Abstract:
Methods and systems for a dry low NO x  gas turbine engine system include a gas turbine engine including at least one dry low NO x  combustor. The combustor includes a plurality of injection points wherein at least some of the injection points are configured to inject a fuel into the combustor at a plurality of different locations. The system includes a water source coupled to the combustor and operable to inject water into others of the plurality of injection points. The system also includes a control system that includes a sensor configured to measure an exhaust gas concentration of the turbine, a processor programmed to receive a signal indicative of the turbine exhaust gas concentration, and to automatically control the water injection using the received exhaust gas concentration signal. Such systems in use together can mitigate visible emissions from the exhaust stack.

Description:
BACKGROUND OF THE INVENTION 
   This invention relates generally to power generation involving the combustion of gas fossil fuels, and more particularly to methods and apparatus for reducing visible emissions in heavy-duty gas turbine power generators. 
   The condition of a visible yellow plume emanating from the stacks of combined cycle power plants is typically caused by an NO 2  concentration exiting the gas turbine engine. As gas turbines have became more sophisticated, exhaust temperatures have increased. The NO 2  level exiting the stack comes generally from two sources, NO 2  formed in the combustion system and conversion of NO to NO 2  in the exhaust path. A higher exhaust temperature increases the amount of NO to NO 2  conversion in the exhaust path. Water injection has been shown to facilitate lowering the amount of NO x  produced in a combustion system. Typically, water is used in non-Dry Low NO x  combustors to reduce NO x  over a contractual guarantee range (usually 50%-100% load). In comparison, existing Dry Low NO x  combustion systems utilize a diffusion stabilized, partially premixed flame without water injection from 0% to 50% load. Typically, the design requirements for a dry low NO x  (DLN) combustion system operating at part load are to maintain a stable flame with robust operability and durability. To mitigate visible exhaust emissions, additional parameters are needed to be added to such list of design requirements. A diffusion stabilized partially premixed DLN combustion flame is not capable of meeting all of these design requirements. 
   During a cold start of a gas turbine engine, at least some known gas turbine engines are operated for approximately four hours or more at partial loading (0 to 50%) prior to reaching full pre-mixed operation (50 to 100% load). During this partial loading operation, the level of NO 2  exiting the exhaust stack can be sufficient to cause a visible plume. It has been found that the concentration of NO 2  exiting the stack can be up to three times the concentration of NO 2  exiting the gas turbine, while the overall NO x  level remained substantially constant. The relationship, NO x =NO+NO 2  suggests that conversion of NO to NO 2  occurs between the gas turbine exit and the top of the exhaust stack. The amount of NO 2  exiting the exhaust stack, which can appear as a yellow plume, does not violate any environmental regulations, however, it is perceived as unsightly and can lead to a poor public perception of the power plant. 
   BRIEF DESCRIPTION OF THE INVENTION 
   In one embodiment, a dry low NO x  gas turbine engine system includes a gas turbine engine including at least one dry low NO x  combustor. The combustor includes a plurality of injection points wherein at least some of the injection points are configured to inject a fuel into the combustor at a plurality of different locations. The system includes a water source coupled to the combustor and operable to inject water into others of the plurality of injection points. The system also includes a control system that includes a sensor configured to measure an exhaust gas concentration of the turbine, a processor programmed to receive a signal indicative of the turbine exhaust gas concentration, and to automatically control the water injection using the received exhaust gas concentration signal. 
   In another embodiment, a low-emission method for producing power using a gas turbine engine includes premixing a plurality of fuel and air mixtures, injecting the fuel and air mixtures into a combustion chamber using a plurality of fuel nozzles, injecting a quantity of water into the combustion chamber using the fuel nozzles during a relatively low power production stage of operation, and automatically controlling a ratio of fuel and air, and water injected by at least one of the fuel nozzles to control a concentration of NO x  emissions exiting the gas turbine engine. 
