Process and device for desulphurization and denitration of flue gas

Abstract

The invention discloses a process and device for desulfurization-denitration of a flue gas. A desulfurization-denitration solution is used in an absorption tower to absorb sulfur dioxide and/or nitrogen oxides from the flue gas or various combustion tail (waste) gases. The desulfurization-denitration solution with absorbed sulfur dioxide and/or nitrogen oxides releases the sulfur dioxide and/or nitrogen oxides by heating and/or gas stripping and/or vacuum regeneration in a regeneration tower. The released sulfur dioxide and/or nitrogen oxides are further concentrated into a sulfur dioxide and/or nitrogen oxide product with a higher purity in a concentration tower. The regenerated desulfurization-denitration solution is recycled for use. The process and device have a wide range of industrial applications, and can be used for desulfurization and/or denitration of flue gases, incineration gases, coke-oven gases, synthetic waste gases from dyestuff plants, pollutant gases discharged from chemical fiber plants and other industrial raw material gases or waste gases containing SOx.

Claims

1. A flue gas desulfurization-denitration process, comprising the following procedures: 1) afterheat recovery procedure: the temperature of the flue gas is lowered to below 50 C. in a heat exchange recovering way, and afterheat recovery is carried out; 2) desulfurization-denitration procedure: the cooled flue gas enters into an absorption tower, sulfur dioxide and/or nitrogen oxides therein are absorbed by a desulfurization-denitration solution, and the said desulfurization-denitration solution is a composite solution containing polyol and/or polymeric polyol; 3) regeneration procedure of desulfurization-denitration solution: in a regeneration tower, the desulfurization-denitration solution with absorbed sulfur dioxide and/or nitrogen oxides releases the sulfur dioxide and/or nitrogen oxides by ways of heating and/or gas stripping and/or vacuum regeneration, and the desulfurization-denitration solution after regeneration is recycled for use; 4) sulfur dioxide and/or nitrogen oxides concentration procedure: in a concentration tower, sulfur dioxide and/or nitrogen oxides released by the regeneration procedure of the desulfurization-denitration solution are concentrated into a product of sulfur dioxide and/or nitrogen oxides with a higher purity.

2. The said flue gas desulfurization-denitration process according to claim 1, characterized in that, a way of direct heat exchange recovery or a way of simultaneous indirect-direct heat exchange recovery is used by the afterheat recovery procedure.

3. The said flue gas desulfurization-denitration process according to claim 2, characterized in that, in the afterheat recovery procedure, the flue gas is brought into direct contact with a heat storage fluid for heat exchange, and the circulation volume of the heat storage fluid is increased by providing one or more stages of internal circulation pumps.

4. The said flue gas desulfurization-denitration process according to claim 1, characterized in that, in the desulfurization-denitration procedure, the circulation volume of the desulfurization-denitration solution is increased by providing one or more stages of internal circulation pumps.

5. The said flue gas desulfurization-denitration process according to claim 1, characterized in that, the regeneration procedure of said desulfurization-denitration solution is specifically as follows: the desulfurization-denitration solution with absorbed sulfur dioxide and/or nitrogen oxides from the flue gas is a desulfurization-denitration rich solution, which is first subjected to indirect heat exchange with a desulfurization-denitration lean solution flowing out of the bottom of the regeneration tower, and is heated to above 90 C., and then enters from the upper end of the regeneration tower to desorb the sulfur dioxide and/or nitrogen oxides by heating and/or gas stripping and/or vacuum regeneration, and turns into the desulfurization-denitration lean solution, which flows out of the bottom of the regeneration tower, is subjected to heat exchange and cooling to below 50 C., and then is sent to the desulfurization-denitration procedure for recycle use.

6. The said flue gas desulfurization-denitration process according to claim 1, characterized in that, the sulfur dioxide and/or nitrogen oxides concentration procedure is specifically as follows: a mixed gas released by the regeneration procedure of desulfurization-denitration solution, which contains sulfur dioxide and/or nitrogen oxides, enters from the middle section of the concentration tower, contacts with the condensed water from the top of the concentration tower in a counter-current way to condense water vapor in the mixed gas, the mixed gas with water vapor removed flows out of the top of the concentration tower; water vapor enters from the bottom end of the concentration tower, contacts with the condensed water in a counter-current way, residual sulfur dioxide and/or nitrogen oxides in the condensed water are extracted by the water vapor, so as to turn the condensed water into distilled water, which flows out of the bottom of the concentration tower and is recycled.

7. A flue gas desulfurization-denitration device, comprising an afterheat recovery tower, an absorption tower, a regeneration tower and a concentration tower, wherein: The afterheat recovery tower: is used for heat exchange between the flue gas and a heat storage fluid, lowering the temperature of the flue gas to below 50 C., and carrying out afterheat recovery; The absorption tower: is used for direct contact of the cooled flue gas with a desulfurization-denitration solution, the desulfurization-denitration solution absorbs sulfur dioxide and/or nitrogen oxides in the flue gas and turns into a desulfurization-denitration rich solution, and then is discharged from the absorption tower; the said desulfurization-denitration solution is a composite solution containing polyol and/or polymeric polyol; The regeneration tower: is used for the desulfurization-denitration rich solution to desorb sulfur dioxide and/or nitrogen oxides by heating and/or gas stripping and/or vacuum regeneration and turn into a desulfurization-denitration lean solution, the desulfurization-denitration lean solution obtained by regeneration is sent back to the absorption tower for recycle use; The concentration tower: is used for removing, by condensation, water vapor from a mixed gas comprising sulfur dioxide and/or nitrogen oxides, which is released from the regeneration tower, sulfur dioxide and/or nitrogen oxides are condensed into a product of sulfur dioxide and/or nitrogen oxides with a higher purity.

8. The said flue gas desulfurization-denitration device according to claim 7, characterized in that, the said afterheat recovery tower is provided with one or more stages of internal circulation pumps for increasing the circulation volume of the heat storage fluid.

