Abstract:
A hybrid power plant system including a gas turbine system and a coal fired boiler system inputs high oxygen content gas turbine flue gas into the coal fired boiler system, said gas turbine flue gas also including carbon dioxide that is desired to be captured rather than released to the atmosphere. Oxygen in the gas turbine flue gas is consumed in the coal fired boiler, resulting in relatively low oxygen content boiler flue gas stream to be processed. Carbon dioxide, originally included in the gas turbine flue gas, is subsequently captured by the post combustion capture apparatus of the coal fired boiler system, along with carbon diode generated by the burning of coal. The supply of gas turbine flue gas which is input into the boiler system is controlled using dampers and/or fans by a controller based on an oxygen sensor measurement and one or more flow rate measurements.

Description:
FIELD 
       [0001]    The present application relates to power plant methods and apparatus, more particularly, to methods and apparatus for reducing CO2 intensity. 
       BACKGROUND 
       [0002]    Power plants burning fossil fuels are large emitters of carbon dioxide. Coal and natural gas are the most widely used fossil fuels for power generation worldwide and in the US. When burned, coal of various types releases more CO2 per unit electricity generated than other fossil fuels including natural gas. As a result, coal-fired power plants have the highest CO2 intensity (CO2 emissions per unit of electricity output) of all thermal power plants. 
         [0003]    On the other hand, natural gas-fired, combustion turbine based power plants have lower CO2 intensity than coal-fired plants. However, gas turbine (GT) exhaust typically has low CO2 concentration (4-5% vol) and high oxygen concentration (13-14% vol), compared to 12-13% CO2 and 5-6% oxygen for typical coal-fired power plants. The low CO2 concentration of GT exhaust can lead to large equipment size and capital investment, and high oxygen concentration can result in accelerated degradation of the CO2 solvent and increased operating cost, for a post-combustion CO2 capture (PCC) system for a gas-fired combustion turbine based power plant. 
         [0004]    Based on the above discussion, there is a need for new methods and apparatus for reducing CO2 intensity with regard to exhaust gases generated in a gas fired combustion turbine. 
       SUMMARY 
       [0005]    Various embodiments, in accordance with the present invention, include the integration of GT exhaust with a coal-fired boiler, and by doing so utilize the remaining oxygen in the GT exhaust. Various exemplary embodiments are directed to an integrated GT-Boiler system. The exhaust gas from the integrated GT-Boiler system will have similar O2 and CO2 concentrations as those from typical coal-fired power plants, which can be more cost effectively captured with available CO2 absorption technology. 
         [0006]    The integration of the GT and boiler, in accordance with the present invention, also effectively utilizes the waste heat of the GT exhaust. Therefore an exemplary novel integrated system, in accordance with the present invention, has higher plant efficiency than the combined efficiency of a standalone coal-fired power plant and a standalone natural gas-fired GT power plant. 
         [0007]    An exemplary proposed integrated system, in accordance with the present invention, reduces the CO2 intensity of the power plant by the above mentioned thermal efficiency improvement and also by utilizing natural gas which emits less CO2 per unit heating value than coal. 
         [0008]    In a first configuration, in accordance with the present invention, the GT exhaust first goes through a heat recovery steam generator (HRSG). This exhaust after the HRSG of a gas turbine combined cycle plant (GTCC) is relatively cool (typically around 200 F) and can be, and in various embodiment is, introduced into a plurality of areas of a coal-fired power plant. For example in one exemplary embodiment in accordance with the first configuration, five streams of relatively cool HRSG output exhaust are introduced into five different locations in a coal fired power plant. This first configuration utilizes the oxygen and low grade waste heat in the GTCC exhaust gas. The resulted flue gas from the boiler power plant can be, and is, effectively treated in a CO2 absorption process for CO2 capture. 
         [0009]    In a second configuration, in accordance with the present invention, hot exhaust gas directly from a simple cycle gas turbine (GT), without going through a HRSG, is injected into the boiler plant, e.g., a coal-fired boiler plant. This exhaust gas from the GT, with temperature typically in the 900-1150 F range, is injected in streams, e.g., four streams, into the boiler plant, with the injection points being at selected locations where such high temperature and partially oxygen-depleted gas can be effectively utilized in the boiler. Essentially, this second configuration utilizes the existing boiler as the heat recovery unit instead of a having a new, separately installed HRSG as the heat recovery unit. This second configuration utilizes the oxygen and the high temperature waste heat in the simple cycle GT exhaust gas, without the need of a separate HRSG. The resulting flue gas from the boiler power plant can be effectively treated in a CO2 absorption process for CO2 capture. 
         [0010]    In various embodiments, oxygen rich exhaust gas from a gas turbine is injected into a coal fired boiler system, said exhaust gas from the gas turbine including carbon dioxide that is desired to be captured. Oxygen in the gas turbine exhaust gas is consumed in the coal-fired boiler, and the CO2, originally from the gas turbine exhaust, is output into the flue gas from the boiler. The CO2, originally from the gas turbine exhaust, is captured within a PCC system, along with CO2 generated from the burning of coal. It should be appreciated that the flue gas being processed by the PCC has a lower oxygen content than the flue gas output from the gas turbine, facilitating a more efficient and less expensive capture of the gas turbine generated CO2. 
         [0011]    In some embodiments, heat energy within the gas turbine exhaust gas is captured using a post gas turbine HRSG. In some embodiments, heat energy within the gas turbine exhaust gas is used to heat inlet gas flows pertaining to the coal fired system. Thus the integrated natural gas turbine-coal fired boiler power plant system utilizes this energy to generate power, which might have been otherwise lost and wasted. 
         [0012]    Various features, methods, apparatus and/or embodiments, in accordance with the present invention, can be applied to any power plants where there is (are) existing gas turbine unit(s) in the vicinity of coal-fired units, or power plants where there is space for building new GT or GTCC unit(s) that are integrated with the coal-fired units. The proposed integration of GT and boiler is an effective way to reduce carbon intensity and extending the service life of existing coal power plants, which, with a total installed capacity of over 300 GW, generates more power than any other types of power plants in the U.S. 
         [0013]    An exemplary power system in accordance with some embodiments includes: a boiler system including: a boiler; an oxygen sensor; one or more gas turbine flue gas inputs including at least one of: i) a gas turbine flue gas boiler hopper input of said boiler or ii) a gas turbine flue gas mill air supply duct input which is included as part of a mill air supply duct which supplies air to a mill which provides fuel to said boiler; a gas turbine system; and a controller for controlling the supply of gas turbine flue gas to said one or more gas turbine flue gas inputs of said boiler system based on an oxygen level measured by said oxygen sensor. 
         [0014]    An exemplary method of operating a system including a boiler system and a gas turbine system, the boiler system including a boiler, the turbine system including a gas turbine, in accordance with some embodiments, comprises: measuring an oxygen level in flue gas output by the boiler; operating a controller, during a first mode of operation during which said boiler is active and said gas turbine is active, to control the supply of gas turbine flue gas to a first gas turbine flue gas input of said boiler system based on the measured oxygen level, said first flue gas input being one of: i) a gas turbine flue gas boiler hopper input of a boiler, ii) a gas turbine flue gas burner air supply duct input which supplies air to a burner of said boiler, or iii) a gas turbine flue gas mill air supply duct input which is included as part of a mill air supply duct which supplies air to a mill which provides fuel to said boiler. 
         [0015]    Numerous additional features, embodiments and benefits of the various embodiments are discussed in the detailed description which follows. While various embodiments have been discussed in the summary above, it should be appreciated that not necessarily all embodiments include the same features and some of the features described above are not necessary but can be desirable in some embodiments. 
     
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         [0016]      FIG. 1  is a drawing of an exemplary integrated gas turbine-coal fired boiler system, in which cold gas turbine exhaust output from a heat recovery steam generator is injected into boiler related flows in accordance with an exemplary embodiment. 
           [0017]      FIG. 2  is a drawing of an exemplary integrated gas turbine-coal fired boiler system, in which hot gas turbine exhaust is injected into boiler related flows in accordance with an exemplary embodiment. 
           [0018]      FIG. 3A  is a first part of a flowchart of an exemplary method of operating a system including a boiler system and a gas turbine system in accordance with an exemplary embodiment. 
           [0019]      FIG. 3B  is a second part of a flowchart of an exemplary method of operating a system including a boiler system and a gas turbine system in accordance with an exemplary embodiment. 
           [0020]      FIG. 3  comprises the combination of  FIG. 3A  and  FIG. 3B . 
