IPC분류정보
국가/구분 |
United States(US) Patent
등록
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국제특허분류(IPC7판) |
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출원번호 |
US-0781060
(2010-05-17)
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등록번호 |
US-8626450
(2014-01-07)
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발명자
/ 주소 |
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출원인 / 주소 |
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인용정보 |
피인용 횟수 :
1 인용 특허 :
1 |
초록
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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
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.
대표청구항
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1. A method comprising: measuring a first energy of feedwater entering into a steam generation system; where the steam generation system is a boiler;measuring a second energy of steam or water exiting the steam generation system;subtracting a difference between the first energy and the second energy
1. A method comprising: measuring a first energy of feedwater entering into a steam generation system; where the steam generation system is a boiler;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;determining the carbon emissions from the heat input to the steam generation system; where the heat input is obtained from the combustion of carbon based fuels; andcontrolling the carbon emissions by adjusting a flow of feedwater or steam; where the first energy and the second energy are both heat energies related to the mass and enthalpy of the feedwater entering into the steam generation system and the steam of water exiting the steam generation system respectively; and where the carbon emissions can be determined from the Equations below: MqCO2=MFrCFHHV×MWCO2MWC×106poundsofcarbondioxidepermillionBTU,MeCO2=MqCO2kW×QFIREDpoundsofcarbondioxideperkilowatt,andMteCO2=MqCO22000×QFIREDtonsofcarbondioxideperhour, MqCO2, MeCO2 and MteCO2 are masses in pounds per BTU of carbon dioxide, mass of carbon dioxide emissions on a per kW basis and mass of carbon dioxide emissions on a ton per hour basis respectively, MFrCF is the mass fraction of carbon in the fuel, MqCO2 is a mass in pounds per BTU of carbon dioxide, MWCO2 is the molecular weight of carbon dioxide respectively, MWc is the molecular weight of carbon and QFIRED is 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. 4. The method of claim 3, 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. 7. The method of claim 1, where the amounts of nitrogen oxides, sulfur dioxides and carbon monoxide are determined using the equations below: MeEm=MqEmkW×QFIREDlbEm/kW,andMteEm=MqEm2000×QFIREDEmTons/hr, where MqEm, MeEm and MteEm are masses in pounds per BTU, the mass of emissions on a per kW basis and mass of emissions on a ton per hour basis of either nitrogen oxides, sulfur dioxides or carbon monoxide emissions respectively, and where QFIRED is the heat input to the steam generation system. 8. The method of claim 1, where the total energy absorbed by the steam generation system is obtained from QBLR=QMS+QMSspray+QBd+QSB+QAUX+QRH+QRHspray, where QMS is a total energy of a main steam; QMSspray is a total energy of a spray introduced into the main steam, QBd is a total energy of a blow down steam, QSB is a total energy of a sootblowing steam, QAUX is a total energy of an auxiliary steam, QRH is a total energy of a reheat steam and QRhspray is a total energy of a spray introduced into a reheat steam. 9. The method of claim 8, where the total energy of the main steam QMS is determined by QMS=(MFW−MSB−MBd−MAux)(HMS−HFW), where MFW is a mass of the feedwater, MSB is a mass of the sootblowing steam, MBd is a mass of the blowdown water, MAux is a mass of the auxiliary steam, HMS is an enthalpy of the main steam, HFW is an enthalpy of the feedwater. 10. The method of claim 8, where the total energy of the sootblowing steam is determined by: QSB=MSB(Hsb−HFW), where QSB is a total energy of a sootblowing steam, MSB is a mass of the sootblowing steam, HFW is an enthalpy of the feedwater and Hsb is the enthalpy of the sootblowing steam. 11. The method of claim 8, where the total energy of the blowdown QBd water is determined by: QBd=MBd(Hbd−HFW), where MBd is a mass of blow down water, HFW is the enthalpy of feedwater and Hbd is the enthalpy of the blowdown water at saturated conditions of drum pressure. 12. The method of claim 8, where the total energy of the auxiliary steam QAUX is determined by: QAUX=MAUX(HAUX−HFW), where MAUX is the mass of auxiliary steam, HFW is the enthalpy of feedwater and HAUX is the enthalpy of the auxiliary steam. 