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US20070095725A1 - Processing of FCC naphtha - Google Patents

Processing of FCC naphtha Download PDF

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Publication number
US20070095725A1
US20070095725A1 US11/263,125 US26312505A US2007095725A1 US 20070095725 A1 US20070095725 A1 US 20070095725A1 US 26312505 A US26312505 A US 26312505A US 2007095725 A1 US2007095725 A1 US 2007095725A1
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Prior art keywords
fraction
heavier
hydrogen
naphtha
lighter
Prior art date
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Abandoned
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US11/263,125
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English (en)
Inventor
Gary Podrebarac
Arvids Judzis
Scott Shorey
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Catalytic Distillation Technologies
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Catalytic Distillation Technologies
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Publication date
Application filed by Catalytic Distillation Technologies filed Critical Catalytic Distillation Technologies
Priority to US11/263,125 priority Critical patent/US20070095725A1/en
Assigned to CATALYTIC DISTILLATION TECHNOLOGIES reassignment CATALYTIC DISTILLATION TECHNOLOGIES ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: SHOREY, SCOTT W., JUDZIDS, JR., ARVIDS, PODREBARAC, GARY G.
Priority to CA002626365A priority patent/CA2626365A1/en
Priority to CN2006800407882A priority patent/CN101300324B/zh
Priority to KR1020087013221A priority patent/KR20080066068A/ko
Priority to AU2006312301A priority patent/AU2006312301B2/en
Priority to RU2008121942/04A priority patent/RU2387696C2/ru
Priority to EP06750006A priority patent/EP1943326A4/en
Priority to UAA200806357A priority patent/UA90177C2/ru
Priority to PCT/US2006/013824 priority patent/WO2007055722A2/en
Priority to TW095115928A priority patent/TW200716736A/zh
Priority to ARP060102743A priority patent/AR055066A1/es
Publication of US20070095725A1 publication Critical patent/US20070095725A1/en
Priority to ZA200803290A priority patent/ZA200803290B/xx
Abandoned legal-status Critical Current

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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
    • 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
    • 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
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/301—Boiling range
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/02—Gasoline

Definitions

  • the present invention relates to a process for the desulfurization of a full boiling range fluid catalytic cracked naphtha. More particularly the present invention employs catalytic distillation steps which reduce sulfur to very low levels, makes more efficient use of hydrogen and causes less olefin hydrogenation for a full boiling range naphtha stream. More particularly the invention relates to a process for controlling the end point of gasoline blended from the treated naphtha by concurrently distilling the naphtha while desulfurizing and then recombining the fractions for the desired endpoint.
  • Petroleum distillate streams contain a variety of organic chemical components. Generally the streams are defined by their boiling ranges which determine the composition. The processing of the streams also affects the composition. For instance, products from either catalytic cracking or thermal cracking processes contain high concentrations of olefinic materials as well as saturated (alkanes) materials and polyunsaturated materials (diolefins). Additionally, these components may be any of the various isomers of the compounds.
  • the composition of untreated naphtha as it comes from the crude still, or straight run naphtha is primarily influenced by the crude source.
  • Naphthas from paraffinic crude sources have more saturated straight chain or cyclic compounds.
  • most of the “sweet” (low sulfur) crudes and naphthas are paraffinic.
  • the naphthenic crudes contain more unsaturates and cyclic and polycylic compounds.
  • the higher sulfur content crudes tend to be naphthenic.
  • Treatment of the different straight run naphthas may be slightly different depending upon their composition due to crude source.
  • Reformed naphtha or reformate generally requires no further treatment except perhaps distillation or solvent extraction for valuable aromatic product removal.
  • Reformed naphthas have essentially no sulfur contaminants due to the severity of their pretreatment for the process and the process itself.
  • Cracked naphtha as it comes from the catalytic cracker has a relatively high octane number as a result of the olefinic and aromatic compounds contained therein. In some cases this fraction may contribute as much as half of the gasoline in the refinery pool together with a significant portion of the octane.
  • Catalytically cracked naphtha gasoline boiling range material
  • gasoline boiling range material gasoline boiling range material
  • the sulfur impurities may require removal, usually by hydrotreating, in order to comply with product specifications or to ensure compliance with environmental regulations.
  • Some users require the sulfur of the final product to be below 50 wppm.
