# Patent

## Title
Process for the intense conversion of residues, maximizing the gasoline yield

## Abstract

A process for the intense conversion of a heavy hydrocarbon feed, comprising a) ebullated bed hydroconversion of the feed; b) separating at least a portion of hydroconverted liquid effluent obtained from a); c)i) either hydrotreatment of at least a portion of the gas oil fraction and of the vacuum gas oil fraction obtained from b), ii) or hydrocracking at least a portion of gas oil fraction and vacuum gas oil fraction obtained from b); d) fractionation of at least a portion of the effluent obtained from c)i) or c)ii); e) recycling at least a portion of unconverted vacuum gas oil fraction obtained from the fractionation d) to said first hydroconversion a); f) hydrocracking at least a portion of gas oil fraction obtained from fractionation d); g) recycling all or a portion of effluent obtained from f) to the fractionation d).

## Background
The invention relates to the field of the production of gasoline (also frequently known as naphtha) from oil residues.
The concatenation of conversion and hydrocracking units in the treatment of oil residue feeds is known in the prior art.
U.S. Pat. No. 5,980,730 and U.S. Pat. No. 6,017,441 describe a process for the intense conversion of a heavy oil fraction, said process comprising a step for hydroconversion in a three-phase ebullated bed, an atmospheric distillation of the effluent obtained, a vacuum distillation of the atmospheric residue obtained after this distillation, a deasphalting step for the vacuum residue obtained and a hydrotreatment of the deasphalted fraction mixed with the distillate obtained during the vacuum distillation. It is also possible in that process to send at least a fraction of the hydrotreated effluent to a catalytic cracking section or to recycle a fraction of the effluent obtained from deasphalting or, in another variation a fraction of the asphalt, to the first hydroconversion step or indeed to send a heavy liquid fraction obtained from the hydrotreatment step to a fluidized bed catalytic cracking section.
U.S. Pat. No. 6,620,311 describes a conversion process which can be used to increase the yield of middle distillates. That process comprises a step for three-phase ebullated bed conversion, sending the effluent obtained to a separation section in order to produce an overhead distillate comprising a gas, gasoline and gas oil and from the bottom, essentially hydrocarbons with a boiling point which is higher than an atmospheric gas oil. The distillate is then treated in a hydrodesulphurization unit and the bottom fraction is treated in a catalytic cracking section in the absence of hydrogen, for example of the fluidized bed cracking type. That type of cracking thus differs from a hydrocracking step operated in fixed bed mode and in the presence of hydrogen.
U.S. Pat. No. 7,919,054 describes a facility for the treatment of heavy oil feeds, comprising an ebullated bed hydroconversion section, a separation and a section for fixed bed hydrotreatment of the distillate obtained in the presence of hydrogen. That hydrotreatment may be a mild hydrocracking (4.5 to 16 MPa) or more severe hydrocracking (7 to 20 MPa).
However, the processes proposed in the prior art suffer from a limitation in the gas oil production yield. In fact, those processes produce a relatively large purge quantity of vacuum distillates from the bottom of the column of the units for vacuum separation of the hydroconversion effluents. Those fractions are obtained from vacuum separations and so, because of their polycondensed structures, they are difficult to upgrade into an oil base compared with vacuum distillate fractions obtained from straight run distillation of oil cuts.
The Applicant proposes a novel process with a particular arrangement of the conversion units and optional deasphalting of the solvent in order to obtain higher production yields of gasoline (also known as naphtha) than in the prior art processes.
One aim of the invention is to obtain an intense conversion of the feed of oil residues while maximizing the gasoline production.
AIM OF THE INVENTION
The present invention concerns a process for the intense conversion of a heavy hydrocarbon feed, comprising the following steps:
a) a first step for ebullated bed hydroconversion of the feed in the presence of hydrogen, comprising at least one three-phase reactor containing at least one ebullated bed hydroconversion catalyst;
b) a step for separating at least a portion of the hydroconverted liquid effluent obtained from step a) into a gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and an unconverted residual fraction;
c) i) either a step for hydrotreatment of at least a portion of the gas oil fraction and the vacuum gas oil fraction obtained from step b) in a reactor comprising at least one fixed bed hydrotreatment catalyst;

    
    
        ii) or a first step for hydrocracking at least a portion of the gas oil fraction and the vacuum gas oil fraction obtained from step b) in a reactor comprising at least one fixed bed hydrocracking catalyst;
    
    


