Control systems and control methods suitable for use with power production systems and power production methods

Abstract

To provide control systems and control methods suitable for combination with power production systems and power production methods.SOLUTION: The control systems and control methods may be used with, for example, closed power cycles as well as semi-closed power cycles. The combined control systems and combined control methods and power production systems and power production methods can provide dynamic control of the power production systems and methods that can be implemented automatically based upon inputs received by controllers and outputs from the controllers to one or more components of the power production systems.SELECTED DRAWING: Figure 1

Description

[Technical field]

[0001] FIELD OF THE DISCLOSURE The present disclosure relates to control systems and methods, and more particularly to control systems and methods that can be incorporated into power generation systems and methods. [Background technology]

[0002] There is a great need for the development of power systems that can meet growing consumption needs. While there has been substantial research into systems that do not utilize the combustion of fossil fuels, the cost factors and availability of fossil fuels, particularly coal and natural gas (including waste hydrocarbons such as residual oil products), continue to require systems that are configured to burn such fuels, particularly with high efficiency and complete carbon capture. To meet these needs, there is a continuing desire for the development of control systems that can provide for precise control of power systems. Summary of the Invention

[0003] In one or more embodiments, the present disclosure may provide systems and methods useful for one or more aspects of a power generation system. The control system may specifically provide control of one or more of pressure, temperature, flow rate, and stream composition of one or more flow streams in the power generation system. The control system may provide optimal efficiency of the power generation system. The control system may further provide control of aspects of the power generation system, such as start-up of the system, shut-down of the system, changing input stream(s) in the system, changing output stream(s) in the system, emergency operational response for the system, and the like for operation of the power generation system.

[0004] In one or more embodiments, the present disclosure may relate to a control system suitable for use in a power plant. For example, the power plant may be a plant that burns a fuel (such as a hydrocarbon, specifically a hydrocarbon gas) in a combustor with substantially pure oxygen at a pressure of about 12 MPa or more, and adds a recycled CO2 stream, to produce a combined stream of combustion products and recycled CO2. In some embodiments, the power generation may further be characterized by one or more of the following points, which may be combined in any number or order:

[0005] The combined stream may be passed through a power generating turbine at a discharge pressure of at least 10 bar.

[0006] The turbine exhaust may be cooled in an economizer heat exchanger to preheat the recycle CO2 stream.

[0007] The turbine exhaust may be further cooled to near ambient temperature and the condensate may be removed.

[0008] The CO2 gas stream may be compressed to or near the turbine suction pressure using a gas compressor followed by a rich CO2 pump to form a circulating CO2 stream.

[0009] The net amount of CO2 produced in the combustor may be removed at a pressure between the turbine suction pressure and the turbine discharge pressure.

[0010] To reduce the temperature difference between the turbine exhaust and the recirculating CO2 stream exiting the economizer heat exchanger to about 50°C or less, heat from an external source may be introduced to preheat a portion of the recirculating CO2 stream to a temperature in the range of 200°C to 400°C.

[0011] The fuel gas flow rate may be controlled to provide a required power output from the turbine.

[0012] The turbine exhaust temperature may be controlled by the speed of the CO2 pump.

[0013] The discharge pressure of the CO2 compressor may be controlled by recirculating the compressed CO2 stream to the suction inlet of the compressor.

[0014] The flow rate of the net CO2 produced by the fuel gas combustion and removed from the system may be used to control the suction pressure of the CO2 compressor.

[0015] The difference between the temperature of the turbine exhaust entering the economizer heat exchanger and the temperature of the recirculating CO2 stream exiting the economizer heat exchanger may be controlled to less than 50°C by controlling the flow rate of the portion of the recirculating CO2 stream that is heated by the additional heat source.

[0016] The flow rate of net liquid water and fuel borne impurities removed from the system may be controlled at the liquid water separator level.

[0017] The oxygen flow rate may be controlled to maintain a ratio of oxygen to fuel gas flow rate such that there is a predetermined amount of excess oxygen in the turbine inlet flow to ensure complete combustion of the fuel gas and complete oxidation of the fuel gas components.

[0018] The oxygen stream at the CO2 compressor suction pressure may be mixed with a quantity of CO2 from the CO2 compressor inlet to produce an oxidizer stream containing about 15% to about 40% (molar concentration) oxygen content, which can reduce the adiabatic flame temperature in the combustor.

[0019] The oxidant flow required to produce the required oxygen to fuel gas ratio may be controlled by the speed of the oxidant pump.

[0020] The discharge pressure of the oxidant compressor may be controlled by recirculating the compressed oxidant stream to the suction inlet of the compressor.

[0021] The suction pressure of the oxidant compressor may be controlled by the flow rate of the CO2 diluent mixed with oxygen to form the oxidant stream.

[0022] The ratio of oxygen to CO2 in the oxidant stream may be controlled by the flow of oxygen.

[0023] Oxygen may be delivered to the power generation system at a pressure at least as high as the turbine suction pressure, and an oxidant stream containing an oxygen content in the range of about 15% to about 40% (molar concentration) may be desired.

[0024] The oxygen to fuel gas ratio may be controlled by the oxygen flow.

[0025] The ratio of oxygen to CO2 in the oxygen stream may be controlled by the flow of CO2 diluent taken from the discharge of the CO2 compressor.

[0026] In any of the embodiments discussed herein, the control of one parameter by a second parameter may specifically indicate that the second parameter is measured (e.g., using a sensor) or otherwise monitored, or that the second parameter is calculated by a computer based on additionally provided information, a look-up table, or an estimate, and that the controller initiates a control sequence based on the measured or calculated second parameter, such that the first parameter is appropriately adjusted (e.g., by opening or closing a valve, increasing or decreasing power to a pump, etc.) In other words, the second parameter is used as a trigger for the controller to effect the adjustment of the first parameter.

[0027] In one or more embodiments, the present disclosure may provide a power generation system including an embedded control system that may be configured for automatic control of at least one component of the power generation system. In particular, the control system may include at least one controller unit configured to receive inputs related to measured parameters of the power generation system and configured to provide outputs to the at least one component of the power generation system that is subject to automatic control. The power generation system and the embedded control system may be further defined with respect to one or more of the following statements, which may be combined in any number or order:

[0028] The power generation system may be configured for heat input via the combustion of a fuel.

[0029] The power generation system may be configured for heat input via a non-combustion heat source.

[0030] The power generation system may be configured to recycle the CO2 stream.

[0031] The power generation system may be configured to produce amounts of CO2 that can optionally be removed from the system, such as input to a pipeline or utilized for another purpose, such as enhanced oil recovery.

[0032] Power generation systems may be configured to utilize a working fluid that is repeatedly compressed, heated, and expanded.

[0033] The embedded control system may include a power controller configured to receive inputs related to the power produced by one or more power generating components of the power generating system.

[0034] The power control unit may be configured to satisfy one or both of a requirement to provide output to a heater component of the power generation system to increase or decrease heat production by the heater component and a requirement to provide output to a fuel valve to allow more or less fuel to be admitted to the power generation system.

[0035] The embedded control system may include a fuel / oxidizer ratio control configured to receive one or both of an input related to a fuel flow rate and an input related to an oxidizer flow rate.

[0036] The fuel / oxidizer ratio control section may be configured to satisfy one or both of the requirements of providing an output to a fuel valve that allows for more or less fuel entering the power generation system and providing an output to an oxidizer valve that allows for more or less oxidizer entering the power generation system.

[0037] The embedded control system may include a pump control configured to receive an input related to a temperature of an exhaust stream of a turbine in the power generation system and provide an output to a pump that increases or decreases the flow rate of the stream exiting the pump upstream from the turbine.

[0038] The embedded control system may include a pump suction pressure control configured to receive an input related to a suction pressure in a fluid upstream of a pump in the power generation system and provide an output to a spillback valve located upstream from the pump.

[0039] The pump suction pressure control section is configured to satisfy one or both of the requirements of adjusting the amount of fluid spilled back to a location further upstream from the spillback valve and adjusting the amount of fluid removed from the power generation system upstream from the pump.

[0040] The embedded control system may include a pressure regulation control configured to receive an input related to a pressure of an exhaust stream of a turbine in the power generation system, provide an output to a fluid exhaust valve to allow fluid to exit the exhaust stream, and optionally provide an output to a fluid intake valve to allow fluid to enter the exhaust stream.

