Electrochemical separation of hydrogen from pipelines.

Abstract

The present invention relates to a one-stage membrane process for the electrochemical separation of hydrogen from a natural gas stream in a pipeline (1) having a positive pressure in the range of 50 mbar to 100 bar, comprising the following process steps: (i) a gas side stream (2) is extracted from the natural gas stream in the pipeline (1) without changing the gas composition, the mass flow rate of said gas side stream being adjusted according to the hydrogen content of the natural gas stream (1) such that a depletion factor of 0.65 to 0.975 is established when the hydrogen concentration is less than 10% by volume, and a depletion factor of 0.55 to 0.925 is established when the hydrogen concentration is greater than 10% by mass, said depletion factor being defined as the quotient of the desired molar H product stream (6) and the molar H reactant flow rate in the gas side stream at the inlet of the membrane unit (2); (ii) this gas substream (2) is compressed (3) upstream of the membrane unit (5); (iii) heating the gas side stream to 100-250°C either upstream of the membrane unit or within the membrane unit, and supplying water (4) to the gas side stream upstream of the membrane unit and / or on the permeate side (4a) of the membrane unit such that the water loading is 0.005-0.2 moles of water / mole of natural gas; (iv) sending this gas side stream to an electrochemical membrane unit where hydrogen is separated as permeate (6a) at a temperature of 100-250°C; (v) the residue (8) from the membrane unit is recycled to the natural gas stream, sent to chemical utilization, and / or used as fuel; The method includes the steps of: The present invention further includes a method for identifying an optimal gas side stream drawn from a pipeline carrying natural gas and hydrogen for separating hydrogen from the gas side stream in an electrochemical membrane unit.

Description

[Technical Field]

[0001] The present invention comprises a one-stage membrane method for electrochemically separating hydrogen from a natural gas stream in a pipeline (1) having a positive pressure in the range of 50 mbar to 100 bar, comprising the following method steps: (i) a gas side stream (2) is taken from the natural gas stream in the pipeline (1) without changing the gas composition, the mass flow rate of said gas side stream being adjusted according to the hydrogen content of the natural gas stream (1) such that a depletion factor of 0.65 to 0.975 is established when the hydrogen concentration is less than 10% by volume, and such that a depletion factor of 0.55 to 0.925 is established when the hydrogen concentration is greater than 10% by mass, said depletion factor being defined as the quotient of the desired molar H product stream (6) and the molar H product flow rate in the gas side stream at the inlet of the membrane unit (2); (ii) this gas substream (2) is compressed (3) upstream of the membrane unit (5); (iii) heating the gas side stream to 100-250°C either upstream of the membrane unit or within the membrane unit, and supplying water (4) to the gas side stream upstream of the membrane unit and / or on the permeate side of the membrane unit (4a) such that the water loading is 0.005-0.2 moles of water / mole of natural gas; (iv) sending this gas side stream to an electrochemical membrane unit where hydrogen is separated as permeate (6a) at a temperature of 100-250°C; (v) Remaining product (8) from the membrane unit is recycled to the natural gas stream, sent to chemical utilization, and / or used as fuel.

[0002] Additionally, the present invention includes a method for identifying an optimized gas side stream extracted from a pipeline carrying natural gas and hydrogen for separating hydrogen from the gas side stream in an electrochemical membrane unit. [Background technology]

[0003] hydrogen: Hydrogen has the right prerequisites to become a key element of future energy supply. The transport sector in particular faces a major challenge to make it more climate-friendly. In Germany, the transport sector accounts for almost 20% of CO2 emissions, with more than half of these attributable to private transport.

[0004] Electromobility, including battery electric vehicles and fuel cell electric vehicles, allows the transport sector to reduce its dependence on petroleum-based fuels. In the best case, the electricity and hydrogen needed to run the vehicles can be produced from renewable energy sources. In the transport sector, hydrogen is an emerging fuel that does not generate local pollution when used in conjunction with fuel cell technology.

[0005] To be able to use hydrogen in fuel cell applications, the hydrogen must be of very high quality, as impurities will affect the catalyst and membrane.

[0006] Currently, hydrogen is mainly produced centrally in relatively large steam methane reformers (SMRs), after which it is compressed to 500 atmospheres, and in rare cases also liquefied, for transport to transport vehicles serving the sites where it is needed, for example hydrogen filling stations.

[0007] Other methods for producing H2 include, for example, electrolysis, pyrolysis, partial oxidation of hydrocarbons (POx), coal gasification, and biogas production. Summary of the Invention [Problem to be solved by the invention]

[0008] However, transporting hydrogen by vehicle is uneconomical and harmful to the environment. For example, transporting about one ton of high-pressure hydrogen requires a truck with a transport load of 40 tons. A large hydrogen filling station uses about one ton of high-pressure hydrogen every day. This means that each hydrogen filling station of any size must be supplied with hydrogen by large trucks every day. For an extensively developed hydrogen filling station network, this means a significant increase in truck traffic on already congested roads.

[0009] Currently, pure hydrogen pipelines already exist in fragments, parallel to vehicle transport. However, to supply hydrogen to filling stations over a wide area, a dedicated, high-density hydrogen pipeline network would need to be built, similar to a natural gas grid. Hydrogen pipeline networks that transport hydrogen at different pressure levels are being considered. However, such pipeline networks would require high infrastructure costs and similarly complex permitting procedures, which is why they are unlikely to become a reality in the near future.

[0010] It is also being considered to produce hydrogen in a decentralized manner in smaller production units, e.g., electrolysis, pyrolysis, SMR, etc., thereby shortening or even completely eliminating the transport route. However, such decentralized small plants have higher specific capital investment costs compared to centralized large plants, and are cost-effective compared to a centralized large plant combined with vehicular transport only if the transport route is very long (e.g., more than several hundred kilometers).

[0011] Many countries already have very dense natural gas networks, so if these could be additionally used to transport hydrogen, this would be very advantageous both economically and environmentally.

[0012] According to the DVGW study "Requirements, Options, and Limitations for the Separation of Hydrogen from Hydrogen / Natural Gas Mixtures" (G 201611), hydrogen as an energy carrier can be transported in existing natural gas supply networks. However, the study's findings indicate that adding hydrogen to natural gas could potentially cause problems for users and require hydrogen removal, for example, at natural gas filling stations, gas infrastructure facilities, or industrial plants. To protect plants, membrane methods, such as palladium membranes, adsorption methods, cryogenic methods, and the chemical conversion of hydrogen to methane (methanation) or water (oxidation) are proposed.

[0013] The H2-carrying gas in the pipeline can in principle be any known to those skilled in the art, examples of which are: L gas, H2 gas, natural gas, city gas, town gas, biogas, but also CO2, for example.

[0014] A typical natural gas composition is as follows: Methane (CH4) volume ratio 80% to 90% Ethane (C2H6) volume ratio 1% to 5% Propane (C3H8) volume ratio 0.4% to 0.7% Butane (C4H 10 ) Volume ratio 0.1% to 0.2% Carbon dioxide gas volume ratio 0-1% Nitrogen volume ratio 0.8% to 14% Mercaptans (odor) volume ratio 3mg / m 3 ~50mg / m 3

[0015] There are no restrictions on the type of pipeline in principle. Typical examples of pipelines include long-distance pipelines with a positive pressure of 30 to 220 bar, high-pressure pipelines with a pressure of 1 to 10 bar, medium-pressure pipelines with a pressure of 100 mbar to 1 bar, and low-pressure pipelines with a pressure of 10 to 100 mbar.

[0016] However, if hydrogen is required in molecular form at the site of use (e.g., at a hydrogen filling station), the use of natural gas pipelines for hydrogen transportation is only possible through the use of hydrogen capture separation methods, since in the case of methanation or oxidation, hydrogen is no longer present at the site of use, but only as methane or water.

[0017] The hydrogen-obtaining separation method can be a membrane method, a sorption method, or a distillation method.

[0018] In principle, it is possible to separate hydrogen from natural gas by distillation due to the large difference in their boiling points. For example, at atmospheric pressure, hydrogen boils at -253°C, while methane boils at -161°C. However, to selectively separate these two gases, the entire amount of natural gas must be cooled and liquefied. Furthermore, to obtain pure hydrogen, most of the hydrogen must be further liquefied. This makes distillation separation very costly.

[0019] Adsorption methods can be physical or chemical in nature: Useful prior art chemisorption methods involve metal hydride reservoirs or liquid organic hydrogen carriers (LOHCs). In either case, hydrogen temporarily binds strongly to the metal hydride or LOHC (e.g., carbazole). The released binding energy must then be reconsumed during the separation of hydrogen from the metal hydride or LOHC. Because the released binding energy is always at a lower temperature level than the energy required for desorption, chemisorption methods always involve losses, typically on the order of more than 25% of the energy content of the separated hydrogen.

[0020] Useful prior art physical adsorption methods include both pressure swing adsorption (PSA) and temperature swing adsorption (TSA). These adsorption methods are economically viable, especially when the amount of material to be separated is small. Using swing adsorption, gas components other than hydrogen are separated, leaving only hydrogen in the product gas stream. This means that more than 90% of the natural gas and hydrogen mixture must be adsorbed. In this concentration range, physical adsorption is extremely uneconomical.

[0021] The current state of membrane technology for hydrogen separation from pipelines is a pressure-driven, passive method.

[0022] Useful membranes for pressure-driven passive processes include materials through which hydrogen molecules (H2) can diffuse but larger gas molecules, such as CH4 and CO2, cannot. For example, such membranes consist of a thin palladium layer applied to a porous substrate layer. The palladium layer is responsible for selectivity, while the porous substrate layer is responsible for the membrane's mechanical strength, which must be very high due to the large pressure difference across the membrane required for separation.

