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
  • C10G67/14—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including at least two different refining steps in the absence of hydrogen
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
  • C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
  • C10G21/12—Organic compounds only
  • C10G21/14—Hydrocarbons
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
  • C10G27/04—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen
  • C10G27/12—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen with oxygen-generating compounds, e.g. per-compounds, chromic acid, chromates
• • 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
  • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
  • C10G31/10—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for with the aid of centrifugal force
• • 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
  • C10G32/00—Refining of hydrocarbon oils by electric or magnetic means, by irradiation, or by using microorganisms
  • C10G32/02—Refining of hydrocarbon oils by electric or magnetic means, by irradiation, or by using microorganisms by electric or magnetic means
• • 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
  • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
  • C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
  • C10G45/04—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used
  • C10G45/06—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof
  • C10G45/08—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof in combination with chromium, molybdenum, or tungsten metals, or compounds thereof
• • 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
  • C10G47/02—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used
  • C10G47/10—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used with catalysts deposited on a carrier
  • C10G47/12—Inorganic carriers
• • 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
  • C10G65/04—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including only refining 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
  • 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
  • C10G7/00—Distillation of hydrocarbon oils
  • C10G7/06—Vacuum distillation
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
  • C10G2300/10—Feedstock materials
  • C10G2300/1077—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
• • 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

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 the conversion of heavy petroleum feedstocks of the atmospheric residue and / or vacuum residue type for the production of heavy fractions that can be used as fuel bases, in particular as 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 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.
• Annex VI of the MARPOL Convention 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.
• 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 that may include catalyst fines and / or sediments that 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.
• the conversion ratio is defined as the mass fraction of organic compounds having a boiling point above 520 ° C in the feed at the inlet of the reaction section minus the mass fraction of organic compounds having a higher boiling point. at 520 ° C at the outlet of the reaction section in the effluent, all divided by the mass fraction of organic compounds having a boiling point above 520 ° C at the inlet of the reaction section in the charge.
• it is economically advantageous to maximize the conversion because generally conversion products, especially distillates, are better valued than the unconverted feed or fraction.
• the temperature is generally lower than in bubbling bed or slurry bed hydrocracking processes.
• the conversion rate in fixed bed is therefore generally lower, but the implementation is simpler than bubbling bed or "slurry".
• the conversion rate of hydrotreatment processes in fixed bed is moderate or low, generally less than 45%, usually less than 35% at the end of the cycle, and less than 25% at the beginning of the cycle.
• the conversion rate generally varies during the cycle due to the increase in temperature to compensate for the catalytic deactivation.
• sediment production is generally lower in fixed bed hydrotreatment processes than in bubbling bed or slurry bed hydrocracking processes.
• the temperatures reached from the middle of the cycle to the end of the cycle for the hydrotreatment processes of fixed bed residues lead to a sufficient sediment formation to degrade the quality of a fuel oil, especially a bunker fuel oil. , consisting largely of a heavy fraction from a fixed bed residue hydrotreatment process.
• the skilled person is familiar with the difference between fixed bed and bed in "slurry".
• a "slurry" bed is a bed in which the catalyst is sufficiently dispersed in the form of small particles to be suspended in the liquid phase.
• permutable reactors a set of at least two reactors of which one of the reactors can be stopped, generally for regeneration or replacing the catalyst or for maintenance while the other (or the others) is (are) in operation.
• the new process may also include a sediment precipitation and separation step downstream of the hydrocracking step in a reactive reactor so as to obtain, after fractionation, at least one heavy fraction with a low sulfur content meeting the future recommendations of ⁇ , but above all with a low sediment content, namely a sediment content after aging less than or equal to 0.1% by weight
• Another advantage of the new process incorporating a step of precipitation and separation of sediments downstream of a hydrocracking step in permutable reactors is that it becomes possible to operate these reactive hydrocracking reactors at a medium temperature over a period of one hour. higher overall cycle than reactors in the fixed bed hydrotreatment section, thus leading to a higher conversion without the formation of sediment, generally increased by the higher temperature, being problematic for the quality of the product . Similarly coking does not become problematic in the hydrocracking section, since the permutable reactors allow the replacement of the catalyst without stopping the unit.
• the method according to the invention can therefore be implemented in the absence of steps e), f) and g) so as to obtain conversion distillates. high value, and a heavy hydrocarbon fraction with a low sulfur content that can be used as fuel oil or as a fuel base.
• the invention relates to a process for treating a hydrocarbon feed containing at least one hydrocarbon fraction having a sulfur content of at least 0.1% by weight, an initial boiling point of at least 340 ° C and a final boiling temperature of at least 440 ° C, to obtain conversion products and a heavy hydrocarbon fraction with low sulfur content.
• This heavy hydrocarbon fraction can be produced so that its sediment content after aging is less than or equal to 0.1% by weight.
