EP0899320B1 - Process and hydrotreatment unit for petroleum charges comprising ammonia cracking and hydrogen recycle - Google Patents

Description

The invention relates to a method and a device for catalytic cracking of ammonia. contained in a gaseous or liquid fluid which comprises hydrogen sulphide, thus that the separation of the hydrogen produced by this cracking of ammonia and the use of this hydrogen in a process for hydrotreating a hydrocarbon feed containing sulfur and nitrogen.

The prior art is illustrated by the following patents: US-A-3,627,470, US-A-4,272,357, US-A-3,365,374 and US-A-4,806,233.

Pressurized hydrogen treatments of liquid petroleum fractions (hydrotreatments) are well known and widely used methods to improve the properties of these cuts. These treatments make it possible in particular to convert the organic compounds containing hetero atoms (sulfur, nitrogen) in hydrocarbons and mineral compounds (hydrogen sulfide, ammonia), which can then easily be separated by simple operations such as stripping (distillation) and water washes. Greater concern for environmental protection leads to lowering the sulfur and nitrogen contents of petroleum products and therefore to increase the quantity of hydrogen necessary for the operation of hydrotreatment units.

As the availability of hydrogen in the refinery is limited, refiners are led to minimize losses of hydrogen at these hydrotreating units. Now these units, by design, always produce a high pressure purge gas, under a pressure generally between 20 and 100 bar (1 bar = 0.1 MPa), relatively rich in hydrogen since the hydrogen content of this type of gas is generally greater than 50%. So we are brought to modern units hydrotreatment to set up a residual hydrogen recovery unit present on this high pressure purge gas.

Different techniques can a priori be used to separate and recover this hydrogen, such as cryogenic distillation, adsorption or gas permeation on membrane. It is however the latter which is preferentially implemented to treat high pressure purge gases from hydrotreatment units. Such a bet in work is now well known to those skilled in the art. We can for example in find a description in "Hydrogen membrane applications and design" by G.L. Poffenbarger, AIChE Spring Natl. Meet. (Houston), 2 - 6 April 1989, Preprint n ° 61 b, incorporated as reference.

During hydrotreatment operations, the nitrogen contained in organic molecules is transformed into ammonia (NH ₃ ). This ammonia is removed by washing with water which, as a result of the presence of hydrogen sulfide (H ₂ S), provides an aqueous solution of ammonium sulfide. Until now, the aqueous solution, after having been concentrated in H ₂ S and NH ₃ by stripping (distillation), was sent to incineration. This is no longer accepted at present for environmental reasons (pollution by SO ₂ and nitrogen oxides).

Refiners are therefore required to send this product to the thermal stage of a unit Claus. However, the combustion of ammonia at the thermal stage of a Claus unit is tricky. It sometimes requires more or less modifications equipment of the Claus unit. This combustion, when it is not performed correctly, can also cause many operational difficulties (clogging, corrosion of the Claus unit). Finally, it causes a dilution of the Claus unit detrimental to the performance of this unit.

It has been described in a patent application by the applicant FR 2 745 806 incorporated as a reference, a process and a device for cracking the ammonia present in a gas containing hydrogen sulfide.

An object of the invention is to allow recovery, at least partially at the level a hydrotreating unit, hydrogen present in the form of ammonia especially in acidic refinery waters.

More specifically, the invention relates to a catalytic cracking process for ammonia present in a fluid containing hydrogen sulfide, in which introduces the fluid into a reaction zone comprising an appropriate catalyst, characterized in that the temperature of said reaction zone is from 1000 to 1400 ° C and in that the cracking effluent obtained at the outlet of said reaction zone is sent to a hydrogen recovery unit treating one or more high purge gases pressure of hydrotreating unit (s), after being possibly cooled and / or partially condensed and / or compressed and / or treated by an amine washing unit.

This cracking process can be implemented in a hydrotreatment process.

