Electro-hydrogen system energy frequency standby cooperative scheduling method based on successive feasible convex relaxation

Abstract

The invention is suitable for the technical field of electric power-natural gas network collaborative optimization, and provides a successive feasible convex relaxation-based electric hydrogen system energy frequency standby collaborative scheduling method, which comprises the following steps of: firstly, obtaining operation parameters such as a power grid, a gas grid and renewable output and multi-scene load data; establishing an electric power, hydrogen electrolysis and hydrogen-doped natural gas model comprising a generator set and a three-state electrolytic cell, taking frequency control reserve and spinning reserve auxiliary service into consideration, and relaxing a non-convex model containing bilinear constraint into a convex model through Meccke envelope; successive feasible point-convex hull relaxation is adopted to alternately solve convex relaxation and an original non-convex model, and the purpose is to minimize the total cost. By introducing an electrolytic cell three-state model and adopting a successive feasible point-convex hull relaxation solving method, the frequency control reserve and spinning reserve potential provided by the hot standby state of the electrolytic cell is fully excavated, the scheduling precision is improved, the system operation cost is reduced, and the standby pressure of a traditional unit is relieved.

Description

Technical Field

[0001] This application belongs to the technical field of power - natural gas network collaborative optimization, and particularly relates to a method for collaborative scheduling of energy and frequency reserves in an electric - hydrogen - gas system based on successive feasible convex relaxation. Background Technique

[0002] The global energy system is undergoing a structural transformation from being dominated by fossil fuels to being dominated by renewable energy. However, the inherent intermittency and uncertainty characteristics of renewable energy pose severe challenges to system operation. Against this background, the integrated energy system based on the multi - energy coupling of electricity - hydrogen - gas demonstrates significant advantages: by converting surplus renewable energy into green hydrogen through electrolyzers and injecting it into the natural gas pipeline network, it can not only achieve large - scale consumption of renewable energy but also effectively improve the flexibility of system operation. Specifically, as a controllable power load and flexible regulation unit, the electrolyzer's fast response characteristics can form complementary advantages with traditional gas turbines. When power fluctuations occur in the system, the electrolyzer can provide auxiliary services such as frequency regulation through rapid start - stop and power adjustment. This multi - energy coupling collaborative regulation mechanism enables the electric - hydrogen - gas hybrid integrated energy system to adapt to the supply - demand balance requirements in the scenario of high - proportion renewable energy penetration. Therefore, as an important carrier for the supply - demand balance of the energy system, it is crucial to fully explore and utilize the flexibility potential brought by electrolyzers in the electric - hydrogen - gas hybrid integrated energy system, make full use of the fast response ability of electrolyzers to provide auxiliary services such as frequency regulation, and improve the reliability and economy of the integrated energy system.

[0003] However, traditional electrolyzer models usually use a two - state model (operating and shutdown states), ignoring the flexibility and economic potential of the heat reserve state in providing reserve auxiliary services during the actual operation of electrolyzers. In addition, the optimization of integrated energy systems considering equipment start - stop and unit commitment is often a mixed - integer non - linear optimization problem, resulting in the problem that it is difficult to efficiently and accurately solve the energy, frequency, and reserve collaborative scheduling in the current electric - hydrogen - gas hybrid integrated energy system under multi - medium coupling. Summary of the Invention

[0004] The embodiment of this application provides a method for collaborative scheduling of energy and frequency reserves in an electric - hydrogen - gas system based on successive feasible convex relaxation, which can solve the problem that it is difficult to efficiently and accurately solve the energy, frequency, and reserve collaborative scheduling in the current electric - hydrogen - gas hybrid integrated energy system under multi - medium coupling.

[0005] In a first aspect, an embodiment of the present application provides a method for coordinated scheduling of energy-frequency reserve in an electric-hydrogen-gas system based on successive feasible convex relaxation, including the following steps: Step 1: Obtain the network coefficients and operating coefficients of the power grid and gas network models. The network coefficients include the power grid topology, gas network topology, line resistance and impedance, natural gas, and hydrogen calorific value. The operating coefficients include the power generation coefficients of generator sets, the coefficients of wind power and photovoltaic inverters, gas source parameters, electrolyzer device parameters, and pressurization station parameters. Step 2: Obtain the dynamic operation scenario data at different time sections. The dynamic operation scenario data includes the power grid load demand, gas network load demand, wind power and photovoltaic output, frequency control reserve demand, and spinning reserve demand scenario data. Step 3: Combining the network coefficients, the operating coefficients, and the dynamic operation scenario data, using the total cost of the electric-hydrogen-gas hybrid integrated energy system as the objective function, successively establish an operation model of the power system considering the combination of generator sets and electrolyzers, an operation model for providing frequency control reserve and spinning reserve ancillary services, and a dynamic natural gas system operation model considering hydrogen blending in pipelines, and combine the objective function with the three established models to construct an optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system considering frequency control reserve, spinning reserve, and unit commitment. Step 4: For the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system established in Step 3, convexify the bilinear terms in all non-convex constraints in the model through McCormick envelopes to obtain an optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system. Step 5: Use the successive feasible point-convex hull relaxation method to alternately solve the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system and the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system to obtain the optimal scheduling method.

