TW201428024A - Integrated process for treating petroleum feedstocks for the production of fuel oils with a low sulfur content - Google Patents

Abstract

The present invention relates to a process for treating heavy petroleum feedstocks for the production of fuel oils and fuel oil bases, especially bunker fuels and bunker fuel bases, with a low sulfur content. This process comprises a step (a) of fixed-bed hydrotreatment of a heavy sulfureous hydrocarbon feedstock, followed by a step (b) of hydroconversion in an ebullated-bed reactor containing a supported catalyst, and a step (c) of separation of the effluent obtained from step (b) to obtain at least one gaseous fraction and at least the said liquid hydrocarbon fraction, without an intermediate separation step between the hydrotreatment step (a) and the hydroconversion step (b).

Description

Process for the treatment of petroleum feedstocks for the production of fuels with low levels of sulfur

The present invention relates to the refining and conversion of heavy hydrocarbon fractions comprising sulfur-based impurities, and more particularly to the use of heavy petroleum feedstocks to produce fuel and fuel bases having low levels of sulfur, particularly marine fuels and The process of marine fuel base.

In recent years, as the limit on the sulfur content of fuel on the land has become very strict, especially for gasoline and diesel, the limitation of the sulfur content of marine combustibles is still relatively loose today. In particular, sulfur can be included in marine combustibles up to 3.5% or even 4.5% by weight. As a result, ships have become a major source of emissions of sulfur dioxide (SO ₂ ).

In order to reduce these emissions, the International Maritime Organization (IMO) has proposed the International Convention for the Prevention of Pollution From Ships (MARPOL). These recommendations are divided into the 2012 version of the ISO standard 8217 (ISO standard 8217). These standards are currently related to the emission of sulfur oxides (SO _x ) from combustibles at sea. In addition to the Sulfur Emission Control Areas (SECA), the sulfur content recommended before 2020 or 2025 is equal to or lower than 0.5% by weight. Within the sulfur emission control zone, the International Maritime Organization envisages that the sulfur content before 2015 is equal to or less than 0.1% by weight.

Further, another very rigorous suggestion is that the content of the deposit should be less than or equal to 0.1% after ageing in accordance with ISO standard 10307-2 (ISO standard 10307-2).

The purpose of the applicant is to produce fuel and fuel bases that comply with the sulfur content recommended by the International Convention for the Prevention of Pollution from Ships, in particular marine fuels and marine fuel bases, and preferably, in line with the requirements for sediment content after aging. .

In general, fuels used for marine transportation include atmospheric distillates, vacuum distillates, atmospheric residues, vacuum residues obtained directly from a distillation process or a refining process. In particular, hydrotreating or conversion processes, and these fractions may be used alone or as a mixture. It is an object of the present invention to provide a method of converting heavy petroleum feedstocks to produce fuel and fuel substrates having low levels, particularly marine fuels and marine fuel substrates. Another object of the present invention is to co-produce atmospheric distillate (naphtha, kerosene, diesel), vacuum distillate and/or light oil (carbon number 1) by the same process. To 4). The bases of naphtha and kerosene types can be upgraded for use in automotive and aviation fuels such as superfuels, jet fuels and diesel.

The process of refining and converting heavy petroleum feedstock comprises a first step of fixed-bed hydrotreatment followed by a step of ebullated-bed hydroconversion. The above-mentioned steps can be found in the French patent FR 2 764 300, the Canadian patent CA 1238005, the European patents EP 1 343 857, EP 0 665 282, EP 0 665 282, etc., which describe the process for the hydrotreating of heavy oil, and Extend the life of the reactor. Canadian Patent CA 1238005 describes several reactors in series to convert heavy hydrocarbon substrate liquid feedstock (heavy Liquid hydrocarbon-based feedstock). In the step, the degree of conversion is improved by subjecting the obtained heavy fraction to a special recovery. The process described in French patent FR 2 764 300 is to obtain a non-fuel base directly, in particular a marine fuel base, but a fuel with a low sulfur content (oil and diesel). In addition, the raw materials processed in the process contain little or no bitumen. Finally, the process described in European Patent No. EP1343857 relates to a hydrotreating process which can use a hydrodemetallation section and a replaceable reactor type prior to hydrogenation of the metal removal section. A guard zone and a hydrodesulfurization section.

However, the above information does not contain a method for producing fuel or fuel bases with low sediment content as recommended by the International Maritime Organization and having a low sediment content as required by ISO Standard 8217:2012 (ISO standard 8217:2012).

It is an object of the present invention to adjust and improve the conversion process for producing fuel and fuel substrates in the prior art, particularly having a low sulfur content.

Applicants have unexpectedly discovered in this study the improvements in existing processes for producing fuel substrates. In detail, different steps are combined in a special order to improve the quality of the fuel substrate, particularly the sulfur content and the precipitate content.

First, the subject matter of the present invention is to treat a sulfur content having at least 0.5% by weight, a bitumen content of at least 2% by weight, an initial boiling point of at least 340 ° C, and a final of at least 440 ° C. A hydrocarbon boiling material of a final boiling point can be obtained by a hydrocarbon fraction having at least one liquid phase having a sulfur content equal to or less than 0.5% by weight. The process consists of the following steps: (a) The step of fixed bed hydrotreating. Wherein the hydrocarbon feedstock and hydrogen are placed in contact with at least one hydrotreatment catalyst; (b) at least one of the steps (a) in at least one ebullated bed reactor comprising a support catalyst a step of hydroconversion of the effluent; and (c) a step of separating the effluent obtained in step (b) to obtain at least one gas phase fraction and said liquid phase hydrocarbon fraction; in hydrotreating step (a) and There is no separation step for the intermediate between the hydroconversion steps (b).

One of the main systems of the present invention is the fuel oil available for marine transportation obtained by the above process. The fuel has a sulfur content of 0.5% by weight or less. Preferably, it is equal to or less than 0.1% by weight.

10‧‧‧Materials

12‧‧‧ chamber

14‧‧‧Common pipeline

16‧‧‧ chamber

18‧‧‧pipe

19‧‧‧ Pipes

20‧‧‧pipe

21‧‧‧ pipeline

22‧‧‧pipes

23‧‧‧ Pipes

24‧‧‧ Input hydrogen

25‧‧‧pipe

26‧‧‧pipe

27‧‧‧pipe

28‧‧‧pipes

29‧‧‧pipe

30‧‧‧Hydrogenation to metal reactor

32‧‧‧fixed bed

34‧‧‧pipe

36‧‧‧First Hydrodesulfurization Reactor

38‧‧‧fixed bed

42‧‧‧pipe

43‧‧‧ heat exchanger

64‧‧‧Recovered hydrogen

65‧‧‧pipe

88‧‧‧Recovered hydrogen

90‧‧‧ Hydrogen

91‧‧‧Oven

94‧‧‧Common raw materials

96‧‧‧pipe

98‧‧‧First bubbling bed reactor

100‧‧‧Recycling pump

102‧‧‧Second boiling bed hydroconversion reactor

104‧‧‧ effluent

106‧‧‧Light fractions

108‧‧‧Interstage separator

110‧‧‧ effluent

112‧‧‧ pipeline

114‧‧‧Recycling pump

134‧‧‧pipe

136‧‧‧High pressure high temperature separator

138‧‧‧ gas fraction

140‧‧‧liquid fraction

142‧‧‧Cooling tower

144‧‧‧High pressure cryogenic separator

146‧‧‧ gas phase fraction

148‧‧‧ liquid fraction

150‧‧‧Hydrogen purification unit

152‧‧‧Recovered hydrogen

154‧‧‧Compressor

156‧‧‧ pipeline

157‧‧‧pipe

158‧‧‧ airflow

160‧‧‧ device

172‧‧‧ fractionation system

174‧‧‧ device

176‧‧‧ gas phase effluent

178‧‧‧Light fractions

180‧‧‧ atmospheric residue fraction

182‧‧‧pipe

184‧‧‧Vacuum distillation column

186‧‧‧vacuum residue

188‧‧‧vacuum distillation fraction

190‧‧‧pipe

191‧‧‧Filter

192‧‧‧Filter

193‧‧‧Filter

A‧‧‧fixed bed

B‧‧‧fixed bed

V1‧‧‧ valve

V2‧‧‧ valve

V3‧‧‧ valve

V4‧‧‧ valve

V5‧‧‧ valve

V6‧‧‧ valve

Ra‧‧ ‧ protected area

Rb‧‧ ‧ protected area

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a diagram of a process disclosed in an embodiment of the present invention which does not separate the intermediate of the product between the fixed bed portion and the ebullated bed portion.

