Process of hydrogen recycling in refinery

Abstract

The disclosure concerns a hydroprocessing of a hydrocarbon feedstock (1) in which the acid gas stream with hydrogen sulphide (11) that is generated is cracked to generate a stream (13) comprising hydrogen and elemental sulphur. The disclosure relates also to an installation for removing one or more organic sulphur compounds from a hydrocarbon feedstock (1).

Description

[0001] Process of hydrogen recycling in refinery

[0002] Technical field

[0003] The present disclosure relates to a hydroprocessing as well as to an installation to perform such a process.

[0004] Technical background

[0005] In hydroprocessing, a refinery incorporates a range of catalytic processes including hydrotreating and hydrocracking for removal of sulfur, oxygen, nitrogen and metals. The process is critical in the production of low sulfur fuels to reduce emissions, as removing the sulfur reduces SOx emissions when fuels are combusted. Sulfur is also harmful for downstream noble metal - containing reformer catalysts and must be removed to the level of suitable specifications. This “clean-up” also saturates olefins to yield easier-to-process intermediates.

[0006] These reactions are carried out in a hydrogen-rich environment over a fixed catalyst bed. The process replaces sulfur or nitrogen contaminants in the hydrocarbon chains with hydrogen, making the process a consumer of hydrogen. Protection of the catalyst beds from fouling is critical to maintaining long term hydrotreating efficiency. Treated products are then stabilized with heat to remove H2S and light ends.

[0007] A part of hydrogen required for hydroprocessing unit operation is irreversibly lost, for instance, in a form of hydrogen sulphide, which is then directed into conventional sulphur recovery units (SRU), which imply the implementation of the Claus process as summarized in accordance with the following equations:

[0008] H2S + 3 / 2 O2 SO2 + H2O (exothermic)

[0009] 2 H2S + SO23 S + 2 H2O

[0010] => 3 H2S+ 3 / 2 O23 S + 3 H2O + heat

[0011] The Claus reaction implies a stoichiometric ratio between O2 and H2S that is amounting to 0.5.

[0012] As it can be seen from these equations, in a SRU, hydrogen is lost in a form of water. This loss hinders optimization of refinery operation and could cause significant economical inefficiencies if a refinery is supplied with “green” hydrogen, i.e., coming from an electrolyzer. On the other hand, processes for the production of hydrogen from hydrogen sulphide, such as those described in US 4,481 ,181 , EP 2 928 819, WO 2014 / 073966 or WO 2019 / 240586, are known but were not yet implemented.

[0013] The objective of this disclosure is therefore to provide a scheme of hydroprocessing which also allows hydrogen recycling and therefore reduces the overall hydrogen consumption in a refinery.

[0014] Summary

[0015] The process

[0016] According to a first aspect, the disclosure relates to a hydroprocessing, remarkable in that it comprises the following steps: a) providing a hydrocarbon feedstock, said hydrocarbon feedstock comprising one or more organic sulphur compounds; b) providing a hydrogen stream; c) performing a hydrogenation reaction of the hydrocarbon feedstock with the hydrogen stream under reaction conditions, to form a first effluent comprising one or more hydrogenated products, unreacted hydrogen, and acid gas with hydrogen sulphide; d) separating said one or more hydrogenated products from said first effluent, to recover a gaseous H2-rich effluent and a liquid effluent, said gaseous H2-rich effluent comprising acid gas with hydrogen sulphide; e) performing a step of amine treating onto said gaseous H2-rich effluent to form a first hydrogen effluent and an acid gas stream with hydrogen sulphide; and f) cracking said acid gas stream with hydrogen sulphide to generate a stream comprising hydrogen and elemental sulphur.

[0017] In particular, the present disclosure relates to a hydroprocessing, remarkable in that it comprises the following steps: a) providing a hydrocarbon feedstock, said hydrocarbon feedstock comprising one or more organic sulphur compounds; b) providing a hydrogen stream; c) performing a hydrogenation reaction of the hydrocarbon feedstock with the hydrogen stream under reaction conditions, to form a first effluent comprising one or more hydrogenated products, unreacted hydrogen, and acid gas with hydrogen sulphide; d) separating said one or more hydrogenated products from said first effluent, to recover a gaseous H2-rich effluent and a liquid effluent, said gaseous H2-rich effluent comprising acid gas with hydrogen sulphide; e) performing a step of amine treating onto said gaseous H2-rich effluent to form a first hydrogen effluent and an acid gas stream with hydrogen sulphide; and f) cracking said acid gas stream with hydrogen sulphide to generate a stream comprising hydrogen and elemental sulphur, wherein the process comprises the step of generating a second hydrogen effluent (21) from the stream (13) comprising hydrogen and elemental sulphur, and the step of using the second hydrogen effluent (21), at least partially or in full, into the hydrogenation reaction of the hydrocarbon feedstock performed at step (c).

[0018] Surprisingly, it was found that implementing a hydroprocessing in which the acid gas stream comprising hydrogen sulphide is cracked, instead of being subjected to the Claus process allows for generating a stream comprising hydrogen and elemental sulphur. The fact that the stream comprises hydrogen is becoming an asset for the hydroprocessing performed within the refineries, because it lets open the possibility to recover a hydrogen stream and to use it, either as an energetic stream for downstream application, or even better, for working the hydroprocessing itself. It is understood that recovering a hydrogen stream allows for an overall reduced consumption of hydrogen.

[0019] Optionally, the process further comprises step (g) of stripping the liquid effluent recovered at step (d) to recover one or more hydrodesulfurized products.

[0020] Advantageously, the process comprises the step of using the first hydrogen effluent in the hydrogenation reaction of the hydrocarbon feedstock performed at step (c) and / or the step of directing the first hydrogen effluent into the hydrogen stream provided at step (b).

[0021] Advantageously, the process comprises the step of generating a second hydrogen effluent from the stream comprising hydrogen and elemental sulphur, and the step of using the second hydrogen effluent in the hydrogenation reaction of the hydrocarbon feedstock performed at step (c) and / or the step of directing the second hydrogen effluent into the hydrogen stream provided at step (b).

[0022] Advantageously, the process comprises the step of using the first hydrogen effluent in the hydrogenation reaction of the hydrocarbon feedstock performed at step (c) and / or the step of directing the first hydrogen effluent into the hydrogen stream provided at step (b); and the process also comprises the step of generating a second hydrogen effluent from the stream comprising hydrogen and elemental sulphur, and the step of using the second hydrogen effluent into the hydrogenation reaction of the hydrocarbon feedstock performed at step (c) and / or the step of directing the second hydrogen effluent into the hydrogen stream provided at step (b). In other words, the first hydrogen effluent and the second hydrogen effluent are recycled.

[0023] With preference, when the process comprises the step of generating a second hydrogen effluent from the stream comprising hydrogen and elemental sulpur, the process comprises the following sub-steps: i. separating the stream comprising hydrogen and elemental sulphur generated at step (f), to form elemental sulphur and a sour hydrogen stream; and ii. performing a step of amine treating onto said sour hydrogen stream to generate a second hydrogen effluent.

[0024] Considering that the hydrogen stream required in the hydroprocessing generally comes from steam methane reforming (SMR) reaction which is a strongly endothermic reaction (AH = +206 kJ / mol), the process of the present disclosure, by allowing the generation of hydrogen and its possibility to recycle it, will considerably alleviate the energy deficiency generally linked to the hydroprocessing implemented into refineries.

[0025] Alternatively, or more preferably complementary to this embodiment, the first hydrogen effluent formed at step (e) and / or the second hydrogen effluent generated at step (i) is directed into downstream applications.

[0026] Advantageously, the gaseous H2-rich effluent recovered from step (d) further comprises water in the gaseous phase and the process comprises the further step of subjecting said gaseous H2-rich effluent to an additional separation step to recover a water stream.

[0027] In a first embodiment, step (f) of cracking is an autothermal non-catalytic cracking reaction. For example, step (f) of cracking is an autothermal non-catalytic cracking reaction performed under reaction conditions comprising a temperature of at least 1100°C, preferably of at least 1200°C. For example, one part of the acid gas stream with hydrogen sulphide is subjected to a Claus reaction to produce heat, and the heat produced from the Claus reaction provides a temperature sufficient to perform a non-catalytic cracking reaction of the remaining of the acid gas stream with hydrogen sulphide. With preference, one part of the acid gas stream with hydrogen sulphide is subjected to a Claus reaction to produce heat, and the heat produced from the Claus reaction provides the temperature of at least 1100°C, preferably at least 1200°C, required for the non-catalytic cracking reaction of the remaining of the acid gas stream with hydrogen sulphide.

[0028] In the first embodiment, the stoichiometric ratio between O2 and H2S is amounting to less than 0.50, preferably less than 0.40.

[0029] Advantageously, step (f) of cracking the acid gas stream with hydrogen sulphide formed at step (e) to generate a stream comprising hydrogen and elemental sulphur comprises providing oxygen and reacting said oxygen with the acid gas stream with hydrogen sulphide formed at step (e), wherein the stoichiometric ratio between O2 and H2S is amounting to less than 0.50, preferably less than 0.45, even more preferably less than 0.40, most preferably less than 0.35, even most preferably less than 0.30. For example, the stoichiometric ratio between O2 and H2S is ranging between 0.20 and less than 0.50, preferably between 0.20 and 0.30.