[0006] In a possible implementation manner of the first aspect, the objective function in Step 3 is specifically as follows:

[0007] (A-1)

[0008] where the subscript represents the generator set, including coal-fired units and gas-fired units; the subscript represents the time section; the subscript represents the electrolyzer; the subscript represents the electrical load; the subscript represents the natural gas source; the subscript represents the gas load; represents the set of coal-fired units; represents the set of gas-fired units; represents the unit start-up cost of the generator set; represents the unit shutdown cost of the generator set; represents the unit up-spinning reserve cost of the generator set; Represents the reserve cost under the spinning reserve unit of the generating set; Represents the unit power generation cost of the coal-fired unit; Represents the unit non-fuel operation and maintenance cost of the gas-fired unit; Represents the unit cost of the gas-fired unit for providing upward reserve of frequency control reserve; Represents the unit cost of the gas-fired unit for providing downward reserve of frequency control reserve; Represents the unit start-up cost of the electrolyzer; Represents the unit cost of cutting off the power load; Represents the unit gas supply cost of the gas source; Represents the unit cost of cutting off the gas load; Represents the start-up action of the generating set; Represents the shutdown action of the generating set; Represents the upward spinning reserve capacity provided by the generating set; Represents the downward spinning reserve capacity provided by the generating set; Represents the active power of power generation of the generating set; Represents the upward reserve capacity of frequency control reserve provided by the gas-fired unit; Represents the downward reserve capacity of frequency control reserve provided by the gas-fired unit; Represents the start-up action of the electrolyzer; Represents the active power demand of the power load; Represents the active power actually supplied to the power load; Represents the gas supply volume of the natural gas source; Represents the required mass flow rate of the natural gas load; Represents the actual mass flow rate supplied to the natural gas load;

[0009] The first item of the objective function in Equation (A-1) is the start-stop cost and spinning reserve cost of the generating set, the generating set includes coal-fired units and gas-fired units, the second item is the power generation cost of the coal-fired unit, the third item is the cost of power generation and providing frequency control reserve of the gas-fired unit, the cost of power generation and providing frequency control reserve includes upward reserve cost and downward reserve cost, the fourth item is the start-up cost of the electrolyzer, the fifth item is the cost of cutting off the power load, the sixth item is the gas supply cost of the natural gas source, and the seventh item is the cost of cutting off the gas load;

[0010] The power system operation model considering the combination of units and electrolyzers in Step 3 is specifically as follows:

[0011] (A-2)

[0012] (A-3)

[0013] (A-4)

[0014] (A-5)

[0015] (A-6)

[0016] (A-7)

[0017] (A-8)

[0018] (A-9)

[0019] (A-10)

[0020] (A-11)

[0021] (A-12)

[0022] (A-13)

[0023] (A-14)

[0024] (A-15)

[0025] (A-16)

[0026] (A-17)

[0027] (A-18)

[0028] (A-19)

[0029] (A-20)

[0030] (A-21)

[0031] (A-22)

[0032] (A-23)

[0033] Among them, the subscripts and represent power nodes; the subscript represents the line from power node to power node ; the subscript represents a new energy unit; the subscript represents the reference busbar; represents the set of generator units connected to node ; represents the set of new energy units connected to node ; represents the set of nodes connected to node ; represents the set of power loads connected to node ; represents the set of electrolyzers connected to node ; represents the active power output of the new energy unit during time period ; is the active power of the line from node to node ; is the square of the current of the line from node to node ; is the resistance of the line from node to node ; represents the hydrogen production power of the electrolyzer; represents the reactive power output of the generator unit; represents the reactive power output of the new energy unit during time period ; is the reactive power of the line from node to node ; is the reactance of the line from node to node ; is the reactive power actually supplied to the power load; is the square of the voltage amplitude of node ; and are the voltage phase angles of node and node ; and are respectively the minimum and maximum values of the square of the voltage amplitude of node ; is the capacity of the line from node to node ; is the reactive power demand of the power load; is the predicted active power of the new energy unit for the day-ahead; For the day-ahead prediction of reactive power of new energy units; is the voltage phase angle of the reference bus; is an integer variable representing the operating state of the generating unit at time period t, where 1 represents the operating state and 0 represents the non-operating state; and are respectively the minimum and maximum active power generations of the unit; and are respectively the minimum and maximum reactive power generations of the unit; represents the maximum ramp rate of the unit; represents the minimum continuous operation time after the unit starts; and are respectively the minimum and maximum power consumptions during the operation of the electrolyzer; is the power consumption required when the electrolyzer is in the hot standby state; is an integer variable representing the operating state of the electrolyzer at time period t, where 1 represents the operating state and 0 represents the non-operating state; is an integer variable representing the hot standby state of the electrolyzer at time period t, where 1 represents being in the hot standby state and 0 represents the non-hot standby state; is the mass flow rate of hydrogen produced by the electrolyzer; is the higher calorific value of hydrogen, taken as 142 MJ / kg; is the hydrogen production conversion efficiency of the electrolyzer; is an integer variable representing the shutdown state of the electrolyzer at time period t, where 1 represents the shutdown state and 0 represents the non-shutdown state;

[0034] Equation (A-2) is the active power balance equation of the node; Equation (A-3) is the reactive power balance equation of the node; Equation (A-4) is the relationship between the node voltage and the line power; Equation (A-5) is the relationship between the voltage phase angle and the line power; Equation (A-6) is the second-order cone relaxation form of the branch power flow; Equation (A-7) is the upper and lower limit constraints of the node voltage; Equation (A-8) is the line transmission capacity constraint; Equation (A-9) is the active load demand constraint; Equation (A-10) is the upper and lower limit constraints of the reactive load; Equation (A-11) is the active power constraint of the grid-connected new energy; Equation (A-12) is the reactive power constraint of the grid-connected new energy; Equation (A-13) stipulates that the phase angle of the reference bus is 0; Equation (A-14) is the upper and lower limit constraints of the active power output of the generator in the operating state; Equation (A-15) is the upper and lower limit constraints of the reactive power output of the generator in the operating state; Equation (A-16) is the active power ramp constraint of the generator; Equation (A-17) is the start-stop action and state constraint of the generator; Equation (A-18) is the minimum operating time constraint of the generator; Equation (A-19) is the upper and lower limit constraints of the power of the electrolyzer in the operating state or the hot standby state; Equation (A-20) is the efficiency constraint of the electrolyzer during electrolytic hydrogen production; Equation (A-21) is the state constraint of the electrolyzer, which can only be in the operating, hot standby or off state at the same time; Equation (A-22) is the start-up state constraint of the electrolyzer; Equation (A-23) restricts that the electrolyzer cannot directly change from the off state to the hot standby state;

