WO2018096063A1 - Procédé de désulfurisation d'hydrocarbures - Google Patents

Procédé de désulfurisation d'hydrocarbures Download PDF

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Publication number
WO2018096063A1
WO2018096063A1 PCT/EP2017/080271 EP2017080271W WO2018096063A1 WO 2018096063 A1 WO2018096063 A1 WO 2018096063A1 EP 2017080271 W EP2017080271 W EP 2017080271W WO 2018096063 A1 WO2018096063 A1 WO 2018096063A1
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Prior art keywords
desulfurized
bar
stream
naphtha
ppmw
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PCT/EP2017/080271
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English (en)
Inventor
George Hoekstra
Christian Ejersbo STREBEL
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Haldor Topsøe A/S
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Publication of WO2018096063A1 publication Critical patent/WO2018096063A1/fr

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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
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/32—Selective hydrogenation of the diolefin or acetylene compounds
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/76—Catalysts 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
    • B01J23/84—Catalysts 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
    • B01J23/85—Chromium, molybdenum or tungsten
    • B01J23/88—Molybdenum
    • B01J23/882—Molybdenum and cobalt
    • 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
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/02—Refining 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
    • C10G45/04—Refining 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
    • C10G45/06—Refining 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
    • C10G45/08—Refining 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
    • 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
    • C10G65/06—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including only refining steps at least one step being a selective hydrogenation of the diolefins
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/70—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of the iron group metals or copper
    • B01J23/76—Catalysts 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
    • B01J23/84—Catalysts 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
    • B01J23/85—Chromium, molybdenum or tungsten
    • B01J23/88—Molybdenum
    • B01J23/883—Molybdenum and nickel
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/104—Light gasoline having a boiling range of about 20 - 100 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1044—Heavy gasoline or naphtha having a boiling range of about 100 - 180 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/202—Heteroatoms content, i.e. S, N, O, P
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/301—Boiling range
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/02—Gasoline

Definitions

  • the present invention relates to a process for the selective hydrodesulfurization of naphtha streams containing sulfur and olefins.
  • An olefinic naphtha stream is hy- drodesulfurized at a high gas to oil ratio, resulting in effective hydrodesulfurization and maintenance of octane values.
  • Hydrodesulfurization is a hydrotreating process for the removal of feed sulfur by conversion to hydrogen sulfide. Conversion is typically achieved by reaction of the feed with hydrogen over non-noble metal sulfided supported and unsupported catalysts, especially those of Co/Mo and Ni/Mo. Severe temperatures and pressures may be re- quired to meet product quality specifications by conventional means.
  • Olefinic cracked naphthas and coker naphthas typically contain more than about 20 weight percent olefins. At least a portion of the olefins are hydrogenated during conventional hydrodesulfurization. Since olefins are relatively high octane number components, it is desirable to retain the olefins rather than to hydrogenate them to saturated compounds.
  • Conventional hydrodesulfurization catalysts have both hydrogenation and desulfurization activity. Hydrodesulfurization of cracked naphthas using conventional naphtha desulfurization catalysts under conventional conditions required for sulfur removal, results in a significant loss of olefins through hydrogenation. This results in a lower grade fuel product that needs additional refining, such as isomerization, catalytic reforming, blending, etc., to produce higher octane fuels. This, of course, adds significantly to production costs.
  • Selective hydrodesulfurization involves removing sulfur while minimizing hydrogenation of olefins and octane reduction by various techniques, such as selective catalysts, separation of feedstocks, with individual treatments of fractions at specific process condi- tions, or both.
  • GOR gas to oil ratio
  • the present invention is a process based on this observation, which is commercially attractive, since the value of naphtha is highly related to the octane number.
  • the octane number has been maintained by providing process modifications increasing the complexity of processes or by development of complex specific catalysts.
  • the gas to oil ratio shall in accordance with the terminology of the skilled person of refinery technology in the following be construed to mean the ratio between hydrogen containing gas and naphtha feedstock, as determined by the individual flows of the streams at the point where the hydrogen containing gas and the feedstock are mixed.
