EP3026097A1 - Verfahren zur herstellung von brennstoffen vom typ schweröl aus einer schweren kohlenwasserstoffcharge unter verwendung einer trennung zwischen der hydrotreating- und der hydrocracken-phase - Google Patents

Verfahren zur herstellung von brennstoffen vom typ schweröl aus einer schweren kohlenwasserstoffcharge unter verwendung einer trennung zwischen der hydrotreating- und der hydrocracken-phase Download PDF

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Publication number
EP3026097A1
EP3026097A1 EP15306619.6A EP15306619A EP3026097A1 EP 3026097 A1 EP3026097 A1 EP 3026097A1 EP 15306619 A EP15306619 A EP 15306619A EP 3026097 A1 EP3026097 A1 EP 3026097A1
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Prior art keywords
fraction
hydrocracking
bed
separation
catalyst
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English (en)
French (fr)
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EP3026097B1 (de
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Wilfried Weiss
Isabelle MERDRIGNAC
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IFP Energies Nouvelles IFPEN
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IFP Energies Nouvelles IFPEN
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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
    • 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
    • C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
    • C10G49/002—Apparatus for fixed bed hydrotreatment processes
    • 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
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/04—Liquid carbonaceous fuels essentially based on blends of hydrocarbons
    • C10L1/08—Liquid carbonaceous fuels essentially based on blends of hydrocarbons for compression ignition
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/107—Atmospheric residues having a boiling point of at least about 538 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1077—Vacuum residues
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/202—Heteroatoms content, i.e. S, N, O, P
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/205—Metal content
    • C10G2300/206—Asphaltenes
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/208—Sediments, e.g. bottom sediment and water or BSW
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2200/00—Components of fuel compositions
    • C10L2200/04—Organic compounds
    • C10L2200/0407—Specifically defined hydrocarbon fractions as obtained from, e.g. a distillation column
    • C10L2200/0415—Light distillates, e.g. LPG, naphtha
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2200/00—Components of fuel compositions
    • C10L2200/04—Organic compounds
    • C10L2200/0407—Specifically defined hydrocarbon fractions as obtained from, e.g. a distillation column
    • C10L2200/0438—Middle or heavy distillates, heating oil, gasoil, marine fuels, residua
    • C10L2200/0446—Diesel
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2270/00—Specifically adapted fuels
    • C10L2270/02—Specifically adapted fuels for internal combustion engines
    • C10L2270/026—Specifically adapted fuels for internal combustion engines for diesel engines, e.g. automobiles, stationary, marine

Definitions

  • the present invention relates to the refining and conversion of heavy hydrocarbon fractions containing, inter alia, sulfur impurities. It relates more particularly to a process for treating heavy petroleum feedstocks for the production of fuel oils and oil bases, in particular bunker oil and bunker oil bases, with low sulfur content and low sediment content.
  • the object of the present invention is to produce fuel oils and oil bases, in particular bunker oil and bunker oil bases, which comply with the recommendations of the MARPOL convention in terms of equivalent sulfur content, and preferably also respecting the recommendations on sediment content after aging, as described for marine fuels in ISO8217.
  • Fuel oils used in maritime transport generally include atmospheric distillates, vacuum distillates, atmospheric residues and vacuum residues from direct distillation or from refining processes, including hydrotreatment and conversion processes, which may be be used alone or mixed.
  • Another object of the present invention is to jointly produce, by the same method, atmospheric distillates (naphtha, kerosene, diesel), vacuum distillates and / or light gases (C1 to C4).
  • the bases of the naphtha and diesel type can be upgraded to refineries for the production of automotive and aviation fuels, such as, for example, super-fuels, Jet fuels and gas oils.
  • the present invention makes it possible to improve the conversion processes described in the state of the art for the production of fuel oils and bases of low-sulfur fuel oils.
  • An ebullating bed can be defined as a fluidized solid-liquid gas bed in which the catalyst particles have a size of between 0.5 and 1.5 mm, preferably between 0.8 mm and 1.2 mm, and still more preferred between 0.9 mm and 1.1 mm.
  • a hybrid type of bed corresponds to a bubbling bed in which an additional injection of a dispersed catalyst was made.
  • a dispersed catalyst is a catalyst in the form of very fine particles, that is to say generally a size of between 1 nanometer (ie 10 -9 m) and 150 micrometers, preferably between 0.1 and 100 micrometers, and even more preferred, between 10 and 80 microns.
  • a hybrid bed thus comprises two populations of catalyst, a population of bubbling bed catalyst to which is added a population of dispersed type catalyst.
  • the HCAT® technology marketed by the company HTI is an example of implementation of dispersed catalyst injected into a bubbling bed reactor.
  • the process for treating a heavy hydrocarbon feedstock according to the present invention can be broken down into several variants.
  • the hydrocracking step c) comprises a first bubbling bed reactor followed by a second "hybrid” type bed reactor (that is to say of the bubbling bed type with catalyst injection type "scattered”).
  • the hydrocracking step c) comprises a first hybrid bed type reactor followed by a second hybrid type reactor.
  • the hydrocracking step c) comprises a single hybrid bed type reactor.
  • the said liquid hydrocarbon fraction resulting from the separation step d) is furthermore subjected to a treatment stage e) making it possible to treat and separate sediments and residues from catalysts, by maturation converting potential sediments into existing sediments and then physical separation allowing the elimination of all existing sediments.
  • said liquid hydrocarbon fraction is further subjected to a step of recovering the "dispersed" catalyst in addition to the treatment step e) for treating and separating sediments and catalyst residues.
  • the step d) of separation of the effluent resulting from the hydrocracking step can be carried out either in a summary manner, allowing one or two liquid fractions to be obtained, or in a more complete manner allowing then to obtain at least three liquid fractions.
  • the separation d) carried out more completely thus makes it possible to obtain well-separated atmospheric and / or vacuum distillate cuts (naphtha, kerosene, gas oil, vacuum gas oil, for example) from the atmospheric residue and / or under vacuum.
  • the treatment step e) makes it possible to convert, by maturation, the potential sediments contained in the heavy fraction resulting from the upstream separation d), into existing sediments, and then to separate them from the liquid fraction.
  • This treatment step therefore involves a physical separation of the sediments formed.
  • we have not given a specific name to this separation which therefore forms an integral part of the processing step e).
  • the final optional separation step f) is necessary in the case where the upstream separation d) has been carried out in a summary manner.
  • the final separation step f) then makes it possible to separate the heavy hydrocarbon fraction with reduced sediment content which can then constitute a marine fuel in the sense of the ISO8217 standard.
  • step a) of fixed bed hydrotreating is both to refine, that is to say substantially reduce the content of metals, sulfur and other impurities, and to improve the hydrogen ratio on carbon (H / C) of the hydrocarbon feed while transforming said hydrocarbon feedstock at least partially into lighter cuts.
  • step (a) of hydrotreating in fixed bed is then subjected to a separation step b) to obtain different fractions.
  • This separation makes it possible to remove from the effluent obtained at the end of step (a) of hydrotreatment the lighter fractions which do not require additional treatment, or a moderate treatment, and to recover a heavy fraction which is sent to step (c) hybrid bed hydrocracking which partially converts said heavy fraction to produce an effluent that can be used totally or partly as fuel oil or as fuel oil base, especially as bunker oil or as a fuel oil base.
