SEPARATION AND CO-CAPTURE OF CO2 AND SO2 FROM COMBUSTION PROCESS FLUE GAS

Abstract

The present invention relates to a process for concurrently removing CO.sub.2 and SO.sub.2 from flue gas produced by a combustion process, comprising: (a) performing a combustion process by combusting a fuel and air in a combustion apparatus, thereby creating an exhaust stream comprising CO.sub.2 and SO.sub.2; (b) compressing the exhaust stream in a first compression step, thereby producing a first compressed gas stream; (c) providing a first membrane having a feed side and a permeate side, and being selectively permeable to CO.sub.2 and SO.sub.2 over nitrogen and to CO.sub.2 and SO.sub.2 over oxygen; (d) passing at least a portion of the first compressed gas stream across the feed side; (e) withdrawing from the feed side a CO.sub.2- and SO.sub.2-depleted residue stream; (f) withdrawing from the permeate side at a lower pressure than the first compressed gas stream, a first permeate stream enriched in CO.sub.2 and SO.sub.2; (g) passing the first permeate stream to a separation process that produces a stream enriched in CO.sub.2 and a stream enriched in SO.sub.2.

Claims

1. A process for concurrently removing CO.sub.2 and SO.sub.2 from flue gas produced by a combustion process, comprising: (a) performing a combustion process by combusting a fuel and air in a combustion apparatus, thereby creating an exhaust stream comprising CO.sub.2 and SO.sub.2; (b) compressing the exhaust stream in a first compression step, thereby producing a first compressed gas stream; (c) providing a first membrane having a feed side and a permeate side, and being selectively permeable to CO.sub.2 and SO.sub.2 over nitrogen and to CO.sub.2 and SO.sub.2 over oxygen; (d) passing at least a portion of the first compressed gas stream across the feed side; (e) withdrawing from the feed side a CO.sub.2- and SO.sub.2-depleted residue stream; (f) withdrawing from the permeate side at a lower pressure than the first compressed gas stream, a first permeate stream enriched in CO.sub.2 and SO.sub.2; (g) passing the first permeate stream to a separation process that produces a stream enriched in CO.sub.2 and a stream enriched in SO.sub.2.

2. The process of claim 1, wherein between steps (f) and (h) there is a further step (f) of compressing the first permeate stream in a second compression step.

3. The process of claim 1, wherein the exhaust stream comprises flue gas from a coal-fired power plant.

4. The process of claim 1, wherein the separation process is a Ca(OH).sub.2, Na(OH) scrubbing step.

5. The process of claim 1, wherein the separation step is an absorption process.

6. The process of claim 5, wherein the absorption process is a Wellman-Lord process.

7. The process of claim 1, wherein volume of the first permeate stream is less than about one-fifth of the volume of the exhaust stream

8. The process of claim 1, wherein the exhaust stream further comprises NO.sub.x.

9. The process of claim 8, wherein the first membrane is also selectively permeable to NO.sub.x over nitrogen and to NO.sub.x over oxygen.

10. The process of claim 9, wherein the stream enriched in SO.sub.2 is also enriched in NO.sub.x.

11. The process of claim 1, wherein the exhaust stream further comprises particulate matter.

12. The process of claim 11, further comprising the step of removing the particulate matter from the exhaust gas in a particulate removal step prior to step (b).

13. The process of claim 1 further comprising the steps of: (i) providing a second membrane having a feed side and a permeate side, and being selectively permeable to CO.sub.2, SO.sub.2, and NO.sub.x over nitrogen and to CO.sub.2, SO.sub.2, and NO.sub.x over oxygen; (j) passing at least a portion of the vent stream across the feed side; (k) passing air, oxygen-enriched air, or oxygen as a sweep stream across the permeate side; (l) withdrawing from the feed side a CO.sub.2-depleted vent stream; (m) withdrawing from the permeate side a second permeate comprising oxygen and carbon dioxide; and (n) passing the second permeate stream to step (a) as at least part of the air used in step (a).

