Upgrading of Hydrocarbon Liquids to Ultra-Low Sulfur Needle Coke

Abstract

In one embodiment, various systems and methods are disclosed, including a method for producing needle coke. 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 hydrotreated product, where 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. The hydrocarbon liquid has an initial boiling point at atmospheric pressure of about 200° C. or greater according to ASTM 7500. The hydrocarbon liquid includes an aromatics content of about 50 wt.% or greater. The method further includes coking at least a portion of the hydrotreated product to form a coker effluent and coke, where the coke includes needle coke.

Description

[Technical field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of and priority to U.S. Provisional Application No. 63 / 341,232, filed May 12, 2022, the disclosure of which is incorporated herein by reference.

[0002] Technical Field A system and method are provided for the production of needle coke, and more specifically, for upgrading hydrocarbon liquids to ultra-low sulfur needle coke by a process that includes hydrotreating with a utility fluid followed by delayed coking. [Background technology]

[0003] Background technology Needle coke is a type of petroleum coke produced in petroleum refineries by pyrolyzing long-chain hydrocarbons into shorter-chain molecules, leaving excess carbon behind in the form of petroleum coke, in a process commonly referred to as "coking." Needle coke is one of the most valuable products that can be produced in petroleum refineries and is used in the manufacture of a variety of products, including electrodes for electric arc furnaces and anodes for lithium batteries. Needle coke has traditionally been produced in delayed cokers from low-sulfur aromatic feedstocks within a specific boiling range, such as fluid catalytic cracking decant oil, vacuum gas oil, atmospheric residues, and coal tar pitch. These feedstreams produce high-quality needle coke because they contain aromatic molecules that are resistant to cracking, and therefore can be coked at higher pressures and for longer times, allowing the molecules to condense, align, and form the needle coke structure. In contrast, steam cracker tar and other hydrocarbon pyrolysis tars typically contain high concentrations of highly reactive molecules and have high sulfur contents, making them unsuitable for the production of high quality needle coke. Summary of the Invention [Means for solving the problem]

[0004] overview Disclosed herein is an example method for producing needle coke, 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 hydrotreated product, wherein hydrotreating the hydrocarbon liquid in at least one of the one or more hydrotreating stages is carried out in the presence of a utility fluid, the hydrocarbon liquid having a first boiling point of about 200° C. or more at atmospheric pressure according to ASTM 7500, and an aromatic content of about 50 wt.% or more. The method further comprises coking at least a portion of the hydrotreated product to form a coker effluent and coke, the coke comprising needle coke.

[0005] Another example of a method for producing needle coke is disclosed herein. The method comprises hydrotreating a feedstock comprising steam cracker 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, the steam cracker tar having an initial boiling point of about 200° C. or more as determined in accordance with ASTM D7500, the steam cracker tar comprising aromatic compounds having 15 or more carbon atoms in an amount of about 50% by weight or more, and the utility fluid having a solubility blending number of about 100 or more and comprising aromatic compounds in an amount of about 25% by weight or more. The method further comprises separating at least a first stage hydrotreating product from the first stage hydrotreating effluent. The method further comprises 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. The method further comprises separating at least the second stage hydroprocessing product from the second stage hydroprocessing effluent, the second stage hydroprocessing product comprising a sulfur content of about 0.5 wt% or less and having a BMCI of about 90 to about 160, the second stage hydroprocessing product comprising an initial boiling point at atmospheric pressure of 300° C. to 400° C. and a final boiling point at atmospheric pressure of 500° C. to 600° C. as determined in accordance with ASTM 7500. The method further comprises coking at least a portion of the second stage hydroprocessing product to form at least a coker effluent and needle coke, the needle coke comprising sulfur in an amount of 0.5 wt% or less.

[0006] These and other features and attributes of the disclosed methods and systems of the present disclosure, as well as their advantageous applications and / or uses, will become apparent from the following detailed description. [Brief description of the drawings]

[0007] BRIEF DESCRIPTION OF THE DRAWINGS To assist those skilled in the relevant art in making and using the subject matter of the present disclosure, reference is made to the accompanying drawings.

[0008] [Figure 1] FIG. 1 is an example of a single reaction stage embodiment for upgrading hydrocarbon pyrolysis tar.

[0009] [Diagram 2] FIG. 2 is an example of upgrading hydrocarbon pyrolysis tar in at least two reaction steps.

[0010] [Diagram 3] FIG. 3 is an example of a system including hydrotreating followed by delayed coking.

[0011] [Figure 4] FIG. 4 is an example of a laboratory-scale batch coker reactor used to produce needle coke of the examples disclosed herein. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0012] Detailed Description Disclosed herein is a process for producing needle coke using hydrocarbon liquids. According to this embodiment, the method for producing needle coke comprises (i) hydrotreating a hydrocarbon liquid by contacting the hydrocarbon pyrolysis tar with at least one hydrotreating catalyst in one or more hydrotreating stages to form a hydrotreated product, and (ii) coking at least a portion of the hydrotreated product to form a coker effluent and a coke, the coke comprising needle coke. The hydrotreating used according to this embodiment is a hydrocarbon conversion process called 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, for example, hydrocarbon pyrolysis tar, atmospheric residue, vacuum residue, slurry oil, and other heavy hydrocarbon streams with high aromatic content.

[0013] Hydrocarbon pyrolysis tar is a high boiling viscous hydrocarbon liquid produced from a thermal cracking process, such as steam cracking, in the conversion of saturated hydrocarbons to higher value products, such as light olefins (e.g., ethylene and propylene). Hydrocarbon pyrolysis tar typically includes high molecular weight non-volatile components, including complex cyclic and branched molecules, and paraffin-insoluble compounds, such as pentane-insoluble compounds and heptane-insoluble compounds, including asphaltenes. Thus, hydrocarbon pyrolysis tar typically includes a large amount of large ring compounds and an insufficient amount of three- and four-ring aromatic compounds, which typically cause needle coke formation. In addition, hydrocarbon tar includes molecules with multiple side chains that a typical coker supplies to needle coke production, which decompose to create multiple reaction sites for molecular growth propagation, resulting in undesirable coke quality. In addition to these compounds, hydrocarbon pyrolysis tar also includes a high sulfur content, such as as much as 5 wt.%, leading to the production of low quality high sulfur needle coke.

[0014] The SATC process is a hydrotreating technology that addresses fouling caused by feedstocks such as, for example, hydrocarbon pyrolysis tar. Thus, an exemplary embodiment includes hydrotreating a hydrocarbon pyrolysis tar in a SATC process, e.g., contacting the hydrocarbon pyrolysis tar with at least one hydrotreating catalyst in one or more hydrotreating stages to form a hydrotreating product, where the hydrotreating in at least one of the one or more hydrotreating stages is performed in the presence of a utility fluid. SATC is a "gentler" hydrotreating process (e.g., lower pressure and temperature) than severe hydrotreating (e.g., 20700 kPA), and can convert the hydrocarbon pyrolysis tar into a low-sulfur hydrotreating product while minimizing aromatic saturation, thereby suppressing more aromatic rings for coke formation. For example, the hydrotreating product contains sulfur in an amount of ≦1.5 wt%, ≦1 wt%, ≦0.5 wt%, ≦0.4 wt%, or ≦0.1 wt%. Thus, the needle coke produced from coking the hydrotreating product is also low in sulfur. Additionally, needle coke is produced from a feedstock that contains high concentrations of three- and four-ring aromatics and low concentrations of five-ring and larger ring aromatics. For example, by increasing the concentration of three- and four-ring aromatics in the hydrotreated product from the SATC process to 70 wt. % or more, the concentration of compounds with 5 or more aromatic rings is reduced, while coking the hydrotreated product advantageously produces needle coke instead of less valuable coke products. BMCI refers to the Bureau of Mines Correlation Index. BMCI is a number that correlates with the aromaticity of the feedstock. Coke feedstocks with a BMCI ≥ 90 can produce desirable needle coke. Advantageously, the SATC process produces hydrotreated products with a BMCI ≥ 90, according to one or more embodiments.

[0015] Hydrocarbon Liquid According to the present embodiment, the hydrocarbon liquid pyrolysis tar is improved in the SATC process to provide a hydrotreated product with improved properties against delayed coking. Non-limiting examples of suitable hydrocarbon liquids include heavy hydrocarbon liquids such as, for example, hydrocarbon pyrolysis tar, atmospheric residue, vacuum residue, slurry oil, and other heavy hydrocarbon streams with high aromatic content. Exemplary hydrocarbon liquids have an initial boiling point of 200° C. or higher. As used herein, the initial boiling point and end point are determined according to ASTM D7500. Exemplary hydrocarbon liquids have an aromatic content of ≧50 wt%, ≧75 wt%, ≧90 wt%, ≧95 wt%, based on the weight of the hydrocarbon liquid. In some embodiments, two or more hydrocarbon liquids are treated in the SATC process.

[0016] In some embodiments, the hydrocarbon pyrolysis tar is improved in a SATC process to provide a hydrotreated product with improved properties against delayed coking. The hydrocarbon pyrolysis tar includes aromatic compounds. In some embodiments, the hydrocarbon pyrolysis tar includes aromatic compounds having 15 or more carbon atoms in an amount of ≧50 wt%, ≧75 wt%, or ≧90 wt%, based on the weight of the hydrocarbon pyrolysis tar. Hydrocarbon pyrolysis tar generally has a lower metal content than crude oil of the same viscosity, e.g., the hydrocarbon pyrolysis tar has a metal content of ≦1.0×10 based on the weight of the hydrocarbon pyrolysis tar. 3 ppmw metals content, which is much less than would be found in a crude oil (or crude oil component) of the same average viscosity.

