US20060151359A1 - Naphtha desulfurization process - Google Patents

Naphtha desulfurization process Download PDF

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US20060151359A1
US20060151359A1 US11/177,809 US17780905A US2006151359A1 US 20060151359 A1 US20060151359 A1 US 20060151359A1 US 17780905 A US17780905 A US 17780905A US 2006151359 A1 US2006151359 A1 US 2006151359A1
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process
sulfur
feedstock
hydrogen
catalyst
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Edward Ellis
Thomas Halbert
Gordon Stuntz
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ExxonMobil Research and Engineering Co
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ExxonMobil Research and Engineering Co
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    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING 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
    • C10G25/00Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents
    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING 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
    • C10G19/00Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment
    • C10G19/02Refining hydrocarbon oils in the absence of hydrogen, by alkaline treatment with aqueous alkaline solutions
    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G45/00Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/02Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
    • C10G45/04Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used
    • C10G45/06Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof
    • C10G45/08Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof in combination with chromium, molybdenum, or tungsten metals, or compounds thereof
    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING 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
    • C10G67/00Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
    • C10G67/02Treatment 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
    • C10G67/06Treatment 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 including a sorption process as the refining step in the absence of hydrogen
    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING 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
    • C10G67/00Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
    • C10G67/02Treatment 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
    • C10G67/10Treatment 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 including alkaline treatment as the refining step in the absence of hydrogen
    • BPERFORMING OPERATIONS; TRANSPORTING
    • B01PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01JCHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/76Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36
    • B01J23/84Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper combined with metals, oxides or hydroxides provided for in groups B01J23/02 - B01J23/36 with arsenic, antimony, bismuth, vanadium, niobium, tantalum, polonium, chromium, molybdenum, tungsten, manganese, technetium or rhenium
    • B01J23/85Chromium, molybdenum or tungsten
    • B01J23/88Molybdenum
    • B01J23/882Molybdenum and cobalt
    • BPERFORMING OPERATIONS; TRANSPORTING
    • B01PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01JCHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J35/00Catalysts, in general, characterised by their form or physical properties
    • B01J35/002Catalysts characterised by their physical properties
    • BPERFORMING OPERATIONS; TRANSPORTING
    • B01PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01JCHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J35/00Catalysts, in general, characterised by their form or physical properties
    • B01J35/02Solids
    • B01J35/10Solids characterised by their surface properties or porosity
    • B01J35/1052Pore diameter
    • B01J35/10612-50 nm
    • BPERFORMING OPERATIONS; TRANSPORTING
    • B01PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01JCHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J37/00Processes, in general, for preparing catalysts; Processes, in general, for activation of catalysts
    • B01J37/20Sulfiding
    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING 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
    • C10G2400/00Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/02Gasoline

Abstract

This invention relates to a process for selectively desulfurizing naphtha. More particularly, a low sulfur naphtha feed containing less than 500 wppm sulfur is hydrodesulfurized using a hydrodesulfurization catalyst and a hydrogen treat gas containing at least about 50 vppm hydrogen sulfide followed by mercaptan removal or conversion.

Description

    FIELD OF THE INVENTION
  • This invention relates to a process for selectively desulfurizing naphtha. More particularly, a low sulfur naphtha feed is hydrodesulfurized using a hydrodesulfurization catalyst and a hydrogen treat gas containing hydrogen sulfide followed by mercaptan removal or conversion.
  • BACKGROUND OF THE INVENTION
  • Environmental regulations covering the sulfur content of fuels for internal combustion engines are becoming more stringent with regard to allowable sulfur in fuels. It is anticipated that motor gasoline sulfur content may need to meet a sulfur limit of 30 wppm with possible further mandated reductions. The feedstocks for motor gasoline are typically catalytically cracked naphthas, which contain substantial amounts of sulfur and olefins.