14. A process for concurrently removing CO.sub.2 and SO.sub.2 from flue gas produced by a combustion process, comprising: (a) performing a combustion process by combusting a of a fuel and air in a combustion apparatus, thereby creating an exhaust stream comprising CO.sub.2 and SO.sub.2; (b) compressing the exhaust stream in a first compression step, thereby producing a first compressed gas stream; (c) providing a first membrane having a feed side and a permeate side, and being selectively permeable to CO.sub.2 and SO.sub.2 over nitrogen and to CO.sub.2 and SO.sub.2 over oxygen; (d) passing at least a portion of the first compressed gas stream across the feed side; (e) withdrawing from the feed side a CO.sub.2- and SO.sub.2-depleted vent stream; (f) withdrawing from the permeate side a first permeate stream at a lower pressure than the feed side pressure enriched in CO.sub.2 and SO.sub.2; (g) compressing the first permeate stream in a second compression step, thereby producing a second compressed gas stream; (h) providing a second membrane having a feed side and a permeate side, and being selectively permeable to CO.sub.2 and SO.sub.2 over nitrogen and to CO.sub.2 and SO.sub.2 over oxygen; passing at least a portion of the second compressed gas stream across the feed side; (j) withdrawing from the feed side a CO.sub.2- and SO.sub.2-depleted residue stream; (k) withdrawing from the permeate side a second permeate stream enriched in CO.sub.2 and SO.sub.2; (l) passing the residue stream back to a point in the process upstream of step (c); (m) compressing the second permeate stream in a third compression step, thereby producing a third compressed gas stream; and (n) passing the third compressed gas stream to separation process that produces a stream enriched in CO.sub.2 and a stream enriched in SO.sub.2.

15. The process of claim 14, wherein the exhaust stream comprises flue gas from a coal-fired power plant.

16. The process of claim 14, wherein the separation process is a Ca(OH).sub.2, Na(OH) scrubbing step.

17. The process of claim 14, wherein the separation step is an absorption process.

18. The process of claim 17, wherein the absorption process is a Wellman-Lord process.

19. The process of claim 14, wherein volume of the second permeate stream is less than about one-tenth of the volume of the exhaust stream

20. The process of claim 14, wherein the exhaust stream further comprises NO.sub.x.

21. The process of claim 20, wherein the first membrane is also selectively permeable to NO.sub.x over nitrogen and to NO.sub.x over oxygen.

22. The process of claim 21, wherein the stream enriched in SO.sub.2 is also enriched in NO.sub.x.

23. The process of claim 14, wherein the exhaust stream further comprises particulate matter.

24. The process of claim 23, further comprising the step of removing the particulate matter from the exhaust gas in a particulate removal step prior to step (b).

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0018] FIG. 1 is a schematic drawing of a basic power plant design not in accordance with the invention.

[0019] FIG. 2 is a schematic drawing of a basic embodiment of the invention.

[0020] FIG. 3 is a schematic drawing of the Holder Topsoe SNO.sub.x process.

[0021] FIG. 4 is a schematic drawing of a process that combines membrane separation with the Wellman-Lord process.

[0022] FIG. 5 is a schematic drawing of a low-temperature fractionation process to separate CO.sub.2 and SO.sub.2/NO.sub.x.

[0023] FIG. 6 is a schematic drawing of a basic embodiment of the invention using a one-stage membrane unit to remove CO.sub.2, SO.sub.2 and NO.sub.x from flue gas

[0024] FIG. 7 is a schematic drawing of a two-stage membrane process to remove CO.sub.2, SO.sub.2 and NO.sub.x from flue gas, producing a concentrate stream that then goes to a CO.sub.2/SO.sub.2 separation step.

[0025] FIG. 8 is a schematic drawing of a two-step membrane process to remove CO.sub.2, SO.sub.2 and NO.sub.x from flue gas producing a concentrated stream that is then separated into CO.sub.2 and SO.sub.2/NO.sub.2 streams.

