. The method can also include hydroprocessing in the second hydroprocessing stage to produce a second hydroprocessing effluent. The method can also include recycling at least a portion of the middle distillate product as at least a portion of the utility fluid to the first hydroprocessing stage.

Description

[0001] Cross-reference to related applications

[0002] This application claims priority and benefit to U.S. Provisional Application No. 63 / 596,327, filed November 6, 2023, the disclosure of which is incorporated herein by reference in its entirety. Technical Field

[0003] The embodiments disclosed herein generally relate to hydrocarbon conversion methods. More specifically, the method involves the hydrotreating of hydrocarbon feedstocks including Type I lubricating oil extracts. Background of the Invention

[0005] Steam crackers are capable of steam cracking a wide range of feedstocks, which can be gaseous at room temperature, such as C. 4- Hydrocarbon feed, and / or liquid, such as C 5+ Hydrocarbon feedstock. Steam cracker effluent includes hydrocarbons that have been converted or upgraded into higher-value products, such as light olefins, like ethylene and propylene. These products are typically separated and processed in the effluent processing unit. In addition to the higher-value products, other relatively low-value products, such as steam cracker tar, are also produced. This steam cracker tar is typically blended with one or more other hydrocarbon feed streams and sold as fuel oil. This steam cracker tar can be upgraded via hydrotreating in a hydrotreating unit to reduce sulfur content and density, thereby producing a low-sulfur fuel oil boiling-range product suitable for use as fuel oil or as a blending component.

[0006] The amount of steam cracker tar in the steam cracker effluent produced by steam cracking liquid hydrocarbon feed is significantly greater than that produced by steam cracking gaseous hydrocarbon feed. Therefore, when a hydrotreating unit is configured to process steam cracker tar originating from steam cracking liquid hydrocarbon feed, such a configuration can limit or prevent the steam cracker from processing gaseous hydrocarbon feed, because the hydrotreating unit requires a minimum amount of steam cracker tar in the steam cracker effluent.

[0007] Therefore, there is a need for improved methods and systems to enhance the hydrocarbon feed flexibility of steam crackers by improving the feed flexibility of the hydrotreating unit configured to process steam cracker tar. This disclosure addresses this and other needs. Summary of the Invention

[0008] Methods and systems for upgrading hydrocarbons are provided. In some embodiments, the hydrocarbon upgrading method may include (I) feeding molecular hydrogen, a utility fluid, and a hydrocarbon feed into a first hydrotreating stage. The hydrocarbon feed may be or may include a Class I lubricating oil extract. The method may further include (II) hydrotreating in the first hydrotreating stage to produce a first hydrotreating effluent. The method may further include (III) separating a mid-cut product and a bottom product from the first hydrotreating effluent. The method may further include (IV) feeding molecular hydrogen and at least a portion of the bottom product into a second hydrotreating stage. The method may further include (V) hydrotreating in the second hydrotreating stage to produce a second hydrotreating effluent. The method may further include (VI) recycling at least a portion of the mid-cut product back to the first hydrotreating stage as at least a portion of the utility fluid.

[0009] In other embodiments, the hydrocarbon upgrading method may include (I) heating hydrocarbons in a steam cracker and combining the hydrocarbons with an aqueous fluid to produce a first mixture that may include hydrocarbons and steam. The heating may be performed before, during, and / or after the combination of the hydrocarbon feed and the aqueous fluid. The method may also include (II) steam cracking at least a portion of the first mixture to produce a steam cracker effluent. The method may also include (III) separating steam cracker tar products and upgraded steam cracker effluent (which may include ethylene and propylene) from the steam cracker effluent. The method may also include (IV) feeding molecular hydrogen, at least a portion of the steam cracker tar products, and the hydrocarbon feed into a first hydrotreating stage. The hydrocarbon feed may be or may include a Class I lubricating oil extract. The method may also include (V) hydrotreating in the first hydrotreating stage to produce a first hydrotreating effluent. The method may also include (VI) separating middle fraction products and bottom products from the first hydrotreating effluent. The method may further include (VII) feeding molecular hydrogen and at least a portion of the bottom product into a second hydrotreating stage. The method may further include (VIII) performing hydrotreating in the second hydrotreating stage to produce a second hydrotreating effluent. The method may further include (IX) recycling at least a portion of the middle fraction product as at least a portion of the utility fluid back to the first hydrotreating stage. Attached Figure Description

[0010] The accompanying drawings described herein are for illustrative purposes only, not for all possible implementations, and are not intended to limit the scope of this disclosure. Similar reference numerals shown throughout the drawings indicate similar components in the overall embodiments illustrated in the drawings.

[0011] Figure 1A schematic diagram of an illustrative method / system for upgrading a hydrocarbon feed comprising a Class I lubricating oil extract, according to one or more embodiments described above, is shown.

[0012] Figure 2 A schematic diagram of another illustrative method / system for upgrading a hydrocarbon feed comprising a Class I lubricating oil extract, according to one or more of the embodiments described above, is shown.

[0013] Figure 3 A schematic diagram of an illustrative method / system for upgrading steam cracker tar and hydrocarbon feed including Class I lubricating oil extracts, according to one or more of the embodiments described above, is shown.

[0014] Figure 4 A schematic diagram of another illustrative method / system for upgrading steam cracker tar, fluidized catalytic cracker main column bottom products, and hydrocarbon feed including Class I lubricating oil extracts, according to one or more of the embodiments described above, is shown. Detailed Implementation

[0015] Different specific embodiments, forms, and examples of the invention will now be described, including preferred embodiments and definitions adopted herein for the purpose of understanding the claimed invention. While specific preferred embodiments are given in the following detailed description, those skilled in the art will understand that these embodiments are merely exemplary and that the invention may be practiced in other ways. For the purpose of determining infringement, the scope of the invention will be referred to by any one or more of the appended claims, including their equivalents, and elements or limitations equivalent to those recited. Any reference to “the invention” may refer to one or more, but not necessarily all, of the inventions as defined by the claims.

[0016] In this disclosure, a method is described as comprising at least one "step". It should be understood that each step is an action or operation that can be performed once or multiple times in a continuous or discontinuous manner within the method. Unless otherwise specified or the context clearly indicates, multiple steps in a method may be performed sequentially in the order they are listed, overlapping or not overlapping with one or more other steps, or in any other order, as applicable. Furthermore, for the same or different batches of material, one or more, or even all, steps may be performed simultaneously. For example, in a continuous method, when the first step in the method is performed relative to the raw material just fed into the method at the start, the second step may be performed simultaneously relative to intermediate material formed from the raw material fed into the method in an early processing stage of the first step. Preferably, the steps are performed in a desired order.

[0017] Unless otherwise indicated, all numbers expressing quantities in this disclosure are to be understood as being modified in all instances by the term "about." It should also be understood that the exact numerical values used in the specification and claims constitute specific embodiments. Efforts have been made to ensure the accuracy of the data in the examples. However, it should be understood that due to limitations of the techniques and / or apparatus used for making the measurements, any data measured inherently contains a certain level of error.

[0018] Certain embodiments and features are described herein using a set of upper numerical limits and a set of lower numerical limits. It should be understood that, unless otherwise indicated, such ranges are contemplated to include any combination of two values, such as any combination of a lower value and an upper value, any combination of two lower values, and / or any combination of two upper values.

[0019] As used herein, the indefinite article "a" or "an" shall mean "at least one," unless otherwise indicated to the contrary or the context clearly dictates otherwise. Thus, embodiments using "a steam cracking furnace" include embodiments in which one, two, or more steam cracking furnaces may be used, unless otherwise indicated to the contrary or the context clearly indicates that only one steam cracking furnace is used.

[0020] As used herein, the term "hydrocarbon" means (i) any compound consisting of hydrogen and carbon atoms, or (ii) any mixture of two or more such compounds in (i). The term "C n hydrocarbon," where n is a positive integer, means (i) any hydrocarbon compound containing a total of n carbon atoms in its molecule, or (ii) any mixture of two or more such hydrocarbon compounds in (i). Thus, C2 hydrocarbons can be ethane, ethylene, acetylene, or any mixture of at least two of these compounds in any proportion. "C m to C n hydrocarbon" or "C m -C n hydrocarbon" (where m and n are positive integers and m < n) means any one of C m 、C m+1 、C m+2 、…、C n-1 、C n hydrocarbons or any mixture of two or more of them. Thus, "C2 to C3 hydrocarbons" or "C2-C3 hydrocarbons" can be any one of ethane, ethylene, acetylene, propane, propylene, propyne, allene, cyclopropane, and any mixture of two or more of them in any ratio between and among the components. "Saturated C2-C3 hydrocarbons" can be any mixture of ethane, propane, cyclopropane, or two or more of them in any proportion. "C n+"Hydrocarbon" means (i) any hydrocarbon compound whose molecule contains a total of at least n carbon atoms, or (ii) any mixture of two or more such hydrocarbon compounds in (i). n- "Hydrocarbon" means (i) any hydrocarbon compound whose molecule contains a maximum of n carbon atoms, or (ii) any mixture of two or more such hydrocarbon compounds in (i). m "Hydrocarbon stream" refers to a stream that is basically composed of C m A hydrocarbon feed stream composed of hydrocarbons. "C m -C n "Hydrocarbon stream" refers to a stream that is basically composed of C m -C n A stream of hydrocarbon feed consisting of hydrocarbons.

[0021] The term "hydrocarbon feedstock" refers to a composition comprising a Type I lubricating oil extract. In some embodiments, in addition to the Type I lubricating oil extract, the hydrocarbon feedstock may also comprise any additional hydrocarbons, such as heavy hydrocarbons, such as C64. 5+ Hydrocarbons and / or light hydrocarbons, such as C 4- hydrocarbon.

[0022] As used herein, the term "aromatic" should be understood in accordance with the generally accepted scope of its field, which includes alkyl-substituted and unsubstituted mononuclear and polynuclear compounds.

[0023] As used herein, “wt%” means weight percentage, “vol%” means volume percentage, “mol%” means molar percentage, “ppm” means parts per million, and “ppm wt” and “wppm” are used interchangeably, meaning parts per million based on weight. Unless otherwise specified, all concentrations herein are expressed as total amounts of the compositions under discussion.

[0024] Overview of methods / systems for upgrading hydrocarbons

[0025] A hydrocarbon feed comprising one or more relatively high-sulfur hydrocarbons may be hydrotreated in a first hydrotreating stage in the presence of molecular hydrogen and a utility fluid to produce a first hydrotreating effluent. The hydrocarbon feed may be, or may include, a Class I lubricating oil extract. In some embodiments, in addition to the Class I lubricating oil extract, the hydrocarbon feed may also comprise steam cracker tar. In other embodiments, in addition to the Class I lubricating oil extract, the hydrocarbon feed may also comprise fluidized bed catalytic cracking main bottoms product. In still other embodiments, in addition to the Class I lubricating oil extract, the hydrocarbon feed may also comprise steam cracker tar and fluidized bed catalytic cracking main bottoms product. Therefore, as used herein, the term "hydrocarbon feed" refers to a feed comprising a Class I lubricating oil extract and optionally one or more additional hydrocarbons, such as steam cracker tar and / or fluidized bed catalytic cracking main bottoms product.

[0026] In some embodiments, the hydrocarbon feed, molecular hydrogen, and utility fluid may be mixed before being introduced into the first hydrotreatment stage. In other embodiments, the hydrocarbon feed and utility fluid may be mixed before being introduced into the first hydrotreatment stage, and the molecular hydrogen and the mixture of the hydrocarbon feed and utility fluid may be introduced into the hydrotreatment stage separately. In still other embodiments, the hydrocarbon feed, molecular hydrogen, and utility fluid may be introduced into the first hydrotreatment stage separately and mixed therein. When the steam cracker effluent and / or the fluidized catalytic cracker main bottom product are also introduced into the first hydrotreatment stage, such additional feed may be introduced therein separately or as a mixture of at least one of the hydrocarbon feed, utility fluid, and molecular hydrogen. In some embodiments, the hydrocarbon feed, utility fluid, and at least one of the steam cracker tar and the fluidized catalytic cracker main bottom product may be combined to produce a mixture, and this mixture and molecular hydrogen may be introduced into the first hydrotreatment stage. In other embodiments, the hydrocarbon feed, utility fluid, molecular hydrogen, and at least one of steam cracker tar and fluidized catalytic cracker main bottom product can be combined to produce a mixture, which can be introduced into a first hydrotreating stage.

