US20170369796A1 - Deep hydroconversion process using an extraction of aromatics and resins, with upgrading of the hydroconversion extract and raffinate in downstream units - Google Patents

Deep hydroconversion process using an extraction of aromatics and resins, with upgrading of the hydroconversion extract and raffinate in downstream units Download PDF

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US20170369796A1
US20170369796A1 US15/631,197 US201715631197A US2017369796A1 US 20170369796 A1 US20170369796 A1 US 20170369796A1 US 201715631197 A US201715631197 A US 201715631197A US 2017369796 A1 US2017369796 A1 US 2017369796A1
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vacuum
fraction
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oil
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Jean-Francois Le Coz
Frederic Morel
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Axens SA
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Axens SA
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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
    • 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
    • C10G67/0409—Extraction of unsaturated hydrocarbons
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/003—Solvent de-asphalting
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
    • 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
    • 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
    • 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
    • C10G69/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process
    • C10G69/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only
    • C10G69/04—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only including at least one step of catalytic cracking 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
    • C10G7/00—Distillation of hydrocarbon oils
    • 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
    • C10G7/00—Distillation of hydrocarbon oils
    • C10G7/06—Vacuum distillation
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1096—Aromatics or polyaromatics
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/44—Solvents

Definitions

  • the invention relates to the field of the deep conversion of heavy hydrocarbon feeds in order to obtain upgradable hydrocarbon cuts such as liquefied petroleum gas (or LPG), gasolines or naphthas, kerosene, gas oil and oils.
  • upgradable hydrocarbon cuts such as liquefied petroleum gas (or LPG), gasolines or naphthas, kerosene, gas oil and oils.
  • the invention pertains to process flow diagrams which can be used to improve the performances of conversion units by introducing an extraction of the aromatics.
  • refineries comprise a unit for deep hydroconversion of residue followed by an atmospheric fractionation then a vacuum fractionation and downstream, a catalytic cracking unit and/or a hydrocracking unit.
  • a unit for deasphalting residue not converted during the hydroconversion is also present.
  • Deep hydroconversion processes are used in the refinery to transform mixtures of heavy hydrocarbons into easily upgradable products. They are usually principally used to con vert heavy feeds such as oil cuts or heavy synthetics, for example residues obtained from atmospheric and vacuum distillation, in order to convert them into lighter gasoline and gas oil. During the hydroconversion, fuel gas and light cuts such as LPG (liquefied petroleum gas) and naphtha (gasoline cut) are also produced.
  • LPG liquefied petroleum gas
  • naphtha gasoline cut
  • the deep hydroconversion process may be an ebullated bed residue hydrocracking process. This technology is in particular commercialized under the name H-OIL®. The feed is then usually vacuum residue.
  • the deep hydroconversion unit produces heavy unconverted residue with a high asphaltenes content.
  • the asphaltenes are unstable and have a tendency to precipitate in hot spots such as the furnaces and column bottoms (more particularly in the vacuum column).
  • the units and columns are periodically stopped for cleaning, which reduces their availability time. Typically, continuous runs last two years, then the units are stopped and opened for cleaning. The vacuum column is stopped even more frequently (typically every year).
  • the asphaltenes constitute a family of compounds which are soluble in aromatic and polyaromatic solvents and are insoluble in aliphatic hydrocarbons (n-pentane, n-heptane, etc). Their structure and their composition vary as a function of the origin of the oil feed, but certain atoms and groups of said structure are always present in variable proportions. Examples of these atoms that may be cited are oxygen, sulphur, nitrogen, heavy metals such as nickel and vanadium, for example. The presence of many polycyclic groups endows the asphaltene molecules with a highly aromatic character.
  • Resins are hydrocarbon compounds analogous to asphaltenes, but in contrast to asphaltenes, they are soluble in solvents such as n-pentane or n-heptane. Resins are typically constituted by a condensed polycyclic nucleus composed of aromatic and cyclanic rings and sulphur-containing or nitrogen-containing heterocycles with a low molecular weight and a less condensed structure than asphaltenes.
  • a first means for improving residue stability is to adjust the conversion in the reaction section by limiting it.
  • the stability of the residue dictates the maximum conversion which can be reached in the deep hydroconversion units (typically 60% to more than 80% by weight).
  • a diluent (5% to 10% by weight, and typically up to 20% by weight) constituted by heavy feeds which are rich in aromatic compounds and resins, alone or as a mixture, with the feed.
  • this diluent may be a slurry from catalytic cracking (namely the sludge or heavy residual fraction obtained from FCC, the 360° C. + cut with dominant aromatics).
  • the refiners combine the two means (adjusted conversion and dilution of the feed) in the hydroconversion unit in order to limit asphaltene deposits.
  • the possible diluents such as the heavy residual fraction (slurry) from catalytic cracking, are available in limited quantities and are thus a factor limiting the maximum conversion which can be obtained in deep hydroconversion units.
