One-furnace two-machine switching operation method and system and control device

Abstract

The invention discloses a one-furnace two-machine switching operation method and system and a control device. The method comprises the steps that S1, the total power utilization load of a power grid is determined; s2, the total cost of the system meeting the total electrical load in multiple operation modes is determined, the multiple operation modes comprise the first operation mode, the second operation mode and the third operation mode, in the first operation mode, the coal-fired boiler is communicated with the first steam turbine set, in the second operation mode, the coal-fired boiler is communicated with the second steam turbine set, and in the third operation mode, the coal-fired boiler is communicated with the second steam turbine set; in the third operation mode, the coal-fired boiler communicates with the first steam turbine set and the second steam turbine set; and S3, switching the system from the current mode to a target mode according to the total cost, wherein the target mode is the mode with the lowest total cost in the first operation mode, the second operation mode and the third operation mode. According to the one-boiler two-machine switching operation method, the peak regulation flexibility and the economic operation level of the thermal power generating unit under the new energy high permeability background can be remarkably improved.

Description

Technical Field

[0001] This invention relates to the field of thermal power generation technology, and in particular to a method, system, and control device for switching between two generators in a single boiler. Background Technology

[0002] The increasing penetration of intermittent renewable energy sources such as wind and solar power in the power system poses a severe challenge to the real-time power balance of the grid due to the randomness and volatility of their output. Against this backdrop, the role of thermal power plants, traditionally responsible for base load and conventional peak shaving, is undergoing a fundamental transformation, requiring them to become flexible regulating power sources that ensure stable grid operation. To effectively absorb renewable energy and avoid "wind and solar curtailment" during off-peak periods, thermal power units must exceed their traditional operating limits and engage in deep peak shaving, i.e., maintaining operation at loads far below their rated capacity. This aims to free up sufficient grid connection space for renewable energy generation and enable rapid response to fill power gaps when their output drops sharply.

[0003] However, deep peak shaving of thermal power units faces a series of key technical bottlenecks, including difficulties in maintaining stable combustion under low boiler loads, significant decreases in unit efficiency, and increased equipment wear. Therefore, researching and improving the deep peak shaving capability of thermal power units has become one of the core technical requirements for building a new power system and supporting the clean transformation of the energy structure. Summary of the Invention

[0004] This invention aims to at least solve one of the technical problems existing in the prior art. To this end, this invention proposes a method for switching between two generators in a single boiler. This method enables the system to meet the total power load of the grid while taking into account the economic efficiency of coal combustion, equipment health, and the cost of mode switching, thereby minimizing operating costs and extending equipment life. This significantly improves the peak-shaving flexibility and economic operation level of thermal power units in the context of high penetration of new energy sources.

[0005] According to a method for switching operation of a single boiler and two turbines according to a first aspect of the present invention, the method is applied to a system for switching operation of a single boiler and two turbines, the system including a coal-fired boiler, a first turbine unit, and a second turbine unit, wherein the rated power of the first turbine unit is greater than the rated power of the second turbine unit, the method includes: determining the total power load of the power grid; determining the total cost of the system meeting the total power load under multiple operating modes, wherein the multiple operating modes include a first operating mode, a second operating mode, and a third operating mode, wherein in the first operating mode, the coal-fired boiler is connected to the first turbine unit, in the second operating mode, the coal-fired boiler is connected to the second turbine unit, and in the third operating mode, the coal-fired boiler is connected to both the first turbine unit and the second turbine unit, and the total cost includes... The costs include coal consumption, equipment wear and tear, and switching costs. The coal consumption includes the coal consumption of the coal-fired boiler when each of the multiple operating modes meets the total electrical load. The equipment wear and tear includes the lifespan loss when the system switches from the current operating mode to another operating mode, and the lifespan loss is determined based on the rotor temperature difference between the first and / or second turbine units. The switching costs include the steam consumption cost and the electricity consumption cost when the system switches from the current operating mode to another operating mode. Based on the total cost, the system is switched from the current mode to a target mode, which is the mode with the lowest total cost among the first, second, and third operating modes.

[0006] The method for switching between two generators in a single boiler according to the present invention effectively addresses the challenges of high costs and significant equipment wear faced by traditional thermal power units during deep peak shaving by configuring a single boiler and two generator systems of varying capacities and dynamically selecting operating modes based on the overall total cost. Furthermore, since the switching between different modes is no longer based on fixed load thresholds but on dynamic decision-making based on "real-time peak demand forecasting + equipment status monitoring + economic model," this method also enables the system to meet the total power load of the grid while simultaneously considering the economics of coal combustion, equipment health, and the cost of mode switching. This minimizes operating costs and extends equipment lifespan, significantly improving the peak shaving flexibility and economic operation level of thermal power units in the context of high penetration of new energy sources.

[0007] According to some embodiments of the present invention, the first turbine unit includes a first high-pressure cylinder and a first intermediate-pressure cylinder, and the second turbine unit includes a second high-pressure cylinder. The system further includes a first pipeline, a second pipeline, a third pipeline, a mechanical steam recompression system, a mixing header, a reheater, a first control valve, and a second control valve. The first pipeline is connected between the steam outlet of the first high-pressure cylinder and the steam inlet of the mixing header. The first pipeline includes a first sub-pipeline and a second sub-pipeline. The diameter and length of the first sub-pipeline are different from those of the second sub-pipeline. The first control valve is disposed on the first pipeline and configured to cause the... The steam outlet of the first high-pressure cylinder can be selectively connected to either the first sub-pipeline or the second sub-pipeline; the second pipeline connects the second high-pressure cylinder to the steam inlet of the mixing header; the mechanical steam recompression system is installed on the second pipeline; the steam outlet of the mixing header is connected to the steam inlet of the reheater, the steam outlet of the reheater is connected to the steam inlet of the first intermediate-pressure cylinder of the first turbine unit, the steam outlet of the first high-pressure cylinder is connected to the steam inlet of the first intermediate-pressure cylinder via the third pipeline, and the second control valve is connected to the third pipeline for controlling the on / off state of the third pipeline and regulating the flow rate of the third pipeline. The method further includes: step S40, confirming that the target mode is the third operating mode; step S50, monitoring the temperature and pressure of the steam outlet of the first high-pressure cylinder and the steam outlet of the second high-pressure cylinder in real time; inputting the temperature and pressure of the steam outlet of the first high-pressure cylinder and the steam outlet of the second high-pressure cylinder into a pre-trained neural network model to obtain multiple control parameters, including the steam flow rate parameter of the third pipeline, the connectivity of the first sub-pipeline and the second sub-pipeline, and the compressor speed parameter of the mechanical vapor recompression system, wherein the neural network model is pre-trained with the goal of minimizing the temperature difference and pressure difference between the first pipeline and the second pipeline; step S60, adjusting the first control valve, the second control valve, and the compressor speed based on the multiple control parameters, so that the pressure and temperature of the steam outlet of the first pipeline and the pressure and temperature of the second pipeline both reach the preset target.

[0008] According to some embodiments of the present invention, the system further includes: a fourth pipeline, a fifth pipeline, a conveying air pipeline, a combustion air pipeline, a first air preheater, and a second air preheater. One end of the fourth pipeline and the fifth pipeline are connected to the main steam pipe of the second steam turbine unit. One end of the conveying air pipeline and the combustion air pipeline are connected to the coal-fired boiler. The first air preheater has a first flow channel and a second flow channel that exchange heat with each other. The first flow channel is connected in series with the conveying air pipeline. The other end of the fourth pipeline is connected to the inlet end of the second flow channel. The second air preheater has a third flow channel and a fourth flow channel that exchange heat with each other. The third flow channel is connected in series with the combustion air pipeline. The other end of the fifth pipeline is connected to the inlet end of the fourth flow channel. The method further includes: step S41, confirming that the target mode is the first operating mode; step S51, confirming that the total power load is lower than a preset threshold, connecting the fourth pipeline and / or the fifth pipeline, wherein the preset threshold is less than or equal to the total output of the system when the coal-fired boiler is running at the lowest stable combustion load in the first operating mode.

[0009] According to some embodiments of the present invention, when the total power load is lower than a preset threshold, step S51 includes: step S511, confirming that the total power load is lower than the preset threshold; step S512, determining flow control information based on the total power load, the output power of the second turbine unit, and the steam pressure of the main steam pipeline of the second turbine unit, wherein the flow control information includes the steam flow path, flow rate, temperature, and pressure; step S513, connecting the fourth pipeline and / or the fifth pipeline based on the flow control information, and controlling the flow rate, temperature, and pressure of the fourth pipeline and / or the fifth pipeline.

[0010] According to some embodiments of the present invention, the outlet end of the second flow channel and / or the fourth flow channel is connected to the steam inlet of the reheater.

[0011] According to some embodiments of the present invention, when the current mode is a first operating mode or a second operating mode and the target mode is a third operating mode, or when the current mode is a first operating mode and the target mode is a second operating mode, or when the current mode is a second operating mode and the target mode is a first operating mode, switching the system from the current mode to the target mode based on the total cost includes: Based on the target mode, the total electrical load, the current main steam pressure of the system, the real-time speed and load of the currently operating turbine units, a first load change curve for the currently operating turbine units and a second load change curve for the turbine units to be started are determined. The first and second load change curves are obtained through closed-loop control with the highest priority of minimizing the change in the total output power of the system. The power of the currently operating turbine units is gradually reduced according to the first load change curve, and the turbine units to be started are started according to the second load change curve. The power of the first and second turbine units is adjusted to match the total electrical load.

[0012] According to some embodiments of the present invention, when the current mode is a third operating mode and the target mode is the first operating mode or the second operating mode, The step of switching the system from the current mode to the target mode based on the total cost includes: determining a third load change curve and a fourth load change curve based on the target mode, the total power load, the current main steam pressure of the system, and the real-time speed and load of the first turbine unit and the second turbine unit. The third load change curve is the total power change curve of the system, and the rate of change of the total power is within a preset range. The fourth load change curve is the power change curve of the turbine unit to be shut down, and its endpoint is 0. The power of the turbine unit to be shut down is reduced according to the fourth load change curve, and the power of another turbine unit other than the turbine unit to be shut down is adjusted according to a fifth load change curve. The fifth load change curve is used to offset the third load change curve and make the total power of the system follow the third load change curve.

[0013] According to some embodiments of the present invention, step S1 includes: predicting the total power load after a preset time based on historical load data, power grid dispatch plan, and weather forecast, as well as the expected mode switching time point; step S3 includes: switching the system to the target mode at the mode switching time point.

[0014] A system for switching between two turbines in a single boiler, according to a second aspect of the present invention, includes: a coal-fired boiler, a first turbine unit, and a second turbine unit, wherein the rated power of the first turbine unit is greater than the rated power of the second turbine unit; the system is used in accordance with the method described in the first aspect of the present invention.

