Loading...
HomeMy WebLinkAboutClean Coal Technology 1999 oO OQ <a - TECHNOLOGY ie Advanced Technologies for the Control of Sulfur Dioxide Emissions from Coal-Fired Boilers TOPICAL REPORT NUMBER 12 JUNE 1999 Advanced Technologies for the Control of Sulfur Dioxide Emissions from Coal-Fired Boilers A report on three projects conducted under separate cooperative agreements between: The U.S. Department of Energy and ¢ Pure Air ¢ Southern Company Services * New York State Electric & Gas Corporation Pure Aijr SOUTHERN a COMPANY Energy to Serve Your World™ NSEG eT ea \ ML, t COAL TECHNOLOGY Advanced Technologies for the Control of Sulfur Dioxide Emissions from Coal-Fired Boilers Executive Summiaty?.i:c2 ss ea e eeee 1 Background 5...os.sscisccc0.: sects tesncirtnagia ce esa oe a hee 2 Hmission Standards 2s. 20000, icusntececs sc cnecenestcsse cea a es 4 Clean Coal Technology Wet FGD Demonstration Projects ........cssesssessssseesseenes 4 Advanced Flue Gas Desulfurization (AFGD) Demonstration Project 2 Demonstration of Innovative Applications of Technology for the CT=121 PGD Process 2.000 eee er te 11 Milliken Clean Coal Technology Demonstration Project ...........s:ssesssessessees 19 Conclusions: .... ic. ni2cii asic ieee tic geri eae ween eB eee 23 Bibliography 2...-.::,0/ thas ate ase er 24 Contacts 2s. a Se ies 20. List of Acronyms and Abbreviations <.3....6062....shecscasesesccucnuor ne 27 Cover image: Plant Views of Bailly, Yates, and Milliken Stations ace ei EERE Executive Summary The Clean Coal Technology (CCT) Program is a government and industry cofunded effort to demonstrate a new generation of innovative coal utilization processes in a series of “showcase” facili- ties built across the country. These projects are carried out on a scale sufficiently large to demonstrate commercial worthiness and to generate data for design, construction, operation, and technical/economic evalua- tion of full-scale commercial applications. The goal of the CCT Program is to fur- nish the U.S. energy marketplace with a num- ber of advanced, more efficient coal-based technologies meeting strict environmental standards. These technologies will mitigate the economic and environmental impedi- ments that limit the full utilization of coal as a continuing viable energy resource. To achieve this goal, beginning in 1985, a multiphased effort consisting of five separate solicitations was administered by the U.S. Department of Energy’s (DOE) Federal Energy Technology Center (FETC). Projects selected through these solicitations have demonstrated technology options with the potential to meet the needs of energy markets while satisfying relevant environmental requirements. Part of this program is the demonstra- tion of technologies, referred to as flue gas desulfurization (FGD) processes, designed to reduce sulfur dioxide (SO) emissions from coal-fired power plants. Emissions of SOy, a precursor of acid rain, are regu- lated under the provisions of the 1990 Clean Air Act Amendments (CAAA). This Topical Report discusses three com- pleted CCT projects that successfully dem- onstrated SO, emissions reductions via innovative FGD processes. The goal of all three projects was to achieve greater than 90% SO removal. This goal was achieved, with SO, removals as high as 98% being demonstrated. High particulate removal efficiencies were also achieved. In addition, these processes demonstrated the capabil- ity of producing wallboard-quality gypsum, a marketable by-product, thereby eliminat- ing the need for FGD sludge disposal, a ma- jor problem for many conventional FGD processes. * Advanced Flue Gas Desulfurization (AFGD) was demonstrated at Northern Indiana Public Service Company’s Bailly Station, near Gary, Indiana. The project was conducted by Pure Air on the Lake, L.P., a company formed by the process developer, Pure Air, which is a partnership between Air Products and Chemicals, Inc. and Mitsubishi Heavy Industries America, Inc. The scrubber was of unique design, incorporating cocurrent flow of gas and liquid. Coal sulfur content varied between 2.3% and 4.5%, typical of high-sulfur bituminous coals. A total of 210,000 tons of high-quality gypsum was produced during the demonstration and sold to a wallboard manufacturer. * Innovative Applications for the CT-121 FGD Process was demonstrated at Georgia Power’s Plant Yates, Newnan, Georgia, using a novel scrubber called a jet bubbling reactor. This single process vessel replaces the usual spray tower/ reaction tank/thickener arrangement. The fiberglass-reinforced plastic used as the construction material proved highly corrosion resistant. Coal sulfur content ranged from 1.2% to 4.3%. In addition to SO, removal, the system also was highly efficient in removing hazardous air pollutants from the flue gas. * Milliken Clean Coal Technology was demonstrated at New York State Electric & Gas Corporation’s (NYSEG) Milliken Station at Lansing, New York. On May 14, 1999, NGE Generation, an affiliate of NYSEG, completed the sale of its coal-fired power plants in New York State, including Milliken Station, to The AES Corporation. The FGD tech- nology demonstrated at Milliken uses the Saarberg-Holter-Umwelttechnik (S-H-U) process, which incorporates a unique cocurrent/countercurrent flow path plus formic acid for enhanced absorp- tion of SO. The Stebbins tile-lined, rein- forced concrete absorber exhibited superior corrosion and abrasion resistance. FGD availability during the test period was 99.9%. Coal sulfur content averaged 3.2%. The technologies described in this report are capable of high levels of SO, removal and have proven to be very reliable. Through the use of efficient, compact absorber equip- ment and the elimination of spare reactors, these technologies offer costs significantly lower than those of previous wet FGD processes. As a result, higher standards for FGD performance and economics have been set. With increasingly stringent air quality regulations, these innovative FGD technologies should find numerous com- mercial applications. Through these CCT demonstrations and related projects, significant experience has been gained by U.S. suppliers of FGD systems and system components. This exper- tise includes operating techniques, equip- ment designs, and selection of materials of construction. These CCT projects have demonstrated advanced features, several of which have been adopted by commer- cial FGD suppliers, thereby accruing sub- stantial cost savings to U.S. electric utilities and their customers. This has led to cost- effective answers to design challenges for equipment such as reaction vessels, pumps, and a wide variety of other items. Advanced Technologies for the Control of Sulfur Dioxide Emissions from Coal-Fired Boilers Background History The Clean Coal Technology (CCT) Program, sponsored by the U.S. Depart- ment of Energy (DOE), is a government and industry cofunded technology develop- ment effort conducted since 1985 to demon- strate a new generation of innovative coal-utilization processes. The CCT Program involves a series of “showcase” projects, conducted on a scale sufficiently large to demonstrate commercial worthiness and generate data for design, construction, operation, and economic/technical evaluation of full-scale commercial applications. The goal of the CCT Program is to furnish the U.S. energy marketplace with advanced, more efficient coal-based technologies meeting strict en- vironmental standards. These technologies will mitigate some of the economic and en- vironmental impediments that inhibit the full utilization of coal as an energy source. Environmental Regulations Concurrent with the development of the CCT Program by DOE, the U.S. Environ- mental Protection Agency (EPA) has pro- mulgated regulations under the 1990 Clean Air Act Amendments (CAAA) controlling emissions from a variety of stationary sources, including coal-burning boilers. The CCT Program has opened a channel to policy-making bodies by providing data from cutting-edge technologies to aid in formulating regulatory decisions. For ex- ample, results from several CCT projects have been provided to EPA to help estab- lish