d) a step for fractionating at least a portion of the effluent obtained from step c)i) or step c)ii) into a gasoline fraction, a gas oil fraction and an unconverted vacuum gas oil fraction;
e) a step for recycling at least a portion of the unconverted vacuum gas oil fraction obtained from fractionation step d) to said first hydroconversion step a);
f) a second step for hydrocracking at least a portion of the gas oil fraction obtained from fractionation step d);
g) a step for recycling all or a portion of the effluent obtained from step f) to the fractionation step d).
The feed for the present invention is advantageously selected from heavy hydrocarbon feeds of the vacuum or atmospheric residue type obtained, for example, by straight run distillation of an oil cut or by vacuum distillation of crude oil, distillate type feeds such as vacuum gas oil or deasphalted oils, asphalts obtained from solvent deasphalting of oil residues, coal in suspension in a hydrocarbon fraction such as, for example, gas oil obtained by vacuum distillation of crude oil (also known as vacuum distilled gas oil), or a distillate obtained from coal liquefaction, used alone or as a mixture. The feed of the invention may contain vacuum residues such as Arabian Heavy vacuum residues, Ural vacuum residues and the like, vacuum residues obtained from Canadian or Venezuelan type heavy crudes, or a mixture of atmospheric residues or vacuum residues of diverse origins.
DETAILED DESCRIPTION OF THE INVENTION
The process in accordance with the invention comprises at least one first ebullated bed step in accordance with the invention for hydroconverting a feed. This technology is in particular marketed under the name “H-Oil® process”.
First Hydroconversion Step
The conditions for the first step for hydroconversion of the feed in the presence of hydrogen are usually conventional conditions for ebullated bed hydroconversion of a liquid hydrocarbon fraction or of coal in suspension in a liquid hydrocarbon fraction.
The hydroconversion step a) may be operated under an absolute pressure in the range 5 to 35 MPa, at a temperature of 260° C. to 600° C. and at an hourly space velocity (HSV) of the liquid of 0.05 h−1 to 10 h−1.
Usually, the operation is carried out under an absolute pressure which is generally in the range 5 to 35 MPa, preferably in the range 10 to 25 MPa, at a temperature of 260° C. to 600° C. and usually 350° C. to 550° C. The hourly space velocity (HSV) and the partial pressure of hydrogen are important factors which are selected as a function of the characteristics of the feed to be treated and the desired conversion. Usually, the HSV is in the range 0.05 h−1 to 10 h−1, preferably 0.1 h−1 to 5 h−1.
In accordance with the invention, the weighted average bed temperature of the catalytic bed for the first hydroconversion step is advantageously in the range 260° C. to 600° C., preferably in the range 300° C. to 600° C. and more preferably in the range 350° C. to 550° C.
The quantity of hydrogen mixed with the feed is normally 300 to 2000 normal cubic metres (Nm3) per cubic metre (m3) of liquid feed. Advantageously, the hydrogen is employed in a volume ratio with the feed in the range 500 to 1800 m3/m3, preferably in the range 600 to 1500 m3/m3.
It is possible to use a granular catalyst for the ebullated bed hydroconversion of residues, comprising at least one compound of a metal with a hydrodehydrogenating function on an amorphous support. This catalyst may be a catalyst comprising metals from group VIII, for example nickel and/or cobalt, usually in association with at least one metal from group VIB, for example molybdenum and/or tungsten. As an example, it is possible to use a catalyst comprising 0.5% to 10% by weight of nickel, preferably 1% to 5% by weight of nickel (expressed as the nickel oxide, NiO) and 1% to 30% by weight of molybdenum, preferably 5% to 20% by weight of molybdenum (expressed as molybdenum oxide, MoO3) on an amorphous mineral support. This support is, for example, selected from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also include other compounds, for example oxides selected from the group formed by boron oxide, zirconia, titanium oxide and phosphorus pentoxide. Usually, an alumina support is used, more usually an alumina support doped with phosphorus and optionally with boron. The concentration of phosphorus pentoxide, P2O5, is usually less than 20% by weight and usually less than 10% by weight. This concentration of P2O5 is usually at least 0.001% by weight. The concentration of boron trioxide, B2O3, is normally 0 to 10% by weight. The alumina used is usually a gamma or rho alumina. This catalyst is more usually in the form of an extrudate. In all cases, the attrition resistance of the catalyst must be high because of the specific constraints associated with ebullated beds.
The total quantity of oxides of metals from groups VI and VIII is often 5% to 40% by weight, and in general 7% to 30% by weight, and the weight ratio expressed as the metallic oxide between the metal (or metals) from group VI and the metal (or metals) from group VIII (group VIII oxide/group VI oxide by weight) is in general 20 to 1 and usually 10 to 2. The spent catalyst is partially replaced with fresh catalyst by withdrawal from the bottom of the reactor and introducing fresh or new catalyst into the top of the reactor at regular time intervals, i.e. for example, in bursts or quasi-continuously. As an example, it could be possible to introduce fresh catalyst every day. The replacement ratio of spent catalyst to fresh catalyst may, for example, be 0.01 kilogram to 10 kilograms per cubic metre of feed. This withdrawal and replacement are carried out using devices that allow this hydroconversion step to operate continuously. The unit normally comprises a recirculating pump in order to maintain the catalyst in an ebullated bed by continuously recycling at least a portion of the liquid withdrawn from the head of the reactor and reinjecting it into the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor to a regeneration zone in which the carbon and sulphur it contains is eliminated, then this regenerated catalyst is returned to the hydroconversion step a). It is also possible to send the spent catalyst to a rejuvenation zone in order to extract a portion of the metals and coke originating from the feed and deposited on the catalyst.
The hydroconverted liquid effluent obtained from the first ebullated bed hydroconversion step (step a) advantageously undergoes a separation step b) in order to produce at least one gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and a residual unconverted fraction.
In accordance with the invention, the boiling point of the gasoline fraction (or cut) is advantageously in the range 20° C. to 130° C., preferably in the range 20° C. to 180° C.; the boiling point of the gas oil fraction (or cut) is advantageously in the range 130° C. to 380° C., preferably in the range 180° C. to 350° C.; the boiling point of the vacuum gas oil fraction is advantageously in the range 350° C. to 550° C., preferably in the range 380° C. to 500° C.; the boiling point of the residual unconverted fraction is preferably at least 500° C. or even 550° C.
This separation step is carried out using any means known to the skilled person, in particular by atmospheric fractionation followed by vacuum fractionation.
First Hydrocracking Step
In accordance with a variation of the invention, at least a portion of the gas oil fraction and the vacuum gas oil fraction (VGO) separated in step b) is treated in a first hydrocracking step comprising at least one hydrocracking reactor.
In the context of the present invention, the expression “hydrocracking” encompasses cracking processes comprising at least one step for conversion of feeds using at least one catalyst in the presence of hydrogen.
Hydrocracking may be operated using one-step layouts comprising, firstly, intense hydrorefining which is intended to carry out intense hydrodenitrogenation and desulphurization of the feed before the effluent is sent in its entirety to the hydrocracking catalyst proper, in particular in the case in which it comprises a zeolite.
