Air Quality Control System Choices for U.S. Utility Power Plants

Technical Paper BR-1900 Air Quality Control System Choices for U.S. Utility Power Plants Authors: G.T. Bielawski M.J. Schmeida N.T. White Babcock & Wilcox Power Generation Group, Inc. Barberton, Ohio, U.S.A. Presented to: Power-Gen International Date: November 12-14, 2013 Location: Orlando, Florida, U.S.A.

Air Quality Control System Choices for U.S. Utility Power Plants G.T. Bielawski, M.J. Schmeida, and N.T. White Babcock & Wilcox Power Generation Group, Inc., Barberton, Ohio, U.S.A. BR-1900 Presented to: Power-Gen International November 12-14, 2013 Orlando, Florida, U.S.A. Abstract Selection criteria for coal-fired utility power plant air quality control system (AQCS) equipment for SO 2, SO 3 (H 2 SO 4 ), HCl, NO x, particulate, and mercury emissions control has always been the subject of varied opinions. For example, SO 2 can be controlled by a wet flue gas desulfurization (FGD) system, spray dryer absorber FGD, circulating dry scrubber FGD, or dry sorbent injection. Wet FGD was the traditional choice for high sulfur fuels with high SO 2 removal requirements, but now additional factors such as wastewater treatment and mercury control are having a major influence on the type of FGD system that is selected. This paper provides a high-level survey of the types of AQCS equipment currently in service or under construction at utility power plants in the United States (U.S.). Tables and charts are presented showing the entire population of U.S. coal-fired power plants and the types of AQCS equipment as a percentage of total installed capacity. The factors that have lead to those decisions are discussed as well as the factors that will likely affect AQCS equipment selection in the future. Environmental regulations continue to evolve. Once regulations are clarified, utilities can proceed with more certainty to upgrade their existing AQCS equipment and/or add additional equipment. Air Quality Control System Choices for U.S. Utility Power Plants Page 1

Regulatory Drivers The utility industry in the U.S. has been faced with a barrage of regulatory-related acronyms: CAA, CAIR, CATR, CSAPR, CAVR, BACT, PSD, MACT, MATS, NAAQS, NSR, SIP, FIP, CCR, ELG, and others. There have been numerous changes in regulatory direction, and the industry has been seeking clarity and stability for many years. This diverse set of regulatory actions related to air pollution control sparked considerable innovation in the development of technologies for utility power plants and other industries. There are several technologies available to control each pollutant. The primary pollutants of interest are sulfur dioxide (SO 2 ), sulfur trioxide (SO 3 ), sulfuric acid (H 2 SO 4 ) mist, hydrogen chloride (HCl), nitrogen oxides (NO x ), particulate, and mercury. Hazardous air pollutants (HAPS), including selenium, are also of interest. Specific equipment was at one time considered to be employed to control a particular pollutant, such as installing a wet flue gas desulfurization system (wet FGD) to control SO 2. Today, wet FGD systems are considered part of an overall strategy to control particulate, mercury and other acid gases, such as HCl. In fact, the various technologies utilized in the air quality control system (AQCS) are looked at holistically to achieve the required levels of control. Thus, a utility plant owner today, trying to make the best choice for their new or upgraded AQCS, is faced with a considerable challenge. Fuel In addition to regulations, fuel is another important factor that impacts the choice of technologies used in an AQCS. The use of low sulfur Powder River Basin (PRB) coal has steadily increased (Figure 1). Initially, PRB was primarily utilized in the western states, frequently close to the mines. Today, there has been a steady penetration of PRB use across the U.S., with PRB now being an important part of the fuel mix for even eastern utilities, despite the additional transportation costs. But as PRB use has grown, so has the requirement of many utilities to assure that their fleet is flexible in the types of fuel that can be used. Each fuel source has its own set of challenges for the boiler and the AQCS. For example, SCR catalyst poisoning can occur from the phosphorus found in PRB coal and the arsenic found in some eastern coals. In addition, the impact of the current low price of natural gas, as well as alternative sources of power generation, drive the need to reduce the cost of coal-fired power generation. Terms such as fuel flexibility and opportunity fuels are now commonly used. Air Quality Control System Choices for U.S. Utility Power Plants Page 2

