US20030127362A1 - Selective hydroprocessing and mercaptan removal - Google Patents

Selective hydroprocessing and mercaptan removal Download PDF

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US20030127362A1
US20030127362A1 US10/273,834 US27383402A US2003127362A1 US 20030127362 A1 US20030127362 A1 US 20030127362A1 US 27383402 A US27383402 A US 27383402A US 2003127362 A1 US2003127362 A1 US 2003127362A1
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sulfur
mercaptan
naphtha
naphtha product
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Thomas Halbert
John Greeley
Robert Welch
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ExxonMobil Technology and Engineering Co
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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
    • 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
    • C10G67/04—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 including solvent extraction as the refining step in the absence of hydrogen
    • C10G67/0409—Extraction of unsaturated hydrocarbons
    • C10G67/0418—The hydrotreatment being a hydrorefining
    • 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
    • C10G67/12—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 including oxidation as the refining step in the absence of hydrogen
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L1/00—Liquid carbonaceous fuels
    • C10L1/02—Liquid carbonaceous fuels essentially based on components consisting of carbon, hydrogen, and oxygen only

Definitions

  • the present invention relates to a process for the production of naphtha streams from cracked naphthas having sulfur levels which help meet future EPA gasoline sulfur standards (30 ppm range and below).
  • step (b) above comprises separating hydrogen gas and hydrogen sulfide from said first naphtha product by using a separation device, such as a separation drum, to separate hydrogen and hydrogen sulfide from said first naphtha product, thence conducting the first naphtha product, which comprises the treated naphtha from the separation device to a monoethanolamine (MEA) scrubber to remove additional amounts of hydrogen sulfide, and conducting the removed hydrogen gas and hydrogen sulfide from the separation device to further processing.
  • MEA monoethanolamine
  • the MEA and non-mercaptan sulfur are conducted to other plant process for further treatment and regeneration of the MEA.
  • step (b) above comprises separating at least a portion of the hydrogen gas and hydrogen sulfide from the first naphtha product by using a separation device, such as a separation drum, to produce a second naphtha product depleted in hydrogen sulfide and hydrogen gas.
  • This second naphtha product is conducted to a monoethanolamine (MEA) scrubber to remove additional amounts of hydrogen sulfide.
  • MEA monoethanolamine
  • the removed hydrogen gas and hydrogen sulfide from the separation device can be further processed.
  • the MEA and non-mercaptan sulfur can be conducted to other plant process for further treatment and regeneration of the MEA.
  • the naphtha product from the MEA scrubber, the third naphtha product is conducted to a sweetening device to dimerize mercaptan to higher boiling disulfides which can then be removed by fractionation.
  • FIG. 1 depicts the mercaptan reversion limits HDS of HCN using an RT-225 catalyst.
  • the Y axis is product sulfur (wppm), product net product from mercaptans (wppm).
  • the X axis is percent olefin saturation.
  • FIG. 2 depicts the mercaptan reversion limits HDS of HCN using a KF-742 catalyst.
  • the Y axis is product sulfur (wppm), net product sulfur from mercaptans (wppm).
  • the X axis is percent olefin saturation.
  • Hydrodesulfurization (HDS) processes are well known in the art. During such processes, an additional reaction occurs whereby the hydrogen sulfide produced during the process reacts with feed olefins to form alkylmercaptans. This reaction is commonly referred to as mercaptan reversion. Thus, to prevent such mercaptan reversion requires saturation of feed olefins resulting in a loss of octane.
  • the amount of mercaptan sulfur in the reactor is controlled by the equilibrium established by the reactor exit temperature, exit olefin and 1-12S partial pressure, and that the SCANfining process can be run to produce an amount of mercaptan sulfur in the reactor that is often higher than the desired specification amount while removing non-mercaptan sulfur to an acceptable regulatory level.
  • regulatory sulfur levels can be met while retaining octane in the product produced.
  • non-mercaptan sulfur is meant to refer to organically bound sulfur species such as thiophenes, benzothiophenes, disulfides, etc., that are not a result of mercaptan reversion.
