Process and apparatus using a plurality of catalytic beds in series for the production of gas oils with a low sulphur content

Abstract

A process for hydrotreating gas oils comprises:

Description

FIELD OF THE INVENTION

[0001] The present invention relates to the field of fuels for internal combustion engines. More particularly, it concerns the production of a fuel for a compression ignition engine. In this field, the invention relates to a process for transforming a gas oil cut to produce a high cetane index fuel that is highly desulphurised. The current legislation in the majority of industrialised countries requires that engines must contain less than about 500 parts per million (ppm) of sulphur. In certain countries, there are currently no standards imposing maximum contents for aromatic compounds and nitrogen. However, in some countries or states, for example Sweden and California, and in particular in Sweden, certain classes of diesel fuel must already satisfy very strict specifications. In that country, class II diesel fuel must not contain more than 50 ppm of sulphur and class I fuel must not contain more than 10 ppm of sulphur. Currently in Sweden, class III diesel fuel must contain less than 500 ppm of sulphur. Similar limits also have to be satisfied for the sale of that type of fuel in California. New environmental standards concerning the storage zone in the refinery for this type of fuel (the storage zone is termed the “gas oil pool” by the skilled person) for 2005 will necessitate reducing the sulphur content of gas oils to 50 ppm or even to 30 ppm. Other specifications may also concern the aromatic compound content, cetane index, density or end point.

PRIOR ART

[0002] The term “gas oil” as used in the present description designates cuts of this type originating from straight run distillation (SR) of crude oil and cuts of this type from different conversion processes, in particular those from catalytic cracking.

[0003] Hydrodesulphurisation constitutes the essential refining process for bringing those products to the required sulphur contents.

[0004] Processes for hydrodesulphurising conventional gas oils termed one-step processes have already been proposed as they use a single catalytic bed. A summary description of such processes can be found, for example, in Hydrocarbon Processing, September 1984, page 70 or in Ullmann's Encyclopaedia of Industrial Chemistry, Vol. A18, page 65-66. The transformation of hydrocarbons in the reaction zone is then carried out in the presence of a certain partial pressure of H2S, essentially due to desulphurisation reactions. Now, the presence of H2S in a hydrotreatment catalyst has the effect of slowing down hydrodesulphurisation reactions very significantly. Such processes were sufficient when the desired sulphur contents in the final product were not too low (up to 300-500 ppm). For deeper desulphurisation, the inhibiting effect of H2S becomes critical.

[0005] For that reason, so-called two-step process layouts using two catalytic beds were proposed. A device for stripping the effluent at the outlet from the first bed can eliminate the major portion of the H2S, and the second catalyst bed functions at a lower partial pressure of H2S with better desulphurisation activity.

[0006] United States patent U.S. Pat. No. 5,292,428 proposes a process for hydrotreating hydrocarbon feeds including gas oils, comprising two or more catalytic zones, with elimination of H2S at the outlet from the first zone and addition of fresh hydrogen to the second reactor. The H2S that is formed is generally eliminated using an amine washing unit. The activity of the catalyst in the second catalytic zone is then improved because of the lower partial pressure of H2S. However, to reach high degrees of desulphurisation, sufficient to satisfy the most strict sulphur specifications (50 ppm or even 30 ppm), it is necessary to employ severe operating conditions from the start of the cycle by increasing the operating pressure and temperature and/or by employing sufficiently low HSVs (volume of feed per volume of catalyst per hour). Increasing the temperature at the start of the cycle can prove to be deleterious as regards the cycle time. The operating pressure can only be increased within reasonable limits for reasons of process economy. Finally, for a given unit capacity, operating at a lower HSV means using a larger volume of catalyst, which involves a supplemental operating cost. Further, French patent FR-A-2 757 532, for example, also describes a two-step process using a catalyst in the second step containing a noble metal from group VIII, enabling very deep desulphurisation of gas oil cuts. However, that process has a certain disadvantage because it uses a noble metal in the second step, increasing the cost of such a catalyst and secondly, increasing the sensitivity to hydrogen sulphide the amount of which at the outlet from the first step must be limited to the maximum if a reasonable service life of the second step catalyst is to be obtained.