[0023] Although the pressure-driven passive membrane method is in principle suitable for separating hydrogen from hydrogen-natural gas mixtures, it has significant drawbacks in the case of pipelines for two reasons: 1. The driving force for separation here is the partial pressure difference. For example, if a mixture of natural gas and hydrogen in a pipeline is under a pressure of 20 bar and we want to reduce the hydrogen content in the natural gas to 1% by volume, the minimum hydrogen partial pressure in the pipeline is:

[0024] 20 bar * 0.01=0.2bar

[0025] Since hydrogen is mainly present on the permeate side, the hydrogen partial pressure there roughly corresponds to the total pressure, meaning that the separated hydrogen can be obtained at a maximum of 0.2 bar. If the pressure were higher, the hydrogen would be pushed back into the pipeline.

[0026] In practice, hydrogen is obtained at much lower pressures, so that the membrane area (which is inversely proportional to the partial pressure difference) does not become too large and expensive.

[0027] For example, the use of hydrogen for filling cars requires very high pressures of over 800 bar, so the compression energy consumption in this case is very high. In particular, compression from, say, 0.2 bar to 2 bar requires roughly the same amount of mechanical energy as compression from 2 bar to 20 bar or from 20 bar to 200 bar. Furthermore, the size and therefore the cost of a gas compressor is linked to the volumetric flow rate. For example, at 0.2 bar it is 10 times more expensive than at 2 bar, and 100 times more expensive than at 20 bar. Gas compressors are correspondingly more expensive at lower inlet pressures. 2. Passive membrane methods have a selectivity of less than 100%. Because the separation effect is based solely on molecular size differences, not only H2 but also a small amount of CH4 diffuses. In particular, CH4 diffuses because the partial pressure difference across the membrane is several orders of magnitude greater than that of H2 due to the concentration ratio on both sides of the membrane. Therefore, without further purification steps, the extracted hydrogen does not have a purity of over 99.97%, as required for PEM fuel cells, for example, by ISO / TS 14687-2-2012.

[0028] Electrochemical hydrogen separation (EHS) is an electrochemical method based on the transport of protons (H+ ions) through an ion-conducting membrane and is a novel application for fuel cell technology (see WO 2016 / 50500 and WO 2010 / 115768). A water-containing mixture enters the anode chamber, where it is oxidized to protons and electrons. An electrical power supply provides the driving force for the transport of protons across a catalytic membrane, where they combine at the cathode to form "new" hydrogen (also called "evolving" hydrogen at the electrode).

[0029] Here, there is a correspondence between the proton and electron flow. The voltage required for the proton and electron flow now depends on both the partial pressure difference and the catalytic activity. The catalytic activity, in turn, depends on how little or how much it is deactivated by trace gases such as CO, CO2, and H2S.

[0030] Because the membrane transports only protons, the other components of the mixture remain in the off-gas system, allowing the EHS to produce highly pure (>99.99% H2) hydrogen.

[0031] Electrochemically activated processes such as EHS may be superior to pressure-driven passive processes in this case of use, but there are well-founded concerns about EHS low-temperature processes, which operate in the temperature range below 100 °C, due to the sulfur-containing trace gases and CO always present in natural gas, which can lead to very rapid deactivation of the catalysts required for platinum-based membrane processes.

[0032] The advantage of the electrochemically activated EHS process is that hydrogen can be transported against a partial pressure difference, making the technology suitable both for reducing hydrogen in natural gas networks to well below 1% hydrogen by volume and for operating at high operating pressures.

[0033] A good overview of the prior art regarding H2 separation from natural gas grids is given in the summary of the HyGrid WP10 Exploitation Workshop [https: / / www.higrid-h2.eu / sites / hygrid.drupal.pulsartecnalia.com / files / documents / HYGRID-WP10-D1016-DLR-TUE-09072017-v01.pdf].

[0034] HyGrid, for example, describes a hybrid system of three different separation methods for the separation of H2 from natural gas pipelines containing H2. In the first stage, a passive membrane method using Pd membranes is used to reduce H2 in the natural gas pipeline from 10% to 2%, followed by an EHS method to further reduce H2 in the natural gas pipeline below 2% concentration. HyGrid uses the abbreviation EHP instead of EHS for electrochemical separation of H2. In this specific case, a sulfonic acid-based Nafion membrane is used. Finally, the hydrogen obtained from the two separation methods is dried using a TSA.

[0035] This method has several drawbacks: 1. Three process stages are required. 2. For the reasons stated above, at least the hydrogen from the passive membrane process must be compressed for further use. 3. The EHP used in this hybrid system operates at low temperatures, making it highly susceptible to irreversible catalyst damage from catalyst poisons such as CO and H2S present in natural gas. The technology is based on the so-called low-temperature PEM membrane electrode assembly, developed for fuel cells operating on pure hydrogen. The oxidation of hydrogen and reduction of oxygen to water are based on platinum catalysts, which are irreversibly deactivated even by traces of CO. 4. Furthermore, the EHP required for this hybrid system requires a high water vapor partial pressure (typically 100% relative humidity) to prevent the membrane from drying out and to obtain electrical conductivity. Therefore, the gas mixture must be saturated with water, typically at 100% relative humidity, before separation, and the hydrogen must be dehumidified again after separation.

[0036] If it is intended to use existing natural gas networks and infrastructure with the present invention, the separation techniques used must be adapted to the structure and required limits, for example, regarding the amount of water allowed in the natural gas mixture. For example, the dew point of water under ambient conditions is required to be below -8°C to prevent damage to downstream pipeline systems as a result of corrosion or hydrate formation. For example, at a pipeline pressure of 70 bar, the water content at saturation is about 74 mg / m 3 This means that it must not exceed

[0037] When a technology requires a high water vapor partial pressure for H2 separation, for example, when a saturated state is used for H2 separation and this H2 separation is carried out at a relatively high temperature, for example, 20 to 160°C, water must be added to the H2-containing natural gas mixture before separation, and the water must be separated again from the natural gas mixture after H2 separation.

[0038] The relevant techniques for drying natural gas, i.e., separating water from natural gas, are known to those skilled in the art. An overview of the prior art relating to methods for drying natural gas is given, for example, by EP 2 477 725 B1 or EP 0 907 400 A1.

[0039] A further important constraint on the utilization of existing natural gas pipelines is the prevailing pressure in the pipeline. In pipelines for long-distance transmission, the pressure can be up to 220 bar. This long-distance network supplies several high-pressure networks at pressures between 4 and 16 bar. The main recipients of natural gas at this pressure level are industries. The high-pressure networks then branch into medium-pressure networks at 0.1 to 1 bar. The main commercial natural gas consumers, as well as industries and some private users, are connected to these medium-pressure networks. The low-pressure networks transport natural gas at lower pressure levels, mainly to private users, at low positive pressures between 22 and 100 mbar.

[0040] What this means for separation processes is that depending on the site of natural gas extraction and separation technology, the pressure required to separate hydrogen from the natural gas mixture must be adjusted. Particularly for pressure-driven separation technologies, this means that the natural gas pressure needs to be increased significantly again, which can result in high energy consumption levels.

[0041] Furthermore, the natural gas mixture has to be moistened and dried again according to the requirements of the respective separation technology, which makes drying a particularly costly process step.

[0042] Furthermore, the natural gas mixture must be brought to the corresponding temperature required for separation, which is true for palladium-based ceramic membranes, which operate at about 100°C, and phosphoric acid-based EHS membranes, which operate at temperatures up to 200°C.

[0043] It has been shown that the economic viability of hydrogen separation from natural gas pipelines is dependent not only on the choice of separation technology but also on the pre-treatment of the natural gas and the post-treatment of the off-gas before reintroducing the hydrogen-depleted natural gas into the natural gas grid.

[0044] It is clear to those skilled in the art that it is technically difficult and economically problematic to pass the entire natural gas stream through a separation unit in order to separate only small amounts of H2 from it. In this case, the entire natural gas volume would need to be compressed, heated, humidified and dried again. The corresponding pre- and post-treatment steps of the natural gas would be very costly.

[0045] The concept of partial gas extraction is disclosed in the HyGrid presentation, Summary on page 5 of the above-cited HyGrid WP10 Exploitation Workshop. However, no mention is made of pre- or post-treatment steps for the natural gas, nor are any recommendations made regarding partial gas volumetric flow rates. The only mention is of the possibility that the H2 product stream may need to be dried for certain applications.

[0046] JP2008248934 describes partial gas extraction without disclosing the corresponding pre- and post-treatment steps of natural gas, and does not give any recommendations regarding the amount of partial gas to be used.

[0047] EP 2 979 743 B1 describes an apparatus and method for the storage and distribution of renewable energy. The focus of the application is on the intermediate storage of hydrogen separated from an H2-bearing natural gas mixture, which can then be recycled to the natural gas mixture as needed. No mention is made of pre- or post-treatment of the natural gas, other than the need for a corresponding storage pressure, and recommendations regarding fractional gas quantities are given only to those fractional gas quantities sufficient to establish the desired H2 concentration in the natural gas pipeline.

[0048] WO 2019 / 180032 describes a method for separating hydrogen from a gas mixture with the aid of a combination of two membranes. The permeate from the first membrane stage, a passive gas membrane, is moistened with water and passed through the second membrane stage, an electrochemical membrane. The permeate from this second membrane stage is dried and directed to an H2 consumer. The retentate from the second membrane stage is compressed and dried before being recycled to the natural gas pipeline.

