EP1310544B1 - Verfahren zur Umwandlung von schweren teroleumfraktionen zur Herstellung einer Beschickung für ein katalytisches Crackverfahren und Mitteldestillate mit niedrigem Schwefelgehalt - Google Patents

Verfahren zur Umwandlung von schweren teroleumfraktionen zur Herstellung einer Beschickung für ein katalytisches Crackverfahren und Mitteldestillate mit niedrigem Schwefelgehalt Download PDF

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EP1310544B1
EP1310544B1 EP02290432A EP02290432A EP1310544B1 EP 1310544 B1 EP1310544 B1 EP 1310544B1 EP 02290432 A EP02290432 A EP 02290432A EP 02290432 A EP02290432 A EP 02290432A EP 1310544 B1 EP1310544 B1 EP 1310544B1
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hydrogen
pipe
fraction
zone
stage
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French (fr)
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EP1310544A1 (de
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Christophe Gueret
Pierre Marion
Cécile Plain
Jérôme Bonnardot
Eric Benazzi
Olivier Martin
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IFP Energies Nouvelles IFPEN
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    • 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
    • C10G69/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process
    • C10G69/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/202—Heteroatoms content, i.e. S, N, O, P
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/301—Boiling range
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4006—Temperature
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4012—Pressure
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4018—Spatial velocity, e.g. LHSV, WHSV
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4081—Recycling aspects
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/04—Diesel oil
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/06—Gasoil

Definitions

  • the present invention relates to a method and an installation for the treatment of heavy hydrocarbon feedstocks containing sulfur impurities. It relates to a process for converting at least in part such a hydrocarbon feedstock, for example a vacuum distillate obtained by the direct distillation of a crude oil, into diesel corresponding to the 2005 sulfur specifications, that is to say having less than 50 ppm sulfur, and a heavier product which can be advantageously used as a feedstock for catalytic cracking (such as catalytic cracking in a fluid bed).
  • a hydrocarbon feedstock for example a vacuum distillate obtained by the direct distillation of a crude oil
  • diesel corresponding to the 2005 sulfur specifications, that is to say having less than 50 ppm sulfur
  • a heavier product which can be advantageously used as a feedstock for catalytic cracking (such as catalytic cracking in a fluid bed).
  • FR-A-2791354 describes a process for converting heavy petroleum fractions comprising a step of hydroconversion into bubbling beds and a hydrotreating step.
  • the treated feeds are heavy, i.e., 80% wt boiling above 340 ° C.
  • Their initial boiling point is usually at least 340 ° C, often at least 370 ° C or above 400 ° C.
  • the process makes it possible to treat feeds having a final boiling point of at least 450 ° C. and which may even exceed 650 ° C.
  • the sulfur content is at least 0.05 wt%, often at least 1% and very often at least 2% or even at least 2.5 wt%. Charges with 3% or more sulfur are well suited in this process.
  • the fillers which can be treated in the context of the present invention are straight-run vacuum distillates, vacuum distillates resulting from conversion processes such as, for example, those resulting from coking, from fixed-bed hydroconversion (such as those resulting from the HYVAHL® processes of heavy processing developed by the Applicant) or ebullated bed hydrotreating processes (such as those resulting from H-OIL® processes), or solvent-deasphalted oils. (for example propane, butane, or pentane) from the deasphalting of residue under a direct distillation vacuum, or residues from the HYVAHL® and H-OIL® processes.
  • the fillers can also be formed by mixing these various fractions.
  • the fillers which are treated are preferably vacuum distillates.
  • Step a) - The charge as described above is treated in step a) by mild hydrocracking.
  • VVH hourly space velocity
  • H hydrogen partial pressure
  • the hourly space velocity (VVH) and the hydrogen partial pressure are chosen according to the characteristics of the product to be treated and the desired conversion. Most often the VVH is in a range from about 0.1 h -1 to 10 h -1 and preferably about 0.2 h -1 to about 5 h -1 .
  • the total quantity of hydrogen mixed with the feed (chemical consumption H 2 + recycling) and therefore entering the zone in which step a) is carried out is usually from about 100 to about 5000 normal cubic meters (Nm3) per cubic meter (m3 ) of liquid charge and most often from about 100 to about 2000 Nm3 / m3, generally it is at least 200 Nm3 / m3 and preferably about 200 to about 1500 Nm3 / 3.
