WO2010033480A2 - Systèmes et procédés de production d'un produit brut - Google Patents

Systèmes et procédés de production d'un produit brut Download PDF

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Publication number
WO2010033480A2
WO2010033480A2 PCT/US2009/056915 US2009056915W WO2010033480A2 WO 2010033480 A2 WO2010033480 A2 WO 2010033480A2 US 2009056915 W US2009056915 W US 2009056915W WO 2010033480 A2 WO2010033480 A2 WO 2010033480A2
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WO
WIPO (PCT)
Prior art keywords
heavy oil
oil feedstock
contacting
zone
contacting zone
Prior art date
Application number
PCT/US2009/056915
Other languages
English (en)
Other versions
WO2010033480A3 (fr
Inventor
Julie Chabot
Bo Kou
Vivion Andrew Brennan
Erin Maris
Shuwu Yang
Bruce Reynolds
Goutam Biswas
Darush Farshid
Kaidong Chen
Original Assignee
Chevron U.S.A. Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US12/233,439 external-priority patent/US7938954B2/en
Priority claimed from US12/233,327 external-priority patent/US7897036B2/en
Priority claimed from US12/233,171 external-priority patent/US8372266B2/en
Priority claimed from US12/212,737 external-priority patent/US7931796B2/en
Priority claimed from US12/233,393 external-priority patent/US7935243B2/en
Priority claimed from US12/212,796 external-priority patent/US7897035B2/en
Priority to EA201170463A priority Critical patent/EA023427B1/ru
Priority to MX2011002970A priority patent/MX2011002970A/es
Priority to CA2737367A priority patent/CA2737367C/fr
Priority to EP09815045.1A priority patent/EP2331657B1/fr
Priority to KR1020117008794A priority patent/KR101700224B1/ko
Application filed by Chevron U.S.A. Inc. filed Critical Chevron U.S.A. Inc.
Priority to JP2011527896A priority patent/JP5661038B2/ja
Priority to BRPI0918085A priority patent/BRPI0918085A2/pt
Priority to CN200980142574.XA priority patent/CN102197116B/zh
Publication of WO2010033480A2 publication Critical patent/WO2010033480A2/fr
Publication of WO2010033480A3 publication Critical patent/WO2010033480A3/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
    • C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
    • C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
    • C10G65/12—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including cracking steps and other hydrotreatment steps
    • 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
    • C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
    • C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1044—Heavy gasoline or naphtha having a boiling range of about 100 - 180 °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
    • C10G2300/1074—Vacuum distillates
    • 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
    • C10G2300/201—Impurities
    • C10G2300/202—Heteroatoms content, i.e. S, N, O, P
    • 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
    • C10G2300/201—Impurities
    • C10G2300/202—Heteroatoms content, i.e. S, N, O, P
    • C10G2300/203—Naphthenic acids, TAN
    • 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
    • C10G2300/201—Impurities
    • C10G2300/205—Metal content
    • C10G2300/206—Asphaltenes
    • 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
    • C10G2300/201—Impurities
    • C10G2300/208—Sediments, e.g. bottom sediment and water or BSW
    • 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
    • C10G2300/302—Viscosity
    • 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
    • C10G2300/308—Gravity, density, e.g. API
    • 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
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4081—Recycling aspects
    • 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
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/44—Solvents
    • 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
    • C10G2300/805—Water
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/02—Gasoline
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/04—Diesel oil
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/08—Jet fuel
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/28—Propane and butane

Definitions

  • the invention relates to systems and methods for treating or upgrading heavy oil feeds, and crude products produced using such systems and methods.
  • feedstocks such as heavy crudes, resids, coals, tar sands, etc.
  • feedstocks are characterized by high concentrations of asphaltenes rich residues, and low API gravities, with some being as low as less than 0° API.
  • this invention relates to a process for by which a heavy oil feedstock can be upgraded.
  • the process employs a plurality of contacting zones, separation zones and at least an interstage solvent deasphalting unit (SDA).
  • SDA solvent deasphalting unit
  • the process comprises: a) combining a hydrogen containing gas feed, a heavy oil feedstock, and a slurry catalyst in a first contacting zone under hydrocracking conditions to convert at least a portion of the heavy oil feedstock to upgraded products; c) sending a mixture of the upgraded products, the slurry catalyst, the hydrogen containing gas, and unconverted heavy oil feedstock to a separation zone; d) in the separation zone, removing the upgraded products with the hydrogen containing gas as an overhead stream, and removing the slurry catalyst and the unconverted heavy oil feedstock as a non- volatile stream; e) sending at least a portion of the non- volatile stream to the SDA unit to separate the asphaltenes and slurry catalyst from the deasphalted
  • a process employing a plurality of contacting zones, separation zones and at least an interstage solvent deasphalting unit (SDA) in which a heavy oil feedstock can be upgraded, and wherein at least a portion of the nonvolatile stream from at least a contacting zone is sent to the SDA unit to separate the asphaltenes from the deasphalted oil.
  • SDA interstage solvent deasphalting unit
  • this invention relates to a process for by which a heavy oil feedstock can be upgraded with reduced heavy metal deposits in the front-end contacting zones.
  • the process employ a plurality of contacting zones and separation zones, the process comprising: a) combining a hydrogen containing gas feed, a heavy oil feedstock, and a slurry catalyst in a first contacting zone under hydrocracking conditions to convert at least a portion of the heavy oil feedstock to upgraded products, wherein water and / or steam being injected into first contacting zone in an amount of 1 to 25 weight % on the weight of the heavy oil feedstock; b) sending a mixture of the upgraded products, the slurry catalyst, the hydrogen containing gas, and unconverted heavy oil feedstock to a separation zone; c) in the separation zone, removing the upgraded products with the hydrogen containing gas as an overhead stream, and removing the slurry catalyst and the unconverted heavy oil feedstock as a nonvolatile stream; d) sending the non- volatile stream to another contacting zone under hydrocracking conditions with additional hydrogen gas, unconverted heavy oil feedstock, and optionally, a fresh slurry catalyst to convert the unconverted heavy oil feedstock to
  • the invention in another aspect, relates to a method for upgrading a heavy oil feedstock employing a plurality of contacting zones and separation zones, in which water and / or steam is injected into the first contacting zone, and wherein at least a portion of the nonvolatile stream from a separation zone other than the first separation zone is recycled to the first contacting zone, wherein the recycled stream ranges between 3 to 50 wt. % of the total heavy oil feedstock to the process.
  • this invention relates to a process for by which a heavy oil feedstock can be upgraded.
  • the process employs a plurality of contacting zones and separation zones, the process comprising: a) a heavy oil feedstock with at least a portion of the heavy oil feedstock is fed to a contacting zone other than the first contacting zone; b) combining a hydrogen containing gas feed, a portion of the heavy oil feedstock, and a slurry catalyst in a first contacting zone under hydrocracking conditions to convert at least a portion of the heavy oil feedstock to upgraded products; c) sending a mixture of the upgraded products, the slurry catalyst, the hydrogen containing gas, and unconverted heavy oil feedstock to a separation zone; d) in the separation zone, removing the upgraded products with the hydrogen containing gas as an overhead stream, and removing the slurry catalyst and the unconverted heavy oil feedstock as a non- volatile stream; e) sending the non- volatile stream to another contacting zone under hydrocracking conditions with additional hydrogen
  • the process employs a plurality of contacting zones and separation zones, the process comprising: a) providing a slurry catalyst containing a used slurry catalyst and optionally a fresh catalyst slurry feed; b) combining a hydrogen containing gas feed, the heavy oil feedstock, and the slurry catalyst in a contacting zone under hydrocracking conditions to convert at least a portion of the heavy oil feedstock to upgraded products; c) sending a mixture comprising the upgraded products, the slurry catalyst, the hydrogen containing gas, and unconverted heavy oil feedstock to a separation zone; d) in the separation zone, removing the upgraded products with the hydrogen containing gas as an overhead stream, and removing the slurry catalyst and the unconverted heavy oil feedstock as a non-volatile stream; e) sending the non-volatile stream to another contacting zone under hydrocracking conditions with additional hydrogen gas and a fresh slurry catalyst to convert the unconverted heavy oil feedstock to upgraded products; f) sending
  • a process employing a plurality of contacting zones and separation zones in which a heavy oil feedstock can be upgraded, and wherein the fresh slurry catalyst is split between the contacting zones.
  • the process employs a plurality of contacting zones and separation zones, the process comprising: a) combining a hydrogen containing gas feed, a heavy oil feedstock, and a slurry catalyst in a first contacting zone under hydrocracking conditions to convert at least a portion of the heavy oil feedstock to upgraded products; b) sending a mixture of the upgraded products, the slurry catalyst, the hydrogen containing gas, and unconverted heavy oil feedstock to a separation zone; c) in the separation zone, removing the upgraded products with the hydrogen containing gas as an overhead stream, and removing the slurry catalyst and the unconverted heavy oil feedstock as a non-volatile stream; d) sending the non-volatile stream to another contacting zone under hydrocracking conditions with additional hydrogen
  • the invention relates to a process for by which a heavy oil feedstock can be upgraded with reduced heavy metal deposits in the front-end contacting zones.
  • the process employ a plurality of contacting zones and separation zones, comprising: a) combining a hydrogen containing gas feed, a heavy oil feedstock, and a slurry catalyst in a first contacting zone under hydrocracking conditions to convert at least a portion of the heavy oil feedstock to upgraded products; b) sending a mixture of the upgraded products, the slurry catalyst, the hydrogen containing gas, and unconverted heavy oil feedstock to a separation zone; c) in the separation zone, removing the upgraded products with the hydrogen containing gas as an overhead stream, and removing the slurry catalyst and the unconverted heavy oil feedstock as a non- volatile stream; d) sending the non-volatile stream to another contacting zone under hydrocracking conditions with additional hydrogen gas, unconverted heavy oil feedstock, and optionally, a fresh slurry catalyst to convert the unconverted
  • Figure 1 is a block diagram that schematically illustrates an embodiment of a hydroprocessing system for upgrading a heavy oil feedstock, with a plurality of contacting zones and separation zones, wherein water and / or steam is injected into the front end contacting zone.
