Method for operating gas storage facilities and apparatus for carrying out the method

Abstract

The invention relates to a method for operating a gas storage facility, wherein existing natural gas reservoirs or storage facilities are used for storing hydrogen as a storage gas, wherein the extracted production gas is separated in a gas separation plant when a mixture of hydrogen and natural gas is present, wherein the gas separation is carried out in a pressure swing adsorption (PSA) plant (E02) with an attached membrane plant (E03), wherein the PSA plant (E02) is supplied with the storage gas and subsequently the membrane plant (E03) is supplied with the desorbate pressure originating from the PSA plant (E02), wherein the permeate gas is returned from the membrane plant (E03) via a third control valve (V03) to the PSA plant (E02).wherein the third control valve (V03) is used to adjust the permeate pressure and the transmembrane flow and thus the gas composition and the residual hydrogen content in the retentate of the membrane system (E03), as well as a device for carrying out the process.

Description

[0001] The invention relates to a method for operating gas storage facilities according to the preamble of claim 1 and to a device for carrying out the method.

[0002] It is known that, in order to extract liquid raw materials from deposits, especially natural gas or crude oil, these deposits are pressurized with a gas to ensure sufficient pressure for the extraction of even residual volumes.

[0003] Either nitrogen or carbon dioxide is used for this purpose, with the use of carbon dioxide now also being employed for the sequestration of carbon dioxide in depleted deposits, thus generating a double benefit.

[0004] From “Journal of Petroleum Science and Engineering”, 196 (2021) “CO2 enhanced gas recovery and sequestration in depleted gas reservoirs: review”, Ahmed Hamza et al., an overview of Enhanced Gas Recovery, i.e. the expulsion of residual gas with CO2, is known, with this article presenting an overview of the known methods and problems.

[0005] In principle, gas-gas exchange in a reservoir involves physicochemical processes that go beyond simply the displacement of one gas by another. Adsorption processes of the introduced displacing gas occur in pores and on the rocks that form these pores, and desorbation processes of the displaced gas occur in the same locations. As is known from these processes, equilibria are established.

[0006] AT Turta, SSK Sim, AK Singhal, BF Hawkins, Alberta Research Council, Journal of Canadian Petroleum Technology, October 2008, Vol. 47, No. 10 also provides an overview of residual gas expulsion by gas-gas displacement, specifically using CO2 and N2 with CO2.

[0007] The same authors provide an overview of the factors that describe gas-gas displacement efficiency in the same journal, issue August 2009, Vol. 48, No. 8. This overview also uses nitrogen and carbon dioxide, as well as combustion gases.

[0008] The expulsion of residual natural gas by CO2 is also known from “Society of Petroleum Engineers, Enhanced Gas Recovery by CO2 Injection and Sequestration: Effect of Connate Water Salinity on Displacement Efficiency”; MK Abba et al., 2017.

[0009] The extraction of natural gas deposits using hydrogen and its recovery is known from DE 10 2010 035 260 A1.

[0010] German patent DE 10 2010 034 711 A1 discloses the extraction of natural gas using hydrogen derived from the natural gas. In this process, the methane in the natural gas is reacted with water.

[0011] The storage of hydrogen in natural gas reservoirs is known from DE 10 2010 031 777 A1. The aim is to continuously analyze gas mixtures forming in the gas network and to react accordingly at the point of consumption.

[0012] From DE 10 2010 020 762 A1 a process for the stabilization and transport of renewable energies is known, in which electrolytically produced hydrogen is to be fed into a natural gas pipeline and the gas mixture is supplied to a consumption point.

[0013] From EP 2 979 743 A1, a device and a method for storing and distributing renewable energy are known, wherein natural gas is mixed with hydrogen produced using renewable energy, the resulting natural gas / hydrogen mixture is distributed via a preferably existing gas network, preferably a natural gas network, and the hydrogen is separated from the natural gas / hydrogen mixture at a desired location by means of membrane separation, wherein the natural gas is mixed with the hydrogen produced using renewable energy and stored in a suitable storage facility, wherein, in the event of withdrawal of natural gas and / or hydrogen, the stored gas mixture is separated by means of membrane separation into natural gas with a hydrogen content corresponding to the legal requirements for injection into the natural gas network on the one hand and a natural gas / hydrogen mixture with a hydrogen content of about 50% for return to the storage facility on the other hand.

[0014] US Patent 5,753,010 A discloses a method for increasing the product yield or reducing the size of steam methane reformers and pressure swing adsorption (PSA) systems used for hydrogen production. A significant portion of the hydrogen in the PSA relief and purge gas, which would otherwise be burned as fuel in the reformer, is captured and recycled back into the PSA system to produce additional high-purity hydrogen product. This is achieved by processing selected portions of the relief and purge gas effluent in adsorption membrane separators to increase the hydrogen content for recycling back into the PSA system. The remaining portions of the relief and purge gas effluent, which contain lower hydrogen concentrations, are used as fuel in the reformer.

