EP1310544B1 - Process for the conversion of heavy petroleum fractions for the production of a feedstock for a catalytic cracking process and low sulfur middle distillates - Google Patents

Abstract

Treatment of a charge of which at least 80% has a boiling point above 340 degrees C and contains at least 0.05% sulfur, to produce a gasoil of sulfur content less than 50 ppm by a 4 stage process involving mild hydrocracking, separation of gases form the effluent formed, hydrotreatment and separation of hydrogen with production of a gasoil of less than 50 ppm of sulfur. <??>The process comprises: <??>(a) mild hydrocracking in a catalytic fixed bed at 330-500 degrees C, 2-12 MPa, VVH of 0.1-10 h<-1> and in the presence of 100-5000 Nm<3> of H2/m<3> of charge, the net conversion to products boiling below 360 degrees C being 10-50 wt.%; <??>(b) the separation from the effluent of a gas containing H2, H2S and a fraction heavier than the gasoil; <??>(c) hydrotreatment by contact with a catalyst of a distillate cut obtained in (b) which includes a gasoil fraction at 300-500 degrees C, 2-12 MPa, a VVH of 0.1-10 h<-1> and in the presence of 200-5000 Nm<3> of H2/m<3> of charge; and <??>(d) the separation of H2, gases and a gasoil of S content less than 50 ppm weight. <??>An Independent claim is also included for the apparatus used for the above process.

Description

The present invention relates to a method and an installation for the treatment of heavy hydrocarbon feedstocks containing sulfur impurities. It relates to a process for converting at least in part such a hydrocarbon feedstock, for example a vacuum distillate obtained by the direct distillation of a crude oil, into diesel corresponding to the 2005 sulfur specifications, that is to say having less than 50 ppm sulfur, and a heavier product which can be advantageously used as a feedstock for catalytic cracking (such as catalytic cracking in a fluid bed).

FR-A-2791354 describes a process for converting heavy petroleum fractions comprising a step of hydroconversion into bubbling beds and a hydrotreating step.

Until 2000, the sulfur content allowed in diesel was 350 ppm. However, drastically more stringent values are expected for 2005 since this maximum content will be reduced to 50 ppm.

The applicant has therefore sought a method to achieve this goal. In doing so, he found that the goal was largely exceeded since levels lower than 20 ppm and even 10 ppm were generally obtained.

1. a) hydrocraquage doux en lit fixe en présence d'au moins un catalyseur à une température de 330 - 500°C, une pression d'au moins 2 MPa et inférieure à 12 MPa, une vitesse spatiale horaire de 0,1 h^-1 à 10 h^-1 et en présence de 100 - 5000 Nm3 d'hydrogène/m3 de charge, la conversion nette en produits bouillant en-dessous de 360°C étant de 10-50 % pds,
2. b) séparation à partir de l'effluent d'un gaz contenant de l'hydrogène, du sulfure d'hydrogène formé dans l'étape a) et d'une fraction plus lourde que le gazole, à l'issue de laquelle ledit gaz contenant de l'hydrogène est recyclé vers l'étape a),
3. c) hydrotraitement, par contact avec au moins un catalyseur, d'au moins une coupe distillat obtenue dans l'étape b) et incluant une fraction gazole, à une température de 300-500°C, une pression de 2-12 MPa, une vitesse spatiale horaire de 0,1 - 10 h^-1 et en présence de 200 - 5000 Nm3 d'hydrogène/m3 de charge,
4. d) d) séparation de l'hydrogène, des gaz et d'au moins une coupe gazole à teneur en soufre inférieure à 50 ppm pds, l'hydrogène séparé additionné de l'hydrogène issu de l'étape b) est recomprimé, puis recyclé vers l'étape a), procédé dans lequel la totalité de l'hydrogène d'appoint nécessaire au procédé est amené à l'étape c).

More specifically, the invention relates to a process for the treatment of petroleum feeds of which at least 80% by weight ends above 340 ° C., and containing at least 0.05% by weight of sulfur, in order to produce at least one diesel fraction with a content of in sulfur of at most 50 ppm by weight, said process comprising the following steps:

1. a) hydrocracking in a fixed bed in the presence of at least one catalyst at a temperature of 330 - 500 ° C, a pressure of at least 2 MPa and less than 12 MPa, a space velocity of 0.1 h ^-1 at 10 h ^-1 and in the presence of 100 - 5000 Nm 3 of hydrogen / m 3 of feed, the net conversion to products boiling below 360 ° C being 10-50% by weight,
2. b) separating from the effluent a hydrogen-containing gas, the hydrogen sulphide formed in step a) and a heavier fraction than diesel, at the end of which said gas containing hydrogen is recycled to step a),
3. c) hydrotreating, by contact with at least one catalyst, at least one distillate cut obtained in step b) and including a gas oil fraction, at a temperature of 300-500 ° C, a pressure of 2-12 MPa, a space velocity of 0.1 - 10 h ^-1 and in the presence of 200 - 5000 Nm 3 of hydrogen / m3 of feed,
4. d) d) separation of hydrogen, gases and at least one gasoil fraction with a sulfur content of less than 50 ppm by weight, the separated hydrogen added with the hydrogen resulting from stage b) is recompressed, then recycled to step a), process in which all the makeup hydrogen necessary for the process is fed to step c).

