Patent Publication Number: US-9903588-B2

Title: System and method for barrier in passage of combustor of gas turbine engine with exhaust gas recirculation

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to and benefit of U.S. Provisional Patent Application No. 61/860,214, entitled “SYSTEM AND METHOD OF CONTROLLING COMBUSTION AND EMISSIONS IN GAS TURBINE ENGINE WITH EXHAUST GAS RECIRCULATION,” filed Jul. 30, 2013, which is hereby incorporated by reference in its entirety for all purposes. 
    
    
     BACKGROUND 
     The subject matter disclosed herein relates to gas turbines, and more specifically, to gas turbines with exhaust gas recirculation. 
     Gas turbine engines are used in a wide variety of applications, such as power generation, aircraft, and various machinery. Gas turbine engines generally combust a fuel with an oxidant (e.g., air) in a combustor section to generate hot combustion gases, which then drive one or more turbine stages of a turbine section. In turn, the turbine section drives one or more compressor stages of a compressor section, thereby compressing oxidant for intake into the combustor section along with the fuel. Again, the fuel and oxidant mix in the combustor section, and then combust to produce the hot combustion gases. Unfortunately, certain components of the combustor section are exposed to high temperatures, which may reduce the life of the components. Furthermore, cooling the components or combustion gases with oxidant may increase the concentrations of oxidant in the exhaust gas. 
     BRIEF DESCRIPTION 
     Certain embodiments commensurate in scope with the originally claimed invention are summarized below. These embodiments are not intended to limit the scope of the claimed invention, but rather these embodiments are intended only to provide a brief summary of possible forms of the invention. Indeed, the invention may encompass a variety of forms that may be similar to or different from the embodiments set forth below. 
     In one embodiment, a system includes a turbine combustor having a combustor liner disposed about a combustion chamber, a head end upstream of the combustion chamber relative to a downstream direction of a flow of combustion gases through the combustion chamber, a flow sleeve disposed at an offset about the combustor liner to define a passage, and a barrier within the passage. The head end is configured to direct an oxidant flow and a first fuel flow toward the combustion chamber. The passage is configured to direct a gas flow toward the head end and to direct a portion of the oxidant flow toward a turbine end of the turbine combustor. The gas flow includes a substantially inert gas. The barrier is configured to block the portion of the oxidant flow toward the turbine end and to block the gas flow toward the head end within the passage. 
     In another embodiment, a system includes a turbine combustor having a combustor liner disposed about a combustion chamber and a flow sleeve disposed at an offset about the combustor liner to define a passage. The passage includes an oxidant section configured to direct an oxidant in a first direction to react with a first fuel in the combustion chamber to produce combustion gases. The passage also includes a cooling section configured to direct an inert gas in a second direction substantially opposite to the first direction. The inert gas is configured to cool the combustor liner and the combustion gases in the combustion chamber. The passage also includes a barrier section between the oxidant section and the cooling section. The barrier section is configured to substantially separate the oxidant in the oxidant section from the inert gas in the cooling section. 
     In another embodiment, a method includes injecting an oxidant and fuel into a combustion chamber from a head end of a turbine combustor, combusting the oxidant and the fuel in the combustion chamber to provide substantially stoichiometric combustion, and cooling the combustion chamber with an exhaust gas flow. The exhaust gas flow is directed upstream from a turbine end of the turbine combustor toward the head end along a passage disposed about the combustion chamber. The method also includes blocking the exhaust gas flow within the passage with a barrier. The barrier includes a dynamic barrier, a physical barrier, or any combination thereof. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein: 
         FIG. 1  is a diagram of an embodiment of a system having a turbine-based service system coupled to a hydrocarbon production system; 
         FIG. 2  is a diagram of an embodiment of the system of  FIG. 1 , further illustrating a control system and a combined cycle system; 
         FIG. 3  is a diagram of an embodiment of the system of  FIGS. 1 and 2 , further illustrating details of a gas turbine engine, exhaust gas supply system, and exhaust gas processing system; 
         FIG. 4  is a flow chart of an embodiment of a process for operating the system of  FIGS. 1-3 ; 
         FIG. 5  is a schematic diagram of an embodiment of a combustor section of a gas turbine engine with exhaust gas recirculation and a barrier section within a flow sleeve; 
         FIG. 6  is a schematic diagram of an embodiment of a combustor section of the gas turbine engine of  FIG. 5  with a dynamic barrier within the barrier section; 
         FIG. 7  is a schematic diagram of an embodiment of a combustor section of the gas turbine engine of  FIG. 5  with a physical barrier within the barrier section; 
         FIG. 8  is a cross-sectional view of an embodiment of a turbine combustor taken along line  8 - 8  of  FIG. 7 ; and 
         FIG. 9  is a cross-sectional view of an embodiment of a turbine combustor taken along line  8 - 8  of  FIG. 7 . 
     
    
    
