Classifications

• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • 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
• • 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
• • 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
  • 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
  • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
  • C10G2400/02—Gasoline

Definitions

• the present invention relates to a desulphurization process employing a catalyst containing at least one support, and an active phase comprising a metal, for example.
• the process allows hydrodesulphurizing gasoline, more particularly gasoline from a catalytic cracking process (fluid catalytic cracking, FCC).
• the production of reformulated gasoline satisfying new environmental regulations primarily necessitates substantially reducing their sulphur content.
• Current and future environmental regulations within the European community require refiners to reduce the sulphur content in the gasoline pool to values of 50 ppm or less by 2005 and 10 ppm by 1 Jan. 2009.
• the feed to be treated is generally a gasoline cut containing sulphur, such as a cut from coking, visbreaking, steam cracking or catalytic cracking (FCC).
• That feed is preferably constituted by a gasoline cut derived from a catalytic cracking unit with a typical boiling point range which extends from that of hydrocarbons containing 5 carbon atoms to about 250° C.
• Said gasoline may optionally be composed of a significant fraction of gasoline from other production processes, such as atmospheric distillation (generally termed straight run gasoline by the refiner) or conversion processes (coker gasoline or steam cracked gasoline).
• Catalytically cracked gasoline which may constitute 30% to 50% by volume of the gasoline pool, has high olefin and sulphur contents. Almost 90% of the sulphur present in reformulated gasoline is due to gasoline derived from catalytic cracking. Desulphurizing gasoline, and principally of FCC gasoline, is thus clearly important in order to satisfy requirements. Hydrotreatment or hydrodesulphurizing catalytically cracked gasoline, carried out under conventional conditions known to skilled person, can reduce the sulphur content in the cut. However, that process suffers from the major disadvantage of causing a very large drop in the octane number of the cut due to hydrogenation or saturation of a major portion or even all of the olefins under the hydrotreatment conditions.
• U.S. Pat. No. 5,318,690 proposes a process consisting of fractionating the gasoline, sweetening the light fraction and hydrotreating the heavy fraction over a conventional catalyst then processing it over a ZSM-5 zeolite to recover the initial octane number.
• International patent WO-A-01/40409 claims the treatment of FCC gasoline at high temperature, low pressure and with a high hydrogen/feed ratio. Under those particular conditions, recombination reactions, employing the H 2 S formed by the desulphurization reaction and olefins, resulting in the formation of mercaptans, are minimized.
• the catalysts used for this type of application are sulphide type catalysts containing a group VIB element (Cr, Mo, W) and a group VIII element (Fe, Ru, Os, Co, Rh, Ir, Pd, Ni, Pt).
• catalytically cracked gasoline can be classified into two families:
• the residual sulphur-containing compounds present in gasoline desulphurized by deep hydrodesulphurization comprise recombination mercaptans derived from the addition of H 2 S formed during the reaction to the olefins present and to unsaturated sulphur-containing compounds such as thiophene and alkylthiophenes.
• the presence of recombination mercaptans at least in part explains why, when seeking to deep desulphurize gasoline comprising an olefin fraction, a major increase in the degree of olefin hydrogenation is observed for high degrees of desulphurization.
• the desired degree of desulphurization approaches 100%, the degree of olefin saturation is greatly increased.
• the use of more selective catalysts may, however, when degrees of desulphurizing close to 100% are desired, limit olefin hydrogenation or allow the formation of recombination mercaptans.
• One of the primary aims of deep desulphurization is thus to develop processes that can attain high selectivities, i.e. minimize olefin hydrogenation reactions while treating residual sulphur-containing compounds such as mercaptans.
• European patent EP-A1-1 031 622 discloses a process for desulphurizing olefinic gasoline comprising at least two steps, a step for hydrogenation of unsaturated sulphur-containing compounds and a step for decomposition of saturated sulphur-containing compounds.
• the invention is based on a combination of two steps in which the first step eliminates unsaturated sulphur-containing compounds to saturated sulphur-containing compounds and the second step decomposes saturated sulphur-containing compounds to H 2 S with limited olefin hydrogenation.
• U.S. Pat. No. 6,231,753 describes a process for hydrodesulpliurizing olefinic gasoline comprising a first hydrodesulphurization step, a step for extracting H 2 S and a second hydrodesulphurization step, the overall degree of desulphurization and the temperature of said second step being greater than those of the first.
