FR2969651A1 - HYDROCARBONATE LOADING CONVERSION METHOD COMPRISING SCIST OIL BY DECONTAMINATION, BOILING BED HYDROCONVERSION, AND ATMOSPHERIC DISTILLATION FRACTIONATION - Google Patents

Abstract

A method and a device for hydrocarbon feed conversion comprising a shale oil, comprising a decontamination step, bubbling bed hydroconversion, fractionation into light fractions, naphtha, gas oil and heavier than diesel, the naphtha and diesel fractions being hydrotreated, the heavier fraction than diesel being returned to the decontamination step. The process aims to maximize the yield of fuel bases.

Description

HYDROCARBONATE LOADING CONVERSION METHOD COMPRISING SCIST OIL BY DECONTAMINATION, BOILING BED HYDROCONVERSION, AND ATMOSPHERIC DISTILLATION FRACTIONATION

The invention relates to a process for converting hydrocarbon feedstocks comprising a shale oil into lighter products, recoverable as fuels and / or raw materials for petrochemicals. More particularly, the invention relates to a process for converting hydrocarbon feedstocks comprising a shale oil comprising a decontamination step, a step of hydroconversion of the decontaminated oil in a bubbling bed, followed by a step of fractionation by atmospheric distillation. light fraction, naphtha, gas oil and in a heavier fraction than the diesel fraction, and a hydrotreatment dedicated to each of the naphtha and diesel fractions. This process makes it possible to convert shale oils into fuel base of very good quality and aims in particular at an excellent yield. Given the high volatility of the price of a barrel and a decline in discoveries of conventional oil fields, oil companies are turning to unconventional sources. Alongside oil sands and deep offshore, oil shale, although relatively unknown, is becoming increasingly popular. Oil shales are sedimentary rocks containing an insoluble organic substance called kerogen. By heat treatment in situ or ex-situ ("retorting" in the English terminology) in the absence of air at temperatures between 400 and 500 ° C, these schists release an oil, shale oil , whose general appearance is that of crude oil.

Although of different composition of crude oil, shale oils can be a substitute for the latter and also a source of chemical intermediates. Shale oils can not be a direct substitute for crude oil applications. Indeed, although these oils are similar in some respects to oil (for example by a similar H / C ratio), they are distinguished by their chemical nature and a much higher content of metallic and / or nonmetallic impurities, which makes the conversion of this unconventional resource much more complex than that of oil. Shale oils have higher levels of oxygen and nitrogen than oil. They may also contain higher concentrations of olefins, sulfur or metal compounds (including arsenic). Shale oils obtained by pyrolysis of kerogen contain many olefinic compounds resulting from cracking, which implies an additional demand for hydrogen in refining. Thus, the bromine index, which makes it possible to calculate the concentration by weight of olefinic hydrocarbons (by addition of bromine to the ethylenic double bond), is generally greater than 30 g / 100 g of filler for shale oils, whereas it is between 1 and 5 g / 100 g of charge for the oil residues. The olefinic compounds resulting from cracking consist essentially of mono olefins and diolefins. The unsaturations present in the olefins are potential source of instability by polymerization and / or oxidation. The oxygen content is generally higher than in heavy crudes and can reach up to 80% by weight of the filler. Oxygen compounds are often phenols or carboxylic acids. As a result, shale oils may have marked acidity. The sulfur content varies between 0.1 and 6.5% by weight, requiring severe desulfurization treatments in order to reach the specifications of the fuel bases. The sulfur compounds are in the form of thiophenes, sulfides or disulfides. In addition, the distribution profile of sulfur in a shale oil may be different from that obtained in conventional oil.

The most distinctive feature of shale oils, however, is their high nitrogen content, making them unsuitable as conventional refinery feedstock. The oil generally contains about 0.2% nitrogen by weight while crude shale oils generally contain from about 1 to about 30% by weight or more of nitrogen. In addition, the nitrogen compounds present in the oil are generally concentrated in the higher boiling ranges while the nitrogen of the compounds present in the crude shale oils is generally distributed throughout all the boiling ranges of the material. Nitrogen compounds in petroleum are predominantly non-basic compounds, whereas typically about half of the nitrogen compounds present in crude shale oils are basic in nature. These basic nitrogen compounds are particularly undesirable in the refining feeds because these compounds often act as catalyst poisons. In addition, product stability is a problem that is common to many shale oil products. Such instability, including photosensitivity, appears to result essentially from the presence of nitrogen compounds. Therefore, crude shale oils must generally be subjected to a severe refining treatment (high total pressure) in order to obtain a synthetic crude oil or fuel-based products meeting the specifications in force. Similarly, it is known that shale oils may contain many trace metal compounds, generally present as organometallic complexes. Among the metal compounds, mention may be made of conventional contaminants such as nickel, vanadium, calcium, sodium, lead or iron, but also metal arsenic compounds. In fact, shale oils can contain an amount of arsenic greater than 20 ppm while the amount of arsenic in crude oil is generally in the area of ppb (parts per billion). All these metal compounds are poisons of catalysts. In particular, they irreversibly poison the hydrotreatment and hydrogenation catalysts by settling progressively on the active surface. Conventional metal compounds and some of the arsenic are found mainly in heavy cuts and are removed by settling on the catalyst. On the other hand, when products containing arsenic are able to generate volatile compounds, these can be found partly in lighter cuts and can, therefore, poison the catalysts of the subsequent transformation processes, at the same time. refining or petrochemicals.

In addition, shale oils generally contain sandy sediments from oil shale deposits from which shale oils are extracted. These sandy sediments can create clogging problems, especially in fixed bed reactors. Finally, shale oils may contain waxes which give them a pour point greater than ambient temperature, preventing their transport in oil pipelines. Due to considerable resources, and their evaluation as a promising source of oil, there is a real need to convert shale oils into lighter products that can be used as fuels and / or raw materials for petrochemicals. Methods for converting shale oils are known. Conventionally, the conversion is done either by coking, by hydroviscoreduction (thermal cracking in the presence of hydrogen) or by hydroconversion (catalytic hydrogenation). Liquid / liquid extraction processes are also known.

Thus, patent document CA2605056 describes a heavy-charge conversion process having an initial boiling point greater than 340 ° C., in which the feedstock is subjected to a deasphalting step, and then the raffinate obtained is hydroconverted in the presence of a dispersed catalyst. The non-hydroconverted raffinate is recycled at the deasphalting stage. The charges envisaged in this document are only of the type atmospheric residue and vacuum residue resulting from conventional oil. A single desulfurization step is considered on the atmospheric gas oil cut. An additional vacuum distillation step with recycle of the residue under vacuum is presented. CA2464796 discloses a heavy load conversion process quite similar to CA2605056 mentioned above. In CA2464796, there is no reference to the treatment of shale oil, the intended loads being limited to atmospheric residues and residues under vacuum. In addition, the vacuum distillation step is optional. Finally, there is no recycling of the residue. The patent application US2007138058 describes a slurry hydroconversion process, in which the feed undergoes a preliminary hydrotreatment or deasphalting step. Converted products are subject to unspecified hydrofinishing. The process described is applied to various heavy loads derived from conventional oil. There is no mention of shale oils.

