CA2622549A1 - Sulfur trioxide removal from a flue gas stream - Google Patents
Sulfur trioxide removal from a flue gas stream Download PDFInfo
- Publication number
- CA2622549A1 CA2622549A1 CA002622549A CA2622549A CA2622549A1 CA 2622549 A1 CA2622549 A1 CA 2622549A1 CA 002622549 A CA002622549 A CA 002622549A CA 2622549 A CA2622549 A CA 2622549A CA 2622549 A1 CA2622549 A1 CA 2622549A1
- Authority
- CA
- Canada
- Prior art keywords
- flue gas
- additive
- trona
- sorbent composition
- gas stream
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
- 239000003546 flue gas Substances 0.000 title claims abstract description 88
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 title claims abstract description 87
- AKEJUJNQAAGONA-UHFFFAOYSA-N sulfur trioxide Chemical compound O=S(=O)=O AKEJUJNQAAGONA-UHFFFAOYSA-N 0.000 title claims description 32
- 239000002594 sorbent Substances 0.000 claims abstract description 81
- 239000000203 mixture Substances 0.000 claims abstract description 72
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 claims abstract description 68
- 238000000034 method Methods 0.000 claims abstract description 67
- 241001625808 Trona Species 0.000 claims abstract description 58
- 239000000654 additive Substances 0.000 claims abstract description 45
- 230000000996 additive effect Effects 0.000 claims abstract description 45
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 claims abstract description 38
- 229910000019 calcium carbonate Inorganic materials 0.000 claims abstract description 19
- WBHQBSYUUJJSRZ-UHFFFAOYSA-M sodium bisulfate Chemical compound [Na+].OS([O-])(=O)=O WBHQBSYUUJJSRZ-UHFFFAOYSA-M 0.000 claims abstract description 17
- 229910000342 sodium bisulfate Inorganic materials 0.000 claims abstract description 17
- 239000007795 chemical reaction product Substances 0.000 claims abstract description 14
- ZLNQQNXFFQJAID-UHFFFAOYSA-L magnesium carbonate Chemical compound [Mg+2].[O-]C([O-])=O ZLNQQNXFFQJAID-UHFFFAOYSA-L 0.000 claims abstract description 14
- 239000001095 magnesium carbonate Substances 0.000 claims abstract description 14
- 229910000021 magnesium carbonate Inorganic materials 0.000 claims abstract description 14
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 claims abstract description 12
- 239000011734 sodium Substances 0.000 claims abstract description 12
- 229910052708 sodium Inorganic materials 0.000 claims abstract description 12
- AXCZMVOFGPJBDE-UHFFFAOYSA-L calcium dihydroxide Chemical compound [OH-].[OH-].[Ca+2] AXCZMVOFGPJBDE-UHFFFAOYSA-L 0.000 claims abstract description 9
- 239000000920 calcium hydroxide Substances 0.000 claims abstract description 9
- 229910001861 calcium hydroxide Inorganic materials 0.000 claims abstract description 9
- VTHJTEIRLNZDEV-UHFFFAOYSA-L magnesium dihydroxide Chemical compound [OH-].[OH-].[Mg+2] VTHJTEIRLNZDEV-UHFFFAOYSA-L 0.000 claims abstract description 9
- 239000000347 magnesium hydroxide Substances 0.000 claims abstract description 9
- 229910001862 magnesium hydroxide Inorganic materials 0.000 claims abstract description 9
- 239000007791 liquid phase Substances 0.000 claims abstract description 8
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 5
- 238000002347 injection Methods 0.000 claims description 17
- 239000007924 injection Substances 0.000 claims description 17
- 239000002245 particle Substances 0.000 claims description 17
- 239000000463 material Substances 0.000 claims description 6
- 238000011144 upstream manufacturing Methods 0.000 claims description 6
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 claims description 3
- 239000011593 sulfur Substances 0.000 claims description 3
- 229910052717 sulfur Inorganic materials 0.000 claims description 3
- UIIMBOGNXHQVGW-DEQYMQKBSA-M Sodium bicarbonate-14C Chemical compound [Na+].O[14C]([O-])=O UIIMBOGNXHQVGW-DEQYMQKBSA-M 0.000 claims description 2
- UIIMBOGNXHQVGW-UHFFFAOYSA-M Sodium bicarbonate Chemical compound [Na+].OC([O-])=O UIIMBOGNXHQVGW-UHFFFAOYSA-M 0.000 abstract description 18
- 235000017557 sodium bicarbonate Nutrition 0.000 abstract description 9
- 229910000030 sodium bicarbonate Inorganic materials 0.000 abstract description 9
- 239000007789 gas Substances 0.000 description 20
- 239000002253 acid Substances 0.000 description 16
- 238000006243 chemical reaction Methods 0.000 description 10
- 239000012717 electrostatic precipitator Substances 0.000 description 10
- QAOWNCQODCNURD-UHFFFAOYSA-N Sulfuric acid Chemical compound OS(O)(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-N 0.000 description 7
- 239000003570 air Substances 0.000 description 7
- 239000002956 ash Substances 0.000 description 6
- 239000010881 fly ash Substances 0.000 description 6
- 241000196324 Embryophyta Species 0.000 description 5
- 229910000029 sodium carbonate Inorganic materials 0.000 description 5
- 235000017550 sodium carbonate Nutrition 0.000 description 5
- 229910000031 sodium sesquicarbonate Inorganic materials 0.000 description 5
- 235000018341 sodium sesquicarbonate Nutrition 0.000 description 5
- 239000007787 solid Substances 0.000 description 5
- WCTAGTRAWPDFQO-UHFFFAOYSA-K trisodium;hydrogen carbonate;carbonate Chemical compound [Na+].[Na+].[Na+].OC([O-])=O.[O-]C([O-])=O WCTAGTRAWPDFQO-UHFFFAOYSA-K 0.000 description 5
- 150000007513 acids Chemical class 0.000 description 4
- 238000002485 combustion reaction Methods 0.000 description 4
- 238000006477 desulfuration reaction Methods 0.000 description 4
- 230000023556 desulfurization Effects 0.000 description 4
- 239000007788 liquid Substances 0.000 description 4
- 239000003595 mist Substances 0.000 description 4
- 238000004140 cleaning Methods 0.000 description 3
- 239000003245 coal Substances 0.000 description 3
- 239000000446 fuel Substances 0.000 description 3
- 235000011149 sulphuric acid Nutrition 0.000 description 3
- 239000012080 ambient air Substances 0.000 description 2
- 239000003054 catalyst Substances 0.000 description 2
- 239000003153 chemical reaction reagent Substances 0.000 description 2
- 230000003247 decreasing effect Effects 0.000 description 2
- GNTDGMZSJNCJKK-UHFFFAOYSA-N divanadium pentaoxide Chemical compound O=[V](=O)O[V](=O)=O GNTDGMZSJNCJKK-UHFFFAOYSA-N 0.000 description 2
- XLYOFNOQVPJJNP-ZSJDYOACSA-N heavy water Substances [2H]O[2H] XLYOFNOQVPJJNP-ZSJDYOACSA-N 0.000 description 2
- 229910052500 inorganic mineral Inorganic materials 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 235000010755 mineral Nutrition 0.000 description 2
- 239000011707 mineral Substances 0.000 description 2
- 238000010587 phase diagram Methods 0.000 description 2
- 239000000047 product Substances 0.000 description 2
- 238000010791 quenching Methods 0.000 description 2
- 239000000126 substance Substances 0.000 description 2
- 235000008733 Citrus aurantifolia Nutrition 0.000 description 1
- 235000007877 Diospyros australis Nutrition 0.000 description 1
- 235000019738 Limestone Nutrition 0.000 description 1
- 239000007832 Na2SO4 Substances 0.000 description 1
- 235000010875 Prunus nigra Nutrition 0.000 description 1
- 240000002577 Prunus nigra Species 0.000 description 1
- PMZURENOXWZQFD-UHFFFAOYSA-L Sodium Sulfate Chemical compound [Na+].[Na+].[O-]S([O-])(=O)=O PMZURENOXWZQFD-UHFFFAOYSA-L 0.000 description 1
- 235000011941 Tilia x europaea Nutrition 0.000 description 1
- 235000018288 Vitex doniana Nutrition 0.000 description 1
