WO2014096704A1 - Process with separation for treating petroleum feedstocks for the production of fuel oils with a low sulphur content - Google Patents
Process with separation for treating petroleum feedstocks for the production of fuel oils with a low sulphur content Download PDFInfo
- Publication number
- WO2014096704A1 WO2014096704A1 PCT/FR2013/053166 FR2013053166W WO2014096704A1 WO 2014096704 A1 WO2014096704 A1 WO 2014096704A1 FR 2013053166 W FR2013053166 W FR 2013053166W WO 2014096704 A1 WO2014096704 A1 WO 2014096704A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- fraction
- vacuum
- separation
- atmospheric
- hydroconversion
- Prior art date
Links
- 238000000034 method Methods 0.000 title claims abstract description 81
- 238000000926 separation method Methods 0.000 title claims abstract description 75
- 230000008569 process Effects 0.000 title claims abstract description 64
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 title claims abstract description 48
- 239000000295 fuel oil Substances 0.000 title claims abstract description 38
- 238000004519 manufacturing process Methods 0.000 title claims abstract description 17
- 239000003208 petroleum Substances 0.000 title abstract description 6
- 239000005864 Sulphur Substances 0.000 title abstract 2
- 239000003054 catalyst Substances 0.000 claims abstract description 90
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 75
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 74
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 62
- 239000003921 oil Substances 0.000 claims abstract description 62
- 239000007788 liquid Substances 0.000 claims abstract description 45
- 229910052717 sulfur Inorganic materials 0.000 claims description 50
- 239000011593 sulfur Substances 0.000 claims description 46
- 229910052739 hydrogen Inorganic materials 0.000 claims description 45
- 239000001257 hydrogen Substances 0.000 claims description 45
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 claims description 38
- 238000006243 chemical reaction Methods 0.000 claims description 34
- 230000005587 bubbling Effects 0.000 claims description 29
- 239000007789 gas Substances 0.000 claims description 26
- 238000004523 catalytic cracking Methods 0.000 claims description 25
- 238000004821 distillation Methods 0.000 claims description 25
- 239000013049 sediment Substances 0.000 claims description 22
- 238000009835 boiling Methods 0.000 claims description 20
- 238000005194 fractionation Methods 0.000 claims description 20
- 239000003350 kerosene Substances 0.000 claims description 20
- 239000000203 mixture Substances 0.000 claims description 19
- 238000011282 treatment Methods 0.000 claims description 18
- 238000005292 vacuum distillation Methods 0.000 claims description 14
- 230000009849 deactivation Effects 0.000 claims description 10
- 230000006837 decompression Effects 0.000 claims description 10
- ZZUFCTLCJUWOSV-UHFFFAOYSA-N furosemide Chemical compound C1=C(Cl)C(S(=O)(=O)N)=CC(C(O)=O)=C1NCC1=CC=CO1 ZZUFCTLCJUWOSV-UHFFFAOYSA-N 0.000 claims description 10
- 239000010730 cutting oil Substances 0.000 claims description 9
- 238000005520 cutting process Methods 0.000 claims description 8
- 239000003502 gasoline Substances 0.000 claims description 6
- 125000003118 aryl group Chemical group 0.000 claims description 4
- 239000010779 crude oil Substances 0.000 claims description 4
- 239000000284 extract Substances 0.000 claims description 4
- 239000000314 lubricant Substances 0.000 claims description 3
- 235000015076 Shorea robusta Nutrition 0.000 claims description 2
- 244000166071 Shorea robusta Species 0.000 claims description 2
- 125000004122 cyclic group Chemical group 0.000 claims description 2
- 238000010908 decantation Methods 0.000 claims description 2
- 239000011295 pitch Substances 0.000 claims description 2
- 239000011347 resin Substances 0.000 claims description 2
- 229920005989 resin Polymers 0.000 claims description 2
- 239000011435 rock Substances 0.000 claims description 2
- 238000002169 hydrotherapy Methods 0.000 claims 1
- 239000010747 number 6 fuel oil Substances 0.000 abstract description 3
- 239000000446 fuel Substances 0.000 description 21
- 229910052751 metal Inorganic materials 0.000 description 19
- 239000002184 metal Substances 0.000 description 19
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 description 16
- 230000003197 catalytic effect Effects 0.000 description 16
- PNEYBMLMFCGWSK-UHFFFAOYSA-N aluminium oxide Inorganic materials [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 description 13
- 150000002431 hydrogen Chemical class 0.000 description 13
- 238000000746 purification Methods 0.000 description 13
- DLYUQMMRRRQYAE-UHFFFAOYSA-N tetraphosphorus decaoxide Chemical compound O1P(O2)(=O)OP3(=O)OP1(=O)OP2(=O)O3 DLYUQMMRRRQYAE-UHFFFAOYSA-N 0.000 description 12
- 239000000047 product Substances 0.000 description 11
- 150000002739 metals Chemical class 0.000 description 9
- 150000001875 compounds Chemical class 0.000 description 8
- 238000004064 recycling Methods 0.000 description 8
- 229910052759 nickel Inorganic materials 0.000 description 7
- 238000007670 refining Methods 0.000 description 7
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 6
