System for optimizing a combustion heating process

1. A system for determining performance characteristics of a combustion heating process in a steam generation system, the system comprising:

means for receiving input data associated with controllable input parameters of the steam generation system, wherein said controllable input parameters are parameters controlled by at least one of (1) an operator of the combustion heating process and (2) a computer control system;

means for determining a plurality of controllable loss components using the input data associated with the controllable input parameters, said controllable loss components determined in accordance with said received input data; and

means for determining an efficiency reference index by summing said plurality of controllable loss components; and

means for outputting the determined efficiency reference index to a combustion optimization system, wherein the combustion optimization system uses the efficiency reference index to determine optimized control values for optimizing the combustion heating process.

2. A system according to claim 1 , wherein said input data associated with the controllable input parameters is selected from the group consisting of:

% carbon in fuel, % hydrogen in fuel, % oxygen in fuel, % nitrogen in fuel, % sulfur in fuel, % ash in fuel, % water in fuel, carbon in bottom ash (percent), fly ash in total ash (percent), carbon in fly ash (percent), measured O 2 (percent), O 2 measurement as wet or dry basis, absolute humidity, air preheater flue gas outlet temperature, ambient temperature, higher heating value, gross mw, fuel flow, max gross load, desired superheat temperature, actual superheat temperature, desired reheat temperature, actual reheat temperature, baseline heat rate, maximum steam flow, superheat steam flow, superheat spray flow, reheat spray flow, total mill amperage, mill volts, total forced draft fan amperage, forced draft fan volts, total induced draft fan amperage, and induced draft fan volts.

3. A system according to claim 1 , wherein said plurality of controllable loss components are selected from the group consisting of: Dry Gas Loss, Superheat (SH) Temperature Loss/Credit, Reheat (RH) Temperature Loss/Credit, Superheat (SH) Spray Flow Loss, Reheat (RH) Spray Flow Loss, Auxiliary Power Energy Loss, and Carbon Loss.

4. A system according to claim 3 , wherein said dry gas loss is determined as a function of % carbon in fuel, % hydrogen in fuel, % oxygen in fuel, % nitrogen in fuel, % sulfur in fuel, % ash in fuel, % water in fuel, carbon in bottom ash (percent), fly ash in total ash (percent), carbon in fly ash (percent), measured 0 2 (percent), 0 2 measurement as wet or dry basis, humidity, air preheater flue gas outlet temperature, ambient temperature, higher heating value, gross MW, and fuel flow.

5. A system according to claim 3 , wherein said Superheat (SH) Temperature Loss is determined as a function of Max Gross Load, Gross MW, desired superheat temperature, and actual superheat temperature.

6. A system according to claim 3 , wherein said Reheat (RH) Temperature Loss is determined as a function of maximum gross load, Gross MW, desired reheat temperature, and actual reheat temperature.

7. A system according to claim 3 , wherein said Superheat (SH) Spray Flow Loss is determined as a function of baseline heat rate, maximum superheat steam flow, superheat steam flow, and superheat spray flow.

8. A system according to claim 3 , wherein said Reheat (RH) Spray Flow Loss is determined as a function of baseline heat rate maximum superheat steam flow, superheat steam flow, and reheat spray flow.

9. A system according to claim 3 , wherein said Auxiliary Power Energy Loss is determined as a function of total mill amps, mill volts, total forced draft fan amps, forced draft fan volts, total induced draft fan amps, and induced draft fan volts.

10. A system according to claim 3 , wherein said Carbon Loss is determined as a function of % Ash in fuel, carbon in bottom ash (percent), fly ash in total ash (percent), carbon in fly ash (percent), high heat value, gross MW, and fuel flow.

11. A system according to claim 1 ,

wherein said combustion optimization system optimizes a combustion process by providing optimal flows, temperatures and distributions of at least one of air and fuel.

12. A system according to claim 1 , wherein said combustion optimization system determines an optimal configuration of the steam generation system that maximizes reduction in said controllable loss components.

13. A system according to claim 1 , wherein said system further comprises:

means for outputting the efficiency reference index to a neural network.

14. A system according to claim 1 , wherein said system further comprises:

means for outputting the efficiency reference index to a distributed control system of the steam generation system, said distributed control system controlling operation of system devices for the steam generation system.

15. A system according to claim 1 , wherein said system further comprises:

means for comparing computed efficiency reference index values associated with multiple steam generation systems.

16. A method for determining performance characteristics of a combustion heating process in a steam generation system, the method comprising:

receiving input data associated with controllable input parameters of a steam generation system, wherein the controllable input parameters are parameters controlled by at least one of (1) an operator of the combustion heating process and (2) a computer control system;

determining a plurality of controllable loss components using the input data associated with the controllable input parameters;

determining an efficiency reference index by summing said plurality of controllable loss components; and

outputting the efficiency reference index to a combustion optimization system, wherein the combustion optimization system uses the efficiency reference index to determine optimized control values for optimizing the combustion heating process.

17. A method according to claim 16 , wherein said input data associated with the controllable input parameters is selected from the group consisting of:

% carbon in fuel, % hydrogen in fuel, % oxygen in fuel, % nitrogen in fuel, % sulfur in fuel, % ash in fuel, % water in fuel, carbon in bottom ash (percent), fly ash in total ash (percent), carbon in fly ash (percent), measured O 2 (percent), O 2 measurement as wet or dry basis, absolute humidity, air preheater flue gas outlet temperature, ambient temperature, higher heating value, gross mw, fuel flow, max gross load, desired superheat temperature, actual superheat temperature, desired reheat temperature, actual reheat temperature, baseline heat rate, maximum steam flow, superheat steam flow, superheat spray flow, reheat spray flow, total mill amperage, mill volts, total forced draft fan amperage, forced draft fan volts, total induced draft fan amperage, and induced draft fan volts.

