Clean Coal Technologies, Coal

Clean coal project nears commercial operation

Issue 2 and Volume 99.

Clean coal project nears commercial operation

By Edmund S. Baron II, New York State Electric & Gas Corp.

A ?rst for NYSEG and the United States: a clean coal system that turns power plant waste into sales

At a power plant on the eastern shore of Cayuga Lake in upstate New York, New York State Electric & Gas Corp. (NYSEG) has finished building and is now operating an advanced clean coal system that represents a first for the United States and a milestone for the nation?s coal-burning utilities. The system?s state-of-the-art technologies show how this country can use its vast coal reserves while reducing the fuel?s impact on the environment.

Not only will this clean coal system be highly efficient in removing SO2 and NOx from the plant?s emissions, it will also minimize waste. The plant?s process and yard water will be recycled, not discharged, and the system?s byproducts will be sold, not buried.

This project is both the keystone of NYSEG?s strategy for complying with the 1990 Clean Air Act Amendments (CAAA) and a part of the U.S. Department of Energy?s (DOE) clean coal technology demonstration program. In 1991, this NYSEG project was one of nine selected nationwide in Round IV of that program. The $45 million awarded by DOE accounts for more than a quarter of the project?s total cost of $159 million. Another $17 million comes from the Electric Power Research Institute (EPRI), the Empire State Electric Energy Research Corp. (ESEERCO), New York State Energy Research and Development Authority (NYSERDA) and CONSOL Inc.

The project is located north of Ithaca at NYSEG?s Milliken Generating Station which has two pulverized-coal, tangentially-fired boilers and two generators with a combined capacity of 317 MW. Although these generating units date back to the 1950s, Milliken is one of the nation?s top 20 power plants in efficiency and reliability.

The clean coal project at Milliken has the following goals:

Y High SO2 removal. The flue gas desulfurization (FGD) system will remove up to 98 percent of the SO2 from the plant?s emissions.

Y Significant NONOx reduction. This is accomplished by using low-NONOx burners on Milliken?s two boilers

and by demonstrating on one of those boilers a selective, non-catalytic reduction technology.

Y High energy efficiency. The project uses innovative technologies to minimize the impact of SO2 and NOx removal on the plant?s heat rate and overall efficiency.

Y Marketable byproducts. Commercial-grade gypsum and calcium chloride will be produced. The gypsum can be sold for use in the manufacture of wallboard, and the calcium chloride can be sold as a road de-icer or dust suppressant.

Other goals met by the project included zero waste water discharge and a space-saving design.

The integrated design to meet these goals places the FGD system directly under a new 374-foot stack which replaces two existing, 250-foot stacks. Construction began in April 1993 and was completed in December 1994. A three-year demonstration and test period now follows.

Innovative technology

This project uses several innovative technologies and designs sourced world-wide from Saarberg-Holter-Umwelttechnik (SHU), Nalco Fuel Tech, Stebbins Engineering and Manufacturing Co., ABB Air Preheater and DHR Technologies Inc.

For example, the SHU wet FGD process, enhanced with formic acid, removes up to 98 percent of the SO2. The Stebbins? FGD absorber uses a single, split-module vessel lined with ceramic tile for durability. Other SHU FGD absorbers in Europe and elsewhere are lined with rubber. Used in conjunction with combustion modifications, Nalco Fuel Tech?s NOxOUT?urea system is expected to be an economical, efficient way to reduce NOx emissions, while allowing Milliken to continue producing marketable flyash.

The plant also is fitted with an ABB air preheater heat pipe that reduces air heater leakage, improves boiler efficiency and saves energy. A corrosion monitoring system, supplied by Real Time Corrosion Management Ltd. of Manchester, England, permits operation below the acid dew point without a significant increase in equipment duct corrosion.

An on-line performance support system developed by DHR Technologies, called the plant economic optimization advisor, has been installed on one generating unit and is designed to help plant personnel optimize the plant?s overall economic performance and meet the CAAA?s Title IV requirements. The system, which integrates key aspects of plant information management and analysis, covers steam generator and turbine equipment, emissions systems, heat transfer systems, auxiliary systems and waste management systems. The system also provides powerful, cost-saving features for engineers and managers.

SO2 emission control

The SHU process is the heart of Milliken?s FGD project. Though new to the United States, it has operated successfully in Europe for more than 10 years. Saarbergwerke AG, a large electric utility and coal producer in Germany, joined Holter Gmbh, an environmental engineering company, in developing advanced desulfurization technology and tested it at Saarbergwerke installations. The SHU process is a wet limestone, forced-oxidation system which achieves low pH SO2 absorption by adding a small amount of formic acid. The SHU process has been applied successfully to 30 projects with 28 absorbers that serve more than 8,000 MW of generation in Europe and Asia. SHU has also been awarded another 13 projects that will serve 7,000 MWs.

