Classifications

• • C—CHEMISTRY; METALLURGY
  • C01—INORGANIC CHEMISTRY
  • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
  • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
  • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
  • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
  • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
  • C01B3/36—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using oxygen or mixtures containing oxygen as gasifying agents
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G17/00—Refining of hydrocarbon oils in the absence of hydrogen, with acids, acid-forming compounds or acid-containing liquids, e.g. acid sludge
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
  • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels

Definitions

• the present invention relates to the refining and conversion of heavy hydrocarbon fractions containing, inter alia, sulfur impurities. It relates more particularly to a process for the treatment of heavy petroleum feedstocks for the production of fuel oils and oil bases, in particular bunker oil and bunker oil bases with low sulfur content.
• the equivalent sulfur content recommended by 2020 or 2025 is less than or equal to 0.5% by weight for vessels operating outside the "Sulfur Emission Control Areas" (ZCES or SECA, "Sulfur Emission Control Areas "according to the English terminology).
• ZCES Sulfur Emission Control Areas
• ⁇ has an equivalent sulfur content of 0.1% by weight or less on the horizon
• another very restrictive recommendation concerns the sediment content after aging according to ISO 10307-2 which must be less than or equal to 0.1%.
• the applicant has set itself the objective of producing fuel oils and fuel oil bases, in particular bunker oil and bunker oil bases, in accordance with the recommendations of the MARPOL Convention in terms of equivalent sulfur content, and preferably respecting also recommendations on sediment content after aging.
• Fuel oils used in marine transport generally include atmospheric distillates, vacuum distillates, atmospheric residues and vacuum residues from direct distillation or from refining processes, including processes for hydrotreatment and conversion, which may be be used alone or mixed.
• One of the objectives of the present invention is to propose a process for converting heavy petroleum feedstocks for the production of fuel oils and oil bases, in particular bunker oils and bunker oil bases, with very low sulfur content.
• Another object of the present invention is to jointly produce, by means of the same process, atmospheric distillates (naphtha, kerosene, diesel), vacuum distillates and / or light (C 1 to C 4) gases.
• the bases of the naphtha and diesel type can be upgraded to refineries for the production of automotive and aviation fuels, such as, for example, super-fuels, Jet fuels and gas oils.
• the feedstocks treated in this process contain little or no asphaltenes.
• the process disclosed in EP 1343857 is described as a hydro-treatment process which can implement a hydrodemetallation section, which can be preceded by a guard zone of the reactive reactor type, and a hydrodesulfurization section.
• One of the objectives of the present invention is to adapt and improve the conversion methods described in the state of the art for the production of fuel oils and oil bases including low sulfur content.
• the subject of the invention is, first of all, a process for treating a hydrocarbon feedstock having a sulfur content of at least 0.5% by weight, an asphaltene content of at least 2% by weight, a initial boiling point of at least 340 ° C and a final boiling point of at least 440 ° C, to obtain at least one liquid hydrocarbon fraction having a sulfur content of less than or equal to 0.5% by weight, comprising the following successive steps:
• step (b) a step of hydroconversion of at least a portion of the effluent from step (a) into at least one reactor containing a catalyst supported in a bubbling bed, and
• step (b) a step of separating the effluent from step (b) to obtain at least one gaseous fraction and at least said liquid hydrocarbon fraction,
• the invention also relates to the fuel oil used in maritime transport, obtained from such a process, having a sulfur content of less than or equal to 0.5% by weight, preferably less than or equal to 0.1% by weight. .
• Figure 1 shows an embodiment of the method according to the invention without intermediate separation of the product between the fixed bed section and the bubbling bed section.
• Figure 2 shows in larger, for more legibility, the guard zones of the hydrotreating section of Figure 1.
• the method according to the invention thus comprises a first step (a) of hydrotreating in a fixed bed, followed by a step (b) of bubbling bed hydroconversion, and finally a step (c) of separation.
• ⁇ hydrotreating is both to refine, that is to say to significantly reduce the content of metals, sulfur and other impurities, while improving the hydrogen to carbon ratio (H / C) and while transforming the hydrocarbon feed more or less partially in lighter cuts.
• Effiuent obtained in step (a) fixed bed hydrotreating is then directly sent to step (b) bubbling bed hydroconversion which allows to partially convert the hydrocarbon effluent obtained after the hydrotreating step (a) in order to produce an effluent which may advantageously be used wholly or partly as fuel oil or as a fuel oil base, especially as bunker oil or bunker oil base.
• a bubbling bed hydroconversion lies in the fact that the load of bubbling bed hydroconversion reactor is already at least partially hydrotreated. In this way, it is possible to obtain equivalent conversion of hydrocarbon effluents. of better quality, especially with lower sulfur contents.
• the catalyst consumption in the bubbling bed hydroconversion reactor is greatly reduced compared to a process without prior fixed bed hydrotreating.
• the process according to the invention is characterized in that it does not comprise an intermediate separation step between the hydrotreatment step (a) and the hydroconversion stage (b).
• Directly sending the effluent from the fixed bed hydrotreating step into the ebullated bed hydroconversion stage without a separation step has several advantages, including:
• the process has a better thermal integration since the temperature of the effluent at the output of the fixed bed of hydro treatment is retained. This does not exclude the fact that the effluent temperature of the fixed bed hydrotreatment stage can be controlled and adjusted before the bubbling bed hydroconversion stage.
• the method has a better energy efficiency since there is no significant pressure drop between the outlet of the fixed bed hydro-treatment section and the inlet of the bubbling bed hydroconversion section.