The patent application US2004163996 relates to a process for treating atmospheric residue or vacuum residue in which said residue undergoes a deasphalting step, then the deasphalted oil (raffinate) and asphalt (extract) cuts are separately hydroconverted by a method of bubbling bed. US Patent Application 2009166253 contemplates the sequencing of several deasphalting steps followed by a step of hydrocracking one or more deasphalted oils, and then of their fractionation. The process is applied to different loads, including shale oils.

Object of the invention

The specificity of shale oils being to have a number of metallic impurities and / or non-metallic makes the conversion of this unconventional resource much more complex than that of oil. The challenge for the industrial development of shale oil conversion processes is therefore the need to develop processes adapted to the load, making it possible to maximize the yield of good quality fuel bases. The conventional refining treatments known from petroleum must therefore be adapted to the specific composition of shale oils. The present invention aims to improve the known processes for converting hydrocarbon feedstocks comprising a shale oil, in particular by increasing the yield of fuel bases for a combination of steps having a specific sequence, and a treatment adapted to each fraction derived from the oils of shale. Likewise, the object of the present invention is to obtain products of good quality having in particular a low content of sulfur, nitrogen and arsenic, preferably respecting the specifications. Another objective is to propose a simple process, that is to say with the least necessary steps, while remaining effective, to limit investment costs. In its widest form, and according to a first aspect, the present invention is defined as a hydrocarbon feed conversion process comprising at least one shale oil having a nitrogen content of at least 0.10 / 0, often from minus 10/0 and very often at least 2% by weight, characterized in that it comprises the following steps: a) The feed is subjected to decontamination in order to obtain a residue and a decontaminated oil, b) L decontaminated oil is sent to a hydroconversion section in the presence of hydrogen, said section comprising at least one ebullating bed reactor operating at an upward flow of liquid and gas and containing at least one supported hydroconversion catalyst, c) L effluent obtained in step b) is sent, at least in part, and often entirely, into a fractionation zone from which a gaseous fraction, a naphtha fraction, a fraction of a diesel fraction and a heavier fraction than diesel, d) said naphtha fraction is treated, at least in part, and often completely in a first hydrotreating section in the presence of hydrogen, said first section comprising at least a first reactor to fixed bed containing at least a first hydrotreating catalyst, and e) Said gas oil fraction is treated, at least in part, and often entirely in a second hydrotreating section in the presence of hydrogen, said second section comprising at least one second fixed bed reactor containing at least a second hydrotreatment catalyst.

Usually, the hydroconversion section of step b) comprises from one to three, and preferably two, reactors in series, and the first and second hydrotreatment sections of steps d) and e) each independently comprise from one to three series reactors.

The process advantageously comprises an additional step in which the heavier fraction than diesel is recycled in step a) to be decontaminated. The research work carried out by the applicants on the conversion of shale oils has led to the discovery that an improvement of the existing processes in terms of fuel efficiency and purity of the products is possible by a combination of different stages, chained together. a specific way. Each fraction obtained by the process according to the invention is then sent to a treatment section. In a first step, the hydrocarbon feedstock comprising the shale oil is subjected to a decontamination advantageously taking the form of deasphalting, using a solvent in the form of a C3-C5 hydrocarbon alone or mixed. The solvent is chosen to separate the asphalt which contains heavy aromatic compounds, which will not be soluble in the solvent. The extraction step also makes it possible to reduce the proportion of aromatic nitrogen compounds which are refractory to hydrodenitrogenation (catalytic hydrogenation denitrogenation), to eliminate particles and minerals originating from oil shale, and to entrain a large part of the compounds organo-heavy metals containing metals such as vanadium or nickel. These heavy organo-metallic compounds may have porphyrinic units within them, which are responsible for metal sequestration. The deasphalting is carried out on the totality of the load, in order to extract as much as possible the nitrogenous aromatic compounds present in sections ranging from LPG to the heavier fraction than diesel. The use of deasphalting on the entire charge before hydroconversion removes a large part of the metal poisons present in the load, in particular arsenic, as well as heavy nitrogen compounds, generally aromatic. Thus, the turnover rate of the hydroconversion catalyst is decreased, and the hydrogen requirements are limited, because of the lesser presence of compounds to be converted in the deasphalted oil. Examples of aromatic nitrogen compounds which can be found in fillers which can be treated according to the process of the invention include pyridines, pyrimidines, pyrazines, quinolines, isoquinolines, pyrroles, imidazoles, and other mono- or polycyclic nitrogenous aromatic heterocycles. These nitrogenous aromatic compounds may be substituted with various hydrocarbon chains, optionally comprising heteroatoms such as nitrogen, oxygen, and sulfur.

The second stage comprises hydroconversion in a bubbling bed. Bubble bed technology allows, compared to fixed bed technology, to treat highly contaminated loads of metals, heteroatoms and sediments, such as shale oils, while having conversion rates generally greater than 500/0. In fact, in this second stage, shale oil is transformed into molecules making it possible to generate future fuel bases. Most of the metal compounds, sediments and heterocyclic compounds are removed.

The effluent exiting the bubbling bed thus contains the most refractory nitrogen and sulfur compounds, and possibly volatile arsenic compounds in lighter components. The effluent obtained in the hydroconversion stage is then fractionated by atmospheric distillation, making it possible to obtain different fractions for which a treatment specific to each fraction is carried out subsequently. The atmospheric distillation makes it possible, in a single step, to obtain the various desired fractions (naphtha, gas oil), thus facilitating a downstream hydrotreatment adapted to each fraction and, consequently, the direct obtaining of naphtha or diesel fuel base products respecting the different specifications. Fractionation after hydrotreatment is therefore not necessary. Due to the strong reduction of contaminants in the bubbling bed, the light fractions (naphtha and gas oil) contain less contaminants and can therefore be processed in a fixed bed section generally having improved hydrogenation kinetics compared to the bubbling bed. Similarly, the operating conditions may be milder due to the limited contaminant content. Providing a treatment for each fraction makes it possible to have a better operability according to the desired products. Depending on the operating conditions chosen (more or less severe), it is possible to obtain either a fraction that can be sent to a fuel pool, or a finished product that meets the specifications (sulfur content, smoke point, cetane, aromatic content, etc.). ) in force.

