KR102289270B1 - Process with separation for treating petroleum feedstocks for the production of fuel oils with a low sulphur content - Google Patents

Abstract

A process with separation for treating petroleum feedstocks for the production of fuel oils with low sulfur content. The present invention relates to a process for processing heavy petroleum feedstocks for the production of fuel oils and fuel oil bases having a low sulfur content, in particular bunker fuels and bunker fuel bases. The process comprises a fixed-bed hydrotreating step (a) of heavy sulfur hydrocarbons, followed by a separation step (b) of the effluent obtained from the hydrotreating step (a) into at least one light fraction and at least one heavy fraction; a hydroconversion step (c) of at least a portion of the heavy fraction of the effluent obtained from step (b) in at least one effervescent bed reactor containing a catalyst, and a step (c) to obtain at least one gaseous fraction and at least said liquid hydrocarbon fraction ) of separation of the effluent obtained from (d).

Description

PROCESS WITH SEPARATION FOR TREATING PETROLEUM FEEDSTOCKS FOR THE PRODUCTION OF FUEL OILS WITH A LOW SULPHUR CONTENT

The present invention relates to the refining and conversion of heavy hydrocarbon fractions containing sulfur-based impurities among heavy fractions. The invention relates more particularly to the production of fuel oils and fuel oil bases with low sulfur content, in particular bunker fuels and bunker fuel bases. It relates to a process for processing heavy petroleum feedstocks for

Regulations on sulfur content in fuels for terrestrial use, typically gasoline and diesel, have become very stringent in recent decades, but regulations on sulfur content in marine combustion products have so far been relatively unrestricted. Specifically, combustibles for marine applications currently on the market may contain up to 3.5 wt % or even 4.5 wt % sulfur. As a result, ships were becoming a major source of emissions of _{sulfur dioxide (SO 2 ).}

To reduce these emissions, the International Maritime Organization (IMO) has submitted recommendations in terms of specifications for marine combustion products (Annex VI to the MARPOL Convention). These Recommendations are subdivided into the 2012 version of ISO standard 8217. The current recommendations relate to emissions of _{SO x from marine combustion.} The recommended equivalent sulfur content for a 2020 or 2025 horizon is 0.5 wt % or less for ships operating outside of “Sulfur Emission Control Areas” (SECA). Within the SECA, the IMO expects an equivalent sulfur content of 0.1 wt % or less in the 2015 Horizon.

Also, another very restrictive recommendation relates to the content of sediments after aging according to ISO standard 10307-2, which should be less than 0.1 %.

Applicants have found that fuel oils and fuel oil bases, in particular bunker fuels and bunker fuels, which meet the recommendations of the MARPOL Convention in terms of equivalent sulfur content and preferably also meet the recommendations on the content of sediments after degradation. The purpose of producing the bases was set by themselves.

Fuel oils used in marine transport are atmospheric distillates, vacuum distillates derived from direct distillation or from refining processes, in particular hydrotreatment and conversion processes. , atmospheric residues and vacuum residues in general, which fractions may be used alone or as mixtures. One of the objects of the present invention is to propose a process for the conversion of heavy petroleum feedstocks for the production of fuel oils and fuel oil bases with very low sulfur content, in particular bunker fuels and bunker fuel bases. Another object of the present invention is to jointly produce atmospheric distillates (naphtha, kerosene, diesel), vacuum distillates and/or light gases (C1 to C4) by the same process. Bases of the naphtha and diesel type may be upgraded in refineries for the production of automotive and aviation fuels, eg superfuels, jet fuels and diesel oils.

Processes for refining and converting heavy petroleum feedstocks comprising a first stage of fixed-bed hydroprocessing followed by a stage of ebullated-bed hydroconversion are described in patents FR 2764300, CA 1238005 , EP 1343857 and EP 0665282. EP 0665282, which describes a process for the hydrotreatment of heavy oils, relates to extending the useful life of reactors. CA 1238005 describes a process for the conversion of a heavy liquid hydrocarbon-based feedstock using several reactors in series, in which the degree of conversion is improved by special recycling of the heavy fraction obtained. The process described in FR 2764300 per se relates to obtaining fuel oil bases, in particular not bunker fuel bases, but fuels with a particularly low sulfur content (petroleum and diesel). In addition, the feedstocks treated in this process contain little or no asphaltenes. Finally, the process disclosed in EP 1343857 is described as a hydrotreating process which may utilize a hydrodemetallation section and a hydrodesulfurization section which may follow a guard zone of a replaceable reactor type. do.

None of these documents support the production of fuel oil or fuel oil bases with a very low sulfur content that meets the new recommendations of the International Maritime Organization and with a low content of sediments as required by the new version of ISO standard 8217:2012. do not explain

One of the objects of the present invention is to adapt and improve the conversion processes described in the prior art, in particular for the production of fuel oils and fuel oil bases having a low sulfur content.

Through research studies, the applicant surprisingly found that the improvement of existing processes in terms of the production of fuel oil bases and in terms of the quality of said fuel oil bases, in particular in the sulfur content and the sediment content, in a combination of different steps carried out in a specific sequence discovered that it is possible.

The subject matter of the invention is first of all a sulfur content of at least 0.5% by weight, an initial boiling point of at least 340° C. and at least 440, which makes it possible to obtain at least one liquid hydrocarbon fraction having a sulfur content of up to 0.5% by weight. A process for treating a hydrocarbon feedstock having a final boiling point of °C, comprising the following successive steps:

a) a fixed bed hydrotreating step, wherein the hydrocarbon feedstock and hydrogen are placed in contact over at least one hydrotreating catalyst;

b) separation of the effluent from 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 effluent derived from step (b) in at least one effervescent bed reactor containing a supported catalyst, and

d) separating said effluent derived from step (c) to obtain at least one gaseous fraction and at least said liquid hydrocarbon fraction.

A subject matter of the invention is also a fuel oil, which may be used in sea transport, obtained from this process having a sulfur content of 0.5% by weight or less, preferably 0.1% by weight or less.

1 shows an embodiment of a process according to the invention with intermediate separation of the effluent between a fixed bed section and an effervescent bed section, with decompression of the heavy fraction;
FIG. 2 shows the protected areas of the hydroprocessing section of FIG. 1 at a larger scale for better readability;
3 shows another embodiment of the process according to the invention with intermediate separation of the effluent between a fixed bed section and an effervescent bed section, without decompression of the heavy fraction;

Throughout this description, it is pointed out that "... to ..." should be understood to include the recited limits.

The process according to the invention thus comprises a first step (a) of a fixed bed hydrotreating, followed by a separation step (b) of the hydrocarbon effluent into a light fraction and a heavy fraction, followed by an effervescent bed hydrogenation of the heavy fraction a conversion step (c), and finally a separation step (d).

At the same time, the purpose of hydrotreating is to improve the hydrogen to carbon ratio (H/C) while also converting the hydrocarbon feedstock somewhat partially into lighter fractions, i.e. refining metals, sulfur and It is to substantially reduce the content of other impurities. Next, the effluent obtained in the fixed bed hydrotreating step (a) is subjected to a separation step to obtain different fractions. This separation makes it possible to remove, from the effluent obtained after hydrotreating step (a), lighter fractions which do not require only intermediate treatment or further treatment from the heavier fractions. The heavier fractions are sent to effervescent bed hydroconversion stage (c), which is used wholly or in part as a fuel oil or fuel oil base, in particular as a bunker fuel or a bunker fuel base, to produce an effluent which may be advantageously used It makes it possible to partially convert the hydrocarbon effluent obtained from treatment step (a).

One of the advantages of carrying out the fixed-bed hydroprocessing and then the effervescent bed hydroconversion in sequence lies in the fact that the feedstock of the ebullated-bed hydroconversion reactor is already at least partially hydrotreated. In this way, in particular, it is possible to obtain an equivalent conversion of hydrocarbon emissions of better quality with lower sulfur contents. Moreover, the consumption of catalyst in an effervescent bed hydroconversion reactor is greatly reduced compared to that of a process without conventional fixed bed hydrotreating.

The process according to the invention is also characterized in that it comprises an intermediate separation step (b) between the hydrotreating step (a) and the hydroconversion step (c). This separation step advantageously makes it possible to minimize the fraction to be treated in the boiling bed. In this way, the capacity of the effervescent bed hydroconversion may be reduced. Similarly, overcracking of the light fractions and thus loss of yield of fuel-type fractions is avoided.

The process according to the invention advantageously produces, in high yield and with high energy efficiency, light fractions, fuel oils and fuel oil bases with a low sulfur content, in particular for marine use, from a sulfur-containing heavy hydrocarbon feedstock. make it possible to do

hydrocarbon feedstock

The hydrocarbon feedstock treated in the process according to the invention may also be referred to as "heavy feedstock". It has an initial boiling point of at least 340°C and a final boiling point of at least 440°C. Preferably, its initial boiling point is at least 350° C., preferentially at least 375° C., and its final boiling point is at least 450° C., preferentially at least 460° C., more preferentially at least 500° C. and even more preferentially at least 600° C.

