Power Plant Repowering with District Heating Supply

District heating systems offer a great way to improve fuel utilization at power plants. Two projects—one in the U.S. and one in Russia—that involved adding gas turbines and heat recovery steam generators to existing facilities demonstrate the benefits repowering can provide.

This article describes two power plant repowering projects, which resulted in improvements to heat rate and district heat supply.

Jamestown, New York

The Carlson Generating Station of the City of Jamestown, New York, offers one example of an old, inefficient plant that underwent a repowering project. Originally the power plant included four coal-fired boilers and two steam-driven turbine-generator units with total electric capacity of 50 MW (Units 5 and 6), both with General Electric non-reheat turbines.

Unit 6 was modified for district heating (combined heat and power [CHP]) operation considering its relative ease of retrofit to cogeneration. This turbine (a 25-MW, 3,600 rpm, 15-stage, single-flow condensing unit) was designed to operate at 850 psig steam pressure, 900F temperature, and 3.5 inches of Hg condenser pressure.

The turbine had one blanked-off extraction point at the 11th stage from which steam was extracted for a new district heat exchanger (Figure 1). Higher loads were served with additional steam from the auxiliary steam header and used in the existing auxiliary heat exchanger that was arranged in series with the new district heat exchanger.

1. Diagram of Carlson Generating Station Unit 6. Courtesy: Joseph Technology Corp.

Single-purpose efficiency for Unit 6 was 26.9%. After unit conversion to district heating operation, the efficiency increased to 32.5%, a 20% improvement. Modifications to the turbine were not required because the redistribution of extraction flows was minimal and all existing feedwater heaters remained in service without modification.

Based on this modification a hot water district heating system was developed (Figure 2). During peak heat load operation, the return water temperature is 160F with water supply of 250F. The district heating water flowrate during peak load conditions is 498,000 lb/hr. The maximum extraction flow available from the turbine’s 11th stage provides heating for 379,000 lb/hr of district circulating water to 210F. At the maximum heat load conditions, 119,000 lb/hr of district heating water bypasses the district and auxiliary heat exchangers.

2. This diagram shows the district heating piping network in the City of Jamestown, New York. Courtesy: Joseph Technology Corp.

F effluent water from the district heat exchanger is passed through the auxiliary heat exchanger. This increases its temperature to above 250F. Thus, when mixed with the 119,000 lb/hr of bypassed water at 210F, a total flowrate of 498,000 lb/hr at 250F is produced.

The district heat exchanger operates throughout the year, providing hot water for both space heating and domestic use. The auxiliary heat exchanger operates about one-third of the year. The maximum operating pressure of the district heat exchanger is about 20 psia; the maximum operating pressure of the auxiliary heat exchanger is 60 psia with a maximum steam flow of 18,900 lb/hr.

Later, the power plant was converted into a more efficient and technologically advanced combined cycle plant. A GE LM6000 gas turbine coupled with a Deltak heat recovery steam generator (HRSG) was installed at the plant (Figure 3). In simple cycle operation, the gas turbine unit generates 43 MW of electricity. With the use of the HRSG and the older steam turbines 5 and 6, the plant can be operated in combined cycle configuration producing about 80 MW of electric power and 80 MMBtu/hr of thermal energy.

3. Repowered combined cycle power plant diagram. Courtesy: Joseph Technology Corp.

Since the combustion process of natural gas occurs at much higher temperatures than normal boiler operation, it allows for the production of steam using the high-temperature exhaust gases from the gas turbine exit. This removes dependency on old, inefficient boilers to produce the steam, and allows for much higher fuel utilization. At current peak conditions, the plant operates with 36% electric efficiency. The addition of the gas turbine and HRSG improves the overall efficiency to about 56% when district heating is included.

The Deltak HRSG also includes a coil for district heating purposes. A portion of the 170F condensate leaving turbine 6 enters the coil and is heated to approximately 375F. This water then passes through a new heat exchanger and provides the district heating water with about 20 MMBtu/hr of heat, or it can pass through a flash separator and turn into low-temperature steam to provide the deaerators and decrease the amount of steam needed to be extracted from the turbines.

This new system represents the possibility for substantial savings in electrical production because less steam extracted from the turbines results in an increase in electrical production. However, the amount of steam available to the deaerators from the flash separator is inherently dependent on the required flow of water through the new district heat exchanger. The lower the flow required, the more flow will be available to the flash separator. In order to reduce this flow, the temperature differential of the district water must increase. This may be accomplished by lowering the return temperature of the district heating water so that more heat can be extracted from the power plant.

St. Petersburg, Russia

For a number of years, the electric utility in St. Petersburg has been improving the efficiency of its electric generation. The repowering of its 250-MW CHP generating unit with a 52.9-MW gas turbine at the Southern Plant is described below.

The Southern CHP plant has an installed electric capacity of 750 MW and heating capacity of 2,326 MWth. It generates electricity and provides district heating to the adjacent southern city district.

Unit 3 of the power plant was selected for repowering. The unit’s electric capacity was 250 MW in the district heating mode and 300 MW in the condensing mode. The unit is equipped with a supercritical steam generator producing steam at 3,700 psig and 1,013F with a capacity of 2,204,000 lb/hr. It was designed for firing both natural gas and oil. The steam turbine is an extraction/condensing machine with two controlled district heating extractions. The steam condenser of each turbine is equipped with built-in bundles to preheat the district heating makeup water. The district heating system of the plant provides a significant quantity of makeup water.