The fixed bed hydrotreatment sections preferably comprise, upstream of the hydrotreatment catalytic beds, guard beds specific for the arsenic and silicon compounds optionally contained in the naphtha and / or diesel fractions. The arsenic compounds escaping the ebullating bed (because they are generally relatively volatile) are fixed in the guard beds, avoiding poisoning the downstream catalysts, and making it possible to obtain fuel bases that are heavily depleted of arsenic. The atmospheric distillation also makes it possible to concentrate the more refractory nitrogen compounds in the heavier fraction than the gas oil fraction, which, in step f1, is returned to step a) to be deasphalted therein. Thus, this recycling step allows for the extinction of the heavier fraction than diesel, and thus to minimize the problems of valuation and economic opportunities of the latter. Asphalts have applications in the preparation of heavy fuels and bitumens.

detailed description

Hydrocarbon feedstock The hydrocarbon feedstock comprises at least one shale oil. The term "shale oil" is used here in its broadest sense and is intended to include any shale oil or a shale oil fraction, which contains nitrogenous impurities. This includes crude shale oil, whether obtained by pyrolysis, solvent extraction or other means, shale oil that has been filtered to remove solids, or that has been treated by a or more solvents, chemicals, or other treatments, and which contains nitrogenous impurities. The term "shale oil" also includes shale oil fractions obtained by distillation or other fractionation technique.

The shale oils used in the present invention generally have a Conradson carbon content of at least 0.1% by weight and generally at least 5% by weight, an asphaltenes content (IP143 / C7 standard) of at least 1%, often at least 2% by weight. Their sulfur content is generally at least 0.1%, often at least 10% and very often at least 20% or even up to 4% or even 7% by weight. The amount of metals they contain is generally at least 5 ppm by weight, often at least 50 ppm by weight, and typically at least 100 ppm by weight or at least 200 ppm by weight. Their nitrogen content is generally at least 0.50 / 0, often at least 1% and very often at least 2% by weight. Their arsenic content is generally greater than 1 ppm by weight, and up to 50 ppm by weight. The process according to the present invention aims at converting shale oils. However, the feed may also contain, in addition to shale oil, other synthetic liquid hydrocarbons, particularly those containing a significant amount of organic cyclic nitrogen compounds. This includes oils derived from coal, oils obtained from heavy tar, tar sands, pyrolysis oils from wood residues such as wood residues, biomass crudes ("biocrudes"), vegetable oils and animal fats.

Other hydrocarbon feedstocks can also supplement shale oil. The feeds are selected from the group consisting of vacuum distillates and straight run residues, vacuum distillates and unconverted residues from conversion processes such as, for example, those from distillation to coke ( coking), products resulting from hydroconversion of heavy liquids in fixed bed, products resulting from hydroconversion processes of heavy boilers, and oils désalphatées with solvents (for example the deasphalted oils with propane, with butane and with pentane from the deasphalting of direct distillation vacuum residues or vacuum residues from ydroconversion processes). The fillers may also contain light cutting oil (LCO for "light cycle oil" in English) of various origins, heavy cutting oil (HCO for "heavy cycle oil" in English) of various origins, and also diesel fuel cuts from catalytic cracking generally having a distillation range of about 150 ° C to about 650 ° C. The fillers may also contain aromatic extracts obtained in the context of the manufacture of lubricating oils. The fillers can also be prepared and used in a mixture, in all proportions.

Decontamination The hydrocarbon feedstock comprising the shale oil is directed to a decontamination step [step a)]. This step aims to extract the compounds rich in contaminants. These contain heavy compounds rich in heteroatoms such as nitrogen, oxygen and sulfur, as well as most metals in the feed. A preferred method of decontamination is deasphalting. Deasphalting with a solvent is carried out under conditions well known to those skilled in the art. For example, methods such as Solvahl of Axens, or Rose of KBR can be used. The deasphalting is carried out traditionally with the aid of an aliphatic solvent, generally a C3-C7 alkane or cycloalkane, preferably C3-C5, or mixtures thereof in all proportions.

The decontamination of step a) is carried out with a solvent selected from the group consisting of propane, n-butane, isobutane, n-pentane, cyclopentane, 2-methyl-butane, 2,2 dimethyl propane, and mixtures thereof in all proportions. Deasphalting may be carried out by any means known to those skilled in the art. The extraction is generally carried out in a mixer-settler or in an extraction column. Preferably, the extraction is carried out in an extraction column. The operating conditions are in general a solvent / charge ratio of 3/1 to 8/1% vol /% vol, preferably 4/1 to 6/1% vol /% vol, a temperature profile of between 60 and 250 ° C. C, preferably between 60 ° C and 200 ° C. The operating pressure must be maintained above the critical pressure of the solvent used. It is preferably between 4 and 5 MPa. In a preferred embodiment, a mixture comprising the hydrocarbon feed and a first fraction of a solvent feed is introduced into the extraction column, the volume ratio between the solvent feed fraction and the hydrocarbon feedstock. being called the rate of solvent injected with the charge. This step is intended to mix well the load with the solvent entering the extraction column. In the settling zone at the bottom of the extractor, it is possible to introduce a second fraction of solvent charge, the volume ratio between the second fraction of feedstock and the hydrocarbon feedstock being called the level of solvent injected at the bottom of the extractor. The volume of the hydrocarbon feedstock considered in the settling zone is generally that introduced into the extraction column. The sum of the two volume ratios between each of the solvent feed fractions and the hydrocarbon feed is referred to as the overall solvent level. The decantation of the asphalt consists of the countercurrent washing of the asphalt emulsion in the solvent + oil mixture with pure solvent. It is favored by an increase in the solvent ratio (it is in fact to replace the solvent + oil environment with a pure solvent environment) and by a decrease in temperature. The solvent can be recovered either by vaporization of the solvent (multi-stage flash with lowering of the pressure and raising of the temperature) followed generally by steam stripping, or by operating the separation of the solvent at a pressure greater than critical pressure of the solvent or that of the solvent deasphalted oil mixture, which reduces the energy cost of the vaporization. Extraction makes it possible to obtain a feedstock to keep nitrogen reduced by about half compared with the nitrogen content of the feedstock. At least a portion, and preferably all, of the deasphalted oil is fed to a bubbling bed reactor for hydroconversion in the presence of hydrogen. The bubbling bed comprises a supported hydroconversion catalyst. According to a preferred variant, the asphalt is sent to an oxy-gas-gasification section in which it is converted into a gas containing hydrogen and carbon monoxide. This gaseous mixture can be used for the synthesis of methanol or for the synthesis of hydrocarbons by the Fischer-Tropsch reaction. This mixture, in the context of the present invention, is preferably sent to a steam conversion section ("shift") in which, in the presence of water vapor, it is converted into hydrogen and hydrogen. carbon dioxide. The hydrogen obtained can be used in steps b), d) and e) of the process according to the invention. The asphalt obtained in step a) can also be used as a solid fuel, or, after fluxing, as a liquid fuel, or enter the bitumen composition (after a possible blowing step) and / or heavy fuels.

