Process and apparatus for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen

Abstract

The invention relates to a process for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen, comprising the following steps: - mixing the carbon dioxide-containing input gas with hydrogen to give a feed gas, - heating the feed gas to a temperature of greater than 330°C by indirect heat exchange, - hydrogenating the heated feed gas and chemically converting organic sulfur compounds to inorganic sulfur compounds, - separating off the inorganic sulfur compounds by adsorption and / or chemical reaction to give a largely desulfurized feed gas having a proportion of organic and inorganic sulfur compounds of less than 0.1 ppm, - mixing the largely desulfurized feed gas with hydrogen and - methanating carbon dioxide in the largely desulfurized feed gas with hydrogen to give methane, wherein a heat of reaction from a process gas formed in the methanation is used at least to heat the feed gas by the indirect heat exchange through cooling and water condensation thereof to give the methane-containing product gas. The invention further relates to an apparatus for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen.

Description

[0001] Method and apparatus for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen

[0002]

[0001] The invention relates to a method for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen. Furthermore, the invention relates to a device for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen, wherein the device comprises at least one mixer for mixing the carbon dioxide-containing input gas and hydrogen to form a feed gas, at least one hydrogenation unit for hydrogenating the feed gas and for chemically converting organic sulfur compounds into inorganic sulfur compounds, an adsorption unit for separating the inorganic sulfur compounds, and a methanation unit for methanizing carbon dioxide in the feed gas with hydrogen to form methane.wherein the device is associated with an electrolysis unit for supplying hydrogen to the hydrogenation unit and the methanization unit, or the device has an electrolysis unit for supplying hydrogen to the hydrogenation unit and the methanization unit, wherein the device has at least two heat exchangers.

[0003]

[0002] Currently, there is a high demand for alternative fuels to petroleum and natural gas, as well as for alternative fuels for vehicles, such as compressed natural gas (CNG). Replacing natural gas with hydrogen, which can also be produced alternatively, is possible in principle, but requires a completely different infrastructure, especially regionally, for a gas supply with systems that operate under high pressure.

[0004]

[0003] Biogas is produced by anaerobic (oxygen-free) fermentation of organic material, such as liquid manure, solid manure, waste and / or renewable raw materials, and is used as a renewable energy source. Known biogases have the following compositions:

[0005]

[0004] In the energy-economic concept “Power-to-Gas”, hydrogen is produced as a fuel gas by means of water electrolysis and the use of electric current and may be stored for later use.

[0006] In general, the electrolysis of water yields hydrogen and oxygen in high purity as end products. Three different electrolysis processes have become established for hydrogen production: alkaline electrolysis (AEL), polymer electrolyte membrane electrolysis (PEM, acidic electrolysis with solid-state polymer), and high-temperature electrolysis (HTE, steam electrolysis). These processes produce two molecules of hydrogen and one molecule of oxygen from two molecules of water. These processes differ significantly in their efficiency, which ranges from 60 to 70% for AEL and PEM electrolysis and up to 90% for HTE electrolysis. Efficiency is understood, in particular, as the ratio of electrical energy input to the energy (calorific value) of the hydrogen produced.All hydrogen electrolysis processes still suffer from the disadvantages that highly purified water must be provided, the heat generated during electrolysis can hardly be used due to the low temperature level (around 50 °C) and must be dissipated to the environment via cooling systems, and the produced hydrogen must be stored and transported under high pressure (over 37 bar) and low temperatures, which is very energy-intensive. Furthermore, the calorific value of hydrogen is 3.6 kWh / Nm³. 3 compared to methane with a calorific value of 11.03 kWh / Nm³ 3 very low.

[0007]

[0005] Furthermore, the methanization of CO2 with hydrogen is generally associated with the Sabatier reaction.

[0008] CO(g) + 3 H2(g) - CH4(g) + H2O(g) -206kJ / mol (1)

[0009] CO2(g) + 4 H2(g) → CH4(g) + 2 H2O(g) - 164 kJ / mol (2) and the water-gas shift reaction (WGS) CO2(g) + H2(g) → CO(g) + H2O(g) 41 kJ / mol (3) are known.

[0006] During the methanization of separated carbon dioxide from biogas upgrading, the proportions of organic and inorganic sulfur compounds contained in the carbon dioxide must be reliably removed to a level below 0.1 ppm so that the catalysts used for methanization are not damaged.

[0010]

[0007] Different purification processes can be used to remove inorganic and organic sulfur compounds. While inorganic sulfur compounds can be removed by adsorption, the removal of organic sulfur compounds requires their hydrogenation to inorganic sulfur compounds. The equilibrium reaction of the type applies here.

[0011] R-SH + H2R-H + H2S (4)

[0012]

[0008] Known organic sulfur compounds include thiols, thiophenols, sulfinic, sulfenic and sulfonic acids, alkyl sulfates, dimethyl sulfide (DMS), dimethyl disulfide (DMDS) and others.

[0013]

[0009] During the methanation process carried out according to equations (1) to (3), it must be taken into account that this process is exothermic and releases an extremely large amount of heat, which must be constantly dissipated. On the other hand, the cooling of the process gas must not be too deep, as this reduces the reaction rates and thus the yield. At excessively high reaction temperatures, however, the Bouduard equilibrium occurs.

[0014] C ( solid ) + CO2 ( gas f . ) + Energy 2 CO ( gas f . ) ( 5 ) a coking of the catalyst surface .

[0015]

[0010] While the technical production of hydrogen using the proven AEL or PEM electrolysis processes achieves a maximum efficiency of 70%, the subsequent methanation results in a further efficiency loss of theoretically 78.2% and practically up to 70% in the form of reaction heat, which often cannot be used at the methanation site, leading to a maximum overall efficiency of less than 49%. The costs for drying and transporting the methane produced in this way lead to further expenses, which further reduce the overall efficiency to around 40% with respect to electricity input. In the extreme case where this stored methane gas is then used to generate electricity for grid stabilization, an efficiency of 50% can generally be assumed, where, without heat recovery, the overall efficiency is reduced to around 20%.This will be illustrated below in a comparative example in a current assessment of the state of the art.

[0011] In the comparative example, a PEM electrolysis process with a power input of 1050 kW and a water requirement of 180 liters / hour produces 200 Nm. 3 / h of hydrogen with a proportion of less than 5 ppm of oxygen at 5 to 30 bar per process pressure and 100 Nm 3 Oxygen with a hydrogen content of 0.5 to 1.5 vol.% per hour. This conversion process requires the dissipation of 406 kW of process heat via cooling water with a maximum supply temperature of 35°C. The maximum required cooling water volume is 35 m³. 3The temperature of the cooling water increases by 11 °C to 46 °C per hour. This heat is generally dissipated to the environment via a table-top cooler. The calorific value of the produced hydrogen is therefore 703 kW. The specific electricity consumption per calorific value of hydrogen, at 1.49 kW electricity / kW H2, is high if the byproduct oxygen and the heat are not used and cannot be considered in the overall assessment.

[0016]

[0012] If the hydrogen obtained is now further methanized according to reaction equations (1) to (4), 50 Nm³ are required for this purpose. 3 CO2 is required per hour and 50 Nm are produced. 3 / h of methane and 100 Nm 3 / h of water. This process can be carried out without pressure or under pressure. The reaction results in a volume reduction of 250 Nm³. 3 / h at 150 Nm 3 / h and a reaction heat of 102 kW is released. The 50 Nm 3The methane produced per hour has a calorific value of 550 kW when fully converted. This increases the energy required for converting electricity to methane to 1.91 kW electricity / kW methane. While this worsens the individual energy costs of converting electricity, it has the advantage that the methane produced in this way can be easily fed into existing natural gas networks, used, and stored. This is in contrast to using hydrogen, which would require pressure increases to at least 37 bar (3.7 * 10 6 The reduced volumetric calorific value (almost three times lower) and the necessary cooling systems and pressure equipment represent a significant advantage when using existing natural gas networks. During methanation, a reaction heat of 102 kW is released, which, due to the existing temperature level of over 100 °C, can be utilized and increases the efficiency of the methanation process.

[0017]

[0013] From AT 282544 B, a process for the methanization of carbon monoxide and / or carbon dioxide in hydrogen-containing gases is known, which takes place at temperatures of 100 to 400 °C using nickel oxide compounds as a catalyst. In AT 518013 Al, the catalytic methanization for the application of electricity generation from renewable energy sources for the electrolytic production of hydrogen and the use of hydrogen for methanization with a honeycomb catalyst is carried out. The honeycomb catalyst is intended to simultaneously function as a heat storage medium. In each reaction chamber with honeycomb catalysts, at least one heat exchanger is arranged for the removal of excess reaction heat, which can optionally be used for temperature control of further reaction chambers. However, this heat exchanger is unsuitable due to the high reaction heat generated, as it does not sufficiently prevent the Boudouard reaction and coking.Consequently, short service lives of the catalysts used are to be expected.

[0018]

[0014] From CH 283359 A it is further known that the inorganic and organic sulfur compounds contained in the reaction gases are removed before they enter the methanation reactor. CH 312960 describes a process for the catalytic methanation of carbon oxide-rich gas mixtures in a fluidized bed with nickel-containing catalysts, wherein water vapor is additionally introduced into the fluidized bed. DE 195 30 528 A of fenbart discloses a metal-supported catalyst for the methanation of CO2 with a specific composition and a particle diameter of 0.2 to 0.3 mm.

