RU2660426C2 - Method of separate treatment of petroleum feedstock for production of fuel oil with low sulphur content - Google Patents

Abstract

FIELD: chemistry.

SUBSTANCE: method of treating hydrocarbon feedstock in which the sulphur content is at least 0.5% by weight, the initial boiling point is at least 340°C, and the final boiling point is at least 440°C, enables to produce at least one liquid hydrocarbon fraction with sulphur content of less than or equal to 0.5% by weight, and comprises the following successive steps a) fixed-bed hydrotreatment, where hydrocarbon feedstock and hydrogen are brought into contact on at least one hydrotreatment catalyst, b) separating the stream obtained from the outlet of the hydrotreating step (a) into at least one light fraction and at least one heavy fraction, c) hydroconversion of at least a portion of the heavy fraction of the stream coming from step (b) in at least one reactor in a fluidised bed state containing a maintained catalyst , and d) separating the stream from step (c) to produce at least one gas fraction and at least one liquid hydrocarbon fraction, where the hydrotreatment step (a) comprises a first hydrodemetallisation (HDM) step (a1) carried out in one or more fixed bed hydrodemetallisation zones, and a subsequent hydrodesulphurisation (HDS) step (a2) carried out in one or more fixed bed hydrodesulphurisation zones.

EFFECT: invention relates to a process for treating heavy oil feedstock for producing liquid fuel and low sulphur fuel oil bases, preferably bunker fuel and bunker fuel bases.

17 cl, 3 dwg, 3 tbl

Description

FIELD OF THE INVENTION

The invention relates to primary refining and conversion of heavy fractions of hydrocarbons containing, in particular, sulfur impurities. More preferably, it relates to a method for processing heavy petroleum feedstocks for the production of liquid fuels and low sulfur liquid fuel bases, preferably bunker fuel and bunker fuel bases.

BACKGROUND OF THE INVENTION

While the regulatory requirements for the amount of sulfur contained in land-based fuels, typically gasoline and diesel, have become very stringent over the past decades, the regulation on the amount of sulfur in marine fuels has been little restrictive to date. Indeed, marine fuel, commercially available at present, may contain up to 3.5% and even 4.5% of the mass. sulfur. The result of this was that ships became the main source of sulfur dioxide (SO ₂ ) emissions.

To reduce these emissions, the International Maritime Organization (OMI) made recommendations regarding specifications for marine fuels (MARPOL Annex VI). These recommendations were rejected in the 2012 version of ISO 8217. The recommendations now apply to emissions of SO _x from marine fuels. The equivalent sulfur content recommended for 2020 or 2025 is less than or equal to 0.5% of the mass. for ships outside the Sulfur Emission Control Zone (ZCES or SECA (Sulfur Emission Control Areas) in English terminology). Within the ZCES zone, OMI for 2015 provides an equivalent sulfur content of less than or equal to 0.1% of the mass.

At the same time, another highly restrictive recommendation relates to the precipitation after aging according to ISO 10307-2, which should be less than or equal to 0.1%.

The applicant has set as its object the invention the production of liquid fuels and bases of liquid fuels, preferably bunker fuels and bases of bunker fuels, in which case the recommendations of the MARPOL convention with regard to the equivalent sulfur content are observed and preferably the recommendations for the content of precipitation after aging are also observed.

The liquid fuel used in maritime transport is generally atmospheric distillates, vacuum distillates, atmospheric and vacuum residues coming from direct distillation or coming from primary oil refining processes, in particular after hydroprocessing and conversion processes, and these fractions can be used individually or in a mixture. One of the objectives of the present invention is to provide a process for converting heavy petroleum feedstocks to produce liquid fuels and very low sulfur fuel oil bases, preferably bunker fuel and bunker fuel bases. Another objective of the present invention is the joint production, by the same method, of atmospheric distillates (solvent naphtha, kerosene, gas oil), vacuum distillates and / or light gases (C ₁ -C ₄ ). Solvent-naphtha and gas oil bases can be economically efficiently processed at oil refineries to produce automobile and aviation fuels, such as, for example, high-calorie fuels, rocket fuels and gas oils.

Methods for the primary processing and conversion of heavy petroleum feedstocks, including first the hydroprocessing stage in a fixed bed and then the hydroconversion stage in a fluidized bed, are described in FR 2764300, CA 1238005, EP 1343857 and EP 0665282. The purpose of EP 0665282, which describes a method of hydroprocessing of heavy oils, is to extend the life of the reactors. CA 1238005 describes a process for converting a heavy liquid hydrocarbon feed using several reactors in series, in which the degree of conversion is improved due to the special recycling of the resulting heavy fraction. The method described in FR 2764300 does not relate to the production of liquid fuel bases, in particular bunker fuel bases, but to fuel (gasoline and diesel fuel) having, in particular, a low sulfur content. In addition, the feedstock processed by this method contains a small amount of asphaltenes or does not contain them. Finally, the method described in EP 1343857 is described as a hydrotreatment method in which a hydrodemetallization section may be implemented, which may be preceded by a protection zone such as interchangeable reactors, and a hydrodesulfurization section.

None of these documents describe the production of liquid fuels or bases of liquid fuels with a very low sulfur content, in accordance with the new recommendations of the International Maritime Organization, and with low precipitation, which is required by the new version of ISO 8217: 2012.

One of the objectives of the present invention is to adapt and improve the conversion methods described in the prior art for the production of liquid fuel and liquid fuel bases, preferably with a low sulfur content.

SUMMARY OF THE INVENTION

Studies led the applicant to establish the fact that in an unexpected way the improvement of existing methods in relation to the production of liquid fuel bases and the quality of these liquid fuel bases, in particular in relation to sulfur content and precipitation, is possible due to a combination of different stages included in the process chain in a special way.

An object of the present invention is, firstly, a hydrocarbon feed processing method in which the sulfur content is at least 0.5 wt%, the initial boiling point is at least 340 ° C, and the final boiling point is at least 440 ° C, and the method allows to obtain at least one liquid hydrocarbon fraction with a sulfur content of less than or equal to 0.5 wt%, and includes the following successive stages:

a) a hydrotreatment step in a fixed bed, in which the hydrocarbon feed and hydrogen are brought into contact with at least one hydrotreatment catalyst;

b) a step for separating the stream obtained from the outlet of step (a) hydrotreatment into at least one light fraction and at least one heavy fraction;

c) a step for hydroconversion of at least a portion of the heavy fraction of the stream coming from step (b) in at least one reactor containing a catalyst maintained in a fluidized bed state;

d) a step for separating the stream from step (c) to obtain at least one gas fraction and at least one liquid hydrocarbon fraction.

The present invention also relates to liquid fuels suitable for use in marine transport, obtained in this way and having a sulfur content of less than or equal to 0.5% of the mass. and preferably less than or equal to 0.1% of the mass.

BRIEF DESCRIPTION OF THE DRAWINGS

In FIG. 1 shows an embodiment of the method of the present invention with intermediate separation of the effluent between the fixed-bed section and the fluidized-bed section with lowering the pressure of the heavy fraction.

In FIG. 2, for greater readability, an enlarged view shows the protection zones of the hydrotreatment section shown in FIG. one.

In FIG. 3 shows another embodiment of the method of the present invention with intermediate separation of the effluent between the fixed bed section and the fluidized bed section without lowering the pressure of the heavy fraction.

DETAILED DESCRIPTION OF THE INVENTION

It should be clarified that in any part of this description, the expression "in the range from ... to ..." must be understood as including the specified boundaries.

Thus, the method of the present invention first includes a step (a) of hydroprocessing in a fixed bed, then a step (b) of separating the leaving hydrocarbon stream into light and heavy fractions, then a step (c) of fluidized bed hydroconversion of said heavy fraction, and finally a step (d) separation.

The purpose of hydrotreatment is to simultaneously purify, that is, to significantly reduce the content of metals, sulfur and other impurities, while improving the ratio of hydrogen to carbon (H / C) and converting the hydrocarbon feed to a greater or lesser extent into lighter fractions . The effluent obtained in stage (a) hydrotreatment in a fixed bed is then directed to the separation stage, which allows to obtain different fractions. This separation allows you to remove from the stream obtained at the outlet of stage (a) hydrotreatment, the lightest fractions that do not require additional processing or require moderate treatment, and the heaviest fractions. These streams are directed to a fluidized-bed hydroconversion stage (c), which allows partially converting the hydrocarbon stream obtained at the outlet of the hydrotreating stage (a) to obtain a stream that can preferably be used in whole or in part as a liquid fuel or as a basis for liquid fuel , preferably as a bunker fuel or as a basis for bunker fuel.

One of the beneficial effects of including hydroprocessing in a fixed bed and subsequent hydroconversion in a fluidized bed is that the feedstock entering the fluidized bed hydroconversion reactor is already at least partially hydroprocessed. Thus, a conversion equivalent to better quality hydrocarbon streams, in particular with a lower sulfur content, can be achieved. In addition, the consumption of catalyst in a fluidized bed hydroconversion reactor is significantly reduced compared to the method without prior hydroprocessing in a fixed bed.