       
    
    
     DETAILED DESCRIPTION 
       [0021]      FIG. 1  is a drawing of an exemplary integrated gas turbine-boiler power plant system  100  in accordance with an exemplary embodiment. Exemplary power plant system  100  includes a boiler system  103  including a boiler  104  and a gas turbine system  109  including a gas turbine  126 . Exemplary system  100  includes mills  102 , a boiler  104 , a selective catalytic reduction (SCR) apparatus  106 , an air heater (AH)  108 , an electrostatic precipitator/fabric filter (ESP/FF)  110 , an induced draft (ID) fan  112 , a flue-gas desulfurization (FGD) apparatus  114 , a post-combustion capture (PCC) apparatus  116 , a first stack  118 , a first damper  120 , a forced draft (FD) fan  122 , a primary air (PA) fan  124 , a gas turbine (GT)  126 , a HRSG  128 , a booster fan  130 , a second damper  134 , a third damper  136 , a fourth damper  138 , a fifth damper  140 , a sixth damper  142 , a second stack  132 , a third stack  133 , a coal chute  144 , a CO2 outlet pipe  146 , a natural gas inlet pipe  148 , a milled coal feed  150 , and a plurality of ducts or pipes ( 154 ,  156 ,  158 ,  160 ,  162 ,  164 ,  166 ,  168 ,  170 ,  172 ,  173 ,  178  including first portion  178   a  and second portion  178   b ,  182 ,  184 ,  186 ,  188 ,  190 ,  196 ,  198 ,  206  including first portion  206   a  and second portion  206   b ,  208  including first portion  208   a  and second portion  208   b ,  209 ,  210  including first portion  210   a  and second portion  210   b ,  211 ,  212  including first portion  212   a  and second portion  212   b ) coupled together as shown in  FIG. 1 . 
         [0022]    Exemplary integrated gas turbine-boiler power plant system  100  further includes a controller  401  for controlling operation of system  100 , an oxygen sensor  444  for measuring oxygen level in a flue gas output by the boiler, a plurality of airflow measurement devices ( 420 ,  422 ,  424 ,  426 ,  428 ,  430 ), e.g., a plurality of airflow meters, each airflow meter including airflow sensor, or a plurality of airflow sensors for measuring flow rates at selected locations in the system, a boiler on/off sensor  448  configured to indicate boiler operational status, and a gas turbine on/off sensor  452  configured to indicated gas turbine operational status. Controller  401  determines a current mode of operation, processes outputs from various sensors, e.g., activation status sensors ( 448 ,  452 ), flow rate sensors ( 420 ,  422 ,  424 ,  426 ,  428 ,  430 ), an oxygen measurement sensor  444 , determines control, e.g., desired GT flue gas input(s) into the boiler system in terms of which input(s) are to be used at a given time and/or GT flue gas injection amounts for the selected inputs, the desired control position of dampers ( 134 ,  136 ,  138 ,  140 ,  142 ) at a given time to achieve the desired control effects, and the desired throughput of fans ( 412 ,  414 ), and generates sends control signal to implement the desired control. In various embodiments, GT flue gas input into the boiler system is determined as a function of a measured oxygen level, e.g., in the flue gas  226  output by the boiler  104 . 
         [0023]    Controller  401  receives a boiler active status signal via line  450 . Controller  701  receives a gas turbine active status signal via line  454 . Controller  701  receives an oxygen sensor measurement signal via line  446 . Controller  701  receives airflow rate measurement signals via lines ( 432 ,  434 ,  436 ,  438 ,  440 ,  442 ). Controller  701  sends controls signals via lines ( 402 ,  404 ,  406 ,  408 ,  410   412 ,  414 ,  414 ) to control the position of the dampers and fans. 
         [0024]    Coal  232  is fed to mills  102  via coal chute  144 . Mills  102  receives the coal  232  and mills the coal  232  generating milled coal  224 , e.g., pulverized coal, which is fed, via milled coal feed  150 , to the burners  152  of boiler  104 . Burner air input stream  310  is received via burner air input  204 ; over fire air stream  308  is received via over fire air input  202 . The burners  152  of boiler  104  burn the received milled coal  224  generating steam, e.g., superheated steam, used to drive a steam turbine which spins a generator and generates electrical power, and the boiler outputs flue gas. Exhaust gas stream  226 , the flue gas output, is output from boiler  104  and directed to SCR  106 , via duct  154 . The SCR  106  processes the received exhaust gas stream  154 , said processing including reducing nitrous oxides (NOx), e.g., into N 2  and water, and generates SCR output gas stream  228 , which is fed to an inlet of AH  108 , via duct  156 . The AH  108  removes heat from the gas stream  228 , at least some of the removed heat is transferred into gas streams being directed into the boiler  108  and the mills  208 . 
         [0025]    The outlet gas stream  230  from AH  108  is directed to an inlet of ESP/FF  110  via duct  158 . The ESP/FF  110  reduces ash from the flue gas flow being processed, and fly ash and other waste products are recovered. The outlet gas stream  232  from ESP/FF  110  is directed to the inlet of ID fan  112  via duct  160 . The outlet gas stream  234  from ID fan  112  is directed to an inlet of FGD  114 . The FGD  114  removes sulfur dioxide (SO2) from the flue gas flow being processed. Outlet gas stream  236  from FGD  114  is directed to the inlet of PCC  116  via duct  164 . The PCC  116  captures CO2 from the flue gas flow being processed. An outlet gas stream  238  from PCC  116  is directed to the inlet of stack  188  via duct  166 . PCC  116  also outlets captured CO2  240  via CO2 outlet pipe  146 . The captured CO2 can be compressed and stored, e.g., underground, and/or may be utilized for other purposes that do not result in release to the atmosphere. It should be appreciated that some of the captured CO2 includes CO2 which was included in the cold GT exhaust injected gas flows ( 256 ,  290 ,  292 ,  294 ,  296 ). 
         [0026]    Gas turbine  126  receives natural gas  242  via gas inlet pipe  148 . The gas turbine burns the received natural gas  242  and outputs hot GT exhaust  244  via duct  168 . Duct  168  directs the hot GT exhaust  244  to an input of HRSG  128 . HRSG  128  extracts heat from the received hot GT exhaust  244  and outputs cold GT exhaust  246  into duct  170 . Duct  170  is coupled to the input of booster fan  130 . Duct  172  is coupled to duct  170 . A first portion  248  of cold GT exhaust  246  is input to booster fan  130 ; and a second portion  250  of cold GT exhaust  246  is directed down duct  172 . 
         [0027]    Duct  172  is coupled to an input of stack  132  and an inlet of duct  178 . A first portion  252  of cold GT exhaust  250  is input to stack  132 ; a second portion  254  of cold GT exhaust  250  is input to duct  178 . 
         [0028]    Cold GT exhaust stream  248  is input to booster fan  130  and output as cold GT exhaust stream  272  into duct  173 . Duct  173  is coupled to the input of stack  133  and to the inputs of ducts  206 ,  208 ,  210  and  212 . The outputs of duct portions ( 206   a ,  208   a ,  210   a ,  212   a ), are coupled to the inputs of dampers ( 136 ,  138 ,  140 ,  142 ), respectively. The outputs of dampers ( 136 ,  138 ,  140 ,  142 ) are coupled to the inputs of duct portions ( 206   b ,  208   b ,  210   b ,  212   b ), respectively. Gas flow  272  is divided into gas flow  274  which proceeds down duct  173  and gas flow  276  which enters duct  212 . Gas flow  274  is divided into gas flow  278  which proceeds down duct  173  and gas flow  280  which enters duct  210 . Gas flow  278  is divided into gas flow  282  which proceeds down duct  173  and gas flow  284  which enters duct  208 . Gas flow  282  is divided into gas flow  286  which proceeds down duct  173  and enters stack  133  and gas flow  288  which enters duct  206 . 
         [0029]    Second cold GT exhaust gas injection stream  290  is output from damper  136  into duct portion  206   b  and is injected into the gas stream  270  emerging from the PA fan  124  at input  214  of duct  190 . 
         [0030]    Third cold GT exhaust gas injection stream  292  is output from damper  138  into duct portion  208   b  and is injected into the gas stream  302  flowing toward the mills  102 , the injection being at input  216  of duct  209 . 
         [0031]    Fourth cold GT exhaust gas injection stream  294  is output from damper  140  into duct portion  210   b  and is injected into the gas stream  306  forming gas stream  307  which will supply burner air as stream  310  and OFA air as stream  308 , the injection being at input  218  of duct  196 . 
         [0032]    Fifth cold GT exhaust gas injection steam  296  is output from damper  142  into duct portion  212   b  and directed into the bottom of the furnace of boiler  104  through water walls below the burners  152  via input  220 . 
         [0033]    The output of duct portion  178   a  is coupled to an input to damper  134 , and the output of damper  134  is coupled to first cold GT air injection stream duct portion  178   b . First cold GT air injection stream duct portion  178   b  is coupled to inlet  180  of air duct  182 . Fresh air  258  received via duct  182  is mixed in duct  182  with cold GT exhaust stream  256  received via duct  178  to generate gas stream  260 . The outlet of duct  182  is coupled to an inlet of damper  120 , and the outlet of damper  120  is coupled to an inlet to FD fan  122 . The outlet of FD fan  122  is coupled to an inlet of duct  186 , and the outlet of duct  186  is coupled to an inlet of AH  108 . Duct  188  is also coupled duct  186 . Gas stream  262  is input to FD fan  122  and output as gas stream  264 . A first portion  266  of gas stream  264  is directed to an AH  108  inlet via duct  186 ; a second portion  268  of gas stream  264  is directed to an input of PA fan  124  via duct  188 . Output gas stream  306 , which corresponds to input gas stream  266 , emerges from air heater  108  and is directed via duct  196  toward burner air input  204  of boiler  104 . 