• Said method comprises the following steps: a) a hydrodemetallation step in permutable reactors in which the hydrocarbon feedstock and hydrogen are brought into contact on a hydrodemetallization catalyst; b) a fixed bed hydrotreatment stage of the hydrodemetallization catalyst; effluent from step a), c) a step of hydrocracking in reactive reactors of the effluent from step b), d) a step of separating the effluent from step c), leading to at least a gas fraction and a heavy liquid fraction, e) a sediment precipitation step in which the heavy liquid fraction from the separation step d) is brought into contact with a distillate cut of which at least 20% weight has a boiling temperature greater than or equal to 100 ° C, for a period of less than 500 minutes, at a temperature of between 25 and 350 ° C, and a pressure of less than 20 MPa, f) a step of physical separation of sediment con held in the heavy liquid fraction resulting from step d), g) a step of recovery of the
• One of the objectives of the present invention is to propose a process coupling conversion and desulphurization of heavy petroleum feedstocks for the production of fuel oils and low-sulfur fuel oil bases.
• Another objective of the process is the production of bunker oil or bunker oil bases, with a low sediment content after aging less than or equal to 0.1% by weight, this being allowed during the implementation of the steps e ), f) and g).
• 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. Description of Figure 1
• FIG. 1 describes an implementation scheme of the invention without limiting the scope.
• the hydrocarbon feedstock (1) and hydrogen (2) are brought into contact in a hydrodemetallation step (a) in permutable reactors, in which the hydrogen (2) can be introduced at the inlet of the first catalytic bed and between two beds of step a).
• the effluent (3) resulting from the hydrodemetallation stage a) in swarfable reactor reactors is sent to a fixed bed hydrotreatment stage b), in which additional hydrogen (4) can be introduced as input of the first catalytic bed and between two beds of step b).
• additional hydrogen (4) can be introduced as input of the first catalytic bed and between two beds of step b).
• the hydrocarbon feedstock (1) and the hydrogen (2) are introduced directly into the hydrotreatment step b).
• the effluent (5) resulting from the fixed bed hydrotreating step b) is sent to a hydrocracking step c) in reactive guard reactors in which additional hydrogen (6) can be introduced at the inlet of the first catalytic bed and between two beds of step c).
• the effluent (7) from the hydrocracking step c) is sent to a separation step d) which makes it possible to obtain at least one light hydrocarbon fraction (8) and a heavy fraction (9) containing compounds. boiling at least 350 ° C. This heavy fraction (9) is brought into contact with a distillate cut (10) during a precipitation step e).
• the effluent (1 1) consisting of a heavy fraction and sediment is treated in a physical separation step f) to remove a fraction comprising sediments (13) and recover a liquid hydrocarbon fraction (12) to content reduced sediment.
• the liquid hydrocarbon fraction (12) is then treated in a step g) of recovering on the one hand the liquid hydrocarbon fraction (15) having a sediment content after aging less than or equal to 0.1% by weight, and of on the other hand, a fraction (14) containing at least a part of the distillate cut introduced during step e).
• the liquid hydrocarbon fraction (14) may be recycled in whole or in part in step e) sediment precipitation.
• Steps e), f), g) are either implemented together or independently of each other. That is to say that a process comprising for example only step e) or steps e) and f) but not step g) remains within the scope of the present invention. Description of Figure 2
• FIG. 2 describes a simplified diagram of implementation of the series of reactors of the invention without limiting its scope.
• the reactors are represented but it is understood that all the equipment necessary for operation are present (balloons, pumps, exchangers, ovens, columns, etc.).
• Only the main streams containing the hydrocarbons are represented, but it is understood that hydrogen-rich gas streams (make-up or recycle) can be injected at the inlet of each catalytic bed or between two beds.
• the charge (1) enters a hydrodemetallation step in reactive guard reactors consisting of reactors Ra and Rb.
• the effluent (2) of the hydrodemetallation step in permutable guard reactors is sent to the fixed bed hydrotreating step consisting of the reactors R1, R2 and R3.
• the fixed bed hydrotreating reactors can for example be loaded respectively with hydrodemetallation, transition and hydrodesulfurization catalysts.
• the feedstock (1) can enter directly into the fixed bed hydrotreatment section.
• the effluent (3) from the fixed-bed hydrotreating stage is sent to the hydrocracking stage in reactive reactors constituted by the reactors Rc and Rd.
• the reactors are permutable in pairs, that is, that is Ra is associated with Rb, and that Rc is associated with Rd.
• Each reactor Ra, Rb, Rc, Rd can be taken offline so as to change the catalyst without stopping the rest of the unit.
• This catalyst change (rinsing, unloading, reloading, sulphurization) is generally permitted by a not shown packaging section.
• the following table gives examples of feasible sequences according to Figure 2:
• the feedstock treated in the process according to the invention is advantageously a hydrocarbonaceous feed having an initial boiling point of at least 340.degree. C. and a final boiling point of at least 440.degree.
• its initial boiling point is at least 350 ° C., preferably at least 375 ° C.
• its final boiling point is at least 450 ° C., preferably at least 460 ° C. 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 fillers being treated are preferably atmospheric residues or vacuum residues, or mixtures of these residues.
• 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, preferably at least 0.5% by weight, preferably at least 1% by weight, more preferably at least 4% by weight. more preferably at least 5% by weight.
