Classifications

• • 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
  • C10G65/14—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural parallel 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
  • C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
  • C10G1/06—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by destructive hydrogenation
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
  • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
  • C10G21/12—Organic compounds only
  • C10G21/14—Hydrocarbons
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes 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
  • 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
  • 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
  • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
  • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
  • C10G67/04—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including solvent extraction as the refining step in the absence of hydrogen
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
  • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
  • C10G67/04—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including solvent extraction as the refining step in the absence of hydrogen
  • C10G67/0454—Solvent desasphalting
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
  • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
  • C10G67/04—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including solvent extraction as the refining step in the absence of hydrogen
  • C10G67/0454—Solvent desasphalting
  • C10G67/0463—The hydrotreatment being a hydrorefining
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
  • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
  • C10G67/04—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including solvent extraction as the refining step in the absence of hydrogen
  • C10G67/0454—Solvent desasphalting
  • C10G67/049—The hydrotreatment being a hydrocracking
• • 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
  • C10G2300/107—Atmospheric residues having a boiling point of at least about 538 °C
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
  • C10G2300/10—Feedstock materials
  • C10G2300/1077—Vacuum residues

Definitions

• Embodiments disclosed herein relate generally to hydroconversion processes, including processes for hydrocracking residue and other heavy hydrocarbon fractions. More specifically, embodiments disclosed herein relate to solvent deasphalting of a residuum hydrocarbon feedstock, processing the resulting deasphalted oil in a residue desulfurization unit and a residue hydrocracking unit, and processing the pitch from the solvent deasphalting unit in a separate residue hydrocracking unit.
• embodiments disclosed herein relate to a process for upgrading residuum hydrocarbons.
• the process may include the following steps: solvent deasphalting a residuum hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction; contacting the asphalt fraction and hydrogen with a first hydroconversion catalyst in a first ebullated bed hydroconversion reactor system; recovering an effluent from the first ebullated bed hydroconversion reactor system; fractionating the effluent from the first ebullated bed hydroconversion reactor system to recover one or more hydrocarbon fractions.
• embodiments disclosed herein relate to a process for upgrading residuum hydrocarbons which may include the following steps: solvent deasphalting a residuum hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction; contacting the asphalt fraction and hydrogen with a first hydroconversion catalyst in a first ebullated bed hydroconversion reactor system; recovering an effluent from the first ebullated bed hydroconversion reactor system; fractionating the effluent from the first ebullated bed hydroconversion reactor system to recover one or more hydrocarbon fractions; contacting the deasphalted oil fraction and hydrogen with a second hydroconversion catalyst in a residue hydrodesulfurization unit; recovering an effluent from the residue hydrodesulfurization unit; contacting the residue hydrodesulfurization unit effluent with a third hydroconversion catalyst in a hydrocracking reactor system; recovering an effluent from the hydrocracking reactor system; and fractionating the effluent from the hydrocracking reactor
• embodiments disclosed herein relate to a process for upgrading residuum hydrocarbons which may include the following steps: solvent deasphalting a residuum hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction; contacting the asphalt fraction and hydrogen with a first hydroconversion catalyst in a first ebullated bed hydroconversion reactor system; recovering an effluent from the first ebullated bed hydroconversion reactor system; fractionating the effluent from the first ebullated bed hydroconversion reactor system to recover one or more hydrocarbon fractions; contacting the deasphalted oil fraction and hydrogen with a second hydroconversion catalyst in a residue hydrodesulfurization unit; recovering an effluent from the residue hydrodesulfurization unit; fractionating the effluent from the hydrocracking reactor system to recover one or more hydrocarbon fractions including a vacuum residua hydrocarbon fraction; contacting the vacuum residua hydrocarbon fraction with a third hydroconversion catalyst in
• Figure 1 is a simplified process flow diagram of a process for upgrading residuum hydrocarbon feedstocks according to embodiments disclosed herein.
• Figure 2 is a simplified process flow diagram of a process for upgrading residuum hydrocarbon feedstocks according to embodiments disclosed herein.