• the device making it possible to implement the process, and more particularly the elements necessary for the recycling of hydrogen in the process, can be simplified. Indeed, in the absence of intermediate separation, a single hydrogen recirculation loop common to the fixed bed hydrotreatment section and the bubbling bed hydroconversion section is necessary since there is no need for intermediate separation. evacuation of a hydrogen-rich gas at the end of the fixed-bed hydrotreating step. A single compressor is sufficient, and the size of this compressor can be reduced to the extent that the flow of recycled gas is also lower.
• the process according to the invention advantageously makes it possible to produce light fractions, fuel oils and oil bases, in particular for marine use, with a low sulfur content, with a high efficiency and energy efficiency, from a feedstock. heavy hydrocarbon sulfur.
• the hydrocarbon feedstock treated in the process according to the invention can be described as a heavy load. It has an initial boiling point of at least 340 ° C and a final boiling temperature of at least 440 ° C. Preferably, its initial boiling point is at least 350 ° C., preferably at least 375 ° C., and its final boiling point is at least 450 ° C., preferably at least 460 ° C. C, more preferably at least 500 ° C, and even more preferably at least 600 ° C.
• the hydrocarbon feedstock may be chosen from atmospheric residues, vacuum residues from direct distillation, crude oils, crude head oils, deasphalting resins, asphalts or deasphalting pitches, residues resulting from conversion processes, aromatic extracts from lubricant base production lines, oil sands or derivatives thereof, bituminous shales or derivatives thereof, parent rock oils or their derivatives, alone or in admixture.
• the fillers being treated are preferably atmospheric residues or vacuum residues, or mixtures of these residues.
• the hydrocarbon feedstock treated in the process according to the invention is sulfurized. Its sulfur content is at least 0.5% by weight, preferably at least 1% by weight, more preferably at least 4% by weight, more preferably at least 5% by weight.
• the hydrocarbon feedstock treated in the process according to the invention contains asphaltenes. Its asphaltenes content of at least 2% by weight.
• asphaltene is meant in the present description heavy hydrocarbon compounds insoluble in n-heptane (also called Cl asphalenes) but soluble in toluene.
• the quantification of asphaltenes generally uses standard analyzes as defined, for example, in standards AFNOR T 60-115 (France) or ASTM 893-69 (United States).
• the nickel and vanadium (Ni + V) metal content of the charge is preferably greater than 110 ppm, and more preferably greater than 150 ppm by weight.
• This co-charge may be a hydrocarbon fraction or a mixture of lighter hydrocarbon fractions, which may preferably be chosen from products derived from a process for catalytic cracking in a bed.
• fluid FCC or "Fluid Catalytic Cracking” according to the English terminology
• LCO light cutting oil
• HCO heavy cutting oil
• decanted oil an FCC residue
• gas oil fraction in particular a fraction obtained by atmospheric distillation or under vacuum, for example vacuum gas oil, or which may come from another process. refining.
• the co-charge may also advantageously be one or more cuts resulting from the process of liquefying coal or biomass, aromatic extracts, or any other hydrocarbon cuts or non-petroleum fillers such as pyrolysis oil.
• the heavy hydrocarbon feedstock according to the invention may represent at least 50%, preferably 70%, more preferably at least 80%, and still more preferably at least 90% by weight of the total hydrocarbon feedstock treated by the process according to the invention. .
• Said hydrocarbon feedstock is subjected according to the process of the present invention to a fixed bed hydrotreating step (a) in which feedstock and hydrogen are contacted on a hydrotreatment catalyst.
• Hydrotreatment commonly known as HDT
• HDT Hydrotreatment
• Hydroprocessing includes hydrodesulphurization reactions (commonly referred to as HDS), hydrodenitrogenation reactions (commonly referred to as HDN), and hydrodemetallation reactions (commonly referred to as HDM), accompanied by hydrogenation, hydrodeoxygenation, and hydrogenation reactions.
• the hydrotreatment step (a) comprises a first hydrodemetallation (HDM) step (a1) carried out in one or more zones. hydrodemetallation in fixed beds and a second step (a2) subsequent hydrodesulphurization (HDS) carried out in one or more hydrodesulfurization zones in fixed beds.
• first hydrodemetallation step (a1) the feedstock and hydrogen are contacted on a hydrodemetallization catalyst, under hydrodemetallation conditions, and then during said second step (a2).
• hydrodesulfurization the effluent of the first step (a1) of hydrodemetallation is brought into contact with a hydrodesulphurization catalyst, under hydrodesulfurization conditions.
• the hydrotreating step (a) according to the invention is carried out under hydrotreatment conditions. It may advantageously be used at a temperature of between 300 ° C. and 500 ° C., preferably between 350 ° C. and 420 ° C. and under an absolute pressure of between 2 MPa and 35 MPa, preferably between 11 MPa and 20 ° C. MPa.
• the temperature is usually adjusted according to the desired level of hydrotreatment and the duration of the targeted treatment.
• the space velocity of the hydrocarbon feedstock can be in a range from 0.1 hr -1 to 5 h -1 , preferably 0.1 h -1 to 2 h -1 , more preferably 0.1 h -1 to 0.45 h -1 , and still more preferably 0.1 h -1 to 0, 2 h "1.
• the amount of hydrogen mixed with the feedstock can be between 100 and 5000 normal cubic meters (Nm 3 ) per cubic meter (m 3 ) of liquid feed, preferably between 200 Nm 3 / m 3 and 2000 Nm 3 / m 3, and more preferably between 300 Nm 3 / m 3 and 1500 Nm 3 / m 3 .
• the hydrotreating step (a) can be carried out industrially in one or more liquid downflow reactors.
• the hydro-treatment catalysts used are preferably known catalysts. These may be granular catalysts comprising, on a support, at least one metal or metal compound having a hydrodehydrogenating 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, a catalyst comprising from 0.5% to 10% by weight of nickel, preferably from 0.5% to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1% to 30% by weight can be used.