  • the patent FR 2 969 650 B1 describes a process for the conversion of hydrocarbon feed comprising a shale oil, said process comprising a step for ebullated bed hydroconversion, an atmospheric distillation of the effluent obtained and a liquid/liquid extraction of the atmospheric residue fraction with a solvent in order to extract the aromatics and the resins.
  • the extract obtained from the extraction unit is likely to contain asphaltenes, which could lead to a degradation of the hydroconversion performances in the case of recycling it to the hydroconversion.
  • the process described in that patent is specifically adapted to the treatment of feeds comprising shale oils the nature of which is different from conventional hydrocarbon feeds.
  • the patent FR 2 984 917 B1 describes a process for optimizing the production of middle distillate in a refinery containing at least one catalytic cracking unit, in which one of the variations consists of submitting the vacuum residue deriving from a catalytic cracking unit to a solvent extraction of the aromatics or, in one variation, to deasphalting with propane, then sending the extract to the fuel oil pool and recycling the raffinate to the inlet of the catalytic cracking unit.
  • the extract from the extraction unit is not upcycled to the hydroconversion unit.
  • the process in accordance with the invention proposes the addition of a deasphalting unit after the deep hydroconversion unit and the fractionation section, followed by a unit for extraction of aromatic hydrocarbons and resins on the residue fraction obtained from the vacuum fractionation, and upcycling the extract and the raffinate obtained to the aromatics extraction unit.
  • the invention can be used to simultaneously improve the performances of the deep hydroconversion unit and those of any units located downstream such as hydrocracking or catalytic cracking.
  • the process in accordance with the invention can be used to obtain yields of upgradable hydrocarbon cuts which are higher, while guaranteeing the same cycle time for the deep hydroconversion unit, or even increasing it, and improving the performances of the downstream units.
  • the present invention is intended to overcome the disadvantages of prior art processes by extracting from the deep hydroconversion effluents a heavy fraction which is enriched in aromatic compounds and resins,
  • the process in accordance with the invention can be used to obtain higher yields of upgradable products using an extraction of aromatics and resins contained in the unconverted residue obtained from the deep hydroconversion in accordance with the variations of the process flow diagrams detailed below.
  • the invention concerns a process for deep conversion of a heavy hydrocarbon feed, comprising the following steps:
  • the process in accordance with the invention may furthermore comprise:
  • the unconverted oil fraction obtained from hydrocracking and/or the heavy residual fraction obtained from catalytic cracking may be sent to the aromatics extraction section.
  • a portion of the extract may be used as a flux oil as a mixture with residual asphalt produced by the deasphalting step d) in order to provide a liquid fuel or to form part of the bitumen composition or to be supplied to a coking unit.
  • the raffinate produced by the aromatics extraction unit may be sent to the hydrocracking unit and/or to the catalytic cracking unit together with one or more other feeds selected from straight run vacuum gas oil (straight run VGO) and light (LVGO) and heavy vacuum distillates (HVGO) obtained from the outlet from the vacuum fractionation c).
  • straight run VGO straight run vacuum gas oil
  • LVGO light
  • HVGO heavy vacuum distillates
  • At least a portion of the light vacuum distillate (LVGO) or of the heavy vacuum distillate (HVGO) is sent to the aromatics extraction section.
  • a portion of the atmospheric residue is sent directly to the deasphalting section.
  • the hydroconversion step a) is preferably operated at an absolute pressure in the range 5 to 35 MPa, at a weighted average catalytic bed temperature of 300° C. to 600° C., at an hourly space velocity of 0.1 h ⁇ 1 to 10 h ⁇ 1 and at a ratio of hydrogen to feed H 2 /HC of 200 to 1000 m 3 /m 3 .
  • the hydrocracking step f1) is preferably operated at an average catalytic bed temperature in the range 300° C. to 550° C., a pressure in the range 5 to 35 MPa, and a liquid space velocity in the range 0.1 to 10 h ⁇ 1 .
  • the fluidized bed catalytic cracking step f2) is preferably operated in upflow mode with a reactor outlet temperature in the range 520° C. to 600° C., a C/O ratio in the range 6 to 14, and a dwell time in the range 1 to 10 s, or in downflow mode with a reactor outlet temperature in the range 580° C. to 630° C., a C/O ratio in the range 15 to 40, and with a dwell time in the range 0.1 to 1 s.
  • the deasphalting step is carried out in an extraction column, the solvent comprising at least 50% by weight of hydrocarbon compounds containing 3 to 7 carbon atoms, the extracter head temperature being in the range 50° C. to 250° C., the extracter bottom temperature being in the range 30° C. to 220° C., and the pressure being in the range 2 to 10 MPa.
  • the solvent comprising at least 50% by weight of hydrocarbon compounds containing 3 to 7 carbon atoms
  • the extracter head temperature being in the range 50° C. to 250° C.
  • the extracter bottom temperature being in the range 30° C. to 220° C.
  • the pressure being in the range 2 to 10 MPa.
  • the solvent is butane.
