US20140221709A1 - Integration of residue hydrocracking and solvent deasphalting - Google Patents

Integration of residue hydrocracking and solvent deasphalting Download PDF

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Publication number
US20140221709A1
US20140221709A1 US13/758,554 US201313758554A US2014221709A1 US 20140221709 A1 US20140221709 A1 US 20140221709A1 US 201313758554 A US201313758554 A US 201313758554A US 2014221709 A1 US2014221709 A1 US 2014221709A1
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United States
Prior art keywords
fraction
reactor system
effluent
hydroconversion
ebullated bed
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US13/758,554
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English (en)
Inventor
Mario C. Baldassari
Ujjal K. Mukherjee
Ann-Marie Olsen
Marvin I. Greene
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CB&I Technology Inc
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Lummus Technology Inc
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Priority to US13/758,554 priority Critical patent/US20140221709A1/en
Assigned to LUMMUS TECHNOLOGY INC. reassignment LUMMUS TECHNOLOGY INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: BALDASSARI, MARIO C., GREENE, MARVIN I., MUKHERJEE, UJJAL K., OLSEN, Ann-Marie
Priority to EP14746104.0A priority patent/EP2951272B1/en
Priority to HUE14746104A priority patent/HUE040512T2/hu
Priority to MYPI2015001758A priority patent/MY173246A/en
Priority to PT14746104T priority patent/PT2951272T/pt
Priority to RU2015137707A priority patent/RU2656273C2/ru
Priority to ES14746104T priority patent/ES2706737T3/es
Priority to PCT/US2014/014106 priority patent/WO2014121052A1/en
Priority to CA2896247A priority patent/CA2896247C/en
Priority to CN201480006287.7A priority patent/CN105008494B/zh
Priority to BR112015018705-6A priority patent/BR112015018705B1/pt
Priority to MX2015009213A priority patent/MX365755B/es
Priority to KR1020157022016A priority patent/KR101829113B1/ko
Priority to SG11201505233TA priority patent/SG11201505233TA/en
Priority to TW103103777A priority patent/TWI481703B/zh
Publication of US20140221709A1 publication Critical patent/US20140221709A1/en
Priority to US15/848,666 priority patent/US20180119027A1/en
Priority to HRP20190106TT priority patent/HRP20190106T1/hr
Abandoned legal-status Critical Current

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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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/003—Solvent de-asphalting
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J8/00—Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes
    • B01J8/18—Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes with fluidised particles
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
    • C10G47/24—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles
    • C10G47/26—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles suspended in the oil, e.g. slurries
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
    • 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
    • C10G67/049—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
    • C10G2300/80—Additives
    • C10G2300/802—Diluents

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 hydrocracking of a residuum hydrocarbon feedstock, solvent deasphalting of the unconverted residuum hydrocarbon feedstock, processing the resulting hydrocracked deasphalted oil in a separate residue hydrocracking unit, and processing the pitch from the solvent deasphalting unit in a separate residue hydrocracking unit.
  • Catalysts have been developed that exhibited excellent distillate selectivity, reasonable conversion activity and stability for heavier feedstocks.
  • the conversion rates attainable by the various processes are limited, however.
  • RDS units alone can produce a 1 wt % sulfur fuel from high sulfur residua, but conversions are generally limited to about 35% to 40%.
  • Others have proposed to use SDA units to solvent deasphalt the residuum feed and process the deasphalted oil only in a Residuum Hydrocracking Unit (RHU).
  • RHU Residuum Hydrocracking Unit
  • DAO deasphalted oil
  • Still others have proposed to process the SDA pitch directly in a RHU. Nonetheless, economic processes to achieve high hydrocarbon conversions and sulfur removal are desired.
  • embodiments disclosed herein relate to a process for upgrading residuum hydrocarbons.
  • the process may include the following steps: contacting a residuum hydrocarbon fraction and hydrogen with a first hydroconversion catalyst in a first ebullated bed hydroconversion reactor system; recovering a first effluent from the first ebullated bed hydroconversion reactor system; solvent deasphalting a vacuum residuum fraction to produce a deasphalted oil fraction and an asphalt fraction; contacting the deasphalted oil fraction and hydrogen with a second hydroconversion catalyst in a second hydroconversion reactor system; recovering a second effluent from the second hydroconversion reactor system; and fractionating the first effluent from the first ebullated bed hydroconversion reactor system and the second effluent from the second hydroconversion reactor system to recover one or more hydrocarbon fractions and the vacuum residuum fraction in a common fractionation system.
  • inventions disclosed herein relate to a system for upgrading residuum hydrocarbons.
