Process and facility to remove carbon dioxide from a methane and carbon dioxide containing gas stream

Abstract

The present invention provides a new process and facility to remove carbon dioxide from a methane and carbon dioxide containing gas stream. The new process is particular suitable to expand capacities of carbon dioxide removal plants using amine absorption technology. In addition, it allows to reduce methane emission and to increase methane yields significantly.

Description

[0001] Process and facility to remove carbon dioxide from a methane and carbon dioxide containing gas stream

[0002] Field of the invention

[0003] The present invention provides a new process and facility to remove carbon dioxide from a methane and carbon dioxide containing gas stream. The new process is particular suitable to expand capacities of carbon dioxide removal plants using amine absorption technology. In addition, it allows to reduce methane emission and to increase methane yields significantly.

[0004] Background of the invention

[0005] Many technologies are known to remove carbon dioxide from a methane and carbon dioxide containing gas stream. R.W. Baker, K. Lokhandwala, “Natural Gas Processing with Membranes: An Overview”, Ind. Eng. Chem. Res., 2008, 47, 2019 - 2121 , disclose that amine absorption as well as membrane separation can be used to remove CO2 from natural gas. While membrane plants would be preferred for high CO2-concentration gas streams and amine plants would be preferred for relatively low CO2- concentration gas streams, in principle, also the combination of membranes for bulk removal of the carbon dioxide from natural gas with amine units as polishing systems would offer a low-cost alternative to all-amine or all-membrane plants. According to the authors, this approach is limited to large plants where the overall savings in capital cost are large enough to offset the increased complexity of the plant, which now contains two separation processes. Figure 6 of this publication shows that a combination of membrane separation plus amine absorption would be the method of choice if the CO2 concentration in the raw gas is higher than 13 mol% and if the raw gas flow is higher than 8 MMscfd. As a typical example of a combination of membrane separation and amine absorption a two-stage membrane separation combined with an amine plant is shown in Figure 5. The plant according to Figure 5, however, requires high CPEX costs and causes significant methane losses since the first permeate stream comprising 20% methane is sent to vent. Beside of the economic disadvantages of the high methane losses, a plant according to Figure 5 of Baker and Lokhandwala does not fulfill todays strong environmental regulations requiring that methane losses must be reduced as much as possible.

[0006] In line with the teachings of Baker and Lokhandwala US 4,466,946 discloses a method for CO2 removal from high CO2 content hydrocarbon containing gas streams, wherein a hybrid process comprising membrane separation and amine absorption is used. The CO2 rich stream obtained from the membrane separation unit is sent to vent and thus, causes high methane losses. For example, the methane loss in the device according to Fig. 11 of US'946 via stream 1 12 is around 11 % of the methane contained in the raw gas.

[0007] Queiroz Fernandes Araujo, “Comparative analysis of separation of technologies for processing carbon dioxide rich natural gas in ultra-deep water oil fields”, Journal of Cleaner Production, 2017, 155, 13 - 22, discloses different methods for CO2 removal from high CO2 content hydrocarbon containing gas streams. , wherein a hybrid process comprising membrane separation and amine absorption is used Queiroz Fernandes Araujo refers to the Baker and Lokhandwala publication discussed above and provides similar results with similar disadvantages.

[0008] B.D. Behide et al., „Hybrid Process for the removal of acid gases from natural gas”, Journal of Membrane Sciences, 1998, 140, 27-49, discloses a hybrid process combining membrane separation and amine absorption to remove carbon dioxide from a carbon dioxide and methane containing gas stream. Also in line with the teachings of Baker and Lokhandwala, Behide et al. use the hybrid process for a CO2 rich raw gas stream comprising 25 mol % CO2. Also, analogue to the publications discussed before, the CO2 rich permeate stream of the membrane separation unit is sent to vent. This stream comprises significant amounts of methane. Thus, the process of Behide shows the same disadvantages as the processes discussed before.

[0009] Anderson Charles L. et al, “CASE STUDY: MEMBRANE CO2 REMOVAL FROM NATURAL GAS, GRISSIK GAS PLANT, SUMATRA, INDONESIA, published under https: / / catalysts.basf.com / files / pdf / Membrane-Protection_Medal-Article-Grissik.pdf, discloses a case study about one of the world’s largest membrane systems used for bulk removal of CO2 from natural gas at the Grissik gas processing plant in South Sumatra, Indonesia. The gas separation system operated at Grissik gas processing plant is a hybrid system comprising a single stage membrane separation unit to separate the raw gas into a methane enriched and a methane depleted stream. The methane enriched stream is further processed in an amine absorption unit to produce a methane enriched sales gas stream. The methane depleted stream obtained from the membrane separation unit is burned in a steam generator and the steam is used to regenerate the amine solution in the amine absorber. The case study described the problem that “at plant startup in 1998, actual levels of heavy hydrocarbons (C10+, aromatics and napthenes) were found to be higher than anticipated. This resulted in a sharp reduction in membrane capacity, declining to 20 - 30% of initial capacity within a month. During this time, and in order to maintain production capacity, membrane elements were being frequently replaced.” To solve this problem a TSA was installed up-stream of the membrane unit. Thus, Anderson et al provides a solution for treating raw gas streams with high contents of heavy hydrocarbons and high amounts of CO2 above 15% . Anderson, however, does not address the problem to optimize the operating profit and minimize CAPEX costs.

[0010] In recent years environmental regulations concerning allowed methane emissions became much more restrict. Facilities and processes with methane losses as those of the prior art processes described above will no longer be allowed to operate.

[0011] Therefore a strong need remains for efficient processes and facilities to remove carbon dioxide from a methane and carbon dioxide containing gas stream, in particular for gas streams having a CO2 content of less than or equal to 10 mol%.

[0012] Problem of the present invention, therefore, was to provide a new gas separation facility and a new process to separate methane from CO2, having the disadvantages of the prior art processes to a reduced degree respectively not having the disadvantages of the prior art processes. A specific problem of the invention was to provide a new gas separation facility and a new process being highly flexible and integrable in existing plants using amine absorption. It should be possible to increase capacities of amine absorption plants for low or even lowest costs, without having a negative impact on the methane emission of the plant.

[0013] The new gas separation facility should have optimized operating profit and minimized CAPEX costs.

[0014] Another specific problem of the invention was to provide a new gas separation facility and a new process being highly flexible regarding the raw gas used. Any kind of raw gas or even two different raw gases comprising methane and CO2 should be processable, independent from further components like water and H2S or higher hydrocarbons and independent from varying contents of such impurities in the raw gas stream.

[0015] Another specific problem of the invention was to provide a new gas separation facility and a new process being beneficial compared to the prior art processes in terms of methane emission and / or methane yield and / or operating costs and / or investment costs when separating raw gas streams having a CO2 content of less than or equal to 10 mol %.

[0016] In another specific problem of the invention a new gas separation facility should be provided allowing to produce a methane rich product gas stream fulfilling all actual pipeline specifications, in particular in terms of gas pressure and methane and CO2 content.

[0017] In another specific problem of the invention a new gas separation facility should be provided fulfilling strongest regulatory requirements regarding methane emission.

[0018] Further problems solved by the present invention but not described before, can be derived from the subsequent description, examples, figures and claims.

[0019] Summary of the invention

[0020] The inventor of the present invention has now surprisingly found that the problems described above, can be solved by using a facility according to claim 1 or a process according to claim 13 respectively by preferred facilities and processes as claimed in the dependent claims and described in the subsequent description, examples and figures.

[0021] In the facility and process of the invention a hybrid technology combining a single stage membrane separation unit and an amine unit is used to separate methane and carbon dioxide from a methane and carbon dioxide containing gas stream.

[0022] In the facility and process of the invention the permeate gas of the single stage membrane separation unit is used as fuel gas of a fuel gas system, which provides heat energy for the amine unit and optionally also electrical energy. In all prior art processes that combine a single or multi-stage membrane separation unit with an amine unit, the permeate gas of the single stage membrane unit or of the first membrane stage of a multi-stage membrane unit is sent to vent, i.e. is discharged to the atmosphere. The consequence is high methane losses and waste of valuable energy.

[0023] The facility and process of the invention comprise a raw gas pre-treatment step, up-stream of the membrane separation step, to separate impurities from one or two raw gas stream(s), which comprises CO2 and CH4. The inventive combination of pre-treatment and subsequent membrane separation allows to treat raw gases with different qualities and compositions and provides sufficiently high flexibility to adapt the process and facility to be used with different raw gas sources. For examples, if H2S is comprised in the raw gas, it can be separated from the raw gas in the pre-treatment step or in the membrane separation step or parts of the H2S can be separated in each of both steps.

[0024] The main product stream of the facility and process of the invention is the methane enriched gas stream obtained from the amine unit. The single stage membrane separation unit, however, also produces a methane enriched retentate gas stream. Said retentate stream may be withdrawn from the process or facility as 2ndmethane enriched product stream or can be used in the process or facility of the invention. For example, it can be combined with the main product gas stream obtained from the amine unit to obtain one single methane enriched product gas stream or it can be fed to the gas inlet of the amine unit or it can be used as supplement fuel gas in the fuel gas system. Combinations of these configurations are also possible. The facility and process of the invention, thus, provide high flexibility to significantly increase the methane yield and / or reduce the methane losses and / or to improve energy efficiency compared to prior art processes.

[0025] The process of the invention can be used effectively to separate raw gas streams with medium or low CO2 content. It is especially beneficial if the CO2 content in the raw gas is below or equal to 13 mol %, preferably below or equal to 10 mol %. In such cases the entire permeate stream of the single stage membrane separation unit can be fed to the fuel gas system where the methane is consumed. This reduced significantly the methane emission compared to prior art processes. Strict regulatory requirements for methane emission to the atmosphere can be met. A reduced methane emission simultaneously increases the methane yield.

[0026] Another benefit of the invention is that beside of the raw gas stream no further energy source for the fuel gas unit is needed respectively that the demand of external energy supply was significantly decreased, both leading to further economic benefits.

[0027] As mentioned before the facility and the process of the present invention allow to produce a methane rich product gas fulfilling all actual pipeline specifications, in particular specifications regarding gas pressure and a maximum CO2 content, which is typical below 3 vol % or even below 2 vol. % of CO2.

[0028] Further benefits of the facility and process of the invention compared to for example Baker / Lokhandwala publication cited above were achieved by using a single stage membrane separation unit instead of a two-stage membrane separation unit and by feeding the permeate stream of the single stage membrane separation unit to the fuel gas system. In addition to the benefits discussed above, these benefits are reduced invest costs and size of the plant. The inventive facility is compact and can easily be moved from one side to another if for example a gas field is exhausted or it can be used in off-shore plants where size and wight of the plant is decisive.

[0029] The inventive facility and process can easily be implemented in existing gas separation plants using amine absorption technology. As shown in the examples below, adding a single stage membrane separation unit to an amine plant increases the capacity of the plant as well as the methane yield and leads to economic benefits. All this is achieved without the need to expand the amine absorption device itself. While amine plants are more complex and require careful, well-monitored operating procedures so that unattended operation is generally less practical, the inventive concept allows to expand the capacities of amine separation plants with lower CAPEX and OPEX costs compared to an expansion of the amine separation unit.

[0030] The facility and process of the invention provides a high degree of flexibility. The single stage membrane separation unit can be arranged up-stream of the amine unit or in a by-pass stream of the amine unit or as a separate stream in the plant. This allows that the inventive concept can be used to debottleneck nearly all existing gas separation plants, separating methane and carbon dioxide by use of amine absorption.

[0031] Further advantages of the facility and the process of the invention are revealed in the subsequent description, examples, figures and claims.

[0032] Brief Description of the drawings

[0033] Figure 1 shows a facility according to the invention characterized in that the retentate gas of the single stage membrane separation unit (3) is fed to the amine unit (4), that a TEG unit is used as product gas dehydration unit (19) and that a heat transfer medium is used to transfer heat generated in the fuel gas system (5) to the amine unit (4) as well as to the dehydration unit (19), which is a TEG unit in Figure 1 .

[0034] Figure 2 shows a facility according to Figure 1 with two modifications. Modification 1 is that a first raw gas stream is divided such that one part is forwarded to the pretreatment unit (2) and another part is fed to the amine unit (4). The second modification is that the retentate stream of the single stage membrane separation unit (3) is combined with the dehydrated first product gas stream.

[0035] Figure 3 shows a facility according to Figure 2 with the modification that the retentate stream of the single stage membrane separation unit (3) is forwarded via retentate conduit (9) to a second product gas conduit (10) and then withdrawn from the facility.

[0036] Figure 4 shows an example of a combined amine unit (4) und TEG unit (19) as well as its connection to the fuel gas system (5).

[0037] Figure 5 shows a directly fired amine reboiler as example for an energy converting device (5a). Figure 6 shows a heating oil boiler as example for an energy converting device (5a).

[0038] Figure 7 shows a fuel gas system 5 where the heat energy is directly exposed to the user without heat transfer medium.