Figure 1: Electric Utility Coal Demand by Coal Type Utility Demand for Coal 2007 2013 % of Total Demand by Coal Type (est.) Central Appalachia 16.1% 7.4% Northern Appalachia 10.7% 11.0% Illinois Basin 7.6% 11.7% Powder River Basin 43.7% 49.8% Other 21.9% 20.1% United States 100.0% 100.0% USA Utility Demand of Coal (Millions of tons) 1,045 901 Source: IHS CERA 500 Wyoming Coal Production 1995-2011 450 400 350 300 250 200 Source: U.S. Energy Information Administration Air Quality Control System Choices for U.S. Utility Power Plants Page 3

AQCS Equipment in Service SO 2 Control The widespread implementation of FGD first began in the U.S. in the 1970s. In the late 1980s, FGD technology saw widespread implementation in Europe, and then beginning in the early 2000s, in China. In the past, wet FGD was favored when the control efficiency for SO 2 was required to be 90% or greater for either high sulfur or lower sulfur coals. Today, wet FGDs are typically designed to achieve 98% or more SO 2 removal with high sulfur coal. The first dry FGD systems that were widely available in the 1980s were of the spray dryer absorber (SDA) type. These SDA systems were used for lower SO 2 removal requirements, typically 70 to 85%, on lower sulfur coals. Today, with better understanding of SDA technology and advanced control systems, some that even employ intelligent control, SDA systems can reliably achieve greater than 96% SO 2 removal on lower sulfur fuels. In addition to the SDA dry FGD, circulating fluid bed FGD systems, commonly referred to as circulating dry scrubbers (CDS) are now widely being implemented in the U.S., primarily on units less than 400 MW. CDS technology is capable of up to 96 to 98% SO 2 removal efficiency on medium and higher sulfur fuels, but a CDS dry FGD system typically uses 20% more lime than an SDA system for the same inlet SO 2 loading and SO 2 removal. Since there has been widespread adoption of PRB fuel and fuel blending, if a utility s fuel choices in the future do not include burning solely high sulfur eastern coal, dry FGD systems utilizing SDA technology will likely have a lower life cycle cost than systems utilizing CDS technology. Dry FGD systems, either SDA or CDS, also achieve high levels of removal of other acid gases and toxics. When coupled with the fabric filter, dry FGD systems also achieve very low particulate emissions. The pending Effluent Limitation Guidelines (ELG) have pushed the desire to eliminate any wastewater. This, in combination with impacts of fuel blending, has resulted in almost all new FGD selections being dry systems of either the SDA or CDS type. Utilities with existing wet FGD systems are also looking into implementing a zero liquid discharge (ZLD) approach through additional technology such as evaporation and crystallization. With the head start in the 1970 s, the U.S. was well ahead of the rest of the world in the adoption of FGD technology. By 1998, the U.S. had 99 GW of installed FGD capacity, and the rest of the world had only a combined 128 GW. 1 By 2011, many countries had surpassed the U.S. in the utilization of FGD. In the U.S. 204 GW (61%) of coal-fired generation was equipped with FGD systems and 130 GW (39%) was not controlled. This compares with other countries as shown in Figure 2. Air Quality Control System Choices for U.S. Utility Power Plants Page 4

Figure 2: Percent of Total Coal-fired Generating Capacity with FGD in 2011 2011 Total Coal- Fired Capacity (GW) Total Coal- Fired Capacity with FGD (GW) Percent of Coal with FGD Germany 82.7 72.2 87% Turkey 13.3 9.5 71% China 758.3 503.3 66% United States 333.7 204.4 61% Poland 35.6 20.6 58% World 1,988.6 1,003.4 50% Source: McIlvaine Company 100% Percent of Total Coal-Fired Generating Capacity with FGD 2011 87% 80% 60% 71% 66% 61% 58% 50% 40% 20% 0% Germany Turkey China United States Poland World Source: McIlvaine Company Air Quality Control System Choices for U.S. Utility Power Plants Page 5

In the U.S. in 2012, there was approximately 324 GW of coal-fired generation in operation. With the announced retirement of a number of coal-fired units, it is projected that 297 GW of coal-fired generation will be operating in the U.S. in 2016. Reduction in coal-fired generating capacity is the result of utilities retiring units that are no longer economically viable when faced with the retrofit costs to comply with new and future regulations, among other factors. Coal, however, will maintain an important role in electric power generation, as fuel diversity is a key for any country that seeks to maintain its competitive position as a supplier to the global economy. The population of FGD systems in the U.S. in 2012 is shown in Figure 3 by type of system. The category of dry FGD systems includes both SDA and CDS and its variants. Dry sorbent injection (DSI) is another technology that can be used when SO 2 removal efficiency requirements are low. Many new FGD systems have been announced or are already under construction, and the expected population of FGD systems in 2016 is also shown in Figure 3. Figure 3 shows that, based on current announcements, approximately 68 GW of coal-fired units in the U.S. will not have an FGD system in 2016. Note that the category CFB Boiler in Figure 3 includes those units for which the boiler is a circulating fluidized-bed boiler with no SO 2 controls other than the limestone that may be used in the CFB boiler s bed material. If an FGD or DSI system is also used with a CFB boiler, those FGD and DSI systems are included in their respective categories. Air Quality Control System Choices for U.S. Utility Power Plants Page 6

