EP1954785A1 - Hydrodesulfuration selective du naphta avec decomposition des mercaptans a haute temperature - Google Patents

Hydrodesulfuration selective du naphta avec decomposition des mercaptans a haute temperature

Info

Publication number
EP1954785A1
EP1954785A1 EP06827807A EP06827807A EP1954785A1 EP 1954785 A1 EP1954785 A1 EP 1954785A1 EP 06827807 A EP06827807 A EP 06827807A EP 06827807 A EP06827807 A EP 06827807A EP 1954785 A1 EP1954785 A1 EP 1954785A1
Authority
EP
European Patent Office
Prior art keywords
mercaptan
effluent stream
hydrodesulfurization
sulfur content
stream
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.)
Withdrawn
Application number
EP06827807A
Other languages
German (de)
English (en)
Other versions
EP1954785A4 (fr
Inventor
John Peter Greeley
Edward Stanley Ellis
Thomas Risher Halbert
William Joseph Tracy, Iii
Jeffrey M. Dysard
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ExxonMobil Technology and Engineering Co
Original Assignee
ExxonMobil Research and Engineering Co
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by ExxonMobil Research and Engineering Co filed Critical ExxonMobil Research and Engineering Co
Publication of EP1954785A1 publication Critical patent/EP1954785A1/fr
Publication of EP1954785A4 publication Critical patent/EP1954785A4/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G69/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process
    • C10G69/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • 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
    • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
    • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4006—Temperature
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4012—Pressure
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/80—Additives
    • C10G2300/805—Water
    • C10G2300/807—Steam

