WO2019164611A1 - Système d'hydrotraitement d'huile lourde - Google Patents

Système d'hydrotraitement d'huile lourde Download PDF

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WO2019164611A1
WO2019164611A1 PCT/US2019/014266 US2019014266W WO2019164611A1 WO 2019164611 A1 WO2019164611 A1 WO 2019164611A1 US 2019014266 W US2019014266 W US 2019014266W WO 2019164611 A1 WO2019164611 A1 WO 2019164611A1
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solvent
hydroprocessing
product
slurry
aromatic
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PCT/US2019/014266
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English (en)
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James R. Lattner
John S. COLEMAN
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Exxonmobil Chemical Patents Inc.
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Publication of WO2019164611A1 publication Critical patent/WO2019164611A1/fr

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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
    • C10G49/10—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00 with moving solid particles
    • C10G49/12—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00 with moving solid particles suspended in the oil, e.g. slurries
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/003—Solvent de-asphalting
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
    • C10G21/12—Organic compounds only
    • C10G21/14—Hydrocarbons
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/28—Recovery of used solvent
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
    • C10G47/24—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles
    • C10G47/26—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles suspended in the oil, e.g. slurries
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
    • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
    • C10G67/04—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including solvent extraction as the refining step in the absence of hydrogen
    • C10G67/0454—Solvent desasphalting
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1055—Diesel having a boiling range of about 230 - 330 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1059—Gasoil having a boiling range of about 330 - 427 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1077—Vacuum residues
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1096—Aromatics or polyaromatics
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/301—Boiling range
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/80—Additives

Definitions

  • This invention relates to methods for reducing reactor fouling during fluidized hydroprocessing of heavy oils and/or heavy hydrocarbon fractions.
  • Heavy oil fractions that include a substantial portion of vacuum resid boiling range compounds can pose a variety of challenges for refinery processing.
  • Conventional processes for hydrotreatment of heavy oil fractions are challenged by reactor fouling and plugging.
  • Processes such as Axens’s“H-OilTM and UOP’s
  • Slurry Hydrocracking technologies attempt to overcome these difficulties by utilizing high hydrogen pressures (>125 bar) and non- fixed bed reactors (either ebullating or slurry reactors).
  • Slurry hydroconversion provides a method for conversion of high boiling, low value petroleum fractions into higher value liquid products.
  • Slurry hydroconversion technology can process difficult feeds, such as feeds with high Conradson carbon residue (CCR) while still maintaining high liquid yields.
  • CCR Conradson carbon residue
  • slurry hydroconversion units have been demonstrated to process other challenging streams present in refinery / petrochemical complexes such as deasphalted rock, steam cracked tar, and visbreaker tar.
  • slurry hydroconversion is also an expensive refinery process from both a capital investment standpoint and a hydrogen consumption standpoint.
  • Various slurry hydroconversion configurations have previously been described. For example, U.S. Patent No. 5,755,955 and U.S.
  • Patent Application Publication No. 2010/01222939 provide examples of configurations for performing slurry hydroconversion.
  • U.S. Patent Application Publication No. 2011/0210045 also describes examples of configurations for slurry hydroconversion, including examples of configurations where the heavy oil feed is diluted with a stream having a lower boiling point range, such as a vacuum gas oil stream and/or catalytic cracking slurry oil stream, and examples of configurations where a bottoms portion of the product from slurry hydroconversion is recycled to the slurry hydroconversion reactor.
  • U.S. Patent No.7,941,313 describes methods for processing a heavy oil feed using a catalyst system including two catalysts with different pore size ranges.
  • the heavy oil feed can be exposed to the two catalysts in any convenient type of reactor, such as an ebullating bed reactor.
  • steam cracking can be used to upgrade heavy hydrocarbon feeds such as vacuum resids.
  • Steam cracking is beneficial in that it converts feedstocks into lighter compounds, such as light olefins, without requiring additional of hydrogen as is the case with hydroprocessing.
  • Steam cracking vacuum resid boiling-range feeds typically results in a greater amount of coke accumulation in the steam cracker than is the case with lighter hydrocarbon feeds (e.g., ethane, naphtha, etc.).
  • systems and methods are provided for hydroprocessing of feeds including a heavy oil fraction, such as feeds including a ⁇ l050°F+ ( ⁇ 566°C+) fraction.
  • the systems and methods can facilitate processing of feeds including a heavy oil fraction in a fluidized hydroprocessing environment while reducing or minimizing hydrogen consumption during the hydroprocessing.
  • This beneficial combination can be achieved, in part, by performing the hydroprocessing in the presence of a solvent with a sufficient aromatic carbon content to reduce or minimize precipitation of insoluble compounds within the fluidized hydroprocessing environment.
  • the reduction in precipitation of insoluble compounds can result in a corresponding reduction in coke formation and/or other fouling within the reaction environment.
  • the reduced or minimized amount of coke formation and/or fouling can be achieved while performing the fluidized hydroprocessing at reduced hydrogen partial pressures, which can lead to correspondingly lower hydrogen consumption during the hydroprocessing.
  • a resulting light phase portion of the products from the hydroprocessing can be suitable for use as a feed for other refinery processes, such as steam cracking.
  • the heavy phase portion of the products at least a portion of the heavy phase can be used as the aromatic solvent for the fluidized hydroprocessing.
  • FIG. 1 shows an example of a fluidized hydroprocessing system that includes a slurry hydroprocessing reactor.
  • FIG. 2 shows an example of possible dependence of a continuous phase in a reaction environment on an amount of a heavy phase and a light phase.
  • systems and methods are provided for hydroprocessing of feeds including a heavy oils, such as feeds that include hydrocarbon compounds having a normal boiling points > l050°F ( ⁇ 566°C).
  • a heavy oils such as feeds that include hydrocarbon compounds having a normal boiling points > l050°F ( ⁇ 566°C).
  • These heavy oils are typically identified as a l050°F+ fraction (or 566°C+ fraction), even when the heavy oil is not a distilled fraction (e.g., not vaporized and then condensed), as may be the case when the heavy oil includes non-boiling oleaginous residue (“resid”) conducted away as bottoms from an atmospheric or vacuum distillation tower.
  • the specified systems and methods can facilitate processing of feeds including a heavy oil fraction in a fluidized hydroprocessing environment while lessening or minimizing hydrogen consumption during the hydroprocessing.
  • a feed including a ⁇ 566°C+ fraction can then be upgraded for use, for example, as a feed for steam
  • Heavy oils such as those found in the bottoms products from atmospheric or vacuum crude pipestill bottoms (but also streams such as steam-cracked tar), contain many molecules with multi-ring aromatic cores with alkyl and alkyl-naphthenic appendages or side- chains.