  • GOR may be used as an abbreviation for the gas to oil ratio.
  • the two terms shall be construed as fully equivalent.
  • the unit for GOR is given as Nm 3 /m 3 , which.
  • the unit Nm 3 shall be understood as "normal" m3, i.e. the amount of gas taken up this volume at 0°C and 1 atmosphere and the flow of oil (m 3 ) shall be un- derstood as the volumetric flow at standard conditions, typically at 60°F and 1 atmosphere.
  • the hydrogen to oil ratio shall similarly in the following be construed to mean the ratio between the hydrogen share of the gas and the naphtha feedstock, as determined by the individual flows of the streams at the point where the hydrogen containing gas and the feedstock are mixed.
  • H20R may be used as an abbreviation for the hydrogen to oil ratio.
  • the two terms shall be construed as fully equivalent.
  • the unit for H20R is given as Nm 3 /m 3 , which.
  • the unit Nm 3 shall be understood as "normal" m3, i.e. the amount of gas taken up this volume at 0°C and 1 atmosphere and the flow of oil (m 3 ) shall be understood as the volumetric flow at standard condi- tions, typically at 60°F and 1 atmosphere.
  • the pressure and temperature shall in accordance with the terminology of the skilled person of refinery technology in the following be construed as the pressure and temperature respectively at the inlet of a reactor.
  • the hydrogen partial pressure shall be construed as the partial pressure of hydrogen at the inlet of the reactor.
  • the space velocity shall in accordance with the terminology of the skilled person of refinery technology in the following be construed as the LHSV (liquid hourly space veloc- ity) over a single catalytically active material unless otherwise indicated.
  • LHSV liquid hourly space veloc- ity
  • the initial boiling point (IBP), the final boiling point (FBP) and the temperatures corresponding to recovered amounts of sample, shall be understood in accordance with the ASTM D86 standard.
  • T 5 , Tio, T 5 o and T95 boiling points shall accordingly be understood as the distillation temperatures where 5vol%, 10vol%, 50vol% and 95vol% respectively have been recovered.
  • the research octane number shall be understood as the octane number measured in accordance with ASTM D2699.
  • Olefins shall in accordance with the lUPAC definition and the language of the skilled person be understood as acyclic and cyclic hydrocarbons having one or more carbon- carbon double bonds.
  • Di-olefins shall similarly be understood as acyclic and cyclic hydrocarbons having two or more carbon-carbon double bonds.
  • reaction conditions shall be understood as the extent to which a given reaction will take place.
  • Hydrodesulfurization severity shall be understood as being increased if one or more physical or chemical conditions are changed in a way having the consequence that the degree of hydrodesulfurization is increased.
  • a broad aspect of the present disclosure relates to a process for hydrodesulfurizing an olefinic naphtha feedstock while retaining a substantial amount of the olefins, which feedstock has a T95 boiling point below 250°C boils and contains at least 50 ppmw of organically bound sulfur and from 5% to 60% olefins, said process comprising hy- drodesulfurizing the feedstock in a sulfur removal stage in the presence of hydrogen and a hydrodesulfurization catalyst, at hydrodesulfurization reaction conditions including a temperature from 200°C to 350°C, a pressure of 2 bar, 5 bar or 10 bar to 40 bar or 50 bar, and gas to oil ratio of 750 Nm 3 /m 3 , 1000 Nm 3 /m 3 , 1 100 Nm 3 /m 3 a or 1200
  • Nm 3 /m 3 to 1500 Nm 3 /m 3 , 2000 Nm 3 /m 3 or 2500 Nm 3 /m 3 , to convert at least 50 % of the organically bound sulfur to hydrogen sulfide and to produce a desulfurized product stream containing from 0 ppmw, 0.1 ppmw or 1 ppmw to 5 ppmw, 8 ppmw, 10 ppmw or 50 ppmw organically bound sulfur, with the associated benefit of such a process providing a lower octane loss, compared to a process with similar conversion of organic sulfur with a lower gas to oil ratio.