- ZOKXTWBITQBERF-UHFFFAOYSA-N Molybdenum Chemical compound [Mo] ZOKXTWBITQBERF-UHFFFAOYSA-N 0.000 description 6
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 6
- JKWMSGQKBLHBQQ-UHFFFAOYSA-N diboron trioxide Chemical compound O=BOB=O JKWMSGQKBLHBQQ-UHFFFAOYSA-N 0.000 description 6
- 229910052750 molybdenum Inorganic materials 0.000 description 6
- 239000011733 molybdenum Substances 0.000 description 6
- 238000001816 cooling Methods 0.000 description 5
- 238000005336 cracking Methods 0.000 description 5
- CPLXHLVBOLITMK-UHFFFAOYSA-N Magnesium oxide Chemical compound [Mg]=O CPLXHLVBOLITMK-UHFFFAOYSA-N 0.000 description 4
- MCMNRKCIXSYSNV-UHFFFAOYSA-N Zirconium dioxide Chemical compound O=[Zr]=O MCMNRKCIXSYSNV-UHFFFAOYSA-N 0.000 description 4
- 230000032683 aging Effects 0.000 description 4
- 229910052799 carbon Inorganic materials 0.000 description 4
- 238000004517 catalytic hydrocracking Methods 0.000 description 4
- 238000004231 fluid catalytic cracking Methods 0.000 description 4
- 238000005984 hydrogenation reaction Methods 0.000 description 4
- 239000012535 impurity Substances 0.000 description 4
- 229910052500 inorganic mineral Inorganic materials 0.000 description 4
- 229910044991 metal oxide Inorganic materials 0.000 description 4
- 150000004706 metal oxides Chemical class 0.000 description 4
- 239000011707 mineral Substances 0.000 description 4
- 230000008929 regeneration Effects 0.000 description 4
- 238000011069 regeneration method Methods 0.000 description 4
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 3
- IMNFDUFMRHMDMM-UHFFFAOYSA-N N-Heptane Chemical compound CCCCCCC IMNFDUFMRHMDMM-UHFFFAOYSA-N 0.000 description 3
- YXFVVABEGXRONW-UHFFFAOYSA-N Toluene Chemical compound CC1=CC=CC=C1 YXFVVABEGXRONW-UHFFFAOYSA-N 0.000 description 3
- 230000003750 conditioning effect Effects 0.000 description 3
- 239000012084 conversion product Substances 0.000 description 3
- 238000005516 engineering process Methods 0.000 description 3
- 239000000945 filler Substances 0.000 description 3
- 239000007791 liquid phase Substances 0.000 description 3
- 229910052757 nitrogen Inorganic materials 0.000 description 3
- 230000008520 organization Effects 0.000 description 3
- 239000000377 silicon dioxide Substances 0.000 description 3
- 238000011144 upstream manufacturing Methods 0.000 description 3
- ZOXJGFHDIHLPTG-UHFFFAOYSA-N Boron Chemical compound [B] ZOXJGFHDIHLPTG-UHFFFAOYSA-N 0.000 description 2
- 241000196324 Embryophyta Species 0.000 description 2
- OAICVXFJPJFONN-UHFFFAOYSA-N Phosphorus Chemical compound [P] OAICVXFJPJFONN-UHFFFAOYSA-N 0.000 description 2
- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 2
- GWEVSGVZZGPLCZ-UHFFFAOYSA-N Titan oxide Chemical compound O=[Ti]=O GWEVSGVZZGPLCZ-UHFFFAOYSA-N 0.000 description 2
- 150000001412 amines Chemical class 0.000 description 2
- 229910052796 boron Inorganic materials 0.000 description 2
- 229910052810 boron oxide Inorganic materials 0.000 description 2
- 239000010941 cobalt Substances 0.000 description 2
- 229910017052 cobalt Inorganic materials 0.000 description 2
- GUTLYIVDDKVIGB-UHFFFAOYSA-N cobalt atom Chemical compound [Co] GUTLYIVDDKVIGB-UHFFFAOYSA-N 0.000 description 2
- 238000010438 heat treatment Methods 0.000 description 2
- 239000000395 magnesium oxide Substances 0.000 description 2
- 239000012528 membrane Substances 0.000 description 2
- 150000002736 metal compounds Chemical class 0.000 description 2
- 229910000476 molybdenum oxide Inorganic materials 0.000 description 2
- 229910000480 nickel oxide Inorganic materials 0.000 description 2
- PQQKPALAQIIWST-UHFFFAOYSA-N oxomolybdenum Chemical compound [Mo]=O PQQKPALAQIIWST-UHFFFAOYSA-N 0.000 description 2
- GNRSAWUEBMWBQH-UHFFFAOYSA-N oxonickel Chemical compound [Ni]=O GNRSAWUEBMWBQH-UHFFFAOYSA-N 0.000 description 2
- 229910052698 phosphorus Inorganic materials 0.000 description 2
- 239000011574 phosphorus Substances 0.000 description 2
- -1 silica-aluminas Chemical compound 0.000 description 2
- 150000003464 sulfur compounds Chemical class 0.000 description 2
- 238000005987 sulfurization reaction Methods 0.000 description 2
- OGIDPMRJRNCKJF-UHFFFAOYSA-N titanium oxide Inorganic materials [Ti]=O OGIDPMRJRNCKJF-UHFFFAOYSA-N 0.000 description 2
- 238000012546 transfer Methods 0.000 description 2
- 230000001131 transforming effect Effects 0.000 description 2
- WFKWXMTUELFFGS-UHFFFAOYSA-N tungsten Chemical compound [W] WFKWXMTUELFFGS-UHFFFAOYSA-N 0.000 description 2
- 229910052721 tungsten Inorganic materials 0.000 description 2
- 239000010937 tungsten Substances 0.000 description 2
- 239000012808 vapor phase Substances 0.000 description 2
- 238000005406 washing Methods 0.000 description 2
- CIWBSHSKHKDKBQ-JLAZNSOCSA-N Ascorbic acid Chemical compound OC[C@H](O)[C@H]1OC(=O)C(O)=C1O CIWBSHSKHKDKBQ-JLAZNSOCSA-N 0.000 description 1
- 239000002028 Biomass Substances 0.000 description 1
- UDHXJZHVNHGCEC-UHFFFAOYSA-N Chlorophacinone Chemical compound C1=CC(Cl)=CC=C1C(C=1C=CC=CC=1)C(=O)C1C(=O)C2=CC=CC=C2C1=O UDHXJZHVNHGCEC-UHFFFAOYSA-N 0.000 description 1
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 description 1
- 229910021536 Zeolite Inorganic materials 0.000 description 1
- 239000008186 active pharmaceutical agent Substances 0.000 description 1
- 230000029936 alkylation Effects 0.000 description 1