[0017] In some embodiments, the hydrocarbon pyrolysis tar has an insolubility number ("IN") of ≧80. For example, the hydrocarbon pyrolysis tar can have an 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.

[0018] Additionally, 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 SBN≧180. In some embodiments, the hydrocarbon pyrolysis tar can have an SBN≧200 or an SBN≧200. In further embodiments, the hydrocarbon pyrolysis tar has an SBN up to 240. The solubility blending number or SBN used herein is determined according to ASTM D7112. In this test method, pentane has an SBN of 25, toluene has an SBN of 100, and quinoline has an SBN of 200.

[0019] Further, exemplary embodiments of the hydrocarbon pyrolysis tar include 7 In some embodiments, the hydrocarbon pyrolysis tar comprises C 7 The insoluble matter is contained in an amount of ≦50% by weight, for example, ≦15% by weight, ≦25% by weight, ≦30% by weight, ≦45% by weight. Thus, the hydrocarbon pyrolysis tar contains, for example, 15% to 50% by weight or 30% to 50% by weight of C. 7 Contains insoluble matter.

[0020] In a particular embodiment, the hydrocarbon pyrolysis tar has an IN of 110 to 135, an SBN of 180 to 240, and a C content of 30% to 50% by weight. 7 Has insoluble content.

[0021] As mentioned above, hydrocarbon pyrolysis tar is generally not used to produce needle coke. Hydrocarbon pyrolysis tar typically contains too many highly reactive molecules and sulfur, making it unsuitable for producing high-quality coke. For example, hydrocarbon pyrolysis tar contains sulfur in an amount up to 5% by weight or more. In some embodiments, the hydrocarbon pyrolysis tar contains sulfur in an amount ranging from about 1% by weight to about 7% by weight, or from about 2% by weight to about 4.5% by weight.

[0022] In addition to sulfur, the hydrocarbon pyrolysis tar also contains high molecular weight non-volatile components including paraffin-insoluble compounds such as pentane-insoluble compounds and heptane-insoluble compounds, including asphaltenes, which can cause undesirable fouling during coking. In some embodiments, the hydrocarbon pyrolysis tar contains >0.5 wt%, in some cases >1 wt%, or even >2 wt% toluene-insoluble compounds. The high molecular weight compounds are typically polycyclic structures, also referred to as tar heavies ("TH"). As used herein, the term tar heavies refers to hydrocarbon pyrolysis products that have a boiling point at atmospheric pressure of ≥565°C and contain ≥5 wt% molecules with multiple aromatic cores, based on the weight of the product. Tar heavies typically include fractions of hydrocarbon pyrolysis tar that are solid at 25°C and generally do not dissolve in a 5:1 (volume:volume) ratio of n-pentane:hydrocarbon pyrolysis tar at 25.0°C.

[0023] Hydrocarbon pyrolysis tar is produced from thermal cracking processes, such as, for example, steam cracking, that are utilized to convert saturated hydrocarbons into higher value products, such as, for example, light olefins (e.g., ethylene and propylene). In addition to these useful products, hydrocarbon pyrolysis can also produce large amounts of relatively less valuable heavy products, such as, for example, hydrocarbon pyrolysis tar.

[0024] A pyrolysis process for producing hydrocarbon pyrolysis tar, for example, includes subjecting a hydrocarbon-containing feedstock to pyrolysis conditions to produce a pyrolysis effluent, the pyrolysis effluent being a mixture including unreacted feedstock, unsaturated hydrocarbons produced from the feedstock during pyrolysis, and pyrolysis tar. For example, a pyrolysis feedstock containing ≥ 10 wt. % hydrocarbons based on the weight of the pyrolysis feedstock is subjected to pyrolysis to produce a pyrolysis effluent, which generally includes a mixture of hydrocarbon pyrolysis tar and ≥ 1 wt. % C based on the weight of the pyrolysis effluent. 2Contains unsaturates. Pyrolysis tar generally contains ≧90% by weight of the molecules of the pyrolysis effluent having an atmospheric boiling point ≧290° C. Thus, in some embodiments, at least a portion of the hydrocarbon pyrolysis tar is separated from the pyrolysis effluent to produce a feedstock for use in the systems and methods described herein, the feedstock containing ≧90% by weight of the molecules of the pyrolysis effluent having an atmospheric boiling point ≧290° C. In addition to the hydrocarbons, the pyrolysis feedstock optionally further contains a diluent, e.g., one or more of nitrogen, water, etc. For example, the pyrolysis feedstock may further contain ≧1% by weight of the diluent, e.g., ≧25% by weight, based on the weight of the pyrolysis feedstock. When the diluent contains a significant amount of steam, the pyrolysis is referred to as steam cracking.

[0025] Exemplary embodiments include hydrocarbon pyrolysis tars, including one or more of steam cracker tars, coal pyrolysis tars, and biomass pyrolysis tars. "Steam cracker tar" means hydrocarbon pyrolysis tars obtained from steam cracking, also referred to as steam cracker tars. "Biomass pyrolysis tar" means hydrocarbon pyrolysis tars obtained by pyrolysis of biomass. "Coal pyrolysis tar" means hydrocarbon pyrolysis tars obtained by pyrolyzing hydrocarbons derived from coal. Alternatively, the hydrocarbon pyrolysis tars can be obtained, for example, from a steam cracked gas oil ("SCGO") stream and / or a bottom stream of a primary fractionator of a steam cracker, from a flash drum bottom (e.g., one or more flash drum bottoms downstream of a pyrolysis furnace and upstream of a primary fractionator), or a combination thereof. For example, the hydrocarbon pyrolysis tars can be a mixture of a primary fractionator bottom and a tar knockout drum bottom.

[0026] In some embodiments, the hydrocarbon pyrolysis tar is provided in a pyrolysis effluent, for example, the pyrolysis effluent comprises hydrocarbon pyrolysis tar (e.g., steam cracker tar) in an amount of ≧90 wt%, ≧95 wt%, or ≧99 wt%, based on the weight of the pyrolysis effluent, for example, the remainder of the pyrolysis effluent being particles.

[0027] In some embodiments, the hydrocarbon pyrolysis tar has, for example, (i) a sulfur content in the range of 0.5 wt.% to 7 wt.% based on the weight of the SCT; (ii) a tar heavy content in the range of 5 wt.% to 40 wt.% based on the weight of the SCT; (iii) a tar heavy content in the range of 1.01 g / cm 3 ~1.15g / cm 3 range, e.g. 1.07g / cm 3 ~1.20g / cm 3 and (iv) a density at 15°C (determined in accordance with ASTM D4052) in the range of 200 cSt to 1.0 x 10 7 The steam cracker tar ("SCT") has a 50°C viscosity (determined according to ASTM D7042) in the cSt range. The amount of olefins in the SCT is generally ≦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 compounds in the SCT and / or (ii) aggregates in the SCT incorporating vinyl aromatic compounds is generally ≦5 wt%, ≦3 wt%, or ≦2 wt%, based on the weight of the SCT.

[0028] Utility Fluids According to this embodiment, the hydrocarbon pyrolysis tar is hydrotreated in the presence of a utility fluid. The utility fluid is used in one or more stages of hydrotreatment. The utility fluid can be or include a specified solvent, but is typically a recycled solvent taken from another process. The utility fluid can be all or part of the product of the process, such as a final product or an intermediate product, e.g., a mid-cut, that is recycled to the initial feed.

[0029] Typically, the utility fluid comprises aromatic hydrocarbons and has an ASTM D86 10% distillation point >60°C and a 90% distillation point <425°C. According to this embodiment, the utility fluid typically comprises a mixture of multi-ring compounds. The rings can be aromatic or non-aromatic and can include various 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.

[0030] In certain embodiments, the utility fluid includes one-ring, two-ring, and three-ring aromatic compounds. In some embodiments, the utility fluid includes two-ring and / or three-ring 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. Two-ring and three-ring aromatic compounds may be used in certain embodiments due to their higher SBN. To the extent that a specified solvent is included in the utility fluid or is used alone, the specified solvent includes one-ring and two-ring aromatic compounds.

[0031] The utility fluid can have a true boiling point distribution, for example, with an initial boiling point of ≥ 177°C and an end 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 an end point of ≤ 430°C. The true boiling point distribution ("TBP", distribution at atmospheric pressure) is determined according to ASTM D7500. If the end point is higher than the boiling point specified in the standard, the true boiling point distribution can be determined by extrapolation.

[0032] Generally, the increased non-aromatic content of utility fluids having relatively low initial boiling points, such as ≧10 wt. % of the utility fluid having an atmospheric boiling point of <175° C., may result in incompatibility with hydrocarbon pyrolysis tars and asphaltene precipitation. Thus, according to this embodiment, the utility fluid has a true initial boiling point of ≧177° C. Similarly, generally, high I N Since higher SBN molecules are needed to avoid incompatibility with tar, and higher boiling molecules have higher SBN, in this embodiment the utility fluid has a true end point of ≦566° C. Optionally, the utility fluid has a true end point of >430° C. Such utility fluids have a higher than typical aromatic content, for example, an amount of two-ring and three-ring aromatic compounds of ≧25 wt % based on the weight of the utility fluid.

