Inquiry into health impacts of air pollution in Victoria Submission 67 - attachment 2

Performance of (NOX) Emission Controls at U.S. Power Plants

A comparison of combustion and post-combustion control technologies for coal-fired power plants

Jeremy Schreifels （石智锐） 2008380009 PhD Candidate

80050012 ʹ 能源与环境 贺克斌教授 2008 Winter

Ta ble of C onte nt s Abbreviations and Acronyms ...... i Notes ...... i Introduction ...... 1 Health and Environmental Impacts of Nitrogen Oxides ...... 2 Air Quality Standards for and Secondary Pollutants ...... 4 Sources of Nitrogen Oxides Emissions ...... 6 Formation of Nitrogen Oxides Emissions...... 9 Technologies for Reducing or Controlling Nitrogen Oxides ...... 11 Combustion Modification Technologies ...... 12 Post-Combustion Control Technologies ...... 18 Emerging and Advanced Control Technologies ...... 28 Technology Performance and Costs ...... 29 Bibliography ...... 31

Abbreviations and Acronyms

BOFA boosted over-fire air NH4HSO4 ammonium bisulfate BOOS burner out of service NH3 ammonia Btu British thermal units NO nitric ;ϭƚƵуϭ͘ϬϱϱŐŝŐĂũŽƵůĞƐͿ NO2 nitrogen dioxide - CAA US Clean Air Act NO3 nitrate CCOFA close-coupled over-fire air NOX nitrogen oxides CFB circulating fluidized bed NSPS New Source Performance CO monoxide Standards (US Clean Air Act) EPA US Environmental Protection O3 ozone Agency OFA over-fire air ESP electrostatic precipitator OH hydroxyl radical FGD flue gas desulfurization PM2.5 fine particles (particulate GW gigawatt matter smaller than 2.5 H2SO4 sulfuric acid microns) HCN cyanide ROFA rotating opposed fire air HNCO isocyanic acid SCR selective catalytic reduction HNO2 nitrous acid SNCR selective non-catalytic HNO3 nitric acid reduction LNB low-NOX burner SO2 dioxide - LOI loss-on-ignition SO3 MW megawatt SOFA separated over-fire air NAAQS US National Ambient Air UBC unburned carbon Quality Standards US United States NCO isocyanate WHO World Health Organization (NH4)2SO4 ammonium sulfate

Notes 1. All monetary figures are in 2007 US dollars unless otherwise noted. Inflators were based on CPI available at http://oregonstate.edu/cla/polisci/faculty- research/sahr/cv2007rsx1.pdf. 2. All measurements are in metric units (i.e., metric tons) unless otherwise noted. 3. NOX emission data ranges (e.g., minimum and maximum) and quartiles for specific coal-fired electric power plants , boiler categories, and control technologies are based on the 5st and 95th percentile unless otherwise noted. This was done to eliminate outliers͕͞ƐƵďƐƚŝƚƵƚĞ͟ĞŵŝƐƐŝŽŶĚĂƚĂƚŚĂƚƉƵƌƉŽƐĞůLJŽǀĞƌĞƐƚŝŵĂƚĞƐĂĐƚƵĂůĞŵŝƐƐŝŽŶƐ͕ start-up and shutdown periods, and out-of-range data.

i Introduction

Nitrogen oxides (NOX) in the atmosphere contribute to a number of environmental issues that can have significant impacts on human health and the environment. As the science of atmospheric chemistry, air quality management, and epidemiology improves our understanding of the impacts of NOX and secondary pollutants related to NOX, national and local governments are implementing regulations and policies to reduce NOX emissions from key sectors and emission sources. For these regulations to be effective, policymakers must understand the extent of the problem and the potential solutions. The following questions are therefore important to ensure that the problems are resolved efficiently and effectively:

x What are the human health and environmental impacts of NOX emissions and secondary pollutants?

x What are the pathways by which NOX emissions and secondary pollutants are formed and transported?

x What are the sources of NOX emissions that contribute to the problem?

x What levels of NOX reductions are necessary to address the human health and environmental challenges?

x What technologies and practices are (or will be) commercially available to reduce NOX? x What are the costs of these technologies and practices? x What are the impacts of these technologies and practices on the operations of power plants and industrial facilities?

This paper briefly addresses these questions, with an emphasis on assessing the real-world effectiveness of commercially-available NOX emission control technologies in the United States (US). In particular, this paper focuses on combustion modifications and post-combustion NOX control technologies commonly installed at US coal-fired electric power plants. These facilities are the largest stationary sources of NOX emissions in the US and they have more than a decade of experience with advanced NOX controls.

This paper is organized into five sections.

1. Health and environmental impacts of NOX explores the human health and environmental effects of nitrogen dioxide (NO2) and secondary pollutants formed from NOX.

2. Air quality standards highlights US national ambient air quality standards for nitrogen dioxide (NO2), fine particles (PM2.5), and ozone (O3) and air quality levels across the US. 3. Source of NOX emissions provides details on NOX emissions from different source categories including coal-fired electric power plants and the policies implemented to control those emissions.

4. Formation of NOX emissions describes the formation of NOX during coal combustion and opportunities for reducing its formation. 5. Technologies for controlling NOX describes primary (i.e., combustion) controls for reducing NOX

formation and secondary (i.e., post-combustion) controls for removing NOX from flue gas. Each of these technologies has distinct advantages and disadvantages that are discussed in this paper.

The final section also includes case studies demonstrating how three coal-fired electric power plants reduced emissions. The first case study is for a 126 megawatt (MW) plant in New York that installed combustion modifications (low-NOX burners with boosted over-fire air technology) to reduce NOX emissions by 60 percent. The second case study is for a 1,300 MW plant in Florida that upgraded combustion technologies (advanced low-NOX burners with over-fire air technology) to reduce NOX emissions by an additional 35 percent. The final case study is for a 2,600 MW plant in Ohio that installed combustion modifications (low-NOX burners) in combination with post-combustion controls (selective catalytic reduction) to reduce NOX by approximately 90 percent. However, the Ohio plant experienced a number of problems related to the SCR. These problems, and the attempted solutions, are reviewed in the case study.

1 Health and Environmental Impacts of Nitrogen Oxides

NOX is a generic term for a group of gases that contain nitrogen and varying amounts of . While there are a number of different gases that meet this definition1, we are most concerned with

(NO) and NO2 ʹ two gases that are emitted in large quantities from fuel combustion. NOX emissions and - secondary pollutants formed from NOX (e.g., O3, nitrate (NO3 ), and acid aerosols) are often transported over long distances, creating regional problems beyond the geographic and political boundaries of the areas where the NOX is emitted. These regional impacts can include the direct health effects of NO2 [1; 2; 3; 4] pollution ʹ NO2 can be a severe respiratory irritant and can to premature death ʹ as well as acid deposition, tropospheric ozone, fine particles, eutrophication of waterways, and regional haze.

Acid Deposition Acid deposition is the general term for both wet (e.g., rain, snow) and dry deposition of acid particles. In the atmosphere, NOX can oxidize into a variety of compounds that dissolve in water and decompose to 2 form nitric acid (HNO3) or nitrous acid (HNO2). These acid gases and neutralized salts contribute to acid rain.

The primary acidic compound ʹ HNO3 ʹ is produced when NO2 reacts with hydroxyl radicals (OH), water, or

O3 (see Equations 1, 2, and 3). During daytime conditions, OH and NO2 (Equation 1) are the dominant source of air-phase HNO3. During nighttime conditions, Equation 3 is the dominant source of aqueous- [5 ] phase HNO3.

Equation 1: NO2 + OH → HNO3

Equation 2: 3NO2 + H2O → 2HNO3 + NO

Equation 3: O3 + NO2 → NO3 + O2 ⇄ N2O5

N2O5 + H2O → 2HNO3

Because it is extremely water soluble, HNO3 rapidly deposits on particles and water droplets in the atmosphere. [5] When these acidic particles or moisture fall to earth they:

x Impair waterways; x Damage aquatic ecosystems; x Reduce forest and agricultural productivity; and x Damage paint finishes, buildings, infrastructure, and historical monuments. [5; 6; 7; 8; 9]

Tropospheric Ozone Tropospheric ozone, often referred to as ground-level ozone or smog, is a photo-oxidant that is formed when NO2 dissociates in the presence of sunlight (wavelengths shorter than 420 nanometers) and the resulting atomic oxygen reacts with molecular oxygen (see equation 4). [3; 5]

Equation 4: NO2 + hv → NO + O

O + O2 → O3

O3 can have serious health impacts for sensitive populations, such as people with lung disease, children, elderly, and the physically active. The health impacts of exposure to ground-level O3 include:

1 - Other forms of NOX include: nitrate (NO3 ), nitrous oxide (N2O), dinitrogen dioxide (N2O2), (N2O3), (N2O4), and (N2O5). 2 Other, less common, forms of acid aerosols include: peroxynitric acid (HNO 4) and ammonium nitrate (NH4NO3) 2 x Breathing difficulties during outdoor activities; x Irritation of eye, nose, and throat; x Skin inflammation; x Chest pain, coughing, nausea, and pulmonary congestion; x Aggravation of asthma; x Increasing incidences of respiratory illnesses (e.g., asthma, pneumonia, and bronchitis); x Permanent lung damage; and x Premature death. [3; 10; 11; 12; 13; 14]

Plants and ecosystems are also susceptible to the effects of O3. These effects include:

x Reduced plant growth and crop yields; x Increased susceptibility to diseases, insects, and harsh weather; and x Damaged leaves that affect the plant͛s ability to produce and store food. [1 5 ; 1 6 ; 1 7 ; 1 8 ]

Fine Particles

When NOX reacts with compounds (e.g., moisture, O3) in the atmosphere or flue gas, it can form NO3 (see Equations 5 and 6).

