Upgrading hydrocarbon liquids to ultra-low sulfur needle coke

Abstract

Various systems and methods are disclosed, in one embodiment, the present invention includes a method of needle coke manufacture. The process comprises hydrotreating a hydrocarbon liquid by contacting the hydrocarbon liquid with at least one hydrotreating catalyst in one or more hydrotreating stages to form a hydrotreated product, where hydrotreating of the hydrocarbon liquid in at least one of the one or more hydrotreating stages is performed in the presence of a utility fluid. The hydrocarbon liquid includes an initial boiling point at atmospheric pressure of about 200 DEG C or greater according to ASTM 7500. The hydrocarbon liquid contains an aromatic compound content of about 50% by weight or greater. The method further includes coking at least a portion of the hydrotreated product to form a coker effluent and coke, wherein the coke comprises needle coke.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of and priority to U.S. Provisional Application No. 63 / 341,232, filed on May 12, 2022, the disclosure of which is incorporated herein by reference. Technical Field

[0003] The present invention provides systems and methods for the production of needle coke, and more particularly, provides systems and methods for upgrading hydrocarbon liquids to ultra-low sulfur needle coke through a process that includes hydro-processing with a utility fluid followed by delayed coking. Background Art

[0004] Needle coke is a type of petroleum coke made in an oil refinery, where long-chain hydrocarbons are thermally cracked into shorter-chain molecules in a process commonly referred to as "coking" and the excess carbon is left in the form of petroleum coke. Needle coke is one of the most valuable products that can be made in an oil refinery and is used to make a variety of products, including electrodes for electric arc furnaces and negative electrodes for lithium batteries. Needle coke is typically made in a delayed coker from low-sulfur aromatic feedstocks within a specific boiling range, such as fluidized catalytic cracking decant oil, vacuum gas oil, atmospheric residue, and coal tar pitch. These feed streams produce high-quality needle coke because they contain aromatic molecules that are not easily cracked, which can be coked at higher pressures and longer durations to condense, align, and form a needle coke structure. In contrast, steam cracking tars and other hydrocarbon pyrolysis tars typically have high concentrations of highly reactive molecules and high sulfur content, making them unfavorable for making high-quality needle coke. Summary of the invention

[0005] An example method of needle coke production is disclosed herein. The method includes hydrotreating a hydrocarbon liquid by contacting the hydrocarbon liquid with at least one hydrotreating catalyst in one or more hydrotreating stages to form a hydrotreating product, wherein the hydrotreating of the hydrocarbon liquid in at least one of the one or more hydrotreating stages is conducted in the presence of a utility fluid, wherein the hydrocarbon liquid comprises an initial boiling point of about 200° C. or greater at atmospheric pressure according to ASTM 7500, and wherein the hydrocarbon liquid comprises an aromatics content of about 50 wt % or greater. The method also includes coking at least a portion of the hydrotreating product to form a coking effluent and coke, wherein the coke comprises needle coke.

[0006] Another exemplary method for needle coke production is disclosed herein. The method includes hydrotreating a feedstock containing steam cracking tar and a utility fluid by contacting the feedstock with at least one first-stage hydrotreating catalyst in the presence of molecular hydrogen in a first hydrotreating stage to produce a first-stage hydrotreating effluent, wherein the steam cracking tar has an initial boiling point of about 200°C or greater as determined by ASTM D7500, wherein the steam cracking tar contains about 50% by weight or greater of aromatic compounds having ≥15 carbon atoms, and wherein the solubility blending number of the utility fluid is about 100 or greater and contains about 25% by weight or greater of aromatic compounds. The method also includes separating at least a first-stage hydrotreating product from the first-stage hydrotreating effluent. The method also includes hydrotreating at least a portion of the first-stage hydrotreating product by contacting at least a portion of the first-stage hydrotreating product with at least one second-stage hydrotreating catalyst in the presence of additional molecular hydrogen in a second hydrotreating stage to produce a second-stage hydrotreating effluent. The method also includes separating at least a second stage hydroprocessing product from the second stage hydroprocessing effluent; wherein the second stage hydroprocessing product comprises a sulfur content of about 0.5 wt % or less and a BMCI of about 90 to about 160, wherein the second stage hydroprocessing product comprises an initial boiling point of 300° C. to 400° C. at atmospheric pressure and a final boiling point of 500° C. to 600° C. at atmospheric pressure as determined according to ASTM 7500. The method also includes coking at least a portion of the second stage hydroprocessing product to form at least a coked effluent and needle coke, wherein the needle coke comprises sulfur in an amount of 0.5 wt % or less.

[0007] These and other features and properties of the methods and systems disclosed in the present disclosure and their advantageous applications and / or uses will be apparent from the following detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] In order to assist one of ordinary skill in the relevant art in making and using the subject matter of the present invention, reference is made to the accompanying drawings, in which:

[0009] Figure 1 An example of a single reaction stage embodiment for upgrading hydrocarbon pyrolysis tar.

[0010] Figure 2 is an example for upgrading hydrocarbon pyrolysis tar in at least two reaction stages.

[0011] Figure 3 An example system includes hydroprocessing followed by delayed coking.

[0012] Figure 4 is an example of a laboratory scale batch coking reactor used in the production of needle coke for the examples disclosed herein. DETAILED DESCRIPTION

[0013] Disclosed herein is a method in which needle coke is produced using a hydrocarbon liquid. According to an embodiment of the present invention, the method for needle coke production includes: (i) hydrotreating a hydrocarbon liquid by contacting a hydrocarbon pyrolysis tar with at least one hydrotreating catalyst in one or more hydrotreating stages to form a hydrotreating product; (ii) coking at least a portion of the hydrotreating product to form a coking effluent and coke, wherein the coke contains needle coke. The hydrotreating used in accordance with an embodiment of the present invention is a hydrocarbon conversion process known as solvent-assisted tar conversion ("SATC"), in which the hydrocarbon pyrolysis tar is hydrotreated in the presence of a utility fluid in at least one of the one or more hydrotreating stages. Suitable hydrocarbon liquids include: heavy hydrocarbon liquids such as hydrocarbon pyrolysis tar, atmospheric residue, vacuum residue, slurry oil, and other heavy hydrocarbon streams with a high aromatic content.

[0014] Hydrocarbon pyrolysis tar is a high boiling point, viscous hydrocarbon liquid produced by the following process: in the pyrolysis process such as steam cracking that converts saturated hydrocarbons into higher value products such as light olefins such as ethylene and propylene. Hydrocarbon pyrolysis tar generally includes complex cyclic and branched molecules and high molecular weight non-volatile components, and the non-volatile components include paraffin-insoluble compounds such as pentane-insoluble compounds and heptane-insoluble compounds, including asphaltenes. Therefore, hydrocarbon pyrolysis tar generally contains too many macrocyclic compounds and insufficient amounts of three-ring aromatic compounds and four-ring aromatic compounds, which generally cause the production of needle coke. In addition, hydrocarbon tar contains molecules with a large number of side chains, which are typical coking feeds for needle coke production, and the side chains break and produce multiple reactive sites for molecular growth value-added, resulting in unsatisfactory coke quality. In addition to these compounds, hydrocarbon pyrolysis tar also includes a high sulfur content, for example up to 5% by weight, resulting in low manufacturing quality of high sulfur needle coke.

[0015] The SATC process is a hydrotreating technology that can solve the fouling problem caused by raw materials such as hydrocarbon pyrolysis tar. Therefore, the exemplary embodiment includes hydrotreating hydrocarbon pyrolysis tar in the SATC process, such as contacting hydrocarbon pyrolysis tar with at least one hydrotreating catalyst in one or more hydrotreating stages to form a hydrotreating product, wherein the hydrotreating in at least one stage in one or more hydrotreating stages is carried out in the presence of a utility fluid. SATC is a more "gentle" hydrotreating process (e.g., lower pressure and temperature) than violent hydrotreating (hydrotreating) (e.g., 20700kPA), which can convert hydrocarbon pyrolysis tar into a low-sulfur hydrotreating product while minimizing aromatic saturation, thereby retaining more aromatic rings for coke formation. For example, the hydrotreating product includes sulfur in an amount of ≤1.5 wt%, ≤1 wt% or less, ≤0.5 wt%, ≤0.4 wt% or ≤0.1 wt%. Therefore, the sulfur of the needle coke manufactured by the coking of the hydrotreating product is also low. In addition, needle coke is made from a feed having a high concentration of three-ring aromatics and four-ring aromatics and a lower concentration of five-ring aromatics and larger ring aromatics. For example, by increasing the concentration of three-ring aromatics and four-ring aromatics in the hydroprocessed product of the SATC process to ≥70 wt. %, while reducing the concentration of compounds with five or more aromatic rings, the coking of the hydroprocessed product advantageously produces needle coke rather than a coke product of lower value. BMCI refers to the Bureau of Mines Correlation Index. BMCI is a number related to the aromaticity of the feedstock. Coking feedstocks with BMCI ≥ 90 can produce the desired needle coke. Advantageously, according to one or more embodiments, the SATC process produces a hydroprocessed product with BMCI ≥ 90.

[0016] Hydrocarbon Liquid

[0017] According to an embodiment of the present invention, the hydrocarbon liquid pyrolysis tar is upgraded in the SATC process to provide a hydroprocessing product with improved delayed coking performance. Non-limiting examples of suitable hydrocarbon liquids include: heavy hydrocarbon liquids such as hydrocarbon pyrolysis tar, atmospheric residue, vacuum residue, slurry oil, and other heavy hydrocarbon streams with high aromatic content. The initial boiling point of the example hydrocarbon liquid is ≥200 ° C. As used herein, the initial boiling point and final boiling point are determined according to ASTM D7500. Based on the weight of the hydrocarbon liquid, the aromatic content of the example hydrocarbon liquid is ≥50 weight %, ≥75 weight %, ≥90 weight %, ≥95 weight %. In some embodiments, two or more hydrocarbon liquids are processed in the SATC process.