  • HDS hydrodesulfurization
  • Typical operating conditions for the HDS reactions are: Temperature, ° F. 600-780 Pressure, psig 600-3000 H 2 recycle rate, SCF/bbl 1500-3000 Fresh H 2 makeup, SCF/bbl 700-1000
  • the product may be fractionated or simply flashed to release the hydrogen sulfide and collect the now desulfurized naphtha.
  • the loss of olefins by incidental hydrogenation is detrimental by the reduction of the octane rating of the naphtha and the reduction in the pool of olefins for other uses.
  • the cracked naphthas are often used as sources of olefins in other processes such as etherifications, oligomerizations and alkylations.
  • the conditions of hydrotreating of the naphtha fraction to remove sulfur will also saturate some of the olefinic compounds in the fraction reducing the octane and causing a loss of source olefins.
  • the predominant light or lower boiling sulfur compounds are mercaptans while the heavier or higher boiling compounds are thiophenes and other heterocyclic compounds.
  • the separation by fractionation alone will not remove the mercaptans.
  • the mercaptans have been removed by oxidative processes involving caustic washing.
  • a combination oxidative removal of the mercaptans followed by fractionation and hydrotreating of the heavier fraction is disclosed in U.S. Pat. No. 5,320,742. In the oxidative removal of the mercaptans the mercaptans are converted to the corresponding disulfides.
  • a full boiling range naphtha stream is hydrodesulfurizated by splitting it into boiling range fractions which are treated to simultaneously hydrodesulfurize and fractionate the fractions.
  • the sulfur may be removed from the light portion of the stream to a heavier portion of the stream without any substantial loss of olefins.
  • substantially all of the sulfur contained in the naphtha is ultimately converted to H 2 S which is quickly removed from the catalyst zones and easily distilled away from the hydrocarbons minimizing production of recombinant mercaptans and with reduced hydrogenation of olefins.
  • the fractions may be selectively combined to adjust the endpoint (ASTM D-86 95% point) as desired for various situations.
  • the invention is a process for the desulfurization of a catalytic cracked naphtha comprising contacting the naphtha and hydrogen in the presence of the hydrodesulfurization catalyst to react a portion of the organic sulfur compounds contained within the naphtha with hydrogen to form H 2 S, and separating the naphtha stream into a lighter fraction and a heavier fraction by distillation; withdrawing the lighter fraction from as an overheads; withdrawing the heavier fraction from as a bottoms; and combining a portion of the heavier fraction with the lighter fraction to obtain an ASTM D-86 95% point greater than the end point of the lighter fraction and less than the ASTM D-86 95% point of the heavier fraction and preferably less than the D-86 95% point of the feed naphtha.
  • a full boiling range naphtha containing diolefins and organic sulfur compounds, including mercaptan is split into a first heavy fraction and a light fraction.
  • the light fraction is brought into contact with a thioetherification catalyst under conditions of concurrent fractionation and reaction to react diolefins and mercaptans to form organic sulfides and to fractionate the organic sulfides into the first heavy fraction.
  • the light fraction having a reduced sulfur content is recovered as overheads.
  • the first heavy fraction is recovered and used as the feed for fractionated into an intermediate fraction and a second heavy fraction. Both fractions are individually brought into contact with hydrodesulfurization catalyst and hydrogen under conditions of concurrent fractionation and reaction to react organic sulfur including organic sulfides from the light fraction with the hydrogen to form H 2 S and hydrocarbons.
  • the intermediate fraction having a reduced sulfur content from the first heavy feed is recovered and combined with the light fraction.
  • a second heavy fraction having a reduced sulfur content from the first heavy feed is recovered and a portion thereof comprising less than all of the second heavy fraction is combined with the light and intermediate fractions to produce a selected endpoint.
  • a portion of the second heavy fraction having a reduced sulfur content from that of the first heavy feed is combined the combined intermediate fraction and light fraction to obtain an ASTM D-86 95% point greater than the end point of the combined intermediate fraction and light fraction and less than the ASTM D-86 95% point of the second heavy fraction.
  • the unused heavy fraction is sent to diesel fuel processing.
