WO2025073690A1

WO2025073690A1 - Hydrocarbon pyrolysis process

Info

Publication number: WO2025073690A1
Application number: PCT/EP2024/077596
Authority: WO
Inventors: Ingo Muenster; Dieter Flick; Frederik SCHEIFF; Daniela Rieck; Germain Kons; Sebastian Schulze
Original assignee: BASF SE
Current assignee: BASF SE
Priority date: 2023-10-06
Filing date: 2024-10-01
Publication date: 2025-04-10
Anticipated expiration: 2026-04-06

Abstract

A method for producing a hydrogen-containing gas stream containing hydrogen sulfide with concomitant production of low-sulfur carbonaceous material comprises the steps of (i) providing a hydrocarbon feed gas stream containing sulfur-containing compounds; (ii) supplying carbonaceous particles to a reactor and subjecting the feed gas stream to pyrolysis in the reactor over a moving bed of the carbonaceous particles; (iii) recovering a stream of hydrogen-containing gas stream containing hydrogen sulfide; and (iv) recovering low-sulfur carbonaceous particles. Sulfur ends up in the form of hydrogen sulfide, which is either harmless for selected downstream applications, or is purposively used in selected downstream applications or could be easily removed from the hydrogen stream. A desulfurization step before thermocatalytic conversion of sulfurous hydrocarbon feedstocks is not necessary.

Description

Hydrocarbon Pyrolysis Process

The invention relates to a hydrocarbon pyrolysis process.

Hydrogen may be produced from hydrocarbon fuels via oxidative and non-oxidative conversion processes. The oxidative processes include steam reforming (SR) and partial oxidation (POX). For methane, steam reforming proceeds according to the following main reaction:

CH₄ + H₂O CO + 3H₂

Similar reactions take place for other hydrocarbons. Normally, the following water-gas shift reaction also occurs in the presence of catalysts for steam reforming:

CO + H₂O CO₂ + H₂

The reactions are endothermic, typically requiring high temperatures above 800 °C in the reactor outlet.

Partial oxidation is a non-catalytic process where a sub-stoichiometric amount of oxygen is allowed to react with a carbonaceous material like natural gas, liquid feeds such as fuel oils, gas oils, and/or coal at high temperatures to yield synthesis gas containing hydrogen and carbon monoxide. For methane, partial oxidation proceeds according to the following main reaction:

2CH₄ + O₂ 2CO + 4H₂

For the partial oxidation reaction, the carbonaceous feed material is mixed with air, oxygen-enriched air, and/or molecular oxygen and introduced into a partial oxidation reactor at an elevated temperature of at least 1200 °C and reacted thermally without a catalyst.

The non-oxidative route includes thermal decomposition of hydrocarbons into hydrogen and carbon, also referred to as decomposition or pyrolysis. For methane, pyrolysis proceeds according to the following main reaction:

CH₄ — > C + 2H₂

The process is moderately endothermic (about 37 kJ/mole of H₂). It is evident from the reaction equation above that in methane pyrolysis, the release of carbon dioxide is prevented. Therefore, in the event that the required energy originates from renewable resources, methane pyrolysis is a CO₂-free, i.e., clean technology to obtain emission- free hydrogen. Methane pyrolysis is a one-step process which produces hydrogen in high volume. Carbon is produced as a valuable byproduct of the process. There is an increasing demand for low-sulfur carbonaceous materials. Such carbonaceous materials find use, e.g., for aluminum and steel production, tire manufacturing, electrode manufacturing, polymer blending, additive for construction materials, carbon devices like heat exchangers, soil conditioning, or storage.

The conventional catalytic reforming and partial oxidation processes require desulfurization of a feedstock down to ppm levels. Sulfur compounds are strong poisons to the catalysts used in steam reforming processes.

Similarly, catalyzed methane pyrolysis processes using solid-phase catalysts such as nickel (Ni), iron (Fe), molybdenum (Mo) or cobalt (Co) are sensitive against sulfur impurities in the feed. Therefore, the feed gas needs desulfurization upfront to the pyrolysis.

Desulfurization of hydrocarbons is commonly achieved by catalytic hydrodesulfurization (HDS), in which the organic sulfur species are converted to H2S. The conversion to hydrogen sulfide is typically achieved by reaction with hydrogen over non-noble metal sulfided catalysts, especially those containing Co/Mo or Ni/Mo. The H2S is easily removed from the desulfurized hydrocarbon by adsorption or absorption in a gas treatment unit.