Figure 3: SO 2 Control Implementation U.S. Coal-Fired Electric Generating Units Greater than 50 MW SO 2 Controls in 2012 Total Units Total GW % of Total GW Wet FGD 349 178.2 54.9% Dry FGD 87 30.1 9.3% DSI 7 1.3 0.4% Controlled Total 443 209.6 64.6% CFB Boiler 28 3.5 1.1% None 408 111.4 34.3% Grand Total 879 324.5 100.0% *Source Platts UDI World Electric Power Producers Database, IHS CERA, U.S. Environmental Protection Agency, McCoy Power Reports, Babcock & Wilcox Market Research U.S. Coal-Fired Electric Generating Units Greater than 50 MW SO 2 Controls in 2016 (Projected) Total Units Total GW % of Total GW Wet FGD 337 177.9 59.8% Dry FGD 118 42.6 14.3% DSI 12 4.9 1.7% Controlled Total 467 225.4 75.8% CFB Boiler 28 3.5 1.2% None 246 68.4 23.0% Grand Total 741 297.3 100.0% *Source Platts UDI World Electric Power Producers Database, IHS CERA, U.S. Environmental Protection Agency, McCoy Power Reports, Babcock & Wilcox Market Research Air Quality Control System Choices for U.S. Utility Power Plants Page 7

SO 2 Control 2012 SO 2 Control 2016 Scrubbed 64.6% Scrubbed 75.8% No FGD 35.4% No FGD 24.2% Total Coal-fired 324 GW; Scrubbed 210 GW DSI is included in scrubbed total Total Coal-fired: 297 GW; Scrubbed 225 GW DSI is included in scrubbed total SO 2 Control 2012 SO 2 Control 2016 WET FGD 54.9% DRY FGD 9.3% DSI 0.4% WET FGD 59.8% DRY FGD 14.3% DSI 1.7% No FGD 35.4% No FGD 24.2% Total Scrubbed: 210 GW Total Scrubbed: 225 GW SO 2 Control 2012 SO 2 Control 2016 DRY FGD 14.4% DRY FGD 18.9% DSI 0.6% DSI 2.2% WET FGD 85.0% WET FGD 78.9% Total Scrubbed: 210 GW Total Scrubbed: 225 GW Air Quality Control System Choices for U.S. Utility Power Plants Page 8

Estimates for additional coal unit retirements beyond 2016 are in the range of 20 to 30 GW through 2030. Assuming that the retirements will primarily include units that do not have an existing FGD, this leaves 38 to 48 GW that will likely be adding FGD systems at some point in the future. Potential choices of technologies for these remaining units that have yet to be controlled are discussed later in this paper. In the earlier years of FGD, there was some use of advanced scrubbing technologies that produced salable byproducts, such as sulfur, sulfuric acid, or fertilizer, but the vast majority of FGD systems in operation today utilize wet limestone technology. There are also a number of wet FGD systems designed to use lime as the reagent, but they were generally installed before 1995. With the Mercury and Air Toxics Standards (MATS), pending Effluent Limitation Guidelines (ELG), and solid waste disposal regulations, the factors that guide the choice of the type of FGD systems for the coal-fired capacity that has yet to be controlled will certainly be different than those that guided past decisions. In addition, many of the FGD systems in service today were installed up to 40 years ago. These existing systems were installed at a time when removal requirements were less stringent. Many of these systems have received upgrades over the years, particularly to improve reliability and reduce maintenance. Nonetheless, many of these systems will require additional modifications to meet as yet to be promulgated regulations. Complete replacement of first generation FGD systems is also a possibility, and has already happened at a few sites. Dry sorbent injection can also be used for SO 2 control, but the primary use of DSI in the past has been the control of SO 3, also referred to as sulfuric acid mist (H 2 SO 4 ), typically for units that utilize higher sulfur coals equipped with a selective catalytic reduction (SCR) system, electrostatic precipitator (ESP) and wet FGD. There is also some use of DSI for HCl control for MATS compliance. Whereas DSI for SO 3 and HCl control frequently utilizes hydrated lime as the reagent, more reactive sodium reagents (trona or sodium bicarbonate) are needed for SO 2 control, and typically a maximum of 70% SO 2 removal is targeted. To achieve 70% SO 2 removal, a stoichiometric ratio of 1.5 is typically needed for the most reactive of the sodium reagents (milled trona), and the cost of the sodium reagents is high. The sodium compounds are also soluble and have a high ph, so the resulting ash contains these soluble sodium compounds, and the high ph is known to increase the solubility of heavy metals from the ash. Thus the leaching of the soluble sodium compounds and heavy metals from the ash is an issue that must be considered in ash disposal systems. In addition to the need to reduce sulfuric acid mist to control the visible blue stack plume, SO 3 control is also utilized upstream of activated carbon injection. The SO 3 can poison activated carbon by taking up the active sites on the activated carbon that otherwise would be available to remove mercury. Air Quality Control System Choices for U.S. Utility Power Plants Page 9

