CA2816666A1 - Method for converting hydrocarbon feedstock comprising a shale oil by hydroconversion in an ebullating bed, fractionation by atmospheric distillation and hydrocracking - Google Patents

Abstract

A hydrocarbon feed conversion method and device comprising a shale oil, comprising a bubbling bed hydroconversion stage, a fractionation into light fractions, naphtha, diesel fuel and heavier than diesel fuel, the naphtha and diesel fractions being hydrotreated, the fraction plus heavy diesel fuel being hydrocracked, the products of the hydrocracking being returned to the hydrotreating step. The process aims to maximize the yield of fuel bases.

Description

PROCESS FOR CONVERTING HYDROCARBONATED LOAD
COMPRISING HYDROCONVERSION SCHIST OIL
IN BOILING BED, FRACTIONATION BY DISTILLATION
ATMOSPHERIC, AND HYDROCRACKING
The invention relates to a method for converting loads hydrocarbons comprising a shale oil in products more light, recoverable as fuels and / or raw materials for petrochemicals. More particularly, the invention relates to a method for converting hydrocarbon feedstocks comprising an oil of shale comprising a step of hydroconversion of the bed load bubbling, followed by a fractionation step by distillation atmospheric light fraction, naphtha, diesel and in a fraction heavier than the diesel fraction, a hydrotreatment dedicated to each naphtha and diesel fractions, and a hydrocracking of the fraction plus heavy as diesel. This process makes it possible to convert shale oils based on fuels of very good quality and aims in particular at excellent performance.
Given the high volatility of the price of a barrel and a decrease in discoveries of conventional oil fields, the oil companies are turn to unconventional sources. Alongside the sands and deep offshore oil shale, although relatively unknown, are more and more coveted.
Oil shales are sedimentary rocks containing an insoluble organic substance called kerogen. By In-situ or ex-situ heat treatment (retorting according to Anglo-Saxon terminology) in the absence of air at temperatures between 400 and 500 C, these schists release an oil, the oil shale, the general appearance of which is that of crude oil.
Although of different composition of crude oil, the oils of shale can be a substitute for the latter and also a source of chemical intermediates.
Shale oils can not substitute directly crude oil applications. Indeed, although these oils in some ways resemble oil (for example by a ratio of H / C similar), they are distinguished by their chemical nature and by a content of metallic and / or non-metallic impurities much

2 more important, which makes the conversion of this resource no conventional more complex than oil. The oils of shale have, in particular, oxygen and nitrogen higher than oil. They may also contain higher concentrations of olefins, sulfur or compounds metal (including arsenic).
Shale oils obtained by pyrolysis of kerogen contain many olefinic compounds resulting from cracking, which implies an additional demand for hydrogen in the refining. Thus, the bromine index, which makes it possible to calculate the concentration by weight of olefinic hydrocarbons (by addition of bromine on the ethylenic double bond), is generally greater than 30g / 100g load for shale oils, while it is between 1 and 5 g / 100g load for the oil residues. Compounds olefins resulting from cracking consist essentially of mono olefins and diolefins. The unsaturations present in olefins are a potential source of instability by polymerization and / or oxidation.
The oxygen content is generally higher than in the heavy crudes and can reach up to 8% by weight of the load. The oxygenates are often phenols or acids carboxylic. As a result, shale oils may exhibit marked acidity.
The sulfur content varies between 0.1 and 6.5% by weight, requiring severe desulphurisation treatments in order to reach the specifications of fuel bases. The sulfur compounds are under form of thiophenes, sulphides or disulfides. In addition, the profile of Sulfur distribution within a shale oil may be different from that obtained in a conventional oil.
The most distinctive feature of shale oils is nevertheless their high nitrogen content, which makes them unsuitable as the conventional load of the refinery. Oil contains general rule around 0.2% by weight of nitrogen whereas raw shale generally contain from 1 to about 3%
by weight or more of nitrogen. In addition, the nitrogen compounds present in oil are usually concentrated in the boiling ranges higher than the nitrogen compounds present in the oils of

3 Raw shale is usually distributed across all ranges boiling of the material. Nitrogen compounds in petroleum are predominantly non-basic compounds, whereas generally the about half of the nitrogen compounds present in shale oils brutes is basic in nature. These basic nitrogen compounds are particularly undesirable in refining loads as these compounds often act as catalyst poisons. More, product stability is a problem that is common to many many products derived from shale oil. Such instability, including photosensitivity, appears to result essentially from the presence of nitrogen compounds. Therefore, shale oils brutes must generally be subjected to a treatment of severe refining (high total pressure) to obtain crude oil synthetic or fuel-based products respecting the specifications in force.
Similarly, it is known that shale oils may contain many trace metal compounds, usually present as organometallic complexes. From metal compounds, mention may be made of conventional contaminants such as nickel, vanadium, calcium, sodium, lead or iron, but also metal arsenic compounds. Indeed, the oils of shale may contain an amount of arsenic greater than 20 ppm while the amount of arsenic in crude oil is usually in the area of ppb (parts per billion). All these compounds Metallic poisons are catalysts. In particular, they irreversibly poison hydrotreatment catalysts and hydrogenation by gradually depositing on the active surface.
The classical metal compounds and some of the arsenic are are found mainly in heavy cuts and are eliminated by depositing on the catalyst. On the other hand, when the products containing arsenic are able to generate volatile compounds, these can be found partly in lighter cuts and can, therefore, poison the catalysts of subsequent processing, during refining or in petrochemicals.
In addition, shale oils generally contain sandy sediments from oil shale deposits from which shale oils are extracted. These sandy sediments