- 239000003513 alkali Substances 0.000 description 1
- 239000002585 base Substances 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 239000006227 byproduct Substances 0.000 description 1
- 238000001354 calcination Methods 0.000 description 1
- 230000003197 catalytic effect Effects 0.000 description 1
- 238000010531 catalytic reduction reaction Methods 0.000 description 1
- 239000000567 combustion gas Substances 0.000 description 1
- 230000000052 comparative effect Effects 0.000 description 1
- 239000000470 constituent Substances 0.000 description 1
- 238000001816 cooling Methods 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 231100001261 hazardous Toxicity 0.000 description 1
- 239000004571 lime Substances 0.000 description 1
- 239000006028 limestone Substances 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- -1 most alkali reagents Chemical compound 0.000 description 1
- 239000003345 natural gas Substances 0.000 description 1
- 230000001473 noxious effect Effects 0.000 description 1
- 239000003921 oil Substances 0.000 description 1
- 230000003647 oxidation Effects 0.000 description 1
- 238000007254 oxidation reaction Methods 0.000 description 1
- 230000001590 oxidative effect Effects 0.000 description 1
- 238000000746 purification Methods 0.000 description 1
- 230000000171 quenching effect Effects 0.000 description 1
- 238000006722 reduction reaction Methods 0.000 description 1
- 150000003839 salts Chemical class 0.000 description 1
- 238000005201 scrubbing Methods 0.000 description 1
- 239000002002 slurry Substances 0.000 description 1
- 229910052938 sodium sulfate Inorganic materials 0.000 description 1
- 235000011152 sodium sulphate Nutrition 0.000 description 1
- 239000007921 spray Substances 0.000 description 1
- 239000002341 toxic gas Substances 0.000 description 1
- 238000013022 venting Methods 0.000 description 1
- 239000002699 waste material Substances 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Chemical compound O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 1
- 238000005200 wet scrubbing Methods 0.000 description 1
Classifications
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/48—Sulfur compounds
- B01D53/50—Sulfur oxides
- B01D53/508—Sulfur oxides by treating the gases with solids
Landscapes
- Engineering & Computer Science (AREA)
- Chemical & Material Sciences (AREA)
- Health & Medical Sciences (AREA)
- Biomedical Technology (AREA)
- Environmental & Geological Engineering (AREA)
- Analytical Chemistry (AREA)
- General Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Treating Waste Gases (AREA)
Abstract
A method of removing SO3 from a flue gas stream having increased amounts of SO3 formed by a NOx removal system, includes injecting a sorbent composition into the flue gas stream. The sorbent composition includes an additive and a sodium sorbent such as mechanically refined trona or sodium bicarbonate. The additive is selected magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The concentration of the SO3 in the flue gas stream is reduced and the formation of a liquid phase NaHSO4 reaction product is minimized.
Description
Sulfur trioxide removal from a flue gas stream The present invention relates to the purification of gases, and more particularly to a method of purifying flue gases which contain noxious gases such as SO3.
SO3 is a noxious gas that is produced from the combustion of sulfur-containing fuel. When present in flue gas, the SO3 can form an acid mist that condenses in electrostatic precipitators, ducts or bag houses, causing corrosion.
SO3 at concentrations as low as 5-10 ppm in exhaust gas can also result in white, blue, purple, or black plumes from the cooling of the hot stack gas in the cooler air in the atmosphere.
The effort to reduce NOX emissions from coal-fired power plants via selective catalytic reactors (SCRs) has resulted in the unintended consequence of oxidizing SOz to SO3 and thereby increasing total SO3 emissions. SCRs employ a catalyst (typically vanadium pentoxide) to convert NOX to N2 and H20 with the addition of NH3, but there is also an unintended oxidation of the SOz to SO3.
Although the higher stack SO3 concentrations are still relatively low, the emissions can sometimes produce a highly visible secondary plume, which, although unregulated, is nonetheless perceived by many to be problematic.
Efforts to reduce the SO3 levels to a point where no secondary SO3 plume is visible can impede particulate collection for stations that employ electrostatic precipitators (ESPs). SO3 in the flue gas absorbs onto the fly ash particles and lowers fly ash resistivity, thereby enabling the ESP to capture the particle by electrostatic means. Many plants actually inject SO3 to lower fly ash resistivity when ash resistivity is too high.
SO3 reacts with water vapor in the flue gas ducts of the coal power plant and forms vaporous H2SO4. A portion of this condenses out in the air heater baskets. Another portion of the sulfuric acid vapor can condense in the duct if the duct temperature is too low, thereby corroding the duct. The remaining acid vapor condenses either when the plume is quenched when it contacts the relatively cold atmosphere or when wet scrubbers are employed for flue gas desulfurization (FGD), in the scrubber's quench zone. The rapid quenching of the acid vapor in the FGD tower results in a fine acid mist. The droplets are often too fine to be absorbed in the FGD tower or to be captured in the mist eliminator. Thus, there is only limited SO3 removal by the FGD towers. If the sulfuric acid levels emitted from the stack are high enough, a secondary plume appears.
Dry sorbent injection (DSI) has been used with a variety of sorbents to remove SO3 and other gases from flue gas. However, DSI has typically been done in the past at temperatures lower than around 370 F because equipment material, such as baghouse media, cannot withstand higher temperatures.
Additionally, many sorbent materials sinter or melt at temperatures greater than around 400 F, which makes them less effective at removing gases. Another problem is that under certain temperature and gas concentration conditions the reaction products of many sorbent materials adhere to equipment and ducts, which requires frequent cleaning of the process equipment.
In one aspect, a method of removing SO3 from a flue gas stream having increased amounts of SO3 formed by a NOX removal system, includes injecting a sorbent composition into the flue gas stream. The sorbent composition includes an additive and a sodium sorbent such as mechanically refined trona or sodium bicarbonate. The additive is selected magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The concentration of the SO3 in the flue gas stream is reduced and the formation of a liquid phase NaHSO4 reaction product is minimized.
In another aspect, a method of delivering a dry sorbent for flue gas injection includes providing trona. A sorbent composition is formed by combining with the trona an additive selected from magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The sorbent composition is transported in a vessel to the location of a flue gas injection. The sorbent composition is offloaded out of the vessel and injected into the flue gas stream. Sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.