  • the net conversion to products boiling below 360 ° C. is generally from 10 to 50% by weight, advantageously from 15 to 45%.
  • the partial pressure of H 2 S at the outlet of step a) is generally 0.1-0.4 MPa, advantageously it is maintained between 0.15-0.3 MPa and preferably between 0.15-0.15. , 25 MPa to improve hydrodesulfurization.
  • a conventional hydroconversion catalyst comprising, on an amorphous support, at least one metal or metal compound having a hydro-dehydrogenating function.
  • This catalyst may be a catalyst comprising Group VIII metals in the catalyst, for example nickel and / or cobalt, most often in combination with at least one Group VIB metal, for example molybdenum and / or tungsten.
  • a catalyst comprising from 0.5 to 10% by weight of nickel and preferably from 1 to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1 to 30% by weight of molybdenum, preferably 5 to 20% by weight of molybdenum (expressed as MoO3 molybdenum oxide) on an amorphous mineral support.
  • the total content of Group VI and VIII metal oxides in the catalyst is often from about 5 to about 40% by weight and generally from about 7 to 30% by weight and preferably the weight ratio of metal oxide to metal Group VIII (or metals) on metal (or metals) of Group VIII is generally from about 20 to about 1 and most often from about 10 to about 2.
  • the support will for example be chosen from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals.
  • This support may also contain other compounds and for example oxides chosen from the group formed by boron oxide, zirconia, titanium oxide, phosphoric anhydride. Most often a support of alumina, and better alumina n or ⁇ is used.
  • the catalyst may also contain an element such as phosphorus and / or boron. This element may have been introduced into the matrix or preferably deposited on the support. It is also possible to deposit silicon on the support, alone or with phosphorus and / or boron.
  • Preferred catalysts contain silicon deposited on a support (such as alumina) optionally with P and / or B also deposited and also containing at least one metal of GVIII Ni, Co and at least one metal of GVIB (Mo, W).
  • the concentration of said element is usually less than about 20% by weight (calculated oxide) and most often less than about 10% and is usually at least 0.001% by weight.
  • the concentration of boron dioxide B 2 O 3 is usually from about 0 to about 10% by weight.
  • Another catalyst comprises at least one Group VIII metal and at least one Group VIB metal and a silica-alumina.
  • Another type of usable catalyst is a catalyst containing at least one matrix, at least one zeolite Y and at least one hydro-dehydrogenating metal.
  • the matrices, metals, additional elements previously described may also be included in the composition of this catalyst.
  • Y advantageous zeolites are described in the applications of WO-00/71641 , EP-911,077 as well as US 4738940 and 4738941 .
  • the mild hydrocracking (step a)) is carried out with at least one fixed bed of at least one catalyst and a hydrocracked effluent is produced.
  • This step is to separate the gases from the liquid, and in particular to recover hydrogen and most of the hydrogen sulfide H 2 S formed in step a), and then obtain a liquid effluent free of H 2 S dissolved.
  • a part of naphtha When separating H 2 S from the liquid, a part of naphtha can be separated. This part is then stabilized (H 2 S removal).
  • the liquid effluent devoid of H 2 S and optionally added stabilized naphtha is distilled to obtain at least one distillate cut including a gas oil fraction, and at least a heavier fraction than the diesel fuel.
  • the distillate cut may be a diesel cut or a diesel fuel cut mixed with naphtha. It feeds step c).
  • the heavier liquid fraction than the diesel-type fraction may optionally be sent to a catalytic cracking process in which it is advantageously treated under conditions making it possible to produce a gaseous fraction, a gasoline fraction, a diesel fraction and a heavier fraction. that the diesel fraction often referred to by those skilled in the art slurry fraction.
  • this heavier liquid fraction than the diesel fraction can be used as a low sulfur industrial fuel or as a thermal cracking feedstock.
  • the naphtha When the naphtha is not sent to the mixture with the diesel fuel in step c), it is distilled.
  • the naphtha fraction obtained can advantageously be separated into heavy gasoline, which will preferably be a feedstock for a reforming process, and light gasoline which preferably will be subjected to a paraffin isomerization process.
  • the diesel fuel cutter most often has a sulfur content of between 100 and 500 ppm by weight and the gasoline cutter most often has a sulfur content of at most 200 ppm by weight.