[0033] As mentioned above, the hydrocarbon pyrolysis tar is hydrotreated in the presence of a utility fluid in one or more stages of hydrotreating. In some embodiments, the utility fluid is employed during hydrotreating in an amount of 5% to 80% by weight based on the total weight of the utility fluid and the hydrocarbon pyrolysis tar, while the hydrocarbon pyrolysis tar is used in an amount of 20% to 95% by weight based on the total weight of the utility fluid and the hydrocarbon pyrolysis tar. For example, the relative amounts of the utility fluid and the tar stream during hydrotreating include the hydrocarbon pyrolysis tar in an amount of 20% to 90% by weight and the utility fluid in an amount of 10% to 80% by weight. As a further example, the relative amounts of the utility fluid and the tar stream during hydrotreating include the hydrocarbon pyrolysis tar in an amount of 40% to 90% by weight and the utility fluid in an amount of 10% to 60% by weight. In some embodiments, the utility fluid:hydrocarbon pyrolysis 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 mixed with at least a portion of the hydrocarbon pyrolysis tar in the hydrotreating vessel or hydrotreating stage, but this is not required, and in one or more embodiments, at least a portion of the utility fluid and at least a portion of the hydrocarbon pyrolysis tar are fed as separate streams and combined into one feed stream prior to entering (e.g., upstream of) the hydrotreating stage. For example, the tar stream and the utility fluid can be combined to produce a feedstock upstream of the hydrotreating stage, the feedstock comprising, for example, 20% to 90% by weight of hydrocarbon pyrolysis tar and 10% to 80% by weight of utility fluid or 40% to 90% by weight of hydrocarbon pyrolysis tar and 10% to 60% by weight of utility fluid, the weight percentages being based on the weight of the feedstock.

[0034] The compatibility of the utility fluid and the hydrocarbon pyrolysis tar is based on a 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 utility fluid has an SBN of ≧100, ≧110, ≧120, ≧130, ≧140, ≧150, or ≧160. In some embodiments, the combined pyrolysis tar and the utility fluid have an SBN of ≧110. Thus, an incompatibility number (IN) of the utility fluid and the hydroprocessed pyrolysis tar mixture after combination is determined to have an SBN of >110, ≧120, or ≧130. N It has been found that reactor plugging is beneficially reduced when hydrotreating pyrolysis tars having an SBN >80. Furthermore, when the combined utility fluid and hydrotreated pyrolysis tar mixture has a high SBN, e.g., ≥150, ≥155, or ≥160, the incompatibility number (I N It has been found that when hydrotreating pyrolysis tar having a C(O) content >110, reactor clogging is beneficially reduced.

[0035] In some embodiments, the utility fluid may be obtained from the first hydroprocessing product, for example, as a midcut stream separated from the first hydroprocessing stage. Thus, an exemplary embodiment of the process provided herein includes separating the first hydroprocessing product into an overhead stream, a midcut stream, and a bottoms stream in one or more separation stages. For example, the first hydroprocessing product may first be separated into a vapor portion and a liquid portion (e.g., in a flash drum), and then the liquid portion may be separated into an overhead stream, a midcut stream, and a bottoms stream (e.g., in a distillation column).

[0036] The SBN of the mid-cut stream is affected by the hydrotreating conditions. For example, when conditions are adjusted to improve product quality (e.g., higher pressure, lower WHSV), the mid-cut stream may be further hydrotreated, thereby lowering the SBN of the mid-cut stream. Lowering the SBN of the mid-cut stream may be problematic when mixed with hydrocarbon pyrolysis tars, because a low SBN may make the mid-cut stream incompatible with the hydrocarbon pyrolysis tars, causing reactor fouling and plugging. However, as described herein, a process using at least two hydrotreating stages, in which the mid-cut stream is separated from the first hydrotreating stage, may produce a mid-cut stream with a composition and boiling range that is useful as a utility fluid in various hydrocarbon conversion processes, such as hydrotreating. In some embodiments, the mid-cut stream has an SBN of ≧100, ≧110, ≧120, ≧130, ≧140, ≧150, or ≧160.

[0037] Thus, according to some embodiments, at least a portion of the midcut stream is recycled as an interstage hydroprocessing product for use as a utility fluid in the first hydroprocessing stage (i.e., interstage recycle). For example, ≧20 wt%, ≧30 wt%, ≧40 wt%, ≧50 wt%, ≧60 wt%, ≧70 wt%, or ≧80 wt% of the midcut stream is recycled for use as a utility fluid in the first hydroprocessing stage.

[0038] In some embodiments, the auxiliary utility fluid is present under certain operating conditions, for example, when starting the process (until sufficient utility fluid is available from the first hydroprocessing product as a midcut stream) or when operating at higher reactor pressures. Thus, an auxiliary utility fluid, such as, for example, a solvent, a solvent mixture, steam cracked naphtha (SCN), steam cracked gas oil (SCGO), or a fluid containing aromatics (i.e., containing molecules having at least one aromatic core), may be added, for example, to start the process. In some embodiments, the auxiliary utility fluid comprises ≧50 wt%, ≧75 wt%, or ≧90 wt% aromatics and / or non-aromatic compounds, based on the weight of the auxiliary utility fluid. The auxiliary utility fluid may have an ASTM D86 10% distillation point of ≧60° C. and a 90% distillation point of ≦350° C. Optionally, the auxiliary utility fluid (which may be a solvent or mixture of solvents) has an ASTM D86 10% distillation point ≧120°C, ≧140°C, or ≧150°C and / or an ASTM D86 90% distillation point ≦300°C.

[0039] Optionally, the auxiliary utility fluid comprises ≥90 wt.% or more, e.g., ≥95 wt.%, e.g., ≥99 wt.%, based on the weight of the utility fluid, of one or more of benzene, ethylbenzene, trimethylbenzene, xylene, toluene, naphthalene, alkylnaphthalene (e.g., methylnaphthalene), tetralin, or alkyltetralin (e.g., methyltetralin). In general, it is desirable for the auxiliary utility fluid to be substantially free of molecules having alkenyl functionality, especially in embodiments utilizing hydrotreating catalysts that are prone to coke formation in the presence of such molecules. In certain embodiments ... based on the weight of the utility fluid, of one or more of benzene, ethylbenzene, trimethylbenzene, xylene, toluene, naphthalene, alkylnaphthalene (e.g., methylnaphthalene), tetralin, or alkyltetralin (e.g., methyltetralin). 1 ~C 6Contains ≦10% by weight of ring compounds having side chains.One suitable auxiliary utility fluid is A200 solvent available from ExxonMobil Chemical Company (Houston, Texas) as Aromatic 200, CAS number 64742-94-5.

[0040] SATC Process The system and method include hydrotreating a hydrocarbon liquid (e.g., a hydrocarbon pyrolysis tar) by contacting the hydrocarbon pyrolysis tar with at least one hydrotreating catalyst in one or more hydrotreating stages in the presence of a treat gas containing hydrogen to form a hydrotreated product. Because at least one or more hydrotreating stages include hydrotreating the hydrocarbon pyrolysis tar in the presence of a utility fluid, the hydrotreating is referred to as a solvent-assisted tar conversion ("SATC") process. The feedstock includes a hydrocarbon pyrolysis tar, for example, ≧10 wt.% of the hydrocarbon pyrolysis tar based on the weight of the feedstock, and may include >15 wt.%, >20 wt.%, >30 wt.%, or up to about 50 wt.% of the hydrocarbon pyrolysis tar.

[0041] Hydrotreating is carried out under hydrotreating conditions in one or more of, for example, hydrocracking (including selective hydrocracking), hydrogenation, hydrotreating, hydrodesulfurization, hydrodenitrogenation, hydrodemetallation, hydrodearomatization, hydroisomerization, or hydrodewaxing. Hydrotreating is carried out in succession in at least one reaction stage. In some embodiments, hydrotreating is carried out in succession in at least one reaction stage. The two reaction stages are typically in two reactors, but can be placed in two parts of one reactor, as long as the midcut is separated and removed between the first and second stages.

[0042] In multi-stage embodiments, hydrotreating is performed in a first hydrotreating stage by contacting the feed with at least one hydrotreating catalyst under catalytic hydrotreating conditions in the presence of a utility fluid and molecular hydrogen to convert at least a portion of the feed to a first hydrotreating product. A midcut stream is separated from the first hydrotreating product. In some embodiments, the midcut stream comprises ≧20 wt.% of the first hydrotreating product and has a boiling point distribution, as measured according to ASTM D7500, of about 120° C. to about 480° C. In some embodiments, the midcut is recycled as a utility fluid in the first hydrotreating stage. In some embodiments, a bottoms stream is also separated from the first hydrotreating product. The bottoms stream comprises, for example, ≧20 wt.% of the first hydrotreating product. At least a portion of the bottoms stream is hydrotreated in a second hydrotreating stage by contacting the bottoms stream with at least one hydrotreating catalyst in the presence of molecular hydrogen under catalytic hydrotreating conditions to convert at least a portion of the bottoms stream to a second hydrotreated product.

[0043] The SATC process allows for the production of a hydrotreated product (SATC product) with desirable properties for the production of needle coke. The hydrotreated product is the second hydrotreated product in a multi-stage embodiment. For example, the hydrotreated product is low in sulfur and has an increased concentration of three- and four-ring aromatics. In some embodiments, the hydrotreated product has a sulfur content of 1.5 wt% or less, 1 wt% or less, 0.5 wt% or less, 0.4 wt% or less, or 0.1 wt% or less, based on the weight of the hydrotreated product. In some embodiments, the hydrotreated product has an increased content of three- and four-ring aromatics. Examples of hydrotreated products include three- and four-ring aromatics in a total amount of ≧50 wt%, ≧60 wt%, or ≧70 wt%, based on the weight of the hydrotreated product. Another measure to quantify aromaticity is the BMCI. In some embodiments, the hydrotreated product has a BMCI of ≧90, ≧100, ≧110, ≧120, for example, from 90-160 or from 120-160.