  • the molecules when present in a crude oil are generally“self-compatible”; that is, all molecules are mutually soluble in the crude oil. Hydrogenation of molecules lowers their density and makes them poorer solvents for multi-ring aromatic compounds.
  • a common problem in hydrotreating is that some molecules hydrogenate faster than others, such that the hydrogenated molecules no longer have sufficient solvent power to keep the less-hydrogenated molecules in solution.
  • the multi-ring aromatic cores tend to hydrogenate more slowly and will come out of solution first.
  • one or more of the above difficulties can be overcome by processing a heavy oil feed under relatively low-severity fluidized hydroprocessing conditions.
  • these upgraded compounds can be more easily steam cracked or hydroprocessed with less coke formation and/or reactor fouling or plugging than would be the case if the heavy oil itself were used as feed to conventional steam cracking or conventional hydroprocessing.
  • the processing of the heavy oil feed under the specified lower-severity hydroprocessing conditions is facilitated by the presence of at least one aromatic solvent during the fluidized hydroprocessing.
  • the fluidized hydroprocessing can be performed under conditions that roughly correspond to having a heavy continuous phase that includes a majority of the aromatic solvent.
  • the heavy continuous phase which includes a majority of the aromatic solvent, is believed to maintain solubility of the multi-ring cores present in the feed even though conversion reactions are occurring to form a lighter phase with less favorable solubility properties.
  • the lighter phase can correspond to a distributed or suspended phase within the heavy continuous phase.
  • the amount of the aromatics-containing solvent which beneficially can be introduced with the heavy oil feed, can correspond to 40 wt. % or more of solvent relative to the total weight of the feed, or 50 wt. % or more, or 60 wt. % or more, such as up to 80 wt. % or possibly still higher.
  • the resulting effluent (the“hydroprocessed effluent”) from the fluidized hydroprocessing environment can undergo one or more separations to generate at least a light phase product and a heavy phase product.
  • the separations can include extraction, such as solvent extraction using a second solvent having a lesser aromatic content than the first solvent.
  • a first separation can correspond to mixing the hydroprocessed effluent with the second solvent (e.g., one having a lesser content of aromatic carbon) to extract a light (primarily non-aromatic) compounds from hydroprocessed effluent.
  • a raffinate comprising the remaining portion of the hydroprocessed effluent after the extraction comprises the heavy phase product.
  • a second separation can be used, if desired, to remove entrained catalyst from one or more of the hydroprocessed effluent, the extract, or the raffinate.
  • the first solvent comprises a recycled portion of the heavy phase product.
  • at least a portion of the first solvent can include compounds (typically aromatic) that are removed from the heavy phase product and have normal boiling points in the same range as that of the first solvent. It is noted that any portions of the aromatic solvent that are saturated (or partially saturated) during the fluidized hydroprocessing can form a portion of the light phase product, while non-saturated portions of the aromatic solvent can be recycled again for further use as aromatic solvent.
  • fluidized hydroprocessing environments examples include a slurry hydroprocessing environment, a fluidized bed hydroprocessing environment, or an ebullating bed hydroprocessing environment.
  • fluidized hydroprocessing environments are distinct from fixed bed or trickle bed hydroprocessing environments, as well as other hydroprocessing environments where the hydroprocessing catalyst maintains a relatively stable or constant position during hydroprocessing.
  • the first solvent includes at least a portion of the heavy phase generated during the hydroprocessing in the fluidized hydroprocessing environment, e.g., at least a portion of the heavy phase product.
  • a mixture of compounds having a normal boiling point range in substantially the same range as the first solvent can be removed from the heavy phase product as a recycle stream to be added to (or even used in place of) the first solvent.
  • the remainder of the heavy phase product following removal of the recycle stream can, for example, be used as a fuel oil component; recycled for further exposure to fluidized hydroprocessing conditions; and/or used in any other convenient manner.
  • the lighter phase products are also suitable for many beneficial uses.
  • the lighter phase product can be used in chemical processing, such as steam cracking; fuels processing, including fuels blending, and lubricating oil processing, including lubricating oil blending.
  • aromatic refers to unsaturated compounds with at least one closed ring of at least 6 atoms, with all of the ring atoms being co-planar or almost co-planar and covalently linked, and with all of the ring atoms being part of a mesomeric system.
  • aromatic hydrocarbons refers to molecules containing one or more aromatic rings. Examples of aromatic hydrocarbons are benzene, toluene, xylenes, naphthalene, and methylnaphthalenes.
  • aromatic carbons refers to carbon atoms within an aromatic compound that are part of the mesomeric system.
  • the weight percent or mole percent of aromatic carbons within a sample can be identified by using nuclear magnetic resonance (NMR) spectroscopy according to standard methods, such as ASTM D5292. In the event that a sample is not suitable for characterization under ASTM D5292, another convenient standard method of performing proton NMR or 13 C NMR may be used.
  • NMR nuclear magnetic resonance
  • the amount of aromatic carbons in a sample or fraction can be described as a percentage of the total carbons in the sample. For convenience, the percent of aromatic carbons in a sample or fraction is described herein as a mole%.
  • the term“C n ” hydrocarbon refers to a hydrocarbon with“n” carbon atoms
  • “C n - C m hydrocarbons” represents hydrocarbons having between“n” and“m” carbon atoms
  • “C n+ hydrocarbons” represents hydrocarbons having n or more carbon atoms
  • “C n ” aromatic refers to an aromatic hydrocarbon with“n” carbon atoms
  • “C n -C m aromatics” represents aromatic hydrocarbon having between“n” and“m” carbon atoms
  • “C n+ aromatics” represents aromatic hydrocarbons having n or more carbon atoms. It is noted that toluene corresponds to a C 7 aromatic.
  • the term“catalyst” refers to a material, which under certain conditions of temperature or pressure increases the rate of specific chemical reactions.
  • a catalyst may also be a material that performs as a physisorbent or chemisorbent for specific components of the feed stream.
  • the term“chain length” may broadly refer to a number of atoms forming and/or making a backbone and/or structure of a molecule and/or compound, such as carbon atoms for a hydrocarbon.
  • chemical reaction refers to any process including the breaking or making of chemical bonds including a dissociation, recombination, or rearrangement of atoms.
  • hydrocarbons formed primarily of carbon and hydrogen atoms.
  • the hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, or sulfur.
  • Hydrocarbons derived from an oil bearing formation may include, but are not limited to, kerogen, bitumen, pyrobitumen, asphaltenes, resins, oils, or combinations thereof.