     DETAILED DESCRIPTION 
     One or more specific embodiments of the present invention will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in an engineering or design project, numerous implementation-specific decisions are made to achieve the specific goals, such as compliance with system-related and/or business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. 
     Detailed example embodiments are disclosed herein. However, specific structural and functional details disclosed herein are merely representative for purposes of describing example embodiments. Embodiments of the present invention may, however, be embodied in many alternate forms, and should not be construed as limited to only the embodiments set forth herein. 
     Accordingly, while example embodiments are capable of various modifications and alternative forms, embodiments thereof are illustrated by way of example in the figures and will herein be described in detail. It should be understood, however, that there is no intent to limit example embodiments to the particular forms disclosed, but to the contrary, example embodiments are to cover all modifications, equivalents, and alternatives falling within the scope of the present invention. 
     The terminology used herein is for describing particular embodiments only and is not intended to be limiting of example embodiments. As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. The terms “comprises”, “comprising”, “includes” and/or “including”, when used herein, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. 
     Although the terms first, second, primary, secondary, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, but not limiting to, a first element could be termed a second element, and, similarly, a second element could be termed a first element, without departing from the scope of example embodiments. As used herein, the term “and/or” includes any, and all, combinations of one or more of the associated listed items. 
     Certain terminology may be used herein for the convenience of the reader only and is not to be taken as a limitation on the scope of the invention. For example, words such as “upper”, “lower”, “left”, “right”, “front”, “rear”, “top”, “bottom”, “horizontal”, “vertical”, “upstream”, “downstream”, “fore”, “aft”, and the like; merely describe the configuration shown in the figures. Indeed, the element or elements of an embodiment of the present invention may be oriented in any direction and the terminology, therefore, should be understood as encompassing such variations unless specified otherwise. 
     As discussed in detail below, the disclosed embodiments relate generally to gas turbine systems with exhaust gas recirculation (EGR), and particularly stoichiometric operation of the gas turbine systems using EGR. For example, the gas turbine systems may be configured to recirculate the exhaust gas along an exhaust recirculation path, stoichiometrically combust fuel and oxidant along with at least some of the recirculated exhaust gas, and capture the exhaust gas for use in various target systems. The recirculation of the exhaust gas along with stoichiometric combustion may help to increase the concentration level of carbon dioxide (CO 2 ) in the exhaust gas, which can then be post treated to separate and purify the CO 2  and nitrogen (N 2 ) for use in various target systems. The gas turbine systems also may employ various exhaust gas processing (e.g., heat recovery, catalyst reactions, etc.) along the exhaust recirculation path, thereby increasing the concentration level of CO 2 , reducing concentration levels of other emissions (e.g., carbon monoxide, nitrogen oxides, and unburnt hydrocarbons), and increasing energy recovery (e.g., with heat recovery units). Furthermore, the gas turbine engines may be configured to combust the fuel and oxidant with one or more diffusion flames (e.g., using diffusion fuel nozzles), premix flames (e.g., using premix fuel nozzles), or any combination thereof. In certain embodiments, the diffusion flames may help to maintain stability and operation within certain limits for stoichiometric combustion, which in turn helps to increase production of CO 2 . For example, a gas turbine system operating with diffusion flames may enable a greater quantity of EGR, as compared to a gas turbine system operating with premix flames. In turn, the increased quantity of EGR helps to increase CO 2  production. Possible target systems include pipelines, storage tanks, carbon sequestration systems, and hydrocarbon production systems, such as enhanced oil recovery (EOR) systems. 
     Some embodiments of a stoichiometric exhaust gas recirculation (SEGR) gas turbine system, as described below, may supply the oxidant and the fuel into a combustion chamber from a head end portion of a combustor, and separately supply an inert gas (e.g., exhaust gas) to the combustor at an opposite turbine end portion of the combustor to cool the combustor liner and combustion gases within the combustion chamber. A barrier (e.g., physical barrier, partial physical barrier, dynamic barrier) in a passage along the combustor liner may separate the oxidant and the inert gas outside of the combustion chamber. In some embodiments, the combustor may have differentially supplied and controlled sets of fuel nozzles to inject the oxidant and one or more fuels into the combustion chamber. The oxidant and the inert gas may flow through the passage in opposite directions. The oxidant and the inert gas may not mix upstream of the flame (e.g., combustion reaction) within the combustion chamber. In some embodiments, the oxidant is concentrated near the flame zone to increase the efficiency of combustion, thereby affecting the equivalence ratio. Adjusting the equivalence ratio to approximately 1.0 (e.g., between 0.95 and 1.05) may reduce the concentrations of oxidant, fuel, and/or other components (e.g., nitrogen oxides, water) within the exhaust gases of the SEGR gas turbine system. However, the combustion temperature also may be greater at an equivalence ratio at or near 1.0 (e.g., substantially stoichiometric combustion). The greater combustion temperature may create greater emissions, such as nitrogen oxide (NO x ) emissions. The inert gas (e.g., exhaust gas) may be a heat sink for the combustor and/or combustion gases. In other words, the inert gas (e.g., exhaust gas) may help to reduce the temperature of combustion gases, thereby reducing the NO emissions without introducing more oxidant (e.g., oxygen) into the combustion gases. In some embodiments, adjusting the equivalence ratio to approximately 1.0 may increase the concentration of carbon dioxide that may be utilized in an enhanced oil recovery system, while the use of exhaust gas as the diluent maintains low levels of NO x , oxygen, and fuel in the combustion gases. The exhaust gas, or the carbon dioxide extracted from the exhaust gas, may be utilized by a fluid injection system for enhanced oil recovery. 
       FIG. 1  is a diagram of an embodiment of a system  10  having a hydrocarbon production system  12  associated with a turbine-based service system  14 . As discussed in further detail below, various embodiments of the turbine-based service system  14  are configured to provide various services, such as electrical power, mechanical power, and fluids (e.g., exhaust gas), to the hydrocarbon production system  12  to facilitate the production or retrieval of oil and/or gas. In the illustrated embodiment, the hydrocarbon production system  12  includes an oil/gas extraction system  16  and an enhanced oil recovery (EOR) system  18 , which are coupled to a subterranean reservoir  20  (e.g., an oil, gas, or hydrocarbon reservoir). The oil/gas extraction system  16  includes a variety of surface equipment  22 , such as a Christmas tree or production tree  24 , coupled to an oil/gas well  26 . Furthermore, the well  26  may include one or more tubulars  28  extending through a drilled bore  30  in the earth  32  to the subterranean reservoir  20 . The tree  24  includes one or more valves, chokes, isolation sleeves, blowout preventers, and various flow control devices, which regulate pressures and control flows to and from the subterranean reservoir  20 . While the tree  24  is generally used to control the flow of the production fluid (e.g., oil or gas) out of the subterranean reservoir  20 , the EOR system  18  may increase the production of oil or gas by injecting one or more fluids into the subterranean reservoir  20 . 
     Accordingly, the EOR system  18  may include a fluid injection system  34 , which has one or more tubulars  36  extending through a bore  38  in the earth  32  to the subterranean reservoir  20 . For example, the EOR system  18  may route one or more fluids  40 , such as gas, steam, water, chemicals, or any combination thereof, into the fluid injection system  34 . For example, as discussed in further detail below, the EOR system  18  may be coupled to the turbine-based service system  14 , such that the system  14  routes an exhaust gas  42  (e.g., substantially or entirely free of oxygen) to the EOR system  18  for use as the injection fluid  40 . The fluid injection system  34  routes the fluid  40  (e.g., the exhaust gas  42 ) through the one or more tubulars  36  into the subterranean reservoir  20 , as indicated by arrows  44 . The injection fluid  40  enters the subterranean reservoir  20  through the tubular  36  at an offset distance  46  away from the tubular  28  of the oil/gas well  26 . Accordingly, the injection fluid  40  displaces the oil/gas  48  disposed in the subterranean reservoir  20 , and drives the oil/gas  48  up through the one or more tubulars  28  of the hydrocarbon production system  12 , as indicated by arrows  50 . As discussed in further detail below, the injection fluid  40  may include the exhaust gas  42  originating from the turbine-based service system  14 , which is able to generate the exhaust gas  42  on-site as needed by the hydrocarbon production system  12 . In other words, the turbine-based system  14  may simultaneously generate one or more services (e.g., electrical power, mechanical power, steam, water (e.g., desalinated water), and exhaust gas (e.g., substantially free of oxygen)) for use by the hydrocarbon production system  12 , thereby reducing or eliminating the reliance on external sources of such services. 
     In the illustrated embodiment, the turbine-based service system  14  includes a stoichiometric exhaust gas recirculation (SEGR) gas turbine system  52  and an exhaust gas (EG) processing system  54 . The gas turbine system  52  may be configured to operate in a stoichiometric combustion mode of operation (e.g., a stoichiometric control mode) and a non-stoichiometric combustion mode of operation (e.g., a non-stoichiometric control mode), such as a fuel-lean control mode or a fuel-rich control mode. In the stoichiometric control mode, the combustion generally occurs in a substantially stoichiometric ratio of a fuel and oxidant, thereby resulting in substantially stoichiometric combustion. In particular, stoichiometric combustion generally involves consuming substantially all of the fuel and oxidant in the combustion reaction, such that the products of combustion are substantially or entirely free of unburnt fuel and oxidant. One measure of stoichiometric combustion is the equivalence ratio, or phi (Φ), which is the ratio of the actual fuel/oxidant ratio relative to the stoichiometric fuel/oxidant ratio. An equivalence ratio of greater than 1.0 results in a fuel-rich combustion of the fuel and oxidant, whereas an equivalence ratio of less than 1.0 results in a fuel-lean combustion of the fuel and oxidant. In contrast, an equivalence ratio of 1.0 results in combustion that is neither fuel-rich nor fuel-lean, thereby substantially consuming all of the fuel and oxidant in the combustion reaction. In context of the disclosed embodiments, the term stoichiometric or substantially stoichiometric may refer to an equivalence ratio of approximately 0.95 to approximately 1.05. However, the disclosed embodiments may also include an equivalence ratio of 1.0 plus or minus 0.01, 0.02, 0.03, 0.04, 0.05, or more. Again, the stoichiometric combustion of fuel and oxidant in the turbine-based service system  14  may result in products of combustion or exhaust gas (e.g.,  42 ) with substantially no unburnt fuel or oxidant remaining. For example, the exhaust gas  42  may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO X ), carbon monoxide (CO), sulfur oxides (e.g., SO X ), hydrogen, and other products of incomplete combustion. By further example, the exhaust gas  42  may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO X ), carbon monoxide (CO), sulfur oxides (e.g., SO X ), hydrogen, and other products of incomplete combustion. However, the disclosed embodiments also may produce other ranges of residual fuel, oxidant, and other emissions levels in the exhaust gas  42 . As used herein, the terms emissions, emissions levels, and emissions targets may refer to concentration levels of certain products of combustion (e.g., NO X , CO, SO X , O 2 , N 2 , H 2 , HCs, etc.), which may be present in recirculated gas streams, vented gas streams (e.g., exhausted into the atmosphere), and gas streams used in various target systems (e.g., the hydrocarbon production system  12 ). 
     Although the SEGR gas turbine system  52  and the EG processing system  54  may include a variety of components in different embodiments, the illustrated EG processing system  54  includes a heat recovery steam generator (HRSG)  56  and an exhaust gas recirculation (EGR) system  58 , which receive and process an exhaust gas  60  originating from the SEGR gas turbine system  52 . The HRSG  56  may include one or more heat exchangers, condensers, and various heat recovery equipment, which collectively function to transfer heat from the exhaust gas  60  to a stream of water, thereby generating steam  62 . The steam  62  may be used in one or more steam turbines, the EOR system  18 , or any other portion of the hydrocarbon production system  12 . For example, the HRSG  56  may generate low pressure, medium pressure, and/or high pressure steam  62 , which may be selectively applied to low, medium, and high pressure steam turbine stages, or different applications of the EOR system  18 . In addition to the steam  62 , a treated water  64 , such as a desalinated water, may be generated by the HRSG  56 , the EGR system  58 , and/or another portion of the EG processing system  54  or the SEGR gas turbine system  52 . The treated water  64  (e.g., desalinated water) may be particularly useful in areas with water shortages, such as inland or desert regions. The treated water  64  may be generated, at least in part, due to the large volume of air driving combustion of fuel within the SEGR gas turbine system  52 . While the on-site generation of steam  62  and water  64  may be beneficial in many applications (including the hydrocarbon production system  12 ), the on-site generation of exhaust gas  42 ,  60  may be particularly beneficial for the EOR system  18 , due to its low oxygen content, high pressure, and heat derived from the SEGR gas turbine system  52 . Accordingly, the HRSG  56 , the EGR system  58 , and/or another portion of the EG processing system  54  may output or recirculate an exhaust gas  66  into the SEGR gas turbine system  52 , while also routing the exhaust gas  42  to the EOR system  18  for use with the hydrocarbon production system  12 . Likewise, the exhaust gas  42  may be extracted directly from the SEGR gas turbine system  52  (i.e., without passing through the EG processing system  54 ) for use in the EOR system  18  of the hydrocarbon production system  12 . 
     The exhaust gas recirculation is handled by the EGR system  58  of the EG processing system  54 . For example, the EGR system  58  includes one or more conduits, valves, blowers, exhaust gas treatment systems (e.g., filters, particulate removal units, gas separation units, gas purification units, heat exchangers, heat recovery units, moisture removal units, catalyst units, chemical injection units, or any combination thereof), and controls to recirculate the exhaust gas along an exhaust gas circulation path from an output (e.g., discharged exhaust gas  60 ) to an input (e.g., intake exhaust gas  66 ) of the SEGR gas turbine system  52 . In the illustrated embodiment, the SEGR gas turbine system  52  intakes the exhaust gas  66  into a compressor section having one or more compressors, thereby compressing the exhaust gas  66  for use in a combustor section along with an intake of an oxidant  68  and one or more fuels  70 . The oxidant  68  may include ambient air, pure oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, or any suitable oxidant that facilitates combustion of the fuel  70 . The fuel  70  may include one or more gas fuels, liquid fuels, or any combination thereof. For example, the fuel  70  may include natural gas, liquefied natural gas (LNG), syngas, methane, ethane, propane, butane, naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or any combination thereof. 
     The SEGR gas turbine system  52  mixes and combusts the exhaust gas  66 , the oxidant  68 , and the fuel  70  in the combustor section, thereby generating hot combustion gases or exhaust gas  60  to drive one or more turbine stages in a turbine section. In certain embodiments, each combustor in the combustor section includes one or more premix fuel nozzles, one or more diffusion fuel nozzles, or any combination thereof. For example, each premix fuel nozzle may be configured to mix the oxidant  68  and the fuel  70  internally within the fuel nozzle and/or partially upstream of the fuel nozzle, thereby injecting an oxidant-fuel mixture from the fuel nozzle into the combustion zone for a premixed combustion (e.g., a premixed flame). By further example, each diffusion fuel nozzle may be configured to isolate the flows of oxidant  68  and fuel  70  within the fuel nozzle, thereby separately injecting the oxidant  68  and the fuel  70  from the fuel nozzle into the combustion zone for diffusion combustion (e.g., a diffusion flame). In particular, the diffusion combustion provided by the diffusion fuel nozzles delays mixing of the oxidant  68  and the fuel  70  until the point of initial combustion, i.e., the flame region. In embodiments employing the diffusion fuel nozzles, the diffusion flame may provide increased flame stability, because the diffusion flame generally forms at the point of stoichiometry between the separate streams of oxidant  68  and fuel  70  (i.e., as the oxidant  68  and fuel  70  are mixing). In certain embodiments, one or more diluents (e.g., the exhaust gas  60 , steam, nitrogen, or another inert gas) may be pre-mixed with the oxidant  68 , the fuel  70 , or both, in either the diffusion fuel nozzle or the premix fuel nozzle. In addition, one or more diluents (e.g., the exhaust gas  60 , steam, nitrogen, or another inert gas) may be injected into the combustor at or downstream from the point of combustion within each combustor. The use of these diluents may help temper the flame (e.g., premix flame or diffusion flame), thereby helping to reduce NO X  emissions, such as nitrogen monoxide (NO) and nitrogen dioxide (NO 2 ). Regardless of the type of flame, the combustion produces hot combustion gases or exhaust gas  60  to drive one or more turbine stages. As each turbine stage is driven by the exhaust gas  60 , the SEGR gas turbine system  52  generates a mechanical power  72  and/or an electrical power  74  (e.g., via an electrical generator). The system  52  also outputs the exhaust gas  60 , and may further output water  64 . Again, the water  64  may be a treated water, such as a desalinated water, which may be useful in a variety of applications on-site or off-site. 
     Exhaust extraction is also provided by the SEGR gas turbine system  52  using one or more extraction points  76 . For example, the illustrated embodiment includes an exhaust gas (EG) supply system  78  having an exhaust gas (EG) extraction system  80  and an exhaust gas (EG) treatment system  82 , which receive exhaust gas  42  from the extraction points  76 , treat the exhaust gas  42 , and then supply or distribute the exhaust gas  42  to various target systems. The target systems may include the EOR system  18  and/or other systems, such as a pipeline  86 , a storage tank  88 , or a carbon sequestration system  90 . The EG extraction system  80  may include one or more conduits, valves, controls, and flow separations, which facilitate isolation of the exhaust gas  42  from the oxidant  68 , the fuel  70 , and other contaminants, while also controlling the temperature, pressure, and flow rate of the extracted exhaust gas  42 . The EG treatment system  82  may include one or more heat exchangers (e.g., heat recovery units such as heat recovery steam generators, condensers, coolers, or heaters), catalyst systems (e.g., oxidation catalyst systems), particulate and/or water removal systems (e.g., gas dehydration units, inertial separators, coalescing filters, water impermeable filters, and other filters), chemical injection systems, solvent based treatment systems (e.g., absorbers, flash tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and/or a solvent based treatment system, exhaust gas compressors, any combination thereof. These subsystems of the EG treatment system  82  enable control of the temperature, pressure, flow rate, moisture content (e.g., amount of water removal), particulate content (e.g., amount of particulate removal), and gas composition (e.g., percentage of CO 2 , N 2 , etc.). 