  • the system may include the following: a first ebullated bed hydroconversion reactor system for contacting a residuum hydrocarbon fraction and hydrogen with a first hydroconversion catalyst to produce a first effluent; a solvent deasphalting unit to solvent deasphalt a vacuum residuum fraction to produce a deasphalted oil fraction and an asphalt fraction; a second hydroconversion reactor system for contacting the deasphalted oil fraction and hydrogen with a second hydroconversion catalyst to produce a second effluent; and a fractionation unit to fractionate the first effluent and the second effluent to recover one or more hydrocarbon fractions and the vacuum residuum fraction.
  • inventions disclosed herein relate to a system for upgrading residuum hydrocarbons.
  • the system may include the following: a first ebullated bed hydroconversion reactor system for contacting a residuum hydrocarbon fraction and hydrogen with a first hydroconversion catalyst to produce a first effluent; a solvent deasphalting unit to solvent deasphalt a vacuum residuum fraction to produce a deasphalted oil fraction and an asphalt fraction; a second hydroconversion reactor system for contacting the deasphalted oil fraction and hydrogen with a second hydroconversion catalyst to produce a second effluent; and a separator to separate a combined fraction of the first effluent and the second effluent to recover a liquid fraction and a vapor fraction; a fractionation unit to fractionate the liquid to recover the vacuum residuum fraction; a third hydroconversion reactor system for contacting the vapor fraction with a third hydroconversion catalyst to produce a third effluent; and
  • inventions disclosed herein relate to a system for upgrading residuum hydrocarbons.
  • the system may include the following: a first ebullated bed hydroconversion reactor system for contacting a residuum hydrocarbon fraction and hydrogen with a first hydroconversion catalyst to produce a first effluent; a solvent deasphalting unit to solvent deasphalt a vacuum residuum fraction to produce a deasphalted oil fraction and an asphalt fraction; a second hydroconversion reactor system for contacting the deasphalted oil fraction and hydrogen with a second hydroconversion catalyst to produce a second effluent; and a first fractionation unit to fractionate the first effluent and the second effluent to recover one or more hydrocarbon fractions and the vacuum residuum fraction; a third ebullated bed hydroconversion reactor system for contacting the asphalt fraction and hydrogen to produce third effluent; a separator to separate the third effluent and recover a liquid fraction and a
  • FIG. 1 is a simplified process flow diagram of a process for upgrading residuum hydrocarbon feedstocks according to embodiments disclosed herein.
  • FIG. 2 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.
  • FIG. 3 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 hydrocracking of a residuum hydrocarbon feedstock, solvent deasphalting of the unconverted residuum hydrocarbon feedstock, processing the resulting hydrocracked deasphalted oil in a separate 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, desulfurization, denitrogenation, cracking, conversion, demetallization, and removal of metals, Conradson Carbon Residue (CCR) or asphaltenes removal, 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 bottoms, 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 and hydrogen 21 may be fed to an ebullated bed reactor system 42 , which may include one or more ebullated bed reactors arranged in series or parallel, where the hydrocarbons and hydrogen are contacted with a hydroconversion catalyst to react at least a portion of the residuum with hydrogen to form lighter hydrocarbons, demetallize the metals contained in residuum, remove Conradson Carbon Residue, or otherwise convert the residuum to useful products.
  • a hydroconversion catalyst to react at least a portion of the residuum with hydrogen to form lighter hydrocarbons, demetallize the metals contained in residuum, 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 30 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 65 wt %
  • metals removal may be in the range from about 40 wt % to 65 wt %
  • Conradson Carbon Residue (CCR) removal may be in the range from about 30 wt % to about 60 wt %.
  • Reactor severity may be defined as the catalyst average temperature in degrees Fahrenheit of the catalysts loaded in the one or more ebullated bed hydrocracking reactors multiplied by the average hydrogen partial pressure of the ebullated bed hydrocracking reactors in Bar absolute and divided by the LHSV in the ebullated bed hydrocracking reactors.
  • the reactor severity of the ebullated bed reactor system 42 may be in the range from about 105,000° F.-Bara-Hr to about 446,000° F.-Bara-Hr.
  • fractionation system 46 may be used to recover an offgas 48 containing light hydrocarbon gases and hydrogen sulfide (H 2 S), 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 .
  • H 2 S hydrogen sulfide
  • vacuum residuum fraction 62 may be recycled for further processing, such as to a solvent deasphalting (SDA) unit 12 , the ebullated bed reactor system 42 , or other reaction units 70 , 20 discussed below.
  • SDA solvent deasphalting
  • a portion of the heavy gas oil fraction 60 may also be routed to the SDA unit 12 .