[0044] The hydrotreated product may have a low ash content, for example, an external ash content of ≦0.5 wt.%, ≦0.3 wt.%, or ≦0.1 wt.%, based on the weight of the hydrotreated product. In some examples, the hydrotreated product also has an initial boiling point of 200° C. to 400° C. at atmospheric pressure and an end point of 500° C. to 700° C. at atmospheric pressure. For example, the hydrotreated product may have an initial boiling point of 250° C. to 375° C., or 275° C. to 375° C. As further examples, the hydrotreated product may have an end point of 525° C. to 675° C., or 525° C. to 600° C. Exemplary hydrotreated products also have a product viscosity of ≦30 cSt at 50° C., ≦20 cSt at 50° C., or ≦15 cSt at 50° C., and a viscosity of ≦1.00 g / cm. 3 has a density of

[0045] In any configuration of the process, hydrotreating conditions may include temperatures of, for example, 200° C. to 450° C. In some embodiments, independently or in combination with any particular arrangement of catalysts in the different hydrotreating stages, the temperature of the first hydrotreating stage may range from about 200° C. to 450° C., or from about 200° C. to 450° C., and the temperature of the second hydrotreating stage may range from about 300° C. to 450° C., or from about 350° C. to 425° C., or vice versa. In some embodiments, the temperature of the first hydrotreating stage may be higher than the temperature of the second hydrotreating stage, or vice versa. Alternatively, the temperatures may be the same for the first and second hydrotreating stages.

[0046] In any configuration of the process, hydrotreating conditions can include pressures of, for example, 4100 kPa to 14000 kPa, 4100 kPa to 1300 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, pressures of 7000 kPa to 8950 kPa are used in the process, for example, where hydrotreating is applied primarily in the first stage, followed by a hydrocracking process. In some embodiments, the catalyst promoting the hydrotreating reaction includes Ni, and the pressure can be >14000 kPa.

[0047] Any of a variety of suitable hydrotreating catalysts can be utilized to hydrotreat the feedstock (e.g., pyrolysis tar) in the SATC process described herein. Suitable hydrotreating catalysts include catalysts that include (i) one or more bulk metals and / or (ii) one or more metals on a support. The metals may be in elemental or compound form. In one or more embodiments, the hydrotreating catalyst includes at least one metal from any of Groups 5 to 10 of the Periodic Table of the Elements (as tabulated in the Periodic Table of the Elements, Merck Index, Merck & Co., 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.

[0048] In one or more embodiments, the catalyst has a total amount of Group 5-10 metals of at least 0.0001 grams, or at least 0.001 grams, or at least 0.01 grams per gram of catalyst, where grams are calculated on an elemental basis. For example, the catalyst can include a total amount of Group 5-10 metals 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. In certain embodiments, the catalyst further includes at least one Group 15 element. An example of a preferred Group 15 element is phosphorus. When a Group 15 element is utilized, the catalyst can include a total amount of the Group 15 element in the range of 0.000001 grams to 0.1 grams, or 0.00001 grams to 0.06 grams, or 0.00005 grams to 0.03 grams, or 0.0001 grams to 0.0001 grams, where the grams are calculated on the basis of the element.

[0049] In one embodiment, the catalyst comprises at least one Group 6 metal. Examples of preferred Group 6 metals include chromium, molybdenum and tungsten. The catalyst may contain a total amount of Group 6 metals of ≧0.00001 grams, or ≧0.01 grams, or ≧0.02 grams per gram of catalyst, where grams are calculated on an elemental basis. For example, the catalyst may contain a total amount of Group 6 metals 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 per gram of catalyst, where grams are calculated on an elemental basis.

[0050] In related embodiments, the catalyst comprises at least one Group 6 metal and further comprises at least one metal from Groups 5, 7, 8, 9, or 10. Such a catalyst can comprise, for example, a combination of metals in which the molar ratio of Group 6 metal to Group 5 metal ranges from 0.1 to 20, 1 to 10, or 2 to 5, said ratios being on an elemental basis. Alternatively, the catalyst can comprise a combination of metals in which the molar ratio of Group 6 metal to the total amount of Groups 7 through 10 metals ranges from 0.1 to 20, 1 to 10, or 2 to 5, said ratios being on an elemental basis.

[0051] When the catalyst comprises at least one group 6 metal and one or more metals of group 9 or 10, e.g., molybdenum-cobalt and / or tungsten-nickel, these metals can be present, for example, in a molar ratio of group 6 metal to group 9 and 10 metals ranging from 1 to 10 or 2 to 5, the ratio being 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 group 5 metal to group 10 metal ranging from 1 to 10 or 2 to 5, the ratio being based on the element. Furthermore, the catalyst may further comprise, for example, an inorganic oxide as a binder and / or support. For example, the catalyst may comprise (i) ≥ 1 wt. % of one or more metals selected from groups 6, 8, 9, and 10 of the periodic table, and (ii) ≥ 1 wt. % of an inorganic oxide, the weight percentage being based on the weight of the catalyst.

[0052] In one or more embodiments, the catalyst (e.g., in the first and / or second hydrotreating stages) is a bulk multimetallic hydrotreating catalyst, with or without a binder. In one embodiment, the catalyst is a bulk trimetallic catalyst composed of two Group 8 metals, preferably Ni and Co, and one Group 6 metal, preferably Mo.

[0053] Exemplary embodiments also include incorporating one or more catalytic metals, such as one or more metals from groups 5-10 and / or 15, into (or deposited on) a support to form a hydrotreating catalyst. The support may be a porous material. For example, the support may include one or more refractory oxides, porous carbon-based materials, zeolites, or combinations thereof, with suitable refractory oxides including, for example, alumina, silica, silica-alumina, titanium oxide, zirconium oxide, magnesium oxide, and mixtures thereof. Suitable porous carbon-based materials include activated carbon and / or porous graphite. Examples of zeolites include, for example, Y-zeolite, beta zeolite, mordenite zeolite, ZSM-5 zeolite, and ferrierite zeolite. Further examples of support materials include gamma alumina, theta alumina, delta alumina, alpha alumina, or combinations thereof. The amount of gamma alumina, delta alumina, alpha alumina, or combinations thereof, per gram of catalyst support, as determined by X-ray diffraction, may range from 0.0001 grams to 0.99 grams, or from 0.001 grams to 0.5 grams, or from 0.01 grams to 0.1 grams, or up to 0.1 grams. In certain embodiments, the hydrotreating catalyst (e.g., in the first and / or second hydrotreating stages) is a supported catalyst, and the support comprises at least one alumina, e.g., theta alumina, in an amount ranging from 0.1 grams to 0.99 grams, or from 0.5 grams to 0.9 grams, or from 0.6 grams to 0.8 grams, per gram of support. The amount of alumina may be determined, for example, using X-ray diffraction. In alternative embodiments, the support may comprise ≧0.1 grams, or ≧0.3 grams, or ≧0.5 grams, or ≧0.8 grams of theta alumina.

[0054] When a support is utilized, the support can be impregnated with the desired metals to form the hydrotreating catalyst. The support can be heat treated at a temperature ranging from 400°C to 1200°C, or 450°C to 1000°C, or 600°C to 900°C prior to impregnation with the metals. In certain embodiments, the hydrotreating catalyst can be formed by adding or incorporating a group 5 to group 10 metal to the shaped heat treated mixture of the support. This type of formation is commonly referred to as layering the metal on the support material. Optionally, the catalyst is heat treated after combining the support with one or more catalytic metals, for example at a temperature ranging from 150°C to 750°C, or 200°C to 740°C, or 400°C to 730°C. Optionally, the catalyst is heat treated at a temperature ranging from 400°C to 1000°C in the presence of hot air and / or oxygen-enriched air to remove volatiles such that at least a portion of the group 5 to group 10 metals are converted to their corresponding metal oxides. In other embodiments, the catalyst can be heat treated in the presence of oxygen (e.g., air) at a temperature ranging from 35°C to 500°C, or 100°C to 400°C, or 150°C to 300°C. The heat treatment can be carried out for a time ranging from 1 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 in this manner are generally referred to as "uncalcined" catalysts or "dried". Such catalysts can be prepared in combination with sulfidation techniques to substantially disperse the Group 5 to Group 10 metals in the support. When the catalyst comprises a theta alumina support and one or more Group 5 to Group 10 metals, the catalyst is generally heat treated at a temperature of ≧400°C to form a hydrotreating catalyst. Typically, such heat treatment is carried out at a temperature of ≦1200°C.

[0055] In one or more embodiments, hydrotreating catalysts typically comprise a transition metal sulfide dispersed on a high surface area support. A typical hydrotreating catalyst structure is comprised of 3% to 15% by weight of a Group 6 metal oxide and 2% to 8% by weight of a Group 8 metal oxide, and these catalysts are typically sulfided prior to use.