[0030] In a second alternative embodiment, step (f) of cracking is a super adiabatic combustion decomposition reaction. For example, step (f) of cracking is a super adiabatic combustion decomposition under reaction conditions comprising a temperature ranging between 500°C and 1500°C, preferably comprising a temperature of at least 500°C, or of at least 700°C, more preferably of at least 1100°C, even preferably of at least 1200°C.

[0031] In the second embodiment, the stoichiometric ratio between O2 and H2S is amounting to less than 0.50, preferably less than 0.30.

[0032] In a third alternative embodiment, step (f) of cracking is performed by directing the acid gas stream with hydrogen sulphide within a plasma made of a plasmagenic gas, wherein said plasmagenic gas is the hydrogen sulphide of the acid gas stream with hydrogen sulphide.

[0033] In a fourth alternative embodiment, step (f) of cracking is performed by oxidizing the hydrogen sulphide of the acid gas stream with hydrogen sulphide with ferric ions.

[0034] In a fifth alternative embodiment, step (f) of cracking is a splitting of H2S with the production of H2 by passing an electric current through a fluidized bed comprising particles and wherein at least 10 wt.% of the particles of the bed are electrically conductive and have a resistivity ranging from 0.001 Ohm. cm to 500 Ohm. cm at 800°C.

[0035] Additional advantageous features of the hydroprocessinq of the disclosure

[0036] For example, the hydrocarbon feedstock comprising one or more organic sulphur compounds provided at step (a) comprises one or more liquid C6+ hydrocarbons, naphtha, gasoline, petrol, jet fuel, kerosene, diesel fuel, fuel oils, or a mixture thereof; preferably one or more liquid C6+ hydrocarbons.

[0037] For example, the one or more organic sulphur compounds are one or more thiols, one or more thiophenes, one or more organic sulphides, one or more organic disulphides or any mixture thereof.

[0038] For example, the amount of the one or more organic sulphur compounds in the hydrocarbon feedstock provided at step (a) is ranging between 1 wt.% and 30 wt.% based on the total weight of the hydrocarbon feedstock and as determined by CH NS elemental analysis, or between 5 wt.% and 25 wt.%.

[0039] For example, at least a part of the hydrogen stream provided at step (b) originates from a steam methane reforming reaction.

[0040] For example, the reaction conditions of step (c) comprise a temperature ranging between 300°C and 400°C, or between 325°C and 375°C.

[0041] For example, the reaction conditions of step (c) comprise a pressure ranging between 3.0 MPa and 13.0 MPa, or between 5.0 MPa and 10.0 MPa.

[0042] The installation

[0043] According to a second aspect, the disclosure relates to an installation for removing one or more organic sulphur compounds from a hydrocarbon feedstock, said installation comprising a hydroprocessing unit and a separation unit downstream of said hydroprocessing unit, the separation unit comprising an amine treatment section, the installation is remarkable in that it comprises a hydrogen sulphide cracking unit downstream of said separation unit and a line directing an acid gas stream with hydrogen sulphide between the amine treatment section and the hydrogen sulphide cracking unit.

[0044] Advantageously, the installation comprises a hydrogen separation unit downstream of said hydrogen sulphide cracking unit. With preference, the installation comprises a line directing a sour hydrogen stream from the hydrogen separation unit to the amine treatment section.

[0045] In particular, the disclosure relates to an installation for removing one or more organic sulphur compounds from a hydrocarbon feedstock, said installation comprising a hydroprocessing unit and a separation unit downstream of said hydroprocessing unit, the separation unit comprising an amine treatment section, the installation is remarkable in that it comprises a hydrogen sulphide cracking unit downstream of said separation unit and a line directing an acid gas stream with hydrogen sulphide between the amine treatment section and the hydrogen sulphide cracking unit, wherein the installation comprises a hydrogen separation unit downstream of said hydrogen sulphide cracking unit and a line directing a sour hydrogen stream from the hydrogen separation unit to the hydroprocessing unit.

[0046] Advantageously, the installation comprises a first line exiting the amine treatment section to convey a first hydrogen effluent to the hydroprocessing unit.

[0047] Advantageously, the amine treatment section is a first amine treatment section, and the installation is remarkable in that the line directing the sour hydrogen stream from the hydrogen separation unit to the hydroprocessing unit goes through one or more additional amine treatment sections and wherein the installation comprises a second line exiting the one or more additional amine treatment sections to convey a second hydrogen effluent to the hydroprocessing unit.

[0048] With preference, the one or more additional amine treatment sections are or comprise the first amine treatment section.

[0049] Advantageously, in a first embodiment, the hydrogen sulphide cracking unit comprises at least one cracking coil to perform a non-catalytic H2S cracking. With preference, the hydrogen sulphide cracking unit comprises one or more Claus burners and the one or more cracking coils are arranged within at least one of the one or more Claus burners and / or in an adjacent manner with at least one of the one or more Claus burners. More preferably, the one or more cracking coils are arranged within at least one of the one or more Claus burners.

[0050] Advantageously, in a second alternative embodiment, the hydrogen sulphide cracking unit comprises a partial oxidation reaction zone comprising one or more catalysts.

[0051] Advantageously, in a third alternative embodiment, the hydrogen sulphide cracking unit comprises at least one plasma torch.

[0052] Advantageously, in a fourth alternative embodiment, the hydrogen sulphide cracking unit comprises a system with an electrolysis reactor having an anode and a cathode and with an absorption reactor arranged between said anode and said cathode.

[0053] Advantageously, in a fifth alternative embodiment, the hydrogen sulphide cracking unit comprises at least one fluidized bed reactor with a bed comprising particles and wherein at least 10 wt.% of the particles of the bed are electrically conductive and have a resistivity ranging from 0.001 Ohm. cm to 500 Ohm. cm at 800°C.

[0054] For example, the separation unit further comprises a gas separator and a stripping section, the gas separator comprising an overhead arranged upstream of the amine treatment section and directing a gaseous H2-rich effluent to the amine treatment section, and the gas separator comprising a bottom line directing a liquid effluent to the stripping section.

[0055] Advantageously, the installation comprises a first line exiting the amine treatment section to convey a first hydrogen effluent to the hydroprocessing unit.

[0056] Advantageously, the installation comprises a second line exiting the amine treatment section to convey a second hydrogen effluent to the hydroprocessing unit.

[0057] For example, the installation further comprises a steam methane reforming (SMR) unit arranged upstream of the hydroprocessing unit.

[0058] For example, the installation further comprises a water electrolyzer arranged upstream of the hydroprocessing unit. Advantageously, the water electrolyzer is selected from a protonexchange membrane (PEM), an alkaline electrolyzer (AEL), or a solid oxide electrolyzer (SOEC) unit.

[0059] Description of the figures

[0060] Figure 1 shows a scheme of the installation per the present disclosure.

[0061] Figure 2 shows an hydrogen sulphide cracking unit per the first embodiment according to the present disclosure.

[0062] Detailed description

[0063] For the disclosure, the following definitions are given:

[0064] The terms "comprising", "comprises" and "comprised of" as used herein are synonymous with "including", "includes" or "containing", "contains", and are inclusive or open-ended and do not exclude additional, non-recited members, elements or method steps. The terms "comprising”, "comprises" and "comprised of" also include the term “consisting of”.

[0065] The recitation of numerical ranges by endpoints includes all integer numbers and, where appropriate, fractions subsumed within that range (e.g., 1 to 5 can include 1 , 2, 3, 4, 5 when referring to, for example, a number of elements, and can also include 1.5, 2, 2.75 and 3.80, when referring to, for example, measurements). The recitation of endpoints also includes the recited endpoint values themselves (e.g., from 1.0 to 5.0 includes both 1.0 and 5.0). Any numerical range recited herein is intended to include all sub-ranges subsumed therein.

[0066] The particular features, structures, characteristics or embodiments may be combined in any suitable manner, as would be apparent to a person skilled in the art from this disclosure, in one or more embodiments.

[0067] The present disclosure relates to a hydroprocessing, remarkable in that it comprises the following steps: a) providing a hydrocarbon feedstock 1 , said hydrocarbon feedstock 1 comprising one or more organic sulphur compounds; b) providing a hydrogen stream 3; c) performing a hydrogenation reaction of the hydrocarbon feedstock 1 with the hydrogen stream 3 under reaction conditions, to form a first effluent 5 comprising one or more hydrogenated products, unreacted hydrogen, and acid gas with hydrogen sulphide; d) separating said one or more hydrogenated products from said first effluent 5, to recover a gaseous H2-rich effluent 7 and a liquid effluent 9, said gaseous H2-rich effluent 7 comprising acid gas with hydrogen sulphide; e) performing a step of amine treating onto said gaseous H2-rich effluent 7 to form a first hydrogen effluent 10 and an acid gas stream with hydrogen sulphide 11 ; and f) cracking said acid gas stream with hydrogen sulphide 11 to generate a stream 13 comprising hydrogen and elemental sulphur, wherein the process comprises the step of generating a second hydrogen effluent 21 from the stream 13 comprising hydrogen and elemental sulphur, and the step of using the second hydrogen effluent 21 , at least partially or in full, into the hydrogenation reaction of the hydrocarbon feedstock performed at step (c).