• Figure 3 is a simplified process flow diagram of a process for an integrated hydroprocessing reactor system to be used with a process for upgrading residuum hydrocarbon feedstocks according to embodiments disclosed herein.
• Figure 4 is a simplified alternate process flow diagram of a process for an integrated hydroprocessing reactor system to be used with a process for upgrading residuum hydrocarbon feedstocks according to embodiments disclosed herein.
• embodiments herein relate generally to hydroconversion processes, including processes for hydrocracking residue and other heavy hydrocarbon fractions. More specifically, embodiments disclosed herein relate to solvent deasphalting of a residuum hydrocarbon feedstock, processing the resulting deasphalted oil in a residue desulfurization unit and a residue hydrocracking unit, and processing the pitch from the solvent deasphalting in a separate residue hydrocracking unit.
• Hydroconversion processes disclosed herein may be used for reacting residuum hydrocarbon feedstocks at conditions of elevated temperatures and pressures in the presence of hydrogen and one or more hydroconversion catalyst to convert the feedstock to lower molecular weight products with reduced contaminant (such as sulfur and/or nitrogen) levels. Hydroconversion processes may include, for example, hydrogenation, hydrodesulfurization, hydrodenitrogenation, hydrocracking, hydrodemetallization, hydroDeCCR or hydrodeaphaltenization, etc.
• residuum hydrocarbon fractions are defined as a hydrocarbon fraction having boiling points or a boiling range above about 340°C but could also include whole heavy crude processing.
• Residuum hydrocarbon feedstocks that may be used with processes disclosed herein may include various refinery and other hydrocarbon streams such as petroleum atmospheric or vacuum residua, deasphalted oils, deasphalter pitch, hydrocracked atmospheric tower or vacuum tower bottom, straight run vacuum gas oils, hydrocracked vacuum gas oils, fluid catalytically cracked (FCC) slurry oils, vacuum gas oils from an ebullated bed hydrocracking process, shale-derived oils, coal-derived oils, tar sands bitumen, tall oils, bio-derived crude oils, black oils, as well as other similar hydrocarbon streams, or a combination of these, each of which may be straight run, process derived, hydrocracked, partially desulfurized, and/or partially demetallized streams.
• residuum hydrocarbon fractions may include hydrocarbons having a normal boiling point of at least 480°C, at least 524°C, or at least 565°C.
• a residuum hydrocarbon fraction (residuum) 10 is fed to a Solvent Deasphalting Unit (SDA) 12.
• SDA 12 the residuum hydrocarbon is contacted with a solvent to selectively dissolve asphaltenes and similar hydrocarbons to produce a deasphalted oil (DAO) fraction 14 and a pitch fraction 15.
• DAO deasphalted oil
• Solvent deasphalting may be performed in SDA 12, for example, by contacting the residuum hydrocarbon feed with a light hydrocarbon solvent at temperatures in the range from about 38°C to about 204°C and pressures in the range from about 7 barg to about 70 barg.
• Solvents useful in SDA 12 may include C3, C4, C5, C6 and/or C7 hydrocarbons, such as propane, butane, isobutene, pentane, isopentane, hexane, heptane, or mixtures thereof, for example.
• the use of the light hydrocarbon solvents may provide a high lift (high DAO yield).
• the DAO fraction 14 recovered from the SDA unit 12 may contain 500 wppm to 5000 wppm asphaltenes (i.e., heptane insoluble), 50 to 150 wppm metals (such as Ni, V, and others), and 5 wt% to 15 wt% Conradson Carbon Residue.
• Pitch fraction 15 may then by mixed with a diluent 17, such as SRVGO
• Diluted pitch fraction 19 and hydrogen 21 may then be fed to an ebullated bed reactor system 42, which may include one or more ebullated bed reactors, where the hydrocarbons and hydrogen are contacted with a hydroconversion catalyst to react at least a portion of the pitch with hydrogen to form lighter hydrocarbons, demetallize the pitch hydrocarbons, remove Conradson Carbon Residue, or otherwise convert the residuum to useful products.
