EA041135B1 - POWER GENERATION SYSTEM AND METHOD OF ITS AUTOMATIC CONTROL - Google Patents

Description

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Technical field

The present invention relates to systems and methods for the automatic control of power generation (power generation) installations, in particular, which can be combined with such installations.

State of the art

There is an urgent need to develop energy systems that can meet growing consumer demands. Although a lot of work has been devoted to systems that do not use fossil fuels, the cost factors and availability of fossil fuels, especially coal and natural gas (and waste hydrocarbons, such as residual petroleum products), create a constant need for systems configured in such a way that burn such fuels, in particular with high efficiency and complete carbon capture. To meet these requirements, there is a constant drive to develop control systems capable of providing precise control of power systems.

Disclosure of invention

The present invention provides a power generation system with an integrated control system configured to automatically control at least one component of the power generation system, comprising: a heater;

a power generator and at least one controller, wherein at least one controller is configured to receive an input signal downstream from the heater and provide an output signal to adjust the flow of fuel to the heater and thereby control the heat output of the heater, and at least at least one controller is configured to receive the same or a different input signal downstream from the heater and provide an output signal to control the flow rate of the working fluid (hereinafter also referred to as the working fluid) to the heater.

In particular embodiments, at least one controller includes a power controller configured to receive an input signal related to the power generated by the power generator and provide an output signal to adjust the flow of fuel to the heater and thereby control the heat output of the heater. The power controller is preferably configured to fulfill one or both of the following requirements:

providing an output signal to the heater to increase or decrease the heat output of the heater;

providing an output signal to the fuel valve to pass more or less fuel to the heater.

The at least one controller includes a pump controller configured to receive an input relating to an exhaust stream temperature downstream of the heater and provide an output to a pump to control the flow rate of the working fluid to the heater.

The at least one controller includes a fuel/oxidizer ratio controller configured to receive one or both of an input relating to fuel flow to the heater and an input relating to oxidizer flow to the heater and to perform one or both of the following: :

providing an output signal to the fuel valve to pass more or less fuel to the heater;

providing an output signal to the oxidant valve to allow more or less oxidant to pass into the heater.

The at least one controller includes an oxidizer pump controller configured to receive an input relating to one or both of a fuel mass flow rate and an oxidizer mass flow rate supplied to the heater and calculate a ratio of fuel and oxidizer mass flow rates, and the oxidizer pump controller is configured to the ability to provide an output signal to the oxidizer pump to change the power of the pump so as to affect the ratio of the mass flow rates of fuel and oxidizer supplied to the heater.

The at least one controller includes an oxidizer pressure controller configured to receive an input relating to the pressure of the oxidizer stream upstream from the oxidizer compressor and provide an output so as to cause more or less working fluid to be added to the upstream oxidizer stream. from the oxidizer compressor.

The working fluid is a stream of essentially pure CO2.

The heater is a combustion chamber.

In another particular embodiment, the heater is a solar powered heater.

- 1 041135

The heater is configured to receive heat from a fluid flow with a temperature above 400°C.

The present invention also provides a method for automatically controlling a power generation system, comprising burning an oxidizer fuel in a heater in the presence of a working fluid and exhausting an exhaust stream from the heater;

generating power using the exhaust stream;

using at least one controller to receive at least one input signal downstream from the heater and provide an output signal to adjust the flow of one or both of the fuel or oxidizer to the heater and thereby control the amount of heat in the exhaust stream, and use at least one controller for receiving the same or a different input signal downstream from the heater and providing an output signal for controlling the flow rate of the working fluid to the heater.

In particular embodiments, at least one controller includes a power controller that receives an input relating to the power generated by the power generator and provides an output to adjust the fuel flow to the heater and thereby control the amount of heat in the exhaust stream.

The power controller is configured to fulfill one or both of the following requirements:

providing an output signal to the heater to increase or decrease the heat output of the heater;

providing an output signal to the fuel valve to allow more or less fuel to pass into the heater.

The at least one controller includes a pump controller that receives an input relating to an exhaust stream temperature downstream of the heater and provides an output to a pump to control the flow rate of the working fluid to the heater.

The at least one controller includes a fuel/oxidizer ratio controller that receives one or both of an input relating to fuel flow to the heater and an input relating to oxidizer flow to the heater and provides one or both of the following:

providing an output signal to the fuel valve for passing more or less fuel to the heater;

providing an output signal to an oxidizer valve to allow more or less oxidizer to pass into the heater.

The at least one controller includes an oxidizer pump controller that receives an input relating to one or both of fuel mass flow and oxidizer mass flow to the heater and calculates a fuel to oxidizer mass flow ratio, and the oxidizer pump controller provides an output. to the oxidizer pump to change the power of the pump so as to affect the ratio of the mass flow rates of fuel and oxidizer supplied to the heater.

At least one controller includes an oxidizer pressure controller that receives an input relating to the pressure of the oxidizer stream upstream of the oxidizer compressor and provides an output causing more or less working fluid to be added to the oxidizer stream upstream of the oxidizer compressor. .

Control systems and methods suitable for controlling one or more parameters of a power generation system may be provided. In particular, control systems may provide control of one or more parameters from the group including pressure, temperature, flow, and flow composition for one or more flows in the power generation system. Control systems can ensure the optimum efficiency of the power generation system. The control systems may also provide control of such functions of the power generation system as starting the system, stopping the system, changing the input stream(s) in the system, changing the output stream(s) in the system, managing emergencies occurring in the system, and other similar aspects, relating to the power generation system.

The present invention uses control systems suitable for use in power generation installations. For example, a power generation plant may be one in which a fuel (eg, hydrocarbons, in particular hydrocarbon gas) is combusted in a combustion chamber in an atmosphere of substantially pure oxygen at a pressure of about 12 MPa or more, with the addition of a circulating CO ₂ stream, resulting in mixed flow of combustion products and circulating CO2. In some embodiments, power generation may differ in one or more of the following features, which may be combined in any number and order.

- 2 041135

The mixed flow may be passed through a power turbine with an outlet pressure of approximately 10 bar.

Turbine exhaust can be cooled in an economizer heat exchanger by preheating the circulating CO2 stream.

The turbine exhaust may be further cooled to near ambient temperature and the condensed water may be removed.

To form a circulating CO2 stream, the CO2 gas stream can be compressed to a pressure equal to or close to the turbine inlet pressure using a gas compressor followed by a density increasing pump.

The pure CO2 product produced in the combustor can be removed at any pressure between turbine inlet and outlet pressures.

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

The flow rate of the fuel gas can be adjusted to provide the desired turbine output.

The outlet temperature of the turbine can be controlled by a CO2 pump.

The compressor CO ₂ outlet pressure can be controlled by recirculating the compressed CO ₂ stream back to the compressor inlet.

The flow rate of the net CO2 product from the combustion of the fuel gas and removed from the system can be used to control the inlet pressure of the CO2 compressor.

The temperature difference between the temperature of the turbine exhaust entering the economizer heat exchanger and the temperature of the circulating CO2 stream leaving the economizer heat exchanger can be controlled so that it does not exceed 50°C by controlling the flow rate in the part of the circulating CO2 stream heated from the booster heat source .

The flow rate of clean liquid water and fuel-derived contaminants removed from the system can be controlled by the level in the liquid water separator.

The oxygen flow rate can be controlled to maintain the ratio of oxygen flow rate to fuel gas flow rate at a level that causes a predetermined excess of oxygen in the turbine inlet stream, which ensures complete combustion of the fuel gas and oxidation of the components included in the fuel gas.

An oxygen stream at a pressure corresponding to the pressure at the CO2 inlet of the compressor may be mixed with some of the CO2 withdrawn from the CO2 inlet of the compressor to produce an oxidant stream containing from about 15 to about 40 mol% oxygen, which can result in a decrease in the temperature of the adiabatic flames in the combustion chamber.

The flow of oxidant necessary to obtain the desired ratio of oxidizer to fuel gas can be controlled by the speed of the oxidizer pump.

The oxidizer compressor outlet pressure can be controlled by recirculating the compressed oxidizer stream to the compressor inlet.

The oxidizer compressor inlet pressure can be controlled by varying the flow rate of diluent CO ₂ mixed with oxygen to form the oxidizer stream.

The ratio of oxygen to CO2 in the oxidizer stream can be controlled by changing the oxygen stream.

