EP3184607A1 - Hydrotreatment- oder hydrokonvertierungsverfahren mit stripper und niedrigdruck-trennbehälter auf dem fraktionierungsabschnitt - Google Patents

Hydrotreatment- oder hydrokonvertierungsverfahren mit stripper und niedrigdruck-trennbehälter auf dem fraktionierungsabschnitt Download PDF

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EP3184607A1
EP3184607A1 EP16306699.6A EP16306699A EP3184607A1 EP 3184607 A1 EP3184607 A1 EP 3184607A1 EP 16306699 A EP16306699 A EP 16306699A EP 3184607 A1 EP3184607 A1 EP 3184607A1
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Prior art keywords
pressure
mpa
stripper
column
effluent
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EP16306699.6A
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English (en)
French (fr)
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EP3184607B1 (de
Inventor
Odile LAJEUNESSE
Pierre-Yves ALSPEKTOR
Pâris PACKEU
Nicolas PUPAT
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Axens SA
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Axens SA
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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
    • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
    • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only 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
    • 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
    • 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
    • C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
    • C10G49/22—Separation of effluents
    • 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
    • C10G5/00—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas
    • 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
    • C10G2300/10—Feedstock materials
    • C10G2300/1022—Fischer-Tropsch products
    • 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
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • 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
    • C10G2300/10—Feedstock materials
    • C10G2300/107—Atmospheric residues having a boiling point of at least about 538 °C
    • 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
    • C10G2300/10—Feedstock materials
    • C10G2300/1074—Vacuum distillates
    • 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
    • C10G2300/10—Feedstock materials
    • C10G2300/1077—Vacuum residues
    • 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