  • higher hydrocarbons refers to hydrocarbon(s) having more than one carbon atom per molecule, oxygenate having at least one carbon atom per molecule, e.g., ethane, ethylene, propane, propylene, benzene, toluene, xylenes, naphthalene, and/or methyl naphthalene; and/or organic compound(s) including at least one carbon atom and at least one non-hydrogen atom, e.g., methanol, ethanol, methylamine, and/or ethylamine.
  • hydrocarbon refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon- containing materials include any form of natural gas, oil, coal, and bitumen.
  • hydrocarbon stream refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
  • hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure).
  • Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state
  • zeolite is defined to refer to a crystalline material having a porous framework structure built from tetrahedra atoms connected by bridging oxygen atoms. Examples of certain zeolite frameworks are given in the“Atlas of Zeolite Frameworks” published on behalf of the Structure Commission of the International Zeolite Association”, 6 th revised edition, Ch. Baerlocher, L.B. McCusker, D.H. Olson, eds., Elsevier, New York (2007) and the corresponding web site, http://www.iza-strueture.org/databases/.
  • a zeolite can refer to aluminosilicates having a zeolitic framework type as well as crystalline structures containing oxides of heteroatoms different from silicon and aluminum.
  • heteroatoms can include any heteroatom generally known to be suitable for inclusion in a zeolitic framework, such as gallium, boron, germanium, phosphorus, zinc, and/or other transition metals that can substitute for silicon and/or aluminum in a zeolitic framework.
  • a 343 °C- product corresponds to a product that contains components with a normal boiling point (at standard temperature and pressure) of 343°C or less.
  • a 343°C+ product corresponds to a product that contains components with a normal boiling point of 343 °C or more.
  • Conversion relative to a temperature can be defined based on the portion of the feedstock having a boiling point that under conversion conditions exceeds the conversion temperature.
  • the amount of conversion during a process can correspond to the weight percentage of the feedstock converted from boiling above the conversion temperature to boiling below the conversion temperature.
  • a feedstock that includes 40 wt. % of components that boil at l050°F ( ⁇ 566°C) or greater.
  • the remaining 60 wt. % of the feedstock boils at less than l050°F ( ⁇ 566°C).
  • the amount of conversion relative to a conversion temperature of ⁇ 566°C would be based only on the 40 wt. % that initially boils at ⁇ 566°C or greater. If such a feedstock could be exposed to a process with 30% conversion relative to a ⁇ 566°C conversion temperature, the resulting product would include 72 wt. % of ⁇ 566°C- components and 28 wt. % of ⁇ 566°C+ components.
  • One way of defining a feedstock, solvent, or other type of hydrocarbon fraction can be based on the boiling range of the feed.
  • One option for defining a boiling range is to use an initial boiling point for a feed and/or a final boiling point for a feed.
  • Another option, which in some instances may provide a more representative description of a feed is to characterize a feed based on the amount of the feed that boils at one or more temperatures. For example, a “T5” boiling point for a feed is defined as the temperature at which 5 wt. % of the feed will boil off. Similarly, a“T95” boiling point is a temperature at 95 wt. % of the feed will boil.
  • boiling points can be determined according to ASTM D2887.
  • ASTM D7169 may be used instead.
  • the term“boiling point” means unless otherwise noted a normal boiling point
  • “boiling range” or“boiling point range” means unless otherwise noted a range of normal boiling points.
  • an aromatic-containing first solvent is introduced into the fluidized hydroprocessing environment.
  • the aromatic solvent can have a boiling range of roughly 400°F ( ⁇ 204°C) to 750°F ( ⁇ 400°C). This can correspond to, for example, having a T10 distillation point of 204°C or higher, or a T5 distillation point of 204°C or higher and/or a T90 distillation point of 400°C or less, or a T95 distillation point of 400°C or less.
  • the aromatic solvent can have a T10 distillation point of roughly 450°F ( ⁇ 232°C) or more.
  • Aromatic solvents with substantial amounts of components having boiling points ⁇ 204°C can potentially exhibit decreased solvency for components of the heavy oil feed, which can lead to feed incompatibility problems during the specified fluidized hydroprocessing.
  • Aromatic solvents with substantial amounts of components having boiling points > 400°C can potentially may have an undesirable sulfur content and may also have a viscosity that is sufficiently large as to pose problems with removal of catalyst solids after hydroprocessing.
  • the aromatic solvent can have a kinematic viscosity at 50°C of 10 cSt or less, or 5.0 cSt or less. Additionally or alternately, the aromatic solvent can have a density at l5°C of 0.97 g/cm 3 or more, or 0.98 g/cm 3 or more, or 1.00 g/cm 3 or more.
  • a suitable first solvent can be selected based on the solubility number (SBN) of the first solvent relative to the insolubility number (IN) of the resulting heavy phase product generated during the fluidized hydroprocessing. For example, it is observed that particulate precipitation from the heavy phase product can be lessened when the first solvent has an SBN that is at least 15 solvency units (“SU”) greater than that of the heavy phase product’ s IN, or at least 20 SU greater, or at least 25 SU greater, such as up to 60 SU greater, or possibly still more.
  • the aromatic solvent can have a SBN of 60 SU or more, or 70 SU or more, or 80 SU or more, such as up to 120 SU, or possibly still higher.
  • the SU values corresponding to the solubility number (SBN) and the insolubility number (IN) are values that can be used to characterize the solubility properties of a petroleum fraction.
  • the determination of IN and SBN for a petroleum oil containing asphaltenes, such as a heavy oil comprising resid requires testing the solubility of the oil in test liquid mixtures at the minimum of two volume ratios of oil to test liquid mixture.
  • the test liquid mixtures are prepared by mixing two liquids in various proportions. One liquid is nonpolar (test solvent A), and is a solvent for the asphaltenes in the oil. The other liquid is nonpolar (test solvent B), and is a nonsolvent for the asphaltenes in the oil.
  • Test solvent A is typically toluene
  • test solvent B is typically n-heptane.
  • a convenient volume ratio of oil to test liquid mixture is selected for the first test, for instance, 1 ml. of oil to 5 ml. of test liquid mixture. Then various mixtures of the test liquid mixture are prepared by blending n-heptane and toluene in various known proportions. Each of these is mixed with the oil at the selected volume ratio of oil to test liquid mixture. Then it is determined for each of these if the asphaltenes are soluble or insoluble. Any convenient method might be used. For example, a drop of the blend of test liquid mixture and oil can be observed between a glass slide and a glass cover slip using transmitted light with an optical microscope at a magnification of from 50 to 600x.
  • asphaltenes are in solution, few, if any, dark particles will be observed. If the asphaltenes are insoluble, many dark, usually brownish, particles, usually 0.5 to 10 microns in size, will be observed.