[0039] Detailed description

[0040] The present invention provides a facility for separating methane and carbon dioxide from a gas stream, the facility comprises a first raw gas conduit (1) or a first raw gas conduit (1) and a second raw gas conduit (1 a), a raw gas pretreatment unit (2), comprising a raw gas inlet (2a) and a pretreated gas outlet (2b), that generates a pretreated gas stream, a single stage membrane separation unit (3), comprising a gas separation membrane having higher permeance for carbon dioxide than for methane and generating a retentate gas stream, which compared to the pretreated gas stream is enriched in methane, and a permeate stream, which compared to the pretreated gas stream is enriched in CO2, a gas inlet (3a) for the pretreated gas, a retentate gas outlet (3b) and a permeate gas outlet (3c), an amine unit (4), generating a methane rich gas stream, which is enriched in methane compared to the feed gas of the amine unit (4), preferably by use of a carbon dioxide absorbing unit (20), and generating a carbon dioxide rich gas stream, which is enriched in CO2 compared to the feed gas of the amine unit (4), preferably by use of carbon dioxide desorbing unit (21), the amine unit (4) further comprising a gas inlet (4a) for a gas comprising methane and carbon dioxide, a methane gas outlet (4b) for the methane rich gas stream and a CO2 gas outlet (4c) for the carbon dioxide rich gas stream; a fuel gas system (5) comprising an energy converting device (5a), converting energy of one or more gas(es) fed to the fuel gas system into heat energy or electrical energy or heat energy and electrical energy, and comprising a gas inlet (5b) for the gas(es) be converted by the energy converting device (5a), a first product gas conduit (6) connected to the methane gas outlet (4b) of the amine unit (4), preferably connecting the methane gas outlet (4b) of the amine unit (4) with a gas pipeline or a gas storage unit or a further processing device, and the facility is characterized in that it further comprises a pretreatment feed conduit (7), connecting the first raw gas conduit (1) and / or the second raw gas conduit (1 a) to the raw gas inlet (2a) of the raw gas pretreatment unit (2), a pretreated gas conduit (8), connecting the pretreated gas outlet (2b) of the raw gas pretreatment unit (2) to the gas inlet (3a) of the single stage membrane separation unit (3), a retentate conduit (9) connecting the retentate gas outlet (3b) of the single stage membrane separation unit (3) to the gas inlet (4a) of the amine unit (4) and / or the first product gas conduit (6) and / or a second product gas conduit (10), which is not connected to the first product gas conduit (6), and / or a second product fuel gas conduit (38), connecting the second product gas conduit (10) or the retentate gas conduit (9) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5), with the proviso that the facility further comprises an amine unit feed conduit (11), connecting the raw gas conduit (1) to the gas inlet (4a) of the amine unit (4), if the retentate conduit (9) is not connected to the gas inlet (4a) of the amine unit (4), a permeate conduit (12) connecting the permeate gas outlet (3c) of the single stage membrane separation unit (3) to the gas inlet (5b) of the fuel gas system (5); it is further characterized in that the amine unit (4) further comprises an inlet for a hot heat transfer medium (4d), and the fuel gas system further comprises an outlet for hot heat transfer medium (5c), and the facility further comprises a hot heat transfer medium conduit (13a) connecting the outlet for hot heat transfer medium (5c) of the fuel gas system (5) to the inlet for the hot heat transfer medium (4d) of the amine unit (4), and characterized that part of or the entire energy, needed to meet the energy needs, preferably the at least entire heat energy demand, of the amine unit (4) is provided by the fuel gas system (5) via the hot heat transfer medium conduit (13a), and that the pure gas permeance for CO2 under reference conditions of the membranes used in the single stage membrane separation unit (3) is in a range of from 10 to 500 GPU, preferably 12 to 400 GPU, more preferred 14 to 350 GPU, even more preferred 20 to 300 GPU, particular preferred 20 to 220 GPU and most preferred 20 to 150 GPU.

[0041] The facility and the process of the invention can be used to treat raw gases comprising methane and carbon dioxide, with different and / or varying compositions, impurity contents and pressures. Preferably they are used to separate natural gas or biogas, even more preferred natural gas with a medium or low CO2 content. Most preferred the first and / or second raw gas stream comprises from 1 to 30 % by volume, preferably 1 to 15 % by volume, more preferred 2 to 13 % by volume, even more preferred 3 to 10 % by volume and most preferred 4 to 9 % by volume carbon dioxide and having a combined content of methane and carbon dioxide of at least 50 % by volume, preferably 60 to 98 % by volume, more preferred 85 to 98 % by volume and most preferred 90 to 98 % by volume. The first raw gas stream is fed into the facility respectively process via the first raw gas conduit (1) and the second raw gas stream is fed into the facility respectively process via the second gas conduit (1a). In each case % by volume defined before refers to the total volume of the raw gas stream. The remaining components of the raw gas stream, up-to 100% of the raw gas composition, are preferably selected from the group consisting of nitrogen, hydrocarbons with more than 2 carbon atoms, water, noble gases, H2S and further sulfur components, e.g. mercaptans, carbonyl sulfide, or mixtures thereof. The first and the second raw gas streams me be generated in one and the same raw gas source or in different raw gas sources.

[0042] The facility of the invention respectively used in the process of the invention comprises a raw gas pretreatment unit (2). The pre-treatment contributes to ensure a good performance of the membrane system. Preferably the pre-treatment unit (2) comprises one or more devices selected from the group consisting of

[0043] - a device to separate impurities comprised in the raw gas stream and that are liquid at or below room temperature or that can be liquified at or below room temperature, from the raw gas stream. Preferred examples for such devices are inlet coalescer and inlet separator. Preferred examples for such liquid or liquifiable impurities are H2O and higher hydrocarbons, preferably hydrocarbons with more than 3, preferably 6 to 10 carbon atoms,

[0044] - a guard bed, i.e. a bed of activated carbon to remove impurities like H2S and higher other sulfur components via adsorption or a bed of silica gel to remove higher hydrocarbons,

[0045] - a particle filter to remove solid particles from the raw gas stream, and

[0046] - a heat exchanger to adjust the temperature of the gas stream to be separated in the membrane separation unit to avoid liquid condensation in the membrane.

[0047] As will be explained in more detail further below, the retentate stream of the single stage membrane separation unit (3) is preferably used as feed stream of the amine unit (4) or can be mixed with the raw gas stream followed by use of the combined streams as feed stream of the amine unit (4). In these preferred configurations it is preferred that the pre-treatment unit (2) separates higher, i.e. >Cs hydrocarbons from the raw gas stream. This contributes to avoid or at least reduce potential foaming problems in the amine unit (4).

[0048] Generally the pre-treatment unit (2) comprises a raw gas inlet (2a), which is connected via the pretreatment feed gas conduit (7) to the first raw gas conduit (1) and / or to the second raw gas conduit (1a), and a pretreated gas outlet (2b) which is connected via the pretreated gas conduit (8) to the gas inlet (3a) of the single stage membrane separation unit (3). Pretreatment unit (2) is supplied with raw a gas and the pretreated gas stream is forwarded to the single stage membrane separation unit (3).

[0049] The facility of the invention respectively the facility used in the process of the invention comprises a single stage membrane separation unit (3). “Single stage” membrane separation unit is to be understood in the context of the present invention as a membrane separation unit providing one single permeate stream at the permeate gas outlet (3c) and one single retentate stream at the retentate gas outlet (3b) of the single stage membrane separation unit (3).

[0050] The single stage membrane separation unit (3) preferably consists of one or more membrane modules and / or pressure housings, each comprising one or more membrane cartridges.

[0051] In a first particular preferred embodiment two or more membrane modules and / or pressure housings, each comprising one or more membrane cartridges, are connected within the single-stage membrane separation unit (3) in series such that the retentate gas of an up-stream module or pressure housing is used as feed gas of the subsequent downstream module or pressure housing and all permeate streams of all modules and pressure housings are combined to one permeate stream. Thus, one single permeate stream and one single retentate stream, which is the retentate stream of the last module in the series, are obtained. When the single-stage membrane separation unit (3) comprises pressure housings with more than one membrane cartridge arranged in series, removable membrane cartridges arranged in series as a chain of cartridges in a common pressure vessel and connected to each other by a central permeate collecting tube are preferably used. Preferred pressure housings and membrane cartridges are disclosed in detail in WO 2016 / 198450 A1 which is entirely included by reference to this description.

[0052] In a second particular preferred embodiment two or more membrane modules and / or pressure housings, each comprising one or more membrane cartridges, are arranged in parallel within the single stage membrane separation unit (3) and the pretreated gas stream provided by the pretreatment unit (2) is split of and a portion of the pretreated gas stream is supplied to each membrane module respectively pressure housing. Thereafter all retentate streams of the membrane modules and / or pressure housings are combined to one single retentate stream and all permeate streams of the membrane modules and / or pressure housings are combined to one single permeate stream.

[0053] As mentioned before, instead of modules membrane cartridges can be used. Membrane cartridges differ from modules in that they are inserted into a pressure resistant housing, which is an integral part of the facility. In contrast thereto modules comprise the pressure resistant housing as an integral part of the module, i.e. the pressure resistant housing need to exchanges, too, if the module is exchanged. Exchange of cartridges is cheaper than exchange of modules since the pressure resistant housing does not have to be exchanged.

[0054] The single stage membrane separation unit (3) comprises gas separation membranes having higher permeance for carbon dioxide than for methane and generating a retentate gas stream, which compared to the pretreated gas stream is enriched in methane and a permeate stream, which compared to the pretreated gas stream is enriched in CO2, as well as a gas inlet (3a), a retentate gas outlet (3b) and a permeate gas outlet (3c). The term “permeate” here refers to a gas stream comprising the gas components of the pretreated gas stream fed to the single stage membrane separation unit (3) which have passed the gas separation membrane due to the difference in partial pressure across the membrane. The term “retentate” refers to the gas stream which remains after the gas components have passed the gas separation membrane at the high pressure side of the membrane. Since the gas separation membrane has higher permeance for carbon dioxide than for methane, the permeate will have a higher molar ratio of carbon dioxide to methane than the raw gas stream and / or pretreated gas stream, i.e. it will be enriched in carbon dioxide compared to those streams, and the retentate will have a higher molar ratio of methane to carbon dioxide than the raw gas stream and / or pretreated gas stream, i.e. it will be enriched in methane compared to those streams.

[0055] In general, membranes containing a separation layer of a glassy polymer, i.e. a polymer having a glass transition point at a temperature above the operating temperature of the membrane separation stage, will provide higher permeability for carbon dioxide than for methane. The glassy polymer may be a polyetherimide, a polycarbonate, a polyamide, a polybenzoxazole, a polybenzimidazole, a polysulfone or a polyimide and the gas separation membrane preferably comprises at least 80 % by weight of a polyimide or a mixture of polyimides.

[0056] In a preferred embodiment, the gas separation membrane comprises at least 50 % by weight of a polyimide prepared by reacting a dianhydride selected from 3,4,3’,4’-benzophenonetetracarboxylic dianhydride, 1 ,2,4,5-benzenetetracarboxylic dianhydride, 3,4,3’,4’-biphenyltetracarboxylic dianhydride, oxydiphthalic dianhydride, sulphonyldiphthalic dianhydride, 1 ,1 ,1 ,3,3,3-hexafluoro- 2,2-propylidenediphthalic dianhydride and mixtures thereof with a diisocyanate selected from 2,4-tolylene diisocyanate, 2,6-tolylene diisocyanate, 4,4’-methylenediphenyl diisocyanate, 2,4,6-trimethyl-1 ,3- phenylene diisocyanate, 2,3,5,6-tetramethyl-1 ,4-phenylene diisocyanate and mixtures thereof. The dianhydride is preferably 3,4,3’,4’-benzophenonetetracarboxylic dianhydride or a mixture of 3,4,3’,4’-benzophenonetetracarboxylic dianhydride and 1 ,2,4,5-benzenetetracarboxylic dianhydride. The diisocyanate is preferably a mixture of 2,4-tolylene diisocyanate and 2,6-tolylene diisocyanate or a mixture of 2,4-tolylene diisocyanate, 2,6-tolylene diisocyanate and 4,4’-methylenediphenyl diisocyanate. Suitable polyimides of this type are commercially available from Evonik Fibres GmbH under the trade name P84® type 70, which has CAS number 9046-51-9 and is a polyimide prepared from 3, 4,3’, 4’- benzophenonetetracarboxylic dianhydride and a mixture of 64 mol% 2,4-tolylene diisocyanate, 16 mol% 2,6-tolylene diisocyanate and 20 mol% 4,4’-methylenediphenyl diisocyanate, and under the trade name P84® HT, which has CAS number 134119-41-8 and is a polyimide prepared from a mixture of 60 mol% 3,4,3’,4’-benzophenonetetracarboxylic dianhydride and 40 mol% 1 ,2,4,5-benzenetetracarboxylic dianhydride and a mixture of 80 mol% 2,4-tolylene diisocyanate and 20 mol% 2,6-tolylene diisocyanate. The gas separation membranes of this embodiment have preferably been heat treated in an inert atmosphere as described in WO 2014 / 202324 A1 to improve their long-term stability in the process of the invention.

[0057] In another preferred embodiment, the gas separation membrane comprises at least 50 % by weight of a block copolyimide as described in WO 2015 / 091122 on page 6, line 20 to page 16, line 4. The block copolyimide preferably comprises at least 90 % by weight of polyimide blocks having a block length of from 5 to 1000, preferably from 5 to 200.