4 can create clogging problems, especially in fixed bed reactors.
Finally, shale oils contain waxes that give a pour point higher than the 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, recoverable as fuels and / or raw materials for the petrochemicals. Shale oil conversion processes are known. Conventionally, the conversion is done either by coking or by hydroviscoreduction (thermal cracking in the presence of hydrogen), or by hydroconversion (catalytic hydrogenation). We also knows processes of liquid / liquid extraction.
Thus, patent document FR2197968 describes a method of filtration and hydrogenation of shale oils or sand oils bitumen containing particles, comprising the steps comprising (a) continuously passing said oil to the foot of a reactor in mixture with hydrogen, (b) intermittently catalyst at the top of the reactor and remove catalyst and particles entrained at the bottom of the reactor to carry out a transfer of catalyst through the reactor, (c) measure the pressure drop between the bottom and the reactor head, and (d) adjust the catalyst flow to correct the pressure drop at a preselected pressure that corresponds to a desired filtration rate in the reactor. The method described in FR2197968 is particularly silent on the use of independent hydrotreatment sections of naphtha fractions and diesel.
US 6153087 discloses a conversion process heavy loads including bubbling bed conversion and hydrocracking. The process is applied to different loads heavy having an initial boiling point of not less than 300 The application to shale oils is neither mentioned nor suggested.
The use of independent fractional hydrotreatment sections naphtha and diesel is not envisaged.

Object of the invention The specificity of shale oils being to have a certain number of metallic and / or non-metallic impurities makes the

5 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. Treatments known petroleum refining systems must therefore be adapted to the specific composition of shale oils.
The present invention aims at improving the known methods of conversion of hydrocarbon feeds comprising an oil of shale, notably by increasing the yield of fuel bases for a combination of steps having a specific sequence, and a treatment adapted to each fraction resulting from shale oils. Of The object of the present invention is also to obtain good quality having in particular a low 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, investment costs.
In its widest form, and according to a first aspect, the The present invention is defined as a process for converting hydrocarbon feedstock comprising at least one shale oil having a nitrogen content of at least 0.1%, often at least 1% and very often at least 2% by weight, characterized in that it comprises the following steps:
a) The load is sent to a hydroconversion section in the presence of hydrogen, said section comprising at least one ebullating bed reactor operating with an upward flow of liquid and gas and containing at least one hydroconversion catalyst supported, (b) The effluent obtained in step (a) is sent, at least part, and often in whole, in a splitting zone from from which is recovered by atmospheric distillation a fraction

6 gas, a naphtha fraction, a diesel fraction and a fraction heavy as diesel, (c) the said naphtha fraction is treated, at least in part, and often entirely in a first section of hydrotreatment in presence of hydrogen, said first section comprising at least a first fixed bed reactor containing at least a first hydrotreatment catalyst, (d) The said diesel fraction is treated, at least in part, and often entirely in a second hydroprocessing section in presence of hydrogen, said second section comprising at least one second fixed bed reactor containing at least a second hydrotreatment catalyst, and (e) The heavier fraction than diesel is treated, at least in part, and often entirely in a hydrocracking section in presence of hydrogen.
Usually, the hydroconversion section of step a) comprises from one to three, and preferably two, reactors in series, and first and second hydrotreatment sections of steps c) and d) each independently of one to three reactors series.
The research work carried out by the applicants on the conversion of shale oils led to the discovery that improvement of existing processes in terms of base performance fuels and purity products is possible by a combination different stages, chained in a specific way. Each fraction obtained by the process according to the invention is then sent in a treatment section.
In a first step, the hydrocarbon feedstock comprising shale oil undergoes bed hydroconversion bubbly. The bubbling bed technology allows, compared to fixed bed technology, to handle heavily contaminated loads metals, heteroatoms and sediments, such as shale oils, while having conversion rates that are generally higher than 50%. In fact, in this first stage, shale oil is transformed into molecules to generate future bases WO 2012/08540

7 PCT / FR2011 / 053021 fuels. Most of the metal compounds, sediments and heterocyclic compounds are removed.
The effluent leaving the bubbling bed thus contains the nitrogenous compounds and most refractory sulfides, and possibly compounds of Volatile arsenic found in lighter components.
The effluent obtained in the hydroconversion stage is then fractionated by atmospheric distillation to obtain different fractions for which specific treatment at each fraction is carried out thereafter. Atmospheric distillation allows, in one step, to obtain the different desired fractions (naphtha, diesel), thus facilitating a downstream hydrotreatment adapted to each fraction and, consequently, the direct fuel bases naphtha or diesel respecting the different specifications. The fractionation after hydrotreatment is therefore not necessary.
Thanks to the strong reduction of contaminants in the bed boiling, light fractions (naphtha and diesel) contain less of contaminants and can therefore be processed in a bed section fixed generally having improved hydrogenation kinetics compared to the bubbling bed. Likewise, the operating conditions may be milder due to the limited contaminant content. The providing a treatment for each fraction makes it possible to have a better operability according to the desired products. According to operating conditions chosen (more or less severe), we can obtain either a fraction that can be sent to a fuel pool, a finished product meeting the specifications (sulfur content, smoke point, cetane, aromatic content, etc.) in force.
Fixed bed hydrotreatment sections include preferably upstream of the catalytic beds of hydrotreating beds of specific safeguards for arsenic and silicon compounds contained in the naphtha and / or diesel fractions. The compounds of arsenic having escaped the bubbling bed (because usually relatively volatile) are fixed in the guard beds, avoiding to poison the downstream catalysts, and to obtain fuel bases heavily depleted in arsenic.
Atmospheric distillation also helps to concentrate the most refractory nitrogen compounds in the heavier fraction than

