Reducing emissions from electric power plants is a priority for European electric utilities
In addition to reducing SO2 and NOx, European power plants are actively lowering particulates, CO2 and other pollutants
By Douglas J. Smith
Controlling emissions from electric power plants is a major concern for all electric utilities throughout the world. Invariably, when the construction of a new power plant is announced the biggest obstacle to its construction is the issue of pollution. Environmental pollution from electric power plants is a problem throughout Europe and because pollution has no borders, it affects all countries of Europe. To reduce environmental pollution, European countries are now cooperating with one another to reduce emissions from the generation of electricity.
The Hungarian model
Under the Hungarian Electric Energy Act of 1994, all new applications for the construction of new power plants must include details about the type of emission control technology that will be used in the plant. Licenses, issued by the Hungarian Energy Office, outline the environmental guarantee obligations of the power plant operator and the financial obligations of the licensee for any environmental damage that might occur from the operation of the plant. If it is determined that the power plant is operated in a manner that seriously endangers the environment, the Hungarian Energy Office has the authority to revoke or amend the license.
Hungarian air emission standards for electric power plants, currently being written, will meet western European standards. Power plant emission limits in Hungary will be set depending upon the type of fuel used and the capacity of the plant. All new power plants constructed in Hungary will have to meet the standards. In addition, a tentative date of Jan. 1, 2004, has been set for all existing power plants to be in compliance with the new standards.
Tables 1(a-d) show the proposed emission standards for new Hungarian power plants. Emissions from existing Hungarian power plants in 1994 are shown in Table 2. By 2010 Hungary is expecting to see a dramatic decrease in emissions of SO2 and NOx from its electric power plants (Figure 1). It is expected that most of these reductions will come from retirement of the oldest polluting units and load reduction of other plants.
NOx reduction in Sweden
Reduction of NOx, SO2 and CO2 has been accomplished in Sweden through a combination of standards and economic measures. In 1991, the Swedish government imposed a carbon tax on the use of fossil fuels. However, biofuels are exempted from the carbon tax and the country`s energy tax. As a result, biofuels have a competitive advantage over fossil fuels.
To control the emissions of NOx, Sweden has mandated more stringent emission standards and also charges a fee on NOx emissions. The fee, or environmental charge, on the emission of nitrogen oxides from combustion plants was instituted in 1992. Initially the charge was levied on boilers and gas turbines with a fuel input of 10 MW and a measured energy production of 50 GWh per year. However, in 1996 the fee was extended to include plants with an energy production of 40 GWh per year. This year the fee will apply to even smaller power plants producing 25 GWh per year. With this change, 500 to 700 plants will be affected. Table 3 shows the Swedish standards for the emission of NOx.
Power plants in Sweden are charged approximately (US)$6 per kilo of nitrogen oxides emitted. Although every plant which produces NOx is levied a charge, they can get a refund. The amount of the refund depends upon their share of the total utilized energy produced. Plants with low emissions of NOx get back more than they pay in while the reverse applies to plants with high NOx. As a result, there is a financial incentive to reduce NOx emissions.
Swedish power plants use a variety of ways to reduce emissions of NOx including burner modifications, installation of low-NOx burners, staged combustion/overfire air (OFA), flue gas recirculation, water or steam injection, cooling or humidification of combustion air and reburning. In addition, many Swedish power plants have installed flue gas treatment systems.
Similarly, the use of selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR) systems has also increased. In 1992 there were 24 SCR and SNCR systems installed. By 1995 the total had increased to 76 systems. Urea and ammonia SNCR systems account for 62 installations; 14 are SCR systems and three plants have SCR in combination with SNCR (Table 4).
The Stenungsund project
Vattenfall Stenungsund power plant in Sweden has four units with a total capacity of 820 MW. Units 1 and 2, 150 MW each, were completed in 1959 and 1960, respectively, and units 3 and 4 of 260 MW each were completed in 1966 and 1969, respectively. Originally the units were designed to burn heavy fuel oil with low excess air.
In 1995 it was stipulated that the fuel used in the plant should have no more than 0.1 percent sulfur content, and that by 1996 NOx emissions should not exceed 50 mg/MJ. When originally firing with heavy fuel oil, the NOx emissions were in the range of 250 to 300 mg/MJ. However, when the plant switched to burning a distillate fuel oil, emissions of NOx were only marginally reduced.
As a means of reducing NOx, emissions units 1 and 2 were fitted with low-NOx burners, and a flue gas recirculation system was installed. Likewise, units 3 and 4 were retrofitted with redesigned fuel guns and atomizers. Unfortunately, even with the modifications the plant was still unable to meet the lower emissions standards of 50 mg/MJ for NOx. Further reduction of NOx was achieved by introducing flue gases to the combustion zone, lowering the air preheater temperature and using water and an emulsifier in the fuel. Although this helped to reduce the emissions of NOx, it was still insufficient to meet the new standard.
