TW201536403A - Integrated sorbent injection and flue gas desulfurization system - Google Patents

Abstract

An integrated sorbent injection, heat recovery, and flue gas desulfurization system is disclosed. A dry sorbent is injected into the flue gas upstream of the air heater. This reduces the acid dew point temperature, permitting additional heat energy to be captured when the flue gas passes through the air heater. The flue gas then passes through a desulfurization unit and through a baghouse, where solids are captured. The capture of additional heat energy permits the overall boiler efficiency to be increased while safely operating at a lower flue gas temperature. The integrated system consumes no greater quantity of sorbent than conventional methods but provides the benefit of improved plant heat rate.

Description

Integrated absorbent injection and flue gas desulfurization system [Reciprocal Reference of Related Applications]

The present application claims priority to U.S. Provisional Application Serial No. 61/904,939, filed on November 15, 2013, which is incorporated herein by reference. U.S. Provisional Application Serial No. 61/904,939, filed on Jan.

The present disclosure relates to a flue gas desulfurization (FGD) system for removing particulates, gases, and other contaminants from flue gas generated during combustion of medium to high sulfur fuels. . In particular, sulfur dioxide (SO ₂ ), sulfur trioxide (SO ₃ ), HCl, and other acid gases can be trapped; the acid dew point temperature of the flue gas can be reduced, and corrosion of related equipment can be mitigated. The absorbent is more effectively used in the system. This in addition increases boiler efficiency, improves system corrosion resistance, improves material utilization, reduces capital and operating costs, and promotes the capture of particulates and/or other contaminants.

During combustion in a boiler, the chemical energy in the fuel is converted to thermal energy, which can be used in various forms for different applications. The fuel used in the combustion process can contain a wide range of solid, liquid and gaseous materials, including coal (with low, medium or high sulfur content), oil (diesel, No. 2, Bunker C or No. 6), natural gas, Wood, tires, biomass, etc.

The combustion system in the boiler converts the fuel into a large amount of compound. Water (H ₂ O) and carbon dioxide (CO ₂ ) are the main products of complete combustion. However, other combustion reactions of the compounds in the fuel result in unwanted by-products. Depending on the fuel used, such by-products may include particulates (eg, fly ash), acid gases such as sulfur oxides (SO _x ) or halides (HCl, HF) or nitrogen oxides (NOx _). ), metals such as mercury or arsenic, carbon monoxide (CO), and hydrocarbons (HC). The emission levels of many of these by-products vary depending on the components found in the fuel, but can also be changed by applying emission control techniques.

Acid Dew Point Temperature (ADP) is the temperature at which the acid gas in the flue gas is expected to begin to condense inside the various system components that contact the flue gas. This acidic condensate causes corrosion of system components and is desirable to avoid.

One way to avoid this corrosion is to design a heat recovery component so that the lowest expected temperature of the flue gas is at an appropriate level. Exceeded ADP. However, doing so will cause some of the energy (heat in the flue gas) leaving the boiler casing to be untrapped. Unrecovered energy directly reduces boiler efficiency, which has an adverse effect on the heat rate of the equipment; the increased heat rate is equivalent to reduced equipment efficiency. Reducing boiler efficiency also reduces equipment heat efficiency by requiring additional fan power to handle increased air and gas flow, as well as additional power for fuel and ash handling systems.

It is desirable to provide systems and methods that remove particulates, gases, and other contaminants from the flue gas and that also mitigate equipment corrosion and/or increase boiler efficiency and overall plant efficiency.

This document discloses a pollution control system using a circulating dry scrubber (CDS) or a spray drying absorber (SDA) for desulfurization, by controlling the SO ₃ concentration upstream of the air heater. boiler flue gas stream to reduce the acid gases (e.g., SO _x) emissions of various methods and systems. Briefly, hydrated lime, i.e., calcium hydroxide powder, is injected into the flue gas upstream of the heat recovery system components, for example, between a boiler economizer and a regenerative air heater. This reduces the SO ₃ concentration of the flue gas and the acid dew point temperature (ADP) to enable the capture of additional thermal energy. In addition, a further improvement in boiler efficiency can be achieved by reducing the ADP of the flue gas and lowering the temperature of the flue gas exiting the air heater.