  • the product of the HDS unit which will have a mercaptan sulfur content well above the desired specification but an acceptable non-mercaptan sulfur level (pre-determined), will be sent to a mercaptan removal step where at least a portion of the mercaptans will be selectively removed, thereby, producing a product that meets specification.
  • intermediate cat naphtha can be hydroprocessed to 60 wppm total sulfur where approximately 45 wppm sulfur is mercaptan sulfur.
  • This first product would not meet the future 30 wppm sulfur specification.
  • This product would then be sent to a mercaptan removal step where the sulfur level would be reduced to approximately 20 wppm total sulfur, meeting the specification.
  • olefin saturation will be less than is obtained from hydroprocessing to 20 wppm directly.
  • considerable octane is preserved affording an economical and regulatory acceptable product.
  • cat naphtha and hydrogen are passed over a hydroprocessing catalyst where organic sulfur is converted to hydrogen sulfide and olefins are saturated to their corresponding paraffins.
  • naphtha >95% of the organic sulfur is in thiophene type structures.
  • the HDS conditions needed to produce a hydrotreated naphtha stream which contains non-mercaptan sulfur at a level below the mogas specification as well as significant amounts of mercaptan sulfur will vary as a function of the concentration of sulfur and types of organic sulfur in the cracked naphtha feed to the HDS unit.
  • the processing conditions will fall within the following ranges: 475-600° F. (246-316° C.), 150-500 psig (1136-3548 kPa) total pressure, 100-300 psig (7912170 kPa) hydrogen partial pressure, 1000-2500 SCFB hydrogen treat gas, and 110 LHSV.
  • the preferred hydroprocessing step to be utilized is SCANfining.
  • SCANfining is described in National Petroleum Refiners Association paper # AM-99-31 titled “Selective Cat Naphtha Hydrofining with Minimal Octane Loss” and U.S. Pat. Nos. 5,985,136 and 6,013,598 herein incorporated by reference.
  • Selective cat naphtha HDS is also described in U.S. Pat. Nos. 4,243,519 and 4,131,537.
  • Typical SCANfining conditions include one and two stage processes for hydrodesulfurizing a naphtha feedstock comprising reacting said feedstock in a first reaction stage under hydrodesulfurization conditions in contact with a catalyst comprised of about 1 to 10 wt. % Mo0 3 ; and about 0.1 to 5 wt.
  • the SCANfining reactor is run at sufficient conditions such that the difference between the total organic sulfur (determined by x-ray adsorption) and the mercaptan sulfur (determined by potentiometric test ASTM 3227) of the liquid product from the strippers is at or below the desired (target) specification (typically 30 ppm for non-mercaptan sulfur).
  • This stream is then sent to a second step for removal of mercaptans.
  • any technology known to the skilled artisan capable of removing >C5+mercaptan sulfur can be employed.
  • sweetening followed by fractionation, thermal decomposition, extraction, adsorption and membrane separation can be employed.
  • Other techniques which selectively remove C5+ mercaptan sulfur of the type produced in the first step may likewise be utilized.
  • step (c) of the instant process can be accomplished by sweetening followed by fractionation.
  • Such processes are commonly known in the art and are described, for example, in U.S. Pat. No. 5,961,819.
  • Processes relating to the treatment of sour distillate hydrocarbons are described in many patents.
  • U.S. Pat. Nos. 3,758,404; 3,977,829 and 3,992,156 describe mass transfer apparatus and processes involving the use of fiber bundles which are particularly suitable for such processes.
  • mercaptans are extracted from the feed and then oxidized by air in the caustic phase in the presence of the Merox catalyst, an iron group chelate (cobalt phthalocyanine) to form disulfides which are then redissolved in the hydrocarbon phase, leaving the process as disulfides in the hydrocarbon product.
  • iron group chelate cobalt phthalocyanine
  • mercaptans are removed by oxidation with cupric chloride which is regenerated with air which is introduced with the feed to oxidation step.
  • the mercaptan oxidation process chosen by the practitioner of the present invention is not critical, but the one chosen must convert at least a portion of the mercaptans to higher boiling disulfides which are transferred to the higher boiling fraction, boiling above about 480° F.