- 238000005804 alkylation reaction Methods 0.000 description 1
- 238000001833 catalytic reforming Methods 0.000 description 1
- 238000005119 centrifugation Methods 0.000 description 1
- 239000000919 ceramic Substances 0.000 description 1
- CETPSERCERDGAM-UHFFFAOYSA-N ceric oxide Chemical compound O=[Ce]=O CETPSERCERDGAM-UHFFFAOYSA-N 0.000 description 1
- 229910000422 cerium(IV) oxide Inorganic materials 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 239000003795 chemical substances by application Substances 0.000 description 1
- 239000003245 coal Substances 0.000 description 1
- 239000002283 diesel fuel Substances 0.000 description 1
- HNPSIPDUKPIQMN-UHFFFAOYSA-N dioxosilane;oxo(oxoalumanyloxy)alumane Chemical group O=[Si]=O.O=[Al]O[Al]=O HNPSIPDUKPIQMN-UHFFFAOYSA-N 0.000 description 1
- 238000007599 discharging Methods 0.000 description 1
- 238000009826 distribution Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000003203 everyday effect Effects 0.000 description 1
- 238000011066 ex-situ storage Methods 0.000 description 1
- 238000000605 extraction Methods 0.000 description 1
- 239000010419 fine particle Substances 0.000 description 1
- 238000009472 formulation Methods 0.000 description 1
- 239000002737 fuel gas Substances 0.000 description 1
- 239000007792 gaseous phase Substances 0.000 description 1
- 239000010763 heavy fuel oil Substances 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 230000010354 integration Effects 0.000 description 1
- 238000006317 isomerization reaction Methods 0.000 description 1
- 238000011068 loading method Methods 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 239000010758 marine gas oil Substances 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 238000001465 metallisation Methods 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- TVMXDCGIABBOFY-UHFFFAOYSA-N octane Chemical compound CCCCCCCC TVMXDCGIABBOFY-UHFFFAOYSA-N 0.000 description 1
- 150000002927 oxygen compounds Chemical class 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 239000008188 pellet Substances 0.000 description 1
- 239000012071 phase Substances 0.000 description 1
- 239000010909 process residue Substances 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 238000010926 purge Methods 0.000 description 1
- 238000000197 pyrolysis Methods 0.000 description 1
- 238000011002 quantification Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- 239000010865 sewage Substances 0.000 description 1
- 239000002002 slurry Substances 0.000 description 1
- 239000000779 smoke Substances 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 238000001179 sorption measurement Methods 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 238000004227 thermal cracking Methods 0.000 description 1
- 230000007704 transition Effects 0.000 description 1
- 229910052720 vanadium Inorganic materials 0.000 description 1
- LEONUFNNVUYDNQ-UHFFFAOYSA-N vanadium atom Chemical compound [V] LEONUFNNVUYDNQ-UHFFFAOYSA-N 0.000 description 1
- 239000010457 zeolite Substances 0.000 description 1
Classifications
-
- 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
- C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
- C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
-
- 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
- C10G47/02—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used
-
- 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
- C10G49/002—Apparatus for fixed bed hydrotreatment processes
-
- 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
- C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
- C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
- C10G65/04—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including only refining steps
-
- 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
- C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
- C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
- C10G65/12—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including cracking steps and other hydrotreatment steps
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L1/00—Liquid carbonaceous fuels
- C10L1/04—Liquid carbonaceous fuels essentially based on blends of hydrocarbons
- C10L1/08—Liquid carbonaceous fuels essentially based on blends of hydrocarbons for compression ignition
-
- 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
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 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 initial boiling point of at least 340 ° C and a final boiling temperature of at least 440 ° C., making it possible 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 stages: a) a step fixed-bed hydrotreatment process, in which the hydrocarbon feedstock and hydrogen are contacted on at least one hydro-treatment catalyst, b) a step of separating the effluent obtained at the end of the step (a) hydrotreating into at least a light fraction and at least one heavy fraction, c) a step of hydroconversion of at least a portion of the heavy fraction of the effluent from step (b) into at least one at least one reactor containing a catalyst supported in a bubbling bed, and d) a step of separating the effluent from step (c) to obtain at least a gaseous
- 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. .