18. A method according to claim 16 , wherein said plurality of controllable loss components are selected from the group consisting of: Dry Gas Loss, Superheat (SH) Temperature Loss/Credit, Reheat (RH) Temperature Loss/Credit, Superheat (SH) Spray Flow Loss, Reheat (RH) Spray Flow Loss, Auxiliary Power Energy Loss, and Carbon Loss.

19. A method according to claim 18 , wherein said dry gas loss is determined as a function of % carbon in fuel, % hydrogen in, % oxygen in fuel, % nitrogen in fuel, % sulfur in fuel, % ash in fuel, % water in fuel, carbon in bottom ash (percent), fly ash in total ash (percent), carbon in fly ash (percent), measured 0 2 (percent), 0 2 measurement as wet or dry basis, humidity, air preheater out temperature, ambient temperature, higher heating value, gross MW, and fuel flow.

20. A method according to claim 19 , wherein said Dry Gas Loss is determined by the steps comprising:

calculating an Adjusted Effective Carbon Fraction Burned;

calculating an amount of O 2 required to produce a “zero excess air” condition;

using an iterative calculation to determine an amount of O 2 in flue gas at a measured excess O 2 level;

calculating an actual flue gas composition by volume for a measured and a reference O 2 level;

calculating individual “dry” and “wet” component losses on a per component basis; and

summing individual “dry” component losses to produce a dry gas loss value.

21. A method according to claim 18 , wherein said Superheat (SH) Temperature Loss/Credit is determined as a function of Max Gross Load, gross MW desired superheat temperature, and actual superheat temperature.

22. A method according to claim 21 , wherein said Superheat (SH) Temperature Loss/Credit is determined by the steps comprising:

calculating a load factor;

calculating a Superheat (SH) temperature deviation factor; and

calculating a Loss/Credit fraction.

23. A method according to claim 18 , wherein said Reheat (RH) Temperature Loss/Credit is determined as a function of maximum gross load, gross MW, desired reheat temperature, and actual reheat temperature.

24. A method according to claim 23 , wherein said Reheat (RH) Temperature Loss/Credit is determined by the steps comprising:

calculating a load factor;

calculating a Reheat (RH) temperature deviation factor; and

calculating a Loss/Credit fraction.

25. A method according to claim 18 , wherein said Superheat (SH) Spray Flow Loss is determined as a function of baseline heat rate, maximum superheat steam flow, superheat steam flow, and superheat spray flow.

26. A method according to claim 25 , wherein said Superheat (SH) Spray Flow Loss is determined by the steps comprising:

calculating a percent maximum throttle flow; and

calculating a percent spray flow of the main steam flow.

27. A method according to claim 18 , wherein said Reheat (RH) Spray Flow Loss is determined as a function of baseline heat rate, maximum superheat steam flow, superheat steam flow, and reheat spray flow.

28. A method according to claim 27 , wherein said Reheat (RH) Spray Flow Loss is determined by the steps comprising:

calculating a percent maximum reheat steam flow; and

calculating a percent spray flow of the reheat steam flow.

29. A method according to claim 18 , wherein said Auxiliary Power Energy Loss is determined as a function of total mill amps, mill volts, total forced draft fan amps, forced draft fan volts, total induced draft fan amps, and induced draft fan volts.

30. A method according to claim 29 , wherein said Auxiliary Power Energy Loss is determined by the steps comprising:

calculating power consumed by each motor; and

calculating a single motor power value for all of the motors.

31. A method according to claim 18 , wherein said Carbon Loss is determined as a function of % Ash in fuel, carbon in bottom ash (percent), fly ash in total ash (percent), carbon in fly ash (percent), high heat value, gross MW, and fuel flow.

32. A method according to claim 31 , wherein said Carbon Loss is determined by the steps comprising:

calculating an unburned carbon fraction; and

calculating unburned carbon loss.

33. A method according to claim 16 , wherein said combustion optimization system optimizes a combustion process by providing optimal flows, temperatures and distributions of at least one of air and fuel.

34. A method according to claim 33 , wherein said combustion optimization system determines an optimal configuration of the steam generation system that maximizes reduction in said controllable loss components.

35. A method according to claim 16 , wherein said method further comprises:

outputting the efficiency reference index to a neural network.

36. A method according to claim 16 , wherein said method further comprises:

outputting the efficiency reference index to a distributed control system of the steam generation system, said distributed control system controlling operation of system devices for the steam generation system.

37. A method according to claim 16 , wherein said method further comprises:

comparing a plurality of computed efficiency reference index values associated with multiple steam generation systems.

38. An operating system for an electric power generating plant using a combustion heating process to produce steam, the system comprising:

a distributed control system for controlling operation of system devices of the electric power generating plant;

a combustion optimization system, in communication with the distributed control system, for optimizing the combustion heating process by determining optimized control values, said optimized control values output to the distributed control system; and

a performance calculation system, in communication with the combustion optimization system, for determining an efficiency reference index indicative of the efficiency of the combustion heating process, said performance calculation system including:

means for receiving input data associated with controllable input parameters of electric power generating plant, wherein said controllable input parameters are parameters that are controlled by at least one of (1) an operator of the combustion heating process and (2) a computer control system;

means for determining a plurality of controllable loss components using the input data associated with the controllable input parameters, said controllable loss components determined in accordance with said received input data; and

means for determining an efficiency reference index by summing said plurality of controllable loss components; and

means for outputting the determined efficiency reference index to the combustion optimization system, wherein the combustion optimization system uses the efficiency reference index in determining the optimized control values.