US20200109337A1 - Process and apparatus for treating mercaptans in a naphtha boiling range feed - Google Patents
Process and apparatus for treating mercaptans in a naphtha boiling range feed Download PDFInfo
- Publication number
- US20200109337A1 US20200109337A1 US16/545,001 US201916545001A US2020109337A1 US 20200109337 A1 US20200109337 A1 US 20200109337A1 US 201916545001 A US201916545001 A US 201916545001A US 2020109337 A1 US2020109337 A1 US 2020109337A1
- Authority
- US
- United States
- Prior art keywords
- naphtha
- stream
- mercaptan
- compounds
- boiling range
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 238000000034 method Methods 0.000 title claims abstract description 40
- 238000009835 boiling Methods 0.000 title claims abstract description 33
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical class S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 title abstract description 24
- LSDPWZHWYPCBBB-UHFFFAOYSA-N Methanethiol Chemical class SC LSDPWZHWYPCBBB-UHFFFAOYSA-N 0.000 claims abstract description 49
- 150000002019 disulfides Chemical class 0.000 claims abstract description 38
- 230000001590 oxidative effect Effects 0.000 claims abstract description 8
- 239000003054 catalyst Substances 0.000 claims description 28
- 230000003647 oxidation Effects 0.000 claims description 27
- 238000007254 oxidation reaction Methods 0.000 claims description 27
- 239000010949 copper Substances 0.000 claims description 17
- 229910052751 metal Inorganic materials 0.000 claims description 17
- 239000002184 metal Substances 0.000 claims description 17
- RYGMFSIKBFXOCR-UHFFFAOYSA-N Copper Chemical compound [Cu] RYGMFSIKBFXOCR-UHFFFAOYSA-N 0.000 claims description 16
- 229910052802 copper Inorganic materials 0.000 claims description 16
- 238000004821 distillation Methods 0.000 claims description 11
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 claims description 10
- 229910052760 oxygen Inorganic materials 0.000 claims description 10
- 239000001301 oxygen Substances 0.000 claims description 10
- 238000004891 communication Methods 0.000 claims description 9
- PNEYBMLMFCGWSK-UHFFFAOYSA-N aluminium oxide Inorganic materials [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 claims description 7
- 239000003518 caustics Substances 0.000 claims description 7
- 229910052809 inorganic oxide Inorganic materials 0.000 claims description 7
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 claims description 6
- 239000003498 natural gas condensate Substances 0.000 claims description 6
- GWEVSGVZZGPLCZ-UHFFFAOYSA-N Titan oxide Chemical compound O=[Ti]=O GWEVSGVZZGPLCZ-UHFFFAOYSA-N 0.000 claims description 5
- MCMNRKCIXSYSNV-UHFFFAOYSA-N Zirconium dioxide Chemical compound O=[Zr]=O MCMNRKCIXSYSNV-UHFFFAOYSA-N 0.000 claims description 5
- 239000010779 crude oil Substances 0.000 claims description 5
- 239000007788 liquid Substances 0.000 claims description 5
- CPLXHLVBOLITMK-UHFFFAOYSA-N Magnesium oxide Chemical compound [Mg]=O CPLXHLVBOLITMK-UHFFFAOYSA-N 0.000 claims description 4
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 4
- -1 boria Chemical compound 0.000 claims description 4
- 230000000717 retained effect Effects 0.000 claims description 4
- XOLBLPGZBRYERU-UHFFFAOYSA-N tin dioxide Chemical compound O=[Sn]=O XOLBLPGZBRYERU-UHFFFAOYSA-N 0.000 claims description 4
- VYZAMTAEIAYCRO-UHFFFAOYSA-N Chromium Chemical compound [Cr] VYZAMTAEIAYCRO-UHFFFAOYSA-N 0.000 claims description 3
- HCHKCACWOHOZIP-UHFFFAOYSA-N Zinc Chemical compound [Zn] HCHKCACWOHOZIP-UHFFFAOYSA-N 0.000 claims description 3
- 229910052804 chromium Inorganic materials 0.000 claims description 3
- 239000011651 chromium Substances 0.000 claims description 3
- 239000010941 cobalt Substances 0.000 claims description 3
- 229910017052 cobalt Inorganic materials 0.000 claims description 3
- GUTLYIVDDKVIGB-UHFFFAOYSA-N cobalt atom Chemical compound [Co] GUTLYIVDDKVIGB-UHFFFAOYSA-N 0.000 claims description 3
- WPBNNNQJVZRUHP-UHFFFAOYSA-L manganese(2+);methyl n-[[2-(methoxycarbonylcarbamothioylamino)phenyl]carbamothioyl]carbamate;n-[2-(sulfidocarbothioylamino)ethyl]carbamodithioate Chemical compound [Mn+2].[S-]C(=S)NCCNC([S-])=S.COC(=O)NC(=S)NC1=CC=CC=C1NC(=S)NC(=O)OC WPBNNNQJVZRUHP-UHFFFAOYSA-L 0.000 claims description 3
- 229910052759 nickel Inorganic materials 0.000 claims description 3
- 238000011144 upstream manufacturing Methods 0.000 claims description 3
- 229910052720 vanadium Inorganic materials 0.000 claims description 3
- GPPXJZIENCGNKB-UHFFFAOYSA-N vanadium Chemical compound [V]#[V] GPPXJZIENCGNKB-UHFFFAOYSA-N 0.000 claims description 3
- 229910052725 zinc Inorganic materials 0.000 claims description 3
- 239000011701 zinc Substances 0.000 claims description 3
- OMZSGWSJDCOLKM-UHFFFAOYSA-N copper(II) sulfide Chemical compound [S-2].[Cu+2] OMZSGWSJDCOLKM-UHFFFAOYSA-N 0.000 claims description 2
- QDOXWKRWXJOMAK-UHFFFAOYSA-N dichromium trioxide Chemical compound O=[Cr]O[Cr]=O QDOXWKRWXJOMAK-UHFFFAOYSA-N 0.000 claims description 2
- 239000000395 magnesium oxide Substances 0.000 claims description 2
- 239000000377 silicon dioxide Substances 0.000 claims description 2
- 239000002904 solvent Substances 0.000 claims description 2
- ZCUFMDLYAMJYST-UHFFFAOYSA-N thorium dioxide Chemical compound O=[Th]=O ZCUFMDLYAMJYST-UHFFFAOYSA-N 0.000 claims description 2
- QPLDLSVMHZLSFG-UHFFFAOYSA-N Copper oxide Chemical compound [Cu]=O QPLDLSVMHZLSFG-UHFFFAOYSA-N 0.000 claims 1
- 239000005751 Copper oxide Substances 0.000 claims 1
- 229910000431 copper oxide Inorganic materials 0.000 claims 1
- 150000002430 hydrocarbons Chemical class 0.000 abstract description 36
- 229930195733 hydrocarbon Natural products 0.000 abstract description 34
- 150000008427 organic disulfides Chemical class 0.000 abstract description 3
- 229910000037 hydrogen sulfide Inorganic materials 0.000 abstract description 2
- 229910052717 sulfur Inorganic materials 0.000 description 23
- 239000011593 sulfur Substances 0.000 description 22
- 239000004215 Carbon black (E152) Substances 0.000 description 21
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 21
- 239000000463 material Substances 0.000 description 7
- QGJOPFRUJISHPQ-UHFFFAOYSA-N Carbon disulfide Chemical compound S=C=S QGJOPFRUJISHPQ-UHFFFAOYSA-N 0.000 description 5
- 150000001875 compounds Chemical class 0.000 description 5
- 239000000446 fuel Substances 0.000 description 5
- 239000003208 petroleum Substances 0.000 description 5
- 239000011230 binding agent Substances 0.000 description 4
- 238000006243 chemical reaction Methods 0.000 description 4
- 238000005260 corrosion Methods 0.000 description 4
- 230000007797 corrosion Effects 0.000 description 4
- 239000003502 gasoline Substances 0.000 description 4
- 239000002245 particle Substances 0.000 description 4
- KWYUFKZDYYNOTN-UHFFFAOYSA-M Potassium hydroxide Chemical compound [OH-].[K+] KWYUFKZDYYNOTN-UHFFFAOYSA-M 0.000 description 3
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 3
