Half of all electricity generated in

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1 em forum Forum invites authors to share their opinions on environmental issues EM readers. Opinions expressed in Forum are those of the author(s), and do not reflect official A&WMA policy. EM encourages your participation by either responding directly to this Forum or addressing another issue of interest to you. Half of all electricity generated in the United States comes from coal. This is not surprising as the United States has more recoverable coal than any other nation. Further, the process of generating electricity from coal is a mature technology known capital and operational/maintenance costs and a well-understood performance record. This allows power generators to produce affordable and reliable electricity. The challenge of using coal consistently environmental expectations is answered by clean coal technologies. In a typical coal-based power plant, steam is raised in a pulverized coal-fired boiler and the energy in the steam is converted to shaft work in a steam turbine that drives an electric generator. Emissions are reduced by three main methods: combustion process modification, post-combustion clean up of the flue gas, and increased plant efficiency. In today s coal plants, all three methods are used. These might include in-furnace combustion control of nitrogen oxides (NOx), flue gas cleanup that captures solid particulates and gaseous- and vapor-phase trace elements during combustion, and use of advanced steam parameters of high pressure and high temperature to increase the efficiency of the energy conversion cycle. Efficiency is the electric energy output as a percentage of the fuel energy input of a thermal power plant. It is also a critical parameter, determining not only how much coal is used to generate a unit of electricity (kw-hr), but impacting the quantity of emissions as well. Improving power plant thermal efficiency will reduce all emissions, including carbon dioxide (CO2).1 János Beér, Ph.D., D.Sc., is professor emeritus of chemical and fuels engineering at Massachusetts Institute of Technology (MIT). His current research interests include clean fossil energy electric power generation; turbulent combustion of gaseous, liquid, and solid fuels; and reduction of pollutant emission form flames by combustion process modification. Karen R. Obenshain, Sc.D., is manager of fuels, technology, and commercial policy Edison Electric Institute (EEI) in Washington, DC. Her primary focus at EEI is on the development and deployment of new energy generation and innovative technologies, in particular coalbased systems, an emphasis on climate. jmbeer@mit.edu; kobenshain@eei.org. Photo: Siemens press picture. Improving power plant thermal ef ficiency will reduce all emissions, including CO2. This article presents a brief overview of clean coal technologies. More detailed information on these technologies can be found in reports published by The National Coal Council.2-3 CLEAN COMBUSTION TECHNOLOGIES Advanced combustion technology choices available today for utility-scale power generation include pulverized coal in supercritical or ultra-supercritical steam cycles and circulating fluidized-bed coal combustion in supercritical steam cycles. Pulverized coal combustion is adaptable to a wide range of fuels and operating requirements, and has proven to be highly reliable and cost-effective for power generation. More than 2 million megawatts (MW) of pulverized coal power plants have been operated globally. Coal power units can range in size from 250 MW to 1300 MW. Circulating fluidized beds are capable of burning a wide range of lowquality and low-cost (waste) fuels. The largest operating circulating fluidized-bed combustion unit today is 340 MW, although units up to 600 MW are being proposed as commercial offerings. em 23

2 Supercritical and Ultra-Supercritical Pulverized Coal Technologies The efficiency of steam cycle power plants is proportional to the pressure and temperature of the steam entering the steam turbine. The majority of the installed pulverized coal-fired power plants are operated subcritical steam parameters (i.e., below 3208 psi steam pressure achieving an average efficiency of 32%, higher heating value[hhv]). The use of subcritical steam limits plant efficiency in new plants to approximately 37%. As steam pressure and superheated temperature are increased above 3208 psi and 706 F, respectively, the steam becomes supercritical. Instead of producing a two-phase mixture of water and steam, the steam undergoes a gradual transition from water to vapor corresponding changes in physical properties. Beyond the supercritical steam temperature of 1050 F, conditions are usually referred to as ultra-supercritical. Specially developed high-temperature/high-strength alloys are used for structural parts in the boiler and the steam turbine to contain supercritical or ultra-supercritical steam necessary to achieve net plant efficiencies up to 43% (HHV), depending on location. This represents more than 25% relative