  • A common method for reducing the sulfur content of feedstocks is by hydrotreating using catalysts that convert sulfur-containing species to hydrogen sulfide. The extent to which hydrotreating lowers the sulfur content of the hydrotreated product is typically dependent on the catalyst and hydrotreating conditions. For any given hydrotreating catalyst, the more severe hydrotreating conditions would be expected to reduce the sulfur content to the greater extent. However, such severe hydrotreating conditions normally result in a loss of molecules contributing to desirable octane properties either by cracking to non-fuel molecules or hydrogenation of olefins to molecules having lower octane rating. As the hydrotreating catalyst ages, it normally becomes necessary to adjust reaction conditions to maintain an acceptable catalyst activity. However, such adjustments result in further loss of desirable molecules contributing to high octane. This then results in increased production costs to produce high octane fuels because of the need to boost octane through added process steps such as isomerization, blending or addition of octane boosting additives.
  • One approach to addressing the problems associated with conventional hydrotreating is to use selective hydrodesulfurization, i.e., hydrodesulfurizing a feed with selective catalysts, selective process conditions, or both, to remove organosulfur while minimizing hydrogenation of olefins and octane reduction. For example, ExxonMobil Corporation's SCANfining® process selectively desulfurizes cat naphthas with little or no loss in octane number. U.S. Pat. Nos. 5,985,136; 6,013,598; and 6,126,814, all of which are incorporated by reference herein, disclose various aspects of SCANfining®. Although selective hydrodesulfurization processes have been developed to avoid significant olefin saturation and loss of octane, H2S liberated in the process can react with retained olefins to form mercaptan sulfur by reversion. Such mercaptans are often referred to as “recombinant” or “reversion” mercaptans.
  • A special situation is created when the feed naphtha has a low sulfur content. While such low sulfur feeds may appear to be more desirable if the target is a lower sulfur containing motor gasoline product, there is a further consideration relating to catalyst activity. Hydrotreating catalysts used for hydrodesulfurization are normally used in a sulfided state. Sulfided catalysts are generally more stable with regard to catalyst deactivation as compared to their non-sulfided counterparts. The use of such catalysts in a low sulfur feed may lead to catalyst deactivation with attendant loss in catalyst activity and selectivity.
  • There is a need in the art to stabilize hydrotreating catalyst activity used with low sulfur feeds to minimize costly turnarounds associated with catalyst deactivation.
  • SUMMARY OF THE INVENTION
  • It has been discovered that a low sulfur naphtha feed can be hydrodesulfurized while maintaining catalyst activity. The present invention relates to a process for hydrodesulfurizing a low sulfur naphtha feedstock, which process comprises: contacting the feedstock containing less than about 500 wppm sulfur, based on feedstock, and greater than about 20 wt. % olefins, based on feedstock, in a first reaction stage under hydrodesulfurization conditions including a hydrogen treat gas provided that the hydrogen treat gas contains at least about 50 vppm of hydrogen sulfide, based on hydrogen, provided that the hydrogen sulfide may be in the form of a precursor spiking agent in at least one of the feedstock or hydrogen treat gas, with a catalyst comprising at least one Group VIB metal and at least one Group VIII metal on an inorganic refractory support material to yield a first stage reaction product having less than about 50 wppm non-mercaptan sulfur, based on reaction product, and a mercaptan sulfur to non-mercaptan sulfur ratio of greater than 1:1; and passing the first stage product to a second stage wherein mercaptan sulfur is at least partially removed or converted from the first stage product to obtain a second stage product having a reduced amount of mercaptan sulfur.
  • In another embodiment, the present invention relates to a process for hydrodesulfurizing a low sulfur naphtha feedstock, which process comprises: contacting the feedstock containing less than about 500 wppm sulfur and greater than about 20 wt. % olefins, based on feedstock, in a first reaction stage under hydrodesulfurization conditions including a hydrogen treat gas provided that the hydrogen treat gas contains at least about 50 vppm of hydrogen sulfide, based on hydrogen, with a catalyst comprising: (a) about 1 to 10 wt % MoO3; (b) about 0.1 to 5 wt. % CoO; (c) a Co/Mo atomic ratio of about 0.1 to 1.0; (d) a median pore diameter of about 75 Å to 175 Å; (e) a MoO3 surface concentration in g MoO3/m2 of about 0.5×10−4 to 3×10−4; (f) an average particle size diameter of less than about 2.0 mm; (g) a metal sulfide edge plane area of from about 760 to 2800 μmol oxygen/g MoO3 as measured by oxygen chemisorption; and (h) an inorganic refractory support material; and passing the first stage product to a second stage wherein mercaptan sulfur is at least partially removed or converted from the first stage product to obtain a second stage product having a reduced amount of mercaptan sulfur.