It also encompasses two-step hydrocracking, which comprises a first step which, like the “one-step” process, is intended to carry out hydrorefining of the feed, but also to obtain a conversion of this feed which is generally of the order of 30 to 60 percent. In the second step of a two-step hydrocracking process, in general only the fraction of the feed which is not converted during the first step is treated.
The conventional hydrorefining catalysts generally contain at least one amorphous support and at least one hydrodehydrogenating element (generally at least one element from the non-noble groups VIE and VIII, and usually at least one element from group VIE and at least one non-noble element from group VIII).
Examples of the matrices which may be used alone or as a mixture in the hydrorefining catalyst are alumina, halogenated alumina, silica, silica-alumina, clays (selected, for example, from natural clays such as kaolin or bentonite), magnesia, titanium oxide, boron oxide, zirconia, aluminium phosphates, titanium phosphates, zirconium phosphates, coal and aluminates. It is preferable to use matrices containing alumina, in all forms known to the skilled person, and still more preferably aluminas, for example gamma alumina.
The operating conditions for the hydrocracking step are adjusted in a manner such as to maximize gasoline production while ensuring that the hydrocracking unit operates properly. The operating conditions used in the reaction zone or zones of the first hydrocracking step are generally a weighted average bed temperature for the catalytic bed (WABT) in the range 300° C. to 550° C., preferably in the range 300° C. to 500° C., more preferably in the range 350° C. to 500° C., a pressure in the range 5 to 35 MPa, preferably in the range 6 to 25 MPa, and a liquid hourly space velocity (flow rate of feed/volume of catalyst) generally in the range 0.1 to 20 h−1, preferably in the range 0.1 to 10 h−1, more preferably in the range 0.15 to 5 h−1.
A quantity of hydrogen is introduced such that the volume ratio, in m3 of hydrogen per m3 of hydrocarbon, at the inlet to the hydrocracking step is in the range 300 to 2000 m3/m3, usually in the range 500 to 1800 m3/m3, preferably in the range 600 to 1500 m3/m3.
This reaction zone generally comprises at least one reactor comprising at least one fixed bed hydrocracking catalyst. The fixed bed of hydrocracking catalyst may optionally be preceded by at least one fixed bed of a hydrorefining catalyst (hydrodesulphurization, hydrodenitrogenation for example). The hydrocracking catalysts used in the hydrocracking processes are generally bi-functional in type, associating an acid function with a hydrogenating function. The acid function may be provided by supports with a large surface area (150 to 800 m2/g in general) and with a superficial acidity, such as halogenated aluminas (in particular chlorinated or fluorinated), combinations of boron oxide and aluminium oxide, amorphous silica-aluminas known as amorphous hydrocracking catalysts, and zeolites. The hydrogenating function may be provided either by one or more metals from group VIII of the periodic classification of the elements, or by an association of at least one metal from group VIE of the periodic classification and at least one metal from group VIII.
The hydrocracking catalyst may also comprise at least one crystalline acidic function such as a Y zeolite, or an amorphous acid function such as a silica-alumina, at least one matrix and a hydrodehydrogenating function.
Optionally, it may also comprise at least one element selected from boron, phosphorus and silicon, at least one element from group VIIA (for example chlorine, fluorine), at least one element from group VIM (for example manganese), and at least one element from group VB (for example niobium).
Hydrotreatment Step
In accordance with another variation of the invention, a hydrotreatment step may be carried out instead of the first hydrocracking step. This variation is particularly suitable for feeds obtained from coal or for residues obtained from the hydroconversion step and having high nitrogen-containing compound contents. The hydrotreatment step (HDT) can thus be used to remove nitrogen from these effluents obtained from the H-Oil or H-Coal (coal feed) step. This avoids sending nitrogen-containing compounds and the ammonia formed to a hydrocracking catalyst and thus inhibiting or poisoning it.
In accordance with the invention, the hydrotreatment step is carried out in a manner such that cracking is limited to less than 40%, preferably less than 30% and more preferably less than 20%.
In accordance with the invention, the hydrotreatment step is advantageously carried out under a pressure in the range 5 to 35 MPa, preferably in the range 6 to 25 MPa, a temperature in the range 320° C. to 460° C., preferably in the range 340° C. to 440° C., and a liquid hourly space velocity (feed flow rate/volume of catalyst) in the range 0.1 to 10 h−1, preferably in the range 0.15 to 4 h−1.
The hydrotreatment catalysts used are preferably known catalysts and are generally granular catalysts comprising, on a support, at least one metal or compound of a metal having a hydrodehydrogenating function. These catalysts are advantageously catalysts comprising at least one metal from group VIII, generally selected from the group formed by nickel and/or cobalt, and/or at least one metal from group VIE, preferably molybdenum and/or tungsten. As an example, a catalyst may be used comprising 0.5% to 10% by weight of nickel and preferably 1% to 5% by weight of nickel (expressed as the nickel oxide, NiO) and 1% to 30% by weight of molybdenum, preferably 5% to 20% by weight of molybdenum (expressed as molybdenum oxide, MoO3) on a mineral support. As an example, this support will be selected from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. Advantageously, this support includes other doping compounds, in particular oxides selected from the group formed by boron oxide, zirconia, cerine, titanium oxide, phosphorus pentoxide and a mixture of these oxides. Usually, an alumina support is used, and most usually an alumina support doped with phosphorus and optionally with boron. When phosphorus pentoxide, P2O5, is present, its concentration is below 10% by weight. When boron trioxide B2O3 is present, its concentration is less than 10% by weight. The alumina used is normally a γ or η alumina. This catalyst is usually in the form of extrudates. The total content of oxides of metals from groups VIB and VIII is usually 5% to 40% by weight and in general 7% to 30% by weight, and the weight ratio, expressed as the metallic oxide, between the group VIE metal (or metals) and the metal (or metals) from group VIII is in general 20 to 1, usually 10 to 2.
Deasphalting Step
In variations, the process of the invention may implement a deasphalting step. In accordance with the invention, at least a portion of the residual unconverted fraction obtained from step b) may be sent to a deasphalting section in which it is treated in an extraction step using a solvent under conditions for obtaining a deasphalted hydrocarbon cut and residual asphalt.
One of the aims of the deasphalting step is on the one hand to maximize the quantity of deasphalted oil, and on the other hand to maintain or even minimize the asphaltenes content. This asphaltenes content is generally determined in terms of the quantity of asphaltenes which are insoluble in heptane, i.e. measured using a method described in the AFNOR standard (NF-T 60115) of January 2002.
In accordance with the invention, the quantity of asphaltenes in the deasphalted effluent (also known as DeAsphalted Oil or DAO) is less than 3000 ppm by weight.
Preferably, the asphaltenes content in the deasphalted effluent is less than 1000 ppm by weight, more preferably less than 500 ppm by weight.
Below an asphaltenes content of 500 ppm by weight, the method of AFNOR standard (NF-T 60115) is no longer sufficient to measure this content. The Applicant has developed an analytical method covering the quantitative analysis of asphaltenes from straight run distillation products and heavy products obtained from residue deasphalting. This method can be used for concentrations of asphaltenes of less than 3000 ppm by weight and more than 50 ppm by weight. The method in question consists of comparing the absorbance at 750 nm of a sample in solution in toluene with that of a sample in solution in heptane after filtration. The difference between the two measured values is correlated to the concentration of insoluble asphaltenes in the heptane using a calibration equation. This method is a supplement to the AFNOR (NF-T 60115) method and the standard IP 143 method which are used for higher concentrations.