The necessity of catalytic hydrodesulfurization adds to the cost of hydrogen formation from hydrocarbons.

US 7,157,167 B1 describes a process and for production of hydrogen and carbon by thermocatalytic decomposition of hydrocarbon fuels over carbon-based catalysts in the absence of air and/or water. When sulfur is present in the hydrocarbon feedstock, it is described to end up in the form of elemental sulfur which can be condensed.

It has now been found that in the thermocatalytic conversion of hydrocarbons over a moving bed of carbonaceous particles, the presence of sulfur in the hydrocarbon feedstock is not only harmless but the moving carbon hydrocarbon pyrolysis actually completely replaces a hydrodesulfurization unit. This implies that there is no need for a very costly desulfurization step before thermocatalytic conversion of sulfurous hydrocarbon feedstocks. Sulfur ends up in the form of hydrogen sulfide, which is either harmless for selected downstream applications, or is purposively used in selected downstream applications or could be easily removed from the hydrogen stream.

Moreover, it has been found that the carbonaceous material concomitantly produced by such a thermocatalytic conversion, which is deposited on the carbonaceous particles, has a high purity and in particular a low sulfur concentration.

Hence, the invention relates to a method, comprising the steps of:

(i) providing a hydrocarbon feed gas stream containing sulfur-containing compounds;

(ii) subjecting the feed gas stream to pyrolysis in a reactor over a moving bed of solid material particles; and (iii) recovering a stream of hydrogen-containing gas stream containing hydrogen sulfide.

In particular, the invention relates to a method for producing a hydrogen-containing gas stream containing hydrogen sulfide with concomitant production of low-sulfur carbonaceous material, comprising the steps of:

(ii) supplying carbonaceous particles to a reactor and subjecting the feed gas stream to pyrolysis in a reactor over a moving bed of the carbonaceous particles;

(iii) recovering a stream of hydrogen-containing gas stream containing hydrogen sulfide; and

(iv) recovering low-sulfur carbonaceous particles.

In one embodiment, the supplied carbonaceous particles have an initial sulfur concentration c(S)o and the recovered low-sulfur carbonaceous particles have a sulfur concentration C(S)R, which is lower than or equal to c(S)o. In one embodiment, the C(S)R is lower than c(S)o by at least 1 percentage point, more preferably by at least 2 percentage points. Thus, the sulfur concentration of the carbonaceous particles does not increase or even decreases in the method of the invention.

The supplied carbonaceous particles typically have an initial sulfur concentration c(S)o of 0 to 10 wt.-%, such as 0 to 7 wt.-%, preferably 0 to 5 wt.-%, more preferably 0.1 to 3.5 wt.-%, most preferably 0.1 to 1.5 wt.-%.

The recovered low-sulfur carbonaceous particles typically have a sulfur concentration C(S)R of 0 to 5.0 wt.-%, 0 to 2.0 wt.-%, 0 to 1 .2 wt.-%, preferably 0 to 0.8 wt.-%.

Without wishing to be bound by theory, it is believed that inherent impurities which may be comprised in the carbonaceous particles supplied to the reactor may be removed from the carbonaceous particles as hydrogen sulfide during the method of the invention. The hydrogen sulfide is carried out by the hydrogen-containing gas stream.

In certain embodiments, the method additionally comprises

(v) directing the stream of hydrogen-containing gas to a gas separation unit to obtain a hydrogen-depleted gas and a hydrogen stream containing hydrogen sulfide; and

(vi) recycling the hydrogen-depleted gas to the reactor.

In a moving bed reactor, the hydrocarbon feed gas and carbonaceous particles flow in countercurrent throughout the reactor. Typically, the process comprises feeding carbonaceous particles to the top of the reactor, allowing the particles to flow downwardly under gravity flow as a compact column, and withdrawing the particles from the reactor at the bottom of the reactor. For this purpose, the reactor is preferably a vertical elongated reactor, which means that the movement of the moving bed is gravity driven. Flow through the moving bed advantageously takes place homogeneously and uniformly (see for example WO 2013/004398, WO 2019/145279 and WO 2020/200522).

The hydrocarbon feed gas stream is preferably introduced via the bottom of the reactor, preferably having a temperature of 10 to 200 °C. The carbonaceous particles are preferably introduced via the top of the reactor, preferably having a temperature of 10 to 200 °C.