[0068] The present disclosure also relates to an installation for removing one or more organic sulphur compounds from a hydrocarbon feedstock 1 , said installation comprising a hydroprocessing unit 100 and a separation unit 200 downstream of said hydroprocessing unit 100, the separation unit 200 comprising an amine treatment section 210, the installation is remarkable in that it comprises a hydrogen sulphide cracking unit 300 downstream of said separation unit 200 and a line directing an acid gas stream with hydrogen sulphide 11 between the amine treatment section 210 and the hydrogen sulphide cracking unit 300, wherein the installation comprises a hydrogen separation unit 400 downstream of said hydrogen sulphide cracking unit 300 and a line directing a sour hydrogen stream 19 from the hydrogen separation unit 400 to the hydroprocessing unit 100.

[0069] The process and installation of the present disclosure will be described with the scheme of the installation depicted in Figure 1.

[0070] The present disclosure relates to a hydroprocessing, remarkable in that it comprises the step of (a) providing a hydrocarbon feedstock 1 comprising one or more organic sulphur compounds, said hydrocarbon feedstock 1 comprising one or more organic sulphur compounds being, for example, a feedstock of one or more liquid C6+ hydrocarbons, naphtha, gasoline, petrol, jet fuel, kerosene, diesel fuel, fuel oils, or a mixture thereof. With preference, the hydrocarbon feedstock 1 comprising one or more organic sulphur compounds is a feedstock of one or more liquid C6+ hydrocarbons.

[0071] The one or more organic sulphur compounds can be one or more thiols, one or more thiophenes, one or more organic sulphides, one or more organic disulphides or any mixture thereof. They can be in an amount ranging between 1 wt.% and 30 wt.% based on the total weight of the hydrocarbon feedstock 1 and as determined by CH NS elemental analysis, or between 5 wt.% and 25 wt.%.

[0072] The step (b) is the step of providing a hydrogen stream 3. Said hydrogen stream can be for example generated in a steam methane reforming (SMR) unit (not shown), which implies the reaction between methane and water to form syngas, which could be further subjected to a water-gas shift (WGS) to convert carbon monoxide into carbon dioxide and improve yield of hydrogen. Hydrogen is then separated and can be used as the hydrogen stream 3.

[0073] The hydrocarbon feedstock 1 and the hydrogen stream 3 are both provided into a hydroprocessing unit 100. The hydrocarbon feedstock 1 can be advantageously pre-heated into a feed heater. The hydrocarbon feedstock 1 and the hydrogen stream 3 are advantageously mixed or introduced into at least one hydroprocessing reactor. For example, the hydroprocessing unit 100 can comprise two hydroprocessing reactors arranged in series, and the hydrogen stream 3 can be provided in each hydroprocessing reactor. Each hydroprocessing reactor is provided with a catalyst, for example one or more metal sulfides.

[0074] The one or more metals of the one or more metal sulfides includes one or more metals from Groups V, VI B, VIII metals of the Periodic Table, or mixture thereof. Catalysts containing a Group VIB metal such as molybdenum and a Group VIII such as cobalt, nickel, palladium or a combination thereof are preferred. The Group VIII metal provides increased overall average activity. Catalysts suitable for the hydroprocessing reaction include cobalt-molybdenum, nickel-molybdenum and nickel-tungsten. The metals are generally present as oxides supported on a neutral base such as alumina, silica-alumina, titania-zirconia; or the like. The metals are reduced to the sulfide, such as molybdenum disulfide (M0S2), either in use or prior to use by exposure to sulfur compounds containing streams and hydrogen. Then, at step (c), a hydrogenation reaction of the hydrocarbon feedstock 1 provided at step (a) with the hydrogen stream 3 provided at step (b) under reaction conditions is performed, for example in the one or more hydroprocessing reactors. This results in the formation of a first effluent 5 comprising one or more hydrogenated products, unreacted hydrogen, acid gas with hydrogen sulphide and unreacted hydrocarbon feedstock. For example, the acid gas can further comprise carbon dioxide. Advantageously, step (c) can be carried out at a temperature ranging between 300°C and 400°C, or between 325°C and 375°C and / or at a pressure ranging between 3.0 MPa and 13.0 MPa, or between 5.0 MPa and 10.0 MPa.

[0075] Then, the installation further comprises a separation unit 200, which is arranged downstream of the hydroprocessing unit 100. In the separation unit 200, a step (d) of separating the one or more hydrogenated products from the first effluent 5 is carried out, preferably in a gas separator 230. For example, the gas separator 230 is a distillation column, which can be operated under distillation conditions, such as at temperatures ranging between 30°C and 400°C and / or at a pressure ranging between 0.02 MPa and 0.5 MPa. This low temperature is sufficient to remove the hydrogen sulphide that has been formed during the hydrogenation reaction since the boiling point of hydrogen sulphide is about -60°C. In the overhead of the gas separator 230, or preferably of the distillation column, a gaseous H2-rich effluent 7 comprising acid gas with hydrogen sulphide can be recovered. For example, the gaseous H2- rich effluent 7 comprises H2 in an amount ranging between 30 vol.% and 70 vol.% of said gaseous H2-rich effluent 7. Other components of said gaseous H2-rich effluent 7 are hydrogen sulphide and unreacted hydrocarbon feedstock. In a bottom line of the gas separator 230, or preferably of the distillation column, a liquid effluent 9 can also be recovered. The liquid effluent 9 comprises the one or more hydrogenated products which have been desulphurized. They do not contain anymore the one or more organic sulphur compounds that were present in the hydrocarbon feedstock 1 , nor the hydrogen sulphide, since the hydrogen sulphide has been removed through the overhead of the gas separator 230. The liquid effluent 9 can be optionally directed in a step (g) into a stripping section 240 which is a fluidic connection with the bottom line of the gas separator 230, so that one or more fractions of hydrodesulfurized products 15 can be recovered.

[0076] The gaseous H2-rich effluent 7 comprising acid gas with hydrogen sulphide is then directed into an amine treatment section 210 which is included in the separation unit 200, so that a step (e) of performing an amine treating onto said gaseous H2-rich effluent 7 is carried out. For example, the amine treatment section 210 comprises one or more amino compounds selected from diethanolamine (DEA), monoethanolamine (MEA), methyldiethanolamine (MDEA), diisopropanolaimine (DI PEA), aminoethoxyethanol (diglycolamine) (DGA) or a mixture thereof. As the acid gas with hydrogen sulphide may also comprise carbon dioxide, such carbon dioxide is also removed in the amine treatment section 210. This results in the formation of a first hydrogen effluent 10 and an acid gas stream with hydrogen sulphide 11 , which may also comprise carbon dioxide. The amine treating of said gaseous H2-rich effluent 7 can also produce an F^S-free H2-rich gas stream 10 which can be optionally directed into the hydroprocessing unit 100 and / or mixed with the hydrogen stream 3. Indeed, the installation can comprise a first line exiting the amine treatment section 210 to convey the first hydrogen effluent 10 to the hydroprocessing unit 100.

[0077] The process advantageously comprises the step of using the first hydrogen effluent 10 into the hydrogenation reaction of the hydrocarbon feedstock performed at step (c) and / or the step of directing the first hydrogen effluent 10 into the hydrogen stream 3 provided at step (b).

[0078] In view of recycling hydrogen, the acid gas stream with hydrogen sulphide 11 is then, instead of being subjected to a Claus process which inherently generates water, directed into a hydrogen sulphide cracking unit 300, which is downstream of the separation unit 200, so that a step (f) of cracking the acid gas stream with hydrogen sulphide 11 is carried out. This results in the formation of a stream 13 comprising hydrogen and elemental sulphur. The presence of hydrogen in said stream 13 exiting the hydrogen sulphide cracking unit 300 is the highlight of the present process since it is now possible to use the hydrogen in a downstream application and / or also for supplying hydrogen to the hydrogen stream 3 required for working the hydroprocessing unit 100.

[0079] For example, the step (f) of cracking the acid gas stream with hydrogen sulphide 11 formed during step (e) to generate a stream 13 comprising hydrogen and elemental sulphur, comprises providing oxygen and reacting said oxygen with the acid gas stream with hydrogen sulphide 11 formed at step (e), wherein the stoichiometric ratio between O2 and H2S is amounting to less than 0.5, preferably less than 0.45, even more preferably less than 0.40. For example, said oxygen could originate from an air separation unit (ASU), water electrolysis unit (PEM, AEL, and / or SOEC), or from a CO2 electrolysis unit (SOEC).

[0080] Step (f) is an autothermal non-catalytic cracking reaction In a first embodiment, step (f) of cracking is an autothermal non-catalytic cracking reaction, preferably conducted under reaction conditions comprising a temperature of at least 1100°C, more preferably of at least 1200°C. To do so, the hydrogen sulphide cracking unit 300 comprises one or more cracking coils.