In more detail, the invention relates to a process for hydrotreating a hydrocarbon feed containing sulfur and nitrogen, in which the feed is hydrotreated in the presence of a catalyst in a hydrotreating zone (HDT), recovering a hydrotreated hydrocarbon product, a high pressure purge gas (12) comprising hydrogen, hydrogen sulfide and light hydrocarbons (C ₅ -) and a first effluent containing water and sulfide ammonium, the first effluent is purified in a stripping zone so as to recover hydrogen sulfide and ammonia, the first effluent is introduced into a cracking zone comprising a catalyst, heated between 1000 and 1400 ° C, recovers a cracking effluent (9,11) comprising hydrogen sulfide, hydrogen and nitrogen resulting from the cracking of ammonia, the method being characterized in that said cracking effluent is cooled to a temperature a liquefies, a gaseous phase (11) comprising nitrogen, hydrogen and hydrogen sulfide is recovered, the said gaseous phase is introduced into a unit (20) for extracting hydrogen sulfide, the gas phase thus substantially freed from the hydrogen sulphide in a hydrogen recovery unit (SM) and the hydrogen recovered is at least partially recycled in the hydrotreating zone (HDT).

According to a characteristic of the invention, the high pressure purge gas (12) originating of the hydrotreating zone can be introduced with said gaseous phase into the unit (20) extraction of hydrogen sulfide and recovering a hydrogen-rich gas sulfide and the gas phase substantially free of hydrogen sulfide.

According to another characteristic, the cracking effluent can be cooled to a temperature from 30 to 100 ° C in an E2 heat exchanger during a period of time at least equal to 1 second and preferably between 1 and 5 seconds.

According to a first variant of the process, the first effluent can be compressed to a pressure from 2 to 10 MPa compatible with the hydrogen sulphide extraction unit, before its introduction into the cracking zone.

According to a second variant of the process, instead of compressing the first effluent hydrotreatment, the cooled cracking effluent can be compressed in the exchanger E2 at a pressure of 2 to 10 MPa, compatible with the hydrogen extraction unit sulfide.

According to a third variant, it is possible both to partially compress the first effluent hydrotreatment before the cracking zone and partly the cooled cracking effluent in the exchanger E2 before extracting the hydrogen sulfide therefrom.

According to another characteristic of the process, it is possible to separate by decantation at least partially the water contained in the cracking effluent, the gaseous phase is recovered which is introduced into said hydrogen sulfide extraction unit and a phase aqueous liquid.

This aqueous liquid phase can advantageously be recycled in the stripping zone into which is introduced the effluent from the hydrotreatment zone which contains hydrogen sulfide and ammonia produced by the hydrotreatment unit, in the form of an aqueous solution of ammonium sulfide. This solution is striped there and we can recover on the one hand purified water at the bottom of the stripping zone and on the other hand, head of the stripping zone, the gaseous effluent containing water vapor, hydrogen sulfide and ammonia which is sent to the cracking zone Catalytic.

The invention relates to a unit for hydrotreating a hydrocarbon feed containing sulfur and nitrogen comprising a hydrotreatment reactor (HDT) which comprises a feed (1) with the feed, a feed (7) with hydrogen, a racking (2) of hydrotreated product, a racking (12) of purge gas, a racking (3) of an effluent containing water and ammonium sulfide, an extraction unit (20) of l hydrogen sulfide contained in the purge gas connected to the HDT reactor, said extraction unit comprising a line (14) for recovery of a product rich in hydrogen sulfide and a line (13) for recovery of a product poor in hydrogen sulphurized and rich in hydrogen, at least one hydrogen separator (SM) connected to the line (13) for recovering the product poor in hydrogen sulphurized and rich in hydrogen and at least one means (16) for recycling the recovered hydrogen connected to the hydrogen separator and the hy reactor drotreatment, the hydrotreatment unit being characterized in that it comprises a means for stripping (SE) of the effluent connected to the withdrawal (3), at least one catalytic cracking reactor for the stripped effluent adapted to operate between 1000 and 1400 ° C connected to the stripping means (SE), at least one cooling means (E ₂ ) of the cracked effluent containing hydrogen, at least one compressor (K) upstream of the cracking reactor or in downstream of the cooling means (E ₂ ) and an outlet line (11) of a gas phase connected to the unit (20) for extracting hydrogen sulfide.