[0018] In some embodiments, hydrocarbon pyrolysis tar is upgraded in a SATC process to provide a hydroprocessed product with improved delayed coking properties. The hydrocarbon pyrolysis tar comprises aromatic compounds. In some embodiments, the hydrocarbon pyrolysis tar comprises aromatic compounds having ≥15 carbon atoms in an amount of ≥50 wt%, ≥75 wt%, or ≥90 wt%, based on the weight of the hydrocarbon pyrolysis tar. The metal content of the hydrocarbon pyrolysis tar is generally less than the metal content of crude oil of the same viscosity, for example, the metal content in the hydrocarbon pyrolysis tar is ≤1.0×10 3 ppmw, which is much lower than the amount of metals found in crude oil (or crude oil components) of the same average viscosity.

[0019] In some embodiments, the hydrocarbon pyrolysis tar has an insolubility number ("IN") of ≥ 80. For example, the hydrocarbon pyrolysis tar may have IN ≥ 85, IN ≥ 90, IN ≥ 100, IN ≥ 110, IN ≥ 120, IN ≥ 130, or IN ≥ 135. As used herein, the insolubility number or IN is determined according to ASTM D7112.

[0020] In addition, the solubility blending number ("SBN") of the hydrocarbon pyrolysis tar can be as low as SBN ≥ 130, but is typically SBN ≥ 140, SBN ≥ 145, SBN ≥ 150, SBN ≥ 160, SBN ≥ 170, SBN ≥ 175, or even SBN ≥ 180. In some embodiments, the hydrocarbon pyrolysis tar can be a tar with SBN ≥ 200 or SBN ≥ 200. In other embodiments, the SBN of the hydrocarbon pyrolysis tar is as high as 240. As used herein, the solubility blending number or SBN is determined according to ASTM D7112. Using this test method, the SBN of pentane is 25, the SBN of toluene is 100, and the SBN of quinoline is 200.

[0021] In addition, exemplary embodiments of hydrocarbon pyrolysis tars include C 7 In some embodiments, the hydrocarbon pyrolysis tar contains C in an amount of ≤50 wt%, such as ≤15 wt%, ≤25 wt%, ≤30 wt%, ≤45 wt%. 7 Therefore, the hydrocarbon pyrolysis tar contains, for example, 15 wt % to 50 wt %, or 30 wt % to 50 wt % of C 7 Insoluble matter.

[0022] In a particular embodiment, the hydrocarbon pyrolysis tar has an IN of 110 to 135, an SBN of 180 to 240, and a C 7 The insoluble matter content is 30 to 50 wt %.

[0023] As previously mentioned, hydrocarbon pyrolysis tar is not generally used for the manufacture of needle coke. Hydrocarbon pyrolysis tar generally contains too many highly reactive molecules and too much sulfur, making hydrocarbon pyrolysis tar unfavorable for the manufacture of high-quality coke. For example, hydrocarbon pyrolysis tar contains sulfur in an amount of up to 5 wt % or greater. In some embodiments, hydrocarbon pyrolysis tar contains sulfur in an amount ranging from about 1 wt % to about 7 wt %, or from about 2 wt % to about 4.5 wt %.

[0024] In addition to sulfur, hydrocarbon pyrolysis tar also contains high molecular weight non-volatile components, which include paraffin insoluble compounds such as pentane insoluble compounds and heptane insoluble compounds, including asphaltenes, which can cause undesirable fouling during coking. In some embodiments, hydrocarbon pyrolysis tar contains> 0.5% by weight, sometimes> 1% by weight, or even> 2% by weight of toluene insoluble compounds. High molecular weight compounds are usually polycyclic structures, also known as tar heavies ("TH"). As used herein, the term tar heavies refers to the product of hydrocarbon pyrolysis, with a boiling point of> 565°C at atmospheric pressure and containing molecules with multiple aromatic cores> 5% by weight based on the weight of the product. Tar heavies are generally solid at 25°C and generally include hydrocarbon pyrolysis tar fractions that are insoluble in 5: 1 (volume: volume) ratios of normal pentane: hydrocarbon pyrolysis tar at 25.0°C.

[0025] Hydrocarbon pyrolysis tar is produced by pyrolysis processes such as steam cracking for converting saturated hydrocarbons into higher value products such as light olefins like ethylene and propylene. In addition to these useful products, hydrocarbon pyrolysis can also produce a large amount of relatively low value heavy products such as hydrocarbon pyrolysis tar.

[0026] The pyrolysis process for producing hydrocarbon pyrolysis tar includes, for example, exposing a hydrocarbon-containing feed to pyrolysis conditions to produce a pyrolysis effluent, which is a mixture comprising unreacted feed, unsaturated hydrocarbons produced from the feed during pyrolysis, and pyrolysis tar. For example, a pyrolysis feed comprising ≥10 wt% hydrocarbons based on the weight of the pyrolysis feed undergoes pyrolysis to produce a pyrolysis effluent, which typically contains hydrocarbon pyrolysis tar and ≥1 wt% C pyrolysis tar based on the weight of the pyrolysis effluent. 2 Unsaturated substances. Pyrolysis tar generally contains ≥90 wt% of the pyrolysis effluent molecules with a normal pressure boiling point of ≥290°C. Therefore, in some embodiments, at least a portion of the hydrocarbon pyrolysis tar is separated from the pyrolysis effluent to produce a feedstock for the systems and methods described herein, wherein the feedstock contains ≥90 wt% of the pyrolysis effluent molecules with a normal pressure boiling point of ≥290°C. In addition to hydrocarbons, the pyrolysis feedstock optionally also contains a diluent, such as one or more of nitrogen, water, etc. For example, the pyrolysis feedstock may also contain ≥1 wt% of the diluent, such as ≥25 wt%, based on the weight of the pyrolysis feedstock. When the diluent contains a considerable amount of steam, the pyrolysis is referred to as steam cracking.

[0027] Example embodiments include hydrocarbon pyrolysis tar, the hydrocarbon pyrolysis tar comprising one or more of steam cracking tar (cracked tar), coal pyrolysis tar and biomass pyrolysis tar. "Steam cracking tar" refers to hydrocarbon pyrolysis tar obtained from steam cracking, also known as steam cracking tar (cracker tar). "Biomass pyrolysis tar" refers to hydrocarbon pyrolysis tar obtained from thermal cracking of biomass. "Coal pyrolysis tar" refers to hydrocarbon pyrolysis tar obtained from thermal cracking of coal-derived hydrocarbons. Alternatively, hydrocarbon pyrolysis tar can be obtained, for example, from a steam cracking gas oil ("SCGO") stream and / or a bottom stream of a steam cracker main fractionator, from a flash tank bottom (e.g., the bottom of one or more flash tanks located downstream of a pyrolysis furnace and upstream of a main fractionator) or a combination thereof. For example, hydrocarbon pyrolysis tar can be a mixture of a main fractionator bottom and a tar separation tank bottom.

[0028] In some embodiments, hydrocarbon pyrolysis tar is provided in the pyrolysis effluent. For example, the pyrolysis effluent comprises hydrocarbon pyrolysis tar (e.g., steam cracking tar) in an amount of ≥90 wt%, ≥95 wt%, or ≥99 wt% based on the weight of the pyrolysis effluent, and the balance of the pyrolysis effluent is, for example, particulate matter.

[0029] In some embodiments, the hydrocarbon pyrolysis tar is a steam cracking tar ("SCT") having, for example, the following characteristics: (i) a sulfur content in the range of 0.5 wt % to 7 wt % based on the weight of the SCT; (ii) a tar heavies content in the range of 5 wt % to 40 wt % based on the weight of the SCT; (iii) a density at 15° C. (measured according to ASTM D4052) of 1.01 g / cm 3 Up to 1.15g / cm 3 In the range of 1.07 g / cm 3 Up to 1.20g / cm 3 and (iv) 50 ° C viscosity (measured according to ASTM D7042) in the range of 200 cSt to 1.0 × 10 7 cSt. The amount of olefin in the SCT is typically ≤10 wt%, such as ≤5 wt%, such as ≤2 wt%, based on the weight of the SCT. For example, the amount of (i) vinyl aromatic compound in the SCT and / or (ii) aggregate in the SCT incorporated into the vinyl aromatic compound is typically ≤5 wt%, ≤3 wt%, or ≤2 wt%, based on the weight of the SCT.

[0030] Utility Fluid

[0031] According to an embodiment of the present invention, hydrocarbon pyrolysis tar is hydrotreated in the presence of a utility fluid. The utility fluid is used in one or more stages of the hydrotreatment. The utility fluid can be a defined solvent or can include a defined solvent, but is typically a recycled solvent taken from a different process. The utility fluid can be all or part of the product of the process of the present invention, such as a middle fraction of the final or intermediate product that is recycled back to the initial feed.

[0032] Typically, the utility fluid will contain aromatic hydrocarbons and ASTM D86 10% distillation point> 60 ° C and 90% distillation point < 425 ° C. According to an embodiment of the present invention, the utility fluid generally comprises a mixture of polycyclic compounds. The ring is aromatic or non-aromatic and can contain a variety of substituents and / or heteroatoms. For example, the utility fluid comprises aromatic and non-aromatic compounds in an amount of ≥40 wt %, ≥45 wt %, ≥50 wt %, ≥55 wt %, or ≥60 wt % based on the weight of the utility fluid. In some embodiments, the utility fluid comprises aromatic compounds in an amount of ≥25 wt %, ≥40 wt %, ≥50 wt %, ≥55 wt %, or ≥60 wt % based on the weight of the utility fluid.

[0033] In particular embodiments, the utility fluid comprises one ring aromatics, two ring aromatics, and three ring aromatics. In some embodiments, the utility fluid comprises 2 ring aromatics and / or 3 ring aromatics in an amount of ≥25 wt%, ≥40 wt%, ≥50 wt%, ≥55 wt%, or ≥60 wt% based on the weight of the utility fluid. 2 ring aromatics and 3 ring aromatics can be used in particular embodiments due to their higher SBN. Where a defined solvent is included in the utility fluid or used alone, the defined solvent comprises 1 ring aromatics and 2 ring aromatics.

[0034] The utility fluid may have a true boiling point distribution, for example, an initial boiling point of ≥177°C and a final boiling point of ≤566°C. In some embodiments, the utility fluid has a true boiling point distribution with an initial boiling point of ≥177°C and a final boiling point of ≤430°C. The true boiling point distribution ("TBP", distribution at atmospheric pressure) is determined according to ASTM D7500. When the final boiling point is greater than the boiling point specified in the standard, the true boiling point distribution can be determined by extrapolation.