- 125000004432 carbon atom Chemical group C* 0.000 description 3
- 239000007789 gas Substances 0.000 description 3
- 238000001765 gas chromatography-flame photometric detection Methods 0.000 description 3
- 239000002243 precursor Substances 0.000 description 3
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 2
- BWGNESOTFCXPMA-UHFFFAOYSA-N Dihydrogen disulfide Chemical compound SS BWGNESOTFCXPMA-UHFFFAOYSA-N 0.000 description 2
- BQCADISMDOOEFD-UHFFFAOYSA-N Silver Chemical compound [Ag] BQCADISMDOOEFD-UHFFFAOYSA-N 0.000 description 2
- 150000001336 alkenes Chemical class 0.000 description 2
- 125000000217 alkyl group Chemical group 0.000 description 2
- 238000004458 analytical method Methods 0.000 description 2
- 125000003118 aryl group Chemical group 0.000 description 2
- 239000002131 composite material Substances 0.000 description 2
- 230000007613 environmental effect Effects 0.000 description 2
- FAHBNUUHRFUEAI-UHFFFAOYSA-M hydroxidooxidoaluminium Chemical compound O[Al]=O FAHBNUUHRFUEAI-UHFFFAOYSA-M 0.000 description 2
- 238000002156 mixing Methods 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 229920006395 saturated elastomer Polymers 0.000 description 2
- 229910052709 silver Inorganic materials 0.000 description 2
- 239000004332 silver Substances 0.000 description 2
- 244000025254 Cannabis sativa Species 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 description 1
- 239000008186 active pharmaceutical agent Substances 0.000 description 1
- 239000000654 additive Substances 0.000 description 1
- 239000003463 adsorbent Substances 0.000 description 1
- 150000008044 alkali metal hydroxides Chemical class 0.000 description 1
- ILRRQNADMUWWFW-UHFFFAOYSA-K aluminium phosphate Chemical compound O1[Al]2OP1(=O)O2 ILRRQNADMUWWFW-UHFFFAOYSA-K 0.000 description 1
- VXAUWWUXCIMFIM-UHFFFAOYSA-M aluminum;oxygen(2-);hydroxide Chemical compound [OH-].[O-2].[Al+3] VXAUWWUXCIMFIM-UHFFFAOYSA-M 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 229910001680 bayerite Inorganic materials 0.000 description 1
- 229910001593 boehmite Inorganic materials 0.000 description 1
- 238000001354 calcination Methods 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 229910002092 carbon dioxide Inorganic materials 0.000 description 1
- 239000001569 carbon dioxide Substances 0.000 description 1
- 239000012876 carrier material Substances 0.000 description 1
- 238000000975 co-precipitation Methods 0.000 description 1
- 238000002485 combustion reaction Methods 0.000 description 1
- 238000010960 commercial process Methods 0.000 description 1
- 125000004122 cyclic group Chemical group 0.000 description 1
- 238000012217 deletion Methods 0.000 description 1
- 230000037430 deletion Effects 0.000 description 1
- 238000010586 diagram Methods 0.000 description 1
- 238000009826 distribution Methods 0.000 description 1
- 238000011143 downstream manufacturing Methods 0.000 description 1
- 230000009977 dual effect Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000004231 fluid catalytic cracking Methods 0.000 description 1
- 238000005194 fractionation Methods 0.000 description 1
- 238000004817 gas chromatography Methods 0.000 description 1
- 239000000499 gel Substances 0.000 description 1
- 230000014509 gene expression Effects 0.000 description 1
- 229910001679 gibbsite Inorganic materials 0.000 description 1
- 239000008187 granular material Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 150000004820 halides Chemical class 0.000 description 1
- 150000004679 hydroxides Chemical class 0.000 description 1
- 238000005470 impregnation Methods 0.000 description 1
- 239000004615 ingredient Substances 0.000 description 1
- 238000005342 ion exchange Methods 0.000 description 1
- 238000006317 isomerization reaction Methods 0.000 description 1
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 description 1
- 229910052753 mercury Inorganic materials 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 239000008188 pellet Substances 0.000 description 1
- 230000000704 physical effect Effects 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
- 239000000376 reactant Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 238000007670 refining Methods 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 239000002594 sorbent Substances 0.000 description 1
- 241000894007 species Species 0.000 description 1
- 238000004230 steam cracking Methods 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 150000003463 sulfur Chemical class 0.000 description 1
- 238000012360 testing method Methods 0.000 description 1
- 230000007704 transition Effects 0.000 description 1
- 238000005406 washing Methods 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 1
- 229910001868 water Inorganic materials 0.000 description 1
Images
Classifications
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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
- C10G35/00—Reforming naphtha
- C10G35/04—Catalytic reforming
- C10G35/06—Catalytic reforming 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
- C10G53/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes
- C10G53/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only
- C10G53/14—Treatment of hydrocarbon oils, in the absence of hydrogen, by two or more refining processes plural serial stages only including at least one oxidation step
-
- 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
- C10G7/00—Distillation of hydrocarbon oils
-
- 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
- C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
- C10G11/02—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils 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
- C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
- C10G27/04—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with oxygen or compounds generating oxygen
-
- 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
- C10G2300/1025—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
- C10G2300/1037—Hydrocarbon fractions
- C10G2300/104—Light gasoline having a boiling range of about 20 - 100 °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
- C10G2300/1037—Hydrocarbon fractions
- C10G2300/1044—Heavy gasoline or naphtha having a boiling range of about 100 - 180 °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
- C10G2300/20—Characteristics of the feedstock or the products
- C10G2300/201—Impurities
- C10G2300/202—Heteroatoms content, i.e. S, N, O, P
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
- C10G2300/40—Characteristics of the process deviating from typical ways of processing
- C10G2300/4018—Spatial velocity, e.g. LHSV, WHSV
Definitions
- the present disclosure generally relates to processes and apparatuses for treating petroleum fractions. More particularly, the field relates to an improved process and apparatus for removing mercaptan compounds from petroleum fractions such as naphtha.