[0015] The system for switching between two turbines in a single boiler, according to the present invention, achieves flexible adjustment of boiler load by configuring two turbine units, one large and one small. For example, when grid demand is high, both turbine units can operate simultaneously; when demand decreases, the large-power turbine unit can be selected to operate; and during off-peak electricity demand, the small-power turbine unit can operate alone. This design ensures that the boiler always operates within its optimal load range, guaranteeing combustion stability and improving system operating efficiency. Compared with traditional single-unit systems, this system significantly improves peak-shaving depth while avoiding efficiency losses and equipment wear under low-load conditions. Furthermore, through the switching control of the steam inlet regulating valve, this system also achieves a smooth transition between different operating modes, ensuring the reliability and economy of system operation.

[0016] According to a third aspect of the present invention, a control device for switching between two boilers in a single furnace is applied to a system for switching between two boilers in a single furnace according to a second aspect of the present invention. The control device includes a processor, a memory, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, the control device enables the system to implement the method for switching between two boilers in a single furnace according to a first aspect of the present invention.

[0017] The control device for switching between two boilers in one boiler according to the present invention can further improve the automation of the system for switching between two boilers in one boiler.

[0018] Additional aspects and advantages of the invention will be set forth in part in the description which follows, and in part will be obvious from the description, or may be learned by practice of the invention. Attached Figure Description

[0019] Figure 1 This is a flowchart of a system for switching between two turbines in a single boiler, according to an embodiment of the present invention. Figure 2 This is a flowchart of a method for switching between two turbines in a single boiler according to an embodiment of the present invention; Figure 3 This is a flowchart of step S51 according to an embodiment of the present invention; Figure 4 This is a schematic diagram of a control device for switching between two machines in a single furnace according to an embodiment of the present invention.

[0020] Figure label: 100. System; 10. Coal-fired boiler; 11. Main pipe; 20. First steam turbine unit; 21. First high-pressure cylinder; 22. First intermediate-pressure cylinder; 23. First low-pressure cylinder; 30. Second steam turbine unit; 31. Second high-pressure cylinder; 32. Second intermediate-pressure cylinder; 33. Second low-pressure cylinder; 34. Main steam pipe; 41. First pipeline; 411. First sub-pipeline; 412. Second sub-pipeline; 42. Second pipeline; 421. Third sub-pipeline; 422. Fourth sub-pipeline; 43. Third pipeline; 44. Mechanical vapor recompression system; 45. Mixing header; 46. Reheater; 47. First control valve; 471. First intake regulating valve; 472. Second intake regulating valve; 48. Second control valve; 491. Third intake regulating valve; 492. Fourth intake regulating valve; 51. First desuperheating and pressure reducing valve; 52. Second desuperheating and pressure reducing valve; 53. Third desuperheating and pressure reducing valve; 60. Water supply regeneration system; 71. Sixth pipeline; 72. Condenser hot well; 73. Seventh pipeline; 74. First equalizing tank; 75. Second equalizing tank; 200. Control device; 201. Processor; 202. Memory; 203. Computer program. Detailed Implementation

[0021] Embodiments of the present invention are described in detail below. Examples of these embodiments are illustrated in the accompanying drawings, wherein the same or similar reference numerals denote the same or similar elements or elements having the same or similar functions throughout. The embodiments described below with reference to the accompanying drawings are exemplary and intended to explain the present invention, and should not be construed as limiting the present invention.

[0022] The process of electricity production is the conversion of primary energy into secondary energy by a power plant through a series of power generation devices. There are many types of power plants, such as thermal power plants, hydropower plants, and nuclear power plants. The primary energy structure dictates a pattern dominated by thermal power generation. With increasing pressure on power supply, the operating load of thermal power units in thermal power plants is changing more significantly and frequently. This places higher demands on the stability of the operating status of thermal power unit equipment and means that power plants will face greater challenges in monitoring the condition of their equipment.

[0023] A power plant system is a core energy conversion system that transforms the chemical energy of fuel into electrical energy. Its function is to ensure the safe and economical operation of the unit through heat transfer and conversion, while also addressing start-up, shutdown, and load regulation requirements. For example, the system is responsible for converting the heat energy generated from fuel combustion into steam, driving the turbine to rotate, and ultimately powering the generator. The system typically consists of multiple interconnected devices that work together to achieve its functions.

[0024] In traditional coal-fired power plant systems, one boiler corresponds to one steam turbine. The boiler has a "minimum stable combustion load" limitation, typically between 30% and 50% of its design load. If the load falls below this value, the furnace temperature will be too low, leading to unstable combustion, flameout, or even the need for oil-assisted combustion, which is neither safe nor economical. Furthermore, due to uneven electricity consumption, there is often a peak-shaving demand on the power grid, and the one-to-one boiler-to-turbine configuration can affect the depth of peak shaving. Specifically, while a steam turbine can theoretically operate at very low loads, its efficiency will drop sharply, and vibrations may occur. In other words, if the steam turbine supports the boiler operating at maximum efficiency, then the boiler cannot operate at its minimum stable combustion load, or its operating efficiency will be extremely low. If the steam turbine can support the boiler operating at its minimum stable combustion load, it means that the turbine's own power output is relatively small, thus failing to fully utilize the boiler's maximum efficiency.

[0025] Therefore, in order to solve the above problems, this application designs a method for switching between two boilers in one furnace, which is applied to a system for switching between two boilers in one furnace.

[0026] The following is a reference. Figure 1 A system 100 for switching between two boilers according to an embodiment of the second aspect of the present invention is described.

[0027] like Figure 1 As shown, a system 100 for switching between two turbines in a single boiler according to a second aspect of the present invention includes: a coal-fired boiler 10, a first turbine unit 20 and a second turbine unit 30, wherein the rated power of the first turbine unit 20 is greater than the rated power of the second turbine unit 30.

[0028] Understandably, the one-boiler-two-turbine switching operation system 100 is configured to include one coal-fired boiler 10 and two turbine units with different rated capacities. As one implementation, the coal-fired boiler 10 can be a conventional pulverized coal boiler or a circulating fluidized bed boiler, with a design capacity sufficient to meet the maximum steam demand of both turbine units operating simultaneously. The first turbine unit 20 can be configured as a large condensing turbine, such as a 600MW unit, used to meet high grid load demands. The second turbine unit 30 can be configured as a medium-sized condensing turbine, such as a 300MW unit, used to meet low grid load demands or deep peak-shaving demands. The two turbine units are connected to the superheater outlet of the coal-fired boiler 10 via their respective main steam pipes 34 and can operate independently or collaboratively. For example, by setting appropriate valves and control logic, steam from the coal-fired boiler 10 can be delivered separately or simultaneously to the first turbine unit 20 and the second turbine unit 30.

[0029] Specifically, the coal-fired boiler 10 is used to generate main steam. As a possible example, the coal-fired boiler 10 includes, for example, an economizer, a water-cooled wall, at least one low-temperature superheater, a high-temperature superheater, a low-temperature reheater 46, and a high-temperature reheater 46. The feedwater inlet of the economizer is connected to the feedwater outlet of the feedwater regeneration system 600, and the feedwater outlet of the economizer is connected to the feedwater inlet of the water-cooled wall. The steam outlet of the water-cooled wall is connected to the steam inlet of the low-temperature superheater, and the steam outlet of the low-temperature superheater is connected to the steam inlet of the high-temperature superheater. After passing through the economizer, the feedwater flows into the water-cooled wall, where it vaporizes into steam. The steam then flows sequentially through the low-temperature superheater and the high-temperature superheater, ultimately becoming the main steam.

[0030] The first steam turbine unit 20 and the second steam turbine unit 30 are used to convert the internal energy of steam into mechanical energy. For example, refer to... Figure 1 The first steam turbine unit 20 includes a first high-pressure cylinder 21, a first intermediate-pressure cylinder 22, and a first low-pressure cylinder 23. The second steam turbine unit 30 includes a second high-pressure cylinder 31, a second intermediate-pressure cylinder 32, and a second low-pressure cylinder 33. The main steam outlet of the coal-fired boiler 10 is connected to the steam inlet of the first steam turbine unit 20 via a main pipe 11 and a pipeline. The main steam outlet of the coal-fired boiler 10 is also connected to the steam inlet of the second steam turbine unit 30 via a main pipe 11 and a pipeline. An inlet steam regulating valve is installed on the pipeline.

[0031] The rated power of the first turbine unit 20 is greater than that of the second turbine unit 30. This means that the first turbine unit 20 is the turbine unit with the larger rated power in system 100, designed to meet higher grid load demands; the second turbine unit 30 is the turbine unit with the smaller rated power in system 100, designed to meet lower grid load demands or for deep peak shaving. It should be noted that rated power refers to the maximum electrical power that the turbine unit can continuously output under design operating conditions. The rated power of the first turbine unit 20 and the second turbine unit 30 can be configured based on the boiler's stable combustion load and rated evaporation capacity.

[0032] The system 100 of the present invention, which allows for switching between two turbines in a single boiler operation, achieves flexible adjustment of boiler load by configuring two turbine units, one large and one small. For example, when grid demand is high, both turbine units can operate simultaneously; when demand decreases, the large-power turbine unit can be selected to operate; and during off-peak electricity demand, the small-power turbine unit can operate alone. This design ensures that the boiler always operates within its optimal load range, guaranteeing combustion stability and improving the operating efficiency of system 100. Compared with the traditional single-unit system 100, this system 100 significantly improves peak-shaving depth while avoiding efficiency losses and equipment wear under low-load conditions. Furthermore, through the switching control of the steam inlet regulating valve, this system 100 also achieves a smooth transition between different operating modes, ensuring the reliability and economy of system 100 operation.

[0033] According to some embodiments of the present invention, such as Figure 1 As shown, system 100 also includes: a first pipeline 41, a second pipeline 42, a third pipeline 43, a mechanical vapor recompression system 44, a mixing manifold 45, a reheater 46, a first control valve 47, and a second control valve 48.

[0034] The first pipeline 41 connects the steam outlet of the first high-pressure cylinder 21 and the steam inlet of the mixing manifold 45. The first pipeline 41 includes a first sub-pipeline 411 and a second sub-pipeline 412. The diameter and length of the first sub-pipeline 411 are different from those of the second sub-pipeline 412. A first control valve 47 is provided on the first pipeline 41 and is configured to allow the steam outlet of the first high-pressure cylinder 21 to be selectively connected to either the first sub-pipeline 411 or the second sub-pipeline 412. The second pipeline 42 connects the second high-pressure cylinder 31 and the steam inlet of the mixing manifold 45. The mechanical steam recompression system 44 is provided on the second pipeline 42.

[0035] Specifically, the first pipeline 41 and the second pipeline 42 are used to connect the mixing manifold 45 with the first high-pressure cylinder 21 and the mixing manifold 45 with the second high-pressure cylinder 31, respectively. The mixing manifold 45 is mainly used to mix the steam from the first pipeline 41 and the second pipeline 42, and the high-pressure cylinder is mainly used to expand the steam from the boiler. The mechanical steam recompression system 44 can use a centrifugal compressor or a screw compressor to increase the steam pressure. The centrifugal compressor is suitable for high flow conditions, and the screw compressor is suitable for variable operating conditions.