  • the results of blending oil with all of the test liquid mixtures are ordered according to increasing percent toluene in the test liquid mixture. The desired value will be between the minimum percent toluene that dissolves asphaltenes and the maximum percent toluene that precipitates asphaltenes. More test liquid mixtures are prepared with percent toluene in between these limits, blended with oil at the selected oil to test liquid mixture volume ratio, and determined if the asphaltenes are soluble or insoluble.
  • the desired value will be between the minimum percent toluene that dissolves asphaltenes and the maximum percent toluene that precipitates asphaltenes. This process is continued until the desired value is determined within the desired accuracy. Finally, the desired value is taken to be the mean of the minimum percent toluene that dissolves asphaltenes and the maximum percent toluene that precipitates asphaltenes. This is the first datum point, Ti, at the selected oil to test liquid mixture volume ratio, Ri. This test is called the toluene equivalence test.
  • the second datum point can be determined by the same process as the first datum point, only by selecting a different volume ratio of oil to test liquid mixture. Alternatively, a percent toluene below that determined for the first datum point can be selected and that test liquid mixture can be added to a known volume of oil until asphaltenes just begin to precipitate. At that point the volume ratio of oil to test liquid mixture, R 2 , at the selected percent toluene in the test liquid mixture, T 2 , becomes the second datum point. Since the accuracy of the final numbers increase as the further apart the second datum point is from the first datum point, the preferred test liquid mixture for determining the second datum point is 0% toluene or 100% n- heptane. This test is called the heptane dilution test.
  • the insolubility number, IN is defined as:
  • the first solvent can include 40 mole % or more of aromatic carbons, or 50 mole % or more, or 60 mole % or more, such as up to 75 mole % or possibly still higher.
  • the aromatic carbon content of the first solvent can be determined according to ASTM D5186.
  • the first solvent can correspond to the boiling range for diesel fuel. Although utilizing diesel fuel as the first solvent is not required, it can be beneficial to do so, e.g., when first starting the specified hydroprocessing (e.g., before sufficient first solvent is available from a recycle stream), or as make-up when insufficient recycle is available during continued hydroprocessing.
  • the first solvent includes a recycled portion of the heavy phase product generated during fluidized hydroprocessing of a heavy oil feedstock.
  • the distillation cut points for the recycled portion can be adjusted to provide a suitable density and/or a suitable boiling range and/or a suitable SBN.
  • feedstock obtained from a suitable source (“Feedstock”).
  • feedstock a heavy oil feed obtained from a suitable source
  • feedstocks will now be described in more detail. The invention is not limited to these feedstocks, and this description should not be interpreted as for closing other feedstocks within the broader scope of the invention.
  • a wide range of petroleum and chemical heavy oil feedstocks can be processed using fluidized hydroprocessing conditions.
  • Suitable feedstocks include whole and reduced petroleum crudes, atmospheric and vacuum residua, propane deasphalted residua, e.g., brightstock, and various other types of heavy oils.
  • heavy oils include, but are not limited to, heavy crude oils, distillation residues, heavy oils coming from catalytic treatment (such as heavy cycle bottom slurry oils from fluid catalytic cracking), thermal tars (such as oils from visbreaking, steam cracking, or similar thermal or non-catalytic processes), oils (such as bitumen) from oil sands and heavy oils derived from coal.
  • Heavy oil feedstocks can be liquid or semi-solid.
  • heavy oils that can be hydroprocessed, treated or upgraded according to this invention include bitumens and residuum from refinery distillation processes, including atmospheric and vacuum distillation processes.
  • Such heavy oils can have an initial boiling point of 650°F (343 °C) or greater.
  • the heavy oils will have a 10% distillation point of at least 650°F (343 °C), alternatively at least 660°F (349°C) or at least 750°F (399°C).
  • the 10% distillation point can be still greater, such as at least 900°F (482°C), or at least 950°F (5l0°C), or at least 975°F (524°C), or at least l020°F (549°C) or at least l050°F (566°C).
  • the 566°C+ feed can correspond to 10 wt. % or more of the feed (i.e., a T90 of 566°C or higher), or 30 wt. % or more (a T70 of 566°C or higher), or 50 wt. % or more (a T50 of 566°C or higher), or 70 wt. % or more (a T30 of 566°C or higher), such as a feed that is substantially composed of 566°C+ components (a T10 of 566°C or higher, or a T5 of 566°C or higher).
  • Density, or weight per volume, of the heavy hydrocarbon can be determined according to ASTM D287 - 92 (2006) Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), and is provided in terms of API gravity. In general, the higher the API gravity, the less dense the oil. API gravity is 20° or less in one aspect, 15° or less in another aspect, and 10° or less in another aspect. Additionally or alternately, the density of the feed at l5°C can be 0.93 g/cm 3 or more, or 0.97 g/cm 3 or more, or 1.00 g/cm 3 or more.
  • the density can be 1.00 g/cm 3 or more, or 1.02 g/cm 3 or more, or 1.04 g/cm 3 or more, such as up to 1.15 g/cm 3 or possibly still higher.
  • Suitable heavy oil feedstocks include those that have a relatively large content of metals.
  • the heavy oil can be high in total nickel, vanadium and iron contents.
  • the heavy oil will contain at least 0.00005 grams of Ni/V/Fe (50 ppm) or at least 0.0002 grams of Ni/V/Fe (200 ppm) per gram of heavy oil, on a total elemental basis of nickel, vanadium and iron.
  • Suitable heavy oil feedstocks also include those that have a relatively large content of nitrogen and sulfur, e.g., nitrogen and/or sulfur in organically-bound form.
  • Nitrogen content can range from about 50 wppm to about 10,000 wppm elemental nitrogen or more, based on total weight of the heavy hydrocarbon component.
  • the nitrogen containing compounds can be present as basic or non-basic nitrogen species. Examples of basic nitrogen species include quinolines and substituted quinolines. Examples of non-basic nitrogen species include carbazoles and substituted carbazoles.
  • suitable heavy oil feedstocks include those containing at least 500 wppm elemental sulfur, based on total weight of the heavy oil.
  • the sulfur content of such heavy oils, typically present as organically-bound sulfur is generally in the range from about 500 wppm to about 100,000 wppm (on an elemental sulfur basis), or from about 1000 wppm to about 50,000 wppm, or from about 1000 wppm to about 30,000 wppm, based on total weight of the heavy oil.
  • Sulfur will usually be present as organically bound sulfur.
  • sulfur compounds examples include the class of heterocyclic sulfur compounds such as thiophenes, tetrahydro thiophenes, benzothiophenes and their higher homologs and analogs.
  • Other organically bound sulfur compounds include aliphatic, naphthenic, and aromatic mercaptans, sulfides, and di- and poly sulfides.
  • the heavy oil feedstock comprise a relatively large amount of n-pentane asphaltenes.