[0015] Despite the increasingly critical scrutiny surrounding the use of fossil fuels, natural gas remains a very valuable resource, particularly for the chemical industry. Therefore, it is essential to effectively exploit existing natural gas reserves. However, keeping costs down is crucial, which is why carbon dioxide is a cost-effective and, if sequestration is involved, also a favorable raw material in terms of its carbon footprint for extracting natural gas.

[0016] As explained in the aforementioned publications, carbon dioxide is also extracted along with the natural gas, and this carbon dioxide must be separated from the natural gas and recycled. This naturally also applies to gas mixtures with nitrogen or other gases. This is due to the equilibrium processes described. The necessary methods and equipment for this are known to those skilled in the art.

[0017] The equilibrium processes during adsorption / desorption mean that the displacement of natural gas is only possible up to a certain point, or up to a point where the separation of natural gas / displacing gas is no longer economical.

[0018] US Patent 6,183,628 B1 discloses a process for separating hydrogen and hydrocarbons within refinery processes, which involves pressure swing adsorption, compression cooling steps, and the use of membranes. The membrane separation is intended to achieve a selectivity of 2.5 for methane and hydrogen. The process is designed to generate a hydrogen stream, an LPG stream, and a methane-rich stream.

[0019] US Patent 2022 / 0219978 A1 addresses the problem that pressure swing adsorption (PSA) and cryogenic separation processes in petrochemical processes have technological limitations regarding hydrogen yield. To overcome this, gas separation membranes are to be combined with the aforementioned processes. A hydrogen-containing gas stream is first fed to a pressure swing adsorption (PSA) unit, with a membrane permeate stream also being fed to the PSA unit. The gas stream containing the hydrogen that has not yet been separated is then fed to the membrane separation stage, where the hydrogen-containing membrane permeate stream is fed to the PSA unit, and the remaining gas stream is diverted.

[0020] US Patent 4,238,204 deals with the separation of hydrogen or helium from a gas stream. The gas stream is fed into a selective adsorption unit where the lighter gas is separated, producing a purge gas containing the lighter gas. This purge gas is then fed into a membrane separation unit where the lighter gas is obtained with higher purity, and the permeate is returned to the selective adsorption unit. The gas, containing adsorbed gases and a small amount of remaining lighter gas, is to be disposed of or otherwise utilized.

[0021] A similar process is known from US 4,229,188.

[0022] US Patent 4,398,926 discloses a process in which a high-pressure gas stream containing up to 90 mol% hydrogen is fed to a separation unit containing a membrane separation stage capable of selectively allowing hydrogen to pass through. After pressure reduction, the hydrogen is fed to a pressure-compensated separation unit (PSA) adapted to the lower pressure. Exhaust gas from the separation unit is obtained primarily from the gas stream at the higher pressure, and a portion of this exhaust gas is depressurized and additionally fed to the PSA to contribute to hydrogen recovery and reduce operating costs.

[0023] The current state of the art indicates that the separation of hydrogen and hydrocarbons can be achieved using various processes and systems. To achieve the desired separation effect (defined as a sufficiently high gas purity and / or gas yield), a sufficient number of separation stages and / or process combinations usually need to be implemented, which, however, involves higher energy and equipment costs.

[0024] On the other hand, a process design task usually involves achieving the desired separation effects with the lowest possible equipment and energy expenditure. Furthermore, factors such as process stability and controllability play a significant role in process design.

[0025] The object of the invention is to create a method that separates hydrogen and natural gas more effectively and cheaply when operating a hydrogen storage system.

[0026] The problem is solved by a method having the features of claim 1.

[0027] Advantageous further training courses are indicated in the dependent sub-claims.

[0028] Another task is to create a device that separates hydrogen and natural gas more effectively and cheaply when operating a hydrogen storage facility.

[0029] The problem is solved with a device having the features of claim 14.

[0030] Advantageous further training courses are characterized by the requirements they meet.

[0031] The invention is used in cases where existing natural gas reservoirs or existing natural gas storage facilities, in particular porous natural gas storage facilities, are supplied with hydrogen.

[0032] This is particularly the case when hydrogen is used as a storage gas in an existing natural gas reservoir or storage facility in order to use a reservoir or existing natural gas storage facility as a hydrogen storage facility.

[0033] The opinion expressed at https: / / www.geostockgroup.com / en / four-ways-to-store-large-quantities-of-hydrogen / is that hydrogen would not mix with any gas present in the reservoir.