[0036] "The first pipeline 41 includes a first sub-pipeline 411 and a second sub-pipeline 412. The diameter and length of the first sub-pipeline 411 are different from those of the second sub-pipeline 412. A first control valve 47 is located on the first pipeline 41 and is configured to selectively connect the steam outlet of the first high-pressure cylinder 21 to either the first sub-pipeline 411 or the second sub-pipeline 412." It can be understood that the first pipeline 41 includes two sub-pipelines (e.g.,... Figure 1 The diagram shows a first sub-pipe 411 and a second sub-pipe 412, with different diameters and lengths. Only one of the two sub-pipes is connected at any given time; that is, the first sub-pipe 411 and the second sub-pipe 412 are two parallel branches within the first pipe 41. For example, the first sub-pipe 411 can be designed with a smaller diameter and a longer length, while the second sub-pipe 412 can be designed with a larger diameter and a shorter length. By controlling the first control valve 47, one of them can be selectively connected. This allows for passive fine-tuning of the steam parameters passing through the first pipe 41 by utilizing their different flow resistances, heat dissipation characteristics, and volume differences. It should be noted that the first control valve 47 can be an electric valve or a pneumatic valve.

[0037] For example, Figure 1 As shown, the exhaust port of the first high-pressure cylinder 21 is connected to the mixing manifold 45 via a first pipeline 41. The first pipeline 41 includes a first sub-pipeline 411 and a second pipeline 42. The first control valve 47 includes a first intake regulating valve 471 and a second intake regulating valve 472. The first intake regulating valve 471 is arranged on the first sub-pipeline 411, and the second intake regulating valve 472 is arranged on the second sub-pipeline 412. During the operation of the system 100, one of the first intake regulating valve 471 and the second intake regulating valve 472 is open, and the other is closed. Closed; the exhaust port of the second high-pressure cylinder 31 is connected to the mixing manifold 45 through the second pipeline 42. The second pipeline 42 includes a third sub-pipeline 421 and a fourth sub-pipeline 422. The diameter and length of the third sub-pipeline 421 and the fourth sub-pipeline 422 are different. A third intake regulating valve 491 and a fourth intake regulating valve 492 are respectively installed on the third sub-pipeline 421 and the fourth sub-pipeline 422. During the operation of the system 100, one of the third intake regulating valve 491 and the fourth intake regulating valve 492 is open and the other is closed.

[0038] For example, the difference in pipe diameter between the first sub-pipe 411 and the second sub-pipe 412 can be achieved in the following ways: for example, the first sub-pipe 411 uses a standard DN150 pipe, and the second sub-pipe 412 uses a DN200 pipe; or the first sub-pipe 411 uses a DN200 pipe, and the second sub-pipe 412 uses a DN250 pipe. It should be noted that the steam inlet regulating valve can be an electric regulating valve or a pneumatic regulating valve, and its opening and closing state is automatically switched by the control system 100 according to the difference in steam parameters. The specific value of the pipe diameter difference can be optimized and calculated based on the exhaust parameters of the high-pressure cylinder and the design pressure of the mixing manifold 45.

[0039] Optional, such as Figure 1As shown, system 100 also includes a first desuperheating and pressure reducing valve 51 and a second desuperheating and pressure reducing valve 52. Specifically, the first desuperheating and pressure reducing valve 51 is located on the first pipeline 41, and the second desuperheating and pressure reducing valve 52 and the mechanical steam recompression system 44 are both located on the second pipeline 42. The second desuperheating and pressure reducing valve 52 is closer to the mixing manifold 45 than the mechanical steam recompression system 44. It should be noted that the desuperheating and pressure reducing valve is mainly used to cool and reduce the pressure of high-parameter steam in the pipeline to meet the requirements of subsequent processes or equipment. It is an integrated device and is usually used in heating, auxiliary steam, and other systems 100.

[0040] It should be further noted that the desuperheating and pressure reducing valve can be a pilot-operated regulating valve or a self-operated regulating valve, achieving closed-loop control through feedback signals from pressure and temperature sensors. The volume design of the mixing manifold 45 must ensure a steam residence time of not less than 0.5 seconds, and a baffle plate or porous medium can be installed inside to enhance the mixing effect.

[0041] Therefore, this technical solution utilizes a dual-pipeline system 100 with different pipe diameters to initially regulate steam parameters by leveraging the pressure drop characteristics caused by the pipe diameter difference. When the high-pressure cylinder exhaust pressure is high, steam is guided to the smaller diameter pipe, where increased flow resistance reduces pressure; conversely, when the exhaust pressure is low, steam flows through the larger diameter pipe to minimize pressure drop. This passive regulation method, together with the subsequent mechanical steam recompression system 44 and the desuperheating and pressure-reducing valve, forms a tiered regulation system, effectively mitigating parameter abrupt changes during steam mixing. Compared to a single-pipeline control valve solution, this design significantly reduces the workload of the control valve, decreases equipment wear, and, by optimizing parameter matching before steam mixing, reduces the thermal stress fluctuation amplitude of the mixing manifold 45A13 by approximately 40%, extending the service life of critical equipment.

[0042] like Figure 1 As shown, the steam outlet of the mixing manifold 45 is connected to the steam inlet of the reheater 46, the steam outlet of the reheater 46 is connected to the steam inlet of the first intermediate pressure cylinder 22, the steam outlet of the first high pressure cylinder 21 is connected to the steam inlet of the first intermediate pressure cylinder 22 through the third pipeline 43, and the second control valve 48 is connected to the third pipeline 43 to control the opening and closing of the third pipeline 43 and to regulate the flow rate of the third pipeline 43.

[0043] It is understandable that the steam mixed in the mixing manifold 45 enters the reheater 46 for reheating and then enters the first intermediate pressure cylinder 22 for secondary expansion and work. At the same time, the remaining steam in the first high pressure cylinder 21 also enters the first intermediate pressure cylinder 22 through the third pipeline 43 for secondary expansion and work.

[0044] Specifically, the reheater 46 is an important component of the coal-fired boiler 10, mainly used to reheat the steam discharged from the intermediate pressure cylinder of the steam turbine to increase the enthalpy and temperature of the steam. Its inlet receives steam from the mixing header 45. The first intermediate pressure cylinder 22 is an important component of the first steam turbine unit 20, used to further expand the steam from the reheater 46. The third pipeline 43 mainly serves as a bypass or auxiliary passage, providing a steam passage from the outlet of the first high pressure cylinder 21 to the inlet of the first intermediate pressure cylinder 22. This can be achieved by setting a second control valve 48 to control the flow and volume of steam, such as by using an electric regulating valve or a pneumatic regulating valve.

[0045] It should be noted that the tube bundle arrangement of the reheater 46 can be in parallel or staggered, and the material is selected as 12Cr1MoVG alloy steel to withstand high temperature and high pressure conditions; the third pipeline 43 can be made of high temperature and high pressure resistant alloy steel pipe, with an inner diameter of 150-300mm designed according to the steam flow rate and a pipe wall thickness of 10-20mm; the second control valve 48 can be an electrically regulating valve, which has a 0-100% linear regulation characteristic and a response time of less than 5 seconds.

[0046] Optional, such as Figure 1 As shown, the third pipeline 43 is also equipped with a third desuperheating and pressure reducing valve 53. The third desuperheating and pressure reducing valve 53 adopts a series structure and includes a pressure reducing module and a water spray desuperheating module. The pressure reducing ratio is adjustable from 1:1.5 to 1:4, and the temperature reduction range can reach 50-100℃.

[0047] For example, when the exhaust pressure of the high-pressure cylinder is too high, the flow rate can be limited by the second control valve 48, and the steam parameters can be reduced to the allowable range of the intermediate-pressure cylinder by the third desuperheating and pressure-reducing valve 53, thereby effectively reducing the impact on the intermediate-pressure cylinder. Thus, it can be understood that this technical solution establishes a direct steam transport channel between the high-pressure cylinder and the intermediate-pressure cylinder by setting an independent third pipeline 43; it precisely controls the steam flow rate by setting the second control valve 48, thereby avoiding sudden changes in the intake volume of the intermediate-pressure cylinder; and it synchronously adjusts the steam pressure and temperature by setting the third desuperheating and pressure-reducing valve 53, so that the steam parameters entering the intermediate-pressure cylinder match the design values. Therefore, compared with the traditional indirect transport method through the mixing manifold 45, this embodiment reduces the attenuation and fluctuation of steam parameters during the transport process and solves the parameter adjustment problem when the exhaust from the high-pressure cylinder directly enters the intermediate-pressure cylinder.

[0048] Optionally, the third pipeline 43 can be equipped with an insulation layer, and the insulation material is aluminum silicate fiber with a thickness of 80-120mm; a pressure sensor and a temperature sensor can be added between the second control valve 48 and the third de-temperature reducing valve 53 to form a closed-loop control system 100.

[0049] In the above technical solution, the safe integration of dual steam sources is achieved through two-stage parameter adjustment and buffer mixing. Specifically, the high-parameter steam from the first high-pressure cylinder 21 is reduced to the target value via a desuperheating and pressure-reducing valve, while the low-parameter steam from the second high-pressure cylinder 31 is first pressurized and heated by the mechanical steam recompression system 44, and then finely adjusted to match the parameters of the first steam stream via a desuperheating and pressure-reducing valve. The two steam streams are fully homogenized within the mixing manifold 45 through turbulent diffusion and kinetic energy dissipation, thereby eliminating pressure pulsations and temperature stratification. After the steady-state steam flow output from the mixing manifold 45 enters the reheater 46, its thermodynamic parameter stability ensures a uniform temperature distribution on the reheater 46 tube walls, avoiding fatigue damage caused by localized overheating or alternating stress. Compared to the conventional branch reheat system 100, this integrated solution reduces the enthalpy fluctuation range of the reheater 46 outlet steam by more than 60%, reduces equipment vibration amplitude by 45%, and simultaneously improves the thermal efficiency of system 100 by 3-5 percentage points through mechanical recompression to recover waste heat from the low-pressure steam.

[0050] Optionally, such as Figure 1 As shown, system 100 also includes a feedwater regeneration system 600, which is the only feedwater regeneration system in system 100. The first turbine unit 20 is connected to the inlet of the condenser hot well 72 via the sixth pipeline 71, and the second turbine unit 30 is connected to the inlet of the condenser hot well 72 via the seventh pipeline 73. A first equalizing box 74 is installed on the sixth pipeline 71, and a second equalizing box 75 is installed on the seventh pipeline 73. The outlet of the condenser hot well 72 is connected to the condensate inlet of the feedwater regeneration system 600, and the condensate outlet of the feedwater regeneration system 600 is connected to the feedwater inlet of the coal-fired boiler 10.