Hydrocarbon feedstock, taken alone or as a mixture, is atmospheric residues, vacuum residues derived from direct distillation, crudes, de-headed crudes, de-asphalted oils, de-asphalted oils - Asphalt resins, de-asphalted pitches or asphalts, residues derived from conversion processes, aromatic extracts derived from lubricating oil base production lines, bituminous sand ) or derivatives thereof, bituminous shales or derivatives thereof, parent-rock oils or derivatives thereof. In the present invention, the feedstocks to be treated are preferably atmospheric residues or vacuum residues, or mixtures of these residues.

Additionally, the hydrocarbon feedstock treated in the process according to the invention contains sulfur. Its sulfur content is at least 0.5% by weight, preferentially at least 1% by weight, more preferentially at least 4% by weight, and even more preferentially at least 5% by weight.

Additionally, the hydrocarbon feedstock treated in the process according to the invention may contain asphaltenes. Its asphaltene content may be at least 2% by weight. In the present description, the term “asphaltene” means heavy hydrocarbon compounds that are insoluble in n-heptane (also referred to as C7 asphaltenes) but soluble in toluene. Quantification of asphaltenes generally includes normalized analyzes as defined, for example, in standards AFNOR T 60-115 (France) or ASTM893-69 (USA).

The content of nickel and vanadium (Ni+V) metals in the feedstock is preferentially greater than 110 weight ppm and more preferentially greater than 150 weight ppm.

These feedstocks may advantageously be used in unmodified form. Alternatively, they may be diluted with co-feedstock. This co-feedstock is preferably products derived from a fluid catalytic cracking (FCC) process, light cycle oil (LCO), heavy cycle oil (HCO), decan may be selected from decanted oil, FCC residues, gas oil fractions, in particular fractions obtained by atmospheric or reduced pressure distillation, for example atmospheric gas oils, or alternatively to be derived from another refining process It may also be a lighter hydrocarbon fraction, or a mixture of lighter hydrocarbon fractions. The co-feedstock is also advantageously one or more fractions derived from the process of liquefaction of charcoal or biomass, aromatic extracts, or any other hydrocarbon fraction or alternatively pyrolysis oil (pyrolysis oil). ) may be non-petroleum feedstocks such as The heavy hydrocarbon feedstock according to the invention represents at least 50% by weight, preferentially 70% by weight, more preferentially at least 80% by weight and even more preferentially at least 90% by weight of the total hydrocarbon feedstock processed through the process according to the invention. may be

Hydrotreating step (a)

According to the process of the present invention, the hydrocarbon feedstock is subjected to a fixed bed hydrotreating step (a) in which the feedstock and hydrogen are placed in contact over a hydrotreating catalyst.

The term "hydroprocessing", commonly referred to as HDT, improves the hydrogen-to-carbon ratio of the feedstock while at the same time converting the feedstock more or less partially into lighter fractions, while refining i.e. metals, sulfur and means catalytic treatments with a supply of hydrogen which makes it possible to substantially reduce the content of other impurities, hydrocarbon feedstocks. Hydrotreatment is, inter alia, hydrogenation, hydrodeoxygenation, hydrodearomatization, hydroisomerization, hydrodealkylation and hydrocracking and hydrodeasphalting. ) reactions and the Conradson carbon reduction reaction, hydrodesulfurization reactions (commonly known as HDS), hydrodeazotization reactions (commonly known as HDN), and hydrodemetallation reactions (commonly known as HDM).

According to a preferred variant, the hydrotreating step (a) comprises a first step (a1) of hydrodemetallization (HDM) carried out in one or more fixed-bed hydrodesulfurization zones and hydrodesulphurization carried out in one or more fixed-bed hydrodesulfurization zones. a second subsequent step (a2) of (HDS). During the first step (a1) of the hydrodemetallization, the feedstock and hydrogen are placed in contact over a hydrodemetallization catalyst under hydrodemetallization conditions, then during the second step (a2) of the hydrodesulfurization, The effluent from the first stage (a1) of hydrodemetallization is placed in contact with a hydrodesulphurization catalyst under hydrodesulphurization conditions. This process, known as HYVAHL-F™, is described, for example, in patent US 5417846.

A person skilled in the art will readily understand that in the hydrodemetallization step, hydrodemetallization reactions are carried out, but also in parallel therewith, other hydroprocessing reactions and in particular some of the hydrodesulfurization reactions. Similarly, in the hydrodesulphurization step, hydrodesulphurization reactions are carried out, but also in parallel thereto, other hydroprocessing reactions and in particular hydrodemetallization reactions. A person skilled in the art understands that the hydrodemetallization step begins when the hydrotreating step begins, ie when the metal concentration is at a maximum. A person skilled in the art understands that the hydrodesulphurization step ends when the hydrotreating step ends, ie when the removal of sulfur is the most difficult. Between the hydrodemetallization step and the hydrodesulphurization step, a person skilled in the art accidentally defines a transition zone in which all types of hydrotreating reactions take place.

The hydrotreating step (a) according to the invention is carried out under hydrotreating conditions. It may advantageously be carried out at a temperature of 300°C to 500°C, preferably 350°C to 420°C, and at an absolute pressure of 2 MPa to 35 MPa, preferably 11 MPa to 20 MPa. The temperature is typically adjusted as a function of the desired level of hydrotreatment and the targeted treatment duration. Typically, the hourly space velocity of a hydrocarbon feedstock, commonly known as HSV, defined as the volumetric flow rate of the feedstock divided by the total volume of the catalyst, is 0.1 h ^-1 to 5 h ^-1 , preferentially as 0.1 h ^-1 to 2 h ^-1 , more preferentially 0.1 h ^-1 to 0.45 h ^-1 , and even more preferentially 0.1 h ^-1 to 0.2 h ^-1 . The amount of hydrogen mixed with the feedstock is between 100 and 5000 normal cubic meters (Nm ^{3 ) per cubic meter (m 3} ) of the liquid feedstock, preferentially between 200 Nm ³ /m ³ and 2000 Nm ³ /m ³ , more preferentially As 300 Nm ³ /m ³ to 1500 Nm ³ /m ³ may be. The hydrotreating step (a) may be carried out industrially in one or more descending-liquid reactors.

(감마) 또는

(에타) 알루미나일 수도 있다. 이 촉매는 통상적으로 압출물 (extrudate) 의 형태이다. VIB 족 및 VIII 족 금속 산화물들의 총 함량은 5 중량% 내지 40 중량%, 일반적으로 7 중량% 내지 30 중량% 일 수도 있고, VIB 족 금속 (들) 및 VIII 족 금속 (들) 사이의 금속 산화물로서 표현된 중량 비율은 일반적으로 20 내지 1 이고, 통상적으로 10 내지 2 이다.The hydrotreating catalysts used are preferably known catalysts. These may be granular catalysts comprising, on a support, at least one metal or metal compound having a hydrogenation-dehydrogenation function. These catalysts may advantageously be catalysts comprising at least one group VIII metal, generally selected from the group consisting of nickel and cobalt, and/or at least one group VIB metal, preferably molybdenum and/or tungsten. . For example, 0.5% to 10% by weight of nickel, preferably 1% to 5% by weight of nickel (expressed as nickel oxide NiO), and 1% to 30% by weight of molybdenum, on the inorganic carrier, Catalysts comprising preferably 5% to 20% by weight of molybdenum ( _{expressed as molybdenum oxide MoO 3} ) may be used. This carrier may be selected, for example, from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. Advantageously, the support may contain other dopant compounds, in particular oxides selected from the group consisting of boron oxide, zirconia, serine, titanium oxide, phosphorus pentoxide and mixtures of these oxides. Typically, an alumina support is used, and very generally an alumina support doped with phosphorus and optionally boron. When phosphorus pentoxide P ₂ O ₅ is present, its concentration is less than 10% by weight. When boron trioxide B ₂ O ₃ is present, its concentration is less than 10% by weight. Alumina used

(gamma) or

It may be (eta) alumina. This catalyst is usually in the form of an extrudate. The total content of Group VIB and Group VIII metal oxides may be from 5% to 40% by weight, generally from 7% to 30% by weight, as a metal oxide between the Group VIB metal(s) and the Group VIII metal(s) The weight ratio expressed is generally from 20 to 1, usually from 10 to 2.

In the case of a hydrotreatment step comprising a hydrodemetallization (HDM) step followed by a hydrodesulfurization (HDS) step, specific catalysts tailored to each step are preferably used.

Catalysts which may be used in the HDM step are indicated, for example, in patents EP 0113297, EP 0113284, US 5221656, US 5827421, US 7119045, US 5622616 and US 5089463. HDM catalysts are preferably used in substitutable reactors.