9. The said flue gas desulfurization-denitration device according to claim 7, characterized in that, the said absorption tower is provided with one or more stages of internal circulation pumps for increasing the circulation volume of the desulfurization-denitration solution.

10. The said flue gas desulfurization-denitration device according to claim 7, characterized in that, a heat exchanger is provided between the said absorption tower and the regeneration tower, and the desulfurization-denitration rich solution from the absorption tower and the desulfurization-denitration lean solution flowing out of the regeneration tower are subjected to indirect heat exchange through the heat exchanger.

Description

DESCRIPTION OF DRAWINGS

(1) FIG. 1 is a schematic diagram of the processes and devices for the flue gas desulfurization-denitration, the regeneration of the desulfurization-denitration solution and the concentration of sulfur dioxide and/or nitrogen oxides.

(2) In FIG. 1: 1 denotes a flue gas with a temperature below 50 C.; 2 denotes a booster fan; 3 denotes an absorption tower; 4 denotes a desulfurization-denitration internal circulation pump; 5 denotes a chimney; 6 denotes a flue gas after desulfurization-denitration; 7 denotes a desulfurization-denitration lean solution; 8 denotes a desulfurization-denitration rich solution; 9 denotes a rich solution pump; 10 denotes a desulfurization-denitration pump; 11 denotes a lean solution tank; 12 denotes a lean solution pump; 13 denotes a cooler; 14 denotes a heat exchanger; 15 denotes cooling water; 16 denotes hot water; 17 denotes a rich solution heater; 18 denotes a hot medium; 19 denotes a cold medium; 20 denotes a regeneration tower; 21 denotes a regenerated desorption gas; 22 denotes stripping steam; 23 denotes a concentration tower; 24 denotes a distilled water pump; 25 denotes a concentrated gas of sulfur dioxide and/or nitrogen oxides; 26 denotes distilled water. Each circled symbol in the figure has the following meanings: F.sub.1, F.sub.2, F.sub.3, and F.sub.4 denote the flow rate of the flue gas 1, the flow rate of the desulfurization lean solution 7, the flow rate of the steam entering into the regeneration tower 20, and the flow rate of the steam entering into the concentration tower 23, respectively; A.sub.1 denotes the composition of the flue gas 1; A.sub.2 denotes the composition of the flue gas after desulfurization-denitration 6; A.sub.3 denotes the composition of the concentrated gas of sulfur dioxide and/or nitrogen oxides 25; A.sub.4 denotes SO.sub.2 and NO content in the desulfurization-denitration rich solution 8; A.sub.5 denotes SO.sub.2 and NO content in the desulfurization-denitration lean solution 7 after regeneration; A.sub.6 denotes SO.sub.2 and NO content in the distilled water 26; P.sub.1 denotes a bottom pressure of the absorption tower 3; P.sub.2 denotes a top pressure of the absorption tower 3; P.sub.3 denotes the pressure in the regeneration tower 20; P.sub.4 denotes the pressure of steam 22; P.sub.5 denotes the pressure in the concentration tower 23; T.sub.1 denotes the temperature of the flue gas 1; T.sub.2 denotes the temperature of the flue gas after desulfurization-denitration 6; T.sub.3 denotes the temperature in the absorption tower 3; T.sub.4 denotes the temperature of the desulfurization-denitration lean solution 7 entering into the absorption tower 3; T.sub.5 denotes the temperature of the desulfurization-denitration lean solution 7 coming out of the cooler 13; T.sub.6 denotes the temperature of the desulfurization-denitration lean solution coming out of the heat exchanger 14; T.sub.7 denotes the temperature of the desulfurization-denitration rich solution entering into the heat exchanger 14; T.sub.8 denotes the temperature of the desulfurization-denitration lean solution entering into the heat exchanger 14; T.sub.9 denotes the temperature of the desulfurization-denitration rich solution coming out of the heat exchanger 14; T.sub.10 denotes the temperature at which the desulfurization-denitration rich solution enters into the regeneration tower 20; T.sub.11 denotes the temperature in the regeneration tower 20; T.sub.12 denotes the temperature of the regenerated desorption gas 21; T.sub.13 denotes the temperature of the steam 22; T.sub.14 denotes the temperature of the distilled water 26; T.sub.15 denotes the temperature in the concentration tower 23; and T.sub.16 denotes the temperature of the concentrated gas of sulfur dioxide and/or nitrogen oxides 25.

(3) FIG. 2 is a schematic diagram of the process and devices for the way of direct heat exchange recovery in the flue gas afterheat recovery.

(4) In FIG. 2: 27 denotes a flue gas with a temperature of 130-180 C. from a boiler; 28 denotes a flue gas with a temperature below 50 C. after the afterheat recovery; 29 denotes a direct heat exchange type afterheat recovery tower; 30 denotes an afterheat recovery internal circulation pump; 31 denotes a heat storage fluid which is hot; 32 denotes a heat storage fluid pump; 33 denotes a heat storage fluid settling tank; 34 denotes dusts and water; 35 denotes a heat storage fluid external circulation pump; 36 denotes a heat storage fluid radiator; 37 denotes a heat storage fluid cooler; 38 denotes a heat storage fluid which is cold; 39 denotes a medium to be heated; 40 denotes a heated medium; 41 denotes cooling water; and 42 denotes hot water.

(5) FIG. 3 is a schematic diagram of the process and devices for the way of heat recovery of simultaneous direct-indirect heat exchange in the flue gas afterheat recovery.

(6) In FIG. 3: 27 denotes a flue gas with a temperature of 130-180 C. from a boiler; 28 denotes a flue gas with a temperature below 50 C. after the afterheat recovery; 29 denotes a direct heat exchange type afterheat recovery tower; 30 denotes an afterheat recovery internal circulation pump; 31 denotes a heat storage fluid which is hot; 32 denotes a heat storage fluid pump; 33 denotes a heat storage fluid settling tank; 34 denotes dusts and water; 35 denotes a heat storage fluid external circulation pump; 37 denotes a heat storage fluid cooler; 38 denotes a heat storage fluid which is cold; 39 denotes a medium to be heated; 40 denotes a heated medium; 41 denotes cooling water; 42 denotes hot water; and 43 denotes a heat recoverer for indirect heat exchange of a flue gas.