[0019]

[0015] DE 10 2009 059 310 relates to the methanization of a gas mixture of pure carbon dioxide, obtained, for example, from air or biogas, with pure hydrogen obtained by electrolysis, wherein, after catalytic methanization of the gas mixture in a temperature range of 300 °C to 600 °C in a first reactor stage, water is partially removed from the gas mixture before post-methanization of the gas mixture in a second reactor stage in a temperature range of 250 °C to 300 °C at a pressure between 2 and 15 bar. The heat of reaction can be used to preheat the gas mixture before it is introduced into the first reactor stage. The gas mixture can also be biogas, although it is only generally stated that catalyst substances, such as sulfur compounds, must be removed before it is introduced into the first reactor stage.

[0020]

[0016] WO 2023 / 212 754 relates to a process for producing methane from a carbon dioxide-containing gas mixture, wherein a carbon dioxide-containing reactant gas stream and a hydrogen-containing gas stream are introduced into a methanation reactor and in the methanation reactor the carbon dioxide is reacted with hydrogen by biological anaerobic fermentation to form a methane-containing product gas stream. Subsequently, the product gas stream is passed through a gas purification unit with an activated carbon filter for desulfurization and a gas drying unit with a dry separator and is introduced into the subsequent gas separation unit.

[0021]

[0017] WO 2018 / 019 872 relates to a process for the production of hydrocarbons, in particular methane, by reacting carbon dioxide and hydrogen, in which the hydrogen used is previously obtained by electrolysis of water and the water separated from the methane-containing product stream by condensation or otherwise is at least partially recycled back into the electrolysis process. Carbon dioxide is supplied cryogenically and the heat from a return flow of a cooling medium used in the process is used for the evaporation and heating of the carbon dioxide.

[0018] Thus, the state of the art shows that although individual process steps for the use of carbon dioxide and hydrogen for methanization are known, there is not yet a comprehensive, self-contained, applicable method for safe and economical operation for real-world technical processes, especially also using biogas.

[0022]

[0019] The object of the invention is to improve the state of the art.

[0023]

[0020] The problem is solved by a method for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen, comprising the following steps:

[0024] - Mixing the carbon dioxide-containing input gas with hydrogen to create a feed gas,

[0025] - Heating the feed gas to a temperature greater than 330 °C by means of indirect heat exchange,

[0026] - Hydrogenation of the heated feed gas and chemical conversion of organic sulfur compounds into inorganic sulfur compounds,

[0027] Separation of the inorganic sulfur compounds by means of adsorption and / or chemical reaction, so that a largely desulfurized feed gas with a proportion of organic and inorganic sulfur compounds of less than 0.1 ppm is obtained; mixing of the largely desulfurized feed gas with

[0028] Hydrogen and

[0029] Methanization of carbon dioxide in the largely desulfurized feed gas with hydrogen to methane, whereby reaction heat from a resulting process gas of the methanization is used at least to heat the feed gas by means of indirect heat exchange through its cooling and water condensation, so that the methane-containing product gas is present.

[0030]

[0021] Thus, a process for producing a methane-containing product gas is provided, in which carbon dioxide-containing input gas from other technical processes and / or in a gas mixture that is not completely purified can be specifically converted to methane by methanation with hydrogen, and in which complete heat utilization from the conversion of hydrogen and carbon dioxide to methane takes place. It is particularly advantageous that the heating of the input gas by means of indirect heat exchange, utilizing the process gas heat and the condensation heat of the water produced during methanation, already takes place before the process step of hydrogenation and thus the chemical conversion of the organic sulfur compound and the subsequent separation of the inorganic sulfur compounds.

[0031]

[0022] Thus, any raw gas containing carbon dioxide, processed gas, and / or corresponding gas mixtures can be used to produce the methane-containing product gas. The carbon dioxide used for methanation can, for example, be a separated carbon dioxide-containing gas stream from a biogas upgrading plant, which has been obtained by means of amine scrubbing, membrane technology, and / or pressure swing adsorption (PSA). In principle, carbon dioxide can be obtained by means of amine scrubbing or another type of scrubbing from any technical exhaust gases from industry, combustion processes, a combined heat and power plant, or steel and / or cement production, and the like. However, it is also possible to use biogas directly.

[0032]

[0023] If the carbon dioxide from biogas upgrading is used, complete utilization of existing biomass, organic waste, and / or residual materials for the production of directly usable and storable methane as product gas is enabled. In addition to the more flexible use of the produced methane-containing product gas compared to the production of hydrogen as fuel gas and the advantageous possibility of direct injection into existing natural gas networks, the significantly higher calorific value of methane compared to hydrogen is advantageous. Consequently, the production process according to the invention enables an economical and technically feasible energy supply with increased methane production without additional raw materials and / or special input materials, such as purified substances, with storage of the produced methane-containing product gas and its use with the existing natural gas supply infrastructure and in ecological cycles.

[0033]

[0024] Thus, a comprehensive, advantageous and technically feasible overall process for the production of storable energy in the form of methane with increased methane yield and reduced energy costs is provided, in which the carbon dioxide-containing input gas from the processing, in particular the biogas processing, from existing organic raw materials regardless of their origin, such as from agriculture, municipalities, or as waste in liquid or solid form, can be used, resulting in a closed-loop process and consequently an overall economically advantageous use.

[0034]

[0025] In the case of biogas upgrading, the claimed production process uses the carbon dioxide separated from the biogas as the input gas and optionally also uses water from the biogas and / or from methane as water for electrolysis to produce hydrogen. Because the carbon dioxide separated in the biogas upgrading is subsequently reacted with hydrogen to form methane, and because the heat from the reaction of hydrogen and carbon dioxide to methane during methanation is fully utilized, the coupling of the production process with an upstream biogas upgrading process enables a comprehensive and advantageous overall process.

[0026] A key aspect of the invention is based on the fact that, for the production of storable methane, not only pure gases are used, but a carbon dioxide-containing input gas is used, which originates primarily from other processes using natural raw materials (such as biogas upgrading or fossil combustion processes). This allows for an increased methane yield due to optimal heat utilization within the process, as well as enabling energy-efficient and technically optimal production of the methane-containing product gas. It is particularly advantageous that the heating of the input gas by means of indirect heat exchange takes place before hydrogenation for the conversion and removal of sulfur compounds, and that only the largely desulfurized input gas is subsequently mixed again with fresh hydrogen and converted to methane.This enables optimal operation of a methanation catalyst and consequently a high methane yield, even with disruptive byproducts in the carbon dioxide-containing input gas, such as sulfur compounds, even in the case that carbon dioxide with a differently complex composition is not used as the pure gas for the production of the methane-containing product gas.

[0035]

[0027] The following terms shall be explained:

[0036]

[0028] “Carbon dioxide” (also “carbon dioxide”, “CO2”) is in particular a chemical compound of carbon and oxygen. Carbon dioxide is in particular a non-flammable, acidic and colorless gas. Carbon dioxide is in particular a well-known greenhouse gas in the Earth's atmosphere and is therefore subject to emission restrictions.

[0037]

[0029] The “carbon dioxide-containing input gas” can be any type of gas containing carbon dioxide. The carbon dioxide-containing input gas can be biogas, sewage gas, landfill gas, or a separated, carbon dioxide-containing gas stream from biogas upgrading, another processed carbon dioxide-containing gas stream, and / or any technical exhaust gas stream containing carbon dioxide from industry, combustion processes, a combined heat and power plant, and / or steel and cement production. The carbon dioxide-containing input gas can also be a mixture of different gas types. The CO2 of the input gas originates, in particular, from natural and / or fossil raw materials. The carbon dioxide-containing input gas has, in particular, a water content of less than 5% by volume, preferably less than 3% by volume, or is adjusted to this water content.Preferably, the carbon dioxide-containing input gas flows continuously into the device according to the invention and is continuously converted to methane. In principle, however, discontinuous operation of the device is also possible.

[0038]

[0030] “Methane” is, in particular under normal conditions, a colorless and odorless, flammable gas and, with the chemical formula CH4, the simplest member of the alkane group of substances. “Biomethane” refers in particular to methane produced in a biogas plant, which can be used as a fuel. “Biomethane” refers in particular to methane that is not of fossil origin, but was produced from biogenic substances and is a component of biogas. In the case of natural gas, the methane is in particular of fossil origin.

[0039]

[0031] A “methane-containing product gas” is understood to mean, in particular, a methane-containing gas produced by the process according to the invention. The term “methane-containing product gas” also includes the produced methane-containing gas that leaves the inventive device. The methane-containing product gas is produced, in particular, using the process steps of hydrogenation and methanization with separate supply of hydrogen. The produced methane-containing product gas may contain other components in small quantities in addition to methane. Likewise, the produced methane-containing product gas may contain water in liquid and / or gaseous form. Accordingly, after methanization, the methane-containing product gas can subsequently be subjected to drying and / or gas post-treatment. Any remaining carbon dioxide can also be separated in a gas post-treatment plant.The dried, methane-containing product gas can be directly injected into an existing natural gas network as fuel gas and / or used for methane liquefaction. It is particularly advantageous that the methane-containing product gas does not require pressure boosting for storage. "Process gas" refers in particular to the gas exiting the methanization process and / or a methanization unit, which is further used within the process and / or device according to the invention, for example, for heat recovery.