• the hydrocarbon feedstock treated in the process may contain, inter alia, metallic impurities, in particular nickel and vanadium.
• metallic impurities in particular nickel and vanadium.
• the sum of the nickel and vanadium contents is generally at least 10 ppm, preferably from at least 50 ppm, preferably at least 100 ppm, more preferably at least 150 ppm.
• 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 cut (LCO or "light cycle oil” according to the English terminology), a heavy cut (HCO or "heavy cycle oil” according to the English terminology), a decanted oil, a residue of FCC, 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 such as coking or visbreaking.
• 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 makes it possible to obtain conversion products, in particular distillates and a heavy hydrocarbon fraction with a low sulfur content.
• This heavy hydrocarbon fraction can be produced in such a way that its sediment content after aging is less than or equal to 0.1% by weight, this being allowed by the implementation of precipitation and sediment separation steps.
• step a) hydrodemetallation, the feedstock and hydrogen are contacted on a hydrodemetallization catalyst loaded in at least two reactive reactors, under hydrodemetallation conditions.
• This step a) is preferably carried out when the feedstock contains more than 50 ppm or more than 100 ppm of metals and / or when the feedstock comprises impurities capable of inducing clogging of the catalyst bed too rapidly, such as by-products. iron or calcium for example.
• the goal is to reduce the impurity content and thus protect the downstream hydrotreating step from the deactivation and clogging, hence the notion of aging reactors.
• These reactors hydrodemetallation guards are implemented as permutable reactors (technology "PRS" for "Permutable Reactor System” according to the English terminology) as described in patent FR2681871.
• permutable reactors are generally fixed beds located upstream of the fixed bed hydrotreatment section and equipped with lines and valves so as to be permuted between them, that is to say for a system with two permutable reactors Ra and Rb, Ra can be in front of Rb and vice versa.
• Each reactor Ra, Rb can be taken offline so as to change the catalyst without stopping the rest of the unit.
• This change of catalyst is generally allowed by a conditioning section (set of equipment outside the main high pressure loop).
• the permutation for catalyst change occurs when the catalyst is no longer sufficiently active (poisoning by metals and coking) and / or the clogging reaches a loss of pressure too high.
• step a) of hydrodemetallation hydrodemetallation reactions (commonly called HDM), but also hydrodesulfurization reactions (commonly called HDS), hydrodenitrogenation reactions occur. (commonly referred to as HDN) accompanied by reactions of hydrogenation, hydrodeoxygenation, hydrodearomatization, hydroisomerization, hydrodealkylation, hydrocracking, hydrodephalting and Conradson carbon reduction.
• Step a) is called hydrodemetallation because it removes the majority of the metals from the charge.
• the hydrodemetallation stage a) in permutable reactors according to the invention may advantageously be carried out at a temperature of between 300 ° C. and 500 ° C., preferably between 350 ° C. and 430 ° C., and under an absolute pressure. between 5 MPa and 35 MPa, preferably between 11 MPa and 26 MPa, preferably between 14 MPa and 20 MPa.
• the temperature is usually adjusted according to the desired level of hydrodemetallation and the duration of the targeted treatment.
• the space velocity of the hydrocarbon feedstock can be in a range from 0.1 hr -1 at 5 h -1 , preferably from 0.15 h -1 to 3 h -1 , and more preferably from 0.2 h -1 to 2 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 1000 Nm3 / m3.
• the hydrodemetallation stage a) in permutable reactors can be carried out industrially in at least two reactors in a fixed bed and preferably in a downflow of liquid.
• the hydrodemetallization 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 weight preferably from 3% to 20% by weight of molybdenum (expressed as molybdenum oxide MoO 3) 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 a 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, preferably from 5% 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 stage (a) in permutable reactors are for example indicated in the patent documents EP 01 13297, EP 01 13284, US Pat. No. 5,221,656, US Pat. No. 5,827,421, US Pat. No. 7,190,445, US Pat. No. 5,622,661 and US Pat. No. 5,089,463.
• step a) of hydrodemetallation is introduced, optionally with hydrogen, in a step b) of hydrotreating in fixed bed to be contacted on at least one hydrotreatment catalyst.
• the feedstock and the hydrogen are introduced directly into the fixed bed hydrotreating step b) to be contacted on at least one catalyst.
• the hydrotreatment catalyst (s) are (are) used in at least one fixed bed reactor and preferably with a liquid downflow reactor.
• 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 step b) comprises a first hydrodemetallation stage (HDM) b1) carried out in one or more hydrodemetallation zones in fixed beds and a second hydrodesulphurization second stage (b2) (HDS). performed in one or more hydrodesulfurization zones in fixed beds.
• first hydrodemetallation step b1) the effluent from step a), or the feedstock and hydrogen in the absence of step a), are contacted on a catalyst of hydrodemetallation, under hydrodemetallation conditions, then during said second hydrodesulfurization step b2), the effluent of the first hydrodemetallation step b1) is brought into contact with a hydrodesulphurization catalyst, under conditions of hydrodesulfurization.