         [0034]    Duct  196  is coupled to an outlet of duct  210  and an inlet of duct  198 . Within duct  196  AH output gas stream  306  is mixed with received fourth cooled GT exhaust stream  294 , received via duct  210 , to generate gas stream  307 . A first portion  310  of gas stream  307  is directed to burner input  204  as the burner air stream, via burner air input duct  196 ; a second portion  308  of gas stream  307  is directed to OFA input  202  via duct  198 . 
         [0035]    Inlet gas flow with regard to the mills  102  will now be described. PA fan  124  receives gas flow  268 , via duct  188 , and outputs flow  270  into duct  190 . Duct  190  is coupled to duct  214  and duct  206 . Gas stream  270  is combined in duct  190 , with second cold GT exhaust stream  290 , received via duct  206 , to generate gas stream  298 . A first portion  300  of gas stream  298  is input to AH  108  via duct  190 ; and a second portion  302  of gas stream  298  is directed into mills inlet duct  209 . The outlet of mills inlet duct  209  is coupled to the mills air inlet of mills  102 . Third cold GT exhaust stream injection duct  208  is coupled to duct  209 . Gas stream  302  is combined in duct  209  with third cold GT exhaust injection stream  292 , which is received via duct  208  to generate gas stream  304 . Duct  209  is further coupled to duct  211 . Output gas stream  306 , which corresponds to inlet gas stream  300 , emerges from AH  108 , and is directed via duct  211  to duct  209 . In duct  209 , gas stream  304  is combined with gas stream  306  to generate mills burner inlet air stream  308 . 
         [0036]    Fifth cold GT exhaust stream  296  is directed via duct  212  directly into inlet  220  in the bottom of the furnace of boiler  104  through water walls below the burners  152 . 
         [0037]    In some embodiments, gas turbine  126  and HRSG  128  are part of a GTCC plant and mills  102 , boiler  104 , SCR  106 , AH  108 , ESP/FF  110 , FGD  114  and PCC  116  are part of a coal fired boiler plant. In some embodiments, the cold exhaust gas from the GTCC plant, e.g., in the range of around 200 degrees F., is sent into the boiler plant. In some such embodiments, the range is, e.g., 150 to 250 degrees F. In Stream  1   256 , the exhaust gas is sent from outlet of the HRSG  128  directly to the inlet of the forced draft (FD) fan  122  of the coal-fired boiler  104 , with a damper  134  to modulate the flow. The GT exhaust  256  will be mixed with fresh air  258  at the inlet to the FD fan  122 . The FD fan  122  supplies the combustion air for the entire boiler  104 . 
         [0038]    In Stream  2   290 , the GT exhaust is injected into the outlet of the primary air (PA) fan  124  which provides air for the coal mills  102  and carries the pulverized coal into the furnace through the burners  152 . In Stream  3   292 , the GT exhaust will be injected into the Cold Air stream  302  coming off the PA fan  124 . In Stream  4   294 , the GT exhaust is directed to the secondary duct  196  which supplies burner air  310  and over-fire-air  308 . In Stream  5   296 , GT exhaust is ducted, via duct  212 , directly into the bottom of the furnace through water walls below the burners  152 . 
         [0039]    In some embodiments, each of cold GT exhaust injection streams  2 ,  3 ,  4 ,  5  ( 290 ,  292 ,  294 ,  296 ) is arranged individually. In some embodiments, each of cold GT exhaust injection streams  2 ,  3 ,  4 ,  5  ( 290 ,  292 ,  294 ,  296 ) are arranged in combination with other streams. In some embodiments, some of cold GT exhaust injection streams  2 ,  3 ,  4 ,  5  ( 290 ,  292 ,  294 ,  296 ) are arranged individually, while some of the cold GT exhaust injection streams  2 ,  3 ,  4 ,  5  ( 290 ,  292 ,  294 ,  296 ) are arranged in combination with other streams. 
         [0040]    In some embodiments, each of these streams ( 290 ,  292 ,  294 ,  296 ) is down stream of a booster fan, e.g., booster fan  130 , and each stream ( 290 ,  292 ,  294 ,  296 ) has a flow modulating damper, e.g. dampers ( 136 ,  138 ,  140 ,  142 ), respectively. Any excess amount of exhaust from the GTCC system can be, and in various embodiments, is vented to the atmosphere, e.g., via stack  133 . 
         [0041]    In the example of system  100  of  FIG. 1 , there are five gas turbine flue gas inputs ( 180 ,  214 ,  216 ,  218 ,  220 ) which are used to input gas turbine flue gas, e.g., cooled gas turbine flue gas, into the boiler system  103 . Gas turbine flue gas input  220  is a gas turbine flue gas boiler hopper input of boiler  104 . The gas turbine flue gas hopper input  220  is for receiving gas turbine flue gas  296  and supplying the received gas turbine flue gas  296  into the boiler  104  at a location beneath the burner  152 . 
         [0042]    Gas turbine flue gas input  216  is a gas turbine flue gas mill air supply duct input which is included as part of mill air supply duct  209  which supplies air to mill  102  which provides fuel  224  to boiler  104 . 
         [0043]    Gas turbine flue gas input  218  is a gas turbine flue gas burner air supply duct input. Burner air supply duct  196  supplies air to the burner  152  of the boiler  104  and the burner air supply duct  196  includes the gas turbine flue gas burner air supply duct input  218 . 
         [0044]    Controller  401  controls the supply of gas turbine flue gas to gas turbine flue gas inputs ( 180 ,  214 ,  216 ,  218 ,  220 ) of boiler system  103  based on an oxygen level measured by oxygen sensor  444 . Damper  142  is located in gas turbine flue gas duct  212  connected to gas turbine flue gas boiler hopper input  220 . In various embodiments, controller  401  is configured to control damper  410  to be in an open position during a first mode of operation during which both the gas turbine  126  and the boiler  104  are active. Fans  122  and  124  blow air  258 , e.g., fresh air, which is mixed with gas turbine flue gas, prior to the gas turbine flue gas reaching the boiler  104 . In some embodiments, controller  401  is configured to control the throughput of one or both of fans ( 122  and  124 ) as a function of the output of the oxygen sensor  444 . 
         [0045]    In some embodiments, the flue gas input  220  of said boiler hopper supplies more gas turbine flue gas to the boiler system  103  than any other gas turbine flue gas input ( 180 ,  214 ,  216 ,  218 ) supplies to the boiler system  103 . 
         [0046]    In various embodiments, the controller  401  is configured to control dampers ( 134 ,  136 ,  138 ,  140 ,  142 ) to isolate the boiler system  103  from the gas turbine system  109  when the boiler system  103  is active and the gas turbine system  109  is inactive. In some such embodiments, the controller  401  is further configured to isolate the boiler system  103  from the gas turbine system  109  when the boiler system  103  is inactive and the gas turbine system is active. 
         [0047]      FIG. 2  is a drawing of an exemplary integrated gas turbine-boiler power plant system  500  in accordance with an exemplary embodiment. Exemplary power plant system  500  includes a boiler system  503  including a boiler  504  and a gas turbine system  509  including a gas turbine  524 . Exemplary system  500  includes mills  502 , a boiler  504 , a SCR  506 , an air heater (AH)  508 , an ESP/FF  510 , an ID fan  512 , a FGD  514 , a PCC  516 , a first stack  518 , an FD fan  520 , a PA fan  522 , a gas turbine (GT)  524 , a first damper  528 , a second damper  530 , a third damper  532 , a fourth damper  534 , a fifth damper  536 , a second stack  526 , a coal chute  538 , a CO2 outlet pipe  540 , a natural gas inlet pipe  542 , a milled coal feed  544 , and a plurality of ducts or pipes ( 546 ,  548 ,  550 ,  552 ,  554 ,  556 ,  558 ,  560 ,  562  including a first portion  562   a  and a second portion  562   b ,  564  including a first portion  564   a  and a second portion  564   b ,  566  including a first portion  566   a  and a second portion  566   b ,  568  including a first portion  568   a  and a second portion  568   b ,  578 ,  580 ,  582 ,  584 ,  586 ,  588 ,  590 ,  592 ,  594 ,  596 ,  598 ) coupled together as shown in  FIG. 2 . Note that reference connection A  569  is used to indicate that cutoff portions of duct portion  568   b  are actually connected. 