[0049] A disadvantage of this method is that two membranes are required. A further disadvantage of this two-stage method is that the pressure in the first membrane stage must be high. H2 separation in the first membrane stage is enabled via a partial pressure difference. Assuming a target H2 partial pressure on the permeate side of at least 1 bar, this means that the pressure in the natural gas pipeline must be greater than 10 bar, for example, when the H2 concentration in the natural gas pipeline is 10% by volume, or 20 bar, for example, when the H2 concentration in the natural gas pipeline is 5% by volume. However, the majority of natural gas pipelines have pressures below 10 bar. In this case, a dedicated compressor to increase the pressure must be installed upstream of the first membrane stage. Furthermore, in WO 2019 / 180032, the entire pipeline flow is directed through this first membrane stage. As a result, the dimensions of this gas membrane must be correspondingly large, and a significant pressure loss must be balanced for the entire pipeline flow.

[0050] The future challenges are (i) the cheap and decentralized supply of high-purity hydrogen, e.g. for decentralized power supply and for filling hydrogen vehicles to operate fuel cells, and (ii) the cheap supply of low-hydrogen natural gas, e.g. for the glass industry, chemical applications, and storage in caverns.

[0051] Therefore, one object of the present invention is to demonstrate a method for separating hydrogen from a pipeline, particularly from a pipeline at low positive pressure, by only a single membrane stage, and thus demonstrate an inexpensive distributed supply of high purity hydrogen. Another object of the present invention is to demonstrate the optimal fractional gas amount that can be separated from a pipeline by using an EHS at the lowest hydrogen separation cost.

[0052] Also required were guidelines on the amount of fractional gas that should be separated from the pipeline to achieve the lowest separation costs for hydrogen separation with the help of EHS. [Means for solving the problem]

[0053] Surprisingly, a one-step membrane method for the electrochemical separation of hydrogen from a natural gas stream in a pipeline (1) having a positive pressure in the range of 50 mbar to 100 bar has been discovered, which method comprises the following method steps (FIG. 1): (i) a gas side stream (2) is extracted from the natural gas stream in the pipeline (1) without changing the gas composition, the mass flow rate of said gas side stream being adjusted according to the hydrogen content of the natural gas stream (1) so as to establish a depletion factor of 0.65 to 0.975 when the hydrogen concentration is less than 10% by volume, and a depletion factor of 0.55 to 0.925 when the hydrogen concentration is greater than 10% by mass, said depletion factor being defined as the quotient of the desired molar H2 product stream (6) and the molar H2 product flow rate in the gas side stream at the inlet of the membrane unit (2); (ii) this gas substream (2) is compressed (3) upstream of the membrane unit (5); (iii) heating the gas side stream to 100-250°C either upstream of the membrane unit or within the membrane unit, and supplying water (4) to the gas side stream upstream of the membrane unit and / or on the permeate side (6a) of the membrane unit such that the water loading is 0.005-0.2 moles of water / mole of natural gas; (iv) sending this gas side stream to an electrochemical membrane unit where hydrogen is separated as permeate (6a) at a temperature of 100-250°C; (v) Recycle of the residue (8) from the membrane unit to the natural gas stream at a feed point (16), sent to chemical utilization, and / or used as fuel. [Brief explanation of the drawings]

[0054] [Figure 1] The process of the present invention is illustrated where the product is high purity H2. [Figure 2] 1 illustrates the process of the present invention where the product is H2-free natural gas. [Figure 3] A processing example is shown to show the effect of the H2 load YH2,PL,α of natural gas in the pipeline on the specific energy consumption tavar. [Figure 4] FIG. 1 shows the effect of the required wetting of the gas side stream on the specific energy consumption tavar for different H2O loadings YH2O;TG,ω of the natural gas upstream of the separation unit. [Figure 5] The influence of the pressure drop over the entire path of the gas sidestream from the withdrawal station to the re-supply station to the pipeline on the specific energy consumption tavar is shown. [Figure 6] The influence of the H2 load YH2,PL,α of natural gas in the pipeline on the separation energy consumption Σ(qi+pi) is shown. [Figure 7] The effect of required wetting of the gas sidestream on the separation energy consumption Σ(qi+pi) for different H2O loadings in the gas sidestream upstream of the separation unit is shown. [Figure 8] The effect of pressure loss in the entire path of the gas side stream from the withdrawal station 15 to the re-supply point 16 to the pipeline on the separation energy consumption Σ(qi+pi) is shown. [Figure 9] Supports the effect of pressure loss Dp on the entire gas side flow path. [Figure 10] The complex dependence of the optimal total reduction degree AGopt, taking into account both variable and fixed components, on two main influencing parameters, the H2 load YPL;H2,α of the natural gas stream in the pipeline and the steam load YTG;H2O,ω of the gas side stream before entering the separation unit, is shown for the case of a pressure drop Δp of 0.1 bar over the entire path of the gas section from the withdrawal station 15 to the resupply station 16. DETAILED DESCRIPTION OF THE INVENTION

[0055] In the following description, all percentages are by volume unless expressly stated to be by weight. In the gas phase, mol% is equivalent to volume%.

[0056] Step (i): From a hydrogen-containing natural gas stream being transported in a pipeline, for example with the aid of one or more compressors, a gas side stream is extracted, representing up to 80% by volume of the total natural gas stream, preferably 0.0001% to 80% by volume, preferably up to 50% by volume, preferably 0.0001% to 50% by volume, more preferably up to 30% by volume, preferably 0.0001% to 30% by volume, even more preferably up to 20% by volume, preferably 0.0001% to 20% by volume, and in particular up to 15% by volume, preferably 0.01% to 15% by volume. The composition of the gas side stream (2) corresponds to the composition of the natural gas mixture (1) in the pipeline, i.e., the gas side stream (2) is extracted without changing the gas composition. The design of tapping points for extracting the natural gas side stream is known to those skilled in the art. For example, a tapping point for extracting the natural gas side stream may advantageously be designed as follows: the volumetric flow rate (2) extracted is measured by a volumeter. An electronic device compares this volume with a target value. If the extracted partial gas flow rate is less than the target value, the compressor (3) is driven to deliver a larger volume. If the extracted partial gas flow rate is greater than the target value, the compressor (3) is driven to deliver a smaller volume. The target value is derived from the optimal reduction degree AG, which will be explained in more detail below.

[0057] The positive pressure in the pipeline is advantageously between 50 mbar and 100 bar, preferably between 100 mbar and 20 bar, more preferably between 100 mbar and 10 bar, more preferably between 100 mbar and 5 bar, more preferably between 100 mbar and 4 bar, other preferably between 100 mbar and 3 bar, preferably between 100 mbar and 2 bar, in particular between 100 mbar and 1 bar. The pipeline is advantageously a low-pressure or medium-pressure pipeline.

[0058] Advantageously, the hydrogen-containing natural gas stream has between 0.1% and 30% by volume of hydrogen, preferably between 0.5% and 10% by volume of hydrogen, more preferably between 0.5% and 5% by volume of hydrogen, even more preferably between 0.5% and 3% by volume of hydrogen, and especially between 1.0% and 2% by volume of hydrogen.

[0059] The energy consumption for hydrogen separation from a natural gas stream is determined by the hydrogen content in the natural gas mixture, the amount of water required for the EHS, and the pressure loss over the total distance between the withdrawal point and the point where the reduced hydrogen gas side stream is returned to the pipeline. The interaction of these three influences is complex, and without a meaningful indicator, erroneous conclusions can be reached. Therefore, an indicator called the reduction degree AG is introduced, with the help of which the lowest equipment complexity and energy consumption can be identified for any scenario. The optimal mass flow rate is then calculated from the optimal reduction degree.

[0060] The reduction rate AG is calculated by the moles of H2 reactant mass flow rate n present in the gas substream at the inlet of the membrane unit EHS in the following equation. TG,H2 , α and the desired molar H2 product flow rate (6)n H2,Pr It is defined as the ratio of

[0061] AG=n H2,Pr / n TG,H2 ,α

[0062] Those skilled in the art will be able to use the specified reduction to determine the preferred mass flow rate of the gas side stream and adjust it via the output of the compressor(s) in step (ii).

[0063] m TG,var ,α ,opt =(M PL / M H2 ) * (1 / AG var,opt ) * (1+1 / Y PL,H2 ,α) * m H2,Pr (1)

[0064] In order to set an optimized reduction rate, it is preferable to use two mass flow meters, preferably for measuring the hydrogen content and the mass flow rate in the gas side stream (2) and the permeate stream (6a).

[0065] If the hydrogen loading of the pipeline is less than 10% by volume, the optimized reduction is advantageously between 0.65 and 0.975, in particular between 0.85 and 0.975.

[0066] Preferably, when the pipeline hydrogen loading is less than 5% by volume, an optimized reduction factor of 0.75 to 0.975 is selected, more preferably an optimized reduction factor of 0.8 to 0.975, especially an optimized reduction factor of 0.85 to 0.975.

[0067] Preferably, when the pipeline hydrogen load is between 5% and less than 10% by volume, an optimized reduction factor of 0.65 to 0.95 is selected, more preferably an optimized reduction factor of 0.8 to 0.95, especially an optimized reduction factor of 0.825 to 0.925.

[0068] For pipeline hydrogen loadings between 10% and less than 20% by volume, the optimized reduction is advantageously between 0.55 and 0.925, more preferably between 0.7 and 0.9, in particular between 0.75 and 0.9.

[0069] Preferably, when the pipeline hydrogen loading is between 10% and less than 15% by volume, an optimized reduction factor of between 0.6 and 0.925, more preferably between 0.7 and 0.925, in particular between 0.8 and 0.9 is selected.