DETAILED DESCRIPTION OF THE INVENTION

[0026] The invention is a process for concurrently removing CO.sub.2 and SO.sub.2 from flue gas produced by a combustion process, comprising:

[0027] (a) performing a combustion process by combusting a fuel and air in a combustion apparatus, thereby creating an exhaust stream comprising CO.sub.2 and SO.sub.2;

[0028] (b) compressing the exhaust stream in a first compression step, thereby producing a first compressed gas stream;

[0029] (c) providing a first membrane having a feed side and a permeate side, and being selectively permeable to CO.sub.2 and SO.sub.2 over nitrogen and to CO.sub.2 and SO.sub.2 over oxygen;

[0030] (d) passing at least a portion of the first compressed gas stream across the feed side;

[0031] (e) withdrawing from the feed side a CO.sub.2- and SO.sub.2-depleted residue stream;

[0032] (f) withdrawing from the permeate side at a lower pressure than the first compressed gas stream, a first permeate stream enriched in CO.sub.2 and SO.sub.2;

optionally, compressing the first permeate stream in a second compression step to form a second compressed gas stream; and

[0033] (g) passing the first permeate stream (or the second compressed gas stream, where appropriate) to a separation process that produces a stream enriched in CO.sub.2 and a stream enriched in SO.sub.2.

[0034] A basic embodiment of the present invention is shown in FIG. 2. As in conventional power plants, coal feed stream (201) is burnt with air stream (202) in boiler (203) to produce high-pressure stream. The flue gas produced (204) is then treated with particulate removal unit (205). The gas is then sent to membrane separation unit (208) that removes the CO.sub.2 SO.sub.2 and NO.sub.x from the gas using a membrane separation step. The driving force to perform the membrane separation step can be provided by feed gas compressor/blower (213) and/or permeate vacuum pump (207). Typical pressures generated by the compressor/blower unit are in the range of 1.1 to 3 bara. The permeate vacuum pressure is typically in the range of 0.1 to 0.3 bara. The membrane separation unit (208) is shown as a single one-stage unit, but those skilled in the art will understand that, depending on the separation required, two-stage or two-step or combination processes may also be used. Such process designs are described in U.S. Pat. No. 6,425,267, Baker et al., U.S. Pat. No. 6,648,944, Baker et al. and U.S. Pat. No. 9,005,335, Baker et al.

[0035] Treated residue gas (214) can then be sent to the chimney for disposal as vent gas (209). Membrane permeate stream (215) is typically about 10-15% of the volume of the original flue gas and is then sent to downstream CO.sub.2, NO.sub.x, SO.sub.x separation step (210) via compressor (207) producing CO.sub.2 concentrate stream (211) and SO.sub.2/NO.sub.x concentrate stream (212).

[0036] Because the SO.sub.2 and NO.sub.x concentration in the treated flue gas is 5 to 20 times more concentrated than in the original flue gas, a number of low-cost separation processes (not practical when treating the total flue gas streams) can be used.

[0037] SO.sub.2 and NO.sub.x are both strong, acid gases and so wet or dry scrubbing can be used. In dry scrubbing, the reactive component is powdered CaCO.sub.3, which reacts

CaCO.sub.3 (solid)+SO.sub.2 (gas) CaSO.sub.3 (solid)+CO.sub.2 (gas)

in wet scrubbing processes, the reactant is a Ca(OH).sub.2 hydrated lime. In some cases, Na(OH) is used or Ca(OH).sub.2 and Mg(OH).sub.2 mixtures. The reaction is then

Na(OH) solid+SO.sub.2 (gas) Na.sub.2SO.sub.3 (solid)+H.sub.2O (liquid)

[0038] The CaSO.sub.3 can be further oxidized with air to produce CaSO.sub.4, which is more marketable as gypsum for wallboards. Flue gas separation with these processes is subject to scaling and precipitation of the gypsum reactant, and careful process system design is needed to minimize these issues. Acid gas scrubbing is a simple, reliable and relatively economical process, but the products of this process are of little value.

[0039] Because the membranes process shown in FIG. 2 produces a concentrated, relatively small permeate stream, a process that would not normally be economical if applied directly to flue gas can be used. The SO.sub.2 and NO.sub.x concentration in the membrane concentration stream is a relatively linked process, so a process, such as the SNO.sub.x process developed by Holder Topsoe, can be considered. A flow diagram of this process is shown in FIG. 3.

