Patent Publication Number: US-2017369796-A1

Title: Deep hydroconversion process using an extraction of aromatics and resins, with upgrading of the hydroconversion extract and raffinate in downstream units

Description:
FIELD OF THE INVENTION 
     The invention relates to the field of the deep conversion of heavy hydrocarbon feeds in order to obtain upgradable hydrocarbon cuts such as liquefied petroleum gas (or LPG), gasolines or naphthas, kerosene, gas oil and oils. 
     The invention pertains to process flow diagrams which can be used to improve the performances of conversion units by introducing an extraction of the aromatics. 
     As a general rule, refineries comprise a unit for deep hydroconversion of residue followed by an atmospheric fractionation then a vacuum fractionation and downstream, a catalytic cracking unit and/or a hydrocracking unit. Optionally, a unit for deasphalting residue not converted during the hydroconversion is also present. 
     Deep hydroconversion processes are used in the refinery to transform mixtures of heavy hydrocarbons into easily upgradable products. They are usually principally used to con vert heavy feeds such as oil cuts or heavy synthetics, for example residues obtained from atmospheric and vacuum distillation, in order to convert them into lighter gasoline and gas oil. During the hydroconversion, fuel gas and light cuts such as LPG (liquefied petroleum gas) and naphtha (gasoline cut) are also produced. 
     The deep hydroconversion process may be an ebullated bed residue hydrocracking process. This technology is in particular commercialized under the name H-OIL®. The feed is then usually vacuum residue. 
     The deep hydroconversion unit produces heavy unconverted residue with a high asphaltenes content. The asphaltenes are unstable and have a tendency to precipitate in hot spots such as the furnaces and column bottoms (more particularly in the vacuum column). As a consequence, the units and columns are periodically stopped for cleaning, which reduces their availability time. Typically, continuous runs last two years, then the units are stopped and opened for cleaning. The vacuum column is stopped even more frequently (typically every year). 
     The asphaltenes constitute a family of compounds which are soluble in aromatic and polyaromatic solvents and are insoluble in aliphatic hydrocarbons (n-pentane, n-heptane, etc). Their structure and their composition vary as a function of the origin of the oil feed, but certain atoms and groups of said structure are always present in variable proportions. Examples of these atoms that may be cited are oxygen, sulphur, nitrogen, heavy metals such as nickel and vanadium, for example. The presence of many polycyclic groups endows the asphaltene molecules with a highly aromatic character. Because of their insolubility in aliphatic hydrocarbons and as a function of the aromatic or less aromatic nature of the crude oil or the oil cuts (also denoted as derivative products), the asphaltenes might precipitate out. This phenomenon causes the formation of deposits in the lines and production equipment (reactors, drums, columns and exchangers). 
     Resins are hydrocarbon compounds analogous to asphaltenes, but in contrast to asphaltenes, they are soluble in solvents such as n-pentane or n-heptane. Resins are typically constituted by a condensed polycyclic nucleus composed of aromatic and cyclanic rings and sulphur-containing or nitrogen-containing heterocycles with a low molecular weight and a less condensed structure than asphaltenes. 
     A first means for improving residue stability is to adjust the conversion in the reaction section by limiting it. In this case, the stability of the residue dictates the maximum conversion which can be reached in the deep hydroconversion units (typically 60% to more than 80% by weight). 
     Another way of obtaining an increase in the conversion of deep hydroconversion units is to mix a diluent (5% to 10% by weight, and typically up to 20% by weight) constituted by heavy feeds which are rich in aromatic compounds and resins, alone or as a mixture, with the feed. This means that longer runs can be operated or, for an equivalent run length, to higher degrees of conversion. Typically, this diluent may be a slurry from catalytic cracking (namely the sludge or heavy residual fraction obtained from FCC, the 360° C. +  cut with dominant aromatics). 
     In practice, the refiners combine the two means (adjusted conversion and dilution of the feed) in the hydroconversion unit in order to limit asphaltene deposits. 
     In a typical refinery, the possible diluents such as the heavy residual fraction (slurry) from catalytic cracking, are available in limited quantities and are thus a factor limiting the maximum conversion which can be obtained in deep hydroconversion units. 
     Prior Art 
     Many configurations have been developed in order to overcome the problems mentioned above, with the aim of improving deep hydroconversion processes by increasing the yields of upgradable products while keeping the operating costs optimized. 
     The patents U.S. Pat. No. 5,980,730 and U.S. Pat. No. 6,017,441 describe a process for the deep conversion of a heavy oil fraction, said process comprising a step for three-phase ebullated bed hydroconversion, an atmospheric distillation of the effluent obtained, a vacuum distillation of the atmospheric residue obtained, deasphalting of the vacuum residue obtained and a hydrotreatment of the deasphalted fraction. It is also possible in that process to send at least a heavy liquid fraction obtained from the hydrotreatment step to a fluidized bed catalytic cracking section, or to recycle a portion of the deasphalted fraction or a portion of the asphalt to the hydroconversion inlet. 
     The patent FR 2 969 650 B1 describes a process for the conversion of hydrocarbon feed comprising a shale oil, said process comprising a step for ebullated bed hydroconversion, an atmospheric distillation of the effluent obtained and a liquid/liquid extraction of the atmospheric residue fraction with a solvent in order to extract the aromatics and the resins. In accordance with the variations of the process, it is possible to send a fraction of raffinate to a catalytic cracking section and to recycle a fraction of the extract to the hydroconversion unit. Since the atmospheric residue obtained from the hydroconversion is not deasphalted in the process described in that patent, the extract obtained from the extraction unit is likely to contain asphaltenes, which could lead to a degradation of the hydroconversion performances in the case of recycling it to the hydroconversion. In addition, the process described in that patent is specifically adapted to the treatment of feeds comprising shale oils the nature of which is different from conventional hydrocarbon feeds. 
     The patent FR 2 984 917 B1 describes a process for optimizing the production of middle distillate in a refinery containing at least one catalytic cracking unit, in which one of the variations consists of submitting the vacuum residue deriving from a catalytic cracking unit to a solvent extraction of the aromatics or, in one variation, to deasphalting with propane, then sending the extract to the fuel oil pool and recycling the raffinate to the inlet of the catalytic cracking unit. In the process described in that patent, the extract from the extraction unit is not upcycled to the hydroconversion unit. 
     The patent application US 2013/0026065 A1 describes a process for producing transport fuels starting from heavy hydrocarbons by submitting them to liquid/liquid extractor of aromatics, then by sending the fraction enriched in aromatics to a hydrocracker and the fraction depleted in aromatics to a catalytic cracking unit. 
     The Applicant&#39;s application Ser. No. 14/62.715 filed on 18 Dec. 2014, which has not been published, describes a process for deep conversion of residues, comprising a step for hydroconversion, a step for separation, a step for hydrocracking of the vacuum gas oil fraction, a step for fractionation of the hydrocracked effluent and a recycle of the unconverted vacuum gas oil fraction to the hydroconversion step, with the aim of maximizing the production of gas oil. 
     However, none of the prior art documents can overcome all of the problems mentioned. 
     The process in accordance with the invention proposes the addition of a deasphalting unit after the deep hydroconversion unit and the fractionation section, followed by a unit for extraction of aromatic hydrocarbons and resins on the residue fraction obtained from the vacuum fractionation, and upcycling the extract and the raffinate obtained to the aromatics extraction unit. 
     The invention can be used to simultaneously improve the performances of the deep hydroconversion unit and those of any units located downstream such as hydrocracking or catalytic cracking. 
     In fact, compared with the usual refinery configuration, the process in accordance with the invention can be used to obtain yields of upgradable hydrocarbon cuts which are higher, while guaranteeing the same cycle time for the deep hydroconversion unit, or even increasing it, and improving the performances of the downstream units. 
     The present invention is intended to overcome the disadvantages of prior art processes by extracting from the deep hydroconversion effluents a heavy fraction which is enriched in aromatic compounds and resins,
         on the one hand, to use this extracted fraction as an aromatic diluent for hydroconversion,   on the other hand, to use the raffinate obtained from this extraction in any downstream units such as hydrocracking and/or catalytic cracking.       

