WO2025056509A1 - Method for treating pyrolysis oil, including pre-fractionation and recycling - Google Patents

Abstract

The invention relates to a method for treating a feedstock comprising a pyrolysis oil from the pyrolysis of plastics and/or tyres and/or solid recovered fuel, the method comprising: a) a step of pre-fractionation of the feedstock in order to obtain a naphtha cut and at least one heavier cut; b) a step of hydrogenation of the naphtha cut from step a) as a mixture with at least a portion of the naphtha cut from step d) in order to obtain a hydrogenated effluent; c) optionally a step of hydrotreating the hydrogenated effluent in order to obtain a hydrotreated effluent; d) a separation step, fed with the hydrogenated effluent from step b) or with the hydrotreated effluent from step c) and an aqueous solution, the step being carried out at a temperature of between 20 and 300°C, in order to obtain at least a gaseous effluent, an aqueous effluent and a naphtha cut, a portion of which is recycled in step b).

Description

PYROLYSIS OIL TREATMENT PROCESS INCLUDING PREFRACTIONATION AND RECYCLE

TECHNICAL FIELD

The present invention relates to the field of recycling plastics and/or tires and/or solid recovered fuels (SRF). More particularly, the present invention relates to a method for treating a feedstock comprising a plastic and/or tire and/or SRF pyrolysis oil, including in particular a prefractionation of the feedstock making it possible to extract a naphtha cut, said naphtha cut subsequently being subjected to a treatment making it possible to eliminate the impurities specifically contained in this cut with a view to using this cut in particular as a feedstock for a steam cracker to produce olefins.

PRIOR TECHNIQUE

Plastics from collection and sorting channels or recycled tires or solid recovered fuels (SRF) can undergo a pyrolysis step in order to recover them. Pyrolysis consists of heating with or without a catalyst a charge containing plastic and/or recycled tires and/or SRF in the absence of oxygen, leading to the formation of three main products: a liquid hydrocarbon phase at room temperature also called pyrolysis oil, a light gas phase also called pyrolysis gas and a solid residue also called char according to Anglo-Saxon terminology.

The liquid hydrocarbon phase, pyrolysis oil, can be recovered in a gasoline, kerosene or diesel fuel storage unit.

Another way of recovering pyrolysis oils is to use them as feedstock for a steam cracking unit in order to (re)create olefins, the latter being monomers that make up certain polymers.

However, pyrolysis oils contain impurities that are often at high levels and are incompatible with direct storage in a fuel storage unit or with steam cracking units or units located downstream of steam cracking units, in particular polymerization processes and selective hydrogenation processes. These impurities can cause operability problems, including corrosion problems (particularly due to the presence of chlorine), coking or deactivation. catalytic, or even incompatibility problems in the uses of the target polymers. The presence of diolefins can also lead to problems of instability of the pyrolysis oil characterized by the formation of gums. Gums and insolubles possibly present in the pyrolysis oil can generate clogging problems in the processes.

One way to remove these impurities from plastic and/or tire pyrolysis oils is to carry out hydrotreatment (H DT) in the presence of catalysts. Such processes are described, for example, in WO2018/055555, WO2021/165178 or WO2022/144235. All these processes have in common that the entire pyrolysis oil is hydrotreated (without prefractionation).

However, the various impurities contained in pyrolysis oil that we seek to eliminate are generally found in different fractions of this oil. Indeed, depending on the origin of the pyrolysis oil, the oil can have a fairly wide range of boiling points (for example between 40°C and 700°C). Some impurities, notably chlorine, silicon or even diolefins and monoolefins are generally found in the lighter fraction of the oil (naphtha cut), while other impurities such as sulfur, nitrogen and metals are more concentrated in the heavier fractions of the oil.

The present invention thus proposes to adapt the type of impurity removal treatment to the different fractions of the oil by first carrying out a prefractionation. It aims in particular to produce a naphtha cut with a view to using this cut as a feedstock for a steam cracker to produce olefins.

During the steam cracking stage, the yields of light olefins sought for petrochemicals, particularly ethylene and propylene, depend heavily on the quality of the feedstocks sent to the steam cracking process. The BMCI (Bureau of Mines Correlation Index) is often used to characterize hydrocarbon fractions. Overall, light olefin yields increase when the paraffin content increases and/or when the BMCI decreases. Conversely, yields of undesired heavy compounds and/or coke increase when the BMCI increases.

Although a heavy middle distillate cut can be sent to a steam cracking unit, few refiners favor this option. Indeed, the heavy cut has a high BMCI and contains more naphthenic, naphtheno-aromatic, and aromatic compounds than the naphtha cut, leading to a higher C/H ratio. This high ratio causes coking in the steam cracker, requiring dedicated steam cracking furnaces for this cut. In addition, steam cracking such a heavy cut produces fewer products. of interest which are notably ethylene and propylene but more pyrolysis gasoline.

It would therefore be advantageous to extract the naphtha cut from the pyrolysis oil and eliminate the specific impurities it contains by a treatment dedicated to this cut with a view to using this cut as a charge for a steam cracker.

Methods for treating pyrolysis oil with prefractionation of the pyrolysis oil are for example described in WO2018/069794, EP4108737, WO2022/034287, US2022/340824, without however adapting the treatment of a fraction to the nature of the impurities as proposed in the present invention.

Document US2023/0013013 describes a process for treating plastics including a pyrolysis step to obtain a pyrolysis oil which is then fractionated into a fraction comprising naphtha and diesel and a vacuum gas oil (VGO) fraction. The fraction comprising naphtha and diesel is then subjected to three consecutive hydrotreatment steps, a first to remove diolefins, a second to remove monoolefins and a third to remove sulfur and nitrogen. This document also describes the possibility of prefractionation into 3 fractions, a naphtha fraction, a diesel fraction and a vacuum gas oil fraction. The naphtha fraction and the diesel fraction are then independently subjected in parallel to the three hydrotreatment steps described above. The vacuum gas oil fraction can be subjected to a hydrodemetallation step or a solvent deasphalting step. This document is aimed at the production of fuels.

WO2022/144491 describes a method for treating pyrolysis oil comprising a stripping step that separates the oil into a distillate cut comprising diolefins and naphtha and a heavier cut. The distillate cut is then subjected to hydrotreatment to remove the diolefins, then subjected to distillation to recover at least one naphtha cut that is further hydrotreated to provide a naphtha cut suitable for a steam cracker. The other cuts can be blended with crude oil and further processed in an oil refinery.

The process according to the invention proposes to extract a naphtha cut by prefractionation, then to carry out the elimination of the impurities contained in this very reactive cut by a hydrogenation treatment and possibly by adapted hydrotreatment, requiring the control of the exothermicity of the reactions by the recycling of a part of the treated naphtha cut. Prefractionation makes it possible to extract a naphtha cut from a pyrolysis oil and compatible in distillation interval with the operation of a steam cracking furnace but also to concentrate certain impurities harmful to the steam cracking unit (olefins, diolefins, chlorinated and silica compounds) with a view to their treatment. The treatment by the process according to the invention makes it possible to reduce a large part of the impurities concentrated in the naphtha cut and to make it compatible with use in the steam cracker, while controlling the strong reaction exotherms generated by the concentration of monoolefins/diolefins within this lighter cut (naphtha cut) in particular by recycling a part of the treated naphtha cut.

It is in fact the high concentration of olefins, and in particular diolefins, in this naphtha cut that requires control of the temperature of the reaction medium, the hydrogenation reactions, in particular of some of the monoolefins and diolefins, being highly exothermic. Thus, due to the highly exothermic nature of all the reactions carried out in hydrogenation step b), control of the temperature of the reaction medium is very important because too high a temperature level promotes:

- self-maintenance, or even runaway reactions due to the effect of thermal acceleration of kinetics.

- undesirable side reactions, such as polymerization, coking of catalysts or cracking reactions.

It is known that recycling part of the product obtained to or upstream of at least one of the reaction stages advantageously makes it possible, on the one hand, to dilute the impurities and, on the other hand, to control the temperature in the reaction stage(s), in which the reactions involved may be highly exothermic.

The present invention thus provides an improvement to this principle of controlling exothermicity by recycling by proposing a process diagram for treating a naphtha cut heavily loaded with highly reactive impurities from a feedstock comprising a pyrolysis oil, allowing, by implementing a recycle at the inlet of step b) of hydrogenation, precise control of temperatures, improved control of exothermicity and of the different reactions taking place in the different catalytic zones.

One of the objectives of the present invention is to control the progress and exothermicity of the reactions in hydrogenation step b), while ensuring the heat supply necessary for starting and controlling the various reactions and in particular the hydrogenation in step b) requiring specific temperature operating conditions. The treatment of the light fraction of the pyrolysis oil (naphtha cut) and not its entirety also allows for softening the operating conditions (partial pressure of hydrogen, temperature, etc.). At the same hourly volumetric flow rate as a unit that would treat the entire pyrolysis oil, a gain in the unit's capacity is achieved as well as in the investment price and the footprint.

Thanks to prefractionation, certain impurities that are particularly harmful to the steam cracking unit are found to be more concentrated in the light naphtha fraction. Conversely, these same compounds are deconcentrated from the heavier fraction(s), which favors their treatment in downstream units. It (these) generally contains little or no diolefins. In addition, it (these) contains fewer chlorinated compounds and siliceous compounds than the naphtha fraction. The heavy fraction(s) can therefore be subjected to specifically adapted subsequent treatments, such as hydrotreatment, then hydrocracking, or fluidized bed catalytic cracking, optionally in co-processing with feedstocks of fossil or biosourced origin. The process according to the invention therefore offers flexibility in the use of the heaviest fractions of the pyrolysis oil.

Another advantage of the invention is to prevent risks of blockage and/or corrosion of the treatment unit, in which the method of the invention is implemented, the risks being exacerbated by the presence, often in significant quantities, of diolefins, metals and halogenated compounds. These risks of blockage and/or corrosion are notably reduced by a separation step involving washing with an aqueous solution. This washing/separation step makes it possible in particular to eliminate the ammonium chloride salts, which are formed by reaction between the chloride ions, released by the hydrogenation of the chlorinated compounds in HCl form, in particular during the hydrogenation step then dissolution in water, and the ammonium ions, generated by the hydrogenation of the nitrogen compounds in the form of NH ₃ during the hydrogenation and/or hydrotreatment step and/or supplied by injection of an amine when the content of chlorinated compounds is high, then dissolution in water.

SUMMARY OF THE INVENTION

More specifically, the invention relates to a method for treating a feedstock comprising a pyrolysis oil from plastic and/or tires and/or recovered solid fuels, said method comprising the following steps: a) a step of prefractionating the feedstock to obtain a naphtha cut and at least one heavier cut, b) a hydrogenation step carried out in a hydrogenation reaction section, implementing at least one fixed bed reactor having n catalytic beds, n being a number integer greater than or equal to 1, each comprising at least one hydrogenation catalyst, said hydrogenation reaction section being supplied at least with said naphtha cut from step a) in mixture with at least a portion of the naphtha cut from step d) and a gas stream comprising hydrogen, said hydrogenation reaction section being carried out at an average temperature between 120 and 380°C, a partial pressure of hydrogen between 1.0 and 10.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h- ¹ , to obtain a hydrogenated effluent, c) optionally a hydrotreatment step implemented in a hydrotreatment reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1 , each comprising at least one hydrotreatment catalyst, said hydrotreatment reaction section being fed at least by said hydrogenated effluent from step b) and a gas stream comprising hydrogen, said hydrotreatment reaction section being implemented at a temperature between 200 and 400°C, a partial pressure of hydrogen between 1.0 and 10.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h' ¹ , to obtain a hydrotreated effluent, d) a separation step, fed with the hydrogenated effluent from step b) or with the hydrotreated effluent from step c) and an aqueous solution, said step being carried out in a separation section at a temperature between 20 and 300°C, to obtain at least one gaseous effluent, an aqueous effluent and a naphtha cut, part of which is recycled in step b).

According to one variant, the process comprises step c) of hydrotreatment.

According to a variant, another part of the naphtha cut obtained in step d) is sent to a steam cracking unit.

According to one variant, the steam cracking is carried out in at least one pyrolysis furnace at a temperature between 700 and 900°C and at a pressure between 0.05 and 0.3 MPa relative in the presence of water vapor.