[0040] The SNO.sub.x process as used in this embodiment may include the following steps: [0041] Particulate removal (305); [0042] Compression (320); [0043] Membrane separation unit (308) to produce a CO.sub.2, 502, NO.sub.x concentrate stream (307) and a CO.sub.2, SO.sub.2, NO.sub.x depleted flue gas vent stream (309); [0044] Catalytic reduction of NO.sub.x by adding NH.sub.3 to the gas upstream SCR DeNO.sub.x reactor (314); [0045] Catalytic oxidation of SO.sub.2 to SO.sub.3 in oxidation reactor (315); [0046] Cooling of the gas to about 100 C. in cooling unit (316), whereby the H.sub.2SO.sub.4 is condensed in condenser (317) and can be withdrawn as concentrated sulfuric acid product stream (318); and [0047] Final concentration of the CO.sub.2 stream, (319) for use or sequestration.

[0048] The final cooling/condensation step often uses combustion air to the boiler as the heat sink, which significantly increases the energy efficiency of the process.

[0049] In the SNO.sub.x process shown in FIG. 3, coal feed stream (301) is burnt with air stream (302) in boiler (303) to produce high-pressure stream. The flue gas produced (304) is then treated with particulate removal unit (305). The gas is then sent to membrane separation unit (308). CO.sub.2, SO.sub.2, NO.sub.x, concentrate stream (307) is treated by heater (313) and the NO.sub.x is removed by catalytically reacting with NH.sub.3 added to the gas (NO.sub.2+NH.sub.3.fwdarw.N.sub.2+H.sub.2O) in catalytic reactor (314). The SO.sub.2 is then oxidized to SO in oxidation reactor (315), which then reacts with the water vapor present. This reaction releases a good deal of heat, but when the gas is cooled the H.sub.2SO.sub.4 formed can be removed as a valuable product stream (318). CO.sub.2 concentrate (319) can then be sent to final downstream purification step.

[0050] Another separation process, possible because of the relatively high SO.sub.2 and NO.sub.x concentration in the gas to be treated is the Wellman-Lord sodium sulfite absorption process. The Wellman-Lord process is a regenerable process to remove sulfur dioxide from the flue gas concentrate without creating a throwaway sludge product as produced by the lime precipitation process. In the Wellman Loral process, sulfur dioxide in the concentrate gas is absorbed in a sodium sulfite solution in water forming sodium bisulfite; other components of flue gas are not absorbed. After lowering the temperature, the bisulfite is converted to sodium pyrosulfite, which precipitates.

[0051] Upon heating, the two previously described chemical reactions are reversed, sodium pyrosulfite is converted to a concentrated stream of sulfur dioxide and sodium sulfite. The sulfur dioxide can be used for further reactions (e.g., the production of sulfuric acid), and the sulfite is reintroduced into the process.

[0052] A diagram showing how the Wellman-Lord process could be combined with membrane separation of the present invention is shown in FIG. 4. Coal stream (401) is burnt with air stream (402) in boiler (403) to produce a high pressure stream. The flue gas produced (404) is then, treated with a particulate removal unit (405). The gas is then sent to a membrane separation step in membrane separation unit (408), that removes the CO.sub.2SO.sub.2 and NO.sub.x from the gas. The driving force to perform the membrane separation step can be provided by a feed gas compressor/blower (423) or a permeate-side vacuum pump, (not shown). Membrane permeate stream (424) containing CO.sub.2, SO.sub.2 and NO.sub.x is treated with ammonia in DeNO.sub.x catalytic reactor (414) and the NO.sub.x is removed via the reaction NO.sub.x+NH.sub.3.fwdarw.N.sub.2+H.sub.2O. Treated steam (425) is sent to reactor (420) where the SO.sub.2 is then removed in reaction with a sodium sulfite solution to form sodium bisulfate by the reaction Na.sub.2SO.sub.3+SO.sub.2+H.sub.2O2NaHSO.sub.3, which further reacts to form sodium pyrosulfite.

