Air Pollution Control for Industrial Boiler Systems

Transcription

1 Air Pollution Control for Industrial Boiler Systems J.B. Kitto Babcock & Wilcox Alliance, Ohio, U.S.A. Presented to: ABMA Industrial Boiler Systems Conference November 6-7, 1996 West Palm Beach, Florida, U.S.A. BR-1624 (RDTPA 96-53) Introduction A variety of constituents found in the products of combustion have been targeted for postcombustion control by national and local regulatory agencies. Primary among these are sulfur dioxide (SO 2 ), oxides of nitrogen ( appearing mainly as NO), and particulate. Additional emphasis has recently been placed upon the control of hazardous air pollutants (HAPs or air toxics ) which are usually found in trace quantities. This paper specifically addresses technologies for the postcombustion control of these emissions. The control of by combustion system improvements and the control of SO 2 and through the implementation of fluidized bed combustion technology are covered extensively in References 1 and 2. In most cases, the postcombustion control technologies discussed here may be added to these two technologies to further reduce emissions. The type of emissions control technology employed for a specific application depends upon the regulatory requirements as well as upon the postcombustion emission levels. Emissions are highly site specific depending upon the fuel being burned and the combustion system. For illustrative purposes, Table 1 summarizes the emissions from a nominal 250,000 pound steam per hour modern pulverized coal-fired industrial boiler at 100% load burning 2 1 / 2 % sulfur, 16% ash, 12,360 Btu/lb eastern bituminous coal. The use of low burners has been assumed. Recent studies have indicated the total emissions rate of key trace metals on such a unit might be on the order of to 0.11 lb/hr and trace organics might be comparable depending upon the coal chemistry and boiler system configuration. However, these levels remain highly preliminary pending the completion of tests currently underway. [3] A variety of postcombustion technologies provide significant control of these emissions today. Technologies typically include filtration, condensation, absorption, adsorption, and various chemical reactions. Specific technologies are available Table 1 Typical 250,000 lb/hr Steam Flow Coal-Fired Steam Generator Air Emissions (2.5% Sulfur, 16% Ash, 12,360 Btu/lb Coal) Constituent Uncontrolled Emissions Rate SO ton/hr as NO ton/hr (includes low burners) Flyash 1.5 ton/hr today to control SO 2 and emissions at 90 to 95% and particulate emissions by 99.5% or more at a cost. Therefore, the key issues for selecting specific technologies include: 1) meeting the emissions requirements at an acceptable minimum cost (capital, operations, and maintenance) and 2) achieving reliable long term operation. The strategies for postcombustion control of all emissions from systems are formulated by considering the specific fuel (coal or other), type and extent of emissions reduction mandate, boiler design, required availability, location, new versus old site, equipment age and remaining life. In some cases fuel selection alone will provide the desired emissions rates. In other cases, the ultimate strategy may include a combination of technologies which work in series or parallel to costeffectively and reliably meet the emissions limits. Desulfurization A broad range of sulfur dioxide (SO 2 ) control technologies have been employed since their introduction to the coal-fired power industry in the early 1970s. However, relatively few have been commercialized extensively over this time period and even Babcock & Wilcox 1

2 fewer are under serious consideration for major commercial FGD applications in the near future. The most widely applied technology today for utility boiler systems is non-regenerable wet scrubbing. The second largest utility category and the largest industrial control technology is dry scrubbing or spray dry scrubbing. Wet FGD systems have provided cost-effective high SO 2 removal efficiencies (90-98%) for a range of low to high sulfur coals in electric utility power plants. [1] Design and efficiency improvements have led to dramatically low initial capital cost and operating power consumption over the past 16 years. However, the systems for converting the wet sludge waste into a usable by-product or safe landfill material are an additional complexity which frequently make wet FGD systems less attractive for industrial applications. Thus, SO 2 control for industrial boilers typically takes the form of burning a low sulfur compliance fuel, fluidized bed combustion with limestone bed material for SO 2 capture (see Reference 1) or the application of a dry flue gas desulfurization process. The last is the subject of the following sections. Inlet Inlet 60 Rotary Atomizer (Lime Slurry) Outlet Dry Scrubbing Technology Description. The term dry scrubbing as used here refers to the class of FGD processes where an aqueous slurry or solution of alkaline reagent is sprayed into the flue gas from a boiler in such a manner that the water evaporates immediately within the scrubber and the reaction products are removed as an essentially dry powder. This technology is also referred to as spray drying, spray dry absorption, and semi-dry scrubbing. The advantage of dry scrubbers over wet scrubbers include simpler, cheaper materials of construction, a dry waste product, no waste water stream, lower fresh water demand, and simpler process control. The disadvantages include less efficient use of reagent, the exclusion of limestone as a reagent option, and a somewhat lesser capability for high SO 2 efficiency. Because of the combination of the strengths and weaknesses, dry scrubbers have become important in selected markets, including many industrial boiler applications. Several simple ways exist to categorize dry scrubbers. These include in part; the reagent used, the method of atomization, the type of dust collector used, and the general features of the dry scrubber itself. By far, the dominant reagent used in dry scrubbing is slaked lime. Whereas most wet scrubbers that use lime also have a significant magnesia content, lime used in dry scrubbers generally has a low magnesia content (less than 1% MgO). Lime is