DE102014100480A1 - System for improving gas turbine output and hot gas path component life by using humid air for nozzle subcooling - Google Patents

Abstract

A system for improving gas turbine output and extending the life of hot gas path components includes a subsystem for estimating a quantity of water or vapor to add to the air flow to achieve the desired hot gas path temperature. The system includes a water or vapor injection component adapted to inject the amount of water or vapor into the air stream to produce a wet air stream to produce a wet air stream and an injection subsystem adapted to inject the wet air stream into a nozzle on the turbine stage , is also included. The system includes a temperature sensor disposed at a turbine stage and a subsystem for determining a desired hot gas path temperature at the turbine stage. An extraction line is connected to a compressor stage and adapted to remove an air flow.

Description

REFER TO RELATED APPLICATIONS

This application is a sub-continuation of U.S. Pat. Patent Application Ser. No. 13/670, 504 entitled "SYSTEMS AND METHODS FOR ACTIVE COMPONENT LIFE MANAGEMENT FOR GAS TURBINE ENGINES", filed October 7, 2012, which is incorporated herein by reference.

TECHNICAL AREA

The subject matter of the invention described herein is generally gas turbines, and more particularly, active component life management systems and methods for providing additional cooling to compensate for peak, low, and ultra-low load modes, and other types of operating parameters.

BACKGROUND

The lifetime of gas turbine hot gas path parts has a significant impact on the economics of the overall life cycle of single cycle and combination cycle power plants. Gas turbines generally use bleed air from one or more stages of a compressor to provide cooling and / or sealing of the components along the hot gas path in the turbine. Air may be taken from the compressor and supplied outside or within the locations requiring cooling in the turbine, which is defined herein as a turbine cooling circuit.

However, any air compressed in the compressor and not used to generate combustion gases generally reduces the overall efficiency of the gas turbine. On the other hand, elevated temperatures in the turbine may have an impact on the emission levels and life of the components positioned along the hot gas path and elsewhere. In general, operation above the base load reduces the life of the hot gas path components while operating below the base load generally extends the component life.

An exception to this relationship, however, can be found in relation to the nozzles and blades of the stages behind the first turbine stage. Backstage inlet gas temperatures may be higher at peak firing than at baseload and even higher at longer settlements or at very low loads and firing temperatures. Gas turbines are typically designed for continuous base load operation with minimized cooling flows to the stages to maximize thermal efficiency. In this regard, low load operation may be detrimental to the components in the rear stages, while peak load operation may be detrimental to the components in all stages of the turbine.

The physics-based understanding of the lifetime of gas turbine hot gas path parts shows that operation above the rated furnace temperature (T-fire) shortens the life of hot gas path parts and operating below the rated furnace temperature (T-fire) prolongs part life. This relationship is quantified as the applicable maintenance factor (MF). However, the effect on the final stage nozzle and last stage nozzle is more complicated and has a relation to T-fire and output power such that the gas temperature at this stage assumes a bath shape in terms of output and T-fire. The gas temperature of the last stage is higher at peak firing than at baseload and even longer at lower or very low load and T-fire. This phenomenon exhibits an intuitionally adverse effect on the final stage components, where operation at longer settling level or ultra-low load has the greatest negative impact on component life.

Gas turbines are typically designed for continuous base load operation and every effort is made to minimize cooling flows to maximize the thermal efficiency of the gas turbine. However, this typical strategy can be detrimental in peak load operation and ultra low load operation. For gas turbines controlled by exhaust gas temperature control (conventional control) or modified exhaust gas temperature control, externally variable turbine region cooling flow presents an additional challenge to exhaust gas temperature controls where the measured exhaust gas temperature must be compensated to account for the effect of variable coolant flow.

Conventional hot gas path temperature management systems do not provide sufficient facilities to control the adverse effects of operation on part life during peak and longer descent (or ultra-low load) operation. In addition, conventional hot gas path temperature management systems provide insufficient selective subcooling of the hot gas path components to increase turbine tip load beyond the rated capacity.