DETAILED DESCRIPTION

(7) The flue gas desulfurization-denitration process and device of the present invention will be described below in conjunction with specific embodiments. The embodiments are intended to better illustrate the present invention, and should not be construed as limiting the claims of the present invention.

(8) The operation methods are as follows:

(9) The operation methods of the processes and devices for the flue gas desulfurization-denitration, the regeneration of the desulfurization-denitration solution and the concentration of sulfur dioxide and/or nitrogen oxides are shown in FIG. 1: A flue gas 1 with a temperature below 50 C. is pressurized by a booster fan 2 and then enters into an absorption tower 3 from the bottom. At the same time, a desulfurization-denitration lean solution 7 enters into the absorption tower 3 from the top. In the absorption tower 3, the flue gas 1 is brought into direct contact with the desulfurization-denitration lean solution 7. At this point, sulfur dioxide, some nitrogen oxides and carbon dioxide in the flue gas 1 are absorbed by the desulfurization-denitration lean solution 7. After sulfur dioxide, some nitrogen oxides and carbon dioxide are absorbed, the flue gas 1 is converted into a flue gas 6 after desulfurization-denitration, flows out of the top of the absorption tower 3, and is discharged through a chimney 5 into atmosphere, while the contents A.sub.1 and A.sub.2 of sulfur dioxide, nitrogen oxides and carbon dioxide in the flue gas 1 with a temperature below 50 C. and in the flue gas 6 after desulfurization-denitration are analyzed online. In order to increase the gas-liquid contact surface, extend the gas-liquid contact time, and improve the desulfurization efficiency, it is needed to increase the circulation volume of the desulfurization-denitration lean solution 7 in the absorption tower 3, this in turn requires increased number of stages (or units) of the desulfurization-denitration internal circulation pump 4 in the absorption tower 3, the increased number can be 0, or 1, or 2, or 3, or 4 . . . or n (n is a positive integer), and so on. The specific increased number of stages that is required can be determined by the sulfur dioxide and/or nitrogen oxides content of the flue gas after desulfurization-denitration at the top outlet of the absorption tower 3. The desulfurization-denitration lean solution 7 with absorbed sulfur dioxide, some nitrogen oxides and carbon dioxide is converted into a desulfurization-denitration rich solution 8, flows out of the bottom of the absorption tower 3, is pressurized by a rich solution pump 9, and is subjected to heat exchange in the shell pass of a heat exchanger 14 with the hot desulfurization-denitration lean solution 7 from the regeneration tower 20 to rise the temperature, and is then heated by a hot medium 18 (the hot medium may be a liquid with a temperature higher than 100 C., or may be a flue gas of 130 C.-170 C., or may be a water vapor with a temperature higher than 100 C.) to above 90 C. through a rich solution heater 17. The desulfurization-denitration rich solution 8 with a temperature higher than 90 C. enters into the regeneration tower 20 from the upper end, while a stripping steam 22 enters into the regeneration tower 20 from the bottom. In the regeneration tower 20, the desulfurization-denitration rich solution 8 with a temperature higher than 90 C. is brought into direct contact with the stripping steam 22. At this point, sulfur dioxide, some nitrogen oxides and carbon dioxide in the desulfurization-denitration rich solution 8 are desorbed, and enter into the stripping steam 22 to be mixed into a regenerated desorption gas 21, which flows out of the top of the regeneration tower 20. After releasing sulfur dioxide, some nitrogen oxides and carbon dioxide, the desulfurization-denitration rich solution 8 with a temperature higher than 90 C. is converted into the hot desulfurization-denitration lean solution 7 with a temperature higher than 90 C., which flows out of the bottom of the regeneration tower 20 and is subjected to heat exchange with the desulfurization-denitration rich solution 8 sent from the rich solution pump 9 in the tube pass and shell pass of the heat exchanger 14 to lower the temperature. The cooled desulfurization-denitration lean solution 7 moves along the tube pass of the cooler 13, is cooled to a normal temperature by the cooling water 15 in the shell pass, and is pressurized by a lean solution pump 12 and sent to a lean solution tank 11. Then, the desulfurization-denitration lean solution 7 in the lean solution tank 11 is pressurized by a desulfurization pump 10 and sent to the absorption tower 3 for desulfurization-denitration. The desulfurization-denitration solution is converted in such a way: in the absorption tower 3, the desulfurization-denitration lean solution 7 absorbs sulfur dioxide, some nitrogen oxides and carbon dioxide, and is converted into the desulfurization-denitration rich solution 8, whereas in the regeneration tower 20, the desulfurization-denitration rich solution 8 is heated, stripped and/or vacuum regenerated and again converted into the desulfurization-denitration lean solution 7, and the desulfurization-denitration lean solution 7 is again recycled for use, and it cycles continuously like this. The regenerated desorption gas 21 flowing out of the top of the regeneration tower 20 enters into a concentration tower 23 from the middle, and contacts with the distilled water condensed at the upper end of the concentration tower 23. In the condensation segment of the concentration tower 23, water vapor in the regenerated desorption gas 21 is condensed by the cooling water 15. A concentrated gas 25 of sulfur dioxide and/or nitrogen oxides comprised of non-condensing mixed gas of sulfur dioxide, nitrogen oxides, carbon dioxide, and the like flows out of the concentration tower 23, and can be recovered as a raw material gas. Simultaneously condensed distilled water contains sulfur dioxide and the like, continues flowing to the bottom of the concentration tower 23, and contacts with the stripping steam 22 from the bottom. Sulfur dioxide and other gases in the distilled water are stripped and desorbed by stripping steam 22, such that the condensed water is essentially free of sulfur dioxide and other gases, reaching a standard of distilled water for recovery 26, and is sent for recycle use by a distilled water pump 24. Throughout the process, the cooling water 15 is heated and converted into hot water 16, which can be recovered as make-up hot water for boiler. After releasing heat, the hot medium 18 is converted into a cold medium 19. The cold medium 19 may be distilled water or other liquid, which can be used in continuation to absorb heat, and then converted into the hot medium 18 for repeated use. When the cold medium 19 is a cooled flue gas, cooling is continued until the temperature of the flue gas 1 goes below 50 C.