     The process in accordance with the invention can be used to obtain higher yields of upgradable products using an extraction of aromatics and resins contained in the unconverted residue obtained from the deep hydroconversion in accordance with the variations of the process flow diagrams detailed below. 
     SUMMARY OF THE INVENTION 
     The invention concerns a process for deep conversion of a heavy hydrocarbon feed, comprising the following steps:
         a) ebullated bed hydroconversion of the feed, in the presence of hydrogen, in a hydroconversion section comprising at least one three-phase reactor containing at least one supported hydroconversion catalyst,   b) atmospheric fractionation of at least a portion of the hydroconverted liquid effluent obtained from step a) in an atmospheric fractionation section in order to produce a fraction comprising a gasoline cut and a gas oil cut, and an atmospheric residue;   c) vacuum fractionation of at least a portion of the atmospheric residue obtained from step b) in a vacuum fractionation section in order to obtain a vacuum gas oil fraction comprising light vacuum distillates (LVGO) and heavy vacuum distillates (HVGO) and an unconverted vacuum residue fraction,   d) deasphalting at least a portion of the unconverted vacuum residue fraction obtained from step c) in a deasphalting section by means of an organic solvent under conditions for obtaining a hydrocarbon cut depleted in asphaltenes, termed deasphalted oil, and residual asphalt,   e) liquid/liquid extraction carried out on the hydrocarbon cut depleted in asphaltenes in a section for the extraction of aromatics by means of a polar solvent under conditions for extracting aromatics in order to produce an extract enriched in aromatics and resins and a raffinate depleted in aromatics and resins, at least a portion of the extract being sent to the inlet to the hydroconversion section as an aromatic diluent.       

     The process in accordance with the invention may furthermore comprise:
         a step f1) for hydrocracking at least a portion of the raffinate obtained from the extraction step e) in a reactor comprising at least one fixed bed of hydrocracking catalyst in order to produce a gasoline fraction, a gas oil fraction (GO), vacuum gas oil (VGO) and an unconverted oil fraction (UCO),   and/or a step f2) for fluidized bed catalytic cracking of at least a portion of the raffinate obtained from the extraction e) in a fluidized bed reactor in order to produce a gaseous fraction, a gasoline fraction, a gas oil fraction and a heavy residual fraction termed a slurry.       

     The unconverted oil fraction obtained from hydrocracking and/or the heavy residual fraction obtained from catalytic cracking may be sent to the aromatics extraction section. 
     A portion of the extract may be used as a flux oil as a mixture with residual asphalt produced by the deasphalting step d) in order to provide a liquid fuel or to form part of the bitumen composition or to be supplied to a coking unit. 
     The raffinate produced by the aromatics extraction unit may be sent to the hydrocracking unit and/or to the catalytic cracking unit together with one or more other feeds selected from straight run vacuum gas oil (straight run VGO) and light (LVGO) and heavy vacuum distillates (HVGO) obtained from the outlet from the vacuum fractionation c). 
     At least a portion of the light vacuum distillate (LVGO) or of the heavy vacuum distillate (HVGO) is sent to the aromatics extraction section. 
     In a variation, a portion of the atmospheric residue is sent directly to the deasphalting section. 
     The hydroconversion step a) is preferably operated at an absolute pressure in the range 5 to 35 MPa, at a weighted average catalytic bed temperature of 300° C. to 600° C., at an hourly space velocity of 0.1 h −1  to 10 h −1  and at a ratio of hydrogen to feed H 2 /HC of 200 to 1000 m 3 /m 3 . 
     The hydrocracking step f1) is preferably operated at an average catalytic bed temperature in the range 300° C. to 550° C., a pressure in the range 5 to 35 MPa, and a liquid space velocity in the range 0.1 to 10 h −1 . 
     The fluidized bed catalytic cracking step f2) is preferably operated in upflow mode with a reactor outlet temperature in the range 520° C. to 600° C., a C/O ratio in the range 6 to 14, and a dwell time in the range 1 to 10 s, or in downflow mode with a reactor outlet temperature in the range 580° C. to 630° C., a C/O ratio in the range 15 to 40, and with a dwell time in the range 0.1 to 1 s. 
     Preferably, the deasphalting step is carried out in an extraction column, the solvent comprising at least 50% by weight of hydrocarbon compounds containing 3 to 7 carbon atoms, the extracter head temperature being in the range 50° C. to 250° C., the extracter bottom temperature being in the range 30° C. to 220° C., and the pressure being in the range 2 to 10 MPa. 
     Highly preferably, the solvent is butane. 
     Preferably, the liquid/liquid extraction is carried out with the aid of a solvent selected from furfural, N-methyl-2-pyrrolidone (NMP), sulfolane, dimethylformamide (DMF), dimethylsulphoxide (DMSO), phenol, or a mixture of these solvents in equal or different proportions, with a solvent/feed ratio of 0.5/1 to 3/1, at a temperature in the range between ambient temperature and 150° C., and at a pressure in the range between atmospheric pressure and 2 MPa. 
     The feed is advantageously selected from heavy hydrocarbon feeds of the atmospheric residue or vacuum 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, asphaltenes obtained by solvent deasphalting oil residues, coal in suspension in a hydrocarbon fraction such as gas oil obtained from vacuum distillation of crude oil, for example, or in fact the distillate obtained from coal liquefaction, alone or as a mixture. 
     DETAILED DESCRIPTION OF THE INVENTION 
     The process in accordance with the invention is preferably applicable to hydrocarbon feeds containing refractory asphaltenes. Compared with flow diagrams known in the prior art, the process in accordance with the invention proposes inserting a supplemental aromatics extraction unit in order to improve the performance of the flow diagram, with upgrading of the extract and possibly the raffinate obtained. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  describes the process flow diagram in accordance with the prior art:
         Flow diagram 1 (prior art): Concatenation of a deep hydroconversion unit, a deasphalting unit SDA and optionally a hydrocracking unit HCK and/or a fluidized bed catalytic cracking unit FCC.       