The invention will be better understood from the figure which represents a preferred mode of embodiment of the invention and which illustrates the combination of a hydrotreating unit, of a catalytic cracking device for ammonia and the recycling of hydrogen into resulting.

We consider an HDT hydrotreating unit, treating, in the presence of a catalyst, a charge of liquid hydrocarbons containing a certain proportion of sulfur and of nitrogen, brought by a line 1. This unit produces by a line 2 a cut hydrotreated hydrocarbons, with reduced sulfur and nitrogen content.

The ammonia produced by the HDT unit is recovered by washing the effluent from the hydrotreatment reactor, in the form of an aqueous solution of ammonium sulphide sent by line 3 to a SE wastewater stripper. This stripper can possibly also supplied, via line 4, with other wastewater similar from other units not shown in the figure. The SE stripper produces purified water at the bottom, essentially free of ammonium sulphide which can be sent back to the HDT hydrotreating unit for washing with water reactor effluent, via a line 5, and possibly to other units via a line 6.

At the head of the stripper SE, we recover via a line 7, under pressure generally between 0.1 and 0.5 MPa abs. and at a temperature generally between 50 and 150 ° C, a gaseous effluent essentially consisting of water vapor and quantities substantially equal to hydrogen sulfide and ammonia. The water content of the effluent gas is generally between 10 and 80%.

The effluent can be compressed in a K compressor to a sufficient pressure to allow it, after passing through an exchanger E1, a reactor F for cracking ammonia, an E2 exchanger and a separator tank C, to be admitted to the washing unit high pressure amines 20, treating the unit's high pressure purge gas HDT hydrotreatment. It is understood that this compression stage K, placed here preferably before reactor F, can also be placed after reactor F, in E2 exchanger outlet. The latter arrangement, however, has the disadvantage of require compression of a larger gas volume, 1 mole of ammonia being dissociated in reactor F in 0.5 mole of nitrogen and 1.5 mole of hydrogen. It is also possible to compress the gaseous effluent to the pressure required for admission to the high pressure amine washing unit in two stages placed respectively before and after reactor F, as indicated above.

The compressed effluent is then sent by a line 8 to the reactor F, being possibly preheated in exchanger E1, before admission to reactor F well said. Preheating can be carried out by any conventional means of heating like an oven, but also by heat exchange with the effluent at high temperature leaving reactor F.

Reactor F is the seat of the reaction zone where the cracking of ammonia into nitrogen and hydrogen, including an embodiment and the conditions for implementation are described in patent application FR 2 745 806 of the Applicant.

The reaction effluent leaving reactor F via a line 9, at high temperature generally above 1000 ° C, is cooled in the exchanger E2 to a temperature allowing admission to the high pressure amine washing unit; this temperature is generally between 30 and 100 ° C, preferably between 40 and 60 ° C.

This reaction effluent is essentially composed of nitrogen and the resulting hydrogen of the decomposition of ammonia in reactor F, as well as hydrogen sulfide and water vapor present at the inlet and unreacted in reactor F. In addition this reaction effluent may contain traces of ammonia which have not been broken down in reactor F. Given the high conversion rates achieved in reactor F the residual ammonia content in the reaction effluent usually does not exceed 1% volume, and is preferably less than 0.2% volume.

The cooling of the reaction effluent can be carried out with a residence time in the exchanger E2, high enough to allow elemental sulfur from dissociation of part of the hydrogen sulfide in reactor F, to recombine entirely with the hydrogen present in hydrogen sulfide. Lack of catalyst allows in the E2 exchanger to avoid significant recombination of nitrogen and hydrogen to ammonia. The effluent cooled at the outlet of E2 is therefore essentially free of elemental sulfur. For this purpose the residence time of the reaction effluent in the exchanger E2 is at least equal to 1 second, preferably between 1 and 5 seconds.