  • the liquid/liquid extraction is carried out with the aid of a solvent selected from furfural, N-methyl-2-pyrrolidone (NMP), sulfolane, dimethylformamide (DMF), dimethylsulphoxide (DMSO), phenol, or a mixture of these solvents in equal or different proportions, with a solvent/feed ratio of 0.5/1 to 3/1, at a temperature in the range between ambient temperature and 150° C., and at a pressure in the range between atmospheric pressure and 2 MPa.
  • NMP N-methyl-2-pyrrolidone
  • DMF dimethylformamide
  • DMSO dimethylsulphoxide
  • the feed is advantageously selected from heavy hydrocarbon feeds of the atmospheric residue or vacuum residue type obtained, for example, by straight run distillation of an oil cut or by vacuum distillation of crude oil, distillate type feeds such as vacuum gas oil or deasphalted oils, asphaltenes obtained by solvent deasphalting oil residues, coal in suspension in a hydrocarbon fraction such as gas oil obtained from vacuum distillation of crude oil, for example, or in fact the distillate obtained from coal liquefaction, alone or as a mixture.
  • the process in accordance with the invention is preferably applicable to hydrocarbon feeds containing refractory asphaltenes.
  • the process in accordance with the invention proposes inserting a supplemental aromatics extraction unit in order to improve the performance of the flow diagram, with upgrading of the extract and possibly the raffinate obtained.
  • FIG. 1 describes the process flow diagram in accordance with the prior art:
  • FIG. 2 describes the process flow diagram in accordance with the invention:
  • FIG. 2 presents an illustration of the process in accordance with the invention and its variations.
  • the feed 01 composed of hydrocarbons of oil origin or of mineral source synthetic hydrocarbons, is sent to the deep hydroconversion section 10 with a diluting fluid 02 which derives from the unit for the extraction of aromatics 50 , via the transport line 53 .
  • the liquid effluent from the deep hydroconversion section is sent to an atmospheric fractionation section 20 via the line 11 .
  • This fractionation section comprises one or more atmospheric distillation columns equipped with plates and contact means in order to separate the various upgradable cuts withdrawn by means of the transport lines 21 22 and 23 , plus optional other side streams. These cuts have boiling point ranges located, for example, in the gasoline, kerosene and gas oil ranges. A heavier fraction of unconverted atmospheric residue 24 with a boiling point which is typically more than 350° C. is recovered from the bottom of the fractionation.
  • This fractionation section comprises at least one vacuum distillation column equipped with plates and contact means in order to separate the various upgradable cuts withdrawn by means of lines 31 and 32 , plus other optional side streams. These cuts have boiling point ranges which are, for example, in the range of light vacuum distillates (LVGO) and heavy vacuum distillates (HVGO). A heavier fraction of unconverted vacuum residue with a boiling point which is typically more than 540° C. is recovered from the bottom of the fractionation section.
  • LVGO light vacuum distillates
  • HVGO heavy vacuum distillates
  • the light vacuum distillate (LVGO) 31 and the heavy vacuum distillate (HVGO) 32 may be sent to the hydrocracking unit 60 and/or catalytic cracking unit 70 .
  • the vacuum residue is sent to the deasphalting unit 40 via the line 33 in order to extract the asphaltenes by precipitation in a solvent and to produce deasphalted oil 41 and pitch (residual asphalt) 42 .
  • the deasphalted oil 41 is sent to the aromatics extraction unit 50 ; as well as, optionally, the unconverted oil purge 62 from the hydrocracking unit or the residual heavy fraction from catalytic cracking (FCC slurry) 72 , depending on the variations of the invention.
  • the unconverted oil purge 62 from the hydrocracking unit or the residual heavy fraction from catalytic cracking (FCC slurry) 72 , depending on the variations of the invention.
  • the raffinate 51 produced by the aromatics extraction unit 50 is sent to the hydrocracking unit as well as, optionally, other feeds such as, for example, a straight run vacuum (straight run VGO) 91 and light vacuum distillate 31 and heavy vacuum distillate 32 , products of the hydroconversion 10 .
  • a straight run vacuum (straight run VGO) 91 and light vacuum distillate 31 and heavy vacuum distillate 32 products of the hydroconversion 10 .
  • all or a portion of the light vacuum distillate 31 or the heavy vacuum distillate 32 may also be sent to the aromatics extraction unit 50 .
  • a portion of the atmospheric residue 24 is sent to the deasphalting unit. It is also possible to envisage the case in which all of the atmospheric residue 24 is sent to the deasphalting unit, so there is no vacuum fractionation section 30 and the cuts which can be upgraded in the boiling point ranges of light (LVGO) and heavy (HVGO) vacuum distillates are not separated but are sent to the deasphalting unit.
  • LVGO light
  • HVGO heavy
  • the process in accordance with the invention comprises neither a hydrocracking unit 60 nor a catalytic cracking unit 70 .
  • the process in accordance with the invention comprises a hydrocracking unit 60 .
  • the process in accordance with the invention does not comprise a hydrocracking unit 60 , but it does comprise a catalytic cracking unit 70 .
  • the process in accordance with the invention comprises a hydrocracking unit 60 and a catalytic cracking unit 70 .