[0035] Typically, an increase in the non-aromatic content of a utility fluid with a relatively low initial boiling point, e.g., ≥10 wt. % of a utility fluid with an atmospheric boiling point <175°C, can result in incompatibility with hydrocarbon pyrolysis tars and asphaltene precipitation. Thus, according to an embodiment of the present invention, the true initial boiling point of the utility fluid is ≥177°C. Similarly, because higher SBN molecules are generally required to avoid interactions with high I NThe incompatibility of tar and higher boiling molecules have higher SBN, so according to an embodiment of the present invention, the true final boiling point of the utility fluid is ≤566° C. Optionally, the true final boiling point of the utility fluid is >430° C. Such utility fluids have more than conventional aromatic content, for example, 2-ring aromatics and 3-ring aromatics in an amount of ≥25 wt % based on the weight of the utility fluid.

[0036] As previously described, the hydrocarbon pyrolysis tar is hydrotreated in the presence of a utility fluid in one or more stages of the hydrotreatment. In some embodiments, based on the total weight of the utility fluid and the hydrocarbon pyrolysis tar, an amount of utility fluid of 5% to 80% by weight based on the total weight of the utility fluid plus the hydrocarbon pyrolysis tar is used during the hydrotreatment, while an amount of hydrocarbon pyrolysis tar of 20% to 95% by weight based on the total weight of the utility fluid plus the hydrocarbon pyrolysis tar is used. For example, the relative amounts of the utility fluid and the tar stream during the hydrotreatment include an amount of hydrocarbon pyrolysis tar of 20% to 90% by weight and an amount of utility fluid of 10% to 80% by weight. As another example, the relative amounts of the utility fluid and the tar stream during the hydrotreatment include an amount of hydrocarbon pyrolysis tar of 40% to 90% by weight and an amount of utility fluid of 10% to 60% by weight. In some embodiments, the utility fluid: hydrocarbon pyrolysis tar weight ratio is ≥ 0.01, such as in the range of 0.05 to 4, such as in the range of 0.1 to 3 or 0.3 to 1.1. At least a portion of the utility fluid can be combined with at least a portion of the hydrocarbon pyrolysis tar in the hydroprocessing vessel or hydroprocessing stage, but this is not necessary. In one or more embodiments, at least a portion of the utility fluid and at least a portion of the hydrocarbon pyrolysis tar are supplied as separate streams and combined into one feed stream before entering (one or more) hydroprocessing stages (e.g., upstream). For example, the tar stream and the utility fluid can be combined upstream of the hydroprocessing stage to produce a feedstock containing, for example, hydrocarbon pyrolysis tar in an amount of 20 wt% to 90 wt% and utility fluid in an amount of 10 wt% to 80 wt%, or hydrocarbon pyrolysis tar in an amount of 40 wt% to 90% and utility fluid in an amount of 10 wt% to 60 wt%, the weight percentages being based on the weight of the feedstock.

[0037] The compatibility of the utility fluid and the hydrocarbon pyrolysis tar is based on the comparison of the SBN of the mixture of the utility fluid and the hydrocarbon pyrolysis tar with the IN of the hydrocarbon pyrolysis tar. In some embodiments, the SBN of the utility fluid is ≥100, ≥110, ≥120, ≥130, ≥140, ≥150, or ≥160. In some embodiments, the SBN of the combined pyrolysis tar and the utility fluid is ≥110. Thus, it has been found that when the hydroprocessing incompatibility number (I N)>80, there is a beneficial reduction in reactor plugging if the combined utility fluid and hydrotreated pyrolysis tar mixture has an SBN of ≥110, ≥120, or ≥130. In addition, it has been found that when the hydroprocessing incompatibility number (I N )>110, there is a beneficial reduction in reactor plugging if the SBN of the combined utility fluid and tar mixture is high, e.g., ≥150, ≥155, or ≥160.

[0038] In some embodiments, the utility fluid can be obtained as a middle distillate stream separated from, for example, the first hydroprocessing product from the first hydroprocessing stage. Therefore, the exemplary embodiments of the process provided herein include separating the first hydroprocessing product into an overhead stream, an intermediate distillate stream, and a bottom stream at one or more separation stages. For example, the first hydroprocessing product (e.g., in a flash tank) can be separated into a vapor portion and a liquid portion, and then the liquid portion (e.g., in a distillation tower) can be separated into an overhead stream, an intermediate distillate stream, and a bottom stream.

[0039] The SBN of the middle distillate stream is affected by the hydroprocessing conditions. For example, as the conditions (for example, higher pressure, lower WHSV) are adjusted in order to improve product quality, the middle distillate stream can become further hydrogenated, which can reduce the SBN of the middle distillate stream. When blended with hydrocarbon pyrolysis tar, the reduced SBN of the middle distillate stream can cause problems, because the lower SBN can make the middle distillate stream incompatible with hydrocarbon pyrolysis tar, which can cause fouling and plugging of the reactor. However, the process of at least two hydroprocessing stages of separating the middle distillate stream from the first hydroprocessing stage as described herein can produce a middle distillate stream with a certain composition and boiling range, so that the middle distillate stream can be used as a utility fluid in a variety of hydrocarbon conversion processes such as hydroprocessing. In some embodiments, the SBN of the middle distillate stream is ≥100, ≥110, ≥120, ≥130, ≥140, ≥150 or ≥160.

[0040] Thus, according to some embodiments, at least a portion of the middle distillate stream is recycled as an interstage hydroprocessing product (i.e., interstage recycle) for use as a utility fluid in the first hydroprocessing stage. For example, ≥20 wt%, ≥30 wt%, ≥40 wt%, ≥50 wt%, ≥60 wt%, ≥70 wt%, or ≥80 wt% of the middle distillate stream is recycled for use as a utility fluid in the first hydroprocessing stage.

[0041] In some embodiments, the supplemental utility fluid is at specific operating conditions, such as when starting the process (until sufficient utility fluid is available from the first hydroprocessed product as an intermediate distillate stream), or when operating at a higher reactor pressure. Thus, a supplemental utility fluid, such as a solvent, a solvent mixture, steam cracked naphtha (SCN), steam cracked gas oil (SCGO), or a fluid containing aromatic compounds (i.e., containing molecules having at least one aromatic core) can be optionally added to, for example, start the process. In some embodiments, the supplemental utility fluid contains ≥50 wt%, ≥75 wt%, or ≥90 wt% aromatic compounds and / or non-aromatic compounds based on the weight of the supplemental utility fluid. The ASTM D86 10% distillation point of the supplemental utility fluid can be ≥60°C and the 90% distillation point can be ≤350°C. Optionally, the supplemental utility fluid (which may be a solvent or mixture of solvents) has an ASTM D86 10% distillation point of ≥ 120°C, ≥ 140°C, or ≥ 150°C and / or an ASTM D86 90% distillation point of ≤ 300°C.

[0042] Optionally, the supplemental utility fluid comprises one or more of benzene, ethylbenzene, trimethylbenzene, xylene, toluene, naphthalene, alkylnaphthalene (e.g., methylnaphthalene), tetralin, or alkyltetralin (e.g., methyltetralin) at ≥90 wt %, such as ≥95 wt %, such as ≥99 wt %, based on the weight of the utility fluid. It is generally desirable that the supplemental utility fluid be substantially free of molecules having alkenyl functional groups, particularly in the context of utilizing hydroprocessing catalysts that have a tendency to form coke in the presence of such molecules. In particular aspects, the supplemental utility fluid comprises ≤10 wt %, based on the weight of the utility fluid, of C-containing alkenyl functional groups. 1 -C 6 A suitable supplemental utility fluid is A200 solvent, available as Aromatic 200 from ExxonMobil Chemical Company (Houston, Texas), CAS No. 64742-94-5.

[0043] SATC Process

[0044] The system and method include hydrotreating a hydrocarbon liquid (e.g., hydrocarbon pyrolysis tar) by contacting the hydrocarbon pyrolysis tar with at least one hydrotreating catalyst in the presence of a treatment gas comprising hydrogen in one or more hydrotreating stages to form a hydrotreating product. Hydrotreating is referred to as a solvent assisted tar conversion ("SATC") process because at least one of the one or more hydrotreating stages includes hydrotreating the hydrocarbon pyrolysis tar in the presence of a utility fluid. The feedstock includes hydrocarbon pyrolysis tar, such as hydrocarbon pyrolysis tar of ≥10 wt % based on the weight of the feedstock, and may include>15 wt %,>20 wt %,>30 wt %, or up to about 50 wt % hydrocarbon pyrolysis tar.

[0045] Hydroprocessing is carried out under hydroprocessing conditions, for example, under conditions for carrying out one or more of hydrocracking (including selective hydrocracking), hydrogenation, hydrofining, hydrodesulfurization, hydrodenitrogenation, hydrodemetallization, hydrodearomatization, hydroisomerization or hydrodewaxing. Hydroprocessing is carried out in at least one reaction stage in series. In some embodiments, hydroprocessing is carried out in at least one reaction stage in series. The two reaction stages are usually located in two reactors, but can also be arranged in two parts of a single reactor as long as the middle fraction is separated and removed between the first stage and the second stage.

[0046] In a multi-stage embodiment, in the first hydroprocessing stage, the feedstock is contacted with at least one hydroprocessing catalyst under catalytic hydroprocessing conditions in the presence of a utility fluid and molecular hydrogen to carry out hydroprocessing, so as to convert at least a portion of the feedstock into a first hydroprocessing product. An intermediate distillate stream is separated from the first hydroprocessing product. In some embodiments, the intermediate distillate stream comprises ≥ about 20% by weight of the first hydroprocessing product, and the boiling point distribution measured according to ASTM D7500 is about 120°C to about 480°C. In some embodiments, the intermediate distillate is recycled as a utility fluid in the first hydroprocessing stage. In some embodiments, the bottom stream is also separated from the first hydroprocessing product. The bottom stream comprises, for example, ≥ about 20% by weight of the first hydroprocessing product. In the second hydroprocessing stage, at least a portion of the bottom stream is hydroprocessed by contacting the bottom stream with at least one hydroprocessing catalyst under catalytic hydroprocessing conditions in the presence of molecular hydrogen to convert at least a portion of the bottom stream into a second hydroprocessing product.