• This process known as HYVAHL-F TM, is for example described in US Patent 541 7846.
• step b1) of hydrodemetallization hydrodemetallization reactions are carried out but also part of the other hydrotreatment reactions, and in particular hydrodesulfurization and hydrocracking reactions.
• hydrodesulfurization step b2) hydrodesulphurization reactions are carried out, but also part of the other hydrotreatment reactions, in particular hydrodemetallation and hydrocracking reactions.
• Those skilled in the art sometimes define a transition zone in which all types of hydrotreatment reactions occur.
• the hydrotreatment stage b) comprises a first hydrodemetallation stage (HDM) b1) carried out in one or more hydrodemetallation zones in fixed beds, a second transition stage b2) carried out in one or more a plurality of transition zones in fixed beds, and a third hydrodesulphurization (HDS) step b3) carried out in one or more hydrodesulfurization zones in fixed beds.
• HDM hydrodemetallation stage
• HDS hydrodesulphurization
• step b1) the effluent from step a), or the feedstock and hydrogen in the absence of step a), are contacted on a catalyst of hydrodemetallization, under hydrodemetallation conditions, then during said second transition step b2), the effluent of the first hydrodemetallation step b1) is brought into contact with a transition catalyst, under transition conditions, then during said third hydrodesulfurization step b3), the effluent of the second transition stage b2) is brought into contact with a hydrodesulfurization catalyst, under hydrodesulfurization conditions.
• Step b1) of hydrodemetallization according to the above variants is particularly necessary in the absence of step a) hydrodemetallation in reactive guard reactors so as to treat the impurities and protect the downstream catalysts.
• the need for a hydrodemetallation step b1) according to the above variants in addition to the hydrodemetallation step a) in relatable guard reactors is justified when the hydrodemetallization carried out in step a) is not not sufficient to protect the catalysts of step b), in particular the hydrodesulphurization catalysts.
• the hydrotreatment step b) according to the invention is carried out under hydrotreatment conditions. It may advantageously be used at a temperature of between 300 ° C. and 500 ° C., preferably between 350 ° C. and 430 ° C.
• VVH space velocity of the hydrocarbon feedstock
• VVH which is defined as being the volumetric flow rate of the feedstock divided by the total volume of the catalyst
• VVH can be in a range from 0.1 hr -1 at 5 h -1 , preferably from 0.1 h -1 to 2 h -1 , and more preferably from 0.1 h -1 to 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.
• the hydrotreating step b) 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 3% 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 a mixture of these oxides.
• oxides selected from the group consisting of boron oxide, zirconia, ceria, titanium oxide, phosphoric anhydride and a mixture of these oxides.
• an alumina support is used and very often a support of alumina doped with phosphorus and possibly boron.
• P2O5 phosphorus pentoxide P2O5
• B2O5 boron trioxide When B2O5 boron trioxide is present, its concentration is less than 10% in weight.
• 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 VI B and VIII may be from 3% to 40% by weight and generally from 5% to 30% by weight and the weight ratio expressed as metal oxide between metal (or metals) of the group VIB on metal (or metals) of group VIII is generally between 20 and 1, and most often between 10 and 2.
• a hydrotreatment step including a hydrodemetallation step (b1) (HDM) and then a hydrodesulfurization step (b2) (HDS)
• specific catalysts adapted to each step are preferably used.
• Catalysts that can be used in the hydrodemetallation step b1) are, for example, indicated in the patent documents EP 01 13297, EP 01 13284, US 5221 656, US 5827421, US 71 19045, US 562261 and US 5089463.
• Usable catalysts in step b2) of hydrodesulphurization are for example indicated in patent documents EP 01 13297, EP 01 13284, US 6589908, US 4818743 or US 6332976.
• a mixed catalyst also called transition catalyst, active in hydrodemetallization and hydrodesulfurization, both for the hydrodemetallation section b1) and for the hydrodesulfurization section b2) as described in the patent document FR 2940143.
• hydrodesulfurization In the case of a hydrotreatment step including a step b1) of hydrodemetallation (HDM) then a step b2) of transition, then a step b3) hydrodesulfurization (HDS), it is preferred to use specific catalysts adapted to each step.
• Catalysts that can be used in step b1) of hydrodemetallation are for example indicated in patent documents EP 01 13297, EP 01 13284, US 5221 656, US 5827421, US 71 19045, US 5622616 and US 5089463.
• Catalysts that can be used in transition stage b2), which are active in hydrodemetallation and in hydrodesulphurization, are for example described in patent document FR 2940143.
• Catalysts that can be used in the hydrodesulfurization step b3) are, for example, indicated in the patent documents EP 01 13297. , EP 01 13284, US 6589908, US 4818743 or US 6332976. also use a transition catalyst as described in FR 2940143 for sections b1), b2) and b3).
• the effluent from the hydrotreatment step b) is introduced into a hydrocracking step c) in reactive reactors.
• Hydrogen can also be injected upstream of the various catalyst beds making up the permutable hydrocracking reactors.