[0081] With preference, the acid gas stream with hydrogen sulphide 11 is subjected to first a Claus reaction, thanks for example to the presence of one or more Claus burners in the hydrogen sulphide cracking unit 300, to produce heat. Then, the heat produced from the Claus reaction provides the temperature of at least 1100°C, preferably at least 1200°C required for generating hydrogen through the non-catalytic cracking reaction of step (f) which is carried out within one or more cracking coils comprised within the hydrogen sulphide cracking unit 300. Such an arrangement is advantageous since it only needs the incorporation of one or more cracking coils into a classical installation already comprising one or more Claus burners. For example, the one or more cracking coils are arranged within at least one of the one or more Claus burners, and / or in an adjacent manner with at least one of the one or more Claus burners. In such embodiment, as the conventional hydroprocessing make use of Claus burners to treat the hydrogen sulphide that is generated during the hydrogenation part of the hydroprocessing, it has been found that using the heat generated by the one or more Claus burners can be efficiently used to work a non-catalytic cracking reaction of the hydrogen sulphide, as depicted in the following equation:

[0082] 3 H2S+ 3 / 2 O2 — > 3 S + 3 H2O + heat (Claus process) H2S + heat — > H2 + S

[0083] => 3 H2S+ 3 / 2 O23 S + 3 H2O + H2

[0084] In the first embodiment, the stoichiometric ratio between O2 and H2S is amounting to less than 0.4, preferably the stoichiometric ratio between O2 and H2S is around 0.33.

[0085] Figure 2 describes a hydrogen sulphide cracking unit 300 that is configured to work an autothermal non-catalyic cracking reaction of the acid gas stream with hydrogen sulphide 11.

[0086] The H2S cracking unit 300 comprises a cracking coil 320 arranged with one Claus burner 310. A heat exchanger 330 is in fluidic communication with the Claus burner 310.

[0087] A part of the acid gas stream with hydrogen sulphide 11 is mixed with an oxygen-containing stream to form an Ch-containing stream with H2S 31. Such Ch-containing stream with H2S 31 is then subjected to a Claus reaction in the Claus burner 310, to produce an effluent 33 comprising water, unreacted H2S and SO2, along with heat. Another part of the acid gas stream with hydrogen sulphide 11 , coming from the separation unit 210 and more particularly from the amine treatment section 210, is pre-heated thanks to the heat generated during the Claus reaction into the heat exchanger 330. The heated H2S- containing stream 35 is thus subjected to a non-catalytic cracking reaction that takes place on the cracking coil 320 arranged with the Claus burner 310, forming an ^-containing stream 37 that is carrying the heat generated during the Claus reaction to the heat exchanger 330, before transferring it to the acid gas stream with hydrogen sulphide 11 and to form a stream 13 comprising hydrogen and elemental sulphur which is going to exit the H2S cracking unit 300.

[0088] Subsequently, the first embodiment is very interesting, since not only hydrogen is generated and can be recycled (either into a downstream application or in the hydroprocessing itself) but also no concerns are raised with the formation of sulphur dioxide that is toxic and needs to be removed from downstream effluents.

[0089] Step (f) is a super adiabatic compustion (SAC) decomposition reaction

[0090] In a second alternative embodiment, the step (f) of cracking is a super adiabatic combustion decomposition reaction, preferably conducted under reaction conditions comprising a temperature ranging between 500°C and 1500°C, preferably comprising a temperature of at least 500°C or of at least 700°C, more preferably of at least 1100°C, even more preferably at least 1200°C. With preference, the super adiabatic combustion decomposition reaction comprises a step of providing a porous ceramic medium and a step of burning a gas-fuel oxidant mixture within said porous ceramic medium, to generate the heat required for reaching a temperature ranging between 500°C and 1500°C, and forming the stream 13 comprising hydrogen and elemental sulphur of step (f).

[0091] In such a second embodiment, hydrogen is formed from hydrogen sulphide using a super adiabatic combustion decomposition reactor, which uses a technology implying filtration combustion in porous media.

[0092] The following equations depict the second embodiment:

[0093] 4 H2S + O22 H2+ 2 H2O + 4S + heat

[0094] H2S + heat — > H2 + S

[0095] => 5 H2S+ O25 S + 2 H2O + 3 H2

[0096] In the second embodiment, the stoichiometric ratio between O2 and H2S is amounting to less than 0.5, preferably less than 0.45. For example, the super adiabatic combustion decomposition reaction can be carried out as described in W02006 / 091658, which is hereby incorporated by reference. That means that it comprises the step of subjecting the acid gas stream with hydrogen sulphide 11 with a catalyst in a catalytic partial oxidation reaction zone, whereby a product gas stream is formed; the step of maintaining the temperature of said acid gas stream with hydrogen sulphide 11 above the dewpoint of sulfur; the step of maintaining the temperature of said catalytic partial oxidation reaction zone above 500°C; and the step of condensing gaseous elemental sulfur from said product gas stream in a cooling zone to provide liquid sulfur and a partially desulfurized product gas stream comprising H2S and SO2. For example, the catalyst in the catalytic partial oxidation reaction zone can comprise at least one metal chosen from the group consisting of Pt, Rh, Ru, Ir, Ni, Pd, Fe, Co, Re, Rb, V, Bi, Sb, Mg, Ca and Ba, preferably Pt and / or Rh.

[0097] Step (f) is performed by electrical conversion of H2S

[0098] In a third alternative embodiment, the step (f) of cracking is performed by directing the acid gas stream with hydrogen sulphide within a plasma made of a plasmagenic gas, wherein said plasmagenic gas is the hydrogen sulphide of the acid gas stream with hydrogen sulphide.

[0099] For example, the electrical conversion of the hydrogen sulphide of the acid gas stream with hydrogen sulphide 11 can be carried out as described in FR 263 96 30, which is hereby incorporated by reference. That means that a plasma torch is provided and that the hydrogen sulphide to be converted is used as a plasmogenic gas. The H2S is decomposed to sulphur which is collected in a storage chamber, while the hydrogen is directed into an absorption tower (where small amounts of unconverted H2S are collected) before being stored. For example, the absorption tower comprises an amine solution or a caustic NaOH solution. In an embodiment, if said absorption tower media is an amine solution, recovered H2S could be recycled back to the cracking reactor.

[0100] Step (f) is conducted by implementing an oxido-reduction reaction between H2S and ferric ions

[0101] In a fourth alternative embodiment, the step (f) of cracking is performed by oxidizing the hydrogen sulphide of the acid gas stream with hydrogen sulphide with ferric ions.

[0102] For example, this redox system can be carried out as described in CN 100450917, which is hereby incorporated by reference. That means that a system comprising an electrolyzing reactor with dual electrode plates and an internal circulation absorption reactor is used, wherein the hydrogen sulphide of the acid gas stream with hydrogen sulphide 11 is oxidized into sulfur at the anode side of the electrolyzing reactor and hydrogen at the cathode side of the electrolyzing reactor, while ferric ions are reduced to ferrous ions in the absorption liquid implied within the internal circulation absorption reactor.

[0103] Step (f) is conducted using an electrified fluidized bed reactor

[0104] In a fifth alternative embodiment, the step (f) of cracking is a splitting of H2S with the production of H2 by passing an electric current through a fluidized bed comprising particles and wherein at least 10 wt.% of the particles of the bed are electrically conductive and have a resistivity ranging from 0.001 Ohm. cm to 500 Ohm. cm at 800°C.

[0105] For example, the electrified non-catalytic cracking reaction of the acid gas stream with hydrogen sulphide 11 can be carried out as described in EP4183741 , which is hereby incorporated by reference. Dear Inventor, the content of this patent application related to EFB and splitting of H2S has been inserted below, so that this present patent application comprises the necessary technical features.

[0106] For example, the electrically conductive particles are selected from one or more metallic alloys, one or more non-metallic resistors, one or more metallic carbides, one or more transition metal nitrides, one or more metallic phosphides, one or more superionic conductors, one or more phosphate electrolytes, one or more mixed oxides being doped with one or more lower-valent cations, one or more mixed sulphides being doped with one or more lower-valent cations, and / or any mixture thereof. For example, the electrically conductive particles are or comprise one or more non-metallic resistors.

[0107] For example, the step (f) of cracking is a splitting of H2S with the production of H2 and comprises the following sub-steps:

[0108] (i) providing at least one fluidized bed reactor comprising at least two electrodes, a bed comprising particles and a F^S-containing feedstock;

[0109] (ii) putting the particles of the bed in a fluidized state to obtain a fluidized bed; and

[0110] (iii) heating the fluidized bed to a temperature ranging from 1000°C to 2700°C to conduct the H2S splitting reaction of the F^S-containing feedstock; and

[0111] (iv) optionally, recovering the products of the reaction; the process is remarkable in that the step (iii) of heating the fluidized bed is performed by passing an electric current through the fluidized bed and in that at least 10 wt.% of the particles based on the total weight of the particles of the bed are electrically conductive particles and have a resistivity ranging from 0.001 Ohm. cm to 500 Ohm. cm at 800°C; and wherein the electrically conductive particles are selected from one or more metallic alloys, one or more non-metallic resistors, one or more metallic carbides, one or more transition metal nitrides, one or more metallic phosphides, one or more superionic conductors, one or more phosphate electrolytes, one or more mixed oxides being doped with one or more lower-valent cations, one or more mixed sulphides being doped with one or more lower-valent cations, and / or any mixture thereof.