         FIG. 2  describes the process flow diagram in accordance with the invention:
         Flow diagram 2 (invention): Concatenation of a deep hydroconversion unit, a deasphalting unit SDA, an aromatics extraction unit and optionally sending the raffinate obtained to a hydrocracking unit HCK and/or a fluidized bed catalytic cracking unit FCC.       

     
    
    
     DESCRIPTION OF THE FIGURES 
     FIG.  1 : Prior Art 
     The flow diagram in accordance with the prior art integrates the following units:
         At least a first unit  10  for deep ebullated bed hydroconversion of the feed. This technology is in particular commercially available under the process name H-OIL RC ®. The deep hydroconversion unit refines and cracks the feed composed of vacuum residue type hydrocarbons obtained by distilling a crude oil VR (vacuum residue) into significant quantities of gas  21 , light and heavy naphtha (heavy naphtha HN and light naphtha LN)  22 , gas oil (GO) and vacuum distillates (vacuum gas oil, VGO) into one or two fractions of light vacuum gas oil, LVGO,  31  and heavy vacuum gas oil, HVGO,  32 . These various products are separated in an atmospheric fractionation section  20  and vacuum fractionation section  30 . A stream of unconverted vacuum residue (VR) subsisting at the bottom of the vacuum distillation is sent to the deasphalting unit  40 .   The solvent deasphalting unit (SDA)  40  supplied with the unconverted vacuum residue (VR)  33  from the deep hydroconversion unit produces a good quality deasphalted oil (DAO)  41  which is compatible with the function of a hydrocracking unit or fluidized bed catalytic cracking unit (FCC), and a residual asphalt  42  concentrating the major portion of the contaminants of the vacuum residue VR obtained from the deep hydroconversion unit which has various possible destinations: as an example, as a supply to a coking unit  80 , or a unit for gasification or for visbreaking, or for use as solid fuel (flaker) or liquid fuel or for use for bitumen.   The fixed bed hydrocracking unit (HCK)  60  can convert the deasphalted oil (DAO)  41  as well as the vacuum distillate (vacuum gas oil VGO)  31  and  32  obtained from the deep hydroconversion unit, as well as, for example, SR VGO (straight run vacuum gas oil, vacuum distillate obtained from straight run distillation of crude oil)  91  and other compatible feeds, in order to form a stream  71  comprising significant quantities of naphtha, gas oil and vacuum gas oil. There remains a stream of unconverted VGO (unconverted oil, UCO)  62 , a portion of which is purged (bleed). This unconverted stream  62  may be used as a base for the oil units or used as a diluent to upgrade the asphalt into heavy fuel. Optionally, the vacuum distillate (VGO) produced in the hydrocracking unit (HCK) may be recycled to the deep hydroconversion unit for partial cracking into gas oil and naphtha without any significant impact on the operation of this unit. In accordance with a variation, the refinery flow diagram does not include a fixed bed hydrocracking unit (HCK), but a fluidized bed catalytic cracking unit (FCC)  70  which may also be supplied with deasphalted oil (DAO)  41  and the vacuum distillate ( 31  and  32 ) VGO from the H-OIL RC ®. In accordance with a variation, vacuum distillate obtained by straight run distillation of crude oil (SR VGO)  91  may be sent to the process together with the preceding two feeds, as well as potentially with other external feeds. The fluidized bed catalytic cracking unit FCC produces a fraction  71  comprising significant quantities of gas, light and heavy gasoline (heavy naphtha HN and light naphtha LN), light cycle oil (LCO) and heavy cycle oil (HCO), and a residual heavy fraction  72  known as slurry. The residual heavy fraction (slurry) from this FCC unit, which is available in limited quantities, is advantageously used as a diluent for the deep hydroconversion unit feed.   In accordance with another variation, the flow diagram comprises both a fixed bed hydroconversion unit (HCK)  60  and a fluidized bed catalytic cracking unit (FCC)  70 . The two units can be used to treat the vacuum gas oil obtained from ebullated bed hydroconversion (VGO from the hydroconversion)  31  and  32 , the deasphalted oil DAO  41 , typically straight run vacuum gas oil (SR VGO)  91  and other feeds in order to convert them into significant quantities of naphtha, gas oil and vacuum gas oil.
 
 FIG. 2 : Flow Diagram for the Process in Accordance with the Invention
       

       FIG. 2  presents an illustration of the process in accordance with the invention and its variations. The feed  01 , composed of hydrocarbons of oil origin or of mineral source synthetic hydrocarbons, is sent to the deep hydroconversion section  10  with a diluting fluid  02  which derives from the unit for the extraction of aromatics  50 , via the transport line  53 . 
     The liquid effluent from the deep hydroconversion section is sent to an atmospheric fractionation section  20  via the line  11 . This fractionation section comprises one or more atmospheric distillation columns equipped with plates and contact means in order to separate the various upgradable cuts withdrawn by means of the transport lines  21   22  and  23 , plus optional other side streams. These cuts have boiling point ranges located, for example, in the gasoline, kerosene and gas oil ranges. A heavier fraction of unconverted atmospheric residue  24  with a boiling point which is typically more than 350° C. is recovered from the bottom of the fractionation. 
     At least a portion of the atmospheric residue is sent to a vacuum fractionation section  30  via the line  24 . This fractionation section comprises at least one vacuum distillation column equipped with plates and contact means in order to separate the various upgradable cuts withdrawn by means of lines  31  and  32 , plus other optional side streams. These cuts have boiling point ranges which are, for example, in the range of light vacuum distillates (LVGO) and heavy vacuum distillates (HVGO). A heavier fraction of unconverted vacuum residue with a boiling point which is typically more than 540° C. is recovered from the bottom of the fractionation section. 
     The light vacuum distillate (LVGO)  31  and the heavy vacuum distillate (HVGO)  32  may be sent to the hydrocracking unit  60  and/or catalytic cracking unit  70 . 
     The vacuum residue is sent to the deasphalting unit  40  via the line  33  in order to extract the asphaltenes by precipitation in a solvent and to produce deasphalted oil  41  and pitch (residual asphalt)  42 . 
     The deasphalted oil  41  is sent to the aromatics extraction unit  50 ; as well as, optionally, the unconverted oil purge  62  from the hydrocracking unit or the residual heavy fraction from catalytic cracking (FCC slurry)  72 , depending on the variations of the invention. 
     The raffinate  51  produced by the aromatics extraction unit  50  is sent to the hydrocracking unit as well as, optionally, other feeds such as, for example, a straight run vacuum (straight run VGO)  91  and light vacuum distillate  31  and heavy vacuum distillate  32 , products of the hydroconversion  10 . 
     In accordance with a variation, all or a portion of the light vacuum distillate  31  or the heavy vacuum distillate  32  may also be sent to the aromatics extraction unit  50 . 
     In accordance with a variation, a portion of the atmospheric residue  24  is sent to the deasphalting unit. It is also possible to envisage the case in which all of the atmospheric residue 24 is sent to the deasphalting unit, so there is no vacuum fractionation section  30  and the cuts which can be upgraded in the boiling point ranges of light (LVGO) and heavy (HVGO) vacuum distillates are not separated but are sent to the deasphalting unit. 
     In accordance with a variation, the process in accordance with the invention comprises neither a hydrocracking unit  60  nor a catalytic cracking unit  70 . 
     In accordance with another variation, the process in accordance with the invention comprises a hydrocracking unit  60 . 
     In accordance with another variation, the process in accordance with the invention does not comprise a hydrocracking unit  60 , but it does comprise a catalytic cracking unit  70 . 
     In accordance with another variation, the process in accordance with the invention comprises a hydrocracking unit  60  and a catalytic cracking unit  70 . 
     At least a portion of the extract  52  produced by the aromatics extraction unit is used as a diluent in the hydroconversion unit via the line  53  and the excess is upgraded with the pitch  42  corresponding to the residual asphalt from the deasphalting unit via the line  54 . 
     The pitch  42  may be upgraded, for example to form bitumen, after appropriate treatment, or to form heavy fuel after dilution, or in fact it may be sent to a visbreaking, coking or gasification unit  80 . 
     In the process in accordance with the invention, a liquid/liquid extraction unit of the aromatics and resins treats the deasphalted oil obtained from the unit for deasphalting the unconverted residue from the deep hydroconversion:
         The feed is converted in the first step for deep hydroconversion of the feed. The effluents are separated in a fractionation section and an unconverted vacuum residue cut (VR) is separated from the bottom of the fractionation.   The deasphalting unit SDA is supplied with the unconverted vacuum residue       

