6. Gas Turbine Performance

Transcription

1 6. Gas Turbine Performance T Combustion (heat In) Topping cycle Bottoming cycle Stack (heat out) Condenser (heat out) s Combined Cycle Power Plants 6. Gas Turbine Performance 1 / 101

2 Generals The gas turbine is a standardized machine, and can be used under widely different ambient conditions. Manufacturers quote gas turbine performances at ISO ambient conditions of 15C(59F), bar (14.7 psia), and 60% relative humidity. Gas turbine performance is mainly governed by pressure ratio, turbine inlet temperature, and efficiency of each parts. The performance of gas turbine is affected by its inlet and exit conditions. The most important items are pressure and temperature. Ambient weather conditions are the most obvious changes. Since the gas turbine is an air-breathing machine, its performance is changed by anything that affects the density and/or mass flow rate of air intake to the compressor. A smaller weight of air requires a smaller weight of fuel to mix with, and the mixture then produces less power when burned. Most peak power enhancement opportunities exists in the topping cycle. In general, however, performance enhancements to the gas turbines will carry with them an increase in bottoming cycle performance due to an associated increase in gas turbine exhaust energy. Duct firing within HRSG is an exceptional performance enhancement occurred in the bottoming cycle. Combined Cycle Power Plants 6. Gas Turbine Performance 2 / 101

3 Factors Affecting GT Performance Factors to be considered individually Solutions for power augmentation Is there a need for peak power production with premium paid for the resulting power? Does peak power demand occur on hot days (summer peaking) only? Supplementary firing in HRSG Steam / water injection GT peak load firing Is there a need to compensate the power reduction continuously during summer period? GT inlet air cooling Is frequency support required? Combined Cycle Power Plants 6. Gas Turbine Performance 3 / 101

4 Various Options for Power Enhancement Output = m h Options for power enhancements Typical performance impact Output Heat Rate Base configuration Base Base Evaporative cooling GT inlet air (85% effective cooler) +5.2 % - Chill GT inlet air to 45F % +1.6 % GT peak load operation +5.2 % 1.0 % GT steam injection (5% of GT airflow) +3.4 % +4.2 % GT water injection (2.9% of GT airflow) +5.9 % +4.8 % HRSG supplementary firing +28 % +9 % Note: 1. Site conditions = 90F, 30% RH(Relative Humidity) 2. Fuel = NG 3. 3-pressure, reheat steam cycle 4. At sites where large power enhancement is possible, the owner must verify that the added power is within the capabilities of the generator and transformer Combined Cycle Power Plants 6. Gas Turbine Performance 4 / 101

5 Typical Gas Turbine Sensors/Effectors Source: GE Combined Cycle Power Plants 6. Gas Turbine Performance 5 / 101

6 Percent design 1. Ambient Temperature [1/7] Because gas turbines are constantvolume-flow engines, they are very sensitive to changing ambient temperature and pressure. The output and thermal efficiency of the gas turbines decrease as air temperature increases. This is because an air density decreases as the ambient air temperature increases, thus the mass flow rate of air decreases because industrial gas turbines running at constant speed are constant volume flow machines. The thermal efficiency decreases as the air temperature increases. This is because compressor driving power increases as the air temperature increase. In addition, heat transfer efficiency of the blade cooling system decreases as the air temperature increases. Thus, more cooling air is needed as the air temperature increases F C Compressor inlet temperature Combined Cycle Power Plants 6. Gas Turbine Performance 6 / 101

7 1. Ambient Temperature [2/7] The specific power consumed by the compressor increases proportional to the inlet air temperature (in K) without a corresponding increase in the turbine output. T 3 3 w C C pt C CPR 1 o, 1 1 The exhaust gas temperature increases as the inlet air temperature increases because the turbine pressure ratio is reduced, although the gas turbine inlet temperature remains constant. This is the main reason for that the gas turbine output and efficiency decrease while the ambient air temperature increases. However, the effect on the performance of the combined cycle is somewhat less because a higher exhaust gas temperature improves the performance of the steam cycle s Combined Cycle Power Plants 6. Gas Turbine Performance 7 / 101

8 Relative efficiency, % 1. Ambient Temperature [3/7] Effect on Combined Cycle Efficiency An increase in the inlet air temperature has a slightly positive effect on the efficiency of the combined cycle plant, while other ambient conditions as well as condenser pressure remain constant. 105 Source: Kehlhofer et al., 2009 Gas turbine Because the increased gas turbine exhaust gas temperature improves the efficiency of the steam process, it more than compensates for the reduced efficiency of the gas turbine unit. 100 Steam turbine Combined cycle According to the open literature, with each onedegree temperature increase above 30 C, power output of the gas turbines drops by 0.50% 1.02% while efficiency drops by approximately 0.24%. Steam turbine power output and efficiency are not significantly changed by changing air temperature, while net CCGT power output drops by 0.3% 0.6% and net efficiency drops by approximately 0.01% per degree above 30 C. 95 Based on constant condenser pressure Air temperature, C Combined Cycle Power Plants 6. Gas Turbine Performance 8 / 101

9 Combined cycle efficiency, % 1. Ambient Temperature [4/7] Effect on Combined Cycle Efficiency Ambient air temperature, K Combined Cycle Power Plants 6. Gas Turbine Performance 9 / 101

10 1. Ambient Temperature [5/7] Net efficiency of a combined cycle power plant as a function of river water temperature. Combined Cycle Power Plants 6. Gas Turbine Performance 10 / 101

11 Relative power output, % 1. Ambient Temperature [6/7] Effect of Ambient Temperature on Combined Cycle Output The power output of the combined cycle decreases as the inlet air temperature increases. 120 Source: Kehlhofer et al., 2009 In a combined cycle plant, gas turbines contribute approximately two-thirds of the power production, while the steam turbine contributes the remaining one-third. 110 Gas turbine The combined cycle power output curve is dominated by the gas turbine output curve, and it is expected that changes in air temperature will have more significant impact on plant power output than changes in water temperature. 100 Based on constant condenser pressure The power output of the combined cycle is affected differently from the efficiency because change in mass flow of inlet air and exhaust gases are more dominant than the exhaust gas temperature Air temperature, C Combined Cycle Power Plants 6. Gas Turbine Performance 11 / 101

12 1. Ambient Temperature [7/7] When the ambient temperature is low, gas turbine output and HRSG steam production are increased above plant rating point. Condenser (exhaust) pressure directly influenced by ambient air or cooling water temperature. Condenser pressure is expected to be lowest at low ambient air / cooling water temperature, and exhaust annulus velocity will be the highest. Combined Cycle Power Plants 6. Gas Turbine Performance 12 / 101

13 Atmospheric pressure, psia Correction factor 2. Ambient Air Pressure Gas turbine performance is quoted at an air pressure of bar ISO conditions, which corresponds to the average pressure prevailing at sea level. A different site elevation and daily weather variations result in a different pressure. The air density reduces as the site elevation increases. Therefore, airflow and output decrease as the site elevation increases. However, the air pressure has no effect on the efficiency if the ambient temperature is constant, even though the output decreases as the pressure decreases. This is because the backpressure of the gas turbine is correspondingly lower at a lower ambient pressure. This is also because both the thermal energy supplied as well as airflow vary in proportion to the air pressure Atmospheric pressure Correction factor Altitude x 10 3 feet GT Model CC Configuration Ambient Temp.,C Site Site Elevation, m CC Thermal Effcy., % CC Net Power, MW GT Net Power, MW ST Net Power, MW PG7221FA 2-on (82.5F) Las Vegas Miami Sea side Combined Cycle Power Plants 6. Gas Turbine Performance 13 / 101

14 Relative power output, % Relative air pressure, % 2. Ambient Air Pressure Effect of Air Pressure on Combined Cycle Output Air pressure Combined cycle output Elevation above sea level, m Combined Cycle Power Plants 6. Gas Turbine Performance 14 / 101

15 Correction factor 3. Humidity Humid air is less dense than dry air. In the past, this effect was thought to be too small to be considered. However, as the size of gas turbine increases, this effect become important. Steam or water injection for NO x control makes this effect more significance ISO specific humidity % RH Specific humidity (kg water vapor/kg dry air) Combined Cycle Power Plants 6. Gas Turbine Performance 15 / 101