usually slaked on-site using either paste slakers, ball mill slakers, or detention slakers. The quality of water for slaking must be good, but the rest of the water used in the system can be of low quality. The other reagent, used on a limited basis, is sodium carbonate. Dry scrubbers employ either dual fluid or rotary disk atomizers. The latter is much more commonly used. The rotary atomizers are generally more energy efficient but are mechanically sophisticated and require a high degree of maintenance. Some dry scrubbers are designed to use a single atomizer situated in the axial center of the scrubber. Such a design is illustrated in Figure 1. This design offers the advantage of geometric simplicity but has the disadvantage of interrupting SO 2 removal in the unlikely event that the single atomizer fails (a backup system can be provided). An alternative design illustrated in Figure 2 uses several dual fluid atomizers. Designs also exist where several rotary atomizers are employed in a single module. Product Figure 1 Vertical flow dry scrubber with single mechanical atomizer. Figure 2 Vertical flow dry scrubber with multiple dual fluid atomizers. 2 Babcock & Wilcox

3 Most dry scrubbers use the cylindrical downflow design fashioned after the conventional spray dryer as illustrated in Figures 1 and 2. Horizontal flow dry scrubbers have also been built utilizing several dual fluid atomizers as illustrated in Figure 3. Both electrostatic precipitators and fabric filters (baghouses) have been used with dry scrubbers. Unlike the wet scrubber, the dust collector is placed after the dry scrubber. Fabric filters are generally preferred because the solids deposited on the bag filter surfaces are in more intimate contact with the flue gases and therefore are a more effective absorber of residual SO 2 from the flue gas. The wastes from dry scrubbers consist of mixtures of fly ash, calcium sulfite, and calcium sulfate. This material is dry in contrast to the sludge from a wet scrubber. Environmental Performance. Lime-based dry scrubbing systems, including the particulate removal equipment, routinely operate with SO 2 removal efficiencies from 70-90% on lower sulfur coals (<2.5% sulfur) depending the design operating conditions such as approach to saturation temperature, the calciumto-sulfur ratio, gas residence time, slurry droplet size distribution and type of particulate collector. [4] In selected cases, removal efficiencies of 98% have been reported. [4] Calcium-tosulfur ratios typically range from 1.1 to 1.6. As indicated above, the presence of alkali in the fuel ash will usually lower the reagent requirements. Auxiliary power requirements due primarily to the flue gas pressure loss and the slurry atomization range from 0.5 to 1.0 % of the plant output depending on the fuel sulfur content, the removal efficiency, and the possible use of additives. Approximately 2.2 tons of dry waste product (plus ash content) are produced for each ton of SO 2 removed. Dry scrubbers have also demonstrated the ability to remove some mercury and chlorides. Commercial Impact. Dry scrubbing will continue to be applied to cases where fuel sulfur content, ash chemistry and required performance requirements make it the most economical choice. Dry scrubbers are most frequently used for coals with less than 1.5% sulfur where the higher calcium-to-sulfur ratio of dry scrubbing is less of a disadvantage. Sorbent Injection Systems Technology Description. In the context of this paper, Sorbent Injection Processes include all technologies where a sorbent is added dry or slightly damp within the confines of the existing boiler or flue work. As such, these processes require relatively little new equipment and are thus suitable candidates for retrofit applications. In general, the level of SO 2 reduction is relatively low to moderate and the sorbent requirements are relatively large. Thus, sorbent injection processes seem most applicable to boilers with limited space. Sorbent injection includes processes where sorbent is added with the fuel, injected in the vicinity of the burners, the furnace arch, the convective pass, upstream of the economizer, downstream of the economizer, and upstream of the particulate collector. SO 2 removal performance depends upon the reagent chemistry, reagent size distribution, the temperature of the flue gas, and the residence time. Sorbent injection SO 2 control processes have seen some limited application recently. Several programs have demonstrated the technical viability of several options at commercial scale and most are ready for commercial use. However, application has been relatively limited to date because of the final regulator requirements in many locations. Figure 4 illustrates that for calcium based sorbents, three distinctive temperature windows exist within the boiler circuit. [4] Figure 3 Horizontal flow dry scrubber with multiple dual-fluid atomizers. Babcock & Wilcox 3

4 SO 2 Removal, % Burner Zone Ca/S = 2 Upper Furnace Zone 1 Superheater Reheater Zone 2 Economizer Air Heater Sorbent Injection Temperature, C Zone 3 Figure 4 SO 2 removal at different temperature windows for sorbent injection. The hottest zone is in the vicinity of the boiler furnace and is referred to as furnace sorbent injection (FSI) or LIMB (see Figure 5). The sorbents used for various injection processes include limestone [CaCO 3 ], lime [CaO], hydrated lime [Ca(OH) 2 ], soda ash [Na 2 CO 3 ], sodium bicarbonate [NaHCO 3 ], and the naturally occurring sodium carbonates and bicarbonates such as trona and nahcolite. T sat Processes that use the third temperature zone, near the adiabatic saturation temperature start to approach dry scrubbing from a technical, performance, and economic standpoint. One commercialized cold end processes is referred to as Coolside. Environmental Performance. Sorbent injection systems, including the effect the particulate removal equipment, have been operated with SO 2 removal efficiencies from 40-70% on lower sulfur coals (<2.5% sulfur) depending the design operating conditions such as approach to saturation temperature and the calcium-to-sulfur ratio. [4] Calcium-to-sulfur ratios typically range from 2 to 3 resulting in modest calcium utilizations. Auxiliary power requirements are primarily