   In yet another embodiment, a combined cycle power plant system includes a dry low NO x  gas turbine engine system including at least one dry low NO x  combustor including a plurality of injection points wherein at least some of the injection points are configured to inject a fuel into the combustor at a plurality of different locations. The system includes a water source coupled to the combustor and operable to inject water into others of the plurality of injection points, and a control system including a sensor configured to measure an exhaust gas concentration. The system also includes a processor programmed to receive a signal indicative of the exhaust gas concentration, and automatically control the water injection using the received exhaust gas concentration signal. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a schematic diagram of a gas turbine engine system; 
       FIG. 2  is a partial cross section of a low NOx gas turbine combustion system such as those shown in  FIG. 1 ; 
       FIG. 3  is a cross-sectional view of an exemplary fuel injection nozzle that may be used with the low NOx gas turbine combustion system shown in  FIG. 2 ; 
       FIG. 4  is a series of schematic illustrations of various stages of an exemplary startup and loading sequence of the dry low NO x  (DLN) combustor illustrated with five outer fuel nozzle assemblies; and 
       FIG. 5  is a flow chart of an exemplary method of reducing visible exhaust stack emissions that may be used with gas turbine engine system shown in  FIG. 1 . 
   

   DETAILED DESCRIPTION OF THE INVENTION 
   While the methods and apparatus are herein described in the context of a gas turbine engine used in an industrial environment, it is contemplated that the method and apparatus described herein may find utility in other combustion turbine systems applications including, but not limited to, turbines installed in aircraft. In addition, the principles and teachings set forth herein are applicable to gas turbine engines using a variety of combustible fuels such as, but not limited to, natural gas, gasoline, kerosene, diesel fuel, and jet fuel. The description hereinbelow is therefore set forth only by way of illustration, rather than limitation. 
     FIG. 1  is a schematic diagram of a gas turbine engine system  10  including a compressor  12 , a combustor  14 , a turbine  16  drivingly coupled to compressor  12 , and a control system  18 . An inlet duct  20  channels ambient air to the compressor. Inlet duct  20  may have ducts, filters, screens and sound absorbing devices that contribute to a pressure loss of ambient air flowing through inlet duct  20  into one or more inlet guide vanes  21  of compressor  12 . An exhaust duct  22  channels combustion gases  23  from an outlet of turbine  16  through, for example, emission control, and sound absorbing devices. Exhaust duct  22  may include sound adsorbing materials and emission control devices. Turbine  16  drives a generator  24  that produces electrical power. 
   The operation of the gas turbine engine system  10  is typically monitored by several sensors  26  used to detect various conditions of turbine  12 , generator  24 , and the ambient environment. For example, temperature sensors  26  may monitor ambient temperature surrounding gas turbine engine system  10 , compressor discharge temperature, turbine exhaust gas temperature, and other temperature measurements of the gas stream through the gas turbine engine. Pressure sensors  26  may monitor ambient pressure, and static and dynamic pressure levels at the compressor inlet and outlet, turbine exhaust, at other locations in the gas stream through the gas turbine. Humidity sensors  26 , such as wet and dry bulb thermometers measure ambient humidity in the inlet duct of the compressor. Sensors  26  may also comprise flow sensors, speed sensors, flame detector sensors, valve position sensors, guide vane angle sensors, and other sensors that sense various parameters relative to the operation of gas turbine engine system  10 . As used herein, “parameters” refer to physical properties whose values can be used to define the operating conditions of gas turbine engine system  10 , such as temperatures, pressures, and gas flows at defined locations. 
   A fuel control system  28  regulates the fuel flowing from a fuel supply to combustor  14 , and the split between the fuel flowing into various fuel nozzles located about the combustion chamber. Fuel control system  28  may also select the type of fuel for the combustor. The fuel control system  28  may be a separate unit or may be a component of control system  18 . Fuel control system  28  may also generate and implement fuel split commands that determine the portion of fuel flowing to primary fuel nozzles and the portion of fuel flowing to secondary fuel nozzles. 
   Control system  18  may be a controller having a processor(s) that executes programs to control the operation of the gas turbine using sensor inputs and instructions from human operators. The programs executed by controller  18  may include scheduling algorithms for regulating fuel flow to combustor  14 . The commands generated by controller  18  cause actuators on the gas turbine to, for example, adjust valves (actuator  32 ) between the fuel supply and combustors that regulate the flow, fuel splits and type of fuel flowing to the combustors; adjust inlet guide vanes  21  (actuator  30 ) on the compressor, and activate other control settings on the gas turbine. 
   A water injection system  36  is also controllable by controller  18  through a variable frequency drive (VFD)  38  coupled to a motor  40  of a water injection pump  42 . Pump  42  receives water from a source  44  and is modulated to supply a quantity of water to combustor  14 . 