[0007] In contrast to the currently unpublished teaching from the Applicant's French patent application, national filing number FR 00/02809, which recommends using a quantity of catalyst that is less than or equal to half the total quantity of catalyst used in the process in the first step a) of the hydrodesulphurisation process, it has surprisingly been discovered that in certain specific cases, excellent results can be obtained by using, in step a) of a process comprising at least two hydrodesulphurisation steps, a quantity of catalyst in the first step that is strictly greater than half the total quantity of catalyst employed in that process. This is particularly the case when an old desulphurisation unit is to be modernised that functions with a single hydrodesulphurisation reactor that cannot satisfy the new specifications required, in particular concerning the sulphur content in engine fuels authorised for sale. In the event of such modemisation, adding a supplemental hydrodesulphurisation zone can produce engine fuels corresponding to new standards and it is understood that, from the point of view of economics, if the reactors that are added have dimensions that are relatively reduced with respect to the single reactor already in place; the cost of modifying the old unit will be very attractive compared with constructing a whole new unit or adding a reactor with larger dimensions that that of the single reactor already present.

DESCRIPTION OF THE INVENTION

[0008] Surprisingly, we have discovered a process for producing kerosines and/or gas oils with a very low sulphur content that can improve the efficiency of the catalyst by acting firstly on the partial pressure of H2S and by optimising the distribution of the residence times (and thus the catalyst volume) in the different catalytic zones. This process can achieve deep desulphurisation with a lower hydrogen consumption than in prior art processes, which constitutes a further very important advantage for the refiner, who is constantly on the lookout for processes that consume small amounts of hydrogen, a precious asset in the refinery.

[0009] More precisely, in the process of the invention, the hydrocarbon cut is typically a kerosine and/or a gas oil, with an initial boiling point in the range about 150° C. to 250° C., and with an end point in the range about 300° C. to 400° C. The process of the invention employs two hydrodesulphurisation zones each containing at least one hydrodesulphurisation catalyst containing, on a support, at least one non noble metal from group VIII associated with at least one group VIB metal.

[0010] In its broadest form, carrying out a process for hydrodesulphurisation of a kerosine and/or gas oil cut in accordance with the present invention comprises:

[0011] at least one first hydrodesulphurisation step a) in which said gas oil cut and hydrogen are passed over a catalyst disposed in a fixed bed comprising, on a mineral support, at least one metal or compound of a metal from group VIB of the periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.5% to 40%, and at least one non noble metal or compound of a non noble metal from group VIII of said periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.1% to 30%;

[0012] b) at least one subsequent second step b) in which a gas fraction containing at least a portion of the hydrogen sulphide (H2S) contained in the total effluent from said first step is recovered along with an effluent that is depleted in hydrogen sulphide; and

[0013] c) at least one third step c) in which at least a portion of the effluent that is depleted in hydrogen sulphide from step b) and hydrogen are passed over a catalyst disposed in a fixed bed that is identical to or different from that used in step a) comprising, on a mineral support, at least one metal or compound of a metal from group VIB of the periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.5% to 40%, at least one non noble metal or compound of a non noble metal from group VIII of said periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.1% to 30%, said process being characterized in that the quantity of catalyst used in the first step a) is strictly greater than 50% by weight of the total quantity of catalyst used in said process. Preferably, the quantity of catalyst used in the first step is about 60% to about 90% of the total quantity of catalyst used in said process.

[0014] The first step a), deep hydrodesulphurisation, is normally carried out in a reaction zone comprising at least one fixed catalyst bed. This zone can contain a plurality of catalyst beds that may be identical to or different. Similarly, step c) is normally carried out in a reaction zone comprising at least one fixed catalyst bed. This zone can contain a plurality of catalyst beds that may be identical to or different. The different catalytic zones can be arranged in different reactors. A plurality of catalytic zones, with the exception of the first zone, can be integrated into one and the same reactor.

[0015] Surprisingly, as will be shown in the comparative examples below, it has been shown that total hydrogen consumption is lower when a smaller quantity of catalyst is used in the second reactor than when the quantity of catalyst is identical in the first and second reactor.