Oxygen may be supplied to the power generation system at a pressure at least as high as the turbine inlet pressure, and the oxidizer stream desirably has a molar concentration of oxygen in the range of about 15% to about 40%.

The ratio of oxygen to fuel gas can be controlled by the amount of oxygen flow.

The ratio of oxygen to CO ₂ in the oxidant stream can be controlled by the amount of dilution CO ₂ flow taken from the compressor CO ₂ outlet.

In any of the embodiments discussed herein, adjusting the first parameter by the second parameter may specifically mean that the second parameter is measurable (eg, by a sensor) or otherwise monitored, or that the second parameter is computed by a computer based on additionally provided information, lookup tables, or allowed values, and the controller initiates a sequence of control commands based on the measured or calculated parameter, so as to adjust the first parameter accordingly (for example, by opening or closing the corresponding valve (hereinafter referred to as the valve), increasing or decreasing the pump power, etc.). In other words, the second parameter is used as a trigger signal for the controller to make adjustments to the first parameter.

The present invention provides power generation systems including an integrated control system that can be configured to automatically control at least one component of the power generation system. In particular, the control system may include at least one controller configured to receive an input signal related to a measured parameter of the power generation system and provide an output signal to at least one component of the power generation system to be automatically controlled. The power generation system and the control system may also be characterized by one or more of the following provisions, which may be combined in any number and order.

The power generation system can be configured to provide heat by burning fuel.

The power generation system may be configured to provide heat from a non-combustion source.

The power generation system can be configured to recycle the CO2 stream.

The power generation system may be configured to generate some amount of CO2, which may optionally be removed from the system, such as by being fed into a mains or used for other purposes such as secondary oil recovery methods.

The power generation system may be configured to use a working fluid that is cyclically compressed, heated, and expanded.

The embedded control system may include a power controller configured to receive an input signal related to power generated by one or more power output components of the power generation system.

The power controller may be configured to meet one or both of the following requirements: provide an output to a heating component of the power generation system to increase or decrease heat generation from the heating component; provide an output signal to a fuel valve (valve) to allow more or less fuel to flow into the power generation system.

The integrated control system may comprise a fuel/oxidizer ratio controller configured to receive a fuel flow rate signal, or an oxidizer flow rate signal, or both.

The fuel/oxidizer ratio controller may be configured to fulfill one or both of the following requirements: provide an output signal to the fuel valve to allow more or less fuel to enter the power generation system; provide an output signal to the oxidizer valve to allow more or less oxidizer to enter the power generation system.

The integrated control system may include a pump controller configured to receive an input relating to the temperature of the turbine exhaust stream in the power generation system and provide an output signal to a pump located upstream of the turbine to increase or decrease the flow rate leaving the pump. .

The integral control system may include a pump suction pressure controller configured to receive an input relating to fluid pressure from the upstream side of the pump in the power generation system and provide an output to an upstream bypass/recirculation valve. from the pump.

The suction pressure controller (suction side) of the compressor may be configured to fulfill one or both of the following requirements: cause more or less fluid to flow back to a point upstream of the bypass valve; cause more or less fluid to be withdrawn from the power generation system at a point upstream of the pump.

The built-in control system may include a pressure control controller configured to receive an input relating to the pressure in the turbine exhaust stream in the power generation system and provide an output signal to a fluid diversion (release) valve configured to remove fluid from the exhaust stream. , and optionally provide an output signal to the fluid diversion valve to pass fluid into the exhaust stream.

The built-in control system may include a water separator controller configured to receive an input relating to the amount of water in the separator of the power generation system and provide an output to a dewatering valve to allow or block the removal of water from the separator, and to maintain the amount of water. in the separator in a given volume.

The onboard control system may include an oxidizer pump controller configured to receive an input relating to either fuel mass flow or oxidizer mass flow or both in the power generation system and calculate the fuel to oxidizer mass flow ratio.

The oxidizer pump controller is configured to provide an output signal to the oxidizer pump, varying pump power to affect the fuel to oxidizer mass flow ratio in the power generation system.

The built-in control system may include an oxidizer pressure controller configured to receive an input relating to pressure in the oxidizer stream downstream of the oxidizer compressor and provide an output to an oxidizer bypass valve causing more or less bypass of the oxidizer to bypass the compressor.

The integral control system may include an oxidizer pressure controller configured to receive an input relating to pressure in the oxidizer stream downstream of the oxidizer compressor and provide an output to a fluid recirculation valve causing more or less fluid from the power generation system to be injected into the stream. oxidizer upstream of the oxidizer compressor. In particular, the circulating fluid may be a stream of substantially pure CO2.

The integrated control system may include a dilution controller configured to receive an input relating to either oxidant mass flow, or oxidant diluent mass flow, or both, and calculate the ratio of oxidant to oxidant diluent flow rates.

The dilution controller may be configured to provide an output to the oxidizer inlet valve, allowing more or less oxidizer to the power generating system such that the mass flow ratio of oxidizer to oxidizer diluent is within a predetermined range.

The integral control system may include a compressor suction pressure controller configured to receive an input relating to fluid suction pressure upstream of the compressor in the power generation system and provide an output to a bypass valve downstream of the compressor causing bypass. more or less fluid to a point upstream of the compressor.

The built-in control system may include a pump speed controller configured to receive an input relating to pressure from the suction side upstream of the pump and provide an output to the pump to increase or decrease the speed of the pump.

The integrated control system may include a bleed heat controller configured to receive input relating to calculated bleed mass flow requirements from the high pressure recycle stream in the power generation system and provide an output to the bleed valve to increase or decrease the proportion high pressure recirculation stream directed to the bypass stream.

The power generation system may include a turbine; a compressor installed downstream of the turbine and in communication with the turbine; a pump installed downstream of the compressor and in communication with the compressor; and a heater installed downstream of the pump and in communication with the pump, as well as upstream of the turbine and in communication with the turbine, optionally, the power generation system may comprise a recuperative heat exchanger.

The present invention provides automatic control of the power generation system. In particular, the operation/operation of a power generation system may be provided, comprising a group of components, which includes a turbine; a compressor installed downstream of the turbine and in communication with the turbine; a pump installed downstream of the compressor and in communication with the compressor; and a heater installed downstream of the pump and in communication with the pump, and upstream of the turbine and in communication with the turbine. In addition, the operation of the power generation system may include the use of controllers associated with the power generation system, designed to receive an input signal related to the measured parameter of the power generation system, and provide an output signal that automatically regulates the operation of at least one component from a group of components of the power generation system. . In additional embodiments, such a method may include one or more of the following steps, which may be combined in any number and in any combination.

The output signal can be obtained on the basis of a software control algorithm embedded in the computer.

Operation may include heat input from fuel combustion.

Operation may include heat from a source other than fuel combustion.

The operation may include recycling the CO2 stream.

The operation may include the production of some CO2, which may optionally be removed from the system, for example, by supply to a mains or used for other purposes, such as in secondary oil recovery methods.

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The operation may include the use of a working fluid that is cyclically compressed, heated and expanded.

The operation may include using the controller to receive an input relating to the power generation system and control one or both of the following: provide an output to a heating component of the power generation system to increase or decrease heat generation from the heating component; providing an output signal to the fuel valve of the power generation system for passing more or less fuel to the power generation system.

Operation may include using the controller to receive either a fuel flow input or an oxidizer flow input, or both, and to control one or both of the following: provide an output signal to the fuel valve of the power generation system to pass more or less fuel into the power generation system; providing an output signal to an oxidizer valve of the power generation system to allow more or less oxidizer into the power generation system.

The operation may include using the controller to receive an input relating to the temperature of the turbine exhaust stream and provide an output to a pump upstream of the turbine to increase or decrease the flow rate leaving the pump.

The operation may include using the controller to receive an input relating to the pressure of the fluid flow at the suction above the pump and provide an output signal to a bypass valve located upstream of the pump. In particular, one or both of the following requirements must be met: the controller causes more or less fluid to flow back to a point upstream of the bypass valve; the controller causes more or less fluid to be withdrawn from the power generation system at a point upstream of the pump.

Operation may include using a controller to receive an input relating to pressure in the turbine exhaust stream and provide an output to the diversion valve and allow fluid to be diverted from the exhaust stream, and optionally to provide an output to the diversion valve. and the possibility of introducing fluid into the exhaust stream.

