TWI516671B - Optimization of gas turbine combustion systems low load performance on simple cycle and heat recovery steam generator applications - Google Patents

Description

Optimization of low load performance for gas turbine combustion systems in simple cycle and waste heat recovery steam generator applications Cross-reference to related applications

This application is part of a continuation of US Application No. 13/542,222 filed on July 5, 2012, and the US application Serial No. 13/542,222 filed on May 8, 2009, filed on Serial No. 12/463,060 Part of the US application is a continuation case. This application also claims the benefit of US Application No. 61/601,876 filed on Feb. 22, 2012. The contents of U.S. Application Serial No. 12/463, 060, U.S. Application Serial No. 13/542,222, and U.S. Application Serial No. 61/601, 876

The present invention relates to an automated system for sensing the operating conditions of a combustion system and making pre-set adjustments to achieve the desired operation of the turbine in an optimized load range.

Lean oil premixed combustion systems have been deployed on subgrade gas turbine engines to reduce emissions such as NOx and CO. These systems have been successful and in some cases have produced emission levels at the lower end of the measurement capability, from about 1 part per million to 3 parts per million of NOx and CO. Although such systems are a significant benefit from the standpoint of emissions production, the operational envelopes of such systems are substantially reduced when compared to more conventional combustion systems. As a result, control of fuel conditions, distribution, and injection into the combustion zone has become a critical operating parameter and is the week Frequent adjustments are required when atmospheric conditions (such as temperature, humidity, and pressure) change. The readjustment of combustion fuel conditions, distribution, and injection is referred to as adjustment.

The controlled operation of a combustion system is typically manually set using one of the burner's operational control elements to produce an average operating condition. Such settings may be entered through a controller, as used herein, to refer to any device used to control the operation of a system. Examples include a decentralized control system (DCS), a fuel turbine controller, a programmable logic controller (PLC), communication with another controller, and/or direct communication to a standalone computer of a system.

These settings are satisfactory at setup, but within hours or days, conditions can change and result in unacceptable operation. The adjustment problem is any situation where any of the operating parameters of the system exceeds the acceptable limit. Examples include emissions deviations outside of the allowable limits, deviations in combustor dynamics outside the allowable limits, or any other adjustment event that requires adjustment of the operational control elements of a turbine. Other methods use a formula to predict emissions based on operational settings of the gas turbine and select a set point for fuel distribution and/or overall machine fuel/air ratio without modifying other control elements, such as fuel gas temperature. Still other methods employ a remote connection from one of the remote locations to one of the sites by adjusting the periodic re-adjustment adjustment. These methods do not allow continuous and timely changes, do not fully utilize actual kinetic characteristics and emissions data, or modify fuel distribution, fuel temperature, and/or other turbine control elements.

Another variable that affects lean oil premixed combustion systems is the fuel composition. Adequate changes in the fuel composition will result in a change in one of the waste heat releases of the lean premixed combustion system. This change can result in emissions deviations, unstable combustion procedures, or even flameout of the combustion system.

In recent years, power generation overload (even using F-class ignition temperature gas turbines) has resulted in many gas turbines in the installed gas turbine fleet operating in a cyclic mode to base load operation. This means that when the price of electricity is so low that the losses incurred during the night of operation far exceed the cost of opening the equipment every morning, many gas turbine operators are forced to shut down their equipment. All night. This procedure has an effect on the maintenance of the equipment, as each of the stop/open cycles results in a load cycle of one of the equipment.

To counter this situation, gas turbine operators are investigating ways to run their equipment overnight while incurring the smallest possible economic loss. One possible solution is to reduce the minimum load that a gas turbine can achieve while still maintaining an acceptable level of emissions. This method of operation is often referred to as "Turndown."

The "regulation ratio" has been used for many years in the power generation industry. Therefore, nothing directly related to this mode of operation is included as part of this patent. The novelty of the content used by the system controller to adjust the ECOMAX ^TM adjustment method in regulation when the ratio of the combustion system and incorporated into ECOMAX ^TM recirculating waste heat to reduce the combined lead of the low vapor flow and high temperature gas turbine exhaust gas recovery to generate steam Method of harmful effects on the HRSG. The system is also suitable for simple cycle operation; however, most simple cycle systems are applied to peak power generation and have a desired shutdown procedure in the operational plan.

Typically, when the gas turbine load is reduced, the HRSG steam flow is reduced and the gas turbine exhaust temperature is increased. This combination, together with the in-stage temperature-regulating flow capacity, typically produces an excessively high HRSG outlet steam temperature (steam turbine inlet steam temperature). In many cases, these vapor temperatures are close to material limits and can cause early component failure. At the other extreme, a steam conditioning/tempering system with sufficient condensate flow provides sufficient condensate to keep the superheated outlet temperature within specifications at the point of entry into a steam turbine; however, local overshoot can occur temperature. This over-temperature regulation typically results in direct condensate impact on the steam line downstream of the thermostat, resulting in excessive thermal fatigue in the pipe section immediately downstream of the heat exchanger/temperature regulator.

So far, efforts have focused primarily on manual (if it does happen) to modify the fuel-to-air (f/a) ratio of a gas turbine to maintain the HRSG design constraints that are met. However, factors such as ambient temperature changes, turbine component degradation, etc., may negate the f/a ratio of the gas turbine at low loads to ensure acceptable HRSG inlet conditions. Use instant One of the HRSG operational information is that the gas turbine's f/a provides an efficient means of maximizing the life of the HRSG component over automatic maneuvering and immediate gas turbine operational information.

It will be appreciated that manipulating the fuel-to-air ratio of a gas turbine will directly affect the "adjustment" of the engine, and therefore, any method used to accomplish this must be accompanied by another automated turbine control scheme to "re-adjust" the turbine as needed.

The erroneous operation of the combustion system manifests itself as an increase in pressure pulsation or combustion dynamics of the amplification. The pulsation can have sufficient force to damage the combustion system and significantly reduce the life of the combustion hardware. In addition, improper adjustment of the combustion system can result in emissions deviations and violation of emission permits. Therefore, one of the means for maintaining the stability of a lean premixed combustion system within an appropriate operational envelope on a regular or periodic basis is of great value and of industrial interest. In addition, one system operates to coordinate fuel composition modulation, fuel distribution, fuel gas inlet temperature, and/or overall machine f/a ratio by utilizing near real-time data obtained from the turbine and HRSG sensors ( HRSG inlet temperature and airflow) will be of significant value.

A system and method for optimizing the operation of a turbine and optimizing the mechanical life of a waste heat recovery steam generator is provided herein. A turbine controller, a sensor component for sensing operational parameters, and a control member for adjusting the operational control elements are provided. The controller is adapted to adjust the operation of the gas turbine in accordance with a pre-programming step in response to an operational priority selected by a user. These operational priorities preferably include the optimum waste heat recovery steam generator life.

The present invention provides a method for optimizing the fuel-to-air ratio of a gas turbine combustor toward mitigating the exhaustive conditions of the turbine to the expected life of a waste heat recovery steam generator (HRSG) system (especially at low load conditions) Controller and method of the period). The gas turbine consumption system is of the type having a sensor member for measuring operational parameters of the turbine and a control member for controlling various operational elements of the turbine. The operational parameters of the turbine received by the controller include combustor dynamics, turbine exhaust temperature (Total fuel/air ratio), turbine exhaust emissions, and various waste heat recovery steam generator (HRSG) steam conditions. The operational control elements may include a fuel gas blend ratio (ratio of non-line quality fuel gas to pipeline quality fuel gas), fuel distribution within the combustion system, fuel temperature, and turbine exhaust temperature. The turbine/power plant system can also include a distributed control system (DCS) in communication with the sensor components and the control components. The adjustment controller is typically connected to the turbine system through the DCS (but the adjustment controller can be directly connected to the gas turbine controller).

The adjustment controller operates by receiving material from the sensor components. The operational priority of the turbine is set within the controller and is typically performed from optimum NOx emissions, optimal power output, optimum combustor dynamics, optimum fuel gas blend ratio, and/or optimal HRSG lifetime. select. The data received from the turbine sensors is compared to the stored operating standards within the controller. The selected operational criteria are based on the set operational priority. A determination is made as to whether the turbine operation meets one of the operational criteria. In addition, in the case where the material does not have compliance, a determination is made again on the dominant adjustment criterion based on the pre-set operation priorities. Once the logic determination is made, the adjustment controller communicates with the operational control members via the DCS to perform a selected adjustment in one of the turbine operating parameters. The selected operational adjustment is based on the dominant adjustment criterion and has a predetermined fixed incremental value and a defined range of values. Each incremental change is entered during a time period set for one of the operational stability of the turbine to achieve operational stability. Once the time period has elapsed, operational data is again received from the turbine sensor components to determine if an additional incremental change is desired. In general, upon completion of the adjustments within the defined range, a further operational parameter adjustment is again selected based on the dominant adjustment criteria, and a further determination is made within a defined time period and within a set time period. Fixed incremental adjustment. The adjustment procedure is continued by the controller receiving the operational data to determine if the operation meets the operational criteria or if an additional incremental adjustment is required. The operating parameters adjusted by the adjustment controller are preferably the fuel/air ratio in the gas turbine, the burner fuel in the nozzles of the combustor The split stock, the fuel gas inlet temperature, and/or the fuel gas blend ratio.

It will be appreciated that when the plant operator selects the optimum HRSG life, the adjustment controller will first evaluate to mitigate the possible HRSG mechanical concerns and what changes, if any, will be made to the gas turbine f/a ratio and make such The changes needed. After this optimization procedure, the adjustment controller will use the standard parameters of the fuel split, fuel gas temperature and/or fuel gas composition, if desired (note: gas turbine f/a ratio is not an option) ) to adjust the gas turbine.

In a further aspect of the invention, the system performs one of the methods for determining the governing gas turbine combustion system adjustment scenario by using Boolean hierarchical logic and a plurality of levels of control settings.