[0034] The opinion is also expressed in “Estimation of Diffusion Losses of Hydrogen During the Creation of its Effective Storage in an Aquifer”, Daniil Pavlovich Anikeev et al,; SPE-206614-MS, 2021, in particular page 11, first paragraph, that hydrogen does not mix with natural gas or, due to its lower density, even separates and collects at the highest point of the reservoir.

[0035] Contrary to expert assumptions, experiments conducted by the applicant have shown that, surprisingly, mixing of the introduced hydrogen (storage gas) with the residual natural gas does indeed occur.

[0036] This mixing allows the stored gas to penetrate more easily into less permeable regions of the reservoir. This leads to an increasing release of natural gas.

[0037] However, this also means that the mixed gases must be separated again.

[0038] It should also be noted that, for reasons of time and / or cost, the cushion gas—that is, the gas remaining in the storage tank as a pressure reservoir—may initially consist of, for example, equal parts hydrogen and natural gas. Therefore, the extraction of a gas mixture is to be expected for an extended period.

[0039] The effects mentioned above occur both when converting a natural gas reservoir into a hydrogen storage facility and when converting a natural gas storage facility into a hydrogen storage facility, as well as over a longer operating period of a hydrogen storage facility itself.

[0040] Contrary to the common belief that hydrogen and natural gas separate in the reservoir or that the two gases do not mix at all, field tests conducted by the applicant have shown that the hydrogen mixes into the natural gas both dispersively and diffusively.

[0041] When operating a hydrogen storage facility in a natural gas reservoir, and even during the conversion of a reservoir into a storage facility or a natural gas reservoir into a hydrogen storage facility, it is to be expected that fluctuating gas composition conditions will persist over an extended period. Furthermore, it is known in storage operations that pressure and flow rates can vary considerably depending on the fill level and the injection and withdrawal rates demanded by the market.

[0042] The present method is essentially intended for the operational phase of a hydrogen storage facility in a natural gas reservoir. However, it is not excluded that the method according to the invention could also be used in a conversion phase of a natural gas storage facility into a hydrogen storage facility, in which natural gas cushion gas is to be replaced by hydrogen cushion gas.

[0043] In any case, a system that processes the gas mixture must be very flexible with regard to input parameters such as pressure and gas composition.

[0044] Methods and systems for separating gases are of course already known, but known systems are designed for continuous processes, for example in refineries, where the volume flow, pressure conditions and gas composition are not subject to strong fluctuations.

[0045] Such existing systems, if adapted to the previously described conditions, would have to be designed to be unnecessarily large in order to cope with all production conditions. Furthermore, the controllability and attainability of the desired separation effect for all production conditions of such gas separation systems are not guaranteed in the current state of the art.

[0046] In order to create an economically viable configuration with high technical efficiency, a pressure swing adsorption system is combined with a membrane separation according to the invention, wherein the pressure in the system is influenced, which allows the separation effect to be achieved even with strongly fluctuating input parameters.

[0047] The invention thus relates in particular to a method for operating a gas storage facility, wherein existing natural gas reservoirs or natural gas storage facilities are used for storing hydrogen as a storage gas, wherein the extracted production gas is separated in a gas separation plant when a mixture of hydrogen and natural gas is present, wherein the gas separation is carried out in a pressure swing adsorption system with an attached membrane system, wherein the pressure swing adsorption system is directly subjected to the storage gas pressure and subsequently the membrane system is subjected to the desorbate pressure originating from the pressure swing adsorption system, wherein the permeate gas is returned from the membrane system to the pressure swing adsorption system via a third control valve, wherein the permeate pressure and the transmembrane flow, and thus the gas composition and the residual hydrogen content in the retentate of the membrane system, are adjusted with the third control valve.

[0048] A further development provides that the pressure swing adsorption system (E02) is directly subjected to the storage gas pressure or to a preset pressure, whereby a pressure reduction system is arranged upstream of the pressure swing adsorption system (E02) to adjust the storage gas pressure to a maximum pressure of the system design.

[0049] Further development involves additionally adjusting the retentate pressure or the retentate gas flow rate using a second control valve in the retentate gas line. This measure is implemented particularly when production conditions exhibit significant variance with regard to the stored gas composition, when the storage pressure range shows large amplitudes, or when the control options of the third control valve have been exhausted.

[0050] Further training stipulates that the absolute pressure of the permeate gas is set to between 0.5 bar and 11 bar directly after the membrane system, particularly between 1 bar and 6 bar.

[0051] Further development envisages that the third control valve influences the pressure of the permeate and thus also the partial pressures of the hydrogen and hydrocarbons in the membrane system, whereby the partial pressures affect the transmembrane flow of hydrogen and the transmembrane flow of hydrocarbons.