On the other hand, the method of the present invention is characterized in that it comprises an intermediate separation step (b) between the hydrotreatment step (a) and the hydroconversion step (c). This separation step makes it possible to efficiently minimize the fraction to be treated in a fluidized bed. Thus, the power of the fluidized bed hydroconversion unit may be less significant. Similarly, this avoids overcracking of light fractions and, consequently, loss of yield of fuel-type fractions.

The method of the present invention allows efficiently producing light fractions, liquid fuel and liquid fuel bases, preferably marine, with low sulfur content, high yield and high energy efficiency, based on heavy sulfur hydrocarbons.

Hydrocarbon feed

The hydrocarbon feed processed in accordance with the method of the present invention can be qualified as a heavy feed. It has an initial boiling point of at least 340 ° C and a final boiling point of at least 440 ° C. Its initial boiling point is preferably at least 350 ° C and preferably at least 375 ° C, and its final boiling point is at least 450 ° C, preferably at least 460 ° C, more preferably at least 500 ° C and most preferably at least 600 ° C.

Hydrocarbons can be selected from atmospheric residues, vacuum residues from direct distillation, crude oil, crude oil devoid of the lightest fractions, deasphalted oils, resins formed during deasphalting, asphalt or asphalt bitumen resulting from deasphalting, residues coming from deasphalting conversion processes, extracts of aromatic compounds coming from plants for the production of bases for lubricants, tar sands or their derivatives, tar shale or X derivatives, oils derived from the source rock or derivatives thereof used alone or in admixture. According to the present invention, the processed feedstock is preferably atmospheric or vacuum residues or mixtures of these residues.

In addition, the hydrocarbon feed processed according to the method of the present invention is sulphurous. The sulfur content in it is at least 0.5% by weight, preferably at least 1% by weight, more preferably at least 4% by weight. and most preferably at least 5% of the mass.

In addition, hydrocarbon feeds processed according to the method of the present invention may contain asphaltenes. Its asphaltene content may be at least 2% by weight. The term "asphaltene" in the present description refers to heavy hydrocarbon compounds insoluble in n-heptane (also referred to as C7 asphaltenes), but soluble in toluene. Quantitative determination of asphaltenes is generally carried out by standard analysis methods, such as those defined, for example, in AFNOR T 60-115 (France) or ASTM 893-69 (USA).

Vanadium and nickel content (Ni + V) in the feedstock is preferably greater ^-1 110 million and more preferably greater than 150 million ^-1 wt.

This feedstock can preferably be used without prior preparation. Alternatively, it may be diluted with concomitant feedstock. This concomitant feedstock may be a single hydrocarbon fraction or a mixture of hydrocarbon fractions that are lighter and can preferably be selected from products from catalytic cracking processes in a fluidized bed (FCC or "Fluid Catalytic Cracking" in English terminology), from light recycle gas oil (LCO or "light cycle oil" according to the terminology in English), heavy recycle gas oil (HCO or "heavy cycle oil" according to the terminology in English), decanted o oil, residue from the FCC, gas oil fraction, preferably from a fraction obtained by atmospheric or vacuum distillation, such as, for example, vacuum gas oil, or also from a fraction that may come from other primary oil refining processes. The associated feedstock may also preferably be one or more fractions from coal or biomass liquefaction processes, aromatic extracts, or any other hydrocarbon fraction or feedstock other than petroleum feeds, such as pyrolysis oil. The heavy hydrocarbon feed of the present invention may be at least 50%, preferably 70%, more preferably at least 80% and most preferably at least 90% by weight. from the total hydrocarbon feed processed according to the method of the present invention.

Hydrotreating Stage (a)

The hydrocarbon feed according to the method of the present invention is directed to a fixed bed hydroprocessing step (a) in which the feed and hydrogen are contacted on a hydroprocessing catalyst.

Hydrotreating, traditionally referred to as HDT, is understood to mean catalytic treatment with hydrogen supply, which makes it possible to purify the hydrocarbon feedstock, i.e., to significantly reduce the content of metals, sulfur and other impurities, while improving the ratio of hydrogen to carbon in the feed mixture and transforming the feedstock into more or less in lighter fractions. Hydrotreating includes, in particular, hydrodesulfurization reactions (traditionally referred to as HDS), hydrodesitration reactions (traditionally referred to as HDN) and hydrodemetallization reactions (traditionally referred to as HDM), followed by hydrogenation, hydrodeoxygenation, hydrodearomatization, hydroisomerization, hydrodealkylation, hydrocracking and hydrode cracking, hydrode according to Conradson.

According to a preferred embodiment, the hydroprocessing step (a) includes a first hydrodemetallization (HDM) step (a1) carried out in one or more fixed bed hydrodemetallization zones and a subsequent hydrodesulfurization step (a2) HDS) carried out in one or in several zones of hydrodesulfurization with fixed layers. In the first stage (a1) of hydrodemetallization, the feedstock and hydrogen are brought into contact on the hydrodemetallization catalyst under hydrodemetallization conditions, and then in the second stage (a2) of hydrodesulfurization, the stream leaving the first stage (a1) of hydrodemetallization is brought into contact with the hydrodesulfurization catalyst in hydrodesulfurization conditions. This method, known as HYVAHL-F ™, is described, for example, in US 5417846.

Those skilled in the art can readily understand that hydrodemetallization reactions are carried out at the hydrodemetallization stage, but part of other hydrotreatment reactions and preferably hydrodesulfurization are also carried out in parallel. Similarly, hydrodesulfurization reactions are carried out in the hydrodesulfurization step, but part of the other hydroprocessing reactions, and preferably hydrodemetallization, are also carried out in parallel. Those skilled in the art will recognize that the hydrodemetallization step begins where the hydroprocessing step begins, or where the metal concentration is maximum. Those skilled in the art will recognize that the hydrodesulfurization step ends where the hydroprocessing step ends, or where sulfur removal is most difficult. Between the hydrodemetallization stage and the hydrodesulfurization stage, specialists in the art sometimes define a transition zone in which all types of hydroprocessing reactions occur.

The hydroprocessing step (a) according to the present invention is carried out under hydroprocessing conditions. It can preferably be carried out at a temperature in the range of 300 to 500 ° C. and preferably in the range of 350 to 420 ° C. and at an absolute pressure in the range of 2 to 35 MPa, and preferably in the range of 11 to 20 MPa. The temperature is usually controlled depending on the desired level of hydroprocessing and the intended processing time. Most often, the volumetric feed rate of hydrocarbons, traditionally referred to as VVH and defined as the ratio of the volumetric flow rate of the feedstock to the total catalyst volume, can be in the range from 0.1 to 5 h ^-1 , preferably from 0.1 to 2 h ^-1 , more preferably from 0.1 to 0.45 h ^-1 and most preferably in the range from 0.1 to 0.2 h ^-1 . The amount of hydrogen mixed with the feed can be in the range of 100 to 5000 normal cubic meters (nm ³ ) per cubic meter (m ³ ) of the feed liquid, preferably in the range of 200 to 2000 nm ³ / m ³ and more preferably the range from 300 to 1500 nm ³ / m ³ . Hydrotreating step (a) can be carried out industrially in one or more downstream reactors.

The hydroprocessing catalysts used are preferably known catalysts. These may be granular catalysts containing at least one metal or metal compound having a hydrogenation-dehydrogenating function on a support. These catalysts can preferably be catalysts containing at least one metal from group VIII, selected generally from the group consisting of nickel and cobalt, and / or at least one metal from group VIB, and preferably molybdenum and / or tungsten. You can use, for example, a catalyst containing on a mineral carrier from 0.5 to 10% of the mass. and preferably from 1 to 5% of the mass. nickel (in terms of nickel oxide NiO) and from 1 to 30% of the mass. and preferably from 5 to 20% of the mass. molybdenum (in terms of molybdenum oxide MoO ₃ ). This carrier may be selected, for example, from the group consisting of alumina, silica, silica-alumina, magnesium oxide, clay and a mixture of at least two of these minerals. This support may preferably contain other alloying compounds, preferably oxides selected from the group consisting of boron oxide, zirconia, cerium dioxide, titanium oxide, phosphoric anhydride, and mixtures of these oxides. Most often, alumina is used as a support, and very often an alumina support is doped with phosphorus and, if necessary, boron. In the presence of phosphoric anhydride P ₂ O ₅ its concentration is less than 10% of the mass. In the presence of boron trioxide B ₂ O ₃ its concentration is less than 10% of the mass. The alumina used may be γ (gamma) or η (eta) alumina. This catalyst is most often found in the form of extruded elements. The total content of metal oxides from groups VIB and VIII can be from 5 to 40% of the mass. and in the General case from 7 to 30 wt. -%, and the mass ratio in terms of metal oxides between the metal (or metals) from group VIB and the metal (or metals) from group VIII in the General case is in the range from 20 to 1 and the most often in the range of 10 to 2.

In the case of a hydroprocessing step including a hydrodemetallization step (HDM) and a subsequent step of hydrodesulfurization (HDS), specific catalysts adapted for each step are preferably used.

Catalysts suitable for use in the HDM stage are indicated, for example, in EP 0113297, EP 0113284, US 5221656, US 5827421, US 7119045, US 5622616 and US 5089463. HDM catalysts are preferably used in interchangeable reactors.