     The extracted exhaust gas  42  is treated by one or more subsystems of the EG treatment system  82 , depending on the target system. For example, the EG treatment system  82  may direct all or part of the exhaust gas  42  through a carbon capture system, a gas separation system, a gas purification system, and/or a solvent based treatment system, which is controlled to separate and purify a carbonaceous gas (e.g., carbon dioxide)  92  and/or nitrogen (N 2 )  94  for use in the various target systems. For example, embodiments of the EG treatment system  82  may perform gas separation and purification to produce a plurality of different streams  95  of exhaust gas  42 , such as a first stream  96 , a second stream  97 , and a third stream  98 . The first stream  96  may have a first composition that is rich in carbon dioxide and/or lean in nitrogen (e.g., a CO 2  rich, N 2  lean stream). The second stream  97  may have a second composition that has intermediate concentration levels of carbon dioxide and/or nitrogen (e.g., intermediate concentration CO 2 , N 2  stream). The third stream  98  may have a third composition that is lean in carbon dioxide and/or rich in nitrogen (e.g., a CO 2  lean, N 2  rich stream). Each stream  95  (e.g.,  96 ,  97 , and  98 ) may include a gas dehydration unit, a filter, a gas compressor, or any combination thereof, to facilitate delivery of the stream  95  to a target system. In certain embodiments, the CO 2  rich, N 2  lean stream  96  may have a CO 2  purity or concentration level of greater than approximately 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume, and a N 2  purity or concentration level of less than approximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or percent by volume. In contrast, the CO 2  lean, N 2  rich stream  98  may have a CO 2  purity or concentration level of less than approximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or percent by volume, and an N 2  purity or concentration level of greater than approximately 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume. The intermediate concentration CO 2 , N 2  stream  97  may have a CO 2  purity or concentration level and/or a N 2  purity or concentration level of between approximately 30 to 70, 35 to 65, 40 to 60, or 45 to 55 percent by volume. Although the foregoing ranges are merely non-limiting examples, the CO 2  rich, N 2  lean stream  96  and the CO 2  lean, N 2  rich stream  98  may be particularly well suited for use with the EOR system  18  and the other systems  84 . However, any of these rich, lean, or intermediate concentration CO 2  streams  95  may be used, alone or in various combinations, with the EOR system  18  and the other systems  84 . For example, the EOR system  18  and the other systems  84  (e.g., the pipeline  86 , storage tank  88 , and the carbon sequestration system  90 ) each may receive one or more CO 2  rich, N 2  lean streams  96 , one or more CO 2  lean, N 2  rich streams  98 , one or more intermediate concentration CO 2 , N 2  streams  97 , and one or more untreated exhaust gas  42  streams (i.e., bypassing the EG treatment system  82 ). 
     The EG extraction system  80  extracts the exhaust gas  42  at one or more extraction points  76  along the compressor section, the combustor section, and/or the turbine section, such that the exhaust gas  42  may be used in the EOR system  18  and other systems  84  at suitable temperatures and pressures. The EG extraction system  80  and/or the EG treatment system  82  also may circulate fluid flows (e.g., exhaust gas  42 ) to and from the EG processing system  54 . For example, a portion of the exhaust gas  42  passing through the EG processing system  54  may be extracted by the EG extraction system  80  for use in the EOR system  18  and the other systems  84 . In certain embodiments, the EG supply system  78  and the EG processing system  54  may be independent or integral with one another, and thus may use independent or common subsystems. For example, the EG treatment system  82  may be used by both the EG supply system  78  and the EG processing system  54 . Exhaust gas  42  extracted from the EG processing system  54  may undergo multiple stages of gas treatment, such as one or more stages of gas treatment in the EG processing system  54  followed by one or more additional stages of gas treatment in the EG treatment system  82 . 
     At each extraction point  76 , the extracted exhaust gas  42  may be substantially free of oxidant  68  and fuel  70  (e.g., unburnt fuel or hydrocarbons) due to substantially stoichiometric combustion and/or gas treatment in the EG processing system  54 . Furthermore, depending on the target system, the extracted exhaust gas  42  may undergo further treatment in the EG treatment system  82  of the EG supply system  78 , thereby further reducing any residual oxidant  68 , fuel  70 , or other undesirable products of combustion. For example, either before or after treatment in the EG treatment system  82 , the extracted exhaust gas  42  may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO X ), carbon monoxide (CO), sulfur oxides (e.g., SO X ), hydrogen, and other products of incomplete combustion. By further example, either before or after treatment in the EG treatment system  82 , the extracted exhaust gas  42  may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO X ), carbon monoxide (CO), sulfur oxides (e.g., SO X ), hydrogen, and other products of incomplete combustion. Thus, the exhaust gas  42  is particularly well suited for use with the EOR system  18 . 
     The EGR operation of the turbine system  52  specifically enables the exhaust extraction at a multitude of locations  76 . For example, the compressor section of the system  52  may be used to compress the exhaust gas  66  without any oxidant  68  (i.e., only compression of the exhaust gas  66 ), such that a substantially oxygen-free exhaust gas  42  may be extracted from the compressor section and/or the combustor section prior to entry of the oxidant  68  and the fuel  70 . The extraction points  76  may be located at interstage ports between adjacent compressor stages, at ports along the compressor discharge casing, at ports along each combustor in the combustor section, or any combination thereof. In certain embodiments, the exhaust gas  66  may not mix with the oxidant  68  and fuel  70  until it reaches the head end portion and/or fuel nozzles of each combustor in the combustor section. Furthermore, one or more flow separators (e.g., walls, dividers, baffles, or the like) may be used to isolate the oxidant  68  and the fuel  70  from the extraction points  76 . With these flow separators, the extraction points  76  may be disposed directly along a wall of each combustor in the combustor section. 
     Once the exhaust gas  66 , oxidant  68 , and fuel  70  flow through the head end portion (e.g., through fuel nozzles) into the combustion portion (e.g., combustion chamber) of each combustor, the SEGR gas turbine system  52  is controlled to provide a substantially stoichiometric combustion of the exhaust gas  66 , oxidant  68 , and fuel  70 . For example, the system  52  may maintain an equivalence ratio of approximately 0.95 to approximately 1.05. As a result, the products of combustion of the mixture of exhaust gas  66 , oxidant  68 , and fuel  70  in each combustor is substantially free of oxygen and unburnt fuel. Thus, the products of combustion (or exhaust gas) may be extracted from the turbine section of the SEGR gas turbine system  52  for use as the exhaust gas  42  routed to the EOR system  18 . Along the turbine section, the extraction points  76  may be located at any turbine stage, such as interstage ports between adjacent turbine stages. Thus, using any of the foregoing extraction points  76 , the turbine-based service system  14  may generate, extract, and deliver the exhaust gas  42  to the hydrocarbon production system  12  (e.g., the EOR system  18 ) for use in the production of oil/gas  48  from the subterranean reservoir  20 . 
       FIG. 2  is a diagram of an embodiment of the system  10  of  FIG. 1 , illustrating a control system  100  coupled to the turbine-based service system  14  and the hydrocarbon production system  12 . In the illustrated embodiment, the turbine-based service system  14  includes a combined cycle system  102 , which includes the SEGR gas turbine system  52  as a topping cycle, a steam turbine  104  as a bottoming cycle, and the HRSG  56  to recover heat from the exhaust gas  60  to generate the steam  62  for driving the steam turbine  104 . Again, the SEGR gas turbine system  52  receives, mixes, and stoichiometrically combusts the exhaust gas  66 , the oxidant  68 , and the fuel  70  (e.g., premix and/or diffusion flames), thereby producing the exhaust gas  60 , the mechanical power  72 , the electrical power  74 , and/or the water  64 . For example, the SEGR gas turbine system  52  may drive one or more loads or machinery  106 , such as an electrical generator, an oxidant compressor (e.g., a main air compressor), a gear box, a pump, equipment of the hydrocarbon production system  12 , or any combination thereof. In some embodiments, the machinery  106  may include other drives, such as electrical motors or steam turbines (e.g., the steam turbine  104 ), in tandem with the SEGR gas turbine system  52 . Accordingly, an output of the machinery  106  driven by the SEGR gas turbines system  52  (and any additional drives) may include the mechanical power  72  and the electrical power  74 . The mechanical power  72  and/or the electrical power  74  may be used on-site for powering the hydrocarbon production system  12 , the electrical power  74  may be distributed to the power grid, or any combination thereof. The output of the machinery  106  also may include a compressed fluid, such as a compressed oxidant  68  (e.g., air or oxygen), for intake into the combustion section of the SEGR gas turbine system  52 . Each of these outputs (e.g., the exhaust gas  60 , the mechanical power  72 , the electrical power  74 , and/or the water  64 ) may be considered a service of the turbine-based service system  14 . 
     The SEGR gas turbine system  52  produces the exhaust gas  42 ,  60 , which may be substantially free of oxygen, and routes this exhaust gas  42 ,  60  to the EG processing system  54  and/or the EG supply system  78 . The EG supply system  78  may treat and delivery the exhaust gas  42  (e.g., streams  95 ) to the hydrocarbon production system  12  and/or the other systems  84 . As discussed above, the EG processing system  54  may include the HRSG  56  and the EGR system  58 . The HRSG  56  may include one or more heat exchangers, condensers, and various heat recovery equipment, which may be used to recover or transfer heat from the exhaust gas  60  to water  108  to generate the steam  62  for driving the steam turbine  104 . Similar to the SEGR gas turbine system  52 , the steam turbine  104  may drive one or more loads or machinery  106 , thereby generating the mechanical power  72  and the electrical power  74 . In the illustrated embodiment, the SEGR gas turbine system  52  and the steam turbine  104  are arranged in tandem to drive the same machinery  106 . However, in other embodiments, the SEGR gas turbine system  52  and the steam turbine  104  may separately drive different machinery  106  to independently generate mechanical power  72  and/or electrical power  74 . As the steam turbine  104  is driven by the steam  62  from the HRSG  56 , the steam  62  gradually decreases in temperature and pressure. Accordingly, the steam turbine  104  recirculates the used steam  62  and/or water  108  back into the HRSG  56  for additional steam generation via heat recovery from the exhaust gas  60 . In addition to steam generation, the HRSG  56 , the EGR system  58 , and/or another portion of the EG processing system  54  may produce the water  64 , the exhaust gas  42  for use with the hydrocarbon production system  12 , and the exhaust gas  66  for use as an input into the SEGR gas turbine system  52 . For example, the water  64  may be a treated water  64 , such as a desalinated water for use in other applications. The desalinated water may be particularly useful in regions of low water availability. Regarding the exhaust gas  60 , embodiments of the EG processing system  54  may be configured to recirculate the exhaust gas  60  through the EGR system  58  with or without passing the exhaust gas  60  through the HRSG  56 . 
     In the illustrated embodiment, the SEGR gas turbine system  52  has an exhaust recirculation path  110 , which extends from an exhaust outlet to an exhaust inlet of the system  52 . Along the path  110 , the exhaust gas  60  passes through the EG processing system  54 , which includes the HRSG  56  and the EGR system  58  in the illustrated embodiment. The EGR system  58  may include one or more conduits, valves, blowers, gas treatment systems (e.g., filters, particulate removal units, gas separation units, gas purification units, heat exchangers, heat recovery units such as heat recovery steam generators, moisture removal units, catalyst units, chemical injection units, or any combination thereof) in series and/or parallel arrangements along the path  110 . In other words, the EGR system  58  may include any flow control components, pressure control components, temperature control components, moisture control components, and gas composition control components along the exhaust recirculation path  110  between the exhaust outlet and the exhaust inlet of the system  52 . Accordingly, in embodiments with the HRSG  56  along the path  110 , the HRSG  56  may be considered a component of the EGR system  58 . However, in certain embodiments, the HRSG  56  may be disposed along an exhaust path independent from the exhaust recirculation path  110 . Regardless of whether the HRSG  56  is along a separate path or a common path with the EGR system  58 , the HRSG  56  and the EGR system  58  intake the exhaust gas  60  and output either the recirculated exhaust gas  66 , the exhaust gas  42  for use with the EG supply system  78  (e.g., for the hydrocarbon production system  12  and/or other systems  84 ), or another output of exhaust gas. Again, the SEGR gas turbine system  52  intakes, mixes, and stoichiometrically combusts the exhaust gas  66 , the oxidant  68 , and the fuel  70  (e.g., premixed and/or diffusion flames) to produce a substantially oxygen-free and fuel-free exhaust gas  60  for distribution to the EG processing system  54 , the hydrocarbon production system  12 , or other systems  84 . 
     As noted above with reference to  FIG. 1 , the hydrocarbon production system  12  may include a variety of equipment to facilitate the recovery or production of oil/gas  48  from a subterranean reservoir  20  through an oil/gas well  26 . For example, the hydrocarbon production system  12  may include the EOR system  18  having the fluid injection system  34 . In the illustrated embodiment, the fluid injection system  34  includes an exhaust gas injection EOR system  112  and a steam injection EOR system  114 . Although the fluid injection system  34  may receive fluids from a variety of sources, the illustrated embodiment may receive the exhaust gas  42  and the steam  62  from the turbine-based service system  14 . The exhaust gas  42  and/or the steam  62  produced by the turbine-based service system  14  also may be routed to the hydrocarbon production system  12  for use in other oil/gas systems  116 . 
     The quantity, quality, and flow of the exhaust gas  42  and/or the steam  62  may be controlled by the control system  100 . The control system  100  may be dedicated entirely to the turbine-based service system  14 , or the control system  100  may optionally also provide control (or at least some data to facilitate control) for the hydrocarbon production system  12  and/or other systems  84 . In the illustrated embodiment, the control system  100  includes a controller  118  having a processor  120 , a memory  122 , a steam turbine control  124 , a SEGR gas turbine system control  126 , and a machinery control  128 . The processor  120  may include a single processor or two or more redundant processors, such as triple redundant processors for control of the turbine-based service system  14 . The memory  122  may include volatile and/or non-volatile memory. For example, the memory  122  may include one or more hard drives, flash memory, read-only memory, random access memory, or any combination thereof. The controls  124 ,  126 , and  128  may include software and/or hardware controls. For example, the controls  124 ,  126 , and  128  may include various instructions or code stored on the memory  122  and executable by the processor  120 . The control  124  is configured to control operation of the steam turbine  104 , the SEGR gas turbine system control  126  is configured to control the system  52 , and the machinery control  128  is configured to control the machinery  106 . Thus, the controller  118  (e.g., controls  124 ,  126 , and  128 ) may be configured to coordinate various sub-systems of the turbine-based service system  14  to provide a suitable stream of the exhaust gas  42  to the hydrocarbon production system  12 . 
     In certain embodiments of the control system  100 , each element (e.g., system, subsystem, and component) illustrated in the drawings or described herein includes (e.g., directly within, upstream, or downstream of such element) one or more industrial control features, such as sensors and control devices, which are communicatively coupled with one another over an industrial control network along with the controller  118 . For example, the control devices associated with each element may include a dedicated device controller (e.g., including a processor, memory, and control instructions), one or more actuators, valves, switches, and industrial control equipment, which enable control based on sensor feedback  130 , control signals from the controller  118 , control signals from a user, or any combination thereof. Thus, any of the control functionality described herein may be implemented with control instructions stored and/or executable by the controller  118 , dedicated device controllers associated with each element, or a combination thereof. 
     In order to facilitate such control functionality, the control system  100  includes one or more sensors distributed throughout the system  10  to obtain the sensor feedback  130  for use in execution of the various controls, e.g., the controls  124 ,  126 , and  128 . For example, the sensor feedback  130  may be obtained from sensors distributed throughout the SEGR gas turbine system  52 , the machinery  106 , the EG processing system  54 , the steam turbine  104 , the hydrocarbon production system  12 , or any other components throughout the turbine-based service system  14  or the hydrocarbon production system  12 . For example, the sensor feedback  130  may include temperature feedback, pressure feedback, flow rate feedback, flame temperature feedback, combustion dynamics feedback, intake oxidant composition feedback, intake fuel composition feedback, exhaust composition feedback, the output level of mechanical power  72 , the output level of electrical power  74 , the output quantity of the exhaust gas  42 ,  60 , the output quantity or quality of the water  64 , or any combination thereof. For example, the sensor feedback  130  may include a composition of the exhaust gas  42 ,  60  to facilitate stoichiometric combustion in the SEGR gas turbine system  52 . For example, the sensor feedback  130  may include feedback from one or more intake oxidant sensors along an oxidant supply path of the oxidant  68 , one or more intake fuel sensors along a fuel supply path of the fuel  70 , and one or more exhaust emissions sensors disposed along the exhaust recirculation path  110  and/or within the SEGR gas turbine system  52 . The intake oxidant sensors, intake fuel sensors, and exhaust emissions sensors may include temperature sensors, pressure sensors, flow rate sensors, and composition sensors. The emissions sensors may includes sensors for nitrogen oxides (e.g., NO X  sensors), carbon oxides (e.g., CO sensors and CO 2  sensors), sulfur oxides (e.g., SO X  sensors), hydrogen (e.g., H 2  sensors), oxygen (e.g., O 2  sensors), unburnt hydrocarbons (e.g., HC sensors), or other products of incomplete combustion, or any combination thereof. 