Definitions

  • the invention relates to the field of hydrotreatment or hydroconversion processes.
  • Conventional processes for the hydrotreatment or hydroconversion of gas oils, vacuum distillates, atmospheric or vacuum residues or Fischer-Tropsch unit effluents generally comprise a fractionation section of the effluent of the reaction section carrying out mainly two objectives, the elimination of H2S and light, and the main fractionation of the unit's products. Achieving these two objectives generates energy consumption and represents a significant investment and operating cost both in absolute terms and in relation to the entire process.
  • the patent US 3,733,260 discloses a gas oil hydrodesulphurization process comprising a hydrodesulfurization reaction section, a separation of the effluent of this section into a gaseous fraction and a first high temperature and high pressure liquid fraction, a partial condensation of said vapor phase into a gaseous fraction consisting essentially of hydrogen, and a second liquid fraction, stripping of the H 2 S and light hydrocarbons of the first and the second liquid fraction by means of the previously treated hydrogen, separation of the stripped hydrocarbons into a naphtha and a diesel fuel and a recycle of said naphtha in the condensation step.
  • This configuration requires generating a reflux for stripping, and has the disadvantage of dissipating a portion of the energy contained in the effluent of the reaction section in the top aircondenser stripper.
  • the optimum temperature required for supply stripping is lower than the minimum temperature required for the downstream separation, it requires heating the load of this separation.
  • the patent US 3,337,1029 discloses a process for separating effluents from a hydrogen-containing hydrocarbon conversion reactor in which there is no stripping of H2S and hydrocarbons upstream of the main hydrocarbon separation in one naphtha, diesel and heavier compounds.
  • This last configuration has the disadvantage that the acid gases inevitably derived from the main separation operated at a pressure close to atmospheric pressure must, after removal of the H2S be compressed before being returned to a fuel gas network. a refinery.
  • the invention corrects these disadvantages by minimizing or even eliminating the separation head compressor while maximizing the energy efficiency of the process.
  • the present invention also relates to a process for hydrotreating or hydroconversion of gas oil, vacuum distillates, atmospheric or vacuum residues using the installation described above.
  • the separation column C-1 generally operates under the following conditions: total pressure of between 0.6 and 2.0 MPa, preferably between 0.7 and 1.8 MPa.
  • the fractionation column C-2 generally operates under the following pressure conditions: total pressure of between 0.1 MPa and 0.4 MPa, preferably between 0.1 MPa and 0.3 MPa.
  • At least part of the top fraction from the fractionation column C-2 containing the residual acid gases is sent to a washing column C-5 operating at very low pressure, in order to remove at least a portion of the H 2 S, said portion of the overhead fraction then being used as a fuel in the furnace F-1 of the reaction section.
  • At least a portion of the overhead fraction from the fractionation column C-2 containing the residual acid gases is sent to the acid gas compressors of a catalytic cracking unit. fluidized bed (FCC).
  • FCC fluidized bed
  • the temperature of the hot high pressure separator tank B-1 is chosen so as not to require an oven on the charge of the main fractionation C2.
  • reaction section R-1 may comprise several reactors arranged in series or in parallel.
  • Each reactor of the reaction section comprises at least one catalyst bed.
  • the catalyst can be used in a fixed bed or in an expanded bed, or in a bubbling bed. In the case of a catalyst implemented in fixed bed, it is possible to have several catalyst beds in at least one reactor.
  • Any catalyst known to those skilled in the art can be used in the process according to the invention, for example a catalyst comprising at least one element selected from the elements of Group VII of the Periodic Table (groups 8, 9 and 10 of the new periodic classification), and possibly at least one element selected from Group VIB elements of the Periodic Table (Group 6 of the new Periodic Table).
  • 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, 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 (expressed in terms of nickel oxide NiO) and from 1 to 30% by weight of molybdenum, preferably from 5 to 20% by weight of molybdenum, may be used. (expressed in terms of MoO3 molybdenum oxide) on an amorphous mineral support.
