Methods, systems and apparatus relating to combustion turbine power plants with exhaust gas recirculation

Description

BACKGROUND OF THE INVENTION

This application is related to U.S. application Ser. Nos. 13/444,956; 13/444,972, now abandoned; U.S. application Ser. Nos. 13/444,906; 13/444,918; 13/444,929; 13/444,948; 13/444,986; and 13/445,088, now granted as U.S. Pat. No. 8,539,749, all of which were filed concurrently herewith, and which are fully incorporated by reference herein and made a part thereof.

This present application relates generally to combustion turbine engines and systems related thereto. More specifically, but not by way of limitation, the present application relates to methods, systems and/or apparatus for achieving operation at the stoichiometric point and extracting a working fluid having desired characteristics within various types of combustion turbine systems having exhaust gas recirculation.

Oxidant-fuel ratio is the mass ratio of oxidant, typically air, to fuel present in an internal combustion engine. As one of ordinary skill in the art will appreciate, if just enough oxidant is provided to completely burn all of the fuel, a stoichiometric ratio of 1 is achieved (which may be referred to herein as “operating at the stoichiometric point” or “stoichiometric point operation”). In combustion turbine systems, it will be appreciated that combustion at the stoichiometric point may be desirable for several reasons, including lowering emissions levels as well as performance tuning reasons. In addition, by definition, stoichiometric point operation may be used to provide an exhaust (which, in the case of a system that includes exhaust recirculation, may be referred to generally as “working fluid”) that is substantially free of oxygen and unspent fuel. More specifically, when operating at the stoichiometric point, the working fluid flowing through certain sections of the recirculation circuit or loop may consists of significantly high levels of carbon dioxide and nitrogen, which, when fed into an air separation unit, may yield substantially pure streams of these gases.

As one of ordinary skill in the art will appreciate, producing gas streams of carbon dioxide and nitrogen in this manner has economic value. For example, the sequestration of carbon dioxide has potential value given current environmental concerns relating to emission of this gas. In addition, pure gas streams of carbon dioxide and nitrogen are useful in many industrial applications. Also, carbon dioxide may be injected into the ground for enhanced oil recovery. As a result, novel power plant system configurations and/or control methods that provide efficient methods by which stoichiometric point operation may be achieved would be useful and valuable. This would be particularly true if novel systems and methods provided effective ways by which existing power plants using reheat and exhaust gas recirculation could achieve improved operation via relatively minor, cost-effective modifications. Other advantages to the systems and methods of the present invention will become apparent to one of ordinary skill in the art given the description of several exemplary embodiments that is provided below.

BRIEF DESCRIPTION OF THE INVENTION

The present application thus describes a method of controlling a power plant that comprises a working fluid and a recirculation loop, wherein the power plant includes a combustor operably connected to a turbine, the method including the steps of: recirculating at least a portion of the working fluid through the recirculation loop; controlling the power plant such that the combustor at least periodically operates at a preferred stoichiometric ratio; and extracting the working fluid from at least one of a first extraction point and a second extraction point positioned on the recirculation loop during the periods when the combustor operates at the preferred stoichiometric ratio.

The present application further describes a power plant configured to include a recirculation loop about which a working fluid is recirculated, the recirculation loop comprising a plurality of components configured to accept an outflow of working fluid from a neighboring upstream component and provide an inflow of working fluid to a neighboring downstream component, wherein the recirculation loop includes: a recirculation compressor; a combustor positioned downstream of the recirculation compressor; a turbine positioned downstream of the combustor; and a recirculation conduit configured to direct the outflow of working fluid from the turbine to the recirculation compressor. The power plant may include: a first extraction means for extracting the working fluid from a first extraction point on the recirculation loop; a second extraction means for extracting the working fluid from a second extraction point on the recirculation loop; means for controlling the power plant such that the combustor at least periodically operates at a preferred stoichiometric ratio; and means for extracting working fluid from at least one of the first extraction means and the second extraction means during the periods when the combustor operates at the preferred stoichiometric ratio.

These and other features of the present application will become apparent upon review of the following detailed description of the preferred embodiments when taken in conjunction with the drawings and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing illustrating an exemplary configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 2 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 3 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 4 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 5 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 6 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 7 is a flow diagram illustrating an exemplary method of operation relating to a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 8 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 9 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a reheat combustion system;

FIG. 10 is a schematic drawing illustrating a configuration of an alternative power plant employing exhaust gas recirculation and a single combustion system;

FIG. 11 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a single combustion system;

FIG. 12 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a single combustion system; and

FIG. 13 is a schematic drawing illustrating an alternative configuration of a power plant employing exhaust gas recirculation and a single combustion system.

DETAILED DESCRIPTION OF THE INVENTION

Referring now to the figures, where the various numbers represent like parts throughout the several views, FIGS. 1 through 13 provided schematic illustrations of exemplary power plants according to configurations of the present application. As will be explained in further detail below, these power plants include novel system architectures and configurations and/or methods of control that achieve performance advantages given the recirculation of exhaust gases. Unless otherwise stated, the term “power plant”, as used herein, is not intended to be exclusionary and may refer to any of the configurations described herein, illustrated in the figures, or claimed. Such systems may include two separate turbines, exhaust gas recirculation, two combustion systems, and/or a heat-recovery steam generator.

As illustrated in FIG. 1, the power plant 9 includes a recirculation loop 10 that includes a recirculating flow of working fluid. In certain embodiments of the present invention, as illustrated in FIG. 1, the recirculation loop 10 is the means by which exhaust gas from the turbines recirculates, thereby creating a recirculating flow of working fluid. It will be appreciated that recirculation loop 10 is configured such that each of the components positioned thereon are configured to accept an outflow of working fluid from a neighboring upstream component and provide an inflow of working fluid to a neighboring downstream component. Note that the several components of the recirculation loop 10 will be described in reference to a designated “start position 8” on the loop 10. It will be appreciated that the start position 8 is arbitrary and the function of the system could be described in another manner or in reference to another start position without substantive effect. As shown, the start position 8 is positioned at the intake of an axial compressor 12. As configured, the axial compressor 12 accepts a flow of recirculated exhaust gases from the turbines; accordingly, the axial compressor 12 is referred to herein as “recirculation compressor 12”. Moving in a downstream direction, the recirculation loop 10 includes an upstream combustor 22, which is associated with a high-pressure turbine 30, and a downstream combustor 24, which is associated with a low-pressure turbine 32. It will be appreciated that the terms used to describe these components are purposely descriptive so that efficient description of the power plant 9 is possible. While the terms are not meant to be overly limiting, it will be appreciated that the “upstream” and “downstream” designations generally refer to the direction of flow of working fluid through the recirculation loop 10 given the designated start position 8. Further, the “high-pressure” and “low-pressure” designations are meant to refer to the operating pressure levels in each turbine 30, 32 relative to the other given the position of each turbine on the recirculation loop 10.

Downstream of the low-pressure turbine 32, recirculation conduit 40 channels exhaust gases to the intake of the recirculation compressor 12, which thereby recirculates the exhaust gases from the turbines (or, at least, a portion thereof). Several other components may be positioned on the recirculation conduit 40. It will be appreciated that these components may function to deliver the exhaust gases to the recirculation compressor 12 in a desired manner (i.e., at a desired temperature, pressure, humidity, etc.). As shown, in various embodiments, a heat recovery steam generator 39, a cooler 44, and a blower 46 may be included on the recirculation conduit 40. In addition, the recirculation loop 10 may include a recirculation vent 41 which provides a way to controllably vent an amount of exhaust from the recirculation conduit 40 such that a desirable flow balance is achieved. For example, it will be appreciated that under steady state conditions an amount of exhaust must be vented through the recirculation vent 41 that approximately equals the amount of compressed oxidant and fuel entering the recirculation loop 10 via the oxidant compressor 11 and fuel supply 20, respectively. It will be appreciated that achieving a desired balance between oxidant/fuel injected into and exhaust vented from the recirculation loop 10 may be done via sensors recording the amount of compressed oxidant and fuel entering the loop 10 and the amount of exhaust exiting, as well as, temperature sensors, valve sensors, pressure sensors within the recirculation loop 10, and other conventional means and systems.

The power plant 9 may include an oxidant compressor 11, which, unlike the recirculation compressor 12, is not fully integrated into the recirculation loop 10. As provided below, the oxidant compressor 11 may be an axial compressor that is configured to inject compressed air or other oxidant at one or more locations within the recirculation loop 10. In most applications, the oxidant compressor 11 will be configured to compress air. It will be appreciated that, in other embodiments, the oxidant compressor 11 may be configured to supply any type of oxidant which could be pressurized and injected into the combustion system. For example, the oxidant compressor 11 could compress a supply of air doped with oxygen. The recirculation compressor 12, on the other hand, is configured to compress recirculated exhaust gases from the turbines 30, 32. When necessary, a booster compressor 16 may be provided to boost the pressure of the discharge of the oxidant compressor 11 before it is injected into the recirculation loop 10 so that a preferable injection pressure is achieved. In this manner, the compressed oxidant may be effectively delivered to one or more combustors.

The oxidant compressor 11 and the recirculation compressor 12 may be mechanically coupled by a single or common shaft 14 that drives both. A generator 18 may also be included on the common shaft 14, while the high-pressure turbine 30 and the low-pressure turbine 32 drive the common shaft 14 and the loads attached thereto. It will be appreciated that the present invention may be employed in systems having shaft configurations different than the exemplary common shaft configuration 14 illustrated in the figures. For example, multiple shafts may be used, each of which may include one of the turbines and one or more of the load elements (i.e., one of the compressors 11, 12 or the generator 18). Such a configuration may include concentric shafts or otherwise.

In exemplary embodiments, the combustion system of the power plant 9, as shown, includes an upstream combustor 22 and, downstream of that, a downstream combustor 24. It will be appreciated that, as discussed in more detail below, the upstream combustor 22 and the downstream combustor 24 may include any type of conventional combustors, combustion systems and/or reheat combustors, and the chosen terminology refers only to relative positioning on the recirculation loop 10 (given the designated start position 8 and direction of flow). Typically, as depicted in FIG. 1 and discussed in more detail below, the upstream combustor 22 operates by injecting into the recirculation loop 10 combustion gas resulting from a fuel being combusted in a can combustor or other type of conventional combustor. Alternatively, certain combustion systems operate by direct fuel injection. Upon injection, the injected fuel combusts within the recirculation loop 10. Either of these methods generally increases the temperature and the kinetic energy of the working fluid, and either of the combustor types may be employed as the upstream combustor 22 or the downstream combustor 24. A fuel supply 20 may supply fuel, such as natural gas, to the upstream combustor 22 and the downstream combustor 24.

More specifically, the upstream combustor 22 may be configured to accept the flow of compressed oxidant from the oxidant compressor 11 and a fuel from the fuel supply 20. In this mode of operation, the upstream combustor 22 may include one or more cans or combustion chambers within which fuel and oxidant are brought together, mixed, and ignited such that a high energy flow of pressurized combustion gases is created. The upstream combustor 22 then may direct the combustion gases into the high-pressure turbine 30, where the gases are expanded and work extracted. The downstream combustor 24 may be configured to add energy/heat to the working fluid at a point downstream of the high-pressure turbine 30. As shown in the embodiment of FIG. 1, the downstream combustor 24 may be positioned just upstream of the low-pressure turbine 32. As stated, the downstream combustor 24 is so-called because it adds heat/energy to the flow of working fluid at a point downstream of the upstream combustor 22.

As one of ordinary skill in the art will appreciate, certain operational advantages may be achieved using a dual combustion or reheat system such as those described above. These advantages include, among other things: 1) fuel flexibility; 2) improved emissions; 3) lower overall firing temperatures; 4) less cooling and sealing requirements; 5) longer part life; and 6) use of less expensive materials due to lower firing temps. Accordingly, improving the operation of power plants that include reheat systems, as provided by the present invention, widens the potential usage of reheat systems and the realization of the advantages these systems typically provide.

As mentioned, the power plant 9 further includes recirculation conduit 40. The recirculation conduit 40, in general, forms the flow path by which exhaust from the turbines is recirculated, thereby completing the recirculation loop 10. More specifically, the recirculation conduit 40 directs the exhaust from the low pressure turbine 32 on a path that ends at the intake of the recirculation compressor 12. It will be appreciated that the recirculation conduit 40 may circulate the exhaust through several components along the way, including, as indicated in FIG. 1, a heat-recovery steam generator 39, a cooler 44, and a blower 46. (Note that, to avoid unnecessary complexity, the heat-recovery steam generator 39 has been represented in a simplified form in FIG. 1.) Those of ordinary skill in the art will appreciate that the heat-recovery steam generator 39 of the present invention may include any type of system in which combustion exhaust from one or more combustion turbines is used as the heat source for the boiler of a steam turbine.

Downstream of the heat-recovery steam generator 39, the cooler 44 may be positioned such that gases flowing through the recirculation conduit 40 flow through it. The cooler 44 may include a direct contact cooler or other conventional heat exchanger that suffices for this function, and may operate by extracting further heat from the exhaust gases such that the exhaust gases enter the recirculation compressor 12 at a desired or preferred temperature. The cooler 44 may also provide means by which humidity levels within the recirculated gases is controlled to preferable levels. That is, the cooler 44 may extract water from the flow through cooling it, which thereby lowers the humidity level of the recirculated gases upon the gases being heated to the temperature of the flow before entering the cooler. As illustrated in FIG. 1, the blower 46 may be located downstream of the cooler 44; however, as one of ordinary skill in the art will appreciate, this order may be reversed. The blower 46 may be of a conventional design. The blower 46 may function to more efficiently circulate the exhaust gases through the recirculation conduit 40 such that the gases are delivered to the intake of the recirculation compressor 12 in a desired manner.

The power plant 9 may include several types of conduits, pipes, valves, sensors and other systems by which the operation of the power plant 9 is controlled and maintained. It will be appreciated that all valves described herein may be controlled to various settings that affect the amount of fluid passing through the conduit. As already described, the recirculation conduit 40 recirculates exhaust gases from the turbines 30, 32 to the intake of the recirculation compressor 12, thereby providing a recirculating flow path for the working fluid. In addition, as indicated in FIG. 1, a first oxidant conduit 52 may be provided that directs the compressed oxidant from the oxidant compressor 11 to the upstream combustor 22. The first oxidant conduit 52 may include an oxidant valve 54 that controls the flow of oxidant through this conduit. The first oxidant conduit 52 further may include the booster compressor 16, which, as described in more detail below, may be used to boost the pressure of the compressed oxidant within this conduit. The first oxidant conduit 52 may further include a vent valve 56. The vent valve 56 provides means by which a portion of the compressed oxidant moving through the first oxidant conduit 52 is vented to atmosphere. As indicated in FIG. 1, certain embodiments of the present invention operate by providing a flow of compressed oxidant from the oxidant compressor 11 to the upstream combustor 22, but not the downstream combustor 24. In other embodiments, such as those shown in FIGS. 2 through 5, the present invention operates by providing a flow of compressed oxidant from the oxidant compressor 11 to the upstream combustor 22 and the downstream combustor 24. In still other embodiments, the present invention operates by providing a flow of compressed oxidant from the oxidant compressor 11 to the downstream combustor 22 but not the upstream combustor 24. This type of system, for example, is represented in FIGS. 2 and 4 when the oxidant valve 54 on the first oxidant conduit 52 is completely shut (i.e., set so that no flow from the oxidant compressor 11 is allowed to pass therethrough).

The fuel supply 20 may include two supply conduits that provide fuel to the upstream combustor 22 and/or the downstream combustor 24. As shown, a fuel valve 58 controls the amount of fuel being delivered to the upstream combustor 22, while another fuel valve 59 controls the amount of fuel being delivered to the downstream combustor 24. It will be appreciated that, though not shown in the figures, the fuel types delivered to the upstream combustor 22 and the downstream combustor 24 do not have to be the same, and that the use of different fuel types may be advantageous given certain system criteria. In addition, as discussed in more detail below, the fuel valve 58 and the fuel valve 59 may be controlled so that fuel is delivered to only one of the two combustors 22, 24. More specifically, in certain embodiments, the fuel valve 58 may be completely shut so that fuel is not delivered to the upstream combustor 22. In this case, as discussed in more detail below, both combustors 22, 24 may operate per the fuel delivered to the downstream combustor 24. Similarly, in certain embodiments, the fuel valve 59 may be completely shut so that fuel is not delivered to the downstream combustor 22. In this case, as discussed in more detail below, both combustors 22, 24 may operate per the fuel delivered to the upstream combustor 22. It will be appreciated that systems described herein as operating with a valve that is shut completely is intended to cover system configurations where the conduit on which the shut valve is positioned is omitted altogether.

An extraction point 51 comprises the point at which gases are extracted from the working fluid. In preferred embodiments, the extraction point 51 is positioned on the recirculation loop 10 such that carbon dioxide (CO₂) and/or nitrogen (N₂) may be efficiently extracted. Given certain modes of operation and system control, the system architecture of the present invention allows for such extraction to occur at a position that, as illustrated in FIG. 1, is upstream of both the high-pressure turbine 30 and the upstream combustor 22. More specifically, as shown, the extraction point 51 may be located at a position that is just upstream of the combustion reaction in the upstream combustor 22. The extraction point 51 may include conventional extracting means by which a portion of the gases within the working fluid are diverted into a conduit and, thereby, removed from the recirculation loop 10. An extracted gas valve 61 may be provided to control the amount of working fluid that is extracted. Downstream of the extracted gas valve 61, the conduit may deliver an extracted gas supply 62 to one or more downstream components (not shown). In preferred embodiments, the extracted gas supply 62 may be directed to a separation system (not shown) that separates the carbon dioxide from the nitrogen per conventional means. As stated, after separation, these gases may be used in many types of industrial applications, such as, for example, applications in the food and beverage industry.

Branching from the conduit that connects to the extraction point 51, a turbine bypass conduit 63 also may be included that provides a pathway that bypasses each of the turbines 30, 32. The turbine bypass conduit 63 is provided for startup situations, and, because it does not meaningfully impact the function of the present invention, will not be discussed further.

