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Turbine powered electricity generation

11149634 · 2021-10-19

    Inventors

    Cpc classification

    International classification

    Abstract

    A process is provided for separating syngas fuel into a CO-rich stream for feeding to oxyfuel combustor means of CO.sub.2 turbine means and a H.sub.2-rich stream for feeding to air-fuel gas turbine means for generating power provides opportunity to realize operating and equipment advantages.

    Claims

    1. A process comprising: a. feeding a separator feedstream comprising syngas from a steam methane reformer to membrane separator means, b. separating the separator feedstream to form a first, CO-rich retentate stream, and a second, H.sub.2-rich permeate stream, c. feeding the retentate stream as an oxyfuel combustor feedstream to oxyfuel combustor means wherein the oxyfuel combustor feedstream is reacted with a high purity oxygen stream to form a supercritical CO.sub.2 working fluid, d. feeding the supercritical CO.sub.2 working fluid to supercritical CO.sub.2 turbine means for producing power, wherein the supercritical CO.sub.2 turbine means provides power to electricity generator means for generating electric power, e. feeding the permeate stream as an air-fuel combustor feedstream to air-fuel combustor means wherein the air-fuel combustor feedstream is reacted with air to form air-fuel gas turbine working fluid, f. feeding the air-fuel gas turbine working fluid to an air-fuel gas turbine means for producing power, wherein the air-fuel gas turbine means provides power to electricity generator means for generating electric power, g. feeding air-fuel gas turbine exhaust from the air-fuel gas turbine means to heat recovery means wherein steam is formed, and h. feeding the steam formed in step g. as working fluid to steam turbine means for producing power, wherein the steam turbine means provides power to electricity generator means for generating electric power.

    2. The process of claim 1, wherein the oxyfuel combustor means reacts high purity oxygen of at least 97% purity with the oxyfuel combustor feedstream to produce supercritical CO.sub.2.

    3. The process of claim 1, wherein exhaust from the supercritical CO.sub.2 turbine comprises sCO.sub.2 and steam and is fed to water separation means for separating water from the exhaust, wherein the water separation means comprises the step of the exchange of heat from the exhaust to cooling fluid.

    4. The process of claim 1, wherein the high purity oxygen stream is at least 95% pure.

    5. The process of claim 4, wherein the CO-rich stream comprises at least 40% CO and the H.sub.2-rich stream comprises at least 40% H.sub.2.

    6. The process of claim 5, wherein the CO-rich stream comprises at least 50% CO and the H.sub.2-rich stream comprises at least 50% H.sub.2.

    7. The process of claim 6, wherein the CO-rich stream comprises at least 65% CO and the H.sub.2-rich stream comprises at least 60% H.sub.2.

    8. The process of claim 7, wherein the CO-rich stream comprises at least 80% CO and the H.sub.2-rich stream comprises at least 85% H.sub.2.

    9. The process of claim 5, wherein the oxyfuel combustor means reacts high purity oxygen of at least 97% purity with the oxyfuel combustor feed steam to produce supercritical CO.sub.2.

    10. The process of claim 1, wherein the oxyfuel combustor means reacts high purity oxygen of at least 99% purity with the oxyfuel combustor feed steam to produce supercritical CO.sub.2.

    11. The process of claim 10, wherein the oxyfuel combustor means reacts high purity oxygen of at least 99.5% purity with the oxyfuel combustor feed steam to produce supercritical CO.sub.2.

    12. A process comprising: a. feeding a separator feedstream comprising syngas from a steam methane reformer to a membrane separator, b. separating the separator feedstream to form a first, CO-rich retentate stream, and a second, H.sub.2-rich permeate stream, c. feeding the retentate stream as an oxyfuel combustor feedstream to an oxyfuel combustor wherein the oxyfuel combustor feedstream is reacted with a high purity oxygen stream to form a supercritical CO.sub.2 working fluid, d. feeding the supercritical CO.sub.2 working fluid to a supercritical CO.sub.2 turbine for producing power, wherein the supercritical CO.sub.2 turbine provides power to an electricity generator for generating electric power, e. feeding the permeate stream as an air-fuel combustor feedstream to an air-fuel combustor wherein the air-fuel combustor feedstream is reacted with air to form air-fuel gas turbine working fluid, f. feeding the air-fuel gas turbine working fluid to an air-fuel gas turbine for producing power, wherein the air-fuel gas turbine provides power to an electricity generator for generating electric power, g. feeding air-fuel gas turbine exhaust from the air-fuel gas turbine to a heat recovery steam generator wherein steam is formed, and h. feeding the steam formed in step g. as working fluid to a steam turbine for producing power, wherein the steam turbine provides power to an electricity generator for generating electric power.