[0070] Preferably, when the pipeline hydrogen loading is between 15% and less than 20% by volume, an optimized reduction factor of between 0.55 and 0.9, more preferably between 0.7 and 0.9, in particular between 0.725 and 0.85 is selected.

[0071] Step (ii): This gas side stream is compressed using a pressure boosting device (e.g., a fan or compressor) to compensate for the pressure drop in the pipeline between the withdrawal station and the re-feed station along the gas side stream path and / or to create the pressure required for H membrane separation, preferably 50 mbar to 1 bar. The pressure drop between the withdrawal station and the re-feed station is typically 1 mbar to 5 bar, preferably 10 mbar to 2 bar, and in particular 50 mbar to 1 bar. This device for boosting pressure can, in principle, be located anywhere along the gas side stream path between the withdrawal station and the re-feed station; determining the optimal location is known to those skilled in the art. When the pressure drop is low, preferably in the range of 1 mbar to 10 mbar, the device for boosting pressure is advantageously located downstream of the membrane unit and upstream of the re-feed station in the flow direction of the gas side stream. When the pressure drop is high, preferably in the range of 1 bar to 5 bar, the device for boosting pressure is advantageously located between the withdrawal station and the membrane unit in the flow direction of the gas side stream.

[0072] In some cases, for example at the end of a pipeline path, it is advantageous to reduce the pressure of the pipeline flow (12), for example with the aid of a throttle or turbine.

[0073] Step (iii): In step (iii), the gaseous side stream is heated to a temperature of 100 to 250°C, preferably 100 to 200°C. Suitable devices for heating the gaseous side stream are known to those skilled in the art; advantageously, a gas-gas heat exchanger is used. It is preferable to heat the gaseous side stream (2) before adding water. In particular, it is particularly preferable to simultaneously heat the gaseous side stream (2) and cool the residue (8) in a gas-gas heat exchanger. It is preferable to cool the residue (8) before the drying step (9).

[0074] To moisten the gas side stream, it is preferable to add water to the gas side stream. Methods for supplying water are known to those skilled in the art. The amount of water required varies depending on the membrane technology and is known to those skilled in the art. In the case of an EHS, advantageously within a temperature range of 120 to 200°C, the preferred water loading is 0.005 to 0.2 mol H2O / mol natural gas, more preferably 0.005 to 0.1 mol H2O / mol natural gas, even more preferably 0.01 to 0.05 mol H2O / mol natural gas, even more preferably 0.015 to 0.035 mol H2O / mol natural gas, and especially 0.02 to 0.03 mol H2O / mol natural gas. This water addition can be carried out upstream of the membrane unit and / or on the permeate side of the membrane unit; in the case of an EHS, the cathode space is the permeate side. Addition of water upstream of the membrane unit is preferred.

[0075] Step (iv): In the membrane unit, hydrogen is separated from the gas stream, i.e., hydrogen is produced as permeate. Depending on the membrane unit used, the permeate may contain too much water for further use. In this case, it is advantageous to subject the permeate (7) to a drying treatment, for example, temperature swing adsorption (TSA), drying with adsorbents such as silica gel, CaO, superabsorbents, or glycol scrubbing. The operating conditions for TSA are known to those skilled in the art and are described, for example, at https: / / www.reicat.de / de / gastrocknung.html.

[0076] Advantageous applications for the use of separated hydrogen are hydrogen filling stations and distributed hydrogen users. Additionally, the method provides a hydrogen-free natural gas stream option for hydrogen-sensitive processes such as natural gas caverns, chemical processes, turbines, etc.

[0077] Membrane unit: A preferred membrane unit is an EHS that uses a phosphoric acid-doped membrane. The configuration for hydrogen separation is similar to that of a fuel cell. The core of the EHS system is a membrane electrode assembly (MEA). On the anode side, hydrogen molecules are catalytically oxidized to protons, which then migrate through a proton-selective membrane to the cathode side, while electrons migrate to the cathode through an external electric circuit. Thus, while an electric current is flowing, the EHS system separates hydrogen from the gas mixture. Electrochemical hydrogen separation techniques are described, for example, in WO 2016 / 50500 and WO 2010 / 115786.

[0078] The catalytically active material used may be any conventional compound or element known to those skilled in the art that catalyzes the dissociation of molecular hydrogen into atomic hydrogen, the oxidation of hydrogen to protons, and the reduction of protons to hydrogen. Suitable examples are Pd, Pt, Cu, Ni, Ru, Fe, Co, Cr, Mn, V, W, tungsten carbide, Mo, molybdenum carbide, Zr, Rh, Ru, Ag, Ir, Au, Re, Y, Nb, and alloys and mixtures thereof, with Pt being preferred according to the present invention. The catalytically active material may be present in a supported form, preferably on a carbon support. In a further development of the membrane electrode assembly, the amount of catalytically active material in the cathode catalyst is 0.1 mg / cm based on the total surface area of ​​the anode and cathode. 2 ~2.00mg / cm 2 , preferably 0.1 mg / cm 2 ~1mg / cm 2 is.

[0079] The membranes used according to the invention selectively conduct protons, i.e., in particular, are not electron-conductive. All materials known to those skilled in the art that can form proton-conductive membranes can be used according to the invention. It is also possible according to the invention to use selectively proton-conductive membranes, such as those known from fuel cell technology.

[0080] Materials particularly suitable for producing gas-tight, selectively proton-conducting membranes are polymeric membranes. Suitable polymers include sulfonated polyetheretherketone (S-PEEK), sulfonated polybenzimidazole (S-PBI), and sulfonated fluorinated hydrocarbon polymers (e.g., Nafion®). Porous materials such as polysulfonic acid, styrenic polymers, poly(arylene ether), polyimide, and polyphosphazene can also be used.

[0081] In particular, it is highly preferred to use membranes made of polybenzimidazole, in particular MEAs based on polybenzimidazole and phosphoric acid, such as those sold, for example, under the name Celtec-P® by BASF SE.

[0082] The operating conditions of an EHS system are highly dependent on the MEA selected: when using Celtec® technology, voltage is 0.1-0.4 V and current is 0.2-1 A / cm 2 The use of a pressure-sensitive electrochemical reactor is advantageous. The separation of H2 is based on electrochemistry, not differential pressure. Therefore, EHSs can advantageously operate at atmospheric pressure. Assuming there is no pressure difference between the anode and cathode, higher pressures are advantageous, resulting in higher separation rates.

[0083] The hydrogen separation rate is usually 60% to 99%, preferably 70% to 95%, and particularly 80% to 90%. The higher the separation rate, the higher the electrical energy required by the EHS.

[0084] The current density is advantageously between 0.1 and 1 A / cm 2 , preferably 0.2 to 0.7 A / cm 2 , especially 0.2~0.5A / cm 2 The voltage is advantageously between 1 and 1000 mV, preferably between 100 and 800 mV, in particular between 150 and 350 mV.

[0085] These electrochemical hydrogen separation systems are advantageously operated at temperatures between 120 and 200°C, preferably between 150 and 180°C, in particular between 160 and 175°C. The pressure is advantageously between 0.5 and 40 bar, preferably between 1 and 10 bar, in particular between 1 and 5 bar. The pressure difference between the anode side and the cathode side is advantageously less than 1 bar, preferably less than 0.5 bar.

[0086] This mode of operation allows for a high tolerance to gas impurities such as CO (3%) and H2S (15 ppm).

[0087] This relatively low temperature allows for relatively fast and material-saving start-up and shutdown, which is particularly advantageous for non-continuous operation in distributed systems with fluctuating hydrogen output, such as filling stations.

[0088] The active surface area of ​​the membrane electrode assembly is advantageously between 5 and 20,000 cm 2 , preferably 25 to 10,000 cm 2 , especially 150-1000cm 2 is within the range.

[0089] The thickness of the membrane electrode assembly is advantageously in the range of 250 to 1500 μm, preferably 600 to 1000 μm.

[0090] 1m 3 The hydrogen separation stack, consisting of end plates, bipolar plates, seals, and membrane electrode assemblies, has a structural volume of 100 to 200 Nm 3 / h of hydrogen and is therefore significantly smaller than systems with physical hydrogen separation.

[0091] Energy consumption depends on the gas composition and the selected separation rate, and is typically between 3 and 7 kWh / kgH2.

[0092] Because the electrochemical separation is based on a gas-tight, highly selective proton-conducting membrane, the purity of the hydrogen produced can be very high, typically greater than about 99.9%, preferably greater than 99.95%, and especially greater than 99.99%.

[0093] In particular, the following membrane electrode assembly specifications are preferred:

[0094] [Table 1]

[0095] PBI = Polybenzimidazole IV=intrinsic viscosity

[0096] Degree of decrease: The reduction rate AG is the molar H2 reactant mass flow rate n TG,H2 α and the desired molar H2 product flow rate (6)n H2,Pr It is defined as the ratio of: AG=n H2,Pr / n TG,H2 ,α

[0097] The optimum reduction in cost depends on the separation energy consumption required for each reduction.

[0098] The reduction rate AG is calculated by the following formula: H2,Pr, The molar fractional gas volume flow rate n extracted from the pipeline to separate TG Derive: n TG =(1 / AG) * (1+1 / Y PL,H2, α) * n H2,Pr

[0099] Load Y PL,H2, α is proportional to the H2 concentration in the natural gas pipeline and the gas sidestream n TG Hydrogen n before extraction PL,H2 Natural gas with n PL;EG It is defined as the molar loading by Y PL,H2,α =n PL,H2 / nPL;EG

[0100] The reduction is advantageously between 0.5 and 0.999, preferably between 0.7 and 0.99, and even more preferably between 0.80 and 0.99.