[0047] The SATC process is capable of producing a hydroprocessed product (SATC product) having the desired properties for needle coke manufacturing. In a multi-stage embodiment, the hydroprocessed product is a second hydroprocessed product. For example, the sulfur of the hydroprocessed product is low, and the concentration of three-ring aromatic compounds and four-ring aromatic compounds increases. In some embodiments, the sulfur content of the hydroprocessed product is ≤1.5 weight %, ≤1 weight %, ≤0.5 weight %, ≤0.4 weight %, ≤0.1 weight % or less based on the weight of the hydroprocessed product. In some embodiments, the content of three-ring aromatic compounds and four-ring aromatic compounds of the hydroprocessed product increases. Examples of hydroprocessed products include three-ring aromatic compounds and four-ring aromatic compounds of a combined amount of ≥50 weight %, ≥60 weight % or ≥70 weight % based on the weight of the hydroprocessed product. Another indicator for measuring aromaticity is BMCI. In some embodiments, the BMCI of the hydroprocessed product is ≥90, ≥100, ≥110, ≥120, eg, from 90 to 160, or from 120 to 160.

[0048] The ash content of the hydroprocessed product can also be low, for example, the ash content is ≤0.5 wt%, ≤0.3 wt% or less, ≤0.1 wt% or less based on the weight of the hydroprocessed product. In some examples, the hydroprocessed product also has an initial boiling point of 200°C to 400°C at atmospheric pressure and a final boiling point of 500°C to 700°C at atmospheric pressure. For example, the initial boiling point of the hydroprocessed product can be 250°C to 375°C or 275°C to 375°C. As another example, the final boiling point of the hydroprocessed product can be 525°C to 675°C or 525°C to 600°C. The example hydroprocessed product also has a product viscosity of ≤30 cSt at 50°C, a product viscosity of ≤20 cSt at 50°C, or a product viscosity of ≤15 cSt at 50°C, and a density of ≤1.00 g / cm 3 .

[0049] In any configuration of the process, the hydroprocessing conditions may include, for example, a temperature of 200°C to 450°C. In some embodiments, independently or in combination with any particular configuration of catalysts in different hydroprocessing stages, the temperature in the first hydroprocessing stage may be in the range of about 200°C to 450°C or about 200°C to 425°C, and the temperature in the second hydroprocessing stage may be in the range of about 300°C to 450°C or about 350°C to 425°C, or vice versa. In some embodiments, the temperature in the first hydroprocessing stage may be higher than the temperature in the second hydroprocessing stage, or vice versa. Alternatively, the temperature in the first hydroprocessing stage and the second hydroprocessing stage may be the same.

[0050] In any configuration of the process, the hydroprocessing conditions may include, for example, pressures of 4100 kPa to 14000 kPa, 4100 kPa to 13000 kPa, 5500 kPa to 11000 kPa, 7000 kPa to 9650 kPa, 7000 kPa to 8200 kPa, 7500 kPa to 11000 kPa, 7500 kPa to 8950 kPa. In some embodiments, a pressure of 7000 kPa to 8950 kPa is used in the process, such as predominantly using hydrofinishing in the first stage, followed by a hydrocracking process. In some embodiments, the catalyst promoting the hydrofinishing reaction comprises Ni and the pressure may be >14000 kPa.

[0051] Any of a variety of suitable hydroprocessing catalysts can be used in the SATC process described herein to hydrotreat raw materials (e.g., pyrolysis tar). Suitable hydroprocessing catalysts include catalysts comprising (i) one or more bulk metals and / or (ii) one or more metals on a carrier. Metals can be in elemental form or compound form. In one or more embodiments, the hydroprocessing catalyst comprises at least one metal from any group in the 5th to 10th group of the periodic table (Table is the periodic table, The Merck Index, Merck & Co., Inc., 1996). Examples of such catalytic metals 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.

[0052] In one or more embodiments, the total amount of the 5th family to the 10th family metal per gram of catalyst in the catalyst is at least 0.0001 gram, or at least 0.001 gram, or at least 0.01 gram, wherein grams are calculated on an elemental basis. For example, the catalyst can include the total amount of the 5th family to the 10th family metal in the range of 0.0001 gram to 0.6 gram, or 0.001 gram to 0.3 gram, or 0.005 gram to 0.1 gram, or 0.01 gram to 0.08 gram. In a particular embodiment, the catalyst also includes at least one 15th family element. The preferred example of the 15th family element is phosphorus. When using the 15th family element, the catalyst can include the total amount of the 15th family element in the range of 0.000001 gram to 0.1 gram, or 0.00001 gram to 0.06 gram, or 0.00005 gram to 0.03 gram, or 0.0001 gram to 0.001 gram, wherein grams are calculated on an elemental basis.

[0053] In one embodiment, the catalyst comprises at least one Group 6 metal. Preferred examples of Group 6 metals include chromium, molybdenum and tungsten. The total amount of Group 6 metal that can be contained in the catalyst per gram of catalyst is ≥0.00001 grams, or ≥0.01 grams, or ≥0.02 grams, where grams are calculated on an elemental basis. For example, the total amount of Group 6 metal that can be contained in the catalyst per gram of catalyst is in the range of 0.0001 grams to 0.6 grams, or 0.001 grams to 0.3 grams, or 0.005 grams to 0.1 grams, or 0.01 grams to 0.08 grams, where grams are calculated on an elemental basis.

[0054] In a related embodiment, the catalyst comprises at least one Group 6 metal and further comprises at least one metal from Group 5, Group 7, Group 8, Group 9, or Group 10. Such catalysts may contain, for example, a combination of metals in a molar ratio of Group 6 metal to Group 5 metal in the range of 0.1 to 20, 1 to 10, or 2 to 5, wherein the ratio is on an elemental basis. Alternatively, the catalyst may contain a combination of metals in a molar ratio of Group 6 metal to the total amount of Group 7 to Group 10 metals in the range of 0.1 to 20, 1 to 10, or 2 to 5, wherein the ratio is on an elemental basis.

[0055] When the catalyst comprises at least one Group 6 metal and one or more metals from Group 9 or Group 10, such as molybdenum-cobalt and / or tungsten-nickel, these metals can be present, for example, in a molar ratio of the metal of Group 6 to the metal of Group 9 and Group 10 in the range of 1 to 10, or 2 to 5, wherein the ratio is based on the element. When the catalyst comprises at least one Group 5 metal and at least one Group 10 metal, these metals can be present, for example, in a molar ratio of the metal of Group 5 to the metal of Group 10 in the range of 1 to 10, or 2 to 5, wherein the ratio is based on the element. In addition, the catalyst can also comprise an inorganic oxide, for example as a binder and / or carrier. For example, the catalyst can comprise (i) ≥1 wt % of one or more metals selected from Group 6, Group 8, Group 9 and Group 10 of the Periodic Table of Elements and (ii) ≥1 wt % of an inorganic oxide, the weight percentage being based on the weight of the catalyst.

[0056] In one or more embodiments, the catalyst (e.g., in the first hydroprocessing stage and / or the second hydroprocessing stage) is a bulk multimetallic hydroprocessing catalyst with or without a binder. In one embodiment, the catalyst is a bulk trimetallic catalyst comprising two Group 8 metals, preferably Ni and Co, and one Group 6 metal, preferably Mo.

[0057] Example embodiments also include introducing one or more catalytic metals, such as one or more metals of the 5th to 10th and / or 15th families, into a carrier (or depositing on a carrier) to form a hydroprocessing catalyst. The carrier can be a porous material. For example, the carrier can include one or more refractory oxides, porous carbon materials, zeolites, or combinations thereof. Suitable refractory oxides include, for example, aluminum oxide, silicon dioxide, silicon dioxide-alumina, titanium oxide, zirconium oxide, magnesium oxide, and mixtures thereof. Suitable porous carbon materials include activated carbon and / or porous graphite. Examples of zeolites include, for example, Y zeolite, beta zeolite, mordenite, ZSM-5 zeolite, and ferrierite. Other examples of carrier materials include gamma alumina, theta alumina, delta alumina, alpha alumina, or combinations thereof. The amount of gamma alumina, delta alumina, alpha alumina or a combination thereof per gram of catalyst support as determined by X-ray diffraction may be in the range of 0.0001 gram to 0.99 gram, or 0.001 gram to 0.5 gram, or 0.01 gram to 0.1 gram, or at most 0.1 gram. In a particular embodiment, the hydroprocessing catalyst (e.g., in the first hydroprocessing stage and / or the second hydroprocessing stage) is a supported catalyst, and the support contains at least one alumina, such as theta alumina, in an amount in the range of 0.1 gram to 0.99 gram, or 0.5 gram to 0.9 gram, or 0.6 gram to 0.8 gram, the amount being the amount per gram of support. The amount of alumina may be determined using, for example, X-ray diffraction. In alternative embodiments, the support may contain ≥0.1 gram, or ≥0.3 gram, or ≥0.5 gram, or ≥0.8 gram of theta alumina.

[0058] When a carrier is used, the carrier can be impregnated with the desired metal to form a hydroprocessing catalyst. Before being impregnated with the metal, the carrier can be heat treated at a temperature in the range of 400°C to 1200°C, or 450°C to 1000°C, or 600°C to 900°C. In a particular embodiment, the hydroprocessing catalyst can be formed by adding or introducing a shaped heat-treated carrier mixture to a 5th to 10th group metal. This type of formation is generally referred to as superimposing a metal on the top of a carrier material. Optionally, after the carrier is combined with one or more catalytic metals, the catalyst is heat treated, for example, at a temperature in the range of 150°C to 750°C, or 200°C to 740°C, or 400°C to 730°C. Optionally, the catalyst is heat treated in the presence of hot wind and / or oxygen-enriched air at a temperature in the range of 400°C to 1000°C to remove volatile substances so that at least a portion of the 5th to 10th group metals are converted into their corresponding metal oxides. In other embodiments, the catalyst may be heat treated in the presence of oxygen (e.g., air) at a temperature in the range of 35°C to 500°C, or 100°C to 400°C, or 150°C to 300°C. The heat treatment may be performed for a period of time in the range of 1 hour to 3 hours to remove most of the volatile components without converting the Group 5 to Group 10 metals to their metal oxide forms. Catalysts prepared by such methods are generally referred to as "uncalcined" catalysts or "dried" catalysts. Such catalysts may be prepared in combination with a sulfidation process, wherein the Group 5 to Group 10 metals are substantially dispersed in the carrier. When the catalyst comprises a theta alumina carrier and one or more Group 5 to Group 10 metals, the catalyst is typically heat treated at a temperature of ≥400°C to form a hydroprocessing catalyst. Typically, such heat treatment is performed at a temperature of ≤1200°C.