BRIEF DESCRIPTION OF THE INVENTION

According to an exemplary non-limiting embodiment, the invention relates to a method of operating a gas turbine. The method includes the steps of determining a hot gas path temperature at a turbine stage and determining a desired hot gas path temperature at the turbine stage. An air stream is taken from a compressor stage and an amount of fluid to be added to the air stream to reach a desired hot gas path temperature at the turbine stage is estimated. The method includes the step of adding the estimated amount of fluid to the air stream to produce a wet air stream and injecting the wet air stream into a nozzle of the turbine stage.

The fluid is water or steam.

The determination of an actual hot gas path temperature may include the step of measuring the actual hot gas path temperature by means of an optical transducer.

Additionally or alternatively, the determination of an actual hot gas path temperature may include the step of measuring a burner exhaust temperature.

Additionally or alternatively, the determination of an actual hot gas path temperature may include the step of determining an actual hot gas path temperature at a first turbine stage and determining an actual hot gas path temperature at a second turbine stage.

Additionally or alternatively, the determination of a desired hot gas path temperature at the turbine stage may include: determining a desired hot gas path temperature at a first stage; and determining a desired hot gas path temperature at a second stage.

The removal of an air stream may include: withdrawing a first air stream from a first compressor stage; and removing a second airflow from a second compressor stage.

Estimation of a quantity of fluid to be added to the airflow may include the steps of: estimating a first amount of fluid to be added to the first airflow; and estimating a second fluid amount to be added to the second airflow;

In another embodiment, a system for extending the life of hot gas path components is described. The system includes a temperature sensor located at a turbine stage and a subsystem for determining a desired hot gas path temperature at the turbine stage. A sampling line is connected to a compressor stage and adapted for the removal of an air flow. The system includes a subsystem for estimating an amount of water or steam to add to the airflow to achieve the desired hot gas path temperature. A water or vapor injection component adapted to inject the amount of water or vapor into the air stream to produce a wet air stream and an injection subsystem adapted to inject the wet air stream into a nozzle at the turbine stage are also included.

The temperature sensor of the system may be an optical transducer.

The water or steam injection component of each system mentioned above may include a water or steam injection chamber.

Each of the aforementioned systems may further include: a second temperature sensor disposed at a second turbine stage; a second extraction line connected to a second compressor stage adapted to extract a second airflow; and a second subsystem for determining a desired hot gas path temperature at the second turbine stage; a second subsystem for estimating a second amount of water or vapor to be added to the second airflow to achieve the desired hot gas path temperature at the second turbine stage; and a second fuel injection component adapted to inject a second quantity of water or vapor into the second airflow to produce a second wet airflow; and a second injection subsystem adapted to inject a second wet air stream into a nozzle at the second turbine stage.

In another embodiment, a gas turbine is described with a compressor, a turbine, and a conduit connected to a stage of the compressor adapted to extract an airflow. The gas turbine also includes a temperature sensor adapted to measure a hot gas path temperature at a turbine stage. The gas turbine includes a water or steam injection chamber connected to the conduit and adapted to inject a predetermined amount of water or vapor into the air stream to produce a moist air stream and an injector connected to the conduit for injecting the wet air stream into the air stream the turbine stage is adjusted.

The temperature sensor of the gas turbine may have an optical transducer.

The gas turbine of any type mentioned above may further include a second bleed line connected to a second stage of the compressor adapted to take a second air flow.

The gas turbine of any type mentioned above may further include a second temperature sensor adapted to measure a second hot gas path temperature at a second turbine stage.

The gas turbine of each type mentioned above may further include: a second water or steam injection chamber connected to the second withdrawal conduit and adapted to inject a second predetermined amount of water or vapor into the airflow to produce a second wet airflow; and a second injector connected to the second withdrawal conduit and adapted to inject the second moist airflow into the second turbine stage.

In another embodiment, a method for improving output of a gas turbine having a compressor and a turbine is described. The method includes the steps of determining an actual output and a target output. The method also includes the steps of extracting an airflow from a compressor stage and estimating an estimated amount of fluid to add to the airflow to achieve the desired output power. In a further step, the method includes adding fluid in an amount substantially equal to the estimated amount of fluid to the airflow to produce a moist airflow. The method also includes injecting the wet air flow into a nozzle at a turbine stage and adjusting the actual output power to the desired output power.

The fluid may be water or steam.