Catalysts suitable for use in the HDS stage are indicated, for example, in EP 0113297, EP 0113284, US 6589908, US 4818743 or US 6332976.

You can also apply a mixed catalyst that is active in HDM and HDS, simultaneously in the HDM section and in the HDS section respectively described in FR 2940143.

Prior to the feed, the catalysts used in the process of the present invention are preferably subjected to sulphidation treatment in or out of the reactor.

According to a preferred embodiment of the present invention, in a fixed bed hydroprocessing step (a), a system of interchangeable reactors, also called protection zones, is used in front of the main hydroprocessing reactors. More preferably, the hydrotreatment step (a) can be carried out in one or more hydrotreatment zones with fixed beds, preceded by at least two hydrotreatment protection zones also with fixed beds, connected in series for cyclic use, which consists in sequentially repeating steps a '') and a '' ') defined below:

a ') the stage at which the protection zones are used together for a period of time not exceeding the time of decontamination and / or mopping of one of them;

a '') a stage during which a deactivated and / or clogged protection zone is blocked and the catalyst contained therein is regenerated and / or replaced with a fresh catalyst, and during which one or more other protection zones are used;

a '' ') the stage during which the protection zones are shared, while the protection zone is again connected, the catalyst of which was regenerated and / or replaced during the previous stage, and this stage lasts for a period of time not exceeding the decontamination time and / or clamming one of the protection zones.

After regeneration and / or replacement of the catalyst in the reactor, this reactor is preferably connected after the operating reactor.

The interchangeable reactor system is known from FR 2681871, FR 2784687 and EP 1343857. The function of the interchangeable reactors is to protect the main hydroprocessing reactors connected further to avoid clogging and / or deactivation. In practice, the problem encountered with the use of fixed layers is colmatage, which occurs due to the presence of asphaltenes and precipitation contained in the feedstock. Another problem is catalyst deactivation due to the significant deposition of metals that occurs during hydroprocessing reactions. Thus, interchangeable reactors are used to increase the duration of the working cycle of a hydroprocessing unit due to the possibility of replacing a deactivated and / or clogged catalyst only in interchangeable reactors operating cyclically without stopping the entire unit for a certain period of time.

The decontamination and / or colmatizing time varies depending on the feedstock, operating conditions at the hydroprocessing stage and one or more catalysts used. In the general case, it manifests itself in a decrease in catalytic characteristics, which can be ascertained by an increase in the concentration of metals and / or other impurities in the effluent, by an increase in the temperature necessary to maintain the activity of the catalyst, or, in the case of colmatization, by a significant increase in pressure loss. The pressure loss ΔP, which expresses the degree of clogging, can be measured continuously throughout the cycle in each of the zones and can be determined by the increase in pressure caused by a partially blocked flow passage through the zone. Similarly, temperature can be measured continuously throughout the cycle in each of the two zones.

To determine the time of decontamination and / or mopping up, specialists in this field of technology preliminarily determine the maximum permissible value of pressure loss ΔP and / or temperature depending on the processed feedstock, operating conditions and selected catalysts, based on which it is necessary to disconnect the protection zone. Thus, the time of decontamination and / or clogging is defined as the time for which the limit value of pressure and / or temperature loss is reached. In the case of hydroprocessing of heavy fractions, the limiting value of the pressure loss is generally in the range from 0.3 to 1 MPa (from 3 to 10 bar) and preferably in the range from 0.5 to 0.8 MPa (from 5 to 8 bar). The temperature limit value is generally in the range of 400 to 430 ° C. The indicated temperature corresponds to the average temperature measured in the catalyst bed.

The operating conditions in interchangeable reactors are generally identical to those in the main hydroprocessing reactors. The value of the space velocity VVH for each interchangeable reactor included in the operation is preferably in the range from 0.2 to 4 h ^-1 and more preferably in the range from 1 to 2 h ^-1 . The values of the total space velocity VVH in the interchangeable reactors and in each reactor are chosen so as to achieve maximum hydrodemetallization, while controlling the reaction temperature and thus limiting the exothermic effect.

In a preferred embodiment of the present invention, a catalyst conditioning section is used, allowing the change of these protection zones in the operating mode, that is, without stopping the unit. The catalyst conditioning section may include the following elements:

- a system that operates at an average pressure, mainly in the range from 1 to 5 MPa (from 10 to 50 bar) and preferably in the range from 1.2 to 2.5 MPa (from 12 to 25 bar), and allows washing operations , stripping and cooling in a protection reactor disconnected before unloading the used catalyst, and then heating and sulfiding after loading fresh catalyst;

- another system for increasing / decreasing the pressure and valve-valves of the corresponding action, which allows changing these protection zones without stopping the unit, since all washing, stripping, unloading of the used catalyst, reloading of fresh catalyst, heating and sulfidation are carried out in a disconnected reactor or zone protection.

Alternatively, the pre-sulfidized catalyst can be used in the conditioning section to simplify the change procedure in the operating mode.

The stream leaving the interchangeable reactors can then be directed to the main hydroprocessing reactors.

Each hydrotreatment zone or hydrotreatment protection zone may contain at least one catalyst bed, for example 1, 2, 3, 4 or 5 catalytic beds. Preferably, each protection zone comprises a catalyst bed. Each catalyst layer may contain at least one catalyst layer, which contains one or more catalysts and which, if necessary, is preceded by at least one inert layer, for example, aluminum oxide or ceramic in the form of extruded elements, balls or tablets. The catalysts used in one or more catalytic layers may be the same or different.

According to a preferred embodiment, the hydrocarbon feed at the inlet of each protection zone passes through a filter plate located in front of one or more catalytic layers contained in the protection zone. This filter plate, described, for example, in FR 2889973, makes it possible to preferentially trap the clogging particles contained in the hydrocarbon feed, thanks to a special distribution plate containing filter material.

Separation Step (b)

The stream obtained at the exit of the hydrotreatment stage (a) in the fixed bed is directed to at least one separation stage, which, if necessary, is supplemented by other additional separation stages and which allows the stream to be divided into at least one light fraction and at least one heavy fraction fraction. By "light fraction" is meant a fraction in which at least 90% of the compounds have a boiling point below 350 ° C. By "heavy fraction" is meant a fraction in which at least 90% of the compounds have a boiling point above 350 ° C. The light fraction obtained in the separation step (b) preferably contains a gas fraction and at least one light fraction of hydrocarbons such as solvent naphtha, kerosene and / or gas oil. The heavy fraction preferably contains a vacuum distillate fraction and a vacuum residue fraction and / or atmospheric residue fraction.

Separation step (b) may be carried out by any method known to those skilled in the art. This method can be selected from methods of separation at high or low pressure, distillation at high or low pressure, distillation at high or low pressure, liquid / liquid extraction, solid / liquid separation, centrifugation, and combinations of these various methods, which can be implemented at different values of pressure and temperature.

According to a first embodiment of the present invention, the stream coming from the hydrotreating step (a) is directed to a pressure reducing step (b).

According to this embodiment, the separation is preferably carried out in a fractionation section, which may include first a high temperature high pressure separator (HPHT) and, if necessary, a low temperature high pressure separator (HPBT), and then, if necessary, an atmospheric distillation section and / or a distillation section in vacuum. The stream leaving stage (a) can be directed to a fractionation section and, in general, to an HPHT separator, which operate at a cut-off temperature of the fraction in the range of 200 to 400 ° C and allow the production of light and heavy fractions. In the general case, separation predominantly occurs without maintaining the exact cut-off temperature of the fraction; rather, it resembles the separation of the type of flash evaporation.

Said heavy fraction can then be separated by atmospheric distillation into at least one atmospheric distillate fraction containing preferably at least one light hydrocarbon fraction such as solvent naphtha, kerosene and / or gas oil, and an atmospheric residue fraction. At least a portion of the atmospheric residue fraction can also be separated by vacuum distillation into a vacuum distillate fraction, preferably containing vacuum gas oil, and a vacuum residue fraction. At least a portion of the fraction of the vacuum residue and / or fraction of the atmospheric residue is preferably sent to the hydroconversion stage (c). A portion of the vacuum residue can also be recycled to the hydrotreatment step (a).

According to a second embodiment, the stream from the hydrotreatment step (a) is directed to the separation step (b) without pressure reduction.

According to this embodiment, the stream leaving the hydrotreatment stage (a) is directed to a fractionation section and, generally, to an HPHT separator, which operate at a cut-off temperature of the fraction in the range of 200 to 400 ° C. and allow at least one light fraction to be obtained and at least one heavy fraction. In the general case, separation predominantly occurs without maintaining the exact cut-off temperature of the fraction; rather, it resembles the separation of the type of flash evaporation.

Then the heavy fraction can be sent directly to stage (c) hydroconversion.

The light fraction can be directed to other stages of separation. It should preferably be directed to atmospheric distillation, allowing to obtain a gas fraction, at least one light fraction of liquid hydrocarbons such as solvent naphtha, kerosene and / or gas oil and a fraction of vacuum distillate, the latter fraction can be at least partially directed to the stage (c ) hydroconversion. Another part of the vacuum distillate can be used as a liquid fuel thinner. Another part of the vacuum distillate can be economically processed at the stage of hydrocracking and / or catalytic cracking in a fluidized bed.