It is clear that faster cooling of the reaction effluent would be possible, but would then require this cooling in 2 steps, not shown on the diagram of the figure. In the first step the reaction effluent would be cooled to a temperature slightly above the melting point of sulfur, i.e. temperature between 120 and 130 ° C. Elemental sulfur present in the effluent after this first stage could be recovered, in the form of liquid sulfur by decantation in a separating flask. The cooling of the reaction effluent as well rid of the elemental sulfur it contained can then be continued until the temperature required in a second stage.

The cooling of the reaction effluent may, depending on the final temperature reached in outlet of E2 and the water content of said effluent, cause partial condensation of the water present in this effluent. If such condensation occurs, the aqueous phase thus formed can be separated by decantation in the separator flask C.

A liquid aqueous phase can be recovered at the bottom of the flask C which may contain all residual ammonia present in the reaction effluent, as well as hydrogen sulphide dissolved in proportions substantially equivalent (in moles) to that of ammonia. This aqueous phase can be returned by a line 10 to the stripper SE. This system allows recycling of unreacted ammonia in oven F and therefore to obtain total destruction of the ammonia present in the acid waters supplying the stripper SE.

At the head of flask C, a gaseous phase is then recovered which consists solely of nitrogen, hydrogen and most of the hydrogen sulfide present in the reaction effluent, in molar proportions substantially equal to 2 H ₂ S / 1 N _2/3 H _2, and a small amount of water vapor, generally less than 5 vol%, preferably less than 1% by volume, corresponding to the vapor pressure of water in the separator tank temperature vs.

This gas phase can then be sent by a line 11 to a unit 20 of high pressure amine wash treating the high pressure purge gas produced the HDT hydrotreating unit by a line 12. This purge gas is essentially composed of hydrogen, hydrogen sulfide and hydrocarbons having mainly 1 with 5 carbon atoms, in varying proportions. It may also contain low contents, generally less than 5% vol, of other compounds such as nitrogen and water vapor.

In the amine unit 20 the purge gas and the gas phase are mixed and washed with a solution of amines so as to extract the hydrogen sulphide from the gases. Washing with amines is generally carried out at the pressure of the purge gas, this pressure being generally between 2 to 10 MPa, preferably between 3 and 7 MPa, and at a temperature generally between 30 and 100 ° C, preferably between 40 and 60 ° C.

The amine unit then produces, under substantially equal pressure and temperature to those for washing, a washed gas essentially free of hydrogen sulfide and containing the major part of the other compounds of the treated gases. The washed gas generally contains from 20 to 95% vol of hydrogen, preferably from 50 to 90% vol, with variable proportions of nitrogen, hydrocarbons from 1 to 5 carbon atoms and traces of water vapor (corresponding substantially to the vapor pressure of water at the temperature of said washing).

The amine unit also produces, under a pressure generally lower than that washing, preferably between 0.2 and 0.5 MPa abs. a gas rich in hydrogen sulfide, preferably containing at least 50% vol of hydrogen sulfide with varying proportions of hydrocarbons, which is usually sent, via a line 14, to a Claus unit.

The washed gas can then be sent via a line 13 to a recovery unit hydrogen. This unit can be a cryogenic distillation, adsorption process or separation by membranes. The washed gas being available under pressure relatively high a separation by membranes is preferably used such than the SM unit shown in the figure. The washed gas can optionally be slightly cooled or reheated before being admitted to the permeation unit proper so as to be at the optimum temperature to separate hydrogen by gas permeation, this temperature being generally understood between 30 and 150 ° C, preferably between 50 and 100 ° C.

The SM unit then makes it possible to produce, on the one hand, a gas depleted in hydrogen (retentate), generally containing less than 50% vol of hydrogen, preferably from 5 to 30% theft with most of the other compounds present in said washed gas, under a pressure close to that of the washed gas; on the other hand a gas enriched in hydrogen (permeate), generally containing more than 90% vol, preferably more than 95% flight of hydrogen with varying proportions of the other compounds present in the washed gas, under a pressure lower than that of the washed gas, generally less than 2 MPa abs. and preferably between 0.5 and I MPa abs.