improvement compared to the average efficiency of installed capacity, the corresponding reductions in emissions. Looking forward, advancements in materials are important to the continued evolution of steam cycles and higher efficiency units. Development programs are underway in the United States, Japan, and Europe, including the Thermie project in Europe and the U.S. Department of Energy/Ohio Coal Development Office (DOE/OCDO) project in the United States, which are expected to result in combustion plants that operate at efficiencies approaching 48% (HHV). Advanced materials development will be critical to success of this program. The Polk Power Station, Polk County, FL, owned and operated by Tampa Electric Company, is one of only two integrated gasification combined cycle (IGCC) power plants in the United States. Photo courtesy of Robert Waselewski, Tampa Electric Company, is that it requires significantly fewer fuel and sorbent feed points compared to bubbling bed units. This provides simplified designs, better operational characteristics, and easier scale-up to larger size units. Consequently, circulating fluidized-bed coal combustion is the predominant type of fluidized-bed boiler installed worldwide in unit sizes above 200,000 lb/hr of steam. Currently, the largest circulating fluidized-bed combustion unit in operation is 320 MW, but designs for units up to 600 MW have been developed by three of the major suppliers. Fluidized-Bed Coal Combustion Fluidized-bed coal combustion is a method of burning millimeter-size coal particles in a hot bed of sorbent and coal ash particles that are suspended in motion (fluidized) by combustion air blown in from below the bed through a series of nozzles. In its original form, fluidized-bed combustion operates low air velocities (4 6 feet per second [ft/sec]) and most of the air rising through the bed in the form of bubbles ( bubbling bed ). In today s applications of circulating fluidized-bed combustion, the gas velocity is high enough (12 30 ft/sec) to entrain a large portion of the solids, which is then separated from the flue gas and recycled (circulated) to the lower furnace to achieve good carbon burnout and sulfur sorbent utilization. Typically, a hot refractory lined cyclone serves at the furnace exit as a separation device. Because of the high recycle rate and high residence time of unutilized sorbent and unburned carbon, circulating fluidizedbed combustion provides better sulfur dioxide (SO2) capture and better carbon burnout than bubbling bed units. Circulating fluidized-bed combustion also facilitates more effective air staging for improved NOx control and is less prone to upsets due to fuel quality variation. Another important advantage of circulating fluidized-bed combustion 24 em INTEGRATED GASIFICATION COMBINED CYCLE In gasification, coal is reacted an oxidizer to produce a fuel gas. Principal reactants are coal, oxygen, steam, and CO2, while desired products are typically carbon monoxide and hydrogen. Coal is gasified either oxygen or air. The resulting synthesis gas, or syngas, consisting primarily of hydrogen and carbon monoxide, is cooled, cleaned, and fired in a gas turbine. The hot exhaust from the gas turbine passes through a heat recovery steam generator, where it produces steam that drives a steam turbine. Power is produced by both gas and steam turbine generators, approximately two-thirds of the total power coming from the gas turbine. By removing emissionforming constituents from the syngas prior to combustion, an IGCC power plant can meet stringent emissions standards smaller equipment than a pulverized coal plant. The predominant and preferred gasification processes for good quality solid feedstocks are Shell, GE Energy, and ConocoPhillips. These processes employ oxygen-blown entrained-flow gasification that operates pulverized coal feed (dry or in the form of coal-water slurry) at high temperature, achieve good carbon conversion, and are capable of removing the coal ash in liquid slag form. Oxygen-blown gasification has been successfully demonstrated for IGCC. It avoids the very

3 Table 1. Costs of different IGCC plants and USC/PC and out CO2 capture.4 Technology IGCC Texaco Quench IGCC Texaco Radiant SGC IGCC E-Gas PC UltraIGCC Shell Supercritical MW out capture TPC $/kw out capture COE $/MWh out capture MW capture TPC $/kw capture COE $/MWh capture Avoided cost of CO2 $/mt Notes: 450 MW net plants; Pittsburg #8 bituminous coal; IGCCs spare gasifiers.4 Assumptions used to derive these results are as follows: Book life = 20 years; Commercial Operation Date = 2010; Total Plant Cost (TPC) includes engineering and contingencies; Assumes EPRI s TAG financial parameters; All costs expressed in 2003 U.S. dollars; The reference plant for avoided cost of CO2 calculations is the same plant out CO2 capture; Cost of Coal = $150/MM Btu; Capacity Factor = 85%. Source: EPRI. large cleanup equipment sizes and costs that air-blown gasification would otherwise impose. Subsystems integration improves plant efficiency. The degree of integration, however, has to be balanced