  • the total content of metal oxides of groups VI and VIII in the catalyst is generally between 5 and 40% by weight and preferably between 7 and 30% by weight.
  • the weight ratio (expressed on the basis of the metal oxides) between the Group VI metal (or metals) and the Group VIII metal (or metals) is, in general, from about 20 to about 1, and most often about 10 to about 2.
  • the support 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 boron oxide, zirconia, titanium oxide and phosphoric anhydride.
  • an alumina support is used, and preferably ⁇ or ⁇ alumina.
  • the catalyst may also contain a promoter element such as phosphorus and / or boron. This element may have been introduced into the matrix or preferably deposited on the support. Silicon may also be deposited on the support, alone or with phosphorus and / or boron.
  • a promoter element such as phosphorus and / or boron. This element may have been introduced into the matrix or preferably deposited on the support. Silicon may also be deposited on the support, alone or with phosphorus and / or boron.
  • the catalysts contain silicon deposited on a support such as alumina, optionally with phosphorus and / or boron deposited on the support, and also containing at least one metal of group VIII (Ni, Co ) and at least one Group VIB metal (Mo, W).
  • concentration of said element is usually less than about 20% by weight (based on the oxide base), and most often less than about 10%.
  • the concentration of boron trioxide (B2O3) is usually from about 0 to about 10% by weight.
  • Another catalyst is a silica-alumina comprising at least one Group VIII metal and at least one Group VIB metal.
  • Another type of catalyst that can be used in the process according to the invention is a catalyst containing at least one matrix, at least one Y zeolite, and at least one hydro-dehydrogenating metal.
  • the matrices, metals, additional elements previously described may also be included in the composition of this catalyst.
  • Certain compounds having a basic character are well known to significantly reduce the cracking activity of acidic catalysts such as silica-aluminas or zeolites.
  • acidic catalysts such as silica-aluminas or zeolites.
  • the separation column (stripper) C-1 aims to eliminate the gases from cracking (generally called acid gases), including H2S, from reactions of the reaction section.
  • This column C-1 can use any stripping gas such as for example a gas containing hydrogen or water vapor.
  • steam is used to carry out the stripping according to the invention.
  • the separation column C-1 (stripper) can be reboiled.
  • the pressure of this separation column C-1 is generally sufficiently high so that the acid gases from this separation, previously purified of the H2S they contain, can be reinjected into the fuel gas network of the site.
  • the total pressure is typically from about 0.4 MPa to about 2.0 MPa, generally from 0.6 to 2.0 MPa, preferably from 0.7 to 1.8 MPa.
  • the fractionation column C-2 is preferably fed by means of any stripping gas, preferably steam.
  • the total pressure of the fractionation column C-2 is generally between 0.1 MPa and 0.4 MPa, preferably between 0.1 MPa and 0.3 MPa.
  • the overhead fraction of the C-2 fractionation column contains the residual acid gases that are compressed in the K-2 compressor before being sent to the acid gas treatment section generally using an amine scrubbing column. This fraction of acid gases after washing is then directed to the fuel gas network.
  • At least part of the overhead fraction from the fractionation column C-2 containing the residual acid gases is sent to a washing column C-5 operating at very low pressure, in order to eliminate at least one part of the H2S, said portion of the top fraction being used as a fuel in the furnace F-1 of the reaction section.
  • At least a part of the top fraction derived from the fractionation column C-2 containing the residual acid gases is sent to the acid gas compressors of a fluidized catalytic cracking unit (FCC). This then eliminates the acid gas compressor of the hydrodesulfurization unit.
  • FCC fluidized catalytic cracking unit
  • the hot high pressure separator balloon B-1 is generally operated at a slightly lower pressure, for example a lower pressure of 0.1 MPa to 1.0 MPa than that of the reactor R-1.
  • the temperature of the hot separator flask B-1 is generally between 200 ° C. and 450 ° C., preferably between 250 ° C. and 380 ° C. and very preferably between 260 ° C. and 360 ° C.
  • the temperature of the hot high pressure separator tank B-1 is chosen so as not to require an oven on the charge of the main fractionation C2.
  • the high-pressure cold separator balloon B-2 the charge of which is the gaseous flow coming from the hot separator balloon B-1, is operated at a pressure slightly lower than that of B-1, for example a lower pressure of 0, 1 MPa at 1.0 MPa than that of B-1.