  • the higher boiling disulfides contained in the higher boiling fraction are then subjected to hydrogenative removal together with the thiophene and other forms of sulfur present in the higher boiling portion of the cracked feed. This fractionation also results in at least one lighter boiling point product, in relation to the heavy boiling point product, boiling below about 480° F.
  • step (c) Another method of removing the mercaptan sulfur in accordance with step (c) will employ a caustic mercaptan extraction step.
  • a combination of aqueous base and a phase transfer catalyst (PTC) known in the art will be utilized as the extractant or a sufficiently basic PTC.
  • PTC phase transfer catalyst
  • phase-transfer catalyst allows for the extraction of higher molecular weight mercaptans (>C5+) produced during hydrodesulfurization (HDS) into the aqueous caustic at a rapid rate.
  • the aqueous phase can then be separated from the petroleum stream by known techniques.
  • at least a portion of lower molecular weight mercaptans, if present, are also removed during the process.
  • Suitable phase transfer catalysts for use in the present invention can be either supported or unsupported.
  • the attachment of the PTC to a solid substrate facilitates its separation and recovery and reduces the likelihood of contamination of the product petroleum stream with PTC.
  • Typical materials used to support PTC are polymers, silicas, aluminas and carbonaceous supports.
  • the PTC and aqueous base extractant may be supported on or contained within the pores of a solid state material to accomplish the mercaptan extraction. After saturation of the supported PTC bed with mercaptide in the substantial absence of oxygen, the bed can be regenerated by flushing with air and a stripper solvent to wash away the disulfide which would be generated. If necessary, the bed could be re-activated with fresh base/PTC before being brought back on stream. This swing bed type of operation may be advantageous relative to liquid-liquid extractions in that the liquid-liquid separation steps would be replaced with solid/liquid separations typical of solid adsorbent bed technologies.
  • substantial absence of oxygen is required if seeking to remove mercaptans as opposed to sweetening the HDS product to disulfides.
  • substantial absence is meant no more than that amount of oxygen which will be present in a refinery process despite precautions to exclude the presence of oxygen.
  • 10 ppm or less, preferably 2 ppm or less oxygen will be the maximum amount present.
  • the process will be run in the absence of oxygen.
  • Such extractions include liquid-liquid extraction where aqueous base and water soluble PTC are utilized to accomplish the extraction, or basic aqueous PTC is utilized.
  • an “extractive” process whereby the thiols are first extracted from the petroleum feedstream in the substantial absence of air into an aqueous phase and the mercaptan-free petroleum feedstream is then separated from the aqueous phase and passed along for further refinery processing can be conducted.
  • the aqueous phase may then be subjected to aerial oxidation to form disulfides from the extracted mercaptans. Separation and disposal of the disulfide would allow for recycle of the aqueous extractant.
  • Regeneration of the spent caustic 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.
  • Such extractants are easily selected by the skilled artisan and can include for example a reformate stream.
  • the extraction step can be conducted in air; the loss of thiol is concurrent with generation of disulfide.
  • the thiol is transported from the organic phase into the aqueous phase, prior to conversion to disulfide then back into the petroleum phase. We have found this oxidation of mercaptide to disulfide to occur readily at room temperature without the addition of any other oxidation catalyst.
  • the extracting medium will consist essentially of aqueous base and PTC or aqueous basic PTC.
  • the porous supports may be selected from, molecular sieves, polymeric beads, carbonaceous solids and inorganic oxides for example.
  • a second adsorbent bed will be swung into operation. Regeneration of the first bed will be accomplished by introduction of oxygen (air) into the bed along with an organic phase which will provide a suitable extractant stream for the disulfide which should form upon oxidation of the mercaptide anions. Such extractants are easily chosen by the skilled artisan. Pressure and heat could be used to stimulate the oxidative process. If necessary, the stripped bed could be regenerated by re-saturation with fresh base/PTC solution before being swung back into operation. Neither the base nor the PTC are consumed in this process, other than by losses due to contaminants. The advantage of using a supported PTC is that the mercaptans are trapped within the pores of the support facilitating separation.