  • the hydrodesulfurization reaction conditions involves a hydrogen pressure in the range 2 bar to 5 bar, with the associated benefit of the low hydro- gen pressure range decreasing the tendency to saturation of olefins, while the elevated gas to oil ratio ensures shifts hydrodesulfurization towards hydrogen sulfide and sulfur- free hydrocarbons.
  • said hydrodesulfurization catalyst comprises 0.5% or 1 % to 5% cobalt and/or nickel and 3% to 20% molybdenum and/or tungsten, on a refractory support, with the associated benefit of such a catalyst being cost effective for hydrodesulfurization.
  • said hydrodesulfurization catalyst comprises 0.5% or 1 % to 5% cobalt and 3% to 20% molybdenum with the associated benefit of such a catalyst being cost effective for hydrodesulfurization and having limited activity in olefin saturation.
  • said refractory support comprises alumina, silica, spinel or silica-alumina, with the associated benefit of such a support being highly robust.
  • Alumina and silica shall be construed as materials of synthetic or natural origin being dominated by the oxides of aluminum and silicium.
  • Alumina-silica shall be construed as a mixture, in any ratio, on any level down to atomic level of these oxides.
  • Spinel shall be con- strued as an oxidic material comprising magnesium and aluminum in a common crystal structure.
  • step (b) comprises the substeps
  • steps (x) and (z) may be simi- lar or different with the associated benefit tailoring the catalytically active material of steps (x) and (z) to the relevant requirements for conversion of sulfur, and with the associated benefit of removing hydrogen sulfide which may interfere with the hydrodesulfurization of step (z).
  • said step (x) converts at least 75,%, 80% or 85% of the organi- cally bound sulfur to hbS, with the associated benefit of the high GOR of the process allowing such a severe HDS step, while avoiding excessive saturation of olefins.
  • step (y) is present and involves the steps (p) separating the desulfurized heavy product stream in at least a desulfurized heavy naphtha stream, a desulfurized intermediate naphtha stream and a gas stream, and and one or both of the steps
  • the process further comprises a step of selective diolefin hy- drogenation prior to said hydrodesulfurizing step, with the associated benefit of reducing the risk of polymerization of diolefins in the process and of reacting olefins and mer- captans to convert low-boiling mercaptans to higher boiling sulfides.
  • the reaction between olefins and mercaptans has the effect of providing a light naphtha fraction com- prising olefins and little or no sulfur and a heavy naphtha fraction comprising few olefins and the majority of sulfur. Such two fractions may be separated and treated individually.
  • the selective diolefin hydrogenation reaction conditions involves a temperature from 80°C, 100°C or 150°C to 200°C, a pressure of 2 bar or 5 bar to 40 bar or 50 bar, and gas to oil ratio of 2 Nm 3 /m 3 , 5 Nm 3 /m 3 or 10 Nm 3 /m 3 to 20 Nm 3 /m 3 or 25 Nm 3 /m 3 to convert at least 50% or 90 % of the diolefins to alkanes or mono-olefins, with the associated benefit of such conditions being effective in hydrogenation of diolefins, with minimal mono-olefin saturation, and thus minimal RON loss.
  • the conditions are effective in formation of sulfides from mercaptans and olefins, which has the potential effect of providing a light naphtha fraction comprising olefins and little or no sulfur and a heavy naphtha fraction comprising few olefins and the majority of sulfur.
  • This difference in characteristics between light naphtha fraction and heavy naphtha fraction may be employed in specific treatment of the two fractions.
  • the selective diolefin hydrogenation reaction conditions in- volves a temperature from 100°C to 200°C, a pressure of 5 bar to 40 bar or 50 bar, and a gas to oil ratio of 250 Nm 3 /m 3 to 2500 Nm 3 /m 3 to convert at least 90 % of the diolefins to paraffins or mono-olefins, with the associated benefit of such a process not requiring separate hydrogen addition in the diolefin hydrogenation and hydrodesulfurizing steps.
  • reaction rates increase with increased temperature, increased reactant concentration, decreased product concentration and decreased space velocities (i.e. increased residence times), but the relations may be more complex than expected, due to the nature of reaction mechanisms on the microscopic level. Especially in refinery processes, increasing the factors which increase reaction rates will be called increased severity of the process.