[0058] The gas separation membrane may be a flat membrane or a hollow fiber membrane and is preferably an asymmetrical hollow fiber membrane comprising a dense polyimide layer on a porous support. The term “dense layer” here refers to a layer which comprises essentially no macropores extending through the layer and the term “porous support” here refers to a support material having macropores extending through the support. The asymmetrical hollow fiber membrane can be prepared by coating a porous hollow fiber with a polyimide to form a dense polyimide layer on the support. In a preferred embodiment, the asymmetrical hollow fiber membrane is a membrane prepared in a phase inversion process by spinning with an annular two component spinning nozzle, passing a solution of a polyimide through the annular opening and a liquid containing a non-solvent for the polyimide through the central opening.

[0059] The gas separation membrane preferably comprises a dense separation layer of a glassy polymer coated with a dense layer of a rubbery polymer which rubbery polymer has higher gas permeability than the glassy polymer. The preferred gas separation membranes comprising a polyimide separation layer are preferably coated with a polydimethylsiloxane elastomer.

[0060] The membranes used in the process and apparatus of the present invention are characterized by a pure gas permeance for CO2 under reference conditions of the membranes used in the single stage membrane separation unit (3) of 10 to 500 GPU, preferably 12 to 400 GPU, more preferred 14 to 350 GPU, even more preferred 20 to 300 GPU, particular preferred 20 to 220 GPU and most preferred 20 to 150 GPU. Permeance is defined as gas flow per time unit, area and differential pressure through a membrane and is usually determined in gas permeation units (GPU, 10'6cm3cm-2S'1cm(Hg)-1) based on volume flow. Permeance P in GPU for a particular membrane and gas component is determined from permeation experiments with the pure gas as P = 106*Q / (RT*Ap) with Q being the normalized gas flow through the membrane in cm3 / s at standard conditions, R being the gas constant, T being the temperature and Ap being the pressure difference across the membrane in cm(Hg). “Pure gas permeance for CO2 under reference conditions” means in the present invention that the permeance for pure CO2 is measured at T = 25 °C, 6 barg feed pressure and 0 barg permeate pressure. “Pure gas permeance for CP under reference conditions” means in the present invention that the permeance for pure CH4 is measured at T = 25 °C, 6 barg feed pressure and 0 barg permeate pressure.

[0061] As will be shown in Example 2 below, use of membranes with sufficient pure gas permeance for CO2 allows to reduce the number of membrane modules in the single stage membrane separation unit and as consequence to optimize the CAPEX costs for the membranes. If the CAPEX for the membranes becomes too high, the depreciations for the membranes might overcompensate potential benefits in operating costs caused by the membrane separation unit such that in sum, the accumulated profit for an capacity increase of an existing amine unit with an inventive single stage membrane separation unit (inventive amine + membrane solution) is lower than that of a capacity increase of an existing amine unit with an additional amine unit (non-inventive amine + amine solution). If on the other hand the pure gas permeance for CO2 of the membranes is sufficiently high, the required CAPEX for the membranes in the inventive amine + membrane solution is so much lower than the required CAPEX for an additional amine unit in the non-inventive amine + amine solution, that even if the operating costs of the amine + membrane unit are higher than the operating costs of an amine + amine solution, this would be overcompensated by the lower depreciation for the membrane unit compared to that of the additional amine unit. As consequence and as shown in Example 2 below, accumulated profit is higher for the inventive amine + membrane solution compared to the amine + amine solution.

[0062] As will be further shown in Example 2 below, the highest economical benefit can be achieved if a membrane with a pure gas permeance for CO2 as defined before are used, which have a high selectivity. Below presented Example 2, Cases 1 and 3 show that use of membranes having high pure gas permeance for CO2 and high selectivity for CO2 / CP leads to higher accumulated profits than use of membranes with the same pure gas permeance for CO2 but lower selectivity for CO2 / CPU. It is thus, preferred that the membranes used in the single stage membrane separating unit (3), in particular in step e) of the process of the invention, having a pure gas selectivity S for CO2 / CPU of 5 to 50, preferably 7 to 40, more preferred 7 to 30 at 25 to 60°C,

[0063] Pure gas selectivity S of a membrane for the first gas component over the second gas component is defined as S = P1 / P2 with Pi being the permeance for the first gas component and P2 being the permeance for the second gas component. Permeances are measured as described before.

[0064] A good pure gas permeance for CPU of the membranes may also contribute to increase the economic benefits of the inventive process and apparatus. It is thus, preferred that the membranes used in the single stage membrane separating unit (3), in particular in step e) of the process of the invention, having a pure gas permeance for CF under reference conditions of the membranes used in the single stage membrane separation unit (3) of 0.15 to 6.5 GPU, more preferred 0.2 to 4.5 GPU, even preferred of 0.25 to 4.5 GPU, particular preferred of 0.4 to 4 GPU and most preferred of 0.8 to 3.5 GPU

[0065] The retentate stream of the single stage membrane separation unit (3) can be used differently.

[0066] In a first preferred embodiment the retentate stream of the single stage membrane separation unit (3) is forwarded to the amine unit (4). Figure 1 shows a facility according to this first preferred embodiment. The facility comprises a pretreatment unit (2), a single stage membrane separation unit (3), an amine unit (4), a fuel gas system (5) and a product gas dehydration unit (19). The first raw gas stream comprising methane and CO2 is supplied to a raw gas conduit (1) and forwarded via a pretreatment feed conduit (7) to the pretreatment unit (2). The pretreated gas stream is forwarded via a pretreated gas conduit (8) to the single stage membrane separation unit (3), where it is separated to generate a retentate stream, enriched in methane compared to the first raw gas stream, and a permeate stream, enriched in carbon dioxide compared to the first raw gas stream. The retentate stream is forwarded via retentate conduit (9) to the amine unit (4), where it is separated to generate a methane rich product gas stream, which is enriched in methane compared to the retentate gas stream and a carbon dioxide rich gas stream, which is enriched in CO2 compared to the retentate gas stream. The methane rich product gas stream generated in the amine unit (4) is discharged from the facility via first product gas conduit (6) after having been dried in the product gas dehydration unit (19), which is arranged in the first product gas conduit (6). In the example according to Figure 1 a TEG unit is used as product dehydration unit (19). The CO2 enriched gas stream generated in the amine unit (4) is withdrawn from the facility via a CO2 stream conduit (14).

[0067] The permeate stream of the single stage membrane separation unit (3) is forwarded via a permeate conduit (12) to a fuel gas system (5), where it is converted to heat energy, which is used in the amine unit (4) and the dehydration unit (19) and optionally electrical energy. In the example according to Figure 1 a heat transfer medium is used to transfer the heat generated in the fuel gas system (5) to the amine unit (4) and the dehydration unit (19) via a hot heat transfer medium conduit (13a). In the embodiment according to Figure 1 the heat transfer medium is not recirculated to the fuel gas system. It is, however, also possible and preferred that the facility comprises a cold heat transfer medium conduit(s) (13b) (not shown in the Figure) to recirculate the cold heat transfer medium obtained after heat transfer in the unit (4) and the dehydration unit (19) back from the amine unit (4) to the fuel gas system (13) and / or from the dehydration unit (19) to the fuel gas system (5).

[0068] In a second preferred embodiment the retentate stream of the single stage membrane separation unit (3) is combined with the methane enriched product gas stream of the amine unit (4). Figure 2 shows a facility according to this second preferred embodiment. Compared to the facility in Figure 1 the facility of Figure 2 has been modified as follows: Modification 1 is that the first raw gas stream is divided. One part of the first raw gas stream is forwarded to the pretreatment unit (2) as described for Figure 1 before. Another part is forwarded from the first raw gas conduit (1) via an amine unit feed conduit (11) to the amine unit (4). The second modification is that the retentate stream of the single stage membrane separation unit (3) is combined with the dried first product gas stream by connecting the retentate conduit (9) with the first product gas conduit (6), downstream of the product gas dehydration unit (19). The embodiment according to Figure 2 is beneficial compared to the embodiment of Figure 1 because it allows to treat a higher volume of raw gas without increase of the capacity of the amine unit (4). This is because part of the raw gas does not have to pass the amine unit (4). For the embodiment according to Figure 2 it is preferred that the methane content of the retentate stream of the single stage membrane separation unit (3) is enriched to a degree that allows to fulfill the final product gas specification after mixing the retentate gas with the first product gas. The amount of retentate stream single stage membrane separation unit (3) that can be mixed with the methane rich gas stream generated in the amine unit (4) is controlled based on the methane contents of both streams to meet the methane content specification of the final methane product stream.

[0069] In a third preferred embodiment the retentate stream of the single stage membrane separation unit (3) is withdrawn from the facility as an independent second product gas stream. Figure 3 shows a facility according to this embodiment. Compared to the facility of Figure 2, the following modifications have been made in the facility according to Figure 3: Analogue to Figure 2 one part of the first raw gas stream is forwarded to the pretreatment unit (2) and the remaining part is forwarded to the amine unit (4). The retentate stream of the single stage membrane separation unit (3) is forwarded via retentate conduit (9) to a second product gas conduit (10) and then withdrawn from the facility. This embodiment has similar benefits in terms of capacity to treat raw gas as the alternative in Figure 2. The withdrawal of two different methane product gas streams, however, has the additional benefit that the methane contents of both streams can be adjusted independently, depending on the intended use of the respective methane product gas stream.

[0070] In a fourth preferred embodiment (not shown in the figures) the retentate stream of the single stage membrane separation unit (3) is forwarded to the amine unit (4) together with parts of the raw gas. This embodiment is a hybrid of the embodiments shown in Figures 1 and 2. Analogue to Figure 2 the raw gas stream is divided. One part is forwarded to the pretreatment unit (2) as described for Figures 1 and 2. The second part is forwarded from the raw gas conduit (1) via an amine unit feed conduit (11) to the amine unit (4) as in Figure 2. The retentate stream of the single stage membrane separation unit (3) is fed to the amine unit (4) either directly or by premixing with the second part of the raw gas stream in amine unit feed conduit (11). It is preferred in this embodiment to connect the retentate conduit (9) with the amine unit feed conduit (11) or with the gas inlet of the amine unit (4a).

[0071] In a fifth preferred embodiment part of the retentate stream of the single stage membrane separation unit (3) is forwarded to the fuel gas system (5) to supplement fuel gas demand that cannot be provided by the permeate stream of the single stage membrane separation unit (3). It is preferred for this embodiment that a second product fuel gas conduit (38), connects the second product gas conduit (10) or the retentate gas conduit (9) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5).

[0072] In a sixth preferred embodiment (not shown in the figures) the second preferred embodiment is modified in that a second raw gas stream is used. Compared to the facility in Figure 2 the facility has been modified as follows: the entire first raw gas stream is forwarded from the first raw gas conduit (1) via an amine unit feed conduit (11) to the amine unit (4) and a second raw gas stream is forwarded via a second raw gas stream conduit (1) to the pretreatment feed conduit (7) and further to the pretreatment unit (2) as described for Figure 1 .

[0073] In a seventh preferred embodiment (not shown in the figures) the third preferred embodiment is modified in that a second raw gas stream is used. Compared to the facility in Figure 3 the facility has been modified as follows: the entire first raw gas stream is forwarded from the first raw gas conduit (1) via an amine unit feed conduit (11) to the amine unit (4) and a second raw gas stream is forwarded via a second raw gas stream conduit (1) to the pretreatment feed conduit (7) and further to the pretreatment unit (2) as described for Figure 1 .

[0074] In an eight preferred embodiment (not shown in the figures) the fourth preferred embodiment is modified in that a second raw gas stream is used. Compared to the fourth preferred embodiment the facility has been modified as follows: the entire first raw gas stream is forwarded from the first raw gas conduit (1) via an amine unit feed conduit (11) to the amine unit (4) and a second raw gas stream is forwarded via a second raw gas stream conduit (1) to the pretreatment feed conduit (7) and further to the pretreatment unit (2) as described for Figure 1 .

[0075] In an nineth preferred embodiment (not shown in the figures) the fifth preferred embodiment is modified in that a second raw gas stream is used. Compared to the fifth preferred embodiment the facility has been modified as follows: the entire first raw gas stream is forwarded from the first raw gas conduit (1) via an amine unit feed conduit (11) to the amine unit (4) and a second raw gas stream is forwarded via a second raw gas stream conduit (1) to the pretreatment feed conduit (7) and further to the pretreatment unit (2) as described for Figure 1 .

[0076] In all embodiments were the retentate of the single stage membrane separation unit (3) is not fed to the amine unit, parts of the raw gas stream are separated by the amine unit. It is thus preferred that the facility of the invention comprises the amine unit feed conduit (11), if the retentate conduit (9) is not connected to the gas inlet (4a) of the amine unit (4).

[0077] The permeate stream of the single stage membrane separation unit (3) is forwarded from the permeate gas outlet (3c) of the single stage membrane separation unit (3) via the permeate conduit (12) to the gas inlet (5b) of fuel gas system (5). Most preferred the entire permeate stream is forwarded to the fuel gas system (5). Entire means that the permeate stream is not split-off between the permeate gas outlet (3c) of the single stage membrane separation unit (3) and the gas inlet (5b) of the fuel gas system (5) and that the total amount of the permeate gas generated in the singe stage membrane separation unit (3) is used as fuel gas of the fuel gas system (5).