The foregoing paragraphs have been provided by way of general introduction, and are not intended to limit the scope of the following claims.
The presently preferred embodiments, together with further advantages, will be best understood by reference to the following detailed description taken in conjunction with the accompanying drawings.
FIG. 1 is a phase diagram showing the reaction products of trona with SO3 as a function of flue gas temperature and SO3 concentration.
SO3 is a noxious gas that is produced from the combustion of sulfur-containing fuel. When present in flue gas, the SO3 can form an acid mist that condenses in electrostatic precipitators, ducts or bag houses, causing corrosion.
SO3 at concentrations as low as 5-10 ppm in exhaust gas can also result in white, blue, purple, or black plumes from the cooling of the hot stack gas in the cooler air in the atmosphere.
The effort to reduce NOX emissions from coal-fired power plants via selective catalytic reactors (SCRs) has resulted in the unintended consequence of oxidizing SOz to SO3 and thereby increasing total SO3 emissions. SCRs employ a catalyst (typically vanadium pentoxide) to convert NOX to N2 and H20 with the addition of NH3, but there is also an unintended oxidation of the SOz to SO3.
Although the higher stack SO3 concentrations are still relatively low, the emissions can sometimes produce a highly visible secondary plume, which, although unregulated, is nonetheless perceived by many to be problematic.
Efforts to reduce the SO3 levels to a point where no secondary SO3 plume is visible can impede particulate collection for stations that employ electrostatic precipitators (ESPs). SO3 in the flue gas absorbs onto the fly ash particles and lowers fly ash resistivity, thereby enabling the ESP to capture the particle by electrostatic means. Many plants actually inject SO3 to lower fly ash resistivity when ash resistivity is too high.
SO3 reacts with water vapor in the flue gas ducts of the coal power plant and forms vaporous H2SO4. A portion of this condenses out in the air heater baskets. Another portion of the sulfuric acid vapor can condense in the duct if the duct temperature is too low, thereby corroding the duct. The remaining acid vapor condenses either when the plume is quenched when it contacts the relatively cold atmosphere or when wet scrubbers are employed for flue gas desulfurization (FGD), in the scrubber's quench zone. The rapid quenching of the acid vapor in the FGD tower results in a fine acid mist. The droplets are often too fine to be absorbed in the FGD tower or to be captured in the mist eliminator. Thus, there is only limited SO3 removal by the FGD towers. If the sulfuric acid levels emitted from the stack are high enough, a secondary plume appears.
Dry sorbent injection (DSI) has been used with a variety of sorbents to remove SO3 and other gases from flue gas. However, DSI has typically been done in the past at temperatures lower than around 370 F because equipment material, such as baghouse media, cannot withstand higher temperatures.
Additionally, many sorbent materials sinter or melt at temperatures greater than around 400 F, which makes them less effective at removing gases. Another problem is that under certain temperature and gas concentration conditions the reaction products of many sorbent materials adhere to equipment and ducts, which requires frequent cleaning of the process equipment.
In one aspect, a method of removing SO3 from a flue gas stream having increased amounts of SO3 formed by a NOX removal system, includes injecting a sorbent composition into the flue gas stream. The sorbent composition includes an additive and a sodium sorbent such as mechanically refined trona or sodium bicarbonate. The additive is selected magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The concentration of the SO3 in the flue gas stream is reduced and the formation of a liquid phase NaHSO4 reaction product is minimized.
In another aspect, a method of delivering a dry sorbent for flue gas injection includes providing trona. A sorbent composition is formed by combining with the trona an additive selected from magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The sorbent composition is transported in a vessel to the location of a flue gas injection. The sorbent composition is offloaded out of the vessel and injected into the flue gas stream. Sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.
The foregoing paragraphs have been provided by way of general introduction, and are not intended to limit the scope of the following claims.
The presently preferred embodiments, together with further advantages, will be best understood by reference to the following detailed description taken in conjunction with the accompanying drawings.
FIG. 1 is a phase diagram showing the reaction products of trona with SO3 as a function of flue gas temperature and SO3 concentration.
FIG. 2 is a schematic of one embodiment of a flue gas desulfurization system.
The invention is described with reference to the drawings in which like elements are referred to by like numerals. The relationship and functioning of the various elements of this invention are better understood by the following detailed description. However, the embodiments of this invention as described below are by way of example only, and the invention is not limited to the embodiments illustrated in the drawings.
Dry sorbent injection (DSI) has been used as a low cost alternative to a spray dry or wet scrubbing system for the removal of SO3. In the DSI process, the sorbent is stored and injected dry into the flue duct where it reacts with the acid gas. Under certain processing conditions, the reaction product of the sorbent and the acid gas is a sticky ash. The sticky ash tends to stick to the process equipment and ducts, thus requiring frequent cleaning. Thus, it would be beneficial to have a process that minimizes the amount of sticky ash reaction product.
A particular sorbent that may be used in SO3 removal is trona. Trona is a mineral that contains about 85-95% sodium sesquicarbonate (Na2CO3=NaHCO3=2H2O). A vast deposit of mineral trona is found in southwestern Wyoming near Green River. As used herein, the term "trona"
includes other sources of sodium sesquicarbonate. Another sorbent that may be used is sodium bicarbonate. The term "flue gas" includes the exhaust gas from any sort of combustion process (including coal, oil, natural gas, etc.). Flue gas typically includes acid gases such as SOz, HC1, SO3, and NOX.
When heated at or above 275 F, sodium sesquicarbonate undergoes rapid calcination of contained sodium bicarbonate to sodium carbonate, as shown in the following reaction:
2[ NazCO3 = NaHCO3 = 2H2O] --* 3Na2CO3 + 5H20 + COz A preferred chemical reaction of the sorbent composition with the SO3 is represented below:
Na2CO3 + SO3 --* Na2SO4 + COz However, under certain conditions, undesirable reactions may occur which produce sodium bisulfate. If the sodium sesquicarbonate is not completely calcined before reaction with SO3, the following reaction occurs:
NaHCO3 + SO3 , NaHSO4 + SO3 Under certain conditions, another undesirable reaction produces sodium bisulfate as represented below:
Na2CO3 + SO3 + H2SO4 , 2NaHSO4 + COz Sodium bisulfate is an acid salt with a low melt temperature and is unstable at high temperatures, decomposing as indicated in the following reaction:
2NaHSO4 --* NazSzO7 The type of reaction product of the NazCO3 and the SO3 depends on the SO3 concentration and the temperature of the flue gas. FIG. 1 is a phase diagram showing the typical reaction products of trona with SO3 as a function of flue gas temperature and SO3 concentration. In particular, above a certain SO3 concentration, the reaction product can be solid NaHSO4, liquid NaHSO4, NazSO4, or NazSz07, depending on the flue gas temperature.
Liquid NaHSO4 is particularly undesirable because it is "sticky" and tends to adhere to the process equipment, and cause other particulates, such as fly ash, to also stick to the equipment. Thus, it may be desirable to operate the process under conditions where the amount of liquid NaHSO4 reaction product is minimized. The boundary in FIG. 1 between the liquid NaHSO4 and the solid Naz SO4 at a temperature above 370 F may be represented by the equation log[S03]=0.009135T-2.456, where log[S03] is the log base 10 of the SO3 concentration in ppm and T is the flue gas temperature in F. Thus, when trona is injected into flue gas at temperatures between about 370 F and about 525 F, and at an SO3 concentration greater than the amount defined by log[S03]=0.009135T-2.456, liquid phase NaHSO4 reaction product is formed.