[0056] The catalyst may, but need not, be in a shaped form, such as, for example, one or more disks, pellets, extrudates, etc. Non-limiting examples of such shaped forms include those having cylindrical symmetry with diameters ranging from 0.79 mm to 3.2 mm, 1.3 mm to 2.5 mm, or 1.3 mm to 1.6 mm. Non-cylindrical shapes of similar size, such as trilobes, tetralobes, etc., are also contemplated herein. Optionally, the catalyst has a flat plate crush strength ranging from 50 to 500 N / cm, or 60 to 400 N / cm, or 100 to 350 N / cm, or 200 to 300 N / cm, or 220 to 280 N / cm.

[0057] Porous catalysts, including catalysts with conventional pore characteristics, are used in one or more embodiments. When porous catalysts are utilized, the catalysts can have pore structures, pore sizes, pore volumes, pore shapes, pore surface areas, etc., in the ranges characteristic of conventional hydroprocessing catalysts, but the invention is not limited thereto. Because the feedstock (e.g., pyrolysis tar) can contain fairly large molecules, catalysts with large pore sizes are preferred, especially at the reactor location where the catalyst and feedstock first come into contact. For example, the catalyst can have a median pore size effective for hydroprocessing SCT molecules, and such catalysts can have a median pore size in the range of 30 Å to 1000 Å, or 50 Å to 500 Å, or 60 Å to 300 Å. Additionally, catalysts with a bimodal pore system with pores of 150 to 250 Å and feeder pores of 250 to 1000 Å in the support are more preferred. Pore size can be determined in accordance with ASTM Method D4284-07 Mercury Intrusion Porometry.

[0058] In certain embodiments, the hydrotreating catalyst (e.g., in the first and / or second hydrotreating stages) has a median pore diameter in the range of 50 Å to 200 Å. Alternatively, the hydrotreating catalyst has a median pore diameter in the range of 90 Å to 180 Å, or 100 Å to 140 Å, or 110 Å to 130 Å. In another embodiment, the hydrotreating catalyst has a median pore diameter in the range of 50 Å to 150 Å. Alternatively, the hydrotreating catalyst has a median pore diameter in the range of 60 Å to 135 Å, or 70 Å to 120 Å. In yet another alternative, a hydrotreating catalyst having a larger median pore size is utilized, e.g., a catalyst having a median pore size in the range of 180 Å to 500 Å, or 200 Å to 300 Å, or 230 Å to 250 Å.

[0059] In general, hydrotreating catalysts have a pore size distribution that is not so large as to significantly reduce catalytic activity or selectivity. For example, hydrotreating catalysts can have a pore size distribution in which at least 60% of the pores have a pore diameter within 45 Å, 35 Å, or 25 Å of the median pore diameter. In certain embodiments, the catalyst has a median pore diameter in the range of 50 Å to 180 Å, or 60 Å to 150 Å, with at least 60% of the pores having a median pore diameter within 45 Å, 35 Å, or 25 Å.

[0060] When a porous catalyst is utilized, the catalyst may have a thickness of, for example, ≥ 0.3 cm 3 / g, e.g. ≥ 0.7 cm 3 / g, or ≥ 0.9 cm 3 In certain embodiments, the pore volume can be, for example, 0.3 cm 3 / g~0.99cm 3 / g, 0.4cm 3 / g~0.8cm 3 / g, or 0.5 cm 3 / g~0.7cm 3 / g.

[0061] In certain embodiments, a relatively large surface area may be desirable. As an example, a hydroprocessing catalyst may have a surface area of ​​≥ 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, 100m 2 / g~300m 2 / g, or 120m 2 / g~270m 2 / g, or 130m 2 / g~250m 2 / g, or 170m 2 / g~220m 2 The nanoparticles can have a surface area in the range of 1 / g.

[0062] Conventional hydrotreating catalysts used in hydrotreating steps can be used, but the invention is not limited thereto. In certain embodiments, the catalyst includes one or more KF860 available from Albemarle Catalysts Company LP, Houston, Texas; Nebula catalysts available from the same supplier, such as Nebula 20; Centera catalysts available from Criterion Catalysts and Technologies, Houston, Texas; Ascent catalysts available from the same supplier, such as one or more DC-2618, DN-2630, DC-2635 and DN-3636; Ascent catalysts available from the same supplier, such as one or more DC-2532, DC-2534, DN-3531; and FCC pretreatment catalysts available from the same supplier, such as DN3651 and / or DN3551. However, the invention is not limited to these catalysts.

[0063] In a particular embodiment, the catalyst in the first hydrotreating stage is amorphous Al 2 O 3 and / or SiO 2Examples of catalysts for use in the hydrotreating stage include Ni-Co-Mo / Al2O3 supported on ASA, where hydrotreating may be the first process applied to hydrocarbon pyrolysis tars. 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, e.g., Fe-Mo supported on non-acidic supports such as carbon black and carbon black composites, or, e.g., TiO 2 Or Al 2 O 3 / TiO 2 and Mo supported on a non-acidic support such as

[0064] In certain embodiments, the catalyst in the second hydrotreating stage may comprise one or more zeolites or Co, Mo, P, Ni, Pd supported on ASA and / or zeolites. Examples of catalysts used in the second hydrotreating stage are USY or VUSY zeolites Y, Co-Mo / Al 2 O 3 , Ni-Co-Mo / Al 2 O 3 , Pd / ASA-zeolite Y. The catalyst in each hydrotreating stage can be selected independently of the catalyst used in the other hydrotreating stages, for example, a RT-228 catalyst can be used in the first hydrotreating stage and a RT-621 catalyst can be used in the second hydrotreating stage.

[0065] In some embodiments, the S and N content of the feedstock is too high and when certain catalysts (e.g., zeolites) are used in the hydrotreating step, e.g., Co-Mo / Al 2 O 3 A guard bed containing an inexpensive and readily available catalyst such as 2 S and NH 3However, if a zeolite catalyst is used in the second reactor, guard beds may not be necessary since the sulfur and nitrogen levels have already been reduced in the first reactor. 3 and H 2 The step of separating S and S can still be applied to the products of both the first and second hydrotreating stages, if desired.

[0066] In another particular embodiment, the catalyst in the first hydrotreating stage may comprise mainly one or more zeolites or Co, Mo, P, Ni, Pd supported on ASA and / or zeolites, and the catalyst in the second hydrotreating stage may comprise amorphous Al. 2 O 3 and / or SiO 2 In this configuration, exemplary catalysts for use in the first hydrotreating stage include 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 hydrotreatment step 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, or TiO, for example, supported on a non-acidic support such as carbon black or a carbon black composite. 2 Or Al 2 O 3 / TiO 2The catalyst for each hydrotreating stage can be selected independently of the catalysts used in the other hydrotreating stages, e.g., a RT-621 catalyst can be used in the first hydrotreating stage and a RT-228 catalyst can be used in the second hydrotreating stage.

[0067] In another embodiment, the catalyst in the first hydrotreating stage may be the same catalyst or perform a similar function as the catalyst in the second hydrotreating stage.

[0068] Delayed coking An exemplary embodiment includes feeding at least a portion of the hydrotreated product to a delayed coking unit. After hydrotreating, the hydrotreated product has a low sulfur concentration, e.g., 1.5 wt%, 1 wt%, 0.5 wt%, 0.1 wt%, or less, and an increased level of three- and four-ring aromatic molecules, which are desirable for the production of needle coke. In the delayed coking unit, the hydrotreated product is processed by delayed coking to produce a coke effluent in the form of coke as well as liquid and vapor products. Delayed coking of the hydrotreated product is carried out by converting a portion of the hydrotreated product into more valuable hydrocarbon products. Depending on its grade, the resulting coke has value as a fuel (fuel grade coke), electrodes for aluminum production (anode grade coke), etc. According to this embodiment, the coke includes needle coke.

[0069] In some embodiments, the hydroprocessed product is co-fed with a conventional coker feed to a delayed coking unit. Examples of suitable conventional coker feedstocks include, but are not limited to, decant oil, vacuum gas oil, atmospheric residue, and coal tar pitch. The conventional coker feed may be co-fed in any suitable ratio, including a ratio of hydroprocessed product to coker feed of about 5:95 to 95:5, 25:75 to 75:25, or 40:60 to 60:40.

[0070] In some embodiments, the hydrotreated product is preheated and then directed to a coking zone. The hydrotreated product is preheated to any temperature suitable for coking, for example, a temperature between 480°C and 570°C. In some embodiments, preheating includes passing the hydrotreated product through a furnace. In some embodiments, preheating includes pumping the hydrotreated product to the bottom of a coke fractionator and then to a furnace. The preheated hydrotreated product is passed from the furnace to a coking zone. In some embodiments, the coking zone includes a coking vessel, such as, for example, a vertically oriented, insulated coker vessel, often referred to as a coking drum. For example, the preheated hydrotreated product is passed from the furnace to the coking drum through an inlet at the bottom of the drum. According to this embodiment, the coking zone (e.g., the coking drum) is operated at coking conditions. Examples of coking conditions in the coking zone include, for example, pressures ranging from 100 kPa to 1200 kPa, 100 kPa to 550 kPa, or 100 kPa to 240 kPa. Higher pressures can also be used. For example, the coking conditions in the coking zone can be as high as 1200 kPa to 8000 kPa. Typical operating temperatures in the coking zone are 400°C to 550°C, 400°C to 475°C, or 450°C to 475°C. The preheated hydrotreated product pyrolyzes in the coke over a period of time (the "coking time") and releases volatiles, comprised primarily of hydrocarbon products, which continuously rise through the coke bed, comprised of channels, pores, and passages, and are collected at the top as coker effluent. The coking time varies, for example, with temperature and pressure. In some embodiments, the coking time is 5 hours to 48 hours, or 8 hours to 16 hours.