о Equation 5: O3 + NO2 → NO3 + O2 о + Equation 6: NO2 + H2O → NO3 + 2H

Nitrate particles are smaller than 2.5 microns in diameter (PM2.5) making it easy for them to penetrate deeply into the lungs. Sensitive populations, such as children and elderly, are particularly at risk from exposure to fine particles. The health effects of these fine particles include:

x Breathing difficulties; x Coughing, and nose and throat irritation; x Aggravation of asthma; x Increasing incidences and severity of respiratory illnesses (e.g., asthma, emphysema, and bronchitis); x Aggravation of existing heart disease; x Irregular heartbeats and heart attacks; x Permanent lung damage; x Lung cancer; and x Premature death. [2; 10; 19; 20]

Eutrophication of Waterways When nitrate concentrations become too high, water bodies suffer from nutrient enrichment (i.e., eutrophication). This occurs when the ratios of nitrogen to other nutrients (e.g., phosphorous, , ) change and cause increased algal growth. The resulting algal blooms reduce the amount of light that reaches lower depths, causing the death of plants at lower depths and reducing oxygen production. When algae and other plants die, sink, and decay, they deplete oxygen in the water (i.e., hypoxia) even further which can make the water body uninhabitable for aquatic life.

Regional Haze Haze occurs when particles in the atmosphere block the transmission of light, which reduces the clarity and/or color of an urban area or scenic vista. The size of NO2 is small enough that it absorbs blue photons in the atmosphere. As a result, white light passing through the atmosphere will tend to have a reddish- [21] - brown appearance. Fine particles, including NO3 , scatter light photons producing a white-grey haze that reduces contrast and visibility.

3 Air Quality Standards for Nitrogen Dioxide and Secondary Pollutants The US Environmental Protection Agency (EPA) establishes National Ambient Air Quality Standards (NAAQS) for criteria pollutants that pose a risk to human health and the environment. The standards have been developed to protect human health, including sensitive groups of the population (e.g., children, elderly, and asthmatics) ǁŝƚŚĂŶĂĚĞƋƵĂƚĞ͞ŵĂƌŐŝŶŽĨƐĂĨĞƚLJ͘͟/ŶĂĚĚŝƚŝŽŶƚŽW͛ƐEY^͕ƚhe World Health Organization (WHO) developed air quality guidelines for national gove rnments to use when setting air quality standards. The US NAAQS and WHO guidelines for NO2 and relevant secondary pollutants are shown in Table 1.

Table 1: US National Ambient Air Quality Standards and WHO Air Quality Guidelines [2; 22] Pollutant US NAAQS WHO Guidelines 3 3 NO2 Annual 100 µg/m Annual 40 µg/m mean mean 1-hour 200 µg/m3 mean 3 3 O3 8-hour 147 µg/m 8-hour 100 µg/m mean mean 3 3 PM2.5 Annual 15 µg/m Annual 10 µg/m mean mean 24-hour 35 µg/m3 24-hour 25 µg/m3 mean mean

In the US, state and local governments are responsible for implementing air pollution control programs and ensuring they attain the NAAQS. EPA provides the state governments with considerable flexibility to design air quality programs that account for local economic, political, and environmental conditions. If, however, the areas fail to meet the NAAQS, state governments must develop implementation plans that detail how state and local governments will improve air quality and achieve the NAAQS. In addition, areas that do not meet the NAAQS must implement rigorous technology and performance standards established and updated by EPA.

[23] Currently, all areas of the US have air quality at or better than the NO2 NAAQS. However, many densely populated urban areas exceed the NAAQS for O3 and/or PM2.5. In 2007 there were 293 counties or portions 3 of counties in the US that did not achieve the O3 standard of 147 µg/m (see Figure 1). Based on US Census figures for 2000, the population of these counties was almost 132 million people, or 47 percent of the total US population of 281.5 million people. [23; 24] The situation, however, is improving; data from 2005 through

2007 show that O3 levels in the Eastern US have fallen ŝŶĂůŵŽƐƚĂůůŽĨƚŚĞĂƌĞĂƐĚĞƐŝŐŶĂƚĞĚ͞ŶŽŶĂƚƚĂŝŶŵĞŶƚ͟ [25] with the 8-hour O3 NAAQS. In addition, longer-term trends show significant improvement: approximately two-ƚŚŝƌĚƐŽĨƚŚĞĂƌĞĂƐƚŚĂƚǁĞƌĞĚĞƐŝŐŶĂƚĞĚ͞ŶŽŶĂƚƚĂŝŶŵĞŶƚ͟ŝŶϮϬϬϭƚŚƌŽƵŐŚϮϬϬϯŶŽǁ [25] have air quality better than the O3 NAAQS.

4 Figure 1: Many Urban Areas in the Eastern US, California, and Texas are Ozone ͞Nonattainment͟ Areas (2007) [23]

3 There were 209 counties or portions of counties that did not achieve the PM2.5 annual NAAQS of 15 µg/m (see Figure 2). Approximately 31 percent of the total US population, or 88 million people, live in these [23; 24] counties. While the composition of PM2.5 pollution varies in different regions of the country, nitrates are an important component of PM2.5 in the Eastern US. Between 2000 and 2007, after the introduction of new emission control policies, ambient nitrate levels fell by 24 percent (see Figure 3). [9]

[23] Figure 2: Many Urban Areas in the Eastern US and California are PM2.5 ͞Nonattainment͟ Areas (2007)

[9 ] Figure 3: Ambient NO3 Concentrations Have Fallen by 24 Percent between 2000 and 2007

2000 2007

5 Sources of Nitrogen Oxides Emissions

In the US the dominant source of NOX emissions is the transportation sector, both on-road vehicles and off- road vehicles (e.g., airplanes, boats, trains, construction equipment). These two source categories were responsible for 33 percent and 24 percent, respectively, of US national NOX emissions in 2007 (see Figure 4).

The third dominant source of NOX in the US is the electric sector (i.e., electric power plants). The electric sector was responsible for 20 percent of national NOX emissions in 2007 and 46 percent of stationary [2 6 ] source NOX emissions. However, over the past decade the eleĐƚƌŝĐƐĞĐƚŽƌ͛ƐEKX emissions have fallen dramatically as a result of efforts to reduce NOX emissions ƵŶĚĞƌW͛Ɛ Acid Rain Program and NOX Budget

Trading Program ʹ cap and trade programs designed to reduce emissions of (SO2) and NOX emissions from electric power plants and large industrial boilers. [8] The Acid Rain Program set a goal to reduce NOX emissions nationally by 1.8 million tons below projected emission levels in the year 2000. To achieve these reductions, many existing coal-fired electric power plants were required to install low-NOX burners (LNBs). Beginning in 2003 and 2004, the NOX Budget Trading Program required 20 states in the Eastern US and the District of Columbia to reduce NOX emissions that contribute to regional transport of

NOX and nonattainment of the O3 NAAQS in downwind areas.

Although the NOX Budget Trading Program only applied to the Eastern US, nationwide NOX emissions from fossil fuel-fired electric power plants decreased by more than 1.8 million metric tons, approximately 38 percent, between the years 2000 and 2007. During that same time fossil fuel consumption increased by approximately 10 percent (see Figure 5).

Figure 4: Electric Power Plants are a Major Source of Figure 5: Coal-fired Electric Power Plants Increased Coal [27] [28] NOX Emissions in the US Consumption but Decreased NOX Emissions (2000-2007) 1.50 Vehicles 1.25 Heat Input Non-road Vehicles 2000 1.00 2007

Electric Utilities Emissions and X 0.75 NO Emissions Fuel Use Fuel X Industry 0.50 0.25 Other

Changes in NO 0.00 0 2 4 6 8 2000 2001 2002 2003 2004 2005 2006 2007 Million Metric Tons of NOX Emissions

In 2007, the US had approximately 335 GW of coal-fired electricity generating capacity [28]; the majority of these power plants are concentrated in the eastern half of the country (see Figure 6). These power plants generate the majority of US electricity ʹ approximately 59 percent of total electricity generation ʹ and 73 percent of total fossil fuel-fired electricity generation in 2007 (see Figure 7). [29] With approximately 30 ƉĞƌĐĞŶƚŽĨƚŚĞǁŽƌůĚ͛ƐŚĂƌĚĐŽĂůƌĞƐĞƌǀĞƐ [30] it is not surprising that coal will continue to be a major fuel for electricity generation in the US. Government analyses project that US coal use will grow by an average of 1.3 percent per year through 2030. [31]

Coal-fired electric power plants are also responsible for most of the NOX emissions from the US electric [28] sector ʹ 93 percenƚŽĨƚŚĞƐĞĐƚŽƌ͛ƐEKX emissions in 2007 (see Figure 8). Because 1) coal is the dominant fuel for generating electricity, 2) coal use will continue to grow, 3) coal-fired electric power plants are a key source of NOX emissions, and 4) coal-fired electric power plants have tall stacks leading to regional transport of pollutants, this paper will focus on NOX emissions from coal-fired electric power plants and options for reducing or controlling these emissions.

6 Figure 6: US Coal-fired Electric Power Plants are Concentrated in the Eastern US [28]

Figure 7: Coal-fired Electric Power Plants Produce Most Figure 8: Coal-fired Electric Power Plants Emit Most of [29] [28] of the h^͛ƐFossil-fuel Fired Electricity (2007) the h^ůĞĐƚƌŝĐ^ĞĐƚŽƌ͛ƐEKX Emissions (2007)

Coal Coal

Gas Gas

Oil Oil

Other Other

0 1,000 2,000 3,000 0 50 100 150 3,100200 3,150250

Gigawatt Hours of Electricity Generation Thousand Metric Tons of NOX Emissions

US coal-fired power plants have widely varying NOX emission rates. In 2007, US coal-fired electric power plants emitted an average of 154.9 grams of NOX per million British thermal units (Btu) of heat input. Plant- specific annual averages, however, ranged from 17.2 grams to 439.5 grams per million Btu. [2 8 ] One reason for the wide variation in NOX emission rates is the composition of the US electric sector, including age and combustion technology. The average US power plant has been in operation for more than 40 years (see Figure 9). Because of the way the US Clean Air Act (CAA) was enacted, many older facilities are exempt from emission standards and other emission reduction requirements established after the facility was placed in operation. Emission rates also differ significantly by boiler type. For example, circulating fluidized bed (CFB) boilers, with lower combustion temperatures and long residency times have emission rates ranging from 47.9 grams to 88.4 grams per million Btu. At the other end of the scale, cyclone boilers which have very high temperatures in the primary combustion zone and a design that makes them impossible to retrofit with standard LNBs have emission rates ranging from 209.0 grams to 363.5 grams per million Btu (see Figure 10). [28]

EPA began regulating NOX emissions from coal-fired electric power plants under the 1970 CAA. In general,

EPA uses three different approaches to regulate NOX emissions from coal-fired electric power plants: technology requirements, performance standards, and cap and trade programs. Technology requirements specify the design or technological options that coal-fired electric power plants must adopt to meet specific emission targets. Performance standards specify a maximum emission rate, but give coal-fired electric power plants the flexibility to adopt any design or technology options to meet the standard. In reality,

7 however, these standards are often set at a level that can only be met with the use of a specific technology. Cap and trade programs establish a limit on total allowable emissions from the electric sector, but give coal-fired electric power plants the flexibility to develop custom emission control strategies that account for economic, technical, and strategic considerations. Coal-fired electric power plants may invest in combustion or post-combustion controls, fuel switching, load shifting, and/or buying or selling allowances. In return for this flexibility, the power plants must continuously monitor emissions, report emission and

ŽƉĞƌĂƚŝŽŶĚĂƚĂƚŽW͕ĂŶĚ͞ƉĂLJ͟ŽŶĞĞŵŝƐƐŝŽŶĂůůŽǁĂŶĐĞĨŽƌĞĂĐŚƚŽŶŽĨEK X emitted.