[0041] The embedded control system may include a water separator control configured to receive an input regarding the amount of water in a separator of the power generation system and provide an output to a water removal valve that enables or disables the removal of water from the separator to maintain the amount of water in the separator within a predetermined value.

[0042] The embedded control system may include an oxidant pump controller configured to receive inputs related to one or both of a mass flow rate of fuel and a mass flow rate of oxidant in the power generation system and calculate a mass flow ratio of fuel to oxidant.

[0043] The oxidant pump control may be configured to provide an output to the oxidant pump that varies the power of the pump to affect the mass flow ratio of fuel to oxidant in the power generation system.

[0044] The embedded control system may include an oxidant pressure control configured to receive an input related to the pressure of the oxidant stream downstream from the oxidant compressor and provide an output to an oxidant bypass valve that increases or decreases the oxidant bypassing the compressor.

[0045] The embedded control system may include an oxidant pressure control configured to receive an input related to the pressure of the oxidant stream upstream of the oxidant compressor and provide an output to a recirculation fluid valve that adds more or less recirculation fluid from the power generation system to the oxidant stream upstream of the oxidant compressor. Specifically, the recirculation fluid may be a substantially pure CO2 stream.

[0046] The embedded control system may include a dilution control configured to receive inputs regarding one or both of a mass flow rate of the oxidant and a mass flow rate of the dilute oxidant stream and calculate a mass flow ratio of the oxidant to the dilute oxidant.

[0047] The dilution control may be configured to provide an output to an oxidant entry valve that allows for more or less oxidant entering the power generation system to provide a mass flow ratio of oxidant to diluted oxidant within a predetermined range.

[0048] The embedded control system may include a compressor suction pressure control configured to receive an input related to a suction pressure of fluid upstream of a compressor in the power generation system and provide an output to a spillback valve located downstream from the compressor to regulate fluid spillback to a location upstream of the compressor.

[0049] The embedded control system may include a pump speed control configured to receive an input related to the suction pressure upstream of the pump and provide an output to the pump that increases or decreases the pump speed.

[0050] The embedded control system may include a side stream heating control configured to receive an input related to a calculated mass flow requirement for a side stream of the high pressure recirculation stream in the power generation system and provide an output to a side stream valve to increase or decrease the amount of the high pressure recirculation stream in the side stream.

[0051] The power generation system may include a turbine, a compressor downstream from and in fluid communication with the turbine, a pump downstream from and in fluid communication with the compressor, and a heater disposed downstream from and in fluid communication with the pump, and disposed upstream from and in fluid communication with the turbine. In some cases, the power generation system may include a recuperator heat exchanger.

[0052] In one or more embodiments, the present disclosure may provide a method for automatic control of a power generation system. Specifically, the method may include operating a power generation system including a plurality of components including a turbine, a compressor downstream from the turbine and in fluid communication with the turbine, a pump downstream from the compressor and in fluid communication with the compressor, and a heater disposed downstream from the pump and in fluid communication with the pump and disposed upstream from the turbine and in fluid communication with the turbine. Additionally, operating the power generation system may include using one or more controllers associated with the power generation system to receive inputs related to measured parameters of the power generation system and provide outputs that automatically control at least one of the plurality of components of the power generation system. In another embodiment, the method may include one or more of the following steps, which may be combined in any number or order:

[0053] The output may be based on a pre-programmed, computerized control algorithm.

[0054] Operating may include the input of heat through the combustion of a fuel.

[0055] Operating may include the input of heat via a non-combustion heat source.

[0056] The operating may include recirculating the CO2 stream.

[0057] Operating may include producing amounts of CO2 that can optionally be removed from the system, such as input into a pipeline or utilized for another purpose, such as enhanced oil recovery.

[0058] Operating may involve utilizing a working fluid that is repeatedly compressed, heated, and expanded.

[0059] Operating may include using a controller to receive input regarding the power produced by the power generation system and direct one or both of providing an output to a heater to increase or decrease heat production by the heater and providing an output to a fuel valve of the power generation system to allow more or less fuel to be admitted to the power generation system.

[0060] Operating may include using a control unit to receive one or both of an input related to a fuel flow rate and an input related to an oxidant flow rate and direct one or both of providing an output to a fuel valve of the power generation system that allows for more or less fuel entering the power generation system and providing an output to an oxidant valve of the power generation system that allows for more or less oxidant entering the power generation system.

[0061] The method of operating may include using a controller to receive an input related to a temperature of the exhaust stream of the turbine and provide an output to a pump upstream of the turbine that increases or decreases the flow rate of the stream exiting the pump.

[0062] Operating may include using a controller to receive an input related to a suction pressure in the fluid upstream of the pump and provide an output to a spillback valve located upstream of the pump. Specifically, the controller may satisfy one or both of a requirement that the controller moderate fluid spilling back to a location further upstream from the spillback valve and a requirement that the controller moderate fluid removed from the power generation system upstream of the pump.

[0063] Operating may include using a control unit to receive an input related to the pressure of the exhaust stream of the turbine, providing an output to a fluid exhaust valve to allow fluid to exit the exhaust stream, and possibly providing an output to a fluid intake valve to allow fluid to enter the exhaust stream.

[0064] Operating may include using a controller to receive an input regarding the amount of water in a separator included in the power generation system and provide an output to a water removal valve that enables or disables the removal of water from the separator and maintains the amount of water in the separator within a predetermined value.

[0065] Operating may include using a controller to receive inputs related to one or both of a mass flow rate of fuel and a mass flow rate of oxidant introduced into the power generation system and calculate a mass flow ratio of the fuel and the oxidant. Specifically, the controller may provide an output to an oxidant pump that causes the pump power to be varied to affect the mass flow ratio of the fuel and the oxidant in the power generation system.

[0066] Operating may include using a controller to receive an input related to the pressure of the oxidant stream downstream from the oxidant compressor and provide an output to an oxidant bypass valve that allows more or less oxidant to bypass the compressor.

[0067] Operating may include using a controller to receive an input related to a pressure of the oxidant stream upstream of the oxidant compressor and provide an output to a recirculation fluid valve that increases or decreases the amount of recirculation fluid added to the oxidant stream upstream of the oxidant compressor. Specifically, the recirculation fluid may be a substantially pure CO2 stream.

[0068] Operating may include receiving inputs related to one or both of the mass flow rate of the oxidant and the mass flow rate of the dilute oxidant stream using a controller to calculate a mass flow ratio of the oxidant to the dilute oxidant. Specifically, the controller may be configured to provide an output to an oxidant entry valve that allows for more or less oxidant entering the power generation system to provide a mass flow ratio of the oxidant to the dilute oxidant within a predetermined range.

[0069] Operating may include using a control unit to receive an input related to a suction pressure of the fluid upstream of the compressor and provide an output to a spillback valve located downstream from the compressor to modulate fluid spilling back to a location upstream of the compressor.

[0070] Operating may include using a controller to receive an input regarding the suction pressure upstream from the pump and provide an output to the pump that increases or decreases the pump speed.

[0071] The operating may include using a controller to receive an input regarding a calculated mass flow requirement for the side stream of the high pressure recirculation stream and provide an output to a side stream valve to increase or decrease the amount of the high pressure recirculation stream in the side stream. [Means for solving the problem]

[0072] The present disclosure can be characterized in terms of many embodiments. As non-limiting examples, the present disclosure includes at least the following embodiments: It should be clearly understood that any one of the following embodiments of a power generation system with an embedded control system can be combined with one or more of the other embodiments of a power generation system with an embedded control system. Thus, any two, three, four, five, six, seven, eight, nine, ten, eleven, twelve, thirteen, fourteen, fifteen, sixteen, seventeen, eighteen, nineteen, twenty, or twenty-one embodiments could be combined without any limitation to include or exclude any of the embodiments. Similarly, it should be clearly understood that any one of the following embodiments of a method for automatic control of a power generation system can be combined with one or more of the other embodiments of a method for automatic control of a power generation system. Thus, any two, three, four, five, six, seven, eight, nine, ten, eleven, twelve, thirteen, fourteen, fifteen, sixteen, seventeen, eighteen, or nineteen embodiments could be combined without any limitation to the inclusion or exclusion of any of the embodiments.

