Patent Publication Number: US-2015075170-A1

Title: Method and system for augmenting the detection reliability of secondary flame detectors in a gas turbine

Description:
BACKGROUND OF THE INVENTION 
     The subject matter disclosed herein generally relates to methods and systems for flame detection in gas turbines, and more particularly to methods and systems for augmenting the detection reliability of secondary flame detectors in a gas turbine. 
     Gas turbine systems are widely utilized in fields such as power generation. A conventional gas turbine system includes a compressor, a combustor, and a turbine. In a conventional gas turbine system, compressed air is provided from the compressor to the combustor. The air entering the combustor is mixed with fuel and combusted. Hot gases of combustion flow from the combustor to the turbine to drive the gas turbine system and generate power. 
     In recent years, the regulatory requirements for low emissions from gas turbines have imposed strict limits on nitrous oxide emissions in power generating equipment. As requirements for gas turbine system emissions have become more stringent, one approach to meeting such requirements is to utilize lean fuel and air mixtures in a fully premixed operations mode in the combustor, to reduce emissions of, for example, NOx and CO. These combustors are known in the art as Dry Low NOx (DLN) combustion systems. These combustors typically include a plurality of primary nozzles which are ignited for low load and mid load operations of the combustor. During fully premixed operations, the primary nozzles supply fuel to feed a secondary flame. The primary nozzles typically surround a secondary nozzle that is utilized for mid load up to fully premixed mode. 
     DLN combustion systems typically use both a pre-mix or primary zone and a secondary zone. Reduced temperature combustion takes place in the secondary zone as a direct result of the enhanced air fuel mixing. The combustion takes place only in the secondary zone at base load, then in either or both combustion zones on a strict start-up and shut-down schedule in order to avoid hardware damage. 
     To control flame presence in the proper zone or zones, one must sense the flame independently in either zone. Typically, flame sensors continuously sense the presence of infrared, visible, ultraviolet or some combination of these three wavelengths of flame radiation (hereinafter sometimes collectively referenced as “light” radiation), and then announce that presence to a control system. 
     With some DLN systems, combustion mode transfer requires recognition and/or confirmation of the flame by the secondary flame detector. In some cases, these flame detectors may not detect flames due to fogging or damage to the optics. Failure to detect flames may result in a failed transfer during load and/or mode changes and after start, such as after water washing. Failed transfers results in trips, shutdowns, and/or continuous operation at part load. 
     BRIEF DESCRIPTION OF THE INVENTION 
     The disclosure provides a solution to the problem of flame detector reliability in detecting a flame out condition in a secondary combustion zone of a gas turbine system, and mitigating “false trips”. 
     In accordance with one exemplary non-limiting embodiment, the invention relates to a method for operating a gas turbine combustion system including the steps of calculating a set of modeled parameters expected when there is a flame in the secondary combustion zone, measuring a set of measured parameters, and generating a flame validation signal based on the set of measured parameters and the set of modeled parameters. 
     In another embodiment, a system for operating a gas turbine combustion system is provided. The system includes a subsystem that calculates a set of modeled parameters expected when there is a flame in the secondary combustion zone. The system also includes a subsystem that measures a set of measured parameters, and a subsystem that generates a flame validation signal based on the set of measured parameters and the set of modeled parameters. 
     In another embodiment, a system is provided having a compressor, a combustor having a secondary combustion zone, and a turbine. The system includes a subsystem that calculates a set of modeled parameters expected when there is a flame in the secondary combustion zone, and a subsystem that measures a set of measured parameters. A subsystem that generates a flame validation signal based on the set of measured parameters and the set of modeled parameters is also included. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Other features and advantages of the present invention will be apparent from the following more detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings which illustrate, by way of example, the principles of certain aspects of the invention. 
         FIG. 1  is a schematic of a gas turbine system. 
         FIG. 2  is a block diagram representation of a system for generating a flame detection signal. 
         FIG. 3  is a flow chart of an exemplary method for detecting a flame in a secondary combustion zone. 
         FIG. 4  is a flow chart of an exemplary method for detecting a flame in a secondary combustion zone. 