  • the supported and dispersed catalyst consumption in the hybrid bed hydrocracking step is greatly reduced compared to a process without prior fixed bed hydrotreatment.
  • the intermediate separation step b) between the hydrotreatment step a) and the hydrocracking step c) advantageously makes it possible to minimize the fraction to be treated in said hydrocracking step c). In this way, the capacity of the hybrid bed hydrocracking reaction section may be less important. Likewise, over-cracking of the light fractions is avoided and thus a loss of yield of fuel-type fractions is avoided.
  • the separation step b) also makes it possible to eliminate a portion of the hydrogen introduced upstream of the hydrotreatment step a), which makes it possible to work with different hydrogen coverage levels in step a ) hydrotreatment and hydrocracking step c).
  • the elimination, during the separation step b), of light fraction, and in particular of a large part of the hydrogen sulphide formed during step a) of hydrotreatment makes it possible to work at a partial pressure of higher hydrogen (for the same total pressure) during the hydrocracking step, thus leading to products of better quality.
  • the hydrocarbon feedstock treated in the process according to the invention can be described as a heavy load. It has an initial boiling point of at least 350 ° C and a final boiling temperature of at least 450 ° C. Preferably, its initial boiling point is at least 375 ° C., and its final boiling point is at least 460 ° C., preferably at least 500 ° C., and even more preferably at least minus 600 ° C.
  • the hydrocarbon feedstock may be chosen from atmospheric residues (RA) obtained from an atmospheric distillation, vacuum residues (RSV) resulting from vacuum distillation, deasphalted oils, deasphalting resins, asphalts or deasphalting pitches. , residues resulting from conversion processes such as coking, aromatic extracts from lubricant base production lines, oil sands or derivatives thereof, oil shales or their derivatives, parent rock oils or their derivatives, whether alone or in admixture.
  • RA atmospheric residues
  • RSV vacuum residues
  • the charges which are treated are preferably atmospheric residues (RA) or vacuum residues (RSV), or residues of conversion processes, or any mixtures of these different types of residues.
  • RA atmospheric residues
  • RSV vacuum residues
  • hydrocarbon feedstock treated in the process according to the invention is sulfurized.
  • Its sulfur content is at least 0.5% by weight, preferably at least 1% by weight, more preferably at least 2% by weight.
  • the hydrocarbon feedstock treated in the process according to the invention may contain asphaltenes. Its asphaltenes content may be at least 1% by weight, preferably at least 2% by weight.
  • This co-charge may be a hydrocarbon fraction or a mixture of lighter hydrocarbon fractions, which may preferably be chosen from products derived from a fluid-bed catalytic cracking (FCC) process, a light cutting oil (LCO or light cycle oil "according to the English terminology), a heavy cutting oil (HCO or" heavy cycle oil “according to the English terminology), a decanted oil, an FCC residue, a diesel fraction, in particular a fraction obtained by atmospheric or vacuum distillation, such as vacuum gas oil, or may come from another refining process.
  • FCC fluid-bed catalytic cracking
  • the co-charge may also consist of one or more cuts from the process of liquefying coal or biomass, aromatic extracts, or any other hydrocarbon cuts or non-petroleum fillers such as pyrolysis oil.
  • the heavy hydrocarbon feedstock according to the invention may represent at least 50%, preferably 70%, more preferably at least 80%, and even more preferably at least 90% by weight of the total hydrocarbon feedstock treated by the process according to the invention.
  • the heavy hydrocarbon feedstock is subjected according to the process of the present invention to a fixed bed hydrotreating step (a) in which feedstock and hydrogen are contacted on a hydrotreatment catalyst.
  • Hydroprocessing commonly known as HDT, is understood to mean catalytic treatments with hydrogen supply that make it possible to refine, that is to say, to substantially reduce the content of metals, sulfur and other impurities contained in the hydrocarbon feed while increasing the ratio hydrogen on carbon charge.
  • Hydroprocessing is accompanied by the formation of lighter cuts than the starting load.
  • Hydrotreatment includes, in particular, hydrodesulfurization reactions (commonly referred to as HDS), hydrodenitrogenation reactions (commonly referred to as HDN), and hydrodemetallation reactions (commonly referred to as HDM), accompanied by hydrogenation, hydrodeoxygenation, hydrogenation, and hydrogenation reactions.
  • the hydrotreatment step (a) comprises a first hydrodemetallization (HDM) step (a1) carried out in one or more hydrodemetallation zones in fixed beds, and a second (a2) subsequent step of hydrodesulfurization (HDS) carried out in one or more hydrodesulfurization zones in fixed beds.
  • HDM hydrodemetallization
  • HDS hydrodesulfurization
  • the fixed-bed hydrotreating zone may comprise permutable reactors, for example reactive guards reactors which, in a sequence including stages of operation, stopping, unloading and replacement of the catalyst, , a longer cycle time, especially for loads with a high metal content.
  • permutable reactors for example reactive guards reactors which, in a sequence including stages of operation, stopping, unloading and replacement of the catalyst, , a longer cycle time, especially for loads with a high metal content.
  • the feedstock and the hydrogen are contacted on a hydrodemetallization catalyst, under hydrodemetallation conditions, and then during said second hydrodesulphurization step (a2). the effluent of the first hydrodemetallation step (a1) is contacted with a hydrodesulfurization catalyst under hydrodesulfurization conditions.
  • This process known as HYVAHL-F TM, is for example described in US Patent 5,417,846 .
  • the hydrotreatment step (a) according to the invention may advantageously be carried out at a temperature of between 300 ° C. and 500 ° C., preferably between 350 ° C. and 420 ° C., and under an absolute pressure of between 2 MPa and 35 MPa, preferably between 11 MPa and 20 MPa.
  • the space velocity of the hydrocarbon feedstock can be in a range from 0, 1 h -1 to 5 h -1 , preferably from 0.1 h -1 to 2 h -1 , and more preferably from 0.1 h -1 to 0.45 h -1 .
  • the quantity of hydrogen mixed with the feedstock may be between 100 and 5000 normal cubic meters (Nm 3 ) per cubic meter (m 3 ) of liquid feedstock, preferably between 200 Nm 3 / m 3 and 2000 Nm 3 / m 3 , and more preferably between 300 Nm 3 / m 3 and 1500 Nm 3 / m 3 .
  • the hydrotreating step (a) can be carried out industrially in one or more liquid downflow reactors.
  • the hydrotreatment catalysts used are generally granular catalysts comprising, on a support, at least one metal or metal compound having a hydrodehydrogenating function. These catalysts may advantageously be catalysts comprising at least one Group VIII metal, generally selected from the group consisting of nickel and cobalt, and / or at least one Group VIB metal, preferably molybdenum and / or tungsten.
  • a catalyst comprising from 0.5% to 10% by weight of nickel, preferably from 1% to 5% by weight of nickel (expressed as nickel oxide NiO), and from 1% to 30% by weight of nickel.
  • weight of molybdenum preferably from 5% to 20% by weight of molybdenum (expressed as MoO 3 molybdenum oxide) on a mineral support.
  • This support may for example be chosen from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals.