• any type of hydrotreating reaction (HDM, HDS, HDN, etc.) is also produced. Specific conditions, including temperature, and / or the use of one or more specific catalysts, promote the desired cracking or hydrocracking reactions.
• the reactors of step c) of hydrocracking are implemented as 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 equipped with lines and valves in ways to be exchanged between them, that is to say for a system with two reactive reactors Rc and Rd, Rc can be in front Rd and vice versa.
• Each reactor Rc, Rd can be taken offline so as to change the catalyst without stopping the rest of the unit.
• This change of catalyst is generally allowed by a conditioning section (set of equipment outside the main high pressure loop).
• the permutation for catalyst change occurs when the catalyst is no longer sufficiently active (mainly coking) and / or the clogging reaches an excessive loss of pressure.
• the hydrocracking step c) according to the invention is carried out under hydrocracking conditions. It may advantageously be carried out at a temperature of between 340 ° C. and 480 ° C., preferably between 350 ° C. and 430 ° C. and under an absolute pressure of between 5 MPa and 35 MPa, preferably between 11 MPa and 26 MPa, preferably between 14 MPa and 20 MPa.
• the temperature is usually adjusted according to the desired level of hydrocracking and the duration of the intended treatment.
• the average temperature at the beginning of the cycle of the hydrocracking step c) in permutable reactors is always greater by at least 5 ° C, preferably by at least 10 ° C, more preferably by at least 15 ° C at the average temperature at the beginning of the cycle of the hydrotreatment step b). This difference may decrease during the cycle due to the increase of the temperature of the hydrotreating step b) to compensate for the catalytic deactivation.
• the average temperature over the entire cycle of step c) of hydrocracking in reactive reactors is always at least 5 ° C higher than the average temperature over the entire cycle of step b) d hydrotreating.
• the space velocity of the hydrocarbon feedstock can be in a range from 0.1 hr -1 at 5 h -1 , preferably from 0.2 h -1 to 2 h -1 , and more preferably from 0.25 h -1 to 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.
• the hydrocracking step c) can be carried out industrially in at least two reactors in a fixed bed, and preferably in a downflow of liquid.
• the hydrocracking catalysts used may be hydrocracking or hydrotreatment catalysts. They may be granular catalysts, in the form of extrudates or beads, 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, a catalyst comprising from 0.5% to 10% can be used.
• nickel oxide NiO nickel oxide
• molybdenum oxide MoO3 molybdenum oxide
• 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 a mixture of these oxides.
• 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 less than 10% by weight. When B2O5 boron trioxide is present, its concentration is less than 10% by weight.
• 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 VI B 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 the group VIB on metal (or metals) of group VIII is generally between 20 and 1, and most often between 10 and 2.
• the hydrocracking step may in part advantageously use a bifunctional catalyst, having a hydrogenating phase in order to be able to hydrogenate the aromatics and to achieve the equilibrium between the saturated compounds and the corresponding olefins and an acidic phase which allows to promote hydroisomerization and hydrocracking reactions.
• the acid function is advantageously provided by supports with large surface areas (generally 100 to 800 m2.g-1) having a surface acidity, such as halogenated aluminas (chlorinated or fluorinated in particular), combinations of boron oxides and aluminum, amorphous silica-aluminas and zeolites.
• the hydrogenating function is advantageously provided either by one or more metals of group VIII of the periodic table of the elements, such as iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum, or by an association of at least a group VIB metal of the periodic table such as molybdenum and tungsten and at least one non-noble group VIII metal (such as nickel and cobalt).
• the catalyst must also advantageously have a high resistance to impurities and asphaltenes due to the use of a heavy load.
• the bifunctional catalyst used comprises at least one metal selected from the group consisting of Group VIII and VIB metals, taken alone or as a mixture, and a support comprising 10 to 90% by weight of a zeolite containing iron and 90% by weight. at 10% by weight of inorganic oxides.
• the Group VIB metal used is preferably selected from tungsten and molybdenum and the Group VIII metal is preferably selected from nickel and cobalt.
• the bifunctional catalyst is preferably prepared according to the method of preparation described in Japanese Patent Application No. 2289,419 (IKC) or EP 0 384 186.
• the catalysts of the permutable hydrocracking reactors are characterized by high porosities, generally greater than 0.7 ml / g of total porosity and whose macroporosity (ie the pore volume greater than 50 nm) constitutes a porous volume. greater than 0.1 mL / g.
• the catalysts used in the process according to the present invention are preferably subjected to an in-situ or ex-situ sulphurization treatment. Step d) separating the hydrocracking effluent
• 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 stripping means with steam or hydrogen 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.
• 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 more 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 hydrodemetallization step a) and / or at different locations during the hydrotreatment step b) 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 fraction (s) liquid hydrocarbon (s) obtained after separation is (are) fractionated by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction.
• the atmospheric distillate fraction may contain commercially available 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 distillate fraction under vacuum and at room temperature. minus a fraction residue under vacuum.
• the vacuum distillate fraction typically contains vacuum gas oil fractions.