[0027] In some embodiments, middle fractions and bottom products can be separated from the first hydrotreating effluent. In other embodiments, top products (which may include molecular hydrogen and one or more C1-C4 hydrocarbons), middle fractions, and bottom products can be separated from the first hydrotreating effluent. In still other embodiments, the top product, light fraction (which may include naphtha), middle fraction, and bottom product can be separated from the first hydrotreating effluent. In some embodiments, at least a portion of the middle fraction can be recycled to the first hydrotreating stage so that the middle fraction can constitute at least a portion or all of the utility fluid. In some embodiments, the top product comprising molecular hydrogen may also include hydrogen sulfide and / or other sulfur-containing compounds. In such embodiments, at least a portion of the sulfur-containing compounds may be removed, for example, via one or more amine towers.

[0028] In some embodiments, a portion or all of the bottom product separated from the first hydrotreating effluent may be used as a blending component to produce low-sulfur fuel oil. In other embodiments, a portion or all of the bottom product may be hydrotreated in a second hydrotreating stage in the presence of molecular hydrogen to produce a second hydrotreating product. In some embodiments, the second hydrotreating product may be used as a low-sulfur fuel oil, such as a fuel oil containing ≤0.5 wt% sulfur or a blend thereof. In some embodiments, a molecularly hydrogen-rich top product and a molecularly hydrogen-poor bottom product may be separated from the second hydrotreating product. In some embodiments, at least a portion of the molecular hydrogen from the top product separated from the first hydrotreating effluent and / or at least a portion of the molecular hydrogen separated from the second hydrotreating product may be fed into the first hydrotreating stage, the second hydrotreating stage, or a combination thereof.

[0029] Hydrocarbon feed

[0030] The Class I lubricating oil extract may include 3.5 wt%, 3.7 wt%, 4 wt%, 4.3 wt%, or 4.5 wt%-5 wt%, 5.3 wt%, 5.5 wt%, 5.7 wt%, or 6 wt% sulfur, based on the total weight of the Class I lubricating oil extract. The Class I lubricating oil extract may include 8 wt%, 8.3 wt%, 8.5 wt%, 8.7 wt%, 9 wt%, 9.3 wt%, 9.5 wt%, 9.7 wt%, or 10 wt%-10.5 wt%, 10.7 wt%, 11 wt%, 11.3 wt%, 11.5 wt%, 11.7 wt%, or 12 wt% hydrogen, based on the total weight of the Class I lubricating oil extract. The hydrogen content can be measured by proton nuclear magnetic resonance (NMR). For example, the hydrogen content can be measured according to ASTM D7171-05 or its equivalent. The sulfur content can be measured by X-ray fluorescence spectroscopy. For example, the sulfur content can be measured according to ASTM D2622-21 or its equivalent. The API specific gravity of the Class I lubricating oil extract may be from 7.3°, 7.5°, 7.7°, 8°, 8.3°, 8.5°, or 8.7° to 9°, 9.3°, 9.5°, 9.7°, or 10°. The API specific gravity of the Class I lubricating oil extract and other hydrocarbon feedstocks may be measured according to ASTM D287-22 at 15.8°C. The solubility blend number (SBN) of the Class I lubricating oil extract may be from 93, 95, 100, 105, 110, 115, or 120 to 125, 130, 135, 140, 145, 150, or 155. The SBN of the Class I lubricating oil extract and other hydrocarbon feedstocks may be measured as described in U.S. Patent No. 5,871,634. The density of the Class I lubricating oil extract at 15°C may be 0.905 g / cm³. 3 0.910 g / cm 3 0.930 g / cm 3 0.950 g / cm 3 0.970 g / cm 3 0.990 g / cm 3 Or 1.000g / cm 3 Up to 1.005 g / cm 3 1.007 g / cm³ 3 1.009 g / cm³ 3 1.100g / cm 3 1.105 g / cm 3 1.110 g / cm 3 Or 1.113 g / cm 3The density of the Class I lubricating oil extract and other hydrocarbon feedstocks can be determined by measuring the API and converting the API to density. In some embodiments, the Class I lubricating oil extract may include 3.5 wt%-6 wt% sulfur and 8 wt%-12 wt% hydrogen, based on the total weight of the Class I lubricating oil extract, and the API specific gravity may be 7.3°-10°, the SBN may be 93-155, and the density may be 0.905 g / cm³. 3 -1.113g / cm 3 .

[0031] In some embodiments, the Type I lubricating oil extract can be produced by fractionating crude oil or its fractions in an atmospheric distillation (APS). One of the products recovered therefrom can be introduced into a lubricating oil vacuum distillation (LVPS) to separate products containing lubricating oil molecules, which can then be introduced into a lubricating oil extraction unit. This lubricating oil extraction unit can use any suitable solvent for extraction. In some embodiments, N-methylpyrrolidone (NMP), furfural, and / or phenol can be used as solvents for the extraction method. The products recovered from the lubricating oil extraction unit may include both Type I and Type II lubricating oil extracts.

[0032] In some embodiments, the Class I lubricant extract may be, or may include, but is not limited to, light neutral (LN) Class I lubricant extract, heavy neutral (HN) Class I lubricant extract, bright oil (BS) Class I lubricant extract, or mixtures thereof. In some embodiments, the light neutral Class I lubricant extract may contain a greater amount of sulfur than the heavy neutral Class I lubricant extract, and the heavy neutral Class I lubricant extract may contain a greater amount of sulfur than the bright oil Class I lubricant extract. In some embodiments, the light neutral Class I lubricant extract may contain a lower amount of hydrogen than the heavy neutral Class I lubricant extract, and the heavy neutral Class I lubricant extract may contain a lower amount of hydrogen than the bright oil Class I lubricant extract. In some embodiments, the API of the bright oil Class I lubricant extract may be greater than that of the light neutral Class I lubricant extract, and the API of the light neutral Class I lubricant extract may be greater than that of the heavy neutral Class I lubricant extract. In some embodiments, the solubility blending number of the light neutral Class I lubricating oil extract may be greater than that of the bright oil Class I lubricating oil extract, and the solubility blending number of the bright oil Class I lubricating oil extract may be greater than that of the heavy neutral Class I lubricating oil extract.

[0033] The light neutral Class I lubricating oil extract may include 3.9 wt%, 4 wt%, 4.3 wt%, 4.5 wt%, or 4.7 wt% to 5 wt%, 5.3 wt%, 5.5 wt%, 5.7 wt%, or 6 wt% sulfur, based on the total weight of the light neutral Class I lubricating oil extract. The light neutral Class I lubricating oil extract may include 8 wt%, 8.3 wt%, 8.5 wt%, or 8.7 wt% to 9 wt%, 9.3 wt%, 9.5 wt%, 9.7 wt%, or 10 wt% hydrogen, based on the total weight of the light neutral Class I lubricating oil extract. The API specific gravity of the light neutral Class I lubricating oil extract may be 8°, 8.3°, 8.5°, or 8.7° to 9°, 9.3°, 9.5°, or 9.8°. The solubility blending number of the light neutral Class I lubricating oil extract can be from 125, 127, 130, 133, 135, 137 or 140 to 143, 145, 147, 150, 153 or 155. The density of the light neutral Class I lubricating oil extract at 15°C can be 0.905 g / cm³. 3 0.910 g / cm 3 0.930g / cm 3 0.950g / cm 3 0.970 g / cm 3 0.990g / cm 3 Or 1.000g / cm 3 Up to 1.005 g / cm 3 1.007 g / cm 3 1.009 g / cm 3 1.100g / cm 3 1.105 g / cm 3 Or 1.108 g / cm 3 In some embodiments, the light neutral Group I lubricant extract may comprise 3.9 wt%-6 wt% sulfur and 8 wt%-10 wt% hydrogen based on the total weight of the light neutral Group I lubricant extract, may have an API specific gravity of 8°-9.8°, may have an SBN of 125-155, and may have a pH of 0.905 g / cm³. 3 -1.108g / cm 3 The density.

[0034] The heavy neutral Class I lubricating oil extract may include 3.7 wt%, 4 wt%, 4.3 wt%, 4.5 wt%, or 4.7 wt% to 5 wt%, 5.3 wt%, 5.5 wt%, or 5.7 wt% sulfur, based on the total weight of the heavy neutral Class I lubricating oil extract. The heavy neutral Class I lubricating oil extract may include 8.8 wt%, 9 wt%, 9.3 wt%, or 9.5 wt% to 9.7 wt%, 10 wt%, 10.3 wt%, 10.5 wt%, or 10.8 wt% hydrogen, based on the total weight of the heavy neutral Class I lubricating oil extract. The API specific gravity of the heavy neutral Class I lubricating oil extract may be 7.3°, 7.5°, 7.7°, or 8° to 8.3°, 8.5°, 8.7°, or 9°. The solubility blending number of the heavy neutral Class I lubricating oil extract can be from 93, 95, 97, 100, 105 or 107 to 109, 111, 112, 113 or 115. The density of the heavy neutral Class I lubricating oil extract at 15°C is 0.910 g / cm³. 3 0.920 g / cm 3 0.930 g / cm 3 0.950 g / cm 3 , or 0.970 g / cm 3 Up to 0.990 g / cm 3 1.000g / cm 3 1.010 g / cm 3 1.050g / cm 3 1.100g / cm 3 1.105 g / cm 3 Or 1.115g / cm 3 In some embodiments, the heavy neutral Class I lubricating oil extract may include 3.7 wt%-5.7 wt% sulfur and 8.8 wt%-10.8 wt% hydrogen, and based on the total weight of the heavy neutral Class I lubricating oil extract, may have an API specific gravity of 7.3°-9°, may have an SBN of 93-115, and may have a pH of 0.910 g / cm³. 3 -1.115 g / cm 3 The density.

[0035] The bright oil type I lubricant extract may include 3.6 wt%, 3.8 wt%, 4 wt%, 4.3 wt%, or 4.5 wt% to 4.7 wt%, 5 wt%, 5.3 wt%, or 5.5 wt% sulfur, based on the total weight of the bright oil type I lubricant extract. The bright oil type I lubricant extract may include 9.5 wt%, 9.7 wt%, 10 wt%, or 10.3 wt% to 10.7 wt%, 11 wt%, 11.3 wt%, 11.5 wt%, or 11.7 wt% hydrogen, based on the total weight of the bright oil type I lubricant extract. The API specific gravity of the bright oil type I lubricant extract may be from 8.1°, 8.3°, 8.5°, or 8.7° to 9°, 9.3°, 9.5°, 9.7°, or 10°. The solubility blending number of the bright oil type I lubricating oil extract is 97, 100, 103, 105, 107 or 110 to 112, 114, 116, 118 or 119. The density of the bright oil type I lubricating oil extract at 15°C is 0.905 g / cm³. 3 0.910 g / cm 3 0.930 g / cm 3 0.950 g / cm 3 Or 0.970 g / cm 3 Up to 0.990 g / cm 3 1.000g / cm 3 1.010 g / cm 3 1.050g / cm 3 1.100g / cm 3 1.105 g / cm 3 Or 1.107 g / cm 3 In some embodiments, the bright oil type I lubricant extract may include 3.6 wt%-5.5 wt% sulfur and 9.5 wt%-11.7 wt% hydrogen, and based on the total weight of the bright oil type I lubricant extract, may have an API specific gravity of 8.1°-10°, may have an SBN of 97-119, and may have a pH of 0.905 g / cm³. 3 -1.107 g / cm 3 The density.

[0036] The term "steam cracker tar" refers to (a) a mixture of hydrocarbons having one or more aromatic components and optionally (b) non-aromatic and / or non-hydrocarbon molecules, produced by steam cracking hydrocarbons in the radiant section of a steam cracker. Some steam cracker tars may have an initial boiling point of ≥200°C. For some steam cracker tars, ≥90 wt% of the steam cracker tar may have a boiling point of ≥290°C at atmospheric pressure. Steam cracker tar may comprise, for example, ≥50 wt%, ≥75 wt%, or ≥90 wt% of hydrocarbon molecules (including mixtures and aggregates thereof) having (i) one or more aromatic components and (ii) a carbon number of ≥15, based on the weight of the steam cracker tar. Steam cracker tar typically may comprise ≤1 × 10⁻⁶ 3 The amount of metal in ppmw, based on the weight of the steam cracker tar, is far less than the amount of metal found in crude oil (or crude oil components) of the same average viscosity.