  • Figure 2 is a flow diagram of a process to upgrade heavy oil feeds with water injection.
  • Figure 3 is a flow diagram of a process to upgrade heavy oil feeds with steam injection directly into a front end contacting zone.
  • Figure 4 is a flow diagram of another embodiment of process to upgrade heavy oil feeds with a recycled catalyst stream at a sufficient rate to reduce heavy metal build-up.
  • Figure 5 is a block diagram that schematically illustrates an embodiment of a hydroprocessing system for upgrading a heavy oil feedstock, having a split fresh catalyst feed scheme, a split heavy oil feed scheme, and additional interstage hydrocarbon oil feedstock.
  • Figure 6 is a block diagram that schematically illustrates another embodiment of a hydroprocessing system for upgrading a heavy oil feedstock with a solvent deasphalting unit for pre-treating the heavy oil feedstock.
  • Figure 7 is a flow diagram of a process to upgrade heavy oil feeds with an embodiment of the catalyst split feed scheme, wherein fresh catalyst feed is fed into all reactors in the process.
  • Figure 8 is a flow diagram of a process to upgrade heavy oil feeds wherein the fresh catalyst feed is diverted from the first reactor to other reactors in the process, and wherein optional / additional hydrocarbon oil is fed to the reactors as feedstock.
  • Figure 9 is a flow diagram of another embodiment of a process to upgrade heavy oil feeds, wherein all of the fresh catalyst feed is sent to the last reactor in the process.
  • Figure 10 is a flow diagram of another embodiment of a process to upgrade heavy oil feeds, wherein some of the untreated heavy oil feed is diverted from the first reactor sent to other reactors in the process.
  • heavy oil feed or feedstock refers to heavy and ultra-heavy crudes, including but not limited to resids, coals, bitumen, shale oils, tar sands, etc.
  • Heavy oil feedstock may be liquid, semi-solid, and / or solid. Examples of heavy oil feedstock that might be upgraded as described herein include but are not limited to Canada Tar sands, vacuum resid from Brazilian Santos and Campos basins, Egyptian Gulf of Suez, Chad, Venezuelan Zulia, Malaysia, and Indonesia Sumatra.
  • heavy oil feedstock examples include bottom of the barrel and residuum left over from refinery processes, including "bottom of the barrel” and “residuum” (or “resid”) — atmospheric tower bottoms, which have a boiling point of at least 343 0 C. (65O 0 F.), or vacuum tower bottoms, which have a boiling point of at least 524 0 C. (975 0 F.), or "resid pitch” and "vacuum residue” - which have a boiling point of 524 0 C. (975 0 F.) or greater.
  • Properties of heavy oil feedstock may include, but are not limited to: TAN of at least 0.1, at least 0.3, or at least 1; viscosity of at least 10 cSt; API gravity at most 15 in one embodiment, and at most 10 in another embodiment.
  • a gram of heavy oil feedstock typically contains at least 0.0001 grams of Ni/V/Fe; at least 0.005 grams of heteroatoms; at least 0.01 grams of residue; at least 0.04 grams C5 asphaltenes; at least 0.002 grams of MCR; per gram of crude; at least 0.00001 grams of alkali metal salts of one or more organic acids; and at least 0.005 grams of sulfur.
  • the heavy oil feedstock has a sulfur content of at least 5 wt.
  • treatment when used in conjunction with a heavy oil feedstock, describes a heavy oil feedstock that is being or has been subjected to hydroprocessing, or a resulting material or crude product, having a reduction in the molecular weight of the heavy oil feedstock, a reduction in the boiling point range of the heavy oil feedstock, a reduction in the concentration of asphaltenes, a reduction in the concentration of hydrocarbon free radicals, and/or a reduction in the quantity of impurities, such as sulfur, nitrogen, oxygen, halides, and metals.
  • impurities such as sulfur, nitrogen, oxygen, halides, and metals.
  • Hydroprocessing is meant as any process that is carried out in the presence of hydrogen, including, but not limited to, hydro conversion, hydrocracking, hydrogenation, hydrotreating, hydrodesulfurization, hydrodenitrogenation, hydrodemetallation, hydrodearomatization, hydroisomerization, hydrodewaxing and hydrocracking including selective hydrocracking.
  • the products of hydroprocessing may show improved viscosities, viscosity indices, saturates content, low temperature properties, volatilities and depolarization, etc.
  • hydrogen refers to hydrogen, and / or a compound or compounds that when in the presence of a heavy oil feed and a catalyst react to provide hydrogen.
  • SCF / BBL refers to a unit of standard cubic foot of gas (N 2 , H 2 , etc.) per barrel of hydrocarbon feed.
  • Nm 3 /m 3 refers to normal cubic meters of gas per cubic meter of heavy oil feed.
  • VGO or vacuum gas oil referring to hydrocarbons with a boiling range distribution between 343 0 C (65O 0 F) and 538 0 C (1000 0 F) at 0.101 MPa.
  • wppm means weight parts per million.
  • catalyst precursor refers to a compound containing one or more catalytically active metals, from which compound a catalyst is eventually formed. It should be noted that a catalyst precursor may be catalytically active as a hydroprocessing catalyst. As used herein, “catalyst precursor” may be referred herein as “catalyst” when used in the context of a catalyst feed.
  • used catalyst refers to a catalyst that has been used in at least a reactor in a hydroprocessing operation and whose activity has thereby been diminished.
  • reaction rate constant of a fresh catalyst at a specific temperature is assumed to be 100%
  • reaction rate constant for a used catalyst is 95% or less in one embodiment, 80% or less in another embodiment, and 70% or less in a third embodiment.
  • used catalyst may be used interchangeably with “recycled catalyst,” “used slurry catalyst” or “recycled slurry catalyst.”
  • fresh catalyst refers to a catalyst or a catalyst precursor that has not been used in a reactor in a hydroprocessing operation.
  • fresh catalyst herein also includes "re-generated” or “rehabilitated” catalysts, i.e., catalyst that has been used in at least a reactor in a hydroprocessing operation ("used catalyst") but its catalytic activity has been restored or at least increased to a level well above the used catalytic activity level.
  • used catalyst catalyst
  • fresh catalyst may be used interchangeably with "fresh slurry catalyst.”
  • slurry catalyst or sometimes referred to as
  • slurry refers to a liquid medium, e.g., oil, water, or mixtures thereof, in which catalyst and / or catalyst precursor particles (particulates or crystallites) having very small average dimensions are dispersed within.
  • the "catalyst feed” includes any catalyst suitable for upgrading heavy oil feed stocks, e.g., one or more bulk catalysts and / or one or more catalysts on a support.
  • the catalyst feed may include at least a fresh catalyst, a used catalyst only, or mixtures of at least a fresh catalyst and a used catalyst.
  • the catalyst feed is in the form of a slurry catalyst.
  • the term “bulk catalyst” may be used interchangeably with “unsupported catalyst,” meaning that the catalyst composition is NOT of the conventional catalyst form which has, i.e., having a preformed, shaped catalyst support which is then loaded with metals via impregnation or deposition catalyst.
  • the bulk catalyst is formed through precipitation.
  • the bulk catalyst has a binder incorporated into the catalyst composition.
  • the bulk catalyst is formed from metal compounds and without any binder.
  • the bulk catalyst is a dispersing-type catalyst for use as dispersed catalyst particles in mixture of liquid (e.g., hydrocarbon oil).
  • the catalyst comprises one or more commercially known catalysts, e.g., MicrocatTM from ExxonMobil Corp.
  • the term "contacting zone” refers to an equipment in which the heavy oil feed is treated or upgraded by contact with a slurry catalyst feed in the presence of hydrogen. In a contacting zone, at least a property of the crude feed may be changed or upgraded.
  • the contacting zone can be a reactor, a portion of a reactor, multiple portions of a reactor, or combinations thereof.
  • the term “contacting zone” may be used interchangeably with “reacting zone.”
  • the term "separation zone” refers to an equipment in which upgraded heavy oil feed from a contacting zone is either fed directly into, or subjected to one or more intermediate processes and then fed directly into the separation zone, e.g., a flash drum or a high pressure separator, wherein gases and volatile liquids are separated from the non-volatile fraction.
  • the non-volatile fraction stream comprises unconverted heavy oil feed, a small amount of heavier hydrocracked liquid products (synthetic or less-volatile / non-volatile upgraded products), the slurry catalyst and any entrained solids (asphaltenes, coke, etc.).
  • bleed stream or "bleed off stream” refers to a stream containing used (or recycled) catalyst, being “bled” or diverted from the hydroprocessing system, helping to prevent or “flush” accumulating metallic sulfides and other unwanted impurities from the upgrade system.
  • the present invention relates to an improved system to treat or upgrade heavy oil feeds, particularly heavy oil feedstock having high levels of heavy metals.
  • a typical prior art hydroprocessing system having a plurality of contacting zones (reactors) in series, it is observed that the feed stream to the 2 nd contacting zone should generally be cleaner than heavy oil feed into the first contacting zone in the system, i.e., having less impurities such as nickel, vanadium, nitrogen, sulfur, etc., as the heavy oil has gone through a treatment process in the first contacting zone. It is also observed that the feed stream into the last contacting zone in the system should generally be cleaner than the feed stream to the prior contacting zone(s) in the system.
  • the feed stream to subsequent contacting zones in the system has properties different than the properties of the heavy oil feed to the preceding contacting zone(s) in the system, including: a) lower TAN; b) viscosity; c) lower residue content; d) lower API gravity; e) lower content of metals in metal salts of organic acids; and g) combinations thereof.
  • the upgrade process comprises a plurality of reactors for contacting zones, with the reactors being the same or different in configurations.
  • reactors that can be used herein include stacked bed reactors, fixed bed reactors, ebullating bed reactors, continuous stirred tank reactors, fluidized bed reactors, spray reactors, liquid / liquid contactors, slurry reactors, liquid recirculation reactors, and combinations thereof.