[0078] If, however, the energy content of the permeate stream of the singe stage membrane separation unit (3), which is determined by its volume, its flow rate and its composition, is higher than the energy demand of the fuel gas system (5), it is preferred to split-off the permeate stream and to forward only as much permeate gas to the fuel gas system (5) as needed. The rest, i.e. permeate gas, not used in the fuel gas system (5), of the permeate gas is preferably sent to vent.

[0079] If on the other hand the energy content of the permeate stream of the singe stage membrane separation unit (3), is lower than the energy demand of the fuel gas system (5), it is preferred to forward the entire permeate gas stream generated in the singe stage membrane separation unit (3) to the fuel gas system (5) and to supplement fuel from other sources until the demand of the fuel gas system (5) is met. Preferably raw gas and / or the first and / or of the second product gas is used as supplemental fuel. As consequence it is preferred that the facility of the invention comprises a raw fuel gas conduit (17) connecting the first raw gas conduit (1) and / or the second raw gas conduit (1a) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5) and / or a first product fuel gas conduit (37) connecting the product gas conduit (6) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5) and / or a second product fuel gas conduit (38) connecting the second product gas conduit (10) or the retentate conduit (9) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5).

[0080] It is further preferred that the facility of the invention comprises a control unit controlling the capacity and stage cut, i.e. the product of membrane surface and membrane permeance, of the single stage membrane separation unit (3) and / or the amount of the raw gas fed to the gas pretreatment unit (2), more preferred such that a permeate stream of the single stage membrane separation unit (3) is provided having an energy content which correlates to the energy demand of the fuel gas system (5) plus minus 10%, preferably plus minus 5%, even more preferred plus minus 3 %, most preferred the energy content of the permeate gas of the single stage membrane separation unit (3) is controlled to be equal to or lower than the energy demand of the fuel gas system (5) by up to 5% lower, preferably up to 3% lower. Controlling the amount and energy content of the permeate gas stream of the single stage membrane separation unit (3) such way is beneficial because no permeate gas has to be sent to vent, which on the other hand reduces methane emission and waste of energy. Controlling the stage cut of the membrane separation unit can for example be done by activating or deactivating membrane modules via valves.

[0081] In facilities and processes of the invention, where no raw gas is fed via the amine unit feed conduit (11) to the amine unit, for example in Figure 1 , or if parts of the raw gas is forwarded via the amine unit feed conduit (11) to the single stage membrane separation unit (3) but the retentate stream of the single stage membrane separation unit (3) is not combined with the first product stream (as in Figure 3), the capacity and stage cut of the single stage membrane separation unit (3) and / or the amount of raw gas forwarded to the single stage membrane separation unit (3) are preferably controlled such that a permeate stream is provided having an energy content meeting the energy demand of the fuel gas system (5) plus minus 10% preferably plus minus 5%, even more preferably plus minus 3 percent, most preferred the energy content of the permeate gas of the single stage membrane separation unit (3) is controlled to be equal to or lower than or equal to the energy demand of the fuel gas system (5) by up to 5%, preferably up to 3% lower.

[0082] In facilities and processes of the invention, where the retentate stream or parts of the retentate stream of the single stage membrane separation unit (3) is combined with the first product stream (as in Figure 2), the capacity and stage cut of the single stage membrane separation unit (3) and / or the amount of raw gas forwarded to the single stage membrane separation unit (3) are preferably controlled such that a permeate stream is provided having an energy content meeting the energy demand of the fuel gas system (5) plus minus 10% preferably plus minus 5%, even more preferably plus minus 3 %, most preferred the energy content of the permeate gas of the single stage membrane separation unit (3) is controlled to be equal to or lower than or equal to the energy demand of the fuel gas system (5) by up to 5%, preferably up to 3% lower and that simultaneously the CO2 content in the first product stream after mixing it with the retentate gas stream does not exceed a pre-set limit. Usually the retentate gas of the single stage membrane separation unit (3) has a higher CO2 content than the methane enriched gas generated in the amine unit (4). In some cases the CO2 content of the retentate gas stream of the single stage membrane separation unit (3) might be higher than the allowed CO2 content in the first product gas stream. Thus, retentate is preferably added to the methane enriched gas generated in the amine unit (4) only in an amount until the maximum allowed CO2 concentration is reached.

[0083] Preferably the facility of the invention is configured such that 50 to 100 %, preferably 75 to 100%, more preferred 80 to 100%, most preferred 100% of the energy demand of the fuel gas system (5) is provided via the first permeate conduit (12) and the remaining gas demand of the fuel gas system (5) is provided from the fuel gas conduit (17) and / or the first product fuel gas conduit (37) and / or the second product fuel gas conduit (38). The fuel gas conduit (17) and / or the first product fuel gas conduit (37) and / or the second product fuel gas conduit (38) can be connected to the gas inlet of the fuel gas system (5b) or to the permeate conduit (12). The permeate conduit (12) is connected to the gas inlet of the fuel gas system (5b).

[0084] The facility of the Invention comprises an amine unit (4). All known amine units can be used.

[0085] Amine unit (4) uses amine based absorbent liquids. Preferred amines used as absorbent liquids are selected from the group consisting of diethanolamine (DEA), monoethanolamine (MEA), 2-Amino-2- methylpropanol (AMP), methyldiethanolamine (MDEA), diisopropylamine (DIPA), aminoethoxyethanol (DGA), piperazine (Pz), triacetonamine derivatives, particular preferred a triacetonamine derivative according to WO 2012 / 062830, or mixtures thereof, even more preferred aqueous solutions of the amines listed before.

[0086] In case aqueous amine solutions are used, the gas to be separated, passing through the aqueous amine solution absorbs water. It is thus, preferred that the facility of the invention comprises a product gas dehydration unit (19) downstream of the amine unit (4) to dry the methane enriched product gas stream generated in the amine unit (4) to or under a pre-set limit.

[0087] The loaded absorber liquid, i.e. the amine solution having absorbed CO2 from the gas mixture to be separated, needs to be regenerated. This is preferably done via heating by state of the art methods. Heating regenerates the absorber liquid that can be re-used for CO2 absorption in the amine unit and generates a CO2 enriched gas stream that is discharged from the facility via CO2 stream conduit (14).

[0088] Preferably the CO2 stream conduit (14) is connected to the CO2 gas outlet (4c) of the amine unit (4) and to a CO2 stream processing device (15) or to a CO2 stream venting device (16). An example for a CO2 stream processing device (15) would be a device for CO2 liquification and storage or liquid CO2. An example for a CO2 stream venting device (16) would be a venting valve.

[0089] To enable feeding of one or both the methane enriched product gas streams to pipelines, it is particular preferred to configure and control the facility and the process of the invention such, that a carbon dioxide content in the first product gas stream, in the first product gas conduit (6), or in each of the first and the second product gas streams in the first product gas conduit (6) and the second product gas conduit (10), to be in a range of from 0 to 3 % by volume, preferably 0,5 to 2 % by volume of the respective gas stream.

[0090] To meet strong environmental requirements it is further preferred to configure and control the facility and the process of the invention such, that a methane content in the first product gas stream, in the first product gas conduit (6), or in each of the first and the second product gas streams, in the first product gas conduit (6) and the second product gas conduit (10), totals more than 95 % by volume, preferably more than 98% by volume, even more preferred more than 99% by volume, particular preferred more than 99.5 % by volume and most preferred more than or equal to 99.8 % by volume of the respective gas stream, wherein the combined contents of CO2 and methane in sum are in a range of from 95 to 100 % by volume of the methane enriched gas stream.

[0091] As mentioned before heat is required to regenerate the absorbent liquid in the amine unit (4). This heat is provided in part or entirely, preferably entirely, by the fuel gas system (5) of the facility of the invention.

[0092] The fuel gas system (5) comprises all elements and devices of the inventive facility that convert fuel gas into heat or electricity or both.

[0093] To convert the energy of the gas fed to the fuel gas system (5), the fuel gas system (5) comprises an energy converting device (5a). Any device that can convert methane fed to the fuel gas system (5) to heat energy and / or electrical energy can be used.

[0094] Energy needs to be transferred from the fuel gas system (5) to the energy consumers in the facility of the invention. This can be achieved in different ways. In a first and second preferred alternative a heat transfer medium is heated in the fuel gas system (5) and transfers the heat energy to the amine unit (4), where the heat is used to regenerate the absorbent liquid. In the first preferred alternative the heat transfer medium is a medium that is recirculated between the fuel gas system (5) and the amine unit (4) and optionally also the dehydration unit (19). Preferred example for such medium is a heating oil. In the second preferred alternative the heat transfer medium is forwarded to the amine unit (4) and / or the dehydration unit (19). and discharged after heat exchange. Preferred examples for such mediums are water vapor and hot gas, preferably flue gas.

[0095] To transfer the heat transfer medium between the fuel gas system (5) and the amine unit (4) the amine unit (4) further comprises an inlet for a hot heat transfer medium (4d) and preferably also an outlet for cold heat transfer medium (4e), obtained after heat transfer within the amine unit (4). In addition the fuel gas system (5) further comprises an outlet for hot heat transfer medium (5c) and preferably an inlet for cold heat transfer medium (5d). In addition the facility of the invention comprises a hot heat transfer medium conduit (13a) connecting the outlet for hot heat transfer medium (5c) of the fuel gas system (5) to the inlet for the hot heat transfer medium (4d) of the amine unit (4), and preferably also a cold heat transfer medium conduit (13b) connecting the outlet for the cold heat transfer medium (4e) of the amine unit (4) to the inlet for the cold heat transfer medium (5d) of the fuel gas system (5).

[0096] In a first preferred embodiment of the invention the facility is configured to recycle the heat transfer medium from the amine unit (4) back to the fuel gas system (5). In this embodiment the outlet for cold heat transfer medium (4e), the inlet for cold heat transfer medium (5d) and the cold heat transfer medium conduit (13b) connecting the outlet for the cold heat transfer medium (4e) of the amine unit (4) to the inlet for the cold heat transfer medium (5d) of the fuel gas system (5) are comprised in the facility of the invention. An example for this embodiment is shown in Figure 4.

[0097] In a second preferred embodiment of the invention the facility is configured such that the heat transfer medium is not recycled from the amine unit (4) back to the fuel gas system (5). In this embodiment it is preferred that the amine unit (4) comprises an outlet for cold heat transfer medium (4e).

[0098] An example for a preferred energy converting device (5a) that can be used in preferred embodiments 1 and 2 is a directly fired reboiler. In a first alternative permeate gas and optionally further fuel gases are burned and heat water in a water tank to generate water vapor. The water vapor as heat transfer is then pumped via hot heat transfer medium conduit (13a) to the amine unit (4). In a second alternative permeate gas and optionally further fuel gases are burned and heat loaded amine absorber liquid, that has passed an amine stripping column, in a tank to generate water vapor and regenerated (lean) absorber liquid. The water is then forwarded via hot heat transfer medium conduit (13a) to the amine stripping still of the amine unit (4) and the regenerated amine solution is preferably recycled to the amine absorption column. An example of such directly fired amine reboiler is shown in Figure 5.

[0099] Further examples for a preferred energy converting devices (5a) that can be used in preferred embodiments 1 is a heating oil boiler as shown in Figure 6. In such systems permeate gas and optionally further fuel gases are burned and heats a heating oil which is used as heat transfer which is pumped via a pipe system through a direct reboiler. The hot heat transfer medium is then pumped via hot heat transfer medium conduit (13a) to the amine unit (4) and after heat transfer in the amine unit the cold heat transfer medium is recirculated to the fuel gas system.

[0100] Another preferred energy converting device (5a) that can be used in preferred embodiment 2 is a burner, like a thermal oxidizer, which generates hot flue gas, which is used as heat transfer medium and forwarded via hot heat transfer medium conduit (13a) to the amine unit (4).

[0101] In a third preferred embodiment no heat transfer medium required and the heat generated in the fuel gas system (5) is transferred directly to loaded absorber liquid. An example for such configuration of the facility of the invention is shown in Figure 7. In Figure 7 the loaded absorber liquid is pumped via a pipe system through a directly fired reboiler. A gas fire as energy converting device (5a) burns the permeate gas and generates flue gas, which gets in direct contact with pipes and the loaded absorber liquid is heated directly.

[0102] Beside of the amine unit (4) there might be other units that need heat energy in the facility of the invention, for example the product gas dehydration unit (19). In principle the same technologies as explained before for the amine unit (4) can be used here. Figure 4 shows an example of a combined amine unit (4) and TEG unit (19) as dehydration unit as well as its connection to the fuel gas system (5). The amine unit (4) in Figure 4 comprises a carbon dioxide absorbing unit (20), generating a methane rich gas stream, enriched in methane compared to the feed gas of the amine unit (4), and a carbon dioxide desorbing unit (21), generating a carbon dioxide rich gas stream, enriched in CO2 compared to the feed gas of the amine unit (4). The heat energy required by the amine desorbing unit (21) is provided by the fuel gas system (5) in form of a hot heat transfer medium, which is forwarded from the fuel gas system (5) to an amine unit heat exchanger (22) via hot heat transfer medium conduit (13a). After heat exchange, the cold heat transfer medium is recirculated to the fuel gas system (5) via cold heat transfer medium conduit (13b). The heat exchanger (22) transfers the heat to the amine desorber column (21) via a transfer medium, recirculating in conduits (26) and (27).