Separation without pressure reduction provides the best thermal balance and is expressed in saving energy and equipment costs. In addition, this embodiment has technical and economic advantages, given that in its case it is not necessary to increase the pressure of the streams after separation before the subsequent hydroconversion stage. Since intermediate separation without pressure reduction is simpler than separation with pressure reduction, therefore, capital costs are advantageously reduced.

The gas fractions from the separation stage are preferably sent for purification to separate hydrogen and recirculate it to the hydroprocessing and / or hydroconversion reactors. The presence of an intermediate separation stage between the hydroprocessing stage (a) and the hydroconversion stage (c) allows to have two independent hydrogen circuits with a positive effect, one of which is associated with hydroprocessing and the other is associated with hydroconversion and which, if necessary, can be connected to each other. The addition of hydrogen can be carried out in the hydrotreatment section or in the hydroconversion section or in both sections. Recycled hydrogen can be fed to the hydrotreatment section or the hydroconversion section or both. The compressor, if necessary, can be common to both hydrogen circuits. The ability to connect both hydrogen circuits allows you to optimize the control of hydrogen supply and reduce the capital cost of compressors and / or exhaust gas treatment plants. Various hydrogen supply embodiments suitable for use in the present invention are described in FR 2957607.

The light fraction obtained from the separation stage (b) and containing hydrocarbons such as solvent naphtha, kerosene and / or gas oil or other hydrocarbons, preferably GPL and vacuum gas oil, can be economically processed using methods well known to those skilled in the art. The resulting products can be introduced into fuel compositions (also called "fuel pools" according to English terminology) or sent to additional stages of primary processing. One or more fractions of solvent naphtha, kerosene, gas oil and vacuum gas oil can be subjected to one or more treatments, for example, hydroprocessing, hydrocracking, alkylation, isomerization, catalytic conversion, catalytic or thermal cracking, to bring their characteristics separately or in a mixture to the required values which may be applicable to sulfur content, smoke-free flame height, octane rating, cetane and other indicators.

Stage (c) fluidized bed hydroconversion

At least a portion of the heavy fraction of the stream from separation step (b) is directed, according to the method of the present invention, to hydroconversion step (c), which is carried out in at least one reactor containing a fluidized bed catalyst. The aforementioned reactor can operate in an upward flow of liquid and gas. The main goal of hydroconversion is to convert heavy hydrocarbon feeds into lighter fractions through partial processing.

According to an embodiment of the present invention, a portion of the hydrocarbon feedstock can be fed directly to the inlet of the hydroconversion section (c) in a fluidized bed mixed with a heavy fraction of the stream from separation step (b), and this portion of the hydrocarbon feed is not processed in the hydroprocessing section (a) in a fixed layer. This embodiment can be identified with partial blocking of the hydrotreatment section (a) in the fixed bed.

According to an embodiment, the concomitant feedstock may be fed to the inlet of the hydroconversion section (c) in a fluidized bed together with a heavy fraction of the stream from separation stage (b). This concomitant feedstock can be selected from atmospheric residues, vacuum residues from direct distillation, deasphalted oils, extracts of aromatic compounds from plants for the production of bases for lubricants, hydrocarbon fractions or a mixture of hydrocarbon fractions that can be selected from products coming in from catalytic cracking processes in a fluidized bed, preferably from light recycle gas oil (LCO), heavy recycle gas oil (HCO), decanted oil, or which may come from distillation, gas oil fractions, preferably fractions obtained by atmospheric or vacuum distillation, such as, for example, vacuum gas oil. According to another embodiment, and in the case where there are several fluidized bed reactors in the hydroconversion section, the accompanying feedstock may be partially or fully supplied to one of the reactors after the first reactor.

Hydrogen necessary for the hydroconversion reaction can be fed to the inlet of the hydroconversion section (c) in a fluidized bed. This may be recycled hydrogen and / or additional hydrogen. In the event that there are several fluidized bed reactors in the hydroconversion section, hydrogen may be fed to the inlet of each reactor.

Fluidized bed technology is well known to those skilled in the art. In this case, only basic operating conditions will be described. Catalysts deposited on extruded elements, the diameter of which in the general case is about 1 mm, for example 0.9 mm or 1.2 mm, are traditionally used in fluidized bed technology. The catalysts remain inside the reactors and are not carried away with the products, with the exception of the stages of replenishment and unloading of the catalysts necessary to maintain catalytic activity. The temperature values can be high in order to obtain high degrees of conversion while minimizing the amount of catalyst used. Catalytic activity can be maintained constant by successive replacement of the catalyst. At the same time, it is not necessary to stop the unit to replace the spent catalyst and increase the reaction temperature during the cycle to compensate for deactivation. In addition, the mode of operation with constant technological conditions allows you to preferably obtain the output and properties of the products, which remain constant during the cycle. Also, due to the fact that the catalyst is maintained in a state of movement by recirculation of a significant fluid flow, the pressure loss in the reactor remains small and constant. Due to the abrasive wear of the catalysts in the reactors, products exiting the reactors may contain finely divided catalyst particles.

The conditions in the fluidized-bed hydroconversion stage (c) may correspond to the conventional fluidized-bed hydroconversion conditions of the liquid hydrocarbon fraction. Operation can be carried out at an absolute pressure in the range of 2.5 to 35 MPa, preferably in the range of 5 to 25 MPa, more preferably in the range of 6 to 20 MPa, and most preferably in the range of 11 to 20 MPa and at a temperature in the range of 330 to 550 ° C, and preferably in the range of 350 to 500 ° C. The space velocity (VVH) and the partial pressure of hydrogen are parameters that are set depending on the characteristics of the processed product and the desired degree of conversion. VVH (defined as the ratio of the volumetric flow rate of the feedstock to the total volume of the fluidized bed reactor) is generally in the range from 0.1 to 10 h ^-1 , preferably from 0.2 to 5 h ^-1 and more preferably from 0.2 up to 1 h ^-1 . The amount of hydrogen mixed with the feedstock is usually from 50 to 5000 normal cubic meters (nm ³ ) per cubic meter (m ³ ) of feed liquid, more often from 100 to 1500 nm ³ / m ³ and preferably from 200 to 1200 nm ³ / m ³ .

You can use the traditional granular hydroconversion catalyst containing on an amorphous support at least one metal or metal compound having a hydrogenating-dehydrogenating function. This catalyst may be a catalyst containing metals from group VIII, for example nickel and / or cobalt, most often in combination with at least one metal from group VIB, for example, molybdenum and / or tungsten. You can apply, for example, a catalyst containing on an amorphous mineral carrier from 0.5 to 10% of the mass. and preferably from 1 to 5% of the mass. nickel (in terms of nickel oxide NiO) and from 1 to 30% of the mass. and preferably from 5 to 20% of the mass. molybdenum (in terms of molybdenum oxide MoO ₃ ). This carrier may be selected, for example, from the group consisting of alumina, silica, silica-alumina, magnesium oxide, clay and a mixture of at least two of these minerals. This carrier may also contain other compounds, for example, oxides selected from the group consisting of boron oxide, zirconia, titanium oxide, phosphoric anhydride. Most often, alumina is used as a support, and very often an alumina support is doped with phosphorus and, if necessary, boron. In the presence of phosphoric anhydride P ₂ O ₅ its concentration is usually less than 20% of the mass. and more often less than 10% of the mass. In the presence of boron trioxide B ₂ O ₃ its concentration is usually less than 10% of the mass. The alumina used is typically alumina γ (gamma) or η (eta). This catalyst may be in the form of extruded elements. The total content of metal oxides from groups VI and VIII can be from 5 to 40% of the mass. and preferably from 7 to 30 wt.%, and the mass ratio in terms of metal oxides between the metal (or metals) from group VI and the metal (or metals) from group VIII is in the range from 20 to 1 and preferably in the range from 10 to 2.

The spent catalyst can be partially replaced with a fresh catalyst in the general case by unloading it from the lower part of the reactor and loading fresh or new catalyst into the upper part of the reactor at regular time intervals, i.e., for example, periodically or continuously, or conditionally continuously. You can also load the catalyst through the bottom and unload through the top of the reactor. For example, you can load fresh catalyst every day. The degree of replacement of the spent catalyst with a fresh catalyst may be, for example, from about 0.05 to about 10 kg per cubic meter of feedstock. Unloading and replacement is carried out by means of devices that provide continuous operation of the hydroconversion stage. The hydroconversion reactor is usually equipped with a recirculation pump that maintains the catalyst in a fluidized bed by continuously recirculating at least a portion of the liquid taken from the upper part of the reactor and then introduced into the lower part of the reactor. It is also possible to direct spent catalyst discharged from the reactor to a regeneration zone where carbon and sulfur contained therein are removed before being fed back to hydroconversion step (c).

Step (c) the hydroconversion process according to the present invention may be carried out under process conditions H-OIL ^®, corresponding to that described for example in US 6,270,654.