The retentate can then for example be sent via a line 15 to the gas network fuel from the refinery. The permeate, recovered via line 16, can be mixed with the make-up hydrogen supplying the HDT hydrotreating unit, via a line 17.

One of the advantages of the process of the invention is that it allows total destruction of ammonia present in refinery wastewater, without any harmful release to the atmosphere.

Another advantage of the process of the invention lies in the fact that hydrogen sulfide present in the form of ammonium sulfide in refinery wastewater, can thus be sent to the Claus unit in a concentrated form, in particular free ammonia but also free of products (nitrogen and hydrogen) formed by the dissociation of this ammonia. This avoids combustion problems of ammonia in the Claus units and in particular to reduce the gas dilution of Claus.

Another advantage of the process lies in the possibility that it offers to recycle a part significant hydrogen present in the form of ammonia in the wastewater of refinery.

Finally, a last advantage of the process lies in its simplicity and in particular in the fact that it only requires the additional installation of a reduced number equipment, compared to those normally found in an equipped refinery hydrotreating units. In fact, the amine washing units of the purge gas high pressure, hydrogen recovery by membrane on the high purge gas pressure SM and sewage stripping SE are normally present around the modern hydrotreating units. The method of the invention can be installed generally without significant modification of these existing units. So it does require that the specific installation of compressor K, oven F, exchangers E1 and E2, as well as the separator flask C.

The following comparative example illustrates the invention.

We consider a hydrotreating unit which treats a load of liquid hydrocarbons at a flow rate of 162.4 tonnes / h. This charge contains 2.12% by weight of sulfur and 0.057% by weight of nitrogen. This unit converts 98% of the sulfur entering the unit into H ₂ S and 14% of the nitrogen into NH ₃ in the presence of a conventional catalyst.

This unit produces by line 3 waste water at a flow rate of 8173 kg / h and containing 0.6% by weight of ammonium sulphide. This water is treated in a SE stripper, which is operated under a pressure of 0.2 MPa abs. This stripper is further supplied, via line 4, with a flow rate of 132,550 kg / h of water containing 2% by weight of ammonium sulphide, coming from another refining unit. The stripper produces at the head, at a temperature of 80 ° C., a gas containing 20% mol of water vapor, 40% mol of ammonia and 40% mol of hydrogen sulfide, at a flow rate of 2965 Nm ³ / h . At the bottom, it produces purified water at a temperature of 119 ° C and at a flow rate of 137,548 kg / h.

When the process of the invention is not implemented, the gas obtained at the top of the stripper should be sent to cremation or to a Claus unit when possible.

The hydrotreating unit is also supplied, by line 17, with a make-up gas rich in hydrogen. Most of this hydrogen is consumed chemically by hydrotreatment reactions. Another part is found in the purge gas high pressure produced by line 12, under a pressure of 4.6 MPa abs. This gas is desulphurized by washing with amines and then admitted via line 13 into a unit of hydrogen recovery by polyaramide membrane (Medal). We can thus recover most of the hydrogen present in the high pressure purge gas and recycle it via line 16 to the hydrotreating unit.

Table 1 shows the hydrogen balance of the hydrotreatment unit, as it usually occurs when the process of the invention is not implemented. Hydrogen balance of the hydrotreating unit in the absence of the process of the invention extra
(17) HP purge
(12) Washed purge
(13) retentate
(15) permeate
(16) Composition
(%flight) H ₂ 91.93 79.48 81.10 47.26 98.77 C ₁ + 6.65 15.35 15.66 43.99 0.87 N ₂ 1.36 3.18 3.24 8.75 0.36 H ₂ S - 1.99 - - H ₂ O - - - - NH ₃ - - - - P (bar abs) 20 46 45 45 20 T (° C) 90 50 50 90 90 Flow (Nm ³ / h) 23536 8166 8003 2746 5257

We can see on this table that 80% of the hydrogen present in the high purge gas pressure are recovered by the membrane unit. The amount of hydrogen as well recovered represents 19.35% of the hydrogen supplied to the hydrotreatment unit (makeup + permeate). The hydrogen lost in the retentate represents only 4.84% of this hydrogen supply.