due to sorbent injection energy and are usually less than 0.5 % of the equivalent plant output. [4] Several tons of dry waste product (ash, spent sorbent and unused sorbent) are produced for each ton of SO 2 removed depending primarily upon the process, removal percentage, and reagent reactivity. Commercial Impact. Because of their relatively low initial capital cost and their relative ease of installation, sorbent injection systems are considered to be particularly attractive for retrofits of older power plants and industrial applications where only modest levels of SO 2 control are needed. In addition, they are used in conjunction with low sulfur coal in order to meet site specific SO 2 emission requirements. Dentrification Emissions of nitrogen oxides ( ) from boilers may be limited through the application of combustion process changes and postcombustion technology. For new systems, the most cost ef- Figure 5 Furnace sorbent injection systems for SO 2 control includes humidification system to enhance particulate collection and SO 2 removal efficiency. 4 Babcock & Wilcox

5 fective approach is to install low burners to minimize the initial formation while adding postcombustion technology if further reductions are needed. This is also generally true for retrofit applications although site specific evaluations are needed. References 1 and 2 provide an overview and status of low burners and combustion technology while this section is specifically devoted to postcombustion systems. Selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) de technologies are the major systems applied commercially today for postcombustion control of from boilers. In both of these technologies, is reduced to nitrogen (N 2 ) and water (H 2 O) through a series of reactions with a reagent injected into the flue gas. Several alternative postcombustion reduction processes are in various stages of development but these other processes have not yet received widespread commercial application. Selective Catalytic Reduction (SCR) Technology Description. In an SCR system, ammonia is injected into the flue gas stream and reacts with species as the gas passes over a catalyst within an appropriate temperature window. The ammonia may be stored as either anhydrous ammonia or as an aqueous solution with a 25 to 28% concentration. Urea solutions have been tested as an alternate reagent and emission reductions comparable to those obtained with ammonia have been observed. [6] The optimal operating temperature is dependent on the specific catalyst and is usually in the range of 450 to 840F. [1] The catalyst used may be of several types as shown in Table 2. [2,6,7] Most of the operating experience to date has been with base metal catalysts using titanium dioxide with small amounts of vanadium, molybdenum, tungsten and other active chemical agents. [1] Technical criteria which determine the type of catalyst to be used in a specific application include: gas temperature, reduction required, permissible ammonia slip (low carryover of unreacted reagent), permissible oxidation of SO 2, concentration of other flue gas constituents which might poison the catalyst (reducing performance or life), particulate loading, and the required catalyst life. The design of each SCR system is unique, based on space constraints, temperature requirements and boiler fuel. For example, a typical hot side, high dust SCR boiler installation is illustrated in Figure 6. The ammonia is mixed with air or steam at about a 20:1 ratio for injection into the flue gas upstream of the catalyst reactor. The ammonia flow rate is controlled to maintain the design mole ratio of ammonia to inlet within the design range typically 1:1. The required removal efficiency and allowable ammonia slip determine the ammonia to mole ratio. Figure 6 New utility boiler with SCR installation high dust, high temperature configuration. Table 2 SCR De Catalyst Types Category Material Applicable Temperature Precious Metal Platinum F Base Metal Titanium Oxide/ F Vanadium Zeolite Aluminum Silicates F The catalyst may be placed on a metal plate substrate or extruded as a honeycomb monolith sections which are then assembled into blocks. These block sections are then stacked in a holder to make up the SCR reactor module. The plate type arrangement offers lower pressure drop and is less susceptible to pluggage and erosion in high dust applications. The honeycomb arrangement provides for higher catalyst surface area in a similar reactor volume. The reactor may be installed in a vertical or horizontal flow orientation depending on the fuel used, space availability and arrangement of adjacent equipment. For solid fuel applications, vertical downward flow is usually employed to enhance ash removal and cleaning. Uniform gas flow distribution and complete mixing of the reagent with the gas stream are required for maximum efficiency and low ammonia slip through the system. SCR units are predominately located at two points downstream of a boiler: hot side, high dust units between the economizer and the air heater and tail end or cold side units downstream of both the particulate collection and desulfurization systems. As experience has been gained with high dust loadings and improved catalyst formulations, most new installations have used the hot side, high dust configuration to minimize costs. Several applications have also been evaluated where catalyst may be installed directly within existing fluework. SCR de systems for boilers are becoming a mature technology in Germany, Japan and the United States because of their extensive installations. Most of these systems use anhydrous ammonia as the reducing agent and achieve 80+% emission reduction. Babcock & Wilcox 5