(10) The process and operation methods of devices for the way of direct heat exchange recovery in the flue gas afterheat recovery are shown in FIG. 2: A flue gas 27 from a boiler with a temperature of 130-180 C. enters into a direct heat exchange type afterheat recovery tower 29 from the bottom, and directly contacts with a heat storage fluid which is cold 38 sprayed from the top of the tower for direct heat exchange, while the flue gas 27 with a temperature of 130-180 C. from the boiler is cooled and converted into a flue gas 28 with a temperature below 50 C., and discharged from the top of the direct heat exchange type afterheat recovery tower 29. In order to increase the gas-liquid contact area, extend the gas-liquid contact time, and improve the heat exchange effect, it is needed to increase the circulation volume of the heat storage fluid in the direct heat exchange type afterheat recovery tower 29, this in turn needs to increase the number of stages (or units) of the afterheat recovery internal circulation pump 30 in the direct heat exchange type afterheat recovery tower 29, the increased number of the stages (or units) of the afterheat recovery internal circulation pump 30 can be 0, or 1, or 2, or 3, or 4 . . . or n (n is a positive integer), the specific increased number of stages that is required can be determined by the temperature of the flue gas 28 discharged from the top of the direct heat exchange type afterheat recovery tower 29. In the direct heat exchange type afterheat recovery tower 29, the heat storage fluid which is cold 38 absorbs heat of the flue gas 27 and is then converted into a heat storage fluid which is hot 31, its temperature is close to or below the temperature of the flue gas 27. At the same time, the heat storage fluid which is cold 38 will also adsorb and enrich HCl, HF, and tiny dusts (including water-soluble and water-insoluble, namely polar and nonpolar tiny particles, such particles are generally referred to as PM100 and/or PM50 and/or PM2.5, and the like) in the flue gas 27. Additionally, some water vapor in the flue gas 27 will be condensed into water, mixed together in the heat storage fluid which is hot 31, and discharged from the bottom of the direct heat exchange type afterheat recovery tower 29, sent to a heat storage fluid settling tank 33 by a heat storage fluid pump 32 for settling. Dusts containing HCl and HF as well as water 34 are separated, and discharged from the bottom of the heat storage fluid settling tank 33. After removal of dusts and water, the heat storage fluid which is hot 31 is pressurized by a heat storage fluid external circulation pump 35 and sent to a heat storage fluid radiator 36. In the heat storage fluid radiator 36, most of the heat is transferred to a medium to be heated 39, and after absorbing the heat, the medium to be heated 39 becomes a heated medium 40, and is used as a heat source for heat recovery. After releasing some heat, the heat storage fluid which is hot 31 enters into a heat storage fluid cooler 37 to be cooled by cooling water 41 to a normal temperature, and is converted into the heat storage fluid which is cold 38, which enters into the direct heat exchange type afterheat recovery tower 29 for repeated heat absorption. At the same time, cooling water 41 absorbs heat and is then converted into hot water 42, wherein the heat can be recovered for use.

(11) The process and operation methods of devices for the way of heat recovery of simultaneous direct-indirect heat exchange in the flue gas afterheat recovery are shown in FIG. 3: A flue gas 27 from a boiler with a temperature of 130-180 C. enters into a flue gas indirect heat exchange type heat recoverer 43, and by way of indirect heat exchange, some heat is absorbed by a medium to be heated 39, which is then converted into a heated medium 40. The temperature of the heated medium 40 is close to is close to but lower than the temperature of the flue gas 27 with a temperature of 130-180 C. from a boiler. The heated medium 40 can be recovered as a heat source. After releasing some heat, the flue gas 27 enters into a direct heat exchange type afterheat recovery tower 29 from the bottom, and is brought into direct contact with a heat storage fluid which is cold 38 sprayed from the top of the tower for direct heat exchange, while the flue gas 27 is cooled and converted into a flue gas 28 with a temperature below 50 C., and discharged from the top of the direct heat exchange type afterheat recovery tower 29. In order to increase the gas-liquid contact area, extend the gas-liquid contact time, and improve the heat exchange effect, it is needed to increase the circulation volume of the heat storage fluid in the direct heat exchange type afterheat recovery tower 29, this in turn needs to increase the number of stages (or units) of the afterheat recovery internal circulation pump 30 in the direct heat exchange type afterheat recovery tower 29, the increased number of the stages (or units) of the afterheat recovery internal circulation pump 30 can be 0, or 1, or 2, or 3, or 4 . . . or n (n is a positive integer), the specific increased number of stages that is required can be determined by the temperature of the flue gas 28 discharged from the top of the direct heat exchange type afterheat recovery tower 29. In the direct heat exchange type afterheat recovery tower 29, the heat storage fluid which is cold 38 absorbs heat of the flue gas 27 and is then converted into a heat storage fluid which is hot 31, its temperature is close to or below the temperature of the flue gas 27 entering into the direct heat exchange type afterheat recovery tower 29 from the bottom. At the same time, the heat storage fluid which is cold 38 will also adsorb and enrich HCl, HF, and tiny dusts (including water-soluble and water-insoluble, namely polar and nonpolar tiny particles, such particles are generally referred to as PM100 and/or PM50 and/or PM2.5, and the like) in the flue gas 27. Additionally, some water vapor in the flue gas 27 will be condensed into water, mixed together in the heat storage fluid which is hot 31, and discharged from the bottom of the direct heat exchange type afterheat recovery tower 29, sent to a heat storage fluid settling tank 33 by a heat storage fluid pump 32 for settling. Dusts containing HCl and HF as well as water 34 are separated, and discharged from the bottom of the heat storage fluid settling tank 33. After removal of dusts and water, the heat storage fluid which is hot 31 is pressurized by a heat storage fluid external circulation pump 35 and sent to a heat storage fluid cooler 37 to be cooled by cooling water 41 to a normal temperature, and is converted into the heat storage fluid which is cold 38, which then enters into the direct heat exchange type afterheat recovery tower 29 for repeated heat absorption. At the same time, cooling water 41 absorbs heat and is then converted into hot water 42, wherein the heat can be recovered for use.

