• 专利附录
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    • 专利摘要:
    In the flue gas treatment facility, the absorption tower 21, the reheating part 22, and the fan 23 are arranged in a straight line on the vertical axis to serve as at least a part of the chimney for releasing the flue gas after treatment. Further, in the flue gas treatment method, the amount of ammonia injected in the denitrification step (denitrification apparatus 2) and / or the ammonia at the downstream side of the denitrification step such that ammonia or ammonium salt remains in the flue gas injected into the desulfurization step (absorption tower 21). Set the injection amount to excess. Accordingly, it is possible to miniaturize the equipment and reduce costs.
    公开号:KR19980081553A
    申请号:KR1019980014045
    申请日:1998-04-20
    公开日:1998-11-25
    发明作者:고따께신이찌로；기무라가즈아끼；스즈끼가즈미쯔；우까와나오히꼬；다까시나도루
    申请人:마스다노부유끼；미쯔비시헤비인더스트리즈,리미티드；
    IPC主号:
    专利说明:

    Flue gas treatment facility and method
    The present invention relates to a flue gas treatment technique for carrying out at least denitration treatment and desulfurization treatment of flue gas. More specifically, the present invention relates to a flue gas treatment technology that enables miniaturization and high performance of equipment.
    Typically, in order to remove nitrogen oxides, sulfur oxides (typically sulfur dioxide) and dust (eg fly ash) contained in flue gas generated from boilers or the like of thermal power plants, for example, in FIGS. 9 and 10. Flue gas treatment facilities or processes as shown are pervasive. Next, such a flue gas treatment technique will be described later.
    As shown in FIG. 9, untreated flue gas A discharged from a boiler (omitted in FIG. 9) is first introduced into a denitrification apparatus 2 installed in boiler house 1 to decompose nitrogen oxides present in the flue gas. This denitrification apparatus 2 uses a catalyst to decompose nitrogen oxides by the catalitic ammonia reduction method. At this stage, the prior art has injected nearly equal amounts of ammonia B into flue gas in an equivalent amount that requires denitrification. The amount of ammonia introduced is very small, about 5 ppm, as it slides downstream of the denitrification apparatus 2.
    Thereafter, this flue is injected into an air heater (or heat exchanger) also installed in boiler house 1. Thus, heat is recovered from this flue gas and used to heat the air C supplied to the boiler. Usually, so-called Jungstrom ( ) Heat exchanger is used as the air heater 3.
    The flue gas from this air heater 3 is then discharged from boiler house 1 according to flue 4 and introduced into an electrostatic precipitator 5 installed outside of boiler house 1. In such electrostatic precipitator 5, dust present in the flue gas is collected and removed.
    In addition, in the case of oil-fired boilers, ammonia is added so that sulfur trioxide (SO 3 ) present in the flue gas in the electrostatic precipitator 5 can be captured by ammonium sulfate [(NH 4 ) 2 SO 4 ]. It can also be injected into flue gas of 4. On the other hand, in the case of coal-fired boilers, since a large amount of dust such as fly ash is present in the flue gas, SO 3 present in the flue gas does not form harmful mists (submicron particles) and condenses on the dust particles. It remains in the closed state and is collected in the electrostatic precipitator 5 and the absorption tower 8 described later. Therefore, in the case of coal-fired boilers, the injection of ammonia into the flue 4 is generally omitted.
    Next, the flue gas leaving the electrostatic precipitator 5 is introduced into the heat recovery portion 7 (or heat exchanger) 7 of the gas-gas heater through which the heat is recovered therefrom. Thereafter, the flue gas is introduced into the absorption tower 8 provided as a desulfurization apparatus. In such an absorption tower 8, an absorbent (eg limestone) is gas-liquid contacted with suspended absorbent liquid (hereinafter referred to as absorbent slurry) and flue gas, mainly absorbing SO 2 present in the flue gas into the absorbent slurry, and also the remaining dust. The absorbent slurry is collected into the slurry. In the bottom tank of the absorption tower 8, the slurry absorbing SO 2 is oxidized to form gypsum as a by-product by subsequent reaction including a neutralization reaction.
    In the absorption tower 8, which is a desulfurization apparatus, the SO 2 and the like are removed via the reheating unit 9 of the gas-gas heater, which is heated to a temperature suitable for release to the atmosphere by using the heat recovered in the heat recovery unit 7. Thereafter, this flue gas is introduced into the lower part of the stack body 13 via year 10, fan 11 and year 12, and finally as treated flue gas D from the top opening of this body 13 to the atmosphere. Is released. The fan 11 acts to pressurize the flue gas so as to offset the pressure loss caused by the plant, finally discharging it to the atmosphere through the chimney body 13. Usually, the motor 11a is provided separately from the main body. For the same purpose, another similar fan may be provided on the upstream side of the absorption tower 8.
    In this installation, the height from the ground of the chimney body 13 is uniquely set according to the concentrations of nitrogen oxides and sulfur oxides remaining in the treated flue gas D, and the concentrations of dusts, etc., so that the regulation of atmospheric emissions can be observed. . For example, on a 150 MW class power plant, a height of about 150 m (L), typically on the basis of typical performance (i.e., slightly higher than 80% denitrification and slightly higher than 80%). ) Has been required. In this case, the surface space required for the installation of the chimney, including the structure 14 supporting and reinforcing the chimney body 13, is usually in the form of a square consisting of sides of about 38 m in length (W).
    10 is a block diagram showing the construction of the boiler to air heater 3. In Fig. 10, reference numeral 1a denotes a boiler, reference numeral 2a denotes a denitrification catalyst contained in the denitrification apparatus 2, and reference numeral 2b denotes an ammonia decomposition catalyst contained in the denitrification apparatus. Ammonia decomposition catalyst 2b is used to remove all flowing ammonia as it slides downstream. However, in the case of the usual ammonia injecting amount, such a catalyst is omitted because the amount of ammonia which flows as if sliding is very small. In addition, as described above, an Ljungstorm type heat exchanger has been used as the air heater 3. Thus, in such a facility, as indicated by the dashed line in FIG. 10, a portion of the air C supplied (eg, about 5% based on the flue volume) will leak into the flue-gas, while at the same time a portion of the flue (eg, about 1%). ) Leaked into the air C part.
    In the conventional flue gas treatment as described above, large expensive equipment is a problem. In particular, in markets such as developing countries and small-scale power generation projects, a significant reduction in cost is strongly required in addition to the reduction in the installation area and the chimney height.
    In particular, in the conventional installation, the electric dust collector 5, the absorption tower 8, and the fan 11 are arranged in the horizontal direction between the boiler house 1 and the chimney 13, and have arrangement arrangements connected in the years 4, 6, 10 and 12. This requires a large space between the boiler house 1 and the chimney 13, increasing the cost by the need for a number of years and thus a number of supporting components.