The deasphalting of the filler therefore makes it possible to extract the refractory aromatic compounds containing nitrogen and the contaminants (metals), as well as the particles and sediments, which sometimes represent 0.2% by weight of the filler. The implementation of a step of prior deasphalting of the feed makes it possible to preserve the hydroconversion catalyst used in the next step and to minimize the continuous catalyst additions.

Hydroconversion After decontamination by deasphalting, the raffinate (deasphalted oil or DAO, or decontaminated load) obtained is subjected to a hydroconversion stage [step b)] in a bubbling bed. Hydroconversion is understood to mean hydrogenation, hydrotreatment, hydrodesulfurization, hydrodenitrogenation, hydrodemetallation and hydrocracking reactions. The operation of the bubbling bed catalytic reactor, including the recycle of reactor liquids upwardly through the agitated catalyst bed, is generally well known. Bubbling bed technologies use supported catalysts, generally in the form of extrudates whose diameter is generally of the order of 1 mm or less than 1 mm, for example greater than or equal to 0.7 mm. The catalysts remain inside the reactors and are not evacuated with the products. The catalytic activity can be kept constant by the on-line replacement (addition and withdrawal) of the catalyst. It is therefore not necessary to stop the unit to change the spent catalyst, nor to increase the reaction temperatures along the cycle to compensate for the deactivation. In addition, working with constant operating conditions provides consistent yields and product qualities throughout the catalyst cycle. Since the catalyst is kept in agitation by a large recycling of liquid, the pressure drop on the reactor remains low and constant, and the heat of reaction is rapidly averaged over the catalytic bed, which is therefore almost isothermal and does not require cooling. via the injection of quenches. The implementation of boiling bed hydroconversion makes it possible to overcome the problems of catalyst contamination linked to the deposition of impurities present naturally in shale oils. The conditions of step b) of treating the feedstock in the presence of hydrogen are usually conventional bubbling bed hydroconversion conditions of a liquid hydrocarbon fraction. It is usually carried out under a total pressure of 2 to 35 MPa, preferably 10 to 20 MPa, at a temperature of 300 ° C to 550 ° C and often 400 ° C to 450 ° C. The hourly space velocity (VVH) and the hydrogen partial pressure are important factors that are chosen according to the characteristics of the product to be treated and the desired conversion. Most often, the VVH is in a range from 0.2 h -1 to 1.5 h -1 and preferably from 0.4 h -1 to 1 h -1. The amount of hydrogen mixed with the feedstock is usually from 50 to 5000 normal cubic meters (Nm3) per cubic meter (m3) of liquid feed, and most often from 100 to 1000 Nm3 / m3, and preferably from 300 to 500 Nm3 / m3; Most often, this hydroconversion step b) can be carried out under the conditions of the T-STAR® process, as described for example in the article Heavy Oil Hydroprocessing, published by Aiche, March 19-23, 1995, HOUSTON, Texas, paper number 42d. It can also be implemented under the conditions of the H-OIL® process, as described for example in the article published by NPRA, Annual Meeting, March 16-18, 1997, J.J. Colyar and L.I. Wisdom under the title THE H-OIL®PROCESS, WORLDWIDE LEADER IN VACUUM RESIDUE HYDROPROCESSING. The hydrogen needed for hydroconversion (and subsequent hydrotreatment) can come from steam reforming hydrocarbons (methane) or gas from oil shale during the production of shale oils.

The catalyst of step b) is preferably a conventional granular hydroconversion catalyst comprising on an amorphous support at least one metal or metal compound having a hydro-dehydrogenating function. In general, a catalyst is used whose porous distribution is suitable for the treatment of metal-containing fillers. The hydro-dehydrogenating function may be provided by at least one Group VIII metal selected from the group consisting of nickel and / or cobalt, optionally in combination with at least one Group VIB metal selected from the group consisting of molybdenum and / or tungsten. For example, a catalyst comprising from 0.5 to 10% by weight of nickel and preferably from 1 to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1 to 30% by weight of molybdenum may be used, preferably from 5 to 20% by weight of molybdenum (expressed as molybdenum oxide MoO3), on an amorphous mineral support. The total content of Group VIB and VIII metal oxides is often from 5 to 40% by weight and generally from 7 to 30% by weight. The weight ratio expressed as metal oxide between metal (or metals) of group VI on metal (or metals) of group VIII is, in general, from 20 to 1 and most often from 10 to 2. The catalyst support will for example be selected from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also contain other compounds, for example oxides chosen from the group formed by boron oxide, zirconia, titanium oxide and phosphoric anhydride. Most often an alumina support is used, and very often a support of alumina doped with phosphorus and possibly boron. In this case, the concentration of phosphorus pentoxide P2O5 is usually less than about 20% by weight and most often less than about 10% by weight and at least 0.001% by weight. The concentration of B2O3 boron trioxide is usually from about 0 to about 10% by weight. The alumina used is usually y (gamma) or r (eta) alumina. This catalyst is most often in the form of extruded. Preferably, the catalyst of step b) is based on nickel and molybdenum, doped with phosphorus and supported on alumina. For example, it is possible to use a catalyst of the HTS 458 type marketed by AXENS. Prior to the injection of the deasphalted oil, the catalysts used in the process according to the present invention may be subjected to a sulphurization treatment making it possible, at least in part, to convert the metal species into sulphides before they come into contact with the load to be processed. This activation treatment by sulfurization is well known to those skilled in the art and can be performed by any method already described in the literature either in-situ, that is to say in the reactor, or ex-situ. The spent catalyst is partly replaced by fresh catalyst by withdrawal at the bottom of the reactor and introduction to the top of the fresh or new catalyst reactor at regular time interval, for example by spot addition, or almost continuously. For example, fresh catalyst can be introduced every day. The replacement rate of spent catalyst with fresh catalyst can be, for example, from about 0.05 kg to about 10 kg per m 3 of feedstock. This withdrawal and replacement are performed using devices for the continuous operation of this hydroconversion step. The unit usually comprises a recirculation pump for maintaining the bubbling bed catalyst by continuously recycling at least a portion of the liquid withdrawn at the top of the reactor and reinjected at the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor into a regeneration zone in which the carbon and the sulfur contained therein are removed, and then to return this regenerated catalyst to the hydroconversion reactor of step b). .