[0112] Indeed, the use of electrically conductive particles in one or more fluidized bed reactors which are electrified, allows maintaining a temperature sufficient to carry out an H2S splitting reaction requesting high-temperature conditions such as temperature reaction ranging from 1000°C to 2700°C without the need of any external heating device. The use of at least 10 wt.% of electrically conductive particles within the particles of the bed allows minimizing the loss of heat when a voltage is applied. Thanks to the Joule effect, most, if not all, the electrical energy is transformed into heat that is used for the heating of the reactor medium.

[0113] For example, the electrically conductive particles are or comprise one or more non-metallic resistors.

[0114] For example, the products recovered at sub-step (iv) are H2 and S2.

[0115] For example, the volumetric heat generation rate is greater than 0.1 MW / m3of fluidized bed, more preferably greater than 1 MW / m3, in particular, greater than 3 MW / m3.

[0116] For example, the at least one fluidized bed reactor is devoid of heating means. For example, the at least one fluidized bed reactor comprises a vessel and is devoid of heating means located around or inside the vessel. For example, at least one fluidized bed reactor is devoid of heating means selected from ovens, gas burners, hot plates, or any combination thereof. For example, all the fluidized bed reactors are devoid of heating means selected from ovens, gas burners, hot plates, or any combination thereof.

[0117] For example, the content of electrically conductive particles is ranging from 10 wt.% to 100 wt.% based on the total weight of the particles of the bed; preferably, from 15 wt.% to 95 wt.%, more preferably from 20 wt.% to 90 wt.%, even more preferably from 25 wt.% to 80 wt.% and most preferably from 30 wt.% to 75 wt.%.

[0118] For example, the content of electrically conductive particles based on the total weight of the bed is at least 12 wt.% based on the total weight of the particles of the bed; preferably, at least 15 wt.%, more preferably, at least 20 wt.%; even more preferably at least 25 wt.%, and most preferably at least 30 wt.% or at least 40 wt.% or at least 50 wt.% or at least 60 wt.%.

[0119] For example, the electrically conductive particles have a resistivity ranging from 0.005 to 400 Ohm. cm at 800°C, preferably ranging from 0.01 to 300 Ohm. cm at 800°C; more preferably ranging from 0.05 to 150 Ohm. cm at 800°C and most preferably ranging from 0.1 to 100 Ohm. cm at 800°C

[0120] For example, the electrically conductive particles have a resistivity of at least 0.005 Ohm. cm at 800°C; preferably of at least 0.01 Ohm. cm at 800°C, more preferably of at least 0.05 Ohm. cm at 800°C; even more preferably of at least 0.1 Ohm. cm at 800°C, and most preferably of at least 0.5 Ohm. cm at 800°C.

[0121] For example, the electrically conductive particles have a resistivity of at most 400 Ohm. cm at 800°C; preferably of at most 300 Ohm. cm at 800°C, more preferably of at most 200 Ohm. cm at 800°C; even more preferably of at most 150 Ohm. cm at 800°C, and most preferably of at most 100 Ohm. cm at 800°C.The selection of the content of electrically conductive particles based on the total weight of the particles of the bed and of the electrically conductive particles of a given resistivity influence the temperature reached by the fluidized bed. Thus, in case the targeted temperature is not attained, the person skilled in the art may increase the density of the bed of particles, the content of electrically conductive particles based on the total weight of the particles of the bed and / or select electrically conductive particles with a lower resistivity to increase the temperature reach by the fluidized bed.

[0122] For example, the density of the bed of particles is expressed as the void fraction. Void fraction or bed porosity is the volume of voids between the particles divided by the total volume of the bed. At the incipient fluidisation velocity, the void fraction is typically between 0.4 and 0.5. The void fraction can increase up to 0.98 in fast fluidised beds with lower values at the bottom of about 0.5 and higher than 0.9 at the top of the bed. The void fraction can be controlled by the linear velocity of the fluidising gas and can be decreased by recycling solid particles that are recovered at the top and sent back to the bottom of the fluidized bed, which compensates for the entrainment of solid particles out of the bed.

[0123] The void fraction VF is defined as the volume fraction of voids in a bed of particles and is determined according to the following equation:

[0124] T7„ Vt-Vp

[0125] VF = - - (1) vt wherein Vt is the total volume of the bed and is determined by Vt = AH (2) wherein A is the cross-sectional area of the fluidized bed and H is the height of the fluidized bed; and wherein Vp is the total volume of particles within the fluidized bed.

[0126] For example, the void fraction of the bed is ranging from 0.5 to 0.8; preferably ranging from 0.5 to 0.7, more preferably from 0.5 to 0.6. To increase the density of the bed of particles, the void fraction is to be reduced.

[0127] For example, the particles of the bed have an average particle size ranging from 5 to 300 pm as determined by sieving according to ASTM D4513-11 , preferably ranging from 10 to 200 pm and more preferably ranging from 20 to 200 pm or from 30 to 150 pm.

[0128] Determination by sieving according to ASTM D4513-11 is preferred. In case the particles have an average size of below 20 pm the determination of the average size can also be done by Laser Light Scattering according to ASTM D4464-15.

[0129] For example, the electrically conductive particles of the bed have an average particle size ranging from 5 to 300 pm as determined by sieving according to ASTM D4513-11 , preferably ranging from 10 to 200 pm and more preferably ranging from 30 to 150 pm.

[0130] For example, from 50 wt.% to 100 wt.% of the electrically conductive particles of the bed based on the total weight of the electrically conductive particles of the bed are one or more non- metallic resistors; preferably, from 60 wt.% to 100 wt.%; more preferably from 70 wt.% to 100 wt.%; even more preferably from 80 wt.% to 100 wt.% and most preferably from 90 wt.% to 100 wt.%.

[0131] For example, the electrically conductive particles of the bed comprise one or more metallic alloys. For example, said one or more metallic alloys are selected from Ni-Cr, Fe-Ni-Cr, Fe- Ni-AI or a mixture thereof. With preference, when said metallic alloy comprises at least chromium, the chromium content is at least 15 mol.% of the total molar content of said metallic alloy comprising at least chromium, more preferably at least 20 mol.%, even more preferably at least 25 mol.%, most preferably at least 30 mol.%. Advantageously yet, the iron content in the metallic alloys is at most 2.0% based on the total molar content of the said metallic alloy, preferably at most 1.5 mol.%, more preferably at most 1.0 mol.%, even more preferably at most 0.5 mol.%.

[0132] For example, a non-metallic resistor is silicon carbide (SiC), molybdenum disilicide (MoSi2), nickel silicide (NiSi), sodium silicide (Na2Si), magnesium silicide (Mg2Si), platinum silicide (PtSi), titanium silicide (TiSi2), tungsten silicide (WSi2) or a mixture thereof, preferably silicon carbide.

[0133] For example, said one or more metallic carbides are selected from iron carbide (FeaC) and / or molybdenum carbide (such as a mixture of MoC and M02C).

[0134] For example, said one or more transition metal nitrides are selected from zirconium nitride (ZrN), tungsten nitride (such as a mixture of W2N, WN, and WN2), vanadium nitride (VN), tantalum nitride (TaN), and / or niobium nitride (NbN).

[0135] For example, said one or more metallic phosphides are selected from copper phosphide (CU3P), indium phosphide (InP), gallium phosphide (GaP), sodium phosphide NasP), aluminium phosphide (AIP), zinc phosphide (ZnaP2) and / or calcium phosphide (CasP2).

[0136] For example, the electrically conductive particles of the bed comprise one or more superionic conductors. For example, said one or more superionic conductors are selected from LiAISiCU, Li GeP2Si2, Li3.eSio.6Po.4O4, sodium superionic conductors (NaSICON), such as Na3Zr2PSi20i2, or sodium beta alumina, such as NaAlnOn, Nai.eAln0i7.3, and / or Nai .76Lio.38Aho.62Ol7.

[0137] For example, said one or more phosphate electrolytes are selected from UPO4 or LaPO4.

[0138] For example, said one or more mixed oxides are ionic or mixed conductors being doped with one or more lower-valent cations. Advantageously, said mixed oxides are doped with one or more lower-valent cations, and are selected from oxides having a cubic fluorite structure, perovskite, pyrochlore.

[0139] For example, said one or more mixed sulphides are ionic or mixed conductors being doped with one or more lower-valent cations.

[0140] For example, the electrically conductive particles of the bed are or comprise a non-metallic resistor being silicon carbide.

[0141] For example, the electrically conductive particles of the bed are or comprise a mixture of a non-metallic resistor being silicon carbide and electrically conductive particles different from silicon carbide. The presence of electrically conductive particles different from silicon carbide in the bed is optional. It can be present as a starting material for heating the bed since it was found that the resistivity of silicon carbide at room temperature is too high to start heating the bed. Alternatively to the presence of electrically conductive particles different from silicon carbide, it is possible to provide heat to the reactor for a defined time to start the reaction. For example, the silicon carbide is selected from sintered silicon carbide, nitride-bounded silicon carbide, recrystallised silicon carbide, reaction bonded silicon carbide and any mixture thereof.

