ABB, Asia, EDF, Europe, North America, Siemens

Efficiency, reliability and control of pollution enhanced during plant upgrade

Issue 2 and Volume 4.

Efficiency, reliability and control of pollution enhanced during plant upgrade

Improving a power plant`s efficiency and availability adds capacity and reduces emissions

By Douglas J. Smith

Managing Editor

Design of today`s modern steam power plants is primarily dictated by economic considerations. However, electric utilities do place high demands on plant availability and operating flexibility. In addition, in today`s environment, power plant designers must design a plant to meet a country`s environmental regulations. One of the most effective technologies for limiting environmental pollution is through the promotion of high-efficiency power generation.

Because of the expense of constructing new power plants, many of the world`s electric power utilities are looking at upgrading existing electric generation facilities to improve efficiency and reliability. To accomplish this, utilities are upgrading boilers, turbines, controls and auxiliary systems. Upgrading is also a prerequisite if utilities are to remain competitive. Renovation and upgrading of power plants can be cost effective because less capital is required than that needed for constructing a new greenfield power plant. One major advantage, and certainly a factor in reducing costs, is that existing sites can be re-used.

Invariably, countries that have a need for new capacity can supply some of their capacity requirements by upgrading inefficient older power plants. A comprehensive power plant upgrade would include:

– retubing condensers,

– replacing steam reheating system,

– upgrading superheaters, steam turbines and cooling towers, and

– installing state-of-the-art control systems.

However, it is not always necessary, or even cost effective, to carry out comprehensive power plant upgrades. In some instances the installation of a modern control system is all that is needed.

Condenser and cooling tower improvements

Condensers are designed for a life of more than 30 years without loss of efficiency or major overhauls. Of course, this assumes that the cooling water characteristics and the operation of the plant have not changed from the plant`s original design conditions. However, this rarely happens and condensers invariably need major renovation and upgrading after 10 to 15 years.

Modernization and upgrading become necessary when condenser tube leakages are the cause of forced outages or when cooling water characteristics change substantially. An increase in condenser pressure, caused by an increase in turbine exhaust pressure increases a plant`s heat rate and subsequently decreases the amount of electricity generated. Table 1 shows typical condenser problems and possible causes.

Robert Burger, president of Burger Cooling Tower Co., Dallas, Texas, USA, says cooling towers have historically been the orphans of electric power plants. However, the cooling tower plays a major role in the efficient operation of electric power plants.

Circulating cooling water systems suffer from a variety of problems including corrosion, erosion and degradation from galvanic action. Over the years electric utilities have used a variety of materials in an effort to reduce or eliminate these problems. However, because cooling system components have different mechanical requirements, it is not uncommon to find concrete, carbon steel, stainless steel, cast iron and brass used in a variety of applications. When used alone, most of these materials generally solve the problems, but when combined they can be an engineer`s nightmare.

A paper presented at the POWER-GEN Asia(TM) `95 conference in Singapore, “Life extension for circulating water systems and condensers using 100-percent solid epoxy copolymers” presented by Duromar Inc., USA, and Florida Power Corp., USA, discussed problems due to galvanic and microbiologically induced corrosion. The latter is caused by some of the newer materials now being utilized in cooling water systems, the authors said.

According to the Duromar speaker, 100-percent solid epoxy systems offer the most effective and long-term solution to erosion and corrosion problems in cooling systems. However, because there are as many variations of epoxy systems as there are problems, it is very important that one selects the right epoxy.

Renovating problem areas

Figure 1 is a schematic of a typical circulating water system. Traveling water screens made from carbon steels (or 304 stainless steel when originally installed) are painted with an alkyd or coal tar epoxy. Unfortunately, as the paint deteriorates, corrosion and galvanic action tend to take place. During major plant outages, these screens are removed and repainted. Because the screens must be removed for this procedure to be successful, it can be costly.