  • the gaseous effluent from B-2 is optionally washed in column C-3, and then compressed in compressor K-1.
  • the temperature of the high-pressure cold separator tank B-2 is generally as low as possible considering the cooling means available on the site, so as to maximize the purity of the recycled hydrogen.
  • the liquid from the cold separator tank B-2 is expanded in a valve or a turbine, and directed into a cold medium pressure separator tank B-4.
  • the total pressure of the latter is preferably that required to efficiently recover the hydrogen included in the separated gaseous fraction in the flask. This recovery of hydrogen is preferably carried out in a pressure reversal adsorption unit.
  • the pressure of the flask B-4 is generally between 1.0 MPa and 3.5 MPa, preferably between 1.5 MPa and 3.5 MPa.
  • the liquid flow from the hot separator tank at high pressure B-1 is directed into a hot medium pressure separator drum B-3.
  • the pressure of said separator tank B-3 is chosen so as to feed the cold medium pressure separator tank B-4 with the separated gas stream into the hot high pressure separator tank B-3.
  • a portion of the liquid from B3 can be reinjected into B-2 to promote the dissolution of light hydrocarbons therein and maximize the hydrogen purity of the recycle gas.
  • the liquid flow from the hot medium pressure separator drum B-3 is expanded and directed to a hot low pressure separator drum B-5.
  • the pressure of said flask B-5 is chosen sufficiently high so that the gaseous effluent from B-5 can be directed to the separation column C-1.
  • the total pressure of the separator flask B-5 is typically from about 0.2 MPa to about 2.5 MPa, generally from 0.3 to 2.0 MPa, preferably from 0.4 to 1.8 MPa.
  • reaction zone R-1 is a hydrocracking zone, without this constituting a limitation to the present invention which relates to the installation of a separator (B-5) and stripper (C-1) assembly upstream of the main fractionation column C-2.
  • the filler is a cup with boiling points between 350 ° C and 530 ° C, a mixture of 70% by weight of heavy vacuum distillate and 30% by weight of heavy coker gas oil, having the following characteristics: Specific density 0.965 Sulfur content % weight 2.8 Nitrogen content ppm weight 5000
  • the load is fed via line 1 by the pump P-1.
  • the makeup hydrogen preferably in excess of the charge, is supplied via line 2 and compressor K-2 and then line 3, and mixed with charge 1 before being admitted to a charge-exchanger. effluent (E-1) via line 4.
  • the exchanger E-1 makes it possible to preheat the feedstock by means of the effluent from the hydrocracking reactor R-1. After this exchange, the charge is fed via line 5 into an oven F-1 to reach the temperature level necessary for the hydrocracking reaction, then the hot charge is sent via line 6 in the section d hydrocracking, constituted by at least one hydrocracking reactor R-1 comprising at least one hydrocracking catalyst.
  • the reaction section R-1 is composed of 2 reactors in series, of 3 catalyst beds each.
  • the first bed of the first reactor and composed of Axens HMC catalysts 868, HF858 and HR844.
  • the other beds consist of Axens HR844 catalyst.
  • the beds are operated approximately at 12.5 MPa and at temperatures between 350 ° C. and 370 ° C.
  • the hydrogen consumption in the reaction section is 2% relative to the fresh charge.
  • the effluent from the reaction section is then sent via line 10 to the exchanger E-1, then via line 11 to the hot separator tank at high pressure B-1. A gaseous fraction of the head is separated in this balloon and recovered via line 12.
  • the liquid fraction is recovered at the bottom of the flask B-1 via the line 20.
  • Said gaseous fraction (12) comprises unreacted hydrogen, the H2S formed in the course of the reaction, as well as light hydrocarbons from the hydrocarbon conversion of the feedstock in the R-1 hydrocracking reaction section.
  • this fraction After cooling in an exchanger E-2 and an aerocondenser A-1, this fraction is fed, via line 13, into a cold separator tank at high pressure B-2 allowing both gas-liquid separation and settling. of the aqueous liquid phase.
  • the liquid hydrocarbon phase is, after expansion in the valve or the liquid turbine V-1, directed into a cold medium pressure separator tank B-4 via line 21.
  • the liquid effluent from the flask B-1 is, after expansion in the valve or the liquid turbine V-2, directed into a hot medium-pressure separator tank B-3 via the line 20.
  • a gaseous fraction is separated in this flask. and recovered via line 22.
  • the gaseous fraction comprises unreacted hydrogen, H 2 S, as well as, generally, light hydrocarbons derived from the conversion of the feed hydrocarbons into the reaction section R-1. .
