Upgrading older power plants can be more cost effective than new construction
Because of lower capital cost and shorter downtime, electric utilities are now upgrading their older power plants to boost capacity
Douglas J. Smith
Minimum environmental impact coupled with high availability and efficiency are key to the design and operation of today`s electric power plants. Obviously, the construction of modern start-of-the-art power plants can meet all of the criteria mentioned but the capital cost for such plants is very high. Electric utilities in eastern Europe, India and China all have a need for more capacity and are actively constructing new power plants. However, they also have many older, inefficient power plants that could be upgraded at less cost than the construction of a new plant. Upgraded power plants invariably see an increase in capacity from improved efficiency and reliability.
Upgrading of older fossil-fueled steam power plants, in addition to adding capacity for less cost, has additional benefits:
– no licensing required as the site is already available,
– transmission lines and other infrastructure are in place,
– less downtime for construction and
– less capital investment.
In addition to the benefits just mentioned, retrofitting fossil-fired power plants, especially with gas turbines, can help electric utilities comply with more stringent pollution control mandates.
Figures 1 and 2 show two ways in which fossil-fueled power plants can be converted to combined cycle: topping and parallel repowering. In the topping cycle the hot, oxygen-rich exhaust gas from the gas turbine is used as combustion air to fire a boiler, thus eliminating the need for an air preheater. The flue gas exhaust from the gas turbine is also used to heat the feedwater and condensate.
With parallel repowering, the exhaust gas from the gas turbine is utilized in a heat recovery steam generator (HRSG). The steam produced in the HRSG supplements the steam from the plant`s existing fossil-fired boilers used to drive steam turbines. In parallel repowering, the HRSG is connected to the steam cycle via steam and water lines. However, unlike the topping cycle, the air preheater is retained.
A third method for converting to a combined-cycle configuration is boosting–using the gas turbine`s exhaust to heat some of the condensate and feedwater. Because less extraction steam from the steam turbine is used in a boosting configuration the output of the steam turbine is increased.
According to Siemens of Germany, the cost effectiveness of the different repowering options is determined by the upgrading costs, the degree to which the capacity and efficiency can be increased and the length of the downtime required for the retrofit. Generally speaking it is more expensive to upgrade to a topping configuration than to parallel repowering. The increased cost is for the boiler, which is more complicated to refit for a topping cycle than for parallel repowering. In addition, the downtime is six to eight months as opposed to one-and-a-half to two months for parallel repowering.
The two-unit Marghera Levante power plant, owned by Edison Termoelettrica S.p.A., is located near Venice in northern Italy on the Adriatic Sea. Unit 1, a 165 MW unit, was put into commercial operation in 1965 and Unit 2, also a 165 MW, went commercial in 1971. All of the steam and electricity produced was sold to a nearby petrochemical plant.
However, because of the need for more capacity, better availability and to reduce emissions of the power plant, the owners decided to upgrade the plant by converting it to combined-cycle operation. Upgrading of the plant included the installation of two GE gas turbines and two Vogt three-pressure HRSGs. The new gas turbines each have an electric output of 127.9 MW while the HRSGs supply 174 t/h of superheated steam at 42 bar and 505 C. Figure 3 shows a schematic of one of the repowered combined-cycle units at the Marghera Levante plant.
In addition to operating in the combined-cycle mode, the plant can be operated in simple cycle or operated as a conventional plant with just the steam turbines and the boilers. When the plant is operated with the gas turbine in simple-cycle mode, all of the steam produced by the HRSGs is used by the petrochemical plant. Natural gas is the main fuel, but in emergencies fuel oil can be utilized.
With the repowering complete, the Marghera Levante plant is now able to meet Italy`s standards for the emissions of SO2. Similarly, because the gas turbines use steam injection and the plant switched from fuel oil to natural gas as the primary fuel, there has been no increase in NOx emissions.