         [0048]    Exemplary integrated gas turbine-boiler power plant system  500  further includes a controller  701  for controlling operation of system  500 , an oxygen sensor  734  for measuring oxygen level in a gas, e.g., flue gas  610  entering SCR  506 , a plurality of airflow measurement devices ( 716 ,  718 ,  720 ,  722 ,  724 ), e.g., a plurality of airflow meters, each airflow meter including airflow sensor, or a plurality of airflow sensors for measuring flow rates at selected locations in the system, a boiler on/off sensor  738  configured to indicate boiler operational status, and a gas turbine on/off sensor  742  configured to indicated gas turbine operational status. Controller  701  determines a current mode of operation, processes outputs from various sensors, e.g., activation status sensors ( 738 ,  742 ), flow rate sensors ( 716 ,  718 ,  720 ,  722 ,  724 ), a oxygen measurement sensor  734 , determines control, e.g., desired GT flue gas input(s) into the boiler system in terms of which input(s) are to be used at a given time and/or GT flue gas injection amounts for the selected inputs, the desired control position of dampers ( 528 ,  530 ,  532 ,  534 ,  536 ) at a given time to achieve the desired control effects, and the desired throughput of fans ( 522 ,  524 ), and generates and sends control signal(s) to implement the desired control. In various embodiments, GT flue gas input into the boiler system is determined as a function of a measured oxygen level. In various embodiments, controlled throughput of fans ( 520 ,  522 ) is determined as a function of a measured oxygen level and/or the determined mode of operation. Controller  701  receives a boiler active status signal via line  740 . Controller  701  receives a gas turbine active status signal via line  744 . Controller  701  receives a oxygen sensor measurement signal via line  736 . Controller  701  receives airflow rate measurement signals via lines ( 724 ,  726 ,  728 ,  730 ,  732 ). Controller  701  sends controls signals via lines ( 702 ,  704 ,  704 ,  706 ,  710   712 ,  714 ) to control the position of the dampers and fans. 
         [0049]    Exemplary integrated gas turbine-boiler power plant system  500  further includes a controller  701 , an oxygen sensor  734 , a plurality of airflow measurement devices ( 716 ,  718 ,  720 ,  722 ,  724 ), e.g., a plurality of airflow meters, each airflow meter including airflow sensor, or a plurality of airflow sensors, a boiler on/off sensor  738 , and a gas turbine on/off sensor  742 . 
         [0050]    Coal  602  is fed to mills  502  via coal chute  538 . Mills  502  receives the coal  602  and mills the coal  602  generating milled coal  604 , e.g., pulverized coal, which is fed, via milled coal feed  544 , to the burners  505  of boiler  504 . Burner air input stream  680  is received via burner air input  509 ; over furnace air stream  682  is received via over furnace air input  507 . The burners  502  of boiler  504  burn the received milled coal  604  generating steam, e.g., superheated steam, used to drive a steam turbine which spins a generator which generate electrical power. The burner  504  outputs flue gas. A first exhaust gas stream  608 , which is a flue gas output, is output from boiler  604  and directed to SCR  506 , via duct  546 . A second exhaust stream  606 , which is an economizer bypass gas stream, is output from the boiler  504  and directed toward the SCR  506  via duct  580  of the economizer bypass provided the damper  536  is open. In some embodiments, duct  578  is included and fourth hot GT exhaust injection stream  652  may be, and sometimes is, directed down duct  578  as gas flow  652   b  and into the economizer duct  580  of the economizer bypass, and toward the boiler  504  upstream of the economizer  511 , with the damper  536  in a closed position. 
         [0051]    Gas stream  660  is an output stream from damper  536  into duct  582  of the economizer bypass. Gas stream  660  is combined with first exhaust gas boiler output steam  608  to form gas stream  610 , which enters SCR  506 . In some embodiments, duct  578  and damper  536  are not included, and gas flows  606  and  660  are the same gas flow. Oxygen sensor  734  measures the oxygen level in gas flow stream  610 . 
         [0052]    The SCR  506  processes the received exhaust gas stream  610 , said processing including reducing nitrous oxides (NOx), e.g., into N 2  and water, and generates SCR output gas stream  612 , which is fed to an inlet of AH  508 , via duct  548 . Air heater  508  removes heat from the received gas stream  612 , at least some of the removed heat is transferred to inlet air streams being directed to the boiler  504  and the mills  502 . The outlet gas stream  614  from AH  508  is directed to an inlet of ESP/FF  510  via duct  550 . The ESP/FF  510  reduces the amount of ash in the flue gas stream being processed, removing fly ash and other waste products. The outlet gas stream  616  from ESP/FF  510  is directed to the inlet of ID fan  512  via duct  552 . The outlet gas stream  618  from ID fan  512  is directed to an inlet of FGD  514 . The FGD  514  removes sulfur dioxide (SO2) from the exhaust flue gas being processed. Outlet gas stream  620  from FGD  514  is directed to the inlet of PCC  516  via duct  556 . An outlet gas stream  624  from PCC  516  is directed to the inlet of stack  518  via duct  558 . PCC  516  also outlets captured CO2  622  via CO2 outlet pipe  540 . The captured CO2 can be compressed and stored, e.g., underground, and/or may be utilized for other purposes that do not result in release to the atmosphere. It should be appreciated that some of the captured CO2 includes CO2 which was included in the hot GT exhaust injected gas flows ( 646 ,  648 ,  650 ,  652 ). 
         [0053]    Gas turbine  524  receives natural gas  626  via gas inlet pipe  542 . The gas turbine  524  burns the received natural gas  626  and outputs hot GT exhaust  628 , which is hot GT flue gas, via duct  560 . Duct  560  is coupled to: an input of stack  526 . Duct  560  is also coupled to an inlet of each of: duct  562 , duct  564 , duct  566 , and duct  568 . The outputs of duct portions ( 562   a ,  564   a ,  566   a ,  568   a ) are coupled to the inputs of dampers ( 528 ,  530 ,  532 ,  534 ), respectively. The outputs of dampers ( 528 ,  530 ,  532 ,  534 ) are coupled to the inputs of duct portions ( 562   b ,  564   b ,  566   b ,  568   b ), respectively. Hot GT exhaust gas flow  628  is divided into gas flow  630  which proceeds down duct  560  and gas flow  632  which enters duct  568 . Gas flow  630  is divided into gas flow  634  which proceeds down duct  560  and gas flow  636  which enters duct  566 . Gas flow  634  is divided into gas flow  638  which proceeds down duct  560  and gas flow  640  which enters duct  564 . Gas flow  638  is divided into gas flow  642  which proceeds down duct  560  and enters stack  526  and gas flow  644  which enters duct  562 . 
         [0054]    First hot GT exhaust gas injection stream  646  is output from damper  528  into duct portion  562   b  and is injected into the gas stream  674 , via input  570  of duct  592 , flowing toward the mills  502 , forming combined gas stream  686 . 
         [0055]    Second hot GT exhaust gas injection stream  648  is output from damper  530  into duct portion  564   b  and is injected into the gas stream  677 , via input  572  of duct  596 , forming combined gas stream  678 , which will supply burner air  680  and OFA air  682 . 
         [0056]    Third hot GT exhaust gas injection stream  650  is output from damper  532  into duct portion  568   b  and directed into the bottom of the furnace of boiler  504  through water walls below the burners  505 , via input  574 . 
         [0057]    Fourth hot GT exhaust gas injection stream  652  is output from damper  534  into duct portion  568   b  and directed toward the boiler  504 . In some embodiments, duct  576  is included and duct  578  is not included and fourth hot GT exhaust injection stream  652  is input to the boiler  504  at input  576   a  above the economizer  511 , via duct  576  as gas flow  652   a . In some embodiments, duct  578  is included and fourth hot GT exhaust injection stream  652  is directed down duct  578 , as gas flow  652   b , and into economizer duct  580  of the economizer bypass at input  576   b , and gas flow  652   b  is directed toward boiler  504  and gas flow  652   b  is input to the boiler  504  slightly above the economizer  511 , with the damper  536  in a closed position. 
         [0058]    Fresh air  662 , received via duct  584 , is directed to the inlet of FD fan  520 . The outlet of FD fan  520  is coupled to an inlet of duct  586 , and the outlet of duct  586  is coupled to an inlet of AH  508 . Duct  588  is also coupled duct  586 . Inlet air stream  662  is output from FD fan  520  as air stream  664 . A first portion  666  of air stream  664  is directed to an AH  108  inlet via duct  586 ; a second portion  668  of air stream  664  is directed to an input of PA fan  522  via duct  588 . Air heater output air stream  677 , which corresponds to air heater input air stream  666 , emerges from air heater  508  and is directed via duct  596  toward burner air input  509  of boiler  504 . 
         [0059]    Duct  596  is coupled, via input  572 , to an outlet of duct  564 , and duct  596  is also coupled to an inlet of duct  598 . Within duct  596  AH output air stream  677  is mixed with received second hot GT exhaust injection stream  648 , received from duct  564  via input  572 , to generate gas stream  678 . A first portion  680  of gas stream  678  is directed to burner input  509  as the burner air stream, via burner air input duct  596 ; a second portion  682  of gas stream  678  is directed to OFA input  507  via duct  598 . 