The operation may include using a controller to receive an input relating to the amount of water in the separator introduced into the power generation system and provide an output to a dewatering valve and the ability to divert or not divert water from the separator to maintain the amount of water in the separator at a predetermined volume. .

The operation may include using the controller to receive an input relating to either fuel mass flow or oxidizer mass flow or both in the power generation system and calculate the fuel to oxidizer mass flow ratio. In particular, the controller may provide an output signal to the oxidizer pump by changing the power of the pump in such a way as to affect the mass flow ratio of fuel and oxidizer in the power generation system.

The operation may include using the controller to receive an input relating to the pressure in the oxidant stream downstream of the oxidizer compressor and provide an output signal to the oxidizer bypass valve so as to cause more or less oxidant to bypass the compressor.

Operation may include using a controller to receive an input relating to pressure in the oxidant stream above the oxidizer compressor and provide an output to a fluid recirculation valve so as to cause more or less recirculation fluid to be added to the oxidizer stream at a point upstream. downstream of the oxidizer compressor. In particular, the circulating fluid may be a stream of substantially pure CO2.

The operation may include using the controller to receive an input relating to either the oxidant mass flow rate or the oxidant diluent mass flow stream, or both, and calculate the ratio of the mass flow rates of the oxidant to the oxidant diluent. In particular, the controller may be configured to provide an output to the oxidizer inlet valve, allowing more or less oxidizer to the power generating system such that the mass flow ratio of oxidizer to oxidant diluent is within a predetermined range.

The operation may include using the controller to receive an input relating to the upstream suction pressure of the compressor in the fluid stream and provide an output signal to a bypass valve located downstream of the compressor causing more or less fluid to be bypassed to a point upstream. By

- 6 041135 flow from the compressor.

The operation may include using the controller to receive an input relating to pressure from the suction side upstream of the pump and provide an output signal to the pump to increase or decrease the speed of the pump.

The operation may include using the controller to receive an input relating to the calculated mass flow requirement in the bleed stream from the high pressure recycle stream and provide an output signal to the bleed valve to increase or decrease the proportion of the high pressure recycle stream directed to the bleed stream.

Below are various options for systems and methods that reflect the ideas of the present invention.

Option 1: a power generation system comprising an integrated control system configured to control at least one component of the power generation system and including at least one controller unit configured to receive an input signal related to the measured parameters of the power generation system and provide providing an output signal to at least one component of the power generation system to be automatically controlled.

Option 2: A power generation system according to any of the preceding or subsequent embodiments, wherein the integrated control system includes a power controller configured to receive an input signal related to power generated by one or more power generating components of the power generation system.

Option 3: The power generation system of any of the preceding or subsequent embodiments, wherein the power controller is configured to fulfill one or both of the following requirements:

provide an output signal to the heating component of the power generation system, increasing or decreasing the heat output of the heating component;

provide an output signal to the fuel valve, passing more or less fuel to the power generation system.

Option 4: The power generation system of any one of the preceding or subsequent embodiments wherein the integrated control system includes a fuel/oxidizer ratio controller configured to receive either a fuel flow rate signal or an oxidizer flow rate signal, or both. signal.

Option 5: The power generation system of any one of the preceding or subsequent embodiments wherein the fuel/oxidizer ratio controller is configured to perform one or both of the following requirements:

provide an output signal to the fuel valve, passing more or less fuel to the power generation system;

provide an output signal to the oxidizer valve, allowing more or less oxidizer into the power generation system.

Option 6: A power generation system as in any one of the preceding or subsequent embodiments, wherein the integrated control system includes a pump controller configured to receive an input relating to the temperature of the turbine exhaust stream in the power generation system and provide an output to the pump, located upstream of the turbine, to increase or decrease the flow rate leaving the pump.

Option 7: A power generation system as in any one of the preceding or subsequent embodiments wherein the integral control system includes a pump suction pressure controller configured to receive an input relating to fluid pressure on the suction side upstream of the pump in the generation system power, and provide an output signal to a bypass valve upstream of the pump.

Option 8: The power generation system of any one of the preceding or subsequent embodiments, wherein the pump suction pressure controller is configured to perform one or both of the following requirements:

causing more or less fluid to flow to a point upstream of the bypass valve;

cause more or less fluid to be diverted from the power generation system at a point upstream of the pump.

Option 9: A power generation system as in any one of the preceding or subsequent embodiments, wherein the integrated control system includes a pressure control controller configured to receive an input relating to turbine exhaust flow pressure in the power generation system and provide an output signal to a bleed valve fluid medium, configured to remove fluid from the exhaust stream, and optionally provide an output signal to the fluid removal valve and pass fluid into the exhaust stream.

Option 10: A power generation system as in any one of the preceding or subsequent embodiments, wherein the integrated control system includes a water separator controller configured to receive an input relating to the amount of water in the separator of the power generation system and provide an output signal to a water diversion valve , allowing or blocking the removal of water from the separator, as well as maintaining the amount of water in the separator in a given volume.

Option 11: The power generation system of any one of the foregoing or subsequent embodiments, wherein the onboard control system includes an oxidizer pump controller configured to receive an input relating to either fuel mass flow rate or oxidizer mass flow rate, or both in power generation system, as well as calculate the ratio of mass flow rates of fuel and oxidizer.

Embodiment 12: A power generation system as in any of the preceding or subsequent embodiments, wherein the oxidizer pump controller is configured to provide an output to the oxidizer pump by varying pump power to affect the fuel to oxidizer mass flow ratio in the power generation system.

Option 13: A power generation system as in any one of the preceding or subsequent embodiments, wherein the integral control system includes an oxidizer pressure controller configured to receive an input relating to pressure in the oxidizer stream downstream of the oxidizer compressor and provide an output signal to the oxidizer bypass valve , causing more or less oxidant to flow around the compressor.

Option 14: The power generation system of any one of the preceding or subsequent embodiments, wherein the integral control system includes an oxidizer pressure controller configured to receive an input relating to pressure in the oxidizer stream downstream of the oxidizer compressor and provide an output signal to a fluid recirculation valve. causing more or less fluid from the power generation system to be introduced into the oxidizer stream upstream of the oxidizer compressor.

Option 15: The power generation system of any one of the preceding or subsequent embodiments wherein the recirculating fluid is a stream of substantially pure CO ₂ .

Option 16: A power generation system as in any one of the preceding or subsequent embodiments, wherein the integrated control system includes a dilution controller configured to receive an input relating to or either oxidant mass flow or oxidant diluent stream mass flow. both, as well as calculate the ratio of the costs of the oxidizer and the oxidizer diluent.

Option 17: The power generation system of any one of the preceding or subsequent embodiments, wherein the dilution controller is configured to provide an output signal to the oxidizer inlet valve, allowing more or less oxidizer into the power generation system such that the mass flow ratio of oxidizer to diluent oxidizer was in the specified range.

Option 18: A power generation system as in any one of the preceding or subsequent embodiments, wherein the integrated control system includes a compressor suction pressure controller configured to receive an input relating to fluid suction pressure upstream of the compressor in the power generation system, and provide an output signal to a bypass valve located downstream of the compressor and causing the bypass of more or less fluid to a point upstream of the compressor.

Option 19: A power generation system as in any of the preceding or subsequent embodiments, wherein the integral control system includes a pump speed controller configured to receive an input relating to pressure from the upstream side of the pump and provide an output signal to the pump to increase or decrease pump speed.

Option 20: The power generation system of any one of the preceding or subsequent embodiments, wherein the integrated control system includes a bleed heat controller configured to receive an input relating to calculated bleed mass flow requirements from a high pressure recycle stream in the system. generating power, and providing an output signal to the bypass valve so as to increase or decrease the proportion of the high pressure recirculation stream directed to the bypass stream.

Option 21: power generation system according to any of the preceding or subsequent

- 8 041135 embodiments, containing a turbine;

a compressor installed downstream of the turbine and in communication with the turbine;

a pump installed downstream of the compressor and in communication with the compressor; and a heater installed downstream of the pump and in communication with the pump and installed upstream of the turbine and in communication with the turbine.

Option 22: a method for automatically controlling a power generation system relating to the operation of a power generation system containing a group of components including a turbine;

a compressor installed downstream of the turbine and in communication with the turbine;

a pump installed downstream of the compressor and in communication with the compressor; and a heater installed downstream of the pump and in communication with the pump and installed upstream of the turbine and in communication with the turbine;

wherein said operation includes using one or more controllers embedded in the power generation system to receive inputs relating to measured parameters of the power generation system and provide output signals that automatically control at least one of a group of power generation system components.

