Energy Futures and Urban Air Pollution: Challenges for China and the United States (2008)

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6 Coal Combustion and Pollution Control Coal accounts for a major fraction of the combustion material used worldwide to produce electricity, and coal generation plants account for a major fraction of the stationary sources of air pollution worldwide. As such, the technologies for coal combustion and control of its air pollution are so significant that they warrant an extended discussion. There are a variety of combustion processes in both countries that have variable impacts on the environment. Traditional processes tend to dominate the energy scenario, although both countries are paying increasing attention to energy efficiency and to cleaner technologies, in order to address rising fuel costs and concerns over emissions. This section describes in detail some of the main processes, their purposes, and their relative contribution to emissions. COMBUSTION PROCESSES Pulverized Coal Traditional pulverized coal (PC) plants account for 99 percent of all coal-fired plants in the United States and over 90 percent worldwide. The technology is well developed and suitable for a variety of coals, although it is not always appropriate for high-ash coals. High combustion temperatures lead to NOx formation, which enters the flue gas along with SO2. CO2 is released in the flue gas at atmospheric pressure and at a relatively low volume (10-15 percent), which presents difficulties in sequestering the carbon, as is discussed later in the chapter. The main distinction among boiler types is the pressure at which they oper- ate. Subcritical boilers are a first-generation technology, with thousands in use 187 

188 ENERGY FUTURES AND URBAN AIR POLLUTION throughout the world. Supercritical plants are widely used in the United States, Europe, Russia, and Japan, with a limited number in operation in South Africa and China. Europe and Japan have also constructed ultra-supercritical plants, which demonstrate even higher efficiencies than do their supercritical counterparts. However, without successful commercial application in the United States, the ultra-supercritical technology is still considered to be unproven and a potential technical and economic risk (EPA, 2006). Supercritical power generation tech- nologies have been considered to be the standard in the electric power industry. Though larger demonstration plants are under development, the average capacity of supercritical plants is between 300 and 600 MW. Increasing thermal efficiency has been a goal of many PC-fired plants, although low energy prices often serve as a disincentive to implement more efficient methods. Nevertheless, this represents a potentially cost-effective way to reduce CO2 and other emissions and to decrease fuel consumption. Methods such as reducing the excess air ratio, reducing stack gas exit temperature (while recovering the heat), and increasing steam pressure and temperature have all been utilized at various times over the past several decades. Fuel type has an impact on efficiency, as does the type of plant. Older subcritical plants using poor-quality coal can have thermal efficiencies as low as 30 percent, while modern subcritical plants tend to operate between 35 and 36 percent. Meanwhile, modern super- critical plants typically operate in the 43-45 percent range (IEA, 2006a). As a reference, a 1 percent increase in efficiency can reduce specific emissions such as CO2, NOx, and SO2 by 2 percent (World Bank, 2006b). Moreover, installation costs are only 2 percent more for supercritical plants as opposed to subcritical, while operation costs are comparable and fuel costs, due to higher efficiency, are lower for supercritical systems. China has recently been focused on adapting supercritical technologies from abroad. The Henan Qinbei power plant, a 600 MW demonstration plant, is a supercritical coal-fired plant utilizing domestically designed technologies, and has been online since late 2004. Another domestic supercritical demonstration plant with a capacity of 1,000 MW—Zhejiang Yuhuan—is under construction. Table 6-1 illustrates the growth of China’s power generation industry since 2000, and highlights the dominant role of thermal power, 98.7 percent of which comes from coal combustion. Fluidized Bed Combustion Fluidized bed combustion (FBC) is considered to be a clean coal technology and can be particularly useful for high-ash coals. It evolved as a result of efforts to develop a combustion process able to control pollutant emissions without imple- menting external controls, such as scrubbers. Coal particles are fed into a com- bustion chamber, suspended on jets of forced air, and combusted at 800-900ºC, yielding less NOx formation in comparison to PC combustion. In the process, the 

COAL COMBUSTION AND POLLUTION CONTROL 189 TABLE 6-1  Development of China’s Installed Power Capacity and Power Generation in Recent Years 2000 2001 2002 2003 2004* Installed Thermal capacity 237540 253012 265547 289771 324900 Capacity Proportion of total 74.4 74.8 74.5 74.0 73.7 (MW) (percent) Annual growth (percent) 6.3 6.5 5.0 9.1 12.1 Hydro capacity 79352 83006 86074 94896 108260 Proportion of total 24.9 24.5 24.1 24.2 24.6 (percent) Annual growth (percent) 8.8 4.6 3.7 10.3 14.1 Nuclear capacity (MW) 2268 2268 4586 6364 7014 Proportion of total 0.71 0.67 1.3 1.6 1.6 (percent) Total 319321 338487 356571 391408 440700 Annual growth (percent) 6.9 6.0 5.3 9.8 12.6 Power Thermal power 1107.9 1204.5 1352.2 1579.0 1807.3 Production Proportion of total 81.0 81.2 81.7 82.9 82.6 (billion (percent) kWh) Hydro power 243.1 261.1 274.6 281.4 328.0 Proportion of total 17.8 17.6 16.6 14.8 15.0 (percent) Nuclear power 16.7 17.5 26.5 43.9 50.1 Proportion of total 1.2 1.2 1.6 2.3 2.3 (percent) Total 1368.5 1483.9 1654.2 1905.2 2187.0 Annual growth (percent) 11.0 8.4 11.5 15.2 14.8 SOURCE: CEC, 2004. flue gas is brought into contact with a sulfur-absorbing material such as limestone, resulting in 95 percent of the sulfur being captured inside the boiler without need for external controls. Although this represents less than 2 percent of the world total of coal-fired power, it has grown significantly between 1985 and 1995, and is utilized in hundreds of small units in China (IEA, 2006a). FBC’s popularity is ascribed to its fuel flexibility as well as to its ability to control SO2 and NOx emissions independent of costly add-on controls. In terms of fuel flexibility, although these units can be designed for co-firing and can accom- modate low-grade fuels including municipal waste, they operate most efficiently when utilized with the originally intended design fuel. A number of atmospheric FBC boilers of sizes from 250 to 300 MW are in use commercially, but are more common at smaller sizes for process heat and on-site power supply. The thermal 