[0073] Embodiment 1: A power generation system comprising an embedded control system configured for automatic control of at least one component of the power generation system, the control system including at least one control unit configured to receive inputs relating to measured parameters of the power generation system and to provide outputs to at least one component of the power generation system that is subject to automatic control.

[0074] Embodiment 2: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a power controller configured to receive input related to power produced by one or more power generation components of the power generation system.

[0075] Embodiment 3: The power control unit is a requirement to provide power to a heater component of the power generation system to increase or decrease heat production by the heater component; The requirement to provide power to a fuel valve that allows for the addition and subtraction of fuel from the power system. 5. The power generation system according to any preceding or following embodiment, configured to satisfy one or both of the following requirements:

[0076] Embodiment 4: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a fuel / oxidizer ratio control configured to receive one or both of an input related to a fuel flow rate and an input related to an oxidizer flow rate.

[0077] Embodiment 5: The fuel / oxidizer ratio control unit is A requirement to provide power to a fuel valve that allows for more or less fuel to be admitted to the power generation system; A requirement to provide output to an oxidizer valve that allows for the addition or subtraction of oxidizer from the power generation system. 5. The power generation system according to any preceding or following embodiment, configured to satisfy one or both of the following requirements:

[0078] Embodiment 6: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a pump controller configured to receive an input related to a temperature of an exhaust stream of a turbine in the power generation system and provide an output to a pump that increases or decreases the flow rate of the stream exiting the pump upstream of the turbine.

[0079] Embodiment 7: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a pump suction pressure control section configured to receive an input related to a suction pressure in a fluid upstream of a pump in the power generation system and provide an output to a spillback valve located upstream of the pump.

[0080] Embodiment 8: The pump suction pressure control unit is A requirement to moderate the amount of fluid spilling back to a location further upstream from the spillback valve; and The requirement to moderate the fluid removed from the power system upstream of the pump; 5. The power generation system according to any preceding or following embodiment, configured to satisfy one or both of the following requirements:

[0081] Embodiment 9: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a pressure regulation control configured to receive an input related to a pressure of an exhaust stream of a turbine in the power generation system, provide an output to a fluid exhaust valve to allow fluid to exit the exhaust stream, and optionally provide an output to a fluid intake valve to allow fluid to enter the exhaust stream.

[0082] Embodiment 10: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a water separator control configured to receive an input regarding the amount of water in a separator of the power generation system and provide an output to a water removal valve that enables or disables the removal of water from the separator and maintains the amount of water in the separator within a predetermined value.

[0083] Embodiment 11: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes an oxidant pump controller configured to receive inputs related to one or both of a mass flow rate of fuel and a mass flow rate of oxidant in the power generation system and calculate a mass flow ratio of fuel to oxidant.

[0084] Embodiment 12: A power generation system according to any preceding or following embodiment, wherein the oxidant pump control is configured to provide an output to the oxidant pump that varies the pump power to affect the mass flow ratio of fuel to oxidant in the power generation system.

[0085] Embodiment 13: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes an oxidant pressure control configured to receive an input related to the pressure of the oxidant stream downstream from the oxidant compressor and provide an output to an oxidant bypass valve that increases or decreases the oxidant bypassing the compressor.

[0086] Embodiment 14: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes an oxidant pressure control section configured to receive an input related to the pressure of the oxidant stream upstream of the oxidant compressor and provide an output to a recirculation fluid valve that increases or decreases the amount of recirculation fluid from the power generation system added to the oxidant stream upstream of the oxidant compressor.

[0087] Embodiment 15: The power generation system according to any preceding or following embodiment, wherein the recirculating fluid is a substantially pure CO2 stream.

[0088] Embodiment 16: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a dilution control configured to receive inputs related to one or both of the mass flow rate of the oxidant and the mass flow rate of the diluted oxidant stream and calculate a mass flow ratio of the oxidant to the diluted oxidant.

[0089] Embodiment 17: A power generation system according to any preceding or following embodiment, wherein the dilution control unit is configured to provide an output to an oxidant entry valve that allows for more or less oxidant entering the power generation system to provide a mass flow ratio of oxidant to diluted oxidant within a predetermined range.

[0090] Embodiment 18: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a compressor suction pressure control section configured to receive an input related to the suction pressure of a fluid upstream of a compressor in the power generation system and provide an output to a spillback valve located downstream from the compressor to regulate the amount of fluid spilling back to a location upstream of the compressor.

[0091] Embodiment 19: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a pump speed control configured to receive an input relating to a suction pressure upstream of the pump and provide an output to the pump that increases or decreases the pump speed.

[0092] Embodiment 20: A power generation system according to any preceding or following embodiment, wherein the embedded control system includes a side stream heating control configured to receive an input related to a calculated mass flow requirement for a side stream of a high pressure recirculation stream in the power generation system and provide an output to a side stream valve that increases or decreases the amount of high pressure recirculation stream in the side stream.

[0093] Embodiment 21: The turbine, a compressor downstream from and in fluid communication with the turbine; a pump downstream from the compressor and in fluid communication with the compressor; a heater disposed downstream from the pump and in fluid communication with the pump, and disposed upstream from the turbine and in fluid communication with the turbine; The power generation system according to the embodiment described above.

[0094] Embodiment 22: A method for automatic control of a power generation system, comprising: The turbine, a compressor downstream from and in fluid communication with the turbine; a pump downstream from the compressor and in fluid communication with the compressor; operating a power generation system having a plurality of components including a heater disposed downstream from the pump and in fluid communication with the pump, and a heater disposed upstream from the turbine and in fluid communication with the turbine; The operating includes using one or more controllers associated with the power generation system to receive inputs related to measured parameters of the power generation system and provide outputs that automatically control at least one of a plurality of components of the power generation system.

[0095] Embodiment 23: A method according to any preceding or following embodiment, wherein the output is based on a pre-programmed, computerized control algorithm.

[0096]

[0031] Embodiment 24: The operating step includes using a controller to receive input regarding the power produced by the power generation system; A movement that provides power to the heater to increase or decrease heat production by the heater; Providing power to the fuel valves in the power generation system that allow the amount of fuel entering the power generation system to be increased or decreased. The method according to any preceding or following embodiment, comprising directing one or both of:

[0097] Embodiment 25: The operating step includes using a controller to receive one or both of an input related to a fuel flow rate and an input related to an oxidizer flow rate; providing power to a fuel valve of the power generation system that allows more or less fuel to be admitted to the power generation system; A movement that provides output to the oxidizer valve of the power generation system that allows the amount of oxidizer to be added to the power generation system. The method according to any preceding or following embodiment, comprising directing one or both of:

[0098] Embodiment 26: A method according to any preceding or following embodiment, wherein the operating includes using a controller to receive an input related to a temperature of the exhaust stream of the turbine and providing an output to a pump upstream of the turbine that increases or decreases the flow rate of the stream exiting the pump.

[0099] Embodiment 27: A method according to any preceding or following embodiment, wherein the operating includes using a control unit to receive an input related to a suction pressure in the fluid upstream of the pump and provide an output to a spillback valve located upstream of the pump.

[0100] Embodiment 28: A requirement for the control unit to moderate the amount of fluid spilling back to a location further upstream from the spillback valve; A requirement for the control to modulate the fluid removed from the power generation system upstream of the pump; 5. The method according to any preceding or following embodiment, wherein one or both of the following conditions are satisfied:

[0101] Embodiment 29: A method according to any preceding or following embodiment, wherein the operating includes using a control unit to receive an input related to the pressure of the exhaust stream of the turbine, providing an output to a fluid exhaust valve to allow fluid to exit the exhaust stream, and optionally providing an output to a fluid intake valve to allow fluid to enter the exhaust stream.

[0102] Embodiment 30: A method according to any preceding or following embodiment, wherein the operating includes using a control unit to receive an input regarding an amount of water in a separator included in the power generation system and providing an output to a water removal valve that enables or disables removal of water from the separator and maintains the amount of water in the separator within a predetermined value.

[0103] Embodiment 31: A method according to any preceding or following embodiment, wherein the operating includes using a control unit to receive input regarding one or both of a mass flow rate of fuel and a mass flow rate of oxidizer introduced into the power generation system, and calculating a mass flow ratio of the fuel to the oxidizer.

[0104] Embodiment 32: A method according to any preceding or following embodiment, wherein the controller provides an output to an oxidant pump that varies the pump power to affect the mass flow ratio of fuel to oxidant in the power generation system.