The treated feeds are heavy, i.e., 80% wt boiling above 340 ° C. Their initial boiling point is usually at least 340 ° C, often at least 370 ° C or above 400 ° C. Very advantageously, the process makes it possible to treat feeds having a final boiling point of at least 450 ° C. and which may even exceed 650 ° C.

The sulfur content is at least 0.05 wt%, often at least 1% and very often at least 2% or even at least 2.5 wt%. Charges with 3% or more sulfur are well suited in this process.

The fillers which can be treated in the context of the present invention are straight-run vacuum distillates, vacuum distillates resulting from conversion processes such as, for example, those resulting from coking, from fixed-bed hydroconversion ( such as those resulting from the HYVAHL® processes of heavy processing developed by the Applicant) or ebullated bed hydrotreating processes (such as those resulting from H-OIL® processes), or solvent-deasphalted oils. (for example propane, butane, or pentane) from the deasphalting of residue under a direct distillation vacuum, or residues from the HYVAHL® and H-OIL® processes. The fillers can also be formed by mixing these various fractions. They may also contain heavy diesel and gas oil cuts from catalytic cracking generally having a distillation range of about 150 ° C to about 370 ° C. They may also contain aromatic extracts and paraffins obtained as part of the manufacture of lubricating oils. According to the present invention, the fillers which are treated are preferably vacuum distillates.

Step a) - The charge as described above is treated in step a) by mild hydrocracking.

It is usually carried out under an absolute pressure of 2 to 12 MPa, often 2 to 10 MPa and most often 4 to 9 MPa or 3 to 7 MPa at a temperature of about 300 to about 500 ° C and often of about 350 to about 450 ° C. The hourly space velocity (VVH) and the hydrogen partial pressure are chosen according to the characteristics of the product to be treated and the desired conversion. Most often the VVH is in a range from about 0.1 h ^-1 to 10 h ^-1 and preferably about 0.2 h ^-1 to about 5 h ^-1 . The total quantity of hydrogen mixed with the feed (chemical consumption H ₂ + recycling) and therefore entering the zone in which step a) is carried out is usually from about 100 to about 5000 normal cubic meters (Nm3) per cubic meter (m3 ) of liquid charge and most often from about 100 to about 2000 Nm3 / m3, generally it is at least 200 Nm3 / m3 and preferably about 200 to about 1500 Nm3 / 3.

The net conversion to products boiling below 360 ° C. is generally from 10 to 50% by weight, advantageously from 15 to 45%.
The partial pressure of H ₂ S at the outlet of step a) is generally 0.1-0.4 MPa, advantageously it is maintained between 0.15-0.3 MPa and preferably between 0.15-0.15. , 25 MPa to improve hydrodesulfurization.

It is possible to use a conventional hydroconversion catalyst comprising, on an amorphous support, at least one metal or metal compound having a hydro-dehydrogenating function.

This catalyst may be a catalyst comprising Group VIII metals in the catalyst, for example nickel and / or cobalt, most often in combination with at least one Group VIB metal, for example molybdenum and / or tungsten. For example, a catalyst comprising from 0.5 to 10% by weight of nickel and preferably from 1 to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1 to 30% by weight of molybdenum, preferably 5 to 20% by weight of molybdenum (expressed as MoO3 molybdenum oxide) on an amorphous mineral support.

The total content of Group VI and VIII metal oxides in the catalyst is often from about 5 to about 40% by weight and generally from about 7 to 30% by weight and preferably the weight ratio of metal oxide to metal Group VIII (or metals) on metal (or metals) of Group VIII is generally from about 20 to about 1 and most often from about 10 to about 2.

The support will for example be chosen from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also contain other compounds and for example oxides chosen from the group formed by boron oxide, zirconia, titanium oxide, phosphoric anhydride. Most often a support of alumina, and better alumina n or γ is used.

The catalyst may also contain an element such as phosphorus and / or boron. This element may have been introduced into the matrix or preferably deposited on the support. It is also possible to deposit silicon on the support, alone or with phosphorus and / or boron. Preferred catalysts contain silicon deposited on a support (such as alumina) optionally with P and / or B also deposited and also containing at least one metal of GVIII Ni, Co and at least one metal of GVIB (Mo, W). The concentration of said element is usually less than about 20% by weight (calculated oxide) and most often less than about 10% and is usually at least 0.001% by weight. The concentration of boron dioxide B ₂ O ₃ is usually from about 0 to about 10% by weight.

Another catalyst comprises at least one Group VIII metal and at least one Group VIB metal and a silica-alumina.