It has been found that using a sorbent composition comprising mechanically refined trona and an additive minimizes the amount of sticky ash formed in the process. Sodium bicarbonate may be used in place of trona. The additive is selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The additive preferably includes magnesium carbonate, calcium carbonate, or mixtures thereof, and most preferably includes calcium carbonate. The additive is preferably between 0.1% and 5%, most preferably between 0.5% and 2%, by weight of the trona or other sodium sorbent. The sorbent composition is injected into the flue gas stream. The sorbent composition is maintained in contact with the flue gas for a time sufficient to react a portion of the sorbent composition with a portion of the SO3 to reduce the concentration of the SO3 in the flue gas stream. Preferably, formation of a liquid phase NaHSO4 reaction product is minimized so that little sticky ash is formed. While not intending to be bound by theory, it is believed that the additive reacts with the H2SO4 present in the flue gas stream to remove it thereform, thus minimizing the production of liquid phase NaHSO4.
Thus, the system may be operated in a range of temperatures and SO3 concentrations where liquid phase NaHSO4 would form in the absence of the additive. In one embodiment, the temperature of the flue gas where the trona is injected is between about 370 F and about 500 F. The temperature of the flue gas is preferably greater than about 370 F, and more preferably greater than about 385 F. The temperature of the flue gas is preferably less than about F, more preferably less than about 450 F, and most preferably less than about 415 F. The temperature of the flue gas is most preferably between about 385 F
and about 415 F. Alternatively, the temperature range can be expressed as a function of the SO3 concentration. Thus, the process may be operated at a temperature and SO3 concentration where log[S03]>0.009135T-2.456, where [SO3] is the SO3 concentration in ppm and T is the flue gas temperature in F.
The SO3 concentration of the flue gas stream to be treated is generally at least about 3 ppm, and commonly between about 10 ppm and about 200 ppm.
The desired outlet SO3 concentration of the gas stack is preferably less than about 50 ppm, more preferably less than about 20 ppm, more preferably less than about 10 ppm, and most preferably less than about 5 ppm. The byproduct of the reaction is collected with fly ash.
Trona, like most alkali reagents, will tend to react more rapidly with the stronger acids in the gas stream first, and then after some residence time it will react with the weaker acids. Such gas constituents as HC1 and SO3 are strong acids and trona will react much more rapidly with these acids than it will with a weak acid such as SOz. Thus, the injected sorbent composition can be used to selectively remove SO3 without substantially decreasing the amount of SOz in the flue gas stream.
A schematic of one embodiment of the process is shown in FIG. 2. The furnace or combustor 10 is fed with a fuel source 12, such as coal, and with air 14 to burn the fuel source 12. From the combustor 10, the combustion gases are conducted to a heat exchanger or air heater 30. Ambient air 32 may be injected to lower the flue gas temperature. A selective catalytic reduction (SCR) device 20 may be used to remove NOX gases. A bypass damper 22 can be opened to bypass the flue gas from the SCR. The outlet of the heat exchanger or air heater 30 is connected to a particulate collection device 50. The particulate collection device 50 removes particles made during the combustion process, such as fly ash, from the flue gas before it is conducted to an optional wet scrubber vesse154 and then to the gas stack 60 for venting. The particulate collection device 50 may be an electrostatic precipitator (ESP). Other types of particulate collection devices, such as a baghouse, may also be used for solids removal. The baghouse contains filters for separating particles made during the combustion process from the flue gas.
The SO3 removal system includes a source of sorbent composition 40. The sorbent composition includes an additive and a sodium sorbent such as trona or sodium bicarbonate. The sodium sorbent is preferably trona. The trona is preferably provided as particles with a mean particle size between about 10 micron and about 40 micron, most preferably between about 24 micron and about 28 micron. The mean particle size of the additive may be generally about the same size as the trona and is preferably between about 10 micron and about micron. The sorbent composition is preferably in a dry granular form.
A suitable trona source is T-200 trona, which is a mechanically refined 20 trona ore product available from Solvay Chemicals. T-200 trona contains about 97.5% sodium sesquicarbonate and has a mean particle size of about 24-28 micron. The system may also include a ball mill pulverizer, or other type of mill, for decreasing and/or otherwise controlling the particle size of the trona or other sorbent compositions.
25 It has also been found that the additive may improve the flow properties of the trona when added thereto. A method of delivering a dry sorbent for flue gas injection includes combining the additive and trona to form a sorbent composition. The additive may be magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The sorbent composition is transported in a vessel to the location of a flue gas injection. The sorbent composition is offloaded out of the vessel and injected into the flue gas stream, wherein sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.
The sorbent composition is conveyed from the sorbent composition source 40 to the injector 42. The sorbent composition may be conveyed pneumatically or by any other suitable method. As shown in FIG. 2, the injection apparatus introduces the sorbent composition into flue gas duct section 44, which is disposed at a position upstream of the baghouse inlet and preferably downstream of the heat exchanger outlet. The injection system is preferably designed to maximize contact of the sorbent composition with the SO3 in the flue gas stream.
Any type of injection apparatus known in the art may be used to introduce the sorbent composition into the gas duct. For example, injection can be accomplished directly by a compressed air-driven eductor.
The process requires no slurry equipment or reactor vessel if the sorbent composition is stored and injected dry into the flue duct 44 where it reacts with the acid gas. However, the process may also be used with humidification of the flue gas or wet injection of the sorbent composition. Additionally, the particulates can be collected wet through a wet scrubber vesse154 should the process be used for trim scrubbing of acid mist. In particular, the flue gas desulfurization system may be operated so that the SO3 removal is accomplished by injecting the sorbent composition into the flue gas, while the majority of the SOz is removed by the wet scrubber 54.
The process may also be varied to control the flue gas temperature. For example, the flue gas temperature upstream of the trona or other sodium sorbent may be adjusted to obtain the desired flue gas temperature where the sorbent composition is injected. Additionally, ambient air 32 may be introduced into the flue gas stream to lower the flue gas temperature and the flue gas temperature monitored where the sorbent composition is injected. Other possible methods of controlling the flue gas temperature include using heat exchanges and/or air coolers. The process may also vary the trona injection location or include multiple locations for sorbent composition injection.
For the achievement of desulfurization, the sorbent composition is preferably injected at a rate with respect to the flow rate of the SO3 to provide a normalized stoichiometric ratio (NSR) of sodium to sulfur of about 1.0 or greater. The NSR is a measure of the amount of reagent injected relative to the amount theoretically required. The NSR expresses the stoichiometric amount of sorbent required to react with all of the acid gas. For example, an NSR of 1.0 would mean that enough material was injected to theoretically yield 100 percent removal of the SO3 in the inlet flue gas; an NSR of 0.5 would theoretically yield 50 percent SO3 removal. The reaction of SO3 with the sodium carbonate is very fast and efficient, so that a NSR of only about one is generally required for removal. The sorbent composition preferentially reacts with SO3 over SOz, so SO3 will be removed even if large amounts of SOz are present. Preferably, an NSR of less than 2.0 or more preferably less than 1.5 is used such that there is no substantial reduction of the SOz concentration in the flue gas caused by reaction with excess sorbent.