   Controller  18  regulates the gas turbine based, in part, on algorithms stored in a computer memory of controller  18 . These algorithms enable controller  18  to maintain the NO x  and CO and other emissions in the turbine exhaust to within certain predefined emission limits. The algorithms have inputs for parameter variables for current compressor pressure ratio, ambient specific humidity, inlet pressure loss and turbine exhaust backpressure. Because of the parameters in inputs used by the algorithms, controller  18  accommodates seasonal variations in ambient temperature and humidity, and changes in the inlet pressure loss through the inlet  20  of the gas turbine and in the exhaust backpressure at the exhaust duct  22 . Input parameters for ambient conditions, and inlet pressure loss and exhaust back pressure enable NO x , CO and turbine firing algorithms executing in controller  18  to automatically compensate for seasonal variations in gas turbine operation and changes in inlet loss and in back pressure. Accordingly, the need is reduced for an operator to manually adjust a gas turbine to account for seasonal variations in ambient conditions and for changes in the inlet pressure loss or turbine exhaust backpressure. 
   In the exemplary embodiment, combustor  14  is a DLN combustion system. Controller  18  may be programmed and modified to control the DLN combustion system and for determining fuel splits. 
   The schedules and algorithms executed by controller  18  accommodate variations in ambient conditions (temperature, humidity, inlet pressure loss, and exhaust backpressure) that affect NOx, combustor dynamics, and firing temperature limits at part-load gas turbine operating conditions. Controller  18  simultaneously schedules exhaust temperature and combustor fuel splits. Controller  18  applies algorithms for scheduling the gas turbine, such as setting desired turbine exhaust temperatures and combustor fuel splits, to satisfy performance objectives while complying with operability boundaries of the gas turbine. Controller  18  simultaneously determines level combustor temperature rise and NOx during part-load operation in order to increase the operating margin to the combustion dynamics boundary and thereby improve operability, reliability, and availability of the gas turbine. 
   The combustor fuel splits are scheduled by controller  18  to maintain the desired combustion mode while observing other operability boundaries, such as combustion dynamics. At a given load level, the cycle match point and the combustor fuel splits influence the resultant NOx emissions. Simultaneously leveling NOx and combustor temperature rise during part-load operation minimizes the level of combustion dynamics and expands the operational envelope of the gas turbine without adversely affecting emissions compliance or parts life. 
   Combustors  14  include a plurality of fuel control valves supplying two or more injector groups in each combustor to allow modulation of modes of operation, emissions, and combustion dynamics levels versus machine load. By modulating fuel splits among the several fuel gas control valves, emissions and dynamics are optimized over the machine load range. Fuel split modulation depends on a calculated reference parameter, called combustion reference temperature, which is a function of machine exhaust temperature and other continuously monitored machine parameters. 
     FIG. 2  is a partial cross section of one low NOx gas turbine combustor  14  such as those shown in  FIG. 1 . Gas turbine engine system  10  includes a plurality of combustors  14  arranged in an annular array about the periphery of a gas turbine casing  205 . High pressure air K from compressor  12  flows into combustors  14  through an array of air inlet holes  206  distributed among a transition piece  207  and a flow sleeve  208  near an outlet end of combustor liner  209 . Compressed air delivered to combustor  14  flows through an annular passage bounded by combustor flow sleeve  208  and combustor liner  209  to a combustor inlet end (or synonymously, head end)  210  where there are arranged a plurality of air-fuel injectors of at least two different types. For example, in some configurations, the plurality of air-fuel injectors comprise an array of outer fuel nozzles  211  and a center nozzle  212  per combustor  14 . Not all configurations have the same number of inner nozzles or the same number of outer nozzles as that described herein. By way of example only, some configurations include more than one center nozzle  212  surrounded by a different number of outer nozzles  211  than that described herein. 
   At an inlet end of each combustor  14 , compressed air and fuel are mixed and flow into a combustion burning zone  213 . At the opposite end of combustion burning zone  213 , hot combustion gases H flow into double-walled transition piece  207  that couples an outlet end of each combustor liner  209  with an inlet end of turbine nozzle  204  to deliver hot combustion gas flow H to turbine  16 , where the enthalpy of the hot gas flow is converted to shaft work in the turbine rotor via the expansion of gas flowing through stationary and rotating turbine airfoils (not shown in the Figures). 