190 ENERGY FUTURES AND URBAN AIR POLLUTION efficiency of these units is typically lower (3-4 percent) than are similar size PC combustion boilers, as heat loss is considerable (IEA, 2006a). Pressurized FBC builds on the earlier atmospheric pressure technologies. While still in the demonstration phase, it already shows advantages over atmo- spheric FBC and traditional PC combustion. Its compact design is suitable to modular construction and makes for easier retrofits compared to conventional FBC units. It has lower capital costs than IGCC plants or PC plants outfitted with pollution controls, and has a higher potential (45 percent); it has demonstrated (40-42 percent) thermal efficiency in contrast to many PC plants. While initial capital costs are typically higher than the cost range for a PC plant, other factors, specifically add-on pollution controls, make FBC plants cost-competitive (World Bank, 2006a). Size seems to be the limiting factor, since the demonstration plants are all 70 MW plants. However, Japan is constructing a 350 MW demonstration plant. Pressurized FBC is categorized into two technologies: bubbling-bed and circulating. Bubbling-bed technology is the first-generation pressurized FBC technology and is in use as a demonstration at the Tidd Plant in Ohio, the result of a joint project between the U.S. Department of Energy (DOE) and the American Electric Power Corporation. A second generation pressurized fluidized bed com- bustor uses circulating fluidized-bed (CFB) technology and a number of efficiency enhancement measures. CFB technology has the potential to improve operational characteristics, by using higher air flows to entrain and move the bed material, and by recirculating nearly all of the bed material with adjacent high-volume, hot cyclone separators. The relatively clean flue gas goes on to the heat exchanger. This approach theoretically simplifies feed design, extends the contact between sorbent and flue gas, reduces the likelihood of heat exchanger tube erosion, and improves SO2 capture and combustion efficiency. In China and potentially in other coal-rich developing countries, CFB may be one of the most important power generation technologies in the future. This technology is mainly adopted in low-quality coal-burning power plants, and is also used in cogeneration (heat and power) plants. CFB boilers were first introduced in China in the 1980s at low capacities. A 300 MW CFB boiler demonstration proj- ect is under construction at the Neijiang Baima power plant in Sichuan province. Domestic CFB boilers with capacities less than 200 MW are already in use at the industrial scale; 300 MW CFB boilers with independent intellectual property rights are also currently at the research and production stage. Integrated Gasification Combined Cycle Integrated gasification combined cycle technology, or IGCC, represents per- haps the most promising technology for utilizing coal, while at the same time decreasing environmental impacts. In the United States, the Environmental Protec- tion Agency (EPA) and DOE have been cooperating to advance and commercialize 

COAL COMBUSTION AND POLLUTION CONTROL 191 the technology. In the coming decades, it will likely be the competing technology, along with PC combustion, in coal-based power generation. Its potential for CO 2 capture is particularly promising. Overall, these plants have less of an environ- mental impact than do traditional PC plants; emissions are lower, they consume significantly less water, and they generate less solid waste (EPA, 2006). The United States currently has 20 coal gasification plants, two of which produce power. Many of these plants were installed at petroleum and chemical plants. Additional plants are in various stages of development, with plans to use coal to generate electricity along with co-products, including hydrogen, ammonia, chemicals, fertilizers, and Fischer Tropsch liquids (NETL, 2005). These plants have been made possible by government subsidies and have experienced technical and commercial problems, as is common for many new technologies (EPA, 2006). These early plants can play an important role in demonstrating and perfecting the technology to make IGCC-based power plants suitable for wider commercial deployment (NRC, 2003). Twenty-four additional coal-fired plants using IGCC have been proposed as of June 2006, thanks in part to a 20 percent investment tax credit for IGCC, as part of the U.S. Energy Policy Act of 2005. Little research has been done on applying low-rank coals to IGCC technology; current plants use bituminous coals and, therefore, comparisons to sub-bituminous or lignite coals are difficult (NRC, 2003). According to the recent EPA study, when assess- ing commercial applications within the United States, IGCC has better thermal performance than do subcritical and supercritical PC plants (see Table 6-2). China has been an industry leader in exploring IGCC technologies. In Yantai, Shandong province, an IGCC power plant of capacity 300-400 MW has been in development for years. However, due to economic constraints, it has yet to be constructed. In 2005, the Chinese Huaneng Group Corporation brought for- ward the coal based polygeneration system, nicknamed “Green Coal Power.” In O ­ ctober of the same year, the Huaneng Group joined the U.S. DOE’s “Future Gen” Enterprise Alliance; and in December, Huaneng formed Green Coal Power Ltd with the Chinese Shenhua Group Corporation, the Chinese Coal Energy Group Corporation, and with five power corporations as member companies (see Box 6-1). The primary aim of this company is to research and demonstrate coal gasification-based energy systems producing hydrogen as a by-product and power source, and outfitted with CO2 separation technologies. At present, they are working on changing gas and steam combined-cycle power generation sets with a capacity of 100 MW into an independent intellectual property rights IGCC system, with a capacity of 120 MW. New coal power plants are long-term construction projects, requiring 3-4 years to place into service after groundbreaking. Adding site evaluation, permit- ting, financing, and other upfront project planning time means that even plants currently under initial development will not provide power until 2010-2012 at the earliest. 