- Hydroprocessing such as hydrotreating
- hydrotreating can be effective for reducing the sulfur content of a naphtha boiling range fraction to a desired sulfur level.
- the existing hydrotreating assets do not have sufficient available hydraulic capacity to process the petrochemical naphtha stream and building a grass roots hydrotreater for this purpose is a very expensive option.
- Sweetening of petroleum fractions such as naphtha boiling range hydrocarbons or other liquid hydrocarbons, that contain mercaptans (or sour petroleum fractions) are well-developed commercial processes commonly used in many petroleum refineries.
- mercaptans contained in the feed hydrocarbon stream e.g., sour hydrocarbon stream
- disulfide compounds that remain in the hydrocarbon stream (e.g., sweetened hydrocarbon stream).
- sweetening processes therefore, do not remove sulfur from the hydrocarbon stream but rather convert the sulfur to an acceptable form.
- the sweetening process involves an admixture of an oxygen-containing stream to the sour hydrocarbon stream to supply the required oxygen.
- the admixture of hydrocarbons and oxygen contacts an oxidation catalyst in an aqueous alkaline environment to oxidize the mercaptans.
- a caustic e.g., an aqueous caustic solution
- the sour hydrocarbon stream to create the aqueous alkaline environment.
- at least a portion of the caustic is carried with the sweetened hydrocarbon stream and can be problematic for further downstream processing.
- Current approaches for removing caustic from sweetened hydrocarbon streams often require additional downstream equipment and can be costly and/or are relatively inefficient.
- a process for treating a naphtha boiling range stream containing mercaptan compounds comprising: (a) oxidizing mercaptan compounds in the naphtha boiling range stream to provide a mercaptan-depleted naphtha stream rich in disulfide compounds; (b) passing the mercaptan-depleted naphtha stream rich in disulfide compounds to a naphtha splitter column; and (c) fractionating at least a portion of the mercaptan-depleted naphtha stream rich in disulfide compounds into at least two streams, a light naphtha stream lean in disulfide compounds and a heavy naphtha stream rich in disulfide compounds.
- an apparatus for treating a naphtha boiling range stream containing mercaptan compounds comprising: (a) an oxidation unit to provide a mercaptan-depleted naphtha stream rich in disulfide compounds; and (b) a naphtha splitter column in downstream communication with the oxidation unit to provide a light naphtha stream lean in disulfide compounds in a naphtha splitter overhead line and a heavy naphtha stream rich in disulfide compounds in a naphtha splitter bottoms line.
- FIG. 1 s a process flow diagram illustrating an exemplary process and apparatus of the present disclosure.
- naphtha or “naphtha boiling range” refers to hydrocarbons boiling in a range of about 25° C. to 190° C. atmospheric equivalent boiling point (AEBP), as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, and can include one or more C 5 -C 10 hydrocarbons.
- AEBP atmospheric equivalent boiling point
- light naphtha refers to hydrocarbons boiling in a range of about 25° C. to 85° C., and can include one or more C 5 -C 6 hydrocarbons.
- heavy naphtha refers to hydrocarbons boiling in the range of about 85° C. to 190° C. (e.g., 110° C. to 170° C.), and can include one or more C 6 -C 10 hydrocarbons.
- straight-run naphtha and its acronym “SRN” which accordingly refers to “naphtha” defined above that is derived directly from the atmospheric distillation unit, optionally subjected to steam stripping, as is well known.
- Straight-run naphtha may also be derived from natural gas condensates.
- the term “rich” refers to a stream exiting a vessel that has a concentration of one or more compounds exceeding a stream entering the vessel.
- lean refers to a stream exiting a vessel that has a concentration of one or more compounds less than a stream entering the vessel.
- depleted is synonymous with reduced from originally present. For example, removing a substantial portion of a material from a stream would produce a material-depleted stream that is substantially depleted of that material.
- mercaptan means thiol compounds of the formula R—SH where R is a hydrocarbon group, such as an alkyl or aryl group, that is saturated or unsaturated and optionally substituted,
- diisulfide means compounds having the molecular formula R—S—S—R′ where R and R′ are each, independently, a hydrocarbon group, such as an alkyl or aryl group, that is saturated or unsaturated and optionally substituted.
- R and R′ are each, independently, a hydrocarbon group, such as an alkyl or aryl group, that is saturated or unsaturated and optionally substituted.
- CS 2 carbon disulfide
- C x means hydrocarbon molecules that have “x” number of carbon atoms
- C x means hydrocarbon molecules that have “x” and/or more than “x” number of carbon atoms
- C x- means hydrocarbon molecules that have “x” and/or less than “x” number of carbon atoms.
- communication means that material flow is operatively permitted between enumerated components.
- downstream communication means that at least a portion of material flowing to the subject in downstream communication may operatively flow from the object with which it communicates.
- upstream communication means that at least a portion of the material flowing from the subject in upstream communication may operatively flow to the object with which it communicates.
- process flow lines in the FIGURE can be referred to interchangeably as, for example, lines, pipes, feeds, gases, products, discharges, parts, portions, conduits or streams.
