EP3303523B1 - Procede de conversion de charges comprenant une etape d'hydrotraitement, une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls - Google Patents

Procede de conversion de charges comprenant une etape d'hydrotraitement, une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls Download PDF

Info

Publication number
EP3303523B1
EP3303523B1 EP16717176.8A EP16717176A EP3303523B1 EP 3303523 B1 EP3303523 B1 EP 3303523B1 EP 16717176 A EP16717176 A EP 16717176A EP 3303523 B1 EP3303523 B1 EP 3303523B1
Authority
EP
European Patent Office
Prior art keywords
fraction
separation
hydrotreatment
hydrocracking
process according
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Active
Application number
EP16717176.8A
Other languages
German (de)
English (en)
French (fr)
Other versions
EP3303523A1 (fr
Inventor
Wilfried Weiss
Isabelle MERDRIGNAC
Jérémie BARBIER
Ann Forret
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
IFP Energies Nouvelles IFPEN
Original Assignee
IFP Energies Nouvelles IFPEN
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by IFP Energies Nouvelles IFPEN filed Critical IFP Energies Nouvelles IFPEN
Publication of EP3303523A1 publication Critical patent/EP3303523A1/fr
Application granted granted Critical
Publication of EP3303523B1 publication Critical patent/EP3303523B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Images

Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • 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
    • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
    • C10G31/06—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by heating, cooling, or pressure treatment
    • 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
    • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
    • C10G31/09—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by filtration
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
    • C10G47/24—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles
    • 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
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1059—Gasoil having a boiling range of about 330 - 427 °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
    • C10G2300/20—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
    • 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