The solvent used during the deasphalting step is advantageously a paraffinic solvent, a gasoline cut or condensates containing paraffins.
Preferably, the solvent used comprises at least 50% by weight of hydrocarbon compounds containing 3 to 7 carbon atoms, more preferably between 4 and 7 carbon atoms, still more preferably 4 or 5 carbon atoms.
Depending on the solvent used, the yield of deasphalted oil and the quality of this oil may vary. By way of example, when changing from a solvent containing 3 carbon atoms to a solvent containing 7 carbon atoms, the oil yield increases but, in contrast, the quantities of impurities (asphaltenes, metals, Conradson Carbon, sulphur, nitrogen, etc.) also increases.
Furthermore, for a given solvent, the choice of operating conditions, in particular the temperature and the quantity of solvent injected, has an impact on the yield of deasphalted oil and on the quality of this oil. The skilled person is able to select the optimal conditions for obtaining an asphaltenes content of less than 500 ppm.
The deasphalting step may be carried out using any means known to the skilled person. This step is generally carried out in a mixer settler or in an extraction column. Preferably, the deasphalting step is carried out in an extraction column.
In accordance with a preferred embodiment, a mixture comprising the hydrocarbon feed and a first fraction of a solvent feed is introduced into the extraction column, the ratio by volume between the solvent fraction feed and the hydrocarbon feed being termed the solvent ratio injected with the feed. This step is intended to properly mix the feed with the solvent entering the extraction column. It is possible to introduce a second fraction of the solvent feed into the settling zone at the bottom of the extractor, the volume ratio between the second solvent feed fraction and the hydrocarbon feed being termed the solvent ratio injected into the bottom of the extractor. The volume of the hydrocarbon feed under consideration 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 termed the overall solvent ratio. Settling the asphalt consists of washing the emulsion of asphalt in the solvent+oil mixture with pure solvent using a counter-current. It is generally favoured by an increase of the solvent ratio (in fact by replacing the solvent+oil environment with a pure solvent environment) and increasing the temperature.
The overall solvent ratio with respect to the treated feed is preferably in the range 2.5/1 to 20/1, more preferably in the range 3/1 to 12/1, more preferably in the range 4/1 to 10/1.
This overall solvent ratio can be broken down into a solvent ratio injected with the feed at the head of the extractor, which is preferably in the range 0.5 to 5/1, preferably in the range 1/1 to 5/1, and a solvent ratio injected into the bottom of the extractor, which is preferably in the range 2/1 to 15/1, more preferably in the range 3/1 to 10/1.
Furthermore, in a preferred embodiment, a temperature gradient is established between the head and the bottom of the column which enables an internal reflux to be generated, which improves separation between the oily medium and the resins. In fact, the solvent+oil mixture heated at the head of the extractor can be used to precipitate a fraction comprising the resin which descends in the extractor. The rising counter-current of the mixture can be used to dissolve the fractions comprising the resin which are the lightest at a lower temperature.
In the deasphalting step, the typical temperature at the head of the extractor varies depending on the selected solvent and is generally in the range 60° C. to 220° C., preferably in the range 70° C. to 210° C., and the temperature at the bottom of the extractor is preferably in the range 50° C. to 190° C., more preferably in the range 60° C. to 180° C.
The prevailing pressure in the interior of the extractor is generally adjusted in a manner such that all of the products remain in the liquid state. This pressure is preferably in the range 4 to 5 MPa.
In accordance with the invention, when the deasphalting step is carried out, at least a portion of the hydrocarbon cut obtained from the deasphalting step is sent to the hydrotreatment step c)i) or to the hydrocracking step c)ii), as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.
Second Hydroconversion Step
The invention may also comprise a second hydroconversion step. In accordance with the invention, this second hydroconversion step of the invention may be carried out in a fixed bed or in an ebullated bed.
This second hydroconversion step is generally carried out on a deasphalted hydrocarbon cut obtained from the deasphalting step of the invention.
In accordance with the invention, at least a portion of the deasphalted hydrocarbon cut obtained from the deasphalting step is sent to a second hydroconversion step in the presence of hydrogen, said step being carried out under fixed bed hydrocracking conditions or under ebullated bed hydrocracking conditions.
The conditions for the second step for hydroconversion of the feed in the presence of hydrogen are usually an absolute pressure which is in the range 5 to 35 MPa, preferably in the range 10 to 25 MPa, and a temperature of 260° C. to 600° C., usually 350° C. to 550° C. The hourly space velocity (HSV) and the partial pressure of hydrogen are important factors which are selected as a function of the characteristics of the product to be treated and the desired conversion. Usually, the HSV is in the range 0.1 h−1 to 10 h−1, preferably 0.15 h−1 to 5 h−1.
In accordance with the invention, the weighted average bed temperature of the catalytic bed for the second hydroconversion step is advantageously in the range 260° C. to 600° C., preferably in the range 300° C. to 600° C., more preferably in the range 350° C. to 550° C.
The quantity of hydrogen mixed with the feed is usually 50 to 5000 normal cubic metres (Nm3) per cubic metre (m3) of liquid feed. Advantageously, the hydrogen is used in a ratio by volume with the feed in the range 300 to 2000 m3/m3, preferably in the range 500 to 1800 m3/m3, and more preferably in the range 600 to 1500 m3/m3.
It is possible to use a conventional granular hydroconversion catalyst comprising at least one compound of a metal with a hydrodehydrogenating function on an amorphous support. This catalyst may be a catalyst comprising metals from group VIII, for example nickel and/or cobalt, usually in association with at least one metal from group VIE, for example molybdenum and/or tungsten. As an example, it is possible to use a catalyst comprising 0.5% to 10% by weight of nickel, preferably 1% to 5% by weight of nickel (expressed as the nickel oxide, NiO) and 1% to 30% by weight of molybdenum, preferably 5% to 20% by weight of molybdenum (expressed as molybdenum oxide, MoO3) on an amorphous mineral support. This support is, for example, selected from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also include other compounds, for example oxides selected from the group formed by boron oxide, zirconia, titanium oxide and phosphorus pentoxide. Usually, an alumina support is used and more usually, an alumina support doped with phosphorus and optionally with boron is used. The concentration of phosphorus pentoxide, P2O5, is usually less than 20% by weight and usually less than 10% by weight. This concentration of P2O5 is usually at least 0.001% by weight. The concentration of boron trioxide, B2O3, is normally 0 to 10% by weight. The alumina used is usually a gamma or rho alumina. This catalyst is more usually in the form of an extrudate.