- FIG. 1 represents an embodiment of the process according to the invention with intermediate separation of the effluent between the fixed bed section and the bubbling bed section, with decompression of the heavy fraction.
- Figure 2 shows in larger, for more legibility, the guard zones of the hydrotreating section of Figure 1.
- FIG. 3 represents another embodiment of the process according to the invention with intermediate separation of the effluent between the fixed-bed section and the bubbling-bed section, without decompression of the heavy fraction.
- the process according to the invention thus comprises a first step (a) of hydrotreating in a fixed bed, then a step (b) of separating the hydrocarbon effluent into a light fraction and a heavy fraction, followed by a step (c). ) bubbling bed hydroconversion of said heavy fraction, and finally a step (d) of separation.
- the objective of the hydro-treatment is both to refine, that is to say substantially reduce the content of metals, sulfur and other impurities, while improving the hydrogen-to-carbon ratio (H / C) and all by transforming the hydrocarbon feed more or less partially into lighter cuts.
- the effluent obtained in step (a) of hydrotreatment in fixed bed is then subjected to a separation step to obtain different fractions. This separation makes it possible to remove from the effluent obtained at the end of step (a) hydrotreating the lighter fractions that do not require additional treatment, or a moderate treatment, the heavier fractions.
- 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, in particular 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 comprises an intermediate separation step (b) between the hydrotreatment step (a) and the hydroconversion stage (c). This separation step advantageously makes it possible to minimize the fraction to be treated in the bubbling bed. In this way, the capacity of the boiling bed hydroconversion unit may be less important. Likewise, over-cracking of the light fractions is avoided and thus a loss of yield of fuel-type fractions is avoided.
- 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 temperature The final boiling point is at least 450 ° C, preferably at least 460 ° 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, deasphalted oils, deasphalting resins, asphalts or deasphalting pitches, process residues. conversion products, aromatic extracts from lubricant base production lines, oil sands or derivatives thereof, oil shales or their derivatives, source rock oils or their derivatives, whether alone or in combination.
- 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 may contain asphaltenes. Its asphaltenes content may be 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 filler 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 lighter hydrocarbon fraction mixture, which may preferably be chosen from the products resulting from a fluid catalytic cracking (FCC) process according to the English terminology. Saxon), a light cutting oil (LCO or "light cycle oil” according to the English terminology), a heavy cutting oil (HCO or "heavy cycle oil” according to the English terminology), a decanted oil, a FCC residue, a diesel fraction, in particular a fraction obtained by atmospheric or vacuum distillation, such as, for example, vacuum gas oil, or possibly from another refining process.
- FCC fluid catalytic cracking
- the co-charge may also advantageously be one or more cuts from the liquefaction process of 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. .
- Hydrotreatment commonly known as HDT, is understood to mean the catalytic treatments with hydrogen supply making it possible to refine, that is to say, to reduce substantially the content of metals, sulfur and other impurities, hydrocarbon feedstocks, while improving the ratio hydrogen on the load and transforming the load more or less partially into lighter cuts.
- Hydroprocessing includes hydrodesulfurization 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, hydrogenation, and hydrogenation reactions. hydrodearomatization, hydroisomerization, hydrodealkylation, hydrocracking, hydro-deasphalting and Conradson carbon reduction.
- the hydrotreatment step (a) comprises a hydrodemetallation first stage (a1) carried out in one or more hydrodemetallation zones in fixed beds and a second hydrodesulfurization second stage (a2) thereafter.
- (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, in hydrodemetallation conditions, and then during said second hydrodesulphurization step (a2), the effluent of the first hydrodemetallation step (a1) is brought into contact with a hydrodesulphurization catalyst, under hydrodesulfurization conditions.
- This process known as HYVAHL-F TM, is described, for example, in US Pat. No. 5,417,846.
- hydrodemetallization step hydrodemetallation reactions are carried out, but also a part of the other hydrotreatment reactions and in particular hydrodesulfurization reactions.
- hydrodesulphurization step hydrodesulphurization reactions are carried out but also part of the other hydro-treatment reactions and in particular hydrodemetallation reactions.
- the hydrodemetallization step begins where the hydrotreatment step begins, ie where the metal concentration is maximum.