16 4. Inlet & Exhaust Pressure Drop [1/6] Inlet filter Evaporative cooler or chiller Anti-icing system Silencer (The large frontal areas of the compressors reduce the inlet velocities, thus reducing air noise) Combined Cycle Power Plants 6. Gas Turbine Performance 16 / 101

17 4. Inlet & Exhaust Pressure Drop [2/6] MS7001E, GE Hot-end drive MS7001F, GE Cold-end drive In the hot-end drive configuration, the output shaft extends out the rear of the turbine. The designer is faced with many constraints, such as output shaft length, high EGT, exhaust duct turbulence, pressure drop, and maintenance accessibility. Insufficient attention to any of these details, in the design process, often results in power loss, vibration, shaft or coupling failures, and increased down-time for maintenance. This configuration is difficult to service as the assembly must be fitted through the exhaust duct. In the cold-end drive configuration, the output shaft extends out the front of the compressor. The single disadvantage is that the compressor inlet must be configured to accommodate output shaft. The inlet duct must be turbulent free and provide uniform, vortex free, flow over the all operating range. Inlet turbulence may induce surge in the compressor resulting in complete destruction of the unit. Combined Cycle Power Plants 6. Gas Turbine Performance 17 / 101

18 Correction factor 4. Inlet & Exhaust Pressure Drop [3/6] Inlet Pressure Drop Inlet pressure drop is a function of the inlet air system design and cleanliness of the inlet air filters. Lower inlet air pressure losses can be achieved by designing for lower inlet air velocities through the filter, silencer, and duct. The improved operating performance associated with a lower inlet air velocity design must be evaluated against the associated higher capital cost. A similar cost evaluation determines the optimum point that dirty air filters, which have higher pressure losses, should be changed out Inlet pressure prop, in.h 2 O Combined Cycle Power Plants 6. Gas Turbine Performance 18 / 101

19 4. Inlet & Exhaust Pressure Drop [4/6] Self-Cleaning Filters Self-cleaning filters were developed in the 1970s and now account for 90% of the new systems. It combines high-efficiency filters, which can collect even small particles smaller than 1 m, and low maintenance. The design pressure drop of a new and clean filter bank is normally on the order of 2 mbar. The approach velocity of air upstream of the filter surface is approximately 3 m/s. When pressure drop builds up to a predetermined level (3~4 in.h 2 O = 7.5~10 mbar), the filter is cleaned by a brief back-pulse of air, either extracted from the gas turbine compressor, or derived from an auxiliary source. A filter compartment includes many filter elements (about 1,200 for 7FA), only a few of which are cleaned at any given time; so the airflow to the gas turbine is not disturbed by the cleaning process. A single cleaning cycle is usually completed in 20~30 minutes. The filter elements are replaced when they begin to show signs of deterioration caused by heat and ultraviolet rays, or when the cleaning is not effective any more. It is impossible to keep the compressor completely clean and usually fouling occurs in the compressor. The fouling that results causes losses in output and efficiency. Two types of compressor cleaning can be used to help recover those losses, on-line washing and off-line washing. Combined Cycle Power Plants 6. Gas Turbine Performance 19 / 101

20 Correction factor 4. Inlet & Exhaust Pressure Drop [5/6] Exhaust Pressure Drop Higher exhaust pressure loss is primarily a function of the exhaust system design For a simple cycle applications, the exhaust system typically consists of an exhaust duct, silencers, and a stack Exhaust pressure losses of 4.0 to 5.0 in.h 2 O are typical for simple cycle gas turbines For combined cycle or cogeneration applications, the exhaust gases pass through an HRSG with the associated additional Exhaust pressure losses of 10 to 17 in.h 2 O are typical for combined cycle and cogeneration applications depending on the complexity of the cycle arrangement, exhaust emission control, or noise-abatement Exhaust pressure drop, in.h 2 O Combined Cycle Power Plants 6. Gas Turbine Performance 20 / 101

21 4. Inlet & Exhaust Pressure Drop [6/6] MS7001EA 기준 4.0 in.h 2 O (10 mbar) Inlet pressure drop produces: 1.42% Power output loss 0.45% Heat rate increase 1.1C Exhaust temperature increase 4.0 in.h 2 O (10 mbar) Exhaust pressure drop produces: 0.42% Power output loss 0.42% Heat rate increase 1.1C Exhaust temperature increase Hot-end drive ( E technology) Inserting air filter, silencer, evaporative coolers or chillers into the inlet or heat recovery devices in the exhaust causes pressure losses in the system. The effects of these pressure losses are unique to each gas turbine models. This is because the amount of pressure drop at the exit of compressor is pressure drop at the inlet times pressure ratio. Hot-end drive has not been used since the cold-end drive type gas turbines have developed. HRSG flue gas draft losses: approximately 25 mbar, 35 mbar if catalysts are required. Combined Cycle Power Plants 6. Gas Turbine Performance 21 / 101

22 5. Fuel [1/7] Fuel affects combined cycle performance in a variety of ways. Output of the gas turbine can be defined as the product of mass flow, specific heat, and temperature differential across the turbine. Here, specific heat (C p ) means that the heat energy in the combustion products. W T m h h mc T 3 4 T p 3 T4 The mass flow in this equation is the sum of compressor air flow and fuel flow. T Natural gas (methane) produces nearly 2% higher output than does distillate oil. This is because of the higher specific heat in the combustion products of natural gas, resulting from the higher water vapor content produced by the higher hydrogen/carbon ratio of methane. This effect is noted even though the mass flow of natural gas is lower than that of distillate oil. Here the effects of specific heat were greater than and in opposition to the effects of mass flow rate. Model Fuel ISO base rati ng, kw Heat rate, Btu/kWh Exhaust flow, kg/hr x10-3 EGT, Pressure ratio PG7251FB N.G. 184,400 9, D.O. 177,700 9, Combined Cycle Power Plants 6. Gas Turbine Performance 22 / 101

23 5. Fuel [2/7] C + O 2 = CO MJ/kg H 2 + 1/2O 2 = H 2 O(water) MJ/kg (HHV) H 2 + 1/2O 2 = H 2 O(vapor) MJ/kg (LHV) S + O 2 = SO MJ/kg Combined Cycle Power Plants 6. Gas Turbine Performance 23 / 101

24 5. Fuel [3/7] The Composition of Natural Gases The composition on a molar basis of natural gases is as follows: Composition, mol% A B C D E F Methane Ethane Propane Isobutane Normal butane Isopentane Normal pentane Hexane Nitrogen Carbon dioxide Hydrogen sulphide Heating value, Btu/ft ? The average heat content of natural gas is 1,030 Btu/ft 3 on an HHV basis and 930 Btu/ft 3 on an LHV basis about a 10% difference. Combined Cycle Power Plants 6. Gas Turbine Performance 24 / 101

25 5. Fuel [4/7] Plant output and efficiency can be reduced when the fuels containing higher sulfur content are used. This is because higher stack gas temperature is required to prevent condensation of corrosive sulfuric acid. Plant output and efficiency can be reduced when the ash bearing fuels (crude oil, residual oil, blends, or heavy distillate) are used because of fouling occurred in gas turbine and HRSG. Heavy fuels normally cannot be ignited for gas turbine startup; therefore a startup and shutdown fuel, usually light distillate, is needed with its own storage, forwarding system, and fuel changeover equipment. The LHV of the fuel is important because it defines the mass flow of fuel supplied to the gas turbine. The lower the LHV, the higher the mass flow of fuel required to provide a certain chemical heat input, normally resulting in a higher power output and efficiency. However, there is no clear relationship between fuel lower heating value and output. This is why low BTU gases can result in high power outputs if they are supplied at the pressure required by the gas turbine. This effect is noted even though the mass flow of methane is lower than the mass flow of distillate fuel. Here the effects of specific heat were greater than that of mass flow. Combined Cycle Power Plants 6. Gas Turbine Performance 25 / 101

26 5. Fuel [5/7] Ash deposition on turbine vanes Degradation in CCPP after 8,000 hours of operation Clean fuel Heavy or crude oil Plant output, % 0.8~ ~5.5 Plant efficiency, % 0.5~ ~1.9 Combined Cycle Power Plants 6. Gas Turbine Performance 26 / 101