Fig. 2 is an enlarged view of a guiding portion of the hydrotreating portion of Fig. 1.

In the present specification, the phrase "between" is understood to include the stated conditions.

The process of the present invention comprises a first step (a) of fixed bed hydrotreating, followed by one of the second step (b) of the fluidized bed hydrotreating and the final step (c) of the separation.

The purpose of hydrotreating is to simultaneously refine. That is, while increasing the carbon/hydrogen ratio and converting the hydrocarbon feedstock to a lighter fraction, more or less partially, while reducing metals, sulfur, and He is not pure content. The effluent from the fixed bed hydrotreating of step (a) is then fed to the bubbling bed hydroconversion of step (b). Thereby, the hydrocarbons obtained from the step (a) are partially converted and further produced as a fuel or fuel base, in particular a marine fuel and a marine fuel base.

The advantage of performing a fixed bed hydrotreating and bubbling bed hydroconversion in sequence is that at least a portion of the fuel in the ebullated bed hydroconversion reactor has been hydrotreated. In this way, a hydrocarbon effluent of better quality can be obtained, in particular having a lower sulfur content. Furthermore, the amount of catalyst used in the bubbling bed hydroconversion reactor of the present invention is substantially reduced compared to the prior art process which does not use fixed bed hydrotreating.

Further, the process of the present invention is characterized in that the separation step of the intermediate is not included between the step (a) of the hydrotreating of the present invention and the step (b) of the hydroconversion. The present invention does not have a hydroconversion step, but instead delivers the effluent from the fixed bed hydrotreating step directly to the bubbling bed hydroconversion. Thus, the present invention has a number of advantages, particularly: the process has better thermal integration due to the preservation of the temperature of the effluent exiting the hydrotreated fixed bed. This does not preclude the possibility of controlling and adjusting the temperature of the effluent leaving the step of hydrotreating from the fixed bed prior to the step of hydroconversion in the bubbling bed; due to the outlet of the fixed bed hydrotreating zone and the hydroconversion of the bubbling bed There is no significant depressurization between the inlets, so the described process has better energy efficiency; it simplifies the equipment used to perform the process, especially the components used to recover hydrogen during the process. In particular, in the absence of the separation step of the intermediate, since the hydrogen-rich gas is not discharged after the fixed bed treatment step, the fixed bed hydrotreating portion and the fluidized bed hydroconversion portion need only a single A common hydrogen recirculation line. A single compressor is sufficient, and the size of the compressor can be reduced and the flow rate of the recovered gas is also small.

According to the process of the present invention, heavy hydrocarbon feedstock containing sulfur can be converted to light ends, fuel oil and fuel bases, particularly for marine applications. The process described can result in a product having a lower sulfur content, and the process has higher yield and energy efficiency.

Hydrocarbon feedstock.

According to the process of the present invention, the hydrocarbon feedstock processed may be a "heavy feedstock". The feedstock has an initial boiling point of at least 340 ° C and a final boiling point of at least 440 °C. Preferably, the starting material has an initial boiling point of at least 350 ° C, preferably 375 ° C. Preferably, the starting material has a final boiling point of at least 450 ° C, preferably 460 ° C, more preferably 500 ° C, and even more preferably 600 ° C.

The hydrocarbon feedstock may be used singly or as a mixture from atmospheric residue, vacuum residue obtained from direct distillation, or crude oil, de-headed crude petroleums, debarred resin ( De-asphalting resins, de-asphalting pitches or asphalts, residual oils from self-conversion processes, aromatic extracts from lubricant base production lines, oil shale ( Bituminous sands) or derivatives thereof, bituminous shales or derivatives thereof, parent-rock oils or derivatives thereof. In the present invention, the raw material to be treated is preferably an atmospheric residue, a vacuum residue or a mixture thereof.

According to the process of the present invention, the treated hydrocarbon feedstock comprises sulfur. The hydrocarbons have a sulfur content of at least 0.5% by weight. Preferably, the sulfur content is at least 1% by weight. Preferably, the sulfur content is at least 4% by weight. More preferably, the sulfur content is at least 5% by weight.

Further, in accordance with the process of the present invention, the hydrocarbon feedstock treated comprises asphalt. The hydrocarbons have a sulfur content of at least 2% by weight. In the present invention, "asphalt" means heavy hydrocarbonized insoluble in n-alkane (also referred to as pitch of carbon 7) but soluble in toluene. Heavy hydrocarbon compounds. In general, the quantification of bitumen involves the analysis of defined normalizations, such as the AFNOR T 60-115 standard (France) (AFNOR T 60-115 (France)) or the ASTM 893-69 standard (USA) (ASTM893-69 (United) States)).

The metal nickel and metal vanadium content of the feedstock is greater than 110 parts per million (110 ppm) by weight, preferably greater than 150 ppm.

Preferably, the starting materials can be used in unmodified form. In addition, the raw materials may be diluted with a co-feedstock. The co-feedstock can be a lighter hydrocarbon fraction or a mixture of lighter hydrocarbon fractions. Preferably, the common raw material may be a product selected from a fluid catalytic cracking (FCC) process, a light cycle oil (LCO), and a heavy cycle oil (HCO). , decanted oil, FCC residue, gas oil fraction. In particular, the fraction obtained by atmospheric distillation or vacuum distillation. For example, vacuum gas oil or from another refining process. Preferably, the common raw material may be one or more fractions, aromatic extracts or any other hydrocarbon fraction from a liquefaction process of charcoal or biomass, or Petroleum raw materials, such as pyrolysis oil. In the present invention, the heavy hydrocarbon feedstock means that at least 50% by weight of all of the hydrocarbon feedstocks processed are passed through the process described. Preferably, it is at least 70% by weight. More preferably, at least 80% by weight. More preferably, at least 90% by weight.

Hydrotreating step (a).

According to the process of the present invention, the hydrocarbon feedstock is treated by a fixed bed hydrotreating step (a). Among them, the raw materials and hydrogen are placed and contacted with a hydrotreatment catalyst.

In general, "hydrotreating" is abbreviated as "HDT", which represents a catalytic treatment with a carrier of hydrogen, and is refined. That is to say, the content of metals, sulfur and other impurities is substantially reduced, and at the same time, the hydrogen/carbon ratio of the raw materials is improved, and part of the raw materials are more or less converted into lighter fractions. Hydrotreating specifically includes hydrodesulfurization reactions (ie, HDS), hydrodenitrogenation reactions (ie, HDN), and hydrodemetallization reactions (ie, HDM), which are accompanied by hydrogenation, Hydrodeoxygenation, hydrodearomatization, hydroisomerization, hydrodealkylation, hydrocracking and hydrodeasphalting reactions Conradson carbon reduction reaction.

According to a preferred variation, the hydrotreating step (a) comprises a first step (a1) of hydrodemetallation (HDM) followed by a second step of hydrodesulfurization (HDS). (a2). The first step (a1) is performed on one or more fixed-bed hydrodemetallation zones. The second step (a2) is performed on one or more fixed-bed hydrodesulfurization zones. In the first step (a1) of the hydrometallization, the raw materials and hydrogen are placed under hydrogenation and demetallization conditions and contacted with a hydrogenation metal removal catalyst. Next, in the second step (a2) of the hydrodesulfurization, the effluent from the first step (a1) of hydrodemetallization is placed under hydrodesulfurization conditions, and is contacted with one Hydrodesulfurization catalyst. The process is referred HYVAHL-F ^TM, and as described in U.S. Patent US 5417 846.

It will be readily understood by those skilled in the art that in the step of hydrogenation metal removal, the reaction of hydrogenation to metal removal is performed. However, compared to this, there are still some other hydrotreating reactions, especially hydrodesulfurization reactions. Similarly, in the step of hydrodesulfurization, a reaction of hydrodesulfurization is performed. However, compared to this, there are some other hydrotreating reactions, especially hydrodemetallization reactions. The skilled artisan understands that when The step of hydrogenation of the metal at the beginning of the hydrogen treatment step (in other words, when the metal concentration is maximum) begins. The skilled artisan understands that the step of hydrodesulfurization ends when the hydrotreating step is completed (in other words, when sulfur removal is most difficult). Between the steps of hydrodemetallization and the step of hydrodesulfurization, the skilled artisan occasionally defines a conversion zone which will carry out all types of hydrotreating reactions.