    In addition, as described above, the installation space and the height of the chimney are determined to unique values, for example, depending on the concentrations of nitrogen oxides and sulfur oxides remaining in the flue gas D. Therefore, in order to reduce the height of the chimney, it is necessary to eventually improve the performance of the facility. This is also difficult with the conventional configuration. For example, to enhance the desulfurization rate, it may be considered to increase the gas-liquid contact capacity by simply increasing the absorption tower 8. However, this is contrary to the desire to reduce the size, so there is a certain limit.
    In addition, to increase the denitrification rate in the denitrification apparatus 2, it may be considered to simply increase the injection amount of ammonia. In such a case, conventional installations use ammonia decomposition catalyst 2b to remove all ammonia flowing as it slides downstream, resulting in a corresponding increase in cost. In this case, if the ammonia decomposition catalyst 2b is not used, ammonia will slide like a downstream, and the following adverse effect will occur.
    That is, when ammonia remains in the flue gas, highly ammonium sulfate (NH 4 HSO 4 ) is formed according to the following reaction formula 2. The dew point of this acidic ammonium sulphate is about 230 [deg.] C. under normal pressure in this type of plant, with flue gas cooling from about 350 [deg.] C. to about 150 [deg.] C. in a conventional air heater. Thus, if ammonia remains in the flue gas from denitrification apparatus 2, a large amount of acidic ammonium sulphate (NH 4 HSO 4 ) will be produced, especially in the air heater. According to the researches of the present inventors, it has been found that such acidic ammonium sulphate is easily deposited in the gap of the heat storage body in the air heater in the conventional air heater of the melt-strength type, so that maintenance work such as cleaning is often necessary.
    SO 3 + NH 3 + H 2 O → NH 4 HSO 4
    Accordingly, it is a first object of the present invention to provide a flue gas treatment facility that can realize a miniaturization and cost reduction of a facility by improving the arrangement of the facility.
    A second object of the present invention is to provide a flue gas treatment process that can improve the flue gas treatment performance and, accordingly, reduce the size of equipment.
    It is a third object of the present invention to provide a flue gas treatment process in which the miniaturization and performance improvement of the equipment as described above can be realized without accompanying the deterioration of its maintainability.
    It is a fourth object of the present invention to improve the arrangement of the equipment and to improve the flue gas treatment performance, and to provide a flue gas treatment process capable of realizing significant size reduction and cost reduction, including miniaturization of the chimney.
    1 is a schematic view showing a flue gas treatment facility according to a first example of the present invention.
    2 is a schematic view showing a flue gas treatment facility according to a second example of the present invention.
    FIG. 3 is a schematic view showing details of a desulfurization apparatus included in the flue gas treatment facility of FIG. 2.
    FIG. 4 is a schematic diagram illustrating a no-waste water disposal system suitable for use in the flue gas treatment plant of FIG. 2.
    5 is a graph showing data for demonstrating the effects of the present invention (ie, improvement of desulfurization rate).
    Fig. 6 is a schematic diagram showing an experimental apparatus for demonstrating the effects of the present invention (i.e. minimization of precipitates due to SO 3 in flue gas).
    7 is a graph showing experimental results (change in air pressure loss of a heat exchanger) for demonstrating the effects of the present invention (minimization of precipitates due to SO 3 in flue gas).
    8 is a graph showing experimental results (change in the overall heat transfer coefficient of the heat exchanger) to demonstrate the effect of the present invention (minimization of precipitates due to SO 3 in the flue gas).
    9 is a schematic view showing a typical flue gas treatment facility.
    10 is a schematic view showing a denitrification apparatus and other apparatuses included in a conventional flue gas treatment facility.
    [Explanation of symbols on the main parts of the drawings]
    1. Boiler house 1a. Boiler
    2. Denitrification unit 3. Air heater ( Type heat exchanger)
    5. Dry electrostatic precipitators 13a, 13b. Chimney body
    14, 14b. The structure of the chimney 21, 21a. Absorption Tower
    22. Reheater 23. Fan
    24. Heat recovery section (non-leak type heat exchanger) 31. Air heater (non-leak type heat exchanger)
    32. Wet Electrostatic Precipitator A. Untreated Flue Gas
    B. Ammonia D. Treated flue gas
    In order to achieve the above objects, the present invention provides an absorption tower which removes flue gas by absorbing at least sulfur oxides from the flue gas by absorbing it with gas-liquid liquid, and at a temperature suitable for releasing the flue gas emitted from the absorption tower into the atmosphere. It provides a flue gas treatment facility consisting of a reheating unit that is combustible and a fan that feeds the flue gas so as to offset pressure loss caused by the flue flow path including the absorption tower and the reheating unit. Arranged in series on the vertical axis, it serves as at least part of the chimney for releasing the treated flue gases into the atmosphere.
    The present invention also provides a denitrification step of decomposing and treating a nitrogen oxide present in the flue gas by injecting ammonia into the flue gas containing at least nitrogen oxides and sulfur oxides, and introducing flue gas discharged from the denitrification step into the absorption tower to absorb the absorbent liquid and the gas. A flue gas desulfurization treatment method comprising liquid contact to remove at least sulfur oxides by absorbing the absorbent liquid, wherein ammonia is injected into the flue gas as necessary at a downstream point of the denitrification step and during flue gas injection into the desulfurization step. The excess level at which ammonia or ammonium salts remain, determines the amount of ammonia injected in this denitrification step and / or the amount of ammonia injected downstream of the denitrification step.
    In the flue gas treatment method of the present invention, the ammonia injection amount in the denitrification step may be set so that the concentration of ammonia remaining in the flue gas discharged from the denitrification step is 30 ppm or more.
    The flue gas treatment method of the present invention may further include a heat recovery step of recovering heat from the flue gas by introducing the flue gas discharged from the denitrification step into a heat exchanger upstream of the absorption tower, and as a heat exchanger, It is also possible to use a non-leakage heat exchanger with a shell-and-tube structure.
    The flue gas treatment method of the present invention may also include a heat recovery step of recovering heat from the flue gas by introducing the flue gas discharged from the denitrification step into a heat exchanger upstream of the absorption tower, wherein the amount of ammonia injected in the denitrification step is And / or the ammonia injection amount at the downstream point of the denitrification step may be determined such that the concentration of ammonia remaining in the flue gas injected into the heat exchanger exceeds 13 ppm relative to the SO 3 concentration in the flue gas.
    In the flue gas treatment method of the present invention, a region in which gas-liquid contact between the flue gas and the absorbent liquid is performed in the absorption tower is sprayed with a liquid having a higher acidity than the absorbent liquid downstream to prevent ammonia from being easily released into the gas phase. The ammonia remaining in the flue gas introduced in the desulfurization step is absorbed in the absorption tower without remaining in the flue gas discharged from the absorption tower.
    The flue gas treatment method of the present invention further includes introducing a flue gas into a dry electrostatic precipitator in an upstream part of the absorption tower to remove dust in the flue gas, and wet flue gas in a downstream part of the absorption tower. A second dust removal step is introduced into the dust collector to remove dust remaining in the flue gas.