[0071] In some embodiments, the coker effluent is directed to a coker fractionator for distillation and recovery of fluid coker products including coker gas, coker naphtha, coker distillate, and coker gas oil. Such fractions can usually, but not always, be used after upgrading to blend fuel and lubricant products, such as, for example, motor gasoline, motor diesel, fuel oil, and lubricant. The upgrading can include separation, removal of heteroatoms by hydrotreating and non-hydrotreating processes, dearomatization, and solvent extraction, and the like. Coker gas includes, for example, a mixture of hydrocarbons containing one to four carbon atoms, as well as hydrocarbons and carbon dioxide. Coker gas includes, for example, light coker gas oil, heavy coker gas oil. In some embodiments, at least a portion of the heavy coker gas oil in the coker effluent introduced to the coker fractionator can be captured for recycling and mixed with a fresh feed of hydroprocessing products, thereby forming a coker heater or coker furnace charge. In some embodiments, there is no recycle, and in some embodiments, the recycle of heavy gas oil can be up to 200% by volume of the hydrotreated product, for example, recycling heavy gas oil in an amount of 5% to 35% by volume of the hydrotreated product.

[0072] In addition to the volatile products, the process also results in the accumulation of coke in the coking zone (e.g., the coking vessel). Periodically, for example, when a predetermined amount of coke accumulation is obtained, the preheated hydroprocessing product is switched to another coking vessel and the hydrocarbon vapors are purged from the coking vessel with steam. In some embodiments, the coking vessel is then cooled with water to reduce the temperature below 150°C, for example to between 95°C and 150°C, after which the water is drained. When the draining step is complete, the drum is opened and the coke is removed, for example, by drilling and / or cutting using high-velocity water jets ("hydraulic decoking"). As previously mentioned, the coke produced in the delayed coking of the hydroprocessing product includes needle coke.

[0073] Needle Coke Needle coke is produced by delayed coking of the hydrotreating product from the SATC process. For example, the coke product produced by delayed coking comprises about 20 wt%, 25 wt%, 35 wt%, 40 wt%, 50 wt%, 60 wt%, or more of needle coke. In some embodiments, the coke product comprises needle coke in an amount between 25 wt% and 60 wt%. Needle coke is a type of coke formed by delayed coking and has a needle-like anisotropic microstructure. When observed under a microscope, a fibrous structure is observed in the needle coke. Needle coke can be converted to graphite for use in electrodes by a graphitization process that includes heating to high temperatures of over 2000°C. Electrodes made from needle coke are used in electric arc furnaces to melt steel, as well as in the anode of lithium batteries.

[0074] The specific composition of the needle coke depends on many factors, including the specific coke conditions, such as, for example, delayed coking conditions and feed composition. In some embodiments, the needle coke contains carbon in an amount of 80% to 98% by weight based on the total weight of the coke. Since the (>90%) hydroprocessed product is low in sulfur, the needle coke will also be low in sulfur. For example, the needle coke contains sulfur in an amount of ≦1.5 wt%, ≦1 wt%, ≦0.5 wt%, ≦0.4 wt%, or ≦0.1 wt%. In addition, the needle coke should have a low ash content. For example, the needle coke has an ash content of about <0.4, <0.2, <0.1, or less.

[0075] Typical Configuration 1 shows an exemplary single-stage hydroprocessing system 100 for hydroprocessing hydrocarbon pyrolysis tars. In the illustrated embodiment, a tar feed 102 comprising the hydrocarbon pyrolysis tars to be processed (e.g., steam cracker tar) is mixed with a recycle fluid 104 comprising a utility fluid to form a feedstock 106. Although not shown, in addition to the recycle fluid 104, make-up utility fluids may also be used. The feedstock 106 is then pumped by a pump 108 through a filter 110. The filter 110 may be, for example, a filter bed or a filter medium. 2 S / NH 3 The process includes removing hydrogen from the feedstock 106. A treat 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" in that after combining with the treat gas 112, it has been enriched with hydrogen to contain more hydrogen. Molecular hydrogen may be added to the feedstock 106 in any suitable ratio, for example, to convert H 2 The partial pressure can be maintained at 4820kpa to 10350kpa.

[0076] 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 to a hydrotreating reactor 120 that includes a hydrotreating catalyst. While FIG. 1 illustrates introducing a hydrogen-rich feedstock 114 that includes hydrocarbon pyrolysis tar, utility fluids, and hydrogen in an incorporated stream, it should be understood that embodiments include separately introducing one or more of these components to the hydrotreating reactor 120. For example, at least a portion of the treat gas 112 can be introduced to the hydrotreating reactor 120 for intermediate cooling. The single-stage hydrotreating system 100 includes only one hydrotreating reactor 120 and is therefore considered to have a single hydrotreating stage. The hydrotreating reactor 120 can be operated at any suitable hydrotreating conditions, as described above. In the hydrotreating reactor 120, the hydrocarbon pyrolysis tar is hydrotreated by contacting it with at least one hydrotreating catalyst in the presence of a utility fluid and hydrogen to form a hydrotreated product. A hydrotreated effluent 122 containing the hydrotreated product is directed from the hydrotreating reactor 120 through a first heat exchanger 116 to a separator (or separator) 124 (e.g., a distillation column). In the separator 124, the hydrotreated product 122 is separated from the hydrotreated effluent 122, and the recycle fluid 104 is reused for mixing with the tar feed 102. Although not shown, an additional separator (e.g., a flash drum) may be used, for example, to remove hydrogen from the hydrotreated effluent 122. Advantageously, the hydrotreated product 123 has desirable properties, such as high concentrations of three- and four-ring aromatic molecules and low sulfur, so that it can be coked to form needle coke that is less foul and produces a higher yield of needle coke than coking of unhydrotreated hydrocarbon pyrolysis tar.

[0077] FIG. 2 illustrates an example of a multi-stage hydrotreating system 200. In the illustrated embodiment, a tar feed 202 containing a hydrocarbon pyrolysis tar (e.g., steam cracker tar) to be treated is mixed with a recycle stream 204 containing a utility fluid to form a feedstock 206. The feedstock 206 is fed to a first hydrotreating reactor 208 containing a hydrotreating catalyst. Optionally, the feedstock 206 stream may first be heated in a first heat exchanger 210. A treat 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" in that the hydrogen has been enriched to contain more hydrogen after mixing with the treat gas. The molecular hydrogen may be, for example, hydrogen from a H 2 O 3 mixture in the first hydrotreating reactor 208 at 4820 kpa to 10350 kpa. 2 It can be added to the feedstock 206 in any suitable ratio to maintain the partial pressure. The hydrogen-rich feedstock 214 then passes through a second heat exchanger 216 and then through a feed heater 218 to preheat the hydrogen-rich feedstock 214. The preheated hydrogen-rich feedstock 214 is then fed to a first heat exchanger 208 containing a hydrotreating catalyst. While FIG. 2 illustrates introducing a hydrogen-rich feedstock 214 containing hydrocarbon pyrolysis tars, utility fluids, and hydrogen in an incorporated stream, it should be understood that embodiments include separately introducing one or more of these components to the first hydrotreating reactor 208. For example, at least a portion of the treat gas 212 can be introduced to the first hydrotreating reactor 208 for intermediate cooling. The first hydrotreating reactor 208 can be operated at any suitable hydrotreating conditions, as described above. In the first hydrotreating reactor 208, the hydrocarbon pyrolysis tar is hydrotreated by contacting it with at least one hydrotreating catalyst in the presence of a utility fluid and hydrogen to form a first hydrotreated product. A first stage hydrotreated effluent 222 comprising the first hydrotreated product is directed from the first hydrotreating reactor 208 through a second heat exchanger 216.

[0078] The first stage hydrotreated effluent 222 is cooled in a second heat exchanger 216 (e.g., by cross-exchange with the hydrogen-rich feedstock 214). Following cooling, the first stage hydrotreated effluent 222 is directed to a first separator 224 for separating a first stage vapor product 226 (e.g., heteroatom vapor, vapor phase cracked products, unused process gas, etc.) and a first stage liquid effluent 228 from the first stage hydrotreated effluent 222. In one embodiment, the first separator 224 is a flash drum. The first stage vapor product 226 is optionally directed to an amine column 230 (e.g., H 2 S scrubber), which is essentially H 2 A fresh amine 234 (e.g., monoethanolamine, methyldiethanolamine, diethanolamine, etc.) is fed to amine column 230, which produces an improved S-free process gas stream 232 (e.g., hydrogen). 2 A rich amine 236 containing S is withdrawn from amine column 230. At least a portion of improved treat gas stream 232 is optionally withdrawn from amine column 230, compressed in compressor 238, and reused during hydroprocessing in the first and / or second stages, e.g., as treat gas 212. Start-up or make-up gases, e.g., molecular hydrogen, for the process can be obtained from feed treat gas stream 240, e.g., mixed with treat gas 212, as needed. In some embodiments, a light gas purge stream 242 is optionally removed from improved treat gas stream 232.

[0079] In the illustrated embodiment, the first-stage liquid effluent 228 containing the first hydrogenation treatment 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, a mid-cut stream 248, and a bottom stream 250. The overhead stream 246 contains, for example, 1 wt% to 20 wt% of the first hydrogenation treatment product. The mid-cut stream 248 contains, for example, 20 wt% to 70 wt% of the first hydrogenation treatment product. The bottom stream 250 contains 10 wt% to 60 wt% of the first hydrogenation treatment product. According to this embodiment, the mid-cut stream 248 is recycled as a recycle fluid 204 for use as a utility fluid in the first stage and / or removed as a separate mid-cut product stream 252.