         [0060]    Inlet gas flow with regard to the mills  502  will now be described. PA fan  522  receives air flow  668 , via duct  588 , and outputs air flow  670  into duct  590 . Duct  590  is coupled to duct  592 . A first portion  672  of air stream  670  is input to AH  108  via duct  590 ; and a second portion  674  of air stream  670  is directed into mills inlet duct  592 . The outlet of mills inlet duct  592  is coupled to the mills air inlet of mills  502 . Mills duct  592  includes inlet  570  which couples duct  562  to duct  592 . Air stream  674  is combined in duct  592  with first hot GT exhaust injection stream  646 , which is received via input  570  of duct  592  from duct  562 , to generate gas stream  686 . Duct  592  is further coupled to duct  594 . Output air stream  684 , which corresponds to inlet air stream  672 , emerges from AH  508 , and is directed via duct  594  to duct  592 . In duct  592 , air stream  686  is combined with gas stream  684  to generate mills burner inlet air stream  689 . 
         [0061]    Third hot GT exhaust stream  650  is directed via duct  566  directly into the bottom of the furnace of boiler  504  through water walls below the burners  505  via input  574 . 
         [0062]    In some embodiments, the hot GT exhaust gas, which is (900-1150 F) is introduced into the boiler plant, e.g., as injection streams ( 646 ,  648 ,  650 ,  652 ) is in the range of 900-1150 degrees F. Due to its high temperature of the hot GT exhaust gas, a booster fan is not used; instead the GT  524  is operated at a significant backpressure, e.g., 20 inches of H2O or higher backpressure, depending on where the GT exhaust is introduced. 
         [0063]    Hot GT exhaust steam  1   646  is injected and mixed into the cold air stream for the coal mills  502 , e.g., first hot GT exhaust injection stream  646  is mixed with cold air stream  674  to form gas stream  686  which is directed toward the mills  502 . Hot GT exhaust stream  2   648  is injected and mixed into the secondary air stream  677  downstream of the air preheater (AH)  508  to form air stream  678  which supplies over-fire-air (OFA)  682  and burner air  680 . Hot GT exhaust stream  3   650  is ducted directly into the bottom of the furnace through water walls below the burners  505  via input  574 . In some embodiments, hot GT exhaust stream  4   652  is introduced, as gas flow  652   a  or as gas stream  652   b , to the upstream of the economizer  511 , a part of the boiler  504  water circuit. In some embodiments, hot GT exhaust gas injection stream  4   652  is injected directly into the main flue gas path upstream of the economizer as gas stream  652   a . Alternatively, in some other embodiments, hot GT exhaust gas injection stream  4   652  is injected, as gas flow  652   b  via duct  578 , into a flue gas bypass duct ( 580 , 582 ) connecting the flue gas flow path from economizer inlet to the SCR inlet. The flue gas bypass duct ( 580 ,  582 ) is common for boiler units equipped with SCR. In the second arrangement in which flow  652   b  is injected into duct  580 , a damper  536  is used to prevent the GT exhaust from entering the SCR  506  directly. In the first arrangement in which flow  652   a  is injected into boiler  504 , damper  536  is not included. 
         [0064]    Each of hot GT exhaust injection streams (stream  1   646 , stream  2   648 , stream  3   650 , stream  4   652 ) can be arranged individually or in combination with other streams. Each of these streams ( 646 ,  648 ,  650 ,  652 ) has a flow modulating damper ( 528 ,  530 ,  532 ,  534 ), respectively. Any excess amount of exhaust from the GTCC system is vented to the atmosphere, e.g., via stack  526 . 
         [0065]    In the example of system  500  of  FIG. 2 , there are four gas turbine flue gas inputs ( 570 ,  572 ,  574 ,  576   a  or  576   b ) which are used to input gas turbine flue gas, e.g., hot gas turbine flue gas, into the boiler system  503 . Gas turbine flue gas input  574  is a gas turbine flue gas boiler hopper input of boiler  504 . The gas turbine flue gas hopper input  574  is for receiving gas turbine flue gas  650  and supplying the received gas turbine flue gas  650  into the boiler  504  at a location beneath the burners  505 . 
         [0066]    Gas turbine flue gas input  570  is a gas turbine flue gas mill air supply duct input which is included as part of mill air supply duct  592  which supplies air to mill  502  which provides fuel  604  to boiler  504 . 
         [0067]    Gas turbine flue gas input  572  is a gas turbine flue gas burner air supply duct input. Burner air supply duct  596  supplies air to the burner  505  of the boiler  504  and the burner air supply duct  596  includes the gas turbine flue gas burner air supply duct input  572 . 
         [0068]    Controller  701  controls the supply of gas turbine flue gas to gas turbine flue gas inputs ( 570 ,  572 ,  574 ,  576   a  or  576   b ) of boiler system  503  based on an oxygen level measured by oxygen sensor  734 . Damper  532  is located in gas turbine flue gas duct  566  connected to gas turbine flue gas boiler hopper input  574 . In various embodiments, controller  701  is configured to control damper  532  to be in an open position during a first mode of operation during which both the gas turbine  524  and the boiler  504  are active. Fans  520  and  522  blow air  258 , e.g., fresh air, which can be, and sometimes is, subsequently mixed with gas turbine flue gas, prior to the mixture including the gas turbine flue gas reaching the boiler  504 . In some embodiments, controller  701  is configured to control the throughput of one or both of fans ( 520  and  522 ) as a function of the output of the oxygen sensor  734 . In some embodiments, controller  701  is configured to control the throughput of one or both of fans ( 520  and  522 ) as a function of the determined mode of operation, e.g. with less fresh air being supplied during a first mode of operation in which both the gas turbine and the boiler are active than another mode in which the boiler is active and the gas turbine is inactive. 
         [0069]    In some embodiments, the flue gas input  574  of said boiler hopper supplies more gas turbine flue gas to the boiler system  503  than any other gas turbine flue gas input ( 570 ,  572 ,  576   a  or  576   b ) supplies to the boiler system  503 . 
         [0070]    In various embodiments, the controller  701  is configured to control dampers ( 528 ,  530 ,  532 ,  534 ) to isolate the boiler system  503  from the gas turbine system  509  when the boiler system  503  is active and the gas turbine system  509  is inactive. In some such embodiments, the controller  701  is further configured to isolate the boiler system  503  from the gas turbine system  509  when the boiler system  503  is inactive and the gas turbine system  509  is active. 
         [0071]      FIG. 3 , comprising the combination of  FIG. 3A  and  FIG. 3B , is a flowchart  800  of an exemplary method of operating a power system including a boiler system, e.g., a coal fired boiler system, and a gas turbine system, in accordance with an exemplary embodiment. Operation starts in step  802  in which at least a portion of the power system is powered on and initialized. For example, a controller is powered on and initialized and at least one of the boiler system and the gas turbine system is powered on and initialized. Operation proceeds from step  802  to steps  804 ,  810  and  812 , which may be performed in parallel. 
         [0072]    In step  804  the controller determines a current mode of operation. Step  804  includes steps  806  and  808 . In step  806  the controller is operated to receive an operation status input from the boiler system, e.g., a signal indicating whether the boiler system is active or inactive. In step  808  the controller is operated to receive an operation status input from the gas turbine system, e.g., a signal indicating whether the gas turbine system is active or inactive. In one exemplary embodiment, in step  804 , the controller determines whether the current mode of operation is: a first mode of operation in which the boiler is active and the gas turbine is active, a second mode of operation in which said boiler is active and said gas turbine is not active or a third module of operation in which said boiler is inactive and said gas turbine is active. Operation proceeds from step  804  to step  814 . 
         [0073]    Returning to step  810 , in step  810  the oxygen level in the flue gas output by the boiler is measured. In various embodiments the oxygen level is determined based on a signal received from an oxygen sensor which is placed in a boiler flue gas stream flow at a location before the boiler flue gas enters an SCR. In some embodiments, multiple oxygen sensors are placed in the system and used by the controller. 
         [0074]    Returning to step  812 , in step  812  flow rates are measured from one or more flow meters. In some embodiments, the flow meters include flow rate sensors which are placed in each of the possible gas turbine flue gas input paths from which gas turbine flue gas may be, and sometimes is, injected into the boiler system. 
         [0075]    In step  814  if the determination of step  804  is that the current mode of operation is the first mode of operation in which said boiler is active and said gas turbine is active, then operation proceeds from step  814 , via connecting node A  826 , to steps  828  and  842 ; otherwise, operation proceeds from step  814  to step  816 . 
         [0076]    In step  816 , if the current mode of operation is a mode of operation in which said boiler is active and said gas turbine is not active, e.g., a second mode of operation, then operation proceeds from step  816  to step  818  and step  819 ; otherwise, operation proceeds from step  816  to step  820 . 
         [0077]    In step  818  the controller is operated during the mode of operation in which said boiler is active and said gas turbine is not active to close dampers between the gas turbine system and said boiler system to isolate the inactive gas turbine system from the active boiler system. In step  819  the controller is operated during the mode of operation in which said boiler is active and said gas turbine is not active to control the throughput of one or more fans. Operation proceeds from steps  818  and  819  to connecting node B  850 . 
         [0078]    In step  820 , if the current mode of operation is a mode of operation in which said boiler is inactive and said gas turbine is inactive, e.g., a third mode of operation, then operation proceeds from step  820  to step  822 ; otherwise, operation proceeds from step  820  to connecting node B  850 . 