[0103] The facility according to Figure 4 further comprises a TEG unit as product gas dehydration unit (19). The heat energy required by the for the regeneration of the loaded TEG or the loaded adsorbent is provided by the fuel gas system (5) in form of a hot heat transfer medium, which is fed from the fuel gas system (5) to a TEG heat exchanger (36) via hot heat transfer medium conduit (13a). After heat exchange, the cold heat transfer medium is recirculated to the fuel gas system (5) via cold heat transfer medium conduit (13b). The heat exchanger (36) transfers the heat to the TEG desorber unit (30) via a transfer medium, recirculating in conduits (33) and (34).

[0104] The amine unit (4) of the facility of Figure 4 is fed with retentate gas and / or raw gas via conduits (9) and / or (11), depending on the design of the facility. The raw gas and / or retentate gas is treated in an amine absorber unit (20) with an organic amine based absorber liquid, which absorbs the CO2 and thus separates CO2 from methane and forms a loaded absorber liquid. The loaded absorber liquid is forwarded via conduit (24) to the amine desorber unit (21), where it is heated to regenerate. The regenerated amine absorber liquid is recycled to the amine absorber unit (20) via conduit (25). The CO2 separated from the amine absorber liquid in the desorber (21) is withdrawn from the amine unit and preferably also from the inventive facility, via CO2 stream conduit (14). The methane enriched gas stream from absorber unit (20) is forwarded to a TEG absorber unit (19), where it is dried. The dried first product gas stream is withdrawn from the facility via the first product gas conduit (6). The loaded TEG solution after water absorption is forwarded from the TEG absorber (29) to the TEG desorber (30) via conduit (31). In the TEG desorber heat provided by the fuel gas system (5) as described before is used to separate TEG and water vapor to obtain regenerated TEG liquid and water vapor. The regenerated TEG liquid is recycled to the TEG absorber via conduit (35). The water vapor is withdrawn from the facility.

[0105] Preferably the amine unit comprises several heat exchangers like the lean / rich heat exchanger (23) shown in Figure 4 or particular preferred an amine cooler (not shown in Figure 4), which cools the amine solution before entry into the absorber column. Inventors found out that in an inventive apparatus according to Figure 1 , i.e. where the single stage membrane unit is located upstream of the amine unit, the required cooling capacity is significantly reduced because a lower amine recycle must be pumped, which in addition reduces the required energy for the pumps. These are additional savings that were not taken into account in the benefit calculations in Example 1 . The fuel gas system (5) is preferably configured such, that it generates heat energy and electrical energy. The electrical energy is preferably used in the facility of the invention, too. Particular preferred to run a compressor. Preferred energy converting devices (5a) to generate electrical energy are gas engines to generate electrical energy or gas turbines. In this embodiment it is preferred that the fuel gas system comprises a power connection (5e) to which the users of the electrical energy can be plugged.

[0106] It is further preferred that the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4), more preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) und the product gas dehydration unit (19), even more preferred the fuel gas system (5) provides the entire heat energy consumed in the facility according to claim 1 , particular preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) and electrical energy consumed in the facility according to claim 1 , especially preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) und the product gas dehydration unit (19) and electrical energy consumed in the facility according to claim 1 , most preferred the fuel gas system (5) provides the entire heat energy consumed in the facility according to claim 1 and electrical energy consumed in the facility according to claim 1 .

[0107] The methane enriched product gas obtained in the amine unit (4) may have a water content higher than allowed. It is thus preferred that the facility of the invention comprises a product gas dehydration unit (19) arranged downstream on the amine unit (4), preferably in the first product gas conduit (6). Preferred product gas dehydration units (19) are selected from the group consisting of units cooling down the gas stream below initial dew-point (sometimes with pre-compression to increase effectiveness of this method) to remove the condensed water, and then reheating the gas to near its original temperature. absorption with liquid desiccants, e.g. glycol or methanol, preferably tri-ethylene glycol (TEG) adsorption with solid desiccants, e.g. alumina, silica gel or molecular sieve absorption with a deliquescing solid, such as calcium chloride

[0108] If the methane enriched product gas obtained in the amine unit (4) comprises hydrocarbons with two or more carbon atoms in amounts higher than specified, it is preferred to separate these downstream of the amine unit (4) via fractionate distillation. In this case it is particular preferred to reduce the CO2 content in the methane enriched product gas to less than or equal to 100 ppm since the distillation is preferably carried out at low temperatures where water and CO2 may precipitate.

[0109] The single stage membrane separation unit (3) as well as the amine unit (4) require a partial pressure difference as driving force. Depending on the raw gas source the raw gas might already have sufficiently high pressure. If this is not the case it is preferred to use a compressor (18) arranged up-stream of the single stage membrane separation unit (3), preferably arranged in the raw gas conduit. To increase the economic efficiency of the inventive facility and process it is further preferred that the compressor comprises a wire connection to the power connection (5e) of the fuel gas system (5). Most preferred 50 to 100 %, preferably 70 to 100%, more preferred 80 to 100%, most preferred 100% of the energy demand of the compressor (18) is provided by the fuel gas system (5). Alternatively, the compressor can also be driven by a turbine that is mounted to the same drive shaft like the compressor. Rotation is transferred via the drive shaft from turbine to compressor. Fuel gas is firing the turbine.

[0110] The present invention further comprises a process for separating methane and carbon dioxide from a gas stream comprising both gases. The process comprises the following steps respectively is characterized as follows:

[0111] (a) it is carried out in an inventive facility as described before respectively as claimed in any one of claims 1 to 12;

[0112] (b) supplying a first raw gas stream via the raw gas conduit (1) to the facility; optionally supplying a second raw gas stream via the raw gas conduit (1a) to the facility;

[0113] (c) feeding the entire raw gas stream via pretreatment feed conduit (7) to the pretreatment unit

[0114] (2) or feeding part of the raw gas stream via pretreatment feed conduit (7) to the pretreatment unit (2) and another part, preferably the remaining part, via the amine unit feed conduit (11) to the amine unit (4) and / or via the raw fuel gas conduit (17) to the fuel gas system (5); or feeding the entire first raw gas stream via the amine unit feed conduit (11) to the amine unit (4) and feeding a second raw gas stream is fed via pretreatment feed conduit (7) to the pretreatment unit (2); or feeding part of the first raw gas stream via pretreatment feed conduit (7) to the pretreatment unit (2) and feeding part, preferably the remaining part of the first raw gas stream, via the amine unit feed conduit (11) to the amine unit (4) and / or via the raw fuel gas conduit (17) to the fuel gas system (5) and feeding a second raw gas stream via pretreatment feed conduit (7) to the pretreatment unit (2);

[0115] (d) treating the first and / or the second raw gas in the pretreatment unit (2) to provide a pretreated gas stream, and forwarding the pretreated gas stream via the pretreated gas conduit (8) to the single stage membrane separating unit (3)

[0116] (e) separating the pretreated gas stream in the single stage membrane separating unit (3) to generate a permeate stream being enriched in CO2 compared to the raw gas stream, and a retentate stream being enriched in methane compared to the raw gas stream,

[0117] (f) forwarding parts of or the entire permeate stream obtained in step (f) via permeate conduit (12) to the gas inlet (5b) of the fuel gas system (5) and converting the gas to heat energy or electrical energy or heat energy and electrical energy;

[0118] (g) forwarding parts of or the entire retentate stream generated in the single stage membrane separation unit (3) via the retentate conduit (9) to the gas inlet (4a) of the amine unit (4) and / or to the first product gas conduit (6) and / or to the optionally comprised second product gas conduit (10) and / or to the optionally comprised amine unit feed conduit (11) and / or to the optionally comprised second product fuel gas conduit (38), with the proviso that parts of the raw gas are forwarded to the amine unit (4) if the retentate gas of the single stage membrane separation unit (3) is not fed to the amine unit (4),

[0119] (h) separating the retentate gas obtained in step (e) or the parts of the raw gas or a mixture of the retentate gas produced in step (e) and the raw gas in the amine unit (4) to generate a methane rich first product gas stream, which is forwarded to the first product gas conduit (6) and a CO2 rich stream, which is preferably forwarded to the CO2 stream conduit (14); and

[0120] (i) using the heat energy generated in step (f) in the amine unit (4), preferably to regenerate amin absorbing solutions in the carbon dioxide desorbing unit.

[0121] The process of the invention is particularly beneficial if the CO2 content in the first and / or second raw gas stream is not too high and if there are as less as possible impurities in the raw gas. It is thus, preferred that the first and / or second raw gas contains from 1 to 30 % by volume, more preferably 1 to 15 % by volume, even more preferred 2 to 13 % by volume, particular preferred 3 to 10 % by volume and most preferred 4 to 9 % by volume carbon dioxide and having a combined content of methane and carbon dioxide of at least 50 % by volume, preferably 60 to 90 % by volume, more preferred 85 to 95 % by volume and most preferred 90 to 98 % by volume, in each case % by volume refers to the total volume of the raw gas stream.

[0122] In step c) either the entire first raw gas stream or parts of the first raw gas stream can be forwarded to the pretreatment unit (2) and the single membrane separation unit (3). The remaining first raw gas is preferably forwarded to the amine unit (4). In case the energy content of the permeate gas is lower than the energy demand of the fuel gas system (5) parts of the first raw gas can also be forwarded to the fuel gas system (5) until the energy demand is met. Preferably the shar of the first raw gas that is forwarded to the pretreatment unit (2) is selected such that the amount and composition of the permeate gas of the single stage membrane separation unit (1) is controlled such, that it meets or is slightly lower than the energy demand of the fuel gas system (5). This ensures that not excess of permeate gas is generated which would have to be discharged and, thus, would negatively impact the methane emissions of the facility and process.

[0123] It is thus, preferred that the entire permeate stream of the single stage membrane separation unit (3) is fed to the fuel gas system (5). It is further preferred that only minor amounts of raw gas and / or retentate gas or gas or oil from other sources is fed to the fuel gas system (5) to meets its energy demand, beside of the permeate gas. More preferred 93 to 100 %, more preferred 95 to 100%, even more preferred 97 to 100% and most preferred 100% of the gas demand of the fuel gas system (5) is provided by the raw gas stream and / or product gas stream and the first permeate stream of the single stage membrane separation unit (3), wherein 50 to 100 %, preferably 75 to 100%, more preferred 80 to 100%, most preferred 100%of the gas demand of the fuel gas system (5) is provided by the first permeate stream and the remaining gas demand of the fuel gas system (5) is fed to the gas inlet (5b) of the fuel gas system (5) via raw fuel gas conduit (17) and / or the first product fuel gas conduit (37) and / or the second product fuel gas conduit (38). It is also preferred that in step (c) 10 to 50 % by volume, preferably 10 to 35 % by volume, more preferred 10 to 30 % by volume of the first raw gas stream is forwarded via the pretreatment feed conduit (7) to the pretreatment unit (2) and the remaining amount of the first raw gas stream is fed via the amine unit feed conduit (11) to the amine unit (4) and / or via the raw fuel gas conduit (17) to the fuel gas system (5).

[0124] It is further preferred that the fuel gas system (5) in step f) provides the entire heat energy consumed in the amine unite (4), more preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) und the product gas dehydration unit (19), even more preferred the fuel gas system (5) provides the entire heat energy consumed in the facility according to claim 1 , particular preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) and electrical energy consumed in the facility according to claim 1 , especially preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) und the product gas dehydration unit (19) and electrical energy consumed in the facility according to claim 1 , most preferred the fuel gas system (5) provides the entire heat energy consumed in the facility according to claim 1 and electrical energy consumed in the facility according to claim 1 .

[0125] The pre-treated gas stream obtained in step d) preferably having a pressure of from 7 to 120 bara, more preferred of from 10 to 110 bara, even more preferred 30 to 110 bara, most preferred 50 to 110 bara and / or a temperature of from of from 0 to 60 °C, preferably 10 to 50°C, more preferred 15 to 50 °C and most preferred 20 to 45°C to ensure most efficient gas separation in the single stage membrane separation unit (3) and to control the amount of permeate gas produced there.

[0126] The permeate stream obtained in the single stage membrane separation unit (3) is used as fuel gas for the fuel gas system (5). It is preferred that sufficient amounts of energy providing gas components are comprised in the permeate gas to reduce or avoid supplementation with other gases like raw gas. It is thus, preferred if the permeate gas being enriched in CO2 in step e) by 200 to 600 %, more preferred 220 to 550 %, even more preferred 250 to 530 %, especially preferred 260 to 500 % and most preferred 280 to 450 %. The percentages values defined before are determined as follows: if the CO2 content in the feed stream 10 vol% and the CO2 content in the permeate stream is 35 vol% this calculates to a CO2 increase of 250%.

[0127] As mentioned before, the retentate gas of the single stage membrane separation unit is forwarded to the amine unit or mixed with the first product gas or used as second product gas or is used as supplemental fuel gas. It is thus preferred that the retentate stream being enriched in methane in step e) by 1 to 20 %, more preferred 1 to 15 % %, even more preferred 2 to 10 % and most preferred 3 to 10 %. The percent values are calculated according to the same logic that was explained in detail for CO2 above. If the methane content is too low, the gas cannot be used as product gas or only minimum amounts can be mixed with the first product gas or the dimensions of the amine unite (4) must be enlarged, which is inefficient.