[0035] The operation model for providing frequency control reserve and spinning reserve ancillary services in Step 3 is specifically as follows:

[0036] (A-24)

[0037] (A-25)

[0038] (A-26)

[0039] (A-27)

[0040] (A-28)

[0041] Among them, is the spinning reserve upward reserve capacity provided for the electrolyzer; is the required spinning reserve upward reserve capacity; is the spinning reserve downward reserve capacity provided for the electrolyzer; is the required spinning reserve downward reserve capacity; is the frequency control reserve upward reserve capacity provided for the electrolyzer; is the required frequency control reserve upward reserve capacity; Reserve capacity provided for the electrolyzer under frequency control reserve; Reserve capacity provided for the required frequency control reserve;

[0042] Equation (A-24) indicates that the spinning reserve is provided jointly by coal-fired units, gas-fired units, and electrolyzers; Equation (A-25) indicates that the frequency control reserve is provided jointly by gas-fired units and electrolyzers; Equation (A-26) represents the upper and lower limits and ramping constraints of the spinning reserve provided by coal-fired units; Equation (A-27) represents the upper and lower limits and ramping constraints of the spinning reserve and frequency control reserve provided by gas-fired units; Equation (A-28) represents the capacity limits of the spinning reserve and frequency control reserve provided by electrolyzers in the operating and hot standby states;

[0043] The specific operation model of the dynamic natural gas system considering hydrogen blending in pipelines in Step 3 is as follows:

[0044] (A-29)

[0045] (A-30)

[0046] (A-31)

[0047] (A-32)

[0048] (A-33)

[0049] (A-34)

[0050] (A-35)

[0051] (A-36)

[0052] (A-37)

[0053] (A-38)

[0054] (A-39)

[0055] (A-40)

[0056] (A-41)

[0057] (A-42)

[0058] (A-43)

[0059] (A-44)

[0060] (A-45)

[0061] (A-46)

[0062] (A-47)

[0063] (A-48)

[0064] (A-49)

[0065] where the subscripts and represent natural gas nodes; the subscript represents the natural gas node and the pipeline between the natural gas node ; the set is the set of nodes connected to the natural gas node ; the set is the set of natural gas sources connected to the natural gas node ; the set is the set of electrolyzers connected to the natural gas node ; the set is the set of pressurization stations connected to the natural gas node ; the set is the set of gas turbines connected to the natural gas node ; the set is the set of loads connected to the natural gas node ; is the density of the natural gas - hydrogen mixture in the natural gas pipeline; is the length of the time section; and are the gas mass flows at the beginning and end of the natural gas pipeline respectively; is the cross - sectional area of the natural gas pipeline; is the length of the natural gas pipeline; and are the pressures at the natural gas nodes; is the mass flow of the gas in the natural gas pipeline; is the friction factor of the turbulent flow in the natural gas pipeline; is the diameter of the natural gas pipeline; is the mass fraction of hydrogen in the natural gas pipeline; and are the mass fractions of hydrogen at the beginning and end of the natural gas pipeline respectively; is the pressure of the pipeline; is the specific gas constant of the natural gas - hydrogen mixture in the pipeline; is the compressibility factor of the pipeline; is the ambient temperature; is the specific gas constant of hydrogen; is the specific gas constant of natural gas; is the mass flow rate of the gas in the pressurization station; is the mass flow rate of natural gas consumed by the gas turbine unit; is the required mass flow rate of the natural gas - hydrogen mixture; is the higher heating value of natural gas, taken as 53.37 MJ / kg; is the hydrogen mass fraction at the natural gas node; is the hydrogen mass fraction in the pressurization station; is the power generation efficiency of the gas turbine unit; is the maximum value of the mass fraction of hydrogen injected into the natural gas pipeline; is the maximum value of the mole fraction of hydrogen injected into the natural gas pipeline; and are the densities of hydrogen and natural gas under standard conditions respectively; and are the minimum and maximum values of the pipeline pressure; and are the minimum and maximum values of the mass flow rate of natural gas supplied by the natural gas source; is the maximum value of the ramping rate of natural gas supplied by the natural gas source; and are the minimum and maximum values of the gas density in the natural gas pipeline respectively; and are the minimum and maximum values of the pressurization factor of the pressurization station respectively; and are the minimum and maximum values of the mass flow rate of the gas in the pressurization station respectively;

[0066] Equation (A-29) represents the mass conservation of the natural gas-hydrogen mixture in the pipeline; Equation (A-30) represents the momentum conservation of the natural gas-hydrogen mixture in the pipeline; Equation (A-31) is the advection transport equation of hydrogen, representing the mass conservation of hydrogen in the pipeline; Equation (A-32) is the state equation, indicating that the pressure and density of the natural gas-hydrogen mixture are related to the temperature; Equation (A-33) is the calculation rule for the specific gas constant of the natural gas-hydrogen mixture; Equation (A-34) is the formula for calculating the average pressure of the natural gas-hydrogen mixture in the pipeline; Equation (A-35) is the formula for calculating the average mass flow rate of the natural gas-hydrogen mixture in the pipeline; Equation (A-36) is the formula for calculating the average mass fraction of hydrogen in the pipeline; Equation (A-37) is the nodal mass flow balance equation of the natural gas-hydrogen mixture; Equation (A-38) represents the energy conversion relationship between the natural gas-hydrogen mixture demand and the original natural gas demand; Equation (A-39) represents the nodal mass flow balance equation of hydrogen; Equation (A-40) represents the power generation efficiency of the gas turbine unit; Equation (A-41) represents the relationship between the maximum hydrogen injection molar fraction and the maximum hydrogen injection mass fraction in the pipeline; Equation (A-42) is the limit of the hydrogen injection mass fraction in the pipeline; Equation (A-43) is the pressure limit of the natural gas node; Equation (A-44) is the gas supply limit of the natural gas source; Equation (A-45) is the ramp constraint of the natural gas source; Equation (A-46) is the gas density limit of the pipeline; Equation (A-47) is the boost ratio constraint of the pressurization station; Equation (A-48) is the gas mass flow limit of the pressurization station; Equation (A-49) is the limit of the natural gas demand.

