Patent Publication Number: US-2015059353-A1

Title: Gas Turbine Combustion System

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a gas turbine combustion system. 
     2. Description of the Related Art 
     Researches are currently underway into an effective utilization of by-product gases, such as a coke oven gas produced as a by-product in iron works and an off-gas produced as a by-product in oil refineries, from the standpoints of, for example, reduction in power generation cost, effective utilization of resources, and prevention of global warming. In the integrated coal gasification combined cycle (IGCC) that generates power by gasifying coal as an abundantly available resource, measures are being studied that use a system for capturing and storing a carbon content in a gas fuel supplied to a gas turbine (carbon capture and storage (CCS)) to replace the carbon content in coal with hydrogen (H 2 ), thereby reducing a discharge amount of carbon dioxide (CO 2 ) (see, for example, JP-2013-139975-A). 
     SUMMARY OF THE INVENTION 
     A by-product gas, a coal-derived gas, or the like contains hydrogen. When such a gas fuel is used, an ignition failure can cause the gas fuel to be discharged unburned from a combustor, resulting in hydrogen being likely to enter a turbine. To prevent this from occurring, an operating method as follows may at times be employed: First, ignition is performed using a startup fuel not containing therein hydrogen (e.g. an oil fuel); Next, the fuel is switched under a partial load condition from the startup fuel to a gas fuel; Then, the number of burners that burns the gas fuel is then increased to thereby shift into a rated load condition. The IGCC plant also employs the above-described operating method in which a gas turbine is started using a startup fuel other than a coal-gasified gas, because a gasifier generates the coal-gasified gas using steam generated with gas turbine waste heat. 
     At timing immediately after a combustion mode is switched from a mode in which the gas fuel is burned with part of the burners (hereinafter, a partial combustion mode) to a mode in which the gas fuel is burned with all burners (hereinafter, a full combustion mode), however, a combustion area expands greatly relative to a rate of increase in a fuel flow rate; as a result, fuel concentration is temporarily reduced. While the fuel concentration is reduced, flame temperatures decrease to cause incomplete combustion of the gas fuel to occur, resulting in an increased discharge amount of unburned content such as CO and unburned hydrocarbon. In this case, the discharge amount of the unburned content may exceed environmental regulation values and, moreover, power output may be reduced. 
     It is an object of the present invention to provide a gas turbine combustion system capable of minimizing unburned content of a gas fuel under all load conditions from partial load to rated load. 
     To achieve the foregoing object, arrangements according to an aspect of the present invention temporarily reduce a combustor inlet air flow rate from a reference flow rate to a set flow rate when a combustion mode is switched from a partial combustion mode in which a gas fuel is burned using part of a plurality of gas fuel burners to a full combustion mode in which the gas fuel is burned using all of the gas fuel burners. 
     Effect of the Invention 
     The present invention can minimize the unburned content of the gas fuel under all load conditions from partial load to rated load. Thus, the discharge amount of, for example, CO and unburned hydrocarbon can be reduced even by using a gas fuel containing therein H 2  and CO. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present invention will be described hereinafter with reference to the accompanying drawings. 
         FIG. 1  is an exemplary configuration diagram showing a gas turbine plant that incorporates a gas turbine combustion system according to a first embodiment of the present invention; 
         FIG. 2  is a graph showing changes in an IGV opening degree, a combustor inlet air flow rate, a fuel flow rate, a fuel air ratio, and a combustion gas temperature during a period of time from a gas turbine startup to a rated load condition; 
         FIG. 3  is a control block diagram showing steps performed by a control system incorporated in the gas turbine combustion system according to the first embodiment of the present invention to output a command signal to an air flow rate adjusting system; 
         FIG. 4  is a diagram showing a relational curve between a local flame temperature of a main burner outer region and an unburned content discharge amount; 
         FIG. 5  is a diagram showing a relation between a main burner outer flame temperature and gas fuel composition required to keep the unburned content discharge amount equal to, or below, a specified value; 
         FIG. 6  is a diagram showing changes in various amounts including the unburned content discharge amount relative to gas turbine load; 
         FIG. 7  is an exemplary configuration diagram showing a gas turbine plant that incorporates a gas turbine combustion system according to a second embodiment of the present invention; and 
         FIG. 8  is an exemplary configuration diagram showing a gas turbine plant that incorporates a gas turbine combustion system according to a third embodiment of the present invention. 
     
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     Preferred embodiments of the present invention will be described below with reference to the accompanying drawings. 