In another aspect of the invention, the method is performed to automatically control the gas turbine inlet fuel temperature by automatically modifying the fuel gas temperature control set point within a distributed control system (DCS).

In yet another aspect of the invention, a method for automatically controlling a gas turbine inlet fuel temperature is defined by automatically modifying the fuel gas temperature control set point within the fuel gas temperature controller.

In another aspect of the invention, by using an external control device (such as, for example, present on the turbine controller for communication with the distributed control system (DCS), one of the MODBUS series or One of the Ethernet communication protocols (现有) is an existing gas turbine communication link to achieve a method for transmitting turbine control signals to a gas turbine controller.

In yet another aspect of the invention, a method for modifying a gas turbine combustion system is defined by a series of automatic adjustment settings via a user interface display, the user interface display utilizing a Boolean logic two state toggle switch to select The optimization criteria expected by the user. The method is preferably based on optimal combustion kinetics, optimum NOx emissions, optimum power, optimum heat recovery rate, optimum CO emissions, and optimal waste heat recovery steam generator (HRSG) life. The optimum gas turbine fuel blend ratio or the optimal gas turbine turndown ratio optimization criterion is defined whereby the two-state switching of the switch changes the magnitude of the burner dynamics control setting.

10‧‧‧Adjust controller/engine controller/controller

12‧‧‧Main user interface/interface display/optimal NOx emission switch/main user interface display/user interface/tuning interface

14‧‧‧Optimal NOx Emission/Optimal Power Switch/Switch/User Interface Two-State Switch/Corresponding Two-State Switch/Competitive Two-State Switch/Optimum NOx/Two-State Switch

16‧‧‧Optimal power/switch/user interface two-state switch/corresponding two-state switch/competitive two-state switch/two-state switch

17‧‧‧Optimal burner dynamics / optimal dynamics / switch / user interface Surface two-state switching switch / corresponding two-state switching switch / competitive two-state switching switch / two-state switching switch / optimal dynamic characteristics two-state switching

18‧‧‧Optimal fuel blend ratio/switch

19‧‧‧Best waste heat recovery steam generator life/switch

20‧‧‧Distributed control system

30‧‧‧Gas Turbine Controller/Engine Control/Adjustment Controller/Related Turbine Operating Parameters/Engine System

40‧‧‧Continuous Emission Monitoring System / Turbine Exhaust Emissions

50‧‧‧Continuous dynamics monitoring system/burner dynamics

60‧‧‧Fuel heating controller/fuel heating unit/fuel gas temperature controller/associated controller

70‧‧‧fuel blend ratio controller/fuel gas ratio controller/associated controller

80‧‧‧Waste heat recovery steam generator/waste heat recovery steam generator operating parameters/related waste heat recovery steam generator operating parameters

90‧‧‧Operating components/engine operating data/turbine systems

100‧‧‧Is emissions compliance?

102‧‧‧Whether the burner dynamics is at an acceptable level

104‧‧‧Steps

106‧‧‧ Dominant adjustment focus/dominance adjustment criteria/“true” dominance adjustment focus/adjustment focus

108‧‧‧Engine burner fuel split

110‧‧‧Adjustment issues

112‧‧‧Overall fuel/air ratio

114‧‧‧Adjustment issues

116‧‧‧fuel blend ratio

118‧‧‧ has sufficient operating margins (in contrast to alarm conditions)

120‧‧‧Related emission parameters/operational data/sensing operation data

122‧‧‧Fuel-to-air ratio/burner dynamics of the turbine controller/sensing operation data/operational data

124‧‧‧ Allowable adjustment of limits / adjustment limits / allowable limits

126‧‧‧ "True" Alert / "True" Logic Alert

130‧‧‧Steps/Classified "True" Alert / "True" Alert / "True" Adjustment Alert

134‧‧‧One of the best NOx preset limits / optimal NOx / adjustment limit

136‧‧‧One of the preset limits for optimal power/adjustment limit/optimal power

138‧‧‧One of the set limits of the best dynamic characteristics/optimal dynamics/adjustment limit/high level 2 δP's

140‧‧‧Preset limit/preset adjustment limit/adjustment limit/no optimal setting

142‧‧‧ Possible dominance adjustment issues

144‧‧‧Importance/Most important dominance adjustment focus/dominant adjustment focus/user defined level/dominance adjustment problem

148‧‧‧Special Bolling Logic/Brin Logic/Hard-coded Bolling Logic

150‧‧‧ steps

152‧‧‧Box/Best NOx/High NOx

154‧‧‧Box / Best Power

156‧‧‧Box/Best Dynamics/High Grade 2 δP's

158‧‧‧ square

160‧‧‧ square

162‧‧‧High Grade 2 δP's

164‧‧‧High-High Grade 2 δP's

166‧‧‧High-High-High Level 2 δP's

168‧‧‧NOx

170‧‧1 level δP's

172‧‧‧ Dominant adjustment focus

200‧‧‧ Actual burner dynamics data/burner dynamics

202‧‧‧Moving average of burner dynamics/average burner dynamics

204‧‧‧ Dynamic characteristics alarm limit value / dynamic characteristic alarm limit / dynamic characteristic limit

206‧‧‧ Burner fuel split adjustment parameters

210‧‧‧NOx emissions data/NOx emissions/NOx emission levels

212‧‧‧Adjustment limit/preset adjustment limit/preset limit/limit

214‧‧‧fuel share/fuel share value

220‧‧‧NOx adjustment limit/pre-set alarm level/alarm level/pre-set limit

222‧‧‧NOx level data/NOx emission data/NOx data/NOx emissions

224‧‧‧fuel share level/fuel share value/fuel share

230‧‧‧NOx emissions data/NOx emissions

232‧‧‧low emission limit/lower limit/limit/minimum

234‧‧‧ fuel share value

236‧‧‧Load control curve/load control curve value

E1‧‧‧ burner fuel split/event/first event/first adjustment event

E2‧‧‧Second event/event/second adjustment event

E3‧‧‧ Further events/incidents

Cycle time / set time T _A ‧‧‧

T _B ‧‧‧ time period/time

T _C ‧‧‧Time

The drawings illustrate the presently preferred forms for purposes of illustrating the invention as disclosed herein. It should be understood that the invention is not limited to the exact arrangements and instrumentalities shown in the drawings.

1 shows an illustrative embodiment of a schematic representation of a power plant communication system incorporating a gas turbine engine system, incorporating a gas turbine adjustment controller, and communicating with one of various components of the power plant DCS and the HRSG.

2 shows an exemplary embodiment of a functional flow diagram of one of the operations of adjusting a controller in accordance with the present invention.

3 shows an illustrative embodiment of a user interface display for selecting one of the optimized modes within the present invention.

Figure 4 shows an exemplary schematic diagram of the interconnection of various optimization mode settings.

Figure 5 shows an illustrative overview of one of the procedural steps for determining an triggered alert signal in accordance with the present invention.

Figure 6 shows an overview of an exemplary procedure for determining the allowable turbine adjustment parameters.

Figure 7 shows a further detailed exemplary procedure in accordance with one of the steps shown in Figure 6.

Figure 8 provides a further detailed illustrative diagram of one of the steps of the present invention for determining a dominant adjustment focus.

Figure 9 is a first exemplary schematic diagram showing the determination of the dominant adjustment focus of the system in the context of various alarm inputs to the present invention.

Figure 10 is a second exemplary schematic diagram showing one of the determinations of the dominant adjustment focus of the system in the context of various alarm inputs to the present invention.

Figure 11 is a third exemplary schematic diagram showing one of the determinations of the dominant adjustment focus of the system in the context of various alarm inputs to the present invention.

Figure 12 is a fourth exemplary schematic diagram showing the determination of the dominant adjustment focus of the system in the context of various alarm inputs to the present invention.

Figure 13 shows a first operational example of operational adjustment of a gas turbine engine system as contemplated by the present invention.

Figure 14 shows a second operational example of operational adjustment of a gas turbine engine system as contemplated by the present invention.

Figure 15 shows a third operational example of operational adjustment of a gas turbine engine system as contemplated by the present invention.

16 shows a fourth operational example of operational adjustment of a gas turbine engine system as contemplated by the present invention.

The present invention relates generally to systems and methods for adjusting the operation of a combustion turbine. In the illustrated embodiment, the systems and methods relate to automatic adjustment of combustion turbines, such as their combustion turbines for power generation. Those skilled in the art will appreciate that the teachings herein can be readily adapted to other types of combustion turbines. Therefore, the terms used herein are not intended to limit the embodiments of the invention. Rather, it will be understood that embodiments of the present invention are generally directed to the field of combustion turbines and, in particular, to systems, methods, and computer readable media for adjusting a combustion turbine.

1 is a communication diagram of one of the gas turbine engines (not shown) in which the adjustment controller 10 operates. A decentralized control system (DCS) 20 acts as a primary communication hub. As an alternative, the use of the gas turbine controller as one of the DCS power plants may also cause the adjustment controller 10 to communicate directly to the gas turbine controller 30. As a further alternative, the adjustment controller 10 can communicate directly with the gas turbine controller 30 regardless of whether the gas turbine controller 30 acts as a DCS. Most of the turbine control is performed through the DCS 20. One turbine control The controller 30 is in direct communication with the gas turbine and with the DCS 20. In the present invention, information related to turbine operation (e.g., turbine dynamics characteristics, turbine exhaust emissions, etc.) is directed to the adjustment controller 10 via the DCS 20. The adjustment controller 10 is comprised as a stand-alone PC for operation as a programmable logic controller (PLC). The adjustment controller 10 is preferably remote from a separate computer of the turbine controller 30 and typically does not communicate directly with the turbine controller 30 other than through the DCS 20. However, as mentioned above, the adjustment controller 10 can be configured to communicate directly with the gas turbine controller 30.