In order to prevent internal corrosion in the underground district heating piping, the makeup water in the system must be deaerated. The unit flow diagram is presented in Figure 4. The makeup water is passed through the preheating section in the steam turbine condenser and then goes to a vacuum deaerator. To prevent losses of steam from the plant cycle, district heating supply water at a temperature of 230F is flashed into steam, which is used as a heating medium in the vacuum deaerator.

4. Flow diagram of the 250-MW unit at Southern Plant in St. Petersburg, Russia, before repowering. Courtesy: Joseph Technology Corp.

An ABB/Alstom gas turbine was selected for repowering. The electric output of the gas turbine at International Standards Organization (ISO) conditions is 52.9 MW. The gas turbine hot exhaust is delivered to the boiler burners and partially replaces the stoichiometric air needed for the combustion process. The oxygen content in the exhaust is about 15% versus 21% in the air.

The gas turbine with a fixed exhaust gas flowrate cannot deliver all the oxygen required for the combustion process and a conventional air heater (AH) is still necessary. The hot air leaving the AH is mixed with the gas turbine exhaust as it leaves the turbine. This lowers the temperature of gas-air flow in the gas turbine-boiler duct and eliminates the use of expensive high-temperature duct material.

Thus, the gas-air mixture delivers the oxygen needed for the combustion process to the flame area of the boiler. The total flowrate of the flue gas through the boiler increases due to the replacement of a portion of the combustion air with gas turbine exhaust, which has less oxygen content, and as a result, a larger amount of the exhaust gas provides the same amount of oxygen as the replaced air. Therefore, the need for a portion of the combustion air heated in the AH is eliminated and the flue gas flowrate is increased. The heat available from the flue gas after the economizer can be utilized. Installing an additional heat exchanger in the flue gas tract downstream of the water economizer provides the heat utilization.

However, operational experience has demonstrated that the plant is firing oil for a substantial period of time. This brings into consideration the issue of sulfur content in the flue gas of the boiler. The temperature regime of the heat exchanger will cause sulfuric acid vapor condensation. Therefore, the heat exchanger tubing would have to be made of an expensive acid-resistant material, or coated, otherwise it would be corroded. Therefore, the repowering arrangement shown in Figure 5 was selected.

5. Flow diagram of the Southern Plant’s repowered cycle arrangement. Courtesy: Joseph Technology Corp.

As a heating medium, the new heat exchanger (HX) utilizes a portion of the hot stoichiometric air replaced by the hot gas turbine exhaust. Thus, the combustion air stream is split after the air heater. Part of it is mixed with the gas turbine exhaust and supplied to the boiler, while the rest is directed to the HX where it heats the makeup water and is then introduced to the air flow after the air preheater. The arrangement involves heating of the makeup water after the steam turbine condenser bundle up to about 50C, the temperature needed to enter the vacuum deaerator. The repowered cycle arrangement is presented in Figure 6.

6. Flow diagram of the 250-MW unit at Southern Plant in St. Petersburg, Russia, after repowering. Courtesy: Joseph Technology Corp.

The advantage of this arrangement is that the flue gas does not go through the heat exchanger, therefore, there is no sulfuric acid vapor condensation on the tubing. However, a certain sulfur content in the hot air is possible due to leaks inside the air heater. The new HX installed to heat makeup water replaces some steam flow previously used to heat the makeup before entering the vacuum deaerator. Therefore, more steam is available for district heating and the unit thermal output increases.

According to the existing dispatch schedule, Unit 3 is operated for approximately 5,790 hours per year. Thus, the repowered unit will also be operated for the same number of hours per year.

Performance of the Repowered Cycle. The results of energy balance analyses for the repowered unit is presented in Table 1. The load duration, and its relation to the ambient air and district heating water supply temperatures, is shown in Figure 7. It demonstrates the dependency between the district heating load, fuel utilization, and the district heating water temperature at any ambient air temperature.

Table 1. Energy balance of repowered Russian unit. Source: Joseph Technology Corp.

7. Heat load duration, fuel utilization, and district heating water temperature in St. Petersburg, Russia. Courtesy: Joseph Technology Corp.

Utilizing the bin method and temperature duration, the monthly quantities characterizing unit operation have been determined. The assessment is based on the comparison of monthly quantities of electricity and heat supply for the existing and repowered unit. The fuel input to the unit and an average monthly efficiency for the repowered unit have also been calculated and compared with the existing unit fuel input and efficiency. Efficiency represents the fuel utilization rate.

The comparison of performance parameters of Unit 3 before and after repowering is presented in Table 2. Operational experience has confirmed the major design parameters and indicated that the unit performance is close to estimated values.

Table 2. Southern Plant Unit 3’s performance parameters before and after repowering. Source: Joseph Technology Corp.

Emissions from the Repowered Plant. Combustion turbine exhaust gases have less oxygen, water, and carbon dioxide. This contributed to a lower flame temperature in the boiler, and therefore, to lower NOx formation. Another aspect of repowered cycle emissions is that the flue gas flowrate through the boiler has increased, while the NOx formation rate is reduced. This reduced the NOx concentration in the flue gas. The test results indicated that the NOx emissions on a per-kWh basis were reduced by 60%. ■

Ishai Oliker, PhD, PE ([email protected]) is principal with Joseph Technology Corp. He has been involved in power plant development and design in the former USSR, Korea, China, and the U.S. for more than 30 years.

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