192 TABLE 6-2  Generation Performance Comparison Bituminous Coal Subbituminous Coal Lignite Coal Performancea IGCC Sub- Super- Ultra- IGCC Sub- Super- Ultra- IGCC Sub- Super- Ultra- Slurry critical critical Super- Slurry critical critical Super- Solid critical critical Super- Feed PC PC critical Feed PC PC critical Feed PC PC critical PC PC PC Net Thermal 41.8 35.9 38.3 42.7 40.0 34.8 37.9 41.9 39.2 33.1 35.9 37.6 Efficiency, percent Net Heat Rate, 8167 9500 8900 8000 8520 9800 9000 8146 8707 10,300 9500 9065 Btu/kWh Gross Power, 564 540 540 543 575 541 541 543 580 544 544 546 MW Internal Power. 64 40 40 43 75 41 41 43 80 44 44 46 MW aBased on a net 500 MW plant. SOURCE: EPA, 2006. 

COAL COMBUSTION AND POLLUTION CONTROL 193 BOX 6-1 United States-China Cooperation on FutureGen Led by the FutureGen Industrial Alliance, Inc., and with support from the U.S. Department of Energy, FutureGen is a government-industry partnership created in response to President George W. Bush’s call for an increase in hydrogen power research to reduce the negative impact of current energy emissions on global cli- mate change. The FutureGen Alliance is a non-profit organization, created in 2005, that represents major coal users and producers. On December 15, 2006, China entered into an agreement with the United States to join the Government Steering Committee. In addition to government participation, key energy companies from both countries have joined the partnership. The China Huaneng Group, a member since 2005, is one of the top ten energy producers in world and China’s largest coal-fired power producer. By recognizing the need for clean energy produced from coal, the FutureGen Alliance believes that its operation can facilitate continuing economic growth within the United States, while serving as a model for future hydrogen-based energy plants around the world.a Instead of releasing harmful emissions during energy production, the FutureGen plant will store carbon dioxide in deep saline formations and will emit hydrogen and other particles that can be used by other industries in their production processes. By exploring current technologies on coal gasification, electricity generation, emissions control, carbon dioxide capture and storage, and hydrogen production the FutureGen plant will be a pioneer in the field of hydrogen power research by testing all of these technologies at one facility. By converting the carbon within coal into a gas, the FutureGen plant will produce a gas that is primarily made up of hydrogen and carbon monoxide, thus producing an environ- mentally clean by-product for use in powering turbines to produce electricity. Other uses for the hydrogen by-products include fuel cells, combustion turbines, and other hydrogen-based technologies. Another important factor in hydrogen power-related research is the facility’s l ­ocation. FutureGen has selected four candidate locations for their test facility: M ­ attoon, IL, Tuscola, IL, Heart of Brazos near Jewett, TX, and Odessa, TX. These sites were selected based on the environmental and financial considerations of us- ing each site for FutureGen’s operation. In the fall of 2007, a decision will be made by the FutureGen Alliance as to which site will be home to the FutureGen facility. There are multiple benefits to choosing this process. First, FutureGen’s tech- nologies could have a major impact on national energy security. FutureGen’s process of energy production also has a very low impact on climate change by storing the carbon dioxide removed from coal during the gasification process. Thus, carbon dioxide emissions, which negatively impact the earth’s climate, will drasti- cally be reduced during this process. Through FutureGen’s process of using coal to produce a cleaner, cost-efficient energy source, countries around the world could rely on their domestic supply of coal to provide energy to growing populations. When the FutureGen plant is operational, it will be the “environmentally cleanest fossil fuel-fired power plant in the world.”b In 2012, FutureGen anticipates to be in operation and will be the first plant producing hydrogen from coal and electricity at the same time. aFutureGen Alliance. 2006. http://www.futuregenalliance.org/. bU.S. Department of Energy. 2006. “FutureGen—Tomorrow’s Pollution-Free Power Plant.” http://www.fossil.energy.gov/programs/powersystems/futuregen/. 