  • the reactor is an up-flow reactor.
  • the contacting zone refers to at least a slurry-bed hydrocracking reactor in series with at least a fixed bed hydrotreating reactor.
  • at least one of the contacting zones further comprises an in-line hydrotreater, capable of removing removed over 70% of the sulfur, over 90% of nitrogen, and over 90% of the heteroatoms in the crude product being processed.
  • the contacting zone comprises a plurality of reactors in series, providing a total residence time ranging from 0.1 to 15 hours.
  • the resident time ranges from 0.5 to 5 hrs.
  • the total residence time in the contacting zone ranges from 0.2 to 2 hours.
  • the amount of heavier hydrocracked products in the non- volatile fraction stream is less than 50 wt. % (of the total weight of the non- volatile stream). In a second embodiment, the amount of heavier hydrocracked products in the non- volatile stream from the separation zone is less than 25 wt. %. In a third embodiment, the amount of heavier hydrocracked products in the non- volatile stream from the separation zone is less than 15 wt. %.
  • the slurry catalyst remains with the upgraded feedstock as the upgraded materials is withdrawn from the contacting zone and fed into the separation zone, and the slurry catalyst continues to be available in the separation zone and exits the separation zone with the non-volatile liquid fraction.
  • both the contacting zone and the separation zone are combined into one equipment, e.g., a reactor having an internal separator, or a multi-stage reactor-separator.
  • the vapor product exits the top of the equipment, and the non- volatile fractions exit the side or bottom of the equipment with the slurry catalyst and entrained solid fraction, if any.
  • the slurry catalyst stream contains a fresh catalyst. In another embodiment, the slurry catalyst stream contains a mixture of at least a fresh catalyst and a recycled (used) catalyst. In a third embodiment, the slurry catalyst stream comprises a used catalyst. In another embodiment, the slurry catalyst contains a well-dispersed catalyst precursor composition capable of forming an active catalyst in situ within the feed heaters and/or the contacting zone.
  • the catalyst particles can be introduced into the medium (diluent) as powder in one embodiment, a precursor in another embodiment, or after a pre- treatment step in a third embodiment.
  • the medium (or diluent) is a hydrocarbon oil diluent.
  • the liquid medium is the heavy oil feedstock itself. In yet another embodiment, the liquid medium is a hydrocarbon oil other than the heavy oil feedstock, e.g., a VGO medium or diluent.
  • the bleed off stream comprises non- volatile materials from a separation zone in the system, typically the last separation zone, comprising unconverted materials, slurry catalyst, a small amount of heavier hydrocracked liquid products, small amounts of coke, asphaltenes, etc.
  • the bleed off stream is the bottom stream from an interstage solvent deasphalting unit in the system.
  • the bleed stream typically ranges from 1 to 35 wt. %; 3-20 wt. %; or 5-15wt. % of the total heavy oil feedstock to the system.
  • the bleed off stream is diverted from the bottom of a deasphalting unit, the bleed off stream ranges from 0.30 to 5 wt.%; 1-30 wt. %; or 0.5 to 10 wt. % of the heavy oil feed stock.
  • the bleed-off stream contains between 3 to 30 wt. % slurry catalyst. In another embodiment, the slurry catalyst amount ranges from 5 to 20 wt. %. In yet another embodiment, the bleed-off stream contains an amount of slurry catalyst ranging from 1 to 15 wt. % in concentration.
  • At least a portion of the fresh catalyst is diverted to at least one other contacting zones (other than the 1 st contacting zone) in the system.
  • At least a portion of the heavy oil feed is diverted to at least one other contacting zones in the system.
  • a combination feed scheme is employed with a portion of the fresh catalyst feed and a portion of the heavy oil feed being diverted to at least one other contact zones other than the first contacting zone in the heavy oil upgrading system.
  • the upgrade system comprises at least two upflow reactors in series with at least two separators, with each separator being positioned right after each reactor and with the interstage SDA unit being positioned before at least one reactor in the system.
  • the upgrade system comprises at least two upflow reactors and at least two separators in series, with of each of the separators being positioned right after each reactor, and the interstage SDA unit being position after the 1 st separator in the series.
  • the upgrade system may comprise a combination of separate reactors and separate separators in series with multi-stage reactor-separators, with the SDA being positioned as an interstage treatment system between any two reactors in series.
  • the unconverted heavy oil feed here herein may comprise one or more different heavy oil feeds from different sources as a single feed stream, or as separate heavy oil feed streams.
  • at least a portion of the heavy oil feed (to be upgraded) is "split" or diverted to at least one other contacting zones in the system (other than the first contacting zone), or to the interstage SDA unit prior to being fed into a contacting zone.
  • "at least a portion” means at least 5% of the heavy oil feed to be upgraded is diverted to at least one other contacting zones in the system other than the first contacting zone. In another embodiment, at least 10%. In a third embodiment, at least 20%. In a fourth embodiment, at least 30% of the heavy oil feed is diverted to at least a contacting zone other than the first one in the system.
  • the heavy oil feedstock is preheated prior to being blended with the slurry catalyst feed stream(s). In another embodiment, the blend of heavy oil feedstock and slurry catalyst feed is preheated to create a feedstock that is sufficiently of low viscosity to allow good mixing of the catalyst into the feedstock.
  • the preheating is conducted at a temperature that is at least about 100 0 C (18O 0 F) less than the hydrocracking temperature within the contacting zone. In another embodiment, the preheating is at a temperature that is about at least 5O 0 C less than the hydrocracking temperature within the contacting zone.
  • additional hydrocarbon oil feed e.g., VGO (vacuum gas oil), naphtha, MCO (medium cycle oil), solvent donor, or other aromatic solvents, etc. in an amount ranging from 2 to 40 wt. % of the heavy oil feed can be optionally added as part of the heavy oil feed stream to any of the contacting zones in the system.
  • the additional hydrocarbon feed functions as a diluent to lower the viscosity of the heavy oil feed.
  • Embodiments of The Heavy Oil Split Feed Scheme In some embodiments, at least a portion of the heavy oil feed (to be upgraded) is "split" or diverted to at least one other contacting zones in the system (other than the first contacting zone).
  • "at least a portion" meaning at least 5% of the heavy oil feed to be upgraded. In another embodiment, at least 10%. In a third embodiment, at least 20%. In a fourth embodiment, at least 30% of the heavy oil feed is diverted to at least a contacting zone other than the first one in the system. [064] In one embodiment, less than 90% of the unconverted heavy oil feed is fed to the first reactor in the system, with 10% or more of the unconverted heavy oil feed being diverted to the other contacting zone(s) in the system. In another embodiment, the heavy oil feed is being equally split between the contacting zones in the system.
  • less than 80% of the unconverted heavy oil feed is fed to the first contacting zone in the system, and the remaining heavy oil feed is diverted to the last contacting zone in the system.
  • less than 60% of the heavy oil feed is fed to the first contacting zone in the system, and the remainder of the unconverted heavy oil feed is equally split between the other contacting zones in the system.
  • the unconverted heavy oil feed herein may comprise one or more different heavy oil feeds from different sources as a single feed stream or separate heavy oil feed streams.
  • a single heavy oil conduit pipe goes to all the contacting zones.
  • multiple heavy oil conduits are employed to supply the heavy oil feed to the different contacting zones, with some heavy oil feed stream(s) going to one or more contacting zones, and some of the other unconverted heavy oil feed stream(s) going to one or more different contacting zones.
  • the heavy oil feedstock is preheated prior to being blended with the slurry catalyst feed, and / or prior to being introduced into the hydrocracking reactors (contacting zones).
  • the blend of heavy oil feedstock and slurry catalyst feed is preheated to create a feedstock that is sufficiently of low viscosity to allow good mixing of the catalyst into the feedstock.
  • the preheating is conducted at a temperature that is about 100 0 C (18O 0 F) less than the hydrocracking temperature within the contacting zone. In another embodiment, the preheating is at a temperature that is about 5O 0 C less than the hydrocracking temperature within the contacting zone.
  • Hydrogen Feed In one embodiment, a hydrogen containing gas is provided to the process. The hydrogen can also be added to the heavy oil feed prior to entering the preheater, or after the preheater. In one embodiment, the hydrogen feed enters the contacting zone co-currently with the heavy oil feed in the same conduit. In another embodiment, the hydrogen source may be added to the contacting zone in a direction that is counter to the flow of the crude feed.
  • the hydrogen enters the contacting zone via a gas conduit separately from the combined heavy oil and slurry catalyst feed stream.
  • the hydrogen feed is introduced directly to the combined catalyst and heavy oil feedstock prior to being introduced into the contacting zone.
  • the hydrogen gas and the combined heavy oil and catalyst feed are introduced at the bottom of the reactor as separate streams.
  • hydrogen gas can be fed to several sections of the contacting zone.
  • the hydrogen source is provided to the process at a rate (based on ratio of the gaseous hydrogen source to the crude feed) of 0.1 NmV 3 to about 100,000 Nm 3 /m 3 (0.563 to 563,380 SCF/bbl), about 0.5 NmW to about 10,000 Nm 3 /m 3 (2.82 to 56,338 SCF/bbl), about 1 Nm 3 /m 3 to about 8,000 Nm 3 /m 3 (5.63 to 45,070 SCF/bbl), about 2 Nm 3 /m 3 to about 5,000 NmW (11.27 to 28,169 SCF/bbl), about 5 NmW to about 3,000 Nm 3 /m 3 (28.2 to 16,901 SCFMl), or about 10 Nm 3 W to about 800 Nm 3 W (56.3 to 4,507 SCF/bbl).
  • some of the hydrogen (25 -75%) is supplied to the first contacting zone, and the rest is added as supplemental hydrogen to other contacting zones
  • the upgrade system produces a volume yield over 100% (compared to the heavy oil input) in upgraded products as added hydrogen expands the heavy oil total volume.
  • the upgraded products i.e., lower boiling hydrocarbons, in one embodiment include liquefied petroleum gas (LPG), gasoline, diesel, vacuum gas oil (VGO), and jet and fuel oils.