[0037] The steam cracker tar may include 3.3 wt%, 3.5 wt%, 3.7 wt%, or 4 wt% to 4.3 wt%, 4.5 wt%, 4.7 wt%, or 5 wt% sulfur, based on the total weight of the steam cracker tar. The steam cracker tar may include 5.5 wt%, 5.7 wt%, 6 wt%, 6.3 wt%, or 6.5 wt% to 6.7 wt%, 7 wt%, 7.3 wt%, or 7.5 wt% hydrogen, based on the total weight of the steam cracker tar. The API specific gravity of the steam cracker tar may be -11°, -10.7°, -10.5°, -10.3°, -10°, or -9.7° to -9.5°, -9.3°, -9°, -8.7°, -8.5°, -8.3°, or -8°. The solubility blending number of the steam cracker tar can be from 180, 185, 190, 195, 200, 205 or 210 to 215, 220, 225, 230, 235, 240, 245 or 250. The density of the steam cracker tar at 15°C can be 1.040 g / cm³. 3 1.070 g / cm 3 1.100g / cm 3 1.150g / cm 3 Or 1.170 g / cm 3 Up to 1.200 g / cm 3 1.230 g / cm 3 1.250g / cm 3 Or 1.271 g / cm 3In some embodiments, the steam cracker tar may include 3.3 wt%-5 wt% sulfur and 5.5 wt%-7.5 wt% hydrogen, based on the total weight of the steam cracker tar, and the API specific gravity may be -11° to -8°, the solubility blend number may be 180-250, and the density may be 1.040 g / cm³. 3 -1.271g / cm 3 .

[0038] The steam cracking conditions in the radiant section of the steam cracker may include, but are not limited to, one or more of the following: exposing the hydrocarbons introduced therein to a temperature of ≥400°C (measured at the radiant outlet of the steam cracker), such as about 700°C, about 800°C, or about 900°C to about 950°C, about 1000°C, or about 1050°C, an absolute pressure of about 100 kPa to about 600 kPa, and / or a steam cracking residence time of about 0.01 seconds to about 5 seconds. Suitable steam crackers, product recovery configurations, other apparatus, and process conditions may include those disclosed below: U.S. Patent Nos. 6,419,885; 7,560,019; 7,993,435; 8,105,479; 8,197,668; 888,2991; 9,637,694; 9,777,227; U.S. Patent Application Publication Nos. 2014 / 0061096; 2014 / 0357923; 2016 / 0376511; 2018 / 0170832; 2019 / 0016975; and International Publication Nos. WO2018 / 111574; WO / 2020 / 096972; WO / 2020 / 096974; WO / 2020 / 096977; and WO / 2020 / 096979.

[0039] The bottom product of the fluidized bed catalytic cracker can be separated from the effluent of the fluidized bed catalytic cracker. The effluent can be produced by contacting hydrocarbons within the fluidized bed catalytic cracker in the presence of fluidized catalyst particles. The bottom product of the fluidized bed catalytic cracker may include 1.5 wt%, 1.7 wt%, 2 wt%, 2.3 wt%, 2.5 wt%, 2.7 wt%, or 3 wt% to 3.3 wt%, 3.5 wt%, 3.7 wt%, 4 wt%, 4.3 wt%, 4.5 wt%, 4.7 wt%, or 5 wt% sulfur, based on the total weight of the bottom product of the fluidized bed catalytic cracker. The bottom product of the fluidized bed catalytic cracker may include 6.1 wt%, 6.3 wt%, 6.5 wt%, 6.7 wt%, 7 wt%, or 7.3 wt% to 7.5 wt%, 7.7 wt%, 8 wt%, 8.3 wt%, 8.5 wt%, or 8.8 wt% hydrogen, based on the total weight of the bottom product. The API specific gravity of the bottom product may be -11°, -10°, -9°, -8°, -7°, -6°, or -5° to -4°, -3°, -2°, 1°, 0°, 1°, 2°, or 2.5°. The solubility blending number of the bottom product may be 180, 185, 190, 195, 200, 205, or 210 to 215, 220, 225, 230, 235, 240, 245, or 250. The density of the bottom product of the main column of the fluidized catalytic cracker is 0.954 g / cm³ at 15°C. 3 0.970 g / cm 3 1.000g / cm 3 1.050 or 1.100 g / cm³ 3 Up to 1.150 g / cm 3 1.200g / cm 3 1.230 g / cm 3 Or 1.243 g / cm 3 In some embodiments, the bottom product of the fluidized catalytic cracker main column may include 1.5 wt%-5 wt% sulfur and 6.1 wt%-8.8 wt% hydrogen. Based on the total weight of the bottom product of the fluidized catalytic cracker main column, the API specific gravity may be -11° to 2.5°, the solubility blending number may be 180-250, and the density may be 0.954 g / cm³. 3 -1.243 g / cm 3 .

[0040] In the fluidized catalytic cracker, hydrocarbons can be contacted with multiple fluidized catalyst particles for a certain contact time. The hydrocarbons can be injected into the reactor riser through one or more feed nozzles. Within this reactor riser, the hydrocarbons can contact the fluidized catalyst under cracking conditions, thereby producing spent catalyst particles containing coke deposited thereon and a lower-boiling-point product stream.

[0041] The fluidizing catalyst may be or may include any one or more catalysts commonly used in fluidized catalytic cracking methods. For example, the catalyst may include macroporous molecular sieve catalysts, mesoporous molecular sieve catalysts, or mixtures thereof. Macroporous molecular sieves typically comprise molecular sieve catalysts with an average pore size of about 0.7 nm or larger, and are commonly used to catalyze the “cracking” of hydrocarbons. Macroporous and mesoporous molecular sieves may have a crystalline tetrahedral framework oxide component. For example, the crystalline tetrahedral framework oxide component may include zeolites, reticulated silicates, tetrahedral aluminophosphate (ALPO), and tetrahedral aluminosilicate phosphate (SAPO). Conventional FCC catalysts (including mixtures of macroporous and shape-selective catalysts) may be used.

[0042] In some embodiments, the fluidized catalytic cracking conditions may include: a temperature of 535-850°C or higher; a hydrocarbon partial pressure of about 70 kPa-a to about 345 kPa-a; and a catalyst-to-feed ratio of 2-10 (wt / wt). In some embodiments, steam may be introduced into the reaction zone simultaneously with the feed. In some embodiments, steam (if present) may comprise up to about 5 wt% of the hydrocarbons introduced into the fluidized catalytic cracker. In some embodiments, the residence time in the reaction zone may be less than about 5 seconds, for example, about 2 to about 3 seconds. Suitable fluidized catalytic crackers, product recovery configurations, other apparatus, and process conditions may include those disclosed in Handbook of Petroleum Refining Processes, 2nd Edition, RAMeyers, 3.3-3.111, McGraw-Hill, and U.S. Patent Application Publication No. 2011 / 0220549.297.

[0043] Utility fluid / middle distillate products

[0044] In some embodiments, the utility fluid and the middle distillate product may have substantially the same or identical properties. In some embodiments, the utility fluid and / or middle distillate product may include ≤1 wt%, ≤0.9 wt%, ≤0.8 wt%, ≤0.7 wt%, ≤0.6 wt%, ≤0.5 wt%, ≤0.4 wt%, ≤0.3 wt%, ≤0.2 wt%, ≤0.18 wt%, ≤0.16 wt%, ≤0.14 wt%, ≤0.12 wt%, ≤0.1 wt%, ≤0.08 wt%, ≤0.06 wt%, ≤0.04 wt%, ≤0.02 wt%, or ≤0.01 wt% sulfur, based on the total weight of the utility fluid and / or middle distillate product. In some embodiments, the utility fluid and / or middle distillate product may be substantially sulfur-free. In other embodiments, the utility fluid and / or middle distillate product may include ≥0.001 wt%, ≥0.002%, ≥0.004%, or ≥0.006 wt% up to 0.2 wt% sulfur, based on the total weight of the utility fluid and / or middle distillate product. In some embodiments, the utility fluid and / or middle distillate product may include 8.7 wt%, 9 wt%, 9.3 wt%, 9.5 wt%, or 9.7 wt% to 10 wt%, 10.3 wt%, 10.5 wt%, 10.7 wt%, or 11 wt% hydrogen, based on the total weight of the utility fluid and / or middle distillate product. The API specific gravity of the utility fluid and / or middle distillate product may be 8°, 8.3°, 8.5°, 8.7°, 9°, 9.3°, 9.5°, 9.7°, 10°, 10.3°, 10.5°, 10.7° or 11° to 11.5°, 11.7°, 12°, 12.3°, 12.5°, 12.7°, 13°, 13.3°, 13.5°, 13.7° or 14°. The solubility blending number of the utility fluid and / or middle distillate product may be 100, 105, 110, 115, 120 or 125 to 130, 133, 135, 137 or 140. The density of the utility fluid and / or middle distillate product at 15°C may be 0.871 g / cm³. 3 0.875 g / cm 3 0.880 g / cm 3 0.885 g / cm 3 0.890 g / cm 3 0.895g / cm 3 Or 0.900g / cm 3 Up to 0.905 g / cm 3 0.910 g / cm 3 0.930 g / cm 3 0.950, 0.970 g / cm³ 3 1.000g / cm3 1.030 g / cm 3 1.050g / cm 3 Or 1.065g / cm 3 In some embodiments, the utility fluid and / or middle distillate product may include ≤0.2 wt% sulfur and 8.7 wt%-11 wt% hydrogen, with an API specific gravity of 8°-14°, a solubility blend number of 100-140, and a density of 0.871 g / cm³ based on the total weight of the utility fluid and / or middle distillate product. 3 -1.065g / cm 3 .

[0045] The utility fluid and / or middle distillate may contain ≥25 wt%, ≥30 wt%, ≥35 wt%, ≥40 wt%, ≥45 wt%, ≥50 wt%, ≥55 wt%, or ≥60 wt% to 65 wt%, 70 wt%, 80 wt%, 90 wt%, or more of cyclic compounds, based on the weight of the utility fluid and / or middle distillate. In some embodiments, the cyclic compounds may be or may include one or more aromatic hydrocarbons, which may include monocyclic, dicyclic, tricyclic, and / or tetracyclic aromatic hydrocarbons. In some embodiments, the utility fluid and / or middle distillate may include ≥15 wt% of dicyclic and / or tricyclic aromatic hydrocarbons, based on the weight of the utility fluid and / or middle distillate, for example ≥20 wt%, or ≥25 wt%, or ≥40 wt%, or ≥50 wt%, or ≥55 wt%, or ≥60 wt% to 65 wt%, 70 wt%, 80 wt%, 90 wt%, or more.

[0046] In some embodiments, the utility fluid and / or intermediate distillate may have a 10% distillation point ≥60°C and a 90% distillation point ≤425°C, for example, ≤400°C, according to ASTM D86-23. In some embodiments, the utility fluid and / or intermediate distillate may have a true boiling point distribution with an initial boiling point ≥130°C, ≥150°C, or ≥177°C and a final boiling point ≤566°C, ≤430°C, or ≤425°C. The true boiling point distribution (distribution at atmospheric pressure) may be determined, for example, by conventional methods such as ASTM D7500-15 (2019). When the final boiling point is higher than that specified in the standard, the true boiling point distribution may be determined by extrapolation. A particular form of the utility fluid and / or intermediate distillate may have a true boiling point distribution with an initial boiling point ≥130°C and a final boiling point ≤566°C and / or may include ≥15 wt% of bicyclic and / or tricyclic aromatic compounds.

[0047] The bottom product separated from the first hydrotreating effluent may include 0.3 wt%, 0.4 wt%, 0.5 wt%, or 0.6 wt% to 1 wt%, 1.5 wt%, 2 wt%, or 3 wt% sulfur, based on the total weight of the bottom product. The bottom product may include 5.5 wt%, 6 wt%, 6.5 wt%, 7 wt%, or 7.5 wt% to 8 wt%, 8.5 wt%, 9 wt%, 9.5 wt%, or 10 wt% hydrogen, based on the total weight of the bottom product. The API specific gravity of the bottom product may be -6°, -5°, -4°, or -3.5° to -3°, -2°, -1°, or 0°. The density of the bottom product at 15°C may be 0.950 g / cm³. 3 0.970 g / cm 3 1.000g / cm 3 1.050 or 1.100 g / cm³ 3 Up to 1.110 g / cm 3 1.150g / cm 3 1.200g / cm 3 Or 1.250g / cm 3 In some embodiments, the bottom product may include 0.3 wt% to 3 wt% sulfur and 5.5 wt% to 10 wt% hydrogen, and based on the total weight of the bottom product, the API specific gravity may be -6° to 0°, and the density may be 0.950 g / cm³. 3 -1.250 g / cm 3 .