[0067] Optionally, in another possible implementation of the first aspect, in the above step 4, the bilinear terms in all non-convex constraints in the model are convex-relaxed through the McCormick envelope to obtain a convex model for the optimal scheduling of the integrated electricity-hydrogen-gas energy system, specifically as follows:

[0068] The six non-linear constraints (A-30), (A-31), (A-32), (A-38), (A-39), and (A-40) in the non-convex model for the optimal scheduling of the integrated electricity-hydrogen-gas energy system established in step 3 are formula-transformed and the bilinear terms therein are relaxed using the McCormick envelope, specifically as follows:

[0069] Convert (A-30)-(A-32) respectively to:

[0070] (A-50)

[0071] (A-51)

[0072] (A-52)

[0073] Convert (A-38) to (A-40) respectively into:

[0074] (A-53)

[0075] (A-54)

[0076] (A-55)

[0077] Among them, , are introduced auxiliary variables;

[0078] Combine equations (A-1) - (A-29), (A-33) - (A-37), (A-41) - (A-49), (A-51) - (A-55) to obtain the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system.

[0079] Optionally, in another possible implementation manner of the first aspect, in the above step 5, the successive feasible point-convex hull relaxation method is used to alternately solve the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system and the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system, specifically as follows:

[0080] Step 51, solve the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system through the GUROBI solver to obtain the lower bound of the objective value and the scheduling strategy. The scheduling strategy includes the output and start-stop status of the generator set and electrolyzer, the power grid power flow, the output of wind power and photovoltaic power, the output of the natural gas source, and the flow of the gas network pipeline;

[0081] Step 52, solve the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system by fixing the scheduling strategy to obtain the upper bound of the objective value and the numerical values of all variables. The fixed scheduling strategy is to fix the numerical values of all variables included in the scheduling strategy in step 51 and solve the model through the DICOPT solver;

[0082] Step 53, refer to the numerical values of the variables corresponding to the bilinear terms in the convex relaxation constraints obtained from the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system, narrow the upper and lower limits of the variables in the bilinear terms of the convex relaxation constraints, so as to solve the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system and improve the lower bound of the objective value;

[0083] Step 54, solve the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system according to the fixed scheduling strategy to update the upper bound of the objective value;

[0084] Step 55: Repeat steps 53 - 54 until the difference between the upper limit and the lower limit of the target value is less than the preset value. Then, determine the obtained target value and the scheduling strategy as the optimal scheduling method.

[0085] Beneficial effects: In the technical solution of this application, first obtain the network coefficients and operating coefficients of the power grid and gas network models, then obtain the dynamic operation scenario data under different time sections, and then combine the network coefficients, operating coefficients, and dynamic operation scenario data. Taking the total cost of the electric-hydrogen-gas hybrid integrated energy system as the objective function, successively establish an operation model of the power system considering the combination of units and electrolyzers, an operation model for providing frequency control reserve and spinning reserve ancillary services, and a dynamic natural gas system operation model considering hydrogen blending in pipelines. Combine the objective function with the three established models to construct a non-convex model for the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system considering frequency control reserve, spinning reserve, and unit commitment. Then, for the established non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system, convexify the bilinear terms in all non-convex constraints in the model through McCormick envelopes to obtain a convex model for the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system. Finally, use the successive feasible point-convex hull relaxation method to alternately solve the convex model for the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system and the non-convex model for the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system to obtain the optimal scheduling method. By introducing the three-state model of the electrolyzer and adopting the successive feasible point-convex hull relaxation solution method, fully exploit the potential of frequency control reserve and spinning reserve provided by the hot standby state of the electrolyzer, improve the scheduling accuracy, reduce the system operation cost, and relieve the standby pressure of traditional units. Brief Description of the Drawings

[0086] To more clearly illustrate the technical solutions in the embodiments of this application, the following will briefly introduce the drawings required for use in the embodiments or the description of the prior art. Obviously, the following-described drawings are only some embodiments of this application. For those of ordinary skill in the art, without creative efforts, other drawings can also be obtained based on these drawings.

[0087] Figure 1 is a schematic flowchart of the energy-frequency reserve coordinated scheduling method for the electric-hydrogen-gas system based on successive feasible convex relaxation provided by an embodiment of this application;

[0088] Figure 2 is a schematic diagram of the spinning reserve (SR) provided by a coal-fired unit under the three-state model provided by an embodiment of this application;

[0089] Figure 3 is a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by a gas turbine unit under the three-state model provided by an embodiment of this application;

[0090] Figure 4 It is a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by an electrolyzer under a three-state model according to an embodiment of the present application;

[0091] Figure 5 It is a schematic diagram of the spinning reserve (SR) provided by a coal-fired power unit under a two-state model according to an embodiment of the present application;

[0092] Figure 6 It is a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by a gas-fired power unit under a two-state model according to an embodiment of the present application;

[0093] Figure 7 It is a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by an electrolyzer under a two-state model according to an embodiment of the present application;

[0094] Figure 8 It is a comparison chart of the default quantity of the optimal scheduling result of an electric-hydrogen-gas hybrid integrated energy system solved based on the successive feasible point-convex hull relaxation method and the default quantity of the energy-frequency reserve coordinated scheduling result of an electric-hydrogen-gas hybrid integrated energy system solved based on the general boundary successive tightening method according to an embodiment of the present application. Detailed implementation manners

[0095] In the following description, specific details such as specific system structures and technologies are proposed for the purpose of illustration rather than limitation, so as to thoroughly understand the embodiments of the present application. However, those skilled in the art should clearly understand that the present application can also be implemented in other embodiments without these specific details. In other cases, detailed descriptions of well-known systems, devices, circuits, and methods are omitted to avoid unnecessary details from interfering with the description of the present application.