     A gas turbine combustor according to an embodiment of the present invention is suitable for burning a gas fuel that contains therein hydrogen as a composition component (hereinafter referred to as a hydrogen containing fuel), in addition to ordinary gas fuels. Specifically, the gas turbine combustor according to the embodiment of the present invention is suitably applicable to, as follows: the integrated coal gasification combined cycle plant that uses the hydrogen containing fuel obtained through gasification of coal; a gas turbine that uses as its fuel a coke oven gas (COG), a blast furnace gas (BFG), a linter donawitz gas (LDG), which are produced as a by-product in iron works plants, or a mixed gas of the foregoing gases; or a gas turbine that uses a gas fuel containing hydrogen as a composition component (hydrogen containing fuel) such as a by-product gas obtained from, for example, naphtha cracking plants. 
     First Embodiment 
     1. Gas Turbine Plant 
       FIG. 1  is an exemplary configuration diagram showing a gas turbine plant that incorporates a gas turbine combustion system according to a first embodiment of the present invention. 
     The gas turbine plant  1  shown in  FIG. 1  includes a gas turbine and a generator  6  driven by the gas turbine. The gas turbine includes a compressor  2 , a gas turbine combustion system, and a turbine  4 . The compressor  2 , the turbine  4 , and the generator  6  each have a rotor connected coaxially with each other. The gas turbine combustion system, including a combustor  3  as one of its main components, will be described later. 
     Operation of the gas turbine plant  1  is as follows. Specifically, air  101  drawn in from the atmosphere is compressed by the air compressor  2  and compressed air  102  is supplied to the combustor  3 . The combustor  3  burns a gas fuel together with the compressed air  102  to thereby generate a combustion gas  110 . The turbine  4  is driven by the combustion gas  110  generated by the combustor  3 . The generator  6  is driven by rotatable driving power of the turbine  4 , thereby generating electric power. 
     2. Gas Turbine Combustion System 
     The gas turbine combustion system includes the combustor  3 , a liquid fuel supply system  71 , a gas fuel supply system  72 , an IGV  9 , and a control system  500 . Each of these components will be described in sequence below. 
     Combustor 
     The combustor  3  includes an outer casing  10 , a liner  12 , a transition piece (not shown), and a burner  8 . The outer casing  10  is a cylindrical member disposed on an outer peripheral portion of a turbine casing (not shown). The outer casing  10  has an end portion (a head portion) on a side opposite to the turbine  4  closed by an end cover  13 . The liner  12  is a cylindrical combustor inner casing that forms a combustion chamber  5  thereinside. Disposed inside the outer casing  10 , the liner  12  forms an annular air passage in a space between the liner  12  and the outer casing  10 . The liner  12  has a plurality of air holes drilled therein. The combustion chamber  5  assumes a space formed by the liner  12  between the burner  8  and the transition piece. Fuel jetted by the burner  8  is burned with air  102   a  in the combustion chamber  5 . The transition piece serves as a member that smoothly connects the line  12  to an inlet (an initial stator inlet) of a gas path of the turbine  4 . Fuel dividers  23  that distribute fuel to the burner  8  are disposed at the end cover  13 . The combustor  3  also has, though not shown, an ignitor that ignites a mixture of fuel and air in the combustion chamber  5 . The gas turbine plant  1  includes a plurality of combustors  3 , such as the combustor  3  as described above, disposed circumferentially at predetermined intervals on the outer peripheral portion of the turbine casing (not shown). 
     The burner  8  is disposed at the end cover  13  so as to be positioned between the end cover  13  and the combustion chamber  5 . The burner  8  includes a plurality of element burners that comprise one pilot burner  32  disposed at a center of the combustor  3 , surrounded by a plurality of main burners  33  disposed on the radial outside of the pilot burner  32 . 
     Each of the main burners  33  is a gas fuel burner and includes an air hole plate  20  and a plurality of fuel nozzles  22 . It is noted that the air hole plate  20  is connected to each of the air hole plates  20  of the main burners  33 . The air hole plate  20  is disposed such that a main surface (a surface with the largest area) thereof faces the combustion chamber  5 . The air hole plate  20  has a plurality of air holes  21  each extending from the end cover  13  in a direction toward the combustion chamber  5 . The air  102   a  is jetted from each of these air holes  21  into the combustion chamber  5 . Each of the fuel nozzles  22  is paired up with a corresponding one of the air holes  21  and extends from the fuel divider  23  so as to be coaxial with the corresponding one of air holes  21 . Each of the fuel nozzles  22  may have a leading end inserted in the air hole  21  (positioned inside the air hole  21 ). The first embodiment of the present invention is, however, arranged such that the fuel nozzle  22  has the leading end facing an inlet of the air hole  21  (has the leading end positioned on the side of the end cover  13  away from the air hole plate  20 ). The gas fuel jetted from the fuel nozzle  22  is jetted via the corresponding air hole  21  paired up with the fuel nozzle  22  into the combustion chamber  5  together with the air  102   a  that passes through the air hole  21 . In addition, in each of the main burners  33 , air holes  21  are arranged concentrically in a plurality of rows (in this example, three rows) about each burner axis. The air hole rows are denoted as a first-row air hole  51 , a second-row air hole  52 , and a third-row air hole  53  in sequence from the center of each main burner  33  radially outwardly. It is noted that, in the description that follows, the term “main burner inner periphery”, as used therein, refers to the first-row air hole  51  of each main burner  33  and the term “main burner outer periphery”, as used therein, refers to the second-row air hole  52  and the third-row air hole  53 . 