• molybdenum oxide M0O3 % by weight of molybdenum, preferably from 5% to 20% by weight of molybdenum (expressed as molybdenum oxide M0O3) on a mineral support.
• This support may for example be chosen from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals.
• this support may contain other doping compounds, in particular oxides selected from the group consisting of boron oxide, zirconia, ceria, titanium oxide, phosphoric anhydride and a mixture of these oxides. Most often an alumina support is used and very often a support of alumina doped with phosphorus and possibly boron.
• the alumina used may be a gamma ( ⁇ ) or ⁇ (eta) alumina. This catalyst is most often in the form of extrudates.
• the total content of metal oxides of Groups VIB and VIII may be from 5% to 40% by weight and in general from 7% to 30% by weight and the weight ratio expressed as metal oxide between metal (or metals) of the group VIB on metal (or metals) of group VIII is generally between 20 and 1, and most often between 10 and 2.
• HDM step Catalysts that can be used in the HDM step are for example indicated in patent documents EP 0113297, EP 0113284, US Pat. No. 5,222,556, US Pat. No. 5,827,421, US Pat. US 5622616 and US 5089463.
• HDM catalysts are preferably used in the reactive reactors.
• Catalysts that can be used in the HDS step are, for example, indicated in patent documents EP 0113297, EP 0113284, US Pat. No. 6589908, US Pat. No. 4,818,743 or US Pat. No. 6,332,976.
• the catalysts used in the process according to the present invention are preferably subjected to an in situ or ex situ sulfurization treatment.
• the step (a) of fixed bed hydrotreatment uses a system of permutable reactors, also called guard zones, upstream of the main hydrotreatment reactors.
• the hydrotreatment step (a) can be implemented in one or more hydrotreatment zones in fixed beds preceded by at least two hydrotreatment guard zones also in fixed beds, arranged in series to be used in a cyclic manner consisting of the successive repetition of steps a ") and a" ") defined below: a ') a step, in which the guard zones are used together for a duration at most equal to the deactivation time and / or clogging of one of them, a ") a step, during which the deactivated and / or clogged guard zone is short-circuited and the catalyst it contains is regenerated and / or replaced by catalyst, and during which the other guard zone (s) are used, and at a step, during which the guard zones are used together, the guard zone whose catalyst has been regenerated and / or replaced at the neck
• this reactor is reconnected downstream of the reactor in operation.
• the system of reactive reactors is known from patents FR 2681871, FR 2784687 and EP 1343857.
• the function of the reactive reactors is to protect the main hydrotreating reactors downstream by avoiding clogging and / or deactivation. Indeed, a problem encountered when using fixed beds is the clogging that occurs because of the asphaltenes and sediments contained in the load. Another problem is catalyst deactivation because of the large metal deposition that occurs during hydrotreatment reactions.
• the switchable reactors are thus used to increase the operating cycle of the hydrotreating unit by allowing the deactivated and / or clogged catalyst to be replaced only in the cyclically operating switchable reactors without stopping the entire unit for a period of time. .
• the deactivation and / or clogging time varies depending on the feedstock, the operating conditions of the hydrotreating step and the catalyst (s) used. It is generally expressed by a drop in the catalytic performance which can be observed by an increase in the concentration of metals and / or other impurities in the effluent, an increase in the temperature necessary for the maintenance of a catalyst activity or, in the specific case of a clogging, by a significant increase in the pressure drop.
• the pressure drop ⁇ expressing a degree of clogging, can be continuously measured throughout the cycle on each of the zones and can be defined by a pressure increase resulting from the partially blocked passage of the flow through the zone. Similarly, the temperature can be measured continuously throughout the cycle on each of the two zones.
• the deactivation and / or clogging time is thus defined as the time when the limit value of the pressure drop and / or the temperature is reached.
• the limit value of the pressure drop is generally between 0.3 MPa and 1 MPa (3 and 10 bar), preferably between 0.5 MPa and 0, 8 MPa (5 and 8 bar).
• the limit value of the temperature is generally between 400 ° C.
• the operating conditions of the reactive reactors are generally identical to those of the main hydro-treatment reactors.
• the value of the LHSV space velocity of each switchable operating reactor is preferably between 0.2 h "1 and 4 h" 1, more preferably between 1 h "1 to 2 hours" 1.
• the overall VVH space velocity value of the permutable reactors and that of each reactor is chosen so as to achieve the maximum hydrodemetallation while controlling the reaction temperature and thus limit the exothermicity.
• a catalyst conditioning section permitting the permutation of these guard zones in operation, that is to say without stopping the operation of the unit.
• the conditioning section of the catalyst may comprise the following elements:
• a pre-sulphide catalyst can be used in the conditioning section to simplify the permutation procedure while running.
• the effluent leaving the reactive reactors can then be sent to the main hydrotreating reactors.
• Each hydrotreatment zone or hydrotreating guard zone may contain at least one catalytic bed, for example 1, 2, 3, 4 or 5 catalytic beds.
• each guard zone contains a catalytic bed.
• Each catalytic bed may contain at least one catalytic layer containing one or more catalysts, optionally preceded by at least one inert layer, for example alumina or ceramic in the form of extrudates, balls or pellets.
• the catalysts used in the catalytic bed (s) may be identical or different.
• the hydrocarbon feedstock passes through the inlet of each guard zone a filter plate located upstream of the catalytic bed (s) (s) contained in the guard zone.
• This filter plate described for example in patent FR 2889973, advantageously allows to trap the clogging particles contained in the hydrocarbon feedstock by means of a specific distributor plate comprising a filter medium.
• the effluent from step (a) hydrotreatment in a fixed bed does not undergo any intermediate separation step between the hydrotreatment step (a) and the hydroconversion step (b).
• This configuration can be described as an integrated schema.