     (VR) and produces a deasphalted hydrocarbon cut DAO which is sent to the liquid/liquid extraction unit and residual asphalt which is upgraded as in the previous flow diagram. Optionally, any type of unit for reducing the asphalt content of the residue could also be installed in place of the deasphalting unit.
         The aromatics extraction unit produces, by liquid/liquid extraction, an extract enriched in aromatics and resins and a raffinate depleted in aromatics and resins. The extraction unit is supplied with deasphalted oil (DAO). It may also be supplied with the purge of unconverted oil (UCO) obtained from hydrocracking and/or the residual heavy fraction from catalytic cracking, depending on the variations of the flow diagram. The extract is used partly as an aromatic diluent for the residue hydroconversion unit and partly upgraded as a flux oil with the residual asphalt produced by the SDA, for example to provide a liquid fuel or to form part of a bitumen composition, or to supply a coking unit. The raffinate is a hydrocarbon fraction which is depleted in aromatics, resins and impurities compared with the deasphalted oil.   The flow diagram in accordance with the invention preferably comprises a fixed bed hydrocracking unit (HCK) which is generally supplied with raffinate originating from the extraction unit and optionally in addition with light vacuum distillate (light vacuum gas oil, LVGO) and heavy vacuum distillate (heavy vacuum gas oil, HVGO) obtained from the deep hydroconversion unit. The raffinate is a much more favorable feed than deasphalted oil DAO as regards the catalytic performances for hydrocracking. Hydrocracking produces significant quantities of naphtha, gas oil and distillate. A stream of unconverted vacuum distillate stream VGO (unconverted oil, UCO) remains, a portion of which is purged (bleed) and may be sent to the extraction unit because this cut concentrates the heavy polynuclear aromatic compounds (heavy polynuclear aromatics, HPNA) which are refractory. Typically, heavy polynuclear aromatics (HPNA) are defined as polycyclic aromatic compounds or polynuclear aromatic compounds which contain at least 4 or even 6 condensed benzene rings in each molecule such as, for example, coronene (composed of 24 carbons), dibenzo(e,ghi) perylene (26 carbons), coronene (30 carbons) and ovalene (32 carbons). Recovering them in the extraction unit means that an unconverted stream (UC) without heavy polynuclear aromatic compounds HPNA can be recycled to the inlet to the hydrocracker and that the heavy polynuclear aromatic compounds in the extract can be upgraded.   In a variation, the flow diagram does not include a hydrocracking unit, but rather a catalytic cracking unit (FCC). This may also be supplied with light vacuum distillate (light vacuum gas oil, LVGO) and heavy vacuum distillate (heavy vacuum gas oil, HVGO) obtained from the deep hydroconversion unit after fractionation, and with the raffinate deriving from the extraction unit. The raffinate is a more favorable feed than the deasphalted oil for the catalytic performances and for the formation of coke from catalytic cracking. On the one hand, the reduced aromatics content of the feed results in reducing coke production. On the other hand, the reduced nitrogen content can be used to obtain a better yield. In addition, the reduced impurities content in the feed results in reducing the catalyst consumption. Finally, the quantities of impurities in the products from catalytic cracking are reduced. As a consequence, the downstream units for the hydrotreatment of the finished products operate with reduced costs in terms of quantities of catalyst and/or cycle times.   In accordance with another variation, vacuum distillate obtained by straight run distillation of crude oil (SR VGO) or other compatible feeds may at the same time be sent for hydrocracking or for fluidized bed catalytic cracking.   In accordance with another variation, the flow diagram comprises both a fluidized bed catalytic cracking unit (FCC) and a fixed bed hydrocracking unit (HCK). Overall, the two units treat the vacuum gas oil VGO from the deep hydroconversion unit, the raffinate from the extraction unit plus, optionally, vacuum distillate obtained by straight run distillation of crude oil (SR VGO). At least a portion of the purged unconverted stream obtained from the hydrocracking unit (UCO) and/or the heavy residual fraction from catalytic cracking (FCC slurry) are sent to the liquid/liquid extraction unit.   In accordance with a variation of the invention, a portion of the vacuum distillate (vacuum gas oil, VGO) or a portion of the heavy vacuum distillate (HVGO) obtained from the deep hydroconversion unit after fractionation may be sent either to the deasphalting unit in addition to the unconverted residue, or directly to the liquid/liquid extraction unit.   In accordance with another variation of the invention, at least a portion of the atmospheric residue may be sent directly to the deasphalting unit.   The raffinate may also advantageously be used to produce a group I oil base.       