  • a hydrotreating step including a hydrodemetallation (HDM) step and then a hydrodesulphurization step (HDS)
  • specific catalysts adapted to each step are preferably used.
  • Catalysts that can be used in the HDM step are, for example, indicated in the patent documents EP 0113297 , EP 0113284 , US 5221656 , US 5827421 , US 7119045 , US 5622616 and US 5089463 .
  • HDM catalysts are preferably used in the reactive reactors.
  • Catalysts that can be used in the HDS step are, for example, indicated in the patent documents EP 0113297 , EP 0113284 , US 6589908 , US 4818743 or US 6332976 .
  • the catalysts used in the process according to the present invention are preferably subjected to an in-situ or ex-situ sulphurization treatment.
  • the effluent obtained at the end of the step (a) of hydrotreatment in a fixed bed undergoes at least one separation step, possibly completed by additional separation steps, making it possible to separate at least one light fraction and at least one less a heavy fraction.
  • light fraction is meant a fraction in which at least 90% of the compounds have a boiling point below 350 ° C.
  • the light fraction obtained during the separation step (b) comprises a gaseous phase and at least a light fraction of hydrocarbons of the naphtha, kerosene and / or diesel type.
  • the heavy fraction preferably comprises a vacuum distillate fraction and a vacuum residue fraction and / or an atmospheric residue fraction.
  • the step (b) of separation can be implemented by any method known to those skilled in the art. This method can be selected from high or low pressure separation, high or low pressure distillation, high or low pressure stripping, liquid / liquid extraction, and combinations of these different methods that can operate at different pressures and temperatures.
  • the effluent from step (a) hydrotreatment undergoes a step (b) separation with decompression.
  • the separation is preferably carried out in a fractionation section which may first include a high temperature high pressure separator (HPHT), and optionally a low temperature high pressure separator (HPBT), optionally followed subsequently by an atmospheric distillation section and / or a vacuum distillation section.
  • HPHT high temperature high pressure separator
  • HPBT low temperature high pressure separator
  • said heavy fraction can be fractionated by atmospheric distillation into at least one atmospheric distillate fraction, preferably containing at least a light fraction of naphtha, kerosene and / or diesel-type hydrocarbons, and an atmospheric residue fraction.
  • At least a portion of the atmospheric residue fraction can also be fractionated by vacuum distillation into a vacuum distillate fraction, preferably containing vacuum gas oil, and a vacuum residue fraction.
  • At least a portion of the vacuum residue fraction and / or the atmospheric residue fraction is advantageously sent to the hydrocracking step (c).
  • Part of the gas oil under vacuum, atmospheric residue and / or under vacuum can also be recycled in step (a) hydrotreatment or be withdrawn and sent to the product tanks or to another refining unit (catalytic cracking or hydrocracking of gas oil under vacuum under vacuum for example).
  • a portion of the effluent from the hydrotreating step (a) undergoes a step (b) of separation without decompression of at least one heavy fraction.
  • the effluent of the hydrotreatment step (a) is sent to a separation section, generally in an HPHT separator, having a cutting point between 200 ° C. and 400 ° C., making it possible to obtain at least one light fraction and at least one heavy fraction.
  • the separation is preferably not made according to a precise cutting point, it is rather like a flash type separation.
  • the heavy fraction can then be directly sent, in admixture with a hydrogen-rich gas, in step (c) of hydrocracking.
  • the light fraction may undergo other separation steps.
  • it may be subjected to atmospheric distillation to obtain a gaseous fraction, at least a light fraction of liquid hydrocarbons of the naphtha, kerosene and / or diesel type and a vacuum distillate fraction, the latter being at least part sent at least partly in step (c) of hydrocracking.
  • Another part of the vacuum distillate can be used as a fluxing agent for a fuel oil.
  • Another part of the vacuum distillate can be upgraded by being subjected to a hydrocracking step and / or catalytic cracking in a fluidized bed.
  • the light fraction from the HPHT separator can be cooled and then introduced into a low temperature high pressure separator (HPBT) in which a hydrogen-containing gas fraction and a distillate-containing liquid fraction are separated.
  • HPBT low temperature high pressure separator
  • This liquid fraction containing distillates can be sent to the hydrocracking step c), via a pump, in a mixture with the liquid fraction from the HPHT separator.
  • this liquid fraction containing distillates can be sent to the final separation step d) which also processes the effluent from the hydrocracking step c).
  • No-decompression separation provides better thermal integration, and saves energy and equipment.
  • this embodiment has technical and economic advantages since it is not necessary to increase the flow pressure after separation before the subsequent hydrocracking step.
  • the gaseous fractions resulting from the separation step preferably undergo a purification treatment to recover the hydrogen and recycle it to the hydrotreatment and / or hydrocracking reactors.
  • the presence of the intermediate separation step, between step (a) of hydrotreatment and step (c) of hydrocracking, advantageously makes it possible to have two independent hydrogen circuits, one connected to hydrotreating, the other hydrocracking, and which, if necessary, can be connected to each other.
  • Hydrogen makeup can be done at the hydrotreatment section, or at the hydrocracking section, or at both.
  • the recycle hydrogen can supply the hydrotreatment section or the hydrocracking section or both.
  • a compressor may possibly be common to both hydrogen circuits. The fact of being able to connect the two hydrogen circuits makes it possible to optimize the hydrogen management and to limit investments in terms of compressors and / or purification units of the gaseous effluents.
  • the light fraction obtained at the end of the separation step (b), which comprises hydrocarbons of the naphtha, kerosene and / or diesel or other type, in particular LPG and vacuum gas oil, can be recovered according to the methods that are well known. of the skilled person.
  • the products obtained can be incorporated into fuel formulations (also called “pools" fuels according to the English terminology), or undergo additional refining steps.
  • the fraction (s) naphtha, kerosene, gas oil and vacuum gas oil may be subjected to one or more treatments, for example hydrotreatment, hydrocracking, alkylation, isomerization, catalytic reforming, catalytic or thermal cracking, to bring them in a controlled manner. separated or in mixture, to the required specifications which may relate to the sulfur content, the smoke point, the octane number, cetane, and others.
  • At least one inter-stage separator for separating a gas fraction and a liquid fraction can be installed so as to send to the second reactor only the liquid fraction from the separator interstage.
  • the "disperse" catalyst that occurs in the hybrid bed reactor is a sulfide catalyst preferably containing at least one member selected from the group consisting of Mo, Fe, Ni, W, Co, V, Ru.
  • These catalysts are generally monometallic or bimetallic (by combining, for example, a non-noble group VIIIB element (Co, Ni, Fe) and a group VIB element (Mo, W) .
  • the catalysts used may be heterogeneous solid powders (such as natural ores, iron sulphate, etc.), dispersed catalysts derived from water-soluble precursors such as phosphomolybdic acid, ammonium molybdate, or a mixture of Mo or Ni oxide. with aqueous ammonia.
  • the catalysts used are derived from soluble precursors in an organic phase (oil-soluble catalysts).
  • the precursors are organometallic compounds such as the naphthenates of Mo, Co, Fe, or Ni, or the Mo octoates, or the multi-carbonyl compounds of these metals, for example 2-ethyl hexanoates of Mo or Ni, acetylacetonates of Mo or Ni, C7-C12 fatty acid salts of Mo or W, etc. They can be used in the presence of a surfactant to improve the dispersion of metals, when the catalyst is bimetallic.