[0142] For example, the electrically conductive particles of the bed are or comprise a mixture of a non-metallic resistor being silicon carbide and electrically conductive particles different from silicon carbide and the electrically conductive particles of the bed comprises from 10 wt.% to 99 wt.% of silicon carbide based on the total weight of the electrically conductive particles of the bed; preferably, from 15 wt.% to 95 wt.%, more preferably from 20 wt.% to 90 wt.%, even more preferably from 25 wt.% to 80 wt.% and most preferably from 30 wt.% to 75 wt.%.

[0143] For example, the electrically conductive particles of the bed are or comprise a mixture of a non-metallic resistor being silicon carbide and electrically conductive particles different from silicon carbide and the said electrically conductive particles different from silicon carbide are or comprise one or more selected from molybdenum disilicide, one or more mixed oxides being doped with one or more lower-valent cations and / or one or more mixed sulphides being doped with one or more lower-valent cations, and any mixture thereof.

[0144] For example, the electrically conductive particles of the bed are or comprise silicon carbide and molybdenum disilicide with from 10 wt.% to 90 wt.% of silicon carbide and from 90 wt.% to 10 wt.% of molybdenum disilicide, both based on the total weight of the electrically conductive particles of the bed.

[0145] For example, the electrically conductive particles of the bed are or comprise one or more mixed oxides being ionic conductor, namely being doped with one or more lower-valent cations; with preference, the mixed oxides are selected from:

[0146] - one or more oxides having a cubic fluorite structure being at least partially substituted with one or more lower-valent cations, preferentially selected from Sm, Gd, Y, Sc, Yb, Mg, Ca, La, Dy, Er, Eu; and / or

[0147] - one or more ABCh-perovskites with A and B tri-valent cations, being at least partially substituted in A position with one or more lower-valent cations, preferentially selected from Ca, Sr, or Mg, and comprising at least one of Ni, Ga, Co, Cr, Mn, Sc, Fe and / or a mixture thereof in B position; and / or

[0148] - one or more ABOa-perovskites with A bivalent cation and B tetra-valent cation, being at least partially substituted with one or more lower-valent cations, preferentially selected from magnesium (Mg), scandium (Sc), yttrium (Y), neodymium (Nd) or ytterbium (Yb) in the B position or with a mixture of different B elements in the B position; and / or - one or more A2B2O7-pyrochlores with A trivalent cation and B tetra-valent cation being at least partially substituted in A position with one or more lower-valent cations, preferentially selected from Ca or Mg, and comprising at least one of Sn, Zr and Ti in B position.

[0149] Examples of one or more mixed sulphides are

[0150] - one or more sulphides having a cubic fluorite structure being at least partially substituted with one or more lower-valent cations, preferentially selected from Sm, Gd, Y, Sc, Yb, Mg, Ca, La, Dy, Er, Eu; and / or

[0151] - one or more ABS3 structures with A and B tri-valent cations being at least partially substituted in A position with one or more lower-valent cations, preferably selected from Ca, Sr, or Mg and comprising at least one of Ni, Ga, Co, Cr, Mn, Sc, Fe and / or a mixture thereof in B position; and / or

[0152] - one or more ABS3 structures with A bi-valent cation and B tetra-valent cation, being at least partially substituted with one or more lower-valent cations, preferably selected from Mg, Sc, Y, Nd or Yb in the B position or with a mixture of different B elements in the B position; and / or

[0153] - one or more A2B2S7 structures with A tri-valent cation and B tetra-valent cation, being at least partially substituted in A position with one or more lower-valent cations, preferably selected from Ca or Mg, and comprising at least one of Sn, Zr and Ti in B position.

[0154] With preference, the degree of substitution in the one or more mixed oxides doped with one or more lower-valent cations and having a cubic fluorite structure is between 1 and 15 atom.% based on the total number of atoms present in the one or more oxides having a cubic fluorite structure, preferably between 3 and 12 atom.%, more preferably between 5 and 10 atom.%.

[0155] With preference, the degree of substitution in the one or more mixed oxides doped with one or more lower-valent cations is between 1 and 50 atom.% based on the total number of atoms present in the one or more ABOs-perovskites with A and B tri-valent cations, in the one or more ABOs-perovskites with A bivalent cation and B tetra-valent cation or in the one or more A2B2O7-pyrochlores with A trivalent cation and B tetra-valent cation respectively, preferably between 3 and 20 atom.%, more preferably between 5 and 15 atom.%.

[0156] With preference, the degree of substitution in the one or more mixed sulphides doped with one or more lower-valent cations and having a cubic fluorite structure is between 1 and 15 atom.% based on the total number of atoms present in the one or more oxides having a cubic fluorite structure, preferably between 3 and 12 atom.%, more preferably between 5 and 10 atom.%. With preference, the degree of substitution in the one or more mixed sulphides doped with one or more lower-valent cations is between 1 and 50 atom.% based on the total number of atoms present in the one or more ABS3 structures with A and B tri-valent cations, in the one or more ABS3 structures with A bivalent cation and B tetra-valent cation or in the one or more A2B2S7 structures with A trivalent cation and B tetra-valent cation respectively, preferably between 3 and 20 atom.%, more preferably between 5 and 15 atom.%.

[0157] For example, the electrically conductive particles of the bed are or comprise one or more metallic alloys; with preference, one or more metallic alloys are selected from Ni-Cr, Fe-Ni-Cr, Fe-Ni-AI or a mixture thereof.

[0158] With preference, when said metallic alloy comprises at least chromium, the chromium content is at least 15 mol.% of the total molar content of said metallic alloy comprising at least chromium, more preferably at least 20 mol.%, even more preferably at least 25 mol.%, most preferably at least 30 mol.%. Advantageously yet, the iron content in the metallic alloys is at most 2.0 mol.% based on the total molar content of said metallic alloy, preferably at most 1 .5 mol.%, more preferably at most 1.0 mol.%, even more preferably at most 0.5 mol.%.

[0159] For example, the electrically conductive particles of the bed are or comprise a mixture of a non-metallic resistor being silicon carbide and particles different from silicon carbide wherein the particles different from silicon carbide are or comprise molybdenum silicide; with preference, said molybdenum silicide is molybdenum silicide particles having an average particle size ranging from 5 to 300 pm as determined by sieving according to ASTM D4513- 11 , more preferably ranging from 10 to 200 pm and most preferably ranging from 30 to 150 pm.

[0160] For example, the H2S splitting reaction is conducted at a temperature ranging from 1000°C to 2700 °C, preferably from 1100°C to 2500°C, more preferably from 1200°C to 2500°C and most preferably from 1300°C to 2200°C.

[0161] For example, the H2S splitting reaction is performed at a pressure ranging between 0.1 MPa and 3.0 MPa, preferably between 0.2 MPa and 2.0 MPa.

[0162] For example, said process comprises a step of pre-heating with a gaseous stream the one or more fluidized bed reactors before conducting the H2S splitting reaction in the fluidized bed reactor; with preference the gaseous stream has a temperature comprised between 400°C and 1500°C; preferably, from 400°C to 1000°C; more preferably from 500 °C to 950 °C; even more preferably, from 600 °C to 900°C; most preferably from 700°C to 1000°C or from 800°C to 1200°C. This is of interest when the particles of the bed such as molybdenum carbide and / or the electro-resistive material have too high resistivity at room temperature to start the electroheating of the bed. For example, the gaseous stream is a stream of inert gas.

[0163] For example, the F^S-containing feedstock is selected from an effluent of amine wash from natural gas sweetening process and / or a stream from cold low-pressure separator after hydrotreatment unit on a refinery.

[0164] For example, in sub-step (ii) the particles of the bed are put in a fluidized state by passing upwardly through the said bed a gaseous stream; with preference the gaseous stream is or comprises the F^S-containing feedstock.

[0165] For example, the outlet temperature of the reactor may range from 500 to 2000°C, preferably from 700 to 1400°C, more preferably from 750 to 1300°C, more preferably from 800°C to 1200°C.

[0166] For example, the residence time of the feedstock in the fluidised bed section of the reactor where the temperature is between 1200 and 2500°C, may range from 0.01 to 5.00 seconds, preferably from 0.10 to 1.20 seconds.

[0167] For example, the step of heating the fluidized bed is performed by passing an electric current at a voltage of at most 300 V through the fluidized bed, preferably at most 200 V, more preferably at most 150 V, even more preferably at most 120 V, most preferably at most 100 V, even most preferably at most 90 V.

[0168] For example, said process comprises a step of pre-heating with a gaseous stream said fluidized bed reactor before conducting said H2S splitting reaction in the fluidized bed reactor; with preference, said gaseous stream has a temperature comprised between 400°C and 1500°C.

[0169] For example, the at least one fluidized bed reactor provided in sub-step (i) comprises a heating zone and a reaction zone and the sub-step (iii) of heating the fluidized bed to a temperature ranging from 1000°C to 2700°C to conduct the H2S splitting reaction comprises the following sub-steps: heating the fluidized bed to a temperature ranging from 1000°C to 2700°C by passing an electric current through the heating zone of the at least one fluidized bed, transporting the heated particles from the heating zone to the reaction zone, in the reaction zone, putting the heated particles in a fluidized state by passing upwardly through the said bed of the reaction zone a stream comprising a H2S- containg feedstock to obtain a fluidized bed and to conduct the H2S splitting reaction, optionally, recovering the particles from the reaction zone and recycling them to the heating zone.