194 ENERGY FUTURES AND URBAN AIR POLLUTION For the first round of new capacity, most generators in the United States have chosen a subcritical or supercritical PC or CFB, as well as a higher temperature European/Japanese ultra-supercritical PC (USC/PC). All of these plants are being designed to significantly exceed new source performance standards. Within the next 5 years, the industry will have to introduce the next generation of advanced IGCC and U.S-designed USC/PC, bringing continued advancements in effi- ciency and environmental performance, including the capability for CO 2 capture. Box 6‑2 details some of these clean coal technologies. Federal, state, and local support may be required to coordinate permitting and approvals, and regulatory and permitting agencies need to support the introduction of each generation of new technology. BOX 6-2 Comparing Clean Coal Technologies Several clean coal technologies are currently available, categorized as ad- vanced high-efficiency combustion-based technologies and gasification-based technologies, and technologies are being developed that will allow capture of carbon dioxide in both advanced combustion and gasification plants. Advanced combustion technologies combust coal in the presence of air or oxygen. Gasifica- tion technologies use a partial combustion of coal, in the presence of either air or oxygen, to produce a synthetic fuel gas (NCC, 2006). Emerging technologies at initial commercialization include: • IGCC with air or oxygen blown gasification to produce syngas for use in combustion turbines, with plant efficiencies of 39-43 percent • PC/Ultra-supercritical steam plants of European and Japanese design, pro- viding efficiencies of 40-42 percent Developing technologies include: • Advanced IGCC with hydrogen production and CO2 capture (FutureGen) • PC/USC steam plants, providing efficiencies of 48 percent • Advanced USC PC/CFB, with efficiency goals of 50 percent prior to CO2 capture • Innovative post-combustion capture technologies with reduced cost and power usage for PC/CFB technologies • Advanced PC/CFB with oxygen combustion to facilitate capture of CO2 e ­ missions Future technologies include: • Hybrid cycles (IGCC with fuel cell) • Chemical looping combustion and gasification • Next-generation PC/CFB oxyfuel plants 

COAL COMBUSTION AND POLLUTION CONTROL 195 POLLUTION CONTROLS Installing pollution controls is another means to reduce specific emissions. Most of these controls are designed to reduce a particular pollutant (e.g. SO 2), although there are some co-benefits to installed controls, such as mercury emis- sions reductions, as will be discussed. Since these pollution controls have devel- oped in response to concerns over air pollution, or in many cases, regulations regarding emissions, they are often installed as a retrofit onto an existing facility. Retrofits have become an essential pollution-control strategy for U.S. energy producers, in order to come into compliance with mandated emissions reductions. Retrofits necessarily entail additional costs, because the new technology must be incorporated into an existing structure (IEA, 2006b). As an example, the original cost of the Plant Bowen coal-fired power plant in Georgia was $400 million in the early 1970s (roughly $1.4 billion in 2005$). Adding NOx control devices in the 1990s cost about $400 million more. The current addition of sulfur dioxide scrubbers is costing another $900 million (Marr, 2006). Altogether, Georgia Power (which operates Plant Bowen and nearby Plant Hammond) plans to spend $1.3 billion on pollution-control devices by 2010, in order to come into compli- ance with federal regulations. China has taken an important first step by requiring new coal-fired power plants to install desulfurization equipment. This has been a direct result of con- cerns over China’s world-leading SO2 emissions. However, a similar requirement for NOx controls does not currently exist, though the government began pilot projects in 2004 to implement a NOx levy of 0.6 RMB/kg. While some plants in China are voluntarily installing low-NOx burners on new facilities, fewer are investing in additional NOx controls. The importance of building in pollution controls cannot be overstated. This of course does not diminish the importance of retrofitting existing facilities with pollution controls, but as both countries consider expanding power generation capacity, much of this coal-fired, there is a significant opportunity to plan for these pollution controls at the outset. While this entails higher initial costs, as experience has shown, costs and installation times increase significantly for retrofits. Finally, in light of the possibility that future regulations may limit CO2 emissions, some power companies are taking steps to prepare for installing further equipment to capture and sequester CO 2, should it become a regulated emission. Coal-fired power plants are also a source of dioxins and furans, 2 of the 12 persistent organic pollutants (POPs) that China, the United States, and numerous other countries are beginning to regulate. China ratified the Stockholm Conven- tion on POPs in 2004 and is making progress in eliminating the manufacture and use of certain POPs (mostly pesticides) (NRC, 2007). Reductions in dioxin and furan emissions, which are unintentional by-products of combustion processes and chemical manufacturing, can be partially achieved by improving pollution controls on combustion sources. Installing particulate controls has the co-benefit of reducing dioxin emissions. 

196 ENERGY FUTURES AND URBAN AIR POLLUTION Coal Preparation Coal preparation, in a broad sense, is any treatment of mined coal to remove waste, and includes crushing, screening, and washing. Approximately 70 percent of raw coal in China is currently burned without crushing and screening it; this has an important impact on emissions of sulfur dioxide and particulate matter, accounting for 70-80 percent of China’s total emissions (NDRC, 2005). ­However, coal preparation can increase heating values, decrease transportation costs, and reduce pollutants before they are released into the air, notably SO2 and Hg. Coal washing in China could reduce sulfur emissions by 20 percent, but requires invest- ments at the mines, which nationwide would total at least 16 billion RMB (NRC, 2004). Additionally, coal briquettes with limestone additive (to reduce SO 2) are used in domestic heating and cooking, but are also appropriate for small industrial boilers: an investment of 2 billion RMB could yield 113 million tons of briquettes, which would help reduce ground-level pollution from the millions of small indus- trial boilers (NRC, 2004). Though burning low-sulfur coal is the most economical way to reduce SO2 emissions, wide-scale substitution would require major disrup- tions and changes to the mining and transportation networks. Particulate Controls Electrostatic Precipitators Electrostatic precipitators (ESPs) are particulate collection devices which use an induced electrical charge to remove particles from flue gas. ESP has been the preferred technology for use at coal-fired power plants. They are highly efficient at particulate removal (typically 99.0-99.5 percent) and have minimal impact on air flow through the device. Since they do not require a large pressure drop, they have less of an impact on plant efficiency, compared to fabric filters. One primary challenge to an ESP’s efficiency is electrical resistance, which can result from combustion of low-sulfur coal. Though this is typically a dry process, it is possible to spray incoming air with moisture, which can improve the capture of fine particles, as well as reduce the electrical resistance of the incoming particles. Dry ESP waste is adsorbed onto metal plates, then rapped to remove the particu- late matter for disposal or potentially reuse (e.g., fly ash used in cement). Wet ESP waste is flushed with water for treatment or disposal. At present more than 96 percent of the coal power plants in China have ESP. Fabric Filters Fabric filters, alternately referred to as baghouses, have been employed more widely than ESP since the 1970s, largely at the industrial scale (IEA, 2006c). China has seen a similar increase in the use of baghouses, not only for industrial purposes but also for use at power plants. The choice between ESP and fabric 