Figure 9: The Average Age of US Coal-fired Electric Power Plants is Approximately 40 Years Old [32] 18 16 14 12 10 8 6

Gigawatts Gigawatts of Capacity 4 2 0 1941 1944 1947 1950 1953 1956 1959 1962 1965 1968 1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 "Vintage" of Coal-fired Power Plants Currently On-line

[28] Figure 10: NOX Emission Rates Vary by Boiler Type (2007) (SNCR/SCR Units Excluded) Unit0 200000 400000 600000 800000 1000000 Count Wet Bottom Wall 14 Dry Bottom Vertical 22 Dry Bottom Wall 303 CFB 25 Cell Burner 14 Cyclone 52 Tangential 323 All Boiler Types 784

0 50 100 150 200 250 300 350 400 NOX Emission Rate (Grams/Million Btu)

Under authority from Section 111 of the CAA, EPA developed New Source Performance Standards (NSPS) for several source categories, including coal-fired electric power plants. NSPS are national emission standards that are periodically updated to improve air quality over time without unreasonable economic disruption. The NSPS program requires new emission sources, and emission sources that expand or modify their facility, to install emission controls. When EPA updates the NSPS emission limits the Agency conducts assessments of the best commercially-available approaches or technologies to reduce emissions. NSPS emission limits are generally based on what can be achieved using these approaches or technologies.

The first NSPS for coal-fired electric power plants ʹ 40 CFR part 60, subpart D ʹ were established in 1971 and updated in 1978, 1997, and 2005 (see Table 2). When the US Congress enacted the NSPS provision the focus was on new, expanded, and modified coal-fired electric power plants, less attention was paid to existing power plants. At the time, the US Congress assumed that coal-fired electric power plants would be decommissioned after their expected functional lifetime of 30 years. Therefore, existing facilities received

8 an exemption to NSPS because many coal-fired electric power plants were nearing the end of their expected lifetime and the legislators expected the power companies to replace the power plants with new power plants subject to the standard. [3 3 ] However, may coal-fired electric power plants have received extensive maintenance to extend their operation and remain in use long after the expected functional lifetime (see Figure 9).

Table 2: US New Source Performance Standards for Coal-Fired Electric Power Plants [34] Construction Date Coal Type Maximum Emission Rate (30-day rolling average) After 1971 August 17 Bituminous, subbituminous, 318 grams/million Btu anthracite Lignite 272 grams/million Btu After 1978 September 18 Subbituminous 227 grams/million Btu Bituminous, anthracite, lignite 272 grams/million Btu After 1997 July 9 All 68 grams/million Btu AND 726 grams/megawatt hour After 2005 February 28 All 50 grams/million Btu AND 454 grams/ megawatt hour

In 1990, the US Congress amended the CAA to include a new performance-based program to control SO2 and NOX emissions from new and existing coal-fired electric power plants. The Acid Rain Program established a goal of reducing expected NOX emissions by 1.8 million tons annually beginning in 2000. The first phase of the program began in January 1996. This phase required tangential and dry bottom wall coal- fired electric power plants to meet emission rates that were based the installation of LNBs. Coal-fired electric power plants could meet the standards by: 1) installing LNBs or more effective emission controls at each unit, or 2) installing more effective (and, generally, more expensive) emission controls at select units and averaging emission rates at two or more units that share the same owner. The option to average emission rates gave the owners and operators of coal-fired electric power plants the flexibility to pursue the most cost-effective opportunities to reduce NOX emissions at their power plants while meeting the ĞŵŝƐƐŝŽŶƌĂƚĞ͞ŽŶĂǀĞƌĂŐĞ͘͟During the first phase of the program, emission rates at the affected combustion units fell by approximately 40 percent. [3 3 ; 3 5 ] The second phase of the program began in January 2000 and extended the emission rate limit to additional boiler types. Emission rates from coal-fired electric power plants participating in the Acid Rain Program fell approximately 50 percent below 1990 levels. [9]

In 1998, EPA, in cooperation with state governments, established a NOX cap and trade program to reduce

NOX emissions from fossil fuel-fired electric power plants and industrial boilers in the Eastern US. The program, known as the NOX Budget Trading Program, began in 2003 and required affected sources to reduce NOX emissions during the ozone season (May through September) from a baseline of 1,745,000 tons in 1990 to 484,000 tons in 2007. [25] While the program does not require specific emission control technologies or set maximum emission rates, on average, fossil fuel-fired electric power plants had to emit 3 [28] no more than 76.9 grams per million Btu during the ozone season to meet the NOX emission cap. The fossil fuel-fired electric power plants and industrial boilers in the NOX Budget Trading Program achieved an average NOX emission rate of 72.9 grams per million Btu during the 2007 ozone season. In total, fossil fuel- fired electric power plants and industrial boilers in the NOX Budget Trading Program reduced ozone-season [25] NOX emissions by 60 percent between 2000 and 2007. Formation of Nitrogen Oxides Emissions

Before exploring emission control techniques, it is first necessary to understand the formation of NOX during combustion. When combusting fossil fuels and biomass at high temperatures, nitrogen in the fuel and air combine with oxygen in the air to form NOX. Typically, 90 to 95 percent of NOX emissions are NO

3 This average emission rate is based on the emission cap of 484,000 tons and 2007 heat input of 6,300 trillion Btu. 9 [1 8 ; 3 6 ; 3 7 ] with the remaining mostly NO2. The level of NOX formation depends on the temperature, residency time of fuel in the combustion zone, nitrogen content in the fuel, and the amount of excess air. During the combustion of coal NOX will form via three distinct mechanisms: fuel NOX, thermal NOX, and prompt NOX.

Approximately 70 ʹ 80 percent of NOX from coal combustion is from fuel NOX, 5 ʹ 25 percent is from [38; 39] thermal NOX, and less than 5 percent is from prompt NOX. Each of these mechanisms is reviewed below.

Fuel NOX

Fuel NOX is the primary source of NOX from coal-fired electric power plants. It is formed from the reaction of organically-bound nitrogen in the coal with oxygen in the air. The nitrogen in the coal quickly evolves to (HCN) and ammonia (NH3) during devolatilization and char combustion. The HCN then reacts with free radicals (atomic oxygen and hydroxyl radicals (OH)) to form intermediaries and ultimately reacts with hydrogen to produce nitrogen-hydrogen radicals (NH and NH2). Further free radical reactions lead to the formation of molecular nitrogen or NO (see Figure 11).

[40] Figure 11: Fuel NOX Formation Occurs Through a Complex Pathway

In fuel-rich conditions, less oxygen is available and, therefore, less of the nitrogen bound in the fuel is converted to NOX. This enables boiler operators to stage combustion to reduce NOX emissions.

Thermal NOX

During combustion at high temperatures, molecular nitrogen in the combustion air is oxidized to form NOX.

The formation rate of thermal NOX is a function of both temperature and residency time at the temperature. At temperatures above 1,200°C, molecular nitrogen and oxygen dissociate to their atomic states and undergo reactions to form NO (see Equations 7, 8, and 9). As temperature increases above

1,200°C, thermal NOX formation increases exponentially.

Equation 7: O + N2 ⇄ NO + N Equation 8: N + O2 ⇄ NO + O Equation 9: N + OH ⇄ NO + H

Thermal NOX can be controlled by reducing oxygen concentrations, temperature, and/or residency time in the combustion zone. This enables boiler operators to reduce thermal NOX by increasing the size of the combustion zone (e.g., over-fire air (OFA)) for a given heat input; reducing the rate of combustion (e.g., LNBs) and, as a result, peak flame temperature; and/or mixing flue gas with combustion air at the burner (e.g., flue gas recirculation).

Prompt NOX

Prompt NOX is formed very quickly from the interaction of molecular nitrogen in the combustion air and hydrocarbon radicals released at the flame front during volatile evolution. The primary prompt NOX

10 reactions involve a complex series of reactions with intermediary steps (see Equations 10 and 11 for simplified examples).

Equation 10: CH + N2 ⇄ HCN + N

N + O2 → NO + O

Equation 11: CH2 + N2 ⇄ HCN + NH

NH + H + O2 → NO + O + H2

While the ratio of prompt NOX to total NOX is quite small, as NOX emissions are reduced to very low levels due to burner design or combustion zone modifications, the prompt NOX-to-total NOX ratio increases. Technologies for Reducing or Controlling Nitrogen Oxides

In general, there are two forms of NOX control technologies: combustion modifications and post- combustion controls. Combustion modifications, as the name implies, modify the combustion zone conditions to reduce NOX formation. Generally, this involves reducing the availability of oxygen in the primary flame and/or reducing the flame temperature. By contrast, post-combustion controls are located downstream of the furnace to remove NOX in flue gas after its formation. These technologies cause a - reaction with NOX to convert it to molecular nitrogen or NO3 . Figure 12 lists some of the different commercially-available NOX reduction and control technologies. Table 3 lists common applications of NOX control technologies at coal-fired electric power plants in the US.