  • the heavy oil contains at least about 5 wt. % of n-pentane asphaltenes, such as at least about 10 wt. % or at least 15 wt. % n-pentane asphaltenes.
  • the heavy oil feedstock can comprise a relatively large amount of Conradson carbon residue.
  • the Conradson carbon residue of the feedstock can be at least about 5 wt. %, such as at least about 10 wt. % or at least about 20 wt. %. Additionally or alternately, the Conradson carbon residue of the feedstock can be about 50 wt. % or less, such as about 40 wt. % or less or about 30 wt. % or less.
  • the specified heavy oil feed is subjected to the specified fluidized hydroprocessing in the presence of the specified first solvent.
  • the first solvent and feed can be introduced into the hydroprocessing in any convenient manner For example, they can be introduced by one or more of (i) combining substantially all of the feed with substantially all of the first solvent to produce feed-solvent mixture A, and then introducing feed-solvent mixture A into the hydroprocessing, (ii) combining a first portion of the feed with substantially all of the first solvent to produce feed- solvent mixture B, and then introducing feed- solvent mixture B at a first location in the hydroprocessing and other portion(s) of the feed at other location(s) in the hydroprocessing, and (iii) combining a first portion of the first solvent with substantially all of the feed to produce feed-solvent mixture C, and then introducing feed- solvent mixture C at a first location in the hydroprocessing and other portion(s) of the feed at other location(s) in the hydroprocessing.
  • Hydrogen typically in the form of molecular hydrogen in a
  • Representative hydroprocessing conditions can include, e.g., one or more of slurry hydroprocessing conditions, fluidized bed hydroprocessing conditions, ebullating bed hydroprocessing conditions.
  • the fluidized hydroprocessing includes exposing a first solvent and a feed comprising heavy oil feed to a hydroprocessing catalyst in a fluidized processing environment to produce a hydroprocessed effluent that includes a heavy phase product and a light phase product. It is typical to combine the feed and first solvent upstream of the hydroprocessor to produce a combined feed, and then introduce the combined feed into the hydroprocessor.
  • the amount of first solvent introduced into the fluidized processing environment can correspond to 40 wt. % or more of the combined feed, or 50 wt. % or more, or 60 wt. % or more, such as up to 80 wt. % or possibly still higher.
  • the feed and first solvent can be introduced as a combined feed, it is not strictly necessary for the feed and first solvent to be introduced into the fluidized hydroprocessing environment as a fully mixed and/or fully combined feed.
  • the feed and first solvent can be introduced in any convenient manner, so long as they are well-mixed when in proximity to the catalyst.
  • the fluidized hydroprocessing conditions can correspond to conditions that are effective for at least partial conversion of the l050°F+ (566°C+) portion of the feed while being mild enough to reduce or minimize hydrogen consumption due to aromatic saturation.
  • the fluidized hydroprocessing conditions can result in conversion of 10 wt. % to 80 wt. % of the feed relative to 566°C, or 10 wt. % to 60 wt. %, or 25 wt. % to 80 wt. %, or 25 wt. % to 60 wt. %, or 50 wt. % to 90 wt. %, or 50 wt. % to 80 wt. %.
  • the fluidized hydroprocessing produces and hydroprocessed effluent comprising a light phase product and a heavy phase product.
  • the light phase product typically comprises a majority of the hydroprocessed effluent’s paraffins, naphthenes, and l-ring aromatic components, while the heavy phase product typically comprises a majority of the hydroprocessed effluent’s multi-ring aromatics.
  • the light phase product can have an aromatic carbon content of 20 mole % or less relative to a total carbon content of the light phase product, or 15 mole % or less, or 10 mole % or less. This can reflect the primarily paraffinic and/or naphthenic nature of the light phase product, with only a minor portion of single-ring aromatic cores.
  • the heavy phase product can have an aromatic carbon content of 50 mole % or more relative to a total carbon content of the heavy phase product, or 60 mole % or more, or 70 mole % or more, such as up to 90 mole %, or possibly still higher.
  • the elevated amounts of aromatic carbons present in the heavy phase product can indicate the reduced or minimized hydrogen consumption when performing fluidized hydroprocessing under lower hydrogen partial pressure conditions.
  • the aromatic carbon content of the heavy phase product can be characterized relative to the aromatic carbon content of the resid boiling range portions of the heavy oil feedstock.
  • the aromatic carbon content of the heavy phase product (relative to the total carbon content of the heavy phase product) can be greater than the aromatic carbon content of the heavy oil feedstock (relative to the total carbon content of the heavy oil feedstock) by 5 mole % or more, or 10 mole % or more, or 20 mole %, or more.
  • the portion of the heavy phase product used for recycle corresponds to a selected boiling range, so that the aromatic content of that portion of the first solvent as is recycled from the heavy phase product may have a lesser aromatics content than the overall heavy phase product.
  • FIG. 1 shows an example of a reaction system suitable for performing fluidized hydroprocessing under hydroprocessing conditions with a reduced or minimized hydrogen partial pressure.
  • the fluidized hydroprocessing conditions correspond to slurry hydroprocessing conditions.
  • a heavy oil feedstock 105 is mixed with an aromatic solvent 152 prior to entering one or more slurry hydroprocessing reactors 120.
  • the mixture of feedstock 105 and aromatic solvent 152 can be heated (not shown) prior to entering reactor 120 in order to achieve a desired temperature for the slurry hydroprocessing reaction.
  • a hydrogen stream 101 is also fed into reactor 120.
  • a portion of feedstock 105 and/or aromatic solvent 152 can be mixed with hydrogen stream 101 prior to hydrogen stream 101 entering reactor 120.
  • catalyst for the slurry hydroprocessing is introduced into reactor 120 as a catalyst makeup stream 112. Catalyst is withdrawn via catalyst withdrawal stream 117.
  • the majority of the catalyst does not become entrained in hydroprocessed effluent 125.
  • the catalyst in the slurry hydroprocessing environment may be entrained with the feed / product flow. It is noted that having a catalyst that is not entrained in the feed / product flow can be more common in other types of fluidized processing environments, such as an ebullating bed hydroprocessing environment.
  • an additional catalyst separation or removal stage (not shown) can be used to separate catalyst from the hydroprocessed effluent 125 and/or the heavy phase portion 135 of the hydroprocessed effluent and/or the heavy phase product 155.
  • some light ends can be formed, which are shown as being separately removed from reactor 120 as an off-gas stream 127.
  • the hydroprocessed effluent 125 is passed into one or more separation stages.
  • an initial separation stage 130 can correspond to a counter-current solvent separator that uses a second solvent (a low-aromatic carbon content solvent having a lesser content of aromatic carbon than the first solvent) to extract a light phase portion 132 of the hydroprocessed effluent 125.