27 5. Fuel [6/7] In the past, corrosion is one of the major causes of gas turbine failures. Corrosion problems have been eliminated by the use of advanced materials and coating. Whenever heavy fuels are used, particularly those containing vanadium or sodium, it is necessary to use additives or treat the fuel to prevent high-temperature corrosion. The additives commonly used are based on magnesium, chromium, or silicon. Hot corrosion of blades Burned turbine blades Combined Cycle Power Plants 6. Gas Turbine Performance 27 / 101

28 5. Fuel [7/7] Effects of Fuel Heat Value on Output As the amount of inert gas is increased, the decrease in LHV will provide an increase in output. This is the major impact of IGCC type fuels that have large amounts of inert gas in the fuel. This mass flow addition, which is not compressed by the gas turbine s compressor, increase the turbine output. Combined Cycle Power Plants 6. Gas Turbine Performance 28 / 101

29 6. Fuel Heating [1/2] One way of improving the cycle efficiency is to raise the apparent LHV (LHV + sensible heat) of the fuel by preheating it with hot water from the IP economizer of the HRSG. Heated fuel gas gives higher turbine efficiency because of the reduced fuel flow required to raise the total gas temperature to firing temperature. Fuel gas Air Stack gas G Fuel heating will result in slightly lower gas turbine output (almost negligible) because of the incremental volume flow decrease. HRSG The reduction in combined cycle output is typically greater than simple cycle output because energy that would otherwise be used to make steam. G ST Condenser Actual combined cycle output and efficiency changes are dependent on fuel temperature rise and cycle design. For combined cycle applications, fuel temperatures on the order of 150 to 230 C (300~450 F) are generally economically optimal. Combined Cycle Power Plants 6. Gas Turbine Performance 29 / 101

30 6. Fuel Heating [2/2] Provided the fuel constituents are acceptable, fuel temperatures can potentially be increased up to approximately 370 C(700 F) before carbon deposits begin to form on heat transfer surfaces. Typical F-class three-pressure reheat systems use water from the intermediate pressure economizer to heat the fuel to approximately 185 C (365 F). Under this conditions, efficiency gains of approximately 0.3 points can be expected for units with no stack temperature limitations. Another factor is the gas supply pressure, depended on the combustor design and the gas turbine pressure ratio. If the gas turbine pressure ratio is high, a gas compressor may be required to increase fuel pressure. In this case, the temperature of the fuel is increased in proportion to the pressure ratio and the benefit of gas preheater will be reduced. In this case, the efficiency improvement is too slight to justify the additional investment in the water/gas heat exchanger, HRSG surface, and piping. It is important to ensure that the fuel does not enter the steam system because maximum steam temperatures are typically above the auto ignition temperature for gas fuels. For a system utilizing a direct water-to-fuel heat exchangers, the water pressure is maintained above the fuel pressure so that any leakage takes place in the fuel system. Additional system design and operation requirements ensure that the fuel does not enter the steam system during periods when the water system is not pressurized. Combined Cycle Power Plants 6. Gas Turbine Performance 30 / 101

31 7. Steam Injection [1/6] Effects of Steam Injection on Output and Heat Rate [MS7001EA] Options for power enhancements Performance impact Output Heat rate Base configuration Base Base Evaporative cooling GT inlet air (85% effective cooler) +5.2 % - Chill GT inlet air to 45F % +1.6 % GT peak load operation +5.2 % 1.0 % GT steam injection (5% of GT airflow) GT water injection (2.9% of GT airflow) +3.4 % +4.2 % +5.9 % +4.8 % HRSG supplementary firing +28 % +9 % Compressor Inlet Temperature Note: 1. Site conditions = 90F, 30% RH(Relative Humidity) 2. Fuel = NG 3. 3-pressure, reheat steam cycle Combined Cycle Power Plants 6. Gas Turbine Performance 31 / 101

32 Relative efficiency, % Relative power output, % 7. Steam Injection [2/6] Power output increases with water/steam injection because of increased mass flow rate. Water injection has a greater effect than steam because steam turbine output is decreased with steam injection Source: Kehlhofer et al., The steam is extracted from the steam turbine. Cold water (15C) from the makeup water line. Hot water (150C) at the outlet of the economizer. Efficiency of the combined cycle plant is decreased in both cases; however, less so by steam than by water, because steam brings more internal energy to the combustor. Hotter water less reduce the efficiency than cold one Hot water injection (150C) Water or steam/fuel ratio, [ Effect of water and steam injection on relative combined-cycle power output and efficiency versus water or steam/fuel ratio (with TIT = constant) ] Combined Cycle Power Plants 6. Gas Turbine Performance 32 / 101

33 7. Steam Injection [3/6] Diluent injection is accomplished by admitting water or steam in the cap area or head-end of the combustion liner to reduce the peak flame temperature. Actually, this has been used for NO x control to meet environmental regulation. The mass flow passing through the gas turbine increase with the amount of water or steam injection. Increased mass flow produces higher power output. Generally, the amount of water is limited to the amount required to meet the NO x abatement in order to minimize operating cost and impact on inspection intervals. When steam is injected for power augmentation, it can be introduced into the compressor discharge casing of the gas turbine as well as combustor. Normally, gas turbines are designed to allow up to 5% of the compressor airflow for steam injection. Steam must contain 50F(28C) superheat and be at pressures comparable to fuel gas pressures (at least 40 bar above the compressor discharge). The way steam is injected must be done very carefully so as to avoid compressor surge. Gas turbine output and heat rate increase 3.4% and 4.2% respectively, by the steam injection of 5% of the compressor airflow. Water or steam injection for emission control or power augmentation can impact parts lives and maintenance intervals. Combined Cycle Power Plants 6. Gas Turbine Performance 33 / 101

34 EGT, F EGT Control Curve MS7001EA 7. Steam Injection [4/6] GER-3620K [ Steam injection for 25 ppm NO x ] Wet control 3% steam injection T F = 2020F(1104C) Load ratio = 1.10 Dry control 0% steam injection T F = 2020F(1104C) Load ratio = 1.0 The wet control maintains constant T F 3% steam injection T F = 1994F(1090C) Load ratio = 1.08 Compressor discharge pressure, psig Combined Cycle Power Plants 6. Gas Turbine Performance 34 / 101

35 7. Steam Injection [5/6] Dry control The control system on most base load applications reduces firing temperature as water or steam is injected. This is known as dry control curve operation. Wet control On some installations, however, the control system is designed to maintain firing temperature constant with water or steam injection level. This is known as wet control curve operation. The dry control curve operation counters the effect of higher heat transfer on the gas side, and results in no net impact on bucket life. This is the standard configuration for all gas turbines, both with and without water or steam injection. The wet control curve operation results in additional unit output, but decreases parts life. Units controlled in this way are generally in peaking applications where annual operating hours are low or where operators have determined that reduced parts lives are justified by the power advantage. An additional factor associated with water or steam injection relates to the higher aerodynamic loading on the turbine components that results for the injected water increasing cycle pressure ratio. This additional loading can increase the downstream deflection rate of the second- and third-stage nozzles, which would reduce repair interval for those components. Combined Cycle Power Plants 6. Gas Turbine Performance 35 / 101

36 7. Steam Injection [6/6] GER-3620K Steam/water injection increases metal temperature of hot-gas-path components in the case of constant firing temperature operation. Water affects gas transport properties: k thermal conductivity C p specific heat viscosity This increases heat transfer coefficient, which increases metal temperature and decreases bucket life Example (MS7001EA 1st stage bucket): 3% steam injection (25 ppm NO x ) h = +4% (heat transfer coefficient) T metal = +15F (8C) Life = 33% Combined Cycle Power Plants 6. Gas Turbine Performance 36 / 101

37 % Effect on output % Effect on heat rate 8. Air Extraction Effects of Air Extraction on Output and Heat Rate In some gas turbine applications, it may be desirable to extract air from the compressor. 100 In general, up to 5% of the compressor airflow can be extracted from the compressor discharge casing without modification to casings or on-base piping % 15% Air extraction between 6% and 20% may be possible, depending on the machine and combustor, with some modification to the casings, piping and controls. Air extractions above 20% will require extensive modification to the turbine casing and unit configuration % 5% 5% 10% 15% 20% F 120 As a rule of thumb, every 1% in air extraction results in a 2% loss in power. Ambient temperature C Combined Cycle Power Plants 6. Gas Turbine Performance 37 / 101