   Each combustor  14  includes a substantially cylindrical combustion casing assembly comprising two sections, namely, a forward combustion casing  216  and an aft combustion casing  217 . Combustion casings  216  and  217  are attached to compressor discharge casing  220  by a bolted joint  219 . Forward combustion casing  216  is connected to aft combustion casing  217  by bolted joint  218 . The head end of forward combustion casing  216  is closed by an end cover assembly  221  that may also include fuel and air supply tubes, manifolds and associated valves for feeding gas, liquid fuel, air, and water (if desired) to combustor  14  as described in greater detail below. In some configurations of the present invention, end cover assembly  221  is configured as a mounting base to receive a plurality (for example, five) outer fuel nozzle assemblies  211  arranged in an annular array about a longitudinal axis of combustor  14 . 
   A substantially cylindrical flow sleeve  208  is concentrically mounted in combustion casings  216  and  217 . Flow sleeve  208  connects at its aft end to an outer wall  222  of double walled transition piece  207 . Compressor air K flows through an outer passage of double walled transition piece  207 , over and through flow sleeve  208 , and to the combustor  14  head end  210 . Flow sleeve  208  is coupled at its forward end by means of a radial flange  223  to aft combustor casing  217  at bolted joint  218  where forward combustion casing  216  and aft combustion casing  217  are joined. 
   In the exemplary embodiment, flow sleeve  208  is concentrically arranged with a combustor liner  209  that is connected at one end with an inner wall  224  of transition piece  207 . The opposite (forward or head) end of the combustor liner  209  is supported by a combustion liner cap assembly  225  which is, in turn, supported within the combustor casing by a plurality of struts (not shown) and an associated mounting flange assembly (not shown). Outer wall  222  of transition piece  207 , as well as a portion of flow sleeve  208  extending aft of the location at which aft combustion casing  217  is bolted to compressor discharge casing  220 , are formed with an array of apertures or inlet holes  206  over their respective peripheral surfaces to permit air to reverse flow from compressor  12  through apertures  206  into the annular space between flow sleeve  208  and combustor liner  209  toward the upstream or head end  210  of combustor  14  (as indicated by the flow arrows K). 
   Combustion liner cap assembly  225  supports a plurality of pre-mix tube assemblies  228 , one mounted concentrically about each fuel nozzle assembly  211  and  212 . Each pre-mix tube assembly  228  is supported within combustion liner cap assembly  225  at its forward and aft ends by a forward plate  229  and aft plate  230 , respectively, each provided with openings aligned with the open-ended pre-mix tube assemblies  228 . Each pre-mix tube assembly  228  comprises an assembly of two tubes separated by a pre-mix tube hula seal  231 , which permits the dual-tube assembly to change in length as combustion liner cap assembly  225  expands thermally from cold non-running conditions to hot operating conditions. In other words, as the distance between forward support plate  229  and aft support plate  230  changes due to thermal expansion of the overall assembly, the pre-mix tube assemblies  228  are free to expand accordingly along an axis of symmetry. 
   Aft plate  230  of combustion liner cap assembly  225  mounts to a plurality of forwardly extending floating collars  236  (one for each pre-mix tube assembly  228 , arranged in substantial alignment with the openings in aft plate  230 ), each of which supports an air swirler  237  (also referred to herein as a “swirling vane”) which is, for example, integrally formed in fuel nozzles  211  and  212  (also referred to herein as “fuel injection nozzles,” “fuel injectors,” or “fuel nozzle assemblies”). The arrangement is such that air flowing in the annular space between combustor liner  209  and flow sleeve  208  is forced to reverse direction at combustor inlet end  210  of combustor  14  (between end cover assembly  221  and combustion liner cap assembly  225 ) and to flow through air swirlers  237  and pre-mix tube assemblies  228 . Fuel passages integrally manufactured into each of air swirlers  237  deliver fuel through an arrangement of apertures that continuously introduce gas fuel, depending upon the operational mode of gas turbine engine assembly  10  into the passing air, thereby creating a fuel and air mixture that is subsequently and continuously ignited in combustion burning zone  213 . 