The step (a) of the hydrotreating of the present invention is carried out under the conditions of hydrotreating. The steps described can be advantageously carried out at temperatures between 300 ° C and 500 ° C. Preferably, it is carried out at a temperature between 350 ° C and 420 ° C. The steps described can be carried out at an absolute pressure between 2 million Pascals (MPa) and 35 MegaPascals. Preferably, it is carried out at an absolute pressure of between 11 MPa and 20 MPa. The temperature is usually adjusted as a function of the degree of hydrotreating desired and the processing time of the target. In general, the hourly space velocity (HSV) of a hydrocarbon feedstock is defined as the volume flow rate of the feed divided by the total volume of the catalyst, which may be between 0.1 and ¹ (h ^-1). ) and between 5 and ^{1 -} . Preferably, it is between 0.1 and ¹ and between 2 and ¹ . More preferably, it is between 0.1 and ¹ and between 0.45 and ^-1 . More preferably, it is between 0.1 and ¹ and between 0.2 and ¹ . The amount of hydrogen mixed with the feedstock may be between 100 standard cubic meters (Nm ³ ) and 5000 standard cubic meters per cubic meter of liquid feedstock. Preferably, it is between 200 standard cubic meters and 2000 standard cubic meters. More preferably, it is between 300 standard cubic meters and 1500 standard cubic meters. The hydrotreating step (a) can be carried out industrially in one or more descending-liquid reactors.

Preferably, the hydrotreating catalyst used is a known catalyst. The catalyst may be a particulate catalyst comprising at least one metal or metal compound having a hydro-dehydrogenating function on a support. Preferably, the catalyst may be a catalyst comprising at least one Group VIII B metal. Generally, the catalyst is selected from the group consisting of nickel, cobalt, and/or at least one Group 6B metal. Preferably, the Group 6B metal is molybdenum and/or tungsten. It can be employed on a mineral support, for example containing between 0.5% and 10% by weight of nickel. Preferably, between 1% and 5% by weight of nickel (expressed as nickel oxide NiO). And between 1% and 30% by weight of molybdenum. Preferably, between 5% and 20% by weight of molybdenum (expressed as molybdenum oxide MoO ₃ ). The support may be selected from, for example, alumina, silica, silica-aluminas, magnesia, clays or a mixture of at least two of the foregoing minerals. The group that makes up. Preferably, the support may comprise other doped compounds, in particular selected from the group consisting of boron oxide, zirconia, cerine, titanium oxide, phosphorus pentoxide (phosphorus). a group consisting of an oxide of pentoxide and a mixture of the above oxides. Alumina is typically used as a support, and typically the alumina support is also doped with phosphorus and selectively doped with boron. In the case of phosphorus pentoxide (P ₂ O ₅ ), its concentration is less than 10% by weight. In the case of boron trioxide (B ₂ O ₃ ), its concentration is less than 10% by weight. The alumina used may be γ (gamma) type alumina or η (eta) type alumina. The catalyst is typically in the form of extrudates. The total content of the Group 6B metal and the Group 8B metal oxide may be between 5% and 40% by weight, usually between 7% and 30% by weight. The weight ratio of the Group 6B and Group 8B metals to the metal oxide is between 20 and 1. Preferably, it is between 10 and 2.

In the case where the hydrotreating step sequentially comprises a hydrodemetallization (HDM) step followed by a hydrodesulfurization (HDS) step, it is preferred to use a catalyst which is specifically adapted to each step.

Catalysts that can be used in the hydrodemetallization (HDM) step are described, for example, in European Patent No. EP0113297, EP0113284, U.S. Patent No. 5,221,656, U.S. Patent No. 5,827,421, U.S. Patent No. 7,119,045, U.S. Pat. Preferably, the hydrogenation metal removal catalyst is used in permutable reactors.

Catalysts that can be used in the hydrodesulfurization (HDS) step are described in European Patent No. EP0113297, EP0113284, U.S. Patent No. 6,589,908, U.S. Patent No. 4,818,743, U.S.

Mixed catalysts active in hydrodemetallization and hydrodesulfurization, such as French patent FR 2 940 143, mixed catalysts for hydrodemetallization and hydrodesulfurization, can also be used.

In the process of the present invention, preferably, the catalyst used is subjected to in-situ or ex-situ vulcanization prior to injection of the feedstock.

In a preferred embodiment of the invention, the fixed bed hydrotreating step (a) uses a system of permutable reactors in the upstream of the main hydrotreatment reactors. Also known as a protected area. More specifically, the hydrotreating step (a) can be carried out in at least two hydrotreating protected zones prior to one or more fixed bed hydrotreating zones. The hydrotreating protected zone is also in a fixed bed, and the hydrotreating protected zone is arranged in series to consist of a continuous, repeating step (a)) and a step (a''') as defined below. Used in the cycle mode: step (a'): all protected areas are used together for a period of time, and the period of time during which the protection zone of one of the zones is inactive and/or clogging is used; step (a)) : when other protected areas are still in use, the protected area that is inactive and/or blocked is short-circuited, and the catalyst contained in the protected area is regenerated and/or replaced with fresh catalyst; (a'''): All protected areas are used together, and the protected areas that have been regenerated and/or replaced in the previous steps are reconnected. The protected area that is one of the longest during the use of this step is inactive and / or the time of the blockage.

Preferably, the reactor is reconnected to the downstream of the functioning reactor after regeneration and/or replacement of the catalyst in a reactor.

The system of the replaceable reactor is French patent FR 2 681 871 and FR 2 784 687 European patent EP 1343857. The function of the replaceable reactor is to protect the main downstream hydrotreatment reactors by preventing clogging and/or deactivation. In particular, the problem encountered with the use of a fixed bed is clogging, which can occur due to the bitumen and precipitate contained in the feedstock. Another problem is that the catalyst loses activity due to the large amount of precipitation of the metal in the hydrotreating reaction. Thereby, the replaceable reactor can be increased by replacing the inactive and/or clogged catalyst in the replaceable reactor operating in a one-cycle mode without stopping the overall unit for a period of time. The operation cycle of the hydrogen processing unit.

The time to loss of activity and/or clogging is a function of the material, the operating conditions of the hydrotreating step, and the catalyst used. In general, it is expressed by the decrease in the performance of the catalyst. The decrease in catalyst performance can be observed by increasing the concentration of metals and/or other impurities in the effluent, by maintaining the temperature required for the activity of the catalyst. The increase is observed, or in the case of a particular clogging, for example, by a significant increase in pressure drop. The drop in pressure ΔP, representing the degree of clogging, can be measured by the long-term measurement of the cycle in each zone, and can be defined by the increase in pressure in the zone due to the passage of a partially blocked passage through the zone. Similarly, the temperature can be measured over long periods of time through the two zones in the cycle.

In order to define deactivation and/or clogging time, the skilled artisan defines a maximum tolerable pressure loss value and/or temperature for the selected operating conditions and catalysts. The function, and the point disconnection of the protected area from which it must be executed. Thereby, the deactivation and/or clogging time can be defined as the time to reach the extreme value of the pressure drop and/or temperature. In the hydrotreating process of a heavy fraction, the extreme value of pressure loss is generally between 0.3 and 100. 10,000 Pa (MPa) and between 1 MPa (between 3 and 10 bar). Preferably, it is between 0.5 MPa and 0.8 MPa (between 5 and 8 bar). The extreme value of the temperature is generally between 400 ° C and 430 ° C, and the temperature is the average measured temperature corresponding to the catalyst bed.

In general, the operating conditions of the replaceable reactor are the same as those of the primary hydrotreating reactor. The hourly space velocity (HSV) of each of the operationally replaceable reactors is preferably between 0.2 and ¹ (h ^-1 ) and between 0.4 and ¹ . More ground, between 1 and 2 ^{-1 -1.} The overall hourly space velocity of the replaceable reactor and each reactor is selected to achieve maximum hydrogenation demetallization while controlling the reaction temperature while limiting the exotherm.

In a preferred embodiment of the invention, a catalytic conditioning section that replaces the operational zones is used, that is, without the operation of the stop component. The catalyst conditioning portion can comprise the following components: a system that can operate at an appropriate pressure, preferably between 1 megapascals (MPa) and 5 megapascals (between 10 and 50 bars). Preferably, between 1.2 MPa and 2.5 MPa (between 12 and 25 bar), cleaning, stripping, and before discharging the used catalyst Cooling operation of the unconnected protective reactor, followed by heating and vulcanization after replenishing fresh catalyst; another pressurization/depressurization and appropriate technique for regulating the valve system, which can be used These protective zones are replaced without a stop element, since all cleaning, dispensing, venting of the catalyst, replenishing fresh catalyst, heating and vulcanization occurs in the unconnected reactor or protection zone.