• ebullated bed reactor system 42 may include one or more ebullated bed reactors, where the hydrocarbons and hydrogen are contacted with a hydroconversion catalyst to react at least a portion of the pitch with hydrogen to form lighter hydrocarbons, demetallize the pitch hydrocarbons, remove Conradson Carbon Residue, or otherwise convert the residuum to useful products.
• Reactors in ebullated bed reactor 42 may be operated at temperatures in the range from about 380°C to about 450°C, hydrogen partial pressures in the range from about 70 bara to about 170 bara, and liquid hourly space velocities (LHSV) in the range from about 0.2 h "1 to about 2.0 h "1 .
• the catalyst may be back mixed and maintained in random motion by the recirculation of the liquid product. This may be accomplished by first separating the recirculated oil from the gaseous products. The oil may then be recirculated by means of an external pump, or, as illustrated, by a pump having an impeller mounted in the bottom head of the reactor.
• Target conversions in ebullated bed reactor system 42 may be in the range from about 40 wt% to about 75 wt%, depending upon the feedstock being processed. In any event, target conversions should be maintained below the level where sediment formation becomes excessive and thereby prevent continuity of operations.
• sulfur removal may be in the range from about 40 wt% to about 80 wt%
• metals removal may be in the range from about 60 wt% to 85 wt%
• Conradson Carbon Residue (CCR) removal may be in the range from about 30 wt% to about 65 wt%.
• fractionation system 46 may be used to recover an offgas 48 containing light hydrocarbon gases and hydrogen sulfide (3 ⁇ 4S), a light naphtha fraction 50, a heavy naphtha fraction 52, a kerosene fraction 54, a diesel fraction 56, a light vacuum gas oil fraction 58, a heavy gas oil fraction 60, and a vacuum residuum fraction 62.
• offgas 48 containing light hydrocarbon gases and hydrogen sulfide (3 ⁇ 4S), a light naphtha fraction 50, a heavy naphtha fraction 52, a kerosene fraction 54, a diesel fraction 56, a light vacuum gas oil fraction 58, a heavy gas oil fraction 60, and a vacuum residuum fraction 62.
• vacuum residuum fraction 62 may be recycled for further processing, such as to SDA unit 12, ebullated bed reactor system 42, or other reaction units 16, 20 discussed below. In other embodiments, vacuum residuum fraction 62 may be blended with a cutter fraction 66 to produce a fuel oil.
• Fractionation system 46 may include, for example, a high pressure high temperature (HP HT) separator to separate the effluent vapor from the effluent liquids.
• HP HT high pressure high temperature
• the separated vapor may be routed through gas cooling, purification, and recycle gas compression, or may be first processed through an Integrated Hydroprocessing Reactor System (which may include one or more additional hydroconversion reactors), alone or in combination with external distillates and/or distillates generated in the hydrocracking process, and thereafter routed for gas cooling, purification, and compression.
• HP HT high pressure high temperature
• the separated liquid from the HP/HT separator may be flashed and routed to an atmospheric distillation system along with other distillate products recovered from the gas cooling and purification section.
• the atmospheric tower bottoms such as hydrocarbons having an initial boiling point of at least about 340°C, such as an initial boiling point in the range from about 340°C to about 427°C, may then be further processed through a vacuum distillation system to recover vacuum distillates.
• the vacuum tower bottoms product such as hydrocarbons having an initial boiling point of at least about 480°C, such as an initial boiling point in the range from about 480°C to about 565°C, may then be routed to tankage after cooling, such as by direct heat exchange or direct injection of a portion of the residuum hydrocarbon feed into the vacuum tower bottoms product.
• the fuel oil fraction 62 recovered following processing in ebullated bed reactor system 42 and fractionation system 46 may have a sulfur content of 2.25 wt% or less; 2.0 wt% or less in other embodiments; and 1.75 wt% or less in yet other embodiments.
• the deasphalted oil fraction 14 recovered from SDA unit 12 may be optionally heated, combined with a hydrogen rich gas 23, and fed to a residue desulfurization (RDS) unit 16.
• RDS unit 16 may include one or more residue desulfurization reactors.
