Patent Application
20080076080
For a further understanding of the nature and objects for the present invention, reference should be made to the following detailed description, taken in conjunction with the accompanying drawings, in which like elements are given the same or analogous reference numbers and wherein:
A cogeneration unit with flue gas recirculation can be continuously operated under Fresh Air mode for a long period with a competitive efficiency that is roughly comparable to the typical value for a conventional boiler. While keeping the total flow of flue gas that exits the stack virtually constant, an increase in flue gas recirculation rate yields less stack loss and reduces emissions. However, with the increase of the flue gas recirculation rate, the oxygen content to the inlet of duct burners can easily decrease to a level that causes excessive CO emission and result in combustion instability. To overcome this difficulty, a practical solution is to add a more reactive fuel, such as hydrogen, to the main fuel (typically natural gas). A system that utilizes a fuel blended with hydrogen in the combustion system, can be used to maintain an efficient and stable combustion in heat recovery steam generator. Such a system will also reduce emissions at these high flue gas recirculation rates. In addition, the use of hydrogen as part of the fuel blend, the greenhouse gas (CO2) production is reduced. Therefore, this solution can serve as a transition strategy to a carbon free energy system at some point in the future.
A hydrogen fuel blend combustion system is proposed to solve the problem of combustion instability and to improve the efficiency of a cogeneration system at a high flue gas recirculation rate. In this solution, the fresh air is mixed with a part of the total flue gas and then this mixture is recycled back to the inlet duct of Heat Recovery Steam Generator. The more reactive fuel, such as hydrogen (or hydrogen/CO), is blended with the primary fuel, or fuels, and then the blended fuel is injected into combustion chamber. In one embodiment, a stable and efficient combustion can be maintained when a large portion of flue gas is recycled, and the emissions (NOx and CO) are also reduced to the required regulation levels at the same time.
To improve the overall performance, it is critical to accurately control the fuel or oxygen-enriched air inlet flow. The important processing parameters, such as O2, CO, and NOx concentrations, and gas temperature, are linked to the performance. To solve this issue, a laser-based diagnostic technology, such as Tunable Diode Laser (TDL) sensors, can provide the non-intrusive in-situ fast response measurements of important gas species concentrations and gas temperature. The sensors are coupled with feedback control to accurately and timely adjust gas and fuel inlet flows, which can improve the overall performance of a cogeneration system at a high percentage flue gas recirculation.
A laser-based diagnostic technology, such as Tunable Diode Laser (TDL) sensor, can provide the non-intrusive in-situ fast response measurements of important gas species concentrations and gas temperature at different cross sections in the combustion chamber. The sensors are then coupled with feedback control to accurately and timely adjust the inlet flow rates of the hydrogen-blended fuel or oxygen-enriched air. The ability of monitoring key process parameters coupled with the feedback control of inlet flows plays an important role for maintaining an efficient and stable combustion with limited emissions at a high percentage flue gas recirculation in a cogeneration system.
Turning to
For a cogeneration unit that is operating in Gas Turbine mode (i.e. with the gas turbine on), primary gas turbine fuel 101 is injected into gas turbine 102 and the high temperature exhaust gas 103 exits the gas turbine 102. When operating in the Gas Turbine mode, the damper 104 remains open, and all the exhaust gas 103 is directed toward the heat recovery steam generator 111, where this heat content is exploited to produce steam. The damper 104 and by-pass stack 105 will be used during the switching period between Gas Turbine mode and Fresh Air mode (i.e. when the gas turbine is off). When operating in Fresh Air mode, fresh air 115 is fed into the heat recovery steam generator 111 and the damper 104 can prevent air from leaking into the gas turbine ducting.
Hydrogen fuel 108 may be blended with primary HRSG fuel 109, and then burned in duct burner 110. As the exhaust gas 112 exits the heat recovery steam generator 111, instead of being completely exhausted into main stack 114, a portion of the flue gas 113 is recycled back to displace an equivalent volume of fresh air 115.
The hydrogen (or hydrogen/CO) blended fuel 118 may go through a fan 119 to increase the pressure for better injection and mixing. After being burned in duct burner 110, the heated gas stream enters heat recovery steam generator 111, where it mixes with gas turbine exhaust gas 103. The velocity with which blended fuels 118 are introduced into the duct burner 110 depends on the structure of duct burner, the size and the geometry of the combustion zone of the heat recovery steam generator, the velocity and the temperature of combustion gases, and the structure of heat recovery steam generator.