  • the diesel cut does not meet the 2005 specifications for sulfur.
  • the other characteristics of diesel are also at a low level; for example, the cetane is of the order of 45 and the aromatic content is greater than 20% by weight.
  • the conditions are generally chosen such that the initial boiling point of the heavy fraction is from about 340 ° C to about 400 ° C and preferably from about 350 ° C to about 380 ° C. for example, about 360 ° C.
  • the boiling point is between about 120 ° C and 180 ° C.
  • the diesel is between the naphtha and the heavy fraction.
  • the cutting points given here are indicative but the operator will choose the cutting point according to the quality and quantity of the desired products, as is generally done.
  • Step c) wherein at least a portion, and preferably all, of the distillate cut undergoes hydrotreatment to reduce the sulfur content below 50 ppm by weight, and most often below 10 ppm.
  • This hydrocarbon fraction may for example be chosen from the group formed by LCOs (light cycle oil from catalytic cracking in a fluidized bed).
  • the temperature in this step is usually from about 300 to about 500 ° C, often from about 300 ° C to about 450 ° C and very often from about 350 to about 420 ° C. This temperature is usually adjusted according to the desired level of hydrodesulfurization and / or saturation of the aromatics and must be compatible with the desired cycle time.
  • the hourly space velocity (VVH) and the hydrogen partial pressure are chosen according to the characteristics of the product to be treated and the desired conversion.
  • VVH is in a range from about 0.1 h -1 to about 10 h -1 and preferably 0.1 h -1 - 5 h -1 and preferably from about 0.2 h -1 to about 2 h - 1 .
  • the total amount of hydrogen mixed with the feedstock is usually about 200 to about 5000 normal cubic meters (Nm 3 ) per cubic meter (m 3 ) of liquid feed and most often about 250 to 2000 Nm 3 / m 3 and preferably from about 300 to 1500 Nm 3 / m 3 .
  • the same operation is carried out with a partial pressure of reduced hydrogen sulfide compatible with the stability of the sulfurized catalysts.
  • the partial pressure of hydrogen sulfide is preferably less than 0.05 MPa, preferably 0.03 MPa, more preferably 0.01 MPa.
  • the ideal catalyst In the hydrodesulfurization zone, the ideal catalyst must have a high hydrogenating power so as to achieve a deep refining of the products and to obtain a significant lowering of sulfur.
  • the hydrotreatment zone operates at a relatively low temperature, which is in the direction of a deep hydrogenation, hence an improvement in the aromatic content of the product and its cetane and a limitation of the product. coking. It is not within the scope of the present invention to use in the hydrotreating zone simultaneously or successively a single catalyst or several different catalysts. Usually this step is carried out industrially in one or more reactors with one or more catalytic beds and downflow of liquid.
  • At least one fixed bed of hydrotreatment catalyst comprising a hydrodehydrogenating function and an amorphous support is used.
  • a catalyst is used, the support of which is for example chosen from the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals.
  • This support may also contain other compounds and for example oxides chosen from the group formed by boron oxide, zirconia, titanium oxide and phosphoric anhydride. Most often a support of alumina and better alumina n or ⁇ is used.
  • the hydrogenating function is provided by at least one Group VIII metal and / or Group VIB.
  • the total content of metal oxides of groups VI and VIII is often from about 5 to about 40% by weight and generally from about 7 to 30% by weight and the weight ratio expressed as metal oxide between Group VI metal (metals) on Group VIII metal (or metals) is generally from about 20 to about 1 and most often from about 10 to about 2.
  • the ideal catalyst must have a high hydrogenating power so as to achieve a deep refining of the products and to obtain a significant lowering of sulfur.
  • This catalyst may be a catalyst comprising Group VIII metals, for example nickel and / or cobalt, most often in combination with at least one Group VIB metal, for example molybdenum and / or tungsten.
  • a NiMo catalyst will be used.
  • the desulfurization of a NiMo catalyst is greater than that of a CoMo catalyst because the first shows a hydrogenating function more important than the second.
  • a catalyst comprising from 0.5 to 10% by weight of nickel and preferably from 1 to 5% by weight of nickel (expressed as nickel oxide NiO) and from 1 to 30% by weight of molybdenum and preferably from 1 to 30% by weight of molybdenum may be used. at 20% by weight of molybdenum (expressed as molybdenum oxide (MoO 3 ) on an amorphous mineral support.