         FIG. 5  is a flow chart of a method for transferring a gas turbine from a lean-lean operating mode to a premix operating mode. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     As summarized above, embodiments of the present invention encompass systems and method for operating a gas turbine system by generating a flame validation signal based on comparing a set of modeled parameters to a set of measured parameters. 
     Referring now to the drawings,  FIG. 1  illustrates a simplified, schematic depiction of one embodiment of a gas turbine system  100 . In general, the gas turbine system  100  may include a compressor  105 , one or more combustor(s)  110  and a turbine  115  drivingly coupled to the compressor  105 . During operation of the gas turbine system  100 , the compressor  105  supplies compressed air to the combustor(s)  110 . The compressed air is mixed with fuel and burned within the combustor(s)  110 . Hot gases of combustion flow from the combustor(s)  110  to the turbine  115  in order to turn the turbine  115  and generate work, for example, by driving a generator  120 . The combustor(s)  110  may comprise a can combustor having a row of individual combustor cans (not shown) in which combustion gases are separately generated and collectively discharged. 
     Additionally, the gas turbine system  100  may include an inlet duct  125  configured to feed ambient air and possibly injected water to the compressor  105 . The inlet duct  125  may have ducts, filters, screens and/or sound absorbing devices that contribute to a pressure loss of ambient air flowing through the inlet duct  125  and into one or more inlet guide vanes  130  of the compressor  105 . The gas turbine system  100  may include a heat recovery steam generator system (HRSG  131 ). The HRSG  131  is an energy recovery heat exchanger that recovers heat from a hot gas stream. It produces steam that can be used in a process (cogeneration) or used to drive a steam turbine (not shown). Moreover, the gas turbine system  100  may include an exhaust duct  135  configured to direct combustion gases from the outlet of the turbine  115 . The exhaust duct  135  may include sound absorbing materials and emission control devices. 
     Moreover, the gas turbine system  100  may also include a controller  140 . In general, the controller  140  may comprise any suitable processing unit (e.g., a computer or other computing device) capable of functioning as described herein. For example, in several embodiments, the controller  140  may comprise a General Electric Company SPEEDTRONIC™ Gas Turbine Control System. The controller  140  may generally include one or more processors that execute programs, such as computer readable instructions stored in the controller&#39;s memory, to control the operation of the gas turbine system  100  using sensor inputs and instructions from human operators. For example, the programs executed by the controller  140  may include scheduling algorithms for regulating fuel flow to the combustor(s)  110 . As another example, the commands generated by the controller  140  may cause actuators on the gas turbine to, for example, adjust valves between the fuel supply and the combustor(s)  110  that regulate the flow, fuel splits and type of fuel flowing to the combustor(s)  110 , adjust the angle of the inlet guide vanes  130  of the compressor  105 , and/or to activate other control settings for the gas turbine system  100 . 
     The scheduling algorithms may enable the controller  140  to maintain, for example, the NOx and CO emissions in the turbine exhaust to within certain predefined emission limits, and to maintain the combustor firing temperature to within predefined temperature limits. Thus, it should be appreciated that the scheduling algorithms may utilize various operating parameters as inputs. The controller  140  may then apply the algorithms to schedule the gas turbine system  100  (e.g., to set desired speed to support load requirement, turbine exhaust temperatures and combustor fuel splits) so as to satisfy performance objectives while complying with operability boundaries of the gas turbine system  100 . 
     Referring still to  FIG. 1 , a fuel control system  145  may be configured to regulate the fuel flowing from a fuel supply to the combustor(s)  110 , the split between the fuel flowing into primary and secondary fuel nozzles, and/or the amount of fuel mixed with secondary air flowing into the combustion chamber of the combustor(s)  110 . The fuel control system  145  may also be adapted to select the type of fuel for the combustor(s)  110 . It should be appreciated that the fuel control system  145  may be configured as a separate unit or may comprise a component of the controller  140 . 