    The present invention also provides a denitrification apparatus for decomposing and treating nitrogen oxides in the flue gas by injecting ammonia into the flue gas, a heat exchanger for recovering heat from the flue gas discharged from the denitrification device, and the flue gas discharged from the heat exchanger. And an absorption tower that removes at least sulfur oxides from the flue gas by absorbing it into the absorbent liquid by gas-liquid contact with the absorbent liquid, and a temperature suitable for releasing the flue gas discharged from the absorption tower into the atmosphere using at least a part of the heat recovered from the heat exchanger. And a fan for feeding flue gas so as to offset the pressure loss of the flue flow path including the absorption tower and the reheating part, and the absorption tower, the reheating part, and the fan discharge the treated flue gas into the atmosphere. On a vertical axis to serve as at least part of the chimney A flue gas treatment method for purifying flue gas containing at least nitrogen oxides and sulfur oxides using a flue gas treatment plant arranged in a manner, wherein ammonia is injected into flue gas as necessary at a downstream point of the denitrification apparatus, and the denitrification is carried out. The amount of ammonia injected in the apparatus and / or the amount of ammonia injected downstream of the denitrification apparatus is set in excess so that the ammonia or ammonium salt remains in the flue gas introduced into the absorption tower.
    In the flue gas treatment facility of the present invention, the absorption tower, the reheater and the fan are arranged in series on the vertical axis so as to serve as at least a part of the chimney for releasing the treated flue gas into the atmosphere. Therefore, all such devices or mechanisms that were conventionally installed outside the structure of the chimney are installed in the space inside the structure of the chimney. In conclusion, the installation area of the entire installation is significantly reduced, so that the miniaturization of the installation in the horizontal direction can be achieved remarkably. Moreover, the flue and a significant part of the support components therefor become unnecessary, and the chimney body is much smaller than before. As a result, a significant reduction in equipment costs is achieved.
    Further, in the flue gas treatment method of the present invention, ammonia injected into flue gas is injected into flue gas as necessary at a downstream point of the denitrification step, and ammonia injection amount in the denitrification step and / or at a downstream point of the denitrification step is The ammonia injection amount is set to an excess that allows ammonia or ammonium salts to remain in the flue gas injected into the desulfurization step.
    Therefore, at least the denitrification rate in the denitrification step is improved, which consequently contributes to the miniaturization of the absorption tower and the chimney.
    In particular, when the ammonia injection amount in the denitrification step is set such that the concentration of ammonia remaining in the flue gas discharged from the denitrification step is 30 ppm or more, the denitrification rate is particularly improved in the denitrification step, which results in miniaturization of the chimney. To contribute.
    In addition, the method for treating flue gas further includes a heat recovery step for recovering heat from the flue gas by introducing flue gas discharged from the denitrification step into a heat exchanger upstream of the absorption tower, the shell-and- as a heat exchanger. In the case of using a non-leakage heat exchanger of tube structure, the heat of the flue gas can be effectively used in a conventional manner to preheat the air for use in the boiler or to reheat the treated flue gas.
    In other words, in the shell-and-tube non-leakage heat exchanger, in contrast to the commonly used melt-strength heat exchanger, acidic ammonium sulfate is produced by reaction of injected ammonia and SO 3 in flue gas. And sulfuric acid mist generated from SO 3 in flue gas is condensed in the heat exchanger, there is little precipitation or clogging on the heat transfer surface of these materials.
    Moreover, in such a case, air cannot leak into the flue gas in the heat exchanger. This can reduce the throughput of flue gas, resulting in cost savings.
    In addition, the flue gas discharged from the denitrification step is injected into the heat exchanger upstream of the absorption tower to recover heat from the flue gas, and the ammonia injection amount in the denitrification step and / or the ammonia injection amount downstream of the denitrification step is injected into the heat exchanger. When the concentration of ammonia remaining in the flue gas is set to be at least 13 ppm above the concentration of SO 3 in the flue gas, condensation of the acidic ammonium sulphate in the heat exchanger is minimized and a fine powder of neutral ammonium sulphate is produced. do. Thus, generation of scale due to acidic ammonium sulfate is significantly suppressed, which makes the maintenance of the heat exchanger very easy.
    In addition, a region is formed downstream of the region where gas-liquid contact between the flue gas and the absorbent liquid in the absorption tower is performed so as to spray a liquid having a higher acidity than the absorbent liquid so that ammonia cannot be easily released into the gas phase. When the ammonia remaining in the introduced flue gas is absorbed into the absorption column without remaining in the flue gas discharged from the absorption tower, the adverse effect of excessive injection of ammonia (ie, release of ammonia into the atmosphere) can be avoided. This may counter future ammonia shrinkage regulations and contribute to further purification of flue gas.
    In addition, the method of treating the flue gas of the present invention further includes a first dust removal step of removing the dust present in the flue gas by introducing the flue gas into the dry electrostatic precipitator at an upstream side of the absorption tower, and wet electricity by the flue gas downstream of the absorption tower. In the case of including a second dust removing step of removing dust remaining in the flue gas by introducing into the dust collector, the dust removal performance of the entire installation is significantly improved.
    Another flue gas treatment method of the present invention is composed of a denitrification device, a desulfurization device, and the like so that an absorption tower (provided as a desulfurization device), a reheater, and a fan serve as at least part of a chimney for emitting treated flue gas into the atmosphere. Purification of flue gas containing at least nitrogen oxides and sulfur oxides using a flue gas treatment plant arranged in a straight line on a vertical axis, in which ammonia is injected into the flue gas as necessary at a downstream point of the denitrification unit, and ammonia in the denitrification unit The injection amount and / or the ammonia injection amount at the downstream point of the denitrification apparatus is set in excess so that the ammonia or ammonium salt can remain in the flue gas injected into the absorption tower.
    Thus, since the absorption tower, the reheater and the fan are arranged in a straight line on the vertical axis to form part of the chimney, the installation space of the installation is significantly reduced. In addition, at least the desulfurization rate is improved due to the excessive injection of ammonia, which in turn reduces the height of the chimney. In other words, through this method, excellent effects such as remarkable miniaturization of the equipment in both the horizontal and vertical directions, and improvement in the performance of the equipment can be obtained.
    Preferred Embodiments of the Invention
    Next, some preferred embodiments of the present invention will be described based on the accompanying drawings.
    First example
    A first example of the present invention will be described with reference to FIG. 1. The same components as those included in the conventional installation of FIG. 9 are denoted by the same reference numerals, and redundant description thereof will be omitted.
    In the flue gas treatment facility of this example, below the chimney main body 13a, the absorption tower 21, the reheating part 22 of a gas-gas heater, and the fan 23 are arranged in a line on the vertical axis of a chimney, and form a part of this chimney.
    The heat recovery portion 24 of the gas-gas heater is installed at a position halfway in the year 25 connecting the absorption tower 21 from the dry electrostatic precipitator 5 and inside the chimney structure 14. As a result, the entire absorption column 21, the heat recovery portion 24 and the reheating portion 22 of the gas-gas heater, and the fan 23 are all installed in the empty space inside the chimney structure 14.