6 Environmental Performance. SCR de systems are typically designed to reduce emissions by 45 to 90% depending upon the regulatory requirements and inlet concentrations. Since reagent and catalyst requirements climb as the reduction requirements increase, units are designed to minimize costs while providing the necessary emission reductions. Most units are designed to remove less than 80% of the inlet because of escalating catalyst costs at higher efficiencies. Not all of the reagent takes part in the reactions connected with reduction. This unreacted reagent is found as ammonia species in the exit flue gas stream. This ammonia slip is routinely limited to less than 5 to 10 parts per million by volume based upon fuel type. Commercial Impact. SCR de is a high efficiency technology but may represent a higher cost alternative for controlling emissions as compared to most low combustion systems and modifications. In many cases, it is more economical to first reduce initial formation through the combustion system, and then if required use SCR de systems. Plant specific conditions must be evaluated to determine the most economical control strategy and system. SCR de systems have demonstrated the ability remove high levels of from fossil fuel-fired plants. Selective Non-Catalytic Reduction (SNCR) Technology Description. SNCR involves the injection of a reducing reagent into the furnace at relatively high temperatures to react with. The desired reaction occurs in a temperature window of 1600 to 2000F. Above this window, the reagent may be oxidized resulting in the formation of additional and below the window the rate of reaction is slowed which may result in excessive emissions of unreacted reagent. [8] The optimum reaction temperature window is also influenced by the O 2, CO and SO 2 concentrations in the flue gas. [2] High CO concentrations which may result from the installation of low- burners reduces the removal efficiency. High SO 2 concentrations increase the temperature for optimal performance. [2] Sufficient mixing of the reagent with the flue gas and adequate residence time for reaction in the furnace are critical for reducing emissions. In general, reductions are lower and chemical consumption is higher than with SCR. [2] Typical reagent/ inlet stoichiometries are 2:1. Since SNCR does not require the use of a catalyst, capital costs are lower than with SCR. Ammonia (NH 3 ) or Urea ((NH 2 ) 2 CO) may be used as the reducing reagent in an SNCR application. The urea may be stored as a solid or mixed with water and stored as a solution. The urea/ reaction occurs in a relatively narrow temperature range (about 1650 to 1800F). Unlike ammonia, the storage and use of urea is not subject to SARA title III reporting requirements. However, the use of urea may result in emissions of N 2 O, a greenhouse gas. Some work has also been done using isocyanate and cyanuric acid as the reducing agents but these are not yet widely commercialized. Additives such as hydrogen, hydrogen peroxide and ethane may be used to lower the effective temperature for the reduction reaction. [2,8] A typical SNCR system consists of storage and handling equipment for the reagent, equipment for mixing the chemical with the carrier (compressed air, steam or water) and the injection equipment. The ammonia or urea injection ports are typically positioned at several locations in the furnace as shown in Figure 7. [1] For industrial boiler applications, the correct temperature window is usually in the upper furnace. Multiple injection locations are usually needed to maintain reduction efficiency as the flue gas temperature profile in the boiler changes with load. Ammonia based SNCR was developed and patented by Exxon and is marketed under the trade name Thermal De emission reductions over 50% were achieved over a range of boiler loads but ammonia slip could not be maintained below 10 ppm at full load. The process has also been applied to a number of boilers in the 50 to 150 MW e range firing coal or wood. A third coal-fired application in the U.S. has achieved 76% reduction on a circulating fluid bed boiler. [8] The OUT process is a urea based SNCR system. The process has been applied to a variety of boilers including stoker, circulating fluidized bed and tangentially fired units with reductions of 40 to 60 %. EPRI owns the basic patents for the urea based SNCR system. Environmental Performance. Current demonstrations on 5 U.S. utility boilers representing a range of boiler types and firing oil and coal with emission reductions ranging from 20 to 60%. [6] Short term demonstrations on coal-fired boilers have shown 40 to 55% reduction with ammonia slip less than 5 ppm. [8] SNCR performance is very dependent on temperature and sufficient residence time at the appropriate reaction temperature. In industrial boilers, the desired temperature window frequently occurs in the furnace making reagent injection and residence time reasonable (see Figure 7). In large utility boilers, the desired temperature window may occur in the convection Reduction Zone Municipal Solid Waste Boiler Injection Ports (Both Sides) Figure 7 Industrial boiler SNCR ammonia injection locations and reaction zone for control. 6 Babcock & Wilcox

7 pass cavities which may limit control to 20 to 40%. [1] Injection in the convection pass limits reduction because of difficulty in dispersing the reagent and the limited residence time in the desired temperature range. Commercial Impact. SNCR de system performance is relatively sensitive to reagent injection location (especially with load change) and to rapid complete mixing of the reagent and flue gas. SNCR technology will likely continue to be used for specific industrial applications where the initial levels, reduction requirements, and boiler/furnace geometry are conducive to SNCR systems. Particulate Collection Flyash from the combustion process is collected using one of four major technologies: electrostatic precipitators (or ESPs), fabric filters (or baghouses), mechanical collectors and wet scrubbers. With today s removal requirements in excess of 99.5%, modern ESPs and fabric filters dominate fly ash collection. Mechanical collectors are still used for specialty applications as a preliminary collection device, especially where fly ash recycle is part of the combustion process, but they are almost always followed by an ESP or fabric filter for final particulate control. Wet scrubbers are no longer used for primary particulate collection because of their high energy requirements for the desired removal efficiencies. Electrostatic Precipitators Technology Description. An electrostatic precipitator (ESP) electrically charges the ash particles in the flue gas to collect and remove them. The unit is comprised of a series of parallel vertical plates through which the flue gas