  • At least a portion of the extract 52 produced by the aromatics extraction unit is used as a diluent in the hydroconversion unit via the line 53 and the excess is upgraded with the pitch 42 corresponding to the residual asphalt from the deasphalting unit via the line 54 .
  • the pitch 42 may be upgraded, for example to form bitumen, after appropriate treatment, or to form heavy fuel after dilution, or in fact it may be sent to a visbreaking, coking or gasification unit 80 .
  • a liquid/liquid extraction unit of the aromatics and resins treats the deasphalted oil obtained from the unit for deasphalting the unconverted residue from the deep hydroconversion:
  • the extraction may be used to obtain a raffinate containing at most 10% by weight of resins, and preferably at most 5% by weight of resins.
  • the extract obtained contains a minimum of 20% by weight of aromatics and 30% by weight of resins, and preferably at least 30% by weight of aromatics and 40% by weight of resins with an asphaltenes content of less than 1000 ppm.
  • the advantage of the invention resides in the presence of the deasphalting unit upstream of the aromatics extraction, which means that an aromatic extract can be obtained with a low impurities content since these are found in the asphalt leaving deasphalting.
  • the extract obtained is ideally suitable for use as an aromatic diluent for deep hydroconversion.
  • the extract as an aromatic diluent for the deep hydroconversion unit, the latter being operated at iso-conversion or otherwise, also means that an increased production of upgradable finished products such as naphtha, gas oil and vacuum gas oil VGO can be obtained.
  • the catalytic performances of the hydrocracking unit are improved, along with the production of upgradable products, compared with a unit supplied with the deasphalted hydrocarbon cut (DAO) leaving the deasphalting unit.
  • DAO deasphalted hydrocarbon cut
  • the catalytic performances of the catalytic cracking unit are improved as well as the production of upgradable products compared with a unit supplied with the deasphalted hydrocarbon cut leaving the deasphalting unit.
  • the impurities contents in the fluidized bed catalytic cracking FCC products are reduced.
  • the downstream units for the hydrotreatment of finished products are operated at reduced costs regarding the quantities of catalyst and/or the cycle times.
  • the ebullated bed process comprises passing a stream comprising liquid, solid and gas vertically through a reactor containing a bed of catalyst.
  • the catalyst in the bed is maintained in random motion in the liquid.
  • the bulk volume of the catalyst dispersed through the liquid is thus higher than the volume of the catalyst at rest.
  • the hourly space velocity (HSV) and the partial pressure of hydrogen are important factors which are selected as a function of the characteristics of the product to be treated and the desired conversion.
  • This catalyst may be a catalyst comprising metals from groups 9 and 10 (formerly group VIII), for example nickel and/or cobalt, usually in association with at least one metal from group 6 (formerly group VIB), for example molybdenum and/or tungsten and other promoter elements.
  • the support is, for example, selected from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals.
  • the support may also include other compounds. Usually, an alumina support is used.
  • the spent catalyst is replaced in part by fresh catalyst (i.e. new or regenerated) by withdrawal from the bottom of the reactor, and introducing fresh catalyst into the top of the reactor at regular time intervals, i.e, for example, in blasts or quasi-continuously.
  • fresh catalyst i.e. new or regenerated
  • the rate of replacement of spent catalyst by fresh catalyst may, for example, be approximately 0.01 kilograms to approximately 10 kilograms per cubic metre of feed.
  • This withdrawal and replacement are carried out with the aid of devices allowing this hydroconversion step to be operated continuously.
  • the unit usually comprises a recirculation pump to maintain the catalyst as an ebullated bed by continuously recycling at least a portion of the liquid withdrawn from the head of the reactor and reinjection into the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor to a regeneration zone from which the carbon and sulphur it contains are eliminated, then returning this regenerated catalyst.
  • Deep ebullated bed hydroconversion means that the Conradson carbon of the incoming stream can be reduced by approximately 50% to 95% and its nitrogen content by approximately 30% to 95%.
  • the cut point of the atmospheric residue is typically adjusted to between 300° C. and 400° C., preferably to between 340° C. and 380° C.
  • the cuts withdrawn, such as naphtha, kerosene and gas oil, are respectively sent to the gasoline pool, the kerosene pool or to the gas oil pool. At least a portion of the atmospheric residue is sent for vacuum fractionation.
  • the vacuum residue cut point is typically adjusted to between 450° C. and 600° C., preferably between 500° C. and 550° C. At least a portion of the cuts withdrawn, such as light vacuum distillate (light vacuum gas oil, LVGO) or heavy vacuum distillate (heavy vacuum gas oil, HVGO), are sent to the downstream units such as hydrocracking or catalytic cracking. A portion of the atmospheric residue (AR) may be sent to the deasphalting unit.
  • light vacuum distillate light vacuum gas oil, LVGO
  • heavy vacuum distillate heavy vacuum gas oil, HVGO
  • a portion of the atmospheric residue (AR) may be sent to the deasphalting unit.
  • the light vacuum distillate (LVGO) is characterized by a distillation range in the range 300° C. to 430° C., preferably in the range 340° C. to 400° C.