  • LPG liquefied petroleum gas
  • VGO vacuum gas oil
  • the upgrade system provides a volume yield of at least 110% in the form of LPG, naphtha, jet & fuel oils, and VGO.
  • over 115% over 115%.
  • At least 98 wt % of heavy oil feed is converted to lighter products.
  • at least 98.5% of heavy oil feed is converted to lighter products.
  • the conversion rate is at least 99%.
  • the conversion rate is at least 95%.
  • the conversion rate is at least 80%.
  • the conversion rate is at least 60%.
  • conversion rate refers to the conversion of heavy oil feedstock to less than 1000 0 F. (538°C) boiling point materials.
  • the hydrogen source in some embodiments, is combined with carrier gas(es) and recirculated through the contacting zone.
  • Carrier gas may be, for example, nitrogen, helium, and/or argon.
  • the carrier gas may facilitate flow of the crude feed and/or flow of the hydrogen source in the contacting zone(s).
  • the carrier gas may also enhance mixing in the contacting zone(s).
  • a hydrogen source for example, hydrogen, methane or ethane
  • Catalyst Feed In one embodiment, all of the slurry catalyst feed is provided to the first contacting zone.
  • At least a portion of the catalyst feed is "split" or diverted to at least one other contacting zones in the system (other than the first contacting zone).
  • all the contacting zones in operation receive a slurry catalyst feed (along with a heavy oil feed).
  • the process is configured for a flexible catalyst feed scheme such that the fresh catalyst can sometimes be fed entirely to the last reactor in the system for certain process conditions (for certain desired product characteristics), or 50% to the first reactor in the system for some of the process runs, or split equally or according to pre-determined proportions to all of the reactors in the system, or split according to pre-determined proportions for the same fresh catalyst to be fed to the different reactors at different concentrations.
  • the slurry catalyst feed used herein may comprise one or more different slurry catalysts as a single catalyst feed stream or separate feed streams.
  • a single fresh catalyst feed stream is supplied to the contacting zones.
  • the catalyst feed comprises multiple and different catalyst types, with a certain catalyst type going to one or more contacting zones (e.g., the first contacting zone in the system) as a separate stream, and a different slurry catalyst going to contacting zone(s) other than the 1 st contacting zone in the system as a different catalyst stream.
  • "at least a portion” means at least 10% of the fresh catalyst. In another embodiment, at least 20%. In a third embodiment, at least 40%. In a fourth embodiment, at least 50% of the fresh catalyst is diverted to at least a contacting zone other than the first one in the system. In a fifth embodiment, all of the fresh catalyst is diverted to a contacting zone other than the 1 st contacting zone.
  • less than 20% of the fresh catalyst is fed to the first reactor in the system, with 80% or more of the fresh catalyst being diverted to the other contacting zone(s) in the system.
  • the fresh catalyst is being equally split between the contacting zones in the system.
  • at least a portion of the fresh catalyst feed is sent to at least one of the intermediate contacting zones and / or the last contacting zone in the system.
  • all of the fresh catalyst is sent to the last contacting zone in the system, with the first contacting zone in the system only getting recycled catalyst from one or more of the processes in the system, e.g., from one of the separation zones in the system or from a solvent deasphalting unit.
  • At least a portion of the fresh catalyst feed is sent to the contacting zone immediately following the interstage SDA unit.
  • all of the fresh catalyst is sent to contacting zone(s) other than the 1 st one in the system, with the first contacting zone only getting SDA bottoms from the SDA unit and recycled catalyst from one or more of the processes in the system, e.g., from one of the separation zones in the system.
  • the fresh catalyst is combined with the recycled catalyst stream from one of the processes in the system, e.g., a separation zone, a distillation column, a SDA unit, or a flash tank, and the combined catalyst feed is thereafter blended with heavy oil feedstock for feeding into the contacting zone(s).
  • the fresh catalyst and the recycled catalyst streams are blended into the heavy oil feedstock as separate streams.
  • the recycled catalyst stream from one of the processes in the system e.g., a separation zone, the SDA unit, etc.
  • the combined catalyst feed is thereafter blended with the (treated or untreated) heavy oil feedstock stream(s) for feeding into the contacting zone(s).
  • the fresh catalyst and the recycled catalyst streams are blended into the heavy oil feedstock stream(s) as separate streams.
  • the process is configured for a flexible catalyst feed scheme such that the catalyst feed can sometimes be fed at full rate (100% of the required catalyst rate) to the first reactor in the system for a certain period of time, then split equally or according to pre-determined proportions to all of the reactors in the system for a predetermined amount of time, or split according to pre-determined proportions for the catalyst feed to be fed to the different reactors at different concentrations.
  • sending different catalysts to the front end and back end contacting zones can be useful in mitigating the vanadium trapping issue and sustain the overall upgrade performance.
  • a Ni-only or a NiMo sulfide slurry catalyst rich in Ni is sent to the front end reactor to help reduce vanadium trapping in the system, while a different catalyst, e.g., Mo sulfide or a NiMo sulfide catalyst rich in Mo, can be injected into the back end reactor(s) to maintain an overall high conversion rate, improve product quality and possibly reduce the gas yield in one embodiment.
  • a slurry catalyst rich in Ni means that the Ni / Mo ratio is greater than 0.15 (as wt. %)
  • a slurry catalyst rich in Mo means that the Ni / Mo ratio is less than 0.05 (as wt. %).
  • the slurry catalyst feed is first preconditioned before entering one of the contacting zones, or before being brought into contact with the heavy oil feed before entering the contacting zones.
  • the catalyst enters into a preconditioning unit along with hydrogen at a rate from 500 to 7500 SCF / BBL (BBL here refers to the total volume of heavy oil feed to the system). It is believed that instead of bringing a cold catalyst in contact with the heavy oil feed, the preconditioning step helps with the hydrogen adsorption into the active catalyst sites, and ultimately the conversion rate.
  • the slurry catalyst / hydrogen mixture is heated to a temperature between 300 0 F to 1000 0 F (149 to 538 0 C).
  • the catalyst is preconditioned in hydrogen at a temperature of 500 to 725 0 F (260 to 385 0 C).
  • the mixture is heated under a pressure of 300 to 3200 psi in one embodiment; 500 - 3000 psi in a second embodiment; and 600 - 2500 psi in a third embodiment.
  • the slurry catalyst comprises an active catalyst in a hydrocarbon oil diluent.
  • the catalyst is a sulfided catalyst comprising at least a Group VIB metal, or at least a Group VIII metal, or at least a group HB metal, e.g., a ferric sulfide catalyst, zinc sulfide, nickel sulfide, molybdenum sulfide, or an iron zinc sulfide catalyst.
  • the catalyst is a multi-metallic catalyst comprising at least a Group VIB metal and at least a Group VIII metal (as a promoter), wherein the metals may be in elemental form or in the form of a compound of the metal.
  • the catalyst is a MoS 2 catalyst promoted with at least a group VIII metal compound.
  • the catalyst is a bulk multi-metallic catalyst comprising at least one Group VIII non-noble metal and at least two Group VIB metals, and wherein the ratio of the at least two Group VIB metals to the Group VIII non-noble metal is from about 10: 1 to about 1 :10.
  • the catalyst is of the formula
  • M represents at least one group VIB metal, such as Mo, W, etc. or a combination thereof
  • X functions as a promoter metal, representing at least one of: a non-noble Group VIII metal such as Ni, Co; a Group VIII metal such as Fe; a Group VIB metal such as Cr; a Group IVB metal such as Ti; a Group HB metal such as Zn, and combinations thereof (X is hereinafter referred to as "Promoter Metal").
  • t, u, v, w, x, y, z representing the total charge for each of the component (M, X, S, C, H, O and N, respectively);
  • S represents sulfur with the value of the subscript d ranging from (a + 0.5b) to (5a + 2b).
  • C represents carbon with subscript e having a value of 0 to 1 l(a+b).
  • H is hydrogen with the value of/ranging from 0 to 7(a+b).
  • the catalyst is the catalyst is prepared from catalyst precursor compositions including organometallic complexes or compounds, e.g., oil soluble compounds or complexes of transition metals and organic acids. Examples of such compounds include naphthenates, pentanedionates, octoates, and acetates of Group VIB and Group VIII metals such as Mo, Co, W, etc. such as molybdenum naphthanate, vanadium naphthanate, vanadium octoate, molybdenum hexacarbonyl, and vanadium hexacarbonyl.
  • the catalyst is a MoS 2 catalyst, promoted with at least a group VIII metal compound.
  • the catalyst is a bulk multimetallic catalyst, wherein said bulk multimetallic catalyst comprises of at least one Group VIII non- noble metal and at least two Group VIB metals and wherein the ratio of said at least two Group VIB metals to said at least one Group VIII non-noble metal is from about 10:1 to about 1 :10.
  • the catalyst feed comprises slurry catalyst having an average particle size of at least 1 micron in a hydrocarbon oil diluent.
  • the catalyst feed comprises slurry catalyst having an average particle size in the range of 1 - 20 microns.
  • the slurry catalyst has an average particle size in the range of 2 - 10 microns.
  • the feed comprises a slurry catalyst having an average particle size ranging from colloidal (nanometer size) to about 1-2 microns.
  • the catalyst comprises catalyst molecules and/or extremely small particles that are colloidal in size (i.e., less than 100 nm, less than about 10 nm, less than about 5 nm, and less than about 1 nm).
  • the colloidal / nanometer sized particles aggregate in a hydrocarbon diluent, forming a slurry catalyst with an average particle size in the range of 1-20 microns.
  • the catalyst comprises single layer MoS 2 clusters of nanometer sizes, e.g., 5-10 nm on edge.
  • the amount of fresh catalyst feed into the contacting zone(s) range from 50 to 15000 wppm of Mo (concentration in heavy oil feed).
  • the concentration of the fresh catalyst feed ranges from 150 to 2000 wppm Mo.
  • the concentration is less than 10,000 wppm Mo.