[0105] Embodiment 33: A method according to any preceding or following embodiment, wherein the operating includes using a controller to receive an input related to a pressure of the oxidant stream downstream from the oxidant compressor and providing an output to an oxidant bypass valve that increases or decreases the oxidant bypassing the compressor.

[0106] Embodiment 34: A method according to any preceding or following embodiment, wherein the operating includes using a controller to receive an input related to the pressure of the oxidant stream upstream of the oxidant compressor and providing an output to a recirculation fluid valve that increases or decreases the amount of recirculation fluid added to the oxidant stream upstream of the oxidant compressor.

[0107] Embodiment 35: The method of any preceding or following embodiment, wherein the recycle fluid is a substantially pure CO2 stream.

[0108] Embodiment 36: A method according to any preceding or following embodiment, wherein the operating includes using a controller to receive inputs related to one or both of the mass flow rate of the oxidant and the mass flow rate of the diluted oxidant stream, and to calculate a mass flow ratio of the oxidant to the diluted oxidant.

[0109] Embodiment 37: A method according to any preceding or following embodiment, wherein the control unit is configured to provide an output to an oxidant entry valve that allows for more or less oxidant entering the power generation system to provide a mass flow ratio of oxidant to diluted oxidant within a predetermined range.

[0110] Embodiment 38: A method according to any preceding or following embodiment, wherein the operating includes using a control unit to receive an input related to the suction pressure of the fluid upstream of the compressor and provide an output to a spillback valve located downstream from the compressor to regulate the amount of fluid spilling back to a location upstream of the compressor.

[0111] Embodiment 39: A method according to any preceding or following embodiment, wherein the operating includes using a control unit to receive an input related to a suction pressure upstream from the pump and provide an output to the pump that increases or decreases the pump speed.

[0112] Embodiment 40: A method according to the previous embodiment, wherein the operating includes using a control unit to receive an input regarding a calculated mass flow requirement for the side flow of the high pressure recirculation stream and provide an output to a side flow valve to increase or decrease the amount of the high pressure recirculation stream in the side flow.

[0113] Having thus described the disclosure in general terms above, reference is now made to the accompanying drawings, which are not necessarily drawn to scale, and in which: [Brief description of the drawings]

[0114] [Figure 1] FIG. 1 is a schematic diagram of a power generation system including components of a control system according to an embodiment of the present disclosure, the control components being specifically configured for thermal control. [Diagram 2] FIG. 2 is a schematic diagram of a power generation system including components of a control system according to another embodiment of the present disclosure, the control components being further configured for control of a heat source. [Diagram 3] FIG. 2 is a schematic diagram of a power generation system including control system components according to another embodiment of the present disclosure, the control components being specifically configured for control of components of a direct fired power generation system. [Figure 4]FIG. 2 is a schematic diagram of a power generation system including components of a control system according to another embodiment of the present disclosure, the control components being specifically configured for control of other components of the direct fired power generation system. [Diagram 5] FIG. 1 is a schematic diagram of a power generation system including components of a control system according to another embodiment of the present disclosure, the control components being specifically configured for control of other components of a direct fired power generation system, including removal of excess mass from the power generation system. [Figure 6] FIG. 1 is a schematic diagram of a power generation system including components of a control system according to another embodiment of the present disclosure, the control system being specifically configured for control of other components of a direct fired power generation system, including removal of excess mass from the power generation system. [Figure 7] FIG. 2 is a schematic diagram of a power generation system including components of a control system according to another embodiment of the present disclosure, the control components being specifically configured for controlling heat input to the power generation system. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0115] The present invention will now be described in more detail hereinafter. However, the present invention may be embodied in many different forms and should not be construed as being limited to the embodiments set forth herein, but rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. As used in this specification and claims, the singular forms "a," "an," and "the" include the plural unless the context clearly dictates otherwise.

[0116] In one or more embodiments, the present disclosure provides systems and methods for control of power generation. The control systems and methods may be utilized for a wide variety of power generation systems. For example, the control system may be applied to one or more systems that combust a fuel to produce heat in a stream, with or without pressure above ambient pressure. The control system may similarly be applied to one or more systems that circulate a working fluid for repeated heating and cooling and / or repeated compression and expansion. Such working fluids may include, for example, one or more of H2O, CO2, and N2.

[0117] Examples of power generation systems and methods that may implement a control system as described herein are disclosed in U.S. Patent No. 9,068,743 to Palmer et al., U.S. Patent No. 9,062,608 to Allam et al., U.S. Patent No. 8,986,002 to Palmer et al., U.S. Patent No. 8,959,887 to Allam et al., U.S. Patent No. 8,869,889 to Palmer et al., U.S. Patent No. 8,776,532 to Allam et al., and U.S. Patent No. 8,596,075 to Allam et al., the disclosures of which are incorporated herein by reference. As a non-limiting example, a power generation system that may utilize a control system as described herein may be configured to combust a fuel with O2 in the presence of a CO2 circulating fluid in a combustor, preferably CO2 is introduced at a pressure of at least about 12 MPa and a temperature of at least about 400°C to provide a combustion product stream containing CO2, preferably the combustion product stream is at a temperature of at least about 800°C. Such a power generation system may further be characterized by one or more of the following:

[0118] The combustion product stream may be expanded across a turbine at a discharge pressure of about 1 MPa or greater to generate power and provide a turbine discharge stream comprising CO2.

[0119] The turbine discharge stream may be passed through a heat exchanger unit to provide a cooled discharge stream.

[0120] The cooling turbine discharge stream may be treated to remove one or more second components other than CO2 to provide a refined discharge stream.

[0121] The refinery discharge stream may be compressed to provide a supercritical CO2 circulating fluid stream.

[0122] The supercritical CO circulating fluid stream is cooled to produce a dense CO circulating fluid (preferably having a density of at least about 200 kg / m 3 ) may be provided.

[0123] The dense CO2 circulating fluid may be pumped to a pressure suitable for input to the combustor.

[0124] The pressurized CO2 circulating fluid may be heated by passing it through a heat exchanger unit using heat recovered from the turbine discharge stream.

[0125] All or a portion of the pressurized CO2 circulating fluid may be further heated with heat not extracted from the turbine discharge stream (preferably the further heating occurs one or more of before, during, or after passing through a heat exchanger).

[0126] The heated, pressurized CO2 circulating fluid may be recirculated to the combustor (preferably the temperature of the heated, pressurized CO2 circulating fluid entering the combustor is up to about 50° C. lower than the temperature of the turbine discharge stream).

[0127] The control system of the present disclosure may be particularly useful in connection with power generation methods such as those illustrated above due to the need to provide precise control of multiple parameters for multiple streams, such as parameters that require precise control to provide desired performance and safety. For example, in one or more embodiments, the control system may be useful in connection with one or more of the following functions:

[0128] The control system may be useful in allowing differential speed control of the power generating turbine and the compressor utilized to compress the stream that finally expands through the turbine. This is an advantage over conventional gas turbines where the compressor and turbine are mounted on the same shaft. This conventional configuration does not allow the compressor to operate at variable speed. A constant rotational speed and suction conditions results in a substantially constant mass throughput to the compressor and therefore to the turbine. This can be influenced through the use of suction guide vanes, restricting the airflow entering the compressor, thereby reducing the mass throughput. In accordance with the present disclosure, the use of a pump between the compressor and turbine provides a significant level of control of the power generating system. This allows for decoupling of the mass throughput of the compressor-pump linkage from the rotational speed of the turbine-compressor-generator linkage.

[0129] The control system may be useful in controlling the suction and / or discharge pressure of a turbine that expands a heated gas stream. The heated gas stream may be mostly CO2 (wt%).

[0130] The control system may be useful in controlling the exhaust temperature of a turbine.

[0131] The control system may be useful in controlling the operation of a power generation system using a CO2 compression means to raise and consequently maintain the pressure of CO2 from the turbine exhaust to that of the turbine inlet.

[0132] The control system may be useful in controlling the removal of the net amount of CO2 formed from carbon in the combustor fuel gas at any point in the CO2 compression means from turbine exhaust pressure to turbine suction pressure.