The total quantity of oxides of metals from groups VI and VIII is often to 40% by weight, and in general 7% to 30% by weight and the weight ratio, expressed as the metallic oxide, between the metal (or metals) from group VI and the metal (or metals) from group VIII is in general 20 to 1 and usually 10 to 2. The spent catalyst is partially replaced with fresh catalyst by withdrawal from the bottom of the reactor and introducing fresh or new catalyst into the top of the reactor at regular time intervals, i.e. for example, in bursts or quasi-continuously. As an example, it could be possible to introduce fresh catalyst every day. The replacement ratio of spent catalyst to fresh catalyst may, for example, be 0.01 kilogram to 10 kilograms per cubic metre of feed. This withdrawal and replacement are carried out using devices that allow this hydroconversion step to operate continuously. The unit normally comprises a recirculating pump in order to maintain the catalyst in an ebullated bed by continuously recycling at least a portion of the liquid withdrawn from the head of the reactor and reinjecting it into the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor to a regeneration zone in which the carbon and sulphur it contains is eliminated, then to send this regenerated catalyst to the second hydroconversion step.
The effluent obtained from the second hydroconversion step advantageously undergoes a separation step h) in order to produce at least one gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and a residual unconverted fraction.
This separation step h) is carried out using any means known to the skilled person, for example by distillation.
In accordance with the invention, at least a portion of the gas oil and vacuum gas oil fractions obtained from separation step h) are sent to the hydrotreatment step c)i) or to hydrocracking step c)ii), as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.
Second Hydrocracking Step
The process of the invention may also comprise a second hydrocracking step. This second hydrocracking step is advantageously carried out on at least a portion, preferably the whole of the gas oil fraction obtained from fractionation step d).
In the interests of consistency, even in the case in which the process of the invention does not include the first hydrocracking step c)ii), this hydrocracking step of the process will be termed the “second hydrocracking step”.
The hydrocracking operating conditions are adjusted in a manner such that the gasoline production is maximized while ensuring that the unit can be operated properly.
Advantageously, the second hydrocracking step is carried out at a temperature at least 10° C. below that employed during the hydrotreatment step c)i) or the first hydrocracking step c)ii), and at a liquid hourly space velocity (feed flow rate/volume of catalyst) at least 30% higher, preferably at least 45% higher, more preferably at least 60% higher than that employed during the hydrotreatment step c)i) or the first hydrocracking step c)ii).
In general, the weighted average bed temperature (WABT) for the second hydrocracking step is in the range 300° C. to 550° C., preferably in the range 250° C. to 400° C. The pressure is generally in the range 5 to 35 MPa, preferably in the range 6 to 25 MPa. The liquid hourly space velocity (feed flow rate/volume of catalyst) is generally in the range 0.1 to 20 h−1, preferably in the range 0.1 to 10 h−1, and more preferably in the range 0.15 to 5 h−1.
During the second hydrocracking step, a quantity of hydrogen is introduced such that the ratio by volume, in m3 of hydrogen per m3 of hydrogen at the inlet to the hydrocracking step, is in the range 300 to 2000 m3/m3, usually in the range 500 to 1800 m3/m3, preferably in the range 600 to 1500 m3/m3.
This reaction zone generally comprises at least one reactor comprising at least one fixed bed hydrocracking catalyst. The fixed bed of hydrocracking catalyst may optionally be preceded by at least one fixed bed of a hydrorefining catalyst (hydrodesulphurization, hydrodenitrogenation for example). The hydrocracking catalysts used in the hydrocracking processes are generally bi-functional in type, associating an acid function with a hydrogenating function. The acid function may be provided by supports with a large surface area (150 to 800 m2/g in general) and with a superficial acidity, such as halogenated aluminas (in particular chlorinated or fluorinated), combinations of boron oxide and aluminium oxide, amorphous silica-aluminas known as amorphous hydrocracking catalysts, and zeolites. The hydrogenating function may be provided either by one or more metals from group VIII of the periodic classification of the elements, or by an association of at least one metal from group VIE of the periodic classification and at least one metal from group VIII.
The hydrocracking catalyst may also comprise at least one crystalline acidic function such as a Y zeolite, or an amorphous acid function such as a silica-alumina, at least one matrix and a hydrodehydrogenating function.
Optionally, it may also comprise at least one element selected from boron, phosphorus and silicon, at least one element from group VIIA (chlorine, fluorine for example), at least one element from group VIM (for example manganese), and at least one element from group VB (for example niobium).
First Variation of the Process of the Invention
In a first variation of the process of the invention known as the “1N implementation”, the feed for the process of the invention is treated in a first hydroconversion step (step a), for example of the H-Oil type, and the effluent obtained is separated (step b) into at least one gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and a residual unconverted fraction. The gas oil and vacuum gas oil fractions obtained thereby, optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction, are sent either to the hydrotreatment step c)i) or to the hydrocracking step c)ii).
In accordance with this first variation of the process of the invention, the effluent obtained from the hydrotreatment step c)i) or the hydrocracking step c)ii) is fractionated in the fractionation step d) into several fractions including a gasoline fraction, a gas oil fraction and an unconverted vacuum gas oil fraction. The fractionation step is carried out using any means known to the skilled person, for example distillation.
All or a portion of the unconverted vacuum gas oil fraction obtained from the fractionation step d) is recycled to the first hydroconversion step (step a).
At least a portion of the gas oil fraction obtained from the fractionation step is sent to the second hydrocracking step. The effluent obtained from the second hydrocracking step is returned to the fractionation step d).
Thus, referring to FIG. 1, the feed A constituted by a vacuum residue (SR VR) is sent via the conduit 1 to a hydroconversion section 20 (denoted H-OilRC in FIG. 1) in order to produce, after separation (not shown), a gasoline fraction 4 (N), a gas oil fraction 5 (GO), a vacuum gas oil fraction 6 (VGO) and a residual unconverted fraction 3 (VR). The gas oil (GO) and vacuum gas oil (VGO) fractions are then sent to a hydrotreatment or hydrocracking section 30 via the conduit 6. This fraction could be sent to the section 30 as a mixture with a distilled vacuum gas oil fraction B and/or vacuum distilled gas oil (SR GO-VGO). The effluent obtained from the section 30 is then separated in the fractionation zone 40 (denoted FRAC in FIG. 1), into a gasoline fraction 12 (N), a gas oil fraction 13 (GO) and a vacuum gas oil fraction 14, (VGO). At least a portion of the VGO is returned to the first hydroconversion section 20 via the conduit 9 as a mixture with the feed A. This VGO is partially cracked in the hydroconversion section and the unconverted VGO is in turn partially converted in the hydrocracking or hydrotreatment section 30. At least a portion 13b of the GO obtained from the fractionation zone 13 is sent to the hydrocracking section 70 (second hydrocracking step). The effluent from the section 70 is recycled to the fractionation zone 40 via the conduit 11. In contrast to conventional two-step hydrocracking processes which recycle the bottom from the fractionation unit to the second hydrocracking step, this configuration means that heavy polyaromatics from the VGO are not recycled to the second hydrocracking step, which favours a large increase in the stability of the hydrocracking catalyst in the hydrocracking section 70 and finally entrains an increased gasoline production.
Thus, compared with the prior art layout represented in FIG. 4 and which has an identical legend to that of FIG. 1, the purges at 14 of VGO and 13 of GO are very small and represent at most 1% by weight, in favour of an additional co-production of high added value gasoline fraction.
Second Variation of the Process of the Invention
A second variation of the process of the invention, termed “2N implementation”, implements a deasphalting step.