38 9. Inlet Air Cooling [1/29] Roughly, 1C temperature decrease corresponds to a combined cycle power increase of about +0.4 to 0.5% and overall efficiency remains more or less same. Water Fuel oil Fuel additives Air Evaporative cooler or chiller Fuel gas Fuel oil treatment Water (NO x reduction, power augmentation) Air filter Water Inlet Fogger (spray cooler) Drain Wet compression (Overspray) Water Compressor Fuel gas compressor Compressor washing Fuel gas pre-heater Turbine Cooling air cooler Steam Combined Cycle Power Plants 6. Gas Turbine Performance 38 / 101

39 9. Inlet Air Cooling [2/29] 건구온도 vs. 습구온도 상대습도 (relative humidity): 공기중에있는수증기의양과그때의온도에서공기중에최대로포함할수있는수증기의양을백분율로표현한값. 건구온도 (dry bulb temperature): 일반온도계측정한온도. 습구온도 (wet bulb temperature): 온도계아래부분동그란구면을거즈로감싸고거즈의한쪽끝을물이담긴그릇에넣어그릇에서빨아올린물이끊임없이온도계의구면에서증발하도록한상태에서측정한온도. 물이증발하면서기화열을빼앗아가기때문에건구온도보다더낮은온도를나타냄. 공기중의습도가낮으면물이더많이증발할수있어서열을더많이빼앗아가기때문에건구와습구온도차이가더커짐. 일반적으로건구온도와습구온도차이에의해서습도를계산. [ 습구온도계 ] 습도계산표가있어서건구온도와습구온도를알면그때의습도를찾을수있음. 대부분습도계산표를이용하여습도확인. Combined Cycle Power Plants 6. Gas Turbine Performance 39 / 101

40 9. Inlet Air Cooling [3/29] For applications where significant power demand and highest electricity prices occur during the hot summer, a gas turbine air inlet cooling system is a useful option for increasing power output. Inlet air cooling increases output because the mass flow rate of air passing through the compressor increases as air temperature decreases. A decrease in the inlet dry-bulb temperature by 10F(5.6C) will normally result in around 2.7% power increase of a combined cycle using heavy-duty gas turbines. The output of the simple-cycle gas turbines is also increased by the same amount. There are three basic systems currently available for inlet air cooling. The first and perhaps the most widely used system is evaporative cooler. Evaporative coolers use the high efficiency evaporative media for the evaporation of water to decrease the gas turbine inlet air temperature. The second one is a fogger system, also called as spray cooler. This is classified as evaporative cooling. The third system employs various ways to chill the inlet air. In this system, the coolant (usually chilled water) flows through a heat exchanger located in the inlet duct to remove heat from the inlet air. Evaporative cooling is limited by the wet-bulb temperature. Chilling, however, can cool the inlet air to temperature that are lower than the wet-bulb temperature, thus providing additional output, although chilling is much more expensive. Depending on the combustion and control system, evaporative cooling may reduce NO x emissions; however, this is very little because of current dry low NO x technology. Combined Cycle Power Plants 6. Gas Turbine Performance 40 / 101

41 9. Inlet Air Cooling [4/29] Evaporative Cooler (Wetted Honeycomb Evaporative Coolers) High efficiency evaporative media Combined Cycle Power Plants 6. Gas Turbine Performance 41 / 101

42 9. Inlet Air Cooling [5/29] Evaporative Cooler (Wetted Honeycomb Evaporative Coolers) Conventional evaporative coolers use a wetted honeycomb type medium to maximize evaporative surface area and the cooling effectiveness. The medium for gas turbines is typically 12 inches thick and covers the entire cross-section of the filter house or the inlet air duct. The pressure drop caused by evaporative media and droplet eliminator is 1 in.h 2 O. Combined Cycle Power Plants 6. Gas Turbine Performance 42 / 101

43 9. Inlet Air Cooling [6/29] Evaporative Cooler (Wetted Honeycomb Evaporative Coolers) The plant output and efficiency decrease due to this pressure drop of about 1.5 to 3 mbar.. The reduction in gas turbine and combined cycle output is 0.35% and 0.3%, respectively. A controller is provided to prevent operation of the evaporative cooler system below 60F(15.6C). Icing could form if the system is allowed to operate below this temperature. The whole system must be deactivated and drained to avoid damage to the water tank and piping if the ambient temperature is expected to fall below freezing. Evaporative cooling is a cost-effective method to recover capacity during periods of high temperature and low or moderate relative humidity. Evaporative cooling works on the principle of reducing the temperature of an air stream through water evaporation. The process of converting the water into a vapor state requires energy. This energy is drawn from the air stream. The result is cooler, denser air. There are limitations that must be considered for each site condition. The key design parameters are the wet and dry bulb temperature and the allowable load limits for the generator and the transformer. At sites where large reductions in the compressor inlet temperature are possible, the owner must verify that the added power is within the capabilities of the generator and transformer. Combined Cycle Power Plants 6. Gas Turbine Performance 43 / 101

44 9. Inlet Air Cooling [7/29] Evaporative Cooler - Theory Theoretically, the lowest temperature that can be achieved by adding water to the air is equal to the ambient wet-bulb temperature. Practically, however, this level of cooling is difficult to achieve. The actual temperature drop realized is a function of both the equipment design and atmospheric conditions. Other factors being constant, the effectiveness of an evaporative cooling system depends on the surface area of water exposed to the air stream and the residence time. Cooler T Effectiven ess T 1, DB 1, DB T T 2, DB 2, WB T means air temperature. Subscripts 1 and 2 refer to inlet and exit of the cooler, respectively. Subscripts DB and WB refer to dry bulb and wet bulb, respectively. Temperature drop of the compressor inlet air is proportional to the difference between wet and dry bulb temperature. If the effectiveness is 85%, the temperature drop is Temperatur e drop 0.85 T1, DB T2, WB The effectiveness of evaporative cooler is typically 85% and of foggers somewhat higher at 90 to 95%. Combined Cycle Power Plants 6. Gas Turbine Performance 44 / 101

45 9. Inlet Air Cooling [8/29] Psychrometric Chart [ 건습계차트 ] Degrees Cooled Water Evaporated [Example 9.1] Ambient temperature is 100F (37.8C) and relative humidity is 20%. Calculate the temperature drop through the cooler. The effectiveness of the evaporation system is 85%. [Solution] The corresponding wet-bulb temperature is 70F. T = 0.85(100-70) = 25F (14C) Dry Bulb Temperature Combined Cycle Power Plants 6. Gas Turbine Performance 45 / 101

46 9. Inlet Air Cooling [9/29] Evaporative Cooler Roughly, 1C temperature decrease corresponds to a combined cycle power increase of about 0.4 to 0.5% and overall efficiency remains more or less same. The exact increase in power available from a particular gas turbine as a result of evaporative cooling depends on the machine model and site altitude, as well as on the ambient temperature and humidity. However, the chart given in the figure can be used to get the power increase from evaporative cooling. As would be anticipated, power increase is greatest in hot, dry weather. Evaporative cooling is limited to ambient temperatures (15C) and above (compressor inlet temperature >7.2C) because of the potential for icing the compressor. An evaporative cooling does only make sense at locations with humidity below 70 to 80%. Combined Cycle Power Plants 6. Gas Turbine Performance 46 / 101

47 9. Inlet Air Cooling [10/29] Fogger Gas turbines have been used foggers, also called as spray coolers, since mid-1980s. These systems atomize the supply of water into billions of tiny droplets. The droplets require a certain amount of residence time in the air stream to evaporate. The size of droplet plays an important role in determining the surface area of water exposed to the airstream and, therefore, to the speed of evaporation. The water droplets should be atomized to less than 20 m in foggers. Demineralized water is used to reduce compressor fouling or nozzle plugging. However, it necessitates the use of a high grade stainless steel for all wetted parts. Combined Cycle Power Plants 6. Gas Turbine Performance 47 / 101