Adding formic acid to the recycle slurry improves the overall efficiency of the SHU system. More specifically, SHU?s use of formic acid provides control over the pH drop in the recycle fluid which allows low pH absorption and eliminates sulfite ions that produce scaling and plugging that can be a problem with other FGD processes. This advantage results in lower operating and maintenance costs.

Formic acid also provides system stability which permits substantial changes in SO2 concentration without affecting system performance. Particularly important is the system?s ability to handle rapid decreases in load or SO2 concentration without pH changes. This prevents any tendency to scale and greatly reduces the maintenance costs associated with FGD system cleaning, as well as making that system more reliable.

The process is more efficient at absorbing SO2, and this cuts down on limestone and recycle slurry, thereby saving energy. Greater limestone solubility is another feature and this permits a coarser grind and reduces the required mill size and grinding power requirements.

Further benefits are derived from the direct oxidation of the recycle slurry to gypsum. The process receives some oxygen from excess boiler air, reduces the extra amount of air required and saves on the power needed for the oxidation blower. The SHU system offers operators superior gypsum formation. The gypsum crystals formed are barrel-shaped, thus minimizing the fines produced. The reduction of fines improves gypsum dewatering and eliminates those costs associated with competing processes. After a final washing to remove chlorides, the SHU processed gypsum is suitable for wallboard.

The SHU process features a co-current/counter-current flow of flue gas through the slurry spray. This flow pattern enables the unit to operate in the low pH range, and this eliminates the formation of sulfite scale, thereby reducing capital, operating and maintenance costs. SHU?s recycle slurry is completely oxidized within the absorber, and this eliminates the need for separate oxidation.

Thanks to its formic acid addition, the SHU process is well-suited to handling flue gas from high-chloride coals. The process accepts more than 50,000 parts per million (ppm) of chloride in the recycle slurry without harming performance. Chlorides separated from the flue gas leave the system as calcium chloride, and this is recovered for resale.

Stebbins tile absorber

The ceramic tiles fitted to the Stebbins absorber are exceptionally strong and resistant to abrasion, corrosion and thermal shock. This technology is expected to demonstrate several advantages over existing linings, notably lower maintenance costs and a tolerance for a wide range of chemical environments. The compact absorber make it especially well-suited for retrofitting when space and construction access are at a premium. By placing the absorber directly below a dedicated flue, expensive alloy dampers and breaching duct work also are eliminated.

Heat pipe air heater system

The ABB heat pipe air heater being demonstrated at Milliken is fitted with a corrosion monitoring system. Similar heat pipe air heaters have been used in smaller, industrial-sized, coal fluidized-bed, natural gas and oil boilers.

West Penn Power installed a similar unit at its Pleasant Station in Willow Island, W.V. At Milliken, extra features were added: aggressive thermal performance, corrosion feedback protection, compact design and corrosion-resistant construction materials.

The heat pipe air heaters offer several advantages over conventional, regenerative air heaters. For example, the new unit can improve boiler efficiency, increase energy savings, while reducing corrosion, fouling and wash water requirements. Heat pipe air heaters do not experience the air leakage common to regenerative air heaters, and eliminating this leakage increases boiler efficiency and energy savings. Without this leakage, precipitators, induced and forced-draft fans, recycle slurry pumps and oxidation air blowers can all be sized smaller.

Another boost to boiler efficiency results from the uniform temperature the heat pipe air heater maintains. This enables the air heater to operate at lower temperatures than more conventional air heaters. It has been estimated that for every 35 F drop in the flue gas exit temperature, plant efficiency improves approximately 1 percent. The new air heater should achieve a 20 F drop in flue gas temperature and an improvement of 50 Btus per kWh in the heat rate.

The heat pipe air heater consists of a series of modules with parallel tubes filled with heat transfer fluids, mounted perpendicular to the gas flow. Different intermediate heat transfer fluids are used for different temperature conditions. The quantity of fluid used in each tube is being engineered to provide the correct internal tube pressure for the flue gas and air temperatures encountered. The heat transfer fluids being used are toluene, naphthalene, trichlorotrifluor-ethane, dowtherm A and dowtherm J.

The heat transfer fluid is sealed inside individual heat transfer tubes. The tubes have been installed at a slight incline, with the lower half of each tube projecting into the flue gas stream and the upper half in the air stream. Each tube provides an

intermediate,closed-loop, evaporation/condensation cycle that is driven by the temperature difference between the hot end immersed in flue gas and the cold end constantly cooled by combustion air.

Corrosion control

By controlling the flue gas temperature at the outlet of the air heater, thermal efficiency of the boiler is being maximized while preventing corrosion. The flue gas exit temperature of the heat pipe air heater is being tempered by bypassing the gas side of the air heater through a damper. If the corrosion rate gets too high, the damper will open and allow hot gas to bypass the air heater, thereby raising the outlet gas temperature.

A feedback control signal is provided from corrosion rate sensors in the flue gas stream to adjust the air heater bypass control damper position. The system adjusts the flue gas exit temperature until the corrosion sensors detect an acceptable corrosion rate.