Definitions

  • the present invention relates to the refining and the conversion of heavy hydrocarbon fractions containing, inter alia, sulfur-containing impurities. It relates more particularly to a process for converting heavy petroleum feeds of the atmospheric residue type and / or vacuum residue for the production of heavy fractions that can be used as fuel bases, in particular bunker oil bases, with a low sediment content.
  • the process according to the invention also makes it possible to produce atmospheric distillates (naphtha, kerosene and diesel), vacuum distillates and light gases (C1 to C4).
  • the quality requirements for marine fuels are described in ISO 8217.
  • the sulfur specification now focuses on SO x emissions (Annex VI of the MARPOL Convention of the International Maritime Organization) and results in a recommendation for sulfur content not exceeding 0.5% by weight outside the Sulfur Emission Control Areas (ZCES or Emissions Control Areas / ECA) by 2020-2025 and less than or equal to 0,1% in ZCES.
  • Another very restrictive recommendation is the sediment content after aging according to ISO 10307-2 (also known as IP390) which must be less than or equal to 0.1%.
  • the sediment content after aging is a measurement carried out according to the method described in the ISO 10307-2 standard (also known to those skilled in the art under the name of IP390). In the rest of the text will therefore read "sediment content after aging", the sediment content measured according to the ISO 10307-2 method.
  • the reference to IP390 will also indicate that the measurement of the sediment content after aging is performed according to the ISO 10307-2 method.
  • the sediment content according to ISO 10307-1 (also known as IP375) is different from the sediment content after aging according to ISO 10307-2 (also known as IP390).
  • the sediment content after aging according to ISO 10307-2 is a much more stringent specification and corresponds to the specification for bunker fuels.
  • a ship may therefore use a sulfur-containing fuel oil if the ship is equipped with a flue gas treatment system that reduces emissions of sulfur oxides.
  • FR 2764300 and EP 0665282 describe a process for the hydrotreatment of heavy oils with the aim of prolonging the life of the reactors.
  • the process described in FR 2764300 describes a process for obtaining fuels (gasoline and diesel) having in particular a low sulfur content. The fillers treated in this process do not contain asphaltenes.
  • WO 2014/096704 discloses a process comprising a final sediment separation step to obtain a fraction having a sediment content of less than or equal to 0.1%.
  • 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. These processes, although known to be suitable for heavy loads loaded with impurities, however, produce hydrocarbon fractions comprising catalyst fines and sediments which must be removed to satisfy a product quality such as bunker fuel oil.
  • the sediments may be precipitated asphaltenes. Initially in the charge, the conversion conditions and in particular the temperature make them undergo reactions (dealkylation, polycondensation ...) leading to their precipitation. In addition to the existing sediments in the heavy cut at the end of the process (measured according to ISO 10307-1 also known as IP375), there are also sediment conditions according to the sediment conversion conditions, which are potential sediments that only appear after physical, chemical and / or thermal treatment. All sediments including potential sediments are measured according to ISO 10307-1 also known as IP390.These phenomena generally occur during the implementation of severe conditions giving rise to high conversion rates, for example greater than 40 or 50% or more, depending on the nature of the load.
  • One of the objectives of the present invention is to propose a process for the conversion of heavy petroleum feedstocks for the production of fuel oils and oil bases, in particular bunker oil and bunker oil bases, with a low sediment content after aging (measured according to the method ISO 10307-2) less than or equal to 0.1% by weight.
  • 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 figure 1 illustrates a schematic view of the process according to the invention showing a hydrotreating zone, a separation zone, a hydrocracking zone, another separation zone, a precipitation zone, a physical separation zone of the sediments and a zone recovery of the fraction of interest.
  • the feedstock treated in the process according to the invention is advantageously a hydrocarbon feed having an initial boiling point of at least 340 ° C. and a final boiling point of at least 440 ° C.
  • its initial boiling temperature is at least 350 ° C, preferably at least 375 ° C
  • its final boiling temperature is at least 450 ° C, preferably at least 450 ° C. 460 ° C, more preferably at least 500 ° C, and even more preferably at least 600 ° C.
  • the hydrocarbon feedstock according to the invention may be chosen from atmospheric residues, vacuum residues resulting from direct distillation, crude oils, crude head oils, deasphalting resins, asphalts or deasphalting pitches, process residues. conversion products, aromatic extracts from lubricant base production lines, oil sands or derivatives thereof, oil shales or their derivatives, source rock oils or their derivatives, whether alone or in combination.
  • the charges that are treated are atmospheric residues or residues under vacuum, or mixtures of these residues.
  • the filler may contain at least 1% of C7 asphaltenes and at least 5 ppm of metals, preferably at least 2% of C7 asphaltenes and at least 25 ppm of metals.
  • the hydrocarbon feedstock treated in the process may contain, among other things, sulfur-containing impurities.
  • the sulfur content may be at least 0.1% by weight, at least 0.5% by weight, preferably at least 1% by weight, more preferably at least 4% by weight, still more preferably at least 5% by weight.
  • This co-charge may be a hydrocarbon fraction or a lighter hydrocarbon fraction mixture, which may preferably be chosen from the products resulting from a fluid catalytic cracking (FCC) process according to the English terminology. Saxon), 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, a FCC residue, a gas oil fraction, especially a fraction obtained by atmospheric distillation or under vacuum, such as vacuum gas oil, or may come from another refining process.
  • FCC fluid catalytic cracking
  • the co-charge may also advantageously be one or more cuts resulting 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 process according to the invention aims to produce a liquid hydrocarbon fraction having a sediment content after aging less than or equal to 0.1% by weight.
  • the process according to the invention comprises a first step a) of fixed bed hydrotreating, optionally a step b) of separating the effluent from step a) of hydrotreatment into a light fraction and a heavy fraction, followed by a step c) bubbling bed hydrocracking of at least a portion of the effluent from step a) or at least a portion of the heavy fraction resulting from step b), a step d) of separating the effluent from step c) to obtain at least one gaseous fraction and at least one heavy liquid fraction, a step e) of precipitation of sediments of the heavy liquid fraction resulting from step d), a step f) of physical separation of the sediments of the heavy liquid fraction resulting from step e) and finally a step g) of recovery of a liquid hydrocarbon fraction having a sediment content after aging less than or equal to 0.1% by weight.
  • the objective of hydrotreating is both to refine, that is to say to significantly reduce the content of metals, sulfur and other impurities, while improving the hydrogen to carbon ratio (H / C) and while transforming the hydrocarbon feed more or less partially into lighter cuts.
  • the effluent obtained in the fixed bed hydrotreating step a) can then be sent to the bubbling bed hydrocracking step c) either directly or after being subjected to a light fraction separation step.
  • Step c) allows a partial conversion of the feedstock to produce an effluent comprising in particular catalyst fines and sediments which must be removed to satisfy a product quality such as bunker oil.
  • the method according to the invention is characterized in that it comprises a precipitation step e) and a step f) of physical separation of the sediments carried out under conditions making it possible to improve the separation efficiency of the sediments and thus to obtain fuel oils or fuel bases having a sediment content after aging less than or equal to 0.1% by weight.
  • the filler according to the invention is subjected according to the process of the present invention to a fixed bed hydrotreating step a) in which the filler and hydrogen are contacted on a hydrotreatment catalyst.
  • Hydrotreatment commonly known as HDT
  • HDT Hydrotreatment
  • hydrodesulfurization reactions commonly referred to as HDS
  • hydrodenitrogenation reactions commonly referred to as HDN
  • hydrodemetallation reactions commonly referred to as HDM
  • the hydrotreatment stage a) comprises a hydrodemetallation first stage (1) (HDM) carried out in one or more hydrodemetallation zones in fixed beds and a second hydrodesulphurization second stage (a2) (HDS). performed in one or more hydrodesulfurization zones in fixed beds.
  • first hydrodemetallation step a1) the feedstock and hydrogen are contacted on a hydrodemetallization catalyst, under hydrodemetallation conditions, and then during said second hydrodesulfurization step a2), the effluent of the first hydrodemetallation step a1) is brought into contact with a hydrodesulfurization catalyst, under hydrodesulfurization conditions.
  • This process known as HYVAHL-F TM, is for example described in the patent US 5417846 .
  • permutable reactors when the feedstock contains more than 100 ppm or more than 200 ppm of metals and / or when the feedstock comprises impurities such as iron derivatives, it may be advantageous to use permutable reactors ("PRS" technology, for "Permutable Reactor System” according to the English terminology) as described in the patent FR2681871 .
  • PRS permutable reactors
  • These permutable reactors are generally fixed beds located upstream of the fixed bed hydrodemetallation section.
  • hydrodemetallization step hydrodemetallation reactions are carried out but also a part of the other hydrotreatment reactions and in particular hydrodesulfurization reactions.
  • hydrodesulphurization step hydrodesulphurization reactions are carried out, but also part of the other hydrotreatment reactions and in particular hydrodemetallation reactions.
  • the hydrodemetallization step begins where the hydrotreatment step begins, where the metal concentration is maximum.
  • the man of The business understands that the hydrodesulfurization step ends where the hydrotreatment step ends, where sulfur removal is the most difficult. Between the hydrodemetallation step and the hydrodesulfurization step, the skilled person sometimes defines a transition zone in which all types of hydrotreatment reaction occur.