  • the concentration of the fresh catalyst into each contacting zone may vary depending on the contacting zone employed in the system, as catalyst may become more concentrated as volatile fractions are removed from a non- volatile resid fraction, thus requiring adjustment of the catalyst concentration.
  • Optional Treatment System - SDA In one embodiment of the invention, a solvent deasphalting unit (SDA) is employed before the first contacting zone to pre-treat the heavy oil feedstock. In yet another embodiment, a solvent deasphalting unit is employed as an intermediate unit located after one of the intermediate separation zones.
  • SDA solvent deasphalting unit
  • SDA units are typically used in refineries to extract incremental lighter hydrocarbons from a heavy hydrocarbon stream, whereby the extracted oil is typically called deasphalted oil (DAO), while leaving a residue stream behind that is more concentrated in heavy molecules and heteroatoms, typically known as SDA Tar, SDA Bottoms, etc.
  • DAO deasphalted oil
  • the SDA can be a separate unit or a unit integrated into the upgrade system.
  • Suitable solvent to be used includes, but not limited to hexane or similar C6+ solvent for a low volume SDA Tar and high volume DAO.
  • all of the heavy oil feed is pre-treated in the SDA and the DAO product is fed into the first contacting zone, or fed according to a split feed scheme with at least a portion going to a contacting zone other than the first in the series.
  • some of the heavy oil feed (depending on the source) is first pre-treated in the SDA and some of the feedstock is fed directly into the contacting zone(s) untreated.
  • the DAO is combined with the untreated heavy oil feedstock as one feed stream to the contacting zone(s).
  • the DAO and the untreated heavy oil feedstock are fed to the system as in separate feed conduits, with the DAO going to one or more of the contacting zones and the untreated heavy oil feed going to one or more of the same or different contacting zones.
  • the non- volatile fraction containing the slurry catalyst and optionally minimum quantities of coke / asphaltenes, etc. from at least one of the separation zones is sent to the SDA for treatment.
  • the DAO is sent to at least one of the contacting zones as a feed stream by itself, in combination with a heavy oil feedstock as a feed, or in combination with the bottom stream from one of the separation zones as a feed.
  • the DA Bottoms containing asphaltenes are sent away to recover metal in any carry-over slurry catalyst, or for applications requiring asphaltenes, e.g., blended to fuel oil, used in asphalt, or utilized in some other applications.
  • the quality of the DAO and DA Bottoms is varied by adjusting the solvent used and the desired recovery of DAO relative to the heavy oil feed.
  • an optional pretreatment unit such as the SDA
  • the more DAO oil that is recovered the poorer the overall quality of the DAO, and the poorer the overall quality of the DA Bottoms.
  • the solvent selection typically, as a lighter solvent is used for the SDA, less DAO will be produced, but the quality will be better, whereas if a heavier solvent is used, more DAO will be produced, but the quality will be lower. This is due to, among other factors, the solubility of the asphaltenes and other heavy molecules in the solvent.
  • the front-end contacting zone means the 1 st reactor in a system with three or less contacting zones. In another embodiment of a system with more than three contacting zones, the first front-end contacting zone may include both first and second reactors. In yet another embodiment, the first contacting zone means the 1 st reactor only.
  • water is used to indicate either water and / or steam. In one embodiment to control heavy metal deposit, water is optionally injected into the system. In one embodiment, the injection is at a rate of about 1 to 25 wt. % (relative to the heavy oil feedstock).
  • a sufficient amount of water is injected for a water concentration in the system in the range of 2 to 15 wt. %. In a third embodiment, a sufficient amount is injected for a water concentration in the range of 4 to 10 wt. %.
  • the water can be added to the heavy oil feedstock before or after preheating.
  • a substantial amount of water is added to the heavy oil feedstock admixture that is to be preheated, and a substantial amount of water is added directly to the front end contacting zone(s).
  • water is added to the front-end contacting zone(s) via the heavy oil feedstock only.
  • at least 50% of the water is added to the heavy oil feedstock mixture to be heated, and the rest of the water is added directly to the front end contacting zone(s).
  • the water introduced into the system at the preheating stage (prior to the preheating of the heavy oil feedstock), in an amount of about 1 to about 25 wt. % of the incoming heavy oil feedstock.
  • water is added to as part of the heavy oil feed to all of the contacting zones.
  • water is added to the heavy oil feed to the first contacting zone only.
  • water is added to the feed to the first two contacting zones only.
  • water is added directly into the contacting zone at multiple points along the contacting zone, in ratio of 1 to 25 wt. % of the heavy oil feedstock.
  • water is added directly into the first few contacting zones in the process which are the most prone to deposits of heavy metals.
  • the water is added to the process in the form of dilution steam. In one embodiment, at least 30% of the water added is in the form of steam.
  • the steam may be added at any point in the process. For example, it may be added to the heavy oil feedstock before or after preheating, to the catalyst / heavy oil mixture stream, and / or directly into the vapor phase of the contacting zones, or at multiple points along the first contacting zone.
  • the dilution steam stream may comprise process steam or clean steam. The steam may be heated or superheated in a furnace prior to being fed into the upgrade process.
  • the presence of the water in the process favorably alter the metallic compound sulfur molecular equilibrium, thus reducing the heavy metal deposit.
  • the addition of water is also believed to help control / maintain a desired temperature profile in the contacting zones.
  • the addition of water to the front end contacting zone(s) lowers the temperature of the reactor(s). As the reactor temperature is lowered, it is believed that the rate of reaction of the most reactive vanadium species slows down, allowing vanadium deposition onto the slurry catalyst to proceed in a more controlled manner and for the catalyst to carry the vanadium deposits out of the reactor thus limiting the solid deposit in the reactor equipment.
  • the addition of water reduces the heavy metal deposits in the reactor equipment at least 25% compared to an operation without the addition of water, for a comparable period of time in operation, e.g., for at least 2 months.
  • the addition of water reduces heavy metal deposits of at least 50% compared to an operation without the water addition.
  • the addition of water reduces heavy metal deposits of at least 75% compared to an operation without the water addition.
  • Controlling Heavy Metal Deposit with Reactor Temperature In one embodiment, instead of and / or in addition to the addition of water to the front end contacting zone(s), the temperature of the front end contacting zone(s) most prone to heavy metal deposits is lowered.
  • the temperature of the first reactor is set to be at least 1O 0 F. (5.56 0 C.) lower than the next reactor in series.
  • the first reactor temperature is set to be at least 15 0 F. (8.33 0 C.) than the next reactor in series.
  • the temperature is set to be at least 2O 0 F. (11.11 0 C.) lower.
  • the temperature is set to be at least 25 0 F. (13.89 0 C.) lower than the next reactor in series.
  • Controlling Heavy Metal Deposit with Recycled Catalyst Stream In one embodiment, at least a portion of the non- volatile stream from at least one of the separation zones and / or an interstage deasphalting unit is recycled back to the front end contacting zone(s) to control the heavy metal deposits.
  • this recycled stream ranges between 3 to 50 wt.% of total heavy oil feedstock to the process.
  • the recycled stream is in an amount ranging from 15 to 45 wt. % of the total heavy oil feedstock to the system.
  • the recycled stream is at least 10 wt. % of the total heavy oil feedstock to the system.
  • the recycled stream is 25 to 45 wt. % of the total heavy oil feed.
  • the recycled stream is at least 30 wt. %.
  • the recycled stream ranges between 35 to 45 wt. %
  • the recycled stream ranges between 30 to 40 wt. %.
  • the recycled stream comprises non- volatile materials from the last separation zone in the system, containing unconverted materials, heavier hydrocracked liquid products, slurry catalyst, small amounts of coke, asphaltenes, etc.
  • the recycled stream contains between 3 to 30 wt. % slurry catalyst.
  • the catalyst amount ranges from 5 to 20 wt. % .
  • the recycled stream contains 1 to 15 wt. % slurry catalyst.
  • Process Conditions In one embodiment, the process condition being controlled to be more or less uniformly across the contacting zones. In another embodiment, the condition varies between the contacting zones for upgrade products with specific properties.
  • the upgrade system is maintained under hydrocracking conditions, e.g., at a minimum temperature to effect hydrocracking of a heavy oil feedstock.
  • the system operates at a temperature ranging from 400 0 C (752 0 F) to 600 0 C (1112 0 F), and a pressure ranging from 10 MPa (1450 psi) to 25 MPa (3625 psi).
  • the process condition being controlled to be more or less uniformly across the contacting zones.
  • the condition varies between the contacting zones for upgrade products with specific properties.
  • the contacting zone process temperature ranges from about 400 0 C (752 0 F) to about 600 0 C (1112 0 F), less than 500 0 C (932 0 F) in another embodiment, and greater than 425 0 C. (797 0 F) in another embodiment.
  • the system operates with a temperature difference between the inlet and outlet of a contacting zone ranging from 5 to 5O 0 F. In a second embodiment, from 10 to 4O 0 F.
  • the temperature of the separation zone is maintained within + 9O 0 F (about + 5O 0 C) of the contacting zone temperature in one embodiment, within + 7O 0 F (about + 38.9 0 C) in a second embodiment, within + 15 0 F (about + 8.3 0 C) in a third embodiment, and within + 5 0 F (about + 2.8 0 C) in a fourth embodiment.
  • the temperature difference between the last separation zone and the immediately preceding contacting zone is within + 5O 0 F (about + 28 0 C).
  • the process pressure in the contacting zones ranges from about 10 MPa (1,450 psi) to about 25 MPa (3,625 psi) in one embodiment, about 15 MPa (2,175 psi) to about 20 MPa (2,900 psi) in a second embodiment, less than 22 MPa (3,190 psi) in a third embodiment, and more than 14 MPa (2,030 psi) in a fourth embodiment.
  • the pressure of the separation zone is maintained within +_10 to + 50 psi of the preceding contacting zone in one embodiment, and within + 2 to + 10 psi in a second embodiment.
  • the upgrade system is configured for optimal operation, e.g., efficiency with much less downtime due to equipment plugging compared to the prior art with less than 100 psi pressure drop.