  • the light phase portion can comprise, e.g., paraffins, naphthenes, and/or l-ring aromatic components extracted from the hydroprocessed effluent.
  • the heavy phase portion namely a raffinate comprising what remains of hydroprocessed effluent 125 after extraction of the light phase portion, is conducted away from stage 130 via line 135.
  • stage 130 operates in a manner similar to a solvent deasphalter.
  • sufficient amounts of the second solvent can be introduced into separation stage 130 so that a continuous light phase is formed in at least some locations within separation stage 130.
  • Recovery of the at least a portion of the second solvent is carried out in stage 140, e.g., by fractionation. Recovered second solvent can be recycled to stage 130 via line 143. A light phase product is also recovered in stage 140, and is conducted away via line 145.
  • the first solvent recycle 152 and the heavy phase product 155 are recovered from the raffinate of line 135 in stage 150 for separation of the aromatic solvent 152 from the heavy phase product 155.
  • slurry hydroprocessing can be performed by processing a feed in one or more slurry hydroprocessing reactors.
  • the reaction conditions in a slurry hydroprocessing reactor can vary based on the nature of the catalyst, the nature of the feed, the desired products, and/or the desired amount of conversion.
  • suitable catalyst concentrations can range from about 50 wppm to about 20,000 wppm (or about 2 wt. %), depending on the nature of the catalyst.
  • catalyst can be incorporated into a hydrocarbon feedstock directly, or the catalyst can be incorporated into a side or slip stream of feed and then combined with the main flow of feedstock.
  • Still another option is to form catalyst in-situ by introducing a catalyst precursor into a feed (or a side/slip stream of feed) and forming catalyst by a subsequent reaction.
  • catalyst can be introduced separately into the reactor(s), as shown in FIG. 1.
  • Catalytically active metals for use in the specified hydroprocessing can include those from Group IVB, Group VB, Group VIB, Group VIIB, or Group VIII of the Periodic Table.
  • suitable metals include iron, nickel, molybdenum, vanadium, tungsten, cobalt, ruthenium, and mixtures thereof.
  • the catalytically active metal may be present as a solid particulate in elemental form or as an organic compound or an inorganic compound such as a sulfide (e.g., iron sulfide) or other ionic compound.
  • Metal or metal compound nanoaggregates may also be used to form the solid particulates.
  • the catalyst can be in the form of a solid particulate, e.g., a particulate comprising a compound of a catalytically active metal, or a metal in elemental form, either alone or supported on a refractory material such as an inorganic metal oxide (e.g., alumina, silica, titania, zirconia, and mixtures thereof).
  • a refractory material such as an inorganic metal oxide (e.g., alumina, silica, titania, zirconia, and mixtures thereof).
  • suitable refractory materials can include carbon, coal, and clays.
  • Zeolites and non-zeolitic molecular sieves are also useful as solid supports.
  • One advantage of using a support is its ability to act as a "coke getter" or adsorbent of asphaltene precursors that might otherwise lead to fouling of process equipment.
  • catalyst for slurry hydroprocessing in situ such as forming catalyst from a metal sulfate (e.g., iron sulfate monohydrate) catalyst precursor or another type of catalyst precursor that decomposes or reacts in the hydroprocessing reaction zone environment, or in a pretreatment step, to form a desired, well-dispersed and catalytically active solid particulate (e.g., as iron sulfide).
  • a metal sulfate e.g., iron sulfate monohydrate
  • catalyst precursors e.g., iron sulfate monohydrate
  • a desired, well-dispersed and catalytically active solid particulate e.g., as iron sulfide
  • Precursors also include oil-soluble organometallic compounds containing the catalytically active metal of interest that thermally decompose to form the solid particulate (e.g., iron sulfide) having catalytic activity.
  • Suitable precursors include metal oxides that may be converted to catalytically active (or more catalytically active) compounds such as metal sulfides.
  • a metal oxide containing mineral may be used as a precursor of a solid particulate comprising the catalytically active metal (e.g., iron sulfide) on an inorganic refractory metal oxide support (e.g., alumina).
  • the reaction conditions within a slurry hydroprocessing reactor can include a temperature of about 375°C to about 450°C, or about 400°C to about 425°C.
  • the hydrogen partial pressure within the reactor can correspond to a pressure for mild hydroprocessing, such as a hydrogen partial pressure of about 1.0 MPa-g to about 8.0 MPa-g, or about 1.0 MPa-g to about 5.0 MPa-g, or about 1.0 MPa-g to about 4.5 MPa-g. Since the catalyst is in slurry form within the feedstock, the space velocity for a slurry hydroprocessing reactor can be characterized based on the volume of feed processed relative to the volume of the reactor used for processing the feed.
  • Suitable space velocities for slurry hydroprocessing can range, for example, from about 0.05 v/v/hr 1 to about 5 v/v/hr 1 , such as about 0.1 v/v/hr 1 to about 2 v/v/hr 1 .
  • multiple slurry hydroprocessing stages and/or reactors can be used for conversion of a feed.
  • the effluent from a first slurry hydroprocessing stage can be fractionated to separate out one or more product fractions.
  • the feed can be fractionated to separate out one or more naphtha fractions and/or distillate fuel (such as diesel) fractions.
  • Such a fractionation can also separate out lower boiling compounds, such as compounds containing 4 carbons or less and contaminant gases such as tTS or NFb.
  • the remaining higher boiling fraction of the feed can have a boiling range roughly corresponding to an atmospheric resid, such as a 10 wt.
  • using multiple stages of slurry hydroconversion reactors can allow for selection of different processing conditions in the stages and/or reactors.
  • the temperature in the first slurry hydroconversion reactor can be lower than the temperature in a second reactor.
  • the second effective hydroprocessing conditions for use in the second slurry hydroconversion reactor can include a temperature that is at least about 5°C greater than a temperature for the first effective slurry hydroprocessing conditions in the first reactor, or at least about l0°C greater, or at least about !5°C greater, or at least about 20°C greater, or at least about 30°C greater, or at least about 40°C greater, or at least about 50°C greater.
  • the catalyst for the slurry hydroconversion can be passed between reactors with a single recycle loop.
  • catalyst is separated from the heavy product fraction of the final hydroconversion stage and then at least partially recycled to an earlier hydroconversion stage.
  • a separate catalyst recycle loop can be used for at least one slurry hydroconversion stage.
  • the slurry catalyst can be separated from the heavy portion of the effluent from each reactor. The separated catalyst from the first reactor can then be recycled back to the first reactor, the separated catalyst from the second reactor can be recycled back to the second reactor, and separated catalyst from each additional reactor (if any) can be recycled to the corresponding reactor.