• RDS unit 16 may include one or more upflow reactors
• the DAO feed may be mixed with the hydrogen rich gas 23 upstream of the reactors or with the feed entering the bottom of the UFRs (s), and in some embodiments with the effluent recovered from the UFRs.
• the UFR may help to increase the catalyst life in the downstream RDS catalyst beds, as well as remove some sulfur, Conradson Carbon Residue, and asphaltenes in the feed.
• Operating conditions in the RDS unit 16, including the UFRs and/or RDS reactors may include temperatures in the range from about 360°C to about 400°C and hydrogen partial pressures ranging from about 70 barg to about 170 barg.
• the RDS may achieve a desulfurization rate of at least 70 wt% in some embodiments, at least 80 wt% in other embodiments, and up to or above 92 wt% in yet other embodiments.
• Effluent 18, recovered from the RDS unit 16 may then be further processed in a hydrocracking reactor system 20, which may include one or more hydrocracking reactors, arranged in series or parallel.
• the RDS effluent may be hydrocracked under hydrogen partial pressures in the range from about 70 bara to about 170 bara, temperatures in the range from about 380°C to about 450°C, and LHSV in the range from about 0.2 h "1 to about 2.0 h "1 in the presence of a catalyst.
• operating conditions in hydrocracking reactor system 20 may be similar to those described above for ebullated bed reactor system 42.
• the ebullated bed reactors may be operated at higher severity conditions than those in reactor system 42, higher severity referring to a higher temperature, a higher pressure, a lower space velocity or combinations thereof.
• the DAO recovered may be treated in a fixed bed reaction system or an ebullated bed reactor system 20, as illustrated, which may be similar to that described above for ebullated bed reactor system 42 with respect to gas / liquid separations and catalyst recirculation, among other similarities.
• a fixed bed reactor system may be used, for example, where the metals and Conradson Carbon Residue content of the DAO is less than 80 wppm and 10 wt%, respectively, such as less than 50 wppm ad 7 wt%, respectively.
• An ebullated bed reactor system may be used, for example, when the metals and Conradson Carbon Residue contents are higher than those listed above for the fixed bed reactor system.
• the number of reactors used may depend on the charge rate, the overall target residue conversion level, and the level of conversion attained in RDS unit 16, among other variables.
• one or two hydrocracking reactors may be used in hydrocracking reactor system 20.
• the partially converted hydrocarbons may be recovered via flow line 22 as a mixed vapor / liquid effluent and fed to a fractionation system 24 to recover one or more hydrocarbon fractions.
• fractionation system 24 may be used to recover an offgas 26, a light naphtha fraction 28, a heavy naphtha fraction 30, a kerosene fraction 32, a diesel fraction 34, a light vacuum gas oil fraction 36, a heavy vacuum gas oil fraction 38, and a vacuum resid fraction 40.
• vacuum resid fraction 40 may be recycled for further processing.
• vacuum resid fraction 40 may be blended with a cutter fraction 64 to produce a fuel oil.
• Fractionation system 24 may include, for example, a high pressure high temperature (HP/HT) separator to separate the effluent vapor from the effluent liquids.
• HP/HT high pressure high temperature
• the separated vapor may be routed through gas cooling, purification, and recycle gas compression, or may be first processed through an Integrated Hydroprocessing Reactor System (IHRS) which may include one or more additional hydroconversion reactors, alone or in combination with external distillates and/or distillates generated in the hydrocracking process and thereafter routed for gas cooling, purification, and compression.
• IHRS Integrated Hydroprocessing Reactor System
• the separated liquid from the HP/HT separator may be flashed and routed to an atmospheric distillation system along with other distillate products recovered from the gas cooling and purification section.
• the atmospheric tower bottoms such as hydrocarbons having an initial boiling point of at least about 340°C, such as an initial boiling point in the range from about 340°C to about 427°C, may then be further processed through a vacuum distillation system to recover vacuum distillates.
• the vacuum tower bottoms product such as hydrocarbons having an initial boiling point of at least about 480°C, such as an initial boiling point in the range from about 480°C to about 565°C, may then be routed to tankage after cooling, such as by direct heat exchange or direct injection of a portion of the residuum hydrocarbon feed into the vacuum tower bottoms product.