[0040]

[0032] A “feed gas” is understood to be, in particular, a gas mixture of the carbon dioxide-containing feed gas and hydrogen. The mixing of the carbon dioxide-containing feed gas with the hydrogen takes place, in particular, in a mixer. A mixer can be a pipeline and / or a mixing reactor. The feed gas has, in particular, a molar CCh / Ib ratio of 1:0.01 to 1:0.1 in order to subsequently convert the organic sulfur compounds present in the feed gas to inorganic sulfur in the form of hydrogen sulfide during hydrogenation. Before mixing, the carbon dioxide-containing feed gas has, in particular, a pressure of above 1 bar to 15 bar. After mixing, the feed gas is heated, in particular, by indirect heat exchange through heat transfer of at least a portion of the heat of reaction from the methanation to a temperature of > 300 °C up to 400 °C.Indirect heat exchange occurs primarily as gas-to-gas heat exchange between the resulting process gas from methanization and the feed gas, also with the separation of water. Organic sulfur compounds are always present in biogas and / or feed gas at significantly lower concentrations than the concentrations of inorganic sulfur compounds. Organic sulfur compounds can be present in biogas and / or feed gas at concentrations ranging from 0.1 to 2 ppm.

[0041]

[0033] “A largely desulfurized feed gas” is, in particular, a feed gas in which organic and inorganic sulfur compounds have a proportion of less than 0.1 ppm, preferably less than 0.01 ppm, and especially preferably less than 0.001 ppm. In the largely desulfurized feed gas, the proportion of organic and inorganic sulfur compounds is, in particular, in the range of 0.05 ppm to 0.0005 ppm, preferably from 0.02 ppm to 0.002 ppm. The proportion of organic sulfur compounds in the largely desulfurized gas mixture and / or feed gas is, in particular, in the range of less than 10 to 20% of the inorganic sulfur compounds. Organic sulfur compounds, in particular, constitute 15% of the inorganic sulfur compounds.Sulfur compounds can be measured, for example, using a mobile or stationary gas measuring device with an electrochemical sensor and / or after taking a gas sample by means of gas chromatography (GC) with a sulfur detector (e.g. FDD or PFPD).

[0042]

[0034] The organic sulfur compounds can be any organic sulfur compounds that occur in gases. For example, the organic sulfur compounds mentioned above can be the organic sulfur compounds. The inorganic sulfur compounds are, in particular, hydrogen sulfide and, optionally, sulfur-containing salts. If the carbon dioxide-containing input gas originates from an upstream biogas upgrading process, the concentrations of inorganic sulfur compounds are typically below 3 ppm H₂S and the concentrations of organic sulfur compounds are below 1 ppm. During hydrogenation, the hydrogen is added to the heated input gas, particularly at substoichiometric concentrations, specifically to first convert the organic sulfur compounds into inorganic sulfur compounds.This conversion proceeds in particular according to the reaction described above in equation (4). The hydrogenation takes place in a hydrogenation unit. The hydrogenation unit may comprise one or more hydrogenation reactors. Two or more hydrogenation reactors may be connected in parallel and / or in series. For the chemical conversion of organic sulfur compounds to inorganic sulfur compounds during hydrogenation, a catalyst, for example a C0N0 catalyst, is used.

[0043]

[0035] The separation of inorganic sulfur compounds already present in the feed gas and / or formed by hydrogenation is carried out in particular by means of adsorption and / or chemical reaction in an adsorption unit. The adsorption unit can have one adsorber or two or more adsorbers and / or adsorption columns. The adsorbers can in particular be connected in parallel and / or in series. ZnO and / or iron pellets can in particular be used as adsorbents for the removal of inorganic sulfur compounds.

[0044]

[0036] After the removal of the inorganic sulfur compounds by adsorption and / or chemical reaction, a heated, largely desulfurized feed gas is obtained. This largely desulfurized feed gas is then mixed again with fresh hydrogen. The mixing can be carried out in a mixer as described above. This mixing is carried out in such a way that, in the subsequent methanation, the carbon dioxide is converted to methane as completely as possible with the added hydrogen. For this purpose, a molecular ratio of CO2 / H2 of a maximum of 7 and a minimum of 2 is set before the methanation. This allows a defined adjustment of the hydrogen content in the methane-containing product gas by controlling the supply of hydrogen when mixing it with the largely desulfurized feed gas before the methanation.

[0045]

[0037] In the methanation of carbon dioxide in the feed gas, which is largely desulfurized and mixed with hydrogen, the reactions already described above proceed in particular according to equations (1) to (3). The methanation is carried out in particular in a methanation unit. The methanation unit can have one or more methanation reactors. Two or more methanation reactors can be connected in parallel and / or in series. The methanation and the methanation unit can thus be designed in particular as a two-stage process.

[0046]

[0038] A methanation reactor is preferably designed as a tubular reactor with jacket cooling. The process is preferably carried out almost isothermally, so that the inlet temperature of the feed gas corresponds approximately to the outlet temperature of the process gas and / or product gas with a difference of only 10 to 20 °C. The tubular reactor consists particularly of a number of parallel reactor tubes in which the catalyst for methanation is embedded in the tubes, wherein the catalyst and / or the catalyst particles are mixed layer by layer with inert particles, such as ceramic spheres, in order to avoid overheating in the catalyst bed and to obtain the most complete possible external utilization of the heat of reaction. The inert material is in particular a solid, inert material. Solid particles are particularly used as the inert material.Besides ceramics, quartz, glass, silicon, aluminum, or similar materials can also be used as inert materials. Metal catalysts based on nickel, rubry, or aluminum supports can be used. A cooling medium is circulated around the tubes to utilize the generated heat of reaction within the process, the overall plant, and / or in a connected, additional system via indirect heat exchange and / or a heat exchanger. In the case of a connected biogas upgrading plant, the generated heat of reaction can be used for biogas upgrading via amine scrubbing, thermal digestion of the fermentation substrate during biogas production to increase methane yield, and / or evaporation of digestate with ammonia removal.The cooling medium used in this process is primarily heat transfer fluids with a temperature range of up to 400 °C, such as synthetic heat transfer fluids or high-temperature salts. Additionally or alternatively, the heat generated by the reaction can also be used to produce steam, which can then be used in HET electrolysis with electricity, achieving a higher efficiency of up to 90% in hydrogen production.

[0047]

[0039] The hot process gas exiting the methanation reactor is then used to preheat the incoming feed gas. An electric heater can be installed to adjust the reaction temperature. By recovering heat from the hot process gas, it is already cooled, in particular, to a temperature of around 100 °C. This method is particularly effective because even at an operating pressure of 5 bar and 100 °C, a lower water content of 17 vol.% is achieved.

[0048]

[0040] A “heat exchanger” (also “heat transfer unit”) is, in particular, a device that transfers thermal energy from one fluid stream to another. A heat exchanger is, in particular, a recuperator in which the two fluid streams each flow through a separate space. A heat exchanger can, for example, be a plate heat exchanger or a tube heat exchanger.

[0049]

[0041] The term “heat recovery” refers in particular to a process step and a process engineering apparatus that enables the reuse of the thermal energy of a mass flow that would otherwise leave the process and / or the processing plant. The heat recovery system can, in particular, include one or more heat exchangers and optionally also a heat storage unit.

[0050]

[0042] The term “biogas” refers in particular to an energy-rich gas mixture that is produced during the natural decomposition of organic material in the absence of air. Biogas is produced in particular by the fermentation of biomass of any kind. Biogas is produced in particular in biogas plants, where it is generated from manure, biowaste, renewable raw materials, and / or energy crops. Biogas is produced in particular by natural processes of microbial degradation of organic substances under anoxic conditions. The composition of biogas varies considerably and depends on both the composition of the substrates used and the operating mode of the biogas plant. In addition to the main components methane and carbon dioxide, biogas contains in particular nitrogen, oxygen, hydrogen sulfide, hydrogen, and / or ammonia. Biogas has a pressure in the range of ambient pressure up to 10 bar.

[0051]

[0043] “Natural gas” is, in particular, a flammable, naturally occurring gas mixture found in underground reservoirs. Natural gas typically has methane as its main component, with the composition of the components depending on the reservoir. Natural gas has, in particular, a pressure in the range of 1 bar to 50 bar, and preferably predetermined pressure levels of 50, 25, 10, 5, and 1 bar.

[0052]

[0044] A “water content” indicates, in particular, the proportion of water in a material. Water content is understood to mean, in particular, the volumetric water content and thus the volume fraction of water in the volume of a gas or liquid.

[0053]

[0045] The term “ppm” (“parts per million”) in particular represents a factor of 10~ 6or for one millionth. The quantity is specified with regard to the invention, in particular as a volume fraction and thus as ppm (v). For example, 1 ppm (v) is equal to 1 milliliter per cubic meter.