  • 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 (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 vacuum resid fraction 62 is fed to a Solvent Deasphalting Unit (SDA) 12 .
  • SDA 12 the vacuum residuum fraction 62 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
  • a portion of the heavy gas oil fraction 60 may also be fed to the SDA 12 .
  • Solvent deasphalting may be performed in the 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 the 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 (CCR).
  • asphaltenes i.e., heptane insoluble
  • metals such as Ni, V, and others
  • CCR Conradson Carbon Residue
  • the DAO fraction 14 and hydrogen 23 may be fed to a hydrocracking reactor system 20 , which may include one or more hydrocracking reactors, arranged in series or parallel.
  • the DAO fraction 14 may be hydrocracked under hydrogen partial pressures in the range from about 70 bara to about 180 bara, temperatures in the range from about 390° C. to about 460° C., and LHSV in the range from about 0.1 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 ebullated bed reactor system 42 , among other variables.
  • one or two hydrocracking reactors may be used in hydrocracking reactor system 20 .
  • the reactor severity may be in the range from about 215,000° F.-Bara-Hr to about 755,000° F.-Bara-Hr.
  • the partially converted hydrocarbons may be recovered via flow line 25 as a mixed vapor/liquid effluent and fed to the fractionation system 46 to recover one or more hydrocarbon fractions as described above.
  • the pitch fraction 15 and hydrogen 16 may be fed to an ebullated bed reactor system 70 , 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 pitch to useful products.
  • a portion of the residuum hydrocarbon fraction 10 may also be fed to the ebullated bed reactor system 70 .
  • the ratio of the residuum hydrocarbon fraction 10 in the ebullated bed reactor system 70 to the ebullated bed reactor system 42 may range from about 0.1/1 to about 10/1. In other embodiments, the ratio of the residuum hydrocarbon fraction 10 in the ebullated bed reactor system 70 to the ebullated bed reactor system 42 may be about 1/1.
  • the fixed-bed hydrotreating reactors 66 or 166 may contain hydroprocessing catalysts tailored to hydrotreating reactions such as hydrodesulfurization, hydrodenitrogenation, olefins saturation, hydrodeoxygenation and hydrodearomatization.
  • the fixed-bed hydrotreating reactors 66 or 166 can contain hydroprocessing catalysts tailored to hydrocracking reactions.
  • the fixed-bed hydrotreating reactors 66 or 166 can contain a mixture of hydrotreating catalysts and hydrocracking catalysts. Examples of catalysts which may be utilized, but are not limited to, may be found in U.S. Pat. No. 4,990,243; U.S. Pat. No. 5,215,955; and U.S. Pat. No. 5,177,047, all of which are hereby incorporated by reference in their entirety.
  • the fixed-bed hydrotreating reactors 66 or 166 may not provide any demetallization and demetallization catalysts may not be necessary.
  • Reactors in the ebullated bed reactor system 70 may be operated at temperatures in the range from about 380° C. to about 450° C., hydrogen partial pressures in the range from about 90 bara to about 170 bara, and liquid hourly space velocities (LHSV) in the range from about 0.15 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 the ebullated bed reactor system 70 may be in the range from about 30 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 65 wt %
  • metals removal may be in the range from about 40 wt % to 65 wt %
  • Conradson Carbon Residue (CCR) removal may be in the range from about 30 wt % to about 60 wt %.
  • the reactor severity of the ebullated bed reactor system 70 may be in the range from about 255,000° F.-Bara-Hr to about 880,000° F.-Bara-Hr.
  • 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 gas oil fraction 38 , and a vacuum residuum fraction 40 .
  • vacuum residuum fraction 40 may be recycled for further processing.
  • vacuum residuum fraction 40 may be blended with a cutter fraction 64 to produce fuel oil.
  • the fuel oil may have a sulfur content of less than about 1.5 weight percent.
  • 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, 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.
  • Catalysts useful in the ebullated bed reactors or hydrocracking reactors may include any catalyst useful in the hydroconversion processes of hydrotreating or hydrocracking 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.
  • the effluents from the hydrocracking reactor system 20 , the ebullated bed reactor system 42 , or the ebullated bed reactor system 70 may be processed prior to entering the fractionation system 24 or the fractionation system 46 through an Integrated Hydroprocessing Reactor System (IHRS).
  • the IHRS is an inline fixed-bed hydrotreating system utilizing an upstream high pressure/high temperature vapor/liquid (HP/HT V/L) separator located between the ebullated-bed hydroprocessing reactor and the downstream IHRS.