[0053] CO.sub.2 stream (419), free of NO.sub.x and SO.sub.2, is removed from the top of reactor (420). The bisulfite and pyrosulfite-containing solution is then sent to second heated reactor (421) where the SO.sub.2 absorption reaction is reversed, producing concentrated SO.sub.2 stream (422) and regenerated sodium sulfite stream (426), which is recycled back to the reactor (420).

[0054] Another separation process that may be used in this step is the LICONOX (Linde Cold DeNO.sub.x) process. LICONOX is used for the reduction NO.sub.x (NO and NO.sub.2) SO.sub.x in a flue gas from an oxyfuel power plant.

[0055] The CO.sub.2 removed from the processes of the invention may be used for a number of applications, including but not limited to sequestration, enhanced oil/natural gas recovery (EOR/ENGR), enhanced coal bed methane recovery (ECBMR), submarine extraction of methane from hydrate, or for use in chemicals and fuels.

[0056] The SO.sub.2 contained in the SO.sub.2 concentrate stream can also be used, for example, to make sulphuric acid.

[0057] A final separation process is fractional condensation of the SO.sub.2 and NO.sub.x streams. A process of this type is shown in FIG. 5. The CO.sub.2 concentrate gas (507) from the membrane separation is compressed in stages by compressor (523) to a pressure of 25 to 30 bar, and then cooled to about 15 to 20 C. by cooler (524). SO.sub.2 and NO.sub.x are considerably more condensable than CO.sub.2, nitrogen and oxygen that might be present in the gas, so when this gas is sent to fractionating column (525). The fractionating column is fitted with a partial condenser unit (532) at the top and a reboiler unit (533) at the bottom. The condensable, SO.sub.2 and NO.sub.x components are removed as liquid condensate (512) while the CO.sub.2 and other light gases stripped of the bulk of the SO.sub.2 and NO.sub.x are removed as overhead vapor (511).

EXAMPLES

Example 1: Embodiment of FIG. 5

[0058] An example calculation to show the efficacy of the approach described in FIG. 5 is shown in Table 1. Stream (507) contains about 80% CO.sub.2, 1% SO.sub.2 and 0.1% NO.sub.x. After fractionating in a ten-stage column, the bottom liquid product containing 97% of the SO.sub.2 and essentially all of the NO.sub.x is removed as a liquid for conversion to sulfuric acid or other product, while the CO.sub.2 concentrates stream containing 89% of the original CO.sub.2 content is ready for final fraction and sequestration or use.

TABLE-US-00001 TABLE 1 SO.sub.2/NO.sub.x Concentrate Stream 507 Stream 511 Stream 512 Temp ( C.) 30 16 1 Pressure (bar) 1.0 30 30 Gas Composition (mol %) CO.sub.2 80.0 79.1 88.9 N.sub.2 15.1 16.7 0.0 O.sub.2 3.8 4.2 0.0 SO.sub.2 1.0 0.03 10.1 NO.sub.x 0.1 0.00005 1.0

[0059] For this process to be successful, membranes are required that selectivity permeate CO.sub.2, SO.sub.2 and NO.sub.x, and are stable in the pressure of these components. We have found a number of membranes that meet this requirement.

[0060] A preferred type of membrane that could be used is a composite membrane made from polar rubbery polymers, such as Pebax or Polaris membranes. Both of these polymers include blocks of polyethylene oxide in their structures that make the membranes very permeable to gases, such as CO.sub.2, NO.sub.2SO.sub.2, and relatively impermeable to other gases, such as oxygen and nitrogen. Typical selectivities that are possible with flue gas are:

SO.sub.2/N.sub.2: 50-100

NO.sub.x/N.sub.2: 50-100

CO.sub.2/N.sub.2: 20-50

O.sub.2/N.sub.2: 2.