         [0079]    In step  822 , the controller is operated, during the mode of operation in which said boiler is not active and said gas turbine is active, to close dampers between the gas turbine system and said boiler system to isolate the inactive boiler system from the active gas turbine system. Step  822  includes step  824  in which the controller, during the mode of operation in which said boiler is not active and said gas turbine is active, to prevent the supply of gas turbine flue gas to first flue gas input of said boiler system. Operation proceeds from step  822  to connecting node B  850 . In some embodiments, during the third mode of operation in which the gas turbine is active and the boiler system is inactive, flue gas from the gas turbine system is directed to an additional carbon recovery and/or pollution control system, e.g., a system which is more expensive to operate than the carbon control recovery and pollution control system included in the boiler system. 
         [0080]    Returning to step  814 , in step  814 , if the current mode of operation is a first mode of operation in which said boiler is active and said gas turbine is active, then operation proceeds from step  814 , via connecting node A  826  to steps  828  and  842 . In step  828  the controller is operated to control the supply of gas turbine flue gas to one or more gas turbine flue gas inputs based on the measured oxygen content level. Step  820  includes one or more or all of steps  830 ,  832  and  834 . In step  830  the controller is operated to control the supply of gas turbine flue gas to a first gas turbine flue gas input of said boiler system based on the measured oxygen content level, said first flue gas input being one of: i) a gas turbine flue gas boiler hopper input of a boiler, ii) a gas turbine flue gas burner air supply duct input which supplies air to a burner of said boiler or iii) a gas turbine flue gas mill air supply duct input, which is included as part of a mill air supply duct, which supplies air to a mill which provides fuel to said boiler. Step  830  includes step  836  in which the controller is operated to control the position of a first damper used to control the supply of gas turbine flue gas to the first gas turbine flue gas input to be in an open position. 
         [0081]    In step  832  the controller is operated to control the supply of gas turbine flue gas to a second gas turbine flue gas input of said boiler system based on the measured oxygen content level, said second flue gas input being one of: i) a gas turbine flue gas boiler hopper input of a boiler, ii) a gas turbine flue gas burner air supply duct input which supplies air to a burner of said boiler or iii) a gas turbine flue gas mill air supply duct input, which is included as part of a mill air supply duct, which supplies air to a mill which provides fuel to said boiler, said second flue gas input being different from said first flue gas input. Step  832  includes step  838  in which the controller is operated to control the position of a second damper used to control the supply of gas turbine flue gas to the second gas turbine flue gas input to be in an open position. 
         [0082]    In step  834  the controller is operated to control the supply of gas turbine flue gas to a third gas turbine flue gas input of said boiler system based on the measured oxygen content level, said third flue gas input being one of: i) a gas turbine flue gas boiler hopper input of a boiler, ii) a gas turbine flue gas burner air supply duct input which supplies air to a burner of said boiler or iii) a gas turbine flue gas mill air supply duct input, which is included as part of a mill air supply duct, which supplies air to a mill which provides fuel to said boiler, said third flue gas input being different from said first flue gas input and said second flue gas input. Step  838  includes step  840  in which the controller is operated to control the position of a third damper used to control the supply of gas turbine flue gas to the third gas turbine flue gas input to be in an open position. 
         [0083]    In step  842  the controller is operated to control the throughput of one or more fans. In various embodiments, the throughput of a fan is controlled by controlling an inlet damper included in an inlet duct prior to the fan inlet, e.g., controlling the position of the damper, and/or by controlling a variable speed drive, e.g., controlling fan motor speed. Step  842  includes one or both of steps  844  and step  846 . In step  844  the controller is operated to control the throughput of a first fan, e.g., a primary air (PA) fan, which supplies air which is mixed with turbine flue gas prior to the combined flue including the flue gas reaching the boiler. In step  846  the controller is operated to control the throughput of a second fan, e.g., a forced draft (FD) fan, which supplies air which is mixed with turbine flue gas prior to the combine gas including the flue gas reaching the boiler. 
         [0084]    Operation proceeds from steps  828  and  842  to connecting node B  850 . Operation proceeds from connecting node B  850  to the input of step  804 , in which a current mode of operation is determined. Steps  804 ,  810  and  812  are repeated on a recurring basis. In various embodiments, the repeat rates for step  804 ,  810  and  812  are different. 
         [0085]    The flowchart  300  of  FIG. 3  will now be described for an exemplary embodiment in which the power system is power system  100  of  FIG. 1  including a boiler system including boiler  104  and a gas turbine system including gas turbine  126 . In step  804  controller  401  determines the current mode of operation based on a received boiler status input signal received on boiler status input signal line B ON/OFF    450  and based on received gas turbine status input signal received gas turbine status input signal line GT ON/OFF    452 , which are received by controller  401  in steps ( 806 ,  808 ), respectively from status indicators devices ( 448 ,  452 ), respectively. The determined mode of operation is one of: a first mode is which both the boiler  104  and the gas turbine  126  are active, a second mode in which the boiler  104  is active and the gas turbine  126  is inactive, or a third mode in which the gas turbine  126  is active and the boiler  104  is inactive. 
         [0086]    In step  810  the oxygen level in the flue gas output  226  by the boiler  104  is measured based on a sensor measurement signal on oxygen sensor line V 02    446 , e.g., a voltage level, from oxygen sensor  444  which is received and processed by controller  401 , said processing including comparing the voltage level to a predetermined oxygen sensor model mapping oxygen content level to voltage level. 
         [0087]    In step  812  the controller  401  measures flow rates based on received flow rate signals received on flow rate signal lines (R 1   432 , R 2   434 , R 3   436 , R 4   438 , R 5   440 , R 6   442 ) from airflow rate measurement devices ( 420 ,  422 ,  424 ,  426 ,  428 ,  430 ), respectively. In some embodiments, airflow measurement devices ( 420 ,  422 ,  424 ,  426 ,  428 ,  430 ) are airflow meters with each meter including an airflow rate sensor. In some other embodiments, airflow measurement devices ( 420 ,  422 ,  424 ,  426 ,  428 ,  430 ) are airflow sensors with the processing of the sensor outputs to determined measured rates being performed within the controller  401 . 
         [0088]    Operation control steps  814 ,  816  and  820  are performed by the controller  401  based on the determination of step  804 . 
         [0089]    In step  818  controller  401  generates and sends control signals via control lines (C 1   402 , C 2   404 , C 3   406 , C 4   408 , C 5   410 ) to close dampers ( 134 ,  136 ,  138 ,  140 ,  142 ), respectively, to isolate the inactive gas turbine system from the active boiler system. 
         [0090]    In step  819  the controller  401  generates and send control signals on control lines (C 7   412 , C 8   414 ) to fans (FD fan  122 , PA fan  124 ) to control the throughput of the fans. In various embodiments, each fan ( 122 ,  124 ) is initially set at a predetermined fixed level corresponding to the second mode of operation in which the boiler  104  is active and the gas turbine  126  is inactive and therefore no gas turbine flue gas is supplied to the boiler. Subsequently fan throughputs are adjusted, e.g., slightly based on oxygen sensor measurement information. In some such embodiments, the rates of step  819  are higher than the rates of step  842 , in which gas turbine flue gas is being input to the boiler. 
         [0091]    In step  822  the controller  401  generates and sends control signals via control lines (C 1   402 , C 2   404 , C 3   406 , C 4   408 , C 5   410 ) to close dampers ( 134 ,  136 ,  138 ,  140 ,  142 ), respectively, to isolate the inactive boiler system from the active gas turbine system. 
         [0092]    In step  828  the controller  401  determines desired gas turbine flue gas input injection levels for each of gas turbine flue gas inputs ( 180 ,  214 ,  216 ,  218 ,  220 ), which are inputs the boiler system, based on the measured oxygen level. Controller  401  generates and sends control signal via control lines (C 1   402 , C 2   404 , C 3   406 , C 4   408 , C 5   410 ) to control the operation of dampers ( 134 ,  136 ,  138 ,  140 ,  142 ), respectively. The control of step  828  includes controlling one or more dampers ( 134 ,  136 ,  138 ,  140 ,  142 ) to be in an open position, which allows gas turbine flue gas to be input into the boiler system. In some embodiments, a damper is controlled to be either in a fully closed or fully open position. In some embodiments, a damper may be, and sometimes is controlled to be in a fully closed position, a fully open position, or a partially open position. In some such embodiments, control supports a fixed number of predetermined partially open conditions for a damper, e.g., 8 or less different partially open conditions. In some embodiments, control supports a continuous range of partially open conditions for a damper. 
         [0093]    Consider that the first gas turbine flue gas input is gas turbine flue gas hopper input  220  of boiler  104 . In step  830 , including step  836 , controller  401  generates and sends a control signal on control signal line C 5   410  to control the position of damper  142  to be in an open position, which results in flue gas  296  being input to flue gas hopper input  220  of boiler  104 . 