  • BRIEF DESCRIPTION OF THE DRAWING
  • The FIGURE is a graph showing RCA HDS vs. days on oil for a low sulfur feed and a DMDS-spiked higher sulfur feed.
  • DETAILED DESCRIPTION OF THE INVENTION
  • The feedstock used in the present process are naphthas having a low sulfur content and an olefins content of at least about 20 wt. %, preferably at least about 30 wt. %, based on feedstock. By “low sulfur” is meant a feed containing less than about 500 wppm sulfur, based on feed. The cat naphtha feeds employed are those having a boiling range from about 18° C. to about 221° C. (65° F. to 430° F.). The naphtha can be any stream predominantly boiling in the naphtha boiling range and containing olefins, for example, a thermally cracked or a catalytically cracked naphtha. Such streams can be derived from any appropriate source, for example, they can be derived from the fluid catalytic cracking (“FCC”) of gas oils and resids, from delayed or fluid coking of resids, and from steam cracking and related processes. Such naphtha typically contains hydrocarbon species such as paraffins, olefins, naphthenes, and aromatics. These naphthas also typically contain species having heteroatoms such as sulfur and nitrogen. Heteroatom species include, for example, mercaptans and thiophenes. Significant amounts of such heteroatom species may be present.
  • FCC cat naphtha typically contains 20 to 40 wt. % olefins, based on the weight of the cat naphtha. Of these olefins, C5 olefins are typically present as 20%. to about 30% of the total amount of olefins, and combined C5 and C6 olefin content is typically about 45% to about 65% of the total C5+ olefins present.
  • The cat naphtha feed may be separated by methods such as splitting and fractionation in order to provide at least a light cat naphtha fraction and a heavy cat naphtha fraction. The separation cut point between the light and heavy fraction is regulated so that a substantial amount of the mercaptan and olefins having fewer than six carbons (“C6 ”) are present in the light fraction and a substantial amount of the thiophene and the olefins having 6 or more carbons (“C6 +”) are present in the heavy fraction.
  • Accordingly, the cut point is regulated so that light fraction boils in the range of about 18° C. to about 74° C. (65° F. to 165° F.), preferably from about 18° C. to about 66° C. (65° F. to 150° F.), and more preferably in the range of about 18° C. to about 46° C. (65° F. to 115° F.). The heavy fraction may have a boiling point in the range of about 74° C. to about 221° C. (165° F. to 430° F.), preferably about 79° C. to about 221° C. (175° F. to 430° F.). Those skilled in the art are aware that hydrocarbon separations having precise cut points are difficult to obtain and, consequently, some overlap in the boiling points of the light and heavy fractions may occur near the cut point. Even so, the light fraction will typically contain more than 50% of the C5 olefins contained in the cat naphtha feed. The heavy fraction will typically contain more than 50% of the C6 olefin contained in the cat naphtha feed. For an FCC cat naphtha, about 10 wt. % to about 40 wt. % of the total weight of the cat naphtha is in the light fraction and about 90 wt. % to about 60 wt. % of the total weight of the cat naphtha is in the heavy fraction.