  • Still another option is to have multiple catalyst separations and recycle loops, but to have fewer recycle loops than the total number of reactors.
  • a first reactor can have a separate catalyst recycle loop, while catalyst can be passed between a second and third reactor, with catalyst separated from the product effluent of the third reactor and recycled (at least in part) back to the second reactor.
  • the amount of solvent introduced as part of the combined feed can be sufficient to allow the fluidized hydroprocessing environment to correspond to a heavy continuous phase.
  • the continuous heavy phase can include a majority of the aromatic solvent, such as 60 wt. % or more of the aromatic solvent, or 70 wt. % or more, or 80 wt. % or more.
  • the heavy phase can also include any l050°F+ (566°C+) components in the reaction environment, such as unreacted feedstock.
  • the heavy phase can further include a majority of the aromatic cores in the reaction environment.
  • a way to avoid reactor fouling can be to improve the ability of the reaction environment to maintain the aromatic cores in solution. This can be achieved by adding a sufficient amount of an aromatic solvent that is suitable for maintaining the aromatic cores in solution. In addition to providing additional solvating power, providing a sufficient amount of solvent can also allow a continuous phase to be formed that is suitable for solvating the aromatic cores.
  • FIG. 2 schematically shows an example of how the amount of the first solvent can impact the continuous phase present in a fluidized hydroprocessing environment, such as a slurry hydroprocessing environment.
  • a fluidized hydroprocessing environment such as a slurry hydroprocessing environment.
  • FIG. 2 a generic hydroprocessing environment having a heavy phase and a light phase is represented.
  • the horizontal axis corresponds to the amount of mixing used.
  • a continuous phase corresponding to the heavy phase / light phase can be formed.
  • Adding the first solvent contributes to forming a heavy phase, which drives the hydroprocessing reaction environment toward having a continuous heavy phase.
  • removing the light phase extract from the hydroprocessed effluent and conducting away the heavy phase raffinate can be carried out in a manner similar to that of solvent deasphalter and/or another type of solvent extraction process.
  • Suitable second solvents for separating the light phase effluent from the heavy phase effluent can correspond to paraffinic and/or naphthenic solvents, with a preference for paraffinic solvents and/or solvents having an aromatic carbon content of 15 mole % or less, or 10 mole % or less, or 5 mole % or less, such as down to substantially no aromatic carbon content (i.e., 0.5 mole% or less).
  • suitable solvents can correspond to light paraffinic solvents, such as alkanes or other hydrocarbons (such as alkenes) containing 4 to 7 carbons per molecule.
  • suitable solvents include n-butane, isobutane, n-pentane, C 4+ alkanes, C + alkanes, C 4+ hydrocarbons, and C 5+ hydrocarbons.
  • One or more of these compounds can be used when starting the process, e.g., before a sufficient amount of the second solvent is available for recovery and recycle; or as make-up when the amount of recovered second solvent is insufficient during operation.
  • the second solvent typically comprises alkane compounds, e.g., alkanes comprising C n (hydrocarbons), where the term C n (hydrocarbons) means a solvent composed of at least 80 wt. % of alkanes (hydrocarbons) having n carbon atoms, or at least 85 wt. %, or at least 90 wt. %, or at least 95 wt. %, or at least 98 wt. %.
  • a second solvent comprising C n+ (hydrocarbons) is defined as a solvent composed of at least 80 wt. % of alkanes (hydrocarbons) having n or more carbon atoms, or at least 85 wt. %, or at least 90 wt. %, or at least 95 wt. %, or at least 98 wt. %.
  • One type of product stream can be a light phase product stream that includes a majority of the (paraffinic) solvent. At least a portion of the second solvent is typically recovered from the light phase product, such as by distillation, for recycle and re-use of the recovered second solvent for extraction of the light phase.
  • a raffinate (the second type of product stream) includes the remaining portion of the hydroprocessed effluent, namely the portion that is not soluble in the second solvent.
  • the raffinate corresponds to the heavy phase portion of the hydroprocessed effluent, including a majority of any unreacted first solvent, a majority of the multi-ring products generated during the fluidized hydroprocessing, and a majority of any unreacted multi -ring aromatics from the initial feed.
  • compounds in the hydroprocessed effluent (light phase) that are soluble in the second solvent are extracted, leaving behind a raffinate (heavy phase) with little or no solubility in the second solvent.
  • Typical solvent extraction conditions include mixing the hydroprocessed effluent with the second solvent in a weight ratio (second solvent : hydroprocessed effluent) of from about 1 : 2 to about 1 : 10, such as about 1 : 8 or less.
  • the extraction is carried out under extraction conditions which include a temperature in the range of from 40°C to 200°C, or 40°C to l50°C; and a total pressure in the range of from 50 psig (345 kPa-g) to about 500 psig (-3500 kPa-g).
  • Extraction conditions are typically pre-selected, and are based at least in part on the composition of the hydroprocessed effluent and the composition of the second solvent.
  • the extract typically comprises the second solvent in an amount of 50 wt. % or more, based on the weight of the extract, or 60 wt. % or more.
  • the raffinate can be further processed by recovering a mixture of hydrocarbon compounds (typically aromatic) that have a boiling range similar to that of the first solvent, and then recycling the recovered mixture for use as at least a portion of the first solvent.
  • the heavy phase product typically comprises at least a portion of what remains of the raffinate after the hydrocarbon mixture has been removed. Any convenient form of separation can be used for removing the hydrocarbon mixture and the heavy phase product from the raffinate, e.g., one or more of distillation, fractionation, another type of separation based on boiling range, etc.
  • separation of catalyst particles from the hydroprocessed effluent and/or the heavy phase portion of the hydroprocessed effluent and/or the heavy phase product may be desirable. Any convenient technique for separation of catalyst particles from an effluent stream can be used, such as filtration and/or centrifugation. It is noted that the presence of the first solvent in the heavy phase portion of the hydroprocessed effluent can be beneficial for the separation of catalyst particles. If filtration is used, the first solvent can reduce the viscosity of the heavy phase portion, which can facilitate reasonable permeation rates. Additionally or alternately, the reduced viscosity of the heavy phase portion due to the presence of the first solvent can be beneficial for using centrifugation to separate catalyst particles from the heavy phase portion of the hydroprocessed effluent.
  • Ebullating bed hydroprocessing conditions correspond to another example of fluidized hydroprocessing conditions for hydroprocessing of a heavy oil feed under relatively low pressure hydroprocessing conditions.
  • a catalyst system is used which includes two catalysts.
  • the catalysts and methods for making the catalysts are described in more detail in U.S. Patent No. 7,491,313, which is incorporated herein by reference for the limited purpose of describing the catalysts and the methods of making the catalysts.