Referring now to Figures 1 and 2, the adjustment controller 10 is comprised as a stand-alone PC for operation as a programmable logic controller (PLC). The adjustment controller 10 is preferably in communication with the turbine controller 30 that is remote from a separate computer of the turbine controller 30. Signals from the adjustment controller 10 may also be communicated to the turbine controller 30 or system by using an external control device such as MODBUS serial or Ethernet protocol 存在 present on the system or added to the system. Other controls within.

The sensor components associated with the turbine receive relevant operational data. For example, turbine exhaust emissions readings are obtained from chimney emissions by being connected to one of the DCS Continuous Emissions Monitoring Systems (CEMS) 40. The kinetic characteristic pressure sensing probe located in the combustion zone of the turbine combustor is used to sense combustion dynamics. As shown, a continuous dynamics characteristic monitoring system (CDMS) 50 is provided and in communication with the DCS. The CDMS 50 preferably measures combustion dynamics using a directly mounted or waveguide connected pressure or light sensing probe. Another related operating parameter is the fuel gas temperature. Again, this temperature information is directed from the fuel heating controller 60 to the adjustment controller 10 via the DCS 20. Since portions of the adjustment operation may include adjusting the fuel temperature, there may be a two-way communication between the adjustment controller 10 and the fuel heating unit 60. The DCS 20 communicates with a fuel blending ratio controller 70 to adjust the ratio of pipeline quality gas to non-line quality gas (for subsequent consumption within the gas turbine). There is an inter-connect communication between the fuel blend ratio controller 70 and the adjustment controller 10 via the DCS 20. Finally, as part of the present invention, certain key operating parameters of the HRSG 80 are via the DCS 20. Send to the adjustment controller 30. If the adjustment controller 10 determines that the various parameters of the HRSG 80 are outside the allowable range, then the change in the gas turbine f/a ratio is transmitted through the DCS 20 from the trim controller 10 to the gas turbine controller 30.

Relevant operational data from the turbine and HRSG are collected several times per minute. This data collection allows for near real-time system adjustments. Most of the associated turbine and HRSG operational data are collected by the adjustment controller 10 in near real time. However, the turbine exhaust emission sensor components are typically received by the adjustment controller 10 with a 2 to 8 minute time lag from the current operating conditions. This delay is necessary for the adjustment controller 10 to receive and buffer relevant information for a similar time lag before making operational adjustment adjustments. This adjustment controller 10, which adjusts the adjustment time lag, ensures that all operations (including exhaust emissions) data represent a stable turbine operation before and after any adjustments have been made. Once the data is deemed stable, the adjustment controller 10 determines if there is a need to adjust one of the adjustment parameters. If no adjustment is needed, the adjustment controller 10 maintains the current adjustment and waits to receive the next data set. If a change is desired, the adjustment begins. First, compare the HRSG operational data with the mechanical limits of the HRSG components. If any of the HRSG mechanical limits are violated (or against the limits of such limits), the adjustment controller 10 will change the gas turbine f/a ratio to the turbine controller 30 via the DCS 20. Subsequently, if there are sufficient margins in the critical operating characteristics of the gas turbine (ie, exhaust emissions and combustor dynamics), the adjustment controller 10 can send a command (if applicable) to the fuel to gas ratio controller 70 (through the DCS) 20) To increase the ratio of non-pipeline quality gas to pipeline quality gas.

All decisions required to perform turbine adjustments within the adjustment controller 10 are performed. The adjustment operation begins by forming an "alarm" by receiving operational data other than the preset operational criteria. In order for the adjustment operation to be initiated, the alarm - and therefore the data anomaly - must last for a predetermined period of time.

An example of an adjustment adjustment is to vary the fuel nozzle pressure ratio to adjust combustion dynamics. In the case of higher ignition temperatures required to achieve greater flame temperatures and efficiencies, turbine combustors must release more energy in a given burner volume. Better exhaust emissions This is usually achieved by increasing the mixing rate of fuel and air upstream of the combustion reaction zone. This increased mixing rate is typically achieved by increasing the pressure drop at the discharge of the fuel nozzle. When the mixing rate is increased in the combustor, the turbulence generated by the combustion typically causes noise within the combustor and can result in the generation of sound waves. Typically, sound waves are generated when the sound waves of the combustion flame are coupled to the burner volume or the acoustic characteristics of the fuel system itself.

Sound waves can affect the internal pressure in the chamber. The rate at which fuel flows through the nozzle and the accompanying pressure drop decreases as the pressure near a fuel nozzle rises. Alternatively, a decrease in pressure near the nozzle will result in an increase in one of the fuel flows. In the event that one of the low fuel nozzle pressure drops allows the fuel flow to oscillate, a combustor can undergo an amplified pressure oscillation. To counter the pressure oscillations within the combustor, monitor combustion dynamics and modify the fuel to air ratio and fuel nozzle pressure ratio to reduce or eliminate undesirable changes in combustor pressure, thereby correcting an alarm condition or returning the combustion system to One of the combustion dynamics characteristics is acceptable.

As shown in FIG. 2, information received by the self-sensing member for HRSG operating parameters (80), combustor dynamics (50), turbine exhaust emissions (40), and other related turbine operating parameters (30) is transmitted through The DCS (20) leads to the adjustment controller (10). Then, compare these input values with the turbine's standard or target operating data. The stored operating criteria are based, at least in part, on the operational priority setting of the turbine. These priority settings are defined on the primary user interface 12 of the adjustment controller 10 and are graphically shown in FIG. Based on the priority setting, a series of adjustments are made to the operation of the turbine by the turbine controller 10 connected through the DCS 20. These adjustments are directed to the control member, including fuel heating unit 60 (Fig. 1), fuel blend ratio controller 70, and various other operating elements 90 of the turbine (Fig. 2).

The interface display 12 shown in Figure 3 is comprised of switches (each switch having an on/off indication). These switches allow the user to specify the desired adjustment priorities for the operation of the turbine. The switching operation priority includes optimal NOx emissions 14, optimum power 16, optimum combustor dynamics characteristics 17, optimum fuel blend ratio 18, and optimum HRSG lifetime 19. These switches Each of these is set by the user to adjust the preferred operation of the turbine. The adjustment controller has a function to operate within the priority set by the switch. Preferably, if both the optimal NOx vent switch 12 and the optimal power switch 14 are set to "on", the controller 10 will operate in an optimal NOx mode rather than an optimum power. Therefore, in order to operate in the optimum power mode, the optimum NOx drain switch 12 must be "off". The best kinetics 17 can be selected at any time. It is explicitly noted that other user interface two-state toggle switches (not shown) may be used, including, for example, optimal waste heat rate, optimal CO emissions, optimal waste heat recovery steam generator (HRSG) life, and optimum gas turbine fuel blending. Ratio, optimal gas turbine adjustment ratio capability and other parameters.

Figure 4 shows a graphical representation of the interconnection of interface display switches. As shown, switching one parameter "on" will change the alarm limit that is one level different from its "off" level. In the example shown in Figure 4, the alarm limit is shown to have both optimal NOx and optimum power in the "on" position and in the "off" position. Then, modify these points on the chart by selecting the best dynamics in the "on" or "off" position (indicated by the symbol δ throughout). The points shown on the graph of Figure 4 represent one exemplary setting based on the limits of the dynamics of the user's selected operational priority.

Returning to Figure 2, one representation of the logic flow of the decisions and calculations made within the adjustment controller 10 is shown. The adjustment controller 10 receives actual operating parameters of the turbine through the turbine controller 30, receives combustor dynamics through the CDMS 50, receives turbine exhaust emissions through the CEMS 40, and receives associated HRSG operating parameters 80. This sensor data is directed to the adjustment controller 10 via the DCS 20. The received sensor data is compared to the stored operating criteria to determine if the turbine operation meets the desired settings. The operational criteria are based on the pre-set operational priorities of the turbines defined by switches 14, 16, 17, 18, and 19 (FIG. 3) on the primary user interface display 12 of the adjustment controller 10.

Based on the pre-set operation priority, a hard-coded hierarchical Boolean logic method determines the dominant adjustment criterion based on the operational priority. According to this logic selection, the adjustment controller 10 is A fixed incremental adjustment value is applied for varying one of the operating parameters of the turbine within a maximum adjustment range (eg, high and low values). The adjustment changes are made in a consistent predetermined direction within a predetermined time increment and depend on the current dominance adjustment criteria. It is expected that no formulation or functional calculations will be made to determine the magnitude of the adjustment adjustment; rather, the adjustments will be incrementally adjusted, the direction of adjustment, the time span between adjustments, and adjustments for each parameter and for each adjustment criterion. The maximum range is stored in the adjustment controller 10.

As shown in FIG. 2, when the operator has not selected the optimal HRSG lifetime 19, the adjustment controller 10 determines if the emissions are compliant 100 and if the burner dynamics are at an acceptable level 102. If both are compliant with the set operating criteria, the adjustment controller 10 waits for a data set from the CEMS 40 or CDMS 50 and waits for other turbine operating data 90. If both are compliant with the set operating criteria and have sufficient operating margins and the optimum fuel blend ratio 18 is selected, the trim controller 10 will send a command to the fuel blend ratio controller 70 to increase non-pipeline quality. The ratio of gas to pipeline quality gas. If the received data does not meet the operating criteria, that is, above or below the alarm level, as in the case of step 104 of FIG. 2, the adjustment operation moves to first determine an adjustment step below the dominant adjustment focus 106. The logic adjustment of the turbine operation is defined by the governing adjustment criteria 106, based at least in part on the pre-set operational priorities set within the user interface 12, as will be discussed below with respect to FIG.