against the need of maintaining high plant availability. Pressurized oxygen-blown gasification enables the delivery of syngas at the specified fuel pressure required by the gas turbine. Commercial gasification pressures in IGCC range from 400 psi to 1000 psi, depending on the process. When CO2 capture and compression for sequestration is required in the future, the higher pressure systems (e.g., GE Energy) should have an advantage. The composition of coal and some of its physical properties have important influences on the gasification process. Young coals, such as lignite and subbituminous, need to be dried because of increased oxygen demand to vaporize the excessive water in the gasifier. Dry coal feed entrained-flow gasification processes (e.g., Shell) are generally more suitable for low-rank subbituminous coals. Current entrained-flow gasification reactors have capacities Vapor Intrusion The Next Great Environmental Challenge September 13-15, 2006 Los Angeles, CA The vapor intrusion (VI) pathway is an emerging concern that may impact thousands of hazardous, brownfield, and commercial/industrial waste sites across the nation. This specialty conference will bring together nationally recognized scientists, engineers, regulators, communications experts and attorneys first-hand experience in the evaluation and remediation of VI. Based on real-life experiences and knowledge gained by the experts, attendees will have a newfound appreciation for the complex technical, legal, and risk communication issues that impact VI programs. For more information, visit em 25

4 Table 2. Performance and efficiency of steam cycle IGCC plants and out CO2 capture and compression after the MIT Coal Study Efficiency % HHV CO2 emitted g/kwh TCR $/kw COE c/kwh Subcritical out Supercritical out Ultra-Supercritical out PC/OXY IGCC out Notes: Total Capital Requirement (TCR) includes interest during construction and owner s costs. Other assumptions are the same as for data in Table 1. of short ton per day (st/day) of good quality coal. Larger coal feed rates are required as coal quality decreases to produce the same quantity of syngas. While somewhat larger gasifier capacities may be possible, two gasifiers might be required for a very low-quality coal to match the syngas energy output of a single gasifier a high-quality coal. A spare gasifier may also be indicated for good quality coals to enable IGCC capacity factors higher than 85% to be achieved. There are currently two IGCC demonstration plants in operation in the United States: the Polk County Gasification Project ( Tour.html) and the Wabash River Coal Gasification Project ( wabashrdemo.html). CO2 CAPTURE CAPABLE TECHNOLOGIES IGCC Oxygen-blown pressurized gasification of coal (IGCC) lends itself more favorably for CO2 capture and sequestration than pulverized coal boilers because CO2 can be separated from a relatively small volume of fuel gas (syngas) at high pressure. This is in contrast to conditions of coal combustion air as an oxidant, where the flue gas volume is much larger and CO2 concentrations in the atmospheric pressure combustion products are low (typically 12 14%). The larger gas volume to be cleaned results in increased size and more expensive equipment, requiring more energy to operate. There is, however, significant cost and performance loss attached to the capture and compression of CO2 for sequestration, shown in Table 1, which displays the performance and cost comparisons of different IGCC technologies and ultra-supercritical pulverized coal technologies (PC/USC) out and CO2 capture and compression. Pulverized Coal and Circulating Fluidized-Bed Oxy-Combustion There is great interest in CO2 capture capable coal combustion plants because of the increasing efficiency of supercritical steam plants, and the flexibility of pulverized coal and fluidized coal combustion for coal quality variation. The use of oxygen instead of air in combustion is the key to this problem.5 When oxygen, instead of air is used as an oxidant in combustion, the mass flow rate of combustion products is 26 em significantly reduced resulting in increasing combustion temperature. By recirculating cooled flue gas that contains mainly CO2 from the end of the boiler to the furnace, the combustion products are diluted and the flame temperature and furnace exit gas temperature can be restored to air combustion levels. Flue gas recirculation increases the CO2 concentration in the flue gas to beyond 90%, making the flue gas ready for sequestration out energy intensive gas separation. It is probable that corrosion danger in the compressor and pipeline requires some post-combustion gas cleanup. In this case, the flow rate of the five-fold reduced flue gas volume flow through the postcombustion emissions (i.e., mercury, particulates, and sulfur) control equipment leads to reduced capital and treatment costs. Circulating fluidized-bed combustion an external heat exchanger lends itself favorably to oxy/fuel application because the solids circulation means an additional flue gas recycle stage for controlling the