Figure 12: NOX Control Technologies Include Combustion Modifications and Post-Combustion Controls

Table 3: Common Applications of NOX Control Technology in the US Boiler Type Control Type

Pulverized Coal Low-NOX burners Over-fire air Reburn SNCR SCR Cyclone Over-fire air Reburn SNCR SCR CFB SNCR

11 Combustion Modification Technologies

When assessing options for reducing NOX emissions at existing coal-fired electric power plants, combustion modifications, including burner optimization, LNBs, OFA, flue gas recirculation, and reburning, are generally the first option analyzed because they require relatively small capital investŵĞŶƚƐĂŶĚĚŽŶ͛ƚƌĞƋƵŝƌĞ ongoing costs for reagents or catalysts. These technologies stage the combustion of fuels to reduce NOX formation in the primary combustion zone.

In the US, the most common combustion modification technologies at coal-fired electric power plants are LNBs and OFA, used either independently or in combination. Reburning, although not as common as LNB or OFA, is also used at numerous coal-fired electric power plants. Therefore, this paper will focus on these three specific combustion technologies.

Low-NOX Burners Pulverized coal-fired electric power plants have multiple burners to combine fuel and combustion air (i.e., secondary air). The basic functions of each burner are: x Fuel injection and ignition; x Air-fuel mixing; x Flame stabilization; and x Emission control. [36; 41]

LNBs are a proven, commercially-available technology designed to control the mixing of fuel and air to control the stoichiometric and temperature profiles of the combustion process. They do this by: x Maximizing the rate of volatile evolution and total volatile yield from the fuel. In general, lower rank coals (e.g., subbituminous coal) have a higher volatile matter content. When these coals are combusted there is greater volatile release near the burner zone. In these conditions, an LNB can

reduce NOX formation significantly because the fuel nitrogen is released in a fuel-rich environment leading to greater conversion to molecular nitrogen and reductions in nitrogen in the char that is oxidized in a fuel-lean area away from the burner. [3 6 ; 4 2 ; 4 3 ; 4 4 ]

x Creating a fuel-rich, oxygen-deficient environment in the primary flame zone to minimize NOX conversion, but ensure flame stability. [43; 44] Figure 13 shows the LNB concept with gradual mixing of combustion air to a fuel-rich flame core.

x Optimizing the residence time and temperature in the reducing zone to minimize NOX formation from fuel nitrogen. [43]

x Maximizing the char residence time under fuel-rich conditions to reduce NOX formation after devolatilization is complete. [43] x Adding sufficient air to complete combustion.

In general, LNBs try to delay the complete mixing of fuel and air as long as possible within the constraints of furnace design. [44] As a result of these modifications, flames from LNBs are often longer and more branched than those of conventional burners.

Figure 13: Low-NOX Burners Control the Mixing of Fuel and Air

12 Operating conditions also significantly affect the performance of LNBs. Boiler design, including furnace size and heat-release rates, can also affect the temperature of and residence time in the furnace, and, as a [4 4 ; 4 5 ] result, the formation of NOX. In general, LNBs can reduce NOX formation by 30 to 50 percent.

LNBs do present some challenges in retrofit applications at existing coal-fired electric power plants. The longer flames of LNBs have to be carefully controlled to avoid impingement on the furnace walls. The LNBs may also change the heat transfer patterns within the furnace, create a drop in burner pressure, increase corrosion of furnace walls and boiler tubes, increase fouling of the furnace, change the temperature profile of heat exchangers, and increase furnace exit gas temperature. [44; 46; 45] However, the major challenge with LNBs in retrofit applications is the possible reduction in combustion efficiency and increase in unburned carbon (UBC). [4 3 ; 4 4 ; 4 5 ; 4 7 ] Increased UBC of 1.5 to 2 times pre-LNB levels is not uncommon. [43] The actual level of increased UBC from LNBs is largely dependent on coal properties, burner and air register design, furnace size, firing configuration, and excess air levels. [44] UBC not only represents reduced efficiency and lost energy content, it is also an important metric for the resale and use of fly ash. If UBC levels in fly ash exceed specifications for the safe, effective use of fly ash in other products (e.g., concrete) the coal-fired electric power plant will be unable to sell the fly ash and must instead pay for its disposal. This can significantly raise operating costs. In the fly ash, UBC will also ůŽǁĞƌƚŚĞĂƐŚ͛ƐƌĞƐŝƐƚŝǀŝƚLJǁŚŝĐŚ͕ŝŶƚƵƌŶ͕ǁŝůů lower the performance of the electrostatic precipitator (ESP) and affect power plant operation. Measures can be taken to reduce UBC, but these actions often reduce the effectiveness of the LNBs. The simplest and most effective options to control UBC levels are upgrading the coal milling or classifier capabilities or improving the fuel and air distributions.

Based on experience with LNBs in the US, there are several essential conditions to optimize combustion in boilers with LNBs: 1. Excess oxygen levels at the furnace exit must be at least 2 percent and preferably 3 percent; 2. Primary air flow and OFA should be measured and controlled with an accuracy of ±3 percent; 3. Secondary air distribution should be controlled with an accuracy of ±10 percent; and 4. Fuel feed quality and size should be consistent. [4 7 ]

Newer advanced LNBs have been developed that can achieve even greater NOX reductions while limiting impacts on combustion efficiency and UBC levels. Typically, these burners can reduce NOX formation by up to 20 percent more than conventional LNBs. [43] ^ŽŵĞĂĚǀĂŶĐĞĚ>EƐ͕ƐƵĐŚĂƐĂďĐŽĐŬĂŶĚtŝůĐŽdž͛ƐZ-4Z burner have additional air zones. In the DRB-4Z, a third air zone, referred to as the transition zone, acts as a buffer between the fuel-rich flame core and the inner and outer combustion air zones. The transition zone draws gases from the outer portion of the flame inward reducing the amount of NOX created in the fuel lean outer flame region.

While LNBs are sometimes used independently, many coal-fired electric power plants use a combination of LNBs and other combustion modifications (e.g., OFA, reburning, or flue gas recirculation) or post- combustion controls. On wall-fired boilers, the addition of OFA to LNB can reduce NOX emissions by an additional 10 to 25 percent. [4 4 ]

Over-fire Air The principle of OFA is to reduce the amount of oxygen available in the primary combustion zone where it is critical to NOX formation. OFA separates the combustion air into a primary and secondary flow to achieve complete burnout. The result is a preference for the formation of molecular nitrogen instead of NOX. The primary air (70 to 95 percent of total combustion air) is mixed with the fuel producing a relatively low- temperature, fuel-rich, oxygen-deficient environment. The secondary air (5 to 30 percent of total combustion air) is injected above the burners where combustion is completed under relatively low temperatures, limiting the formation of thermal NOX.

In general, OFA is used in one of three configurations: 1) close-coupled to the burner (CCOFA), 2) separated from the burner (SOFA), or 3) both (see Figure 14). The location of the OFA ports is critical to maintain

13 efficient combustion. Because the location is critical, retrofitting OFA on an existing coal-fired boiler can be relatively expensive because it often involves modifications to waterwall tubing to create the necessary ports. [46] Also, because the burner provides less combustion air than it would otherwise provide without OFA, it can impair flame stability and slow the combustion process. [3 6 ]

Figure 14: Over-ĨŝƌĞŝƌWŽƌƚƐĐĂŶďĞ͞ůŽƐĞ-ĐŽƵƉůĞĚ͟ƚŽƚŚĞƵƌŶĞƌŽƌ͞^ĞƉĂƌĂƚĞĚ͟ĨƌŽŵƚŚĞƵƌŶĞƌ

In general, NOX reductions are greatest when the stoichiometry in the burner zone is 0.85 or less. The OFA must then be gradually introduced into the combustion zone to avoid rapid reformation of NOX. In order to achieve this gradual introduction of OFA, coal-fired electric power plants may introduce OFA through two different zones (i.e., CCOFA and SOFA ports). The ports nearest the burner (CCOFA) supply the lesser portion of OFA to bring the stoichiometry close to 1.0 with the SOFA ports supplying the balance of OFA to complete the combustion process. This approach reduces peak oxygen levels and moderates UBC. [36]

As with LNBs, OFA presents some challenges for coal-fired electric power plants. If not designed or configured properly, OFA can decrease combustion efficiency, increasing (CO) and UBC levels due to sub-stoichiometric conditions. Ideally, the design of an OFA system should provide sufficient [48] residence both above and below the OFA ports to complete combustion and maximize NO X reduction. Coal type also impacts UBC levels ʹ low volatile content coals yield greater increases in UBC than high volatile content coals. Some additional challenges presented by OFA include: waterwall corrosion, loss of steam temperature, and changes in slagging and fouling patterns. [48]

Coal-fired electric power plants have also installed boosted over-fire air (BOFA) systems to improve the mixing between the remaining fuel and air. [4 5 ] The increased energy of the BOFA makes it possible to locate the OFA ports higher in the furnace than otherwise possible. The improved mixing of fuel and OFA, and longer residence times enable additional NOX reductions with lower UBC levels and without additional losses in efficiency. The tradeoff with BOFA is the cost for the installation, operation, and maintenance of booster fans for the system.

[4 4 ; 4 5 ] OFA can reduce NOX emissions by around 20 to 60 percent. The actual reductions will depend on coal properties, boiler design, burner design, and initial NOX levels. Higher NOX reductions are expected for coals with a higher volatile content (e.g., subbituminous coals).

More advanced OFA designs can achieve even greater efficiency and NOX reductions. For example, rotating opposed fire air (ROFA) injects air into the furnace to create a cyclonic gas flow to improve combustion.

14 ROFA uses a booster fan to increase the velocity of air to promote improved mixing which results in a more even distribution of combustion products, less temperature variation across the furnace, and less excess air required to complete combustion. ROFA has been shown to reduce NOX emissions by 45 to 60 percent. [44] In addition, ROFA avoids many of the challenges of conventional OFA, including UBC and excess air.