In other embodiments, the extraction point 51 may be located in different locations within the recirculation loop 10 of FIG. 1. As described in more detail below (particularly with regard to FIGS. 5 and 6), the architecture and control methods provided herein teach efficient and effective means by which one of the combustors 22, 24 may be operated at or near the stoichiometric point or a preferred stoichiometric ratio. That is, the fuel and oxidant supply within the power plant 9 may be controlled in such a way that, once the oxidant and fuel have adequately mixed, ignited and combusted within one of the combustors 22, 24, an exhaust that is free or substantially free of oxygen and unspent fuel is produced. In this condition, the exhaust consists of high levels of carbon dioxide and nitrogen, which may be economically extracted for use in other applications. As stated, “operation at the stoichiometric point” or “stoichiometric point operation” refers to operation at, near or within an acceptable or desired range about the stoichiometric point. It will be appreciated that “stoichiometric point” may also be referred to a stoichiometric ratio of 1, as it is said to include a 1-to-1 ratio of fuel and oxidant. It will further be appreciated that ratios that are greater than 1 are described as containing excess oxidant, while ratios less than 1 are described as containing excess fuel. It will be appreciated that, depending on the limitations of a particular power plant, the desired properties of the extracted working fluid, as well as other criteria, stoichiometric point operation may refer to stoichiometric operation within a range about the stoichiometric point or, put another way, a stoichiometric ratio of 1. Accordingly, in certain embodiments, “stoichiometric point operation” may refer to operation within the range of stoichiometric ratios defined between 0.75 and to 1.25. In more preferable embodiments, “stoichiometric point operation” may refer to operation within the range of stoichiometric ratios defined between 0.9 and to 1.1. In still more preferable embodiments, “stoichiometric point operation” may refer to operation that is substantially at or very close to a stoichiometric ratio of 1. Finally, in other preferable embodiments, “stoichiometric point operation” may refer to operation within the range of stoichiometric ratios defined between approximately 1.0 and to 1.1.

It will be appreciated that if one of the combustors 22, 24 is operated at the stoichiometric point (i.e., a stoichiometric ratio of 1 or within one of the predefined ranges described above or another desired range), the exhaust downstream of the combustor is substantially devoid of unspent fuel and oxygen, and consists substantially of carbon dioxide and nitrogen gas (and/or some other desirable gaseous characteristic), which may be economically extracted. As a result of this, pursuant to embodiments of the present invention, the extraction point 51 generally may be located at any point on the recirculation loop 10 that is both: 1) downstream of the whichever combustor 22, 24 is operating at the stoichiometric point and 2) upstream of the other combustor 22, 24. (It will be appreciated by those of ordinary skill in the art that “upstream of the other combustor”, as used herein, means upstream of the point within the combustor at which oxidant and/or fuel actually enters the recirculation loop 51, and that, because of this, “upstream of the other combustor” may include areas that might be construed as within the “other combustor” but which are also upstream of the position at which oxidant and/or fuel is injected into the flow of working fluid, such as, for example, certain areas within a combustor head-end. In a configuration like FIG. 1, assuming that the fuel input of the downstream combustor 24 is controlled to produce combustion at (or substantially at) the stoichiometric point, the extraction point 51 may be located at any point within a range defined between the downstream combustor 24 and, proceeding in a downstream direction, the upstream combustor 22. In one preferred embodiment, as illustrated in FIG. 1, the extraction point may be located within this range at the discharge of the recirculation compressor 12. It will be appreciated that this location provides extracted gas that is highly pressurized, which may be advantageous in certain downstream uses.

The power plant 9 may further include one or more sensors 70 that measure operating parameters, settings, and conditions within the components and various conduits of the system. One such sensor may be a sensor for detecting excess oxidant 64, such as, for example, a conventional oxygen sensor. The sensor for detecting excess oxidant 64 may be positioned just upstream of the extraction point 51 and may measure at predefined intervals the oxygen content of the exhaust or working fluid flowing through the recirculation loop 10. Positioned thusly, the sensor for detecting excess oxidant 64 may be well situated to test the working fluid for oxidant content, which may provide information as to stoichiometric ratio within the combustor directly upstream of the sensor for detecting excess oxidant 64 and/or whether extraction of the working fluid would yield a gas supply that is suitably free of oxidant and unspent fuel. It will be appreciated that the sensor for detecting excess oxidant 64 may be positioned within a range on the recirculation loop 10 that is defined between the extraction point 51 and, proceeding in the upstream direction, the first combustor 22, 24 that is encountered. It will be appreciated that, given the positioning of the extraction point 51, the first combustor 22, 24 encountered in the upstream direction is the combustor 22, 24 which is being controlled at the preferred stoichiometric ratio. In this manner, the sensor for detecting excess oxidant 64 may be used to determine the current desirability of extracting gas from the recirculation loop 10. As described in more detail below, the system may include other sensors 70 that measure a host of process variables that may relate to any of the components of the system. Accordingly, the figures indicate a plurality of sensors 70 at exemplary locations about the power plant 9. As one of ordinary skill in the art will appreciate, conventional systems typically include many sensors other than just those represented in the several figures, and, further, that those other sensors may be located in other locations within the system than just those indicated. It will be appreciated that these sensors 70 may electronically communicate their readings with the control unit 65 and/or function pursuant to instructions communicated to them by the control unit 65. One such sensor 70 that could be used either together or interchangeably with the sensor for detecting excess oxidant 64 is a sensor that detects the presence of unspent fuel in the exhaust. Teamed with the sensor for detecting excess oxidant 64, an unspent fuel sensor 70 could provide measurements from which the stoichiometric ratio in the upstream combustor 22, 24 could be determined as well as the current suitability of extracting working fluid. Those skilled in the art will appreciate that other sensors may be used to collect data concerning the stoichiometric properties of the combustion occurring within the combustors. For example, a CO sensor and a humidity sensor may be used.

The power plant 9 may further include a control unit 65 that functions according to certain embodiments described herein. It will be appreciated that the control unit 65 may include an electronic or computer implemented device that takes in data from sensors and other sources regarding plant operational parameters, settings, and conditions, and, pursuant to algorithms, stored data, operator preferences, etc., controls the settings of the various mechanical and electrical systems of the power plant 9 such that desired modes of operation are achieved. For example, the control unit 65 may control the power plant 9 such that stoichiometric operation or operation at a preferred stoichiometric ratio is achieved in one of the combustors 22, 24. It will be appreciated that the control mechanism may achieve this objective by balancing the fuel and oxidant injected into the either the upstream or downstream combustor 22, 24, as well as taking into account any excess oxidant or unspent fuel from the other of the two combustor 22, 24 that travels within the recirculating working fluid. Once stoichiometric operation is achieved, the control unit 65 may control the extracted gas valve 61 such that extraction takes place at a desired rate and for a desired period of time or until changing conditions make the extraction no longer suitable. The settings of the various valves described above that govern the flow of working fluid, extraction of gases, fuel consumption, etc. may be controlled pursuant to electrical signals, which may be sent via wired or wireless communication connections, received from the control unit 65.

In use, the power plant 9 according to an exemplary embodiment may operate as follows. The rotation of blades within oxidant compressor 11 compresses oxidant that is supplied, via the first oxidant conduit 52 to the upstream combustor 22. Before reaching the upstream combustor 22, the booster compressor 16 may be provided in some embodiments. The booster compressor 16 may be used to increase the pressure of the oxidant being supplied by the oxidant compressor 11 to a level that is adequate or preferable for injection into the upstream combustor 22. In this manner, the flow of compressed oxidant may be joined within the upstream combustor 22 with a flow of compressed exhaust gases, which is supplied to the combustor from the recirculation compressor 12. It will be appreciated that successfully bringing together two such flows within the upstream combustor 22 may be accomplished in several ways and that, depending on how the flows are introduced within the upstream combustor 22, suitable pressure levels for each may vary. The present invention teaches methods and system configurations by which pressure levels may be controlled such that the flows may be combined in a suitable manner, while avoiding avoidable aerodynamic losses, backflow, and other potential performance issues.

Accordingly, the upstream combustor 22 may be configured to combine the flow of compressed oxidant from the oxidant compressor 11 with the flow of compressed exhaust gases from the recirculation compressor 12 and combust a fuel therein, producing a flow of high-energy, pressurized combustion gases. The flow of combustion gases then is directed over the stages of rotating blade within the high-pressure turbine 30, which induces rotation about the shaft 14. In this manner, the energy of the combustion gases is transformed into the mechanical energy of the rotating shaft 14. As described, the shaft 14 may couple the high-pressure turbine 30 to the oxidant compressor 11 so that the rotation of the shaft 14 drives the oxidant compressor 11. The shaft 14 further may couple the high-pressure turbine 30 to the recirculation compressor 12 so that the rotation of the shaft 14 drives the recirculation compressor 12. The shaft 14 also may couple the high-pressure turbine 30 to the generator 18 so that it drives the generator 18 as well. It will be appreciated that the generator 18 converts the mechanical energy of the rotating shaft into electrical energy. Of course, other types of loads may be driven by the high-pressure turbine 30.

The working fluid (i.e., the exhaust from the high-pressure turbine 30) then is directed to the low-pressure turbine 32. Before reaching the low-pressure turbine 32, the downstream combustor 24 adds heat/energy to the working fluid flowing through the recirculation loop 10, as described above. In the embodiment of FIG. 1, the downstream combustor 24 is configured to combust a fuel within the exhaust from the high-pressure turbine 30. In alternative embodiments, as shown in FIGS. 2-6 and discussed in more detail below, the downstream combustor 24 may be configured to combine a flow of compressed oxidant from the oxidant compressor with the flow of exhaust gases from the high-pressure turbine 30 and combust a fuel therein, producing a flow of high-energy, pressurized combustion gases. The working fluid then is directed over the stages of rotating blades within the low-pressure turbine 32, which induces rotation about the shaft 14, thereby transforming the energy of the combustion gases into the mechanical energy of the rotating shaft 14. As with the high-pressure turbine 30, the shaft 14 may couple the low-pressure turbine 32 to the oxidant compressor 11, the recirculation compressor 12, and/or the generator 18. In certain embodiments, the high-pressure turbine 30 and the low-pressure turbine 32 may drive these loads in tandem. In other embodiments, concentric shafts may be used such that the high-pressure turbine 30 drives part of the load on one of the concentric shafts, while the low-pressure turbine 32 drives the remaining load on the other. Additionally, in other system configurations, the high-pressure turbine 30 and the low-pressure turbine 32 may drive separate, non-concentric shafts (not shown).

From the low-pressure turbine 32, recirculation conduit 40 may form a flow path that completes the recirculation loop 10 of the present invention. This flow path, ultimately, delivers the exhaust gases from the turbines 30, 32 to the intake of the recirculation compressor 12. As part of this recirculation conduit 40, the exhaust gases may be used by the heat-recovery steam generator 39. That is, the exhaust gases may provide a heat source for the boiler that drives a steam turbine which receives steam from the heat-recovery steam generator 39. Downstream of that, the exhaust gases may be further cooled by the cooler 44 as well as being passed through a blower 46. The cooler 44 may be used to lower the temperature of the exhaust gases so that they are delivered to the intake of the recirculation compressor 12 within a desired temperature range. The blower 46 may assist in circulating the exhaust gases through the recirculation loop 10. It will be appreciated that the heat recovery steam generator 39, the cooler 44 and the blower 46 may include conventional components and be operated pursuant to conventional methods.

In regard to the operation of the control unit 65, it will be appreciated that it may include an electronic or computer implemented device that takes in data regarding plant operational parameters and conditions, and, pursuant to algorithms, stored data, operator preferences, etc., controls the settings of the various mechanical and electrical systems of the power plant 9 such that desired modes of operation are achieved—for example, achieving operation at or substantially at the stoichiometric point. The control unit 65 may include control logic specifying how the mechanical and electrical systems of the power plant 9 should operate. More specifically, and in accordance with certain embodiments of the present application, the control unit 65 typically includes programmed logic that specifies how certain operating parameters/stored data/operator preferences/etc. should be monitored and, given certain inputs from the monitored data, how the various mechanical and electrical systems of the power plant 9, such as those described above, should be operated. The control unit 65 may control the operation of the various systems and devices automatically in response to the dictates of the control logic, or, in certain instances, may seek operator input before actions are taken. As one of ordinary skill in the art will appreciate, such a system may include multiple sensors, devices, and instruments, some of which are discussed above, that monitor relevant operational parameters. These hardware devices may transmit data and information to the control unit 65, as well as being controlled and manipulated by the control unit 65. That is, pursuant to conventional means and methods, the control unit 65 may receive and/or acquire data from the systems of the power plant 9, process the data, consult stored data, communicate with the operators of the power plant 9, and/or control the various mechanical and electrical devices of the system pursuant to a set of instructions or logic flow diagrams, which, as one of ordinary skill in the art will appreciate, may be made part of a software program that is operated by control unit 65, and which may include aspects relating to embodiments of the present invention. In short, the control unit 65 may control operation of the power plant 9 such that it operates at the stoichiometric point and, while operating thusly, extracts a supply of combustion exhaust that is substantially devoid of oxygen and unspent fuel. Discussion below, in relation to FIG. 7, relates to logic flow diagrams according to the present invention for operating the systems described herein at the stoichiometric point and extraction of desirable exhaust gas. It will be appreciated that these logic flow diagrams may be used by the control unit for such purposes.

FIGS. 2 through 6 provide embodiments of the present invention that include alternative system configurations. It will be appreciated that these configurations present alternative strategies for injecting oxidant from the oxidant compressor 11 into the recirculation loop 10, delivering fuel to the combustion systems, and the manner in which exhaust gases may be extracted. Each of these alternatives offers certain advantages, including the manner in which stoichiometric operation may be achieved and maintained. It will be appreciated that these alternatives are exemplary and not intended to provide an exhaustive description of all possible system configurations which might fall within the scope of the appended claims. In addition, while FIGS. 2 through 6 illustrate both fuel and oxidant being delivered to each of the upstream and the downstream combustor 22, 24, it will be appreciated that certain embodiments described below function in systems in which oxidant is delivered to only one of the upstream and downstream combustors 22, 24 and/or systems in which fuel is delivered to only one of the upstream and downstream combustors 22, 24. Examples of any of these systems may be constructed via control of the various valves 54, 58, 59, 68 that deliver oxidant and fuel to the combustors 22, 24.

FIG. 2 through 4 provide embodiments that include a second oxidant conduit 67 and oxidant valve 68, which together may be used to supply a controlled compressed oxidant amount (which like the first oxidant conduit 52 is derived from the oxidant compressor 11) to the downstream combustor 24. As shown in FIGS. 2 and 3, the second oxidant conduit 67 may branch from the first oxidant conduit 52, which means that the compressed oxidant for each is drawn from the same supply point from the oxidant compressor 11. In FIG. 2, the branching occurs such that a connection with the first oxidant conduit 52 occurs upstream of the oxidant valve 54 and booster compressor 16 of the first oxidant conduit 52. In this case, the second oxidant conduit 67 thereby bypasses the booster compressor 16. This may be useful in creating flows of differing pressures levels within the first oxidant conduit 52, which would have a higher pressure due to the booster compressor 16 than that within the second oxidant conduit 67. As the first oxidant conduit 52 provides compressed oxidant to a point on the recirculation loop 10 upstream of the second oxidant conduit 67, this configuration allows for an efficient means by which the pressure in each may be controlled to a pressure level that is appropriate for injection at the different locations. In FIG. 3, the branching occurs downstream of the oxidant valve 54 of the first oxidant conduit 52. More specifically, the branching of the second oxidant conduit 52 occurs between the oxidant valve 54 of the first oxidant conduit 52 (which may be positioned downstream of the booster compressor 16, as shown) and combustor 22.

As illustrated in FIG. 4, the second oxidant conduit 67 may also be independent of the first oxidant conduit 52. As shown, in this instance, the second oxidant conduit 67 may extend from an extraction point within the oxidant compressor 11. The extraction point for the second oxidant conduit may be located at one of the stages that is upstream of the position where the first oxidant conduit 52 derives its flow of compressed oxidant, which, for example, may be located in the compressor discharge casing. More specifically, the extraction point may be configured to bleed compressed oxidant at an intermediate stage within the oxidant compressor 11. With the first oxidant conduit 52 drawing from the compressor discharge casing or in proximity thereto, this arrangement results in a higher pressure flow of compressed oxidant through the first oxidant conduit 52 than that in the second oxidant conduit 67. It again will be appreciated that this configuration allows the first and second oxidant conduits 52, 67 to have differing pressure levels without the need of including a booster compressor 16. As before, the pressure differential may be useful in that the pressure of the compressed oxidant may be matched to the pressure at the position on the recirculation loop 10 it is used.

FIGS. 5 and 6 provide differing strategies for locating the extraction point 51 given the fact that both combustors 22, 24 receive a supply of compressed oxidant from the oxidant compressor 11. It will be appreciated that configuring the system to have two points at which oxidant/fuel are combusted provides new alternatives for producing operation at the stoichiometric point (note that, as stated, this refers to operation within a desired range about or near the stoichiometric point), and, thus, differing locations (as provided in FIGS. 5 and 6) at which working fluid may be extracted. As described, the architecture and control methods provided herein teach efficient and effective means by which power plants may be operated at the stoichiometric point. The fuel and oxidant supply to the power plant 9 may be controlled in such way that, once the oxygen (from the injected oxidant) and fuel have adequately mixed, ignited and combusted, an exhaust that is substantially free of oxygen and unspent fuel is produced. As a result of this, pursuant to embodiments of the present invention, the extraction point 51 may be located at any point on the recirculation loop 10 that has exhaust derived from stoichiometric point operation. As described above in relation to the configuration of FIG. 1, this generally means that the extraction point may be located at any position on the recirculation loop 10 that is both: 1) downstream of the combustor 22, 24 which is being operated at the stoichiometric point; and 2) upstream of the other combustor 22, 24. It will be appreciated that more than one extraction point within this range may be provided, and that this arrangement may be useful where different pressure levels are useful for a plurality of extracted gas supplies.

FIG. 5 illustrates an exemplary configuration having an extraction point 51 that is positioned near the aft end of the high-pressure turbine 30. It will be appreciated that this extraction point 51 may prove effective when the upstream combustor 22 operates at the stoichiometric point. Given the principles discussed above and assuming this operation, possible extraction points 51 constitute a range defined between the upstream combustor 22 and, proceeding in the downstream direction, the downstream combustor 24. That is, pursuant to embodiments of the present invention, the power plant 9 may be controlled such that the combined effect of the oxidant and fuel introduced within the combustors 22, 24 produces combustion within the upstream combustor 22 at a preferred stoichiometric ratio, which thereby creates a range of positions downstream of the upstream combustor 22 in which extraction of working fluid having desired characteristics may be achieved.