Injecting a wet air stream into a nozzle at the turbine stage may include injecting a wet air stream into a plurality of nozzles at a plurality of turbine stages.

Other features and advantages of the present invention will become apparent from the following more detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, which illustrate, by way of example, the principles of certain aspects of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

1 is a schematic representation of a gas turbine, which is a compressor, a burner, a turbine and a load.

2 Figure 3 is a schematic representation of one embodiment of a wet air cooling system as described herein.

3 Figure 11 is a functional diagram of one embodiment of a control system used in a wet air cooling system.

4 is a schematic representation of a portion of a turbine with an infrared camera.

5 FIG. 10 is a flowchart of one embodiment of a method of operating a gas turbine using a wet air cooling system.

6 FIG. 10 is a flowchart of one embodiment of a method for improving an output of a gas turbine.

DETAILED DESCRIPTION OF THE INVENTION

The systems and methods described herein provide subcooling of the hot gas path nozzles with humid air coupled with exhaust temperature control compensation. In another embodiment, a direct hot gas path component metal temperature measurement is provided with an optical transducer (e.g., an infrared camera). In yet another embodiment, a direct hot gas path gas flow temperature measurement may be applied with an optical transducer (e.g., an infrared camera). The cooling flow temperatures are measured and the cooling flow temperatures are controlled to the set point by the addition of demineralized water or steam to increase the cooling air "humidity" or cooling air mass flow, respectively. The subcooling of all nozzle stages in the turbine enables active part life management, which can be used to extend engine operation beyond its current limitations, in conjunction with additional peak overheat approval.

In the drawings, wherein like reference numerals refer to like elements throughout the several views 1 a schematic representation of a gas turbine 10 as may be used herein. The gas turbine 10 can a compressor 15 contain. The compressor 15 compacts an incoming airflow 20 , The compressor 15 provides the compressed air flow 20 to a burner 25 , The burner 25 mixes the compressed airflow 20 with a pressurized fuel stream 30 and ignite the mixture to a combustion gas stream 35 to create. Although only a burner 25 is shown, the gas turbine 10 contain any number of burners. The combustion gas flow 35 will turn to a turbine 40 delivered. The combustion gas flow 35 drives the turbine 40 to create mechanical work. The one in the turbine 40 generated mechanical work drives the compressor 15 and an external load 50 , such as an electric generator and the like, via a shaft 45 at.

The gas turbine 10 may use natural gas, liquid fuels, various types of syngas, and / or other fuel types. The gas turbine 10 can be any of a number of different gas turbines offered by different manufacturers worldwide. The gas turbine 10 can have different designs and can use other component types. More than just a gas turbine 10 Other types of turbomachinery and other types of power generators may also be used herein.

As described above, the compressor 15 a number of compressor stages 55 use in it. Likewise, the turbine can 40 any number of turbine stages 40 use in it. The gas turbine 10 can thus have a number of air extraction points 65 Use to remove cooling air from the compressor 15 for the turbine 40 provide. In this example, air is taken from the first compressor stage 72 for a first turbine stage 72 using a first sampling line 70 taken. As used herein, "first" and "second" are used to distinguish the stages from one another and not necessarily the stage of the compressor 15 or the turbine 40 to imply. For example, the first compressor stage 72 at a stage 9 of the compressor 15 refer and the second compressor stage may be at a stage 13 of the compressor 15 Respectively. A first extraction control valve 76 can in the first sampling line 70 be positioned. Likewise, the gas turbine 10 a second sampling line 80 have that differ from that of a second compressor stage 82 to a second turbine 84 extends. A second extraction control valve 86 can in the second sampling line 80 be positioned. A compressor outlet line 90 can be from a compressor outlet 92 to an inlet fuel heat collector 94 or another job. The inlet tap heat collector 94 can be around an inlet of the compressor 15 be positioned around. An inlet tap heat collector valve 96 can be used to control the flow there. The extraction lines can be located inside or outside the turbine housing. Other components and other designs may be used herein.

2 provides a humid air cooling system 100 according to one embodiment. The humid air cooling system 100 can with the gas turbine 10 as described above. The humid air cooling system 100 can the components of the turbine 40 therefore along the hot gas path, in particular in the region of the first turbine stage 74 (which may be stage 3 of the turbine in one embodiment) and the second turbine stage 89 (which may be stage 2 of the turbine in one embodiment) actively cool.