According to a variant, the weight ratio between the naphtha cut from step d) recycled in step b) and the naphtha cut from step a) and introduced into step b) is between 0.01 and 10.

According to a variant, the process comprises at least one step of pretreatment of the feed or naphtha cut obtained in step a), said pretreatment step being carried out before or after step a) of prefractionation and upstream of step b) of hydrogenation and comprises an adsorption step and/or a filtration step and/or a centrifugation step and/or a decantation step and/or an electrostatic separation step and/or a washing step using an aqueous solution and/or a gas stripping step.

According to a variant, said hydrogenation catalyst of step b) comprises a support chosen from alumina, silica, silica-aluminas, magnesia, clays and their mixtures and a hydro-dehydrogenating function comprising either at least one element from group VIII and at least one element from group VIB, or at least one element from group VIII.

According to a variant, said hydrotreatment catalyst of step c) comprises a support chosen from alumina, silica, silica-aluminas, magnesia, clays and their mixtures, and a hydro-dehydrogenating function comprising at least one element from group VIII and/or at least one element from group VIB.

Alternatively, the charge consists of plastic and/or tire pyrolysis oil and/or recovered solid fuels.

According to a variant, said prefractionation step a) is carried out so as to obtain said naphtha cut and at least one middle distillate cut and one vacuum gas oil cut.

According to a variant, at least a portion of said heavy cut, or of said middle distillate cut and/or of said vacuum gas oil cut is subjected to a dedicated hydrotreatment step, in a hydrotreatment reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrotreatment catalyst, said hydrotreatment reaction section being fed at least by said heavy cut, or said one middle distillate cut and/or said vacuum gas oil cut and a gas stream comprising hydrogen, said hydrotreatment reaction section being implemented at an average temperature between 250 and 430°C, a partial pressure of hydrogen between 1.0 and 10.0 MPa abs. and an hourly volumetric velocity between 0.1 and 10.0 h ^-1 , to obtain a heavy hydrotreated effluent.

According to a variant, at least a portion of the hydrotreated heavy effluent is sent to a hydrocracking step implemented in a hydrocracking reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrocracking catalyst, said hydrocracking reaction section being fed at least by said hydrotreated heavy effluent and a gas stream comprising hydrogen, said hydrocracking reaction section being implemented at an average temperature between 250 and 480°C, a hydrogen partial pressure between 1.5 and 20.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h ^-1 , to obtain a hydrocracked effluent.

According to a variant, at least a portion of said heavy cut, or of said middle distillate cut and/or of said vacuum gas oil cut, or of the hydrotreated heavy effluent is sent to a fluidized bed catalytic cracking step implemented in a fluidized bed catalytic cracking reaction section in a substantially vertical reactor either in ascending mode or in descending mode in the presence of a zeolite catalyst at a reactor temperature of between 450°C and 600°C with a contact time in the reactor of less than 1 minute.

The invention also relates to a product obtained by the process according to the invention.

Alternatively, the product includes a bio-based carbon content according to ASTM D6866 of between 0 and 70% by weight.

In the following text, "pyrolysis oil" means oil from the pyrolysis of plastics and/or tires and/or CSR, unless otherwise stated. Where the origin of the pyrolysis oil is important, its origin is added (e.g., tire pyrolysis oil).

According to the present invention, the expressions "between ... and ..." and "between .... and ..." are equivalent and mean that the limit values of the interval are included in the range of values described. If this were not the case and the limit values were not included in the range described, such precision will be provided by the present invention.

In this description, the term “include” is synonymous with (means the same as) “include” and “contain”, and is inclusive or open and does not exclude other elements not mentioned. It is understood that the term “include” includes the exclusive and closed term “consist”.

For the purposes of the present invention, the different parameter ranges for a given step such as pressure ranges and temperature ranges may be used alone or in combination. For example, for the purposes of the present invention, a range of preferred pressure values may be combined with a range of preferred temperature values.

In the following, particular and/or preferred embodiments of the invention may be described. They may be implemented separately or combined with each other, without limitation of combination when technically feasible. In the following, the groups of chemical elements are given according to the CAS classification (CRC Handbook of Chemistry and Physics, publisher CRC press, editor-in-chief DR Lide, ^81st edition, 2000-2001). For example, group VIII (or VI 11 B) according to the CAS classification corresponds to the metals of columns 8, 9 and 10 according to the new IIIPAC classification.

The metal content is measured by X-ray fluorescence.

DETAILED DESCRIPTION

The charge

According to the invention, the charge comprises a pyrolysis oil from plastic and/or tire and/or recovered solid fuels.

Plastic waste is generally a mixture of several polymers. The feedstock used in the process according to the invention may comprise, alone or in a mixture, polyethylene (low and/or high density), polypropylene, polyethylene terephthalate, polyvinyl chloride and polystyrene. In addition, depending on the uses, plastics may contain, in addition to polymers, other compounds, such as plasticizers, pigments, dyes or even residues of polymerization catalysts. Plastic waste may also contain, to a minor extent, biomass originating for example from household waste.

As for tires, they are mainly made of rubber for their elastic property (mixture of elastomers of the crosslinked natural and synthetic rubber type, added with additives of the silica, resin, sulfur, zinc oxide, carbon black, etc. type) and textile and metallic fibers for their reinforcing property.

Solid recovered fuels (SRF), also known as refuse derived fuel (RDF), or solid recovered fuels (SRF), are solid non-hazardous waste prepared for energy recovery, whether they come from household and similar waste, waste from economic activities or construction and demolition waste. SRF are generally a mixture of any combustible waste such as used tires, food by-products (fats, animal meal, etc.), viscose and wood waste, light fractions from shredders (e.g. from used vehicles, electrical and electronic equipment (WEEE), household and commercial waste, residues from the recycling of various types of waste, including certain municipal waste, plastic waste, textiles, wood among others. SRF generally contains plastic waste. The pyrolysis oil included in the feedstock, whether from tires, plastics and/or CSR, comes from a pyrolysis step of a feedstock containing tires, plastic(s) and/or CSR in a pyrolysis unit.

The pyrolysis step can be carried out by thermal or catalytic pyrolysis treatment or can be prepared by hydropyrolysis (pyrolysis in the presence of a catalyst and hydrogen).

The pyrolysis step is generally carried out at a temperature between 250°C and 750°C. The pyrolysis step can be carried out under more or less severe conditions. The low severity pyrolysis step is carried out at a temperature between 250°C and 450°C, preferably between 275°C and 425°C, and particularly preferably between 300°C and 400°C. The low severity pyrolysis step produces pyrolysis oils rich in mono- and diolefins as well as a significant amount of aromatics, and which may include chlorinated compounds.

The high severity pyrolysis step is carried out at a temperature between 450°C and 750°C, preferably between 500°C and 700°C, and particularly preferably between 550°C and 650°C. The high severity pyrolysis step produces pyrolysis oils rich in aromatics, which may include chlorinated compounds.

The pyrolysis unit may include one or more reactors configured to convert the feedstock into gas-phase and liquid-phase products (e.g., simultaneously). The reactor(s) may contain one or more beds of inert materials or pyrolysis catalysts including sand, zeolite, or combinations thereof. Typically, the pyrolysis catalyst is capable of transferring heat to the components undergoing the pyrolysis process in the pyrolysis unit.

The pyrolysis unit may comprise one or more pieces of equipment, for example one or more heated extruders, a heated rotary kiln, heated tank-type reactors, empty heated vessels, closed heated surfaces where the feedstock flows along the wall, vessels surrounded by furnaces or ovens or other equipment providing a heated surface.

In one or more embodiments of the pyrolysis unit, a purge gas is used in all or part of the pyrolysis stage(s) to enhance plastics cracking, produce valuable products, provide feed for steam cracking, or combinations thereof. The purge gas may include hydrogen (H2), nitrogen (N2), steam, product gases, or combinations thereof. Pyrolysis oil, whether from tires, plastics and/or CSR, generally has a boiling point range of between 40°C and 1000°C, preferably between 45 and 650°C, most preferably between 45°C and 550°C.

The density of pyrolysis oil, whether from tires, plastics and/or CSR, generally has a density, measured at 15°C according to the ASTM D4052 method, between 0.75 and 1.05 g/cm ³ , preferably between 0.75 and 0.95 g/cm ³ .

The pyrolysis oil, advantageously in liquid form at room temperature, comprises in particular a mixture of hydrocarbon compounds, in particular paraffins (n- and i-paraffins), olefins (mono- and/or diolefins), naphthenes and aromatics. In particular, depending on the origin of the feedstock treated by the pyrolysis unit, the pyrolysis oil may comprise up to 70% by weight of paraffins, up to 90% by weight of naphthenes, up to 90% by weight of olefins and up to 90% by weight of aromatics, it being understood that the sum of the paraffins, naphthenes, olefins and aromatics is equal to 100% by weight of the hydrocarbon compounds.

Pyrolysis oil may contain diolefins. The diolefin content is commonly determined indirectly as the maleic anhydride value (MAV). The method is based on the Diels-Alder addition reaction between conjugated diolefins and maleic anhydride. The method for determining MAV is described in C. Lôpez-Garcia et al., Near Infrared Monitoring of Low Conjugated Diolefins Content in Hydrotreated FCC Gasoline Streams, Oil & Gas Science and Technology - Rev. IFP, Vol. 62 (2007), No. 1, pp. 57-68. MAV is expressed as mg of maleic anhydride reacted with 1 g of sample (mg/g). MAV varies between 5 and 100 mg/g in pyrolysis oils.

Pyrolysis oil, whether from tires, plastics and/or CSR, may contain a portion of compounds of biological origin, such as for example tire pyrolysis oil produced from natural rubber elastomers, or plastic and/or CSR pyrolysis oil produced from plastic and/or CSR waste which may contain, to a minor extent, biomass from, for example, household waste. The biological carbon content (according to the analytical method of radiocarbon isotope C ¹⁴ according to ASTM D6866) may be between 0 and 70% by weight, preferably between 0.1 and 60% by weight relative to the total weight of the pyrolysis oil. In the case of a tire pyrolysis oil, this may comprise a biological carbon content (according to the analytical method of radiocarbon isotope C ¹⁴ according to ASTM D6866) of between 20 and 70% by weight, preferably between 30 and 60% by weight. relative to the total weight of the pyrolysis oil. This makes it possible to incorporate a biological composition into the products of the process according to the invention.

Pyrolysis oil may include, and most often does include, additional impurities such as metals, in particular iron, silicon, halogenated compounds, in particular chlorinated compounds. These impurities may be present at high levels, for example up to 500 ppm by weight or 700 ppm by weight or even 1000 ppm by weight, and even 5000 ppm by weight, of halogenated elements (in particular chlorine but also bromine, fluorine or iodine) provided by halogenated compounds, and generally between 1 and 1000 ppm by weight or between 1 and 700 ppm by weight or between 1 and 500 ppm by weight of halogenated elements. Pyrolysis oil can contain up to 500 ppm by weight or 700 ppm by weight or even 1000 ppm by weight or even 5000 ppm by weight of chlorine element provided by chlorinated compounds, and generally between 1 and 1000 ppm by weight or between 1 and 700 ppm by weight or between 1 and 500 ppm by weight of chlorine element. Pyrolysis oil can contain up to 50 ppm by weight or even 100 ppm by weight of bromine element provided by brominated compounds, and generally between 1 and 100 ppm by weight or between 1 and 50 ppm by weight of bromine element.

The oil may contain up to 200 ppm by weight, or even 1500 ppm by weight of metallic or semi-metallic elements, and generally between 1 and 200 ppm by weight or between 1 and 1500 ppm by weight of metallic or semi-metallic elements. Alkali metals, alkaline earth metals, transition metals, poor metals and metalloids may be considered as contaminants of a metallic nature, called metals or metallic or semi-metallic elements. In particular, metals or metallic or semi-metallic elements include silicon, iron or both of these elements. Pyrolysis oil may contain up to 200 ppm by weight or even 1000 ppm by weight of silicon, and generally between 1 and 200 ppm by weight or between 1 and 1000 ppm by weight or even between 1 and 500 ppm by weight of silicon. Pyrolysis oil may contain up to 50 ppm by weight or 100 ppm by weight of iron, and generally between 1 and 50 ppm by weight or between 1 and 100 ppm by weight of iron. Pyrolysis oil may also contain phosphorus, sodium, calcium, potassium and magnesium.