Option 23: A method according to any of the preceding or subsequent embodiments, wherein the output signal is obtained based on a software control algorithm embedded in the computer.

Option 24: A method according to any one of the preceding or subsequent embodiments wherein said operation uses a controller to receive an input signal related to a power generation system and control one or both of the following operations:

providing an output signal to the heater to increase or decrease the heat output of the heater;

providing an output signal to the fuel valve of the power generation system to pass more or less fuel to the power generation system.

Option 25: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using the controller to receive either a fuel flow input or an oxidizer flow input, or both, and to control one or both of the following operations:

providing an output signal to the fuel valve of the power generation system to pass more or less fuel to the power generation system.

providing an output signal to an oxidizer valve of the power generation system to allow more or less oxidizer into the power generation system.

Option 26: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using the controller to receive an input relating to the temperature of the turbine exhaust stream and providing the output to a pump located upstream of the turbine to increase or reducing the flow rate leaving the pump.

Option 27: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using a controller to receive an input relating to the pressure of a fluid flow upstream of the pump and provide an output signal to a bypass valve located upstream of the pump.

Option 28: A method according to any one of the preceding or subsequent embodiments, wherein one or both of the following requirements are met:

the controller causes more or less fluid to flow back to a point upstream of the bypass valve;

the controller causes more or less fluid to be withdrawn from the power generation system at a point upstream of the pump.

Embodiment 29: A method according to any one of the preceding or subsequent embodiments, wherein said operation includes using a controller to receive an input relating to pressure in the turbine exhaust stream and cause an output signal to be provided to a fluid bleed valve and able to bleed fluid from the exhaust flow, as well as optionally providing an output signal to the fluid diversion valve and the possibility of introducing fluid into the exhaust stream.

Embodiment 30: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using a controller to receive an input relating to the amount of water in the separator introduced into the power generation system and provide an output signal to a dewatering valve and be able to divert or not drain water

- 9 041135 from the separator to maintain the amount of water in the separator in a given volume.

Option 31: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using the controller to receive an input relating to either fuel mass flow or oxidizer mass flow or both in the power generation system, and to calculation of the ratio of mass flow rates of fuel and oxidizer.

Embodiment 32: A method as in any one of the preceding or subsequent embodiments, wherein the controller provides an output to the oxidizer pump by varying the power of the pump so as to affect the fuel to oxidizer mass flow ratio in the power generation system.

Option 33: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using a controller to receive an input relating to pressure in the oxidizer stream downstream of the oxidizer compressor and provide an output signal to the oxidizer bypass valve so as to cause more or less oxidizer bypassing the compressor.

Option 34: The method of any one of the preceding or subsequent embodiments wherein said operation includes using a controller to receive an input relating to pressure in the oxidant stream upstream of the oxidizer compressor and provide an output to a fluid recirculation valve so as to cause addition more or less recycle fluid into the oxidizer stream at a point upstream of the oxidizer compressor.

Option 35: The process of any one of the preceding or subsequent embodiments, wherein the recycle fluid is a stream of substantially pure CO ₂ .

Option 36: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using a controller to receive an input relating to either an oxidant mass flow rate or an oxidant diluent stream mass flow rate, or both, and to calculate the ratio of the costs of the oxidizer and the diluent of the oxidizer.

Option 37: A method as in any one of the preceding or subsequent embodiments wherein the controller is configured to provide an output signal to the oxidizer inlet valve by allowing more or less oxidizer into the power generating system such that the mass flow ratio of oxidizer to oxidizer diluent is in specified range.

Option 38: The method of any one of the preceding or subsequent embodiments, wherein said operation includes using the controller to receive an input relating to suction pressure above the compressor in the fluid stream and provide an output signal to a bypass valve located downstream of compressor and causing bypass more or less fluid to a point upstream of the compressor.

Option 39: A method as in any one of the preceding or subsequent embodiments, wherein said operation includes using a controller to receive an input relating to pressure from the suction side upstream of the pump and cause the output to be applied to the pump to increase or decrease the speed of the pump .

Option 40: A method as in any of the preceding embodiments, wherein said operation includes using a controller to receive an input relating to a calculated bleed mass flow requirement from the high pressure recycle stream and provide an output to the bleed valve to increase or reducing the proportion of the high pressure recirculation stream directed to the bypass stream.

Brief description of the drawings

The invention will now be described in more detail with reference to the accompanying drawings, in which, not necessarily to scale, is shown schematically in FIG. 1 shows a power generation system comprising control system components according to embodiments of the present invention, the control components being configured in particular to control temperature;

in fig. 2 shows a power generation system comprising components of a control system according to other embodiments of the present invention, wherein the control components are further configured to control a heat source;

in fig. 3 shows a power generation system comprising components of a control system according to other embodiments of the present invention, wherein the control components are configured, in particular, to control elements of a direct combustion power generation system;

- 10 041135 in FIG. 4 shows a power generation system comprising components of a control system according to other embodiments of the present invention, wherein the control components are configured in particular to control other elements of the direct combustion power generation system;

in fig. 5 is a power generation system comprising components of a control system according to other embodiments of the present invention, wherein the control components are configured, in particular, to control other elements of the direct combustion power generation system, including removing excess mass from the power generation system. ;

in fig. 6 is a power generation system containing components of a control system according to other embodiments of the present invention, wherein the control components are configured, in particular, to control other elements of the direct combustion power generation system, including removing excess mass from the generation system power and in Fig. 7 shows a power generation system comprising components of a control system according to other embodiments of the present invention, wherein the control components are configured, in particular, to control the supply of heat to the power generation system;

Implementation of the invention

Hereinafter, the present invention will be described more fully. The invention, however, may be embodied in many different ways and should not be construed as limited to the embodiments described below, which embodiments are presented so that the description is complete and complete, and the scope of the invention is fully disclosed to a person skilled in the art. In practice, in the foregoing description and in the claims, the use of singular forms includes plurality of objects, unless otherwise expressly stated.

In one or more embodiments, the present disclosure makes use of systems and methods for controlling power generation. Control systems and methods can be used in a wide variety of power generation systems. For example, control systems may be used in one or more systems in which fuel is burned to generate heat to heat a stream that may or may not compress above external pressure. Similarly, control systems can be used in one or more systems in which the working fluid circulates, reheating and cooling, thereby repeatedly contracting and expanding. Such a working fluid may contain, for example, one or more components from the group consisting of H2O, CO2 and N ₂ .

Examples of power generation systems and methods into which the control systems described herein can be incorporated are disclosed in US Pat. ., 8869889 to Palmer et al., 8776532 to Allam et al., 8596075 to Allam et al., the entire contents of which are incorporated herein by reference. As a non-limiting example, a power generation system with which the control system described herein can be used can be configured to combust an O ₂ fuel in the presence of a circulating CO ₂ based fluid in a combustion chamber into which the CO 2 is preferably introduced under pressure through at least about 12 MPa and at a temperature of at least about 400°C, which provides a stream of combustion products containing CO2 and preferably having a temperature of at least about 800°C. Such a power generation system may also have one or more of the following:

The combustion product stream may be expanded in a turbine with an outlet pressure of approximately 1 MPa or more, generating power and providing a turbine exhaust stream containing CO2.

The turbine exhaust stream may be passed through a heat exchanger block to provide a cooled exhaust stream.

The cooled turbine exhaust stream may be treated to remove concomitant components other than CO2, resulting in a clean exhaust stream.

The cleaned exhaust stream can be compressed to provide a circulating supercritical CO ₂ fluid stream.

The supercritical CO2 circulating fluid stream may be cooled to provide a high density CO2 circulating fluid (wherein the density is preferably at least about 200 kg/m ³ ).

The high-density CO2 circulating fluid can be compressed by pumping to a pressure suitable for injection into the combustion chamber.

The CO2-based compressed circulating fluid may be heated as it passes through the heat exchanger block using heat recovered from the turbine exhaust stream.

All or part of the compressed CO ₂ circulating fluid may be optionally

- 11 041135 is heated with heat other than from the turbine exhaust stream (preferably additional heating is provided in one or more ways, such as heating before, during or after passing through the heat exchanger).