(12) According to the processes and devices for the flue gas desulfurization-denitration, the regeneration of the desulfurization-denitration solution and the concentration of sulfur dioxide and/or nitrogen oxides shown in FIG. 1, a small-sized flue gas desulfurization-denitration apparatus which simulates industrial production was made and installed. The specifications for various devices in the apparatus are as follows:

(13) Specifications for absorption tower 3: 2194, total height 7.2 m, 4-layer packing, each 1 m high, material 316L stainless steel;

(14) Specifications for lean solution tank 11: 4503, total height 2.0 m, material 316L stainless steel;

(15) Cooler 13: 1593, tube 101, length 1.5 m, total heat exchange area 3.9 m.sup.2, material 316L stainless steel;

(16) Heat exchanger 14: 1593, 2 units, tube 101, length 1.5 m, heat exchange area 23.9 m.sup.2, 2193, 1 unit, tube 61, length 1.4 m, heat exchange area 9.63 m.sup.2, total heat exchange area 23.9+9.63=17.43 m.sup.2, material 316L stainless steel;

(17) Rich solution heater 17: 1593, tube 321, length 0.9 m, total heat exchange area 1.63 m.sup.2, material titanium;

(18) Specifications for regeneration tower 20: 2194, total height 5.57 m, upper section with one layer of packing 1.5 m high, lower end empty tower, material 316L stainless steel;

(19) Specifications for concentration tower 23: 1594, total height 6.2 m, upper end titanium tube condenser, middle section with one layer of packing 1.5 m high, lower section with one layer of packing 2.0 m high, material 316L stainless steel.

(20) Booster fan 2: Model 2HB710-AH37, air volume 318 m.sup.3/hr, air pressure 290390 mbar (29 kPa39 kPa), Shanghai Likai Mechanical & Electrical device Co., Ltd.;

(21) Internal circulation pump 4: Model IHG20-125, flow 4.0 m.sup.3/hr, head 20 m, 0.75 KW, 3 units, material 316L stainless steel, Shanghai Changshen Pump Manufacturing Co., Ltd.;

(22) Rich solution pump 9, desulfurization pump 10 and lean solution pump 12: models are the same IHG25-160, flow 4.0 m.sup.3/hr, head 32 m, 1.5 KW, 1 unit for each, material 316L stainless steel, Shanghai Changshen Pump Manufacturing Co., Ltd.;

(23) Distilled water pump 24: all models WB50/037D, flow 1.2 m.sup.3/hr, head 14.5 m, 0.37 KW, 1 unit, material 316L stainless steel, Guangdong Yongli Pump Co., Ltd.;

(24) Flue gas flowmeter: Model LZB-50 glass rotor flowmeter, measuring range 50-250 m.sup.3/hr, Jiangyin Keda Instrument Factory;

(25) Desulfurization-denitration solution flowmeter: rich solution pump, lean solution pump and desulfurization pump outlet liquid flowmeter, LZB-32 S glass pipeline flowmeter, measuring range: 0.4-4 m.sup.3/hr, Jiangyin Keda Instrument Factory;

(26) The outlet liquid flowmeter of internal circulation pump in absorption tower: Model LZB-25 S glass pipeline flowmeter, measuring range 0.36-3.6 m.sup.3/hr, 3 units, Jiangyin Keda Instrument Factory;

(27) Steam flowmeter (for gas stripping regeneration tower): Model LUGB-2303-P2 vortex shedding flowmeter, measuring range: 8-80 m.sup.3/hr, Beijing Bangyu Chengxin Industrial Technology Development Co., Ltd.;

(28) Steam flowmeter (for concentration tower): Model GHLUGB-25 vortex shedding flowmeter, measuring range: 10-60 m.sup.3/hr, Tianjin Guanghua Kaite Flow Meter Co., Ltd.;

(29) For the inlet and outlet gases of absorption tower 3 as well as the desorbed gases from the concentration tower 23, all ingredients were subjected to on-line analysis by continuous flue gas analyzer, wherein the contents of SO.sub.2, NO and O.sub.2 were analyzed by UV-light JNYQ-I-41 type gas analyzer; the content of CO.sub.2 was analyzed by JNYQ-I-41C type infrared gas analyzer, manufactured by Xi'an Juneng Instrument Co., Ltd.; At the same time, the contents of SO.sub.2, NO and CO.sub.2 in a gas were analyzed and calibrated by chemical analysis, and compared with values of instrumental analysis, in which: the content of SO.sub.2 in a gas was analyzed by iodometric method, the content of CO.sub.2 in a gas was analyzed by barium chloride method, and the content of NO in a gas was analyzed by naphthyl ethylenediamine hydrochloride colorimetric method.

(30) The contents of SO.sub.2, NO and CO.sub.2 in desulfurization-denitration lean solution 7, desulfurization-denitration rich solution 8 and distilled water 26 were analyzed by chemical method, in which: the content of SO.sub.2 in a solution was analyzed by iodometric method, the content of CO.sub.2 in a solution was analyzed by barium chloride method, and the content of NO in a solution was analyzed by naphthyl ethylenediamine hydrochloride colorimetric method.

(31) Gas mixing was performed with air, SO.sub.2, NO and CO.sub.2, the gas ingredients are shown in tables of the test data.