         [0094]    Further consider that the second gas turbine flue gas input is the gas turbine flue gas burner air supply duct input  218  which supplies air to the burners  152  of said boiler  104 . In step  832 , including step  838 , controller  401  generates and sends a control signal on control signal line C 4   408  to control the position of damper  140  to be in an open position, which results in flue gas  294  being input into gas turbine flue gas burner air supply duct input  218  of duct  196 . 
         [0095]    Further consider that the third gas turbine flue gas input is the gas turbine flue gas mill air duct supply duct input  216 , which is included as part of a mill air duct  209  which supplies air to mill  102  which provides fuel  224  said boiler  104 . In step  834 , including step  840 , controller  401  generates and sends a control signal on control signal line C 3   406  to control the position of damper  138  to be in an open position, which results in flue gas  292  being input into the gas turbine flue gas mill air duct supply duct input  216  of a mill air duct  209 . 
         [0096]    In some embodiments, controller  401  generates and sends a control signal via control signal line C 2   404  to control the position of damper  136  to be in an open position, which results in gas turbine flue gas  290  being input into gas turbine flue gas input  214  of duct  190 . 
         [0097]    In some embodiments, controller  401  generates and sends a control signal via control signal line C 1   402  to control the position of damper  134  to be in an open position, which results in gas turbine flue gas  256  being input into gas turbine flue gas input  180  of duct  182 . 
         [0098]    In step  842 , including steps  844  and  846 , controller  401  determines desired throughputs for FD fan  122  and PA fan  124 , generates and sends control signals on control lines (C 7   412 , C 8   414 ), respectively to control the throughputs of the fans ( 122 ,  124 ), respectively, which supply air  258  which is mixed with gas turbine flue gas prior to the mixture including the flue gas reaching the boiler  104 . In various embodiments, the fan throughputs of step  842  are adjusted, e.g., lowered, with respect to gas turbine inactive mode of operation of step  819 , since with the gas turbine active some or all of the fresh supply air  258  can be, and sometimes is, replaced by gas turbine flue gas. 
         [0099]    The flowchart  300  of  FIG. 3  will now be described for an exemplary embodiment in which the power system is power system  500  of  FIG. 2  including a boiler system including boiler  504  and a gas turbine system  509  including gas turbine  524 . In step  804  controller  701  determines the current mode of operation based on a received boiler status input signal received on boiler status input signal line B ON/OFF    740  and based on received gas turbine status input signal received gas turbine status input signal line GT ON/OFF    744 , which are received by controller  701  in steps ( 806 ,  808 ), respectively from status indicators devices ( 738 ,  742 ), respectively. The determined mode of operation is one of: a first mode is which both the boiler  504  and the gas turbine  524  are active, a second mode in which the boiler  504  is active and the gas turbine  524  is inactive, or a third mode in which the gas turbine  524  is active and the boiler  504  is inactive. 
         [0100]    In step  810  the oxygen level in the flue gas output  610  by the boiler  504 , prior to the SCR  506 , is measured based on a sensor measurement signal on oxygen sensor line V 02    736 , e.g., a voltage level, from oxygen sensor  734  which is received and processed by controller  701 , said processing including comparing the voltage level to a predetermined oxygen sensor model mapping oxygen content level to voltage level. 
         [0101]    In step  812  the controller  701  measures flow rates based on received flow rate signals received on flow rate signal lines (R 1   724 , R 2   726 , R 3   728 , R 4   730 , R 5   732 ) from airflow rate measurement devices ( 716 ,  718 ,  720 ,  722 ,  724 ), respectively. In some embodiments, airflow measurement devices ( 716 ,  718 ,  720 ,  722 ,  724 ) are airflow meters with each meter including an airflow rate sensor. In some other embodiments, airflow measurement devices ( 716 ,  718 ,  720 ,  722 ,  724 ) are airflow sensors with the processing of the sensor outputs to determine measured rates being performed within the controller  701 . In some embodiments, the airflow rate sensors&#39; measurement signals are input to different channels of a meter included within controller  701 , e.g., with multiplexing occurring between the channels. 
         [0102]    Operation control steps  814 ,  816  and  820  are performed by the controller  701  based on the determination of step  804 . 
         [0103]    In step  818  controller  701  generates and sends control signals via control lines (C 1   702 , C 2   704 , C 3   706 , C 4   708 ) to close dampers ( 528 ,  530 ,  532 ,  534 ), respectively, to isolate the inactive gas turbine system from the active boiler system. 
         [0104]    In step  819  the controller  701  generates and send control signals on control lines (C 6   712 , C 7   714 ) to fans (FD fan  520 , PA fan  522 ) to control the throughput of the fans. In various embodiments, each fan ( 520 ,  524 ) is initially set at a predetermined fixed level corresponding to the second mode of operation in which the boiler  504  is active and the gas turbine  524  in inactive and since the gas turbine  524  is inactive no gas turbine flue gas is supplied to the boiler in the second mode of operation. In some such embodiments, the fan throughput rates are adjusted slightly, e.g., a change of 25% or less, from the initial nominal rates based on an oxygen sensor measurement. In some embodiments, the rates of step  819  are higher than the rates of step  842 , in which gas turbine flue gas is being input to the boiler. 
         [0105]    In step  822  the controller  701  generates and sends control signals via control lines (C 1   702 , C 2   704 , C 3   706 , C 4   708 ) to close dampers ( 528 ,  530 ,  532 ,  534 ), respectively, to isolate the inactive boiler system from the active gas turbine system. 
         [0106]    In step  828  the controller  701  determines desired gas turbine flue gas input injection levels for each of gas turbine flue gas inputs ( 570 ,  572 ,  574 ,  652   a  or  652   b ), which are inputs the boiler system, based on the measured oxygen level. Controller  701  generates and sends control signal via control lines (C 1   702 , C 2   704 , C 3   706 , C 4   708 ) to control the operation of dampers ( 528 ,  530 ,  532 ,  534 ), respectively. The control of step  828  includes controlling one or more dampers ( 528 ,  530 ,  532 ,  534 ) to be in an open position, which allows gas turbine flue gas to be input into the boiler system. In some embodiments, a damper is controlled to be either in a fully closed or fully open position. In some embodiments, a damper may be, and sometimes is controlled to be in a fully closed position, a fully open position, or a partially open position. In some such embodiments, control supports a fixed number of predetermined partially open conditions for a damper, e.g., 16 or less different partially open conditions. In some embodiments, control supports a continuous range of partially open conditions for a damper. 
         [0107]    Consider that the first gas turbine flue gas input is gas turbine flue gas hopper input  574  of boiler  504 . In step  830 , including step  836 , controller  701  generates and sends a control signal on control signal line C 3   706  to control the position of damper  532  to be in an open position, which results in flue gas  650  being input to flue gas hopper input  574  of boiler  504 . 
         [0108]    Further consider that the second gas turbine flue gas input is the gas turbine flue gas burner air supply duct input  572  which supplies air to a burner of said boiler  504 . In step  832 , including step  838 , controller  701  generates and sends a control signal on control signal line C 2   704  to control the position of damper  530  to be in an open position, which results in flue gas  648  being input into gas turbine flue gas burner air supply duct input  572  of duct  596 . 
         [0109]    Further consider that the third gas turbine flue gas input is the gas turbine flue gas mill air duct supply duct input  570 , which is included as part of a mill air duct  592  which supplies air to mill  502  which provides fuel  604  said boiler  504 . In step  834 , including step  840 , controller  701  generates and sends a control signal on control signal line C 1   702  to control the position of damper  528  to be in an open position, which results in flue gas  646  being input into the gas turbine flue gas mill air duct supply duct input  570  of the mill air duct  592 . 
         [0110]    In some embodiments, controller  701  generates and sends a control signal via control signal line C 4   708  to control the position of damper  534  to be in an open position, which results in gas turbine flue gas  652  being input into gas turbine flue gas input  576   a  of boiler  504  as flue gas  652   a  or which results in gas turbine flue gas  652  being input into gas turbine flue gas input  576   b  of duct  580  as flue gas  652   b , depending upon the particular embodiment of the boiler system. 
         [0111]    In some embodiments, controller  701  generates and sends a control signal via control signal line C 5   710  to control the position of damper  536  to be in an closed position, which results in gas turbine flue gas  652   b  entering economizer bypass duct  580  at input  576   b  and being directed toward boiler  504  where it enters the boiler  504  upstream of the economizer  511 . 
         [0112]    In step  842 , including steps  844  and  846 , controller  701  determines desired throughputs for FD fan  520  and PA fan  522 , generates and sends control signals on control lines (C 6   712 , C 7   714 ), respectively to control the throughputs of the fans ( 520 ,  522 ), respectively, which supply air  662 , e.g., fresh air, which is mixed with gas turbine flue gas prior to the mixed gas including the fresh air and the flue gas reaching the boiler. In various embodiments, the fan throughputs of step  842  are adjusted, e.g., lowered, with respect to gas turbine inactive mode of operation of step  819 , since with the gas turbine active some or all of the air  662  can be, and sometimes is replaced by gas turbine flue gas, i.e., not as much fresh air  662  is needed to be supplied to the burner system since some or all of the fresh air is replaced by flue gas from the gas turbine system. 