Because NOX removal systems tend to oxidize existing SOz into SO3, the injection system may also be combined with an NOX removal system. The trona injection system may also be combined with other SOX removal systems, such as sodium bicarbonate, lime, limestone, etc. in order to enhance performance or remove additional hazardous gases such as HC1, NOX, and the like.
An electric generation plant uses a hot side electrostatic precipitator (ESP) and no baghouse. The plant uses a catalyst for NOX removal, which causes elevated SO3 levels in the flue gas. The SO3 concentration in the flue gas is between about 100 ppm and about 125 ppm. T-200 trona from Solvay Chemicals is injected to remove SO3 from the flue gas.
As a comparative example, trona is injected at a temperature of 400 F
with no additive at NSR values of about 1.5. The perforated plates of the ESP
in the plant exhibit significant solids buildup which requires frequent cleaning.
A sorbent composition comprising trona and 1% calcium carbonate is injected into flue gas at a temperature of 400 F at NSR values of about 1.5.
A
perforated plate of an ESP in the plant after operation of the SO3 removal system is relatively free of solids buildup.
According to the present invention, using an additive reduces the amount of sticky waste products in the SO3 removal process, compared to a process using trona without an additive under the same processing conditions.
The embodiments described above and shown herein are illustrative and not restrictive. The scope of the invention is indicated by the claims rather than by the foregoing description and attached drawings. The invention may be embodied in other specific forms without departing from the spirit of the invention. Accordingly, these and any other changes which come within the scope of the claims are intended to be embraced therein.
The invention is described with reference to the drawings in which like elements are referred to by like numerals. The relationship and functioning of the various elements of this invention are better understood by the following detailed description. However, the embodiments of this invention as described below are by way of example only, and the invention is not limited to the embodiments illustrated in the drawings.
Dry sorbent injection (DSI) has been used as a low cost alternative to a spray dry or wet scrubbing system for the removal of SO3. In the DSI process, the sorbent is stored and injected dry into the flue duct where it reacts with the acid gas. Under certain processing conditions, the reaction product of the sorbent and the acid gas is a sticky ash. The sticky ash tends to stick to the process equipment and ducts, thus requiring frequent cleaning. Thus, it would be beneficial to have a process that minimizes the amount of sticky ash reaction product.
A particular sorbent that may be used in SO3 removal is trona. Trona is a mineral that contains about 85-95% sodium sesquicarbonate (Na2CO3=NaHCO3=2H2O). A vast deposit of mineral trona is found in southwestern Wyoming near Green River. As used herein, the term "trona"
includes other sources of sodium sesquicarbonate. Another sorbent that may be used is sodium bicarbonate. The term "flue gas" includes the exhaust gas from any sort of combustion process (including coal, oil, natural gas, etc.). Flue gas typically includes acid gases such as SOz, HC1, SO3, and NOX.
When heated at or above 275 F, sodium sesquicarbonate undergoes rapid calcination of contained sodium bicarbonate to sodium carbonate, as shown in the following reaction:
2[ NazCO3 = NaHCO3 = 2H2O] --* 3Na2CO3 + 5H20 + COz A preferred chemical reaction of the sorbent composition with the SO3 is represented below:
Na2CO3 + SO3 --* Na2SO4 + COz However, under certain conditions, undesirable reactions may occur which produce sodium bisulfate. If the sodium sesquicarbonate is not completely calcined before reaction with SO3, the following reaction occurs:
NaHCO3 + SO3 , NaHSO4 + SO3 Under certain conditions, another undesirable reaction produces sodium bisulfate as represented below:
Na2CO3 + SO3 + H2SO4 , 2NaHSO4 + COz Sodium bisulfate is an acid salt with a low melt temperature and is unstable at high temperatures, decomposing as indicated in the following reaction:
2NaHSO4 --* NazSzO7 The type of reaction product of the NazCO3 and the SO3 depends on the SO3 concentration and the temperature of the flue gas. FIG. 1 is a phase diagram showing the typical reaction products of trona with SO3 as a function of flue gas temperature and SO3 concentration. In particular, above a certain SO3 concentration, the reaction product can be solid NaHSO4, liquid NaHSO4, NazSO4, or NazSz07, depending on the flue gas temperature.
Liquid NaHSO4 is particularly undesirable because it is "sticky" and tends to adhere to the process equipment, and cause other particulates, such as fly ash, to also stick to the equipment. Thus, it may be desirable to operate the process under conditions where the amount of liquid NaHSO4 reaction product is minimized. The boundary in FIG. 1 between the liquid NaHSO4 and the solid Naz SO4 at a temperature above 370 F may be represented by the equation log[S03]=0.009135T-2.456, where log[S03] is the log base 10 of the SO3 concentration in ppm and T is the flue gas temperature in F. Thus, when trona is injected into flue gas at temperatures between about 370 F and about 525 F, and at an SO3 concentration greater than the amount defined by log[S03]=0.009135T-2.456, liquid phase NaHSO4 reaction product is formed.
It has been found that using a sorbent composition comprising mechanically refined trona and an additive minimizes the amount of sticky ash formed in the process. Sodium bicarbonate may be used in place of trona. The additive is selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The additive preferably includes magnesium carbonate, calcium carbonate, or mixtures thereof, and most preferably includes calcium carbonate. The additive is preferably between 0.1% and 5%, most preferably between 0.5% and 2%, by weight of the trona or other sodium sorbent. The sorbent composition is injected into the flue gas stream. The sorbent composition is maintained in contact with the flue gas for a time sufficient to react a portion of the sorbent composition with a portion of the SO3 to reduce the concentration of the SO3 in the flue gas stream. Preferably, formation of a liquid phase NaHSO4 reaction product is minimized so that little sticky ash is formed. While not intending to be bound by theory, it is believed that the additive reacts with the H2SO4 present in the flue gas stream to remove it thereform, thus minimizing the production of liquid phase NaHSO4.
Thus, the system may be operated in a range of temperatures and SO3 concentrations where liquid phase NaHSO4 would form in the absence of the additive. In one embodiment, the temperature of the flue gas where the trona is injected is between about 370 F and about 500 F. The temperature of the flue gas is preferably greater than about 370 F, and more preferably greater than about 385 F. The temperature of the flue gas is preferably less than about F, more preferably less than about 450 F, and most preferably less than about 415 F. The temperature of the flue gas is most preferably between about 385 F
and about 415 F. Alternatively, the temperature range can be expressed as a function of the SO3 concentration. Thus, the process may be operated at a temperature and SO3 concentration where log[S03]>0.009135T-2.456, where [SO3] is the SO3 concentration in ppm and T is the flue gas temperature in F.
The SO3 concentration of the flue gas stream to be treated is generally at least about 3 ppm, and commonly between about 10 ppm and about 200 ppm.
The desired outlet SO3 concentration of the gas stack is preferably less than about 50 ppm, more preferably less than about 20 ppm, more preferably less than about 10 ppm, and most preferably less than about 5 ppm. The byproduct of the reaction is collected with fly ash.