COAL COMBUSTION AND POLLUTION CONTROL 197 filters depends on coal type, plant size, and boiler type and configuration; addi- tionally, if regulations require removal efficiency above 99.5 percent, fabric filters may be more cost-effective (World Bank, 2007). However, fabric filters require a decrease in pressure and thus a decrease in plant efficiency. Flue Gas Desulfurization Wet flue-gas desulfurization (FGD), commonly referred to as wet scrubbers, is a well-established process for significantly reducing SO2 emissions. Design efficiencies range from 80 to 95 percent SO2 removal, and with additives, this can be improved by 5-10 percent. FGD continues to be the preferred technology for both retrofits and new construction of power plants, particularly in Europe, Japan, and the United States (World Bank, 2006d). Although its effectiveness has been demonstrated on both high- and low-sulfur coals in developed countries, the applicability to local coals in developing countries, such as China, sometimes requires further adaptation. Although wet scrubbers can also be utilized in particulate removal, they are most effective when coupled with ESP or filters (EPA, 2002b). Wet scrubbers consist of a spray tower or absorber where flue gas is sprayed with a calcium- based water slurry. The calcium and SO2 react to form calcium sulfite or sulfate, which can then be thickened, dewatered, and mixed with fly ash for disposal in landfills. Alternatively, the waste can be turned into gypsum for reuse. Limestone with forced oxidation is the process by which the calcium sulfite created in the wet scrubber is oxidized by bubbling compressed air through the slurry to produce wallboard-grade gypsum. In the United States, this technology is useful when connected to local markets for wallboard, cement, and other applications. Dry scrubbers are an alternative application for SO2 removal. Instead of saturat- ing the flue gas, dry FGD uses little or no moisture and thus eliminates the need for dewatering. Dry FGD’s efficiency is slightly lower than wet FGD (70-90 percent), but capital costs are also lower, and the scrubbers are easier to operate and main- tain. Dry scrubbers have been proven with low-sulfur coal in the United States and elsewhere, but their applicability for use with high-sulfur coals has not been widely demonstrated (World Bank, 2006d). Moreover, as wet scrubbers become more competitive in terms of ease of use and cost, dry scrubbers lose their competitive advantage. More than 20 percent of coal-fired utility boiler capacity in the United States uses wet FGD; roughly half that amount uses dry FGD technology (EPA, 2002b). The United States has been a leader in deploying FGD technology, mostly as a result of stringent regulations which required their use (Rubin et al., 2003). Figure 6-1 shows projected U.S. capacity of coal-fired burners with some sort of FGD technology installed. The figure also projects the potential impacts of retrofits based on CAIR, CAMR, and CAVR—legislation which places caps on SO2, NOx, and mercury. Though only about one-third of coal-fired capacity currently has FGD installed, this share is projected to increase to over 70 percent by 2020. 

198 ENERGY FUTURES AND URBAN AIR POLLUTION 250 200 90.8 150 72.3 36.0 22.7 100 110.3 115.9 117.0 50 101.6 0 2005 2010 2015 2020 Year Existing or NOx SIP Call/State Retrofit New PC and IGCC Capacity Retrofit for CAIR/CAMR/CAVR FIGURE 6-1  Projected U.S. capacity of coal-fired burners with FGD technology. SOURCE: EPA, 2005. China has recently begun adopting and adapting FGD technologies. New 6-1 power plants are now required to install FGD equipment. There are more than ten kinds of FGD technologies, which have been applied in power stations through- out China. At the end of 2003, the total power capacity equipped with FGD was 45,315 MW, or about 16 percent of the total (including power plants completed, under construction. and invited for public bidding). Limestone-gypsum wet desul- furization was 84 percent of the total FGD capacity. China possesses independent intellectual property rights on the limestone-gypsum desulfurization process, which has cut additional costs to $25/kW, with a desulfurization efficiency above 95 percent—thereby significantly decreasing the proportion of desulfurization technologies in terms of total investment. The electric power industry has made the limestone-gypsum desulfurization technique the main technique for thermal power plant FGD. But a report from the National Development and Reform Commission (NDRC) estimated that no more than 60 percent of scrubbers are operating because, lacking financial incentives and supervision from the State, plant officials turned them off (NDRC, 2006). Selective Catalytic Reduction Selective catalytic reduction (SCR) is effective in reducing NOx ­emissions, making it an attractive technology for countries with emissions limits, and ­Germany 