passes. Centered between the plates are charging electrodes which provide the electric field. The collecting plates are typically electrically grounded and are the positive electrode components. The discharge electrodes in the flue gas stream are connected to high voltage power source, typically 55 to 75 kv DC, with a negative polarity. As the flue gas passes through the electric field, the particulate takes on a negative charge. The negatively charged particles are then collected on the grounded collection plates. Gas velocity between the plates must be low to permit time for the charged particles to move to the collection plates and reduce the likelihood of re-entrainment. The ash layer must be periodically removed. The most common method of removing dry particulate is rapping of the collector plates and electrodes. This consists of suddenly striking the collection surface with this rapping force dislodging the ash. The dislodged particulate falls from the collection surface into hoppers. It is important to design the ESP to minimize particle re-entrainment. The hoppers are periodically emptied by means of vacuum, pressurized and mechanical ash removal systems. The balance of the ESP includes the steel enclosure plus inlet and outlet flue transitions with internal flow distribution devices to provide the uniform gas velocities necessary for effective operation. Electrostatic precipitators can be designed (or sized) to meet virtually all particulate control requirements. Several factors affect ESP sizing include: Fuel and ash characteristics - The fuel and ash constituents which are favorable to ash collection and reduce equipment size include moisture, sulfur, sodium and potassium. Constituents which hamper ash collection and increase equipment size, include calcium, silicon, and magnesium. Operating conditions - Gas temperature has a direct effect on the ability of the fly ash particles to accept and hold a charge as well as on the flue gas volume passing through the ESP. ESPs have two optimum operating temperature ranges (below 300F and above 600F). However, experience has generally indicated that operation in the higher range results in disappointing performance due to complications from other factors. Gas flow has a direct effect on sizing. There is an optimum gas velocity range within an ESP for maximum performance. Maximum ESP efficiency is achieved when the gas flow is distributed uniformly across the unit cross section. Particle size and loading - In addition to the quantity of particulate sent to the precipitator, particle size also affects ESP design and performance. An ESP is less efficient for smaller particles (less than 2 microns) than for larger ones. Therefore, ESP applications with a high percentage of particles less than 2 microns will require more collection surface and/or lower gas velocities to achieve low outlet emissions. ESP s represent the most mature particulate control technology available today and have been the workhorse of the available technologies for the boiler applications for the last thirty years. Internationally the ESP has also been the particulate collector of choice. Advantages of the well designed ESP are high total collection efficiency, high reliability, low flue gas pressure loss, resistance to moisture and temperature upsets and low maintenance. Environmental Performance. An ESP is designed to meet a specified particulate collection efficiency. To meet the particulate control regulations and considering the resulting high collection efficiency, special attention must be given to details of precipitator sizing and design. The result is a collector which can be consistently operated to meet the outlet emissions requirements. Operating collection efficiencies which exceed 99.5% are common on the medium and higher ash coals with outlet emissions levels of 0.01 to 0.03 lb/10 6 Btu heat input common on all coals. Specific collection areas of ft 2 per 1000 acfm or higher are typically required to achieve this level of removal efficiency. A change in fuel, a boiler upgrade, a change in regulation or performance deterioration may result in precipitator performance deterioration. Enhancement techniques are available to return the ESP close to the original design performance. These include additional collection surface, gas conditioning, improved flow distribution, control upgrades and internals replacement. Gas conditioning alters resistivity and other ash characteristics by adding sulfur trioxide (SO 3 ), ammonia, moisture or sodium compounds while the other modifications involve only mechanical hardware changes. Commercial Impact. Overall, ESPs have been the collection device of choice for many applications. High removal efficiencies are possible and the units are rugged and relatively insensitive to operating upsets. They represent by far the largest segment of the boiler system particulate collection market. However, where low sulfur coal or dry scrubbing are used to minimize SO 2 emissions, ESPs may become larger and less cost effective compared to baghouses. In the dry scrubbing process, they are also not as effective in enhancing SO 2 removal and sorbent utilization. Fabric Filters/Baghouses Technology Description. A fabric filter, or baghouse, collects the dry particulate matter as the cooled flue gas passes Babcock & Wilcox 7

