FLUE GAS

FIELD OF THE INVENTION

[0001] The invention relates to membrane-based gas separation processes, and specifically the concurrent separation of acidic gases, such as S0 ₂ , NO _x , and C0 ₂ , from combustion gases.

BACKGROUND OF THE INVENTION

[0002] Presented below is background information on certain aspects of the present invention as they may relate to technical features referred to in the summary of the invention, but not necessarily described in detail. The discussion below should not be construed as an admission as to the relevance of the information to the claimed invention or the prior art effect of the material described.

[0003] Combustion of many fuels, such as coal, petroleum coke, or municipal solid waste produces flue gas containing nitrogen, some oxygen, carbon dioxide, and 100 to 20,000 ppm of sulfur dioxide and up to 200 ppm of NO _x . Since the clean air act of 1990, the United States and other countries have controlled the emission of the most acidic gases: S0 ₂ , NO _x , and in some cases HCl and HF. In the last few years, emissions of C0 ₂ have also been the subject of research and regulation because of the contribution of C0 ₂ to global warming.

[0004] A simple block diagram of coal-burning power fitted with emission control equipment is shown in Figure 1.

[0005] Coal feed stream (101) and air stream (102) are combined in boiler (103) that produces high temperature steam used to drive a steam turbine. Because the coal contains 0.5 to 2% sulfur and up to 1% nitrogen, the flue gas, 104, produced contains C0 ₂ (typically 10-15 mol%), S0 ₂ (0.2 to 1 mol%), and as much as 1 ,000 ppm N0 ₂ . Almost all U.S. power plants have electrostatic preceptors (105) sometimes supplanted by bag house filters to control particulate emissions. U.S. coal power plants are also fitted with S0 ₂ /NO _x control systems (107) to remove S0 ₂ and N0 _X . C0 ₂ control systems (108) are installed on only one or two plants. The C0 ₂ control systems installed to date are based on amine absorption technology. Because amine absorbents react with S0 ₂ and NO _x to form inert salt precipitates, the amine systems installed to date are all positioned after the particulate and S0 ₂ O _x separating systems.

[0006] In many parts of the world, however, the power plants being operated are not fitted with S0 ₂ /NO _x separating systems and the flue gas emitted (109) contains high levels of C0 ₂ , S0 ₂ and NO _x . Thus, it would be beneficial to develop a separation process that was able to remove S0 ₂ , NO _x , and C0 ₂ concurrently in the same separation unit.

[0007] In the embodiments of the present invention, all of these components are removed concurrently with the C0 ₂ from the flue gas into a single concentrate stream. In this way, the costs of C0 ₂ , S0 ₂ and NO _x removal and final segregation are significantly reduced.

[0008] The embodiments of the invention are for coal power plant flue gas, which is the largest and most important flue-gas source, but the process can also be applied to other gas streams, including but not limited to those produced by burning petroleum, coke, catalysis regeneration in FCC crackers and refineries, or flue gas emitted in cement plants, steel mills, or by municipal solid waste incinerators.

SUMMARY OF THE INVENTION

[0009] The invention is a process for concurrently removing C0 ₂ and S0 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 C0 ₂ and S0 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 C0 ₂ and S0 ₂ over nitrogen and to CO2 and SO2 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 ₂ - and S0 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 CO2 and SO2;

(g) passing the second compressed gas stream to separation process that produces a stream enriched in CO and a stream enriched in SO ₂ .

BRIEF DESCRIPTION OF THE DRAWTNGS

[0010] Figure 1 is a schematic drawing of a basic power plant design not in accordance with the invention.

[0011] Figure 2 is a schematic drawing of a basic embodiment of the invention.

[0012] Figure 3 is a schematic drawing of the Holder Topsoe SNO _x process.

[0013] Figure 4 is a schematic drawing of a process that combines membrane separation with the

Wellman-Lord process.

[0014] Figure 5 is a schematic drawing of a low-temperature fractionation process to separate C0 ₂ and S0 ₂ /NO _x .

[0015] Figure 6 is a schematic drawing of a basic embodiment of the invention using a one-stage membrane unit to remove C0 ₂ , S0 ₂ and NO _x from flue gas

[0016] Figure 7 is a schematic drawing of a two-stage membrane process to remove CO ₂ , SO ₂ and ΝΟχ from flue gas, producing a concentrate stream that then goes to a CO ₂ /SO ₂ separation step.

[0017] Figure 8 is a schematic drawing of a two-step membrane process to remove CO2, SO2 and NO _x from flue gas producing a concentrated stream that is then separated into CO ₂ and SO ₂ NO ₂ streams.

DETAILED DESCRIPTION OF THE INVENTION [0018] The invention is a process for concurrently removing C0 ₂ and S0 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 C0 ₂ and S0 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 C0 ₂ and S0 ₂ over nitrogen and to C0 ₂ and S0 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 C0 ₂ - and S0 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 C0 ₂ and S0 ₂ ;

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

(g) passing the first permeate stream (or the second compressed gas stream , where appropriate) to a separation process that produces a stream enriched in C0 ₂ and a stream enriched in S0 ₂ .