[0096] It should be understood that when used in the specification and appended claims of the present application, the term "comprising" indicates the presence of the described features, wholes, steps, operations, elements, and / or components, but does not exclude the presence or addition of one or more other features, wholes, steps, operations, elements, components, and / or their combinations.

[0097] It should also be understood that the term " / and" as used in the specification and appended claims of the present application refers to any combination and all possible combinations of one or more of the associated listed items, and includes these combinations.

[0098] As used in the specification of this application and the appended claims, the term "if" may be construed, depending on the context, as "when", or "once", or "in response to determining", or "in response to detecting". Similarly, the phrase "if determined" or "if [the described condition or event] is detected" may be construed, depending on the context, as meaning "once determined", or "in response to determining", or "once [the described condition or event] is detected", or "in response to detecting [the described condition or event]".

[0099] In addition, in the description of the specification of this application and the appended claims, the terms "first", "second", "third", etc. are used only for distinguishing descriptions and cannot be construed as indicating or implying relative importance.

[0100] Reference to "one embodiment" or "some embodiments" or the like described in the specification of this application means that a specific feature, structure, or characteristic described in connection with that embodiment is included in one or more embodiments of this application. Thus, statements such as "in one embodiment", "in some embodiments", "in other some embodiments", "in still other embodiments", etc. that appear in different places in this specification do not necessarily all refer to the same embodiment, but mean "one or more but not all embodiments", unless otherwise specifically emphasized in another way. The terms "comprising", "including", "having", and their variants all mean "including but not limited to", unless otherwise specifically emphasized in another way.

[0101] The method for coordinated scheduling of energy and frequency reserves of an electric-hydrogen system based on successive feasible convex relaxation provided by this application will be described in detail below with reference to the accompanying drawings.

[0102] Figure 1 A flowchart showing a method for coordinated scheduling of energy and frequency reserves of an electric-hydrogen system based on successive feasible convex relaxation provided by an embodiment of this application is shown.

[0103] As Figure 1 shown, the method for coordinated scheduling of energy and frequency reserves of an electric-hydrogen system based on successive feasible convex relaxation includes the following steps:

[0104] Step 101: Obtain the network coefficients and operating coefficients of the power grid and gas network models. The network coefficients include the power grid topology, gas network topology, line resistance and impedance, natural gas, and hydrogen calorific value. The operating coefficients include the power generation coefficients of the generator sets, the coefficients of the wind power and photovoltaic inverters, the gas source parameters, the parameters of the electrolyzer devices, and the parameters of the pressurization stations;

[0105] Step 102: Obtain the dynamic operation scenario data at different time sections. The dynamic operation scenario data includes the power grid load demand, gas network load demand, wind power and photovoltaic output, frequency control reserve demand, and spinning reserve demand scenario data;

[0106] Step 103: Combining the network coefficient, operation coefficient, and dynamic operation scenario data, using the total cost of the electric-hydrogen-gas hybrid integrated energy system as the objective function, successively establish an operation model of the power system considering the combination of units and electrolyzers, an operation model for providing frequency control reserve and spinning reserve ancillary services, and a dynamic natural gas system operation model considering hydrogen blending in pipelines. Then, combine the objective function with the three established models to construct a non-convex model for the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system considering frequency control reserve, spinning reserve, and unit commitment.

[0107] Further, in the embodiment of the present application, the objective function in the above Step 103 is specifically as follows:

[0108] (A-1)

[0109] where the subscript represents the generator set, including coal-fired units and gas-fired units; the subscript represents the time section; the subscript represents the electrolyzer; the subscript represents the electrical load; the subscript represents the natural gas source; the subscript represents the gas load; represents the set of coal-fired units; represents the set of gas-fired units; represents the unit start-up cost of the generator set; represents the unit shutdown cost of the generator set; represents the unit cost of the spinning reserve upper reserve provided by the generator set; represents the unit cost of the spinning reserve lower reserve provided by the generator set; represents the unit power generation cost of the coal-fired unit; represents the unit non-fuel operation and maintenance cost of the gas-fired unit; represents the unit cost of the gas-fired unit for providing the upper reserve of the frequency control reserve; represents the unit cost of the gas-fired unit for providing the lower reserve of the frequency control reserve; represents the unit start-up cost of the electrolyzer; represents the unit cost of the cut electrical load; represents the unit gas supply cost of the gas source; represents the unit cost of the cut gas load; represents the start-up action of the generator set; represents the shutdown action of the generator set; represents the upper reserve capacity of the spinning reserve provided by the generator set; represents the lower reserve capacity of the spinning reserve provided by the generator set; represents the active power generation of the generator set; Indicates the reserve capacity of the frequency control reserve provided by the gas turbine unit; Indicates the reserve capacity of the frequency control reserve provided by the gas turbine unit; Indicates the start-up action of the electrolyzer; Indicates the active power demand of the electrical load; Indicates the active power actually supplied to the electrical load; Indicates the gas supply volume of the natural gas source; Indicates the required mass flow rate of the natural gas load; Indicates the actual mass flow rate supplied to the natural gas load;

[0110] The first term of the objective function in Equation (A-1) is the start-up and shutdown cost and the spinning reserve cost of the power generation units, which include coal-fired units and gas turbine units. The second term is the power generation cost of the coal-fired units. The third term is the cost of power generation and providing frequency control reserve of the gas turbine units, and the cost of power generation and providing frequency control reserve includes the up-reserve cost and the down-reserve cost. The fourth term is the start-up cost of the electrolyzer. The fifth term is the cost of shedding electrical load. The sixth term is the gas supply cost of the natural gas source. The seventh term is the cost of shedding gas load;

[0111] The power system operation model considering the combination of units and electrolyzers in Step 3 above is specifically as follows:

[0112] (A-2)

[0113] (A-3)

[0114] (A-4)

[0115] (A-5)