[0054]

[0046] Under “Nm 3 "Standard cubic meters are understood to be, in particular, the quantity of a gas that, at 1.01325 bar and 273.15 K (0 °C), fills a volume of 1 m³." 3 is included.

[0055]

[0047] The term “normal pressure” is understood to mean, in particular, an agreed fixed gas pressure which corresponds to the mean atmospheric pressure at the Earth's surface. The normal pressure is, in particular, 101,325 Pa and thus 1.01325 bar. The term “normal pressure” is understood to mean, in particular, a relative pressure which lies in a range of up to +250 mbar and may also have a negative pressure, in particular down to -50 mbar, preferably -20 mbar.

[0056]

[0048] A “washing column” (also called an “absorption column”) is, in particular, a process engineering apparatus in which a gas stream is brought into contact with a liquid stream in order to absorb components of the gas stream into the liquid. In the washing column of a biogas upgrading plant and / or a gas post-treatment plant, raw gas, biogas, and / or the methane-containing product gas are brought into contact with a washing liquid, in particular an amine-containing washing liquid. To enable good mass transfer between the gas phase and the liquid phase, the washing column has, in particular, solid elements. “Solid elements” are understood to mean, in particular, one or more solid surfaces. Solid elements can, for example, be packings and / or oriented packings.

[0057]

[0049] The term "washing" refers in particular to a chemical process for separating carbon dioxide, hydrogen sulfide, and / or other acidic gases from raw gas and / or biogas, or in post-gas treatment for removing residual carbon dioxide and / or other residues from the produced, methane-containing product gas. In amine washing, slightly alkaline aqueous solutions of amines are used, particularly in the washing column, which reversibly chemically absorb carbon dioxide and / or other acidic gas components. The amine-containing washing liquid uses, in particular, monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), diisopropylamine, diisopropanolamine, diglycolamine (DGA), and / or AMP (2-amino-2-methylpropanol). Furthermore, the amine-containing washing liquid may contain alkazide solutions and / or other additives such as piperazines, morpholine and / or foam inhibitors.Before being used in the washing column, the washing liquid contains at least one amine component with a concentration of 15% to 60%. The amount of washing liquid used for amine washing depends primarily on the amine concentration and its composition. Washing can also be carried out using potassium carbonate (potash) as the washing solution.

[0058]

[0050] A “desorption column” is, in particular, a process engineering apparatus in which components of a liquid are transferred into the gas phase and / or a gas stream. For the desorption of the components from the liquid, the liquid and / or a liquid stream can be brought into contact with a gas stream and / or heated. In the desorption column, carbon dioxide bound in the scrubbing solution is transferred from the liquid phase to the gas phase. This allows the scrubbing solution to be reused, and in the case of biogas upgrading, a separated, carbon dioxide-containing gas stream is available, which can be used as a carbon dioxide-containing input gas in the process and / or the apparatus according to the invention. Similarly, an absorption column and a desorption column can be used in post-gas processing to remove residual carbon dioxide from the produced methane-containing product gas.Gas post-processing can also refer to a biogas upgrading plant.

[0059]

[0051] An “electrolysis” (also electrolysis device) is, in particular, a device in which an electrochemical reaction and thus a substance conversion is effected by means of an electric current. The electrolysis can, in particular, comprise one or more electrolysis cells for water electrolysis. During electrolysis, the reactions described above take place, producing hydrogen. The electrolysis can be classical alkaline electrolysis (AEL), alkaline electrolyte membrane (AEM) electrolysis, acid electrolysis, and / or proton exchange membrane (PEM) electrolysis.

[0060]

[0052] To enable maximum heat transfer and heat recovery within the methanation process, the heat of reaction from the methanation is removed by means of a heat exchanger, the heat exchanger being operated with a high-temperature heat transfer fluid in a temperature range of 150 °C to 300 °C.

[0053] It was surprisingly found that the heat content of the generated process and / or product gas is so high that it is sufficient to heat the feed gas to the reaction temperature for the hydrogenation of the organic sulfur compounds and the subsequent methanation. There is even a surplus of, in particular, 40% due to the heat of condensation present in the water. Thus, the entire methanation process can be carried out much more efficiently, both energetically and thermodynamically, at low pressures, resulting in an energy gain.

[0061]

[0054] In order to specifically utilize existing carbon dioxide-containing gas from a biogas upgrading plant, biogas and / or separated carbon dioxide-containing gas from an upstream biogas upgrading plant is used as input gas, wherein the heat of reaction from methanization is additionally used for thermal digestion of fermentation substrate to increase methane production, evaporation of fermentation substrate with separation of water and ammonia and / or detergent regeneration of an amine scrubbing or potassium carbonate scrubbing, each in the upstream biogas upgrading plant.

[0062]

[0055] In the process according to the invention, the heat of reaction generated during methanization is additionally available to increase the efficiency of the overall process. This allows the heat of reaction to be used internally and / or externally. It can thus be used for biogas upgrading with an amine scrubbing process for the necessary regeneration of the

[0063] The wastewater can be used for detergents, for the thermal digestion of biomass to increase methane yield, for the evaporation of digestate, for the production of steam for HET electrolysis, and / or in other processes. The energy required for these processes no longer needs to be supplied from renewable or fossil energy sources, but is provided entirely internally within the process and / or the device by means of heat exchange, heat transfer, and / or heat recovery. The resulting water cycle further eliminates the need for the external supply of water and / or steam for the electrolysis of these feedstocks to hydrogen and oxygen.

[0064]

[0056] In a further embodiment of the process, the hydrogen is supplied from an electrolysis unit for hydrogenation and methanization, wherein water is converted to hydrogen and oxygen in the electrolysis unit and optionally the oxygen produced is used for biological desulfurization in a biogas plant.

[0065]

[0057] To operate the electrolysis unit in a more resource-efficient and / or efficient manner, water produced during methanization can be separated from the process gas, fed to a water treatment unit, and the treated water, in liquid or vapor form, can then be fed to the electrolysis unit.

[0058] In a further embodiment of the process, the methanization and / or the upstream biogas treatment is carried out at a pressure in the range of ambient pressure up to 10 6 Pa (10 bar), especially of 2*10 5 Pa up to 8*10 5Pa, preferably from 4*10 5 Pa up to 6*10 5 Pa, carried out.

[0066]

[0059] In order to achieve high methane yield in the produced product gas and / or fuel gas, a molecular hydrogen / carbon dioxide ratio in the range of 1 to 4, preferably 1.6 to 3.95, can be set in the methanation.

[0067]

[0060] In a further embodiment of the process, after methanization a gas post-treatment is carried out to separate remaining carbon dioxide from the methane-containing product gas.

[0068]

[0061] In order to achieve a fuel gas quality, the water content of the methane-containing product gas can be adjusted by drying such that a dried methane-containing fuel gas is available for direct injection into a natural gas network and / or for methane liquefaction.

[0069]

[0062] In a further embodiment of the process, the methane-containing product gas and / or the methane-containing fuel gas is mixed with processed biomethane from the upstream biogas processing.

[0070]

[0063] Thus, the produced methane-containing product gas and the processed biomethane from the biogas processing can be supplied, stored, directly injected into a natural gas network and / or used for methane liquefaction, each with an increased methane yield and reduced energy requirement.

[0071]

[0064] In a further aspect of the invention, the problem is solved by a device for producing a methane-containing product gas from a carbon dioxide-containing input gas and hydrogen, wherein the device comprises at least one mixer for mixing the carbon dioxide-containing input gas and hydrogen to form a feed gas, at least one hydrogenation unit for hydrogenating the feed gas and for chemically converting organic sulfur compounds into inorganic sulfur compounds, an adsorption unit for separating the inorganic sulfur compounds, and a methanation unit for methanizing carbon dioxide in the feed gas with hydrogen to form methane.wherein the device is associated with an electrolysis unit for supplying hydrogen to the hydrogenation unit and the methanization unit, or the device has an electrolysis unit for supplying hydrogen to the hydrogenation unit and the methanization unit, wherein the device has at least two heat exchangers, and by means of a heat exchanger, heat of reaction from a resulting process gas of the methanization unit can be removed and, by means of indirect heat exchange, can be used at least to heat the feed gas to a temperature of > 330 °C before the at least one hydrogenation unit.

[0065] Thus, a comprehensive device is provided as a complete system for the production of methane-containing product gas for energy storage and use with a high methane yield and energy efficiency.

[0072]

[0066] In a further embodiment of the device, in which the methanization device has at least one reactor with a catalyst material, the catalyst material is mixed with an inert material in a ratio of 1 : 1 to 1 : 5, in particular from 1 : 3 to 1 : 4, preferably from 1 : 2.

[0073]

[0067] This prevents unwanted overheating of the catalyst material and coking reactions of the catalyst material.

[0074]

[0068] The invention will now be explained using exemplary embodiments. These show

[0075] Figure 1 is a highly schematic representation of a

[0076] Complete plant for the production of methane-containing product gas,

[0077] Figure 2 is a highly schematic representation of an upstream biogas processing plant.

[0078] Figure 3 is a highly schematic representation of a

[0079] Alternative of the overall system with a two-stage design

[0080] Methanization unit and corresponding heat exchangers, and Figure 4 a highly schematic flow diagram of a process for producing a methane-containing product gas.