Trona, like most alkali reagents, will tend to react more rapidly with the stronger acids in the gas stream first, and then after some residence time it will react with the weaker acids. Such gas constituents as HC1 and SO3 are strong acids and trona will react much more rapidly with these acids than it will with a weak acid such as SOz. Thus, the injected sorbent composition can be used to selectively remove SO3 without substantially decreasing the amount of SOz in the flue gas stream.
A schematic of one embodiment of the process is shown in FIG. 2. The furnace or combustor 10 is fed with a fuel source 12, such as coal, and with air 14 to burn the fuel source 12. From the combustor 10, the combustion gases are conducted to a heat exchanger or air heater 30. Ambient air 32 may be injected to lower the flue gas temperature. A selective catalytic reduction (SCR) device 20 may be used to remove NOX gases. A bypass damper 22 can be opened to bypass the flue gas from the SCR. The outlet of the heat exchanger or air heater 30 is connected to a particulate collection device 50. The particulate collection device 50 removes particles made during the combustion process, such as fly ash, from the flue gas before it is conducted to an optional wet scrubber vesse154 and then to the gas stack 60 for venting. The particulate collection device 50 may be an electrostatic precipitator (ESP). Other types of particulate collection devices, such as a baghouse, may also be used for solids removal. The baghouse contains filters for separating particles made during the combustion process from the flue gas.
The SO3 removal system includes a source of sorbent composition 40. The sorbent composition includes an additive and a sodium sorbent such as trona or sodium bicarbonate. The sodium sorbent is preferably trona. The trona is preferably provided as particles with a mean particle size between about 10 micron and about 40 micron, most preferably between about 24 micron and about 28 micron. The mean particle size of the additive may be generally about the same size as the trona and is preferably between about 10 micron and about micron. The sorbent composition is preferably in a dry granular form.
A suitable trona source is T-200 trona, which is a mechanically refined 20 trona ore product available from Solvay Chemicals. T-200 trona contains about 97.5% sodium sesquicarbonate and has a mean particle size of about 24-28 micron. The system may also include a ball mill pulverizer, or other type of mill, for decreasing and/or otherwise controlling the particle size of the trona or other sorbent compositions.
25 It has also been found that the additive may improve the flow properties of the trona when added thereto. A method of delivering a dry sorbent for flue gas injection includes combining the additive and trona to form a sorbent composition. The additive may be magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The sorbent composition is transported in a vessel to the location of a flue gas injection. The sorbent composition is offloaded out of the vessel and injected into the flue gas stream, wherein sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.
The sorbent composition is conveyed from the sorbent composition source 40 to the injector 42. The sorbent composition may be conveyed pneumatically or by any other suitable method. As shown in FIG. 2, the injection apparatus introduces the sorbent composition into flue gas duct section 44, which is disposed at a position upstream of the baghouse inlet and preferably downstream of the heat exchanger outlet. The injection system is preferably designed to maximize contact of the sorbent composition with the SO3 in the flue gas stream.
Any type of injection apparatus known in the art may be used to introduce the sorbent composition into the gas duct. For example, injection can be accomplished directly by a compressed air-driven eductor.
The process requires no slurry equipment or reactor vessel if the sorbent composition is stored and injected dry into the flue duct 44 where it reacts with the acid gas. However, the process may also be used with humidification of the flue gas or wet injection of the sorbent composition. Additionally, the particulates can be collected wet through a wet scrubber vesse154 should the process be used for trim scrubbing of acid mist. In particular, the flue gas desulfurization system may be operated so that the SO3 removal is accomplished by injecting the sorbent composition into the flue gas, while the majority of the SOz is removed by the wet scrubber 54.
The process may also be varied to control the flue gas temperature. For example, the flue gas temperature upstream of the trona or other sodium sorbent may be adjusted to obtain the desired flue gas temperature where the sorbent composition is injected. Additionally, ambient air 32 may be introduced into the flue gas stream to lower the flue gas temperature and the flue gas temperature monitored where the sorbent composition is injected. Other possible methods of controlling the flue gas temperature include using heat exchanges and/or air coolers. The process may also vary the trona injection location or include multiple locations for sorbent composition injection.
For the achievement of desulfurization, the sorbent composition is preferably injected at a rate with respect to the flow rate of the SO3 to provide a normalized stoichiometric ratio (NSR) of sodium to sulfur of about 1.0 or greater. The NSR is a measure of the amount of reagent injected relative to the amount theoretically required. The NSR expresses the stoichiometric amount of sorbent required to react with all of the acid gas. For example, an NSR of 1.0 would mean that enough material was injected to theoretically yield 100 percent removal of the SO3 in the inlet flue gas; an NSR of 0.5 would theoretically yield 50 percent SO3 removal. The reaction of SO3 with the sodium carbonate is very fast and efficient, so that a NSR of only about one is generally required for removal. The sorbent composition preferentially reacts with SO3 over SOz, so SO3 will be removed even if large amounts of SOz are present. Preferably, an NSR of less than 2.0 or more preferably less than 1.5 is used such that there is no substantial reduction of the SOz concentration in the flue gas caused by reaction with excess sorbent.
Because NOX removal systems tend to oxidize existing SOz into SO3, the injection system may also be combined with an NOX removal system. The trona injection system may also be combined with other SOX removal systems, such as sodium bicarbonate, lime, limestone, etc. in order to enhance performance or remove additional hazardous gases such as HC1, NOX, and the like.
An electric generation plant uses a hot side electrostatic precipitator (ESP) and no baghouse. The plant uses a catalyst for NOX removal, which causes elevated SO3 levels in the flue gas. The SO3 concentration in the flue gas is between about 100 ppm and about 125 ppm. T-200 trona from Solvay Chemicals is injected to remove SO3 from the flue gas.
As a comparative example, trona is injected at a temperature of 400 F
with no additive at NSR values of about 1.5. The perforated plates of the ESP
in the plant exhibit significant solids buildup which requires frequent cleaning.
A sorbent composition comprising trona and 1% calcium carbonate is injected into flue gas at a temperature of 400 F at NSR values of about 1.5.
A
perforated plate of an ESP in the plant after operation of the SO3 removal system is relatively free of solids buildup.
According to the present invention, using an additive reduces the amount of sticky waste products in the SO3 removal process, compared to a process using trona without an additive under the same processing conditions.
The embodiments described above and shown herein are illustrative and not restrictive. The scope of the invention is indicated by the claims rather than by the foregoing description and attached drawings. The invention may be embodied in other specific forms without departing from the spirit of the invention. Accordingly, these and any other changes which come within the scope of the claims are intended to be embraced therein.
Claims (41)
1. A method of removing SO3 from a flue gas stream having increased amounts of SO3 formed by a NO x removal system, the method comprising injecting into the flue gas stream a sorbent composition comprising a sodium sorbent and an additive to reduce the concentration of the SO3 in the flue gas stream and minimize the formation of a liquid phase NaHSO4 reaction product, wherein the sodium sorbent is selected from the group consisting of mechanically refined trona, sodium bicarbonate, and mixtures thereof, and the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof.
2. The method of claim 1 wherein the temperature of the flue gas is between 370° F and 500° F.
3. The method of claim 1 wherein the temperature of the flue gas is between 385° F and 450° F.
4. The method of claim 1 wherein the additive is between 0.1% and 5%
by weight of the trona.
by weight of the trona.
5. The method of claim 1 wherein the additive is between 0.5% and 2%
by weight of the trona.
by weight of the trona.