  • Bases utilizable in the extraction step are strong bases, such as, for example, sodium, potassium and ammonium hydroxide, and sodium and potassium carbonate, and mixtures thereof. These may be used as an aqueous solution of sufficient strength, typically base will be up to or equal to 50 wt. % of the aqueous medium, preferably about 15% to about 25 wt. % when used in conjunction with onium salt PTCs and about 30-50 wt. % when used in conjunction with polyethyleneglycol type PTCs.
  • strong bases such as, for example, sodium, potassium and ammonium hydroxide, and sodium and potassium carbonate, and mixtures thereof. These may be used as an aqueous solution of sufficient strength, typically base will be up to or equal to 50 wt. % of the aqueous medium, preferably about 15% to about 25 wt. % when used in conjunction with onium salt PTCs and about 30-50 wt. % when used in conjunction with polyethyleneglycol type PTCs.
  • the phase transfer catalyst is present in a sufficient concentration to result in a treated feed having a decreased mercaptan content.
  • a catalytically effective amount of the phase transfer catalyst will be utilized.
  • the phase transfer catalyst may be miscible or immiscible with the petroleum stream to be treated. Typically, this is influenced by the length of the hydrocarbyl chains in the molecule; and these may be selected by one skilled in the art. While this may vary with the catalyst selected, typically concentrations of about 0.01 to about 10 wt. %, preferably about 0.05 to about 1 wt. % based on the amount of aqueous solution will be used.
  • Phase transfer catalysts suitable for use in this process include the types of PTCs described in standard references on PTC, such as Phase Transfer Catalysis: Fundamentals, Applications and Industrial Perspectives by Charles M. Starks, Charles L. Liotta and Marc Halpern (ISBN 0-412-04071-9 Chapman and Hall, 1994). These reagents are typically used to transport a reactive anion from an aqueous phase into an organic phase in which it would otherwise be insoluble. This “phase-transferred” anion then undergoes reaction in the organic phase and the phase transfer catalyst then returns to the aqueous phase to repeat the cycle, and hence is a “catalytic” agent.
  • the PTC transports the hydroxide anion, —OH, into the petroleum stream, where it reacts with the thiols in a simple acid base reaction, producing the deprotonated thiol or thiolate anion.
  • This charged species is much more soluble in the aqueous phase and hence the concentration of thiol in the petroleum stream is reduced by this chemistry.
  • PTC PTC
  • onium salts such as quaternary ammonium and quaternary phosphonium halides, hydroxides and hydrogen sulfates for example.
  • the phase transfer catalyst is a quaternary ammonium hydroxide
  • the quaternary ammonium cation will preferably have the formula:
  • Cw, Cx, Cy, and Cz represent alkyl radicals with carbon chain lengths of w, x, y and z carbon atoms, respectively.
  • the preferred quaternary ammonium salts are the quaternary ammonium halides.
  • the four alkyl groups on the quaternary cation are typically alkyl groups with total carbons ranging from four to forty, but may also include cycloalkyl, aryl, and arylalkyl groups.
  • Some examples of useable onium cations are tetrabutyl ammonium, tetrabutylphosphonium, tributylmethyl ammonium, cetyltrimethyl ammonium, methyltrioctyl ammonium, and methyltricapryl ammonium.
  • PTC PTC have been found effective for hydroxide transfer.
  • crown ethers such as 18-crown-6 and dicyclohexano-18-crown-6 and open chain polyethers such as polyethyleneglycol 400.
  • open chain polyethers such as polyethyleneglycol 400.
  • Partially-capped and fully-capped polyethyleneglycols are also suitable. This list is not meant to be exhaustive but is presented for illustrative purposes. Supported or unsupported PTC and mixtures thereof are utilizable herein.
  • the amount of aqueous medium to be added to the petroleum stream being treated will range from about 5% to about 200% by volume relative to petroleum feed.
  • process temperatures for the extraction of from 25° C. to 180° C. are suitable, lower temperatures of less than 25° C. can be used depending on the nature of the feed and phase transfer catalyst used.
  • the pressure should be sufficient pressure to maintain the petroleum stream in the liquid state. Oxygen must be excluded, or be substantially absent, during the extraction and phase separation steps to avoid the premature formation of disulfides, which would then redissolve in the feed. Oxygen is necessary for a sweetening process.