    Description

    BRIEF DESCRIPTION OF THE DRAWINGS

    (1) FIG. 1 is a schematic diagram of a supercritical carbon dioxide turbine plant;

    (2) FIG. 2 is a schematic diagram of a supercritical carbon dioxide plant combined with an air-fuel turbine/steam turbine plant.

    DETAILED DESCRIPTION OF THE INVENTION

    (3) In the following detailed description, reference is made to the accompanying drawings, which form a part hereof. In the drawings, similar symbols typically identify similar components, unless context dictates otherwise. The illustrative embodiments described in the detailed description, drawings, and claims are not meant to be limiting. Other embodiments may be utilized, and other changes may be made, without departing from the spirit or scope of the subject matter presented herein.

    (4) All publications, patents and patent applications cited herein, whether supra or infra, are hereby incorporated herein by reference in their entirety to the same extent as if each individual publication, patent or patent application was specifically and individually indicated to be incorporated herein by reference. Further, when an amount, concentration, or other value or parameter is given as either a range, preferred range, or a list of upper preferable values and lower preferable values, this is to be understood as specifically disclosing all ranges formed from any pair of any upper range limit or preferred value and any lower range limit or preferred value, as well as, any range formed within a specified range, regardless of whether ranges are separately disclosed. Where a range of numerical values is recited herein, unless otherwise stated, the range is intended to include the endpoints thereof, and all integers and fractions within the range. For example, recitation of 1-5 is intended to include all integers including and between 1 and 5 and all fractions and decimals between 1 and 5, e.g., 1, 1.1, 1.2, 1.3 etc. It is not intended that the scope of the invention be limited to the specific values recited when defining a specific range. Similarly, recitation of at least about or up to about a number is intended to include that number and all integers, fractions and decimals greater than or up to that number as indicated. For example, at least 5 is intended to include 5 and all fractions and decimals above 5, e.g., 5.1, 5.2, 5.3 etc.

    (5) It is noted that, as used in this specification and the appended claims, the singular forms “a,” “an” and “the” include plural referents unless the content clearly dictates otherwise. Unless otherwise expressly indicated herein, all amounts are based on volume.

    (6) According to an embodiment, the process comprises: a. feeding a separator feedstream comprising syngas to separator means, b. separating the separator feedstream in the separator means to form a first, CO-rich stream and a second, H.sub.2-rich stream, c. feeding the first CO-rich stream as an oxyfuel combustor feedstream to an oxyfuel combustor means wherein the oxyfuel combustor feedstream is reacted with a high purity oxygen feedstream of at least about 95% purity, and d. feeding the second H.sub.2-rich stream as an air-fuel combustor feedstream to air-fuel combustor means wherein the air-fuel combustor feedstream is reacted with air.

    (7) With reference to illustrative FIG. 2 of the drawings, 1a is a source for producing syngas feedstream 1b to separator means 2. The source of syngas feed can be any known source, for example, a steam reformer system or a coal gasification system. Steam reformer systems are known and are described, for example, in U.S. Pat. Nos. 3,479,298, 5,653,774 and 5,628,931. Coal gasification systems are also known and are described, for example, in U.S. Pat. No. 8,252,074B2, U.S. Pat. No. 8,758,458B2 and U.S. Pat. No. 9,388,348B2.

    (8) Syngas feed compositions are well known in the art and can vary depending on the source. By way of nonlimiting example, it is believed that syngas feed 1b can comprise H.sub.2, CO.sub.2, CO, CH.sub.4 and H.sub.2O in the following amounts. The H.sub.2 content can be about 20-65%. The CO.sub.2 content can be about 2-25%. The CO content can be about 20-60%. The H.sub.2O content can be about 5-40%. The CH.sub.4 content can typically be about 0.1%-0.9%. It is understood that the syngas feed 1b may contain minor amounts of contaminants, e.g., H.sub.2S, NH.sub.3, HCl, COS, and Hg, depending whether the syngas is gasified coal or reformed natural gas, and can be removed by known treatments. By way of example, contaminants could comprise less than about 0.5% of syngas feed 1b.

    (9) Separator means 2 can be any known separator means suitable for the purpose of separating the syngas feedstream into a first, CO-rich stream 3 and a second, H.sub.2-rich stream 26. For example, separator means can be membrane separator means or pressure swing adsorption means. Membrane separation is preferred.