- FIGURE has been simplified by the deletion of a large number of apparatuses customarily employed in a process of this nature, such as vessel internals, temperature and pressure control systems, flow control valves, recycle pumps, etcetera which are not specifically required to illustrate the performance of the invention.
- a feed 2 that is a crude oil or a natural gas condensate stream containing a range of hydrocarbons is passed to a distillation unit 10 where the feed is separated into a light stream 3 , a naphtha boiling range stream 5 , and/or one or more heavier or bottoms fractions.
- the distillation unit 10 may be an atmospheric distillation unit.
- the distillation unit 10 may be a natural gas condensate splitter.
- the feed in line 2 may be dried and/or pre-treated to reduce and/or remove one or more of undesired components such as carbon dioxide, mercury, and water prior to fractionation.
- Naphtha boiling range streams typically contain one or more mercaptan compounds.
- the mercaptans occurring in naphtha boiling range streams are generally C 1 -C 10 mercaptans (e.g., C 1 -C 6 mercaptans).
- the mercaptans are generally concentrated in the light fractions of the naphtha and more precisely in the fraction with a boiling point of less than 120° C.
- the mercaptan sulfur may be present in the naphtha boiling range stream in an amount ranging from about 2 ppm to 300 wppm or more, depending on the particular stream to be treated.
- the mercaptan-containing naphtha boiling range stream 5 is passed to an oxidation unit 20 where mercaptan compounds in the naphtha stream are converted to disulfide compounds.
- the flow direction in oxidation unit 20 can be down flow or up flow.
- the naphtha stream 5 is mixed with an air or other oxygen-containing gas stream 7 supplied at a rate that supplies at least the stoichiometric amount of oxygen necessary to oxidize the mercaptan compounds in the naphtha boiling range stream 5 to disulfide compounds.
- the mole ratio of oxygen to mercaptan sulfur may range from about 1:4 to 10:1 (e.g., about 1:1 to 10:1, or about 1:1 to 3:1).
- the oxidation of the mercaptan compounds is promoted through the presence of a catalytically effective amount of an oxidation catalyst capable of functioning at the conditions found in the oxidation unit 20 .
- the oxidation unit 20 may be configured in a packed bed configuration to ensure adequate mixing between the naphtha boiling range feed, the catalyst, and the oxygen.
- the oxidation unit 20 may comprise a cylindrical fixed bed of catalyst through which the reactants move in a vertical direction.
- the oxidation conditions utilized in oxidation unit 20 may include a pressure of from about 101 to 2068 kPa (gauge) (15 to 300 psig), such as from 172 to 689 kPa (gauge) (25 to 100 psig); a temperature of from 35° C. to 200° C. (e.g. 50° C. to 150° C.); and a liquid hourly space velocity of from 1 to 10 h ⁇ 1 (e.g., 1 to 5 h ⁇ 1 ).
- mercaptan compounds are depleted in the naphtha boiling range stream in the substantial absence of any caustic solvent, such as an aqueous solution of alkali metal hydroxide (e.g., sodium hydroxide, potassium hydroxide).
- alkali metal hydroxide e.g., sodium hydroxide, potassium hydroxide
- Suitable oxidation catalysts are any known conventional catalysts for oxidizing mercaptans to disulfides and can include those which are comprised of a Group 5-12 metal component (e.g., one or more of vanadium, chromium, manganese, cobalt, nickel, copper, zinc) retained on a refractory inorganic oxide support.
- a Group 5-12 metal component e.g., one or more of vanadium, chromium, manganese, cobalt, nickel, copper, zinc
- the inorganic oxide binder of the catalyst may comprise materials such as alumina, silica, zirconia, titania, thoria, boria, magnesia, chromia, stannic oxide, and the like as well as combinations and composites thereof, for example silica-alumina, alumina-zirconia, alumina-titania, aluminum phosphate, and the like.
- Alumina is a preferred refractory inorganic oxide binder.
- a precursor of the desired refractory inorganic oxide may be used to form, bind, and/or otherwise prepare the catalyst.
- Such binder precursors or sources may be converted into a refractory inorganic oxide binder, for example, by calcination.
- the alumina may be any of the various aluminum oxides, hydroxides, and gels, including boehmite, pseudo-boehmite, gibbsite, bayerite, and the like, especially transition and gamma aluminas. Suitable aluminas are commercially available, for example, under the trade names CATAPAL ⁇ B and VERSALTM 250.
- the metal component of the catalyst may comprise a metal selected from the group consisting of vanadium, chromium, manganese, cobalt, nickel, copper, zinc, and combinations thereof. In one embodiment, the metal component comprises copper.
- the metal content of the catalyst can range from 10 to 40 wt. % (e.g., 15 to 30 wt. %) as the metal based upon the total weight of the catalyst.
- the metal component may be incorporated into the catalyst in any suitable manner such as co-mulling, co-precipitation or co-gellation with the carrier material, ion exchange, or impregnation.
- the metal component may exist within the final catalyst as a compound such as an oxide, sulfide, halide, or oxyhalide, in chemical combination with one or more of the other ingredients of the composite, or as an elemental metal.
- the metal component is copper
- the metal component may be present as copper metal, copper, oxide, copper sulfide, or a combination thereof.
- the catalyst is most preferably used in particulate form, for example as pellets, extrudate, spheres or granules, although other solid forms also are suitable.
- Particle size of the catalyst is selected such that a bed of catalyst particles is easily maintained in a suitable reactor for the oxidation process but permits flow of the naphtha boiling range through the bed without undesirable pressure drop.
- Preferred average particle sizes are such that catalyst particles pass through a 2-mesh screen but are retained on a 24-mesh screen (U.S. Sieve Series) and more preferably pass through a 4-mesh screen but are retained on a 12-mesh screen.
- the oxidation catalyst may have a BET surface area in a range of 30 to 300 m 2 /g (e.g., 50 to 200 m 2 /g).
- the oxidation catalyst may be a fresh or spent sulfur sorbent having application in eliminating residual sulfur from conventionally desulfurized reformer or isomerization feed streams, such as described in U.S. Pat. No. 4,259,213.
- the effluent from oxidation unit 20 comprises a mercaptan-depleted naphtha stream rich in disulfide compounds.
- Organic disulfides have higher boiling points than those of their mercaptan precursors.