  • The light fraction can be processed to remove sulfur while preserving the olefin content to maintain octane number. Accordingly, the light fraction is desulfurized via a non-hydrotreating process (i.e., a process employing no more than 50 psig (446 kPa) hydrogen partial pressure) to remove sulfur species such as mercaptan. The desulfurized light fraction has a sulfur content of less than about 500 wppm, preferably less than 50 wppm, based on the weight of the light fraction. A substantial portion of the olefins in the light fraction (mostly C5 olefins and some C6 olefins) can be preserved during sulfur removal. Preferably more than 75% of the C5 olefins are retained following sulfur removal, more preferably more than 90%, based on the total weight of C5 olefins in the light fraction. MEROX™ and EXTRACTIVE MEROX™, Universal Oil Products, Des Plaines, Ill., are suitable processes for removing sulfur while preserving olefin content, as are sulfur absorption processes set forth, for example, in U.S. Pat. No. 5,843,300. It should be noted that such processes are representative, and that any non-hydrotreating process capable of removing sulfur to a level lower than 500 ppm can be employed. The preparation of low sulfur naphthas is further described in U.S. published application 20020084211, which is incorporated herein by reference.
  • Hydrodesulfurization catalysts are those containing at least one Group VIB metal (based on the Periodic Table of the Elements published by the Sargent-Welch Scientific Company) and at least one Group VIII metal on an inorganic refractory support material. Preferred Group VIB metals include Mo and W and preferred Group VIII metals are non-noble metals including Ni and Co. The terms “hydrotreating” or “hydrodesulfurization” may be considered as interchangeable. The amount of metal, either individually or as mixtures, ranges from about 0.5 to 35 wt. %, based on catalyst. In the case of mixtures, the Group VIII metals are preferably present in amounts of 0.5 to 5 wt. % and the Group VIB metals in amounts of from 5 to 30 wt. %. The hydrodesulfurization catalysts may also be bulk metal catalysts wherein the amount of metal is 30 wt. % or greater, based on catalyst.
  • Any suitable inorganic oxide support material may be used for the hydrotreating catalyst. Non-limiting examples of suitable support materials include: alumina, silica, silica-alumina, titania, calcium oxide, strontium oxide, barium oxide, magnesium oxide, carbon, zirconia, diatomaceous earth, lanthanide oxides including cerium oxide, lanthanum oxide, neodynium oxide, yttrium oxide and praesodynium oxide, oxides of chromium, thorium, uranium, niobium and tantalum, tin oxide, zinc oxide, and aluminum phosphate. Preferred supports are alumina, silica, and silica-alumina. More preferred is alumina.
  • A preferred catalyst which exhibits high hydrodesulfurization activity while minimizing olefin saturation is a Mo/Co catalyst having the following properties, including (a) a MoO3 concentration of about 1 to 10 wt. %, preferably about 2 to 8 wt. %, and more preferably about 4 to 6 wt. %, based on the total weight of the catalyst; (b) a CoO concentration of about 0.1 to 5 wt. %, preferably about 0.5 to 4 wt. %, and more preferably about 1 to 3 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 pore diameter of about 60 to about 200 Å., preferably from about 75 Å. to about 175 Å, and more preferably from about 80 Å to about 150 Å; (e) a MoO3 surface concentration of about 0.5×10−4 to about 3×10−4 g. MoO3/m2, preferably about 0.75×10−4 to about 2.5×10−4, more preferably from about 1×10−4 to about 2×10−4; and (f) an average particle size diameter of less than 2.0 mm, preferably less than about 1.6 mm, more preferably less than about 1.4 mm, and most preferably as small as practical for a commercial hydrodesulfurization process unit.
  • Hydrodesulfurization (HDS) of the low sulfur naphtha feedstocks may be carried out under the following conditions: temperatures of from 232 to 371° C. (450 to 700° F.), preferably 260 to 329° C. (500 to 625° F.), pressure (total) of from 1480 to 2514 kPa (200 to 350 psig), preferably 1480 to 2169 kPa (200 to 300 psig), liquid hourly space velocities of from 0.1 to 15, preferably 0.5 to 10, and hydrogen treat gas rates of from 36 to 1780 m3/m3 (200 to 10,000 scf/B), preferably 178 to 540 m3/m3 (1000 to 3000 scf/B).