    (10) Gas separation membranes and the operation thereof for separating gas mixtures are well known. See for example, U.S. Pat. No. 5,482,539. U.S. Pat. Nos. 4,990,168, 4,639,257, 2,966,235, 4,130,403, 4,264,338, and 5,102,432. Any known membrane that is operable under the conditions of operation to meet the noted product compositions can be used. For example, UBE membranes advertised for H.sub.2 separations would be suitable, as would a polybenzimidazole (PBI) membrane. Reference is made, respectively, to Haruhiko Ohya et al, “Polyimide Membranes: Applications, Fabrications and Properties” by H. Ohya, V. V. Kudryavtsev and S. I, Semenova (Jan. 30, 1997) co-published by Kodansha LYD., 12-21 Otowa 2-Chome Bunkyo-Ku, Tokyo 112, Japan and Gordan and Breach Science Publishers S.A. Emmaplein 5, 1075 AW Amsterdam, The Netherlands, for the Ube membranes and to Jayaweera, Indira S. “Development of Pre-Combustion CO.sub.2 Capture Process Using High-Temperature Polybenzimidazole (PBI) Hollow-Fiber Membranes (HFMs)”, 2017 NETL CO.sub.2 Capture Technology Project Review Meeting, Aug. 21-25, 2017, [online] [retrieved Jan. 17, 2019], [https://www.netl.doe.gov/sites/default/files/2017-12/2I-S-Jayaweera2-SRI-PBI-Hollow-Fiber-Membranes.pdf], and “Celazole.sup.R PBI”, [online] [retrieved Jan. 17, 2019], [https://pbipolymer.com/markets/membrane/].

    (11) As illustrated in FIG. 2, separator means 2 comprises membrane means 25 disposed therewithin. The syngas feedstream is fed to separator means on one side of the membrane means and is separated into separate streams by selective permeation of syngas components therethrough. As shown, the membrane is more permeable to the H.sub.2 contained in the syngas feedstream than it is to CO. The membrane being more selective for H.sub.2 permeation, permeate stream 26 is enriched in H.sub.2 as compared to syngas feedstream 1b, and retentate stream 3 is enriched in CO as compared to the syngas feedstream 1b. Accordingly, stream 26 comprises a H.sub.2-rich stream and stream 3 comprises a CO-rich stream. The CO-rich stream is then sent to a sCO.sub.2 power plant 33 as discussed above.

    (12) Concepts of mixed-gas separation, gas permeability and selectivity are discussed in a number of publications, including “Materials Science of Membranes for Gas and Vapor Separation”, Edited by Yampolski et al, 2006 JohnWiley & Sons; “Pure and mixed gas CH.sub.4 and n-C4H10 permeability and diffusivity in poly(1-trimethylsilyl-1-propyne)” Roy D. Raharjo et al, Polymer 48 (2007) 7329-7344, 2006 Elsevier Ltd., “Carbon Dioxide Separation through Polymeric Membrane Systems for Flue Gas Applications”, Colin A. Scholes et al, Cooperative Research Centre for Greenhouse Gas Technologies, Department of Chemical and Biomolecular Engineering, The University of Melbourne, VIC, 3010, Australia; and “Recent Patents on Chemical Engineering”, 2008, 1 52-66, 2008 Bentham Science Publishers Ltd.

    (13) The CO-rich stream 3 comprises primarily CO, with minor amounts of carbon dioxide and hydrogen.

    (14) After optional contaminant removal (not shown), stream 3 should comprise primarily CO and hydrogen. Stream 3 can also comprise a small amount of CO.sub.2 and traces of remaining contaminants. For example, stream 3 can comprise at least about 35%, or at least about 50%, or at least about 65%, or at least about 80% CO. Having the benefit of the disclosure of the present invention, it is seen that the H.sub.2 content of stream 3 depends on operational and plant design objectives. On that basis, it is believed that the stream 3 should comprise less than about 55%, or less than about 40%, or less than about 25%, or less than about 10% H.sub.2. Stream 3 can also comprise a small amount of CO.sub.2 and traces of remaining contaminants. Stream 3 should comprise less than about 0.01%, or less than about 0.001%, or less than about 0.0001%, or less than about 0.00001% of contaminants; and CO.sub.2 should comprise less than about 25%, or less than about 15%, or less than about 10%, or less than about 5% of stream 3. Any upper limit for the CO content of stream 3 is considered to be limited only by the ability of technology to economically enrich stream 3 in CO. It is believed that using present technology, stream 3 can comprise up to about 90-95% CO.