  • the hydrotreating step a) according to the invention is carried out under hydrotreatment conditions. It can 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 5 MPa and 35 MPa, preferably between 11 MPa and 20 ° C. MPa.
  • the temperature is usually adjusted according to the desired level of hydrotreatment and the duration of the targeted treatment.
  • the space velocity of the hydrocarbon feedstock commonly referred to as VVH, which is defined as the volumetric flow rate of the feedstock divided by the total volume of the catalyst, can be in a range of 0.1 h -1.
  • the amount of hydrogen mixed with the feedstock may be between 100 and 5000 normal cubic meters (Nm3) per cubic meter (m3) of liquid feedstock, preferably between 200 Nm3 / m3 and 2000 Nm3 / m3, and more preferably between 300 Nm3 / m3 and 1500 Nm3 / m3.
  • Step a) of hydrotreatment can be carried out industrially in one or more liquid downflow reactors.
  • the hydrotreatment catalysts used are preferably known catalysts. They may be granular catalysts comprising, on a support, at least one metal or metal compound having a hydro-dehydrogenating 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. For example, it is possible to use 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.
  • nickel oxide NiO nickel oxide
  • molybdenum preferably from 5% to 20% by weight of molybdenum (expressed as molybdenum oxide MoO3) 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.
  • this support may contain other doping compounds, in particular oxides selected from the group consisting of boron oxide, zirconia, ceria, titanium oxide, phosphoric anhydride and mixture of these oxides. Most often an alumina support is used and very often a support of alumina doped with phosphorus and possibly boron.
  • the alumina used may be a gamma ( ⁇ ) or ⁇ (eta) alumina. This catalyst is most often in the form of extrudates.
  • the total content of metal oxides of groups VIB and VIII may be from 5% to 40% by weight and in general from 7% to 30% by weight and the weight ratio expressed as metal oxide between metal (or metals) of group VIB on metal (or metals) of group VIII is generally between 20 and 1, and most often between 10 and 2.
  • Catalysts that can be used in the hydrodemetallation 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 hydrodesulfurization 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.
  • step separating the effluent from step a) of hydrotreatment is optional.
  • step separating the effluent from step a) of hydrotreatment is not implemented, at least part of the effluent from step a) of hydrotreatment is introduced in the section allowing the implementation of step c) bubbling bed hydrocracking without changing chemical composition and without significant pressure loss.
  • "Significant loss of pressure” means a loss of pressure caused by a valve or expansion turbine, which could be estimated at a pressure loss of more than 10% of the total pressure. Those skilled in the art generally use these pressure losses or relaxations during the separation steps.
  • step a) of hydrotreatment When the separation step is carried out on the effluent from step a) of hydrotreatment, this is optionally supplemented by further 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 separation step b) 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, 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 firstly comprise a high temperature high pressure separator (HPHT), and possibly a low temperature high pressure separator (HPBT), followed optionally afterwards.
  • HPHT high temperature high pressure separator
  • HPBT low temperature high pressure separator
  • the effluent of step a) can be sent to a fractionation section, generally in an HPHT separator making it possible to obtain a light fraction and a heavy fraction containing predominantly boiling compounds at least 350 ° C.
  • the separation is preferably not made according to a precise cutting point, it is rather like a separation of the instantaneous type (or flash according to the English terminology).
  • the cutting point of the separation is advantageously between 200 and 400 ° C.
  • said heavy fraction can then 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 are advantageously sent to the hydrocracking step c).
  • Part of the vacuum residue fraction and / or the atmospheric residue fraction can (also) be used directly as a fuel oil base, especially as a base of low sulfur fuel oil.
  • Part of the vacuum residue fraction and / or the atmospheric residue fraction can (also) be sent to another conversion process, in particular a fluidized catalytic cracking process.
  • the effluent from step a) hydrotreatment undergoes a step b) separation without decompression.
  • the effluent of the hydrotreatment step a) is sent to a fractionation section, generally in an HPHT separator, having a cutting point between 200 and 450 ° 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 separation of the instantaneous type (or flash according to the English terminology).
  • the heavy fraction can then be directly sent to the hydrocracking step c).
  • 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 last fraction possibly being at least part sent in step c) 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.
  • 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. Intermediate fractionation without decompression being simpler than fractionation with decompression, the investment cost is therefore advantageously reduced.
  • the gaseous fractions resulting from the separation step preferably undergo a purification treatment to recover the hydrogen and recycle it to the hydrotreating and / or hydrocracking reactors, or even in the precipitation stage.
  • the presence of the separation step between the hydrotreatment step a) and the hydrocracking step c) advantageously makes it possible to have two independent hydrogen circuits, one connected to the hydrotreatment, the hydrocracking, and which, if necessary, can be connected to each other.
  • the addition of hydrogen can be done at the hydrotreatment section or at the level of 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 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 which are well known in the art. 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 with the required specifications which may relate to the sulfur content, the point of smoke, the octane number, cetane, and others.
  • the light fraction obtained after step b) may be used at least in part to form the distillate cut according to the invention used in step e) sediment precipitation, or to be mixed with said cut distillate according to the invention.
  • Part of the heavy fraction from the separation step b) can be used to form the distillate cut according to the invention used in the sediment precipitation step e).
  • At least a portion of the effluent from step a) of hydrotreatment or at least a portion of the heavy fraction from step b) is sent according to the process of the present invention in a step c) of hydrocracking which is carried out in at least one reactor, advantageously two reactors, containing at least one catalyst supported in a bubbling bed.
  • Said reactor can operate at an upward flow of liquid and gas.
  • the main objective of hydrocracking is to convert the heavy hydrocarbon feedstock into lighter cuts while partially refining it.
  • part of the initial hydrocarbon feedstock can be injected directly into the bubbling bed hydrocracking section c), mixed with the effluent of the hydrotreatment section a) in fixed bed or the heavy fraction from step b), without this portion of the hydrocarbon feedstock being treated in the hydrotreatment section a) in a fixed bed.
  • This embodiment can be likened to a partial short circuit of the hydrotreatment section a) in a fixed bed.
  • a co-charge may be introduced at the inlet of the hydrocracking section c) in a bubbling bed with the effluent of the hydrotreatment section a) in fixed bed or the heavy fraction resulting from step b) .
  • This co-charge can be chosen from atmospheric residues, vacuum residues from direct distillation, deasphalted oils, aromatic extracts from lubricant base production lines, hydrocarbon fractions or a mixture of hydrocarbon fractions that can be chosen.
  • this co-charge may be partially or totally injected into one of the reactors downstream of the first reactor.
  • the hydrogen necessary for the hydrocracking reaction may already be present in sufficient quantity in the effluent resulting from the hydrotreatment stage a) injected at the inlet of the hydrocracking section c) in a bubbling bed. However, it is preferable to provide an additional supply of hydrogen at the inlet of the hydrocracking section c). In the case where the hydrocracking section has several bubbling bed reactors, hydrogen can be injected at the inlet of each reactor.
  • the injected hydrogen may be a make-up stream and / or a recycle stream.
  • Bubbling bed technology is well known to those skilled in the art. Only the main operating conditions will be described here. Bubbling bed technologies conventionally use supported catalysts in the form of extrudates whose diameter is generally of the order of 1 millimeter or less.
  • the catalysts remain inside the reactors and are not evacuated with the products, except during the makeup and catalyst withdrawal phases necessary to maintain the catalytic activity.
  • the temperature levels can be high in order to obtain high conversions while minimizing the amounts of catalysts used.
  • the catalytic activity can be kept constant by replacing the catalyst in line. It is therefore not necessary to stop the unit to change the spent catalyst, nor to increase the reaction temperatures along the cycle to compensate for the deactivation.
  • working at constant operating conditions advantageously provides consistent yields and product qualities along the cycle.
  • the catalyst is kept agitated by a large recycling of liquid, the pressure drop on the reactor remains low and constant. Because of the attrition of the catalysts in the reactors, the products leaving the reactors may contain fine particles of catalyst.
  • the conditions of the ebullated bed hydrocracking step c) may be conventional bubbling bed hydrocracking conditions of a hydrocarbon feedstock. It can be operated under an absolute pressure of between 2.5 MPa and 35 MPa, preferably between 5 MPa and 25 MPa, more preferably between 6 MPa and 20 MPa, and even more preferably between 11 MPa and 20 MPa at a temperature between 330 ° C and 550 ° C, preferably between 350 ° C and 500 ° C.
  • the space velocity (VVH) and the partial pressure of hydrogen are parameters that are fixed according to the characteristics of the product to be processed and the desired conversion.
  • the VVH which is defined as being the volumetric flow rate of the charge divided by the total volume of the reactor is generally in a range from 0.1 h -1 to 10 h -1 , preferably from 0.1 h -1 to 5 h -1. h -1 and more preferably from 0.1 h -1 to 1 h -1 .