     Additionally, in several embodiments, operation of the gas turbine system  100  may be monitored by a plurality of sensors  150  detecting various operating parameters of the gas turbine system  100 , the generator  120  and/or the ambient environment. In many instances, a plurality of sensors  150  may be utilized to measure the same operating parameters. For example, a plurality of sensors  150  (redundant temperature sensors) may monitor the ambient air temperature, compressor inlet temperature, compressor discharge temperature, turbine exhaust gas temperature, fuel temperature and/or other temperatures of the fluids flowing through the gas turbine system  100 . Similarly, a plurality of sensors  150  (redundant pressure sensors) may monitor ambient air pressure and static and dynamic pressure levels at the compressor inlet and outlet, at the turbine exhaust and at other locations at which fluids are flowing through the gas turbine system  100 . Moreover, the plurality of sensors  150  may include redundant humidity sensors (e.g., wet and dry bulb thermometers) to measure ambient specific humidity within the inlet duct  125  of the compressor  105 . Further, the plurality of sensors  150  may also comprise flow sensors (e.g., fuel flow sensors, air flow sensors, inlet bleed heat flow sensors, other mass flow sensors and/or the like), speed sensors (e.g., turbine shaft speed sensors), flame detector sensors, valve position sensors, guide vane angle sensors and/or the like that sense various other parameters pertinent to the operation of the gas turbine system  100 . 
     As indicated above, in several embodiments of the present subject matter, one or more operating parameters of the compressor  105  (e.g., compressor mass flow, compressor pressure ratio and/or the like) may be monitored by the controller  140 . Thus, a plurality of sensors  150  may be disposed at various locations within and/or adjacent to the compressor  105  to allow such operating parameters to be monitored. For example, the plurality of sensors  150  may include one or more pressure sensors that may be disposed within and/or adjacent to the compressor inlet and compressor outlet to permit the compressor pressure ratio to be monitored. Similarly, the plurality of sensors  150  may include one or more flow sensors that may be disposed within and/or adjacent to the compressor  105  to allow the mass flow through the compressor  105  to be measured. 
     It should also be appreciated that, as used herein, the term “parameter” refers to an item(s) that may be used to define the operating conditions of the gas turbine system  100 , such as temperatures, pressures, air flows, gas flows, gas concentrations, turbine speeds, humidity and the like at defined locations in the gas turbine system  100 . Some parameters may be measured (e.g., using sensors  150 ) and, thus, may be directly known. Other parameters may be estimated or modeled using the gas turbine model and, thus, may be indirectly known. The measured and/or modeled parameters may generally be used to represent a given turbine operating state. 
     Current gas turbine combustion systems producing low nitrous oxide emissions typically use both a pre-mix or primary zone and a secondary zone where reduced temperature combustion takes place as a direct result of the enhanced air fuel mixing. The combustion takes place only in the secondary zone at base load, then in either or both combustion zones on a strict start-up and shut-down schedule in order to avoid hardware damage. To control flame presence in the proper zone or zones, one must sense the flame independently in either zone. To sense the flame in the primary and secondary combustion zone, the combustor(s)  110  may be provided with a primary flame detection sensor  155  and a secondary flame detection sensor  160 . Typically, primary flame detection sensor  155  and secondary flame detection sensor  160  continuously sense the presence of light radiation, and then announce that presence to a control system which then acts immediately when the flame improperly appears in either combustion zone. The primary flame detection sensor  155  and the secondary flame detection sensor  160  must be physically located some distance away from the intense heat generated by the combustion chambers while retaining high sensitivity to the generated radiation. 
     Illustrated in  FIG. 2  is a high-level block diagram of a system for generating a flame detection signal (SGFDS)  200 . The SGFDS  200  includes a modeling subsystem  205  that calculates a set of modeled parameters expected when there is a flame in the secondary combustion zone. The modeling subsystem  205  may comprise an adaptive real-time engine simulation (ARES) model configured to model electronically, in real-time, several operating parameters of the gas turbine system  100 . As shown in  FIG. 1 , the gas turbine system  100  has a set of observable parameters that are herein referred to as ARES inputs  210 . The ARES inputs  210  may be directly measured by sensors  150  and may include (without limitation): ambient conditions, such as the ambient air pressure (PAMB) and ambient air temperature (TAMB), inlet pressure differential (DP-inlet) (i.e., the pressure differential between the ambient air pressure and the pressure of the air exiting the inlet duct  125  and entering the compressor  105 ), exhaust pressure differential (DP-exhaust) (i.e., the pressure differential between the ambient air pressure and the pressure of the exhaust gases flowing through the exhaust duct  135 ), specific humidity of the ambient air (SPHUM), compressor inlet temperature (CTIM), angle of the inlet guide vanes  130  (IGV), inlet bleed heat flow (IBH) (i.e., the percentage of the compressor flow redirected to the compressor inlet), flow rate of the fuel supplied to the combustor(s)  110  (W-FUEL), temperature of the fuel (T-FUEL), rotational speed of the turbine shaft (SPEED), effective area of the stage one nozzle of the turbine  115  (S 1 NA) and power factor of the generator  120  (PFACT), among others. 