[0081]

[0069] A complete system 101 has a

[0082] Hydrogenation unit 103 with a reactor RI, an adsorption unit 105, a methanization unit 107 with a reactor R2, a

[0083] Water treatment plant 113 with reactor R3 and an electrolysis plant 111 with reactor R4 (see Figures 1 and 2). Upstream of the hydrogenation plant 103, a mixer M1 for mixing CCh-containing gas 115 with hydrogen to form a feed gas, a heat exchanger W1 for heating the mixed feed gas using a process gas, and downstream a heat exchanger W2 for further electrical heating of the feed gas are arranged upstream of the hydrogenation plant 103. The hydrogenation plant 103 includes the reactor RI for hydrogenation. The adsorption plant 105 arranged downstream of the hydrogenation plant 103 has two adsorbers Al and A2 arranged in parallel and an adsorber A3 connected downstream in series. A mixer M2 is arranged after the adsorption unit 105 for heating the feed gas desulfurized by means of the adsorption unit 105.The subsequent methanization unit 107 includes a reactor R2 for methanization and is connected to a heat recovery unit W6. Furthermore, the complete system 101 shown in Figure 1 includes associated piping, the additional heat exchangers and / or heat recovery units W3 to W5 and W7 to W9, the circulation pumps Pl and P2, and water separators Fl to F3.

[0084]

[0070] In an alternative of the overall system 101 shown in Figure 3, the methanization unit 107 is designed in two stages with reactor R2 and a subsequent reactor R2A of the second methanization stage and has corresponding further heat exchangers W1A, W2A, W5A and W12, a further heat recovery unit W10 and further water separators F1A, F3A and F12, further associated piping and a further circulation pump PIA.

[0085]

[0071] The complete system 101 shown in Figure 1 has a biogas upstream processing plant 121 upstream of the mixer Ml, which is shown schematically in Figure 2. The biogas upstream processing plant 121 has an absorption column 141 followed by a desorption column 143. Fresh amine solution 131 is continuously fed into the head of the absorption column 141, while biogas 123 is introduced into the bottom of the absorption column 141. The carbon dioxide contained in the biogas 123 is absorbed by the amine solution in the absorption column 141, while the purified biogas 125, containing biomethane, exits the head of the absorption column 141.The loaded amine solution is fed from the bottom of the absorption column 141 via a heat recovery unit 147 to the top of the desorption column 143 and heated by means of an evaporator 153 connected to the bottom of the desorption column 143. The evaporator 153 is connected to the heat recovery unit W7 of the overall system 101 for heat transfer. Due to the heating of the loaded amine solution in the desorption column 143, carbon dioxide is displaced from the liquid phase and exits the desorption column 143 via its top and, after passing through a condenser 149, as separated carbon dioxide 127 from the biogas upgrading plant 121. Part of the hot, regenerated amine solution is returned to the absorption column 141 for reuse via the heat recovery unit 147 and a cooler 145 using the pump 151, while another part is circulated as amine excess 131.

[0086]

[0072] With the complete system 101 shown in Figure 1, a process 201 for producing a methane-containing product gas 223 is carried out with the following steps:

[0087]

[0073] The separated carbon dioxide 127 from the upstream biogas upgrading plant 121 (Figure 2) is fed via pipeline 1 to the mixer Ml as carbon dioxide-containing input gas 217 and mixed with hydrogen 219 from an electrolysis (R4) of the electrolysis unit 111 to form a feed gas 221 (step 203). Subsequently, the mixed feed gas 221 is heated 205 in heat exchanger W1 by means of indirect heat exchange and further heated in heat exchanger W2. Following this, hydrogenation 207 and chemical conversion of organic sulfur compounds into inorganic sulfur compounds are carried out in reactor RI of the hydrogenation unit 103. Inorganic sulfur compounds formed in this process are removed from the feed gas in the downstream adsorption unit 105 (step 209), so that a largely desulfurized feed gas is available.The largely desulfurized feed gas is then mixed with hydrogen from the electrolysis unit 111 in the mixer M2 (step 211), and subsequently a methanation 213 of carbon dioxide with hydrogen to methane is carried out in the reactor R2 of the methanation unit 107. The heat of reaction generated during the methanation 213 from a process gas is transferred via pipeline 16 by means of the heat exchanger W1 and indirect heat exchange to the mixed feed gas 221 to heat it 205 (step 215). Thus, a methane-containing product gas 223 is produced by the process 201.

[0088]

[0074] The method 201 according to the invention and the operating modes of the overall system 101 are explained in more detail in the following examples.

[0089] Example 1

[0090]

[0075] In a biogas plant, an amount of 593 Nm³ is produced from organic plant raw materials. 3Biogas with a methane content of 53% by volume is produced per hour. Of this, 236 Nm³ are used. 3 Biogas is converted in a combined heat and power plant (CHP) into 500 kW of electricity and 250 kW of high-temperature heat for biogas upgrading in biogas upgrading plant 121 with an amine scrubber in absorption column 141. A total of 2.37 t of corn silage / h, corresponding to 20,382 t / a, is used for this purpose. Other raw materials can also be used instead of corn.

[0091] Biogas upgrading plant 121 will be equipped with the amine scrubber 357 Nm 3 / h of biogas to 189 Nm 3Biomethane is converted per hour and fed into the natural gas grid; 0.94 tons of corn silage per year are consumed in the CHP unit. The calorific value of the biogas recorded in the CHP unit is 1,251 kW, of which 750 kW are used in the form of electricity and high-temperature heat, 15% (188 kW) are lost via the exhaust gas, and 313 kW are available for heating the digesters of the associated biogas plant or other processes.

[0092]

[0076] When applying the method 201 according to the invention, in the reactor R4 designed as a PEM electrolysis with 1.21 MW of electricity per hour, preferably from wind or solar energy, a quantity of 21.6 kg / h (242 Nm³) is produced from 184.4 kg / h of water. 3The process produces 172.8 kg / h of hydrogen and 172.8 kg / h of oxygen. Both products are available at a pressure of over 5 bar. During the PEM electrolysis in reactor R4, 364 kW of heat is released during the conversion process. This heat, combined with a hot water temperature of 50°C, can be used to heat the digesters or other buildings of the biogas plant. In this case, 65% of the heat can be used for the digesters of the biogas plant. The efficiency of PEM electrolysis is often related to the electrical power input for hydrogen production. 1 kg of hydrogen has a calorific value of 33.33 kWh / kg. Therefore, 719.9 kW out of 1,210 kW, or 59.5% of the electricity input, is used for hydrogen production. In this case, an additional 2 kg / h of oxygen is used for biological desulfurization in the biogas plant, increasing the overall efficiency of the electricity input to over 60%.By utilizing the waste heat from the electrolysis reaction (1210 - 719.9 kWh = 490.1 kWh) at a rate of 65%, the overall efficiency of this combined technical process increases to 1338.5 kW, resulting in a total efficiency of 85.8%. This overall efficiency can be further increased by adding additional heat consumers. Therefore, the combination of a biogas plant and hydrogen electrolysis for hydrogen production and its supply via a storage system with pipelines 2, 3, and 4 to the hydrogenation unit 103 and methanation unit 107, while converting CO2 from the biogas plant, proves to be advantageous. Only 246 Nm of CO2 is now required in the biogas plant. 3 The system produces biogas with a methane content of 53% by volume per hour, thereby reducing the raw material input by 0.983 t / h of corn silage or 8,455 t / a. The biogas upgrading plant 121 then produces 130.38 Nm³ of this biogas. 3 / h of biomethane and 115.62 Nm 3226.6 kg / h of CO2 is produced. The heat required for detergent regeneration is 173 kW. To regenerate 189 Nm 3 To produce biomethane per hour, the difference of 58.62 Nm must now be achieved. 3 / h of methane from the methanization of 58, 62 Nm 3 / h CO2 and 234.6 Nm 3 / h H2 is generated, releasing only 119.9 kW of reaction heat. In this case, 69% of the heat required for detergent regeneration can be supplied from the methanation via the heat recovery system W7 of the overall system 101.

[0077] If, on the other hand, the entire CCk quantity from the amine scrubbing is 115.62 Nm 3 The amount used for methanization is 462.6 Nm per hour. 3 / h of H2 is required, resulting in 115.62 Nm. 3 / h of additional methane with 236 kW of heat release, which corresponds to a total amount of methane of 246.0 Nm³ 3 / h corresponds to this. With this operating method, 246 Nm are now used in the amine scrubbing process. 3 / h Biogas instead of 357 Nm 3 / h processed. This reduces the heat requirement for detergent regeneration from 250 kW to 172 kW. To operate the process energy-autonomously for the heat supply of the amine washing process, only 84.5 Nm is sufficient. 3 73.1% of the separated CO2 is directed to methanization per hour. In this operating scenario, 338.2 Nm³ are required. 3 Hydrogen is supplied via PEM electrolysis with reactor R4, consuming 1,690 kW of electricity. This allows the electricity supplied by the PEM electrolysis system to control total methane production and provide the complete heat supply for biogas production, biogas upgrading, and external heat supply, with a high overall efficiency of over 90%.