(32) According to our patent technologies, the following desulfurization-denitration solutions were formulated:

(33) 1. 15% Na.sub.2SO.sub.3 (w) aqueous solution;

(34) 2. 20% monopotassium citrate (w) aqueous solution;

(35) 3. EG solution;

(36) 4. PEG400 solution;

(37) 5. PEG400+3% triethanolamine (w) solution;

(38) 6. NHD solution (a mixture of polyethylene glycol dimethyl ethers with a degree of polymerization of 4-8);

(39) 7. 60% EG (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution;

(40) 8. 60% PEG400 (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution;

(41) 9. 30% EG (w)+30% PEG400 (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution.

(42) Using these desulfurization-denitration solutions, desulfurization-denitration tests were carried out on the desulfurization-denitration apparatus made and installed as shown in FIG. 1 according to the operation methods described above.

(43) Tests results showed that:

(44) 1. When the desulfurization-denitration was carried out by using 15% Na.sub.2SO.sub.3 (w) aqueous solution, 20% monopotassium citrate (w) aqueous solution, EG solution and PEG400 solution, respectively, initially the solution had a relatively strong absorption capacity for sulfur dioxide, with an absorption rate of 90% or more, but had no absorption capacity for nitrogen oxides. However, after 2 to 5 days of continuous operation, the solution gradually lost its ability to absorb sulfur dioxide, the solution gradually changed in nature, and the solution could not be regenerated when heated to above 120 C.

(45) 2. When the desulfurization-denitration was carried out using PEG400+3% triethanolamine (w) solution and NHD solution, respectively, initially the solution had a relatively strong absorption capacity for sulfur dioxide, with an absorption rate above 90%, absorption capacity for nitrogen oxides also reached 50% or so, However, after 5 to 10 days of continuous operation, the solution gradually turned brownish black, absorption capacities for sulfur dioxide and nitrogen oxides were reduced to 50% and 20% or so, respectively, the solution gradually changed in nature, and a viscous black gelatineous material was produced.

(46) 3. When the desulfurization-denitration was carried out using 60% EG (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution, 60% PEG400 (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution and 30% EG (w)+30% PEG400 (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution, respectively, the solution had a relatively strong absorption capacity for sulfur dioxide, with an absorption rate up to 90-100%, and absorption capacity for nitrogen oxides was 40-80%. After 90 days of continuous operation, absorption capacities for sulfur dioxide and nitrogen oxides were unchanged, removal efficiencies for sulfur dioxide and nitrogen oxides were stable, and no changes of nature of the solution were found. Some running test data were extracted therefrom, and listed in Table 1, Table 2 and Table 3, respectively.

(47) It was seen from the test results that, there were little differences among the desulfurization-denitration effects of 60% EG(w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution, 60% PEG400 (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution and 30% EG (w)+30% PEG400 (w)+30% H.sub.2O (w)+10% monosodium citrate (w) solution. The effects were quite ideal, and the solutions were relatively stable.

(48) The test results indicate that, we formerly submitted patent applications Method for removing SOx from gas using modified polyethylene glycol (Application No. 201310409296.8), Method for removing SOx from gas using composite alcohol amine solution (Application No. 201310481557.7), Method for removing SOx from gas using ethylene glycol composite solution (Application No. 201310682799.2), Method for removing SOx from gas using polyol composite solution (Application No. 201310682382.6), and the like, the desulfurization solution taught therein not only has the ability of removing sulfur dioxide from gas, but also has the ability of absorbing nitrogen oxides in the gas. In particular, by adding a small amount of additives containing sulfoxide and/or sulfone group (such as DMSO and/or sulfolane, or hydroxyl and/or carboxyl substitutes thereof) to such solution, the ability of the solution to absorb nitrogen oxides increases greatly. Therefore, the use of these solutions in the said process and device of the present invention allows for large-scale industrialized desulfurization and denitration of flue gas and/or waste gas.