8 through a filter material. The fabric filter is comprised of a multiple compartment enclosure with each compartment containing up to several thousand long, vertically supported, small diameter fabric bags. The gas passes through the porous bag material which separates the particulate from the flue gas. An inlet plenum distributes the gas to each of the compartments for cleaning. An outlet plenum collects the cleaned flue gas from each compartment and directs it toward the induced draft fan. Inlet and outlet dampers allow isolation of each compartment for bag cleaning and maintenance. Each compartment has a hopper for inlet gas flow as well as for particulate collection and removal by conventional equipment. The individual bags are closed at one end and connected to a tubesheet at the other end to permit the gas to pass through the bag assembly. The layer of dust accumulating on the bag is usually referred to as the dustcake. Particulate collection takes place through impingement by either direct contact or impaction and dustcake sieving. Minor forces which assist in the collection are diffusion, electrostatic forces, London-van der Waal s forces and gravity. Once formed, the dustcake and not the filter bag material provides most of the filtration. The bags must be cleaned periodically to maintain pressure drop within acceptable limits and remove the particulate although a residual dust layer is maintained to enhance collection efficiency. Each compartment is cleaned sequentially. A key design parameter is the air or gas flow rate to cloth area ratio (or A/C ratio) which is set to: 1) minimize unit size and cost, 2) provide reasonable periods between cleaning cycles, and 3) optimize bag replacement life. The three most common bag cleaning methods include: reverse air, shake deflate and pulse jet. The cleaning method also determines the relative size by the A/C ratio and the filtering side of the bag. Both the reverse air and the shake deflate are inside-the-bag filters with gas flow from inside the bag to outside; the pulse jet is an outside-the-bag filter with the flow from outside to inside. The tubesheet on the inside-bag filtering is located below the bags and for pulse jet the tubesheet is above the bags. Substantial research and development on bags and their materials has taken place to lengthen their life and to select bags for various applications. The flexing action during cleaning is the major factor affecting bag life. Bag blinding, which occurs when small particulate becomes trapped in the fabric interstices, limits bag life by causing excessive pressure drop in the flue gas. Finishes on the bag surface are also used to make some bags more acid resistant and to improve cleaning. The most common bag material in coal-fired units with reverse fabric filters is woven fiberglass. Typical bag size is 12 in. diameter with a length of 30 to 36 ft. Bag life of three to five years is common. The shake deflate filters also use mostly fiberglass bags. On both of these units the fiberglass bag is fastened at the bottom to a thimble in the tubesheet. At the top, a metal cap is sown into the bag and the bag has a spring loaded support for the reverse air filters. The upper operating temperature limit is 500F for most fiberglass bags. In addition to fiberglass, the pulse jet filters commonly use the advanced synthetic materials. Advantages of the synthetic materials include better abrasion resistance and resistance to acid attack. Disadvantages include higher cost and limited temperature capabilities. For the pulse jet filters, the typical bag size is 5 or 6 in. diameter with a length of 10 to 20 ft. The key parameters that determine effective fabric filter performance are: air/cloth ratio, pressure drop control, cleanability, filtercloth performance, dustcake properties, bag life considerations, and flue gas properties. While not as popular as ESP s, there are many coal-fired units in the U.S. Use of the fabric filter became popular during the early and mid 1980s for application on boilers. Pulse-Jet fabric filters have become popular on industrial boiler systems because of their smaller size and lower initial capital cost. Environmental Performance. The operating experience with fabric filters for coal-fired boiler applications has been very encouraging. The filters easily meet the 0.03 lbs/10 6 Btu standards (usually greater than 99.5% removal) required for the new plants built in the 1980s. Operating pressure drops varied between 4 to 8 inches H 2 O. Bag life has improved considerably and 4 year bag life is common today. Even during bag failures, the target compartments could be brought off-line for bag replacement without a need for boiler shut down. Most boilers instituted a flue gas bypass arrangement during start-up to avoid condensation and acid dewpoint attacks on the fabric material. Mechanical Collectors Mechanical dust collectors, often called cyclones or multiclones, have been used extensively to separate large particles from a flue gas stream. The cyclonic flow of gas within the collector and the centrifugal force on the particulate drive the particulate out of the flue gas. Hoppers below the cyclones collect the particulate and feed an ash removal system. The mechanical collector is most effective on particles larger than 10 microns. For smaller particles, the collection efficiency drops considerably below 90%. These collectors have frequently been used for reinjection to improve unit efficiency on stoker firing of coal and oil firing. With stricter emissions regulations, mechanical collectors can no longer be used as the primary control device. However, with the onset of fluidized-bed boilers, there has been a resurgence of mechanical collectors for recirculating the bed material. A high efficiency collector is then used in series with the mechanical one to meet particulate emissions requirements. Multiclones are used on most wood fired boilers as the primary collection means producing baseline emissions of 0.45 to 0.6 lb/million Btu. Advanced and Combined Systems A number of advanced emissions control systems are under development with a focus on minimizing total cost and improving removal efficiency. Two of these are LIDS and SNRB. LIDS (Limestone Injection With Dry Scrubbing). A further evolution of the furnace sorbent injection process, this technology combines furnace injection with dry scrubbing technology. As shown in Figure 8, finely ground limestone is injected into the high-temperature portion of the upper boiler. The high temperatures present at this point calcine the limestone into reactive lime. This material is carried through to the particulate collector where it is removed from the flue gas. The collected material, which consists of powdered unreacted lime, reacted material, and flyash, is slurried and sprayed into a simple dry scrubber ahead of the particulate collector. SO 2 is removed in the boiler, dry scrubber and fabric filter. The furnace injection reduces the cost of scrubbing by: 1) permitting the use of limestone instead of more expensive lime and 2) reducing the SO 2 concentration entering the dry scrubber through furnace in-furnace SO 2 removal which permits the LIDS 8 Babcock & Wilcox