    In this example, absorption tower 21 introduces flue gas through an inlet formed on its lower side, removes gaseous liquid contact with the absorbent liquid in countercurrent manner to absorb at least nitrogen oxides from the flue gas by absorbing it into the absorbent liquid, and the upper portion thereof. Eject from the outlet formed in the. In conventional installations gypsum is produced in the same way as described above, for example by using limestone as an absorbent.
    The reheat 22 of the gas-gas heater is connected directly to the upper end of the absorption tower 21. Accordingly, the flue gas discharged from the upper outlet of the absorption tower 21 is injected into the reheating unit 22 from the base surface, and heated to a temperature suitable for discharge into the atmosphere by using the heat recovered in the heat recovery 24, and is discharged from the upper upper surface.
    In such a case, a gas-gas heater of circulating heating medium is used so that the heat recovery section 24 and the reheat section 22 consist of a shell-and-tube non-leakage heat exchanger. Such a non-leakage heat exchanger is acidic, which tends to form a scale even when SO 3 present in the flue gas reacts with ammonia in the flue gas according to the above Reaction Formula 2 to produce acidic ammonium sulfate (NH 4 HSO 4 ). There is an advantage that the deposition of ammonium sulfate is relatively small.
    Fan 23 is a vertical-flow fan installed on the upper portion of the reheater 22, and serves to suck the flue gas from the bottom surface to discharge to the upper upper surface. The motor is mounted on its inner shaft.
    In the arrangement of the flue gas treatment facility of this example, compared with the conventional facility shown in FIG. 9, the installation area of the entire facility is significantly reduced, and the remarkable miniaturization of the facility can be achieved in the horizontal direction. In particular, the entire space required for installation of the absorption tower 8, the fan 11, and the flues 6 and 10 in the installation of FIG. 9 becomes unnecessary. Furthermore, since there is usually a space in which the absorption tower 21 and the like can be installed in the structure 12 of the chimney, the installation space of the chimney is the same as before.
    In addition, years 6 and 10 themselves and their supporting components become unnecessary, and the height of the chimney body 13a is significantly shorter than before. As a result, significant savings are achieved in equipment costs as well.
    2nd example
    Next, a second example of the present invention will be described with reference to FIG. The same components as those included in the first example are denoted by the same reference numerals, and redundant description thereof will be omitted.
    The present example is characterized in that an air heater (or heat exchanger 31) consisting of a non-leakage heat exchanger having a shell-and-tube structure is mounted, and a wet electrostatic precipitator 32 is installed between the absorption tower 21a and the reheater 22. . In this example, the heat recovery unit 24 of the air heater 31 and the gas-gas heater as described above constitutes a heat exchanger performing the heat recovery step of the present invention. In addition, the dry electrostatic precipitator 5 as described above in the conventional equipment performs the first dust removal step of the present invention, the wet electrostatic precipitator 32 performs the second dust removal step of the present invention.
    In the above configuration, there are the following advantages. Among them, since the air heater 31 is composed of a non-leakage heat exchanger, even when acidic ammonium sulfate is produced in the flue gas injected into the air heater 31 as described above, the amount of scale to be deposited is relatively small. This is very advantageous in terms of holding.
    In particular, as described above, when ammonia remains in the flue gas discharged from the denitrification apparatus 2, acidic ammonium sulfate is produced in particular in the air heater 31. Studies conducted by the present inventors have found that in the case of a conventional melt-strength type air heater, such acidic ammonium sulphate tends to be deposited in the heat accumulator gap in the air heater, so that maintenance work such as cleaning is frequently required.
    However, studies conducted by the inventors have found that shell-and-tube structured non-leakage heat exchangers have relatively little such deposition of, or resulting blockages of, acidic ammonium sulfate. It has also been found that the production of acidic ammonium sulphate and its deposition at the inner surface of the heat exchanger can also be improved by injecting an excess of ammonia into the flue gas, which will be described later.
    In addition, when the air heater 31 is composed of a non-leakage heat exchanger, the air C supplied to the boiler does not leak into the flue gas. This slows down the flow rate of flue gas to be treated, resulting in a corresponding reduction effect on the capacity of fans 23 and flue, and power consumption.
    Moreover, since the wet electrostatic precipitator 32 is installed, it is possible to remove fine dust and other foreign matter not collected in the absorption tower 21a. Thus, the residual dust concentration in the treated flue gas D is reduced. In this respect, the facility performance is improved and contributes to the reduction of the chimney height.
    Next, the structure and effect of the characteristic part of the flue gas treatment process of this invention using the said flue gas treatment facility of the said example are mentioned later.
    In such a method, the amount of ammonia B injected into the denitration apparatus 2 is excessively selected so that a large amount of ammonia or ammonium salt remains in the flue gas injected into the absorption tower 21a without using an ammonia decomposition catalyst.
    If ammonia or ammonium salts remain in the flue gas injected into absorption tower 21a, this ammonia or ammonium salt is dissolved into the slurry in absorption tower 21a as a result of gas-liquid contact between the flue gas and the absorbent slurry. This raises the ammonium salt concentration (ie, ammonium ion concentration) in the liquid phase of the slurry to be purified in absorption tower 21a.
    According to a study conducted by the inventors, when the ammonium salt concentration (or ammonium ion concentration) in the circulating fluid of the absorption tower increases to 150 mmol / L or more, even if other conditions are constant, The sulfur dioxide removal rate (ie, desulfurization rate) from flue gas increases by about 95%, as shown in FIG. 5. For this reason, according to this example in which the injection amount of the ammonia B injected into the denitration apparatus 2 is set to be excessive as described above, the absorption tower 21a can be miniaturized as compared with the conventional one. In addition, the concentration of sulfur oxides (mainly sulfur dioxide) remaining in the treated flue gas D can be further reduced, thereby shortening the height of the chimney.
    In addition, since the injection amount of ammonia B naturally exceeds the equivalent amount required for the denitrification reaction, the denitrification performance of the denitrification apparatus 2 (or the denitrification step) is also improved. According to a study conducted by the present inventors, the injection amount of ammonia B exceeds the equivalent amount required for the denitrification reaction, and in addition, the concentration of ammonia remaining in the flue gas after the denitrification step (i.e., sliding ammonia) is 30 ppm or more. If this is set, the denitrification rate is improved to about 90% at the conventional level of about 80%, and the concentration of residual nitrogen oxides in the treated flue gas D can be reduced by half.
    In this regard, according to the test calculations carried out by the inventors, in the case of a power plant of 150 MW class, the desulfurization rate and the denitrification rate are improved as described above, and the dust removal rate is also enhanced by the installation of the wet electrostatic precipitator 32. If so, it has been found that the height L1 of the chimney can be significantly reduced to about 90 m from the conventional value of about 150 m. Moreover, as a result of this, the width W1 of the installation space of the chimney structure 14b can be significantly reduced to about 25 m from the conventional value of about 38 m.