  • the optimal efficiency is obtained in one embodiment with minimal pressure drop in the system, wherein the pressure of the separation zone is maintained within +_10 to + 100 psi of the preceding contacting zone in one embodiment, within + 20 to + 75 psi in a second embodiment, and within + 50 to + 100 psi in a third embodiment.
  • the pressure drop refers to the difference between the exit pressure of the preceding contacting zone X and the entry pressure of the separation Y, with (X-Y) being less than 100 psi.
  • Optimal efficiency can also be obtained with minimal pressure from one contacting zone to the next contacting zone for a system operating sequentially, with the pressure drop being maintained to be 100 psi or less in one embodiment, and 75 psi or less in a second embodiment, and less than 50 psi in a third embodiment.
  • the pressure drop herein refers to the difference between the exit pressure of one contacting zone and the entry pressure of the next contacting zone.
  • the contacting zone is in direct fluid communication to the next separation zone or contacting zone for a minimum pressure drop.
  • direct fluid communication means that there is free flow from the contacting zone to the next separation zone (or the next contacting zone) in series, with no flow restriction.
  • direct fluid communication is obtained with no flow restriction due to presence of valves, orifices (or a similar device), or changes in pipe diameter.
  • the minimal pressure drop from the contacting zone to the next separation zone or contacting zone is due to piping components, e.g., elbows, bends, tees in the line, etc., and not due to the use of pressure reducing device such as valves, control valves, etc. to induce the pressure drop as in the prior art.
  • pressure reducing device such as valves, control valves, etc.
  • the minimal pressure drop is induced by friction loss, wall drag, volume increase, and changes in height as the effluent flows from the contacting zone to the next equipment in series. If valves are used in the once through system, the valves are selected / configured such that the pressure drop from one equipment, e.g., the contacting zone, to the next piece of equipment is kept to be at 100 psi or lower.
  • the liquid hourly space velocity (LHSV) of the heavy oil feed will generally range from about 0.025 h “1 to about 10 h “1 , about 0.5 h “1 to about 7.5 h “1 , about 0.1 h. -1 to about 5 h “1 , about 0.75 h “1 to about 1.5 h “1 , or about 0.2 h “1 to about 10 h “1 .
  • LHSV is at least 0.5 h "1 , at least 1 h "1 , at least 1.5 h “1 , or at least 2 h “1 .
  • the LHSV ranges from 0.025 to 0.9 h "1 .
  • the LHSV ranges from 0.1 to 3 LHSV. In another embodiment, the LHSV is less than 0.5 h "1 .
  • the solid deposit in the last contacting zone in the system decreases by at least 10% (in terms of deposit volume) after a similar run time compared to a prior art operation without deasphalting with the SDA unit. In a second embodiment, the solid deposit decreases by at least 20% compared to an operation without the use of the interstage SDA unit. In a third embodiment, the solid deposit decreases at least 30%.
  • the shift in the location of the fresh catalyst injection yields a significant boost in overall catalytic activity, with the improved quality of the non- volatile stream from the last separation zone in the system (bleed stream, "Stripper Bottoms" or STB) in terms of API, viscosity, MCR level, nickel, Hydrogen / Carbon ratio, and hot heptane asphaltenes (HHA) level.
  • less catalyst bleeding is also observed with the overall improvement in catalytic activity.
  • the STB product improvements include a nickel reduction of at least 10%, in a second embodiment, a nickel reduction of at least 20%. In a third embodiment, a Ni level of less than 10 ppm. [0124] In one embodiment, the MCR reduction in the STB is at least 5%. In another embodiment, the MCR reduction is at least 10%. In a third embodiment, the MCR level is less than 13 wt. %.
  • the STB displays an API viscosity improvement of at least 15%.
  • an API viscosity improvement of at least 30% In a third embodiment, an API viscosity of at least 50%, going from 2.7 to 4.5. It is observed that in some embodiments, the improvement of the API is due to overall improved catalytic activity, thus resulting in a higher H/C ratio.
  • the heavy oil split feed scheme reduces or eliminates "over-conversion events" or "dry” conditions often observed in hydroprocessing reactors. In upgrade system running under “dry” conditions, insufficient liquid flow is present thus leading to solids buildup / coking, degrading flow patterns and / or hydrodynamics, degrading thermometry, loss of reaction volume, eventually compromised performance, stability and longevity of the operation.
  • FIG. 1 is a block diagram schematically illustrating a system for upgrading heavy oil feedstock with reduced heavy metal deposits.
  • a heavy oil feedstock is introduced into the first contacting zone in the system together with a slurry catalyst feed.
  • the slurry catalyst feed comprises a combination of fresh catalyst and recycled catalyst slurry as separate streams.
  • Hydrogen may be introduced together with the feed in the same conduit, or optionally, as a separate feed stream.
  • Water and / or steam may be introduced together with the feed and slurry catalyst in the same conduit or a separate feed stream.
  • the mixture of water, heavy oil feed, and slurry catalyst can be preheated in a heater prior to feeding into the contacting zone.
  • additional hydrocarbon oil feed e.g., VGO, naphtha
  • VGO vanadium-oxide-semiconductor
  • the system may comprise recirculating / recycling channels and pumps for promoting the dispersion of reactants, catalyst, and heavy oil feedstock in the contacting zones, particularly with a high recirculation flow rate to the first contacting zone to induce turbulent mixing in the reactor, thus reducing heavy metal deposits.
  • a recirculating pump circulates through the loop reactor, thus maintaining a temperature difference between the reactor feed point to the exit point ranging from 1 to 5O 0 F, and preferably between 2-25 0 F.
  • the water / steam in the first contacting zone is expected to cut down on the heavy metal deposits onto the equipment.
  • the temperature of the first contacting zone can be kept at least 5 - 25 degrees (Fahrenheit) lower than the temperature of the next contacting zone in series.
  • Upgraded material is withdrawn from the 1 st contacting zone and sent to a separation zone, e.g., a hot separator, operated at a high temperature and high pressure similar to the contacting zone.
  • the upgraded material may be alternatively introduced into one or more additional hydroprocessing reactors (not shown) for further upgrading prior to going to the hot separator.
  • the separation zone causes or allows the separation of gas and volatile liquids from the non- volatile fractions.
  • the gaseous and volatile liquid fractions are withdrawn from the top of the separation zone for further processing.
  • the non- volatile (or less volatile) fraction is withdrawn from the bottom.
  • Slurry catalyst and entrained solids, coke, hydrocarbons newly generated in the hot separator, etc. are withdrawn from the bottom of the separator and fed to the next contacting zone in the series.
  • a portion of the non- volatile stream is recycled back to one of the contacting zones preceding the separation zone, providing recycled catalyst for use in the hydroconversion reactions.
  • portions of the fresh catalyst feed and heavy oil feedstock are fed directly into contacting zones (reactors) other than the 1 st contacting zone in the system.
  • water and / or steam is also provided to the contacting zones as a separate feed stream, or introduced together with the feed and slurry catalyst in the same conduit.
  • the liquid stream from the preceding separation zone is combined with optional fresh catalyst, optional additional heavy oil feed, optional hydrocarbon oil feedstock such as VGO (vacuum gas oil), and optionally recycled catalyst (not shown) as the feed stream for the next contacting zone in the series.
  • Hydrogen may be introduced together with the feed in the same conduit, or optionally, as a separate feed stream.
  • Upgraded materials along with slurry catalyst flow to the next separation zone in series for separation of gas and volatile liquids from the non- volatile fractions.
  • the gaseous and volatile liquid fractions are withdrawn from the top of the separation zone, and combined with the gaseous and volatile liquid fractions from a preceding separation zone for further processing.
  • the non-volatile (or less volatile) fraction stream is withdrawn and sent to the next contacting zone in series for the unconverted heavy oil feedstock to be upgraded.
  • the system may optionally comprise an in-line hydrotreater (not shown) for treating the gaseous and volatile liquid fractions from the separation zones.
  • the in-line hydrotreater in one embodiment employs conventional hydrotreating catalysts, is operated at a similarly high pressure (within 10 psig) as the rest of the upgrade system, and capable of removing sulfur, Ni, V, and other impurities from the upgraded products.
  • the in-line hydrotreater operates at a temperature within 100 0 F of the temperature of the contacting zones.
  • FIG. 2 is a flow diagram of a heavy oil upgrade process with water injection.
  • water 81 is injected into the system with the heavy oil feedstock, with the mixture being preheated in furnace before being introduced into the contacting zone.
  • Water / steam can also be optionally injected into the system after the preheater as stream 82.
  • the fresh catalyst feed is split amongst the contacting zones.
  • Recycle catalyst stream 17, water / heavy oil feedstock mixture, and hydrogen gas 2 are fed to the first contacting zone as feed 3.
  • Stream 4 comprising upgraded heavy oil feedstock exits the contacting zone
  • R- 10 flows to a separation zone 40, wherein gases (including hydrogen) and upgraded products in the form of volatile liquids are separated from the non- volatile liquid fraction 7 and removed overhead as stream 6.
  • gases including hydrogen
  • upgraded products in the form of volatile liquids are separated from the non- volatile liquid fraction 7 and removed overhead as stream 6.
  • the non- volatile stream 7 is sent to the next contacting zone 20 in series for further upgrade.
  • Non- volatile stream 7 contains slurry catalyst in combination with unconverted oil, and small amounts of coke and asphaltenes in some embodiments.
  • the upgrade process continues with the other contacting zones as shown, wherein the feed stream to contacting zone 20 comprises non- volatile fractions, hydrogen feed, optional VGO feed, and fresh catalyst feed 32.
  • stream 8 comprising upgraded heavy oil feedstock flows to separation zone 50, wherein upgraded products are combined with hydrogen and removed as overhead product 9.
  • Bottom stream 11 containing non- volatile fractions, e.g., catalyst slurry, unconverted oil containing coke and asphaltenes flow to the next contacting zone in the series 30.