[0016] In order for the catalyst bed or beds in the reaction zone for step c) to stay in the sulphurised state, the concentration of H2S at the inlet to this second catalytic zone is kept at a sufficient level by adjusting the amount of hydrogen sulphide elimination in step b). Step b) for recovering a liquid feed that is depleted in hydrogen sulphide and a gas fraction containing at least a portion of the hydrogen sulphide contained in the total effluent from step a) can be carried out using any method known to the skilled person. By way of illustration, it is possible to carry out this recovery of a gas fraction containing at least a portion of the hydrogen sulphide contained in the total effluent from step a) by stripping or entraining using at least one hydrogen-containing gas at a pressure that is substantially identical to that prevailing in the first step and at a temperature of about 100° C. to about 450° C. under conditions for forming a gaseous stripping effluent containing hydrogen and hydrogen sulphide. This recovery can also, for example, be carried out by flashing the total effluent from step a). In a particular implementation of the invention, the gas fraction recovered in step b) containing hydrogen sulphide is sent to a zone for at least partial elimination of the hydrogen sulphide it contains, from which purified hydrogen is recovered, at least a portion of which is recycled to the inlet to at least one of steps a), b) or c) indifferently. All of the purified hydrogen can be recycled. Complete or partial recycling of the purified hydrogen can be carried out to just a single step or to two of the steps, or to all three. In this zone, hydrogen purification from a gas mixture containing hydrogen and hydrogen sulphide originating from the zone for at least partial elimination of hydrogen sulphide, is normally carried out using a conventional technique that is well known to the skilled person and in particular by a prior treatment of this gas mixture with a solution of at least one amine under conditions that can eliminate hydrogen sulphide by absorption, said amine usually being selected from the group formed by monoethanolamine, diethanolamine, diglycolamine, diisopropylamine and methyldiethanolamine. In a particular implementation of this absorption, the gas mixture will be brought into contact with a basic solution, preferably an aqueous solution of an amine selected from the group mentioned above, which forms an addition compound with hydrogen sulphide to enable the production of purified gas containing proportions of hydrogen sulphide of far less than 500 ppm by weight and usually less than about 100 ppm by weight. Usually, the quantity of remaining hydrogen sulphide is less than about 50 ppm by weight and most frequently less than about 10 ppm by weight. This method for purifying a gas mixture is a conventional method that is well known to the skilled person and has been widely described in the literature. As an example, it has been succinctly described for the treatment of natural gas containing hydrogen sulphide, for example, in Ullmann's Encyclopaedia, volume A12, pages 258 ff. Within the context of the present invention, treatment with an aqueous amine solution is normally carried out at a temperature of about 10° C. to about 100° C. and usually about 20° C. to about 70° C. Normally, the quantity of amine used is such that the mole ratio of hydrogen sulphide to amine is about 0.1:1 to about 1:1 and usually about 0.3:1 to about 0.8:1, for example about 0.5:1. The pressure at which the hydrogen sulphide is absorbed by the amine is normally about 0.1 MPa to about 50 MPa, usually about 1 MPa to about 25 MPa and usually about 1 MPa to about 10 MPa. The amine solution is conventionally regenerated by varying the pressure. To produce a dryer gas and to eliminate more of the hydrogen sulphide initially present in the gas mixture, it is also possible to provide at least a portion of this gas mixture with a complementary treatment such as treating the gas leaving the absorption step, in a zone for adsorbing hydrogen sulphide comprising at least one reactor and usually at least two adsorption reactors containing a sieve, for example, preferably a regeneratable sieve or, for example, zinc oxide and operating, for example, at a temperature of about 10° C. to about 400° C., normally at about 10° C. to about 100° C. and usually at about 20° C. to about 50° C. at a total pressure of about 0.1 MPa to about 50 MPa, normally about 1 MPa to about 25 MPa and preferably about 1 MPa to about 10 MPa. In this implementation, when the adsorption zone comprises two reactors, one reactor is used to treat the gas while the other is being regenerated or the material it contains is being replaced to dry and desulphurise the gas mixture entering said zone. At the end of the complementary treatment, the hydrogen sulphide content of the gas is normally less than 1 ppm by weight and usually of the order of a few tens of ppb by weight.