48 9. Inlet Air Cooling [11/29] Fogger Combined Cycle Power Plants 6. Gas Turbine Performance 48 / 101

49 9. Inlet Air Cooling [12/29] Fogger - EPRI Spray Nozzle Array Nozzle fog spray pattern A typical spray-impingement fog nozzle Combined Cycle Power Plants 6. Gas Turbine Performance 49 / 101

50 9. Inlet Air Cooling [13/29] Fogger Two methods are used for water atomization. The first relies on compressor air in the nozzles to atomize the water. The second uses a high pressure pump to force the water through a small orifice. Air-atomized nozzles require less water pressure. However, they result in low power output due to the air extraction from the gas turbine. An air-atomized system using compressor discharge air would reduce the power output 1.3% (EPRI, TR ). The typical air-to-water mass ratio is 0.6 (volume ratio is 500). Some high-pressure pumps use swirlers to break the water into small droplets. Other force the water on an impingement pin to generate the same effect. A typical high-pressure pumped fog system has an operating pressure of between 1000 and 3000 psi (6.8 and 20.4 MPa). In contrast to evaporative coolers, fogging systems have a negligible pressure drop and are ideal for retrofitting. Combined Cycle Power Plants 6. Gas Turbine Performance 50 / 101

51 9. Inlet Air Cooling [14/29] Fogger - Large Droplet Eliminator Careful application of these systems is essential, because condensation or carryover of water can be causes of severe compressor fouling and performance degradation. These systems generally are followed by moisture separators or coalescing pads to reduce the possibility of moisture carryover. More spray flow was removed (~70%) by the Large Droplet Eliminator than was originally anticipated (~58%) in the EPRI test (TR ). Normally, water droplets are agglomerated by turbulent fluctuations and become large droplets. Analysis of the drain water gives some beneficial air scrubbing effects when the spray cooler is operating. A large droplet eliminator (LDE) is installed in the in the inlet housing downstream of the spray nozzle array to remove large water droplets from the air stream. The modules are manufactured using polypropylene with sine curve shaped vanes. Combined Cycle Power Plants 6. Gas Turbine Performance 51 / 101

52 9. Inlet Air Cooling [15/29] Fogger - Large Droplet Eliminator d p = 4 m 10 m 20 m 40 m Combined Cycle Power Plants 6. Gas Turbine Performance 52 / 101

53 9. Inlet Air Cooling [16/29] Fogger - Large Droplet Eliminator Single nozzle droplet distribution Droplet distribution upstream of LDE Droplet distribution downstream of LDE Combined Cycle Power Plants 6. Gas Turbine Performance 53 / 101

54 9. Inlet Air Cooling [17/29] Fogger - Summary of ERPI Test Results The power increase from evaporative cooling is about 3.5% for every 10F (5.6C) of cooling. Evaporative cooling is limited by the difference between the dry bulb and wet bulb temperatures. If sufficient water can be introduced into the air such that the air becomes fully saturated, the air temperature will be reduced to the wet bulb temperature. The amount of cooling is limited by the potential for icing as the air flow speeds up in the bellmouth and the static air temperature drops. The icing limit is engine dependent but typically varies from 40F to 50F. Combined Cycle Power Plants 6. Gas Turbine Performance 54 / 101

55 9. Inlet Air Cooling [18/29] Evaporative Cooling Evaporative cooler Fogger (spray cooler) Advantages Water quality requirements are less severe than fogger system. Simple and reliable. More operating experience. Gas turbine inlet pressure drop is lower than that of evaporative cooler and provides increased output. Higher effectiveness. Potential for lower uprate costs and faster installation time due to reduced duct modifications compared to evaporative cooler. Disadvantages Uprates frequently require substantial duct modifications. Higher gas turbine inlet pressure drop than fogger system degrades output and efficiency when not in use. Lower cooling effectiveness. Requires demineralized water. Higher parasitic load than evaporative cooler for high-pressure pumped systems. Lower power increase for air-atomized systems. Controls are more complex. Combined Cycle Power Plants 6. Gas Turbine Performance 55 / 101

56 9. Inlet Air Cooling [19/29] Chiller There are two types of inlet chilling systems, direct chillers and thermal storage. Liquefied natural gas (LNG) systems use the cooling generated by the vaporization of liquefied gas in the fuel supply. Thermal storage systems use off-peak power to store thermal energy in the form of ice. During peak power periods, the ice is used to perform inlet chilling. Direct chilling systems use mechanical or absorption chillers. All these options can be installed in new plants or retrofitted in older plants. The chilling achieved by using cooling coils depends on the design of the equipment and ambient conditions. Unlike evaporative coolers, cooling coils are capable of lowering the temperature below the wet-bulb temperature. The capacity of the inlet chilling device, the compressor s acceptable temperature and humidity limits, and the effectiveness of the coils limit actual reduction in temperature. Combined Cycle Power Plants 6. Gas Turbine Performance 56 / 101

57 9. Inlet Air Cooling [20/29] Chiller Figure illustrates a typical cooling process from an ambient dry-bulb temperature of 100F(37.8C) and 20% relative humidity. Degrees Cooled The initial cooling process follows a line of constant specific humidity. As the air approaches saturation, condensation starts to occur. Additional cooling results in further condensation. Mist eliminator should be installed downstream of coils to prevent condensed water from entering the gas turbine. Water Evaporated Evaporative Cooling Process Specific Humidity The air can be cooled below the ambient wet-bulb temperature. However, the compressor inlet temperature should be higher than 45F(7.2C) with a relative humidity of 95%. Icing will form at lower temperature, resulting in possible equipment damage. Dry Bulb Temperature Combined Cycle Power Plants 6. Gas Turbine Performance 57 / 101

58 9. Inlet Air Cooling [21/29] Chiller Combined Cycle Power Plants 6. Gas Turbine Performance 58 / 101

59 9. Inlet Air Cooling [22/29] Chiller F-Class gas turbine inlet filter house, showing installation of chiller coils. Coil manifolds are the vertical pipes along side the filter house. This filter house is passively balanced with a third reverse return manifold. Filter houses for chilling applications are much larger than standard models. A larger face area keeps pressure drop across the coils low. This filter house also has a symmetrical transition duct that improves the airflow across the coils. The fogger systems react to the ambient weather conditions, being limited to the spread between DB and WB. However, chiller systems break through the WB and dew-point barriers that would limit fogger systems. The power output enhancement associated with chiller systems can be nearly twice that of the fogger systems. In addition, temperature of the inlet air can be as constant as possible using chiller systems. Combined Cycle Power Plants 6. Gas Turbine Performance 59 / 101

60 9. Inlet Air Cooling [23/29] Summary for Performance Simulation Results Case Inlet air cooling GT output, kw (each) Total duct burner fuel input, MMBtu/hr (LHV) ST output, kw (gross) Auxiliary power, kw Net plant output, kw Each GT fuel input, MMBtu/hr (LHV) Net plant heat rate, Btu/kWh (LHV) 1 None Fogger Chiller None Fogger Chiller Chiller Model: STAG207FA Simulation software: GTPro & GTMaster Ambient conditions: 95F (35C), 40% RH Effectiveness of fogging system: 95% The chiller cools the inlet air temperature down to 50F (10C) Source: T.C. Tillman, PowerGen International 2003 Combined Cycle Power Plants 6. Gas Turbine Performance 60 / 101

61 9. Inlet Air Cooling [24/29] Summary for Capital Cost Simulation Results Source: T.C. Tillman, PowerGen International 2003 Case Inlet air cooling Duct firing Net plant output, kw Incremental output, kw Reference cost, M$ Incremental cost (to Case 1), M$ Unit cost, $/kw 1 None No Fogger No % Chiller No % None Yes % Fogger Yes % Chiller Yes % All cost figures are provided by Thermoflow s PEACE costing module. This software uses the plant configuration as provided by GTPro. Combined Cycle Power Plants 6. Gas Turbine Performance 61 / 101

62 Comparison of Fogger and Inlet Chiller 9. Inlet Air Cooling [25/29] TR (EPRI) Inlet Chiller Fogger GT: PG7221FA Site: Las Vegas (Dry Weather Condition) Peak Load Operation (Simple Cycle) No Augmentation GT Model CC Configuration Ambient Temp.,C Site Site Elevation, m CC Thermal Effcy., % CC Net Power, MW GT Net Power, MW ST Net Power, MW PG7221FA 2-on (82.5F) Las Vegas Miami Sea side Combined Cycle Power Plants 6. Gas Turbine Performance 62 / 101