     FIG. 3  is a cross-sectional view of an exemplary fuel injection nozzle  211  shown in  FIG. 2 . Each fuel injector nozzle  211  includes a flange assembly  338  that attaches by a sealed and bolted joint assembly to the inside of end cover assembly  221  (shown in  FIG. 2 ). Fluids including, but not necessarily limited to gas fuel and purge air, are supplied to passages of gas fuel injection nozzle  211 . These fluids are supplied through flange assembly  238 , having previously passed through piping manifold assemblies (not shown). End cover assembly  221  is thus supplied with fuels and other working fluids that are delivered via fuel nozzle  211  in a precise fashion into combustion burning zone  213  (shown in  FIG. 2 ). A liquid fuel and water injection cartridge  390  attaches to the outside of end cover assembly  221  (shown in  FIG. 2 ). Liquid fuel and water injection cartridge  390  is installed within each outer gas fuel injection nozzle  211 . In some configurations that can burn liquid fuel as an alternative to gas fuel, a liquid fuel mode of operation is provided. This liquid fuel mode delivers sprays of liquid fuel and water into combustion burning zone  213  via liquid fuel and water injection cartridge  390 . 
   Gas fuel nozzle  11  includes a sheet metal screen or inlet flow conditioner  340  that has an array of holes and guide vanes that create a drop in pressure and provide directional guidance for incoming air supplied to combustor chamber inlet or head end  210 . Air that passes through inlet flow conditioner  340  is subsequently mixed with gas fuel through a plurality of swirling vanes  337 , each of which has integral passages leading to inner premix gas injection holes  341  (inner premixing holes) and outer premix gas injection holes  342  (outer premixing holes). Concentric tube assemblies  343  are arranged in fuel nozzle  211  to form independent fuel passages allowing control of fuel flow split between inner premix gas injection holes  341  and outer premix gas injection holes  342 . This inner and outer flow division of gas fuel in the outer fuel nozzle assemblies  211  allows direct control of the concentration distribution of premixed fuel and air as measured radially from a hub  344  of fuel nozzle  211  to a shroud  345  of fuel nozzle  211 . Methods used to actively or passively deliver a gas fuel supply that divides the gas fuel flow upstream prior to entering fuel nozzle flange assembly  338  between inner and outer premix passages can be selected as a design choice depending on design requirements of a specific gas turbine application. Methods that allow the concentration distribution of premixed air and fuel to be adjusted to a predetermined value within one or more fuel nozzles as a function of gas turbine engine system  10  operating conditions (such as the methods described herein) can be used to produce minimal NOx emissions along with minimal combustion dynamic pressures. 
   An additional annular passage  392  is formed by an inner diameter of wall  346  and an outer diameter  391  of liquid fuel and water injection cartridge  390  (or a blank counterpart, not shown, that does not pass fluid but occupies the same or an equivalent space). Annular passage  392  leads to an array of diffusion fuel metering holes  347 . Diffusion fuel metering holes  347  and annular passage  392  are supplied with gas fuel and enable the direct injection of gas fuel into combustion burning zone  213  and the production of a diffusion-type combustion flame that is stabilized in a recirculation zone  393  immediately downstream of fuel nozzle aft tip  348 . As a result, diffusion combustion can be used as a stabilization feature of the combustion system at ignition and low load conditions. Diffusion combustion as a stable pilot flame can be used with or without simultaneous premixed combustion in various desired combinations, all of which occurs in combustion burning zone  213  of combustor liner  209  downstream of aft plate  230  of combustion liner cap assembly  225 . 
     FIG. 4  is a series of schematic illustrations of various stages of an exemplary startup and loading sequence of dry low NO x  (DLN) combustor  14  illustrated with five outer fuel nozzle assemblies  211 . During a first stage  402  of the startup and loading sequence, combustor  14  is operating using diffusion combustion to warm-up the various gas path components of gas turbine engine system  10  from a cold iron to a warm condition. After a predetermined warm-up period, gas turbine engine system is accelerated to operating speed and the generator output breaker is synchronized and closed  404 . During a second stage  406 , water injection  408  is initiated to lower the amount of NO x  generated in combustor  14  such that NO 2  in exhaust duct  22  is maintained at a level less than that at which a yellow plume is visible, for example, less than fifteen parts per million (ppm). In the exemplary embodiment, during loading, a first fuel split schedule that incorporates water injection is used. Typically, the first fuel split is used only during loading ramp up and during those periods below approximately 50% load where, for operational needs, load may be held relatively constant for a period of time, for example, for testing, maintenance, and/or soaking. In an alternative embodiment, the first fuel schedule is used less than approximately 30% load. The first fuel schedule also determines an amount of water injected into combustor  14 , such that generally, as the fuel input to combustor  14  increases during ramp-up, the amount of water injected also increases, for example, but not limited to proportionally. 