  • the gaseous fraction from the high-pressure cold separator flask B-2 is sent via line 14 to an amine absorber or a C-3 scrubbing column for removing at least a portion of the H 2 S.
  • the gaseous fraction containing hydrogen is then recycled via lines 15 and 16 to the hydrocracking reactor, after compression using compressor K-1 and mixing with charge 1.
  • the hydrocarbon liquid effluent from the flask B-4 feeds the stripper C-1 via the lines 32 and 33, the valve or the liquid turbine V-5 and the exchanger E-3.
  • water vapor is preferentially added via lines 60 and 61 to the top effluent of balloons B-1 and / or B-3 to facilitate fractionation.
  • This water is separated in the balloons B-2 and B-4, and discharged after separation via the line 57.
  • the water separated in the balloon B-2 is sent via the line 56 and the valve V4 to the balloon B-4.
  • Line 58 makes it possible to evacuate a gaseous flow.
  • Stripper C-1 is operated at 0.9 MPa at the top of the column, 45 ° C. at reflux tank B-6 for a bottom temperature of 180 ° C.
  • a gaseous fraction is separated in the B-5 flask. This gaseous fraction feeds the stripper C-1 via the line 34.
  • the stripper C-1 is fed with stripping steam via the line 35 at a ratio of 7 kg / hr of steam for 1 standard m3 of bottoms product. .
  • a gaseous fraction (generally called acid gas) is recovered via line 36, and via line 37 a naphtha having a final boiling point, most often greater than 100 ° C., by a B-6 flask. and an E-6 exchanger.
  • the liquid recovered at the bottom of the stripper via line 39 is sent to the main fractionation column C-2, without it being necessary to heat it in an oven or exchanger.
  • the liquid fraction from the flask B-5 directly feeds the main fractionation C-2 via the line 38 without being the subject of an acid gas separation operation in a stripping column or a reboiled separation column.
  • the main fractionating column C-2 is operated at a low pressure of 0.29 MPa at the top of the column, at 45 ° C. at the reflux tank B-7 (after passing through an A-3 aerocondenser and a P-2 pump) for a bottom temperature of 330 ° C.
  • the heat required for separation is preferably provided by the temperature of the hot separator flask B-5, operated at 340 ° C. and 1.1 MPa.
  • This column C-2 is also supplied with stripping steam via line 40 at a ratio of 7 kg / hr of steam per 1 standard m3 of bottoms product.
  • the overhead fraction recovered via line 41 contains the residual acid gases that are compressed in the K-2 compressor prior to export to acid gas treatment (typically an amine wash or wash column) before being directed to a reactor. fuel gas network via line 42.
  • acid gas treatment typically an amine wash or wash column
  • the residual acid gases are sent via line 43 to an amine absorber or a C-5 washing column operating at very low pressure which makes it possible to eliminate at least a part of the H 2 S, before being used in a minority way as fuel in the furnace R-1 of the reaction section via line 44.
  • these residual acid gases are directed to the acid gas compressors of the catalytic cracking unit. in a fluidized bed via line 45.
  • the product obtained line 50 by the pump P-3 consists of naphtha cuts having a final boiling point, most often less than 200 ° C.
  • the intermediate fraction from the main fractionating column C-2 via the intermediate column C-4 (optional), possibly equipped with an E-7 reboiler, via the line 51 is cooled, for example, by means of a heat exchanger E-4 after passing through a pump P-5, then recovered via line 52. It is for example a diesel cut having a distillation temperature of 95% volume (NF EN ISO 3405 standard) less than 360 ° vs.
  • the heavy fraction from the main fractionation column via the lines 53 and 54 is also cooled after passing through a pump P-4 by means of the exchanger E-5.
  • the fraction thus obtained via line 55 is a vacuum gas oil having cutting points close to the initial charge.
  • fractionation column C-2 does not include intermediate fractionation C-4, and lines 51 and 52 are absent.
  • Table 1 compares a mild hydrocracking process according to the prior art, that is to say without stripper C-1 ( figure 2 ), with a mild hydrocracking process according to the invention, that is to say with a B-5 flask and a C-1 stripper ( figure 1 ).
  • the amount of acid gas at the top of the main low-pressure fractionating column (stream 41) to be compressed in the compressor K-2 is divided by 6 compared to the method according to the prior art. (107 Kg / h against 608 Kg / h).
  • the temperature at the low pressure hot-water separator tank B-5 is 340 ° C., which makes it possible to avoid putting an oven for heating the charge 38, drawn off at the bottom of the low-pressure balloon B-5, which feeds the column C-2.