achievable nitrogen oxides (NOx) emissions targets for coal-fired boilers subject to CAAA compliance. Control of SO, Emissions A major goal of the CCT Program is the demonstration of technologies designed to reduce emissions of sulfur dioxide (SO,) from coal-fired utility boilers. Many U.S. coals have a sufficiently high sulfur con- tent to cause SO, emissions to exceed air quality regulations. For operators of boilers burning such coals, three major compliance options are available: ¢ Switch fuels (low-sulfur coal or natural gas) ¢ Purchase SO, credits (allowances) on the open market ¢ Employ flue gas desulfurization (FGD) technologies. Use of low-sulfur coals is quite common, but may result in reduced boiler output, since these fuels frequently have a lower heat content. Natural gas is more expensive than coal and may not be available at the site. Since the price of SO, allowances is rising, FGD is becoming the choice for more and more boiler owners. Types of FGD Processes FGD processes can be categorized as (a) wet and (b) dry or semidry systems. In most wet FGD systems, SO, is removed from the flue gas by reaction with a calcium-based’‘sor- bent in an aqueous solution or slurry. A rela- tively high degree of SO, removal is usually achieved, with a high level of sorbent utiliza- tion. In addition, wet FGD systems generally achieve excellent particulate removal because of intimate contact between the gas and liquid phases. Dry and semidry FGD systems involve in- jecting a solid sorbent (dry), usually limestone, or a sorbent slurry (semidry), usually lime, into the furnace or flue gas duct; the by-product solids are collected in a dry form along with the flyash from the boiler in the existing par- ticulate removal equipment. Compared with wet FGD systems, SO, removal efficiency and sorbent utilization are usually lower. This report reviews the results of demon- strations of three innovative wet FGD pro- cesses conducted under the auspices of the CCT Program. Loading FGD by-product gypsum for transport to wallboard plant. 4 Sorbent recirculation system at Bailly Station. eRe Emissions Standards The Clean Air Act was originally passed in 1970. It was amended in 1977 and most recently in 1990. The CAAA authorized EPA to establish new standards for a number of atmospheric pollutants, including SO, and NOx. Periodic review of the emissions standards every five years is mandated. SO, Emissions Standards Under Phase II of Title IV, the CAAA impose significant reductions in SO, emis- sions from existing boilers by 2000 and place an annual cap on emissions beyond 2000. The Phase II allowable SO, emis- sions rate is 1.2 lb/million Btu input, down from 2.5 1b/million Btu in Phase I. The CAAA provide for SO, emissions allowances (each allowance permits the emission of 1 ton of SO). As part of a trading program, allowances can be bought and sold on the open market. To date, allowance prices have been relatively low, with the result that many utilities have opted to purchase allowances instead of installing FGD systems. However, SO, allowance prices have been increasing re- cently, thereby providing the potential for development of a large-scale retrofit mar- ket for FGD technologies. To meet forthcoming emissions regula- tions, especially when burning high-sulfur coals, it is essential to achieve high levels of SO, removal, usually 90% or higher. Even higher levels of SO, removal can be beneficial, since this is a way to generate emissions allowance credits. Clean Coal Technology Wet FGD Demonstration Projects This report discusses three CCT projects involving innovative wet FGD technologies: * Advanced Flue Gas Desulfurization (AFGD) Demonstration Project * Demonstration of Innovative Applica- tions of Technology for the CT-121 FGD Process ¢ Milliken Clean Coal Technology Demonstration Project Each of the technologies demonstrated uses limestone (CaCO ) as a sorbent and is capable of producing wallboard-grade gyp- sum as a by-product. A major goal of these projects was to demonstrate greater than 90% SO, removal at a cost substantially lower than that of conventional wet FGD processes. Advanced Flue Gas Desulfurization (AFGD) Demonstration Project Project Description This project was selected during Round II of DOE’s CCT Program. In December 1989, Pure Air on the Lake, L.P. entered into an agreement to conduct this demonstration project. Pure Air on the Lake is a company formed to carry out this project by Pure Air, a general partnership between Air Products and Chemicals, Inc. and Mitsubishi Heavy Industries America, Inc. The host site was the Bailly Generating Station of Northern Indiana Public Service Company (NIPSCO), located about 12 miles northeast of Gary, Indiana. The site is im- mediately adjacent to the Indiana Dunes National Lakeshore, along the southern edge of Lake Michigan. The demonstration was conducted between June 1992 and June 1995, treating the combined flue gases from two boilers (Units No. 7 and 8) having a total nameplate capacity of 616 MWe. Total project cost was $152 million, of which DOE provided $64 million, or 42%. The project consisted of installing a scrubber of unique design involving co- current flow of gas and liquid, an air rotary sparger (ARS) located within the base of the absorber, and a novel wastewater evaporation system (WES). The project also included a gypsum agglomeration process known as PowerChip®, which enhances the handling and transportability characteristics of the by-product gypsum. The result is a stable, densely agglomer- ated, semidry flake with handling proper- ties equivalent to natural gypsum rock. Adding PowerChip® technology ex- pands the potential market for the gypsum by-product. Gypsum made at the Bailly Station is sold to United States Gypsum Company for wallboard manufacture at its East Chicago, Indiana, plant. The East Chi- cago plant is the first facility in North America to produce wallboard from 100% FGD gypsum. Process Description The AFGD process accomplishes SO, removal in a single absorber which per- forms three functions: prequenching the flue gas, absorption of SO,, and oxidation of the resulting calcium sulfite to wall- board-grade gypsum. Night view of Bailly Generation Station. 5 Description of the Advanced Flue Gas Desulfurization (AFGD) Demonstration Unit at Bailly Station Hot na Wastewater => oe Evaporator iia _ Electrostatic Precipitator To Disposal or Sales Polymer Grid Disengagement eo Packing ‘one Mist Water Eliminator Centrifuge System Water Wastewater | Slurry Dry Limestone Air Rotary Reservoir Injection Absorber Sparger Slaked Lime Incoming flue gas is cooled and humidified with pro- the slurry in the reservoir and inject air into it. Fixed air cess water sprays before passing to the absorber. In spargers assist in completing the oxidation. Slurry from the absorber, two tiers of fountain-like sprays distribute the reservoir is circulated to the absorber grid. reagent slurry over polymer grid packing that provides A slurry stream is drawn from the tank, dewatered, a large surface area for gas/liquid contact. The gas then and washed to remove chlorides and produce wall- enters a large gas/liquid disengagement zone above the board quality gypsum. The resultant gypsum cake slurry reservoir in the bottom of the absorber and exits contains less than 10% water and 20 ppm chlorides. through a horizontal mist eliminator. The clarified liquid is returned to the reservoir, with After contacting the flue gas, slurry falls into the slurry a slipstream being withdrawn and sent to the waste- reservoir where any unreacted acids are neutralized by water evaporation system for injection into the hot flue limestone injected in dry powder form into the reservoir. gas ahead of the electrostatic precipitator. Water evapo- The primary reaction product, calcium sulfite, is oxidized rates and dissolved solids are collected along with the to gypsum by the air rotary spargers, which both mix flyash for disposal or sale. Important features of the AFGD project technology are: * The use of cocurrent flow to permit high flue gas velocities (up to 20 feet per second) and compact design ¢ A non-pressurized slurry distribution system that requires approximately 30% less recirculation pump power than conventional countercurrent scrubbers * Fountain-like flow that doesn’t gener- ate a fine mist, thereby reducing mist eliminator loading by as much as 95% compared to countercurrent designs * Use of a dry pulverized limestone di- rect injection system, eliminating the need for ball mills, tanks, pumps, and other equipment associated with on- site wet grinding systems * Use of an ARS, combining agitation and oxidation, that significantly en- hances scrubber performance * Incorporation of WES to control chlorides without creating a new waste stream * Use of the PowerChip® system, incorporating a compression mill operating at an optimum compacting pressure and cure time/temperature relationship to change the physical structure of the gypsum Results The AFGD unit successfully achieved the target of removing more than 90% of the SO, from the flue gas. Five Midwest- ern bituminous coals, having sulfur con- tents between 2.25% and 4.5%, were burned during this demonstration. SO, removal efficiency averaged 94%, with a maximum of over 98%. The facility was operated for 26,300 hours during the demonstration, with system availability of 99.5%. High availability eliminates the need for a spare absorber. SO2 Removal Efficiency, % 1.01 1.04 Coal Sulfur Content, % 2.25 4.0 4.5 1.07 Stoichiometric Ratio, moles calcium/mole SO2z removed 1.10 SO, removal performance at Bailly Station (76% of design liquid-to-gas flow ratio). Variables studied in the test program included the sulfur content of the coal, the slurry recirculation rate, the ratio of calcium injected to SO) in the flue gas, and the liquid-to-gas ratio in the absorber. U.S. Gypsum has taken the entire by- product gypsum output from the Bailly AFGD unit. During the three-year demon- stration, gypsum production exceeded 210,000 tons, with an average purity of 97.2%. Business Arrangement An important innovation with the AFGD project was a business arrangement where- by Pure Air owns and operates the FGD system on behalf of NIPSCO, thus reliev- ing the utility of day-to-day operating and maintenance responsibilities. History The Clean Air Act of 1970 estab- lished a major air regulatory role for the federal government. The Act was extended by amendments in 1977 and most recently in 1990. The 1990 CAAA is one of the most complex and com- prehensive pieces of environmental legislation ever written. It authorizes EPA to establish standards for a num- ber of atmospheric pollutants, includ- ing sulfur dioxide (SO3). SO, Emissions Standards SO, is formed through the combus- tion of sulfur contained in coal. Burn- ing typical medium- and high-sulfur coals produces SO, emissions that exceed the allowable limits under the CAAA. Two major portions of the CAAA relevant to SO, control are Title | and Title IV. Title | establishes National Ambient Air Quality Stan- dards (NAAQS) for six criteria pol- lutants, including SO. The 24-hour average ambient air standard for SO, under Title | is 0.14 ppm. Title |1V addresses controls for spe- cific types of stationary boilers, includ- ing those found in coal-fired power plants. Title IV is often referred to as the Acid Rain Program. The overall goal of Title IV is to achieve environ- mental and public health benefits through reductions in emissions of SO, as well as reduced nitrogen oxides (NOx) and particulates emissions. Title lV uses a two-phase SO, con- trol strategy. Phase | began in 1995 and affects 263 units at 110 mostly coal-burning electric utility plants located in 21 Eastern and Midwestern ese ee eee eee eee eeeeeccecceneeeeeeeeneeeaceeeeeenccoeaccencce acc caecececaceac nee eee ncn Emissions Standards states. An additional 182 units joined the program as substitution or compen- sating units, bringing the total of Phase | affected units to 445. Phase II, which begins January 1, 2000, tightens annual emissions limits and also sets restrictions on smaller plants fired by coal, oil, and gas. The Title lV Phase | SO, emissions limit is 2.5 Ib/million Btu of heat input to the boiler. This decreases to 1.2 |b/ million Btu in Phase II. Title IV allows sources to select their own compliance strategies. To reduce SO, emissions an affected source may repower, use cleaner burning fuel, re- assign some of its energy production from dirtier to cleaner units, or reduce fuel consumption by improving effi- ciency. In general, no prior approval is required, allowing sources to re- spond quickly to market conditions. The SO, Trading Allowance Program The Acid Rain Program represents a dramatic departure from traditional regulatory methods that establish spe- cific, inflexible, emissions limits with which all affected sources must com- ply. Instead, the program introduces an allowance trading system that har- nesses the incentives of the free mar- ket to reduce pollution. Affected utility units have been allocated allowances based on their historic fuel consump- tion. Each allowance permits a unit to emit one ton of SO,; for each ton of SO, emitted, one allowance is retired. Allowances may be bought, sold, or banked. Anyone may acquire allow- ances and participate in the trading system. However, regardless of the number of allowances held, a source may not emit pollutants at levels that would violate federal or state limits set under Title | of the CAAA to protect public health. In Phase II, the CAAA set a per- manent ceiling (or cap) of 8.95 mil- lion annual allowances allocated to utilities. This cap firmly restricts SO, emissions and ensures that environmental benefits will be achieved and maintained. The allowance trading system contains an inherent incentive for utilities to reduce pollution, since for each ton of SO, that a utility avoids emitting, one fewer allowance must be retired. Utilities that reduce emissions below their allowance allocation are able to sell, transfer, or bank their surplus allowances. Title IV includes an optional pro- gram involving voluntary reduction of SO, emissions. This program allows sources not regulated under Title IV the opportunity to participate on a voluntary basis, reducing their emissions and, thereby, receiving SO, allowances. EPA invited broad input into the development of Title IV by consult- ing with representatives from various stakeholder groups and is maintain- ing this open-door policy as it imple- ments the program. The Acid Rain Program is viewed as a prototype for tackling emerging environmental is- sues. The allowance trading system capitalizes on the power of the mar- ketplace to reduce SO, emissions in the most cost effective manner. Costs Pure Air developed cost estimates for commercial implementation of the AFGD technology, covering a range of plant ca- pacities and coal sulfur contents. For a 500- MWe power plant firing a 3% sulfur coal and operating at 90% SO, emissions reduc- tion, the capital cost is estimated at $94/kW. For a 15-year project life, the levelized cost on a current dollar basis is 6.5 mills/kWh, which is equivalent to $302/ton of SO, removed. These costs are about one-half those of a conventional wet FGD process. The advanced design features of the AFGD technology result in a comparatively small- er scrubber, one that requires less plot area, less material to construct, and has much lower capital and operating costs than con- ventional scrubbers. Awards The Bailly AFGD project received a 1992 Outstanding Engineering Achievement Award from the National Society of Professional Engineers and Power magazine’s 1993 Powerplant Award. Conclusions This project shows that a single absorber can provide flue gas desulfurization for a power plant of at least 600-MWe capacity and that no spare absorber is required. It also shows that pulverized limestone can be suc- cessfully injected directly into an absorber. Wastewater evaporation in the flue gas duct eliminates the need for liquid waste dis- posal, and use of the gypsum by-product for wallboard manufacture eliminates the need to dispose of solid waste. A unique own-and-operate business arrangement successfully handles the processing