If the operator selects the optimal HRSG lifetime of 19, the first decision made by the adjustment controller is to evaluate one of the margins of the relevant HRSG parameters against the design limit (including but not limited to high pressure superheated outlet steam temperature, hot reheat outlet steam) The temperature, the saturation of the high pressure superheated steam reducer threshold (compared to the saturation temperature, the Fahrenheit temperature immediately downstream of the thermostat), the thermal reheat steam desuperheater threshold of the control saturation). These temperature margins are compared to the allowable margins as defined by the user. If the actual temperature margin is less than the allowable margin, the adjustment controller 10 will automatically adjust the f/a ratio 122 of the turbine controller. In this particular case, for an external reason (HRSG component life), the adjustment controller 10 has first adjusted the f/a ratio of the gas turbine. This change can adversely affect the current adjustment state of the gas turbine. Therefore, by adjustment The controller 10 performs a normal gas turbine adjustment scheme; however, the f/a ratio change to the turbine is not allowed. The remaining gas turbine adjustment schemes are defined below.

In a preferred operation, the adjustment controller 10 will first attempt to change the turbine combustor fuel split 108. The fuel split determines the distribution of fuel flow to the fuel nozzles in each combustor. It should be noted that although the current embodiment indicates the presence of two adjustable fuel circuits, this method can be used for one, two or more fuel circuits. If these adjustments do not resolve the adjustment problem and the operational data is not returned to meet the operational criteria, then a further adjustment is performed. In some cases or if the fuel split change is less effective in addressing high burner dynamics, the next incremental adjustment is one of the fuel gas temperature set points. In this adjustment step, the adjustment controller 10 sends a modified fuel gas inlet temperature signal to the DCS 20 that is directed to the fuel heating unit 60.

Referring again to FIG. 2, if the modified burner fuel split and/or fuel gas inlet temperature is not resolved, the adjustment controller 10 will then change the overall fuel/air ratio 112. This method makes changes to the turbine thermal cycle with a fixed incremental change over a predetermined amount of time. This step is intended to adjust (turn up or down) the exhaust gas temperature by adjusting the air to fuel ratio according to a predetermined standard control curve for turbine operation, which is maintained in the memory of the trim controller 10. If the change to the overall fuel/air ratio of the gas turbine does not resolve the adjustment problem 114 or if the optimal HRSG lifetime 19 is reached and there is an HRSG mechanical focus, the adjustment controller 10 will adjust the fuel blend ratio 116.

In the present invention, it is contemplated that all control changes directed by the adjustment controller 10 are fed back to the turbine system (30, 90), the fuel gas temperature controller 60, and the fuel blend ratio controller 70 via the DCS 20. However, the adjustment controller 10 can be configured to communicate directly with the turbine controller 30. These changes are implemented directly within or through the various controller components within the system. When the operational data is returned to the desired operational criteria, the adjustment settings are maintained by the adjustment controller in an appropriate position until an alarm is generated due to non-compliance data received through the DCS self-sensor component.

The magnitude of the adjustments that the self-adjusting controller 10 sends to the turbine controller 30 or associated controller (60, 70) components is preferably fixed. Therefore, such adjustments are not recalculated or optimized to a target without new information. These adjustments are part of an "open loop". Once initiated, the adjustments are incrementally moved to a preset maximum amount or a maximum amount within a specified range unless an intermediate adjustment causes the operational data to meet operational criteria. In most cases, when the full incremental range of an operational parameter is completed, the adjustment controller continues to move to the next operational parameter defined by the pre-set operational priority. The particular order of operational control elements is not fixed and can be determined by operational priority. The logic of the adjustment controller drives the operational control element adjustment based on a "find" table stored in the memory of the adjustment controller and a pre-set operation priority.

The adjustment controller preferably processes one operational parameter at a time. For example, the dominant adjustment criteria determine the first adjustment to be made. In the preferred embodiment discussed above, the fuel distribution/dividing parameters are first adjusted. As indicated in Figure 2, the fuel split of the fuel circuit 1 is first processed, followed by the splitting of the fuel circuit 2. Again, this method can be applied to any combustion system having one or more adjustable fuel circuits. When required, the fuel gas inlet temperature adjustment is typically followed by fuel split adjustment. Within each step, there is an incremental adjustment followed by a time lag to permit stabilization of the regulated turbine operation. After the time lag, if the current operational data analyzed by the adjustment controller indicates that the turbine operation remains outside the operational criteria, then an incremental adjustment is made within the step. Repeat this pattern for each step. In most cases, the adjustment controller continues to move to the next operating parameter only when one adjustment step is completed. It should be noted that if the critical turbine operating characteristics have sufficient operating margins (in contrast to the alarm condition) 118, then there is a more dynamic control loop whereby the adjustment controller 10 will directly increase the non-line quality gas blend ratio (through fuel blending) Ratio controller 70). The control method of this change control loop is equivalent to the method mentioned above for fuel split and turbine f/a ratio - a change is made in a predefined direction, a predefined amount in a predefined amount of time.

The adjustment controller preferably controls the combustion operation to maintain ambient temperature, humidity and pressure With appropriate adjustments in variable conditions, all variable conditions vary over time and have a significant impact on turbine operation. The adjustment controller can also maintain turbine adjustments during changes in the fuel composition. A change in the fuel composition can result in a change in the release of waste heat, which can result in unacceptable emissions, unstable combustion, or even flameout. The adjustment controller will adjust the fuel composition entering the turbine indirectly through a change in fuel blend ratio 116.

Another aspect of the fuel splitting within the combustor is directly related to having a series of outer nozzles (for the same type, controlled by an outer fuel split that affects the circumferential distribution of fuel within the outer fuel nozzle) in combination with a central nozzle ( A combustion system controlled by an internal/central fuel split for the same or a different type than the outer nozzle. Within this framework, the center nozzle can operate in a "rich" or "lean" fuel to air ratio compared to the f/a of the outer fuel nozzle. Most of the combustion adjustments keep the combustion system in a "poor center nozzle" or a "rich center nozzle" mode of operation. In some cases, better flame stability can be achieved with a "rich center nozzle" fuel split curve when compared to a "poor center nozzle"; however, this usually results in higher NOx emissions. . Therefore, particular attention is paid to a mixed fuel schedule whereby the combustion system utilizes a "poor center nozzle" fuel splitter row under higher load conditions (where flame stability is below a point of interest but NOx emissions are above a point of interest) The process is converted to a "rich center nozzle" fuel split schedule at lower load and ratio conditions (where flame stability is above a point of interest and NOx is below a point of interest). The system of the present invention determines which fuel split schedule (rich or lean center nozzle) is employed at each operating point (allowing the use of a mixed fuel split schedule) and adjusts the fuel split schedule in the appropriate direction ( Fuel circuit 1 split and fuel circuit 2 shares). Again, the changes made have a fixed magnitude in a fixed time interval.

In the absence of a central nozzle, another point regarding fuel splitting is directly related to having a series of outer nozzles (for the same or different types, controlled by an external fuel split that affects the circumferential distribution of fuel within the outer fuel nozzle) The combustion system. Within this framework, compared to the f/a of the remaining external fuel nozzles (referred to as primary circuit 1), these external nozzles (often referred to as secondary A subset of loop 1) can be operated in a "rich" or "lean" fuel to air ratio. Most of the combustion adjustments keep the combustion system in a "lean secondary circuit 1" or a "rich secondary circuit 1" circumferential fuel split mode of operation. In some cases, when compared with a "rich secondary circuit 1" fuel split curve, a better flame stability can be achieved with a "lean secondary circuit 1" fuel split curve; However, this can result in higher NOx emissions. Therefore, particular attention is paid to a mixed fuel schedule whereby a combustion system can utilize a "rich secondary circuit 1" fuel under higher load conditions (where flame stability is below a point of interest but NOx emissions are above a point of interest) The split schedule is converted to a "lean secondary loop 1" fuel split schedule at lower load and ratio conditions (where flame stability / CO is above a point of interest and NOx is below a point of interest). The system of the present invention determines which fuel splitting schedule (rich or lean secondary loop 1) is employed at each operating point (allowing the use of a mixed fuel split schedule) and adjusts the fuel splitter row in the appropriate direction Cheng (if applicable, fuel circuit 1 share and fuel circuit 2 shares). Again, the changes made have a fixed magnitude in a fixed time interval.

A further aspect of the fuel split is directed to fuel nozzles having one or more annular rings (for the same or different types, controlled by a circumferential fuel split that affects the circumferential distribution of fuel within each fuel nozzle) a combustion system whereby a second type of fuel split (if more than one annular fuel nozzle is present) is utilized, which is adjusted to the relative of each of the radially concentric fuel rings (circle 1, circle 2, etc.) (radial) amount of fuel. In this frame, compared to the f/a of the remaining ring of fuel nozzles (called main loop 1, main loop 2, etc.), each lap of the fuel nozzle (called the secondary loop 1, the secondary loop A subgroup of Circles 2, etc. can operate in a "rich" or "lean" fuel to air ratio. Most of the combustion adjustments keep the combustion system in a "lean secondary loop 1" or a "rich secondary loop 1" (and similar methods for loop 2, loop 3, etc.) circular fuel split mode of operation. In some cases, when compared with a "rich secondary loop 1" fuel split curve, you can use (circle 1 as an example) a "lean secondary loop 1" fuel split curve Better flame stability is achieved in this case; however, this can result in higher NOx emissions. Therefore, pay special attention A mixed fuel schedule whereby the combustion system can utilize a "rich secondary loop 1" fuel split strand under higher load conditions (where flame stability is below a point of interest but NOx emissions are above a point of interest) The process is converted to a "lean secondary loop 1" fuel split schedule at lower load and ratio conditions (where flame stability / CO is above a point of interest and NOx is below a point of interest). The system of the present invention determines which fuel split schedule (if applicable) is used for each revolution at each operating point (allowing the use of a mixed fuel split schedule) (rich or poor secondary loop 1, rich or Lean secondary loop 2, etc., and adjust the fuel split schedule in the appropriate direction (if applicable, fuel circuit 1 split and fuel loop 2 split). Again, the changes made have a fixed magnitude in a fixed time interval.