Because of the need to reduce the emissions further, a decision was made to mathematically simulate the complete combustion process, including the chemistry and emissions. A mathematics model was developed and then used to predict NOx emissions from under stoichiometric firing with OFA. After extensive testing it was determined that a redesigned combustion system with OFA would give low NOx emissions with no unburned-burned carbon or CO in the flue gases.
Utilizing the design parameters from the simulation calculations, a new combustion system was designed and installed on unit 3. Tests conducted after the retrofit showed very low NOx emissions and almost complete burnout of the fuel. In addition, the flame zone and flue gas stream patterns agreed with the results obtained from the simulation model. Because of the success of the tests conducted on unit 3, a decision was made to also retrofit unit 4 with the new combustion system design. According to Vattenfall Thermal Power, test results from unit 4 were better than those achieved on unit 3.
It is reported that the investment costs for the retrofitted redesigned combustion system is just a fraction of the costs for the installation of low-NOx burners and recirculated flue gas systems on units 1 and 2.
Czech plant installs FGD systems
Because many of the electric power plants burned high-sulfur lignite coal without flue gas desulfurization (FGD) the northwestern part of the Czech Republic was one of the most polluted areas in Europe in the 1980s. However, to help in reducing pollution in the area, the government-owned electric utility CEZ agreed to install FGD systems on units 3, 4, 5 and 6 at its Prunerov power station. On account of units 1 and 2 having reached the end of their life, it was decided that they would be decommissioned and dismantled.
Bids were invited from international suppliers of gas cleaning plants to engineer, construct and commission FGD systems to units 3-6 at the Prunerov plant. After evaluating the bids the contract was awarded to Gottfried Bischoff GmbH & Co. of Essen, Germany. Two Czech companies, Skoda and Vodni Stavby, also joined the Essen company as partners. Because of ease of operation, high flexibility and efficiency removal, a wet limestone/gypsum process was chosen. The utility also decided each unit would have its own separate FGD system. However, absorbent preparation and handling of the end products from the FGDs are handled by a common system.
Each FGD has a spray tower, a regenerative rotary-type gas/gas heater and a wet-type induced-draft (ID) fan installed on the gas side of the units. The equipment is installed in pairs on either side of the plant`s stack.
Before the flue gases enter the spray tower, they are cooled to approximately 129 C in the rotary-type gas/gas heater. Further cooling of the gases to 60 C takes place as the gases pass through the spray tower. ID fans have been installed between the FGD outlet and the rotary-type gas/gas heater. Not only does this arrangement lower the operating costs but it prevents leakage of the untreated gas into the treated gas when passing through the rotary heater.
Coarsely crushed limestone, delivered to the plant by rail, is stored outside at the plant. From this storage area the limestone is transferred into a central storage silo hopper. At the plant the limestone is further processed in pre-crushers and vertical wet-type ball mills. After being processed the limestone is stored in tanks prior to it being used in the FGDs. Reclaimed water is added to the storage tanks to maintain a limestone concentration of 250 g/l.
Since December 1995, the FGD systems have been in commercial operation and are reported to have met the guaranteed removal efficiencies, consumption rates and by-product quality. CEZ is of the opinion that a wet limestone/gypsum process is the best FGD process for high-sulfur Bohemian lignite coal used at Prunerov power plant.
Poland and Germany FGD installations
L&C Steinm?ller GmbH of Germany has been involved in the installation of FGD systems in the Boxberg III 1,000 MW power station in eastern Germany and the 1,200 MW Jaworzno III power plant in Poland. At the German plant locally mined brown coal is burned while the Polish plant burns a local bituminous coal.
Boxberg power station, formally part of the state-owned Kombinat Braunkohlekraftwerke, became part of VEAG after reunification of East and West Germany. The plant has four boilers and each boiler has been fitted with its own FGD system, which consists of new ID fans, absorber and a clean gas cooling tower. Since the market for gypsum in the area served by VEAG power stations is still being developed, the gypsum produced at the Boxberg plant is being landfilled at a brown coal mine near the plant. However, the design of the gypsum landfill allows for it to be reclaimed in the future once the markets for gypsum become established.
The Jaworzno power station consists of 6 x 200 MW units all burning bituminous pulverized coal with a sulfur content of about 2 percent. Consequently, the power station was the largest individual producer of SO2 in that part of Poland. Because of the need to reduce pollution in the area, the operators of the plant were forced to reduce emissions. This was initially accomplished by upgrading the plant to burn a higher grade of fuel. Together, the higher grade coal and upgrading improvements to the boilers and turbines has allowed the plant to decrease its consumption of coal from 4.2 million tons/year down to 3.2 million tons/year.
Similar to the German site, the area around the Jaworzno power station has little or no market for the gypsum produced. Until a market opens for the gypsum, it is being landfilled. However, the power plant`s management is actively soliciting companies which might be able to utilize the gypsum.
Besides changing the fuel and upgrading the units, the plant has retrofitted four of the units with FGD systems similar to those installed in the Boxberg power station. However, if Jaworzno is to meet the new Polish standards for SO2 of 870 g/GJ by Jan. 1, 1998, it will have to retrofit FGD systems to the other two units.