[0051] For example, the first equalizing tank 74 and the second equalizing tank 75 can adopt a pressure balancing container or buffer tank structure, with a pressure sensor and regulating valve linked inside to dynamically compensate for pipeline pressure fluctuations. As a preferred embodiment, the working pressure range of the equalizing tank can be set to 0.5-1.2 MPa, and the volume is configured according to a safety factor of 1.5-2 times the turbine exhaust volume. The condenser hot well 72 can adopt an inclined separation structure, with a multi-layer corrugated plate separator inside, achieving a condensate recovery efficiency of over 99%. The feedwater regeneration system 600 can use a multi-stage low-pressure heater arranged in series, with the number of heating stages configured as 3-5 stages according to the boiler feedwater temperature requirements, and the temperature difference of each heater stage controlled within the range of 15-25℃.

[0052] In the above scheme, by setting up a single feedwater regeneration system 600 instead of the traditional dual-set configuration, the number of heaters, pumps, valves, and other equipment can be reduced, thereby lowering the complexity and maintenance costs of the system 100. By setting up independent pipelines to connect the exhaust steam of the two turbine units to the condenser hot well 72, and installing equalizing boxes on both pipelines to eliminate pressure imbalance caused by load differences, the water hammer effect can be effectively avoided. In addition, since the condensate is returned to the boiler after being heated by the unified regeneration system 100, the thermal energy can be utilized in a cascade manner, thereby improving the thermal efficiency of the system 100 by 2-3 percentage points. Moreover, this design is particularly suitable for situations where the rated power of the first turbine unit 20 is significantly greater than that of the second turbine unit 30, and the regeneration system 100 can still maintain high-efficiency operation when the second turbine unit 30 is running alone.

[0053] The following is for reference. Figure 2 A method for switching between two turbines in a single boiler according to an embodiment of the first aspect of the present invention is described.

[0054] like Figure 2 As shown, according to an embodiment of the present invention, a method for switching between two boilers in a single boiler is applied to a system 100 for switching between two boilers in a single boiler. The method includes: Step S1: Determine the total power load of the power grid; specifically, during operation, obtain the total power load of the power grid.

[0055] For example, the current total power load can be received directly through the real-time data interface provided by the power dispatch center. For instance, the power dispatch system 100 updates the total grid load data every few seconds or minutes, and this data can be periodically read by the system 100. Alternatively, by deploying load measurement devices at key nodes in the power grid, the electricity consumption of each region can be collected in real time and aggregated to calculate the total power load of the grid.

[0056] Step S2: Determine the total cost of the system 100 to meet the total power load under multiple operating modes. The multiple operating modes include a first operating mode, a second operating mode, and a third operating mode. In the first operating mode, the coal-fired boiler 10 is connected to the first steam turbine unit 20. In the second operating mode, the coal-fired boiler 10 is connected to the second steam turbine unit 30. In the third operating mode, the coal-fired boiler 10 is connected to both the first steam turbine unit 20 and the second steam turbine unit 30.

[0057] Understandably, system 100 has three basic operating modes: the first operating mode, the second operating mode, and the third operating mode. In the first operating mode, the coal-fired boiler 10 supplies steam only to the first turbine unit 20, which generates electricity independently. In the second operating mode, the coal-fired boiler 10 supplies steam only to the second turbine unit 30, which generates electricity independently. In the third operating mode, the coal-fired boiler 10 supplies steam to both the first turbine unit 20 and the second turbine unit 30 simultaneously, with the two turbine units operating in parallel to generate electricity.

[0058] The total cost includes coal consumption cost, equipment depreciation cost, and switching cost. Coal consumption cost includes the coal consumption of the coal-fired boiler 10 when multiple operating modes meet the total power load. Equipment depreciation cost includes the life loss when the system 100 switches from the current operating mode to another operating mode and starts the first turbine unit 20 and / or the second turbine unit 30. The life loss is determined based on the rotor temperature difference between the first turbine unit 20 and / or the second turbine unit 30. Switching cost includes the steam consumption cost and the electricity consumption cost when the system 100 switches from the current operating mode to another operating mode.

[0059] Specifically, the determination of coal-fired costs can be based on preset coal consumption curves of the coal-fired boiler 10 under different loads. For example, for each operating mode, the coal consumption per unit of power generation of the coal-fired boiler 10 under that load is consulted or calculated based on the total electricity load it needs to meet, and then multiplied by the coal price and power generation to obtain the coal-fired cost. The determination of equipment wear-out costs can be based on the number of turbine unit starts and the average wear-out value per start. For example, each time the first turbine unit 20 or the second turbine unit 30 is started, a fixed lifespan wear-out value can be set, which can be estimated based on historical operating data or equipment manufacturer recommendations. When the system 100 switches from the current mode to a new mode requiring turbine unit startup, the corresponding fixed wear-out value is included in the total cost. The assessment of lifespan wear-out can be simply accumulated by monitoring the number of turbine unit start / stop cycles. The determination of switching costs can be based on the average consumption of steam and electricity during preset mode switching processes. For example, when system 100 switches from the first operating mode to the third operating mode, the second steam turbine unit 30 needs to be started, which consumes a certain amount of steam and electricity. These consumptions can be estimated on average based on historical switching data and multiplied by the unit price of steam and electricity to obtain the switching cost.

[0060] Step S3: Based on the total cost, switch system 100 from the current mode to the target mode. The target mode is the mode with the lowest total cost among the first operating mode, the second operating mode, and the third operating mode.

[0061] Specifically, after calculating the total cost under all possible operating modes, the mode selection and switching operation will be performed by system 100. As one implementation, a decision module can be used to compare the total costs of the first, second, and third operating modes, with the mode having the lowest total cost selected as the target mode. For example, if the current total grid load is at a moderate level and the calculated total cost of the second operating mode is the lowest, then system 100 will switch to the second operating mode. The switching process can be performed manually by the operator or automatically through a preset sequence of control commands. For example, once the target mode is determined, the corresponding valves and circuit breakers can be commanded by system 100, thereby enabling the turbine unit to start, stop, or connect to the grid, and system 100 will be adjusted to the target mode.

[0062] In other words, this application provides a method for intelligently deciding when and which mode to switch to based on cost considerations to achieve the most cost-effective and safest outcome. For example, when the current mode is the second operating mode, namely "boiler with small turbine (100MW) mode," based on the total power load, it is determined that the load needs to be increased to 180MW and maintained for 2 hours. Option A: Maintain the current mode without switching, but since the small turbine's maximum power is only 120MW, it cannot reach 180MW, therefore this option is not feasible. Option B: Switch to the second operating mode, namely "boiler with large turbine" mode, where the large turbine can easily handle 180MW, but the small turbine needs to be stopped first, and then the large turbine started, which costs [amount missing]. Calculations revealed that the main unit is currently cold, resulting in high thermal stress losses during startup; furthermore, there are several minutes of power generation interruption during the switching process, leading to lost electricity revenue. Option C: Switch to the third operating mode, namely the "boiler simultaneously operating two units" mode, maintaining the smaller unit at 100MW while starting the main unit and handling 80MW. Calculations showed that although the main unit also needs to start, the load it bears is smaller, the heating process is smoother, and the thermal stress loss cost is lower. The total coal consumption may be slightly higher than operating only the main unit, but considering electricity revenue and equipment losses, the total cost is the lowest.

[0063] According to the method for switching operation of a boiler and two generators according to the present invention, by configuring a boiler and two generator system 100 with different capacities and dynamically selecting the operating mode based on the comprehensive total cost, the challenges faced by traditional thermal power units in deep peak shaving, such as high costs and large equipment losses, are effectively addressed. At the same time, since the switching between different modes is no longer based on fixed load thresholds, but on dynamic decision-making based on "real-time peak shaving demand forecasting + equipment status monitoring + economic model", this method can also enable the system 100 to meet the total power load of the grid while taking into account the economics of coal combustion, equipment health status and mode switching costs, thereby minimizing operating costs and extending equipment life, and significantly improving the peak shaving flexibility and economic operation level of thermal power units in the context of high penetration of new energy.

[0064] According to some embodiments of the present invention, such as Figure 2 As shown, the method also includes: Step S40: Confirm that the target mode is the third operating mode; Step S50: Real-time monitoring of the temperature and pressure at the steam outlet of the first high-pressure cylinder 21 and the steam outlet of the second high-pressure cylinder 31; wherein, real-time monitoring refers to continuously acquiring steam temperature and pressure data through sensors and data acquisition system 100, such as using thermocouples or resistance thermometers for temperature measurement, and using piezoresistive or capacitive sensors for pressure measurement, and these data serve as inputs for subsequent intelligent control.

[0065] The temperature and pressure of the steam outlets of the first high-pressure cylinder 21 and the second high-pressure cylinder 31 are input into a pre-trained neural network model to obtain multiple control parameters. These control parameters include the steam flow rate parameter of the third pipeline 43, the connectivity of the first sub-pipeline 411 and the second sub-pipeline 412, and the compressor speed parameter of the mechanical vapor recompression system 44. The neural network model is pre-trained with the goal of minimizing the temperature difference and pressure difference between the first pipeline 41 and the second pipeline 42.

[0066] It should be noted that the pre-trained neural network model is an intelligent algorithm model trained with a large amount of historical and simulated data to learn the complex nonlinear relationship between input and output. For example, it can employ deep learning architectures such as recurrent neural networks (RNNs) or long short-term memory networks (LSTMs). These control parameters are optimized instructions calculated by the neural network model based on the input data. For example, the steam flow rate of the third pipeline 43 can be controlled by adjusting the opening of the second control valve 48 on that pipeline, for example, by driving the second control valve 48 through a proportional-integral-derivative (PID) controller; the connection status of the first sub-pipeline 411 and the second sub-pipeline 412 is controlled by controlling the first control valve 47; the compressor speed of the mechanical steam recompression system 44 can be precisely controlled by adjusting the power supply frequency and voltage of the compressor motor through a frequency converter.

[0067] "The neural network model is pre-trained with the objective of minimizing the temperature and pressure differences between the first pipe 41 and the second pipe 42." This means that during the model training phase, by defining a loss function and employing optimization algorithms such as gradient descent, the model can output a control strategy that makes the parameters of the two steam streams as close as possible, thereby enabling the model to have parameter matching optimization capabilities. It should be noted that this application does not limit the specific training process of the model.

[0068] In step S60, the first control valve 47, the second control valve 48, and the compressor speed are adjusted based on multiple control parameters so that the pressure and temperature at the outlet of the first pipeline 41 and the pressure and temperature at the outlet of the second pipeline 42 both reach the preset target.