  • the catalysts are in the form of dispersed particles, colloidal or otherwise depending on the nature of the catalyst. Such precursors and catalysts that can be used in the process according to the invention are widely described in the literature.
  • the catalysts are prepared before being injected into the feed.
  • the preparation process is adapted according to the state in which the precursor is and of its nature. In all cases, the precursor is sulfided (ex-situ or in-situ) to form the catalyst dispersed in the feedstock.
  • the precursor is mixed with a carbonaceous feedstock (which may be part of the feedstock to be treated, an external feedstock, a recycled fraction, etc.).
  • the mixture is then sulphurized by adding a sulfur compound (preferred hydrogen sulphide or optionally an organic sulphide such as DMDS in the presence of hydrogen) and heated.
  • a sulfur compound preferred hydrogen sulphide or optionally an organic sulphide such as DMDS in the presence of hydrogen
  • the preparations of these catalysts are described in the literature.
  • the "dispersed" catalyst particles as defined above generally have a size of between 1 nanometer and 150 microns, preferably between 0.1 and 100 microns, and even more preferably between 10 and 80 microns.
  • the content of catalytic compounds (expressed as weight percentage of metal elements of group VIII and / or of group VIB) is between 0 and 10% by weight, preferably between 0 and 1% by weight.
  • Additives may be added during the preparation of the dispersed catalyst or the dispersed catalyst before it is injected into the reactor. These additives are described in the literature.
  • the preferred solid additives are inorganic oxides such as alumina, silica, mixed Al / Si oxides, supported spent catalysts (for example, on alumina and / or silica) containing at least one group VIII element (such as Ni, Co) and / or at least one group VIB element (such as Mo, W).
  • group VIII element such as Ni, Co
  • group VIB element such as Mo, W
  • the catalysts described in the application US2008 / 177124 Carbonaceous solids with a low hydrogen content (for example 4% hydrogen) such as coke or milled activated carbon, optionally pretreated, may also be used. Mixtures of such additives can also be used.
  • the particle size of the additive is generally between 10 and 750 microns, preferably between 100 and 600 microns.
  • the content of any solid additive present at the inlet of the hydrocracking reaction zone in a hybrid bed is between 0 and 10 wt.%, Preferably between 1 and 3 wt.%,
  • the content of catalytic compounds (expressed as a percentage wt. Group VIII and / or Group VIB metal elements are from 0 to 10% by weight, preferably from 0 to 1% by weight.
  • the hybrid bed reactor (s) used in the hydrocracking zone therefore consist of two populations of catalysts, a first population using supported catalysts in the form of extrudates whose diameter is advantageously between 0.8 and 1.2 mm. , generally equal to 0.9 mm or 1.1 mm and a second population of "dispersed" type catalyst discussed above.
  • the fluidization of the catalyst particles in the bubbling bed is enabled by the use of a boiling pump which allows a recycle of liquid, generally inside the reactor.
  • the flow rate of liquid recycled by the boiling pump is adjusted so that the catalyst particles are fluidized but not transported, so that these particles remain in the bubbling bed reactor (with the exception of fine catalysts that can be formed by attrition and trained with the liquid since these fines are small).
  • a conventional granular hydrocracking catalyst generally an extrudate, comprising, on an amorphous support, at least one metal or metal compound having a hydro-dehydrogenating function.
  • This catalyst may be a catalyst comprising Group VIII metals, for example nickel and / or cobalt, most often in combination with at least one Group VIB metal, for example molybdenum and / or tungsten.
  • Group VIII metals for example nickel and / or cobalt
  • a catalyst comprising from 0.5% to 10% by weight of nickel and preferably from 1% to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1% to 30% by weight may be used.
  • molybdenum preferably from 5% to 20% by weight of molybdenum (expressed as molybdenum oxide MoO3) on an amorphous mineral support.
  • This support may for example be chosen from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals.
  • This support may also contain other compounds and for example oxides selected from the group consisting of boron oxide, zirconia, titanium oxide, phosphoric anhydride. Most often an alumina support is used and very often a support of alumina doped with phosphorus and possibly boron.
  • phosphorus pentoxide P2O5 When phosphorus pentoxide P2O5 is present, its concentration is usually less than 20% by weight and most often less than 10% by weight. When B2O3 boron trioxide is present, its concentration is usually less than 10% by weight.
  • the alumina used is usually a y (gamma) or ⁇ (eta) alumina. This catalyst may be in the form of extrudates.
  • the total content of metal oxides of groups VI and VIII may be between 5% and 40% by weight, preferably between 7% and 30% by weight, and the weight ratio expressed as metal oxide between metal (or metals) of group VI on metal (or metals) of group VIII is between 20 and 1, preferably between 10 and 2.
  • the spent catalyst may be partly replaced by fresh catalyst, generally by withdrawing from the bottom of the reactor and introducing the fresh or new catalyst at the top of the reactor at a regular time interval, that is to say, for example by puff or continuously or almost continuously.
  • the catalyst can also be introduced from below and withdrawn from the top of the reactor. For example, fresh catalyst can be introduced every day.
  • the replacement rate of spent catalyst with fresh catalyst may be, for example, from about 0.05 kilograms to about 10 kilograms per cubic meter of charge.
  • the hydrocracking reactor usually comprises a recirculation pump for maintaining the catalyst in a bubbling bed by continuous recycling of at least a portion of the liquid withdrawn at the top of the reactor and reinjected at the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor into a regeneration zone in which the carbon and the sulfur contained therein are eliminated before it is reinjected in the hydrocracking step c).
  • a reactor operating in a bubbling bed during step c) of hydrocracking its implementation may be similar to that of the H-OIL® process as described, for example, in the US Patent 6270654 .
  • the operating conditions of the hydrocracking zone in at least one reactor containing a "dispersed" catalyst coupled with the fact that the feedstock was previously hydrotreated in step a) of hydrotreatment, then separated in step b) of separation allow to obtain conversion rates of between 30 and 100%, preferably between 40 and 80% and hydrodesulphurization rates between 70 and 100%, preferably between 85 and 99%.
  • the conversion ratio mentioned above is defined as the amount of compounds having a boiling point greater than 520 ° C in the initial hydrocarbon feedstock, minus the amount of compounds having a boiling point higher than 520 ° C in the hydrocarbon effluent obtained at the end of the hydrocracking step c), all divided by the amount of compounds having a boiling point greater than 520 ° C. in the initial hydrocarbon feedstock.
  • a high conversion rate is advantageous to the extent that this conversion rate illustrates the production of conversion products, mainly atmospheric distillates and / or vacuum distillates of the naphtha, kerosene and diesel type, in a significant amount.
  • the hydrodesulphurization rate mentioned above is defined as the amount of sulfur in the initial hydrocarbon feedstock, minus the amount of sulfur in the hydrocarbon effluent obtained at the end of the hydrocracking step c), the whole divided by the amount of sulfur in the initial hydrocarbon feed.
  • the process according to the invention comprises a step d) of separation make it possible to obtain at least one gaseous fraction and at least one liquid hydrocarbon fraction.