Figure 5 provides a schematic diagram detailing the framework for determining the dominant adjustment focus 106 (as contained in Figure 2). Future steps will be explained below with respect to Figure 8. First, the associated emissions parameter 120 and combustor dynamics 122 are received by the adjustment controller 10 from the CEMS 40 and CDMS 50, as detailed above. The associated emissions parameter 120 and combustor dynamics 122 are then compared to an allowable adjustment limit 124 that is also provided to the adjustment controller 10. The allowable adjustment limits are in the form of a preset range that can be adjusted using the adjustment interface 12 of FIG. 3 and determined according to the logic set forth below with respect to FIGS. 6 and 7. The output of this comparison is a series of "true" alarms 126 of various adjustment concerns, wherein an alarm condition is indicated if the sensed operational data 120, 122 is above or below one of the established alarm ranges as stated in the adjustment limit 124.

The alarm condition can have more than one level or level. For example, there may be a severity of change in the alert, such as: high "H"; high-high "HH"; high-high-high "HHH" and low "L"; low-low "L"; low - Low-low "LLL". In step 130, the "true" logic alert 126 is then ranked according to its importance level (eg, high-high "HH" alert is higher than high "H" alert, etc.). If more than one adjustment focus share the same level, then the adjustment focus will be ranked according to user preferences, as set forth below with respect to FIG. If only one "true" alert appears, this alert will be selected and used as the dominator The focus point 106 is adjusted to initiate the adjustment procedure set forth in FIG. However, the results of the procedure of FIG. 5 (ie, the ranked "true" alert 130) will be processed by the criteria determined by the user, as shown in FIG. 8, after which a fit adjustment focus 106 is confirmed.

In FIG. 6, a flow chart is provided to illustrate how to determine the allowable adjustment limit 124. Once determined, the adjustment limit 124 and the operational data 120, 122 are compared, as set forth above and shown in FIG. First, an internal hierarchy is used to compare user interface toggle switches 14, 16, 17 corresponding to their user interface toggle switches in the interface display 12 of FIG. 3 to allow passage of most significant binary states. The alarm constraint of the toggle switch. Therefore, depending on which switches are in the "on" position, different adjustment limits may be included in the adjustment limit 124. Depending on whether the corresponding two-state changeover switches 14, 16, 17 are in the "on" or "off" position, each of the optimal NOx, optimum power, and optimal dynamics has one of the preset limits. Set (represented by numbers 134, 136, and 138 in Figure 6). When the two-state toggle switch is not in the "on" position, there is also an internal setting of one of the preset limits 140 to be used.

The internal hierarchy will determine which of the adjustment limits should be prioritized in the event that the competitive toggle switch 14, 16 or 17 is in the "on" position. In this example, the hierarchy ranks the optimal NOx 14 above the optimal power 16. The optimal dynamics 17 can be selected at any time and will only change the adjustment limits of the other choices given, such as shown in FIG. If both the best NOx 14 and the best power 16 are in the "on" position, the optimum NOx 134 adjustment limit will be used. In addition, if the two-state changeover switch 17 is activated, the adjustment limit of the optimum dynamics characteristic 138 is utilized. If the user interface toggle switches 14, 16, 17 are inactive, the preset adjustment limit 140 is provided to allow the adjustment limit 124. All of the adjustment limits 134, 136, 138, and 140 that can be used to construct the allowable adjustment limits of the adjustment controller 10 can be developed by the end user and programmer and then preferably hard coded into the adjustment controller 10 for a given application. The method outlined in Figure 6 is intended to provide for the incorporation of several different user interface two-state toggle switches (such as the best described above with respect to Figure 3) One of the options for the HRSG Lifetime 19 option, whereby only a subset of the components are specifically outlined in the present invention.

Figure 7 shows a specific example of the flow chart of Figure 6 that is intended to determine a subset of the allowable adjustment limits of the system. In this example, the adjustment limits for high NOx, high NOx, high level 1 δP's, and high level 2 δP's will be determined based on the preset adjustment limits and the user's preferences. Various exemplary adjustment limits provided for optimal NOx 134, optimum power 136, optimal dynamics 138, and no optimal settings 140 are assigned corresponding values (shown in blocks 152, 154, 156, and 158, respectively). The change is intended to be a corresponding value for each criterion such that depending on which two-state toggle switches 14, 16 or 17, are selected, the limit 124 may be allowed to be different. By way of example, optimal NOx 134, 152 and optimum power 136, 154 give the limits of NOx, but also provide the limits of the kinetic characteristics to be used without the selection of optimal kinetics 138, 156. However, in the case of selecting the optimum dynamics characteristic two-state switching 17, the first-order δP's and 2 thus provided should be used instead of the values listed with respect to the optimum NOx 134, 152 and optimum powers 136, 154. The level δP's value is 156.

In this particular example, a two-state switch for the best NOx 14 and best dynamics 17 is selected, with the switch for the best power 16 in the "off" position. Therefore, the value of the optimum NOx for high NOx and high NOx 152 is provided. In addition, since the optimum kinetic characteristics 17 are also selected, the kinetic characteristic values of the high level δP's and the higher level δP's 138, 156 replace those δP's values provided with respect to the optimum NOx 134, 152. Accordingly, an allowable adjustment limit 124 is provided, as shown in block 160. These allowable adjustment limits 124 correspond to their allowable adjustment limits (as set forth above) used in Figure 5 to determine if the information from CEMS 40 and CDMS 50 is in an alarm state or normal operation.

8 shows a further schematic diagram of one of the procedures for incorporating a user's priority and receiving a "true" alert condition for determining the dominant adjustment focus 106. This adjustment focus 106 determines the turbine operation changes performed by the turbine controller 10, as shown in FIG.

First, a determination is made for all possible dominance adjustment questions 142. Such possible support The coordination adjustment issues include, but are not limited to, burner flameout, CO emissions, NOx emissions, Class 1 burner dynamics (Grade 1 δP's), Class 2 burner dynamics (Level 2 δP's), and HRSG mechanical life. The list of possible dominance adjustment questions 142 is determined by the user and the programmer and may be based on a number of factors or operational criteria. By way of example, Class 1 and Class 2 combustor dynamics δP's refer to combustion dynamics that occur over a particular range of frequencies, whereby the range of frequencies is different between Level 1 and Level 2. In fact, many combustion systems can have different acoustic resonant frequencies corresponding to levels 1 and 2, and these two dynamics can be mitigated with different turbine operating parameter changes for each different turbine and/or combustor configuration. Changes in the level. It should also be noted that some combustion systems may have "levels" (frequency ranges) with adjustable burner dynamics, with 1, 2 or more than 2 different "levels" (frequency ranges). The invention utilizes a system whereby one of the two different burner dynamics levels is mentioned. However, the invention is intended to be broadly applicable to any number of different kinetic characteristic frequency levels (from 0 to more than 2).

After determining the possible dominance adjustment problem 142, the questions are ranked in order of importance 144 according to the needs of the end user and the detrimental effects that each adjustment focus can have on the environment and/or turbine performance. The relative importance of each possible dominant adjustment focus can be different from each end user and will be different for each burner configuration. For example, some combustion systems will demonstrate extreme sensitivity to one of the burner dynamics characteristics such that normal daily operating parameter changes can cause a normal benign dynamics adjustment focus to become malignant in a very short amount of time. . In this case, one or both of the dominant dynamics adjustment points of interest (levels 1 and 2) can be promoted to priority 1 (most important). In the manner of the example of Figure 7, burner stalling is listed as the most important dominant adjustment point of interest 144. This rating is used to determine the dominant adjustment focus in the presence of multiple alerts with equal levels of severity. This ranking of dominant adjustment concerns 144 (from most important to least important) provides an overall framework in which a particular Boolean logic hierarchy 148 is formed. For example, assume that Level 1 and Level 2 δP's generally follow monotonic behavior with respect to perturbations in system operating parameters, a high-high The "HH" level 2 δP's alarm can be more important than the high "H" level 1 δP's alarm. In addition, in the example given for the Boolean logic level 148 in FIG. 8, high "H" NOx emissions are more important than high "H" level 2 kinetics. This means that if both the high "H" NOx and the high "H" level 2 kinetics are "in the alarm" (logic = true), then automatically adjust if there are no other alarms that are "true". The system will adjust for high "H" NOx, which is due to the high "H" NOx system dominance adjustment focus. Finally, it can be seen that the flameout classification is above the NOx emissions and both the flameout and NOx emissions are graded above the level 1 δP's. Therefore, if there is a high "H" alarm returned for all three categories, the flameout will be the dominant adjustment focus, followed by NOx emissions and then 1 level δP's. This Boolean logic level 148 will be compared to the "true" alarm 130 (as stated above with respect to Figure 5) that allows the adjustment limit 124 to be returned with the operational data 120, 122.

All "true" adjustment alerts 130 are provided to be ranked by severity (eg, HHH is higher than HH, etc.). Then, in step 150, the "true" adjustment alert 130 and the hardcoded Boolean logic hierarchy 148 are compared to determine which adjustment will become the "true" dominant adjustment focus 106. When this "true" dominant adjustment focus 106 is mitigated by operational changes, the dominant adjustment focus 106 is now the remainder of the automatic adjustment algorithm, as detailed in FIG.

Thus, when the critical HRSG operating characteristics indicate insufficient design margins for over-temperature (at steam outlet conditions) and/or over-temperature (at-stage heat reducers), the adjustment controller 10 can be configured to operate through The gas turbine exhaust temperature (turbine fuel air (f/a) ratio) optimizes the mechanical life of a waste heat recovery steam generator (HRSG). The HRSG will have a sensor for measuring the operating parameters of the boiler and the turbine has sensor components for measuring the operating parameters of the turbine, as discussed above. The HRSG operating parameters include high pressure and/or hot reheat steam outlet temperature and/or high pressure and/or heat reheat stage in the heat exchanger outlet temperature and pressure. These turbine operating parameters include combustor dynamics and turbine exhaust emissions. Using the logic applied above for the alarm level, the turbine controller will adjust various operational control elements as needed Factors such as fuel distribution and/or fuel to air (f/a) ratio.