    (15) Stream 3 is then fed as oxyfuel combustor feedstream 4 to oxyfuel combustor means 5, wherein it is combined and reacted with high purity oxygen stream 8 of at least about 95% purity from air separation unit means 6 for separating oxygen from air. The oxygen content of stream 8 comprises at least about 95%, at least about 97%, at least about 99%, or at least about 99.5%. Air separation units are well known, for example, as illustrated in U.S. Pat. Nos. 2,548,377, 4,531,371 and 4,382,366. See also, Rong Jiang, Analysis and Optimization of ASU for Oxyfuel Combustion [online] [retrieved 2-19-2019][http://ieaghg.org/docs/General_Docs/5oxy%20presentations/Session%207B/7B-05%20-%20R.%20Jiang%20(SASPG%20Ltd.).pdf]. and “History and progress in the course of time, [online] [retrieved Feb. 19, 2019] [https://www.linde-engineering.com/en/images/Air_separation_plants_History_and_progress_in_the_course_of_time_tcm19-457349.pdf]. Before the use of a separator means to separate hydrogen from the syngas feedstream 1b in accordance with the present invention, a considerable portion of the oxygen produced in prior air separation units was consumed by reaction with H.sub.2 contained in the combustor fuel stream 4. Combustion in accordance with an embodiment of the present invention, results in stream 9 comprised primarily of sCO.sub.2 working fluid with a substantially reduced amount of steam. The sCO.sub.2 content of the oxyfuel combustion exhaust in stream 9 will, of course, vary, depending on the amount of H.sub.2 recovery in the membrane permeate and the amount of CO.sub.2 in the membrane feedstream both of which affects the CO.sub.2 content in the sCO.sub.2 oxyfuel combustion exhaust. In any event, it can comprise at least about 50%, at least about 60% at least about 70%, or at least about 80% sCO.sub.2, with the balance comprising H.sub.2O, and contaminants such as N.sub.2+Ar. An unexpected advantage of using a CO-rich fuel stream in accordance with the present invention to the oxyfuel combustor means 5 is that the oxyfuel combustor oxygen requirement can be significantly reduced, by way of nonlimiting example, by up to about 50 to 75%, depending on the source of the feed to separator means 2 (e.g., gasified coal or steam reformed methane, respectively) and the operating conditions and type of separator means 2 used. In addition, the oxyfuel combustor and sCO.sub.2 turbine sizes can be significantly reduced due to the substantial reduction of the hydrogen fraction and hydrogen mass flow in stream 4 and consequently, after combustion with high purity oxygen in oxyfuel combustor means 5, a substantial reduction in steam fraction in stream 12.

    (16) Supercritical CO.sub.2 (sCO.sub.2) 9 is then fed to the inlet of a sCO.sub.2 turbine means 10 wherein power is produced to power electricity generator 11.

    (17) Turbine exhaust 12 is then fed to regenerative heat exchanger means 13 for indirect cooling with cooled sCO.sub.2 stream 34. The thus-cooled sCO.sub.2 stream 35 is fed for further cooling in cooling means 15 for indirect cooling with cooling fluid 36. Cooled sCO.sub.2 stream 37 is sent to condensed water separator means 16 for removing condensed water 17 from cooled sCO.sub.2 stream 37. Since stream 37 comprises less water due to the separation of hydrogen from stream 1b by separator means 2, cooling means 23 energy and equipment size requirements can be significantly reduced. Cooling fluid 36 for heat exchangers 15 and 19 is provided by cooling fluid cooling means 23. The sCO.sub.2 working fluid leaving the water separator 16, is compressed in CO.sub.2 compressor means 18, and then cooled in aftercooler means 19 to remove heat of compression. Compressed and cooled sCO.sub.2 is circulated by pump 21 for capture in stream 22 and recirculation in stream 34 and then forwarded through regenerative heat exchanger 13 and finally back to oxyfuel combustor means 5. Recycle stream 24 is a working fluid for the optimum performance of the sCO.sub.2 oxyfuel combustor and sCO.sub.2 turbine. Recycling the supercritical CO.sub.2 after reheating in regenerative heat exchanger 13 to oxyfuel combustor means 5 enables the supercritical carbon dioxide power cycle to operate with super critical CO.sub.2 as the working fluid in turbine 10. The cycle is operated above the critical point of CO.sub.2 so that it does not change phases (from liquid to gas), but rather undergoes density changes over small ranges of temperature and pressure. This allows a large amount of energy to be extracted at high temperature from equipment that is relatively small. For example, sCO.sub.2 turbines can have a nominal gas path diameter an order of magnitude smaller than utility scale gas turbines or steam turbines.