In this regard, various embodiments of the present disclosure disclose smoke exhaust a desulfurization system comprising: a first absorbent injection point upstream of the air heater; a desulfurization unit downstream of the air heater; and a baghouse downstream of the desulfurization unit, the bag dust collector The solid particles are separated from a clean gas. The system includes a second absorbent injection point located between the air heater and the desulfurization unit or in the desulfurization unit. In some cases, the system may further include a purge gas recirculation flue that is directed downstream of the baghouse to a point upstream of the desulfurization unit. The system can further include a recycle system to move solid particles from the baghouse to the desulfurization unit. The system can also include a sorbent silo that is fed at least to the first absorbent injection point. A second absorbent reservoir can optionally be present to feed the second absorbent injection point.

The desulfurization unit can be a circulating dry scrubber or a spray dryer absorber. The bag dust collector may be a pulse jet fabric filter, a shake deflate fabric filter, a reverse gas fabric filter, or an electrostatic precipitator. (electrostatic precipitator).

An air heater can be described as comprising a hot flow pass and a cold flow pass through which the flue gas passes and transfers thermal energy to the gas from the inlet fan through the cold flow channel (eg ,air). The system can further include a preheater between the inlet fan and the cold flow passage of the air heater. Alternatively, the system can include a cold air bypass around the air heater (cold Air bypass) so that the gas supplied by the inlet fan does not pass through the cold flow passage. Sometimes, the system includes a heated air recirculation flue, which is the point from the point downstream of the cold flow path to the upstream of the cold flow path.

The system can include a selective catalytic reduction (SCR) unit upstream of the air heater, the first absorbent injection point being located downstream of the SCR unit.

In this system, there are a plurality of ports for slaked lime injection, such that a small portion of the lime stream is injected upstream of the air heater and the remainder is added elsewhere in the desulfurization unit. The total flow rate of slaked lime is not greater than only the CDS loader (where slaked lime is only injected in a circulating dry scrubber). By applying this system, the same total flow of absorbent can promote more advantages such as enhanced boiler efficiency (and thus equipment efficiency and equipment heat rate) and safe operation at lower flue gas temperatures.

Also disclosed herein is a method for increasing boiler efficiency, comprising: injecting slaked lime into the flue gas at a first slaked lime injection point upstream of the air heater; reducing the temperature of the flue gas in the air heater; and second hydrated lime downstream of the air heater Injecting slaked lime into the flue gas; sending the flue gas to the desulfurization unit downstream of the air heater and downstream of the second slaked lime injection point; and sending the flue gas to the baghouse downstream of the desulfurization unit, The bag filter separates solid particles from a clean gas; wherein the temperature of the flue gas after leaving the air heater is lower than the leaving air heater in the system where the slaked lime is not injected at the first slaked lime injection point The temperature of the subsequent flue gas (preferably at least 10 °F lower, including at least 20 °F lower or 30 °F lower).

The temperature of the flue gas entering the air heater can range from about 600 °F to about 800 °F. The temperature of the flue gas exiting the air heater (including those caused by air heater leakage, if any) may range from about 220 °F to about 350 °F.

These and other non-limiting features are described in more detail below.

100‧‧‧Boiler

105‧‧‧ furnace

110‧‧‧Desulfurization system

111‧‧‧Crusher

112‧‧‧ fossil fuel

114‧‧‧Air

116‧‧‧heater

120‧‧‧flue gas

130‧‧‧SCR unit

140‧‧‧Air heater

150‧‧‧Particle collection device

160‧‧‧Desulfurization unit

161‧‧‧Absorbent supply

162‧‧‧Dry absorbent

164‧‧‧ water

166‧‧‧ lines

167‧‧‧ lines

168‧‧‧ lines

170‧‧‧ bag dust collector

172‧‧‧Recycling flow

180‧‧‧ chimney

190‧‧‧Preheater

192‧‧‧heated air recirculation flue

194‧‧‧ Cold air bypass

196‧‧‧ entrance fan

200‧‧‧Recycling system

204‧‧‧ Ground

206‧‧‧ chimney

210‧‧‧ absorption tank

212‧‧‧ bottom entrance

214‧‧‧ top exit

220‧‧‧ Venturi tube

222‧‧‧ solid injection point

224‧‧‧ water injection point

230‧‧‧ bag dust collector

232‧‧‧ catheter

240‧‧ ‧ slide

242‧‧ ‧ slide

250‧‧‧Distribution box

255‧‧‧ height

260‧‧‧slaked lime storage bin

262‧‧‧ channel

266‧‧‧ channel

270‧‧ Air heater

272‧‧‧heat flow channel entrance

274‧‧‧Hot flow channel exit

276‧‧‧ cold flow access

278‧‧‧Cold flow passage exit

The following is a brief description of the drawings, which are intended to illustrate the illustrative embodiments disclosed herein

Figure 1 is a diagram showing the components and flow paths of a conventional boiler having a dry desulfurization system.