of flue gas, relieving the host utility of these responsibilities. The Bailly AFGD scrubber continues to operate commercially under a long-term agree- ment between NIPSCO and Pure Air. Limestone and lime silos for AFGD Demonstration Project, adjacent to Indiana Dunes National Lakeshore. Adjacent to the Pure Air project site, only about 300 feet away, are the Indiana Dunes National Lake- shore and the Indiana Dunes State Park. The State Park was estab- lished in 1926, followed by estab- lishment of the adjacent National Lakeshore in 1996. Together, these two parks span about 20 miles along the southern shore of Lake Michigan. The Indiana Dunes consist of large sand dunes at the lake’s edge, behind which is an area of dunes whose plant cover has evolved to mature forests. With 1,445 native plant species present, the area is a botanist’s dream with variety exceeded in the United States only by the Grand Canyon and Great Smoky Mountains Na- tional Parks. Overlapping ranges of plant species converge at the dunes, where plants usually found in warmer climates (orchids, cacti, and carnivorous plants) grow alongside species more typical of Canadian forests and the tun- dra (Arctic bayberry, jack pine, and northern rose). This unusual diversity of plant life serves to attract a wide variety of wildlife to the area. For example, nearly 350 species of birds have been sighted in the dunes, rang- ing from waterfowl (geese, ducks, and swans) to raptors (hawks, falcons, and eagles). The National Lakeshore staff even manages a nearby heron rookery. From 1895 to 1934, the Indi- ana Dunes served as the labora- The Indiana Dunes tory for Henry C. Cowles, a pro- fessor at the University of Chicago who was eulogized as being America’s first professional ecologist. At the Indiana Dunes, Dr. Cowles studied the effects of geological formations on plant communities and the transfor- mation of habitat by those com- munities. Amidst the kaleidoscope of plant communities found at the dunes, Cowles recognized some patterns. As the habitat changed, proceeding inland from beach- front to forested dunes, he ob- served a succession of plant communities—ranging from grasses that colonize the beach- front dunes to increasingly com- plex cottonwood, pine, oak, and beech-maple forests. This prin- ciple of ecological succession is important enough that when ten European botanists were asked what sites they wanted to see on their trip to America in 1913, they responded, “The Grand Canyon, Yosemite, and the Indi- ana Dunes.” Scientific investiga- tions are still performed at the Indiana Dunes, largely under the auspices of a staff of scien- tists at the National Lakeshore. It is fitting that the AFGD demonstration project is located in the midst of this environmen- tally sensitive area. In addition to such features as reduced SO, emissions, production of com- mercial gypsum instead of sludge, and wastewater evaporation, the project includes extensive envi- ronmental monitoring. Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Project Description In April 1990, Southern Company Ser- vices entered into an agreement with DOE to conduct this project, which was selected during Round II of DOE’s CCT Program. The demonstration was hosted at Georgia Power Company’s Plant Yates, Unit 1, located at Newnan, Georgia. This unit is a 100-MWe (net) pulverized-coal fired boiler. Total project cost was $43 million, of which DOE provided $21 million, or 49%. The project involved installation of the Chiyoda CT-121 FGD process, that includes a specially designed absorber known as a Jet Bubbling Reactor® (JBR), made of fiberglass-reinforced plastic (FRP). A pri- mary objective was to demonstrate reli- able, long-term operation of the JBR. Coal sulfur content ranged from 1.2% to 4.3%. Process Description A major innovative feature of the CT-121 process is the use of a single absorber ves- sel — Chiyoda’s patented JBR — in place of the spray tower/reaction tank/thickener arrangement used in conventional FGD sys- tems. The JBR combines SO, absorption in a limestone slurry, oxidation of sulfite to sul- fate, and gypsum crystallization. Much of the undesirable crystal attrition and secondary nucleation associated with the large centrifugal pumps used for slurry recir- culation in conventional FGD systems is elimi- nated in the CT-121 design. The result is that large, easily dewatered, gypsum crystals are consistently produced. The CT-121 design also significantly reduces the potential for gyp- sum scale growth, a problem that frequently occurs in conventional FGD systems. The gypsum storage area at Plant Yates has three separate cells: a “clean” gypsum stack area, a gypsum/flyash stack area, and a recycle water pond. The stacks are used to store and dewater the solids, with clear, decanted process water being collected in the common pond area and returned to the process. Aerial view of Yates Electric Station. 11 SO, Emissions Control Technologies (err EE SEEDED ELIE IE) Overview Most SO, control technologies involve the addition of a calcium- based sorbent to the system. Under the proper conditions, this material reacts with SO, to form calcium sul- fite (CaSO3), which is then oxidized to calcium sulfate (CaSO,). Be- cause of their low cost, limestone and lime are the most frequently used sorbents. In the majority of applications, the sorbent is dissolved in, or slur- ried with, water; flue gas contacts the solution or slurry in a scrubber. Alternatively, the sorbent is inject- ed directly into the furnace or flue gas duct. Historical Note The notion of scrubbing SO, from coal-derived flue gas dates back to the 1920s and 30s, when the first scrubbers were built in Great Brit- ain. These facilities were shut down during World War II so that the Brit- ish power plants would not be de- tected by aircraft that could follow the vapor plumes. Interestingly, even these first scrubbers were capable of removing 90% of the SO5. Scrub- ber technology continued to evolve through the 1960s, with installations in Europe, Japan, and the United States. However, widespread applica- tion in the United States did not occur until enactment of the Clean Air Act of 1970. In the United States, a number of coal-fired power plants were equipped with scrubbers during the 1970s and early 1980s. These scrubbers were, for the most part, installed at newly constructed power plants, because existing plants were exempt under the law. When domestic power plant construction decreased in the 1980s, the market for scrubber technology moved overseas, where improvements were made. With the advent of acid rain controls for older units under the 1990 Clean Air Act Amendments (CAAA), a new market for scrubber technology began to emerge in the United States. Technology develop- ments continue to improve perfor- mance and reduce costs. Dry and Semidry Sorbent Injection A reactive calcium- or sodium-based sorbent is injected into the economizer or flue gas duct, where the particles react with SO, and are subsequently removed along with flyash by the boiler’s particulate control device. The two most common calcium-based sor- bents are limestone, CaCO3, and slak- ed lime, Ca(OH)». Limestone, which generally requires a higher reaction temperature, is usually injected as a dry powder. Lime, on the other hand, is usually handled as a slurry that dries as soon as it is injected into the hot flue gas. This is referred to as semidry scrubbing, which dominates the sor- bent injection market. All commer- cial semidry systems in the U.S. use lime and recycled fly ash as sorbent. These systems account for 8-10% of the installed FGD capacity in the U.S. Sulfuric Acid Production Although less commonly used, another approach is to oxidize the SO, to SO, over a catalyst and ab- sorb it in water to form sulfuric acid, which can be sold for a variety of uses, such as metals pickling. Conventional Wet FGD Technology Conventional wet FGD systems are typically designed for SO, re- moval efficiencies of about 90%, a level required to meet air quality standards when burning high-sulfur coals. The processing scheme for most wet FGD systems is essentially