   In the exemplary embodiment, at approximately 30% load, the fuel split schedule modifies  410  combustion in combustor  14  to a piloted premix combustion stage  412  up to approximately 50% load. At approximately 50% load combustion control is modified  414  to provide pre-mix steady state combustion for operation in a fourth stage  416 . Water injection is ramped down to substantially zero water injection and a second fuel split schedule may be automatically selected for operation up to 100% load. 
     FIG. 5  is a flow chart of an exemplary method  500  of reducing visible exhaust stack emissions that may be used with gas turbine engine system  10  (shown in  FIG. 1 ). 
   Low-emission method  500  for producing power using gas turbine engine  10  includes premixing  502  a plurality of fuel and air mixtures, injecting  504  the fuel and air mixtures into a combustion chamber using a plurality of fuel nozzles. Method  500  includes injecting  506  a quantity of water into the combustion chamber using the fuel nozzles during a relatively low power production stage of operation. In the exemplary embodiment, a variable frequency drive (VFD) pump coupled with flow and system pressure feedback for precise water to fuel/air ratio control is used. The VFD provides turndown of a supply of water to provide the low water flow used for the relatively low gas turbine load levels when water injection is used. Method  500  also includes automatically controlling a ratio of fuel and air, and water injected by at least one of the fuel nozzles to control a concentration of NO x  emissions exiting the gas turbine engine. Combustion water injection is used with the DLN combustion system to control the total amount of NO x  generated to a level where in the 0-50% load range even with 100% conversion of NO to NO 2 , the NO 2  level exiting the exhaust stack will not be visible while maintaining a stable flame with robust operability and durability in the combustion system. Water injection is used to reduce combustion dynamics due to flame instabilities. Due to the lower dynamics, more even fuel splits (uniform fuel distribution within the combustion chamber) can be obtained. One cause of high emissions during low load operations of a gas turbine is that there are local hot and cold spots inside the combustion chamber due to the uneven fuel distribution required to control dynamics. More even fuel splits reduce these hot and cold zones and the emissions generated by having equal amount of fuel come out of each fuel nozzle. A secondary benefit of more even fuel splits is more even heat loading on the combustion hardware, which increases durability. Therefore, it is the utilization of water injection that allows the design requirements of low NO x  and robust durability to be met at the same time. The water injection facilitates reducing NO, NO 2 , NO x , and combustion dynamics in any of diffusion, partially premixed, or fully premixed combustion system operating modes. 
   Method  500  includes operating a controller to provide two gas fuel split schedules, one for operation without water injection and one for operation with water injection. The first schedule allows the utilization of even gas fuel splits and controls the water injection so that there is minimum plume intensity without negatively affecting the combustion system hardware life. The second schedule is used as a backup should there be a trip of the water injection system. The controller is programmed to control the visibility of the exhaust plume by reducing stack exit NO 2  concentration to less than 15 ppm, which through testing is determined to be a visibility threshold. Additionally, although there are many factors that affect the visibility of a plume including stack diameter and background luminosity it is further determined that 30 ppm NO 2  concentration is a visible threshold between a light plume and a heavy plume. 
   The above-described methods and apparatus provide a cost-effective and reliable means for automatically and continuously modulating water injection into a DLN combustor during relatively low load periods, such as warm-up for a combined cycle power plant. The water injection is primarily used during diffusion, partially premixed, or fully premixed combustion system operating modes at power load levels where mitigation of visible emissions is desired. More specifically, the methods facilitate operation by reducing yellow plume during low power levels of low NO x  emissions combustion systems. As a result, the methods and systems described herein facilitate gas turbine engine operation in a cost-effective and reliable manner. 
   An exemplary methods and apparatus for reducing visible emissions from a gas turbine engine and controlling the fuel split schedule for fuel/air and water supplied to the gas turbine engine combustors are described above in detail. The apparatus illustrated is not limited to the specific embodiments described herein, but rather, components of each may be utilized independently and separately from other components described herein. Each system component can also be used in combination with other system components. 
   A technical effect of the method and apparatus is to provide a system that automatically and continuously modulates water injection to facilitate operation without a substantially visible exhaust plume. 
   While the invention has been described in terms of various specific embodiments, those skilled in the art will recognize that the invention can be practiced with modification within the spirit and scope of the claims.