Figure 2 is a side view of a conventional desulfurization system using a distribution box.

Figure 3 is a plan (top view) view of the conventional system of Figure 2.

Figure 4 is a perspective view of the conventional system of Figure 2.

Figure 5 is a bar graph showing the temperature of a predictive example of the temperature of the flue gas leaving the air heater upstream of the air heater without dry sorbent injection (DSI) and DSI upstream of the air heater. Compare, and the minimum allowable temperature of CDS and SDA (desulfurization technology). The y-axis is the temperature expressed in °F.

Figure 6 is a bar graph showing no dry absorbent injection (DSI) upstream of the air heater and DSI leaving upstream of the air heater. A temperature comparison of another predictive example of the flue gas temperature of the gas heater, and a minimum allowable temperature of the CDS and SDA (desulfurization technology). The y-axis is the temperature expressed in °F.

A more complete understanding of the components, methods, and devices disclosed herein can be obtained by reference to the drawings. The drawings are merely diagrams based on convenience and ease of presentation of the present disclosure, and thus are not intended to indicate the relative size and size of the device or its components and/or to define or define the scope of the exemplary embodiments.

In the following, the specific terms are used for the sake of clarity, but such terms are not intended to be merely a specific configuration of the embodiment selected for the exemplified in the drawings, and are not intended to define or define the scope of the present disclosure. . In the drawings and the following description, the description of similar component symbols refers to components having similar functions.

The singular forms "a", "the" and "the" are meant to include the plural.

The terms "including" used in the specification and claims are intended to include the meaning of "consisting of" and "consisting essentially of."

Numerical values are to be understood to include the same values when reduced to the number of significant figures and the difference from the values is less than the experimental error of the conventional measurement technique of the type described in the application for determining the value. The value.

All ranges disclosed herein are inclusive of the recited endpoints Values are independently combinable (eg, a range of "2 grams to 10 grams" includes endpoint values (2 grams and 10 grams) and all intermediate values).

As used herein, a near-language language can be applied to modify any number of statements, which may vary but does not result in a change in related basic functions. Therefore, values modified in terms such as "about" and "substantially" are not limited to a particular exact value. The modifier "about" shall also be taken to reveal the extent defined by the absolute value of the two ends. For example, the expression "about 2 to about 4" also reveals the scope of "2 to 4".

It should be understood that many of the terms used herein are relative terms. For example, the terms "inlet" and "outlet" are for a given structure with respect to fluids flowing through them, for example, fluid flows through the inlet into the structure and through the outlet leaving the structure. The terms "upstream" and "downstream" are relative to the direction in which the fluid flows through the various components, i.e., the flow system flows through the upstream component before flowing through the downstream component. It should be understood that in a loop, the first component can be described as being upstream of the second component and can be described as downstream.

The terms "horizontal" and "vertical" are used to refer to the direction relative to the absolute reference, the ground plane. However, such terms are not to be construed as requiring that the structures be absolutely parallel or absolutely perpendicular to each other. For example, the first vertical structure and the second vertical structure are not necessarily parallel to each other. The terms "top" and "bottom" or "base" are used to refer to a position/surface where the top is always higher than the bottom/base relative to the absolute reference (ie, the earth's surface). . The terms "upward" and "downward" are also relative to absolute benchmarks. In this case, the upward flow is always opposite to the gravity of the earth.

The term "hydrated lime" refers to calcium hydroxide, also known as Ca(OH) ₂ . The term "hydrated" as used herein does not refer to the presence of molecular water. The term "lime slurry" is used to mean a mixture of calcium hydroxide and water. Other calcium absorbents include, for example, limestone or quicklime. The term "limestone" means calcium carbonate, also known as CaCO ₃ . The term "quicklime" means calcium oxide, CaO.

As used herein, the term "plane" generally refers to a common level and is understood to mean a volume rather than a flat surface.

When the term "directly" is used to refer to two system components, it is meant that there are no significant system components in the path between the two components. However, less significant components such as valves or pumps or other control devices, or sensors (such as temperature or pressure) may be located in the path between the two components.