as follows. Flue gas from the particulate collector flows to the SO, absorber, the energy necessary to overcome the FGD system pressure drop being provided by the boiler induced draft (ID) fans. In the absorber, a variety of technology specific de- vices achieve intimate contact of the flue gas with the sorbent slurry. Gas flow per unit cross sectional area, which determines scrubber diameter, must be low enough to minimize entrainment. Mass transfer characteristics of the system deter- mine absorber height. Absorber ves- sels tend to be quite large in practice. Following contact with the slurry, the scrubbed flue gas passes through mist eliminators, which remove en- trained slurry droplets. Periodic wash- ing using fresh water keeps the mist eliminators clean and provides make- up water to the FGD system. In the absorber, SO, reacts with limestone, forming calcium sulfite. Limestone is supplied either as a dry solid or a slurry. The sulfite is subsequently oxidized in a separate reaction tank to form calcium sul- fate, which crystallizes as gypsum (CaSO, 2H,0). The residence time of solids in the reaction tank is gen- erally in the range of 15 to 25 hours. This extended residence time, coupl- ed with proper reaction tank design and operation, provides an environ- ment conducive to gypsum crystal growth. In some processes, pumps recircu- late slurry from the reaction tank to the scrubber to provide the volume of slurry necessary to maintain good gas/ slurry contact and ensure high SO, re- moval efficiency. The slurry in the re- cycle tank is agitated to maintain the solids in suspension and prevent sol- ids buildup on the tank bottom. A small slipstream of slurry is sent to a primary dewatering system, which recovers solids (gypsum and flyash). The dewatering system is designed to concentrate the gypsum crystals to an ultimate solids content of 85% to 90% (dewatered gypsum has the consistency of wet sand). The gypsum is conveyed to an on-site waste disposal landfill or shipped to a processing facility where the by- product gypsum is utilized for wall- board or cement manufacture. Recovered process water is re- turned to the absorption and reagent preparation systems. Over its life, a 500-MWe coal-fired power plant with a conventional wet scrubber produces enough sludge to fill a 500-acre disposal pond 40 feet deep. Early scrubbers were plagued by poor reliability, often requiring the installation of spare modules as back-up to ensure continuous flue gas cleanup. Innovative Wet FGD Technology The innovative scrubbers de- scribed in this report are a signifi- cant improvement over 1970s wet scrubber technology, featuring state-of-the-art designs and materi- als of construction. Highly efficient, compact, and less expensive to construct and operate, these scrub- bers eliminate waste disposal prob- lems by incorporating oxidation of the calcium sulfite sludge to wall- board-grade gypsum. Because of high process reliability, spare scrub- ber modules are not required. Advanced features developed in these CCT projects have been widely adopted by scrubber ven- dors and, more importantly, the U.S. electric utility industry. These demonstration projects have re- sulted in increased competition, pointing the scrubber market to- ward fewer but larger absorber vessels, salable by-products, and better equipment guarantees. The resultant savings to U.S. electricity customers amount to billions of dollars in reduced costs for CAAA compliance. Description of the CT-121 Process Demonstration Unit at Plant Yates Boiler _Precipitator Jet Bubbling Reactor Flue gas enters the scrubber inlet gas cooling section downstream of the boiler’s ID fan, which also serves as the scrubber’s booster fan. In the gas cooling section, the flue gas is cooled and saturated using diluted Jet Bubbling Reactor™ (JBR) slurry. From the gas cooling sec- tion, the flue gas enters an enclosed ple- num chamber in the JBR, formed by the upper and lower deck plates. Sparger tubes mounted in the floor of the inlet plenum conduct the flue gas be- low the level of the slurry reservoir in the jet bubbling zone (froth zone) of the JBR. After bubbling through the slurry, the gas flows upward through large gas riser tubes that bypass the inlet plenum. The cleaned gas enters a second ple- num above the upper deck plate, where, because of a large decrease in velocity, Reaction Deck Plate Disengagement ‘one Bubbling 4__ Limestone Slurry Slurry Reservoir entrained liquor is disengaged. The clean- ed gas passes to a two-stage, chevron- style, horizontal-flow mist eliminator, then on to a wet fiberglass-reinforced plastic chimney. A closed-circuit, wet ball mill limestone preparation system is used to grind raw (s 3/4") limestone to a particle size small enough (90% through a 200-mesh screen) to ensure rapid reaction and minimize the amount of unreacted limestone in the JBR. The JBR slurry reservoir provides about 36 hours of solid-phase residence time, depending on the SO, absorption rate. For JBR slurry level and density control, slurry from the JBR is pumped intermit- tently to a gypsum slurry transfer tank. It is then diluted for pumping to a Hypalon®- lined gypsum (or gypsum/ash) stacking area for gravity dewatering and storage. Collection Pond Gypsum stacking involves filling a lined, diked area with slurry for gravity sedimentation. Over time, this area fills with settled solids. The filled area is then partially excavated, with the excavated material used to increase the height of the containment dikes. The repetitive cycle of sedimentation, excavation, and raising of perimeter dikes continues on a regular basis during the active life of the stack. Process water is decanted, stored in a surge pond and then returned to the CT-121 process. The amount of SOz removed from the flue gas is controlled by varying the slurry pH or the depth of submergence of the flue gas spargers in the JBR. Higher liq- uid levels result in increased SO. removal because of increased contact time be- tween the flue gas and the slurry. 14 Out Limestone and Gypsum wee A Particles art Gas Sparger Tube Jet Bubbling Zone Flue Gas Air ~<— Lower Deck Plate Initial Liquid Level Clean Gas Gas Sparger Tube Limestone Slurry “ Gypsum By-product S, Slurry Detail of gas sparger tube. Schematic of Chiyoda’s Jet Bubbling Reactor with gas sparger action. 15 SO, Formation and Removal Combustion All coals contain sulfur. Some of this sulfur, known as organic sulfur, is inti- mately associated with the coal matrix. The rest of the sulfur, in the form of pyrites or sulfates, is associated with the mineral matter. High-sulfur bitumi- nous coals contain up to about 4% sulfur, whereas low-sulfur Western coals may have a sulfur content below 1%. Upon combustion, most of the sulfur is converted to SO, with a small amount being further oxidized to sulfur trioxide (SO3). S(Coal) + Op ----> SOz SOz + 1/5 Op ----> SO3 Because, in the absence of a catalyst, the formation of SOs is slow, over 98% of the combusted sulfur is in the form of SOp. Effective January 1, 2000, the SO, emissions limit for coal-fired power plants is 1.2 Ib/million Btu. To comply with this regulation without FGD, the maximum sulfur content for a coal having a higher heating value of 12,000 Btu/lb is 0.72% by weight, assuming 100% conversion of sulfur to SO5. Wet FGD The major reactions occurring in wet FGD processes are shown by the fol- lowing equations: Absorption SO, + H,O ----> HaSO3 SO3 + H2O ----> HaSO4 Neutralization CaCO + H2SO3 ----> CaSO3 + CO + HzO CaCO, + H2SO, ----> CaSO, + CO + HzO Oxidation CaSO3 + 1/5 Oz ----> CaSO, Crystallization CaSO, + 2H,O ----> CaSO, * 2H20 Results When high-sulfur coal was burned at maximum boiler load at Plant Yates, the CT-121 scrubber exceeded the target 90% SO, removal efficiency and dem- onstrated excellent availability. Lime- stone utilization was greater than 97%. Maximum SO, removal was about 98% when burning 2.2% sulfur coal, and about 95% with 3.5% sulfur coal. Since removal efficiency is controlled by ad- justing the depth of submergence of the flue gas spargers, it is relatively simple to compensate for the higher