[0048] mixture

[0049] In some embodiments, the mixture of the hydrocarbon feedstock (i.e., Class I lubricating oil extract and optionally steam cracker tar and / or fluidized catalytic cracker main bottom product) with utility fluid and / or middle distillate product may include an amount of utility fluid and / or middle distillate product sufficient to provide a sufficiently low viscosity for the mixture to be fed to hydrotreating, for example, the kinematic viscosity of the mixture at 50°C may be from 1 cSt to ≤500 cSt, as measured by ASTM D445-21e2. In some embodiments, the mixture of the hydrocarbon feed and utility fluid and / or middle distillate product may comprise 20 wt%, 25 wt%, 30 wt%, 35 wt%, 40 wt%, 45 wt%, or 50 wt% to 60 wt%, 65 wt%, 70 wt%, 75 wt%, 80 wt%, 85 wt%, 90 wt%, or 95 wt% of the hydrocarbon feed and 5 wt%, 10 wt%, 15 wt%, 20 wt%, 25 wt%, 30 wt%, 35 wt%, 40 wt%, 45 wt%, or 50 wt% to 60 wt%, 65 wt%, 70 wt%, 75 wt%, 80 wt%, 85 wt%, 90 wt%, or 95 wt% of the utility fluid and / or middle distillate product, based on the total weight of the mixture. In some embodiments, the mixture of hydrocarbon feed and utility fluid and / or middle distillate product may comprise 30 wt%-50 wt% of the utility fluid and / or middle distillate product and 70 wt%-50 wt% of the hydrocarbon feed, based on the total weight of the mixture. In other embodiments, the mixture of hydrocarbon feed and utility fluid and / or middle distillate product may comprise 35 wt%-45 wt% of the utility fluid and / or middle distillate product and 65 wt%-55 wt% of the hydrocarbon feed, based on the total weight of the mixture.

[0050] In some embodiments, the mixture of the hydrocarbon feedstock (e.g., Class I lubricating oil extract and optionally steam cracker tar and / or fluidized catalytic cracker main bottom product) with the utility fluid and / or middle distillate product may include 1.8 wt%, 1.9 wt%, 2 wt%, 2.1 wt%, or 2.2 wt% to 2.4 wt%, 2.5 wt%, 2.7 wt%, 2.9 wt%, or 3.1 wt% sulfur, based on the total weight of the mixture. In some embodiments, the mixture of the hydrocarbon feedstock and the utility fluid and / or middle distillate product may include 6.8 wt%, 7 wt%, 7.3 wt%, 7.5 wt%, 7.7 wt%, or 8 wt% to 8.3 wt%, 8.5 wt%, 8.7 wt%, 9 wt%, or 9.2 wt% hydrogen, based on the total weight of the mixture. In some embodiments, the solubility blending number of the mixture of hydrocarbon feedstock and utility fluid and / or middle distillate products may be 160, 165, 170, 173, 175, 177 or 180 to 183, 185, 187, 190, 193, 195, 197 or 200. In some embodiments, the solubility blending number of the mixture of hydrocarbon feedstock and utility fluid and / or middle distillate products may be ≤200, ≤195 or ≤190 and ≥170, ≥173, ≥175 or ≥177. In some embodiments, the density of the mixture of hydrocarbon feedstock and utility fluid and / or middle distillate products at 15°C may be 0.950 g / cm³. 3 0.970 g / cm 3 Or 0.990 g / cm 3 Up to 1.000 g / cm 3 1.020 g / cm 3 1.030 g / cm 3 1.050g / cm 3 Or 1.100g / cm 3 .

[0051] In some embodiments, the hydrocarbon feed or at least a portion thereof may be subjected to a hot-dip process. This hot-dip process can reduce the reactivity of the hydrocarbons in the hydrocarbon feed. For example, when the hydrocarbon feed comprises steam cracker tar and / or fluidized catalytic cracker main column bottoms, such components may be subjected to a hot-dip step before, during, or after combination with other components of the hydrocarbon feed (i.e., the Class I lubricating oil extract and any additional hydrocarbons that may be present in the hydrocarbon feed).

[0052] In some embodiments, the hot soaking process can be carried out at temperatures ranging from 200°C, 210°C, 215°C, 230°C, or 245°C to 260°C, 275°C, 290°C, or 300°C. In some embodiments, the hot soaking process can be carried out for time periods of 1 minute, 2 minutes, 5 minutes, or 10 minutes to 15 minutes, 20 minutes, 25 minutes, or 30 minutes. In some embodiments, the hot soaking process can be carried out in one or more tar tanks and associated piping. In other embodiments, the hot soaking process can be carried out at least in part in one or more soaker drums and / or containers, conduits, and other devices (e.g., fractionators, water quench towers, indirect condensers) associated with, for example (i) separating the steam cracker tar and / or the fluidized catalytic cracker main column bottom products and / or (ii) conveying such hydrocarbons to the first hydrotreating stage. The location of the hot soaking process is not critical. This hot-dip process can be performed at any convenient location, for example, after separating the steam cracker tar and / or the fluidized catalytic cracker bottom product from the steam cracker effluent and / or the fluidized catalytic cracker effluent, and before hydrotreating in the first hydrotreating stage, for example, downstream of the tar tank and upstream of mixing the heat-treated tar and / or fluidized catalytic cracker bottom product with utility fluid / middle fraction product and Class I lubricating oil extract.

[0053] In some embodiments, the utility fluid and / or middle distillate product may be combined with the hydrocarbon feed during the hot leaching process. In other embodiments, the utility fluid and / or middle distillate product may be mixed with the hydrocarbon feed after the hot leaching process step has been applied to the hydrocarbon feed or a portion thereof (e.g., the steam cracker tar and / or the fluidized bed bottoms product of the main column).

[0054] In some embodiments, particularly when the hydrocarbon feed comprises steam cracker tar, a solids removal step may be performed on the hydrocarbon feed or a mixture of the hydrocarbon feed with utility fluids and / or middle distillate products. In some embodiments, when the hydrocarbon feed comprises steam cracker tar and / or fluidized bed bottoms products, the steam cracker tar and / or fluidized bed bottoms products may undergo a solids removal step, and may then be combined with additional components of the hydrocarbon feed (i.e., Class I lubricant extracts and any additional hydrocarbons that may be present in the hydrocarbon feed). The solids removal step may include any suitable method or system capable of removing solids from the feed, such as centrifugation, filtration, etc. In some embodiments, the solids removal step may include filtration followed by centrifugation.

[0055] First hydrogenation treatment stage

[0056] In some embodiments, the first hydrotreating stage can be carried out at temperatures ranging from 200°C, 225°C, 250°C, 260°C, 280°C, or 300°C to 325°C, 350°C, 375°C, 400°C, 410°C, or 425°C. In some embodiments, the first hydrotreating stage can be carried out at temperatures ranging from 0.6 h to 0.6 h. -1 0.8 h -1 1 h -1 1.5 h -1 or 2 hours -1 up to 3 hours -1 4 h -1 5 h -1 6 h -1 7h -1 8 h -1 9 h -1 or 10 h -1 Or a greater gravity time space velocity (WHSV). In some embodiments, the first hydrotreating stage can be carried out at a total pressure of 4 MPa, 5 MPa, 6 MPa, 7 MPa, or 8 MPa to 10 MPa, 11 MPa, 12 MPa, 13 MPa, 14 MPa, 15 MPa, or greater. In some embodiments, the first hydrotreating stage may include a 150 standard cubic meter molecular hydrogen / cubic meter hydrocarbon feed (Sm 3 / m 3 ), 175 Sm 3 / m 3 200 Sm 3 / m 3 250 Sm 3 / m 3 275 Sm 3 / m 3 300Sm 3 / m 3 325 Sm 3 / m 3 Or 350 Sm 3 / m 3 Up to 375 Sm 3 / m 3 400 Sm 3 / m 3 450 Sm 3 / m 3 500 Sm 3 / m 3 550Sm 3 / m 3 600 Sm 3 / m 3 700 Sm 3 / m3 800 Sm 3 / m 3 900 Sm 3 / m 3 , or 1,000 Sm 3 / m 3 The rate of molecular hydrogen supply.

[0057] The first hydrotreating stage may include processing the mixture of hydrocarbon feedstock and molecular hydrogen in the presence of at least one catalyst with hydrocarbon hydrotreating activity in a catalytically effective amount. In some embodiments, conventional hydrotreating catalysts may be used for hydrotreating in the first hydrotreating stage, for example those specified for hydrotreating residue oil and / or heavy oil, but the invention is not limited thereto. Suitable catalysts for the first hydrotreating stage may include bulk metal catalysts and supported catalysts, such as catalysts supported on alumina and / or silica. The metal may be in elemental or compound form. In some embodiments, the catalyst may include at least one metal from Groups 5-10 of the periodic table (as listed in the Periodic Chart of the Elements, The Merck Index, Merck & Co., Inc., 1996). Examples of such catalytic metals may include, but are not limited to, vanadium, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium, iridium, platinum, or mixtures thereof. In some embodiments, the catalyst may include a conventional RT-621 catalyst.

[0058] In some embodiments, the catalyst may contain a total of at least 0.0001 g, at least 0.001 g, or at least 0.01 g of Group 5-10 metals per gram of catalyst, wherein the gram number is calculated based on the element. For example, the catalyst may include 0.0001 g, 0.001 g, 0.005 g, 0.01 g, or 0.05 g to 0.08 g, 0.1 g, 0.2 g, or 0.3 g of Group 5-10 metals. In some embodiments, the catalyst may also include at least one Group 15 element. A preferred example of a Group 15 element is phosphorus. When using a Group 15 element, the catalyst may include a total of 0.000001 g, 0.00001 g, 0.0001 g, or 0.0005 g to 0.001 g, 0.03 g, 0.06 g, or 0.08 g of Group 15 element, wherein the gram number is calculated based on the element. In some embodiments, the first-stage hydrotreating can be carried out in the presence of a catalyst located in at least one catalyst bed. In some embodiments, two, three, or more catalyst beds may be connected in series, optionally with intercooling.

[0059] In some embodiments, the first hydrotreating stage may include one, two, three, or more units. In some embodiments, the first hydrotreating stage may sequentially include one or more guard bed reactors, one or more pre-processors downstream of the guard bed reactors, and one or more main first hydrotreating reactors downstream of the pre-processors. In some embodiments, the hydrocarbon feed, molecular hydrogen, and utility fluid and / or middle distillate products may be introduced individually in the form of a mixture, or in a combination of a mixture and individual feeds. For example, a mixture of the hydrocarbon feed and utility fluid and / or middle distillate products, along with the molecular hydrogen feed, may be introduced into the guard bed reactor.

[0060] The guard bed reactor may include one or more catalysts and can operate under relatively mild hydrotreating conditions to reduce the reactivity of the hydrocarbon feed. In some embodiments, the guard bed reactor may include one or more materials configured to trap solid particulate matter, such as coke, that may be present in the hydrocarbon feed. The effluent from the guard bed reactor may pass through an outlet and enter the pre-processor for further hydrotreating under slightly more demanding conditions and optionally with a more active catalyst. The effluent from the pre-processor may be sent to the main hydrotreating reactor for further hydrotreating under still more demanding conditions to obtain a first hydrotreating product.

[0061] In some embodiments, the protective bed reactor can operate at temperatures ranging from 240°C, 250°C, 255°C, or 260°C to 265°C, 270°C, 275°C, 280°C, or 290°C. In some embodiments, the protective bed reactor can operate for 3 hours. -1 3.5 h -1 4 h -1 Or 4.5 h -1 up to 5 hours -1 5.5 h -1 6 h -1 7 h -1 8 h -1 9 h -1 or 10 h -1The reactor operates at WHSV. In some embodiments, the guard bed reactor can operate at a total pressure of 6 MPa, 6.5 MPa, 7 MPa, or 8 MPa to 9 MPa, 10 MPa, 11 MPa, or 12 MPa. In some embodiments, the guard bed reactor may include one or more upstream catalyst beds, which may include at least one catalyst with demetallization activity, such as a relatively macroporous catalyst, to capture metals in the hydrocarbon feed. In some embodiments, one or more catalyst beds located further downstream in the guard bed reactor may contain at least one catalyst with olefin saturation activity, such as a catalyst containing Ni and / or Mo.