The carbonaceous particles are maintained at the reaction temperature in the reaction zone. This heat is released and transferred to the feed gas. Consequently, the hydrocarbon pyrolysis takes place. The carbon originating from the reaction is deposited on the carbonaceous particles and continuously removed at the reactor bottom. The gaseous product is cooled down at the reactor top upon contact with the cold fresh carbon. As a consequence, the carbon is preheated by the outlet gas before entering the reaction zone and being electrically heated.

The hydrogen-containing gas is preferably recovered via the top of the reactor, preferably having a temperature of 10 to 200 °C. The granular pyrolytic carbon is preferably recovered via the bottom of the reactor, preferably having a temperature of 10 to 200 °C. Discharging the particles may be accomplished by conventional discharge means, e.g., by a rotary valve.

The pyrolysis is preferably carried out at temperatures ranging from 1000 to 1600 °C, more preferably 1150 to 1550 °C, such as 1200 to 1500 °C, most preferably 1400 to 1500 °C, and at pressures ranging from 1 to 100 bar (abs), more preferably 5 to 50 bar (abs). Pyrolysis reactions underlie complex kinetic equilibria which are temperature dependent. Likewise, sulfur-containing compounds present during the pyrolysis reactions may undergo different reaction pathways and can end up as, e.g., elemental sulfur and/or hydrogen sulfide. Based on the evidence at hand, it is believed that the above temperature ranges allow for increased conversion of sulfur-containing compounds to hydrogen sulfide and its discharge via the hydrogen-containing gas stream.

The flow velocity of the carbonaceous particles is advantageously in the range of 0.005 to 0.5 cm/s. The flow velocity of the hydrocarbon feed gas flow is advantageously in the range of 0.025 to 2 m/s.

The gas residence time in the reactor is advantageously between 0.5 and 50 s, preferably between 1 and 10 s. The residence time of the carbonaceous particles is preferably between 0.5 and 15 hours, preferably between 1 and 10 hours and more preferably between 2 and 8 hours.

The moving bed reactor provides a very good heat transfer between the gas and the carbonaceous particles . In addition, there is no back-mixing, and the residence time can be controlled for both phases. The counterflow operation allows the energy integration of the reactor, and the excellent heat transfer between the gas and the carbonaceous particles guarantees a thermally efficient process.

The solid material particles act as substrate for the deposition of carbon generated by the decomposition of the hydrocarbon compounds. The solid material particles may be selected from carbonaceous materials, metals, ceramics and mixtures thereof, in particular carbonaceous particles.

Metallic particles may be metallic throughout or have a metallic coating over a non-metallic core. Metallic particles include conductive pre-reduced oxidic particles.

Examples of carbonaceous particles include petroleum-based coke, coal-based coke, natural graphite, and artificial graphite, preferably petroleum-based coke. Generally, the carbon deposited on the supplied carbonaceous particles inherits the morphological properties of the supplied carbonaceous particles.

Carbonaceous particles may be in the form of fines, or be agglomerated such as pelletised or granulated, if required. The carbonaceous particles can be porous or non- porous.

Preferably, carbonaceous particles are macro-structured carbonaceous materials. The porosity of the carbonaceous material may be in the range of 0 to 70 vol.-% and the carbonaceous material contains a carbon content of 98 wt.-% to 100 wt.-%, preferably

99 wt.-% to 100 wt.-%, even more preferably 99.5 wt.-% to 100 wt.-% and a content of alkaline-earth metals, transition metals and metalloids of 0 to 2 wt.-%, preferably 0 to 1 wt.-%, even more preferably 0 to 0.5 wt.-%, in relation to the total mass of solid carbonaceous material (see WO 2023/057242).

The BET surface area of the carbonaceous particles is preferably between 0.1 and

100 m²/g, preferably 0.1 and 50 m²/g, in particular 0.1 to 30 m²/g.

Preferably, the density of the carbonaceous particles is in the range of 1.5 to 2.5 g/cc (real density in xylene, ISO 8004). Preferably, the bulk density of the carbonaceous particles is in the range of 0.5 to 1.5 g/cc.

In case the solid material particles are carbonaceous particles, the carbon produced in the pyrolysis deposits on the existing carbonaceous particles. The obtained granular pyrolytic carbon can be sold as a commercial product for selected applications, depending on the carbon morphology and physical/chemical properties. For example, the solid carbon from methane pyrolysis may be used for aluminum and steel production, tire manufacturing, electrode manufacturing, polymer blending, additive for construction materials, carbon devices like heat exchangers, soil conditioning, or storage. Particular applications of the solid carbon from methane pyrolysis include:

1) Steel production: as an additive which helps in improving the carbon content and reducing impurities, resulting in high-quality steel products.