8 the diesel fraction, which in step e) is hydrocracked. This step hydrocracking makes it possible to recover the heavier fraction than diesel by producing lighter products and thus minimizing problems of valuation and economic opportunities of this fraction.
detailed description Hydrocarbon load The hydrocarbon feedstock comprises at least one shale or a mixture of shale oils. The term shale oil is used here in its broadest sense and is meant to include any oil from shale or a fraction of shale oil, which contains impurities nitrogen. This includes crude shale oil, whether obtained by pyrolysis, extraction by solvent or other means, shale that has been filtered to remove solids, or has been treated with one or more solvents, chemicals, or other treatments, and which contains nitrogen impurities. The term oil of shale also includes shale oil fractions obtained by distillation or by another 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, a content of asphaltenes (Standard 1P143 / C7) by at least 1%, often by at least 2% by weight. Their sulfur content is generally at least 0.1%, often at least 1% and often at least 2%, or even 4% or even 7% by weight. The amount of metals they contain is usually at least 5 ppm by weight, often at least 50 ppm by weight, and typically at least 100 ppm by weight or from less than 200 ppm by weight. Their nitrogen content is generally from less than 0.5%, often at least 1% and very often at least 2%
weight. Their arsenic content is generally greater than 1 ppm in weight, and up to 50 ppm by weight.
The process according to the present invention aims at converting oils shale. However, the load may also contain, in addition to shale oil, other synthetic liquid hydrocarbons, in particular especially those that contain a significant amount of

9 organic cyclic nitrogen. This includes oils derived from coal, oils obtained from heavy tar, sands bitumen, pyrolysis oils of ligneous residues such as wood residues, biomass crudes (biocrudes), oils vegetable and animal fats.
Other hydrocarbon feedstocks can also complement shale oil or the mixture of shale oils. The charges are selected from the group consisting of oils derived from coal, oils obtained from heavy tar and oil sands, vacuum distillates and direct distillation residues, vacuum distillates and unconverted residues from such as, for example, those derived from distillation up to coke (coking), products resulting from a hydroconversion fixed bed heavy goods, products derived from hydroconversion processes heavy boiling bed, and oils désalphatées solvents (for example deasphalted propane, butane and pentane resulting from the deasphalting of vacuum residues direct distillation or vacuum residues from processes hydroconversion). Charges may also contain oil light cycle (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 coupes from catalytic cracking generally having a range of distillation from about 150 ° C. to about 650 ° C.
also contain aromatic extracts obtained in the context of the manufacture of lubricating oils. Charges can also be prepared and used in a mixture, in all proportions.
Hydrocarbons added to shale oil or mixture of shale oils can represent from 20 to 60% by weight of the total hydrocarbon feedstock (shale oil or blend of shale + added hydrocarbons), or even from 10% to 90% by weight.
hydroconversion The charge containing a shale oil is subject to a hydroconversion stage [step a)] in a bubbling bed. By hydroconversion means hydrogenation reactions, hydrotreatment, hydrodesulfurization, hydrodenitrogenation, hydrodemetallization and hydrocracking.
The operation of the bubbling bed catalytic reactor, including including recycling the reactor liquids upwards through 5 of the agitated catalyst bed is generally well known. The bubbling bed technologies use supported catalysts, generally in the form of extrudates, the diameter of which 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

10 not evacuated with the products. Catalytic activity can be kept constant by replacing (adding and withdrawing) catalyst line. It is not necessary to stop the unit for change the used catalyst, or increase the temperatures of reaction along the cycle to compensate for the deactivation. In addition, working with constant operating conditions allows to obtain consistent returns and product qualities throughout along the catalyst cycle. Since the catalyst is maintained in agitation by a large recycling of liquid, the pressure drop on the reactor remains weak and constant, and the heat of reaction is quickly averaged over the catalytic bed, which is almost isothermal and does not require cooling via injection of quenches. The implementation of hydroconversion in bubbling bed eliminates catalyst contamination problems related to deposits of impurities naturally present in the oils of Shale.
The conditions of step a) of the charge treatment in presence of hydrogen are usually conventional conditions hydroconversion in bubbling bed of a hydrocarbon fraction liquid. It is usually operated under a total pressure of 2 to 35 MPa, preferably from 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 hydrogen partial pressure are important factors that depending on the characteristics of the product to be treated and the desired conversion. Most often, VVH is located 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 load is usually 50 to 5000 normal cubic meters (Nm3) per cubic meter (m3) of load

11 liquid, and most often from 100 to 1000 Nm3 / m3, and preferably from 300 to 500 Nm3 / m3;
Most often, this step a) hydroconversion can be put under the conditions of the T-STAR process, as described by example in the article Heavy Oil Hydroprocessing, published by Aiche, March 19-23, 1995, HOUSTON, Texas, paper number 42d. She can also be implemented under the conditions of the H-OILO process, as described for example in the article published by the NPRA, Annual Meeting, March 16-18, 1997, JJ Colyar and LI Wisdom under the title THE H-OILOPROCESS, WORLDWIDE LEADER IN VACUUM
RESIDUE HYDROPROCESSING.
The hydrogen needed for hydroconversion (and subsequent hydrotreatments) may be from steam reforming hydrocarbons (methane) or gas from shale bitumen during the production of shale oils.
The catalyst of step a) is preferably a catalyst conventional granular hydroconversion, comprising on a support amorphous at least one metal or metal compound having a function hydrodehydrogenating. In general, a catalyst is used which porous distribution is suitable for the treatment of metals.
The hydro-dehydrogenating function can be ensured by least one Group VIII metal selected from the group formed by the nickel and / or cobalt, optionally in combination with at least a group VIB metal selected from the group consisting of molybdenum and / or tungsten. For example, a catalyst can be used 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 molybdenum weight, preferably 5 to 20% by weight of molybdenum (expressed in molybdenum oxide MoO3), on a mineral support amorphous. The total content of Group VIB and VIII metal oxides is often from 5 to 40% by weight and in general from 7 to 30% by weight. The weight ratio expressed as metal oxide between metal (or metals) group VI on metal (or metals) of group VIII is generally 20 to 1 and most often 10 to 2.
The catalyst support will for example be chosen from the group formed by alumina, silica, silica-aluminas, magnesia,