• step (b) By “without intermediate separation step” is meant in the present invention the fact that at least a portion of the effluent from step (a) of hydrotreatment is introduced into the section allowing the implementation of the step (b) bubbling bed hydroconversion without changing chemical composition and without significant pressure loss.
• separation means one or more separator tanks and / or one or more stripping columns or distillation, these equipment can operate at different temperatures or pressures.
• Signal loss of pressure means a loss of pressure caused by a valve or expansion turbine, which could be estimated at a pressure loss of more than 10% of the total pressure. Those skilled in the art generally use these pressure losses or relaxations during the separation steps.
• step (a) of hydrotreatment all of the effluent from step (a) of hydrotreatment is introduced into the section allowing the implementation of step (b) of hydroconversion.
• step (b) of hydroconversion only a portion of the effluent from step (a) of hydrotreatment is introduced into the section allowing the implementation of step (b) of hydroconversion.
• This embodiment is however not contradictory to the fact that the method is without an intermediate separation step.
• This embodiment can consist in dividing the hydrotreatment stage effluent (a) into two streams having the same composition, one going to the hydroconversion stage (b), the other going to a section of separation and fractionation treating downstream hydroconversion effluent (b) of it.
• This embodiment can thus be likened to a partial short circuit of the hydroconversion section (b) but, for the part of the effluent of the hydrotreatment section (a) going to the hydroconversion section ( b) bubbling bed, there is no separation, no change in the chemical composition, or significant loss of pressure.
• Another variant of this short-circuit embodiment may consist in dividing the hydrotreating stage effluent (a) into several streams having the same composition, and sending one or more of these streams to the inlet of a first bubbling bed hydroconversion reactor and one or more of such streams to one or more downstream hydroconversion reactors.
• At least a portion of the effluent from the hydrotreating step (a) is sent according to the process of the present invention to a hydroconversion step (b) which is carried out in at least one reactor containing a supported catalyst. in bubbling bed. Said reactor can operate at an upward flow of liquid and gas.
• the main purpose of hydroconversion is to convert the heavy hydrocarbon feedstock into lighter cuts while partially refining it.
• part of the initial hydrocarbon feedstock can be injected directly into the hydroconversion section (b) in bubbling bed, mixed with the effluent of the hydrotreating section (a). ) in a fixed bed, without this part of the hydrocarbon feed being treated in the fixed bed hydrotreatment section (a).
• This embodiment can be likened to a partial short circuit of the hydrotreatment section (a) in a fixed bed.
• a co-charge may be introduced at the inlet of the hydroconversion section (b) in a bubbling bed with the effluent from the hydrotreatment section (a) in a fixed bed.
• This co-charge can be chosen from atmospheric residues, vacuum residues from direct distillation, deasphalted oils, aromatic extracts from lubricant base production lines, hydrocarbon fractions or a mixture of hydrocarbon fractions that can be chosen. among the products resulting from a fluid bed catalytic cracking process, in particular a light cutting oil (LCO), a heavy cutting oil (HCO), a decanted oil, or which may be From the distillation, the gas oil fractions in particular those obtained by atmospheric or vacuum distillation, such as vacuum gas oil.
• this co-charge may be partially or totally injected into one of the reactors downstream of the first reactor.
• the hydrogen necessary for the hydroconversion reaction may already be present in sufficient quantity in the effluent resulting from the hydrotreatment step (a) injected at the inlet of the boiling bed hydroconversion section (b). However, it is preferable to provide an additional hydrogen input at the inlet of the hydroconversion section (b). In the case where the hydroconversion section has several bubbling bed reactors, hydrogen can be injected at the inlet of each reactor.
• the injected hydrogen may be a make-up stream and / or a recycle stream.
• Bubbling bed technology is well known to those skilled in the art. Only the main operating conditions will be described here. Bubbling bed technologies conventionally use supported catalysts in the form of extrudates whose diameter is generally of the order of about 1 millimeter, for example 0.9 mm or 1.2 mm.
• the catalysts remain inside the reactors and are not evacuated with the products, except during the makeup and catalyst withdrawal phases necessary to maintain the catalytic activity.
• the temperature levels can be high to achieve high conversions while minimizing the amounts of catalysts used.
• the catalytic activity can be kept constant by replacing the catalyst in line. It is therefore not necessary to stop the unit to change the spent catalyst, nor to increase the reaction temperatures along the cycle to compensate for the deactivation.
• the conditions of the boiling bed hydroconversion stage (b) may be conventional bubbling bed hydroconversion conditions of a liquid hydrocarbon fraction. It can operate under an absolute pressure of between 2.5 MPa and 35 MPa, preferably between 5 MPa and 25 MPa, more preferably between 6 MPa and 20 MPa, and even more preferably between 11 MPa and 20 MPa at a temperature between 330 ° C and 550 ° C, preferably between 350 ° C and 500 ° C.
• VVH space velocity
• hydrogen partial pressure are parameters that are set according to the characteristics of the product to be treated and the desired conversion.
• VVH (defined as the volumetric flow rate of the load divided by the total volume of the reactor ebullated bed) is typically in a range of from 0.1 hr "1 to 10 hours" 1, preferably 0.2 h " 1 to 5 h -1 and more preferably 0.2 h -1 to 1 h -1 .
• the amount of hydrogen mixed with the feedstock is usually from 50 to 5000 normal cubic meters (Nm 3 ) per cubic meter (m 3 ) of liquid feed, most often from 100 Nm 3 / m 3 to 1500 NmV and preferably from 200 NmV at 1200 NmV.
• a conventional hydroconversion granular catalyst comprising, on an amorphous support, at least one metal or metal compound having a hydro-dehydrogenating function can be used.
• This catalyst may be a catalyst comprising Group VIII metals, for example nickel and / or cobalt, most often in combination with at least one Group VIB metal, for example molybdenum and / or tungsten.