Besides converting the plant to combined-cycle operation, new control and burner management systems were installed, and the steam turbine`s moving blades in the intermediate pressure section of the turbines were upgraded. Modification of the blades has increased steam flow through the turbine, thus augmenting the steam turbine`s capacity by an extra 8 to 10 MW. Each of the upgraded steam turbines can now produce a gross electric output of approximately 170 MW.
When operated in combined-cycle, the plant has a heat rate of 1,950 kcal/kWh and a gross plant efficiency of almost 60 percent.
Slagging problems at Tuncbilek
Tuncbilek power station and lignite mine are located in the northwestern region of Turkey about 300 km west of Ankara. The power station has five units: Units 1 and 2 are 32 MW each, Unit 3 is 65 MW and Units 4 and 5 are each 150 MW. From startup in the mid- to late 1970s, Units 4 and 5 experienced problems with slagging on the furnace water walls. Slagging was particularly severe in the burner areas and the primary superheater section located at the furnace outlet.
As a consequence of the slagging, the units suffered from poor availability and unit capacity could only be maintained at 60 to 70 percent of maximum continuous rating. Besides the slagging problems, the sootblowing system on each unit was inadequate and pollution from the units was unacceptable. To rectify these problems, the Turkish Power Generating Co., owner of the Tuncbilek station, made the decision in the early 1990s to upgrade and rehabilitate Units 4 and 5.
The lignite-fired boilers on Units 4 and 5, commissioned in 1977 and 1978, were designed as natural circulation, balanced draft units. Originally the units were designed with indirect firing with six pulverizers discharging into mechanical cyclones arranged in parallel, as seen in Figure 4. The mechanical cyclones separated the pulverized lignite from the transport flue gas.
A major part of the upgrading of Units 4 and 5 was the conversion from indirect to direct firing and the replacement of the lignite and oil burner assemblies with new ones. Two additional lignite and oil burner assemblies were also added. The original pulverizers were retained, but they now transfer the pulverized lignite directly to the burners, thus bypassing the mechanical cyclones. Similarly, to optimize the plant`s operation, a modern control and burner management system has been installed. The new lignite burner assemblies have been installed on the furnace side walls to supplement the existing burner assemblies mounted on the furnace corners. Each pulverizer is coupled to a lignite burner assembly. Other upgrades carried out to the units included:
– new sootblowers,
– new induced draft fans,
– new third-stage superheater attemperators and
– upgraded intermediate spray water attemperators for the reheat section.
Figure 5 shows a schematic of the direct firing system after the upgrade. The direct firing system was designed to reduce the overall furnace temperature at rated load. However, the design allows the flame temperature in the lower portion of the combustion chamber to increase and the flame temperature in the upper burner zone to decrease. As a result, the formation of slag is reduced or, in many cases, eliminated.
Unit 4 was returned to service in July 1995 and Unit 5 in January 1996. According to Ansaldo Energia, the units meet all of the performance guarantees–increased availability and the reduction of dust and NOx emissions. Ansaldo Energia, the major contractor for the Tuncbilek upgrade, subcontracted with Ziomar Podolsk of Russia for the supply of the fuel-firing equipment.
Upgrade in Poland
Rybnik power plant in Poland awarded Westinghouse Electric Corp. of the US a contract to modernize the low-pressure (LP) turbine on a 200 MW Russian-designed steam turbine installed on Unit 4. According to the contract, the following criteria had to be met:
– The new LP rotor must not have any adverse impact on the balance of plant equipment.
– All torsional and lateral rotor system frequencies should be safely away from the design operating range.
– Interface between the existing supervisory instrumentation should not be affected by the upgrade.
– The cause of the high vibration at the LP and generator supports has to be identified and corrected.
According to Westinghouse, in order to minimize cost and maximize customer return on investment, any upgrade should reuse as much of the original equipment as possible. This requires significant up-front work in order to evaluate the original equipment and for determining its use in the upgraded power plant, according to Westinghouse. Although the process can be time consuming, it is important as it not only reduces manufacturing costs, but it also reduces outage time for the upgrade.