FIG. 6 illustrates an exemplary configuration having an extraction point 51 that is positioned just upstream of the heat recovery steam generator 39. It will be appreciated that this extraction point 51 may prove effective when the downstream combustor 24 operates at the stoichiometric point. Given the principles discussed above and assuming this operation, possible extraction points 51 constitute a range defined between the downstream combustor 24 and, proceeding in the downstream direction, the upstream combustor 22. That is, pursuant to embodiments of the present invention, the power plant 9 may be controlled such that the combined effect of the oxidant and fuel introduced within the combustors 22, 24 produces combustion within the downstream combustor 24 at a preferred stoichiometric ratio, which thereby creates a range of positions downstream of the downstream combustor 24 in which extraction of the working fluid having desired characteristics may be achieved.

FIG. 7 illustrates a logic flow diagram 100 for a method of operating the power plant 9 according to an exemplary embodiment of the present invention. As one of ordinary skill in the art will appreciate, the logic flow diagram 100 is exemplary and includes steps which may not be included in the appended claims. Further, any function described above in relationship to the several components of the system is incorporated into the discussion below where necessary or possible to aid in the carrying out of the specified steps. The logic flow diagram 100 may be implemented and performed by the control unit 65. In some embodiments, the control unit 65 may comprise any appropriate high-powered solid-state switching device. The control unit 65 may be a computer; however, this is merely exemplary of an appropriate high-powered control system, which is within the scope of the present application. In certain embodiments, the control unit 65 may be implemented as a single special purpose integrated circuit, such as ASIC, having a main or central processor section for overall, system-level control, and separate sections dedicated to performing various different specific combinations, functions and other processes under control of the central processor section. It will be appreciated by those skilled in the art that the control unit also may be implemented using a variety of separate dedicated or programmable integrated or other electronic circuits or devices, such as hardwired electronic or logic circuits including discrete element circuits or programmable logic devices. The control unit 65 also may be implemented using a suitably programmed general-purpose computer, such as a microprocessor or microcontroller, or other processor device, such as a CPU or MPU, either alone or in conjunction with one or more peripheral data and signal processing devices. In general, any device or similar devices on which a finite state machine capable of implementing the logic flow diagram 100 may be used as the control unit 65.

It will be appreciated that, in one possible environment, the control unit 65 may include a General Electric SPEEDTRONIC™ Gas Turbine Control System, such as is described in Rowen, W. I., “SPEEDTRONIC™ Mark V Gas Turbine Control System”, GE-3658D, published by GE Industrial & Power Systems of Schenectady, N.Y. The control unit 65 may be a computer system having a processor(s) that executes programs to control the operation of the gas turbine using sensor inputs and instructions from human operators. The programs executed by the control unit 65 may include scheduling algorithms for regulating the components of the power plant 9. The commands generated by the control unit 65 may cause actuators within any of the components to, for example, adjust valves between the fuel supply and combustors 22, 24 that regulate the flow and type of fuel, inlet guide vanes on the compressors 11, 12, and other control settings on the turbine 30, 32. Further, the control unit 65 may regulate the power plant 9 based, in part, on algorithms stored in computer memory of the control unit 65. These algorithms, for example, may enable the control unit 65 to maintain emission levels in exhaust to within certain predefined limits, to maintain the combustor firing temperature to within predefined temperature limits, or another maintain operational parameter within a predefined range.

Returning to FIG. 7, one of ordinary skill in the art will appreciate that, in general, flow diagram 100 illustrates an example of how a feedback loop may be structured to provide an iterative process for controlling stoichiometry within one of the combustors and/or extraction level of exhaust having desired characteristics. It will be appreciated that the several steps of such a process may be described in many different ways without deviating from the central idea of the process set forth herein. The control methods described herein may be implemented via a feedback loop that is used in conjunction with control algorithms, such as a PID control algorithm, though other control algorithms also may be used.

Logic flow diagram 100 may begin at a step 102, which includes monitoring and measuring the operating conditions and process variables (which will be referred to generally as “process variables”) of the power plant 9. Process variables, as used herein, represent the current status of the system or process that is being controlled. In this case, process variables may include any operating parameter that may be measured by any type of sensor. More specifically, at step 102, the control unit 65, pursuant to any of the methods discussed above or any conventional systems (either current or developed in the future), may receive, monitor, and record data relating to the operation of the power plant 9. The operation of the power plant 9 and the several components related thereto may be monitored by several sensors 70 detecting various conditions of the system and environment. For example, one or more of the following process variable may be monitored by the sensors 70: temperature sensors may monitor ambient temperature surrounding the plant 9, inlet and discharge temperatures of the compressors 11, 12, exhaust temperature and other temperature measurements along the hot-gas path of the turbines 30, 32, pressure sensors may monitor ambient pressure, and static and dynamic pressure levels at the inlet and outlet of the compressors 11, 12, and exhaust of the turbines 30, 32, as well as at other locations in the gas stream. Sensors 70 further may measure the extraction level at the extraction point 51, fuel flow to each of the combustors 22, 24, gas composition within the recirculated exhaust gas or working fluid (which may include sensor for detecting excess oxidant 64 as well as other sensors that measure levels of unspent fuel or CO or other gases within the exhaust gas), temperature and pressure of the recirculated exhaust gas along the recirculation conduit 10, including parameters relating to the operation of the heat recovery steam generator 39, the cooler 44, and the blower 46. The sensors 70 may also comprise flow sensors, speed sensors, flame detector sensors, valve position sensors, guide vane angle sensors, and the like that sense various parameters pertinent to the operation of power plant 9, which may include oxidant flow characteristics through the first oxidant conduit 52 and the second oxidant conduit 67. It will be appreciated that the system may further store and monitor certain “specified set-points” that include operator preferences relating to preferred or efficient modes of operation. It further will be appreciated that the measuring, monitoring, storing and/or recording of process variables and/or specified set-point may occur continuously or at regular intervals, and that updated or current data may be used throughout any of the several steps of logic flow diagram 100 whether or not there is a direct line in FIG. 7 connecting step 102 to the other steps. From step 102, the process may continue to step 104.

At a step 104, the method may determine whether whichever combustor 22, 24 is configured to operate at a preferred stoichiometric ratio (which may include a range of suitable stoichiometric ratios) is, in fact, operating at the preferred stoichiometric ratio. It will be appreciated that this may be accomplished by comparing measured process variables, calculating current conditions, and comparing current conditions to specified set-points. If it is determined that this mode of operation is occurring, the method may proceed to step 106. If it is determined that this mode of operation is not occurring, the method may proceed to step 114.

It will be appreciated that the determination as to whether the relevant combustor 22, 24 is operating at the preferred stoichiometric ratio may be achieved in several ways and that, once determined, a feedback loop using one or more control inputs may be used to control the system within this preferred mode or cause the system to operate in this manner. One method may be to detect or measure the content of the exhaust gases being emitted from the relevant combustor. This may include sensors 70, such as the sensor for detecting excess oxidant 64, that measures the gases present in the exhaust and/or other relevant characteristics. It will be appreciated that a sensor 70 that detects the presence of unspent fuel or CO or other gases within the exhaust flow may be used also. Measuring the flow characteristics of the inputs (i.e., the oxidant and the fuel) to one of the combustors also may be used to determine if combustion within the relevant combustor is occurring at the preferred stoichiometric ratio. In this case, for example, the oxidant flow into the combustor may be measured, the fuel flow into the combustor may be measured, and a determination made as to the stoichiometric characteristics of the combustion therein given these inputs. Other relevant operating characteristics (such as temperature, pressure, etc.) may also be taken into account. Alternatively, or in conjunction with this calculation, unspent fuel or CO or other gases and/or oxygen may be measured downstream of the combustors or other points within the circulating flow of working fluid. From this, a calculation may be made as to the stoichiometric balance of the combustion, which may then be compared with the specified set-point or preferred stoichiometric ratio to determine if it falls within an acceptable range.

At step 106, having already determined that one of the combustors is operating within the desired stoichiometric range, the logic flow diagram 100 may determine the current level of extraction at extraction point 51. This may be done via checking measured process variables which either indicate this flow level directly or may be used to calculate the amount of gas being extracted. The method may further check whether the current level of extraction satisfies a desired level of extraction or specified set-point. This may be done by comparing the actual level of extraction (which may be measured) to operator defined set-points or preference. If it is determined that the desired level of extraction is being satisfied, the method may cycle back to step 102 where the process begins anew. If it is determined that the desired level of extraction is not being satisfied, the method may proceed to step 108.

At step 108, the method determines one or more “control inputs” that may be used to manipulate the function of system components in such a way as to achieve the desired level of extraction or, at least, to achieve an extraction level that decreases the difference between the actual level of extraction and the desired level of extraction. It will be appreciated that a “control input” is one of the many ways by which operation of the power plant 9 or any of its components may be controlled or manipulated. These, for example, may include level of fuel flow to the combustors 22, 24, control of oxidant flow to the combustors 22, 24, angle of inlet guide vanes within the compressors 11, 12, etc. Whereas, a “variance amount” is the extent to which a control input must be manipulated to bring about the desired manner of operation. The variance amount, for example, may include the extent to which the fuel flow to the combustors 11, 12 must be increased or decreased to bring about desired operation. In certain embodiments, one of the control inputs that is particularly relevant at step 108 is the setting of the extracted gas valve 61. In this case, the variance amount is the extent to which the setting of the valve 61 needs to be manipulated so that a desired extraction level is achieved. The method may then proceed to step 110. It will be appreciated that a conventional feedback control mechanism in conjunction with a PID controller or the like may be used to achieve control as specified herein. Thus, an iterative process of variations to one or more control inputs may bring the system toward desired operation.

At step 110, in some embodiments, the method may determine the probable effects to plant operation of each of the available control inputs/variance amounts from step 108 before making the actual change to the control input. It will be appreciated that these types of calculations may be achieved per conventional power plant control programs and modeling software, such as those systems and methods mention herein and others similar to them. It further will be appreciated that these calculations may involve an iterative process that takes into account efficient control measures/counter-measures which may be made in response to the proposed variance of the relevant control input, economic considerations, wear and tear to the power plant, operator preferences, plant operational boundaries, etc. The method then may proceed to Step 112.

At step 112, the process 100 may determine which of the available control inputs/variance amounts from the above step is most favorable or preferred. This determination, in large part, may be based upon the effects to system operation that were calculated in step 110. Then, for whichever control input/variance amount is deemed most favorable, the method may determine if the proposed control input/variance amount should be executed based on whether the associated benefits of meeting extraction demand outweighs the costs associated with executing the variance amount. It will be appreciated that economic considerations and operator preferences may be included in this determination. Based on this calculation, the method then may execute the proposed control input/variance amount or not. The method then may return to step 102, and an iterative process begun by which a preferred level of extraction is achieved.

As described above, if at step 104 it is determined that the relevant combustor is not operating at the stoichiometric point, the method may proceed to step 114. At step 114, the method may determine one or more control inputs/variance amounts that are available for achieving stoichiometric point operation within the relevant combustor. As before, control inputs include ways in which operation of the power plant 9 may be altered, manipulated or controlled, and the variance amount is the extent to which a control input must be manipulated to achieve a desired mode of operation. The method may then proceed to step 116.

At step 116, the method may determine the probable effects to plant operation of each of the available control inputs/variance amounts from step 114. It will be appreciated that these types of calculations may be achieved per conventional power plant control programs and modeling software, such as those systems and methods mention herein and others similar to them. It further will be appreciated that these calculations may involve an iterative process that takes into account efficient control measures/counter-measures which may be made in response to the proposed variance of the relevant control input, economic considerations, wear and tear to the power plant, operator preferences, plant operational boundaries, etc. The method then may proceed to Step 118.

Plant operation boundaries may include any prescribed limit that must be followed so that efficient operation is achieved and/or undue wear and tear or more serious damage to systems is avoided. For example, operational boundaries may include maximum allowable temperatures within the turbines 30, 32 or combustor components. It will be appreciated that exceeding these temperatures may cause damage to turbine components or cause increased emissions levels. Another operational boundary includes a maximum compressor pressure ratio across each of the oxidant compressor 11 and the recirculation compressor 12. Exceeding this limitation may cause the unit to surge, which may cause extensive damage to components. Further, the turbine may have a maximum mach number, which indicates the maximum flow rate of the combusted gases at the exit of the turbine. Exceeding this maximum flow rate may damage turbine components. Given the possible configuration of combustors within the power plant 9, relative pressures of the flows delivered at the combustors 22, 24 by each of the compressors 11, 12 may be another operational boundary. That is, depending on the configuration of the combustor 22, 24 and the manner in which flows are combined, the pressure of the compressed oxidant delivered by the oxidant compressor 11 must be within a certain range of that supplied by recirculation compressor 12 to avoid aerodynamic losses, backflow, and other potential issues.

At step 118, the method may determine which of the available control inputs/variance amounts from the above step is most favorable or preferred. This determination, in large part, may be based upon the effects to system operation that were calculated in step 116 as well as the extent to which the control input/variance amount is able to manipulate the power plant system toward the intended mode of operation. Then, for whichever control input/variance amount is deemed most favorable, the method may determine if the proposed control input/variance amount should be executed based on whether the associated benefits of achieving stoichiometric point operation (which may include the benefits of being able to extract working fluid) outweighs the costs associated with executing the variance amount. It will be appreciated that economic considerations and operator preferences may be included in this determination. Based on this calculation, the method then may execute the proposed control input/variance amount or not. The method then may return to step 104, and an iterative process by which stoichiometric point operation within one of the combustors is ultimately achieved or determined not possible due to some operational constraint.

It will be appreciated that there are many possible control inputs/variance amounts that affect the stoichiometric ratio in the combustors 22, 24. In preferred embodiments, one such control input includes controllably varying the compressed oxidant amount delivered to the combustors 22, 24. It will be appreciated that controllably varying the supply of compressed oxidant may have a significant effect on the stoichiometry ratio within the combustors 22, 24. For example, if sensors indicate that, given the supply of fuel to a combustor, more compressed oxidant (i.e., more oxygen) is needed to achieve stoichiometric combustion, the supply of compressed oxidant may be increased by manipulating inlet guide vanes of the oxidant compressor 11 and/or changing valve settings on the oxidant valves 54, 68 so that more compressed oxidant is able to pass through the oxidant conduit 52, 67 associated with the combustor. On the other hand, varying fuel supply is another control input that may be used to achieve operation at a preferred stoichiometric ratio. In this case, for example, sensors 70 may indicate that, given the compressed oxidant amount being delivered to the combustor, more fuel is needed to achieve stoichiometric point operation. The fuel amount being delivered to the one or both combustors 22, 24 may be increased by manipulating one or both of the fuel valves 58, 59. Further, it will be appreciated that stoichiometric point combustion may be controlled in one of the combustors by changing settings that are directly related to the other combustor. This is because changed settings within one combustor may create excess oxidant or unspent fuel in the recirculation loop 10 that is ultimately ingested within the other combustor, thereby affecting the combustion stoichiometric ratio therein.

In one exemplary mode of control, the fuel/oxidant input into the power plant 9 may be set such that there is excess oxidant (i.e., a stoichiometric ratio greater than 1) in whichever of the combustors 22, 24 is meant to operate at the stoichiometric point. Then, the control process may decrease the excess oxidant by small increments within the relevant combustor 22, 24 (either by increasing fuel flow to the combustor or by decreasing the oxidant supply) while monitoring the stoichiometric ratio therein by measuring a relevant process variable. In certain embodiments, this may continue until the stoichiometric ratio is within a preferred range, while still being slightly above 1 (i.e., still having excess oxidant). This may be implemented by slowly increasing oxidant flow, decreasing fuel flow, or both to the particularly combustor 22, 24, while monitoring stoichiometric conditions therein. It may also be done indirectly by slowly increasing oxidant flow, decreasing fuel flow, or both to the other combustor 22, 24 so that excess fuel or oxidant becomes part of the working fluid and ingested into the relevant combustor.

FIGS. 8 and 9 provide schematic illustrations of alternative configurations of exemplary power plants according to the present application. As shown, these power plants also employ exhaust gas recirculation and a reheat combustion system similar to those described above. However, the power plants of FIGS. 8 and 9 provide dual extraction locations on the recirculation loop. It will be appreciated that while the description of components, system configurations, and control methods provided above are applicable to the power plants of FIGS. 8 and 9 (as well as some of the functionality described below being applicable to the components, system configuration, and control methods described above), the dual extraction locations provide a novel application that enables enhanced functionality, which may beneficially employed in certain operating conditions. As before, the power plant 9 may include a recirculation loop 10 about which a working fluid is recirculated. The recirculation loop 10 may include a plurality of components that are configured to accept an outflow of working fluid from a neighboring upstream component and provide an inflow of working fluid to a neighboring downstream component. The components of the recirculation loop 10 may include: a recirculation compressor 12; an upstream combustor 22 positioned downstream of the recirculation compressor 12; a high-pressure turbine 30 positioned downstream of the upstream combustor 22; a downstream combustor 24 positioned downstream of the high-pressure turbine 30; a low-pressure turbine 32 positioned downstream of the downstream combustor 24; and recirculation conduit 40 configured to complete the loop by directing the outflow of working fluid from the low-pressure turbine 32 to the recirculation compressor 12. As described in more detail above in relation to the other exemplary power plants 9 provided in the several figures, the power plant 9 of FIGS. 8 and 9 may further include systems and components that control and deliver a compressed oxidant amount to each of the upstream combustor and the downstream combustor. As described above in relation to the other exemplary power plants 9, the power plant 9 of FIGS. 8 and 9 may further include systems and components that control a fuel amount supplied to each of the upstream combustor 22 and the downstream combustor 24. The power plant 9, as illustrated, may further include systems and components that extract the working fluid exhausted from the upstream combustor 22 from a first extraction point 75, and systems and components that extract the working fluid exhausted from the downstream combustor 24 from a second extraction point 76. The power plant 9, as illustrated in FIGS. 8 and 9 and discussed further above, may include systems and components for controlling operation such that each of the upstream combustor 22 and the downstream combustor 24 periodically operate at a preferred stoichiometric ratio, as well as means for selectively extracting working fluid from the first extraction point 75 and the second extraction point 76 based on which of the upstream combustor 22 and the downstream combustor 24 operates at the preferred stoichiometric ratio.