63 Comparison of Fogger and Inlet Chiller 9. Inlet Air Cooling [26/29] TR (EPRI) Inlet Chiller Fogger No Augmentation GT: PG7221FA Site: Miami (Humid Weather Condition) Peak Load Operation (Simple Cycle) GT Model CC Configuration Ambient Temp.,C Site Site Elevation, m CC Thermal Effcy., % CC Net Power, MW GT Net Power, MW ST Net Power, MW PG7221FA 2-on (82.5F) Las Vegas Miami Sea side Combined Cycle Power Plants 6. Gas Turbine Performance 63 / 101

64 Comparison of Fogger and Inlet Chiller 9. Inlet Air Cooling [27/29] TR (EPRI) Inlet Chiller Fogger Combined Cycle Output Site: Las Vegas (Dry Weather Condition) No Augmentation GT Model CC Configuration Ambient Temp.,C Site Site Elevation, m CC Thermal Effcy., % CC Net Power, MW GT Net Power, MW ST Net Power, MW PG7221FA 2-on (82.5F) Las Vegas Miami Sea side Combined Cycle Power Plants 6. Gas Turbine Performance 64 / 101

65 Comparison of Fogger and Inlet Chiller 9. Inlet Air Cooling [28/29] TR (EPRI) Inlet Chiller Fogger No Augmentation Combined Cycle Output Site: Miami (Humid Weather Condition) GT Model CC Configuration Ambient Temp.,C Site Site Elevation, m CC Thermal Effcy., % CC Net Power, MW GT Net Power, MW ST Net Power, MW PG7221FA 2-on (82.5F) Las Vegas Miami Sea side Combined Cycle Power Plants 6. Gas Turbine Performance 65 / 101

66 9. Inlet Air Cooling [29/29] Combined Cycle Power Plants 6. Gas Turbine Performance 66 / 101

67 10. Wet Compression [1/11] Air Air filter Water Inlet Fogger (spray cooler) Drain Wet compression (Overspray) Water Evaporative cooler or chiller Water Compressor washing Compressor Wet compression (Overspray ) Wet compression is defined as the excess spray beyond that which is required to completely saturate the air. As an extension of the fogger system, water droplets are allowed to enter the compressor and evaporation takes place within the compressor. Droplets are evaporated inside the compressor to give evaporative intercooling effect. Wet compression is also called as high fogging, over spray, over-fogging system, and are usually in operation together with a fogging or evaporation cooling system. Turbine Cooling air cooler Steam Combined Cycle Power Plants 6. Gas Turbine Performance 67 / 101

68 10. Wet Compression [2/11] Source: GER-3620K Wet compression (Overspray) The power increase resulting from overspray is about 5% for every 1% overspray (overspray water mass is expressed as a percentage of inlet air mass). The amount of overspray will depend on ambient conditions. LM6000 Sprint Combined Cycle Power Plants 6. Gas Turbine Performance 68 / 101

69 10. Wet Compression [3/11] When water droplets enter the compressor, the process is called as wet compression or overspray. There are two methods of overspray. One is spraying more water droplets into the inlet air stream than can be evaporative with given ambient conditions. The other is installing a separate fogger system (two-stage evaporative cooler, also called as two-zone system) downstream of the acoustic silencers to spray water directly into the compressor inlet. The airstream carries unevaporated fog droplets into the compressor section. Then, they are evaporated in the compressor because higher temperatures in the compressor increase moisture-holding capacity of air. When the water droplets evaporate, the compressed air becomes cooler and denser. This increases total mass flow of air through the gas turbine and reduces the compressor work. Therefore, gas turbine output increases. As the compressor discharge temperature decreases when the overspray system is operated, more fuel is required to achieve a given TIT. In this case, the increase of power output is greater than the increase of fuel consumed resulting in a net decrease in overall heat rate. Source: TR (EPRI) Combined Cycle Power Plants 6. Gas Turbine Performance 69 / 101

70 10. Wet Compression [4/11] There is one possible drawback to wet compression; if water droplets are too large, there is potential for liquid-impaction erosion of compressor blades. For this reason, spray droplet diameter should be less than 20 m. EPRI has recommended that droplets on the order of 10 microns in diameter or smaller are desirable to evaporate quickly, follow streamlines, minimize wall wetting and minimize erosion. Evaporation of the water droplets inside the compressor provides continuous cooling of the air thus leading to a reduction in the compressor work and compressor discharge temperature for a given pressure ratio. The maximum desirable ratio of water-to-air flow is limited by compressor surge or stall and combustor efficiency. A coating of liquid on the airfoil surfaces will change the blade path geometry and the related position of the surge line. The spray of untreated water will results in fouling on the airfoil surfaces. This, in turn, leads to a change in airfoil geometry and the position of the surge line. It has been estimated that an overspray limit of 0.5% of the air flow appears reasonable without reducing the surge margin. The effect of this amount of injection on a W501AB is estimated to reduce the compressor power, increase the turbine output, and results in a net output increase of 4.8%, based on 100F dry bulb and 80F saturated air inlet conditions. (from TR , EPRI) The wet compression system should be operated at or above 50F because of the formation of ice. Combined Cycle Power Plants 6. Gas Turbine Performance 70 / 101

71 10. Wet Compression [5/11] Source: TR (EPRI) Experimental investigation has shown that overspray into an axial compressor can reduce compressor work, reduce the compressor discharge temperature, increase output power, and reduce NO x emissions. The benefits of overspray are greatest when complete evaporation is achieved as soon as possible in the compressor. The cooling air temperatures often limit the firing temperature to achieve the desired hot section parts life. The spraying of water adds mass flow and increase the specific heat, so the actual compression power reduction is somewhat offset by these effects. Issues of concern are the potential for erosion for the compressor blade and the reduced stall margin. The use of very fine droplets that are less than 3 microns is diameter has been shown to reduce erosion to a negligible rate. The maximum amount of water sprayed to saturate the air throughout the compressor is nearly 10% of the air flow. However, it is affected by many factors, such as ambient conditions, compressor surge margin, compressor blade incidence angle, and choking condition of the 1 st stage turbine nozzle. The estimated heat rate changes for simple cycles are small and increase slightly for combined cycle. The increase of power with fogging or evaporative cooling depends on ambient conditions. However, the wet compression power increase is nearly independent of ambient humidity and temperature. Combined Cycle Power Plants 6. Gas Turbine Performance 71 / 101

72 Change in rotor incidence angle, deg. 10. Wet Compression [6/11] Effect of water overspray on rotor incidence angle (2 micron droplets) % inlet water spray % inlet water spray 3% inlet water spray Stage Combined Cycle Power Plants 6. Gas Turbine Performance 72 / 101

73 Change in stator incidence angle, deg. 10. Wet Compression [7/11] Effect of water ovesrpray on stator incidence angle (2 micron droplets) % inlet water spray 2% inlet water spray 3% inlet water spray Stage Combined Cycle Power Plants 6. Gas Turbine Performance 73 / 101

74 Power output, MW Delta power, % 10. Wet Compression [8/11] Source: TR (EPRI) GT: Alstom/ABB 9D gas turbine Power output Delta power Spray water, % Combined Cycle Power Plants 6. Gas Turbine Performance 74 / 101

75 NO x, g/gj 10. Wet Compression [9/11] Source: TR (EPRI) GT: Alstom/ABB 9D gas turbine Base load 75% load 50% load Spray water, % Combined Cycle Power Plants 6. Gas Turbine Performance 75 / 101

76 Peak generator rating 10. Wet Compression [10/11] Comparison of Prediction and Measurement of Inlet Air Cooling (A) Predicted [97F(36C), 34% RH] (B) Predicted [97F(36C), 34% RH] (C) Predicted [New and clean compressor, Ambient conditions are not given] (D) Measured [Ambient conditions are not given] GT Model: MS7001E Base Load Power Base + NO x WI 62.2 MW Peak Load Power Peak + NO x WI 67.7 MW Evaporative cooling 6.3 MW (10.2%) Evaporative cooling 3.2 MW Overspray 0.75 MW Evaporative cooling 3.5 MW Overspray 1.8 MW (2.9%) Max WI 2.9 MW (4.7%) Evaporative cooling 6.5 MW (10.2%) Overspray 1.25 MW Source: TR (EPRI) Overspray 2.0 MW (3%) Max WI 3.1 MW (4.6%) Power Output, MW Combined Cycle Power Plants 6. Gas Turbine Performance 76 / 101