For an explanation of certain terms or principles of boiler and/or steam generator technology that may be necessary to understand this disclosure, the reader is referred to Steam/its generation and use, 40th Edition, Stultz and Kitto, Eds. , Copyright 1992, The Babcock & Wilcox Company, and Steam/its generation and use, 41st Edition, Kitto and Stultz, Eds., Copyright 2005, The Babcock & Wilcox Company, the content of which is hereby incorporated by reference in its entirety. Incorporate.

The present disclosure is directed to various methods and systems for reducing acid gas emissions and associated corrosion during desulfurization. In general, flue gas is produced by a combustion system containing a combustion chamber that combusts fuel. The calcium hydroxide dry powder (i.e., slaked lime) is injected into the flue gas upstream of the air heater, i.e., in the earlier stage of the system, to reduce the acid dew point (ADP) temperature in the earlier portion of the system. This causes the flue gas to exit the air heater at a lower outlet temperature and avoid condensation of acid gases. This makes it possible to capture additional heat energy that may be wasted. Continued to the flue gas desulfurization unit, such as a circulating dry scrubber (CDS) or spray dry absorber (the SDA), based on where the trapped SO _x. The resulting flue gas, which now contains solid particles and a purge gas, passes through a downstream baghouse to separate solid particles from the purge gas. The solid particles can be recycled back to the desulfurization unit as needed.

In general, it is believed that the present desulfurization system and method can be used in combination with any combustion system. Combustion can be used for any purpose, such as power generation, manufacturing of a particular product, or just for incineration of fuel. An exemplary combustion system to which the method of the present invention can be applied includes a power generation system using a boiler having a furnace as a combustion chamber; a cement kiln; an electric arc furnace; a glass furnace; a melting furnace ( Smelter) (pellet, gold, tin, etc.); pelletizer roaster; blast furnace; coke oven battery; chemical fired heater; Refinery oven); and incinerators (medical waste, municipal solid waste, etc.). As used herein, the term "combustion chamber" refers to a particular structure in which combustion occurs in a system.

FIG. 1 generally illustrates an exemplary power generation system of the present disclosure having a boiler 100 and a downstream desulfurization system 110. The fossil fuel 112, such as coal, from the pulverizer 111, and the air 114 are combusted in the furnace 105 to produce the flue gas 120. The flue gas 120 passes through an economizer 116 that is used to preheat the water used in the boiler to produce steam and to cool the flue gas 120. Other heat transfer surfaces upstream of the economizer 116 are not shown. The economizer 116 in Figure 1 represents the last vapor or hydrothermal transfer surface boiler in the boiler in the direction of gas flow out of the boiler, and may be from the superheater surface, the reheater surface, or depending on the type of boiler used. Replace the evaporator surface. The flue gas 120 then flows downstream and enters a selective catalytic reduction (SCR) unit 130 (which may or may not be present) to remove nitrogen oxides (NO _x ) from the flue gas 120.

Next, the dry absorbent is injected into the flue gas at the first dry absorbent injection point A (before the flue gas enters the air heater 140). The first injection point A is upstream of the air heater 140 and may be described as being located between the economizer 116 and the air heater 140. The dry absorbent travels from absorbent supply 161 via line 166 to injection point A. If the SCR unit 130 is present, the first injection point A can be described as being directly between the SCR unit 130 and the air heater 140, or downstream of the SCR unit. A replacement (or additional) location (not shown) of one of the dry absorbent injections may be provided upstream of the SCR unit 130 if deemed suitable for the particular application. This reaction injection of dry absorbent and SO _x, the flue gas stream to reduce the amount of SO _x, thereby reducing ADP.

The flue gas 120 then passes through an air heater 140 that cools the flue gas 120 and heats the air 114 entering the furnace 105. The air heater can be a recuperative air heater or Regenerative air heater. The addition of a dry absorbent upstream of the air heater allows the flue gas outlet temperature to be lowered without causing corrosion. In other words, more of the heat energy in the flue gas can be transferred to the air 114 entering the furnace and recycled back to the boiler. This has resulted in higher boiler efficiency and considerable equipment protection and reliability. The temperature of the flue gas 120 after exiting the air heater 140 is lower than the temperature of the flue gas 120 after exiting the air heater 140 in the system in which the absorbent is not injected at the first absorbent injection point. In a particular embodiment, the temperature of the flue gas 120 after exiting the air heater 140 is greater than the flue gas 120 after exiting the air heater 140 in a system where the absorbent is not injected at the first absorbent injection point. The temperature is at least 10 °F lower, at least 20 °F lower, or at least 30 °F lower.