12 clays and mixtures of two or more of these minerals. This support may also contain other compounds, for example oxides selected from the group consisting of boron oxide, zirconia, titanium, phosphoric anhydride. We most often use a support of alumina, and very often a carrier of alumina doped with phosphorus and possibly boron. In this case, the concentration in Phosphoric anhydride P205 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 boron trioxide B203 is usually from about 0 to about 10% by weight. 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 a) is based on nickel and molybdenum, doped with phosphorus and supported on alumina. One can for example use a catalyst of the type HTS 458 marketed by the company AXENS.
Prior to the injection of the charge, the catalysts used in the process according to the present invention can be subjected to a sulphurisation treatment to transform, at least into part, the metallic species in sulphides before they come into contact with the load to be treated. This sulphidation activation treatment is well known to those skilled in the art and can be carried out by any method already described in the literature either in situ, that is to say in the reactor, ie ex-situ.
The used catalyst is partly replaced by a catalyst fresh by racking down the reactor and introducing the top of the fresh or new catalyst reactor at regular time interval, by example by punctual addition, or almost continuously. We can for example, introducing fresh catalyst every day. The rate of replacement of spent catalyst with fresh catalyst may be by example of about 0.05 kg to about 10 kg per m 3 of filler. This racking and replacement are carried out using allowing the continuous operation of this stage hydroconversion. The unit usually has a pump recirculation allowing the maintenance of the catalyst in bubbling bed 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

13 to send spent catalyst withdrawn from the reactor in a zone of regeneration in which one removes the carbon and sulfur that he encloses and then return this regenerated catalyst to the reactor hydroconversion of step a).
The operating conditions coupled with the catalytic activity allow you to get load conversion rates that can go from 50 to 95%, preferably from 70 to 95%. The conversion rate mentioned above is defined as the mass fraction of the charge 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 exit from the reaction section, all divided by the mass fraction the charge at the inlet of the reaction section.
Bubble bed technology can handle loads heavily contaminated with metals, sediments and heteroatoms, without encounter problems of loss of charge or clogging known in the case of fixed bed use. Metals such as nickel, vanadium, iron and arsenic are largely eliminated from the charge settling on the catalysts during the reaction. arsenic remaining (volatile) will be removed during the hydrotreatment steps by specific guard beds. The sediments contained in the oils of shale are also eliminated through the replacement of the catalyst in the bubbling bed without disturbing the reactions hydroconversion. These steps also eliminate hydrodenitrogenation most of the nitrogen, leaving only the most refractory nitrogen compounds.
The hydroconversion of step a) makes it possible to obtain an effluent nitrogen content very low compared to that of the load, the order from 3 times to 10 times less than in the load.
Fractionation by atmospheric distillation The effluent obtained in step a) of hydroconversion is sent to least in part, and preferably in whole, in a zone of fractionation from which is recovered by distillation a gaseous fraction, a naphtha fraction, a fraction diesel and a heavier fraction than the diesel fraction.
Preferably, the effluent obtained in step a) is fractionated by atmospheric distillation into a gaseous fraction having a point

14 boiling point below 50 ° C, a naphtha fraction boiling between about 50 C and 150 C, a diesel fraction boiling between 150 C and 370 C, and a heavier fraction than the diesel fraction boiling generally above 340 C, preferably above The naphtha and diesel fractions are then sent separately in hydrotreatment sections. The heavier fraction than the diesel fraction is sent to the hydrocracking section of the stage e).
The gaseous fraction contains gases (H2, H2S, NH3, H2O, CO2, CO, C 1 -C 4 hydrocarbons, ...). It can advantageously undergo a purification treatment to recover hydrogen and recycle it in the hydroconversion section of step a) or in sections hydrotreating steps c) and d). C3- and C4 hydrocarbons may, after purification treatment, serve to constitute LPG products (liquefied petroleum gases). Incondensable gases (Ci-C2) are usually used as internal fuel for furnaces for heating hydroconversion and / or hydrotreating reactors and / or hydrocracking.
hydrocracking The method according to the invention comprises a step of hydrocracking method [step e)], in which at least a portion, and preferably the whole of the heavier fraction than diesel obtained at step b) is sent to a hydrocracking section in the presence hydrogen, in which said heavier fraction than diesel is conventionally treated under well-known conditions of those skilled in the art, to produce a second gaseous fraction, a second naphtha fraction, a second diesel fraction and a second heavier fraction than diesel, called unconverted oil according to the Anglo-Saxon terminology. The second naphtha fraction will be for example treated, at least in part, and often entirely in the hydrotreatment section of step c). The second diesel fraction will be, for example, at least in part, often in full, sent to fuel tanks and / or recycled at least in part, or even in total, in step d) of hydrotreatment. The second fraction plus that diesel will be, for example, at least in part or even in all, sent to the fuel pool and / or recycled at least partly, if not all, in hydroconversion stage a) and / or step e) hydrocracking.
Hydrocracking effluents, obtained at the end of stage e), can also be separated into a diesel fraction and less heavy than diesel, and a second fraction heavier than diesel. This fraction diesel and lighter than diesel is a mixture of a second gaseous fraction, a second naphtha fraction and a second diesel fraction.
10 The diesel fraction and less heavy than diesel can be sent, at least in part, and often in whole, in a zone of splitting of step b).
For example, a brief description of hydrocracking in ULLMANS ENCYCLOPEDIA OF INDUSTRIAL

15 CHEMISTRY VOLUME A18, 1991, page 71. Usually used a conventional catalyst or an assembly of conventional catalysts arranged on separate fixed beds. Catalysts used include combinations of metals supported on aluminas or zeolites. Examples of catalysts used in the context of industrial exploitation of a hydrocracker include catalysts Ni-Mo on alumina, Ni-Mo on zeolite, Ni-Mo and Ni-W on silica-alumina, Co-Mo on alumina and Co-Mo on zeolite. These catalysts may also contain, depending on the desired properties, other metals selected from transition metals and rare, in trace amounts or in relatively large proportions (from less than 1% by weight to 30% by weight relative to the total metals) in metallic form or in oxide form.
Hydrocracking is carried out in a vertical reactor, usually in descending mode. The charge is preheated in presence of hydrogen before introduction to the reactor head. A
hydrogen is supplied between each catalyst bed quench) to reduce the temperature. This quench gas is then intimately mixed with the charge, usually in devices called quench boxes.
The choice of the catalyst and the operating conditions are function of the desired products according to the load treated. The hydrocracking units are usually operated at