6. The method of claim 1 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.
7. The method of claim 1 wherein the additive comprises calcium carbonate.
8. The method of claim 1 wherein the flue gas stream comprises at least 3 ppm SO3 upstream of the location where the sorbent composition is injected.
9. The method of claim 20 wherein the flue gas stream comprises between 10 ppm and 200 ppm SO3 upstream of the location where the sorbent composition is injected.
10. The method of claim 1 wherein the sodium sorbent comprises trona with a mean particle size less than 40 micron.
11. The method of claim 1 wherein the sodium sorbent comprises trona with a mean particle size between 24 micron and 28 micron.
12. The method of claim 1 wherein the sorbent composition is injected as a dry material.
13. The method of claim 1 wherein the SO3 concentration is greater than an amount according to the equation log[SO3] > 0.009135T-2.456, where T is the flue gas temperature in ° F and SO3 is the concentration in ppm.
14. A method of removing SO3 from a flue gas stream having increased amounts of SO3 formed by a NO x removal system, the method comprising:
.cndot. providing a sorbent composition comprising mechanically refined trona and an additive selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof;
.cndot. injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is greater than 370° F and less than 450° F; and .cndot. maintaining the sorbent composition in contact with the flue gas for a time sufficient to react a portion of the sorbent composition with a portion of the SO3 to reduce the concentration of the SO3 in the flue gas stream and minimize the formation of a liquid phase NaHSO4 reaction product.
.cndot. providing a sorbent composition comprising mechanically refined trona and an additive selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof;
.cndot. injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is greater than 370° F and less than 450° F; and .cndot. maintaining the sorbent composition in contact with the flue gas for a time sufficient to react a portion of the sorbent composition with a portion of the SO3 to reduce the concentration of the SO3 in the flue gas stream and minimize the formation of a liquid phase NaHSO4 reaction product.
15. The method of claim 14 wherein the additive is between 0.1% and 5% by weight of the trona.
16. The method of claim 14 wherein the additive is between 0.5% and 2% by weight of the trona.
17. The method of claim 14 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.
18. The method of claim 14 wherein the additive comprises calcium carbonate.
19. The method of claim 14 wherein the mean particle size of the additive is between 20 micron and 25 micron.
20. The method of claim 14 wherein the flue gas stream comprises at least 3 ppm SO3 upstream of the location where the sorbent composition is injected.
21. The method of claim 14 wherein the flue gas stream comprises between 10 ppm and 200 ppm SO3 upstream of the location where the sorbent composition is injected.
22. The method of claim 14 wherein the SO3 concentration is greater than an amount according to the equation log[SO3] > 0.009135T-2.456, where T
is the flue gas temperature in ° F and SO3 is the concentration in ppm.
is the flue gas temperature in ° F and SO3 is the concentration in ppm.
23. The method of claim 14 wherein the mean particle size of trona is between 10 micron and 40 micron.
24. The method of claim 14 wherein the temperature of the flue gas is between 385° F and 415° F.
25. The method of claim 14 wherein the sorbent composition is injected at a rate with respect to the flow rate of the SO3 to provide a normalized stoichiometric ratio of sodium to sulfur of between 1.0 and 1.5.
26. The method of claim 14 wherein the sorbent composition is injected as a dry material.
27. The method of claim 14 further comprising combining the additive with the trona before delivery of the sorbent composition to the site of the flue gas stream.
28. A method of removing SO3 from a flue gas stream comprising between 3 ppm and 200 ppm SO3, the method comprising:
.cndot. providing a sorbent composition comprising trona and an additive selected from group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof, wherein the additive is between 0.1% and 5% by weight of the trona; and .cndot. injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is between 370° F and 450° F.
.cndot. providing a sorbent composition comprising trona and an additive selected from group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof, wherein the additive is between 0.1% and 5% by weight of the trona; and .cndot. injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is between 370° F and 450° F.
29. The method of claim 28 wherein the additive is between 0.5% and 2% by weight of the trona.
30. The method of claim 28 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.
31. The method of claim 28 wherein the mean particle size of trona is between 24 micron and 28 micron.
32. The method of claim 28 wherein the temperature of the flue gas is between 385° F and 415° F.
33. The method of claim 28 wherein the SO3 concentration is greater than an amount according to the equation log[SO3] > 0.009135T-2.456, where T
is the flue gas temperature in ° F and SO3 is the concentration in ppm.
is the flue gas temperature in ° F and SO3 is the concentration in ppm.
34. A method of delivering a dry sorbent for flue gas injection comprising:
.cndot. providing trona;
.cndot. combining with the trona an additive selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof to form a sorbent composition;
.cndot. transporting the sorbent composition in a vessel to the location of a flue gas injection;
.cndot. offloading the sorbent composition out of the vessel and injecting the sorbent composition into the flue gas stream wherein sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.
.cndot. providing trona;
.cndot. combining with the trona an additive selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof to form a sorbent composition;
.cndot. transporting the sorbent composition in a vessel to the location of a flue gas injection;
.cndot. offloading the sorbent composition out of the vessel and injecting the sorbent composition into the flue gas stream wherein sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.