In certain embodiments, the first extraction point 75 may include a first controllable extracted gas valve 61 for controlling the amount of gas extracted at that location. The first extraction point 75 may be disposed on the recirculation loop 10 between the upstream combustor 22 and, proceeding in a downstream direction, the downstream combustor 24. As illustrated in FIGS. 8 and 9, one exemplary location for the first extraction point 75 is the aft end of the high-pressure turbine 30. The first controllable extracted gas valve 61 may be controllable to at least two settings: a closed setting that prevents the extraction of working fluid and an open setting that allows the extraction of working fluid. Similarly, the second extraction point 76 may include a second controllable extracted gas valve 61 for controlling the amount of gas extracted at that location. The second extraction point 76 may be disposed on the recirculation loop 10 between the downstream combustor 24 and, proceeding in a downstream direction, the upstream combustor 22. As illustrated in FIG. 8, one exemplary location for the second extraction point 76 is the aft end of the low-pressure turbine 32. As illustrated in FIG. 9, another exemplary location for the second extraction point 76 is on the recirculation conduit 40 between the cooler 44 and the blower 46. Depending on the required properties of the extracted gas, other locations are possible. The second controllable extracted gas valve 61 may be controllable to at least two settings: a closed setting that prevents the extraction of working fluid and an open setting that allows the extraction of working fluid.

In certain embodiments, the systems and components for controlling the compressed oxidant amount supplied to the upstream combustor 22 may include an oxidant compressor 11, a first oxidant conduit 52 that is configured to direct compressed oxidant derived from the oxidant compressor 11 to the upstream combustor 22, and a first controllable oxidant valve 54 disposed on the first oxidant conduit 52 that is controllable to at least three settings: a closed setting that prevents delivery of the compressed oxidant to the upstream combustor 22 and two open settings that allow delivery of differing compressed oxidant amounts to the upstream combustor 22. In certain embodiments, the systems and components for controlling the compressed oxidant amount supplied to the downstream combustor 24 may include the oxidant compressor 11, a second oxidant conduit 67 that is configured to direct compressed oxidant derived from the oxidant compressor 11 to the downstream combustor 24, and a second controllable oxidant valve 68 disposed on the second oxidant conduit 67 that is controllable to at least three settings: a closed setting that prevents delivery of the compressed oxidant to the downstream combustor 24 and two open settings that allow delivery of differing compressed oxidant amounts to the downstream combustor 24. In certain embodiments, a booster compressor 16 may be included that is disposed on at least one of the first oxidant conduit 52 and the second oxidant conduit 67 (an example of which is shown in FIG. 6). The booster compressor 16 may be configured to boost the pressure of the compressed oxidant flowing through at least one of the first 52 and the second oxidant conduit 67 such that the compressed oxidant amount supplied to at least one of the upstream 22 and the downstream combustor 24 comprises a pressure level that corresponds to a preferable injection pressure of whichever of the upstream 22 and downstream combustor 24. In certain embodiments, at an upstream end, the first oxidant conduit 52 may include a first oxidant extraction location 81 at which the compressed oxidant is extracted from the oxidant compressor 11. At an upstream end, the second oxidant conduit 67 may include a second oxidant extraction location 83 at which the compressed oxidant is extracted from the oxidant compressor 11. Within the oxidant compressor 11, the first oxidant extraction location 81 may include a downstream position relative to the second oxidant extraction location 83. The first oxidant extraction location 81 may include a predetermined position within the oxidant compressor 11 that corresponds to a preferable injection pressure at the upstream combustor 22. The second extraction location 83 may include a predetermined position within the oxidant compressor 11 that corresponds to a preferable injection pressure at the downstream combustor 24.

In certain embodiments, the systems and components for controlling the fuel amount supplied to the upstream combustor 22 may include an upstream combustor fuel supply 78 that may include a controllable upstream combustor fuel valve or first controllable fuel valve 58. The first controllable fuel valve 58 may be controllable to at least three settings: a closed setting that prevents delivery of fuel to the upstream combustor 22 and two open settings that allow delivery of differing fuel amounts to the upstream combustor 22. The systems and components for controlling the fuel amount supplied to the downstream combustor 24 may include a downstream combustor fuel supply 79 that may include a controllable downstream combustor fuel valve or second controllable fuel valve 59. The second controllable fuel valve 59 may be controllable to at least three settings: a closed setting that prevents delivery of fuel to the downstream combustor 24 and two open settings that allow delivery of differing fuel amounts to the downstream combustor 24. In certain embodiments, as shown in FIG. 8, the upstream combustor fuel supply 78 and the downstream combustor fuel supply 79 may have a common source and, thus, a common fuel type. In other embodiments, as shown in FIG. 9, the upstream combustor fuel supply 78 and the downstream combustor fuel supply 79 may have difference sources and may supply differing fuel types.

As describe above in more detail, the power plant 9 of FIGS. 8 and 9 may include systems and components for controlling the power plant 9 such that each of the upstream combustor 22 and the downstream combustor 24 periodically operate at the preferred stoichiometric ratio. In certain embodiments includes a computerized control unit 65 that is configured to control the settings of the first and second controllable oxidant valves 54 and the first and second controllable fuel valves 58, 59.

As described in more detail above, in certain embodiments, the power plant 9 of FIGS. 8 and 9 may include systems and components for determining a current stoichiometric ratio at which the upstream combustor 22 and the downstream combustor 24 operate. In certain exemplary embodiments, the systems and components for determining the current stoichiometric ratio at which the upstream combustor 22 and the downstream combustor 24 operate include: systems and components for measuring the compressed oxidant amount being supplied to the upstream and downstream combustors 22, 24 and systems and components for measuring the fuel amount being supplied to the upstream and downstream combustors 22, 24; and systems and components for calculating the current stoichiometric ratio at which each of the upstream combustor 22 and the downstream combustor 24 operates based on the measured compressed oxidant amounts and the measured fuel amount being supplied to each. In certain exemplary embodiments, the systems and components for determining the stoichiometric ratio at which the upstream combustor 22 and the downstream combustor 24 operate include: a first testing component for testing the working fluid exhausted from the upstream combustor 22; and a second testing component for testing the working fluid exhausted from the downstream combustor 24. The first testing component and the second testing component each may include one of a sensor for detecting excess oxidant and a sensor for detecting unspent fuel. One or more CO sensors and one or more humidity sensors may also be used, as one of ordinary skill in the art will appreciate. The first testing location may include a location within a range of positions on the recirculation loop 10. The range of positions may be defined between the first extraction point 75 and, proceeding in an upstream direction, the upstream combustor 22. The second testing location may include a location within a range of positions on the recirculation loop 10. The range of positions may be defined between the second extraction point 76 and, proceeding in an upstream direction, the downstream combustor 24.

In certain embodiments, the systems and components for selectively extracting from the first extraction point 75 and the second extraction point 76 based on which of the upstream combustor 22 and the downstream combustor 24 is being operated at the preferred stoichiometric ratio includes a computerized control unit 65. In one preferred embodiment, the control unit 65 is configured to: extract working fluid from the first extraction point 75 during periods when the upstream combustor 22 operates at the preferred stoichiometric ratio; and extract working fluid from the second extraction point 76 during periods when the downstream combustor 24 operates at the preferred stoichiometric ratio.

As provided herein, the power plant of FIGS. 8 and 9 may be operated per novel control methods. In certain embodiments, such methods may include the steps of: recirculating at least a portion of the working fluid through the recirculation loop 10; controlling a compressed oxidant amount supplied to each of the upstream combustor 22 and the downstream combustor 24; controlling a fuel amount supplied to each of the upstream combustor 22 and the downstream combustor 24; controlling the power plant 9 such that each of the upstream combustor 22 and the downstream combustor 24 periodically operates at a preferred stoichiometric ratio; and selectively extracting the working fluid from a first extraction point 75 associated with the upstream combustor 22 and a second extraction point 76 associated with the downstream combustor 24 based upon which of the upstream 22 and the downstream combustor 24 operates at the preferred stoichiometric ratio. The step of selectively extracting the working fluid from the first 75 and the second extraction points 76 may include selecting to extract from the first extraction point 75 only during periods when the upstream combustor 22 operates at the preferred stoichiometric ratio, and selecting to extract working fluid from the second extraction point 76 only during periods when the downstream combustor 24 operates at the preferred stoichiometric ratio. In one preferred embodiment, for example, the upstream combustor 22 may be operated at the preferred stoichiometric ratio during low-load operation, and the downstream combustor 24 may be operated at the preferred stoichiometric ration during full operation. The step of selectively extracting working fluid from the first 75 and second extraction points 76 may include controlling the settings of the first 61 and second controllable extracted gas valves 61. The step of controlling the compressed oxidant amount supplied to each of the upstream and downstream combustors 22, 24 may include manipulating the settings of the first and second controllable oxidant valves 54, 68. The step of controlling the fuel amounts supplied to each of the upstream and downstream combustors 22, 24 may include the steps of manipulating the settings of the first and second controllable fuel valves 58, 59.

The step of controlling the power plant 9 such that each of the upstream combustor 22 and the downstream combustor 24 periodically operate at the preferred stoichiometric ratio may include using a computerized control unit 65 that is configured to control the settings of the first and second controllable oxidant valves 54 and the first 58 and second controllable fuel values 59. The preferred stoichiometric ratio may include a stoichiometric ratio of about 1, though the other ranges discussed herein are also possible.

In certain embodiments, the method may include the steps of: measuring a plurality of process variables of the power plant 9; determining an output requirement for the power plant 9; based on the measured process variables and the output requirement, determining a desired mode of operation for the power plant 9; determining a preferred stoichiometric combustor, the preferred stoichiometric combustor including whichever of the upstream combustor 22 and the downstream combustor 24 is preferred for operation at the preferred stoichiometric ratio given the desired mode of operation for the power plant 9 and a chosen criteria; and controlling the power plant 9 such that the preferred stoichiometric combustor operates at the preferred stoichiometric ratio. It will be appreciated that power plants configured as with dual combustion systems may choose to shut-down one of the combustion systems during a turndown mode of operation, thereby more efficiently satisfying a lower output requirement. Accordingly, in certain embodiments, the desired mode of operation includes a turndown mode of operation during which only one of the upstream combustor 22 and the downstream combustor 24 operates. In this case, the preferred stoichiometric combustor may include whichever of the upstream combustor 22 and the downstream combustor 24 operates during the turndown mode of operation. In certain embodiments, the upstream combustor 22 is the combustor that operates during the turndown mode of operation.

The chosen criteria for determining the preferred stoichiometric combustor may be any of several. In certain preferred embodiments, the chosen criteria relates to the efficiency level of the power plant 9. In this manner, the preferred stoichiometric combustor is the combustor that, when operated at the preferred stoichiometric ratio, promotes efficiency. The chosen criteria also may be related to economic considerations, i.e., the preferred stoichiometric combustor is the one that promotes the profits of the power plant 9.

In certain embodiments, the method of the present application may further include the steps of: determining a current stoichiometric ratio at which the preferred stoichiometric combustor operates; determining whether the current stoichiometric ratio is equal to the preferred stoichiometric ratio; and extracting working fluid from the extraction point associated with the preferred stoichiometric combustor if the current stoichiometric ratio is determined to be equal to the preferred stoichiometric ratio. In certain embodiments, this may include the steps of: measuring the compressed oxidant amount being supplied to the upstream and downstream combustors 22, 24; measuring the fuel amount being supplied to the upstream and downstream combustors 22, 24; and calculating the current stoichiometric ratio at which the preferred stoichiometric combustor operates based on the measured compressed oxidant amount being supplied to the upstream and downstream combustors 22, 24 and the measured fuel amounts being supplied to the upstream and downstream combustors 22, 24. In certain embodiments, the step of determining the current stoichiometric ratio at which the preferred stoichiometric combustor operates includes the steps of: if the upstream combustor 22 may include the preferred stoichiometric combustor, testing the working fluid exhausted from the upstream combustor 22; and if the downstream combustor 24 may include the preferred stoichiometric combustor, testing the working fluid exhausted from the downstream combustor 24. The working fluid exhausted from the upstream combustor 22 may be tested at a first test location by one of a sensor for detecting excess oxidant and a sensor for detecting unspent fuel. The first test location may include a location within a range of locations on the recirculation loop defined between the first extraction point 75 and, proceeding in an upstream direction, the upstream combustor 22. The working fluid exhausted from the downstream combustor 24 may be tested at a second test location by one of a sensor for detecting excess oxidant and a sensor for detecting unspent fuel. The second test location may include a location within a range of locations on the recirculation loop defined between the second extraction point 76 and, proceeding in an upstream direction, the downstream combustor 24. In this manner, the status of the exhaust prior to extraction may be tested to confirm desired properties.

In certain embodiments, the step of controlling the power plant 9 such that the preferred stoichiometric combustor operates at the preferred stoichiometric ratio includes the step of operating a feedback loop control mechanism that includes manipulating a control input of the power plant 9 based on the measured plurality of the process variables. The methods of operating a feedback loop control mechanism are discussed in more detail above. In certain cases, it will be appreciated that the step of measuring the plurality of process variables may include measuring the compressed oxidant amount and the fuel amount supplied to the preferred stoichiometric combustor and calculating a current stoichiometric ratio in the preferred stoichiometric combustor based on the measured compressed oxidant amount and fuel amount supplied to the preferred stoichiometric combustor. In certain embodiments, the control input may include the settings for whichever of the first and second controllable oxidant valves 54, 68 correspond to the preferred stoichiometric combustor and whichever of the first and second controllable fuel valves 58, 59 correspond to the preferred stoichiometric combustor.

In certain embodiments, the step of measuring the plurality of process variables may include measuring the compressed oxidant amounts and the compressed fuel amounts being supplied to each of the upstream and downstream combustors 22, 24. The step of calculating the current stoichiometric ratio in the preferred stoichiometric combustor may include balancing, in each of the upstream and downstream combustors 22, 24, the measured oxygen amount against the measured fuel amount to determine whether the preferred stoichiometric combustor ingests an excess fuel amount or an excess oxidant amount that is present in the working fluid from whichever of the upstream and downstream combustors 22, 24 is not the preferred stoichiometric combustor.

In certain embodiments, the step of measuring the plurality of process variables may include testing a working fluid content at a position on the recirculation loop that is both downstream of the preferred stoichiometric combustor and upstream of whichever of the upstream and downstream combustors 22, 24 is not the preferred stoichiometric combustor. The control input may include at least one of the fuel amount supplied to the upstream combustor 22, the fuel amount supplied to the downstream combustor 24, the compressed oxidant amount supplied to the upstream combustor 22, and the compressed oxidant amount supplied to the downstream combustor 24. The step of testing the working fluid content may include measuring at least one of an oxidant content and an unspent fuel content of the working fluid, which may further include the step of calculating a current stoichiometric ratio in the preferred stoichiometric combustor based on the testing of the working fluid content.

In certain exemplary embodiments, the method of the present application includes controlling the power plant 9 such that both of the upstream combustor 22 and the downstream combustor 24 periodically operate at the preferred stoichiometric ratio during the same period of time. In this case, selectively extracting the working fluid from the first extraction point 75 and the second extraction point 76 may include extracting working fluid from both the first extraction point 75 and the second extraction point 76 when both combustors 22, 24 operate at the preferred stoichiometric ratio. As shown in FIGS. 8 and 9, the two extracted gas flows may be combined at a combining point 86. That is, the method of the present application may include the step of combining the working fluid extracted from the first extraction point 75 and the working fluid extracted from the second extraction point 76. The method may further include the step of controllably combining the two extracted flows of working fluid such that a combined flow of extracted working fluid includes a desired characteristic. It will be appreciated that this may be done by controlling the settings of the controllable extracted gas valves 61 that are included at each extraction point 75, 76. Depending on the downstream applications for which the extracted gas is extracted, it is beneficial to have the ability to provide the extracted gas at varying pressure levels or temperatures. This may be achieved by mixing the gases extracted from different points on the recirculation loop 10 in desired or controlled amounts. As shown in FIG. 9, the first extraction point 75 extracts gas from a region of relative high temperature and high pressure, while the second extraction point 76 extracts gas from a region of relatively low temperature and low pressure. It will be appreciated that by mixing the two flows in a controlled manner, desired extracted gas characteristics within the range of characteristics defined by the differing extraction location may be achieved.

Turning now to FIGS. 10-13, schematic drawings illustrating configurations of alternative power plants that employ exhaust gas recirculation and a single combustion system are provided. It will be appreciated that the power plant 9 of these figures includes many of the same components as the power plants described above and that these components may be employed in much the same manner at that described elsewhere in this application. As stated, any of the descriptions pertaining to any of the power plants that one of ordinary skill in the art would appreciate as not being limited to a specific configuration is applicable to all the configurations, particularly as such alternatives may be described in the claims or any amendments made thereto. In certain embodiments, the power plant 9 is configured to include a recirculation loop 10 about which a working fluid is recirculated. As before, the recirculation loop 10 may include a plurality of components configured to accept an outflow of working fluid from a neighboring upstream component and provide an inflow of working fluid to a neighboring downstream component. In this case, the recirculation loop 10 includes a recirculation compressor 12; a combustor 22 positioned downstream of the recirculation compressor 12; a turbine 30 positioned downstream of the combustor 22; and a recirculation conduit 40 configured to direct the outflow of working fluid from the turbine 30 to the recirculation compressor 12. The power plant 9 is configured to have a single combustion system. As such, the recirculation loop 10 may be configured to prevent the input of combustion gases at all locations except for an input related to the combustor 22. As shown, the power plant 9 may further include a first extraction point 75 and a second extraction point 76 positioned on the recirculation loop 10. The outflow of working fluid from the turbine 30 includes exhaust gases, which, via the recirculation conduit 40, are directed to the recirculation compressor 12. The recirculation compressor 12 is configured to compress the exhaust gases such that the outflow of working fluid from the recirculation compressor 12 includes compressed exhaust gases;

The first extraction point 75 may include a controllable extraction valve 61 that is controllable to at least two settings: a closed setting that prevents the extraction of working fluid and an open setting that allows the extraction of working fluid. The second extraction point 76 may include a controllable extraction valve 61 that is controllable to at least two settings: a closed setting that prevents the extraction of working fluid and an open setting that allows the extraction of working fluid.