  • the amount of hydrogen mixed with the feedstock is usually from 50 to 5000 normal cubic meters (Nm3) per cubic meter (m3) of liquid feed, most often from 100 Nm3 / m3 to 1500 Nm3 / m3 and preferably 200 Nm3 / m3 at 1200 Nm3 / m3.
  • a conventional granular hydrocracking catalyst 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.
  • 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.
  • B2O3 boron trioxide When B2O3 boron trioxide is present, its concentration is usually less than 10% by weight.
  • the alumina used is usually ⁇ (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 continuous way or almost continuous.
  • 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. This withdrawal and this replacement are performed using devices allowing the continuous operation of this hydrocracking step.
  • 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 (b).
  • the hydrocracking step c) according to the process of the invention can be carried out under the conditions of the H-OIL® process as described, for example, in the patent US 6270654 .
  • the bubbling bed hydrocracking can be carried out in a single reactor or in several reactors, preferably two, arranged in series.
  • the fact of using at least two bubbling bed reactors in series makes it possible to obtain products of better quality and with better performance.
  • the hydrocracking into two reactors makes it possible to have improved operability in terms of the flexibility of the operating conditions and of the catalytic system.
  • the temperature of the second bubbling bed reactor is at least 5 ° C higher than that of the first bubbling bed reactor.
  • the pressure of the second reactor may be 0.1 MPa to 1 MPa lower than for the first reactor to allow the flow of at least a portion of the effluent from the first step without pumping is necessary.
  • the different operating conditions in terms of temperature in the two hydrocracking reactors are selected to be able to control the hydrogenation and the conversion of the feedstock into the desired products in each reactor.
  • the effluent obtained at the end of the first substep c1) can optionally be subjected to a separation step of the light fraction and the heavy fraction, and at least a portion, preferably all, of said heavy fraction can be treated in the second hydrocracking sub-step c2).
  • This separation is advantageously made in an inter-floor separator, as described for example in the patent US 6270654 , and in particular makes it possible to avoid overcracking of the light fraction in the second hydrocracking reactor.
  • the hydrocracking stage can also be done with several reactors in parallel (generally two) in the case of large capacity.
  • the hydrocracking step may thus comprise several stages in series, possibly separated from an inter-stage separator, each stage being constituted by one or more reactors in parallel.
  • the process according to the invention may furthermore comprise a step d) of separation which makes it possible to obtain at least one gaseous fraction and at least one heavy liquid 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 effluent by means of separating devices that are 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 steam or hydrogen stripping means and 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 heavy liquid fraction.
  • These separators may for example be high temperature high pressure separators (HPHT) and / or high temperature low 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 type system, or a plurality of such means arranged in series.
  • the purified hydrogen can then advantageously be recycled in the process according to the invention, after a possible recompression.
  • the hydrogen may be introduced at the inlet of the hydrotreatment step a) and / or at different locations during the hydrotreatment step a) and / or at the inlet of the hydrocracking step c) and / or at different locations during step c) of hydrocracking, or even in the precipitation step.
  • 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 (s) obtained after separation is (are) fractionated (s) by atmospheric distillation in 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 separation step d) comprises, first of all, an 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, followed by vacuum distillation in which the atmospheric residue fraction obtained after atmospheric distillation is fractionated by vacuum distillation into at least one vacuum distillate fraction and at minus a fraction residue under vacuum.
  • the vacuum distillate fraction typically contains vacuum gas oil fractions.
  • At least a portion of the vacuum residue fraction can be recycled to the hydrocracking step c).
  • a portion of heavy liquid fraction from step d) of separation can be used to form the distillate cut according to the invention used in step e) sediment precipitation.
  • the heavy liquid fraction obtained at the end of the separation step d) contains organic sediments which result from hydrotreatment and hydrocracking conditions and catalyst residues.
  • Part of the sediments consist of asphaltenes precipitated under hydrotreatment and hydrocracking conditions and are analyzed as existing sediments (IP375).
  • IP375 existing sediments
  • IP390 sediments after aging
  • the process according to the invention comprises a step precipitation to improve the sediment separation efficiency and thus to obtain stable oil or fuel bases, that is to say a sediment content after aging less than or equal to 0.1% by weight.
  • the precipitation step according to the process of the invention comprises bringing the heavy liquid fraction coming from the separation step d) into contact with a distillate cut of which at least 20% by weight has a higher boiling point or equal to 100 ° C, preferably greater than or equal to 120 ° C, more preferably greater than or equal to 150 ° C.
  • the distillate pool is characterized in that it comprises at least 25% by weight having a boiling point greater than or equal to 100 ° C., preferably greater than or equal to 120 ° C. more preferably greater than or equal to 150 ° C.
  • At least 5% by weight or even 10% by weight of the distillate cut according to the invention has a boiling point of at least 252 ° C.
  • At least 5 wt.% Or even 10 wt.% Of the distillate cut according to the invention has a boiling point of at least 255 ° C.
  • Said distillate cut may partly or even entirely derive from steps b) and / or d) separation of the invention or another refining process or another chemical process.
  • distillate cut according to the invention also has the advantage of avoiding the majority use of high value added cuts such as petrochemical cuts, naphtha ...
  • the distillate cut according to the invention advantageously comprises hydrocarbons having more than 12 carbon atoms, preferably hydrocarbons having more than 13 carbon atoms, more preferably hydrocarbons having between 13 and 40 carbon atoms.
  • the distillate cut may be used in a mixture with a naphtha-type cut and / or a vacuum-type gas oil cut and / or vacuum residue.
  • Said distillate fraction may be used as a mixture with the light fraction obtained after step b), the heavy fraction resulting from step b), the heavy liquid fraction resulting from step d), these fractions can be taken alone or mixed.
  • the distillate cut according to the invention is mixed with another cut, a light fraction and / or a heavy fraction as indicated above, the proportions are chosen so that the resulting mixture respects the characteristics of the the distillate cut according to the invention.
  • the precipitation step e) according to the invention makes it possible to obtain all the existing and potential sediments (by converting the potential sediments into existing sediments) so as to separate them effectively and thus reach the sediment content after aging (measured according to the method ISO 10307-2) 0.1% maximum weight.
  • the precipitation step e) according to the invention is advantageously carried out for a residence time of less than 500 minutes, preferably less than 300 minutes, more preferably less than 60 minutes, at a temperature between 25 and 350 ° C, preferably between 50 and 350 ° C, preferably between 65 and 300 ° C and more preferably between 80 and 250 ° C.
  • the pressure of the precipitation step is advantageously less than 20 MPa, preferably less than 10 MPa, more preferably less than 3 MPa and even more preferably less than 1.5 MPa.
  • the mass ratio between the distillate fraction according to the invention and the heavy fraction obtained at the end of the separation step d) is between 0.01 and 100, preferably between 0.05 and 10, more preferably between 0.1. and 5, and even more preferably between 0.1 and 2.
  • the distillate cut according to the invention can also partly come from step g) of recovering the liquid hydrocarbon fraction.
  • the precipitation step e) can be carried out using several equipment.
  • a static mixer or a stirred tank may optionally be used so as to promote effective contact between the heavy liquid fraction obtained at the end of the separation step d) and the distillate cut according to the invention.
  • One or more exchangers may be used before or after mixing the heavy liquid fraction obtained at the end of step d) and the distillate cut according to the invention so as to reach the desired temperature.
  • One or more capacity (s) can (be) used in series or in parallel such as a horizontal or vertical balloon, possibly with a decantation function to remove some of the heavier solids.
  • a stirred tank possibly equipped with a jacket for temperature regulation can also be used. This tank can be provided with a bottom withdrawal to remove some of the heavier solids.
  • the precipitation step e) is carried out in the presence of an inert gas and / or an oxidizing gas and / or an oxidizing liquid and / or hydrogen, preferably derived from the process of the invention. invention, especially separation steps b) and / or c).
  • Step e) sediment precipitation can be carried out in the presence of an inert gas such as dinitrogen, or in the presence of an oxidizing gas such as oxygen, ozone or nitrogen oxides, or in the presence a mixture containing an inert gas and an oxidizing gas such as air or air depleted by nitrogen.
  • an oxidizing gas has the advantage of accelerating the precipitation process.
  • Step e) sediment precipitation can be carried out in the presence of an oxidizing liquid to accelerate the precipitation process.
  • oxidizing liquid means an oxygenated compound, for example a peroxide such as hydrogen peroxide, or an inorganic oxidizing solution such as a solution of potassium permanganate or a mineral acid such as sulfuric acid.
  • the oxidizing liquid is then mixed with the heavy liquid fraction from step d) of separation and the distillate cut according to the invention during the implementation of step e) sediment precipitation.