A more reliable and less costly alternative to repainting is to apply a rubberized epoxy copolymer. In this application, the epoxy material chosen must have good abrasion resistance and be flexible enough to handle any movement of the screens. Similarly, the material must be capable of being applied using conventional airless spraying systems without removing the screens.

When originally constructed, the intake tunnels of cooling water systems were usually lined with rubber. Even though this solves the problem of erosion and corrosion, the rubber is susceptible to damage, and over time the adhesives can fail. Rubber linings also can be difficult and time consuming to repair.

Although new rubberized epoxy copolymers show potential as a replacement for rubber linings, an underwater curing material may have to be utilized. The epoxy copolymer material should also be able to cure at or below ambient conditions.

Condensers are another area where epoxy coating has been successful. When utilized in condensers, a 5-mm solids epoxy-cladding is installed on the tubesheets. This coating completely seals the tube to tubesheet joint, thus protecting it from corrosion, erosion and/or physical damage. According to Raymond Jaworowski of Duromar Inc., several thousand tubesheets have been coated in this way, and the oldest installations have more than 25 years of service without any problems.

To prevent erosion at condenser tube inlets from entrained solids in the cooling water, it has been the practice to install metal or plastic inserts into the end of the tubes. Unfortunately, this transferred the erosion problem to the inserts. However, an abrasion-resistant thin film of 100-percent epoxy can now be used to line the ends of the tubes. When installed correctly, it becomes an integral part of the epoxy cladding on the tube sheet.

A procedure for coating the entire length of condenser tubing with epoxy has also been developed by Duromar. Although commercial application is limited at this time, its application has been evaluated in USA, German and Italian power plants. Early results from these tests look very promising.

EGAT`s cooling tower upgrade

Because of the need to reduce the impact of water recirculation on the Bang Pakong River, the Electricity Generating Authority of Thailand (EGAT) made the decision to retrofit its Bang Pakong power station with what is reported to be one of the world`s largest cooling tower installations. According to Black & Veatch, Architect-Engineers of the USA, the cooling towers have been installed as “helper cooling towers.” The major objective of the retrofit is to reduce the temperature of the circulating water discharge from the power station into the river.

Bang Pakong power station is on the east bank of the Bang Pakong River and is approximately 10-km upstream from the Gulf of Thailand. At this location, the river is strongly tidal and during the dry season–March and April–the flow stagnates and at times reverses direction. March and April are also the warmest months of the year. Not only is the plant`s efficiency severely impacted when this occurs, but it also puts thermal stress on the river. Research into the problem indicates that the river`s flow-reversal problems will worsen in the future because of plans to add a check dam upstream of the power station. Not only would this cause the power station`s efficiency to drop further, there is an increased likelihood that environmental problems could occur in the river in the vicinity of the power station.

Four thermal electric power units, with a total generating capacity of 2,300 MW, and four combined-cycle generating blocks, with a total capacity of 1,380 MW, are installed at the Bang Pakong power station. All the units are cooled by once-through circulating water systems. During peak loading, the flow of cooling water from the river into the cooling systems is 136,000 l/s.

To overcome the station`s cooling water problems, EGAT made the decision to construct additional cooling towers. Thus adding a further 114,000 l/s of circulating water to the plant. When all of the towers are in operation, approximately 70 percent of the power station`s waste heat from its steam cycle is rejected directly to the atmosphere instead of into the river.

Because higher discharge temperatures have the potential to cause environmental damage to the Bang Pakong river`s ecological system, EGAT, prior to the installation of the helper towers, were forced to derate the station`s units at the most critical time of the year–a time when EGAT needed the most amount of electricity to meet its customer`s needs.

Not only is the water from the river used to cool the condenser, it is also used for the generator coolers, steam turbine lube oil coolers, condenser air removal system coolers and the station`s air compressors. Although higher cooling water temperatures typically impact the surface condenser, increased cooling water temperatures above the design figure also means that the Bang Pakong plant`s generator must be derated because of the inability of the warmer cooling water to properly cool the generator.