• At least a portion of the atmospheric residue fraction or a portion of the vacuum residue fraction can be recycled to the hydrocracking step c).
• the atmospheric residue fraction and / or the vacuum residue fraction can be sent to a catalytic cracking process.
• the atmospheric residue fraction and / or the vacuum residue fraction can be used as fuel oil or as a base of low sulfur fuel oil.
• Part of the vacuum residue fraction and / or part of the vacuum distillate fraction may be fed to a catalytic cracking or bubbling bed hydrocracking step.
• a portion of heavy liquid fraction from step d) of separation can be used to form the distillate cup according to the invention used in step e) sediment precipitation.
• the heavy liquid fraction obtained at the end of step d) of separation contains organic sediments which result from hydrotreating and hydrocracking conditions.
• Part of the sediments consist of asphaltenes precipitated under hydrotreatment and hydrocracking conditions and are analyzed as existing sediments (IP375).
• IP375 existing sediments
• IP375 existing sediments
• IP390 sediments after aging
• high hydrocracking conditions that is to say when the conversion rate is for example greater than 30, or even 40 or 50%, cause the formation of existing sediments and potential sediments.
• the method according to the invention comprises a precipitation step making it possible 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 sediment content after aging is measured by the IP390 method with a measurement uncertainty of ⁇ 0.1.
• the precipitation step according to the invention can be implemented according to several variants e1), e2), e3):
• Destabilization precipitation e1 which consists in bringing the heavy liquid fraction from the separation step d) into contact with a distillate cut
• An oxidation precipitation e2) which consists in bringing the heavy liquid fraction resulting from step d) of separation with an oxidizing agent into contact,
• a precipitation by oxidative destabilization e3) which consists in bringing the heavy liquid fraction from the separation step d) into contact with a distillate cut and an oxidizing agent
• the destabilization precipitation step e1) comprises bringing the heavy liquid fraction from the separation step d) into contact with a distillate cut comprising hydrocarbons, generally obtained by distillation of oil. raw or derived from refining process.
• hydrocarbons advantageously comprise paraffins, preferably at least 20% paraffins.
• These hydrocarbons typically have a boiling temperature under atmospheric conditions between -42 ° C and 400 ° C.
• These hydrocarbons are typically composed of more than 3 carbon atoms, generally between 3 and 40 carbon atoms. It may for example be cuts of propane, butane, pentane, hexane, heptane, naptha, kerosene, atmospheric gas oil or vacuum gas oil taken alone or mixture.
• at least 20% by weight of the distillate fraction has 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.
• the distillate cut 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 fraction according to the invention has a boiling point of at least 252 ° C.
• At least 5% by weight or even 10% by weight of the distillate fraction according to the invention has a boiling point of at least 255 ° C.
• Said distillate cut may partly or even wholly originate from step d) of separation of the invention or another refining process or another chemical process.
• distillate cut according to the invention also has the advantage of being free from the predominant use of high value added cuts such as petrochemical cuts of the naphtha type.
• the use of the distillate cut according to the invention makes it possible to improve the yield of the heavy liquid fraction separated from the sediments.
• the use of the distillate cutter according to the invention allows the maintenance of the solubilization of valuable compounds in the heavy liquid fraction to be separated from the sediments, contrary to the use of cuts having lower boiling points, in which these valued compounds would be precipitated with the sediments.
• the distillate cut may be used in admixture with a naphtha-type cut and / or a vacuum-type gas oil cut and / or vacuum residue. Said distillate cut may be used in a mixture with the light fraction obtained after step d), the heavy fraction resulting from step d), these fractions may be taken alone or as a mixture. In the case where 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 cup according to the invention.
• 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 Preferred between 0.1 and 2.
• the distillate cut according to the invention can also partly come from step g) of recovery of the liquid hydrocarbon fraction.
• the variant e1) is carried out in the presence of an inert gas such as nitrogen and / or of a gas rich in hydrogen, preferably derived from the process of the invention, in particular from the separation step d).
• an inert gas such as nitrogen and / or of a gas rich in hydrogen, preferably derived from the process of the invention, in particular from the separation step d).
• the step of destabilization precipitation e2) comprises bringing the heavy liquid fraction from step d) of separation into contact with an oxidizing gas, liquid or solid.
• an oxidizing gas has the advantage of accelerating the precipitation process.
• oxidizing gas is meant a gas which may contain oxygen, ozone or nitrogen oxides, taken alone or as a mixture, optionally in addition to an inert gas. This oxidizing gas may be air or air depleted by nitrogen.
• an oxidizing gas may be a halogenated gas (for example chlorine) easily leading to the formation of oxygen, for example in the presence of water.
• Oxidizing liquid is understood to mean an oxygenated compound, for example water, a peroxide such as hydrogen peroxide, a peracid or an inorganic oxidizing solution such as a solution of nitrate (ammonium nitrate, for example) or permanganate (potassium permanganate for example) or chlorate or hypochlorite or persulfate or a mineral acid such as sulfuric acid.