[0059] In one or more embodiments, the hydroprocessing catalyst generally comprises a transition metal sulfide dispersed on a high surface area support. The structure of a typical hydrofinishing catalyst is made of 3 wt % to 15 wt % oxide of a Group 6 metal and 2 wt % to 8 wt % oxide of a Group 8 metal, and these catalysts are generally sulfided before use.

[0060] Catalyst can be shaped form, such as one or more in disk, pill, extrudate etc., but this is not inevitable.The limiting examples of such shaped form include the form with diameter in the cylindrical symmetry in the range of 0.79mm to 3.2mm, 1.3mm to 2.5mm or 1.3mm to 1.6mm.Non-cylindrical shapes of similar size are also considered herein, such as trilobal, quadrilobal etc.Optionally, the flat plate compressive strength of catalyst is in the range of 50N / cm to 500N / cm, or 60N / cm to 400N / cm, or 100N / cm to 350N / cm, or 200N / cm to 300N / cm, or 220N / cm to 280N / cm.

[0061] In one or more embodiments, porous catalysts are used, including those having conventional pore characteristics. When a porous catalyst is used, the catalyst can have a pore structure, pore size, pore volume, pore shape, pore surface area, etc. within the characteristic range of conventional hydroprocessing catalysts, but the invention is not limited thereto. Because the feedstock (e.g., pyrolysis tar) can contain relatively large molecules, catalysts with large pore sizes are preferred, especially at the reactor location where the catalyst and feed first meet. For example, the catalyst can have a median pore size that is effective for hydroprocessing SCT molecules, and the median pore size of such a catalyst is between 100 and 1000 Å. to or to or to In addition, a catalyst having a bimodal pore system is more advantageous, wherein the catalyst has to and having a hole in the carrier to The pore size can be determined according to ASTM method D4284-07 mercury porosimetry.

[0062] In a particular embodiment, the median pore diameter of the hydroprocessing catalyst (e.g., in the first hydroprocessing stage and / or the second hydroprocessing stage) is in the range of to Alternatively, the median pore size of the hydroprocessing catalyst is in the range of to or to or to In another embodiment, the median pore size of the hydroprocessing catalyst is in the range of to Alternatively, the median pore size of the hydroprocessing catalyst is in the range of to or to In yet another alternative, a hydroprocessing catalyst having a larger median pore size is used, for example, a median pore size of to or to or to Those hydroprocessing catalysts within the range of.

[0063] Typically, the hydroprocessing catalyst has a pore size distribution that is not so large as to significantly reduce the activity or selectivity of the catalyst. For example, the hydroprocessing catalyst may have a pore size distribution in which at least 60% of the pores have a pore size of or In certain embodiments, the median pore size of the catalyst is between to or to In the range of 200 μm, at least 60% of the pores have a diameter of or within the median pore diameter.

[0064] When a porous catalyst is used, the pore volume of the catalyst may be, for example, ≥ 0.3 cm 3 / g, for example ≥0.7cm 3 / g, or ≥0.9cm 3 In certain embodiments, the pore volume may range from, for example, 0.3 cm 3 / g to 0.99cm 3 / g, 0.4cm 3 / g to 0.8cm 3 / g, or 0.5cm 3 / g to 0.7cm 3 / g.

[0065] In certain embodiments, a relatively large surface area may be desired. For example, the surface area of ​​the hydroprocessing catalyst may be ≥ 60 m 2 / g, or ≥100m 2 / g, or ≥120m 2 / g, or ≥170m 2 / g, or ≥220m 2 / g, or ≥270m 2 / g; for example, at 100m 2 / g to 300m 2 / g, or 120m 2 / g to 270m 2 / g, or 130m 2 / g to 250m 2 / g, or 170m 2 / g to 220m 2 / g range.

[0066] Conventional hydroprocessing catalysts used in the hydroprocessing stage may be used, but the invention is not limited thereto. In a particular embodiment, the catalyst comprises one or more of: KF860 available from Albemarle Catalysts Company LP of Houston, Texas; Catalysts, such as 20; available from Criterion Catalysts and Technologies, Houston, Texas Catalysts such as one or more of DC-2618, DN-2630, DC-2635 and DN-3636; available from the same source Catalysts such as one or more of DC-2532, DC-2534 and DN-3531; and FCC pretreatment catalysts such as DN3651 and / or DN3551 which can be purchased from the same source. However, the present invention is not limited to these catalysts.

[0067] In a particular embodiment, the catalyst in the first hydroprocessing stage may be a catalyst comprising 2 O 3 and / or SiO 2 (ASA). An exemplary catalyst for use in the hydroprocessing stage is: Ni-Co-Mo / Al 2 O 3 Type catalyst, or Pt-Pd / Al 2 O 3 -SiO 2 、Ni-W / Al 2 O 3 、Ni-Mo / Al 2 O 3 , or Fe, Fe-Mo supported on non-acidic supports such as carbon black or carbon black composites, or Fe, Fe-Mo supported on non-acidic supports such as TiO 2 or Al 2 O 3 / TiO 2 On Mo, this hydroprocessing can be the first treatment applied to hydrocarbon pyrolysis tar.

[0068] In a particular embodiment, the catalyst in the second hydroprocessing stage may be a catalyst comprising primarily zeolite or one or more of Co, Mo, P, Ni, Pd supported on ASA and / or zeolite. Exemplary catalysts for use in the second hydroprocessing stage are USY or VUSY Zeolite Y, Co-Mo / Al 2 O 3 、Ni-Co-Mo / Al 2 O 3 , Pd / ASAZeolite Y. The catalyst used in each hydroprocessing stage can be independently selected from the catalyst used in any other hydroprocessing stage; for example, RT-228 catalyst can be used in the first hydroprocessing stage, and RT-621 catalyst can be used in the second hydroprocessing stage.

[0069] In some embodiments, if the S and N content of the feed is too high and a specific catalyst (e.g., zeolite) is used in the hydroprocessing stage, it is necessary to include a cheap and readily available catalyst such as Co-Mo / Al 2 O 3 The guard bed is then removed by H 2 S and NH 3 However, when a zeolite catalyst is used in the second reactor, a guard bed may not be necessary because the sulfur and nitrogen levels have already been reduced in the first reactor. 3 and H 2 The S separation step can still be applied to the product of the first hydroprocessing stage and to the product of the second hydroprocessing stage.

[0070] In another particular embodiment, the catalyst in the first hydroprocessing stage may be a catalyst comprising primarily zeolite or one or more of Co, Mo, P, Ni, Pd supported on ASA and / or zeolite, and the catalyst in the second hydroprocessing stage may be a catalyst comprising Co supported on amorphous Al. 2 O 3 and / or SiO 2 (ASA) catalyst. In such a configuration, exemplary catalysts used in the first hydroprocessing stage are USY or VUSY Zeolite Y, Co-Mo / Al 2 O 3 、Ni-Co-Mo / Al 2 O 3 , Pd / ASA Zeolite Y, and an exemplary catalyst for use in the second hydroprocessing stage is: Ni-Co-Mo / Al 2 O 3 Type catalyst, or Pt-Pd / Al2 O 3 -SiO 2 、Ni-W / Al 2 O 3 、Ni-Mo / Al 2 O 3 , or Fe, Fe-Mo supported on non-acidic supports such as carbon black or carbon black composites, or Fe, Fe-Mo supported on non-acidic supports such as TiO 2 or Al 2 O 3 / TiO 2 The catalyst used in each hydroprocessing stage can be independently selected from the catalyst used in any other hydroprocessing stage; for example, RT-621 catalyst can be used in the first hydroprocessing stage, and RT-228 catalyst can be used in the second hydroprocessing stage.

[0071] In another embodiment, the catalyst in the first hydroprocessing stage may be the same catalyst or perform a similar function as the catalyst in the second hydroprocessing stage.

[0072] Delayed coking

[0073] An exemplary embodiment includes feeding at least a portion of the hydroprocessed product to a delayed coking unit. After hydroprocessing, the sulfur concentration of the hydroprocessed product is low, such as 1.5 wt%, 1 wt%, 0.5 wt%, 0.1 wt% or less, and the level of the desired three-ring aromatic compound molecules and four-ring aromatic compound molecules for needle coke manufacturing is increased. In the delayed coking unit, the hydroprocessed product is treated by delayed coking to produce a coke effluent and coke in the form of liquid and vapor products. The delayed coking of the hydroprocessed product is carried out by partially converting the hydroprocessed product into more valuable hydrocarbon products. Depending on its grade, the resulting coke has value as a fuel (fuel-grade coke), an electrode for aluminum manufacturing (anode-grade coke), etc. According to an embodiment of the present invention, the coke comprises needle coke.

[0074] In some embodiments, the hydroprocessing product is co-fed with a conventional coking feed to a delayed coking unit. Examples of suitable conventional coking feeds include, but are not limited to, decant oil, vacuum gas oil, atmospheric residue, and coal tar pitch. Conventional coking feeds may be co-fed in any suitable ratio, including a ratio of hydroprocessing product to coking feed of about 5:95 to 95:5, 25:75 to 75:25, or 40:60 to 60:40.