[0170] For example, in sub-step (ii) the particles of the bed are put in a fluidized state by passing upwardly through the said bed a gaseous stream wherein the gaseous stream is provided to the heating zone. For example, the gaseous stream used in sub-step (ii) has a temperature ranging from 400°C and 1000°C; preferably, from 500 °C to 950 °C; more preferably, from 600 °C to 900°C; even more preferably from 700°C to 1000°C or from 800°C to 1000°C.

[0171] For example, the at least one fluidized bed reactor provided in sub-step (i) comprises a heating zone and a reaction zone and the sub-step (iii) of heating the fluidized bed to a temperature ranging from 1000°C to 2700°C to conduct the H2S splitting reaction comprises the following sub-steps: pre-heating the fluidized bed to ranging from 400°C and 1000°C by passing upwardly through the particles bed a gaseous stream having a temperature ranging from 400°C and 1000°C; with preference, the gaseous stream is or comprises one or more diluent gas; heating the fluidized bed to a temperature ranging from 1000°C to 2700°C by passing an electric current through the heating zone, transporting the heated particles from the heating zone to the reaction zone, in the reaction zone, putting the heated particles in a fluidized state by passing upwardly through the said bed of the reaction zone a stream comprising a H2S feedstock to obtain a fluidized bed and to conduct the H2S splitting reaction, optionally, recovering the particles from the reaction zone and recycling them to the heating zone.

[0172] For example, the gaseous stream used has a temperature ranging from 400°C and 1000°C; preferably, from 500 °C to 950 °C; more preferably, from 600 °C to 900°C; even more preferably from 700°C to 1000°C or from 800°C to 1000°C.ln an embodiment, the tat least one fluidized bed reactor provided in step a) comprises a pre-heating zone to for pre-heating the bed particles.

[0173] Thus, preferably, the particles are pre-heated and / or heated before sub-step (iii) in a preheating zone and / or in a heating zone, so that:

[0174] - the at least one fluidized bed reactor provided in sub-step (i) comprises a pre-heating zone wherein the step of pre-heating is performed by passing upwardly through the said bed a gaseous stream wherein the gaseous stream is provided to the pre-heating zone and wherein the gaseous stream used has a temperature ranging from 400°C and 1000°C; and / or - the at least one fluidized bed reactor provided in sub-step (i) comprises a heating zone and a reaction zone, wherein the particles of the bed are put in a fluidized state in the heating zone by passing upwardly through the said bed a gaseous stream having a temperature ranging from 400°C and 1000°C, and wherein the fluidized bed is further heated to a temperature ranging from 1000°C to 2700°C by passing an electric current through the heating zone.

[0175] Sub-step (iii) provides that the H2S splitting reaction is performed on an H2S-comprising feedstock which implies that a said feedstock is provided.

[0176] For example, wherein the heating zone and the reaction zone are mixed ( / .e., the same zone); the stream provided in sub-step (ii) comprises an F^S-containing feedstock. For example, wherein the heating zone and the reaction zone are separated zones, the stream provided to the heating zone is devoid of F^S-containing feedstock.

[0177] For example, wherein the process comprises providing at least one fluidized bed reactor being a heating zone and at least one fluidized bed reactor being a reaction zone, the stream provided to the heating zone is devoid of an F^S-containing feedstock and the reaction H2S- containing feedstock is provided to the reaction zone only.

[0178] It is understood that the F^S-containing feedstock is provided to the reaction zone and that when the heating zone is separated from the reaction zone, no F^S-containing feedstock is provided to the heating zone. In an embodiment, steam is provided to the reaction zone, in addition to the F^S-containing feedstock.

[0179] For example, the step (f) of cracking is a splitting of H2S with the production of H2 conducted in an installation to perform an H2S splitting reaction with production of H2, said installation comprises at least one fluidized bed reactor comprising: at least two electrodes; with preference, one electrode is a submerged central electrode or two electrodes are submerged electrodes, a reactor vessel; one or more fluid nozzles for the introduction of an F^S-containing feedstock and an optional further gaseous stream within at least one fluidized bed reactor; and a bed comprising particles; the installation is remarkable in that at least 10 wt.% of the particles of the bed based on the total weight of the particle of the bed are electrically conductive and have a resistivity ranging from 0.001 Ohm. cm to 500 Ohm. cm at a temperature of 800°C; wherein the electrically conductive particles are selected from one or more metallic alloys, one or more non-metallic resistors, one or more metallic carbides, one or more transition metal nitrides, one or more 1 metallic phosphides, one or more superionic conductors, one or more phosphate electrolytes, one or more mixed oxides being doped with one or more lower-valent cations, one or more mixed sulphides being doped with one or more lower-valent cations, and / or any mixture thereof; and in that the at least two electrodes comprise or are made of tantalum. For example, at least one fluidized bed reactor is devoid of heating means. For example, at least one fluidized bed reactor is devoid of heating means located around or inside the reactor vessel. For example, all the fluidized bed reactors are devoid of heating means. When stating that at least one of the fluidized bed reactors is devoid of “heating means”, it refers to “classical’ heating means, such as ovens, gas burners, hot plates and the like. There are no other heating means than the at least two electrodes of the fluidized bed reactor itself. For example, at least one fluidized bed reactor is devoid of heating means selected from ovens, gas burners, hot plates, or any combination thereof. For example, all the fluidized bed reactors are devoid of heating means selected from ovens, gas burners, hot plates, or any combination thereof.

[0180] For example, the at least one fluidized bed reactor comprising at least two electrodes and a bed comprising particles is devoid of packing.

[0181] For example, the gaseous stream is a fluidizing gas and is or comprises one or more diluent gases.

[0182] For example, the at least one reactor vessel has an inner diameter of at least 100 cm, preferably at least 200 cm, more preferably at least 300 cm.

[0183] With preference, the reactor vessel comprises a reactor wall made of materials that are corrosion-resistant materials and advantageously said reactor wall materials comprise nickel (Ni), SiAION ceramics, yttria-stabilized zirconia (YSZ), tetragonal polycrystalline zirconia (TZP) and / or tetragonal zirconia polycrystal (TPZ).

[0184] With preference, one of the electrodes is the reactor vessel or the gas distributor and / or said at least two electrodes are made in stainless steel material or nickel-chromium alloys or nickel- chromium-iron alloys.

[0185] For example, the at least one fluidized bed reactor comprises a heating zone and a reaction zone, one or more fluid nozzles to provide an F^S-containing feedstock to the reaction zone, and optional means to transport the particles of the bed from the reaction zone back to the heating zone.

[0186] For example, the installation comprises at least two fluidized bed reactors connected one to each other wherein at least one reactor of said at least two fluidized bed reactors is the heating zone and at least another reactor of said at least two fluidized bed reactors is the reaction zone. With preference, the installation comprises one or more fluid nozzles arranged to inject an H2S-containing feedstock to the at least one fluidized bed reactor being the reaction zone, means to transport the particles of the bed from the heating zone to the reaction zone when necessary and optional means to transport the particles from the reaction zone back to the heating zone. This configuration is remarkable in that a given particle bed is common to at least two fluidized bed reactors.

[0187] For example, the at least one fluidized bed reactor is a single fluidized bed reactor wherein the heating zone is the bottom part of the fluidized bed reactor while the reaction zone is the top part of the fluidised bed reactor. With preference, the installation comprises one or more fluid nozzles to inject an F^S-containing feedstock between the two zones. The diameter of the heating zone and reaction zone can be different to accomplish optimum conditions for heating in the bottom zone and optimum conditions for methane conversion in the top zone. Particles can move from the heating zone to the reaction zone by entrainment and the other way around from the reaction zone back to the heating zone by gravity. Optionally, particles can be collected from the upper heating zone and transferred by a separate transfer line back to the bottom heating zone.

[0188] For example, the at least one fluidized bed comprises at least two lateral zones being an outer zone and an inner zone wherein the outer zone is surrounding the inner zone, with the outer zone being the heating zone and the inner zone being the reaction zone. In a less preferred configuration, the outer zone is the reaction zone and the inner zone is the heating zone. With preference, the installation comprises one or more fluid nozzles to inject an F^S-containing feedstock in the reaction zone

[0189] Whichever the embodiment selected, to recover the hydrogen present in the stream 13 comprising hydrogen and elemental sulphur exiting the hydrogen sulphide cracking unit 300, a hydrogen separation unit 400 can be set up downstream of said hydrogen sulphide cracking unit 300. In said hydrogen separation unit 400, a step (h) of separating the stream 13 comprising hydrogen and elemental sulphur is carried out. Said separation could be performed by flash-separation, membrane separation, distillation or a combination of these approaches. Thus, elemental sulphur 17 is precipitating and a sour hydrogen stream 19 is formed. In addition to hydrogen, the sour hydrogen stream 19 comprises hydrogen sulphide and may also comprise carbon dioxide. In a step (h), the sour hydrogen stream 19 can be directed into an amine treatment unit, preferably into the amine treatment section 210 of the separation unit 200 of the installation of the present disclosure. Said amine treatment section 210 can be for example referred to as a first amine treatment section 210 and / or is the amine treatment section 210 where the gaseous H2-rich effluent 7 comprising acid gas with hydrogen sulphide has already been subjected to. Thus a step of amine treating said sour hydrogen stream 19 can be performed. For example, the amine treatment section in the step (h) for the sour hydrogen stream 19 can be the same or different from the amine treating of step (e). This results in the generation of a second hydrogen effluent 21 , which is F^S-free, and which can be thus used for downstream application and / or which is directed into the hydrogen stream 3 that is used to work the hydroprocessing unit 100. With preference, the hydrogen effluent is directed into the hydrogen stream 3 which is used to work the hydroprocessing unit 100. For example, the F^S-free H2- rich gas stream 10, which originates from the unreacted hydrogen that was present in the first effluent 5 exiting the hydroprocessing unit 100, can be supplemented by the second hydrogen effluent 21 to provide hydrogen into the hydrogen stream 3.