Particulate Control Dry electrostatic precipitators (ESP) have historically been used to control particulate emissions from coal-fired boilers. Most of these precipitators were installed in the 1970s and 1980s in a cold-side configuration, as they are located downstream of the air heater. In some cases, the ESP was located upstream of the air heater in a hotside configuration, normally to address low sulfur applications that have high ash restivity at lower temperatures. Many original hot-side precipitators have since been rebuilt with modern ESP technology, converted into cold-side ESPs, or replaced by fabric filters. The implementation of hot-side precipitators is a good example of the utility industry adopting a new, seemingly better, technology before it was fully proven. Most utilities will continue operating existing ESPs as part of a MATS compliance plan. However, in some cases, the plans also include improving the ESP performance by increasing collecting area or improving migration velocity (how fast the charged ash particle moves toward the collecting surface). Additionally, many owners are performing repairs to improve mechanical reliability due to neglect in the past. Options to increase collecting area can include: 1) rebuilding the ESP with taller collecting plates, 2) adding an additional field in the direction of gas flow, and 3) adding an additional chamber perpendicular to gas flow. The options to increase migration velocity can include: 1) replacing or upgrading the ESP control system, 2) replacing and/or increasing the size of power supplies, 3) upgrading to or adding high frequency power supplies or three-phase power supplies, and 4) increasing sectionalization of the high voltage configuration. If there is an existing wet FGD system following the ESP that is to be upgraded, new high performance mist eliminators are available for the existing wet FGD system to increase fine particulate capture. If a new FGD system is being added to a boiler, it will most likely be a dry FGD. In this case, a new fabric filter will almost certainly be part of the dry FGD system. An existing ESP may then be used as a primary particulate collector, such that the majority of the flyash can still be sold for beneficial use, or the ESP can be deactivated, bypassed or dismantled. Prior to the advent of SDA technology, fabric filters (also called baghouses) saw very few applications in the utility industry. The first fabric filters that were employed were of the reverse gas type, in which the dust is dislodged from the filter bag by passing clean flue gas in reverse through the fabric filter media. Later, pulsejet fabric filters (PJFF), which were already proven on industrial applications, came to be accepted for utility applications. In a PJFF, blow pipes are located immediately above the bags through which short bursts of air are emitted to dislodge the dust from the filter media. Air Quality Control System Choices for U.S. Utility Power Plants Page 10

Fabric filters have also been used upstream of a wet FGD on a few higher sulfur, newer units, usually with lime DSI upstream of the fabric filter. The lime injection is used to protect the bags and other fabric filter internals from SO 3 attack. Other higher sulfur, new coal-fired boilers built within the last 10 years with a wet FGD system have adopted the wet ESP for final particulate removal and acid gas mist control. Wet ESPs follow the wet FGD system, therefore the gas passing through the wet ESP is saturated with water. The collecting surfaces of a wet ESP are washed with water to dislodge the collected particulate matter. The wet ESPs are effective; however, similar overall system efficiencies for the pollutants of interest can be obtained at a lower life cycle cost with SDA/CDS with a PJFF or DSI/PJFF/Wet FGD system configurations. Another method of simultaneous particulate and SO 2 removal employed at a few plants in the 1970s was the downflow venturi scrubber followed by an absorber tower. However, the combination of the SO 2 scrubbing byproducts plus the flyash presented erosion and scaling issues. Venturis are also size-selective in particulate removal, that is, much of the submicron fraction of the flyash passes through the scrubber. Only a few of these systems are still in service today. The population of each one of these technologies in the current utility coal-fired fleet is shown in Figure 4. Air Quality Control System Choices for U.S. Utility Power Plants Page 11