• U.S. Pat. No. 6,231,754 describes a process in which a used hydrotreatment catalyst is then used in a hydrodesulphurization step at a higher temperature.
• the pore diameters of the catalyst are described as being in the range 6 to 20 nm and the surface concentration of MoO 3 is in the range 0.5 ⁇ 10 ⁇ 4 to 3 ⁇ 10 ⁇ 4 g/m 2 .
• the present invention describes a process that can reduce the total sulphur content of hydrocarbon cuts and preferably FCC gasoline cuts without losing the gasoline yield and minimizing the reduction in octane number.
• the process for hydrodesulphurizing a gasoline of the invention employs a catalyst comprising a support and an active phase comprising at least one metal, characterized in that the mean pore diameter of said catalyst is more than 20 nanometers, preferably in the range 20 to 100 nm.
• the support is preferably selected from the group constituted by aluminas, silica, silica aluminas and oxides of titanium or magnesium, used alone or mixed with alumina or silica alumina. More preferably, the support is at least partially constituted by an alumina. In a variation of the invention, the specific surface area of the support is less than 200 m 2 /g.
• the hydrodesulphurization process of the invention comprises at least two successive hydrodesulphurization steps and a catalyst with a mean pore diameter of more than 20 nanometres is employed in at least one of said steps.
• the successive steps are carried out without intermediate degassing.
• the process of the invention comprises a succession of hydrodesulphurization steps and the activity of a catalyst in a step n+1 is in the range 1% to 90% of the activity of the catalyst in step n.
• the reaction temperature in step n+1 is higher than that in step n.
• the catalyst of step n+1 is the catalyst of step n which has undergone partial deactivation.
• the catalyst may be deactivated by bringing the catalyst into contact with a feed containing a hydrocarbon fraction comprising olefins at a temperature of at least 250° C. It is also possible to recycle the catalyst of step n to step n+1 when its activity has reduced by at least 10%.
• the catalyst of step n+1 has a metals content which is lower than that of the catalyst of step n.
• the process of the invention employs at least one hydrodesulphurization catalyst comprising at least one group VI metal (M VI ) and/or at least one group VIII metal (M VIII ) on a support.
• the group VI metal is generally molybdenum or tungsten; the group VIII metal is generally nickel or cobalt.
• the catalyst support is normally a porous solid selected from the group constituted by aluminas, silicon carbide, silica, silica-aluminas or titanium or magnesium oxides used alone or mixed with alumina or silica-alumina. It is preferably selected from the group constituted by silica, the transition alumina family and silica-aluminas.
• the support is essentially constituted by at least one transition alumina, i.e. it comprises at least 51% by weight, preferably at least 60% by weight, more preferably at least 80% by weight or even at least 90% by weight of transition alumina. It may optionally be constituted solely by a transition alumina.
• the specific surface area of the support is generally less than 200 m 2 /g, usually less than 150 m 2 /g.
• the porosity of the catalyst prior to sulphurization is such that it has a mean pore diameter of more than 20 nm, preferably more than 25 nm or even more than 30 nm and usually in the range 20 to 140 nm, preferably in the range 20 to 100 nm, and highly preferably in the range 25 to 80 nm.
• the pore diameter is measured by mercury porosimetry using ASTM D4284-92 with a wetting angle of 140°.
• the surface density of the group VI metal in accordance with the invention is in the range 2 ⁇ 10 ⁇ 4 to 40 ⁇ 10 ⁇ 4 grams of the metal oxide per m 2 of support, preferably in the range 4 ⁇ 10 ⁇ 4 to 16 ⁇ 10 ⁇ 4 gm 2 .
• salts of group VIB and VIII metals which can be used in the process for preparing the catalyst are cobalt nitrate, nickel nitrate, ammonium heptamolybdate and ammonium metatungstate. Any other salt which is known to the skilled person, has sufficient solubility and can decompose during the activation treatment may be used.
• the catalyst is normally used in the sulphide form obtained after treatment at temperature in contact with an organic sulphur-containing compound which is decomposable and which can generate H 2 S or directly in contact with a gaseous stream of H 2 S diluted in H 2 .
• This step may be carried out in situ or ex situ (inside or outside) the hydrodesulphurization reactor at temperatures in the range 200° C. to 600° C. and more preferably in the range 300° C. to 500° C.