[0133] The control system may be useful in controlling the operation of a power generation system that heats a recirculated high pressure CO2 stream and ensures heat recovery from the cooled turbine exhaust to provide optimal flow of heated recirculated high pressure CO2 to the combustor at the highest possible temperature while cooling the hot turbine exhaust in an economizer heat exchanger.

[0134] The control system may be useful in optimizing heat input to the recirculated CO2 stream from an external heat source (e.g., at a temperature of about 400°C or less), controlling the temperature differential in the economizer heat exchanger to less than 400°C, maximizing the amount of recirculated CO2 that may be heated against the cooled turbine exhaust stream, and minimizing the temperature differential at the hot end of the economizer heat exchanger.

[0135] The control system can be useful in controlling fuel flow to the combustor to ensure that the products of combustion when mixed with the high pressure heated recirculated CO2 stream form an inlet gas stream to the turbine at the required temperature and pressure.

[0136] The control system may be useful in controlling the oxygen flow to the combustor to obtain a desired excess CO2 concentration in the turbine exhaust stream and ensure complete combustion of the fuel.

[0137] The control system may be useful in controlling the operation of a power generation system so that the turbine exhaust stream leaving the economizer heat exchanger can be further cooled by ambient cooling means to maximize condensation of water formed in the combustion process and avoid net water production from fuel gas combustion with other fuel or combustion-derived impurities.

[0138] In one or more embodiments, a power generation system suitable for implementing a control system as described herein may be configured for heating via methods other than via fossil fuel combustion. As one non-limiting example, solar power may be used to supplement or replace heat input from the combustion of fossil fuels in a combustor. Similarly, other heating means may be used. In some embodiments, forms of heat input to the CO2 recycle stream at temperatures below 400° C. may be used. For example, condensate streams, gas turbine exhaust, adiabatic compressed gas streams, and / or other high temperature fluid streams that may be above 400° C. could be utilized.

[0139] In some embodiments, the control system may be useful in controlling the turbine discharge temperature, specifically at a maximum value determined by the maximum allowable temperature of the economizer heat exchanger utilized. Such control may be based on the turbine suction and discharge pressures and the temperature difference of the hot end in which the heat exchanger operates.

[0140] The control system of the present disclosure may be defined by one or more functions where a parameter (e.g., a measured parameter and / or a calculated parameter) may be associated with one or more executable actions. The executable actions may include one or more actions to regulate the flow of fluid in the system, such as through opening or closing one or more valves. By way of non-limiting example, the measured parameters in the control system of the present disclosure may include fluid flow rate, pressure, temperature, liquid level, fluid volume, and fluid composition, etc. The measured parameters may be measured using any suitable device, such as a thermocouple, pressure sensor, transducer, photodetector, flow meter, analytical equipment (e.g., UV-VIS spectrometer, IR spectrometer, mass spectrometer, gas chromatography, high performance liquid chromatography, etc.), gauge, and the like. The calculated parameters in the control system of the present disclosure may include, for example, compressor (e.g., CO2 compressor) power consumption, pump (e.g., CO2 pump) power consumption, cryogenic oxygen plant power consumption, fuel heat input, pressure drop (e.g., pressure drop across a heat exchanger) of one or more fluid streams, temperature difference (e.g., temperature difference across a hot end of a heat exchanger and / or a cold end of a heat exchanger), turbine power output, generator power output, and system efficiency. The calculated parameters could be calculated, for example, by a computerized supervisory control system based on the measured parameters.

[0141] FIG. 1 illustrates an embodiment of the present disclosure, specifically a control system that may be used in a closed power cycle. The control system is particularly useful in systems and methods that do not require direct control of the amount of heat entering the system, for example, in solar applications. In this configuration, a working fluid circulates through a heater 12, a turbine 10 connected to a generator 11, a first heater / cooler 16, a compressor 30, a second heater / cooler 18, and a pump 20. Optionally, a recuperator heat exchanger 50 may be included such that heat in the working fluid stream 101b exiting the turbine 10 can be recovered into a working fluid stream 101g and exited as working fluid stream 101b to be further heated by the heater 12.

[0142] Heat entering the power generation system at heater 12 is added to the working fluid, preferably at high pressure (e.g., about 10 bar or more, about 20 bar or more, about 50 bar or more, about 80 bar or more, about 100 bar or more, about 150 bar or more, about 200 bar or more, or about 250 bar or more), to provide a high pressure heated working fluid stream 101a. This stream passes through turbine 10, expands to a lower pressure, and exits as working fluid stream 101b. Parameter check location 13 is configured downstream of turbine 10 and upstream of first heater / cooler 16 (and possibly upstream of recuperator heat exchanger 50, if present), and includes a temperature sensor or thermocouple or the like. Controller 2 (which may be considered a pump controller) directs and / or collects one or more temperature readings (which readings may be continuous or periodic) at parameter check location 13. Controller 2 directs power adjustments as needed for pump 20 to maintain a substantially constant temperature at parameter check location 13. For example, the controller 2 may control the speed of the pump 20 in response to a temperature reading at the parameter check location 13. In this manner, the controller 2 may be configured to maintain a desired temperature in the working fluid stream 101b independent of the amount of heat input to the system at the heater 12, and similarly independent of the inlet temperature of the turbine 10. This is particularly beneficial in that the pump 20 can be controlled to deliver a precise mass flow rate of working fluid at a precise pressure as dictated by the inlet temperature to the turbine 10 as dictated by the amount of heat input to the heater 12.

[0143] Such dynamic control may affect one or more other parameters in the power generation system illustrated in FIG. 1. For example, a change in flow rate through the pump 20 will cause a change in the suction pressure immediately upstream from the pump in the working fluid stream 101f. To maintain the desired controllability of the pump 20, the pump suction condition should be kept as constant as possible within a predetermined range. The second heater / cooler 18 may be useful in maintaining the suction temperature at the pump 20 at a desired value. To maintain a substantially constant suction pressure of the pump 20, the controller 3 (which may be considered as the pump suction pressure controller) may be configured to monitor a pressure sensor or transducer or the like located at the parameter check location 23, and the controller 3 may use pressure readings therefrom to control a spillback valve 31, which may be configured to allow more or less fluid from the working fluid stream 101e to spill back to the parameter check location 44, which may be located anywhere in the working fluid stream 101c. Thus, the controller 3 may be configured to essentially control the amount of recirculation flow around the compressor 30 via the spillback valve 31. Thus, the pressure at the parameter check site 23 can be increased by decreasing the fluid flow through the spillback valve 31, and can be decreased by increasing the fluid flow through the spillback valve. It may also be desired that a substantially constant pressure be maintained in the working fluids 101b and 101c as fluid spills back into the working fluid stream 101c. As such, the parameter check site 13 may also include pressure sensors or transducers, etc. Temperature and pressure sensors may be configured in the same parameter check site, or different parameter check sites in the working fluid stream 101b may be utilized for the respective sensors.

[0144] Since parameter check site 13 is in fluid communication with parameter check site 44 and parameter check site 43, the individual pressures at sites 13, 44, and 43 may differ substantially only due to inherent pressure losses through the equipment and piping. Controller 4 may be configured to monitor a pressure sensor, transducer, or the like located at parameter check site 43, and controller 4 may be configured to control valve 41 to allow fluid from working fluid stream 101d to enter or leave the system to maintain a substantially constant pressure at parameter check site 44. Thus, parameter check site 44 may include a pressure sensor, transducer, or the like that controller 4 may monitor, as needed. Alternatively, since parameter check sites 43 and 44 are in fluid communication, the measured pressure at parameter check site 43 may be considered to be substantially the same as the pressure at parameter check site 44. Valve 41 may be configured to remove and / or add fluid to the working fluid stream to maintain a desired pressure. In some embodiments, instead of a single valve 41, there may be two valves: a first valve (i.e., a fluid exhaust valve) configured to allow fluid to be discharged to a low pressure sink, and a second valve (i.e., a fluid intake valve) configured to allow fluid to be admitted from a high pressure source.

[0145] In some embodiments, the illustrated system may be controlled without or without the use of valve 41, and instead, controller 3 may operate to substantially prevent surge by compressor 30. In such an embodiment, controller 2 may still operate to manage temperature at parameter check site 13, and control may seemingly be fully closed loop, which may be particularly useful for indirect heating power generation cycles. For example, in one or more embodiments, heater 12 may be configured for the provision of solar heating above a predetermined heat level, so that the power generation system can dynamically respond to changes in solar incidence and substantially self-adjust to produce as much power as possible. Such a configuration may be maintained as well when additional heat is added at heater 12 from another source, either continuously or intermittently.