[0069] Specifically, this application monitors the temperature and pressure of the two steam streams in real time and inputs this data into a pre-trained neural network model. This model intelligently calculates the optimal control parameters, including the steam flow rate of the third pipe 43, the connectivity of the first sub-pipe 411 and the second sub-pipe 412, and the compressor speed of the mechanical vapor recompression system 44. By adjusting the mechanical vapor recompression system 44, the pressure and temperature of the steam in the second pipe 42 can be actively and precisely increased, bringing its parameters closer to those of the first pipe 41. Simultaneously, the system 100 intelligently switches between the first sub-pipe 411 and the second sub-pipe 412 based on the predictions of the neural network model, utilizing the differences in flow resistance and heat dissipation characteristics caused by their different pipe diameters and lengths to passively buffer and fine-tune the parameters of the steam in the first pipe 41. This combined approach of "active adjustment" and "passive selection" ensures that the temperature and pressure of the two steam streams are precisely adjusted to be highly similar before entering the mixing manifold 45, thereby achieving smooth mixing. This fundamentally eliminates the risk of thermal collisions caused by excessive differences in steam parameters, ensuring the safe and stable operation of critical equipment such as the reheater 46 and subsequent pipelines. Furthermore, after the two steam streams are gently and uniformly mixed within the mixing header 45, the stability of the steam flow field and temperature field entering the reheater 46 is significantly improved. This ensures that the reheater 46 can operate within its design operating range, avoiding damage to the reheater 46 tube walls caused by localized overheating or uneven heat exchange, and enabling the output of stable reheated steam. Finally, the stable and high-quality reheated steam is fed into the first intermediate-pressure cylinder 22 of the first turbine unit 20, resulting in stable operation of this cylinder section. This not only improves the operating efficiency of this cylinder section but also reduces component fatigue wear caused by fluctuations in inlet parameters, thereby enhancing the long-term reliability and overall operating efficiency of the unit. The above technical solution allows two turbine units to share a single reheat system 100 in the third operating mode, reducing hardware layout. It also solves the problem that the steam temperature and pressure at the outlet of the first high-pressure cylinder 21 and the outlet of the second high-pressure cylinder 31 may differ, leading to uneven steam mixing in the mixing header 45, which in turn causes increased equipment wear, reduced operating efficiency, and increased safety risks.

[0070] According to some embodiments of the present invention, such as Figure 1As shown, system 100 also includes: a fourth pipeline, a fifth pipeline, a conveying air pipeline, a combustion air pipeline, a first air preheater, and a second air preheater. One end of the fourth pipeline and the fifth pipeline are connected to the main steam pipe 34 of the second steam turbine unit 30. One end of the conveying air pipeline and the combustion air pipeline are connected to the coal-fired boiler 10. The first air preheater has a first flow channel and a second flow channel that exchange heat with each other. The first flow channel is connected in series on the conveying air pipeline. The other end of the fourth pipeline is connected to the inlet end of the second flow channel. The second air preheater has a third flow channel and a fourth flow channel that exchange heat with each other. The third flow channel is connected in series on the combustion air pipeline. The other end of the fifth pipeline is connected to the inlet end of the fourth flow channel.

[0071] The fourth pipeline is an auxiliary pipeline connecting the main steam pipe 34 of the second steam turbine unit 30 to the first air preheater of the conveying air duct of the coal-fired boiler 10. The main function of this fourth pipeline is to divert a portion of the main steam to the first air preheater under specific operating conditions to provide additional heating to the conveying air. The first air preheater of the conveying air duct of the coal-fired boiler 10 is a device in the coal-fired boiler 10 system 100 used to preheat the air (primary air) used to convey pulverized coal. It increases the temperature of the primary air by exchanging heat with the boiler exhaust, thereby improving the drying and ignition performance of the pulverized coal and increasing combustion efficiency. In this design, the first air preheater is designed to receive additional steam from the fourth pipeline for heating, further increasing the temperature of the primary air. The fifth pipeline is an auxiliary pipeline connecting the main steam pipe 34 of the second steam turbine unit 30 to the combustion air duct of the coal-fired boiler 10 to the second air preheater. Its function is similar to the fourth pipeline, used to divert a portion of the main steam to the second air preheater under specific conditions to achieve additional heating of the combustion air. The fifth pipeline also typically includes flow control valves, such as regulating valves or throttle valves, to precisely control the steam flow rate and may be equipped with pressure reduction devices. The second air preheater of the combustion air duct of the coal-fired boiler 10 is a device in the coal-fired boiler 10 system 100 used to preheat the combustion air (secondary air). It increases the temperature of the secondary air by exchanging heat with the boiler exhaust, thereby promoting complete fuel combustion and reducing heat loss. In this design, the second air preheater is designed to receive additional steam from the fifth pipeline for heating, further increasing the temperature of the secondary air.

[0072] It should be noted that the fourth and fifth pipelines are not connected by default; that is, these pipelines are generally closed and do not siphon steam to ensure that all the main steam is used to power the turbine and maintain the system at 100% normal efficiency. This is usually achieved by setting normally closed isolation valves.

[0073] like Figure 2 As shown, the method also includes: Step S41: Confirm the target mode as the first operating mode; specifically, in the first operating mode, the first turbine unit 20 undertakes all or most of the power generation tasks.

[0074] Step S51: Confirm that the total power load is lower than the preset threshold, connect the fourth pipeline and / or the fifth pipeline. The preset threshold is less than or equal to the total output of the system 100 when the coal-fired boiler 10 is running at the lowest stable combustion load in the first operating mode.

[0075] The statement that "the preset threshold is less than or equal to the total output of system 100 when the coal-fired boiler 10 is operating at the lowest stable combustion load in the first operating mode" aims to indicate that when system 100 is in the first operating mode and the coal-fired boiler 10 is already operating at its lowest load level capable of stable combustion, its total power output is still higher than the actual demand of the power grid (i.e., the preset threshold). This indicates that under the current low load condition, the boiler has "excess" steam energy, which, if not utilized, may lead to bypass emissions or efficiency losses.

[0076] The instruction to "connect the fourth and / or fifth pipelines when the total power load is confirmed to be below a preset threshold" indicates that when the total power output still exceeds the actual demand of the power grid, the fourth and / or fifth pipelines are selectively opened according to the operating requirements of system 100. This allows steam in the main steam pipe 34 of the second turbine unit 30 to flow to the first air preheater of the delivery air duct of the coal-fired boiler 10 and / or the second air preheater of the combustion air duct of the coal-fired boiler 10. It should be noted that this connection process typically achieves precise regulation of steam flow by controlling the opening degree of valves, rather than simply opening or closing them completely. The purpose is to provide an appropriate amount of steam to preheat the air based on the actual load and boiler operating status, thereby optimizing combustion conditions.

[0077] Specifically, when the total electrical load is below a preset threshold, and the coal-fired boiler 10 still has "excess" output even when operating at the lowest stable combustion load, the system 100 will connect the fourth and / or fifth pipelines to divert some of the steam from the main steam pipe 34 of the second turbine unit 30 to the first air preheater and / or the second air preheater of the combustion air pipe of the coal-fired boiler 10. This high-quality steam provides additional heating to the primary and / or secondary air entering the boiler, significantly increasing the air supply temperature. The higher hot air temperature improves combustion conditions in the furnace, promotes complete combustion of pulverized coal, and reduces incomplete combustion losses, thereby increasing the boiler's combustion efficiency with the same amount of coal. At the same time, the increase in hot air temperature enhances the boiler's stable combustion capability under ultra-low loads, reduces dependence on auxiliary fuels such as combustion oil, lowers operating costs, and makes it possible for the unit to operate safely and stably under even lower loads. This design transforms the "excess" steam energy generated by the boiler under low load into an effective means of improving boiler efficiency and stable combustion, avoiding energy bypass dissipation and achieving internal energy optimization circulation. This not only expands the unit's deep peak-shaving range, enabling it to adapt to lower grid load demands, but also significantly improves overall energy utilization efficiency and economy under low load conditions while ensuring the safe and stable operation of the boiler.

[0078] Through the above technical solution, when the system 100 faces extremely low total power load in the first operating mode, even lower than the output corresponding to the minimum stable combustion load of the coal-fired boiler 10, this application can effectively solve the problems of boiler stable combustion difficulty, efficiency decline and energy waste.

[0079] According to some embodiments of the present invention, such as Figure 3 As shown, when the total electricity load is lower than a preset threshold, step S51 includes: Step S511: Confirm that the total power load is lower than the preset threshold; Step S512: Determine flow control information based on total electrical load, output power of the second turbine unit 30, and steam pressure of the main steam pipe 34 of the second turbine unit 30. The flow control information includes steam flow path, flow rate, temperature, and pressure. Step S513: Connect the fourth pipeline and / or the fifth pipeline based on the flow control information, and control the flow rate, temperature and pressure of the fourth pipeline and / or the fifth pipeline.

[0080] The section on "determining flow control information based on total power load, output power of the second turbine unit 30, and steam pressure in the main steam pipe 34 of the second turbine unit 30" aims to comprehensively consider current grid demand, actual unit output, and the availability of steam sources. This provides a data foundation for selecting pipelines and setting parameters for steam preheating air, ensuring the accuracy and effectiveness of the preheating process. Specifically, this determination process can be implemented using a pre-defined lookup table or rule base. This lookup table or rule base maps different combinations of total power load, output power of the second turbine unit 30, and steam pressure in the main steam pipe 34 to corresponding flow control information based on historical operating data and expert experience. Alternatively, it can be implemented by establishing a mathematical model or a machine learning-based model. This model takes the total power load, output power of the second turbine unit 30, and steam pressure in the main steam pipe 34 as inputs and outputs optimal flow control information through real-time calculation or prediction. For example, it could be a multivariate regression model or a neural network model.

[0081] The phrase "flow control information includes steam flow path, flow rate, temperature, and pressure" can be understood to mean that flow control information primarily includes indicators of the pipeline to be connected, and the flow rate, temperature, and pressure of the steam within that pipeline. Specifically, flow control information is a set of key parameters calculated or determined based on the operating status of system 100, used to guide the steam preheating air process. It clarifies which pipelines need to be activated and the flow rate, temperature, and pressure characteristics that the steam passing through these pipelines should possess. For example, flow control information can be stored in the form of a data structure, such as a tuple or object containing a pipeline identifier (e.g., "fourth pipeline" or "fifth pipeline"), a target flow rate value, a target temperature value, and a target pressure value. Alternatively, flow control information can also be a sequence of control commands that are directly sent to actuators (such as valves or regulators) instructing them to adjust to a specific opening or setpoint to achieve the required flow rate, temperature, and pressure.

[0082] "Connecting the fourth and / or fifth pipelines according to flow control information" physically establishes or adjusts the steam flow path to the air preheater based on the previously determined flow control information. Its purpose is to ensure that steam is accurately delivered to the preheater where air needs preheating and to prepare for subsequent precise control. This connection operation can be achieved by controlling electric or pneumatic valves. When the flow control information indicates that a pipeline should be connected, the corresponding valve will be opened or adjusted to a preset opening degree, allowing steam to pass through. Alternatively, it can be achieved through a logic module integrated into the distributed control system 100 (DCS). This logic module receives the flow control information and, according to a preset control strategy, sends commands to actuators (such as shut-off valves and regulating valves) on the pipeline to achieve pipeline connection.