[0075] In some embodiments, the hydroprocessed product is preheated and then directed to the coking zone. The hydroprocessed product is preheated to any temperature suitable for coking, such as a temperature of 480°C to 570°C. In some embodiments, preheating includes passing the hydroprocessed product through a furnace. In some embodiments, preheating includes pumping the hydroprocessed product to the bottom of a coker fractionator and then pumping it into the furnace. The preheated hydroprocessed product is transported from the furnace to the coking zone. In some embodiments, the coking zone includes a coking vessel, such as a vertically oriented isolated coker vessel, commonly referred to as a coking drum. For example, the preheated hydroprocessed product is transported from the furnace to the coking drum through an inlet at the bottom of the drum. According to an embodiment of the present invention, the coking zone (e.g., coking drum) operates under coking conditions. Example coking conditions in the coking zone include, for example, pressures in the range of 100kPa to 1200kPa, 100kPa to 550kPa, or 100kPa to 240kPa. Higher pressures may also be used. For example, the coking conditions in the coking zone can be as high as 1200 kPa to 8000 kPa. The typical operating temperature of the coking zone will be between 400 ° C and 550 ° C, 400 ° C and 475 ° C, or 450 ° C and 475 ° C. The preheated hydroprocessed product is thermally cracked in the coke for a period of time ("coking time"), releasing volatiles consisting mainly of hydrocarbon products, which continuously rise through the coke bed composed of channels, holes and passages and are collected at the top of the tower as coking effluent. For example, the coking time varies according to temperature and pressure. In some embodiments, the coking time is 5 hours to 48 hours, or 8 hours to 16 hours.

[0076] In some embodiments, the coking effluent is directed to a coker fractionator for distillation and recovery of fluid coking products, including coking gas, coking naphtha, coking distillate and coking gas oil. Typically, but not always, after upgrading, such fractions can be used in the blending of fuel and lubricant products such as motor gasoline, motor diesel, fuel oil and lubricating oil. Upgrading can include separation, removal of heteroatoms, dearomatization, solvent extraction, etc. via hydrofining and non-hydrofining processes. Coking gas includes, for example, a mixture of hydrocarbons including 1 carbon to 4 carbons and hydrocarbons and carbon dioxide. Coking gas oil includes, for example, light coking gas oil and heavy coking gas oil. In some embodiments, at least a portion of the heavy coking gas oil in the coking effluent introduced into the coker fractionator can be captured for recycling, and merged with the fresh feed of the hydroprocessing product to form the charge of the coking heater or the coker furnace. In some embodiments, there is no recycle, and in some embodiments, the recycle of heavy gas oil may be up to 200 vol% of the hydroprocessed product, for example, heavy gas oil is recycled in an amount of 5 vol% to 35 vol% of the hydroprocessed product.

[0077] In addition to volatile products, the process also results in the accumulation of coke in the coking zone (e.g., coking vessel). At periodic intervals, such as when a predetermined coke accumulation is obtained, the preheated hydrotreated product is switched to another coking vessel, and hydrocarbon vapors are purged from the coking vessel with steam. In some embodiments, the coking vessel is then quenched with water to reduce the temperature to below 150°C, such as to 95°C to 150°C, after which the water is drained. When the drainage step is completed, the tank is opened and the coke is removed ("hydraulic decoking"), such as by drilling and / or cutting using a high-speed water jet. As previously described, the coke produced in the delayed coking of the hydrotreated product includes needle coke.

[0078] Needle coke

[0079] Needle coke is manufactured by delaying the coking of the hydroprocessing product from the SATC process. For example, the coke product manufactured in delayed coking contains needle coke in an amount of about 20 wt%, 25 wt%, 35 wt%, 40 wt%, 50 wt%, 60 wt% or more. In some embodiments, the coke product contains needle coke in an amount of 25 wt% to 60 wt%. Needle coke is a type of coke formed in delayed coking, which has a needle-shaped, anisotropic microstructure. Under a microscope, a fibrous structure is observed in needle coke. Needle coke can be converted into graphite for use in electrodes by a graphitization process, which includes heating to a high temperature of more than 2000 ° C. Electrodes manufactured from needle coke are used in arc furnaces for melting steel and in the negative electrode of lithium batteries.

[0080] The particular composition of needle coke depends on many factors, including particular coking conditions, such as delayed coking conditions and feed composition. In some embodiments, needle coke comprises carbon in an amount of 80 wt % to 98 wt % (>90%) based on the total weight of the coke. Because the sulfur of the hydroprocessed product is low, the sulfur of the needle coke is also low. For example, needle coke comprises sulfur in an amount of ≤1.5 wt %, ≤1 wt % or less, ≤0.5 wt %, ≤0.4 wt %, or ≤0.1 wt %. In addition, needle coke should also have a low ash content. For example, the ash content of needle coke is about <0.4, <0.2, <0.1 or less.

[0081] Composition Example

[0082] Figure 1An exemplary single-stage hydroprocessing system 100 for hydroprocessing hydrocarbon pyrolysis tar is shown. In the illustrated embodiment, a tar feed 102 containing hydrocarbon pyrolysis tar to be processed (e.g., steam cracking tar) is blended with a recycle fluid 104 containing a utility fluid to form a feedstock 106. Although not shown, a supplemental utility fluid may be used in addition to the recycle fluid 104. The feedstock 106 is then pumped through a filter 110 by means of a pump 108. The filter 110 includes, for example, a guard bed and / or a H 2 S / NH 3 The process gas 112 containing molecular hydrogen is then added to the feedstock 106 to form a hydrogen-rich feedstock 114. This stream is referred to as "hydrogen-rich" because it is enriched with hydrogen after being combined with the process gas 112 and thus contains more hydrogen. Molecular hydrogen can be added to the feedstock 106 at any suitable rate, for example, to maintain a H pressure of 4820 kPa to 10350 kPa in the hydroprocessing reactor 120. 2 Pressure division.

[0083] The hydrogen-rich feedstock 114 then passes through a first heat exchanger 116 and then a second heat exchanger 118 to preheat the hydrogen-rich feedstock 114. The preheated hydrogen-rich feedstock 114 is then fed into a hydroprocessing reactor 120 containing a hydroprocessing catalyst. Figure 1The introduction of a hydrogen-rich feedstock 114 comprising hydrocarbon pyrolysis tar, utility fluid, and hydrogen in a combined stream is shown, but it should be understood that embodiments include the introduction of one or more of these components separately into the hydroprocessing reactor 120. For example, at least a portion of the process gas 112 can be introduced into the hydroprocessing reactor 120 for intermediate cooling. The single-stage hydroprocessing system 100 is considered to have a single hydroprocessing stage because it only includes one hydroprocessing reactor 120. As described above, the hydroprocessing reactor 120 can be operated under any suitable hydroprocessing conditions. In the hydroprocessing reactor 120, the hydrocarbon pyrolysis tar is hydroprocessed by contacting with at least one hydroprocessing catalyst in the presence of a utility fluid and hydrogen to form a hydroprocessed product. The hydroprocessing effluent 122 comprising the hydroprocessed product is directed from the hydroprocessing reactor 120 to a separator 124 (e.g., a distillation column) through a first heat exchanger 116. In separator 124, hydroprocessed product 123 is separated from hydroprocessed effluent 122, with recycle stream 104 being recycled for mixing with tar feed 102. Although not shown, additional separators (e.g., flash drums) may be used, for example, to remove hydrogen from hydroprocessed effluent 122. Advantageously, hydroprocessed product 123 has desirable characteristics, such as higher concentrations of three-ring aromatic molecules and four-ring aromatic molecules and low sulfur, and can be coked to form needle coke with less fouling and a higher yield of needle coke than coking of unhydroprocessed hydrocarbon pyrolysis tar.

[0084] Figure 2 An example of a multi-stage hydroprocessing system 200 is shown. In the illustrated embodiment, a tar feed 202 containing hydrocarbon pyrolysis tar to be treated (e.g., steam cracking tar) is blended with a recycle stream 204 containing a utility fluid to form a feedstock 206. The feedstock 206 is provided to a first hydroprocessing reactor 208 containing a hydroprocessing catalyst. The feedstock 206 stream may optionally be first heated in a first heat exchanger 210. A treatment gas 212 containing molecular hydrogen is then added to the feedstock 206 to form a hydrogen-rich feedstock 214. This stream is referred to as "hydrogen-rich" because it is already enriched in hydrogen and thus contains more hydrogen after being combined with the treatment gas 212. Molecular hydrogen can be added to the feedstock 206 at any suitable ratio, such as to maintain a H of 4820 kPa to 10350 kPa in the first hydroprocessing reactor 208. 2 The hydrogen-rich feedstock 214 then passes through a second heat exchanger 216 and then a feed heater 218 to preheat the hydrogen-rich feedstock 214. The preheated hydrogen-rich feedstock 214 is then fed into the first hydroprocessing reactor 208 containing a hydroprocessing catalyst. Figure 2The introduction of a hydrogen-rich feedstock 214 comprising hydrocarbon pyrolysis tar, utility fluid, and hydrogen in a combined stream is shown, but it should be understood that embodiments include introducing one or more of these components separately into the first hydroprocessing reactor 208. For example, at least a portion of the process gas 212 can be introduced into the first hydroprocessing reactor 208 for intermediate cooling. As described above, the first hydroprocessing reactor 208 can be operated under any suitable hydroprocessing conditions. In the first hydroprocessing reactor 208, the hydrocarbon pyrolysis tar is hydroprocessed by contacting with at least one hydroprocessing catalyst in the presence of a utility fluid and hydrogen to form a first hydroprocessing product. The first stage hydroprocessing effluent 222 comprising the first hydroprocessing product is directed from the first hydroprocessing reactor 208 through the second heat exchanger 216.

[0085] The first stage hydroprocessing effluent 222 is cooled in the second heat exchanger 216 (e.g., by cross exchange with the hydrogen-rich feedstock 214). After cooling, the first stage hydroprocessing effluent 222 is directed to the first separator 224 for separating the first stage vapor product 226 (e.g., heteroatom vapor, vapor phase cracking products, unused process gas, etc.) and the first stage liquid effluent 228 from the first stage hydroprocessing effluent 222. In one embodiment, the first separator 224 is a flash tank. The first stage vapor product 226 is optionally directed to the amine column 230 (e.g., H 2 S scrubber) to produce a gas that is essentially free of H 2 A fresh amine 234 (e.g., monoethanolamine, methyldiethanolamine, diethanolamine, etc.) is provided to the amine column 230, and the H 2 S-rich amine 236 is directed away from amine column 230. At least a portion of upgraded treat gas stream 232 is optionally directed away from amine column 230, compressed in compressor 238, and reused during the first stage and / or second stage hydroprocessing, such as treat gas 212. For example, if desired, gas, such as molecular hydrogen for start-up of the process or for make-up, may be obtained from feed treat gas stream 240 and mixed with treat gas 212. In some embodiments, a light gas purge stream 242 is removed from upgraded treat gas stream 232 as desired.