  • In the usual HDS process with feeds containing greater than 500 wppm sulfur, hydrogen sulfide would be stripped from hydrogen treat gas as HDS creates hydrogen sulfide from sulfur-containing species in the feed. The hydrogen sulfide is then treated as a contaminant and stripped from the hydrotreated feed. In the case of a low sulfur feed, applicants have discovered that using hydrogen treat gas that contains at least about 50 vppm hydrogen sulfide based on hydrogen treat gas, preferably at least about 100 vppm, more preferably at least about 200 vppm, stabilizes the HDS catalyst against deactivation. The hydrogen sulfide may be provided directly by a spiking agent added either directly to the hydrogen treat gas or to the feedstock. Spiking agents which may serve as a hydrogen sulfide precursor include at least one of carbon disulfide, thiophene, mercaptan, organic sulfide, dialkyl disulfide, diaryl disulfide and organic polysulfide, preferably dimethyl sulfide or dimethyl disulfide. While not wishing to be bound to any theory, the typical feed to the HDS process contains greater than 500 wppm sulfur. Thus for the typical feed, there is sufficient hydrogen sulfide created by the HDS process to maintain the activity of the sulfided HDS catalyst during the HDS process. In the case of low sulfur feeds, there may be insufficient hydrogen sulfide present to maintain catalyst activity of the sulfided HDS catalyst and hence the catalyst may undergo deactivation.
  • In one embodiment, the HDS reactor may be preceded by a diolefin reactor. The purpose of the diolefin reactor is to convert diolefins to monoolefins. Diolefins may be subject to a polymerization reaction and such polymerization reactions may be avoided by partially saturating the diolefin to a monoolefin. A preferred catalyst for the saturation reaction is sulfided Ni/Mo.
  • The hydrogen sulfide in the processed naphtha, whether present by direct addition to the hydrogen treat gas or liberated in the process, can react with retained olefins to form mercaptan sulfur by reversion. Such mercaptans are often referred to as “recombinant” or “reversion” mercaptans. In the present process, such mercaptans are removed or converted.
  • Caustic extraction is a non-hydrotreating process capable of extracting mercaptan sulfur. Commercially available process include MEROX™ or EXTRACTIVE MEROX™, Universal Oil Products, Des Plains, Ill., and those offered by Merichem, Houston, Tex. Such processes use an iron-based catalyst that is soluble in caustic, or in the alternative supported on a support, to oxidize mercaptans. Mercaptans in the naphtha are converted to sodium salts which, in the presence of a catalyst, are oxidized to form disulfides. The disulfides are not soluble in the caustic solution and can be separated therefrom. Examples of other catalysts that can be used for mercaptan removal include phthalocyanine and metal chelates.
  • The conditions for the extraction step utilized herein can be easily selected by the skilled artisan. Preferably, the conditions utilized will be those described in U.S. Pat. No. 4,626,341 herein incorporated by reference. For example, the conditions employed in the extraction zone may vary greatly depending on such factors as the nature of the hydrocarbon stream being treated and its mercaptan content, etc. The skilled artisan can readily select such conditions with reference to the applicable art. However, in general, the mercaptan extraction may be performed at a temperature above about 15° C. (60° F.) and at a pressure sufficient to ensure liquid state operation.
  • Another method for reducing the sulfur content of a liquid hydrocarbon is by the extraction of the acidic species such as mercaptans, particularly reversion mercaptans, from the hydrocarbon to an aqueous treatment solution where the mercaptans subsist as mercaptides, and then separating a treated hydrocarbon substantially reduced in mercaptans from the treatment solution while curtailing treatment solution entrainment in the treated hydrocarbon. Preferably, the extraction of the mercaptans from the hydrocarbon to the treatment solution is conducted under anaerobic conditions, i.e., in the substantial absence of added oxygen.