16 temperatures between 320 C and 450 C, preferably between 350 C and 400 C, with hourly mass velocities between 0.3 and 7 h -1, with a hydrogen / charge ratio of between 300 and 1000 Nm3 of hydrogen / m3 of charge. There are two types hydrocrackers according to their service pressure: (1) MHC, acronym for Mild HydroCracking (mild hydrocracking), which have service pressures usually between 8 and MPa, more generally between 10 and 12 MPa, and (2) DHCs, acronym for Distillate HydroCracking, which have 10 operating pressures usually between 12 and 20 MPa, more generally between 15 and 20 MPa.
Step e) hydrocracking of the heavier fraction than diesel operates at a temperature of between 350 ° C. and 450 ° C., preferably between 370 C and 425 C, at a total pressure of between 10 and 20 15 MPa, preferably between 15 and 18 MPa, at a speed hourly mass between 0.3 and 7 h-1, preferably between 0.5 and 1.5 h-1, and at a hydrogen / charge ratio of between 100 and 5000 Nm3 / m3, preferably between 1000 and 2000 Nm3 / m3.
The use of an MHC, in the context of the invention, will produce effluents converted to approximately 10 to 20%, sufficient to constitute a synthetic crude oil, after mixing with the different slices naphtha and diesel fuel from the process. This synthetic crude can then be shipped to a conventional refinery. So alternative, the use of a DHC in the context of the invention would produce 80 to 90% converted effluent, which would allow to direct products rather towards commercialization as bases for the manufacture of fuels.
Hydrotreatment of the naphtha fraction and the fraction diesel The naphtha and diesel fractions are then submitted separately to fixed bed hydrotreatment [steps c1 and d]]. By hydrotreatment hydrodesulfurization, hydrodenitrogenation and hydrodemetallization. The objective is, depending on the operating conditions chosen in a more or less severe way, to bring different specifications (sulfur content, smoke point, cetane, aromatic content, etc.) or to produce a crude oil

17 synthetic. Treating the naphtha fraction in a section hydrotreatment and the diesel fraction in another section hydrotreatment makes it possible to have better operability at operating conditions, so that each section can be brought to required specifications with maximum efficiency and this in one single step by cut. Thus, fractionation after hydrotreatment is not necessary. The difference between the two sections hydrotreatment is based more on different conditions only on the choice of catalyst.
Fixed bed hydrotreatment sections include, preferably, upstream of the hydrotreatment catalytic beds, beds compounds specific for arsenic compounds (arsenic compounds) and silicon optionally contained in the naphtha and / or diesel. The arsenic compounds escaping the bubbling bed (because generally relatively volatile) are fixed in the guard beds, thus avoiding poisoning the catalysts downstream, and allowing to obtain fuel bases heavily depleted of arsenic.
Guard beds to remove 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.
We can also mention the guard beds marketed by the company AXENS: ACT 979, ACT989, ACT961, ACT981.
The operating conditions of each hydrotreatment section are adapted to the load to be treated. Operating conditions hydrotreatment of the naphtha fraction are generally milder than those of the diesel fraction.
In the hydrotreating step of the naphtha fraction [step c)], usually operates under an absolute pressure of 4 to 15 MPa, often 10 to 13 MPa. The temperature during this step c) is usually from 280 C to 380 C, often from 300 C to 350 C. This temperature is usually adjusted according to the desired level hydrodesulfurization. Most often, hourly space velocity (VVH) is in a range from 0.1 hr -1 to 5 hr -1, and preferably from 0.5 h-1 to 1 hr-1. The amount of hydrogen mixed with the charge is

18 usually from 100 to 5000 normal cubic meters (Nm3) per meter cube (m3) of liquid charge, and most often from 200 to 1000 Nm3 / m3, and preferably from 300 to 500 Nm3 / m3. One operates usefully in presence of hydrogen sulphide (for catalyst sulphidation) and partial pressure of hydrogen sulfide is usually 0.002 times to 0.1 times, and preferably from 0.005 times to 0.05 times the pressure total.
In the step of hydrotreating the diesel fraction [step d)], usually operates under an absolute pressure of 7 to 20 MPa, often 10 to 15 MPa. The temperature during this step d) is usually 320 C to 450 C, often 340 C to 400 C. This temperature is usually adjusted according to the desired level hydrodesulfurization. The hourly mass speed is between 0.1 and 1 h-1. Most often, the hourly space velocity (VVH) is in a range 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 charge is usually from 100 to 5000 normal cubic meters (Nm3) per meter cube (m3) of liquid charge, and most often from 200 to 1000 Nm3 / m3, and preferably from 300 to 500 Nm3 / m3. One operates usefully in presence of hydrogen sulphide, and the partial pressure of hydrogen sulphide is usually 0.002 times to 0.1 times, and preferably 0.005 times at 0.05 times the total pressure.
In the hydrotreatment sections, the ideal catalyst must have a strong hydrogenating power, so as to achieve a deep refining products, and to achieve a significant reduction in the content of sulfur and nitrogen. In the preferred embodiment, the sections of hydrotreatment operate at a relatively low temperature, which will in the sense of a deep hydrogenation and a limitation of coking the catalyst. We would not go beyond the scope of this invention using, in the hydrotreatment sections, so simultaneous or successively, a single catalyst or several different catalysts. Usually, hydrotreating steps c) and d) is carried out industrially, in one or more reactors with downflow of liquid.
In both hydrotreatment sections [steps c) and d)]
uses the same type of catalyst, the catalysts in each section may be the same or different. At least one fixed bed of