Alternatively, a pre-vulcanization catalyst can be used in the conditioning section to simplify the functioning permutation procedure.

The effluent exiting the replaceable reactor can then be passed to a primary hydrotreating reactor.

Each hydrotreating zone or hydrotreating zone may comprise at least one catalyst bed, such as 1, 2, 3, 4 or 5 catalyst beds. Preferably, each protected area comprises a catalyst bed. Each of the catalyst beds may comprise at least one catalyst layer, the catalyst layer comprising one or more catalysts, the catalyst layer comprising at least one inner layer, such as extrudates, beads or particles. (pellets) in the form of alumina or ceramics. The catalysts used in the catalyst bed may be the same or different.

According to a particular embodiment of the invention, the hydrocarbon feedstock passes through the inlet of each protected zone to a filter plate contained within the protected zone and downstream of the catalyst bed. Filter plates are described, for example, in French patent FR 2 889 973. Preferably, clogging particles contained in the hydrocarbon feedstock are trapped by a particular distributing plate comprising a filtration medium.

In the present invention, the effluent from the fixed bed hydrotreating step (a) does not undergo any separation step of the intermediate between the hydrotreating step (a) and the hydroconversion step (b). This configuration can be referred to as an integrated scheme.

In the present invention, "the separation step without intermediate" means that the effluent obtained from the step (a) of the hydrotreating is introduced at least partially without a change in chemical composition and any significant pressure loss. In the region of step (b) of the ebullating bed conversion. The "separation" means one or more separation bottles and/or one or more stripping columns or distillation columns, and the above items can be operated at different temperatures or pressures. The "significant pressure loss" is representative of the pressure loss caused by a buck turbine or helium, which can be estimated by a loss of more than 10% of the overall pressure. In general, the skilled artisan will use such pressure loss or drop in the separation step. Pressure.

According to one embodiment of the process of the invention, all of the effluent from the hydrodemetallization step (a) is introduced into the zone where step (b) of the hydroconversion is carried out.

In another embodiment, only a portion of the effluent from the hydrodemetallization step (a) is introduced to the zone where step (b) of the hydroconversion is carried out. However, this embodiment does not contradict the fact that the process does not include an intermediate separation step. This embodiment may consist of dividing the effluent from hydrotreating step (a) into two streams of the same composition and fractionating portions of the hydrotreated effluent (b). One gas stream is passed to the hydroconversion step (b), the other gas stream is passed to the separation step, and the fractionation portion is treated to treat the hydroconverted effluent (b). The fractionated portion of the hydro-converted effluent (b) is disposed downstream of the hydrotreating step (a). Therefore, the present embodiment can be likened to a partially short-circuited hydroconversion portion (b), but, for the separation or modification from the hydrotreating portion (a) to the bubbling bed heating conversion portion (b) without any chemical composition, Or any significant pressure drop. Another variation of the short-circuit straight line mode can be obtained by dividing the effluent of the hydrotreating step (a) into a plurality of gas streams having the same composition and feeding one or more of these gas streams to the inlet of the first fluidized bed hydroconversion reactor. And one or more other such streams are sent downstream of one or more hydroconversion reactors.

Ebullated bed hydroconversion step (b).

In accordance with the process of the present invention, at least a portion of the effluent obtained from step (a) of the hydrotreating is sent to at least one ebullated bed reactor comprising a supported catalyst to carry out the hydroconversion step (b). The reactor can operate with an ascending stream of liquids and gases. The main goal of hydroconversion is to convert heavy hydrocarbon feedstocks into lighter fractions while refining some of the heavy hydrocarbon feedstock.

According to an embodiment of the invention, part of the initial hydrocarbon feedstock can be hydrogenated from a fixed bed The effluent of treatment (a) is injected directly into the inlet of the bubbling bed hydroconversion zone (b) as a mixture, with the exception of the partial effluent being treated in the fixed bed hydrotreating section (a). This embodiment can be similar to a partial short circuit of the fixed bed hydrotreating zone (a).

According to a variant of the invention, the co-feedstock can be introduced into the inlet of the bubbling bed hydroconversion zone (b) together with the effluent from the fixed bed hydroconversion zone (a). The co-feedstock may be a mixture selected from the group consisting of atmospheric residue, vacuum residue obtained from direct distillation, de-asphalt oil, an aromatic extract obtained from a lubricating base line, a hydrocarbon fraction, or a hydrocarbon fraction. The mixture of hydrocarbon fractions may be selected from the group consisting of a fluid-bed catalytic cracking process, particularly light cycle oil (LCO), heavy cycle oil (heavy cycle oil). , HCO), decanted oil or may be derived from distillation, gas oil fractions, especially from atmospheric or vacuum distillation, such as vacuum gas oil. According to another variation of the invention and in the case where the hydroconversion section comprises several ebullated bed reactors, this co-feedstock may be partially or fully injected into one of the reactors downstream of the first reactor.

The hydrogen required for the hydroconversion reaction may be an inlet which has been injected into the ebullary hydrotreating portion (b) in a sufficient amount from the effluent obtained from the hydrotreating step (a). However, an additional carrier for supplying hydrogen at the inlet of the hydroconversion portion (b) is preferred. In the case where the hydroconversion zone contains several ebullated bed reactors, hydrogen can be injected into the inlet of each reactor. The injected hydrogen can be flowed in from the inlet or from the recycle.

The technique of a fluidized bed is well known to those skilled in the art. Therefore, only the main operating conditions are described below. Conventionally, the technique of a fluidized bed is to use an extruded catalyst in the form of an extrudates, and the carrier catalyst has a diameter of about 1 mm, for example, 0.9 mm or 1.2 mm. The catalyst is retained in the reactor, unless the catalyst is input or the catalyst is removed in order to maintain the activity of the catalyst, and the catalyst does not follow The product was removed. In order to obtain a higher conversion rate with a minimized amount of catalyst, the temperature can be at a higher level. Catalytic activity can be maintained at a constant value by on-line replacement of the catalyst. Therefore, it is not necessary to stop the component to replace the used catalyst, or to increase the temperature of the reaction in the cycle in order to compensate for the decreased activity. Furthermore, preferably, the operation in the cycle under defined operating conditions results in a quantitative yield and product quality. Further, since the catalyst maintains the disturbance by the flow of the largely recovered liquid, the pressure loss of the reactor is maintained at a low and constant value. The product leaving the reactor may contain fine catalyst particles due to friction of the catalyst in the reactor.

The conditions of step (b) of the hydrobed conversion of the fluidized bed may be standard conditions for the fluidized bed hydroconversion of the liquid phase hydrocarbon fraction. The process can be carried out at an absolute pressure of between 2.5 million Pascals (MPa) and 35 MPa. Preferably, it is between 5 MPa and 25 MPa. More preferably, it is between 6 MPa and 20 MPa. More preferably, it is between 11 MPa and 20 MPa. The process can be performed at a temperature between 330 ° C and 550 ° C. Preferably, it is between 350 ° C and 500 ° C. The hourly space velocity of hydrogen and the partial pressure of hydrogen are parameters that are set as a function of the characteristics of the product being processed and the desired conversion. The hourly space velocity (defined as the volumetric flow rate of the feed divided by the total volume of the bubbling bed reactor) is typically between 0.1 and ¹ (h ^-1 ) and between 10 h ^-1 and ^-1 . Preferably, between 0.2 and 5H ^{-1 -1 -1.} More specifically, between 0.2 and ¹ and 1h ^-1 to ^{1 -1} . The amount of hydrogen mixed with the feedstock is typically between 50 standard cubic meters (Nm ³ ) and 5000 standard cubic meters per cubic meter of liquid feedstock. It is usually between 100 standard cubic meters and 1500 standard cubic meters. Preferably, it is between 200 standard cubic meters and 1200 standard cubic meters.