  • The treatment solution may be prepared by combining alkali metal hydroxide, alkylphenols, sulfonated cobalt pthalocyanine, and water. The amounts of the constituents may be regulated so that the treatment solution forms two substantially immiscible phases, i.e., a less dense, homogeneous, top phase of dissolved alkali metal hydroxide, alkali metal alkylphenylate, and water, and a more dense, homogeneous, bottom phase of dissolved alkali metal hydroxide and water. An amount of solid alkali metal hydroxide may be present, preferably a small amount (e.g., 10 wt. % in excess of the solubility limit), as a buffer, for example. When the treatment solution contains both top and bottom phases, the top phase is frequently referred to as the extractant or extractant phase. The top and bottom phases are liquid, and are substantially immiscible in equilibrium in a temperature ranging from about 27° C. to about 66° C. (80° F. to 150° F.) and a pressure range of about ambient (zero psig) to about 1480 kPa (200 psig). The phases formed for a treatment solution formed from potassium hydroxide, water, and alkylphenols may be represented by phase diagrams.
  • A two-phase treatment solution is combined with the hydrocarbon to be treated and allowed to settle. Following settling, less dense treated hydrocarbon is located above the top phase, and may be separated. Alternatively, the top and bottom phases are separated before the top phase (extractant) contacts the hydrocarbon. All or a portion of the top phase may be regenerated following contact with the hydrocarbon and returned to the process for re-use. For example, the regenerated top phase may be returned to the treatment solution prior to top phase separation, where it may be added to either the top phase, bottom phase, or both. Alternatively, the regenerated top phase may be added to the either top phase, bottom phase, or both subsequent to the separation of the top and bottom phases.
  • With very light material in the feed stream, this may be impractical and the extraction is performed with a vapor phase feed stream. The pressure may range from atmospheric up to 6996 kPa (1000 psig) or more, but a pressure in the range of from about 1100 to 2485 kPa (145 to about 348 psig) is preferred.
  • Once the petroleum stream having organo sulfur and mercaptans removed therefrom is separated from the used extractant mixture, the used extractant mixture can be recycled to extract a fresh petroleum containing mercaptan or hydroprocessed petroleum stream or regenerated to remove mercaptans and the base. Regeneration of the spent base can occur using either steam stripping as described in The Oil and Gas Journal, Sep. 9, 1948, pp. 95-103, or oxidation followed by extraction into a hydrocarbon stream.
  • Typically regeneration of the mercaptan-containing used extractant is accomplished by mixing the stream with an air stream supplied at a rate which provides at least the stoichiometric amount of oxygen necessary to oxidize the mercaptans in the caustic stream. The air or other oxidizing agent is well admixed with the base, and the mixed-phase admixture is then passed into the oxidation zone. The oxidation of the mercaptans is promoted through the presence of a catalytically effective amount of an oxidation catalyst capable of functioning at the conditions found in the oxidizing zone. Several suitable catalytic materials are known in the art.
  • Preferred as a catalyst is a metal phthalocyanine such as cobalt phthalocyanine or vanadium phthalocyanine, etc. Higher catalytic activity may be obtained through the use of a polar derivative of the metal phthalocyanine, especially the monosulfo, disulfo, trisulfo, and tetrasulfo derivatives. The preferred oxidation catalysts may be utilized in a form which is soluble or suspended in the alkaline solution or it may be placed on a solid carrier material. If the catalyst is present in the solution, it is preferably cobalt or vanadium phthalocyanine disulfonate at a concentration of from about 5 to 1000 wppm, based on solution. Carrier materials should be highly absorptive and capable of withstanding the alkaline environment. Activated charcoals have been found very suitable for this purpose, and either animal or vegetable charcoals may be used. The carrier material is to be suspended in a fixed bed, which provides efficient circulation of the caustic solution. Preferably the metal phthalocyanine compound comprises about 0.1 to 2.0 wt. % of the final composite.
  • The oxidation conditions utilized include a pressure of from atmospheric to about 6996 kPa (1000 psig). This pressure is normally less than 600 kPa (72.5 psig). The temperature may range from ambient to about 95° C. (203° F.) when operating near atmospheric pressure and to about 205° C. (401° F.) when operating at superatmospheric pressures. In general, it is preferred that a temperature within the range of about 38 to about 80° C. is utilized.