[0190] Overall, when after the cracking step (f), the stream comprising hydrogen and elemental sulphur is treated to precipitate elemental sulphur and to form a sour hydrogen stream which is then sweetened to remove the hydrogen sulphide left in the stream, it is advantageously possible to recover a second hydrogen effluent 21 and to direct it into the hydrogen stream 3 necessary to work the hydroprocessing. Thus, in this particular implementation, hydrogen is not discarded into the form of water as in traditional hydroprocessing involving conventional sulphur recovery units (SRUs) and is thus recycled. The recovery of the second hydrogen effluent 21 also allows for relieving at least in part or totally the requirement of using a steam methane reforming unit to provide the hydrogen effluent 3.

[0191] The hydroprocessing of the present disclosure can further be improved in terms of hydrogen recycling, since, as water may be involved in the separating step (d), the separation unit 200 can further comprise a cold separator or dryer 220 arranged upstream of the amine treatment section 210. In such a cold separator or dryer 220, the gaseous F^-rich effluent 7, which may then further comprise water in the gaseous phase, can be subjected to an additional separation step by implementing molecular sieve adsorption. This results in the recovery of a water stream 23.

[0192] Examples

[0193] The embodiments of the present disclosure will be better understood by looking at the example below. Figure 2 describes a hydrogen sulphide cracking unit 300 that is configured to work an autothermal non-catalyic cracking reaction of the acid gas stream with hydrogen sulphide 11. Table 1 indicates the content of the different streams of Figure 2.

[0194] Table 1 : Composition of the streams involved in an authermal non-catalyic cracking reaction (simulation)

[0195] A conversion of H2S cracking of about 40% ( / .e., amount of H2S cracked / total H2S inlet cracking = (400-234)7400 = 41.5%) is obtained.

Claims

CLAIMS1 . A hydroprocessing is characterized in that it comprises the following steps: a) providing a hydrocarbon feedstock (1), said hydrocarbon feedstock (1) comprising one or more organic sulphur compounds; b) providing a hydrogen stream (3); c) performing a hydrogenation reaction of the hydrocarbon feedstock (1) with the hydrogen stream (3) under reaction conditions, to form a first effluent (5) comprising one or more hydrogenated products, unreacted hydrogen, and acid gas with hydrogen sulphide; d) separating said one or more hydrogenated products from said first effluent (5), to recover a gaseous H2-rich effluent (7) and a liquid effluent (9), said gaseous H2- rich effluent (7) comprising hydrogen sulphide; e) performing a step of amine treating onto said gaseous H2-rich effluent (7) to form a first hydrogen effluent (10) and an acid gas stream with hydrogen sulphide (11); and f) cracking said acid gas stream with hydrogen sulphide (11) to generate a stream (13) comprising hydrogen and elemental sulphur, wherein the process comprises the step of generating a second hydrogen effluent (21) from the stream (13) comprising hydrogen and elemental sulphur, and the step of using the second hydrogen effluent (21) into the hydrogenation reaction of the hydrocarbon feedstock performed at step (c).

2. The process according to claim 1 is characterized in that the process comprises the step of using the first hydrogen effluent (10) into the hydrogenation reaction of the hydrocarbon feedstock performed at step (c).

3. The process according to claim 1 or 2, characterized in that the process comprises the step (g) of stripping the liquid effluent (9) recovered at step (d) to recover one or more hydrodesulfurized products (15).

4. The process according to any one of claims 1 to 3 is characterized in that it comprises the following sub-steps:I. separating the stream (13) comprising hydrogen and elemental sulphur generated at step (f), to form elemental sulphur (17) and a sour hydrogen stream (19); and ii. performing a step of amine treating onto said sour hydrogen stream (19) to generate a second hydrogen effluent (21).

5. The process according to any one of claims 1 to 4 is characterized in that step (f) of cracking is an autothermal non-catalytic cracking reaction.

6. The process according to claim 5, chararacterized in that one part of the acid gas stream with hydrogen sulphide (11) is subjected to a Claus reaction to produce heat, and the heat produced from the Claus reaction provides a temperature sufficient to perform a non-catalytic cracking reaction of the remaining of the acid gas stream with hydrogen sulphide (11).

7. The process according to any one of claims 1 to 4 is characterized in that step (f) of cracking is a super adiabatic combustion decomposition reaction.

8. The process according to any one of claims 1 to 4 is characterized in that step (f) of cracking is performed by directing the acid gas stream with hydrogen sulphide (11) within a plasma made of a plasmagenic gas, wherein said plasmagenic gas is the hydrogen sulphide of the acid gas stream with hydrogen sulphide (11).

9. The process according to any one of claims 1 to 4 is characterized in that step (f) of cracking is performed by oxidizing the hydrogen sulphide of the acid gas stream with hydrogen sulphide (11) with ferric ions.

10. The process according to any one of claims 1 to 4 is characterized in that step (f) of cracking is a splitting of H2S with the production of H2 by passing an electric current through a fluidized bed comprising particles and wherein at least 10 wt.% of the particles of the bed are electrically conductive and have a resistivity ranging from 0.001 Ohm. cm to 500 Ohm.com at 800°C.11 . The process according to any one of claims 1 to 10 is characterized in that the gaseous H2-rich effluent (7) recovered from step (d) further comprises water in the gaseous phase and in that the process comprises the further step of subjecting said gaseous H2-rich effluent (7) to an additional separation step to recover a water stream (23).

12. The process according to any one of claims 1 to 11 is characterized in that said hydrocarbon feedstock (1) comprising one or more organic sulphur compounds is a feedstock comprising one or more liquid C6+ hydrocarbons, naphtha, gasoline, petrol, jet fuel, kerosene, diesel fuel, fuel oils, or a mixture thereof.

13. Installation for removing one or more organic sulphur compounds from a hydrocarbon feedstock (1), said installation comprising a hydroprocessing unit (100) and a separation unit (200) downstream of said hydroprocessing unit (100), the separation unit (200) comprising an amine treatment section (210), the installation is characterized in that it comprises a hydrogen sulphide cracking unit (300) downstream of said separation unit (200) and a line directing an acid gas stream with hydrogen sulphide (11) between the amine treatment section (210) and the hydrogen sulphide cracking unit (300); wherein the installation comprises a hydrogen separation unit (400) downstream of said hydrogen sulphide cracking unit (300) and a line directing a sour hydrogen stream (19) from the hydrogen separation unit (400) to the hydroprocessing unit (100).

14. The installation according to claim 13 is characterized in that it comprises a first line exiting the amine treatment section (210) to convey a first hydrogen effluent (10) to the hydroprocessing unit (100).

15. The installation according to claim 13 or 14 wherein the amine treatment section (210) is a first amine treatment section (210), and the installation is characterized in that the line directing the sour hydrogen stream (19) from the hydrogen separation unit (400) to the hydroprocessing unit (100) goes through one or more additional amine treatment sections and wherein the installation comprises a second line exiting the one or more additional amine treatment sections to convey a second hydrogen effluent (21) to the hydroprocessing unit (100).

16. The installation according to claim 15 is characterized in that the one or more additional amine treatment sections are or comprise the first amine treatment section (210).

17. The installation according to any one of claims 13 to 16 is characterized in that the hydrogen sulphide cracking unit (300) comprises at least one cracking coil.

18. The installation according to claim 17 is characterized in that the hydrogen sulphide cracking unit (300) comprises one or more Claus burners and the one or more cracking coils are arranged within at least one of the one or more Claus burners .

19. The installation according to claim 17 or 18 is characterized in that the hydrogen sulphide cracking unit (300) comprises one or more Claus burners and the one or more cracking coils are arranged in an adjacent manner with at least one of the one or more Claus burners.

20. The installation according to any one of claims 13 to 16 is characterized in that the hydrogen sulphide cracking unit (300) comprises a partial oxidation reaction zone comprising one or more catalysts.

21. The installation according to any one of claims 13 to 16 is characterized in that the hydrogen sulphide cracking unit (300) comprises at least one plasma torch.

22. The installation according to any one of claims 13 to 16 is characterized in that the hydrogen sulphide cracking unit (300) comprises a system with an electrolysis reactor having an anode and a cathode and with an absorption reactor arranged between said anode and said cathode.

23. The installation according to any one of claims 13 to 16 is characterized in that the hydrogen sulphide cracking unit (300) comprises at least one fluidized bed reactor with a bed comprising particles and wherein at least 10 wt.% of the particles of the bed are electrically conductive and have a resistivity ranging from 0.001 Ohm.com to 500 Ohm.com at 800°C.

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