Fluidized bed hydroconversion can be carried out in one or more reactors, and preferably in two reactors connected in series. The use of at least two fluidized bed reactors connected in series allows to obtain products of better quality and with a higher yield. In addition, the hydroconversion in two reactors allows for operation, improved in terms of the flexibility of the operating conditions and the catalytic system. The temperature in the second fluidized bed reactor is preferably at least 10 ° C higher than the temperature in the first fluidized bed reactor. The pressure in the second reactor can be from 0.1 to 1 MPa less than the pressure in the first reactor, in order to ensure the movement of at least part of the stream leaving the first stage, without the need for a pump. Different operating conditions with respect to temperature in the two hydroconversion reactors are chosen to be able to control the hydrogenation and conversion of the feed into the desired products in each reactor.

In the case where the stage (c) of hydroconversion is implemented in two stages (c1) and (c2) in two reactors connected in series, the stream obtained at the outlet of the first stage (c1) can, if necessary, be directed to the light separation stage and a heavy fraction and at least a portion and preferably an entire heavy fraction can be processed in a second hydroconversion stage (c2). This separation, preferably carried out in a bypass separator as described, for example, in US 6,270,654, preferably avoids overcracking of the light fraction in the second hydroconversion reactor. It is also possible to completely or partially transfer spent catalyst discharged from the reactor of the first cascade (c1) of hydroconversion operating at a lower temperature directly to the reactor of the second cascade (c2) operating at a higher temperature, or completely or partially move the spent catalyst discharged from a second stage reactor (c2), directly to a first stage reactor (c1). This cascade system is described, for example, in US 4816841.

Stage (d) separation of the stream leaving after hydroconversion

The method of the present invention also includes a separation step (d), which allows at least one gas fraction and at least one liquid hydrocarbon fraction to be obtained.

The stream obtained at the outlet of the hydroconversion stage (c) comprises a liquid fraction and a gas fraction containing gases, preferably H ₂ , H ₂ S, NH ₃ , and C ₁ -C ₄ hydrocarbons. This gas fraction can be separated from the hydrocarbon stream by means of separation devices well known to those skilled in the art, in particular by means of one or more separation vessels that can operate at different pressures and temperatures and, if necessary, are connected to a steam stripping device or hydrogen. The stream obtained at the outlet of the hydroconversion stage (c) is preferably divided in at least one gas fraction and at least one liquid fraction in at least one separation vessel. These separators can be, for example, high temperature high pressure separators (HPHT) and / or low temperature high pressure separators (HPBT).

After possible cooling, this gas fraction is preferably treated in a hydrogen purification device in order to liberate hydrogen not consumed in hydrotreatment and hydroconversion reactions. The hydrogen purification device may be an amine flushing device, a membrane device, a PSA type system (Pressure Swing Adsorption according to English terminology), or several of these devices connected in series. In this case, the purified hydrogen can preferably be recycled to the process of the present invention after a possible increase in pressure. Hydrogen may be supplied to the inlet of the hydrotreatment stage (a) and / or to different places during the hydrotreatment stage (a) and / or to the inlet of the hydroconversion stage (c) and / or to different places during the hydroconversion stage (c).

The separation step (d) may also include an atmospheric and / or vacuum distillation unit. The separation step (d) preferably also includes at least one atmospheric distillation unit in which one or more liquid hydrocarbon fractions obtained after separation are separated by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric fraction the remainder. The atmospheric distillate fraction may contain fuel bases (solvent naphtha, kerosene and / or diesel fuel) suitable for cost-effective processing, for example, in oil refineries for the production of automobile and aviation fuel.

In addition, the separation step (d) of the method of the present invention can preferably also include at least one vacuum distillation unit in which one or more liquid hydrocarbon fractions obtained after separation and / or an atmospheric residue fraction obtained after atmospheric distillation are separated by vacuum distillation of at least one fraction of a vacuum distillate and at least one fraction of a vacuum residue. The separation step (d) preferably includes, first of all, an atmospheric distillation unit in which one or more liquid hydrocarbon fractions obtained after separation are separated by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction, and then a vacuum distillation unit in which a fraction of the atmospheric residue obtained after atmospheric distillation is separated by vacuum distillation into at least one fraction of a vacuum distillate and at least at least one fraction of the vacuum residue. The vacuum distillate fraction typically contains fractions such as vacuum gas oil.

At least a portion of the fraction of the vacuum residue can be recycled to the hydroconversion step (c).

At the output of the separation step (d), at least one liquid hydrocarbon fraction can be obtained, the sulfur content of which is less than or equal to 0.5 wt%, preferably less than or equal to 0.3 wt%, more preferably less than or equal to 0.1 % of the mass. and most preferably less than or equal to 0.08% of the mass. This liquid hydrocarbon fraction can preferably serve as a basis for liquid fuel, preferably for bunker fuel. The entire liquid hydrocarbon stream obtained from the separation stage (d) may preferably contain sulfur in an amount less than or equal to 0.5% by weight, preferably less than or equal to 0.3% by weight, more preferably less than or equal to 0.1 % of the mass. and most preferably less than or equal to 0.08% of the mass.

In the framework of the present invention, the degree of conversion of the hydrocarbon feed to lighter fractions can be in the range of 10 to 95%, preferably in the range of 25 to 90%, and more preferably in the range of 40 to 85%. The degree of conversion is defined as the ratio of the number of compounds having a boiling point above 520 ° C in the hydrocarbon feed, minus the number of compounds having a boiling point above 520 ° C, in the hydrocarbon effluent obtained from the hydroconversion stage (c), to the number of compounds having a boiling point above 520 ° C in the hydrocarbon feedstock. A high degree of conversion is preferred in cases where the degree of conversion illustrates the production of conversion products, mainly atmospheric distillates and / or vacuum distillates such as solvent naphtha, kerosene and gas oil, in significant quantities.

This liquid hydrocarbon stream can be, at least partially, preferably used as a base for liquid fuel or as a liquid fuel, in particular as a base for bunker fuel or as a bunker fuel, with a low sulfur content, in accordance with the new recommendations of the International Maritime Organization.

The term "liquid fuel" according to the present invention means a hydrocarbon feed suitable for use as a fuel. By the term “liquid fuel base” of the present invention is meant a hydrocarbon feed which, when mixed with other bases, forms liquid fuel. Depending on the origin of these bases, in particular depending on the type of crude oil and the type of primary processing, the properties of these bases, in particular the sulfur content and viscosity, are very different.

Possible step (e) of separating sediment and fine particles

The hydrocarbon stream obtained at the outlet of the hydroconversion stage (c), and in particular the heaviest liquid fraction obtained, may contain precipitates and catalyst residues coming in the form of fine particles from the fixed-bed stage and / or from the fluidized-bed stage. In order to obtain a liquid fuel or a liquid fuel base that meets the recommendations for a precipitation after aging of less than or equal to 0.1%, the method of the present invention may include an additional step consisting in separating precipitation and fine particles from the liquid hydrocarbon stream after the step ( d) separation.

Thus, the method of the present invention may also include a step (e) of separating precipitation and fine particles, in which at least a fraction of the atmospheric residue and / or vacuum distillate and / or vacuum residue are directed to separating precipitation and fine catalyst particles using at least one filter, centrifugation or decantation system connected in series.

Possible catalytic cracking step (f)

According to an embodiment, the method of the present invention may also include a catalytic cracking step (f), in which at least a portion of the vacuum distillate fraction and / or the vacuum residue fraction, optionally pretreated in the precipitate and fine particle separation step (e), is sent in the catalytic cracking section, in which it is processed under conditions allowing to obtain gas, gasoline, gas oil and residual fractions.

The catalytic cracking step (f) may be a fluidized bed catalytic cracking step, for example, by a method developed by the applicant company called R2R. This step can be carried out in the traditional manner known to those skilled in the art under conditions appropriate for cracking in order to obtain hydrocarbon compounds with a lower molecular weight. A description of the operating mode and the catalysts suitable for use in cracking in a fluidized bed in step (f) is given, for example, in US 4695370, EP 0184517, US 4959334, EP 0323297, US 4965232, US 5120691, US 5344554, US 5449496, EP 0485259, US 5286690, US 5324696, EP 0542604 and EP 0699224.

The fluidized bed catalytic cracking reactor may be operated in an upward or downward flow mode. Although this is not a preferred embodiment of the present invention, catalytic cracking can also be carried out in a moving bed reactor. More preferred catalytic cracking catalysts are catalysts containing at least one zeolite, usually in admixture with an appropriate matrix, such as, for example, alumina, silica, silica-alumina.

At least a portion of the residual fraction obtained from the outlet of the catalytic cracking step (f), often referred to as the slurry fraction (slurry) by those skilled in the art, may be recycled to the inlet of the catalytic cracking step (f) and / or to the inlet of the step ( a) hydrotreatment, and / or at the inlet of stage (c) hydroconversion. The residual fraction can also be at least partially and possibly completely directed to the storage area of the heavy liquid fuel of the refinery.

In an embodiment of the present invention, a portion of the gas oil and / or residual fraction obtained from the catalytic cracking step (f) can be used to form a thinning base.

