METHOD FOR DETERMINATION OF CARBON DIOXIDE EMISSIONS FROM COMBUSTION SOURCES USED TO HEAT A WORKING FLUID

• US 20100312490A1
• Filed: 05/17/2010
• Published: 12/09/2010
• Est. Priority Date: 06/04/2009
• Status: Active Grant

• Current Assignee: General Electric Technology GmbH (General Electric Company)
• Original Assignee: Alstom Technology Ltd. (Alstom SA)
• Inventors: Dooley, Matthew Joseph
• Granted Patent: US 8,626,450 B2
• Time in Patent Office: Days
• US Class Current: 702/24
• CPC Class Codes: F22B 37/38 Determining or indicating operating conditions in steam boilers, e.g. monitoring direction or rate of water flow through water tubes measuring or indicating instruments in general G01
• CPC Class Codes: Y02P 80/15 On-site combined power, heat or cool generation or distribution, e.g. combined heat and power [CHP] supply

Abstract

A method for determining carbon emissions from a steam generation system is disclosed. It includes measuring a first energy of feedwater entering into a steam generation system and measuring a second energy of steam exiting the steam generation system. The first energy is subtracted from the second energy to determine a total energy absorbed by the steam generation system. The total energy absorbed by the steam generation system is divided by the total energy to determine a heat input to the steam generation system. The heat input is used to determine the carbon emissions from the steam generation system.

Claims

1. A method comprising:

measuring a first energy of feedwater entering into a steam generation system;

measuring a second energy of steam or water exiting the steam generation system;

subtracting a difference between the first energy and the second energy to determine a total energy absorbed by the steam generation system;

dividing the total energy absorbed by the steam generation system by an efficiency of the steam generation system to determine a heat input to the steam generation system; and

determining the carbon emissions from the heat input to the steam generation system.

2. The method of claim 1, further comprising measuring flue gas oxygen content and flue gas temperature in a grid at an exit of an air heater.

3. The method of claim 1, further comprising periodically sampling fuel and ash from the steam generation system and analyzing the fuel and the ash.

7. The method of claim 1, where the carbon emissions can be determined from the Equations (11), (12) and (13) below:

8. The method of claim 1, where the amounts of nitrogen oxides, sulfur dioxides and carbon monoxide are determined using the equations (14) and (15) below:

9. The method of claim 1, where the total energy absorbed by the steam generation system is obtained from Equation (8)

Q_BLR=Q_MS+Q_MSspray+Q_Bd+Q_SB+Q_AUX+Q_RH+Q_RHspray 

 

(8),

where Q_MS is a total energy of a main steam;

M_MSspray is a total energy of a spray introduced into a mains steam, Q_Bd is a total energy of a blow down steam, Q_SB is a total energy of a sootblowing steam, Q_AUX is a total energy of an auxiliary steam, Q_RH is a total energy of a reheat steam and Q_Rhspray is a total energy of a spray introduced into a reheat steam.

10. The method of claim 9, where the total energy of the main steam Q_MS is determined by Equation (1)

Q_MS=(M_FW−

M_SB−

M_Bd−

M_AUX)(H_MS−

H_FW) 

 

(1),

where M_FW is a mass of the feedwater, M_SB is a mass of the sootblowing steam, M_Bd is a mass of the blowdown water, M_AUX is a mass of the auxiliary steam, H_MS is an enthalpy of the main steam, H_FW is an enthalpy of the feedwater.

11. The method of claim 9, where the total energy of the sootblowing steam is determined by Equation (2) below:

Q_SB=M_SB(H_sb−

H_FW) 

 

(2),

where Q_SB is a total energy of a sootblowing steam, M_SB is a mass of the sootblowing steam, H_FW is an enthalpy of the feedwater and H_sb is the enthalpy of the sootblowing steam.

12. The method of claim 9, where the total energy of the blowdown Q_Bd water is determined by Equation (3) below:

Q_Bd=M_Bd(M_bd−

H_FW) 

 

(3),

where M_Bd is a mass of blow down water, H_FW is the enthalpy of feedwater and H_bd is the enthalpy of the blowdown water at saturated conditions of drum pressure.

13. The method of claim 9, where the total energy of the auxiliary steam Q_AUX is determined by Equation (4) below:

Q_AUX=M_AUX(H_AUX−

H_FW) 

 

(4),

where M_AUX is the mass of auxiliary steam, H_FW is the enthalpy of feedwater and H_AUX is the enthalpy of the auxiliary steam.

14. The method of claim 9, where the total energy absorbed by sprays to the main steam is determined by Equation (5) below:

QrMSspray=MrMSspray(H_MS−

H_MSspray) 

 

(5),

where

QrMSspray and MrMSspray are an energy rate of a spray to the main steam and z mass rate of the spray to the main steam respectively, H_MS is an enthalpy of the main steam and H_MSspray is an enthalpy of a spray to the main steam.