[0086] In the illustrated embodiment, the first stage liquid effluent 228 containing the first hydroprocessing product is provided to a second separator 244 (e.g., a distillation column) to separate the first stage liquid effluent 228 into an overhead stream 246, an intermediate distillate stream 248, and a bottom stream 250. The overhead stream 246 contains, for example, 1% to 20% by weight of the first hydroprocessing product. The intermediate distillate stream 248 contains, for example, 20% to 70% by weight of the first hydroprocessing product. The bottom stream 250 contains 10% to 60% by weight of the first hydroprocessing product. According to an embodiment of the present invention, the intermediate distillate stream 248 is recycled as a recycle fluid 204, thereby being used as a utility fluid in the first stage and / or being taken away as a separate intermediate distillate product stream 252.

[0087] As shown, bottoms stream 250 is pumped to the second stage via pump 251 where it is combined with a second stage treat gas stream 254, e.g., from treat gas 212, and heated in a fourth heat exchanger 256 before being fed to a second hydroprocessing reactor 258 containing one or more hydroprocessing catalysts. The catalysts used in the first hydroprocessing reactor 208 and the second hydroprocessing reactor 258 may be the same or different. Although Figure 2 The bottoms stream 250 comprising at least a portion of the hydroprocessed product and hydrogen is shown introduced in a combined stream, but it should be understood that embodiments include introducing one or more of these components separately into the second hydroprocessing reactor 258. For example, at least a portion of the second stage treated gas stream 254 can be introduced into the second hydroprocessing reactor 258 for intermediate cooling. As described above, the second hydroprocessing reactor 258 can be operated under any suitable hydroprocessing conditions. In the second hydroprocessing reactor 258, at least a portion of the hydroprocessed product is hydroprocessed by contacting with at least one hydroprocessing catalyst in the presence of hydrogen to form a second hydroprocessed product.

[0088] The second stage hydroprocessing effluent 259 containing the second hydroprocessing product is directed from the second hydroprocessing reactor 258 to the third separator 260 for separating the vapor stream 262 (e.g., heteroatom vapor, gas phase cracking product, unused processing gas, etc.) and the second stage liquid effluent 264 (e.g., the second hydroprocessing product) from the second stage hydroprocessing effluent 259. In one embodiment, the third separator 260 is a flash tank. The vapor stream 262 is optionally cooled in the fifth heat exchanger 266 and then optionally transported to the fourth separator 268 for further separation for separating the second stage vapor product stream 270 and the additional liquid product stream 271. The second stage vapor product stream 270 can be optionally directed to the amine tower 230 and optionally combined with the first stage vapor product 226.

[0089] The second stage liquid effluent 264 and the additional liquid product stream 271 are then provided to a fifth separator 272 (e.g., a distillation column) where a second stage product overhead stream 274 and a second stage liquid product stream 276 are separated. The second stage liquid product stream 276 comprises at least a portion of the second hydroprocessed product. Advantageously, the second hydroprocessed product has desirable characteristics, such as higher concentrations of three-ring reactive molecules and four-ring reactive molecules and low sulfur, so that it can be coked to form needle coke with less fouling and higher needle coke yields compared to coking of unhydrotreated hydrocarbon pyrolysis tars.

[0090] Figure 3 An example system 300 for making needle coke is shown. In the illustrated embodiment, a tar feed 301 containing hydrocarbon pyrolysis tar (e.g., steam cracking tar) to be treated is fed into a hydroprocessing stage 302. In the hydroprocessing stage, the hydrocarbon pyrolysis tar is contacted with at least one hydroprocessing catalyst in one or more hydroprocessing stages to form a hydroprocessing product. In at least one stage in the one or more hydroprocessing stages, the hydrocarbon pyrolysis tar is contacted with at least one hydroprocessing catalyst in the presence of a utility fluid. The liquid product stream 304 containing the hydroprocessing product is then conveyed to a delayed coking stage 306. In the delayed coking stage 306, for example, the hydroprocessing product is preheated and then coked. In some embodiments, preheating the hydroprocessing product includes introducing the hydroprocessing product into a coker fractionator 308, and then extracting a fractionator effluent 310 containing at least a portion of the hydroprocessing product from the coker fractionator 308 to a coker furnace 312. The preheated effluent 314 comprising the preheated hydroprocessed product is conveyed from the coker furnace 312 to a coking zone 316, which includes, for example, a coking vessel or coking drum. The preheated effluent 314 also includes a bottom (or recycle). The coking zone 316 is operated under coking conditions such that the preheated hydroprocessed product is thermally cracked in the coking zone over a period of time ("coking time"), releasing volatiles comprising primarily hydrocarbon products, which continuously rise through the coke bed consisting of channels, holes, and passages and are collected at the top of the tower as a coking effluent 318, which is conveyed to the coker fractionator 308. In the illustrated embodiment, the coking effluent 318 is separated into a plurality of fractions in the coker fractionator 308, including, but not limited to, a coking gas fraction 322, a coking naphtha fraction 324, a coking distillate fraction 326, and a coking gas oil fraction 328. As previously described, coke accumulates in a coking zone 316 (eg, a coking vessel). The coke includes needle coke. A coke product 320 comprising needle coke is removed from the coking zone 316.

[0091] Additional embodiments

[0092] Therefore, the present invention is provided for the production of needle coke from hydrocarbon liquids. The method and system include any of the various features disclosed herein, including one or more of the following statements.

[0093] Embodiment 1. A method for producing needle coke, the method comprising: hydrotreating a hydrocarbon liquid by contacting the hydrocarbon liquid with at least one hydrotreating catalyst in one or more hydrotreating stages to form a hydrotreating product, wherein the hydrotreating of the hydrocarbon liquid in at least one of the one or more hydrotreating stages is carried out in the presence of a utility fluid, wherein the hydrocarbon liquid comprises an initial boiling point of about 200° C. or greater at atmospheric pressure according to ASTM 7500, wherein the hydrocarbon liquid comprises an aromatics content of about 50 wt % or greater; and coking at least a portion of the hydrotreating product to form a coking effluent and coke, wherein the coke comprises needle coke.

[0094] Embodiment 2. A method according to embodiment 1, wherein the hydrocarbon liquid comprises hydrocarbon pyrolysis tar.

[0095] Embodiment 3. A method according to Embodiment 1 or Embodiment 2, wherein the hydrocarbon liquid comprises hydrocarbon pyrolysis tar having an initial boiling point of about 200° C. or greater as measured according to ASTM D7500, and wherein the hydrocarbon pyrolysis tar comprises about 50 wt % or greater of aromatic compounds having ≥15 carbon atoms.

[0096] Embodiment 4. A method according to any of the preceding embodiments, wherein the hydrocarbon liquid comprises steam cracking tar.

[0097] Embodiment 5. The method of any of the preceding embodiments, wherein the hydrocarbon liquid comprises sulfur in an amount of about 3 wt % to about 4.5 wt %, and wherein the needle coke comprises sulfur in an amount of about 0.5 wt % or less.

[0098] Embodiment 6. The method according to any of the preceding embodiments, wherein the sulfur content of the hydroprocessed product is about 0.5 wt% or less.

[0099] Embodiment 7. The method of any of the preceding embodiments, wherein the hydroprocessed product comprises about 70 wt% or greater combined amounts of three-ring aromatics and four-ring aromatics.

[0100] Embodiment 8. A method according to any of the preceding embodiments, wherein the hydroprocessed product comprises an initial boiling point of 200°C to 400°C at atmospheric pressure and a final boiling point of 500°C to 700°C at atmospheric pressure as determined according to ASTM 7500, and wherein the BMCI of the hydroprocessed product is about 90 to about 160.

[0101] Embodiment 9. The method according to any of the preceding embodiments, wherein the utility fluid comprises at least a portion of an interstage hydroprocessing product that is recycled for combination with the hydrocarbon liquid.

[0102] Embodiment 10. The method of any of the preceding embodiments, wherein the utility fluid has a solubility blending number of about 100 or greater.

[0103] Embodiment 11. The method of any of the preceding embodiments, wherein the utility fluid comprises aromatic compounds in an amount of about 25 wt % or greater.

[0104] Embodiment 12. The method of any of the preceding embodiments, wherein the needle coke comprises sulfur in an amount of about 0.5 wt% or less.

[0105] Embodiment 13. The method of any of the preceding embodiments, wherein the needle coke comprises sulfur in an amount of about 0.1 wt % or less.

[0106] Embodiment 14. The method of any of the preceding embodiments, wherein the coke product comprises the needle coke in an amount from about 25 wt.% to about 60 wt.%.

[0107] Embodiment 15. A method according to any of the preceding embodiments, wherein the hydroprocessing includes: hydroprocessing the hydrocarbon liquid in the presence of the utility fluid in a first hydroprocessing stage to produce a first stage hydroprocessing effluent; separating at least a first stage hydroprocessing product from the first stage hydroprocessing effluent; and hydroprocessing at least a portion of the first stage hydroprocessing product in a second hydroprocessing stage to produce a second stage hydroprocessing effluent; and separating at least a second stage hydroprocessing product from the second stage hydroprocessing effluent, wherein the second stage hydroprocessing product contains the hydroprocessing product.

[0108] Embodiment 16. A method according to any of the preceding embodiments, wherein the coking of at least a portion of the hydrotreated product comprises: feeding the hydrotreated product to a coker fractionator; heating at least a portion of the fractionator effluent from the coker fractionator in a coker furnace, wherein the fractionator effluent contains at least a portion of the hydrotreated product; thermally cracking the fractionator effluent in a coking vessel to form at least a coking effluent and the coke product; and feeding the coking effluent to the coker fractionator for separation into two or more fractions.