[0062] In some embodiments, all molecular hydrogen introduced into the first hydrotreating stage may be introduced into the guard bed reactor, and unreacted molecular hydrogen may flow out of the guard bed reactor and into the pre-processor, etc. In other embodiments, a first portion of the molecular hydrogen introduced into the first hydrotreating stage may be introduced into the guard bed reactor, and the remaining amount of molecular hydrogen introduced into the first hydrotreating stage may be introduced into the pre-processor, and unreacted molecular hydrogen in the pre-processor effluent may flow into the main first hydrotreating reactor. In yet another embodiment, a first portion of the molecular hydrogen introduced into the first hydrotreating stage may be introduced into the guard bed reactor, a second portion of the molecular hydrogen introduced into the first hydrotreating stage may be introduced into the pre-processor, and a third portion of the molecular hydrogen introduced into the first hydrotreating stage may be introduced into the main first hydrotreating reactor.

[0063] In some embodiments, the preprocessor can operate at temperatures ranging from 255°C, 260°C, 265°C, 270°C, or 275°C to 280°C, 285°C, 290°C, 295°C, 300°C, 305°C, or 310°C. In some embodiments, the preprocessor can operate for 1 hour. -1 1.5 h -1 2 h -1 or 2.5 h -1 up to 3 hours -1 3.5 h -1 4 h -1 4.5 h -1 or 5 hours -1The preprocessor operates at a WHSV. In some embodiments, the preprocessor can operate at a total pressure of 6 MPa, 6.5 MPa, 7 MPa, or 8 MPa to 9 MPa, 10 MPa, 11 MPa, 12 MPa, 13 MPa, 14 MPa, or 15 MPa. Suitable catalysts for the preprocessor may include bulk metal catalysts and supported catalysts, such as catalysts supported on alumina and / or silica. The metal may be in elemental or compound form. In some embodiments, the catalyst may include at least one metal from groups 5-10 of the periodic table (as listed in the Periodic Chart of the Elements, The Merck Index, Merck & Co., Inc., 1996). Examples of such catalytic metals may include, but are not limited to, vanadium, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium, iridium, platinum, or mixtures thereof. In some embodiments, the catalyst may include a conventional RT-621 catalyst.

[0064] In some embodiments, the main hydrotreating reactor can operate at temperatures ranging from 365°C, 370°C, 375°C, 380°C, 390°C, or 400°C to 405°C, 410°C, 415°C, or 420°C. In some embodiments, the main hydrotreating reactor can operate for 0.4 h. -1 0.6 h -1 0.7 h -1 up to 0.9 h -1 1 h -1 1.3 h -1 or 1.5 h -1 For example, about 0.8 h -1 The operation is carried out under WHSV conditions. Suitable catalysts for the main hydrotreating reactor may include bulk metal catalysts and supported catalysts, such as catalysts supported on alumina and / or silica. The metal may be in elemental or compound form. In some embodiments, the catalyst may include at least one metal from groups 5-10 of the periodic table (as listed in the Periodic Chart of the Elements, The Merck Index, Merck & Co., Inc., 1996). Examples of such catalytic metals may include, but are not limited to, vanadium, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium, iridium, platinum, or mixtures thereof. In some embodiments, the catalyst may include a conventional RT-621 catalyst.

[0065] In some embodiments, the main hydrotreating reactor can operate at a temperature greater than that of the preprocessor, and the preprocessor can operate at a temperature greater than that of the guard bed reactor. In some embodiments, the main hydrotreating reactor can operate at a WHSV less than that of the preprocessor, and the guard bed reactor can operate at a WHSV less than that of the preprocessor. In other embodiments, the guard bed reactor can operate at a WHSV greater than that of the preprocessor, and the preprocessor can operate at a WHSV greater than that of the main hydrotreating reactor. In some embodiments, a suitable first hydrotreating stage may include those described in WO Publications Nos. WO2018 / 111576A1 and WO2018 / 111577A1.

[0066] Separation stage

[0067] The first hydrotreated effluent may be separated via one or more separation stages or units. In some embodiments, the first hydrotreated effluent may be introduced into a fractionating column or distillation column, from which the middle fraction and bottom product may be recovered or otherwise obtained. In some embodiments, a top product comprising molecular hydrogen and a light fraction comprising naphtha may also be recovered from the fractionating column or distillation column. In other embodiments, the first hydrotreated effluent may be introduced into a first fractionating column or distillation column, from which a top product comprising molecular hydrogen and an intermediate bottom product comprising liquid hydrocarbons may be recovered. In such embodiments, the intermediate bottom product may be introduced into a second fractionating column or distillation column, from which a light fraction comprising naphtha, middle fraction, and bottom product may be recovered or otherwise obtained. In some embodiments, suitable separation stages for separating the first hydrotreated effluent into multiple products may include those described in WO Publications No. WO2018 / 111576A1 and / or WO2018 / 111577A1.

[0068] Second hydrogenation treatment stage

[0069] In some embodiments, the second hydrogenation treatment stage can be carried out at temperatures ranging from 350°C, 375°C, or 400°C to 410°C, 420°C, 425°C, 440°C, or 450°C. In some embodiments, the second hydrogenation treatment stage can be carried out for 0.1 hours. -1 0.2 h -1 0.3 h -1 or 0.4 h -1 up to 0.5 h -1 0.6 h -1 0.7 h -1 0.8 h -1 0.9 h-1 or 1 hour -1 The process is carried out at a weight time space velocity (WHSV). In some embodiments, the second hydrogenation stage can be carried out at a lower WHSV than the first hydrogenation stage. In other words, in some embodiments, the first hydrogenation stage can be carried out at a higher WHSV than the second hydrogenation stage.

[0070] In some embodiments, the second hydrotreating stage can be operated at a total pressure of 4 MPa, 5 MPa, 6 MPa, 7 MPa, or 8 MPa up to 10 MPa, 11 MPa, 12 MPa, 13 MPa, 14 MPa, 15 MPa, or higher. In some embodiments, the second hydrotreating stage may include 150 Sm 3 / m 3 250 Sm 3 / m 3 350 Sm 3 / m 3 450 Sm 3 / m 3 500Sm 3 / m 3 535 Sm 3 / m 3 575 Sm 3 / m 3 Or 600 Sm 3 / m 3 Up to 800 Sm 3 / m 3 900 Sm 3 / m 3 1065 Sm 3 / m 3 1100Sm 3 / m 3 1150 Sm 3 / m 3 1250 Sm 3 / m 3 1350 Sm 3 / m 3 Or 1500 Sm 3 / m 3 The rate of molecular hydrogen supply.

[0071] The second hydrotreating stage may include treating the bottom product and molecular hydrogen in the presence of at least one catalyst with hydrocarbon hydrotreating activity in a catalytically effective amount. In some embodiments, a portion of the middle distillate and / or other utility fluid may be mixed with the bottom product. In other embodiments, the bottom product may be hydrotreated in the second hydrotreating stage in the absence or substantially absence of any utility fluid and / or middle distillate.

[0072] In some embodiments, conventional hydrotreating catalysts may be used for hydrotreating in a second hydrotreating stage, such as those specified for hydrotreating residues and / or heavy oils, but the invention is not limited thereto. Suitable catalysts for the first hydrotreating stage may include bulk metal catalysts and supported catalysts, such as catalysts supported on alumina and / or silica. The metal may be in elemental or compound form. In some embodiments, the catalyst may include at least one metal from groups 5-10 of the periodic table (as listed in the Periodic Chart of the Elements, The Merck Index, Merck & Co., Inc., 1996). Examples of such catalytic metals may include, but are not limited to, vanadium, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium, iridium, platinum, or mixtures thereof. In some embodiments, the catalyst may include a conventional RT-621 catalyst.

[0073] In some embodiments, the catalyst may contain a total of at least 0.0001 g, at least 0.001 g, or at least 0.01 g of Group 5-10 metals per gram of catalyst, wherein the gram number is calculated based on the element. For example, the catalyst may include 0.0001 g, 0.001 g, 0.005 g, 0.01 g, or 0.05 g to 0.08 g, 0.1 g, 0.2 g, or 0.3 g of Group 5-10 metals. In some embodiments, the catalyst may also include at least one Group 15 element. A preferred example of a Group 15 element is phosphorus. When using a Group 15 element, the catalyst may include a total of 0.000001 g, 0.00001 g, 0.0001 g, or 0.0005 g to 0.001 g, 0.03 g, 0.06 g, or 0.08 g of Group 15 element, wherein the gram number is calculated based on the element. In some embodiments, the first-stage hydrotreating can be carried out in the presence of a catalyst located in at least one catalyst bed. In some embodiments, two, three, or more catalyst beds may be connected in series, optionally with intercooling. In some embodiments, a suitable second hydrotreating stage may include those described in WO Publications Nos. WO2018 / 111576A1 and WO2018 / 111577A1.

[0074] In some embodiments, the second hydrotreated effluent may include ≤0.5 wt%, ≤0.4 wt%, ≤0.3 wt%, ≤0.2 wt%, or ≤0.1 wt% sulfur, based on the total weight of the second hydrotreated effluent. In some embodiments, the second hydrotreated effluent may include 6.5 wt%, 7 wt%, 7.5 wt%, or 8 wt% to 8.5 wt%, 9 wt%, or 10 wt% hydrogen, based on the total weight of the second hydrotreated effluent. In some embodiments, the solubility blending number of the second hydrotreated effluent may be 170, 175, 180, 185, 190, or 195 to 200, 210, 220, 230, 240, or 250. In some embodiments, the density of the second hydrotreated product at 15°C may be 0.990 g / cm³. 3 1.000g / cm 3 Or 1.050 g / cm 3 Up to 1.060 g / cm 3 1.080 g / cm 3 Or 1.100g / cm 3 In some embodiments, the second hydrotreated effluent may include ≤0.5 wt% sulfur and 6.5 wt%-10 wt% hydrogen, and based on the total weight of the second hydrotreated effluent, the API specific gravity may be -4° to 10°, the SBN may be 170-250, and the density may be 0.990 g / cm³. 3 -1.100g / cm 3 It should be understood, as referenced below. Figure 3 and 4 Furthermore, the second hydrotreated effluent properties can be used for second hydrotreated effluents that have undergone separation processes to remove at least a portion of gaseous components such as molecular hydrogen and sulfur-containing compounds, such as hydrogen sulfide.

[0075] In some embodiments, the second hydrotreated effluent or a fraction thereof may be used as a diluent (e.g., a flux) for heavy hydrocarbons, especially those with relatively high viscosity. Optionally, all or part of the second hydrotreated effluent may replace more expensive conventional diluents. Non-limiting examples of blending feedstocks suitable for blending with the second hydrotreated effluent or a fraction thereof may include one or more of marine fuels, burner oils, heavy fuel oils (e.g., No. 5 and No. 6 fuel oils), high-sulfur fuel oils, low-sulfur fuel oils, conventional sulfur fuel oils, and gas oils, which may be obtained from the distillation of crude oil, crude oil components, and crude oil-derived hydrocarbons (e.g., coking gas oil). For example, the second hydrotreated effluent or a fraction thereof may be used as a blending component to produce fuel oil compositions that may include ≤0.5 wt% sulfur.

[0076] Now for reference Figure 1-4 The method / system for hydrocarbon upgrading is described in more detail. Figure 1 A diagram illustrating an illustrative method / system 101 according to one or more embodiments is shown for upgrading a hydrocarbon feed (including a Class I lubricating oil extract) obtained from a hydrocarbon feed source 1001 in line 1003. In some embodiments, the hydrocarbon feed (via line 1003), utility fluid (via line 1007, which may be obtained from one or more utility fluid sources 1005), and molecular hydrogen (via line 1009) may be introduced into a first hydrotreating stage 1011. As explained below, in some embodiments, the utility fluid source 1005 may be optional and therefore unnecessary, due to the recycling of intermediate distillate products (which are recovered from separation stage 1017 via lines 1019 and 1027). As shown, the hydrocarbon feed (via line 1003), utility fluid (via line 1007), and molecular hydrogen (via line 1009) may be introduced separately and mixed in the first hydrotreating stage 1011. However, in other embodiments, two of the following may be mixed before the introduction of the first hydrotreating stage 1011: hydrocarbon feed in line 1003 and utility fluid in line 1007 and / or middle distillate product in line 1027, or all three of the following may be mixed before the introduction of the first hydrotreating stage 1011: hydrocarbon feed in line 1003, molecular hydrogen in line 1009 and utility fluid in line 1007 and / or middle distillate product in line 1027.