The power plant 9 may be operated or controlled such that the combustor 22 at least periodically operates at a preferred stoichiometric ratio. The preferred stoichiometric ratios may be similar to those ratios discussed above. To achieve this type of operation, a compressed oxidant amount and a fuel amount supplied the combustor 22 may be controlled. The compressed oxidant amount may be controlled by an oxidant compressor 11, an oxidant conduit 52 that is configured to direct compressed oxidant derived from the oxidant compressor 11 to the combustor 22, and a controllable oxidant valve 54 disposed on the oxidant conduit that is controllable to at least two open settings that allow delivery of differing compressed oxidant amounts to the combustor 22. The fuel amount may be controlled by a controllable fuel valve 58 that has at least two open settings that allow delivery of differing fuel amounts to the combustor 22. It will be appreciated that the power plant 9 may be controlled such that the combustor 22 at least periodically operates at the preferred stoichiometric ratio via a computerized control unit 65 that is configured to control the settings of the controllable oxidant valve 54 and the controllable fuel valve 58, and may include systems for determining a current stoichiometric ratio at which the combustor 22 operates, the various systems for which are discussed in detail above, whether the current stoichiometric ratio is equal to the preferred stoichiometric ratio, as well as a control feedback loop mechanism that achieves the desired modes of operations. As discussed in more detail below, the computerized control unit 65 may be configured to selectively extract working fluid from at least one of the first extraction point 75 and the second extraction point 76 based on whether the current stoichiometric ratio in the combustor 22 is determined to be equal to the preferred stoichiometric ratio, as well as the intended downstream uses of the extracted working fluid.

In certain embodiments, the power plant 9 includes a recirculation conduit 40 that is configured to collect exhaust gases from the turbine 30 and direct the exhaust gases to an intake of the recirculation compressor 12. The recirculation conduit 40 may further include a heat recovery steam generator, the heat recovery steam generator including a boiler, the heat recovery steam generator being configured such that the exhaust gases from the turbine 30 includes a heat source for the boiler. The recirculation conduit 40 may include a chiller 44 and a blower 46 positioned thereon. The chiller 44 may be configured to controllably remove an amount of heat from the exhaust gases flowing through the recirculation conduit 40 such that a more desirable temperature is achieved at the intake of the recirculation compressor 12. The blower 46 may be configured to controllably circulate the exhaust gases flowing through the recirculation conduit 40 such that a more desirable pressure is achieved at the intake of the recirculation compressor 12.

The power plant 9 may include instruments, sensors, and systems for determining a property of characteristic of the working fluid at the extraction points 75, 76. These may include direct measurement of the characteristic or calculation based on other measured process variables. The characteristic may include any property of the working fluid, such as, pressure and temperature. As stated, the extracted working fluid has economic value in certain industrial and other applications. It will be appreciated that if the extracted working fluid may be efficiently delivered with desired characteristics given an intended application, such as at a desired pressure or temperature, the value of it is increased. In certain embodiments, the means for determining the characteristic of the working fluid at the first extraction point 75 and the second extraction point 76 may include a pressure sensor and/or a temperature sensor. The computerized control unit 65 may be configured to selectively extract the working fluid from only or just the first extraction point 75, just the second extraction point 76, or both the first and second extraction point 75, 76 based on the characteristic of the working fluid that is determined to be at each of the extraction points 75, 76. The computerized control unit 65 may do this via controlling the settings of the first and second controllable extraction valves 61.

The computerized control unit 65 may be configured to determine a preferred value for the characteristic of the working fluid. This may be done via determining an intended downstream application for the extracted working fluid, which could be completed via consulting an operator entered value or otherwise. The system then could determine a preferred value for the characteristic of the working fluid based on what would be a preferred value given the intended downstream application.

The extraction points 75, 76 may include various locations. While a few preferred embodiments relating to extraction point configuration are provided in FIGS. 10-13, it will be appreciated that others are possible. As shown in FIG. 10, the first extraction point 75 may have a location within the recirculation compressor 12, and the second extraction point 76 may have a location within the turbine 30. As shown in FIG. 11, the first extraction point 75 may have a location within the recirculation compressor 12, and the second extraction point 76 may have a location within the recirculation conduit 40. As shown in FIG. 12, the first extraction point 75 may have a first location within the recirculation compressor 12, and the second extraction point 76 may have a second location within the recirculation compressor 12. As shown in FIG. 13, the first extraction point 75 may have a first location within the turbine 30, and the second extraction point 76 may have a second location within the turbine 30. The advantages of these configurations are discussed in more detail below.

The present application further describes a method of controlling a power plant that includes configurations discussed above in relation to FIGS. 10-13. In general, these methods may include the steps of: recirculating at least a portion of the working fluid through the recirculation loop; controlling the power plant such that the combustor 22 at least periodically operates at a preferred stoichiometric ratio; and extracting working fluid from at least one of a first extraction point 75 and a second extraction point 76 positioned on the recirculation loop 10 during the periods when the combustor 22 operates at the preferred stoichiometric ratio. The step of controlling the power plant such that the combustor 22 periodically operates at the preferred stoichiometric ratio may include the steps of controlling a compressed oxidant amount and a fuel amount supplied to the combustor 22.

The method may further include the steps of: determining a characteristic of the working fluid at the first extraction point 75; determining a characteristic of the working fluid at the second extraction point 76; and, based on the characteristic of the working fluid at the first and second extraction points 75,76 selectively extracting the working fluid from just the first extraction point 75, just the second extraction point 76, or both the first and second extraction points 75, 76. Based on a downstream application, the method may determine a preferred value for the characteristic of the working fluid, which may also be used to selectively extract working fluid from the extraction points 75, 76. This type of method of operation may result in working fluid being extracted from both the first extraction point 75 and the second extraction point 76 at the same time. In this instance, the method may controllably mix the extracted flows of working fluid from both extraction points 75, 76 so as to create a combined flow of extracted working fluid that has a characteristic consistent with the preferred value for the characteristic. As before, the preferred value for the characteristic of the working fluid may be based on an intended downstream application. A computerized control unit 65 may be configured to control the settings of the various valves and other components discussed herein so that the desired modes of operation are achieved.

In certain embodiments, the step of selectively extracting the working fluid from just the first extraction point 75, just the second extraction point 76, or both the first and second extraction points 75, 76 includes the steps of: when the characteristic of the working fluid at the first extraction point 75 is within a predetermined range relative to the preferred value for the characteristic, extracting from just the first extraction point 75; when the characteristic of the working fluid at the second extraction point 76 is within a predetermined range relative to the preferred value for the characteristic, extracting from just the second extraction point 76; when the preferred value for the characteristic is within a predetermined range nested between the characteristic of the working fluid at the first extraction point 75 and the characteristic of the working fluid at the second extraction point 76, and extracting from both the first and second extraction points 75, 76. In this manner, the method may employ just one extraction point when the desired characteristic may be achieved this way, or extract from both extraction points when mixing may be employed to deliver the extracted gases in a more desirable state given a downstream application. In certain embodiments, these steps may include the following: when the characteristic of the working fluid at the first extraction point 75 is approximately equal to the preferred value for the characteristic, extracting from the first extraction point 75; when the characteristic of the working fluid at the second extraction point 76 is approximately equal to the preferred value for the characteristic, extracting from the second extraction point 76; and when the preferred value for the characteristic falls in between the characteristic of the working fluid at the first extraction point 75 and the characteristic of the working fluid at the second extraction point 76, extracting from both the first and second extraction points 75, 76. When the method operates to extract working fluid from both extraction points 75, 76, a mixing step, as mentioned, may be employed to create a combined flow that is more desirable. In certain embodiments, this may be achieved by controlling the setting of the first controllable extraction valve 61 such that a first predetermined amount of working fluid is extracted from the first extraction point 75; controlling the setting of the second controllable extraction valve 61 such that a second predetermined amount of working fluid is extracted from the second extraction point 76; and combining the first predetermined amount of working fluid with the second predetermined amount of working fluid at a combining junction such that the combined flow of extracted working fluid is formed. It will be appreciated that, given the characteristic of the working fluid at the first extraction point 75 and the second extraction point 76, the first predetermined amount of working fluid extracted from the first extraction point 75 and the second predetermined amount of working fluid extracted from the second extraction point 76 may include predetermined amounts of working fluid that, once mixed, result in the combined flow of extracted working fluid having the preferred value for the characteristic. As stated, the characteristic may be one of pressure and temperature, though others are possible.

The extraction point locations may be predetermined to provide desired operation, efficiency, and flexibility in delivering extracted flows having desired characteristics. Generally, the first extraction point 75 may have a predetermined first location within the recirculation loop 10 and the second extraction point 76 may have a predetermined second location within the recirculation loop 10. In one preferred embodiments, the first predetermined location within the recirculation loop 10 and the second predetermined location within the recirculation loop 10 are selected such that the working fluid at each include a dissimilar first characteristic and a similar second characteristic. In this case, the working fluid extracted from the first extraction point 75 and the second extraction point 76 may be mixed to achieve a wide range of levels for the first characteristic, while the mixing has little effect on the resulting second characteristic, which will remain at about the level of the similar second characteristics of the extracted flows. In other cases, the first predetermined location within the recirculation loop 10 and the second predetermined location within the recirculation loop 10 may be selected such that the working fluid at each includes a dissimilar first characteristic and a dissimilar second characteristic. This time, the working fluid extracted from the first extraction point 75 and the second extraction point 76 may be mixed to achieve a wide range of first characteristic values and a wide range of second characteristic values.

Referring to FIG. 10, it will be appreciated that the position within the recirculation compressor 12 for the first extraction point 75 and the location within the turbine 30 for the second extraction point 76 may be selected such that the dissimilar first characteristic is pressure and the similar second characteristic is temperature. Referring to FIG. 11, it will be appreciated that the position within the recirculation compressor 12 for the first extraction point 75 and the location within the recirculation conduit 40 for the second extraction point 76 may be selected such that the dissimilar first characteristic is pressure and the similar second characteristic is temperature. The location for the second extraction point 76 may be varied to produce other results, such as producing a dissimilar temperature characteristic. Another possible configuration includes positioning first extraction point 75 in the turbine 30 and the second extraction point 76 in the recirculation conduit 40 so that dissimilar pressure and dissimilar temperature characteristics at the two extraction locations are achieved. It will be appreciated that this type of arrangement may provide great flexibility in the mixing of extracted flows to achieve a broad range of values for each of the pressure and temperatures characteristics.

In another embodiment, as illustrated in FIG. 12, the first extraction point 75 may have a first predetermined location within the recirculation compressor 12, which may be selected to provide a desired pressure or temperature level for the extracted working fluid during an anticipated first mode of operation for the power plant 9. The second extraction point 76 may have a second predetermined location within the recirculation compressor 12, which may be selected to provide the desired pressure or temperature level for extracted working fluid during an anticipated second mode of operation for the power plant 9. It will be appreciated that this configuration provides the flexibility of extracting working fluid at a consistent pressure or temperature level, i.e., the desired pressure or temperature level, no matter if the power plant 9 is operating in the first or second mode of operation. In a preferred embodiment, the modes coincide with a base load mode of operation and a turndown mode of operation. It will be appreciated that this configuration further provides the advantageous alternative of extracting at different pressure or temperature levels during those times when the operation mode of the power plant 9 remains unchanged.

In another embodiment, as illustrated in FIG. 13, the first extraction point 75 may have a first predetermined location within the turbine 30, which may be selected to provide a desired pressure or temperature level for extracted working fluid during an anticipated first mode of operation for the power plant 9. The second extraction point 76 may have a second predetermined location within the turbine 30, which may be selected to provide the desired pressure or temperature level for extracted working fluid during an anticipated second mode of operation for the power plant 9. In this case, it will be appreciated that the configuration provides the flexibility of extracting working fluid at a consistent pressure or temperature level, i.e., the desired pressure or temperature level, no matter if the power plant 9 is operating in the first or second mode of operation. In a preferred embodiment, the modes coincide with a base load mode of operation and a turndown mode of operation. It will be appreciated that this configuration further provides the advantageous alternative of extracting at different pressure or temperature levels during those times when the operation mode of the power plant 9 remains unchanged.

From the above description of preferred embodiments of the invention, those skilled in the art will perceive improvements, changes and modifications. Such improvements, changes and modifications within the skill of the art are intended to be covered by the appended claims. Further, it should be apparent that the foregoing relates only to the described embodiments of the present application and that numerous changes and modifications may be made herein without departing from the spirit and scope of the application as defined by the following claims and the equivalents thereof.