  • the stream is then passed through the remaining refinery processes, if any.
  • the base and PTC or basic PTC may then be recycled for extracting additional mercaptans from a fresh hydrodesulfurized petroleum stream.
  • the mixture of PTC and base may consist essentially of or consist of PTC and base.
  • basic PTCs they may consist essentially of or consist of basic PTCs.
  • the invention will be practiced in the absence of any catalyst other than the phase transfer catalyst such as those used to oxidize mercaptans, e.g., metal chelates as described in U.S. Pat. Nos. 4,124,493; 4,156,641; 4,206,079; 4,290,913; and 4,337,147. Hence in such cases the PTC will be the only catalyst present.
  • the conditions under which the HDS unit is operated are chosen such that at least a portion of the organic sulfur species present in the feed (e.g., thiophenes, benzothiophenes, mercaptans, sulfides, disulfides and tetrahydrothiophenes) are substantially converted into hydrogen sulfide without significantly impacting olefin saturation.
  • the conditions chosen are sufficient to accomplish the conversion of organic sulfur in the feed. Olefin saturation will thus, only occur to the extent caused by the HDS organic sulfur conversion conditions.
  • the extractant mixture can then be recycled to extract a fresh hydroprocessed stream.
  • the preferred streams treated in accordance herewith are naphtha streams, more preferably, intermediate naphtha streams. Regeneration of the spent caustic 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.
  • regeneration of the inercaptan containing caustic stream is accomplished by mixing the stream with an air stream supplied at a rate which supplies 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 liquid caustic stream 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.
  • an oxidation catalyst capable of functioning at the conditions found in the oxidizing zone.
  • Preferred catalysts include 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 wt. ppm. 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.
  • 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 6895 kPag (1000 psig). This pressure is normally less than 500 kPag (72.5 psig).
  • the temperature may range from ambient to about 95 degrees Celsius (203 degrees Fahrenheit) when operating near atmospheric pressure and to about 205 degrees Celsius (401 degrees Fahrenheit) when operating at superatmospheric pressures. In general, it is preferred that a temperature within the range of about 38 to about 80 degrees Celsius is utilized.
  • the pressure in the phase separation zone may range from atmospheric to about 2068 kPag (300 psig) or more, but a pressure in the range of from about 65 to 300 kpag is preferred.
  • the temperature in this zone is confined within the range of from about 10 to about 120 degrees Celsius (50 to 248 degrees Fahrenheit), and preferably from about 26 to 54 degrees Celsius.
  • 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.
  • step (c) of the process involves catalytic decomposition.
  • the catalytic decomposition of mercaptans to form olefins and H2S at high temperature vapor conditions is well known in the art.
  • Simple, noncatalyzed thermal decomposition is well known to be quite slow for primary mercaptans (W. M. Malisoff and E. M. Marks, Industrial and Engineering Chemistry 1931, 23, pp. 1114-1120), requiring temperatures in excess of 400° C. in order to achieve greater than 10% conversion.
  • a catalyst is therefore preferred.
  • a wide variety of solid oxides are well known to catalyze this reaction. Typical materials utilized to catalyze this reaction are described in C. P. C. Bradshaw and L.
  • the catalyst may be selected from: alumina, silica, titania, Group IIA metal oxides, mixed oxides of aluminum and Group IIA metals, silica—alumina, crystalline silica-alumina, aluminum phosphates, crystalline aluminum phosphates, silica-alumina phosphates, Group VI metal sulfides, and Group VIII metal promoted Group VI metal sulfides and mixtures thereof.
  • the preferred catalyst may be selected from: alumina, silica, titania, Group IIA metal oxides, mixed oxides of aluminum and Group IIA metals, silica-alumina, crystalline silica-alumina, aluminum phosphates, crystalline aluminum phosphates, silica-alumina phosphates and mixtures thereof.
  • the most preferred catalyst is alumina.
  • the reactor effluent from SCANfining is condensed in a separation drum, and at least a portion of the gaseous products of the HDS reaction such as, for example, H 2 S are separated from the liquid product.
  • the liquid product is then sent to a stripper or stabilizer vessel where at least a portion of the dissolved H 2 S and light hydrocarbons are removed.