• the present invention also pertains to a process for desulphurizing gasoline comprising olefins, comprising at least two hydrodesulphurization steps and intended to minimize both the amount of the compounds most refractory to hydrodesulphurization, such as thiophenes and recombination mercaptans, derived from adding H 2 S to olefins while limiting the degree of olefin hydrogenation, associated with elimination of sulphur-containing compounds.
• At least one of the steps in the hydrodesulphurization process employs a catalyst as described above.
• At least partial extraction of H 2 S between the two reactors using any means known to the skilled person is a known solution for achieving high degrees of desulphurization with a limited degree of olefin hydrogenation.
• that type of scheme may be applied in the context of the present invention.
• the present process is of particular advantage in the case in which the hydrodesulphurization reactors are concatenated without H 2 S elimination between the reactors.
• a first step A for hydrodesulphurization is preferably carried out in a fixed bed reactor, generally in the vapour phase, on any catalyst which is conventionally used for said application.
• the use of “selective” catalysts is preferred as they can limit olefin hydrogenation while maximizing hydrodesulphurization.
• This first step is followed by a second step B, for example with no operations between steps A and B apart from reheating the effluent from step A.
• Step B is characterized in that it is carried out using a catalyst having a catalytic activity for thiophene conversion in the range 1% to 90%, or even in the range 1% to 70% and preferably in the range 1% to 50% of the activity of the catalyst of step A.
• the catalyst employed in step B may be either a catalyst the catalytic formulation of which has been optimized to reach the desired catalytic activity, or a partially deactivated catalyst.
• the use of catalysts which are preferably more selective in series can limit olefin hydrogenation at high degrees of desulphurization. It has been observed that such a combination may, by means of a cheaper device, significantly improve the selectivity of the desulphurization reaction by minimizing the degree of olefin saturation while maintaining a high degree of transformation of sulphur-containing compounds to H 2 S. That device also has the advantage that, for a scheme with no H 2 S extraction between the two reactors, it can improve the selectivity of the process with respect to desulphurization carried out in a single step.
• the device is usually based on an assembly of at least two or even three reactors and may be carried out as follows: the reactor for step A contains fresh catalyst and the reactor for step B contains the used catalyst.
• the reactor for step A contains fresh catalyst
• the reactor for step B contains the used catalyst.
• the reactor containing the deactivated step A catalyst is used in the second step, a reactor containing fresh catalyst being fired up and placed at step A.
• the reactor containing catalyst B is stopped, the catalyst is replaced with fresh catalyst and the reactor is placed on standby.
• This scheme means that the desulphurization unit can be operated continuously when replacing used catalyst while maximizing process selectivity.
• low pressure means relative pressures that are generally less than 2 MPa relative and preferably less than 1.5 MPa relative or even less than 1 MPa relative, and temperatures that are generally more than 250° C. or even 260° C. and usually more than 280° C.
• the pressure in steps A and B is generally in the range 0.4 MPa relative to 3 MPa relative, preferably in the range 0.6 MPa to 2.5 MPa; the hydrogen flow rate is such that the ratio of the flow rates of hydrogen in normal litres per hour to the flow rate of hydrocarbons in litres per hour is in the range 50 to 800, preferably in the range 60 to 600.
• the temperature in step A is in the range 150° C. to 450° C., preferably in the range 200° C. to 400° C. and more preferably in the range 230° C. to 350° C. and the temperature in step B is in the range 150° C. to 450° C., preferably in the range 210° C. to 410° C. and more preferably in the range 240° C. to 360° C.
• Steps A and B are carried out in a preferred mode in a combination without a supplemental intermediate step.
• the catalytic zone corresponding to step B is operated at a mean temperature that is higher by a minimum of 10° C. than in the catalytic zone corresponding to step A.
• This difference in temperature may derive either from the heat of reaction released by olefin hydrogenation or by injecting a hotter fluid selected from hydrogen or an inert gas such as nitrogen, the feed or the fluid derived from recycling a fraction of the effluent of the process between the catalytic zones A and B.
• Steps A and B may also be employed in a catalytic colum from which overhead compounds which are gaseous under normal temperature and pressure conditions are extracted.
• the catalytic zone of step A is disposed higher in the column than the catalytic zone of step B.
• the catalyst of step B advantageously differs from the catalyst of step A by a catalytic activity in the range 1% to 90%, or even in the range 1% to 70% and preferably in the range 1% to 50% of the catalytic activity of the catalyst of step A the catalysts for steps A and B are used in the sulphurized form.