Claims

1. A method of controlling a power plant that comprises a working fluid and a recirculation loop, wherein the power plant includes a combustor operably connected to a turbine, and wherein the recirculation loop comprises a recirculation compressor, the combustor positioned downstream of the recirculation compressor, the turbine positioned downstream of the combustor, and a recirculation conduit configured to direct an outflow of the working fluid from the turbine to the recirculation compressor, the method including the steps of: recirculating at least a portion of the working fluid through the recirculation loop;controlling the power plant such that the combustor at least periodically operates at a preferred stoichiometric ratio by controlling an amount of a compressed oxidant supplied to the combustor at an oxidant input and an amount of a fuel supplied to the combustor at a fuel input, wherein the recirculation loop is configured to prevent the input of the compressed oxidant and the fuel to all locations except for the oxidant input and the fuel input, respectively, occurring in the combustor;extracting the working fluid from a first extraction point and a second extraction point positioned on the recirculation loop during periods when the combustor operates at the preferred stoichiometric ratio;determining a characteristic of the working fluid at the first extraction point;determining the characteristic of the working fluid at the second extraction point; andbased on the characteristic of the working fluid at the first extraction point and the characteristic of the working fluid at the second extraction point, extracting the working fluid from both the first extraction point and the second extraction point;determining a preferred value for the characteristic of the working fluid based on an intended downstream application; andcontrollably mixing the working fluid extracted from the first extraction point and the working fluid extracted from the second extraction point such that a combined flow of extracted working fluid comprises the preferred value for the characteristic of the working fluid.
2. The method according to claim 1, wherein: the first extraction point comprises a first controllable extraction valve, wherein the first controllable extraction valve is controllable to at least three settings: a closed setting that prevents extraction of the working fluid at the first extraction point and two open settings that allow for the extraction of differing levels of the working fluid at the first extraction point;the second extraction point comprises a second controllable extraction valve, wherein the second controllable extraction valve is controllable to at least three settings: a closed setting that prevents extraction of the working fluid at the second extraction point and two open settings that allow for the extraction of differing levels of the working fluid at the second extraction point; andwherein extracting the working fluid from the first extraction point and the second extraction point comprises controlling the settings of the first and second controllable extraction valves, respectively.
3. The method according to claim 2, wherein: the step of controlling the amount of the compressed oxidant supplied to the combustor includes: compressing oxidant in an oxidant compressor to generate the compressed oxidant; directing the compressed oxidant derived from the oxidant compressor through an oxidant conduit that includes a controllable oxidant valve that is controllable to at least two open settings that allow controlled delivery of the amount of the compressed oxidant to the combustor; and manipulating the at least two open settings of the controllable oxidant valve to vary the amount of the compressed oxidant delivered to the combustor; andthe step of controlling the amount of the fuel amount supplied to the combustor includes: directing the fuel derived from a fuel supply through a controllable fuel valve to the combustor, wherein the controllable fuel valve is controllable to at least two open settings that allow controlled delivery of the amount of the fuel to the combustor; andmanipulating the at least two open settings of the controllable fuel valve to vary the amount of the fuel delivered to the combustor.
4. The method according to claim 3, wherein: the outflow of the working fluid from the turbine comprises exhaust gases, which, via the recirculation conduit, are directed to the recirculation compressor;the recirculation compressor is configured to compress the exhaust gases such that the outflow of the working fluid from the recirculation compressor comprises compressed exhaust gases;the step of controlling the power plant such that the combustor at least periodically operates at the preferred stoichiometric ratio includes using a computerized control unit that is configured to control the settings of the controllable oxidant valve and the controllable fuel value; andthe preferred stoichiometric ratio comprises a stoichiometric ratio of about 1.
5. The method according to claim 1, wherein the preferred stoichiometric ratio comprises a range of stoichiometric ratios between 0.75 and 1.25.
6. The method according to claim 1, wherein the preferred stoichiometric ratio comprises a range of stoichiometric ratios between 0.9 and 1.1.
7. The method according to claim 2, wherein the step of controllably mixing the working fluid extracted from the first extraction point and the second extraction point includes the steps of: controlling the setting of the first controllable extraction valve such that a first predetermined amount of the working fluid is extracted from the first extraction point;controlling the setting of the second controllable extraction valve such that a second predetermined amount of the working fluid is extracted from the second extraction point; andcombining the first predetermined amount of the working fluid with the second predetermined amount of the working fluid at a combining junction such that a combined flow of the working fluid extracted from the first extraction point and from the second extraction point is formed;wherein, given the characteristic of the working fluid at the first extraction point and the the characteristic of the working fluid at the second extraction point, the first predetermined amount of the working fluid extracted from the first extraction point and the second predetermined amount of the working fluid extracted from the second extraction point comprise amounts of the working fluid that, once mixed, result in the combined flow of the working fluid having the preferred value for the characteristic.
8. The method according to claim 1, further comprising the step of determining the intended downstream application for the working fluid extracted from the first extraction point and from the second extraction point; wherein the preferred value for the characteristic of the working fluid is based on a predetermined preferred value given the intended downstream application.
9. The method according to claim 8, wherein extracting the working fluid from the first extraction point and the second extraction point comprises the steps of: when the preferred value for the characteristic is within a predetermined range nested between the characteristic of the working fluid at the first extraction point and the characteristic of the working fluid at the second extraction point, extracting the working fluid from the first extraction point and the second extraction point.
10. The method according to claim 1, wherein the characteristic of the working fluid comprises pressure or temperature.
11. The method according to claim 1, wherein: the first extraction point comprises a predetermined first location within the recirculation loop, wherein the predetermined first location is at the recirculation compressor, at the turbine, or downstream of the turbine and upstream of the recirculation compressor; andthe second extraction point comprises a predetermined second location within the recirculation loop, wherein the predetermined second location is at the recirculation compressor, at the turbine, or downstream of the turbine and upstream of the recirculation compressor.
12. The method according to claim 11, wherein: the predetermined first location is within the recirculation compressor; andthe predetermined second location is within the turbine.
13. The method according to claim 11, wherein: the predetermined first location is within the recirculation compressor; andthe predetermined second location is within the recirculation conduit.
14. The method according to claim 11, wherein: the predetermined first location is within the turbine; andthe predetermined second location is within the recirculation conduit.
15. The method according to claim 1, wherein: the first extraction point comprises a first location within the recirculation compressor, the first location being selected because the first location coincides with a desired pressure or temperature level for the working fluid at the first location during a first mode of operation for the power plant; andthe second extraction point comprises a second location within the recirculation compressor, the second location being selected because the second location coincides with the desired pressure or temperature level for the working fluid at the second location during a second mode of operation for the power plant;and wherein the method further comprises the step of extracting the working fluid from the first extraction point at the first location when the power plant operates in the first mode of operation, and extracting the working fluid from the second extraction point at the second location when the power plant operates in a second mode of operation.
16. The method according to claim 15, wherein the first mode of operation comprises a base load mode of operation and the second mode of operation comprises a turndown mode of operation.
17. The method according to claim 1, wherein: the first extraction point comprises a first location within the turbine, the first location being selected because the first location coincides with a desired pressure or temperature level for the working fluid during a first mode of operation for the power plant; andthe second extraction point comprises a second location within the turbine, the second location being selected because the second location coincides with the desired pressure or temperature level for the working fluid during a second mode of operation for the power plant;further comprising the step of extracting the working fluid from the first extraction point when the power plant operates in the first mode of operation, and extracting the working fluid from the second extraction point when the power plant operates in a second mode of operation.
18. The method according to claim 17, wherein the first mode of operation comprises a base load mode of operation and the second mode of operation comprises a turndown mode of operation.
19. The method according to claim 1, further comprising the steps of: dumping the working fluid extracted at the first extraction point, the second extraction point, or both to atmosphere.
20. A power plant comprising: a recirculation loop about which a working fluid is recirculated, the recirculation loop comprising a plurality of components configured to accept an outflow of the working fluid from a neighboring upstream component and provide an inflow of the working fluid to a neighboring downstream component, wherein the recirculation loop includes: a recirculation compressor; a combustor positioned downstream of the recirculation compressor; a turbine positioned downstream of the combustor; and a recirculation conduit configured to direct the outflow of the working fluid from the turbine as the inflow of the working fluid to the recirculation compressor;a first extraction means for extracting the working fluid from a first extraction point on the recirculation loop, wherein the first extraction point is located in the recirculation compressor, in the turbine, or in the recirculation conduit;a second extraction means for extracting the working fluid from a second extraction point on the recirculation loop, wherein the second extraction point is located in the recirculation compressor, in the turbine, or in the recirculation conduit;means for controlling the power plant such that the combustor operates at least in periods at a preferred stoichiometric ratio; andwherein the means for controlling the power plant comprises a computerized control unit configured to control extraction of the working fluid from the first extraction point, by the first extraction means, and from the second extraction point, by the second extraction means, during periods when the combustor operates at the preferred stoichiometric ratio, wherein the computerized control unit is configured to control mixing of the working fluid extracted from the first extraction point and the working fluid extracted from the second extraction point to generate a combined working fluid having a preferred value for a characteristic of the combined working fluid based on an intended downstream application.
21. The power plant according to claim 20, wherein: the means for controlling the power plant such that the combustor operates at least in the periods at the preferred stoichiometric ratio comprises means for controlling an amount of a compressed oxidant supplied to the combustor and means for controlling an amount of a fuel supplied to the combustor;the first extraction means for extracting the working fluid comprises a first controllable extraction valve at the first extraction point, and wherein the first controllable extraction valve is controllable to at least two settings: a closed setting that prevents extraction of the working fluid and an open setting that allows the extraction of the working fluid; andthe second extraction means for extracting the working fluid comprises a second controllable extraction valve at the second extraction point, and wherein the second controllable is controllable to at least two settings: a closed setting that prevents extraction of the working fluid and an open setting that allows the extraction of the working fluid.
22. The power plant according to claim 21, wherein: the means for controlling the amount of the compressed oxidant supplied to the combustor includes an oxidant compressor, an oxidant conduit that is configured to direct the compressed oxidant derived from the oxidant compressor to the combustor, and a controllable oxidant valve disposed on the oxidant conduit that is controllable to at least two open settings that allow delivery of the amount of the compressed oxidant to the combustor and manipulating the at least two open settings of the controllable oxidant valve to vary the amount of the compressed oxidant delivered to the combustor; andthe means for controlling the amount of the fuel supplied to the combustor comprises a combustor fuel supply that includes a controllable fuel valve, the controllable fuel valve being controllable to at least two open settings that allow delivery of the amount of the fuel to the combustor; and manipulating the at least two open settings of the controllable fuel valve to vary the amount of the fuel delivered to the combustor.
23. The power plant according to claim 22, wherein: the outflow of the working fluid from the turbine comprises exhaust gases, which, via the recirculation conduit, are directed to the recirculation compressor;the recirculation compressor is configured to compress the exhaust gases such that the outflow of the working fluid from the recirculation compressor comprises compressed exhaust gases; and wherein the computerized control unit that is configured to control the settings of the controllable oxidant valve and the controllable fuel valve and means for determining a current stoichiometric ratio at which the combustor operates and whether the current stoichiometric ratio is equal to the preferred stoichiometric ratio.
24. The power plant according to claim 23, wherein the preferred stoichiometric ratio comprises a stoichiometric ratio of between 0.75 and 1.25.
25. The power plant according to claim 23, wherein the preferred stoichiometric ratio comprises a stoichiometric ratio of between 0.9 and 1.1.
26. The power plant according to claim 23, wherein the means for determining the current stoichiometric ratio at which the combustor operates comprises: means for measuring the amount of the compressed oxidant being supplied to the combustor and means for measuring the amount of the fuel being supplied to the combustor; andthe computerized control unit being configured to calculate the current stoichiometric ratio at which the combustor operates based on a measurement of the amount of the compressed oxidant and a measurement of the amount of the fuel being supplied to the combustor.
27. The power plant according to claim 26, wherein the means for determining the current stoichiometric ratio at which the combustor operates comprises a testing means for testing the working fluid exhausted from the combustor, the testing means comprises at least one of a sensor for detecting excess oxidant and a sensor for detecting unspent fuel; and the testing location comprises a location within a range of positions on the recirculation loop, the range of positions being defined between an inlet to the turbine, and proceeding in an downstream direction, an inlet to the combustor.
28. The power plant according to claim 23, wherein the computerized control unit is configured to selectively extract the working fluid from at least one of the first extraction point or the second extraction point based on whether the current stoichiometric ratio in the combustor is determined to be equal to the preferred stoichiometric ratio.
29. The power plant according to claim 23, wherein: the recirculation conduit is configured to collect a portion of the exhaust gases from the turbine and direct the portion of the exhaust gases to an intake of the recirculation compressor;the recirculation conduit further comprises a heat recovery steam generator, the heat recovery steam generator including a boiler, the heat recovery steam generator being configured such that the exhaust gases from the turbine comprises a heat source for the boiler;the recirculation conduit includes at least one of a chiller and a blower positioned thereon, the chiller being configured to controllably remove an amount of heat from the exhaust gases flowing through the recirculation conduit such that a more desirable temperature is achieved at the intake of the recirculation compressor, and the blower being configured to controllably circulate the exhaust gases flowing through the recirculation conduit such that a more desirable pressure is achieved at the intake of the recirculation compressor.
30. The power plant according to claim 23, further comprising: means for determining a characteristic of the working fluid at the first extraction point;means for determining the characteristic of the working fluid at the second extraction point; andwherein the computerized control unit is configured to selectively extract the working fluid from just the first extraction point, just the second extraction point, or both the first extraction point and the second extraction point based on the characteristic of the working fluid at the first extraction point and the second extraction point.
31. The power plant according to claim 30, wherein: the first extraction point comprises a location within the recirculation compressor; andthe second extraction point comprises a location within the turbine.
32. The power plant according to claim 30, wherein: the first extraction point comprises a location within the recirculation compressor; andthe second extraction point comprises a location within the recirculation conduit.
33. The power plant according to claim 30, wherein: the first extraction point comprises a location within the turbine; andthe second extraction point comprises a location within the recirculation conduit.
34. The power plant according to claim 30, wherein: the first extraction point comprises a first location within the recirculation compressor, the first location being selected to provide a desired pressure or temperature level for the working fluid during a first mode of operation for the power plant; andthe second extraction point comprises a second location within the recirculation compressor, the second location being selected to provide the desired pressure or temperature level for the working fluid during a second mode of operation for the power plant;the computerized control unit is configured to extract the working fluid from the first extraction point when the power plant operates in the first mode of operation and extract the working fluid from the second extraction point when the power plant operates in the second mode of operation.
35. The power plant according to claim 34, wherein the first mode of operation comprises a base load mode of operation and the second mode of operation comprises a turndown mode of operation.
36. The power plant according to claim 30, wherein: the first extraction point comprises a first location within the turbine, the first location being selected to provide a desired pressure or temperature level for the working fluid during a first mode of operation for the power plant; andthe second extraction point comprises a second location within the turbine, the second location being selected to provide the desired pressure or temperature level during a second mode of operation for the power plant;the computerized control unit is configured to extract the working fluid from the first extraction point when the power plant operates in the first mode of operation, and extract the working fluid from the second extraction point when the power plant operates in the second mode of operation.
37. The power plant according to claim 36, wherein the first mode of operation comprises a base load mode of operation and the second mode of operation comprises a turndown mode of operation.

US Referenced Citations (693)