Definitions

  • the present invention relates to a multistage process for the selective hydrodesulfurization and mercaptan removal of an olefinic naphtha stream containing a substantial amount of organically bound sulfur and olefins.
  • Hydrodesulfurization is one of the fundamental hydrotreating processes of refining and petrochemical industries.
  • the removal of feed organically bound sulfur by conversion to hydrogen sulfide is typically achieved by reaction with hydrogen over non-noble metal sulfided supported and unsupported catalysts, especially those containing Co/Mo or Ni/Mo. This is usually achieved at fairly severe temperatures and pressures in order to meet product quality specifications, or to supply a desulfurized stream to a subsequent sulfur sensitive process.
  • Olefinic naphthas such as cracked naphthas and coker naphthas, typically contain more than about 20 wt.% olefins.
  • a process for hydrodesulfurizing olefinic naphtha feedstream and retaining a substantial amount of the olefins, which feedstream boils in the range of about 50 0 F (10 0 C) to about 45O 0 F (232°C) and contains organically bound sulfur and an olefin content of at least about 5 wt.% which process comprises: a) hydrodesulfurizing the olefmic naphtha feedstream in a first reaction stage in the presence of a hydrogen-containing treat gas and a hydrodesulfurization catalyst, at first hydrodesulfurization reaction conditions including temperatures from about 450 0 F (232°C) to about 800 0 F (427°C), pressures of about 60 to about 800 psig, and hydrogen-containing treat gas rates of about 1000 to about 6000 standard cubic feet per barrel, to convert a portion of the elemental and organically bound sulfur in said olefinic naphtha feedstream to hydrogen s
  • reaction conditions including temperatures from about 500 0 F (260 0 C) to about 800 0 F (427°C), pressures of about 60 to about 80 psig, and hydrogen-containing treat gas rates of about 1000 to about 6000 standard cubic feet per barrel, to convert at least a portion of the non-
  • the feedstreams to the hydrodesulfurization reactor and mercaptan decomposition stages will be in the vapor phase.
  • a portion of the hydrogen- containing treat gas to said first, second and mercaptan decomposition reaction stages is comprised of a portion of the gas removed from said first reactor effluent stream in said H 2 S removal zone.
  • the heat from at least a portion of said first reactor effluent is utilized to heat at least a portion of said olefinic naphtha feedstream prior to contact with said first reaction stage.
  • the heat from at least a portion of said mercaptan decomposition reactor product is utilized to heat at least a portion of said olefinic naphtha feedstream prior to contact with said first reaction stage.
  • the total sulfur content of said mercaptan decomposition reactor product stream is less than about 1 wt.% of the total sulfur content of said olefinic naphtha feedstream.
  • the mercaptan sulfur content of said mercaptan decomposition reactor product stream is less than about 10 wt.% of the mercaptan sulfur content of said first reactor effluent stream.
  • FIGURE 1 depicts a first preferred process scheme for practicing the present invention, wherein the olefinic naphtha feedstream is subjected to two hydrodesulfurization reaction stages with an intermediate H 2 S removal step which is then followed by a final mercaptan decomposition reaction stage.
  • FIGURE 2 depicts a second preferred process scheme for practicing the present invention, wherein the olefinic naphtha feedstream is subjected to one hydrodesulfurization reaction stage followed by an H 2 S removal step which is then followed by a final mercaptan decomposition reaction stage.
  • Feedstocks suitable for use in the present invention are olefinic naphtha boiling range refinery streams that typically boil in the range of about 50 0 F (10 0 C) to about 450 0 F (232°C).
  • olefinic naphtha stream as used herein are those naphtha streams having an olefin content of at least about 5 wt.%.
  • Non-limiting examples of olefinic naphtha streams include fluid catalytic cracking unit naphtha (FCC catalytic naphtha or cat naphtha), steam cracked naphtha, and coker naphtha.
  • blends of olefinic naphthas with non-olefinic naphthas as long as the blend has an olefin content of at least about 5 wt.%.
  • Olefinic naphtha refinery streams generally contain not only paraffins, naphthenes, and aromatics, but also unsaturates, such as open-chain and cyclic olefins, dienes, and cyclic hydrocarbons with olefinic side chains.
  • the olefinic naphtha feedstock can contain an overall olefins concentration ranging as high as about 60 wt.%, more typically as high as about 50 wt.%, and most typically from about 5 wt.% to about 40 wt.%.
  • the olefinic naphtha feedstock can also have a diene concentration up to about 15 wt.%, but more typically less than about 5 wt.% based on the total weight of the feedstock. High diene concentrations are undesirable since they can result in a gasoline product having poor stability and color.
  • the sulfur content of the olefinic naphtha will generally range from about 300 wppm to about 7000 wppm, more typically from about 1000 wppm to about 6000 wppm, and most typically from about 1500 to about 5000 wppm.