    (18) Permeate, H.sub.2-rich gas stream 26 is fed to a combined cycle system 27. Gas stream 26 comprises primarily H.sub.2 and H.sub.2O with small quantities of CO.sub.2 and CO. Stream 26 can comprise at least about 40%, or at least about 50%, or at least about 60% or at least about 85% H.sub.2. Having the benefit of the disclosure of the present invention, it is seen that the CO content of stream 26 depends on operational and plant design objectives. On that basis, it is believed that stream 26 should comprise less than about 10% CO, or less than about 5% CO, or less than about 3% CO, or less than about 1% CO with the balance comprising other components such as CO.sub.2 and H.sub.2O. Any upper limit for the H.sub.2 content of stream 26 is considered to be limited only by the ability of technology to economically enrich stream 26 in H.sub.2. It is believed that using present technology, stream 26 can comprise up to about 90-95% H.sub.2.

    (19) Gas stream 26 is fed as an air-fuel combustor feedstream to air-fuel combustor means 45 of a known air-fuel gas turbine means comprising known turbine compressor section 39 and expansion section 40. As shown, working fluid air stream 43 is fed to compressor section 39. Compressed air stream 44 is fed to combustor means 45 wherein the compressed air and fuel gas stream 26 are mixed and combusted to form gas turbine working fluid 46. Working fluid 46 is then fed to expansion section 40 of the air-fuel gas turbine means wherein the working fluid expands, producing power which, in turn, drives electricity generator 29 and compressor section 39. Expanded exhaust 28 is then fed to known heat recovery steam generator means (HRSG) 31, wherein exhaust 28 indirectly heats a water stream to produce steam stream 42. The steam becomes the working fluid 42 which is fed to a known steam turbine system 32 that powers electricity generator 30. Condensed steam stream 41 is recycled back to the HRSG 31.

    (20) While known gas turbines typically burn carbonaceous fuels (e.g., natural gas or syngas) mixed with air to form a working fluid, processes in accordance with the present invention burn primarily H.sub.2 with substantially reduced percentages of CO.sub.2 and CO, and thus little or virtually no carbon dioxide is exhausted to the ambient environment in stream 32a. Reduction or elimination of the carbonaceous part of the separator means syngas feed stream enables a significant downsizing of the combined cycle power generation equipment by not having to burn the fraction of carbon contained in natural gas and syngas.

    EXAMPLES

    Example 1

    (21) Table 1 gives nonlimiting illustrative summary cases of potential approximate plant size reductions and therefore capital cost reductions due to the benefits of the invention when the separator means is a membrane. The summary cases correspond to two types of membrane separator means (membranes described in Examples 2 and 3 below), four separator means operating temperatures and two syngas sources. Table 2 is a representative material balance diagram explaining how savings were calculated.

    (22) TABLE-US-00001 TABLE 1 Respective plant size reductions according to membrane type, syngas source and operating temperature. Plant Red..sup.1 Plant Red..sup.2 Selec- Selec- sCO.sub.2 sCO.sub.2 Plant Red..sup.3 System Mbr.* Syngas Temp. tivity tivity cooler turbine Combined CO.sub.2 H.sub.2 Type Source ° C. H.sub.2/CO H.sub.2/CO.sub.2 Condenser and ASU Cycle Capture Recovery PI nat. gas 60.3 100.0 8.0 95.77% 72.36% 27.64% 91.3% 100.0% PI nat. gas 97.4 76.0 8.8 44.08% 32.97% 67.03% 98.4% 100.0% PI nat. gas 127.0 65.0 9.3 43.80% 32.79% 67.21% 98.3% 100.0% PI coal 60.3 100.0 8.0 63.73% 31.63% 68.37% 95.0% 100.0% PI coal 97.4 76.0 8.8 64.02% 31.99% 68.01% 95.0% 100.0% PI coal 127.0 65.0 9.3 63.57% 31.91% 68.09% 95.0% 100.0% PBI nat. gas 225.0 103.2 40.0 96.04% 72.44% 27.56% 95.0% 100.0% PBI coal 225.0 103.2 40.0 95.42% 48.16% 51.84% 95.0% 100.0% *PI = polyimide membrane and PBI = polybenzimidazole membrane .sup.1Plant size reductions for the sCO.sub.2 plant cooler, condenser and heat exchangers. .sup.2Plant size reductions for the air separation unit, sCO.sub.2 combustor and sCO.sub.2 turbine. .sup.3Plant size reduction for the air-fuel turbine, HRSG and steam turbine.