35. The method of claim 34 wherein the additive is between 0.1% and 5% by weight of the trona.
36. The method of claim 34 wherein the additive is between 0.5% and 2% by weight of the trona.
37. The method of claim 34 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.
38. The method of claim 34 wherein the additive comprises calcium carbonate.
39. The method of claim 34 wherein the mean particle size of the trona is less than 40 micron.
40. The method of claim 34 wherein the mean particle size of the trona is between 24 micron and 28 micron.
41. The method of claim 34 wherein the mean particle size of the additive is between 20 micron and 25 micron.
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US22905605A | 2005-09-15 | 2005-09-15 | |
US11/229,056 | 2005-09-15 | ||
PCT/EP2006/066359 WO2007031552A1 (en) | 2005-09-15 | 2006-09-14 | Sulfur trioxide removal from a flue gas stream |
Publications (2)
Publication Number | Publication Date |
---|---|
CA2622549A1 true CA2622549A1 (en) | 2007-03-22 |
CA2622549C CA2622549C (en) | 2014-07-29 |
Family
ID=37311371
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
CA2622549A Expired - Fee Related CA2622549C (en) | 2005-09-15 | 2006-09-14 | Sulfur trioxide removal from a flue gas stream |
Country Status (7)
Country | Link |
---|---|
EP (1) | EP1937391A1 (en) |
JP (1) | JP2009507632A (en) |
CN (1) | CN101262929B (en) |
BR (1) | BRPI0616068A2 (en) |
CA (1) | CA2622549C (en) |
EA (1) | EA015416B1 (en) |
WO (1) | WO2007031552A1 (en) |
Families Citing this family (15)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7276217B2 (en) | 2004-08-16 | 2007-10-02 | Premier Chemicals, Llc | Reduction of coal-fired combustion emissions |
US7531154B2 (en) | 2005-08-18 | 2009-05-12 | Solvay Chemicals | Method of removing sulfur dioxide from a flue gas stream |
KR101099073B1 (en) * | 2008-12-04 | 2011-12-26 | 주식회사 유니코정밀화학 | Composition for removing sox in exhausted gas |
IT1401506B1 (en) * | 2010-08-03 | 2013-07-26 | Icico S R L | SORBENT COMPOSITION IN POWDER TO PURGE A GASEOUS EFFLUENT AND ITS USE |
CN102527324A (en) * | 2012-01-05 | 2012-07-04 | 张泉 | Porous adsorbing material with health care function and preparation method of porous adsorbing material |
KR101388179B1 (en) | 2012-05-03 | 2014-04-22 | 주식회사 유니코정밀화학 | COMPOSITION FOR REMOVING SOx IN EXHAUSTED GAS AND METHOD FOR REMOVING SOx IN EXHAUSTED GAS |
JP6254012B2 (en) * | 2014-02-24 | 2017-12-27 | 三菱日立パワーシステムズ株式会社 | Exhaust gas treatment system and exhaust gas treatment method |
CN105344326B (en) * | 2015-11-09 | 2018-03-16 | 建德丽园环保科技有限公司 | A kind of preparation method of ultra-fine sodium acid carbonate gas cleaning medicament |
WO2017102533A1 (en) * | 2015-12-14 | 2017-06-22 | Carmeuse Research And Technology | Powdered composition comprising one or more double salt(s) for use in combustion gas purification |
EP3187243A1 (en) * | 2015-12-30 | 2017-07-05 | Lhoist Recherche et Développement S.A. | Composition for the purification of flue gas |
EP3187244A1 (en) | 2015-12-30 | 2017-07-05 | Lhoist Recherche et Développement S.A. | Composition for the purification of flue gas |
CN105477995B (en) * | 2016-01-18 | 2019-03-19 | 北京清新环境技术股份有限公司 | A kind of method of sulfur trioxide in removing coal-fired flue-gas |
BR112020002489A2 (en) * | 2017-09-06 | 2020-07-28 | S.A. Lhoist Recherche Et Developpement | process to treat flue gases in flue gas treatment of CDs |
CN110170241B (en) * | 2019-06-27 | 2021-08-24 | 上海交通大学 | Method for inhibiting generation of sulfur trioxide in heavy non-ferrous metal smelting acid-making flue gas |
CN111318142A (en) * | 2020-02-20 | 2020-06-23 | 中国神华能源股份有限公司国华电力分公司 | Sulfur trioxide removing device for coal combustion system |
Family Cites Families (15)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3897540A (en) * | 1973-03-07 | 1975-07-29 | American Air Filter Co | Method of controlling reaction conditions in a sulfur dioxide scrubber |
US4504451A (en) * | 1983-07-14 | 1985-03-12 | Dec International, Inc. | Dry scrubbing oxides and particulate contaminants from hot gases |
US4559211A (en) * | 1983-08-05 | 1985-12-17 | Research-Cottrell, Inc. | Method for reduced temperature operation of flue gas collectors |
US4663136A (en) * | 1984-05-29 | 1987-05-05 | Ets, Inc. | Emission control process for combustion flue gases |
US4783325A (en) * | 1985-05-14 | 1988-11-08 | Jones Dale G | Process and apparatus for removing oxides of nitrogen and sulfur from combustion gases |
CN86108162A (en) * | 1985-11-29 | 1988-06-08 | 通用电气公司 | The method of washing sulfur oxide and nitrogen oxide in the flue gas conduit |
JPS63175652A (en) * | 1987-01-16 | 1988-07-20 | Mitsubishi Heavy Ind Ltd | Prevention of enlargement of discharging wire of electrostatic precipitator |
US4812295A (en) * | 1987-10-01 | 1989-03-14 | Combustion Engineering, Inc. | Apparatus for dry scrubbing a hot gas and start-up process |
JPH0558622A (en) * | 1991-08-30 | 1993-03-09 | Asahi Glass Co Ltd | Consolidation inhibition method of sodium hydrogen carbonate |
CA2127884A1 (en) * | 1992-01-13 | 1994-07-22 | Nobuyasu Hasebe | Method and apparatus for desulfurization of a gas |
BE1011153A3 (en) * | 1997-05-14 | 1999-05-04 | Solvay | Reactive powder composition and method for the treatment of a gas. |
JP3840858B2 (en) * | 1998-11-26 | 2006-11-01 | 旭硝子株式会社 | Acid component removal agent and acid component removal method |
JP2002035546A (en) * | 1999-09-09 | 2002-02-05 | Asahi Glass Co Ltd | Gas treatment method |
JP4637392B2 (en) * | 2000-05-16 | 2011-02-23 | 旭硝子株式会社 | Gas processing method |
JP2002263441A (en) * | 2001-03-12 | 2002-09-17 | Mitsubishi Heavy Ind Ltd | Blue smoke generation preventive equipment |
-
2006
- 2006-09-14 EP EP06793512A patent/EP1937391A1/en not_active Withdrawn
- 2006-09-14 EA EA200800829A patent/EA015416B1/en not_active IP Right Cessation
- 2006-09-14 BR BRPI0616068-9A patent/BRPI0616068A2/en not_active IP Right Cessation
- 2006-09-14 JP JP2008530530A patent/JP2009507632A/en not_active Ceased
- 2006-09-14 WO PCT/EP2006/066359 patent/WO2007031552A1/en active Application Filing
- 2006-09-14 CN CN200680033934.9A patent/CN101262929B/en active Active
- 2006-09-14 CA CA2622549A patent/CA2622549C/en not_active Expired - Fee Related
Also Published As
Publication number | Publication date |
---|---|
CN101262929B (en) | 2013-01-09 |
EA015416B1 (en) | 2011-08-30 |
EA200800829A1 (en) | 2008-08-29 |
EP1937391A1 (en) | 2008-07-02 |
WO2007031552A1 (en) | 2007-03-22 |
JP2009507632A (en) | 2009-02-26 |
CN101262929A (en) | 2008-09-10 |
BRPI0616068A2 (en) | 2011-06-07 |
CA2622549C (en) | 2014-07-29 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
CA2622064C (en) | Method of removing sulfur trioxide from a flue gas stream | |
CA2622549C (en) | Sulfur trioxide removal from a flue gas stream | |
CA2618202C (en) | Method of removing sulfur dioxide from a flue gas stream | |
CN106659971B (en) | Method and apparatus for removing pollutants from exhaust gas | |
EP2026897B1 (en) | Integrated dry and wet flue gas cleaning process and system | |
US6143263A (en) | Method and system for SO2 and SO3 control by dry sorbent/reagent injection and wet scrubbing | |
TWI444224B (en) | A method and a device for removing nitrogen oxides and sulphur trioxide from a process gas | |
US7766997B2 (en) | Method of reducing an amount of mercury in a flue gas | |
US20110014106A1 (en) | COMBUSTION FLUE GAS SOx TREATMENT VIA DRY SORBENT INJECTION | |
US20170029343A1 (en) | Sulfur enhanced nitrogen production from emission scrubbing | |
CN113251420A (en) | Industrial waste treatment method and device | |
US20200116355A1 (en) | Ammonia-based flue gas desulfurization system and method | |
EP0836878A1 (en) | Method for removing sulfur dioxide and nitrogen oxides from combustion gases | |
MX2008003648A (en) | Method of removing sulfur trioxide from a flue gas stream | |
MX2008002302A (en) | Method of removing sulfur dioxide from a flue gas stream |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
EEER | Examination request | ||
MKLA | Lapsed |
Effective date: 20190916 |