     Using this feedback  130 , the control system  100  may adjust (e.g., increase, decrease, or maintain) the intake flow of exhaust gas  66 , oxidant  68 , and/or fuel  70  into the SEGR gas turbine system  52  (among other operational parameters) to maintain the equivalence ratio within a suitable range, e.g., between approximately 0.95 to approximately 1.05, between approximately 0.95 to approximately 1.0, between approximately 1.0 to approximately 1.05, or substantially at 1.0. For example, the control system  100  may analyze the feedback  130  to monitor the exhaust emissions (e.g., concentration levels of nitrogen oxides, carbon oxides such as CO and CO 2 , sulfur oxides, hydrogen, oxygen, unburnt hydrocarbons, and other products of incomplete combustion) and/or determine the equivalence ratio, and then control one or more components to adjust the exhaust emissions (e.g., concentration levels in the exhaust gas  42 ) and/or the equivalence ratio. The controlled components may include any of the components illustrated and described with reference to the drawings, including but not limited to, valves along the supply paths for the oxidant  68 , the fuel  70 , and the exhaust gas  66 ; an oxidant compressor, a fuel pump, or any components in the EG processing system  54 ; any components of the SEGR gas turbine system  52 , or any combination thereof. The controlled components may adjust (e.g., increase, decrease, or maintain) the flow rates, temperatures, pressures, or percentages (e.g., equivalence ratio) of the oxidant  68 , the fuel  70 , and the exhaust gas  66  that combust within the SEGR gas turbine system  52 . The controlled components also may include one or more gas treatment systems, such as catalyst units (e.g., oxidation catalyst units), supplies for the catalyst units (e.g., oxidation fuel, heat, electricity, etc.), gas purification and/or separation units (e.g., solvent based separators, absorbers, flash tanks, etc.), and filtration units. The gas treatment systems may help reduce various exhaust emissions along the exhaust recirculation path  110 , a vent path (e.g., exhausted into the atmosphere), or an extraction path to the EG supply system  78 . 
     In certain embodiments, the control system  100  may analyze the feedback  130  and control one or more components to maintain or reduce emissions levels (e.g., concentration levels in the exhaust gas  42 ,  60 ,  95 ) to a target range, such as less than approximately 10, 20, 30, 40, 50, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or 10000 parts per million by volume (ppmv). These target ranges may be the same or different for each of the exhaust emissions, e.g., concentration levels of nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen, unburnt hydrocarbons, and other products of incomplete combustion. For example, depending on the equivalence ratio, the control system  100  may selectively control exhaust emissions (e.g., concentration levels) of oxidant (e.g., oxygen) within a target range of less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 250, 500, 750, or 1000 ppmv; carbon monoxide (CO) within a target range of less than approximately 20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv; and nitrogen oxides (NO X ) within a target range of less than approximately 50, 100, 200, 300, 400, or 500 ppmv. In certain embodiments operating with a substantially stoichiometric equivalence ratio, the control system  100  may selectively control exhaust emissions (e.g., concentration levels) of oxidant (e.g., oxygen) within a target range of less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 ppmv; and carbon monoxide (CO) within a target range of less than approximately 500, 1000, 2000, 3000, 4000, or 5000 ppmv. In certain embodiments operating with a fuel-lean equivalence ratio (e.g., between approximately 0.95 to 1.0), the control system  100  may selectively control exhaust emissions (e.g., concentration levels) of oxidant (e.g., oxygen) within a target range of less than approximately 500, 600, 700, 800, 900, 1000, 1100, 1200, 1300, 1400, or 1500 ppmv; carbon monoxide (CO) within a target range of less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 150, or 200 ppmv; and nitrogen oxides (e.g., NO X ) within a target range of less than approximately 50, 100, 150, 200, 250, 300, 350, or 400 ppmv. The foregoing target ranges are merely examples, and are not intended to limit the scope of the disclosed embodiments. 
     The control system  100  also may be coupled to a local interface  132  and a remote interface  134 . For example, the local interface  132  may include a computer workstation disposed on-site at the turbine-based service system  14  and/or the hydrocarbon production system  12 . In contrast, the remote interface  134  may include a computer workstation disposed off-site from the turbine-based service system  14  and the hydrocarbon production system  12 , such as through an internet connection. These interfaces  132  and  134  facilitate monitoring and control of the turbine-based service system  14 , such as through one or more graphical displays of sensor feedback  130 , operational parameters, and so forth. 
     Again, as noted above, the controller  118  includes a variety of controls  124 ,  126 , and  128  to facilitate control of the turbine-based service system  14 . The steam turbine control  124  may receive the sensor feedback  130  and output control commands to facilitate operation of the steam turbine  104 . For example, the steam turbine control  124  may receive the sensor feedback  130  from the HRSG  56 , the machinery  106 , temperature and pressure sensors along a path of the steam  62 , temperature and pressure sensors along a path of the water  108 , and various sensors indicative of the mechanical power  72  and the electrical power  74 . Likewise, the SEGR gas turbine system control  126  may receive sensor feedback  130  from one or more sensors disposed along the SEGR gas turbine system  52 , the machinery  106 , the EG processing system  54 , or any combination thereof. For example, the sensor feedback  130  may be obtained from temperature sensors, pressure sensors, clearance sensors, vibration sensors, flame sensors, fuel composition sensors, exhaust gas composition sensors, or any combination thereof, disposed within or external to the SEGR gas turbine system  52 . Finally, the machinery control  128  may receive sensor feedback  130  from various sensors associated with the mechanical power  72  and the electrical power  74 , as well as sensors disposed within the machinery  106 . Each of these controls  124 ,  126 , and  128  uses the sensor feedback  130  to improve operation of the turbine-based service system  14 . 
     In the illustrated embodiment, the SEGR gas turbine system control  126  may execute instructions to control the quantity and quality of the exhaust gas  42 ,  60 ,  95  in the EG processing system  54 , the EG supply system  78 , the hydrocarbon production system  12 , and/or the other systems  84 . For example, the SEGR gas turbine system control  126  may maintain a level of oxidant (e.g., oxygen) and/or unburnt fuel in the exhaust gas  60  below a threshold suitable for use with the exhaust gas injection EOR system  112 . In certain embodiments, the threshold levels may be less than 1, 2, 3, 4, or 5 percent of oxidant (e.g., oxygen) and/or unburnt fuel by volume of the exhaust gas  42 ,  60 ; or the threshold levels of oxidant (e.g., oxygen) and/or unburnt fuel (and other exhaust emissions) may be less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) in the exhaust gas  42 ,  60 . By further example, in order to achieve these low levels of oxidant (e.g., oxygen) and/or unburnt fuel, the SEGR gas turbine system control  126  may maintain an equivalence ratio for combustion in the SEGR gas turbine system  52  between approximately 0.95 and approximately 1.05. The SEGR gas turbine system control  126  also may control the EG extraction system  80  and the EG treatment system  82  to maintain the temperature, pressure, flow rate, and gas composition of the exhaust gas  42 ,  60 ,  95  within suitable ranges for the exhaust gas injection EOR system  112 , the pipeline  86 , the storage tank  88 , and the carbon sequestration system  90 . As discussed above, the EG treatment system  82  may be controlled to purify and/or separate the exhaust gas  42  into one or more gas streams  95 , such as the CO 2  rich, N 2  lean stream  96 , the intermediate concentration CO 2 , N 2  stream  97 , and the CO 2  lean, N 2  rich stream  98 . In addition to controls for the exhaust gas  42 ,  60 , and  95 , the controls  124 ,  126 , and  128  may execute one or more instructions to maintain the mechanical power  72  within a suitable power range, or maintain the electrical power  74  within a suitable frequency and power range. 
       FIG. 3  is a diagram of embodiment of the system  10 , further illustrating details of the SEGR gas turbine system  52  for use with the hydrocarbon production system  12  and/or other systems  84 . In the illustrated embodiment, the SEGR gas turbine system  52  includes a gas turbine engine  150  coupled to the EG processing system  54 . The illustrated gas turbine engine  150  includes a compressor section  152 , a combustor section  154 , and an expander section or turbine section  156 . The compressor section  152  includes one or more exhaust gas compressors or compressor stages  158 , such as 1 to 20 stages of rotary compressor blades disposed in a series arrangement. Likewise, the combustor section  154  includes one or more combustors  160 , such as 1 to 20 combustors  160  distributed circumferentially about a rotational axis  162  of the SEGR gas turbine system  52 . Furthermore, each combustor  160  may include one or more fuel nozzles  164  configured to inject the exhaust gas  66 , the oxidant  68 , and/or the fuel  70 . For example, a head end portion  166  of each combustor  160  may house 1, 2, 3, 4, 5, 6, or more fuel nozzles  164 , which may inject streams or mixtures of the exhaust gas  66 , the oxidant  68 , and/or the fuel  70  into a combustion portion  168  (e.g., combustion chamber) of the combustor  160 . 
     The fuel nozzles  164  may include any combination of premix fuel nozzles  164  (e.g., configured to premix the oxidant  68  and fuel  70  for generation of an oxidant/fuel premix flame) and/or diffusion fuel nozzles  164  (e.g., configured to inject separate flows of the oxidant  68  and fuel  70  for generation of an oxidant/fuel diffusion flame). Embodiments of the premix fuel nozzles  164  may include swirl vanes, mixing chambers, or other features to internally mix the oxidant  68  and fuel  70  within the nozzles  164 , prior to injection and combustion in the combustion chamber  168 . The premix fuel nozzles  164  also may receive at least some partially mixed oxidant  68  and fuel  70 . In certain embodiments, each diffusion fuel nozzle  164  may isolate flows of the oxidant  68  and the fuel  70  until the point of injection, while also isolating flows of one or more diluents (e.g., the exhaust gas  66 , steam, nitrogen, or another inert gas) until the point of injection. In other embodiments, each diffusion fuel nozzle  164  may isolate flows of the oxidant  68  and the fuel  70  until the point of injection, while partially mixing one or more diluents (e.g., the exhaust gas  66 , steam, nitrogen, or another inert gas) with the oxidant  68  and/or the fuel  70  prior to the point of injection. In addition, one or more diluents (e.g., the exhaust gas  66 , steam, nitrogen, or another inert gas) may be injected into the combustor (e.g., into the hot products of combustion) either at or downstream from the combustion zone, thereby helping to reduce the temperature of the hot products of combustion and reduce emissions of NO X  (e.g., NO and NO 2 ). Regardless of the type of fuel nozzle  164 , the SEGR gas turbine system  52  may be controlled to provide substantially stoichiometric combustion of the oxidant  68  and fuel  70 . 
     In diffusion combustion embodiments using the diffusion fuel nozzles  164 , the fuel  70  and oxidant  68  generally do not mix upstream from the diffusion flame, but rather the fuel  70  and oxidant  68  mix and react directly at the flame surface and/or the flame surface exists at the location of mixing between the fuel  70  and oxidant  68 . In particular, the fuel  70  and oxidant  68  separately approach the flame surface (or diffusion boundary/interface), and then diffuse (e.g., via molecular and viscous diffusion) along the flame surface (or diffusion boundary/interface) to generate the diffusion flame. It is noteworthy that the fuel  70  and oxidant  68  may be at a substantially stoichiometric ratio along this flame surface (or diffusion boundary/interface), which may result in a greater flame temperature (e.g., a peak flame temperature) along this flame surface. The stoichiometric fuel/oxidant ratio generally results in a greater flame temperature (e.g., a peak flame temperature), as compared with a fuel-lean or fuel-rich fuel/oxidant ratio. As a result, the diffusion flame may be substantially more stable than a premix flame, because the diffusion of fuel  70  and oxidant  68  helps to maintain a stoichiometric ratio (and greater temperature) along the flame surface. Although greater flame temperatures can also lead to greater exhaust emissions, such as NO X  emissions, the disclosed embodiments use one or more diluents to help control the temperature and emissions while still avoiding any premixing of the fuel  70  and oxidant  68 . For example, the disclosed embodiments may introduce one or more diluents separate from the fuel  70  and oxidant  68  (e.g., after the point of combustion and/or downstream from the diffusion flame), thereby helping to reduce the temperature and reduce the emissions (e.g., NO X  emissions) produced by the diffusion flame. 
     In operation, as illustrated, the compressor section  152  receives and compresses the exhaust gas  66  from the EG processing system  54 , and outputs a compressed exhaust gas  170  to each of the combustors  160  in the combustor section  154 . Upon combustion of the fuel  60 , oxidant  68 , and exhaust gas  170  within each combustor  160 , additional exhaust gas or products of combustion  172  (i.e., combustion gas) is routed into the turbine section  156 . Similar to the compressor section  152 , the turbine section  156  includes one or more turbines or turbine stages  174 , which may include a series of rotary turbine blades. These turbine blades are then driven by the products of combustion  172  generated in the combustor section  154 , thereby driving rotation of a shaft  176  coupled to the machinery  106 . Again, the machinery  106  may include a variety of equipment coupled to either end of the SEGR gas turbine system  52 , such as machinery  106 ,  178  coupled to the turbine section  156  and/or machinery  106 ,  180  coupled to the compressor section  152 . In certain embodiments, the machinery  106 ,  178 ,  180  may include one or more electrical generators, oxidant compressors for the oxidant  68 , fuel pumps for the fuel  70 , gear boxes, or additional drives (e.g. steam turbine  104 , electrical motor, etc.) coupled to the SEGR gas turbine system  52 . Non-limiting examples are discussed in further detail below with reference to TABLE 1. As illustrated, the turbine section  156  outputs the exhaust gas  60  to recirculate along the exhaust recirculation path  110  from an exhaust outlet  182  of the turbine section  156  to an exhaust inlet  184  into the compressor section  152 . Along the exhaust recirculation path  110 , the exhaust gas  60  passes through the EG processing system  54  (e.g., the HRSG  56  and/or the EGR system  58 ) as discussed in detail above. 
     Again, each combustor  160  in the combustor section  154  receives, mixes, and stoichiometrically combusts the compressed exhaust gas  170 , the oxidant  68 , and the fuel  70  to produce the additional exhaust gas or products of combustion  172  to drive the turbine section  156 . In certain embodiments, the oxidant  68  is compressed by an oxidant compression system  186 , such as a main oxidant compression (MOC) system (e.g., a main air compression (MAC) system) having one or more oxidant compressors (MOCs). The oxidant compression system  186  includes an oxidant compressor  188  coupled to a drive  190 . For example, the drive  190  may include an electric motor, a combustion engine, or any combination thereof. In certain embodiments, the drive  190  may be a turbine engine, such as the gas turbine engine  150 . Accordingly, the oxidant compression system  186  may be an integral part of the machinery  106 . In other words, the compressor  188  may be directly or indirectly driven by the mechanical power  72  supplied by the shaft  176  of the gas turbine engine  150 . In such an embodiment, the drive  190  may be excluded, because the compressor  188  relies on the power output from the turbine engine  150 . However, in certain embodiments employing more than one oxidant compressor is employed, a first oxidant compressor (e.g., a low pressure (LP) oxidant compressor) may be driven by the drive  190  while the shaft  176  drives a second oxidant compressor (e.g., a high pressure (HP) oxidant compressor), or vice versa. For example, in another embodiment, the HP MOC is driven by the drive  190  and the LP oxidant compressor is driven by the shaft  176 . In the illustrated embodiment, the oxidant compression system  186  is separate from the machinery  106 . In each of these embodiments, the compression system  186  compresses and supplies the oxidant  68  to the fuel nozzles  164  and the combustors  160 . Accordingly, some or all of the machinery  106 ,  178 ,  180  may be configured to increase the operational efficiency of the compression system  186  (e.g., the compressor  188  and/or additional compressors). 
     The variety of components of the machinery  106 , indicated by element numbers  106 A,  106 B,  106 C,  106 D,  106 E, and  106 F, may be disposed along the line of the shaft  176  and/or parallel to the line of the shaft  176  in one or more series arrangements, parallel arrangements, or any combination of series and parallel arrangements. For example, the machinery  106 ,  178 ,  180  (e.g.,  106 A through  106 F) may include any series and/or parallel arrangement, in any order, of: one or more gearboxes (e.g., parallel shaft, epicyclic gearboxes), one or more compressors (e.g., oxidant compressors, booster compressors such as EG booster compressors), one or more power generation units (e.g., electrical generators), one or more drives (e.g., steam turbine engines, electrical motors), heat exchange units (e.g., direct or indirect heat exchangers), clutches, or any combination thereof. The compressors may include axial compressors, radial or centrifugal compressors, or any combination thereof, each having one or more compression stages. Regarding the heat exchangers, direct heat exchangers may include spray coolers (e.g., spray intercoolers), which inject a liquid spray into a gas flow (e.g., oxidant flow) for direct cooling of the gas flow. Indirect heat exchangers may include at least one wall (e.g., a shell and tube heat exchanger) separating first and second flows, such as a fluid flow (e.g., oxidant flow) separated from a coolant flow (e.g., water, air, refrigerant, or any other liquid or gas coolant), wherein the coolant flow transfers heat from the fluid flow without any direct contact. Examples of indirect heat exchangers include intercooler heat exchangers and heat recovery units, such as heat recovery steam generators. The heat exchangers also may include heaters. As discussed in further detail below, each of these machinery components may be used in various combinations as indicated by the non-limiting examples set forth in TABLE 1. 
     Generally, the machinery  106 ,  178 ,  180  may be configured to increase the efficiency of the compression system  186  by, for example, adjusting operational speeds of one or more oxidant compressors in the system  186 , facilitating compression of the oxidant  68  through cooling, and/or extraction of surplus power. The disclosed embodiments are intended to include any and all permutations of the foregoing components in the machinery  106 ,  178 ,  180  in series and parallel arrangements, wherein one, more than one, all, or none of the components derive power from the shaft  176 . As illustrated below, TABLE 1 depicts some non-limiting examples of arrangements of the machinery  106 ,  178 ,  180  disposed proximate and/or coupled to the compressor and turbine sections  152 ,  156 . 
     