[0109] Embodiment 17. A method of needle coke production, the method comprising: hydrotreating a feedstock comprising steam cracked tar and a utility fluid in a first hydrotreating stage by contacting the feedstock with at least one first stage hydrotreating catalyst in the presence of molecular hydrogen to produce a first stage hydrotreating effluent, wherein the steam cracked tar has a hydrolysis rate of 100 % by mass according to ASTM D 1066. an initial boiling point of about 200°C or greater as measured by D7500, wherein the steam cracked tar comprises aromatic compounds in an amount of about 50 wt% or greater having ≥15 carbon atoms; wherein the utility fluid has a solubility blending number of about 100 or greater and comprises aromatic compounds in an amount of about 25 wt% or greater; separating at least a first stage hydroprocessing product from the first stage hydroprocessing effluent; hydrotreating at least a portion of the first stage hydroprocessing product in a second hydroprocessing stage by contacting at least a portion of the first stage hydroprocessing product with at least one second stage hydroprocessing catalyst in the presence of additional molecular hydrogen to produce a second stage hydroprocessing effluent; separating at least a second stage hydroprocessing product from the second stage hydroprocessing effluent; wherein the second stage hydroprocessing product comprises a sulfur content of about 0.5 wt% or less and a BMCI of about 90 to about 160, wherein the second stage hydroprocessing product comprises a sulfur content of about 0.5 wt% or less and a BMCI of about 90 to about 160, wherein the second stage hydroprocessing product comprises a sulfur content of about 0.5 wt% or less and a BMCI of about 1.5 wt% to about 2.5 wt%; ... The method comprises the steps of: coking at least a portion of the second stage hydroprocessing product to form at least a coking effluent and needle coke, wherein the needle coke comprises sulfur in an amount of 0.5 wt % or less.

[0110] Embodiment 18. A method according to Embodiment 17, wherein the separation of at least the first stage hydroprocessing product from the first stage hydroprocessing effluent includes separating the first stage hydroprocessing effluent in one or more stages to form at least: (i) an overhead stream, the overhead stream comprising ≥ about 1 weight % of the first hydroprocessing product; (ii) an intermediate distillate stream, the intermediate distillate stream comprising ≥ about 20 weight % of the first hydroprocessing product and having a boiling point distribution of about 120°C to about 480°C measured according to ASTM D7500; and (iii) a bottoms stream, the bottoms stream comprising ≥ about 10 weight % of the first hydroprocessing product, wherein at least a portion of the bottoms stream is hydroprocessed in a second hydroprocessing stage.

[0111] Embodiment 19. The method of Embodiment 18, further comprising recycling at least a portion of the middle distillate stream for use as at least a portion of the utility fluid in the first hydroprocessing stage.

[0112] Embodiment 20. A method according to any one of Embodiments 17 to 19, wherein the coking includes: feeding a hydrotreated product into a coker fractionator; heating at least a portion of a fractionator effluent from a coker fractionator in a coker furnace, wherein the fractionator effluent contains at least a portion of a second stage hydrotreated product; thermally cracking the fractionator effluent in a coking vessel to form at least a coking effluent and a coke product; and feeding the coking effluent to a coker fractionator for separation into two or more fractions.

[0113] Example

[0114] Example 1 - Tar Hydroprocessing (SATC Process)

[0115] The following example is carried out to illustrate the upgrading of hydrocarbon pyrolysis tar to a hydroprocessing product. In this example, a tar having a density of 1.16 g / cm 3 Steam cracking tar with a density of 0.94g / cm 3 The combined feed was directed to a two-stage fixed bed reactor. The two-stage reactor was heated at 400°C for the first reactor stage, 370°C for the second reactor stage, 1100 psi (7584 kPa) and 1.0 h -1 The total liquid product from the second reactor was distilled to form a SATC product for analysis. The fractions boiling between 340°C and 620°C were combined and used for the needle coke experiments in Example 2.

[0116] The properties of the hydrotreated steam cracked tar product before and after hydrotreatment are provided in the table below.

[0117] Table 1

[0118]

[0119] Example 2 - Decanted Oil Hydrotreating

[0120] For comparative purposes, the decant oil was hydrotreated (without a utility fluid) and the resulting hydrotreated decant oil was used in the needle coke experiments of Example 3. The decant oil was a blend of low sulfur decant oil and high sulfur decant oil from at least 4 different refineries. The decant oil was hydrotreated at 390°C in a reactor maintained at 2400 psia of hydrogen using a sulfide NiMo catalyst. The liquid hourly space velocity was maintained at 0.4 h -1 The total liquid product was fractionated to remove components below 350°C, and the heavier fraction was used in the needle coke experiments.

[0121] The properties of the hydrotreated decant oil product before and after hydrotreatment are provided in the table below.

[0122] Table 2

[0123]

[0124] Example 3 - Needle Coke Production

[0125] The following example was conducted to illustrate the production of needle coke from hydrocarbon liquids such as hydrocarbon pyrolysis tar. About 3 to 4 grams of the hydrotreated steam cracking tar product from Example 1 was fed into a laboratory scale batch coking reactor and held at 500°C for 5 hours under autothermal pressure. The laboratory scale batch coking reactor was heated to 100 °C. Figure 4 400. The reactor was filled with aluminum foil tubes to facilitate recovery of the char product. At the end of each run, the reactor air / water was cooled to room temperature and depressurized after sampling the headspace gas. After opening the reactor, the char and the interior of the reactor were washed with dichloromethane to recover the liquid product. The recovered char was weighed after the dichloromethane was evaporated. Two runs were performed on the hydrotreated steam cracking tar product. For comparison purposes, a conventional delayed coking feed was also tested. The conventional delayed coking feed was the hydrotreated decant oil product from Example 2.

[0126] The yields of hydrotreated steam cracked tar and hydrotreated decant oil products from each run are shown in Table 3 below.

[0127] Table 3

[0128]

[0129] Both the hydroprocessed steam cracked product and the hydroprocessed decant oil product produced a coherent coke column upon carbonization. Further, the optical images of the coke obtained from both samples showed a needle-like structure, indicating the production of needle coke. The sulfur of the needle coke used for the hydroprocessed steam cracked product was low, as the sulfur content of the hydroprocessed steam cracked tar product was 0.105 wt%.

[0130] Although compositions, methods and processes are described herein as "comprising," "containing," "having," or "including" various components or steps, the compositions and methods may also "consist essentially of" or "consist of" various components and steps. Unless otherwise indicated, whether or not specifically mentioned in this specification, the phrases "consist essentially of" and "consist essentially of" do not exclude the presence of other steps, elements, or materials, as long as such steps, elements, and materials do not affect the basic and novel characteristics of the present disclosure, and further, they do not exclude impurities and variations normally associated with the components and materials used.

[0131] All numerical values ​​in the detailed description are modified by the indication of "about", and take into account experimental errors and variations that would be expected by a person of ordinary skill in the art.

[0132] Many changes, modifications and variations will be apparent to those skilled in the art from the above description without departing from the spirit or scope of the present disclosure, and when numerical lower limits and numerical upper limits are listed herein, ranges from any lower limit to any upper limit are contemplated.

Claims

1. A method for producing needle coke, the method comprising: hydroprocessing a hydrocarbon liquid by contacting the hydrocarbon liquid with at least one hydroprocessing catalyst in one or more hydroprocessing stages to form a hydroprocessed product, wherein the hydroprocessing of the hydrocarbon liquid in at least one of the one or more hydroprocessing stages is carried out in the presence of a utility fluid, wherein the hydrocarbon liquid comprises an initial boiling point at atmospheric pressure of about 200° C. or greater according to ASTM 7500, wherein the hydrocarbon liquid comprises an aromatics content of about 50 wt % or greater; and At least a portion of the hydroprocessed product is coked to form a coking effluent and coke, wherein the coke comprises needle coke.

2. The method of claim 1, wherein the hydrocarbon liquid comprises hydrocarbon pyrolysis tar.

3. The method of claim 1 or claim 2, wherein the hydrocarbon liquid comprises hydrocarbon pyrolysis tar having an initial boiling point of about 200° C. or greater as measured according to ASTM D7500, and wherein the hydrocarbon pyrolysis tar comprises aromatic compounds having ≥15 carbon atoms in an amount of about 50 wt % or greater.

4. A method according to any preceding claim, wherein the hydrocarbon liquid comprises steam cracked tar.

5. The process of any preceding claim, wherein the hydrocarbon liquid comprises sulfur in an amount of about 3 wt% to about 4.5 wt%, and wherein the needle coke comprises sulfur in an amount of about 0.5 wt% or less.

6. The process of any preceding claim, wherein the hydroprocessed product has a sulfur content of about 0.5 wt% or less.

7. The process of any preceding claim, wherein the hydroprocessed product comprises about 70 wt% or greater combined amounts of three-ring aromatics and four-ring aromatics.

8. The method of any preceding claim, wherein the hydroprocessed product comprises an initial boiling point of 200°C to 400°C at atmospheric pressure and a final boiling point of 500°C to 700°C at atmospheric pressure as determined according to ASTM 7500, and wherein the hydroprocessed product has a BMCI of about 90 to about 160.

9. A method according to any preceding claim, wherein the utility fluid comprises at least a portion of an interstage hydroprocessing product which is recycled for combination with the hydrocarbon liquid.

10. The method of any preceding claim, wherein the utility fluid has a solubility blending number of about 100 or greater, and wherein the utility fluid comprises aromatic compounds in an amount of about 25 weight percent or greater.

11. The method of any preceding claim, wherein the needle coke comprises sulfur in an amount of about 0.5 wt% or less.

12. The method of any preceding claim, wherein the needle coke comprises sulfur in an amount of about 0.1 wt% or less.

13. The method of any preceding claim, wherein the coke product comprises the needle coke in an amount from about 25 wt% to about 60 wt%.

14. The method according to any preceding claim, wherein the hydroprocessing comprises: hydroprocessing the hydrocarbon liquid in the presence of the utility fluid in a first hydroprocessing stage to produce a first stage hydroprocessing effluent; separating at least a first stage hydroprocessing product from the first stage hydroprocessing effluent; and hydroprocessing at least a portion of the first stage hydroprocessing product in a second hydroprocessing stage to produce a second stage hydroprocessing effluent; and At least a second stage hydroprocessing product is separated from the second stage hydroprocessing effluent, wherein the second stage hydroprocessing product comprises the hydroprocessing product.

15. The method of any preceding claim, wherein coking at least a portion of the hydroprocessed product comprises: feeding the hydroprocessed product to a coker fractionator; heating at least a portion of a fractionator effluent from the coker fractionator in a coker furnace, wherein the fractionator effluent comprises at least a portion of the hydroprocessed product; thermally cracking the fractionator effluent in a coking vessel to form at least a coking effluent and a coke product; and The coking effluent is fed to the coker fractionator for separation into two or more fractions.

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