The operating conditions coupled with the catalytic activity make it possible to obtain conversion rates of the feedstock that can range from 50 to 950/0, preferably from 70 to 95%. The conversion rate mentioned above is defined as the mass fraction of the feed at the inlet of the reaction section minus the mass fraction of the heavy fraction having a boiling point greater than 343 ° C. at the outlet of the reaction zone. reaction section, all divided by the mass fraction of the feed at the inlet of the reaction section. The bubbling bed technology makes it possible to treat highly contaminated loads of metals, sediments and heteroatoms, without encountering problems of loss of pressure or clogging known in the case of use of fixed bed. Metals such as nickel, vanadium, iron and arsenic are largely removed from the charge by settling on the catalysts during the reaction. The remaining (volatile) arsenic will be removed during the hydrotreatment stages by specific guard beds. The sediments contained in the shale oils are also removed by replacing the catalyst in the bubbling bed without disturbing the hydroconversion reactions. These steps also make it possible to remove most of the nitrogen by hydrodenitrogenation, leaving only the most refractory nitrogen compounds. The hydroconversion of step b) makes it possible to obtain an effluent containing at most 3000 ppm, preferably at most 2000 ppm by weight of nitrogen.

Fractionation by Atmospheric Distillation The effluent obtained in hydroconversion stage b) is sent at least partly, and preferably entirely, into a fractionation zone from which a gaseous fraction, a fraction, is recovered by atmospheric distillation. naphtha, a diesel fraction and a heavier fraction than the diesel fraction. Preferably, the effluent obtained in step b) is fractionated by atmospheric distillation into a gaseous fraction having a boiling point of less than 50 ° C., a naphtha fraction boiling between about 50 ° C. and 150 ° C., a fraction gas oil boiling between about 150 ° C and 370 ° C, and a heavier fraction than the gas oil fraction generally boiling above 340 ° C, preferably above 370 ° C. The naphtha and diesel fractions are then separately sent to hydrotreatment sections. The heavier fraction than the diesel fraction is returned to the decontamination unit of step a) and mixed with the feed.

The gaseous fraction contains gases (H2, H2S, NH3, H2O, CO2, CO, C1-C4 hydrocarbons, etc.). It may advantageously undergo a purification treatment to recover the hydrogen and recycle it in the hydroconversion section of step b) or in the hydrotreatment sections of steps d) and e). The C3- and C4 hydrocarbons may, after purification treatments, be used to constitute LPG (liquefied petroleum gas) products. Incondensable gases (C1-C2) are generally used as internal fuel for heating furnaces of hydroconversion and / or hydrotreating reactors. Optionally, the C1-C4 hydrocarbons isolated from the gaseous fraction can be used to carry out the decontamination step a). The operating conditions of the decontamination (pressure, temperature, solvent / charge ratio) will vary with the nature of the shale oil containing filler and will be adjusted to make it compatible with the desired purification parameters.

Hydrotreatment of the naphtha fraction and the diesel fraction The naphtha and gas oil fractions are then subjected separately to a fixed bed hydrotreatment [steps d] and e]]. Hydrotreatment is understood to mean hydrodesulfurization, hydrodenitrogenation and ydrodemetallation reactions. The objective is, according to the operating conditions chosen in a more or less severe way, to bring the different cuts to the specifications (sulfur content, smoke point, cetane, aromatic content, etc.) or to produce an oil synthetic crude. The fact of treating the naphtha fraction in a hydrotreatment section and the gas oil fraction in another hydrotreatment section makes it possible to have a better operability in the operating conditions, in order to be able to bring each cut to the required specifications with a maximum yield. and this in one step by cutting. Thus, fractionation after hydrotreatment is not necessary. The difference between the two hydrotreating sections is based more on differences in operating conditions than on the choice of catalyst. The fixed-bed hydrotreatment sections preferably comprise, upstream of the hydrotreatment catalytic beds, specific guard beds for the arsenic compounds (arsenic compounds) and silicon optionally contained in the naphtha and / or diesel fractions. . The arsenic compounds having escaped the bubbling bed (because they are generally relatively volatile) are fixed in the guard beds, thus avoiding poisoning the catalysts downstream, and making it possible to obtain fuel bases that are heavily depleted of arsenic.

Guard beds for removing arsenic and silicon from naphtha or diesel cuts are known to those skilled in the art. They include for example an absorbent mass comprising nickel deposited on a suitable support (silica, magnesia or alumina) as described in FR2617497, or an absorbent mass comprising copper on a support, as described in FR2762004. Mention may also be made of guard beds marketed by AXENS: ACT 979, ACT989, ACT961, ACT981.

The operating conditions of each hydrotreatment section are adapted to the batch to be treated. The operating conditions for hydrotreatment of the naphtha fraction are generally milder than those of the diesel fraction.

In the hydrotreating step of the naphtha fraction [step d)], it is usually carried out under an absolute pressure of 4 to 15 MPa, often 10 to 13 MPa. The temperature in this step d) is usually 280 ° C to 380 ° C, often 300 ° C to 350 ° C. This temperature is usually adjusted according to the desired level of hydrodesulfurization. Most often, the hourly space velocity (WH) is in the range of 0.1 hr-1 to hr-1, and preferably 0.5 hr-l to hr-1. The amount of hydrogen mixed with the feedstock is usually from 100 to 5000 normal cubic meters (Nm3) per cubic meter (m3) of liquid feed, and most often from 200 to 1000 Nm3 / m3, and preferably from 300 to 500 Nm3 / m3. Use is advantageously carried out in the presence of hydrogen sulphide (for the sulphidation of the catalyst) and the partial pressure of the hydrogen sulphide is usually 0.002 times to 0.1 times, and preferably 0.005 times to 0.05 times the total pressure. .

In the step of hydrotreating the gas oil fraction (step e), the operation is usually carried out under an absolute pressure of 7 to 20 MPa, often 10 to 15 MPa. The temperature in this step e) is usually 320 ° C to 450 ° C, often 340 ° C to 400 ° C. This temperature is usually adjusted according to the desired level of hydrodesulfurization. The hourly mass velocity is between 0.1 and 1 hr-1. Most often, the hourly space velocity (WH) is in a range of from 0.2 h -1 to 1 h -1, and preferably from 0.3 h -1 to 0.8 h -1. The amount of hydrogen mixed with the feedstock is usually from 100 to 5000 normal cubic meters (Nm3) per cubic meter (m3) of liquid feed, and most often from 200 to 1000 Nm3 / m3, and preferably from 300 to 500 Nm3 / m3. Useful operation is carried out in the presence of hydrogen sulfide, and the partial pressure of hydrogen sulfide is usually 0.002 times to 0.1 times, and preferably 0.005 times to 0.05 times the total pressure.

In the hydrotreatment sections, the ideal catalyst must have a high hydrogenating power, so as to achieve a deep refining of the products, and to obtain a significant lowering of the sulfur and nitrogen content. In the preferred embodiment, the hydrotreatment sections operate at a relatively low temperature, which is in the sense of deep hydrogenation and coking limitation of the catalyst. It is not within the scope of the present invention to use, in the hydrotreatment sections, simultaneously or successively, a single catalyst or several different catalysts. Usually, the hydrotreatment of steps d) and e) is carried out industrially, in one or more liquid downflow reactors.