     The operating conditions for the hydroconversion units and deasphalting units (SDA) are known to the person skilled in the art and identical to the operating conditions for the configuration in accordance with the prior art. 
     The extraction may be used to obtain a raffinate containing at most 10% by weight of resins, and preferably at most 5% by weight of resins. 
     The extract obtained contains a minimum of 20% by weight of aromatics and 30% by weight of resins, and preferably at least 30% by weight of aromatics and 40% by weight of resins with an asphaltenes content of less than 1000 ppm. 
     The advantage of the invention resides in the presence of the deasphalting unit upstream of the aromatics extraction, which means that an aromatic extract can be obtained with a low impurities content since these are found in the asphalt leaving deasphalting. 
     The extract obtained is ideally suitable for use as an aromatic diluent for deep hydroconversion. 
     By sending a portion of the extract obtained from hydroconversion, this preferably being operated at iso-conversion, the duration of the continuous deep hydroconversion run is extended very significantly. 
     In another approach, by sending a portion of the extract obtained from hydroconversion, this being operated with an unchangeed continuous run length, the maximum conversion obtained from the deep hydroconversion unit is significantly increased. 
     Using the extract as an aromatic diluent for the deep hydroconversion unit, the latter being operated at iso-conversion or otherwise, also means that an increased production of upgradable finished products such as naphtha, gas oil and vacuum gas oil VGO can be obtained. 
     By sending all or a portion of the raffinate produced in the extraction unit to the hydrocracking unit, the catalytic performances of the hydrocracking unit are improved, along with the production of upgradable products, compared with a unit supplied with the deasphalted hydrocarbon cut (DAO) leaving the deasphalting unit. 
     By sending all or a portion of the unconverted residue (UCO) obtained at the outlet from the hydrocracking unit to the extraction unit, a portion of the unconverted residue purified of heavy polynuclear aromatic compounds HPNA is recycled to the inlet to the HCK and the remainder of the stream, containing the heavy polynuclear aromatic compounds HPNA, is upgraded in the extract instead of the usual practice of purging or upgrading all of this unconverted residue into fuel. 
     By sending all or a portion of the raffinate produced to the aromatics extraction unit in the catalytic cracking unit, alone or as a mixture with other feeds, the catalytic performances of the catalytic cracking unit (consumption of catalysts, conversion, coke production) are improved as well as the production of upgradable products compared with a unit supplied with the deasphalted hydrocarbon cut leaving the deasphalting unit. In addition, the impurities contents in the fluidized bed catalytic cracking FCC products are reduced. As a consequence, the downstream units for the hydrotreatment of finished products are operated at reduced costs regarding the quantities of catalyst and/or the cycle times. 
     By sending all or a portion of the residual heavy fraction (FCC slurry) leaving the catalytic cracking unit to the extraction unit, a portion of this stream may be recycled to the inlet to the fluidized bed catalytic cracking unit FCC. 
     The general operating conditions for the units employed in the process in accordance with the invention are described below. 
     Ebullated Bed Hydroconversion: 
     The technology for ebullated bed hydroconversion of residue type feeds is in particular commercially available under the process name H-OIL ®. 
     The ebullated bed process comprises passing a stream comprising liquid, solid and gas vertically through a reactor containing a bed of catalyst. The catalyst in the bed is maintained in random motion in the liquid. The bulk volume of the catalyst dispersed through the liquid is thus higher than the volume of the catalyst at rest. This technology is generally used for the conversion of heavy liquid hydrocarbons or to convert coal into synthetic oils. 
     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. 
     Any type of supported hydroconversion catalyst comprising a hydrodehydrogenating function may be used. This catalyst may be a catalyst comprising metals from groups 9 and 10 (formerly group VIII), for example nickel and/or cobalt, usually in association with at least one metal from group 6 (formerly group VIB), for example molybdenum and/or tungsten and other promoter elements. The 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. The support may also include other compounds. Usually, an alumina support is used. 
     The spent catalyst is replaced in part by fresh catalyst (i.e. new or regenerated) by withdrawal from the bottom of the reactor, and introducing fresh catalyst into the top of the reactor at regular time intervals, i.e, for example, in blasts or quasi-continuously. As an example, it is possible to introduce fresh catalyst every day. The rate of replacement of spent catalyst by fresh catalyst may, for example, be approximately 0.01 kilograms to approximately 10 kilograms per cubic metre of feed. This withdrawal and replacement are carried out with the aid of devices allowing this hydroconversion step to be operated continuously. The unit usually comprises a recirculation pump to maintain the catalyst as an ebullated bed by continuously recycling at least a portion of the liquid withdrawn from the head of the reactor and reinjection into the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor to a regeneration zone from which the carbon and sulphur it contains are eliminated, then returning this regenerated catalyst. 
     The operating conditions for ebullated bed hydroconversion are advantageously as follows:
         Pressure: the pressure is generally in the range 5 to 35 MPa, preferably in the range 10 to 25 MPa, typically approximately 18 MPa.   LHSV (liquid hourly space velocity): the liquid hourly space velocity is generally in the range 0.1 to 10 h −1 , preferably in the range 0.15 to 5 h −1 , typically approximately 0.25 h −1 .   The average catalytic bed temperature (i.e. the arithmetic mean of the temperature measurements in the catalytic bed) is generally in the range 300° C. to 600° C., preferably in the range 350° C. to 510° C., typically 420° C.   H 2 /HC: the hydrogen/feed ratio is generally in the range: 200 to 1000 m 3 /m 3 , preferably in the range 300 to 800 m 3 /m 3 , highly preferably in the range 300 to 600 m 3 /m 3 .       

     Deep ebullated bed hydroconversion means that the Conradson carbon of the incoming stream can be reduced by approximately 50% to 95% and its nitrogen content by approximately 30% to 95%. 
     Fractionation: 
     In atmospheric fractionation, the cut point of the atmospheric residue is typically adjusted to between 300° C. and 400° C., preferably to between 340° C. and 380° C. The cuts withdrawn, such as naphtha, kerosene and gas oil, are respectively sent to the gasoline pool, the kerosene pool or to the gas oil pool. At least a portion of the atmospheric residue is sent for vacuum fractionation. 
     In the vacuum fractionation section (vacuum distillation column), the vacuum residue cut point is typically adjusted to between 450° C. and 600° C., preferably between 500° C. and 550° C. At least a portion of the cuts withdrawn, such as light vacuum distillate (light vacuum gas oil, LVGO) or heavy vacuum distillate (heavy vacuum gas oil, HVGO), are sent to the downstream units such as hydrocracking or catalytic cracking. A portion of the atmospheric residue (AR) may be sent to the deasphalting unit. 
     The light vacuum distillate (LVGO) is characterized by a distillation range in the range 300° C. to 430° C., preferably in the range 340° C. to 400° C. The heavy vacuum distillate (HVGO) is characterized by a distillation range in the range 400° C. to 600° C., preferably in the range 440° C. to 550° C. 
     At least a portion, preferably all, of the vacuum residue (VR_) is sent to the deasphalting unit. 
     Solvent Deasphalting: 
     This operation can be used to extract a large part of the asphaltenes and reduce the metals content. During this deasphalting, these latter elements become concentrated in an effluent known as asphalt, known here as residual asphalt. 
     The deasphalted effluent, often termed the deasphalted oil DAO, has a very reduced asphaltenes and metals content. 
     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 is insoluble in heptane, i.e. measured using a method described in the standard NF-T 60-115 of January 2002. 
     In accordance with the invention, deasphalting can be used to obtain a deasphalted oil (DAO) containing at most 10000 ppm by weight of asphaltenes, preferably at most 2000 ppm by weight of asphaltenes. 
     The organic 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 (alkanes) containing between 3 and 7 carbon atoms, more preferably between 3 and 6 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 passing 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 increase. 
     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 that oil. The person skilled in the art may select the optimized conditions to obtain an asphaltenes content of below 3000 ppm. 
     The deasphalting step may be carried out using any means known to the person skilled in the art. 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 are introduced into the extraction column, the ratio by volume between the fraction of solvent feed and the hydrocarbon feed being termed the solvent ratio injected with the feed. The aim of this step is to properly mix the feed with the solvent entering the extraction column. A second fraction of solvent feed may be introduced into the decanting zone at the extractor bottom, the ratio by volume between the second fraction of solvent feed and the hydrocarbon feed being termed the solvent ratio injected into the bottom of the extractor. The volume of hydrocarbon feed under consideration in the decanting zone is generally that introduced into the extraction column. The sum of the two ratios by volume between each of the fractions of solvent feed and the hydrocarbon feed is known as the overall solvent ratio. Decanting the asphalt consists of counter-current washing of the emulsion of asphalt in the solvent-oil mixture using pure solvent. It is favoured by an increase in the solvent ratio (in fact, the solvent-oil environment is replaced by a pure solvent environment) and a reduction in temperature. 
     Furthermore, in accordance with a preferred embodiment, a gradient of temperature is established between the head and the bottom of the column in order to generate an internal reflux, which improves the separation between the oily medium and the resins. In fact, the heated mixture of solvent and oil at the head of the extracter means that a fraction comprising resin can be precipitated, which falls inside the extractor. The rising counter-current of the mixture means that the fractions comprising resin which are the lightest can be dissolved at a lower temperature. 
     The pressure prevailing inside the extractor is generally adjusted in a manner such that all of the products remain in the liquid state. 
     The operating conditions for the deasphalting unit (SDA) are advantageously as follows:
         Preferably, the solvent used is an organic C3, C4 or C5 solvent, preferably C4 in the invention. The highly preferred solvent in the context of the invention is butane.   The solvent ratio is generally in the range 2.5/1 to 20/1, preferably in the range 5/1 to 15/1 and more preferably in the range 5/1 to 10/1, typically 6/1 by volume overall (a portion added at the head and a portion at the bottom of the extractor).   The pressure is generally in the range 2 to 10 MPa, preferably in the range 3 to 6 MPa, highly preferably in the range 4 to 5 MPa, typically 4.5 MPa.   The extractor head temperature is generally in the range 50° C. to 250° C., and the extractor bottom temperature is between 30° C. and 220° C.   For a solvent containing 4 carbon atoms (C4): the extractor head temperature is generally in the range 70° C. to 150° C., preferably in the range 90° C. to 130° C., highly preferably 120° C. The extractor bottom temperature is generally in the range 40° C. to 120° C., preferably in the range 60° C. to 100° C.   For a solvent containing 5 carbon atoms (C5): the extractor head temperature is generally in the range 120° C. to 240° C., preferably in the range 150° C. to 210° C., and highly preferably 180° C. The extractor bottom temperature is generally in the range 90° C. to 210° C., preferably in the range 120° C. to 180° C.       

