CA2622549C - Sulfur trioxide removal from a flue gas stream - Google Patents
Sulfur trioxide removal from a flue gas stream Download PDFInfo
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- CA2622549C CA2622549C CA2622549A CA2622549A CA2622549C CA 2622549 C CA2622549 C CA 2622549C CA 2622549 A CA2622549 A CA 2622549A CA 2622549 A CA2622549 A CA 2622549A CA 2622549 C CA2622549 C CA 2622549C
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- flue gas
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- 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
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 S03.
S03 is a noxious gas that is produced from the combustion of sulfur-containing fuel. When present in flue gas, the S03 can form an acid mist that condenses in electrostatic precipitators, ducts or bag houses, causing corrosion.
S03 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 NO emissions from coal-fired power plants via selective catalytic reactors (SCRs) has resulted in the unintended consequence of oxidizing SO2 to S03 and thereby increasing total S03 emissions. SCRs employ a catalyst (typically vanadium pentoxide) to convert NO to N2 and H20 with the addition of NH3, but there is also an unintended oxidation of the SO2 to S03.
Although the higher stack S03 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 S03 levels to a point where no secondary S03 plume is visible can impede particulate collection for stations that employ electrostatic precipitators (ESPs). S03 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 S03 to lower fly ash resistivity when ash resistivity is too high.
S03 reacts with water vapor in the flue gas ducts of the coal power plant and forms vaporous H2504. 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 , = e=
+4-eliminator. Thus, there is only limited S03 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 S03 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 S03 from a flue gas stream having increased amounts of S03 formed by a NO 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 S03 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 2a 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 invention as claimed is however more specifically directed to a method of removing S03 from a flue gas stream comprising between 3 ppm and 200 ppm S03, the method comprising:
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 = injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is between 370 F and 450 F.
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 S03 as a function of flue gas temperature and S03 concentration.
S03 is a noxious gas that is produced from the combustion of sulfur-containing fuel. When present in flue gas, the S03 can form an acid mist that condenses in electrostatic precipitators, ducts or bag houses, causing corrosion.
S03 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 NO emissions from coal-fired power plants via selective catalytic reactors (SCRs) has resulted in the unintended consequence of oxidizing SO2 to S03 and thereby increasing total S03 emissions. SCRs employ a catalyst (typically vanadium pentoxide) to convert NO to N2 and H20 with the addition of NH3, but there is also an unintended oxidation of the SO2 to S03.
Although the higher stack S03 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 S03 levels to a point where no secondary S03 plume is visible can impede particulate collection for stations that employ electrostatic precipitators (ESPs). S03 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 S03 to lower fly ash resistivity when ash resistivity is too high.
S03 reacts with water vapor in the flue gas ducts of the coal power plant and forms vaporous H2504. 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 , = e=
+4-eliminator. Thus, there is only limited S03 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 S03 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 S03 from a flue gas stream having increased amounts of S03 formed by a NO 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 S03 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 2a 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 invention as claimed is however more specifically directed to a method of removing S03 from a flue gas stream comprising between 3 ppm and 200 ppm S03, the method comprising:
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 = injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is between 370 F and 450 F.
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 S03 as a function of flue gas temperature and S03 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 S03. 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 S03 removal is trona. Trona is a mineral that contains about 85-95% sodium sesquicarbonate (Na2CO3=NaHCO3.2H20). 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 S02, HC1, S03, and NO.