15. The method of claim 9, where the total energy absorbed in the reheat steam is determined by Equation (6) below:

QrRH=MrCRH(H_HRH−

H_CRH) 

 

(6),

where QrRH and MrCRH are the energy rate and the mass rate of the reheat steam respectively and H_HRH and H_CRH are the enthalpy of the hot reheat steam and the cold reheat steam respectively.

16. The method of claim 9, where the total energy absorbed by sprays to the reheat steam are provided in the Equation (7) below:

QrRHspray=MrRHspray(H_HRH−

HRH_RHSpray) 

 

(7)

where QrRHspray and MrRHspray are an enthalpy rate and a mass rate for the spray to the reheat steam, H_HRH and HRH_RHSpray is an enthalpy for hot reheat steam and an enthalpy for a spray for the reheat steam respectively.

17. The method of claim 1, further comprising determining the fuel flow to the steam generation system by Equation (15a) below:

18. The method of claim 1, further comprising determining the amount of dry air entering the boiler ahead of a location z via equation (29)

19. The method of claim 1, further comprising determining the wet air entering the boiler ahead of a location z by Equations (31) and (32)

MqAz=(1+MFrWA)MqDAz pounds per BTU 

 

(31)

MFrAz=(1+MFrWA)MFrDAz pounds per pound of fuel 

 

(32),

where the terms Mq represents the mass in pounds per BTU, MqAz represents the mass in pounds of dry air at location z, MFrWA is the mass fraction of wet air, MqDAz represents the mass in pounds per BTU of dry air at location z and MFrDAz represents the mass fraction of dry air at location z.

20. The method of claim 1, further comprising determining the wet gas from fuel by Equation (33) below:

21. The method of claim 1, further comprising determining the total wet flue gas weight in pounds per BTU via Equation (41), where

MqFgz=MqDAz+MqWAz+MqFgF+MqCO₂Sb+MqWSb+MqWADz 

 

(41),

where MqFgz is the mass in pounds per BTU of wet gas in fuel at a location z, MqDAz represents the mass in pounds per BTU of dry air at location z, MqWAz represents the mass in pounds per BTU of wet air at location z, MqFgF is the mass in pounds per BTU of wet gas in fuel, MqCO₂Sb is the mass in pounds per BTU of carbon dioxide in sorbent, MqWSb is the mass in pounds per BTU of wet sorbent and MqWADz is the mass in pounds per BTU of moisture added per pound of fuel fired.

22. The method of claim 1, further comprising determining the theoretical air corrected for carbon burned via Equation (21) below:

MFrThACr=0.1151×

MpCb+0.3430×

MpH₂F+MpSF(1+0.5MFrSc)−

0.0432×

MpO₂F 

 

(21),

where MFrThACr is the theoretical air corrected for carbon burned in pounds per pound of fuel, where MFrSc is the mass fraction of sulfur capture and where MpCb, MpH₂F, MpSF and MpO₂F are the mass percent of carbon, the mass percent of hydrogen in fuel, the mass percent of sulfur in fuel and the mass percent of oxygen in fuel respectively.

23. The method of claim 1, where an efficiency of the steam generation system is determined by a modified ASME PTC 4 methodology.

24. The method of claim 1, where the steam generation system is a boiler.

4. The method of claim 4, further comprising maintaining a database of the analysis of fuel and ash and using data from the database to accurately determine the heat input to the steam generation system.

5. The method of claim 4, wherein the database is used to compile a historical record;

the historical record being used to analyze yields that provide the lowest uncertainty.

6. The method of claim 5, wherein analyzing the yields that provide the lowest uncertainty is conducted on a moisture and ash-free basis in addition to an as-received basis;

the as-received basis pertaining to as-received fuel.

25. A method comprising:

calculating the total energy absorbed by a working fluid in a boiler as it undergoes a change of state;

dividing the total energy absorbed by the boiler by an efficiency of the boiler to determine a heat input to the boiler; and

determining carbon emissions from the heat input to the boiler.

26. The method of claim 25, where the working fluid is water.

27. The method of claim 25, where the calculating the total energy absorbed by the working fluid comprises measuring a first energy of the working fluid as it enters the boiler and a second energy of the working fluid as it exist the boiler and subtracting the first energy from the second energy.

28. The method of claim 27, where the first energy is an energy of feedwater as it enters the boiler.

29. The method of claim 28, wherein the energy of feedwater is determined by repeatedly verifying feedwater flow measurement to where an uncertainty of flow is less than 1.5%.

30. The method of claim 27, where the second energy is an energy of steam as it exits the boiler.

31. The method of claim 25, where the carbon emissions can be determined from the Equations (11), (12) and (13) below:

32. The method of claim 25, where an efficiency of the steam generation system is determined by a modified ASME PTC 4 methodology.