Another type of usable catalyst is a catalyst containing at least one matrix, at least one zeolite Y and at least one hydro-dehydrogenating metal. The matrices, metals, additional elements previously described may also be included in the composition of this catalyst.
Y advantageous zeolites are described in the applications of WO-00/71641 , EP-911,077 as well as US 4738940 and 4738941 .

The mild hydrocracking (step a)) is carried out with at least one fixed bed of at least one catalyst and a hydrocracked effluent is produced.

Step b) wherein said hydrocracked effluent is subjected at least in part, and preferably in whole, to one or more separations.

The purpose of this step is to separate the gases from the liquid, and in particular to recover hydrogen and most of the hydrogen sulfide H ₂ S formed in step a), and then obtain a liquid effluent free of H ₂ S dissolved.

When separating H ₂ S from the liquid, a part of naphtha can be separated. This part is then stabilized (H ₂ S removal).
The liquid effluent devoid of H ₂ S and optionally added stabilized naphtha is distilled to obtain at least one distillate cut including a gas oil fraction, and at least a heavier fraction than the diesel fuel.

The distillate cut may be a diesel cut or a diesel fuel cut mixed with naphtha. It feeds step c).

The heavier liquid fraction than the diesel-type fraction may optionally be sent to a catalytic cracking process in which it is advantageously treated under conditions making it possible to produce a gaseous fraction, a gasoline fraction, a diesel fraction and a heavier fraction. that the diesel fraction often referred to by those skilled in the art slurry fraction.

In other cases, this heavier liquid fraction than the diesel fraction can be used as a low sulfur industrial fuel or as a thermal cracking feedstock.

When the naphtha is not sent to the mixture with the diesel fuel in step c), it is distilled. The naphtha fraction obtained can advantageously be separated into heavy gasoline, which will preferably be a feedstock for a reforming process, and light gasoline which preferably will be subjected to a paraffin isomerization process.

At the end of step b), the diesel fuel cutter most often has a sulfur content of between 100 and 500 ppm by weight and the gasoline cutter most often has a sulfur content of at most 200 ppm by weight. The diesel cut does not meet the 2005 specifications for sulfur. The other characteristics of diesel are also at a low level; for example, the cetane is of the order of 45 and the aromatic content is greater than 20% by weight.

On distillation, the conditions are generally chosen such that the initial boiling point of the heavy fraction is from about 340 ° C to about 400 ° C and preferably from about 350 ° C to about 380 ° C. for example, about 360 ° C.

For naphtha, the boiling point is between about 120 ° C and 180 ° C.

The diesel is between the naphtha and the heavy fraction.

The cutting points given here are indicative but the operator will choose the cutting point according to the quality and quantity of the desired products, as is generally done.

Step c) wherein at least a portion, and preferably all, of the distillate cut undergoes hydrotreatment to reduce the sulfur content below 50 ppm by weight, and most often below 10 ppm.

At said distillate cut, it is possible to add a cut produced outside the process according to the invention, and which is not normally incorporated directly into the diesel fuel pool. This hydrocarbon fraction may for example be chosen from the group formed by LCOs (light cycle oil from catalytic cracking in a fluidized bed).

It is usually carried out under an absolute pressure of about 2 to 12 MPa, often about 2 to 10 MPa and most often about 4 to 9 MPa; it is also possible to work under 3 to 7 MPa. The temperature in this step is usually from about 300 to about 500 ° C, often from about 300 ° C to about 450 ° C and very often from about 350 to about 420 ° C. This temperature is usually adjusted according to the desired level of hydrodesulfurization and / or saturation of the aromatics and must be compatible with the desired cycle time. The hourly space velocity (VVH) and the hydrogen partial pressure are chosen according to the characteristics of the product to be treated and the desired conversion.

Most often the VVH is in a range from about 0.1 h ^-1 to about 10 h ^-1 and preferably 0.1 h ^-1 - 5 h ^-1 and preferably from about 0.2 h ^-1 to about 2 h ^{- 1} .

The total amount of hydrogen mixed with the feedstock is usually about 200 to about 5000 normal cubic meters (Nm ³ ) per cubic meter (m ³ ) of liquid feed and most often about 250 to 2000 Nm ³ / m ³ and preferably from about 300 to 1500 Nm ³ / m ³ .

The same operation is carried out with a partial pressure of reduced hydrogen sulfide compatible with the stability of the sulfurized catalysts. In the preferred case of the present invention, the partial pressure of hydrogen sulfide is preferably less than 0.05 MPa, preferably 0.03 MPa, more preferably 0.01 MPa.

In the hydrodesulfurization zone, the ideal catalyst must have a high hydrogenating power so as to achieve a deep refining of the products and to obtain a significant lowering of sulfur. In the preferred embodiment, the hydrotreatment zone operates at a relatively low temperature, which is in the direction of a deep hydrogenation, hence an improvement in the aromatic content of the product and its cetane and a limitation of the product. coking. It is not within the scope of the present invention to use in the hydrotreating zone simultaneously or successively a single catalyst or several different catalysts. Usually this step is carried out industrially in one or more reactors with one or more catalytic beds and downflow of liquid.