       
         
           
               
               
               
               
               
               
               
             
               
                   
                 TABLE 1 
               
               
                   
                   
               
               
                   
                 106A 
                 106B 
                 106C 
                 106D 
                 106E 
                 106F 
               
               
                   
                   
               
             
            
               
                   
                 MOC 
                 GEN 
                   
                   
                   
                   
               
               
                   
                 MOC 
                 GBX 
                 GEN 
               
               
                   
                 LP 
                 HP 
                 GEN 
               
               
                   
                 MOC 
                 MOC 
               
               
                   
                 HP 
                 GBX 
                 LP 
                 GEN 
               
               
                   
                 MOC 
                   
                 MOC 
               
               
                   
                 MOC 
                 GBX 
                 GEN 
               
               
                   
                 MOC 
               
               
                   
                 HP 
                 GBX 
                 GEN 
                 LP 
               
               
                   
                 MOC 
                   
                   
                 MOC 
               
               
                   
                 MOC 
                 GBX 
                 GEN 
               
               
                   
                 MOC 
                 GBX 
                 DRV 
               
               
                   
                 DRV 
                 GBX 
                 LP 
                 HP 
                 GBX 
                 GEN 
               
               
                   
                   
                   
                 MOC 
                 MOC 
               
               
                   
                 DRV 
                 GBX 
                 HP 
                 LP 
                 GEN 
               
               
                   
                   
                   
                 MOC 
                 MOC 
               
               
                   
                 HP 
                 GBX 
                 LP 
                 GEN 
               
               
                   
                 MOC 
                 CLR 
                 MOC 
               
               
                   
                 HP 
                 GBX 
                 LP 
                 GBX 
                 GEN 
               
               
                   
                 MOC 
                 CLR 
                 MOC 
               
               
                   
                 HP 
                 GBX 
                 LP 
                 GEN 
               
               
                   
                 MOC 
                 HTR 
                 MOC 
               
               
                   
                   
                 STGN 
               
               
                   
                 MOC 
                 GEN 
                 DRV 
               
               
                   
                 MOC 
                 DRV 
                 GEN 
               
               
                   
                 DRV 
                 MOC 
                 GEN 
               
               
                   
                 DRV 
                 CLU 
                 MOC 
                 GEN 
               
               
                   
                 DRV 
                 CLU 
                 MOC 
                 GBX 
                 GEN 
               
               
                   
                   
               
            
           
         
       
     
     As illustrated above in TABLE 1, a cooling unit is represented as CLR, a clutch is represented as CLU, a drive is represented by DRV, a gearbox is represented as GBX, a generator is represented by GEN, a heating unit is represented by HTR, a main oxidant compressor unit is represented by MOC, with low pressure and high pressure variants being represented as LP MOC and HP MOC, respectively, and a steam generator unit is represented as STGN. Although TABLE 1 illustrates the machinery  106 ,  178 ,  180  in sequence toward the compressor section  152  or the turbine section  156 , TABLE 1 is also intended to cover the reverse sequence of the machinery  106 ,  178 ,  180 . In TABLE 1, any cell including two or more components is intended to cover a parallel arrangement of the components. TABLE 1 is not intended to exclude any non-illustrated permutations of the machinery  106 ,  178 ,  180 . These components of the machinery  106 ,  178 ,  180  may enable feedback control of temperature, pressure, and flow rate of the oxidant  68  sent to the gas turbine engine  150 . As discussed in further detail below, the oxidant  68  and the fuel  70  may be supplied to the gas turbine engine  150  at locations specifically selected to facilitate isolation and extraction of the compressed exhaust gas  170  without any oxidant  68  or fuel  70  degrading the quality of the exhaust gas  170 . 
     The EG supply system  78 , as illustrated in  FIG. 3 , is disposed between the gas turbine engine  150  and the target systems (e.g., the hydrocarbon production system  12  and the other systems  84 ). In particular, the EG supply system  78 , e.g., the EG extraction system (EGES)  80 ), may be coupled to the gas turbine engine  150  at one or more extraction points  76  along the compressor section  152 , the combustor section  154 , and/or the turbine section  156 . For example, the extraction points  76  may be located between adjacent compressor stages, such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points  76  between compressor stages. Each of these interstage extraction points  76  provides a different temperature and pressure of the extracted exhaust gas  42 . Similarly, the extraction points  76  may be located between adjacent turbine stages, such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points  76  between turbine stages. Each of these interstage extraction points  76  provides a different temperature and pressure of the extracted exhaust gas  42 . By further example, the extraction points  76  may be located at a multitude of locations throughout the combustor section  154 , which may provide different temperatures, pressures, flow rates, and gas compositions. Each of these extraction points  76  may include an EG extraction conduit, one or more valves, sensors, and controls, which may be used to selectively control the flow of the extracted exhaust gas  42  to the EG supply system  78 . 
     The extracted exhaust gas  42 , which is distributed by the EG supply system  78 , has a controlled composition suitable for the target systems (e.g., the hydrocarbon production system  12  and the other systems  84 ). For example, at each of these extraction points  76 , the exhaust gas  170  may be substantially isolated from injection points (or flows) of the oxidant  68  and the fuel  70 . In other words, the EG supply system  78  may be specifically designed to extract the exhaust gas  170  from the gas turbine engine  150  without any added oxidant  68  or fuel  70 . Furthermore, in view of the stoichiometric combustion in each of the combustors  160 , the extracted exhaust gas  42  may be substantially free of oxygen and fuel. The EG supply system  78  may route the extracted exhaust gas  42  directly or indirectly to the hydrocarbon production system  12  and/or other systems  84  for use in various processes, such as enhanced oil recovery, carbon sequestration, storage, or transport to an offsite location. However, in certain embodiments, the EG supply system  78  includes the EG treatment system (EGTS)  82  for further treatment of the exhaust gas  42 , prior to use with the target systems. For example, the EG treatment system  82  may purify and/or separate the exhaust gas  42  into one or more streams  95 , such as the CO 2  rich, N 2  lean stream  96 , the intermediate concentration CO 2 , N 2  stream  97 , and the CO 2  lean, N 2  rich stream  98 . These treated exhaust gas streams  95  may be used individually, or in any combination, with the hydrocarbon production system  12  and the other systems  84  (e.g., the pipeline  86 , the storage tank  88 , and the carbon sequestration system  90 ). 
     Similar to the exhaust gas treatments performed in the EG supply system  78 , the EG processing system  54  may include a plurality of exhaust gas (EG) treatment components  192 , such as indicated by element numbers  194 ,  196 ,  198 ,  200 ,  202 ,  204 ,  206 ,  208 , and  210 . These EG treatment components  192  (e.g.,  194  through  210 ) may be disposed along the exhaust recirculation path  110  in one or more series arrangements, parallel arrangements, or any combination of series and parallel arrangements. For example, the EG treatment components  192  (e.g.,  194  through  210 ) may include any series and/or parallel arrangement, in any order, of: one or more heat exchangers (e.g., heat recovery units such as heat recovery steam generators, condensers, coolers, or heaters), catalyst systems (e.g., oxidation catalyst systems), particulate and/or water removal systems (e.g., inertial separators, coalescing filters, water impermeable filters, and other filters), chemical injection systems, solvent based treatment systems (e.g., absorbers, flash tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and/or a solvent based treatment system, or any combination thereof. In certain embodiments, the catalyst systems may include an oxidation catalyst, a carbon monoxide reduction catalyst, a nitrogen oxides reduction catalyst, an aluminum oxide, a zirconium oxide, a silicone oxide, a titanium oxide, a platinum oxide, a palladium oxide, a cobalt oxide, or a mixed metal oxide, or a combination thereof. The disclosed embodiments are intended to include any and all permutations of the foregoing components  192  in series and parallel arrangements. As illustrated below, TABLE 2 depicts some non-limiting examples of arrangements of the components  192  along the exhaust recirculation path  110 . 
     
       
         
           
               
               
               
               
               
               
               
               
               
             
               
                 TABLE 2 
               
               
                   
               
               
                 194 
                 196 
                 198 
                 200 
                 202 
                 204 
                 206 
                 208 
                 210 
               
               
                   
               
             
            
               
                 CU 
                 HRU 
                 BB 
                 MRU 
                 PRU 
                   
                   
                   
                   
               
               
                 CU 
                 HRU 
                 HRU 
                 BB 
                 MRU 
                 PRU 
                 DIL 
               
               
                 CU 
                 HRSG 
                 HRSG 
                 BB 
                 MRU 
                 PRU 
               
               
                 OCU 
                 HRU 
                 OCU 
                 HRU 
                 OCU 
                 BB 
                 MRU 
                 PRU 
               
               
                 HRU 
                 HRU 
                 BB 
                 MRU 
                 PRU 
               
               
                 CU 
                 CU 
               
               
                 HRSG 
                 HRSG 
                 BB 
                 MRU 
                 PRU 
                 DIL 
               
               
                 OCU 
                 OCU 
               
               
                 OCU 
                 HRSG 
                 OCU 
                 HRSG 
                 OCU 
                 BB 
                 MRU 
                 PRU 
                 DIL 
               
               
                   
                 OCU 
                   
                 OCU 
               
               
                 OCU 
                 HRSG 
                 HRSG 
                 BB 
                 COND 
                 INER 
                 WFIL 
                 CFIL 
                 DIL 
               
               
                   
                 ST 
                 ST 
               
               
                 OCU 
                 OCU 
                 BB 
                 COND 
                 INER 
                 FIL 
                 DIL 
               
               
                 HRSG 
                 HRSG 
               
               
                 ST 
                 ST 
               
               
                 OCU 
                 HRSG 
                 HRSG 
                 OCU 
                 BB 
                 MRU 
                 MRU 
                 PRU 
                 PRU 
               
               
                   
                 ST 
                 ST 
                   
                   
                 HE 
                 WFIL 
                 INER 
                 FIL 
               
               
                   
                   
                   
                   
                   
                 COND 
                   
                   
                 CFIL 
               
               
                 CU 
                 HRU 
                 HRU 
                 HRU 
                 BB 
                 MRU 
                 PRU 
                 PRU 
                 DIL 
               
               
                   
                 COND 
                 COND 
                 COND 
                   
                 HE 
                 INER 
                 FIL 
               
               
                   
                   
                   
                   
                   
                 COND 
                   
                 CFIL 
               
               
                   
                   
                   
                   
                   
                 WFIL 
               
               
                   
               
            
           
         
       
     