Innovative FGD system installed
The Polish ZEPAK Group has installed wet FGD systems on units 7 and 8 at its Konin power station 200 km west of Warsaw. According ABB Flkt of Sweden, the FGDs installed at Konin have been designed to reduce capital costs for the equipment. In doing this ABB Fl?kt says it has created a competitive FGD design for the Polish market.
Utilizing ABB`s experiences on recovery boilers in the pulp and paper industry, the Konin FGDs use a concrete absorber-in-stack combination which has a smaller footprint. One of the cost benefits of the smaller footprint is it minimizes the amount of ducting in corrosive areas. While the concept of absorber-in-stack has been the solution for many years in recovery boiler applications, the Konin installation is reported to be the first in a fossil-fired power plant.
Unlike other FGD systems that use more expensive rotary regenerative heat exchangers, the Konin units are able to utilize less expensive hot air reheaters in the transition area between the absorber and the stack. Figure 2 shows the compact arrangement of the FGD system and the material handling and storage area for the gypsum at the Konin plant.
When completed the absorber section will have an internal diameter of 13 m and a stack height of 110 m (Figure 3). The existing ID fans will be used, thus allowing the untreated flue gas to be bypassed to the old stack if needed. However, with the FGD system in operation, the outlet from the ID fans will be connected to a common duct. A one-stage axial-flow booster fan will be used to overcome the pressure drop in the absorber.
The contract was awarded in December 1994 and commissioning started in December 1996. According to ABB, the FGD performance tests will be completed by the end of May 1997 and the units put into commercial operation by the first part of June.
ESP reduces pollution at heavy fuel oil-fired plant
Dunamenti power station is the largest electric power plant in Hungary with six units of 215 MW each. The heavy fuel oil burned in the plant has a sulfur content of 2 to 3 percent and substantial amounts of nickel and vanadium. Before the installation of an electrostatic precipitator (ESP), the flue gases leaving the plant caused heavy pollution of the ambient air in the vicinity of the plant.
To overcome the pollution problems associated with the power plant and meet the new Hungarian Environmental Act, a decision was made to install an ESP at the Dunamenti power plant. A contract was eventually signed in March 1994 with Lurgi GmbH of Germany for the supply and construction of an ESP. One of the main reasons for Lurgi being awarded the contract was an Austrian reference plant firing heavy fuel oil with a very high sulfur content.
Since startup of the ESP, the plant is not only able to collect the fly ash but is substantially reducing the emission of SO3, nickel and vanadium. With the success of the first ESP, the plant`s management is now planning to install additional ESPs.
Dutch power plant meets stringent NOx emissions
When commissioned in 1993, the 630 MW Hemweg power station in the Netherlands was required to meet some of Europe`s most stringent NOx emissions–300 mg/Nm3 (6 percent O2)–when burning coal. Meeting the mandated NOx limits was achieved by controlled combustion alone and did not require the installation of an expensive deNOx system. Because Hemweg power station is in a densely populated area near Amsterdam, the plant not only had to limit the emissions of NOx, but it also had to control the emissions of SO2 and particulates. A FGD system supplied by Dutch Hoogovens Technical Services controls SO2 emissions.
The Hemweg po-wer station is a pulverized coal-fired supercritical unit supplied by Stork Ketels of the Netherlands. In order to control NOx emissions, high-temperature NOx reduction (HTNR) burners were installed and two-stage combustion was applied. Because of the large furnace area of the boiler, the burners were able to be mounted at a greater distance from each other. As a result, there is an increase in furnace wall heat absorption near the burners which in turn decreases the flame temperature, thus reducing the formation of thermal NOx.
A total of 36 HTNR coal/natural gas burners have been installed–three rows on the front and three rows on the rear of the boiler. Each row has six burners. With this design the burner zone heat release is low, the temperatures minimized and NOx emissions lowered. Two rows of OFA ports have also been installed on the front and rear walls of the furnace.
About 35 percent of the combustion air, for the two-stage combustion process, is supplied through the OFA ports. The end result is a deficiency of oxygen near the burners, sub-stoichiometric conditions between the burners and the OFA ports and an excess of oxygen in the upper part of the furnace above the OFA ports. In the area between the burners and the OFA ports, a reducing zone is created, thus minimizing the emissions of NOx. The combination of HTNR burners, two-stage combustion and smaller coal particles now allows the Hemweg power station to meet the NOx limits of less than 300 mg/Nm3 (6 percent O2) during commercial operation. Residence time of the coal particles is also a factor in reducing NOx.
For this reason, during part-load operation the upper rows of burners are taken out of service which maximizes the residence time of the flue gases in the furnace. A 24-hour monthly average of NOx emissions for June 1995 was 264 mg/Nm3 (6 percent O2).
Performance tests conducted during commissioning and commercial operation of the plant have demonstrated that low-NOx emissions can be achieved by controlled combustion methods alone, and the use of other deNOx systems is not necessary.
The wet limestone/gypsum FGD system at Konin power station, Poland
A: absorber with stack
B: force draught fan
C: air steam-heater for flue gas reheat
D: limestone silo
E: gypsum storage