OPTIMIZING PERFORMANCE BY APPLYING THE FUNDAMENTALS

Transcription

1 OPTIMIZING PERFORMANCE BY APPLYING THE FUNDAMENTALS By: Richard Storm and Staff of Storm Technologies, Inc. STORM TECHNOLOGIES, INC.

2 Typical Operation & Maintenance Expenses for Fossil Plants Including Fuel Fuel 80% Steam Exp 3% Elec Plt Maint 2% Misc Pow er Exp 3% Boiler Maint 7% Other 5%

3 Typical Operation and Maintenance Expenses for Fossil Fuel Plants Excluding Fuel Elec Plt Maint 10% Boiler Maint 31% Steam Exp 12% Misc Pow er Exp 13% Maint Structures 4% Other 5% Maint Supv & Eng 6% Electric Exp 6% Oper Supv & Eng 13%

4 U.S. ELECTRICITY GENERATION BY SOURCE SOURCE YEAR 2000 YTD 2001 % Change kwh produced 2000 vs Coal Nuclear Natural Gas Hydro Oil Renewables *Source: Nuclear Energy Institute

5 Heat Rate Medians 10,800 10,790 10,750 Btu/KwHr 10,700 10,650 10,650 10,616 10,600 10,601 10,564 10,605 10,550 10,569 10,568 10,546 10,523 10,515 Margin for Excellence in Operation and Maintenance. A Typical 2,400 Psi 10,500 o 1000/1000 F. Coal Fired Power Plant operating at 80% load factor can usually produce a heat rate of less than 9800 Btu/Kwh 10,450 10,400 10, , Year

6 TOP 10 Plants from EL&P Nov Rank State Holding company/utility name Plant name 2001 Capacity (MW) Capacity factor % Heat rate (Btu/kWh) 1 TN Tennessee Valley Authority Bull Run % 8,881 2 NC Duke Power Co. Marshall 2, % 9,026 3 NC Duke Power Co. Belews Creek 2, % 9,092 4 GA Southern Co Georgia Power Wansley 1, % 9,201 5 MD Mirant Mid-Atlantic LLC Morgantown 1, % 9,229 6 CO Xcel Energy Public Service Co of Colorado Valmont % 9,272 7 PA Reliant Resources Keystone 1, % 9,338 8 SC South Carolina Electric & Gas McMeekin % 9,369 9 PA Edison Mission Energy Homer City 1, % 9, PA PPL Corp Montour 1, % 9,436 Source: Energy Ventures Analysis Inc.

7 Large Coal Fired Power Plants have regressed in efficiency over the last 40 years due to over-regulation regulation and the absence of applying the fundamentals Heat Rate 9500 Opportunity to Apply the Fundamentals 9,500 Typical "Average" 500 MW Coal Fired Plant 2400 Psi 1000/ ,800 8,881 Typical 2400 Psi 1000/ ,210 Eddystone Station 8,500 Typical New Supercritical units 8,500 Typical supercritical units with cooling towers Typical Supercritical units with Low NOx Burners Year "Best" Supercritical Units

8 Updates to Reduce Emissions Low NOx Burners Over Fire Air New DCS Control Systems SNCR or SCR s

9 A Devolatilization Zone B Production of Reducing Species C NOx Decomposition Zone D Char Oxidizing Zone Notice how the fuel is deliberately separated from the fuel-rich core of the flame. This, of course, lengthens the flame and extends the combustion process to higher in the furnace.

10 Typical Low NOx burner as compared to a pre- low NOx burner with flames approx. to scale. State of the art 1990 s 2002 low NOx burners Both burners 175 MM Btu/hour s High Intensity Burner Low NOx burners and low NOx systems which utilize OFA deliberately stage combustion and consume more of the available residence time

11 Boilers Retrofitted with low NOx burners still have the same furnace size and residence time for carbon char burnout. Residence Time

12 The three elements of Carbon Char burnout are absolutely essential for low unburned carbon in ash.

13 The Usual NOx and Carbon in Ash Relationship without Addressing the Fundamentals High Intensity Combustion Maximum Turbulence Low intensity Combustion

14 Representative Flyash Sampling

15 There are five items, which should be measured periodically. These are leading indicators of performance opportunities: Furnace Exit Gas Temperature by HVT Furnace Exit Gas Oxygen by water-cooled HVT Economizer Exit Gas Temperature Flyash Unburned Carbon by Representative Flue Inserted Sampler Stack Oxygen, (to measure overall leakage from furnace to stack)

16 Typical Boiler Temperatures 1,400-1,600 F Economizer 750 F 2,100 F Burner Belt 2,800 3,200 F Approximately 1 sec Residence Time

17 OFA Zone To Complete Combustion Stoichiometry Greater Than 1.0 Burner Zone Stoichiometry Less Than 1.0

18 Thirteen Essentials of Optimum Combustion 1. Furnace exit must be oxidizing preferably, 3%.

19 Air in leakage continues to be a problem with year old balanced draft boilers. The numbers shown are ideal.

20 Thirteen Essentials of Optimum Combustion 2. Fuel lines balanced to each burner by Clean Air test ±2% or better.

21 Thirteen Essentials of Optimum Combustion 3. Fuel lines balanced by Dirty Air test, using a Dirty Air Velocity Probe, to ±5% or better. 4. Fuel lines balanced in fuel flow to ±10% or better.