19 conventional hydrotreatment catalyst, comprising on a support amorphous at least one metal or metal compound having a function hydrodehydrogenating.
The hydro-dehydrogenating function can be ensured by least one Group VIII metal selected from the group formed by the nickel and / or cobalt, optionally in combination with at least a group VIB metal selected from the group consisting of molybdenum and / or tungsten. For example, a catalyst can be used 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, preferably from 5 to 20% by weight of molybdenum (expressed as molybdenum oxide MoO3) on a support amorphous mineral. The total content of Group VI metal oxide and VIII is often from about 5 to about 40% by weight, and in general from about 7 to 30% by weight, and the weight ratio expressed as oxide between metal (or metals) of group VIB on metal (or metals) of Group VIII is generally from about 20 to about 1, and more often from about 10 to about 2.
The support is for example chosen from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support can also contain other compounds, for example oxides selected from the group consisting of boron oxide, zirconia, titanium, phosphoric anhydride. We most often use a support of alumina and very often a support of alumina doped with phosphorus and possibly boron. In this case, the concentration in Phosphoric anhydride P205 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 boron trioxide B203 is usually from about 0 to about 10% by weight. alumina used is usually alumina y (gamma) or ri (eta). This Catalyst is most often in the form of beads or extrudates.
Prior to the injection of the charge, the catalysts used in the process according to the present invention are preferably subject to sulphurization treatment to transform, at least into part, the metal species in sulphide before they come into contact with the load to be treated. This sulphidation activation treatment is well known to those skilled in the art and can be carried out by any method already described in the literature either in situ, that is to say in the reactor, ie ex-situ.
The hydrotreatment of step c) of the naphtha cut allows To obtain a cut containing not more than 1 ppm by weight of nitrogen, preferably not more than 0.5 ppm of nitrogen and not more than 5 ppm by weight of sulfur, preferably at most 0.5 ppm of sulfur.
The hydrotreatment of step d) of the diesel cut allows to obtain a cut containing not more than 100 ppm of nitrogen, preferably Not more than 20 ppm of nitrogen and not more than 50 ppm of sulfur, preferably plus 10 ppm sulfur.
According to a penultième aspect, the invention relates to a crude synthetic resin obtained by a process according to one of its aspects Previous 15 According to a final aspect, the invention relates to an installation intended to treat a shale oil implementing a process according to one of its previous aspects.
Such an installation includes:
A hydroconversion section in the presence of hydrogen comprising at least one bubbling bed reactor operating at upflow of liquid and gas and containing at least one hydroconversion catalyst supported, a zone of fractionation by atmospheric distillation, a first hydrotreatment section in the presence of hydrogen, comprising at least one fixed bed reactor containing at least minus a hydrotreatment catalyst, a second hydrotreatment section in the presence of hydrogen, said section comprising at least one fixed bed reactor containing at least one hydrotreatment catalyst, a hydrocracking section in the presence of hydrogen.
These elements are arranged for the implementation of the method according to the invention.
For this purpose, for example:
- the hydroconversion section is connected to the zone of fractionation in order to supply the latter with effluents from the hydroconversion

21 -a first line (or line) connects the area of fractionation at the first hydrotreatment section, a second pipe (or line) connects the split zone to the second hydrotreatment section and a third pipe connects the area of fractionation at the hydrocracking section.
The installation may also include one or more recycle lines to return the different fractions to the section hydroconversion, the hydrocracking section or any of the first and second hydrotreatment sections.
FIG. 1 schematically represents the process according to present invention. Figure 2 schematically represents a variant of the process in which the separation of several sections is carried out in the same distillation unit.
According to FIG. 1, the charge comprising shale oil (1) at to be treated between a line (2) in a bed hydroconversion section bubbling (3), in the presence of hydrogen (4), hydrogen (4) being introduced by a line (5). The effluent from the hydroconversion section bubbling bed (3) is sent by a line (6) in a column of atmospheric distillation (7), at the exit of which is recovered a gas fraction (8), a naphtha fraction (9), a gas oil fraction (10) and a fraction heavier than the diesel fraction (11). The gaseous fraction (8), and a second gaseous fraction (26) containing hydrogen, can be purified (not shown) to recycle hydrogen and reinject it (i) into the bed hydroconversion section bubbling (3) via line (2) and / or (5), and / or (ii) in a section hydrotreatment process (12) via a line (18) and / or (14), and / or (iii) in a hydrotreatment section (13) via a line (19) and / or (15), and / or (iv) in a hydrocracking section (20) via a line (21) and / or (22). The naphtha fraction (9) is sent to the bed hydrotreatment section stationary (12) at the exit of which a naphtha fraction is recovered (16) depleted in impurities. The diesel fraction (10) is sent to the hydrotreatment section in a fixed bed (13) at the exit of which one recovering a diesel fraction (17) depleted of impurities. Both hydrotreatment sections (12) and (13) are powered by hydrogen via lines (14) and (15). The heavier fraction than the diesel fraction (11) is sent to the hydrocracking section (20)