2) Aluminum smelting: as a carbon anode, which provides electrical conductivity and promotes the reduction of aluminum oxide to aluminum metal.

3) Titanium dioxide production: as a carbon source; titanium dioxide is a white pigment used in various industries such as paints, coatings, and plastics.

4) Graphite electrode production: these electrodes are essential in electric arc furnaces used for steel and other metal production.

5) Carbon products manufacturing: as a crucial raw material in the production of various carbon products such as carbon blocks and carbon brushes.

6) Foundry industry: as an additive which helps in enhancing the carbon content in cast iron and steel, improving meltability and reducing casting defects.

7) Brake pads and friction materials: as a friction modifier, providing excellent thermal conductivity, high strength, and low wear rates.

8) Carbon anodes for lithium-ion batteries: as a precursor material for the production of carbon anodes in lithium-ion batteries; such anodes are crucial for storing and releasing electrical energy in portable electronic devices and electric vehicles.

9) Chemical industry: as a carbon source, it is utilized in the production of chemicals such as calcium carbide, carbon disulfide, and graphite-based lubricants.

A fraction of the withdrawn carbon may be ground in a grinder and sieved, formulated and recycled to the reactor.

Typically, the density of the granular pyrolytic carbon produced via the present method is in the range of 1.5 to 2.5 g/cc, preferably 1.8 to 2.3 g/cc (real density in xylene, ISO 8004). Typically, the bulk density of the granular pyrolytic carbon is in the range of 0.5 to 1.5 g/cc, more preferably 0.7 to 1.3 g/cc.

Typically, the ash content of the granular pyrolytic carbon composition is in the range of 0.001 to 1 wt.-% of the composition, preferably 0.01 to 0.2 wt.-%.

Typically, the carbon content of the granular pyrolytic carbon composition is in the range of 98 to 100 wt.-%, more preferably 99.5 to 100 wt.-%, even more 99.75 to 100 wt.-%, even more 99.9 to 100 wt.-%.

Typically, the granular pyrolytic carbon comprises impurities, in particular: S in the range of 0 to 0.5 wt.-%, more preferably 0 to 0.1 wt.-%, Fe in the range of 0 to 1000 ppm, preferably 0 to 500 ppm, Ni in the range of 0 to 250 ppm, preferably 0 to 100 ppm, V in the range of 0 to 250 ppm, more preferably 0 to 100 ppm. Na in the range of 0 to 200 ppm, preferably 0 to 100 ppm. Oxygen is in the range of 0 to 100 ppm, preferably below the detection limit.

Typically, 90 wt.-% of the carbon of the granular pyrolytic carbon composition is non-functionalized, preferably 95 wt.-%, even more preferably 98 wt.-%, especially 99 wt.-%, wherein carbon functionalization refers to a reaction in which a carbon-carbon bond is broken and replaced by a carbon-X bond, wherein X may be selected from hydrogen, oxygen, sulfur, phosphorus, nitrogen, halogens, and/or metals.

Typically, the particle size of the granular pyrolytic carbon is in the range of 0.3 mm (d10) to 8 mm (d90), preferably 0.5 mm (d10) to 5 mm (d90), more preferably 1 mm (d10) to 4 mm (d90).

Typically, the porosity of the granular pyrolytic carbon is between 0% to 15%, preferably 0.1 % to 10%, most preferably 0.2% to 8%. Porosity may be determined via Hg porosimetry in accordance with DIN66133.

Typically, the specific surface area of the granular pyrolytic carbon is in the range of 0.001 to 10 m²/g, preferably 0.001 to 5 m²/g, even more preferably 0.05 to 2 m²/g. The specific surface area may be determined via Hg porosimetry in accordance with DIN66133.

As discussed above, the pyrolysis is endothermic. In a preferred embodiment, thermal energy is provided to the pyrolysis reaction by electrical heating. If the solid material particles are electrically conductive, they may be heated by resistive heating (Joule heating), as described for example in US 2,982,622, WO 2019/145279 and WO 2020/200522. To this end, electrically conductive solid material particles may be heated by an electrical potential or voltage applied across at least a portion of the particle bed. Electrical power may be supplied through a plurality of electrodes that are in an electrically conductive relationship with the particle bed, e.g., immersed in the particle bed.