sulfur con- tent, thereby maintaining SO, removal efficiency. Materials of Construction As indicated previously, one of the novel aspects of the CT-121 design is the use of fiberglass-reinforced plastic to avoid the corrosion damage associ- ated with traditional closed-loop FGD systems. Both the JBR and the inlet transition duct, where flue gas is cooled prior to contacting the sparger tubes, are made completely of FRP. A distinct advantage of this construction is that it eliminates the need for a flue gas pre- scrubber, traditionally included in FGD systems to remove chlorides that cause serious corrosion in alloys. Exposed surfaces at Plant Yates were coated with homogeneous filler materials (Duromar® and Duromix®) to protect against erosion. The use of FRP was very successful; this material proved to be durable both structurally and chemically. The chimney resisted corrosion from condensates in the wet flue gas, thereby precluding the need for flue gas reheat. The high reliability verified that a spare absorber is not necessary. Particulate Removal In 1993, the Yates CT-121 Project was chosen by DOE as one of eight coal-fired sites for a study of hazardous air pollutants (HAPs) conducted on EPA’s behalf. The project investigated the fate of HAPs at a number of plants that utilize a variety of air pollution control technologies. At all tested conditions, the JBR exhib- ited excellent particulate removal efficiency, ranging from 97.7% to 99.3%. The JBR also removed from 40% to 95% of HAPs. Since much of the HAPs of interest are associated with the particulate phase, re- moval of particulates effectively removes the HAPs. Additional testing in 1994 con- firmed that the Chiyoda CT-121 JBR is highly efficient at HAPs removal. Gypsum Quality The gypsum was of wallboard quality except for high chloride content, which would require washing for removal. In 1996, Georgia Power received a Plant Food Permit from the State of Georgia that allows the unrestricted sale of ash-free gypsum from the Yates project for agricul- tural purposes. This market exceeds | mil- lion tons/yr in Georgia alone. Costs Projected capital costs for commercial implementation of the CT-121 process are in the range of $80-$95/kW. Levelized cost estimates are not available. Awards The Yates CT-121 project received Power magazine’s 1994 Powerplant Award, the Society of Plastic Industries’ 1995 Design Award, and environmental awards from the Air & Waste Management Association and the Georgia Chamber of Commerce. (EERE iene A a Me a aA RS Hazardous Air Pollutants Hazardous air pollutants (HAPs), also referred to as toxic air pollutants or air toxics, are generally defined as atmospheric pollutants that are known or suspected to cause serious health problems. HAPs are emitted by motor vehicles and a variety of industrial sources and may exist as particulate mat- ter or as gases. HAPs include metals and other particulates, gases adsorbed on particulates, and certain vapors, such as benzene, from fuels and other sources. For coal-fired power plants, the HAPs of most concern are metals such as arsenic, cadmium, mercury, selenium, and vanadium, present in trace quantities in the mineral matter in coal. There is also concern over certain other elements such as fluorine. DOE conducted on EPA’s behalf a study to investigate the fate of HAPs at a number of coal-fired plants utilizing a variety of air pollution control tech- nologies. The objective was to see how effective these technologies are for removing HAPs from flue gas. The CCT Program has made a significant contribution to this study through the participation of a number of its projects. 100 o So Inlet SO2 1000 ppm 2500 ppm 3500 ppm SO2 Removal Efficiency, % N © ° So 6 8 10 12 14 16 18 20 JBR Pressure Drop, inches of water SO, removal performance at Plant Yates. 17 Benefits of U.S. Experience in SO, Removal The United States has the largest number of FGD installations in the world, with over 260 units installed on coal-fired power plants having a total capacity of over 85,000 MWe. As a consequence of the extensive work on CCT demonstrations and other projects, vast experience has been gained by U.S. suppliers of FGD systems and system compo- nents, including expertise in operat- al ing techniques, equipment design, and construction materials. Examples include the use of Warman pumps, made in Milwaukee, Wisconsin, for circulating the slurry in the AFGD Demonstration Unit, and the use of Stebbins tile, made in Watertown, New York, as a corrosion resistant liner in the S-H-U absorber at Milliken Station. Taken together, these projects have demonstrated advanced fea- tures, several of which have been adopted by FGD suppliers, thereby accruing substantial cost savings to U.S. electric utilities and their customers. This has led to cost- effective answers to design chal- lenges for equipment such as reac- tion vessels, pumps, and a wide variety of other items. When the CAAA were promul- gated, many operators of high-sulfur coal mines expressed concern that their markets would be significantly reduced. Development of innova- tive, economic FGD technologies has provided new opportunities for continued use of high-sulfur Eastern coal. Limestone unloading conveyor, slurry tank, and hopper at CT-121 Demonstration Unit. Gypsum stack impoundment at CT-121 Demonstration Unit. Conveying by-product gypsum. 18 Milliken Clean Coal Technology Demonstration Project This project was selected during Round IV of DOE’s CCT Program. In October 1992, the New York State Electric & Gas Corporation (NYSEG) entered into an agree- ment with DOE to conduct this demonstra- tion. The project was hosted at NYSEG’s Milliken Station, Units 1 and 2, located at Lansing, New York. The plant is in an en- vironmentally sensitive area on the shores of one of the famous Finger Lakes. Units 1 and 2 are 150-MWe (net) pulverized-coal fired units built in the 1950s by Combus- tion Engineering. Total cost of the CCT project was $159 million, of which DOE provided $45 million, or 28%. The project involved installing a combi- nation of technologies to control both SO, and NOx emissions, including a wet lime- stone scrubber, low-NOx burners, and a heat-pipe combustion air preheater. Because low-NOx burners are, to a great extent, developed technologies and are covered in other Topical Reports, this re- port is limited to discussion of the innova- tive SO, removal technology tested at Milliken, namely the Saarberg-Holter- Umwelttechnik (S-H-U) FGD process. The project goals were to demonstrate SO, emissions reduction of greater than 90%, improved boiler efficiency, minimum solid waste production through by-product utili- zation, and zero wastewater discharge. The S-H-U process was installed on both Units 1 and 2 at Milliken. A single two-compartment absorber was used, pro- viding separate absorber sections for each unit within a single vessel. The Milliken FGD system has been in operation since 1995. Performance testing was concluded in 1998. Process Description In the S-H-U process, flue gas is scrubbed with a limestone slurry in a space-saving cocurrent/countercurrent absorber vessel. The process is design- ed specifically to take advantage of the benefits of organic acid enhanced ab- sorption by utilizing a low concentra- tion of formic acid additive in the scrubbing liquid. Formic acid acts as a buffer in the absorber. Formic acid addition im- proves both the rate of limestone disso- lution and the solubility of calcium in the scrubbing liquid, thereby enhancing SO, absorption efficiency, reducing limestone consumption, improving en- ergy efficiency, improving by-product gypsum quality, and reducing waste- water production. View of Milliken Station on the shores of Cayuga Lake. 19 20 Description of the F@D Demonstration Unit at Milliken Station Flue Ss Gas Gia Limestone Addition ——— = To Primary Dewatering rt Mist Eliminators Air <_ Makeup Water —_—__——_- Formic Acid eed Filtrate Return Flue gas from the boiler ID fans is ducted to the top of the absorber and flows cocurrently downward with scrub- bing liquid sprayed into the flue gas through an array of spray