The pyrolysis oil may also include other impurities such as heteroelements provided in particular by sulfur compounds, oxygenated compounds and/or nitrogenous compounds, at contents generally less than 40,000 ppm by weight of heteroelements and preferably less than 15,500 ppm by weight of heteroelements, and generally between 1 and 40,000 ppm by weight or between 1 and 15,500 ppm by weight of heteroelements. The sulfur compounds are generally present in a content of less than 15,000 ppm by weight and preferably less than 10,000 ppm by weight, and generally between 1 and 15,000 ppm by weight or between 1 and 10,000 ppm by weight of sulfur compounds.

The oxygenated compounds are generally present in a content of less than 15,000 ppm by weight and preferably less than 10,000 ppm by weight, and generally between 1 and 15,000 ppm by weight or between 1 and 10,000 ppm by weight of oxygenated compounds.

Nitrogen compounds are generally present in a content of less than 10,000 ppm by weight and preferably less than 5,000 ppm by weight, and generally between 1 and 10,000 ppm by weight or between 1 and 5,000 ppm by weight of nitrogen compounds.

The contents of sulfur, oxygenated and/or nitrogenous compounds often depend on the origin of the treated feedstock. Thus, tire pyrolysis oils generally contain more heteroelements than plastic pyrolysis oils, particularly sulfur compounds.

Pyrolysis oil may also include other impurities such as heavy metals such as mercury, arsenic, zinc and lead, for example up to 100 ppb by weight or 200 ppb by weight of mercury or arsenic, and generally between 1 and 200 ppb by weight or between 1 and 100 ppb by weight of heavy metals.

The feedstock of the process according to the invention comprises at least one plastic and/or tire and/or solid recovered fuel pyrolysis oil, and this in any proportion. Said feedstock may consist solely of pyrolysis oil(s). Preferably, said feedstock comprises at least 50% by weight, preferably between 70 and 100% by weight, of pyrolysis oil relative to the total weight of the feedstock, i.e. preferably between 50 and 100% by weight, preferably between 70% and 100% by weight of pyrolysis oil.

The feedstock of the process according to the invention may further comprise, at a low content, typically between 1% and 50% by weight of the feedstock, or even between 1% and 30% or between 1 and 10% by weight, in addition to the pyrolysis oil, a conventional petroleum feedstock or a feedstock resulting from the conversion of biomass which is then co-treated with the pyrolysis oil of the feedstock.

The conventional petroleum feedstock can advantageously be a cut or a mixture of cuts of the naphtha, diesel or vacuum diesel type.

The feedstock resulting from the conversion of biomass can advantageously be chosen from vegetable oils, algae or algal oils, fish oils, oils used food, and fats of vegetable or animal origin; or mixtures of such fillers. Said vegetable oils may advantageously be crude or refined, totally or partially, and derived from plants chosen from rapeseed, sunflower, soybean, palm, olive, coconut, copra, castor, cotton, peanut, linseed and crambe oils and all oils derived for example from sunflower or rapeseed by genetic modification or hybridization, this list not being exhaustive. Said animal fats are advantageously chosen from lard and fats composed of residues from the food industry or from the catering industries. Frying oils, various animal oils such as fish oils, tallow, lard may also be used. The feedstock resulting from the conversion of biomass can also advantageously be chosen from methyl esters of fatty acids of plant and/or animal origin or even methyl esters of fatty acids from used edible vegetable oils.

The feedstock from biomass conversion may also be selected from feedstocks from thermal or catalytic biomass conversion processes, such as oils that are produced from biomass, particularly lignocellulosic biomass, with various liquefaction methods, such as hydrothermal liquefaction or pyrolysis. The term "biomass" refers to material derived from recently living organisms, which includes plants, animals and their by-products. The term "lignocellulosic biomass" refers to biomass derived from plants or their by-products. Lignocellulosic biomass is composed of carbohydrate polymers (cellulose, hemicellulose) and an aromatic polymer (lignin).

The feedstock from biomass conversion can also advantageously be chosen from feedstocks from the paper industry.

Pre-processing step (optional)

The process according to the invention may comprise a pretreatment step which may be carried out before or after the prefractionation step and upstream of the hydrogenation step.

Thus, according to the embodiment of carrying out the pretreatment before the prefractionation step a), the feed comprising a pyrolysis oil can advantageously be pretreated in an optional pretreatment step, to obtain a pretreated feed which feeds the prefractionation step a).

According to the embodiment of carrying out the pretreatment after the prefractionation step a), the naphtha cut resulting from the prefractionation step can advantageously be pretreated in an optional pretreatment step, previously in hydrogenation step b), to obtain a pretreated naphtha cut which feeds hydrogenation step b).

The pretreatment step may also be carried out on at least one heavy cut. When the pretreatment step is carried out on at least one heavy cut, it is carried out independently of the pretreatment step of the naphtha cut.

Alternatively, this optional pretreatment step can reduce the amount of contaminants and solid particles. This optional pretreatment step can notably eliminate sediments that can form due to the unstable nature of pyrolysis oils and/or a compatibility problem between two different feedstocks.

Said optional pretreatment step may be implemented by any method known to those skilled in the art for reducing the quantity of contaminants. It may in particular comprise an adsorption step and/or a filtration step and/or a centrifugation step and/or a decantation step and/or an electrostatic separation step and/or a washing step using an aqueous solution and/or a gas stripping step.

The optional pretreatment step is advantageously carried out at a temperature between 20 and 400°C, preferably between 40 and 350°C, and at a pressure between 0.15 and 10.0 MPa abs, preferably between 0.2 and 7.0 MPa abs.

According to a variant, said optional pretreatment step is implemented in an adsorption section operated in the presence of at least one adsorbent. The adsorbent may be chosen from a zeolite, activated carbon, a clay, a silica or an alumina. Advantageously, said adsorbent comprises less than 1% by weight of metallic elements, preferably is free of metallic elements. By metallic elements of the adsorbent, it is meant the elements of groups 6 to 10 of the periodic table of elements (new IUPAC classification).

According to another variant, said optional pretreatment step is implemented in a washing section with an aqueous solution, for example water or an acidic or basic solution, or with an organic solvent. This washing section may comprise equipment for bringing the feedstock, or the naphtha cut and/or at least one heavy cut obtained after pre-fractionation, into contact with the aqueous solution and for separating the phases so as to obtain the feedstock or a pre-treated cut on the one hand and the aqueous solution comprising impurities on the other hand. Among this equipment, there may be for example a stirred reactor, a decanter, a mixer-decanter and/or a co- or counter-current washing column. According to another variant, said optional pretreatment step is implemented by filtration. The filtration step makes it possible to remove inorganic solids, sediments and/or fines contained in the feedstock, or the naphtha cut and/or at least one heavy cut obtained after pre-fractionation, in particular metals, metal oxides and metal chlorides. A filter is generally used whose pore size (for example the diameter or equivalent diameter) is less than 25 μm, preferably less than or equal to 10 μm, even more preferably less than or equal to 5 μm. It is also possible to use a series of filters with different pore sizes, in particular a series of filters having decreasing pore sizes in the direction of flow of the feedstock. These filter media are well known for industrial uses. Cartridge filters, self-cleaning filters, for example, are suitable.

Alternatively, filter aids, for example diatomaceous earth, can be used in the filtration system, as seeding, i.e. suspended in the load or as a pre-coat (coating according to English terminology) on the filter.

Regardless of the filters, especially those with additives, two filters can be used in parallel to carry out cleaning and maintenance on one while the other is in operation.

According to another variant, said optional pretreatment step is implemented by centrifugation, by decantation or by electrostatic separation.

According to another variant, said optional pretreatment step is implemented by gas stripping, thereby reducing the oxygen content in the feed. The gas stripping may remove oxygen (O2) that may be dissolved in the feed, or the naphtha cut and/or at least one heavy cut obtained after the pre-fractionation, thereby reducing the likelihood of formation of free radicals leading to polymerization in downstream steps. The process generally involves contacting the feed, or the naphtha cut and/or at least one heavy cut obtained after the pre-fractionation, with a stripping gas (e.g. H2, N2 or a mixture thereof), thereby transferring at least a portion of the dissolved oxygen from the feed or cut to the stripping gas, followed by separation of the stripping gas from the feed or cut. Any dissolved H2 remaining in the feed, or the naphtha cut and/or at least one heavy cut obtained after prefractionation, after the gas extraction step is not a problem, given the hydrogenation steps performed downstream.

Said optional pre-processing step generally comprises one or more, preferably several, treatments described above. Step a) of prefractionation

The process according to the invention comprises a step a) of prefractionation of the charge, optionally pretreated, to obtain a naphtha cut and at least one heavy cut.

The term “naphtha cut” means a hydrocarbon cut comprising compounds having a boiling point generally less than or equal to 175°C, in particular between 45 and 175°C.

A "heavy cut" is a hydrocarbon cut comprising compounds with a boiling point generally above 175°C. The heavy cut may include middle distillates such as a diesel cut and/or a kerosene cut. It may also include heavier compounds such as a vacuum gas oil (or VGO). The kerosene cut generally has initial and final boiling points in a range of approximately 175 to 250°C and the diesel cut generally has initial and final boiling points in a range of approximately 250°C to 370°C. As for the vacuum gas oil cut, it generally has boiling points above 370°C.

Depending on the destination or use of the cuts from the prefractionation step, the person skilled in the art will adjust the cut points in the stripping and/or distillation operations. For example, it may be necessary to adjust the end point of the naphtha cut to 150, 175, 180 or 200°C, or even 250°C.

The prefractionation step can be carried out to obtain a naphtha cut and a (single) heavy cut. It can also be carried out to obtain a naphtha cut, a middle distillate cut and a vacuum diesel cut. The middle distillate cut can also be fractionated into a kerosene cut and a diesel cut.

The prefractionation step is advantageously carried out at a pressure less than or equal to 1.0 MPa abs., preferably between 0.1 and 1.0 MPa abs.

The prefractionation step can advantageously be implemented by any method known to those skilled in the art, such as for example the combination of one or more separator(s) (balloon(s)), and/or one or more stripping column(s), and/or a distillation column, this or these separator(s) (balloon(s)) and/or columns optionally being able to be supplied with a stripping gas, for example a hydrogen-rich gas stream. Preferably, the prefractionation step uses a distillation column. The impurities contained in the starting pyrolysis oil are not distributed in the same way among the different cuts after prefractionation. The naphtha cut generally contains the majority of diolefins, monoolefins, chlorinated compounds, and silica compounds. As for the heavy cut, it generally contains no or very few diolefins. In addition, it contains fewer chlorinated compounds and silica compounds than the naphtha cut. However, sulfur and/or nitrogen-based impurities are generally concentrated in the heavy cut.

Step b) of hydrogenation

According to the invention, the process comprises a hydrogenation step b) implemented in a hydrogenation reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrogenation catalyst, said hydrogenation reaction section being fed at least with said naphtha cut from step a) in a mixture with at least a portion of the naphtha cut from step d) and a gas stream comprising hydrogen, said hydrogenation reaction section being implemented at an average temperature between 120 and 380°C, a partial pressure of hydrogen between 1.0 and 10.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h' ¹ , to obtain a hydrogenated effluent.

Step b) is carried out in particular under hydrogen pressure and temperature conditions enabling the hydrogenation of the diolefins and monoolefins to be carried out at the start of the hydrogenation reaction section while enabling, by means of a rising temperature profile, the hydrodemetallation and hydrodechlorination to be carried out, in particular at the end of the hydrogenation reaction section. A necessary quantity of hydrogen is injected so as to enable the hydrogenation of at least a portion of the diolefins and monoolefins present in the pyrolysis oil, the hydrodemetallation of at least a portion of the metals, in particular the retention of silicon, and also the conversion of at least a portion, and preferably all, of the chlorine (into HCl). The hydrogenation of diolefins and monoolefins thus makes it possible to avoid or at least limit the formation of "gums", i.e. the polymerization of diolefins and monoolefins and therefore the formation of oligomers and polymers, which can block the reaction section of hydrotreatment step c). In parallel with hydrogenation, hydrodemetallation, and in particular the retention of silicon during step b), makes it possible to limit the catalytic deactivation of the reaction section of hydrotreatment step c) downstream when it is present. The person skilled in the art easily understands that, in hydrogenation step b), hydrogenation reactions are carried out as described above but also in parallel some of the other hydrotreatment reactions, and in particular hydrodesulfurization and hydrodenitrogenation, even if these reactions are rather favored in hydrotreatment step c), which is generally carried out at a higher temperature.