The resistive thermal energy generated by passing a current through the particles defining the electrically conductive bed may be supplemented by other heat sources. In embodiments, additional heat can be provided to the pyrolysis by preheating the hydrocarbon that is designed to be flowed through the particle bed. In still other embodiments, additional heat can be provided by inductive heating. Optionally, additional resistive heating elements may be used. The additional heating elements can take the shape of a wire, ribbon, sheet or strip and can be straight, meandering or coiled. Such a heating element converts electricity into heat through the process of Joule heating. Preferably, the reactor comprises:

- a reactor surrounding a reactor interior

- the reactor is configured to provide a gravity-driven moving bed in a reaction zone of the reactor interior, which gravity-driven moving bed comprises solid material particles, wherein the reactor is also configured to guide the hydrocarbon feed gas stream into the reaction zone, wherein, in order to heat the hydrocarbon feed gas stream, the reactor is configured to heat the solid material particles in the reaction zone by generating an electric current in the moving bed between a pair of first and second electrodes such that, by transferring heat from the solid material particles to the hydrocarbon feed gas stream the hydrocarbon feed gas stream in the reaction zone can be heated to a reaction temperature to produce hydrogen and granular pyrolytic carbon,

- and wherein the reactor interior also comprises a first heat integration zone in which heat from hydrogen produced in the reaction zone can be transferred to solid material particles of the reactor gravity driven moving bed which are to be guided into the reaction zone, and wherein the reactor interior also comprises a second heat integration zone in which heat from solid material particles of the reactor gravity driven moving bed leaving the reaction zone can be transferred to the hydrocarbon feed gas stream in order to preheat the hydrocarbon feed gas stream, wherein said reaction zone is arranged between said pair of first and second electrodes and said first heat integration zone is arranged above said first electrode and said second heat integration zone is arranged below said second electrode.

Preferably, the electrodes comprise a grid or are formed by a grid.

Hence, in preferred embodiment the method comprises:

- guiding solid material particles into the first heat integration zone and from there into the reaction zone,

- heating the solid material particles in the reaction zone,

- guiding the solid material particles from the reaction zone into the second heat integration zone and withdrawing the solid material particles from the second heat integration zone,

- introducing the hydrocarbon feed gas stream into the second heat integration zone and from there into the reaction zone, wherein the hydrocarbon feed gas stream in the second heat integration zone is heated against solid material particles leaving the reaction zone, wherein the solid material particles are cooled and

- contacting the pre-heated hydrocarbon feed gas stream with the heated solid material particles in the reaction zone, wherein heat from the heated solid material particles is transferred to the hydrocarbon feed gas stream in order to heat the hydrocarbon feed gas stream in the reaction zone, wherein the hydrocarbon feed gas stream is decomposed to hydrogen and granular pyrolytic carbon in the reaction zone, - guiding a hydrogen-containing gas from the reaction zone into the first heat integration zone, wherein the solid material particles in the first heat integration zone are preheated against the hydrogen-containing gas leaving the reaction zone, wherein the hydrogen-containing gas is cooled, and wherein

- hydrogen-containing gas is withdrawn from the first heat integration zone

- carbon produced is deposited on the solid material particles and withdrawn with the solid material particles.

The hydrocarbon feed gas stream contains at least one hydrocarbon which may be selected from methane, saturated hydrocarbons, in particular saturated C2 to C3 hydrocarbons, or C5-9 hydrocarbons. The hydrocarbon feedstock preferably includes methane as a main hydrocarbon constituent, e.g., at least 75 vol.-% of methane, preferably at least 85 vol.-% of methane. Most often, natural gas comprising methane is used as feed gas.

The hydrocarbon feed gas stream contains sulfur-containing compounds. The sulfur- containing compounds may comprise mercaptans, organic sulfides, carbonyl sulfide and hydrogen sulfide. The concentration of sulfur-containing compounds in the hydrocarbon feed gas stream may range from 1 ppm to 30 vol.-%.

A hydrogen-containing gas is withdrawn from the reactor. The hydrogen-containing gas may pass a gas-solid separation unit. A filter, a cyclone, or any other system capable of separating fine particles from a gas stream, may be employed as the gas-solid separation unit. The hydrogen-containing gas is optionally directed through a heat exchanger. The hydrogen-containing gas may contain residual unreacted hydrocarbon.