[0116] (A-6)

[0117] (A-7)

[0118] (A-8)

[0119] (A-9)

[0120] (A-10)

[0121] (A-11)

[0122] (A-12)

[0123] (A-13)

[0124] (A-14)

[0125] (A-15)

[0126] (A-16)

[0127] (A-17)

[0128] (A-18)

[0129] (A-19)

[0130] (A-20)

[0131] (A-21)

[0132] (A-22)

[0133] (A-23)

[0134] Among them, the subscript and represent power nodes; the subscript represents the line from power node to power node ; the subscript represents new energy units; the subscript represents the reference bus; represents the set of generator units connected to node ; represents the set of new energy units connected to node ; represents the set of nodes connected to node ; represents the set of power loads connected to node ; represents the set of electrolyzers connected to node ; represents the active power output of new energy unit in time period ; is the active power of the line from node to node ; is the active power from node to node The square of the current in the branch line; From node To node The resistance of the branch line; Represents the hydrogen production power of the electrolyzer; Represents the reactive power generated by the generator set; Represents the new energy unit During the time period The reactive power fed into the grid; From node To node The reactive power of the branch line; From node To node The reactance of the branch line; Is the reactive power actually supplied to the power load; For node The square of the voltage amplitude; And For node And node The voltage phase angles; And Are respectively the minimum and maximum values of the square of the voltage amplitude of node ; From node To node The capacity of the branch line; Is the reactive power demand of the power load; Is the predicted active power of the new energy unit for the day ahead; Is the predicted reactive power of the new energy unit for the day ahead; Is the voltage phase angle of the reference bus; Is an integer variable representing the operating state of the generator set at time t, 1 for the operating state and 0 for the non-operating state; And Are respectively The minimum and maximum active power generations of the unit; And Are respectively The minimum and maximum reactive power generations of the unit; Represents The maximum ramp rate of the unit; Represents The minimum continuous operating time after the unit starts up; And Are respectively the minimum and maximum consumption powers when the electrolyzer is operating; Is the power consumption required when the electrolyzer is in the hot standby state; is an integer variable representing the operating state of the electrolyzer at time period t. 1 indicates the operating state, and 0 indicates the non-operating state; is an integer variable representing the hot standby state of the electrolyzer at time period t. 1 indicates being in the hot standby state, and 0 indicates the non-hot standby state; is the mass flow rate of hydrogen produced by the electrolyzer; is the higher calorific value of hydrogen, taken as 142 MJ / kg; is the hydrogen production conversion efficiency of the electrolyzer; is an integer variable representing the shutdown state of the electrolyzer at time period t. 1 indicates the shutdown state, and 0 indicates the non-shutdown state;

[0135] Equation (A-2) is the nodal active power balance equation; Equation (A-3) is the nodal reactive power balance equation; Equation (A-4) is the relationship between the nodal voltage and the line power; Equation (A-5) is the relationship between the voltage phase angle and the line power; Equation (A-6) is the second-order cone relaxation form of the branch power flow; Equation (A-7) is the upper and lower limit constraints of the nodal voltage; Equation (A-8) is the line transmission capacity constraint; Equation (A-9) is the active load demand constraint; Equation (A-10) is the upper and lower limit constraints of the reactive load; Equation (A-11) is the active power constraint of the grid-connected new energy; Equation (A-12) is the reactive power constraint of the grid-connected new energy; Equation (A-13) stipulates that the phase angle of the reference bus is 0; Equation (A-14) is the upper and lower limit constraints of the active power output of the generator when it is in the operating state; Equation (A-15) is the upper and lower limit constraints of the reactive power output of the generator when it is in the operating state; Equation (A-16) is the active power ramp constraint of the generator; Equation (A-17) is the start-stop action and state constraint of the generator; Equation (A-18) is the minimum operating time constraint of the generator; Equation (A-19) is the upper and lower limit constraints of the power of the electrolyzer when it is in the operating state or the hot standby state; Equation (A-20) is the efficiency constraint of the electrolyzer during electrolytic hydrogen production; Equation (A-21) is the state constraint of the electrolyzer, which can only be in the operating, hot standby or shutdown state at the same time; Equation (A-22) is the start-up state constraint of the electrolyzer; Equation (A-23) restricts that the electrolyzer cannot directly change from the shutdown state to the hot standby state;

[0136] The operation model for providing frequency control reserve and spinning reserve ancillary services in step 3 above is specifically as follows:

[0137] (A-24)

[0138] (A-25)

[0139] (A-26)

[0140] (A-27)

[0141] (A-28)

[0142] Wherein, is the upper reserve capacity of the spinning reserve provided for the electrolyzer; is the required upper reserve capacity of the spinning reserve; is the lower reserve capacity of the spinning reserve provided for the electrolyzer; is the required lower reserve capacity of the spinning reserve; is the upper reserve capacity of the frequency control reserve provided for the electrolyzer; is the required upper reserve capacity of the frequency control reserve; is the lower reserve capacity of the frequency control reserve provided for the electrolyzer; is the required lower reserve capacity of the frequency control reserve;

[0143] Equation (A-24) indicates that the spinning reserve is jointly provided by coal-fired units, gas-fired units and electrolyzers; Equation (A-25) indicates that the frequency control reserve is jointly provided by gas-fired units and electrolyzers; Equation (A-26) indicates the upper and lower limit constraints and ramp constraints of the spinning reserve provided by coal-fired units; Equation (A-27) indicates the upper and lower limit constraints and ramp constraints of the spinning reserve and frequency control reserve provided by gas-fired units; Equation (A-28) indicates the capacity limits of the spinning reserve and frequency control reserve provided by the electrolyzer in the operating and hot standby states;

[0144] The specific operation model of the dynamic natural gas system considering hydrogen blending in the pipeline in Step 3 above is as follows:

[0145] (A-29)

[0146] (A-30)

[0147] (A-31)

[0148] (A-32)

[0149] (A-33)

[0150] (A-34)