  • fluidized hydroprocessing can be performed using both catalysts from the catalyst system.
  • fluidized hydroprocessing can be performed using only one of the catalysts.
  • Catalyst (1) is a hydroprocessing catalyst in which a porous inorganic carrier (also called a“support”) is loaded with about 7 wt. % to about 20 wt. % of an oxide of a Group VI(b) metal of the Periodic Table and about 0.5 wt. % to about 6 wt. % of an oxide of a Group VIII metal of the Periodic Table of the Elements (Sargent- Welch Scientific Company, No.
  • the catalyst can optionally have one or more of (a) a specific surface area of about 100 to about 180 m 2 /g, (b) a total pore volume of about 0.55 ml/g or more, and (c) a pore size distribution wherein (i) the proportion of the volume of the pores having diameters of about 200 A and more is 50% or more based on the total pore volume, and (ii) the proportion of the volume of the pores having diameters of about 2000 A and more is about 10 to 30%, based on the total pore volume.
  • the pore size distribution is determined by a method such as mercury penetration.
  • Catalyst (2) is a hydroprocessing catalyst having a silica-alumina type carrier (or support) such as those where a silica layer is formed on an alumina surface.
  • the support contains about 2 wt. % to about 40 wt. % of silica based on the total weight of the carrier.
  • the support is loaded with about 7 wt. % to about 20 wt. % of an oxide of a Group VI(b) metal of the Periodic Table, and about 0.5 wt. % to about 6 wt. % of an oxide of a Group VIII metal of the Periodic Table, respectively based on the weight of the catalyst.
  • the catalyst has a specific surface area of about 150 m 2 /g to about 400 m 2 /g, and a total pore volume of about 0.3 ml/g to about 1.2 ml/g.
  • the pore size distribution as measured by a method such as mercury penetration is such that the catalyst has a first peak of the pore size distribution in a range of a diameter of about 40 A to about 200 A with the proportion of about 35% to about 90% of a total pore volume, and a second peak of said pore size distribution in a range of a diameter of about 200 A to about 2000 A.
  • the catalyst contains pores of diameter of about 200 A to about 1000 A, which comprise about 10% to about 60% of said total pore volume and pores of diameters about 1000 A or larger, which comprise a volume of about 20% or less of said total pore volume; and a pore volume in a pore diameter range of about ⁇ 20 A corresponding to the position of the first peak in the diameter range of about 40 A to about 200 A is 50% or more of the pore volume in the diameter range of about 40 A to about 200 A.
  • the catalyst has a mean pore diameter of about 70 A to about 180 A.
  • fluidized hydroprocessing in the presence of one or both of the above catalysts can be carried out at a temperature of about 350° C to about 450° C and at a pressure of about 1.0 MPa-g to about 5.0 MPa-g, or about 1.0 Mpa-g to about 4.5 Mpa-g.
  • the liquid hourly space velocity (LHSV) can be about 0.1 to about 3 hr -1 , preferably about 0.3 to 2.0 hr -1 , with hydrogen at a flow rate ratio of hydrogen to the hydrocarbon oil (Fb/Oil) of about 300 to about 1500 NL/L, preferably about 600 to about 1000 NL/L.
  • the feed plus aromatic solvent can be exposed to the catalysts sequentially in first and second reaction zones.
  • the feed plus solvent can be exposed to the catalysts in an ebullating bed hydroprocessing environment.
  • the combined feed of heavy oil feedstock plus aromatic solvent can be similar to the heavy oil feedstock and aromatic solvent as described herein.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

L'invention concerne des systèmes et des procédés d'hydrotraitement de charges comprenant une fraction d'huile lourde, telle que des charges comprenant une fraction ~1050°F + (~566°C+). Les systèmes et les procédés peuvent faciliter le traitement de charges comprenant une fraction d'huile lourde dans un environnement d'hydrotraitement fluidisé tout en réduisant ou en réduisant au minimum la consommation d'hydrogène pendant l'hydrotraitement.
PCT/US2019/014266 2018-02-21 2019-01-18 Système d'hydrotraitement d'huile lourde WO2019164611A1 (fr)

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US201862633297P 2018-02-21 2018-02-21
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Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4619759A (en) * 1985-04-24 1986-10-28 Phillips Petroleum Company Two-stage hydrotreating of a mixture of resid and light cycle oil
US5755955A (en) 1995-12-21 1998-05-26 Petro-Canada Hydrocracking of heavy hydrocarbon oils with conversion facilitated by control of polar aromatics
US20050241991A1 (en) * 2004-04-28 2005-11-03 Headwaters Heavy Oil, Llc Ebullated bed hydroprocessing methods and systems and methods of upgrading an existing ebullated bed system
US7491313B2 (en) 2004-06-17 2009-02-17 Exxonmobil Research And Engineering Company Two-step hydroprocessing method for heavy hydrocarbon oil
US7941313B2 (en) 2001-05-17 2011-05-10 Qualcomm Incorporated System and method for transmitting speech activity information ahead of speech features in a distributed voice recognition system
US20110210045A1 (en) 2005-12-16 2011-09-01 c/o Chevron Corporation Systems and Methods for Producing a Crude Product
US20130081977A1 (en) * 2011-08-31 2013-04-04 Exxonmobil Research And Engineering Company Hydroprocessing of heavy hydrocarbon feeds using small pore catalysts

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Publication number Priority date Publication date Assignee Title
US4619759A (en) * 1985-04-24 1986-10-28 Phillips Petroleum Company Two-stage hydrotreating of a mixture of resid and light cycle oil
US5755955A (en) 1995-12-21 1998-05-26 Petro-Canada Hydrocracking of heavy hydrocarbon oils with conversion facilitated by control of polar aromatics
US7941313B2 (en) 2001-05-17 2011-05-10 Qualcomm Incorporated System and method for transmitting speech activity information ahead of speech features in a distributed voice recognition system
US20050241991A1 (en) * 2004-04-28 2005-11-03 Headwaters Heavy Oil, Llc Ebullated bed hydroprocessing methods and systems and methods of upgrading an existing ebullated bed system
US7491313B2 (en) 2004-06-17 2009-02-17 Exxonmobil Research And Engineering Company Two-step hydroprocessing method for heavy hydrocarbon oil
US20110210045A1 (en) 2005-12-16 2011-09-01 c/o Chevron Corporation Systems and Methods for Producing a Crude Product
US20130081977A1 (en) * 2011-08-31 2013-04-04 Exxonmobil Research And Engineering Company Hydroprocessing of heavy hydrocarbon feeds using small pore catalysts

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"Structure Commission of the International Zeolite Association", 2007, ELSEVIER

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