     As illustrated above in TABLE 2, a catalyst unit is represented by CU, an oxidation catalyst unit is represented by OCU, a booster blower is represented by BB, a heat exchanger is represented by HX, a heat recovery unit is represented by HRU, a heat recovery steam generator is represented by HRSG, a condenser is represented by COND, a steam turbine is represented by ST, a particulate removal unit is represented by PRU, a moisture removal unit is represented by MRU, a filter is represented by FIL, a coalescing filter is represented by CFIL, a water impermeable filter is represented by WFIL, an inertial separator is represented by INER, and a diluent supply system (e.g., steam, nitrogen, or other inert gas) is represented by DIL. Although TABLE 2 illustrates the components  192  in sequence from the exhaust outlet  182  of the turbine section  156  toward the exhaust inlet  184  of the compressor section  152 , TABLE 2 is also intended to cover the reverse sequence of the illustrated components  192 . In TABLE 2, any cell including two or more components is intended to cover an integrated unit with the components, a parallel arrangement of the components, or any combination thereof. Furthermore, in context of TABLE 2, the HRU, the HRSG, and the COND are examples of the HE; the HRSG is an example of the HRU; the COND, WFIL, and CFIL are examples of the WRU; the INER, FIL, WFIL, and CFIL are examples of the PRU; and the WFIL and CFIL are examples of the FIL. Again, TABLE 2 is not intended to exclude any non-illustrated permutations of the components  192 . In certain embodiments, the illustrated components  192  (e.g.,  194  through  210 ) may be partially or completed integrated within the HRSG  56 , the EGR system  58 , or any combination thereof. These EG treatment components  192  may enable feedback control of temperature, pressure, flow rate, and gas composition, while also removing moisture and particulates from the exhaust gas  60 . Furthermore, the treated exhaust gas  60  may be extracted at one or more extraction points  76  for use in the EG supply system  78  and/or recirculated to the exhaust inlet  184  of the compressor section  152 . 
     As the treated, recirculated exhaust gas  66  passes through the compressor section  152 , the SEGR gas turbine system  52  may bleed off a portion of the compressed exhaust gas along one or more lines  212  (e.g., bleed conduits or bypass conduits). Each line  212  may route the exhaust gas into one or more heat exchangers  214  (e.g., cooling units), thereby cooling the exhaust gas for recirculation back into the SEGR gas turbine system  52 . For example, after passing through the heat exchanger  214 , a portion of the cooled exhaust gas may be routed to the turbine section  156  along line  212  for cooling and/or sealing of the turbine casing, turbine shrouds, bearings, and other components. In such an embodiment, the SEGR gas turbine system  52  does not route any oxidant  68  (or other potential contaminants) through the turbine section  156  for cooling and/or sealing purposes, and thus any leakage of the cooled exhaust gas will not contaminate the hot products of combustion (e.g., working exhaust gas) flowing through and driving the turbine stages of the turbine section  156 . By further example, after passing through the heat exchanger  214 , a portion of the cooled exhaust gas may be routed along line  216  (e.g., return conduit) to an upstream compressor stage of the compressor section  152 , thereby improving the efficiency of compression by the compressor section  152 . In such an embodiment, the heat exchanger  214  may be configured as an interstage cooling unit for the compressor section  152 . In this manner, the cooled exhaust gas helps to increase the operational efficiency of the SEGR gas turbine system  52 , while simultaneously helping to maintain the purity of the exhaust gas (e.g., substantially free of oxidant and fuel). 
       FIG. 4  is a flow chart of an embodiment of an operational process  220  of the system  10  illustrated in  FIGS. 1-3 . In certain embodiments, the process  220  may be a computer implemented process, which accesses one or more instructions stored on the memory  122  and executes the instructions on the processor  120  of the controller  118  shown in  FIG. 2 . For example, each step in the process  220  may include instructions executable by the controller  118  of the control system  100  described with reference to  FIG. 2 . 
     The process  220  may begin by initiating a startup mode of the SEGR gas turbine system  52  of  FIGS. 1-3 , as indicated by block  222 . For example, the startup mode may involve a gradual ramp up of the SEGR gas turbine system  52  to maintain thermal gradients, vibration, and clearance (e.g., between rotating and stationary parts) within acceptable thresholds. For example, during the startup mode  222 , the process  220  may begin to supply a compressed oxidant  68  to the combustors  160  and the fuel nozzles  164  of the combustor section  154 , as indicated by block  224 . In certain embodiments, the compressed oxidant may include a compressed air, oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, or any combination thereof. For example, the oxidant  68  may be compressed by the oxidant compression system  186  illustrated in  FIG. 3 . The process  220  also may begin to supply fuel to the combustors  160  and the fuel nozzles  164  during the startup mode  222 , as indicated by block  226 . During the startup mode  222 , the process  220  also may begin to supply exhaust gas (as available) to the combustors  160  and the fuel nozzles  164 , as indicated by block  228 . For example, the fuel nozzles  164  may produce one or more diffusion flames, premix flames, or a combination of diffusion and premix flames. During the startup mode  222 , the exhaust gas  60  being generated by the gas turbine engine  156  may be insufficient or unstable in quantity and/or quality. Accordingly, during the startup mode, the process  220  may supply the exhaust gas  66  from one or more storage units (e.g., storage tank  88 ), the pipeline  86 , other SEGR gas turbine systems  52 , or other exhaust gas sources. 
     The process  220  may then combust a mixture of the compressed oxidant, fuel, and exhaust gas in the combustors  160  to produce hot combustion gas  172 , as indicated by block  230  by the one or more diffusion flames, premix flames, or a combination of diffusion and premix flames. In particular, the process  220  may be controlled by the control system  100  of  FIG. 2  to facilitate stoichiometric combustion (e.g., stoichiometric diffusion combustion, premix combustion, or both) of the mixture in the combustors  160  of the combustor section  154 . However, during the startup mode  222 , it may be particularly difficult to maintain stoichiometric combustion of the mixture (and thus low levels of oxidant and unburnt fuel may be present in the hot combustion gas  172 ). As a result, in the startup mode  222 , the hot combustion gas  172  may have greater amounts of residual oxidant  68  and/or fuel  70  than during a steady state mode as discussed in further detail below. For this reason, the process  220  may execute one or more control instructions to reduce or eliminate the residual oxidant  68  and/or fuel  70  in the hot combustion gas  172  during the startup mode. 
     The process  220  then drives the turbine section  156  with the hot combustion gas  172 , as indicated by block  232 . For example, the hot combustion gas  172  may drive one or more turbine stages  174  disposed within the turbine section  156 . Downstream of the turbine section  156 , the process  220  may treat the exhaust gas  60  from the final turbine stage  174 , as indicated by block  234 . For example, the exhaust gas treatment  234  may include filtration, catalytic reaction of any residual oxidant  68  and/or fuel  70 , chemical treatment, heat recovery with the HRSG  56 , and so forth. The process  220  may also recirculate at least some of the exhaust gas  60  back to the compressor section  152  of the SEGR gas turbine system  52 , as indicated by block  236 . For example, the exhaust gas recirculation  236  may involve passage through the exhaust recirculation path  110  having the EG processing system  54  as illustrated in  FIGS. 1-3 . 
     In turn, the recirculated exhaust gas  66  may be compressed in the compressor section  152 , as indicated by block  238 . For example, the SEGR gas turbine system  52  may sequentially compress the recirculated exhaust gas  66  in one or more compressor stages  158  of the compressor section  152 . Subsequently, the compressed exhaust gas  170  may be supplied to the combustors  160  and fuel nozzles  164 , as indicated by block  228 . Steps  230 ,  232 ,  234 ,  236 , and  238  may then repeat, until the process  220  eventually transitions to a steady state mode, as indicated by block  240 . Upon the transition  240 , the process  220  may continue to perform the steps  224  through  238 , but may also begin to extract the exhaust gas  42  via the EG supply system  78 , as indicated by block  242 . For example, the exhaust gas  42  may be extracted from one or more extraction points  76  along the compressor section  152 , the combustor section  154 , and the turbine section  156  as indicated in  FIG. 3 . In turn, the process  220  may supply the extracted exhaust gas  42  from the EG supply system  78  to the hydrocarbon production system  12 , as indicated by block  244 . The hydrocarbon production system  12  may then inject the exhaust gas  42  into the earth  32  for enhanced oil recovery, as indicated by block  246 . For example, the extracted exhaust gas  42  may be used by the exhaust gas injection EOR system  112  of the EOR system  18  illustrated in  FIGS. 1-3 . 
     In some embodiments of the SEGR gas turbine system  52 , the exhaust gas  42  is recirculated and used to cool the combustor section  154  of the gas turbine engine  150 .  FIG. 5  is a schematic diagram of the combustor section  154  that includes various features that are shown in detail in  FIGS. 6-9 . Elements in  FIG. 5  in common with those shown in previous figures are labeled with the same reference numerals. The axial direction of the combustor  160  is indicated by arrow  294 , the radial direction is indicated by arrow  296 , and the circumferential direction is indicated by arrow  298 . As shown in  FIG. 5 , the oxidant compression system  186  generates a compressed oxidant  300  that may be provided to various locations at a head end portion  302  of the combustor  160 . Fuel  70  is provided to the one or more fuel nozzles  164  in the head end portion  302  of the turbine combustor  160 . As discussed above, the oxidant  300  and fuel  70  may be mixed prior to injection into the combustor  160  via one or more premix fuel nozzles, mixed in the combustion chamber  160  via one or more diffusion flame nozzles, or any combination thereof. Thus, the fuel nozzles  164  may be diffusion nozzles, pre-mix fuel nozzles, or any combination thereof. The compressed oxidant  300  may include air, oxygen, oxygen-enriched air, oxygen-reduced air, or oxygen nitrogen mixtures. In some embodiments, the compressed oxidant  300  may have a concentration of the exhaust gas  42  of less than approximately 10 percent, 5 percent, or 1 percent by volume. As discussed above, a SEGR gas turbine system  52  may recirculate a portion of the exhaust gas  42  (e.g., compressed exhaust gas  170 ) through the compressor section  152  and at least part of the combustor section  154  (e.g., one or more combustors  160 ). In some of the embodiments discussed below, the exhaust gas  42  and/or a relatively inert gas  304  do not recirculate through the head end portion  302  of the combustor  160 . The compressed exhaust gas  170  and/or the relatively inert gas  304  from the compressor section  152  may be supplied to a turbine end portion  310  of the combustor  160  rather than to the head end portion  302 , thus helping to maintain isolation between the oxidant  300  and the inert gas  304 . In some embodiments, the inert gas  304  may have less than approximately 10 percent, 5 percent, or 1 percent by volume of oxidant  300  (e.g., oxygen (O 2 )). One or more fuels  70  may be supplied to the fuel nozzles  164 . For example, the fuel  70  may include, but is not limited to, a gaseous fuel (e.g., natural gas, process gas, methane, hydrogen, carbon monoxide), a liquid fuel (e.g., light distillates, kerosene, heating oil), or any combination thereof. 
     The compressor section  152  supplies the inert gas  304  (e.g., nitrogen, carbon dioxide, carbon monoxide, compressed exhaust gas  170 ) to a compressor discharge casing  305 , which encloses at least part of the combustor  160  of the combustor section  154  (e.g., the combustion chamber  168 ). The inert gas  304  may be substantially inert (e.g., unreactive) relative to the oxidant  300 . The combustion chamber  168  is partially enclosed by a combustor cap  306  of the head end portion  302 , and a combustor liner  308  (e.g., inner wall) along the axis  294  of the combustor  160 . The combustor liner  308  extends in the circumferential direction  298  around the combustion chamber  168 . The turbine end portion  310  of the combustor  160  guides the combustion gases  172  from combustion of the oxidant  300  and the fuel  70  in the downstream direction  312  to the turbine section  156 . In some embodiments, the combustion gases  172  that exit the combustor  160  may be substantially free of oxidant  300  and fuel  70 , with a concentration of less than approximately 10, 5, 3, 2, or 1 percent by volume of oxidant  300  and fuel  70 . A flow sleeve  314  (e.g., intermediate wall) forms a passage  316  about the combustor liner  308  that enables a fluid (e.g., inert gas  304  such as exhaust gas  170 ) to flow along the outside of the combustion chamber  168 . The passage  316  extends in the circumferential direction  298  around the combustor liner  308 , and the flow sleeve  314  extends in the circumferential direction  298  around the passage  316 . In some embodiments, the inert gas  304  is a primary cooling media for the combustion chamber  168  and/or a heat sink for the combustion gases  172 . 
     The passage  316  may be open to the head end portion  302  and to the discharge casing  305 . In some embodiments, a portion of the compressed oxidant  300  enters an oxidant section  318  of the passage  316  in the downstream direction  312  relative to the combustion gases  172  from the head end portion  302  toward the turbine section  156 . The inert gas  304  (e.g., exhaust gas  170 ) enters a cooling section  320  of the passage  316  in an upstream direction  322  relative to the combustion gases  172  from the turbine end portion  310  of the combustor  160 . A barrier section  324  separates the oxidant section  318  from the cooling section  320 . As discussed in detail below, the barrier section  324  may include a physical barrier that at least partially blocks the oxidant  300  and the inert gas  304  from interacting within the passage  316 , and/or the barrier section  324  may include a dynamic barrier. The opposing flows (e.g., oxidant  300  in the downstream direction  312 , inert gas  304  in the upstream direction  322 ) interact at a dynamic barrier to substantially block either flow from passing to the other section (e.g., oxidant section  318 , cooling section  320 ). 
     In some embodiments, an extraction sleeve  326  extends circumferentially  298  around at least part of the flow sleeve  314  and combustor section  154 . The extraction sleeve  326  is in fluid communication with the flow sleeve  314 , thereby enabling some of the inert gas  304  (e.g., compressed exhaust gas  170 ) in the flow sleeve  314  to be extracted to an exhaust extraction system  80 . The inert gas  304  may be bled into the extraction sleeve  326  to control the flow rate of the inert gas  304  within the passage  316 . As described in some embodiments above, the compressed exhaust gas  170  may be recirculated through the SEGR gas turbine system  52  and may be utilized by a fluid injection system  36  for enhanced oil recovery. 
       FIG. 6  illustrates a schematic of an embodiment of the combustor  160  with the oxidant  300  and the inert gas  304  separated within the passage  316  by a dynamic barrier  340 . The oxidant  300  and fuel  70  are supplied to the head end portion  302  and fuel nozzles  164 . A controller  342  controls the supply of the fuel  70  and the oxidant  300  to the head end portion  302 . The controller  342  may control the fuel nozzles  164  to adjust the mixing and distribution of the oxidant  300  and fuel  70  within the combustion chamber  168 . A portion  344  of the oxidant  300  may be supplied to the passage  316  along the combustion liner  308 . Mixing holes  346  may direct the oxidant portion  344  into the combustion chamber  168  to mix (e.g., uniformly mix) the oxidant  300  and fuel  70  from the fuel nozzles  164 , to stabilize a flame  348  (e.g., diffusion flame and/or premix flame) from the one or more fuel nozzles  164 , and/or to shape the flame  348  within the combustion chamber  168 . The controller  342  may adjust the oxidant/fuel mixture injected through the combustor cap  306 , and the controller  342  may adjust the oxidant portion  344  supplied through the mixing holes  346  or the passage  316  to control the equivalence ratio for the reaction within the combustion chamber  168 . In some embodiments, the combustor liner  308  may have one or more rows of mixing holes  346  proximate to the head end portion  302 . For example, the combustor liner  308  may have approximately 1 to 1000, 1 to 500, 1 to 100, 1 to 10, or any other number of rows of mixing holes  346  about the combustor liner  308 , wherein each row may include approximately 1 to 1000 or more holes  346 . In some embodiments, the mixing holes  346  are symmetrically spaced about the combustor liner  308 . In some embodiments, the position, shape, and/or size of the mixing holes  346  may differ based at least in part on spacing from the combustor cap  306 . The shape of the mixing holes  346  may include, but is not limited to, circles, slots, or chevrons, or any combination thereof. 