  • the present invention provides a new configuration where the amount of heavy cracked naphtha blended into light/intermediate cracked naphtha is controlled and can be varied, thus giving a refiner control over the endpoint of the gasoline produced. Any excess heavy cracked naphtha produced would be suitable to route to a distillate hydrotreater or perhaps directly into the diesel pool. This also gives some flexibility to vary the amount of gasoline and diesel fuel produced at the refinery. Since less than all of the recovered heavy naphtha fraction is blended with intermediate fraction, it is contemplated that, up to 100% of the desulfurized heavy fraction will be used.
  • FIG. 1 is a simplified flow diagram in schematic form of one embodiment of the invention.
  • FIG. 2 is a simplified flow diagram in schematic form of a second embodiment of the invention.
  • FIG. 3 is a simplified flow diagram in schematic form of an embodiment of the invention employing one fixed bed, straight pass HDS polishing reactor in combination with a distillation column.
  • FIG. 4 is a simplified flow diagram in schematic form of an embodiment of the invention employing fixed bed, straight pass HDS reactors.
  • the bottoms are subjected to hydrodesulfurization in a second distillation column reactor where the sulfur compounds are converted to H 2 S and removed.
  • the second distillation column reactor desulfurizes FCC gasoline in a distillation environment.
  • an overhead and a bottom stream are produced.
  • the overhead product contains the midrange cat-cracked naphtha (MCN) and typically covers a boiling range of 150-350° F., although there is some flexibility for the exact temperatures.
  • the bottom product contains the heavy cat-cracked naphtha (HCN) and has a typical endpoint near 480° F.
  • hydrodesulfurization reactions and distillation separations may be carried out concurrently in a reaction distillation zone or in a fixed bed, straight pass reaction zone followed by a distillation zone or in combinations of these two modes.
  • a full boiling range naphtha stream containing organic sulfur compounds and diolefins may be fractionated in a first distillation column reactor by boiling a portion of the stream containing lower boiling organic sulfur compounds, generally mercaptans and diolefins into contact with a Group VIII metal hydrogenation catalyst under conditions to form sulfides.
  • a lower boiling portion of the stream, having a reduced amount of organic sulfur compounds and diolefins is recovered as light naphtha overheads.
  • the sulfides formed by the reaction of the mercaptans and diolefins are higher boiling and are removed from the column in a heavier bottoms. The heavier bottoms comprise that portion of the streams not removed as overheads.
  • the heavier bottoms and hydrogen may be fed to a second distillation column reactor, where the heavier bottoms are fractionated into an intermediate naphtha fraction and a heavy naphtha fraction.
  • the organic sulfur compounds in the intermediate naphtha portion are brought into contact with hydrogen in the upper end of the distillation column reactor in the presence of a hydrodesulfization catalyst under conditions to convert the organic sulfur compounds to H 2 S which is removed overhead with the intermediate naphtha fraction.
  • Higher boiling organic sulfur compounds originally present in the stream and the sulfides produced in the first column are brought into contact with hydrogen in the lower end of the distillation column reactor in the presence of a hydrodesulfurization catalyst under conditions to convert the heavier sulfur compounds to H 2 S which is also removed with the intermediate naphtha in the overheads.
  • the H 2 S is separated from the intermediate fraction is condensed and recovered.
  • a reduced sulfur content heavy naphtha is recovered as bottoms.
  • the recovered heavy, intermediate and light naphtha fractions are then selectively blended to obtain the endpoint (ASTM D-86 95% point) of less than the heavy fraction and greater than the combined light and intermediate fractions.
  • the endpoint being controlled is measured by the ASTM D-86 method which is the standard in the refining industry. ASTM D-86 does not measure a true boiling point because of the equipment used but is still the standard used. Because ASTM D-86 does not measure a true boiling point, the endpoint according to this method may be manipulated by blending a higher boiling stock into a lower boiling stock.
  • Catalysts which are useful in the mercaptan-diolefin reaction and the selective hydrogenation of dienes include the Group VIII metals. Generally the metals are deposited as the oxides on an alumina support.
  • a preferred catalyst for the thioetherification reaction in CD mode is 54 wt. % Ni on 8 to 14 mesh Al 2 O 3 (alumina) spheres, supplied by Calcicat designated as E-475-SR.