  • the sulfur will typically be present as organically bound sulfur.
  • sulfur compounds such as simple aliphatic, naphthenic, and aromatic mercaptans, sulfides, di- and polysulfides and the like.
  • Other organically bound sulfur compounds include the class of heterocyclic sulfur compounds such as thiophene and its higher homologs and analogs. Nitrogen will also be present and will usually range from about 5 wppm to about 500 wppm.
  • Figure 1 is a simple flow scheme of the first preferred embodiment for practicing the present invention.
  • Various ancillary equipment, such as compressors, pumps, heat exchangers and valves is not shown for simplicity reasons.
  • an olefinic naphtha feed (1) and a hydrogen-containing treat gas stream (2) are contacted with a catalyst in a first hydrodesulfurization reaction stage (3) that is preferably operated in selective hydrodesulfurization conditions that will vary as a function of the concentration and types of organically bound sulfur species of the feedstream.
  • selective hydrodesulfurization we mean that the hydrodesulfurization reaction stage is operated in a manner to achieve as high a level of sulfur removal as possible with as low a level of olefin saturation as possible. It is also operated to avoid as much mercaptan reversion as possible.
  • hydrodesulfurization conditions for both of the hydrodesulfurization reaction stages include: temperatures from about 45O 0 F (232°C) to about 800°F (427°C), preferably from about 500 0 F (260 0 C) to about 675°F (357 0 C); pressures from about 60 to about 800 psig, preferably from about 200 to about 500 psig, more preferably from about 250 to about 400 psig; hydrogen feed rates of about 1000 to about 6000 standard cubic feet per barrel (scf/b), preferably from about 1000 to about 3000 scf/b; and liquid hourly space velocities of about 0.5 hr "1 to about 15 hr "1 , preferably from about 0.5 hr '1 to about 10 hr "1 , more preferably from about 1 hr "1 to about 5 hr "1 . It is preferred that the feedstream to the first and second reaction stages as well as the mercaptan destruction reaction stage be in the vapor stage when contacting the catalyst.
  • This first hydrodesulfurization reaction stage can be comprised of one or more fixed bed reactors each of which can comprise one or more catalyst beds of the same, or different, hydrodesulfurization catalyst. Although other types of catalyst beds can be used, fixed beds are preferred. Non-limiting examples of such other types of catalyst beds that may be used in the practice of the present invention include fluidized beds, ebullating beds, slurry beds, and moving beds. Interstage cooling between reactors, or between catalyst beds in the same reactor, can be employed since some olefin saturation can take place, and olefin saturation as well as the desulfurization reaction are generally exothermic. A portion of the heat generated during hydrodesulfurization can be recovered by conventional techniques.
  • the first hydrodesulfurization stage be configured in a manner and operated under hydrodesulfurization conditions such that from about 40% to 100%, more preferably from about 60% to about 95% of the total targeted sulfur removal is reached in the first hydrodesulfurization stage.
  • Preferred hydrotreating catalysts for use in both the first and second hydrodesulfurization reaction stages are those that are comprised of at least one Group VIII metal oxide, preferably an oxide of a metal selected from Fe, Co and Ni, more preferably selected from Co and/or Ni, and most preferably Co; and at least one Group VI metal oxide, preferably an oxide of a metal selected from Mo and W, more preferably Mo, on a high surface area support material, preferably alumina.
  • Other suitable hydrotreating catalysts include zeolitic catalysts, as well as noble metal catalysts where the noble metal is selected from Pd and Pt. It is within the scope of the present invention that more than one type of hydrotreating catalyst be used in the same reaction vessel.
  • the Group VIII metal oxide of the first hydrodesulfurization catalyst is typically present in an amount ranging from about 0.1 to about 20 wt.%, preferably from about 1 to about 12%.
  • the Group VI metal oxide will typically be present in an amount ranging from about 1 to about 50 wt.%, preferably from about 2 to about 20 wt.%. All metal oxide weight percents are on support. By “on support” we mean that the percents are based on the weight of the support. For example, if the support were to weigh 100 g. then 20 wt.% Group VIII metal oxide would mean that 20 g. of Group VIII metal oxide is on the support.
  • Preferred catalysts for both the first and second hydrodesulfurization stage will also have a high degree of metal sulfide edge plane area as measured by the Oxygen Chemisorption Test as described in "Structure and Properties of Molybdenum Sulfide: Correlation of O2 Chemisorption with Hydrodesulfurization Activity," SJ. Tauster et al., Journal of Catalysis 63, pp. 515-519 (1980), which is incorporated herein by reference.
  • the Oxygen Chemisorption Test involves edge-plane area measurements made wherein pulses of oxygen are added to a carrier gas stream and thus rapidly traverse the catalyst bed.