The solution

After a study of the cooling water problem at Bang Pakong power station by EGAT and Black & Veatch, it was decided that the following modifications would be required to return the power station to peak loading and reduce the potential for ecological damage to the river:

– Install helper cooling towers at the circulating water discharge,

– Convert from a once-through to a closed-cycle circulating

– water system,

– Pump cooler water from an upriver location for the circulating water intake and,

– Discharge the station`s circulating water directly to the Gulf of Thailand.

According to Black & Veatch, this solution provided the lowest capital cost and eliminated a large part of the heat-load discharged into the river and the Gulf of Thailand. The end result would allow the station to maintain peak gross generating capacity during the hottest parts of the year. A major advantage of the proposal was that the design, procurement and construction could be accomplished in a very short period of time. In addition, the construction could be completed with minimal outages of the existing units.

It was determined that because of the size of the helper cooling towers and associated pumps, piping and auxiliary equipment that the installation could not be completed before the 1994 dry season. However, a design and construction schedule was developed that allowed the majority of the helper cooling towers to be put into service by the 1995 dry season. Units 1 through 4 were put into service in the spring of 1995, and the remaining two units, 5 and 6, were put into commercial operation in December 1995. Figure 2 shows a schematic of the layout of the upgraded version of Bang Pakong station`s cooling water system. EGAT was able to eliminate derating of Bang Pakong power station during the 1995 dry season and was thus able to supply electricity to meet Thailand`s increasing need.

Martinlaakso CHP repowered

When the Martinlaakso combined-heat power station was put into commercial operation in the fall of 1975 it was fired with No. 6 fuel oil and had an output of 60-MW electrical and 120-MW thermal. Over the years, many additions have been made to the plant, including adding a coal-fired plant in 1982 and converting from No. 6 fuel oil to natural gas in 1989. The latest upgrade was the installation of an ABB GT8C gas turbine and heat recovery steam generator (HRSG) in 1993. Today the plant has a total capacity of 200-MW electrical and 310-MW thermal.

Figure 3 is a simplified flow diagram of the upgraded Martinlaakso combined-cycle district heating plant. Construction for the repowering of Martinlaakso started in April 1994, and plant startup went from Nov. 11, 1994, through April 13, 1995. The repowered plant went into commercial operation on May 11, 1995. Since that time the utility has been able to drastically reduce its power purchase requirements.

Steam turbine upgrades

Efficiency of older steam turbines can be increased by retrofitting the latest designed blades. Figure 4 indicates typical turbine losses for a 1970 era 600-MW reheat turbine generator. Applying modern steam turbine technology to older steam turbines can bring them up to almost today`s new turbine standards, reports Seimens Power.

When a power plant finds that its steam turbines have reached the end of their operating life, it is sometimes cost effective to completely modernize and upgrade the turbines. Before making this decision, it is advisable to carry out an analysis of the steam turbine`s condition. This will allow the engineers to determine the scope and cost effectiveness of upgrading the turbines. Obviously, the main reason for upgrading older steam turbines is to improve efficiency and capacity. However, upgrading steam turbines also increases the equipment`s life and improves its availability.

In older units, the greatest losses occur in the blading itself and from the blade tip clearances. Because of this, a steam turbine upgrade will invariably include replacing stationary and moving blades along with the rotor and casing. When a steam turbine`s rotor and inner casing is replaced, it is sometimes possible to also install a larger last stage. The end result is a larger exhaust area, which thus reduces the outflow velocities and exhaust losses.