  • the effluent obtained at the end of the hydrocracking step c) comprises a liquid fraction and a gaseous fraction containing the gases, in particular H 2, H 2 S, NH 3, and C 1 -C 4 hydrocarbons.
  • This gaseous fraction can be separated from the hydrocarbon effluent by means of separating devices well known to those skilled in the art, in particular by means of one or more separator flasks that can operate at different pressures and temperatures, possibly associated with each other. steam or hydrogen stripping means, and generally one or more distillation columns.
  • the effluent obtained at the end of the hydrocracking step c) is advantageously separated in at least one separator flask into at least one gaseous fraction and at least one liquid fraction.
  • separators may, for example, be high temperature high pressure separators (HPHT) and / or low temperature high pressure separators (HPBT).
  • this gaseous fraction is preferably treated in a hydrogen purification means so as to recover the hydrogen that is not consumed during the hydrotreatment and hydrocracking reactions.
  • the hydrogen purification means may be an amine wash, a membrane, a PSA (pressure swing adsorption) system, or a plurality of these means arranged in series.
  • the purified hydrogen can then advantageously be recycled in the process according to the invention, after possible recompression.
  • the hydrogen may be introduced at the inlet of the hydrotreatment step (a) and / or at different locations during the hydrotreatment stage and / or at the inlet of the hydrocracking step (c). and / or at different locations during step c) of hydrocracking.
  • the separation step d) may also comprise a steam or hydrogen stripping step, generally with steam, in order to remove at least one gas fraction rich in hydrogen sulfide (H2S).
  • H2S hydrogen sulfide
  • the separation step d) may also comprise atmospheric distillation and / or vacuum distillation.
  • the separation step (d) further comprises at least one atmospheric distillation, in which the liquid hydrocarbon fraction (s) obtained after separation is (are) fractionated (s). by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction.
  • the atmospheric distillate fraction may contain commercially recoverable fuels bases (naphtha, kerosene and / or diesel), for example in the refinery for the production of motor and aviation fuels.
  • the separation step (d) of the process according to the invention may advantageously also comprise at least one vacuum distillation in which the liquid hydrocarbon fraction (s) obtained (s) after separation and / or the atmospheric residue fraction obtained after atmospheric distillation is (are) fractionated by vacuum distillation into at least one vacuum distillate fraction and at least one vacuum residue fraction.
  • the step d) of separation of the effluent resulting from the hydrocracking step can be carried out either in a summary manner, allowing one or two liquid fractions to be obtained, or in a more complete manner and making it possible to obtain at least three liquid fractions.
  • the separation d) carried out in a more complete manner thus makes it possible to obtain distillate atmospheric and / or well separated vacuum cuts (naphthta, kerosen, gas oil, vacuum gas oil, for example) from the atmospheric residue and / or under vacuum.
  • the manner in which this separation step is performed conditions the continuation of the optional steps e) and f).
  • the separation step (d) comprises a hot high pressure flask, a high pressure cold flask, a low pressure hot flask, a low pressure cold flask, and then a flask.
  • the vacuum distillate fraction typically contains vacuum gas oil fractions.
  • At least a portion of the atmospheric residue fraction and / or the vacuum distillate fraction, and / or the vacuum residue fraction, can be recycled in the hydrocracking step c) or in the hydrotreatment step a) or be sent to product tanks or be treated in another refining unit (catalytic cracking or vacuum distillate hydrocracking, for example).
  • the separation step (d) comprises a hot high pressure flask, a high pressure cold flask, a low pressure hot flask, a low pressure cold flask and then a liquid fraction. from the separator flasks, a steam stripping column for removing at least one light fraction rich in hydrogen sulfide.
  • This second embodiment may be advantageous during the implementation of the optional steps e) treatment of sediments and catalyst residues and f) separation of the liquid fraction from step d).
  • the distillation columns of step f) are less prone to fouling since they treat a liquid fraction whose sediment content was reduced during step e). It is therefore advantageous to carry out step d) in a summary manner by using a minimum of equipment that processes a hydrocarbon fraction that may contain sediments.
  • This liquid hydrocarbon fraction can advantageously be used as a base of fuel oil or as fuel oil, especially as a base of bunker oil or as fuel oil, with low sulfur content meeting the new recommendations of the International Maritime Organization.
  • all of the liquid hydrocarbon effluent obtained at the end of the separation step (d) may have a sulfur content of less than or equal to 0.5% by weight, and preferably less than or equal to 0.3. % in weight.
  • This liquid hydrocarbon effluent may, at least in part, advantageously be used as fuel oil bases or as fuel oil, especially as a fuel oil base or as bunker oil with low sulfur content meeting the new recommendations of the International Maritime Organization.
  • fuel is meant in the invention a hydrocarbon feedstock used as fuel.
  • oil base is meant in the invention a hydrocarbon feed which, mixed with other bases, constitutes a fuel oil.
  • the properties of these bases are very diverse.
  • One of the interests of the sequence of a hydrotreatment in a fixed bed and then a hydrocracking in at least one reactor containing a "dispersed" catalyst lies in the fact that the charge of the hybrid bed hydrocracking reactor is already at least partially hydrotreated. In this way, it is possible to obtain equivalent conversion of hydrocarbon effluents of better quality, in particular with lower sulfur contents.
  • the supported and dispersed catalyst consumption in the hybrid bed hydrocracking step is greatly reduced compared to a process without prior fixed bed hydrotreatment.
  • the hydrocarbon effluent obtained at the end of step d) of separation of the hydrocracking effluent, and in particular the heavier liquid fraction obtained, generally a fraction of the atmospheric residue or vacuum residue type, may contain sediments and catalyst residues. At least a portion of the sediments may consist of precipitated asphaltenes resulting from a hydrocracking of a petroleum residue feed.
  • the catalyst residues may be fines resulting from the attrition of extruded type catalysts in the implementation of a bubbling bed hydrocracking reactor.
  • the phenomenon of attrition of extruded type catalysts can also be in a hybrid bed.
  • Another part of the catalyst residues comes from the "dispersed" catalyst.
  • the process according to the invention may comprise an additional step of separating the sediments. and the catalyst residues of the liquid hydrocarbon effluent after step d) of separation.
  • the maturation step consists in applying a residence time of between 1 and 1500 minutes, preferably between 30 and 300 minutes, more preferably between 60 and 180 minutes, to the heavy fraction previously heated to a temperature between 100 and 500 ° C. C, preferably between 150 and 350 ° C, and more preferably between 200 and 300 ° C.
  • the pressure of the maturation stage is less than 200 bar, preferably less than 100 bar, more preferably less than 30 bar, and even more preferably less than 15 bar.
  • This maturation step can be done, for example with an exchanger or a heating furnace and then one or more capacity (s) in series or in parallel such (s) as a horizontal or vertical balloon, optionally with a decanting function for remove some of the heavier solids, and / or a piston reactor.
  • a stirred and heated tank may also be used, and may optionally be bottom tapped to remove some of the heavier solids.
  • the maturation step can be carried out in the presence of an inert gas (nitrogen for example) or oxidizing (oxygen, air or air depleted by nitrogen). The use of an oxidizing gas accelerates the maturation process.