  • nickel oxide NiO nickel oxide
  • MoO 3 molybdenum oxide
  • the catalyst may also contain an element such as phosphorus and / or boron. This element may have been introduced into the matrix or may have been deposited on the support. It is also possible to deposit silicon on the support, alone or with phosphorus and / or boron.
  • the concentration of said element is usually less than about 20% by weight (calculated oxide) and most often less than about 10% by weight and is usually at least 0.001% by weight.
  • concentration of boron trioxide B 2 O 3 is usually from about 0 to about 10% by weight.
  • Preferred catalysts contain silicon deposited on a support (such as alumina), optionally with P and / or B also deposited, and also containing at least one metal of GVIII (Ni, Co) and at least one metal of GVIB (W, MB).
  • a support such as alumina
  • P and / or B also deposited, and also containing at least one metal of GVIII (Ni, Co) and at least one metal of GVIB (W, MB).
  • gasolines and gas oils resulting from conversion processes are very resistant to hydrotreating if they are compared with gas oils directly derived from the atmospheric distillation of crudes.
  • the critical point is the conversion of the most refractory species, particularly the di- and trialkylated or more dibenzothiophenes for which the access of the sulfur atom to the catalyst is limited by the alkyl groups.
  • the route of the hydrogenation of an aromatic ring before desulfurization by breaking the Csp3-S bond is faster than the direct desulfurization by breaking the Csp2-S bond.
  • Conversion gas oils therefore require very severe operating conditions to achieve future sulfur specifications. If it is desired to hydrotreat these conversion gas oils under operating conditions making it possible to maintain moderate investments with a reasonable cycle time of the hydrotreatment catalyst, optimization of the integration of the process equipment is necessary.
  • step c) of hydrotreatment additional hydrogen is introduced into step c) of hydrotreatment.
  • the amount of additional hydrogen introduced in this step c) is greater than the chemical consumption of hydrogen necessary to obtain the performances set under the operating conditions set for this step c).
  • the quantity of additional hydrogen is at least equal to the difference in the material balance, the difference found corresponds approximately to the chemical consumption of hydrogen.
  • An appropriate means for measuring the hydrogen content in the feedstock or the liquid effluent is the 1 H-NMR measurement.
  • the chromatographic analysis is suitable for the gaseous effluent.
  • step c) All the makeup hydrogen necessary for the process is introduced in step c). Therefore, the quantity supplied will also take into account the chemical consumption of hydrogen on step a) so as to bring the hydrogen necessary for the hydrogenation sought in step a) also.
  • Another consequence is that it is possible to optimize the hydrogen filling in step c) according to the refractory level of the gas oils to be treated.
  • the invention thus makes it possible to substantially improve the performance of the hydrotreatment catalyst and in particular the hydrodesulfurization for given temperature and total pressure conditions and which correspond to industrially practicable values.
  • step a) For highly sulfur-containing fillers of step a) (for example having at least 1 wt.% Sulfur or at least 2%) which produce refractory and sulfur-containing conversion gas oils, it has thus become possible to obtain middle distillates. good qualities especially with a low sulfur content under conditions including relatively low pressure and thus to limit the cost of necessary investments.
  • Step d) final separation on at least part, and preferably all of the hydrotreated effluent from step c).
  • the hydrogen is separated from the effluent. It contains small amounts of hydrogen sulfide and usually does not require treatment.
  • the hydrogen sulphide is also separated from the liquid effluent and thus a gas oil is obtained at most 50 ppm by weight of sulfur, and most often at less than 10 ppm by weight of sulfur. Naphtha is also obtained in general.
  • the hydrogen-containing gas which has been separated in step b) is, if necessary, at least partly treated to reduce its H 2 S content (preferably by washing with at least one amine) before recycling it into step a) and possibly in step c).
  • the recycle gas preferably contains an amount of H 2 S greater than 0% and up to 1% mol.
  • this amount is at least 15 ppm, preferably at least 0.1%, or even at least 0.2% mol.
  • At least a portion of the gaseous fraction can be sent to an amine wash section where the H 2 S is removed in its entirety; the other part can pass the amine wash section and be sent directly to recycling after compression.
  • H 2 S is useful for maintaining the catalysts in the sulfurized state in steps a) and c), but an excess of H 2 S could reduce hydrodesulfurization.