    In this case, the specific injection amount of ammonia B not only exceeds the equivalent amount required for the denitrification reaction, but also needs to be set in consideration of the SO 3 concentration in the flue gas.
    In particular, at least a portion of the ammonia remaining in the flue gas discharged from the denitrification apparatus 2 (or the denitrification step) reacts with SO 3 present in the flue gas to form ammonium salts such as ammonium sulfate and acidic ammonium sulfate as described above. In this case, most of these ammonium salts are trapped in the electrostatic precipitator 5. Therefore, of the ammonia gas remaining in the flue gas discharged from the denitrification apparatus 2, only a part of the ammonia gas which is excessive with respect to the equivalent of SO 3 remains in the flue gas injected into the absorption tower 21a.
    More specifically, the injection amount of ammonia is 13 ppm of the concentration of ammonia remaining in the flue gas injected into the air heater 31 and the heat recovery portion (or heat exchanger) 24 of the gas-gas heater, relative to the SO 3 concentration in the flue gas. It is preferable to set so that it may exceed.
    In this way, deposition of the acidic ammonium sulfate condensed in the heat exchanger can be suppressed, as demonstrated by the embodiments to be described later. Thus, formation of deposits (or scales) on the heat transfer surface and other inner surfaces of the heat exchanger is slight, thereby facilitating maintenance of the heat exchanger.
    That is, in the conventional equipment as shown in Fig. 9, the concentration of ammonia remaining in the flue gas injected into the air heater 3 is about 5 ppm, so that the acidic ammonium sulfate is produced in a larger amount than the usual ammonium sulfate. Such acidic ammonium sulfate is particularly susceptible to condensation in the air heater 3. However, if this ammonia concentration exceeds 13 ppm relative to the SO 3 concentration in the flue gas, most of the SO 3 present in the flue gas is converted to neutral ammonium sulfate fine powder containing (NH 4 ) 2 SO 4 , and scale The formation of highly adherent ammonium sulphate, which is easy to form, is relatively reduced. In addition, according to the present example using the air exchanger 31 of the shell-and-tube structure, the problem due to scale formation is reduced as compared with the conventional equipment using the melt-type air heater. As a result, the problem of skein formation due to acidic ammonium sulfate is substantially solved and there is no need to provide an ammonia decomposition catalyst to the denitrification apparatus.
    In this example, an excessive amount of ammonia is actively injected so that a large amount of ammonia or ammonium salt can remain in the flue gas injected into the absorption tower 21a. Therefore, the treatment of ammonia to be absorbed into the slurry in the absorption tower 21a and ammonia leaking into the treated flue gas D become a problem. However, these problems are newly solved by the existing no-waste water disposal technique (so-called AWMT), or the present inventors, in which dust from an electrostatic precipitator is mixed with wastewater from a desulfurization unit to recover and reuse ammonia. This can be solved by using the devised ammonia absorption technique.
    Some examples of these technical methods are described with reference to FIGS. 3 and 4. FIG. 3 is a schematic diagram showing a detailed configuration example of a desulfurization apparatus suitable for use in the flue gas treatment facility of this example as shown in FIG. 2, and FIG. 4 is a representative non-dehydration solution suitable for use in the flue gas treatment facility of this example. It is a schematic diagram which shows the structural example (in the case of an oil-fired boiler) of a processing installation.
    In this case, as shown in Fig. 3, the absorption tower 21a as the desulfurization apparatus is provided with a tank 41 for holding the absorbent liquid E (hereinafter referred to as absorbent slurry E) in which the absorbent (i.e. limestone) is suspended, The upper portion of the tank 41 has a gas-liquid contact portion, which is a liquid column type absorption tower in which gas-liquid contact between the flue gas and the slurry in the tank 41 is performed.
    The absorption tower 21a has a flue gas inlet 42 for introducing flue gas at its lower part, and a flue gas deriving part 43 for discharging the desulfurized flue gas A1 is formed at its upper end, so that flue gas is introduced from the lower part of the absorber tower, It is a so-called counterflow absorption tower that flows into.
    In the flue gas derivation part 43, the mist eliminator 43a is provided. This fume eliminator 43a traps all fumes produced by gas-liquid contact and accompanied by flue gas, such that large quantities of fumes containing sulfur dioxide, ammonia, and the like are not released with desulfurized flue gas A1. In this example, the mist collected by this mist eliminator 43a flows down from its lower end and falls directly into tank 41.
    In addition, in the absorption tower 21a, many spray pipes 44 are provided in parallel. Such a spray pipe 44 is formed with a plurality of nozzles (not shown) for injecting the slurry in the tank 41 in the form of a liquid column in the upstream direction.
    Furthermore, outside the tank 41, a circulation pump 45 for sucking upward the absorbent slurry in the tank 41 is provided. Accordingly, the slurry is supplied to the spray pipe 44 via the circulation line 46.
    In the example as shown in FIG. 3, the tank 41 is supplied to a means for blowing air F for oxidation as fine bubbles while stirring the slurry in the tank 41. This means consists of a stirrer 47 and an air supply pipe 48 which blows air F into the slally in the vicinity of the stirring blade of the stirrer 47. Thus, the absorbent slurry in which sulfur dioxide is absorbed is efficiently contacted with the air in the tank 41 and completely oxidized to form gypsum.
    More specifically, the absorbent slurry sprayed from the spray pipe 44 in the absorption tower 21a flows down while absorbing sulfur dioxide and dust as a result of gas-liquid contact with the flue gas, as well as ammonia gas, and the stirrer 47 and air After being introduced into the tank 41 to oxidize by contact with a large amount of bubbles blown in by stirring by the feed pipe 48, the neutralization reaction proceeds to become a slurry containing gypsum at a high concentration. The main reactions occurring in this treatment route are shown in Scheme 1 above.
    Thus, large amounts of gypsum, small amounts of limestone (used as absorbents), and ammonia collected from traces of dust and flue gas are constantly suspended or dissolved in the slurry in tank 41. In this example, the slurry in tank 41 is aspirated and fed to solid-liquid separator 49 through pipeline 46a branched from circulation line 46. This slurry is filtered in solid-liquid separator 49 to recover gypsum G of low moisture content. On the other hand, a portion of the filtrate H1 from the solid-liquid separator 49 is introduced into the slurry preparation tank 52 as water consisting of absorbent slurry E, and the residue is discharged as desulfurization drainage H2 to prevent accumulation of impurities.
    Since ammonia and ammonium salts (such as ammonium sulfate) absorbed from flue gas are solubility high, most are contained in slurry E in the liquid phase, and finally discharged together with desulfurization waste water H2.