Reburning/Fuel Staging In reburning, fuel and combustion are supplied in stages in the furnace. Combustion is divided into three zones (see Figure 15): 1. The primary combustion zone in which coal is fired through a conventional burner or LNB in fuel- lean conditions. Typically, the burners are operated with the lowest excess air to maintain acceptable performance ʹ flame stability, UBC, ash deposition, and wall corrosion. [43] This zone

produces significant thermal and fuel NOX which is subsequently reduced in the reburn and burnout zones. 2. The reburn zone in which 10 to 30 percent of total heat input [43] is injected above the main combustion zone to produce fuel-rich conditions (stoichiometry of approximately 90 percent theoretical air). [44] The fuel is typically injected at high temperatures (>1,200° C) to avoid competing reactions and to obtain sufficient reaction time. The fuel must also have good entrainment, mixing, and dispersion within the reburn zone providing residence times of 0.4 to 1.5 [46] seconds. This zone produces hydrocarbon radicals that react with a portion of the NOX to form hydrogen cyanide (HCN), isocyanic acid (HNCO), isocyanate (NCO), and other compounds which are eventually reduced to molecular nitrogen. [44] 3. The burnout zone in which OFA is supplied to complete combustion. Burnout air should provide rapid mixing and provide residence times of 0.7 to 0.9 seconds to complete burnout. [4 6 ] This final stage consumes the CO and UBC from the reburn zone.

Figure 15: Reburning Uses Three Zones to Complete Combustion

Reburn zone stoichiometry has a significant impact on NOX reductions. The stoichiometry is directly related to the portion of total heat input to each zone. In general, increasing the heat input to the reburn zone while reducing the heat input to the primary combustion zone will decrease the stoichiometry in the reburn zone and reduce NOX further. However, the ability to shift heat input between the zones is generally limited by: a) conditions required for flame stability in each zone, b) potential CO or UBC resulting from additional reburn fuel, and c) potential water tube corrosion in the reburn zone. [44]

15 A reburning system has the added advantage that it can be used to generate a range of NO X emission reductions, from 25 percent using the OFA system only and no reburn fuel to over 60 percent when reburn fuel is added. [4 3 ] This allows plant operators to fine tune operations to meet different emission limits.

In principal, any hydrocarbon fuel can be used in a reburn application. In the US, however, natural gas is the most commonly used fuel because it x Has no sulfur, ash, or fuel nitrogen; x Mixes well; x Is easily controlled;

x Contains hydrocarbons that are immediately available to react with NOX from the primary combustion zone; and x Has a limited impact on boiler performance. [4 3 ]

Coal has also been used as a reburn fuel. The advantages of coal are its lower cost relative to natural gas and the reduced complication of supplying a second fuel at coal-fired electric power plants. However, using coal as a reburn fuel requires relatively longer residence times in the reburn zone and the burnout zone to complete combustion. In some applications, it may be necessary to upgrade pulverizers or use micronized ĐŽĂů;уϮϬŵŝĐƌŽŶƐͿ for the reburn zone . Micronized coal has the advantage of releasing volatiles at an even rate and combusting in milliseconds. [43] However, it increases capital costs because it requires special coal pulverizers.

Summary

Combustion modification technologies are a proven, cost-effective approach to reduce NOX emissions from coal-fired power plants. With the development of new technologies and enhancements to existing [4 3 ] technologies NOX removal rates can range from 10 to 80 percent. The level of NOX reduction depends largely on initial NOX levels, boiler design, fuel quality, and plant operating conditions. Advances in the technologies, combined with increasingly stringent performance-based NOX emission control policies, are leading coal-fired power plants to combine control technologies to achieve even greater NOX reduction.

The primary challenges with combustion modifications are controlling UBC levels which can increase by 50 to 100 percent over pre-modification levels. [43] Other concerns include: waterwall corrosion, loss of steam temperature, and changes in slagging and fouling patterns. [43; 48]

Case Study 1: Low-NOX Burner and Fan-boosted Over-fire Air Modifications The AES Westover Station, a 126 megawatt (MW) coal- fired electric power plant in Johnson City, New York, underwent a combustion optimization program at Unit 8

to reduce NOX emissions while maintaining acceptable levels of UBC in ash. The modifications implemented in 2002 centered on combustion optimizations and a fan-

boosted OFA system which reduced NOX emission levels by 60 percent and improved unit reliability. Unit 8, a tangentially-fired boiler rated for 281,000 kilograms/hour (620,000 pounds/hour) of steam at 103.7 2 kilograms/centimeter (1,475 psig), was put into operation in 1951. At its inception, ƚŚĞƵŶŝƚ͛ƐEKX emission rate was typical of tangential units at the time ʹ 272 to 408 grams/million Btu with 3 percent loss- on-ignition (LOI). Subsequent combustion modifications reduced the NOX emission rate to 227 grams/million Btu, but the LOI increased to 20 percent. [47]

After some initial actions to optimize combustion, such as upgrading coal pulverizers and optimizing furnace inputs to minimize secondary combustion and the consequent potential for overheating water tubes, a BOFA system with eight OFA nozzles (two on each wall) was installed at Westover Station Unit 8. Up to 25 percent of the 315° C combustion air from the air preheater is sent directly to the OFA ports in the

16 upper furnace, bypassing the burners. The burners and BOFA supply the recommended total air flow to the boiler. [47] However, the OFA ports enable staging of the combustion process, thereby lowering furnace stoichiometry. Fuel and air are staged both vertically (burner tilt) and horizontally (air diverters). The configuration of the BOFA was designed to maintain a large oxidizing environment to limit waterwall wastage.

The booster fan increases the pressure of combustion air to approximately 25 to 38 centimeters to provide proper penetration velocities. [4 7 ] The penetration velocities are critical to maintaining acceptable levels of flyash LOI and CO in exit gas. In addition, the proper penetration velocity ensures there is sufficient oxygen to complete combustion.

The combustion optimizations and addition of the BOFA yielded emission reductions of about 60 percent. [47] The BOFA alone reduced NOX between 26 and 41 percent (see Table 4).

[47] Table 4: Pre- and Post-Modification NOX Emission Rates for Westover Station Unit 8 5 Net Load Pre-retrofit NOX level Post-retrofit NOX level Change (%) (MW) (g/million Btu)4 (g/million Btu) 36 ʹ 90.7 ʹ 40 185.5 137.9 26 50 200.0 140.2 30 60 215.0 142.0 34 70 229.5 144.2 37 80 244.5 146.0 40 83 248.5 146.5 41

The upgrades to Unit 8 also improved reliability. Between 2002, when the modifications went online, and 2005, the availability factor of Unit 8 averaged over 92% and the forced outage rate declined from 3.44 to 1.74 percent. The total cost for the modifications was approximately $20 per kilowatt. [4 7 ]

In 2006 December, AES announced [49] that the company would begin installation of a state-of-the-art multi-pollutant emission control system on Westover Station Unit 8. The $50 million project includes an ammonia selective catalytic reduction (SCR) unit to raise the NOX removal from 60 to 90 percent, a dry scrubber to reduce SO2 emissions by 95 percent, and a fabric filter baghouse, the combination of which is expected to reduce emissions by 90 percent.

Case Study 2: Low-NOX Burner and Over-fire Air Modifications The SECI Seminole Generating Station, a 1,300 MW coal-fired electric power plant in Putnam County, Florida, underwent a retrofit to upgrade its LNBs and OFA. The modifications implemented at the two 650 MW units in the Fall of 2006 (Unit 1) and Spring of 2007 (Unit 2) centered on the replacement of LNBs and OFA with more advanced systems to improve air-fuel mixing and increase the share of combustion air from the OFA. The new burners and increased OFA

reduced NOX emissions by 35 percent and reduced fly ash LOI. The two units, opposed wall-fired boilers rated for 2.13 million kilograms/hour of steam, were put into operation in 1983 and 1984. [50] Each unit had high burn zone heat release rates which led to higher levels of NOX formation. Both units typically combust a blend of 70 percent high-sulfur eastern bituminous coal and 30 percent petroleum coke.

4 The pre-retrofit measurements were taken after the optimization activities, but before the installation of the BOFA system. 5 The percent change is lower than the reduction in the overall NO X emission rate change because the 60 percent improvement is calculated from the pre-optimization (data not available) and pre-modification measurements. 17

The new LNBs installed as part of the retrofit were designed to provide improved air-fuel mixing with a one-piece axial swirl assembly to improve air flow distribution control and air-fuel mixing. The fixed axial swirl generator produces a vortex air flow pattern with strong inward recirculation around the coal jet (see Figure 16). In addition, the OFA system was upgraded and new OFA ports were added to the front and rear walls to increase air flow while baffles and vanes were added to improve distribution and penetration. As a result of these enhancements, Seminole Station was able to increase OFA from 10 percent of combustion air to 25 percent. The retrofit also included extensive measurement equipment, including an electric charge transfer system, to measure coal flow and velocity and combustion air to the burner. [50]

The enhancements to Unit 1 were tested using the normal 70/30 blend of bituminous coal/petroleum coke.

At full load, the NOX emission rate declined from a pre-retrofit rate of 240 grams per million Btu to 158.8 grams per million Btu, a 35 percent reduction. Using 100 percent bituminous coal at 50 percent of load, the

NOX emission rate declined to 99.8 grams per million Btu. CO emission rates also declined from 167 parts per million to 125 parts per million, but fly ash LOI was only slightly lower at approximately 26 percent. [5 0 ]

Figure 16: The New Burners Create a Vortex Flow Pattern for Better Air-Fuel Mixing [50]

In 2007 January, SECI announced [51] that the company would begin installation of a urea-to-ammonia SCR to raise the NOX removal and to meet new environmental performance requirements.

Post-Combustion Control Technologies

Post-combustion NOX control technologies are typically installed downstream of the furnace to remove NOX after it has formed. In general, these technologies involve injecting ammonia, urea, or other reagents into the flue gas where they react with NOX to form molecular nitrogen and water. The two most common post-combustion control technologies are selective non-catalytic reduction (SNCR) and SCR. In the US, 29.5 gigawatts (GW) of electric generating capacity at 180 coal-fired units have SNCR installed, and 105.6 GW of electric generating capacity at 212 coal-fired units have SCR. An additional 47 units with 22.7 GW of capacity have SCR controls under construction (see Figure 17). [32] The first SCR application on a US coal- fired electric power plant started operation in 1991 at the 600 MW J.M. Stuart Power Plant in Ohio.