[0093] Example 2

[0094]

[0078] In the existing system configuration of the overall system 101 (Figure 1), the methanization of 84.5 Nm³ is used for a heat energy self-sufficient supply of the amine scrubbing with 172 kW according to Example 1. 3 / h and thus 166 kg / h CO2 at a pressure of 5 bar. This is achieved via PEM electrolysis with reactor R4 338.2 Nm 3 / h of hydrogen is provided at a pressure of also 5 bar.

[0079] Therefore, only 84.5 Nm³ of hydrogen are supplied from the amine scrubbing of the biogas upgrading plant 121 via the pipeline 1 of the first methanization stage with reactor R2. 3CO2 is supplied as input gas at a pressure of 5 bar per hour. A molecular ratio of CO2 / H2 of 4 is established via pipes 1 and 3 and fed to mixer M1. In mixer M1, a mixing quality of over 99% is achieved for both gas streams as feed gas 221. The remaining hydrogen is supplied via pipe 4 to heat exchangers W3 and W4 for heating and mixing with the feed gas (hydrogenation gas) purified of sulfur compounds in mixer M2.

[0095]

[0080] The feed gas stream at the outlet of the mixer Ml of the mixed feed gas has the following composition:

[0096]

[0081] This feed gas stream is heated to 330 °C or higher in heat exchanger W1 with hot process gas from pipeline 16. A heat transfer of 17 kW is achieved. This feed gas is then further heated to 400 °C in heat exchanger W2 using electrical energy. This requires 4.2 kW. This feed gas contains a maximum of 2 ppm H₂S and a maximum of 2 ppm thiosulfate. The heated feed gas is then fed to the hydrogenation reactor (RI), in which the conversion of organically bound sulfur to inorganically bound sulfur takes place. Subsequently, in the adsorbers A₂, A₂, and A₃, the adsorption of inorganic sulfur compounds onto ZnO occurs under nearly constant temperature conditions. The CCh exhaust gas stream thus purified (desulfurized feed gas) with less than 0.01 ppm of sulfur compounds is then mixed with the hydrogen from 304 Nm via pipeline 12. 3The gases are collected via pipe 6 and fed to mixer M2. The optimal gas temperature at the inlet of reactor R2 of the methanation unit 107 is heated to approximately 300 °C in heat exchanger W3 by preheating the hydrogen with the feed gas via pipe 15. This process transfers 29 kW of heat. Heat exchanger W4 is electrically operated and is only installed for start-up operation. The gas mixture exiting mixer M2 is fed to reactor R2 at a temperature of 310 to 350 °C via pipe 13. Excess heating power from the process gas at the outlet of reactor R2 can be integrated via heat exchanger W10 in addition to heat exchanger W6 (see Figure 3). Heat exchanger W10 can be operated in parallel or in series with heat exchanger W3.Our own methanation experiments under molar reaction conditions according to equation 2 have shown that on a nickel catalyst with a 3 mm diameter, the temperature depends on the volumetric loading in vvh (Nm). 3 Gas / m 3 Catalyst h) the following conversion rates result with respect to the starting materials CO2 and H2 used:

[0097]

[0082] In addition to this main reaction, the side reaction according to equation ( 3 ) takes place, which leads to the formation of CO. It was found that under the conditions given in the table above, the following CO formation occurs.

[0083] Natural gas generally does not contain CO as a component. In some countries, such as Switzerland, this proportion is specified as less than 0.5 vol.%. In Germany, CO is only specified in gas family 1 (town gas) with a maximum of 6 vol.%. Hydrogen can be present in the injected gas up to 0.2 vol.% in England, up to 0.5 vol.% in Sweden and Belgium, up to 4 vol.% in Switzerland, up to 6 vol.% in France, and up to 10 vol.% in Germany (20 vol.% from 2021) and up to 12 vol.% in the Netherlands. In Germany, hydrogen can be present in gas family 1 with a proportion of 40 to 67 vol.%, while no hydrogen is specified in gas family 2.

[0098]

[0084] The reactor R2 of the methanization unit 107 is operated under the given conditions at a pressure of 5 bar, a temperature of 350°C and a vvh of 5,000 tu 1The reactor is operated using a nickel catalyst with varying diameters from 3 to 5 mm. Furthermore, the catalyst is mixed with 5 mm ceramic spheres in a ratio of 1:1 to 1:2 (catalyst:ceramic sphere). At the inlet and outlet (94% methanation) of reactor R2, the gas mixture has the following composition:

[0099]

[0100]

[0085] The gas mixture dried under these conditions in an amount of 104.84 Nm 3 / h (with a proportion of 79.47 Nm 3 / h of methane) does not meet the required conditions for injection into a natural gas network in Europe. However, if this gas mixture is mixed with the biomethane from the biogas upgrading plant, which consists of 246 Nm 3 / h Biogas produces a biomethane quantity of 130.38 Nm³ 3 / h is created, which is still approximately 1 Nm 3When a cylinder is loaded with CO2 per hour, a mixed gas is produced with a composition of 2.57 vol.% CO2, 8.59 vol.% H2 and 88.04 vol.% CH4. This product gas can be fed into the natural gas network without restriction in Germany and some other countries and can be used as fuel gas.

[0101]

[0086] Under these conditions, a total of 162 kW is extracted via heat extraction in reactor R2, heat recovery W6 and pump PI via heat recovery W7 for the amine scrubbing. For this purpose, the inner cooling circuit with pump PI is operated at a temperature level of 250 to 350 °C and the outer cooling circuit with pump P2 is operated at a temperature level of 110 to 150 °C for the heat supply in heat recovery W7 for detergent regeneration of the amine scrubbing.

[0102]

[0087] The process gas stream exiting reactor R2 via pipeline 14 is used with the partial streams in pipelines 15 and 16 for process gas heating in heat exchangers W1 and W3, whereby condensate is formed in separators Fl, F2 and F3, which is fed to reactor R3 of the water treatment unit 113, which provides the water for the PEM electrolysis with reactor R4. For the process operation, approximately 40% of the exhaust gas stream from pipeline 14 is routed via pipeline 16 for heating in heat exchanger W1 and 50% of the exhaust gas stream is routed via pipeline 15 for heating in heat exchanger W3. When this process gas is cooled to 90 °C, 88 kW of heat is released, which is sufficient for heating in both heat exchangers W1 (18.3 kW) and W3 (29.4 kW) with 47.7 kW.The excess heat of 40.3 kW can be transferred from pipeline 15 via heat recovery unit W10, at least 50% of which can be used in pipeline 33 for external heat utilization in the biogas upgrading process. Together with the extraction of the reaction heat via heat recovery unit W6, this results in a total heat output of 202.3 kW (Figure 3). This allows the biogas upgrading process to be increased by 15%, from 246 to 283 Nm. 3The throughput can be further increased without the need for external heat input. The cooled process gas is further cooled in heat exchanger W5 from 90–100°C to a temperature of 40–50°C and can also be dried directly for injection, as in the present example. The excess heat of 40.3 kW in heat exchanger W5 and heat recovery unit W10 can thus be used for process control in addition to the heat of reaction during the methanation reaction according to equation (2), thereby increasing the usable heat extraction from 172 kW to 202.2 kW by 17.6%.

[0103]

[0088] If drying takes place, a total of 127.6 1 / h of water is produced during methanization at the specified conversion rate. This water is supplied to the water treatment plant 113 with reactor R3 to provide water for the water cycle of the PEM electrolysis in reactor R4. 271.6 1 / h of water are required for PEM electrolysis in this case. The difference of 144 1 / h is extracted as water 163 from the dehumidification of the biogas before it enters the biogas treatment process and supplied to reactor R3 (Figure 3). The condensate / distillate thus treated in the water treatment of the water treatment plant 113 has a conductivity of less than 5 pS / cm.

[0104] Example 3 with a second methanization stage (Figure 3)

[0089] The process gas exiting reactor R2 from the first methanization stage 1 is cooled down to 42 °C via the heat exchanger W5 and the heat recovery W8 during the digestion of fermentation substrate of a biogas plant and exits from the separator F3 via the pipeline 23 .

[0105] The following gas composition results:

[0106]

[0090] This process gas is heated to a temperature of 300 °C in the heat exchangers W1A and W2A of the second methanation stage and fed to a second reactor R2A, in which 96% of the CO2 and / or H2 contained in this gas mixture is converted. Under these conditions, a gas mixture of the following is formed at the outlet of the second, downstream reactor R2A:

[0107] Composition with:

[0108]

[0091] A product gas containing methane is now formed

[0109] 117, that after drying a methane quantity of 84.34 Nm 3 / h. This means the methane yield with the 2nd stage with reactor R2A is 79.47 Nm³. 3 / h by 4.87 Nm 3The output can be increased by 10 kW / h. In this stage, a total of 10 kW of additional reaction heat can be extracted from reactor R2A via heat exchanger W6A. Heating the process gas in heat exchanger W1A from 50 °C to 300 °C requires 15.75 kW of heat. Cooling the hot process gas from 300 °C to 100 °C already contributes 11.63 kW. Under the given conditions at 6 bar, the water content in the exhaust gas results in a water dew point of approximately 100 °C, so that under these conditions about 5 kg / h of water condense and release 3.2 kW of heat. Thus, a nearly energy-autonomous heat process can be realized when cooling the process gas from 300 °C to 50 °C. Only a small heat input of about 1 kW is required in heat exchanger W2A. This heat exchanger W2A is preferably only needed for start-up operation.

[0110]

[0092] While the reactor R2 with a vvh of 2,500 to 8,000 tr1 When operated, the downstream, second reactor R2A is used for methanization with a vvh of 3,000 to 15,000 tu. 1 operated.

[0111]

[0093] The methane gas produced in this way can now be introduced into the natural gas network in all different European countries, either completely or partially, either separately or as a mixture with the biomethane from the biogas processing.

[0112]

[0094] With the now higher provision of heat for the detergent regeneration of the biogas upgrading with the amine scrubbing of 10 kW compared to Example 2, an additional biogas quantity of 14 Nm³ can also be produced. 3 / h are processed into biomethane.

[0113] Example 4 with methanization at 10 bar

[0114]

[0095] If methanation takes place at a pressure of 10 bar in reactors R2 and R2A, then, under the same process conditions, a conversion of 94.5% is achieved in reactor R2 and 96.5% in reactor R2A. This results in a reduction of the CO2 and hydrogen content in the dried methane from 0.24 vol.% to 0.18 vol.% for CO2 and from 0.95 vol.% to 0.71 vol.% for H2. Due to the now higher operating pressure, the condensation temperature of the process gas exiting reactor R2 increases from 120°C to 159°C compared to the operating conditions described in Examples 2 and 3. This allows a larger quantity of heat to be extracted from this process gas stream at a higher temperature level in the heat exchanger W5 or heat recovery unit W10. This heat can be used in heat recovery W7 for amine scrubbing, heat recovery W8 for thermal digestion of fermentation substrates and / or heat recovery W9 for steam generation.

[0115] Example 5 with methanization of biogas

[0116]

[0096] According to Example 1, a total of 357 + 236 = 593 Nm are required. 3 / h Biogas with a methane content of 53 vol.%, i.e. 314.3 Nm 3 Methane is produced from 2.37 t / h of corn silage. This biogas is dehumidified to a dew point of 8 to 14 °C and conventionally desulfurized to a H₂S content of less than 1 ppm using activated carbon or iron salts. The biogas is compressed to a pressure in the range of 2 to 10 bar, in this case to 5 bar. Due to the compression, the temperature of the biogas rises to 150 °C. Under these conditions, the compressed biogas is fed via pipeline 1 and mixed in mixer Ml via pipeline 3 at a pressure of 40 Nm. 3 / h hydrogen from a PEM electrolysis (111) is mixed. In addition to methane, the biogas also contains 18.6 Nm 3 / h water and 260.1 Nm 3 The CO2 content is present in / h. 1040.4 Nm³ is required for the methanization of this amount of CCh.3 Hydrogen is required per hour. This necessitates a PEM hydrogen electrolysis system with a power connection exceeding 5 MW and enables heat extraction of 532 kW during methanation. In this case, only 50% of the CO2 contained in the biogas is methanized with hydrogen at a slightly substoichiometric rate in reactor R2. A total of 500 Nm³ is required. 3 Hydrogen is used per hour, which corresponds to an electrolysis power of 2.5 MW. 460 Nm³ are supplied to reactor R2 for methanation via pipeline 4. 3Hydrogen is supplied via mixer M2. In heat exchanger W1, a total of 92 kW of heat is transferred with the process gas to raise the temperature to 330 °C. In heat exchanger W2, the hydrogen is heated to the hydrogenation temperature of 400 °C. 36 kW of heat is transferred electrically for this purpose. In heat exchanger W3, the hydrogen is heated from 30 °C to 300 °C with the process gas via pipeline 15, transferring 44 kW of heat. Heat exchanger W4 is again used only for the start-up process. The H2 / CO2 ratio at the inlet to reactor R2 for methanation is not stoichiometrically 4, as in examples 1 to 4, but rather 1.8. Internal investigations have shown that the hydrogen conversion is strongly dependent on the H2 / CO2 ratio in addition to the reaction temperature.While a H2 / CO2 volume ratio of 3.93 results in a 94% conversion of H2 to methane under the given conditions, this figure rises to 98% at a volume ratio of 3.53. At the present volume ratio of 1.8, the H2 conversion to methane exceeds 99.5%. The methanized process gas exiting reactor R2 has the following composition:

[0117]

[0097] When cooling the process gas from a

[0118] Reducing the reaction temperature from 350 °C to 50 °C releases a total of 213 kW of heat in the heat exchangers W1, W3 and W5, of which 136 kW is used for heating the

[0119] Biogas and hydrogen are required as feedstocks to reach the reaction temperature. The difference of 77 kW can be used externally. The reaction heat discharged in reactor R2 and heat recovery unit W6 amounts to 254.3 kW. This heat can be used in a downstream process.

[0120] Biogas upgrading, specifically gas post-treatment using amine scrubbing or potassium carbonate scrubbing, removes the remaining 301.9 kg / h of CO2 from the process gas. Approximately 0.76 kW / kg CO2 is required for CO2 removal with an amine scrubbing system. This results in a heat requirement of 229.4 kW, of which 24.9 kW from the reaction heat and 77 kW from the process gas are available for external use, such as increasing biogas production through thermal digestion, further biogas upgrading, digestate evaporation, or use as a heating medium, either directly or indirectly as a heat pump. The biogas, as product gas after amine scrubbing, has the following composition:

[0121]

[0098] The biomethane produced in this way can be fed into any natural gas network. In total, the biogas is used to produce

[0122] 314.3 Nm 3 Methane content / h now 438.1 Nm 3Methane is produced per hour. The residual hydrogen content in the biomethane can be precisely adjusted within the range of 0.05 to 20 vol. by supplying hydrogen via pipelines 4, 5, and 6 to mixer M2 and thus to reactor R2 of the methanation process, using hydrogen measurement at the outlet. Optionally, a second methanation stage with reactor R2A can be added, as shown in Example 3. This process allows hydrogen to be used in the existing natural gas network without additional modifications, while maintaining the high calorific value of the natural gas. A separate hydrogen network is therefore unnecessary.

[0123] Example 6

[0124]

[0099] Analogous to Example 5, biogas and methane are produced in the same plant configuration with 438.1 Nm 3 / h is generated. For biogas upgrading, instead of amine scrubbing or scrubbing with potash, biogas upgrading is now performed using physical scrubbing with water or polyether glycol, as well as membrane technology or pressure swing adsorption. In this case, CO2 is separated from the gas mixture without the addition of heat to a CCh content of less than 4 vol.%. The reaction heat of 229.4 kW released in Example 5 can now be used externally for other heat processes, heat pumps, or the generation of 350 kg / h of steam for HTE hydrogen electrolysis.

[0125] Example 7

[0126]

[0100] In a technical embodiment of the process 201 according to the invention, combining amine scrubbing, hydrogen electrolysis, and methanation, the hydrogen produced during electrolysis can be preheated from 20 °C to at least 50 °C using a heat exchanger upstream of heat exchanger W3 containing regenerated scrubbing solution from the amine scrubbing process. Likewise, the CO2 separated during scrubbing regeneration can be heated to at least 50 °C upstream of heat exchanger W1 using this regenerated scrubbing solution after water separation. This increases the additional heat extractable from methanation, with a temperature level above 80 °C, from 40.3 kW to 85 kW compared to Example 2. The vaporous water produced as a by-product during methanation acts as a heat pump in this process.

[0127]

[0101] The energy efficiency based on the calorific value generation according to equation (2) is 78.1% for the conversion of hydrogen (1196.6 kW) to methane (934.6 kW). However, since in the present case the heat of reaction released in the biogas upgrading process can be completely utilized, the overall energy efficiency under consideration increases to 92.55%. If the energy from the conversion to water vapor and its condensation is also used, the overall process can even be energy-neutral or positive.

[0128]

[0102] At an operating pressure in the methanization unit 107 of above 5 bar, a positive overall energy efficiency with respect to hydrogen input can be achieved through heat pump effects. Furthermore, in combination with biogas upgrading, the amount of methane can be doubled without additional raw materials. Reference list

[0129] Al Adsorber H2S

[0130] A2 Adsorber H2S

[0131] A3 Adsorber H2S

[0132] FL water separator

[0133] F2 water separator

[0134] F3 Water separator ml mixer CO2-containing gas with hydrogen f

[0135] F1A Water Separator

[0136] F3A Water Separator

[0137] F12 water separator

[0138] M2 mixer CO2-containing gas with hydrogen f

[0139] PI circulation pump cooling circuit

[0140] PIA circulation pump cooling circuit

[0141] P2 Circulation Pump Heat Recovery

[0142] RI Reactor Hydrogenation

[0143] R2 reactor methanization

[0144] R2A Reactor 2. Methanization Stage

[0145] R3 reactor water treatment for electrolysis

[0146] R4 Electrolysis

[0147] W1 Heat exchanger heater CO2-containing gas and hydrogen with process gas

[0148] W1A Heat exchanger process gas 2. Methanization stage

[0149] W2 Heat exchanger heater CO2-containing gas with hydrogen, electric

[0150] W2A heat exchanger process gas 2. Methanization stage electric

[0151] W3 Heat exchanger heater hydrogen with process gas

[0152] W4 Heat exchanger, electric water heater; W5 Heat exchanger, external cooler, heat recovery

[0153] W5A Heat Exchanger Cooler Heat Recovery 2 .