     The pilot burner  32  is a dual-fuel burner that burns both the gas fuel and a liquid fuel. The pilot burner  32  is disposed at the center of the main burners  33 . Specifically, the pilot burner  32  comprises a gas fuel burner section and a liquid fuel burner section. The gas fuel burner section is similar in construction to the main burner  33 , including an air hole plate and a plurality of fuel nozzles. The air hole plate has a plurality of air holes each being paired up with a corresponding one of the fuel nozzles. The gas fuel burner section differs from the main burner  33  in that the gas fuel burner section has two rows of air holes and that the air hole is inclined toward the side of the central axis of the combustor  3  toward the combustion chamber  5 . The liquid fuel burner section includes a liquid fuel nozzle (e.g. an oil nozzle)  40 . The liquid fuel burner section is disposed at the center of the gas fuel burner section (center of the air hole rows in the gas fuel burner section). 
     Liquid Fuel Supply System 
     The liquid fuel supply system  71  supplies the liquid fuel to the liquid fuel nozzle  40  of the pilot burner  32 . The liquid fuel supply system  71  includes a liquid fuel source  210 , a shut-off valve  65 , and a fuel control valve  66 . The liquid fuel source  210  supplies an oil fuel such as gas oil, kerosene, or heavy oil A as the startup fuel. The liquid fuel source  210  is connected to the liquid fuel nozzle  40  via a line  204 . The shut-off valve  65  and the fuel control valve  66  are disposed in the line  204 . The shut-off valve  65  and the fuel control valve  66  are driven by signals from the control system  500  so as to be opened to varying degrees and closed. 
     Gas Fuel Supply System 
     The gas fuel supply system  72  supplies the gas fuel to the gas fuel burner section of the pilot burner  32  and each of the main burners  33 . The gas fuel supply system  72  includes a gas fuel source  200 , a shut-off valve  60 , and fuel control valves  61  to  63 . The gas fuel source  200  supplies a fuel that contains hydrogen or carbon monoxide, such as the coke oven gas, the off-gas produced as a by-product in oil refineries, and the coal-gasified gas. The line through which the gas fuel is passed from the gas fuel source  200  is branched into three lines  201  to  203 . The line  201  is connected to the fuel divider  23  of the gas fuel burner section of the pilot burner  32 . The line  202  is connected to the fuel divider  23  of the main burner inner periphery of each main burner  33 . The line  203  is connected to the fuel divider  23  of the main burner outer periphery of each main burner  33 . The shut-off valve  60  is disposed in the line before the branch. The fuel control valves  61  to  63  are disposed in the lines  201  to  203 , respectively. The shut-off valve  60  and the fuel control valves  61  to  63  are driven by signals from the control system  500  so as to be opened to varying degrees and closed. Opening or closing and adjusting the opening degree of the fuel control valves  61  to  63  varies the ratio of the gas fuel supplied to the pilot burner  32  and to the main burner outer periphery and the main burner inner periphery of each main burner  33 . 
     Additionally, a gas measuring system  400  and a gas temperature measuring system  601  are disposed in the line between the gas fuel source  200  and the shut-off valve  60 . The gas measuring system  400  measures composition and the heating value of the gas fuel supplied from the gas fuel source  200 . In the first embodiment of the present invention, the gas measuring system  400  measures concentration of hydrogen, carbon monoxide, methane, carbon dioxide, and nitrogen and the heating value based on the measured values. The gas temperature measuring system  601  is exemplarily a thermocouple that measures temperature of the gas fuel. In the first embodiment, the gas temperature measuring system  601  is disposed midway in a line extending to the gas measuring system  400  from a point in the line between the gas fuel source  200  and the shut-off valve  60 . 