  • contacting zone 30 additional hydrogen containing gas 16, fresh catalyst 33, optional hydrocarbon feed such as VGO (not shown), optional untreated heavy oil feed (not shown), are added to the non-volatile stream from the preceding separation zone.
  • optional hydrocarbon feed such as VGO (not shown)
  • optional untreated heavy oil feed (not shown)
  • upgraded products, unconverted heavy oil, slurry catalyst, hydrogen, etc. are removed overhead as stream 12 and sent to the next separation zone 60.
  • overhead stream 13 containing hydrogen and upgraded products is combined with the overhead streams from preceding separation zones, and sent away for subsequent processing in another part of the system, e.g., to a high pressure separator and / or lean oil contactor and / or an in-line hydrotreater (not shown).
  • a portion of the non- volatile stream 17 is removed as bleed-off stream 18.
  • FIG. 3 is a flow diagram of another embodiment of the heavy oil upgrade process, but with steam injection 91 instead of/ or in addition to the water injection stream 81.
  • Figure 4 is a flow diagram of another embodiment of the heavy oil upgrade process, with a recycled catalyst stream 19 ranging between 3 to 50 wt.% of total heavy oil feedstock to the process.
  • FIG. 5 is a block diagram schematically illustrating another embodiment for upgrading heavy oil feedstock.
  • a heavy oil feedstock is introduced into the first contacting zone in the system together with a slurry catalyst feed.
  • Hydrogen may be introduced together with the feed in the same conduit, or optionally, as a separate feed stream.
  • optional hydrocarbon oil feedstock such as VGO (vacuum gas oil), naphtha, MCO (medium cycle oil), solvent donor, or other aromatic solvents, etc. in an amount ranging from 2 to 30 wt. % of the heavy oil feed.
  • the additional hydrocarbon feedstock may be used to modify the concentration of metals and impurities in the system.
  • at least a portion of the heavy oil feedstock (higher boiling point hydrocarbons) is converted to lower boiling hydrocarbons, forming an upgraded product.
  • Upgraded material is withdrawn from the 1 st contacting zone and sent to a separation zone, e.g., a hot separator.
  • the upgraded material may be alternatively introduced into one or more additional hydroprocessing reactors (not shown) for further upgrading prior to going to the hot separator.
  • the separation zone causes or allows the separation of gas and volatile liquids from the non- volatile fractions.
  • the gaseous and volatile liquid fractions are withdrawn from the top of the separation zone for further processing.
  • the non- volatile (or less volatile) fraction is withdrawn from the bottom.
  • Slurry catalyst small amounts of heavier hydrocracked liquid products, and entrained solids, coke, hydrocarbons newly generated in the hot separator, etc., are withdrawn from the bottom of the separator and fed to the next contacting zone in the series.
  • a portion of the nonvolatile stream is recycled back to the contacting zone directly preceding the separation zone, in an amount equivalent to 2 to 40 wt. % of the total heavy oil feed.
  • the non- volatile stream from the preceding separation zone containing unconverted feedstock is combined with additional fresh catalyst, optional additional heavy oil feed, and optionally recycled catalyst (not shown) as the feed stream for the next contacting zone in the series.
  • next contacting zone and under hydrocracking conditions more of the heavy oil feedstock is upgraded to lower boiling hydrocarbons.
  • Upgraded materials along with slurry catalyst flow to the next separation zone in series for separation of gas and volatile liquids from the non- volatile fractions.
  • the non- volatile (or less volatile) stream is withdrawn from the bottom.
  • the gaseous and volatile liquid fractions are withdrawn from the top of the separation zone (and combined with the gaseous and volatile liquid fractions from a preceding separation zone) as "upgraded" products for further processing or blending, e.g., for final blended products meeting specifications designated by refineries and / or transportation carriers.
  • the non- volatile material containing unconverted materials is sent to the next contacting zone in series.
  • the non- volatile material is recycled back to one of the contacting zones in the system, with a portion of the material being bled off for further processing, e.g., going to a solvent deasphalting unit, a catalyst deoiling unit and subsequently a metal recovery system.
  • the recycled non- volatile material in one embodiment is an amount equivalent to 2 to 50 wt. % of the heavy oil feedstock to the system, providing recycled catalyst for use in the hydroconversion reactions.
  • the outlet stream from the contacting zones comprises a ratio of 20:80 to 60:40 of upgraded products to unconverted heavy oil feed.
  • the amount of upgraded products out of the first contacting zone is in the range of 30-35% to unconverted heavy oil product of 65-70%.
  • the system may optionally comprise recirculating / recycling channels and pumps for promoting the dispersion of reactants, catalyst, and heavy oil feedstock in the contacting zones.
  • a recirculating pump circulates through the loop reactor a volumetric recirculation ratio of 5: 1 to 15:1 (recirculated amount to heavy oil feed ratio), thus maintaining a temperature difference between the reactor feed point to the exit point ranging from 10 to 5O 0 F, and preferably between 20-40 0 F.
  • the system may optionally comprise an in-line hydrotreater (not shown) for treating the gaseous and volatile liquid fractions from the separation zones.
  • the in-line hydrotreater in one embodiment employs conventional hydrotreating catalysts, is operated at a similarly high pressure (within 10 psig in one embodiment, and 50 psig in a second embodiment) as the rest of the upgrade system, and capable of removing sulfur, Ni, V, and other impurities from the upgraded products.
  • FIG. 6 is a block diagram schematically illustrating another embodiment of an upgrade system, wherein a solvent deasphalting unit is employed for pre-treating some, if not all of the heavy oil feed to the system.
  • the de-asphaltened oil (DAO) can be fed directly to the contacting zone(s) or combined with a heavy oil feed stream as a feedstock.
  • other hydrocarbon materials e.g., VGO
  • All of the fresh catalyst can be fed directly to the 1 st contacting zone in the system, or diverted to other contacting zone(s) in the series.
  • FIG. 7 is a flow diagram of a heavy oil upgrade process with a fresh catalyst split feed scheme, wherein some of the fresh catalyst feed is diverted from the first reactor to other reactors in the process. As shown, the fresh catalyst feed is split amongst the various contacting zones as feed streams 31, 32, and 33. Fresh catalyst feed 31 is combined with the recycle catalyst stream 17 and fed to the first contacting zone as slurry catalyst feed 3.
  • Hydrogen gas 2 and heavy oil feedstock 1 are combined with slurry catalyst 3 as feed into the first contacting zone 10.
  • heavy oil feedstock is preheated in furnace 80 before being introduced into the contacting zone as heated oil feed 4.
  • Stream 5 comprising upgraded heavy oil feedstock exits the contacting zone 10 and flows to a separation zone 40, wherein gases (including hydrogen) and volatile upgraded products are separated from the non- volatile fractions 7 and removed overhead as stream 6.
  • the non- volatile fractions stream 7 is sent to the next contacting zone 20 in series for further upgrade.
  • Stream 7 contains slurry catalyst in combination with unconverted oil, and small amounts of coke and asphaltenes in some embodiments.
  • the upgrade process continues with the other contacting zones as shown, wherein stream 7 is combined with hydrogen feed 15 and fresh catalyst 32 as feed stream into contacting zone 20.
  • the streams can also be fed to the contacting zone in separate conduits.
  • Stream 8 comprising upgraded heavy oil feedstock flows to separation zone 50, wherein upgrade products are combined with hydrogen and removed as overhead product 9.
  • Bottom stream 11 containing catalyst slurry, unconverted oil (plus small amounts of coke and asphaltenes in some embodiments) is combined with a fresh catalyst stream 33 and a fresh supply of hydrogen 16 as feed stream to the next contacting zone 30.
  • Stream 12 exits the contacting zone and flows to separation zone 60, wherein upgraded products and hydrogen are removed overhead as stream 13.
  • Some of the bottom stream 17 from the separation zone, which contains catalyst slurry, unconverted oil plus small amounts of coke and asphaltenes in some embodiments, is recycled back to the 1 st contacting zone 10 as recycled stream 19.
  • vapor stream 14 containing the upgraded products and hydrogen in one embodiment is subsequently processed in another part of the system, e.g., in a high pressure separator and / or lean oil contactor.
  • FIG. 8 illustrates another embodiment of the invention, wherein reactors having internal separators are employed, thus separate hot separators / flash drums are not necessary for phase separation.
  • a reactor differential pressure control system (not shown) is employed, regulating the product stream out of the top of each reactor- separator.
  • External pumps (not shown) may be employed to aid in the dispersion of the slurry catalyst in the system and help control the temperature in the system.
  • Recycled catalyst stream 19 provides slurry catalyst feed to the first contacting zone, and optionally, to other contacting zone(s) in the system.
  • additional hydrocarbon oil feed e.g., VGO, naphtha
  • VGO vanadium-oxide-semiconductor
  • naphtha in an amount ranging from 2 to 30 wt. % of the heavy oil feed can be optionally added as part of the feed stream to any of the contacting zones in the system.
  • Figure 9 illustrates an embodiment of the invention wherein all of the fresh catalyst feed 99 is fed directly to the last contacting zone in the upgrade system, with other contacting zone(s) in the system simply getting a portion of the recycled catalyst stream 19.
  • Figure 10 illustrates is an embodiment of a heavy oil split feed scheme. As shown, some of heavy oil feed is diverted from the 1 st reactor and fed directly to the 2 nd contacting zone in the system as heavy oil feed stream 42. Also as shown, recycled catalyst is optionally sent to the 2 nd contacting zone in the system along with portions of the fresh catalyst as stream 32.
  • Comparative Example 1 Heavy oil upgrade experiments were carried out in a pilot system having three gas-liquid slurry phase reactors connected in series with three hot separators, each being connected in series with the reactors. The upgrade system was run continuously for about 50 days. [0161] A fresh slurry catalyst used was prepared according to the teaching of US Patent No.
  • a Mo compound was first mixed with aqueous ammonia forming an aqueous Mo compound mixture, sulf ⁇ ded with hydrogen compound, promoted with a Ni compound, then transformed in a hydrocarbon oil (other than heavy oil feedstock) at a temperature of at least 35O 0 F and a pressure of at least 200 psig, forming an active slurry catalyst to send to the first reactor.