  • the separator allows for a separation between the unconverted residuum in the liquid effluent of the HP/HT V/L separator and the overhead vapor products boiling below about 1000° F. normal boiling point which may provide a lower cost route for further hydrotreating or hydrocracking of the gas oils, diesel and naphtha fractions formed by cracking of residuum in the upstream ebullated bed reactor.
  • 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.
  • FIGS. 2 and 3 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.
  • FIG. 2 illustrates an embodiment where the IHRS is installed downstream of the blended stream derived by mixing the partially converted hydrocarbons recovered via flow line 44 from ebullated bed reactor system 42 and the partially converted hydrocarbons recovered via flow line 25 from the hydrocracking reactor system 20 .
  • FIG. 3 illustrates an embodiment where the IHRS is installed downstream of the ebullated bed hydroprocessing reactor 70 .
  • the effluent streams 44 and 25 from ebullated bed hydroprocessing reactor 42 and the hydrocracking reactor system 20 may be cooled in a heat exchanger (not shown) and fed to a HP/HT V/L separator 61 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 66 to carry out hydrotreating, hydrocracking or a combination thereof.
  • An effluent stream 68 from the IHRS fixed-bed reactor system 66 is fed to the fractionation system 46 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.
  • the effluent stream 22 from the ebullated bed reactor system 70 may be cooled in a heat exchanger (not shown) and fed to a HP/HT V/L separator 161 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 167 is fed to a fixed-bed hydroprocessing reactor 166 to carry out hydrotreating, hydrocracking or a combination thereof.
  • An effluent stream 168 from the IHRS 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.
  • 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 pre-conditioned 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 catalyst 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. 4,976,848, the entire disclosure of which is incorporated herein by reference for all purposes.
  • catalysts useful for desulfurization of heavy streams are described, for example, in U.S. Pat. Nos.
  • 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. Pat. 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. Pat. 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, but may be composed of an intermixture of different catalysts 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.
  • embodiments disclosed herein also contemplate fractionating the effluents 22 , 44 , and 25 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.
  • embodiments disclosed herein effectively processes vacuum residue and intermediate streams through multiple hydrocracking reactors, each operating at different severities and processing different feed compositions with a SDA located within the process, 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 requirement. 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 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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US13/758,554 US20140221709A1 (en) 2013-02-04 2013-02-04 Integration of residue hydrocracking and solvent deasphalting
SG11201505233TA SG11201505233TA (en) 2013-02-04 2014-01-31 Intergration of residue hydrocracking and solvent deasphalting
CA2896247A CA2896247C (en) 2013-02-04 2014-01-31 Intergration of residue hydrocracking and solvent deasphalting
BR112015018705-6A BR112015018705B1 (pt) 2013-02-04 2014-01-31 processo para melhorar os resíduos de hidrocarbonetos
MYPI2015001758A MY173246A (en) 2013-02-04 2014-01-31 Integration of residue hydrocracking and solvent deasphalting
PT14746104T PT2951272T (pt) 2013-02-04 2014-01-31 Integração de resíduo proveniente de hidrocraqueamento e desfaltagem de solvente
RU2015137707A RU2656273C2 (ru) 2013-02-04 2014-01-31 Комбинирование гидрокрекинга и деасфальтизации растворителем кубового остатка
ES14746104T ES2706737T3 (es) 2013-02-04 2014-01-31 Integración de hidrocraqueo de residuos y desasfaltado con disolvente
PCT/US2014/014106 WO2014121052A1 (en) 2013-02-04 2014-01-31 Intergration of residue hydrocracking and solvent deasphalting
EP14746104.0A EP2951272B1 (en) 2013-02-04 2014-01-31 Intergration of residue hydrocracking and solvent deasphalting
CN201480006287.7A CN105008494B (zh) 2013-02-04 2014-01-31 渣油加氢裂化和溶剂脱沥青的整合
HUE14746104A HUE040512T2 (hu) 2013-02-04 2014-01-31 Maradék hidrokrakkolásának és oldószer aszfaltmentesítésének integrációja
MX2015009213A MX365755B (es) 2013-02-04 2014-01-31 Integracion de hidrocraqueo de residuos, y desasfaltado con solvente.
KR1020157022016A KR101829113B1 (ko) 2013-02-04 2014-01-31 잔사유 수소첨가분해 및 용매 탈아스팔트화의 통합
TW103103777A TWI481703B (zh) 2013-02-04 2014-02-05 殘餘物加氫裂解及溶劑脫瀝青的整合技術
US15/848,666 US20180119027A1 (en) 2013-02-04 2017-12-20 System for upgrading residuum hydrocarbons
HRP20190106TT HRP20190106T1 (hr) 2013-02-04 2019-01-17 Integracija hidrokrekiranja ostataka i deasfaltiranja otapalom

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