     IGV 
     The inlet guide vane (IGV)  9  assumes an inlet guide vane disposed at an inlet of the compressor  2 . In the first embodiment of the present invention, the IGV  9  functions as an air flow rate adjusting system that adjusts the flow rate of air to be mixed with the gas fuel in the combustor  3 . Varying the opening degree of the IGV  9  adjusts the flow rate of the air  101  drawn in the compressor  2 . This results in the air flow rate supplied to the combustor  3  being adjusted. 
     Control System 
     The control system  500  controls the shut-off valves  60 ,  65 , the fuel control valves  61  to  63 ,  66 , and the IGV  9  based on measurements taken by a power measuring system  602 , an air temperature measuring system  603 , an air flow rate measuring system  604 , the gas temperature measuring system  601 , and the gas measuring system  400 . The control system  500  includes a storage that stores therein programs and data required for controlling the shut-off valves  60 ,  65 , the fuel control valves  61  to  63 ,  66 , and the IGV  9  and a storage that stores therein control histories (opening degree histories) of the shut-off valves  60 ,  65 , the fuel control valves  61  to  63 ,  66 , and the IGV  9 . Specifically, when a combustion mode is switched from a partial combustion mode in which the gas fuel is burned using part of the gas fuel burners to a full combustion mode in which the gas fuel is burned using all of the gas fuel burners, the control system  500  outputs a signal to the IGV  9  to thereby temporarily reduce the air flow rate from a reference flow rate to a set flow rate. 
     The term “partial combustion mode” refers to a combustion mode in which the gas fuel is burned with at least one line of the lines  201  to  203  closed. Examples of the partial combustion mode include a condition in which the lines  202  and  203  are closed to thereby distribute the gas fuel only to the pilot burner  32  and a condition in which the line  203  is closed to thereby distribute the gas fuel only to the pilot burner  32  and the main burner inner periphery of each main burner  33 . In contrast, the term “full combustion mode” refers to a combustion mode in which all of the lines  201  to  203  are open to thereby cause the gas fuel to be jetted from the pilot burner  32  and the main burner inner peripheries and the main burner outer peripheries of all main burners  33 . Additionally, the term “reference flow rate” refers to a value set in consideration of preventing a surge and icing from occurring in the compressor  2  under the partial load condition. The term “set flow rate” refers to a value calculated by the control system  500  based on the composition and the temperature of the gas fuel measured with the gas measuring system  400  and the gas temperature measuring system  601 , respectively, with the aim of minimizing a difference in a local fuel air ratio near a burner end face when the combustion mode is switched from the partial combustion mode to the full combustion mode. 
     3. Operation 
       FIG. 2  is a graph showing changes in an IGV opening degree, a combustor inlet air flow rate, a fuel flow rate, a fuel air ratio, and a combustion gas temperature during a period of time from a gas turbine startup to a rated load condition. The sketches in the uppermost row of  FIG. 2  show burners operated in different combustion modes by being filled with black. 
     The process from the startup to the rated load condition may generally be classified into six steps of (a) to (f) as specified below. 
     (a) Gas turbine startup 
     (b) Full speed no load (FSNL) 
     (c) Fuel changeover (from the liquid fuel to the gas fuel) 
     (d) Gas-fired combustion mode changeover (from the partial combustion mode to the full combustion mode) 
     (e) IGV opening degree increased through exhaust gas temperature control setting 
     (f) Rated load condition 
     Each of the above-referenced steps will be described below. 
     (a) to (b): Gas Turbine Startup to FSNL 
     The control system  500  outputs a signal to a startup motor (not shown), so that the gas turbine can be started by the startup motor. When a gas turbine speed thereafter increases to a value that satisfies an ignition condition, the control system  500  outputs signals to the shut-off valve  65  and the fuel control valve  66  to thereby supply the liquid fuel nozzle  40  with the liquid fuel, thus igniting the combustor  3 . An operating range from the gas turbine startup to loading start (power generation start) is called an acceleration zone. In the acceleration zone, the control system  500  outputs signals to the IGV  9  and the fuel control valve  66  and increases the opening degree of the fuel control valve  66  until the turbine speed reaches a predetermined value, while maintaining the opening degree of the IGV  9  at a constant value. This increases the fuel air ratio together with the fuel flow rate, and accordingly the gas temperature at the combustor exit increases. 
     When the turbine speed reaches the predetermined value, the control system  500  outputs a signal to the IGV  9  to thereby increase the opening degree of the IGV  9  to a reference opening degree. As the fuel flow rate thereafter increases, the gas turbine speed reaches the full speed no load (FSNL). When the air flow rate reaches a reference flow rate (the IGV opening degree reaches the reference opening degree), the control system  500  outputs a signal to the generator  6  to thereby start taking the load (start generating electric power). 