The humid air cooling system 100 can be a first flow and temperature sensor 110 included in the area of the first sampling line 70 is positioned. Likewise, the humid air cooling system 100 a second flow and temperature sensor 120 included in the scope of the second sampling line 80 is positioned. The first flow and temperature sensor 110 and the second flow and temperature sensor 120 may be of conventional design. The first flow and temperature sensor 110 and the second flow and temperature sensor 120 thus determine the flow rate and the temperature of the air flow 20 in the first sampling line 70 (first air flow) and in the second extraction line 80 (second airflow).

The humid air cooling system 100 can also have a first water / steam injection chamber 130 included in the area of the first sampling line 70 is positioned. The first water / steam injection chamber 130 may be an evaporative cooling system in which distilled water is supplied to an absorption medium and exposed to the air flow through the medium to evaporate the water by means of the energy in the air. Alternatively, multiple collectors and nozzles may deliver a jet of finely atomized water or steam into the airflow.

Likewise, the humid air cooling system 100 a second water / steam injection chamber 140 included in the scope of the second sampling line 80 is positioned. The first water / steam injection chamber 130 and the second water / steam injection chamber 140 can be connected to any heating or cooling medium from any source. Other components and other configurations may be used herein.

The humid air cooling system 100 may be a first control valve 150 included in that first sampling line 70 downstream of the first water / steam injection chamber 130 is arranged. The first control valve 150 controls the amount of humid air entering the first turbine stage 74 is injected. In addition, there is a first downstream sensor 170 downstream of the first water / steam injection chamber 130 and is used to determine the temperature and flow rate of the wet air stream entering the first turbine stage 74 is injected. Likewise, the humid air cooling system 100 a second control valve 160 included in the second sampling line 80 downstream of the second water / steam injection chamber 140 is arranged. The second control valve 160 controls the amount of humid air entering the second turbine stage 84 is injected. In addition, there is a second downstream sensor 180 downstream of the second water / steam injection chamber 140 and is used to determine the temperature and flow rate of the wet air stream entering the second turbine stage 84 is injected.

The addition of moisture to the turbine nozzle cooling streams by means of water / steam injection improves the specific heat (Cp) of the cooling air and to a lesser extent that of the primary flow. In addition, the addition of moisture to the turbine nozzle cooling streams via water / steam injection lowers the stage operating temperature, which improves part life and enables active part life management by modulating the injection at each stage. Another benefit of adding humid air to the turbine nozzle cooling flows is that it increases the mass flow of the stage and thereby increases the peak output power. The addition of wet air also reduces the exhaust gas temperature during a low load operation, thereby improving the ability to meet the isothermal limit of heat recovery steam generators in gas turbine power increases.

The humid air cooling system 100 can by means of a cooling control 350 operate. The cooling control 350 can with the overall control system of the gas turbine 10 be connected or integrated in it. The cooling control 350 can receive feedback from the various flow sensors so as to properly operate the various control valves and blocking valves so as to determine the temperature of the air extraction 65 and to control the temperature of the hot gas path components. In addition, through the first water / steam injection chamber 130 (first fluid quantity) and through the second water / steam injection chamber 140 (Second fluid amount) amount of fluid to be added by the cooling controller 350 to be controlled.

The cooling control 350 of the moist air cooling system described herein 100 thus monitors the flow rate and temperature in the first sampling line 70 and the second sampling line 80 and the temperature of the hot gas path components in the turbine 40 and the load conditions in it. The temperature of the air withdrawals 65 can thus by means of the first water / steam injection chamber 130 and the second water / steam injection chamber 140 to be changed.

The cooling control 350 can also by the humid air cooling system 100 compensate for the variable wet-air cooling flow provided. An exhaust gas temperature sensor 360 can be downstream from the turbine 40 be positioned to determine the exhaust gas temperature. Because the gas turbine 10 Can be controlled exhaust gas temperature-controlled, the cooling control 350 an input from the exhaust temperature sensor 360 and the second exhaust gas flow and the temperature sensor 120 and the first flow and the temperature sensor 110 so as to provide an adequate compensation factor for the additional cooling moist air. The cooling control 350 can thus provide step-level time in temperature tracking and management.