- mercaptans that typically boil in a light naphtha fraction are converted in the oxidation unit 20 into disulfides that typically boil in a heavy naphtha fraction.
- the mercaptan-depleted naphtha stream rich in disulfide compounds in line 11 is passed to a naphtha splitter column 30 in which it is fractionated to provide a light naphtha stream lean in disulfide compounds in a naphtha splitter overhead line 13 and a heavy naphtha stream rich in disulfide compounds in a naphtha splitter bottoms line 23 .
- the light naphtha stream typically a C 5 -C 6 or a C 5 -C 7 stream, with reduced sulfur content may be condensed and separated in a receiver with a portion of the condensed liquid being sent in line 19 for blending to the gasoline pool.
- Any light ends may be vented to an appropriate combustion destination such as a furnace burner of a flare equipped for streams with high levels of oxygen via line 17 .
- the heavy naphtha stream typically comprising C 7+ naphtha, is rich in disulfide compounds, and may be taken from a bottoms outlet in the naphtha splitter bottoms line 23 for further processing.
- the naphtha splitter column 30 may be operated with a top pressure of 69 to 448 kPa (gauge) (10 to 65 psig) and a bottom temperature of 121° C. to 232° C. (250° F. to 450° F.). Alternatively, the naphtha splitter column 30 may be operated at a vacuum.
- the naphtha splitter column 30 may include a reboiler at a bottom of the column to vaporize and send a portion of the heavy naphtha stream back to the bottom of the column.
- the heavy naphtha stream rich in disulfide compounds in line 23 may be passed to a hydroprocessing unit to convert organic disulfides in the stream to hydrocarbons and hydrogen sulfide.
- a heavy naphtha stream lean in disulfide compounds can be recovered and routed as desired by the refiner.
- a mercaptan-containing whole straight-run naphtha (boiling range of 30° F.-330° F.; API gravity of 62.5) mixed with a selected air rate was flowed continuously through a 10 mL reactor bed loaded with a spent copper-containing oxidation catalyst that was previously used as an adsorbent in a sulfur guard bed for a refinery process.
- the catalyst contained about 30 wt. % copper and was prepared by co-mulling and impregnating an alumina support with copper, as described in U.S. Pat. No. 4,259,213.
- the unit was operated at various temperatures and liquid hourly space velocities (LHSV) at a pressure of 65 psig. The results are summarized in Table 1.
- the treated naphtha products in Runs 1-5 contained less than 1 ppm mercaptans.
- a treated naphtha product prepared as described in Example 1 was then distilled into light (200° F. ⁇ ) and heavy (200° F.+) naphtha cuts.
- the physical properties and composition of the light and heavy naphtha cuts are summarized in Tables 2.
- ASTM D4814 requires that fuels for automotive spark engines have a copper strip corrosion maximum of 1.
- a silver strip rating of 1 indicates slight tarnish.
- ASTM D4814 requires that fuels for automotive spark engines have a silver strip corrosion maximum of 1.
- ASTM D4814 requires that fuels for automotive spark engines have a maximum solvent-washed gum content of 5 mg/100 mL.
- Hydrocarbon class distribution was analyzed via detailed hydrocarbon analysis using gas chromatography (GC-DHA) by a method derived from the ASTM D6729 method. To improve identifications of GC species, 60 meter high resolution dual columns (one polar column and one non-polar column) were used. Those peaks that were not identified were grouped in the “Unclassified” category.
- the thermal stability of disulfides in the light and heavy naphtha cuts was determined at the naphtha splitter bottom temperature. Disulfides are products from mercaptan oxidation and can convert reversibly back to mercaptans at higher temperature. Each cut was heated to 350° F. in a Parr bomb type reactor for one and four hours. Sulfur speciation studies using gas chromatography sulfur chemiluminescence detection (GC-SCD) indicated no detectable reappearance of any mercaptans in the light and heavy naphtha cuts.
- GC-SCD gas chromatography sulfur chemiluminescence detection
- Example 1 was repeated except that the whole straight-run naphtha feed was a 300° F. ⁇ cut from a blend of Canadian condensates CFT and CRW.
- the feed contained 90.4 wppm of C 1 -C 9 mercaptans including cyclic and aromatic mercaptans.
- the mercaptan conversion results for this “tough feed” are summarized in Table 3.
- a treated naphtha product was then distilled into light (200° F. ⁇ ) and heavy (200° F.+) naphtha cuts. Both cuts were tested for their thermal stability at 302° F. GC-SCD indicated no detectable reappearance of any mercaptans in the light and heavy naphtha cuts.
- Example 1 was repeated except that a fresh copper-containing oxidation catalyst was used.
- the test was conducted on a conventional whole straight-run naphtha under the following conditions:
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Abstract
Description
- This application claims priority to and the benefit of U.S. Provisional Application Ser. No. 62/742,603, filed Oct. 8, 2018.
- The present disclosure generally relates to processes and apparatuses for treating petroleum fractions. More particularly, the field relates to an improved process and apparatus for removing mercaptan compounds from petroleum fractions such as naphtha.
- Most distillate hydrocarbon streams produced from crude oil contain some amount of sulfur in one form or another unless these streams have been subjected to extensive sulfur removal procedures such as hydrotreating. Often a major amount of this sulfur is present in the form of mercaptans. Mercaptan sulfur content must be reduced in the hydrocarbon distillate stream in order to meet certain product specifications such as a limitation on the total sulfur content of a product. It may also be desirable to remove mercaptan compounds from a hydrocarbon stream for the purpose of eliminating the rather malodorous mercaptan compounds and thereby improve or reduce the odor associated with the hydrocarbon stream. Another reason for removing mercaptan compounds from a hydrocarbon stream would be to eliminate the passage of sulfur-containing compounds into a catalyst bed which is sensitive to the presence of sulfur. It may therefore be necessary to remove mercaptans from a hydrocarbon distillate stream for the purpose of preserving the activity of a catalyst employed in a downstream conversion unit.
- In many regions, naphtha is useful for motor fuel and petrochemical feedstock and its further recovery is desirable. Due to environmental concerns and newly enacted rules and regulations, saleable fuels must meet lower and lower limits on contaminates, such as sulfur and nitrogen. For example, the U.S. Environmental Protection Agency (EPA) is implementing its
Tier 3 Gasoline Sulfur Program, a goal of which is to decrease the average gasoline sulfur content from 30 parts per million (ppm) to 10 ppm across each refining company's total annual output. - Hydroprocessing, such as hydrotreating, can be effective for reducing the sulfur content of a naphtha boiling range fraction to a desired sulfur level. In many cases, however, the existing hydrotreating assets do not have sufficient available hydraulic capacity to process the petrochemical naphtha stream and building a grass roots hydrotreater for this purpose is a very expensive option.