• a catalyst comprising from 0.5% to 10% by weight of nickel and preferably from 1% to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1% to 30% by weight of molybdenum, preferably from 5% to 20% by weight of molybdenum (expressed as molybdenum oxide M0O3) on an amorphous mineral support.
• This support may for example be chosen from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals.
• This support may also contain other compounds and for example oxides selected from the group consisting of boron oxide, zirconia, titanium oxide, phosphoric anhydride. Most often an alumina support is used and very often a support of alumina doped with phosphorus and possibly boron.
• phosphorus pentoxide P2O5 When phosphorus pentoxide P2O5 is present, its concentration is usually less than 20% by weight and most often less than 10% by weight.
• boron trioxide B 2 0 3 When boron trioxide B 2 0 3 is present, its concentration is usually less than 10% by weight.
• the alumina used is usually ⁇ (gamma) or ⁇ (eta) alumina.
• This catalyst may be in the form of extrudates.
• the total content of metal oxides of groups VI and VIII may be between 5% and 40% by weight, preferably between 7% and 30% by weight, and the weight ratio expressed as oxide metal group VI metal (or metals) on metal (or metals) of group VIII is between 20 and 1, preferably between 10 and 2.
• the spent catalyst may be partly replaced by fresh catalyst, generally by withdrawing from the bottom of the reactor and introducing the fresh or new catalyst at the top of the reactor at a regular time interval, that is to say, for example by puff or continuously or almost continuously.
• the catalyst can also be introduced from below and withdrawn from the top of the reactor. For example, fresh catalyst can be introduced every day.
• the replacement rate of spent catalyst with fresh catalyst may be, for example, from about 0.05 kilograms to about 10 kilograms per cubic meter of charge. This withdrawal and replacement are performed using devices for the continuous operation of this hydroconversion step.
• the hydroconversion reactor usually comprises a recirculation pump for maintaining the bubbling bed catalyst by continuous recycling of at least a portion of the liquid withdrawn at the top of the reactor and reinjected at the bottom of the reactor. It is also possible to send the spent catalyst withdrawn from the reactor into a regeneration zone in which the carbon and the sulfur contained therein are eliminated before it is reinjected in the hydroconversion stage (b).
• This hydroconversion step (b) can be carried out under the conditions of the H-OIL® process as described, for example, in US Pat. No. 6,270,654.
• Bubbling bed hydroconversion can be carried out in a single reactor or in several reactors, preferably two, arranged in series.
• the fact of using at least two bubbling bed reactors in series makes it possible to obtain products of better quality and with better performance.
• hydroconversion into two reactors makes it possible to have improved operability in terms of the flexibility of the operating conditions and of the catalytic system.
• the temperature of the second bubbling bed reactor is at least 10 ° C higher than that of the first bubbling bed reactor.
• the pressure of the second reactor may be 0.1 MPa to 1 MPa lower than for the first reactor to allow the flow of at least a portion of the effluent from the first step without pumping is necessary.
• the different operating conditions in terms of temperature in the two hydroconversion reactors are selected to be able to control the hydrogenation and the conversion of the feedstock into the desired products in each reactor.
• the effluent obtained at the end of the first substep (b1) can optionally be subjected to a separation step of the light fraction and the heavy fraction, and at least a portion, preferably all, of said heavy fraction can be treated in the second hydroconversion sub-step (b1).
• This separation is advantageously done in an inter-stage separator, as described for example in US Pat. No. 6,270,654, and in particular makes it possible to avoid over cracking of the light fraction in the second hydroconversion reactor.
• the process according to the invention further comprises a step (c) of separation make it possible to obtain at least one gaseous fraction and at least one liquid hydrocarbon fraction.
• the effluent obtained at the end of the hydroconversion stage (b) comprises a liquid fraction and a gaseous fraction containing the gases, in particular H 2 , H 2 S, NH 3 , and C 1 -C 4 hydrocarbons.
• This gaseous fraction can be separated from the hydrocarbon effluent by means of separating devices well known to those skilled in the art, in particular by means of one or more separator flasks that can operate at different pressures and temperatures, possibly associated with each other. to a means of stripping with steam or hydrogen.
• the effluent obtained at the end of the hydroconversion stage (b) is advantageously separated in at least one separator flask into at least one gaseous fraction and at least one liquid fraction.
• separators may for example be high temperature high pressure separators (HPHT) and / or high temperature low pressure separators (HPBT).
• HPHT high temperature high pressure separators
• HPBT high temperature low pressure separators
• this gaseous fraction is preferably treated in a hydrogen purification means so as to recover the hydrogen not consumed during hydro-treatment and hydroconversion reactions.
• the hydrogen purification means may be an amine wash, a membrane, a PSA (Pressure Swing Adsorption) system, or a plurality of these means arranged in series.
• the purified hydrogen can then advantageously be recycled in the process according to the invention, after possible recompression.
• the hydrogen may be introduced at the inlet of the hydrotreatment step (a) and / or at different locations during the hydro-treatment stage (a) and / or at the stage (b) stage entry. hydroconversion and / or at different locations during step (b) hydroconversion.
• the separation step (c) may also comprise atmospheric distillation and / or vacuum distillation.
• the separation step (c) further comprises at least one atmospheric distillation, in which the liquid hydrocarbon fraction (s) obtained (s) after separation is (are) fractionated (s) by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction.
• the atmospheric distillate fraction may contain commercially recoverable fuels bases (naphtha, kerosene and / or diesel), for example in the refinery for the production of automotive and aviation fuels.
• the separation step (c) of the process according to the invention may advantageously also comprise at least one vacuum distillation in which the liquid hydrocarbon fraction (s) obtained (s) after separation and / or the atmospheric residue fraction obtained after atmospheric distillation is (are) fractionated by vacuum distillation into at least one vacuum distillate fraction and at least one vacuum residue fraction.