     The listed ARES inputs  210  are exemplary, and are provided merely to illustrate one example of sensed inputs that may be collected. Thus, it should be appreciated that the specific ARES inputs  210  of the modeling subsystem  205  may vary depending on, for example, the type of controller  140  used, the specific modeling subsystem  205  applied and/or the sensors  150  available at a particular gas turbine installation. In other words, it should also be appreciated that the term “ARES” does not imply or require that each and every one of the measured parameters described above must be input into the gas turbine model disclosed herein or that any such modeling subsystem  205  must have these inputs. Thus, the ARES inputs  210  may only include some of the measured parameters described above and/or may include other measured operating parameters of the gas turbine system  100 . The term ARES inputs  210  merely indicates that, for the particular embodiment of the modeling subsystem  205  disclosed herein, these inputs may be taken from measurements of actual turbine conditions and may be applied as inputs to the modeling subsystem  205 . 
     As shown in  FIG. 2 , the ARES inputs  210  may be applied by the modeling subsystem  205  to generate modeled output values  215  corresponding to predicted operating parameters of the gas turbine system  100 . For example, modeled output values may include modeled turbine exhaust temperature (TTXM mod ), modeled compressor discharge pressure (CPD mod ), and modeled expected turbine torque (τ mod ), among others. The modeled output values  215  may be calculated based on the assumption that there is a flame in the secondary combustion zone. The modeled output values  215  are applied as inputs to a flame detection logic module  220 . The SGFDS  200  also includes a measurement subsystem  221  that measures and provides measured inputs  225 . Measured inputs  225  may include measurements from combustion dynamics monitoring probes (CDM), turbine exhaust temperatures (TTXM), fuel stroke reference command (FSR), compressor discharge pressure (CPD), swirl chart logic and measurements from gas pressure transmitters (FPG 2 ), among others. The flame detection logic module  220  generates a flame validation signal  230  based on the measured parameters and the modeled parameters. The flame validation signal  230  indicates if the flame is on or off. 
     Illustrated in  FIG. 3  is a flow chart of an exemplary method  300  of generating a flame detection signal in a secondary combustion zone. 
     In this example, in step  305 , the method  300  models the turbine torque and provides a modeled turbine torque value TTm. The modeled turbine torque value is modeled by the modeling subsystem  205  using ARES inputs  210 . 
     In step  310 , the method  300  measures the actual turbine torque (TTa). The actual turbine torque TTa may be derived from measurements of current transformers (CT) and potential transformers (PT) associated with the generator  120 . Compressor shaft acceleration measurements (TNHA) may be used to correct real power during grid transients using a TNHA based transient inertia model. 
     In step  315 , the method  300  determines whether the difference between the modeled turbine torque TTm and the actual turbine torque TTa is greater than or equal to a predetermined limit. 
     If the difference between the modeled turbine torque and the actual turbine torque is greater than or equal to the predetermined limit, the method proceeds to the next step  320  that generates a loss of flame signal. Alternately, if the difference between the modeled turbine torque and the actual turbine torque is less than the predetermined limit, the method proceeds to the next step  325  that generates a flame on signal. 
     Illustrated in  FIG. 4  is a flow chart of an exemplary method  400  for generating a flame detection signal in a secondary combustion zone. 
     In step  405 , the method  400  models the expected exhaust temperature TTXMm based on no fuel consumption. Modeling of the expected exhaust temperature TTXMm is accomplished using the ARES inputs  210  and the modeling subsystem  205 . 