  • step d With the hydrogen from step b) optionally purified, is added the hydrogen separated in step d). The mixture is re-compressed and then recycled to step a) and possibly to step c).
  • step c) may not be necessary, when all the additional hydrogen is introduced in step c).
  • the gas oil obtained has a sulfur content of less than 50 ppm by weight, generally less than 20 ppm, and most often less than 10 ppm.
  • the cetane has been improved from 1 to 12 points, generally from 1 to 7, or from 1 to 5 points with respect to the diesel entering hydrotreating. Its total amount of aromatics has also been reduced by at least 10%, the reduction can even go up to 90%.
  • the amount of polyaromatics in the final gas oil is at most 11% wt.
  • the feedstock to be treated enters a line (1) in a soft hydrocracking zone (I) which contains at least one fixed bed of a hydrocracking catalyst.
  • the hydrocracked effluent obtained in line (2) is sent to separation zone (II).
  • the hydrocracked effluent first passes into a separator (3) separating on the one hand a hydrogen-containing gas (gaseous phase) in the pipe (4) and on the other hand a liquid effluent in the pipe (5) .
  • a hot separator can be used followed by a cold separator (preferred) or a cold separator only.
  • the liquid effluent is sent to a separator (6), which is preferably a steam stripper, to separate the hydrogen sulfide from the hydrocarbon effluent. At the same time, at least a portion of the naphtha fraction can be separated with the hydrogen sulfide.
  • the hydrogen sulfide with said naphtha exits the line (7) while the hydrocarbon effluent is obtained in the line (8).
  • the hydrocarbon effluent then passes into a distillation column (9) and is separated at least one distillate cut including a gas oil fraction and found in the pipe (11), it is also separated a heavier fraction than the diesel fuel and found in the pipe (10).
  • the naphtha separated at the separator (6) is stabilized (H 2 S removed).
  • the stabilized naphtha is injected into the effluent entering the column (9).
  • the naphtha can be separated in an additional pipe not shown in FIG.
  • the column (9) separates a gas oil fraction mixed with naphtha, in the pipe (11).
  • the fraction of the pipe (10) is advantageously sent to the zone (V) of catalytic cracking.
  • the naphtha obtained separately, optionally added naphtha separated in the zone (IV) is advantageously separated into gasoline heavy and light, the heavy gasoline being sent to a reforming zone and the light gasoline in an area where isomerization is carried out paraffins.
  • the dividing zone (II) formed of separators (3) (6) and column (9) is schematized in broken lines.
  • the distillate cut is then sent (alone or optionally added a cut) naphtha and / or diesel outside the process) in a hydrotreating zone (III) provided with at least one fixed bed of a hydrotreatment catalyst.
  • the hydrotreated effluent obtained exits via the pipe (12) to be sent into the separation zone (IV) schematized in dashed lines in FIG. It comprises here a separator (13), preferably a cold separator, wherein are separated a gaseous phase exiting through the pipe (14) and a liquid phase exiting through the pipe (15).
  • a separator 13
  • a cold separator wherein are separated a gaseous phase exiting through the pipe (14) and a liquid phase exiting through the pipe (15).
  • the liquid phase is sent to a separator (16) preferably a stripper, to remove the hydrogen sulfide exiting in the pipe (17), usually mixed with the naphtha.
  • a diesel fraction is withdrawn through the line (18), which fraction meets the sulfur specifications, ie less than 50 ppm wt sulfur is generally less than 10 ppm.
  • the H 2 S-naphtha mixture is then optionally treated to recover the purified naphtha fraction.
  • the method and the installation according to the invention also advantageously comprise a hydrogen recycling loop for the 2 zones (I) and (II) and which is now described starting from FIG.
  • the gas containing hydrogen (gaseous phase of the pipe (4) separated in the zone (II)) is treated to reduce its sulfur content and possibly eliminate the hydrocarbon compounds that may have passed during the separation.
  • the gaseous phase of the pipe (4) is sent into an air cooler (19) after having been washed by the water injected by the pipe (20) and partly condensed by a hydrocarbon fraction sent by the line (21).
  • the effluent of the dry cooler is sent to a zone (22) of separation where are separated the water which is withdrawn by the pipe (23), a hydrocarbon fraction by the pipe (21) and a gaseous phase by the pipe ( 24).