• the sulphurization procedure may be carried out in situ or ex situ using any sulphurization method known to the skilled person.
• the activity of the catalyst is defined by the ratio of the rate constant for conversion of normalized thiophene per volume of catalyst determined during a model molecule test.
• new catalyst When the catalyst used is a new catalyst prepared to have a reduced activity, new catalyst may be prepared by impregnating a small quantity of metals onto the support. Typically, the amounts of group VIII and group VIB metals deposited on the support will not exceed 10.9% and 14% by weight respectively in the oxide form and preferably 7.8% and 10% by weight respectively in the oxide form (to remain coherent with the maximum Co/Co+Mo ratio of 0.6 for the preferred range).
• the support used generally contains silicon, silicon carbide, titanium oxide or magnesium oxide and/or alumina, but is preferably mainly composed of alumina.
• the catalyst of step B may also be a deactivated hydrotreatment catalyst.
• a used catalyst from a distillate hydrodesulphurization unit or from any other hydrodesulphurization process present in the refinery may be employed, provided that the residual activity measured by the method described in Example 6 does not exceed 90% or 70% and preferably 50% of the activity of the catalyst from step A.
• the catalyst of step B can have an identical formulation to that of step A, but after having undergone deactivation by treatment of a cut comprising olefins.
• the used catalysts generally have an activity reduced by the presence of a deposit of carbon due to polymerization of the hydrocarbons treated over the catalyst.
• the gasoline to be treated is, for example, characterized by a sulphur content of more than 50 ppm and an olefins content of more than 10%; at least 70% of the sulphur is intended to be converted into H 2 S.
• This gasoline which has boiling points which are generally less than 250° C., may either be treated directly using the device of the present invention, or it can undergo pretreatment consisting of a selective hydrogenation step and fractionation. Said pretreatments are described in detail in European application EP-A-0 1 077 247. In this case, advantageously only the C 6 +(i.e. containing hydrocarbons with a total number of carbon atoms of 6 or more) of the gasoline may be treated by the process of the present invention.
• the gasoline, mixed with hydrogen, is heated in an exchanger train and/or an oven.
• the mixture, heated to the desired temperature and pressure, is generally in the vapour phase. It is sent to a first reactor (step A) containing a hydrodesulphurization catalyst as described above, used in fixed bed mode.
• the effluent from this reactor contains hydrocarbons and unreacted sulphur-containing compounds, paraffins derived from olefin hydrogenation, H 2 S from the decomposition of sulphur-containing compounds and recombination mercaptans derived from addition reactions of H 2 S with olefins.
• This effluent is generally reheated in an exchange train and/or an oven to increase its temperature by at least 10° C.
• step B a second reactor containing a hydrodesulphurization catalyst which is less active than that described above, used in a fixed bed mode.
• the effluent from this reactor is constituted by hydrocarbons and a reduced quantity of sulphur-containing compounds which did not react in step A, paraffins derived from olefin hydrogenation, H 2 S derived from the decomposition of sulphur-containing compounds and a reduced quantity of recombination mercaptans derived from H 2 S-olefin addition reactions.
• steps A and B can, with respect to step A alone, minimize the olefin loss by hydrogenation.
• steps A and B can, with respect to step A alone, minimize the olefin loss by hydrogenation.
• the examples below illustrate the advantages of the process in one or two steps as described above. In these examples (and the preceding description), the amounts of sulphur or sulphur-containing compounds are given in ppm by weight.
• the catalysts were prepared using the same method.
• the synthesis protocol consisted of dry impregnating a solution of ammonium heptamolybdate and cobalt nitrate, the volume of the aqueous solution containing the metallic precursors being equal to the water take-up volume (WTV) corresponding to the mass of support to be impregnated.
• WTV water take-up volume
• the concentrations of precursors in the solution were adjusted to deposit the desired amounts by weight of metallic oxides onto the support.
• the solid was left to mature at ambient temperature for 12 hours, then dried at ⁇ 120° C. for 12 hours. Finally, the solid was calcined at 500° C. for two hours in a stream of air (1 l/h/g).
• the alumina supports used were industrial supports provided by Axens with the characteristics shown in Table 1 below.
• the catalyst sulphurization protocol was identical for each catalytic test.