A standard particulate hydrogenation conversion catalyst can be used, the catalyst comprising an amorphous support, at least one metal or metal compound having a hydro-dehydrogenating function. The catalyst may be a catalyst comprising a Group 8B metal, such as nickel and/or cobalt, and is typically used in combination with at least a Group 6B metal. The Group 6B metal is, for example, molybdenum and/or tungsten. A catalyst comprising, for example, 0.5 to 10% by weight of nickel and 1% to 30% by weight of molybdenum may be used. Preferably, from 1% to 5% by weight of nickel (expressed as nickel oxide NiO). Preferably, from 5% to 20% by weight of molybdenum (expressed as molybdenum oxide MoO ₃ ). The support may be selected from, for example, alumina, silica, silica-aluminas, magnesia, clays or a mixture of at least two of the foregoing minerals. The group that makes up. The support may further comprise other compounds, for example, selected from the group consisting of boron oxide, zirconia, titanium oxide, phosphorus oxide pentoxide oxide, and mixtures of the foregoing. Group. Typically, alumina supports and alumina supports which are typically doped with sulfur and optionally boron are used. In the case of phosphorus pentoxide (P ₂ O ₅ ), its concentration is less than 20% by weight and will generally be less than 10% by weight. In the case of boron trioxide (B ₂ O ₃ ), its concentration is less than 10% by weight. The alumina used may be γ (gamma) type alumina or η (eta) type alumina. The catalyst is typically in the form of extrudates. The content of the Group 6B and Group 8B metal oxides may be between 5% and 40% by weight. Usually, it is between 7% and 30% by weight. The weight ratio of the Group 6B and Group 8B metals in terms of metal oxide is between 20 and 1. Preferably, between 10 and 2.

The catalyst used can be partially replaced by fresh catalyst. It is generally removed from the bottom of the reactor at a fixed time and fresh or new catalyst is introduced from the top of the reactor. That is to say, for example, batches or continuous or substantially continuous. It is also possible to introduce the catalyst from the bottom of the reactor and remove the catalyst from the top. For example, it is possible to introduce fresh catalyst every day. The rate of replacement of the catalyst used with fresh catalyst can be, for example, about 0.05 kg per cubic meter of raw material and About 10 kg. Removal and replacement are the means by which the hydroconversion step can be operated continuously. The hydroconversion reactor typically includes a recirculating pump that continuously recovers at least a portion of the liquid removed from the top of the reactor and reinjects it into the bottom of the reactor to maintain the catalyst within the bubbling bed. It is also possible to move the catalyst used from the reactor to the regeneration zone, and the carbon and sulfur contained in the regeneration zone are removed before entering the hydroconversion step (b).

In the process of the present invention, the hydroconversion step (b) can be carried out under the conditions of the H-OIL® process described in, for example, U.S. Patent No. 6,270,654.

Fluidized bed hydroconversion can occur in one reactor or multiple reactors. Preferably, this occurs in two reactors arranged in series. The use of at least two ebullated bed reactors arranged in series may result in a product of better quality and better yield. In addition, hydroconversion at the second reactor can have operating conditions and flexibility of the catalyst system to improve operability. Preferably, the temperature of the second ebullated bed reactor is at least 10 ° C higher than the temperature of the first ebullated bed reactor. The pressure of the second ebullated bed reactor may be between 0.1 MPa and 1 MPa lower than the temperature of the first ebullated bed reactor such that at least a portion of the effluent obtained from the first step flows without pressure. The operating conditions of the temperature of the two hydro-conversion reactors are selected to control the hydrogenation of the feed to form the desired product in each reactor.

In the case where the hydroconversion step (b) is carried out in two sub-steps (b1) and (b2) in two reactors connected in series, the effluent obtained from the first sub-step (b1) can be selectively After the separation step of the light fraction and the heavy fraction, and at least in part, preferably all of the heavy fraction can be treated in the sub-step (b2) of the second hydrocarbon conversion. Preferably, the separating step can be performed in an inter-stage separator as described in U.S. Patent No. 6,270,654, which avoids overcracking of light ends in the second hydroconversion reactor. The catalyst used can be moved, in whole or in part, from the first hydroconversion substep (b1) operating at a lower temperature to the second subunit operating at a higher temperature. Step (b2), or all or part of the use of the catalyst directly from the second sub-step (b2) of the reactor to the first sub-step (b1) of the reactor. This cascade system is described in U.S. Patent No. 4,184,841.

Separation step (c) of the hydroconversion effluent.

In the present invention, the process may further comprise a separation step (c). Thereby, at least one gas phase fraction and at least one liquid phase hydrocarbon fraction are obtained.

The effluent obtained after the step (b) of the hydroconversion comprises a liquid phase fraction and a gas phase fraction. The gas phase fraction contains a gas such as hydrogen (H ₂ ) hydrogen sulfide (H ₂ S) ammonia gas (NH ₃ ) and hydrocarbons having a carbon number of 1-4 (C ₁ - C ₄ hydrocarbons). This vapor phase fraction can be separated from the hydrocarbon effluent by a separation apparatus. Separating equipment is known to those skilled in the art, particularly using one or more separate flasks that can be operated at different pressures and temperatures, and optionally stripped with steam or hydrogen ( Stripping) means a combination. Preferably, the effluent obtained after the hydroconversion step (b) can separate at least one gas phase fraction and at least one liquid phase fraction in at least one separation vial. These separators can be, for example, high-pressure high-temperature (HPHT) and/or high-pressure low-temperature (HPLT).

Preferably, after selective cooling, the vapor phase fraction is treated by means of a hydrogen purification unit to recover hydrogen gas which is not consumed in the hydrotreating and hydroconversion reactions. The hydrogen purification means may be an amine wash, a membrane, a Pressure Swing Adsorption (PSA) or a series connection of these means. In the present invention, preferably, after selective recompression, the purified hydrogen can then be recovered into the process. Hydrogen can be introduced to the inlet of the hydrotreating step (a) and/or to different locations in the hydrotreating step (a) and/or to the hydroconversion step (b) The inlet and/or the different positions in the hydroconversion step (b).

The separation step (c) may also comprise atmospheric distillation and/or vacuum distillation. Preferably, the separating step (c) further comprises at least one atmospheric distillation. Wherein, the liquid-saturated hydrocarbon fraction obtained after the separation step is fractionated by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction. The atmospheric distillation fraction may comprise commercially upgradeable fuel bases (naphtha, kerosene, and/or diesel), such as by refining to produce fuel for mobile vehicles and aviation.

Further, preferably, the separation step (c) of the process of the present invention may comprise at least one vacuum distillation, a liquid fraction obtained after separation in vacuum distillation, and/or an atmospheric residue obtained after atmospheric distillation. The fraction is distilled into at least one vacuum distillation fraction and at least one vacuum residue fraction by vacuum distillation. Preferably, the separating step (c) comprises first atmospheric distillation followed by vacuum distillation. In atmospheric distillation, the liquid fraction obtained after separation is subjected to atmospheric distillation to fractionate into at least one atmospheric distillation fraction and at least one atmospheric residue fraction. In vacuum distillation, the atmospheric residue obtained after atmospheric distillation is fractionated by vacuum distillation into at least one vacuum distillation fraction and at least one vacuum residue fraction. The vacuum distillation fraction typically comprises a fraction in the form of a vacuum gasoline.

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

After the separation step (c), at least a liquid fraction having a sulfur content of less than or equal to 0.5% by weight can be obtained. Preferably, it is less than or equal to 0.3% by weight. More preferably, it is less than or equal to 0.1% by weight. More preferably, it is less than or equal to 0.08% by weight. Preferably, the liquid hydrocarbon fraction can be used as a fuel base, particularly as a marine fuel. Preferably, all of the liquid hydrocarbon effluent obtained from the separation step (c) may have a sulfur content of less than or equal to 0.5% by weight. Preferably, the sulfur content is less than or equal to 0.3% by weight. More preferably, the sulfur content is less than or equal to 0.1% by weight. More preferably, the sulfur content is less than or equal to 0.08% by weight.

In the present invention, the conversion rate of the hydrocarbon feedstock to a lighter fraction is between 10% and 95%. Preferably, it is between 25% and 90%. More preferably, between 40% and 85%. The degree of the above conversion ratio is defined as follows: the amount of the compound having a temperature higher than 520 ° C in the initial hydrocarbon raw material minus the amount of the compound having a temperature higher than 520 ° C in the hydrocarbon effluent obtained after the hydroconversion step (b) The difference obtained is then divided by the amount of the compound having a higher than 520 ° C in the initial hydrocarbon feed. As long as the degree of conversion indicates the production of conversion products, mainly naphtha, kerosene and diesel types in a certain amount of atmospheric distillation and/or vacuum distillation, a high degree of conversion is preferred.

Preferably, the liquid phase hydrocarbon effluent is used, at least in part, as a fuel base or fuel having a lower sulfur content, particularly a marine fuel base or marine fuel, in accordance with the new International Maritime Organization recommendations.

In the present invention, "fuel" means a hydrocarbon material which can be used as a fuel. In the present invention, the "fuel base" means a fuel composed of a mixture of a hydrocarbon raw material and other substrates. As a function of these substrate sources, especially the type of crude oil and the type of refining type, the properties of these substrates, especially their sulfur content and viscosity, are quite diverse.