  • the liquid from the stripper/stabilizer is then heated to vaporization at a pressure between atmospheric. pressure and 200 psig (1480 kPa). This vapor feed and hydrogen are then sent to an additional mercaptan decomposition reactor operated at effective conditions that contains a catalyst suitable for decomposing the mercaptans.
  • Typical temperatures for this reactor would be temperatures of about 200-450° C., pressures from atmospheric to about 200 psig and hydrogen treat rates of about 100-5000 SCFB. It is understood that the temperature and pressure chosen must be such as to produce a complete vaporous feed to the reactor. Subsequent to the reaction the product containing reduced levels of mercaptans is condensed in another separation drum and then stripped of any remaining dissolved H 2 S in an additional stripper.
  • a second embodiment of this invention the mercaptan decomposition reactor is placed immediately following the first separation drum and sent without stripping directly to the mercaptan decomposition reactor at the conditions described above.
  • This embodiment removes the requirement for an intermediate stripper.
  • this configuration will result in some H 2 S in the mercaptan destruction reactor, this can be overcome by running the mercaptan reactor at slightly higher temperatures and/or lower pressures to compensate and is readily accomplished by the skilled artisan.
  • the reactor effluent from SCANfining is condensed in a separation drum, and at least a portion of the gaseous products of the HDS reaction such as, for example, H 2 S are separated from the liquid product.
  • the liquid product is then sent to another sulfur removal step such as a stripper, scrubber or stabilizer vessel, preferably an MEA scrubber, to remove an additional portion of hydrogen sulfide.
  • a stripper, scrubber or stabilizer vessel preferably an MEA scrubber
  • the effluent with reduced amounts of hydrogen sulfide is sent to a reactor to remove or convert at least a portion of the mercaptan sulfur.
  • the effluent from the mercaptan removal/conversion reactor is then sent to the existing stripper of the base hydrotreating unit where at least a portion of the converted mercaptans are removed as a heavier boiling point fraction.
  • a countercurrent or co-current in relation to the flow of the naphtha product stream of the mercaptan conversion reactor, hydrocarbon stream may be added, preferably diesel oil, to promote the removal of at least a portion of the converted mercaptans.
  • the injection of a hydrocarbon stream may be necessary because of low concentrations of converted mercaptans.
  • a cracked naphtha which may be a cat naphtha, coker naphtha, steam cracked naphtha or a mixture thereof, containing quantities of undesirable sulfur species and desirable high octane olefinic species is treated in a selective hydrotreating process (for example SCANfining).
  • the selective hydrotreating process removes at least a portion of mercaptan and non-mercaptan (e.g., thiophenic) sulfur species from the feed with a minimum saturation of olefins.
  • H 2 S is liberated and reacts with olefins in the naphtha product to form mercaptans.
  • Conditions in the selective naphtha hydrotreating process are chosen to reduce the level of non-mercaptan sulfur species in the product to preferably less than 30 wppm.
  • the second step involves the removal of at least a portion of hydrogen sulfide and light end, C 4 C 1 , hydrocarbons through the use of a separation drum and MEA scrubber.
  • the third step involves removing at least a portion of the mercaptans formed in the first step. A variety of techniques can be used to accomplish this while minimizing olefin saturation and hence octane lost. These include: sweetening and fractionation; extraction, adsorption, mild hydrotreating, and thermal decomposition.
  • the final naphtha product from the three step sequence has very low sulfur content (i.e., 30 ppm or less) and increased octane.
  • the product from the instant process is suitable for blending to make motor gasoline (mogas) that meets sulfur specifications in the 30 ppm range and below.
  • a sample of naphtha product from a commercial Fluid Catalytic Cracking unit was fractionated to provide an intermediate cat naphtha (ICN) stream having a nominal boiling range of 180-370° F.
  • the ICN stream contained 3340 wppm sulfur and 32.8 vol. % olefins (measured by FIA) and had a Bromine number of 50.7.
  • the ICN stream was hydrotreated at SCANfining conditions using RT-225 catalyst at 500° F., 250 psig, 1500 SCFB hydrogen treat gas and 0.5 LHSV.