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 [ Na2CO3 = NaHCO3 = 2H20] ¨> 3Na2CO3 + 5H20 + CO2 A preferred chemical reaction of the sorbent composition with the S03 is represented below:
Na2CO3 + S03 ¨> Na2SO4 + CO2 However, under certain conditions, undesirable reactions may occur which produce sodium bisulfate. If the sodium sesquicarbonate is not completely calcined before reaction with S03, the following reaction occurs:
NaHCO3 + S03 ¨> NaHSO4 + S03 Under certain conditions, another undesirable reaction produces sodium bisulfate as represented below:
Na2CO3 + S03 + H2SO4 ¨> 2NaHSO4 + CO2 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 ¨> Na25207 The type of reaction product of the Na2CO3 and the S03 depends on the S03 concentration and the temperature of the flue gas. FIG. 1 is a phase diagram showing the typical reaction products of trona with S03 as a function of flue gas temperature and S03 concentration. In particular, above a certain S03 concentration, the reaction product can be solid NaHSO4, liquid NaHSO4, Na2504, or Na25207, 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 Na2 SO4 at a temperature above 370 F may be represented by the equation log[503]=0.009135T-2.456, where log[503] is the log base 10 of the S03 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 S03 concentration greater than the amount defined by log[503]=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 S03 to reduce the concentration of the S03 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 S03 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 S03 concentration. Thus, the process may be operated at a temperature and S03 concentration where log[503]>0.009135T-2.456, where [S03] is the S03 concentration in ppm and T is the flue gas temperature in F.
The S03 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 S03 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 S03 are strong acids and trona will react much more rapidly with these acids than it will with a weak acid such as S02. Thus, the injected sorbent composition can be used to selectively remove S03 without substantially decreasing the amount of SO2 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 NO 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 vessel 54 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 S03 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 S03 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 vessel 54 should the process be used for trim scrubbing of acid mist. In particular, the flue gas desulfurization system may be operated so that the S03 removal is accomplished by injecting the sorbent composition into the flue gas, while the majority of the SO2 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 S03 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 S03 in the inlet flue gas; an NSR of 0.5 would theoretically yield 50 percent S03 removal. The reaction of S03 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 S03 over S02, so S03 will be removed even if large amounts of SO2 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 SO2 concentration in the flue gas caused by reaction with excess sorbent.
Because NO removal systems tend to oxidize existing SO2 into S03, the injection system may also be combined with an NO 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, NO, and the like.
An electric generation plant uses a hot side electrostatic precipitator (ESP) and no baghouse. The plant uses a catalyst for NO removal, which causes elevated S03 levels in the flue gas. The S03 concentration in the flue gas is between about 100 ppm and about 125 ppm. T-200 trona from Solvay Chemicals is injected to remove S03 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 S03 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 S03 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 S03. 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 S03 removal is trona. Trona is a mineral that contains about 85-95% sodium sesquicarbonate (Na2CO3=NaHCO3.2H20). 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 S02, HC1, S03, and NO.
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 [ Na2CO3 = NaHCO3 = 2H20] ¨> 3Na2CO3 + 5H20 + CO2 A preferred chemical reaction of the sorbent composition with the S03 is represented below:
Na2CO3 + S03 ¨> Na2SO4 + CO2 However, under certain conditions, undesirable reactions may occur which produce sodium bisulfate. If the sodium sesquicarbonate is not completely calcined before reaction with S03, the following reaction occurs:
NaHCO3 + S03 ¨> NaHSO4 + S03 Under certain conditions, another undesirable reaction produces sodium bisulfate as represented below:
Na2CO3 + S03 + H2SO4 ¨> 2NaHSO4 + CO2 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 ¨> Na25207 The type of reaction product of the Na2CO3 and the S03 depends on the S03 concentration and the temperature of the flue gas. FIG. 1 is a phase diagram showing the typical reaction products of trona with S03 as a function of flue gas temperature and S03 concentration. In particular, above a certain S03 concentration, the reaction product can be solid NaHSO4, liquid NaHSO4, Na2504, or Na25207, 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 Na2 SO4 at a temperature above 370 F may be represented by the equation log[503]=0.009135T-2.456, where log[503] is the log base 10 of the S03 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 S03 concentration greater than the amount defined by log[503]=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 S03 to reduce the concentration of the S03 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 S03 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 S03 concentration. Thus, the process may be operated at a temperature and S03 concentration where log[503]>0.009135T-2.456, where [S03] is the S03 concentration in ppm and T is the flue gas temperature in F.