     The term “reference opening degree”, as used herein, refers to the IGV opening degree for achieving the abovementioned reference flow rate. The “reference opening degree” is specified so that a surge or icing does not occur in the compressor  2  under the partial load condition. Surge is a phenomenon in which the compressor  2  operates erratically at any given pressure ratio involving pressure fluctuations occurring with sudden loud acoustics, severe pulsations of the air flow, and mechanical vibrations, when the pressure ratio of the compressor  2  is increased. Icing is a phenomenon in which, when the opening degree of the IGV  9  is reduced under a condition of a low ambient temperature, the liquid temperature decreases with an increasing exit speed (Mach number) of the IGV  9 , causing moisture content in the atmosphere to freeze. When icing occurs, the solidified moisture content (block of ice) can collide with and damage vanes of the compressor  2 . 
     (b) to (c): FSNL to Fuel Changeover 
     When the FSNL is reached, the control system  500  causes the generator  6  to take load and the operation range is a load-up zone. In the load-up zone, the control system  500  maintains a constant opening degree of the IGV  9  (reference opening degree) and keeps the combustor inlet air flow rate constant (reference flow rate). During this time, the fuel flow rate increases with the load to thereby increase the fuel air ratio, which increases a combustor exit gas temperature. The load is increased and the specified partial load condition ((c) in  FIG. 2 ) is reached at which the fuel is switched from the startup liquid fuel to the gas fuel. 
     (c) to (d): Fuel Changeover to Gas-Fired Combustion Mode Changeover 
     When the specified partial load condition is reached, the control system  500  outputs signals to the shut-off valves  60 ,  65  and the fuel control valves  61 ,  62 ,  66  to thereby increase the flow rate of the gas fuel to the pilot burner  32  and the main burner inner periphery, while decreasing the flow rate of the liquid fuel, thereby changing the fuel from the liquid fuel to the gas fuel. The combustion mode after the changeover is the partial combustion mode using the pilot burner  32  and the main burner inner periphery only. In the operating range by the partial combustion mode, the control system  500  maintains the IGV opening degree at the reference opening degree and the combustor inlet air flow rate at the reference flow rate. During the operation in the partial combustion mode, the control system  500  increases the gas fuel flow rate in response to a load increase and the combustor exit gas temperature increases with the increasing fuel air ratio. 
     (d) to (e): Gas-Fired Combustion Mode Changeover to IGV Opening Degree Increase 
     When the specified partial load condition (d) to change over the combustion mode is reached, the control system  500  outputs signals to the fuel control valves  61  to  63  to thereby distribute the gas fuel to the main burner outer periphery in addition to the pilot burner  32  and the main burner inner periphery, thus changing the combustion mode from the partial combustion mode to the full combustion mode. To change the combustion mode to the full combustion mode, the control system  500  outputs a signal to the IGV  9  and reduces the IGV opening degree from the reference opening degree (only by ΔIGV) to the set opening degree, thereby temporarily decreasing the combustor inlet air flow rate. The control system  500  thereafter gradually returns the IGV opening degree from the set opening degree to the reference opening degree to thereby return the combustor inlet air flow rate to the reference flow rate. During this time, the control system  500  increases the gas fuel flow rate according as the load increases. 
     (e) to (f): IGV Opening Degree Increase to Rated Load Condition 
     When the combustor exit gas temperature thereafter increases with the increasing load, the condition (e) is reached in which the turbine exhaust gas temperature exceeds a limit value. When the condition (e) is reached, the control system  500  increases the opening degree of the IGV  9  further from the reference opening degree and controls the combustor exit gas temperature to thereby keep the exhaust gas temperature equal to, or below, the limit value. With the load reaching 100%, the operating condition shifts to the rated load condition. Of the load-up zone, the range excluding the rated load condition (load 100%) is called a partial load range. 
     Reference is now made to  FIG. 3  that is a control block diagram showing steps performed by the control system  500  to output a command signal to the air flow rate adjusting system. 
     The IGV opening degree needs to be reduced from the reference opening degree IGV 0  to the set opening degree IGV′ immediately after the combustion mode is switched from the partial combustion mode to the full combustion mode. The changeover of the combustion mode is triggered by the gas turbine load reaching the above condition (d). Thus, the control system  500 , when having determined based on measurements taken by the power measuring system  602  that the gas turbine load reaches the condition (d), starts controlling an IGV opening degree variation command. 