     Extraction of Aromatics: 
     The aromatics extraction unit is intended to extract the aromatic compounds and resins from the heavy fraction obtained from the deasphalting step by liquid/liquid extraction using a polar solvent. The solvent used is a solvent which is known to preferentially extract aromatic compounds. 
     It is important to emphasize that the liquid/liquid extraction is carried out on the heavy fraction in order to prevent losses in the fuel base yields during solvent recovery after extraction. The products which are to be extracted from the heavy fraction preferably have a boiling point which is higher than the boiling point of the solvent in order to avoid a loss of yield during separation of the solvent from the raffinate after the extraction. In fact, during the separation of solvent and raffinate, any compound with a boiling point lower than the boiling point of the solvent will inevitably leave with the solvent and thus reduce the quantity of raffinate obtained (and thus the fuel base yield). As an example, in the case of furfural as the extraction solvent, with a boiling point of 162° C., the C10-compounds, compounds representative of the gasoline/naphtha fraction, will be lost. By treating only the heavy fraction comprising compounds with boiling points above the boiling point of the extraction solvent, there is no loss of these compounds boiling above the boiling point of the extraction solvent (C10-compounds). In addition, contamination of the solvent with the C10-compounds is avoided, as well as any steps for treatment of the solvent with a view to recycling it. Thus, solvent recovery is more effective and economical. 
     The solvent which may be used is furfural, N-methyl-2-pyrrolidone (NMP), sulfolane, dimethylformamide(DMF), dimethylsulphoxide (DMSO), phenol, or a mixture of these solvents in equal or different proportions. 
     In the context of the invention, the preferred solvent is furfural, which is a product which is sufficiently heavy compared with the treated fluid: deasphalted oil DAO. 
     An aromatics extraction unit originally constructed for an oil line could advantageously be modified for use in the process in accordance with the invention. 
     The operating conditions are in general a solvent/feed ratio of 0.5/1 to 3/1, preferably 1/1 to 2/1, a temperature profile in the range between ambient temperature and 150° C., preferably in the range 50° C. to 150° C. The pressure is between atmospheric pressure and 2 MPa, preferably between 0.1 MPa and 1 MPa. 
     The liquid/liquid extraction may generally be carried out in a mixer settler or in an extraction column operating in counter-current mode. Preferably, the extraction is carried out in an extraction column. 
     The solvent selected has a boiling point which is sufficiently high to be able to fluidize the heavy fraction obtained from fractionation without vaporizing it, the heavy fraction typically being conveyed at temperatures in the range 200° C. to 300° C. 
     After contact of the solvent with the heavy fraction, two phases are formed: (i) the extract, constituted by portions of the heavy fraction not dissolved in the solvent (and highly concentrated in aromatics) and (ii) the raffinate, constituted by solvent and soluble portions of the heavy fraction. The solvent is separated by distillation of the soluble portions and recycled inside the liquid/liquid extraction process; the management of the solvent is known to the person skilled in the art. 
     Downstream Units: 
     The raffinate obtained from the aromatics extraction is sent to the hydrocracking and/or catalytic cracking unit alone or together with one or more other feeds selected from straight run vacuum gas oil (straight run VGO) and light (LVGO) and heavy vacuum distillates (HVGO) obtained from the outlet from the vacuum fractionation c). 
     Hydrocracking 
     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 carried out in accordance with once-through configurations comprising an initial intense hydrorefining step which is intended to carry out intense hydrodehydrogenation and desulphurization of the feed before the invention can be sent in its entirety over the hydrocracking catalyst proper, in particular in the case when the latter comprises a zeolite. 
     It also encompasses two-step hydrocracking, which comprises a first step which is aimed, like the “once-through” process, at carrying out hydrorefining of the feed, but also to obtain a conversion thereof of the order of 30% to 60% in general. In the second step of a two-step hydrocracking process, generally only the fraction of the feed not converted during the first step is treated. 
     Conventional hydrorefining catalysts generally contain at least one amorphous support and at least one hydrodehydrogenating element (generally at least one element from group VIB and non-noble group VIII, and usually at least one element from group VIE and at least one element from non-noble group VIII). 
     Examples of the matrices which may be used in the hydrorefining catalyst, alone or as a mixture, 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, carbon black, and aluminates. It is preferable to use matrices containing alumina, in any of the forms known to the person skilled in the art, and more preferably aluminas, for example gamma alumina. 
     The operating conditions for the hydrocracking step are adjusted in a manner such as to maximize the production of the desired cut while ensuring good operability of the hydrocracking unit. The operating conditions used in the reaction zone or zones are generally an average catalytic bed temperature (WABT) in the range 300° C. to 550° C., preferably in the range 350° C. to 500° C. 
     The pressure is generally in the range 5 to 35 MPa, preferably in the range 6 to 25 MPa. The liquid space velocity (flow rate of feed/volume of catalyst) is generally in the range 0.1 to 10 h −1 , preferably in the range 0.2 to 5 h −1 . 
     A quantity of hydrogen is introduced in a manner such that the volume ratio in m 3  of hydrogen per m 3  of hydrocarbon at the inlet to the hydrocracking step is in the range 300 to 2000 m 3 /m 3 , usually in the range 500 to 1800 m 3 /m 3 , preferably in the range 600 to 1500 m 3 /m 3 . 
     This reaction zone generally comprises at least one reactor comprising at least one fixed bed of 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 bifunctional in type, associating an acidic function with a hydrogenating function. The acidic function may be provided by supports with a large surface area (generally 150 to 800 m 2 /g) and with a superficial acidity, such as halogenated aluminas (especially chlorinated or fluorinated), combinations of boron and aluminium oxides, amorphous silica-aluminas termed 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 VIB of the periodic classification of the elements 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 acidic 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 VITA (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). 
     Fluidized Bed Catalytic Cracking 
     Fluidized bed catalytic cracking (FCC) is a well-known process which has evolved enormously since the 1930s (see Avidan A., Shinnar R., “Development of catalytic cracking technology: A lesson in chemical reactor design”, Ind. Eng. Chem. Res, 29, 931-942, 1990). This process is characterized by a reaction zone in which the cracking reactions occur over a zeolitic type catalyst, and a regeneration zone which can be used to eliminate the coke deposited on the catalyst during the cracking reactions by combustion. 
     The catalytic cracking unit of a refinery is principally intended for the production of bases for gasoline, i.e. cuts with a distillation interval in the range 35° C. to 250° C. 
     Gasoline production is ensured by cracking of the feed in the principal reactor termed a riser, because of the slender elongate shape of this reactor and its upflow mode of flow. When the flow is downwards in the principal reactor, it is known as a “downer”. 
     The conventional feed for a fluidized bed catalytic cracking unit for heavy cuts is generally constituted by a hydrocarbon or a mixture of hydrocarbons essentially (i.e. at least 80%) containing molecules with a boiling point of more than 340° C. This principal feed also contains limited quantities of metals (Ni+V), generally in a concentration of less than 50 ppm, preferably less than 20 ppm, and a hydrogen content which is generally more than 11% by weight, typically in the range 11.5% to 14.5%, and preferably in the range 11.8% to 14% by weight. 
     The Conradson carbon content (abbreviated to CCR) of the feed (defined by the ASTM standard D 482) provides an evaluation of the production of coke during catalytic cracking. The coke yield necessitates specific dimensioning for the unit in order to provide a thermal balance, which is a function of the Conradson carbon of the feed. 
     In the context of the invention, the fluidized bed catalytic cracking unit is supplied with at least a portion of the raffinate produced in the aromatics extraction unit, alone or as a mixture with other feeds. The catalytic performances of the catalytic cracking unit (consumption of catalysts, conversion, coke production) as well as the quantity and quality of the upgradable products are improved compared with a unit supplied with the deasphalted hydrocarbon cut leaving the deasphalting unit. As a consequence, the costs for operating the downstream units for the hydrotreatment of finished products are reduced as regards the quantities of contact and/or cycle times. 
     By sending all or a portion of the heavy residual fraction (FCC slurry) leaving the catalytic cracking unit to the aromatics extraction unit, a portion of this residual fraction, which is depleted in aromatics, may also be recycled to the inlet to the fluidized bed catalytic cracking unit FCC.
         When the catalytic cracking unit operates in upflow mode, the operating conditions are as follows:
           riser outlet temperature in the range 520° C. to 600° C.,   C/O ratio in the range 6 to 14, and preferably in the range 7 to 12,   dwell time in the range 1 to 10 s, and preferably in the range 2 to 6 s.   
           When the catalytic cracking unit operates in downflow mode, the operating conditions are as follows:
           reactor outlet temperature in the range 580° C. to 630° C.,   C/O ratio in the range 15 to 40, and preferably in the range 20 to 30,   dwell time in the range 0.1 to 1 s, and preferably in the range 0.2 to 0.7 s.   
               