  • Hydrogenation processes are often employed in the conversion of hydrocarbons, e.g. for the removal of sulfur by hydrodesulfurization (HDS).
  • the severity of hydrogenation is typically increased by increasing temperature, pressure, hydrogen partial pressure, the gas to oil ratio (GOR) , the hydrogen to oil ratio (H20R) or decreasing the space velocity.
  • a common intermediate product in refineries is naphtha withdrawn from a fluid catalytic cracker, which is suitable for use as gasoline.
  • the amount of sulfur in this FCC naphtha is typically too high to be included in final gasoline product, and the sulfur is often reduced by hydrotreatment, but at the same time it is desired that the amount of olefins is maintained, as removal of these would lead to a reduced octane number of the final gasoline product.
  • desulfurization as well as olefin saturation are hydrogenation pro-
  • the immediate expectation is that increasing the hydrogenation severity to obtain a high extent of HDS will be associated with a high sacrifice of octane number due to olefin saturation.
  • a further aspect of FCC naphtha post-treat is that the presence of di-olefins is undesired, as diolefins, which may be present in a concentration from 0.1 %, 0.5% or 1 % to around 5%, may polymerize and form solid products which will block the reactor.
  • the first hy- drotreatment step is carried out in the presence of a cobalt/molybdenum catalyst, which is more active in HDS than in olefin saturation.
  • Recent environmental standards require the sulfur content to be as low as 10 ppm in gasoline. To obtain this for a feed with 1000 ppm sulfur as much as 99% HDS will be required. It is well known that this may be obtained by increasing the severity of the HDS process by increasing the temperature or pressure. This increase in temperature or pressure will however have the drawback of also increasing the olefin saturation, such that the octane number and thus the gasoline value is reduced.
  • the GOR for HDS of FCC naphtha has typically been 300 Nm 3 /m 3 to 500 Nm 3 /m 3 , but studies of the effect of varying GOR have not been made.
  • Increasing GOR has however been considered an increase of hydrotreatment severity, and therefore a common expectation has been that increased GOR would result in increased rates of other hydrogenation processes.
  • the experiments in the present document evidence that increasing GOR above 500 Nm 3 /m 3 results in increased HDS without increasing olefin saturation; on the contrary a reduction in olefin saturation is observed.
  • the high GOR may protect some olefins or alternatively that new olefins may be formed which have a strong contribution to the octane number.
  • This surprising experimental observation may be implemented in a novel and inventive process, involving operation of a HDS reactor at unusually high GOR, such as above 500 Nm 3 /m 3 , 750 Nm 3 /m 3 , 1 100 Nm 3 /m 3 , 1200 Nm 3 /m 3 or even 1500 Nm 3 /m 3 .
  • the high GOR provides a dilution effect, such that the released H2S is diluted by the increase gas flow, and thus less available for contributing to the dynamic equilibrium between e.g. mercaptans and H2S and olefins. Therefore the high GOR may be obtained the gas phase comprising an amount of hydrogen in combination with a gas not partaking in the hydrogenation reaction, such as nitrogen or methane.
  • Reducing sulfur content while having low or no reduction of octane number, by a high GOR has the benefit that complex process layouts may be avoided or that it is made possible to obtain very low sulfur levels in combination with satisfactory octane numbers, which would otherwise be hard to obtain. It may however also be found beneficial to combine a process with a high GOR with the existing process designs, such as an initial hydrogenation of diolefins, a separation of heavy and light naphtha streams, and treatment of one or both of these streams, in one or more steps. Some or all of the process steps involving hydrodesulfurisation may be carried out at increased GOR in accordance with the present disclosure.
  • the hydrogenation of diolefins is preferably carried out at moderate conditions.
  • the reason is that the hydrogenation of the first double bond in diolefins is readily carried out at low temperature, and by limiting the temperature the second double bond may be protected. Therefore, the GOR are kept very low, typically below 25 Nm 3 /m 3 , 10 Nm 3 /m 3 or even 5 Nm 3 /m 3 , but also temperature is kept low, e.g. around 100°C-200°C.