[0077] The mixture of hydrocarbon feed, utility fluid, and molecular hydrogen can be heated and contacted with one or more catalysts 1013 in a first hydrotreating stage 1011 to produce a first hydrotreating effluent, which can be recovered via line 1015. The first hydrotreating effluent via line 1015 can be introduced into a separation stage 1017. In some embodiments, middle distillate products (via line 1019) and bottom products (via line 1021) can be recovered from the separation stage 1017. In other embodiments, the middle distillate products (via line 1019), bottom products (via line 1021), and top products (via line 1023, which may include molecular hydrogen) can be recovered from the separation stage 1017. In other embodiments, the middle distillate (via line 1019), bottom product (via line 1021), top product (via line 1023), and light distillate (via line 1025, which may include naphtha) can be recovered from the separation stage 1017.

[0078] In some embodiments, at least a portion of the middle distillate (in line 1019) may be recycled to the first hydrotreating stage 1011 via line 1027, for example, by mixing with the hydrocarbon feed in line 1003. In some embodiments, at least a portion of the middle distillate (in line 1019) may be removed from the method / system 101 via line 1029. As mentioned above, the utility fluid source 1005 may be optional and absent because the middle distillate (which may be recycled to the first hydrotreating stage 1011 via lines 1019 and 1027) may constitute all of the utility fluid, which may be combined with the hydrocarbon feed in line 1003, whether before and / or after introducing the hydrocarbon feed 1003 into the first hydrotreating stage 1011.

[0079] In some embodiments, at least a portion of the bottom product (via line 1021) and molecular hydrogen (via line 1031) may be introduced into a second hydrotreating stage 1033. The mixture of the bottom product and molecular hydrogen may be heated and contacted with one or more catalysts 1035 in the second hydrotreating stage 1033 to produce a second hydrotreating effluent (which may be recovered via line 1037).

[0080] In some embodiments, when the top product in line 1023 is recovered from separation stage 1017, at least a portion of the top product (via line 1023) may be introduced into one or more upgrading units 1039, such as one or more amine towers. For example, fresh amine (via line 1041) may be introduced into upgrading unit 1039, and rich amine (via line 1043) may be recovered therefrom. Regenerated process gas (which may be or may include molecular hydrogen, via line 1045) may also be recovered from upgrading unit 1039. In some embodiments, at least a portion of the regenerated process gas (in line 1045) may be recycled via lines 1047 and 1049 to the first hydrotreatment stage 1011 and / or via lines 1047 and 1051 to the second hydrotreatment stage 1033. In some embodiments, at least a portion of the regenerated process gas (in line 1045) may be removed from the method / system 101 via line 1053.

[0081] Figure 2A schematic diagram of another illustrative method / system 201 according to one or more embodiments is shown for a hydrocarbon feed (comprising a Class I lubricating oil extract) in a upgrading line 1003. In some embodiments, the hydrocarbon feed (via line 1003), molecular hydrogen (via line 1009), and utility fluid (via line 1007) and / or middle distillate products (via lines 1019 and 1027) may be introduced into a first hydrotreating stage 2000. In some embodiments, the molecular hydrogen in line 1009 may be obtained from a molecular hydrogen source 2002 and / or recycled from one or more upgrading units 1039 via lines 1045 and 1047, as referenced above. Figure 1 As stated above.

[0082] As shown, the first hydrotreatment stage 2000 may include one or more guard bed reactors 2001, one or more pre-processors 2007, and one or more main hydrotreatment reactors 2013. The guard bed reactor 2001 may include one or more catalysts 2003, the pre-processor 2007 may include one or more catalysts 2009, and the main hydrotreatment reactor 2013 may include one or more catalysts 2015. In some embodiments, the compositions of catalysts 2003, 2009, and 2015 may be the same or different from each other. In some embodiments, the guard bed reactor 2001, pre-processor 2007, and / or main hydrotreatment reactor 2013 may include one, two, three, or more different catalysts. For example, in some embodiments, one or more catalysts 2003 in the guard bed reactor 2001 may include a relatively low-reactivity hydrotreatment catalyst layer, a hydrodemetallization catalyst layer, and a relatively high-activity catalyst layer, such as catalysts containing Ni, Co, or combinations or mixtures thereof.

[0083] The effluent from the guard bed reactor (via line 2005) may be introduced into the pre-processor 2007. The pre-processor effluent (via line 2011) may be introduced into the main hydrotreating reactor 2013. The first hydrotreating effluent (via line 2017) may be recovered from the first hydrotreating stage 2000 and introduced into the separation stage 1017 and as referenced above. Figure 1 The further processing. As described above, in some embodiments, the first hydrotreating stage 2000 (which includes the guard bed reactor 2001, the pre-processor 2007 and the main hydrotreating reactor 2013) may be as discussed and described in WO Publications Nos. WO2018 / 111576A1 and WO2018 / 111577A1.

[0084] In some embodiments, at least a portion of the middle distillate product (in line 1019) may be recycled to the first hydrotreating stage 2000 via line 1027, for example, by mixing with the hydrocarbon feed (in line 1003). In some embodiments, at least a portion of the regenerated process gas (in line 1045) may be recycled to the guard bed reactor 2001 via line 1047, to the pre-processor 2007 via lines 1047 and 2019, and / or to the main hydrotreating reactor 2013 via lines 1047 and 2021.

[0085] Figure 3 A schematic diagram of an illustrative method / system 301 according to one or more embodiments is shown for upgrading steam cracker tar in line 3023 and hydrocarbon feed (which includes Class I lubricating oil extract) in line 1003. The steam cracker hydrocarbon feed, or simply "hydrocarbons" (via line 3001), can be heated in the convection section 3007 of steam cracker furnace 3005 to produce heated hydrocarbons via line 3009. The hydrocarbons in line 3001 can be combined with an aqueous fluid in line 3003 to produce a first mixture (which may include hydrocarbons and steam). Heating of the hydrocarbons in line 3001 can occur before, during, and / or after the combination of the hydrocarbons with the aqueous fluid. At least a portion of the heated hydrocarbons (via line 3009) can be introduced into the radiant section 3011 of steam cracker furnace 3005 and steam cracked therein to produce steam cracker effluent (via line 3013).

[0086] In some embodiments, the hydrocarbons in pipeline 3001 (which may be mixed, blended, combined, or otherwise contacted with and heated to produce a heated mixture with water, steam, or mixtures thereof) may include any one or more of a plurality of hydrocarbons. In other embodiments, the hydrocarbons may include one or more C 4- Hydrocarbons. In some embodiments, the hydrocarbons may include one or more C44 hydrocarbons. 5+ Hydrocarbons. In other embodiments, the hydrocarbons may include one or more C44 hydrocarbons. 4- Hydrocarbons and one or more C 5+ A mixture of hydrocarbons. Feed or hydrocarbons (including C24H2O) 4- Hydrocarbons may include one or more of the feedstocks that are gaseous at room temperature, such as ethane, propane, and / or butane. The feedstock or hydrocarbon (which includes C...) 5+Hydrocarbons (which can be mixed, blended, combined, or otherwise contacted with water and / or steam and heated to produce heated mixtures) may include, but are not limited to, crude crude oil, steam cracking gas oil and residues, gas oil, heating oil, jet fuel, diesel, kerosene, gasoline, coking naphtha, steam cracking naphtha, catalytic cracking naphtha, hydrocracking products, reforming products, frying residue reforming products, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasoline, distillates, straight-run naphtha, and other hydrocarbons. Bottom material from a die-tube still, feed stream from a vacuum tube still such as bottom material from a vacuum tube still and naphtha to gas oil condensate from a wide-boiling-range vacuum tube still, heavy non-straight-run hydrocarbons from a refinery, vacuum gas oil, heavy gas oil, naphtha contaminated with crude oil, atmospheric residue, heavy residue, C4 / residue mixture, naphtha / residue mixture, hydrocarbon gas / residue mixture, hydrogen / residue mixture, waxy residue, gas oil / residue mixture, or any mixture thereof.

[0087] In some embodiments, the heated mixture in line 3009 (which comprises the hydrocarbon and the aqueous fluid) may comprise from about 10 wt%, about 20 wt%, or about 30 wt% to about 70 wt%, about 80 wt%, about 90 wt%, or about 95 wt% of the aqueous fluid, based on the total weight of the hydrocarbon and the aqueous fluid. In some embodiments, the heated mixture in line 3009 may be at a temperature of 330°C, 340°C, 400°C, 405°C, 410°C, 425°C, or 450°C to 475°C, 500°C, 525°C, 550°C, 565°C, or 585°C.

[0088] The steam cracker effluent (via line 3013) may be introduced into the steam cracker primary fractionator 3015 and separated into multiple products, such as the top product via line 3017, the steam cracker gas oil (“SCGO”) side stream via line 3019, the steam cracker quench oil (“SCQO”) via line 3021, and the steam cracker tar (“SCT”) stream via line 3023. In some embodiments, illustrative primary fractionators may include those disclosed in U.S. Patent No. 8,083,931 and U.S. Patent Application Publication No. 2014 / 0357923. In some embodiments, the steam cracker effluent in line 3013 may be cooled via indirect heat exchange, direct heat exchange via contact with a quench medium, or a combination thereof, prior to introduction into the steam cracker primary fractionator 3015.

[0089] In some embodiments, at least a portion of the steam cracker tar in line 3023 may be combined with the utility fluid in line 1007 (obtained from utility fluid source 1005) and the hydrocarbon feed in line 1003 (obtained from hydrocarbon feed source 1001, which may include a type I lubricating oil extract) to produce a second mixture in line 3023 (which includes the steam cracker tar, utility fluid, and hydrocarbon feed). In other embodiments, the middle distillate product in line 1027 may be combined with the steam cracker tar and hydrocarbon feed to produce the second mixture in line 3023, as referenced above. Figure 1 and 2 In other embodiments, the steam cracker tar in line 3023 may be combined with the utility fluid in line 1007, the middle distillate product in line 1027, and the hydrocarbon feed in line 1003 to produce the second mixture. In some embodiments, the fluidized catalytic cracker main column bottom product in line 3031 (obtained from the fluidized catalytic cracker primary fractionator 3029) may also be combined with the steam cracker tar, the hydrocarbon feed, and at least one of the utility fluid and the middle distillate product to produce the second mixture.

[0090] In some embodiments, molecular hydrogen (via line 1009) and the second mixture (via line 3023, which includes at least one of the steam cracker tar, hydrocarbon feed, and the utility fluid and middle distillate products) may be introduced into the first hydrotreating stage 1011 to produce a first hydrotreating effluent (via line 1015), as referenced above. Figure 1 In other embodiments, molecular hydrogen (via line 1009) and the second mixture (via line 3023, which includes at least one of the steam cracker tar, hydrocarbon feed, and the utility fluid and middle distillate products) may be introduced into the first hydrotreating stage 2000 to produce a first hydrotreating effluent (via line 1015), as referenced above. Figure 2 As mentioned above.

[0091] The first hydrotreating effluent (via line 1015) may be introduced into separation stage 1017 to recover at least the middle fraction product (via line 1019) and bottom product (via line 1021) and optionally top product (via line 1023) and / or light fraction (via line 1025), as referenced above. Figure 1 and 2In some embodiments, at least a portion of the bottom product (via line 1021) and molecular hydrogen (via line 1031) may be fed into a second hydrotreating stage 1033 to produce a second hydrotreating effluent (via line 1037). In some embodiments, at least a portion of the middle distillate product (via lines 1019 and 1027) may be recycled as at least a portion of the utility fluid to the first hydrotreating stage 1011.