9 Boiler Figure 8 LIDS Limestone Injection with Dry Scrubbing. process to be applied to units firing high sulfur coal. In addition to SO 2 and particulate removal, air toxics control is also addressed. Pilot scale testing of the fully integrated LIDS system [10,11] has indicated that the combined SO 2 removal efficiency over 90% downstream of the baghouse (approaching 98% under some conditions). Pilot tests have also indicated relatively high removal of mercury on the order of 90% over the entire system. Benefits of this system include the use of inexpensive limestone in place of the lime found in most dry scrubbers, high removal efficiency and the production of a dry by-product ready for disposal. SNRB. SO x - -Rox Box or SNRB technology is an advanced pollution control system for the combined removal of SO 2,, and particulate in a single high temperature fabric filter. As shown in Figure 9, the process combines three technologies: Dry sorbent injection for SO 2 control Selective catalytic reduction of Fabric filtration for particulate control This post combustion technology is integrated into a power plant or fired process between the combustion zone and the downstream heat recovery typically between the boiler economizer and the air heater. High Temperature Ceramic Bag Inlet Flue Gas SO x Particulates Coal Limestone Receiving & Preparation Air Heater 1. Furnace Limestone Injection & Calcination Recycle System Dry Scrubber Reactor Water Alkali Injection Ammonia Injection 2. Dry SO x Removal Particulate Collector 3. Recycle Calcined Limestone Flyash & Spent Sorbent Clean Flue Gas Alkali Rich Ash Catalyst Figure 9 SNRB process schematic combined SO 2, and particulate control. Ash To Waste Disposal Stack The SNRB process includes operation of a pulse-jet baghouse at high temperatures which require that the filter bag material to withstand exposure to temperatures as high as 900F, while maintaining high particle collection efficiency and flexibility. SO 2 removal is accomplished by using either a calcium or sodium based sorbent (depending upon location and cost) which is injected into the hot flue gas stream downstream of the economizer. Initial SO 2 capture takes place as the sorbent is transported through the system to the filter bag, and final absorption occurs as the flue gas passes through the sorbent/ash/spent-sorbent filter-cake on the bag surface. SO 2 removal efficiencies of 85-90% have been obtained with hydrated lime sorbent injection and as high as 92-95% with sodium bicarbonate. removal occurs by injection of ammonia into the hot flue gas upstream of the baghouse and reaction of the ammonia with the in the presence of a zeolite catalyst inside the bags (and away from the SO 2 and particulate) to form water vapor and nitrogen. Removal efficiencies up to 95% have been achieved. Particulate emissions from the high temperature bags have been consistently below the 0.03 lb/million Btu during testing on a 5 MW e coal-fired pilot. [12] Key features of this technology include: 1) multiple emissions removed in a single component, 2) small plan area, 3) operational simplicity, 4) ability to implement in stages, 5) enhanced SCR operation and catalyst life and 6) dry materials handling. Hazardous Air Pollutants Framework for HAP Assessment of Coal-Fired Boilers Passage of Title III of the Clean Air Act Amendments (CAAA) of 1990 mandated that the Environmental Protection Agency (EPA) require U.S. industrial facilities (except electrical utility plants) which emit more than 10 tons per year of any one or 25 tons per year of any combination of 189 specified hazardous air pollutants (HAPs) to apply maximum achievable control technology (MACT). [13] Determination of the risks and implications of HAPs from steam generating units is an extremely difficult and complex task. The combination of the circumstances which influence the impact of HAP emissions is multifaceted including a wide range of creation mechanisms, the transportation and fate in the atmosphere, and the effectiveness of existing emission control technologies. A particularly challenging problem is the accurate, reliable, and repeatable measurements of HAPs in the extremely low concentrations found in flue gas from boiler systems. HAPs consist, by definition, of 189 trace metals, organic compounds, and inorganic compounds as detailed in Reference 13. The elements which can lead to HAPs are present in virtually all fuels and are released or created during the combustion process. The quantity released will be dependent upon the asfired fuel chemistry, combustion process, combustion equipment, and emissions control technology. Depending upon the combustion process, the elements are released as gases, liquids, or solids. System operating conditions such as reducing/oxidizing environment, gas-phase composition, temperature, and pressure influence how the HAPs are partitioned through the system. Of particular importance for postcombustion control technologies is the volatility of the elements or compounds. Elements/compounds with low volatility (examples include thorium (Th) and scandium (Sc)) are relatively evenly dispersed as sol- Babcock & Wilcox 9

10 ids throughout the boiler bottom ash or flyash. A second class (Class II) of elements and compounds are vaporized as part of the high-temperature combustion but are condensed during their passage through the boiler system (examples include chromium (Cr), nickel (Ni), arsenic (As), cadmium (Cd), lead (Pb), and zinc (Zn)). The HAPs in this class tend to show increasing enrichment with declining particle size. Finally, a third class (Class III) of elements are vaporized during combustion and remain in the vapor phase through the system. Examples include mercury (Hg), selenium (Se), fluorine (Fl), and chlorine (Cl). HAPs found in flue gas are typically measured in parts per billion (ppb) or parts per trillion (ppt). These levels compare to hundreds and thousands of parts per million (ppm) for currently regulated SO 2 and. The exact form and chemistry leading to various emissions is not well understood for many of the HAPs mercury, for example. These factors have led to large uncertainty and inconsistencies in historical data. [14] Table 3 provides preliminary DOE emission factors based