This variation is distinguished from the 1N variation in that at least a portion of the residual unconverted fraction obtained from the separation step b) may be sent to a deasphalting step in which it is treated in an extraction section using a solvent under conditions that mean that a deasphalted hydrocarbon cut and residual asphalt (pitch) can be obtained.
This operation can be used to extract a large portion of the asphaltenes and to reduce the quantity of metals in the unconverted residual fraction. During this deasphalting step, these latter elements become concentrated in an effluent termed the asphalt or pitch.
The deasphalted effluent, often known as Deasphalted Oil, abbreviated to DAO, has a reduced asphaltenes and metals content.
In accordance with this variation of the “2N implementation” process, the deasphalted hydrocarbon cut obtained from the deasphalting step is sent to the hydrotreatment step c)i) or to the hydrocracking step c)ii) as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.
The effluent from hydrotreatment or hydrocracking is then fractionated in the fractionation zone into a plurality of fractions including a gasoline fraction, a gas oil fraction and an unconverted vacuum gas oil fraction. At least a portion of the vacuum gas oil fraction obtained from the fractionation step d) is recycled to the inlet of the deasphalting step and/or to the inlet of the first hydroconversion step.
At least a portion of the gas oil fraction obtained from the fractionation step is sent to the second hydrocracking step. The effluent obtained from the second hydrocracking step is returned to the fractionation step d).
Thus, referring to FIG. 2, the feed A of vacuum residues (SR VR) is sent via the conduit 1 to a hydroconversion section 20 (denoted H-OilRC in FIG. 2) in order to produce, after separation (not shown), a gasoline fraction 4 (N), a gas oil fraction 5 (GO), a vacuum gas oil fraction 6 (VGO) and a residual unconverted fraction 3 (VR). The gas oil (GO) and vacuum gas oil (VGO) fractions are sent to the hydrotreatment or hydrocracking section 30 via the conduit 6. The residual unconverted fraction (VR) is sent to a deasphalting unit 50 (SDA) via the conduit 3 in order to extract a deasphalted oil (DAO) and a residual asphalt (pitch) via the conduit 16. The deasphalted oil fraction (DAO) is then sent to a hydrotreatment or hydrocracking section 30 via the conduit 15. The effluent from section 30 is then separated in the fractionation zone 40 into a gasoline fraction 12 (N), a gas oil fraction 13 (GO) and a vacuum gas oil fraction 14, (VGO). At least a portion of the vacuum gas oil fraction 14 (VGO) is returned to the deasphalting section 50 via the conduits 9 and 2 and/or to the first hydroconversion section 20 via the conduits 9 and 10. Recycling the vacuum gas oil fraction 14 (VGO) to the deasphalting unit means that an additional quantity of deasphalted oil (DAO) can be sent to the first hydrocracking step (section 30) to generate additional gasoline production. Recycling the vacuum gas oil fraction 14 (VGO) to the first hydroconversion section 20 means that additional cracking of the vacuum gas oil fraction can be carried out to form gas oil and gasoline without having an impact on the function of the unit in this section.
At least a portion 13b of the gas oil fraction 13 obtained from the fractionation zone is sent to the hydrocracking section 70 (second hydrocracking step). The effluent leaving the section 70 is recycled to the fractionation zone 40 via the conduit 11. In this variation, the hydrotreatment or hydrocracking section 30 then the fractionation zone 40 are supplied with both the gas oil and vacuum gas oil fractions obtained from the first hydroconversion step and with the deasphalted oil (DAO) obtained from the deasphalting step and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.
The production of gasoline is significantly increased.
Third Variation of the Process of the Invention
The third variation of the process of the invention, known as the “3N implementation”, is distinguished from the second variation by the fact that the deasphalted hydrocarbon cut obtained from the deasphalting step is sent to a second step for hydroconversion in the presence of hydrogen: this step may be carried out under fixed bed hydrocracking conditions or under ebullated bed hydrocracking conditions so as to produce, preferably after a separation step h), a gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and a residual unconverted fraction.
In this variation, the gas oil and vacuum gas oil fractions obtained from the separation step h) are sent to the hydrotreatment step c)i) or to the hydrocracking step c)ii) as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.
In this variation of the process of the invention, the hydrotreatment or hydrocracking effluent is fractionated in the fractionation zone (step d) into several fractions including a gasoline fraction, a gas oil fraction and an unconverted vacuum gas oil fraction.
In this variation of the invention known as the “3N implementation”, at least a portion of the vacuum gas oil fraction obtained from the fractionation step d) is recycled to the inlet of the deasphalting step and/or to the inlet of the first hydroconversion step.
At least a portion of the gas oil fraction obtained from the fractionation step is sent to the second hydrocracking step. The effluent obtained from the second hydrocracking step is returned to the fractionation step d).
Thus, referring to FIG. 3, the feed A constituted by vacuum residues (SR VR) is sent via the conduit 1 to a hydroconversion section 20 (denoted H-OilRC in FIG. 3) in order to produce, after separation (not shown), a gasoline fraction 4 (N), a gas oil fraction 5 (GO), a vacuum gas oil fraction 6 (VGO) and a residual unconverted fraction 3 (VR). The gas oil fraction 5 (GO) and the vacuum gas oil fraction 6 (VGO) are sent to the hydrotreatment or hydrocracking section (HCK) 30 via the conduit 6. The residual unconverted fraction (VR) is sent via the conduit 3 to a deasphalting unit 50 (SDA) in order to extract a deasphalted oil (DAO) and a residual asphalt (Pitch) via the conduit 16. The deasphalted oil fraction (DAO) is then sent via the conduit 15 to a hydroconversion section 60 (denoted H-OilDC in FIG. 3) in order to produce a gasoline fraction 18 (N), a gas oil fraction 17 (GO), a vacuum gas oil fraction 7 (VGO) and a residual unconverted fraction 19 (VR). The gas oil fraction 17 (GO) and the vacuum gas oil fraction 7 (VGO) obtained from section 60 are then sent to the hydrotreatment or hydrocracking section 30 via the conduit 6. The effluent obtained from the section 30 is then separated, in the fractionation zone 40, into a gasoline fraction 12 (N), a gas oil fraction 13 (GO) and a vacuum gas oil fraction 14 (VGO). At least a portion of the vacuum gas oil fraction 14 (VGO) is returned to the deasphalting section 50 via the conduits 9 and 2 and/or to the first hydroconversion section 20 via the conduits 9 and 10. Recycling the vacuum gas oil fraction 14 (VGO) to the deasphalting unit means that an additional quantity of deasphalted oil (DAO) can be sent to the first hydrotreatment or hydrocracking step (section 30) and an additional production of gasoline can be generated. Recycling the vacuum gas oil fraction 14 (VGO) to the first hydroconversion section 20 means that the vacuum gas oil can be cracked into gas oil and gasoline without any impact on the operation of the unit in this section.
At least a portion 13b of the gas oil fraction 13 obtained from the fractionation zone is sent to the hydrocracking section 70 (second hydrocracking step). The effluent leaving the section 70 is recycled to the fractionation zone 40 via the conduit 11.
Without further elaboration, it is believed that one skilled in the art can, using the preceding description, utilize the present invention to its fullest extent. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way whatsoever.
In the foregoing and in the examples, all temperatures are set forth uncorrected in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated.
The entire disclosures of all applications, patents and publications, cited herein and of corresponding Franch application No. 14/62.713, filed Dec. 18, 2014 are incorporated by reference herein.