COAL COMBUSTION AND POLLUTION CONTROL 199 and Japan are currently utilizing SCR on coal-fired power plants. SCR technology is widely available for low-sulfur coal, but high capital costs and operations and maintenance costs have made it difficult to implement in developing countries (World Bank, 2006b). An even larger impediment to widespread implementation in countries such as China is the lack of restrictions on NOx emissions. However, in 2005 the Chinese government began recommending that new power plants with a capacity of more than 300 MW apply denitrifying technologies to reduce the exhaustion of NOx. Following this, some power plants have installed SCR, and more may follow if the government enacts stricter NOx control regulations. SCR works by injecting ammonia into the flue gas, converting NOx to N and H2O. Selective non-catalytic reduction (SNCR) is a similar technology, the major difference being the presence of a catalyst in SCR, and the temperatures at which the processes take place. SCR requires much lower temperatures (340°‑380°C) than SNCR (870°-1,200°C). When utilized in low-sulfur boilers (<1.5 percent sulfur content), SCR has been demonstrated to remove 70-95 percent of NOx emissions. The United States is currently focusing efforts on demonstrations for medium- and high-sulfur coal as well. Capital costs depend on required NOx reductions, unit layout, and type of SCR. SCR systems can either be “hot-side,” that is, located between the econo- mizer and the air heater, or “cold-side/post-FGD”—installed downstream of the particulate control. Hot-side systems are severely limited by space constraints and require extensive modifications that result in an average outage of 2-3 months. Cold-side systems are less constrained in terms of space and require shorter outages on average (3-6 weeks), but the flue gas must be reheated and costs are significantly higher than those for hot-side systems. The United States has lagged behind other countries in SCR deployment and did not install its first units until 1993. However, recent legislation to curb NO x emissions in the United States has led to an increase in capacity of boilers with SCR technology. Figure 6-2 shows projected U.S. capacity of coal-fired burners with SCR technology, and the potential impacts of retrofits based on CAIR/ CAMR/CAVR legislation. Again, SCR-equipped capacity is projected to increase from just under one-third to over 56 percent of total capacity by 2020. Mercury Control Issues and Technologies Trace amounts of mercury are present in coal, and when electric utilities burn coal to generate electricity, mercury is released. In 2000, the total mercury content of the coal received at power plants in the United States was approximately 75 tons. Because of fuel processing and other environmental control equipment, total mer- cury emissions from coal-fired power plants in the United States were approximately 45 tons—representing a 40 percent reduction relative to “as received” coal. Approximately 30 percent of the mercury in eastern bituminous coal is typically removed by coal washing before shipping to the plant. 

200 ENERGY FUTURES AND URBAN AIR POLLUTION 200 37.0 150 37.3 22.7 15.2 100 111.3 118.7 121.2 50 85.4 0 2004 2010 2015 2020 Year Existing or NOx SIP Call/State Retrofit New PC and IGCC Capacity Retrofit for CAIR/CAMR/CAVR FIGURE 6-2  Projected U.S. capacity of coal-fired burners with SCR technology. SOURCE: EPA, 2005. 6-2 Mercury is known to bioaccumulate in fish as methylmercury—its most toxic form. Human exposure to methylmercury, which occurs primarily from fish con- sumption, is associated with serious neurological and developmental effects. The U.S. Centers for Disease Control and Prevention estimates that roughly 6 percent of American women of child-bearing age have blood levels of mercury that are above the reference dose set by EPA to represent a safe level. Since the 1990s, methods for capturing mercury from coal-fired power plant flue gases have been the subject of considerable R&D and demonstration ini- tiatives in the United States. Up until now, control of mercury emissions from coal-fired plants has been achieved primarily as a co-benefit of existing pollution controls. Fabric filters and ESPs, FGD systems, and SCR systems contribute to mercury capture (Srivastava et al., 2005). On average, these pollution controls are estimated to remove 36 percent of the mercury emitted from U.S. coal-fired boilers. Due to mercury speciation, or the partitioning of elemental mercury into various forms (elemental, Hg0, ionic, Hg2+, and particle-adsorbed mercury, Hgp), mercury control approaches and success rates vary. In general, bituminous coal produces a majority of Hg2+, while sub-bituminous and lignite coals pro- duce a majority of Hg0. Figure 6-3 illustrates that units burning sub-bituminous and lignite coals exhibited significantly inferior mercury capture in cold-side e ­ lectrostatic precipitators (CS-ESP) compared to similarly equipped units burning 

COAL COMBUSTION AND POLLUTION CONTROL 201 FIGURE 6-3  Mercury capture across cold-side ESP. SOURCE: DOE, 2003. bituminous coal (DOE, 2003). In the case of sub-bituminous coals, a maximum mercury capture of 35 percent has been reported for units with ESPs. However, plants that burn sub-bituminous coals and are equipped with fabric filters report relatively high mercury removal levels of 60 to 99 percent (Grover et al., 1999; Butz et al. 2000). Chlorine in coal can be detrimental to boiler performance because of its cor- rosive nature. However, chlorine content plays an important role in the control of mercury. The presence of chlorine results in the conversion of mercury to HgCl 2, a relatively soluble form that can be effectively captured in a wet FGD system. Ele- mental mercury is not removed by FGD. SCR systems can also convert elemental mercury to Hg2+, enhancing control by a FGD system. In general, the higher the chlorine content, the higher the degree of mercury removal. Limited tests suggest that the use of wet FGD in combination with SCR may be able to capture 80 to 90 percent of mercury from some high-chlorine bituminous coals, which tend to have a high percentage of ionic mercury. Deactivation of the SCR’s mercury oxidation effect with time has been observed in plants burning sub-­bituminous PRB coals but remains to be determined for bituminous coals. 