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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)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)
EP16306699.6A 2015-12-23 2016-12-15 Hydrotreatment- oder hydrokonvertierungsverfahren mit stripper und niedrigdruck-trennbehälter auf dem fraktionierungsabschnitt Active EP3184607B1 (de)

Applications Claiming Priority (1)

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FR1563173A FR3046176A1 (fr) 2015-12-23 2015-12-23 Procede d'hydrotraitement ou d'hydroconversion avec striper et ballon separateur basse pression sur la section de fractionnement

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EP3184607A1 true EP3184607A1 (de) 2017-06-28
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US (1) US11028330B2 (de)
EP (1) EP3184607B1 (de)
CN (1) CN106906002B (de)
ES (1) ES2714797T3 (de)
FR (1) FR3046176A1 (de)
RU (1) RU2726528C2 (de)

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP3502213A1 (de) * 2017-12-22 2019-06-26 Axens Wärmetauscherspule für die hydrobehandlung oder hydroumwandlung
EP3502214A1 (de) * 2017-12-22 2019-06-26 Axens Wärmetauscherspule für die hydrobehandlung oder hydroumwandlung
WO2022079051A1 (en) * 2020-10-14 2022-04-21 Shell Internationale Research Maatschappij B.V. Systems and processes for generating a reduced chloride stripped fluid from a hydroprocessing effluent
FR3126423A1 (fr) 2021-08-26 2023-03-03 IFP Energies Nouvelles Procédé d’hydroconversion de charges hydrocarbonées

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WO2000071641A1 (fr) 1999-05-19 2000-11-30 Institut Francais Du Petrole Catalyseur comprenant une zeolithe y partiellement amorphe et son utilisation en hydroconversion de charges petrolieres hydrocarbonees
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US3371029A (en) 1966-11-30 1968-02-27 Universal Oil Prod Co Mixed-phase conversion product separation process
US3733260A (en) 1972-02-04 1973-05-15 Texaco Inc Hydrodesulfurization process
US4738940A (en) 1984-03-30 1988-04-19 Institut Francais Du Petrole Novel hydrocracking or cracking catalyst for hydrocarbon charges
US4738941A (en) 1984-04-26 1988-04-19 Societe Francaise Des Produits Pour Catalyse Pro-Catalyse Hydrocracking catalyst for the production of middle distillates
EP0911077A1 (de) 1997-10-20 1999-04-28 Institut Français du Pétrole Katalyseur und Verfahren zum Hydrokracken von Kohlenwasserstoffen enthaltenden Fraktionen
WO2000071641A1 (fr) 1999-05-19 2000-11-30 Institut Francais Du Petrole Catalyseur comprenant une zeolithe y partiellement amorphe et son utilisation en hydroconversion de charges petrolieres hydrocarbonees
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Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP3502213A1 (de) * 2017-12-22 2019-06-26 Axens Wärmetauscherspule für die hydrobehandlung oder hydroumwandlung
EP3502214A1 (de) * 2017-12-22 2019-06-26 Axens Wärmetauscherspule für die hydrobehandlung oder hydroumwandlung
FR3075942A1 (fr) * 2017-12-22 2019-06-28 Axens Echangeur de chaleur bobine pour hydrotraitement ou hydroconversion
FR3075941A1 (fr) * 2017-12-22 2019-06-28 Axens Echangeur de chaleur bobine pour hydrotraitement ou hydroconversion
WO2022079051A1 (en) * 2020-10-14 2022-04-21 Shell Internationale Research Maatschappij B.V. Systems and processes for generating a reduced chloride stripped fluid from a hydroprocessing effluent
FR3126423A1 (fr) 2021-08-26 2023-03-03 IFP Energies Nouvelles Procédé d’hydroconversion de charges hydrocarbonées

Also Published As

Publication number Publication date
RU2016149662A (ru) 2018-06-20
CN106906002B (zh) 2021-04-02
ES2714797T3 (es) 2019-05-30
US20170183574A1 (en) 2017-06-29
US11028330B2 (en) 2021-06-08
EP3184607B1 (de) 2018-12-12
RU2016149662A3 (de) 2020-03-11
RU2726528C2 (ru) 2020-07-14
CN106906002A (zh) 2017-06-30
FR3046176A1 (fr) 2017-06-30

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