Figure 4: Particulate Control Equipment Implementation U.S. Coal-Fired Electric Generating Units Greater than 50 MW Particulate Controls in 2012 Total Units Total GW % of Total GW ESP 634 240.5 74.1% Baghouse 192 65.0 20.0% ESP 15 7.5 2.3% and Baghouse Other 38 11.5 3.6% (i.e., venturis) Grand Total 879 324.5 100.0% *Source Platts UDI World Electric Power Producers Database, IHS CERA, U.S. Environmental Protection Agency, McCoy Power Reports, Babcock & Wilcox Market Research U.S. Coal-Fired Electric Generating Units Greater than 50 MW Particulate Controls in 2016 (Projected) Total Units Total GW % of Total GW ESP 487 202.6 68.1% Baghouse 203 74.0 24.9% ESP 18 10.0 3.4% and Baghouse Other 33 10.7 3.6% (i.e., venturis) Grand Total 741 297.3 100.0% *Source Platts UDI World Electric Power Producers Database, IHS CERA, U.S. Environmental Protection Agency, McCoy Power Reports, Babcock & Wilcox Market Research PM Control 2012 PM Control 2016 ESP 74.1% Baghouse 20.0% ESP 68.1% Baghouse 24.9% ESP & Baghouse 2.3% Other 3.6% ESP & Baghouse 3.4% Other 3.6% Air Quality Control System Choices for U.S. Utility Power Plants Page 12

NO x The first technology used to lower NO x emissions is the low NO x burner, sometimes used in combination with two-stage combustion, as any further reduction typically requires the use of ammonia or urea. Each boiler manufacturer has their own version of low NO x burner technology, having gone through multiple iterations to develop the optimized designs that are available today. Further NO x reduction is achievable with two-stage combustion, where less than the total air required for complete combustion is introduced at the burners, with the balance entering through overfire air ports. Beyond combustion controls, additional NO x reduction requires the use of either selective noncatalytic reduction (SNCR) or selective catalytic reduction (SCR). With SNCR, ammonia or urea is injected into a high temperature area of the boiler (typically above 1500 F). The chemical reaction that takes place in the furnace typically provides NO x reduction of 30 to 50% from uncontrolled levels. The level of NO x reduction is frequently limited by the need to maintain low levels of ammonia in the stack gas. The SCR process can typically provide up to 92% NO x reduction of the NOx entering the SCR. In the SCR process, ammonia is added to the flue gas immediately upstream of multiple levels of catalyst in a reactor that is located between the economizer and air heater. SCR catalysts, however, are susceptible to poisoning by various elements frequently found in coal ash, most notably arsenic in some eastern coals and phosphorus in PRB coal, particularly when the PRB is fired with two-stage combustion. In some cases, fuel additives may lessen the impact of these unfavorable fuel constituents on catalyst life. The SCR process also provides some mercury removal benefits, as discussed later in this paper. The current and projected utilization of low NO x burners, SNCR, and SCR on U.S. utility boilers is shown in Figure 5. The other category below includes boilers that utilize only low NO x burners, possibly with the addition of two-stage combustion, as the only means of NO x control. Air Quality Control System Choices for U.S. Utility Power Plants Page 13

Figure 5: NO x Control Implementation U.S. Coal-Fired Electric Generating Units Greater than 50 MW NO x Controls in 2012 Total Units Total GW % of Total GW SCR 257 140.8 43.4% SNCR 97 27.0 8.3% Other 525 156.7 48.3% Grand Total 879 324.5 100.0% *Source Platts UDI World Electric Power Producers Database, IHS CERA, U.S. Environmental Protection Agency, McCoy Power Reports, Babcock & Wilcox Market Research U.S. Coal-Fired Electric Generating Units Greater than 50 MW NO x Controls in 2016 (Projected) Total Units Total GW % of Total GW SCR 268 147.5 49.6% SNCR 86 29.0 9.8% Other 387 120.8 40.6% Grand Total 741 297.3 100.0% *Source Platts UDI World Electric Power Producers Database, IHS CERA, U.S. Environmental Protection Agency, McCoy Power Reports, Babcock & Wilcox Market Research SNCR 8.3% NOx Control 2012 OTHER 48.3% SNCR 9.8% NOx Control 2016 OTHER 40.6% SCR 43.4% SCR 49.6% Air Quality Control System Choices for U.S. Utility Power Plants Page 14