Liquefaction and liquid fuels

The aim of the present invention is the production of liquid fuels suitable for commercial sale, preferably bunker fuels for marine transport. Of course, this type of liquid fuel meets certain technical conditions, in particular with respect to viscosity. Very popular bunker fuels preferably have a viscosity of less than or equal to 380 cSt (at 50 ° C). Other properties of liquid fuels qualifying as “grades” correspond to various technical conditions, in particular with respect to viscosity. In particular, for distillate type fuels, a viscosity in the range of 2 to 6 cSt at 40 ° C is required for a DMA grade, and a viscosity in the range of 2 to 11 cSt at 40 ° C is required for a DMB grade. In particular, to obtain a viscosity corresponding to the desired brand of liquid fuel, the basis of the liquid fuel can be mixed, if necessary, with thinning bases or "distillate oil products" ("cutter stocks" according to English terminology). Technical specifications for liquid fuels are described, for example, in ISO 8217 (latest version from 2012).

Liquefying bases are generally bases such as kerosene, gas oil or vacuum gas oil. They can be selected from light recycle gas oils (LCO), heavy recycle gas oils (HCO) obtained by catalytic cracking, the remainder from catalytic cracking, kerosene, gas oil, vacuum distillate and / or decanted oil.

According to the method of the present invention, the atmospheric residue and / or vacuum distillate and / or vacuum residue obtained at the outlet of the separation step (d) and, if necessary, preliminarily processed in the step (e) of separating precipitation and fine particles, can be mixed with one or several thinning bases selected from the group consisting of light recycle gas oils from catalytic cracking, heavy recycle gas oils from catalytic cracking, residue from catalytic cracking, kerosene, g azoil, vacuum distillate and / or decanted oil.

Most preferably, the fluidizing base is selected from a portion of a light hydrocarbon fraction such as kerosene or gas oil obtained from the separation stage (b), a portion of a heavy hydrocarbon fraction such as a vacuum distillate obtained from the separation stage (b), and a portion of the gasoline fraction, gas oil fraction and / or a residual fraction obtained from the outlet of step (f) of catalytic cracking. In addition or alternatively, a thinning base may be selected from a portion of the kerosene and / or gas oil fraction obtained from the fluidized bed hydroconversion stage.

At the output of the stage of mixing the atmospheric residue and / or vacuum distillate and / or vacuum residue obtained at the output of separation stage (d) and, if necessary, preliminarily processed in stage (e) of separating precipitation and fine particles, with one or more thinning bases preferably, low sulfur liquid fuels suitable for use in maritime transport and also called bunker fuels are obtained.

Thus, the aim of the present invention is a liquid fuel with a sulfur content of less than or equal to 0.5% of the mass. and preferably less than or equal to 0.1% of the mass. In this liquid fuel, the precipitation content may preferably be less than or equal to 0.1% by mass, in order to comply with the new version of ISO 8217: 2012.

In addition, the viscosity of this liquid fuel may range from 1 to 700 cSt at 50 ° C.

A preferred embodiment of the method of the present invention is shown in FIG. 1, 2 and 3.

In FIG. 1 shows a method of the present invention with intermediate separation under pressure reduction. For greater readability, the functioning of the protection zones in the hydroprocessing section shown in FIG. 1 is described with reference to FIG. 2.

Accordingly, FIG. 1, the initial mixture (10), heated in the chamber (12), mixed with recycled hydrogen (14) and additional hydrogen (24), heated in the chamber (16), is fed through a pipeline (18) to the system of protection zones.

Accordingly, FIG. 2, the functioning of the protection zones in the hydroprocessing section, which includes two protection zones (or two interchangeable reactors) Ra and Rb, is a sequence of cycles, each of which includes the following four stages:

- the first stage (stage i), during which the feedstock passes sequentially through the reactor Ra and then through the reactor Rb;

- the second stage (stage ii), during which the feedstock passes only through the reactor Rb, and the reactor Ra is blocked for regeneration and / or replacement of the catalyst;

- the third stage (stage iii), during which the feedstock passes sequentially through the reactor Rb and then through the reactor Ra;

- the fourth stage (stage iv), during which the feedstock passes only through the reactor Ra, and the reactor Rb is blocked for regeneration and / or replacement of the catalyst.

Then the cycle can be carried out from the initial stage.

Stage i and iii are stages during which all protection zones operate. Steps ii and iv are stages during which one protection zone is blocked while the other zone is operating.

During step (i), the heated feedstock is fed through line (18) and line (19) containing the open valve V1 to line (20) and the protection reactor Ra containing the fixed catalyst bed A. During this period, valves V3, V4 and V5 are closed. The effluent from the reactor Ra is directed through a conduit (21), a conduit (22) containing an open valve V2, and a conduit (23) to a protection reactor Rb containing a fixed catalyst layer B. The stream leaving reactor Rb is directed through a pipe (24), a pipe (25) containing an open valve V6, and a pipe (26) to the main hydroprocessing section, which will be described later.

In step (ii), valves V1, V2, V4, and V5 are closed, and feed is supplied via line (18) and line (27) containing open valve V3 to line (23) and reactor Rb. During this period, the effluent from reactor Rb is directed through a conduit (24), a conduit (25) containing an open valve V6, and a conduit (26) to the main hydroprocessing section.

During step (iii), valves V1, V2 and V6 are closed and valves V3, V4 and V5 are open. The feedstock is fed through line (18) and lines (27) and (23) to reactor Rb. The stream leaving reactor Rb is directed through a conduit (24), a conduit (28) containing an open valve V4, and a conduit (20) to a protection reactor Ra.

The effluent from the Ra reactor is directed through a conduit (21), a conduit (29) containing an open valve V5, and a conduit (26) to the main hydroprocessing section.

During step (iv), valves V2, V3, V4 and V6 are closed and valves V1 and V5 are open. The feedstock is fed through line (18) and lines (19) and (20) to the reactor Ra. During this period, the effluent from the Ra reactor is directed through a conduit (21), a conduit (29) containing an open valve V5, and a conduit (26) to the main hydroprocessing section.

Accordingly, FIG. 1 stream leaving one or more protection reactors, if necessary, is re-mixed with hydrogen entering through the pipeline (65) into the HDM reactor (30), which contains a fixed catalyst bed (32). For readability reasons, the figure shows one HDM reactor and one HDS reactor, but the HDM and HDS section may include several HDM and HDS reactors connected in series. If necessary, recycled and / or additional hydrogen can also be fed to the hydroprocessing reactors between different catalytic beds (not shown).

The stream leaving the HDM reactor is diverted through a conduit (34) and then directed to the first HDS reactor (36), in which it passes through a fixed catalyst bed (38).

The stream coming from the hydroprocessing stage is sent via line (42) to a high-temperature high-pressure separator (HPHT) (44), at the outlet of which a gas fraction (46) and a liquid fraction (48) are obtained. The cut-off temperature of the fraction is generally in the range from 200 to 400 ° C. The gas fraction (46) is generally directed through a heat exchanger (not shown) or an air cooler (50) for cooling in front of the low-temperature high-pressure separator (HPBT) (52), at the outlet of which a gas fraction (54) containing gases (H ₂ , H ₂ S, NH ₃ , hydrocarbons C ₁ -C ₄ , etc.), and the liquid fraction (56).

The gas fraction (54) coming from the low-temperature high-pressure separator (HPBT) (52) is processed in a hydrogen purification unit (58), at the outlet of which hydrogen (60) is obtained for recirculation through a compressor (62) and line (65) to reactors (30) and / or (36) or via line (14) to interchangeable reactors. Gases containing undesirable nitrogen and sulfur compounds are removed from the unit (stream (66)).

The liquid fraction (56) coming from the low temperature high pressure separator (HPBT) (52) is expanded in the device (68) and then sent to the fractionation system (70). If necessary, a medium pressure separator (not shown) can be installed after the expander (68) to separate the gas fraction, which is sent to the purification unit (58), and the liquid fraction, which is sent to the fractionation section (70).

The liquid fraction (48) coming from the high-temperature high-pressure separator (HPHT) (44) is expanded in the device (72) and then sent to the fractionation system (70). Fractions (56) and (48) can be sent together, after expansion, to system (70). According to a not shown embodiment, the fractionation units (70) and (172) can be shared and all light fractions can be processed in them, including the fraction coming from the bypass separator (108). The fractionation system (70) includes an atmospheric distillation system to produce a gas stream (74) of at least one fraction (76) called light and containing, in particular, solvent naphtha, kerosene and gas oil, and atmospheric residue fractions (78) ) Part of the atmospheric residue fraction can be sent via line (80) to hydroconversion reactors. The whole fraction or part of the atmospheric residue fraction (78) is sent to a vacuum distillation column (82) to separate the fraction (84) containing the vacuum residue and the vacuum distillate fraction (86) containing the vacuum gas oil.

The vacuum residue fraction (84), optionally mixed with a portion of the atmospheric residue fraction (80) and / or with a portion of the vacuum distillate fraction (86), is mixed with recycled hydrogen (88), which is optionally supplemented with additional hydrogen (90), heated in the oven (91). If necessary, it passes through the furnace (92). If necessary, concomitant feedstock may be supplied (94). Then, the heavy fraction is fed via line (96) to the hydroconversion stage to the bottom of the first fluidized bed reactor (98) operating in an upward flow of liquid and gas and containing at least one hydroconversion catalyst. The reactor (98) is usually equipped with a recirculation pump (100), ensuring that the catalyst is in a fluidized bed state by continuously recirculating at least a portion of the liquid taken from the upper part of the reactor and then introduced into the lower part of the reactor. Fresh catalyst can be added through the top or bottom of the reactor (not shown). The addition of catalyst may be carried out in batch or continuous mode. Spent catalyst can be discharged from the bottom of the reactor (not shown) to remove or regenerate by removing carbon and sulfur before reloading it through the top of the reactor. The partially spent catalyst discharged from the bottom of the first reactor can also be transferred directly to the top of the second hydroconversion reactor (102) (not shown). If necessary, the converted stream (104) leaving the reactor (98) can be directed to separate the light fraction (106) into the bypass separator (108).