     The control system  500 , having started controlling the IGV opening degree variation command, inputs the concentration of the unburned content in the gas fuel measured by the gas measuring system  400  and the temperature of the gas fuel measured by the gas temperature measuring system  601 . The concentration of the unburned content to be here input refers to concentration of a component to be controlled so as not to be discharged unburned from the combustor  3 , specifically, to the concentration of hydrogen or carbon monoxide, but still including the concentration of methane, carbon dioxide, nitrogen, and the like. The control system  500  stores therein in advance a relational curve between a local flame temperature of a main burner outer region and an unburned content discharge amount (see  FIG. 4 ). According to this relation, the control system  500  calculates a main burner outer region local flame temperature Tr that satisfies an unburned content discharge amount specified value Unburn(r), the calculation being based on the input value of the unburned content concentration. Strictly speaking, the specified flame temperature Tr varies depending on the fuel temperature, as well as depending on the concentration of the unburned content contained in the gas fuel.  FIG. 5  is a diagram showing a relation between a main burner outer flame temperature and gas fuel composition required to keep the unburned content discharge amount equal to, or below, a specified value. As shown in  FIG. 5 , the higher the unburned content concentration of the gas fuel or the lower a fuel temperature Tf (Tf 1 &lt;Tf 2 &lt;Tf 3 ), the higher the specified flame temperature Tr that satisfies the unburned content discharge amount specified value Unburn(r). Therefore, the control system  500  preferably stores therein in the form of a table the relation between the main burner outer region local flame temperature and the unburned content discharge amount for each fuel temperature so that the control system  500  can calculate the main burner outer region local flame temperature Tr based on the input values of the unburned content concentration and the fuel temperature. 
     Next, based on the current fuel composition, fuel temperature, and air temperature input from the gas measuring system  400 , the gas temperature measuring system  601 , and the air temperature measuring system  603 , and the calculated main burner outer region local flame temperature Tr, the control system  500  calculates a local fuel air ratio (F/A)r in an area near the main burner outer periphery end face for achieving the main burner outer region local flame temperature Tr. Then, the control system  500  calculates an air flow rate Ar required for achieving the main burner outer region local flame temperature Tr from (F/A)r and the opening degree of the current gas fuel flow rate (fuel control valves  61  to  63 ). 
     Finally, the control system  500  compares Ar with the current air flow rate and calculates, based on the relation between the IGV opening degree and the air flow rate, a variation ΔIGV in the IGV opening degree. At this time, ΔIGV is limited by an IGV critical opening degree (a minimum reduction amount) in order to avoid occurrence of a surge or icing occurring due to an excessive reduction in the IGV opening degree. The control system  500  then calculates, based on the calculated ΔIGV, a command value that results in the IGV opening degree being the set opening degree IGV′ (=IGV 0 −ΔIGV) and outputs a command signal to the IGV  9 . This causes the opening degree of the IGV  9  to be reduced to the set opening degree IGV′, so that the air flow rate is reduced to the set flow rate. The control system  500  thereafter repeatedly performs the steps shown in  FIG. 3 . Through the repeated performance of the steps shown in  FIG. 3 , the fuel air ratio in the main burner outer region increases and the calculated set opening degree IGV′ gradually approaches the reference opening degree IGV 0 . Specifically, the set opening degree IGV′ does not remain constant. When the IGV opening degree returns to the reference opening degree IGV 0  as a result of the control of the IGV opening degree, the control system  500  terminates the process of  FIG. 3 . The control system  500  then increases the fuel flow rate, while maintaining the IGV opening degree at the reference opening degree IGV 0 , and increases the IGV opening degree by way of the condition (e) as described earlier to thereby shift to the rated load condition. 
     4. Effects 
       FIG. 6  is a diagram showing changes in various amounts including the unburned content discharge amount relative to gas turbine load.  FIG. 6  also shows, for comparison purposes, a case in which the combustor inlet air flow rate is maintained at the reference flow rate when the combustion mode is shifted to the full combustion mode. In  FIG. 6 , operations common to the first embodiment and the case being compared are indicated by the broken line, while those unique to the first embodiment changing differently from the case being compared are indicated by the solid line.  FIG. 6  shows changes in the IGV opening degree, the unburned content discharge amount, the fuel flow rate, the fuel air ratio, and the local flame temperature at each burner region for the period of time from the startup of the gas turbine to the rated load condition. 