  • the oxygen chemisorption will be from about 800 to 2,800, preferably from about 1,000 to 2,200, and more preferably from about 1,200 to 2,000 ⁇ mol oxygen/gram MoO 3 .
  • the most preferred catalysts for the first and second hydrodesulfurization zone can be characterized by the properties: (a) a MoO 3 concentration of about 1 to 25 wt.%, preferably about 2 to 18 wt.%, and more preferably about 4 to 10 wt.%, and most preferably 4 to 8 wt.%, based on the total weight of the catalyst; (b) a CoO concentration of about 0.1 to 6 wt.%, preferably about 0.5 to 5.5 wt.%, and more preferably about 1 to 5 wt.%, also based on the total weight of the catalyst; (c) a Co/Mo atomic ratio of about 0.1 to about 1.0, preferably from about 0.20 to about 0.80, more preferably from about 0.25 to about 0.72; (d) a median
  • the hydrodesulfurization catalysts used in the practice of the present invention are preferably supported catalysts.
  • Any suitable refractory catalyst support material preferably inorganic oxide support materials, can be used as supports for the catalyst of the present invention.
  • suitable support materials include: zeolites, alumina, silica, titania, calcium oxide, strontium oxide, barium oxide, carbons, zirconia, diatomaceous earth, lanthanide oxides including cerium oxide, lanthanum oxide, neodynium oxide, yttrium oxide, and praesodymium oxide; chromia, thorium oxide, urania, niobia, tantala, tin oxide, zinc oxide, and aluminum phosphate.
  • alumina silica, and silica-alumina. More preferred is alumina.
  • Magnesia can also be used for the catalysts with a high degree of metal sulfide edge plane area of the present invention.
  • the support material can also contain small amounts of contaminants, such as Fe, sulfates, silica, and various metal oxides that can be introduced during the preparation of the support material. These contaminants are present in the raw materials used to prepare the support and will preferably be present in amounts less than about 1 wt.%, based on the total weight of the support. It is more preferred that the support material be substantially free of such contaminants.
  • an additive be present in the support, which additive is selected from the group consisting of phosphorus and metals or metal oxides from Group IA (alkali metals) of the Periodic Table of the Elements.
  • the total effluent product from the first hydrodesulfurization reaction stage (4) is conducted to an H 2 S removal zone (6).
  • a stripping agent such as a steam or an amine solution (5) is contacted with the first reactor effluent to remove substantially all of the H 2 S from the effluent stream (7).
  • This H 2 S removal zone operates at substantially the same pressure as the first hydrodesulfurization reaction stage pressure.
  • the H 2 S stripped product stream (8) from the H 2 S removal zone and a hydrogen- containing treat gas (9) is then contacted with a catalyst in a second hydrodesulfurization reaction stage (10) that is also preferably operated at selective hydrodesulfurization conditions.
  • the hydrodesulfurization conditions of the second stage reaction include similar temperature ranges, pressure ranges, treat gas ranges, liquid hourly space velocities ranges, catalyst properties, catalyst characteristics and catalyst compositions, reactor configurations, and heat recovery configurations as described for the first reaction stage above.
  • the reactor effluent (11) from the second reaction stage is then contacted with a catalyst in a mercaptan decomposition reaction stage (12).
  • This mercaptan decomposition reaction stage can be comprised of one or more fixed bed reactors, each of which can comprise one or more catalyst beds of the same, or different, mercaptan decomposition catalyst.
  • fixed beds are preferred.
  • Non-limiting examples of such other types of catalyst beds that may be used in the practice of the present invention include fluidized beds, ebullating beds, slurry beds, and moving beds.
  • the mercaptan decomposition catalysts suitable for use in this invention are those which contain a material that catalyzes the mercaptan reversal back to H 2 S and olefins.
  • Suitable mercaptan decomposition catalytic materials for this process include refractory metal oxides resistant to sulfur and hydrogen at high temperatures and which possess substantially no hydrogenation activity.
  • Catalytic materials which possess substantially no hydrogenation activity are those which have virtually no tendency to promote the saturation or partial saturation of any non-saturated hydrocarbon molecules, such as aromatics and olefins, in a feedstream under mercaptan decomposition reaction stage conditions as disclosed in this invention.
  • These catalytic materials specifically exclude catalysts containing metals, metal oxides, or metal sulfides of the Group V, VI, or VIII elements, including but not limited to V, Nb, Ta, Cr, Mo, W, Fe, Ru, Co, Rh, Ir, Ni, Pd, and Pt.