  • Part of the hydrocarbon fraction of the pipe (21) is sent to the separation zone (II), and advantageously to the pipe (5).
  • the gaseous phase obtained in the pipe (24) freed from the hydrocarbon compounds is, if necessary, sent to a treatment unit (25) to reduce the sulfur content.
  • it is a treatment with at least one amine.
  • the hydrogen-containing gas thus optionally purified is then re-compressed in the compressor (27).
  • the compressed mixture is then recycled in part to the hydrotreatment zone (III) (Step c) and partly to the mild hydrocracking zone (I) (step a) by the lines (28) and (29) respectively.
  • the recycling hydrogen is introduced at the inlet of the reaction zones with the liquid charge.
  • Part of the hydrogen can also be introduced between the catalytic beds in order to control the inlet temperature of the bed ("quench").
  • a preferred mode for bringing hydrogen to zone (III) is to provide a pipe for recycling and a pipe for top-up.
  • the invention operates at moderate pressures, investments are reduced.
  • Example 1 (addition of H2 at the inlet of the hydrocracking MHDC and at the entrance of the HDT).
  • the feedstock is a vacuum distillate containing 3% wt sulfur.
  • the conversion of the distillation range in the hydrocracking zone is 35% of the 360 ° C + fraction.
  • a gas oil fraction is obtained containing 250 ppm by weight of sulfur. This diesel cut is hydrotreated in a dedicated reactor.
  • the process is carried out according to the scheme of FIG. 1 except that the makeup of H2 is dedicated to each hydrocracking and hydrotreatment unit.
  • the recycling of the hydrogen-rich gas is common to both units with an amine wash of the gas separated in step b).
  • Example 2 H2 supplement only at the HDT inlet corresponding to the total H2 consumption of the MHDC + HDT section).

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Catalysts (AREA)

Claims (16)

  1. Verfahren zur Behandlung von Erdölbeschickungen, wovon mindestens 80 Gew.-% oberhalb von 340 °C sieden, und die mindestens 0,05 Gew.-% Schwefel enthalten, um mindestens einen Gasölschnitt mit einem Schwefelgehalt von höchsten 50 ppm (Gewicht) herzustellen, wobei das Verfahren die folgenden Schritte umfasst:
    a) mildes Hydrokracken im Festbett in Gegenwart mindestens eines Katalysators bei einer Temperatur von 330 - 500 °C, einem Druck von mindestens 2 MPa und weniger als 12 MPa, einer Raumgeschwindigkeit pro Stunde von 0,1 h-1 bis 10 h-1 und in Gegenwart von 100 - 5.000 Nm3 Wasserstoff/m3 Beschickung, wobei die Nettokonversion von Produkten, die oberhalb von 360 °C sieden, bei 10 - 50 Gew.-% liegt,
    b) Abscheiden eines Gases aus dem Abfluss, das Wasserstoff, den in Schritt a) gebildeten Schwefelwasserstoff und eine Fraktion enthält, die schwerer ist als Gasöl, wobei das Gas, das den Wasserstoff enthält, danach zum Schritt a) zurückgeführt wird,
    c) Hydrobehandlung, durch Kontakt mit mindestens einem Katalysator, mindestens eines in Schritt b) erhaltenen Destillatschnitts, der eine Gasölfraktion beinhaltet, bei einer Temperatur von 300 - 500 °C, einem Druck von 2 - 12 MPa, einer Raumgeschwindigkeit pro Stunde von 0,1 - 10 h-1 und in Gegenwart von 200 - 5.000 Nm3 Wasserstoff/m3 Beschickung,
    d) Abscheiden des Wasserstoffs, der Gase und mindestens eines Gasölschnitts mit einem Schwefelgehalt von weniger als 50 ppm (Gewicht), wobei der abgeschiedene Wasserstoff zusammen mit dem Wasserstoff aus Schritt b) erneut verdichtet, und dann zum Schritt a) zurückgeführt wird,
    und wobei in dem Verfahren die Gesamtheit des für das Verfahren erforderlichen Zusatzwasserstoffs zu Schritt c) geleitet wird.
  2. Verfahren nach Anspruch 1, wobei die Menge an Zusatzwasserstoff, die in Schritt c) eingeführt wird, größer ist als der chemische Wasserstoffverbrauch, der erforderlich ist, um die Leistungen zu erhalten, die in den für Schritt c) festgelegten Betriebsbedingungen festgelegt wurden.