     First, attention is focused on the case in which the combustor inlet air flow rate is maintained at the reference flow rate when the combustion mode is shifted to the full combustion mode.  FIG. 6  shows that the unburned content discharge amount increases sharply when the gas-fired combustion mode is switched from the partial combustion mode to the full combustion mode (d). The unburned content discharge amount remains for some while thereafter large, though decreasing at a mild pace with increasing load, and may exceed an environmental regulation value. As the load further increases thereafter, the unburned content discharge amount starts decreasing under a certain condition and thereafter remains small before reaching the rated load condition. 
     The following is a possible reason for the increase in the unburned content discharge amount when the reference flow rate is maintained upon the shift to the full combustion mode. Specifically, when the combustion mode is switched to the full combustion mode, the fuel flow rate is distributed to each burner substantially at the rate shown in  FIG. 6 . As shown in  FIG. 6 , the fuel air ratio of the main burner outer region at timing soon after the start of fuel supply is lower than that of the pilot burner and the main burner inner periphery, and the main burner outer region local flame temperature remains lower than others for some while. As a result, the gas fuel jetted from the main burner outer periphery is not completely burned; part of the gas fuel is discharged as unburned fuel. Additionally, the gas fuel, because of CO contained therein, tends to discharge unburned content more than commonly used fuels, such as natural gas, do. When the load increases, the fuel flow rate increases. When the main burner outer region local flame temperature increases to a level (T 0  in  FIG. 6 ) or higher, the gas fuel starts to burn completely even in the main burner outer region, which reduces the unburned content discharge amount. 
     In contrast, in the first embodiment of the present invention, when the combustion mode is shifted to the full combustion mode, the IGV opening degree is adjusted to reduce the air flow rate as indicated by the solid line in  FIG. 6 . This maintains the main burner outer region local flame temperature at Tr or higher to thereby reduce the unburned content discharge amount. Thus, even when the gas fuel that contains H 2  and CO is used, the unburned content of the gas fuel can be prevented from being discharged under all load conditions from partial load to rated load. Thus, the unburned content discharge amount can be prevented from exceeding the environmental regulation value and electric power output can be prevented from being reduced. 
     The gas fuel in the first embodiment of the present invention contains as its main components hydrogen (H 2 ) and carbon monoxide (CO) and exhibits a burning speed faster than that of the natural gas (containing methane as its main component) commonly used in gas turbines. This results in flame at high temperatures being formed in an area near the burner end face inside the combustion chamber  5 . Considering such a characteristic, the first embodiment of the present invention employs a burner configuration that includes a plurality of pairs of fuel nozzles  22  and air holes  21 . Fuel streams covered in air flows via the air holes  21  are jetted into the combustion chamber  5 , thereby mix fuel and air with each other through a sudden expansion of flow passage. This enables uniform combustion of the gas fuel in the combustion chamber, while enhancing dispersion of the fuel. The flame at high temperatures can thereby be prevented from being formed and a burner metal temperature can be prevented from increasing. The arrangement also contributes to reduction in a NOx discharge amount. 
     The set opening degree IGV′ that can keep the unburned content discharge amount at Unburn(r) is calculated based on the measurements taken by the gas measuring system  400  and the gas temperature measuring system  601 . This allows the unburned content discharge amount to be reduced reasonably. 
     The ratio of the gas fuel supplied to each burner zone can be varied using the fuel control valves  61  to  63 . Thus, by increasing the fuel flow rate in the main burner outer region, the main burner outer region local flame temperature can be efficiently increased to thereby efficiently reduce the unburned content discharge amount. The foregoing further contributes to prevention of uneven fuel flow rate. 
     The pilot burner  32  disposed at the center of the main burners  33  is a dual-fuel burner that burns both the gas fuel and the liquid fuel. This allows fuel to be jetted from an area near the burner center even after the fuel has been switched to the gas fuel, thus maintaining homogeneity of combustion. 
     Second Embodiment 
       FIG. 7  is an exemplary configuration diagram showing a gas turbine plant that incorporates a gas turbine combustion system according to a second embodiment of the present invention. In  FIG. 7 , like or corresponding parts are identified by the same reference numerals as those used in the first embodiment of the present invention and descriptions for those parts will not be duplicated. 
     The second embodiment of the present invention differs from the first embodiment in that a bleed adjusting valve  11  of an inlet bleed heat (IBH) system that returns the compressed air  102  compressed by the compressor  2  to the inlet of the compressor  2  constitutes the air flow rate adjusting system. The IBH system increases the temperature of the compressed air  102  and reduces the air flow rate by returning part of the compressed air  102  to the inlet of the compressor  2 . The IBH system achieves an effect equivalent to that achieved by the IGV. The bleed adjusting valve  11  adjusts the flow rate returning to the inlet of the compressor  2 . The second embodiment is configured such that the control system  500  adjusts the opening degree of the bleed adjusting valve  11 , instead of the IGV  9 . The opening degree of the bleed adjusting valve  11  is controlled so as to adjust the combustor inlet air flow rate as shown in  FIG. 2 . The second embodiment is otherwise configured similarly to the first embodiment. 