(49) TABLE-US-00001 TABLE 1 Operation data for the case where 60% EG (w) + 30% H.sub.2O (w) + 10% monosodium citrate (w) solution worked as desulfurization-denitration solution (excerpts from May, 6 to 14, 2014) Time 22:30 13:30 13:30 13:30 13:30 13:30 13:30 23:30 21:30 T.sub.1/ C. 43.6 48.8 46.2 49.4 49.1 44.5 44.7 43.4 42.6 T.sub.2/ C. 30.8 37.1 39.5 37.2 37 35.8 37 35 37.2 T.sub.3/ C. 33.6 37.6 40.9 38.1 37.7 38.8 37.8 37.3 41.9 T.sub.4/ C. 32.5 35.8 39.6 39.2 36.2 39.3 36.7 36.5 41.6 T.sub.5/ C. 42.2 47.9 53.8 30.2 45.5 49.8 35.1 38.2 38.5 T.sub.6/ C. 88.9 81.7 89.5 81.9 86.3 91 89.3 80.9 82.1 T.sub.7/ C. 36.1 39.5 42.5 40.8 40 39.1 38.5 37.4 41 T.sub.8/ C. 115.7 113.9 117.4 114.6 113.2 112 111.5 100.9 101 T.sub.9/ C. 108.1 105.1 103.2 99.4 99.4 101.4 100.1 91.5 94.2 T.sub.10/ C. 116.5 116 115.3 114 113.4 113.4 112.8 103.7 105.6 T.sub.11/ C. 115.9 115 116.5 115.6 112.8 112.6 112.3 101.4 101.9 T.sub.12/ C. 106.5 106 105.7 104.7 104.2 103.6 103.8 92.6 92.4 T.sub.13/ C. 114 114.3 116.3 114.9 114.8 114.4 115.5 109.1 106.1 T.sub.14/ C. 106.9 108.2 107.6 105.5 105.7 106.9 107.1 94.2 91.6 T.sub.15/ C. 105 105 104.9 103.7 103.6 103.1 103.2 92.3 92.2 T.sub.16/ C. 44.5 44.3 36.8 41.2 36.3 36 36.4 38.6 50.1 P.sub.1/kPa 16 17 19 20 17 19 20 20 16.85 P.sub.2/kPa 11 10 12 10 10 11 10 10 10.9 P.sub.3/kPa 1 2 2 0 3 2 10 30 13 P.sub.4/kPa 26 27 3 30 20 27 30 0 0 P.sub.5/kPa 3 2 3 0 3 2 0 40 36.3 F.sub.1(m.sup.3/hr) 105 100 105 105 105 115 105 95 105 F.sub.2(l/min) 15 15 15 15 15 15 15 15 15 F.sub.3(m.sup.3/hr) 18 11.1 22.3 24.6 8.7 24.4 18.4 22.3 16 F.sub.4(m.sup.3/hr) 10.2 4 9.5 11.6 4.0 7 10 4.5 8.8 A.sub.1 SO.sub.2(PPm) 1248.4 801 1267.6 963.4 989 675.4 783.8 1053.5 1001.9 NO(PPm) CO.sub.2(V %) 3.48 5.27 3.29 4.86 3.2 4.19 3.34 3.43 4.82 O.sub.2(V %) A.sub.2 SO.sub.2(PPm) 1.1 1 22.9 45.2 3.8 11.4 3.7 7.1 29 NO(PPm) CO.sub.2(V %) 3.66 5.26 3.28 4.94 3.53 4.36 3.44 3.46 5.83 O.sub.2(V %) A.sub.3 SO.sub.2(V %) 55.55 71.8 68.74 64.77 79.74 79.98 NO(V %) CO.sub.2(V %) O.sub.2(V %) A.sub.4 SO.sub.2(g/l) 2.10 1.744 1.47 1.5224 1.467 0.54 1.0242 1.2233 0.91 NO(g/l) A.sub.5 SO.sub.2(g/l) 0.19 0.109 0.08 0.083 0.083 0.06 0.0415 0.1037 0.129 NO(g/l) A.sub.6 SO.sub.2(g/l) 0.0163 0.0014 0.01 0.0108 0.0025 0.001 0.0077 0.0019 0.0016 NO(g/l)

(50) TABLE-US-00002 TABLE 2 Operation data for the case where 60% PEG400 (w) + 30% H.sub.2O (w) + 10% monosodium citrate (w) solution worked as desulfurization-denitration solution (May 18 to 21, 2014, two sets per day, 3 sets of data on date 21) Time 3:30 7:30 13:30 23:30 7:30 23:30 7:30 11:30 23:30 T.sub.1/ C. 41.6 44.5 44.7 42.6 41.2 42.4 46.9 39.7 T.sub.2/ C. 37.3 35.2 36.5 39.1 35.9 33.1 39.7 39.7 T.sub.3/ C. 42 38 40.4 43.7 39.2 34.8 41.7 41.9 T.sub.4/ C. 42 38.9 40 42.5 38.4 35.9 40.8 40.9 T.sub.5/ C. 44.3 32.7 40.4 41.5 40.7 32.8 42.9 42.9 T.sub.6/ C. 54.7 50.1 52.5 56.1 56 45 55.3 55 T.sub.7/ C. 42.4 39.8 41.4 45 39.2 38.1 41.7 41.8 T.sub.8/ C. 105.5 108.9 116.1 113.3 112.1 113.3 113.2 110.6 T.sub.9/ C. 92.1 96.1 101.9 101.9 101.6 101.9 99.3 140.4 T.sub.10/ C. 101.5 110.5 113 113.4 113.4 113.6 112.8 111.6 T.sub.11/ C. 105.6 1110 115.6 113.8 112.6 112.6 113.3 111.1 T.sub.12/ C. 92.6 98.7 103.4 102.9 102.7 102.4 102.8 101.5 T.sub.13/ C. 106 110.4 118.3 117.3 111.7 111.7 114.2 110.5 T.sub.14/ C. 91.1 90.7 103.8 105.1 104.9 103.8 103.1 105.3 T.sub.15/ C. 92.6 98.2 103 102.7 102.6 102.2 102.7 101.7 T.sub.16/ C. 35.9 38.7 34.3 34.3 37.7 37.5 36.8 37.9 P.sub.1/kPa 18.95 14.9 17.15 20.4 18.7 16.4 20.4 21.2 P.sub.2/kPa 6.2 7.95 6.65 5.7 5.55 8 3.3 4.45 P.sub.3/kPa 28.45 19.6 2.45 4.15 1.7 7.55 4.95 2.65 P.sub.4/kPa 4.8 2.1 56.25 51.6 24.6 17.55 33.75 20.85 P.sub.5/kPa 31.8 21.1 4.25 4.65 5.55 7.5 5.8 4.4 F.sub.1(m.sup.3/hr) 80 105 105 105 95 95 105 95 80 F.sub.2(l/min) 25 20 25 22 22 20 18 22 22 F.sub.3(m.sup.3/hr) 16.4 17.9 16.8 15 15.8 1.5 14.1 24.2 F.sub.4(m.sup.3/hr) 6.3 6.7 6.7 5.3 4.9 0 5.1 6.9 A.sub.1 SO.sub.2(PPm) 1011 1207.5 1860 910.5 975 888.1 634.4 543 912 NO(PPm) 83 95 351.8 263.5 79.5 29.8 84.3 178 65.9 CO.sub.2(V %) 4.275 2.89 3.67 4.4 3.6 2.35 1.96 3.5 3.36 O.sub.2(V %) 20.3 20.6 20.9 20.6 20.1 20.25 A.sub.2 SO.sub.2(PPm) 5.75 67.25 22.4 4.1 27.5 8.8 14.4 39.8 93.8 NO(PPm) 94 79.1 318 219.5 54.3 11.4 29.3 145.1 27 CO.sub.2(V %) 4.2 2.86 4.14 4.5 3.7 2.57 1.92 3.5 3.77 O.sub.2(V %) 19.9 20.4 20.5 21 20.3 20.31 A.sub.3 SO.sub.2(V %) 88.3 89.6 89.5 90 90 89.6 90 NO(V %) 0.1 0.1 0.1 0.1 0.1 0 CO.sub.2(V %) 5.1 12.6 11.6 5.35 8.2 14.1 10.4 O.sub.2(V %) A.sub.4 SO.sub.2(g/l) 0.49 1.09 1.0626 0.6531 0.49 0.5464 0.4798 0.4265 0.3532 NO(g/l) A.sub.5 SO.sub.2(g/l) 0.11 0.0076 0.015 0.02 0.048 0.0266 0.0267 0.0533 0.0267 NO(g/l) A.sub.6 SO.sub.2(g/l) 0.010 0.006 0.0054 0.0014 0.001 0.0018 0.0017 0.0012 0.0065 NO(g/l)