  • the GOR must however be sufficient for the desired saturation of diolefins present.
  • Fig.1 shows a simple process, implementing the present disclosure.
  • Fig.2 shows an implementation of the present disclosure in a process involving pre- treatment and separation.
  • Fig.3 shows experimental results documenting the effect of increased GOR upon the loss of olefins and the extent of HDS.
  • Fig.4 shows experimental results documenting the effect of increased GOR and H20R upon the loss of olefins and the extent of HDS.
  • Desulfurized naphtha product Figure 1 shows a process for removing organically bound sulfur from hydrocarbons. The process involves combining a hydrocarbon feedstock 102 containing organically bound sulfur and olefins with a stream of hydrogen containing gas 104 such that the ratio of hydrogen containing gas to feedstock is at least 750 Nm 3 /m 3 . The combined feed- stock 106 is directed to contact a material catalytically active in hydrodesulfurization
  • a desulfurized naphtha stream 1 10 is withdrawn from the catalytically active material.
  • the catalytically active material may have a different composi- tion such as 1 % to 5% cobalt and 3% to 20% molybdenum or tungsten, on a refractory support, which may be alumina, silica, spinel or silica-alumina.
  • the hydrogen containing gas may comprise significant amounts of other gases, e.g. more than 25%, 50% or even 75% nitrogen, methane or ethane.
  • Figure 2 shows a process for removing organically bound sulfur from hydrocarbons comprising di-olefins.
  • the process involves combining a di-olefinic hydrocarbon feedstock 202 containing organically bound sulfur, olefins and diolefins with a stream of hydrogen containing gas 204 such that the ratio of hydrogen containing gas to feedstock is around 5-10 Nm 3 /m 3 providing a di-olefinic feedstock reaction mixture 206.
  • the di- olefinic feedstock reaction mixture 206 is directed to contact a material catalytically active in diolefin saturation 208, such as 2% nickel or cobalt and 7% molybdenum or tungsten, on an alumina support, at a temperature around 100-200°C, to provide an intermediate product 210 comprising less than 0.1 % or 0.3% di-olefins.
  • a material catalytically active in diolefin saturation 208 such as 2% nickel or cobalt and 7% molybdenum or tungsten
  • the intermediate product 210 is directed to a separator 212, from which a light naphtha stream 214 and a heavy naphtha stream 216 are withdrawn.
  • the heavy naphtha stream 216 is combined with a stream of hydrogen containing gas 218 such that the ratio of hydrogen containing gas to feedstock in the resulting heavy naphtha reaction mixture 220 is at least 750 Nm 3 /m 3 and directed to contact a first material catalytically active in hydrodesulfurization 222, such as 1 % cobalt and 3% molybdenum, on an alumina support, at a temperature around 250°C, providing a partly desulfurized heavy naphtha 224.
  • a first material catalytically active in hydrodesulfurization 222 such as 1 % cobalt and 3% molybdenum
  • the partly desulfurized heavy naphtha 224 may optionally be directed to a further catalytically active material 226 such as 12% nickel on an alumina support, typically operating at a temperature higher than the first material catalytically active in hydrodesul- furization 222, such as 300°C to 360°C, providing a desulfurized heavy naphtha 228.
  • the desulfurized heavy naphtha 228 is then combined with the light naphtha stream 214 to provide a desulfurized naphtha product 230.
  • the temperature control of the reactions are not shown, but since the HDS reactions are exothermic, it is typical to add cold hydrogen containing gas or cold recycled product to maintain a low temperature increase. If the GOR is increased the requirement for using product recy- cle may be reduced, as more quench gas will be available.
  • the light naphtha may also be desulfurized by contact with a material catalytically active in hydrotreatment, but typically at less severe conditions than the heavy stream(s).
  • the partly desulfurized heavy naphtha may be directed to a separator to provide the heavy sulfurized naphtha fraction contacting the third catalytically active material and an intermediate naphtha fraction which may either be treated by contact with a further catalytically active material or be combined into the desulfurized naphtha product.
  • the feedstock is characterized in Table 1 .