- Sweetening of petroleum fractions, such as naphtha boiling range hydrocarbons or other liquid hydrocarbons, that contain mercaptans (or sour petroleum fractions) are well-developed commercial processes commonly used in many petroleum refineries. In the sweetening process, mercaptans contained in the feed hydrocarbon stream (e.g., sour hydrocarbon stream) are converted to disulfide compounds that remain in the hydrocarbon stream (e.g., sweetened hydrocarbon stream). Sweetening processes, therefore, do not remove sulfur from the hydrocarbon stream but rather convert the sulfur to an acceptable form. The sweetening process involves an admixture of an oxygen-containing stream to the sour hydrocarbon stream to supply the required oxygen. Typically, the admixture of hydrocarbons and oxygen contacts an oxidation catalyst in an aqueous alkaline environment to oxidize the mercaptans. Typically, a caustic (e.g., an aqueous caustic solution) is combined with the sour hydrocarbon stream to create the aqueous alkaline environment. After contacting the oxidation catalysts, at least a portion of the caustic is carried with the sweetened hydrocarbon stream and can be problematic for further downstream processing. Current approaches for removing caustic from sweetened hydrocarbon streams often require additional downstream equipment and can be costly and/or are relatively inefficient.
- Accordingly, it is desirable to provide improved processes and apparatuses for treating naphtha streams containing mercaptan compounds. Additionally, it is desirable to provide such processes and apparatuses that can sweeten naphtha streams without the need for caustic and separate washing apparatus/procedures.
- In one aspect, there is provided a process for treating a naphtha boiling range stream containing mercaptan compounds, the process comprising: (a) oxidizing mercaptan compounds in the naphtha boiling range stream to provide a mercaptan-depleted naphtha stream rich in disulfide compounds; (b) passing the mercaptan-depleted naphtha stream rich in disulfide compounds to a naphtha splitter column; and (c) fractionating at least a portion of the mercaptan-depleted naphtha stream rich in disulfide compounds into at least two streams, a light naphtha stream lean in disulfide compounds and a heavy naphtha stream rich in disulfide compounds.
- In another aspect, there is provided an apparatus for treating a naphtha boiling range stream containing mercaptan compounds, wherein the apparatus comprises: (a) an oxidation unit to provide a mercaptan-depleted naphtha stream rich in disulfide compounds; and (b) a naphtha splitter column in downstream communication with the oxidation unit to provide a light naphtha stream lean in disulfide compounds in a naphtha splitter overhead line and a heavy naphtha stream rich in disulfide compounds in a naphtha splitter bottoms line.
- The
FIG. 1s a process flow diagram illustrating an exemplary process and apparatus of the present disclosure. - In this specification, the following words and expressions, if and when used, have the meanings ascribed below.
- The term “naphtha” or “naphtha boiling range” refers to hydrocarbons boiling in a range of about 25° C. to 190° C. atmospheric equivalent boiling point (AEBP), as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, and can include one or more C5-C10 hydrocarbons.
- The term “light naphtha” refers to hydrocarbons boiling in a range of about 25° C. to 85° C., and can include one or more C5-C6 hydrocarbons.
- The term “heavy naphtha” refers to hydrocarbons boiling in the range of about 85° C. to 190° C. (e.g., 110° C. to 170° C.), and can include one or more C6-C10 hydrocarbons.
- The modifying term “straight-run” is used herein having its well-known meaning, that is, describing fractions derived directly from the atmospheric distillation unit, optionally subjected to steam stripping, without other refinery treatment such as hydroprocessing, fluid catalytic cracking or steam cracking. An example of this is “straight-run naphtha” and its acronym “SRN” which accordingly refers to “naphtha” defined above that is derived directly from the atmospheric distillation unit, optionally subjected to steam stripping, as is well known. Straight-run naphtha may also be derived from natural gas condensates.
- The term “rich” refers to a stream exiting a vessel that has a concentration of one or more compounds exceeding a stream entering the vessel.
- The term “lean” refers to a stream exiting a vessel that has a concentration of one or more compounds less than a stream entering the vessel.
- The term “depleted” is synonymous with reduced from originally present. For example, removing a substantial portion of a material from a stream would produce a material-depleted stream that is substantially depleted of that material.
- The term “mercaptan” means thiol compounds of the formula R—SH where R is a hydrocarbon group, such as an alkyl or aryl group, that is saturated or unsaturated and optionally substituted,
- The term “disulfide” means compounds having the molecular formula R—S—S—R′ where R and R′ are each, independently, a hydrocarbon group, such as an alkyl or aryl group, that is saturated or unsaturated and optionally substituted. Generally, the term “disulfide” as used herein excludes carbon disulfide (CS2).
- The notation “Cx” means hydrocarbon molecules that have “x” number of carbon atoms, “Cx” means hydrocarbon molecules that have “x” and/or more than “x” number of carbon atoms, and “Cx-” means hydrocarbon molecules that have “x” and/or less than “x” number of carbon atoms.
- The term “communication” means that material flow is operatively permitted between enumerated components.
- The term “downstream communication” means that at least a portion of material flowing to the subject in downstream communication may operatively flow from the object with which it communicates.
- The term “upstream communication” means that at least a portion of the material flowing from the subject in upstream communication may operatively flow to the object with which it communicates.
- Numbers expressing quantities, percentages or proportions, and other numerical values used in the specification and claims are to be understood as being modified in all instances by the term “about.” The term “about” can be understood as within 10%, 5%, 2.5%, 1%, 0.5%, 0.1%, 0.05%, or 0.01% of the reported numerical value.
- As depicted, process flow lines in the FIGURE can be referred to interchangeably as, for example, lines, pipes, feeds, gases, products, discharges, parts, portions, conduits or streams.
- The following description is merely exemplary in nature and is not intended to limit the various embodiments or the application and uses thereof. The FIGURE has been simplified by the deletion of a large number of apparatuses customarily employed in a process of this nature, such as vessel internals, temperature and pressure control systems, flow control valves, recycle pumps, etcetera which are not specifically required to illustrate the performance of the invention.