The concentration of hydrogen in the hydrogen-containing gas depends on the hydrocarbon feedstock, the temperature, the pressure and the residence time and varies in the range of 5 to 98 vol.-%, preferably 20 to 95 vol.-%, most preferably 50 to 95 vol.-%. The balance comprises residual unreacted hydrocarbons and hydrogen sulfide. The hydrogen-containing gas can be used as such or further refined. The concentration of hydrogen sulfide in the hydrogen-containing gas may range from 1 ppm to 30 vol.-% by weight, preferably 1 ppm to 5 vol.-%, most preferably 1 ppm to 1 vol.-%.

The hydrogen-containing gas comprises hydrogen sulfide. In one embodiment, at least 90 wt.-%, preferably at least 95 wt.-%, most preferably at least 99 wt.-% or at least 99.9 wt.-% of sulfur comprised in the sulfur-containing compounds is discharged as hydrogen sulfide in the hydrogen-containing gas stream. Further optionally present sulfur species include carbonyl sulfide and carbon disulfide.

In an embodiment, the hydrogen-containing gas, preferably after passing a gas-solid separation unit and heat exchanger, is directed to a gas separation unit. A gas separation membrane, a pressure swing adsorption (PSA) system, a cryogenic absorption (or adsorption) unit, or any other system capable of separating hydrogen from hydrocarbons, may be employed as the gas separation unit. A stream of pure hydrogen is separated from the gaseous stream. In the gas separation unit, a stream of pure hydrogen containing hydrogen sulfide is separated from the gaseous stream. A hydrogen-depleted gas is recycled to the reactor.

The concentration of hydrogen in the stream of pure hydrogen varies in the range of 95 to 99.99 vol.-%. The concentration of hydrogen sulfide in the stream of pure hydrogen may range from 0.1 to 1 ppm by weight.

While there is a number of applications where the presence of hydrogen sulfide in the hydrogen is either desired or harmless, low sulfur hydrogen may be required in certain instances. Hence, in an embodiment, hydrogen sulfide is removed from the hydrogencontaining gas or the hydrogen stream containing hydrogen sulfide.

Methods that have been conventionally used for the removal of hydrogen sulfide from hydrodesulfurized hydrocarbon streams may be adopted for hydrogen sulfide removal from the hydrogen-containing gas or the hydrogen stream containing hydrogen sulfide.

The process may comprise contacting the hydrogen-containing gas or the hydrogen stream containing hydrogen sulfide with an adsorbent for hydrogen sulfide, and adsorbing hydrogen sulfide from said gas.

Suitable solid adsorbents comprise one or more metal oxide, hydrated oxide, or hydroxide or combinations thereof, the metals being selected from the group of zinc, iron, nickel, cobalt, tin, and molybdenum. A preferred solid adsorbent is ZnO, due to its good performance. The H2S adsorbent may be supported on an inorganic support material for the purpose of, for example, increasing the surface area, the pore volume and the pore diameter. Preferably, an inorganic refractory support material selected from the group consisting of alumina, silica, titania, zirconia, carbon, silicon carbide, and Kieselguhr is used.

In yet another embodiment, hydrogen sulfide removal is accomplished by treating the hydrogen-containing gas or the hydrogen stream containing hydrogen sulfide with a chemical or physical scrubbing solvent or a combination thereof. A process based on chilled methanol as a scrubbing solvent is preferred.

Without prior hydrogen sulfide removal, the hydrogen-containing gas or hydrogen stream containing hydrogen sulfide may be directed to a sulfur-insensitive hydrogen-consuming reaction, hydrogen sulfide manufacturing, or a catalyst sulfiding operation.

A “sulfur-insensitive reaction” is meant to denote a reaction that is either uncatalyzed or catalyzed by a catalyst the activity and selectivity of which is not substantially deteriorated by the presence of hydrogen sulfide in the hydrogen. Sulfur-insensitive hydrogen-consuming reaction typically include reactions where hydrogen sulfide is one of the reaction products or is the sole reaction product.

Sulfur-insensitive hydrogen-consuming reaction include a refinery hydrotreatment, preferably a hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and/or hydrodearomatisation (HDA).

Hydrotreating refers to a variety of catalytic hydrogenation processes. Among the known hydrotreating processes are hydrodesulfurization, hydrodenitrogenation and hydrodearomatisation wherein feedstocks such as olefinic naphtha streams are contacted with catalysts under conditions of elevated temperature and pressure and in the presence of hydrogen so that the sulfur components are converted to hydrogen sulfide, the nitrogen components to ammonia, and the aromatic hydrocarbons are converted to aliphatic compounds.