• the separation step (c) firstly comprises an atmospheric distillation, in which the liquid hydrocarbon fraction (s) obtained (s) obtained after separation is (are) fractionated ( s) by atmospheric distillation into at least one atmospheric distillate fraction and at least one atmospheric residue fraction, followed by vacuum distillation in which the atmospheric residue fraction obtained after atmospheric distillation is fractionated by vacuum distillation into at least one vacuum distillate fraction and at least one residue fraction under vacuum.
• the vacuum distillate fraction typically contains vacuum gas oil fractions. At least a portion of the vacuum residue fraction can be recycled to the hydroconversion stage (b).
• This liquid hydrocarbon fraction may advantageously serve as a fuel oil base, especially for a bunker oil.
• all of the liquid hydrocarbon effluent obtained at the end of the separation step (c) may have a sulfur content of less than or equal to 0.5% by weight, preferably less than or equal to 0.3. % by weight, more preferably less than or equal to 0.1% by weight, and even more preferably less than or equal to 0.08% by weight.
• the conversion of the hydrocarbon feedstock into lighter fractions may be between 10% and 95%, preferably between 25% and 90%, and more preferably between 40% and 85%.
• the conversion rate mentioned above is defined as the amount of compounds having a boiling point above 520 ° C in the initial hydrocarbon feedstock, minus the amount of compounds having a boiling point above 520 ° C in the hydrocarbon effluent obtained at the end of the hydroconversion stage (b), all divided by the amount of compounds having a boiling point greater than 520 ° C. in the initial hydrocarbon feedstock.
• a high conversion rate is advantageous insofar as this conversion rate illustrates the production of conversion products, mainly atmospheric distillates and / or vacuum distillates of the naphtha, kerosene and diesel type, in a significant amount.
• This liquid hydrocarbon effluent may, at least in part, advantageously be used as fuel oil bases or as fuel oil, especially as a base of bunker oil or as fuel oil, with low sulfur content meeting the new recommendations of the International Maritime Organization .
• fuel is meant in the invention a hydrocarbon feedstock used as fuel.
• oil base is meant in the invention a hydrocarbon feed which, mixed with other bases, constitutes a fuel oil.
• the properties of these bases in particular their sulfur content and their viscosity, are very diverse.
• the hydrocarbon effluent obtained at the end of the hydroconversion stage (b), and in particular the heavier liquid fraction obtained, may contain sediments and catalyst residues from the fixed stage and / or the boiling bed stage in the form of fines.
• the process according to the invention may comprise an additional step of separating the sediments and the fines. the liquid hydrocarbon effluent after the separation step (c).
• the process according to the invention may therefore also comprise a step (d) of separating sediments and fines, in which at least a portion of the atmospheric residue and / or vacuum distillate and / or vacuum residue fractions are subjected to separation of sediments and catalyst fines, using at least one filter, centrifuge system or inline decantation.
• the process according to the invention may further comprise a catalytic cracking step (e), in which at least a part of the vacuum distillate fraction and / or the vacuum residue fraction, optionally previously subjected to at the sediment and fines separation step (d), is sent to a catalytic cracking section in which it is treated under conditions allowing the production of a gaseous fraction, a gasoline fraction, a diesel fraction and a fraction. residual.
• a catalytic cracking step (e) in which at least a part of the vacuum distillate fraction and / or the vacuum residue fraction, optionally previously subjected to at the sediment and fines separation step (d) is sent to a catalytic cracking section in which it is treated under conditions allowing the production of a gaseous fraction, a gasoline fraction, a diesel fraction and a fraction. residual.
• Said step (e) of catalytic cracking may be a catalytic cracking step in a fluidized bed, for example according to the process developed by the Applicant Company called R2R.
• This step can be carried out in a conventional manner known to those skilled in the art under the appropriate cracking conditions in order to produce lower molecular weight hydrocarbon products.
• Functional descriptions and catalysts that can be used for fluidized bed cracking in this step (e) are described, for example, in US Pat. No. 4,695,370, EP 0184517, US Pat. No. 4,959,334, EP 0323297, US Pat. No. 4,365,232 and US Pat.
• the fluidized catalytic cracking reactor is operable with upflow or downflow. Although this is not a preferred embodiment of the present invention, it is also conceivable to perform catalytic cracking in a moving bed reactor.
• Particularly preferred catalytic cracking catalysts are those containing at least one zeolite usually in admixture with a suitable matrix such as, for example, alumina, silica, silica-alumina.
• At least a portion of the residual fraction obtained at the end of the catalytic cracking step (e), often referred to as "slurry" fraction by a person skilled in the art, may be recycled at the inlet of step (e). ) of catalytic cracking and / or at the inlet of the hydrotreatment stage (a) and / or at the inlet of the hydroconversion stage (b).
• the residual fraction may also be at least partly or even entirely sent to a refinery heavy fuel oil storage zone.
• a portion of the diesel fraction and / or the residual fraction obtained at the end of this catalytic cracking step (e) may be used to form a fluxing base.
• An object of the present invention is to produce marketable oils, including bunker fuels for maritime transport. It is preferable that this type of fuel meets certain specifications, especially in terms of viscosity.
• a very common type of bunker oil has a viscosity of less than or equal to 380 cSt (at 50 ° C).
• Other qualities of fuel oil, called “grades”, meet different specifications, especially from the point of view of viscosity.
• the DMA grade imposes a viscosity of between 2 cSt and 6 cSt at 40 ° C. and the DMB grade has a viscosity of between 2 cSt and 11 cSt at 40 ° C.
• oil bases may be mixed, if necessary, with fluxing bases or "cutter stocks" according to Anglo-Saxon terminology.
• Fuel specifications are for example described in the IS08217 standard (last version in 2012).