In both hydrotreatment sections [steps d) and e) the same type of catalyst is used, the catalysts in each section being identical or different. At least one fixed bed of conventional hydrotreatment catalyst is used, comprising on an amorphous support at least one metal or metal compound having a hydro-dehydrogenating function. The hydro-dehydrogenating function may be provided by at least one Group VIII metal selected from the group consisting of nickel and / or cobalt, optionally in combination with at least one Group VIB metal selected from the group consisting of molybdenum and / or tungsten. For example, a catalyst comprising from 0.5 to 10% by weight of nickel and preferably from 1 to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1 to 30% by weight of molybdenum can be used. preferably from 5 to 20% by weight of molybdenum (expressed as molybdenum oxide MoO3), on an amorphous mineral support. The total metal oxide content of Groups VI and VIII is often from about 5 to about 40% by weight, and generally from about 7 to 30% by weight, and the weight ratio of metal oxide to metal (or metals) of group VIB on metal (or metals) of group VIII is generally from about 20 to about 1, and most often from about 10 to about 2. The carrier is for example selected from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also contain other compounds, for example oxides chosen from the group formed by boron oxide, zirconia, titanium oxide and phosphoric anhydride. Most often an alumina support is used and very often a support of alumina doped with phosphorus and possibly boron. In this case, the concentration of phosphorus pentoxide P2O5 is usually less than about 20% by weight and most often less than about 10% by weight, and is at least 0.001% by weight. The concentration of B2O3 boron trioxide is usually from about 0 to about 10% by weight. The alumina used is usually y (gamma) or hal (eta) alumina. This catalyst is most often in the form of beads or extrudates. Before the charge is injected, the catalysts used in the process according to the present invention are preferably subjected to a sulphurization treatment making it possible, at least in part, to transform the metallic species into sulphide before they come into contact with the charge. treat. This activation treatment by sulfurization is well known to those skilled in the art and can be performed by any method already described in the literature either in-situ, that is to say in the reactor, or ex-situ. The hydrotreatment of stage d) of the naphtha section makes it possible to obtain a section containing at most 1 ppm by weight of nitrogen, preferably at most 0.5 ppm of nitrogen and at most 5 ppm by weight of sulfur, of preferably at most 0.5 ppm of sulfur.

The hydrotreatment of step e) of the diesel cut makes it possible to obtain a cut containing not more than 100 ppm of nitrogen, preferably not more than 200 ppm of nitrogen and not more than 50 ppm of sulfur, preferably not more than 10 ppm. ppm of sulfur.

Catalytic Cracking Finally, according to one variant, the process according to the invention may comprise a catalytic cracking step [step g)], in which at least a portion, and preferably the whole of the heavier fraction than gas oil obtained at step c), is sent to a conventional catalytic cracking section, wherein said heavier fraction than gas oil is conventionally treated under conditions well known to those skilled in the art, to produce a second gaseous fraction, a second gasoline fraction, a second diesel fraction and a second heavier fraction than diesel, called "slurry" according to the English terminology. The second diesel fraction will be, for example, at least partly sent to fuel tanks (pools) and / or recycled, at least partially, or in whole, in step e) hydrotreating diesel. The second heavier fraction that diesel will be, for example, at least partly, or even entirely, sent to the tank (pool) fuel oil and / or recycled at least partially, or in whole, in step g) cracking catalytic. At least a part of the second heavier fraction obtained from gas oil after step g), is recycled to the decontamination step a). In the context of the present invention, the conventional catalytic cracking expression includes cracking processes comprising at least one partial combustion catalyst regeneration stage, and those comprising at least one total combustion catalyst regeneration stage, and / or those comprising both at least one partial combustion step and at least one total combustion step. For example, a brief description of catalytic cracking (the first industrial implementation of which dates back to 1936 (HOUDRY process) or 1942 for the use of a fluidized bed catalyst) can be found in ULLMANS ENCYCLOPEDIA OF INDUSTRIAL CHEMISTRY VOLUME A 18, 1991, pages 61 to 64. A conventional catalyst comprising a matrix, optionally an additive and at least one zeolite is usually used. The amount of zeolite is variable but usually from about 3 to 60% by weight, often from about 6 to 50% by weight and most often from about 10 to 45% by weight. The zeolite is usually dispersed in the matrix. The amount of additive is usually from about 0 to about 30% by weight. The amount of matrix represents the complement at 100% by weight. The additive is generally chosen from the group formed by the metal oxides of group IIA of the periodic table of elements, such as, for example, magnesium oxide or calcium oxide, rare earth oxides and titanates. Group IIA metals. The matrix is most often a silica, an alumina, a silica-alumina, a silica-magnesia, a clay or a mixture of several of these products. The most commonly used zeolite is zeolite Y. The cracking is carried out in a substantially vertical reactor, either in ascending or descending mode. The choice of the catalyst and the operating conditions depend on the desired products as a function of the feedstock treated, as described, for example, in the article by M.Marcilly, pages 990-991, published in the review of the Institut Français du Pétrole nov. .-Dec. 1975 pages 969-1006. The operation is usually at a temperature of 450 ° C to 600 ° C and reactor residence times of less than 1 minute, often from about 0.1 to about 50 seconds.

The catalytic cracking step g) may also be a catalytic cracking step in a fluidized bed, for example according to the process known as R2R. This step can be carried out in a manner conventionally known to those skilled in the art under suitable cracking conditions in order to produce lower molecular weight hydrocarbon products. Functional descriptions and catalysts for use in fluidized bed cracking in this step g) are described, for example, in US-A-5286690, US-A-65324696 and EP-A-699224. The fluidized catalytic cracking reactor is operable with upflow or downflow. Although this is not a preferred embodiment of the present invention, it is also conceivable to perform catalytic cracking in a moving bed reactor. Particularly preferred catalytic cracking catalysts are those containing at least one zeolite, usually in admixture with a suitable matrix such as, for example, alumina, silica, silica-alumina. According to a penultième aspect, the invention relates to obtaining a synthetic crude by a method according to one of its previous aspects. According to a final aspect, the invention relates to an installation for treating a shale oil implementing a method according to one of its previous aspects.

Figure 1 shows schematically the method according to the present invention. Figure 2 schematically shows a variant of the process including the catalytic cracking step. According to Figure 1, the load comprising the shale oil (1) to be treated enters the line (2) in a decontamination section (3). This step (3) is a deasphalting carried out using a solvent (not shown) which produces a deasphalted oil (4) and a residue (5). Residue (5), via line (6), can be used as fuel or feed a gasification unit to produce hydrogen and energy.