  • the hydrodesulfurization conditions in the reactor were temperatures from 200 to 280 °C, a 100% hydrogen treat gas to feedstock ratio (GOR) of 250 to 1400 Nm 3 /m 3 , an inlet pressure of 20 barg and a liquid hourly space velocity (LHSV) of 2.5 1/hr (v/v/hr).
  • the reactor effluent was cooled to ca. -5°C to condense the treated naphtha product, which was separated from a remaining gas phase comprising H2S and unreacted hb, and subsequently stripped using N2 to remove any dissolved H2S from the product.
  • the catalyst used was a hydrodesulfurization catalyst comprising 1.1 wt % Co and 3.2 wt % Mo on alumina support. The catalyst was a 1/20 inch trilobe size.
  • Example 1 the HDS process was carried out at a temperature of 250°C and varying GOR to obtain HDS from 82-94%. From the examples it is seen that when increasing the HDS by increasing GOR, the olefin saturation is constant or even decreased.
  • Example 2 according to the prior art, the HDS process was carried out at varying temperatures and a constant GOR of 502 Nm 3 /m 3 to obtain HDS from 41 -97%. From the examples it is seen that when increasing the HDS by increasing temperature, the olefin saturation is increased significantly, especially at temperatures above 240°C.
  • Figure 3 compare the data according to the two examples.
  • the dashed line indicates the relation between desulfurization and olefin saturation when the process severity is controlled by variation of the process temperature and the solid line shows the relation between desulfurization and olefin saturation when the process severity is controlled by variation of the GOR.
  • a further feedstock of commercial, heavy catalyst cracked naphtha boiling between 60 and 200°C was directed to hydrodesulfurization in an isothermal downflow pilot plant reactor.
  • the feedstock is characterized in Table 4.
  • the hydrodesulfurization conditions in the reactor were temperatures of 235°C, a 100% hydrogen treat gas to feedstock ratio (GOR) of 250 to 1500 Nm 3 /m 3 , an inlet pressure of 20 barg and a liquid hourly space velocity (LHSV) of 2.5 1/hr (v/v/hr).
  • GOR hydrogen treat gas to feedstock ratio
  • LHSV liquid hourly space velocity
  • the catalyst used was a hydrodesulfuriza- tion catalyst comprising 1.1 wt % Co and 3.2 wt % Mo on alumina support.
  • the catalyst was a 1/10 inch assymmetric quadlobe size.
  • Example 3 the HDS process was carried out at a temperature of 235°C and varying GOR from 250 Nm 3 /m 3 to 150 Nm 3 /m 3 to obtain HDS from 77-93%.
  • the experiment confirmed the trend of increasing HDS, with minimal sacrifice of olefins by increasing the GOR.
  • Example 4
  • Example 4 the HDS process was carried out at a temperature of 235°C, a GOR of 1000 Nm 3 /m 3 and a H20R (H2:oil ratio) from 250 to 1000 Nm 3 /m 3 (balanced with methane) to obtain HDS from 75-92%, in order to evaluate the influence of hydrogen partial pressure on HDS and olefin saturation, having a constant GOR and varying H20R (and thus hydrogen partial pressure).
  • Example 3 and Example 4 are compared in Figure 4, which shows the experiments as circles, with the diameter proportional to the GOR.
  • Example 3 where only GOR was varied is indicated as circles with horizontal lines.