[0101] The term "loading" is known to those skilled in the art, in particular from the description of the composition of moist air (see pages 146 and 147 of https: / / www.thm.de / wi / images / user / Thielen-72 / Downloads / Energietechnik / Kapitel_8_-_feuchte_Luft.pdf). In the case of moist gases, the composition is typically based on the mass or moles of the dry gas, since these parameters of the dry gas remain constant in all physical processes.

[0102] Load Y PL,H2,α In the case of a two-substance mixture consisting of H2 and CH4, it can be converted to volume % using the following formula:

[0103] y PL,H2,α Volume % = n PL,H2 / (n PL;EG +n PL,H2 )=Y PL,H2,α / (1+Y PL,H2,α )

[0104] Given H2 load Y in the pipeline H2;Pl,α and the predetermined pressure p1 at the tapping point of the pipeline for the gas side stream, the pressure loss Δp resulting from the equipment conditions over the entire path of the gas side stream, and the established load Y of the dry gas side stream due to water vapor. TG,H2O;ω The optimal AG range for is within this range, and the specific energy consumption ta var is the minimum specific energy consumption ta var,min This 30% requirement corresponds to the typical approach that a competitor would have production costs at least 30% higher in operating a similar process.

[0105] For example, p1=1.5bar, Δp=0.1bar, Y TG,H2O;ω = 0.025, the next optimal AG range is the pipeline H2 load Y H2;Pl,α is found as a function of: Y H2;Pl,α =0.05: AG opt =0.57~0.99996;0.64~0.9997;0.73~0.997 Y H2;Pl,α =0.10: AG opt =0.48~0.9993;0.55~0.997;0.65~0.987 Y H2;Pl,α =0.20: AG opt =0.39~0.9958;0.46~0.988;0.55~0.965

[0106] For example, Y H2;Pl,α =0.10, p1=1.5bar, Y TG,H2O;ω = 0.025, the following optimum AG range is found as a function of the pressure drop Δp over the entire path of the gas side stream: Δp=0.1bar: AG opt =0.48~0.9993;0.55~0.997;0.65~0.987 Δp=1.0bar: AG opt =0.56~0.99992;0.63~0.9994;0.73~0.996 Δp=10.0bar: AG opt =0.66~0.99999;0.72~0.99998;0.81~0.9997

[0107] For example, Y H2;Pl,α = 0.1, p1 = 1.5 bar, Δp = 0.1 bar, the next optimal AG range is the H2O load Y TG,H2O;ω is found as a function of: YTG,H2O;ω =0.01: AG opt =0.35~0.995;0.41~0.986;0.50~0.959 Y TG,H2O;ω =0.10: AG opt =0.64~0.99999;0.71~0.99998;0.80~0.9995 Y TG,H2O;ω =0.20: AG opt =0.69~0.99999;0.76~0.99998;0.84~0.99997

[0108] Step (v): The residue from the membrane unit (8), i.e., the H2-depleted stream, is recycled to the natural gas stream (1). If the water content of the residue is too high for this recycling in the pipeline, it is advantageously dried before being introduced into the pipeline. Drying steps (9) are known to those skilled in the art; an advantageous example is gas scrubbing with ethylene glycol. Drying can provide an aqueous stream (11) that can be treated, for example, with the aid of distillation or membrane processes. The water stream (11) obtained from the step of drying the residue can advantageously be used for wetting the gas side stream (4) in step (iii).

[0109] Alternatively, the residue from the membrane unit (8) is sent to chemical utilization and / or used as fuel.

[0110] Many chemical processes and internal combustion engines can be run on almost pure natural gas alone. For example, in the process of producing benzene from natural gas, hydrogen must be separated from the reaction mixture to avoid a chemical equilibrium being reached and the reaction halting. Here, the hydrogen concentration must be reduced from 11% to less than 1%. A further example is a natural gas filling station that supplies natural gas to cars and buses, which can contain only less than 2% hydrogen. Therefore, hydrogen removal is absolutely necessary, given the 10% hydrogen addition limit, as currently permitted.

[0111] If appropriate, the residue is cooled before being introduced into the pipeline, advantageously from 100-260°C in the membrane unit to a dew point of -8°C at pipeline pressure. Suitable devices for cooling the gas side stream are known to those skilled in the art; advantageously, a gas-gas heat exchanger is used. Advantageously, such a gas-gas heat exchanger is used for simultaneously heating the gas side stream in step (iii) and cooling it in step (v).

[0112] How to determine the optimum partial gas volume flow rate The present invention further relates to a method for identifying an optimal gas side stream extracted from a pipeline transmitting natural gas and hydrogen, and separating hydrogen from this gas side stream in an electrochemical membrane unit, the optimal gas side stream resulting in the lowest separation cost.

[0113] Since only mass flow rate (mass / h) can be measured, the optimal gas sub-flow is determined as a mass flow rate. In contrast, molar flow rate (mol / h) is more suitable for describing molar processes, such as the transport of H2 through an EHS or the humidification of a gas stream. Converting moles to mass via molar mass is a common method for those skilled in the art.

[0114] Optimal gas sidestream mTG ,opt To calculate the optimal reduction, AG opt This is confirmed by iteration as follows: H2 product-specific variable separation energy consumption ta var In the following equation for ta var The value of the decrease rate AG is changed until the value of is minimized.

[0115] ta var =(1 / AG) * {K moist * [(Y TG,H2O ,ω-Y TG,H2O ,α) / Y PL,H2, α]+K comp * (1+1 / Y PL,H2, α)* ln[(p1+Δp) / p1)]}+K F * {U EHS,over +K U,min * ln[1+(1+Y TG,H2O, ω) / Y PL,H2, α / (1-AG)]}

[0116] where the following constants: K moist =13.78kW el / kgH2,K comp =0.49kW el / kg,K F =26.59Ah / kgH2,K U,min =0.019V and the following process parameters: U EHS,min =K U,min * ln(p cathode / (p anode * y TG,H2, ω), where p cathode = cathode pressure, p anode = anode pressure, and y TG,H2, ω = molar ratio of H2 at the outlet from the separation unit (8) It has.

[0117] Δp is the total pressure drop between the withdrawal station (15) and the resupply station (16) of the gas side stream from and to the pipeline.

[0118] Y TG,H2O , α is the molar loading of natural gas containing H2O in pipeline (1) Y TG,H2O , ω is the molar loading of natural gas containing H2O before entering the separation unit Y PL,H2 , α = Molar loading of natural gas containing H2 in pipeline (1) Optimal reduction AG opt The procedure for determining may advantageously be as follows: The procedure starts with AG=0.90 and the specific energy consumption ta var gives the value of

[0119] Then, the value of AG increases by 0.01 up to 0.91, and the corresponding specific energy consumption ta var is obtained. var If the new value of (AG=0.91) is smaller than the previous value (AG=0.9), then in the next step the new AG value is again increased by 0.01. var The new value of (AG alt+0.01) is the old value (AG alt ) and the old AG value is the next best decreasing AG var,opt Configure.

[0120] AG value 0.91 is higher than AG value 0.90 var If this results in a value of , then in the next step the value of AG is var Value of (AGalt -0.01 ) is increased by 0.01 each time until it rises again. Then, the old AG value is increased by the minimum specific energy consumption ta var,min The optimal reduction degree AG with var,opt Configure.

[0121] Characteristic value per capital cost (Σ(q i +p i ) is represented by ta var Since the value from the variation of AG tends to follow the progression of var is assumed to be the optimal value of

[0122] The economics of a process is revealed by the difference between the product price and the product cost. The product cost can be calculated from the manufacturing cost and the return on capital (ROI), which reflects the return requirement, capital interest, and tackle situation. If the product cost exceeds the product price, the process is uneconomical. Manufacturing costs consist of variable costs and fixed costs. In this case, the majority of the variable costs are energy costs. The energy costs here are the electricity costs and the t avar is the product of

[0123] Fixed costs depend, to a first approximation, on the cost of capital, which is then calculated as the product of S(qi+pi) and the associated specific cost of capital.

[0124] ROI is directly proportional to the cost of capital.

[0125] where qi is the total heat transfer power and pi is the total electrical power, in each case based on the H2 product mass flow rate mH2,Pr.

[0126] AG fluctuation / segregation var If the minimum value of is confirmed, the corresponding reduction degree AG is the optimal reduction degree AG opt Corresponding to AG opt Using this, the optimal gas sub-flow rate m TG,var ,α opt is calculated using the following formula: m TG,var, α ,opt =(M PL / M H2 ) * (1 / AG var , opt ) * (1+1 / Y PL,H2,α ) * m H2,Pr where: M PL = Molar mass of the hydrogen-natural gas mixture in pipeline (1) M H2 = Molar mass of hydrogen = 2.0159 g / mol m H2,Pr= desired mass flow rate of pure hydrogen (6a)

[0127] advantage: The advantages of the process are: (i) a one-step process; (ii) an efficient process, especially at low hydrogen concentrations, e.g., below 5 bar; (iii) a process that tolerates impurities in the feed gas stream; (iv) electrochemical separation in operation at atmospheric pressure; (v) a modular principle: capacity expansion by installation of further stacks; (vi) advantageous for relatively small amounts of gas.

[0128] An advantage of using this method is that the optimum gas side stream can be identified, although it will vary and not always be unity decreasing, for a wide range of hydrogen contents in the pipeline, a wide range of pipeline pressures, and a wide range of different electrochemical hydrogen separation technologies for the desired product stream. The optimum gas side stream will result in the lowest separation cost. FIG. 1 illustrates the process of the present invention where the product is high purity H2.