[0061] This type of membrane is described, for example in papers by H. Lin and Freeman, J. Molec Struct, vol. 739, pp 57-74 (2005), and Lin, et al., Macromolecules, vol. 38, pp 8381-8393 (2005). Even more selective membranes can be used if needed, such as the membrane incorporating amine groups and working by facilitated transport, for example, Zhao, et al., J. Mater. Chem A. vol. 1, pp 246-249 (2013), Zou and Ho, J. Memb. Sci vol. 286, pp 310-321 2006), and Chen and Ho, J. memb. Sci. vol. 514, pp 376-384 (2016) In general, these polar rubbery membranes have good selectivities for CO.sub.2 over nitrogen, SO.sub.2 and NO.sub.2 because they are more condensable than CO.sub.2 and have even higher selectivities over nitrogen. Typically SO.sub.2 and NO.sub.x are 2 to 3 times more permeable than CO.sub.2. This means that a membrane process designed to remove, for example 50% of the CO.sub.2 from the flue gas stream will generally remove 70 to 80% of the SO.sub.2 and NO.sub.2 at the same time.

[0062] A number of membrane processes to separate CO.sub.2 from flue gas have been suggested. These processes, if fitted with the right membrane that permeate NO.sub.x and SO.sub.2, as well as CO.sub.2, could be used in the total process. Examples of certain embodiments of potential process designs are shown below in FIGS. 6-8.

Example 2: Embodiment of FIG. 6

[0063] A calculation was performed to model the performance of the process of the invention shown in FIG. 6, which shows a simple one-stage process. Vacuum operation is generally preferred because less energy is used. Generally, they are most economical at CO.sub.2 removals from flue gas of less than 60% In the one-stage membrane process shown in FIG. 6, coal feed stream (601) is burnt with air stream (602) in boiler (603) to produce high-pressure stream. The flue gas produced (604) is then treated with particulate removal unit (605). The gas is then sent to compressor (613) and then sent on to the single membrane separation unit (608), producing CO.sub.2, SO.sub.2, NO.sub.x concentrate stream (607) from flue gas (604). This design is best used for partial removal of CO.sub.2 from flue gas, that is removal of about 50% of the CO.sub.2 content. Such partial removal is useful since it reduces overall CO.sub.2 emissions in emitted gas (609) to the atmosphere from 800 g CO.sub.2/KWe of electricity produced to about 400 g CO.sub.2/KWe of electricity produced, which is about the same level of CO.sub.2 emissions from natural gas power turbines, a good target emission rate for a coal power plant. The performance of this type of one stage system is shown in Table 2. The membrane in the example calculation removes 50% of the CO.sub.2 from the feed flue gas (604) producing a concentrate in which the CO.sub.2 concentration is enriched from 15% to 73%. At the same time, the membrane removes 76% of the SO.sub.2 and NO.sub.x into the CO.sub.2, SO.sub.2, NO.sub.x concentrate permeate stream (607) enriching the SO.sub.2 concentration from 1.0% to 7.5% and the NO.sub.x concentration from 0.1% to 0.75%. Final separation of the CO.sub.2, SO.sub.2, NO.sub.x concentrate stream (607) into SO.sub.2 and NO.sub.x stream (612) and CO.sub.2 stream (611) by fractionating column (610) described earlier in FIG. 5 (525) is far easier than treating raw flue gas.

TABLE-US-00002 TABLE 2 Flue Gas Feed CO.sub.2 Depleted Gas CO.sub.2 Concentrate (604) (609) (607) Mass (Kg/h) 10,000 8,590 1,410 Pressure (Bar) 3.0 3.0 0.1 Gas Composition (Mol %) CO.sub.2 15.0 8.4 73.3 N.sub.2 80.9 88.2 17.2 O.sub.2 3.0 3.2 1.3 SO.sub.2 1.0 0.26 7.5 NO.sub.2 0.1 0.026 0.75

[0064] The membrane used for this process has a CO.sub.2 permeance of 1,000 gpu, an SO.sub.2 permeance of 3,000 gpu, an NO.sub.x permeance of 3,000 gpu, a nitrogen permeance of 25 gpu and an oxygen permeance of 50 gpu. Membranes with these permeances and selectivities are well known.