Number	Name	Date	Kind
2488911	Hepburn et al.	Nov 1949	A
2884758	Oberle	May 1959	A
3631672	Gentile et al.	Jan 1972	A
3643430	Emory et al.	Feb 1972	A
3705492	Vickers	Dec 1972	A
3841382	Gravis, III et al.	Oct 1974	A
3949548	Lockwood, Jr.	Apr 1976	A
4018046	Hurley	Apr 1977	A
4043395	Every et al.	Aug 1977	A
4050239	Kappler et al.	Sep 1977	A
4066214	Johnson	Jan 1978	A
4077206	Ayyagari	Mar 1978	A
4085578	Kydd	Apr 1978	A
4092095	Straitz, III	May 1978	A
4101294	Kimura	Jul 1978	A
4112676	DeCorso	Sep 1978	A
4117671	Neal et al.	Oct 1978	A
4160640	Maev et al.	Jul 1979	A
4165609	Rudolph	Aug 1979	A
4171349	Cucuiat et al.	Oct 1979	A
4204401	Earnest	May 1980	A
4222240	Castellano	Sep 1980	A
4224991	Sowa et al.	Sep 1980	A
4236378	Vogt	Dec 1980	A
4253301	Vogt	Mar 1981	A
4271664	Earnest	Jun 1981	A
4313300	Wilkes et al.	Feb 1982	A
4344486	Parrish	Aug 1982	A
4345426	Egnell et al.	Aug 1982	A
4352269	Dineen	Oct 1982	A
4380895	Adkins	Apr 1983	A
4399652	Cole et al.	Aug 1983	A
4414334	Hitzman	Nov 1983	A
4434613	Stahl	Mar 1984	A
4435153	Hashimoto et al.	Mar 1984	A
4442665	Fick et al.	Apr 1984	A
4445842	Syska	May 1984	A
4479484	Davis	Oct 1984	A
4480985	Davis	Nov 1984	A
4488865	Davis	Dec 1984	A
4498288	Vogt	Feb 1985	A
4498289	Osgerby	Feb 1985	A
4528811	Stahl	Jul 1985	A
4543784	Kirker	Oct 1985	A
4548034	Maguire	Oct 1985	A
4561245	Ball	Dec 1985	A
4569310	Davis	Feb 1986	A
4577462	Robertson	Mar 1986	A
4602614	Percival et al.	Jul 1986	A
4606721	Livingston	Aug 1986	A
4613299	Backheim	Sep 1986	A
4637792	Davis	Jan 1987	A
4651712	Davis	Mar 1987	A
4653278	Vinson et al.	Mar 1987	A
4681678	Leaseburge et al.	Jul 1987	A
4684465	Leaseburge et al.	Aug 1987	A
4753666	Pastor et al.	Jun 1988	A
4762543	Pantermuehl et al.	Aug 1988	A
4817387	Lashbrook	Apr 1989	A
4858428	Paul	Aug 1989	A
4895710	Hartmann et al.	Jan 1990	A
4898001	Kuroda et al.	Feb 1990	A
4946597	Sury	Aug 1990	A
4976100	Lee	Dec 1990	A
5014785	Puri et al.	May 1991	A
5044932	Martin et al.	Sep 1991	A
5073105	Martin et al.	Dec 1991	A
5084438	Matsubara et al.	Jan 1992	A
5085274	Puri et al.	Feb 1992	A
5098282	Schwartz et al.	Mar 1992	A
5123248	Monty et al.	Jun 1992	A
5135387	Martin et al.	Aug 1992	A
5141049	Larsen et al.	Aug 1992	A
5142866	Yanagihara et al.	Sep 1992	A
5147111	Montgomery	Sep 1992	A
5154596	Schwartz et al.	Oct 1992	A
5183232	Gale	Feb 1993	A
5195884	Schwartz et al.	Mar 1993	A
5197289	Glevicky et al.	Mar 1993	A
5238395	Schwartz et al.	Aug 1993	A
5255506	Wilkes et al.	Oct 1993	A
5265410	Hisatome	Nov 1993	A
5271905	Owen et al.	Dec 1993	A
5275552	Schwartz et al.	Jan 1994	A
5295350	Child	Mar 1994	A
5304362	Madsen	Apr 1994	A
5325660	Taniguchi et al.	Jul 1994	A
5332036	Shirley et al.	Jul 1994	A
5344307	Schwartz et al.	Sep 1994	A
5345756	Jahnke et al.	Sep 1994	A
5355668	Weil	Oct 1994	A
5359847	Pillsbury et al.	Nov 1994	A
5361586	McWhirter et al.	Nov 1994	A
5388395	Scharpf et al.	Feb 1995	A
5394688	Amos	Mar 1995	A
5402847	Wilson et al.	Apr 1995	A
5444971	Holenberger	Aug 1995	A
5457951	Johnson	Oct 1995	A
5458481	Surbey et al.	Oct 1995	A
5468270	Borszynski	Nov 1995	A
5490378	Berger et al.	Feb 1996	A
5542840	Surbey et al.	Aug 1996	A
5566756	Chaback et al.	Oct 1996	A
5572862	Mowill	Nov 1996	A
5581998	Craig	Dec 1996	A
5584182	Althaus et al.	Dec 1996	A
5590518	Janes	Jan 1997	A
5628182	Mowill	May 1997	A
5634329	Andersson et al.	Jun 1997	A
5638675	Zysman et al.	Jun 1997	A
5640840	Briesch	Jun 1997	A
5657631	Androsov	Aug 1997	A
5680764	Viteri	Oct 1997	A
5685158	Lenahan et al.	Nov 1997	A
5709077	Beichel	Jan 1998	A
5713206	McWhirter et al.	Feb 1998	A
5715673	Beichel	Feb 1998	A
5724805	Golomb et al.	Mar 1998	A
5725054	Shayegi et al.	Mar 1998	A
5740786	Gartner	Apr 1998	A
5743079	Walsh et al.	Apr 1998	A
5765363	Mowill	Jun 1998	A
5771867	Amstutz et al.	Jun 1998	A
5771868	Khair	Jun 1998	A
5794431	Utamura et al.	Aug 1998	A
5819540	Massarani	Oct 1998	A
5832712	Ronning et al.	Nov 1998	A
5836164	Tsukahara et al.	Nov 1998	A
5839283	Dobbeling	Nov 1998	A
5850732	Willis et al.	Dec 1998	A
5894720	Willis et al.	Apr 1999	A
5901547	Smith et al.	May 1999	A
5924275	Cohen et al.	Jul 1999	A
5930990	Zachary et al.	Aug 1999	A
5937634	Etheridge et al.	Aug 1999	A
5950417	Robertson, Jr. et al.	Sep 1999	A
5956937	Beichel	Sep 1999	A
5968349	Duyvesteyn et al.	Oct 1999	A
5974780	Santos	Nov 1999	A
5992388	Seger	Nov 1999	A
6016658	Willis et al.	Jan 2000	A
6032465	Regnier	Mar 2000	A
6035641	Lokhandwala	Mar 2000	A
6062026	Woollenweber et al.	May 2000	A
6079974	Thompson	Jun 2000	A
6082093	Greenwood et al.	Jul 2000	A
6089855	Becker et al.	Jul 2000	A
6094916	Puri et al.	Aug 2000	A
6101983	Anand et al.	Aug 2000	A
6148602	Demetri	Nov 2000	A
6170264	Viteri et al.	Jan 2001	B1
6173562	Utamura et al.	Jan 2001	B1
6183241	Bohn et al.	Feb 2001	B1
6201029	Waycuilis	Mar 2001	B1
6202400	Utamura et al.	Mar 2001	B1
6202442	Brugerolle	Mar 2001	B1
6202574	Liljedahl et al.	Mar 2001	B1
6209325	Alkabie	Apr 2001	B1
6216459	Daudel et al.	Apr 2001	B1
6216549	Davis et al.	Apr 2001	B1
6230103	DeCorso et al.	May 2001	B1
6237339	Åsen et al.	May 2001	B1
6247315	Marin et al.	Jun 2001	B1
6247316	Viteri	Jun 2001	B1
6248794	Gieskes	Jun 2001	B1
6253555	Willis	Jul 2001	B1
6256976	Kataoka et al.	Jul 2001	B1
6256994	Dillon, IV	Jul 2001	B1
6263659	Dillon, IV et al.	Jul 2001	B1
6266954	McCallum et al.	Jul 2001	B1
6269624	Frutschi et al.	Aug 2001	B1
6269882	Wellington et al.	Aug 2001	B1
6276171	Brugerolle	Aug 2001	B1
6282901	Marin et al.	Sep 2001	B1
6283087	Isaksen	Sep 2001	B1
6289677	Prociw et al.	Sep 2001	B1
6298652	Mittricker et al.	Oct 2001	B1
6298654	Vermes et al.	Oct 2001	B1
6298664	Åsen et al.	Oct 2001	B1
6301888	Gray, Jr.	Oct 2001	B1
6301889	Gladden et al.	Oct 2001	B1
6305929	Chung et al.	Oct 2001	B1
6314721	Mathews et al.	Nov 2001	B1
6324867	Fanning	Dec 2001	B1
6332313	Willis et al.	Dec 2001	B1
6345493	Smith et al.	Feb 2002	B1
6360528	Brausch et al.	Mar 2002	B1
6363709	Kataoka et al.	Apr 2002	B2
6367258	Wen	Apr 2002	B1
6370870	Kamijo et al.	Apr 2002	B1
6374591	Johnson	Apr 2002	B1
6374594	Kraft et al.	Apr 2002	B1
6383461	Lang	May 2002	B1
6389814	Viteri et al.	May 2002	B2
6405536	Ho et al.	Jun 2002	B1
6412278	Matthews	Jul 2002	B1
6412302	Foglietta	Jul 2002	B1
6412559	Gunter et al.	Jul 2002	B1
6418725	Maeda et al.	Jul 2002	B1
6429020	Thornton et al.	Aug 2002	B1
6449954	Bachmann	Sep 2002	B2
6450256	Mones	Sep 2002	B2
6461147	Sonju et al.	Oct 2002	B1
6467270	Mulloy et al.	Oct 2002	B2
6470682	Gray, Jr.	Oct 2002	B2
6477859	Wong et al.	Nov 2002	B2
6484503	Raz	Nov 2002	B1
6484507	Pradt	Nov 2002	B1
6487863	Chen et al.	Dec 2002	B1
6499990	Zink et al.	Dec 2002	B1
6502383	Janardan et al.	Jan 2003	B1
6505567	Anderson et al.	Jan 2003	B1
6505683	Minkkinen et al.	Jan 2003	B2
6508209	Collier, Jr.	Jan 2003	B1
6523349	Viteri	Feb 2003	B2
6532745	Neary	Mar 2003	B1
6539716	Finger et al.	Apr 2003	B2
6584775	Schneider et al.	Jul 2003	B1
6598398	Viteri et al.	Jul 2003	B2
6598399	Liebig	Jul 2003	B2
6598402	Kataoka et al.	Jul 2003	B2
6606861	Snyder	Aug 2003	B2
6612291	Sakamoto	Sep 2003	B2
6615576	Sheoran et al.	Sep 2003	B2
6615589	Allam et al.	Sep 2003	B2
6622470	Viteri et al.	Sep 2003	B2
6622645	Havlena	Sep 2003	B2
6637183	Viteri et al.	Oct 2003	B2
6644041	Eyermann	Nov 2003	B1
6655150	Åsen et al.	Dec 2003	B1
6668541	Rice et al.	Dec 2003	B2
6672863	Doebbeling et al.	Jan 2004	B2
6675579	Yang	Jan 2004	B1
6684643	Frutschi	Feb 2004	B2
6694735	Sumser et al.	Feb 2004	B2
6698412	Dalla Betta	Mar 2004	B2
6702570	Shah et al.	Mar 2004	B2
6722436	Krill	Apr 2004	B2
6725665	Tuschy et al.	Apr 2004	B2
6731501	Cheng	May 2004	B1
6732531	Dickey	May 2004	B2
6742506	Grandin	Jun 2004	B1
6743829	Fischer-Calderon et al.	Jun 2004	B2
6745573	Marin et al.	Jun 2004	B2
6745624	Porter et al.	Jun 2004	B2
6748004	Jepson	Jun 2004	B2
6752620	Heier et al.	Jun 2004	B2
6767527	Åsen et al.	Jul 2004	B1
6772583	Bland	Aug 2004	B2
6790030	Fischer et al.	Sep 2004	B2
6805483	Tomlinson et al.	Oct 2004	B2
6810673	Snyder	Nov 2004	B2
6813889	Inoue et al.	Nov 2004	B2
6817187	Yu	Nov 2004	B2
6820428	Wylie	Nov 2004	B2
6821501	Matzakos et al.	Nov 2004	B2
6823852	Collier, Jr.	Nov 2004	B2
6824710	Viteri et al.	Nov 2004	B2
6826912	Levy et al.	Dec 2004	B2
6826913	Wright	Dec 2004	B2
6838071	Olsvik et al.	Jan 2005	B1
6851413	Tamol, Sr.	Feb 2005	B1
6868677	Viteri et al.	Mar 2005	B2
6886334	Shirakawa	May 2005	B2
6887069	Thornton et al.	May 2005	B1
6899859	Olsvik	May 2005	B1
6901760	Dittmann et al.	Jun 2005	B2
6904815	Widmer	Jun 2005	B2
6907737	Mittricker et al.	Jun 2005	B2
6910335	Viteri et al.	Jun 2005	B2
6923915	Alford et al.	Aug 2005	B2
6939130	Abbasi et al.	Sep 2005	B2
6945029	Viteri	Sep 2005	B2
6945052	Frutschi et al.	Sep 2005	B2
6945087	Porter et al.	Sep 2005	B2
6945089	Barie et al.	Sep 2005	B2
6946419	Kaefer	Sep 2005	B2
6969123	Vinegar et al.	Nov 2005	B2
6971242	Boardman	Dec 2005	B2
6981358	Bellucci et al.	Jan 2006	B2
6988549	Babcock	Jan 2006	B1
6993901	Shirakawa	Feb 2006	B2
6993916	Johnson et al.	Feb 2006	B2
6994491	Kittle	Feb 2006	B2
7007487	Belokon et al.	Mar 2006	B2
7010921	Intile et al.	Mar 2006	B2
7011154	Maher et al.	Mar 2006	B2
7015271	Bice et al.	Mar 2006	B2
7032388	Healy	Apr 2006	B2
7040400	de Rouffignac et al.	May 2006	B2
7043898	Rago	May 2006	B2
7043920	Viteri et al.	May 2006	B2
7045553	Hershkowitz	May 2006	B2
7053128	Hershkowitz	May 2006	B2
7056482	Hakka et al.	Jun 2006	B2
7059152	Oakey et al.	Jun 2006	B2
7065953	Kopko	Jun 2006	B1
7065972	Zupanc et al.	Jun 2006	B2
7074033	Neary	Jul 2006	B2
7077199	Vinegar et al.	Jul 2006	B2
7089743	Frutschi et al.	Aug 2006	B2
7096942	de Rouffignac et al.	Aug 2006	B1
7097925	Keefer	Aug 2006	B2
7104319	Vinegar et al.	Sep 2006	B2
7104784	Hasegawa et al.	Sep 2006	B1
7124589	Neary	Oct 2006	B2
7137256	Stuttaford et al.	Nov 2006	B1
7137623	Mockry	Nov 2006	B2
7143572	Ooka et al.	Dec 2006	B2
7143606	Tranier	Dec 2006	B2
7146969	Weirich	Dec 2006	B2
7147461	Neary	Dec 2006	B2
7148261	Hershkowitz et al.	Dec 2006	B2
7152409	Yee et al.	Dec 2006	B2
7162875	Fletcher et al.	Jan 2007	B2
7168265	Briscoe et al.	Jan 2007	B2
7168488	Olsvik et al.	Jan 2007	B2
7183328	Hershkowitz et al.	Feb 2007	B2
7185497	Dudebout et al.	Mar 2007	B2
7194869	McQuiggan et al.	Mar 2007	B2
7197880	Thornton et al.	Apr 2007	B2
7217303	Hershkowitz et al.	May 2007	B2
7225623	Koshoffer	Jun 2007	B2
7237385	Carrea	Jul 2007	B2
7284362	Marin et al.	Oct 2007	B2
7299619	Briesch	Nov 2007	B2
7299868	Zapadinski	Nov 2007	B2
7302801	Chen	Dec 2007	B2
7305817	Blodgett et al.	Dec 2007	B2
7305831	Carrea et al.	Dec 2007	B2
7313916	Pellizzari	Jan 2008	B2
7318317	Carrea	Jan 2008	B2
7343742	Wimmer et al.	Mar 2008	B2
7353655	Bolis et al.	Apr 2008	B2
7357857	Hart et al.	Apr 2008	B2
7363756	Carrea et al.	Apr 2008	B2
7363764	Griffin et al.	Apr 2008	B2
7381393	Lynn	Jun 2008	B2
7401577	Saucedo et al.	Jul 2008	B2
7410525	Liu et al.	Aug 2008	B1
7416137	Hagen et al.	Aug 2008	B2
7434384	Lord et al.	Oct 2008	B2
7438744	Beaumont	Oct 2008	B2
7467942	Carroni et al.	Dec 2008	B2
7468173	Hughes et al.	Dec 2008	B2
7472550	Lear, Jr. et al.	Jan 2009	B2
7481048	Harmon et al.	Jan 2009	B2
7481275	Olsvik et al.	Jan 2009	B2
7482500	Johann et al.	Jan 2009	B2
7485761	Schindler et al.	Feb 2009	B2
7488857	Johann et al.	Feb 2009	B2
7490472	Lynghjem et al.	Feb 2009	B2
7491250	Hershkowitz et al.	Feb 2009	B2
7492054	Catlin	Feb 2009	B2
7493769	Jangili	Feb 2009	B2
7498009	Leach et al.	Mar 2009	B2
7503178	Bucker et al.	Mar 2009	B2
7503948	Hershkowitz et al.	Mar 2009	B2
7506501	Anderson et al.	Mar 2009	B2
7513099	Nuding et al.	Apr 2009	B2
7513100	Motter et al.	Apr 2009	B2
7516626	Brox et al.	Apr 2009	B2
7520134	Durbin et al.	Apr 2009	B2
7523603	Hagen et al.	Apr 2009	B2
7536252	Hibshman, II et al.	May 2009	B1
7536873	Nohlen	May 2009	B2
7540150	Schmid et al.	Jun 2009	B2
7559977	Fleischer et al.	Jul 2009	B2
7562519	Harris et al.	Jul 2009	B1
7562529	Kuspert et al.	Jul 2009	B2
7566394	Koseoglu	Jul 2009	B2
7574856	Mak	Aug 2009	B2
7591866	Bose	Sep 2009	B2
7594386	Narayanan et al.	Sep 2009	B2
7610752	Dalla Betta et al.	Nov 2009	B2
7610759	Yoshida et al.	Nov 2009	B2
7611681	Kaefer	Nov 2009	B2
7614352	Anthony et al.	Nov 2009	B2
7618606	Fan et al.	Nov 2009	B2
7631493	Shirakawa et al.	Dec 2009	B2
7634915	Hoffmann et al.	Dec 2009	B2
7635408	Mak et al.	Dec 2009	B2
7637093	Rao	Dec 2009	B2
7644573	Smith	Jan 2010	B2
7650744	Varatharajan et al.	Jan 2010	B2
7654320	Payton	Feb 2010	B2
7654330	Zubrin et al.	Feb 2010	B2
7655071	De Vreede	Feb 2010	B2
7670135	Zink et al.	Mar 2010	B1
7673454	Saito et al.	Mar 2010	B2
7673685	Huntley Shaw et al.	Mar 2010	B2
7674443	Davis	Mar 2010	B1
7677309	Shaw et al.	Mar 2010	B2
7681394	Haugen	Mar 2010	B2
7682597	Blumenfeld et al.	Mar 2010	B2
7690204	Drnevich et al.	Apr 2010	B2
7691788	Tan et al.	Apr 2010	B2
7695703	Sobolevskiy et al.	Apr 2010	B2
7717173	Grott	May 2010	B2
7721543	Massey et al.	May 2010	B2
7726114	Evulet	Jun 2010	B2
7734408	Shiraki	Jun 2010	B2
7739864	Finkenrath et al.	Jun 2010	B2
7749311	Saito et al.	Jul 2010	B2
7752848	Balan et al.	Jul 2010	B2
7752850	Laster et al.	Jul 2010	B2
7753039	Harima et al.	Jul 2010	B2
7753972	Zubrin et al.	Jul 2010	B2
7762084	Martis et al.	Jul 2010	B2
7763163	Koseoglu	Jul 2010	B2
7763227	Wang	Jul 2010	B2
7765810	Pfefferle	Aug 2010	B2
7788897	Campbell et al.	Sep 2010	B2
7789159	Bader	Sep 2010	B1
7789658	Towler et al.	Sep 2010	B2
7789944	Saito et al.	Sep 2010	B2
7793494	Wirth et al.	Sep 2010	B2
7802434	Varatharajan et al.	Sep 2010	B2
7815873	Sankaranarayanan et al.	Oct 2010	B2
7815892	Hershkowitz et al.	Oct 2010	B2
7819951	White et al.	Oct 2010	B2
7824179	Hasegawa et al.	Nov 2010	B2
7827778	Finkenrath et al.	Nov 2010	B2
7827794	Pronske et al.	Nov 2010	B1
7841186	So et al.	Nov 2010	B2
7845406	Nitschke	Dec 2010	B2
7846401	Hershkowitz et al.	Dec 2010	B2
7861511	Chillar et al.	Jan 2011	B2
7874140	Fan et al.	Jan 2011	B2
7874350	Pfefferle	Jan 2011	B2
7875402	Hershkowitz et al.	Jan 2011	B2
7882692	Pronske et al.	Feb 2011	B2
7886522	Kammel	Feb 2011	B2
7895822	Hoffmann et al.	Mar 2011	B2
7896105	Dupriest	Mar 2011	B2
7906304	Kohr	Mar 2011	B2
7909898	White et al.	Mar 2011	B2
7914749	Carstens et al.	Mar 2011	B2
7914764	Hershkowitz et al.	Mar 2011	B2
7918906	Zubrin et al.	Apr 2011	B2
7921633	Rising	Apr 2011	B2
7922871	Price et al.	Apr 2011	B2
7926292	Rabovitser et al.	Apr 2011	B2
7931712	Zubrin et al.	Apr 2011	B2
7931731	Van Heeringen et al.	Apr 2011	B2
7931888	Drnevich et al.	Apr 2011	B2
7934926	Kornbluth et al.	May 2011	B2
7942003	Baudoin et al.	May 2011	B2
7942008	Joshi et al.	May 2011	B2
7943097	Golden et al.	May 2011	B2
7950239	Lilley et al.	May 2011	B2
7950240	Nemet et al.	May 2011	B2
7955403	Ariyapadi et al.	Jun 2011	B2
7966822	Myers et al.	Jun 2011	B2
7976803	Hooper et al.	Jul 2011	B2
7980312	Hill et al.	Jul 2011	B1
7985399	Drnevich et al.	Jul 2011	B2
7988750	Lee	Aug 2011	B2
8001789	Vega et al.	Aug 2011	B2
8029273	Paschereit et al.	Oct 2011	B2
8036813	Tonetti et al.	Oct 2011	B2
8038416	Ono et al.	Oct 2011	B2
8038746	Clark	Oct 2011	B2
8038773	Ochs et al.	Oct 2011	B2
8046986	Chillar et al.	Nov 2011	B2
8047007	Zubrin et al.	Nov 2011	B2
8051638	Aljabari et al.	Nov 2011	B2
8061120	Hwang	Nov 2011	B2
8062617	Stakhev et al.	Nov 2011	B2
8065870	Jobson et al.	Nov 2011	B2
8065874	Fong et al.	Nov 2011	B2
8074439	Foret	Dec 2011	B2
8080225	Dickinson et al.	Dec 2011	B2
8083474	Hashimoto et al.	Dec 2011	B2
8097230	Mesters et al.	Jan 2012	B2
8101146	Fedeyko et al.	Jan 2012	B2
8105559	Melville et al.	Jan 2012	B2
8110012	Chiu et al.	Feb 2012	B2
8117825	Griffin et al.	Feb 2012	B2
8117846	Wilbraham	Feb 2012	B2
8127558	Bland et al.	Mar 2012	B2
8127936	Liu et al.	Mar 2012	B2
8127937	Liu et al.	Mar 2012	B2
8133298	Lanyi et al.	Mar 2012	B2
8166766	Draper	May 2012	B2
8167960	Gil	May 2012	B2
8176982	Gil et al.	May 2012	B2
8191360	Fong et al.	Jun 2012	B2
8191361	Fong et al.	Jun 2012	B2
8196387	Shah et al.	Jun 2012	B2
8196413	Mak	Jun 2012	B2
8201402	Fong et al.	Jun 2012	B2
8205455	Popovic	Jun 2012	B2
8206669	Schaffer et al.	Jun 2012	B2
8209192	Gil et al.	Jun 2012	B2
8215105	Fong et al.	Jul 2012	B2
8220247	Wijmans et al.	Jul 2012	B2
8220248	Wijmans et al.	Jul 2012	B2
8220268	Callas	Jul 2012	B2
8225600	Theis	Jul 2012	B2
8226912	Kloosterman et al.	Jul 2012	B2
8240142	Fong et al.	Aug 2012	B2
8240153	Childers et al.	Aug 2012	B2
8245492	Draper	Aug 2012	B2
8245493	Minto	Aug 2012	B2
8247462	Boshoff et al.	Aug 2012	B2
8257476	White et al.	Sep 2012	B2
8261823	Hill et al.	Sep 2012	B1
8262343	Hagen	Sep 2012	B2
8266883	Dion Ouellet et al.	Sep 2012	B2
8266913	Snook et al.	Sep 2012	B2
8268044	Wright et al.	Sep 2012	B2
8281596	Rohrssen et al.	Oct 2012	B1
8316665	Mak	Nov 2012	B2
8316784	D'Agostini	Nov 2012	B2
8337613	Zauderer	Dec 2012	B2
8347600	Wichmann et al.	Jan 2013	B2
8348551	Baker et al.	Jan 2013	B2
8371100	Draper	Feb 2013	B2
8372251	Goller et al.	Feb 2013	B2
8377184	Fujikawa et al.	Feb 2013	B2
8377401	Darde et al.	Feb 2013	B2
8388919	Hooper et al.	Mar 2013	B2
8397482	Kraemer et al.	Mar 2013	B2
8398757	Iijima et al.	Mar 2013	B2
8409307	Drnevich et al.	Apr 2013	B2
8414694	Iijima et al.	Apr 2013	B2
8424282	Vollmer et al.	Apr 2013	B2
8424601	Betzer-Zilevitch	Apr 2013	B2
8436489	Stahlkopf et al.	May 2013	B2
8453461	Draper	Jun 2013	B2
8453462	Wichmann et al.	Jun 2013	B2
8453583	Malavasi et al.	Jun 2013	B2
8454350	Berry et al.	Jun 2013	B2
8475160	Campbell et al.	Jul 2013	B2
8539749	Wichmann et al.	Sep 2013	B1
8567200	Brook et al.	Oct 2013	B2
8616294	Zubrin et al.	Dec 2013	B2
8627643	Chillar et al.	Jan 2014	B2
20010000049	Kataoka et al.	Mar 2001	A1
20010029732	Bachmann	Oct 2001	A1
20010045090	Gray, Jr.	Nov 2001	A1
20020043063	Kataoka et al.	Apr 2002	A1
20020053207	Finger et al.	May 2002	A1
20020069648	Levy et al.	Jun 2002	A1
20020187449	Doebbeling et al.	Dec 2002	A1
20030005698	Keller	Jan 2003	A1
20030131582	Anderson et al.	Jul 2003	A1
20030134241	Marin et al.	Jul 2003	A1
20030221409	McGowan	Dec 2003	A1
20040006994	Walsh et al.	Jan 2004	A1
20040068981	Siefker et al.	Apr 2004	A1
20040166034	Kaefer	Aug 2004	A1
20040170559	Hershkowitz et al.	Sep 2004	A1
20040223408	Mathys et al.	Nov 2004	A1
20040238654	Hagen et al.	Dec 2004	A1
20050028529	Bartlett et al.	Feb 2005	A1
20050144961	Colibaba-Evulet et al.	Jul 2005	A1
20050197267	Zaki et al.	Sep 2005	A1
20050229585	Webster	Oct 2005	A1
20050236602	Viteri et al.	Oct 2005	A1
20060112675	Anderson et al.	Jun 2006	A1
20060158961	Ruscheweyh et al.	Jul 2006	A1
20060183009	Berlowitz et al.	Aug 2006	A1
20060196812	Beetge et al.	Sep 2006	A1
20060248888	Geskes	Nov 2006	A1
20070000242	Harmon et al.	Jan 2007	A1
20070044475	Leser et al.	Mar 2007	A1
20070044479	Brandt et al.	Mar 2007	A1
20070089425	Motter et al.	Apr 2007	A1
20070107430	Schmid et al.	May 2007	A1
20070144747	Steinberg	Jun 2007	A1
20070231233	Bose	Oct 2007	A1
20070234702	Hagen et al.	Oct 2007	A1
20070245736	Barnicki	Oct 2007	A1
20070249738	Haynes et al.	Oct 2007	A1
20070272201	Amano et al.	Nov 2007	A1
20080000229	Kuspert et al.	Jan 2008	A1
20080006561	Moran et al.	Jan 2008	A1
20080010967	Griffin et al.	Jan 2008	A1
20080034727	Sutikno	Feb 2008	A1
20080038598	Berlowitz et al.	Feb 2008	A1
20080047280	Dubar	Feb 2008	A1
20080066443	Frutschi et al.	Mar 2008	A1
20080115478	Sullivan	May 2008	A1
20080118310	Graham	May 2008	A1
20080127632	Finkenrath et al.	Jun 2008	A1
20080155984	Liu et al.	Jul 2008	A1
20080178611	Ding	Jul 2008	A1
20080202123	Sullivan et al.	Aug 2008	A1
20080223038	Lutz et al.	Sep 2008	A1
20080250795	Katdare	Oct 2008	A1
20080251234	Wilson	Oct 2008	A1
20080290719	Kaminsky et al.	Nov 2008	A1
20080309087	Evulet et al.	Dec 2008	A1
20090000762	Wilson	Jan 2009	A1
20090025390	Christensen et al.	Jan 2009	A1
20090038247	Taylor et al.	Feb 2009	A1
20090056342	Kirzhner	Mar 2009	A1
20090064653	Hagen et al.	Mar 2009	A1
20090071166	Hagen et al.	Mar 2009	A1
20090107141	Chillar et al.	Apr 2009	A1
20090117024	Weedon et al.	May 2009	A1
20090120087	Sumser et al.	May 2009	A1
20090157230	Hibshman, II et al.	Jun 2009	A1
20090193809	Schroder et al.	Aug 2009	A1
20090205334	Aljabari et al.	Aug 2009	A1
20090218821	ElKady et al.	Sep 2009	A1
20090223227	Lipinski et al.	Sep 2009	A1
20090229263	Ouellet et al.	Sep 2009	A1
20090235637	Foret	Sep 2009	A1
20090241506	Nilsson	Oct 2009	A1
20090255242	Paterson et al.	Oct 2009	A1
20090262599	Kohrs et al.	Oct 2009	A1
20090284013	Anand et al.	Nov 2009	A1
20090301054	Simpson et al.	Dec 2009	A1
20090301099	Nigro	Dec 2009	A1
20100003123	Smith	Jan 2010	A1
20100018218	Riley et al.	Jan 2010	A1
20100058732	Kaufmann et al.	Mar 2010	A1
20100115960	Brautsch et al.	May 2010	A1
20100126176	Kim	May 2010	A1
20100126906	Sury	May 2010	A1
20100162703	Li et al.	Jul 2010	A1
20100170253	Berry et al.	Jul 2010	A1
20100180565	Draper	Jul 2010	A1
20100300102	Bathina et al.	Dec 2010	A1
20100310439	Brok et al.	Dec 2010	A1
20100322759	Tanioka	Dec 2010	A1
20100326084	Anderson et al.	Dec 2010	A1
20110000221	Minta et al.	Jan 2011	A1
20110000671	Hershkowitz et al.	Jan 2011	A1
20110036082	Collinot	Feb 2011	A1
20110048002	Taylor et al.	Mar 2011	A1
20110048010	Balcezak et al.	Mar 2011	A1
20110068585	Dube et al.	Mar 2011	A1
20110072779	ElKady et al.	Mar 2011	A1
20110088379	Nanda	Apr 2011	A1
20110110759	Sanchez et al.	May 2011	A1
20110126512	Anderson	Jun 2011	A1
20110138766	ElKady et al.	Jun 2011	A1
20110162353	Vanvolsem et al.	Jul 2011	A1
20110205837	Gentgen	Aug 2011	A1
20110226010	Baxter	Sep 2011	A1
20110227346	Klenven	Sep 2011	A1
20110232545	Clements	Sep 2011	A1
20110239653	Valeev et al.	Oct 2011	A1
20110265447	Cunningham	Nov 2011	A1
20110300493	Mittricker et al.	Dec 2011	A1
20120023954	Wichmann	Feb 2012	A1
20120023955	Draper	Feb 2012	A1
20120023956	Popovic	Feb 2012	A1
20120023957	Draper et al.	Feb 2012	A1
20120023958	Snook et al.	Feb 2012	A1
20120023960	Minto	Feb 2012	A1
20120023962	Wichmann et al.	Feb 2012	A1
20120023963	Wichmann et al.	Feb 2012	A1
20120023966	Ouellet et al.	Feb 2012	A1
20120031581	Chillar et al.	Feb 2012	A1
20120032810	Chillar et al.	Feb 2012	A1
20120085100	Hughes et al.	Apr 2012	A1
20120096870	Wichmann et al.	Apr 2012	A1
20120119512	Draper	May 2012	A1
20120131925	Mittricker et al.	May 2012	A1
20120144837	Rasmussen et al.	Jun 2012	A1
20120185144	Draper	Jul 2012	A1
20120192565	Tretyakov et al.	Aug 2012	A1
20120247105	Nelson et al.	Oct 2012	A1
20120260660	Kraemer et al.	Oct 2012	A1
20130086916	Oelfke et al.	Apr 2013	A1
20130086917	Slobodyanskiy et al.	Apr 2013	A1
20130091853	Denton et al.	Apr 2013	A1
20130091854	Gupta et al.	Apr 2013	A1
20130104562	Oelfke et al.	May 2013	A1
20130104563	Oelfke et al.	May 2013	A1
20130125554	Mittricker et al.	May 2013	A1
20130125555	Mittricker et al.	May 2013	A1
20130232980	Chen et al.	Sep 2013	A1
20130269310	Wichmann et al.	Oct 2013	A1
20130269311	Wichmann et al.	Oct 2013	A1
20130269355	Wichmann et al.	Oct 2013	A1
20130269356	Butkiewicz et al.	Oct 2013	A1
20130269357	Wichmann et al.	Oct 2013	A1
20130269358	Wichmann et al.	Oct 2013	A1
20130269360	Wichmann et al.	Oct 2013	A1
20130269361	Wichmann et al.	Oct 2013	A1
20130269362	Wichmann et al.	Oct 2013	A1
20130283808	Kolvick	Oct 2013	A1
20140000271	Mittricker et al.	Jan 2014	A1
20140000273	Mittricker et al.	Jan 2014	A1
20140007590	Huntington et al.	Jan 2014	A1
20140013766	Mittricker et al.	Jan 2014	A1
20140020398	Mittricker et al.	Jan 2014	A1