[0052] Further development stipulates that if an excessively high hydrogen content is detected in the retentate, the third control valve is opened to induce an increased transmembrane flow. Since hydrogen permeates faster than hydrocarbons, the increase in transmembrane flow is proportionally higher for hydrogen than for methane or hydrocarbons, thereby reducing the proportion of hydrogen in the retentate, as proportionally more hydrogen permeates from the retentate side to the permeate side than methane. Conversely, if the hydrogen content in the retentate is too low, the control is carried out in the opposite direction.

[0053] Further development involves intervening in the partial pressures by closing the second control valve, thereby changing the transmembrane flow so that more hydrogen enters the permeate.

[0054] Further training stipulates that, in the case of particularly low desorbate quantities, the functionality of the membrane system is maintained by accumulating the permeate, and the methane is not recycled via the permeate but enters the retentate.

[0055] Further training involves mixing the permeate with the storage gas via a gas mixer as a component of the feed gas to the pressure swing adsorption system.

[0056] Further training involves recompressing the permeate gas to the current pressure of the storage gas via a compressor stage, so that it can be mixed with the storage gas in the gas mixer.

[0057] Further development provides that the compressor stage is controlled via the suction pressure on the suction side, whereby a lower suction pressure is achieved by closing the third control valve, especially with small permeate quantities and low proportions of hydrocarbons in the storage gas.

[0058] Further development provides that, as the storage gas pressure decreases, the compressor output is adjusted and reduced to the lower required feed pressure of the permeate into the gas mixer, and as the proportion of hydrocarbons in the stored gas increases and the amount of desorbate increases accordingly, the pressure on the permeate side is lowered by opening the third control valve, so that the membrane system can process larger quantities of gas.

[0059] Further development involves opening the third control valve (V03) to increase the pressure on the suction side of the compressor stage (E04), enabling it to compress higher quantities of permeate gas.

[0060] Another aspect of the invention relates to a device for separating natural gas and hydrogen during the operation of a gas storage facility, in particular for carrying out the method described above, wherein existing natural gas reservoirs or storage facilities are used for storing hydrogen as a storage gas, wherein the extracted production gas is separated in a gas separation plant when a mixture of hydrogen and natural gas is present, characterized in that a pressure swing adsorption system with an attached membrane system is provided for separating the gases, wherein a gas-carrying connection for the permeate gas from the membrane system to the pressure swing adsorption system is provided, wherein a third control valve for controlling the permeate pressure and the gas composition of the retentate is arranged in a fifth gas-carrying gas connection in the gas-carrying connection.

[0061] Further training stipulates that a second control valve is present in the fifth gas-carrying connection for the retentate gas from the membrane system.

[0062] A further development provides that a gas mixer is arranged in a first gas-conducting connection for the storage gas, wherein the gas-conducting connection for the permeate gas leads into the gas mixer and the gas mixer is designed to mix the storage gas and the permeate gas to form the feed gas for injection into the pressure swing adsorption system.

[0063] A further development provides that in the sixth gas-conducting connection for the permeate gas, a compressor stage for compressing the permeate gas is arranged before or after the third control valve.

[0064] The invention is explained by way of example with the aid of a drawing. The drawing shows: Fig. 1: A highly schematic block diagram showing a device according to the invention with the process flow; Fig. 2: The natural gas content in the gas depends on the storage pressure.

[0065] The device is in Fig. 1 shown schematically.

[0066] The device according to the invention comprises one or more gas storage tanks E01, which are filled with a gas mixture consisting essentially of hydrogen and gaseous hydrocarbons (natural gas). The storage gas is fed to a gas mixer E05 via a gas-conducting first connection S01 and from there, as feed gas, passes via a gas-conducting second connection S02 to a pressure swing adsorption system E02.

[0067] The E02 pressure swing adsorption system comprises one or more adsorption stages and / or adsorbers, control valves and standard process accessories.

[0068] Via a gas-conducting fourth connection S04, gas from the low-pressure side of the pressure swing adsorption plant E02 passes to a membrane plant E03, comprising the desorbate gas of the pressure swing adsorption plant E02 with a mixture of hydrogen and hydrocarbons.

[0069] Via a third gas-conducting connection S03 from the high-pressure side of the pressure swing adsorption plant E02, the product gas with the purified hydrogen is conveyed to the hydrogen network or to another hydrogen consumer, or to a hydrogen storage facility.

[0070] The membrane system E03 includes in particular one or more membrane stages and / or membrane modules, fittings and accessories.

[0071] From a high-pressure side of the membrane system E03, a fifth gas-conducting connection S05 leads to a natural gas network or other hydrocarbon consumer or storage facility, comprising the retentate gas from the membrane system with the enriched hydrocarbons.

[0072] A sixth gas-conducting connection, S06, leads from a low-pressure side of the membrane system E03 to the gas mixer E05. The permeate gas from the membrane system E03, containing a mixture of hydrogen and hydrocarbons, is fed to the gas mixer E05 via this connection and mixed with the storage gas from the gas-conducting line S01 to form the feed gas for the pressure swing adsorption system E02.

[0073] The permeate gas from the membrane system E03 is passed through a compressor stage E04, which consists of one or more compressors comprising one or more compression stages with the corresponding control valves and accessories.

[0074] Furthermore, the device according to the invention can include one, several or all of the following group of devices: - a first control valve V01 positioned in the connection which includes product gas, - a second control valve V02 in the connection which includes the retentate gas, - a third control valve V03 in the connection which includes the permeate gas, - a first measuring device X001 for measuring the gas composition in the feed gas or storage gas, - a second measuring device X002 for measuring the gas composition in the product gas, - a third measuring device X003 for measuring the gas composition in the retentate gas, - a first pressure measuring device P004 for measuring the pressure in the retentate gas or in the desorbate gas, - one or more measuring devices F005 for measuring the quantity of the product gas flow or the storage gas flow.

[0075] The method according to the invention provides for first extracting a storage gas from a storage E01, comprising a hydrogen-natural gas mixture.

[0076] This storage gas is fed to a gas mixer E05 and mixed there with the permeate gas from the membrane system E03. The feed gas resulting from these two gases is then fed to the pressure swing adsorption system E02.

[0077] In the pressure swing adsorption plant E02, the feed gas is separated into the hydrogen-enriched product gas and the hydrogen-depleted desorbate gas.

[0078] The product gas is fed into or stored in a corresponding hydrogen gas network via line S03. Line S03 may contain measuring devices F005 for measuring the quantity of the product gas, measuring devices X002 for measuring the gas composition, and at least one valve V01.

[0079] The desorbate gas is fed into the membrane system E03 via line S04 and separated there into the retentate gas enriched with hydrocarbons and the permeate gas, which consists of hydrogen and hydrocarbons.

[0080] The permeate gas is fed to the gas mixer E05 via line S06, where the pressure of the permeate gas is increased by the compressor stage E04 if necessary. This is particularly necessary with comparatively small quantities of permeate gas.

[0081] According to the invention, the pressure swing adsorption (PSA) system can be directly pressurized with the storage pressure or storage gas pressure if this pressure is within the pressure range specified for the system design. If the storage gas pressure is too high, i.e., exceeds the maximum pressure specified for the system design, a pressure reducer can be installed upstream of the PSA system. The membrane system is then pressurized with the desorbate pressure originating from the PSA system.

[0082] According to the invention, this avoids equipment and energy costs for increasing the pressure.

[0083] According to the invention, the stable and controllable operation of the device in combination with a gas storage unit is achieved by recording the quantity of product gas with the measuring device F005 and, using this measured value, adjusting the stored quantity of purified hydrogen to the predetermined value by adjusting the valve position of the valve V01.

[0084] Furthermore, according to the invention, the gas composition in the feed gas or in the storage gas is measured using the measuring device X001. Alternatively or additionally, the gas composition in the product gas is measured using the measuring device X002.

[0085] The valve switching times of the pressure swing adsorption system E02 are controlled using these measured values. This means that, for example, if increasing methane concentrations are measured in the feed gas, the adsorbers must be switched earlier or the cycle times must be shortened because the adsorbers become saturated more quickly.

[0086] As is well known, pressure swing absorption is operated in cycles, in which a change takes place whenever the absorber is occupied, in order to release the absorbed gas.

[0087] The lower the methane content in the gas (especially at the beginning of the extraction), the longer the cycles can be and can be adjusted accordingly.

[0088] Furthermore, according to the invention, the gas composition in the retentate gas is measured using the measuring device X003. This measurement is used to control the adjustment of the desired gas composition in the retentate gas by adjusting the valve position of the valve V03.

[0089] Furthermore, according to the invention, the pressure in the retentate gas and / or the desorbate gas can be measured using the pressure measuring device P004. This measured value allows the setting of a pressure range predefined in the process design to be ensured by adjusting the valve position of valve V02.

[0090] The combination of pressure swing adsorption with a membrane system and one, several or all of the previously outlined control systems results in a surprising technical effect: such a system operates efficiently with minimal equipment even under the constantly changing conditions of storage operation.

[0091] To minimize the amount of hydrogen circulated and repeatedly fed into the pressure swing absorber, it makes sense to measure the feed gas for its methane content and adjust the cycle time accordingly.

[0092] In a typical withdrawal process from an underground storage facility filled with hydrogen and natural gas, the pressure gradually decreases along a ramp from a maximum storage pressure to the minimum permissible storage pressure. The gas composition of the withdrawn gas is subject to various fluctuations, which depend on a number of factors such as the withdrawal rate, the type of storage facility, geological conditions, and past operational processes. According to the inventors' experience, the withdrawal process usually begins with a high hydrogen content, which then continuously decreases to a lower value. An example of such a process is shown in Fig.Figure 2 illustrates the withdrawal ramp, which begins at 65 bar and approximately 4% natural gas content. During withdrawal and the associated pressure reduction, the natural gas content initially increases relatively slowly. As withdrawal progresses, the natural gas content grows more rapidly. At the end of withdrawal, at approximately 35 bar, the natural gas content in the withdrawn gas is already >12%. However, linear increases are also known.

[0093] In the energy-saving direct application of the pressure swing adsorption system to the storage pressure according to the invention, but also when a pressure reduction is installed upstream, the difficulty in applying the process lies in the fact that the driving force (pressure) available for the operation of the pressure swing adsorption system and the membrane system decreases, while the demand for it increases due to the increasing proportion of natural gas.

[0094] Despite this adverse relationship, the plant according to the invention can be operated over a wide range of production conditions using the disclosed method if the control processes according to the invention are applied.

[0095] The normal storage operating pressure available for the operation of the system is in a range between 10 and 320 bar, particularly 10 and 150 bar, and often between 20 and 80 bar.

[0096] The hydrogen content to be achieved in the product gas is >95%, but in particular >98% and preferably >99.999% if fuel cell applications are intended.

[0097] The hydrogen purity is adjusted during the design phase of the pressure swing adsorption and during the operation phase of the plant by adjusting the valve switching times of the pressure swing adsorption plant E02.

[0098] The control valve V01 serves to regulate the quantity and expands the product gas to the downstream hydrogen consumer, whose operating pressure is normally below the lowest value of the storage pressure range.

[0099] The absolute pressure of the desorbate gas is typically between 2 bar and 30 bar, but most often between 4 and 11 bar. The desorbate pressure range has a significant influence on the separation efficiency of the pressure swing system and the membrane system and is selected during the design phase of the process.

[0100] During operation of the plant, the position of valve V02 controls the desorbate pressure or the retentate pressure. The valve releases the retentate gas enriched with natural gas to a natural gas consumer whose operating pressure is normally below the lowest value of the desorbate or retentate range.

[0101] The set residual hydrogen content in the retentate gas is normally < 10%, but usually < 2%. The specified hydrogen or natural gas content in the retentate gas is set by the position of valve V03 via the influence on the permeate pressure directly after the membrane system E03.

[0102] If necessary, if the production conditions differ greatly with regard to the stored gas composition or the storage pressure range, the position of valve V02 can also be used to adjust the retentate gas composition within a limited range.

[0103] Otherwise, setting a constant pressure using the position of valve V02 in the retentate / desorbate gas is sufficient.

[0104] The absolute pressure of the permeate gas directly after the membrane system E03 is normally between 0.5 bar and 11 bar, but mostly between 1 bar and 6 bar.

[0105] According to the invention, gas separation should therefore be possible under changing conditions regarding pressure and gas composition, which on the one hand results in the highest possible purity of the gas streams with the highest possible yield.

[0106] The device and method can be used, with the pressure settings and pressure control devices mentioned above, to achieve stable operation and constant gas compositions in the product gas and the retentate gas, even when the storage gas pressure and composition are affected by large-amplitude fluctuations. This is achieved with minimal energy consumption.

[0107] The surprising effect is due to a special combination resulting from the nature of the two separation methods and the selection of optimized control processes.

[0108] During a withdrawal process, the proportion of natural gas in the storage gas increases and leads directly to an increase in the proportion of natural gas in the desorbate gas and an increase in the amount of desorbate gas.

[0109] For the membrane system that processes the desorbate gas, these two factors compensate for each other to a certain extent. On the one hand, the membrane has to process an increased volume of desorbate gas, but on the other hand, the hydrogen content to be separated is lower, which simplifies the separation process for the membrane system to a certain degree. In any case, the pressure conditions of the membrane system must be adjusted to accommodate the fluctuations.

[0110] This is primarily achieved by adjusting the third control valve, V03, which regulates the permeate pressure and, consequently, the transmembrane flow and the gas composition in the retentate. The third control valve, V03, influences the permeate pressure and thus also the partial pressures of hydrogen and hydrocarbons, or methane, in the membrane system. These partial pressures affect the transmembrane flow of hydrogen and the transmembrane flow of hydrocarbons.

[0111] For example, if a desorbate with a specific gas composition and quantity is introduced into the membrane system, and an excessively high hydrogen content is detected in the retentate by the third measuring device XO3, opening the third control valve VO3 results in an increased transmembrane flow. Since hydrogen permeates at least an order of magnitude faster than methane or hydrocarbons, the increase in transmembrane flow is proportionally greater for hydrogen than for methane or hydrocarbons. Consequently, the proportion of hydrogen in the retentate decreases because a relatively larger proportion of hydrogen permeates from the feed / retentate side to the permeate side than methane.