• Overall conversion of the DAO fraction through the RDS unit 16 and the hydrocracking reaction system 20 may be in the range from about 75 wt% to about 95 wt%, such as in the range from about 85 wt% to about 90 wt%.
• the fuel oil fraction 40 recovered following processing in RDS unit 16, hydrocracking reactor system 20 and fractionation system 24 may have a sulfur content of 1.25 wt% or less; 1.0 wt% or less in other embodiments; and 0.75 wt% or less in yet other embodiments.
• Catalysts useful in the RDS reactors, the URFs , and the ebullated bed reactors may include any catalyst useful for the hydrotreating or hydrocracking of a hydrocarbon feedstock.
• a hydrotreating catalyst for example, may include any catalyst composition that may be used to catalyze the hydrogenation of hydrocarbon feedstocks to increase its hydrogen content and/or remove heteroatom contaminants.
• a hydrocracking catalyst for example, may include any catalyst composition that may be used to catalyze the addition of hydrogen to large or complex hydrocarbon molecules as well as the cracking of the molecules to obtain smaller, lower molecular weight molecules.
• Hydroconversion catalyst compositions for use in the hydroconversion process according to embodiments disclosed herein are well known to those skilled in the art and several are commercially available from W.R. Grace & Co., Criterion Catalysts & Technologies, and Albemarle, among others.
• Suitable hydroconversion catalysts may include one or more elements selected from Groups 4-12 of the Periodic Table of the Elements.
• hydroconversion catalysts according to embodiments disclosed herein may comprise, consist of, or consist essentially of one or more of nickel, cobalt, tungsten, molybdenum and combinations thereof, either unsupported or supported on a porous substrate such as silica, alumina, titania, or combinations thereof.
• the hydroconversion catalysts may be in the form of metal oxides, for example.
• the hydroconversion catalysts may be pre-sulfided and/or preconditioned prior to introduction to the hydrocracking reactor(s).
• Distillate hydrotreating catalysts that may be useful include catalyst selected from those elements known to provide catalytic hydrogenation activity. At least one metal component selected from Group 8-10 elements and/or from Group 6 elements is generally chosen. Group 6 elements may include chromium, molybdenum and tungsten. Group 8-10 elements may include iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum.
• the amount(s) of hydrogenation component(s) in the catalyst suitably range from about 0.5% to about 10% by weight of Group 8-10 metal component(s) and from about 5% to about 25% by weight of Group 6 metal component(s), calculated as metal oxide(s) per 100 parts by weight of total catalyst, where the percentages by weight are based on the weight of the catalyst before sulfiding.
• the hydrogenation components in the catalyst may be in the oxidic and/or the sulphidic form. If a combination of at least a Group 6 and a Group 8 metal component is present as (mixed) oxides, it will be subjected to a sulfiding treatment prior to proper use in hydrocracking.
• the catalyst comprises one or more components of nickel and/or cobalt and one or more components of molybdenum and/or tungsten or one or more components of platinum and/or palladium.
• Catalysts containing nickel and molybdenum, nickel and tungsten, platinum and/or palladium are useful.
• Residue hydrotreating catalysts that may be useful include catalysts generally composed of a hydrogenation component, selected from Group 6 elements (such as molybdenum and/or tungsten) and Group 8-10 elements (such as cobalt and/or nickel), or a mixture thereof, which may be supported on an alumina support.
• Phosphorous (Group 15) oxide is optionally present as an active ingredient.
• a typical catalyst may contain from 3 to 35 wt % hydrogenation components, with an alumina binder.
• the catalyst pellets may range in size from 1/32 inch to 1/8 inch, and may be of a spherical, extruded, trilobate or quadrilobate shape.
• the feed passing through the catalyst zone contacts first a catalyst preselected for metals removal, though some sulfur, nitrogen and aromatics removal may also occur. Subsequent catalyst layers may be used for sulfur and nitrogen removal, though they would also be expected to catalyze the removal of metals and/or cracking reactions.