• a peroxide such as hydrogen peroxide
• a peracid or an inorganic oxidizing solution such as a solution of nitrate (ammonium nitrate, for example) or permanganate (potassium permanganate for example) or chlorate or hypochlorite or persulfate or a mineral acid such as sulfuric acid.
• nitrate ammonium nitrate, for example
• permanganate potassium permanganate
• chlorate or hypochlorite or persulfate or a mineral acid such as sulfuric acid
• the step of precipitation by oxidative destabilization e3) comprises bringing the heavy liquid fraction from the separation step d) into contact with a distillate cut as defined in the variant e1) of destabilization precipitation and an oxidizing gas, liquid or solid compound as defined in the variant e2) of precipitation by oxidation.
• a distillate cut as defined in the variant e1) of destabilization precipitation
• an oxidizing gas, liquid or solid compound as defined in the variant e2) of precipitation by oxidation.
• the precipitation step e) according to the invention, implemented according to the variants e1), e2) or e3), makes it possible to obtain all the existing and potential sediments (by converting the potential sediments into existing sediments) of to separate them effectively and thus reach the sediment content after aging (IP390) of 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, of 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 precipitation step e) according to the invention can be carried out using several equipment.
• a static mixer, an autoclave 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 and or the oxidizing compound according to the invention.
• One or more exchangers can (wind) be used before or after mixing the liquid fraction heavy product obtained at the end of step d) and the distillate cut according to the invention and / or the oxidizing compound 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 flask, optionally with a settling function to eliminate a portion of the distillate cut according to the invention and / or a part or all of the oxidizing compound according to the invention, or a part 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.
• a hydrocarbon fraction with an enriched content of existing sediments is obtained.
• This fraction may comprise at least part of the distillate cut according to the invention during the implementation according to the variants e1) or e3) by oxidative destabilization.
• the hydrocarbon fraction with a content enriched with sediments 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 the sediments 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.
• a sediment separation which is a solid-liquid type separation, this separation being able to use a physical separation means chosen from a filter , a separation membrane, a bed of organic or inorganic type filtering solids, electrostatic precipitation, an electrostatic filter, a centrifugation system, a decantation, a centrifugal decanter, an auger withdrawal.
• a combination, in series and / or in parallel and being able to operate sequentially, of several separation means of the same type or different type can be used during this step f) sediment separation.
• 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 less than or equal to 0.1% by weight) is obtained.
• This reduced sediment content fraction may comprise at least in part the distillate cut according to the invention introduced during step e).
• the liquid hydrocarbon fraction with a reduced sediment content can advantageously be used as a base for fuel oil or as fuel oil, especially as a base for bunker oil or as bunker oil, having a content in sediment after aging less than 0.1% by weight.
• 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 step 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 for fuel oil or as fuel oil, especially as a base for bunker fuel oil or as fuel oil. bunker, having a sediment content after aging of 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.
• 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.
• 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 of 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 d) or g) can be mixed with one or more fluxing bases selected from the group consisting of light-cutting oils of a catalytic cracking, heavy cutting oils.
• catalytic cracking the residue of a catalytic cracking, a kerosene, a gas oil, a vacuum distillate and / or a decanted oil.
• kerosene, gas oil and / or vacuum distillate produced in the process of the invention will be used.
• the filler is a mixture of atmospheric residues (RA) of Middle Eastern origin. This mixture is characterized by a high amount of metals (100 ppm by weight) and sulfur (4.0% by weight), as well as 7% of [370-].
• the hydrotreatment process involves the use of two permutable reactors Ra and Rb in the first hydrodemetallization (HDM) stage upstream of a fixed bed hydrotreatment section.
• HDM hydrodemetallization
• the HDM stage includes a HDM zone in permutable beds (Ra, Rb).
• the hydrotreatment stage HDT comprises three reactors in fixed bed (R1, R2, R3).
• the effluent obtained at the end of the hydrotreating step is flash separated to obtain 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.
• the liquid fraction is then stripped in a column, then fractionated in an atmospheric column, and then a vacuum column in several sections (PI-350 ° C, 350-520 ° C and 520 ° C +, see Table 5).
• the two permutable reactors R a and R b of hydrodemetallation are charged with a hydrodemetallization catalyst.
• the three hydrotreating reactors R1 R2 R3 are loaded with hydrotreatment catalysts.
• the process is carried out under a hydrogen partial pressure of 15 MPa, a reactor inlet temperature at the beginning of the cycle of 360 ° C. and at the end of the cycle of 420 ° C.
• Table 2 shows the residence times and average temperatures on the cycle for the different sections.
• each switchable reactor Ra and Rb is taken offline for 3 weeks to renew the hydrodemetallization catalyst.
• Table 1 shows the hourly space velocities (VVH) for each catalytic reactor, and the corresponding average temperatures (WABT) obtained over the entire cycle according to the described operating mode.
• the WABT is an average temperature on the height of the bed (possibly with a weighting that gives a different weight to this or that portion of the bed), and also averaged over time over the duration of the bed. a cycle.
• the process according to the invention is carried out in this example with the same feedstock, the same catalysts, and under the same operating conditions for the reactors of the hydrodemetallization step and the reactors R1 and R2 of step b).