On this same unit we now install the equipment (compressors K and K1 (not shown), oven F, exchangers E1 and E2 and separator tank C) allowing implement the method of the invention.

The SE stripper is then supplied not only with 8,173 kg / h of waste water at 0.6% wt of ammonium sulphide coming from the HDT unit and with 132550 kg / h of water containing 2% wt of sulphide d ammonium, but also, via line 10, by the water condensed in the separator flask C. The flow rate of this condensed water is 473 kg / h and it contains 0.85% by weight of ammonium sulphide. The stripper SE then produces at the head, under a pressure of 0.2 MPa abs. and at a temperature of 80 ° C., a gas containing 40% mol of hydrogen sulphide, 40% mol of ammonia and 20% mol of water vapor, with a flow rate of 2968 Nm ³ / h. This stripper at the bottom produces purified water at a temperature of 119 ° C, with a flow rate of 138,016 kg / h.

The gas thus obtained at the top of the stripper SE is compressed in the compressor K to a pressure of 0.7 MPa abs. then reheated in the exchanger E1 to a temperature of 1000 ° C. This hot gas then feeds an oven F, produced according to the method described in application FR 96 / 02.909 of the Applicant. The hot gas leaving the oven F is cooled in the exchanger E2 to a temperature of 50 ° C. The residence time in the exchanger E2 is fixed at 2 s. This cooling causes most of the water vapor present in the gas leaving the oven to condense. It is this condensed water which is recovered at the level of the separator flask C and is returned by line 10 to the stripper SE. Is also recovered at the separator tank C, via line 11, a flow rate of 3566 Nm ³ / h of a gas under a pressure of 0.6 MPa abs. the composition of which is given in Table 2 below (cracked gas). The ammonia decomposition rate observed at the outlet of E2 is 99.85%. No significant decomposition of hydrogen sulfide can be observed after cooling in E2.

The cracked gas thus recovered by line 11 is compressed to a pressure of 4.6 Mpa abs. in a second compressor K1, not shown in the figure, then mixed with the high-pressure purge gas leaving the HDT unit via line 12. This gas mixture is washed in the amine washing unit 20 which produces through the line 13 a washed gas supplying the membrane separator SM at a pressure of 4.5 MPa. As before, the permeate from the SM unit is recycled to the hydrotreating unit. Table 2 shows the hydrogen balance of the hydrotreatment unit when the process of the invention is implemented. Hydrogen balance of the hydrotreating unit with the process of the invention extra
(17) HP purge
(12) Cracked gas
(11) Washed gas
(13) retentate
(15) permeate
(16) Composition (% vol) H ₂ 91.93 79.48 49.88 79.71 45.39 98.29 C ₁ + 6.65 15.35 - 12.08 33,06 0.71 N ₂ 1.36 3.18 16,60 8.21 21.54 0.99 H ₂ S - 1.99 33.26 - - H ₂ O - - 0.26 - - NH ₃ - - - - - P (bar abs) 20 46 6 45 45 20 T (° C) 90 50 50 50 90 90 Flow (Nm ³ / h) 21989 8166 3566 10374 3644 6730

We can see in Table 2 that the amount of hydrogen recovered by the unit at membranes SM this time represents 24.65% of the hydrogen supply (booster + permeate) of the hydrotreatment unit, always with a recovery rate of 80% at level of the membrane unit itself. Recovery of hydrogen coming from the cracking of ammonia allows in particular, compared to the previous case, reduce the consumption of make-up hydrogen by 6.6%.