    In this example, a slurry containing limestone as an absorbent during operation is supplied from the slurry preparation tank 52 to the tank 41. The slurry preparation tank 52 is equipped with a stirrer 53, mixes powder limestone I introduced from a silo and filtrate H1 supplied as described above, and stirs the mixture to produce an absorbent slurry E. Let's do it. The absorbent slurry E in the slurry preparation tank 52 is properly supplied to the tank 41 by the slurry pump 54. In addition, replenishment water (industrial water, etc.) is appropriately supplied to, for example, the tank 41 or the slurry preparation tank 52 so as to compensate for the gradual loss of water due to evaporation or the like in the absorption tower 21a.
    During operation, the flow rate of the replenishment water supplied to the tank 41, the flow rate of the slurry sucked through the pipeline 46a, and the like are appropriately controlled. Thus, in the tank 41, a slurry containing a predetermined concentration of gypsum and an absorbent is always maintained in a predetermined range of levels.
    In addition, during operation, in order to maintain high purity and desulfurization rate of gypsum, boiler load (i.e., flue A flow rate), sulfur dioxide concentration in flue gas introduced into absorption tower 21a, limestone concentration and pH of absorbent slurry in tank 41 The back is detected with a sensor. Based on the detection results, the rate of infusion of limestone into the tank 41 and other parameters are appropriately adjusted by a controller (not shown). Usually, the pH of the absorbent slurry in the tank 41 is usually adjusted to about 6.0 so as to form high purity gypsum by accelerating the oxidation reaction as described above, while maintaining a high sulfur dioxide absorption performance.
    Further, as a means for preventing the excessively injected ammonia from remaining in the desulfurized flue gas A1, the spray pipe 55 is provided on the upper portion of the spray pipe 44. This spray pipe 55 injects liquid J (which may also be slurry) having a lower pH than the slurry in the tank 41 to the absorption tower 21a, thereby forming an area in the upper part of the absorption tower 21a which does not easily release ammonia into the gas phase.
    Liquid J, sprayed from spray pipe 55, consists of, for example, a dilute sulfuric acid solution, and its pH is adjusted to a value (eg, 4.0 to 5.0) that prevents ammonia from being easily released into the flue gas.
    With the above configuration, the flue gas introduced from the flue gas inlet 42 to the absorption tower 21a is first subjected to gas-liquid contact with the slurry sprayed from the spray pipe 44 in the form of a liquid column, and then to gas-liquid contact with the liquid sprayed from the spray pipe 55. do. Thus, together with sulfur dioxide, they absorb or collect dust and ammonia.
    During this process, the liquid sprayed from the spray pipe 55 at the outlet (or top) of the absorption tower 21a is adjusted to a pH value that prevents ammonia from being easily released into the flue gas. For this reason, the partial pressure of ammonia is suppressed in the upper part of the absorption tower 21a, and the phenomenon which ammonia once dissolved in the liquid phase of a slurry is reversely discharged in flue gas from the upper part of this absorption tower is prevented.
    Thus, finally, desulfurized flue gas A1 having a very small concentration of sulfur dioxide, dust and ammonia is discharged from the flue gas deriving portion 43 formed at the upper end of the absorption tower 21a. In this case, calculations performed by the inventors found that the removal rate of ammonia is about 90%. Therefore, despite the configuration of actively injecting excess ammonia, the treated flue gas D (FIG. 2) contains little ammonia, and does not cause a problem due to the release of ammonia into the atmosphere.
    However, in terms of preventing air pollution, it is desirable to minimize the ammonia concentration in the treated flue gas D released into the atmosphere. Therefore, there is a need for a flue gas treatment technique capable of achieving a high desulfurization rate and miniaturization of a facility, and also minimizing the amount of ammonia released.
    Next, the structural example of the typical drainage-free treatment facility shown in FIG. 4 is mentioned later. This is an example of the treatment of flue gas from an oil fired boiler. In this case, among the dust K collected from the flue gas by the dry electrostatic precipitator 5 shown in Figs. 2 and 3, vanadium (heavy metal) and magnesium, injected ammonia and SO 3 present in the flue gas in addition to the main component of unburned carbon. Ammonium sulphate and the like formed from.
    In this installation, as shown in FIG. 4, the desulfurization wastewater H2 shown in FIG. 3 is first injected into the mixing tank 61, mixed with the dust K supplied from the stirred and dry electrostatic precipitator 5, to form a mixed slurry S1. In this step, ammonia and ammonium sulfate containing the dust K are dissolved in the liquid slurry S1, and most of them exist as sulfate ions or ammonium ions, similarly to those contained in the waste water H2. Thereafter, the mixed slurry S1 is transferred to the pH adjustment / reduction tank 62 and an acid L (eg sulfuric acid (H 2 SO 4 )) is added. Then, the mixed slurry S1 is adjusted to a pH value (about 2 or less) capable of reducing vanadium. In addition, reducing agent M [eg, sodium sulfite (Na 2 SO 3 )] is added and mixed with the slurry. Thus, according to the following Scheme 3, the pentavalent vanadium present in the slurry is reduced to the tetravalent state, and the vanadium is dissolved in the liquid phase.
    2VO 2 + + SO 3 2- + 2H + → 2VO 2+ + SO 4 2- + H 2 O
    Thereafter, the mixed slurry S2 having undergone the reduction of vanadium is transferred to the precipitation tank 63, and ammonia B3 (to be described later) is added and mixed with the slurry. In this step, the vanadium 4 present in the slurry is reacted with ammonia according to the following reaction formula 4, and the product precipitates.
    VO 2+ + 2 NH 4 OH → VO (OH) 2 + 2 NH 4 +
    After the treatment of depositing vanadium, the mixed slurry S3 derived from the precipitation tank 63 is transferred to the solid-liquid separator 65 composed of the flocculation settling device and / or the vacuum belt filter using the slurry pump 64. Thus, the solid material N is separated into sludge or cake form. The separated solid material N consists mainly of unburned carbon present in the dust K and additionally contains precipitated vanadium.
    Thereafter, drain S4 from which the vanadium-containing solid material has been removed is transferred to neutralization tank 66, and chemical treatment agent O (eg, slaked lime (Ca (OH) 2 )) and return drain P (described below) are added thereto. Stir. Thus, sulfate ions and ammonium ions present in the drainage are converted to gypsum or ammonium hydroxide.
    The resulting slurry S5, containing gypsum and ammonium hydroxide as a solid component, is then transferred to a primary concentrator 67 to separate ammonia B1 by evaporation. The resulting slurry S6, containing high concentrations of gypsum and other solid materials, is discharged by slurry pump 68.
    The primary concentrator 67 consists of an evaporator 67a, a heater 67b and a circulation pump 67c, and serves to evaporate the water B1 containing ammonia by heating the slurry with, for example, hot steam W1 generated in a boiler of a power plant or the like.
    In addition to gypsum, the solid material contained in the slurry S6 mainly contains magnesium hydroxide [Mg (OH) 2 ]. This magnesium hydroxide is formed by mixing magnesium present in the dust K as impurities and hydroxide ions present in the slurry.