     The C/O ratio is the ratio of the mass flow rate of catalyst moving in the unit to the mass flow rate of feed at the inlet to the unit. 
     The dwell time is defined as the volume of the riser (m 3 ) over the volume flow rate of feed (m 3 /s). 
     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 French application No. 16/55.845, filed June 23, 2016 are incorporated by reference herein. 
     EXAMPLE 
     The feed used in this example had the composition detailed in Table 1. It was a vacuum residue of the “Urals” type, and thus a vacuum residue obtained from crude oil originating from Russia. 
     
       
         
           
               
             
               
                 TABLE 1 
               
             
            
               
                   
               
               
                 Composition of the feed used (“Urals” type vacuum residue) 
               
            
           
           
               
               
               
               
            
               
                   
                 Property 
                 Unit 
                 Value 
               
               
                   
               
            
           
           
               
               
               
               
            
               
                   
                 Density 
                 — 
                 1.003 
               
               
                   
                 Viscosity at 100° C. 
                 cSt 
                 540 
               
               
                   
                 Conradson carbon 
                 % by wt 
                 15.0 
               
               
                   
                 C7 asphaltenes 
                 % by wt 
                 4.0 
               
               
                   
                 Nickel 
                 ppm by wt 
                 70 
               
               
                   
                 Vanadium 
                 ppm by wt 
                 200 
               
               
                   
                 Nitrogen 
                 ppm by wt 
                 5800 
               
               
                   
                 Sulphur 
                 % by wt 
                 2.7 
               
               
                   
                 540° C. −  cut* 
                 % by wt 
                 10.0 
               
               
                   
               
               
                 *Cut containing products with a boiling point below 540° C. 
               
            
           
         
       
     
     In this example, the feed was used in the process in accordance with the invention ( FIG. 2 ) with neither hydrocracking in  60  nor catalytic cracking in  70 , and thus also without adding vacuum distillate obtained by straight run crude oil distillation (SR VGO)  91  at the inlet to the hydrocracking and/or catalytic cracking steps. 
     However, in accordance with another variation, certain products obtained may subsequently be sent to a hydrocracking step, in particular the raffinate obtained from the extraction step, alone or as a mixture with other cuts obtained from the process in accordance with the invention. 
     The feed was treated in an ebullated bed H-OIL® reactor containing a commercial catalyst for ebullated bed residue hydroconversion (for example TEX2740 or TEX2910, sold by Criterion). The liquid products obtained from the reactor were fractionated by atmospheric distillation into a naphtha fraction (C5+-150° C.), a gas oil fraction (150-370° C.) and a residual fraction 370° C.+. 
     The residual fraction was fractionated by vacuum distillation into a gas fraction which was sent to the fuel pool, a vacuum distillate VGO (370° C.-540° C.) and a vacuum residual fraction 540° C.+. 
     The residual vacuum fraction underwent C4 solvent deasphalting with an extraction column. A deasphalted oil DAO and a pitch (residual asphalt) were obtained. 
     In the aromatics extraction section, the deasphalted oil DAO underwent a liquid/liquid extraction with furfural to provide a raffinate and an extract. Part of the extract was advantageously used as the diluent for the deep hydroconversion unit, and part was upgraded with the pitch. 
     The operating conditions for the H-OIL® conversion units which treated the residues, the solvent deasphalting unit (SDA) and the liquid/liquid aromatics extraction unit are summarized in Table 2. 
     