[0080] As shown, the bottom stream 250 is pumped to the second stage via a pump 251 where it is mixed, for example, with a second-stage treatment gas stream 254 from the treatment gas 212 and heated in a fourth heat exchanger 256 before being supplied to a second hydrogenation treatment reactor 258 containing one or more hydrogenation treatment catalysts. The catalysts used in the first and second hydrogenation treatment reactors 208, 258 may be the same or different. While FIG. 2 shows introducing into the bottom stream 250 hydrogen in a stream combined with at least a portion of the hydrogenation treatment product, embodiments are to be understood to include introducing one or more of these components separately into the second hydrogenation treatment reactor 258. For example, at least a portion of the second-stage treatment gas stream 254 can be introduced into the second hydrogenation treatment reactor 258 for intermediate cooling. The second hydrogenation treatment reactor 258 can be operated under any suitable hydrogenation treatment conditions as described above. In the second hydrogenation treatment reactor 258, at least a portion of the hydrogenation treatment product is hydrogenated by contacting with at least one hydrogenation treatment catalyst in the presence of hydrogen to form a second hydrogenation treatment product.

[0081] The second stage hydroprocessing effluent 259, including the second hydroprocessing product, is introduced from the second hydroprocessing reactor 258 to a third separator 260 for separation of a vapor stream 262 (e.g., heteroatom vapor, vapor phase cracked products, unused process gas, etc.) and a second stage liquid effluent 264 (e.g., second hydroprocessing product) from the second stage hydroprocessing effluent 259. In one embodiment, the third separator 260 is a flash drum. The vapor stream 262 is optionally cooled in a fifth heat exchanger 266 and then optionally passed to further separation in a fourth separator 268 for separation of a second stage vapor product stream 270 and an additional liquid product stream 271. The second stage vapor product stream 270 is optionally directed to the amine column 230 and may optionally be mixed with the first stage vapor product 226.

[0082] The second stage liquid effluent 264 and additional liquid product stream 271 are then provided to a fifth separator 272 (e.g., a distillation column) which separates a second stage product overhead stream 274 and a second stage liquid product stream 276. The second stage liquid product stream 276 comprises at least a portion of the second hydroprocessed product. Advantageously, the second hydroprocessed product has desirable properties, such as high concentrations of three- 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 than coking of non-hydrotreated hydrocarbon pyrolysis tar.

[0083] FIG. 3 shows an exemplary system 300 for producing needle coke. In the illustrated embodiment, a tar feed 301 containing a hydrocarbon pyrolysis tar (e.g., steam cracker tar) to be treated is fed to a hydrotreating stage 302. In the hydrotreating stage, the hydrocarbon pyrolysis tar is contacted with at least one hydrotreating catalyst in at least one or more hydrotreating stages to form a hydrotreating product. In at least one of the one or more hydrotreating stages, the hydrocarbon pyrolysis tar is contacted with at least one hydrotreating catalyst in the presence of a utility fluid. A liquid product stream 304 containing the hydrotreating product is then sent to a delayed coking stage 306. In the delayed coking stage 306, for example, the hydrotreating product is preheated and then coked. In some embodiments, preheating the hydrotreated product includes introducing the hydrotreated product into a coker fractionator 308 and then removing a fractionator effluent 310 comprising at least a portion of the hydrotreated product from the coker fractionator 308 to a coker furnace 312. A preheated effluent 314 comprising the preheated hydrotreated product is sent from the coker furnace 312 to a coking zone 316, which may comprise, for example, a coking vessel or a coking drum. The preheated effluent 314 also comprises a bottoms (or recycle). The coking zone 316 is a zone in which the preheated hydrotreated product is thermally cracked in the coking zone over a period of time (the "coking time") and the released volatiles, comprised primarily of hydrocarbon products, are comprised of channels, pores, and pathways that continuously rise through the coke bed and are collected overhead as coker effluent 318, which is sent to the coker fractionator 308. In the illustrated embodiment, the coker effluent 318 is separated in the coker fractionator 308 into various fractions including, but not limited to, a coker gas fraction 322, a coker naphtha fraction 324, a coker distillate fraction 326, and a coker gas oil fraction 328. As previously mentioned, coke accumulates in the coking zone 316 (e.g., a coking vessel). The coke comprises needle coke. A coke product 320 comprising needle coke is removed from the coking zone 316.

[0084] Additional Embodiments Accordingly, the present disclosure provides for the preparation of needle coke from a hydrocarbon liquid. The methods and systems include any of the various features disclosed herein, including one or more of the following:

[0085] Embodiment 1. A method for producing needle coke 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 hydrotreated 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 has an initial boiling point of about 200° C. or greater at atmospheric pressure according to ASTM 7500, and wherein the hydrocarbon liquid comprises about 50 wt.% or greater aromatics content; and coking at least a portion of the hydrotreated product to form a coker effluent and coke, wherein the coke comprises needle coke.

[0086] Embodiment 2. The method of embodiment 1, wherein the hydrocarbon liquid comprises hydrocarbon pyrolysis tar.

[0087]

[0023] Embodiment 3. The method of embodiment 1 or embodiment 2, wherein the hydrocarbon liquid comprises a hydrocarbon pyrolysis tar having an initial boiling point of about 200° C. or more as determined in accordance with ASTM D7500, and the hydrocarbon pyrolysis tar comprises about 50% by weight or more of aromatic compounds having 15 or more carbon atoms.

[0088]

[0023] Embodiment 4. The method of any preceding embodiment, wherein the hydrocarbon liquid comprises steam cracker tar.

[0089]

[0023] Embodiment 5. The method of any of the previous embodiments, wherein the hydrocarbon liquid comprises sulfur in an amount between about 3% and about 4.5% by weight, and the needle coke comprises sulfur in an amount not greater than about 0.5% by weight.

[0090]

[0023] Embodiment 6. The method of any preceding embodiment, wherein the hydrotreated product has a sulfur content of about 0.5 wt.% or less.

[0091] Embodiment 7. The method of any preceding embodiment, wherein the hydroprocessed product comprises three- and four-ring aromatic compounds in a combined amount of about 70 wt.% or greater.

[0092] Embodiment 8. The method of any of the previous embodiments, wherein the hydrotreated product has an initial boiling point at atmospheric pressure of 200° C. to 400° C. and an end point at atmospheric pressure of 500° C. to 700° C., as determined in accordance with ASTM 7500, and the hydrotreated product has a BMCI of about 90 to about 160.

[0093] Embodiment 9. The method of any preceding embodiment, wherein the utility fluid comprises at least a portion of an intermediate-stage hydroprocessing product that is recycled for combination with the hydrocarbon liquids.

[0094] Embodiment 10. The method of any preceding embodiment, wherein the utility fluid has a solubility mixing number of about 100 or greater.

[0095] Embodiment 11. The method of any preceding embodiment, wherein the utility fluid comprises aromatic compounds in an amount of about 25% by weight or greater.

[0096]

[0023] Embodiment 12. The method of any preceding embodiment, wherein the needle coke comprises sulfur in an amount of about 0.5% by weight or less.

[0097]

[0023] Embodiment 13. The method of any preceding embodiment, wherein the needle coke comprises sulfur in an amount of about 0.1% by weight or less.

[0098]

[0023] Embodiment 14. The method of any preceding embodiment, wherein the coke product comprises the needle coke in an amount of about 25% to about 60% by weight.

[0099] Embodiment 15. The method of any of the preceding embodiments, wherein said hydrotreating comprises hydrotreating said hydrocarbon liquid in a first hydrotreating stage in the presence of said utility fluid to produce a first stage hydrotreating effluent, separating at least a first stage hydrotreating product from said first stage hydrotreating effluent, hydrotreating at least a portion of the first stage hydrotreating product in a second hydrotreating stage to produce a second stage hydrotreating effluent, and separating at least a second stage hydrotreating product from the second stage hydrotreating effluent, wherein said second stage hydrotreating product comprises said hydrotreating product.

[0100] Embodiment 16. The method of any of the preceding embodiments, wherein coking at least a portion of a hydrotreated product comprises feeding the hydrotreated product to a coker fractionator; heating at least a portion of a fractionator effluent from the coker fractionator in a coker furnace; pyrolyzing the fractionator effluent in a coking vessel to form at least a coker effluent and the coke product; and feeding the coker effluent to a coker fractionator for separation into two or more fractions, wherein the fractionator effluent comprises at least a portion of the hydrotreated product.

[0101] Embodiment 17. A method for producing needle coke, comprising: contacting a feedstock in the presence of molecular hydrogen with at least one first-stage hydrogenation treatment catalyst to hydrogenate the feedstock containing steam cracker tar and a utility fluid in a first hydrogenation treatment stage to produce a first-stage hydrogenation treatment effluent, wherein the steam cracker tar has an initial boiling point of about 200 °C or higher as determined in accordance with ASTM D7500, the steam cracker tar contains aromatic compounds having 15 or more carbon atoms in an amount of about 50% by weight, the utility fluid has a solubility parameter of about 100 or more and contains aromatic compounds in an amount of about 25% by weight or more; separating at least a first-stage hydrogenation treatment product from the first-stage hydrogenation treatment effluent; contacting at least a portion of the first-stage hydrogenation treatment product with at least a portion of a second-stage hydrogenation treatment catalyst in the presence of additional molecular hydrogen to hydrogenate at least a portion of the first-stage hydrogenation treatment product in a second hydrogenation treatment stage to produce a second-stage hydrogenation treatment effluent, wherein the second hydrogenation treatment product contains a sulfur content of about 0.5% by weight or less and has a BMCI of about 90 to about 160, and the second hydrogenation treatment product has an initial boiling point of 300 °C to 400 °C and an end point of 500 °C to 600 °C at atmospheric pressure as determined in accordance with ASTM 7500; coking at least a portion of the second-stage hydrogenation treatment product to form at least a coke effluent and needle coke, wherein the needle coke contains sulfur in an amount of 0.5% by weight or less.