• Catalyst layer(s) for demetallization when present, may comprise catalyst(s) having an average pore size ranging from 125 to 225 Angstroms and a pore volume ranging from 0.5-1.1 cm 3 /g.
• Catalyst layer(s) for denitrogenation/desulfurization may comprise catalyst(s) having an average pore size ranging from 100 to 190 Angstroms with a pore volume of 0.5-1.1 cm 3 /g.
• U.S. Pat. No. 4,990,243 describes a hydrotreating catalyst having a pore size of at least about 60 Angstroms, and preferably from about 75 Angstroms to about 120 Angstroms.
• a demetallization catalyst useful for the present process is described, for example, in U.S. Pat. No.
• Useful residue hydrotreating catalysts include catalysts having a porous refractory base made up of alumina, silica, phosphorous, or various combinations of these.
• One or more types of catalysts may be used as residue hydrotreating catalyst, and where two or more catalysts are used, the catalysts may be present in the reactor zone as layers.
• the catalysts in the lower layer(s) may have good demetallization activity.
• the catalysts may also have hydrogenation and desulfurization activity, and it may be advantageous to use large pore size catalysts to maximize the removal of metals. Catalysts having these characteristics are not optimal for the removal of Conradson Carbon Residue and sulfur.
• the average pore size for catalyst in the lower layer or layers will usually be at least 60 Angstroms and in many cases will be considerably larger.
• the catalyst may contain a metal or combination of metals such as nickel, molybdenum, or cobalt.
• Catalysts useful in the lower layer or layers are described in U.S. Pat. Nos. 5,071,805 5,215,955, and 5,472,928.
• those catalysts as described in U.S. Patent No. 5,472,928 and having at least 20% of the pores in the range of 130 to 170 Angstroms, based on the nitrogen method may be useful in the lower catalysts layer(s).
• the catalysts present in the upper layer or layers of the catalyst zone should have greater hydrogenation activity as compared to catalysts in the lower layer or layers. Consequently catalysts useful in the upper layer or layers may be characterized by smaller pore sizes and greater Conradson Carbon Residue removal, denitrogenation and desulfurization activity.
• the catalysts will contain metals such as, for example, nickel, tungsten, and molybdenum to enhance the hydrogenation activity.
• those catalysts as described in U.S. Patent No. 5,472,928 and having at least 30% of the pores in the range of 95 to 135 Angstroms, based on the nitrogen method may be useful in the upper catalysts layers.
• the catalysts may be shaped catalysts or spherical catalysts. In addition, dense, less friable catalysts may be used in the upflow fixed catalyst zones to minimize breakage of the catalyst particles and the entrainment of particulates in the product recovered from the reactor.
• the various catalyst layers may not be made up of only a single catalyst type, but may be composed of an intermixture of different catalyst types to achieve the optimal level of metals or Conradson Carbon Residue removal and desulfurization for that layer. Although some hydrogenation will occur in the lower portion of the zone, the removal of Conradson Carbon Residue, nitrogen, and sulfur may take place primarily in the upper layer or layers. Obviously additional metals removal also will take place.
• the specific catalyst or catalyst mixture selected for each layer, the number of layers in the zone, the proportional volume in the bed of each layer, and the specific hydrotreating conditions selected will depend on the feedstock being processed by the unit, the desired product to be recovered, as well as commercial considerations such as cost of the catalyst. All of these parameters are within the skill of a person engaged in the petroleum refining industry and should not need further elaboration here.
• FIG. 2 a simplified flow diagram of a process for upgrading residuum hydrocarbon feedstocks according to embodiments disclosed herein is illustrated.
• the residuum hydrocarbon feedstock 10 is processed through SDA unit 12, and the resulting pitch fraction is processed in ebullated bed reactor system 42 and fractionation system 46.
• Deasphalted oil fraction 14 may be combined with a hydrogen rich gas 23 and fed to RDS unit 16, which may include one or more residue desulfurization reactors.
• Effluent 18 recovered from RDS unit 16 may then be processed in a fractionation system 24 to produce one or more hydrocarbon fractions 26, 28, and 38, among others, as well as a vacuum residua fraction 40.