    Table 2

    (23) TABLE-US-00002 A B C D E F G H I  1 First CO-rich stream 3:  2 Membrane separator means: UBE polyimide combust.sup.3  3 Separator feedstream 1b: reformed natural gas to sCO.sub.2 to sCO.sub.2  4 Temperature: 60.33° C. scf scf  5 Super critical CO.sub.2 H.sub.2 recovery:  4.23% CO.sub.2 1.53 0.00  6 Combined cycle H.sub.2 recovery: 95.77% CO 20.80  20.80   7 Total system H.sub.2 recovery: 100.00%  CH.sub.4 0.86 0.86  8 Super critical CO.sub.2 capture: 91.32% Ar + N.sub.2 0.17 0.00  9 H.sub.2 2.78 2.78 10 Membrane feedstream 1b: H.sub.2O 0.37 0.00 11 scf combust.sup.1 cool.sup.2 26.52  24.44  12 CO.sub.2  2.63  0.00  0.00 13 CO 21.89 21.89  0.00 Second H.sub.2-rich stream 26: 14 CH.sub.4  0.88  0.88  0.00 combust.sup.4 cool.sup.5 15 Ar + N.sub.2  0.18  0.00  0.00 to CC to CC to CC 16 H.sub.2 65.66 65.66 65.66 scf scf scf 17 H.sub.2O  8.76  0.00  8.76 CO.sub.2 1.10 0.00 0.00 18 100.00  88.43 74.42 CO 1.09 1.09 0.00 19 CH.sub.4 0.02 0.02 0.00 20 Ar + N.sub.2 0.01 0.00 0.00 21 H.sub.2 62.88  62.88  62.88  22 H.sub.2O 8.39 0.00 839 23 73.48  63.99  71.27  .sup.1Combustible components in membrane feedstream 1b in FIG. 2 .sup.2Hydrogen and water components in membrane feedstream 1b in FIG. 2 .sup.3Combustible components in first CO-rich stream 3 in FIG. 2 to super critical CO2 stream 4 in FIG. 2 .sup.4Combustible components in second H.sub.2-rich stream 26 in FIG. 2 to combined cycle (CC) .sup.5Hydrogen and water components in second H.sub.2-rich stream 26 in FIG. 2 to combined cycle (CC)

    Plant Size Reductions

    (24) ASU & sCO.sub.2 power cycle plant size reduction=H23/C18=72.36%

    (25) Combined cycle (CC) plant size reduction=I11/C18=27.64%

    (26) Cooling/condenser/heat exchanger plant size reduction=I23/D18=95.77%

    Example 2

    Table 3

    (27) TABLE-US-00003 UBE Industries, Ltd., Polyimide Membrane H.sub.2 and CO Permeability and Selectivity vs. Temperature Data 1000T.sup.−1(K).sup.−1 selectivity GPU.sup.1 GPU.sup.1 GPU.sup.2 GPU.sup.2 Barrer.sup.3 Barrer.sup.3 ° F. x ° C. H.sub.2/CO H.sub.2 CO H.sub.2 × 10.sup.−6 CO × 10.sup.−6 H.sub.2 (×10.sup.−10) CO (×10.sup.−10) 77.91 3.35 25.51 134.78 0.31 0.002 4.135 0.031 4.135 0.0307 140.60 3.00 60.33 100.00 0.80 0.008 10.671 0.107 10.671 0.1067 207.27 2.70 97.37 75.95 1.80 0.024 24.010 0.316 24.010 0.3161 260.60 2.50 127.00 65.00 2.60 0.040 34.681 0.534 34.681 0.5336 212.00 2.68 100.00 74.88 UBE membrane maximum operating temperature is 100° C. .sup.1P/I (mm.sup.3/s/m.sup.2/Pa) Selectivity for 100° C. calculated by equation .sup.2P/I (cm.sup.3/s/cm.sup.2/cm Hg) y = 0.0046x.sup.2 − 1.3818x + 166.98 .sup.3P (cm.sup.3-cm)/s/cm.sup.2/cm Hg) when I = 0.0001 cm membrane thickness Source: Polyimide Membranes - Applications, Fabrication, and Properties by Haruhiko Ohya, Vladislav V. Kudryavtsev and Svetlana I. Semenova (Jan. 30, 1997) page 250 Gordan and Breach Science Publishers S.A., Emmaplein 5, 107SAW Amsterdam, The Netherlands Pg. 250, FIG. 6.7, Temperature of pure gas permeation rates through asymmetric polyimide hollow fiber membrane . . . by UBE Industries, Ltd. (From Haraya, K. et al., Gas Separation and Purification, 1, 4 (1987))