The cooling control 350 can be a standalone processor or part of a larger control system, such as the General Electric's "SPEEDTRONIC ™ Gas Turbine Control System, as described in Rowen, WI, SPEEDTRONIC ™ Mark V Gas Turbine Control System", GE-3658D, published by GE Industrial & Power Systems of Schenectady, NY is described. The cooling control 350 may be a computer system having a processor (s) executing programs to control operation of the gas turbine using sensor input signals and instructions from an operator. The of the cooling control 350 Running programs may include scheduling algorithms for controlling the flow of fuel to the burner 25 include. The of the cooling control 350 generated commands cause actuators in the moist air cooling system 100 for example, the first control valve 150 and the second control valve 160 adjust.

3 is a functional representation of an embodiment of the cooling control 350 , Exhaust gas temperature values measured by exhaust gas temperature sensors 420 can through a first processing module 440 are processed. The first processing module 440 may be a control algorithm based model using a linear quadratic estimation algorithm (Kalman filter). The first downstream sensor 170 and second downstream sensor 180 measured cooling injection current values 430 will also be sent to second processing module 450 which may be a model-based control algorithm using a Kalman filter. The output signals from the first processing module 440 and the second processing module 450 are sent to a third processing module 460 where the exhaust gas temperature, the derived firing temperature and the hot gas path level's level are calculated and compensated for active nozzle cooling flows. Another module 470 can maintain a time log of temperature at various stages for tracking and management purposes.

4 represents an optical system, such as an infrared camera 370 that is above a hot gas path component 380 is positioned. The hot gas path component 380 can a blade 390 , a nozzle 400 or any other type of component that is in the turbine 40 is positioned. The infrared camera 370 may be of conventional design. The infrared camera 370 may be a temperature distribution along the hot gas path component 380 to capture. The infrared camera 370 or another type of device may be with the cooling control 350 keep in touch. Diagnostic algorithms can be used to generate a state index that reflects either the overall state of the component surface or the state of a specific location along the surface. Local defects such as oxidation and spalling may appear as deviations around the location on the component surface. The state index can thus be used as an indicator of the state of the component or a portion thereof. The infrared camera 370 can be a trigger 410 for use with rotating hot gas path components. Similar types of pyrometer systems and other types of optical systems may also be used herein in a similar manner. Other components and other configurations may also be used herein.

5 shows a flowchart illustrating a method 500 for operating a gas turbine 10 illustrated.

In step 510 determines the procedure 500 an actual state, such as a desired output signal or an actual hot gas path temperature at a turbine stage.

In step 520 determines the procedure 500 a desired state, such as a desired output signal or an actual hot gas path temperature at the turbine stage.

In step 530 takes the procedure 500 an air flow from a compressor stage.

In step 540 appreciates the process 500 a quantity of water or steam to be added to the air stream to achieve a desired hot gas path temperature at the turbine stage.

In step 550 adds the procedure 500 add the amount of water or steam to the air stream to create a wet air stream.

In step 560 the process injects 500 the moist air flow into a nozzle at the turbine stage.

The determination of the hot gas path temperature can be achieved by measuring the hot gas path temperature with the optical transducer, or by measuring a burner exhaust temperature. The determination of the hot gas path temperature can be carried out for several turbine stages. Similar determination of a target hot gas path temperature may be performed for multiple turbine stages. The removal of the air flow can be achieved by removing air streams from multiple compressor stages. Estimation of the amount of water or steam to add may include estimating the amount of water or steam to add to each of a plurality of air streams. Likewise, the addition of water or steam to the air stream may involve the addition of water or steam to multiple air streams.

The humid air cooling system 100 Thus, the temperature of the hot gas path component 380 especially under operating conditions, such as peak loads and low loads, to provide increased cooling as needed. The humid air cooling system 100 allows selective overcooling of the affected components with a variable cooling flow based on the temperature compensation method described herein to adequately control the overall load. Furthermore, the selective subcooling of all stages of the turbine 40 provide active component life management, thus reducing the overall performance of the gas turbine 10 extend beyond current limits for a period of time in conjunction with an additional overheating license.