     The inert gas  304  enters the flow sleeve  314  from the compressor discharge casing  305  through inlets  350 . The inert gas  304  cools the combustor liner  308  through one or more cooling processes. For example, the inert gas  304  flowing through the inlets  350  may cool the combustor liner  308  opposite the inlets  350  by impingement cooling against the liner  308 . The inert gas  304  flowing through the cooling section  320  of the passage  316  may cool the liner  308  by convective cooling and/or film cooling along an outer surface  352 . The inert gas  304  may cool an inner surface  354  by flowing through mixing holes  346  and/or dilution holes  356  in the combustor liner  308 . In some embodiments, the combustor liner  308  may have one or more rows of dilution holes  356  downstream (e.g., arrow  312 ) of the mixing holes  346 . For example, the combustor liner  308  may have approximately 1 to 1000, 1 to 500, 1 to 100, 1 to 10, or any other number of rows of dilution holes  356  about the combustor liner  308 . In some embodiments, the dilution holes  356  are symmetrically spaced about the combustor liner  308 . As discussed above with the mixing holes  346 , the dilution holes  356  may include varying positions, shapes, and/or sizes based at least in part on spacing from the combustor cap  306 . 
     In some embodiments, the mixing holes  346  direct the inert gas  304  (e.g., exhaust gas  170 ) into the combustion chamber  168  to mix with the oxidant  300  and the fuel  70  from the fuel nozzles  164 , to stabilize the flame  348 , to quench the flame  348  and reduce emissions (e.g., NO x  emission), and/or to shape the flame  348  within the combustion chamber  168 . In some embodiments, mixing the oxidant  300  and the fuel  70  may aid bringing the equivalence ratio to approximately 1.0. The mixing holes  346  extend through the combustor liner  308  along a flame zone  358 . The flame zone  358  at least partially surrounds the flames  348  within the combustion chamber  168 . Accordingly, the mixing holes  346  may direct a fluid (e.g., oxidant  300 , inert gas  304 ) toward the flame  348  to affect the equivalence ratio of the combustion. The flow rate, velocity, and/or direction of the fluid (e.g., oxidant  300 , inert gas  304 ) through the mixing holes  346  may affect various parameters of the flames  348  in the combustion chamber  168 . For example, the flow rate and velocity of the fluid may affect mixing of the oxidant  300  and the fuel  70  by shaping the flames  348 . In some embodiments, a fluid flow through mixing holes  346  angled downstream may form a cooling film (e.g., film cooling) along the combustor liner  308 . 
     The dilution holes  356  extend through the combustor liner  308  along a dilution zone  360 . The dilution zone  360  may be between the flame zone  358  and the turbine section  156  connected to the turbine end portion  310 . The dilution holes  356  may direct the inert gas  304  (e.g., exhaust gas  170 ) into the combustion chamber  168  to cool the combustion gases  172  and/or to dilute reactants (e.g., oxidant  300 , fuel  70 ) near the turbine end section  310 . The flow rate, velocity, and/or direction of the inert gas  304  through the dilution holes  356  may affect various parameters of the combustion gases  172 . For example, increasing the velocity of the inert gas  304  may mix the combustion gases  172  to increase the equivalence ratio and/or to increase a dilution of unreacted oxidant  300  or fuel  70 . Increasing the flow rate of the inert gas  304  may further dilute and cool the combustion gases  172 , which may help to reduce emissions such as NO x . In some embodiments, the combustion gases  172  and flames  348  are between approximately 1800° C. to 2200° C. in the flame zone  358 . The inert gas  304  cools the combustion gases  172  to less than approximately 1700° C. at an exit  362  of the turbine end portion  310 . In some embodiments, the inert gas  304  may cool the combustion gases  172  approximately 100° C., 250° C., 500° C., 750° C., or 1000° C. or more through the dilution zone  360 . In some embodiments, the dilution holes  356  are staged within the dilution zone  360  to enable a desired heat removal from the combustion gases  172 , a desired exit temperature profile of the combustion gases  172 , or a desired inert gas  304  distribution, or any combination thereof. 
     The inert gas  304  (e.g., exhaust gas  170 ) enters the passage  316  and flows in the upstream direction  322  towards the head end portion  302 . In some embodiments, the controller  342  may control one or more valves  364  along the flow sleeve  314  and/or the extraction sleeve  326  to control the flow rate of the inert gas  304  into the passage  316 . As may be appreciated, the inert gas  304  and oxidant  300  may be pressurized to the pressure of the combustion gases  172 , so that the inert gas  304  and oxidant  300  may flow into the combustion chamber  168 . The oxidant portion  344  enters the passage  316  and flows in the downstream direction  312  towards the turbine end portion  310  from the head end portion  302 . In some embodiments, the oxidant portion  344  and the inert gas  304  interact at the dynamic barrier  340  within the passage  316 . The dynamic barrier  340  is the interaction of the opposing oxidant portion  344  flow and the inert gas  304  flow. At the dynamic barrier  340 , the oxidant portion  344  flowing downstream substantially blocks the inert gas  304  from flowing upstream beyond the dynamic barrier  340 , and the inert gas  304  flowing upstream substantially blocks the oxidant portion  344  from flowing downstream beyond the dynamic barrier  340 . The dynamic barrier  340  is positioned within the barrier section  324  of the passage  316 , separating the oxidant portion  344  from the inert gas  304  within the passage  316 . Accordingly, the oxidant section  318  of the passage  316  supplies the oxidant portion  344  substantially free of the inert gas  304 , and the cooling section  320  of the passage  316  supplies the inert gas  304  substantially free of the oxidant portion  344 . The position of the dynamic barrier  340  along the passage  316  may be adjustable (e.g., dynamic) during operation of the combustor  160  based at least in part on parameters (e.g., relative flow rates, pressures, velocities) of the oxidant portion  344  and the inert gas  304  within the passage  316 . Adjusting the position of the dynamic barrier  340  affects the relative lengths of the oxidant section  318  and the cooling section  320 . 
     The dynamic barrier  340  may be located within the passage  316  where the pressure of the inert gas  304  is approximately equal to the pressure of the oxidant portion  344 , or a pressure balance point. For example, the dynamic barrier  340  may be positioned at a first location  366  near the head end portion  302  if the pressure of the inert gas  304  in the passage  316  is approximately equal to the pressure of the oxidant  300  at the head end portion  302 . Positioning the dynamic barrier  340  near the head end portion  302  may reduce the flow of the oxidant portion  344  through the mixing holes  346 , and increase the flow of the inert gas  304  through the mixing holes  346 . The dynamic barrier  340  at the first location  366  may reduce the concentration of the oxidant  300  in the flame zone  358 . The dynamic barrier  340  may be positioned at a second location  368  near the turbine end portion  310  of the combustor  160  if the pressure of the oxidant portion  344  in the passage  316  is approximately equal to the pressure of the inert gas  304  in the compressor discharge casing  305 . Positioning the dynamic barrier  340  near the turbine end portion  310  may reduce or eliminate the flow of the inert gas  304  through the mixing holes  346 , and increase the flow of the oxidant portion  344  through the mixing holes  346 . The dynamic barrier  340  at the second location  368  may increase the concentration of the oxidant  300  in the flame zone  358 . The pressure balance point, and accordingly the location of the dynamic barrier  340  within the passage  316  between the oxidant portion  344  and the inert gas  304 , may be controlled by controlling the pressures of the oxidant portion  344  and the inert gas  304  within the passage  316 . The dynamic barrier  340  may be positioned within the passage  316  to control the composition of the fluid through the mixing holes  346  and/or the dilution holes  356 . For example, the dynamic barrier  340  may be positioned relative to mixing holes  346  to adjust the oxidant portion  344  supplied to the combustion chamber  168 , thereby affecting the equivalence ratio of combustion. The dynamic barrier  340  may be positioned to control the cooling of the combustor liner  308  and the combustion gases  172  by the inert gas  304  (e.g., exhaust gas  170 ). Accordingly, the position of the dynamic barrier  340  may control the composition of the fluid entering the combustion chamber  168  through the combustor liner  308 , the mix of the oxidant  300  and fuel  70 , the shape of the flames  348 , the temperature of the combustion liner  308 , the temperature of the combustion gases  172 , emissions (e.g., NO x ) in the combustion gases  172 , or any combination thereof. 
     The controller  342  may control the position of the dynamic barrier  340  by controlling the flow of the oxidant portion  344  into the passage  316  and controlling the flow of the inert gas  304  (e.g., exhaust gas  170 ) within the passage  316 . In some embodiments, the controller  342  controls the flow of the oxidant portion  344  through controlling the pressure of the oxidant portion  344  within the head end portion  302  and/or, controlling the flow rate of the oxidant  300  supplied to the fuel nozzles  164 . The controller  342  may control the flow of the inert gas  304  into the passage  316  by controlling the flow of exhaust gas  42  into the compressor discharge casing  305 , controlling the pressure within the compressor discharge casing  305 , and/or controlling a bleed flow  370  through the extraction sleeve  326 . The valve  364  connected to the extraction sleeve  326  may control the flow of the inert gas  304  through the passage  316 . For example, opening the valve  364  may increase the bleed flow  370  and decrease the flow of inert gas  304  through the coolant section  320 , thereby moving the dynamic barrier  340  toward the turbine end portion  310 . Closing the valve  364  may decrease the bleed flow  370  to the exhaust extraction system  80  and may increase the flow of inert gas  304  through the coolant section  320  into the combustion chamber  168 . Thus, closing the valve  364  may move the dynamic barrier  340  toward the head end portion  302 . The controller  342  may control the oxidant portion  344  and the inert gas  304  to adjust the dynamic barrier  340  within the passage  316  while maintaining the head end portion  302  substantially free of the inert gas  304 . The controller  342  may adjust the dynamic barrier  340  within the passage while maintaining the combustion gases  172  at the turbine end portion  310  substantially free of oxidant  300 . As discussed above, combustion gases  172  with low concentrations (e.g., less than approximately 10, 5 or 1 percent oxidant  300  by volume) may be recirculated through the combustor as compressed exhaust gas  170  and/or utilized by a fluid injection system  36  for enhanced oil recovery. 
       FIG. 7  illustrates a schematic of an embodiment of the combustor  160  with the oxidant  300  and the inert gas  304  separated within the passage  316  by a physical barrier  400  or divider in the barrier section  324  of the passage  316 . The oxidant  300  may enter the head end portion  302  and the inert gas  304  may enter the passage  316  as described above with  FIG. 6 . The physical barrier  400  is arranged between the combustor liner  308  and the flow sleeve  314 , at least partially blocking a fluid flow through the passage  316 . In some embodiments, the physical barrier  400  is a separate component from the combustor liner  308  and the flow sleeve  314 . For example, the physical barrier  400  may be a fitting (e.g., ring, partial ring, annular wall) about the combustor liner  308 . The physical barrier  400  may have seals to interface with the combustor liner  308  and the flow sleeve  314 , and to at least partially block fluid communication between the oxidant portion  344  and the inert gas  304 . In some embodiments, the physical barrier  400  is connected to or integrally formed with the combustor liner  308  or the flow sleeve  314 . For example, the physical barrier  400  may be a flange disposed circumferentially  298  about the combustor liner  308  or within the flow sleeve  314 . 
     In some embodiments, the physical barrier  400  blocks substantially the entire passage of the barrier section  324 , thereby blocking the inert gas  304  and oxidant portion  344  from interacting within the passage  316 . As shown in  FIG. 7 , one or more partial physical barriers  402  may be arranged within the passage  316  in addition to a physical barrier  400  that blocks substantially all fluid communication between the oxidant portion  344  and the inert gas  304  in the passage  316 . The one or more partial physical barrier  402  may affect the pressure, velocity, and/or flow rate of the fluid (e.g., oxidant portion  344 , inert gas  304 ) entering the combustion chamber  168  through the mixing holes  346  or dilution holes  356  beyond the partial physical barrier  402 . For example, a partial physical barrier  402  in the oxidant section  318  between mixing holes  346  may reduce the flow rate or pressure of the oxidant portion  344  through the mixing hole  346  downstream (e.g., arrow  312 ) of the partial physical barrier  402 . 
     In some embodiments, the partial physical barrier  402  includes passages or flow guides that restrict or limit fluid communication across the partial physical barrier  402 . A partial physical barrier  402  may affect the velocity and/or pressure of the oxidant  300  or the inert gas  304  flowing around the partial physical barrier  402 . Accordingly, one or more partial physical barriers  402  may be utilized to control a position of the dynamic barrier  340  discussed above. For example, a partial physical barrier  402  in the cooling section  320  upstream (e.g., arrow  322 ) of the dilution holes  356  may reduce the pressure of the inert gas  304  so that the dynamic barrier  340  is positioned proximate to the mixing holes  346  or among the mixing holes  346  for a desirable equivalence ratio rather than proximate to the head end portion  302 . In some embodiments, a partial physical barrier  402  may be utilized in addition to controlling the flows of the oxidant portion  344  and the inert gas  304  into the passage  316  to form the dynamic barrier  340 . 
     As described above, the controller  342  may control the flow of oxidant  300  to the head end portion  302 , and may control the flow of the inert gas  304  (e.g., exhaust gas  170 ) into the passage  316  and the extraction sleeve  326 . In some embodiments, the controller  342  controls the distribution of a first fuel  404  to a first set  406  of fuel nozzles  164  and controls the distribution of a second fuel  408  to a second set  410  of fuel nozzles  164 . Each set  406 ,  410  may include one or more fuel nozzles  164 . For example, the first set  406  may include a center fuel nozzle, and the second set  410  may include perimeter fuel nozzles (e.g., approximately 1 to 10 nozzles) as shown in  FIG. 7 . In some embodiments, a first set  406  may be a pilot fuel nozzle, and the first fuel  404  may have a higher heating value than the second fuel  408  injected by the second set  410  of perimeter fuel nozzles. As may be appreciated, the first set  406  of fuel nozzles may be used at startup of the gas turbine engine  150 , and the flow rate of the first fuel  404  may be reduced after a period of operation of the gas turbine engine  150 . The first set  406  may improve the flame stability of the second set  410 . In some embodiments, oxidant  300  injected through the combustor cap  306  about the first set  406  of fuel nozzles  164  may shield and/or stabilize the flame  348  of the first set  406 . The first fuel  404  injected from the first set  406  of fuel nozzles  164  may adjust a rate of combustion, thereby affecting the equivalence ratio. In some embodiments, the second set  410  of fuel nozzles  164  provides the second fuel  408  that is utilized primarily for a steady-state operation of the gas turbine engine  150 . 
     The first and second fuels  404 ,  408  may include, but are not limited to natural gas, liquefied natural gas (LNG), syngas, carbon monoxide, hydrogen, methane, ethane, propane, butane, naphtha, kerosene, diesel fuel, light distillates, heating oil, ethanol, methanol, biofuel, or any combination thereof. In some embodiments, the first and the second fuels  404 ,  408  are the same fuel, and the controller  342  differentially controls the distribution to the first and second sets  406 ,  410  of fuel nozzles. It may be appreciated that while two fuels  404 ,  408  and two sets  406 ,  410  of fuel nozzles  164  are described above, some embodiments of the combustor  160  may have 1, 2, 3, 4, 5, or more sets of fuel nozzles  164  to inject 1, 2, 3, 4, 5, or more fuels  70  into the combustion chamber  168 . 