13. The method of claim 8, where the total energy absorbed by sprays to the main steam is determined by: QrMSspray=MrMSspray(HMS−HMSspray), where QrMSspray and MrMSspray are an energy rate of a spray to the main steam and a mass rate of the spray to the main steam respectively, HMS is an enthalpy of the main steam and HMSspray is an enthalpy of a spray to the main steam. 14. The method of claim 8, where the total energy absorbed in the reheat steam is determined by: QrRH=MrCRH(HHRH−HCRH), where QrRH and MrCRH are the energy rate and the mass rate of the reheat steam respectively and HHRH and HCRH are the enthalpy of the hot reheat steam and the cold reheat steam respectively. 15. The method of claim 8, where the total energy absorbed by sprays to the reheat steam are provided below: QrRHspray=MrRHspray(HHRH−HRHRHSpray) where QrRHspray and MrRHspray are an enthalpy rate and a mass rate for the spray to the reheat steam, HHRH and HRHRHSpray is an enthalpy for hot reheat steam and an enthalpy for a spray for the reheat steam respectively. 16. The method of claim 1, further comprising determining the fuel flow to the steam generation system by: Mfuel=QFIREDHHV×2000tonsperhourwhere QFIRED is the heat input to the steam generation system and HHV represents the higher heating value. 17. The method of claim 1, further comprising determining the amount of dry air entering the boiler ahead of a location z by MqDAz=MqThACr(1+XpAz100)poundsperBTU, where MqDAz represents the mass in pounds per BTU of dry air at location z, MqThACr represents the mass in pounds per BTU of theoretical air in pounds per pound of fuel and XpAz represents the excess air based on an oxygen volume wet basis at location z. 18. The method of claim 1, further comprising determining the wet air entering the boiler ahead of a location z by MqAz=(1+MFrWA)MqDAz pounds per BTUMFrAz=(1+MFrWA)MFrDAz pounds per pound of fuel MqAz represents the mass in pounds of dry air at location z, MFrAz represents the mass fraction in pounds per pound of fuel 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. 19. The method of claim 1, further comprising determining the wet gas from fuel by: MqFgF=(100-MpAsF-MpUbC-MFrSc×MpSF)100×HHV where the terms MqFgF is the mass in pounds per BTU of wet gas in fuel, MpAsF is the mass percent of ash in fuel, MpUbC is the mass percent of unburned carbon, MFrSc is the fractional mass of captured sulfur, MpSF is the mass percent of sulfur in fuel. 20. The method of claim 1, further comprising determining the total wet flue gas weight in pounds per BTU by MqFgz=MqDAz+MqWAz+MqFgF+MqCO2Sb+MqWSb+MqWADz 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. 21. The method of claim 1, further comprising determining the theoretical air corrected for carbon burned by: MFrThACr=0.1151×MpCb+0.3430×MpH2F+0.0431×MpSF(1+0.5MFrSc)−0.0432×MpO2F 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. 22. The method of claim 1, where an efficiency of the steam generation system is determined by a modified ASME PTC 4 methodology. 23. The method of claim 1, where the steam generation system is a boiler. 24. 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; anddetermining carbon emissions from the heat input to the boiler; andcontrolling the carbon emissions by adjusting a flow of feedwater or steam; and where the carbon emissions can be determined from the Equations below: MqCO2=MFrCFHHV×MWCO2MWC×106poundsofcarbondioxidepermillionBTU,MeCO2=MqCO2kW×QFIREDpoundsofcarbondioxideperkilowatt,andMteCO2=MqCO22000×QFIREDtonsofcarbondioxideperhour, MqCO2, MeCO2 and MteCO2 are masses in pounds per BTU of carbon dioxide, mass of carbon dioxide emissions on a per kW basis and mass of carbon dioxide emissions on a ton per hour basis respectively, MFrCF is the mass fraction of carbon in the fuel, MqCO2 is a mass in pounds per BTU of carbon dioxide, MWCO2 is the molecular weight of carbon dioxide respectively, MWc is the molecular weight of carbon and QFIRED is the heat input to the steam generation system. 25. The method of claim 24, where the working fluid is water. 26. The method of claim 24, 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. 27. The method of claim 26, where the first energy is an energy of feedwater as it enters the boiler. 28. The method of claim 27, wherein the energy of feedwater is determined by repeatedly verifying feedwater flow measurement to where an uncertainty of flow is less than 1.5%. 29. The method of claim 26, where the second energy is an energy of steam as it exits the boiler. 30. The method of claim 24, where an efficiency of the steam generation system is determined by a modified ASME PTC 4 methodology.
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