[0112] If the hydrogen content in the retentate is too low, the above-mentioned regulation and method can be carried out in reverse.

[0113] Furthermore, the separation effect can be changed with the second control valve V02, which sets the desorbate pressure of the pressure swing adsorption system, which is why it should only be used when the control options with the third control valve V03 have been exhausted.

[0114] An increase in pressure or the closure of the second control valve V02 on the retentate side has an effect analogous to, or supports, the opening of the third control valve V03. This also affects the partial pressures. Closing the second control valve V02 also changes the transmembrane flow and affects the hydrogen flow, which then enters the permeate in greater quantities.

[0115] The purpose of the V03 valve is also to ensure that, in the case of particularly low desorbate quantities (especially at the beginning of the storage process), the functionality of the E03 membrane is maintained by a build-up of the permeate, and the methane is not recycled via the permeate but enters the retentate.

[0116] The permeate contains hydrogen and methane and is mixed with the storage gas via the gas mixer E05 as a component of the feed gas.

[0117] Because the pressure drops across the two separation stages from desorbate to permeate, the permeate must be recompressed to the current pressure of the storage gas via the compressor stage E04 so that it can be mixed with the storage gas in the gas mixer E05.

[0118] Conventional compressors cannot be controlled across the entire range of gas volume differences. Therefore, according to the invention, the compressor stage is controlled via the suction pressure on the suction side if speed control is insufficient or even impermissible for the desired control range. A lower suction pressure can be achieved by closing the third control valve V03, causing the compressor stage to draw in smaller quantities of gas. This is particularly necessary when dealing with small permeate volumes resulting from low concentrations of hydrocarbons in the storage gas.

[0119] This approach has two advantages. Firstly, only a small portion of the permeate needs to be recompressed. Secondly, the storage gas pressure changes (decreases), allowing the compressor output to be adjusted to the lower required feed pressure of the permeate into the gas mixer. Since compressors account for a significant portion of the energy consumption in such systems, this allows for energy-efficient operation.

[0120] Conversely, if the proportion of hydrocarbons in the extracted gas increases, the amount of desorbate increases accordingly. Opening the third control valve V03 reduces the pressure on the permeate side immediately upstream of the third control valve V03, allowing the membrane system to process larger volumes of gas. Simultaneously, opening the third control valve V03 increases the pressure on the suction side of the compressor stage E04, enabling it to compress larger volumes of permeate gas, which was achieved using the disclosed control method.

[0121] The selection of the appropriate control ranges for the third control valve V03, with regard to regulating the permeate flow and the interaction between the membrane system E03 and the compressor stage E04, is primarily carried out during the design phase. In the operational phase, however, the position of the third valve V03 is mainly used to control the gas composition in the retentate. By correctly selecting the design parameters of all process units and control devices, the pressure values ​​before and after the control valve V03 are set correctly, and the compressor stage E04 operates appropriately even with varying permeate flows. Overall, however, intelligent control, as described previously, is then necessary to manage the pressure differences.

[0122] Furthermore, it is surprising that such a process, using a pressure swing adsorption (PSA) absorber and a membrane stage, is particularly well-suited for hydrogen storage in porous reservoirs, since any hydrogen sulfide produced is absorbed into the desorbate during PSA and from there passes to the separated CH4, where it causes comparatively few problems. The hydrogen sulfide in the extracted hydrogen is returned to PSA and either dried again or recirculated and, if necessary, chemically removed, for example, with activated carbon or metal oxides. This prevents its accumulation in the cycle. Reference symbol list E01 Gas storage E02 Pressure swing adsorption system E03 Membrane system E04 Compressor stage E05 Gas Mixer S01 first gas-conducting connection S02 second gas-conducting connection S03 third gas-conducting connection S04 fourth gas-conducting connection S05 fifth gas-conducting connection S06 sixth gas-conducting connection V01 first control valve V02 second control valve V03 third control valve X001 first measuring device X002 second measuring device X003 third measuring device P004 fourth measuring device F005 Flow meter