In the hydrotreating zone at least one fixed bed of hydrotreatment catalyst comprising a hydrodehydrogenating function and an amorphous support is used. Preferably, a catalyst is used, the support of which is for example chosen from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also contain other compounds and for example oxides chosen from the group formed by boron oxide, zirconia, titanium oxide and phosphoric anhydride. Most often a support of alumina and better alumina n or γ is used.

The hydrogenating function is provided by at least one Group VIII metal and / or Group VIB.

In an advantageous case, the total content of metal oxides of groups VI and VIII is often from about 5 to about 40% by weight and generally from about 7 to 30% by weight and the weight ratio expressed as metal oxide between Group VI metal (metals) on Group VIII metal (or metals) is generally from about 20 to about 1 and most often from about 10 to about 2.

The ideal catalyst must have a high hydrogenating power so as to achieve a deep refining of the products and to obtain a significant lowering of sulfur. This catalyst may be a catalyst comprising Group VIII metals, for example nickel and / or cobalt, most often in combination with at least one Group VIB metal, for example molybdenum and / or tungsten. Preferably a NiMo catalyst will be used. For gas oils difficult to hydrotreat and for a very high rate of hydrodesulfurization, it is known to those skilled in the art that the desulfurization of a NiMo catalyst is greater than that of a CoMo catalyst because the first shows a hydrogenating function more important than the second. For example, a catalyst comprising from 0.5 to 10% by weight of nickel and preferably from 1 to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1 to 30% by weight of molybdenum and preferably from 1 to 30% by weight of molybdenum may be used. at 20% by weight of molybdenum (expressed as molybdenum oxide (MoO ₃ ) on an amorphous mineral support.

The catalyst may also contain an element such as phosphorus and / or boron. This element may have been introduced into the matrix or may have been deposited on the support. It is also possible to deposit silicon on the support, alone or with phosphorus and / or boron.

The concentration of said element is usually less than about 20% by weight (calculated oxide) and most often less than about 10% by weight and is usually at least 0.001% by weight. The concentration of boron trioxide B ₂ O ₃ is usually from about 0 to about 10% by weight.

Preferred catalysts contain silicon deposited on a support (such as alumina), optionally with P and / or B also deposited, and also containing at least one metal of GVIII (Ni, Co) and at least one metal of GVIB (W, MB).

In the process according to the invention, the gasolines and gas oils resulting from conversion processes, such as, for example, mild hydrocracking, are very resistant to hydrotreating if they are compared with gas oils directly derived from the atmospheric distillation of crudes.

In order to obtain very low sulfur contents, the critical point is the conversion of the most refractory species, particularly the di- and trialkylated or more dibenzothiophenes for which the access of the sulfur atom to the catalyst is limited by the alkyl groups. For this family of compounds, the route of the hydrogenation of an aromatic ring before desulfurization by breaking the Csp3-S bond is faster than the direct desulfurization by breaking the Csp2-S bond.

Conversion gas oils therefore require very severe operating conditions to achieve future sulfur specifications. If it is desired to hydrotreat these conversion gas oils under operating conditions making it possible to maintain moderate investments with a reasonable cycle time of the hydrotreatment catalyst, optimization of the integration of the process equipment is necessary.

We have discovered that it is possible to obtain good quality gas oils while minimizing the investments by maximizing the hydrogen partial pressure in the second stage.

To this end, according to the invention, additional hydrogen is introduced into step c) of hydrotreatment.

Preferably, the amount of additional hydrogen introduced in this step c) is greater than the chemical consumption of hydrogen necessary to obtain the performances set under the operating conditions set for this step c).

This means that this quantity is greater than that required for the desired level of hydrogenation of the hydrogenatable compounds.

If a hydrogen material balance is made between the inlet corresponding to the hydrocarbon feedstock and the outlet corresponding to the liquid and gaseous effluents excluding separated hydrogen, the quantity of additional hydrogen is at least equal to the difference in the material balance, the difference found corresponds approximately to the chemical consumption of hydrogen.
An appropriate means for measuring the hydrogen content in the feedstock or the liquid effluent is the ¹ H-NMR measurement. For the gaseous effluent, the chromatographic analysis is suitable.

All the makeup hydrogen necessary for the process is introduced in step c).
Therefore, the quantity supplied will also take into account the chemical consumption of hydrogen on step a) so as to bring the hydrogen necessary for the hydrogenation sought in step a) also.

• au niveau de l'étape c) uniquement.

Thus, in the process, the makeup hydrogen is introduced:

• in step c) only.

Another consequence is that it is possible to optimize the hydrogen filling in step c) according to the refractory level of the gas oils to be treated.

The invention thus makes it possible to substantially improve the performance of the hydrotreatment catalyst and in particular the hydrodesulfurization for given temperature and total pressure conditions and which correspond to industrially practicable values.

Indeed, it makes it possible to maximize the hydrogen partial pressure, therefore the performance, on step c), while maintaining a total pressure of steps a) and c) (and therefore their investment cost) almost identical.