[0128] Preferably a compressor (18) is arranged up-stream of the single stage membrane separating unit (3), more preferred in the first raw gas conduit (1) or the pretreatment feed conduit (7) or the pretreated gas conduit (8), to compress the respective gas stream to a pressure of 30 to 120 bara, preferably 50 to 110 bara. Also preferred the at least parts of the electrical energy demand of the compressor (18) are provided by the fuel gas system (5) in step (f), more preferred 50 to 100 %, even more preferred 75 to 100%, particular preferred 85 to 100% and most preferred 100% of the electrical energy demand of the compressor (18) is provided by the fuel gas system (5) in step (f).

[0129] Inventors found out that the process of the invention is most efficient if gas mixture to be separated in step (h) at the gas inlet of the amine unit (4) has a temperature of from 0 to 60 °C, preferably 10 to 50°C, more preferred 20 to 45°C and / or a pressure of from 10 to 110 bara preferably 30 to 110 bara, more preferred 50 to 110 bara.

[0130] It is preferred to heat up a heat transfer medium in step f) to a temperature in the range of from 160 to 250 °C, preferably 160 to 210 °C for efficient energy transfer to the users, in particular the amine unit (4) and / or the product gas dehydration unit (19).

[0131] To meet actual pipeline specifications the process of the invention is controlled such, that characterized in that the methane rich product gas stream generated in step (h) having a carbon dioxide content of from 0 to 3 % by volume, preferably 0 to 2 % by volume and / or methane content of more than 95 % by volume, preferably more than 98% by volume, even more preferred of more than 99% by volume and most preferred of more than 99.5 % by volume, wherein the combined contents of CO2 and methane in sum are in a range of from 95 to 100 % by volume. In each case by volume means by volume of the methane rich product gas stream.

[0132] The process and facility of the invention can be used to separate any gas comprising CO2 and methane. Preferably it is used to separate natural gas on shore or off-shore or biogas, most preferred natural gas.

[0133] The following examples demonstrate the invention and its advantages.

[0134] Examples

[0135] Calculations were carried out for gas separation in a facilities as shown in Figures 1 to 3 using process simulation software which calculates mass transfer of the gas components through the membrane by numerical integration of the known differential equations for mass transfer through a membrane by a solution-diffusion process, based on experimental data for the permeance of the membrane for methane and carbon dioxide. All pressures are given as absolute pressure (barg).

[0136] Example 1 4 series of simulations, with varying CO2 and CH4 contents in the raw gas, were conducted for a gas separation facilities according to Figures 1 to 4. The CO2 and CH4 contents in the raw gas for each series are given in Table 1 .

[0137] Table 1

[0138] The simulation underlying Example 1 were conducted under the following assumptions:

[0139] In all cases the raw gas contains 2 vol.% C2 hydrocarbons, 1 vol. % C3 hydrocarbons, 0.055 vol.

[0140] % N2. The CO2 and CH4 contents of the raw gases are given in Table 1 . The rest to 100 vol. % is water

[0141] The pretreated gas stream in the pretreated gas conduit (8) in all simulations had T = 44 °C, p =

[0142] 68,6 barg

[0143] The heat demand of the site was estimated according to: W.G. Brown, “Gas Treating Technologies: Which Ones Should Be Used and Under What Conditions?”, GPA 2008; The following demand was utilized o Depending on operating pressure, an amine plant will have an electrical power usage of 2.0 to 2.5 bhp per gallon of amine circulated (i.e. a 100 gpm plant will have an operating electrical load of 200 - 250 bhp) o Reciprocating compressors, operating at 80% efficiency and requiring a heat input of 7600 Btu / hp-hr, are assumed to be useful for all compression operations

[0144] 30% efficiency to provide electricity from a gas-fired engine

[0145] The reboiler duty was obtained via a simulation software, efficiency of reboiler heat utilization: 80%

[0146] 30% additional requirement for electricity on-site

[0147] These assumptions lead to an approx. 3% fuel gas utilization from the feed gas for a standard amine plant which is in good agreement with actual fuel gas demand.

[0148] In the simulations hollow fibre membrane modules were used having the following pure gas permeances under reference conditions and the following mixed gas permeances under operating conditions of the membranes:

[0149] Table 2a pure gas permeances under ref. conditions Table 2b mixed gas permeances of membranes according to Table 2a for mixed gas according to

[0150] Table 1 under operating conditions (T = 44 °C, p = 68,6 barg )

[0151] The reference conditions are 6 barg feed pressure, 0 barg permeate pressure and 25°C feed temperature.

[0152] In each of series 1 to 4 a comparative simulation without membrane separation unit was conducted, wherein as much raw gas was fed to the fuel gas system as necessary to meet the energy demand of the site (heat energy for amine unit, electrical energy for recompression and pumps), and the rest of the raw gas was fed to the amine unit.

[0153] In addition in each of series 1 to 4 a number of examples using amine unit plus membrane unit in a facility according to Figure 1 , 2 or 3 was calculated. For each series the number of membranes modules in the single stage membrane separation unit (3) was varied until the energy content of the permeate gas provided by the membrane separation unit (volumetric flow permeate gas (mmscf / d) x energy content permeate gas (btu / scf)) matched or is slightly lower than the heat demand of the site (mmbtu / d).

[0154] The results are summarized in Tables 3 to 1 1 .

[0155] Table 3 (Series 2, 6 vol. % CO2 in raw gas, facility according to Figure 1)

[0156] Table 3 (continuation)

[0157] Table 3 shows that using a membrane area of 1 1477 m2is the optimum since the energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 4003 mmbtu / d and thus 97% of the facility. Thus, only 3% of the heat demand must be supplemented by feeding raw gas to the fuel gas system (5). Table 3 further shows that with the inventive facility even strong pipeline specifications requiring CO2 contents below 2% are met. In addition the inventive facility reduces the hydrocarbon losses compared to amine stand alone units. Finally Table 3 shows that the inventive facility leads to benefits in operating costs of nearly 1 million USD per year.

[0158] Table 4 (Series 3, 8 vol. % CO2 in raw gas, facility according to Figure 1)

[0159] Table 4 (continuation) Table 4 shows that using a membrane area of 14434 m2is the optimum since the energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 4888 mmbtu / d and thus 99% of the facility. Thus, only 1 % of the heat demand must be supplemented by feeding raw gas to the fuel gas system (5). Table 4 further shows that with the inventive facility even strong pipeline specifications requiring CO2 contents below 2% are met. In addition the inventive facility reduces the hydrocarbon losses compared to amine stand-alone units. Finally Table 4 shows that the inventive facility leads to benefits in operating costs of more than 1 .1 million USD per year.

[0160] Table 5 (Series 4, 10 vol. % CO2 in raw gas, facility according to Figure 1)

[0161] Table 5 (continuation)

[0162] Table 5 shows that using a membrane are of 19477 m2is the optimum for a raw gas with 10 vol. % CO2 since the energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 6089 mmbtu / d and thus 103% of the facility heat demand. Table 5 further shows that with the inventive facility even strong pipeline specifications requiring CO2 contents below 2% are met. In addition the inventive facility reduces the hydrocarbon losses compared to amine standalone units. Finally Table 5 shows that the inventive facility leads to benefits in operating costs of nearly 540000 USD per year. A comparison of Tables 3 to 4 further shows that the inventive facility according to Figure 1 provides the highest monetary benefits if raw gas streams with a lower CO2 content, i.e. below 10 vol. % CO2 must be treated.

[0163] Table 6 (Series 2, 6 vol. % CO2 in raw gas, facility according to Figure 2)

[0164] Table 6 (continuation)

[0165] In the examples according to Table 6 the starting point was a process wherein by use of an amine wash stand-alone facility, the CO2 content of a 219.5 mmscfd feed gas was reduced from 6 to 0.7 vol%. The methane enriched gas stream obtained from the amine plus TEG unit was mixed with 54.9 mmscfd of unpurified gas (bypass) comprising 6 vol% CO2 to produce a total pipeline gas of 255.9 mmscfd comprising 1 .87 vol% CO2. In the second simulation the first simulation was modified by feeding the bypass stream into a single stage membrane separation unit, which produces a retentate stream with a reduced CO2 content that was mixed with the product stream of the amine unit. Because of the reduced CO2 content of said retentate stream the overall volume flow of the bypass stream could be increased, without changing the CO2 content of the pipeline gas, compared to the amine wash stand-alone facility. As consequence a higher product gas flow of 323.3 mmscfd, i.e. a capacity expansion of the plant, was achieved. The flow rate of the bypass is preferably increased until the energy content of the permeate of the membrane unit corresponds exactly to the heat requirement of the entire system / site. Table 6 shows that using a membrane area of 15825 m2is the optimum since the energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 5765 mmbtu / d and thus 100,1 % of the facility. Table 6 further shows that with the inventive facility even strong pipeline specifications requiring CO2 contents below 2% are met. Finally Table 6 shows that the inventive facility according to Figure 2 leads to much higher financial benefits in operating costs than the facility according to Figure 1 (see Table 2). On the other hand the hydrocarbon losses are higher with the facility according to Figure 2 compared to Figure 1 . A man skilled in the art can, thus, make a choice depending on the requirements of the intended application

[0166] Table 7 (Series 4, 10 vol. % CO2 in raw gas, facility according to Figure 2)

[0167] Table 7 (continuation)

[0168] Table 7 shows that using a membrane area of 24346 m2is the optimum since the energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 7627 mmbtu / d and thus 99.5% of the facility. Thus, only 0.5% of the heat demand must be supplemented by feeding raw gas to the fuel gas system (5). Table 7 further shows that with the inventive facility even strong pipeline specifications requiring CO2 contents below 2% are met. In addition the inventive facility reduces the hydrocarbon losses compared to amine stand-alone units. Finally Table 7 shows that the inventive facility according to Figure 2 leads to much higher financial benefits in operating costs than the facility according to Figure 1 (see Table 4). On the other hand the hydrocarbon losses are higher with the facility according to Figure 2 compared to Figure 1 . Table 8 (Series 1 , 4 vol. % CO2 in raw gas, facility according to Figure 2)

[0169] Table 8 (continuation)

[0170] Table 8 shows that using a membrane area of 12173 m2is the optimum for a raw gas with only 4 vol. % CO2 since the energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 4397 mmbtu / d and thus 100.5% of the facility heat demand. Table 8 further shows that with the inventive facility even strong pipeline specifications requiring CO2 contents below 2% are met. Finally Table 8 shows that the inventive facility leads to benefits in operating costs of more than 65 million USD per year.

[0171] A comparison of Tables 6 to 8 further shows that the inventive facility according to Figure 2 provides the highest monetary benefits if raw gas streams with a lower CO2 content, i.e. below 10 vol. % CO2 must be treated. Table 9 (Series 2, 6 vol. % CO2 in raw gas, facility according to modified Figure 3 comprising a 2ndraw gas stream that is fed to the pre-treatment unit (2) instead of a by-pass stream as shown in Figure 3)

[0172] Table 9 (continuation)

[0173] Table 9 shows that using a membrane area of 14782 m2is the optimum for a raw gas with 6 vol. % CO2 in an inventive facility where the retentate stream, of the membrane separation stage (3) is withdrawn as 2ndproduct stream. The energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 5334 mmbtu / d and thus 109.7% of the facility heat demand. Table 9 further shows that with the inventive facility even strong pipeline specifications requiring CO2 contents below 2% are met. Finally Table 9 shows that the inventive facility leads to benefits in operating costs of nearly 1 million USD per year.

[0174] Table 10 (Series 4, 10 vol. % CO2 in raw gas, facility according to modified Figure 3 comprising a 2ndraw gas stream that is fed to the pre-treatment unit (2) instead of a by-pass stream as shown in Figure 3)

[0175] Table 10 (continuation)

[0176] Table 10 shows that using a membrane are of 19999m2is the optimum for a raw gas with 10 vol. % CO2 in an inventive facility where the retentate stream, of the single stage membrane separation unit (3) is withdrawn as 2ndproduct stream. The energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 6242 mmbtu / d and thus 100.1 % of the facility. Table 10 further shows that with the inventive facility according to Figure 3 even strong pipeline specifications requiring CO2 contents below 2% are met. In addition the inventive facility reduces the hydrocarbon losses compared to amine stand-alone units. Finally Table 10 shows that the inventive facility according to modified Figure 3 leads to much higher financial benefits in operating costs than the facility according to Figure 1 (see Table 5). On the other hand the hydrocarbon losses are higher with the facility according modified to Figure 3 compared to Figure 1 . Table 11 (Series 1 , 4 vol. % CO2 in raw gas, facility according to modified Figure 3 comprising a 2ndraw gas stream that is fed to the pre-treatment unit (2) instead of a by-pass stream as shown in Figure 3)

[0177] Table 11 (continuation)

[0178] Table 11 shows that using a membrane area of 8695 m2is the optimum for a raw gas with only 4 vol. % CO2 in an inventive facility where the retentate stream, of the single stage membrane separation unit (3) is withdrawn as 2ndproduct stream. The energy provided by the permeate stream of the single stage membrane separation unit (3) in this case is 3183 mmbtu / d and thus 102.1% of the facility heat demand. Table 11 further shows that with the inventive facility according to modified Figure 3 even strong pipeline specifications requiring CO2 contents below 2% are met. Finally Table 11 shows that the inventive facility leads to benefits in operating costs of around 400000 USD per year.