  • the heavy vacuum distillate (HVGO) is characterized by a distillation range in the range 400° C. to 600° C., preferably in the range 440° C. to 550° C.
  • At least a portion, preferably all, of the vacuum residue (VR_) is sent to the deasphalting unit.
  • This operation can be used to extract a large part of the asphaltenes and reduce the metals content. During this deasphalting, these latter elements become concentrated in an effluent known as asphalt, known here as residual asphalt.
  • the deasphalted effluent often termed the deasphalted oil DAO, has a very reduced asphaltenes and metals content.
  • One of the aims of the deasphalting step is on the one hand to maximize the quantity of deasphalted oil, and on the other hand to maintain or even minimize the asphaltenes content.
  • This asphaltenes content is generally determined in terms of the quantity of asphaltenes which is insoluble in heptane, i.e. measured using a method described in the standard NF-T 60-115 of January 2002.
  • deasphalting can be used to obtain a deasphalted oil (DAO) containing at most 10000 ppm by weight of asphaltenes, preferably at most 2000 ppm by weight of asphaltenes.
  • DAO deasphalted oil
  • the organic solvent used during the deasphalting step is advantageously a paraffinic solvent, a gasoline cut or condensates containing paraffins.
  • the solvent used comprises at least 50% by weight of hydrocarbon compounds (alkanes) containing between 3 and 7 carbon atoms, more preferably between 3 and 6 carbon atoms, still more preferably 4 or 5 carbon atoms.
  • hydrocarbon compounds alkanes
  • the yield of deasphalted oil and the quality of this oil may vary.
  • the oil yield increases but, in contrast, the quantities of impurities (asphaltenes, metals, Conradson carbon, sulphur, nitrogen, etc) also increase.
  • the choice of operating conditions, in particular the temperature and the quantity of solvent injected has an impact on the yield of deasphalted oil and on the quality of that oil.
  • the person skilled in the art may select the optimized conditions to obtain an asphaltenes content of below 3000 ppm.
  • the deasphalting step may be carried out using any means known to the person skilled in the art. This step is generally carried out in a mixer settler or in an extraction column. Preferably, the deasphalting step is carried out in an extraction column.
  • a mixture comprising the hydrocarbon feed and a first fraction of a solvent feed are introduced into the extraction column, the ratio by volume between the fraction of solvent feed and the hydrocarbon feed being termed the solvent ratio injected with the feed.
  • the aim of this step is to properly mix the feed with the solvent entering the extraction column.
  • a second fraction of solvent feed may be introduced into the decanting zone at the extractor bottom, the ratio by volume between the second fraction of solvent feed and the hydrocarbon feed being termed the solvent ratio injected into the bottom of the extractor.
  • the volume of hydrocarbon feed under consideration in the decanting zone is generally that introduced into the extraction column.
  • the sum of the two ratios by volume between each of the fractions of solvent feed and the hydrocarbon feed is known as the overall solvent ratio.
  • Decanting the asphalt consists of counter-current washing of the emulsion of asphalt in the solvent-oil mixture using pure solvent. It is favoured by an increase in the solvent ratio (in fact, the solvent-oil environment is replaced by a pure solvent environment) and a reduction in temperature.
  • a gradient of temperature is established between the head and the bottom of the column in order to generate an internal reflux, which improves the separation between the oily medium and the resins.
  • the heated mixture of solvent and oil at the head of the extracter means that a fraction comprising resin can be precipitated, which falls inside the extractor.
  • the rising counter-current of the mixture means that the fractions comprising resin which are the lightest can be dissolved at a lower temperature.
  • the pressure prevailing inside the extractor is generally adjusted in a manner such that all of the products remain in the liquid state.
  • the operating conditions for the deasphalting unit (SDA) are advantageously as follows:
  • the aromatics extraction unit is intended to extract the aromatic compounds and resins from the heavy fraction obtained from the deasphalting step by liquid/liquid extraction using a polar solvent.
  • the solvent used is a solvent which is known to preferentially extract aromatic compounds.
  • the liquid/liquid extraction is carried out on the heavy fraction in order to prevent losses in the fuel base yields during solvent recovery after extraction.
  • the products which are to be extracted from the heavy fraction preferably have a boiling point which is higher than the boiling point of the solvent in order to avoid a loss of yield during separation of the solvent from the raffinate after the extraction.
  • any compound with a boiling point lower than the boiling point of the solvent will inevitably leave with the solvent and thus reduce the quantity of raffinate obtained (and thus the fuel base yield).
  • the solvent which may be used is furfural, N-methyl-2-pyrrolidone (NMP), sulfolane, dimethylformamide(DMF), dimethylsulphoxide (DMSO), phenol, or a mixture of these solvents in equal or different proportions.
  • the preferred solvent is furfural, which is a product which is sufficiently heavy compared with the treated fluid: deasphalted oil DAO.
  • An aromatics extraction unit originally constructed for an oil line could advantageously be modified for use in the process in accordance with the invention.