For highly sulfur-containing fillers of step a) (for example having at least 1 wt.% Sulfur or at least 2%) which produce refractory and sulfur-containing conversion gas oils, it has thus become possible to obtain middle distillates. good qualities especially with a low sulfur content under conditions including relatively low pressure and thus to limit the cost of necessary investments.

Step d) final separation on at least part, and preferably all of the hydrotreated effluent from step c).

The hydrogen is separated from the effluent. It contains small amounts of hydrogen sulfide and usually does not require treatment.

The hydrogen sulphide is also separated from the liquid effluent and thus a gas oil is obtained at most 50 ppm by weight of sulfur, and most often at less than 10 ppm by weight of sulfur.
Naphtha is also obtained in general.

Hydrogen treatment and recycling

The hydrogen-containing gas which has been separated in step b) is, if necessary, at least partly treated to reduce its H ₂ S content (preferably by washing with at least one amine) before recycling it into step a) and possibly in step c).

The recycle gas preferably contains an amount of H 2 S greater than 0% and up to 1% mol. Advantageously, this amount is at least 15 ppm, preferably at least 0.1%, or even at least 0.2% mol.

Thus, for example, at least a portion of the gaseous fraction can be sent to an amine wash section where the H ₂ S is removed in its entirety; the other part can pass the amine wash section and be sent directly to recycling after compression.

The presence of H ₂ S is useful for maintaining the catalysts in the sulfurized state in steps a) and c), but an excess of H ₂ S could reduce hydrodesulfurization.

With the hydrogen from step b) optionally purified, is added the hydrogen separated in step d). The mixture is re-compressed and then recycled to step a) and possibly to step c).

Indeed, the recycle to step c) may not be necessary, when all the additional hydrogen is introduced in step c).

It is advantageous to introduce the recycle hydrogen with the feed entering step a) and / or in the form of a quench between the catalyst beds.

The gas oil obtained has a sulfur content of less than 50 ppm by weight, generally less than 20 ppm, and most often less than 10 ppm.
In addition, the cetane has been improved from 1 to 12 points, generally from 1 to 7, or from 1 to 5 points with respect to the diesel entering hydrotreating.
Its total amount of aromatics has also been reduced by at least 10%, the reduction can even go up to 90%.
The amount of polyaromatics in the final gas oil is at most 11% wt.

Installation

1. a) une zone (I) d'hydrocraquage doux contenant au moins un lit fixe de catalyseur d'hydrocraquage et munie d'une conduite (1) pour l'introduction de la charge à traiter, d'une conduite (2) pour la sortie de l'effluent hydrocraqué, et d'une conduite (29) pour l'introduction de l'hydrogène,
2. b) une zone (II) de séparation incluant au moins un séparateur (3) (6) pour séparer le gaz riche en hydrogène par la conduite (4), pour séparer dans la conduite (7) le sulfure d'hydrogène et obtenir dans la conduite (8) une fraction liquide, et incluant également une colonne de distillation (9) pour séparer au moins une coupe distillat incluant une fraction gazole dans la conduite (11) et une fraction lourde dans la conduite (10),
3. c) une zone (III) d'hydrotraitement contenant au moins un lit fixe de catalyseur d'hydrotraitement pour traiter une fraction gazole obtenue à l'issue de l'étape b), munie d'une conduite pour l'introduction de la totalité de l'hydrogène et d'une conduite (12) pour la sortie de l'effluent hydrotraité.
4. d) une zone (IV) de séparation incluant au moins un séparateur (13) (16) pour séparer l'hydrogène par la conduite (14), pour séparer dans la conduite (17) le sulfure d'hydrogène et par la conduite (18) un gazole ayant une teneur en soufre inférieure à 50 ppm.

l'installation comportant une zone (25) de traitement pour abaisser la teneur en H2S du gaz contenant de l'hydrogène de la conduite (4) un compresseur 27) recomprimant le gaz issu de la zone (25) et l'hydrogène amené par la conduite (14), et une conduite (29) de recyclage de l'hydrogène dans la zone (I).The invention also relates to a petroleum feed treatment plant of which at least 80 wt% boils above 340 ° C and contains at least 0.05% sulfur, comprising:

1. a) a zone (I) of mild hydrocracking containing at least one fixed bed of hydrocracking catalyst and provided with a pipe (1) for introducing the charge to be treated, a pipe (2) for the leaving the hydrocracked effluent, and a pipe (29) for the introduction of hydrogen,
2. b) a separating zone (II) including at least one separator (3) (6) for separating the hydrogen-rich gas from the pipe (4), for separating the hydrogen sulfide in the pipe (7) and the pipe (8) a liquid fraction, and also including a distillation column (9) for separating at least one distillate cut including a gas oil fraction in the pipe (11) and a heavy fraction in the pipe (10),
3. c) a hydrotreatment zone (III) containing at least one fixed bed of hydrotreatment catalyst for treating a gas oil fraction obtained at the end of step b), provided with a pipe for the introduction of the totality of hydrogen and a pipe (12) for the outlet of the hydrotreated effluent.
4. d) a separating zone (IV) including at least one separator (13) (16) for separating the hydrogen via the pipe (14), for separating hydrogen sulfide in the pipe (17) and the pipe ( 18) a gas oil having a sulfur content of less than 50 ppm.

the plant comprising a treatment zone (25) for lowering the H2S content of the hydrogen-containing gas of the pipe (4) a compressor 27) recompressing the gas from the zone (25) and the hydrogen supplied by the pipe (14), and a pipe (29) for recycling hydrogen in zone (I).