Catalysts which may be used in the HDS step are indicated, for example, in patents EP 0113297, EP 0113284, US 6589908, US 4818743 or US 6332976.

Mixed catalysts active in HDM and HDS may also be used for both HDM and HDS sections, as described in patent FR 2940143.

Prior to feeding the feedstock, the catalyst used in the process according to the invention is preferably subjected to an in-situ or ex-situ sulfiding treatment.

According to a preferred embodiment of the invention, the fixed bed hydroprocessing stage (a) uses, on the upstream side of the main hydroprocessing reactors, a system of substitutable reactors, also known as protected zones. More specifically, the hydrotreating step (a) is in fixed beds, arranged in series to be used in a cyclic manner consisting of successive repetitions of steps a'') and a''') as defined below. It may be carried out in one or more fixed bed hydroprocessing zones followed by at least two hydroprocessing protected zones:

a') the protected areas are all used together for a period that is less than or equal to the inactivation and/or clogging time for one of them;

a'') the deactivated and/or clogged protected zone is short-circuited, the catalyst contained in this protected zone is regenerated and/or replaced with fresh catalyst, while other protected zone(s) are used, and

a''') the protected zones are all used together, the catalyst is regenerated and/or the replaced protected zone is reconnected during the preceding step, said step being the deactivation of one of the protected zones and/or A method for treating a hydrocarbon feedstock, the step being continued for a period of time less than or equal to a clogging time.

Preferably, after regeneration and/or replacement of the catalyst in the reactor, this reactor is connected again downstream of the functioning reactor.

A system of substitutable reactors is known from patents FR 2681871, FR 2784687, and EP 1343857. The function of the substitutable reactors is to protect the main downstream hydroprocessing reactors by preventing clogging and/or deactivation. Specifically, a problem encountered during the use of fixed beds is clogging, which arises from sediments and asphaltenes contained in the feedstock. Another problem is catalyst deactivation due to the high deposition of metals that occur during hydrotreating reactions. Accordingly, the replaceable reactors increase the operating cycle of the hydrotreating unit by allowing the replacement of deactivated and/or clogged catalyst only in the substitutable reactors functioning in a cyclic manner, without shutting down the entire unit for any period of time. is used for

The deactivation and/or clogging time varies as a function of the feedstock, the operating conditions of the hydroprocessing stage and the catalyst used. It may be an increase in the concentration of metals and/or other impurities in the effluent, an increase in the temperature required to maintain the activity of the catalyst, or, in the particular case of clogging, a significant increase in pressure loss. It is generally expressed by the degradation in catalytic performance that may be observed. The pressure loss ΔP, which expresses the degree of clogging, may be measured permanently throughout the cycle for each of the zones, defined by the increase in pressure resulting from a partially blocked passage of flow through the zone. may be Similarly, the temperature may be measured permanently throughout the cycle for each of the two zones.

In order to define the deactivation and/or clogging time, the person skilled in the art will first of all know, for the selected operating conditions and catalysts, the maximum acceptable function of the feedstock to be treated, at which point disconnection of the protected zone should be performed. Define the pressure loss value ΔP and/or temperature. The deactivation and/or clogging time is thus defined as the time at which the limit values of pressure loss and/or temperature are reached. For heavy fraction hydrotreating processes, the limiting value of the pressure loss is generally from 0.3 MPa to 1 MPa (3 to 10 bar), preferably from 0.5 MPa to 0.8 MPa (5 to 8 bar). The limit value of the temperature is generally 400° C. to 430° C., and the temperature corresponds to the average measured temperature of the catalyst bed.

The operating conditions of the substitutable reactors are generally the same as those of the main hydroprocessing reactors. The hourly space velocity HSV values for each functioning substitutable reactor are preferentially from 0.2 h ^-1 to 4 h ^-1 , more preferentially from 1 h ^-1 to 2 h ^-1 . The overall hourly space velocity HSV values of the substitutable reactors and the HSV values of each reactor are selected to achieve maximum hydrodemetallization while controlling the reaction temperature, thus limiting exothermicity.

In a preferred embodiment of the invention, a catalyst control section is used which allows replacement of these functioning protected zones, ie without stopping the functioning of the unit. The catalyst control section may include the following elements:

- a system operating at medium pressure, preferentially between 1 MPa and 5 MPa (10-50 bar), preferentially between 1.2 MPa and 2.5 MPa (15-25 bar), with a guard disconnected before discharging spent catalyst said system making it possible to perform washing, stripping and cooling operations on the reactor and then heating and sulfiding after loading fresh catalyst;

- Another pressurization/depressurization and regulator-valve system of suitable technology, where all operations of cleaning, stripping, evacuating spent catalyst, refilling fresh catalyst, heating and sulfiding occur on a disconnected reactor or guard zone The pressurization/depressurization and regulator-valve system thus making it possible to replace these protection zones without shutting down the unit.

Alternatively, a presulfurized catalyst may be used in the control section to simplify the functional substitution procedure.

The effluent from the substitutable reactors may then be sent to the main hydroprocessing reactors.

Each hydrotreating zone or hydrotreating protected zone may contain at least one catalyst bed, for example 1, 2, 3, 4 or 5 catalyst beds. Preferably, each protected zone contains a catalyst bed. Each catalyst layer optionally contains at least one catalyst containing one or more catalysts, optionally followed by at least one inert layer of alumina or ceramic, for example in the form of extrudates, beads or pellets. It may contain a catalytic layer. The catalysts used in the catalyst layer(s) may be the same or different.

According to a particular embodiment, the hydrocarbon feedstock passes at the inlet of each protection zone through a filter plate located upstream of the catalyst bed(s) contained within the protection zone. This filter plate, described for example in patent FR 2889973, advantageously makes it possible to capture the clogging particles contained in the hydrocarbon feedstock by means of a specific distribution plate comprising a filtering medium.

separation step (b)

The effluent obtained after the fixed bed hydrotreating step (a) is subjected to at least one separation step, optionally completed together with other further separation steps, to separate at least one light fraction and at least one heavy fraction. The term “light fraction” means a fraction in which at least 90% of the compounds have a boiling point of less than 350°C. The term “heavy fraction” means a fraction in which at least 90% of the compounds have a boiling point of at least 350°C. Preferably, the light fraction obtained during separation step (b) comprises a gaseous phase and at least one light hydrocarbon fraction of the naphtha, kerosene and/or diesel type. Preferably, the heavy fraction comprises a vacuum distillate fraction, a vacuum residue fraction and/or an atmospheric residue fraction.

Separation step (b) may be performed via any method known to those skilled in the art. This method includes high or low pressure separation, high or low pressure distillation, high or low pressure stripping, liquid/liquid extraction, solid/liquid separation, centrifugation, and of these various methods that may be performed at different pressures and temperatures. It may be selected from combinations.

According to a first embodiment of the invention, the effluent derived from the hydrotreating step (a) is subjected to a separation step (b) with decompression.

According to this embodiment, the separation preferably first a fractionation section which may comprise a high-pressure high-temperature (HPHT) separator and optionally a high-pressure low-temperature (HPLT) separator. , then optionally in an atmospheric distillation section and/or a reduced pressure distillation section. The effluent from step (a) may be sent to a fractionation section having a cut-off point of 200° C. to 400° C., usually to an HPHT separator, making it possible to obtain a light fraction and a heavy fraction. In general, the separation is preferably not done at a precise cut-off point, but rather resembles a flash type separation.

Preferably, the heavy fraction is then subjected to atmospheric distillation into at least one atmospheric distillate fraction containing at least one light hydrocarbon fraction, preferably of naphtha, kerosene and/or diesel type, and an atmospheric residue fraction. may be differentiated. At least a part of the atmospheric residue fraction may also be fractionated by vacuum distillation into a vacuum distillate fraction, preferably containing a reduced pressure gas oil, and a reduced pressure residue fraction. At least a part of the reduced pressure residue fraction and/or the atmospheric residue fraction is advantageously sent to the hydroconversion step (c). A part of the reduced pressure residue may also be recycled to the hydrotreating step (a).

According to a second embodiment, the effluent derived from the hydrotreating step (a) is subjected to a separation step (b) without decompression.

According to this embodiment, the effluent from the hydrotreating step (a) is sent to a fractionation section having a cut-off point of 200 to 400° C., usually to an HPHT separator, to obtain at least one light fraction and at least one heavy fraction make it possible In general, the separation is preferably not done at a precise cut-off point, but rather resembles a flash type separation.

The heavy fraction may then be sent directly to the hydroconversion step (c).