  • Suitable catalytic materials for the mercaptan decomposition reaction process of this invention include materials such as alumina, silica, both crystalline and amorphous silica-alumina, aluminum phosphates, titania, magnesium oxide, alkali and alkaline earth metal oxides, alkaline metal oxides, magnesium oxide supported on alumina, faujasite that has been ion exchanged with sodium to remove the acidity and ammonium ion treated aluminum phosphate.
  • the mercaptan decomposition reaction stage conditions include: temperatures from about 500 0 F (26O 0 C) to about 800 0 F (427°C), preferably from about 550 0 F (288°C) to about 700 0 F (371°C); pressures from about 60 to about 800 psig, preferably from about 150 to about 500 psig; hydrogen feed rates of about 1000 to about 6000 standard cubic feet per barrel (scf/b), preferably from about 1000 to about 3000 scf/b; and liquid hourly space velocities of about 0.5 hr "1 to about 15 hr "1 , preferably from about 0.5 hr "1 to about 10 hr "1 , more preferably from about 1 hr '1 to about 5 hr '1 .
  • organic and elemental sulfur compounds and mercaptan sulfur compounds are converted with a minimal amount of olefin saturation resulting in a final product stream (13) with properties of a reduced organic and elemental sulfur content, reduced mercaptan content and minimal octane reduction.
  • Figure 2 is a simple flow scheme depicting a second preferred embodiment for practicing the present invention. Again, various ancillary equipment, such as compressors, pumps, heat exchangers and valves are not shown for simplicity reasons.
  • an olefinic naphtha feed (1) and a hydrogen-containing treat gas stream (2) are contacted with a catalyst in a first hydrodesulfurization reaction stage (3) that is preferably operated in selective hydrodesulfurization conditions that will vary as a function of the concentration and types of organically bound sulfur species of the feedstream.
  • the hydrodesulfurization conditions of the first reaction stage in Figure 2 utilizes similar temperature ranges, pressure ranges, treat gas ranges, liquid hourly space velocities ranges, catalyst properties, catalyst characteristics and catalyst compositions, reactor configurations, and heat recovery configurations as described for the first reaction stage in Figure 1, above.
  • the total effluent product from the first hydrodesulfurization reaction stage (4) is conducted to an H 2 S removal zone (6).
  • a compound such as a steam or an amine solution (5) is contacted with the first reactor effluent to substantially remove all of the H 2 S from the effluent stream (7).
  • This H 2 S removal zone operates at substantially the same pressure as the first hydrodesulfurization reaction stage pressure.
  • the H 2 S stripped product stream (8) from the H 2 S removal zone and a hydrogen-containing treat gas (9) is then contacted with a catalyst in a mercaptan decomposition reaction stage (10).
  • the mercaptan decomposition conditions of the mercaptan decomposition reaction stage in this configuration are the same as described for the mercaptan decomposition reaction stage in the first embodiment, above (see Figure 1 and associated detailed description).
  • the mercaptan decomposition reaction conditions include similar temperature ranges, pressure ranges, treat gas ranges, liquid hourly space velocities ranges, catalyst properties, catalyst characteristics and catalyst compositions, reactor configurations, and heat recovery configurations as described for the mercaptan decomposition reaction conditions described in the first embodiment, above (see Figure 1 and associated detailed description).
  • organic and elemental sulfur compounds and mercaptan sulfur compounds are converted with a minimal amount of olefin saturation resulting in a final product stream (11) with properties of a reduced organic and elemental sulfur content, reduced mercaptan content and minimal octane reduction.
  • the process configuration utilized is shown in Figure 1.
  • the hydrogen treat gas rates, shown as streams (2) and (9) in Figure 1 are 2,000 standard cubic feet per barrel (scf/b).
  • the amount OfH 2 S removal in the H 2 S reaction zone (6) is modeled utilizing an H 2 S removal step to remove free and dissolved H 2 S from the process stream at the first hydrodesulfurization reaction pressures (327 psig).
  • Any stripping agent utilized in the art to facilitate H 2 S removal, such as steam or an amine solution, can be utilized and is shown as stream (5).
  • the H 2 S or H 2 S rich compound is then removed from the process via stream (7).
  • Tables 1 and 2 below Table 1
  • the process configuration utilized is shown in Figure 2.
  • the hydrogen treat gas rates, shown as streams (2) and (9) in Figure 2 are 2,000 standard cubic feet per barrel (scf/b).
  • the amount OfH 2 S removal in the H 2 S reaction zone (6) is modeled utilizing an H 2 S removal step to remove free and dissolved H 2 S from the process stream at the hydrodesulfurization reaction pressures (327 psig).
  • Any stripping agent utilized in the art to facilitate H 2 S removal such as steam or an amine solution, can be utilized and is shown as stream (5).
  • the H 2 S or H 2 S rich compound is then removed from the process via stream (7).
  • Tables 3 and 4 The conditions and resulting product qualities are predicted based on a kinetic model developed from a pilot plant database are shown in Tables 3 and 4 below. Table 3