[0179] A comparison of Tables 9 to 11 further shows that the inventive facility according to modified Figure 3 provides the highest monetary benefits if raw gas streams comprising a higher CO2 content of 10 vol. % CO2 must be treated.

[0180] Example 2

[0181] In Example 2 the influence of membrane selectivity and capacities was investigated for a facility according to Figure 1 . Simulations were conducted with the following approach:

[0182] The capacity of a first amine plant was increased to a higher target capacity, i.e. the plant can process a larger volume flow rate of the raw gas stream, by either adding a second amine plant (not inventive) to process the additional raw gas and to produce a second methane enriched gas stream that was combined with the methane enriched gas stream of the first amine plant and an off-gas stream that was discarded or by adding an inventive single stage membrane separation unit to process the additional raw gas and to produce as retentate stream a second methane enriched gas stream that was combined with the methane enriched gas stream of the first amine plant and a permeate stream that was used as fuel gas according to the invention. The number of membrane modules was optimized to process the additional feed gas such, that the energy provided by the permeate stream of the membrane unit matches the complete fuel gas demand of the site. In addition the second amine unit as well as the additional membrane unit were designed such that the CO2 content of the 1stproduct stream, i.e. the methane enriched gas stream of the first amine unit, was kept constant. The simulations and profit calculations were done under the assumptions that Fuel gas is needed for:

[0183] • Amine unit reboiler

[0184] • Compression of feed gas to amine & membrane unit from 600 psig to 990 psig

[0185] • Providing energy to the amine solution pumps

[0186] • Profit = 0.1 USD / mmbtu

[0187] • 90% plant availability for amine & membrane

[0188] • CAPEX Amine based on cost curve for 1977 (Source: Gas Conditioning and Processing, Vol. 4:

[0189] Gas Treating and Sulfur Recovery, 4. Ed., R.N. Maddox, J. Morgan, 1985-2008, Campbell Petroleum Series.)) and $1 (1977) $4.74 (2022)

[0190] • CAPEX Membrane: 50 USD / m2membrane / / total costs = Membrane costs x 2.5

[0191] The four different membrane types were investigated:

[0192] Type 1 : high selectivity and high capacity

[0193] Type 2: high selectivity and low, non-inventive capacity

[0194] Type 3: low selectivity and high capacity

[0195] Type 4: low selectivity and low, non-inventive capacity.

[0196] Membranes of Types 1 , 2 and 5 were prepared based on US 10,040,036 B2, Example 15, wherein the capacity of the membrane was adjusted by adjusting the thickness of the membranes as shown in Table 12. In Table 12 the “Pure Gas Permeance in barrer” was converted into “Pure Gas Permeance in GPU” by dividing the “Pure Gas Permeance in barrer” through the membrane thickness. In a second step the “Pure Gas Permeance in GPU” was converted to the “Mixed-Gas Permeance under operating conditions in GPU” by multiplying the “Pure Gas Permeance at reference conditions in GPU” with a “Pure Gas / Mixed Gas under reference conditions conversion factor” of 1 .45 for CO2 and 2.32 for CP , both factors were determined by experiments.

[0197] Membranes of Types 3 and 4 were derived from the membranes according to Type 1 by adjusting the permeances to obtain the target capacities and selectivities. Mixed gas membrane selectivities and permeances under operating conditions were used for the simulations. Details are given in Table 12:

[0198] Table 12:

[0199] The composition of the raw gas in all cases was as follows:

[0200] Table 13:

[0201] The results of the simulations are given in Table 14:

[0202] Table 14

[0203] Table 14 (continuation)

[0204] As shown in Figure 8, it turned out that if the inventive single stage membrane unit (amine + membrane solution) is used for a capacity expansion of an existing amine plant instead of an additional amine unit (amine + amine solution), the membranes must have a minimum pure gas permeance for CO2 to achieve economical benefits. Use of membranes with sufficient pure gas permeance for CO2 allows to reduce the number of membrane modules and thus, to optimize the CAPEX costs of membranes. If the CAPEX for the membranes becomes too high, the depreciations for the membranes overcompensate potential benefits in operating costs, as shown in Case 2 compared to Case AA, and in sum, the accumulated profit for the amine + membrane solution is lower than that of the amine + amine solution. If on the other hand the pure gas permeance for CO2 of the membranes is high enough, the required CAPEX for the membranes in the amine + membrane solution is so much lower than that for the additional amin adsorber capacities in the amine + amine solution, that even if the operating costs for the amine + amine solution would be lower than for the amine + membrane solution, the lower depreciation for the membrane unit compared to that of the additional amine unit overcompensates this and the accumulated profit is beneficial for the amine + membrane solution compared to the amine + amine solution (see case 3 compared to case AA). Comparison of Case 1 to Case 3 shows that the selectivity of the membranes has lower effect on the accumulated profit. Nevertheless, use of a higher selective membrane leads to higher accumulated profits after 5 years than use of membranes with a lower selectivity.

[0205] List of reference signs:

[0206] 1 first raw gas conduit

[0207] 1a second raw gas conduit

[0208] 2 raw gas pretreatment unit

[0209] 2a raw gas inlet (not shown in the figures)

[0210] 2b pretreated gas outlet (not shown in the figures)

[0211] 3 single stage membrane separation unit

[0212] 3a gas inlet

[0213] 3b retentate gas outlet

[0214] 3c permeate gas outlet

[0215] 4 amine unit

[0216] 4a gas inlet

[0217] 4b methan gas outlet (not shown in the figures)

[0218] 4c CO2 gas outlet (not shown in the figures)

[0219] 4d an inlet for a hot heat transfer medium (not shown in the figures)

[0220] 4e outlet for cold heat transfer medium (not shown in the figures)

[0221] 5 fuel gas system

[0222] 5a energy converting device converting energy of the gas fed to the fuel gas system (5) into heat energy or heat energy and electrical energy (not shown in the figures)

[0223] 5b gas inlet (not shown in the figures)

[0224] 5c outlet for hot heat transfer medium (not shown in the figures)

[0225] 5d inlet for cold heat transfer medium (not shown in the figures)

[0226] 5e power connection to supply the electrical energy generated in the energy converting device

[0227] 6 first product gas conduit

[0228] 7 pretreatment feed conduit

[0229] 8 pretreated gas conduit

[0230] 9 retentate conduit

[0231] 10 second product gas conduit

[0232] 11 amine unit feed conduit

[0233] 12 permeate conduit

[0234] 13a hot heat transfer medium conduit

[0235] 13b cold heat transfer medium conduit

[0236] 14 CO2 stream conduit

[0237] 15 CO2 stream processing device

[0238] 16 CO2 stream venting device

[0239] 17 fuel gas conduit (not shown in the figures)

[0240] 18 compressor

[0241] 19 product gas dehydration unit 20 carbon dioxide absorbing unit (amine absorber)

[0242] 21 carbon dioxide desorbing unit (amine desorber)

[0243] 22 Amine reboiler

[0244] 23 lean / rich heat exchanger

[0245] 24 saturated absorber solution

[0246] 25 fresh absorber solution

[0247] 26 cold amine conduit

[0248] 27 hot amine conduit

[0249] 28 recirculating conduit

[0250] 29 TEG absorber

[0251] 30 TEG desorber

[0252] 31 saturated TEG solution

[0253] 32 fresh TEG solution

[0254] 33 cold TEG conduit

[0255] 34 hot TEG conduit

[0256] 35 recirculating conduit

[0257] 36 TEG reboiler

[0258] 37 first product fuel gas conduit

[0259] 38 second product fuel gas conduit

Claims

Claims:1 . A facility for separating methane and carbon dioxide from a gas stream, the facility comprising a first raw gas conduit (1) or a first raw gas conduit (1) and a second raw gas conduit (1a), a raw gas pretreatment unit (2), comprising a raw gas inlet (2a) and a pretreated gas outlet (2b), that generates a pretreated gas stream, a single stage membrane separation unit (3), comprising a gas separation membrane having higher permeance for carbon dioxide than for methane and generating a retentate gas stream, which compared to the pretreated gas stream is enriched in methane, and a permeate stream, which compared to the pretreated gas stream is enriched in CO2, a gas inlet (3a) for the pretreated gas, a retentate gas outlet (3b) and a permeate gas outlet (3c); an amine unit (4), generating a methane rich gas stream, which is enriched in methane compared to the feed gas of the amine unit (4), and generating a carbon dioxide rich gas stream, which is enriched in CO2 compared to the feed gas of the amine unit (4), the amine unit further comprising a gas inlet (4a) for a gas comprising methane and carbon dioxide, a methane gas outlet (4b) for the methane rich gas stream and a CO2 gas outlet (4c) for the carbon dioxide rich gas stream; a fuel gas system (5) comprising an energy converting device (5a), converting energy of one or more gas(es) fed to the fuel gas system into heat energy or electrical energy or heat energy and electrical energy, and a gas inlet (5b) for the gas or gases to be converted by the energy converting device (5a), a first product gas conduit (6) connected to the methane gas outlet (4b) of the amine unit (4), characterized in that it further comprises a pretreatment feed conduit (7), connecting the first raw gas conduit (1) and / or the second raw gas conduit (1a) to the raw gas inlet (2a) of the raw gas pretreatment unit (2), a pretreated gas conduit (8), connecting the pretreated gas outlet (2b) of the raw gas pretreatment unit (2) to the gas inlet (3a) of the single stage membrane separation unit (3), a retentate conduit (9) connecting the retentate gas outlet (3b) of the single stage membrane separation unit (3) to the gas inlet (4a) of the amine unit (4), and / or the first product gas conduit (6), and / or a second product gas conduit (10), which is not connected to the first product gas conduit (6), and / or a second product fuel gas conduit (38), connecting the second product gas conduit (10) or the retentate gas conduit (9) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5), with the proviso that the facility further comprises an amine unit feed conduit (11), connecting the raw gas conduit (1) to the gas inlet (4a) of the amine unit (4), if the retentate conduit (9) is not connected to the gas inlet (4a) of the amine unit (4), a permeate conduit (12) connecting the permeate gas outlet (3c) of the single stage membrane separation unit (3) to the gas inlet (5b) of the fuel gas system (5); andcharacterized in that the amine unit (4) further comprises an inlet for a hot heat transfer medium (4d), and the fuel gas system further comprises an outlet for hot heat transfer medium (5c), and the facility further comprises a hot heat transfer medium conduit (13a) connecting the outlet for hot heat transfer medium (5c) of the fuel gas system (5) to the inlet for the hot heat transfer medium (4d) of the amine unit (4), and characterized that part of or the entire energy, needed to meet the energy needs, preferably the at least entire heat energy demand, of the amine unit (4) is provided by the fuel gas system (5) via the hot heat transfer medium conduit (13a), and characterized that the pure gas permeance for CO2, measured at 25 °C, 6 barg feed pressure and 0 barg permeate pressure, of the membranes used in the single stage membrane separation unit (3) is in a range of from 10 to 500 GPU, preferably 12 to 400 GPU, more preferred 14 to 350 GPU, even more preferred 20 to 300 GPU, particular preferred 20 to 220 GPU and most preferred 20 to 150 GPU.

2. The facility according to claim 1 , characterized in that the amine unit (4) further comprises an outlet for a cold heat transfer medium (4e), the fuel gas system further comprises an inlet for cold heat transfer medium (5d), the device further comprises a cold heat transfer medium conduit (13b) connecting the outlet for the cold heat transfer medium (4e) of the amine unit (4) to the inlet for the cold heat transfer medium (5d) of the fuel gas system (5).

3. The facility according to claim 1 or 2, characterized in that the fuel gas system (5) further comprises a power connection (5e) to supply the electrical energy generated in the energy converting device (5a), preferably for use in the facility.

4. The facility according to any one of claims 1 to 3 configured to provide a carbon dioxide content of the first product gas stream in the first product gas conduit (6) or in each of the first and the second product gas streams in the first product gas conduit (6) and the second product gas conduit (10) in a range of from 0 to 3 % by volume, preferably 0,5 to 2 % by volume of the respective gas stream, and / or a methane content of the first product gas stream in the first product gas conduit (6) or in each of the first and the second product gas stream in the first product gas conduit (6) and the second product gas conduit (10) of more than 95 % by volume, preferably of more than 98% by volume, even more preferred of more than 99% by volume, particular preferred of more than 99.5 % by volume and most preferred of more than or equal to 99.8 % by volume.

5. The facility according to any one of claims 1 to 4, further comprising control unit controlling the capacity and stage cut of the single stage membrane separation unit (3) and / or the amount of the raw gas fed to the gas pretreatment unit (2) and / or that the facility is configured such that the entire permeate stream of the single stage membrane separation unit (3) is fed to the fuel gas system (5).

6. The facility according to any one of claims 1 to 5 further comprising a raw fuel gas conduit (17) connecting the raw gas conduit (1) and / or the second raw gas conduit (1a) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5), and / or a first product fuel gas conduit (37) connecting the product gas conduit (6) with the permeate conduit (12) or the gas inlet (5b) of the fuel gas system (5).