• the fluxing bases are generally of the kerosene, diesel or vacuum gas oil type. They can be chosen from light cutting oil oils (LCO) of a cracking catalytic cracking, catalytic cracking heavy-cutting oils (HCO), catalytic cracking residue, kerosene, gas oil, vacuum distillate and / or decanted oil.
• LCO light cutting oil oils
• HCO catalytic cracking heavy-cutting oils
• the atmospheric residue and / or the vacuum distillate and / or the vacuum residue obtained (s) at the end of the separation step (c), possibly previously subjected to the step (d) separating sediments and fines may be mixed with one or more fluxing bases selected from the group consisting of light catalytic cracking oils, heavy-duty cutting oils, and catalytic cracking, the residue of a catalytic cracking, a kerosene, a gas oil, a vacuum distillate and / or a decanted oil.
• one or more fluxing bases selected from the group consisting of light catalytic cracking oils, heavy-duty cutting oils, and catalytic cracking, the residue of a catalytic cracking, a kerosene, a gas oil, a vacuum distillate and / or a decanted oil.
• said fluxing base is chosen from a part of the diesel fraction and / or of the residual fraction obtained at the end of the catalytic cracking step (e).
• said fluxing base may be chosen from a part of the kerosene and / or diesel fraction obtained at the end of the boiling bed hydroconversion stage.
• Step (d) of separation of sediments and fines with one or more fluxing bases, advantageously obtained a fuel oil used in shipping, also called bunker oil, low sulfur content.
• the present invention therefore also relates to such a fuel oil having a sulfur content of less than or equal to 0.5% by weight, preferably less than or equal to 0.1% by weight.
• This oil can advantageously have a sediment content of less than or equal to 0.1% by weight, so as to comply with the new version of the ISO 8217: 2012 standard.
• the viscosity of this oil may be between 1 cSt and 700 cSt at 50 ° C.
• FIGS. 1 and 2 An advantageous embodiment of the method according to the invention is shown in FIGS. 1 and 2.
• FIG. 1 represents a method according to the invention in an integrated diagram, that is to say without intermediate separation and without significant decompression between the fixed bed section. and the bubbling bed section. For more legibility, the operation of the guard zones in the hydrotreating section of FIG. 1 is described in FIG.
• the operation of the guard zones in the hydrotreatment section comprising two guard zones (or reactive reactors) Ra and Rb comprises a series of cycles each comprising four successive stages: a first step (step i) during which the charge passes successively through the reactor Ra and then the reactor Rb,
• step iii in which the charge passes only through the reactor Rb, the reactor Ra being short-circuited for regeneration and / or replacement of the catalyst; a third step (step iii) during which the charge crosses successively the reactor Rb, then the reactor Ra,
• step iv a fourth step (step iv) during which the charge passes only through the reactor Ra, the reactor Rb being short-circuited for regeneration and / or replacement of the catalyst.
• the cycle can then start again.
• Steps i and iii are steps during which all guard zones are used. Steps ii and iv are steps during which one guard area is short-circuited while the other is used.
• step (i) the preheated charge is introduced via the line (18) and the line (19) comprising a valve VI open towards the line (20) and the guard reactor Ra containing a fixed bed A of catalyst.
• valves V3, V4 and V5 are closed.
• the effluent from the reactor Ra is sent via the pipe (21), the pipe (22) comprising an open valve V2 and the pipe (23) into the guard reactor Rb containing a fixed bed B of catalyst.
• the effluent from the reactor Rb is sent via the pipes (24) and (25) having an open valve V6 and the pipe (26) to the main hydro-treatment section which will be described later.
• step (ii) the valves VI, V2, V4 and V5 are closed and the load is introduced via the line (18) and the line (27) comprising a valve V3 open towards the line (23) and the reactor Rb.
• the reactor effluent Rb is sent through lines (24) and (25) having an open valve V6 and line (26) to the main hydrotreatment section.
• step (iii) the valves VI, V2 and V6 are closed and the valves V3, V4 and V5 are open.
• the charge is introduced via the line (18) and the lines (27) and (23) to the reactor Rb.
• the effluent from the reactor Rb is sent via the pipe (24), the pipe (28) having an open valve V4 and the pipe (20) into the guard reactor Ra.
• the effluent from the reactor Ra is sent through the lines (21) and (29) having an open valve V5 and the pipe (26) to the main hydrotreatment section.
• step (iv) the valves V2, V3, V4 and V6 are closed and the valves V1 and V5 are open.
• the charge is introduced via line (18) and lines (19) and (20) to the reactor Ra.
• the effluent from the reactor Ra is sent via the lines (21) and (29) comprising an open valve V5 and the pipe (26) to the main hydrotreatment section.
• the effluent leaving the at least one holding reactor is optionally remixed with hydrogen arriving via line (65) in an HDM reactor (30) which contains a fixed bed (32) of catalyst .
• an HDM reactor (30) which contains a fixed bed (32) of catalyst .
• the HDM and HDS section may have multiple HDM and HDS reactors in series. If necessary, the recycled and / or auxiliary hydrogen can also be introduced into the hydrotreatment reactors between the different catalytic beds (not shown).
• the effluent from the HDM reactor is withdrawn through line (34) and sent to the first HDS reactor (36) where it passes through a fixed bed (38) of catalyst.
• the effluent from the hydrotreatment stage is sent via line (42) to the bubbling bed hydroconversion section via an optional heat exchanger (43).
• the effluent from the hydrotreating step going to the bubbling bed hydroconversion section may optionally be mixed with a co-charge (94) and / or optionally mixed with recycled hydrogen (88) optionally supplemented with makeup hydrogen (90) preheated in the oven (91).