All or part of the stream (110) leaving the bypass separator (108) is preferably mixed with additional hydrogen (157), optionally preheated (not shown). This mixture is then piped (112) to a second fluidized bed hydroconversion reactor (102) operating in an upward flow of liquid and gas and containing at least one hydroconversion catalyst. Operating conditions, in particular temperature, in this reactor are chosen in order to achieve the desired degree of conversion as previously described. The addition and discharge of the catalyst is carried out in a similar manner as described in the case of the first reactor. The reactor (102) is usually also equipped with a recirculation pump (114), which functions in the same way as the pump in the first reactor.

The effluent from the fluidized bed reactors is sent via line (134) to a high-temperature high-pressure separator (HPHT) (136), at the outlet of which a gas fraction (138) and a liquid fraction (140) are obtained. The gas fraction (138) is generally directed through a heat exchanger (not shown) or an air cooler (142) for cooling in front of the low-temperature high-pressure separator (HPBT) (144), at the outlet of which a gas fraction (146) containing gases (H ₂ , H ₂ S, NH ₃ , hydrocarbons C ₁ -C ₄ , etc.), and the liquid fraction (148).

The gas fraction (146) from the low-temperature high-pressure separator (HPBT) (144) is treated in a hydrogen purification unit (150), at the outlet of which hydrogen (152) is obtained for recirculation through a compressor (154) and line (156) and / or line (157) to the hydroconversion section. The hydrogen purification unit may be an amine wash device, a membrane device, a PSA type system. Gases containing undesired nitrogen and sulfur compounds are removed from the unit (stream (158), which may be multiple streams, in particular a stream with a high H ₂ S content and one or more purge streams containing light hydrocarbons (C ₁ -C ₂ ) that can be used in gaseous fuels of a refinery).

The liquid fraction (148) from the low temperature high pressure separator (HPBT) (144) is expanded in the device (160) and then sent to the fractionation system (172). If necessary, after the expander (160), a medium pressure separator (not shown) can be installed to separate the vapor fraction, which is sent to the purification unit (150) and / or to a special medium pressure purification unit (not shown), and a liquid fraction, which sent to the fractionation section (172).

The liquid fraction (140) coming after high-temperature high pressure separation (HPHT) (136) is expanded in the device (174) and then sent to the fractionation system (172). If necessary, after the expander (174), a medium pressure separator (not shown) can be installed to separate the vapor fraction, which is sent to the purification unit (150) and / or to a special medium pressure purification unit (not shown), and a liquid fraction, which sent to the fractionation section (172).

It is obvious that fractions (148) and (140) can be sent together, after expansion, to system (172). The fractionation system (172) includes an atmospheric distillation system to produce a gas stream (176) of at least one fraction (178) called light and containing, in particular, solvent naphtha, kerosene and gas oil, and atmospheric residue fractions (180) ) A portion of the atmospheric residue fraction (180) can be taken along line (182) to form the required liquid fuel bases. All or part of the fraction of atmospheric residue (180) can be sent to a vacuum distillation column (184) to isolate a fraction containing a vacuum residue (186) and a fraction of a vacuum distillate (188) containing vacuum gas oil. At least a portion of the fraction of the vacuum residue is preferably recycled via line (190) to the hydroconversion stage or to the inlet of the hydroprocessing stage (line not shown) in order to increase the degree of conversion. If necessary, the atmospheric residue fraction (182), the vacuum distillate fraction (188) and / or the vacuum residue fraction (186) can be directed to the stage of separation of fine particles and precipitates, for example, in filters (191), (192) and (193 ) respectively.

An alternative scheme not shown for separation and fractionation may be carried out using a steam stripping column in which one or more heavy fractions from high, medium, or low pressure separators are treated. In this case, the bottom residue from the stripping column goes directly to the vacuum distillation column; The atmospheric distillation column is used to process distillate mixtures, but is not used to process the unconverted fraction (the heaviest).

In FIG. 3 shows another method of the present invention with intermediate separation without pressure reduction. Hereinafter, only differences between the method of FIG. 3 and the method shown in FIG. 1, while the stages of hydroprocessing, hydroconversion and separation after hydroconversion (including their reference positions) are completely identical.

The stream processed in the hydroprocessing reactors is sent via line (42) to a high-temperature high-pressure separator (HPHT) (44), at the outlet of which a lighter fraction (46) and a residual fraction (48) are obtained. The cut-off temperature of the fraction is generally in the range from 200 to 400 ° C.

The residual fraction (48) is sent immediately after possible passage through the furnace (92) to the hydroconversion section.

The lighter fraction (46) is generally sent through a heat exchanger (not shown) or an air cooler (50) for cooling in front of the low-temperature high-pressure separator (HPBT) (52), at the outlet of which a gas fraction (54) containing gases ( H ₂ , H ₂ S, NH ₃ , hydrocarbons C ₁ -C ₄ , etc.), and the liquid fraction (56).

The gas fraction (54) from the low-temperature high-pressure separator (HPBT) (52) is treated in a hydrogen purification unit (58), at the outlet of which hydrogen (60) is obtained for recirculation through a compressor (154) and lines (64) and (156) ) to the hydrotreatment and / or hydroconversion section. Gases containing undesired nitrogen, sulfur and oxygen derivatives are removed from the unit (stream (66)). In this configuration, only one compressor (154) is used to supply the required hydrogen to the entire reactor complex.

The liquid fraction (56) coming from the low temperature high pressure separator (HPBT) (52) is expanded in the device (68) and then sent to the fractionation system (70). The fractionation system (70) includes an atmospheric distillation system for producing a gas stream (74) of at least one fraction (76) called light and containing, in particular, solvent naphtha, kerosene and gas oil, and atmospheric residue fractions (195) ) A portion of the atmospheric residue fraction can be sent via line (195) to hydroconversion reactors, while another portion of the atmospheric residue fraction (194) can be sent to another process (hydrocracking or FCC, or hydroprocessing).

EXAMPLES

The present invention is illustrated by this example without limiting the scope of patent protection.

Was processed vacuum residue (RSV Oural), containing 87.0% of the mass. compounds boiling at temperatures above 520 ° C, with a density of 9.5 ° API and a sulfur content of 2.72% of the mass. The feedstock contains 254 million ^-1 metals (Ni + V).

The feedstock was processed at the hydroprocessing stage, which includes two interchangeable reactors. The load distribution of the HDM / HDS catalysts is 63/27. Operating conditions are shown in table 1.

Table 1
Fixed bed operating conditions HDM and HDS catalysts NiMo Alumina Temperature ° C 370 Pressure, MPa fifteen VVH (h ^-1 , st. M ³ / h of fresh raw materials / m ³ catalyst in a fixed bed) 0.18 H ₂ / HC at the inlet to the fixed bed section without consumption of H ₂ (nm ³ / m ³ fresh feed) 1000

The HDM hydrodemetallization rate in the fixed-bed HDT section exceeds 80%.

The hydroprocessing effluent was then separated in a high temperature high pressure flash (HPHT) separator.

The heavy fraction (fraction 350 ° C) was sent to the hydroconversion stage, which includes two successive fluidized bed reactors. Operating conditions are shown in table 2.

table 2
Fluidized bed operating conditions Catalyst NiMo Alumina Fluidized bed temperature R1, ° C 418 Fluidized bed temperature R2, ° C 428 Pressure, MPa 16 VVH (h ^-1 , st. M ³ / h of fresh raw materials / m ³ volume of fluidized bed reactors) 0.3 H ₂ / HC at the entrance to the section with a fluidized bed without the consumption of H ₂ (nm ³ / m ³ fresh raw materials) 1000

The output and sulfur content for each fraction obtained from the stream leaving the installation as a whole are presented in table 3.

Table 3
The output and sulfur content in the stream leaving the section with a fluidized bed (% wt. / Feedstock) Products Yield,% mass. The content of S,% of the mass. NH ₃ 0.7 0 H ₂ s 2.7 94.12 C ₁ -C ₄ (gas) 3.8 0 Solvent naphtha (t _flash = 150 ° C) 8.0 0.02 Gas oil (150-350 ° C) 22.7 0.05 Vacuum distillate (350-520 ° C) 29.5 0.26 Vacuum residue (520 ° C ⁺ ) 34.3 0.43

The amount of hydrogen consumed is 1.69% of the mass of fresh raw materials supplied to the inlet of the hydroprocessing section.