Optional separation step (d) of the precipitate from the powder.

The hydrocarbon effluent obtained after the hydroconversion step (b), in particular the heaviest liquid fraction obtained, may comprise a precipitate in the form of a powder obtained from a fixed bed step and/or from an ebullated bed step. And catalyst residue. In order to obtain a fuel or fuel base in accordance with the proposal, that is, the content of the precipitate after aging is less than or equal to 0.1%, the process of the present invention may comprise an additional step which is after the separation step (c) and is carried out by The liquid hydrocarbon effluent consists of a step of separating the precipitate from the powder.

In the present invention, the process may further comprise the step (d) of separating the precipitate from the powder. In the separating step, at least a portion of the atmospheric residue fraction and/or the vacuum distillation fraction and/or the vacuum residue fraction is using at least one filter, a centrifugal system or an on-line decantation (on- Line decantation) to separate the precipitate and catalyst powder.

Optional catalyst lysis step (e).

According to an embodiment of the invention, the process may further comprise the step (e) of catalytic cracking. In this step, at least a portion of the vacuum distillate fraction and/or the vacuum residue fraction, optionally, is sent to the touch prior to the step (d) of separating the precipitate and the powder. Media cracking part. In the catalytic cracking section, it is treated under the conditions that a gas phase fraction, a petroleum fraction, a diesel fraction, and a residue fraction can be produced.

The catalyst cracking step (e) may be a step of fluidized-bed catalytic cracking, such as the known R2R process developed by the applicant. The steps described can be carried out under suitable cleavage conditions in a conventional manner as understood by those skilled in the art to obtain a hydrocarbon product having a lower molecular weight. In the catalytic cracking step (e), the functions and catalysts are described in, for example, U.S. Patent No. 4,695,370, European Patent No. EP 0 845 517, U.S. Patent No. 4,959,334, European Patent No. EP 0 323 297, U.S. Patent No. 4,496,232, US Pat. No. 5,106, 061, US Pat. No. 5,344,554, US Pat. U.S. Patent No. 5,286,690, U.S. Patent No. 5,324,696, European Patent No. EP 0 542 604, and EP 0 699 224.

A fluidized-bed catalytic cracking reactor can operate in an ascending stream or a descending stream. Although this is not a preferred embodiment, it is still conceivable to perform a media cracking in a mobile-bed reactor. Preferably, the catalytically cleaved catalyst comprises at least one zeolite, It is usually mixed with a suitable matrix such as alumina, silica or silica-alumina.

The residue fraction obtained at least in part from the catalyst cracking step (e), which is generally considered by the prior art to be a "slurry" fraction, can be recovered to the inlet of the catalyst cracking step (e) and/or The inlet to the hydrotreating step (a) and/or the inlet to the hydroconversion step (b). At least some or even all of the residue fraction can be sent to a zone where heavy refinery fuel oil is stored.

In one embodiment of the invention, a portion of the diesel fraction and/or residue fraction obtained after the catalyst cracking step (e) can be used to form a flux base.

Flux and fuel oils.

One of the objects of the present invention is to produce a commercially available fuel, particularly for marine transportation. It is preferred that this type of fuel meets specific specifications, particularly viscosity. Preferably, the type of marine fuel that is quite common has a viscosity of less than or equal to 380 cSt (at 50 ° C). Other qualities of fuel, known as "grades", meet different specifications, especially in terms of adhesion. In particular, in terms of distillation type, the DMA grade specifies a viscosity between 2 cSt and 6 cST at 40 ° C, and the DMB grade specifies a viscosity between 2 cSt and 11 cST at 40 ° C. In order to obtain the target viscosity of the desired grade of fuel, the fuel base can be mixed with flux bases or cutter stocks, if necessary. The specification of the fuel is, for example, in ISO standard 8217 (the last standard in 2012) (standard ISO 8217 (last version in 2012)).

In general, the flow substrate is a kerosene, gasoline or vacuum gas oil type. It may be selected from light cycle oils obtained by catalyst cleavage, heavy cycle oils obtained by catalyst cracking, catalyst cracked residue, kerosene, gasoline, vacuum Distillate and / or decanted oil.

According to the process of the present invention, the atmospheric residue and/or the vacuum distillate and/or the vacuum residue obtained after the step (c) are separated, optionally, before the step (d) of separating the precipitate or the powder, One or more flow substrates are mixed. The flow substrate may be selected from the group consisting of light cycle oil obtained by catalyst cracking, heavy cycle oil obtained by catalyst cracking, catalyst cracked residue, kerosene, gasoline, vacuum distillate and/or decant oil. Group.

In a preferred embodiment, the flow substrate is a residue fraction selected from a portion of the diesel fraction and/or the catalyst cracking step (e). In a preferred embodiment, the flow substrate is a residue fraction selected from a portion of the diesel fraction and/or the catalyst cracking step (e). Additionally, or the flow substrate may be a media oil and/or diesel fraction selected from the group after the bubbling bed hydroconversion step.

After the step of mixing the atmospheric residue and/or vacuum distillate and/or vacuum residue obtained after the separation step (c) with one or more flow substrates, optionally, separating the precipitate and the powder Prior to step (d), fuel is preferably available for marine transportation having a low sulfur content, also known as marine fuel.

One subject of the present invention is also a fuel having a sulfur content of less than or equal to 0.5% by weight. Preferably, it is a content of sulfur of less than or equal to 0.1% by weight. Preferably, the fuel has a precipitated amount of less than or equal to 0.1% by weight, which meets the new standard of ISO8217:2012.

In addition, the viscosity of the fuel at 50 ° C is between 1 cSt (centistokes, 1 cSt = 10 ^-6 m ² .s ^-1 ) and 700 cSt.

The process of the preferred embodiment of the present invention is shown in Figs. 1 and 2 .

Figure 1 is an integrated view of a process in accordance with the present invention. That is, there is no intermediate separation step There is no particular depressurization between the fixed bed portion and the bubbling bed portion. For ease of reading, the operation of the protected zone of the hydrotreating section in Figure 1 is as shown in Figure 2.

In Figure 1, the feedstock 10 is preheated in the chamber 12, and the recovered hydrogen 64 and the incoming hydrogen 24 preheated via the chamber 16 are mixed by a common line 14, the mixture of which is mixed with the feedstock 10, through line 18 A guard zone system is introduced.

Referring to Figure 2, the operation of the protected zone of the hydrotreating section comprises a secondary zone (or a replaceable reactor) Ra and Rb. The function of the protected zone of the hydrotreating section comprises a series of cycles, each cycle comprising four consecutive steps: (step i) the feedstock is passed sequentially through the reactor Ra and then Rb; (step ii) the feedstock is passed only through the reactor Rb, the reactor Ra is short-circuited to replace and/or replace the catalyst; (step iii) the raw material is sequentially passed through the reactor Rb and then Ra; (step iv) the raw material passes only through the reactor Ra, the reactor Rb is a short circuit to replace and/or replace the catalyst.

The loop can then be restarted.

In step i and step iii, all protected areas are used. In step ii and step iv, one protected area is shorted and the other protected area is used.

In step i, the preheated feedstock is introduced into line 18 and line 19. Line 19 contains valve V1 and valve V1 is open to line 20 and to protective reactor Ra. The protective reactor Ra contains a fixed bed A of catalyst. During this time, valves V3, V4 and V5 are closed. The effluent from the reactor Ra is sent to the protective reactor Rb through the line 21, the line 22 and the line 23. Line 22 contains an open valve V2. The protective reactor Rb contains a fixed bed B of catalyst. From reactor Rb The effluent is sent to the main hydrotreating section (described in the following paragraph) via line 24, line 25, and line 26. Line 25 contains an open valve V6.

In step ii, valves V1, V2, V4 and V5 are closed and the feedstock is directed to line 18 and line 27. Line 27 contains valve V3, which is open to line 23 and reactor Rb. During this time, the effluent from reactor Rb is sent to the main hydrotreating section via line 24 line 25 and line 26. Line 25 contains an open valve V6.

In step iii, valves V1, V2, and V6 are closed and valves V3, V4, and V5 are open. The raw materials are introduced into the reactor Rb through the line 18 and the lines 27 and 23. The effluent from the reactor Rb is sent to the protective reactor Ra via line 24 line 28 and line 20. Line 28 contains an open valve V4. The effluent from reactor Ra is sent to the main hydrotreating section via line 21 and line 29 and line 26. Line 29 contains an open valve V5.