[0017] The operating conditions for step a) normally include a temperature of about 240° C. to about 420° C., a total pressure of about 2 MPa to about 20 MPa and an hourly space velocity of liquid feed of about 0.1 to about 5, and that of step c) normally comprises a temperature of about 240° C. to about 420° C., a total pressure of about 2 MPa to about 20 MPa and an hourly space velocity of liquid feed that is strictly higher than the hourly space velocity of the liquid feed for step a).

[0018] The catalyst(s) used in the different catalytic zones are hydrodesulphurisation catalysts. These catalysts can be conventional catalysts such as those described in the prior art, for example one of those described by the Applicant in French patent applications FR-A-2 197 966, FR-A-2 583 813 and in European patent document EP-A-0 297 949. It is also possible to use commercial catalysts such as those sold by PROCATALYSE. These catalysts each comprise at least one metal or compound of a metal from group VIB and/or at least one non noble metal or compound of a non noble metal from group VIII, on a suitable mineral support.

[0019] The catalyst support is generally a porous solid. This support is normally selected from the group formed by alumina, silica, silica-aluminas, zeolites, magnesia, titanium oxide TiO2 and mixtures of at least two of these mineral compounds. Alumina is routinely used. The supports for the two catalysts used in steps a) and c) are selected independently of each other, but can optionally be of the same nature or be identical.

[0020] The group VIB metal is normally selected from the group formed by molybdenum and tungsten, and the group VIII metal is normally selected from the group formed by nickel, cobalt and iron, usually selected from the group formed by nickel and cobalt. Combinations such as NiMo and CoMo are typical. In a preferred implementation, the catalyst used in step a) and that used in step c) each comprise molybdenum or a compound of molybdenum in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 2% to 30% and a metal or compound of a metal selected from the group formed by nickel and cobalt in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.5% to 15%. Usually a catalyst comprising nickel as the group VIII metal and molybdenum as the group VIB metal is used in step a) and in step c).

[0021] In a preferred implementation, the catalyst used in step a) and that used in step c) each also comprise at least one element selected from the group formed by silicon, phosphorus and boron or one or more compounds of this/these element(s).

[0022] In a further implementation, the catalysts used in step a) and in step c) each comprise at least one halogen. Normally, the quantity of halogen is about 0.1% to about 15% by weight with respect to the weight of finished catalyst. The halogen is usually selected from the group formed by chlorine and fluorine and in a particular implementation, the catalysts used will contain chlorine and fluorine.

[0023] The temperature of the different catalytic zones is preferably in the range 260° C. to 400° C., more preferably in the range 280° C. to 390° C. The operating pressures used are preferably in the range 2 MPa to 15 MPa and preferably in the range 2 MPa to 10 MPa.

[0024] The overall hourly space velocity or overall HSV (volume of feed per volume of catalyst per hour) is in the range 0.1 h−1 to 10 h−1.

[0025] When the process comprises two catalytic zones, the distribution of the residence times in the catalytic zones is such that the residence time in the second catalytic bed is a maximum of 50% of the overall residence time.

EXAMPLES

Example 1 (Comparative)

[0026] A gas oil composed of 75% of straight run, SR, gas oil and 25% of LCO (light cycle oil, gas oil from catalytic cracking) was treated using a one-step process with a single bed of catalyst in a reactor. The characteristics of the gas oil are shown in Table 1 below.

[0027] The catalyst used is sold by Procatalyse under the trade reference HR 448. It contains nickel and molybdenum in amounts that lie within the ranges mentioned for steps a) and c) of the process of the invention. After activating the catalyst by sulphurisation, the reactor was kept under a total pressure of 30 bar g (1 bar g is equal to 0.1 MPa) and at a temperature of 340° C. A quantity of hydrogen corresponding to a H2/feed ratio of 270 l/l was injected, the mixture of feed and hydrogen traversing the catalytic bed in upflow mode. The gas oil was injected into the bottom of the reactor at a liquid flow rate of 200 cm3/h. 1 TABLE 1 Principal characteristics of gas oil feed Density 15/4 (g/cm3) 0.8712 Sulphur (ppm by wt) 13435 Distillation, ASTM D86  5% point 235 50% point 286 95% point 354