• the catalyst in its calcined (oxide) form, was loaded into the catalytic test unit then sulphurized using a synthetic feed (4% S in the form of DMDS in n-heptane).
• the sulphur content (in ppm) was evaluated in the feed and in the tests (after eliminating dissolved H 2 S) using the ISO14596 method, which enabled the degree of desulphurizing the gasoline to be calculated using the formula: HDS (%) (sulphur in feed in ppm ⁇ sulphur in test in ppm)/(sulphur in feed in ppm)*100.
• the total mercaptans content was measured in the tests by potentiometry using the ASTM D3227 method after separating the H 2 S.
• catalyst A has a degree of olefin hydrogenation (HDO) which is lower than for catalyst D.
• HDO degree of olefin hydrogenation
• catalyst B had a lower hydrogenating activity (HDO) than catalyst A.
• HDO hydrogenating activity
• catalysts A and C were evaluated using FCC n° 3 gasoline which had been depentanized and contained a large amount of sulphur, and which had the characteristics shown in Table 7 below. TABLE 7 characteristics of FCC n° 3 gasoline Total sulphur (ppm) 2450 Olefins (weight %) 32.1 Aromatics (weight %) 36.2 ASTM distillation: IP 39° C. EP 240° C.
• catalyst C is not more selective than catalyst A.
• catalyst C was less active than catalyst A in hydrodesulphurization, which may potentially constitute a handicap as regards the service life of this type of catalyst in an industrial unit.
• selectivity catalyst C remained superior to catalyst D, however (see Example 2, Table 4).
• catalysts B, D, E, F and G were evaluated using a hydrodesulphurization test on a mixture of model molecules carried out in a stirred 500 ml autoclave reactor.
• a hydrodesulphurization test on a mixture of model molecules carried out in a stirred 500 ml autoclave reactor.
• catalysts B, D, E, F and G were sulphurized at atmospheric pressure in a sulphurization bank with a H 2 S/H 2 mixture constituted by 15% by volume of H 2 S at 1 l/l/g of catalyst and 400° C. for two hours.
• the model feed used for the activity test had the following composition: 1000 ppm of sulphur in the form of thiophene, 10% by weight of olefins in the form of 2,3-dimethyl-2-butene in n-heptane.
• This reaction mixture was selected as it was Judged to be representative of a catalytically cracked gasoline.
• the total pressure of the system was then adjusted and maintained at 3.5 MPa relative by adding hydrogen and the temperature was adjusted to 250° C.
• the catalyst was brought into contact with the reaction mixture.
• Periodical removal of samples allowed the change in composition of the solution to be monitored over time by gas chromatographic analysis. The test period was selected so as to obtain final thiophene conversion values in the range 50% to 90%.
• the activity of a catalyst can be defined by the ratio of the rate constant for conversion of normalized thiophene per volume of catalyst.
• catalysts B, D, E and F The relative activities of catalysts B, D, E and F obtained are shown in Table 9 below. TABLE 9 relative activities of catalysts B, D, E, F and G Catalyst B Catalyst D Catalyst E Catalyst F Catalyst G Relative 100* 120 42 31 45 activity *base.
• Gasoline n° 4 described in Table 10 was used to study the performance of a combination of catalysts. This gasoline derived from a FCC unit and had been depentanized. TABLE 10 characteristics of FCC n° 4 gasoline Total sulphur (ppm) 380 Olefins (weight %) 27.8 Olefins (weight %) 32.1 Aromatics (weight %) 33.9 ASTM distillation: IP 55° C. EP 219° C.
• the base operating conditions used for the set of tests were as follows: a pressure of 1.8 MPa relative and a hydrogen to feed ratio of 400 normal litres per litre.
• reactor 1 The two reactors, placed in series, were respectively termed reactor 1 and reactor 2.
• the volume of catalyst in each reactor was 100 ml.
• Tests 1 and 2 were carried out on catalysts B and D alone. Catalyst D was not in accordance with the invention. The olefin loss during test 1 was lower than the olefin loss in test 2 due to the difference in selectivity between catalysts B and D.
• Test 7 was carried out using a combination which was not in accordance with the invention, in which reactor 2 was loaded with a more active catalyst than that loaded into reactor 1. Comparing tests 3 to 6, it can be seen that an olefin loss and a higher residual mercaptans content occurred for an equivalent sulphur content in the effluents.

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