22 Thirteen Essentials of Optimum Combustion 5. Fuel line fineness shall be 75% or more passing a 200 mesh screen. 50 mesh particles shall be less than 0.1%. Rosin-Rammler Fineness Plot 1000 U.S. Standard Sieve Size % Thru

23 Thirteen Essentials of Optimum Combustion 6. Primary airflow shall be accurately measured & controlled to ±3% accuracy. 7. Overfire air shall be accurately measured & controlled to ±3% accuracy.

24 Thirteen Essentials of Optimum Combustion 8. Primary air/fuel ratio shall be accurately controlled when above minimum. 9. Fuel line minimum velocities shall be 3,300 fpm.

25 Thirteen Essentials of Optimum Combustion 10. Mechanical tolerances of burners and dampers shall be ±1/4 or better.

26 Thirteen Essentials of Optimum Combustion 11. Secondary air distribution to burners should be within ±5% to ±10%.

27 Thirteen Essentials of Optimum Combustion 12. Fuel feed to the pulverizers should be smooth during load changes and measured and controlled as accurately as possible. Load cell equipped gravimetric feeders are preferred.

28 Thirteen Essentials of Optimum Combustion 13. Fuel feed quality and size should be consistent. Consistent raw coal sizing of feed to pulverizers is a good start. 100 Raw Fuel Size vs. Percent Fuel Feed Rate Percent Coal Feed Rate (%) Trend Raw Coal Top Size (inches) This data is based on Actual Recorded conditions of an EL 56; for informational purposes only. All data recorded for coal with the same HGI.

29 Pulverized Coal Fueled Boilers Built 30 Years Ago with Original Pulverizers Have a 25-30% Capacity Penalty When Firing Low Sulfur, Low HGI Eastern Fuels. Normal Design for 60 s 70 s pulverizers Approx % reduction in real pulverizer capacity Design 50 HGI and 70% passing 200 mesh 40 HGI and 75-80% Passing 200 mesh normal requirements for 2003 operation

30 Airflow and Fuel line balancing, What are the benefits?

31 Typical 450 MW Coal Fired Unit Comprehensive Boiler Air and Fuel Balancing Furnace Exit HVT Traverse Economizer Exit Gas Temp and Oxygen Traverse Secondary Air Velocity Traverse Locations Each of 4 Corners Vertical Fuel Line Test Conections for Fuel Fineness, Fuel Distribution, Clean Air Velocity, and Dirty Air Velocity Air Heater Exit Flue Gas for Temp, Oxygen, and Flyash Sampling Primary Air Flow Measurement

32 Unit heat rate was reduced by applying the fundamentals to the fuel and air inputs to the furnace. WCB6 HEAT RATE BTU/NET-KWH 10,100 10,050 10,047 10,000 BTU/KWH 9,950 9,900 9,850 9,800 9,750 9,700 9,847 9,770 9,741 9,661 9,766 9,650 9, months

33 Capacity Factor Was Significantly Increased Due to Reduced Slagging WCBS #6 Monthly Generation 3,000,000 2,800,000 Monthly Net Generation (MW H) 2,600,000 2,400,000 2,200,000 2,000,000 1,800,000 1,600, Month

34 Operations and Maintenance Controlled Variables that Affect Heat Rate 1. Flyash unburned carbon content 2. Bottom ash carbon content 3. Airheater leakage 4. A.H. Exit Gas Temperature (corrected for leakage) 5. Furnace Exit Gas Temperature and its effect on superheater de-superheating spray flow 6. Air in-leakage 7. S.H. Steam Temperature 8. R. H. Steam Temperature 9. Primary airflow (tempering air which bypasses the airheaters.

35 Flyash Carbon Content % Change in Efficiency Increase in Heat Rate (BTU/Kwhr) % Change in Flyash Carbon 1% Change in Flyash Carbon Results in about a 1/10% change in Boiler Efficiency or about 10 BTU/Kwhr heat reat increase

36 10. Auxiliary power consumption (fan clearances, airheater pluggage, air in leakage, sootblowing air compressors, pulverizers, boiler fouling, which creates draft losses, etc ) 11. Sootblower operation 12. Boiler Exit Gas Temperature (economizer exit) 13. Furnace, boiler exit and airheater exit excess oxygen content 14. De superheating spray water flow into the reheater. 15. Cycle losses due to vent and drain valve leakage. 16. Steam purity and turbine deposits from boiler water carryover 17. Pulverizer air in-leakage for exhauster equipped pulverizers 18. Pulverizer coal spillage

37 To Maintain Optimum Performance Weekly, monthly, and quarterly tests of: Coal fineness Furnace exit HVT Testing Boiler Air In-Leakage Air Heater Leakage Flyash Unburned Carbon

38 Testing does not correct a heat rate problem

39 But testing is necessary to identify opportunities for improvement A problem identified is a problem half solved

40 Recommended Periodic Testing Weekly representative flyash carbon content sampling Monthly coal fineness tests Monthly airheater performance tests Quarterly oxygen rise tests from the furnace to the stack Quarterly coal feeder calibrations Quarterly high precision coal fineness and distribution tests Semi-annual airflow device calibrations Semi-annual fuel line clean-air air testing to prove ±2% balance Pre-outage comprehensive boiler evaluation tests to fine tune the outage work list.

41 The best approach to achieving close to design heat rate is a real team effort of: Operations Maintenance Heat Rate Engineers Plant Engineers/Results Engineers