The light fraction may be subjected to other separation steps. Advantageously, it may be subjected to atmospheric distillation, making it possible to obtain a gaseous fraction, at least one light fraction of liquid hydrocarbons of naphtha, kerosene and/or diesel type, and a reduced pressure distillation fraction, may possibly be sent at least partially to the hydroconversion step (c). Another portion of the vacuum distillate may be used as a fuel oil flux. Another portion of the vacuum distillate may be upgraded by going through fluid bed hydrocracking and/or catalytic cracking steps.

Separation without decompression allows for better heat integration and is reflected by savings in energy and equipment. Additionally, since it is not necessary to increase the pressure of the streams after separation before the subsequent hydroconversion step, this embodiment has technical-economic advantages. Intermediate fractionation without decompression is simpler than fractionation with decompression, thus the investment cost is advantageously reduced.

The gaseous fractions derived from the separation step are preferably subjected to a purification treatment in order to recover hydrogen and recycle it to the hydrotreating and/or hydroconversion reactors. The presence of an intermediate separation step between the hydrotreating step (a) and the hydroconversion step (c) advantageously allows two It makes it possible to provide independent hydrogen circuits. The input of hydrogen may occur on the hydrotreating section or on the hydroconversion section or both. Hydrogen for recycling may be fed to the hydrotreating section or the hydroconversion section or both. The compressor may optionally be common to the two hydrogen circuits. The possibility to connect the two hydrogen circuits allows for optimization of hydrogen management and limits investments in terms of compressors and/or purification units for gas discharges. Various embodiments of hydrogen management that may be used in the present invention are described in patent application FR 2957607.

The light fraction obtained after separation step (b) comprising hydrocarbons of naphtha, kerosene and/or diesel type, in particular GPL and vacuum gas oil, may be upgraded according to methods well known to those skilled in the art. The resulting products may be incorporated into fuel formulations (also known as fuel “pools”) and may be subjected to additional purification steps. The naphtha, kerosene, gas oil and reduced pressure gas oil fraction(s), either separately or as a mixture, may relate to the required specification which may relate to sulfur content, soak point, octane number, cetane number, etc. It may be subjected to one or more treatments, eg, hydrotreating, hydrocracking, alkylation, isomerization, catalytic reforming, catalytic or thermal cracking, in order to become

effervescent bed hydroconversion step (c)

According to the process of the invention, at least a portion of the heavy fraction of the effluent derived from separation step (b) is sent to a hydroconversion step (c) carried out in at least one effervescent bed reactor containing a supported catalyst. The reactor may function with an upward stream of liquids and gases. The primary purpose of hydroconversion is to convert the heavy hydrocarbon feedstock into lighter fractions while simultaneously partially refining the heavy hydrocarbon feedstock.

According to one embodiment of the invention, a portion of the initial hydrocarbon feedstock is a heavy fraction of the effluent derived from the separation step (b), while this portion of the hydrocarbon feedstock is not treated in the fixed bed hydrotreating section (b). It may also be injected directly into the inlet of the boiling bed hydroconversion section (c) as a mixture with This embodiment may be similar to the partial paragraph of the fixed bed hydroprocessing section (a).

According to one variant, the co-feedstock may be introduced at the inlet of the boiling bed hydroconversion section (c) together with the heavy fraction of the effluent derived from the separation step (b). This co-feedstock comes from atmospheric residues, vacuum residues derived from direct distillation, de-asphalted oils, aromatic extracts derived from lubricating oil base production lines, fluid-bed catalytic cracking process. Derived products, in particular those obtained by distillation, gas oil fractions, in particular atmospheric or reduced pressure distillation, which may be selected from light cycle oil (LCO), heavy cycle oil (HCO), decanted oil, for example, It may be selected from hydrocarbon fractions or mixtures of hydrocarbon fractions which may be derived from vacuum gas oil. According to another variant, and if the hydroconversion section comprises several effervescent bed reactors, this co-feedstock may be partially or wholly injected into one of the reactors downstream of the first reactor.

The hydrogen required for the hydroconversion reaction may be injected into the inlet of the boiling bed hydroconversion section (c). It may be hydrogen for recycling and/or input hydrogen. Where the hydroconversion section comprises several effervescent bed reactors, hydrogen may be injected into the inlet of each reactor.

Effervescent layer techniques are well known to those skilled in the art. Only key operating conditions will be described herein. Effervescent bed techniques conventionally use supported catalysts in the form of extrudates, typically about 1 millimeter in diameter, for example 0.9 mm or 1.2 mm. Catalysts remain inside the reactors and are not removed with the products except during the steps of input and removal of catalysts necessary to maintain catalytic activity. Temperature levels may be high to obtain high conversions while simultaneously minimizing the amounts of catalysts used. Catalytic activity may be kept constant by on-line replacement of the catalyst. Therefore, it is not necessary to shut down the unit to change spent catalyst, or to increase reaction temperatures throughout the cycle to compensate for deactivation. Moreover, operating under constant operating conditions advantageously makes it possible to obtain constant yields and product qualities throughout the cycle. Also, since the catalyst is kept under agitation by substantial recirculation of the liquid, the pressure loss on the reactor remains low and constant. Due to attrition of the catalysts in the reactors, the products exiting the reactors may contain fine catalyst particles.

The conditions of effervescent bed hydroconversion step (c) may be standard conditions for effervescent bed hydroconversion of the liquid hydrocarbon fraction. The process is carried out at an absolute pressure of 2.5 MPa to 35 MPa, preferentially 5 MPa to 25 MPa, more preferentially from 6 MPa to 20 MPa, even more preferentially from 11 MPa to 20 MPa, from 330°C to 550°C, preferentially from 350°C to It may be carried out at a temperature of 500°C. Hourly space velocity (HSV) and partial pressure of hydrogen are parameters that are established as a function of the properties of the product to be treated and the desired conversion. HSV (defined as the volumetric flow rate of the feedstock divided by the total volume of the boiling bed reactor) is generally 0.1 h ^-1 to 10 h ^-1 , preferentially 0.2 h ^-1 to 5 h ^-1 , more preferentially 0.2 h ⁻¹ to 1 h ⁻¹ . The amount of hydrogen mixed with the feedstock is typically from 50 to 5000 normal cubic meters (Nm ^{3 ) per cubic meter (m 3} ) of the liquid feedstock, typically from 100 Nm ³ /m ³ to 1500 Nm ³ /m ³ , preferably is 200 Nm ³ /m ³ to 1200 Nm ³ /m ³ .

(감마) 또는

(에타) 알루미나이다. 이 촉매는 압출물 (extrudate) 의 형태일 수도 있다. VI 족 및 VIII 족 금속 산화물들의 총 함량은 5 중량% 내지 40 중량%, 일반적으로 7 중량% 내지 30 중량% 일 수도 있고, VI 족 금속 (들) 및 VIII 족 금속 (들) 사이의 금속 산화물로서 표현된 중량 비율은 일반적으로 20 내지 1 이고, 바람직하게는 10 내지 2 이다.On the amorphous support, a standard granular hydroconversion catalyst comprising at least one metal or metal compound having a hydrogenation-dehydrogenation function may be used. The catalyst may also be a catalyst comprising Group VIII metals, for example nickel and/or cobalt, typically in combination with at least one Group VIB metal, for example molybdenum and/or tungsten. For example, 0.5% to 10% by weight of nickel, preferably 1% to 5% by weight of nickel (expressed as nickel oxide NiO), and 1% to 30% by weight of molybdenum on an amorphous inorganic carrier , preferably 5% to 20% by weight of molybdenum ( _{expressed as molybdenum oxide MoO 3} ) may be used. This carrier may be selected, for example, from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. The support may also contain other compounds, for example, oxides selected from the group consisting of boron oxide, zirconia, titanium oxide, phosphorus pentoxide. Typically, an alumina support is used, and very generally an alumina support doped with phosphorus and optionally boron. When phosphorus pentoxide P ₂ O ₅ is present, its concentration is usually less than 20% by weight and very typically less than 10% by weight. When boron trioxide B ₂ O ₃ is present, its concentration is usually less than 10% by weight. The alumina used is usually

(gamma) or

(Eta) is alumina. This catalyst may be in the form of an extrudate. The total content of the Group VI and Group VIII metal oxides may be from 5% to 40% by weight, generally from 7% to 30% by weight, as a metal oxide between the Group VI metal(s) and the Group VIII metal(s) The weight ratio expressed is generally from 20 to 1, preferably from 10 to 2.

Spent catalyst is generally removed from the bottom of the reactor and at regular time intervals, ie, eg batchwise or continuously or virtually continuously, fresh or fresh catalyst to the top of the reactor. By introduction, it may be partially replaced by fresh catalyst. It is also possible to introduce the catalyst from the bottom and remove the catalyst from the top of the reactor. For example, it is possible to introduce fresh catalyst daily. The rate of replacement of spent catalyst with fresh catalyst may be, for example, from about 0.05 kilograms to about 10 kilograms per cubic meter of feedstock. This removal and this replacement are carried out by means of devices which enable the continuous functioning of this hydroconversion step. Hydroconversion reactors typically include a recycle pump for maintaining the catalyst in the boiling bed by continuous recirculation of at least a portion of the liquid removed from the top of the reactor and reinjected into the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor to a regeneration zone where the carbon and sulfur which it contains are removed before reinjecting the spent catalyst into the hydroconversion step (c).