    Subsequently, this slurry S6 was introduced into a solid separator 69 composed of a cyclone or sedimentation centrifuge and the like, and contained slurry S7 mainly containing gypsum (crude particulate solid material) and other fine particle solid materials. Slurry S8 (mainly containing said magnesium hydroxide). Slurry S7 is conveyed to the absorption tower tank 41 which consists of a desulfurization apparatus shown in FIG. On the other hand, part of the slurry S8 is dewatered in the dewatering device (or secondary concentrator) 70, and the resulting solid material, which mainly contains magnesium hydroxide, is released to the sludge Q.
    The remaining part which is not supplied to the dehydration apparatus 70 in slurry S8 is conveyed to the neutralization tank 66 as conveyance waste liquid P.
    The ammonia water B1 produced by evaporation in the primary concentrator 67 is cooled, condensed in the cooler using the cooling water W2 as the refrigerant and stored in the storage tank 72.
    The ammonia water B1 in the storage tank 72 is usually at a low concentration of about 3 to 6%, and is supplied to the ammonia concentrator 74 by the pump 73 and concentrated to obtain ammonia water having a concentration of about 10 to 20%. Some of this ammonia water is vaporized in the vaporizer 75, and the resulting ammonia B2 is injected into the flue gas as ammonia B containing water vapor W3 in the denitrification apparatus 2 as described above. The remaining portion of the ammonia water is fed to the settling tank 63 as ammonia B3.
    In the non-drainage treatment facility as described above, the treatment is performed by mixing the desulfurization wastewater H2 generated by the desulfurization treatment with the removed dust K, thereby achieving an improved handleability. The resulting mixed slurry undergoes a series of treatments for the reduction, precipitation and solid-liquid separation of the contained vanadium and release the separated vanadium as sludge. In addition, the mixed slurry is concentrated and treated in such a way that the gypsum, water and ammonia in the slurry are finally conveyed into flue gas or upstream of the facility (eg, an absorption tower consisting of a desulfurization apparatus). Therefore, it becomes possible to use ammonia cyclically, and the so-called drainage cut-off facility which does not produce the discharged discharged water is realizable. This eliminates the need for drainage treatment prior to discharge, and enables effective use of ammonia.
    Example
    Next, some embodiments performed by the inventors are described below. The object of this embodiment is due to the acidic ammonium sulphate when the present invention injects excess ammonia according to one feature and uses a non-leakage heat exchanger of shell-and-tube structure as the heat exchanger in the heat recovery stage. It is intended to demonstrate that scale generation at the heat exchanger inner surface (eg, heat transfer surface) is suppressed.
    First, the experimental apparatus shown in FIG. 6 was used. In particular, the air heater 82 and the cooler 83 were installed downstream of the combustion furnace 81. In addition, cyclone 84 was installed downstream to remove and remove dust such as unburned carbon. The flue gas discharged from this cyclone 84 was injected into a non-leak heat exchanger 85 having a shell-and-tube structure. In this case, flue gas passes through the shell portion of the heat exchanger (ie, outside of the heating tube), with the heating medium passing through the heating tube of the heat exchanger 85. The heating medium heated by the heat of flue gas in the heat exchanger 85 was cooled and regenerated in the cooler 86 with cooling water.
    The concentration of SO 3 in flue gas was adjusted by injecting SO 3 into flue gas at a position downstream of the air heater 82 and upstream of the cooler 83. In addition, the ammonia concentration in flue gas was adjusted by injecting ammonia (NH 3 ) into flue gas at a position downstream of cyclone 84 and upstream of the heat exchanger. The heat exchanger 85 can perform so-called steel ball cleaning by continuously spreading steel balls in the shell portion thereof, and optionally, a steel ball cleaning test was performed.
    Other experimental conditions are as follows.
    (fuel)
    Type: fuel oil A.
    Burning rate: 15 L / hr.
    (Smoke)
    Flow rate: 200 m 3 N / h.
    SO 3 concentration: 25 ppm.
    NH 3 concentration: 63 ppm.
    Temperature at cyclone outlet: 170 ° C.
    Temperature at the inlet / outlet of the heat exchanger: 130/90 ° C.
    (Heating medium)
    Injection temperature: 75 ° C.
    (Steel ball)
    Dispersion rate: 2280 kg / m 2 · h.
    In this case, the ammonia concentration in the flue gas was 63 (= 50 + 13) ppm, exceeding about 13 ppm relative to the equivalent required to produce ammonium sulfate [(NH 4 ) 2 SO 4 ] as a result of reaction with SO 3 . It was decided. The required equivalent was twice the number of moles of SO 3 , in this case equivalent to 50 (= 25 × 2) ppm.
    Under the conditions as described above, the experimental apparatus was run continuously for 83 hours without steel ball cleaning. After that, steel ball cleaning was performed for 2 hours.
    FIG. 7 shows the result of measuring the change in air pressure loss in the heat exchanger 85, and FIG. 8 shows the result of measuring the change in the overall heat transfer coefficient of the heat exchanger 85 as an index of the heat transfer performance.
    As can be seen from these results, even after 83 hours of continuous operation, the change in air pressure loss and overall heat transfer coefficient was relatively small. In addition, they can be completely restored to their initial state by steel ball cleaning.
    In addition, after 83 hours of continuous operation, the surface of the heating tube of the heat exchanger 85 was photographed, visually observed, and there was a slight precipitate. According to the analysis results, the precipitate mainly contains an ammonium sulfate type compound having a molar ratio of NH 4 / SO 4 of 1.5 to 1.9.
    Therefore, when ammonia is injected in an amount exceeding 13 ppm or more with respect to the SO 3 concentration, it can be seen that the formation of acidic ammonium sulfate is suppressed, which makes the precipitation removal work very easy.
    It should be understood that the present invention is not limited to the example as described above, but may be implemented in various ways.
    For example, the injection of ammonia can be carried out not only in the denitrification apparatus (or denitrification step), but also at any point downstream of the denitrification apparatus and upstream of the absorption tower. As an example, in flue 4 in the installation of FIG. 2, ammonia can be injected into flue gas to capture SO 3 and improve desulfurization performance, or ammonia for flue gas desulfurization performance in flue 25 (downstream of dry electrostatic precipitator 5), and the like. May be injected into flue gas.
    In this case, the amount of ammonia injected in the denitrification step and / or downstream point of the denitrification step, such that ammonia or ammonium salt (eg ammonium sulfate) remains in the flue gas injected into the absorption tower so as to improve the desulfurization performance of the absorption tower. The amount of ammonia injected may be set in excess of the equivalent amount required for the denitrification reaction or the equivalent amount to SO 3 .
    Further, in order to completely suppress the generation of scale due to SO 3 in the air heater 31 and the heat recovery portion 24 of the gas-gas heater, the concentration of ammonia remaining in the flue gas injected into such a heat exchanger is the concentration of SO 3 in the flue gas. The amount of ammonia injected in the denitrification step and / or the amount of ammonia injected in the downstream point of the denitrification step may be set to an excess of 13 ppm or more relative to.