  • step e a hydrocarbon fraction with an enriched content of existing sediments mixed at least partly with the distillate cut according to the invention is obtained.
  • This mixture is sent to step f) of physical separation of the sediments.
  • the method according to the invention further comprises a step f) of physical separation of sediments and catalyst fines to obtain a liquid hydrocarbon fraction.
  • the heavy liquid fraction obtained at the end of the precipitation step e) contains precipitated asphaltene-type organic sediments which result from the hydrocracking conditions and precipitation conditions according to the invention.
  • This heavy liquid fraction may also contain catalyst fines resulting from the attrition of extruded type catalysts in the implementation of hydrocracking reactor.
  • a separation of sediments and catalyst residues by means of a physical separation means selected from a filter, a membrane of separation, a bed of organic or inorganic type filter solids, electrostatic precipitation, electrostatic filter, centrifuge system, decantation, centrifugal decanter, auger withdrawal, or physical extraction.
  • a combination, in series and / or in parallel and can function sequentially, of several separation means of the same type or different type can be used during this step f) separation of sediments and catalyst residues.
  • One of these solid-liquid separation techniques may require the periodic use of a light rinsing fraction, resulting from the process or not, allowing for example the cleaning of a filter and the evacuation of sediments.
  • a liquid hydrocarbon fraction (with a sediment content after aging of less than or equal to 0.1% by weight) is obtained, comprising a portion of the distillate cut according to US Pat. invention introduced in step e).
  • the mixture resulting from stage f) is advantageously introduced into a stage g) of recovery of the liquid hydrocarbon fraction having a sediment content after aging less than or equal to 0.1% by weight consisting of separating the liquid hydrocarbon fraction from step f) of the distillate cut introduced during step e).
  • Step g) is a separation step similar to steps b) and d) of separation.
  • Step g) can be implemented by means of separator balloon type equipment and / or distillation columns so as to separate on the one hand at least part of the distillate cut introduced during step e) and on the other hand the liquid hydrocarbon fraction having a sediment content after aging less than or equal to 0.1% by weight.
  • a portion of the distillate cut separated from step g) is recycled to the precipitation step e).
  • Said liquid hydrocarbon fraction may advantageously be used as a base of fuel oil or as fuel oil, especially as a base of bunker oil or as bunker oil, having a sediment content after aging less than 0.1% by weight.
  • said liquid hydrocarbon fraction is mixed with one or more fluxing bases selected from the group consisting of catalytic cracking light cutting oils, catalytic cracking heavy cutting oils, catalytic cracking residue, a kerosene, a gas oil, a vacuum distillate and / or a decanted oil, the distillate cut according to the invention.
  • part of the distillate cut according to the invention can be left in the sediment-reduced liquid hydrocarbon fraction so that the viscosity of the mixture is directly that of a desired grade of fuel oil. for example 180 or 380 cSt at 50 ° C.
  • the liquid hydrocarbon fractions according to the invention may, at least in part, advantageously be used as fuel oil bases or as fuel oil, in particular as a base of bunker oil or as bunker oil with a sediment content after aging (measured according to the ISO method 10307-2) less than or equal to 0.1% by weight.
  • fuel oil is meant in the invention a hydrocarbon fraction that can be used as a fuel.
  • oil base is meant in the invention a hydrocarbon fraction which, mixed with other bases, is a fuel oil.
  • the liquid hydrocarbon fractions from step f) or g) can be mixed with one or more fluxing bases selected from the group consisting of light catalytic cracking oils, heavy cutting oils and catalytic cracking, the residue of a catalytic cracking, a kerosene, a gas oil, a vacuum distillate and / or a decanted oil, the distillate cut according to the invention.
  • one or more fluxing bases selected from the group consisting of light catalytic cracking oils, heavy cutting oils and catalytic cracking, the residue of a catalytic cracking, a kerosene, a gas oil, a vacuum distillate and / or a decanted oil, the distillate cut according to the invention.
  • kerosene, gas oil and / or vacuum distillate produced in the process of the invention will be used.
  • a portion of the fluxes may be introduced as part or all of the distillate cut according to the invention.
  • the figure 1 schematically describes an example of implementation of the invention without limiting the scope.
  • the hydrocarbon feedstock (1) and hydrogen (2) are contacted in a fixed bed hydrotreating zone (step a).
  • the effluent (3) from the hydrotreatment zone is sent to a separation zone (optional separation step b)) making it possible to obtain at least one light hydrocarbon fraction (4) and a heavy fraction (5). containing compounds boiling at not less than 350 ° C.
  • the effluent (3) from the hydrotreatment zone, in particular in the absence of the optional step b), or a heavy fraction (5) from the separation zone b) (when the step b) is placed implemented) is sent to the bubbling bed hydrocracking zone c).
  • the effluent (6) from the hydrocracking zone c) is sent to a separation zone d) to obtain at least one gaseous fraction (7) and at least one heavy liquid fraction (8).
  • This liquid fraction (8) is brought into contact with the distillate cup (9) according to the invention during a step e) of precipitation in the zone e) of precipitation.
  • the effluent (10) consisting of a heavy fraction and sediment is treated in a physical separation zone f) for removing a fraction comprising sediments (12) and recovering a reduced-content liquid hydrocarbon fraction (11). in sediments.
  • the liquid hydrocarbon fraction (11) is then treated in a zone g) of recovery on the one hand of the liquid hydrocarbon fraction (14) having a sediment content after aging less than or equal to 0.1% by weight, and secondly a fraction (13) containing at least a portion of the distillate cut introduced during step e) into the zone e).
  • the separation zone b) between the fixed bed hydrotreatment zone a) and the bubbling bed hydrocracking zone c) is carried out with decompression.
  • the separation zone b) between the fixed bed hydrotreating zone a) and the bubbling bed hydrocracking zone c) is carried out without decompression. It is also possible for at least part of the effluent from the hydrotreatment zone a) to be introduced directly into the bubbling bed hydrocracking zone c) without changing the chemical composition and without significant pressure loss. that is to say without decompression.
  • a vacuum residue (RSV Ural) containing 87.0% by weight of compounds boiling at a temperature above 520 ° C, having a density of 9.5 ° API and a sulfur content of 2.72% by weight are treated. .
  • the feedstock was subjected to a hydrotreatment step including two permutable reactors.
  • the three NiCoMo catalysts on Alumina used in series are sold by Axens under the references HF858 (hydrodemetallation catalyst: HDM), HM848 (transition catalyst) and HT438 (hydrodesulphurization catalyst: HDS).
  • the operating conditions are given in Table 1.
  • Table 1 Operating conditions fixed bed step of hydrotreatment ⁇ / u> HDM, transition 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 hydrotreatment is then subjected to a separation step making it possible to recover a light fraction (gas) and a heavy fraction containing a majority of compounds boiling at more than 350 ° C (350 ° C + fraction).
  • the heavy fraction (350 ° C + fraction) is then treated in a hydrocracking step comprising two successive bubbling bed reactors.
  • the operating conditions of the hydrocracking step are given in Table 2.
  • Table 2 Operating conditions of the hydrocracking section ⁇ / u> 2 bubbling beds catalysts NiMo on alumina Temperature R1 (° C) 423 Temperature R2 (° C) 431 H2 partial pressure (MPa) 13.5 VVH "reactors" (h-1, Sm3 / h fresh load / m3 of reactors) 0.3 VVH "bubbling bed catalysts" (h-1, Sm3 / h fresh load / m3 bubbling bed catalysts) 0.6 H2 / HC entry hydrocracking section excluding H2 consumption (Nm3 / m3 fresh load) 600
  • NiMo catalyst on Alumina used is sold by the company Axens under the reference HOC-548.
  • the effluent of the hydrocracking step is then subjected to a separation step for separating a gaseous fraction and a heavy liquid fraction by means of separators.
  • the heavy liquid fraction is then distilled in an atmospheric distillation column so as to recover distillates and an atmospheric residue.
  • the atmospheric residue corresponding to the 350 ° C + fraction of the effluent from the hydrocracking stage is characterized by a sediment content (IP375) of 0.3% m / m and a sediment content after aging (IP390) 0.7% m / m.
  • the operating conditions of the hydrocracking step coupled with the different treatment variants (sediment separation with precipitation stage and recovery of the distillate cut (variant B) or without precipitation step (variant A) of the atmospheric residue (RA) have an impact on the stability of the effluents obtained This is illustrated by the sediment contents after aging measured in the atmospheric residue RA (cutting 350 ° C +) before (0.7% m / m) and after ( ⁇ 0.1% m / m) ) the precipitation and sediment separation step, then recovery of the distillate cut.
  • the atmospheric residues obtained according to the invention constitute excellent fuel oil bases, in particular bunker oil bases having a sediment content after aging (IP390) of less than 0.1% by weight.
  • the resulting blend has a viscosity of 336 cSt at 50 ° C, a sulfur content of 0.34% w / w and a sediment content after aging (IP390) of less than 0.1 wt%.
  • This mixture thus constitutes a quality bunker oil, which can be sold according to grade RMG or IFO 380, with low sediment content and low sulfur content. For example, it may be burned outside the ECA zones by 2020-25 without the vessel being equipped with flue-gas scrubbing to remove the sulfur oxides.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
EP16717176.8A 2015-06-01 2016-04-20 Procede de conversion de charges comprenant une etape d'hydrotraitement, une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls Active EP3303523B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
FR1554964A FR3036705B1 (fr) 2015-06-01 2015-06-01 Procede de conversion de charges comprenant une etape d'hydrotraitement, une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls
PCT/EP2016/058745 WO2016192891A1 (fr) 2015-06-01 2016-04-20 Procede de conversion de charges comprenant une etape d'hydrotraitement, une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls

Publications (2)

Publication Number Publication Date
EP3303523A1 EP3303523A1 (fr) 2018-04-11
EP3303523B1 true EP3303523B1 (fr) 2019-03-06

Family

ID=54260864

Family Applications (1)

Application Number Title Priority Date Filing Date
EP16717176.8A Active EP3303523B1 (fr) 2015-06-01 2016-04-20 Procede de conversion de charges comprenant une etape d'hydrotraitement, une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls

Country Status (11)

Country Link
US (1) US11692142B2 (https=)
EP (1) EP3303523B1 (https=)
JP (1) JP6670856B2 (https=)
KR (1) KR102529349B1 (https=)
CN (1) CN107912046A (https=)
ES (1) ES2728582T3 (https=)
FR (1) FR3036705B1 (https=)
PT (1) PT3303523T (https=)
SA (1) SA517390454B1 (https=)
TW (1) TWI691591B (https=)
WO (1) WO2016192891A1 (https=)

Families Citing this family (26)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
FR3064642B1 (fr) * 2017-03-29 2019-05-24 IFP Energies Nouvelles Procede de traitement d'une charge hydrocarbonee comprenant une etape de desasphaltage, une etape de conditionnement de l'asphalte et une etape de recyclage des sediments issus de la dao
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
US10696906B2 (en) 2017-09-29 2020-06-30 Marathon Petroleum Company Lp Tower bottoms coke catching device
FR3084371B1 (fr) * 2018-07-24 2020-08-07 Ifp Energies Now Procede de traitement d'une charge hydrocarbonee lourde comprenant un hydrotraitement en lit fixe, un desasphaltage et un hydrocraquage en lit bouillonnant de l'asphalte
US12000720B2 (en) 2018-09-10 2024-06-04 Marathon Petroleum Company Lp Product inventory monitoring
US10894923B2 (en) * 2018-10-22 2021-01-19 Saudi Arabian Oil Company Integrated process for solvent deasphalting and gas phase oxidative desulfurization of residual oil
EP3870683A1 (en) 2018-10-24 2021-09-01 Haldor Topsøe A/S Method for co-production of aviation fuel and diesel
US12031676B2 (en) 2019-03-25 2024-07-09 Marathon Petroleum Company Lp Insulation securement system and associated methods
US11975316B2 (en) 2019-05-09 2024-05-07 Marathon Petroleum Company Lp Methods and reforming systems for re-dispersing platinum on reforming catalyst
CA3212048A1 (en) 2019-05-30 2020-11-30 Marathon Petroleum Company Lp Methods and systems for minimizing nox and co emissions in natural draft heaters
US11384301B2 (en) 2020-02-19 2022-07-12 Marathon Petroleum Company Lp Low sulfur fuel oil blends for stability enhancement and associated methods
US11905468B2 (en) 2021-02-25 2024-02-20 Marathon Petroleum Company Lp Assemblies and methods for enhancing control of fluid catalytic cracking (FCC) processes using spectroscopic analyzers
US11898109B2 (en) 2021-02-25 2024-02-13 Marathon Petroleum Company Lp Assemblies and methods for enhancing control of hydrotreating and fluid catalytic cracking (FCC) processes using spectroscopic analyzers
US20250012744A1 (en) 2021-02-25 2025-01-09 Marathon Petroleum Company Lp Methods and assemblies for enhancing control of refining processes using spectroscopic analyzers
US12473500B2 (en) 2021-02-25 2025-11-18 Marathon Petroleum Company Lp Assemblies and methods for enhancing control of fluid catalytic cracking (FCC) processes using spectroscopic analyzers
US12461022B2 (en) 2021-02-25 2025-11-04 Marathon Petroleum Company Lp Methods and assemblies for determining and using standardized spectral responses for calibration of spectroscopic analyzers
US11702600B2 (en) 2021-02-25 2023-07-18 Marathon Petroleum Company Lp Assemblies and methods for enhancing fluid catalytic cracking (FCC) processes during the FCC process using spectroscopic analyzers
US11326111B1 (en) * 2021-03-15 2022-05-10 Saudi Arabian Oil Company Multi-step pressure cascaded hydrocracking process
US11692141B2 (en) 2021-10-10 2023-07-04 Marathon Petroleum Company Lp Methods and systems for enhancing processing of hydrocarbons in a fluid catalytic cracking unit using a renewable additive
CA3188122A1 (en) 2022-01-31 2023-07-31 Marathon Petroleum Company Lp Systems and methods for reducing rendered fats pour point
CN115895723B (zh) * 2022-11-03 2024-06-04 宁波中循环保科技有限公司 含氯硅的废矿物油连续生产基础油的方法及系统
US12311305B2 (en) 2022-12-08 2025-05-27 Marathon Petroleum Company Lp Removable flue gas strainer and associated methods
US12306076B2 (en) 2023-05-12 2025-05-20 Marathon Petroleum Company Lp Systems, apparatuses, and methods for sample cylinder inspection, pressurization, and sample disposal
US12533615B2 (en) 2023-06-02 2026-01-27 Marathon Petroleum Company Lp Methods and systems for reducing contaminants in a feed stream
US12415962B2 (en) 2023-11-10 2025-09-16 Marathon Petroleum Company Lp Systems and methods for producing aviation fuel
US12599848B2 (en) 2024-06-03 2026-04-14 Marathon Petroleum Company Lp Systems, analyzers, controllers, and associated methods to enhance fluid separation for distillation operations