  • To separate the mercaptans from the base, the pressure in the phase separation zone may range from atmospheric to about 2170 kPa (300 psig) or more. The temperature in this zone is confined within the range of from about 10 to about 120° C. (50 to 248° F.), and preferably from about 26 to 54° C. The phase separation zone is sized to allow the denser caustic mixture to separate by gravity from the disulfide compounds. This may be aided by a coalescing means located in the zone. The above describes one possible method for regenerating used extractant. Other methods known to the skilled artisan may also be employed.
  • An alternative method for removing mercaptans is adsorption. The adsorption process typically involves adsorption followed by desorption to remove any adsorbed contaminant and regeneration of the adsorbent. Adsorbents include activated carbon optionally including a catalyst, aluminas such as SELEXSORB™ manufactured by ALCOA, zeolites and combinations thereof. Typical zeolites used as adsorbents are those containing relatively large pores (greater than 6 Å). Examples include faujasite, offretite, mordenite, zeolites X, Y and L, and zeolite beta. In batch operation, the adsorbent bed is contacted with the mercaptan-containing stream. The adsorbent bed becomes progressively saturated with pollutant and will normally be regenerated by contacting with hot gas. The pollutants are carried of with the hot gas and the adsorbent is recycled back to the adsorbent bed for further removal of pollutant. The adsorption process can also be continuous. In this process, the contaminant adsorbent is continuously adsorbed in one or more stages and the adsorbent regenerated and recycled. Such processes are described in U.S. Pat. No. 5,730,860 and U.S. Published Application 20020043501 herein incorporated by reference.
  • The adsorbent may be regenerated or desorbed by heating in one or more stages in the presence of a gas such as hydrogen or hydrogen-containing gas, nitrogen or other gas, which will not interfere with the adsorbing properties of the adsorbent. The spent adsorbent is typically contacted with gas heated to a temperature sufficient to cause desorption of adsorbed pollutants. The heated gas may be in counter- or cross-current flow to the spent adsorbent. The heated gas containing desorbed pollutants is sent to recovery zone where gas is separated and recycled to the regeneration zone and the regenerated adsorbent recycled to the adsorption zone.
  • The following non-limiting example serves to illustrate the invention.
  • EXAMPLE
  • A SCANfining® pilot unit was loaded with catalyst RT-225 which is commercially available from Exxon Mobil Coporation. The RT-225 catalyst contains 4.5 wt. % MoO3 and 1.2 wt. % CoO, on an alumina support. The catalyst was in a quadralobe shape and had a catalyst size of 1.3 mm. After a preliminary drying at 399° C. (750° F.) for 3 hours, the catalyst was loaded in a pilot unit and further dried at 371° C. (700° F.) for 6 hours. The catalyst was then sulfided using a 10 vol. % H2S in H2 mixture at an initial temperature of 93° C. (200° F.) and a final temperature of 343° C. (650° F.).
  • The catalyst was then activated using a straight run naphtha and a heavy cat naphtha used for catalyst break-in. Two feeds were then prepared for the low sulfur and high sulfur runs. The low sulfur feed was a naphtha blend having a total sulfur content of about 30 wppm, based on feed. The high sulfur feed had a total sulfur content of about 550 wppm and was prepared by spiking a low sulfur feed with dimethyl disulfide (DMDS). DMDS decomposes to H2S under reaction conditions.
  • The low sulfur and high sulfur feeds were then added to the pilot unit under the following conditions: temperatures from 274 to 285° C. (525 to 545° F.), pressure of 1894 kPa (260 psig), LHSV of 4 hr−1, and treat gas rate of 214 m3/m3 (1200 scf/b).
  • The hydrodesulfurization (HDS) relative catalyst activity (RCA) for the low sulfur feed shows a higher deactivation rate when compared to the DMDS-spiked high sulfur feed. This is shown in the FIGURE, which is a graph showing RCA vs. days on oil for the respective feeds. As can be seen from the FIGURE, the low-sulfur feed shows nearly twice the deactivation as the DMDS-spiked feed. This means that the spiked feed will have a much longer run length than the low-sulfur feed.