  3. Verfahren nach einem der vorhergehenden Ansprüche, wobei die schwere Fraktion in ein Verfahren zum katalytischen Kracken geschickt wird.
  4. Verfahren nach einem der vorhergehenden Ansprüche, wobei der H2S-Partialdruck am Ausgang von Schritt a) 0,1 - 0,4 MPa und am Ausgang von Schritt c) weniger als 0,05 MPa beträgt.
  5. Verfahren nach einem der vorhergehenden Ansprüche, wobei in Schritt b) auch das Naphta abgeschieden wird und in Schritt c) eine Gasölfraktion durchläuft.
  6. Verfahren nach einem der Ansprüche 1 bis 4, wobei in Schritt c) eine mit Naphta gemischte Gasölfraktion durchläuft.
  7. Verfahren nach einem der vorhergehenden Ansprüche, wobei mindestens ein Teil des Gases, das den in Schritt b) abgeschiedenen Wasserstoff enthält, behandelt wird, um seinen Gehalt an Schwefelwasserstoff zu reduzieren, dann zum Schritt a) zurückgeführt wird, wobei das zurückgeführte Gas Schwefelwasserstoff in der Größenordnung von höchstens 1 Mol.-% enthält.
  8. Verfahren nach Anspruch 7, wobei es sich bei der Behandlung um eine Wäsche mit mindestens einem Amin handelt.
  9. Verfahren nach einem der Ansprüche 7 bis 8, wobei der Wasserstoff ebenfalls in den Schritt c) zurückgeführt wird.
  10. Verfahren nach einem der vorhergehenden Ansprüche, wobei die in den Schritten b) und d) abgeschiedenen Fraktionen, in Schwer- und Leichtbenzin geschieden werden, wobei das Schwerbenzin zur Reformierung und das Leichtbenzin zur Paraffinisomerisierung geschickt werden.
  11. Anlage zur Behandlung von Erdölbeschickungen, wovon mindestens 80 Gew.-% oberhalb von 340 °C sieden und mindestens 0,05 % Schwefel enthalten, umfassend:
    a) eine Zone (I) zum milden Hydrokracken, die mindestens ein Festbett mit einem Katalysator zum Hydrokracken enthält und mit einer Leitung (1) zum Einführen der zu behandelnden Beschickung, einer Leitung (2) zum Ausleiten des hydrogekrackten Abflusses und einer Leitung (29) zum Einführen des Wasserstoffs ausgestattet ist,
    b) eine Zone (II) zum Abscheiden, die mindestens einen Separator (3) (6) beinhaltet, um das Gas, das reich an Wasserstoff ist, durch die Leitung (4) abzuscheiden, um in der Leitung (7) den Schwefelwasserstoff abzuscheiden und in der Leitung (8) eine flüssige Fraktion zu erhalten, und außerdem eine Destillationssäule (9) beinhaltet, um mindestens einen Destillatschnitt, der eine Gasölfraktion beinhaltet, in der Leitung (11) und eine schwere Fraktion in der Leitung (10) abzuscheiden,
    c) eine Zone (III) zur Hydrobehandlung, die mindestens ein Festbett mit Hydrobehandlungskatalysator enthält, um eine Gasölfraktion zu behandeln, die am Ende von Schritt b) erhalten wird, die mit einer Leitung zum Einführen der Gesamtheit des Wasserstoffs und einer Leitung (12) zum Ausleiten des hydrobehandelten Abflusses ausgestattet ist,
    d) eine Zone (IV) zum Abscheiden, die mindestens einen Separator (13) (16) beinhaltet, um den Wasserstoff über die Leitung (14) abzuscheiden, um in der Leitung (17) den Schwefelwasserstoff und über die Leitung (18) ein Gasöl abzuscheiden, das einen Schwefelgehalt von weniger als 50 ppm aufweist,
    wobei die Anlage eine Zone (25) zur Behandlung, um den H2S-Gehalt des Gases, das den Wasserstoff aus Leitung (4) enthält, zu senken, einen Verdichter (27), der das Gas aus der Zone (25) und den Wasserstoff, der durch die Leitung (14) geleitet wird, erneut verdichtet, und eine Leitung (29) zum Zurückführen des Wasserstoffs in die Zone (I) umfasst.