[0019] A basic embodiment of the present invention is shown in Figure 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 C0 ₂ S0 ₂ and ΝΟχ 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. Patents 6,425,267, Baker et al., 6,648,944, Baker et al. and 9,005,335, Baker et al. [0020] 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 C0 ₂ , NO _x , SO _x separation step (210) via compressor (207) producing C0 ₂ concentrate stream (211) and S0 ₂ /NO _x concentrate stream (212).

[0021] Because the S0 ₂ and NO _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.

[0022] S0 ₂ and NO _x are both strong, acid gases and so wet or dry scrubbing can be used. In dry scrubbing, the reactive component is powdered CaCOs, which reacts

CaC0 ₃ (solid) + S0 ₂ (gas) -> CaS0 ₃ (solid) + C0 ₂ (gas) in wet scrubbing processes, the reactant is a Ca(OH) ₂ hydrated lime. In some cases, Na(OH) is used or Ca(OH) ₂ and Mg(OH) ₂ mixtures. The reaction is then

Na(OH) solid + S0 ₂ (gas)→ Na ₂ S0 ₃ (solid) + H ₂ 0 (liquid)

The CaSC can be further oxidized with air to produce CaS0 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.

[0023] Because the membranes process shown in Figure 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 S0 ₂ and NO _x concentration in the membrane concentration stream is a relatively linked process, so a process, such as the SNO _x process developed by Holder Topsoe, can be considered. A flow diagram of this process is shown in Figure 3.

[0024] The SNO _x process as used in this embodiment may include the following steps:

• Particulate removal (305);

• Compression (320); • Membrane separation unit (308) to produce a CO ₂ , S0 ₂ , NO _x concentrate stream (307) and a CO _2. S0 ₂ ,NO _x depleted flue gas vent stream (309);

• Catalytic reduction of NO _x by adding N¾ to the gas upstream SCR DeNO _x reactor (314);

• Catalytic oxidation of S0 ₂ to SO ₃ in oxidation reactor (315);

• Cooling of the gas to about 100°C in cooling unit (316), whereby the H ₂ SO4 is condensed in condenser (317) and can be withdrawn as concentrated sulfuric acid product stream (318); and

• Final concentration of the CO ₂ stream, (319) for use or sequestration.

[0025] 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.

[0026] In the SNO _x process shown in Figure 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). CCh _, S0 ₂ , NO _x , concentrate stream (307) is treated by heater (313) and the NO is removed by catalytically reacting with N¾ added to the gas (NO ₂ + NH ₃ → N ₂ + H2O) in catalytic reactor (314). The SO 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 ₂ SO ₄ formed can be removed as a valuable product stream (318). CO ₂ concentrate (319) can then be sent to final downstream purification step.

[0027] Another separation process, possible because of the relatively high SO2 and NO _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.

[0028] 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.

[0029] A diagram showing how the Wellman-Lord process could be combined with membrane separation of the present invention is shown in Figure 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 C0 ₂ S0 ₂ and NO _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 C0 ₂ , S0 ₂ and NO _x is treated with ammonia in DeNO _x catalytic reactor (414) and the NO _x is removed via the reaction NO _x + N¾ → N ₂ + H ₂ 0. Treated steam (425) is sent to reactor (420) where the S0 ₂ is then removed in reaction with a sodium sulfite solution to form sodium bisulfate by the reaction Na ₂ SC>3 + S0 ₂ + H ₂ 0→ 2NaHS0 ₃ , which further reacts to form sodium pyrosulfite.

[0030] C0 ₂ stream (419), free of NO _x and S0 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 S0 ₂ absorption reaction is reversed, producing concentrated S0 ₂ stream (422) and regenerated sodium sulfite stream (426), which is recycled back to the reactor (420).

[0031] Another separation process that may be used in this step is the LICONOX® (Linde Cold DeNO _x ) process. LICONOX is used for the reduction NO _x (NO and N0 ₂ ) SO _x in a flue gas from an oxyfuel power plant. [0032] The C0 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.

[0033] The S0 ₂ contained in the S0 ₂ concentrate stream can also be used, for example, to make sulphuric acid.

[0034] A final separation process is fractional condensation of the SO ₂ and NO _x streams. A process of this type is shown in Figure 5. The C0 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 ₂ and NO _x are considerably more condensable than CO 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, SO2 and NO _x components are removed as liquid condensate (512) while the CO ₂ and other light gases stripped of the bulk of the S0 ₂ and NO _x are removed as overhead vapor (511).