• the vacuum residua fraction 40 and optionally one or more of additional heavier hydrocarbon fractions recovered in fractionation system 24 may then be fed to a hydrocracking reactor system 20 to produce additional distillate range hydrocarbons.
• effluent 22 may be fractionated to recover various distillate hydrocarbon fractions.
• effluent 22 may be fractionated along with effluent 18 in fractionation system 24 (as illustrated) or a combined fractionation system processing effluents 18 and 44.
• the conversion of the DAO fraction can be increased to very high levels, such as 85 wt% to 90 wt%, while still producing a 1 wt% sulfur stable fuel oil, even when processing high sulfur containing residues, such as those having up to or greater than 6.5 wt% sulfur.
• the processing of SDA pitch in a separate reaction / separation train may allow the production of a 2 wt% sulfur stable fuel oil while converting 40 wt% to 65 wt% of the pitch to atmospheric and vacuum distillate boiling range materials.
• the resulting combined overall conversion from both processing trains may be in the range from about 55 wt% or 60 wt% to as high as about 95 wt% or more, such as in the range from about 65 wt% to about 85 wt%. Further, such conversions may be advantageously achieved without sediment formation that could otherwise cause plugging and intermittent operation.
• a 40 k BPSD of Arabian Heavy vacuum residue is first processed in an SDA unit at a 73 vol% lift.
• the resulting properties of the DAO and SDA pitch are summarized in Table 1.
• the DAO containing 4.27 wt% sulfur, 10 wt% CCR and 47 wppm Ni + V, is then processed in an RDS unit so as to reduce the sulfur content of the feed by 85 to 87 wt%. Concurrently the residue fraction in the feed is converted 35 to 45%.
• the RDS effluent is then hydrocracked in single ebullated bed reactor, which is close coupled to the RDS reactors, increasing the overall conversion to 85 vol% and overall HDS to 91.8 wt%.
• the resulting unconverted oil has a sulfur content and API gravity of approximately 1.0 wt% and 11.9 °, respectively. It is envisaged the UCO from this reaction system will meet the low sulfur fuel oil specifications without any additional cutterstock addition. The overall space velocity required to achieve this level of conversion and desulfurization is estimated to be about 0.2 hr-1.
• Fifty-five (55) vol% of the SDA pitch is then also converted a separate ebullated bed reactor system, containing a single reactor, operating in parallel with the RDS and hydrocracking reactors, producing a medium sulfur vacuum residue which contains 2.6 wt% sulfiir.
• the resulting fuel oil will contain less than 2 wt% sulfur and more than likely less than 1.5 wt% sulfiir, depending on the fuel oil blending components.
• the reactor space velocity for the pitch conversion unit is estimated to be about 0.25 h "1 , resulting in an overall space velocity for the RDS plus DAO hydrocracking reactor and the pitch conversion reactor of 0.22 h .
• the resulting overall conversion for this configuration is 75 vol%, producing approximately 12,096 BPSD of diesel, 12,332 BPSD of hydrocracker or FCC feed, 4,056 BPSD of LS fuel oil and 4,760 BPSD of medium sulfur vacuum residue.
• the overall yields and product properties for this processing configuration are provided in Table 2.
• Figures 3 and 4 illustrate two embodiments for the IHRS and are described below, however other embodiments will be obvious to those skilled in the art as being possible.
• Figure 3 describes an embodiment where the IHRS is installed downstream of the ebullated bed reactor system 42.
• Figure 4 illustrates an embodiment where the IHRS is installed downstream of the hydrocracking reactor system 20.
• the effluent stream 44 from ebullated bed hydroprocessing reactor 42 may be cooled in a heat exchanger (not shown) and fed to a HP/HT V/L separator 81 where a vapor stream including the light products and distillates boiling below about 1000°F normal boiling point and a liquid stream including unconverted residuum may be separated and processed separately in downstream equipment.
• a vapor stream 67 may be fed to a fixed-bed hydroprocessing reactor 86 to carry out hydrotreating, hydrocracking or a combination thereof.