  • the operating conditions are in general a solvent/feed ratio of 0.5/1 to 3/1, preferably 1/1 to 2/1, a temperature profile in the range between ambient temperature and 150° C., preferably in the range 50° C. to 150° C.
  • the pressure is between atmospheric pressure and 2 MPa, preferably between 0.1 MPa and 1 MPa.
  • the liquid/liquid extraction may generally be carried out in a mixer settler or in an extraction column operating in counter-current mode.
  • the extraction is carried out in an extraction column.
  • the solvent selected has a boiling point which is sufficiently high to be able to fluidize the heavy fraction obtained from fractionation without vaporizing it, the heavy fraction typically being conveyed at temperatures in the range 200° C. to 300° C.
  • the extract constituted by portions of the heavy fraction not dissolved in the solvent (and highly concentrated in aromatics)
  • the raffinate constituted by solvent and soluble portions of the heavy fraction.
  • the solvent is separated by distillation of the soluble portions and recycled inside the liquid/liquid extraction process; the management of the solvent is known to the person skilled in the art.
  • the raffinate obtained from the aromatics extraction is sent to the hydrocracking and/or catalytic cracking unit alone or together with one or more other feeds selected from straight run vacuum gas oil (straight run VGO) and light (LVGO) and heavy vacuum distillates (HVGO) obtained from the outlet from the vacuum fractionation c).
  • straight run VGO straight run vacuum gas oil
  • LVGO light
  • HVGO heavy vacuum distillates
  • hydrocracking encompasses cracking processes comprising at least one step for conversion of feeds using at least one catalyst in the presence of hydrogen.
  • Hydrocracking may be carried out in accordance with once-through configurations comprising an initial intense hydrorefining step which is intended to carry out intense hydrodehydrogenation and desulphurization of the feed before the invention can be sent in its entirety over the hydrocracking catalyst proper, in particular in the case when the latter comprises a zeolite.
  • two-step hydrocracking which comprises a first step which is aimed, like the “once-through” process, at carrying out hydrorefining of the feed, but also to obtain a conversion thereof of the order of 30% to 60% in general.
  • first step which is aimed, like the “once-through” process, at carrying out hydrorefining of the feed, but also to obtain a conversion thereof of the order of 30% to 60% in general.
  • second step of a two-step hydrocracking process generally only the fraction of the feed not converted during the first step is treated.
  • Conventional hydrorefining catalysts generally contain at least one amorphous support and at least one hydrodehydrogenating element (generally at least one element from group VIB and non-noble group VIII, and usually at least one element from group VIE and at least one element from non-noble group VIII).
  • matrices which may be used in the hydrorefining catalyst, alone or as a mixture, are alumina, halogenated alumina, silica, silica-alumina, clays (selected, for example, from natural clays such as kaolin or bentonite), magnesia, titanium oxide, boron oxide, zirconia, aluminium phosphates, titanium phosphates, zirconium phosphates, carbon black, and aluminates. It is preferable to use matrices containing alumina, in any of the forms known to the person skilled in the art, and more preferably aluminas, for example gamma alumina.
  • the operating conditions for the hydrocracking step are adjusted in a manner such as to maximize the production of the desired cut while ensuring good operability of the hydrocracking unit.
  • the operating conditions used in the reaction zone or zones are generally an average catalytic bed temperature (WABT) in the range 300° C. to 550° C., preferably in the range 350° C. to 500° C.
  • WABT average catalytic bed temperature
  • the pressure is generally in the range 5 to 35 MPa, preferably in the range 6 to 25 MPa.
  • the liquid space velocity (flow rate of feed/volume of catalyst) is generally in the range 0.1 to 10 h ⁇ 1 , preferably in the range 0.2 to 5 h ⁇ 1 .
  • a quantity of hydrogen is introduced in a manner such that the volume ratio in m 3 of hydrogen per m 3 of hydrocarbon at the inlet to the hydrocracking step is in the range 300 to 2000 m 3 /m 3 , usually in the range 500 to 1800 m 3 /m 3 , preferably in the range 600 to 1500 m 3 /m 3 .
  • This reaction zone generally comprises at least one reactor comprising at least one fixed bed of hydrocracking catalyst.
  • the fixed bed of hydrocracking catalyst may optionally be preceded by at least one fixed bed of a hydrorefining catalyst (hydrodesulphurization, hydrodenitrogenation, for example).
  • the hydrocracking catalysts used in the hydrocracking processes are generally bifunctional in type, associating an acidic function with a hydrogenating function.
  • the acidic function may be provided by supports with a large surface area (generally 150 to 800 m 2 /g) and with a superficial acidity, such as halogenated aluminas (especially chlorinated or fluorinated), combinations of boron and aluminium oxides, amorphous silica-aluminas termed hydrocracking catalysts, and zeolites.
  • the hydrogenating function may be provided either by one or more metals from group VIII of the periodic classification of the elements, or by an association of at least one metal from group VIB of the periodic classification of the elements and at least one metal from group VIII.
  • the hydrocracking catalyst may also comprise at least one crystalline acidic function such as a Y zeolite, or an amorphous acidic function such as a silica-alumina, at least one matrix and a hydrodehydrogenating function.