The deasphalted oil (4) is sent via a line (7) to a boiling bed hydroconversion section (8) in the presence of hydrogen (9), the hydrogen (9) being introduced via the line (10). ). The effluent of the boiling bed hydroconversion section (8) is sent via line (11) to an atmospheric distillation column (12), at the outlet of which a gaseous fraction (13), a naphtha fraction is recovered. (14), a gas oil fraction (15) and a heavier fraction than the gas oil fraction (16). The gaseous fraction (13), containing hydrogen, can be purified (not shown) to recycle hydrogen and reinject it into the ebullated bed hydroconversion section (8) via line (10) and / or hydrotreatment sections (17) and / or (18) via lines (19) and (20). The naphtha fraction (14) is sent to the fixed bed hydrotreatment section (17) at the outlet of which a naphtha fraction (21) depleted of impurities is recovered.

The gas oil fraction (15) is sent to the fixed bed hydrotreatment section (18) at the outlet of which a diesel fuel fraction (22) depleted of impurities is recovered. The two hydrotreatment sections (17) and (18) are fed with hydrogen via lines (23) and (24). The heavier fraction than the gas oil fraction (16) is recycled within the deasphalting section (3) via the line (25). In FIG. 2, the stages (and reference signs) of liquid / liquid extraction, hydroconversion, separation and hydrotreatments are identical to FIG. 1. The heavier fraction than the diesel fraction (16) exiting from the atmospheric distillation step can be directed into a catalytic cracking section (26) by means of a line (27). The effluent of this section (26) is directed via the line (28) to a fractionation section (29), preferably an atmospheric distillation, from which a fraction of fuels or middle distillates is recovered, comprising at least a second gasoline fraction (30), a second diesel fraction (31) and a second heavier fraction than diesel (32) also called "slurry". The second diesel fraction (31) is sent, at least in part, to the fuel tanks (pools) and / or is recycled, at least in part, or in whole, to the diesel fuel hydrotreatment stage e) (18) via the line (33). The second heavier fraction ("slurry") (32) is, for example, at least partly, if not all, sent to the heavy fuel tank and / or is recycled, at least in part, or even all, at the catalytic cracking stage (26) via the line (34). Optionally, the second heavier fraction that diesel (32) is sent in part or in full to the deasphalting unit (3) by a line (35). Example A shale oil is processed, the characteristics of which are shown in Table 1.

Table 1: Characteristics of shale oil feed Density 15/4 - 0.948 Hydrogen% by weight 10.9 Sulfur% by weight 1.9 Nitrogen% by weight 0.9 Oxygen% by weight 2.4 Asphaltenes% by weight 2.0 Carbon Conradson % by weight 3.1 Metals ppm 195 Shale oil, whose hydrocarbons less than C5 were separated, is subjected to a prior atmospheric distillation, from which are isolated volatile products, constituents of gas oils, kerosenes, and naphthas, which are processed in the refining chain according to their properties. The atmospheric distillation of shale oil also produces an atmospheric residue, comprising within it a majority of compounds having a boiling point above 350 ° C. The atmospheric residue, in the context of the present example, represents 40% by weight of the filler. The latter undergoes propane deasphalting with a solvent / filler ratio of 5/1; at a temperature of 100 ° C, and at 4 MPa. A deasphalted oil and a residue are obtained. The deasphalted oil is processed in a bubbling bed reactor containing the HTS458 commercial catalyst from Axens. The operating conditions for use are the following: 5 - Temperature in the reactor: 425 ° C - Pressure: 195 bar (19.5 MPa) - Hydrogen / charge ratio: 400 Nm3 / m3 - global WH: 0.6 h The liquid products from the reactor are fractionated by atmospheric distillation into a naphtha fraction (C5 + - 150 ° C), a gas oil fraction (150-370 ° C) and a residual fraction 370 ° C + which constitutes a heavier fraction than diesel fuel. . The naphtha fraction is subjected to a fixed bed hydrotreatment using a NiMo catalyst on alumina. The operating conditions are the following: - Temperature in the reactor: 320 ° C - Pressure: 50 bar (5 MPa) - Hydrogen / charge ratio: 400 Nm3 / m3 - global WH: 1 h-1 The diesel fraction is subjected to a fixed bed hydrotreatment using a NiMo catalyst on alumina. The operating conditions are the following: - Temperature in the reactor: 350 ° C - Pressure: 120 bar (12 MPa) - Hydrogen / charge ratio: 400Nm3 / m3 - Overall VVH: 0.6 h-1 The heavier fraction than diesel is then catalytically cracked using a catalyst containing 20% by weight of zeolite Y and 80% by weight of a silica-alumina matrix. This preheated charge at 135 ° C. is brought into contact at the bottom of a vertical reactor with a hot regenerated catalyst from a regenerator. The catalyst inlet temperature in the reactor is 720 ° C. The ratio of catalyst flow to charge flow is 6.0. The heat input of the catalyst at 720 ° C allows the vaporization of the feedstock and the cracking reaction, which are endothermic. The average residence time of the catalyst in the reaction zone is about 3 seconds. The operating pressure is 1.8 bar absolute. The temperature of the catalyst measured at the outlet of the riser fluidized bed reactor is 525 ° C. The cracked hydrocarbons and the catalyst are separated by cyclones located in a stripper zone where the catalyst is stripped. The catalyst, which is coked during the reaction and then stripped into the disengaging zone, is then fed into the regenerator. The coke content of the solid (delta coke) at the inlet of the regenerator is 0.85%. This coke is burned by air injected into the regenerator. The highly exothermic combustion raises the solid temperature from 525 ° C to 720 ° C. The regenerated and hot catalyst leaves the regenerator and is returned to the bottom of the reactor. The hydrocarbons separated from the catalyst leave the zone of disengagement. They are directed to a main fractionation tower from which the gases and gasoline cuts are leading, then in order of increasing boiling point, the LCO, HCO and slurry sections (370 ° C +) at the bottom of the tower. Table 2 gives the properties of the different loads of each step as well as the yields obtained in the different units and the overall yield. It is then observed that starting from 100% by weight of shale oil gives 86.2 by weight of products (LPG, naphtha, middle distillates) to the commercial specifications Euro V.