Claims (11)

1. Process for hydrotreating a hydrocarbon feedstock that contains sulfur and nitrogen, in which the feedstock is hydrotreated in the presence of a catalyst in a hydrotreatment zone (HDT); a hydrotreated hydrocarbon product, a high-pressure purging gas (12) that contains hydrogen, hydrogen sulfide, and light hydrocarbons (C₅-), and a first effluent that contains water and ammonium sulfide are recovered; the first effluent is purified in a stripping zone (SE) to recover the hydrogen sulfide and the ammonia; the first effluent is introduced into a cracking zone that comprises a catalyst, heated between 1000 and 1400°C; a cracking effluent (9, 11), which contains hydrogen sulfide, hydrogen and nitrogen that results from the cracking of the ammonia are recovered; whereby the process is characterized in that said cracking effluent is cooled to a suitable temperature; a gaseous phase (11) that contains nitrogen, hydrogen, and hydrogen sulfide is recovered; said gaseous phase is introduced into a unit (20) for extracting hydrogen sulfide; the gaseous phase from which hydrogen sulfide has thus been removed is passed through a hydrogen recovery unit (SM), and at least part of the hydrogen that is recovered in hydrotreatment zone (HDT) is recycled.
2. Process according to claim 1, wherein high-pressure purging gas (12) that comes from the hydrotreatment zone is introduced into unit (20) for extraction of the hydrogen sulfide, and a hydrogen sulfide-rich gas and the gaseous phase from which hydrogen sulfide has been removed are recovered.
3. Process according to one of claims 1 and 2, wherein the cracking effluent is cooled to a temperature of 30 to 100°C in a heat exchanger E2 during a period of time that is at least equal to 1 second and preferably between 1 and 5 seconds.
4. Process according to one of claims 1 to 3, wherein the first effluent is compressed to a pressure of 2 to 10 MPa which is compatible with the extraction unit of the hydrogen sulfide, before it is introduced into the cracking zone.
5. Process according to one of claims 1 to 4, wherein the cracking effluent that is cooled in exchanger E2 is compressed to a pressure of 2 to 10 MPa which is compatible with the extraction unit of the hydrogen sulfide.
6. Process according to one of claims 1 to 5, wherein the hydrogen sulfide extraction unit is a high-pressure unit for extraction with amines.
7. Process according to one of claims 1 to 6, wherein the hydrogen recovery unit is a membrane permeation unit.
8. Process according to one of claims 1 to 7, wherein at least a portion of the water that is contained in the cracking effluent is separated by decanting, and the gaseous phase that is introduced into said unit for extraction of hydrogen sulfide and an aqueous liquid phase are recovered.
9. Process according to claim 8, wherein said aqueous liquid phase is recycled in the stripping zone.
10. Unit for hydrotreatment of a hydrocarbon feedstock that contains sulfur and nitrogen, whereby said unit contains a hydrotreatment reactor (HDT) that comprises a supply (1) for the feedstock, a supply (17) for hydrogen, a drain (2) for hydrotreated product, a drain (12) for purging gas, a drain (3) for an effluent that contains water and ammonium sulfide, and a unit for extraction (20) of the hydrogen sulfide that is contained in the purging gas that is connected to the reactor (HDT), whereby said extraction unit contains a line (14) for recovering a product that is rich in hydrogen sulfide, and a line (13) for recovering a product that is low in hydrogen sulfide and rich in hydrogen, at least one hydrogen separator (SM) that is connected to line (13) for recovery of the product that is low in hydrogen sulfide and rich in hydrogen and at least one means (16) for recycling the recovered hydrogen that is connected to the hydrogen separator and to the hydrotreatment reactor, with the hydrotreatment unit being characterized in that it contains an effluent stripping means (SE) that is connected to drain (3), at least one catalytic cracking reactor for the stripped effluent that is suitable for operating between 1000 and 1400°C and that is connected to stripping means (SE), at least one cooling means (E₂) for the cracked effluent that contains hydrogen, at least one compressor (K) that is upstream from the cracking reactor or downstream from cooling means (E₂), and an output line (11) for a gaseous phase that is connected to unit (20) for extracting the hydrogen sulfide.
11. Unit according to claim 10, in which a phase separator is interposed between cooling means E2 and extraction unit (20), containing a line (10) for recycling a liquid phase in the stripping means and output line (11) for a gaseous phase that is connected to said hydrogen sulfide extraction unit (20).

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