[0083] Through the above technical solution, when the total power load is lower than a preset threshold, system 100 can intelligently determine and generate precise flow control information based on the real-time total power load, the output power of the second turbine unit 30, and the steam pressure of the main steam pipe 34 of the second turbine unit 30. This flow control information not only clarifies the fourth and / or fifth pipes to be connected, but more importantly, it specifies in detail the target values ​​of flow rate, temperature, and pressure required for the steam in the pipes to be connected. Based on this, system 100 can accurately connect the fourth and / or fifth pipes according to this precise control information, and perform closed-loop or feedforward and feedback-based precise control of the flow rate, temperature, and pressure of the steam passing through these pipes. This refined control mechanism effectively avoids problems such as steam waste, equipment overheating, or system 100 instability that may occur during steam preheating of air under low-load operation. By precisely matching steam parameters with actual preheating requirements, the efficient utilization of steam thermal energy is ensured, and the air preheating effect is optimized, thereby significantly improving the stable combustion capability and operational economy of the coal-fired boiler 10 under deep peak-shaving conditions. Furthermore, this precise control helps protect related equipment, extends its service life, and provides a solid guarantee for the stable and safe operation of the entire one-boiler-two-unit switching system 100. It enables the system 100 to perform energy dispatch more flexibly and efficiently when facing low grid load challenges, further enhancing the unit's deep peak-shaving capability.

[0084] According to some embodiments of the present invention, the outlet end of the second flow channel and / or the fourth flow channel is connected to the steam inlet of the reheater 46.

[0085] Specifically, the first and second air preheaters are devices used to heat the air entering the coal-fired boiler 10 using steam. The outlets of the second and fourth flow channels refer to the outlets from which the steam exits the preheaters after preheating the air. It should be noted that these outlets are typically designed as pipe interfaces to guide the partially heated steam to other systems 100 or for condensation. For example, the steam outlet could be a pipe with a steam trap to discharge condensate and uncondensed steam; or an interface directly connected to other steam pipelines so that the steam can continue to be utilized.

[0086] The reheater 46 of the coal-fired boiler 10 is an important component of the boiler system 100. Its main function is to reheat the steam after it has done work in the high-pressure cylinder, thereby increasing the steam temperature, increasing the work capacity of the intermediate-pressure and low-pressure cylinders of the turbine, and reducing the moisture content of the steam during the expansion process. The steam inlet of the reheater 46 is the starting point for steam to enter the coils or tube bundles of the reheater 46. This inlet is usually a header or pipe connection point used to receive steam from the exhaust steam of the high-pressure cylinder of the turbine.

[0087] Therefore, the statement that "the outlet ends of the second and / or fourth flow channels are connected to the steam inlet of the reheater 46" indicates that a channel for steam to flow from the air preheater to the reheater 46 is established through physical piping and a corresponding valve control system 100. It should be noted that this connection can be achieved in several ways. For example, a separate bypass pipe can be installed to directly lead the steam from the air preheater outlet to the reheater 46 inlet header; or, existing steam piping can be utilized by adding a three-way valve or a switching valve to flexibly switch the steam flow direction. The purpose of this connection is to achieve cascaded utilization of steam, ensuring that steam can still be effectively used in the reheat cycle after preheating the air.

[0088] Through the above technical solution, the steam from the air preheater outlet is introduced into the reheater 46, realizing the cascade and series utilization of waste heat. During low-load operation, the steam drawn from the main steam pipe 34, after releasing some heat in the air preheater to heat the air supply, still has a significantly higher temperature and pressure than the cold section steam in the reheater 46. Introducing this steam into the reheater 46 inlet is equivalent to supplementing the reheat system 100 with a high-quality heat source, thereby directly improving the overall thermal efficiency. This allows the same amount of steam's heat energy to be used sequentially to improve boiler combustion efficiency and main steam cycle efficiency, reducing cold source losses. Simultaneously, this solution enhances the stability of the reheat steam temperature under low load; the supplemented heat source helps maintain the reheat steam temperature, ensuring the operating efficiency and safety of the intermediate-pressure cylinder. Furthermore, together with the preceding solution, it forms a closed-loop optimization of the entire process from "fuel" to "work" under deep peak shaving. Through the precise scheduling and reuse of energy within the system 100, the economic advantages of the unit over a wide load range are further amplified, effectively avoiding energy waste caused by the underutilization of steam after preheating the air.

[0089] According to some embodiments of the present invention, when the current mode is a first operating mode or a second operating mode and the target mode is a third operating mode, or when the current mode is a first operating mode and the target mode is a second operating mode, or when the current mode is a second operating mode and the target mode is a first operating mode, switching the system 100 from the current mode to the target mode based on the total cost includes: Based on the target mode, total power load, current main steam pressure of system 100, real-time speed and load of the currently operating turbine unit, the first load change curve of the currently operating turbine unit and the second load change curve of the turbine unit to be started are determined. The first load change curve and the second load change curve are obtained by closed-loop control with minimizing the change in total output power of system 100 as the highest priority. According to the first load change curve, the power of the currently operating turbine unit is slowly reduced, and the turbine unit to be started is started according to the second load change curve; the power of the first turbine unit 20 and the second turbine unit 30 are adjusted to match the total power load.

[0090] It should be noted that the above methods are applicable to specific operating mode switching scenarios, namely switching from a single-unit operating mode (first or second operating mode) to a dual-unit operating mode (third operating mode), or switching between two single-unit operating modes (from first to second operating mode, or from second to first operating mode). These switching scenarios typically involve the start-up or shutdown of turbine units, which are the main cause of fluctuations in the total output power of the system. For example, switching from the first operating mode to the third operating mode means that, while the first turbine unit 20 is running, the second turbine unit 30 needs to be started and connected to the grid; switching from the first operating mode to the second operating mode means that the first turbine unit 20 is shut down and the second turbine unit 30 is started and connected to the grid. If these operations are not carefully controlled, they can easily have an adverse impact on grid stability and equipment lifespan.

[0091] When switching modes, it is necessary to determine the first load change curve of the currently operating turbine and the second load change curve of the turbine to be started based on key operating parameters such as the target mode, the total power load of the grid, the current main steam pressure of system 100, and the real-time speed and load of the currently operating turbine. These parameters provide comprehensive information on the current and target states of system 100 and are the basis for generating smooth transition curves. For example, a model predictive control (MPC) approach can be used to predict the system 100 response over a future period by establishing a dynamic model of system 100 and optimizing the control strategy to generate load change curves; alternatively, artificial intelligence algorithms, such as reinforcement learning, can be used to train the model in a simulation environment, enabling it to learn how to generate optimal load change curves under different operating conditions. Furthermore, a rule base or lookup table based on expert experience can be used to directly query or calculate the corresponding load change curves according to preset operating conditions.

[0092] The generation of the first and second load change curves prioritizes minimizing the total output power variation of system 100 and is achieved through closed-loop control. Minimizing the total output power variation of system 100 aims to ensure that the total power output provided by system 100 to the grid is as smooth as possible during mode switching, avoiding sudden drops or rises in power, thereby maintaining the frequency stability and operational safety of the grid. The closed-loop control mechanism means that system 100 monitors the actual power output in real time and compares it with the preset load change curve, dynamically adjusting control commands based on the deviation to ensure that the actual operating trajectory closely follows the target curve. For example, a proportional-integral-derivative (PID) controller can be used to adjust the turbine unit's valve opening or fuel supply based on the power deviation and its rate of change; alternatively, an adaptive control strategy can be used to dynamically adjust the controller gain based on changes in system 100 parameters to adapt to different operating conditions.

[0093] Based on the established first load change curve, the power output of the currently operating turbine unit will be gradually reduced. This "gradual reduction," as opposed to a traditional "emergency stop," aims to avoid thermal stress, vibration, and grid impact caused by a rapid power drop. Simultaneously, based on the second load change curve, the turbine unit awaiting startup will be gradually started and connected to the grid. The startup process also follows a preset curve to ensure a smooth and controllable transition from standstill to grid connection, avoiding load shocks. For example, power reduction can be achieved by gradually closing the turbine's main steam valve or regulating valve; when starting the turbine unit, a strict startup procedure is required, gradually increasing speed, warming up, starting, and connecting to the grid, while precisely controlling steam flow and temperature to ensure that its output power gradually increases according to the second load change curve.

[0094] After the turbine units have reduced power and started up, the power of the first turbine unit 20 and the second turbine unit 30 will be further adjusted to ensure that their combined power output precisely matches the total power load of the grid. This is the ultimate goal of mode switching, ensuring that system 100 can stably and efficiently meet the grid's demands in the new operating mode. For example, the load distribution control system 100 can dynamically adjust the power output of each turbine unit based on their operating characteristics and efficiency curves to optimize the overall operating economy of system 100 while meeting the total load demand.

[0095] The above scheme provides a stable switching solution that neither affects grid power supply nor impacts equipment. Its core principle is "seamless load transfer and proactive pressure buffering." Taking the switch from the first operating mode to the third operating mode as an example, a specific implementation process is illustrated below: First, 10 minutes in advance, the rotor of the first turbine unit 20 is warmed up with steam, increasing the speed to 2950 revolutions per minute (rated 3000 revolutions per minute). Then, load handover begins: the first turbine unit 20 slowly opens its inlet steam control valve to begin receiving load. Under the command of the control system 100, the control valve of the second turbine unit 30 begins to decrease its opening by the same amount. The monitoring screen displays: the total load stabilizes at 100MW. The load of the second turbine unit 30 gradually decreases from 100MW to 95, 90, 85… and the load of the first turbine unit 20 gradually increases from 0MW to 5, 10, 15… When the second turbine unit decreases to 80MW and the first turbine unit 20 increases to 20MW, the load transfer is suspended. After System 100 checks that all steam parameters, vibration, and other parameters are normal, it declares the switchover complete. Subsequently, based on the overall target of 180MW, the smaller turbine is upgraded back to 100MW, and the larger turbine is upgraded to 80MW. The specific load increase and decrease process can be based on a pre-determined load change curve, which will not be elaborated here.

[0096] Through the above technical solution, this application can effectively solve the problem of drastic fluctuations in the total output power of System 100 caused by the start-up or shutdown of the turbine unit when switching operating modes. Specifically, by comprehensively considering the target mode, total electrical load, current main steam pressure of System 100, and real-time operating parameters of the turbine unit, the load reduction curve of the currently operating unit and the load increase curve of the unit to be started are accurately determined. These curves prioritize minimizing the change in the total output power of System 100 and are adjusted in real time through closed-loop control to ensure a smooth transition of the total output power of System 100 during the switching process, avoiding impact on the power grid. This coordinated load increase and decrease strategy allows the two turbine units to operate synchronously during the switching period, one decreasing and the other increasing, so that the total output power of System 100 is almost constant and matches the power grid demand. This not only significantly improves the continuity and frequency stability of power grid supply and enhances the grid's ability to accept fluctuations, but also avoids drastic fluctuations in key parameters such as main steam pressure during smooth load transfer, effectively reducing stress impact on major equipment such as the coal-fired boiler 10 and the turbine, extending equipment life, and improving operational safety. With the core concern of power fluctuations resolved, the upper-level intelligent decision-making system 100 can initiate mode switching more frequently and flexibly, thereby fully leveraging the potential of the system 100 in deep peak shaving and waste heat utilization, and further improving the economy and operational flexibility of the system 100.

[0097] According to some embodiments of the present invention, when the current mode is the third operating mode and the target mode is the first operating mode or the second operating mode, Switching system 100 from its current mode to the target mode based on the total cost includes: The third and fourth load change curves are determined based on the target mode, total power load, current main steam pressure of system 100, real-time speed and load of the first turbine unit 20 and the second turbine unit 30. The third load change curve is the total power change curve of system 100, and the rate of change of total power is within the preset range. The fourth load change curve is the power change curve of the turbine unit to be shut down, and the endpoint is 0. The power of the turbine unit to be shut down is reduced according to the fourth load change curve, and the power of another turbine unit other than the turbine unit to be shut down is adjusted according to the fifth load change curve. The fifth load change curve is used to offset the third load change curve and make the total power of the system 100 follow the third load change curve.

[0098] Specifically, the method proposed in this application is applied in a scenario where the current system 100 is in the third operating mode, i.e., the coal-fired boiler 10 is simultaneously connected to the first turbine unit 20 and the second turbine unit 30. However, based on total cost optimization decisions, it is necessary to switch to the first operating mode (the coal-fired boiler 10 is only connected to the first turbine unit 20) or the second operating mode (the coal-fired boiler 10 is only connected to the second turbine unit 30). This switching process involves the shutdown of one turbine unit, therefore, the smoothness of the switching is critical to avoid impacting the power grid and equipment.

[0099] In the aforementioned switching scenario, the third and fourth load change curves first need to be determined based on the target mode, the total power load of the grid, the current main steam pressure of system 100, and the real-time speed and load of the first turbine unit 20 and the second turbine unit 30. The target mode specifies the single-unit operating state after the switch; the total power load represents the external demand that system 100 needs to meet; the current main steam pressure of system 100 reflects the real-time output status of the boiler; and the real-time speed and load of the first turbine unit 20 and the second turbine unit 30 provide the current operating conditions of the two units. These parameters are the basic inputs for generating a smooth switching path. Specifically, a model predictive control (MPC) algorithm can be used, taking the aforementioned real-time operating parameters as input, combined with the system 100 dynamic model and preset optimization objectives (e.g., minimizing power fluctuations, minimizing equipment thermal stress, etc.), to calculate and generate these load change curves online. Another approach is to pre-establish a database containing load change curves under various operating conditions. During actual operation, the load change curve that best matches the current operating condition can be quickly obtained based on the parameters monitored in real time through table lookup and interpolation.

[0100] The third load change curve represents the trajectory of the total power output of the entire system 100 over time as it switches from a dual-machine operation mode to a single-machine operation mode. Its core characteristic is that the rate of change of the total power is strictly controlled within a preset range. This means that the decrease in the total power of the system 100 is gradual and controllable, effectively avoiding sudden power drops. The determination of this preset range can be based on the specific requirements of the power grid for power fluctuation stability; for example, the power grid dispatching department may specify the maximum allowable power change per minute. Alternatively, it can be based on the thermal stress tolerance of the equipment itself, such as the coal-fired boiler 10, the first turbine unit 20, and the second turbine unit 30, ensuring that the equipment will not be damaged due to excessively rapid temperature or pressure changes during load reduction. This curve can be described by various mathematical models, such as piecewise linear functions, exponential decay functions, or polynomial functions, with specific parameters (such as the starting point, ending point, and rate of decrease) calculated using the aforementioned determination steps. Meanwhile, the fourth load change curve describes how the power output of the selected turbine unit (i.e., the unit chosen to be shut down from dual-unit operation) gradually decreases from the current load to zero during the switching process. Its "endpoint of 0" clearly indicates that the unit will eventually stop completely. The generation of this curve also requires comprehensive consideration of the unit's own load reduction capacity, thermal stress limitations, and coordination with the coal-fired boiler 10. For example, a linear decrease, a stepped decrease, or an optimal load reduction curve calculated based on the unit's thermal stress model can be used. Its main purpose is to ensure that the temperature and pressure change rates of key components such as the rotor and cylinder of the unit remain within a safe range during shutdown, thereby minimizing equipment wear and extending equipment lifespan.

[0101] After determining the aforementioned curves, the control system 100 precisely adjusts the steam intake of the turbine unit to be shut down according to the fourth load change curve, causing its power output to gradually decrease according to the curve. For example, this can be achieved by gradually closing the turbine's main steam valve or adjusting the valve opening. In actual operation, the control system 100 monitors the power output of the unit to be shut down in real time and compares it with the fourth load change curve. Through a feedback control mechanism, it ensures that the actual power closely follows the target curve, achieving a smooth load reduction.

[0102] While the power of the turbine unit to be shut down decreases, the power of the other turbine unit that continues to operate needs to be adjusted according to the fifth load change curve. This adjustment is key to achieving a smooth transition of the total power of the system (100). The power adjustment of this operating unit can be either an increase or a maintenance, depending on the difference between the target total power of the system (100) (third load change curve) and the power decrease of the turbine unit to be shut down (fourth load change curve). For example, parameters such as the steam intake and fuel quantity of the operating unit can be adjusted to make its power output respond in real time to the fifth load change curve. The core function of the fifth load change curve is to offset the impact of the power decrease of the turbine unit to be shut down on the total power of the system (100) and to ensure that the total power of the entire system (100) accurately follows the preset third load change curve. Specifically, the generation logic of the fifth load change curve is: Fifth load change curve = Third load change curve - Fourth load change curve. This collaborative control strategy ensures that while the power of the unit waiting to be shut down decreases, the power of the other operating unit can be precisely compensated or adjusted, so that the total power output of the entire system 100 always closely follows the preset third load change curve with a rate of change within a preset range.

[0103] Through the above technical solution, this application effectively solves the problem of drastic fluctuations in the total power of system 100 during the switch from dual-unit operation mode to single-unit operation mode, which can lead to grid instability and additional equipment losses. Specifically, by pre-determining a third load change curve with a total power change rate within a preset range as the smooth transition target for the total power of system 100, and simultaneously generating a fourth load change curve for the unit to be shut down, and calculating a fifth load change curve based on these two curves to adjust the power of the other operating unit, coordinated control of the power of the two turbine units is achieved. During the switchover process, the power of the unit to be shut down gradually decreases according to the fourth load change curve until it stops operating, while the power of the other operating unit is precisely adjusted according to the fifth load change curve to compensate for the power reduction of the unit to be shut down in real time. This refined coordinated control ensures that the total power output of the entire system 100 can smoothly follow the third load change curve, avoiding the load step drop caused by the traditional "direct shutdown" method. This not only ensures the power continuity and stability of the power grid, especially in grids with high renewable energy penetration, effectively avoiding grid frequency fluctuations caused by sudden power output changes; simultaneously, as the units to be shut down gradually reduce their load to zero according to a curve, the temperature drop rate and thermal stress of key components such as rotors and cylinders are strictly controlled, greatly reducing equipment switching damage and extending equipment lifespan. Furthermore, the main steam pressure of the coal-fired boiler can also transition smoothly, reducing mechanical and thermal shocks to the entire system. This solution completes the smooth switching capability in the critical scenario of "dual-unit to single-unit," forming a seamless switching technology loop across all scenarios together with the previous single-unit to dual-unit solution. This allows dynamic decisions based on economic models to switch freely between the three modes without any concerns, truly transforming the unit's configuration flexibility into a safe and frequently used operational advantage, maximizing the economic benefits throughout its entire lifecycle.

[0104] According to some embodiments of the present invention, step S1 includes: predicting the total power load after a preset time based on historical load data, power grid dispatch plan, weather forecast, and expected mode switching time point; step S3 includes: switching system 100 to target mode at the mode switching time point.

[0105] Specifically, historical load data refers to the actual electricity load record of the power grid over a past period, and its purpose is to reflect the periodic and trend-based changes in the power grid load. It should be noted that historical load data can be obtained from load curve data stored long-term in the SCADA (Supervisory and Data Acquisition) system 100 of the power dispatch center or the power grid operator, or from electricity consumption data collected and archived in real time using devices such as smart meters and sensors.

[0106] A power grid dispatch plan refers to the arrangements for power generation, transmission, and consumption over a future period formulated by power dispatching agencies to ensure the safe and stable operation of the power grid and the balance between power supply and demand. Its function is to provide macro-level guidance and constraints for future power grid operation, reflecting the expected operating status of the power grid. It should be noted that power grid dispatch plans can be obtained through documents or electronic information such as daily, weekly, and monthly power balance plans and unit start-up and shutdown plans issued by power dispatching agencies, or through data interfaces with the power dispatching system to obtain dispatching instructions and forecast information in real time or periodically synchronized.

[0107] The weather forecast refers to the predicted information on changes in meteorological elements (such as temperature, humidity, wind speed, and sunshine) over a future period. Its function is to correct load forecasts, as meteorological conditions have a significant impact on electricity load. The weather forecast can obtain high-precision, regionalized weather forecast data through professional meteorological data interfaces or services provided by meteorological departments, or obtain weather forecast information for the next few hours to days using publicly available meteorological data platforms or commercial meteorological services.

[0108] Based on the above information, system 100 can predict the total electricity load after a preset time. That is, by using historical data, planning, and forecasting information, it calculates the total electricity demand of the power grid at a specific point in time or within a specific time period using a forecasting model. Its function is to provide a basis for system 100 to plan its operation mode and resource allocation in advance, enabling forward-looking decision-making. It should be noted that the prediction can be achieved by constructing a load forecasting model using algorithms based on time series analysis (such as ARIMA and Prophet models), machine learning (such as support vector machines and neural networks), or deep learning (such as LSTM). Alternatively, it can combine expert experience methods and statistical regression analysis to conduct correlation analysis between historical load and influencing factors (such as weather and holidays) to establish a forecasting function.

[0109] Meanwhile, System 100 can determine the expected mode switching time point. This means that based on the predicted load change trend, System 100's operational constraints, and optimization objectives, it pre-plans the specific moment when the System 100's operating mode will switch. Its function is to provide a clear switching execution window, avoiding random switching and reducing uncertainty and risk during the switching process. The mode switching time point can be calculated using optimization algorithms (such as dynamic programming or genetic algorithms) combined with load forecast results and the System 100's operating cost model to determine the optimal switching time point. Alternatively, it can be based on empirical rules or preset load thresholds; when the predicted load reaches or exceeds a specific threshold, the mode switching time point is triggered.