Increasing a condenser`s vacuum will also increase the output from the steam turbine. Likewise, a plant`s efficiency can be increased by utilizing extract steam, particularly in steam turbines built in the 1950s and 1960s. Pressure between the IP and LP of these vintage steam turbines is approximately 2 to 4 bar at a steam temperature of 140 C. Extract steam at this temperature is ideal when used in district heating systems. Adding extraction steam to these older units involves the installation of an extraction nozzle in the casing of the older turbine, and the installation of two valves in the crossover pipe for pressure control. However, it is important that during operation, the operators pay careful attention to the exhaust steam temperature in the IP turbine.

Aging steam turbines upgraded

Utilizing state-of-the-art technology, Seimens Power improved the performance of the Wedel cogeneration/district heat plant in Hamburg, Germany. Due to the growing demand for district heating from the Wedel plant, the electric utility, Hamburgische Electricitäts-Werke made the decision to convert the two units at the Wedel plant from exclusive condensing units to extract units. The steam turbine on Unit 1 was replaced with a new steam turbine specifically designed for steam extraction. However, Unit 2 was converted to steam extraction.

The first step in the upgrading of Unit 2 was to determine its condition. This was done by reviewing the maintenance and operating records of the plant and through diagnostic analysis of the unit. From this data, it was determined Unit 2 had operated for more than 173,000 hours and had been through 402 starts. In addition, it was determined that during this time period, some of the materials in many areas of the unit had exceeded their design lives.

After reviewing all of the data and conducting a cost-effective analysis based on extending the life of the unit for a further 200,000 hours of operation, a decision was made to upgrade the HP and IP turbines and auxiliary systems. The HP turbine was replaced with a new single-flow barrel-type turbine with a control stage. According to Seimens, the advantage of this design is that its axial symmetry prevents most accumulations of materials and associated thermal stresses. Along with other improvements made to the HP turbine, its efficiency was increased by approximately 6 percent, Siemens stated.

Conversion of the IP turbine included adding heat extraction points and replacing the last five rows of moving and stationary blades with blades having a different profile and blade height. The new blades are cylindrical in shape and have a constant profile over the length of the blade. As a result, profile losses are reduced. Likewise, integral shrouds reduce the clearance and exhaust losses in the final stages.

Besides upgrading of the steam turbine, the design of the boiler was changed to increase its mass flow from 390 ton/hr to 430 ton/hr. Through the installation of new blading and the upgrading of the boilers, the capacity of the plant was increased from 121 MW to 137 MW. The result of the upgrade is increased plant availability, efficiency and plant capacity. This in turn has reduced emissions and fuel consumption and extended the life of the plant.

EdF power plant upgrades

Over the last few years, Electricit? de France has refurbished and renovated many of its thermal power plants. Under its refurbishment program Electricit? de France renovated Units 3 and 4 at its blast-furnace-fired Dunkirk plant. The work involved condenser retubing, replacement of the plant`s HP reheaters and the upgrading of the superheaters. In addition, the HP and IP steam turbines were upgraded. The controls system was also replaced with a state-of-the-art analog system. Upgrading of Unit 3 was completed in 1994 and Unit 4 in 1995.

To reduce overall emissions, Electricit? de France is in the process of retrofitting wet-limestone gypsum flue gas desulfurization (FGD) systems to its 600-MW coal-fired units: Cordemais Units 4 and 5 and Le Havre Unit 4. The Cordemais units and the unit at Le Havre were all put into service in the early 1980s. Start up of Unit 4 and 5 at Cordemais is scheduled for 1997 and 1998 respectively. Le Havre will also start up in 1998.

What`s the answer?

When electric utilities have a need to add new capacity, the first thing that should be evaluated is the possibility of upgrading older units to make them more efficient and reliable. In general, if this proves to be the most cost-effective solution, management should consider taking this route rather than constructing new and more expensive greenfield power plants.

From the developed industrial nations of the west to the fast developing nations of Asia, upgrading of existing power plants is one way of increasing capacity. The end result is a more reliable, efficient and less polluting power generation system.

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EGAT`s Bang Pakong thermal electric power station, Thailand. Photo courtesy of Black & Veatch, USA.

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