A control system for optimizing the life of the HRSG is set forth above in Figure 1 and the control system (as appropriate) relies on communicating with the sensor components and control components listed above via the DCS 20 to control the operation of the turbine The turbine controller 10 of the control element. To maximize HRSG life based on other possible operational priorities, a user will select an operational priority for the HRSG and/or other turbine operations selected from the group consisting of: optimal NOx emissions, optimal power output , optimum burner dynamics, optimum HRSG life and/or optimum fuel blend ratio (ratio of non-line quality gas to pipeline quality gas). For example, an example will be provided in which the optimal HRSG lifetime 19 is selected in the control panel shown in Figure 3 such that the optimal HRSG lifetime is one of the possible operational priorities, among other selected priorities.

During operation, the turbine controller will receive operational data from the gas turbine sensor component and the HRSG sensor component. The operational data and stored operational criteria will be compared based on the selected operational priority. Using this comparison, the turbine controller will determine if both HRSG and gas turbine operation meets operational criteria.

Under conditions where the HRSG or gas turbine operating parameters are not within the allowable limits, the adjustment controller 10 will determine the dominance adjustment criteria for the HRSG and/or gas turbine non-compliance based on the pre-set operational priorities. In the event that the dominant adjustment criteria are determined, the turbine controller 10 will communicate with the selected operational control element to perform a selected adjustment in the operational control elements of the gas turbine. The operational control element can be a burner fuel distribution split within the nozzle of the combustor, a fuel gas inlet temperature, a fuel/air ratio within the turbine, and/or a gas fuel blend ratio (fuel composition). The adjustment of the operational control elements will be based on the dominance adjustment criteria and have a fixed increment value and a defined range, each incremental change being input for a time period set for one of the operational stability of the turbine.

The sensing procedure will be repeated in an open loop manner such that the turbine controller will immediately receive feedback from the HRSG and gas turbine sensor components after a set period of time has elapsed. Further information on the parameters is made to determine if an additional incremental change is desired. If additional adjustments are required, further incremental adjustments to the operational control elements will be made within a defined range. Under the condition that the available adjustment range for a particular control element is exhausted, the adjustment controller 10 will select a further operational control element adjustment based on the dominant adjustment criteria, the further selected adjustment having a fixed increment value and a defined range, wherein Each incremental adjustment is made within a set period of time sufficient for the turbine to achieve operational stability. This sensing and adjustment (if needed) procedure will continue during the operation of the turbine and HRSG.

In one embodiment, the stored operational data can be used to program the system such that the mechanical life of an HRSG is optimized in an adjustment procedure by first adjusting the fuel to air ratio of the gas turbine in increments. The HRSG hot gas inlet conditions are varied to provide a sufficient design margin in key HRSG operating parameters (ie, to reduce or increase the temperature of the hot gas inlet). This adjustment can then be continued as needed to produce one of these changes to the f/a ratio of the turbine. For example, the HRSG may be provided with sensor components for measuring operational parameters of the associated boiler, including high pressure and/or hot reheat outlet steam temperatures and high pressure and/or thermal reheat stage internal heat exchanger outlet temperatures and pressure. The gas turbine will also have sensor components for measuring the operating parameters of the turbine (including the chimney emissions and combustion dynamics of the turbine), as well as various operational elements of the turbine (including fuel distribution and/or fuel temperature and/or fuel blending). Control components for combination and/or fuel to air ratio. Optionally, the adjustment controller 10, various sensor components, and control components can be directly connected or connected via a distributed control system (DCS). The control system may also be provided with means for setting operational priorities selected from the group consisting of: (such as the group shown in Figure 3 discussed above) for turbine operation: optimal NOx emissions, most Good power output, optimum burner dynamics, optimum fuel blend ratio and/or optimum HRSG life. Using this adjustment system, use the methods discussed herein to optimize HRSG life and turbine operation to select operational priorities, sense operational parameters, and make adjustments, in this case, f/a ratio Adjusting the predetermined first operational control element to optimize the HRSG life while adjusting other operational controls The elements are designed to maintain the combustion turbine within the permissible limits of each operating parameter.

The use of the system described herein now reveals one way to optimize the mechanical life of an HRSG by adjusting the operation of a gas turbine. The method first includes establishing a communication link between the turbine controller 10 and the (as appropriate) DCS 20 and receiving information regarding the status of various operational parameters of the HRSG and the turbine from the HRSG and/or gas turbine sensor components. The operating parameter values are then compared to a standard data set to determine if adjustments to the operational control elements are required to operate the turbine or HRSG in the allowable limits. If an adjustment is required, the adjustment controller will communicate with the selected operational control element to perform a defined incremental adjustment of one of the selected control elements. The system then receives operational parameter data from the sensor component regarding the operation of both the HRSG and the turbine at the adjustment controller via the sensor component and determines whether the adjustment conforms the turbine operation to a set standard or whether a need is required Further incremental adjustments.

Sensing data from the HRSG may include steam outlet temperature and/or steam superheater level over-temperature regulator supersaturation conditions. The operational control element adjusted to modify the values of these sensed parameters can be the fuel to air ratio of the turbine. Once the HRSG value is within the allowable limits, further adjustments are needed to operate the turbine within its allowable limits. This will preferably be accomplished in accordance with the adjustment methods set forth above without further modification of the f/a ratio such that the fuel gas temperature, fuel split or fuel blend ratio is an operational control element.

The adjustment of the system can be adapted to a method for adjusting a premixed combustion system in which there are two distinct modes of operation. The conditioned turbine (not shown) may have an outer ring of the same fuel nozzle that utilizes an outer nozzle fuel split to modulate the circumferential fuel distribution within the outer nozzles; an inner fuel nozzle that utilizes an inner nozzle fuel split The strands adjust the fuel to air ratio of the inner nozzle to the outer nozzle. The outer and inner nozzles discussed herein are well known to those skilled in the art and are not specifically recounted herein. The two different modes of operation include a "lean" inner nozzle mode whereby the f/a ratio of the inner nozzle is less than the f/a ratio of the outer fuel nozzle and a "rich" inner nozzle whereby the inner nozzle f/a The ratio is greater than the f/a ratio of the outer fuel nozzle. Used to adjust with this The method of one of the isophase modes includes selecting one of the mixed fuel split schedules for the change mode at the adjustment controller 10 based on the turbine load. The “poor” center nozzle fuel split schedule will be used under higher load conditions and the “rich” fuel split schedule will be used at lower load and turndown conditions, where the turbine is operated at the lowest possible level to maintain The operation of the HRSG.

The method can include the steps disclosed above along with determining whether the current mode of operation at the adjustment controller 10 is utilizing one of the "lean" or "rich" inner nozzle operating modes, and depending on the current operating conditions and stored in Which operating mode is being utilized under the pre-set operating parameters within the turbine controller, and when there is an adjustment problem, the direction of adjustment of the fuel circuit split 1 and/or the fuel circuit split 2 is selected.

All of the methods provided above can be performed using a Boolean logic two-state toggle switch (such as the Boolean logic two-state toggle switch shown in Figure 3) to select the optimization criteria desired by the user. One of the optimization criteria is the best HRSG lifetime, whereby switching the switch to a "1" ("true") allows the controller to adjust the HRSG entry conditions through the modified fuel-to-air ratio of the gas turbine. The change is to improve the HRSG mechanical operating margin, such as the steam outlet temperature and/or the steamer saturation temperature threshold within the steam superheater stage. These changes can be made using the methods and systems disclosed above.

A method for adjusting a premixed combustion system is also provided whereby there is an outer ring fuel nozzle that utilizes an outer nozzle fuel split to modulate the circumferential fuel distribution within the outer nozzles using two modes of operation: One of the outer nozzles is a sub-group of "lean secondary circuit 1", whereby the f/a ratio of the fuel nozzle subgroup is smaller than the f/a ratio of the remaining outer fuel nozzles; and the nozzle in the "rich secondary circuit 1" In addition, the f/a ratio of the fuel nozzle subgroup is greater than the f/a ratio of the remaining outer fuel nozzles. The method includes using a mixed fuel split schedule with a "rich secondary loop 1" fuel split schedule under higher load conditions and a "lean secondary" at lower load and turndown conditions Loop 1" fuel split scheduling. The method may also include changing other operational control elements (as set forth herein) to enable operation of the turbine or HRSG Allowable in the limit.

The method may also include using a mixed fuel split schedule in which a "lean secondary loop 1" fuel split schedule is performed under higher load conditions, and a "rich" is used at lower load and ratio ratio conditions. Secondary circuit 1" fuel split scheduling. Additionally, the method can include determining whether the current mode of operation at the adjustment controller 10 is determined using one of the "lean secondary circuit 1" or "rich secondary circuit 1" modes of operation, and depending on the current operating conditions. Which operating mode is utilized, when there is an adjustment problem, the fuel circuit split 1 and/or the fuel loop split 2 are adjusted in the appropriate direction using the operational control elements of the fuel split.