Mercury Mercury control can be achieved by a number of technologies. Activated carbon injection is one technology that is frequently used. However, mercury control can also be achieved by optimizing the other equipment in the AQCS so that as much mercury as possible is removed. Then, activated carbon injection is used only as a trim, if it is needed at all. Mercury exists in the flue gas in both elemental and oxidized forms; the concentration of oxidized mercury in the flue gas is higher when more halogen is present. There is typically a sufficient level of chlorine present in many eastern bituminous coals such that more oxidized mercury is present in the flue gas than elemental mercury. For low chlorine coals, such as PRB, chlorine or bromine is sometimes added in small amounts to oxidize the mercury. Oxidized mercury is readily absorbed in a wet FGD system; elemental mercury is also absorbed in a wet FGD system, but to a lesser degree. Oxidized mercury is also more readily captured than elemental mercury in a dry FGD system. SCR systems provide the added benefit of enhanced mercury oxidation to aid in this capture in the FGD system. Therefore, SCR systems are expected to become an integral part of mercury compliance strategy moving forward, and mercury compliance may play as much of a part in catalyst management strategy as NO x compliance. Bromine injection can also be used to promote mercury oxidation with either a wet or dry FGD system. However, this causes soluble bromine compounds to accumulate in a wet FGD system, with the soluble bromine compounds then present in any wet FGD wastewater. Sulfides in some form are sometimes injected into a wet FGD system to turn the captured oxidized and elemental mercury into highly insoluble and stable mercuric sulfides that are removed with the solids. Data is not readily available on the population of the different types of mercury control technology being employed on coal-fired utility boilers. Air Quality Control System Choices for U.S. Utility Power Plants Page 15

AQCS Equipment Choice Criteria: Looking to the Future Into the foreseeable future, many of the criteria that are factors in AQCS equipment selection today will continue to be the drivers. These include items such as: Proven experience for the intended application Multi-pollutant control Operational flexibility O&M considerations Proven Experience As previously discussed, there are several technologies that are suitable for SO 2, particulate, NO x, and mercury control. However, more stringent emissions regulations, as well as other considerations, may limit the viable technologies. For example, both SDA and CDS dry FGD systems have been proven successful at achieving required SO 2 reductions on PRB fuels. And while CDS has proven successful on medium and some higher sulfur coals, reagent costs have not generally made it an economical choice for higher sulfur fuel applications where wet FGD dominates. Also, although a particular technology may demonstrate effective emissions reductions on a particular fuel, consistent results are necessary to maintain its viability on a long-term basis when considering changes in fuel blends, market conditions and regulatory requirements. In addition to the fuel considerations, unit size is a factor when evaluating a technology. What works well on a smaller unit where a single reactor or module can be utilized may not translate to larger units where multiple modules would be required. There are also emerging technologies that have not been proven in a utility application. Utilities must therefore continue to carefully evaluate use of new technologies to determine if the plant is willing to accept the potential risk involved with unproven technologies. Multi-Pollutant Control Utility coal-fired plants face many challenges to remain viable, so it is critical to evaluate the plant as a whole to take advantage of synergies that exist between equipment and to improve plant efficiency. AQCS technology was previously often selected specifically for the pollutant to be controlled, such as FGD for SO 2, SCR for NO x, and ESP for particulate matter. Many of these systems are also capable of controlling other pollutants, and the capability of a particular technology to control multiple pollutants will continue to be a driver in the selection of a complete AQCS. Air Quality Control System Choices for U.S. Utility Power Plants Page 16

In addition to the ability of a technology to directly control other pollutants, its impact on the ability of other AQCS equipment to control its targeted pollutant(s) must also be considered. For example, a side reaction of an SCR includes the ability of the catalyst to oxidize mercury, which makes it more readily captured in an FGD system. However, an SCR also oxidizes SO 2 to SO 3, which evades capture in a wet FGD system, but not in a dry FGD system. In FGD systems, both SDA and CDS designs are well-known for their ability to control other acid gases, while wet FGD systems often require the addition of DSI systems. The particulate control devices also play an integral role in mercury and acid gas control, with fabric filters permitting much higher removals of these pollutants than ESPs alone. Fabric filters are also integral to SO 2 removal with dry FGD systems, which is a key factor when evaluating an AQCS system as a whole. The tables below illustrate other interactions between the various AQCS components and the interrelationship between pollutants. An effective multi-pollutant control strategy will carefully consider these interrelationships. Post-Combustion Emission Control Technology for Multi-Pollutants Air Emissions Wet FGD Dry FGD DSI SCR SNCR ACI ESP FF Acid gases ❶ ❶ 2 3 3 NO x ❶ ❶ Mercury ❶ ❶ 2 3 3 Particulate matter ❶ ❶ ❶ ❶ This technology directly captures this pollutant or, in the case of NO x, converts it into nitrogen and water 2 This technology captures a gas or an ultra-fine particulate on a readily filterable sorbent 3 This technology filters or precipitates previously injected sorbent laden with the pollutant from the flue gas Source: Adapted from IHS CERA s Post-combustion emission control technology cheat sheet Air Quality Control System Choices for U.S. Utility Power Plants Page 17