- the hydrodesulphurization step ends where the hydro-treatment step ends, where sulfur removal is the most difficult.
- the skilled person sometimes defines a transition zone in which all types of hydrotreatment reaction occur.
- the hydrotreatment 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 quantity of hydrogen mixed with the feedstock may be between 100 and 5000 normal cubic meters (Nm 3 ) per cubic meter (m 3 ) of liquid feedstock, 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 hydrotreatment 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.
- 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.
- % 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.
- oxides selected from the group consisting of boron oxide, zirconia, ceria, titanium oxide, phosphoric anhydride and a mixture of these oxides.
- phosphorus pentoxide P2O5 When phosphorus pentoxide P2O5 is present, its concentration is less than 10% by weight.
- boron trioxide B 2 0 5 When boron trioxide B 2 0 5 is present, its concentration is less than 10% by weight.
- 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) group VIII is generally between 20 and 1, and usually between 10 and 2.
- specific catalysts suitable for each step are preferably used.
- Catalysts that can be used in the HDM step are for example indicated in patent documents EP 0113297, EP 0113284, US Pat. No. 5,222,656, US Pat. No. 5,827,421, US Pat. No. 7,110,445, US Pat. No. 5,622,616 and US Pat. No. 5,089,463.
- 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 "") a step, during which the guard zones are used together, the guard zone whose catalyst has been regenerated and / or replaced during the previous step being reconnected and said step being continued for a period at most equal to the time of deactivation and / or clogging of one of the guard zones.
- 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 reactors hydrotreating downstream 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 deactivation of the catalyst due to the large metal deposition that occurs during the 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. and 430 ° C., the temperature corresponding to the measured average temperature of the catalytic bed.
- the operating conditions of the reactive reactors are generally identical to those of the main hydrotreating reactors.
- the value of the space velocity VVH 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 system that operates at moderate pressure, preferably between 1 MPa and
- 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 obtained at the end of the fixed bed hydrotreatment step (a) undergoes at least one separation step, optionally supplemented by additional separation steps, which make it possible to separate at least one light fraction and at least one heavy fraction.
- light fraction is meant a fraction in which at least 90% of the compounds have a boiling point below 350 ° C.
- heavy fraction is meant a fraction in which at least 90% of the compounds have a boiling point greater than or equal to 350 ° C.
- the light fraction obtained during the separation step (b) comprises a gaseous phase and at least a light fraction of hydrocarbons of the naphtha, kerosene and / or diesel type.
- the heavy fraction preferably comprises a vacuum distillate fraction and a vacuum residue fraction and / or an atmospheric residue fraction.
- the step (b) of separation can be implemented by any method known to those skilled in the art. This method may be selected from high or low pressure separation, high or low pressure distillation, high or low pressure stripping, liquid / liquid extraction, solid / liquid separation, centrifugation, and combinations of these methods. operate at different pressures and temperatures.
- the effluent from step (a) hydrotreatment undergoes a step (b) separation with decompression.
- the separation is preferably carried out in a fractionation section which may firstly comprise a high temperature high pressure separator (HPHT), and possibly a low temperature high pressure separator (HPBT), followed optionally afterwards.
- HPHT high temperature high pressure separator
- HPBT low temperature high pressure separator
- an atmospheric distillation section and / or a vacuum distillation section The effluent of step (a) can be sent to a fractionation section, usually in an HPHT separator, having a point of cutting between 200 ° C and 400 ° C to obtain a light fraction and a heavy fraction.
- the separation is preferably not made according to a precise cutting point, it is rather like a flash type separation.
- said heavy fraction can then be fractionated by atmospheric distillation into at least one atmospheric distillate fraction, preferably containing at least a light fraction of naphtha, kerosene and / or diesel type hydrocarbons, and an atmospheric residue fraction.
- At least a part of the atmospheric residue fraction can also be fractionated by vacuum distillation into a vacuum distillate fraction, preferably containing vacuum gas oil, and a vacuum residue fraction.
- At least a portion of the vacuum residue fraction and / or the atmospheric residue fraction are advantageously sent to the hydroconversion step (c).
- Part of the vacuum residue may also be recycled in step (a) of hydrotreatment.
- the effluent from the hydrotreating step (a) undergoes a step (b) of separation without decompression.
- the effluent of the hydrotreatment stage (a) is sent to a fractionation section, generally in an HPHT separator, having a cutting point between 200 and 400.degree. minus a light fraction and at least one heavy fraction.
- the separation is preferably not made according to a precise cutting point, it is rather like a flash type separation.
- the heavy fraction can then be directly sent to the hydroconversion stage (c).
- the light fraction may undergo other separation steps.
- it may be subjected to atmospheric distillation to obtain a gaseous fraction, at least a light fraction of liquid hydrocarbons of the naphtha, kerosene and / or diesel type and a vacuum distillate fraction, the last fraction possibly being at least part sent at least partly in step (c) of hydroconversion.
- Another part of the vacuum distillate can be used as a fluxing agent for a fuel oil.
- Another part of the vacuum distillate can be upgraded by being subjected to a hydrocracking step and / or catalytic cracking in a fluidized bed. No-decompression separation provides better thermal integration and saves energy and equipment.