combustion temperature. The cooling of the combustor by the cold solids permits the reduction of the rate of flue gas recirculation. This, in turn, results in the oxygen concentration in the feed stream to rise to more than 50% out exceeding a limiting combustor temperature level of approximately 800 C (required by the thermodynamic stability of CaSO4 and by smooth fluidization). The corresponding lower gas mass flow leads to reduced size and cost of the boiler and of the postcombustion cleanup equipment. Table 2 displays data from the Massachusetts Institute of Technology 2006 Coal Study6 and provides comparisons on estimates of the efficiency, CO2 emissions, total plant cost, and cost of electricity for different combustion technologies, including oxy-combustion and IGCC, both out and CO2 capture and storage. As can be seen, the slightly higher capital cost of a more advanced, higher efficiency plant is compensated by fuel savings even for inexpensive U.S. coals so that the cost of electricity (COE) is gradually reduced as the plant efficiency increases for plants both out and CO2 capture and storage. IN SUMMARY There is great interest in the continued development and application of clean coal technologies because of the abundant and affordable coal supply and the ability of coal utilization technologies to comply increasingly tight environmental controls. In addition to combustion process modifications and post-combustion cleanup, the improving efficiency of combustion and gasification cycles are leading

5 to significant reductions in pollutant and CO 2 emisbooras, G.; Holt, N. Pulverized Coal sions. Currently available and IGCC plant Cost and Performance Estimates. Presented at the pulverized coal, circulating Gasification Technologies Conferfluidized-bed, and IGCC ence, Washington, DC, Opportunities to Expedite the Construcplants have efficiencies of aption of New Coal Based Power plants; proximately eight percentthe National Coal Council: Washington, DC, 2004 age points, or a relative 25%, Coal: America s Energy Future; The higher than the installed National Coal Council: Washington, DC, plant average, correholt, N. Gasification Process Selecspondingly better environtion-trade-offs and Ironies. Presented at the Gasification Technolomental performance. gies Conference, Washington, DC, The near-zero emission Bozzuto, C.; Mohn, N. Environmencoal plant of the future will tally Advanced Clean Coal Plants. include CO2 capture and Presented at the 19th World Energy Congress, Sydney, Australia, Sepcompression for sequestratember 6 9, tion, a technology expected The Future of Coal in a Greenhouse-Constrained World; MIT to come to fruition in the Report (in preparation); J. Deutch, mid-2020s. In the near term, E. Moniz, eds.; Massachusetts Institute of Technology, Cambridge, the choices for coal-based MA, generating technology out CO2 capture and storage include pulverized coal or circulating fluidized-bed combustion supercritical steam cycles or pulverized coal combustion ultra-supercritical steam cycles. The primary coal-based electricity generating REFERENCES technologies CO2 capture are IGCC pre-combustion capture, pulverized coal post-combustion capture, and oxy-fired pulverized coal or circulating fluidized-bed combustion. IGCC is presently estimated to have the lowest cost for high-quality bituminous coals when CO2 capture plants may be built, possibly in the early 2020s, but the cost differential between IGCC and combustion plants is closing for high-ash or high-moisture coals. Because flue gas cleanup for an oxy-combustion plant may have to satisfy less stringent standards for compression, pipeline transportation, and sequestration than those for gas turbine combustion in IGCC, the dry flue gas could be sequestered out CO2 separation. Thus, oxy-combustion in supercritical and ultrasupercritical steam plants could become competitive IGCC even for high-quality bituminous coals. These examples are illustrative of the increasing portfolio of clean coal technologies leading toward the development of affordable nearzero emissions power generation in the next two decades. ACKNOWLEDGMENTS The authors gratefully acknowledge permission of The National Coal Council to use material from its 2004 and 2006 reports.2-3 Special thanks to Chris Larsen, George Booras, John Parkes and George Offen, Electric Power Research Institute (EPRI), for their helpful review of the manuscript. em Reform School: Understanding the Changing World of New Source Review (NSR) September 21-22, 2006 Orlando, FL For more information, visit If you are involved in NSR permitting, this is the training you need to keep abreast of the latest developments. This highly interactive two-day workshop will show where each version of the rule applies; explain the basics of the major NSR permit requirements; discuss the applicability criteria for each version of the rule; update you on the latest enforcement initiatives, settlement agreements, and court decisions; and provide you an idea of what s in store for NSR rules and programs in the near future. em 27