Air Emissions NAAQS MATS CAIR, etc Regional Haze Acid gases NO x Mercury PM Source: Adapted from IHS CERA s Post-combustion emission control technology cheat sheet Operational Flexibility Equipment selection must accommodate changing requirements with minimal new equipment or modifications in order for the facility to remain competitive. One aspect of this is fuel flexibility. Switching to lower sulfur fuels such as PRB has permitted some existing facilities to achieve compliance with the installation of less expensive systems such as low NO x burners and DSI rather than installing more expensive systems like SCR and FGD. However, fuel choice is most often driven by cost to improve plant economics. The flexibility of a system to accommodate varying fuels is therefore critical to the continued operation of the plant. In addition, emissions limits are likely to become even more stringent. One can view this as a continuation of the need for fuel flexibility. For example, if the design of a dry FGD system is for a certain emission when burning a 1.0 lb SO 2 per million Btu coal but the plant is required to burn a 1.5 lb SO 2 per million Btu coal, the emissions control system must perform to a higher standard to remove more sulfur. A utility would be best served to install a system that has the capability of meeting more stringent future emissions levels than one that is only designed for the fuel being used at the time of installation. This point is also illustrated by the use of ESPs. This technology served the industry well in the past, and many ESPs will stay in service achieving MATS requirements. However, ESPs are much more sensitive to changing flue gas conditions, flyash composition, and injected sorbents such as activated carbon and lime, than fabric filters, and are not capable of cost effectively achieving the very low emissions levels required for a new unit. These facts, coupled with the expectation of decreased particulate limits and the multi-pollutant capability of fabric filters, make fabric filters the clear path for new installations. Air Quality Control System Choices for U.S. Utility Power Plants Page 18

Fewer and fewer coal-fired units are dispatched at base load. As demand on coal-fired units continues to be more susceptible to cycling, primarily due to the variability of wind and other renewables, coal-fired units will be required to swing from minimum to full load on a regular basis. The ability of the selected technology to follow these load swings with minimal negative impacts will be critical. The efficiency of the equipment at reduced loads and the potential negative impacts to overall system operations must be considered. For example, SDA system turndown is approximately 5:1, and CDS system turndown is approximately 2:1 with no flue gas recirculation. With flue gas recirculation, greater turndown of CDS systems is achievable, but the range varies for each unit. With SDA systems, the conditions match the unit load; that is, pressure drop and power consumption decrease with load. To accommodate reduced load with a CDS, either modules are taken offline, or gas recirculation is utilized, requiring proportionately more power. Low flue gas temperature impacts the ability of both technologies to achieve proper drying. As another example, the design of an SCR system must account for the swings in fuel and boiler load. The primary concern is flue gas temperature as the catalyst cannot typically handle all economizer outlet temperatures throughout the load range. Changes to the convection pass design can regulate the temperature to the SCR. Also of importance with load following is the concern for ash deposition, which can be exacerbated by swings in load. This is another area where the SCR operations cannot be adjusted to accommodate these swings, but the system design can take this into account from the start by evaluating ash flow distribution throughout the load range. These examples illustrate the holistic approach to AQCS design that will continue to play a large role. O&M Considerations AQCS system selection must also carefully consider the operating and maintenance (O&M) impact of the equipment, as well as the impact on other plant systems throughout the life of the plant. The number of personnel that are required to operate and maintain new systems is a critical consideration. For SCR systems or fabric filters, the impact on staffing is relatively minor and is typically covered by existing operations. But for an FGD, this can be a significant additional cost for the plant. Wet FGD systems are certainly the workhorse of the eastern fleet of coal-fired power plants. O&M costs for wet FGD systems are higher than dry FGD systems because there are more moving parts, more wear parts, and chemistry to monitor. On the other Air Quality Control System Choices for U.S. Utility Power Plants Page 19

