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Published on November 18, 2010

Author: shivajichoudhury

Source: authorstream.com

HEAT RATE AUDIT IN THERMAL POWER PLANT: HEAT RATE AUDIT IN THERMAL POWER PLANT SHIVAJI CHOUDHURY The New Scenario: The New Scenario In the new competitive scenario, power stations must face: • To Reduce the generating costs. • To Maintain high availability, efficiency and operational flexibility. • To Meet strict environmental conditions. • To Manage and extend the equipment life, including systems modernization. The Generation Cost: The Generation Cost The variable overall cost =(The Plant Availability Factor ,Station Heat Rate , Specific Fuel Oil Consumption , Auxiliary Energy Consumption ). The Variable Cost, decides the competitiveness of the electric units in a generating pool. The Generation Cost Reduction: The Generation Cost Reduction The kWh fuel cost = 70 % approx the variable overall cost . The Fuel cost components: The station Heat Rate (kcal/kWh). To reduce the variable cost through the heat rate improvement. Heat rate: Heat rate Heat rate is the heat input (fuel) required per unit of power generated (kcal/kWh), for specific fuel being fired and specific site conditions. Station heat rate = Turbine cycle heat rate =-------------------------- x100 Boiler efficiency % Objective: Objective To point out the causes and location of efficiency losses. Improve station heat rate. LOSSES IN THERMAL POWER PLANT: LOSSES IN THERMAL POWER PLANT 1.Boiler losses 2.Turbine losses 3.Condensate/feed water system losses. 4.Circulating water system losses. 5.Steam conditions 6.Electrical auxiliary losses 7.Steam auxiliary losses 8.Fuel handing 9.Heat losses 10.Cycle isolation 11. Impact of parameter deviation on HEAT RATE 12.D M water Makeup 1.Boiler losses: 1.Boiler losses Symptoms Boiler efficiency Exit gas temp high Excess air Causes 1.1.Moisture losses 1.2.Dry gas losses 1.3.Incomplete combustion 1.4.Radiation losses 1.1.Moisture losses: 1.1.Moisture losses High moisture in air Tube leaks Coal quality 1.2.Dry losses: 1.2.Dry losses Boiler casing air leakage Air pre heater leakage Incorrect fuel air ratio Fouled heat transfer surfaces 1.3.Incomplete Combustion: 1.3.Incomplete Combustion Coal quality Increased in ash contain Increased in carbon contain Decreased Coal mill fineness Classifier vanes improperly adjusted Ring/roller wear Classifier vane wear Burner tips plugged/eroded Burner damper settings Incorrect fuel air ratio. Hi oxygen at boiler out 2.Turbine losses: 2.Turbine losses Symptoms HP/IP/LP section efficiency Causes 2.1.Mechanical damage Metallurgical defects Maintenance practices 2.2.Flow area decrease Mechanical blockage Blade deposits 2.3.Flow area bypass 2.4.Flow area increase 2.3. Flow area bypass: 2.3. Flow area bypass H P Turbine inlet bushing leakage Main steam valve leakage H P gland seal leakage IP steam /intercept valve leakage I P Turbine inlet bushing leakage 2.4. Flow area increase: 2.4. Flow area increase Spill strip or packing leakage. Rubbing Thermal stress Erosion of turbine stages. Solid particle erosion of nozzle block. Condenser leaks Poor water chemistry Blade mechanism damage. PowerPoint Presentation: Leaking steam not contribution to power generation (in RED) 2.5.Cross section of turbine –showing efficiency loss due to leakage 3.Condensate / F W system losses: 3.Condensate / F W system losses Symptoms Low feed water temp Causes HP/LP heaters out of service CEP/BFP efficiency Shaft rub Impeller wear Flow resistance path increase LP/HP heaters (high TTD/DCA) Excessive tube plugged FW heater out/bypass FW heater level low/high 4.Circulating water losses: 4.Circulating water losses Symptoms High back pressure Causes Number of CW pump in operation Air binding of condenser tubes Excessive air in leakage Inadequate air removal capacity Fouled condenser tubes Microfouling Plugged condenser tubes Air binding water box Low circulating water flow Increased CW system resistance Decreased CW pump performance Excessive condenser tube plugged 5.Steam condition: 5.Steam condition Firing conditions High super heater spray flow High re heater spray flow Inadequate heat transfer surface 6.Electrical auxiliary losses: 6.Electrical auxiliary losses Symptoms Station load Causes Precipitator (ESP) performance Ash deposit Excessive rapping High ash in coal Fan (ID,FD,PA ) Change in fan efficiency AHP chocking Pump (BFP,CEP,CW ) Change in pump efficiency LP/HP Feedwater heater tube plugged Coal Mill performance Classifier setting incorrect Coal quality 7.Seam Auxiliary Losses: 7.Seam Auxiliary Losses Excessive soot blowing Decreased in BFP Turbine efficiency Low inlet steam temperature Excessive steam flow through vacuum pump/ejector Steam trap/vent leaking Excessive usage of steam coil 8.Fuel Handling: 8.Fuel Handling Spillage from the belt/transport Measurement inaccuracies Coal pile erosion Wind erosion Water erosion Coal pile fire 9. Heat Losses: 9. Heat Losses Insulation on duct, pipe , turbine etc . No insulation Insulation damages Poor insulation Cladding missing /loose Steam leakage. Leakage to blow down tank. Leakage through vents, drains. 10.Cycle isolation: 10.Cycle isolation Leakage from recirculation valves of BFP/CEP. Leakage through bypass valves. Leakage to condenser through high energy drains. Leakage to condenser through emergency control valves of feed water heaters. Check high energy drains after every startup. Provide Thermocouple in High energy Drains, To detect passing of drain valve. 11.Impact of parameter deviation on HEAT RATE (210 MW ,KWU Turbine )-operator controllable parameters.: 11.Impact of parameter deviation on HEAT RATE (210 MW ,KWU Turbine )-operator controllable parameters. SN PARTICULAR UNIT DESIGN PARAMETERS INCREASE OF HEAT RATE DUE TO DEVIATION IN KCAL/KWH MULTIPLICATION FACTOR 1 PARTIAL LOADING MW 210 24.7 PER 20 MW 1.235 2 MS PRESS KG/CM2 150 25.5 PER 20 KG/CM2 1.275 3 MS TEMP AT HPT INLET DEG C 535 7.5 PER 10 DEG C 0.75 4 HRH TEMP AT IPT INLET DEG 535 6.6 PER PER 10 DEG C 0.66 5 CONDENSER VACUUM mmHg 660 23.4 PER 10 mm Hg 2.34 6 FEED WATER TEMP DEG C 241 16 PER 20 DEG C 0.8 7 RH ATTEMP FLOW T/HR 0 6.4 PER 10 T/HR 0.64 8 OXYGEN % IN FLUE GASES % 3 8 PER 1% 8

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