The heated, compressed CO2 circulating fluid may be recycled to the combustion chamber (with the temperature of the heated, compressed CO2 circulating fluid entering the combustion chamber preferably less than about 50° C. less than the turbine exhaust flow temperature). ).

The control systems disclosed herein may be particularly applicable to power generation methods such as those illustrated above due to the need for precise control of several parameters of multiple streams requiring precise control to ensure desired process performance and safety. For example, in one or more embodiments, the present control systems may be applicable to perform one or more of the following functions.

The presented control systems can be used to allow separate variable speed control of the power generating turbine and the compressor used to compress the flow, which will eventually expand as it passes through the turbine. This is an advantage over conventional gas turbines where the compressor and turbine are mounted on the same shaft. This known arrangement makes it impossible for the compressor to operate at variable speed. Constant rotational speeds at the inputs result in a substantially constant mass flow to the compressor and hence to the turbine. This can be addressed by the use of inlet vanes which restrict the airflow entering the compressor and thereby reduce the mass flow that is allowed to pass through. According to the present invention, the use of a pump between the compressor and the turbine provides a high level of controllability of the power generation system. This makes it possible to eliminate the interdependence between the mass flow passing through the compressor-pump link and the shaft speed in the turbine-compressor-generator link.

The presented control systems can be useful for controlling the inlet and/or outlet pressure of a turbine in which the heated gas flow expands. The heated gas stream may be predominantly a CO ₂ stream (by weight).

The presented control systems can be useful for controlling the outlet temperature of the turbine.

The presented control systems may be useful for controlling the operation of a power generation system including compression means for raising the CO2 pressure in the turbine outlet stream to the pressure in the turbine inlet stream so that these pressures are maintained at the proper level.

The present control systems may be useful for controlling the removal of net CO2 derived from the carbon contained in the combustor fuel gas at any point in the _CO2 compression means from turbine outlet pressure to turbine inlet pressure.

The presented control systems can be useful for controlling the operation of a power generation system in which hot turbine exhaust is cooled in an economizer heat exchanger, heating the high pressure CO ₂ recirculation stream, which ensures heat recovery from the cooling turbine exhaust and an optimal recirculation flow of heated high pressure CO 2 to the combustion chamber at highest possible temperature.

The presented control systems can be useful for optimizing the heat input to the recirculating CO2 stream (for example, at a temperature of approximately 400°C or less) from an external heat source in order to reduce the temperature difference in the economizer heat exchanger below 400°C in order to achieve the maximum amount of recirculated CO2, which can be heated by the flow of cooling turbine exhaust, and minimizing the temperature difference at the hot end of the economizer heat exchanger.

The presented control systems may be useful for controlling the flow of fuel into the combustor to ensure that the combustion products, when mixed with the high pressure heated CO ₂ recirculation stream, constitute the gas inlet stream to the turbine at the desired temperature and pressure.

The presented control systems can be useful for controlling the flow of oxygen into the combustion chamber, creating the required excess concentration of O2 in the turbine inlet stream, which ensures complete combustion of the fuel.

The presented control systems may be useful for controlling the operation of the power generation system so that the turbine exhaust stream exiting the economizer heat exchanger can be further cooled in the ambient temperature cooling means to ensure maximum condensation of the combustion water and separation of clean water from combustion products of fuel gas together with other fuel or combustion products of harmful impurities formed.

- 12 041135

In one or more embodiments, power generation using the control system described herein may be by heating by methods other than burning fossil fuels. As a non-limiting example, solar power can be used to supplement or replace the heat input from burning fossil fuels in a combustion chamber. Other heating means can be used similarly. In some embodiments, any method of supplying heat to the recycle CO2 stream at a temperature of 400° C. or less may be used. For example, condensed steam, gas turbine exhaust, adiabatically compressed gas streams, and/or other hot fluid streams with temperatures above 400°C may be used.

In some embodiments, it is particularly advantageous to control the turbine outlet temperature near a maximum value determined by the maximum allowable temperature for the economizer heat exchanger used. This regulation can be based on the inlet and outlet pressures and the temperature difference at the hot end of the operating heat exchanger.

Control systems according to the present invention may be characterized by one or more functions, in which a parameter (eg, a measured and/or calculated parameter) may be associated with one or more executable actions. The actions performed may include one or more actions that control the flow of fluid in the system, such as opening and closing one or more valves. As a non-limiting example, according to the present invention, the control system may take into account parameters such as fluid flow, pressure, temperature, liquid level, fluid volume, fluid composition, and the like. The measured parameter can be determined by any suitable device such as thermocouples, pressure sensors, optical detectors, flow meters, analytical equipment (for example, ultraviolet and visible radiation spectrometers, infrared spectrometers, mass spectrometers, gas chromatographs, high resolution liquid spectrometers, etc.), level gauges and similar devices. According to the present invention, in the control system, the calculated parameters may include, for example, compressor power consumption (for example, CO ₂ compressor), pump power consumption (for example, CO ₂ pump), cryogenic oxygen plant power consumption, heat input from fuel, pressure drop (for example, pressure drop at the heat exchanger) for one or more streams, temperature difference (e.g. temperature difference at the hot end of the heat exchanger and/or at the cold end of the heat exchanger), turbine output, generator output and system efficiency. The calculated parameter may be determined, for example, by a computerized supervisory system based on the measured parameters.

In the embodiment in FIG. 1 shows a control system that can be used in particular for a closed energy cycle. This control system is particularly applicable to systems and methods in which direct control of the amount of heat entering the system is not required, such as when using solar installations. In this configuration, the working fluid circulates through heater 12, turbine 10 connected to generator 11, first heater/cooler 16, compressor 30, second heater/cooler 18 and pump 20, optionally a recuperative heat exchanger 50 may be introduced so that heat from the stream 101b of the working fluid exiting the turbine 10 could be transferred to the working fluid stream 101g leaving the heat exchanger as the working fluid stream 101h, which is then heated by the heater 12.

Heat supplied to the power generation system in heater 12 is imparted to a 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 heated high pressure working fluid stream 101a. This flow passes through the turbine 10 and expands to a lower pressure, leaving it as the flow 101b of the working fluid. Downstream of the turbine 10 and upstream of the first heater/cooler 16 (and optionally upstream of the recuperative heat exchanger 50, if present), a parameter measurement post 13 is formed, including a temperature sensor, thermocouple, or the like. The controller 2, which may be referred to as the pump controller, sends and/or collects one or more temperature readings (which may be continuous or intermittent) to the parameter control post 13 . In order to maintain a substantially constant temperature at the parameter control station 13, the controller 2 sends the power control signals necessary to the pump 20. For example, the controller 2 may adjust the speed of the pump 20 depending on the temperature value read at the parameter control station 13. Thus, the controller 2 can be configured to maintain the desired temperature in the flow 101b of the working fluid depending on the amount of heat introduced into the system in the heater 12 and equally depending on the inlet temperature of the turbine 10. The advantage of this approach is that the operation of the pump 20 can be specifically controlled to supply the proper fluid mass flow at the proper pressure,

- 13 041135 depending on the inlet temperature of the turbine 10, determined by the amount of heat introduced in the heat exchanger 12.

Such dynamic control may affect one or more other parameters of the power generation system shown in FIG. 1. For example, a change in flow through pump 20 causes a change in suction pressure in fluid stream 101f immediately upstream of the pump. In order to maintain controllability of the pump 20, the suction conditions for it must remain constant within a predetermined range, as far as possible. A second heater/cooler 18 may be useful to maintain the suction temperature of the pump 20 near a set point. To keep the suction pressure of the pump 20 substantially constant, the controller 3 (which may be referred to as the pump suction pressure controller) can be configured to monitor the pressure sensor, transducer, or similar device located in the parameter control station 23 and still be able to use the pressure readings obtained from them to control the bypass valve 31, which must be configured to allow more or less fluid to be bypassed from the working fluid stream 101e at the parameter control station 44, which can be located anywhere in the working fluid stream 101c body. Therefore, the controller 3 can be configured to control the amount of recirculation flow around the compressor 30 through the bypass valve 31. As such, the pressure at the parameter control station 23 can be increased by decreasing the fluid flow through the bypass valve 31 and can be lowered by increasing the fluid flow medium through this bypass valve. Since fluid is bypassed back into working fluid stream 101c, it may also be desirable to maintain a substantially constant pressure in working fluid streams 101b and 101c. Accordingly, the parameter control post 13 may likewise include a pressure transducer, transducer, or other similar equipment. The temperature sensor and the pressure sensor may be provided in the same parameter control stations or in different parameter control stations, and may be used in the working medium flow 101b to perform the respective measurements.