It will be better understood from Figure 1 which illustrates a preferred embodiment of the invention.

The feedstock to be treated (as defined above) enters a line (1) in a soft hydrocracking zone (I) which contains at least one fixed bed of a hydrocracking catalyst. The hydrocracked effluent obtained in line (2) is sent to separation zone (II).

The hydrocracked effluent first passes into a separator (3) separating on the one hand a hydrogen-containing gas (gaseous phase) in the pipe (4) and on the other hand a liquid effluent in the pipe (5) . A hot separator can be used followed by a cold separator (preferred) or a cold separator only.

The liquid effluent is sent to a separator (6), which is preferably a steam stripper, to separate the hydrogen sulfide from the hydrocarbon effluent. At the same time, at least a portion of the naphtha fraction can be separated with the hydrogen sulfide. The hydrogen sulfide with said naphtha exits the line (7) while the hydrocarbon effluent is obtained in the line (8).

The hydrocarbon effluent then passes into a distillation column (9) and is separated at least one distillate cut including a gas oil fraction and found in the pipe (11), it is also separated a heavier fraction than the diesel fuel and found in the pipe (10).

In general the naphtha separated at the separator (6) is stabilized (H ₂ S removed). In an advantageous arrangement, the stabilized naphtha is injected into the effluent entering the column (9).

At the column (9), the naphtha can be separated in an additional pipe not shown in FIG.

According to Figure 1, the column (9) separates a gas oil fraction mixed with naphtha, in the pipe (11). The fraction of the pipe (10) is advantageously sent to the zone (V) of catalytic cracking.

The naphtha obtained separately, optionally added naphtha separated in the zone (IV) is advantageously separated into gasoline heavy and light, the heavy gasoline being sent to a reforming zone and the light gasoline in an area where isomerization is carried out paraffins.

In FIG. 1, the dividing zone (II) formed of separators (3) (6) and column (9) is schematized in broken lines.

The distillate cut is then sent (alone or optionally added a cut) naphtha and / or diesel outside the process) in a hydrotreating zone (III) provided with at least one fixed bed of a hydrotreatment catalyst.

The hydrotreated effluent obtained exits via the pipe (12) to be sent into the separation zone (IV) schematized in dashed lines in FIG.
It comprises here a separator (13), preferably a cold separator, wherein are separated a gaseous phase exiting through the pipe (14) and a liquid phase exiting through the pipe (15).

The liquid phase is sent to a separator (16) preferably a stripper, to remove the hydrogen sulfide exiting in the pipe (17), usually mixed with the naphtha. A diesel fraction is withdrawn through the line (18), which fraction meets the sulfur specifications, ie less than 50 ppm wt sulfur is generally less than 10 ppm. The H ₂ S-naphtha mixture is then optionally treated to recover the purified naphtha fraction.

The method and the installation according to the invention also advantageously comprise a hydrogen recycling loop for the 2 zones (I) and (II) and which is now described starting from FIG.

The gas containing hydrogen (gaseous phase of the pipe (4) separated in the zone (II)) is treated to reduce its sulfur content and possibly eliminate the hydrocarbon compounds that may have passed during the separation.

Advantageously and according to FIG. 1, the gaseous phase of the pipe (4) is sent into an air cooler (19) after having been washed by the water injected by the pipe (20) and partly condensed by a hydrocarbon fraction sent by the line (21). The effluent of the dry cooler is sent to a zone (22) of separation where are separated the water which is withdrawn by the pipe (23), a hydrocarbon fraction by the pipe (21) and a gaseous phase by the pipe ( 24).
Part of the hydrocarbon fraction of the pipe (21) is sent to the separation zone (II), and advantageously to the pipe (5).

There is described here a particular embodiment for separating the hydrocarbon compounds entrained, any other mode known to those skilled in the art.

The gaseous phase obtained in the pipe (24) freed from the hydrocarbon compounds is, if necessary, sent to a treatment unit (25) to reduce the sulfur content.

Advantageously, it is a treatment with at least one amine.

In some cases, only a portion of the gas phase needs to be treated. In other cases, all of it will have to be treated, which is illustrated in FIG. 1, where part of the gaseous phase in the pipe (26) does not pass into the unit (25).

The hydrogen-containing gas thus optionally purified is then re-compressed in the compressor (27).

Before compression, the separated hydrogen is added to the line (14).