After passing through the air heater 140, the flue gas 120 typically has a temperature of from about 240 °F to about 280 °F (115 °C to 138 °C). If desired, the flue gas 120 then passes through the particulate collection device 150 to collect fly ash and other larger particles. This particulate collection device 150 is arbitrarily present and typically does not exist. The collected particles are then recycled to the desulfurization unit 160 when present.

The additional dry absorbent is injected into the second absorbent injection point between the air heater 140 and the desulfurization unit 160, or in the desulfurization unit itself, into the flue gas. Two of the second absorbent injection points are indicated by the letters B and C. These second injection points are fed by an absorbent supply 161 (via lines 167 and 168, respectively). In an embodiment, the ratio of the first absorbent injection point to the second absorbent injection point of the absorbent injection rate is from about 1:99 to about 10:90 (measured in pounds per hour at each injection point).

The desulfurization unit 160 is a circulating dry scrubber (CDS), or a spray drying absorber (SDA), or a circulating fluidized bed (CFB) scrubber. In the CDS as illustrated herein, dry absorbent 162 and water 164 are injected into the flue gas to react with sulfur oxides (SO _x ) and halides (HCl, HF) and further cool the flue gas 120 to about 140. From °F to a range of about 210°F (60°C to 99°C). Were injected water and dry absorbent can be readily adjusted such that the material feeding lime and _the SO _x concentration can be varied and enables the use of lower quality water. In the desulfurization unit 160, water is evaporated. In SDA, an atomized alkaline slurry, such as a lime slurry, is sprayed into the flue gas to purify and cool the flue gas. In the CFB scrubber, the dry absorbent is introduced into the fluidized bed and the flue gas is used as a fluidizing gas. In a particular embodiment, slaked lime is considered as a dry absorbent in the desulfurization unit. In a particular embodiment, the desulfurization unit is a circulating dry scrubber (CDS).

The resulting purified particulate-bearing flue gas 120 is delivered to a baghouse 170 such as a fabric filter or an electrostatic precipitator to remove particles from the flue gas 120. The purified flue gas 120 is then sent to the chimney 180.

The recycle stream 172 from the baghouse 170 can be used to collect solid alkaline particles and recycle them from the baghouse back to the desulfurization unit 160, particularly when using CDS. This recycling imparts multiple opportunities for the unreacted reagent to pass through the desulfurization unit 160 and react with the sulfur oxides to achieve high reagent utilization. A new dry absorbent 162 can also be added to replace any dry absorbent that has been used. The particles can also be removed from the baghouse 170 and disposed of. This is indicated by the symbol 174.

When there is 130, and / or CO SCR catalyst unit, at the first injection point of the injection of dry absorbent A is particularly useful, since these catalysts tend to promote conversion of SO ₂ to SO _3. This increases the acid dew point temperature (ADP) of the flue gas.

Other design features can be used to control the temperature of the outlet gas from the flue gas of the air heater (i.e., component symbol 140), primarily by controlling the temperature of the incoming air 114 to the boiler. Three such features are illustrated in Figure 1. Any of the six possible combinations of these features can be considered. Temperature control is applicable to, for example, non-designed fuel combustion, non-designed environmental conditions (eg, temperature, pressure, humidity) operation, or operation under partial load on the boiler.

In this regard, it is contemplated that the air heater 140 has a heat flow passage and a cold flow passage. The so-called "hot" and "cold" are relative to each other, not the absolute temperature. The flue gas 120 passes through the heat flow passage and the incoming air 114 passes through the cold flow passage. The thermal energy is transferred from the flue gas in the heat flow passage to the air passing through the cold flow passage. An inlet fan 196 provides the incoming air.

The first feature is a preheater 190 located between the inlet fan 196 and the cold flow passage inlet of the air heater 140. This heater may use steam or hot water to preheat the incoming air, which limits heat transfer from the flue gas. The second feature is a heated air recirculation flue 192 that passes from a point downstream of the outlet of the cold flow passage to a point upstream of the inlet of the cold flow passage. This flue takes a relatively small flow of heated air and returns it to the inlet to the surrounding air Mix and change the temperature gradient in the air heater. The third feature is a cold air bypass 194 around the air heater 140 that causes some of the incoming air to be completely unheated. This feature also limits the transfer of heat from the flue gas to the incoming gas.