nozzles. The sprayed liquid is collected in a reser- voir at the bottom of the absorber, while the partially scrubbed flue gas makes a 180-degree turn and flows upward through the countercurrent stage of the absorber. Here, additional scrubbing liquid is sprayed into the flue gas to complete SO, absorption. Mist eliminators are mounted in the roof of the vessel to remove entrained liquid droplets before the flue gas is discharged to the stack. Spent scrubbing liquid from both absorption stages collects in a com- mon reservoir in the base of the ab- sorber. Air blown into this reservoir oxidizes calcium sulfite to gypsum. Oxidation is enhanced by agitation of the liquid, which also prevents gypsum particles from settling to the bottom of the reservoir. Reagent limestone is added to the reservoir along with makeup formic acid as re- quired to maintain stable operation. A slurry slipstream is pumped from the reservoir to the gypsum dewatering system, where solid gypsum particles are recovered before the liquid is returned to the scrubbing vessel. A small liquid bleed stream is removed from the gypsum dewatering system to control the chloride concentration in the slurry. Hydrocyclone in gypsum dewatering system at Milliken Station. Operation at low pH provides the benefit of producing soluble calcium bisulfite as a reaction product, rather than the less soluble calcium sulfite. This greatly increases the ease of oxidation to gypsum and essen- tially eliminates the potential for sulfite scaling within the absorber, thus reducing maintenance costs. The by-product gypsum is trucked to a wallboard manufactur- er located in Mississauga, Ontario. Results Operating variables studied in- clude formic acid concentration, coal sulfur content, limestone grind size, and flue gas velocity within the absorber vessel. In addition, FGD efficiency was examined as the number and location of operating spray headers were varied. SO, removal efficiency as high as 98% was demonstrated, exceeding the target value of 90%. A high degree of reliability was achieved. By-product gypsum storage prior to wallboard manufacture. a | tee iS | LU tn 1 hf Limestone ball mill at Milliken Station. Performance testing has demonstrated the beneficial effect of formic acid en- hanced operation. In one series of tests, SO, removal efficiency increased from 83% without formic acid to 95% with for- mic acid. At the same removal efficiency, using formic acid results in a 75% reduc- tion in energy required for circulating the sorbent slurry. Materials of Construction Special consideration was given to the materials of construction of the absorber to minimize erosion and corrosion, which have caused problems with some conven- tional FGD systems. The absorber shell is constructed of reinforced concrete with an integral, cast-in-place liner made of Stebbins ceramic tile. This tile has superior abrasion and corrosion resistance compared to rub- ber and alloy linings and is expected to last for the life of the plant. Costs Projected economics for commercial implementation of the S-H-U process have been prepared by NYSEG. For a 300-MWe power plant burning 3.2% sulfur coal, the total capital requirement for an S-H-U retrofit with 95% SO, removal is $300/ kW. Assuming a 15-year project life, the levelized cost on a current dollar basis is 12.0 mills/kWh, which is equivalent to $534/ton of SO, removed. Aerial view of Milliken Station. eae Conclusions The demonstration phase for the projects described in this report has been completed. The AFGD, CT-121, and S-H-U facilities continue to operate on a commercial basis, attesting to the success of these demonstra- tion projects and the technical and economic viability of the technologies. During the demonstrations, all of the projects exceeded their goals with respect to SO, removal efficiency and proved to be easily maintained and economical to operate. As a result of these efforts, the utility industry has several new technology choices to enable continued use of coal, our most abundant fuel, in an economical and environmentally sound manner. In ad- dition, because of high levels of particulate removal, these technologies are very effec- tive at removing HAPs. The FGD processes demonstrated in these CCT projects feature compact scrub- bers which operate at high levels of reli- ability, thereby eliminating the need for spare reactors. All three technologies of- fer high SO, removal efficiency at costs significantly lower than conventional wet Loading finished wallboard for use in construction industry. FGD. As a result of these projects, im- proved standards for FGD performance and economics have been set. Another important benefit of the inno- vative FGD systems demonstrated in the CCT Program is the production of wall- board-quality gypsum, thus eliminating the sludge disposal problem common to conventional wet FGD processes. Ac- cording to recent trade announcements, several facilities for manufacture of wall- board from FGD gypsum waste are planned or under construction. Because of its uniform high quality, synthetic gypsum, produced as an FGD by-product, has become the preferred feedstock for wallboard manufacture. With implementation of increasingly stringent air quality regulations, there should be a significant market, both in the United States and abroad, for innovative wet FGD processes such as those pre- sented in this report. In the past, many utilities have chosen other options, includ- ing fuel switching and purchasing SO, al- lowances, but these new wet FGD technologies that offer lower costs, high reliability, and low maintenance should result in many more power producers opting for FGD. 23 ee Bibliography Pure Air/AFGD Comprehensive Report to Congress, Clean Coal Technology Program, “Advanced Flue Gas Desulfurization (AFGD) Demon- stration Project,” proposed by Pure Air, U.S. DOE, November 1989. R.J. Keeth, P.J. Ireland, and P.T. Radcliffe, “Economic Evaluation of 28 FGD Pro- cesses,” 199] EPRI/EPA/DOE SO), Con- trol Symposium (Washington DC), December 1991. B. Wrobel and D.C. Vymazal, “Acid Rain Compliance -- Advanced Co-Current Wet FGD Design for the Bailly Station,” First Annual Clean Coal Technology Confer- ence (Cleveland OH), September 1992. B. Wrobel and D.C. Vymazal, “Acid Rain Compliance -- Advanced Co-Current Wet FGD Design for the Bailly Station,” AWMA Annual Meeting (Denver CO), June 1993. P.M. Ashline, “A Case Study: The Com- mercial Deployment of Pure Air’s Clean Coal Technology,” Second Annual Clean Coal Technology Conference (Atlanta GA), September 1993. J. Henderson, D.C. Vymazal, D.A. Stryf, and T.A. Sarkus, “Two Years of Outstand- ing AFGD Performance -- Pure Air on the Lake’s Bailly Scrubber Facility,” Third Annual Clean Coal Technology Confer- ence (Chicago IL), September 1994. G.B. Manavizadeh, J.J. Lewnard, D.A. Stryf, and T.A. Sarkus, “Bailly Station AFGD Demonstration Program,” Fourth Annual Clean Coal Technology Confer- ence (Denver CO), September 1995. 