According to Westinghouse, the important part of any assessment should be the checking of critical dimensions of the parts to be replaced or retained. Prior to being awarded the contract, Westinghouse sent a team of experts to assess similar Russian-designed turbines installed at the Laziska power plant in Poland, which was undergoing an outage at the time. After being awarded the contract, a second team was sent to the Rybnik station to verify that the Unit 4 steam turbine was the same as that checked at the Laziska plant.
The major problem with the Russian-designed LP turbine was its low thermal performance and operating efficiencies of 60 to 70 percent. Because of the high flow losses associated with the older blade design, Westinghouse had the opportunity to upgrade the LP turbine with state-of-the-art technology that would provide efficiencies above 85 percent.
The Rybnik LP turbine upgrade consisted of three parts:
1. reinforcement of the inner cylinders,
2. installation of redesigned and/or modified components, and
3. installation of rotors and the assembly of blade rings and other stationary parts.
Modernization of the Russian-designed 200 MW LP steam turbine has significantly improved the mechanical and thermal performance over the old design. Westinghouse Electric reports that the operating performance of the upgraded Unit 4 LP turbine at Rybnik has exceeded all guarantee criteria by more than 13 percent. The customer is on re-cord as saying, “The worst vibrating unit in Poland has now become the smoothest operating unit.”
Without an efficient operating condenser, no steam turbine can perform to its maximum efficiency. Optimizing condenser performance is critical, and any upgrading of power plants should include renovation of condensers. In relation to the overall cost of upgrading other power plant equipment, the cost for condenser refurbishment is relatively inexpensive. Some of the problems that are encountered with condensers and the possible causes are outlined in Table 1.
Condensers used in today`s modern power plants are designed for a life of more than 30 years without loss of efficiency or the need for a major overall. However, this assumes that the plant is operated according to the design specification of the condenser and that the cooling water used has not changed. Unfortunately, this rarely is the case, and invariably the condenser needs refurbishing after 10 to 15 years of service.
The economic consequences of inefficient condensers can be quite significant. A steam turbine`s exhaust temperature is very important because the more it is above the design value the worse the heat rate becomes. According to a paper by Christian Pouzenc and Francois Taveau of GEC Alsthom Delas, with a 300 MW fossil-fired power plant an increase of 5 mbar in the nominal exhaust pressure would result in a loss of 1.2 MW to the grid. A similar increase on a 900 MW nuclear power plant would mean a loss of 5.4 MW.
When high oxygen levels occur in the condensate, the water leaving the condenser must be deaerated completely by injecting auxiliary steam into the condenser hotwell. When this happens, the output of the power plant is reduced. As an example, Pouzenc and Taveau mention the renovation of the condenser on Unit 1 at the 900 MW French Dampierre nuclear power station which eliminated the use of auxiliary steam injection. The end result was a net gain of 7 MW.
When condenser tube bundles have degraded due to erosion and/or corrosion, invariably the condenser is retubed with tubes of a different material than originally specified. Obviously, this assumes that all other components of the condenser are in good condition. Tubesheet corrosion and/or erosion can be avoided by using a protective coating applied to the condenser`s tubesheets. This procedure can be done on site at the same time the condenser is being retubed.
Where an existing condenser needs more than a simple retubing or the application of protective coatings, a complete revamping may be the answer. Under this scenario the condenser`s internals and tube bundles are invariably redesigned to optimize its performance. Downtime for a complete rehabilitation of the condenser is substantially longer than that for a retubing job.
With a shortage of financing for the thousands of megawatts of new capacity required in China, India, southeast Asia and eastern Europe, electric utilities are looking at other ways to increase capacity at less cost. Because electric utilities in these countries have many inefficient older power plants still in operation, the solution might be the upgrading of these power plant to improve their efficiency.
Although it might not be cost effective to upgrade all of the older plants, there are certainly some that can cost effectively be upgraded to improve their operating efficiency. Not only does a more efficient power plant produce more energy, it is also less polluting. As a consequence of upgrading, electric utilities are able to increase capacity, reduce pollution and reduce capital expenditure.