Claims

[1] Method for operating a gas storage facility, wherein existing natural gas deposits or natural gas storage facilities are used to store hydrogen as storage gas, wherein the extracted production gas is separated in a gas separation plant when a mixture of hydrogen and natural gas is present, characterized bythat the gas separation is carried out in a pressure swing adsorption plant (E02) with a connected membrane plant (E03), wherein the pressure swing adsorption plant (E02) is pressurized with the storage gas and subsequently the membrane plant (E03) is pressurized with the desorbate pressure originating from the pressure swing adsorption plant (E02), wherein the permeate gas is fed from the membrane plant (E03) via a third control valve (V03) back to the pressure swing adsorption plant (E02), wherein the third control valve (V03) is used to adjust the permeate pressure and the transmembrane flow and thus the gas composition and the residual hydrogen content in the retentate of the membrane plant (E03). [2] Method according to claim 1, characterized bythat the pressure swing adsorption system (E02) is directly pressurized with the storage gas pressure or with a reduced storage gas pressure, whereby a pressure reduction system is arranged upstream of the pressure swing adsorption system (E02) in order to adjust the storage gas pressure to a maximum pressure of the system design. [3] Method according to claim 1 or 2, characterized by that the retentate pressure or the retentate gas quantity is additionally adjusted with a second control valve (V02) in the retentate gas line (S05). [4] Method according to one of the preceding claims, characterized by that the permeate gas absolute pressure directly after the membrane system (E03) is set to 0.5 bar to 11 bar, in particular between 1 bar and 6 bar. [5] Method according to one of the preceding claims, characterized bythat the third control valve (V03) influences the pressure of the permeate and thus also the partial pressures of the hydrogen and the hydrocarbons in the membrane system, whereby the partial pressures affect the transmembrane flow of the hydrogen and the transmembrane flow of the hydrocarbons. [6] Method according to one of the preceding claims, characterized bythat if too high a hydrogen content is detected in the retentate, the third control valve (V03) is opened in order to bring about an increased transmembrane flow, whereby, since hydrogen permeates faster than hydrocarbons, the increase in the transmembrane flow is proportionally higher for hydrogen than for methane or hydrocarbons, whereby the proportion of hydrogen in the retentate is reduced because proportionally more hydrogen permeates from the retentate side to the permeate side than methane, whereby if the hydrogen content in the retentate is too low, the control is carried out in the opposite direction. [7] Method according to one of the preceding claims, characterized by that by closing the second control valve (V02) the partial pressures are intervened, causing a change in the transmembrane flow so that more hydrogen enters the permeate. [8] Method according to one of the preceding claims, characterized by that at particularly low desorbate quantities, the functionality of the membrane system (E03) is maintained by damming the permeate and the methane is not recycled via the permeate but enters the retentate. [9] Method according to one of the preceding claims, characterized by that the permeate is mixed with the storage gas via a gas mixer (E05) as a component of the feed gas to the pressure swing adsorption plant (E02). [10] Method according to one of the preceding claims, characterized by that the permeate gas is recompressed to the current pressure of the storage gas via a compressor stage (E04) so ​​that it can be mixed with the storage gas in the gas mixer (E05). [11] Method according to one of the preceding claims, characterized bythat the compressor stage (E04) is controlled via the suction pressure on the suction side, whereby a lower suction pressure is achieved by closing the third control valve (V03), in particular with small permeate quantities and with low proportions of hydrocarbons in the storage gas. [12] Method according to one of the preceding claims, characterized by that when the storage gas pressure decreases, the compressor output is adapted to the lower required feed pressure of the permeate into the gas mixer and is reduced, and when the proportion of hydrocarbons in the stored gas increases and the amount of desorbate increases accordingly, the pressure on the permeate side is reduced by opening the third control valve (V03) so that the membrane system (E03) can process larger gas quantities. [13] Method according to one of the preceding claims, characterized bythat an opening of the third control valve (V03) causes an increase in the pressure on the suction side of the compressor stage (E04), whereby it can compress higher quantities of permeate gas. [14] Device for separating natural gas and hydrogen during the operation of a gas storage facility, in particular for carrying out the method according to one of the preceding claims, wherein existing natural gas deposits or natural gas storage facilities are used for storing hydrogen as storage gas, wherein the extracted production gas is separated in a gas separation plant when a mixture of hydrogen and natural gas is present, characterized bythat a pressure swing adsorption plant (E02) with a connected membrane plant (E03) is provided for separating the gases, wherein a sixth gas-conducting connection (S06) for the permeate gas from the membrane plant (E03) to the pressure swing adsorption plant (E02) is provided, wherein a third control valve (V03) for controlling the permeate pressure and the gas composition of the retentate in the fifth gas-conducting gas connection (S05) is arranged in the sixth gas-conducting connection (S06). [15] Device according to claim 14, characterized by that a second control valve (V02) is present in the fifth gas-carrying connection (S05) for the retentate gas from the membrane system (E03). [16] Device according to claim 14 or 15, characterized bythat a gas mixer (E05) is arranged in a gas-conducting connection (S01) for the storage gas, wherein the gas-conducting connection for the permeate gas (S06) opens into the gas mixer (E05) and the gas mixer (E05) is designed to mix the storage gas and the permeate gas to form the feed gas for feeding into the pressure swing adsorption system (E02). [17] Device according to one of claims 14 to 16, characterized by that a compressor stage (E04) for compressing the permeate gas is arranged in the gas-conducting connection (S06) for the permeate gas before or after the third control valve (V03).

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