It is noted that the SDA typically requires that the incoming flue gas have a minimum temperature of about 220 °F to evaporate the water, while the CDS requires a slightly lower minimum temperature. Therefore, the desulfurization unit needs to be integrated with the dry absorbent injection. Conventional applications of flue gas desulfurization technology control acid gas emissions, but do not affect the overall equipment efficiency/heat rate of the equipment as occurs in the present disclosure. It is noted that Figure 1 illustrates the use of a dry absorbent for injection at two or more different injection points and that is fed from the same (i.e., single) absorbent supply. However, it is more likely that each injection point has its own source of supply because the feed rate between the two injection points can vary by a factor of 10 to 20 (the second injection point receives the most absorbent). Two different absorbents can also be used if desired.

In conventional systems and methods, the dry absorbent is only injected at a location corresponding to the second dry absorbent injection point of the present disclosure. To obtain system designers typically determine an appropriate flow rate of SO _x desired degree of reduction of the required dry absorbents (flow rate). In the present disclosure, a portion of the dry absorbent is transferred to the first dry absorbent injection point. As previously mentioned, the ratio of the first absorbent injection point to the second absorbent injection point of the absorbent injection rate is from about 1:99 to about 10:90 (measured in pounds per hour at each injection point). Therefore, the total flow rate of the dry absorbent does not change. It is noted that only the redistribution of dry absorbent does not improve boiler efficiency and overall equipment efficiency. Rather, the design of the injection system, desulfurization unit, and air heater must be combined to increase these efficiencies. The temperature of the flue gas exiting the air heater needs to be optimized to balance the efficiency of the proper conditions for operating the desulfurization unit. In particular, the dry absorbent injection system upstream of the air heater enables additional thermal energy to be captured. This means that the need to burn less fuel, and therefore the amount of SO _x is less per unit of energy used to generate the absorber is reduced. In general, this means that the total absorbent consumption is also reduced. As a result, fuel and absorbent costs are reduced, and auxiliary power plant consumption is also decreasing. This achieves more cost-effective power generation.

The increase in boiler efficiency also has an impact on the design of the desulfurization unit, especially the CDS absorption tower. Since the CDS is a volumetric device and the increase in boiler efficiency is equivalent to a decrease in the volumetric gas flow (because of less fuel and lower inlet gas temperature), the corresponding CDS absorber required to process the gas stream The diameter is also reduced. A smaller diameter absorber will promote better contact between the gas, liquid and solid phases and will be equivalent to better wetting of the solid particles. In other words, due to the lower volumetric flue gas flow, a smaller CDS absorber can be used while still achieving the same efficiency.

2 and 3 provide some additional details of a conventional recirculation system 200 for returning solid particles to a CDS absorption tank in an exemplary embodiment of the present disclosure. Figure 2 is a side view and Figure 3 is a plan view (i.e., viewed from the top). Figure 4 is a perspective view of a similar recirculation system.

Referring first to Figure 2, the untreated flue gas system enters through the left side and passes through an air heater 270. A heat flow channel inlet 272 and a heat flow channel outlet 274 are illustrated. The hydrated lime silo has a passage 266 that injects the slaked lime absorbent into the flue gas at an injection point A upstream of the air heater. Also shown are the cold flow passage inlet 276 and the cold flow passage outlet 278 through which the incoming air flows. The heat energy in the flue gas is transferred to the air. The direction of the flow is indicated by an arrow. The particle collecting device (element symbol 150) shown in Fig. 1 is not included here.

Continuing to refer to Figure 2, on the right side of the air heater 270, the flue gas enters the passage to the pollution control system, which is tied at a low elevation (relative to the ground 204). The passage is then turned vertically to cause the flue gas to flow upward through the Venturis 220 (see Figure 4) into the bottom inlet 212 of the circulating dry scrubber (CDS) absorption tank 210. The flue gas passes through a solid injection point 222 upstream of the venturi 220 as the flue gas flows upward. This example is shown in Figure 3, which shows four venturis. Water injection point 224 is located at the base of absorption tank 210 and downstream of venturi 220. The solid particles and the purified gas then flow from the top outlet 214 of the absorption tank into the baghouse 230. The baghouse 230 is raised above the ground 204 by a particular height 255.