This hydroconversion step (c) according to the process of the invention may be carried out under the conditions of the H-OIL® process as described for example in patent US 6270654.

The effervescent bed hydroconversion may take place in a single reactor or in several reactors, preferably in two arranged in series. Using at least two fluidized bed reactors in series makes it possible to obtain products of better quality and better yield. Furthermore, the hydroconversion in the two reactors makes it possible to have improved operability with respect to operating conditions and flexibility of the catalyst system. Preferably, the temperature of the second boiling bed reactor is at least 10° C. higher than the temperature of the first boiling bed reactor. To allow flow of at least a portion of the effluent derived from the first stage without requiring pumping, the pressure in the second reactor may be 0.1 MPa to 1 MPa lower than that for the first reactor. The various operating conditions in terms of temperature in the two hydroconversion reactors are selected so as to control the hydrogenation and conversion of the feedstock to the desired products in each reactor.

When the hydroconversion step (c) is carried out in two sub-steps (c1) and (c2) in two reactors arranged in series, the effluent obtained from the first sub-step (c1) is optionally a light fraction and separation of the heavy fraction, wherein at least a part, preferably all, of the heavy fraction may be treated in a second hydroconversion sub-step (c2). This separation is advantageously carried out in an inter-stage separator as described, for example, in patent US 6270654, which in particular avoids overcracking of the light fraction in the second hydroconversion reactor. make it possible In addition, the spent catalyst withdrawn from the reactor of the first hydroconversion sub-stage (c1) operating at a lower temperature is transferred, in whole or in part, directly to the reactor of the second sub-stage (c2) operating at a higher temperature, or , it is possible to transfer the spent catalyst withdrawn from the reactor of the second sub-stage (c2) in whole or in part directly to the reactor of the first sub-stage (c1). This cascade system is described, for example, in patent US 4816841.

Separation of the hydroconversion effluent (d)

The process according to the invention also comprises a separation step (d) to obtain at least one gaseous fraction and at least one liquid hydrocarbon fraction.

The effluent obtained after hydroconversion step (c) comprises a liquid fraction and a gaseous fraction containing _{gases, in particular H 2} , H ₂ S, NH ₃ and C ₁ -C _{4 hydrocarbons.} This gaseous fraction is well known to those skilled in the art, particularly using one or more separating flasks which may operate at different pressures and temperatures, optionally in combination with means for stripping with steam or hydrogen. It may also be separated from the hydrocarbon effluent by known separation devices. The effluent obtained after the hydroconversion step (c) is advantageously separated in at least one separating flask into at least one gas fraction and at least one liquid fraction. These separators may be, for example, high-pressure high-temperature (HPHT) separators and/or high-pressure low-temperature (HPLT) separators.

After optional cooling, this gaseous fraction is preferably treated in a hydrogen purification means to recover hydrogen not consumed during hydrotreating and hydroconversion reactions. The hydrogen purification means may be an amine wash, a membrane, a Pressure Swing Adsorption (PSA) type system, or several of these means arranged in series. The purified hydrogen may then advantageously be recycled to the process according to the invention after optional recompression. Hydrogen is introduced into the inlet of the hydrotreating step (a) and/or at different points during the hydrotreating step (a) and/or to the inlet of the hydroconversion step (c) and/or at different points during the hydroconversion step (c). Points may also be introduced.

Separation step (d) may also comprise atmospheric distillation and/or reduced pressure distillation. Advantageously, separation step (d) further comprises at least one atmospheric distillation wherein the liquid hydrocarbon fraction(s) obtained after separation are fractionated by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction do. The atmospheric distillate fraction may contain commercially upgradable fuel bases (naphtha, kerosene and/or diesel), for example in refineries for the production of automotive and aviation fuels.

Additionally, the separation step (d) of the process according to the invention advantageously comprises that the liquid hydrocarbon fraction(s) obtained after separation and/or the atmospheric residue fraction obtained after atmospheric distillation are reduced by vacuum distillation to at least one reduced pressure distillate fraction and at least It also includes at least one reduced pressure distillation fractionated into one reduced pressure residue fraction. Preferably, the separation step (d) comprises first atmospheric distillation in which the liquid hydrocarbon fraction(s) obtained after separation are fractionated by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction, then , wherein the atmospheric residue fraction obtained after atmospheric distillation is fractionated into at least one vacuum distillate fraction and at least one vacuum distillate fraction by vacuum distillation. The vacuum distillate fraction typically contains fractions of the vacuum gas oil type.

At least a portion of the reduced pressure residue fraction may be recycled to the hydroconversion step (c).

After separation step (d), at least one liquid hydrocarbon fraction having a sulfur content of 0.5% by weight or less, preferentially up to 0.3% by weight, more preferably up to 0.1% by weight, even more preferentially up to 0.08% by weight is obtained. may be This liquid hydrocarbon fraction may advantageously serve as a fuel oil base, in particular for bunker fuels. Advantageously, all of the liquid hydrocarbon effluent obtained after separation step (d) may have a sulfur content of 0.5% by weight or less, preferentially up to 0.3% by weight, more preferentially up to 0.1% by weight, even more preferentially up to 0.08% by weight there is.

In the context of the present invention, the conversion of hydrocarbon feedstock to lighter fractions may be between 10% and 95%, preferentially between 25% and 90%, more preferentially between 40% and 85%. The degree of conversion mentioned above is the amount of compounds having a boiling point greater than 520° C. in the initial hydrocarbon feedstock, as the amount of compounds having a boiling point greater than 520° C. in the hydrocarbon effluent obtained after the minus hydroconversion step (c). , defined as the total divided by the amount of compounds having a boiling point greater than 520° C. in the initial hydrocarbon feedstock. A high degree of conversion is advantageous insofar as it exemplifies in significant quantities conversion products, mainly atmospheric distillates and/or vacuum distillates of the naphtha, kerosene and diesel type.

This liquid hydrocarbon effluent may be advantageously used, at least in part, as fuel oil bases or fuel oil, in particular as a bunker fuel base or bunker fuel with a low sulfur content that meets the new recommendations of the International Maritime Organization.

In the present invention, the term "fuel oil" means a hydrocarbon feedstock which may be used as a fuel. In the present invention, the term "fuel oil base" means a hydrocarbon feedstock that, when mixed with other bases, constitutes fuel oil. As a function of the origin of these bases, in particular as a function of the type of crude oil and the type of refining, the properties of these bases, in particular their sulfur content and their viscosity, vary widely.

Optional separation of precipitates and fines (e)

The hydrocarbon effluent obtained after the hydroconversion step (c), and in particular the heaviest liquid fraction obtained, may contain catalyst residues and precipitates derived from the fixed bed stage and/or in the form of fines in the boiling bed stage. In order to obtain a fuel oil or fuel oil base that meets the recommendations of a content of sediments after deterioration of not more than 0.1 %, the process according to the invention comprises an additional step in separating sediments and fines from the liquid hydrocarbon effluent after the separation step (d). It may include steps.

Accordingly, the process according to the invention also comprises that at least a portion of the atmospheric residue fractions and/or the vacuum distillate fractions and/or the vacuum residue fractions is subjected to at least one filter, a centrifugation system or on-line. It may include a separation step (e) of precipitates and fines, which is subjected to separation of precipitates and catalyst fines using decantation.

optional catalytic cracking step (f)

According to an embodiment, the process according to the invention further comprises at least a part of the atmospheric distillate fraction and/or the reduced pressure residue fraction optionally previously subjected to step (e) for separating sediments and fines, such as a gas fraction, a petroleum fraction , a catalytic cracking step (f) sent to a catalytic cracking section to be treated under conditions enabling the production of a diesel fraction and a residue fraction.

Said catalytic cracking step (f) may be, for example, a fluidized bed catalytic cracking step according to a process developed by Applicants' company known as R2R. This step may be carried out in a conventional manner known to those skilled in the art under suitable cracking conditions to obtain lower molecular weight hydrocarbon products. Descriptions of catalysts and functions which may be used in the context of fluidized bed cracking in this step (f) are given, for example, in patents 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 derived bed catalytic cracking reactor may function with either an upstream or a downstream. Although this is not a preferred embodiment of the present invention, it may also be envisioned to carry out catalytic cracking in a moving bed reactor. Particularly preferred catalysts for catalytic cracking are usually those containing at least one zeolite in a suitable matrix, for example alumina, silica or a mixture with silica-alumina.