24 Radian Corporation, “Plume Opacity Mod- eling of NIPSCO Bailly Unit 7 and 8 Stack with May 1995 Data,” November 1995. D.C. Vymazal, G.B. Manavizadeh, and D.W. Smith, “Economic and Environmen- tal Benefits of Advanced Flue-Gas Des- ulfurization Technology -- Three Years of DOE Test Results,” American Power Con- ference (Chicago IL), April 1996. Final Report, “Volume 2, Project Perfor- mance and Economics,” Pure Air, April 1996. Chiyoda CT-121 Comprehensive Report to Congress, Clean Coal Technology Program, “Demonstra- tion of Innovative Applications of Tech- nology for the CT-121 FGD Process,” proposed by Southern Company Services, U.S. DOE, February 1990. D.P. Burford, O.W. Hargrove, and H.J. Ritz, “Demonstration of Innovative Appli- cations of Technology for the CT-121 FGD Process,” First Annual Clean Coal Technology Conference (Cleveland OH), September 1992. D.P. Burford, “Chiyoda Thoroughbred 121 Innovative Clean Coal Technology Dem- onstration Project -- Initial Testing Re- sults,” Second Annual Clean Coal Technology Conference (Atlanta GA), September 1993. D.P. Burford, I.G. Pearl, and H.J. Ritz, “CT-121 Scrubber Demonstration Mid- Project Performance Results,” Third An- nual Clean Coal Technology Conference (Chicago IL), September 1994. I.G. Pearl, “Chiyoda Thoroughbred 121 Phase II Demonstration Results,” Fourth Annual Clean Coal Technology Confer- ence (Denver CO), September 1995. D.P. Burford, “Chiyoda Thoroughbred CT- 121 Clean Coal Project at Georgia Power’s Plant Yates -- Phase II Results,” Fifth An- nual Clean Coal Technology Conference (Tampa FL), January 1997. Milliken/S-H-U Comprehensive Report to Congress, Clean Coal Technology Program, “Milliken Clean Coal Technology Demonstration Project,” proposed by New York State Electric & Gas Corporation, U.S. DOE, September 1992. M.E. Mahlmeister, J.E. Hofman, R.M. Statnick, C.E. Jackson, G.G. Elia, J. Glamser, and R.E. Aliasso, “Overview of the Milliken Clean Coal Technology Demonstration Project,” First Annual Clean Coal Technology Conference (Cleveland OH), September 1992. D.T. O’Dea, C.E. Jackson, and G.G. Elia, “Milliken Station Demonstration Project FGD Retrofit Update,” Third Annual Clean Coal Technology Conference (Chi- cago IL), September 1994. E.S. Baron, G. Gaufillet, and C.E. Jackson, “Milliken Station Demonstration Project FGD Retrofit Update - 1995,” Fourth An- nual Clean Coal Technology Conference (Denver CO), September 1995. James Harvilla, Sharon Burns, Walter Savichky, Mark Mahlmeister, and James Watts, “Milliken Clean Coal Technology Demonstration Project,” Sixth Clean Coal Technology Conference (Reno NV), April 1998. Final Report, “Project Performance and Economics Report,” New York State Elec- tric & Gas Corporation, April 1999. The Clean Coal Technology Program The Clean Coal Technology (CCT) Program is a unique partnership be- tween the federal government and industry that has as its primary goal the successful introduction of new clean coal utilization technologies into the energy marketplace. With its roots in the acid rain debate of the 1980s, the program has met its objective of broadening the range of technological solutions available to eliminate acid rain concerns associated with coal use. Moreover, the CCT Program has evolved and been expanded to address the need for new, high- efficiency power-generating tech- nologies that will allow coal to con- tinue to be a fuel option well into the 21st century. Begun in 1985 and expanded in 1987 consistent with the recommen- dation of the U.S. and Canadian Special Envoys on Acid Rain, the CCT Program has been implement- ed through a series of five nation- wide competitive solicitations. Each solicitation has been associated with specific government funding and program objectives. After five solicitations, the CCT Program comprises a total of 40 projects located in 18 states with a capital investment value of nearly $6 bil- lion. DOE’s share of the total pro- ject costs is about $2 billion, or approximately 34% of the total. The projects’ industrial participants (i.e., the non-DOE participants) are providing the remainder — nearly $4 billion. Technologies being demonstrat- ed under the CCT Program are es- tablishing a technology base that will enable the nation to meet more strin- gent energy and environmental goals. Most of the demonstrations are being conducted at commercial scale, in actual user environments, and under circumstances typical of commercial operations. These features allow the potential of the technologies to be evaluated in their intended commercial applica- tions. Each application addresses one of the following four market sectors: ¢ Advanced electric power generation ¢ Environmental control devices * Coal processing for clean fuels ¢ Industrial applications Given its programmatic success, the CCT Program serves as a model for other cooperative government/ industry programs aimed at introduc- ing new technologies into the com- mercial marketplace. Yates CT-121 scrubber in the early stages of fabrication. 25 To Receive Additional Information To be placed on the Department of Energy’s distribution list for future in- formation on the Clean Coal Tech- nology Program, the demonstration projects it is financing, or other Fos- sil Energy Programs, contact: Robert C. Porter, Director Office of Communication U.S. Department of Energy FE-5 1000 Independence Ave SW Washington DC 20585 (202) 586-6503 (202) 586-5146 fax robert.porter @ hq.doe.gov Otis Mills Public Information Office U.S. Department of Energy Federal Energy Technology Center P.O. Box 10940 Pittsburgh PA 15236-0940 (412) 386-5890 (412) 386-6195 fax mills @fetc.doe.gov Contacts for CCT Project and U.S. DOE CCT Program Southern Company Services, Inc. Contact David P. Burford Project Manager Southern Company Services, Inc. P.O. Box 2625 Birmingham AL 35202-2625 (205) 992-6329 (205) 992-7535 fax dpburfor @ southernco.com A SRS et PES DE AEP OT Pure Air on the Lake, L.P. Contact Tim Roth Asset Manager Pure Air on the Lake, L.P. 7201 Hamilton Blvd. Allentown PA 18195-1501 (610) 481-6257 (610) 481-5444 fax rotht|@ apci.com itd eeeetaeiich hcrieielenteleernereianrmentdbeaigeeriemmaemtainemenatinneas ener eee New York State Electric & Gas Corporation Contact James Harvilla Project Manager New York State Electric & Gas Corporation Corporate Drive - Kirkwood Industrial Park P.O. Box 5224 Binghamton NY 13902-2551 (607) 762-8630 (607) 762-8457 fax jharvila@ spectra.net U.S. Department of Energy Contacts David J. Beecy Director, Office of Environmental Systems Technology FE 23, GTN, Room D-212 Germantown MD 20874-1290 (301) 903-2787 (301) 903-8350 fax david.beecy @hq.doe.gov James U. Watts Project Manager Federal Energy Technology Center P.O. Box 10940 Pittsburgh PA 15236-0940 (412) 386-5991 (412) 386-4775 fax watts @ fetc.doe.gov This report is available on the Internet at U.S. DOE, Office of Fossil Energy's home page: www.fe.doe.gov List of Acronyms and Abbreviations Advanced Flue Gas Desulfurization shsusasuedossslessstosesustonnsseasssacsvedsesessatatsacassdsesseacausseesesvansd casdrasetsssssnsesseass Air rotary sparger qcusaduvivsdietedc butucusutuy utvanqussogbesopentctspsete4s¢oobesd ssvaeos ae eastia bussuresssaunazeees British thermal unit Clean Air Act Amendments of 1990 .. Calcium carbonate (limestone) Calcium oxide (lime) Le atesheeteedeMactoataataatastataataeatiaseatastatbadietteclestedeellerleesteetates Calcium hydroxide (slaked lime) lg feehad eta cct acetate aeteteetat tetoattcedecan totter ont naftoetoctastoataafoteetent ots tsetse arfectss tat Calcium sulfite Wr illdeslestedastatlestecticltedbodlealeadLedledlatnetoedeclestatadeed/atealetledbstaalredeoasalalsalatsettednellatestn Calcium sulfate gypsum Clean Coal Technology Carbon dioxide Mecbeaeavecsecneusatsdcerstuttcucvossnealatssaseusanssecsesustestenstcatensetslacbeteds U.S. Department of Energy Reece eece rel Mcletedsorcdconstedteteesseaene U.S. Environmental Protection Agency ea etedeucatotaa vapsssoveusucataserel asstsssstessotsssstesadsssaresaauatsssasounsssecassoes Electrostatic precipitator PT esesescevecec-etedoctetedcssetototsese!csvotodsecotecsetessteevsreroates Federal Energy Technology Center Flue gas desulfurization Fiberglass-reinforced plastic Hazardous air pollutants Fees eects rt dedltatadelsdbstedediadneledednabedslsdedtatadsatednereloat Induced draft UB Roars ca ec cd cc ret nt net et eesctedectetetetscoe ctcesetsasntessatay stan satsdsdtedoatetodsetetsteios "> Jet Bubbling Reactor® FH eee er et adeetcetatedaalceaetetaeetsaersateedsae/tol se setseqnsrtesenncsjsa crnyeoteneessseetanneeteens Sulfuric acid Megawatts of electric power nossuasaiisa sat cssusstesoudseesusssesesveveqsusesvesstvasezass National Ambient Air Quality Standards ededennsleccaberedvesatescedsisiearatecceroacetereetsredet Northern Indiana Public Service Company eg tou eu duswaut seed Gesevastssu assweusveetaesassuna:ossaststus soussssd tees sasvsessdsesssesoscoseassretses Nitrogen oxides ebaladetedacbetoehetiadealalcatatecelodvebetnebetndbetedvetedntadeatetacts New Source Performance Standards ..New York State Electric & Gas Corporation parts per million Saarberg-Holter-Umwelttechnik Latlelateteedeedealeaestatbedeedetaslelosteslenadtededadtestettenatatestoedunteslsteadtateutsstetiabeabedaatestectettestedes Sulfur dioxide 27