  • crystalline acidic function such as a Y zeolite
  • amorphous acidic function such as a silica-alumina
  • it may also comprise at least one element selected from boron, phosphorus and silicon, at least one element from group VITA (for example chlorine, fluorine), at least one element from group VIM (for example manganese), and at least one element from group VB (for example niobium).
  • group VITA for example chlorine, fluorine
  • VIM for example manganese
  • group VB for example niobium
  • Fluidized bed catalytic cracking is a well-known process which has evolved enormously since the 1930s (see Avidan A., Shinnar R., “Development of catalytic cracking technology: A lesson in chemical reactor design”, Ind. Eng. Chem. Res, 29, 931-942, 1990).
  • This process is characterized by a reaction zone in which the cracking reactions occur over a zeolitic type catalyst, and a regeneration zone which can be used to eliminate the coke deposited on the catalyst during the cracking reactions by combustion.
  • the catalytic cracking unit of a refinery is principally intended for the production of bases for gasoline, i.e. cuts with a distillation interval in the range 35° C. to 250° C.
  • the conventional feed for a fluidized bed catalytic cracking unit for heavy cuts is generally constituted by a hydrocarbon or a mixture of hydrocarbons essentially (i.e. at least 80%) containing molecules with a boiling point of more than 340° C.
  • This principal feed also contains limited quantities of metals (Ni+V), generally in a concentration of less than 50 ppm, preferably less than 20 ppm, and a hydrogen content which is generally more than 11% by weight, typically in the range 11.5% to 14.5%, and preferably in the range 11.8% to 14% by weight.
  • the Conradson carbon content (abbreviated to CCR) of the feed (defined by the ASTM standard D 482) provides an evaluation of the production of coke during catalytic cracking.
  • the coke yield necessitates specific dimensioning for the unit in order to provide a thermal balance, which is a function of the Conradson carbon of the feed.
  • the fluidized bed catalytic cracking unit is supplied with at least a portion of the raffinate produced in the aromatics extraction unit, alone or as a mixture with other feeds.
  • the catalytic performances of the catalytic cracking unit (consumption of catalysts, conversion, coke production) as well as the quantity and quality of the upgradable products are improved compared with a unit supplied with the deasphalted hydrocarbon cut leaving the deasphalting unit.
  • the costs for operating the downstream units for the hydrotreatment of finished products are reduced as regards the quantities of contact and/or cycle times.
  • the C/O ratio is the ratio of the mass flow rate of catalyst moving in the unit to the mass flow rate of feed at the inlet to the unit.
  • the dwell time is defined as the volume of the riser (m 3 ) over the volume flow rate of feed (m 3 /s).
  • the feed used in this example had the composition detailed in Table 1. It was a vacuum residue of the “Urals” type, and thus a vacuum residue obtained from crude oil originating from Russia.
  • the feed was used in the process in accordance with the invention ( FIG. 2 ) with neither hydrocracking in 60 nor catalytic cracking in 70 , and thus also without adding vacuum distillate obtained by straight run crude oil distillation (SR VGO) 91 at the inlet to the hydrocracking and/or catalytic cracking steps.
  • SR VGO straight run crude oil distillation
  • certain products obtained may subsequently be sent to a hydrocracking step, in particular the raffinate obtained from the extraction step, alone or as a mixture with other cuts obtained from the process in accordance with the invention.
  • the feed was treated in an ebullated bed H-OIL® reactor containing a commercial catalyst for ebullated bed residue hydroconversion (for example TEX2740 or TEX2910, sold by Criterion).
  • a commercial catalyst for ebullated bed residue hydroconversion for example TEX2740 or TEX2910, sold by Criterion.
  • the liquid products obtained from the reactor were fractionated by atmospheric distillation into a naphtha fraction (C5+-150° C.), a gas oil fraction (150-370° C.) and a residual fraction 370° C.+.
  • the residual fraction was fractionated by vacuum distillation into a gas fraction which was sent to the fuel pool, a vacuum distillate VGO (370° C.-540° C.) and a vacuum residual fraction 540° C.+.
  • the residual vacuum fraction underwent C4 solvent deasphalting with an extraction column.
  • a deasphalted oil DAO and a pitch (residual asphalt) were obtained.
  • the deasphalted oil DAO underwent a liquid/liquid extraction with furfural to provide a raffinate and an extract.
  • Part of the extract was advantageously used as the diluent for the deep hydroconversion unit, and part was upgraded with the pitch.
  • the solvent used in the SDA unit was a mixture of butanes containing 60% of nC4 and 40% of iC4.
  • the DAO yield of the deasphalting unit was pushed to 75% in order to maximize upgrading of the deasphalted oil.
  • Table 3 shows that the fact of using the extract obtained in the extraction unit as a diluent for the hydroconversion unit means that the run length for deep hydroconversion can be doubled. The associated gain in finished product production was a little over 3% (1.5 months over 4 years of run).
  • the hydroconversion unit produces a supplemental 5% of upgradable products, i.e. 5% of naphtha, 5% of gas oil and 5% of vacuum gas oil VGO.