  • the SCANfiner product contained 93 wppm sulfur and had a Bromine number of 19.4.
  • the SCANfiner product was sweetened by contacting it in air with a solution of 20 wt. % NaOH in water and 500 wppm cetyltrimethylammonium bromide in water. The resulting sweetened SCANfiner product contained 5 wppm mercaptan sulfur. The sweetened SCANfiner product was then fractionated via a 15/5 distillation to achieve a 350° F. cut point. 90 wt. % was recovered as 350° F. desulfurized product which contained 21 wppm total sulfur, 5 wppm mercaptan sulfur and had a Bromine number of 19.5.
  • the remaining 350° F. product contained 538 wppm sulfur consisting primarily of high boiling disulfides from the sweetening step.
  • the desulfurized 350° F. product is suitable for blending into low sulfur gasoline.
  • the 350° F. product can be processed further via hydrotreating to remove the disulfides.
  • Example 1 The ICN stream of Example 1 was hydrotreated at SCANfining conditions using RT-225 catalyst at 525° F., 227 psig, 2124 SCFB hydrogen treat gas and 1.29 LHSV.
  • the SCANfiner product contained 35 wppm sulfur and had a Bromine number of 10.1. Although this SCANfiner product had ⁇ 50 ppm S total sulfur content like the 350° F.—product of Example 1, the Bromine number was significantly lower (10.1 vs. 19.5) indicating the olefin content was lower resulting in increased octane loss.
  • a commercially prepared, catalyst consisting of 4.34 wt. % Mo0 3 , 1.19 wt. % CoO. SCANfining operation was demonstrated using a catalyst in a commercially available 1.3 mm asymmetric quadralobe size with a Heavy Cat Naphtha feed, 2125 wppm total sulfur, and 27.4 bromine number, in an isothermal, downflow, all vapor-phase pilot plant. Catalyst volume loading was 35 cubic centimeters. Reactor conditions were 560° F., 2600 scf/b, 100% hydrogen treat gas and 300 psig total inlet pressure.
  • FIG. 1 shows product sulfur levels, both total and product sulfur less mercaptan sulfur, as a function of olefin saturation. To make 30 ppm sulfur in the product without mercaptan sulfur removal would require approximately 34 wt. % olefin hydrogenation compared to 26.5 wt. % with mercaptan removal. If lower sulfur levels were required, this difference in olefin hydrogenation would be even higher.
  • KF-742 10 cc charge
  • the catalyst (KF-742) consisted of 15.0 wt. % Mo0 3 , 4.0 wt. % CoO.
  • the SCANfining operation was demonstrated using a catalyst in a commercially available 1.3 mm asymmetric quadralobe size with a Heavy Cat Naphtha feed, 2125 wppm total sulfur, and 27.4 bromine number in an isothermal, downflow, all vapor-phase pilot plant.
  • Reactor conditions were 560° F., 2600 scf/b, 100% hydrogen treat gas and 300 psig total inlet pressure.

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  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20190184383A1 (en) * 2016-04-25 2019-06-20 Liudmila Aleksandrovna TYURINA Catalyst intended for desulfurization/demercaptanization/dehydration of gaseous hydrocarbons
US10427095B2 (en) * 2016-04-25 2019-10-01 Start-Catalyst Llc Device, process, and catalyst intended for desulfurization and demercaptanization of gaseous hydrocarbons
US10443001B2 (en) * 2016-10-28 2019-10-15 Uop Llc Removal of sulfur from naphtha
WO2022241386A1 (fr) 2021-05-14 2022-11-17 ExxonMobil Technology and Engineering Company Produits issus du traitement de craquage catalytique fluide (fcc) de charges à teneur élevée en saturation et à faible teneur en hétéroatomes
US11873451B2 (en) 2021-05-14 2024-01-16 ExxonMobil Technology and Engineering Company Products from FCC processing of high saturates and low heteroatom feeds

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US7244352B2 (en) 2007-07-17
WO2001079391A1 (fr) 2001-10-25
JP2004501222A (ja) 2004-01-15
EP1285047A4 (fr) 2003-07-23
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EP1285047A1 (fr) 2003-02-26
NO20025018D0 (no) 2002-10-18

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