202 ENERGY FUTURES AND URBAN AIR POLLUTION In contrast to bituminous coals where a synergism or co-benefit between FGD and mercury control has been found, the opposite may be true for sub-bituminous coals. This was first discovered in an analysis of data from the EPA’s 1999 mercury Information Collection Request (ICR). The data showed that mercury removal dropped when a spray dryer absorber was part of the air pollution control train (Kilgroe et al., 2001). The average mercury removal for ICR plants burning sub- bituminous coal with a fabric filter was 72 percent. However, for units burning sub-bituminous coal that had both a spray dryer absorber for SO2 control and a fabric filter, the average mercury removal dropped to 25 percent. Injection of powdered activated carbon (PAC) represents the most mature add-on technology for reducing mercury emissions from coal-fired boilers. This sorbent binds with the mercury and is subsequently captured in the ESP or fabric filter, depending on which device is installed. To date, activated carbon injection (ACI) has primarily been used to control mercury emissions from municipal and medical waste incinerators. However, due to state and federal mercury con- trol requirements, commercial contracts have recently been placed for ACI or b ­ rominated-ACI equipment for a number of new and existing electrical generating units in the United States (Feeley, 2006). Jones et al. (2007) recently reported results from sorbent injection tests at six full-scale plants, which demonstrated that injection of PAC (for bituminous coal) or brominated-PAC (for lignite or sub- bituminous coal) is capable of reducing mercury emissions by 70 to 90 percent, depending on the coal type, sorbent injection rate, and type of particulate control equipment. Additional short-term field tests and long-term demonstrations of s ­ orbent injection technologies are being conducted at a number of plants repre- senting a range of plant designs, operating characteristics, and fuel types. Complicating mercury emission controls is the need to dispose of mercury- containing wastes generated from the removal of mercury from flue gases. In addition, injection of activated carbon can impact the ability to sell coal combus- tion by-products such as fly ash. Although the cost attributed to mercury controls would increase significantly if it rendered fly ash unmarketable (Jones et al., 2007), the majority of existing coal plants in the United States presently landfill their fly ash as waste, and modest quantities of carbon in fly ash may be toler- ated (Srivastava et al., 2005). The use and presence of activated carbon may also complicate SCR operation and generate concerns that depleted catalyst be handled as special wastes. It may also complicate FGD system operation, increasing the quantity of FGD by-products requiring disposal in a landfill. Carbon Capture and Sequestration Though not widely regulated as a pollutant, governments and energy ­producers are increasingly seeking methods to capture CO2 over concerns about global cli- mate change. To achieve further CO2 reductions (beyond reductions achieved through efficiency improvements), CO2 must be removed from the gas streams, 

COAL COMBUSTION AND POLLUTION CONTROL 203 TABLE 6-3  Performance and Economic Impacts of Carbon Capture Technologies IGCC Supercritical PC Net plant output (pre-CO2 capture), MW 425 462 Plant output derating, percent 14 29 Heat rate increase, percent 17 40 Total capital cost increase, percent 47 73 Cost of electricity increase, percent 38 66 CO2 capture cost, $/ton 24 35 NOTE: Based on 90 percent capture. SOURCE: EPA, 2006. concentrated, and compressed for transportation to the storage and sequestration location. Commercially available technologies can capture over 90 percent of the CO2, but are capital intensive, impose an electric power output reduction, and cause energy efficiency penalties. The current costs for carbon capture for all coal technologies are substantial and would significantly increase the cost of electricity. Examples of advanced technologies for post-combustion capture include advanced imines, ammonia scrubbing, and a variety of other promising solvents, and these technologies are in the process of RD&D. Advanced CO2 capture for IGCC includes improvements to the water-gas shift reaction and hydrogen separation. Table 6-3 shows the projected performance and economic impacts of applying currently available technologies to IGCC and PC plants. This comparison points to the cost-competitiveness of IGCC, if carbon capture technologies are applied. Near-term goals for U.S. RD&D are: by 2007, developing two capture technolo- gies limiting energy cost increases to 20 percent for pre-combustion, 45 percent for post-combustion; and by 2012, developing two capture technologies limiting cost increases to 10 percent for pre-combustion, 20 percent for post-combustion (NETL, 2006). Sequestration can take many forms. Biological or terrestrial sequestration relies on long-lived biomass, such as forests, which sequester carbon until reach- ing equilibrium as trees die and decay, thereby re-releasing carbon back into the atmosphere. Longer-term storage options include geologic and oceanic sequestra- tion. Geologic sequestration is the only method currently available for seques- Studies by DOE, EPRI, the Canadian Clean Power Coalition, and others indicate that advanced capture processes, applied to SCPC or SCCFB, could result in competitive electricity costs with c ­ arbon capture. With the commercialization of these advanced capture processes, the selection of a coal power technology with carbon capture would be based on fuel, operational, and site ­specifics, thus providing generation companies with a portfolio of proven options for near-zero emission power. 