At least a portion of the residue fraction obtained after the catalytic cracking step (f), often referred to by those skilled in the art as a “slurry” fraction, is passed to the inlet of the catalytic cracking step (f), and/or a hydrotreating step It may be recycled to the inlet of (c) and/or to the inlet of the hydroconversion step (b). The residue fraction may also be sent at least partially or even entirely to a zone for storing heavy refinery fuel oil.

In one embodiment of the invention, a part of the diesel fraction and/or the residue fraction obtained after this catalytic cracking step (f) may be used to constitute a flux base.

Flux and fuel oils

One object of the present invention is to produce commercializable fuel oils, in particular bunker fuels for marine transport. It is desirable that this type of fuel oil meet certain specifications, especially in terms of viscosity. Preferably, a very common type of bunker fuel has a viscosity (at 50° C.) of 380 cSt or less. Different qualities of fuel oils, known as “grades”, meet different specifications, in particular in terms of viscosity. In particular, for distillate type fuels, the DMA grade imposes a viscosity of 2 cSt to 6 cSt at 40° C. and the DMB grade imposes a viscosity of 2 cSt to 11 cSt at 40° C. Fuel oil bases may be mixed with flux bases or “cutter stocks” if necessary, inter alia, to obtain a target viscosity for a desired grade of fuel oil. Specifications for fuel oils are described, for example, in standard ISO 8217 (last version of 2012).

Flux bases are generally of the kerosene, gas oil or reduced pressure gas oil type. These are from light cycle oils from catalytic cracking (LCO), heavy cycle oils from catalytic cracking (HCO), residues from catalytic cracking, oils from kerosene, gas oil, vacuum distillate and/or decanted oil. may be selected.

In the process according to the invention, the atmospheric residue and/or the vacuum distillate and/or the vacuum residue obtained after the separation step (d), optionally previously subjected to step (e) for separating the precipitates and fines, are subjected to catalytic cracking light cycle oils from catalytic cracking, heavy cycle oils from catalytic cracking, residues of catalytic cracking, kerosene, gas oil, vacuum distillate and/or decanted oil. may be

In a most particularly preferred manner, the flux base comprises a portion of the light hydrocarbon fraction of the kerosene or gas oil type obtained after the separation step (b), a portion of the heavy hydrocarbon fraction of the vacuum distillate type obtained after the separation step (b), and a catalyst a portion of the petroleum fraction, diesel fraction and/or residue fraction obtained after cracking step (f). Additionally or alternatively, the flux base may be selected from a portion of the kerosene and/or diesel fraction obtained after the boiling bed hydroconversion step.

Mixing the atmospheric residue and/or the vacuum distillate and/or the vacuum residue obtained after the separation step (d), optionally previously subjected to a step (e) of separating the precipitates and fines, with one or more flux bases After the step, a fuel oil, also known as bunker fuel with low sulfur content, is obtained which may be advantageously used in marine transport.

Accordingly, subject matter of the present invention is also such a fuel oil having a sulfur content of 0.5% by weight or less, and preferably 0.1% by weight or less. This fuel oil may advantageously have a sediment content of up to 0.1% by weight in order to meet the new version of the standard ISO 8217:2012.

In addition, the viscosity of this fuel oil may be 1 cSt to 700 cSt at 50°C.

An advantageous embodiment of the process according to the invention is shown in FIGS. 1 , 2 and 3 .

1 shows a process according to the invention with intermediate separation with decompression; For better readability, the function of the protected zones in the hydroprocessing section of FIG. 1 is illustrated in FIG. 2 .

In FIG. 1 , feedstock 10 preheated in chamber 12 and mixed with recycled hydrogen 14 and input hydrogen 24 preheated in chamber 16 are routed via pipe 18 to the protected area system. is introduced

Referring to FIG. 2 , the function of the protected zones in the hydroprocessing section comprising two protected zones (or substitutable reactors) (Ra and Rb) comprises a series of cycles each comprising four successive steps. do:

- a first stage (stage i) in which the feedstock is passed continuously through a reactor (Ra) and then through a reactor (Rb),

- a second stage (stage ii), in which the feedstock passes only through a reactor (Rb), wherein the reactor (Ra) is short-circuited for regeneration and/or replacement of the catalyst (stage ii);

- a third stage (stage iii) in which the feedstock is passed continuously through the reactor (Rb) and then through the reactor (Ra);

- a fourth stage (stage iv), in which the feedstock passes only through the reactor (Ra), wherein the reactor (Rb) is short-circuited for regeneration and/or replacement of the catalyst (stage iv).

Next, the cycle can be restarted.

Steps i and iii are steps in which all protected areas are used. Steps ii and iv are steps in which one protected area is shorted while the other is used.

During step (i), the preheated feedstock is fed into a line comprising a guard reactor (Ra) comprising a fixed bed (A) of catalyst and a valve (V1) opening towards line (20) ( 18) and via line 19 . During this period, valves V3, V4 and V5 are closed. The discharge from the reactor (Ra) is sent through a pipe (21), a pipe (22) comprising an open valve (V2), and a pipe (23) in a protective reactor (Rb) containing a fixed bed (B) of catalyst lose The effluent from the reactor Rb is sent via pipes 24 and 25 comprising an open valve V6 and pipe 26 to the main hydrotreating section, which will be described hereinafter.

During step (ii), the valves V1, V2, V4 and V5 are closed and the feedstock comprises a line 18 and a line 23 and a valve V3 which opens towards the reactor Rb. It is introduced via line 27 . During this cycle, the effluent from the reactor Ra is sent to the main hydrotreating section via pipes 24 and 25 and pipe 26 comprising an open valve V6.

During step (iii), valves V1, V2 and V6 are closed and valves V3, V4 and V5 are open. The feedstock is introduced into the reactor Rb via line 18 and lines 27 and 23 . The effluent from the reactor (Rb) is sent to the protective reactor (Ra) via a line (24), a line (28) comprising an open valve (V4), and a line (20). The effluent from the reactor (Ra) is sent to the main hydrotreating section via pipes ( 21 and 29 ) and pipe ( 26 ) comprising an open valve ( V5 ).

During step (iv), valves V2, V3, V4 and V6 are closed and valves V1 and V5 are opened. The feedstock is introduced into the reactor (Ra) via line (18) and lines (19 and 20). During this cycle, the effluent from the reactor (Ra) is sent to the main hydrotreating section via lines (21 and 29) and line (26) comprising an open valve (V5).

1 , the effluent leaving the guard reactor(s) is optionally remixed with hydrogen arriving via line 65 in the HDM reactor 30 containing a fixed bed 32 of catalyst. For reasons of readability, only one HDM reactor and one HDS reactor are shown in the figures, the HDM and HDS section may include several HDM and HDS reactors in series. If desired, recycled and/or input hydrogen may also be introduced into the hydrotreating reactors between the various catalyst beds (not shown).

The effluent from the HDM reactor is withdrawn via line 34 and then sent to a first HCK reactor 36 , where it passes through a fixed bed 38 of catalyst.

The effluent from the hydrotreating step is sent via line 42 to a high pressure and high temperature (HPHT) separator 44 from which a gas fraction 46 and a liquid fraction 48 are recovered. The cut-off point is generally between 200 and 400°C. The gas fraction 46 is generally sent to a high pressure cryogenic (HPLT) separator 52 via an exchanger (not shown) or a cooling tower 50 for cooling, from which the gases (H _{2 )} , H ₂ S, NH ₃ , C ₁ -C ₄ hydrocarbons, etc.) and a liquid fraction 56 are recovered.

The gas fraction 54 obtained from the high pressure and low temperature (HPLT) separator 52 is treated in a hydrogen purification unit 58, from which hydrogen 60 is recovered, and the compressor 62 and line 65 are to the reactors 30 and/or 36 via line 14 or to the substitutable reactors via line 14 . Gases containing undesirable nitrogen and sulfur compounds are removed from the plant (stream 66).