     In some embodiments, the second set  410  of fuel nozzles  164  (e.g., perimeter fuel nozzles) may provide more than approximately 70, 80, 90, or 95 percent of the total fuel injected into the combustor  160 . The controller  342  may control the second set  410  of fuel nozzles  164  to adjust the bulk combustor equivalence ratio, and may control the first set  406  of fuel nozzles  164  (e.g., center fuel nozzle) to fine tune the equivalence ratio. For example, the first set  406  of fuel nozzles  164  may provide less than approximately 30, 20, 10, or 5 percent of the total fuel injected into the combustor  160 . Controlling the flow rate of the first fuel  404  through the first set  406  of fuel nozzles  164  thereby enables the controller  342  to adjust (e.g., fine tune) the equivalence ratio with relatively small adjustments. As an example, where the first set  406  provides approximately 20 percent of the total fuel and the second set  410  provides approximately 80 percent of the total fuel, adjusting (e.g., increasing, decreasing) the first fuel  404  by 10 percent adjusts the total fuel in the combustor  160  by approximately 2 percent. 
       FIG. 8  illustrates a cross-section of an embodiment of the combustor  160  of  FIG. 7 , taken along line  8 - 8 . In some embodiments, the fuel nozzles  164  may be arranged in a circular arrangement, such as the second set  410  arranged circumferentially  298  around the first set  406 . As may be appreciated, the cross-section of the combustor  160  is not limited to be substantially circular, and the combustor liner  308 , the flow sleeve  314 , and the extraction sleeve  326  may have other shapes (e.g., rectangular, ovoid). The partial physical barrier  402  is arranged between the combustor liner  308  and the flow sleeve  314 , within the passage  316 . In some embodiments, portions  430  of the partial physical barrier  402  interface with the combustor liner  308  and the flow sleeve  314  at points about the passage  316 , and have openings  432  (e.g., flow guides) that enable restricted fluid communication about the partial physical barrier  402 . In some embodiments, liner openings  438  may lie along the combustor liner  308 , sleeve openings  440  may lie along the flow sleeve  314 , or interior openings  442  may lie through the partial physical barrier  40  (e.g., holes, slots, etc.) between the liner  308  and the flow sleeve  314 . In some embodiments, the partial physical barrier  402  may interface with one of the combustor liner  308  or the flow sleeve  314 , permitting fluid (e.g., oxidant portion  344 , inert gas  304 ) to pass along the other of the combustor liner  308  or the flow sleeve  314  around the partial physical barrier  402 . 
       FIG. 9  illustrates an embodiment of the combustor  160  of  FIG. 7 , taken along line  8 - 8 , where the partial physical barrier  402  has another geometry. Protrusions  434  of the partial physical barrier  402  from the combustor liner  308  or the flow sleeve  314  partially surround the combustor liner  308 , thereby partially blocking the flow of the oxidant portion  344  or inert gas  304  at some points about the combustor liner  308 . The openings  432  may extend across the passage  316  at other points about the combustor liner  308 , thereby enabling a substantially unrestricted flow of the oxidant portion  344  or the inert gas  304  around the partial physical barrier  402 . In some embodiments, the protrusions  434  of one or more partial physical barriers  402  may direct the fluids in the passage  316  in a desired circumferential direction  298  about an axis  436  of the combustor  160 . Accordingly, one or more partial physical barriers  402  may provide a rotational component (e.g., swirl) to the flow of the oxidant portion  344  or the inert gas  304  through the passage  316 . In some embodiments, the one or more partial physical barriers  402  affect the pressure, velocity, and/or flow rate of the oxidant portion  344  or the inert gas  304 , which may cause the dynamic barrier  340  to form at a desired position along the passage  316 . Presently contemplated embodiments of the partial physical barrier  402  may include other geometries of openings  432  and protrusions  434  to at least partially block the passage  316  between the combustor liner  308  and the flow sleeve  314 . 
     The SEGR gas turbine systems  52  and combustors  160  described above may supply the oxidant  300  and fuel  70  to the combustor  160  at a head end portion  302 , and supply an inert gas  304  (e.g., compressed exhaust gas  170 ) to the combustor  160  at a turbine end portion  310  for cooling the combustor liner  308  and combustion gases  172 . In some embodiments, the inert gas  304  may cool the combustion gases  172  to reduce emissions, such as NO x . In some embodiments, the combustor  160  may have differentially supplied and controlled sets of fuel nozzles  164 , in which the oxidant  300  and fuels  404 ,  408  flow in the downstream direction  312  from the head end portion  302 . The inert gas  304  (e.g., compressed exhaust gas  170 ) is supplied through the passage  316  at the turbine end portion  310  to cool the combustor liner  308  and the combustion gases  172 . The inert gas  304  flows in the upstream direction  312  through the passage  316 , which may be substantially the opposite direction of the oxidant portion  342  through the passage  316 . The oxidant  300  and the inert gas  304  may not mix upstream (e.g., arrow  322 ) of the flame  348  (e.g., in the head end portion  302 ). In some embodiments, the oxidant  300  flows from the fuel nozzles  164 , flows through the combustor cap  306 , and/or flows through the mixing holes  346  to improve a distribution and/or concentration of oxidant  300  in the flame zone  360 . In turn, the improved distribution of oxidant  300  helps to increase the efficiency of combustion, thereby affecting the equivalence ratio. For example, the improved distribution of the oxidant  300  flow may help provide substantially stoichiometric combustion. The inert gas  304  may be a heat sink for the combustor liner  308  and/or combustion gases  172 . Reducing the temperature of the combustion gases  172  may reduce emissions, such as NO x . The passage  316  between the combustor liner  308  and the flow sleeve  314  may have one or more physical barriers  400  and/or a dynamic barrier  340  between the oxidant portion  344  and the inert gas  304 . The positions of the one or more physical barriers  400  and/or the dynamic barrier  340  within the passage  316  may be adjusted among various embodiments, based at least in part on the flows of the oxidant portion  300 , the inert gas  304 , the equivalence ratio, and other factors. 
     Separating the oxidant  300  from the inert gas  304  (e.g., compressed exhaust gas  170 ) upstream of the flame zone  358  within the combustion chamber  168  may increase the flame stability and completeness of combustion. The fuel nozzles  164  may also be controlled to adjust the equivalence ratio. Controlling the fuel nozzles  164  and/or isolating the oxidant  300  from the inert gas  304  at desired points in the combustor  160  may affect the equivalence ratio. Adjusting the equivalence ratio to approximately 1.0 (e.g., between 0.95 and 1.05) may reduce the concentrations of oxidant  300 , fuel  70 , and/or other components (e.g., nitrogen oxides, water) within the exhaust gases  42  of a SEGR gas turbine system  52 . In some embodiments, adjusting the equivalence ratio to approximately 1.0 may increase the concentration of carbon dioxide that may be utilized in an enhanced oil recovery system  18 . The exhaust gas  42 , or the carbon dioxide extracted from the exhaust gas  42 , may be utilized by a fluid injection system  36  for enhanced oil recovery. 
     This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. 
     Additional Embodiments 
     The present embodiments provide a system and method for controlling combustion and emissions in a gas turbine engine with exhaust recirculation. It should be noted that any one or a combination of the features described above may be utilized in any suitable combination. Indeed, all permutations of such combinations are presently contemplated. By way of example, the following clauses are offered as further description of the present disclosure: 
     Embodiment 1 
     A system having a turbine combustor with a combustor liner disposed about a combustion chamber and a head end upstream of the combustion chamber relative to a downstream direction of a flow of combustion gases through the combustion chamber. The head end is configured to direct an oxidant flow and a first fuel flow toward the combustion chamber. The turbine combustor also includes a flow sleeve disposed at an offset about the combustor liner to define a passage configured to direct a gas flow toward the head end and configured to direct a portion of the oxidant flow toward a turbine end of the turbine combustor. The gas flow includes a substantially inert gas. The turbine combustor also includes a barrier within the passage, and the barrier is configured to block the portion of the oxidant flow toward the turbine end and to is configured to block the gas flow toward the head end within the passage 
     Embodiment 2 
     The system of embodiment 1, wherein the oxidant flow and the first fuel flow are configured to substantially stoichiometrically combust in the combustion chamber. 
     Embodiment 3 
     The system of any preceding embodiment, wherein the head end includes a first fuel nozzle configured to direct the first fuel flow into the combustion chamber, and a second fuel nozzle configured to direct a second fuel flow into the combustion chamber, wherein the first fuel nozzle is controlled separately from the second fuel nozzle. 
     Embodiment 4 
     The system of any preceding embodiment, wherein the gas flow includes an exhaust gas having less than approximately 5 percent by volume of the oxidant or the first fuel. 
     Embodiment 5 
     The system of any preceding embodiment, wherein the barrier includes a physical barrier configured to extend across the passage and to separate the passage into an oxidant section and a cooling section. 
     Embodiment 6 
     The system of any preceding embodiment, wherein the barrier includes a dynamic barrier configured to separate the passage into an oxidant section and a cooling section. The dynamic barrier includes a fluid interface between the portion of the oxidant flow and the gas flow, and a position of the dynamic barrier is controlled based at least in part on a pressure difference between the portion of the oxidant flow and the gas flow. 
     Embodiment 7 
     The system of embodiment 6, wherein the barrier includes multiple flow guides configured to restrict the passage at the dynamic barrier. 
     Embodiment 8 
     The system of any preceding embodiment, wherein the flow sleeve is coupled to a bleed passage configured to direct a portion of the gas flow into the bleed passage. 
     Embodiment 9 
     The system of any preceding embodiment, wherein the gas flow is configured to cool the combustor liner, and the gas flow is configured to dilute and to cool the flow of combustion gases in the turbine combustor. 
     Embodiment 10 
     The system of any preceding embodiment, wherein the combustor liner includes multiple mixing holes and multiple dilution holes. The multiple mixing holes are configured to direct at least one of the oxidant flow and the gas flow into the combustion chamber. The multiple dilution holes are configured to direct the gas flow into the combustion chamber. 
     Embodiment 11 
     The system of any preceding embodiment, wherein the system includes a gas turbine engine having the turbine combustor, a turbine driven by the combustion gases from the turbine combustor and that outputs the exhaust gas, and an exhaust gas compressor driven by the turbine. The exhaust gas compressor is configured to compress and to rout the exhaust gas to the turbine combustor. 
     Embodiment 12 
     The system of embodiment 11, wherein the gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine. 
     Embodiment 13 
     The system of embodiment 11 or 12, wherein the system includes an exhaust gas extraction system coupled to the gas turbine engine, and a hydrocarbon production system coupled to the exhaust gas extraction system. 
     Embodiment 14 
     A system includes a turbine combustor having a combustor liner disposed about a combustion chamber and a flow sleeve disposed at an offset about the combustor liner to define a passage. The passage includes an oxidant section configured to direct an oxidant in a first direction, wherein the oxidant is configured to react with a first fuel in the combustion chamber to produce combustion gases. The passage also includes a cooling section configured to direct an inert gas in a second direction substantially opposite to the first direction, wherein the inert gas is configured to cool the combustor liner and the combustion gases in the combustion chamber. The passage also includes a barrier section between the oxidant section and the cooling section, wherein the barrier section is configured to substantially separate the oxidant in the oxidant section from the inert gas in the cooling section. 
     Embodiment 15 
     The system of embodiment 14, wherein the system includes a controller configured to control a ratio between the oxidant and the first fuel in the combustion chamber. 
     Embodiment 16 
     The system of embodiment 15, wherein the system includes a first fuel nozzle configured to inject the first fuel into the combustion chamber. The controller is configured to control one or more flows through the first fuel nozzle to adjust a first ratio between the oxidant and the first fuel in the combustion chamber. 
     Embodiment 17 
     The system of embodiment 16, wherein the system includes a second fuel nozzle configured to inject a second fuel into the combustion chamber, wherein the controller is configured to control one or more flows through the second fuel nozzle to adjust a second ratio between the oxidant and the second fuel in the combustion chamber. 
     Embodiment 18 
     The system of embodiment 14, 15, 16, or 17 wherein the inert gas includes an exhaust gas having less than approximately 5 percent by volume of the oxidant or the first fuel. 
     Embodiment 19 
     The system of embodiment 14, 15, 16, 17, or 18, wherein the system includes a controller configured to control a first flow of the oxidant into the oxidant section, a second flow of the inert gas into the cooling section, and a position of the barrier section within the passage based at least in part on controlling the first flow, the second flow, or any combination thereof. 
     Embodiment 20 
     The system of embodiment 14, 15, 16, 17, 18, or 19, wherein the passage includes a physical barrier that at least partially extends between the combustor liner and a flow sleeve. 
     Embodiment 21 
     The system of embodiment 14, 15, 16, 17, 18, 19, or 20, wherein the oxidant section includes multiple mixing holes configured to direct the oxidant into the combustion chamber to mix with the first fuel, to increase a concentration of oxidant in the combustion chamber, or to raise a temperature of a reaction with the first fuel, or any combination thereof. 
     Embodiment 22 
     The system of embodiment 14, 15, 16, 17, 18, 19, 20, or 12, wherein the coolant section includes multiple dilution holes configured to direct a first portion of the inert gas into the combustion chamber to cool the combustor liner, to cool the combustion gases in the combustion chamber, or to reduce emissions of the combustion gases, or any combination thereof. 
     Embodiment 23 
     The system of embodiment 22, wherein the coolant section includes multiple mixing holes configured to direct a second portion of the inert gas into the combustion chamber to mix with the oxidant and the first fuel, to quench a reaction of the oxidant and the first fuel, or to reduce emissions of the combustion gases, or any combination thereof. 
     Embodiment 24 
     A method including injection an oxidant and a fuel into a combustion chamber from a head end of a turbine combustor, combusting the oxidant and the fuel in the combustion chamber to provide substantially stoichiometric combustion, and cooling the combustion chamber with an exhaust gas flow. The exhaust gas flow is directed upstream from a turbine end of the turbine combustor toward the head end along a passage disposed about the combustion chamber. The method also includes blocking the exhaust gas flow within the passage with a barrier, wherein the barrier includes a dynamic barrier, a physical barrier, or any combination thereof. 
     Embodiment 25 
     The method of embodiment 24, including controlling an equivalence ratio to provide the substantially stoichiometric combustion based at least in part on controlling at least one of the oxidant and the fuel injected into the combustion chamber through one or more fuel nozzles. 
     Embodiment 26 
     The method of embodiment 25, including adjusting the equivalence ratio by controlling a first ratio of the oxidant and the fuel injected through a center fuel nozzle of the one or more fuel nozzles while maintaining a second ratio of the oxidant and the fuel injected through perimeter fuel nozzles of the one or more fuel nozzles. 
     Embodiment 27 
     The method of embodiment 25, including adjusting the equivalence ratio by controlling the exhaust gas flow into the combustion chamber through mixing holes of the passage, dilution holes of the passage, or any combination thereof. 
     Embodiment 28 
     The method of embodiment 24, 25, 26, or 27, including reducing emissions of the combustion gases by diluting the combustion gases in the combustion chamber with the exhaust gas flow, cooling the combustion gases, or any combination thereof. 
     Embodiment 29 
     The method of embodiment 24, 25, 26, 27, or 28, including bleeding a portion of the exhaust gas flow from the passage to control the cooling of the combustion chamber. 
     Embodiment 30 
     The method of embodiment 24, 25, 26, 27, 28, or 29, including controlling the dynamic barrier in the passage by controlling a portion of the oxidant in the passage, the exhaust gas flow in the passage, or any combination thereof, wherein the dynamic barrier includes an interface with the oxidant and the exhaust gas flow.