upon six of the eight coal fired boiler sites in their study. [3] Performance of Existing Boiler Emissions Control Systems Final hazardous air pollutant emissions can potentially be reduced as the elements and compounds pass through the power system. While the details of recovery by equipment type and HAP specie have not yet been fully defined, a general picture is emerging. The degree of reduction depends upon species to be controlled, the power plant design, and the environmental equipment employed. Table 4 provides a range of possible emission reductions for four representative elements as they pass through a sample boiler system burning Pittsburgh seam bituminous coal. [15] Coal Cleaning. HAPs which are extraneous in nature and are not chemically bound to the coal carbon matrix (especially trace metals) can generally be reduced to some level by coal cleaning depending upon the cost and the acceptable amount of coal rejected in the refuse. Coal cleaning typically involves initial size reduction, screening, removal of foreign material, and some form of washing. Besides the trace metals which are removed as part of this process, washing can also remove some of the soluble compounds such as chlorides. Particulate Control Electrostatic Precipitators and Fabric Filters. Results indicate that particulate control systems significantly reduce the levels of many heavy metals in the flue gas streams. Some metals, including arsenic, cadmium, chromium, lead, and nickel can be removed with greater than 90% efficiency. The measurement data also indicate that fabric filters can achieve reductions of over 99% for such heavy metals as arsenic. [15] The notable exceptions are mercury and selenium. A key performance parameter is the species volatility. More volatile species such as mercury tend to remain in a vapor phase and pass through the ESP or the baghouse. Table 3 Emission Factor Ranges for Trace Metals and Selected Organics From the DOE Coal-Fired Power Plant Program [3] Trace Metals (lbs/10 12 Btu) Trace Organics (lbs/10 12 Btu) Metal DOE Ref 14 Organic DOE Ref 14 Antimony < N/A Benzene N/A Arsenic <1-860 Toluene N/A Beryllium < <1-32 Naphtalene < a/ Cadmium < Anthracene (3.0-20) 10-3 a/ Chromium < Phenanthrene (2.0-31) 10-2 a/ Cobalt > N/A Pyrene (3.0-40) 10-3 a- Lead N/A Benzo(a)pyrene (2.0-12) 10-4 a- Manganese Formaldehyde Mercury Butanone N/A Nickel ,3,7,8-TCDD (8.1-25) 10-7 Selenium < N/A 2,3,7,8-TCDF ( ) 10-7 N/A The literature data are classified as Polycyclic Organic Matter and range from 0.03 to 565 lbs/10 12 Btu. Table 4 General Emission Reductions of Four Representative Trace Elements in a Typical 500 MW e Boiler System Burning Pittsburgh-Seam Bituminous Coal With Average Chemical Species Concentrations [15] Reduction in Emissions Chemical Raw Coal Emission Rate Coal Washing Boiler ESP/Fabric Filter FGD % Emitted Arsenic lb/hr 65-75% 0-2% 85-99% 0-20% 0-5% Chromium lb/hr 30-75% 3-20% 85-99% 0-20% 0-2% Mercury lb/hr 30-40% 0% 0-60% 10-90% 5-95% Selenium lb/hr 25-50% 0-5% 10-80% 0-50% 20-80% 10 Babcock & Wilcox

11 Flue Gas Desulfurization Wet and Dry Scrubbers. The scrubber systems themselves are relatively poor particulate collection devices, thus are not viewed as primary devices for collection of solid phase HAPs (most trace metals and nonvolatile organics) from boiler systems. However, wet and dry FGD scrubbers also offer the potential to control vapor-phase HAPs. Scrubbers can be effective in controlling chlorine emissions. [15] 95% of the chlorine is released as vapor phase hydrogen chloride (HCl) during the combustion process and wet or dry FGD systems can potentially achieve over 90% removal by HCl. [15] Dry scrubbers are routinely used to remove HCl from municipal waste combustors energy plants. [1] FGD Systems and Mercury. Mercury is more volatile than the other trace metals and is emitted in relatively small quantities. During combustion and subsequent cooling, some of this mercury reacts with other flue gas constituents to produce a number of compounds, in particular mercuric chloride (HgCl 2 ). Mercury removal in wet FGD systems has been reported to be 10-90%. Emerging Control System Options and Upgrades The effective control of the wide range of HAPs from coalfired boilers has only recently received focused attention and study. A particular challenge is the relatively low concentration of HAPs in the flue gas stream, especially compared to the existing experience on municipal waste combustors where concentrations are substantially higher. Some of the control options under evaluation include: 1) Application of condensing heat exchanger systems to minimize emissions of HAPs. 2) Use of activated carbon filters to collect vaporous HAPs, especially mercury. 3) Injection of activated carbon powder in spray dry/fabric filter systems and boiler/fabric filter systems to reduce mercury emissions 4) Additives for wet and dry FGD systems to improve HAP removal efficiency 5) Optimization of existing particulate and SO 2 control systems to remove more HAPs Application of condensing heat exchanger technology such as the IFGT (Figure 10) system offers the potential to enhance HAP recovery by reducing the flue gas temperature to Heat Recovery Transition Section First Heat Exchanger Stage Figure 10 IFGT process schematic. Second Heat Exchanger Stage Condensate Affluent Mist Eliminator Cooling Particulate/ SO 2 Removal Pump promote HAP condensation while providing wet contact surfaces to promote capture. The condensing heat exchanger also recovers additional waste heat which can be utilized to enhance plant thermal efficiency. The use of activated carbon to remove mercury has shown promise. Activated carbon is currently used on some municipal waste combustion (MWC) facilities in Europe to control mercury emissions. Results from activated carbon injection in MWC systems which also use a spray dryer and fabric filter show an increase from 40-50% removal without carbon injection to 90-95% with injection. [15] Pilot tests of activated carbon injection in conjunction with a pulse-jet fabric filter indicated better than 90% removal. Acknowledgments W. Downs, R.A. McIlroy, K.E. Redinger and D. Tonn contributed material for this paper and their assistance is kindly acknowledged. Reagent Babcock & Wilcox 11