7. The facility according to claim 1 to 6, configured such that 50 to 100 %, preferably 75 to 100%, more preferred 80 to 100%, most preferred 100% of the energy demand of the fuel gas system (5) is provided via the first permeate conduit (12) and the remaining demand of the fuel gas system (5) is provided from the raw fuel gas conduit (17) and / or the first product fuel gas conduit (37) and / or the second product fuel gas conduit (38).

8. The facility according to any one of claims 1 to 7 further comprising a compressor (18) arranged up-stream of the single stage membrane separation unit (3), preferably the compressor comprises a wire connection to the power connection (5e) of the fuel gas system (5).

9. The facility according to claim 8, configured such that 50 to 100 %, preferably 70 to 100%, more preferred 80 to 100%, most preferred 100% of the energy demand of the compressor (18) is provided by the fuel gas system (5).

10. The facility according to any one of claims 1 to 9 further comprising a product gas dehydration unit (19) arranged downstream on the amine unit (4), preferably in the first product gas conduit (6) an amine unit (4) comprising a carbon dioxide absorbing unit (20) and a carbon dioxide desorbing unit (21).11 . The facility according to any one of claims 1 to 10 characterized in that the membranes used in the single stage membrane separating unit (3) containing a separation layer of a glassy polymer, wherein the glassy polymer having a glass transition point at a temperature above the operating temperature of the membrane separation stage, preferably the glassy polymers are selected from the group consisting of polyetherimide, a polycarbonate, a polyamide, a polybenzoxazole, apolybenzimidazole, a polysulfone or a polyimide, even more preferred the membranes used in the single stage membrane separating unit (3) having o a pure gas selectivity for CO2 / CH4 of 5 to 50, preferably 7 to 40, more preferred 7 to 30 at 25 to 60°C, and / or a pure gas permeance for CH4 under reference conditions of the membranes used in the single stage membrane separation unit (3) of of 0.15 to 6.5 GPU, more preferred 0.2 to 4.5 GPU, even preferred of 0.25 to 4.5 GPU, particular preferred of 0.4 to 4 GPU and most preferred of 0.8 to 3.5 GPU.

12. The facility according to any one of claims 1 to 11 characterized in that the pretreatment unit (2) comprises one or more devices selected from the group consisting of a device to separate impurities comprised in the raw gas stream and that are liquid at or below room temperature or that can be liquified at or below room temperature, from the raw gas stream, preferred devices are inlet coalescer and inlet separator, preferred liquid or liquifiable impurities are ITOand higher hydrocarbons, more preferred hydrocarbons with more than 3, preferably 6 to 10 carbon atoms a guard bed, i.e. a bed of activated carbon to remove impurities like H2S and other sulfur components via adsorption or a bed of silica gel to remove higher hydrocarbons, a particle filter to remove solid particles from the raw gas stream, and a heat exchanger to adjust the temperature of the gas stream to be separated in the membrane separation unit.

13. A process for separating methane and carbon dioxide from each other, characterized in that(a) the process is carried out in a facility as claimed in any one of claims 1 to 12;(b) a first raw gas stream, preferably containing from 1 to 30 % by volume, more preferred 1 to 15 % by volume, even more preferred 2 to 13 % by volume, particular preferred 3 to 10 % by volume and most preferred 4 to 9 % by volume carbon dioxide and having a combined content of methane and carbon dioxide of at least 50 % by volume, preferably 60 to 90 % by volume, more preferred 85 to 95 % by volume and most preferred 90 to 98 % by volume, in each case % by volume refers to the total volume of the raw gas stream, is supplied via the raw gas conduit (1) to the facility; optionally a second raw gas stream preferably containing from 1 to 30 % by volume, more preferred 1 to 15 % by volume, even more preferred 2 to 13 % by volume, particular preferred 3 to 10 % by volume and most preferred 4 to 9 % by volume carbon dioxide and having a combined content of methane and carbon dioxide of at least 50 % by volume, preferably 60 to 90 % by volume, more preferred 85 to 95 % by volume and most preferred 90 to 98 % by volume, in each case % by volume refers to the total volume of the raw gas stream, is supplied via the second raw gas conduit (1a) to the facility;(c) the entire first raw gas stream is fed via pretreatment feed conduit (7) to the pretreatment unit (2);or part of the first raw gas stream is fed via pretreatment feed conduit (7) to the pretreatment unit (2) and part of the first raw gas stream, preferably the remaining part, is fed via the amine unit feed conduit (11) to the amine unit (4) and / or via the raw fuel gas conduit (17) to the fuel gas system (5); or the entire first raw gas stream is fed via the amine unit feed conduit (11) to the amine unit (4) and a second raw gas stream is fed via pretreatment feed conduit (7) to the pretreatment unit (2); or part of the first raw gas stream is fed via pretreatment feed conduit (7) to the pretreatment unit (2) and part, preferably the remaining part of the first raw gas stream, is fed via the amine unit feed conduit (11) to the amine unit (4) and / or via the raw fuel gas conduit (17) to the fuel gas system (5) and a second raw gas stream is fed via pretreatment feed conduit (7) to the pretreatment unit (2);(d) first and / or second raw gas is treated in the pretreatment unit (2) to provide a pretreated gas stream, preferably pretreated gas stream having a pressure of from 7 to 120 bara, preferably of from 10 to 1 10 bara, more preferred 30 to 110 bara, most preferred 50 to 110 bara and / or a temperature of from of from 0 to 60 °C, preferably 10 to 50°C, more preferred 15 to 50 °C and most preferred 20 to 45°C, and that the pretreated gas stream is forwarded via the pretreated gas conduit (8) to the single stage membrane separating unit (3),(e) the pretreated gas stream is separated in the single stage membrane separating unit (3) to generate a permeate stream being enriched in CO2 compared to the raw gas stream, preferably being enriched in CO2 by 200 to 600 %, preferred 220 to 550 %, more preferred 250 to 530 %, even more preferred 260 to 500 % and most preferred 280 to 450 %and to generate a retentate stream being enriched in methane compared to the raw gas stream, preferably being enriched in methane by 1 to 20 %, more preferred 1 to 15 % %, even more preferred 2 to 10 % and most preferred 3 to 10 %;(f) the parts of or the entire permeate stream obtained in step (f) is supplied via permeate conduit (12) to the gas inlet (5b) of the fuel gas system (5) to convert the gas to heat energy or electrical energy or heat energy and electrical energy;(g) the entire or part of the retentate stream generated in the single stage membrane separation unit (3) is forwarded via the retentate conduit (9) to the gas inlet (4a) of the amine unit (4) and / or to the first product gas conduit (6) and / or to the optionally comprised second product gas conduit (10) and / or to the optionally comprised amine unit feed conduit (1 1) and / or to the optionally comprised second product fuel gas conduit (38), with the proviso that parts of the raw gas are forwarded to the amine unit (4) if the retentate gas of the single stage membrane separation unit (3) is not fed to the amine unit (4),(h) the retentate gas produced in step (e) or parts of the raw gas or a mixture of the retentate gas produced in step (e) and raw gas is separated in the amine unit (4) to generate a methane rich first product gas stream, which is forwarded to the first product gas conduit (6) and a CO2 rich stream, which is preferably forwarded to the CO2 stream conduit (14);and(i) using the heat energy generated in step (f) in the amine unit (4), preferably to regenerate amine absorbing solutions in the carbon dioxide desorbing unit.

14. The process according to claim 13, characterized in that in step (c) 10 to 50 % by volume, preferably 10 to 35 % by volume, more preferred 10 to 30 % by volume of the first raw gas stream is forwarded via the pretreatment feed conduit (7) to the pretreatment unit (2) and the remaining amount of the first raw gas stream is fed via the amine unit feed conduit (11) to the amine unit (4) and / or via the raw fuel gas conduit (17) to the fuel gas system (5).

15. The process according to any one of claims 13 or 14, characterized in that a compressor (18) is arranged up-stream of the single stage membrane separating unit (3), preferably in the first raw gas conduit (1) or the pretreatment feed conduit (7) or the pretreated gas conduit (8), to compress the respective gas stream to a pressure of 30 to 120 bar, preferably 50 to 110 bar; preferably 50 to 100 %, preferably 75 to 100%, more preferred 85 to 100%, most preferred 100% of the electrical energy demand of the compressor (18) is provided by the fuel gas system (5) in step (f).

16. The process according to any one of claims 13 to 15, characterized in that the heat transfer medium is selected from the group consisting of water, a heating oil, and gas, preferably flue gas, and / or the heat transfer medium is heated in the fuel gas system (5) to a temperature in the range of from 160 to 250 °C, preferably 160 to 210 °C, and / or the energy converting device used in step (f) to convert the energy of the permeate gas into heat energy and / or electrical energy is selected from the group consisting of thermal Oxidizer, heating oil boiler, direct-fired reboiler, gas engine to generate electrical energy or gas turbine to generate electrical energy.

17. The process according to any one of claims 13 to 16, characterized in that the gas mixture to be separated in step (h) at the gas inlet of the amine unit (4) has a temperature of from 0 to 60 °C, preferably 10 to 50°C, more preferred 20 to 45°C and / or a pressure of from 10 to 110 bara preferably 30 to 110 bara, more preferred 50 to 110 bara.

18. The process according to any one of claims 13 to 17, characterized in that the amine absorbents used in the amine unit (4) is selected from the group consisting of diethanolamine (DEA), monoethanolamine (MEA), 2-Amino-2-methylpropanol (AMP), methyldiethanolamine (MDEA), diisopropylamine (DIPA), aminoethoxyethanol (DGA), piperazine (Pz), a triacetonamine derivative or mixtures thereof, preferably aqueous solutions of said absorbents or absorbents mixtures are used.

19. The process according to any one of claims 13 to 18, characterized in that the methane rich product gas stream generated in step (h) having a carbon dioxide content of from 0 to 3 % by volume, preferably 0,5 to 2 % by volume and / or methane content of more than 95 % by volume, preferably or more than 98% by volume, even more preferred of more than 99% by volume, particular preferred of more than 99,5% and most preferred of more than or equal to 99.8 % by volume, wherein the combined contents of CO2 and methane in sum are in a range of from 95 to 100 % by volume, in each case of the respective gas streams.

20. The process according to any one of claims 13 to 19, characterized in that the entire permeate stream of the single stage membrane separation unit (3) is fed to the fuel gas system (5), and / or that raw and / or product gas is fed to the fuel gas system (5) in addition to the permeate stream of the single stage membrane separation unit (3), preferably such, that that 93 to 100 %, more preferred 95 to 100%, even more preferred 97 to 100% and most preferred 100% of the gas demand of the fuel gas system (5) is provided by the raw gas stream and / or product gas stream and / or the first permeate stream of the single stage membrane separation unit (3), wherein 50 to 100 %, preferably 75 to 100%, more preferred 80 to 100%, most preferred 100% of the gas demand of the fuel gas system (5) is provided by the first permeate stream and the remaining gas demand of the fuel gas system (5) is fed to the gas inlet (5b) of the fuel gas system (5) via raw fuel gas conduit (17) and / or the first product fuel gas conduit (37) and / or the second product fuel gas conduit (38) and / or the fuel gas system (5) in step f) provides the entire heat energy consumed in the amine unite (4), more preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) und the product gas dehydration unit (19), even more preferred the fuel gas system (5) provides the entire heat energy consumed in the facility according to claim 1 , particular preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) and electrical energy consumed in the facility according to claim 1 , especially preferred the fuel gas system (5) provides the entire heat energy consumed in the amine unite (4) und the product gas dehydration unit (19) and electrical energy consumed in the facility according to claim 1 , most preferred the fuel gas system (5) provides the entire heat energy consumed inthe facility according to claim 1 and electrical energy consumed in the facility according to claim 1.21 . The process according to any one of claims 13 to 20, characterized in that in cases, where no raw gas is fed via the amine unit feed conduit (11) to the amine unit or in cases where parts of the raw gas is forwarded via the amine unit feed conduit (11) to the single stage membrane separation unit (3) but the retentate stream of the single stage membrane separation unit (3) is not combined with the first product stream, the capacity and stage cut of the single stage membrane separation unit (3) and / or the amount of raw gas forwarded to the single stage membrane separation unit (3) are controlled such a permeate stream is provided having an energy content meeting the energy demand of the fuel gas system (5) plus minus 10%, preferably plus minus 5%, even more preferably plus minus 3 percent, most preferred the energy content of the permeate gas of the single stage membrane separation unit (3) is controlled to be equal to or lower than or equal to the energy demand of the fuel gas system (5) by up to 5%, preferably up to 3% lower, or in cases, where the retentate stream or parts of the retentate stream of the single stage membrane separation unit (3) is combined with the first product stream, the capacity and stage cut of the single stage membrane separation unit (3) and / or the amount of raw gas forwarded to the single stage membrane separation unit (3) are controlled such that a permeate stream is provided having an energy content meeting the energy demand of the fuel gas system (5) plus minus 10%, preferably plus minus 5%, even more preferably plus minus 3 percent, most preferred the energy content of the permeate gas of the single stage membrane separation unit (3) is controlled to be equal to or lower than or equal to the energy demand of the fuel gas system (5) by up to 5%, preferably up to 3% lower and that the CO2 content in the first product stream after mixing it with the retentate gas stream does not exceed a pre-set limit.

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