For a cogeneration unit that is operating in Fresh Air mode (i.e. with the gas turbine off), the damper 104 will be closed. When operating in Fresh Air mode, fresh air 115 is fed into the heat recovery steam generator 111 and the damper 104 can prevent air from leaking into the gas turbine ducting. Fresh air 115, and the recirculated flue gas to be discussed below, may go through a fan 117 to increase the pressure as needed.
Hydrogen fuel 108 may be blended with primary HRSG fuel 109, and then burned in duct burner 110. As the exhaust gas 112 exits the heat recovery steam generator 111, instead of being completely exhausted into main stack 114, a portion of the flue gas 113 is recycled back to displace an equivalent volume of fresh air 115.
The hydrogen (or hydrogen/CO) blended fuel 118 may go through a fan 119 to increase the pressure for better injection and mixing. After being burned in duct burner 110, the heated gas stream enters heat recovery steam generator 111, where it mixes with gas turbine exhaust gas 103. The velocity with which blended fuels 118 are introduced into the duct burner 110 depends on the structure of duct burner, the size and the geometry of the combustion zone of the heat recovery steam generator, the velocity and the temperature of combustion gases, and the structure of heat recovery steam generator.
Shown in
The laser launcher 202 and laser receiver 204 are mounted at the downstream of duct burners 110 on opposite side walls of combustion zone of the heat recovery steam generator 111. To have improved control of the combustion process, one preferred location of monitoring gas species concentrations is close to the end of the flame 201. At the downstream of flame 201, the combustion gases start to mix with the surrounding extra air/flue gas to achieve a uniform distribution of gas species concentrations and temperature as the combustion gases exit the combustion zone of the heat recovery steam generator 111 and enter the heat transfer sections of the heat recovery steam generator.
The laser beam 205 is transported to the launcher module 202 by fiber optic cable 207. The laser beams 203 are multiplexed to monitor gas species concentrations and gas temperature for different rows of duct burner 110. This may require different sets of launcher 202 and receiver 204 modules mounted on the opposite side of the combustion zone of the heat recovery steam generator 111. However, only one signal laser and acquisition system 205 is required. The beams 203 are launched across the combustion zone of the heat recovery steam generator 111 and collected in the receiver module 204 at the opposite side. The resulting measurement provides a path averaged concentration and/or temperature of the gas volume that the laser beam 203 intercepts. The signal is collected in the data acquisition unit 205 where the resulting measured laser beam attenuation can be related to the concentration of a resonant absorption transition. The measured process parameters are sent to a control system 206 to perform the control of the inlet flow of the hydrogen-blended fuel 108,109 or oxygen-enriched air 119. As used within this application, oxygen-enriched air contains greater than atmospheric concentrations of oxygen.
The monitored gas species include CO, H2O, and O2. By monitoring O2 and CO, the NO can also be indirectly monitored to some extent. The combustion gas temperature is also measured. When multiple water lines are used, the non-uniformity of gas temperature along the laser path 203 can also be evaluated by comparing the temperatures calculated from each water line. If the gas temperature is uniform along the laser path 203 in the combustion zone of heat recovery steam generator 111, the calculated temperatures from all water lines will be equal.
For the lasers generating multiple water lines, two options are available. One option is to use different lasers and another option is to use one sweeping laser.
A cross section 300 of duct burner 110, as it is positioned within the transition duct between gas turbine 102 and heat recovery steam generator 111 is shown in
As shown in Table 1, with the increase of the percentage of the recirculated flue gas, the thermal efficiency of the heat recovery steam generator increases. Simultaneously, the oxygen content to the burner decreases with an increase of flue gas recirculation rate. When a hydrogen-blended combustion system is used, a stable and efficient combustion can be maintained even if the oxygen content of the mixed gas of air/flue gas 107 at the upstream of the burners drops to a level that is not acceptable for a stable combustion. The last three rows of Table 1, generally represent cases in which a hydrogen-blended combustion system may be needed. The percentages of the blended hydrogen fuel depend on the oxygen content of the mixed gas of air/flue gas 107 at the upstream of the burners and several other factors (such as the structure of duct burner, the size and the geometries of the combustion chamber, the velocity and the temperature of combustion gases). It is anticipated that a hydrogen fuel ratio of up to 20% is desirable for this application.
This application claims the benefit of U.S. Provisional Application No. 60/826,645, filed Sep. 22, 2006, the entire contents of which are incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 60826645 | Sep 2006 | US |