[0154] Methanization stage

[0155] W6 External heat recovery (hot water, thermal oil, steam)

[0156] W7 Heat recovery for amine scrubbing

[0157] W8 Heat recovery for thermal digestion

[0158] W9 Heat recovery for steam generation in HET electrolysis

[0159] W10 Heat Recovery

[0160] W12 heat exchanger cooler heat recovery 2 .

[0161] Methanization stage

[0162] 1 pipeline for raw gas containing CCh

[0163] 2. Pipeline for hydrogen from the electrolysis unit

[0164] 3 Pipeline for partial flow of hydrogen to the hydrogenation plant

[0165] 4. Pipeline for hydrogen to the methanization plant

[0166] 5. Hydrogen pipeline after heating

[0167] 6. Hydrogen pipeline after heating

[0168] 7 Pipeline for mixed gas consisting of CCh-containing raw gas with hydrogen f

[0169] 8 Pipeline for mixed gas after heating

[0170] 9 Pipeline for mixed gas after heating

[0171] 10 Pipeline for mixed gas after hydrogenation

[0172] 11 Pipeline for mixed gas after adsorption

[0173] 12 Pipeline for mixed gas after adsorption

[0174] 13 Pipeline for mixed gas mixture before methanization

[0175] 14 Pipeline for process gas after methanization Pipeline for partial process gas flow for heating hydrogen f Pipeline for process gas for heating hydrogenation gas Pipeline for process gas after heating hydrogen f Pipeline for process gas after water separation Pipeline for process gas after heating hydrogenation gas Pipeline for process gas after water separation Pipeline for process gas after heating hydrogenation gas and hydrogen f Pipeline for process gas after heat recovery Pipeline for product gas after water separation Pipeline for process gas after heating 2nd methanization reactor Pipeline for process gas after heating 2nd methanization reactor Pipeline for product gas outlet 2nd methanization reactor Pipeline for product gas after cooling and heat recovery Pipeline for product gas after water separation Pipeline for product gas after heat recovery Pipeline for product gas after water separation Pipeline for product gas after coolingPipeline for product gas for drying; Pipeline for water from separator F2 to reactor R3 of the water treatment plant; Pipeline for water from separator Fl to reactor R3; Pipeline for water from separator F3 to reactor R3; Pipeline for water from the water treatment plant to the electrolysis plant; Pipeline for hot water for heat recovery; Pipeline for hot water for heat recovery; Pipeline for cooling circuit; Inlet for methanization; Pipeline for water to reactor R3 of the water treatment plant; Pipeline for water to reactor R3 of the water treatment plant; Pipeline for water to reactor R3 of the water treatment plant; Pipeline for water to reactor R3 of the water treatment plant; Pipeline for water to reactor R3 of the water treatment plant; Pipeline for water to reactor R3 of the water treatment plant; Pipeline for cooling circuit reactor R2; Pipeline for cooling circuitReactor R2 Piping for cooling circuit W6 Piping for cooling circuit W6 Piping for cooling circuit W10 for piping 52 Piping for cooling circuit W10 for piping 52 Piping for cooling circuit Reactor R2A for piping 50 Piping for cooling circuit Reactor R2A for piping 50 Piping for hot water inlet W5 Piping for hot water outlet W5 Piping for hot water inlet W5 A Piping for hot water outlet W5 A Piping for cold water W12 Piping for cold water W12 Complete system Hydrogenation unit Adsorption unit Methanization unit Electrolysis unit Water treatment unit CO2-containing raw gas Methane (for drying) Upstream biogas upgrading plant Biogas Purified biogas Separated carbon dioxide Fresh amine solution Excess amine Absorption column Desorption column Cooler Heat recovery Condenser Pump Evaporator Water from biogas upgrading 121 Process for producing a methane-containingMixing product gases, heating via indirect heat exchange, hydrogenation and chemical conversion of organic sulfur compounds into inorganic sulfur compounds, separation of the inorganic sulfur compounds.

[0176] 211 Mixing a largely desulfurized feed gas with hydrogen f

[0177] 213 Methanization of carbon dioxide with hydrogen to methane

[0178] 215 Transfer of reaction heat from a resulting process gas of methanization

[0179] 217 Carbon dioxide-containing input gas

[0180] 219 Hydrogen f 221 Operating gas

[0181] 223 Product gas

Claims

Patent claims:

1. Method (201) for producing a methane-containing product gas (223) from a carbon dioxide-containing input gas (217) and hydrogen (219) , by the following steps: - Mixing (203) the carbon dioxide-containing input gas (217) with hydrogen (219) , so that a feed gas (221) is present, - Heating (205) the feed gas (221) to a Temperatures greater than 330 °C using indirect methods Heat exchange - Hydrogenation (207) of the heated feed gas and chemical conversion of organic Sulfur compounds in inorganic Sulfur compounds - Separation (209) of the inorganic sulfur compounds by means of adsorption and / or chemical reaction, so that a largely desulfurized feed gas with a proportion of organic and inorganic sulfur compounds of less than 0.1 ppm is obtained, - Mixing (211) the largely desulfurized feed gas with hydrogen and - Methanization (213) of carbon dioxide in the largely desulfurized feed gas with hydrogen (219) to methane (117) , wherein a reaction heat from a resulting process gas of the methanization is used by means of indirect heat exchange through its cooling and water condensation at least to heat the feed gas (221), so that the methane-containing product gas (223) is available.

2. Method (201) according to claim 1, characterized in that the heat of reaction from the methanation (213) is removed by means of a heat exchanger (W6), wherein the heat exchanger (W6) is equipped with a High-temperature heat transfer fluids are operated in a temperature range of 150 °C to 300 °C.

3. Method (201) according to claim 1 or 2, characterized in that a biogas and / or a separated carbon dioxide-containing gas (127) from an upstream biogas upgrading process is used as input gas (217), wherein the heat of reaction from methanization is additionally used for thermal digestion of fermentation substrate to increase methane production, evaporation of fermentation substrate with separation of water and ammonia and / or scrubbing agent regeneration of an amine scrubbing or Potassium carbonate scrubbing is used in the upstream biogas upgrading process.

4. Method (201) according to one of the preceding claims, characterized in that the hydrogen (219) is supplied from an electrolysis unit (111) for hydrogenation and methanation, wherein water is converted to hydrogen (219) and oxygen in the electrolysis unit (111) and optionally the oxygen produced is used for biological desulfurization in a biogas plant.

5. Method (201) according to claim 4, characterized in that water produced during methanization is separated from the process gas, a Water treatment unit (113) is supplied and the treated water, in liquid or vapor form, is then supplied to the electrolysis unit (111).

6. Method (201) according to one of the preceding claims, characterized in that the methanization and / or the upstream biogas treatment is carried out at a pressure in a range from ambient pressure to 10 6 Pa is carried out.

7. Method (201) according to one of the preceding claims, characterized in that a molecular hydrogen / carbon dioxide ratio in a range of 1 to 4, preferably 1.6 to 3.95, is set in the methanization.

8. Method (201) according to one of the preceding claims, characterized in that after methanization a gas post-processing is carried out to separate remaining carbon dioxide from the methane-containing product gas (223).

9. Method (201) according to one of the preceding claims, characterized in that the water content of the methane-containing product gas (223) is adjusted by drying such that a dried methane-containing fuel gas is available for direct injection into a natural gas network and / or for methane liquefaction.

10. Method (201) according to one of the preceding claims, characterized in that the methane-containing product gas (223) and / or the methane-containing fuel gas is mixed with processed biomethane from the upstream biogas processing.

11. Device (101) for producing a methane-containing product gas (223) from a carbon dioxide-containing input gas (217) and hydrogen (219), wherein the Device (101) at least one mixer (Ml) for mixing the carbon dioxide-containing input gas (217) and The device (101) comprises a feed gas (221) containing hydrogen (219), at least one hydrogenation unit (103) for hydrogenating the feed gas (221) and for chemically converting organic sulfur compounds into inorganic sulfur compounds, an adsorption unit (105) for separating the inorganic sulfur compounds, and a methanation unit (107) for methanizing carbon dioxide in the feed gas with hydrogen to methane, wherein the device (101) is associated with an electrolysis unit (111) for supplying hydrogen (219) to the hydrogenation unit (103) and the methanation unit (107), or the device (101) comprises an electrolysis unit (111) for supplying hydrogen (219) to the hydrogenation unit (103) and the methanation unit (107), wherein the device (101) comprises at least two heat exchangers, characterized in thatthat reaction heat from a resulting process gas of the methanization unit (107) can be removed by means of a heat exchanger (W6) and can be used by means of indirect heat exchange at least to heat the feed gas (221) to a temperature of greater than 330 °C before the at least one hydrogenation unit (103).

12. Device (101) according to claim 11, wherein the methanization device (107) has at least one reactor (RI) with a catalyst material, characterized in that the catalyst material is mixed with a solid inert material in a ratio of 1:1 to 1:5, in particular 1:3 to 1:4, preferably 1:2.

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