77 10. Wet Compression [11/11] Water droplets will cause leading edge erosion on the first few stages of the compressor. This erosion, if sufficiently developed, may lead to blade failure. Additionally, the rounded leading edge surface lowers the compressor efficiency and unit performance. Utilization of inlet fogging or evaporative cooling may also introduce water carry-over or water ingestion into the compressor, resulting in water droplet erosion. Although the design intent of evaporative coolers and inlet foggers should be to fully vaporize all cooling water prior to its ingestion into the compressor, evidence suggests that, on systems that were not properly commissioned, the water may not be fully vaporized. [ Frame 7FA R0 compressor blade leading edge liquid droplet erosion ] Combined Cycle Power Plants 6. Gas Turbine Performance 77 / 101

78 11. Supercharging [1/3] Ducted fan-motor set (plan view) Combined Cycle Power Plants 6. Gas Turbine Performance 78 / 101

79 11. Supercharging [2/3] External motor drive (Plan View) Combined Cycle Power Plants 6. Gas Turbine Performance 79 / 101

80 11. Supercharging [3/3] TR (EPRI) Supercharging rounds out the technologies based on inlet air conditioning such that the inlet temperature, humidity and pressure may be controlled. An electric motor-driven fan (or blower) strategically located in the GT inlet air flow path increases the inlet pressure at the axial compressor scroll. A temperature rise accompanies the pressure rise, so after-cooling is desirable to capture the maximum benefit of the pressure rise. Evaporative cooling is also beneficial in reducing the fan power, but this is considered a separate technology. The motor, fan and after-cooler ensemble constitute the supercharger. During the late 1960s, Westinghouse offered their W301 gas turbine with supercharging. The W301 was offered in a fully fired combined cycle configuration, so the supercharger blower was also used for operating the furnace and steam turbine when the CT was not operating. The Westinghouse performance data was modeled with SCAAD (Strategic Capacity Analysis and Design) software developed for EPRI. Combined Cycle Power Plants 6. Gas Turbine Performance 80 / 101

81 12. Peak Firing [1/2] Some gas turbine models can be operated at a higher firing temperature than their base rating. This is called peak firing. During the peak firing operation, both simple-cycle and combined-cycle output will increase. Peak firing is available to get 3~10% higher output than the output at base load. Normally, thermal efficiency of the plant is increased during peak firing of gas turbine because of higher firing temperatures. This mode of operation results in a shorter inspection interval and increased maintenance. Despite this penalty, operating at elevated peak firing temperatures for short periods is cost-effective way for power gain without any additional peripheral equipment. Peaking at 110% rating will increase maintenance costs by a factor of 3 relative to base-load operation at rated capacity, for any given period. For an MS7001EA turbine, each hour of operation at peak load firing temperature (+100F/56C) is the same, from a bucket parts life standpoint, as six hours of operation at base load. Combined Cycle Power Plants 6. Gas Turbine Performance 81 / 101

82 Maintenance factor 12. Peak Firing [2/2] Maintenance Factor 100 E-class 10 6 F-class E-class peak rating life factor 6x Firing temperature, F Combined Cycle Power Plants 6. Gas Turbine Performance 82 / 101

83 13. Part Load Operation Load, % Combined Cycle Power Plants 6. Gas Turbine Performance 83 / 101

84 14. Supplementary Firing in HRSG It can be used to increase steam turbine capacity by as much as 100%. This will increase plant capacity by about 33%. Cogeneration of power and process steam is usually the incentive for HRSG supplementary firing. Normally, thermal efficiency of the plant is decreased during HRSG supplementary firing. There is a small performance penalty when operating unfired compared to operating a unit designed without supplementary firing, and the magnitude of this performance penalty is directly proportional to the amount of supplementary firing built into the combined-cycle plant. The performance penalty is due to two factors: unfired operation results in lower steam flows and pressures and, thus, lower steam turbine efficiency; also, the pumps, auxiliary equipment and generator are sized for higher loads. Operating unfired results in comparatively higher parasitic loads compared to a unit designed solely for unfired operation. Combined Cycle Power Plants 6. Gas Turbine Performance 84 / 101

85 15. Cooling Water Temperature [1/2] T 3 2 p p 4 a a b s The end pressure of steam expansion in the turbine is determined by the steam saturation temperature depending on the cooling water temperature and heat transfer conditions on the condenser tubes. Combined Cycle Power Plants 6. Gas Turbine Performance 85 / 101

86 Steam turbine output, MW 15. Cooling Water Temperature [2/2] Effect of Condenser Pressure on Steam Turbine Output Source: Kehlhofer et al., Triple pressure reheat Single pressure Double pressure Condenser pressure, mbar Combined Cycle Power Plants 6. Gas Turbine Performance 86 / 101

87 16. Compressor Washing [1/11] Performance Degradation All guaranteed performance numbers are valid for a new and clean engine. New and clean conditions are specified on a project-by-project basis, but typically are defined as performance during first 20 to 100 hours of fired operation. All engines have performance degradation, those are easily recoverable, or non-recoverable. A typical recoverable loss is usually associated with compressor fouling which can be partially removed by water washing or by mechanical cleaning after opening the unit. The removal of fouling deposits from the air path components can restore partially the aerodynamic performance of the machine. Non-recoverable loss is due to increased turbine and compressor tip clearances and changes in surface finish and airfoil contour, mainly caused by corrosion and erosion, and sometimes by FOD. These non-recoverable losses are main cause of the reduction in component efficiencies, and it may be recovered only by replacement or repair of the affected parts at recommended inspection intervals. OEMs typically recommend periodic maintenance inspections and overhauls which are scheduled on the basis of hours of fired operation, type of fuel used, and the number of starting the machine. On the basis of natural gas firing, it has generally being recommended that the inspection intervals are 8,000 hours of operation for combustors, 24,000 hours of operation for hot gas parts, and 48,000 hours of operation for a major overhaul. Typically, performance degradation during the first 24,000 hours of operation (the normally recommended interval for a hot gas path inspection) is 2% to 6% from the guaranteed performance. This assumes degraded parts are not replaced. If replaced, the expected performance degradation is 1% to 1.5%. Combined Cycle Power Plants 6. Gas Turbine Performance 87 / 101

88 16. Compressor Washing [2/11] Compressor Fouling The most significant performance degradation occurred in gas turbines is caused by compressor fouling. Compressor fouling takes place when particulate matter in the inlet air is deposited and adhered to the bell mouth or compressor blades. The fouling physically changes the shape of the compressor blades, reducing aerodynamic performance. Fouling may also block cooling air flow ports and passages, resulting in thermal damage to the components. A large quantities of air pass through the compressor, combustor, and turbine section. Although inlet air is filtered, some contaminants pass through the compressor and turbine. Typical contaminants are submicron dirt particles entering the compressor, oil vapors, smoke, and sea salt. There is a temperature and humidity region showing higher compressor fouling rate. Too little humidity gives too little water for sticking the particles whilst too high levels might result in the effect of on-line wash. Compressor fouling can be severer with inlet foggers. Fouled gas turbine air inlet bell mouth and blading, engine operated in an industrial environment Front stages are usually fouled worst. This is because the particles adhere to the compressor blade mainly by bell mouth condensation, or by oil leak from #1 bearing. Rear stage fouling gives a smaller impact on performance; but due to higher temperatures, deposits can become baked and difficult to remove. This baking effect is more severe on the machines with high pressure ratio compressor. Combined Cycle Power Plants 6. Gas Turbine Performance 88 / 101