The humid air cooling system 100 thus improves the life of the hot gas path component 380 by offsetting the higher heat generated during peak load operation, longer downtime periods and other types of operating parameters. Furthermore, the humid air cooling system adds 100 the ability to operate over normal peak loads added for a limited time. The humid air cooling system 100 Thus, it can improve the economy of the overall life of the gas turbine while providing functional flexibility in a relatively inexpensive system.

6 is a flowchart of one embodiment of a method 600 for improving an output of a gas turbine.

In step 610 the method determines an actual output power.

In step 615 determines the procedure 600 a nominal output power.

In step 620 takes the method an air flow from a compressor stage.

In step 625 appreciates the process 600 an amount of fluid to be added to the air flow to reach the desired output power.

In step 630 adds the procedure 600 adding a fluid in an amount substantially equal to the estimated amount of fluid to the airflow to produce a moist airflow.

In step 635 the process injects 600 a humid air flow into a nozzle at a turbine stage. This can be achieved by injecting a stream of moist air into several nozzles at several turbine stages.

In step 640 puts the procedure 600 the actual output power is set to the target output power.

Where the definition of terms differs from the commonly used meaning of the term, the applicant wishes to use the definitions provided below, unless specifically stated otherwise.

The terminology used herein is for the purpose of describing specific embodiments only and is not intended to limit the invention. Where the definition of terms differs from the commonly used meaning of the term, the applicant wishes to use the definitions provided herein unless specifically stated otherwise. The singular forms "one, one, one" and "the, the, the" should also include the plural forms unless the context clearly dictates otherwise. It should be understood that although the terms "first, second, etc." can be used to describe various elements, these elements should not be limited by these terms. These terms will only be used to distinguish one element from another. The term "and / or" includes any and all combinations of one or more of the associated listed items. The terms "coupled" or "coupled with" contemplate direct or indirect coupling.

This description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using all of the elements and systems, and performing all of the methods involved. The patentable scope of the invention is defined by the claims, and may include other examples that will be apparent to those skilled in the art. Such other examples are intended to be within the scope of the invention if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.

A system for improving gas turbine output and extending the life of hot gas path components includes a subsystem for estimating a quantity of water or vapor to add to the air flow to achieve the desired hot gas path temperature. The system includes a water or vapor injection component adapted to inject the amount of water or vapor into the air stream to produce a wet air stream to produce a wet air stream and an injection subsystem adapted to inject the wet air stream into a nozzle on the turbine stage , is also included. The system includes a temperature sensor disposed at a turbine stage and a subsystem for determining a desired hot gas path temperature at the turbine stage. An extraction line is connected to a compressor stage and adapted to remove an air flow.

LIST OF REFERENCE NUMBERS

10

 Gas turbine (13)

15

 Compressor (10)

20

 Air (4)

25

 Burner (3)

25

 a burner

30

 fuel

35

 Combustion gases (3)

40

 Turbine (11)

45

 wave

50

 external load

55

 compressor stages

60

 turbine stages

65

 Air withdrawals (30)

70

 first sampling tube (7)

72

 first compressor stage (2)

74

 first turbine stage (4)

76

 first removal control valve

80

 second sampling tube (6)

82

 second compressor stage

84

 second turbine stage (3)

86

 second removal control valve

89

 second turbine stage

90

 Verdichterauslassentnahmerohr

92

 compressor outlet

94

 Inlet Branch Heat Collector (2)

96

 Inlet bleed heat collector valve

100

 Wet air cooling system (18)

110

 Temperature sensor (4)

120

 Temperature sensor (4)

130

 first water / steam injection chamber (6)

140

 second water / steam injection chamber (5)

150

 first control valve (3)

160

 second control valve (3)

170

 first downstream sensor (2)

180

 second downstream sensor (2)

350

 Cooling control (13)

360

 Temperature sensor (2)

370

 Infrared camera (5)

380

 Hot gas path component (5)

390

 blade

400

 jet

410

 trigger

420

 Exhaust gas temperature values

430

 Cooling injection flow values

440

 first processing module (3)

450

 second processing module (2)

460

 third processing module

470

 module

500

 Method (7)

510

 step

520

 step

530

 step

540

 step

550

 step

560

 step

QUOTES INCLUDE IN THE DESCRIPTION

This list of the documents listed by the applicant has been generated automatically and is included solely for the better information of the reader. The list is not part of the German patent or utility model application. The DPMA assumes no liability for any errors or omissions.