22 by the line (21). The hydrocracking effluents (23) are sent via a line (24) in a separation section (25) at the exit of which the second gaseous fraction (26) is recovered, a second naphtha fraction (27), a second diesel fraction (28), and a second fraction heavier than diesel (29). The second fraction naphtha (27) may be sent in whole or in part to the section hydrotreating (12) via a line (30). The second diesel fraction (28) is sent preferentially to the fuel pool or can be sent in whole or in part to the hydrotreatment section (13) via a line (31). The second heavier fraction than diesel (29) can be (i) withdrawn, and / or (ii) returned in whole or in part to the section hydrocracking (20) via a line (32), and / or (iii) returned in full or partly to the boiling bed hydroconversion section (3) via a line (33).
In Figure 2, the steps (and reference signs) hydroconversion, separation and hydrotreatment are identical in Figure 1 to the hydrocracking stage, which shows some differences.
The charge comprising the shale oil (1) to be treated enters through a line (2) in a bubbling bed hydroconversion section (3), in the presence of hydrogen (4), the hydrogen (4) being introduced by a line (5). The effluent from the boiling bed hydroconversion section (3) is sent via a line (6) to a distillation column (7), at the exit of which a fraction is recovered.
gas (8), a naphtha fraction (9), a gas oil fraction (10) and a heavier fraction than the diesel fraction (11). The gaseous fraction (8), containing hydrogen, can be purified (not shown) for recycle hydrogen and reinject it (i) into the section ebullating hydroconversion (3) via line (2) and / or (5), and / or (ii) in a hydrotreatment section (12) via a line (18) and / or (14), and / or (iii) in a hydrotreatment section (13) via a line (19) and / or (15), and / or (iv) in a hydrocracking section (20) via a line (21) and / or (22). The naphtha fraction (9) is sent to the stationary hydrotreatment section (12) at the exit of which one recovering a naphtha fraction (16) depleted of impurities. Fraction diesel (10) is sent to the fixed bed hydrotreatment section (13) at the exit of which is recovered a diesel fraction (17) depleted in

23 impurities. The two hydrotreatment sections (12) and (13) are fed with hydrogen via lines (14) and (15). Fraction heavier than the diesel fraction (11) is sent to the hydrocracking (20) via line (21). Hydrocracking effluents (23) are sent via a line (24) into a separation section (34) at the exit of which we recover, at the head, a mixture (35) comprising a second gaseous fraction, a second fraction naphtha and a second diesel fraction (28), and, in the foot, a second heavier fraction than diesel (29). The mixture (35) is sent by a line (36) to the distillation column (7). The second fraction heavier than diesel (29) may be (i) withdrawn, and / or (ii) returned all or part to the hydrocracking section (20) via a line (32), and / or (iii) returned in whole or in part to the section ebullating hydroconversion (3) via a line (33).
Example We treat a shale oil whose characteristics are presented in Table 1.
Table 1: Characteristics of Shale Oil Charge Density 15/4 - 0.945 Hydrogen% by weight 10.9 Sulfur% by weight 1.9 Nitrogen% by weight 0.8 Oxygen% by weight 1.8 Asphaltenes% by weight 1.8 Conradson Carbon% by weight 3.6 PPm metals 236 Shale oil is treated in a bubbling bed reactor containing the commercial catalyst HOC 458 from the company Axens. The Operating conditions for implementation are as follows:
- Temperature in the reactor: 435 C
- Pressure: 195 bar (19.5 MPa) - Hydrogen ratio / charge: 600 Nm3 / m3 - overall VVH: 0.3 h-

24 Liquid products from the reactor are fractionated by atmospheric distillation to a naphtha fraction (C5 + - 150 C), a diesel fraction (150-370 ° C) and a residual fraction 370 C + which is a heavier fraction than diesel.
The naphtha fraction is subjected to a fixed bed hydrotreatment using a NiMo catalyst on alumina. Operating conditions are the following :
- Temperature in the reactor: 320 C
- Pressure: 50 bar (5 MPa) - Hydrogen / charge ratio: 400 Nm3 / m3 - overall VVH: 1 h-1 The diesel fraction is subjected to a hydrotreatment in a fixed bed using a NiMo catalyst on alumina. 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 subjected to hydrocracking using catalysts containing NiMo on alumina, NiW on silica alumina and NiMo on zeolite. This charge preheated in presence of hydrogen is introduced at the top of a vertical reactor containing 5 catalyst beds. The operating pressure is 16 MPa absolute, the temperature is 380 C, the hydrogen / charge ratio is 1200 Nm3 / m3, and the VVH is 0.6h-1. A supplement of hydrogen is brought between each catalyst bed (quench gas) in order to decrease temperature. This quench gas is intimately mixed with the charge in devices called quench boxes.
Hydrocracked hydrocarbons are drawn off at the bottom of reactor and are cooled. They are directed to a unit of splitting from which are isolated at the head gases, at least one cut naphtha, at least one diesel fuel cup, and at least one more heavy as diesel in the background.

Table 2 gives the properties of the different loads of each stage as well as the yields obtained in the different units and overall yield. We observe then that starting from 100%
by weight of shale oil, 93.9% by weight of products are obtained 5 (LPG, naphtha, middle distillates) to commercial specifications Euro V.

PCT / EU2011 / 053,021 Table 2 Refining unit H-011Dc hydrocracker Shale oil Charge C5 + Background ex H-011Dc Product Background ex H-01IRc Product yield on load shale oil% by weight 16.0 Product properties density (d15 / 4) 0.852 0/0 by weight sulfur 0.05 Total nitrogen weight% in .0.25 Performance on each unit LPG% by weight 2.2 2.5 % by weight 27.
Naphtha 23.5 weight.
Average distillate% in po 61.0 Weight% background 16.0 15.0 % in weight Oil yield of% by weight schist LPG% by weight 2.2 0.4 Naphtha% by weight 27.1 3.8 Average distillate% by weight 50.7 9.8 Weight% background 16.0 2.4 Total (LPG + naphtha + distillate medium) / Shale oil charge 80.0 13.9 Total (LPG + naphtha + distillate medium) / shale oil charge 93.9

Claims (19)