89 Output decrease, % Heat rate increase, % 16. Compressor Washing [3/11] Fouling Effects in terms of Performance The compressor efficiency is governed by the smoothness of stator and rotor blade surfaces and their shapes. These surfaces can be roughened by erosion, but more frequently by fouling. The shapes of compressor blades are also changed from its design shape by fouling. An axial compressor is a machine where the aerodynamic efficiency of each stage depends on that of the previous stages. Thus, when fouling occurs in the inlet guide vanes and the first few stages, there may be a dramatic decrease in compressor efficiency. The effects of compressor fouling are decrease of airflow, pressure ratio, and compressor efficiency, resulting in a decrease in power output and thermal efficiency. Airflow is reduced by 5% due to the compressor fouling, which will reduce output by 13% and increase heat rate by 5.5%. The output of a gas turbine can be reduced as much as 20% by fouling. Deterioration of GT performance due to compressor blade fouling Fouling Fouling 5% loss of airflow Pressure ratio decrease, % It has been estimated that the fouling is responsible for 70 to 85% of all gas turbine performance losses accumulated during operation. In extreme cases, fouling can also result in surge problems, as it tends to reduce the surge margin. Combined Cycle Power Plants 6. Gas Turbine Performance 89 / 101

90 Pressure ratio 16. Compressor Washing [4/11] Compressor Fouling Severe fouling, dried carbonaceous type of deposits Surge line Fouled Design point Heavy stage loading Light stage loading Mass flow Severe carbonaceous oily type of deposits on 1st stage vanes. Fouling mainly caused by oil leaks in the bearing system Combined Cycle Power Plants 6. Gas Turbine Performance 90 / 101

91 16. Compressor Washing [5/11] Disposition for Compressor Fouling Fouling is best controlled by a combination of two methods. The first one is to employ a high quality air filtration system. Recently, fouling problems have reduced dramatically by the employment of HEPA (High Efficiency Particulate Air) filters, which can remove % of 0.3 µm particles. However, as fouling will inevitably occur, compressor washing should be used to control its impact. In general, water washing is employed to remove the fouling. Under extreme fouling conditions, however, hand washing of the IGVs may have to be conducted. During overhauls, hand cleaning of the full axial compressor is most effective. Previously, abrasive cleaning using crushed nutshells had been employed for compressor cleaning. However, abrasive cleaning is not recommended anymore because it can damage compressor blade coatings and compressor blade surface finish. Moreover, abrasive cleaning compounds are also a potential cause of plugged cooling passages. Silica deposits resulting from untreated water used for evaporative cooling of the compressor inlet air are difficult to remove. The various impurities can be washed by condensed water at bell mouth. The droplets and wet blade and end-walls become acidic due to the scrubbed pollutants, such as CO 2, SO 2, NO x, HCl, and Cl 2. Therefore, corrosion risk is elevated and protective coatings are required. Before water washing After water washing Combined Cycle Power Plants 6. Gas Turbine Performance 91 / 101

92 16. Compressor Washing [6/11] Water washing piping system (GE) On-line water washing (GE 7EA) On/off-line washing system diagram (GE) Combined Cycle Power Plants 6. Gas Turbine Performance 92 / 101

93 16. Compressor Washing [7/11] Off-line wash nozzles On-line wash nozzles Off-line wash (Siemens) On-line wash (Siemens) Combined Cycle Power Plants 6. Gas Turbine Performance 93 / 101

94 Power output, % of new clean machine 16. Compressor Washing [8/11] On-line Washing There are two water wash systems performed on gas turbines: on-line and off-line (crank wash). 100 On-line washing with the machine running at full speed and loaded. On-line is not as effective as off-line but on-line washing is performed with the unit in full operation, and outages or shutdown periods are not required On-line washing is now very popular as a means to control fouling by avoiding the problem from developing. 91 The primary purpose of on-line washing is to extend the operating period between off-line washes by minimizing the compressor fouling, thereby to provide peak availability Operating hours 1000 On-line cleaning is straightforward but because the temperature increases through the compressor, the cleaning solution evaporates and cleaning is limited to the first compressor rows. Fortunately, fouling of the first stage guide vane is the primary cause of reduced air mass flow through the compressor. On-line washing has become increasingly important with base load combined cycle plants and CHP plants. On-line cleaning has a risk of getting dirt particles into the secondary air system. Combined Cycle Power Plants 6. Gas Turbine Performance 94 / 101

95 16. Compressor Washing [9/11] Off-line Washing Off-line washing is better suited to large, modern gas turbines because it is more effective. Normally, off-line washing removes particulate matter and sticky coating on blades. On-line washing removes particulate matter. However, it requires shutting down and cooling the engine. Off-line washing with the machine on crank. Off-line involves injecting the cleaning solution into the compressor while it is turning at cranking speed (= 850 rpm for 7FA +e ). The downtime for a crank wash depends mainly on the time it takes for cooling the engine. In order to avoid thermal shock, wheel spacer temperatures must be below 200F. Larger heavy-duty engines can take 8 to 10 hours to cool whereas on light aeroderivative engines only 1.5 to 3 hours may be needed due to its low metal mass. Optimal compressor washing can normally be achieved by adopting a combined program of regular and routine on-line washing (every few days or weekly), plus periodic offline washing during planned outages. Typical on-line cleaning cycles are in the order of 10 to 20 minutes. Combined Cycle Power Plants 6. Gas Turbine Performance 95 / 101

96 16. Compressor Washing [10/11] Off-line Washing Objective: To clean a dirty compressor Virtually full power recovery (approaches new and clean values) Reaches all compressor stages Involves shutdown and cool-down period (8 to 10 hours) Lost revenue during shutdown Optimum time for cleaning may not be convenient, especially with base load plants Effluent water for disposal On-line Washing Objective: To keep a clean compressor cleaner for longer. To extend operating period between off-line cleaning, thus enhancing availability. About 1% power can be recovered per wash, with a frequent on-line cleaning program Primarily cleans the IGVs (no effect after water evaporates) No shutdown No lost revenue Optimum cleaning frequency is site specific No effluent water for disposal Maintains safe margin to surge line Reduce risk of blade corrosion Combined Cycle Power Plants 6. Gas Turbine Performance 96 / 101

97 16. Compressor Washing [11/11] Benefits of Compressor Washing Restoration of lost performance Maintaining higher efficiency Compliance with environmental regulations Increased availability and reliability Longer life expectancy Reduced O&M costs Reduction of gas turbine fuel consumption Combined Cycle Power Plants 6. Gas Turbine Performance 97 / 101

98 High Pressure Packing Brush Seal 17. Seal Rubbing [1/3] GER-3571H For a MS7001E unit, a rub of 20 mils on the labyrinth seal teeth equates to at least 1.0% loss in unit performance. To increase unit performance and to reduce the rate of performance degradation due to wear on labyrinth seal teeth, a wire brush seal has been employed. Since the wire brush seal is flexible and will bend (not wear) on contact with the compressor aft shaft, a closer clearance can be allowed for the initial installation. Since the wire brush seal will bounce back to its original configuration after a rub, there will be substantially less performance degradation over time than for the original labyrinth seal. Performance improvement is typically about 1% output and 0.5% heat rate. Combined Cycle Power Plants 6. Gas Turbine Performance 98 / 101

99 Stage 2 Nozzle Inner Diaphragm Brush Seal 17. Seal Rubbing [2/3] GER-3571H There is a large gap between the stage 2 nozzle inner diaphragm and the stage 1-2 wheel spacer to prevent any contact due to rotor vibration, thermal transients or nozzle deflection. A brush seal has also been employed to improve the inner stage packing seal. This seal is available for all single shaft designs and provides a performance improvement of approximately 1% output and 0.5% heat rate. Combined Cycle Power Plants 6. Gas Turbine Performance 99 / 101

100 Stage 2 and 3 Shroud Honeycomb Seal 17. Seal Rubbing [3/3] GER-3571H To avoid bucket tip rub, the clearance between the bucket tip and stationary shroud blocks have always been about 100 mils. This large clearance allows a significant amount of hot gas to flow over the bucket tip, resulting in significant performance loss. The honeycomb material is softer than the shroud and bucket material, which makes it sacrificial in nature for this application. The bucket tip shroud labyrinth seals are designed to cut a groove into the honeycomb material. The clearance between the bucket tip and the honeycomb shroud seals provide a performance improvement up to 0.6% in both output and heat rate. Combined Cycle Power Plants 6. Gas Turbine Performance 100 / 101