Since the parameter control post 13 is in flow communication with the parameter control post 44 and the parameter control post 43, the corresponding pressures at posts 13, 44 and 43 can differ significantly only due to internal pressure losses in the equipment and in the lines. The controller 4 may be configured to monitor a pressure sensor, transducer, or similar equipment located at the parameter control station 43, and may be configured to control the valve 41 so as to provide fluid from the working fluid stream 101d to or from the system to maintain a basically constant pressure at the post 44 control parameters. As such, the parameter control station 44 may include a pressure transducer, transmitter, or other similar equipment that can be monitored by the controller 4 if necessary. parameters can be considered basically equal to the pressure at the post 44 control parameters. The valve 41 may be configured to withdraw fluid from the flow of the working fluid and/or enter it to maintain the desired pressure. In some embodiments, two valves may be present instead of one valve 41 - a first valve (i.e., a fluid outlet valve) configured to exit fluid into a lower pressure receiver, and a second valve (i.e., an inlet valve). fluid) configured to receive fluid from a source of higher pressure.

In some embodiments, the present power generation system can be controlled so that valve 41 is either not present or not used, and the controller can operate to largely prevent unwanted vibrations due to the compressor. In such embodiments, the controller 2 can still control the temperature at the parameter control station 13, the control circuitry being a fully closed loop, and such a configuration is particularly suitable for indirectly heated power generation cycles. For example, in one or more embodiments, heater 12 could be configured to provide solar heating to or above a predetermined heating level, and the power generation system could thus be self-regulating, producing the maximum possible power in dynamic response to changes in incident solar radiation. Similarly, such a configuration may occur if heat is continuously or intermittently introduced into the heater 12 from an additional source.

In the one shown in FIG. 1, compressor 30 receives an input working fluid stream from turbine 10 and its output working fluid eventually enters pump 20. Compressor 30 may be mounted on the shaft of turbine 10 and the compressor operating mode may be substantially unchanged by controlling the turbine exhaust. .

Although controller 2, controller 3 and controller 4 are shown and considered as separate controllers, it should be understood that the respective controllers may be part of

- 14 041135 of the larger block. For example, a common control unit may include a group of sub-units that may be individually connected to their specific control stations and devices controlled by them (eg, pump 20, bypass valve 31 and valve 41). In addition, these control units can be implemented essentially as subroutines of a common control device (eg, a computer or similar electronic device) having a group of inputs and a group of outputs for communication with certain parameter control stations and controlled devices.

In embodiments in which the recuperative heat exchanger 50 is introduced, temperature control at the control station 13 may be particularly important. By maintaining the temperature at the control station 13 at or near a steady state level, the temperature profile in the recuperative heat exchanger 50 can also remain substantially constant. At a minimum, this control scheme has the advantage of reducing or eliminating the cyclic effects of thermal loads on piping, heat exchangers and other high temperature equipment used in the system, which in turn can lead to a significant increase in component life.

In FIG. 2 shows a power generation system substantially identical to the power generation system of FIG. 1. In the system of FIG. 2 denotes an additional controller 1 (which can be called a power controller) configured to monitor parameter changes and send some control commands.

In some embodiments, controller 1 is configured to measure and/or receive measurements relating to the power output of generator 11. In some embodiments, controller 1 may be configured to control heat input through heater 12 to generate the required power. Thus, if the power output of the generator 11 is above or below a predetermined value, the heat supply through the heater 12 can either be reduced or increased to establish the required power output. Similarly, monitoring the power output by the controller 1 may allow the heat input to change dynamically so that the power output can be substantially constant. As a non-limiting example, if solar heating is used in heater 12, then the power output can be used for switching where, for example, more mirrors can be used in the solar collector to increase heat output if the power output falls below a certain level, and/or if the output power is not sufficient to implement a predetermined heating algorithm, whereby, for example, the output power can be automatically increased during times of the day when consumption is expected to increase. As another non-limiting example, a heat source group can be used in which the first heat source can be used first and the second heat source is automatically switched on if the output power of the generator 11 is not sufficient. For example, solar heating can be combined with combustion heating, of which one is the primary heat source and the other is an auxiliary heat source in addition to the primary source.

As more or less heat is introduced into the system, the turbine inlet temperature will change and after expansion in the turbine, the temperature at the parameter control station 13 will change. As such, one or more of the control functions described above in connection with FIG. 1 can similarly be performed on the system of FIG. 2.

In FIG. 3 shows a control system that can be used, in particular, for a semi-closed energy cycle. This control system is particularly suitable for systems and methods in which the cycle is a direct combustion cycle of a fuel in an oxygen atmosphere, in which a carbonaceous fuel is burned with oxygen. As shown, at least two components, valve 14 and valve 71, are introduced into the system, capable of providing an exothermic reaction together. These components are shown connected directly to turbine 10, however, in one or more embodiments, they may be connected to a reactor, such as a combustion chamber. In some embodiments, turbine 10 is a multi-stage component including a reaction chamber or combustor located upstream of the turbine. In FIG. 3, the portion of element 10 below the dotted line may be a combustion chamber, and the portion of element 10 above the dashed line may be a turbine. As a non-limiting example, valve 14 may be configured to dispense a fuel, such as natural gas or other fossil fuel, and valve 71 may be configured to dispense an oxidant, such as air or substantially pure oxygen (for example, oxygen with a purity of at least at least 95%, at least 98%, at least 99%, or at least 99.5%).

In the system illustrated in FIG. 3, controller 1 may be configured to monitor the power output of generator 11. Based on the measured power output, controller 1 adjusts valve 14 to allow more or less fuel to be supplied to the power generation system. As more or less fuel enters the power generation system, the controller 7 (which can be called a fuel/oxidizer ratio controller) compares the fuel consumption at the parameter control station 15 with

- 15 041135 oxidizer flow rate at the parameter control post 72 and sends a command to the oxidizer valve 71, providing more or less oxidizer flow through it to maintain a given ratio of fuel to oxidizer.

Reaction products (eg, combustion) pass through turbine 10 (or the turbine section of the reactor/turbine composition) and exit as a turbine exhaust stream. As an example, if natural gas and oxygen are metered into valve 14 and valve 71, then H ₂ O and CO 2 will be the main products in the turbine exhaust stream. The turbine exhaust stream may pass through a recuperative heat exchanger 50 (although such a component is optional) and then pass through a first heater/cooler 16. The turbine exhaust stream is then treated in a water separator 60 from which water may be vented through a valve 61. A substantially pure CO2 stream exits from the top of the separator 60 and is passed through the compressor 30 (in this case, part of it is discharged through the valve 41). The compressed CO2 recirculation stream exiting the compressor 30 is passed through a second heater/cooler 18 and then through a pump 20 to provide a high pressure CO2 recirculation stream that can be sent back to the turbine 10 (optionally passing through a recuperative heat exchanger 50 and being heated by the heat extracted from turbine exhaust flow). The substantially pure CO2 stream may contain CO2 at a concentration (mass) of at least 95%, at least 97%, at least 98%, at least 99%, or at least 99.5%.

As shown in FIG. 3, a control system used in conjunction with an exemplary power generation system includes controller 2, controller 3, and controller 4, which may operate essentially as described above in connection with the systems illustrated in FIG. 1 and FIG. 2. In addition, a controller 6 (which can be called a water separator controller) is used to monitor the water level in the separator 60, possibly including one or more sensors suitable for providing a water level signal that can be read by the controller 6. Based on the obtained the water level signal, the controller 6 can direct the valve 61 to open at the proper intervals and for the proper time to maintain the desired water level in the separator 60. Although the measurement process is related to the water level, it should be understood that in order to provide a signal to the controller 6 may volume, mass or other parameters are used.

In FIG. 4 shows a control system used in particular in a semi-closed energy cycle using a source of conditioned air. This control system is particularly suitable for systems and methods in which the cycle is a direct combustion cycle in oxygen, in which carbon fuel is burned with oxygen. The controller 1 again monitors the power output of the generator 11 and doses the fuel supply through the valve 14 accordingly.