The solid particles are then removed from the gas stream and some of the solid particles are recycled back to the absorption tank by a baghouse. The solid particles exit the baghouse 230 through a hopper to an air slide 240. One or two slides can be used depending on the size and setting of the bag dust collector. The solid particles then need to be nearly evenly distributed onto a second set of slides equal to the number of solid injection points.

This can be done using distribution box 250. The slide rail 240 is guided by the bag dust collector 230 to the distribution box 250. Here, two distribution boxes are shown. The distribution box divides the solids flowing from the baghouse into two distinct streams which then flow down to the other chute 242 to the solids injection point 222. There are four solid injection points in Figure 3, and six solid injection points (one for each venturi 220) in Figure 4, which are placed between the absorption tanks 210 on average. Each slide has a minimum slope of seven (7) degrees to effect flow. Distribution box 250 has a height 255 of from about 8 呎 to about 15 。. It is noted that as shown in Fig. 3, the distribution box is located on the side of the absorption tank, not below the absorption tank, i.e., the distribution box does not affect the height of the absorption tank.

The slaked lime storage bin 260 has a passage 262 that is directed by the slaked lime storage bin to each of the distribution bins 250. As shown in FIG. 4, a new slaked lime is injected into the distribution tank 250 or injected into the top of the CDS absorption tank 210 (not shown). The distribution box also mixes the solid particles with the new slaked lime. Typically, the fresh slaked lime bin 260 is higher than the injection point so that the slope from the bin to the injection point is at least 15° so that new slaked lime can be fed by gravity.

Referring again to Figure 4, the purge gas exits the baghouse 230 through conduit 232 to the chimney 206 downstream of the baghouse, and the purge gas can be vented to the atmosphere. Also seen is a purge gas recycle flue 270 that recycles the purified flue gas from downstream of the baghouse 230 to a point upstream of the solids injection point 222.

The bag dust collector in various embodiments may be an electrostatic precipitator (ESP), a reverse gas fabric filter, a vibration exhaust fabric filter. (shake deflate fabric filter), or pulse jet fabric filter. It is desirable that the bag dust collector be a pulse jet fabric filter (PJFF) or a reverse gas fabric filter. In this regard, the baghouse is superior to ESP because of the desulfurization ability of fabric filters and ESP. In other words, because of the development of a filter cake, fabric filters can trap contaminants in the vapor phase, while ESP captures only particles and does not significantly trap vapor phase contaminants.

The individual systems of the present disclosure and the components required for their integration are within the skill of the art. Devices, valves, tubing, sensors, connections, and accessories used herein are also generally commercially available. The design of the method of operating the present disclosure is also within the skill of the art.

Example Example 1

In the proposed application involving medium sulfur coal, the acid dew point temperature (ADP) (based on uncontrolled SO ₃ formation) is expected to be calculated to be 289 °F (out of the air heater). Dry absorbent injection (DSI) was used upstream of the air heater to reduce the predicted ADP to 256 °F. The difference between these temperatures (33 °F) indicates that the energy can be transferred stably with general heat transfer equipment and there is no additional risk of corrosion. To achieve this benefit by transferring additional heat, the boiler's economizer and air heater surface can be increased. The boiler efficiency increased with this method is approximately 0.8%. As a result, auxiliary power consumption was also improved, and total absorbent consumption was also reduced by 0.8% (because less 0.8% of flue gas and associated emissions were produced). CO ₂ emissions are also reduced by 0.8% because less fuel is burned. As the integrated system achieves improved boiler efficiency, it is expected that the absorbent consumption will be reduced and maintain the same stack outlet emissions concentration.

In some cases, it is contemplated that the integrated dry absorbent injection and desulfurization unit can reduce the ADP of the air heater to as much as 45 °F to 50 °F. The resulting boiler efficiency improvement can be about 1.2%.

Example 2

As shown in Figure 5, the use of a dry absorbent upstream of the air heater allows the safe operating flue gas outlet temperature (at the heat flow passage outlet) to be reduced to 240 °F. If desulfurization with CDS is chosen, the integrated system can be designed at 250 °F, thus achieving a 30 °F reduction from the case where no dry absorbent is applied upstream (280 °F). If you choose to desulfurize with SDA, you can design it at 270 °F. Further, the total consumption of the absorbent system is no greater than the initial "uncontrolled" the situation of persons; in fact, consumption-based absorbents decreased because less fuel burn and less SO ₃ produced in the boiler.