BRIEF DESCRIPTION OF FIGURES
FIG. 4 is a schematic representation of a process of the prior art.
FIGS. 1-3 are schematic representations of various embodiments of the invention



EXAMPLES
The feed used in these examples had the composition detailed in Table 1. It was an “Arabian Heavy” type residue, i.e. a vacuum residue obtained by distillation of a crude oil originating from the Arab Peninsula.







TABLE 1







Composition of the feed used (“Arabian Heavy” vacuum residue)











Property
Unit
Value















Density
—
1.040



Viscosity at 100° C.
cSt
5200



Conradson Carbon
% by wt
23.5



C7 asphaltenes
% by wt
13.8



Nickel
ppm
52



Vanadium
ppm
140



Nitrogen
ppm
5300



Sulphur
% by wt
5.4



565° C.− cut*
% by wt
16.45







*cut containing products with a boiling point of less than 565° C.






This feed was used in the various variations of the process illustrated by layouts 0, 1N, 2N, 3N (respectively represented in FIGS. 1, 2, 3 and 4) without the addition of straight run gas oil and/or straight run vacuum gas oil (SR GO-VGO) to the inlet of the hydrocracking step (HCK) or hydrotreatment step (HDT). Furthermore, regarding the layouts 2N and 3N, the recycle of VGO obtained from fractionation was sent only to the deasphalting unit (SDA), while in the case of layout 1N it was sent to the first hydroconversion unit H-OilRC.
The operating conditions for the conversion sections H-OilRC, H-OilDC, first and second hydroconversion unit, first and second HCK unit (hydrocracking units) in a first variation using two hydrocracking units as well as the solvent deasphalting unit (SDA) are summarized in Table 2.
Table 2bis summarizes the operating conditions for the units in a second variation using the conversion sections H-OilRC, H-OilDC, first and second hydroconversion unit, one hydrotreatment unit HDT (replacing the first hydrocracking unit), one hydrocracking unit as well as one solvent deasphalting unit (SDA).
The H-Oil hydroconversion units were operated with ebullated bed reactors and the hydrocracking units were operated with fixed bed reactors.
The deasphalting unit was operated with an extraction column.







TABLE 2







Operating conditions for units

















HCK
HCK



Parameter

H-OilRC
H-OilDC
(1st step)
(2nd step)
SDA
















Liquid HSV
h-1
0.25
0.3
0.5
1.2
—


Pressure
MPa
18
17
18
18
4.5


WABT SOR*
° C.
420
445
385
370
—


Extractor





120 at


temperature





extractor








head








90 at








extractor








bottom


H2/feed
m3/m3
400
300
1000
1000
—


Solvent/feed
m3/m3
—
—
—
—
2/1


Extractor inlet
m3/m3




4/1


Extract bottom








Catalysts

HOC 458 TM
HTS 458 TM
HRK 1448 TM
HYK 732 TM
—






HYK 732 TM

—


Catalyst

NiMo/Al2O3
NiMo/Al2O3
NiMo/Al2O3
NiMo/zeolite Y



compositions



NiMo/zeolite Y





*Weighted Average Bed Temperature at Start of Run













TABLE 2bis







Operating conditions for units













Parameter

H-OilRC
H-OilDC
HDT
HCK
SDA
















Liquid HSV
h-1
0.25
0.3
0.7
0.8
—


Pressure
MPa
18
17
18
18
4.5


WABT SOR*
° C.
420
445
390
375
—


Extractor





120 at


temperature





extractor








head








90 at








extractor








bottom


H2/feed
m3/m3
400
300
1000
1000
—


Solvent/feed
m3/m3
—
—
—
—
2/1


Extractor inlet
m3/m3




4/1


Extract bottom








Catalysts

HOC 458 TM
HTS 458 TM
HRK 1448 TM
HYK732 TM
—


Catalyst

NiMo/Al2O3
NiMo/Al2O3
NiMo/Al2O3
NiMo/zeolite Y



composition











*Weighted Average Bed Temperature at Start of Run






The catalysts used were commercial catalysts from Axens. The solvent used in the SDA unit was a mixture of butanes comprising 60% of nC4 and 40% of iC4.
The yields for the products obtained with the operating conditions of Table 2 are indicated in Table 3 in the form of a percentage by weight for each product obtained with respect to the initial weight of the vacuum residue feed (SR VR) introduced into the process.







TABLE 3







Yields of products as a function of the process layout used













Variation 1N
Variation 2N
Variation 3N




(HCK 1st 
(HCK 1st 
(HCK 1st 


% by weight vs.
FIG. 0
step)
step)
step)


SR VR*
(prior art)
(invention)
(invention)
(invention)














LN
8
21
22
23


HN
9
42
45
49


GO
47
<1
<1
<1


VGO
5
1
7
2


VR + pitch
22
22
10
11


Total liquids
91
87
84
86





*LN: Light Naphta,


HN: Heavy Naphta,


GO: Gas Oil


VGO: Vacuum Gas Oil,


VR: Vacuum Residue,


SR Straight Run.






It appears that the variations 1N, 2N and 3N with a hydrocracking (HCK 1st step) in step c) in accordance with the invention favours the formation of light naphtha (LN) and heavy naphtha (HN) and a reduction in the overall liquid yield due to a more intense conversion. This reduction in the liquid yield is, however, very limited and in the range 4% to 7% compared with the prior art layout (layout 0).
At the same time, a considerable increase in the naphtha yield was noticed; it passed from 8% (layout 0) to more than 20% (layouts 1N, 2N, 3N) for the light naphtha and from 9% to values in the range 40% to 50% for the heavy naphtha.
The overall naphtha yield was thus 72% with layout 3N, with a negligible production of GO and VGO (<3%), the other principal products being pitch and vacuum residue (pitch obtained from the SDA unit and VR effluent obtained from the H-OilDC unit), which represented approximately 10% of yield points. The layout 1N resulted in higher yields of VR+pitch than layouts 2N and 3N.
Table 3bis describes the results obtained when the first hydrocracking of step c)i) was replaced with a hydrotreatment with the operating conditions indicated in Table 2bis.