Said reaction section implements hydrogenation in the presence of at least one hydrogenation catalyst, advantageously at an average temperature (or WABT as defined below) between 120 and 380°C, preferably between 180 and 350°C, and particularly preferably between 200 and 330°C, a hydrogen partial pressure between 1.0 and 10.0 MPa abs, preferably between 1.5 and 8.0 MPa abs. and very preferably between 2.0 and 6.0 MPa abs. and at an hourly volumetric flow rate (WH) between 0.1 and 10.0 h' ¹ , preferably between 0.2 and 5.0 h' ¹ , and very preferably between 0.3 and 3.0 h' ¹ .

According to the invention, the “average temperature” of a reaction section corresponds to the Weight Average Bed Temperature (WABT) according to the established Anglo-Saxon term, well known to those skilled in the art. The average temperature is advantageously determined according to the catalytic systems, the equipment, and the configuration thereof, used. The average temperature (or WABT) is calculated as follows:

WABT = (Tentrw + _{Tout )} /2 with Tin: the temperature of the effluent at the inlet of the reaction section and Tout: the temperature of the effluent at the outlet of the reaction section. Unless otherwise indicated, the “average temperature” of a reaction section is given at start-of-cycle conditions.

The hourly volume flow rate (WH) is defined here as the ratio between the hourly volume flow rate of the feedstock (fresh naphtha cut) and the volume of catalyst(s).

The quantity of the gas flow comprising hydrogen (H2) feeding said reaction section is advantageously such that the hydrogen coverage is between 100 and 1500 Nm ³ of hydrogen per m ³ of charge (Nm ³ /m ³ ), preferably between 120 and 1000 Nm ³ of hydrogen per m ³ of charge (Nm ³ /m ³ ), more preferably between 150 and 800 Nm ³ of hydrogen per m ³ of charge (Nm ³ /m ³ ).

Hydrogen coverage is defined as the ratio of the volume flow rate of hydrogen taken under standard temperature and pressure conditions to the volume flow rate of the charge (fresh naphtha cut), without taking into account the recycled fraction, at 15°C (in normal m ³ , noted Nm ³ , of H2 per m ³ of charge).

Advantageously, the reaction section of said step b) comprises between 1 and 5 reactors, preferably between 2 and 5 reactors, and particularly preferably it comprises two reactors. Each reactor comprises at least one catalytic bed, for example between 1 and 10 catalytic beds.

According to a preferred variant, these reactors operate in permutable mode, called "PRS" for Permutable Reactor System or "lead and lag". The association of at least two reactors in PRS mode makes it possible to isolate a reactor, unload the spent catalyst, reload the reactor with fresh catalyst and put said reactor back into service without stopping the process. The PRS technology is described, in particular, in patent FR2681871. According to a particularly preferred variant, the hydrogenation reaction section of step b) comprises two reactors operating in permutable mode.

Advantageously, reactor internals, for example of the filter tray type, can be used to prevent clogging of the reactor(s). An example of a filter tray is described in patent FR3051375.

Advantageously, said hydrogenation catalyst comprises a support, preferably mineral, and a hydro-dehydrogenating function.

According to one variant, the hydro-dehydrogenating function comprises in particular at least one element from group VIII, preferably chosen from nickel and cobalt, and at least one element from group VI B, preferably chosen from molybdenum and tungsten. According to this variant, the total content expressed as oxides of the metallic elements from groups VI B and VIII is preferably between 1% and 40% by weight, preferably from 5% to 30% by weight relative to the total weight of the catalyst. When the metal is cobalt or nickel, the metal content is expressed as CoO and NiO respectively. When the metal is molybdenum or tungsten, the metal content is expressed as MoOa and WO3 respectively.

The weight ratio expressed in metal oxide between the metal (or metals) of group VI B relative to the metal (or metals) of group VIII is preferably between 1 and 20, and preferably between 2 and 10.

According to this variant, the reaction section of said step b) comprises for example a hydrogenation catalyst comprising between 0.5% and 12% by weight of nickel, preferably between 0.9% and 10% by weight of nickel (expressed as nickel oxide NiO relative to the weight of said catalyst), and between 1% and 30% by weight of molybdenum, preferably between 3% and 20% by weight of molybdenum (expressed as molybdenum oxide MoOa relative to the weight of said catalyst) on a preferably mineral support, preferably on an alumina support.

According to another variant, the hydro-dehydrogenating function comprises, and is preferably made up of, at least one element from group VIII, preferably nickel. According to this variant, the content of nickel oxides is preferably between 1 and 50% by weight, preferably between 10% and 30% by weight relative to the weight of said catalyst. This type of catalyst is preferably used in its reduced form, on a preferably mineral support, preferably on an alumina support.

The support of said hydrogenation catalyst is preferably chosen from alumina, silica, silica-aluminas, magnesia, clays and mixtures thereof. Said support may contain doping compounds, in particular oxides chosen from boron oxide, in particular boron trioxide, zirconia, ceria, titanium oxide, phosphoric anhydride and a mixture of these oxides. Preferably, said hydrogenation catalyst comprises an alumina support, optionally doped with phosphorus and optionally boron. When phosphoric anhydride P2O5 is present, its concentration is less than 10% by weight relative to the weight of the alumina and advantageously at least 0.001% by weight relative to the total weight of the alumina. When boron trioxide B2O3 is present, its concentration is less than 10% by weight relative to the weight of the alumina and advantageously at least 0.001% relative to the total weight of the alumina. The alumina used may be, for example, a y (gamma) or q (eta) alumina.

The said hydrogenation catalyst is, for example, in the form of extrudates.

Very preferably, step b) may implement, in addition to the hydrogenation catalyst(s) described above, also at least one hydrogenation catalyst used in step b) comprising less than 1% by weight of nickel and at least 0.1% by weight of nickel, preferably 0.5% by weight of nickel, expressed as nickel oxide NiO relative to the weight of said catalyst, and less than 5% by weight of molybdenum and at least 0.1% by weight of molybdenum, preferably 0.5% by weight of molybdenum, expressed as molybdenum oxide MoOs relative to the weight of said catalyst, on an alumina support. This catalyst with a low metal content may preferably be placed upstream or downstream of the hydrogenation catalyst(s) described above, preferably upstream. According to another aspect of the invention, the hydrogenation catalyst as described above further comprises one or more organic compounds containing oxygen and/or nitrogen and/or sulfur (additive catalyst). Such a catalyst is often referred to as "additive catalyst". Generally, the organic compound is chosen from a compound comprising one or more chemical functions chosen from a carboxylic function, alcohol, thiol, thioether, sulfone, sulfoxide, ether, aldehyde, ketone, ester, carbonate, amine, nitrile, imide, oxime, urea and amide or compounds including a furan cycle or sugars.

Preferably, the hydrogenation step may use, upstream of the hydrogenation catalyst(s), at least one guard bed containing adsorbents of the alumina, silica-alumina, zeolite and/or activated carbon type, possibly containing metals from group VIB and/or VIII. It is also possible to use a series of guard beds with particles of different diameters, in particular a series of guard beds having decreasing diameters in the direction of circulation of the feedstock (also called “grading” according to English terminology).

According to a particular embodiment, all or part of the feed (naphtha cut) can be injected in a staged manner at the inlet of each catalytic bed so as to manage the exotherms as described in FR2969642. In this case, the total flow of the feed (naphtha cut) is divided into a certain number of different partial flows equal to the number of catalytic beds in the reactor, the different partial flows are injected at the inlet of the successive catalytic beds in increasing proportions.

Since hydrogenation reactions, particularly of some olefins and diolefins, are highly exothermic, a rising temperature profile is observed in the hydrogenation reaction section. This higher temperature at the end of the section allows hydrodemetallation and hydrodechlorination reactions to be carried out.

The temperature difference (delta T) between the outlet and the inlet of each catalytic bed of hydrogenation step b) is generally less than 30°C, or even less than 25°C.

In order to be able to manage the exothermicity in the reaction section, a portion of the naphtha cut from step d) must be recycled into step b). Advantageously, the quantity of the naphtha cut from step d) recycled, i.e. the fraction of product obtained recycled, is adjusted so that the weight ratio between the naphtha cut from step d) recycled into step b) and the naphtha cut from step a) and introduced into step b) is between 0.01 and 10, preferably between 0.1 and 7, and particularly preferably between 0.2 and 5. This recycle rate makes it possible to control the temperature rise in step b). Indeed, when the recycle rate is high, the dilution rate of the feedstock is high, and the temperature rise at the start of the reaction section of step b), is thus controllable by the dilution effect.

The injection of at least a portion of the naphtha cut from step d) can be carried out at the first catalytic bed of the reaction section, or between the different catalytic beds of each section. When the reaction section comprises two reactors operating in permutable mode, at least a portion of the naphtha cut from step d) can be injected between the two reactors.

In addition, a liquid and/or gaseous diluent may be injected in step b) (also called quench according to English terminology) in addition to the naphtha cut from step d). The injection of the liquid and/or gaseous diluent may be carried out in the same manner as described above. The liquid diluent (or liquid quench) may be an external liquid, for example a fossil naphtha cut. The gaseous diluent (or gaseous quench) is generally a gaseous stream comprising fresh and/or recycled hydrogen. The gaseous diluent may be at least a part of the gaseous effluent obtained in step d) which contains hydrogen, possibly purified.

Said hydrogenation step b) makes it possible to obtain a hydrogenated effluent, i.e. an effluent with a reduced content of olefins, in particular diolefins, metals, in particular silicon, and halogens, in particular chlorine. It also makes it possible to hydrogenate the monoolefins. Hydrogenation step b) generally makes it possible to convert at least 40%, and preferably at least 60% of the diolefins as well as at least 40%, and preferably at least 60% of the monoolefins contained in the initial feedstock. The heat released by the saturation of the double bonds makes it possible to raise the temperature of the reaction medium and to initiate the hydrotreatment reactions, in particular the elimination, at least in part, of other contaminants, such as for example silicon and chlorine or nitrogen. Preferably, at least 50%, and more preferably at least 75% of the chlorine and silicon of the initial charge are respectively removed during step b). Generally, the silicon content is less than 10 ppm by weight in the hydrogenated effluent from step b).

Depending on the residual impurity content in the hydrogenated naphtha cut obtained after step b) and its final destination, this cut may be subjected to a hydrotreatment step. When it is desired to use this cut as a feedstock for a steam cracker to produce olefins, a hydrotreatment step is generally necessary in order to achieve the sulfur and nitrogen specifications. In this case, the effluent obtained at the end of step b) is sent at least in part and preferably in whole, preferably directly, to step c) of hydrotreatment.

When it is desired to send this cut to a fuel storage unit, a hydrotreatment step may not be necessary. In this case, the effluent obtained at the end of step b) is sent at least in part and preferably in full, preferably directly, to the separation step d).

Step c) of hydrotreatment (optional)

According to the invention, the treatment method may comprise a hydrotreatment step c) implemented in a hydrotreatment reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrotreatment catalyst, said hydrotreatment reaction section being fed at least with said hydrogenated effluent from step b) and a gas stream comprising hydrogen, said hydrotreatment reaction section being implemented at an average temperature between 200 and 400°C, a hydrogen partial pressure between 1.0 and 10.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h' ¹ , to obtain a hydrotreated effluent.

Advantageously, step c) implements hydrotreatment reactions well known to those skilled in the art, and more particularly hydrotreatment reactions such as the hydrogenation of aromatics, hydrodesulfurization and hydrodenitrogenation. In addition, the hydrogenation of the remaining olefins and halogenated compounds as well as the hydrodemetalation can continue even if the majority and preferably all of these impurities have been removed during step b).