- With reference to the FIGURE, a
feed 2 that is a crude oil or a natural gas condensate stream containing a range of hydrocarbons is passed to adistillation unit 10 where the feed is separated into alight stream 3, a naphthaboiling range stream 5, and/or one or more heavier or bottoms fractions. In embodiments where thefeed 2 is a crude oil, thedistillation unit 10 may be an atmospheric distillation unit. In embodiments where thefeed 2 is a natural gas condensate stream, thedistillation unit 10 may be a natural gas condensate splitter. - The feed in
line 2 may be dried and/or pre-treated to reduce and/or remove one or more of undesired components such as carbon dioxide, mercury, and water prior to fractionation. - Naphtha boiling range streams typically contain one or more mercaptan compounds. The mercaptans occurring in naphtha boiling range streams are generally C1-C10 mercaptans (e.g., C1-C6 mercaptans). The mercaptans are generally concentrated in the light fractions of the naphtha and more precisely in the fraction with a boiling point of less than 120° C. The mercaptan sulfur may be present in the naphtha boiling range stream in an amount ranging from about 2 ppm to 300 wppm or more, depending on the particular stream to be treated.
- Upon exiting the
distillation unit 10, the mercaptan-containing naphthaboiling range stream 5 is passed to anoxidation unit 20 where mercaptan compounds in the naphtha stream are converted to disulfide compounds. The flow direction inoxidation unit 20 can be down flow or up flow. Thenaphtha stream 5 is mixed with an air or other oxygen-containinggas stream 7 supplied at a rate that supplies at least the stoichiometric amount of oxygen necessary to oxidize the mercaptan compounds in the naphthaboiling range stream 5 to disulfide compounds. The mole ratio of oxygen to mercaptan sulfur may range from about 1:4 to 10:1 (e.g., about 1:1 to 10:1, or about 1:1 to 3:1). The oxidation of the mercaptan compounds is promoted through the presence of a catalytically effective amount of an oxidation catalyst capable of functioning at the conditions found in theoxidation unit 20. Theoxidation unit 20 may be configured in a packed bed configuration to ensure adequate mixing between the naphtha boiling range feed, the catalyst, and the oxygen. Theoxidation unit 20 may comprise a cylindrical fixed bed of catalyst through which the reactants move in a vertical direction. - The oxidation conditions utilized in
oxidation unit 20 may include a pressure of from about 101 to 2068 kPa (gauge) (15 to 300 psig), such as from 172 to 689 kPa (gauge) (25 to 100 psig); a temperature of from 35° C. to 200° C. (e.g. 50° C. to 150° C.); and a liquid hourly space velocity of from 1 to 10 h−1 (e.g., 1 to 5 h−1). - In an aspect, mercaptan compounds are depleted in the naphtha boiling range stream in the substantial absence of any caustic solvent, such as an aqueous solution of alkali metal hydroxide (e.g., sodium hydroxide, potassium hydroxide).
- Suitable oxidation catalysts are any known conventional catalysts for oxidizing mercaptans to disulfides and can include those which are comprised of a Group 5-12 metal component (e.g., one or more of vanadium, chromium, manganese, cobalt, nickel, copper, zinc) retained on a refractory inorganic oxide support.
- The inorganic oxide binder of the catalyst may comprise materials such as alumina, silica, zirconia, titania, thoria, boria, magnesia, chromia, stannic oxide, and the like as well as combinations and composites thereof, for example silica-alumina, alumina-zirconia, alumina-titania, aluminum phosphate, and the like. Alumina is a preferred refractory inorganic oxide binder. As is well known in the art, a precursor of the desired refractory inorganic oxide may be used to form, bind, and/or otherwise prepare the catalyst. Such binder precursors or sources may be converted into a refractory inorganic oxide binder, for example, by calcination. The alumina may be any of the various aluminum oxides, hydroxides, and gels, including boehmite, pseudo-boehmite, gibbsite, bayerite, and the like, especially transition and gamma aluminas. Suitable aluminas are commercially available, for example, under the trade names CATAPAL© B and VERSAL™ 250.
- The metal component of the catalyst may comprise a metal selected from the group consisting of vanadium, chromium, manganese, cobalt, nickel, copper, zinc, and combinations thereof. In one embodiment, the metal component comprises copper. The metal content of the catalyst can range from 10 to 40 wt. % (e.g., 15 to 30 wt. %) as the metal based upon the total weight of the catalyst.
- The metal component may be incorporated into the catalyst in any suitable manner such as co-mulling, co-precipitation or co-gellation with the carrier material, ion exchange, or impregnation. The metal component may exist within the final catalyst as a compound such as an oxide, sulfide, halide, or oxyhalide, in chemical combination with one or more of the other ingredients of the composite, or as an elemental metal. In an embodiment where the metal component is copper, the metal component may be present as copper metal, copper, oxide, copper sulfide, or a combination thereof.
- For practical applications, the catalyst is most preferably used in particulate form, for example as pellets, extrudate, spheres or granules, although other solid forms also are suitable. Particle size of the catalyst is selected such that a bed of catalyst particles is easily maintained in a suitable reactor for the oxidation process but permits flow of the naphtha boiling range through the bed without undesirable pressure drop. Preferred average particle sizes are such that catalyst particles pass through a 2-mesh screen but are retained on a 24-mesh screen (U.S. Sieve Series) and more preferably pass through a 4-mesh screen but are retained on a 12-mesh screen.
- The oxidation catalyst may have a BET surface area in a range of 30 to 300 m2/g (e.g., 50 to 200 m2/g).
- In one embodiment, the oxidation catalyst may be a fresh or spent sulfur sorbent having application in eliminating residual sulfur from conventionally desulfurized reformer or isomerization feed streams, such as described in U.S. Pat. No. 4,259,213.