Minimizing waste

To minimize solid and liquid waste, Milliken?s FGD system is designed for zero waste water discharge while producing the maximum amount of marketable byproducts. A gypsum bleed stream from the scrubber, for example, is fed to hydroclones and the primary hydroclone underflow feeds a centrifuge. The resulting washed filter cake contains only about 6 percent free moisture when discharged to the gypsum storage building.

A bleed stream from the gypsum dewatering area is pumped to the blowdown treatment area. Blowdown treatment consists of two subsystems: blowdown pretreatment and brine concentration. Pretreatment includes separate stages for gypsum desaturation, heavy metal precipitation and magnesium hydroxide precipitation. Brine concentration involves separate distillate and concentrated brine phases, as well as a drying state for further dewatering of the brine.

In blowdown pretreatment, the pH of the bleed stream is increased by the addition of lime slurry to remove heavy metals from solution by precipitation as metal hydroxides. Gypsum seed crystals are recycled from the clarifier/thickener to accomplish gypsum desaturation. Additional heavy metals are removed via precipitation, as sulfides through organosulfide or sodium sulfide dosing. After coagulation and flocculation, the waste water is separated into liquid and sludge phases by a clarifier/thickener unit. The heavy metal sludge is dewatered in a filter press for landfill disposal. Following metal precipitation, the blowdown contains primarily calcium chloride, with some sodium chloride.

The brine concentration system processes the effluent from the pretreatment system through a vapor-compression type of falling-film evaporator, and this produces a very pure distillate that is recycled to the FGD system as process makeup water. The system?s byproduct salt is calcium chloride that meets N.Y. State Department of Transportation?s requirements for use in dust control, soil stabilization, ice control and other highway construction purposes. This material is Type B (liquid calcium chloride solution) with at least 33 percent calcium chloride.

NOx emission control

NOx emissions have been reduced from 0.65 to 0.40 pounds per million Btu by using low-NOx burners that have been retrofitted to Milliken?s two boilers. The low-NOx burners have reduced NOx emissions by 38 percent. As mentioned Nalco Fuel Tech?s, NOxOUT?is being demonstrated on Milliken?s unit one generator and is expected to reduce NOx emissions by an additional 15 percent to 20 percent. This NOx reduction is to be accomplished with minimal effect on boiler equipment and marketable ash byproducts.

NOxOUT?uses chemicals to convert NOx to a harmless form of nitrogen and water. Water, urea and chemical enhancers are injected into the flue gas of the boiler. The reaction between the NOx and the urea forms nitrogen, CO2 and water. The chemical enhancers improve the technology.

These enhancers are also effective in controlling ammonia which can be formed as a byproduct of the NOx-urea reaction. Ammonia is undesirable because it can lead to the formation of ammonium sulfate and bisulfate in the presence of sulfur trioxide. Ammonium bisulfate can cause fouling of air heaters and can contaminate the flyash, thus affecting the sale or disposal of the ash. NOxOUT?can control ammonia slip to as little as 2 ppm.

Test program

NYSEG plans to conduct a comprehensive evaluation during a three-year demonstration program that starts this year (1995). Reports will be issued through the DOE, EPRI, ESEERCO and NYSERDA.

Topics to be examined and reported include the impact on the SHU process of the coal sulfur content, the concentration of formic acid in the recycle slurry and the spray header combinations. The impact of the FGD on the net plant heat rate will also be assessed, and the limestone utilization and formic acid makeup requirements will be confirmed. The impact of FGD variables on SO2 removal and on the quality of the gypsum and calcium chloride byproducts will also be studied.

Testing for the low-NOx burners will aim at maximizing the NOx reduction while achieving acceptable levels of waterwall slagging, tube corrosion and carbon carryover in the fly ash. NOxOUT?testing will seek to increase NOx removal while maintaining ammonia slip below 2 ppm in the flue gas. Also evaluated will be NOxOUT?s?impact on the air heater, electrostatic precipitators, FGD system and on the quality of the bottom ash, flyash, gypsum and calcium chloride.

The air heater study will seek to optimize the net plant heat rate while having minimal impact on plant availability. The plant particulate control efficiency will be evaluated across the electrostatic precipitators and the FGD.

A study of the trace element-air toxics balance will be conducted around Milliken to determine the effectiveness of the upgraded electrostatic precipitators and SHU process in reducing trace element-air emissions. END


Edmund S. Baron II is a project engineering manager for NYSEG Corp.?s generation deptartment. A licensed professional engineer in New York, Baron holds a bachelor?s degree in mechanical engineering from Clarkson University. Baron joined NYSEG Corp. in 1978 as a mechanical engineer and worked on the construction of the Kintigh Generating Station near Niagara Falls. He was promoted to manager of mechanical engineering in 1988 and to his present position in 1991.

The Milliken Generating Station prior to its repowering with clean coal demonstration technology

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A digitized rendering of the completed project.