(51) TABLE-US-00003 TABLE 3 Operation data for the case where 30% EG (w) + 30% PEG400 (w) + 30% H.sub.2O (w) + 10% monosodium citrate (w) solution worked as desulfurization-denitration solution (excerpts from May, 23 to 31, 2014) Time 7:30 9:30 9:30 21:30 19:30 9:30 9:30 7:30 7:30 T.sub.1/ C. 40.8 54.7 56.1 54.5 57.9 56.9 57.4 54.8 55.6 T.sub.2/ C. 27 26.3 24.4 23.7 25.2 23.5 23.2 27.3 22.3 T.sub.3/ C. 38.5 39.7 37.6 37.1 38.1 35.1 37.2 37.3 35.1 T.sub.4/ C. 38.3 39.1 37.2 37.1 38.6 36.8 35.2 37.5 35 T.sub.5/ C. 46.2 44.9 37.2 40.7 45 34.5 31.7 39.7 37.6 T.sub.6/ C. 60.8 54.2 46.2 55.2 53 45.1 46.9 37.4 63.7 T.sub.7/ C. 40.8 42.4 38 39.6 39.8 37.7 40.1 38.5 38.3 T.sub.8/ C. 114.7 107.4 112.7 109.8 108 109 114.1 108.1 112.1 T.sub.9/ C. 104.1 104.7 110.7 92.8 107 101.3 102.8 107.7 111.6 T.sub.10/ C. 116.2 112.9 115.8 113 113.5 112.6 115.7 114.0 116.1 T.sub.11/ C. 115.6 108.5 113.2 111.1 105.7 104.8 107.6 103.3 106.7 T.sub.12/ C. 104.1 99 102.3 100.2 102.3 101 103.7 100.1 103 T.sub.13/ C. 110.9 135.4 114.4 110.5 111.3 111.2 116 111.4 112.4 T.sub.14/ C. 104 100.6 105.4 101 101.6 104.7 105.7 103.9 105.1 T.sub.15/ C. 103.7 99.1 100.9 100 98.2 99.8 102.9 100.1 103.1 T.sub.16/ C. 36.7 43.1 39.8 37.3 40.4 38.6 39.5 38.4 37.6 P.sub.1/kPa 13.75 20.2 15.65 16.2 16.85 17.15 16.25 15.9 17.8 P.sub.2/kPa 7.4 4.95 6.85 8.75 8.65 8.8 8.9 6.1 10.2 P.sub.3/kPa 1.1 10.55 4.3 8.9 3.65 9.7 0.5 6.8 0.9 P.sub.4/kPa 23.1 135.15 34.05 22.5 22.95 21.45 46.2 25.8 28.95 P.sub.5/kPa 3.1 14.25 8.1 11.05 5.25 11.5 1.15 9.5 0.35 F.sub.1(m.sup.3/hr) 110 110 115 115 120 120 120 110 114 F.sub.2(l/min) 15 18 18 14 15 15 15 15 15 F.sub.3(m.sup.3/hr) 17.8 23.2 18.5 20.4 19.7 21.3 24.6 25 15.6 F.sub.4(m.sup.3/hr) 5.1 6.4 6.1 5.2 5.9 5.9 5.1 7 4.9 A.sub.1 SO.sub.2(PPm) 1141.5 708 933 528 490.5 690 805.5 646.5 538.5 NO(PPm) 75.8 23.3 33.5 32.8 28 29.8 45 35.8 21.1 CO.sub.2(V %) 4.5 1.8 7.9 4.7 7.3 7.3 5.97 7.8 7.57 O.sub.2(V %) 20.4 18.4 20 18.6 19.9 17.2 18.425 17.8 18.8 A.sub.2 SO.sub.2(PPm) 2.1 6.6 4.6 0.4 0.1 0.1 4.4 48.8 9.5 NO(PPm) 28.9 3.3 8.3 5.3 1.4 10.4 16.9 3.0 12.4 CO.sub.2(V %) 5.1 1.8 6.7 4.8 8.9 8.2 6.7 8.1 9.4 O.sub.2(V %) 20.1 18.5 18.6 18.6 16.4 17.6 18.8 18.1 19 A.sub.3 SO.sub.2(V %) 89.7 83.6 89.3 56.2 43.7 72.4 80.6 64.5 82 NO(V %) 0.1 0.1 0.1 0.1 0 0.1 0.06 0.1 0.09 CO.sub.2(V %) 6.7 5.8 10.1 6 O.sub.2(V %) A.sub.4 SO.sub.2(g/l) 0.9611 1.01 1.4776 0.6712 1.2088 1.2217 1.5209 1.1728 0.7552 NO(g/l) A.sub.5 SO.sub.2(g/l) 0.0163 0.1662 0.0358 0.0358 0.044 0.068 0.0383 0.1462 0.1114 NO(g/l) A.sub.6 SO.sub.2(g/l) 0.0009 0.0011 0.0017 0.0016 0.0016 0.0027 0.0010 0.0009 0.0019 NO(g/l)