Abstract

L’invention concerne un procédé d’hydrodésulfuration sélective des flux de naphta oléfiniques contenant une quantité importante de soufre organiquement lié et d’oléfines. Le flux de naphta oléfinique est désulfuré de façon sélective au cours d’une première étape réactionnelle d’hydrodésulfuration. Le flux effluent est ensuite mis en contact avec un agent d’épuisement, par exemple de la vapeur ou une solution d’amine, dans une zone d’élimination de H2S afin d’éliminer ce composé de l’effluent. Il en résulte une réduction de la pression partielle de H2S dans le flux de procédé. Le flux de procédé est ensuite soumis à une seconde étape réactionnelle de désulfuration, puis à une étape de décomposition des mercaptans de manière à diminuer la teneur en soufre sous forme mercaptan dans le flux de produit final. Selon un second mode de réalisation, le flux effluent provenant de la première étape réactionnelle d’hydrodésulfuration est directement introduit, après passage dans la zone d’élimination de H2S, dans l’étape de décomposition des mercaptans au cours de laquelle la teneur totale en soufre et la teneur en soufre sous forme mercaptan sont abaissées dans le flux de produit final.
EP06827807A 2005-11-23 2006-11-14 Hydrodesulfuration selective du naphta avec decomposition des mercaptans a haute temperature Withdrawn EP1954785A4 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US11/286,580 US20070114156A1 (en) 2005-11-23 2005-11-23 Selective naphtha hydrodesulfurization with high temperature mercaptan decomposition
PCT/US2006/044231 WO2007061701A1 (fr) 2005-11-23 2006-11-14 Hydrodesulfuration selective du naphta avec decomposition des mercaptans a haute temperature

Publications (2)

Publication Number Publication Date
EP1954785A1 true EP1954785A1 (fr) 2008-08-13
EP1954785A4 EP1954785A4 (fr) 2011-06-22

Family

ID=38052405

Family Applications (1)

Application Number Title Priority Date Filing Date
EP06827807A Withdrawn EP1954785A4 (fr) 2005-11-23 2006-11-14 Hydrodesulfuration selective du naphta avec decomposition des mercaptans a haute temperature

Country Status (7)

Country Link
US (1) US20070114156A1 (fr)
EP (1) EP1954785A4 (fr)
JP (1) JP5396084B2 (fr)
CN (1) CN101313053B (fr)
BR (1) BRPI0618818A2 (fr)
CA (1) CA2630340C (fr)
WO (1) WO2007061701A1 (fr)