As shown in FIG. 4, fuel and oxidizer 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 recuperative heat exchanger 50 (although such a component is optional) and then pass through a first heater/cooler 16. The turbine exhaust stream is then treated in a water separator 60 from which water may be vented through a valve 61. A substantially pure CO2 stream exits from the top of the separator 60 and is passed through the compressor 30 (in this case, part of it is discharged through the valve 41). Compressed CO ₂ recycle stream exiting compressor 30 is passed through a second heater/cooler 18 and then through pump 20 to provide a high pressure CO ₂ recycle stream that can be sent back to dual combustor/turbine 10 (optionally passing through a recuperative heat exchanger 50 and heated by the heat taken from the turbine exhaust stream).

In this configuration, the oxidant enters through valve 111 and passes through mixer 114, where it may be mixed with CO2. The oxidant stream (optionally diluted with the CO2 stream) passes through the heater/cooler 22, is compressed in the compressor 90, passes through the heater/cooler 24, and finally is fed to the pump 80. The controller 8 (which may be referred to as the oxidizer pump controller) determines the relationship between mass flow rate of fuel (determined at the post 26 control parameters) and the mass flow rate of the oxidizer (determined at the post 82 control parameters). Based on the calculated ratio, the controller 8 can control the pump at a variable speed, varying its power and allowing the oxidizer to be delivered at the proper mass flow to maintain the desired ratio of oxidizer to fuel at a given pressure. Thus, the amount of oxidizer introduced into the power generation system constantly corresponds to the actual flow rate and actual pressure when supplied to the dual combustor/turbine 10. If, for example, the pressure at the parameter control station 82 would increase due to the back pressure of the combustor/turbine , then the compressor is configured to command the pump to run at a different speed to ensure proper pressure and mass flow of the oxidizer. Based on the pressure readings taken at the parameter control station 93, the controller 9 (which can be called an oxidizer pressure controller) can control the bypass valve 91, reducing or increasing the pressure at the parameter control station 93 by bypassing more or less fluid (or recycling) to a point upstream of

- 16 041135 compressor 90 (practically between mixer 114 and heater/cooler 22). Similarly, the pressure at the parameter control station 102 (where the pressure corresponds to the suction pressure of the compressor 90) can be monitored. Based on this pressure, controller 100 (which may be referred to as an oxidizer pressure controller) can control valve 103 by diverting nothing or diverting some of the fluid upstream of compressor 30 to mixer 114 so as to maintain a substantially constant pressure at parameter control station 102. The flow of mostly pure CO ₂ drawn through valve 103 can be used to dilute the oxidant, and controller 100 can similarly be configured to increase or decrease flow through valve 103 to provide the desired dilution. The mass flow rate in the CO2 stream provided through valve 103 may be measured at parameter control station 113, and the mass flow rate of oxidant provided through valve 111 may be measured at parameter control station 112. Controller 110 (which may be referred to as a dilution controller) may be configured to calculate the ratio of flows at control stations 112 and 113 and control valve 111 to allow more or less oxidant to enter the system to ensure that the proper ratio is maintained.

The control system can be made, in particular, with the possibility of providing mass control in a wide range of pressures. Mass control at low pressure (for example, at ambient pressure up to about 10 bar, up to about 8 bar, or up to about 5 bar) can be achieved similarly to the above description of the controller 4. In particular, the controller 4 can be configured to open or close the valve 41 to release excess mass from the power generation system. For example, in a system that uses a recirculating CO2 stream as the working fluid, excess CO2 can be generated. To maintain the correct mass balance in the system, all or part of this mass of formed CO2 can be removed through valve 41. The amount of mass removed through valve 41 for the purpose of mass control can be calculated based on the known stoichiometry of the combustion reaction, and controller 4 can be configured to to regulate the mass flow through valve 41 respectively. If necessary, one or more sensors may be used to measure and/or calculate the mass of fluid downstream of the combustion chamber and/or measure and/or calculate the ratio of the mass of fluid in the flow from the combustion chamber to the valve 41 to the same value below downstream from compressor 30 and/or pump 20.

In the embodiment shown in FIG. 5, controllers 3 and 4 described above are omitted, and additional controllers are provided to release excess mass from the power generation system at substantially the same pressure as the outlet pressure of compressor 30 (which is substantially identical to the suction pressure of pump 20). As described above, the speed of pump 20 is controlled by controller 2 in response to the outlet temperature of turbine 10. However, in the illustrative embodiment shown in FIG. 5, the suction pressure of the compressor 30 is controlled. In particular, the parameter control post 54 may include a pressure sensor, and the controller 35 (which may be referred to as the compressor suction pressure controller) may be configured to open and close the valve 31 depending on the compressor suction pressure. 30, measured at the post 54 control parameters. Upon a drop in pressure at the parameter control station 54, the controller may be configured to open valve 31 allowing fluid to be bypassed to a point upstream of the parameter control station 54 (in this embodiment, bypass directed to the parameter control station 44), and an increase in pressure at the post 54 control parameters. As the pressure at the parameter control station 54 increases, the controller 35 can be configured to close the valve 31, reducing the amount of fluid being flushed back and reducing the pressure at the parameter control station 54.

In addition to controlling the speed of the pump 20, its suction pressure can also be controlled. In particular, the pressure recorded at the parameter control station 23 can be used by the controller 75 (which can be called a pump speed controller), which can be configured to open and close the valve 88. Accordingly, the suction pressure of the pump 20 is controlled by removing excess fluid from the power generation system through valve 88, which in turn maintains the required pressure in the system.

In the shown in FIG. 6 embodiment, the power control system is similar to the structure of FIG. 5, but without the use of valve 88. In this exemplary embodiment, compressor 30 operates with suction pressure control as described in connection with FIG. 5 and the pump 20 also operates with suction pressure control. In particular, the pressure read at the parameter control station 23 can be used by the controller 75, which can be configured to adjust the speed of the pump 20 while maintaining adjustable, combustion cycle-specific suction and outlet parameters for a given pressure. In addition, the temperature determined at the control station 13 can again be used by the controller 2, however, the controller 2 can be configured to control the flow through the valve 115, regulating the temperature of the turbine exhaust. By allowing more fluid to be expelled from the power generation system through valve 115 (or keeping

- 17 041135 more fluid in the power generation system), it is possible to regulate the inlet pressure on the turbine 10, and similarly regulate the outlet temperature of the turbine 10.

In one or more embodiments, the energy system shown in FIG. 7 may include a turbine 10 connected to an electric generator 11. The fuel flow is metered by passing through valve 14, oxygen is metered by valve 71, and the fuel is combusted with oxygen in combustion chamber 10a. The fuel and oxygen are mixed with the heated high pressure CO2 recycle stream 120 exiting the economizer heat exchanger 50. The combustion products enter the turbine 10b. The turbine exhaust stream is cooled in economizer heat exchanger 50 by high pressure CO2 recycle stream 119 and further cooled to near ambient temperature in first heater/cooler 16. In some embodiments, first heater/cooler 16 may be an indirect heat exchanger in which cooling water is used, for example, or it can be a direct contact heat exchanger in which both the turbine exhaust stream is cooled and water is condensed. The near-ambient temperature stream enters the water separator 60, from which the condensed liquid water exits through valve 61. This stream may contain fuel or combustion contaminants in an oxidized state, such as SO2 and NO2. In the case of a direct contact cooler, such a unit acts as a combined gas water contact cooling unit and a liquid phase separator. The CO2 recycle stream 116 enters the CO2 recycle compressor 30 where it is pressurized (eg, from about 30-70 bar to about 80 bar). Compressor 30 is provided with a CO2 recirculation line 45 with valve 31 to reduce pressure and return part of the flow through the compressor to the suction side at point 44. The pure CO2 product, containing all the carbon and resulting from the fuel gas stream after oxidation in the combustion chamber, is removed from the system as a flow through valve 41. The pure CO2 product can be removed at a pressure ranging from the pressure at the suction side of the compressor to the pressure at the outlet of the pump. The recycle CO2 stream leaving compressor 30 is cooled to near ambient temperature in second heater/cooler 18. The density typically increases to a value in the range of about 0.7 to about 0.85 kg/L. With a multistage pump 20 dense supercritical CO ₂ is pumped with increasing pressure typically up to 320 bar. The recirculating CO2 stream 119 leaving the pump 20 enters the economizer heat exchanger 50.