EXAMPLES

Example 1 : Embodiment of Figure 5

[0035] An example calculation to show the efficacy of the approach described in Figure 5 is shown in Table 1. Stream (507) contains about 80% C0 ₂ , 1% S0 ₂ and 0.1% NO _x . After fractionating in a ten-stage column, the bottom liquid product containing 97% of the SO ₂ and essentially all of the NO _x is removed as a liquid for conversion to sulfuric acid or other product, while the C0 ₂ concentrates stream containing 89% of the original CO2 content is ready for final fraction and sequestration or use. Table 1

[0036] For this process to be successful, membranes are required that selectivity permeate C0 ₂ , S0 ₂ and NO _x and are stable in the pressure of these components. We have found a number of membranes that meet this requirement.

[0037] 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 C0 ₂ , N0 ₂ S0 ₂ , and relatively impermeable to other gases, such as oxygen and nitrogen. Typical selectivities that are possible with flue gas are:

S0 ₂ / ₂ : 50-100

C0 ₂ N ₂ : 20-50

0 ₂ /N ₂ : 2.

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 ₂ over nitrogen, SO ₂ and N0 ₂ because they are more condensable than C0 ₂ and have even higher selectivities over nitrogen. Typically S0 ₂ and NO _x are 2 to 3 times more permeable than C0 ₂ . This means that a membrane process designed to remove, for example 50% of the C0 ₂ from the flue gas stream will generally remove 70 to 80% of the S0 ₂ and N0 ₂ at the same time.

[0038J A number of membrane processes to separate C0 ₂ from flue gas have been suggested. These processes, if fitted with the right membrane that permeate NO _x and SO2, as well as CO2, could be used in the total process. Examples of certain embodiments of potential process designs are shown below in Figures 6-8

Example 2: Embodiment of Figure 6

[0039] A calculation was performed to model the performance of the process of the invention shown in Figure 6, which shows a simple one-stage process. Vacuum operation is generally preferred because less energy is used. Generally, they are most economical at C0 ₂ removals from flue gas of less than 60% In the one-stage membrane process shown in Figure 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 ₂ , SO ₂ , Οχ concentrate stream (607) from flue gas (604). This design is best used for partial removal of CO ₂ from flue gas, that is removal of about 50% of the CO2 content. Such partial removal is useful since it reduces overall C0 ₂ emissions in emitted gas (609) to the atmosphere from 800g CO ₂ KWe of electricity produced to about 400g C02/KWe of electricity produced, which is about the same level of CO 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 CO2 from the feed flue gas (604) producing a concentrate in which the CO ₂ concentration is enriched from 15% to 73%. At the same time, the membrane removes 76% of the SO2 and NO _x into the C0 ₂ , S0 ₂ , NO _x concentrate permeate stream (607) enriching the S0 ₂ concentration from 1.0% to 7.5% and the Οχ concentration from 0.1% to 0.75%. Final separation of the CO ₂ , SO ₂ , NO _x concentrate stream (607) into S0 ₂ and NO _x stream (612) and C0 ₂ stream (611) by fractionating column (610) described earlier in Figure 5 (525) is far easier than treating raw flue gas.

Table 2

[0040] The membrane used for this process has a C0 ₂ permeance of 1,000 gpu, an S0 ₂ permeance of 3,000 gpu, an NO _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 Figure 7

[0041] Figure 7 is a schematic of a two-stage removal, also most economical at C0 ₂ removals of 60% or less. The two-stage process, by twice concentrating the C0 ₂ / S0 ₂ /NO _x stream, produces a small volume of very concentrated gas that is very economically treated by the Wellman-Lord process, for example. In Figure 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 C0 ₂ , S0 ₂ , and NO _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 C0 ₂ concentrate stream (711) and an S0 ₂ /NO _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 Figure 7 is shown in Table 3. The membrane used has the same properties as that used in the example shown in Figure 6. By using two sequential membrane stages, the concentration of C0 ₂ , S0 ₂ and NO _x in the final second stage concentrate can be increased. This reduces the size and cost of the final of C0 ₂ , S0 ₂ and NO _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 3

[0042] Another membrane separation process that can be used is the MTR membrane contactor design shown in Figure 8. This design is described in U.S. Patents 8,016,923, Baker et al., and 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 C0 ₂ , S0 ₂ , NO _x concentrated permeate stream that has one-tenth of the volume of the flue gas stream. Downstream removal of NO _x and end- stage separation of CO ₂ and S0 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 ₂ , SO ₂ , and NO _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 ₂ , S0 ₂ , and NO _x concentrate stream (807) is produced. Typically about 50 to 60% of the CO 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 CO2, SO ₂ , and NO _x present in feed stream (827) permeates into the air stream (802). There is also some permeation of oxygen from air stream (802) into flue gas 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 ₂ , SO2, and NO _x in stream (802) that eventually becomes combination air to boiler stream (829). This increases the CO ₂ , SO ₂ , and NO _x content in flue gas (804) making the separation process easier while depleting the concentration of these components in the gas finally emitted (809).