Families Citing this family (22)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
BRPI0601787B1 (pt) * 2006-05-17 2016-06-07 Petroleo Brasileiro Sa processo de hidrodessulfurização seletiva de nafta
US8753504B2 (en) 2011-04-28 2014-06-17 Battelle Memorial Institute Systems and processes for removing elemental sulfur compounds from desulfurized fuels
US8828218B2 (en) * 2011-10-31 2014-09-09 Exxonmobil Research And Engineering Company Pretreatment of FCC naphthas and selective hydrotreating
FR3020376B1 (fr) * 2014-04-28 2017-10-20 Ifp Energies Now Procede de production d'une essence a basse temperature en soufre et en marcaptans.
EP2816094B1 (fr) 2013-06-19 2020-04-29 IFP Energies nouvelles Procédé de production d'une essence à basse teneur en soufre et en mercaptans
FR3007416B1 (fr) * 2013-06-19 2018-03-23 IFP Energies Nouvelles Procede de production d'une essence a basse teneur en soufre et en mercaptans
JP6600912B2 (ja) * 2013-10-11 2019-11-06 コスモ石油株式会社 重質炭化水素油の水素化処理触媒及び重質炭化水素油の水素化処理触媒の製造方法
US10144883B2 (en) 2013-11-14 2018-12-04 Uop Llc Apparatuses and methods for desulfurization of naphtha
US9850435B2 (en) 2014-08-26 2017-12-26 Exxonmobil Research And Engineering Company Hydroprocessing with drum blanketing gas compositional control
CN105602618B (zh) * 2014-11-19 2017-08-25 中国海洋石油总公司 一种汽油选择性加氢脱硫的方法
CN105363481A (zh) * 2015-11-20 2016-03-02 洛阳金达石化有限责任公司 一种超低芳烃白油加氢精制催化剂的制备方法
FR3049955B1 (fr) 2016-04-08 2018-04-06 IFP Energies Nouvelles Procede de traitement d'une essence
FR3057578B1 (fr) 2016-10-19 2018-11-16 IFP Energies Nouvelles Procede d'hydrodesulfuration d'une essence olefinique.
SG11201906393TA (en) 2017-02-21 2019-09-27 Exxonmobil Res & Eng Co Desulfurization of a naphtha boiling range feed
FR3099175B1 (fr) 2019-07-23 2021-07-16 Ifp Energies Now Procédé de production d'une essence a basse teneur en soufre et en mercaptans
FR3099172B1 (fr) 2019-07-23 2021-07-16 Ifp Energies Now Procede de traitement d'une essence par separation en trois coupes
FR3099173B1 (fr) 2019-07-23 2021-07-09 Ifp Energies Now Procédé de production d'une essence a basse teneur en soufre et en mercaptans
FR3099174B1 (fr) 2019-07-23 2021-11-12 Ifp Energies Now Procédé de production d'une essence a basse teneur en soufre et en mercaptans
FR3104602A1 (fr) 2019-12-17 2021-06-18 IFP Energies Nouvelles Procédé d’hydrodésulfuration de finition en présence d’un catalyseur obtenu par la voie sels fondus
FR3108333B1 (fr) 2020-03-20 2022-03-11 Ifp Energies Now Procédé de production d'une essence a basse teneur en soufre et en mercaptans
FR3130834A1 (fr) 2021-12-20 2023-06-23 IFP Energies Nouvelles Procédé de traitement d'une essence contenant des composés soufrés
FR3130831A1 (fr) 2021-12-20 2023-06-23 IFP Energies Nouvelles Procédé de production d'une coupe essence légère à basse teneur en soufre

Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3349027A (en) * 1965-02-08 1967-10-24 Gulf Research Development Co Multi-stage hydrodesulfurization process
US4132632A (en) * 1978-03-31 1979-01-02 Standard Oil Company (Indiana) Selective hydrodesulfurization of cracked naphtha
EP0755995A1 (fr) * 1995-07-26 1997-01-29 Mitsubishi Oil Co., Ltd. Procédé de désulfuration d'essence craquée catalytiquement
US5846406A (en) * 1996-03-22 1998-12-08 Texaco Inc Selective hydrodesulfurization of cracked naphtha using novel manganese oxide octahedral molecular sieve supported catalysts
WO2001079391A1 (fr) * 2000-04-18 2001-10-25 Exxonmobil Research And Engineering Company Hydrocraquage et elimination selectifs de mercaptans
WO2005033930A2 (fr) * 2003-10-02 2005-04-14 Exxonmobil Research And Engineering Company Procede de valorisation du naphte
US20050252831A1 (en) * 2004-05-14 2005-11-17 Dysard Jeffrey M Process for removing sulfur from naphtha