     In step  410 , the method  400  measures the actual turbine exhaust temperature TTXMa. 
     In step  415 , the method  400  determines if the difference between the modeled exhaust temperature TTXMm and the actual exhaust temperature TTXMa is greater than or equal to a predetermined limit. This step may take place in the flame detection logic module  220 . 
     If the difference between the modeled exhaust temperature TTXMm and the actual exhaust temperature TTXMa is greater than or equal to the predetermined limit, the method proceeds to the next step  420  that generates a loss of flame signal. Alternately, if the difference between the modeled exhaust temperature TTXMm and the actual exhaust temperature TTXMa is less than the predetermined limit, the method proceeds to the next step  425  that generates a flame on signal. 
     Other modeled and actual parameters may be used to generate a flame validation signal  230  or to indicate a loss of flame. 
     For example, a plurality of differential pressure transducers may be added to a combustion dynamics monitoring system. One may measure the combustion chamber pressure in the combustor(s)  110  relative to compressor discharge pressure. If the measured differential pressure is not greater than the minimum expected value based on load, one may count the combustion chamber as not having a flame. 
     Another way to indicate a loss of flame signal is to compare a model based value of active power derived from the modeling subsystem  205  against a sensor based active power. The sensor based active power may be derived from a high speed PGEN board (a steam turbine unload balance controller used for large steam turbine power load unbalance function). If the sensor based active power is less than the model based value of active power, then the system may generate a flame out signal. 
     The flame detection methodology set out herein may be used to detect a flame during startup as a pre-condition for continuing the startup process. One may use the temperature difference between the compressor discharge temperature (CTD) and the combustion reference temperature (C_CRT) that is an established reference value. Standard flow rate algorithms may be used to account for residual heat stored in the hot gas path. Spread algorithms (at a higher level) may be used to account for scenarios where multiple combustion chambers are flamed out. 
     In another example, one may use a spread algorithm to detect limited flame out. One may also use a compressor discharge temperature to exhaust temperature algorithm with flow compensation to detect bulk flame out. 
     Illustrated in  FIG. 5  is a flow chart of a method  500  for transferring a gas turbine from a lean-lean operating mode to a premix operating mode. 
     In step  505 , the method  500  sets a counter or timer to zero. 
     In step  510 , the method  500  attempts a transfer to premix mode. 
     In step  515 , the method  500  adjusts the secondary fuel flow valve. 
     In step  520 , the method determines whether a flame has been detected. The indication of flame detection is based on the operation of flame detection logic module  220  that compares the modeled output values  215  to the measured inputs  225  and provides the flame validation signal  230 . 
     In step  525 , if a flame is detected, then the method  500  transfers the gas turbine to a premix operating mode. 
     In step  530 , the method  500  continues the gas turbine operation in the premix operating mode. 
     In step  535 , if a flame has not been detected, the method  500  adds an increment to the counter or timer N so that N=N+1. 
     In step  540 , the method  500  determines if the counter is below an established threshold (e.g. N≦3). If the counter is below the established threshold, the method  500  adjusts the secondary valve (step  515 ) and tests again to determine if there is a flame. 
     If the counter exceeds the predetermined threshold (e.g. N=4), then in step  545  the method  500  alerts the operator to make a decision while still maintaining the gas turbine system  100  in the lean-lean mode. 
     Flame detection may be used to detect total loss of flame during operation to account for the possibility that all combustors flame out at the same time and no high exhaust spread is apparent. Additionally, flame detection may be used to detect flame on condition during startup as a pre-condition for continuing the start process. Flame detection may also be used to detect flame off condition during shutdown to determine the point at which it is necessary to close the valves. 
     Where the definition of terms departs from the commonly used meaning of the term, applicants intend to utilize the definitions provided below, unless specifically indicated. 
     The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. Where the definition of terms departs from the commonly used meaning of the term, applicants intend to utilize the definitions provided herein, unless specifically indicated. The singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be understood that, although the terms first, second, etc. may be used to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. The term “and/or” includes any, and all, combinations of one or more of the associated listed items. The phrases “coupled to” and “coupled with” contemplates direct or indirect coupling. 
     This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements.