Liquid air energy storage gas turbine system and method

Abstract

The present application relates to the technical field of energy, in particular to a liquid air energy storage gas turbine system and method, the system is composed of four parts of gas subsystem, gas turbine subsystem, liquid air gasification air intake subsystem and waste heat utilization subsystem, and is integrated into a replaceable gas turbine compressor, and releases the work of the gas turbine system for power generation which is distributed to the compressor about 2 / 3 of the turbine, further tapping the utilization value of liquid air energy storage, which can realize the coordinated control of gas subsystem, liquid air gasification air intake subsystem and waste heat utilization subsystem on each operating condition of gas turbine subsystem, solve the integration and operation control problem of liquid air energy storage device replacing compressor and gas turbine, the system focuses on the comprehensive utilization of system waste heat resources, compared with the existing system, the total energy utilization efficiency, system economy, system stability and reliability of the system are greatly improved, which will play a greater role in flexible regulation, climbing ability and inertia support in the construction of new power system with new energy as the main body.

Description

Technical Field

[0001] This invention relates to the field of energy technology, and in particular to a liquid air energy storage gas turbine system and method. Background Technology

[0002] Liquid air energy storage gas turbine systems are advanced clean energy and highly efficient power generation technologies. This technology uses a liquid air energy storage device to replace the gas turbine compressor, providing intake air to the gas turbine combustion chamber. The liquid air energy storage device and the gas turbine are integrated into a single, collaborative system for efficient energy utilization. Gas turbines are currently among the most advanced energy utilization equipment. In the power industry, approximately two-thirds of the mechanical work generated by a gas turbine is used to drive the gas turbine compressor, while the remaining one-third is used to drive a generator. This means that the mechanical work generated by the gas turbine is not fully utilized for power generation, resulting in low energy efficiency and underutilization of its energy value. Liquid air energy storage is one of the main research and application directions for large-scale, long-term energy storage technologies. Liquid air energy storage can utilize off-peak electricity from the grid, photovoltaic power, and wind power to produce and store liquid air. When releasing energy, the high-pressure air generated by the vaporization of the liquid air drives a turbine to generate electricity. However, this energy is difficult to utilize efficiently and reversibly, and the power density and energy efficiency of liquid air vaporization energy release power generation are relatively low. Integrating liquid air energy storage devices with gas turbines could replace the gas turbine compressor in supplying intake air to the combustion chamber, allowing approximately two-thirds of the power generated by the turbine and intended for the compressor to be used for power generation. This will significantly improve the energy efficiency and utilization value of liquid air energy storage, as well as the overall energy efficiency and energy utilization value of gas turbine systems. It can also reduce natural gas consumption by about two-thirds per unit of power generation from gas turbines, thereby saving natural gas resources and reducing carbon emissions per unit of power generation. At the same time, it can fully convert photovoltaic power generation without inertia and wind power with low inertia into gas turbine power generation with inertia. It will provide huge flexibility, ramp-up capability and inertia support in the construction of a new power system based on new energy sources.

[0003] As early as 1978, BBC designed and manufactured the world's first compressed air energy storage gas turbine system, which was installed and put into use in Hentoff, Germany. This system replaced the gas turbine compressor with a compressed air energy storage device, freeing up nearly two-thirds of the mechanical work previously done by the gas turbine to drive the compressor, and instead used it for power generation and peak shaving. The compressed air energy storage device replaced the compressor for two hours, achieving the expected peak shaving effect. After the merger of ASEA and BBC in 1988, some improvements were made, and the system was applied in the United States, the European Union, Australia, and other countries and regions. However, the continuous operation time of the compressed air energy storage device replacing the gas turbine compressor to provide intake air to the gas turbine combustion chamber is short, and the power generation unit operates in a transient environment. Transient operation may cause unforeseen problems and may lead to sudden generator tripping, endangering the entire gas turbine power plant. Furthermore, a series of unforeseen overall integration design and control reliability issues remain unresolved. Therefore, it has not yet been widely adopted worldwide. However, the concept and practical exploration of using compressed air energy storage devices to replace gas turbine compressors are of extremely significant importance.

[0004] The development of clean and reliable energy technologies has never been more urgent worldwide. Breakthroughs in research and technological innovation are crucial for new power generation technologies, large-capacity energy storage technologies, large-scale grid integration of renewable energy sources such as wind and solar power, efficient power generation applications of natural gas and hydrogen, and new power systems. In recent years, research and application of liquid air energy storage solutions have reached the forefront. Utilizing liquid air for energy storage allows for large-scale, long-term energy storage without geographical limitations. This has led to high attention and importance being paid to the integration of liquid air energy storage devices with gas turbines by research institutions and enterprises in the United States, the United Kingdom, France, Sweden, Australia, and China. Breakthroughs in integrated solutions and control strategies are expected to play a vital role in building new power systems.

[0005] The integration of air energy storage devices with gas turbines, and the research and application of air energy storage devices to replace gas turbine compressors, currently face several common problems:

[0006] 1. Liquid air energy storage devices and gas turbine compressors differ in structure, function, integration within the gas turbine, and operating mechanism. Excessive focus on the engineering design and research of liquid air energy storage devices replacing gas turbine compressors, while neglecting the analysis, research, and design of the operational integration mechanism between liquid air energy storage devices and gas turbines, results in a lack of systematic integration technology solutions. This leads to insufficient integration and coupling, making it difficult to form a systematic control strategy. Consequently, gas turbine operation becomes unstable, and unpredictable problems arise. Full-condition integrated operation is not achieved; it is only applied to short-term peak shaving. Its application value has not been fully explored, its economic efficiency is poor, and it is difficult to widely promote its application.

[0007] 2. Existing research and application schemes for air-storage gas turbine systems only consider air energy storage devices, including compressed air energy storage devices and liquid air energy storage devices. While the pressure and mass flow rate of the released normal air entering the gas turbine combustion chamber meet the technical parameters such as pressure and mass flow rate required to supply intake air to the combustion chamber via the gas turbine compressor, they neglect the fact that the temperature rise generated during the compressor process typically reaches around 400℃, ensuring sufficient O2 reactivity for rapid combustion when mixed with fuel, thus meeting the requirements for flame propagation speed and full release of fuel calorific value. However, the temperature of the depressurized or vaporized air released from the air energy storage device is low, and the O2 reactivity in the air is insufficient to achieve millisecond-level rapid combustion and rapid full release of calorific value from natural gas or fuel, resulting in unsatisfactory energy efficiency.

[0008] 3. The intake air supplied to the gas turbine combustion chamber by the liquid air energy storage device and the intake air supplied by the compressor each have their own advantages and disadvantages for the combustion of natural gas in the combustion chamber. Existing air-storage gas turbine systems have not fully utilized the advantages of the air energy storage device in supplying intake air to the gas turbine combustion chamber, nor have they effectively overcome its disadvantages. They are unable to overcome the adverse effects of variable operating conditions caused by dynamic load changes, and lack control strategies and measures for the corresponding co-combustion modes of intake air and natural gas under different operating conditions. Existing research and application of gas turbine control strategies focus on control strategies for compressor conditions, which cannot be adapted to liquid air energy storage gas turbine systems, making it difficult to achieve full-condition and variable-condition control operation.

[0009] 4. Parameters such as the temperature of natural gas or fuel and the temperature, oxygen content, mass flow rate, and mixing ratio of liquid air vaporized air have a significant impact on the gas turbine's operating technical parameters, such as combustion, flue gas temperature and flow rate, output power and efficiency. Moreover, there are interactive effects among these parameters. The coordination strategies for these parameters differ under different operating conditions of the gas turbine, and the mechanisms are complex. Therefore, there is an urgent need for active full-condition and variable-condition operation control strategy solutions.

[0010] 5. Air energy storage devices can replace gas turbine compressors, but currently their application is limited to peak shaving and cannot replace operation under all or varying conditions. Therefore, their replacement value has not been fully explored. Summary of the Invention

[0011] To address the shortcomings of existing air-based energy storage gas turbine systems, this invention proposes a liquid-air energy storage gas turbine system and method, which has the following characteristics:

[0012] 1. Due to differences in structure, function, and characteristics between gas turbine compressors and liquid air energy storage devices, their integration with gas turbines has its own advantages and disadvantages. These differences manifest in the integration mechanisms involving thermal power, aerodynamics, combustion science, chemical kinetics, and collaborative control strategies. This invention fully utilizes the advantages of liquid air energy storage devices in providing intake air to the gas turbine combustion chamber while overcoming their disadvantages. Through thorough research and analysis of the integration mechanism of liquid air energy storage replacing the compressor and gas turbine, it proposes for the first time the integrated structure of the liquid air energy storage gas turbine system as described in claims 1 and 2. This achieves comprehensive integration of the liquid air energy storage device and the gas turbine, rather than simply piecing them together. This results in more complete coupling and better combustion of the liquid air energy storage device replacing the compressor and gas turbine, meeting the requirements of full-condition and variable-condition operation, leading to more stable system operation, higher energy utilization efficiency, better economy, and lower NOx emissions. x Lower emissions.

[0013] 2. Due to the low temperature of the dry air vaporized in liquid air energy storage devices, and the large mass flow rate and high velocity of the intake air required in the gas turbine combustion chamber, the intake air temperature needs to be increased to around 320℃ to meet the activity requirements of O2 in the intake air for millisecond-level ultra-fast combustion of natural gas. This requires a large amount of heating heat with a high grade, necessitating a fast heat exchange rate and uniform heating. Furthermore, it is crucial to improve the enthalpy of natural gas per unit mass and reduce natural gas consumption and NOx. x The emissions require preheating of natural gas according to different operating conditions of the gas turbine. This invention, based on the requirements for natural gas preheating and heating of the intake air in the gas turbine combustion chamber, proposes for the first time a multi-grade, multi-type waste heat utilization subsystem for liquid air energy storage gas turbines. This subsystem is the first to propose a comprehensive waste heat utilization scheme for liquid air energy storage gas turbine systems, enabling the tiered, complementary, and fully effective utilization of limited multi-type, multi-grade waste heat resources. It saves energy compared to existing electric heaters and fuel heaters, and solves the problems of heat transfer lag and heating uniformity during the heating and heat exchange process.

[0014] 3. This invention is the first to propose an integrated structure and function for active regulation of a liquid air energy storage gas turbine system under all operating conditions. Parameters such as the temperature and flow rate of natural gas or fuel, and the temperature, oxygen content, mass flow rate, and mixing ratio of the intake air in the gas turbine combustion chamber formed after heating by liquid air vaporization, have a significant impact on gas turbine operating parameters such as combustion mode, combustion rate, flame propagation speed and length, natural gas or fuel consumption, exhaust temperature and flow rate, output power, and efficiency. Utilizing the integrated structure, waste heat utilization method, and valve nodes proposed in this invention, active regulation of system operating parameters under various operating conditions is achieved through the combined adjustment of various valves. This enables the active coordination of the gas subsystem, liquid air vaporization intake subsystem, and waste heat utilization subsystem with the gas turbine subsystem to operate under all and varying operating conditions. It can also overcome the adverse effects of varying operating conditions on the system energy efficiency of the liquid air energy storage gas turbine system and meet the combustion mode requirements of different operating conditions.

[0015] 4. Emphasize energy conservation and emission reduction in the system, and integrate energy conservation and emission reduction into the design of every process node of the system to ensure that the effects of energy conservation, emission reduction and ecological environmental protection are fully realized.

[0016] To address the shortcomings of existing air-storage gas turbine systems and achieve the aforementioned objectives, the technical solution of this invention is to provide a liquid air-storage gas turbine system and method. This system fully integrates the liquid air storage device with the gas turbine compressor, making full use of the system's waste heat resources and active control strategies to meet the technical parameter requirements of natural gas and gas turbine combustion chamber intake air under various operating conditions. It fully leverages the advantages of using vaporized air from the liquid air storage device as gas turbine combustion chamber intake air while overcoming its disadvantages. This solves the coupling and integration challenges of liquid air-storage gas turbine systems, unlocks their comprehensive energy utilization efficiency, energy-saving and emission-reduction potential, and their controllability and grid support capabilities as a flexible power source. Ultimately, this allows the liquid air-storage gas turbine system to play a significant role in building new power systems.

[0017] The liquid air energy storage gas turbine system described above allows for more complete integration and coupling of the liquid air energy storage device with the gas turbine, replacing the compressor; the system operates more stably; the overall energy utilization efficiency is higher; the economy is better; combustion is superior; and NO is reduced. xLower emissions. In liquid air energy storage devices, the cold energy from the vaporization of liquid air needs to be recovered. In practical applications, atmospheric air is typically used as the heat exchange medium for the reheating and vaporization of liquid air. The vaporized air is usually at room temperature, which is significantly lower than the compressor outlet temperature of around 400°C. This makes the vaporized air too cold for the gas turbine combustion chamber, requiring a large mass flow rate. Furthermore, the low reactivity of O2 in the intake air prevents the achievement of the millisecond-level rapid combustion rate of natural gas in the combustion chamber, hindering complete combustion and calorific value release. Therefore, the heat required to heat the intake air is large, and the temperature is high. Using electric or fuel heating methods would result in low overall system efficiency and poor economics, making widespread application difficult. In contrast, the liquid air in liquid air energy storage devices undergoes a production process that removes water vapor, CO2, and impurities, resulting in clean, dry vaporized air. Under the same mass flow rate, dry air has a slower flow rate and a higher oxygen content than humid air. This is beneficial for solving the problem of complete combustion of CO produced in the chain chemical reaction during natural gas combustion, thus improving energy efficiency. In gas turbine applications, the mass flow rate of the intake air has a significant impact on the output power and efficiency of the gas turbine. The higher the intake air mass flow rate, the higher the output power and efficiency. In engineering practice, measures such as compressor inlet air cooling or steam reinjection into the combustion chamber to increase humidity and flow rate are commonly used to increase the air mass flow rate and thus increase turbine work. Compressor inlet air cooling has a slightly greater effect on improving the output power and efficiency of gas turbines than steam reinjection into the combustion chamber. In addition, since dry air does not contain water vapor, it has no latent heat, only sensible heat, and is easier to heat and warm up than humid air. When heated with the same amount of heat, the heating temperature is higher. Based on a thorough analysis of the aforementioned mechanisms and factors, this paper proposes a liquid air energy storage gas turbine system scheme. This scheme leverages the advantages of using vaporized air from a liquid air energy storage device as intake air for the gas turbine combustion chamber while mitigating its disadvantages. The goal is to achieve more complete integration and coupling of the liquid air energy storage device with the gas turbine, replacing the compressor; more stable system operation; higher overall energy utilization efficiency; better economic performance; and superior combustion and NO reduction. x Lower emissions.

[0018] The liquid air energy storage gas turbine system described herein utilizes a comprehensive waste heat utilization scheme to fully and effectively utilize waste heat resources. While the system possesses relatively abundant waste heat resources, these resources vary in grade, with a shortage of high-grade waste heat. Specifically, to meet the requirements of high intake air velocity, large mass flow rate, and high temperature in the gas turbine combustion chamber, and the need for extremely rapid and uniform heat exchange during waste heat heating, the system employs a scientific and rational allocation, tiered, and complementary utilization of waste heat resources of various grades. Specifically, it uses cold heating to create a diffusion airflow, followed by hot heating to create turbulence, and finally, further hot heating to create even stronger turbulence. This intensifies molecular motion in the intake air. The tiered temperature rise increases the Reynolds number, and while dry air heats up quickly, heat transfer is slow, resulting in disturbance energy exceeding dissipated energy. This leads to intermittent turbulence, while maintaining a layered structure. Localized, transient pulsating turbulence achieves the exchange of momentum, heat, and mass.

[0019] The technology for comprehensive utilization of waste heat, characterized by high-intensity heat transfer and rapid, uniform heat exchange, achieves full and effective utilization of waste heat resources. Furthermore, other heat transfer media are not as uniform in heating as heat transfer oil, and the combustion chamber of a gas turbine has strict requirements for the uniform temperature rise of the intake air, as this directly affects the combustion state and stability of the combustion chamber. The inlet air temperature of a gas turbine compressor is typically around 400℃, and this temperature range is usually used as an empirical value in research and engineering practice. Given that a significant amount of unburned CO combustible gas exists in the exhaust of a gas turbine combustion chamber, some experts and engineers believe that, based on the chain chemical reaction in the natural gas combustion process, CO is the last to complete the reaction, and the combustion rate of natural gas should be determined by the combustion rate of CO in the chain chemical reaction. According to Arrhenius's law, increasing the intake air temperature of the gas turbine combustion chamber can increase the CO combustion rate and reduce the CO content in the exhaust of the gas turbine combustion chamber. However, further increasing the intake air temperature of the gas turbine combustion chamber is very difficult in the application of gas turbines and air-storage gas turbine systems. This invention suggests that the compressor outlet temperature of a gas turbine is typically around 400°C due to passive heating during air compression. For liquid air storage gas turbine systems, an intake air temperature of around 320°C is ideal for the combustion chamber, sufficient to meet the millisecond-level rapid combustion of natural gas. This is because liquid air vaporizes into dry air, which has a lower specific heat capacity, absorbs less heat, and has a higher oxygen content than wet air. This allows the flame preheating zone temperature at the combustion chamber nozzle to reach approximately 530°C, achieving the design combustion temperature. The activation energy of O2 in air is lower than that of N2. While an intake air temperature of around 320°C provides sufficient O2 activity for millisecond-level rapid combustion of natural gas, it reduces N2 activity, resulting in an extremely slow reaction rate between O2 and N2. This reduces their competitive ability to react, making rapid reactions difficult at flame temperatures below 1320°C, thus increasing the concentration of O2 involved in combustion. The high CO content in the exhaust gas from the gas turbine combustor is not due to low intake air temperature or insufficient O2 reactivity affecting the reaction rate between CO and O2, but rather to insufficient O2 concentration. Therefore, simply increasing the intake air temperature to improve the chemical reaction rate between CO and O2 is not significant. Dry air has a higher oxygen content than humid air. Under the same mass flow rate and slower velocity, dry air cannot flow too quickly to the other end of the combustion chamber, thus appropriately prolonging the time for CO and O2 to react completely. Therefore, CO can burn completely. However, dry air combustion occurs at a higher temperature and has a slightly higher N2 concentration than humid air, which is unfavorable for NO combustion. x While NO can be controlled, it can be reduced by decreasing the proportion of natural gas in the gas mixture and lowering the combustion temperature. x This reduces emissions while also saving natural gas.

[0020] The liquid air energy storage gas turbine system described herein, with its active control strategy, addresses the significant impact of the temperature, humidity, pressure, mass flow rate of the gas turbine combustion chamber intake air, the calorific value of natural gas, and the preheating temperature on the premixed gas ratio, combustion mode, combustion rate, flame temperature, exhaust gas temperature and mass flow rate, emission indicators, and the output power and efficiency of the gas turbine under various operating conditions. Therefore, the liquid air energy storage gas turbine system requires an integrated structure, function, and method for the active combination and control of these operating parameters. The active control strategy of this invention is based on the integrated structure and function described in claims 1 and 2. Through the active coordinated combination and control of various valves, it achieves the active dynamic combination and matching of the operating technical parameters of the gas subsystem, waste heat utilization subsystem, and liquid air vaporization intake subsystem to coordinate the operating conditions of the gas turbine. This solves the problem of active control strategies for gas turbines and liquid air energy storage gas turbine systems, overcomes the adverse effects of dynamic loads on the gas turbine subsystem under varying operating conditions, and makes the system more stable, more energy-efficient, and more economical. Attached Figure Description

[0021] Figure 1 This is a structural diagram of a liquid air energy storage gas turbine system;

[0022] Figure 2 This is a structural diagram of the waste heat utilization subsystem.

[0023] Implementation

[0024] This invention provides a liquid air energy storage gas turbine system and method. Under the active coordinated control of the gas subsystem, waste heat utilization subsystem, and liquid air vaporization intake subsystem, the gas turbine subsystem fully optimizes the utilization of waste heat resources and optimizes operation under various conditions, thereby improving the overall energy utilization efficiency and stability of the liquid air energy storage gas turbine system and reducing emissions. The invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0025] Implementation

[0026] Waste heat utilization subsystem implementation: Hot water recovered from the liquid air production process is used as a start-up heat source. This heat source is then used for gas turbine ignition, startup, warm-up, and combustion chamber diffusion combustion, gradually generating flue gas, waste heat steam, and economizer effluent for utilization. The heat transfer oil storage tank is used to regulate the dynamic changes in waste heat resource supply during gas turbine operation under varying conditions, providing a reliable and stable natural gas preheating and intake air heating process. Heat transfer oil I uses low-temperature heat transfer oil, while heat transfer oils III, IV, and V use high-temperature heat transfer oil. Interconnected high-temperature heat transfer oil circulation can be established between these oils, facilitating complementary use of various types of waste heat. Heat transfer oil VI uses ultra-high-temperature heat transfer oil. For example... Figure 2During natural gas preheating, waste heat water from the liquid air production process, along with the effluent from the economizer of the waste heat steam boiler after gas turbine ignition, warm-up, and startup, passes through valve 2 and heats the heat transfer oil 11 via heat exchanger 11. The hot water discharged from heat exchanger 11 then heats the heat transfer oil I via heat exchanger 1, flows into heat transfer oil storage tank I via valve 26, and then flows into waste heat heater I via valve 9 to preheat the natural gas I flowing in via valve 6. The outflowing heat transfer oil I returns to the inlet of heat exchanger I. The outflowing heat transfer oil 1 from heat exchanger 1 flows into heat transfer oil storage tank 1 via valve 27, and then flows into waste heat heater 1 via valve 10 to preheat the natural gas II flowing in via valve 7. The outflowing heat transfer oil 1 returns to the inlet of heat exchanger II. Waste heat from flue gas passes through valve 3 and heats the heat transfer oil III via heat exchanger III, then flows into heat transfer oil storage tank III via valve 29, and then flows into waste heat heater III via valve 11 to preheat the natural gas III flowing in via valve 8. In cold weather and winter when waste heat resources are insufficient, an electric heater can be installed at the front end of the natural gas inlet pipeline, i.e., before valve 1, to preheat the natural gas to above 15.5℃ and 0.103 MPa. Figure 2 When heating the intake air, the waste heat from the flue gas discharged from the waste heat boiler passes through valve 3 and heats the heat transfer oil 3 via heat exchanger 3. The waste heat from the flue gas discharged from heat exchanger 3 passes through heat exchanger 4 and heats the heat transfer oil 4. It then flows into the heat transfer oil storage tank 4 via valve 28, and then into the waste heat heater 4 via valve 12 to heat the vaporized dry air 1. The heat transfer oil 4 flowing out of the waste heat boiler returns to the inlet of heat exchanger 4. The waste heat steam from the waste heat boiler passes through valve 4 and heats the heat transfer oil 6 via heat exchanger 5. The steam discharged from heat exchanger 6 heats the heat transfer oil V via heat exchanger 6, and then flows into the heat transfer oil storage tank V via valve 30. It then flows into the waste heat heater 5 via valve 13 to heat the vaporized dry air 1. The heat transfer oil V flowing out returns to the inlet of heat exchanger 5. The heat transfer oil 6 flows into the heat transfer oil storage tank 6 via valve 31, and then into the waste heat heater 6 via valve 14 to reheat the hot vaporized dry air 11, forming hot intake air. In cold weather and winter when waste heat resources are insufficient, an electric heating vaporizer can be used instead of an air vaporizer to heat and vaporize the air to 15°C. The vaporized dry air meets the rated pressure and mass flow rate technical parameters required by the gas turbine combustion chamber intake air manufacturer.

[0027] Implementation

[0028] Natural gas preheating supply implementation method: such as Figure 1 ,like Figure 2Open valves 1, 2, 6, 7, 9, 10, 15, 16, and 19. Natural gas passing through valve 7 is first heated to 49°C by hot water (approximately 100°C) stored in the liquid air production process waste heat recovery subsystem, and then by the effluent from the waste heat steam boiler economizer. This ensures a certain degree of superheat and prevents condensation. Natural gas passing through valve 6 is then heated to 49°C by hot water discharged from heat exchanger 11 via waste heat heater 1, achieving tiered utilization of waste heat resources. The preheated natural gas from waste heat heaters 1 and 11 is then injected into the combustion chamber via valves 15 and 16, and finally combined with the gas gas through valve 19, igniting, starting, and warming up the gas turbine. It provides diffusion combustion in the combustion chamber; opens valves 3, 8, 11, 17, 20, and 25, and closes valves 6, 15, and 19, so that the natural gas passing through valve 7 is gradually heated to 185°C by the waste heat heater II using hot water at around 100°C and the waste heat steam boiler economizer outlet water recovery and storage. The natural gas passing through valve 8 is gradually heated to 185°C by the waste heat heater III using the waste heat boiler flue gas waste heat utilization and waste heat utilization subsystem, and then first passes through valves 16 and 17, and then merges with valve 20 before being injected into the mixer to mix with the heated intake air, forming a premixed gas, which is then injected into the combustion chamber through valve 25, realizing the sub-pilot premixed combustion mode, pilot premixed combustion mode, and premixed combustion mode.

[0029] Implementation

[0030] Intake air heating implementation method: The intake air is the vaporized air from the liquid air storage device, heated, and then used as the inlet air for the combustion chamber of the gas turbine. Figure 1 , Figure 2Liquid air flows into the air vaporizer through valve 18, where it exchanges heat with atmospheric air and is reheated to room temperature to vaporize into dry air, recovering the cold energy from vaporization. Valves 23, 12, 13, and 14 are opened, allowing the room temperature vaporized dry air to pass through the waste heat heater IV and the exhaust gas through the heat exchanger III. The hot vaporized dry air I, which is then cold-heated by the waste heat utilization subsystem, flows into the waste heat heater V. Valve 4 is opened, allowing the waste heat steam from the waste heat boiler to be heated by the waste heat utilization module, resulting in hot vaporized dry air II, which flows into the waste heat heater VI. The waste heat steam from the waste heat boiler is then reheated by the waste heat utilization module to form hot intake air at approximately 320°C. Valve 22 is opened, allowing the hot intake air to flow into the combustion chamber and form diffusion combustion with the preheated natural gas, thus achieving ignition, start-up, and heat-up of the gas turbine subsystem. Open valve 21 and close valve 22 to allow hot intake air to flow into the mixer and mix with preheated natural gas to form premixed gas, which is then injected into the combustion chamber through valve 25 to achieve sub-pilot premixed combustion mode, pilot premixed combustion mode, and premixed combustion mode.

[0031] Implementation

[0032] Coordinated Control Implementation Method: The performance of the gas turbine combustor is highly sensitive to the blending ratio of natural gas and intake air. Coordinated control of intake air and natural gas is a complex combustion adjustment process, requiring corresponding adjustments at different load levels. It should also consider combustion pulsation and NOx emissions. The dynamic characteristics of the gas turbine combustor are greatly influenced by the temperature, calorific value, and composition of the natural gas, as well as the mass flow rate, pressure, temperature, and humidity of the combustor inlet air. To ensure accurate control, adjustments should be made based on seasonal or climatic temperature changes, dynamic changes in system operating conditions, comprehensive utilization of waste heat, natural gas preheating, intake air heating, and blending ratios. Figure 1 , Figure 2The electric valve shown is used to open, regulate flow, and close according to the mechanism and implementation methods 1, 2, and 3 of the liquid air energy storage gas turbine system described in this invention. When the liquid air vaporization intake subsystem coordinates with the gas turbine system for startup control, the natural gas demand varies greatly during gas turbine startup. The natural gas supply should not be controlled based on the manufacturer's upper limit, as this would cause rapid gas turbine startup, generating significant thermal stress and leading to material thermal fatigue. Instead, the liquid air co-vaporization should be used as the air mass flow reference, i.e., the upper limit of natural gas supply provided by the manufacturer that varies with speed and time (i.e., the gas turbine startup control natural gas stroke reference), based on the mixing ratio of natural gas and intake air mass flow rate and the manufacturer's upper limit for natural gas supply, which varies with speed and time. Based on this, the ignition control intake air mass flow rate coordinate stroke reference is determined. After successful ignition, the warm-up natural gas stroke reference value should be used to determine the warm-up... The reference for controlling the mass flow rate of liquid air in conjunction with vaporization is the reference for controlling the mass flow rate of intake air, and keeping it stable. As the gas turbine enters the stage of gradual speed increase from warm-up, the natural gas supply flow rate also increases accordingly. Based on the rate of speed increase over time, the reference for the vaporized air and intake air to control the speed increase rate of the start-up is determined, and the gas turbine start-up speed is controlled to reach the preset acceleration value, i.e., the start-up is successfully completed. When controlling the speed of the liquid air vaporization intake subsystem, it is determined according to the differential speed control mode and the non-differential speed control mode of the gas turbine. When the generator is connected to the grid, the differential speed control mode is selected, and when the generator is running alone, the non-differential speed control mode is selected. Based on the reference for controlling the natural gas stroke when the gas turbine is controlled by differential speed and the reference for controlling the natural gas stroke when the gas turbine is controlled by non-differential speed, the reference for the mass flow rate of liquid air in conjunction with vaporization and the reference for the mass flow rate of intake air are determined.When the liquid air vaporization intake subsystem is used for temperature control, the temperature at the nozzles inside the gas turbine, i.e., the operating temperature, is the control target. Gas turbines operate at high temperatures and speeds for extended periods, experiencing extreme stress, which can easily lead to turbine blade burnout and breakage. Therefore, the operating temperature must be controlled within a certain range. When the liquid air vaporization intake subsystem is used for combustion control, the mass flow rate of the liquid air in conjunction with the natural gas ratio, as well as the operating temperature range specified by the gas turbine manufacturer, must be strictly controlled. When the gas turbine exhaust temperature exceeds the allowable reference value, the temperature control will switch to controlling the natural gas stroke reference, reducing the natural gas flow rate. The intake air stroke reference should reduce the amount of vaporized air and the intake air volume, and coordinate with the control of the gas turbine exhaust temperature to return to the temperature control reference value. When the gas turbine exhaust temperature is lower than the temperature control reference, the temperature control natural gas stroke reference should be increased so that it exceeds the speed control natural gas stroke reference. The mass flow rate of liquid air co-vaporized and the mass flow rate of intake air should exceed the mass flow rate of air co-vaporized and the mass flow rate of intake air controlled by the speed, and the temperature control system should be deactivated. When the gas turbine is operating at peak load, the temperature control reference should be increased within the control exhaust temperature reference. The stroke references for controlling the mass flow rate of liquid air co-vaporized and the mass flow rate of intake air should also be increased accordingly, so that the gas turbine unit can carry more... Under heavy load, if the exhaust temperature dispersion of the gas turbine exceeds a certain value, an alarm is triggered and the temperature control circuit is disconnected. When the load stops, the intake air mass flow rate is stopped by the liquid air vaporization system and the natural gas control system to ensure the gas turbine operating temperature does not rise. When indirectly controlling the gas turbine operating temperature using the exhaust temperature, the temperature control reference changes with the ambient temperature. Both temperature control lines that change with the natural gas supply and those that change with the gas turbine combustion chamber intake air pressure are acceptable. During the shutdown control of the liquid air vaporization intake subsystem, the reduction and cutoff of natural gas during the gas turbine shutdown process causes stress in the hot passages of the gas turbine due to temperature changes, similar to the stress experienced during startup. Similar to the process, excessively rapid heating and cooling rates also affect the service life of unit components. The mass flow rate of air and intake air for coordinated shutdown control of liquid air co-vaporization is determined based on the deceleration rate of the natural gas stroke reference for gas turbine shutdown control. This continues until the natural gas supply is cut off during the natural gas control stroke. When the liquid air vaporization intake subsystem coordinates load control and primary frequency regulation, the load of the gas turbine is mainly controlled by the gas control system and temperature control system. This is mainly reflected in the control of the unit's natural gas stroke reference. Based on the natural gas stroke reference for load regulation, the mass flow rate of air and intake air for load regulation of liquid air co-vaporization is determined. The coordinated gas system regulates the load of the gas turbine and is limited by the exhaust temperature reference.After the gas turbine is connected to the grid, the mass flow rate references for the liquid air co-vaporization and intake air are selected and determined according to the pre-selected load state or the base load state, respectively. In the base load control mode, the exhaust temperature of the gas turbine increases with the increase of load, entering temperature control near the maximum load of the operating condition. During grid-connected power generation, the speed control natural gas stroke reference is increased to increase output. The mass flow rate references for the liquid air co-vaporization and intake air are controlled according to both temperature control and speed control. When the exhaust temperature rises to the temperature control reference, the speed control system exits control and switches to temperature control mode. The reference for the mass flow rate of air and intake air in the liquid air co-vaporization system is set at a certain temperature. In pre-selected load control mode, the gas turbine output power always tracks the set load point. The speed control reference for natural gas travel is used as the reference for natural gas travel control of the gas turbine. When the gas turbine unit reaches temperature control, speed control continues to calculate and should provide a speed control reference higher than the temperature control reference for natural gas travel, ensuring the unit remains stable at temperature control and does not flash back to speed control. The liquid air vaporization intake subsystem should also be set to a higher reference for the mass flow rate of air and intake air in the liquid air co-vaporization system than the temperature control reference for natural gas travel. The speed control of the liquefied air co-vaporized air and the intake air mass flow rate is based on the stroke reference; when the power grid dispatch requires the gas turbine to participate in the primary frequency regulation, the primary frequency regulation dead zone is controlled within ±0.033Hz, the primary frequency regulation load adjustment limit is not less than ±10% of the rated load, and within 15s after the primary frequency regulation is triggered, its load response reaches more than 50% of the maximum load adjustment range of the primary frequency regulation. The average deviation between the actual output of the unit and the response target should be within ±3% of the adjustment range within 45s. At basic load, the liquefied air co-vaporized air and the intake air mass flow rate are coordinated for unidirectional primary frequency regulation, through the actual speed and... A 100% speed comparison is used to establish a function of speed difference (frequency difference) and changing natural gas travel reference. This changing natural gas travel reference is superimposed with the temperature-controlled natural gas travel reference. The air mass flow rate of liquid air co-vaporization is co-controlled by the superposition of the changing intake air mass flow rate reference and the temperature-controlled intake air mass flow rate reference, and the gas turbine load is increased and decreased in coordination. It is protected by exhaust temperature control. When the grid frequency is low and the gas turbine needs to be loaded, the impact on the unit life should be considered and it should not be executed. The liquid air vaporization intake subsystem can only coordinate unidirectional primary frequency regulation when the gas turbine needs to be reduced in load due to high grid frequency.When the pre-selected load is selected, the liquid air vaporization intake subsystem should coordinate with the primary frequency regulation to meet the conditions set by the gas turbine manufacturer for primary frequency regulation under pre-selected load. The speed control natural gas stroke reference should only track changes in speed and pre-selected load point. The liquid air vaporization intake subsystem should perform as required in the pre-selected load control mode to coordinate with the gas turbine to achieve primary frequency regulation. It should also coordinate to avoid load control dead zones, which would affect the frequency regulation effect. In the coordinated control of the gas system, to meet the natural gas flow requirements of the control gas stroke reference under various operating conditions of the gas turbine, relevant control valves are arranged. Valve 1 is a natural gas shut-off valve; valves 6, 7, and 8 are natural gas auxiliary shut-off valves; valves 15, 16, and 17 are natural gas speed ratio shut-off valves; valve 19 is a diffusion combustion natural gas control valve; valve 22 is a diffusion combustion intake air control valve; valve 20 is a premixed combustion natural gas control valve; valve 21 is a premixed combustion intake air control valve; and valve 25 is a premixed gas flow control valve. The natural gas speed ratio shut-off valve maintains the required pressure between the control valves and the speed ratio valves. The premixed natural gas control valve receives instructions from the control gas stroke reference and regulates the natural gas flow supplied to the gas turbine. The natural gas control valves adjust the natural gas flow according to the combustion mode provided by the gas turbine manufacturer, including... The combination and operation mode of the natural gas control valves are determined for diffusion combustion, sub-pilot premixed mode, pilot premixed mode, premixed mode, and load shedding mode. Natural gas and intake air should coordinate combustion mode switching. The combustion mode should be rationally switched under different operating conditions to control the combustion reference temperature, ensuring the gas turbine unit operates at its optimal condition and meets emission requirements. Based on the combustion mode switching points and conditions provided by the gas turbine manufacturer, a control scheme for the coordinated switching points of natural gas and intake air should be determined, including the natural gas control stroke reference, natural gas preheating control temperature, and intake air mass flow control stroke reference. During commissioning, the appropriate combustion mode switching point should be determined by combining the gas turbine manufacturer's experience and commissioning test plan. A coordinated switching point scheme for natural gas and intake air should be established to ensure the combustion chamber operates within the normal range and emissions meet environmental protection requirements.

[0033] Implementation

[0034] Cooling Implementation Method for High-Temperature Components of Gas Turbines: During gas turbine operation, high-temperature components such as the turbine need to be cooled by air cooling. Valve 24 is opened to allow a portion of the vaporized liquid air to enter the gas turbine cooling air passage. After cooling the high-temperature components, this air is discharged along with the combustion chamber flue gas. Since the vaporized air is dry air, an appropriate amount of water should be sprayed into the gas turbine to ensure a better cooling effect on the high-temperature components. Because the gas turbine is designed and manufactured according to ISO standards (1 standard atmosphere, atmospheric air temperature 15°C, relative humidity 60%), and because both the intake air and cooling air are liquid air, the vaporized air is dry air. The combustion chamber temperature and turbine front-end temperature are obtained indirectly by measuring the gas turbine exhaust temperature field and then calculating. Furthermore, to coordinate with the calculation of the waste heat and flow rate of the waste heat boiler, water is sprayed into the cooling air to ensure that the water content of the gas turbine exhaust gas is equivalent to that of the intake air and cooling air at a relative humidity of 60%. Of course, the intake air is dry air. When calculating the heat of the flue gas discharged from the gas turbine combustion chamber, only the sensible heat and the latent heat of the small amount of water vapor generated during combustion are calculated. The turbine front-end temperature, i.e. the initial temperature, is calculated based on the combustion chamber heat balance equation.

[0035] Implementation

[0036] When the gas pipeline is not supplying natural gas, it should be purged with air. Purging should be done by heating liquid air with waste heat to vaporize it. The purging pressure and temperature should meet the technical requirements specified by the equipment manufacturer and prevent natural gas backflow and interference between the gas nozzle and the combustion chamber. Figure 1 Open valves 32, 33, and 34 to jointly regulate the pressure and temperature of the purge air. The regulated purge air then flows through valve 35 to the relevant natural gas pipeline.

[0037] Implementation

[0038] Waste heat utilization methods for liquid air energy storage gas turbine systems: After utilizing waste heat hot water, waste heat steam, and waste heat flue gas, liquid air energy storage gas turbine systems will discharge a large amount of waste heat resources. Although this cannot be economically utilized in a way that matches the grade of the liquid air energy storage gas turbine system, it still has its value. For example, it can be used to generate electricity using screw expanders or low-temperature low-pressure turbines, provide domestic hot water, drive lithium bromide absorption chillers and absorption dehumidifiers, preheat natural gas and vaporize liquid air in winter or cold weather, and reduce the use of electric heaters.

[0039] The above are merely the principles and typical embodiments of the present invention. Engineers and technicians in the art can combine these embodiments with specific technical parameters of the gas turbine, the distribution method of intake and cooling air, the control curve and combustion mode, the fluctuation of wind and photovoltaic power generation, the dynamic load changes and inertia support level of the power grid, and the dynamic load changes of other energy systems. The present invention can also be applied to hydrogen permeation and pure hydrogen gas turbines in the future. Once the technology for hydrogen permeation and pure hydrogen gas turbines matures, the relevant control parameters can be adjusted for application.

Claims

1. A liquid air energy storage gas turbine system, comprising four parts: a gas subsystem, a gas turbine subsystem, a liquid air vaporization intake subsystem, and a waste heat utilization subsystem. The gas subsystem consists of a natural gas transmission pipeline, a natural gas shut-off valve, a natural gas auxiliary shut-off valve, a natural gas speed ratio shut-off valve, a diffusion combustion natural gas control valve, and a premixed combustion natural gas control valve. The gas turbine subsystem consists of a mixer, a combustion chamber, a turbine, a generator, a waste heat steam boiler, and valves. The waste heat utilization subsystem consists of a heat exchanger, a thermal oil storage tank, a thermal oil pipeline, a waste heat heater, and valves. The liquid air vaporization intake subsystem consists of a liquid air storage tank, a cryogenic variable frequency pump, an air vaporizer, a cold storage tank, and valves. Its characteristic is liquid In the air-storage gas turbine subsystem, the natural gas pipeline connects to waste heat heaters I, II, and III in the waste heat utilization subsystem via valve 1 (1), valve 6 (6), valve 7 (7), and valve 8 (8), respectively. Waste heat heaters I, II, and III are then connected to the combustion chamber in the gas turbine subsystem via valves 15 (15), 16 (16), and 17 (17), respectively, and then to the mixer in the gas turbine subsystem via valve 19 (19). The mixer is then connected to the mixer in the gas turbine subsystem via valve 20 (20). The mixer is connected to the... The combustion chamber is connected to the turbine, and the turbine shaft is connected to generator I and generator II at both ends respectively. The turbine exhaust is connected to the waste heat steam boiler. The waste heat hot water generated in the liquid air production process, the economizer outlet water of the waste heat boiler, the waste heat flue gas of the waste heat steam boiler, and the waste heat steam of the waste heat steam boiler are connected to the waste heat utilization subsystem via valves 2 (2), 3 (3), and 4 (4) respectively. In the waste heat utilization subsystem, valves 9 (9), 10 (10), 11 (11), 12 (12), 13 (13), and 14 (14) are connected to waste heat heater I and waste heat heater I respectively. Waste heat heaters II, III, IV, V, and VI are connected to the mixer and combustion chamber in the gas turbine subsystem via valves 21 (21) and 22 (22), respectively. In the liquid air vaporization intake subsystem, the liquid air storage tank is connected to the cryogenic variable frequency pump via valve 5 (5). The cryogenic variable frequency pump is connected to the air vaporizer via valve 18 (18). The air vaporizer is connected to waste heat heater IV in the waste heat utilization subsystem via valve 23 (23). Waste heat heater IV is connected to waste heat heater V, and waste heat heater V is connected to the waste heat heater... VI. In the liquid air vaporization intake subsystem, the air vaporizer is connected to the cooling air passage of the high-temperature components of the gas turbine via valve 24 (24). The air vaporizer is connected to the cold storage tank via the recovered vaporization cold energy. Waste heat heaters VI, ∨, and IV are connected to valves 32 (32), 33 (33), and 34 (34) respectively. The purge air with pressure and temperature adjusted by valves 32 (32), 33 (33), and 34 (34) is connected to valve 35 (35) and then to the natural gas pipeline that needs to be purged via valve 35 (35).

2. The liquid air energy storage gas turbine system as described in claim 1, characterized in that... In the waste heat utilization subsystem, the waste heat hot water from the liquid air production process, the waste heat from the flue gas, and the waste heat steam are connected to heat exchangers 11, 3, and 4 respectively via valve 2 (2), valve 3 (3), and valve 4 (4); The hot water discharged from heat exchanger 11 is connected to heat exchanger 1. The heat transfer oil 1 heated by heat exchanger 1 is connected to heat transfer oil storage tank 1 via valve 26 (26), and is connected to waste heat heater 1 via valve 9 (9) to heat the natural gas via valve 6 (6), outputting hot natural gas 1. The heat transfer oil 1 flows back to heat exchanger 1. The heat transfer oil ll heated by heat exchanger II is connected to heat transfer oil storage tank II via valve 27 (27), and is connected to waste heat heater ll via valve 10 (10) to heat natural gas via valve 7 (7), outputting hot natural gas II, and heat transfer oil II flows back to heat exchanger II; The flue gas discharged from heat exchanger III is connected to heat exchanger IV. The heat transfer oil IV heated by heat exchanger IV is connected to heat transfer oil storage tank IV via valve 28 (28), and is connected to waste heat heater IV via valve 12 (12) to heat the vaporized dry air via valve 23 (23), outputting hot vaporized dry air I. The heat transfer oil IV flows back to heat exchanger IV. The heat transfer oil III heated by heat exchanger III is connected to heat transfer oil storage tank III via valve 29 (29), and is connected to heat transfer oil storage tank III via valve 29 (28) to heat transfer oil storage tank IV. 11 (11) connects to waste heat heater Ⅲ to heat natural gas via valve 8 (8), outputting hot natural gas Ⅲ, and heat transfer oil Ⅲ flows back to heat exchanger Ⅲ; steam is discharged through heat exchanger VI and connected to heat exchanger Ⅴ, and heat transfer oil Ⅴ heated by heat exchanger Ⅴ connects to heat transfer oil storage tank Ⅴ via valve 30 (30), and connects to waste heat heater Ⅴ via valve 13 (13) to heat and vaporize dry air I, outputting hot vaporized dry air II, and heat transfer oil Ⅴ flows back to heat exchanger Ⅴ; The heat transfer oil heated by heat exchanger VI is connected to heat transfer oil storage tank VI via valve 31 (31), and then connected to waste heat heater VI via valve 14 (14) to continue heating and vaporizing dry air 11, outputting heated intake air, which is the intake air of the combustion chamber in the gas turbine system. Heat transfer oil VI flows back to heat exchanger VI. Heat transfer oil storage tank 11 is bidirectionally connected to heat transfer oil storage tank IV via valve 36 (36). Heat transfer oil storage tank IV is bidirectionally connected to heat transfer oil storage tank III via valve 37 (37). Heat transfer oil storage tank III is bidirectionally connected to heat transfer oil storage tank V via valve 38 (38). This achieves similar quality of waste heat from the economizer outlet water, flue gas waste heat, and steam waste heat in the waste heat boiler, and complementary utilization of different types of waste heat resources.

Images