Part 119a of the recirculating CO2 stream exiting pump 20 is heated in heat exchanger 56 by heating stream 53, which may come from any source, such as heat taken from an air separation unit. Stream 119a is typically heated to a temperature of about 200 to about 400°C. The heated stream is then sent to heat exchanger 50 at an intermediate point and remixed with high pressure CO2 recycle stream 119. The system is controlled by control valves that control fluid flows. The system is equipped with sensors that measure flow rates, pressures, temperatures and gas compositions. The results of these measurements can be sent to a digital control system that controls the power plant according to the control algorithms and the dispatcher control programs embedded in it. The output signals of the control system control the degree of opening of the control valves, as well as the speed of the pump 20 and other system functions. The challenge is to achieve the desired operating efficiency for any desired output power, optimal starting conditions, adjustable response rates to load changes both on load increase and decrease, shutdown and response to malfunctions. Although such a digital control system and control algorithms have been mentioned in connection with FIG. 7, it should be understood that this description can be used with the same success for any of the other embodiments described here, including those described in connection with FIG. 1-6 and FIG. 7.

The functional control of this system can be performed by the relationship between the variables measured by the sensors and the response of a particular control valve. One or more embodiments of the control system that may be used in any of the embodiments set forth include the following.

The flow of fuel through the valve 14 can be adjusted depending on the power generation requirements of the generator 58.

The speed of the pump 20 can be used to control its flow. In particular, the flow setpoint may be varied to maintain a certain turbine outlet temperature.

The CO2 outlet pressure of the compressor 30 can be maintained at a constant predetermined level by changing the operating point of the compressor recirculation flow control valve 31 .

The removal of the CO2 generated in the power generation cycle can be controlled by the flow control valve 41 . The setpoints for this flow controller can be varied to maintain constant compressor CO2 inlet pressure and turbine outlet pressure. In some embodiments where valve 41 is bled downstream of compressor 30, the control system may be configured to vary flow through valve 41 and through

-

Claims (11)

recirculation valve 31. The amount of high pressure recycle CO2 heated by the additional heat source in the heat exchanger 56 can be controlled by the flow control valve 42 and the controller 17 (which may be referred to as the bypass heating controller). The CO2 flow setpoints are adjusted to minimize, below 50° C., the temperature difference at the hot end of the heat exchanger 50 between the high pressure CO2 recycle stream 120 and the turbine exhaust stream at point 13. Discharge of condensed water, along with fuel and oxidized contaminants formed during the combustion process, can be controlled by maintaining a constant water level in the water separator 60 or in the reservoir of an alternative direct contact cooler. In the latter case, excess water is removed as the main water withdrawal stream is pumped through the cold water heat exchanger and enters the top of the direct contact cooler over the bed. When considering FIG. 5, it can be understood that the flow of oxygen into the combustion chamber can be controlled by the flow control valve 111. The set point of the flow controller can be varied to maintain a certain ratio of oxygen to fuel gas so as to typically provide a 1% excess of oxygen relative to the stoichiometric value, ensuring complete combustion of the fuel plus oxidation of fuel-derived contaminants. To control the adiabatic temperature of the flame in the combined turbine and combustor, it may be useful to dilute the oxygen with some CO ₂ to obtain a CO ₂ plus O ₂ gas mixture with an O 2 molar concentration of 15 to 40%, typically 25%. The oxygen stream may be diluted with CO2 from the CO2 inlet of compressor 30. The removed CO2 passes through flow control valve 103 and enters mixer 114, which in some embodiments may be a stand mixer. The set point of the flow controller for valve 91 can be adjusted by the supervisory computer program to maintain a constant pressure at point 102. The set point of the oxygen inlet flow control valve 111 can be adjusted to maintain a constant ratio of oxygen to carbon dioxide flow entering mixer 114. The mixed oxidant flow passes through heater/cooler 22. The cooled oxidant stream enters an oxidizer compressor 90 where it is compressed, typically to a pressure in the range of about 90 to about 120 bar. The operating point of the flow control valve 91 can be varied to change the outlet pressure of the oxidizer compressor 90. The oxidant compressor 90 may operate at fixed inlet and outlet pressures. The effluent from compressor 90 may be cooled to near ambient temperature in heater/cooler 24. The flow density increases to values ranging, for example, from about 0.6 to about 0.75 kg/L. The dense supercritical oxidant stream 82 is pumped by a multi-stage centrifugal pump with pressure increase typically up to 320 bar. The high pressure outlet stream from pump 80 enters heat exchanger-economizer 50 where it is heated by a portion of the heat released from the cooling turbine exhaust stream. The flow rate of the oxidizer can be controlled by adjusting the speed of the oxidizer pump 80 . The set operating flow rate may be varied to maintain a predetermined ratio of oxygen to fuel gas, typically providing a 1% excess of oxygen relative to the amount required for stoichiometric combustion of the fuel gas, which ensures complete combustion of the fuel gas plus oxidation of any fuel-derived contaminants. Many modifications and other embodiments can be implemented by a person skilled in the art. Accordingly, the invention is not limited to the specific particular embodiments and modifications given, and the scope of the invention, as defined by the appended claims, includes other embodiments. Although specific terms may be used in this specification, they are used in a generally accepted and descriptive sense only and are not intended to be limiting. CLAIM 1. A power generation system with an integrated control system configured to automatically control at least one component of the power generation system, comprising a heater; a power generator and at least one controller, wherein at least one controller is configured to receive an input signal downstream from the heater and provide an output signal to adjust the flow of fuel to the heater and thereby control the heat output of the heater, at least one controller is configured to receive the same or a different - 19 041135 input signal downstream from the heater and output signal to control the flow rate of the working fluid to the heater and at least one controller includes a fuel/oxidizer ratio controller that provides regulation of the fuel/oxidizer ratio and is configured to receive at least one of an input relating to fuel flow to the heater and an input relating to oxidizer flow to the heater, and doing one or both of the following: providing an output signal to the fuel valve to pass more or less fuel to the heater; providing an output signal to the oxidant valve to allow more or less oxidant to pass into the heater. 2. The system of claim 1, wherein the at least one controller includes a power controller configured to receive an input signal related to power generated by the power generator and provide an output signal to adjust fuel flow to the heater and thereby regulation of heat output by the heater. 3. The system of claim 2, wherein the power controller is configured to fulfill one or both of the following requirements: providing an output signal to the heater to increase or decrease the heat output of the heater; providing an output signal to the fuel valve to pass more or less fuel to the heater. 4. The system of claim 1, wherein the at least one controller includes a pump controller configured to receive an input relating to an exhaust stream temperature downstream of the heater and provide output to the pump to control the flow rate of the working fluid. environment to the heater. 5. The system of claim 1, wherein the at least one controller includes an oxidizer pump controller configured to receive an input relating to one or both of fuel mass flow and oxidizer mass flow to the heater and calculate the mass flow ratio fuel and oxidizer, and the oxidizer pump controller is configured to provide an output signal to the oxidizer pump to change the power of the pump so as to affect the mass flow ratio of fuel and oxidizer supplied to the heater. 6. The system of claim 1, wherein the at least one controller includes an oxidizer pressure controller configured to receive an input relating to an oxidizer flow pressure upstream of the oxidizer compressor and provide an output so as to cause more or less adding a working fluid to the oxidizer stream upstream of the oxidizer compressor. 7. The system of claim 1 wherein the working fluid is a stream of substantially pure CO ₂ . 8. The system of claim 1 wherein the heater is a combustion chamber. 9. The system of claim 1 wherein the heater is a solar powered heater. 10. The system of claim 1, wherein the heater is configured to receive heat from a fluid stream with a temperature above 400°C. 11. A method for automatically controlling a power generation system according to any one of claims 1 to 10, comprising burning an oxidizer fuel in a heater in the presence of a working fluid and exhausting an exhaust stream from the heater; generating power using the exhaust stream; using at least one controller to receive at least one input signal downstream from the heater and provide an output signal that adjusts the flow of one or both of the fuel or oxidizer to the heater and thereby controls the amount of heat in the exhaust stream, using at least one controller for receiving the same or a different input signal downstream from the heater and providing an output signal for controlling the flow rate of the working fluid flow to the heater and using a fuel/oxidizer ratio controller that receives one or both of the flow related input signals fuel to the heater, and an input signal related to the flow of oxidizer to the heater, and provides one or both of the following: applying an output signal to the fuel valve to pass more or less fuel to the heater; supplying an output signal to the oxidizer valve to pass more or less