[0028] To achieve a sulphur specification of 50 ppm by weight in the gas oil produced, it was necessary to use 500 cm3 of catalyst, giving a HSV of 0.4 h−1, as shown in Table 2. 2 TABLE 2 Hydrogen consumption to achieve 50 ppm sulphur specification (Feed: 75% SR gas oil + 25% LCO; 1 reactor; pressure = 30 bar g) Sulphur specification (ppm) 50 Corresponding HDS (%) 99.63 HSV required (h−1) 0.4 Hydrogen consumption 100 (wt %/feed)

Example 2 (Comparative)

[0029] The same gas oil as that described in Example 1 was treated using a two-step process with a single bed of catalyst (per reactor) in two successive reactors R1 and R2. A stripping apparatus between the two beds eliminated the H2S produced in the first bed.

[0030] This time, there were two beds of the same HR 448 catalyst. The second catalyst bed was subjected to the same operating pressure as the first bed (3 MPa).

[0031] Each reactor contained 250 cm3 of HR 448 catalyst. The results obtained are shown in Table 3 below. 3 TABLE 3 Sulphur and hydrogen consumption (Feed: 75% SR gas oil + 25% LCO) Operating conditions Catalyst volume, R1 (cm3) 250 HSV R1 (h−1) 0.8 Sulphur, outlet R1 (ppm) 200 Catalyst volume, R2 (cm3) 250 HSV R2 (h−1) 0.8 Sulphur, outlet R2 (ppm) 15 Overall HSV (h−1) 0.4 Hydrogen consumption 94 (wt %/feed)

[0032] Under the operating conditions described above and in particular for the same quantity of overall catalyst as that used in Example 1, the layout of processes with intermediate H2S stripping between the two catalyst beds produced a better hydrodesulphurisation (HDS) performance (15 ppm of sulphur in the gas oil produced, in place of 50 ppm) for a hydrogen consumption that was reduced by 6%.

Example 3 (In Accordance with the Invention)

[0033] The same gas oil feed as described in the preceding examples was treated using the same process as described in Example 2 and under the same pressure, temperature and H2/feed conditions. The volume of catalyst in the first reactor was 200 cm3 while that in the second reactor contained a volume of catalyst of 100 cm3.

[0034] Under these conditions, as shown in the results given in Table 4 below, the HSV was 2 h−1 compared with the second catalyst bed contained in the second reactor, and the overall HSV was 0.7 h−1. These conditions satisfied the 50 ppm sulphur specification, while further reducing the hydrogen consumption (85% as opposed to 94% in Example 2) with a lower quantity of catalyst and a higher overall HSV. 4 TABLE 4 Sulphur and hydrogen consumption (Feed: 75% SR gas oil + 25% LCO) Operating conditions Catalyst volume, R1 (cm3) 200 HSV R1 (h−1) 1.0 Sulphur, outlet R1 (ppm) 300 Catalyst volume, R2 (cm3) 100 HSV R2 (h−1) 2.0 Sulphur, outlet R2 (ppm) 45 Overall HSV (h−1) 0.7 Hydrogen consumption 85 (wt %/feed)

[0035] The preceding examples can be repeated with similar success by substituting the generically or specifically described reactants and/or operating conditions of this invention for those used in the preceding examples. Also, the preceding specific embodiments are to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way whatsoever.

[0036] The entire disclosure of all application, patents and publications, cited above and below, and of corresponding French Application No. 01/04.924, are hereby incorporated by reference.

[0037] From the foregoing description, one skilled in the art can easily ascertain the essential characteristics of this invention, and without departing from the spirit and scope thereof, can make various changes and modifications of the invention to adapt it to various usages and conditions.