[0146] 1, the compressor 30 receives its intake working fluid stream from the turbine 10 and its exhaust working fluid stream is ultimately delivered to the pump 20. The compressor 30 may be axially mounted to the turbine 10, and the operating conditions of the compressor may be substantially unchanged based on control of the turbine exhaust conditions.

[0147] Although control unit 2, control unit 3, and control unit 4 are shown and discussed as separate control units, it is understood that the individual control units may be configured as parts of a larger unit. For example, a single control unit could include multiple sub-units that can be independently connected to their designated parameter check locations and the devices they control (e.g., pump 20, spillback valve 31, and valve 41). Furthermore, the control units may be configured substantially as subroutines in an overall control unit (e.g., a computer or similar electronic device) with multiple inputs and multiple outputs designated for the individual parameter checks and controlled devices.

[0148] In embodiments including a recuperative heat exchanger 50, control of the temperature at the parameter check location 13 can be particularly important. By maintaining the temperature at the parameter check location 13 at or substantially close to a steady-state value, the temperature profile in the recuperative heat exchanger 50 can also be kept substantially constant. At a minimum, such a control scheme is beneficial because it can reduce or eliminate thermal cycling of piping, heat exchangers, and other high temperature equipment utilized in the system, significantly increasing component life.

[0149] Figure 2 illustrates an embodiment of the present disclosure, in which a power generation system is shown that is substantially identical to the power generation system illustrated in Figure 1. In the system of Figure 2, a separate controller 1 (which may be considered a power controller) is included and may be configured to monitor various values ​​and direct a number of control commands.

[0150] In one or more embodiments, the controller 1 may be configured to measure and / or receive measurements related to the power output of the generator 11. In some embodiments, the controller 1 may be configured to direct the heat input through the heater 12 to generate the required power. In this manner, if the power output at the generator 11 is more or less than the desired output, the heat input through the heater 12 can be decreased or increased to deliver the desired power output. Similarly, monitoring the power output with the controller 1 can allow the heat input to be dynamically changed to provide a substantially constant power output. As a non-limiting example, when using solar heating for the heater 12, the power output at the generator 11 may be used as a trigger so that more mirrors could be directed towards the collection tower to increase the heat output when the power output is insufficient to meet a predefined heating algorithm, such as when the power output drops below a predetermined value and / or the power output may be automatically increased once a day when usage is expected to increase. As another non-limiting example, multiple heat sources may be utilized, where a first heat source may be utilized primarily and a second heat source may be automatically activated when the power output of the generator 11 is insufficient. For example, solar heating could be combined with combustion heating, with one heat source being the primary heat source and another being the secondary heat source that supplements the primary heat source.

[0151] As more or less heat is added to the system, the turbine suction temperature will change and after expansion through the turbine the temperature at the parameter check location 13 will change. Thus, one or more of the control functions described above with respect to Figure 1 may similarly be implemented in a system such as that shown in Figure 2.

[0152] FIG. 3 further illustrates an embodiment of the present disclosure, specifically a control system that may be used in a semi-closed power cycle. The control system is specifically useful in systems and methods where the cycle is a direct-fired oxy-fuel cycle that burns a carbonaceous fuel with oxygen. As shown, at least two components that may be combined to provide an exothermic reaction are introduced into the system through valves 14 and 71. Although the components are shown to be introduced directly into the turbine 10, in one or more embodiments, the components may be introduced into a reactor, such as a combustor. In some embodiments, the turbine 10 is a multi-stage component that includes a reaction or combustion chamber upstream from the turbine. In FIG. 3, the portion of the component 10 below the dotted line may be a combustion chamber, and the portion of the component 10 above the dotted line may be a turbine. As non-limiting examples, valve 14 may be configured to supply a fuel, such as natural gas or other fossil fuel, via a meter, and valve 71 may be configured to supply an oxidant, such as air or substantially pure oxygen (e.g., at least 95%, at least 98%, at least 99%, or at least 99.5% pure oxygen), via a meter.

[0153] 3, controller 1 may be configured to monitor the power output of generator 11. Based on the measured power output, controller 1 controls fuel valve 14 to allow more or less fuel to the power generation system. As more or less fuel is added to the power generation system, controller 7 (which may be considered a fuel / oxidizer ratio controller) compares the oxidizer flow rate at parameter check location 72 with the fuel flow rate ratio at parameter check location 15, and controller 7 commands oxidizer valve 71 to allow more or less oxidizer therethrough to maintain a predetermined ratio of fuel to oxygen.

[0154] The reaction (e.g., combustion) products pass through the turbine 10 (or the turbine portion of a combined reactor / turbine) and exit as a turbine exhaust stream. As an example, when natural gas and oxygen are metered through valves 14 and 71, the primary products in the turbine exhaust stream will be H2O and CO2. The turbine exhaust stream may pass through a recuperator heat exchanger 50 (although such components are optional) and then through the first heater / cooler 16. The turbine exhaust stream is then treated in a water separator 60, where water may be removed through valve 61. A substantially pure CO2 stream exits the top of the separator 60 and passes through the compressor 30 (with a fraction withdrawn through valve 41). The compressed recycle CO2 stream exiting the compressor 30 passes through the second heater / cooler 18 and then through the pump 20 to provide a high pressure recycle CO2 stream. This may be returned to the turbine 10 (possibly passing through the recuperator heat exchanger 50 and heated with heat drawn from the turbine exhaust stream). The substantially pure CO2 stream may comprise at least 95%, at least 97%, at least 98%, at least 99%, or at least 99.5% CO2 by weight.

[0155] As illustrated in Figure 3, the control system used in the exemplary power generation system includes controller 2, controller 3, and controller 4, which may function substantially the same as those described above with respect to the systems of Figures 1 and 2. Controller 6 (which may be considered a water separator controller) is also utilized to monitor the water level in separator 60, which may include one or more sensors adapted to provide a water level output that can be read by controller 6. Based on the received water level signal, controller 6 directs valve 61 to open at precise intervals and durations to maintain the water level in separator 60 at a desired level. It should be understood that although measurements are referenced in terms of water level, volume, mass, or other parameters may be utilized to provide signals to controller 6.

[0156] 4 illustrates a further embodiment of the present disclosure, in which a control system is shown that may be used in a semi-closed power cycle that utilizes an artificial air source. The control system is particularly useful in systems and methods where the cycle is a direct-fired oxy-combustion cycle that burns a carbonaceous fuel with oxygen. The control unit 1 again monitors the power output of the generator 11 and meters the fuel input through valve 14 accordingly.

[0157] As illustrated in FIG. 4, fuel and oxidant enter the combustion section of the dual combustor / turbine 10, and the turbine exhaust stream exits the turbine section. The turbine exhaust stream may pass through a recuperator heat exchanger 50 (although such a component is optional) and then through the first heater / cooler 16. The turbine exhaust stream is then processed in a water separator 60, where water may be removed through valve 61. A substantially pure CO2 stream exits the top of the separator 60 and passes through the compressor 30 (with a fraction withdrawn through valve 41). The compressed recirculated CO2 stream exiting the compressor 30 passes through the second heater / cooler 18 and then through the pump 20 to provide a high pressure recirculated CO2 stream, which may be returned to the dual combustor / turbine 10 (possibly heated by heat drawn from the turbine exhaust stream through the recuperator heat exchanger 50).