Claims (17)

1. A process for hydrodesulfurizing a low sulfur naphtha feedstock, which process comprises:
a) contacting the feedstock containing less than about 500 wppm sulfur, based on feedstock, and greater than about 20 wt. % olefins, based on feedstock, in a first reaction stage under hydrodesulfurization conditions including a hydrogen treat gas provided that the hydrogen treat gas contains at least about 50 vppm of hydrogen sulfide, based on hydrogen, and provided that the hydrogen sulfide may be in the form of a precursor spiking agent in at least one of the feedstock or hydrogen treat gas, with a catalyst comprising at least one Group VIB metal and at least one Group VIII metal on an inorganic refractory support material to yield a first stage reaction product having less than about 50 wppm non-mercaptan sulfur, based on reaction product, and a mercaptan sulfur to non-mercaptan sulfur ratio of greater than 1:1; and
b) passing the first stage product to a second stage wherein mercaptan sulfur is at least partially removed or converted from the first stage product to obtain a second stage product having a reduced amount of mercaptan sulfur.
2. The process of claim 1 wherein the hydrogen treat gas contains at least about 100 vppm hydrogen sulfide.
3. The process of claim 2 wherein the hydrogen treat gas contains at least about 200 vppm hydrogen sulfide.
4. The process of claim 1 wherein the spiking agent is at least one of carbon disulfide, thiophene, mercaptan, organic sulfide, dialkyl disulfide, diaryl disulfide and organic polysulfide.
5. The process of claim 4 wherein the spiking agent is dimethyl sulfide or dimethyl disulfide.
6. The process of claim 1 wherein the catalyst comprises: (a) about 1 to about 10 wt. % MoO3; (b) about 0.1 to about 5 wt. % CoO; (c) a Co/Mo atomic ratio of about 0.1 to about 1.0; (d) a median pore diameter of about 75 Å to about 175 Å; (e) a MoO3 surface concentration in g MoO3/m2 of about 0.5×10−4 to about 3×10−4; (f) an average particle size diameter of less than about 2.0 mm; (g) a metal sulfide edge plane area of from about 760 to about 2800 μmol oxygen/g MoO3 as measured by oxygen chemisorption; and (h) an inorganic refractory support material.
7. The process of claim 1 wherein the olefins content is at least about 30 wt. %, based on feedstock.
8. The process of claim 1 wherein the hydrodesulfurization conditions include temperatures of from about 232 to about 371° C., pressures (total) of from about 1480 to about 2514 kPa, liquid hourly space velocities of from about 0.1 to about 15, and hydrogen treat gas rates of from about 36 to about 1780 m3/m3.
9. The process of claim 1 wherein mercaptan sulfur is removed by caustic extraction.
10. The process of claim 9 wherein caustic extraction uses an iron-based catalyst that is soluble in caustic, or in the alternative supported on a support, to oxidize mercaptans.
11. The process of claim 1 wherein the mercaptan sulfur is extracted to an aqueous treatment solution and converted to mercaptides.
12. The process of claim 11 wherein the aqueous treatment solution combines alkali metal hydroxide, alkylphenols, sulfonated cobalt pthalocyanine, and water.
13. The process of claim 12 wherein the aqueous treatment solution forms two substantially immiscible phases which are a less dense, homogeneous, top phase of dissolved alkali metal hydroxide, alkali metal alkylphenylate, and water, and a more dense, homogeneous, bottom phase of dissolved alkali metal hydroxide and water.
14. The process of claim 13 wherein the two immiscible phase are combined with first stage product and allowed to settle.
15. The process of claim 1 wherein mercaptan sulfur is removed by adsorption.
16. The process of claim 1 wherein the feedstock has a boiling range from about 18° C. to about 221° C.
17. The process of claim 1 wherein the first reaction stage for hydrodesulfurization is preceded by a diolefin reactor.
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