The compressed mixture is then recycled in part to the hydrotreatment zone (III) (Step c) and partly to the mild hydrocracking zone (I) (step a) by the lines (28) and (29) respectively.

In FIG. 1, it is shown that the recycling hydrogen is introduced at the inlet of the reaction zones with the liquid charge. Part of the hydrogen can also be introduced between the catalytic beds in order to control the inlet temperature of the bed ("quench").

In FIG. 1, all of the makeup hydrogen is introduced via line (30) at zone (II).

As shown in FIG. 1, a preferred mode for bringing hydrogen to zone (III) is to provide a pipe for recycling and a pipe for top-up.

The invention thus described has many advantages. In addition to those already described, it may be noted that in the preferred embodiment where the pressures are identical for the steps a) and c), because of the unique gas recirculation system it is allowed to use only one recycle compressor for both reaction zones thus further reducing investment.

The invention operates at moderate pressures, investments are reduced.

In addition, a high quality feedstock is produced for catalytic cracking (low sulfur and nitrogen content, moderate hydrogen enrichment).

Examples

These examples were obtained in a pilot unit that differs from an industrial unit in that the fluids are up-flow mode in the pilot unit. It has been shown elsewhere that this mode of operation in a pilot unit gives results that are equivalent to those of an industrial unit operating in tickle bed mode.

Example 1 (addition of H2 at the inlet of the hydrocracking MHDC and at the entrance of the HDT).

The feedstock is a vacuum distillate containing 3% wt sulfur. The conversion of the distillation range in the hydrocracking zone is 35% of the 360 ° C + fraction. After separation, a gas oil fraction is obtained containing 250 ppm by weight of sulfur. This diesel cut is hydrotreated in a dedicated reactor.

The process is carried out according to the scheme of FIG. 1 except that the makeup of H2 is dedicated to each hydrocracking and hydrotreatment unit. The recycling of the hydrogen-rich gas is common to both units with an amine wash of the gas separated in step b).

• Pression partielle hydrogène (PpH2) = 54 bar
• Vitesse spatiale (VVH) = 0.62
• Température de réaction (WABT) = 350°C

The hydrogen purity of the recycle gas is 77.1 mol%. The hydrogen partial pressure is 56.1 bar at the outlet of the hydrocracking section and 54.0 bar at the outlet of the hydrotreatment section. The operating conditions used to obtain a gas oil cut having about 14 ppm of sulfur are:

• Hydrogen partial pressure (PpH2) = 54 bar
• Space velocity (VVH) = 0.62
• Reaction temperature (WABT) = 350 ° C

Example 2 (H2 supplement only at the HDT inlet corresponding to the total H2 consumption of the MHDC + HDT section).

• Pression partielle hydrogène (PpH2) = 66 bar
• Vitesse spatiale (VVH) = 0.62
• Température de réaction (WABT) = 350°C

With the same charge, the same operating conditions in hydrocracking, the same treatment of hydrogen gas, the hydrogen purity of the recycle gas is 78.8 mol%. The hydrogen partial pressure is then 56.3 bar at the outlet of the hydrocracking section and 66.2 bar at the outlet of the hydrotreatment section for a total pressure at the intake of the recycle compressor increased by 2.5 bar. The operating conditions used to obtain a gasoil fraction having less than 10 ppm of sulfur are:

• Hydrogen partial pressure (PpH2) = 66 bar
• Space velocity (VVH) = 0.62
• Reaction temperature (WABT) = 350 ° C

This shows that the injection of all the extra hydrogen in the HDT reactor as described in the preferred embodiment of the present invention makes it possible to very substantially increase the hydrogen partial pressure favorable to very strong desulfurization. . This aspect of the present invention therefore makes it possible either to operate with a load flow rate at the larger hydrotreatment section as shown in this example, or to work with a lower temperature favorable to a longer life of the catalyst. or to obtain a greater desulphurization by keeping the flow rate and the temperature of Example 1.

Claims (16)

1. Process for treatment of petroleum feedstocks of which at least 80% by weight boils above 340°C and which contains at least 0.05% by weight of sulfur for producing at least one gas oil fraction with a sulfur content of at most 50 ppm by weight, whereby said process comprises the following stages:

   a) Mild hydrocracking in a fixed bed in the presence of at least one catalyst at a temperature of 330-500°C, a pressure of at least 2 MPa and less than 12 MPa, an hourly space velocity of 0.1 h^-1 to 10 h^-1 and in the presence of 100-5000 Nm3 of hydrogen/m3 of feedstock, whereby the net conversion of products boiling below 360°C is 10-50% by weight,

   b) Separation from the effluent of a gas that contains hydrogen, hydrogen sulfide formed in stage a) and a heavier fraction than the gas oil, after which said gas that contains hydrogen is recycled in stage a),

   c) Hydrotreatment, by contact with at least one catalyst, of at least one distillate fraction that is obtained in stage b) and that includes a gas oil fraction, at a temperature of 300-500°C, a pressure of 2-12 MPa, an hourly space velocity of 0.1-10 h^-1 and in the presence of 200-5000 Nm3 of hydrogen/m3 of feedstock,