Said hydrotreatment reaction section is advantageously carried out at an average hydrotreatment temperature between 200 and 400°C, preferably between 250 and 360°C, at a hydrogen partial pressure between 1.0 and 10.0 MPa abs. and at an hourly volumetric flow rate (WH) between 0.1 and 10.0 h ^-1 , preferably between 0.1 and 5.0 h ^-1 , preferentially between 0.2 and 2.0 h ^-1 , more preferably between 0.2 and 1h' ¹ . The hydrogen coverage in step d) is advantageously between 100 and 1500 Nm ³ of hydrogen per m ³ of the feedstock which feeds step d), and preferably between 120 and 1000 Nm ³ /m ³ , more preferably between 150 and 800 Nm ³ /m ³ . The definitions of the average temperature (WABT), the WH and the hydrogen coverage correspond to those described above. Compared to the processes for treating a feedstock comprising a pyrolysis oil which treat the entire pyrolysis oil (without prefractionation), the operating conditions of the hydrogenation step as well as those of the hydrotreatment step can be milder in the process according to the invention (in particular a lower temperature and/or a higher WH). Indeed, the sulfur and nitrogen impurities, in particular the most refractory ones, are found after prefractionation mainly in said heavy cut.

Advantageously, the reaction section of said step c) comprises between 1 and 5 reactors, preferably between 2 and 5 reactors. These reactors can operate in series and/or in parallel and/or in permutable mode (or PRS).

In a preferred embodiment, said hydrotreatment reaction section comprises a single fixed-bed reactor containing n catalytic beds, n being an integer greater than or equal to one, preferably between one and ten, more preferably between two and five. In a particularly preferred embodiment, the hydrogenation reaction section of step b) comprises two reactors operating in switchable mode followed by the hydrotreatment reaction section of step c) which comprises a single fixed-bed reactor.

In another embodiment, said hydrogenation reaction section and said hydrotreatment section may be located in a single (single) fixed bed reactor containing n catalytic beds, n being an integer greater than or equal to one, preferably between one and ten, more preferably between two and seven. In this case, the naphtha cut first passes through the hydrogenation reaction section and then the hydrotreatment section.

In another embodiment, there may be at least two reactors, preferably between 2 and 5 reactors, operating in switchable mode (PRS), each reactor containing a hydrogenation reaction section and then a hydrotreatment section.

Advantageously, reactor internals, for example of the filter tray type as described above, may be used to prevent clogging of the reactor(s).

Advantageously, said hydrotreatment catalyst may be chosen from known hydrodemetallization, hydrotreatment, silicon capture catalysts, used in particular for the treatment of petroleum fractions, and combinations thereof. Known hydrodemetallization catalysts are, for example, those described in patents EP 0113297, EP 0113284, US 5221656, US 5827421, US 7119045, US 5622616 and US 5089463. Known hydrotreatment catalysts are, for example, those described in patents EP 0113297, EP 0113284, US 6589908, US 4818743 or US 6332976. Known silicon capture methods are, for example, those described in patent applications CN 102051202 and US 2007/080099.

In particular, said hydrotreatment catalyst comprises a support, preferably mineral, and at least one metallic element having a hydro-dehydrogenating function. Said metallic element having a hydro-dehydrogenating function advantageously comprises at least one element from group VIII, preferably chosen from the group consisting of nickel and cobalt, and/or at least one element from group VI B, preferably chosen from the group consisting of molybdenum and tungsten. The total content expressed as oxides of the metallic elements from groups VI B and VIII is preferably between 0.1% and 40% by weight, preferably from 5% to 35% by weight, relative to the total weight of the catalyst. When the metal is cobalt or nickel, the metal content is expressed as CoO and NiO respectively. When the metal is molybdenum or tungsten, the metal content is expressed as MoOa and WO3 respectively. The weight ratio expressed as metal oxide between the metal (or metals) of group VIB relative to the metal (or metals) of group VIII is preferably between 1.0 and 20, preferably between 2.0 and 10. For example, the hydrotreatment reaction section of step d) of the process comprises a hydrotreatment catalyst comprising between 0.5% and 10% by weight of nickel, preferably between 1% and 8% by weight of nickel, expressed as nickel oxide NiO relative to the total weight of the hydrotreatment catalyst, and between 1.0% and 30% by weight of molybdenum, preferably between 3.0% and 29% by weight of molybdenum, expressed as molybdenum oxide MoOs relative to the total weight of the hydrotreatment catalyst, on a mineral support, preferably on an alumina support.

The support of said hydrotreatment catalyst is advantageously chosen from alumina, silica, silica-aluminas, magnesia, clays and mixtures thereof. Said support may also contain doping compounds, in particular oxides chosen from boron oxide, in particular boron trioxide, zirconia, ceria, titanium oxide, phosphoric anhydride and a mixture of these oxides. Preferably, said hydrotreatment catalyst comprises an alumina support, preferably an alumina support doped with phosphorus and optionally boron. When phosphoric anhydride P2O5 is present, its concentration is less than 10% by weight relative to the weight of the alumina and advantageously at least 0.001% by weight relative to the total weight of the alumina. When boron trioxide B2O3 is present, its concentration is less than 10% by weight relative to the weight of the alumina and advantageously at least 0.001% relative to the total weight of the alumina. The alumina used may be, for example, a γ (gamma) or (eta) alumina. Said hydrotreatment catalyst is for example in the form of extrudates.

Advantageously, said hydrotreatment catalyst of the process has a specific surface area greater than or equal to 250 m ² /g, preferably greater than or equal to 300 m ² /g. The specific surface area of said hydrotreatment catalyst is advantageously less than or equal to 800 m ² /g, preferably less than or equal to 600 m ² /g, in particular less than or equal to 400 m ² /g. The specific surface area of the hydrotreatment catalyst is measured by the BET method, i.e. the specific surface area determined by nitrogen adsorption in accordance with ASTM D 3663-78 established from the BRUNAUER-EMMETT-TELLER method described in the periodical The Journal of the American Chemical Society, 6Q, 309 (1938). Such a specific surface area makes it possible to further improve the removal of contaminants, in particular metals such as silicon.

According to another aspect of the invention, the hydrotreatment catalyst as described above further comprises one or more organic compounds containing oxygen and/or nitrogen and/or sulfur as described above (additive catalyst).

Preferably, step c) can implement upstream of the hydrotreatment catalyst(s) at least one guard bed or a series of guard beds of the “grading” type as described above for step b).

Advantageously, hydrotreatment step c) allows the hydrogenation of at least 80%, and preferably of all of the olefins and halogenated compounds remaining after hydrogenation step b), but also the conversion at least in part of other impurities present in the feedstock, such as aromatic compounds, metallic compounds, sulfur compounds, nitrogen compounds, oxygenated compounds. Preferably, the nitrogen content at the outlet of step c) is less than 100 ppm by weight, and preferably less than 10 ppm by weight. Preferably, the sulfur content at the outlet of step c) is less than 100 ppm by weight, and preferably less than 10 ppm by weight. Step c) can also make it possible to further reduce the contaminant content, such as that of metals, in particular the silicon content. Preferably, the metal content at the outlet of step c) is less than 10 ppm by weight, and preferably less than 2 ppm by weight, and the silicon content is less than 5 ppm by weight. Preferably, the halogen element content at the outlet of step c) is less than 5 ppm by weight.

The hydrotreated effluent from hydrotreatment step c) is then sent, in part or in full, to a separation step d).

Any reaction section of steps b) and c) is advantageously fed at the level of the first catalytic bed of the first reactor in operation. An injection of at least one part of the charge and/or at least part of hydrogen between the different catalytic beds is also possible.

Any reaction section of steps b) and c) implementing at least one fixed-bed reactor can operate with a descending or ascending flow of gas and liquid.

The gas stream comprising hydrogen, which feeds at least one reaction section of steps b) and c) may consist of a hydrogen make-up and/or recycled hydrogen and/or hydrogen originating from the upstream step. The gas stream comprising hydrogen may come from a fossil source or a renewable source, for example from the gasification of plastic waste or produced by electrolysis.

Preferably, an additional gas flow comprising hydrogen is advantageously introduced at the inlet of each reactor, in particular operating in series, and/or at the inlet of each catalytic bed from the second catalytic bed of the reaction section.

The preparation of the catalysts of steps b) and c) is known and generally comprises a step of impregnation of the metals of group VIII and group VIB when present, and possibly phosphorus and/or boron on the support, followed by drying, then possibly calcination. In the case of an additive catalyst, the preparation is generally carried out by simple drying without calcination after introduction of the organic compound. Here, calcination means a heat treatment under a gas containing air or oxygen at a temperature greater than or equal to 200°C. Before their use in a step of the process, the catalysts are generally subjected to sulfurization in order to form the active species. When the catalyst is a catalyst used in its reduced form, the preparation involves a reduction step.

Depending on the content of sulfur compounds in the initial feed to be treated, a stream containing a sulfurizing agent can be injected upstream of the optional pretreatment step and/or the hydrogenation step and/or the optional hydrotreatment step, preferably upstream of the hydrogenation step and/or the hydrotreatment step in order to ensure a sufficient quantity of sulfur to form the active species of the catalyst (in sulfide form).

This activation or sulfurization step is carried out by methods well known to those skilled in the art, and advantageously under a sulfide-reducing atmosphere in the presence of hydrogen and hydrogen sulfide. The sulfurizing agents are preferably H2S gas, elemental sulfur, CS2, mercaptans, sulfides and/or polysulfides, fractions hydrocarbons with a boiling point below 400°C containing sulfur compounds or any other sulfur-containing compound used for the activation of hydrocarbon feedstocks in order to sulfurize the catalyst. Said sulfur-containing compounds are advantageously chosen from alkyl disulfides such as, for example, dimethyl disulfide (DMDS), alkyl sulfides, such as, for example, dimethyl sulfide, thiols such as, for example, n-butyl mercaptan (or 1-butanethiol) and polysulfide compounds of the tert-onylpolysulfide type. The catalyst can also be sulfurized by the sulfur contained in the feedstock to be desulfurized. Preferably, the catalyst is sulfurized in situ in the presence of a sulfurizing agent and a hydrocarbon feedstock. Very preferably, the catalyst is sulfurized in situ in the presence of the feedstock with added dimethyl disulfide. The injection of a sulfurizing agent is particularly necessary at the beginning of the catalytic cycle, while the hLS is forming. Additional injections throughout the catalytic cycle may be necessary to compensate for the natural loss.

Step d) washing/separation

According to the invention, the process comprises a separation step d), fed with at least part and preferably all of the hydrogenated effluent from step b) or with the hydrotreated effluent from step c) and an aqueous solution, said step being carried out in a separation section at a temperature between 30 and 300°C, to obtain at least one gaseous effluent, one aqueous effluent and a naphtha cut freed from its impurities and part of which is recycled in step b).

This washing/separation step makes it possible in particular to eliminate the ammonium chloride salts, which are formed by reaction between the chloride ions, released by the hydrogenation of the chlorinated compounds in HCl form, in particular during the hydrogenation step then dissolution in water, and the ammonium ions, generated in particular by the hydrogenation of the nitrogen compounds in the form of NH ₃ during the hydrogenation and/or hydrotreatment step and/or supplied by injection of an amine then dissolution in water, and thus to limit the risks of blockage, in particular in the transfer lines and/or in the sections of the process of the invention and/or the transfer lines to the steam cracker, due to the precipitation of the ammonium chloride salts. This step also removes hydrochloric acid formed by the reaction of hydrogen ions and halide ions released by the hydrogenation of halogenated compounds during the hydrogenation step which dissolve in the aqueous solution. When H2S is formed, the washing/separation step also removes ammonium sulfide salts (NH^S) which are formed by the reaction between H2S resulting from the hydrodesulfurization of sulfur compounds and NH3 by dissolving them in aqueous solution.

The washing/separation step is advantageously carried out at a temperature between 20 and 300°C, preferably between 25 and 200°C, preferably between 30 and 150°C, and particularly preferably between 30 and 100°C. Advantageously, the washing/separation step is carried out at a pressure close to that used in the hydrotreatment step, preferably between 1.0 and 10.0 MPa abs, so as to facilitate the recycling of hydrogen.

The aqueous solution can be water. It can also be a basic aqueous solution (by adding NaOH for example). Using a basic solution helps neutralize hydrogen halides and any dissolved salts.

Said separation section may comprise any separation means known to those skilled in the art, in particular one or more separator drums arranged in series, and/or one or more steam and/or hydrogen stripping columns, and/or an atmospheric distillation column, and/or a vacuum distillation column. The washing/separation step may advantageously be carried out in common or separate washing and separation equipment, this equipment being well known (separator drums capable of operating at different pressures and temperatures, pumps, heat exchangers, washing columns, etc.).

Advantageously, the washing/separation step comprises an injection of an aqueous solution, preferably an injection of water, into the hydrogenated or hydrotreated effluent, upstream of the washing/separation section, so as to dissolve at least in part and preferably all of the hydrogen halides (HCl in particular) and any salts present.

In a possible embodiment of the invention, the washing/separation step comprises the injection of an aqueous solution into the hydrogenated or hydrotreated effluent, followed by the washing/separation section advantageously comprising a separation phase making it possible to obtain at least one aqueous effluent loaded with hydrogen halides (HCl in particular) and any dissolved salts, said naphtha cut freed from these impurities and a partially washed gaseous effluent. Said aqueous effluent and the washed naphtha cut can then be separated in a settling tank in order to obtain said washed naphtha cut and said aqueous effluent. Said partially washed gaseous effluent can in parallel be introduced into a washing column where it circulates countercurrent to an aqueous flow, preferably of the same nature as the aqueous solution injected into the hydrotreated effluent, which makes it possible to eliminate at least in part, preferably in full, the hydrochloric acid contained in the partially washed gaseous effluent and thus obtain said gaseous effluent, preferably essentially comprising hydrogen, and an acidic aqueous stream. Said aqueous effluent from the settling tank may optionally be mixed with said acidic aqueous stream, and be used, optionally in a mixture with said acidic aqueous stream in a water recycling circuit to supply the washing/separation step with said aqueous solution upstream of the washing/separation section and/or with said aqueous stream in the washing column. Said water recycling circuit may include a make-up of water and/or a basic solution and/or a purge to remove impurities.

According to one embodiment, and depending on the content of chlorinated compounds in said naphtha cut obtained after prefractionation, a stream containing a nitrogen compound such as ammonia or an amine, for example monoethanolamine, diethanolamine, monodiethanolamine and/or aniline, may be injected upstream of the hydrogenation step and/or upstream of the hydrotreatment step in order to ensure a sufficient quantity of ammonium ions to combine the chloride ions formed during the hydrotreatment step in the form of ammonium chloride salts, thus making it possible to limit the formation of hydrochloric acid and thus to limit corrosion downstream of the separation section.

Said gaseous effluent obtained at the end of the washing/separation step advantageously comprises hydrogen, preferably comprises at least 60% by volume, preferably at least 70% by volume, of hydrogen. Said gaseous effluent obtained at the end of the washing/separation step contains very little chlorine, generally at a content of less than 3 ppm by weight of chlorine, which makes it possible to send it to a refining unit requiring hydrogen. According to one embodiment, said gaseous effluent can at least partly be recycled to one of the steps of the process according to the invention requiring hydrogen (steps b) and/or c)), the recycling system being able to comprise a purification section (for example adsorption of heavy metals such as mercury).

The aqueous effluent obtained from the washing/separation step advantageously comprises ammonium salts and/or hydrochloric acid.

After separation of the gaseous effluent, said naphtha cut, freed from its impurities and washed, is preferably sent to a steam stripping stage preferably operating at a pressure of between 0.5 and 2 MPa abs, to separate the hydrogen sulfide (H2S) dissolved in said naphtha cut, freed from its impurities.

A portion of said naphtha cut from step d) is recycled upstream of the hydrogenation step, and possibly upstream of the hydrotreatment step. According to a variant, part or all of said naphtha cut from step d) and recycled to the hydrogenation and/or hydrotreatment step can advantageously be either cooled, or preheated, if necessary, or kept at the same temperature. The temperature changes of all or part of said recycled naphtha cut will be made by any means known to those skilled in the art (exchanger, air cooler, furnace, etc.) and will make it possible to adjust the temperature profile (inlet temperature, delta T) of the catalytic beds of the hydrogenation and/or hydrotreatment steps as required.

According to one embodiment, another part of said naphtha cut from step d) can also be sent in part or in full to a fuel storage unit, for example a naphtha storage unit, from conventional petroleum feedstocks.

According to another preferred embodiment, another part of said naphtha cut from step d) is sent directly to the inlet of a steam cracking unit.

Advantageously, the process according to the invention allows the hydrogenation of at least 80%, and preferably of all of the olefins (mono- and diolefins), but also the conversion at least in part of other impurities present in said naphtha cut obtained after prefractionation, such as aromatic compounds, metallic compounds, sulfur compounds, nitrogen compounds, halogenated compounds (in particular chlorinated compounds), oxygenated compounds.

Preferably, said naphtha cut obtained after separation step d) has a nitrogen content of less than 10 ppm by weight, preferably less than 5 ppm by weight.

Preferably, said naphtha cut obtained after separation step d) has a sulfur content of less than 10 ppm by weight.

Preferably, said naphtha cut obtained after separation step d) has an oxygen content of less than 10 ppm by weight.

Preferably, said naphtha cut obtained after separation step d) has a metal content of less than 10 ppm by weight, preferably less than 2 ppm by weight, and the silicon content is less than 5 ppm by weight.

Preferably, said naphtha cut obtained after separation step d) has a halogen content (in particular chlorine) of less than 3 ppm by weight.

The contents are given in relative weight concentrations, percentage (%) by weight, part(s) per million (ppm) by weight or part(s) per billion (ppb) by weight, relative to the total weight of the flow considered. Steam cracking step (optional)

A portion of said naphtha cut freed from its impurities from step d) can be sent to a steam cracking step, possibly mixed with a fossil feedstock suitable for the steam cracker.

Said steam cracking step is advantageously carried out in at least one pyrolysis furnace at a temperature between 700 and 900°C, preferably between 750 and 850°C, and at a pressure between 0.05 and 0.3 MPa relative. The residence time of the hydrocarbon compounds is generally less than or equal to 1.0 seconds (denoted s), preferably between 0.1 and 0.5 s. Advantageously, water vapor is introduced upstream of the steam cracking step and after the separation (or fractionation). The quantity of water introduced, advantageously in the form of water vapor, is advantageously between 0.3 and 3.0 kg of water per kg of hydrocarbon compounds at the inlet of the steam cracking step. Preferably, the steam cracking step is carried out in several pyrolysis furnaces in parallel so as to adapt the operating conditions to the different streams, and also to manage the decoking times of the tubes. A furnace comprises one or more tubes arranged in parallel. A furnace can also designate a group of furnaces operating in parallel. For example, one furnace can be dedicated to cracking the naphtha cut and another dedicated to the middle distillate cut.

The effluents from the various steam cracking furnaces are generally recombined before separation in order to constitute an effluent. It is understood that the steam cracking stage includes the steam cracking furnaces but also the sub-stages associated with steam cracking well known to those skilled in the art. These sub-stages may include in particular heat exchangers, columns and catalytic reactors and recycles to the furnaces. A column generally makes it possible to fractionate the effluent in order to recover at least a light fraction comprising hydrogen and compounds having 2 to 5 carbon atoms, and a fraction comprising pyrolysis gasoline, and possibly a heavier fraction. Columns make it possible to separate the different constituents of the light fractionation fraction in order to recover at least an ethylene-rich cut (C2 cut) and a propylene-rich cut (C3 cut) and possibly a butene-rich cut (C4 cut). Catalytic reactors are used in particular to carry out hydrogenation of C2, C3 and even C4 cuts and pyrolysis gasoline. Saturated compounds, particularly saturated compounds with 2 to 4 carbon atoms, are advantageously recycled to steam cracking furnaces in order to increase overall olefin yields. This steam cracking step makes it possible to obtain at least one effluent containing olefins comprising 2, 3 and/or 4 carbon atoms (i.e. C2, C3 and/or C4 olefins), at satisfactory contents, in particular greater than or equal to 30% by weight, in particular greater than or equal to 40% by weight, or even greater than or equal to 50% by weight of total olefins comprising 2, 3 and 4 carbon atoms relative to the weight of the steam cracking effluent in question. Said C2, C3 and C4 olefins can then be advantageously used as polyolefin monomers.

Valorization of heavy cutting

One or more further processing stages of the heavy cut, or of the other cut(s) from the heavy cut during prefractionation stage a) (middle distillate cut including a diesel cut and a kerosene cut, vacuum diesel cut) other than the naphtha cut, may be carried out in order to recover them.

Such a step may include at least one step chosen from the list consisting of hydrotreatment, steam cracking, hydrocracking or fluidized bed catalytic cracking. These examples of further treatment are not exhaustive.

The further processing steps may be carried out on a single cut or several of the cuts resulting from step a) of prefractionation in a mixture, alone or in a mixture with an oil feedstock and/or a feedstock resulting from the conversion of the biomass.

Hydrotreatment

Given the impurities contained in the heavy cut or in the other cut(s) from the heavy cut during prefractionation step a), hydrotreatment is generally necessary before the cut(s) can be sent either to other subsequent treatments or to a storage unit in order to protect the catalysts from subsequent treatments or to meet the required specifications.

Hydrotreatment can be carried out on the heavy cut (whole) or on the middle distillate cut including a diesel cut and a kerosene cut, or on the vacuum diesel cut from prefractionation step a), alone or in a mixture.

Co-processing can also be carried out by mixing the heavy cut, or the other cut(s) from the heavy cut with a petroleum feedstock and/or a feedstock from biomass conversion. Such feedstocks are gasolines, diesels, vacuum diesels, atmospheric residues, vacuum residues, atmospheric distillates, vacuum distillates, heavy fuel oils, oils, waxes and paraffins, used oils, residues or deasphalted crudes, feedstocks from thermal or catalytic conversion processes, lignocellulosic feedstocks or more generally feedstocks from biomass such as vegetable oils, algae or algal oils, fish oils, used cooking oils, and fats of vegetable or animal origin, taken alone or in a mixture.

According to a first embodiment, the heavy (whole) cut from the prefractionation step is subjected to a hydrotreatment step implemented in a hydrotreatment section, preferably in a fixed bed, which is carried out under the operating conditions and with hydrotreatment catalysts as described for the hydrotreatment step c) of the naphtha cut.

According to a second embodiment, a hydrotreatment dedicated to each cut can be carried out, in particular a hydrotreatment dedicated to the middle distillate cut (including a diesel cut or a kerosene cut) and/or a hydrotreatment dedicated to the vacuum diesel cut.

According to one embodiment of this embodiment, the middle distillate cut and/or the vacuum gas oil cut may be sent to a dedicated hydrotreatment section which is different from the hydrotreatment section of the naphtha cut of step c). In this case, the operating conditions, in particular the temperature and the pressure, may be higher than those of the hydrotreatment step of the naphtha cut in order to eliminate the sulfur and nitrogen-based impurities which are often more significant and refractory in this cut.

In this case, at least a portion of said heavy cut, or of said middle distillate cut and/or of said vacuum gas oil cut may be subjected to a dedicated hydrotreatment step, in a hydrotreatment reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrotreatment catalyst, said hydrotreatment reaction section being fed at least by said heavy cut, or said middle distillate cut and/or said vacuum gas oil cut and a gas stream comprising hydrogen, said hydrotreatment reaction section being implemented at an average temperature between 250 and 430°C, a hydrogen partial pressure between 1.0 and 10.0 MPa abs. and an hourly volumetric velocity between 0.1 and 10.0 h ^-1 , to obtain a heavy hydrotreated effluent.

The middle distillate cut freed from its impurities can then be introduced, alone or in a mixture with the naphtha cut freed from its impurities, into a steam cracking unit or be sent to a fuel storage unit, for example a unit diesel storage or a kerosene storage unit, from conventional petroleum feedstocks or even be recycled in a step of the process according to the invention, for example in steps b) and/or c).

The vacuum gas oil cut freed from its impurities can then be introduced, alone or mixed with the middle distillate cut, into a hydrocracking unit or into a fluidized bed catalytic cracking unit or even be recycled in a stage of the process according to the invention, for example in stages b) and/or c).