[0158] In this configuration, the oxidizer enters through valve 111 and passes through a junction tube 114 where CO2 can be combined with the oxidizer. The oxidizer stream (possibly diluted with the CO2 stream) passes through heater / cooler 22, is pressurized by compressor 90, passes through heater / cooler 24, and finally passes through pump 80. Controller 8 (which can be considered an oxidizer pump controller) measures the ratio between the mass flow rate of fuel (read at parameter check location 26) and the mass flow rate of oxidizer (read at parameter check location 82). Based on the calculated ratio, controller 8 can instruct variable speed pump 80 to vary pump power to enable delivery of oxidizer at the correct mass flow rate, maintaining the desired oxidizer to fuel ratio at the required pressure. In this way, the amount of oxidizer delivered to the power generation system is consistently at the correct flow rate and the correct pressure for passage to the dual combustor / turbine 10. For example, if the pressure at the parameter check location 82 could rise due to back pressure from the combustor / turbine 10, the control 8 could be configured to command the pump 80 to operate at a different speed appropriate to provide the correct pressure and mass flow rate of the oxidizer. Based on the pressure reading obtained at the parameter check location 93, the control 9 (which could be considered an oxidizer pressure control) could instruct the spillback valve 91 to increase or decrease the pressure at the parameter check location 93 by allowing more or less fluid to spill back (or be recirculated) to a point upstream of the compressor 90 (specifically, between the junction 114 and the heater / cooler 22). Pressure could also be monitored at the parameter check location 102 (which is the pressure corresponding to the suction of the compressor 90). Based on this pressure, the control 100 (which could be considered an oxidizer pressure control) could instruct the valve 103 not to divert all or a portion of the fluid upstream of the compressor 30 to the junction 114 in order to maintain a substantially constant pressure at the parameter check location 102. The substantially pure CO2 stream diverted through valve 103 may be utilized to dilute the oxidant, and control unit 100 may similarly be configured to increase or decrease flow through valve 103 to provide the desired dilution.The mass flow rate of the CO2 stream provided through valve 103 may be measured at parameter check site 113, and the mass flow rate of the oxidant provided through valve 111 may be measured at parameter check site 112. Control 110 (which may be considered a dilution control) may be configured to calculate the ratio of the flows at check sites 112 and 113, and may be configured to direct valve 111 to allow more or less oxidant to enter the system to ensure the correct ratio is maintained.

[0159] In one or more embodiments, the control system according to the present disclosure may be specifically configured to provide mass control over a wide range of pressures. Low pressure mass control (e.g., mass control at ambient pressures up to about 10 bar, up to about 8 bar, or up to about 5 bar) may be achieved similarly to that described for control unit 4 above. Specifically, control unit 4 may be configured to open and close valve 41 to remove excess mass from the power generation system. For example, in a system that utilizes a recirculated CO2 stream as the working fluid and burns fossil fuels, excess CO2 may be formed. To maintain an accurate mass balance in the system, all or a portion of the formed CO2 may be drawn through valve 41. For mass control, the amount of fluid drawn through valve 41 may be calculated based on the known stoichiometry of the combustion reaction, and control unit 4 may be configured to control the mass flow rate through valve 41 accordingly. If desired, one or more sensors may be utilized to measure and / or calculate the fluid mass downstream from the combustor and / or to measure and / or calculate the fluid mass ratio between the streams between the combustor and the valve 41 with respect to the streams downstream from the compressor 30 and / or pump 20.

[0160] In the embodiment illustrated in FIG. 5, instead of control 3 and control 4 as described above, another control is provided to dump excess mass from the power generation system at substantially the same pressure as the discharge pressure of compressor 30 (which is substantially the same as the suction of pump 20). As described above, the speed of pump 20 is controlled by the exhaust temperature of turbine 10 via control 2. However, in the embodiment illustrated in FIG. 5, the suction pressure of compressor 30 is controlled. Specifically, parameter check point 54 may include a pressure sensor, and control 35 (which may be considered a compressor suction control) may be configured to open and close valve 31 based on the pressure at the suction of compressor 30 as measured at parameter check point 54. If the pressure at parameter check point 54 begins to drop, control 35 may be configured to open valve 31 and allow fluid to spill back to a point upstream of parameter check point 54 (in the illustrated embodiment, spill back toward parameter check point 44), causing the pressure at parameter check point 54 to increase. If the pressure at parameter check site 54 begins to increase, control 35 may be configured to close valve 31 to reduce the amount of fluid spilling back and lower the pressure at parameter check site 54 .

[0161] In addition to controlling the speed of the pump 20, the suction pressure of the pump may also be controlled. Specifically, the pressure read at the parameter check location 23 may be utilized by the controller 75 (which may be considered a pump speed controller) which may be configured to open and close a valve 88. Thus, the suction pressure of the pump 20 is controlled at the valve 88 by removing excess fluid from the power generation system, thereby providing for maintaining a desired system pressure.

[0162] In the embodiment illustrated in FIG. 6, the power control system is configured similarly to the structure illustrated in FIG. 5, except that the valve 88 is not used. In this illustrated embodiment, the compressor 30 operates with suction pressure control as described with respect to FIG. 5, and the pump 20 also operates with suction pressure control. Specifically, the pressure read at the parameter check location 23 may be utilized by the control 75, which may be configured to adjust the speed of the pump 20 to maintain a precise pressure controlled suction and output as defined by another parameter of the combustion cycle. The temperature obtained from the parameter check location 13 may also be used again by the control 2, which is configured to direct the fluid through the valve 115 to control the temperature of the exhaust from the turbine 10. By allowing more fluid to leave the power generation system (or by keeping more fluid in the power generation system) through the valve 115, the suction pressure (and thus the mass flow rate) through the turbine 10 may be controlled, which in turn may control the exhaust temperature of the turbine 10.

[0163] In one or more embodiments, the power system shown in FIG. 7 may include a turbine 10 coupled to an electric generator 11. A fuel stream is metered through valve 14, and oxygen is metered through valve 117, and the fuel is combusted with the oxygen in a combustor 10. The fuel and oxygen are mixed with a heated high pressure recirculated CO2 stream 120 exiting an economizer heat exchanger 50. The combustion gases pass to a turbine 10b. The turbine discharge stream is cooled in the economizer heat exchanger 50 against a high pressure recirculated CO2 stream 119 and further cooled to near ambient temperature in a first heater / cooler 16. In some embodiments, the first heater / cooler 16 may be an indirect heat exchanger using, for example, cooling water, or may be a direct contact heat exchanger that both cools the turbine exhaust stream and condenses the water. The near ambient temperature stream enters a water separator 60 which discharges a condensate stream through a valve 61. The stream may contain fuel or combustion derived impurities in oxidized states such as SO2 and NO2. In the case of a direct contact cooler, the unit acts as a combined gas cooler gas / water contactor and liquid phase separator. The recycled CO2 stream 116 enters a CO2 recycle compressor 30 which increases its pressure (e.g., from about 30-70 bar to about 80 bar). The compressor 30 is provided with a recycle CO2 line 45 having a valve 31 to reduce the pressure and return a portion of the compressor flow to the suction at point 44. The net CO2 product contains all the carbon from the fuel gas stream which is subsequently oxidized in the turbine combustor and is exhausted from the compressor as a stream through valve 41. The net CO2 product may be delivered at a pressure from the compressor suction to the pump discharge. The recycled CO2 stream leaving the compressor 30 is cooled to near ambient temperature in a second heater / cooler 18. The density is typically increased from about 0.7 kg / liter to about 0.85 kg / liter. The concentrated supercritical CO2 is pumped in a multi-stage pump 20, typically to 320 bar. The recycled CO2 stream 119 leaving the pump 20 enters the economizer heat exchanger 50.

[0164] A portion 119a of the recycled CO2 stream leaving pump 20 is heated in heat exchanger 56 against heating stream 53, which may be from any source, such as heat extracted from an air separation unit. This stream 119a is typically heated to a temperature of about 200°C to about 400°C. The heated stream then passes through heat exchanger 50 at an intermediate location and is mixed again with the high pressure recycled CO2 stream 119. The system is controlled by control valves that regulate the fluid flows. The system is provided with sensors that measure flow, pressure, temperature, and gas composition. These measurements may be provided to a digital control system that regulates the power plant, for example, using control algorithms with stored supervisory control programs. Output from the control system regulates the opening of the control valves, as well as the speed of pump 20 and other system functions. The objective is to achieve a predetermined high efficiency operation at the required power output, optimal start-up conditions, controlled either ramp-up or ramp-down rates, and shutdown and response to system malfunctions. Although such a digital control system and control algorithms will be described with respect to the system of FIG. 7, it should be understood that such disclosure applies equally to other embodiments described herein, including those described with respect to FIGS. 1 through 6 and 8.

[0165] The functional control of the system may be defined by the relationship between the variables measured by the sensors and the response of a particular control valve. One or more embodiments of a control system that can be utilized in connection with the embodiments disclosed herein include the following:

[0166] The fuel flow rate through the valve 14 may be controlled by the power demand placed on the electrical generator 58 .