A method for adjusting a premixed combustion system using similar systems and steps as set forth above is also provided whereby there are one or more annular ring fuel nozzles (for the same or different types, affecting each fuel nozzle ring One of the circumferences of the fuel is distributed by a circular fuel split to control). In the current system, it is contemplated that a second type of fuel split (if there are more than one annular ring of fuel nozzles) may be utilized, which is adjusted to each of the radially concentric fuel nozzle rings using two modes of operation Relative (radial) fuel amount (circle 1, circle 2, etc.): one of the "depleted secondary circuit ring 1" subgroups of the ring 1 fuel nozzle, whereby the f/a ratio of the fuel nozzle subgroup of the ring 1 is less than the circle a f/a ratio of the remaining fuel nozzles; and a sub-group of one of the fuel nozzles of the coil 1 "rich secondary loop 1", whereby the f/a ratio of the fuel nozzle subgroup is greater than the remaining fuel nozzles of the coil 1 /a ratio. The adjustment method includes using a mixed fuel splitting schedule in which a "lean secondary loop 1" fuel split schedule is performed under higher load conditions, and a "rich" is used under lower load and ratio ratio conditions. For the loop 1" fuel split schedule, and the similar use of the "rich" and "lean" fuel split schedules, for each of the remaining fuel nozzle rings of the combustion system, under high load and The other is under the lower load/regulation ratio conditions. Each of the fuel schedules can be pre-programmed into the adjustment controller 10 and selected based on the sensed operating parameters of the system.

Depending on the operational priority and user input to the adjustment controller 10, the method can also be modified to include the use of a hybrid fuel split schedule, with higher load conditions A "rich secondary loop 1" fuel split schedule, using a "lean secondary loop 1" fuel split schedule and "rich" and "lean" fuel splits under lower load and regulation ratio conditions A similar use of scheduling is for each of the remaining fuel nozzle rings of the combustion system, one under high load and the other under lower load/regulation conditions.

Also provided is a method for adjusting a premixed combustion system, such as the method disclosed above, whereby one or more annular ring fuel nozzles are present (for the same or different types, by affecting each fuel nozzle ring One of the circumferential distributions of fuel is controlled by a circumferential fuel split) whereby a second type of fuel split can be utilized (if more than one annular fuel nozzle is present), which is adjusted to radial concentricity using the following two modes of operation The relative (radial) fuel amount of each of the fuel nozzle rings (circle 1, ring 2, etc.): one of the "depleted secondary loop 1" subgroups of the coil 1 fuel nozzle, whereby the coil 1 fuel nozzle The ratio of f/a of the group is less than the ratio of the f/a of the remaining fuel nozzles of the circle 1; and the sub-group of the "rich secondary loop 1" of the coil 1 fuel nozzle, whereby the f/a ratio of the fuel nozzle subgroup is greater than The f/a ratio of the remaining fuel nozzles of circle 1. The method first includes the step of determining whether the current mode of operation utilizes a "lean secondary loop 1" or "rich secondary loop 1" mode of operation, for each of the remaining fuel nozzle rings of the combustion system One of the operational modes ("rich" or "lean" secondary fuel circuit operation) is similarly determined. Once such a determination is made, the method includes the steps of adjusting fuel circuit split 1 and/or fuel circuit split 2 in an appropriate direction via adjustment controller 10 and selected operational control elements when there is an adjustment problem. The direction of adjustment is determined based on which operating mode is being utilized under the current operating conditions.

Figures 9 through 12 provide an illustrative visual representation of an automatic adjustment system interface that illustrates how the logic logic of the Bollinger works in practice. FIG. 9 shows an alert returned along with the examples set forth above with respect to FIG. That is, the alarm returns for the level 2 δP's at the levels of H 162, HH 164, and HHH 166. In addition, the alarm for NOx 168 and Class 1 δP's 170 returns at the H level. Since the more extreme levels outweigh the conflicts of different alarms at the same level, the HHH level 2 δP's is prioritized and thus the dominant point of interest 172 is adjusted.

Figures 10 through 12 illustrate various other examples of dominant adjustment focus points for different "true" alarm levels under the hierarchy 144 defined by the user of Figure 8. Figure 10 shows the high pressure steam at maximum operating temperature without any other alarms and the high pressure steam desuperheater under saturation conditions (putting water into the steam line). Therefore, the HRSG mechanical life optimization is the dominant adjustment focus. Figure 11 shows a level 2 δP's at the H level with NOx in both H and HH conditions, thus making high NOx a dominant adjustment concern. Finally, Figure 12 shows the level δP's and the level 2 δP's at the H level. Referring to the user ranking of the dominant adjustment question 144 in FIG. 8, the level 1 δP's is ranked as one of the priorities above the level 2 δP's, and therefore, although the severity of the alarm is equal, the level 1 δP's becomes dominant. Adjust the focus.

In Figures 13 through 16, various examples of operational results of one of the adjustment controllers of the present invention based on operational data from a running turbine system are shown. In Fig. 13, the dominant adjustment focus is the high level 2 δP's, and when the burner dynamics is moved outside the set operational priority of the optimal dynamics, one of the high level 2 δP's alarms should be generated. And make a change in the burner fuel split E1. The actual burner dynamics data received by the turbine controller 10 from, for example, the CDMS 50 is designated 200 in the chart. The moving average of the burner dynamics is identified as 202 in the chart. An alarm is issued from the adjustment controller when the burner dynamics exceeds the dynamics alarm limit value 204 for a set time period TA. This alarm results in an incremental adjustment of the first event E1 and one of the burner fuel split adjustment parameters 206. As illustrated, the incremental increase in fuel splitting results in a corresponding decrease in one of the combustor dynamics characteristics 200, wherein the average combustor dynamics characteristic 202 decreases below the kinetic characteristic alert limit 204. Over time, the adjustment is maintained by the adjustment controller and the average burner dynamics 202 maintains its operating position below the dynamics limit 204. Therefore, no further adjustments or alarms are required.

In Figure 14, the adjustment criterion is high NOx emissions. When the self-regulating controller receives the NOx exhaust When the data 210 is placed, an alarm is generated after the elapse of time TA. This alarm is caused by the NOx emissions 210 exceeding the operational criteria or adjustment limits 212. The alarm is initiated causing one of the fuel splits 214 to incrementally increase by one of the first events E1. After one of the time periods TB from the first event E1, the NOx alarm is still initiated due to the NOx emissions 210 exceeding the pre-set adjustment limit 212. This continuous alert after time TB results in a second incremental increase in one of the second event E2 and the fuel split value 214. This second increase is equal to the first incremental increase in magnitude. The second event E2 causes the NOx emission level 210 to decrease below the preset limit 212 and stop the alarm during the review time period. When the NOx emissions 210 remain below the limit 212, the fuel split 214 is maintained and the operation of the turbine continues with the defined operating parameters.

In Figure 15, the adjustment criteria are extinguished if the alarm is formed by a low NOx reading received by the adjustment controller. As shown, the NOx adjustment limit 220 is defined. Immediately after the set time period TA has elapsed since the reception of the NOx level data 222, an alarm is generated and a first event E1 occurs. At the first event E1, the fuel split level 224 is incrementally adjusted downward. After setting the elapsed time TB from event E1, the additional NOx emissions profile 222 is received and compared to the pre-set alarm level 220. Since NOx is still below alarm level 220, a second event E2 occurs, resulting in a further incremental decrease in one of the fuel split values 224. A further time TC has elapsed since event E2 and additional data has been received. Again, the NOx data 222 is low, thereby maintaining an alarm and causing a further event E3. At event E3, the fuel split value 224 is again reduced by the same incremental amount. This third incremental adjustment results in a rise in NOx emissions 222 that is above the preset limit 220 and results in the removal of an alarm. The fuel split 224 adjustment value set after event E3 is held in place by adjustment controller 10.

In FIG. 16, the adjustment criterion is again stalled, whereby the NOx emissions profile 230 received by the adjustment controller 10 is again tracked along the lower emission limit 232. At the first adjustment event E1, the fuel split value 234 is incrementally decreased to cause a corresponding increase in one of the NOx emissions 230 within the lower limit 232. After this first incremental adjustment, the NOx emissions remain above the limit 232 for a period of time and then begin to fall again. At the second adjustment event E2, The fuel split value 234 is again adjusted by the specified fixed increment value. This second adjustment then places the fuel split value 234 at its defined minimum within a pre-set range of allowable values (determined to be one of the hard-coded limits within the controller 10). As this limit is reached, the adjustment operation moves to an operating parameter that is typically adjusted for the second fuel circuit. In the example provided, this second loop value (not shown) is already at its set maximum/minimum value and is therefore unregulated. Therefore, the adjustment operation continues to move to the next operational parameter, load control curve 236. As shown, at event E2, an incremental adjustment is made in load control curve value 236. An increase in the load control curve value 236 results in a corresponding increase in one of the NOx emissions 230 to a value above the minimum value 232 and the alarm is removed. Immediately after the alarm is removed, the adjustment settings are maintained and no further adjustments are made. The adjustment controller 10 then proceeds to receive data through the DCS self-sensor component and continues to compare with the set operating criteria (including the minimum NOx emission limit EL).

The invention has been illustrated and described with respect to several exemplary embodiments of the invention. It will be understood by those skilled in the art that various changes, omissions and additions may be made therein without departing from the spirit and scope of the invention.