- this embodiment has technico-economic advantages since it is not necessary to increase the flow pressure after separation before the subsequent hydroconversion step. Intermediate fractionation without decompression being simpler than fractionation with decompression, the investment cost is therefore advantageously reduced.
- the gaseous fractions resulting from the separation step preferably undergo a purification treatment to recover the hydrogen and recycle it to the hydrotreating and / or hydroconversion reactors.
- the presence of the intermediate separation step, between the hydrotreatment step (a) and the hydroconversion step (c) advantageously makes it possible to have two independent hydrogen circuits, one connected to the hydro-treatment, the other to hydroconversion, and which, if necessary, can be connected to each other.
- the addition of hydrogen can be done at the hydrotreatment section or at the hydroconversion section or at both.
- the recycle hydrogen can feed the hydrotreatment section or the hydroconversion section or both.
- a compressor may possibly be common to both hydrogen circuits.
- the fact of being able to connect the two hydrogen circuits makes it possible to optimize the management of hydrogen and to limit the investments in terms of compressors and / or purification units of the gaseous effluents.
- the various embodiments of the hydrogen management that can be used in the present invention are described in the patent application FR 2957607.
- the light fraction obtained at the end of the separation step (b), which comprises hydrocarbon-type hydrocarbons. naphtha, kerosene and / or diesel or other, including LPG and vacuum gas oil, can be upgraded according to the methods are well known to those skilled in the art.
- the products obtained can be incorporated into fuel formulations (also called “pools" fuels according to the English terminology) or undergo additional refining steps.
- the fraction (s) naphtha, kerosene, gas oil and vacuum gas oil may be subjected to one or more treatments, for example hydrotreatment, hydrocracking, alkylation, isomerization, catalytic reforming, catalytic or thermal cracking, to bring them in a controlled manner. separated or in mixture with the required specifications which may relate to the sulfur content, the point of smoke, the octane number, cetane, and others.
- Step (c) bubbling bed hydroconversion
- a hydroconversion stage (c) which is carried out in at least one reactor containing a catalyst supported 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 bubbling bed hydroconversion section (c), mixed with the heavy fraction of the effluent from the step (b) of separation, without this part of the hydrocarbon feedstock being treated in the hydrotreatment section (a) in a fixed bed.
- 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 (c) in a bubbling bed with the heavy fraction of the effluent resulting from the separation step (b).
- 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 possibly derived from distillation, the gas oil fractions including those obtained by atmospheric or vacuum distillation, such as, for example, 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 can be injected at the inlet of the hydroconversion section (c) in a bubbling bed. It may be recycling hydrogen and / or make-up hydrogen. In the case where the hydroconversion section has several bubbling bed reactors, hydrogen can be injected at the inlet of each reactor.
- 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 (c) may be conventional bubbling bed hydroconversion conditions of a liquid hydrocarbon fraction. It can be operated 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.
- the space velocity (VVH) and the 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 a 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 may be employed.
- 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 metal oxide between metal (or metals) of group VI on metal (or metals) of group VIII is between 20 and 1, preferably between 10 and 2.
- the used catalyst can be partly replaced by fresh catalyst, generally by withdrawal at the bottom of the reactor and introduction at the top of the fresh or new catalyst reactor at 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 (c).
- This hydroconversion step (c) according to the process of the invention can be carried out under the conditions of the H-OIL® process as described, for example, in US Pat. No. 6,270,654.
- the ebullated 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 with regard to the flexibility of the operating conditions and 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 (cl ) can optionally be subjected to a separation step of the light fraction and the heavy fraction, and at least a part, preferably all, of said heavy fraction can be treated in the second hydroconversion sub-step (c2) .
- 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.
- Step (d) of separation of the hydroconversion effluent The process according to the invention further comprises a step (d) 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 (c) 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 (c) is advantageously separated in at least one separator flask into at least one gaseous fraction and at least one liquid fraction.
- These separators may for example be high temperature high pressure separators (HPHT) and / or high temperature low pressure separators (HPBT).
- this gaseous fraction is preferably treated in a hydrogen purification means so as to recover the hydrogen not consumed during the hydro-treatment and hydroconversion reactions.
- the hydrogen purification means may be an amine wash, a membrane, a PSA (pressure swing adsorption) system, or several 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 hydro-treatment step (a) and / or at different locations during the hydrotreatment stage (a) and / or at the inlet of the stage (c). hydroconversion and / or at different locations during step (c) of hydroconversion.
- the separation step (d) may also comprise atmospheric distillation and / or vacuum distillation.
- the separation step (d) further comprises at least one atmospheric distillation, in which the liquid hydrocarbon fraction (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.
- 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 (d) 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 (d) 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 (c).
- 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 (d) 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 step (c) hydroconversion, all divided by the amount of compounds having a point boiling above 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 are very diverse.
- the hydrocarbon effluent obtained at the end of the hydroconversion stage (c), and in particular the heavier liquid fraction obtained, may contain sediments and catalyst residues resulting from the fixed-bed stage and / or of 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 (d).