[0167] The speed of the pump 20 may be used to control its discharge flow rate. Specifically, the flow rate set point may be varied to maintain a given turbine discharge temperature.

[0168] The discharge pressure of the CO2 compressor 30 may be maintained at a constant predetermined value by varying the setting of the compressor recirculation flow control valve 31.

[0169] The exhaust of CO2 produced in the power cycle may be controlled by flow control valve 41. The set point of this flow control may be varied to maintain a constant suction pressure to the CO2 compressor and turbine discharge. In some embodiments where the exhaust through valve 41 is at the discharge of compressor 30, the control system may be configured to vary the flow through valve 41 and through recirculation valve 31.

[0170] The amount of recirculated high pressure CO2 heated by the added heat source in heat exchanger 56 may be controlled by flow control valve 42 and controller 17 (which may be considered a side flow heating controller). The CO2 flow set point is controlled to minimize the temperature difference at the hot end of heat exchanger 50 between the high pressure CO2 recirculation stream 120 and the turbine exhaust stream at location 13 to less than 50°C.

[0171] The discharge of the condensate with fuel and combustion-derived oxygenated impurities may be controlled by maintaining a constant water level in the water separator 60 or in the sump of an alternative direct contact cooler. In the latter case, excess water is discharged while the discharge stream is pumped through a cooling water heat exchanger and introduced into the top of the direct contact cooler above the packing bed.

[0172] With reference to FIG. 5, the flow rate of oxygen to the combustor may be controlled by flow control valve 111. The flow control setpoint may be varied to maintain a predetermined ratio of oxygen to fuel gas, which will ensure a typical 1% excess of oxygen over stoichiometric to ensure complete fuel combustion as well as oxidation of fuel-borne impurities. To control the heat-resistant flame temperature of the integrated turbine combustor, it may be useful to dilute the oxygen with a quantity of CO2 to produce a CO2 plus O2 gas mixture with an O2 concentration between 15% and 40%, typically 25% (molar). The oxygen stream may be diluted with a CO2 stream obtained from the suction line of the CO2 compressor 30. The extracted CO2 passes through flow control valve 103 and enters a junction tube 114, which may be a static mixer in some embodiments. The flow control setpoint for valve 91 may be adjusted by a supervisory computer program to maintain a constant pressure at location 102. The setting of the oxygen suction flow control valve 111 may be adjusted to maintain a fixed ratio of oxygen to carbon dioxide flow entering the mixer 114. The mixed oxidant stream passes through the heater / cooler 22. The cooled oxidant stream enters the oxidant compressor 90 where it is compressed, typically to a pressure range of about 90 bar to about 120 bar. The setting of the flow control valve 91 may be varied to control the discharge pressure of the oxidant compressor 90. The oxidant compressor 90 may operate at a fixed suction pressure and a fixed discharge pressure. The discharge from the compressor may be cooled to about ambient temperature in the heater / cooler 24. Its density is increased, for example, to a range of about 0.6 kg / liter to about 0.75 kg / liter. The rich supercritical oxidant stream 82 is pumped in a multi-stage centrifugal pump 80, typically to a pressure of 320 bar. The high pressure discharge stream leaving pump 80 enters economizer heat exchanger 50 where it is heated by a portion of the heat rejected from the cooled turbine discharge stream. The oxidant flow rate may be controlled by adjusting the speed of oxidant pump 80. The flow rate set point may be adjusted to maintain a predetermined ratio of oxygen to fuel gas, which will typically provide 1% excess oxygen over that required for stoichiometric fuel gas combustion to ensure complete combustion of the fuel gas as well as oxidation of fuel borne impurities.

[0173] Those skilled in the art, having the benefit of the teachings in the foregoing description, will come to mind numerous variations and other embodiments of the invention which fall within the scope of the invention. It is to be understood, therefore, that the invention is not limited to the specific embodiments disclosed, and that variations and other embodiments are expected to be included within the scope of the appended claims. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.

Claims

1. A power plant, at least one compressor configured to compress a stream of working fluid; at least one combustor configured to receive at least a portion of the streams of fuel, oxidant, and compressed working fluid and configured to provide a combustion product stream; at least one turbine configured to receive the combustion product stream and expand the combustion product stream to generate electricity; one or more components configured to process the combustion product stream to remove at least water therefrom and provide the working fluid stream, the one or more components disposed downstream from the at least one turbine and upstream from the at least one compressor; a controller configured to execute one or more control algorithms effective to maintain a designated mass of the working fluid at one or more points within the power plant; A power plant equipped with

2. The power plant of claim 1 , wherein the controller is configured to control a mass flow rate of the working fluid through an escape valve located at a point between an exhaust of the at least one turbine and an inlet of the at least one compressor.

3. 3. The power plant of claim 2, wherein the controller is configured to calculate a mass of working fluid to be forced through the escape valve using a stoichiometry of combustion of fuel and oxidant in the at least one combustor.

4. 3. The power plant of claim 2, wherein the controller is configured to calculate a mass of working fluid to be forced through the escape valve based on readings obtained from one or more sensors configured to measure and / or calculate a fluid mass downstream of the at least one combustor and upstream of the at least one compressor.

5. 3. The power plant of claim 2, wherein the controller is configured to calculate a mass flow rate of working fluid to be passed through the escape valve based on readings obtained from one or more sensors configured to measure and / or calculate a fluid mass ratio between a stream between the at least one combustor and the escape valve relative to a stream downstream of the at least one compressor.

6. 2. The power plant of claim 1, wherein the controller is configured to control a mass flow rate of the working fluid through a spillback valve configured to receive the working fluid from a point downstream of the at least one compressor and upstream of the at least one combustor, and configured to direct the working fluid to a point upstream of the at least one compressor and downstream of the at least one turbine.

7. 7. The power plant of claim 6, wherein the controller is configured to calculate a mass of working fluid to be forced through the spillback valve based on readings obtained from one or more sensors configured to measure and / or calculate a suction pressure at a point immediately upstream of the at least one compressor.

8. 10. The power plant of claim 1, further comprising a pump configured to receive the stream of working fluid from the at least one compressor and pump the stream of working fluid to an increased pressure for input to the at least one combustor.

9. The power plant of claim 8 , wherein the controller is configured to control a mass flow rate of the working fluid through an escape valve located at a point between the at least one compressor and the pump.

10. 10. The power plant of claim 9, wherein the controller is configured to calculate a mass flow rate of working fluid to be forced through the relief valve based on readings obtained from one or more sensors configured to measure and / or calculate a suction pressure at a point immediately upstream of the pump.

11. The power plant of claim 1 , further comprising a recuperator heat exchanger configured to extract heat from the combustion product stream between the at least one turbine and the one or more components.

12. The power plant of claim 11 , wherein the recuperator heat exchanger is configured to add heat to one or more streams delivered to the at least one combustor.

13. A power plant, at least one compressor configured to compress a stream of working fluid; at least one combustor configured to receive at least a portion of the streams of fuel, oxidant, and compressed working fluid and configured to provide a combustion product stream; at least one turbine configured to receive the combustion product stream and expand the combustion product stream to generate electricity; one or more components configured to process the combustion product stream and provide the stream of working fluid, the one or more components disposed downstream from the at least one turbine and upstream from the at least one compressor; a controller configured to execute one or more control algorithms effective to maintain a designated mass of the working fluid at one or more points within the power plant, the controller configured to control a mass flow rate of the working fluid through a spillback valve configured to receive working fluid from a point downstream of the at least one compressor and upstream of the at least one combustor, and configured to direct working fluid to a point upstream of the at least one compressor and downstream of the at least one turbine; A power plant equipped with

14. A power plant, at least one compressor configured to compress a stream of working fluid; at least one combustor configured to receive at least a portion of the streams of fuel, oxidant, and compressed working fluid and configured to provide a combustion product stream; at least one turbine configured to receive the combustion product stream and expand the combustion product stream to generate electricity; one or more components configured to process the combustion product stream and provide the stream of working fluid, the one or more components disposed downstream from the at least one turbine and upstream from the at least one compressor; a controller configured to execute one or more control algorithms effective to maintain a designated mass of the working fluid at one or more points within the power plant; a recuperator heat exchanger configured to extract heat from the combustion product stream between the at least one turbine and the one or more components; A power plant equipped with

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