  • Typical physical and chemical properties of the catalyst as provided by the manufacturer are as follows: TABLE Designation E-475-SR Form Sphere Nominal size 8 ⁇ 14 mesh Ni wt. % 54 Support alumina
  • Hydrogen must be fed to the reactor at a rate to the reactor must be sufficient to maintain the reaction, but kept below that which would cause flooding of the column which is understood to be the “effectuating amount of hydrogen” as that term is used herein.
  • the mole ratio of hydrogen to diolefins and acetylenes in the feed is at least 1.0 to 1.0 and preferably 2.0 to 1.0.
  • the thioetherification catalyst also catalyzes the selective hydrogenation of polyolefins, such as the diolefins, contained within the light cracked naphtha and to a lesser degree the isomerization of some of the mono-olefins.
  • polyolefins such as the diolefins
  • the relative rates of reaction for various compounds are in the order of from faster to slower:
  • the reaction of interest is the reaction of the mercaptans with diolefins. In the presence of the catalyst the mercaptans will also react with mono-olefins. However, there is an excess of diolefins to mercaptans in the light cracked naphtha feed and the mercaptans preferentially react with them before reacting with the mono-olefins.
  • the equation of interest which describes the reaction is:
  • R 1 or R 2 can be either an alkyl group or a hydrogen atom.
  • the catalyst may be used as individual Group VIII metal component or in admixture with each other or modifiers as known in the art, particularly those in Group VIB and IB such as hydrogenation catalysts of the type characterized by platinum, palladium, rhodium or mixtures thereof.
  • the metals are deposited as the oxides on an alumina support.
  • the supports are usually small diameter extrudates or spheres, typically alumina.
  • Catalysts preferred for the selective hydrogenation of diolefins are alumina supported palladium catalysts.
  • the catalyst typically is in the form of extrudates having a diameter of 1 ⁇ 8, 1/16 or 1/32 inches and an L/D of 1.5 to 10.
  • the catalyst also may be in the form of spheres having the same diameters. In their regular form they present too compact a mass and are preferably prepared in the form of a catalytic distillation structure.
  • the catalytic distillation structure must be able to function as catalyst and as mass transfer medium.
  • the catalysts When the catalysts are used within a distillation column reactor, they are preferably prepared in the form of a catalytic distillation structure.
  • the catalytic distillation structure must be able to function as catalyst and as mass transfer medium.
  • the catalyst is preferably supported and spaced within the column to act as a catalytic distillation structure.
  • a variety of catalyst structures for this use are disclosed in U.S. Pat. Nos. 4,443,559; 4,536;373; 5,057,468; 5,130,102; 5,133,942; 5,189,001; 5,262,012; 5,266,546; 5,348,710; 5,431,890; and 5,730,843 which are incorporated herein by reference.
  • a preferred structure is that shown in U.S. Pat. No. 5,730,843 which is incorporated by reference.
  • the structure comprises a rigid frame made of two substantially vertical duplicate grids spaced apart and held rigid by a plurality of substantially horizontal rigid members and a plurality of substantially horizontal wire mesh tubes mounted to the grids to form a plurality of fluid pathways among the tubes.
  • At least a portion of the wire mesh tubes contain a particulate catalytic material.
  • the catalyst within the tubes provides a reaction zone where catalytic reactions may occur and the wire mesh provides mass transfer surfaces to effect a fractional distillation.
  • the spacing elements provide for a variation of the catalyst density and loading and structural integrity and provides ample vapor and liquid throughput capability.
  • the light FC naphtha is fed via flow line 101 to a thioetherification distillation column reactor 10 containing a bed 12 of thioetherification catalyst. Hydrogen is fed in an amount sufficient to keep the catalyst in the hydride state.
  • the mercaptans in the naphtha are reacted with diolefins to form sulfides which are higher boiling and are removed with the bottoms via flow line 103 .
  • a light naphtha product is taken as overheads via flow line 102 and sent to the final blend.
  • the bottoms in flow line 103 are combined with a heavy FC naphtha stream from flow line 104 and fed via flow line 105 to a hydrodesulfurization distillation column reactor 20 containing two beds 22 and 24 of hydrodesulfurization catalyst. Hydrogen is also fed to the unit. It may be co-fed as shown or as a separate feed below the bed 24 .
  • the organic sulfur compounds, including the sulfides produced in the reactor 10 are reacted with hydrogen to form hydrogen sulfide.