18 [32] Figure 17: More Than 135 GW of Coal-fired Electric Generating Capacity Have Post-combustion NOX Controls

SNCR An additional 298 GW of coal-fired electric generating capacity have Under SCR NOX combustion controls. Construction

SNCR

Operating SCR

0 20 40 60 80 100 120 GW Selective Non-catalytic Reduction There are two widely-used, commercially-available SNCR processes ʹ ammonia-based technology and urea-based technology. Although there are differences between each system, the overall processes are similar. SNCR technologies involve injecting a reagent into the flue gas at 850° C to 1,100 ° C. Temperature is a critical factor for SNCR NOX reduction. Above 1,100 ° C, NOX reductions slow as the nitrogen in the [4 3 ] reagent is dissociated and converted to molecular nitrogen or NOX. Above 1,200° C this reaction may [3 6 ] become dominant, leading to increases in NOX emissions. However, there are some high-temperature applications (>1,100° C) (e.g., cyclone boilers) in the US in which high initial concentrations of NOX cause [44] the reduction kinetics to dominate oxidation kinetics. Below 850° C, NOX reaction rates are too slow and ammonia slip increases [4 3 ] unless hydrogen is added to assist the reaction [36; 52] or the mixing time is sufficient for the reactions to reach completion. [44] In addition to the temperature range requirements, SNCR requires good mixing, adequate residence time, and no chemical impingement against tubing. [52]

The chemical reaction for urea-based SNCR is show in Equation 12 and the reactions for ammonia-based SNCR are shown in Equations 13 and 14.

Equation 12: CO(NH2)2 + 2NO + ½O2 → 2N2 + CO2 + 2H2O

Equation 13: 4NO + 4NH3 + O2 → 4N2 + 6H2O (NH3:NO = 1:1)

Equation 14: 2NO + 4NH3 + 2O2 → 3N2 + 6H2O (NH3:NO = 2:1)

The reagent and the injection configuration are critical design elements that affect the mixing of reagent and flue gas. Urea (aqueous) and aqueous ammonia injection are generally more effective at reducing NO X than anhydrous ammonia injection because the aqueous droplets penetrate further into the flue gas stream. In addition, because urea is less volatile than ammonia, urea droplets penetrate further into the flue gas stream which provides better mixing. To facilitate proper mixing of ammonia with the flue gas, more elaborate injection schemes are often used.

Although urea provides better mixing without expensive injection grids, anhydrous ammonia is the most cost effective reagent in the US. However, it is also the most hazardous and requires very strict procedures for transportation, handling, and storage. As a result, urea is becoming more common and is replacing ammonia at many US coal-fired electric power plants because it is safer and easier to handle than ammonia. [53] In addition, the use of urea can lower capital and operating costs due to the elimination of large system compressors and anhydrous storage, handling, and safety equipment. [43]

SNCR systems in coal-fired electric power plants generally use a multilevel injection system (see Figure 18). Larger units may require up to four separate injection levels. [36] This approach provides more flexibility for the coal-fired electric power plant owner and operator to modify the injection rate, reagent concentration, and injection point(s) to match temperature and load changes of the boiler.

19

Commercial SNCR systems typically have reagent utilization rates of 20 to 60 percent. [43] As a result, a higher amount of reagent (e.g., 3 or 4 times) is required to achieve NOX reduction levels similar to SCR.

Figure 18: Selective Non-catalytic Reduction Systems Often Include Multiple Injection Points

When ammonia is used as the reagent, it is important to control the excess unreacted ammonia. As flue gas temperatures are reduced, excess ammonia can react with other compounds in the flue gas, primarily sulfur trioxide (SO3) to form ammonium sulfate [(NH4)2SO4] and ammonium bisulfate (NH4HSO4). Ammonium sulfate is a fine particle that can contribute to plume formation while ammonium bisulfate is a highly acidic, sticky compound that can foul and corrode downstream equipment (e.g., economizers and air heaters). In addition, excess ammonia can contaminate fly ash reducing its reuse value. As with increased UBC in fly ash, high levels of ammonia make it difficult to sell fly ash. This increases cost because the coal - fired electric power plant will have to pay for ash disposal. As a result of these impacts from excess ammonia, ammonia slip ʹ the release of unreacted ammonia ʹ is usually controlled to levels below 5 ppm.

It should be noted, however, that managing an SNCR to minimize ammonia slip often results in higher NOX emission rates.

SNCR effectiveness may also depend on the size of the boiler. In the US, larger boilers have much lower

NOX removal from SNCR, probably due to the challenge of uniformly distributing the reagent in the furnace. Data show that small boilers can achieve more than 60 percent NOX reduction with SNCR while larger boilers may only be able to reduce NOX by approximately 30 percent (see Table 5).

[54] Table 5: NOX Emission Reductions using SNCR Plant & unit Unit size NOX reduction (MW) efficiency (%) BL England ʹ 1 129 31 BL England ʹ 2 155 36 Cardinal ʹ 1 500 30 Clover ʹ 1 441 25 Cromby ʹ 1 144 25 Mercer ʹ 2 321 35 Salem Harbor ʹ 1 78 66 Salem Harbor ʹ 3 142 66 Schiller ʹ 5 50 30 Seward ʹ 15 136 35

20 One distinct advantage of SNCR is ease of installation. A typical SNCR system can be installed at most power plants in less than 8 weeks. [55]

The removal efficiency of SNCR systems can vary widely. At US coal-fired electric power plants with SNCR systems, NOX emission rates during the 2007 ozone season ranged from 25 grams per million Btu to 182 grams per million Btu (see Figure 19).

Figure 19: NOX Emission Rates at Coal-fired Electric Power Plants with SNCR Vary Widely (2007 Ozone Season) 25

20

15

10 (2007Ozone Season) TrillionBtu Heat Input 5

0 0 50 100 150 200 NOX Emission Rate (grams/million Btu)

Selective Catalytic Reduction SCR is similar to an SNCR system, but the reagent (e.g., ammonia) is usually injected through an injection grid located downstream of the furnace and just before the SCR reactor containing a catalyst. The catalyst facilitates the reaction between NOX and the ammonia (see Figure 20). As the flue gas and ammonia pass across the catalyst surface, the micropores of the catalyst cause a reaction between NOX and the ammonia producing molecular nitrogen and water (see Equations 15, 16, and 17).

Equation 15: 4NO + 4NH3 + O2 → 4N2 + 6H2O

Equation 16: NO + NO2 + 2NH3 → 2N2 + 3H2O

Equation 17: 2NO2 + 4NH3 + O2 → 3N2 + 6H2O

Figure 20: The SCR Catalyst Enhances the Reaction between the Reagent and NOX

Because approximately 90 percent of NOX in the flue gas is NO, the reaction in Equation 15 dominates. This 6 [44; 56] means the ratio of NH3 inputs to NOX reductions is approximately 1:1. This allows coal-fired electric power plant to carefully manage reagent injection based on measured NOX concentrations in the flue gas

6 A higher NH3/NOX ratio would increase NOX reduction. However, a higher ratio also requires more catalyst surface area and may result in higher ammonia slip. Therefore, most SCR installations aim for a ratio near 1:1. 21 prior to the SCR (e.g., at the economizer outlet for hot-side high-dust configurations).7 This ratio should remain nearly constant to maximize NOX removal and reduce the risk of ammonia slip.

Also note that Equation 15 for SCR is the same as Equation 13 for SNCR. While the reactions are the same, the addition of the catalyst in the SCR makes it possible for the reaction to occur at lower temperatures. The optimal temperature range for the reactions is 350° C to 400° C. [36; 44; 52] For most coal-fired electric boilers, this temperature range is found near the economizer outlet, but before the air heater. In addition to temperature range requirements, SCR requires good mixing of ammonia and flue gas, an NH3/NOX ratio of approximately one or less, an oxygen concentration of 2 percent or more, and sufficient catalyst life. To enhance mixing prior to the catalyst, SCR typically use an ammonia injection grid located far enough upstream to ensure mixing and distribution of flue gas and ammonia across the catalyst. The ammonia injection grid consists of multiple nozzles over the cross-sectional area of the duct leading to the SCR (see Figure 21).

Figure 21: SCR Uses an Injection Grid to Achieve Good Mixing of Ammonia and Flue Gas

The performance of the SCR is affected by a number of factors, including flue gas velocity, temperature,

NOX concentration, and reagent distribution. Variations in the flue gas in a cross-section of the duct can create challenges for an SCR. However, it is common to have velocity, temperature, and/or NOX/ammonia concentration differences in flue gas. A typical heterogeneous flow might occur if some burners are out of service.8 For example, heterogeneous velocity in a hot-side high-dust SCR configuration (see below) can cause variation in catalyst plugging and fly ash erosion across the catalyst. [36] Variation in flue gas velocity is important at both the injection grid and the catalyst. At the point of the injection grid, differences in velocity can affect the ammonia concentration as the gas passes the grid. A uniform reagent injection rate could result in low ammonia concentrations in high-velocity zones and high ammonia concentrations in low-velocity zones. To address this, many injection grids have multiple independently controlled zones to match ammonia injection rates with flue gas velocity. Velocity differences at the catalyst can also affect

NOX removal and ammonia slip. High-velocity zones have reduced residence time in the catalyst bed

7 In addition to NOX concentration, other parameters, including pressure, temperature, and flue gas flow rate, are used to calculate the NOX flow rate to the SCR which is used to adjust the ammonia flow rate. 8 Burners out of service, or BOOS, is another approach to reduce NOX emissions. The BOOS approach stages combustion by shutting off fuel flow to one or more burners to create fuel rich and fuel lean zones. This approach is not widely implemented and has relatively limited impact on NOX emissions (i.e., approximately 10 percent NOX reduction). [72] 22 resulting in lower NOX reductions and unused ammonia. However, this may be balanced by low-velocity zones with increased residence time and increased NOX reduction and less ammonia slip.

To address the heterogeneous nature of the flue gas, many SCR installations include upstream flue gas flow correction, independently controlled injection zones, and/or downstream mixing. [36] Static mixing devices are often employed to create homogeneous conditions for: temperature, oxygen concentration, dust concentration, NOX concentration, ammonia concentration, and SO3 concentration. The disadvantages of static mixers include additional pressure drop and velocity disturbances downstream of the mixers.