[0092] In some embodiments, the second hydrotreated effluent (via line 1037) may be introduced into separation stage 3041 to at least recover the top product (via line 3043, which may include molecular hydrogen) and the bottom product (via line 3045). As disclosed herein, the bottom product in line 3045 may also be referred to as the "second hydrotreated effluent" and may have the properties described above with reference to the second hydrotreated effluent. The top product in line 3043 comprises gaseous components, such as molecular hydrogen and sulfur-containing compounds such as hydrogen sulfide, and does not contribute to the properties of the second hydrotreated effluent as described herein. In other words, the second hydrotreated effluent as described herein refers to the product following at least the top product in separation line 3043, such that at least a portion of the sulfur-containing compounds present in the second hydrotreated effluent have been removed immediately upon exiting the second hydrotreated stage 1033. The top product via line 3043 may be introduced into one or more upgrading units 1039, such as one or more amine towers, to provide additional molecular hydrogen (via line 1045), which may be recycled via lines 1047 and 1049 to the first hydrotreating stage 1011 and / or via lines 1047 and 1051 to the second hydrotreating stage 1033.

[0093] It has been found that combining the hydrocarbon feed in line 1003 with the effluent from the steam cracker can significantly alter the hydrocarbon composition in line 3001. For example, if the steam cracker 3005 is designed to primarily process C... 5+ With hydrocarbon feed, the first hydrotreating stage 1011, separator 1017, and second hydrotreating stage 1033 are typically designed to operate with a certain amount of steam cracker tar processed therein. By combining the hydrocarbon feed in line 1003 with the steam cracker tar in line 3023, the hydrocarbon composition in line 3001 can be adjusted to provide feed flexibility, while the first hydrotreating stage 1011, separator 1017, and second hydrotreating stage 1033 can continue to operate as initially designed due to the increased volume introduced therein, which is due to the addition of the hydrocarbon feed in line 1003.

[0094] Figure 4A schematic diagram of another illustrative method / system 401 according to one or more embodiments is shown for upgrading steam cracker tar in lines 4029 and / or 4033 and hydrocarbon feed (which includes Class I lubricating oil extract) in line 1003. The steam cracker hydrocarbon feed, or simply "hydrocarbons," via line 4001 can be heated in the convection section 4007 of steam cracker furnace 4005 to produce heated hydrocarbons via line 4009. In some embodiments, the hydrocarbons in line 4001 may preferably include one or more of the C444 described above. 5+ Hydrocarbons. In some embodiments, at least a portion of the hydrocarbons in pipeline 4001 may include one or more C44 hydrocarbons. 4- hydrocarbon.

[0095] The hydrocarbons in line 4001 may be combined with an aqueous fluid in line 4003 to produce a first mixture (which may include hydrocarbons and vapor). Heating of the hydrocarbons in line 4001 may be performed before, during, and / or after the combination of the hydrocarbons with the aqueous fluid in line 4003. At least a portion of the heated hydrocarbons (via line 4009) may be introduced into separator 4011 (which may be referred to as a flash tank, separator) or other separator to produce a gaseous product (via line 4013) and a liquid product (via line 4015). In some embodiments, separator 4011 may be or include separators and / or other devices disclosed in U.S. Patent Nos. 7,138,047; 7,090,765; 7,097,758; 782,0035; 7,311,746; 7,220,887; 7,244,871; 7,247,765; 7,351,872; 7,297,833; 7,488,459; 7,312,371; 6,632,351; 7,578,929; and 7,235,705.

[0096] In some embodiments, the heated mixture (comprising hydrocarbons and an aqueous fluid) described in line 4009 may comprise about 10 wt%, about 20 wt%, or about 30 wt% to about 70 wt%, about 80 wt%, about 90 wt%, or about 95 wt% of the aqueous fluid, based on the total weight of the hydrocarbons and the aqueous fluid. In some embodiments, the temperature of the heated mixture in line 4009 may be 330°C, 340°C, 400°C, 405°C, 410°C, 425°C, or 450°C to 475°C, 500°C, 525°C, 550°C, 565°C, or 585°C. In some embodiments, the liquid phase products in line 4015 may include hydrocarbons with a minimum boiling point ≥350°C, such as 400°C, 425°C, 450°C, or 475°C to 500°C, 525°C, 550°C, or 570°C, as measured according to ASTM D6352-19e1 or ASTM D2887-22e1. Those skilled in the art will understand that if the indicated boiling point falls outside the range specified in one or more of these standards, it can be determined by extrapolation.

[0097] At least a portion of the gaseous products (via line 4013) may be introduced into the radiant section 4017 of the steam cracker furnace 4005 and steam-cracked therein to produce steam cracker effluent (via line 4019). This steam cracker effluent (via line 4019) may be introduced into the steam cracker primary fractionator 4021 and separated into multiple products, such as the top product via line 4023, steam cracker gas oil (“SCGO”) via line 4025, steam cracker quench oil (“SCQO”) via line 4027, and steam cracker tar (“SCT”) via line 4029. In some embodiments, the illustrative primary fractionator may include those disclosed in U.S. Patent No. 8,083,931 and U.S. Patent Application Publication No. 2014 / 0357923. In some embodiments, the steam cracker effluent in line 4019 can be cooled to produce cooled steam cracker effluent before being introduced into the primary fractionator 4021 of the steam cracker. In some embodiments, the steam cracker effluent in line 4019 can be cooled by direct contact with one or more quenching media and / or by indirect heat exchange with one or more quenching media.

[0098] In some embodiments, at least a portion of the steam cracker tar in line 4029 may be introduced into solids removal unit 4031 to produce lean-solids steam cracker tar (via line 4033) and solids-rich product (via line 4035). In some embodiments, solids removal unit 4031 may include one or more filters, one or more centrifuges, or a combination thereof. In some embodiments, a first amount of steam cracker tar in line 4029 may be introduced into solids removal unit 4031, and a second amount of steam cracker tar in line 4029 may bypass solids removal unit 4031 and may be combined with the lean-solids steam cracker tar in line 4033. It should be understood that solids removal unit 4031 is optional, as the composition of the steam cracker tar in line 4029 may vary at least in part based on the specific composition of the hydrocarbon feed in 4001.

[0099] In some embodiments, at least a portion of the steam cracker tar in line 4033 may be combined with a utility fluid in line 1007 (obtained from utility fluid source 1005) and a hydrocarbon feed in line 1003 (obtained from hydrocarbon feed source 1001, and which may include a type I lubricating oil extract) to produce a second mixture in line 4033 comprising the steam cracker tar, utility fluid, and hydrocarbon feed. In other embodiments, the middle distillate in line 1027 may be combined with the steam cracker tar and hydrocarbon feed to produce a second mixture in line 4033, as referenced above. Figure 1 and 2 In other embodiments, the steam cracker tar in line 4033 may be combined with the utility fluid in line 1007, the middle distillate in line 1027, and the hydrocarbon feed in line 1003 to produce a second mixture in line 4033. In other embodiments, the steam cracker tar in line 4033, the middle distillate in line 1027, and the hydrocarbon feed in line 1007 may be combined to produce a second mixture in line 4033. In other embodiments, molecular hydrogen via line 1009 and the second mixture via line 4033 (which includes the steam cracker tar, the hydrocarbon feed, and at least one of the utility fluid and the middle distillate) may be introduced into the first hydrotreating stage 2000 to produce a first hydrotreating effluent (via line 1015), as referenced above. Figure 2 As mentioned above.

[0100] In some embodiments, at least a portion of the liquid-phase product (via line 4015) may be introduced into a fluidized catalytic cracker 4041 to produce a fluidized catalytic cracker effluent (via line 4043). This fluidized catalytic cracker effluent (via line 4043) may be introduced into a fluidized catalytic cracker primary fractionator 4045 and separated into multiple products, such as C. 4- The top products (i.e., C1, C2, C3, and C4 hydrocarbons, and typically including H2S, via line 4047), naphtha (via line 4049), recycle oil (via line 4051), and fluidized bed catalytic cracker main column bottom products (via line 4053). The fluidized bed catalytic cracker 4041 may include additional devices typically used in such methods, such as separators like cyclone separators, for separating fluidized catalyst particles from the fluidized bed effluent. It should also be understood that the fluidized bed catalytic cracker 4041 may further include additional separators, such as catalyst feed separators, configured to remove entrained catalyst particles from the fluidized bed catalytic cracker main column bottom products or other products separated therefrom.

[0101] In some embodiments, at least a portion of the fluidized catalytic cracker main bottom product (via line 4053) may be combined with at least one of the following: steam cracker tar in line 4033, hydrocarbon feed in line 1003, utility fluid in line 1007, and middle distillate product in line 1027, to produce a second mixture in line 4033. The second mixture (via line 4033, comprising the steam cracker tar, hydrocarbon feed from line 1003, utility fluid from line 1007, and / or middle distillate product from line 1027), and optionally the fluidized catalytic cracker main bottom product from line 4053 and molecular hydrogen via line 1009, may be introduced into the first hydrotreating stage 1033 to produce a first hydrotreating effluent via line 1015. In other embodiments, the second mixture in line 4033 may include hydrocarbon feed in line 1003, fluidized catalytic cracker main bottom product in line 4053, and utility fluid in line 1007 and / or middle fraction in line 1027, and may not contain the steam cracker tar.

[0102] The first hydrotreating effluent via line 1015 can be introduced into separation stage 1017 to at least recover the middle fraction product (via line 1019) and bottom product (via line 1021) and optionally top product (via line 1023) and / or light fraction (via line 1025), as referenced above. Figure 1 and 2In some embodiments, at least a portion of the bottom product (via line 1021) and molecular hydrogen (via line 1031) may be fed into the second hydrotreating stage 1033 to produce a second hydrotreating effluent (via line 1037). In some embodiments, at least a portion of the middle fraction product (via lines 1019 and 1027) may be recycled as at least a portion of the utility fluid to the first hydrotreating stage 1011. In some embodiments, at least a portion of the top product in line 1023 may be introduced into the one or more upgrading units 1039, and molecular hydrogen (via lines 1047 and 1049 and / or via lines 1047 and 1051) may be recycled to the first hydrotreating stage 1011 and / or the second hydrotreating stage 1033, respectively.

[0103] In some embodiments, the second hydrotreating effluent (via line 1037) may be introduced into the separation stage 3041 to at least recover the top product (via line 3043, which may include molecular hydrogen) and the bottom product (via line 3045), as referenced above. Figure 3 The top product (via line 3043) may be introduced into one or more upgrading units 1039, such as one or more amine towers, to provide additional molecular hydrogen via line 1045, which may be recycled via lines 1047 and 1049 and / or via lines 1047 and 1051 to the first hydrotreating stage 1011 and / or the second hydrotreating stage 1033, respectively.

[0104] Example:

[0105] The preceding discussion can be further described with reference to the following non-limiting embodiments.

[0106] Example I

[0107] Three feed mixtures comprising middle distillate products and different Type I lubricating oil extracts were prepared. Each mixture comprised 60 wt% of a Type I lubricating oil extract and 40 wt% of a middle distillate product (MC). The Type I lubricating oil extracts were light neutral Type I lubricating oil extract (LN), heavy neutral Type I lubricating oil extract (HN), and bright oil Type I lubricating oil extract (BS). The Type I lubricating oil extracts, middle distillate products, and their mixtures (LN / MC, HN / MC, and BS / MC) had the properties shown in Table 1.

[0108]

[0109] At 0.8h -1 WHSV, 534Sm 3 / m3 Hydrogenation of each feed was performed using a CoMo / Al2O3 catalyst at a total pressure of 8.3 MPa (gauge pressure, 1200 psi). Sulfur conversion and hydrogen consumption were determined at 360 °C, 370 °C, 380 °C, 390 °C, and 400 °C. Table 2 shows the sulfur conversion for each mixture after hydrogenation.

[0110]

[0111] Table 3 shows the hydrogen consumption rate when each mixture is hydrogenated.

[0112]

[0113] As shown in Tables 2 and 3, sulfur conversion and hydrogen consumption increased with increasing hydrotreating temperature. Boiling point distributions of LN / MC, HN / MC, and BS / MC mixtures (feeds) were also measured after hydrotreating at 360°C, 370°C, 380°C, 390°C, and 400°C. The boiling point distributions of the LN / MC, HN / MC, and BS / MC mixtures after hydrotreating showed an increase of approximately 10% in the amount of middle distillate products in all three mixtures.