Example 3: Embodiment of FIG. 7

[0065] FIG. 7 is a schematic of a two-stage removal, also most economical at CO.sub.2 removals of 60% or less. The two-stage process, by twice concentrating the CO.sub.2/SO.sub.2/NO.sub.x stream, produces a small volume of very concentrated gas that is very economically treated by the Wellman-Lord process, for example. In FIG. 7, coal feed stream (701) is burnt with air stream (702) in boiler (703) to produce high-pressure steam. The flue gas produced (704) is then treated with particulate removal unit (705) and sent to a first-stage membrane separation unit (708). A CO.sub.2, SO.sub.2, and NO.sub.x concentrate stream (707) is sent to second stage membrane unit (728) and a retentate stream (730) is released as vent stream (729). The permeate from the second stage membrane separation unit (724) is sent to fractionating column (710) to produce a CO.sub.2 concentrate stream (711) and an SO.sub.2/NO.sub.x concentrate stream (712). The retentate (731) from the second stage membrane separation unit (728) is sent back to join the stream (732) entering the first stage membrane unit (708). An example calculation to illustrate the performance of the design shown in FIG. 7 is shown in Table 3. The membrane used has the same properties as that used in the example shown in FIG. 6. By using two sequential membrane stages, the concentration of CO.sub.2, SO.sub.2 and NO.sub.x in the final second stage concentrate can be increased. This reduces the size and cost of the final of CO.sub.2, SO.sub.2 and NO.sub.x separation step (710). Also because the second stage membrane separation unit (728) performs an additional stage of separation, the need for the first stage membrane separation unit (708) to perform a very good separation can be relaxed. This means instead of using compressor/blower (713) to increase the pressure of the gas to be treated to 2 to 3 bar, a simple 1:1 bar blower can be used. This increases the membrane area needed but substantially reduces the energy consumption of compressor/blower (713).

TABLE-US-00003 TABLE 3 First Second Flue Gas Membrane Membrane Treated Flue (704) Permeate (707) Permeate (724) Gas (709) Gas Pressure 1.1 0.1 0.1 1.9 (Bar) Gas Composition (mol %) CO.sub.2 15.0 66.5 88.0 8.5 N.sub.2 80.9 25.6 3.1 87.9 O.sub.2 3.0 1.86 0.43 3.2 SO.sub.2 1.0 5.5 7.7 0.40 NO.sub.2 0.1 0.55 0.77 0.040

[0066] Another membrane separation process that can be used is the MTR membrane contactor design shown in FIG. 8. This design is described in U.S. Pat. No. 8,016,923, Baker et al., and U.S. Pat. No. 8,025,715, Wijamns et al. The process is also described in a paper by Merkel et al, J. Memb. Sci. v359 (2010) pp. 126-139. It generally produces a CO.sub.2, SO.sub.2, NO.sub.x concentrated permeate stream that has one-tenth of the volume of the flue gas stream. Downstream removal of NO.sub.x and end-stage separation of CO.sub.2 and SO.sub.2 is then relatively economical. Coal feed stream (801) and air stream (829) are burnt in boiler (803) to make steam. The resulting flue gas (804), mostly consisting of nitrogen, also contains CO.sub.2, SO.sub.2, and NO.sub.x produced by the combustion process. This flue gas after particulate removal (805) is pressurized to 1.1 to 2 bara with compressor/blower (not shown) and sent to a two-step membrane separation process (808) and (826). In first membrane separation unit (808), a CO.sub.2, SO.sub.2, and NO.sub.x concentrate stream (807) is produced. Typically about 50 to 60% of the CO.sub.2 in flue gas (804) is removed in this step. Retentate gas from membrane unit (808) is then sent as feed stream (827) to second membrane separation unit (826). There may be a small pressure difference across membrane in unit (826) but most of the separation driving force is generated by flow of air (802) across the permeate side of the membrane. Because of the air flow, there is a concentration difference across the membrane and CO.sub.2, SO.sub.2, and NO.sub.x present in feed stream (827) permeates into the air stream (802). There is also some permeation of oxygen from air stream (802) into feed stream (827), but because the membrane is relatively impermeable to oxygen, this flow is small. The result of this operation is to strip much of the CO.sub.2, SO.sub.2, and NO.sub.x in stream (802) that eventually becomes combination air to boiler stream (829). This increases the CO.sub.2, SO.sub.2, and NO.sub.x content in flue gas (804) making the separation process easier while depleting the concentration of these components in the gas finally emitted (809).