  12. Anlage nach Anspruch 11, die außerdem eine Zone (V) zum katalytischen Kracken umfasst, wobei die schwere Fraktion über die Leitung (10) geschickt wird.
  13. Anlage nach einem der Ansprüche 11 oder 12, wobei die Zone (II) einen Gas-/Flüssigkeitsseparator (3), um ein Gas, das Wasserstoff enthält, über die Leitung (4) abzuscheiden, dann einen Separator (6), der den Abfluss, der aus dem Separator (3) stammt, einströmen lässt, um den Schwefelwasserstoff und Naphta über die Leitung (7) abzuscheiden und eine flüssige Fraktion in der Leitung (8) zu erhalten, umfasst, wobei die Zone (II) außerdem eine Destillationssäule (9) umfasst, um über die Leitung (11) einen Naphta- und Gasöl-Schnitt abzuscheiden und über die Leitung (10) eine Fraktion abzuscheiden, die schwerer ist als das Gasöl und wobei die Leitung (10) mit einer Zone (V) zum katalytischen Kracken verbunden ist.
  14. Anlage nach einem der Ansprüche 11 bis 13, wobei die Zone (II) einen Gas-/Flüssigkeitsseparator (3), um ein Gas, das Wasserstoff enthält, über die Leitung (4) abzuscheiden, dann einen Separator (6) umfasst, der den Abfluss aus dem Separator (3) einströmen lässt, um den Schwefelwasserstoff und Naphta über die Leitung (7) abzuscheiden und um in der Leitung (8) eine flüssige Fraktion zu erhalten, wobei auf der Leitung (7) ein Stabilisator angeordnet ist, um den Schwefelwasserstoff zu entfernen, wobei das gereinigte Naphta in die Leitung (8) geschickt wird, wobei die Zone (II) außerdem eine Destillationssäule (9) umfasst, um das Naphta, eine Fraktion, die schwerer ist als das Gasöl, über die Leitung (10), und einen Gasölschnitt über die Leitung (11) abzuscheiden, wobei die Leitung (10) mit der Zone (V) zum katalytischen Kracken verbunden ist.
  15. Anlage nach einem der Ansprüche 11 bis 14, die außerdem mit einer Leitung (28) zur Rückführung des Wasserstoffs in die Zone (III) ausgestattet ist.
  16. Anlage nach einem der Ansprüche 11 bis 15, die außerdem mit einer Leitung (30) ausgestattet ist, die den Zusatzwasserstoff in die Zone (III) leitet.
EP02290432A 2001-11-09 2002-02-22 Verfahren zur Umwandlung von schweren teroleumfraktionen zur Herstellung einer Beschickung für ein katalytisches Crackverfahren und Mitteldestillate mit niedrigem Schwefelgehalt Expired - Lifetime EP1310544B1 (de)

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FR0114531A FR2832158B1 (fr) 2001-11-09 2001-11-09 Procede de conversion de fractions lourdes petrolieres pour produire une charge de craquage catalytique et des distillats moyens de faible teneur en soufre
FR0114531 2001-11-09

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US7704377B2 (en) * 2006-03-08 2010-04-27 Institut Francais Du Petrole Process and installation for conversion of heavy petroleum fractions in a boiling bed with integrated production of middle distillates with a very low sulfur content
FR2907459B1 (fr) * 2006-10-24 2012-10-19 Inst Francais Du Petrole Procede et installation de conversion de fractions lourdes petrolieres en lit fixe avec production integree de distillats moyens a tres basse teneur en soufre.

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US4839025A (en) * 1979-10-15 1989-06-13 Union Oil Company Of California Mild hydrocracking with a catalyst containing non-hydrolyzable halogen
FR2791354B1 (fr) * 1999-03-25 2003-06-13 Inst Francais Du Petrole Procede de conversion de fractions lourdes petrolieres comprenant une etape d'hydroconversion en lits bouillonnants et une etape d'hydrotraitement

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ATE525449T1 (de) 2011-10-15
FR2832158B1 (fr) 2004-10-22
CA2372620C (fr) 2010-05-04
CA2372620A1 (fr) 2003-05-09
ES2372747T3 (es) 2012-01-26
FR2832158A1 (fr) 2003-05-16
EP1310544A1 (de) 2003-05-14

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