Example 3

In the embodiment illustrated in Figure 6, the safe operating air heater outlet gas temperature of the flue gas can be reduced from 320 °F to 280 °F. Both CDS and SDA are effectively operated at 280 °F, so the integrated system allows the flue gas temperature to drop by 40 °F. Again, total absorbent consumption The amount has also been reduced as described above. The overall emissions from the boiler are reduced due to reduced fuel flow (better equipment efficiency).

The disclosure has been set forth with reference to the exemplary embodiments. Obviously, other modifications and variations can be made by reading and understanding the foregoing detailed description. All such modifications and variations are intended to be included within the scope of the appended claims.

100‧‧‧Boiler

105‧‧‧ furnace

110‧‧‧Desulfurization system

111‧‧‧Crusher

112‧‧‧ fossil fuel

114‧‧‧Air

116‧‧‧heater

120‧‧‧flue gas

130‧‧‧SCR unit

140‧‧‧Air heater

150‧‧‧Particle collection device

160‧‧‧Desulfurization unit

161‧‧‧Absorbent supply

162‧‧‧Dry absorbent

164‧‧‧ water

166‧‧‧ lines

167‧‧‧ lines

168‧‧‧ lines

170‧‧‧ bag dust collector

172‧‧‧Recycling flow

180‧‧‧ chimney

190‧‧‧Preheater

192‧‧‧heated air recirculation flue

194‧‧‧ Cold air bypass

196‧‧‧ entrance fan

Claims (17)

A flue gas desulfurization system comprising: a first dry absorbent injection point upstream of an air heater; a desulfurization unit downstream of the air heater; and a bag dust collector downstream of the desulfurization unit, the bag type dust collector The solid particles are separated from the purge gas. The system of claim 1, further comprising a second dry absorbent injection point located between the air heater and the desulfurization unit or in the desulfurization unit. The system of claim 1, wherein the desulfurization unit is a circulating dry scrubber or a spray drying absorber. The system of claim 1, further comprising a purge gas recirculation flue that is directed downstream of the baghouse to a point upstream of the desulfurization unit. The system of claim 1, further comprising a recirculation system for moving solid particles from the baghouse to the desulfurization unit. The system of claim 1, further comprising a dry absorbent reservoir that feeds the first dry absorbent injection point. The system of claim 1, wherein the bag dust collector is a pulse jet fabric filter, a shake deflate fabric filter, and a reverse gas fabric filter. (reverse gas fabric filter), or electrostatic precipitator. Such as the system of claim 1 of the patent scope, wherein the air plus The heat exchanger includes a heat flow passage and a cold flow passage, and the flue gas passes through the heat flow passage and transfers the heat energy to the gas from the inlet fan through the cold flow passage. A system of claim 8 further comprising a preheater positioned between the inlet fan and the cold flow passage of the air heater. The system of claim 9, further comprising a cold air bypass around the air heater such that the gas supplied by the inlet fan does not pass through the cold flow passage. The system of claim 8 further comprising a heated air recirculation flue that is from a point downstream of the outlet of the cold flow passage to a point upstream of the inlet of the cold flow passage. A system of claim 8 further comprising a selective catalytic reduction (SCR) unit upstream of the air heater, the first dry absorbent injection point being located downstream of the SCR unit or upstream of the SCR unit. A method for improving boiler efficiency, comprising: injecting slaked lime into a flue gas at a first slaked lime injection point upstream of an air heater; reducing a flue gas temperature in an air heater; and a second slaked lime injection point downstream of the air heater The slaked lime is injected into the flue gas; the flue gas is sent to the desulfurization unit downstream of the air heater and downstream of the second slaked lime injection point; and the baghouse is sent to the baghouse downstream of the desulfurization unit, the bag set The dust separator separates the solid particles from the purge gas; wherein the temperature of the flue gas after leaving the air heater is lower than the flue gas after leaving the air heater in the system where the slaked lime is not injected at the injection point of the first slaked lime temperature. The method of claim 13, wherein the temperature of the flue gas entering the air heater is about 600 °F or higher. The method of claim 13, wherein the temperature of the flue gas exiting the air heater is from about 220 °F to about 350 °F. The method of claim 13, wherein the desulfurization unit is a circulating dry scrubber or a spray drying absorber. The method of claim 13, wherein the temperature of the flue gas after leaving the air heater is higher than the flue gas after leaving the air heater in the system where the slaked lime is not injected at the first slaked lime injection point. The temperature is at least 30 °F.