         [0113]    Various additional features of the present invention will now be described in connection with exemplary apparatus/system embodiments. The apparatus/system embodiments are only exemplary in nature and the features may be used in any number of combinations. 
         [0114]    A power system ( 100  or  500 ) embodiment 1 includes: a boiler system ( 103  or  503 ) including: a boiler ( 104  or  504 ); an oxygen sensor ( 444  or  734 ); and one or more gas turbine flue gas inputs (( 180 ,  214 ,  216 ,  218 ,  220 ) or ( 570 ,  572 ,  574 ,  576   a  or  576   b ))) including at least one of: i) a gas turbine flue gas boiler hopper input ( 220  or  574 ) of said boiler ( 104  or  504 ) or ii) a gas turbine flue gas mill air supply duct input ( 216  or  570 ) which is included as part of a mill air supply duct ( 209  or  592 ) which supplies air to a mill ( 102  or  502 ) which provides fuel ( 224  or  604 ) to said boiler ( 104  or  504 ); a gas turbine system ( 109  or  509 ); and a controller ( 401  or  701 ) for controlling the supply of gas turbine flue gas to said one or more gas turbine flue gas inputs (( 180 , 214 ,  216 ,  218 ,  220 ) or ( 570 ,  572 ,  574 ,  576   a  or  576   b )) of said boiler system ( 103  or  503 ) based on an oxygen level measured by said oxygen sensor ( 444  or  734 ). 
         [0115]    A power system embodiment 2 including the power system embodiment 1, wherein the boiler system ( 103  or  503 ) includes: a burner ( 152  or  505 ); and at least said gas turbine flue gas boiler hopper input ( 220  or  574 ) for receiving gas turbine flue gas ( 296 ) and supplying said received gas turbine flue gas ( 296 ) into said boiler ( 104  or  504 ) at a location beneath the burner ( 152  or  505 ). 
         [0116]    A power system embodiment 3 including the power system embodiment 2, wherein said boiler system ( 103  or  503 ) further includes: a burner air supply duct ( 196  or  596 ) which supplies air to a burner ( 152  or  505 ) of said boiler ( 104  or  504 ), said burner air supply duct ( 196  or  596 ) including a gas turbine flue gas burner air supply duct input ( 218  or  572 ). 
         [0117]    A power system embodiment 4 including the power system embodiment 2, wherein said boiler system ( 103  or  503 ) includes both the gas turbine flue gas boiler hopper input ( 220  or  574 ) of said boiler and the gas turbine flue gas mill air supply duct input ( 216  or  570 ). 
         [0118]    A power system embodiment 5 including the power system embodiment 2 wherein the power system embodiment 2 further includes: a first damper ( 142  or  532 ) in a first gas turbine flue gas duct ( 212  or  566 ) connected to said gas turbine flue gas boiler hopper input ( 220  or  574 ); and 
         [0119]    wherein said controller ( 401  or  701 ) is configured to control the first damper ( 142  or  532 ) to be in an open position during a first mode of operation during which both said gas turbine ( 126  or  524 ) and said boiler ( 104  or  504 ) are active. 
         [0120]    A power system embodiment 6 including the power system embodiment 5 wherein the power system embodiment 5 further includes: a fan (( 122  or  124 ) or ( 520  or  522 ) which blows air ( 258  or  584 ) which is mixed with gas turbine flue gas prior to the gas turbine flue gas reaching the boiler ( 104  or  504 ); and wherein said controller ( 401  or  701 ) is further configured to control the throughput of the fan (PA fan ( 124  or  522 ) or FD fan ( 122  or  520 )) as a function of the output of said oxygen sensor ( 444  or  734 ). 
         [0121]    A power system embodiment 7 including the power system embodiment 5, wherein said flue gas input of said boiler hopper ( 220  or  574 ) supplies more gas turbine flue gas to said boiler system ( 103  or  503 ) than any other gas turbine flue gas input (( 180 ,  214 ,  216 ,  218 ) or ( 570 ,  572 ,  576   a  or  576   b )) supplies to said boiler system ( 103  or  503 ). 
         [0122]    A power system embodiment 8 including the power system embodiment 2, wherein said controller ( 401  or  701 ) is further configured to control dampers (( 134 ,  136 ,  138 ,  140 ,  142 ) or ( 528 ,  530 ,  532 ,  534 )) to isolate said boiler system ( 103  or  503 ) from said gas turbine system ( 109  or  509 ) when said boiler system ( 103  or  503 ) is active and said gas turbine system ( 109  or  509 ) is inactive. 
         [0123]    A power system embodiment 9 including the power system embodiment 8, wherein said controller ( 401  or  701 ) is further configured to control said dampers (( 134 ,  136 ,  138 ,  140 ,  142 ) or ( 528 ,  530 ,  532 ,  534 )) to isolate said boiler system ( 103  or  503 ) from said gas turbine system ( 109  or  509 ) when said boiler system ( 103  or  503 ) is inactive and said gas turbine system ( 109  or  509 ) is active. 
         [0124]    Various additional features of the present invention will now be described in connection with exemplary method embodiments. The method embodiments are only exemplary in nature and the features may be used in any number of combinations. 
         [0125]    A method embodiment 1 of operating a system ( 100  or  500 ) including a boiler system ( 103  or  503 ) and a gas turbine system ( 109  or  509 ), the boiler system ( 103  or  503 ) including a boiler ( 104  or  504 ), the gas turbine system ( 109  or  509 ) including a gas turbine ( 524 ), the method including: measuring an oxygen level in flue gas output by the boiler ( 104  or  504 ); operating a controller ( 401  or  701 ), during a first mode of operation during which said boiler ( 504 ) is active and said gas turbine ( 524 ) is active, to control the supply of gas turbine flue gas to a first gas turbine flue gas input of said boiler system based on the measured oxygen level, said first flue gas input being one of: i) a gas turbine flue gas boiler hopper input ( 220  or  574 ) of a boiler ( 104  or  504 ), ii) a gas turbine flue gas burner air supply duct input ( 210  or  572 ) which supplies air to a burner ( 152  or  505 ) of said boiler ( 104  or  504 ), or iii) a gas turbine flue gas mill air supply duct input ( 216  or  570 ) which is included as part of a mill air supply duct ( 209  or  592 ) which supplies air to a mill ( 102  or  502 ) which provides fuel ( 224 ) to said boiler ( 104  or  504 ). 
         [0126]    A method embodiment 2 including the method of method embodiment 1, wherein operating the controller ( 401  or  701 ), during the first mode of operation includes operating the controller ( 401  or  701 ) to control a position of a first damper used to control the supply of gas turbine flue gas to the first gas turbine flue gas input to be in an open position. 
         [0127]    A method embodiment 3 including the method of method embodiment 2, the method of method embodiment 3 further including: operating the controller to control the throughput of a fan (PA fan or FD fan) which supplies air which is mixed with gas turbine flue gas prior to the gas turbine flue gas reaching the boiler. 
         [0128]    A method embodiment 4 including the method of method embodiment 2, wherein said controller further controls during the first mode of operation a supply of gas turbine flue gas to a second gas turbine flue gas input of said boiler system based on the measured oxygen level, the second flue gas input being one of: i) a boiler hopper input of a boiler, ii) a burner air supply duct which supplies air to a burner of said boiler, or iii) a mill air supply duct which supplies air to a mill which provides fuel to said boiler, said second flue gas input being different from said first flue gas input. 
         [0129]    A method embodiment 5 including the method of method embodiment 4, wherein said first flue gas input is said gas turbine flue gas boiler hopper input and said second flue gas input is one of the gas turbine flue gas burner air supply duct input or the gas turbine flue gas mill air supply duct input. 
         [0130]    A method embodiment 6 including the method of method embodiment 5, wherein said controller further controls during the first mode of operation a supply of gas turbine flue gas to a third gas turbine flue gas input of said boiler system based on the measured oxygen level, the third flue gas input being the gas turbine flue gas mill air supply duct input, said second flue gas input being different from said first flue gas input. 
         [0131]    A method embodiment 7 including the method of method embodiment 1, the method of method embodiment 7 further including: operating the controller, during a second mode of operation during which said boiler is not active and said gas turbine is active, to prevent the supply of gas turbine flue gas to the first flue gas input of said boiler system. 
         [0132]    A method embodiment 8 including the method of method embodiment 1, the method of method embodiment 8 further including: operating the controller, during a second mode of operation during which said boiler is active and said gas turbine is not active to close dampers between the gas turbine system and said boiler system to isolate the inactive gas turbine system from the active boiler system. 
         [0133]    A method embodiment 9 including the method of method embodiment 8, the method of method embodiment 9 further including: operating the controller, during a third mode of operation during which said boiler is not active and said gas turbine is active to close said dampers between the gas turbine system and said boiler system to isolate the inactive boiler system from the active gas turbine system. 
         [0134]    Numerous additional variations on the methods and apparatus of the present invention described above will be apparent to those skilled in the art in view of the above description of the invention. Such variations are to be considered within the scope of the invention.