  • a hydrocarbon oil other than heavy oil feedstock
  • the hydroprocessing conditions were as follows: a reactor temperature (in three reactors) of about 825 0 F.; a total pressure in the range of 2400 to 2600 psig; a fresh Mo/ fresh heavy oil feed ratio (wt. %) 0.20 - 0.40; fresh Mo catalyst /total Mo catalyst ratio 0.125 - 0.250; total feed LHSV about 0.070 to 0.15; and H 2 gas rate (SCF/ bbl) of 7500 to 20000.
  • Effluent taken from each reactor was sent to the separator (connected in series), and separated into a hot vapor stream and a non-volatile stream. Vapor streams were removed from the top of the high pressure separators and collected for further analysis ("HPO" or high-pressure overhead streams). The non- volatile stream containing slurry catalyst and unconverted heavy oil feedstock was removed from the separator and sent to the next reactor in series.
  • HPO high-pressure overhead streams
  • a portion of the non- volatile stream from the last separator in an amount of 30 wt. % of heavy oil feedstock was recycled (STB), and the rest was removed as a bleed stream (in an amount of about 15 wt. % of the heavy oil feedstock).
  • the STB stream contains about 10 to 15 wt. % slurry catalyst.
  • Example 2 Example 1 was repeated, except that the temperature of the 1 st reactor was decreased 2O 0 F. (from about 825 0 F. to about 805 0 F), the recycled catalyst rate was increased from 30 wt. % (in Example 1) to about 40 wt. % of the heavy oil feed rate, and water was added to the front end reactor at a rate equivalent to 5 wt. % of the heavy oil feed rate. The system ran for 54 days before shutdown.
  • Water injection was carried out by adding water to the fresh catalyst, then the water catalyst mixture was added to an autoclave along with the heavy oil feed and hydrogen, with the mixture being pre -heated to a temperature of about 35O 0 F.
  • Example 3 Heavy oil upgrade experiments were carried out in a pilot system having three gas-liquid slurry phase reactors connected in series with two hot separators. The hot separators are connected in series with the 1 st and 3 rd reactors respectively, with no hot separator following the 2 nd reactor. The gas-liquid slurry phase reactors were continuously stirred reactors. The upgrade system was run continuously for about 70 days.
  • a fresh slurry catalyst used was prepared according to the teaching of US Patent No. 2006/0058174, i.e., a Mo compound was first mixed with aqueous ammonia forming an aqueous Mo compound mixture, sulfided with hydrogen/sulfur compound, promoted with a Ni compound, then transformed in a hydrocarbon oil (other than heavy oil feedstock) at a temperature of at least 35O 0 F and a pressure of at least 200 psig, forming an active slurry catalyst.
  • Effluent taken from the 1 st and 3 rd reactors was introduced into the hot separators connected in series with the reactors, and separated into a hot vapor stream and a non- volatile stream. Vapor streams were removed from the top of the high pressure separators and collected for further analysis ("HPO" or high-pressure overhead streams). The non- volatile stream containing slurry catalyst and unconverted heavy oil feedstock was removed from the bottom of the 1 st separator and sent to the 2 nd reactor in series. Effluent from the 2 nd reactor was sent directly to the 3 rd reactor as feedstock.
  • a portion of the non- volatile stream from the last separator in an amount of 5 - 15 wt. % of heavy oil feedstock was removed as the bleed-off stream, for an overall conversion rate of 98 to 98.5% of heavy oil feed to distillate products.
  • the rest of the nonvolatile stream, the "Stripper Bottoms product" or STB, containing the bulk of the catalyst (in an amount of 80 to 95% of total slurry catalyst entering the system) was recycled back to the first reactor for maintaining the flow of catalyst through the upgrade system.
  • the STB stream contains about 7 to 20 wt% slurry catalyst.
  • the STB was also analyzed to evaluate the overall performance of the system.
  • the improvement in STB product API did not correlate with an improvement in the distillation of the STB product.
  • the STB product API did not improve due to additional cracking in a lighter product distillation, but due to improved catalytic activity, resulting into a higher H/C ratio.
  • Example 5 Comparative Example 3 is repeated except that 20% of the heavy oil feedstock is diverted from the 1 st reactor to the 3 rd reactor while other process conditions remain the same.
  • Example 5 with a portion of the heavy oil feedstock being fed directly to the last reactor, it is anticipated that the preceding reactors (1 st and 2 nd ) with a decrease in liquid throughput (as a portion of the heavy oil feedstock is diverted) and a corresponding increase in catalyst concentration will operate more efficiently and with a higher conversion rate. Additionally, with more liquid dilution in the 3 rd reactor, there is a more uniform catalyst concentration profile across all three reactors.

Abstract

La présente invention concerne des systèmes et des procédés d'hydrotraitement d'une charge d'alimentation constituée de pétrole lourd, entraînant une réduction des dépôts de pétrole lourd. Ces systèmes ont recours à une pluralité de zones de contact et de zones de séparation, permettant la conversion, dans des conditions d'hydrocraquage, d'au moins une partie de la charge d'alimentation constituée de pétrole lourd en des hydrocarbures à point d'ébullition plus bas, ainsi que l'obtention de produits valorisés, de l'eau et/ou de la vapeur d'eau étant éventuellement injectées dans la première zone de contact à hauteur de 1 à 25 % en poids du poids de la charge d'alimentation constituée de pétrole lourd. Dans un mode de réalisation, la première zone de contact est portée à une température inférieure d'au moins -12 °C (10°F) à celle de la zone de contact suivante. Des conditions d'hydrocraquage règnent au niveau des zones de contact et l'on utilise un catalyseur en suspension pour valoriser la charge d'alimentation constituée de pétrole lourd, ce qui permet d'obtenir des produits valorisés correspondant à des hydrocarbures à point d'ébullition plus bas. Dans les zones de séparation, les produits ainsi valorisés, constituant le distillat de tête, sont prélevés et, éventuellement, soumis à un autre traitement dans un dispositif d'hydrotraitement en ligne. Au moins une partie des fractions non volatiles récupérées au niveau d'au moins l'une des zones de séparation est recyclée dans le système, au niveau de la première zone de contact, à hauteur de 3 à 50 % en poids de la charge d'alimentation constituée de pétrole lourd. Dans un mode de réalisation, au moins une partie de la charge d'alimentation constituée de pétrole lourd est acheminée jusqu'à au moins une zone de contact autre que la première zone de contact et/ou au moins une partie du catalyseur en suspension frais est acheminée jusqu'à au moins une zone de contact autre que la première zone de contact. Dans un mode de réalisation, au moins une partie des fractions non volatiles récupérées au niveau d'au moins l'une des zones de séparation est envoyée en direction de l'unité intermédiaire de désasphaltage au solvant, afin de séparer la charge d'alimentation constituée de pétrole lourd non converti en pétrole désasphalté et en asphaltènes. Le flux de pétrole désasphalté est envoyé vers l'une des zones de contact pour une nouvelle valorisation.
PCT/US2009/056915 2008-09-18 2009-09-15 Systèmes et procédés de production d'un produit brut WO2010033480A2 (fr)

Priority Applications (8)

Application Number Priority Date Filing Date Title
CN200980142574.XA CN102197116B (zh) 2008-09-18 2009-09-15 用于生产粗产品的系统和方法
BRPI0918085A BRPI0918085A2 (pt) 2008-09-18 2009-09-15 processo para hidroprocessar uma carga de alimentacao de oleo pesado
JP2011527896A JP5661038B2 (ja) 2008-09-18 2009-09-15 粗生成物を生成するためのシステム及び方法
EA201170463A EA023427B1 (ru) 2008-09-18 2009-09-15 Способ гидрокрекинга исходного сырья на основе тяжелой нефти
KR1020117008794A KR101700224B1 (ko) 2008-09-18 2009-09-15 원유 제품 생산을 위한 시스템 및 방법
EP09815045.1A EP2331657B1 (fr) 2008-09-18 2009-09-15 Systèmes et procédés de production d'un produit brut
MX2011002970A MX2011002970A (es) 2008-09-18 2009-09-15 Sistemas y metodos para producir un producto crudo.
CA2737367A CA2737367C (fr) 2008-09-18 2009-09-15 Systemes et procedes de production d'un produit brut

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US12/233,439 2008-09-18
US12/233,439 US7938954B2 (en) 2005-12-16 2008-09-18 Systems and methods for producing a crude product
US12/212,796 2008-09-18
US12/233,393 2008-09-18
US12/212,737 2008-09-18
US12/233,171 2008-09-18
US12/212,796 US7897035B2 (en) 2008-09-18 2008-09-18 Systems and methods for producing a crude product
US12/233,393 US7935243B2 (en) 2008-09-18 2008-09-18 Systems and methods for producing a crude product
US12/212,737 US7931796B2 (en) 2008-09-18 2008-09-18 Systems and methods for producing a crude product
US12/233,171 US8372266B2 (en) 2005-12-16 2008-09-18 Systems and methods for producing a crude product
US12/233,327 2008-09-18
US12/233,327 US7897036B2 (en) 2008-09-18 2008-09-18 Systems and methods for producing a crude product

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CN102197116A (zh) 2011-09-21
EP2331657A4 (fr) 2012-05-16
WO2010033480A3 (fr) 2010-06-03
EP2331657A2 (fr) 2011-06-15
EA201170463A1 (ru) 2011-10-31
KR20110059881A (ko) 2011-06-07
EP2331657B1 (fr) 2023-10-18
CN102197116B (zh) 2014-05-14
CA2737367A1 (fr) 2010-03-25
CA2737367C (fr) 2018-03-06
JP2012503071A (ja) 2012-02-02
JP5661038B2 (ja) 2015-01-28
BRPI0918085A2 (pt) 2019-09-24
MX2011002970A (es) 2011-04-11
KR101700224B1 (ko) 2017-01-31
EA023427B1 (ru) 2016-06-30

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