- The effluent from
oxidation unit 20 comprises a mercaptan-depleted naphtha stream rich in disulfide compounds. Organic disulfides have higher boiling points than those of their mercaptan precursors. Thus, mercaptans that typically boil in a light naphtha fraction are converted in theoxidation unit 20 into disulfides that typically boil in a heavy naphtha fraction. - The mercaptan-depleted naphtha stream rich in disulfide compounds in
line 11 is passed to anaphtha splitter column 30 in which it is fractionated to provide a light naphtha stream lean in disulfide compounds in a naphtha splitteroverhead line 13 and a heavy naphtha stream rich in disulfide compounds in a naphthasplitter bottoms line 23. The light naphtha stream, typically a C5-C6 or a C5-C7 stream, with reduced sulfur content may be condensed and separated in a receiver with a portion of the condensed liquid being sent inline 19 for blending to the gasoline pool. Any light ends may be vented to an appropriate combustion destination such as a furnace burner of a flare equipped for streams with high levels of oxygen vialine 17. The heavy naphtha stream, typically comprising C7+ naphtha, is rich in disulfide compounds, and may be taken from a bottoms outlet in the naphtha splitter bottoms line 23 for further processing. - The
naphtha splitter column 30 may be operated with a top pressure of 69 to 448 kPa (gauge) (10 to 65 psig) and a bottom temperature of 121° C. to 232° C. (250° F. to 450° F.). Alternatively, thenaphtha splitter column 30 may be operated at a vacuum. Thenaphtha splitter column 30 may include a reboiler at a bottom of the column to vaporize and send a portion of the heavy naphtha stream back to the bottom of the column. - The heavy naphtha stream rich in disulfide compounds in
line 23 may be passed to a hydroprocessing unit to convert organic disulfides in the stream to hydrocarbons and hydrogen sulfide. A heavy naphtha stream lean in disulfide compounds can be recovered and routed as desired by the refiner. - The following illustrative examples are intended to be non-limiting.
- A mercaptan-containing whole straight-run naphtha (boiling range of 30° F.-330° F.; API gravity of 62.5) mixed with a selected air rate was flowed continuously through a 10 mL reactor bed loaded with a spent copper-containing oxidation catalyst that was previously used as an adsorbent in a sulfur guard bed for a refinery process. The catalyst contained about 30 wt. % copper and was prepared by co-mulling and impregnating an alumina support with copper, as described in U.S. Pat. No. 4,259,213. The unit was operated at various temperatures and liquid hourly space velocities (LHSV) at a pressure of 65 psig. The results are summarized in Table 1.
-
TABLE 1 SRN Treated Naphtha Feed Run 1 Run 2Run 3Run 4 Run 5Sulfur as RSH, 20.66 Not De- 0.07 0.58 0.68 0.25 wppm (ASTM tectable D3227) Process Conditions T, ° F. 210 210 230 230 230 LHSV, h−1 2.0 1.2 2.0 2.0 3.0 O2/RSH mole 1.5 1.5 1.5 0.75 0.75 ratio - As shown in Table 1, the treated naphtha products in Runs 1-5 contained less than 1 ppm mercaptans.
- A treated naphtha product prepared as described in Example 1 was then distilled into light (200° F.−) and heavy (200° F.+) naphtha cuts. The physical properties and composition of the light and heavy naphtha cuts are summarized in Tables 2.
-
TABLE 2 Light Naphtha Heavy Naphtha Fraction Fraction Cu Strip Corrosion(a) 1a 1a (ASTM D130) Ag Strip Corrosion(b) 1 1 (ASTM D7667) Unwashed Gum, mg/100 mL 3.4 (ASTM D381) Washed Gum(c), mg/100 mL 0 (ASTM D381) Hydrocarbon Class Distibution(d), vol % (Modified ASTM D6729) Aromatics 2.72 13.03 i-Paraffins 37.48 28.43 n-Paraffins 37.10 22.75 Naphthenes 22.56 32.08 Olefins 0.07 0.02 Oxygen 0.00 0.00 Unclassified 0.07 3.69 (a)A copper strip rating of 1a indicates slight tarnish, almost the same as a freshly polished strip. ASTM D4814 requires that fuels for automotive spark engines have a copper strip corrosion maximum of 1. (b)A silver strip rating of 1 indicates slight tarnish. ASTM D4814 requires that fuels for automotive spark engines have a silver strip corrosion maximum of 1. (c)ASTM D4814 requires that fuels for automotive spark engines have a maximum solvent-washed gum content of 5 mg/100 mL. (d)Hydrocarbon class distribution was analyzed via detailed hydrocarbon analysis using gas chromatography (GC-DHA) by a method derived from the ASTM D6729 method. To improve identifications of GC species, 60 meter high resolution dual columns (one polar column and one non-polar column) were used. Those peaks that were not identified were grouped in the “Unclassified” category. - The GC-DHA analysis showed that very small amounts of olefins were found in either the light or heavy treated naphtha. This indicates the mercaptan oxidation process did not dehydrogenate hydrocarbons to any substantial extent. Furthermore, the heavy naphtha has a higher relative concentration of aromatics as compared to the light naphtha. Most aromatics are higher boiling than paraffins with the same carbon number. These results indicate that the mercaptan oxidation process does not reveal any product quality concerns nor require a need for additives in order meet
US EPA Tier 3 requirements for gasoline. - The thermal stability of disulfides in the light and heavy naphtha cuts was determined at the naphtha splitter bottom temperature. Disulfides are products from mercaptan oxidation and can convert reversibly back to mercaptans at higher temperature. Each cut was heated to 350° F. in a Parr bomb type reactor for one and four hours. Sulfur speciation studies using gas chromatography sulfur chemiluminescence detection (GC-SCD) indicated no detectable reappearance of any mercaptans in the light and heavy naphtha cuts.
- Example 1 was repeated except that the whole straight-run naphtha feed was a 300° F.− cut from a blend of Canadian condensates CFT and CRW. The feed contained 90.4 wppm of C1-C9 mercaptans including cyclic and aromatic mercaptans. The mercaptan conversion results for this “tough feed” are summarized in Table 3.
-
TABLE 3 Treated Naphtha SRN Feed Run 6 Run 7Run 8 Sulfur as RSH, wppm 90.4 Not Not Not (ASTM D3227) Detectable Detectable Detectable Process Conditions T, ° F. 210 210 210 LHSV, h−1 1.2 2.0 3.0 O2/RSH mole ratio 0.75 0.75 0.75 - The results show complete mercaptan conversion of the high mercaptan content feed.
- A treated naphtha product was then distilled into light (200° F.−) and heavy (200° F.+) naphtha cuts. Both cuts were tested for their thermal stability at 302° F. GC-SCD indicated no detectable reappearance of any mercaptans in the light and heavy naphtha cuts.
- Example 1 was repeated except that a fresh copper-containing oxidation catalyst was used. The test was conducted on a conventional whole straight-run naphtha under the following conditions:
- Pressure=70 psig
- Temperature=210° F.
- LHSV=1.2 h−1
- O2/RSH mole ratio=3
- Time=2 months
- Complete mercaptan conversion was achieved during the run.
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