10‧‧‧Adjust controller/engine controller/controller

20‧‧‧Distributed control system

30‧‧‧Gas Turbine Controller/Engine Control/Adjustment Controller/Related Turbine Operating Parameters/Engine System

40‧‧‧Continuous Emission Monitoring System / Turbine Exhaust Emissions

50‧‧‧Continuous dynamics monitoring system/burner dynamics

60‧‧‧Fuel heating controller/fuel heating unit/fuel gas temperature controller/associated controller

70‧‧‧fuel blend ratio controller/fuel gas ratio controller/associated controller

80‧‧‧Waste heat recovery steam generator/waste heat recovery steam generator operating parameters/related waste heat recovery steam generator operating parameters

Claims (24)

An adjustment system for optimizing the mechanical life of a waste heat recovery steam generator, the waste heat recovery steam generator being operated together with a same combustion turbine, the adjustment system comprising: a turbine controller; a sensor component, Sensing an operating parameter of a turbine and a waste heat recovery steam generator; and controlling a member for controlling various operational control elements, wherein the turbine controller is adapted to adjust operation of the gas turbine according to the following steps: recovering steam for the waste heat At least one of generator or turbine operation specifies a number of operational priorities, thereby specifying such operational priority operations to change the stored heat recovery steam generator and the stored operational criteria of the turbine, receiving from the sensor components The operational parameter data of the operation of the turbine and the waste heat recovery steam generator are based on the specified operational priorities to compare the operational data with the stored operational criteria to determine whether the waste heat recovery steam generator and the turbine operation are in compliance The operational criteria, based on the pre-set operation priorities, determine the waste heat back a steam generator and a governing adjustment criterion for the non-conforming operation of the turbine, in communication with the control members to perform a selected adjustment in a first operational control element of the gas turbine, after a set period of time, immediately The sensor components receive operational data to determine if an additional incremental change is desired and further adjustments are made to the selected first operational control element, A parameter adjustment different from the one of the first selected operational control elements is selected, and after a set period of time, the operational data is received from the sensor components to determine whether an additional incremental change is desired. The system of claim 1 further comprising a decentralized control system whereby the adjustment controller communicates with the sensor components and the control members using the distributed control system. The system of claim 1, wherein the operational priorities are selected from the group consisting of: optimal NOx emissions, optimal power output, optimal combustor dynamics, optimal waste heat recovery steam generator life, and Optimal fuel blend ratio. The system of claim 3, wherein the optimal fuel blend ratio comprises a ratio of non-line quality gas to pipeline quality gas. The system of claim 1, wherein the selected operational control element adjustment is based on the dominant adjustment criterion, the selected adjustment having a fixed increment value and a defined range, each incremental change being sufficient to provide the turbine with operational stability Entered within the set time period. The system of claim 1 wherein the adjustments in the operational control elements of the gas turbine are selected from the group consisting of burner fuel distribution splits in a nozzle of a combustor, fuel gas inlet temperature, The fuel/air ratio and the gas fuel blend ratio (fuel composition) in the turbine. The system of claim 1, wherein the operational priorities include an optimal waste heat recovery steam generator life, and wherein the fuel is to be used for the turbine when the specified operational priority is the optimum waste heat recovery steam generator life The adjustment to air is selected as the first operational control element to be adjusted. A system as claimed in claim 1, wherein the adjustment controller is adapted to first adjust the fuel to air ratio before making any adjustment adjustment based on the remaining operational priorities The control element is used to optimize the mechanical life of the waste heat recovery steam generator. The system of claim 8 wherein after adjusting the fuel to air ratio operating control element, the turbine controller subsequently responds to a change in an operating parameter of the turbine that occurs as a result of adjusting the fuel to air ratio operating control element Adjust the extra control elements. The system of claim 1, wherein the waste heat recovery steam generator has operating parameters selected from the group consisting of high pressure outlet steam temperature, hot reheat steam temperature, heat exchanger outlet temperature and pressure in the high pressure stage, and Heat reheat stage internal heat exchanger outlet temperature and pressure. The system of claim 1 wherein the turbine has operating parameters selected from the group consisting of turbine stack emissions and combustion dynamics. A system for controlling operation of a combustion turbine, the same coupled to a waste heat recovery steam generator, the system comprising: a turbine controller for storing operations with the turbine and the waste heat recovery steam generator Relevant information specifying a number of operational priorities for at least one of the waste heat recovery steam generator or turbine operation, thereby specifying such operational priority operations to change the stored heat recovery steam generator and the operating standard of the turbine Receiving operational information relating to the operation of the turbine and the waste heat recovery steam generator and providing command signals related to operation of the turbine and the waste heat recovery steam generator; a sensor component for sensing and Information relating to the operation of the turbine and the waste heat recovery steam generator and transferring the sensed data to the turbine controller; a control member operative to control the turbine in response to a command signal provided by the turbine controller Operation control elements. The system of claim 12, wherein the operational priorities are selected from the group consisting of: optimal NOx emissions, optimal power output, optimal combustor dynamics, Optimal fuel blend ratio and optimum waste heat recovery steam generator life. A method of optimizing a mechanical life of a waste heat recovery steam generator by adjusting operation of a gas turbine, the method comprising: providing a sensor member for sensing an operational parameter of the waste heat recovery steam generator; a control member for controlling an operational control element of the turbine, wherein the control member adjusts the selected control element in response to a control signal from the adjustment controller; providing an adjustment controller for recovering the steam generator or turbine for the waste heat At least one of the operations defines a plurality of operational priorities, thereby specifying the operational priority operations to change the stored heat recovery steam generator and the stored operational criteria of the turbine, receiving, from the sensor components, the operations Data of parameters and sends control signals to the control members; establishing a communication link between the adjustment controller, the control members, and the sensor members; sensing the waste heat recovery steam generator and the Information on the operating parameters of the turbine and transmitting the sensed data to the turbine controller; Sensing the operational parameter data and comparing the sensed operational parameter data to the stored operational criteria stored in the turbine controller to determine whether adjustment of an operational control element is required to improve the turbine or the waste heat recovery steam generation Operating parameters of the apparatus, wherein the pre-set operating parameter level is based on an operational priority of the turbine; transferring control signals from the turbine controller to the control components to perform a defined incremental adjustment of one of the first selected operational control elements, After a predetermined time period from the adjustment of the first selected operational control element, sensing information about the operational parameter and transmitting the sensed data to the turbine controller and comparing the sensed operational data to the pre-measurement Set operating parameter level Determining whether the first operational control element is capable of receiving further adjustments and passing control signals from the turbine controller to the control members to perform a second selected operational control element, to determine whether further adjustments within the operational control members are required One is defined as an incremental adjustment. The method of claim 14, wherein the first selected control element to be adjusted is a fuel to air ratio of the turbine, wherein the operational parameters of the waste heat recovery steam generator are in response to comparison with the stored operational standards This adjustment of the fuel to air ratio can be done outside the allowable limit. A method for adjusting a premixed combustion system of a combustion turbine, the turbine comprising at least one combustor having an outer ring of the same fuel nozzle and an inner fuel nozzle, the combustor utilizing an inner nozzle fuel split to adjust the a fuel to air ratio of the inner nozzle to the outer nozzles, the method comprising: providing a turbine controller programmed to operate the premixed combustion system in accordance with at least two distinct modes of operation, the distinct modes comprising: An lean nozzle mode whereby the fuel to air ratio of the inner nozzle is less than the fuel to air ratio of the outer fuel nozzles; and an rich nozzle mode whereby the fuel to air ratio of the inner nozzle is greater than The fuel-to-air ratio of the outer fuel nozzle senses operating conditions of the turbine, wherein the sensed conditions include a high load, a low load, and a turndown ratio; and the lean nozzle mode is used according to the operating condition of the turbine The pre-mixed combustion system operates both of the rich-injection modes; wherein the mode of operation of the turbine is modified from the lean-in-nozzle mode to the rich-injector mode, which is performed by The steps are completed: a plurality of operational priorities are specified for the turbine operation, whereby the operational priority operations are defined to change the stored operational criteria of the turbine; and in response to the operational modes exiting from one of the stored operational criteria Tune These fuel shares of the turbine. The method of claim 16, wherein the premixed combustion system is operated in an lean nozzle mode during high load conditions and the premixed combustion system is operated in an rich nozzle mode during low load and regulated ratio conditions. The method of claim 16, wherein the premixed combustion system is operated in an rich nozzle mode during high load conditions and the premixed combustion system is operated in a lean inner nozzle mode during low load and regulated ratio conditions. A method for adjusting a premixed combustion system of a combustion turbine, the turbine including at least one burner having an outer fuel nozzle whereby fuel between selected subsets of the outer fuel nozzles can be individually adjusted Splitting, the method comprising: providing a turbine controller programmed to operate one of the premixed combustion systems in accordance with at least two distinct modes of operation, the first mode of operation comprising a lean secondary circuit whereby the outer fuel nozzle The fuel to air ratio of the subset is less than the fuel to air ratio of the remaining outer fuel nozzles, and the second mode of operation includes a rich secondary circuit whereby the fuel to air ratio of the fuel nozzle subset is greater than the remaining outer fuel a ratio of the fuel to the air of the nozzle; sensing operating conditions of the turbine, wherein the sensed conditions include a high load, a low load, and a ratio; and using the lean nozzle mode and the rich according to the operating condition of the turbine The nozzle mode operates both of the premixed combustion systems; wherein the mode of operation of the turbine is modified from the lean inner nozzle mode to the rich inner nozzle mode by the following steps Completion: a number of operational priorities are specified for turbine operation, whereby the operational priority operations are defined to change the stored operational criteria of the turbine; and in response to the operational modes being adjusted from one of the stored operational criteria The fuel shares of the turbine. The method of claim 19, wherein the premixed combustion system is operated in a lean secondary circuit mode during high load conditions and the premixed combustion system is adjusted to a rich secondary circuit during low load and switching ratio conditions Mode to operate. The method of claim 19, wherein the premixed combustion system is operated in a rich secondary circuit mode during high load conditions and the premixed combustion system is adjusted to a lean secondary circuit during low load and switching ratio conditions Mode to operate. The method of claim 19, further comprising the step of determining whether the current mode of operation is a lean secondary circuit or a rich secondary circuit, and when there is an adjustment problem, depending on which operation is being utilized under the current operating conditions Mode to adjust selected subsets of external fuel nozzles in the appropriate direction. The method of claim 19, wherein the turbine includes a plurality of annular nozzle fuel nozzles, whereby the fuel split of each revolution can be adjusted based on operating conditions of a turbine such that a first loop can be independently adjusted The fuel to air ratio of the fuel nozzle of the ring and the fuel nozzle of a second annular ring. The method of claim 23, wherein the fuel nozzle of the first annular ring is selectively operable at a fuel to air ratio that is higher than a fuel nozzle of the second annular ring.