Table 2 Distillation Unit Deasphalting Deasphalting H-Oiluc FCC Atmospheric solvent solvent refining Charge Shale oil Shale oil Shale oil Oil C5 bottom + 360 ° C + 360 ° C + deasphalted H-0nm Product Shale oil Oil Residue Bottom H -011m Products 360 ° C + deasphalted ex-FCC Yield in% in 40.0 28.0 12.0 5.9 product on weight load resulting from shale oil Product properties Density (d15 / 4) - 1.035 0.980 1.191 0.905 Sulfur 0/0 in 1.5 1.3 2.0 0.06 weight Total nitrogen cYo in 1.1 0.7 1.8 0.15 weight Yield on each unit LPG 0/0 in 2.0 10.0 weight Naphtha% in 19.0 55.0 weight Average distillate 0/0 in 56.0 14.0 weight Fund% in 21.0 5.0 weight% in weight Yield on% in shale oil weight LPG% in 0.6 0.6 weight Naphtha% in 5.3 3.2 weight Average distillate cYo in 15.7 0.8 weight Melting in 5.9 0.3 total weight 60.0 21.6 4.6 (LPG + naphtha + distillate medium) / shale oil charge Total 86.2 (LPG + naphtha + dist illat medium) / tank ge shale oil 28

Claims (17)

REVENDICATIONS1. A hydrocarbon feed conversion process comprising at least one shale oil having a nitrogen content of at least 0.1%, often at least 1% and often at least 2% by weight, characterized in that It comprises the following steps: a) The feed is decontaminated to obtain a residue and a decontaminated oil, b) The decontaminated oil is sent to a hydroconversion section 10 in the presence of hydrogen, said section comprising at least one ebullating bed reactor operating at an upward flow of liquid and gas and containing at least one supported hydroconversion catalyst; c) The effluent obtained in step b) is sent, at least in part, and often in whole, in a fractionation zone from which a gaseous fraction, a naphtha fraction, a gas oil fraction and a heavier fraction than diesel oil are recovered by atmospheric distillation, d) The naphtha fraction is partly, and often in whole, in a hydrotreating section in the presence of hydrogen, said section comprising at least one fixed bed reactor containing at least one hydrotreatment catalyst, and e) said diesel fuel fraction is treated, at less in part, and often in whole in a hydrotreating section in the presence of hydrogen, said section comprising at least one fixed bed reactor containing at least one hydrotreatment catalyst. 2. Method according to claim 1, characterized in that it further comprises a step f1, in which the heavier fraction than diesel is returned to step a) to be decontaminated. 3. Method according to one of the preceding claims, wherein the effluent obtained in step b) is fractionated by atmospheric distillation into a gaseous fraction having a boiling point below 50 ° C, a naphtha fraction boiling between about At 50.degree. C. and 150.degree. C., a gas oil fraction boiling between about 150.degree. C. and 370.degree. C., and a heavier fraction than the diesel type fraction, boiling generally above 340.degree. C., preferably above 370 ° C 4. Method according to one of the preceding claims, wherein the decontamination of step a) is carried out with a solvent selected from the group consisting of propane, n-butane, isobutane, n-pentane, cyclopentane, 2-methylbutane, 2,2-dimethylpropane, and mixtures thereof in all proportions. 5. Method according to one of the preceding claims, wherein the decontamination step a) is carried out with a solvent / filler ratio of 3/1 to 8/1, preferably 4/1 to 6/1, at a temperature between 60 ° C and 250 ° C, preferably between 60 ° C and 200 ° C, and at a pressure between 4 MPa and 5 MPa. 6. Method according to one of the preceding claims, wherein the fixed bed hydrotreating section of step d) and / or e) comprises, upstream of the hydrotreatment catalytic beds, at least one specific guard bed. to the compounds of arsenic and silicon. 7. Method according to one of the preceding claims, wherein the heavier fraction that diesel is sent to a catalytic cracking section, called step g), in which it is treated under conditions making it possible to produce a second gaseous fraction, a second petrol fraction, a second diesel fraction and a second fraction heavier than diesel. 8. The method of claim 7, wherein at least a portion of the second heavier than diesel fraction obtained at the end of step g) is recycled to the input of said step g). 9. The method of claim 7, wherein at least a portion of the second gas oil fraction obtained at the end of step g), is recycled to step e) of hydrotreating diesel fuel. 10. The method of claim 7, wherein at least a portion of the second heavier fraction that diesel obtained after step g), is recycled to the decontamination step a). 11. Method according to one of the preceding claims, wherein the hydroconversion step b) operates at a temperature between 300 ° C and 550 ° C, preferably between 400 ° C and 450 ° C at a total pressure. between 2 and 35 MPa, preferably between 10 and 20 MPa, at an hourly mass velocity (t of load / h) / t of catalyst) of between 0.2 and 1.5 h -1, and at a ratio of hydrogen / charge between 50 and 5000 Nm3 / m3, preferably between 100 and 1000 Nm3 / m3. 12. Method according to one of the preceding claims, wherein the step d) of hydrotreatment of the naphtha fraction operates at a temperature between 280 ° C and 380 ° C, preferably between 300 ° C and 350 ° C, at a total pressure of between 4 and 15 MPa, preferably between 10 and 13 MPa, at an hourly mass velocity of between 0.1 and 5 h -1, preferably between 0.5 and 1 h -1, and at a hydrogen / charge ratio of between 100 and 5000 Nm3 / m3, preferably between 100 and 1000 Nm3 / m3. 13. Method according to one of the preceding claims, wherein the step e) of hydrotreating of the gas oil fraction operates at a temperature between 320 ° C and 450 ° C, preferably between 340 ° C and 400 ° C, at a total pressure of between 7 and 20 MPa, preferably between 10 and 15 MPa, at an hourly mass velocity of between 0.1 and 1 h -1, preferably between 0.3 and 0.8 h -1, and a hydrogen / charge ratio of between 100 and 5000 Nm3 / m3, preferably between 200 and 1000 Nm3 / m3. The process according to one of the preceding claims, wherein the catalyst of hydroconversion steps b) and hydrotreating d) and e) are independently selected from the group of catalysts comprising a Group VIII metal selected from the group formed. with Ni and / or Co, optionally a Group VIB metal selected from the group formed by Mo and / or W, on an amorphous support selected from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures thereof. The process according to one of the preceding claims, wherein the hydrocarbon feedstock also comprises a feedstock selected from the group consisting of coal derived oils, oils obtained from heavy tar and oil sands, vacuum distillates, and direct distillation residues, vacuum distillates and unconverted residues from residue conversion process, solvent deasphalted oils, light cutting oils, heavy cutting oils, diesel fuel cuts from catalytic cracking having in general a distillation range of about 150 ° C to about 650 ° C, aromatic extracts obtained in the manufacture of lubricating oils, pyrolysis oils of wood residues such as wood residues, crudes from biomass ("biocrudes"), vegetable oils and animal fats, or mixtures of such fillers. 16. Synthetic crude, obtained by a process according to one of the preceding claims. 17. Installation intended for treating a shale oil, comprising: a section for decontaminating the shale oil to be treated; a hydroconversion section in the presence of hydrogen comprising a bubbling bed reactor operating at an upward flow of liquid and gas and containing at least one supported hydroconversion catalyst, - an atmospheric distillation fractionation zone, - a hydrotreating section in the presence of hydrogen, comprising a fixed bed reactor containing at least one hydrotreatment catalyst another hydrotreatment section in the presence of hydrogen comprising at least one fixed bed reactor containing at least one hydrotreatment catalyst, these elements being arranged for carrying out the process according to one of claims 1 to 15; .