Hydrocracking

The hydrotreated heavy effluent (the hydrotreated heavy cut, or the hydrotreated middle distillate cut and/or the hydrotreated vacuum gas oil cut) from the heavy cut during the prefractionation step a) can then be introduced into a hydrocracking step which converts the cut into lighter and more valuable products (naphtha, middle distillates). Compounds with a boiling point above 175°C contain, compared to lighter compounds, more naphthenic, naphtheno-aromatic and aromatic compounds, thus leading to a higher C/H ratio. This high ratio is a cause of coking in the steam cracker, thus requiring steam cracking furnaces dedicated to this cut. When we want to minimize the yield of these heavy compounds (middle distillate cut) and maximize the yield of light compounds (naphtha cut), we can transform these compounds at least in part into light compounds by hydrocracking, a cut generally favored for a steam cracking unit.

Co-processing can also be carried out by mixing the hydrotreated heavy cut or the hydrotreated middle distillate cut and/or the hydrotreated vacuum gas oil cut with a petroleum feedstock and/or a feedstock from biomass conversion. Such a feedstock is generally a hydrocarbon feedstock of which at least 50% by weight of the compounds have an initial boiling point above 300°C and a final boiling point below 650°C. It can be chosen from HCO (Heavy Cycle Oil according to the English terminology (heavy gas oils from a catalytic cracking unit)), vacuum distillates, for example gas oils from the direct distillation of crude or from conversion units such as catalytic cracking, coker or visbreaking, feedstocks from aromatic extraction units, lubricating oil bases or from solvent dewaxing of lubricating oil bases, distillates from fixed bed or ebullated bed desulfurization or hydroconversion processes of atmospheric residues and/or vacuum residues and/or deasphalted oils, or the feedstock can be a deasphalted oil or include vegetable oils or even come from the conversion of feedstocks from biomass. It can also be paraffins from the Fischer-Tropsch process. Said feedstock may also be a mixture of said feedstocks mentioned above. Preferably, when coprocessing is desired, the co-feedstock is a vacuum distillate.

The hydrocracking is carried out in a hydrocracking reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrocracking catalyst, said hydrocracking reaction section being fed with said hydrotreated heavy effluent (the hydrotreated heavy cut, or the hydrotreated middle distillate cut and/or the hydrotreated vacuum gas oil cut), and a gas stream comprising hydrogen, said hydrocracking reaction section being carried out at an average temperature between 250 and 480°C, a hydrogen partial pressure between 1.5 and 20.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h' ¹ , to obtain a hydrocracked effluent.

Thus, said hydrocracking reaction section is advantageously carried out at an average temperature between 250 and 480°C, preferably between 320 and 450°C, at a hydrogen partial pressure between 1.5 and 20.0 MPa abs., preferably between 2 and 18.0 MPa abs., and at an hourly volumetric flow rate (WH) between 0.1 and 10.0 h' ¹ , preferably between 0.1 and 5.0 h' ¹ , preferentially between 0.2 and 4 h' ¹ . The hydrogen coverage in the hydrocracking step is advantageously between 80 and 2000 Nm ³ of hydrogen per m ³ of feedstock feeding the hydrocracking step, and preferably between 200 and 1800 Nm ³ of hydrogen per m ³ of feedstock feeding the hydrocracking step. The definitions of the average temperature (WABT), the WH and the hydrogen coverage correspond to those described above.

The hydrotreatment step and the hydrocracking step can advantageously be carried out in the same reactor or in different reactors. In the case where they are carried out in the same reactor, the reactor comprises several catalytic beds, the first catalytic beds comprising the hydrotreatment catalyst(s) and the following catalytic beds comprising the hydrocracking catalyst(s).

The hydrocracking step can be carried out in one or two stages. When it is carried out in two stages, a separation of the effluent from the first hydrocracking stage is carried out to obtain a heavy cut (middle distillate cut and/or unreacted vacuum gas oil cut), which is introduced into the second hydrocracking stage comprising a second dedicated hydrocracking reaction section, different from the first hydrocracking reaction section. This configuration is particularly suitable when it is desired to produce only a naphtha cut. The preferred operating conditions and catalysts used in the second hydrocracking stage are those described for the first hydrocracking stage. The operating conditions and catalysts used in the two hydrocracking stages may be identical or different.

The hydrocracking catalyst(s) used in the hydrocracking step(s) are conventional hydrocracking catalysts known to those skilled in the art, of the bifunctional type combining an acid function with a hydro-dehydrogenating function and optionally at least one binding matrix. The acid function is provided by supports with a large surface area (generally 150 to 800 m ² /g) having a surface acidity, such as halogenated aluminas (chlorinated or fluorinated in particular), combinations of boron and aluminum oxides, amorphous silica-aluminas and zeolites. The hydro-dehydrogenating function is provided by at least one metal from group VI B of the periodic table and/or at least one metal from group VIII. Hydro-dehydrogenating functions of the NiMo, NiMoW, NiW type are preferred.

Metal contents are generally as described for hydrotreating catalysts.

Hydrocracking catalysts may also contain phosphorus and/or an organic compound containing oxygen and/or nitrogen and/or sulfur in levels as described for hydrotreating catalysts.

The hydrocracked effluent is then generally subjected to a fractionation step to recover lighter cuts, for example a naphtha cut and at least one middle distillate cut, and an unconverted cut which can be recycled in the hydrocracking step. The naphtha cut and/or at least one middle distillate cut can then be sent to a steam cracking unit or be sent to a fuel storage unit or even be recycled in a step of the process according to the invention, for example in steps b) and/or c).

FCC

The heavy cut, or the middle distillate cut and/or the vacuum diesel cut, from the heavy cut during prefractionation step a), hydrotreated or not, can also be subjected to a fluidized bed catalytic cracking step (FCC for Fluid Catalytic Cracking according to the English terminology) to produce products such as high octane gasoline, light fuel oil, heavy fuel oil, light olefin-rich gas (propylene, butylene) and coke.

Co-processing can also be carried out by mixing the heavy cut, or the middle distillate cut and/or the vacuum diesel cut, hydrotreated or not, with a petroleum feedstock and/or a feedstock from biomass conversion. Such a feedstock is a atmospheric diesel, vacuum diesel and atmospheric residue, a lignocellulosic feedstock or more generally a feedstock from biomass, taken alone or in a mixture.

The FCC unit uses a high activity zeolite catalyst to crack heavy hydrocarbon molecules. A conventional FCC unit is used. For example, a brief description of catalytic cracking (first industrially implemented in 1936 (HOUDRY process) or in 1942 for the use of fluidized bed catalyst) can be found in ULLMANS ENCYCLOPEDIA OF INDUSTRIAL CHEMISTRY VOLUME A 18, 1991, pages 61 to 64. The choice of catalyst and operating conditions depend on the desired products depending on the feedstock being treated, as described, for example, in the article by M. MARCILLY pages 990-991 published in the journal of the French Petroleum Institute Nov.-Dec. 1975 pages 969-1006.

Fluidized bed catalytic cracking is generally carried out in a fluidized bed catalytic cracking reaction section in a substantially vertical reactor either in riser mode or in downer mode in the presence of the heavy cut or the middle distillates cut and/or the vacuum gas oil cut and a zeolite catalyst at a reactor temperature between 450°C and 600°C with a contact time in the reactor of less than 1 minute, often from 0.1 to 50 seconds.

A conventional zeolite catalyst comprising a matrix, optionally an additive and at least one zeolite is usually used in the FCC process. The amount of zeolite is variable but usually 3 to 60% by weight, often 6 to 50% by weight and most often 10 to 45% by weight relative to the weight of the catalyst. The zeolite is usually dispersed in the matrix. The amount of additive is usually 0 to 30% by weight and often 0 to 20% by weight relative to the weight of the catalyst. The amount of matrix represents the balance to 100% by weight. The additive is generally selected from the group formed by the oxides of the metals of group HA of the periodic table of elements such as for example magnesium oxide or calcium oxide, the oxides of the rare earths and the titanates of the metals of group HA. The matrix is most often silica, alumina, silica-alumina, silica-magnesia, clay, or a mixture of two or more of these. The most commonly used zeolite is zeolite Y.

(Optional) heavy metal adsorption step

Any gaseous effluent and/or any liquid effluent from separation step d) may be subjected to an optional heavy metal adsorption step. The optional adsorption step makes it possible to eliminate or reduce the quantity of metallic impurities, in particular the quantity of heavy metals such as arsenic, zinc, lead, and in particular mercury, possibly present in said gaseous and liquid effluents. The metallic impurities, and in particular the heavy metals, are present in the feedstock. Certain impurities, in particular mercury-based, can be transformed in one of the steps of the process according to the invention. Their transformed form is easier to trap. Their elimination or reduction may in particular be necessary when at least part of said gaseous and liquid effluents is intended to be sent, either directly or after having undergone one or more optional additional separation steps, to a step having strict specifications for metallic impurities, such as a steam cracking step.

Thus, an optional step of adsorption of a gaseous effluent and/or a hydrocarbon effluent from the process according to the invention is advantageously carried out in particular when at least one of these effluents or the feed respectively comprises more than 20 ppb by weight, in particular more than 15 ppb by weight of heavy metal metallic elements (As, Zn, Pb, Hg, etc.), and in particular when at least one of these effluents or the feed respectively comprises more than 10 ppb by weight of mercury, more particularly more than 15 ppb by weight of mercury.

Said optional adsorption step is advantageously carried out at a temperature between 20 and 250°C, preferably between 40 and 200°C, and at a pressure between 0.15 and 10.0 MPa abs, preferably between 0.2 and 1.0 MPa abs.

Said optional adsorption step can be implemented by any adsorbent known to those skilled in the art making it possible to reduce the quantity of such contaminants.

According to a variant, said optional adsorption step is implemented in an adsorption section operated in the presence of at least one adsorbent comprising a porous support, and optionally at least one active phase which may be based on sulfur in elemental form, or in the form of metal sulfide or metal oxide, or even in metallic form in elemental form.

The porous support can be chosen from the families of aluminas, silica-aluminas, silicas, zeolites and/or activated carbons. Advantageously, the porous support is based on alumina.

Said adsorption section may comprise one or more adsorption columns. When the adsorption section comprises two adsorption columns, a mode of operation may be a so-called "swing" operation, according to the established Anglo-Saxon term, in which one of the columns is online, i.e. in operation, while the other column is in reserve. Another mode of operation is to have at least two columns operating in series in permutable mode. Preferably, said adsorption section comprises an adsorption column for the gaseous effluent(s) and an adsorption column for the liquid effluent(s).

Analysis methods used

The analysis methods and/or standards used to determine the characteristics of the various flows, in particular the load to be treated and the effluents, are known to those skilled in the art. They are in particular listed below for information purposes in Table 1. Other methods deemed equivalent may also be used, in particular equivalent IP, EN or ISO methods:

(1) Méthode MAV décrite dans l’article : C. Lôpez-Garcia et al., Near Infrared Monitoring of Low Conjugated Diolefins Content in Hydrotreated FCC Gasoline Streams, Oil & Gas Science and Technology - Rev. IFP, Vol. 62 (2007), No. 1, pp. 57-68 Table 1

(1) MAV method described in the article: C. Lôpez-Garcia et al., Near Infrared Monitoring of Low Conjugated Diolefins Content in Hydrotreated FCC Gasoline Streams, Oil & Gas Science and Technology - Rev. IFP, Vol. 62 (2007), No. 1, pp. 57-68

LIST OF FIGURES

The mention of the elements referenced in Figure 1 allows a better understanding of the invention, without it being limited to the particular embodiments illustrated in Figure 1. The different embodiments presented can be used alone or in combination with each other, without limitation of combination.

Figure 1 represents the diagram of a particular embodiment of the method of the present invention, comprising:

- a step a) of prefractionation of a feedstock comprising a plastic pyrolysis oil and/or tires and/or recovered solid fuels 1 to obtain a naphtha cut 2, a middle distillate cut 3 and a vacuum diesel oil (VGO) cut 4.