[0151] (A-35)

[0152] (A-36)

[0153] (A-37)

[0154] (A-38)

[0155] (A-39)

[0156] (A-40)

[0157] (A-41)

[0158] (A-42)

[0159] (A-43)

[0160] (A-44)

[0161] (A-45)

[0162] (A-46)

[0163] (A-47)

[0164] (A-48)

[0165] (A-49)

[0166] Among them, the subscripts and represent natural gas nodes; the subscript represents a natural gas node and the pipeline between natural gas nodes ; the set is the set of nodes connected to the natural gas node ; the set is the set of natural gas sources connected to the natural gas node ; the set is the set of electrolyzers connected to the natural gas node ; the set is the set of pressurization stations connected to the natural gas node ; the set is the set of gas turbines connected to the natural gas node ; the set is the set of loads connected to the natural gas node ; is the density of the natural gas-hydrogen mixture in the natural gas pipeline; is the length of the time section; and are the gas mass flow rates at the beginning and end of the natural gas pipeline respectively; is the cross-sectional area of the natural gas pipeline; is the length of the natural gas pipeline; and is the pressure at the natural gas node; is the mass flow rate of the gas in the natural gas pipeline; is the friction factor of the turbulent flow in the natural gas pipeline; is the diameter of the natural gas pipeline; is the mass fraction of hydrogen in the natural gas pipeline; and are the mass fractions of hydrogen at the beginning and end of the natural gas pipeline respectively; is the pressure of the pipeline; is the specific gas constant of the natural gas - hydrogen mixture in the pipeline; is the compressibility factor of the pipeline; is the ambient temperature; is the specific gas constant of hydrogen; is the specific gas constant of natural gas; is the mass flow rate of the gas in the pressurizing station; is the mass flow rate of natural gas consumed by the gas turbine unit; is the required mass flow rate of the natural gas - hydrogen mixture; is the higher heating value of natural gas, taken as 53.37 MJ / kg; is the mass fraction of hydrogen at the natural gas node; is the mass fraction of hydrogen in the pressurizing station; is the power generation efficiency of the gas turbine unit; is the maximum value of the mass fraction of hydrogen injected into the natural gas pipeline; is the maximum value of the mole fraction of hydrogen injected into the natural gas pipeline; and are the densities of hydrogen and natural gas under standard conditions respectively; and are the minimum and maximum values of the pipeline pressure; and are the minimum and maximum values of the mass flow rate of natural gas supplied by the natural gas source; is the maximum value of the ramping rate of natural gas supplied by the natural gas source; and are the minimum and maximum values of the gas density in the natural gas pipeline respectively; and are the minimum and maximum values of the pressurizing coefficient of the pressurizing station respectively; and are the minimum and maximum values of the mass flow rate of the gas in the pressurizing station respectively;

[0167] Equation (A-29) represents the mass conservation of the natural gas-hydrogen mixture in the pipeline; Equation (A-30) represents the momentum conservation of the natural gas-hydrogen mixture in the pipeline; Equation (A-31) is the advection transport equation of hydrogen, representing the mass conservation of hydrogen in the pipeline; Equation (A-32) is the state equation, indicating that the pressure and density of the natural gas-hydrogen mixture are related to the temperature; Equation (A-33) is the calculation rule for the specific gas constant of the natural gas-hydrogen mixture; Equation (A-34) is the formula for calculating the average pressure of the natural gas-hydrogen mixture in the pipeline; Equation (A-35) is the formula for calculating the average mass flow rate of the natural gas-hydrogen mixture in the pipeline; Equation (A-36) is the formula for calculating the average mass fraction of hydrogen in the pipeline; Equation (A-37) is the nodal mass flow balance equation of the natural gas-hydrogen mixture; Equation (A-38) represents the energy conversion relationship between the natural gas-hydrogen mixture demand and the original natural gas demand; Equation (A-39) represents the nodal mass flow balance equation of hydrogen; Equation (A-40) represents the power generation efficiency of the gas turbine unit; Equation (A-41) represents the relationship between the maximum hydrogen injection mole fraction and the maximum hydrogen injection mass fraction in the pipeline; Equation (A-42) is the limit of the hydrogen injection mass fraction in the pipeline; Equation (A-43) is the pressure limit of the natural gas node; Equation (A-44) is the gas supply limit of the natural gas source; Equation (A-45) is the ramping constraint of the natural gas source; Equation (A-46) is the gas density limit of the pipeline; Equation (A-47) is the boost ratio constraint of the pressurization station; Equation (A-48) is the gas mass flow limit of the pressurization station; Equation (A-49) is the limit of the natural gas demand.

[0168] Step 104: For the non-convex model of the optimal scheduling of the integrated electricity-hydrogen-gas hybrid energy system established in Step 103, convex relaxation is performed on the bilinear terms in all non-convex constraints in the model through the McCormick envelope to obtain the convex model of the optimal scheduling of the integrated electricity-hydrogen-gas hybrid energy system.

[0169] Further, in the embodiment of the present application, the above Step 104 includes:

[0170] Six non-linear constraints (A-30), (A-31), (A-32), (A-38), (A-39), and (A-40) in the non-convex model of the optimal scheduling of the integrated electricity-hydrogen-gas hybrid energy system established in Step 103 are formula-transformed and the bilinear terms therein are relaxed using the McCormick envelope, specifically as follows:

[0171] Convert (A-30)-(A-32) into:

[0172] (A-50)

[0173] (A-51)

[0174] (A-52)

[0175] Convert (A-38)-(A-40) into:

[0176] (A-53)

[0177] (A-54)

[0178] (A-55)

[0179] Among them, , is the introduced auxiliary variable;

[0180] Combine equations (A-1)-(A-29), (A-33)-(A-37), (A-41)-(A-49), (A-51)-(A-55) to obtain the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system.