    (28) UBE Industries, Ltd., Polyimide Membrane H.sub.2 and CO Permeability and Selectivity vs. Temperature Data

    (29) TABLE-US-00004 TABLE 4 UBE Industries, Ltd., Polyimide Membrane H.sub.2 and CO.sub.2 Permeability and Selectivity vs. Temperature Data 1000T.sup.−1(K).sup.−1 selectivity GPU.sup.1 GPU.sup.1 GPU.sup.2 GPU.sup.2 Barrer.sup.3 Barrer.sup.3 ° F. x ° C. H.sub.2/CO.sub.2 H.sub.2 CO.sub.2 H.sub.2 × 10.sup.−6 CO × 10.sup.−6 H.sub.2 (×10.sup.−10) CO (×10.sup.−10) 77.91 3.35 25.51 6.89 0.31 0.045 4.135 0.600 4.135 0.6003 140.60 3.00 60.33 8.00 0.80 0.100 10.671 1.334 10.671 1.3339 207.27 2.70 97.37 8.82 1.80 0.204 24.010 2.721 24.010 2.7212 260.60 2.50 127.00 9.29 2.60 0.280 34.681 3.735 34.681 3.7349 212.00 2.68 100.00 9.97 UBE membrane maximum operating temperature is 100° C. .sup.1P/I (mm.sup.3/s/m.sup.2/Pa) Selectivity for 100° C. calculated by equation .sup.2P/I (cm.sup.3/s/cm.sup.2/cm Hg) .sup.3P (cm.sup.3-cm)/s/cm.sup.2/cm Hg) when I = 0.0001 cm membranw thickness Source: Polyimide Membranes - Applications, Fabrication, and Properties by Haruhiko Ohya, Vladislav V. Kudryavtsev and Svetlana I. Semenova (Jan. 30, 1997) page 250 Gordan and Breach Science Publishers S.A., Emmaplein 5, 107SAW Amsterdam, The Netherlands, Pg. 250, FIG. 6.7, Temperature of pure gas permeation rates through asymmetric polyimide hollow fiber membrane . . . by UBE Industries, Ltd. (From Haraya, K. et al., Gas Separation and Purification, 1, 4 (1987))
    In Tables 3 and 4, UBE Industries, Ltd. (UBE) is a Japanese multinational manufacturer of polyimide hydrogen separation membranes and have supplied membranes globally to industry for many years.
    H.sub.2 and CO permeability values versus temperature are presented in Table 3 and H.sub.2 and CO.sub.2 permeability values are presented in Table 4. The GPU unit, also known as permeance, is a pressure normalized steady state flux for a given membrane thickness and is given as volumetric flow per unit area per second per unit differential pressure across the membrane. The Barrer unit, also known as permeability, is a steady state flux normalized for both membrane thickness and pressure differential across the membrane and is given as volumetric flow times membrane thickness, per unit area per second per unit differential pressure across the membrane. Selectivity is the ratio of the respective GPU or Barrer units, e.g., H.sub.2/CO selectivity at 97.37° C. of 75.95 is determined by following ratio:
    24.1010 cm.sup.3/cm.sup.2/s/cm Hg divided by 0.316.sup.3/cm.sup.2/s/cm Hg=75.95
    It can be seen from the Tables 3 and 4 that H.sub.2/CO selectivity is more sensitive to temperature change than H.sub.2/CO.sub.2 selectivity. The maximum operating temperature for the UBE polyimide membrane is 150° C. Operating an UBE polyimide membrane separator means at the maximum temperature of 150° C. increases overall system thermal efficiency. Further, the trendline equation in Table 3 calculates a H.sub.2/CO selectivity of 63.33 at 150° C., a selectivity reduction of only 2.60% compared with 127° C. Furthermore, based a trendline algorithm for temperature vs. H.sub.2 GPU values in Table 3, H.sub.2 GPU is increased by about 30% at 150° C. compared with 127° C.