HDS or HDN processes commonly employ Group VIB transition metal oxides and Group VIII transition metal oxide catalysts in sulfided form during operation conditions, supported on suitable porous solids. Preferably the acidity of the supports is diminished with the aid of additives, or the acidity is intrinsically low.

The Group VIB metal component may be selected from the group consisting of molybdenum, tungsten, chromium, and a mixture of two or more of the foregoing, while molybdenum and/or tungsten is typically preferred, and molybdenum is typically more preferred. The Group VIII metal is selected from group consisting of iron, cobalt, and nickel, while nickel and/or cobalt are typically preferred. Preferred mixtures of metals include a combination of (a) nickel and/or cobalt and (b) molybdenum and/or tungsten.

When hydrodesulfurization activity of the catalyst is important, a combination of cobalt and molybdenum is advantageous and typically preferred. When hydrodenitrogenation activity of the catalyst is important, a combination of nickel and either molybdenum or tungsten is advantageous and typically preferred.

The Group VIB metal component can be introduced as an oxide, an oxo acid, or an ammonium salt of an oxo or polyoxo anion. The Group VIB metal compounds are formally in the +6 oxidation state. Oxides and oxo acids are preferred Group VIB metal compounds. Suitable Group VIB metal compounds include chromium trioxide, chromic acid, ammonium chromate, ammonium dichromate, molybdenum trioxide, molybdic acid, ammonium molybdate, ammonium para-molybdate, tungsten trioxide, tungstic acid, ammonium tungsten oxide, ammonium metatungstate hydrate, ammonium paratungstate, and the like. Preferred Group VIB metal compounds include molybdenum trioxide, molybdic acid, tungstic acid and tungsten trioxide. Mixtures of any two or more Group VIB metal compounds can be used; a mixture of products will be obtained when compounds having different Group VIB metal are used. The amount of Group VIB metal compound employed in the catalyst will typically be in the range of about 15 to about 30 wt % (as trioxide), based on the total weight of the catalyst.

The Group VIII metal component is usually introduced as an oxide, hydroxide or salt. Suitable Group VIII metal compounds include, but are not limited to, cobalt oxide, cobalt hydroxide, cobalt nitrate, cobalt carbonate, cobalt hydroxy-carbonate, cobalt acetate, cobalt citrate, nickel oxide, nickel hydroxide, nickel nitrate, nickel carbonate, nickel hydroxy-carbonate, nickel acetate, and nickel citrate. Preferred Group VIII metal compounds include cobalt carbonate, cobalt hydroxy-carbonate, cobalt hydroxide, nickel hydroxy-carbonate nickel carbonate and nickel hydroxide. Mixtures of two or more Group VIII metal compounds can be used; when the Group VIII metals of the compounds in the mixture are different, a mixture of products will be obtained. The amount of Group VIII metal compound employed in the catalyst will typically be in the range of about 2 to about 8 wt % (as oxide), based on the total weight of the catalyst.

Another application that is envisaged for the hydrogen-containing gas or the hydrogen stream containing hydrogen sulfide relate to catalyst sulfiding operations.

Herein, the term “sulfiding” is meant to include any process step in which a sulfur- containing compound is added to the catalyst composition and in which at least a portion of the metal components present in the catalyst is converted into the sulfidic form, either directly or after an activation treatment with hydrogen. The sulfiding step can take place ex situ to the reactor in which the catalyst is to be used, in situ, or in a combination of ex situ and in situ to the reactor.

Catalysts that may be subjected to the sulfiding operation include the hydrotreating catalysts mentioned above, in particular hydrotreating catalysts employ Group VI B transition metal oxides and Group VIII transition metal oxides, such as CoMo or NiMo catalysts.

In situ sulfiding processes are preferred. In situ sulfiding processes take place in the reactor in which the catalyst is to be used in hydrotreating hydrocarbon feeds. Here, the catalyst is contacted in the reactor at elevated temperature with the hydrogen gas stream containing hydrogen sulfide.