The S03 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 S03 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 S03 are strong acids and trona will react much more rapidly with these acids than it will with a weak acid such as S02. Thus, the injected sorbent composition can be used to selectively remove S03 without substantially decreasing the amount of SO2 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 NO 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 vessel 54 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 S03 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 S03 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 vessel 54 should the process be used for trim scrubbing of acid mist. In particular, the flue gas desulfurization system may be operated so that the S03 removal is accomplished by injecting the sorbent composition into the flue gas, while the majority of the SO2 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 S03 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 S03 in the inlet flue gas; an NSR of 0.5 would theoretically yield 50 percent S03 removal. The reaction of S03 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 S03 over S02, so S03 will be removed even if large amounts of SO2 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 SO2 concentration in the flue gas caused by reaction with excess sorbent.
Because NO removal systems tend to oxidize existing SO2 into S03, the injection system may also be combined with an NO 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, NO, and the like.
An electric generation plant uses a hot side electrostatic precipitator (ESP) and no baghouse. The plant uses a catalyst for NO removal, which causes elevated S03 levels in the flue gas. The S03 concentration in the flue gas is between about 100 ppm and about 125 ppm. T-200 trona from Solvay Chemicals is injected to remove S03 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 S03 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 S03 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 (8)
1. 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.
2. The method of claim 1, wherein the additive is between 0.5% and 2% by weight of the trona.
3. The method of claim 1 or 2, wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.
4. The method of any one of claims 1 to 3, wherein the mean particle size of trona is between 24 micron and 28 micron.
5. The method of any one of claims 1 to 4, wherein the temperature of the flue gas is between 385°F and 415°F.
6. The method of any one of claims 1 to 5, 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.
7. The method of any one of claims 1 to 6, which further comprises:
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.
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.
8. The method of any one of claims 1 to 7, wherein the amounts of SO3 to be removed from the flue gas stream are amounts formed by a NO x removal system.
Applications Claiming Priority (3)
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| 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 |
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| CA2622549C true CA2622549C (en) | 2014-07-29 |
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| CA2622549A Expired - Fee Related CA2622549C (en) | 2005-09-15 | 2006-09-14 | Sulfur trioxide removal from a flue gas stream |
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| JP (1) | JP2009507632A (en) |
| CN (1) | CN101262929B (en) |
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| CA (1) | CA2622549C (en) |
| EA (1) | EA015416B1 (en) |
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| 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 |
| CA3007333A1 (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 |
| JP7360378B2 (en) * | 2017-09-06 | 2023-10-12 | エス．ア．ロイスト ルシェルシュ エ デヴロップマン | Method of treating exhaust gas in CDS exhaust gas treatment |
| 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 |
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|---|---|---|---|---|
| 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 |
| JPH07505603A (en) * | 1992-01-13 | 1995-06-22 | 長谷部 信康 | Gas desulfurization method and equipment |
| 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 |
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- 2006-09-14 EA EA200800829A patent/EA015416B1/en not_active IP Right Cessation
- 2006-09-14 EP EP06793512A patent/EP1937391A1/en not_active Withdrawn
- 2006-09-14 JP JP2008530530A patent/JP2009507632A/en not_active Ceased
- 2006-09-14 CA CA2622549A patent/CA2622549C/en not_active Expired - Fee Related
- 2006-09-14 WO PCT/EP2006/066359 patent/WO2007031552A1/en active Application Filing
- 2006-09-14 CN CN200680033934.9A patent/CN101262929B/en active Active
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| CA2622549A1 (en) | 2007-03-22 |
| EP1937391A1 (en) | 2008-07-02 |
| BRPI0616068A2 (en) | 2011-06-07 |
| EA015416B1 (en) | 2011-08-30 |
| EA200800829A1 (en) | 2008-08-29 |
| WO2007031552A1 (en) | 2007-03-22 |
| CN101262929B (en) | 2013-01-09 |
| JP2009507632A (en) | 2009-02-26 |
| CN101262929A (en) | 2008-09-10 |
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