    Example 3

    (30) TABLE-US-00005 TABLE 5 SRI International, Polybenzimidazole (PBI) Membrane H.sub.2, CO and CO.sub.2 Permeability and Selectivity vs. Temperature Data GPU.sup.1 GPU.sup.1 Barrer.sup.2 Barrer.sup.2 selectivity H.sub.2 × CO × H.sub.2 CO ° F. ° C. H.sub.2/CO 10.sup.−6 10.sup.−6 (×10.sup.−10) (×10.sup.−10) 437.00 225.00 103.0 80.0 0.775 80.0 0.775 .sup.1P/I (cm3/s/cm2/cm Hg) .sup.2P (cm.sup.3 − cm)/s/cm.sup.2/cm Hg) when I = 0.0001 cm membrane thickness GPU.sup.1 GPU.sup.1 Barrer.sup.2 Barrer.sup.2 selectivity H.sub.2 × CO.sub.2 × H.sub.2 CO.sub.2 ° F. ° C. H.sub.2/CO 10.sup.−6 10.sup.−6 (×10.sup.−10) (×10.sup.−10) 437.00 225.00  40.0 80.0 2.00 80.0 2.00 .sup.1P/I (cm3/s/cm2/cm Hg) .sup.2P (cm.sup.3 × cm)/s/cm.sup.2/cm Hg) when I = 0.0001 cm membrane thickness
    PBI DATA:
    The PBI data in Table 4 is available at: https://www.netl.doe.gov/sites/default/files/2017-12/2I-S-Jayaweera2-SRI-PBI-Hollow-Fiber-Membranes.pdf

    Example 4

    (31) TABLE-US-00006 TABLE 6 Non-limiting examples of a range of concentrations of the first separated CO-rich stream and the second separated H.sub.2-rich stream CO.sub.2 CO CH.sub.4 Ar/N.sub.2 H.sub.2 H.sub.2S H.sub.2O conc. conc. conc. conc. conc. conc. conc. PI membrane Reformed natural gas syngas Feed  2.6% 21.9% 0.9% 0.2% 65.7% 0.0%  8.8% First CO-rich stream at 60.33° C.  5.8% 78.4% 3.2% 0.7% 10.5% 0.0%  1.4% First CO-rich stream at 97.37° C.  5.9% 69.9% 2.9% 0.6% 18.3% 0.0%  2.4% First CO-rich stream at 127.00° C.  5.9% 64.9% 2.7% 0.5% 23.0% 0.0%  3.1% Second H.sub.2-rich stream at 60.33° C.  1.5%  1.5% 0.0% 0.0% 85.6% 0.0% 11.4% Second H.sub.2-rich stream at 97.37° C.  1.2%  1.6% 0.0% 0.0% 85.8% 0.0% 11.4% Second H.sub.2-rich stream at 127.00° C.  1.1%  1.6% 0.0% 0.0% 85.8% 0.0% 11.4% PI membrane Gasified coal syngasFeed 10.9% 28.5% 0.1% 1.2% 27.0% 0.6% 31.7% First CO-rich stream at 60.33° C. 15.3% 46.4% 0.2% 2.0% 16.2% 1.0% 19.0% First CO-rich stream at 97.37° C. 15.6% 46.3% 0.2% 2.0% 16.1% 1.0% 18.9% First CO-rich stream at 127.00° C. 15.6% 46.0% 0.2% 2.0% 16.2% 1.0% 19.0% Second H.sub.2-rich stream at 60.33° C.  4.1%  1.0% 0.0% 0.0% 43.7% 0.0% 51.3% Second H.sub.2-rich stream at 97.37° C.  3.8%  1.3% 0.0% 0.0% 43.7% 0.0% 51.3% Second H.sub.2-rich stream at 127.00° C.  3.6%  1.5% 0.0% 0.0% 43.7% 0.0% 51.3% PBI membrane Reformed natural gas syngas Feed  2.6% 21.9% 0.9% 0.2% 65.7% 0.0%  8.8% First CO-rich stream at 225° C.  8.6% 76.8% 3.2% 0.6%  9.5% 0.0%  1.3% Second H.sub.2-rich stream at 225° C.  0.4%  1.3% 0.0% 0.0% 86.7% 0.0% 11.6% PBI membrane Gasified coal syngasFeed 10.9% 28.5% 0.1% 1.2% 27.0% 0.6% 31.7% First CO-rich stream at 225° C. 23.7% 65.5% 0.2% 2.8%  2.9% 1.4%  3.5% Second H.sub.2-rich stream at 225° C.  1.6%  1.7% 0.0% 0.0% 44.4% 0.0% 52.1%
    Table 6 is a non-limiting illustration of membrane separator means performance which depends upon given operating conditions of syngas source, feed composition, membrane type and operating temperature. Accordingly, for the different operating conditions, CO concentration in the first CO-rich stream ranges from 46.0% to 78.4% and H.sub.2 concentration in the second H.sub.2-rich stream ranges from 43.7% to 86.7%%.