The formulation of the catalyst in an SCR reactor can vary significantly and most designs are proprietary. In general, SCR catalysts for coal-fired electric power plants are made of an active phase of pentoxide with other metal oxides (e.g., or ) as promoters on a dioxide carrier. The amount of active material in the catalyst influences the catalyst͛s ability to reduce NOX. The greater the active material, the greater the ability to reduce NOX. In addition, a higher-activity catalyst is [5 7 ] less dependent on temperature. However, a high-activity catalyst also has a greater ability to oxidize SO2 [52] to form SO3. The choice of catalyst material, catalyst volume, and catalyst channel size are critical elements of an SCR system. The choice of catalyst formulation should be based on the flue gas composition, including fly ash constituents, quantity of fly ash (e.g., high-dust or low-dust configurations), temperature, and SO2 and SO3 concentration.

[57] In the catalyst, a portion of SO2 in the flue gas is oxidized to SO3. At lower temperatures (e.g., 315° C) , the SO3 reacts with ammonia to form (NH4)2SO4 and NH4HSO4 which can damage downstream pollution control equipment. In addition, SO3 passing through a wet flue gas desulfurization unit (FGD) will generally react with moisture to form sulfuric acid (H2SO4) which is emitted from the exhaust stack. There are options for minimizing this reaction. For example, reducing the amount of vanadium in the catalyst can reduce SO2-to-SO3 conversion, but this decreases catalyst activity and, therefore, increases catalyst volume. [52] Experience at several US coal-fired power plants shows that each layer of catalyst oxidizes [58] approximately 0.2 to 0.8 percent of SO2. Therefore, a reactor with three layers of catalyst would convert

0.6 to 2.4 percent of SO2 to SO3. The SO2-to-SO3 conversion rate of the catalyst also depends on the operating temperature. This makes it possible to lower the temperature to limit SO2-to-SO3 conversion while adding an additional catalyst layer to compensate for the reduced NOX control.

In US coal-fired electric power plants an SCR reactor contains two to four layers of catalyst. The flue gas passes through the layers in stages. As the catalyst is exposed to flue gas it slowly becomes deactivated,

ŵĞĂŶŝŶŐƚŚĞĐĂƚĂůLJƐƚ͛ƐĂďŝůŝƚLJƚŽƌĞĚƵĐĞNOX declines. The four primary mechanisms that reduce the ĐĂƚĂůLJƐƚ͛ƐĂďŝůŝƚLJƚŽƌĞĚƵĐĞNOX are: 1. Erosion: Fly ash and other solids can damage the catalyst surface, reducing the active surface area of the catalyst.

2. Pore plugging: Fly ash, solids, or NH4SO4 can block the pores of the catalyst. At temperatures above 350° C the conversion of SO2 to SO3 increases exponentially for most catalyst formulations,

resulting in higher NH4SO4 formation and, as a result, pore blockage. SCR can be designed to reduce plugging with larger channel size, improved homogeneity of flue gas velocity to eliminate ͞ĚĞĂĚnjŽŶĞƐ͕͟ĂŶĚƐŽŽƚďůŽǁĞƌƐŽƌƐŽŶŝĐŚŽƌŶƐƚŽƌĞŵŽǀĞĨůLJĂƐŚĨƌŽŵƚŚĞĐĂƚĂůLJƐƚďĞĚ͘ 3. Poisoning: Compounds (e.g., alkali ions ʹ , , , and ; ; and ) are chemically bound to the catalyst, reducing the amount of active material available to promote NOX reduction. 4. Sintering: At high temperatures the surface area of the catalyst is reduced, lowering the activity of the catalyst. [46; 57; 59; 60]

Before a catalyst is completely deactivated, it must be replaced.

In general, there are three configurations used for SCR systems at coal-fired power plants: 1) hot-side high- dust applications, 2) hot-side low-dust applications, and 3) tail-end applications.

23 Hot-side High-dust SCR Configuration The hot-side high-dust configuration is the most widely used SCR configuration, especially with dry bottom boilers, because it does not require reheating the flue gas to achieve the desired temperature range. In this configuration, the SCR is located after the economizer outlet but before the air heater and particulate controls (see Figure 22). This facilitates the reaction because the temperatures are often within the optimal range of 350° C to 400° C. Many high-dust SCR installations include an economizer bypass; in low-load conditions the bypass is used to ensure proper flue gas temperature for the SCR. In some coal-fired electric power plants, the ideal temperature range does not occur at a convenient location so special accommodations, such as a split economizer, must be included in the system design. [3 6 ]

Figure 22: High-Dust SCR Configurations Do Not Require Reheating of Flue Gas

As the name implies, a high-dust SCR is characterized by high ash levels in the flue gas because the reactor is located upstream of the particulate control device(s). This fly ash can degrade the catalyst shortening its lifetime (and increasing O&M expenses for the SCR system.) To reduce plugging of the catalysts, many high-dust designs have larger channels so the fly ash does not plug the channel. The catalyst beds also require extensive cleaning systems, usually in the form of sonic horns or soot blowers.

In addition, because space can be very limited between the economizer and air heater, this configuration often involves extensive modifications to the boiler backpass. [43] Changes may also be required on existing equipment to maintain efficient flue gas temperature and to adjust flue gas flow after the catalyst. [46]

Hot-side Low-dust SCR Configuration The hot-side low-dust configuration is not widely used because it requires a costly hot-side ESP to reduce particulate matter before the air heater. In a low-dust configuration, the SCR is located immediately downstream of the ESP and upstream of the air heater (see Figure 23). Like the high-dust configuration, the low-dust configuration does not require reheating the flue gas to achieve the desired temperature range. However, as the name implies, low-dust configuration has the advantage of being nearly free of fly ash

(although it does contain SO2). This reduces plugging of the catalysts and reduces catalyst degradation due to fly ash erosion.

Figure 23: Low-Dust SCR Configurations Requires a Hot-side ESP But Lower Ash Levels Reduce Catalyst Degradation

In general, this configuration is only used on facilities with existing hot side ESPs or where space constraints are a key factor in the design of the emission control system. Because hot-side ESPs are considerably more expensive than other particulate controls, their use is limited. In the US, only 12 percent of generating capacity at coal-fired electric power plants (40 GW at 230 units) is serviced by a hot-side ESP. [61]

24 Tail-end SCR Configuration The tail-end SCR configuration is commonly used with wet bottom boilers to avoid catalyst degradation caused by arsenic poisoning. It is also commonly used in retrofit applications when sufficient space is not available between the economizer and air heater. In this configuration, the SCR is located downstream of the particulate and SO2 controls (see Figure 24). Because the SCR is located after particulate and SO2 controls the sulfur oxides and particulates in the flue gas are very low and, therefore, have fewer problems with catalysts plugging, catalysts degrading due to fly ash erosion, and (NH4)2SO4 and NH4HSO4 formation. However, this configuration requires reheating the flue gas with auxiliary fuel to bring the flue gas temperature into the optimal range for the SCR.

Figure 24: Tail-end SCR Configurations Require Reheating of Flue Gas

Reheating the flue gas typically involves: 1) using heat exchangers to recover waste heat from the flue gas as it exits the SCR, and 2) using direct or indirect heating to raise the flue gas temperature an extra 50° C. [46] If direct heating (e.g., duct burners) is used for additional heat, the fuel must be free of soot to avoid degrading the catalyst. The use of direct or indirect (e.g., regenerative heat exchanger with high-pressure steam) heating, increasing the flue gas an additional 50° C requires 2 to 3 percent of boiler capacity [46; 62] but can be as high as 3 to 4 percent of boiler capacity. [4 5 ]

The advantages of tail-end SCR configuration include: x Longer catalyst life because there is less degradation of catalyst from fly ash erosion, poisoning, and plugging; [44; 46] x Less dependence on boiler load because flue gas temperature is managed independently; [36; 46] x Less catalyst required (and lower catalyst cost) because higher-activity catalyst can be used9 (and cost of catalyst); [4 3 ; 4 5 ; 4 6 ] x No impact on ash quality from ammonia slip. [46]

In retrofit applications the additional benefits of tail-end SCR configuration include less need for rebuilding boiler and duct work to accommodate the SCR near the boiler; more flexibility for locating the SCR unit; and shorter downtime for installation.

The disadvantage of tail-end SCR configuration is the cost associated with reheating the flue gas. [4 4 ; 4 5 ; 4 6 ] In many situations the cost of reheating is greater than the cost savings from the longer catalyst life in tail- [43] end SCR configurations.

Table 6 lists some of the impacts that SCR configuration has on catalyst requirements.

9 In theory, the greater volume of flue gas due to water from the SO 2 control device and possible air leakage from the air preheater means the tail-end SCR configuration should require greater catalyst volume than other SCR configurations. However, because most SO2 has been removed from the flue gas before reaching the catalyst, a higher-activity catalyst can be used than would be possible in a high-dust SCR configuration where the high-activity catalyst would oxidize the SO2 to SO3. In addition, the lower levels of fly ash allow for a more compact catalyst design with smaller channel widths. The result is that tail -end SCR configurations require significantly less catalyst volume than high-dust SCR configurations. 25

Table 6: Impact of SCR Configuration on Catalyst Requirements [46] High-dust Low-dust Tail-end Flue gas volume 100 102 120 (relative to high-dust) Catalyst type Anti-erosion Normal Normal Catalyst volume 100 85 90 (relative to high-dust) Catalyst life (years) 2-3 3-4 3-5 Reheating required No No Yes

As with SNCR, high ammonia slip can make fly ash utilization unsuitable and pollute emission control equipment after the SCR system. In addition, unreacted ammonia can react with SO3 to form (NH4)2SO4 or NH4HSO4 that can foul downstream equipment.

The removal efficiency of SCR systems is around 90 percent at most US coal-fired electric power plants. However, the actual removal rate can vary significantly based on operating conditions and catalyst deactivation. During the 2007 ozone season, NOX emission rates from coal-fired power plants with SCR ranged from 10 grams to 94 grams10 per million Btu (see Figure 25).