Family Cites Families (28)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2988501A (en) * 1958-08-18 1961-06-13 Union Oil Co Hydrorefining of crude oils
US3477943A (en) * 1967-04-25 1969-11-11 Atlantic Richfield Co Two-stage treatment of high sulfur content petroleum materials
US3637483A (en) * 1969-11-10 1972-01-25 Ghenron Research Co Synthetic lubricating oil stock production
FR2538814B1 (fr) 1982-12-30 1986-06-27 Inst Francais Du Petrole Procede de traitement d'une huile lourde ou d'une fraction d'huile lourde pour les convertir en fractions plus legeres
FR2538813A1 (fr) 1982-12-31 1984-07-06 Inst Francais Du Petrole Procede d'hydrotraitement convertissant en au moins deux etapes une fraction lourde d'hydrocarbures contenant des impuretes soufrees et des impuretes metalliques
US4818743A (en) 1983-04-07 1989-04-04 Union Oil Company Of California Desulfurization catalyst and the catalyst prepared by a method
US4816841A (en) 1986-07-11 1989-03-28 Kuraray Co., Ltd. Optical recording medium
US5089463A (en) 1988-10-04 1992-02-18 Chevron Research And Technology Company Hydrodemetalation and hydrodesulfurization catalyst of specified macroporosity
FR2660322B1 (fr) 1990-03-29 1992-06-19 Inst Francais Du Petrole Procede d'hydrotraitement d'un residu petrolier ou d'une huile lourde en vue de les raffiner et de les convertir en fractions plus legeres.
US5622616A (en) 1991-05-02 1997-04-22 Texaco Development Corporation Hydroconversion process and catalyst
FR2681871B1 (fr) 1991-09-26 1993-12-24 Institut Francais Petrole Procede d'hydrotraitement d'une fraction lourde d'hydrocarbures en vue de la raffiner et de la convertir en fractions plus legeres.
US5221656A (en) 1992-03-25 1993-06-22 Amoco Corporation Hydroprocessing catalyst
US5827421A (en) 1992-04-20 1998-10-27 Texaco Inc Hydroconversion process employing catalyst with specified pore size distribution and no added silica
US6270654B1 (en) 1993-08-18 2001-08-07 Ifp North America, Inc. Catalytic hydrogenation process utilizing multi-stage ebullated bed reactors
JPH0753967A (ja) 1993-08-18 1995-02-28 Catalysts & Chem Ind Co Ltd 重質油の水素化処理方法
FR2753984B1 (fr) * 1996-10-02 1999-05-28 Inst Francais Du Petrole Procede de conversion d'une fraction lourde d'hydrocarbures impliquant une hydrodemetallisation en lit bouillonnant de catalyseur
US6332976B1 (en) 1996-11-13 2001-12-25 Institut Francais Du Petrole Catalyst containing phosphorous and a process hydrotreatment of petroleum feeds using the catalyst
FR2764300B1 (fr) 1997-06-10 1999-07-23 Inst Francais Du Petrole Procede de conversion de fractions lourdes petrolieres comprenant une etape d'hydrodesulfuration et une etape de conversion en lit bouillonnant
US6589908B1 (en) 2000-11-28 2003-07-08 Shell Oil Company Method of making alumina having bimodal pore structure, and catalysts made therefrom
FR2839902B1 (fr) 2002-05-24 2007-06-29 Inst Francais Du Petrole Catalyseur d'hydroraffinage et/ou d'hydroconversion et son utilisation dans des procedes d'hydrotraitement de charges hydrocarbonees
FR2933709B1 (fr) * 2008-07-10 2011-07-22 Inst Francais Du Petrole Procede de conversion comprenant une hydroconversion d'une charge, un fractionnement, puis un desasphatage de la fraction residu sous vide
FR2940143B1 (fr) 2008-12-18 2015-12-11 Inst Francais Du Petrole Catalyseurs d'hydrodemetallation et d'hydrodesulfuration et mise en oeuvre dans un procede d'enchainement en formulation unique
US20110266198A1 (en) * 2009-11-17 2011-11-03 H R D Corporation Bitumen extraction and asphaltene removal from heavy crude using high shear
FR2957607B1 (fr) 2010-03-18 2013-05-03 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
US8790508B2 (en) 2010-09-29 2014-07-29 Saudi Arabian Oil Company Integrated deasphalting and oxidative removal of heteroatom hydrocarbon compounds from liquid hydrocarbon feedstocks
WO2013019418A2 (en) * 2011-07-29 2013-02-07 Saudi Arabian Oil Company Process for stabilization of heavy hydrocarbons
FR2983866B1 (fr) * 2011-12-07 2015-01-16 Ifp Energies Now Procede d'hydroconversion de charges petrolieres en lits fixes pour la production de fiouls a basse teneur en soufre
FR3000098B1 (fr) * 2012-12-20 2014-12-26 IFP Energies Nouvelles Procede avec separation de traitement de charges petrolieres pour la production de fiouls a basse teneur en soufre

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
None *

Also Published As

Publication number Publication date
ES2728582T3 (es) 2019-10-25
TWI691591B (zh) 2020-04-21
JP2018521162A (ja) 2018-08-02
KR20180014775A (ko) 2018-02-09
CN107912046A (zh) 2018-04-13
US11692142B2 (en) 2023-07-04
WO2016192891A1 (fr) 2016-12-08
JP6670856B2 (ja) 2020-03-25
FR3036705B1 (fr) 2017-06-02
TW201715031A (zh) 2017-05-01
EP3303523A1 (fr) 2018-04-11
PT3303523T (pt) 2019-06-12
US20180163144A1 (en) 2018-06-14
SA517390454B1 (ar) 2022-06-19
FR3036705A1 (fr) 2016-12-02
KR102529349B1 (ko) 2023-05-04