[0129] A gas side stream 2 is extracted at extraction point 15 from the pipelined H-containing natural gas stream 1 without changing the gas composition. This gas side stream is compressed in a pressure booster 3 (e.g., a fan or compressor) solely to compensate for the pressure drop along the gas side stream path or to increase the pressure required for H separation. This pressure booster can in principle be located anywhere along the gas side stream path. Those skilled in the art of chemical engineering will know the optimal location.

[0130] Water 4 is added to moisten the gas side stream 2. The amount of water required varies depending on the membrane technology. The membrane may also be supplied with water 4a to prevent it from drying out, or water 4a may be supplied only to the permeate side. In the case of an EHS, the cathode space is the permeate side.

[0131] In the H2 separation unit 5, H2 is separated from the gas side stream 2a. The membrane unit 5 is an electrochemical hydrogen separation, EHS, where the driving force for H2 transport is the natural logarithm of the potential ratio.

[0132] The residue is hydrogen 6a. According to the present technology, the residue may still be too wet for further use. Stream 6a is then advantageously subjected to a drying step 7, such as temperature swing adsorption, after which stream 6 becomes hydrogen on specification. The residue 8 in the case of EHS is the anode off-stream.

[0133] If this H2-depleted stream is too moist to be recycled into the pipeline at the re-feed point 16, it is advantageously subjected to drying 9 before being introduced. An example of a useful drying step is gas scrubbing with ethylene glycol, which provides an aqueous stream that can be treated with the aid of distillation or membrane processes. The water stream 11 obtained from the drying step can in principle be recycled again for the humidification of the gas side stream 2.

[0134] The dried H2-depleted gas stream 10 is then returned to the residual gas stream 12 in the pipeline network.

[0135] In certain cases, it may be more preferable to omit the machine 3 for pressurization in the gas side stream 2 and instead install a device (e.g., a throttle or turbine) for creating a pressure drop 14 in the gas stream 12. FIG. 2 illustrates the process of the present invention when the product is H2-free natural gas.

[0136] Some processes that consume natural gas require specifications regarding the hydrogen content of the natural gas (FIG. 2). In this case, the withdrawn gas side stream 2 is similarly compressed (3) and, if necessary, moistened (4) before being fed to a membrane unit (5). The residue stream (8) can then be further dried (9) if necessary. The dried residue stream (10) is then fed to the natural gas consuming process (17) rather than to a pipeline. An example of processing is shown in Figure 3.

[0137] 40 kg / h of ultra-high purity H2 (stream 7) is first separated from a pipeline carrying 29,050 kg / h of natural gas (stream 1), initially containing 10% H2 by volume, at 500 mbar positive pressure. Upstream of the site where the H2 is introduced into the natural gas pipeline network, the natural gas contains 0.2% water by volume, which corresponds to a dew point of -8°C at 1.5 bar absolute. The H2 is separated at atmospheric pressure with the help of an EHS operating at 160°C, which requires a water content of 2.5% by volume in gas stream 6 upstream of the EHS for reliable operation.

[0138] For simplicity, natural gas can be considered as pure methane. Furthermore, in the following, the subscript PL denotes the pipeline, the subscript α denotes the start, and the subscript ω denotes the end. Furthermore, the subscripts H2, H2O, and CH4 denote their respective components.

[0139] Figure 3 shows the H2 loading of natural gas in the pipeline, Y H2,PL,α However, the specific energy consumption ta var The separation unit here humidifies the gas side stream to 0.025 mol H2O / mol natural gas, and the total pressure drop over the path of the gas side stream is 0.1 bar.

[0140] It is clear that the optimal reduction factor AG is in the range of 0.80 to 0.95. opt is the specific energy consumption ta var The minimum value is the H2 load Y of natural gas in the pipeline. H2,Pl,α The higher the value, the better the reduction rate AG opt It can be seen that Y H2,Pl,α If =0.05, AG opt is 0.95, and Y H2,Pl,α =0.20, AG opt is 0.80.

[0141] Figure 4 shows the results of different H2O loadings Y of natural gas upstream of the separation unit. H2O;TG,ω The required wetting of the gas side stream for the specific energy consumption ta varGraph showing the effect of natural gas, in its original state, on the HO loading Y TG,H2O,α =Y PL,H2O,α = 0.00223 mol H2O / mol of natural gas. The H2 loading of the natural gas in the pipeline in this example, Y H2,PL,α is 0.10 mol H2 / mol of natural gas, and the total pressure drop on the gas sidestream path is 0.1 bar.

[0142] It can be seen that the optimum reduction factor AG is in the range of 0.70 to 0.97. Also, the lower the required wetting, the lower the optimum reduction factor AG. opt It can be seen that Y TG,H2O,ω If =0.010, AG opt is 0.70, and Y TG,H2O,ω If =0.200, AG opt is 0.97.

[0143] Figure 5 shows that the pressure drop in the entire path of the gas sidestream from the extraction station to the re-supply station to the pipeline is proportional to the specific energy consumption ta var In this example, the H2 loading of natural gas in the pipeline, Y H2,PL,α is 0.10 mol H2 / mol of natural gas, and the pipeline pressure p1 is 1.5 bar absolute abs Upstream of the separation unit, the gas side stream is wetted to 0.025 mol H2O / mol natural gas.

[0144] It can be seen that the optimum reduction rate AG is in the range of 0.85 to 0.97. In addition, the lower the pressure loss, the higher the optimum reduction rate AG. opt It is also clear that Δp=0.1bar, AG opt is 0.85, and when Δp=10.0 bar, AG opt is 0.97.

[0145] Figure 6 shows the H2 load of natural gas in the pipeline, Y H2,PL,α The figure shows the effect of on the separation energy consumption Σ(qi+pi). The capital cost of the entire plant is proportional to the separation energy consumption.

[0146] The separation unit in this example wets the gas side stream to 0.025 mol H2O / mol natural gas, with a total pressure drop in the gas side stream path of 0.1 bar.

[0147] It can be seen that the optimal reduction rate AG is in the range of 0.96 to 0.99. opt is where the separation energy consumption Σ(qi+pi) is at its lowest. Also, the H2 load of natural gas in the pipeline Y H2,Pl,α The higher the value, the better the reduction rate AG opt It can also be seen that Y H2,Pl,α If =0.05, AG opt is 0.99, Y H2,Pl,α =0.20, AG opt is 0.96.

[0148] Figure 7 shows the effect of the required wetting of the gas side stream on the separation energy consumption Σ(qi+pi) for different H2O loadings in the gas side stream upstream of the separation unit. In its original state, natural gas has an H2O loading Y TG,H2O,α =Y PL,H2O,α = 0.00223 mol H2O / mol of natural gas. The H2 loading of the natural gas in the pipeline in this example, Y H2,PL,α is 0.10 mol H2 / mol of natural gas, and the total pressure drop on the gas sidestream path is 0.1 bar.

[0149] It can be seen that the optimum reduction factor AG is in the range of 0.90 to 0.97. Also, the lower the required wetting, the lower the optimum reduction factor AG. opt It can also be seen that Y TG,H2O,ω If =0.010, AG opt is 0.97, and Y TG,H2O,ω If =0.200, AG opt becomes 0.90.

[0150] FIG. 8 shows the effect of pressure loss in the entire path of the gas side stream from the withdrawal station 15 to the re-supply point 16 to the pipeline on the separation energy consumption Σ(qi+pi).

[0151] The H2 load Y of the natural gas in this example pipeline H2,PL,α is 0.10 mol H2 / mole of natural gas and the pipeline pressure is 1.5 bar absolute abs Upstream of the separation unit, the gas side stream is wetted to 0.025 mol H2O / mol natural gas.

[0152] It can be seen that the optimum reduction rate AG is in the range of 0.97 to 0.99. In addition, the lower the pressure loss, the greater the optimum reduction rate AG. opt It is also clear that Δp=0.1bar, AG opt is 0.97, and when Δp=10.0 bar, AG opt is 0.99.

[0153] 1) Pipeline For a gas mixture flowing through a pipeline containing 10% by volume of hydrogen, the average molar mass M PL The molar flow rate of natural gas is calculated as 14.64 kg / kmol. PL,α The value of is derived.

[0154] n PLα =m PL,α / M PL =29050kg / h / 14.64kg / kmol=1984.2kmol / h (1.1)

[0155] The molar amount n of H2 present in the gas mixture stream 1 upstream of the withdrawal point PL,H2,α is as follows:

[0156] n PL,H2,α =y H2,α * n PL,α =1984.2 * 0.10 = 198.4 kmol / h (1.2)

[0157] The molar amount n of H2O present in the gas mixture stream 1 upstream of the withdrawal pointPL,H2O,α, is as follows:

[0158] n PL,H2O,α =y H2Oα * n PL,α =1984.2 * 0.002=3.97kmol / h (1.3)

[0159] The molar amount n of CH4 present in gas mixture stream 1 PL,CH4,α, is as follows:

[0160] n PL,CH4,α =n PL,α -n PL,H2,α -n PL,H2O,α =1984.2-198.4-3.97=1781.83kmol / h (1.4)

[0161] This leads to the following load Y based on the amount of CH4:

[0162] Y PL,H2,α =n PL,H2,α / n PL;CH4,α =198.4 / 1781.83=0.111 (1.5) Y PL,H2O,α =n PL,H2O,α / n PL,CH4,α =3.97 / 1781.83=0.00223 (1.6)

[0163] Desired H2 product flow rate n for filling station operation H2,Pr is as follows:

[0164] n H2,Pr =m H2;Pr / M H2 =40kg / h / 2kg / kmol=20kmol / h (1.7)