27 1. Process for converting a shale oil or a mixture of shale oils comprising at least one shale oil having a nitrogen content of at least 0.1%, often at least 1% and very often at least 2% by weight, characterized in that it comprises the following steps :
a) The load is sent to a section hydroconversion in the presence of hydrogen, the said section comprising at least one operating bubbling bed reactor with an upward flow of liquid and gas and containing at least a hydroconversion catalyst supported, (b) The effluent obtained in step (a) is sent, at least partly, and often entirely, in a fractionation zone at from which an atmospheric distillation gaseous fraction, a naphtha fraction, a diesel fraction and a heavier fraction than diesel, (c) The said naphtha fraction is treated, at least in part, and often entirely in a first section hydrotreatment process in the presence of hydrogen, said comprising at least one fixed bed reactor containing at least a hydrotreatment catalyst, (d) The said diesel fraction is treated, at least in part, and often entirely in a second hydrotreatment section in the presence of hydrogen, said section comprising at least one fixed bed reactor containing at least one catalyst hydrotreatment, and (e) That heavier fraction than diesel oil is treated at less in part, and often entirely in one section hydrocracking in the presence of hydrogen. 2. Method according to claim 1, characterized in that the hydrocracking effluents, obtained at the end of step e), are separated in a second gaseous fraction, a second naphtha fraction, a second diesel fraction, and a second fraction heavier than diesel. 3. The method of claim 2, wherein the second naphtha fraction is treated, at least in part, and often in full in the hydrotreatment section of step c). 4. The method of claim 2, wherein the second Diesel fraction is treated, at least in part, and often in full in the hydrotreatment section of step d). The method of claim 2, wherein the second heavier fraction than diesel is treated, at least in part, and often entirely in the hydroconversion section of step a). 6. Method according to claim 1, characterized in that the hydrocracking effluents, obtained at the end of step e), are separated in a diesel fraction and less heavy than diesel, and a second heavier fraction than diesel. The method of claim 6, wherein the second heavier fraction than diesel is treated, at least in part, and often entirely in the hydroconversion section of step a). The process according to claim 6, wherein the diesel fraction and less heavy than diesel is sent, at least in part, and often in total, in a fractionation zone of step b). The process according to any of claims 2 to 8, wherein the second heavier fraction than diesel is treated, at least in part, and often entirely in the hydrocracking section of step e). 10. Method according to one of the preceding claims, in which the effluent obtained in step a) is fractionated by distillation atmospheric to a gaseous fraction having a boiling point less than 50 ° C, a naphtha fraction boiling between 50 ° C and 150 ° C, a gas oil fraction boiling between about 150 ° C and 370 ° C, and a heavier fraction than the diesel type fraction, boiling generally above 340 ° C, preferably above 370 ° C 11. Method according to one of the preceding claims, in which the fixed bed hydrotreatment section of step c) and / or d) comprises, upstream of the catalytic hydrotreatment beds, at least a guard bed specific to the compounds of arsenic and silicon. 12. Method according to one of the preceding claims, in which the hydroconversion stage a) operates at a temperature of between 300 ° C and 550 ° C, preferably between 400 ° C and 450 ° C, at a total pressure of between 2 and 35 MPa, preferably between 10 and 20 MPa, at an hourly mass velocity ((t of load / h) / t of catalyst) between 0.2 and 1.5 h-1, and at a ratio hydrogen / charge between 50 and 5000 Nm3 / m3, preferably between 100 and 1000 Nm3 / m3. 13. Method according to one of the preceding claims, in which step c) 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 speed between 0.1 and 5 h-1, preferably between 0.5 and 1 h-1, and at a hydrogen / charge ratio between 100 and 5000 Nm3 / m3, preferably between 100 and 1000 Nm3 / m3. 14. Method according to one of the preceding claims, in which step d) of hydrotreating of the diesel 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 between 0.1 and 1 h -1, preferably between 0.3 and 0.8 h -1, and at a hydrogen / charge ratio between 100 and 5000 Nm3 / m3, preferably between 200 and 1000 Nm3 / m3. 15. Method according to one of the preceding claims, in which step e) hydrocracking the heavier fraction than diesel operates at a temperature of between 350 ° C and 450 ° C, preference between 370 ° C and 425 ° C, at a total pressure of between 10 and MPa, preferably between 15 and 18 MPa, at a speed hourly mass between 0.3 and 7 h-1, preferably between 0.5 and 1.5 h-1, and at a hydrogen / charge ratio of between 100 and 5000 Nm3 / m3, preferably between 1000 and 2000 Nm3 / m3. 16. Method according to one of the preceding claims, in which the catalysts of steps a) of hydroconversion and c) and d) hydrotreatment and e) hydrocracking are independently selected from the group of catalysts comprising a metal of group VIII chosen from the group formed by Ni and / or Co, optionally a group VIB metal chosen from the group formed by Mo and / or W, on an amorphous support selected from the group formed with alumina, silica, silica-aluminas, magnesia, clays and their mixtures, or on a support comprising at least partly a zeolitic material. 17. Method according to one of the preceding claims, in shale oil or shale oil blend is completed by a hydrocarbon feed selected from the group consisting of oils derived from coal, oils obtained from tars oil sands, vacuum distillates, and residues straight-run distillation, vacuum distillates and non-converted from the process of conversion of residues, oils deasphalted solvents, light cutting oils, heavy cut, diesel cuts from catalytic cracking having in general a distillation range of about 150 ° C to about 650 ° C, aromatic extracts obtained in the course of manufacture lubricating oils, pyrolysis oils of wood residues such as wood residues, biomass crudes (biocrudes), vegetable oils and animal fats, or mixtures thereof loads. 18. Synthetic crude, obtained by a process according to one of preceding claims. 19. Installation, intended to treat a shale oil comprising:
a hydroconversion section in the presence of hydrogen comprising at least one bubbling bed reactor operating at upflow of liquid and gas and containing at least one hydroconversion catalyst supported, a zone of fractionation by atmospheric distillation, a first hydrotreatment section in the presence of hydrogen, comprising at least one fixed bed reactor containing at least one hydrotreatment catalyst, a second hydrotreatment section in the presence of hydrogen, said section comprising at least one fixed bed reactor containing at least minus a hydrotreatment catalyst, a hydrocracking section in the presence of hydrogen, these elements being arranged for setting, implementing a method according to one of claims 1 to 17.