[0102] Embodiment 18. The method of embodiment 17, wherein separating at least the first stage hydrotreated product from the first stage hydrotreated effluent comprises separating the first stage hydrotreated effluent in one or more stages to form at least: (i) an overhead stream comprising at least about 1 wt.% of the first hydrotreated product; (ii) a midcut stream comprising at least about 20 wt.% of the first hydrotreated product and having a boiling point distribution, as measured in accordance with ASTM D7500, between about 120° C. and about 480° C.; and (iii) a bottoms stream comprising at least about 10 wt.% of the first hydrotreated product, wherein at least a portion of the bottoms stream is hydrotreated in the second hydrotreatment stage.

[0103] Embodiment 19. The method of embodiment 18, further comprising recycling at least a portion of said mid-cut stream for use as at least a portion of said utility fluid in said first hydroprocessing stage.

[0104] Embodiment 20. The method of any one of embodiments 17-19, wherein the coking comprises: feeding the hydrotreated product to a coker fractionator; heating at least a portion of a fractionator effluent from a coker fractionator in a coker furnace, the fractionator effluent comprising at least a portion of the second stage hydrotreated product; pyrolyzing the fractionator effluent in a coking vessel to form at least a coker effluent and the coke product; and feeding the coker effluent to the coker fractionator for separation into two or more fractions. EXAMPLES

[0105] Working Example Example 1 - Tar Hydrotreatment (SATC Process) The following example was carried out to illustrate the upgrading of hydrocarbon pyrolysis tar to hydroprocessed products. In this example, the density of the tar was 1.16 g / cm 3 The steam cracker tar with a density of 0.94 g / cm 3The combined feed was directed to a two-stage fixed bed reactor, which was operated at 400° C. in the first reactor stage, 370° C. in the second reactor stage, 1100 psi (7584 kpa) and 1.0 h. -1 The first reactor was operated at a WHSV of 1000 scfb. The hydrogen to mixed feed ratio for both runs was provided at 3000 scfb. The total liquid product from the second reactor was distilled to form the SATC product for analysis. The fractions boiling between 340° C. and 620° C. were combined and used for the needle coke run in Example 2.

[0106] The properties of the hydrotreated steam cracker tar product before and after hydrotreatment are shown in the table below. [Table 1]

[0107] Example 2 - Hydrotreatment of Decant Oil For comparison purposes, the decant oil was hydrotreated (without utility fluids) with the resulting hydrotreated decant oil used in the needle coke experiment in Example 3. The decant oil was a mixture of low and high sulfur decant oils from at least four different refineries. The decant oil was hydrotreated using a sulfided NiMo catalyst at 390 °C in a reactor maintained at 2400 psia of hydrogen. The liquid hourly space velocity was 0.4 h -1 The total liquid product was fractionally distilled to remove the 350°C minus components and the heavier fraction was used for needle coke experiments.

[0108] The properties of the hydrotreated decant oil product before and after hydrotreatment are shown in the table below. [Table 2]

[0109] Example 3 - Needle Coke Product The following examples were conducted to illustrate the production of needle coke from hydrocarbon liquids, such as, for example, hydrocarbon pyrolysis tar. Approximately 3-4 grams of hydrotreated steam cracker tar product from Example 1 was fed to a laboratory-scale batch coker reactor that was maintained at a delayed condition of 500°C for 5 hours by autothermal pressure. The laboratory-scale batch coker reactor is shown in FIG. 4, reference number 400. The reactor was filled with aluminum foil tubes to facilitate the recovery of the semi-coke product. At the end of each run, the reactor was air / water cooled to room temperature and depressurized after sampling of headspace gas. After opening the reactor, dichloromethane was used to wash the semi-coke and inside of the reactor and the liquid product was recovered. After evaporating the dichloromethane, the weight of the recovered semi-coke was measured. Two runs were conducted with the hydrotreated steam cracker tar product. For comparison purposes, a conventional delayed coker feed was also tested. This conventional delayed coker feed was the hydrotreated decant oil product from Example 2.

[0110] The yields of hydrotreated steam cracker tar and hydrotreated decant oil product from each run are shown in Table 3 below. [Table 3]

[0111] Both the hydrotreated steam cracker and hydrotreated decant oil products produced cohesive coke cylinders upon carbonization. Furthermore, optical images of the coke obtained from both samples showed needle-like structures, indicating the production of needle coke. The needle coke for the hydrotreated steam cracker product was low in sulfur, as the sulfur content of the hydrotreated steam cracker tar product was 0.105 wt%.

[0112] Although compositions, methods, and processes are described herein in terms of "comprising," "containing," "having," or "including" various components or steps, the compositions and methods can also "essentially consist of" or "consist of" the various components and steps. Unless otherwise specified, the terms "consists essentially of" and "consisting essentially of" do not exclude the presence of other steps, elements, or materials, whether or not specifically mentioned herein, that do not affect the basic and novel characteristics of the disclosure, and further do not exclude impurities and variations normally associated with the elements and materials used.

[0113] All numerical values ​​in the detailed description are modified by "about" the indicated value to take into account experimental error and variations that would be expected by one of ordinary skill in the art.

[0114] Numerous changes, modifications, and variations will be apparent to those of ordinary skill in the art in light of the foregoing description without departing from the spirit or scope of the present disclosure, and where numerical lower limits and numerical upper limits are recited herein, ranges from any lower limit to any upper limit are contemplated.

Claims

1. 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, 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; the hydrocarbon liquid has an initial boiling point of greater than or equal to about 200° C. at atmospheric pressure according to ASTM 7500; the hydrocarbon liquid having an aromatic content of about 50% by weight or greater; coking at least a portion of the hydroprocessing product to form a coker effluent and coke, the coke comprising needle coke; A method for producing needle coke comprising the steps of:

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

3. 3. The method of claim 1 or 2, wherein the hydrocarbon liquid comprises a hydrocarbon pyrolysis tar having an initial boiling point of about 200° C. or more as determined in accordance with ASTM D7500, and the hydrocarbon pyrolysis tar comprises aromatic compounds having 15 or more carbon atoms in an amount of about 50% by weight or more.

4. 3. The method of claim 1 or 2, wherein the hydrocarbon liquid comprises steam cracker tar.

5. 3. The method of claim 1 or 2, wherein the hydrocarbon liquid comprises sulfur in an amount of about 3 wt.% to about 4.5 wt.% and the needle coke comprises sulfur in an amount of about 0.5 wt.% or less.

6. 3. The process of claim 1 or 2, wherein the hydrotreated product has a sulfur content of about 0.5 wt.% or less.

7. 3. The process of claim 1 or 2, wherein the hydroprocessed product comprises three-ring and four-ring aromatic compounds in a combined amount of about 70 wt.% or greater.

8. 3. The method of claim 1 or 2, wherein the hydrotreated product has an initial boiling point of from 200° C. to 400° C. at atmospheric pressure and an end point of from 500° C. to 700° C. at atmospheric pressure, as determined in accordance with ASTM 7500, and the hydrotreated product has a BMCI of from about 90 to about 160.

9. 3. The method of claim 1 or 2, wherein the utility fluid comprises at least a portion of an intermediate stage hydroprocessing product that is recycled for mixing with the hydrocarbon liquids.

10. 3. The method of claim 1 or 2, wherein the utility fluid has a solubility mixing number of about 100 or greater, and the utility fluid comprises aromatic compounds in an amount of about 25% by weight or greater.

11. 3. The method of claim 1 or 2, wherein the needle coke comprises sulfur in an amount of about 0.5 wt.% or less.

12. 3. The method of claim 1 or 2, wherein the needle coke contains sulfur in an amount of about 0.1 wt.% or less.

13. 3. The method of claim 1 or 2, wherein the coke product comprises the needle coke in an amount of about 2.5% to about 60% by weight.

14. The hydrotreating step comprises: hydrotreating the hydrocarbon liquid in a first hydrotreating stage in the presence of the utility fluid to produce a first stage hydrotreated effluent; separating at least a first stage hydroprocessing product from said first stage hydroprocessing effluent; hydrotreating at least a portion of the first stage hydroprocessed product in a second hydroprocessing stage to produce a second stage hydroprocessed effluent; separating at least a second stage hydroprocessing product from said second stage hydroprocessing effluent, said second stage hydroprocessing product comprising a hydroprocessed product; The method according to claim 1 or 2, comprising:

15. Coking at least a portion of the hydrotreated product comprises: feeding the hydrotreated product to a coker fractionator; heating at least a portion of a fractionator effluent from the coker fractionator in a coker furnace, the fractionator effluent comprising at least a portion of the hydrotreated product; pyrolyzing the fractionator effluent in a coking vessel to form at least a coker effluent and a coke product; feeding said coker effluent to said coker fractionator for separation into two or more fractions; The method according to claim 1 or 2, comprising:

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