    Furthermore, for example, in the example as described above in FIG. 2, the heat recovery part 24 of the air heater 31 and the gas-gas heater are separately provided, but they may be combined into a single unit. That is, for example, the air C injected into the boiler by the heat recovered from the heat exchanger installed at the position of the air heater 31 (FIG. 2) is heated, and a part of the heating medium is introduced into the reheating unit 22 of the gas-gas heater to be treated. The plant may also be constructed in such a way that it is used to heat flue gas D.
    Even when the heat recovery portions of the air heater and the gas-gas heater are separately installed, the position of the heat recovery portion of the gas-gas heater may be provided at an upstream point of the electrostatic precipitator 5.
    In this connection, if the heat recovery from the flue gas is carried out completely upstream of the electrostatic precipitator 5 and the temperature of the flue gas introduced into the electrostatic precipitator 5 is further lowered, this is especially true in the case of flue gas from coal-fired boilers. It is advantageous because the removal rate of dust (for example, suspended ash) in the electrostatic precipitator 5 is significantly improved based on the resistivity.
    As described above, miniaturization and cost reduction can be achieved by the flue gas treatment facility and the method of the present invention.
    权利要求:
    Claims (8)
    [1" claim-type="Currently amended] An absorption tower that removes at least sulfur dioxide from the flue-gas by absorbing the flue gas into the absorbing liquid by absorbing it into the absorbing liquid, a reheating unit for heating the flue gas discharged from the absorption tower to a temperature suitable for release into the atmosphere, and the absorption tower and the reheating unit. A fan for pumping flue gas so as to offset pressure loss caused by the flue gas flow path,
    Said absorption tower, said reheater and said fan arranged in a straight line on a vertical axis, thereby serving as at least part of a chimney for discharging the treated flue gas into the atmosphere.
    [2" claim-type="Currently amended] A denitrification step of decomposing nitrogen dioxide present in the flue gas by injecting ammonia into the flue gas containing at least nitrogen dioxide and sulfur dioxide, and the flue gas discharged from the denitrification step is introduced into the absorption tower and absorbed into the absorbent liquid upon contact with the absorbent liquid and gas-liquid. A flue gas treatment method comprising a desulfurization step of removing at least sulfur dioxide from the flue gas by
    And ammonia injection amount in said denitrification step and / or ammonia injection amount downstream in said denitrification step so that ammonia and ammonium salt remain in the flue gas introduced into said desulfurization step.
    [3" claim-type="Currently amended] The process of claim 2, wherein the amount of ammonia injected in the denitrification step is set so that the concentration of ammonia remaining in the flue gas discharged from the denitrification step is 30 ppm or more.
    [4" claim-type="Currently amended] 3. The method of claim 2, further comprising a heat recovery step of introducing the flue gas discharged from the denitrification step into a heat exchanger upstream of the absorption tower to recover heat from the flue gas. A flue gas treatment method using a non-leak type heat exchanger having a tube structure.
    [5" claim-type="Currently amended] The method according to claim 2 or 4, further comprising a heat recovery step of introducing the flue gas discharged from the denitrification step into a heat exchanger upstream of the absorption tower, to recover heat from the flue gas, and injected into the heat exchanger. And ammonia injection amount in the denitrification step and / or ammonia injection amount in a downstream point of the denitrification step so that the concentration of ammonia remaining in the flue gas exceeds 13 ppm or more with respect to the SO 3 concentration in the flue gas.
    [6" claim-type="Currently amended] The liquid according to any one of claims 2 to 4, wherein a liquid having a higher acidity than that of the absorbent liquid is sprayed so that ammonia is not easily released into the gaseous phase downstream of the region of the absorber tower in which the flue gas is gas-liquid contacted with the absorbent liquid. And forming an area so that the ammonia remaining in the flue gas introduced into the desulfurization step is absorbed into the absorption tower without remaining in the flue gas discharged from the absorption tower.
    [7" claim-type="Currently amended] 5. The method according to any one of claims 2 to 4, wherein the first dust removal step of removing dust present in the flue gas by introducing flue gas into a dry electric precipitator in an upstream part of the absorption tower, and in the downstream part of the absorption tower. And a second dust removing step of introducing a wet electrostatic precipitator to remove dust remaining in the flue gas.
    [8" claim-type="Currently amended] A denitrification apparatus that decomposes nitrogen dioxide contained by injecting ammonia into the flue gas, a heat exchanger that recovers heat from flue gas discharged from the denitrification device, and a flue gas discharged from the heat exchanger by absorbing gas and liquid in contact with an absorbent liquid. An absorption tower for removing at least sulfur dioxide by absorbing the absorption liquid, a reheating unit for heating flue gas discharged from the absorption tower to a temperature suitable for releasing it into the atmosphere using at least a part of the heat recovered from the heat exchanger, and the absorption tower; A fan for pumping the flue gas so as to offset pressure loss due to the flue gas flow path including the reheater,
    The absorption tower, the reheater and the fan contain at least nitrogen dioxide and sulfur dioxide using a flue gas treatment plant arranged in a straight line on a vertical axis to serve as at least part of the chimney for releasing the treated flue gas into the atmosphere. As a flue gas treatment method to purify flue gas to do,
    Inject ammonia into flue gas as necessary at the downstream point of the denitrification apparatus,
    And setting the ammonia injection amount in the denitrification apparatus and / or the ammonia injection amount in a downstream point of the denitrification apparatus so that ammonia or ammonium salt remains in the flue gas injected into the absorption tower.
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    同族专利:
    公开号 | 公开日
    ID20175A|1998-10-22|
    EP0873777A2|1998-10-28|
    ES2200233T3|2004-03-01|
    CN1101721C|2003-02-19|
    EP0873777A3|1999-03-31|
    PL190656B1|2005-12-30|
    JPH10290919A|1998-11-04|
    DE69816509D1|2003-08-28|
    CN1387940A|2003-01-01|
    EP0873777B1|2003-07-23|
    EP1182400A1|2002-02-27|
    CZ117898A3|1998-11-11|
    CZ291726B6|2003-05-14|
    TR199800736A2|1999-10-21|
    TR199800736A3|1999-10-21|
    CN1192816C|2005-03-16|
    DE69816509T2|2004-04-15|
    JP3676032B2|2005-07-27|
    TW410169B|2000-11-01|
    DK873777T3|
    CN1205913A|1999-01-27|
    DK0873777T3|2003-11-03|
    PL325896A1|1998-10-26|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    法律状态:
    1997-04-21|Priority to JP11752197A
    1997-04-21|Priority to JP117521/1997
    1998-04-20|Application filed by 마스다노부유끼, 미쯔비시헤비인더스트리즈,리미티드
    1998-11-25|Publication of KR19980081553A
    2001-04-16|Application granted
    2001-04-16|Publication of KR100287634B1
    优先权:
    申请号 | 申请日 | 专利标题
    JP11752197A|JP3676032B2|1997-04-21|1997-04-21|Smoke exhaust treatment facility and smoke exhaust treatment method|
    JP117521/1997|1997-04-21|
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