Another application that is envisaged for the hydrogen-containing gas or the hydrogen stream containing hydrogen sulfide relates to selective sulfur poisoning of Fischer- Tropsch catalysts. The Fischer-Tropsch process is a collection of chemical reactions that converts a mixture of carbon monoxide and hydrogen, known as syngas, into liquid hydrocarbons. These reactions occur in the presence of metal catalysts, typically at temperatures of 150-300 °C and pressures of one to several tens of atmospheres. The Fischer-Tropsch process is an important reaction in both coal liquefaction and gas to liquids technology for producing liquid hydrocarbons. Four metals are active as catalysts for the Fischer-Tropsch process: iron, cobalt, nickel, and ruthenium, but iron and cobalt are mostly used. Sulfur is a well-known poison for Fischer-Tropsch catalysts. However, small quantities of sulfur can enhance the activity and alter the selectivity of the catalyst.

Other applications that are envisaged for the hydrogen-containing gas or the hydrogen stream containing hydrogen sulfide relate to the production of elemental sulfur, or to the production of hydrogen sulfide by reacting the hydrogen-containing gas or the hydrogen stream containing hydrogen sulfide with elemental sulfur. The hydrogen sulfide thus produced can be further processed to, e.g., methionine.

The invention is further illustrated by the following examples.

The experiments were carried out in a fixed bed laboratory reactor with a reactant stream of 80 mol-% H2 and 20 mol-% CH4. The reactor had an inner diameter of 50 mm and was initially filled with calcinated petroleum coke (CPC) with a bed height of 500 mm. The bed was heated with an electrical oven through the wall. The CPC had a size fraction of 1 to 3 mm, a total initial mass of 870 g and a sulfur content of 1.4 wt.-%, as determined by elemental analysis.

Two experiments were carried out at a pressure of 1.1 bar (abs) and at a temperature of 1300 °C and 1450 °C, respectively, as indicated in the table below.

At 1300 °C, the sulfur content in the CPC was reduced by 1.2 wt.-% (148 mg) and converted to H2S in the gas-phase. Increasing the temperature to 1450 °C increased the sulfur conversion to 7.3 wt.-% (884 mg) within the same time on stream. The conversion was calculated by the H2S concentration in the gas-phase and cross-checked by elemental analysis of the carbonaceous material after the experiment, considering the additional carbon from the pyrolysis of methane.

Claims

1. A method for producing a hydrogen-containing gas stream containing hydrogen sulfide with concomitant production of low-sulfur carbonaceous material, comprising the steps of:

(ii) supplying carbonaceous particles to a reactor and subjecting the feed gas stream to pyrolysis in the reactor over a moving bed of the carbonaceous particles;

(iv) recovering low-sulfur carbonaceous particles.

2. The method of claim 1 , wherein the supplied carbonaceous particles have an initial sulfur concentration c(S)o and the recovered low-sulfur carbonaceous particles have a sulfur concentration C(S)R, which is lower than or equal to c(S)o.

3. The method of claim 1 or 2, additionally comprising

(vi) recycling the hydrogen-depleted gas to the reactor.

4. The method of claim 1 or 2, comprising removing hydrogen sulfide from the hydrogen-containing gas containing hydrogen sulfide.

5. The method of claim 3, comprising removing hydrogen sulfide from the hydrogen stream containing hydrogen sulfide.

6. The method of claim 1 or 2, comprising directing the hydrogen-containing gas containing hydrogen sulfide to a sulfur-insensitive hydrogen-consuming reaction, hydrogen sulfide manufacturing, a catalyst sulfiding operation, or selective sulfur poisoning of a catalyst.

7. The method of claim 3, comprising directing the hydrogen stream containing hydrogen sulfide to a sulfur-insensitive hydrogen-consuming reaction, hydrogen sulfide manufacturing, a catalyst sulfiding operation, or selective sulfur poisoning of a catalyst.

8. The method of claim 6 or 7, wherein the sulfur-insensitive hydrogen-consuming reaction is a refinery hydrotreatment, preferably a hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and/or hydrodearomatisation (HDA).

9. The method of claim 6 or 7, wherein the catalyst sulfiding operation is sulfiding of a hydrotreatment catalyst.

10. The method of claim 6 or 7, wherein the selective sulfur poisoning is selective sulfur poisoning of Fischer-Tropsch catalysts.

11. The method according to any one of the preceding claims, wherein the solid material particles are selected from carbonaceous materials, metals, ceramics and mixtures thereof.

12. The method according to any one of the preceding claims, comprising applying a voltage across at least a portion of the moving bed to provide direct electric resistance heating.

13. The method according to any one the preceding claims, wherein the pyrolysis is carried out at a temperature in the range of 1000 to 1600 °C.