  • the experiments of Example 4, where GOR was constant, and the H20R was varied are indicated by pairs of concentric circles. The inner circles with vertical lines shows the H20R, and the outer open circles shows the total GOR.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Organic Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Materials Engineering (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

L'invention concerne un procédé d'hydrodésulfuration d'une charge d'alimentation de naphta oléfinique tout en conservant une quantité substantielle d'oléfines, ladite charge d'alimentation ayant un point d'ébullition T95 inférieur à 250 °C et contenant au moins 50 ppmw de soufre lié organiquement et de 5 % à 60 % d'oléfines, ledit procédé comprenant l'hydrodésulfuration de la charge d'alimentation dans un étage d'élimination de soufre en présence d'hydrogène et d'un catalyseur d'hydrodésulfuration, dans des conditions de réaction d'hydrodésulfuration comprenant une température de 200 °C à 350 °C, une pression de 2 bars, 5 bars ou 10 bars à 40 bars ou 50 bars, et le rapport gaz/huile de 750 Nm 3 /m 3 , 1000 Nm 3 /m 3 , 1100 Nm 3 /m 3 ou 1200 Nm 3 /m 3 à 1500 Nm 3 /m 3 , 2000 Nm 3 /m 3 ou 2500 Nm 3 /m 3 , pour convertir au moins 50 % du soufre lié organiquement en sulfure d'hydrogène et pour produire un flux de produit désulfuré contenant de 0 ppmw, 0,1 ppmw ou 1 ppmw à 5 ppmw, 8 ppmw, 10 ppmw ou 50 ppmw organiquement lié au soufre.
PCT/EP2017/080271 2016-11-23 2017-11-23 Procédé de désulfurisation d'hydrocarbures WO2018096063A1 (fr)

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WO2021013526A1 (fr) 2019-07-23 2021-01-28 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans
WO2021013528A1 (fr) 2019-07-23 2021-01-28 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans
WO2021185658A1 (fr) 2020-03-20 2021-09-23 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans

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FR3142486A1 (fr) * 2022-11-30 2024-05-31 IFP Energies Nouvelles Procédé d’hydrodésulfuration de finition des essences mettant en œuvre un enchaînement de catalyseurs

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EP0725126A1 (fr) 1995-02-03 1996-08-07 Mitsubishi Oil Co., Ltd. Procédé de désulfuration d'essence craquée catalytiquement
WO2003029388A1 (fr) * 2001-09-28 2003-04-10 Catalytic Distillation Technologies Methode de desulfuration de naphte de craquage catalytique fluide
EP1800748A2 (fr) * 2005-12-22 2007-06-27 Institut Français du Pétrole Procédé d'hydrogénation sélectrive mettant en oeuvre un catalyseur sulfure
EP1831333B1 (fr) * 2004-12-27 2011-01-05 ExxonMobil Research and Engineering Company Hydrodesulfuration a deux etages de flux de naphta de craquage avec derivation ou elimination du naphta leger
WO2014031274A1 (fr) * 2012-08-21 2014-02-27 Catalytic Distillation Technologies Hydrodésulfuration sélective d'essence de craquage catalytique en lit fluidisé (fcc) au-dessous de 10 ppm de soufre

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EP0725126A1 (fr) 1995-02-03 1996-08-07 Mitsubishi Oil Co., Ltd. Procédé de désulfuration d'essence craquée catalytiquement
WO2003029388A1 (fr) * 2001-09-28 2003-04-10 Catalytic Distillation Technologies Methode de desulfuration de naphte de craquage catalytique fluide
EP1831333B1 (fr) * 2004-12-27 2011-01-05 ExxonMobil Research and Engineering Company Hydrodesulfuration a deux etages de flux de naphta de craquage avec derivation ou elimination du naphta leger
EP1800748A2 (fr) * 2005-12-22 2007-06-27 Institut Français du Pétrole Procédé d'hydrogénation sélectrive mettant en oeuvre un catalyseur sulfure
WO2014031274A1 (fr) * 2012-08-21 2014-02-27 Catalytic Distillation Technologies Hydrodésulfuration sélective d'essence de craquage catalytique en lit fluidisé (fcc) au-dessous de 10 ppm de soufre

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Publication number Priority date Publication date Assignee Title
WO2021013526A1 (fr) 2019-07-23 2021-01-28 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans
WO2021013528A1 (fr) 2019-07-23 2021-01-28 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans
FR3099173A1 (fr) 2019-07-23 2021-01-29 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans
FR3099175A1 (fr) 2019-07-23 2021-01-29 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans
WO2021185658A1 (fr) 2020-03-20 2021-09-23 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans
FR3108333A1 (fr) 2020-03-20 2021-09-24 IFP Energies Nouvelles Procédé de production d'une essence a basse teneur en soufre et en mercaptans

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