- the process according to the invention may therefore also comprise a step (e) for 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 (f), in which at least a part of the fraction vacuum distillate and / or of the fraction vacuum residue, possibly previously subject in the sediment and fines separation step (e), 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 (f) in which at least a part of the fraction vacuum distillate and / or of the fraction vacuum residue, possibly previously subject in the sediment and fines separation step (e) 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 (f) 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 for use in fluidized bed cracking in this step (f) are described, for example, in US Pat. Nos. 4,695,370, EP 0184517, US 4959334, EP 0323297, US 4965232, US 5120691, US 5344554, US 5449496, EP 0485259, US 5286690, US 5324696, EP 0542604 and EP 0699224.
- the 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 part of the residual fraction obtained at the end of the catalytic cracking step (f), often called "slurry" fraction by the person skilled in the art, can be recycled at the inlet of the step (f). ) of catalytic cracking and / or at the inlet of the hydrotreatment stage (a) and / or at the inlet of the hydroconversion stage (c).
- 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 (f) 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 oils of light cutting oils (LCO) of a catalytic cracking, heavy cutting oils (HCO) of a catalytic cracking, the residue of a catalytic cracking, kerosene, diesel fuel, vacuum distillate and / or decanted oil.
- LCO light cutting oils
- HCO 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 (d), possibly previously subjected to the step (e) 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 light fraction of kerosene or diesel type hydrocarbons obtained at the end of step (b) of separation, a part of the heavy hydrocarbon fraction. of the vacuum distillate type obtained at the end of the separation step (b), and a portion of the gasoline fraction, of the diesel fraction and / or of the residual fraction obtained at the end of the step (f) of cracking Catalytic.
- said fluxing base may be chosen from a part of the kerosene and / or diesel fraction obtained at the end of the ebullated bed hydroconversion stage.
- Step (e) separation of sediment 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, 2 and 3 An advantageous embodiment of the method according to the invention is shown in FIGS. 1, 2 and 3.
- FIG. 1 represents a process according to the invention with intermediate separation with decompression. For more legibility, the operation of the guard zones in the hydrotreatment section of FIG. 1 is described in FIG. 2.
- the charge (10), preheated in the enclosure (12), mixed with recycled hydrogen (14) and makeup hydrogen (24) preheated in the enclosure (16) are introduced via the conduit (18) into the guard zone system
- the operation of the guard zones in the hydrotreatment section comprising two guard zones (or permutable reactors) Ra and Rb comprises a series of cycles each comprising four successive stages:
- step i a first step (step i) during which the charge passes successively through the reactor Ra and then the reactor Rb, a second step (step ii) during which the feed passes only through the reactor Rb, the reactor Ra being short-circuited for regeneration and / or replacement of the catalyst,
- step iii a third step (step iii) during which the charge passes successively through the reactor Rb and 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.
- 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 through the lines (24) and (25) comprising an open valve V6 and the pipe (26) to the main hydrotreatment 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.
- 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 step is sent via line (42) into a high temperature high pressure separator (HPHT) (44) from which a gaseous fraction (46) and a liquid fraction (48) are recovered. ).
- the cutting point is usually between 200 and 400 ° C.
- the gaseous fraction (46) is sent, generally via an exchanger (not shown) or an air cooler (50) for cooling to a low temperature high pressure separator (HPBT) (52) from which a gaseous fraction (54) containing the gases (H 2 , H 2 S, NH 3 , C 1 -C 4 hydrocarbons, etc.) and a liquid fraction (56).
- the gaseous fraction (54) from the low temperature high pressure separator (HPBT) (52) is treated in the hydrogen purification unit (58) from which the hydrogen (60) is recovered for recycling via the compressor (62) and the line (65) to the reactors (30) and / or (36) or via the line (14) to the reactive reactors. Gases containing undesirable nitrogen and sulfur compounds are removed from the plant (stream (66)).
- the liquid fraction (56) from the low temperature high pressure separator (HPBT) (52) is expanded in the device (68) and sent to the fractionation system (70).
- a medium pressure separator (not shown) after the expander (68) can be installed to recover a gaseous fraction which is sent to the purification unit (58) and a liquid phase which is fed to the fractionation section (70).
- the liquid fraction (48) from the high temperature high pressure separator (HPHT) (44) is expanded in the device (72) and sent to the fractionation system (70).
- Fractions (56) and (48) may be sent together, after expansion, to the system (70).
- the fractionations (70) and (172) may be common and treated all the light fractions including that coming from the inter-stage separator (108).
- the fractionation system (70) comprises an atmospheric distillation system for producing a gaseous effluent (74), at least a so-called light fraction (76) and in particular containing naphtha, kerosene and diesel and an atmospheric residue fraction (78) .
- Part of the atmospheric residue fraction can be sent via the line (80) into the hydroconversion reactors. All or part of the atmospheric residue fraction (78) is sent to a vacuum distillation column (82) to recover a fraction (84) containing the vacuum residue and a vacuum distillate fraction (86) containing vacuum gas oil.