The liquid fraction 56 obtained from the high pressure and low temperature (HPLT) separator 52 is decompressed in an apparatus 68 and then sent to a fractionation system 70 . Optionally, an intermediate-pressure separator (not shown) after the pressure-relief device 68 recovers the gas fraction sent to the purification unit 58 and the liquid phase sent to the fractionation section 70 . It may be installed to

The liquid fraction 48 obtained from the high pressure high temperature (HPHT) separator 44 is decompressed in an apparatus 72 and then sent to a fractionation system 70 . Fractions 56 and 48 may be sent together to system 70 after pressure relief. According to a variant not shown, fractions 70 and 172 may be all common and processed light fractions, including those coming from inter-stage separator 108 . Fractionation system 70 comprises an atmospheric distillation system for producing a gaseous effluent 74, in particular at least one "light" fraction 76 containing naphtha, kerosene and diesel, and an atmospheric residue fraction 78 do. A portion of the atmospheric residue fraction may be sent via line 80 to the hydroconversion reactors. All or part of the atmospheric residue fraction 78 is subjected to a vacuum distillation column 82 to recover a fraction 84 containing a vacuum residue and a vacuum distillate fraction 86 containing a reduced pressure gas oil. is sent to

The reduced pressure residue fraction (84) optionally mixed with a portion of the atmospheric residue fraction (80) and/or a portion of the vacuum distillate fraction (86) is optionally composed of input hydrogen (90) preheated in an oven (91). It is mixed with recycled hydrogen (88). It optionally passes through an oven 92 . Optionally, a co-feedstock 84 may be introduced. Next, the heavy fraction is introduced via line 96 into the hydroconversion stage at the bottom of a first ebullated bed reactor 98 containing at least one hydroconversion catalyst and functioning with an upward stream of liquid and gas. Reactor 98 typically includes a recirculation pump 100 for maintaining the boiling bed catalyst by continuous recirculation of at least a portion of the liquid withdrawn from the top of the reactor and reinjected into the bottom of the reactor. Input of fresh catalyst may occur through the top or bottom of the reactor (not shown). The input of catalyst may occur periodically or continuously. Spent catalyst may be withdrawn from the bottom of the reactor (not shown) to be disposed of or regenerated to remove carbon and sulfur before being reinjected to the top of the reactor. The partially spent catalyst withdrawn from the bottom of the first reactor may also be sent directly to the top of the second hydroconversion reactor 102 (not shown). Optionally, the converted effluent 104 obtained from the reactor 98 may be subjected to separation of the light fraction 106 in an interstage separator 108 .

All or part of the effluent 110 obtained from the interstage separator 108 is advantageously mixed (not shown) with additional hydrogen 157 which is preheated if necessary. Next, this mixture is injected via pipe 112 into a second boiling bed hydroconversion reactor 102 , which functions with an upward stream of liquid and gas containing at least one hydroconversion catalyst. The operating conditions in this reactor, in particular the temperature, are selected to achieve the desired conversion level, as previously described. The input and withdrawal of catalyst is carried out in the same manner as described for the first reactor. Reactor 102 also includes a recirculation pump 114, which typically functions in the same manner as the pump of the first reactor.

The effluent from the boiling bed reactors is sent via line 134 to a high pressure high temperature (HPHT) separator 136 from which a gas fraction 138 and a liquid fraction 140 are recovered. Gas fraction 138 is generally sent to a high pressure cryogenic (HPLT) separator 144 via an exchanger (not shown) or a cooling tower for cooling, from which the gases (H ₂ , H _{2 )} A gas fraction 146 and a liquid fraction 148 containing S, NH ₃ , C ₁ -C _{4 hydrocarbons, etc.) are recovered.}

Gas fraction 146 from high pressure and low temperature (HPLT) separator 144 is treated in hydrogen purification unit 150, from which compressor 154 and line 156 and/or line 157 are removed. Hydrogen 152 is recovered for recycling to the hydroconversion section via The hydrogen purification unit may consist of an amine scrubber, membrane or PSA type system. Gases containing undesirable nitrogen and sulfur compounds are vented from the plant (some streams, particularly _{stream 158, which may represent an H 2} S-rich stream, and light hydrocarbons, which may be used as refinery fuel gas). one or more purges containing (C1 and C2)).

The liquid fraction 148 from the high pressure cryogenic (HPLT) separator 144 is depressurized in an apparatus 160 and then sent to a fractionation system 172 . Optionally, a medium-pressure separator (not shown) after the pressure-release device 160 is connected to a purification unit 150 and/or a dedicated medium-pressure purification unit (not shown) It may be installed to recover the vapor phase sent to the , and the liquid phase sent to the fractionation section 172 .

The liquid fraction 140 obtained from the high pressure high temperature (HPHT) separator 136 is depressurized in an apparatus 174 and then sent to a fractionation system 172 . Optionally, an intermediate-pressure separator (not shown) after the pressure-relief device 174 comprises a gas phase that is sent to a purification unit 150 and/or a dedicated intermediate-pressure purification unit (not shown), and a fractionation section ( 172) may be installed to recover the liquid phase conveyed to

Obviously, fractions 148 and 140 may be sent together to decompression system 172 . Fractionation system 172 comprises an atmospheric distillation system for producing gaseous effluent 176 , in particular, at least one “light” fraction 178 comprising naphtha, kerosene and diesel, and atmospheric residue fraction 180 . do. A portion of atmospheric residue fraction 180 may be withdrawn via line 182 to constitute the desired fuel oil bases. All or a portion of the atmospheric residue fraction 180 may be sent to a reduced pressure distillation column 184 to recover a fraction containing the reduced pressure residue 186 and a reduced pressure distillate fraction 188 containing a reduced pressure gas oil. . At least a portion of the vacuum residue fraction is preferably recycled to the hydroconversion stage via line 190 or upstream of the hydrotreating stage to increase conversion (line not shown). Optionally, the atmospheric residue fraction 182 , the vacuum distillate fraction 188 , and/or the vacuum residue fraction 186 are passed through, for example, filters 191 , 192 and 193 respectively to fines and precipitate Steps may be taken to separate them.

An alternative manner, not shown, for separation and fractionation may be carried out using a vapor stripping column which treats the heavy fraction(s) from high or medium pressure or low pressure separators. Through this means, the bottom of the stripping column directly feeds the reduced pressure column; The atmospheric distillation column remains for treating the distillate mixtures, but not the unconverted fraction (heaviest fraction).

3 shows another process according to the invention with intermediate separation without decompression. Essentially, only the differences between the process according to FIG. 3 and the process according to FIG. 1 will be described below, the hydrotreating and hydroconversion steps and the steps for the separation after hydroconversion (and their reference signs) are Otherwise it would be strictly the same.

The treated effluent from the hydroconversion reactors is sent via line 42 to a high pressure and high temperature (HPHT) separator 44 from which a lighter fraction 46 and a residue fraction 48 are separated. is recovered The cut-off point is generally between 200 and 400°C.

Residue fraction 48 is sent directly to the hydroconversion section after optional passage through an oven 92 .

The lighter fraction 46 is generally sent to a high pressure cryogenic (HPLT) separator 52 via an exchanger (not shown) or a cooling tower for cooling, from which the gases H ₂ , A gas fraction 54 and a liquid fraction 56 containing H ₂ S, NH ₃ , C ₁ -C _{4 hydrocarbons, etc.) are recovered.}

Gas fraction 54 from high pressure and low temperature (HPLT) separator 52 is treated in hydrogen purification unit 58 from which hydroprocessing section via compressor 154 and lines 64 and 156 . and/or hydrogen (60) recycled to the hydroconversion section is recovered. Gases containing undesirable nitrogen, sulfur and oxygenated compounds exit the plant (stream 66). In this configuration, only one compressor 154 is used to supply all reactors requiring hydrogen.

The liquid fraction 56 obtained from the high pressure and low temperature (HPLT) separator 52 is decompressed in an apparatus 68 and then sent to a fractionation system 70 . Fractionation system 70 comprises an atmospheric distillation system for producing a gaseous effluent 74, in particular, at least one "light" fraction 76 containing naphtha, kerosene and diesel, and an atmospheric residue fraction 195 do. A portion of the commercial residue fraction may be sent to the hydroconversion reactors via line 195, while another portion of the atmospheric residue fraction 194 may be sent to another process (hydrocracking or FCC or hydrotreating). there is.

Examples

The following examples illustrate the invention, but do not limit its scope.

A reduced pressure residue (RSV Oural) containing 87.0% by weight of compounds boiling at temperatures above 520°C, having a density of 9.5°API and a sulfur content of 2.72% by weight, was treated. The feedstock contains 254 ppm of metals (Ni + V).

The feedstock was subjected to a hydrotreating stage comprising two substitutable reactors. The HDM/HDS catalyst distribution of the feedstock is 63/27. The operating conditions are given in Table 1.

The hydrodemetallization HDM performance in the fixed bed HDT section is greater than 80%.

Next, the hydrotreating effluent was subjected to a flash flask separation at high pressure and high pressure (HPHT).

The heavy fraction (fraction 350° C.+) was sent to a hydroconversion stage comprising two successive boiling bed reactors. The operating conditions are given in Table 2.

The yield and sulfur content for each fraction obtained from the effluent leaving the whole chain are given in Table 3.

Consumed hydrogen represents 1.69% by weight of fresh feedstock introduced at the inlet of the hydroprocessing section.

The yields make it possible to calculate the degree of conversion of the fraction of the feedstock boiling at a temperature above 520°C, which is converted to products boiling at a temperature below 520°C, according to the formulas:

The numerical application gives: Conversion = (87.0 - 34.3) / 87.0 = 60.5%

This particularly high degree of conversion exemplifies the production of significant amounts of conversion products (mainly distillates).