[28] Figure 25: NOX Emission Rates at Coal-fired Electric Power Plants with SCR Vary Widely (2007 Ozone Season) 50 45 40 35 30 25 20 15 (2007Ozone Season) TrillionBtu Heat Input 10 5 - 0 20 40 60 80 100 NOX Emission Rate (grams/million Btu)

Case Study: Selective Catalytic Reduction Retrofit at Two 1,300 MW Coal-fired Boilers General James M. Gavin Power Plant is a 2.6-Gigawatt coal-fired power station in Cheshire, Ohio operated by American Electric Power. It is the largest coal-fired electric power plants in Ohio, and one of the largest in the US. dŚĞƉůĂŶƚ͛Ɛ two units, cell burners rated at 1,300 MW each, began operation in 1974 (Unit 1) and 1975 (Unit 2). In addition to the two large boilers, the plant includes two 250 meter exhaust stacks, 12 ESPs, 6 FGDs, 224 LNBs, and 6 SCRs (see Table 7). The General Gavin power plant combusts bituminous coal from Ohio with an average sulfur content of 3.7 percent, ash content of 9.5 percent [6 1 ], content of 2

10 The emission data reported to EPA do not include information about SCR operation. Therefore, these data may reflect less than full-time use of the SCR control equipment. 26 percent, and of 0.75 percent. [43]

Table 7: Pollution Controls at AEP General James M. Gavin Power Plant [61] Pollutant Control Install Date Particulates Cold-side ESP 1974 and 1975

SO2 Wet lime FGD 1994 and 1995 NOX LNBs 1998 and 2001 SCR 2001 and 2002

SO3 Trona injection 2002

Each SCR is a hot-side high-dust configuration with three catalyst reactors (one for each air preheater) and four layers of catalyst (three initial layers and one spare) designed to control 90 percent of NOX, limit [6 3 ] ammonia slip to less than 2 ppm, and keep SO2-to-SO3 conversion to no more than 1.6 percent. The original designs were for an anhydrous ammonia SCR that would have required on-site storage of approximately 1,362,750 liters of ammonia for use as a reagent in the SCR. [64] However, due to safety concerns from neighboring residents who were worried about the risk of accidental release from the transport, handling, and storage of ammonia, the SCR was modified to use a urea-based system. [65] Prior to injecting the reagent in the flue gas, the urea is converted to ammonia. Unlike anhydrous ammonia which is poisonous and dangerous, storage of urea in its dry, granular form poses no serious handling challenges or potential health hazards. Gavin was only the third power plant in the US to employ this urea-to- ammonia system. [66] The cost of the urea-to-ammonia reagent system was approximately $28 million. [67]

In 2001, the first SCR went online. But the SCR significantly increased emissions of SO 3. During hot and humid days these emissions covered the neighboring town in a thick blue haze. Residents of the town took legal action against the Ge ne ral Gavin power půĂŶƚ͛ƐŽǁŶĞƌʹ American Electric Power ʹ in an effort to ƌĞƋƵŝƌĞŐƌĞĂƚĞƌĞŵŝƐƐŝŽŶƌĞĚƵĐƚŝŽŶƐĂŶĚĞůŝŵŝŶĂƚŝŽŶŽĨƚŚĞ͞ďůƵĞƉůƵŵĞ͘͟/ŶϮϬϬϮƚŽϮϬϬϯ͕ŵĞƌŝĐĂŶ Electric Power settled with the community and agreed to purchase the town and relocate its residents. [68] dŚĂƚƐŽůƵƚŝŽŶƚŽƚŚĞůĞŐĂůĐŚĂůůĞŶŐĞƐĚŝĚŶŽƚ͕ŚŽǁĞǀĞƌ͕ĞůŝŵŝŶĂƚĞƚŚĞŶĞĞĚƚŽƌĞĚƵĐĞƚŚĞƉŽǁĞƌƉůĂŶƚ͛Ɛ^K 3 emissions.

To address the high SO3 emissions, American Electric Power replaced all the catalyst in 2005 with a new [63] low-SO2-to-SO3-conversion catalyst designed by Babcock-Hitachi . This was accompanied by a three- point injection system to control SO3 emissions. The injection system injects water, magnesium hydroxide, [69] and calcium hydroxide into the flue gas at specific points to reduce SO3 levels. The new system, installed in 2002, cost approximately $8 million. Based on performance tests in the spring of 2005, the new catalyst [6 3 ] had a 0.1 percent SO2-to-SO3 conversion rate.

While the SCR are typically in operation only during the ozone season, the SCR at units 1 and 2 have demonstrated a consistent ability to reduce NOX emissions by 90 percent (see Figure 26)

27 [28] Figure 26: The SCR at General Gavin Unit 1 Reduces Ozone Season NOX Emissions by Approximately 90 Percent

450 Unit 1 300

150

0 450 Unit 2 300 Emission Rate (grams/million Btu) Emission (grams/million Rate X

150

0 Daily AverageNO Daily 1/1/2003 4/1/2003 7/1/2003 1/1/2004 4/1/2004 7/1/2004 1/1/2005 4/1/2005 7/1/2005 1/1/2006 4/1/2006 7/1/2006 1/1/2007 4/1/2007 7/1/2007 10/1/2003 10/1/2004 10/1/2005 10/1/2006 10/1/2007

Emerging and Advanced Control Technologies

There are several promising new technologies to reduce NOX emissions from coal-fired electric power plants. A very brief summary of some of those technologies is presented below.

SOx-NOx-ROx Box

The SOx-NOx-ROx Box process is a multi-pollutant control that removes SO2, NOX, and particulates in a single control device ʹ a high-temperature baghouse. The baghouse operates between the economizer and air heater in the temperature range of 425° C to 455° C. The baghouse removes NOX in the same manner as an SCR. Ammonia is injected into the flue gas after which a catalyst on the high-temperature ceramic filters of the baghouse completes the reaction (see Equation 15). SO2 is reduced with a calcium- or sodium-based sorbent. In demonstration projects, the SOx-NOx-ROx Box has reduced NOX by 90 percent with a 0.9 [44; 70] NH3/NOX ratio.

Electron Beam The electron beam (E-beam) process involves cooling the flue gas to 60° C after the particulate controls, injecting ammonia, and then discharging high-energy electrons into the flue gas. The main component of the E-beam process is an irradiation chamber where the flue gas is irradiated by a beam of high-energy electrons while water is added to counteract the temperature rise. The irradiation generates hydroxyl radicals and oxygen atoms, which oxidize the SO2 and NOX. These oxidized species mix with water in the flue gas to form H2SO4 and HNO3, which are neutralized by the ammonia, creating solid ammonium sulfate and ammonium sulfate-nitrate. These byproducts can be collected downstream and sold as fertilizer. In [70] demonstration projects, the E-beam process has reduced NOX by 90 percent with at least 2.7 millirad.

Electro-catalytic Oxidation Electro-catalytic Oxidation, or ECO, is a multi-step emission control process. First, a conventional dry ESP removes most of the particulates. Second, a barrier discharge reactor oxidizes gaseous pollutants to higher

28 oxides (e.g., NO їHNO3, SO2 їH2SO4, Hg ї HgO). Finally, a wet ESP removes the oxidized pollutants and fine particulate matter. The effluent from the wet ESP can be treated to remove the byproducts for use as gypsum, fertilizer, or concentrated sulfuric and nitric acids. In demonstration projects, the ECO process has [7 0 ] reduced NOX by 90 percent. Technology Performance and Costs

Emission reduction and control technologies for NOX are highly dependent on overall plant design, coal quality, and emission reduction requirements. The following cost estimates (see Table 8 and 9) are based on EPA [71]and IEA [45] published data, updated to reflect 2007 US dollars.

Table 8: Combustion Modification Performance and Costs Based on 300 MW Coal-fired Unit Technology Boiler Type Cost Capital Cost Fixed O&M Variable ($/MW) ($/MW year) O&M ($/MW hour) LNB Dry-bottom wall- $21,120 $318 $0.065 fired LNB & OFA Dry-bottom wall- $28,670 $439 $0.088 fired LNB & CCOFA Tangential $11,130 $176 $0.00 LNB & SOFA Tangential $15,550 $231 $0.03 LNB & Tangential $17,770 $274 $0.03 CCOFA/SOFA

To convert the capital cost and fixed O&M costs in Table 8 for a different boiler size use the following equation:

300 0.359 Equation 18: ܭܤ = ܭ300 × ቀ ቁ ܯܹܤ

Where KB = cost for X MW boiler K300 = cost for 300 MW boiler from Table 8 MWB = size of boiler in MW

Note that no scaling factor is applied to variable O&M costs.

Table 9: Post-combustion Controls Performance and Costs Technology Performance (NOX removal) Cost Capital Cost Fixed O&M Variable O&M ($/MW) ($/MW year) ($/MW hour) SNCR ʹ 35 percent Tier 1 $20,922 $307 $1.08 Pulverized Coal Tier 2 $23,864 $362 $1.08 SNCR ʹ CFB 50 percent $20,966 $318 $0.93 SCR 90 percent to $122,371 $812 $0.74 27 grams per million Btu

To convert the SNCRͶpulverized coal capital cost and fixed O&M costs in Table 9 for a different boiler size (between 25 and 200 MW) use the following equation:

200 0.577 100 0.581 Equation 19: ܭܤ = ൬ܭܶ݅݁ݎ 1 ܺ ቀ ቁ + ܭܶ݅݁ݎ 2 ܺ ቀ ቁ ൰ൗ2 ܯܹܤ ܯܹܤ Where KB = cost for X MW boiler

KTier1 = Tier 1 cost from Table 9

29 KTier2 = Tier 2 cost from Table 9

MWB = size of boiler in MW

To convert the SNCRͶCFB capital cost and fixed O&M costs in Table 9 for a different boiler size use the following equation:

200 0.577 Equation 20: ܭܤ = ܭ200 × ቀ ቁ ܯܹܤ

Where KB = cost for X MW boiler K200 = cost for 200 MW boiler from Table 9

MWB = size of boiler in MW

To convert the SCR capital cost and fixed O&M costs in Table 9 for a different boiler size (up to 600 MW) use the following equation:

242.72 0.27 Equation 21: ܭܤ = ܭ242.72 × ቀ ቁ ܯܹܤ

Where KB = cost for X MW boiler

K242.72 = cost for 242 MW boiler from Table 9 MWB = size of boiler in MW

To convert the SCR variable O&M costs in Table 9 for a different boiler size (up to 600 MW) use the following equation:

242.72 0.11 Equation 22: ܭܤ = ܭ242.72 × ቀ ቁ ܯܹܤ

Where KB = cost for X MW boiler K242.72 = cost for 242 MW boiler from Table 9

MWB = size of boiler in MW

30

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