The yield values given above allow us to calculate the degree of conversion of the fraction of the feedstock boiling at a temperature above 520 ° C and converted into products boiling at a temperature below 520 ° C using the following formula:

Conversion rate = (amount of fraction 520 ° C ⁺ in the feedstock) - (amount of fraction 520 ° C ⁺ in the leaving stream) (amount of fraction 520 ° C ⁺ in the feedstock)

Numerical data give: the degree of conversion = (87.0-34.3) / 87.0 = 60.5%.

This particularly high degree of conversion characterizes the production of conversion products (mainly distillates) in significant quantities.

Next, a mixture was prepared based on the fractions 350-520 ° C and 520 ° C ⁺ obtained at the hydroconversion stage, in the following proportions:

- fraction 350-540 ° C: 48% by weight of the mixture;

- fraction 520 ° C ⁺ : 52% by weight of the mixture.

Thus was obtained liquid fuel with a sulfur content of 0.35% of the mass. and with a viscosity of 380 cSt at 50 ° C. In addition, the content of precipitation after aging was less than 0.1% of the mass. Based on these results, this liquid fuel is preferably acceptable for the formation of bunker fuel in accordance with IMO recommendations outside the ZCES zone as of 2020-2025.

In addition, from the first mixture leading to the production of liquid fuel containing 0.35% sulfur, a second mixture was prepared, consisting of 80% of the mass. from the fraction originating from the gas oil fraction, and 20% of the mass. from a fraction originating from a fraction of a vacuum distillate. In the case of these proportions, the mixture contains sulfur in an amount of 0.09% and has a viscosity of 6 cSt at 40 ° C. Thus, this mixture forms distillate marine fuel (“marine gas-oil” or marine diesel according to English terminology), which can be identified, for example, with the DMB brand (in the case of which, according to the technical conditions, the viscosity is in the range from 2 to 11 cSt at 40 ° C). Due to a sulfur content of less than 0.1%, this mixture forms high-quality fuel for use in the ZCES zone as of 2015.

Claims (33)

1. A method of processing a hydrocarbon feedstock in which the sulfur content is at least 0.5 wt%, the initial boiling point is at least 340 ° C, and the final boiling point is at least 440 ° C, and the method allows to obtain at least one liquid hydrocarbon fraction with a sulfur content of less than or equal to 0.5 wt%, and includes the following successive steps: a) a stage of hydroprocessing in a fixed bed, in which the hydrocarbon feed and hydrogen are brought into contact with at least one hydroprocessing catalyst, b) the stage of separation of the stream obtained at the exit of stage (a) hydrotreatment, at least one light fraction and at least one heavy fraction, c) a step for hydroconversion of at least a portion of the heavy fraction of the stream coming from step (b) in at least one fluidized bed reactor containing a supported catalyst, and d) a step for separating the stream from step (c) to obtain at least one gas fraction and at least one liquid hydrocarbon fraction, in which stage (a) hydrotreatment includes the first stage (a1) of hydrodemetallization (HDM), carried out in one or more zones of hydrodemetallization with fixed layers, and the subsequent stage (a2) of hydrodesulfurization (HDS), carried out in one or more zones of hydrodesulfurization with fixed layers. 2. The method according to claim 1, in which the hydroprocessing step (a) is carried out at a temperature in the range from 300 to 500 ° C and at an absolute pressure in the range from 2 to 35 MPa with a space velocity of hydrocarbon feedstock in the range from 0.1 to 5 h ^-1 , while the amount of hydrogen mixed with the feedstock is in the range from 100 to 5000 nm ³ / m ³ . 3. The method according to claim 1, in which the hydroconversion stage (c) is carried out at an absolute pressure in the range from 2.5 to 35 MPa and at a temperature in the range from 330 to 550 ° C with a space velocity in the range from 0.1 to 10 h ^-1 , while the amount of hydrogen mixed with the feedstock is from 50 to 5000 nm ³ / m ³ . 4. The method according to claim 1, in which stage (a) hydroprocessing is carried out in one or more zones of hydroprocessing with fixed layers, which is preceded by at least two zones of protection of hydroprocessing also with fixed layers, connected in series for cyclic use, consisting in sequential repeating steps a '') and a '' ') defined below: a ') the stage at which the protection zones are used together for a period of time not exceeding the time of decontamination and / or clogging of one of them, a '') a stage during which the deactivated and / or clogged protection zone is blocked and the catalyst contained therein is regenerated and / or replaced with a fresh catalyst, and during which one or more other protection zones are used, and a '' ') the stage during which the protection zones are shared, while the protection zone is again connected, the catalyst of which was regenerated and / or replaced during the previous stage, and this stage lasts for a period of time not exceeding the decontamination time and / or clamming one of the protection zones. 5. The method according to claim 1, in which the hydrocarbon feedstock is selected from atmospheric residues, vacuum residues from direct distillation, crude oil, crude oil devoid of the lightest fractions, deasphalted oils, resins formed during deasphalting, asphalts or asphalt bitumen, residues arising from deasphalting, residues from conversion processes, extracts of aromatic compounds from plants for the production of bases for lubricants, tar sands or their derivatives, tar shales or their derivatives, oils derived from source rocks, or their derivatives, used individually or in a mixture. 6. The method according to claim 1, in which the stream coming from stage (a) of the hydroprocessing is directed to stage (b) of separation under reduced pressure, which includes the following stages, in which: - the stream exiting from stage (a) is directed to a fractionation section in which the cut-off temperature of the fraction is in the range from 200 to 400 ° C and which allows to obtain light and heavy fractions, - then the heavy fraction is separated by atmospheric distillation into at least one atmospheric distillate fraction containing preferably at least one light fraction of hydrocarbons such as solvent naphtha, kerosene and / or gas oil, and an atmospheric residue fraction, at least a portion of the atmospheric residue fraction is separated by vacuum distillation into a vacuum distillate fraction, preferably containing a vacuum gas oil, and a vacuum residue fraction, and - at least a portion of the fraction of the vacuum residue and / or fraction of the atmospheric residue is preferably sent to the hydroconversion stage (c). 7. The method according to claim 1, in which the stream coming from stage (a) hydrotreatment, is directed to stage (b) of separation without pressure reduction, which includes the following stages, in which: - the stream leaving the hydrotreatment stage (a) is sent to a fractionation section in which the cut-off temperature of the fraction is in the range from 200 to 400 ° C and which allows to obtain at least one light fraction and at least one heavy fraction, - the heavy fraction is sent directly to stage (c) hydroconversion, - the light fraction is sent to atmospheric distillation, which allows to obtain a gas fraction, at least one light fraction of liquid hydrocarbons such as solvent naphtha, kerosene and / or gas oil, and a fraction of vacuum distillate, and - the fraction of the vacuum distillate is at least partially sent to the hydroconversion stage (c). 8. The method according to claim 1, wherein the separation step (d) further comprises at least one atmospheric distillation unit, in which one or more liquid hydrocarbon fractions obtained after separation are separated by atmospheric distillation into at least one atmospheric distillate fraction and at least one fraction of atmospheric residue. 9. The method according to claim 1, wherein the separation step (d) further comprises at least one vacuum distillation unit, in which one or more liquid hydrocarbon fractions obtained after separation, and / or an atmospheric residue fraction obtained after atmospheric distillation, separated by vacuum distillation of at least one fraction of a vacuum distillate and at least one fraction of a vacuum residue. 10. The method according to claim 9, in which part of the fraction of the vacuum residue is recycled to stage (c) hydroconversion. 11. The method according to claim 9, further comprising a step (e) of separating precipitation and fine particles, wherein at least a fraction of the atmospheric residue and / or vacuum distillate and / or vacuum residue is directed to separating precipitation and fine catalyst particles with using at least one filter, a centrifugation or decantation system connected in series. 12. The method according to claim 9, further comprising a catalytic cracking step (f), wherein at least a portion of the vacuum distillate fraction and / or the vacuum residue fraction, optionally pretreated at the stage of separating sediments and fine particles (e), is sent in the catalytic cracking section, in which it is processed under conditions allowing to obtain gas, gasoline, gas oil and residual fractions. 13. The method according to claim 9, in which the atmospheric residue and / or vacuum distillate and / or vacuum residue obtained at the outlet of separation stage (d) and, if necessary, preliminarily processed in stage (e) of separating precipitation and fine particles , mixed with one or more thinning bases selected from the group consisting of light recycle gas oils from catalytic cracking, heavy recycle gas oils from catalytic cracking, residue from catalytic cracking, kerosene, gas oil, vacuum distillation and / or decant oil. 14. The method according to item 13, in which the thinning base is selected from part of a light fraction of hydrocarbons such as kerosene or gas oil obtained at the output of separation stage (b), part of a heavy fraction of hydrocarbons such as vacuum distillate obtained at the output of separation stage (b), and parts of the gasoline fraction, gas oil fraction and / or residual fraction obtained at the outlet of catalytic cracking step (f). 15. Liquid fuel suitable for use in maritime transport and obtained by the method according to item 13 or 14, with a sulfur content of less than or equal to 0.5% of the mass. and preferably less than or equal to 0.1% of the mass. 16. Liquid fuel according to clause 15, characterized in that the precipitation therein is less than or equal to 0.1% of the mass. 17. Liquid fuel according to item 15 or 16, characterized in that its viscosity is in the range from 1 to 700 cSt at 50 ° C.

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