[0110] Through the above technical solution, this application enables proactive management of the one-boiler-two-unit switching operation system 100. Specifically, by comprehensively analyzing historical load data, power grid dispatch plans, and weather forecasts, system 100 can more accurately predict the total power load after a preset time, thus providing reliable input for subsequent operation mode optimization. Based on this, system 100 can pre-determine the optimal mode switching time, avoiding the switching lag or frequent switching problems that may occur with traditional real-time load response. In actual operation, system 100 performs mode switching at the preset mode switching time, ensuring the synchronization of the switching operation with the predicted load change trend, thereby effectively reducing equipment damage and energy waste caused by improper switching timing. This proactive switching strategy allows the one-boiler-two-unit switching system 100 to better adapt to the randomness and volatility of new energy output such as wind power and photovoltaics, improving the system 100's ability to respond to load changes, ensuring the stable operation of the power grid, and optimizing overall operating costs. According to the third aspect of the present invention, a control device 200 for switching between two boilers in one furnace is applied to a system 100 for switching between two boilers in one furnace according to the second aspect of the present invention. The control device 200 includes a processor 201, a memory 202, and a computer program 203 stored in the memory 202 and executable on the processor 201. When the processor 201 executes the computer program 203, the control device 200 implements the method for switching between two boilers in one furnace according to the first aspect of the present invention.

[0111] The control device 200 for switching between two boilers in one boiler according to the present invention can further improve the automation of the system 100 for switching between two boilers in one boiler.

[0112] In the description of this invention, it should be understood that the terms "center," "longitudinal," "lateral," "length," "width," "thickness," "upper," "lower," "front," "rear," "left," "right," "vertical," "horizontal," "top," "bottom," "inner," "outer," "clockwise," "counterclockwise," "axial," "radial," and "circumferential" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0113] Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of technical features indicated. Thus, a feature defined as "first" or "second" may explicitly or implicitly include one or more of that feature. In the description of this invention, "a plurality of" means two or more, unless otherwise explicitly specified.

[0114] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection, an electrical connection, or a communication connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0115] In the description of this specification, the references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the present invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0116] Although embodiments of the invention have been shown and described, those skilled in the art will understand that various changes, modifications, substitutions and alterations can be made to these embodiments without departing from the principles and spirit of the invention, the scope of which is defined by the claims and their equivalents.

Claims

1. A method for switching between two turbines in a single furnace, characterized in that, The method is applied to a system (100) with one boiler and two turbines switching operation. The system (100) includes a coal-fired boiler (10), a first turbine unit (20), and a second turbine unit (30). The rated power of the first turbine unit (20) is greater than the rated power of the second turbine unit (30). The method includes: Step S1: Determine the total power load of the power grid; Step S2: Determine the total cost of the system (100) meeting the total power load under multiple operating modes. The multiple operating modes include a first operating mode, a second operating mode, and a third operating mode. In the first operating mode, the coal-fired boiler (10) is connected to the first turbine unit (20). In the second operating mode, the coal-fired boiler (10) is connected to the second turbine unit (30). In the third operating mode, the coal-fired boiler (10) is connected to both the first turbine unit (20) and the second turbine unit (30). The total cost includes coal costs, equipment depreciation costs, and switching costs. The coal cost includes the coal consumption of the coal-fired boiler (10) when the total electricity load is met in each of the multiple operating modes. The equipment wear and tear costs include: the life loss of the first turbine unit (20) and / or the second turbine unit (30) when the system (100) switches from the current operating mode to another operating mode, the life loss being determined based on the rotor temperature difference between the first turbine unit (20) and / or the second turbine unit (30). The switching costs include the steam consumption costs and electrical energy consumption costs when the system (100) switches from the current operating mode to another operating mode; Step S3: Based on the total cost, switch the system (100) from the current mode to the target mode, where the target mode is the mode with the lowest total cost among the first operating mode, the second operating mode, and the third operating mode.

2. The method for switching between two turbines in a single boiler according to claim 1, characterized in that, The first turbine generator set (20) includes a first high-pressure cylinder (21) and a first intermediate-pressure cylinder (22), and the second turbine generator set (30) includes a second high-pressure cylinder (31). The system (100) further includes: a first pipeline (41), a second pipeline (42), a third pipeline (43), a mechanical vapor recompression system (44), a mixing manifold (45), a reheater (46), a first control valve (47), and a second control valve (48). The first pipeline (41) is connected between the steam outlet of the first high-pressure cylinder (21) and the steam inlet of the mixing manifold (45). The first pipeline (41) includes a first sub-pipeline (411) and a second sub-pipeline (412). The diameter and length of the first sub-pipeline (411) are different from those of the second sub-pipeline (412). The first control valve (47) is located on the first pipeline (41) and is configured to selectively connect the steam outlet of the first high-pressure cylinder (21) to the first sub-pipeline. (411) or the second sub-pipeline (412); the second pipeline (42) is connected between the second high-pressure cylinder (31) and the steam inlet of the mixing header (45); the mechanical steam recompression system (44) is installed on the second pipeline (42); the steam outlet of the mixing header (45) is connected to the steam inlet of the reheater (46), the steam outlet of the reheater (46) is connected to the steam inlet of the first intermediate-pressure cylinder (22) of the first turbine unit (20), the steam outlet of the first high-pressure cylinder (21) is connected to the steam inlet of the first intermediate-pressure cylinder (22) through the third pipeline (43), and the second control valve (48) is connected to the third pipeline (43) for controlling the opening and closing of the third pipeline (43) and regulating the flow rate of the third pipeline (43). The method further includes: Step S40: Confirm that the target mode is the third operating mode; Step S50: Monitor the temperature and pressure at the steam outlet of the first high-pressure cylinder (21) and the steam outlet of the second high-pressure cylinder (31) in real time; The temperature and pressure of the steam outlets of the first high-pressure cylinder (21) and the second high-pressure cylinder (31) are input into a pre-trained neural network model to obtain multiple control parameters. These control parameters include the steam flow rate parameter of the third pipeline (43), the connectivity of the first sub-pipeline (411) and the second sub-pipeline (412), and the compressor speed parameter of the mechanical vapor recompression system (44). The neural network model is pre-trained with the goal of minimizing the temperature difference and pressure difference between the first pipeline (41) and the second pipeline (42); Step S60: Adjust the first control valve (47), the second control valve (48), and the compressor speed based on multiple control parameters so that the pressure and temperature at the steam outlet of the first pipeline (41) and the pressure and temperature at the second pipeline (42) both reach the preset target.

3. The method for switching between two turbines in a single boiler according to claim 2, characterized in that, The system (100) further includes: a fourth pipeline, a fifth pipeline, a conveying air pipeline, a combustion air pipeline, a first air preheater, and a second air preheater. One end of the fourth pipeline and the fifth pipeline are connected to the main steam pipe (34) of the second steam turbine unit (30). One end of the conveying air pipeline and the combustion air pipeline are connected to the coal-fired boiler (10). The first air preheater has a first flow channel and a second flow channel that exchange heat with each other. The first flow channel is connected in series with the conveying air pipeline. The other end of the fourth pipeline is connected to the inlet end of the second flow channel. The second air preheater has a third flow channel and a fourth flow channel that exchange heat with each other. The third flow channel is connected in series with the combustion air pipeline. The other end of the fifth pipeline is connected to the inlet end of the fourth flow channel. The method further includes: Step S41: Confirm that the target mode is the first operating mode; Step S51: Confirm that the total power load is lower than a preset threshold, connect the fourth pipeline and / or the fifth pipeline, where the preset threshold is less than or equal to the total output of the system (100) when the coal-fired boiler (10) is running at the lowest stable combustion load in the first operating mode.

4. The method for switching between two turbines in a single boiler according to claim 3, characterized in that, Step S51 includes: Step S511: Confirm that the total power load is lower than the preset threshold; Step S512: Determine flow control information based on the total electrical load, the output power of the second turbine unit (30), and the steam pressure of the main steam pipe (34) of the second turbine unit (30). The flow control information includes the steam flow path, flow rate, temperature, and pressure. Step S513: Connect the fourth pipeline and / or the fifth pipeline based on the flow control information, and control the flow rate, temperature and pressure of the fourth pipeline and / or the fifth pipeline.

5. The method for switching between two turbines in a single boiler according to claim 3, characterized in that, The outlet end of the second flow channel and / or the fourth flow channel is connected to the steam inlet of the reheater (46).

6. The method for switching between two turbines in a single boiler according to any one of claims 1-5, characterized in that, When the current mode is a first operating mode or a second operating mode and the target mode is a third operating mode, or when the current mode is a first operating mode and the target mode is a second operating mode, or when the current mode is a second operating mode and the target mode is a first operating mode, switching the system (100) from the current mode to the target mode based on the total cost includes: The first load change curve of the currently operating turbine unit and the second load change curve of the turbine unit to be started are determined based on the target mode, the total power load, the current main steam pressure of the system (100), the real-time speed and load of the currently operating turbine unit. The first load change curve and the second load change curve are obtained by closed-loop control with the highest priority of minimizing the change in the total output power of the system (100). According to the first load change curve, the power of the currently operating turbine unit is gradually reduced, and the turbine unit to be started is started according to the second load change curve. The power of the first turbine unit (20) and the second turbine unit (30) is adjusted to match the total electrical load.

7. The method for switching between two turbines in a single boiler according to any one of claims 1-5, characterized in that, When the current mode is the third operating mode and the target mode is the first operating mode or the second operating mode, switching the system (100) from the current mode to the target mode based on the total cost includes: Based on the target mode, the total power load, the current main steam pressure of the system (100), and the real-time speed and load of the first turbine unit (20) and the second turbine unit (30), a third load change curve and a fourth load change curve are determined. The third load change curve is the total power change curve of the system (100), and the rate of change of the total power is within a preset range. The fourth load change curve is the power change curve of the turbine unit to be shut down, and the endpoint is 0. The power of the turbine unit to be shut down is reduced according to the fourth load change curve, and the power of another turbine unit other than the turbine unit to be shut down is adjusted according to the fifth load change curve, the fifth load change curve being used to offset the third load change curve and make the total power of the system (100) follow the third load change curve.

8. The method for switching between two turbines in a single boiler according to any one of claims 1-5, characterized in that, Step S1 includes: predicting the total electricity load and the expected mode switching time based on historical load data, power grid dispatch plan, weather forecast, and a preset time. Step S3 includes: switching the system (100) to the target mode at the mode switching time point.

9. A system for switching between two generators in a single furnace (100), characterized in that, include: The system (100) comprises a coal-fired boiler (10), a first turbine unit (20), and a second turbine unit (30), wherein the rated power of the first turbine unit (20) is greater than the rated power of the second turbine unit (30); the system (100) is used in the method according to any one of claims 1-8.

10. A control device (200) for switching between two machines in a single furnace, characterized in that, The control device (200) is applied to the system (100) for switching operation of one furnace and two machines according to claim 9. The control device (200) includes a processor (201), a memory (202), and a computer program (203) stored in the memory (202) and executable on the processor (201). When the processor (201) executes the computer program (203), the control device (200) implements the method for switching operation of one furnace and two machines according to any one of claims 1-8.

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