hand, wet FGD systems accommodate fuels of any sulfur level, adjust to varying boiler loads, and use an inexpensive reagent. However, concerns over waste water treatment and disposal, and the solid byproduct disposal, have some speculating about the future of this technology. Nonetheless, for plants that wish to maintain a high sulfur fuel in their fuel mix, wet FGD is still a viable alternative. Recent advances in system design to make the wet FGD system closed-loop from a water balance standpoint reduce concerns about plant waste water treatment and disposal, and disposal costs for gypsum are no more than that produced from dry FGD systems. Although inherent differences are believed to exist in the reagent required for the various dry systems, pebble lime or hydrated lime can be used for both SDA and CDS systems. For an SDA using pebble lime, a slaker is used on-site. Hydrated lime used for an SDA or CDS system can be delivered to the site or made on site from pebble lime with a hydrator system. Therefore, the choice of pebble lime or hydrated lime should be based only on consumption rates and equipment capital costs. Power and water consumption will also affect technology choice. Power consumption for wet FGD systems is typically higher than for dry FGD systems. Power consumption is comparable for the various dry FGD systems at full load, but lower for an SDA than a CDS at reduced boiler loads. The number of operators required for each system varies. Wet FGD systems require a fair amount of attention. Dry FGD systems require much less attention, with both SDA and CDS systems typically requiring one control room and one area operator, and a share of other plant resources like mechanics and IC&E technicians. However, CDS systems typically require a lesser share of mechanics and IC&E technicians than SDA systems, unless a CDS system includes an on-site hydrator system, which tends to equalize the resources needed. Maintenance costs extend beyond the number of people required to control and maintain the system. It includes the cost and frequency of repairs and wear parts, including the effects on other AQCS equipment. An example of this is the quantity and frequency of fabric filter bag changes associated with SDA and CDS systems, where there are fewer bags with a longer expected life with SDA systems. Bag life expectancies can also affect the maximum length of time between planned boiler outages. Water treatment and byproduct disposal concerns will factor into future equipment selections as effluent and disposal guidelines continue to tighten. Wet FGD systems can be made to be closed loop systems to lessen the impact of water treatment concerns. Dry FGD systems can utilize waste water from other sources, making them ideal where water usage is an issue. Byproduct disposal for all solid wastes from FGD processes is similar, but ash disposal or re-use potential can be impacted by other upstream processes. For example, activated carbon injection often results in too high of Air Quality Control System Choices for U.S. Utility Power Plants Page 20

a carbon content to permit flyash sale. The use of SNCR results in higher residual ammonia in the flyash than with an SCR, which could also impact flyash sales. Conclusion Coal will continue to be an important part of the landscape for U.S. utilities, and there is still a substantial portion of the coal fleet that will require AQCS equipment. AQCS equipment selection will continue to be very complex, requiring considerable analyses by utilities, architect-engineers, and system suppliers working together. The operation of a coal-fired power plant cannot be neatly segmented into packages that discretely control various air pollutants. The plant operations as a whole must be evaluated holistically to arrive at the most economical means of achieving not only air emissions requirements, but also to evaluate the impact on water and solids treatment and disposal requirements. Likewise, air, water and solids disposal regulations are not independent of each other. Clarity and stability of all regulations at the same time would allow utilities to select the most optimum system configurations for their plants. References 1. Srivastava, R., Controlling SO 2 Emissions: A Review of Technologies, U.S. Environmental Protection Agency, November 2000. 2013 by Babcock & Wilcox Power Generation Group, Inc. All rights reserved. No part of this work may be published, translated or reproduced in any form or by any means, or incorporated into any information retrieval system, without the written permission of the copyright holder. Permission requests should be addressed to: Marketing Communications, Babcock & Wilcox Power Generation Group, P.O. Box 351, Barberton, Ohio, U.S.A. 44203-0351. Or, contact us from our Web site at www.babcock.com. Disclaimer Although the information presented in this work is believed to be reliable, this work is published with the understanding that Babcock & Wilcox Power Generation Group, Inc. (B&W PGG) and the authors and contributors to this work are supplying general information and are not attempting to render or provide engineering or professional services. Neither B&W PGG nor any of its employees make any warranty, guarantee or representation, whether expressed or implied, with respect to the accuracy, completeness or usefulness of any information, product, process, method or apparatus discussed in this work, including warranties of merchantability and fitness for a particular or intended purpose. Neither B&W PGG nor any of its officers, directors or employees shall be liable for any losses or damages with respect to or resulting from the use of, or the inability to use, any information, product, process, method or apparatus discussed in this work. Air Quality Control System Choices for U.S. Utility Power Plants Page 21