  • the raffinate is a less refractory feed to be treated in a fixed bed hydrotreatment unit, for example, or in a hydrocracking unit.

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US20180362865A1 (en) * 2017-06-15 2018-12-20 Saudi Arabian Oil Company Converting carbon-rich hydrocarbons to carbon-poor hydrocarbons
WO2020249498A1 (fr) * 2019-06-12 2020-12-17 IFP Energies Nouvelles Procede de production d'olefines comprenant un hydrotraitement, un desasphaltage, un hydrocraquage et un vapocraquage
CN112920839A (zh) * 2019-12-06 2021-06-08 中国石化工程建设有限公司 一种浆态床加氢裂化反应产物的分离系统及分离方法
US11118122B2 (en) 2017-08-29 2021-09-14 Saudi Arabian Oil Company Integrated residuum hydrocracking and hydrofinishing
US11180701B2 (en) * 2019-08-02 2021-11-23 Saudi Arabian Oil Company Hydrocracking process and system including separation of heavy poly nuclear aromatics from recycle by extraction
US11248174B2 (en) * 2019-12-27 2022-02-15 Saudi Arabian Oil Company Process to remove asphaltene from heavy oil by solvent
CN114599768A (zh) * 2019-11-06 2022-06-07 Ifp 新能源公司 包括脱沥青、加氢裂化和蒸汽裂化的烯烃制备方法
US20220380690A1 (en) * 2019-07-17 2022-12-01 IFP Energies Nouvelles Process for the preparation of olefins, comprising hydrotreatment, de-asphalting, hydrocracking and steam cracking
US20240067891A1 (en) * 2019-10-07 2024-02-29 IFP Energies Nouvelles Process for the preparation of olefins, involving de-asphalting, hydroconversion, hydrocracking and steam cracking

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FR3098522B1 (fr) 2019-07-10 2021-07-09 Axens Procédé de conversion d’une charge contenant de l’huile de pyrolyse
FR3101082B1 (fr) * 2019-09-24 2021-10-08 Ifp Energies Now Procédé intégré d’hydrocraquage en lit fixe et d’hydroconversion en lit bouillonnant avec une séparation gaz/liquide améliorée
FR3113062B1 (fr) * 2020-07-30 2023-11-03 Ifp Energies Now Procédé d’hydroconversion de résidus à plusieurs étages d’hydroconversion intégrant une étape de désasphaltage

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US10836967B2 (en) * 2017-06-15 2020-11-17 Saudi Arabian Oil Company Converting carbon-rich hydrocarbons to carbon-poor hydrocarbons
US20180362865A1 (en) * 2017-06-15 2018-12-20 Saudi Arabian Oil Company Converting carbon-rich hydrocarbons to carbon-poor hydrocarbons
US11118122B2 (en) 2017-08-29 2021-09-14 Saudi Arabian Oil Company Integrated residuum hydrocracking and hydrofinishing
WO2020249498A1 (fr) * 2019-06-12 2020-12-17 IFP Energies Nouvelles Procede de production d'olefines comprenant un hydrotraitement, un desasphaltage, un hydrocraquage et un vapocraquage
FR3097229A1 (fr) * 2019-06-12 2020-12-18 IFP Energies Nouvelles Procede de production d’olefines comprenant un hydrotraitement, un desasphaltage, un hydrocraquage et un vapocraquage
US20220380690A1 (en) * 2019-07-17 2022-12-01 IFP Energies Nouvelles Process for the preparation of olefins, comprising hydrotreatment, de-asphalting, hydrocracking and steam cracking
US11959030B2 (en) * 2019-07-17 2024-04-16 IFP Energies Nouvelles Process for the preparation of olefins, comprising hydrotreatment, de-asphalting, hydrocracking and steam cracking
US11180701B2 (en) * 2019-08-02 2021-11-23 Saudi Arabian Oil Company Hydrocracking process and system including separation of heavy poly nuclear aromatics from recycle by extraction
US20240067891A1 (en) * 2019-10-07 2024-02-29 IFP Energies Nouvelles Process for the preparation of olefins, involving de-asphalting, hydroconversion, hydrocracking and steam cracking
US12098333B2 (en) * 2019-10-07 2024-09-24 IFP Energies Nouvelles Process for the preparation of olefins, involving de-asphalting, hydroconversion, hydrocracking and steam cracking
CN114599768A (zh) * 2019-11-06 2022-06-07 Ifp 新能源公司 包括脱沥青、加氢裂化和蒸汽裂化的烯烃制备方法
US20220372384A1 (en) * 2019-11-06 2022-11-24 IFP Energies Nouvelles Process for the preparation of olefins, comprising de-asphalting, hydrocracking and steam cracking
CN112920839A (zh) * 2019-12-06 2021-06-08 中国石化工程建设有限公司 一种浆态床加氢裂化反应产物的分离系统及分离方法
US11248174B2 (en) * 2019-12-27 2022-02-15 Saudi Arabian Oil Company Process to remove asphaltene from heavy oil by solvent

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