In step iv, valves V2, V3, V4, and V6 are closed and valves V1 and V5 are open. The raw materials are introduced into the reactor Ra through the line 18 and the lines 19 and 20. During this time, the effluent from reactor Ra is sent to the main hydrotreating section via line 21, line 29, and line 26. Line 29 contains an open valve V5.

Referring again to Figure 1, the effluent exiting the protection reactor is optionally remixed with hydrogen from line 65 to the hydrodemetallization reactor 30. The hydrodemetallization reactor 30 contains a fixed bed 32 of catalyst. For ease of reading, the drawing only shows a single hydrodemetallization reactor and a single hydrodesulfurization reactor, and the hydrodemetallization and hydrodesulfurization section may contain several hydrogenation and demetallization in series. Reactor and hydrodesulfurization reactor. If desired, the recovered and/or inlet hydrogen can also be introduced into a hydrotreating reactor (not shown) between a plurality of circulating beds.

The effluent from the hydrodemetallization reactor is passed through line 34 and then sent to the first hydrodesulfurization Sulfur reactor 36. The effluent from the first hydrodesulfurization reactor 36 passes through a fixed bed 38 of catalyst.

The effluent obtained from the hydrotreating step is passed through line 42 and passed to a fluidized bed hydroconversion section via a selective heat exchanger 43. The effluent from the hydrotreating step to the bubbling bed hydroconversion portion can be selectively mixed with the co-feed 94 and/or selectively with the recovered hydrogen 88. The recovered hydrogen 88 is selectively heated by the inlet hydrogen 90 in the oven 91. The effluent of the hydrotreating step or a mixture of co-feedstock and/or hydrogen is then introduced via line 96 to the hydroconversion step and operates with the updraft of liquids and gases and comprises at least one hydrocarbon shifting contact Media. The hydroconversion step is at the bottom of the first bubbling bed reactor 98. Reactor 98 typically includes a recycle pump 100 that maintains the bubbling bed catalyst by continuously recovering at least a portion of the liquid phase from the bottom of the reactor into the bottom of the reactor. Fresh catalyst can be input from the top or bottom of the reactor (not shown). The input to the catalyst can be periodic or continuous. The catalyst used can be discarded or regenerated from the bottom of the reactor (not shown) to remove carbon and sulfur before being injected into the top of the reactor. The partially used catalyst can be transferred directly from the bottom of the first reactor to the top of the second hydroconversion reactor 102 (not shown). Alternatively, the converted effluent 104 obtained from reactor 98 can be separated by a light fraction 106 within an inter-stage separator.

Preferably, all or a portion of the effluent 110 obtained from the interstage separator 108 is mixed with additional hydrogen from line 157. If necessary, the hydrogen is preheated (not shown). This mixture is then injected through line 112 to a second ebullated bed hydroconversion reactor 102 to operate with a liquid and an updraft of gas comprising at least one hydroconversion catalyst. The operating conditions of the reactor, particularly the temperature, are chosen to achieve the desired degree of conversion (as described above). The input and removal of the catalyst is performed in the same manner as described for the first reactor. Reactor 102 typically also includes a recirculation pump 114 that operates in the same manner as the pump of the first reactor.

The effluent from the ebullated bed reactor is sent to high pressure high temperature separator 136 through line 134. The gas phase fraction 138 and the liquid phase fraction 140 are recovered in a high pressure high temperature separator 136. In general, the gas phase fraction 138 is sent to a high-pressure low-temperature (HPLT) 144 through an exchanger (not shown) or a cooling tower 142 for cooling. The gas phase fraction 146 and the liquid phase fraction 148 containing a gas (hydrogen, hydrogen sulfide, ammonia, hydrocarbons having a carbon number of 1 to 4, etc.) are recovered in a high pressure cryogenic separator 144.

The gas phase fraction 146 from the high pressure cryogenic separator 144 is treated in a hydrogen purification unit 150 for recovery to the hydroconversion portion via compressor 154 and line 156 and/or line 157. The recovered hydrogen 152 is derived from the hydrogen purification unit 150. The hydrogen purification unit may be composed of an amine wash, a membrane or a Pressure Swing Adsorption (PSA). Gas containing undesired nitrogen and sulfur-containing compounds is withdrawn from the facility (gas stream 158 can represent a variety of gas streams, particularly hydrogen sulfide-rich gas streams and one or more light hydrocarbons (carbon numbers 1 and 2) Purges, light hydrocarbons can be used as refining fuel gas).

The liquid fraction 148 from the high-pressure low-temperature (HPLT) separator 144 is depressurized in the apparatus 160 and sent to the fractionation system 172. Alternatively, a medium-pressure separator (not shown) may be installed after the pressure relief device 160 to recover the delivery to the purification unit 150 and/or a dedicated intermediate pressure separator (not shown). The vapor phase is communicated to the liquid phase of the fractionation section 172.

The liquid fraction 140 from the high-pressure hugh-temperature (HPHT) separator 136 is depressurized in the apparatus 174 and sent to the fractionation system 172. Alternatively, a medium-pressure separator (not shown) may be installed after the pressure relief device 174 to recover the delivery to the purification unit 150 and/or a dedicated intermediate pressure separator (not shown). Vapor phase and conveyed to The liquid phase of fraction 172 is fractionated.

Clearly, after depressurization, fractions 148 and 140 can be sent to system 172 together. The fractionation system 172 includes an atmospheric distillation system to produce a vapor phase effluent 176, at least one "light" fraction 178, particularly comprising naphtha, kerosene and diesel, and an atmospheric residue fraction 180. A portion of the atmospheric residue fraction 180 can be retrieved through line 182 to form the desired fuel base. All or part of the atmospheric residue fraction 180 can be sent to a vacuum distillation column 184 to recover a fraction comprising vacuum residue 186 and a vacuum distillation fraction 188 comprising vacuum gasoline. Preferably, at least a portion of the vacuum residue fraction is recovered through line 190 to the hydroconversion step or upstream of the hydrotreating step (not shown) to increase the conversion rate. Alternatively, the atmospheric residue fraction 182, the vacuum distillation fraction 188, and/or the vacuum residue fraction 186 may be separately passed through steps of separating the powder and the precipitate, such as filters 191, 192, and 193.

An alternative (not shown) for separation and fractionation can be carried out using a steam stripping column for treating heavy fractions at high or medium or low pressure. Thereby, the bottom of the column is directly filled to fill the vacuum column; the atmospheric distillation column is maintained to treat the distillation mixture, but the unconverted fraction (the heaviest fraction) is not treated.

Example

The following examples are intended to illustrate the invention and are not intended to limit the scope of the invention.

Treatment of a vacuum residue (RSV Arabian Heavy) containing 88.6% by weight of the compound vaporized at a temperature above 520 ° C and having a density of 6.2 ° API and a sulfur content of 5.2% by weight. . The feedstock contained 202 ppm of metal (nickel + vanadium).

The feedstock is processed in a hydrotreating step with a two-replaceable reactor. The proportion of the hydrodemetallization/hydrodesulfurization catalyst in the feedstock is 40/60. The operating conditions for the fixed bed step are shown in Table 1:

The performance of the hydrodemetallization (HDM) of the fixed bed hydrotreating section is greater than 80%.

The hydrotreating effluent is not passed through any separation step and is sent to the hydroconversion step as a whole. The hydroconversion step comprises two continuous ebullated bed reactors. The operating conditions of the steps of the bubbling bed are shown in Table 2.

The yield of each fraction obtained from the effluent leaving the hydroconversion portion and the sulfur content are shown in Table 3.

The hydrogen consumed represents 3.4% by weight of fresh feedstock being introduced into the inlet of the hydrotreating section.

The above yield can be used to calculate the degree to which the fraction of the raw material vaporized above 520 ° C is converted to the conversion rate of the product vaporized below 520 ° C, according to the following formula:

The values are as follows: conversion rate = (88.6 - 25.2) / 88.6 = 71.5%.

This particularly high conversion rate illustrates the production of a significant amount of conversion product (primarily distillate).

Then, according to the following ratio, 350 to 520 ° C and 520 ° C ⁺ fraction obtained from the hydroconversion step were prepared to prepare a mixture: 350 to 520 ° C fraction: 44% by weight of the mixture; and 520 ° C ⁺ fraction: 56% by weight of the mixture percentage.

Thereby, the obtained fuel had a sulfur content of 0.42% by weight and an adhesion of 380 cSt at 50 °C. Further, the content of the precipitate after aging is less than 0.1% by weight. With regard to these analyses, this fuel is particularly suitable for use in composing marine fuels such as those recommended by the International Maritime Organization outside the sulphur emission control zone by 2020 or 2025.