[0114] Example II

[0115] A mixture of the middle distillate, steam cracker tar, and another light neutral Type I lubricating oil extract used in Example I was hydrotreated. This mixture comprised 48 wt% of the steam cracker tar, 12 wt% of the LN Type I lubricating oil extract, and 40 wt% of the middle distillate. Before and after the hydrotreatment of the mixture of the middle distillate, steam cracker tar, and another light neutral Type I lubricating oil extract used in Example I, a 60 / 40 mixture of only the steam cracker tar and the middle distillate was also hydrotreated in the same hydrotreatment arrangement. Table 5 shows the properties of the LN Type I lubricating oil extract, steam cracker tar, middle distillate, and mixtures thereof.

[0116]

[0117] To identify the molecular class and boiling point distribution of the LN Type I lubricating oil extract and to detect potential fouling promoters, the boiling range was estimated by simulated distillation (“SimDis”) according to ASTM D2887-18, and two-dimensional gas chromatography (2D-GC) analysis was performed. The SimDis plot showed a narrower boiling point distribution of the LN Type I lubricating oil extract, spanning from 343°C to 538°C, compared to the steam cracker tar. The LN Type I lubricating oil extract is a lighter feed stream than the steam cracker tar and is therefore fed with a mixture comprising 60 wt% of the steam cracker tar and 40 wt% of the middle distillate products (1.030 g / cm³). 3 Compared to the above, the density of the mixed feed is slightly lower (1.016 g / cm³). 3 The 2D-GC data showed that the amount of saturated compounds (alkanes) present was approximately 9.12 wt%.

[0118] The mixture of the LN Class I lubricating oil extract, steam cracker tar, and middle distillate products was hydrotreated for one month under the following conditions. The hydrotreatment stage included a preheater that heated the mixture to 250°C, and then passed the heated mixture through a process at 260°C for 1.2 hours. -1 A guard bed process is performed under WHSV to produce guard bed effluent, which is then pre-processed at 362°C for 2.4 h. -1 The mixture is processed under WHSF to produce a pretreated mixture, which is then subjected to a primary hydrotreating reactor at 375-390°C for 0.8 h. -1 Processing under WHSV. Total hydrogen flow rate is 534 Sm. 3 / m 3 (3000 SCFB), based on LN Class I lubricating oil extract and steam cracker tar. Hydrogen pressure is 8274 kPa gauge pressure. The hydrogen content is distributed as follows: 25% is introduced into the guard bed reactor, 40% into the pre-processor, and 35% into the main hydrotreating reactor. The catalysts used in the guard bed reactor and pre-processor are sulfide catalysts comprising molybdenum oxide on alumina and nickel-molybdenum oxide, and the catalyst used in the main hydrotreating reactor is a sulfide catalyst comprising cobalt-molybdenum oxide on alumina.

[0119] It has been found that during the introduction of a mixture comprising the LN Class I lubricating oil extract, steam cracker tar, and middle distillate products, the hydrodesulfurization activity (sulfur conversion) and solubility blend number of the middle distillate products recovered from the hydrotreatment effluent remain consistent and are similar to those of a mixture comprising only the steam cracker tar and middle distillate products.

[0120] During a one-month run of the mixture comprising LN Class I lubricating oil extract, steam cracker tar, and middle distillate products, three middle distillate products were obtained, and the solubility blending number of each middle distillate product was tested. All three middle distillate products had a solubility value of 120 or greater.

[0121] During the hydrotreating process, the relative catalyst activity (RCA) was compared between the initial (feed from steam cracker tar and middle fraction only) and the intermediate (a mixture of LN Type I lubricating oil extract, steam cracker tar, and middle fraction products) phases to plot the catalyst deactivation trend with and without the LN Type I lubricating oil extract in the feed to the hydrotreating reactor. A shift in RCA was observed, but this shift was an artificial phenomenon resulting from changes in feed properties, and the decrease in relative activity remained almost constant, indicating that the LN Type I lubricating oil extract had no significant effect on the catalyst deactivation rate.

[0122] Different terms have been defined above. Where a term used in the claims does not fall under the scope defined above, it shall be given the broadest definition that has been given to a person skilled in the art, as reflected in at least one printed publication or authorized patent. Furthermore, all patents, patent application publications, test procedures, and other documents cited in this application are incorporated herein by reference to the extent that such disclosures are not contradictory to this application and are used within all jurisdictions in which such incorporation is permitted.

[0123] While the foregoing relates to embodiments of the present invention, other and further embodiments of the present invention may be devised without departing from the basic scope of the invention, the scope of which is defined by the appended claims.

Claims

1. A method for upgrading hydrocarbons, comprising: (I) Molecular hydrogen, utility fluid and hydrocarbon feed containing type I lubricating oil extract are fed into the first hydrotreating stage; (II) Hydrogenation is performed in the first hydrotreatment stage to produce a first hydrotreatment effluent; (III) Separate the middle fraction and bottom fraction from the first hydrotreating effluent; (IV) Feeding molecular hydrogen and at least a portion of the bottom product into a second hydrotreating stage; (V) Hydrotreating is performed in the second hydrotreating stage to produce a second hydrotreating effluent; as well as (VI) At least a portion of the intermediate distillate product is recycled back to the first hydrotreating stage as at least a portion of the utility fluid.

2. The method of claim 1, wherein the middle distillate comprises ≤0.5 wt% sulfur and 8.7 wt%-11 wt% hydrogen, and based on the total weight of the middle distillate, has an API specific gravity of 8°-14°, an SBN of 100-140, and a density of 0.871 g / cm³. 3 -1.065 g / cm 3 .

3. The method of claim 1 or claim 2, wherein the Type I lubricating oil extract comprises 3.5 wt%-6 wt% sulfur and 8 wt%-12 wt% hydrogen, and based on the total weight of the Type I lubricating oil extract, has an API specific gravity of 7.3°-10°, an SBN of 93-155, and a density of 0.905 g / cm³. 3 -1.113 g / cm 3 .

4. The method of any one of claims 1-3, wherein the hydrocarbon feed in step (I) further comprises steam cracker tar.

5. The method of claim 4, wherein the steam cracker tar comprises 3.3 wt%-5 wt% sulfur and 5.5 wt%-7.5 wt% hydrogen, and based on the total weight of the steam cracker tar, has an API specific gravity of -11° to -8°, an SBN of 180-250, and a density of 1.040 g / cm³. 3 -1.271 g / cm 3 .

6. The method of claim 4 or claim 5, further comprising: Provides particulate steam cracker tar containing solid particles; and At least a portion of the solid particles are removed from the particulate steam cracker tar to obtain the steam cracker tar.

7. The method of any one of claims 1-6, wherein the hydrocarbon feed in step (I) further comprises the bottom product of the fluidized catalytic cracker main column.

8. The method of claim 7, wherein the bottom product of the fluidized catalytic cracking main column comprises 1.5 wt%-5 wt% sulfur and 6.1 wt%-8.8 wt% hydrogen, and based on the total weight of the bottom product of the fluidized catalytic cracking main column, has an API specific gravity of -11° to 2.5°, an SBN of 180-250, and a density of 0.954 g / cm³. 3 -1.243 g / cm 3 .

9. The method of any one of claims 1-3, wherein the hydrocarbon feed in step (I) consists substantially of the Class I lubricating oil extract.

10. The method of any one of claims 1-8, wherein the hydrogenation treatment in step (V) is carried out at a temperature higher than that of the hydrogenation treatment in step (II).

11. The method of any one of claims 1-10, wherein the hydrogenation treatment in step (II) is carried out at a greater weight hourly space velocity than that in step (V).

12. The method of any one of claims 1-11, wherein step (III) further comprises separating a top product containing molecular hydrogen from the first hydrotreating effluent, and wherein at least a portion of the molecular hydrogen separated in step (III) is recycled to step (I), fed into the second hydrotreating stage in step (IV), or a combination thereof.

13. The method of any one of claims 1-12, wherein step (III) further comprises separating a light fraction containing naphtha from the first hydrotreated effluent.

14. The method of any one of claims 1-13, wherein the first hydrotreating stage comprises, in sequence, a guard bed reactor, a pre-processor downstream of the guard bed reactor, and a main first hydrotreating reactor downstream of the pre-processor.

15. A method for upgrading hydrocarbons, comprising: (I) Heating hydrocarbons in a steam cracking furnace and combining the hydrocarbons with an aqueous fluid to produce a first mixture comprising hydrocarbons and steam, wherein the heating is performed before, during and / or after the combination of the hydrocarbon feed and the aqueous fluid; (II) Steam cracking at least a portion of the first mixture to produce steam cracker effluent; (III) Separating steam cracker tar products and upgraded steam cracker effluent containing ethylene and propylene from the steam cracker effluent. (IV) Molecular hydrogen, at least a portion of the steam cracker tar products and hydrocarbon feed comprising type I lubricating oil extract are fed into the first hydrotreating stage. (V) Hydrogenation is performed in the first hydrotreatment stage to produce a first hydrotreatment effluent; (VI) Separate the middle fraction and bottom fraction from the first hydrotreating effluent; (VII) The molecular hydrogen and at least a portion of the bottom product are fed into the second hydrotreating stage; (VIII) Hydrotreating is performed in the second hydrotreating stage to produce a second hydrotreating effluent; as well as (IX) At least a portion of the intermediate distillate product is recycled back to the first hydrotreating stage as at least a portion of the utility fluid.

16. The method of claim 15, wherein the Type I lubricating oil extract comprises 3.5 wt%-6 wt% sulfur and 8 wt%-12 wt% hydrogen, based on the total weight of the Type I lubricating oil extract, and has an API specific gravity of 7.3°-10°, an SBN of 93-155, and a density of 0.905 g / cm³. 3 -1.113 g / cm 3 .

17. The method of claim 15 or claim 16, wherein the middle distillate comprises ≤0.5 wt% sulfur and 8.7 wt%-11 wt% hydrogen, and based on the total weight of the middle distillate, has an API specific gravity of 8°-14°, an SBN of 100-140, and a density of 0.871 g / cm³. 3 -1.065 g / cm 3 .

18. The method of any one of claims 15-17, wherein the steam cracker tar comprises 3.3 wt%-5 wt% sulfur and 5.5 wt%-7.5 wt% hydrogen, and based on the total weight of the steam cracker tar, has an API specific gravity of -11° to -8°, an SBN of 180-250, and a density of 1.040 g / cm³. 3 -1.271 g / cm 3 .

19. The method of any one of claims 15-18, wherein step (IV) further comprises feeding the bottom product of the fluidized catalytic cracker main column together with at least a portion of the steam cracker tar product, the utility fluid and the hydrocarbon feed into the first hydrotreating stage.

20. The method of claim 19, wherein the fluidized bed catalytic cracker bottom product comprises 1.5 wt%-5 wt% sulfur and 6.1 wt%-8.8 wt% hydrogen, and based on the total weight of the fluidized bed catalytic cracker bottom product, has an API specific gravity of -11° to 2.5°, an SBN of 180-250, and a density of 0.954 g / cm³. 3 -1.243 g / cm 3 .

21. The method of claim 19 or claim 20, further comprising: (I a Separate gaseous and liquid products from the first mixture, wherein at least a portion of the gaseous products are steam-cracked in step (II) to produce the steam cracker effluent; (X) Catalytic cracking at least a portion of the liquid phase products in a fluidized catalytic cracker to produce fluidized catalytic cracker effluent; as well as (XI) Separating the fluidized catalytic cracker main bottom product from the fluidized catalytic cracker effluent, wherein at least a portion of the separated fluidized catalytic cracker main bottom product is fed into the first hydrotreating stage in step (IV).

22. The method of any one of claims 15-21, wherein the hydrogenation treatment in step (VIII) is carried out at a temperature higher than that of the hydrogenation treatment in step (V).

23. The method of any one of claims 15-22, wherein the hydrogenation treatment in step (V) is carried out at a greater weight hourly space velocity than that of the hydrogenation treatment in step (VIII).

24. The method of any one of claims 15-23, wherein step (VI) further comprises separating a top product containing molecular hydrogen from the first hydrotreating effluent, and wherein at least a portion of the molecular hydrogen separated in step (VI) is recycled to step (IV), fed into the second hydrotreating stage in step (VII), or a combination thereof.

25. The method of any one of claims 15-24, further comprising (IV) a At least a portion of the steam cracker tar products are combined with the utility fluid and the hydrocarbon feed to produce a second mixture, wherein the second mixture is fed into the first hydrotreating stage.

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