     As with the first embodiment, the second embodiment also allows the flow rate of the compressed air  102  to be reduced by increasing the opening degree of the bleed adjusting valve  11  when the combustion mode is shifted to the full combustion mode. Thus, the second embodiment achieves the same effects as those achieved by the first embodiment. 
     Third Embodiment 
       FIG. 8  is an exemplary configuration diagram showing a gas turbine plant that incorporates a gas turbine combustion system according to a third embodiment of the present invention. In  FIG. 8 , like or corresponding parts are identified by the same reference numerals as those used in the first embodiment of the present invention and descriptions for those parts will not be duplicated. 
     The third embodiment of the present invention differs from the first and second embodiments in that a bleed adjusting valve  14  constitutes the air flow rate adjusting system, the bleed adjusting valve  14  being disposed in a bypass system that bypasses air bled from the compressor  2  to the turbine  4 . The bypass system bleeds part of the compressed air as cooling air for cooling parts that are hot in the turbine  4 . The combustor inlet air flow rate can be controlled as shown in  FIG. 2  by adjusting the opening degree of the bleed adjusting valve  14 . An IGV  9  or an IBH, though not shown in  FIG. 8 , may be disposed in the gas turbine according to the third embodiment. In this case, in the partial load operation, the opening degree of the IGV  9  or the bleed adjusting valve  11  is maintained at the reference opening degree in the operating zone by the partial combustion mode and the full combustion mode. The bleed adjusting valve  14  is controlled as a device for reducing the combustor inlet air flow rate from the reference flow rate IGV 0  to the set flow rate IGV′. The third embodiment is otherwise configured similarly to the first or second embodiment. 
     In the third embodiment, too, similar effects as those achieved by the first or second embodiment can be achieved. In addition, the combustor inlet air flow rate is reduced when the combustion mode is shifted to the full combustion mode so that the turbine cooling air flow rate increases at timing at which the burner zone local flame temperature increases. This reduces a pace at which the metal temperature increases. 
     Miscellaneous 
     Each of the first to third embodiments of the present invention has been exemplarily described for a case in which the present invention is applied to the gas turbine combustion system that uses the gas fuel containing as its main components hydrogen (H 2 ) and carbon monoxide (CO), such as the coke oven gas, the off-gas produced as a by-product in oil refineries, and the coal-gasified gas. Understandably, other type of gas fuel including the natural gas can be used as the gas fuel. Additionally, although the embodiments have been exemplarily described for a case in which the liquid fuel is used as the startup fuel, a gas fuel such as natural gas or propane may even be used for the startup fuel. In this case, the pilot burner does not necessarily have to be a dual burner. 
     The embodiments have been exemplarily described for a case in which the present invention is applied to the gas turbine combustion system having a burner configuration that includes a plurality of pairs of fuel nozzles  22  and air holes  21  and a plurality of fuel streams covered in air flows via the air holes  21  is jetted into the combustion chamber  5 . Nonetheless, the present invention can be applied also to a gas turbine combustion system including a main burner operating on another combustion system, such as a common premixed combustion system burner. 
     In addition, an arrangement has been exemplified in which the set flow rate is calculated based on the input signals from the gas measuring system  400  and the gas temperature measuring system  601  and the combustor inlet air flow rate is reduced from the reference flow rate to the set flow rate. The set flow rate may nonetheless be controlled along a predetermined operating line. In that sense, the set flow rate does not necessarily have to be calculated based on the input signals from the gas measuring system  400  and the gas temperature measuring system  601  when the combustion mode is switched to the full combustion mode. Moreover, values measured by the gas measuring system  400  and the gas temperature measuring system  601  may still be used as a basis for calculating the set flow rate. Further, the input value from, for example, the power measuring system  602 , the air temperature measuring system  603 , and the air flow rate measuring system  604  does not necessarily have to be used as the basis for calculating the set flow rate. 
     The embodiments have been described for a case in which the present invention is applied to a one-shaft simple-cycle gas turbine. Nonetheless, the present invention can also be applied to a gas turbine operating on another operating principle, such as a two-shaft gas turbine, a combined cycle power generating system, advanced humid air turbine (AHAT), and a regenerative cycle gas turbine that heats compressor outlet air with turbine exhaust gas.