• the effluent from the hydrotreatment stage or the mixture constituted with a co-charge and / or hydrogen is then introduced via the line (96) in the hydroconversion stage at the bottom of the first reactor (98). bubbling bed operating at upward flow of liquid and gas and containing at least one hydroconversion catalyst.
• the reactor (98) usually comprises a recirculation pump (100) for maintaining the bubbling bed catalyst by continuously recycling at least a portion of the liquid withdrawn into the upper part of the reactor and reinjected at the bottom of the reactor.
• the addition of fresh catalyst can be done from the top or the bottom of the reactor (not shown).
• the catalyst supply can be carried out periodically or continuously.
• the spent catalyst can be withdrawn from the bottom of the reactor (not shown) to either be removed or regenerated to remove carbon and sulfur prior to reinjection from the top of the reactor.
• the catalyst withdrawn from the bottom of the first partially used reactor can also be transferred directly to the top of the second hydroconversion reactor (102) (not shown).
• the converted effluent (104) from the reactor (98) may be separated from the light fraction (106) in an inter-stage separator (108).
• All or part of the effluent (110) from the inter-stage separator (108) is advantageously mixed with additional hydrogen (157), if necessary preheated (not shown).
• This mixture is then injected via the pipe (112) into a second bubbling bed hydroconversion reactor (102) operating with an upward flow of liquid and gas containing at least one hydroconversion catalyst.
• the operating conditions, in particular the temperature, in this reactor are chosen to reach the desired conversion level, as previously described. Addition and removal of the catalyst is carried out in the same manner as described for the first reactor.
• the reactor (102) also usually includes a recirculation pump (114) operating in the same manner as the pump of the first reactor.
• the effluent from bubbling bed reactors is sent via line (134) to a high temperature high pressure (HPHT) separator (136) from which a gaseous fraction (138) and a liquid fraction (140) are recovered.
• the gaseous fraction (138) is sent generally via an exchanger (not shown) or a dry cooler (142) for cooling to a low temperature high pressure separator (HPBT) (144) from from which a gaseous fraction (146) containing the gases (H 2 , H 2 S, NH 3 , hydrocarbons in dC 4 ...) and a liquid fraction (148) are recovered.
• HPHT high temperature high pressure separator
• the gaseous fraction (146) of the low temperature high pressure separator (HPBT) (144) is treated in the hydrogen purification unit (150) from which hydrogen (152) is recovered for recycling via the compressor. (154) and the line (156) and / or the line
• the hydrogen purification unit may consist of an amine wash, a membrane, a PSA type system. Gases containing undesirable nitrogen and sulfur compounds are removed from the installation (flow
• the liquid fraction (148) of the low temperature high pressure separator (HPBT) (144) is expanded in the device (160) and sent to the fractionation system (172).
• a medium pressure separator (not shown) after the expander (160) can be installed to recover a vapor phase that is sent to the purification unit (150) and / or a dedicated medium pressure purification unit (not shown). ), and a liquid phase which is fed to the fractionation section (172).
• the liquid fraction (140) from the high temperature high pressure separation (HPHT) (136) is expanded in the device (174) and sent to the fractionation system (172).
• a medium pressure separator (not shown) after the expander (174) can be installed to recover a vapor phase that is sent to the purification unit (150) and / or to a dedicated medium pressure purification unit (not shown). ), and a liquid phase which is fed to the fractionation section (172).
• the fractionation system (172) comprises an atmospheric distillation system for producing a gaseous effluent (176), at least a so-called light fraction (178), containing in particular naphtha, kerosene and diesel, and an atmospheric residue fraction (180). ).
• Part of the atmospheric residue fraction (180) can be withdrawn via line (182) to form the desired oil bases.
• All or part of the atmospheric residue fraction (180) can be sent to a vacuum distillation column (184) to recover a fraction containing the vacuum residue (186) and a vacuum distillate fraction (188) containing vacuum gas oil .
• At least part of the fraction Vacuum residue is preferably recycled via line (190) to the hydroconversion stage, or upstream of the hydrotreating step (line not shown) to increase the conversion.
• the atmospheric residue fraction (182), the vacuum distillate fraction (188) and / or the vacuum residue fraction (186) can be subjected to a separation step of fines and sediments by, for example, filters (191). ), (192) and (193) respectively.
• the feed contains 202 ppm of metals (Ni + V).
• the feedstock was subjected to a hydrotreatment step including two permutable reactors.
• the loading distribution of HDM / HDS catalysts is 40/60.
• the operating conditions of the step in fixed bed (s) are given in Table 1.
• Table 1 Operating conditions fixed bed The performance in HDM hydrodemetallation in the fixed bed HDT section is greater than 80%.
• the effluent of the hydrotreatment has not been subjected to any separation and is directly sent wholly in a hydroconversion stage comprising two successive bubbling bed reactors.
• the operating conditions of the step in bubbling bed (s) are given in Table 2.
• the hydrogen consumed represents 3.4% by weight of the fresh feed introduced at the inlet of the hydrotreatment section.
• the above yields make it possible to calculate the conversion rate of the fraction of the boiling charge at a temperature above 520 ° C., which converts into products boiling at a temperature below 520 ° C., according to the following formula:
• This particularly high conversion rate illustrates the production of conversion products (mainly distillates) in a significant amount.
• a second mixture consisting of 20% by weight of a fraction from the diesel cut and 80% by weight of a fraction from the vacuum distillate cut was also produced.
• the mixture has a sulfur content of 0.09% and a viscosity of 6 cSt at 40 ° C.
• This mixture thus constitutes a marine fuel of the distillate type ("marine diesel” or “marine diesel” in the English terminology) which can be likened to the DMB grade (whose viscosity specification is between 2 cSt and 11 cSt at 40.degree. ° C) for example. Because of its sulfur content of less than 0.1%, this mixture is a fuel of choice for ZCESs by 2015.

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