- a hydrogenation step b) carried out in a reaction section supplied by said naphtha cut 2 and a gas stream comprising hydrogen 5, in the presence of at least one hydrogenation catalyst, and optionally an amine supplied by stream 6 and optionally a sulfur compound by stream 7, to obtain a hydrogenated effluent 8;

- a step c) of hydrotreatment of the hydrogenated effluent 8 from step b), in the presence of hydrogen 9 carried out in at least one fixed-bed reactor comprising at least one hydrotreatment catalyst, to obtain a hydrotreated effluent 10;

- a separation step d), supplied with the hydrotreated effluent 10 from step c) and an aqueous solution 11, said step being carried out at a temperature between 20 and 300°C, to obtain at least one gaseous effluent 12, one aqueous effluent 13 and a naphtha cut freed from these impurities 14, a part 15 of which is recycled in step b).

At the end of step d), another part of the naphtha cut freed from these impurities 14 can be sent to a steam cracking process (not shown). Another part of the naphtha cut freed from these impurities 14 can also feed the hydrotreatment step c) (not shown).

The middle distillate cut 3 can be sent to a dedicated hydrotreatment stage, undergo stripping to remove in particular hydrogen and H2S, then be sent to a fuel storage unit, for example a diesel storage unit or a kerosene storage unit, from conventional petroleum feedstocks (not shown). The vacuum gas oil (VGO) 4 cut, and possibly the middle distillate cut, can be introduced into a dedicated hydrotreatment stage, then into a hydrocracking stage, undergo a separation stage to remove in particular the hydrogen and the H2S and a heavy cut which has not been hydrocracked, then be sent to a fuel storage unit, for example a diesel storage unit or a kerosene storage unit, from conventional petroleum feedstocks (not shown).

Only the main steps, with the main flows, are shown in Figure 1, in order to allow a better understanding of the invention. It is understood that all the equipment necessary for operation is present (balloons, pumps, exchangers, furnaces, columns, etc.), even if not shown. It is also understood that hydrogen-rich gas flows (make-up or recycle), as described above, can be injected at the inlet of each reactor or catalytic bed or between two reactors or two catalytic beds. Means well known to those skilled in the art for purifying and recycling hydrogen can also be implemented.

EXAMPLE

Feedstock 1 treated in the process is a plastic pyrolysis oil (i.e. comprising 100% by weight of said plastic pyrolysis oil).

Charge 1 is subjected to a prefractionation step a) to obtain a naphtha cut 2 having a boiling point between 36 and 180°C and a heavy cut (distillates 180°C+) having a boiling point above 180°C. The characteristics of the charge and the cuts are indicated in Table 2.

Thanks to fractionation, certain impurities that are particularly harmful to the steam cracking unit are found to be more concentrated in the light naphtha fraction. This concerns chlorinated and silica compounds, monoolefins and diolefins.

Conversely, these same compounds are deconcentrated from the heavier 180°C+ fraction, which favors their treatment in downstream units directly in co-processing. In particular, the chlorinated/silicon content obtained within the heavy cut (Cl = 30 ppm weight, Si = 15 ppm weight) after prefractionation makes it possible to incorporate this fraction directly into the FCC unit feed. Table 2: Characteristics of the load and cuts after prefractionation

The naphtha cut 2 is subjected to a hydrogenation step b) carried out in a fixed bed reactor and in the presence of hydrogen 5 as well as a recycle of a fraction of the hydrotreated naphtha cut 15 from the separation step d) and a hydrogenation catalyst of the type

NiMo on alumina under the conditions indicated in Table 3.

Table 3: Conditions for hydrogenation step b)

(2) Here defined in relation to the volume of total liquid charge under standard conditions, i.e. fresh charge + liquid recycle

(3) Defined as the following weight ratio: hydrotreated naphtha mass flow rate from step d)/fresh naphtha feed mass flow rate)

At the end of hydrogenation step b), all the diolefins and monoolefins initially present in the feedstock have been converted. Given the high exothermicity of the reactions involved, the concentration of monoolefins/diolefins within the naphtha feedstock poses a challenge in terms of controlling the thermal profile.

In the process according to the invention and according to table 3, the implementation of strong liquid recycling at the inlet of the first bed allows control of reaction exotherms.

The hydrogenated effluent from hydrogenation step b) is subjected directly, without separation, to a hydrotreatment step c) carried out in a fixed bed and in the presence of hydrogen 9, and a NiMo-on-alumina hydrotreatment catalyst under the conditions presented in Table 4. A fraction of the hydrogen-rich gas 12 from separation step d) is mixed with the hydrogenated effluent from step b) in order to satisfy the average temperature and H2/HC ratio criteria of hydrotreatment step c). Table 4: Conditions of hydrotreatment step c)

(4) Here defined in relation to the total liquid charge volume under standard conditions, i.e. fresh charge + liquid recycle/quench if applicable

At the end of hydrotreatment step c), the sulfur and nitrogen compounds as well as the aromatics are converted sufficiently to meet the steam cracker input specifications (Table 6). From an exothermic reaction point of view, it should be noted that:

On the one hand, the reconcentration phenomenon observed for olefins/diolefins within the naphtha cut is not valid for sulfur, nitrogen and aromatic compounds

The exotherm of the hydrodenitrogenation, hydrodesulfurization and hydrogenation reactions of aromatics is lower than for the hydrogenation of olefins.

Thus, according to Table 4, the temperature difference between the inlet and outlet of the hydrotreatment reactor does not pose a problem (AT < 5°C) in the process according to the invention.

The hydrotreated effluent 10 from hydrotreatment step c) is subjected to a separation step d) in which a stream of water is injected into the effluent from hydrotreatment step c); the mixture having reached a temperature of 45°C, it is then separated in a separator drum so as to obtain a hydrogen-rich gaseous effluent sent to an acid gas scrubbing column and a liquid effluent which is then treated in a two-phase separator drum so as to obtain an aqueous effluent and a washed naphtha cut. The washed naphtha cut is then partly recycled to hydrogenation step b) in order to control the reaction exotherms and partly directed into a stripping column so as to obtain a naphtha cut freed from its impurities. The yields and qualities obtained after separation are indicated in Table 5 (the yields corresponding to the ratios of the mass quantities of the different products obtained in relation to the mass of charge upstream of step b), expressed as a percentage and noted % m/m).

Les caractéristiques de la coupe liquide naphta PI+ obtenue après l’étape d) de séparation sont présentés tableau 6 : Table 5: Yields of the different products obtained after separation and fractionation

The characteristics of the liquid naphtha PI+ cut obtained after separation step d) are presented in table 6:

Table 6: characteristics of the liquid naphtha PI+ cut

The PI+ naphtha cut has a composition compatible with a steam cracking unit since:

- it does not contain diolefins and few monoolefins;

- it has a very low chlorine element content (content not detected) and lower than the limit required for a steam cracker load (< 50 ppb weight);

- it has very low metal contents, in particular iron (Fe) and silicon (metal content not detected; Fe content not detected; Si content < 0.2 ppm wt) and below the limits required for a steam cracker feed (< 5.0 ppm wt, very preferably < 1 ppm wt for metals; < 100 ppb wt for Fe; < 0.6 ppm weight for Si);

- finally it contains little sulfur (2 ppm by weight) and little nitrogen (<5 ppm by weight), these contents are much lower than the limits required for a steam cracker load (<500 ppm by weight, preferably <200 ppm by weight for S and N).

Claims

1. A method for treating a feedstock comprising a plastic and/or tire and/or solid recovered fuel pyrolysis oil, said method comprising the following steps: a) a step of prefractionating the feedstock to obtain a naphtha cut and at least one heavier cut, b) a hydrogenation step carried out in a hydrogenation reaction section, using at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrogenation catalyst, said hydrogenation reaction section being fed at least with said naphtha cut from step a) in a mixture with at least a portion of the naphtha cut from step d) and a gas stream comprising hydrogen, said hydrogenation reaction section being carried out at an average temperature between 120 and 380°C, a partial pressure of hydrogen between 1.0 and 10.0 MPa abs. and an hourly volumetric velocity between 0.1 and 10.0 IT ^1. to obtain a hydrogenated effluent, c) optionally a hydrotreatment step implemented in a hydrotreatment reaction section, implementing at least one fixed bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrotreatment catalyst, said hydrotreatment reaction section being fed at least by said hydrogenated effluent from step b) and a gas stream comprising hydrogen, said hydrotreatment reaction section being implemented at a temperature between 200 and 400°C, a partial pressure of hydrogen between 1.0 and 10.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h' ¹ , to obtain a hydrotreated effluent, d) a separation step, fed with the hydrogenated effluent from step b) or with the hydrotreated effluent from step c) and an aqueous solution, said step being carried out in a separation section at a temperature between 20 and 300°C, to obtain at least one gaseous effluent, an aqueous effluent and a naphtha cut, part of which is recycled in step b). 2. Process according to claim 1 comprising step c) of hydrotreatment. 3. Process according to the preceding claim, in which another part of the naphtha cut obtained in step d) is sent to a steam cracking unit. 4. Method according to the preceding claim, in which the steam cracking is carried out in at least one pyrolysis furnace at a temperature between 700 and 900°C and at a pressure between 0.05 and 0.3 MPa relative in the presence of water vapor. 5. Process according to one of the preceding claims, in which the weight ratio between the naphtha cut from step d) recycled in step b) and the naphtha cut from step a) and introduced into step b) is between 0.01 and 10. 6. Process according to one of the preceding claims, comprising at least one step of pretreatment of the feed or naphtha cut obtained in step a), said pretreatment step being carried out before or after step a) of prefractionation and upstream of step b) of hydrogenation and comprises an adsorption step and/or a filtration step and/or a centrifugation step and/or a decantation step and/or an electrostatic separation step and/or a step of washing using an aqueous solution and/or a gas stripping step. 7. Process according to one of the preceding claims, in which said hydrogenation catalyst of step b) comprises a support chosen from alumina, silica, silica-aluminas, magnesia, clays and their mixtures and a hydro-dehydrogenating function comprising either at least one element from group VIII and at least one element from group VIB, or at least one element from group VIII. 8. Process according to one of the preceding claims, in which said hydrotreatment catalyst of step c) comprises a support chosen from alumina, silica, silica-aluminas, magnesia, clays and their mixtures, and a hydro-dehydrogenating function comprising at least one element from group VIII and/or at least one element from group VIB. 9. Method according to one of the preceding claims, in which the charge consists of a pyrolysis oil from plastic and/or tires and/or solid recovered fuels. 10. Process according to any one of the preceding claims, in which said prefractionation step a) is carried out so as to obtain said naphtha cut and at least one middle distillate cut and one vacuum gas oil cut. 11. A process according to any one of the preceding claims, wherein at least a portion of said heavy cut, or of said middle distillate cut and/or of said vacuum gas oil cut is subjected to a dedicated hydrotreatment step, in a hydrotreatment reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrotreatment catalyst, said hydrotreatment reaction section being fed at least by said heavy cut, or said one middle distillate cut and/or said vacuum gas oil cut and a gas stream comprising hydrogen, said hydrotreatment reaction section being implemented at an average temperature between 250 and 430°C, a hydrogen partial pressure between 1.0 and 10.0 MPa abs. and an hourly volumetric velocity between 0.1 and 10.0 h' ¹ , to obtain a heavy hydrotreated effluent. 12. Process according to the preceding claim, in which at least a portion of the hydrotreated heavy effluent is sent to a hydrocracking step implemented in a hydrocracking reaction section, implementing at least one fixed-bed reactor having n catalytic beds, n being an integer greater than or equal to 1, each comprising at least one hydrocracking catalyst, said hydrocracking reaction section being fed at least with said hydrotreated heavy effluent and a gas stream comprising hydrogen, said hydrocracking reaction section being implemented at an average temperature between 250 and 480°C, a partial pressure of hydrogen between 1.5 and 20.0 MPa abs. and an hourly volumetric flow rate between 0.1 and 10.0 h ^-1 , to obtain a hydrocracked effluent. 13. Process according to one of claims 1 to 11, in which at least a portion of said heavy cut, or of said middle distillate cut and/or of said vacuum gas oil cut, or of the hydrotreated heavy effluent is sent to a fluidized bed catalytic cracking step carried out in a fluidized bed catalytic cracking reaction section in a substantially vertical reactor either in ascending mode or in descending mode in the presence of a zeolite catalyst at a reactor temperature of between 450°C and 600°C with a contact time in the reactor of less than 1 minute. 14. Product obtained by the process according to one of claims 1 to 13. 15. Product according to claim 14 comprising a biological carbon content according to ASTM D6866 of between 0 and 70% by weight.