[0165] 2) The gas sidestream H2 is not separated directly from the gas mixture stream in the pipeline (1), but from a significantly smaller gas substream (2). The reduction AG is as follows: AG=(n TG,H2 ,α-n TG,H2 ,ω) / n TG,H2 ,α=n H2,Pr / n TG,H2 ,α=0.990 (2.1) where the amount of H2 present in the gas substream 2 at the inlet of the EHS, n TG,H2 , α, and the amount n remaining in the gas sub-stream 8 at the outlet from the EHS TG,H2 , ω, the total amount of partial gases n present in the gas substream 2 extracted from the pipeline flow TG, Directly correlated with alpha: n TG, α=(1 / AG) * (1+1 / Y PL,H2 ,α) * n H2,Pr =200 kmol / h (2.2)

[0166] Hereinafter, all loadings are based on the CH or its amount present in the gas substream 2, since this is kept constant in all process steps. This is because: load Y TG,H2 ,α=Y PL,H2 ,α=n TG,H2 ,α / n TG,CH4 ,α (2.3) and, by equation (2.1), n TG,CH4 ,α=n TG,CH4 ,ω=n TG,CH4 =n TG,H2 ,α / Y PL,H2 ,α=n H2,Pr / AG / Y PL,H2 ,α=180kmol / h (2.4) where: X=n H2,Pr / n PL,H2 ,α=0.100 (2.5)

[0167] 3) Increase in pressure To overcome the flow losses of the gas side stream from 2 to 12, it must be compressed. In the ideal case, this is done isothermally. In this case, to achieve the exemplary pressure rise Δp = 100 mbar, the compressor power P1 required for this purpose is: P1=m TG, α * (R * T PL / M PL / η comp ) * ln((p1+Δp) / p1)=12kW (3.1)

[0168] Gas side stream m TG, For α, after several reconstructions, we obtain the following relationship: m TG, α=m H2,Pr * (K M,TG, α / AG) * (1+1 / Y PL,H2, α) = 2934 kg / h (3.2)

[0169] where: K M,TG, α=M TG, α / M H2 =M PL / M H2 =7.26 (3.3) Specific compressor output p comp For, therefore, we have: p comp =P1 / m H2,Pr =K comp * (1 / AG) * (1+1 / YPL,H2, α) * ln((p1+Δp) / p1)=0.30kW el / kgH2(3.4) where: K comp =R * T PL / M H2 / η comp =0.49kW el / kgH2 (3.5) And the derived compressor efficiency η comp η comp =0.70 (3.6)

[0170] 4) Gas heating and cooling The isothermally compressed gas substream 3 is compressed at a pipeline temperature τ PL = 25℃ to that temperature τ EHS = 160 °C and then must be cooled again. For this purpose, the heat flow Q1 must be transferred by a heat exchanger.

[0171] cp TG According to the estimated value of cp TG =2.3kJ / kgK (4.1) Q1=m TG, α * cp TG * (τ EHS -τ PL )=253kW (4.2)

[0172] Before being introduced into the natural gas network, the gas sidestream must be dried again to a water content of 0.2 mol% for natural gas pipelines. In the case of drying with propylene glycol, a pressure of 1.5 bar absolute is required for this purpose. absolute According to the thermodynamic simulation, the gas side flow is τ drying= 21 °C. For this purpose, the heat flow Q2 must be transferred by a heat exchanger.

[0173] Q2=m TG, α * cp TG * (τ PL -τ drying )=8kW (4.3)

[0174] where: K HT,TG =cp TG * ((τ EHS -τ drying )=0.089kWh / kg (4.4)

[0175] Therefore, the product flow rate m H2,Pr The transferred heat flow, or heat transfer power of the gas sub-stream based on

[0176] q TG =(Q1+Q2) / m H2,Pr =K HT,TG * (K M,TG, α / AG) * (1+1 / Y PL,H2.α )=6.50kWh / kgH2(4.5)

[0177] 5) H2 separation by EHS According to Faraday's law, the H2 product flow rate n H2,Pr For electrochemical separation of flow rate 7, the following current I = 19.84 kmol / h is obtained: EHS is required: I EHS =2 * n H2,Pr * F=1063600A (5.1)

[0178] where: F=96485AS / mol (5.2)

[0179] Minimum voltage required for separation U EHS,min is calculated using the following formula: U EHS,min =K U,min * ln(p cathode / (p anode * y TG,H2, ω)=0.127V (5.3) where: K U,min =R * T EHS / 2 / F=0,019V (5.4) where the ideal gas constant R R=8.314J / molK (5.5) And the H2 partial pressure in the cathode space is p H2,cathode =1.013bar p H2,cathode =p cathode * y H2,cathode =1.013bar (5.6) where: y H2,cathode =1, and p anode =1.013bar (5.7)

[0180] For the required separation energy, the partial pressure p at the outlet of the EHS H2,anode is important, i.e., p H2,anode =p anode * y TG , H2 ω=0.0011 (5.8) YTG,H2O, According to equation (6.2) for ω, we get: Y TG,H2 ω=1 / (1+(1+Y TG,H2O ω) / Y PL,H2 α / (1-AG)=0.0011 (5.9)

[0181] However, in EHS, the conductive resistance R EHS,specific These are generated at a current density i EHS and the CO content in the gas mixture. The current density i EHS is usually 0.1 to 1 A / cm 2 The order is:

[0182] CO-free gas mixture and assumed current density i EHS i EHS =0.8A / cm 2 (5.10) In this case, the specific membrane resistance R EHS,specific For example, for CHS, is calculated as follows: R EHS,specific =98-20 * (i EHS 2 +i EHS )=69.2mΩ * cm 2 (5.11) Overvoltage component U of CHS EHS,over is calculated as follows: U EHS,over =R EHS,specific * i EHS =0.055V (5.12) This results in the total voltage U required to separate H2. EHS,tot is calculated: U EHS,tot =U EHS,min +U EHS,over =0.182V (5.13)

[0183] The power P2 required for the EHS is therefore given by the following formula:

[0184] P2=U EHS,tot * I EHS =194kW (5.14)

[0185] Or, power p based on H2 product mass flow rate EHS p EHS =P EHS / m H2,Pr =4.84kWh / kgH2(5.15)

[0186] 6) Wet / Dry The moisture content in the gas substream 6 upstream of the EHS, y TG,H2O, ω needs to be, for example, 2.5% by volume to prevent the membrane from drying out. To achieve that value, the water vapor flow Δn TG,H2O is added to the partial gas volume stream 6 via stream 5 .

[0187] Equation (1.6) and Y TG,H2O ,α=Y PL,H2O ,α = 0.00223 (6.1) and, Y TG,H2O, ω=(1+Y PL,H2 ,α / (1 / y TG,H2O ,ω-1)=0.0285 (6.2) Therefore, according to equation (2.4), we get the following: Δn TG,H2O =n TG,CH4 * (Y TG;H2O ,ω-Y TG,H2O ,α)=4.73 kmol H2O / h (6.3) Or, Δm TG,H2O =Δn TG,H2O * M ;H2O =85.1 kgH2O / h (6.4)

[0188] The amount of water vapor downstream of this additionally introduced EHS, Δm TG,H2O must be separated again from the gas sub-stream 8 to prevent condensation after the H2-depleted gas sub-stream 12 is returned to the pipeline.

[0189] According to the prior art, the gas side stream 9 is dried with the aid of a glycol scrub, which requires both steam and power for operation, the steam here being generated, for example, by the combustion of natural gas.

[0190] Thermodynamic simulations performed as an example (considering both the wetting of the gas side stream with water and the drying of the residue or anode off-gas downstream of the EHS with the help of a propylene glycol scrub) give the following specific consumptions:

[0191] For the generation of steam, the amount of steam introduced per kg is: K cal,H2O =2.29kWh CH4 / kgH2O (6.4) If this is provided by the combustion of CH4, then for each kg of water vapor introduced for this purpose, K CH4,H2O =0.165 kg CH4 / kg H2O (6.5). needs to be burned.

[0192] This is used to calculate the natural gas consumption per hour for wetting: m CH4,H2O =K CH4,H2O * m TG,H2O =14.0 kg CH4 / h (6.6)

[0193] This is fed to the steam generator via stream 22.

[0194] For glycol scrub operation, K el,H2O =0.97kWh el / kgH2O (6.7) of electrical energy is required for refrigeration in the cold box, which is used to calculate the power consumption for humidification P3: P3=K el,H2O * m TG,H2O =82kW el (6.8)

[0195] In total, due to the wetting and drying of the gas side streams, K HT,H2O =7.99kWh / kgH2O (6.9) This means that the total heat transfer output Q HT,H2O Used to calculate Q HT,H2O =Q3+Q4+Q5+Q6=K HT,H2O * m TG,H2O =681kW (6.10) K H2O = (M H2O / M H2 ) * [(Y TG,H2O ,ω-Y TG,H2O ,α) / Y PL,H2 ,α] * (1 / AG)=2.13 (6.11). A specific consumption value based on the product amount for natural gas demand is then determined by: h H2O =m CH4,H2O / m H2,Pr =K cal,H2O* K H2O =4.87 kg CH4 / kg H2(6.12) This is the power demand: p H2O =P3 / m H2,Pr =K el,H2O * K H2O =2.06kW el / kgH2(6.13) and heat transfer output: q H2O =Q HT,H2O / m H2,Pr =K HT,H2O * K H2O =17.0kW therm / kgH2(6.14) This is in response to the above.

[0196] 7) Separation energy consumption Total separated energy expenditure TA tot is the fluctuation component TA var and fixed component TA fix It consists of:

[0197] TA tot =TA var +TA fix (7.1)

[0198] The variable components based on the H2 product volume flow rate include all important operating media. ta var =TA var / m H2,Pr =h H2O * (1 / F el,Gas )+p comp +p EHS +p H2O (7.2).