  • the present invention limits the cost of hydrocracking catalysts due to the upstream hydrotreatment step. It may, however, be advantageous to at least partially recover the "dispersed” catalyst present in the heavy cuts. This step of recovering the "dispersed” catalyst can therefore be performed consecutively or simultaneously at the step of separating sediments and catalyst residues.
  • the method according to the invention may therefore further comprise a treatment step e) allowing the separation of sediments and catalyst residues, optionally coupled simultaneously or consecutively, to a "dispersed" catalyst recovery step.
  • a treatment step e) allowing the separation of sediments and catalyst residues, optionally coupled simultaneously or consecutively, to a "dispersed" catalyst recovery step.
  • this step e) at least a portion of the atmospheric residue and / or vacuum residue fractions are subjected to a separation of sediments and catalyst residues, optionally coupled simultaneously or consecutively, to a catalyst recovery step.
  • dispersed ", using in step e) after the maturation to convert the potential sediments into existing sediments, at least one filter, a separation on membranes, a bed of organic or inorganic type filtering solids, an electrostatic precipitation , a centrifuge system, in-line decantation, auger withdrawal.
  • Step e) sediment treatment is a clever coupling of a first stage of maturation to convert potential sediments into existing
  • the liquid hydrocarbon fraction from sediment treatment step e) is characterized by a sediment content after aging (IP390) of less than 0.1% by weight.
  • This liquid hydrocarbon fraction can advantageously be used as a fuel oil base or as fuel oil, especially as a bunker oil or bunker fuel oil base, with low sulfur content and low sediment content after aging in accordance with the new recommendations of the Maritime Organization. International and ISO8217 standard for marine fuels.
  • all the liquid hydrocarbon effluent obtained at the end of the sediment treatment step e) has a sulfur content of less than or equal to 0.5% by weight, and preferably less than or equal to 0.3. % in weight.
  • all of the liquid hydrocarbon effluent obtained at the end of the sediment treatment step e) has a sediment content after aging (IP390) of less than 0.1% by weight.
  • Step f separating the effluent from the sediment treatment stage
  • the method according to the invention comprises a step f) of separation make it possible to obtain at least one liquid hydrocarbon fraction.
  • the effluent obtained at the end of step d) of sediment treatment comprises at least one liquid fraction.
  • the composition of this liquid fraction depends on the manner in which the step d) of separation of the hydrocracking effluent has been carried out. If step d) has been carried out in a summary manner, the effluent from step e) therefore contains a mixture of distillates and residues that must be separated in order to valorize each of the cuts, by putting into effect at least one distillation column. If step d) was conducted more completely, only a liquid fraction of the vacuum residue type and / or atmospheric residue was sent to the sediment treatment step e). In the case of a d) more complete separation, the liquid fraction from step e) may therefore not require an optional step f).
  • the liquid hydrocarbon fraction from the separation step f) is characterized by a sediment content after aging (IP390) of less than 0.1% by weight.
  • This liquid hydrocarbon fraction can advantageously be used as a base of fuel oil or as fuel oil, especially as a bunker oil or bunker fuel oil base, with low sulfur content and low sediment content after aging in accordance with the new recommendations of the Maritime Organization. International and ISO8217 standard for marine fuels.
  • fuel is meant in the invention a hydrocarbon feedstock used as fuel.
  • oil base is meant in the invention a hydrocarbon feed which, mixed with other bases, constitutes a fuel oil.
  • the properties of these bases are very diverse.
  • the figure 1 represents a process according to the invention with intermediate separation with decompression.
  • the introduction of the feedstock (10) to the outlet of the effluent (42) represents the hydrotreatment zone and this zone is described briefly because it can know many variants known to those skilled in the art.
  • the effluent leaving the at least one guard reactor (Ra, Rb) is optionally remixed with hydrogen arriving via line (65) into an HDM reactor (32) containing a fixed bed of catalyst.
  • an HDM reactor (32) containing a fixed bed of catalyst For readability reasons, a single HDM reactor (32) and a single HDS reactor (38) are shown in the figure, but the HDM and HDS section may include multiple HDM and HDM reactors. 'HDS in series.
  • the effluent from the HDM reactor is withdrawn through line (34) and sent to the first HDS reactor (38) where it passes through a fixed bed of catalyst.
  • the effluent from the hydrotreatment stage is sent via line (42) into a high temperature high pressure separator (HPHT) (44) from which a gaseous fraction (46) and a liquid fraction (48) are recovered. .
  • HPHT high temperature high pressure separator
  • the cutting point is usually between 200 and 400 ° C.
  • the gaseous fraction (46) is sent, generally via an exchanger (not shown) or an air cooler (50) for cooling to a low temperature high pressure separator (HPBT) (52) from which a gaseous fraction (54) containing gases (H2, H2S, NH3, C1-C4 hydrocarbons, ...) and a liquid fraction (56).
  • the gaseous fraction (54) from the low temperature high pressure separator (HPBT) (52) is treated in the hydrogen purification unit (58) from which the hydrogen (60) is recovered for recycling via the compressor (62) and the line (65) to the reactors (32) and / or (38) or via the line (14) to the permutable reactors (Ra, Rb).
  • Gases containing undesirable nitrogen and sulfur compounds are removed from the plant (stream (66)).
  • the liquid fraction (56) from the low temperature high pressure separator (HPBT) (52) is expanded in the device (68) and sent to the fractionation system (70).
  • a medium pressure separator (not shown) after the expander (68) can be installed to recover a gaseous fraction that is sent to the purification unit (58), and a liquid phase that is fed to the fractionation section (58). 70).
  • the liquid fraction (48) from the high temperature high pressure separator (HPHT) (44) is expanded in the device (72) and sent to the fractionation system (70).
  • Fractions (56) and (48) can be sent together, after expansion, to the fractionation (70).
  • the fractionation system (70) comprises an atmospheric distillation system for producing a gaseous effluent (74), at least a so-called light fraction (76) and in particular containing naphtha, kerosene and diesel and an atmospheric residue fraction (78) .
  • Part of the atmospheric residue fraction can be sent via the line (80) into the hydrocracking reactors (98, 102).
  • All or part of the atmospheric residue fraction (78) is sent to a vacuum distillation column (82) to recover a fraction (84) containing the vacuum residue and a vacuum distillate fraction (86) containing vacuum gas oil.
  • the vacuum residue fraction (84), optionally mixed with a portion of the atmospheric residue fraction (80) and / or with a portion of the vacuum distillate fraction (86), is mixed with optionally recycled hydrogen (88). supplemented with makeup hydrogen (90) preheated in the furnace (91). It optionally passes through an oven (92).
  • a co-charge (94) may be introduced.
  • the heavy fraction is then introduced via line (96) into the hydrocracking step at the bottom of the first hybrid bed reactor (98) operating at an upward flow of liquid and gas and containing at least one type hydrocracking catalyst.
  • "Dispersed" and a supported catalyst are a bubbling bed which contains a supported catalyst which has been added a "dispersed" catalyst.
  • the "dispersed" type catalyst is introduced via line (100) upstream of the first hydrocracking reactor (98).
  • the converted effluent (104) from the reactor (98) may be separated from the light fraction (106) in an inter-stage separator (108).