204 ENERGY FUTURES AND URBAN AIR POLLUTION tering CO2 from large stationary sources (such as power plants) (NETL, 2006). Carbon can be sequestered in a number of geologic formations, including depleted oil and gas reservoirs, unmineable coal seams, and saline formations. The first two options have the attendant benefit of producing additional energy resources, which might otherwise not be recovered. These processes are described in more detail in Appendix B. References Butz, J. and J. Albiston. 2000. Use of fly ash fractions from western coals for mercury removal from flue gas streams. Proceedings of the Air Quality II: Mercury, Trace Elements, and Particulate Matter Conference. Arlington, VA, September 19-21. CEC (China Electricity Council). 2004. Electric Power in China. DOE (U.S. Department of Energy). 2003. A Review of DOE/NETL’s Mercury Control Technology R&D Program for Coal-Fired Power Plants. DOE/NETL Hg R&D Program Review. EIA (Energy Information Administration). 2005. Average Flue Gas Desulfurization Costs. Washing- ton, D.C.: U.S. Department of Energy. EPA (U.S. Environmental Protection Agency). 2002a. Clean Alternative Fuels: Fischer-Tropsch. Washington, D.C. EPA. 2002b. Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies. Washington, D.C.: Office of Research and Development. EPA. 2005. Multi-Pollutant Regulatory Analysis: The Clean Air Interstate Rule, The Clear Air M ­ ercury Rule, and The Clean Air Visibility Rule, October. EPA. 2006. Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle and Pulverized Coal Technologies. Washington, D.C.: Office of Atmospheric Research. Feeley, T.J. 2006. U.S. DOE’s Mercury Control Technology R&D Program Review. 2006 Mercury Control Technology Conference, Pittsburgh, PA, December 11-13, 2006. Grover, C., J. Butz, S. Haythornthwaite, J. Smith, M. Fox, T. Hunt, R. Chang, T. D. Brown, and E. Prestbo. 1999. Mercury measurements across particulate collectors of PSCO coal-fired utility boilers. Proceedings of the Utility Mega Conference. Atlanta. IEA (International Energy Agency). 2006a. Clean coal technologies. Retrieved June 9, 2006, from http://www.iea-coal.org.uk/. IEA. 2006b. Economics of Retrofit Air Pollution Control Technologies. London: IEA Clean Coal Centre. Jones, A.P., J.W. Hoffmann, D.N. Smith, T.J. Feeley, and J.T. Murphy. 2007. DOE/NETL’s Phase II Mercury Control Technology Field Testing Program: Preliminary Economic Analysis of Acti- vated Carbon Injection. Environmental Science and Technology 41(4):1365-1371. Kilgroe, J.D., C.B. Sedman, R. K. Srivastava, J. V. Ryan, C.W. Lee, and S.A. Thorne. 2002. Control of Mecury Emissions for Coal-fired Electric Utility Boilers: Interim Report with Errata Pages. U.S. Environmental Protection Agency, EPA-600/R-01-109. Marr, C. 2006. Under federal pressure, Georgia Power and others are spending billions to cut back air pollution. Rome News-Tribune, November 12, 2006, Rome, GA. NCC (National Coal Council). 2006. Coal: America’s Energy Future. Washington, D.C. NDRC (National Development and Reform Commission). 2005. China Medium and Long Term Energy Conservation Plan. NDRC. 2006. Perfect Policy, Strengthen Management, Guide and Promote Industrial FGD for Healthy and Rapid Development, available at http://www.ndrc.gov.cn/hjbh/huanjing/t20060731_78633. htm (in Chinese). NETL (National Energy Technology Laboratory). 2005. Gasification: World Survey Results 2004. Washington, D.C.: Office of Fossil Energy, U.S. Department of Energy. 

COAL COMBUSTION AND POLLUTION CONTROL 205 NETL. 2006. Carbon Sequestration Technology Roadmap and Program Plan—2006. Washington, D.C.: Office of Fossil Energy, U.S. Department of Energy. NRC (National Research Council). 2003. Review of DOE’s Vision 21 R&D Program—Phase I. Washington, D.C.: The National Academies Press. NRC. 2004. Urbanization, Energy, and Air Pollution in China: The Challenges Ahead. Washington, D.C.: The National Academies Press. NRC. 2007. Implementing the Stockholm Convention on Persistent Organic Pollutants: Summary of a Workshop in China. From the series: Strenghtening Science-Based Decision Making in Developing Countries. Washington, D.C.: The National Academies Press. Rubin, E.S., M.R. Taylor, S. Yeh, and D.A. Hounshell. 2003. Experience Curves for Environmental Technology and Their Relationship to Government Actions, Presented at EXTOOL-EXCETP6 Workshop, IEA, Paris, January 22-24. Srivastava, R.K., J.E. Staudt, and W. Jozewicz. 2005. Preliminary estimates of performance and cost of mercury emission control technology applications on electric utility boilers: An update. Environmental Progress 24:198-213. World Bank. 2006a. Pressurized Fluidized Bed Combustion. Environmental Management for Power Development Program. Retrieved August 16, 2006, from http://www.worldbank.org/html/fpd/ em/power/EA/mitigatn/pfbcsubs.stm. World Bank. 2006b. Selective Catalytic Reduction (SCR). Environmental Management for Power Development Program. Retrieved August 16, 2006, from http://www.worldbank.org/html/fpd/ em/power/EA/mitigatn/aqnoscr.stm. World Bank. 2006c. Supercritical Coal Fired Power Plants. Environmental Management for Power Development Program. Retrieved August 15, 2006, from http://www.worldbank.org/html/fpd/ em/supercritical/supercritical.htm. World Bank. 2006d. Wet Flue Gas Desulfurization (FGD). Retrieved August 15, 2006, from http:// www.worldbank.org/html/fpd/em/power/EA/mitgatn/aqsowet.stm. World Bank. 2007. Environmental Health and Safety Guidelines. Retrieved June 5, 2007 from http:// www.ifc.org/ifcext/policyreview.nsf/Content/EHSGuidelinesUpdate.