  • An intermediate boiling range naphtha (MCN) is taken as overheads via flow line 106 and stripped of hydrogen sulfide in stripper 30 where the hydrogen sulfide is removed as overheads via flow line 107 .
  • the product MCN is taken from the stripper 30 as bottoms via flow line 108 .
  • a heavy naphtha stream (HCN) is taken from the reactor 20 as bottoms via flow line 109 and stripped of hydrogen sulfide in stripper 40 where the hydrogen sulfide is taken as overheads via flow line 110 .
  • the product HCN is removed from the stripper as bottoms via flow line 111 . Once stripped, the HCN is suitable to send to the diesel pool, via flow line 112 or perhaps to a distillate hydrotreater or other type of unit if additional processing is required.
  • Some of the HCN is also routed via flow line 113 into the MCN product.
  • the amount of HCN blended into the MCN depends on the endpoint required in the final product. A higher endpoint temperature will require more of the HCN, and a lower endpoint will require less HCN.
  • the combined stream of MCN and desired HCN is sent to the final blend via flow line 114 .
  • the refiner determines that the HCN requires additional processing before being sent to the diesel pool, there may be an opportunity to eliminate the stripper 40 and save capital.
  • This layout is provided in FIG. 2 .
  • the required proportion of the HCN would be routed to the stripper 30 via flow line 115 where it would mix with the MCN and be stripped of dissolved gases.
  • the remainder of the HCN would be routed directly to a distillate hydrotreater.
  • the dissolved hydrogen and hydrogen sulphide in the HCN do not pose a problem in a typical distillate hydrotreater.
  • the dissolved gases could pose a problem if there is a need to store the material prior to further processing, so this process scheme must be considered carefully.
  • MCN/HCN blend may be required.
  • Such units are well known in the art and are not shown.
  • any or all of the hydrodesulfurizations may be carried out in fixed bed, single pass reactors as illustrated in FIGS. 3 and 4 .
  • HCN heavy naphtha stream
  • stripper 30 where it would mix with the MCN, stripped of dissolved gases and total product from reactor 20 sent to a polishing reactor 50 via line 108 where it is subjected to further hydrodesulfurization in fixed catalyst bed 52 with hydrogen added through line 108 A and the product passed via line 118 to splitter 60 where H 2 S and H 2 are removed as overheads via line 116 and the polished product split to send the LCN to the Final Blend via sided raw line 114 .
  • Some or all of the HCN may also go tothe Final Blend or Diesel vial line 120 by adjustment of the operating conditions of splitter 60 .
  • the unconverted sulfur will either recycle to extension in the heavy recycle loop ( 109 A, 105 ) or be easily converted in the diesel hydrotreater (not shown).
  • any or all of the hydrodesulfizations may be carried out in fixed bed, straight pass reactors ss illustrated in FIGS. 3 and 4 .
  • FIG. 4 illustrates the present process where each of the hydrodesulfurization is carried out in fixed bed, straight pass reactors 310 and 340 with appropriate adjustments. Nonetheless, the product streams 102 and 114 to the Final Blend and Diesel are substantially equivalent to those produced by the catalytic distillation HDS.
  • the feed 101 is hydrodesulfurized in fixed bed, straight pass reactor 310 with the product the product passing to stripper 320 where the H 2 S is removed via line 312 .
  • the liquid from stripper 320 with reduced sulfur content is sent via line 314 to splitter 330 where the LCN overheads 102 are recovered and sent Final Blend.
  • the bottoms 103 are sent to fixed bed, straight pass reactor 340 where it contacts hydrodesulfurization catalyst 24 .
  • the bottoms is passed to stripper 30 and H 2 S is removed vial line 107 .
  • the liquid bottoms having reduced sulfur content pass via line 318 to splitter 350 and a MCH is taken overheads 108 to Final Blend vial line 114 while bottoms 111 are handled as described above.
  • the hydrodesulfurization distillation column reactor was set up in a 3′′ diameter column ⁇ 50 ft. tall.
  • a Co/Mo catalyst (DC-130 from Criterion Catalyst Company) was loaded into the column in structure as described in U.S. Pat. No. 5,730,843. Operating conditions and results are presented in TABLE II below.