Foreign Referenced Citations (23)

Number	Date	Country
2231749	Sep 1998	CA
2645450	Sep 2007	CA
0770771	May 1997	EP
776269	Jun 1957	GB
2117053	Oct 1983	GB
WO9906674	Feb 1999	WO
WO9963210	Dec 1999	WO
WO2007068682	Jun 2007	WO
WO2008142009	Nov 2008	WO
WO2011003606	Jan 2011	WO
2012003078	Jan 2012	WO
2012003079	Jan 2012	WO
WO2012003489	Jan 2012	WO
2012018457	Feb 2012	WO
WO2012128928	Sep 2012	WO
WO2012128929	Sep 2012	WO
WO2012170114	Dec 2012	WO
PCTRU2013000162	Feb 2013	WO
PCTUS13036020	Apr 2013	WO
WO2013147632	Oct 2013	WO
WO2013147633	Oct 2013	WO
WO2013155214	Oct 2013	WO
WO2013163045	Oct 2013	WO

Non-Patent Literature Citations (53)

Entry
Ahmed, S. et al. (1998) “Catalytic Partial Oxidation Reforming of Hydrocarbon Fuels,” 1998 Fuel Cell Seminar, Nov. 16-19, 1998, 7 pgs.
Air Separation Technology Ion Transport Membrane—Air Products 2008.
Air Separation Technology Ion Transport Membrane—Air Products 2011.
Anderson, R. E. (2006) “Durability and Reliability Demonstration of a Near-Zero-Emission Gas-Fired Power Plant,” California Energy Comm., CEC 500-2006-074, 80 pgs.
Baxter, E. et al. (2003) “Fabricate and Test an Advanced Non-Polluting Turbine Drive Gas Generator,” U. S. Dept. of Energy, Nat'l Energy Tech. Lab., DE-FC26-00NT 40804, 51 pgs.
Bolland, O. et al. (1998) “Removal of CO2 From Gas Turbine Power Plants Evaluation of Pre- and Postcombustion Methods,” SINTEF Group, 1998, www.energy.sintef.no/publ/xergi/98/3/art-8engelsk.htm, 11 pgs.
BP Press Release (2006) “BP and Edison Mission Group Plan Major Hydrogen Power Project for California,” Feb. 10, 2006, www.bp.com/hydrogenpower, 2 pgs.
Bryngelsson, M. et al. (2005) “Feasibility Study of CO2 Removal From Pressurized Flue Gas in a Fully Fired Combined Cycle—The Sargas Project,” KTH—Royal Institute of Technology, Dept. of Chemical Engineering and Technology, 9 pgs.
Clark, Hal (2002) “Development of a Unique Gas Generator for a Non-Polluting Power Plant,” California Energy Commission Feasibility Analysis, P500-02-011F, Mar. 2002, 42 pgs.
Comparison of Ion Transport Membranes—Fourth Annual Conference on Carbon Capture and Sequestration DOE/NETL; May 2005.
Ciulia, Vincent. About.com. Auto Repair. How the Engine Works. 2001-2003.
Cryogenics. Science Clarified. 2012. http://www.scienceclarified.com/Co-Di/Cryogenics.html.
Defrate, L. A. et al. (1959) “Optimum Design of Ejector Using Digital Computers” Chem. Eng. Prog. Symp. Ser., 55 ( 21) pp. 46.
Ditaranto, M. et al. (2006) “Combustion Instabilities in Sudden Expansion Oxy-Fuel Flames,” ScienceDirect, Combustion and Flame, v.146, Jun. 30, 2006, pp. 493-451.
Elwell, L. C. et al. (2005) “Technical Overview of Carbon Dioxide Capture Technologies for Coal-Fired Power Plants,” MPR Associates, Inc., Jun. 22, 2005, 15 pgs.
Eriksson, Sara. Licentiate Thesis 2005, p. 22. KTH—“Development of Methane Oxidation Catalysts for Different Gas Turbine Combustor Concepts.” The Royal Institute of Technology, Department of Chemical Engineering and Technology, Chemical Technology, Stockholm Sweden.
Ertesvag, I. S. et al. (2005) “Exergy Analysis of a Gas-Turbin Combined-Cycle Power Plant With Precombustion CO2 Capture,” Elsivier, 2004, pp. 5-39.
Evulet, Andrei T. et al. “Application of Exhaust Gas Recirculation in a DLN F-Class Combustion System for Postcombustion Carbon Capture” ASME J. Engineering for Gas Turbines and Power, vol. 131, May 2009.
Evulet, Andrei T. et al. “On the Performance and Operability of GE's Dry Low Nox Combustors utilizing Exhaust Gas Recirculation for Post-Combustion Carbon Capture” Energy Procedia I 2009, 3809-3816.
http://www.turbineinletcooling.org/resources/papers/CTIC—WetCompression—Shepherd—ASMETurboExpo2011.pdf Jun. 2011.
Luby, P. et al. (2003) “Zero Carbon Power Generation: IGCC as the Premium Option,” Powergen International, 19 pgs.
MacAdam, S. et al. (2008) “Coal-Based Oxy-Fuel System Evaluation and Combustor Development,” Clean Energy Systems, Inc. 6 pgs.
Morehead, H. (2007) “Siemens Global Gasification and IGCC Update,” Siemens, Coal-Gen, Aug. 3, 2007, 17 pgs.
Reeves, S. R. (2001) “Geological Sequestration of CO2 in Deep, Unmineable Coalbeds: An Integrated Research and Commercial-Scale Field Demonstration Project,” SPE 71749, 10 pgs.
Reeves, S. R. (2003) “Enhanced Coalbed Methane Recovery,” SPE 101466-DL, 8 pgs.
Richards, G. A. et al. (2001) “Advanced Steam Generators,” National Energy Technology Laboratory, 7 pgs.
Snarheim, D. et al. (2006) “Control Design for a Gas Turbine Cycle With CO2 Capture Capabilities,” Modeling, Identification and Control, vol. 00, 10 pgs.
Ulfsnes, R. E. et al. (2003) “Investigation of Physical Properties for CO2/H2O Mixtures for use in Semi-Closed O2/CO2 Gas Turbine Cycle With CO2-Capture,” Department of Energy and Process Eng., Norwegian Univ. of Science and Technology, 9 pgs.
vanHemert, P. et al. (2006) “Adsorption of Carbon Dioxide and a Hydrogen-Carbon Dioxide Mixture,” Intn'l Coalbed Methane Symposium (Tuscaloosa, AL) Paper 0615, 9 pgs.
Zhu, J. et al. (2002) “Recovery of Coalbed Methane by Gas Injection,” SPE 75255, 15 pgs.
U.S. Appl. No. 13/596,684, filed Aug. 28, 2012, Slobodyanskiy et al.
U.S. Appl. No. 14/066,579, filed Oct. 29, 2013, Huntington et al.
U.S. Appl. No. 14/066,551, filed Oct. 29, 2013, Minto.
U.S. Appl. No. 14/144,511, filed Dec. 30, 2013, Thatcher et al.
U.S. Appl. No. 14/067,559, filed Oct. 30, 2013, Lucas John Stoia et al.
U.S. Appl. No. 14/067,679, filed Oct. 30, 2013, Elizabeth Angelyn Fadde et al.
U.S. Appl. No. 14/067,714, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
U.S. Appl. No. 14/067,726, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
U.S. Appl. No. 14/067,731, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
U.S. Appl. No. 14/067,739, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
U.S. Appl. No. 14/067,797, filed Oct. 31, 2013, Anthony Wayne Krull et al.
U.S. Appl. No. 14/066,488, filed Oct. 29, 2013, Pramod K. Biyani et al.
U.S. Appl. No. 14/135,055, filed Dec. 19, 2013, Pramod K. Biyani et al.
U.S. Appl. No. 14/067,844, filed Oct. 30, 2013, John Farrior Woodall et al.
U.S. Appl. No. 14/067,486, filed Oct. 30, 2013, Huntington et al.
U.S. Appl. No. 14/067,537, filed Oct. 30, 2013, Huntington et al.
U.S. Appl. No. 14/067,552, filed Oct. 30, 2013, Huntington et al.
U.S. Appl. No. 14/067,563, filed Oct. 30, 2013, Huntington et al.
PCT International Search Report & Written Opinion for PCT Application No. PCT/US2013/036020; dated Jul. 11, 2013.
Cho, J. H. et al. (2005) “Marrying LNG and Power Generation,” Energy Markets; 10, 8; ABI/INFORM Trade & Industry, 5 pgs.
Corti, A. et al. (1988) “Athabasca Mineable Oil Sands: The RTR/Gulf Extraction Process Theoretical Model of Bitumen Detachment,” 4th UNITAR/UNDP Int'l Conf. on Heavy Crude and Tar Sands Proceedings, v.5, paper No. 81, Edmonton, AB, Canada, 4 pgs.
Nanda, R. et al. (2007) “Utilizing Air Based Technologies as Heat Source for LNG Vaporization,” presented at the 86th Annual convention of the Gas Processors of America (GPA 2007), , San Antonio, TX; 13 pgs.
Rosetta, M. J. et al. (2005) “Integrating Ambient Air Vaporization Technology with Waste Heat Recovery—A Fresh Approach to LNG Vaporization,” presented at the 85th annual convention of the Gas Processors of America (GPA 2006), Grapevine, Texas, 22 pgs.

Related Publications (1)

	Number	Date	Country
	20130269362 A1	Oct 2013	US

Methods, systems and apparatus relating to combustion turbine power plants with exhaust gas recirculation

Information

Patent Number

Date Filed

Date Issued

Inventors

Original Assignees

Examiners

Agents

CPC

Field of Search

CPC

International Classifications