       
         
           
               
             
               
                 TABLE 2 
               
             
            
               
                   
               
               
                 Operating conditions for units 
               
            
           
           
               
               
               
               
               
            
               
                 Operating 
                   
                   
                   
                 Aromatic 
               
               
                 parameters 
                   
                 H-Oil ® 
                 SDA 
                 extraction 
               
               
                   
               
            
           
           
               
               
               
               
               
            
               
                 Liquid HSV 
                 h-1 
                 0.25 
                 — 
                 — 
               
               
                 Pressure 
                 MPa 
                 18 
                 4.5 
                 4.5 
               
               
                 Average catalytic 
                 ° C. 
                 416 
                 — 
                 — 
               
               
                 bed temperature* 
                   
                   
                   
                   
               
               
                 Extractor 
                   
                   
                 120 at head 
                 100 at head 
               
               
                 temperature 
                   
                   
                 90 at bottom 
                 70 at bottom 
               
               
                 H2/feed 
                 m3/m3 
                 400 
                 — 
                 — 
               
               
                 Solvent/feed 
                   
                   
                   
                   
               
               
                 Extractor inlet 
                 m3/m3 
                 — 
                 2/1 
                 1.8/1   
               
               
                 Extractor bottom 
                 m3/m3 
                   
                 4/1 
                 4/1 
               
               
                 Catalysts 
                   
                 TEX 2731 
                 — 
                 — 
               
               
                 Catalyst 
                   
                 NiMo/Al 2 O 3   
                 — 
                 — 
               
               
                 composition 
                   
                   
                   
                   
               
               
                 Solvent 
                   
                 — 
                 Butanes 
                 Furfural 
               
               
                   
               
            
           
         
       
     
     The solvent used in the SDA unit was a mixture of butanes containing 60% of nC4 and 40% of iC4. 
     The DAO yield of the deasphalting unit was pushed to 75% in order to maximize upgrading of the deasphalted oil. 
     Using aromatic diluent in the deep hydroconversion unit meant that the run length thereof could be improved very significantly, as can be seen in Table 3. 
     
       
         
           
               
             
               
                 TABLE 3 
               
             
            
               
                   
               
               
                 Impact of aromatic diluent originating from the extraction unit  
               
               
                 on the performances of the H-OIL ® hydroconversion unit 
               
            
           
           
               
               
               
               
            
               
                   
                   
                 Case 
                   
               
               
                   
                   
                 without 
                 Case with 
               
               
                   
                   
                 aromatic 
                 aromatic 
               
               
                   
                 Operating conditions 
                 diluent 
                 diluent 
               
               
                   
               
            
           
           
               
               
               
               
            
               
                   
                 Feed flow rate, t/h 
                 100 
                 100 
               
               
                   
                 Aromatic diluent flow rate, t/h 
                 0 
                 10 
               
               
                   
                 H-OIL RC  ® conversion, % by wt 
                 60 
                 60 
               
               
                   
                 H-OIL RC  ® run length 
                 2 years 
                 4 years 
               
               
                   
               
            
           
         
       
     
     Table 3 shows that the fact of using the extract obtained in the extraction unit as a diluent for the hydroconversion unit means that the run length for deep hydroconversion can be doubled. The associated gain in finished product production was a little over 3% (1.5 months over 4 years of run). 
     Using an aromatic diluent also means that an increased production of upgradable finished products can be obtained, as can be seen in Table 4 below. 
     
       
         
           
               
             
               
                 TABLE 4 
               
             
            
               
                   
               
               
                 Feed and products for hydroconversion unit with and without  
               
               
                 aromatic diluent, for a conversion of 60% by weight 
               
            
           
           
               
               
               
               
            
               
                   
                   
                 No 
                 With 
               
               
                   
                   
                 aromatic 
                 aromatic 
               
               
                   
                   
                 diluent 
                 diluent 
               
               
                   
               
            
           
           
               
               
               
               
            
               
                   
                 Hydroconversion feeds 
                   
                   
               
               
                   
                 Feed, t/h 
                 100 
                 100 
               
               
                   
                 Extract used as diluent, t/h 
                 0 
                 10 
               
               
                   
                 Hydrogen, t/h 
                 1.42 
                 1.56 
               
               
                   
                 Hydroconversion products 
                   
                   
               
               
                   
                 C1-C4, t/h 
                 2.94 
                 3.08 
               
               
                   
                 Naphtha, t/h 
                 7.45 
                 7.83 
               
               
                   
                 Gas oil (GO), t/h 
                 23.23 
                 24.39 
               
               
                   
                 Vacuum gas oil (VGO), t/h 
                 28.40 
                 29.82 
               
               
                   
                 Unconverted residue, t/h 
                 36.78 
                 43.78 
               
               
                   
               
            
           
         
       
     
     With a fixed conversion, using the extract as the aromatic diluent, the hydroconversion unit produces a supplemental 5% of upgradable products, i.e. 5% of naphtha, 5% of gas oil and 5% of vacuum gas oil VGO. 
     The properties of the raffinate and extract at the outlet from the extraction unit are compared with the deasphalted oil DAO in Table 5. 
     
       
         
           
               
             
               
                 TABLE 5 
               
             
            
               
                   
               
               
                 Properties of deasphalted oil (DAO) at inlet, of raffinate and  
               
               
                 of extract at outlet from extraction unit 
               
            
           
           
               
               
               
               
               
            
               
                 Property 
                 Unit 
                 DAO 
                 Raffinate 
                 Extract 
               
               
                   
               
            
           
           
               
               
               
               
               
            
               
                 Density 
                 — 
                    0.97 
                 0.880 
                    0.967 
               
               
                 Conradson carbon 
                 % by wt 
                   12.6 
                 3.0 
                   19 
               
               
                 C7 asphaltenes 
                 % by wt 
                    0.1 
                 &lt;0.05 
                    0.2 
               
               
                 Nickel + Vanadium 
                 ppm by wt 
                   20 
                 &lt;2 
                   40 
               
               
                 Nitrogen 
                 ppm by wt 
                 4 000 
                 900 
                 6 400 
               
               
                 Sulphur 
                 % by wt 
                    1.16 
                 0.57 
                    1.60 
               
               
                 Aromatics content 
                 % by wt 
                   47 
                 55 
                   41 
               
               
                 Resins content 
                 % by wt 
                   27 
                 0 
                   48 
               
               
                 Hydrogen 
                 % by wt 
                   11.1 
                 14.0 
                    9.0 
               
               
                   
               
            
           
         
       
     
     The density of the raffinate and the nitrogen and sulphur content of the raffinate were lower than those of the deasphalted oil DAO. Thus, the raffinate is a less refractory feed to be treated in a fixed bed hydrotreatment unit, for example, or in a hydrocracking unit. 
     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.