  • This mixture is then injected by the pipe (112) into a second hydrocracking reactor (102) also in a hybrid bed operating at an upward flow of liquid and gas containing at least one "dispersed" hydrocracking catalyst and a catalyst. supported.
  • This "dispersed" type catalyst was injected upstream of the first reactor (98), but a booster upstream of the second reactor (102) could also be achieved via a conduit not shown.
  • the operating conditions, in particular the temperature, in this reactor are chosen to reach the desired conversion level, as previously described.
  • the hydrocracking reactor effluent is fed through line (134) into a high temperature high pressure (HPHT) separator (136) from which a gaseous fraction (138) and a liquid fraction (140) are recovered.
  • HPHT high temperature high pressure
  • the gaseous fraction (138) is generally sent via an exchanger (not shown) or a dry cooler (142) for cooling to a low temperature high pressure separator (HPBT) (144) from which a gaseous fraction (146) containing the gases (H2, H2S, NH3, C1-C4 hydrocarbons ...) and a liquid fraction (148) is recovered.
  • HPBT high pressure separator
  • the gaseous fraction (146) of the low temperature high pressure separator (HPBT) (144) is treated in the hydrogen purification unit (150) from which hydrogen (152) is recovered for recycling via the compressor. (154) and line (156) and / or line (157) to the hydrocracking section.
  • the hydrogen purification unit may consist of an amine wash, a membrane, a PSA type system.
  • the gases containing undesirable nitrogen and sulfur compounds are removed from the installation (stream (158) which may represent several streams, in particular a flow rich in H2S and one or more purges containing light hydrocarbons (C1 and C2) which can (can ) be used in refinery fuel gas).
  • stream (158) which may represent several streams, in particular a flow rich in H2S and one or more purges containing light hydrocarbons (C1 and C2) which can (can ) be used in refinery fuel gas).
  • the liquid fraction (148) of the low temperature high pressure separator (HPBT) (144) is expanded in the device (160) and sent to the fractionation system (172).
  • a medium pressure separator after the expander (160) can be installed to recover a vapor phase that is sent to the purification unit (150) and / or a dedicated medium pressure purification unit (not shown). ), and a liquid phase which is fed to the fractionation section (172).
  • the liquid fraction (140) from the high temperature high pressure separation (HPHT) (136) is expanded in the device (174) and sent to the fractionation system (172).
  • a medium pressure separator (not shown) after the expander (174) can be installed to recover a vapor phase that is sent to the purification unit (150) and / or a dedicated medium pressure purification unit (not shown ), and a liquid phase which is fed to the fractionation section (172).
  • the fractionation system (172) comprises an atmospheric distillation system for producing a gaseous effluent (176), at least a so-called light fraction (178), containing in particular naphtha, kerosene and diesel, and an atmospheric residue fraction (180). ).
  • Part of the atmospheric residue fraction (180) can be withdrawn via line (182) to form a desired fuel oil base. All or part of the atmospheric residue fraction (180) can be sent to a vacuum distillation column (184) to recover a fraction containing the vacuum residue (186) and a vacuum distillate fraction (188) containing vacuum gas oil.
  • the atmospheric residue fraction (182) and / or the vacuum residue fraction (186) may be subjected to a step of treatment and separation of sediments and catalyst residues.
  • a heavy fraction of the atmospheric residue type (182) is optionally preheated in an oven or exchanger (205) so as to reach the temperature necessary for the maturation (conversion of the potential sediments into existing sediments) which takes place in the capacity (207).
  • the purpose of the capacity (207) is to provide a residence time necessary for maturation, it can therefore be a horizontal or vertical flask, a buffer tank, a stirred tank or a reactor piston.
  • the heating function can be integrated with the capacity in the case of a stirred stirred tank according to an embodiment not shown.
  • the capacity (207) may also allow settling so as to evacuate a portion of the solids (208).
  • the maturing stream (209) is then subjected to solid-liquid separation (191) to obtain a sediment-reduced fraction (212) and a sediment-rich fraction (211).
  • a vacuum residue heavy fraction (186) is optionally preheated in an oven or exchanger (213) so as to reach the temperature necessary for the maturation which takes place in the capacity (215).
  • the purpose of the capacity (215) is to provide a residence time necessary for maturation, it can therefore be a horizontal or vertical flask, a buffer tank, a stirred tank or a reactor piston.
  • the heating function can be integrated with the capacity in the case of a stirred stirred tank according to an embodiment not shown.
  • the capacity (215) may also allow settling so as to evacuate a portion of the solids (216).
  • the maturation stream (217) is then subjected to a solid-liquid separation (192) to obtain a sediment-reduced fraction (219) and a sediment-rich fraction (218).
  • the maturation devices (207) and (215) can operate in the presence of a gas, in particular an oxidizing gas.
  • An advantageous mode may consist in operating the step of treating and separating the sediments on the stream recovered at the bottom of a stripping column.
  • this column is less prone to fouling.
  • At least a portion of the streams (188) and / or (212) and / or (219) constitutes one or more desired oil bases, in particular bases for low-sulfur bunker fuels.
  • Some of the streams (188) and / or (212) and / or (219), before or after the optional sediment treatment and separation step, may be recycled via line (190) to step hydrocracking, or upstream of the hydrotreating step (line not shown).
  • the recycling of a vacuum-type gas oil section (188) upstream of the hydrotreatment can make it possible to lower the viscosity of the charge and thus facilitate pumping. Recycling an atmospheric residue type (212) or vacuum residue type (219) cutoff upstream of the hydrotreatment or hydrocracking may make it possible to increase the overall conversion.
  • the figure 2 represents another method according to the invention with intermediate separation without decompression. It will be described below essentially only the differences between the process according to the figure 2 and the method according to figure 1 the hydrotreatment, hydrocracking and separation stages after hydrocracking (and their reference signs) being moreover strictly identical.
  • the effluent treated in the hydrotreatment reactors is sent via line (42) into a high temperature high pressure separator (HPHT) (44) from which a lighter fraction (46) and a residual fraction (48) are recovered. .
  • HPHT high temperature high pressure separator
  • the cutting point between these two fractions is generally between 200 and 450 ° C., and preferably between 250 ° C. and 350 ° C.
  • the residual fraction (48) is sent directly after a possible passage through an oven (92) in the hydrocracking section.
  • the lighter fraction (46) is sent, generally via an exchanger (not shown) or an air cooler (50) for cooling to a low temperature high pressure separator (HPBT) (52) from which a gaseous fraction is recovered (54). containing the gases (H2, H2S, NH3, C1-C4 hydrocarbons ...) and a liquid fraction (56).
  • HPBT high pressure separator
  • the gaseous fraction (54) of the low temperature high pressure separator (HPBT) (52) is treated in the hydrogen purification unit (58) from which is recovered hydrogen (60) for recycling via the compressor (154) and lines (64) and (156) to the hydrotreating section and / or the hydrocracking section.
  • Gases containing undesirable nitrogen, sulfur and oxygen compounds are removed from the plant (stream (66)).
  • a single compressor (154) is used to supply all the reactors requiring hydrogen.
  • the liquid fraction (56) from the low temperature high pressure separator (HPBT) (52) is expanded in the device (68) and sent to the fractionation system (70).