Claims

1. A process for hydrodesulphurisation of a kerosine and/or gas oil cut comprising:

at least one first hydrodesulphurisation step a) in which said gas oil cut and hydrogen are passed over a catalyst disposed in a fixed bed comprising, on a mineral support, at least one metal or compound of a metal from group VIB of the periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.5% to 40%, and at least one non noble metal or compound of a non noble metal from group VIII of said periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0. 1% to 30%;

at least one subsequent second step b) in which a gas fraction containing at least a portion of the hydrogen sulphide contained in the total effluent from said first step is recovered along with an effluent that is depleted in hydrogen sulphide; and

at least one third step c) in which at least a portion of the effluent that is depleted in hydrogen sulphide from step b) and hydrogen are passed over a catalyst disposed in a fixed bed that is identical to or different from that used in step a) comprising, on a mineral support, at least one metal or compound of a metal from group VIB of the periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.5% to 40%, at least one non noble metal or compound of a non noble metal from group VIII of said periodic table in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.1% to 30%, said process being characterized in that the quantity of catalyst used in the first step is strictly greater than 50% by weight of the total quantity of catalyst used in said process.

2. A process according to claim 1, in which the quantity of catalyst used in the first step is about 60% to about 90% of the total quantity of catalyst used in said process.

3. A process according to claim 1 or claim 2, in which in step b), recovery of a gas fraction containing at least a portion of the hydrogen sulphide contained in the total effluent from step a) is carried out by stripping using at least a hydrogen-containing gas at a pressure that is substantially identical to that prevailing in the first step and at a temperature of about 100° C. to about 450° C. under conditions for forming a gaseous stripping effluent containing hydrogen and hydrogen sulphide, along with a liquid feed that is depleted in hydrogen sulphide.

4. A process according to claim 1 or claim 2, in which in step b), recovery of a gas fraction containing at least a portion of the hydrogen sulphide contained in the total effluent from step a) is carried out by flashing the total effluent from step a).

5. A process according to any one of claims 1 to 4, in which the operating conditions for step a) comprises a temperature of about 240° C. to about 420° C., a total pressure of about 2 MPa to about 20 MPa and an hourly space velocity of liquid feed of about 0.1 to about 5, and those of step c) comprise a temperature of about 240° C. to about 420° C., a total pressure of about 2 MPa to about 20 MPa and an hourly space velocity of liquid feed that is strictly higher than the hourly space velocity of the liquid feed in step a).

6. A process according to any one of claims 1 to 5, in which the catalyst used in step a) and that used in step c) each comprise at least one metal or compound of a metal ftom group VIB selected from the group formed by molybdenum and tungsten and at least one metal or compound of a metal from group VIII selected from the group formed by nickel, cobalt and iron.

7. A process according to any one of claims 1 to 6, in which the catalyst used in step a) and that used in step c) each comprise molybdenum or a compound of molybdenum in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 2% to 30%, and a metal or compound of a metal selected from the group formed by nickel and cobalt in a quantity, expressed as the weight of metal with respect to the weight of finished catalyst, of about 0.5% to 15%.

8. A process according to any one of claims 1 to 7, in which the catalyst used in step a) and that used in step c) each comprise nickel as the group VIII metal, and molybdenum as the group VIB metal.

9. A process according to any one of claims 1 to 8, in which the catalyst used in step a) and that used in step c) each further comprise at least one element selected from the group formed by silicon, phosphorus and boron or one or more compounds of this element or elements.

10. A process according to any one of claims 1 to 9, in which the catalyst support used in step a) and in step c) are selected independently of each other from the group formed by alumina, silica, silica-aluminas, zeolites, magnesia, titanium oxide TiO2 and mixtures of at least two of these mineral compounds.

11. A process according to any one of claims 1 to 10, in which the catalysts used in step a) and in step c) each comprise at least one halogen.

12. A process according to any one of claims 1 to 11, in which the catalysts used in step a) and in step c) each comprise a quantity of halogen of about 0. 1% to about 15% by weight with respect to the weight of finished catalyst.

13. A process according to any one of claims 1 to 12, in which the catalysts used in step a) and in step c) each comprise at least one halogen selected from the group formed by chlorine and fluorine.

14. A process according to any one of claims 1 to 13, in which the catalysts used in step a) and in step c) each comprise chlorine and fluorine.

15. A process according to any one of claims 1 to 14, in which the gas fraction recovered in step b) containing hydrogen sulphide is sent to a zone for at least partial elimination of the hydrogen sulphide it contains, from which purified hydrogen is recovered, at least a portion of which is recycled indifferently to the inlet to at least one of steps a), b) or c).