  • Hydrogen (scfh) 20.1 Pressure (pig) 265 Throughput (bpd/ft 3 catalyst packing) 2.8 Upper bed temp. ° F. 487 Lower bed temp. ° F.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
US11/263,125 2005-10-31 2005-10-31 Processing of FCC naphtha Abandoned US20070095725A1 (en)

Priority Applications (12)

Application Number Priority Date Filing Date Title
US11/263,125 US20070095725A1 (en) 2005-10-31 2005-10-31 Processing of FCC naphtha
PCT/US2006/013824 WO2007055722A2 (en) 2005-10-31 2006-04-13 Processing of fcc naphtha
EP06750006A EP1943326A4 (en) 2005-10-31 2006-04-13 PROCESSING OF FCC-NAPHTHA
CN2006800407882A CN101300324B (zh) 2005-10-31 2006-04-13 Fcc石脑油的加工
KR1020087013221A KR20080066068A (ko) 2005-10-31 2006-04-13 Ｆｃｃ 나프타의 가공
AU2006312301A AU2006312301B2 (en) 2005-10-31 2006-04-13 Processing of FCC naphtha
RU2008121942/04A RU2387696C2 (ru) 2005-10-31 2006-04-13 Обработка лигроина флюид-каталитического крекинга (fcc)
CA002626365A CA2626365A1 (en) 2005-10-31 2006-04-13 Processing of fcc naphtha
UAA200806357A UA90177C2 (ru) 2005-10-31 2006-04-13 Способ десульфуризации (варианты) и способ обработки подвергнутого каталитическому крекингу лигроину
TW095115928A TW200716736A (en) 2005-10-31 2006-05-04 Processing of FCC naphtha
ARP060102743A AR055066A1 (es) 2005-10-31 2006-06-26 Procesamiento de nafta fcc
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US20120048778A1 (en) * 2010-08-25 2012-03-01 Catalytic Distillation Technologies Selective desulfurization of fcc gasoline
US9914891B2 (en) 2014-11-24 2018-03-13 Uop Llc Process for maximizing diesel production using a heavy heavy naphtha stream
US10377956B2 (en) * 2016-10-19 2019-08-13 IFP Energies Nouvelles Process for hydrodesulphurizing an olefinic gasoline
US10377957B2 (en) * 2016-04-08 2019-08-13 IFP Energies Nouvelles Process for the treatment of a gasoline
WO2021127322A1 (en) * 2019-12-19 2021-06-24 Kellogg Brown & Root Llc Process to prepare feed using dividing-wall column and/or conventional column for catalytic cracking unit targeting olefin production

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US20120048778A1 (en) * 2010-08-25 2012-03-01 Catalytic Distillation Technologies Selective desulfurization of fcc gasoline
US8628656B2 (en) * 2010-08-25 2014-01-14 Catalytic Distillation Technologies Hydrodesulfurization process with selected liquid recycle to reduce formation of recombinant mercaptans
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WO2021127322A1 (en) * 2019-12-19 2021-06-24 Kellogg Brown & Root Llc Process to prepare feed using dividing-wall column and/or conventional column for catalytic cracking unit targeting olefin production
GB2605105A (en) * 2019-12-19 2022-09-21 Kellogg Brown & Root Llc Process to prepare feed using dividing-wall column and/or conventional column for catalytic cracking unit targeting olefin production
GB2605105B (en) * 2019-12-19 2025-04-02 Kellogg Brown & Root Llc Process to prepare feed using dividing-wall column and/or conventional column for catalytic cracking unit targeting olefin production
US12522769B2 (en) 2019-12-19 2026-01-13 Kellogg Brown & Root Llc Process to prepare feed by using dividing wall column and/or conventional column for catalytic cracking unit targeting olefin production

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AU2006312301A1 (en) 2007-05-18
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RU2008121942A (ru) 2009-12-10
TW200716736A (en) 2007-05-01
AU2006312301B2 (en) 2009-12-17
CA2626365A1 (en) 2007-05-18
AR055066A1 (es) 2007-08-01
UA90177C2 (ru) 2010-04-12
CN101300324A (zh) 2008-11-05
RU2387696C2 (ru) 2010-04-27
WO2007055722A3 (en) 2007-10-25
WO2007055722A2 (en) 2007-05-18
KR20080066068A (ko) 2008-07-15

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