[0199] In the formula, the electricity-gas coefficient F represents the ratio of electricity prices to natural gas prices. el,Gas For example, the value is as follows:

[0200] F el,Gas =4.0kW el / kW cal (7.3)

[0201] From this, the following can be deduced:

[0202] ta var =4.29 / 4.0+0.44+4.84+2.19=8,50kW el / kgH2O (7.4)

[0203] The general formula for determining the specific variable separation energy consumption of the H2 product is therefore:

[0204] ta var =(1 / AG) * [K moist * [(Y TG,H2O ,ω-Y TG,H2O ,α) / Y PL,H2 ,α]+K comp * (1+1 / Y PL,H2 ,α) * ln(p1+Δp) / p1)]+K F * {U EHS,over +K U,min * ln[1+(1+Y TG,H2O ,ω) / Y PL,H2 ,α / (1-AG)]} (7.5) where: K F =2 * F / M H2 / 3600=26.59Ah / kgH2(7.6) and K moist =(M H2O / M H2 ) * (K cal,H2O / F el,Gas +K el,H2O )=13.78kW el / kgH2(7.7) and p1 = pressure upstream of the compressor (7.8)

[0205] By varying AG for each parameter using equation (2.2), the optimum gas subvolume m that minimizes the specific variable separation energy consumption of the H2 product is obtained. TG ,α op is obtained.

[0206] m TG,var ,α opt =(M PL / M H2 ) * (1 / AG var , opt ) * (1+1 / Y PL,H2 ,α) * m H2,Pr (7.9)

[0207] Figures 3, 4 and 5 show, as an example, the dependence of the specific variable separation energy consumption of the H2 product on the reduction degree AG. The optimal separation level is always 0.80 <AG var,opt in the range of <0.99.

[0208] The fixed component of the required separation energy consumption based on the H2 product volumetric flow rate is derived from the capital cost. comp , the heat transfer power q for heating or cooling the gas substream TG , power p for wetting and drying the gas side stream H2O and q H2O , and the separation performance of EHS p EHS is proportional to.

[0209] Specific capital investment cost I spec is the sum of all expenditures Σ(p i +q i ) is proportional to Σ(p i +q i )=p comp +q TG +p H2O +q H2O +p EHS

[0210] Figures 6 to 8 show the sum Σ(p i +q i ) also has a minimum value. In other words, there is also an optimal gas side flow. The optimal separation level is always 0.90 <AG fix,opt in the range of <0.99.

[0211] m TG,fix,α,opt =(M PL / M H2 ) * (1 / AG fix , opt ) * (1+1 / Y PL,H2 ,α) * m H2,Pr

[0212] Optimal total reduction AG considering both variable and fixed components opt of the H2 loading of the natural gas flow in the pipeline, Y PL,H2 , α and the steam load Y of the gas sidestream before entering the separation unit. TG;H2O The complex dependence of the two main influencing parameters, ω, is given in Table 1 for several sampling points and shown in Figure 10 for the case where a pressure drop Δp of 0.1 bar occurs over the entire path of the gas section from the withdrawal station 15 to the resupply station 16.

[0213] Table 1:Y H2,PL , α and Y TG,H2O AG as a function of ω opt(Δp=0.1bar)

[0214] Table 2

Claims

1. A single-stage membrane process for electrochemically separating hydrogen from a natural gas stream in a membrane unit (5), comprising the following process steps: (i) a gas substream (2) is extracted from a natural gas stream in a pipeline (1) having a positive pressure in the range of 50 mbar (0.005 MPa) to 100 bar (10 MPa) without changing the gas composition, the mass flow rate of said gas substream (2) being adjusted according to the hydrogen content of the natural gas stream (1) so as to establish a depletion factor of 0.65 to 0.975 when the hydrogen concentration is less than 10% by volume, and a depletion factor of 0.55 to 0.925 when the hydrogen concentration is greater than 10% by mass, said depletion factor being such that the desired molar H ２ The molar H in the product stream (6) and the gas substream (2) at the inlet of the membrane unit (5) ２ a step, defined as the quotient of the reactant flow rate and the (ii) this gas substream (2) is compressed (3) upstream of said membrane unit (5); (iii) this gas side stream (2) is heated to 100-250°C upstream of said membrane unit (5) and is supplied with water (4) by feeding water to said gas side stream (2) so that the water loading of said gas side stream (2) is 0.005-0.2 moles of water / mole of natural gas either upstream of said membrane unit (5) and / or on the permeate side (4a) of said membrane unit; (iv) this gas sub-stream (2) is sent to the membrane unit (5) where hydrogen is separated as permeate (6a) at a temperature between 100 and 250°C; (v) the residue (8) from the membrane unit (5) is recycled to the natural gas stream in the pipeline (1), sent to chemical utilization, and / or used as fuel; and The membrane unit is an EHS (electrochemical hydrogen separation membrane) using a phosphoric acid-doped membrane, and the anode side of the EHS has a catalytically active material selected from Pd, Pt, Cu, Ni, Ru, Fe, Co, Cr, Mn, V, W, tungsten carbide, Mo, molybdenum carbide, Zr, Rh, Ru, Ag, Ir, Au, Re, Y, Nb, and alloys and mixtures thereof, and the operating conditions of the EHS are a voltage of 0.1 to 0.4 V and a current of 0.2 to 1 A / cm. ２ and a temperature of 120 to 200°C and a pressure of 0.5 to 40 bar; method.

2. 2. The method of claim 1, wherein the pipeline (1) has a positive pressure of between 100 mbar (0.01 MPa) and 10 bar (1 MPa).

3. 3. The method according to claim 1 or 2, wherein the pipeline (1) has a positive pressure of between 100 mbar (0.01 MPa) and 2 bar (0.2 MPa).

4. The method according to any one of claims 1 to 3, wherein the hydrogen content of the natural gas stream in the pipeline (1) is between 0.1% and 20% by volume.

5. The method according to any one of claims 1 to 4, wherein the hydrogen content of the natural gas stream in the pipeline (1) is between 0.5% and 5% by volume.

6. 6. The method according to any one of claims 1 to 5, wherein a polybenzimidazole membrane based on polybenzimidazole and phosphoric acid is used in the membrane unit (5).

7. 7. The method according to any one of claims 1 to 6, wherein the electrochemical separation step in the membrane unit (5) is carried out at a temperature of 120 to 200°C.

8. The water loading in step (iii) is 0.015 to 0.035 moles H ２ 8. The method of claim 1, wherein the molar ratio of the mixture to the natural gas is 0 / mole.

9. A method according to any one of the preceding claims, wherein a gas-gas heat exchanger simultaneously heats the gas sub-stream (2) and cools the residue (8).

10. The method according to any one of claims 1 to 9, wherein the residue is dried in a drying step (9).

11. 11. The method according to any one of claims 1 to 10, wherein the degree of reduction of the gas sub-stream (2) is ascertained using the following formula: m ＴＧ，ｖａｒ， α ，ｏｐｔ =(M ＰＬ / M Ｈ２ )*(1 / AGG ｖａｒ , ｏｐｔ )*(1+1 / Y ＰＬ，Ｈ２，α )*m Ｈ２，Ｐｒ where: M ＰＬ = Molar mass of the hydrogen-natural gas mixture in the pipeline (1) M Ｈ２ = Molar mass of hydrogen = 2.0159 g / mol AG ｖａｒ , ｏｐｔ = Optimal reduction in the molar amount of hydrogen in the gas substream (2) calculated by the following method Y ＰＬ，Ｈ２，α = Molar ratio of hydrogen in the hydrogen-natural gas mixture in pipeline (1) m Ｈ２，Ｐｒ = desired mass flow rate of pure hydrogen (6a) H ２ Product-specific variable separation energy consumption ta ｖａｒ In the following equation for ta ｖａｒ The value of the decrease rate AG is changed until the value of that ｖａｒ =(1 / AG)*{K ｍｏｉｓｔ *[(Y ＴＧ，Ｈ２Ｏ ,ω-Y ＴＧ，Ｈ２Ｏ ,a) / Y ＰＬ，Ｈ２， a]+K ｃｏｍｐ *(1+1 / Y) ＰＬ，Ｈ２， a) *ln [(p1+Δp) / p1)]}+K Ｆ *{U ＥＨＳ，ｏｖｅｒ +K Ｕ，ｍｉｎ *ln[1+(1+Y ＴＧ，Ｈ２Ｏ， oh) / Y ＰＬ，Ｈ２， a / (1-AG)]} The following constants: K ｍｏｉｓｔ =13.78kW ｅｌ / kgH ２ K ｃｏｍｐ =0.49kW ｅｌ / kg K Ｕ，ｍｉｎ =0.019V and the following process parameters: P1 = pipeline pressure Δp = total pressure drop between the withdrawal station (15) and the resupply station (16) of the gas substream (2) from and to the pipeline (1) U ＥＨＳ，ｏｖｅｒ =R ＥＨＳ，ｓｐｅｃｉｆｉｃ *i ＥＨＳ =0.055V Here, the conduction resistance R ＥＨＳ，ｓｐｅｃｉｆｉｃ and current density i ＥＨＳ p ａｎｏｄｅ = anode side pressure, and y ＴＧ，Ｈ２， ω = H at the outlet from the separation unit (8) ２ Molar ratio of Y ＴＧ，Ｈ２Ｏ , α = H in pipeline (1) ２ Molar Loading of Natural Gas Containing O Y ＴＧ，Ｈ２Ｏ , ω = H before entering the separation unit ２ Molar Loading of Natural Gas Containing O 10. A method comprising:

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