• An effluent stream 68 from the IHRS fixed-bed reactor system 86 is fed to a fractionation system 147 which recovers an offgas stream 48, light hydrotreated or hydrocracked naphtha stream 50, heavy hydrotreated or hydrocracked naphtha stream 52, hydrotreated or hydrocracked kerosene stream 54, hydrotreated or hydrocracked diesel stream 56, as described above.
• the liquid stream 63 may be cooled in a heat exchanger (not shown) and depressurized in a pressure letdown system (not shown) before being fed to a vacuum fractionation system 72 which recovers a light hydrotreated or hydrocracked VGO stream 58, a heavy hydrotreated or hydrocracked VGO stream 60 and an unconverted vacuum residuum stream 62.
• the vacuum tower bottoms product stream such as hydrocarbons having an initial boiling point of at least about 480°C, such as an initial boiling point in the range from about 480°C to about 565°C, may be routed to tankage after cooling, such as by direct heat exchange or direct injection of a portion of the residuum hydrocarbon feed into the vacuum tower bottoms product.
• a vapor stream including the light products and distillates boiling below about 1000°F normal boiling point and a liquid stream including unconverted residuum may be separated and processed separately in downstream equipment.
• a vapor stream 167 is fed to a fixed-bed hydroprocessing reactor 186 to carry out hydrotreating, hydrocracking or a combination thereof.
• An effluent stream 168 from the IH S fixed-bed reactor system 166 may be fed to an atmospheric fractionation system 146 which recovers an offgas stream 26, light hydrotreated or hydrocracked naphtha stream 28, heavy hydrotreated or hydrocracked naphtha stream 30, hydrotreated or hydrocracked kerosene stream 32, hydrotreated or hydrocracked diesel stream 34.
• a liquid stream 163 is cooled in a heat exchanger (not shown) and depressurized in a pressure letdown system (not shown) and may be fed to a vacuum fractionation system 172 which recovers a light hydrotreated or hydrocracked VGO stream 36, a heavy hydrotreated or hydrocracked VGO stream 38 and an unconverted vacuum residuum stream 40.
• the vacuum tower bottoms product stream such as hydrocarbons having an initial boiling point of at least about 480°C, such as an initial boiling point in the range from about 480°C to about 565°C, may then be routed to tankage after cooling, such as by direct heat exchange or direct injection of a portion of the residuum hydrocarbon feed into the vacuum tower bottoms product.
• embodiments disclosed herein also contemplate fractionating the effluents 22, 44 in a common fractionation system.
• the effluents may be fed into a common gas cooling, purification, and compression loop before further processing in an atmospheric tower and a vacuum tower as described above.
• the use of a combined separation scheme may provide for a reduced capital investment, when desired, but may result in the production of a single fuel oil fraction having a sulfur level intermediate those achieved by separate processing.
• the combined separation scheme may also be used along with the IHRS being installed downstream of both the ebullated bed reactor system 42 and the hydrocracking reactor system 20 and being fed by the combined effluents 22, 44.
• embodiments disclosed herein effectively integrate SDA and RDS with residue hydrocracking, extending the residue conversion limits above those which can be attained by residue hydrocracking alone. Further, the higher conversions may be attained using less catalytic reactor volume as compared to other schemes proposed to achieve similar conversions. As a result, embodiments disclosed herein may provide comparable or higher conversions but requiring a lower capital investment. Further, embodiments disclosed herein may be used to produce a fuel oil having less than 1 wt% sulfur from a high sulfur containing residue feed while maximizing overall conversion.
• the initial SDA may allow the hydrocracking of the pitch to be operated at relatively high temperatures and space velocities, without the tendency to form excessive sediments, by limiting conversion.
• the hydrocracking of the DAO may also be performed at relatively high temperatures and space velocities, as the DAO may have a very low asphaltene content.
• the overall processing schemes disclosed herein may be performed using low reactor volumes while still achieving high conversions.
• other resulting advantages may include: reduced catalyst consumption rates due to rejecting metals in the asphalt from the SDA unit; reduced capital investment; and elimination or significant reduction in the need for injection of slurry oil upstream of the ebullated bed reactors, among other advantages.

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