The mixture was then prepared from the ^{350-520°C fraction and 520°C +} fraction obtained from the hydroconversion step in the following proportions:

- 350-540° C. fraction: 48% by weight of a mixture, and

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

Thus, a fuel oil having a sulfur content of 0.35% by weight and a viscosity of 380 cSt at 50°C was obtained. Moreover, the content of the residues after deterioration is less than 0.1% by weight. For these analyses, this fuel oil is particularly suitable for constructing bunker fuels as recommended by the IMO beyond the ZCES in the 2020-2025 Horizon.

In addition to the first mixture resulting in a fuel oil containing 0.35% sulfur, a second mixture was prepared consisting of a fraction of 80% by weight obtained from the diesel cycle and a fraction of 20% by weight obtained from the vacuum distillate cycle. At these ratios, the mixture has a sulfur content of 0.09% and a viscosity of 6 cSt at 40°C. Accordingly, this mixture can be used as a distillate type marine fuel (“marine gas-oil” or “marine diesel”), which may be likened, for example, to a DMB grade (its viscosity specification is 2 cSt to 11 cSt at 40°C). ) constitutes Due to its sulfur content of less than 0.1%, this mixture constitutes the fuel of choice for ZCES at Horizon 2015.

Claims (18)

processing a hydrocarbon feedstock having a sulfur content of at least 0.5% by weight, an initial boiling point of at least 340°C and a final boiling point of at least 440°C, which makes it possible to obtain at least one liquid hydrocarbon fraction having a sulfur content of 0.5% by weight or less As a method for
a) a fixed bed hydrotreating step, wherein the hydrocarbon feedstock and hydrogen are placed in contact over at least one hydrotreating catalyst;
b) separation of the effluent from the hydrotreating step (a) into at least one light fraction and at least one heavy fraction;
c) hydroconversion of at least a portion of said heavy fraction of the effluent derived from step (b) in at least one effervescent bed reactor containing a supported catalyst, and
d) a separation step of separating the effluent derived from step (c) to obtain at least one gaseous fraction and at least said liquid hydrocarbon fraction
including successive steps of
wherein the hydrotreating step (a) is carried out at a temperature of 300° C. to 500° C., at an absolute pressure of 2 MPa to 35 MPa, with an hourly space velocity of the hydrocarbon feedstock in the range of ^{0.1 h −1} to 5 h ^{−1 and} , the amount of hydrogen mixed with the feedstock is 100 Nm ³ /m ³ to 5000 Nm ³ /m ³ ,
the hydroconversion step (c) is carried out at an absolute pressure of 2.5 MPa to 35 MPa, at a temperature of 330°C to 550°C, with an hourly space velocity in the range of ^{0.1 h −1} to 10 h ^{−1 , the feedstock} and the amount of hydrogen mixed with is 50 Nm ³ /m ³ to 5000 Nm ³ /m ³ . The method of claim 1,
The hydrotreating step (a) is a first step (a1) of hydrodemetallation carried out in one or more fixed-bed hydrodemetallation (HDM) zones and one or more fixed-bed hydrodesulfurization (HDS) zones. A process for treating a hydrocarbon feedstock comprising the subsequent second step (a2) of hydrodesulphurization. delete delete The method of claim 1,
Said hydrotreating step (a) comprises at least two hydroprocessing protections arranged in series in fixed beds and also to be used in a cyclic manner consisting of successive repetitions of steps a'') and a''') as defined below. carried out in one or more fixed bed hydroprocessing zones following the zones, the steps defined above comprising:
a') the protected areas are all used together for a period less than or equal to the deactivation and/or clogging time for one of the protected areas;
a'') the deactivated and/or clogged protected zone is short-circuited, the catalyst contained in this protected zone is regenerated and/or replaced with fresh catalyst, while other protected zone(s) are used, and
a''') the said protected areas are all used together, the catalyst is regenerated and/or the replaced protected area is reconnected during the preceding step, which is the deactivation and/or clogging time of one of the protected areas A phase that continues for a period of less than or equal to
A method for treating a phosphorus, hydrocarbon feedstock. The method of claim 1,
The hydrocarbon feedstock is atmospheric residues, vacuum residues obtained from direct distillation, crudes, de-headed crudes, deasphalted oils, deasphalted resins, taken alone or as a mixture , deasphalted pitches or asphalts, residues from conversion processes, aromatic extracts from lubricating oil base production lines, bituminous sands or derivatives thereof, A method for treating a hydrocarbon feedstock selected from bituminous shales or derivatives thereof, parent-rock oils or derivatives thereof. 7. The method of any one of claims 1, 2, 5, and 6, wherein
The effluent obtained from the hydrotreating step (a) is subjected to a separation step (b) with decompression, wherein the separation step (b) comprises
- said effluent from step (a) is sent to a fractionation section having a cut-off point between 200 °C and 400 °C, making it possible to obtain a light fraction and a heavy fraction,
- fractionation of said heavy fraction by atmospheric distillation into at least one atmospheric distillate fraction and an atmospheric residue fraction;
- at least a portion of the atmospheric residue fraction is fractionated by vacuum distillation into a vacuum distillate fraction, and a reduced pressure residue fraction, and
- at least a part of the reduced pressure residue fraction and/or the atmospheric residue fraction is advantageously sent to a hydroconversion step (c);
A method for treating a hydrocarbon feedstock comprising: 7. The method of any one of claims 1, 2, 5, and 6, wherein
The effluent from the hydrotreating step (a) is subjected to a separation step (b) without decompression, wherein the separation step (b) comprises:
- the effluent from the hydrotreating step (a) is sent to a fractionation section having a cut-off point of 200 to 400° C., making it possible to obtain at least one light fraction and at least one heavy fraction;
- the heavy fraction is sent directly to the hydroconversion step (c);
- allowing said light fraction to undergo atmospheric distillation to obtain a gas fraction, at least one light fraction of liquid hydrocarbons of naphtha, kerosene and/or diesel type, and a vacuum distillate fraction, and
- said vacuum distillate fraction is at least partially sent to said hydroconversion step (c);
A method for treating a hydrocarbon feedstock comprising: 7. The method of any one of claims 1, 2, 5, and 6, wherein
said separation step (d) also comprises at least one atmospheric distillation, wherein the liquid hydrocarbon fraction(s) obtained after separation are fractionated by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction, A method for treating hydrocarbon feedstock. 8. The method of claim 7,
The separation step (d) may further comprise that the liquid hydrocarbon fraction(s) obtained after separation and/or the atmospheric residue fraction obtained after atmospheric distillation are reduced to at least one vacuum distillate fraction and at least one vacuum residue by vacuum distillation. A method for treating a hydrocarbon feedstock comprising at least one vacuum distillation fractionated into fractions. 11. The method of claim 10,
and a portion of the reduced pressure residue fraction is recycled to the hydroconversion step (c). 11. The method of claim 10,
further comprising the step (e) of separating precipitates and fines, wherein at least a portion of the atmospheric residue fraction and/or the vacuum distillate fraction and/or the vacuum residue fraction comprises at least one filter, a centrifugation system or an on- A method for treating a hydrocarbon feedstock that undergoes separation of catalyst fines and precipitates using line decantation. 13. The method of claim 12,
further comprising a catalytic cracking step (f), wherein at least a portion of the vacuum distillate fraction and/or the vacuum residue fraction optionally previously subjected to a separation step (e) of the precipitates and fines is a gas fraction, a petroleum fraction , which is sent to a catalytic cracking section where it is treated under conditions enabling the production of a diesel fraction and a residue fraction. 14. The method of claim 13,
The atmospheric residue and/or the vacuum distillate and/or the vacuum residue obtained after the separation step (d), optionally previously subjected to a separation step (e) of the precipitates and fines, are light from catalytic cracking. A hydrocarbon feed mixed with one or more flux bases selected from the group consisting of cycle oils, heavy cycle oils from catalytic cracking, residues of catalytic cracking, kerosene, gas oil, vacuum distillate and/or decanted oil. Methods for processing raw materials. 15. The method of claim 14,
The flux base comprises a portion of the light fraction of the kerosene or gas oil type obtained from the separation step (b), a portion of the heavy fraction of the vacuum distillate type obtained from the separation step (b), and the catalytic cracking step (f) A method for treating a hydrocarbon feedstock, selected from a portion of a petroleum fraction, a diesel fraction and/or a residue fraction obtained from 15. A fuel oil which may be used in sea transport, obtained through the method as defined in claim 14, comprising:
A fuel oil having a sulfur content of 0.5% by weight or less, or 0.1% by weight or less. 17. The method of claim 16,
Fuel oil, characterized in that it has a sediment content of 0.1% by weight or less. 17. The method of claim 16,
A fuel oil, characterized in that it has a viscosity of 1 cSt to 700 cSt at 50°C.

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