Cited non-patent literature

• General Electric "SPEEDTRONIC ™ Gas Turbine Control System as described in Rowen, WI, SPEEDTRONIC ™ Mark V Gas Turbine Control System", GE-3658D, published by GE Industrial & Power Systems of Schenectady, NY. [0049]

Claims (10)

Method for operating a gas turbine, with the steps: Determining a desired state at a turbine stage; Determining an actual hot gas path temperature; Determining a desired hot gas path temperature at the turbine stage; Removal of an air flow from a compressor stage; Estimating an estimated amount of fluid to be added to the airflow to achieve a desired hot gas path temperature at the turbine stage; Adding a fluid in an amount substantially equal to the estimated amount of fluid to the airflow to produce a moist airflow; and Injecting the moist air flow into a nozzle at the turbine stage. The method of claim 1, wherein the fluid is water or steam. A method for operating a gas turbine according to claim 1, wherein the determination of an actual hot gas path temperature comprises the step of measuring the actual hot gas path temperature with an optical transducer and / or wherein the determination of an actual hot gas path temperature comprises the step of measuring a burner exhaust gas temperature and / or the determination of an actual hot gas path temperature comprises the step of determining an actual hot gas path temperature at a first turbine stage and determining an actual hot gas path temperature at a second turbine stage. A method of operating a gas turbine according to claim 3, wherein the determination of a desired hot gas path temperature at the turbine stage comprises the steps of: Determining a desired hot gas path temperature at a first turbine stage; and Determining a desired hot gas path temperature at a second turbine stage. A method of operating a gas turbine according to claim 4, wherein the extraction of an air stream comprises the steps of: Removing a first air flow from a first compressor stage; and Removal of a second air flow from a second compressor stage. A method of operating a gas turbine according to claim 5, wherein the estimation of a quantity of fluid to be added to the airflow comprises the steps of: Estimating a first amount of fluid to be added to the first airflow; and Estimating a second amount of fluid to be added to the second airflow. System comprising: a temperature sensor disposed on a turbine stage; a subsystem for determining a desired hot gas path temperature at the turbine stage; an extraction line connected to a compressor stage adapted to extract an airflow; a subsystem for estimating an amount of water or steam to be added to the airflow to reach the target hot gas path temperature; a water or vapor injection component adapted to inject the amount of water or vapor into the air stream to produce a moist air stream; and an injection subsystem adapted to inject the wet air stream into a nozzle at the turbine stage. The system of claim 7, further comprising: a second temperature sensor disposed at a second turbine stage; a second extraction line connected to a second compressor stage and adapted to extract a second airflow; and a second subsystem for determining a desired hot gas path temperature at a second turbine stage; a second subsystem for estimating a second amount of water or steam to be added to the airflow to reach the desired hot gas path temperature and the second turbine stage; and a second fuel injection component adapted to inject a second quantity of water or vapor into the second airflow to produce a second wet airflow; and a second injection subsystem adapted to inject the second wet air stream into a nozzle at the second turbine stage. Gas turbine, comprising: a compressor; a turbine; a conduit connected to a stage of the compressor and adapted to remove an airflow; a temperature sensor adapted to measure a hot gas path temperature at a turbine stage; a water or steam injection chamber connected to the conduit and adapted to inject a predetermined amount of water or vapor into the airflow to produce a moist airflow; and an injector connected to the conduit and adapted for injecting the moist air flow into the turbine stage. A method of improving an output of a gas turbine having a compressor and a turbine, the method comprising the steps of: determining an actual output; Determining a desired output power; Removing an airflow from a compressor stage; Estimating an estimated amount of fluid to be added to the airflow to achieve the desired output power; Adding fluid in an amount substantially equal to the estimated amount of fluid to the airflow to produce a moist airflow; Injecting the moist air flow into a nozzle at a turbine stage; and setting the actual output power to the target output power.

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