  • the fractionation system (70) comprises an atmospheric distillation system for producing a gaseous effluent (74), at least a so-called light fraction (76) and containing in particular naphtha, kerosene and diesel and an atmospheric residue fraction (195). .
  • Part of the atmospheric residue fraction can be sent, by means of a pump, not represented, via the line (195) in the hydrocracking reactors (98, 102), whereas another part of the atmospheric residue fraction ( 194) can be sent to another process (hydrocracking or FCC or hydrotreatment).
  • a variant not shown but close to the diagram of the figure 2 may consist of not using a fractionation system (70) nor to relax the liquid fraction (56) from the cold separator (52).
  • the liquid fraction (56) is then sent to the hydrocracking section optionally by means of a pump mixed with the heavy fraction (48) issuing from the separator (44).
  • the separation step is with or without decompression, with variants of the hydrocracking section since this hydrocracking section comprises at least one type hydrocracking reactor. hybrid.
  • the feedstock was subjected to a fixed bed hydrotreating step a) including two permutable reactors.
  • the operating conditions are given in Table 1.
  • Table 1 Operating conditions of stage a) of hydrotreatment in fixed bed HDM and HDS catalysts NiCoMo on alumina Temperature (° C) 370 H2 partial pressure (MPa) 15 VVH (h-1, Sm3 / h fresh load / m3 fixed bed catalyst) 0.18 H2 / HC inlet section fixed bed excluding H2 consumption (Nm3 / m3 fresh load) 1000
  • the effluent from the hydrotreating is then subjected to a separation step b) as described in FIG. figure 1 and allowing to recover a gas fraction and a heavy fraction containing a majority of compounds boiling at more than 350 ° C (350 ° C + fraction).
  • the effluents from the hydrocracking step were then subjected to a separation step d) to separate the gases and liquids by means of separators and atmospheric and vacuum distillation columns.
  • Table 3 Yields and Sulfur Content of Hydrocracking Section Effluent (% w / w) (Non-compliant) a) Fixed bed hydrotreatment + b) Separation + c) Hydrocracking 2 bubbling beds (423/431 ° C) (Complies) a) Hydrotreatment fixed bed + b) separation + c) Hydrocracking 2 hybrid bubbling beds (423/431 ° C) products Yield (% wt) S (% wt) Yield (% wt) S (% wt) NH3 0.7 0 0.7 0 H2S 2.7 94.12 2.7 94.12 C1-C4 (gas) 4.0 0 4.1 0 Naphtha (PI - 150 ° C) 9.3 0.02 9.9 0.02 Diesel (150 ° C - 350 ° C) 24.6 0.05 25.5 0.05 Vacuum distillation
  • the operating conditions of the hydrocracking step coupled with the different treatment variants (sediment separation with or without treatment) of the heavy phase resulting from the atmospheric distillation have an impact on the stability of the effluents obtained. This is illustrated by the post-aging sediment concentrations measured in the atmospheric residues (350 ° C + cut) after separation or after the sediment treatment step.
  • Table 4 Summary of process performance according to the prior art and according to the invention (Non compliant) Hydrotreatment fixed bed + separation + Hydrocracking 2 bubbling beds (423/431 ° C) (Complies) Hydrotreatment fixed bed + separation + Hydrocracking 2 hybrid bubbling beds (423/431 ° C) H2 consumption (% w / w) 1.8 2.0 Hydrodesulfurization rate (%) 91 91 Conversion rate (%) 66 69 Treatment No No Yes Separation of sediments Yes Yes Yes Sediment content after aging (IP390) in the 350 ° C + cut from sediment separation 0.4 0.5 ⁇ 0.1
  • the sediment treatment step e) involving maturation prior to the physical separation of the sediments is essential to form all potential sediments and thus allow their effective separation. Without treatment, beyond a certain level of conversion that leads to many potential sediments, the sediment separation step is not efficient enough for the sediment after aging (IP390) is less than 0.1% by weight, which is the maximum level required for residual type bunkers.
  • the sediment treatment stage e may be optional, the sediment content will then be greater than 0.1% by weight.
  • this fuel oil having a sulfur content of 0.40% by weight, and having a viscosity of 375 cSt at 50 ° C. In addition, its sediment content after aging is less than 0.1% by weight. In view of these analyzes, this fuel oil is particularly suitable for forming a residual type of fuel oil related to the RMG 380 grade as recommended by the IMO outside the ZESCs by 2020-2025.
  • a second mixture consisting of 85% by weight of a fraction from the diesel cut and 15% by weight of a fraction derived from the vacuum distillate cut.
  • the mixture has a sulfur content of 0.08% and a viscosity of 6 cSt at 40 ° C.
  • This mixture thus constitutes a marine fuel of the distillate type ("marine gas oil” or "marine diesel” in the English terminology) which can be likened to the DMB grade (whose viscosity specification is between 2 cSt and 11 cSt at 40 ° C) for example.
EP15306619.6A 2014-11-04 2015-10-13 Verfahren zur herstellung von brennstoffen vom typ schweröl aus einer schweren kohlenwasserstoffcharge unter verwendung einer trennung zwischen der hydrotreating- und der hydrocracken-phase Active EP3026097B1 (de)

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US20080177124A1 (en) 2006-12-21 2008-07-24 Magalie Roy-Auberger Process for the hydroconversion in a slurry of heavy hydrocarbonaceous feedstocks in the presence of a dispersed phase and an alumina-based oxide
FR2940143A1 (fr) 2008-12-18 2010-06-25 Inst Francais Du Petrole Catalyseurs d'hydrodemetallation et d'hydrodesulfuration et mise en oeuvre dans un procede d'enchainement en formulation unique
FR2957607A1 (fr) 2010-03-18 2011-09-23 Inst Francais Du Petrole Procede et produits de conversion de charbon comprenant deux etapes de liquefaction directe en lit bouillonnant et une etape d'hydrocraquage en lit fixe
WO2014096704A1 (fr) * 2012-12-20 2014-06-26 IFP Energies Nouvelles Procédé avec separation de traitement de charges petrolieres pour la production de fiouls a basse teneur en soufre

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
FR3067037A1 (fr) * 2017-06-02 2018-12-07 IFP Energies Nouvelles Procede de conversion comprenant un hydrotraitement en lit fixe, une separation d'un distillat sous vide, une etape d'hydrocraquage de distillat sous vide
FR3067036A1 (fr) * 2017-06-02 2018-12-07 IFP Energies Nouvelles Procede de conversion comprenant un hydrotraitement en lit fixe, une separation d'un distillat sous vide, une etape d'hydrotraitement de distillat sous vide
FR3072684A1 (fr) * 2017-10-25 2019-04-26 IFP Energies Nouvelles Procede d'hydrotraitement de charge hydrocarbonee

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EP3026097B1 (de) 2017-12-13
KR20160052404A (ko) 2016-05-12
US20160122666A1 (en) 2016-05-05
PL3026097T3 (pl) 2018-07-31
KR102447844B1 (ko) 2022-09-26
ES2659797T3 (es) 2018-03-19
CN105567315A (zh) 2016-05-11
US11421166B2 (en) 2022-08-23
FR3027912A1 (fr) 2016-05-06
CN105567315B (zh) 2019-06-04
FR3027912B1 (fr) 2018-04-27

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