   d) Separation of hydrogen, gases and at least one gas oil fraction with a sulfur content of less than 50 ppm by weight, the separated hydrogen to which hydrogen obtained from stage b) is added is re-compressed and then recycled to stage a)

   and process in which all of the make-up hydrogen that is necessary to the process is brought to stage c).
2. Process according to claim 1, in which the amount of make-up hydrogen that is introduced in stage c) is greater than the chemical consumption of hydrogen that is necessary for obtaining the performance levels that are fixed under the operating conditions that are fixed for stage c).
3. Process according to one of the preceding claims, in which said heavy fraction is sent to a catalytic cracking process.
4. Process according to one of the preceding claims, in which the partial H₂S pressure at the outlet of stage a) is 0.1-0.4 MPa, and at the outlet of stage c), it is less than 0.05 MPa.
5. Process according to one of the preceding claims, in which in stage b), the naphtha is also separated, and a gas oil fraction passes into stage c).
6. Process according to one of claims 1 to 4, in which a gas oil fraction that is mixed with naphtha passes into stage c).
7. Process according to one of the preceding claims, in which at least a portion of the gas that contains hydrogen and that is separated in stage b) is treated to reduce its hydrogen sulfide content and then is recycled to stage a), whereby the recycling gas contains at most 1 mol % of hydrogen sulfide.
8. Process according to claim 7, in which the treatment is a washing with at least one amine.
9. Process according to one of claims 7 à 8, in which the hydrogen is also recycled in stage c).
10. Process according to one of the preceding claims, in which the fractions that are separated in stages b) and d) are separated into heavy and light gasolines, whereby the heavy gasoline is sent to reforming, and the light gasoline is sent to isomerization of the paraffins.
11. Installation for treatment of petroleum feedstocks of which at least 80% by weight boils above 340°C and which contains at least 0.05% of sulfur, comprising:

    a) A mild hydrocracking zone (I) that contains at least one fixed bed of hydrocracking catalyst and provided with a pipe (1) for introducing the feedstock to be treated, a pipe (2) for the output of the hydrocracked effluent, and a pipe (29) for the introduction of the hydrogen,

    b) a zone (II) for separation including at least one separator (3) (6) for separating the hydrogen-rich gas via pipe (4), for separating the hydrogen sulfide in pipe (7) and obtaining a liquid fraction in pipe (8), and also including a distillation column (9) for separating at least one distillate fraction that includes a gas oil fraction in pipe (11) and a heavy fraction in pipe (10),

    c) a hydrotreatment zone (III) that contains at least one fixed bed of hydrotreatment catalyst for treating a gas oil fraction that is obtained at the end of stage b), provided with a pipe for introducing all of the hydrogen and a pipe (12) for the output of hydrotreated effluent,

    d) a separation zone (IV) that includes at least one separator (13) (16) for separating hydrogen via pipe (14), for separating the hydrogen sulfide in pipe (17) and for separating a gas oil that has a sulfur content of less than 50 ppm via pipe (18),

    the installation comprising a treatment zone (25) for reducing the H₂S content of the gas that contains hydrogen from pipe (4), a compressor (27) that recompresses the gas that is obtained from zone (25) and the hydrogen that is brought via pipe (14), and a pipe (29) for recycling the hydrogen in zone (I).
12. Installation according to claim 11 that also comprises a catalytic cracking zone (V) in which said heavy fraction is sent via pipe (10).
13. Installation according to one of claims 11 or 12 in which zone (II) comprises a gas/liquid separator (3) for separating a gas that contains hydrogen via pipe (4), then a separator (6) that admits the effluent that is obtained from separator (3) for separating hydrogen sulfide and naphtha via pipe (7) and for obtaining a liquid fraction in pipe (8), whereby said zone (II) also comprises a distillation column (9) for separating a naphtha + gas oil fraction via pipe (11) and a heavier fraction than the gas oil via pipe (10), and pipe (10) is connected to a catalytic cracking zone (V).
14. Installation according to one of claims 11 to 13, in which zone (II) comprises a gas/liquid separator (3) for separating a gas that contains hydrogen via pipe (4), then a separator (6) that admits the effluent that is obtained from separator (3) for separating hydrogen sulfide and naphtha via pipe (7) and for obtaining a liquid fraction in pipe (8); a stabilizer for removing the hydrogen sulfide is placed in pipe (7), whereby the purified naphtha is sent into pipe (8), and whereby said zone (II) also comprises a distillation column (9) for separating the naphtha, a heavier fraction than the gas oil via pipe (10), and a gas oil fraction via pipe (11), whereby pipe (10) is connected to catalytic cracking zone (V).
15. Installation according to claim 11 to 14 that is also provided with a pipe (28) for recycling the hydrogen in zone (III).
16. Installation according to one of claims 11 to 15 that is also provided with a pipe (30) that brings the make-up hydrogen into zone (III).

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