- the vacuum residue fraction (84), optionally mixed with a portion of the atmospheric residue fraction (80) and / or with a portion of the vacuum distillate fraction (86), is mixed with optionally recycled hydrogen (88). supplemented with makeup hydrogen (90) preheated in the furnace (91). It optionally passes through an oven (92).
- a co-charge (94) may be introduced.
- the heavy fraction is then introduced via the line (96) into the hydroconversion step at the bottom of the first bubbling bed reactor (98) operating at an 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).
- effluent converted (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 which a gaseous fraction (146) containing the gaseous fraction (146) is recovered.
- 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 after the expander (160) can be installed to recover a vapor phase that is sent to the unit.
- 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 a portion of the vacuum residue fraction 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.
- FIG. 3 represents another method according to the invention with intermediate separation without decompression. Essentially, only the differences between the process according to FIG. 3 and the process according to FIG. 1, the hydrotreating steps, will be described below. hydroconversion and separation after hydroconversion (and their references) being otherwise strictly identical.
- the effluent treated in the hydrotreating reactors is sent via line (42) into a high temperature high pressure separator (HPHT) (44) from which a lighter fraction (46) and a residual fraction (48) are recovered. .
- HPHT high temperature high pressure separator
- the cutting point is usually between 200 and 400 ° C.
- the residual fraction (48) is sent directly after a possible passage in an oven (92) in the hydroconversion section.
- the lighter fraction (46) is sent, generally via an exchanger (not shown) or an air cooler (50) for cooling to a low temperature high pressure separator (HPBT) (52) from which a gaseous fraction is recovered (54). containing the gases (H 2 , H 2 S, NH 3 , hydrocarbons dC 4 ...) and a liquid fraction (56).
- HPBT high pressure separator
- the gaseous fraction (54) of the low temperature high pressure separator (HPBT) (52) is treated in the hydrogen purification unit (58) from which hydrogen (60) is recovered for recycling via the compressor. (154) and lines (64) and (156) to the hydrotreatment section and / or the hydroconversion section. Gases containing undesirable nitrogen, sulfur and oxygen compounds are removed from the plant (stream (66)). In this configuration, a single compressor (154) is used to supply all the reactors requiring hydrogen.
- the liquid fraction (56) from the low temperature high pressure separator (HPBT) (52) is expanded in the device (68) and sent to the fractionation system (70).
- the fractionation system (70) comprises an atmospheric distillation system for producing a gaseous effluent (74), at least a so-called light fraction (76) and containing in particular naphtha, kerosene and diesel and an atmospheric residue fraction (195).
- a part of the atmospheric residue fraction can be sent via the line (195) into the hydroconversion reactors while another part of the atmospheric residue fraction (194) can be sent to another process (hydrocracking or FCC or hydrotreatment) .
- the feed contains 254 ppm of metals (Ni + V).
- the feedstock was subjected to a hydrotreatment step including two permutable reactors.
- the distribution of HDM / HDS catalyst loading is 63/27.
- the operating conditions are given in Table 1.
- the performance in HDM hydrodemetallation in the fixed bed HDT section is greater than 80%.
- the hydrotreatment effluent was then flashed at high pressure and high temperature flash (HPHT).
- the heavy fraction (350 ° C. fraction) was sent to a hydroconversion stage comprising two successive bubbling bed reactors.
- the operating conditions are given in Table 2.
- the hydrogen consumed represents 1.69% by weight of the fresh feed introduced at the inlet of the hydrotreatment section.
- This particularly high conversion rate illustrates the production of conversion products (mainly distillates) in a significant amount.
- a second mixture consisting of 80% by weight of a fraction from the diesel cut and 20% by weight of a fraction was made. from the vacuum distillate cut. In these proportions, 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 gas oil” or “diesel marine” in the English terminology) which can be likened to the DMB grade (whose viscosity specification is between 2 cSt and 11 cSt at 40 ° 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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Abstract
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RU2015129080A RU2660426C2 (en) | 2012-12-20 | 2013-12-18 | Method of separate treatment of petroleum feedstock for production of fuel oil with low sulphur content |
CA2894610A CA2894610A1 (en) | 2012-12-20 | 2013-12-18 | Process with separation for treating petroleum feedstocks for the production of fuel oils with a low sulphur content |
KR1020157019490A KR102289270B1 (en) | 2012-12-20 | 2013-12-18 | Process with separation for treating petroleum feedstocks for the production of fuel oils with a low sulphur content |
SG11201504854XA SG11201504854XA (en) | 2012-12-20 | 2013-12-18 | Process with separation for treating petroleum feedstocks for the production of fuel oils with a low sulphur content |
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SG11201504854XA (en) | 2015-07-30 |
KR20150096778A (en) | 2015-08-25 |
TWI617661B (en) | 2018-03-11 |
RU2660426C2 (en) | 2018-07-06 |
KR102289270B1 (en) | 2021-08-11 |
CA2894610A1 (en) | 2014-06-26 |
SG10201703360XA (en) | 2017-06-29 |
RU2015129080A (en) | 2017-01-26 |
FR3000098A1 (en) | 2014-06-27 |
FR3000098B1 (en) | 2014-12-26 |
TW201432042A (en) | 2014-08-16 |
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