Similar Documents

Publication Publication Date Title
EP3303523B1 (fr) Procede de conversion de charges comprenant une etape d'hydrotraitement, une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls
EP3018188B1 (fr) Procede de conversion de charges petrolieres comprenant une etape d'hydrotraitement en lit fixe, une etape d'hydrocraquage en lit bouillonnant, une etape de maturation et une etape de separation des sediments pour la production de fiouls a basse teneur en sediments
EP3303522B1 (fr) Procede de conversion de charges comprenant une etape d'hydrocraquage, une etape de precipitation et une etape de separation des sediments pour la production de fiouls
EP3026097B1 (fr) Procede de production de combustibles de type fuel lourd a partir d'une charge hydrocarbonee lourde utilisant une separation entre l'etape d'hydrotraitement et l'etape d'hydrocraquage
CA3021600C (fr) Procede de conversion comprenant des lits de garde permutables d'hydrodemetallation, une etape d'hydrotraitement en lit fixe et une etape d'hydrocraquage en reacteurs permutables
EP3018187B1 (fr) Procede de conversion de charges petrolieres comprenant une etape d'hydrocraquage en lit bouillonnant, une etape de maturation et une etape de separation des sediments pour la production de fiouls a basse teneur en sediments
EP2788458B1 (fr) Procede d'hydroconversion de charges petrolieres en lits fixes pour la production de fiouls a basse teneur en soufre
EP3018189B1 (fr) Procede de conversion de charges petrolieres comprenant une etape de viscoreduction, une etape de maturation et une etape de separation des sediments pour la production de fiouls a basse teneur en sediments
EP3077483B1 (fr) Procede de conversion d'une charge hydrocarbonee lourde integrant un desasphaltage selectif en cascade avec recyclage d'une coupe desasphaltee
WO2015091033A1 (fr) Nouveau procede integre de traitement de charges petrolieres pour la production de fiouls a basse teneur en soufre et en sediments
WO2014096704A1 (fr) Procédé avec separation de traitement de charges petrolieres pour la production de fiouls a basse teneur en soufre
FR3075808A1 (fr) Procede de traitement d'une charge hydrocarbonee lourde
FR3027909A1 (fr) Procede integre de production de combustibles de type fuel lourd a partir d'une charge hydrocarbonee lourde sans separation intermediaire entre l'etape d'hydrotraitement et l'etape d'hydrocraquage
FR2981659A1 (fr) Procede de conversion de charges petrolieres comprenant une etape d'hydroconversion en lit bouillonnant et une etape d'hydrotraitement en lit fixe pour la production de fiouls a basse teneur en soufre
CA2894607A1 (fr) Procede integre de traitement de charges petrolieres pour la production de fiouls a basse teneur en soufre
WO2012085407A1 (fr) Procède de conversion de charge hydrocarbonate comprenant une huile de schiste par hydre conversion en lit bouillonnant, fractionnement par distillation atmosphérique, et hydrocraquage
FR3084371A1 (fr) Procede de traitement d'une charge hydrocarbonee lourde comprenant un hydrotraitement en lit fixe, un desasphaltage et un hydrocraquage en lit bouillonnant de l'asphalte
WO2012085408A1 (fr) Procede de conversion de charge hydrocarbonee comprenant une huile de schiste par decontamination, hydroconversion en lit bouillonnant, et fractionnement par distillation atmospherique
FR3084372A1 (fr) Procede de traitement d'une charge hydrocarbonee lourde comprenant un hydrotraitement en lit fixe, deux desasphaltages et un hydrocraquage en lit bouillonnant de l'asphalte
FR2970478A1 (fr) Procede d'hydroconversion en lit fixe d'un petrole brut, etete ou non, un fractionnement, puis un desasphaltage de la fraction lourde pour la production d'un brut synthetique preraffine
FR3064642A1 (fr) Procede de traitement d'une charge hydrocarbonee comprenant une etape de desasphaltage, une etape de conditionnement de l'asphalte et une etape de recyclage des sediments issus de la dao
WO2016192893A1 (fr) Procédé de conversion de charges comprenant une étape de viscoréduction, une étape de précipitation et une étape de séparation des sédiments pour la production de fiouls

Legal Events

Date Code Title Description
STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE INTERNATIONAL PUBLICATION HAS BEEN MADE

PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: REQUEST FOR EXAMINATION WAS MADE

17P Request for examination filed

Effective date: 20180102

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

AX Request for extension of the european patent

Extension state: BA ME

DAV Request for validation of the european patent (deleted)
DAX Request for extension of the european patent (deleted)
GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: GRANT OF PATENT IS INTENDED

INTG Intention to grant announced

Effective date: 20180927

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE PATENT HAS BEEN GRANTED

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

REG Reference to a national code

Ref country code: GB

Ref legal event code: FG4D

Free format text: NOT ENGLISH

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

Ref country code: AT

Ref legal event code: REF

Ref document number: 1104532

Country of ref document: AT

Kind code of ref document: T

Effective date: 20190315

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

Free format text: LANGUAGE OF EP DOCUMENT: FRENCH

REG Reference to a national code

Ref country code: DE

Ref legal event code: R096

Ref document number: 602016010737

Country of ref document: DE

REG Reference to a national code

Ref country code: PT

Ref legal event code: SC4A

Ref document number: 3303523

Country of ref document: PT

Date of ref document: 20190612

Kind code of ref document: T

Free format text: AVAILABILITY OF NATIONAL TRANSLATION

Effective date: 20190603

REG Reference to a national code

Ref country code: NL

Ref legal event code: FP

REG Reference to a national code

Ref country code: LT

Ref legal event code: MG4D

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190606

Ref country code: LT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190606

Ref country code: HR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: LV

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: GR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190607

Ref country code: RS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

REG Reference to a national code

Ref country code: AT

Ref legal event code: MK05

Ref document number: 1104532

Country of ref document: AT

Kind code of ref document: T

Effective date: 20190306

REG Reference to a national code

Ref country code: ES

Ref legal event code: FG2A

Ref document number: 2728582

Country of ref document: ES

Kind code of ref document: T3

Effective date: 20191025

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: RO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: AL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: PL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: SM

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

REG Reference to a national code

Ref country code: DE

Ref legal event code: R097

Ref document number: 602016010737

Country of ref document: DE

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LU

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20190420

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190706

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MC

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: LI

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20190430

Ref country code: CH

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20190430

26N No opposition filed

Effective date: 20191209

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20190420

GBPC Gb: european patent ceased through non-payment of renewal fee

Effective date: 20200420

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: GB

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20200420

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

Ref country code: HU

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT; INVALID AB INITIO

Effective date: 20160420

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190306

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: NL

Payment date: 20250424

Year of fee payment: 10

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: DE

Payment date: 20250428

Year of fee payment: 10

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: ES

Payment date: 20250513

Year of fee payment: 10

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: BE

Payment date: 20250424

Year of fee payment: 10

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: PT

Payment date: 20250407

Year of fee payment: 10

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: FR

Payment date: 20250424

Year of fee payment: 10