Family Cites Families (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5597476A (en) * 1995-08-28 1997-01-28 Chemical Research & Licensing Company Gasoline desulfurization process
US6231753B1 (en) * 1996-02-02 2001-05-15 Exxon Research And Engineering Company Two stage deep naphtha desulfurization with reduced mercaptan formation
US6387249B1 (en) * 1999-12-22 2002-05-14 Exxonmobil Research And Engineering Company High temperature depressurization for naphtha mercaptan removal
JP4681794B2 (ja) * 1999-12-22 2011-05-11 エクソンモービル リサーチ アンド エンジニアリング カンパニー ナフサメルカプタン除去のための高温減圧
US6495030B1 (en) * 2000-10-03 2002-12-17 Catalytic Distillation Technologies Process for the desulfurization of FCC naphtha
US6913688B2 (en) * 2001-11-30 2005-07-05 Exxonmobil Research And Engineering Company Multi-stage hydrodesulfurization of cracked naphtha streams with interstage fractionation
US7297251B2 (en) * 2002-05-21 2007-11-20 Exxonmobil Research And Engineering Company Multi-stage hydrodesulfurization of cracked naphtha streams with a stacked bed reactor

Patent Citations (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3349027A (en) * 1965-02-08 1967-10-24 Gulf Research Development Co Multi-stage hydrodesulfurization process
US4132632A (en) * 1978-03-31 1979-01-02 Standard Oil Company (Indiana) Selective hydrodesulfurization of cracked naphtha
EP0755995A1 (fr) * 1995-07-26 1997-01-29 Mitsubishi Oil Co., Ltd. Procédé de désulfuration d'essence craquée catalytiquement
US5906730A (en) * 1995-07-26 1999-05-25 Mitsubishi Oil Co., Ltd. Process for desulfurizing catalytically cracked gasoline
US5846406A (en) * 1996-03-22 1998-12-08 Texaco Inc Selective hydrodesulfurization of cracked naphtha using novel manganese oxide octahedral molecular sieve supported catalysts
WO2001079391A1 (fr) * 2000-04-18 2001-10-25 Exxonmobil Research And Engineering Company Hydrocraquage et elimination selectifs de mercaptans
WO2005033930A2 (fr) * 2003-10-02 2005-04-14 Exxonmobil Research And Engineering Company Procede de valorisation du naphte
US20050252831A1 (en) * 2004-05-14 2005-11-17 Dysard Jeffrey M Process for removing sulfur from naphtha

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
See also references of WO2007061701A1 *

Also Published As

Publication number Publication date
WO2007061701A1 (fr) 2007-05-31
CA2630340A1 (fr) 2007-05-31
BRPI0618818A2 (pt) 2016-09-13
JP2009517499A (ja) 2009-04-30
JP5396084B2 (ja) 2014-01-22
US20070114156A1 (en) 2007-05-24
CN101313053A (zh) 2008-11-26
EP1954785A4 (fr) 2011-06-22
CA2630340C (fr) 2015-12-22
CN101313053B (zh) 2012-01-25

Similar Documents

Publication Publication Date Title
CA2630340C (fr) Hydrodesulfuration selective du naphta avec decomposition des mercaptans a haute temperature
CA2593062C (fr) Hydrodesulfuration selective et processus de decomposition du thiol avec separation des etapes intermediaires
US7297251B2 (en) Multi-stage hydrodesulfurization of cracked naphtha streams with a stacked bed reactor
EP1238042A1 (fr) Desulfuration poussee de naphta en deux etapes avec formation reduite de mercaptans
CA2467879C (fr) Hydrodesulfuration a plusieurs etapes de flux de naphtha a craquer presentant une etape intermediaire de fractionnement
CA2480168C (fr) Hydrodesulfuration selective de flux de naphtha
WO2005019387A1 (fr) Production de flux de naphta faible en soufre par adoucissement et fractionnement combines avec une alkylation de thiofene
JP5581396B2 (ja) 脱硫前に捕捉触媒を用いてヒ素を除去するための方法

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

17P Request for examination filed

Effective date: 20080610

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HU IE IS IT LI LT LU LV MC NL PL PT RO SE SI SK TR

A4 Supplementary search report drawn up and despatched

Effective date: 20110523

RIC1 Information provided on ipc code assigned before grant

Ipc: C10G 45/00 20060101AFI20070720BHEP

Ipc: C10G 67/02 20060101ALI20110517BHEP

17Q First examination report despatched

Effective date: 20120511

DAX Request for extension of the european patent (deleted)
STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE APPLICATION HAS BEEN WITHDRAWN

18W Application withdrawn

Effective date: 20170719