The second mixture consisted of 20% by weight of the fraction obtained from the diesel cycle and 80% by weight of the fraction obtained from the vacuum distillation cycle. At this ratio, the mixture had a sulfur content of 0.09% and a viscosity of 6 cSt at 40 °C. Thereby, the mixture constitutes a marine fuel of a distillation type ("marine gas-oil" or "marine diesel"). This marine fuel may be referred to as, for example, the DMB specification (which specifies a viscosity between 2 cSt and 11 cSt at 40 ° C). Due to its sulfur content below 0.1%, this mixture constitutes the fuel for the pre-2015 target of the Sulphur Emission Control Zone.

10‧‧‧Materials

12‧‧‧ chamber

14‧‧‧Common pipeline

16‧‧‧ chamber

18‧‧‧pipe

24‧‧‧ Input hydrogen

30‧‧‧Hydrogenation to metal reactor

32‧‧‧fixed bed

34‧‧‧pipe

36‧‧‧First Hydrodesulfurization Reactor

38‧‧‧fixed bed

42‧‧‧pipe

43‧‧‧ heat exchanger

64‧‧‧Recovered hydrogen

65‧‧‧pipe

88‧‧‧Recovered hydrogen

90‧‧‧ Hydrogen

91‧‧‧Oven

94‧‧‧Common raw materials

96‧‧‧pipe

98‧‧‧First bubbling bed reactor

100‧‧‧Recycling pump

102‧‧‧Second boiling bed hydroconversion reactor

104‧‧‧ effluent

106‧‧‧Light fractions

108‧‧‧Interstage separator

110‧‧‧ effluent

112‧‧‧ pipeline

114‧‧‧Recycling pump

134‧‧‧pipe

136‧‧‧High pressure high temperature separator

138‧‧‧ gas fraction

140‧‧‧liquid fraction

142‧‧‧Cooling tower

144‧‧‧High pressure cryogenic separator

146‧‧‧ gas phase fraction

148‧‧‧ liquid fraction

150‧‧‧Hydrogen purification unit

152‧‧‧Recovered hydrogen

154‧‧‧Compressor

156‧‧‧ pipeline

157‧‧‧pipe

158‧‧‧ airflow

160‧‧‧ device

172‧‧‧ fractionation system

174‧‧‧ device

176‧‧‧ gas phase effluent

178‧‧‧Light fractions

180‧‧‧ atmospheric residue fraction

182‧‧‧pipe

184‧‧‧Vacuum distillation column

186‧‧‧vacuum residue

188‧‧‧vacuum distillation fraction

190‧‧‧pipe

191‧‧‧Filter

192‧‧‧Filter

193‧‧‧Filter

Ra‧‧ ‧ protected area

Rb‧‧ ‧ protected area

Claims (16)

A process for treating a hydrocarbon feedstock having a sulfur content of at least 0.5% by weight, a bitumen content of at least 2% by weight, an initial boiling point of at least 340 °C, and a final boiling point of at least 440 ° C, the process may be used to obtain at least one liquid phase hydrocarbon fraction having a sulfur content and an amount of less than or equal to 0.5% by weight, the process comprising the following consecutive steps: a fixed A fixed-bed hydrotreatment, wherein the hydrocarbon feedstock and hydrogen are placed in contact with at least one hydroconversion catalyst; in at least one ebullated-bed reactor, from at least a portion of the step (a) a step (b) (hydroconversion) of hydroconversion of one of the obtained effluents, the bubbling bed reactor comprising a carrier catalyst; and a step of separating one of the effluents obtained from the step (b) (c) to obtain at least one gas phase fraction and at least one liquid phase fraction; wherein there is no separation step of the intermediate between the hydrotreating step (a) and the hydroconversion step (b). The process of claim 1, wherein the step (a) of the hydrotreating process comprises: a step (a1) of hydrogenation and demetallization, performed in one or more fixed bed hydrogenation metal removal zones; The step (a2) of the hydrogen desulfurization procedure, after the step (a1) of the hydrodemetallization, the step (a2) of the hydrodesulfurization procedure is carried out in one or more fixed bed hydrodesulfurization zones. The process of any of claim 1 or claim 2, wherein the temperature of the step (a) of the hydrotreating is between 300 ° C and 500 ° C, and the absolute pressure is between 2 MPa ( Between MPa) and 35 MPa, the space velocity of the hydrocarbon feedstock is between 0.1 hours ^-1 (h ¹ ) and 5: ¹ , and the amount of hydrogen mixed with the raw material is between 100 standard cubic meters. Metric (Nm ³ /m ³ ) and 5000 standard cubic meters. The process of claim 1, wherein the absolute pressure of the step (b) of the hydroconversion is between 2.5 MPa and 35 MPa, and the temperature is between 330 ° C and 550 ° C, hourly space velocity between one of between 0.1 and 5 h ^-1, and ^-1, and the amount of mixing of the feedstock with hydrogen is between 50 and 5000 standard cubic meters standard cubic meters. The process of claim 1, wherein the hydrotreating step (a) is carried out by at least two hydrotreating protection zones before the one or more fixed bed hydrotreating zones, the hydroprotecting zones being located in the fixed bed And the hydrogenation protection zones are connected in series and can be used in one cycle consisting of steps (a") and (a''') which are continuously repeated as follows: one step (a'), wherein all The protected areas are used together for a period of time equal to the time during which one of the protected areas is inactive and/or blocked; in a step (a"), wherein the inactive and/or blocked protective area is shorted (short) -circuited) and the catalyst contained in the protected area is regenerated and/or replaced by fresh catalyst, and at the same time other such protected areas are used; and a step (a''') in which all of the protected areas are Used together, wherein the protected area in which the catalyst is regenerated and/or replaced in the aforementioned step (a") is reconnected and the time used in the step (a''') is at most equal to one of the protected areas being inactive and/or Or the time of blocking. The process of claim 1, wherein the hydrocarbon raw material is selected from atmospheric residue and is directly distilled. Vacuum residue, crude oil, de-headed crude petroleums, deasphalting resins, deasphalting pitches or asphalts, residue from the conversion process, lubricated An aromatic extract obtained from lubricant base production lines, oil shale (bituminous sands) or a derivative thereof, one or a mixture of parent-rock oils or derivatives thereof. The process of claim 1, wherein the separating step (c) further comprises at least one atmospheric distillation, wherein the liquid phase hydrocarbon fraction obtained after the separation is divided into at least one atmospheric pressure by atmospheric distillation. A distillation fraction and at least one atmospheric residue fraction. The process of claim 1, wherein the separating step (c) further comprises at least one vacuum distillation, the vacuum distillation, the liquid phase hydrocarbon fraction obtained after the separation, and/or after the atmospheric distillation The resulting atmospheric residue fraction is fractionated by vacuum distillation into at least one vacuum distillation fraction and at least one vacuum residue fraction. The process of claim 8, wherein at least a portion of the vacuum residue fraction is recovered to the step (b) of the hydroconversion. The process of claim 7, further comprising a step (d) of separating the precipitate and the powder, wherein at least a portion of the atmospheric residue fraction and/or the vacuum distillation fraction and/or the vacuum residue fraction are filtered by at least one A catalyst, a centrifugation system or an on-line decantation to separate the catalyst powder and precipitate. The process of claim 10, further comprising a catalyst cracking step (e), wherein at least a portion of the vacuum distillation fraction and/or the vacuum residue fraction is prior to the step (d) of separating the precipitate and the powder, Is sent to a catalyst cracking part, in the catalyst cracking part, the part of the vacuum distillation fraction can generate a gas The fraction, a petroleum fraction, a diesel fraction, and a residue fraction are treated under conditions. The process of claim 10, wherein the atmospheric residue and/or vacuum distillate and/or vacuum residue obtained after the separating step (c) is in the step of separating the precipitate and the powder (d) Before mixing with one or more flow substrates, the one or more flow substrates are selected from light catalyst oils from a catalytic cracking, cleavage from a catalyst The resulting heavy cycle oils from a catalytic cracking, a residue of a catalytic cracking, kerosene, gas oil, vacuum distillate And/or a group of decanted oils. The process of claim 12, wherein the flow substrate is selected from the group consisting of diesel fractions and/or residue fractions obtained from the catalyst cracking step (e). A fuel oil for use in marine transportation, the fuel being obtained by the process of claim 12, having a sulfur content of less than or equal to 0.5% by weight. The fuel of claim 14, wherein the fuel has a precipitate content of less than or equal to 0.1% by weight. The fuel of claim 14, wherein the fuel has a viscosity of between 1 cSt and 700 cSt at 50 °C.