TABLE 3bis







Yields of products as a function of the process layout used











Variation 3N


% by weight vs.
FIG. 0
(HDT)


SR VR*
(prior art)
(invention)












LN
8
24


HN
9
51


GO
47
<1


VGO
5
1


VR + pitch
22
11


Total liquids
91
87









It appears that variation 3N, carried out with a hydrotreatment (HDT) step instead of the first hydrocracking step, resulted in the substantial formation of light naphtha (LN) and heavy naphtha (HN) and a substantial reduction in the liquid yield compared with the prior art. The results obtained were of the same order of magnitude as for the variations 1N, 2N and 3N carried out with the first hydrocracking step (Table 3), or even slightly higher. Removal of the contaminants in the hydrotreatment section and thus their absence in the second hydrocracking step could explain these results.
Table 4 indicates the properties of the various products obtained using the various layouts of the process.







TABLE 4







Properties of products obtained from hydrocracking














LN
HN







Cut points
° C.
30-80
80-150



Density
—
0.685
0.755



Sulphur
ppm
<1
<1



P/N/A*
% by wt 
63/36/1
31/66/3



Cetane
—
—
—







*Paraffins/Naphthenes/Aromatics






The naphthas obtained from the hydrocracking step may be upgraded as they are, for example in catalytic reforming units, in order to produce gasoline.
The vacuum residues (VR obtained from the H-OilRC unit, VR obtained from the H-OilDC unit and asphalt obtained from deasphalting) were principally upgraded as heavy fuel after adjusting their viscosity by mixing with distillates available on site.
The preceding examples can be repeated with similar success by substituting the generically or specifically described reactants and/or operating conditions of this invention for those used in the preceding examples.
From the foregoing description, one skilled in the art can easily ascertain the essential characteristics of this invention and, without departing from the spirit and scope thereof, can make various changes and modifications of the invention to adapt it to various usages and conditions.

## Claims

1. A process for the intense conversion of a heavy hydrocarbon feed, comprising the following steps:
a) a first step for ebullated bed hydroconversion of the feed in the presence of hydrogen, comprising at least one three-phase reactor containing at least one ebullated bed hydroconversion catalyst;
b) a step for separating at least a portion of the hydroconverted liquid effluent obtained from step a) into a gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and an unconverted residual fraction;
c) i) either a step for hydrotreatment of at least a portion of the gas oil fraction and the vacuum gas oil fraction obtained from step b) in a reactor comprising at least one fixed bed hydrotreatment catalyst;
ii) or a first step for hydrocracking at least a portion of the gas oil fraction and the vacuum gas oil fraction obtained from step b) in a reactor comprising at least one fixed bed hydrocracking catalyst;

d) a step for fractionating at least a portion of the effluent obtained from step c)i) or step c)ii) into a gasoline fraction, a gas oil fraction and an unconverted vacuum gas oil fraction;
e) a step for recycling at least a portion of the unconverted vacuum gas oil fraction obtained from fractionation step d) to said first hydroconversion step a);
f) a second step for hydrocracking at least a portion of the gas oil fraction obtained from fractionation step d);
g) a step for recycling all or a portion of the effluent obtained from step f) to the fractionation step d).

2. The process according to claim 1, in which at least a portion of the residual unconverted fraction obtained from step b) is sent to a deasphalting section in which it is treated in an extraction step using a solvent under conditions for obtaining a deasphalted hydrocarbon cut and pitch.

3. The process according to claim 2, in which at least a portion of the deasphalted hydrocarbon cut obtained from the deasphalting step is sent to the hydrotreatment step c)i) or the hydrocracking step c)ii) as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.

4. The process according to claim 2, in which at least a portion of the deasphalted hydrocarbon cut obtained from the deasphalting step is sent to a second step for hydroconversion in the presence of hydrogen, said step being carried out in fixed bed or ebullated bed mode.

5. The process according to claim 4, in which the effluent obtained from the second hydroconversion step undergoes a separation step h) in order to produce at least a gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and a residual unconverted fraction.

6. The process according to claim 5, in which at least a portion of the gas oil and vacuum gas oil fractions obtained from the separation step h) is sent to the hydrotreatment step c)i) or the hydrocracking step c)ii) as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.

7. The process according to claim 2, in which at least a portion of the vacuum gas oil fraction obtained from the fractionation step d) is recycled to the inlet of the deasphalting step and/or to the inlet of the first hydroconversion step.

8. The process according to claim 1, in which the hydroconversion step a) is operated under an absolute pressure in the range 5 to 35 MPa, at a temperature of 260° C. to 600° C. and at an hourly space velocity of 0.05 h−1 to 10 h−1.

9. The process according to claim 1, in which the operating conditions used in the hydrotreatment step c)i) are a pressure in the range 5 to 35 MPa, a temperature in the range 320° C. to 460° C. and a liquid hourly space velocity in the range 0.1 to 10 h−1.

10. The process according to claim 1, in which the operating conditions used in the first hydrocracking step c)ii) are a weighted average catalytic bed temperature in the range 300° C. to 550° C., a pressure in the range 5 to 35 MPa and a liquid hourly space velocity in the range 0.1 to 20 h−1.

11. The process according to claim 1, in which the second hydrocracking step is carried out at a temperature at least 10° C. below that employed during the hydrotreatment step c)i) or the first hydrocracking step c)ii), and at a liquid hourly space velocity (feed flow rate/volume of catalyst) which is at least 30% higher, preferably at least 45% higher, more preferably at least 60% higher than that employed during the hydrotreatment step c)i) or the first hydrocracking step c)ii).

12. The process according to claim 2 in which, in the deasphalting step, the typical temperature at the head of the extractor is in the range 60° C. to 220° C. and the temperature at the bottom of the extractor is in the range 50° C. to 190° C.

13. The process according to claim 1, in which the feed is selected from heavy hydrocarbon feeds of the atmospheric residue or vacuum residue type obtained, for example, by straight run oil cut distillation or by vacuum distillation of crude oil, distillate type feeds such as vacuum gas oils or deasphalted oils, asphalts obtained from oil residue solvent deasphalting, coal in suspension in a hydrocarbon fraction such as, for example, gas oil obtained by vacuum distillation of crude oil or a distillate obtained from the liquefaction of coal, used alone or as a mixture.