• hydrotreatment (HDT) The method according to the invention comprises the use of two new permutable hydrocracking reactors marked Rc and Rd, replacing a portion of the reactor R3 which appears in the hydrotreating section (HDT) of the prior art.
• the hydrocracking step c) is carried out at a high temperature downstream of the fixed bed hydrotreating step b) which comprises only two reactors R1 and R2.
• Table 2 below gives an example of operation around the 4 permutable reactors Ra, Rb, Rc and Rd.
• step c) The effluent obtained at the end of step c) is similar in terms of purification to that of Example 1, but is more converted.
• the two reactors Rc and Rd of the hydrocracking step c) are charged with a hydrocracking catalyst.
• the process is carried out under a hydrogen partial pressure of 15 MPa, a reactor inlet temperature at the beginning of the cycle of 360 ° C. and at the end of the cycle of 420 ° C.
• each switchable reactor Rc and Rd is taken offline for 3 weeks to renew the hydrocracking catalyst.
• Table 3 below shows hourly space velocity (VVH) for each catalytic reactor and the corresponding average temperatures (WABT) obtained over the entire cycle according to the described operating mode.
• Table 4 below shows the comparison of the yields and hydrogen consumption obtained according to the non-compliant example and according to the example according to the invention.
• Table 4 Comparison of the average yields obtained during cycle II thus appears, according to Tables 2, 3 and 4, that the process according to the invention incorporating a hydrocracking section (step c) into permutable reactors, permits increase in average cycle WABT (+ 4 ° C) as well as an increase in VVH.
• the WABT is the average temperature of the bed during a cycle.
• VVH is the ratio of the volume flow rate of charge to the volume of catalyst contained in the reactor.
• the gain obtained in terms of WABT (+ 4 ° C) results in an increase in the yields of the most valued cuts: +09 points on the section [PI-350 ° C] and + 1 , 9 points on the cut [350 ° C-520 ° C].
• WABT average temperature on the permutable beds
• the sediment content after aging (IP390) in the atmospheric residue (350 ° C +) is greater than 0.1% by weight in the part of the cycle where the WABT of the reactive hydrocracking reactors is greater than 402 ° C.
• the atmospheric residue (consisting of the 350-520 ° C cut and the 520 ° C + cut) is subjected to a sediment precipitation and separation step according to two variants:
• the atmospheric residue is mixed with a distillate cut which is a gasoil cut from the process (150-350 ° C) in proportions of 50/50 vol / vol at 80 ° C for 5 minutes.
• the mixture is then filtered to remove precipitated sediments and then the sediment-reduced liquid fraction (IP390 less than 0.1% by weight) is distilled so as to recover the distillate fraction (150-350) on the one hand, and the atmospheric residue (350+) with reduced sediment content (IP390 less than 0.1% by weight) on the other hand.
• the atmospheric residue is contacted in an autoclave with air at 2 bar oxygen pressure and stirring for 6 hours at 200 ° C. After decompression, the atmospheric residue is then filtered to remove the precipitated sediments and obtain the sediment-reduced liquid fraction (IP390 less than 0.1% by weight).
• the atmospheric residues (consisting of the 350-520 ° C cut and the 520 ° C + cut) recovered after precipitation by destabilization and oxidation precipitation have a viscosity from 280 cSt to 50 ° C. They also have a sediment content after aging of less than 0.1% by weight and a sulfur content of less than 0.5% S. According to IS08217, these atmospheric residues can be sold as RMG grade residual marine fuel. 380. Because of the sulfur content of less than 0.5% by weight, these marine fuels may be used by 2020-25 outside the ECA zones without the vessels being equipped with a washing device. fumes.

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)
• Life Sciences & Earth Sciences (AREA)
• Microbiology (AREA)
• Inorganic Chemistry (AREA)
• Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Applications Claiming Priority (2)

Publications (1)

Family

ID=56684023

Family Applications (1)

Country Status (10)

Families Citing this family (18)

Family Cites Families (38)

• 2016
  • 2016-04-27 FR FR1653751A patent/FR3050735B1/fr active Active
• 2017
  • 2017-04-11 EP EP17715766.6A patent/EP3448967A1/de not_active Withdrawn
  • 2017-04-11 JP JP2018555461A patent/JP6872559B2/ja active Active
  • 2017-04-11 US US16/097,461 patent/US10597591B2/en active Active
  • 2017-04-11 CA CA3021600A patent/CA3021600A1/fr active Pending
  • 2017-04-11 KR KR1020187034019A patent/KR102378453B1/ko active IP Right Grant
  • 2017-04-11 WO PCT/EP2017/058686 patent/WO2017186484A1/fr active Application Filing
  • 2017-04-11 CN CN201780040145.6A patent/CN109477007B/zh active Active
  • 2017-04-11 RU RU2018141377A patent/RU2726626C2/ru active
• 2018
  • 2018-10-24 SA SA518400297A patent/SA518400297B1/ar unknown

Also Published As

Similar Documents

Legal Events