[0181] It should be noted that the McCormick envelope uses a set of linear constraints to replace the bilinear terms in the non-linear constraints, convexify the non-convex constraints. Taking the bilinear term as an example, its McCormick envelope represented by is shown as follows:

[0182] .

[0183] Step 105: Use the successive feasible point-convex hull relaxation method to alternately solve the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system and the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system to obtain the optimal scheduling method.

[0184] Furthermore, in the embodiment of the present application, the above step 105 includes:

[0185] Step 1051: Solve the optimal scheduling convex model of the electric-hydrogen-gas hybrid integrated energy system through the GUROBI solver to obtain the lower limit of the objective value and the scheduling strategy. The scheduling strategy includes the output and start-stop status of the generator set and the electrolyzer, the power grid power flow, the output of wind power and photovoltaic power, the output of the natural gas source, and the flow rate of the gas network pipeline;

[0186] Step 1052: Solve the optimal scheduling non-convex model of the electric-hydrogen-gas hybrid integrated energy system by fixing the scheduling strategy to obtain the upper limit of the objective value and the numerical values of all variables. The fixed scheduling strategy is to fix the numerical values of all variables included in the scheduling strategy in step 51 and solve the model through the DICOPT solver;

[0187] Step 1053: Refer to the numerical values of the variables corresponding to the bilinear terms in the convex relaxation constraints obtained from the non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system, narrow the upper and lower limits of the variables in the bilinear terms of the convex relaxation constraints, so as to solve the convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system and improve the lower limit of the objective value;

[0188] Step 1054: Solve the non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system according to the fixed scheduling strategy, and update the upper limit of the objective value;

[0189] Step 1055: Repeat Step 1053 - Step 1054 until the difference between the upper limit and the lower limit of the objective value is less than the preset value, and determine the obtained objective value and the scheduling strategy at this time as the optimal scheduling method.

[0190] The method for coordinated scheduling of energy and frequency reserve of the electric-hydrogen-gas system based on successive feasible convex relaxation provided by this application first obtains the network coefficients and operation coefficients of the power grid and gas network models, then obtains the dynamic operation scenario data under different time sections, and then combines the network coefficients, operation coefficients and dynamic operation scenario data, uses the total cost of the electric-hydrogen-gas hybrid integrated energy system as the objective function, and successively establishes an operation model of the power system considering the combination of units and electrolyzers, an operation model for providing frequency control reserve and spinning reserve ancillary services, and a dynamic natural gas system operation model considering hydrogen blending in pipelines, and combines the objective function with the three established models to construct a non-convex model for the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system considering frequency control reserve, spinning reserve and unit commitment. Then, for the established non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system, the bilinear terms in all non-convex constraints in the model are convex-relaxed through McCormick envelopes to obtain a convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system. Finally, the successive feasible point-convex hull relaxation method is used to alternately solve the convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system and the non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system to obtain the optimal scheduling method. By introducing the three-state model of the electrolyzer and using the successive feasible point-convex hull relaxation solution method, the potential of the electrolyzer's thermal reserve state to provide frequency control reserve and spinning reserve is fully exploited, the scheduling accuracy is improved, the system operation cost is reduced, and the standby pressure of traditional units is alleviated.

[0191] The following numerical example is used to illustrate the progressiveness of the present application. This numerical example adopts a 24-node power system and a 20-node natural gas system. To compare the superiority of the method proposed in the present application, the traditional co-scheduling method of energy-frequency reserve for the electric-hydrogen system that provides reserve based on the two-state model of the electrolyzer, the co-scheduling method of energy-frequency reserve for the electric-hydrogen system solved by the general boundary successive tightening method (gradually tightening the upper and lower limits of the variables in the relaxed bilinear terms during the iteration process), and the co-scheduling method of energy-frequency reserve for the electric-hydrogen system proposed in the present application based on successive feasible convex relaxation are used to compare the scheduling results and the solution accuracy. The present application solves the MIQCP and MINLP problems of the basic scenario through the GAMS optimization platform with GUROBI and DICOPT solvers.

[0192] Based on this numerical example, the comparison results of the costs between the traditional co-scheduling method of energy-frequency reserve for the electric-hydrogen system that provides reserve based on the two-state model of the electrolyzer and the co-scheduling method of energy-frequency reserve for the electric-hydrogen system proposed in the present application based on successive feasible point-convex hull relaxation (the electrolyzer model is a three-state model) are shown in Table 1. The comparison results with the provided frequency control reserve and spinning reserve are shown in Figure 2 — Figure 7 , where Figure 2 is a schematic diagram of the spinning reserve (SR) provided by coal-fired units under the three-state model, Figure 3 is a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by gas-fired units under the three-state model, Figure 4 is a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by the electrolyzer under the three-state model, Figure 5 is a schematic diagram of the spinning reserve (SR) provided by coal-fired units under the two-state model, Figure 6 is a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by gas-fired units under the two-state model, Figure 7 represents a schematic diagram of the frequency control reserve (FCR) and spinning reserve (SR) provided by the electrolyzer under the two-state model, and the comparison between the co-scheduling method of energy-frequency reserve for the electric-hydrogen system solved by the general boundary successive tightening method and the co-scheduling method of energy-frequency reserve for the electric-hydrogen system proposed in the present application based on successive feasible point-convex hull relaxation (the results are shown in Figure 8). It shows that the scheduling cost of the electrolyzer model using the three-state model in the frequency reserve coordinated scheduling method of the electric-hydrogen-gas system based on successive feasible convex relaxation is reduced by 0.82% compared with the scheduling cost when the electrolyzer model uses the traditional two-state model. Compared with the coordinated energy-frequency reserve scheduling of the integrated electric-hydrogen-gas energy system based on the traditional two-state model of the electrolyzer, the coordinated energy-frequency reserve scheduling of the hybrid integrated electric-hydrogen-gas energy system using the three-state model of the electrolyzer can make full use of the additional frequency control reserve and spinning reserve provided in the hot standby state of the electrolyzer, reducing the frequency control reserve and spinning reserve that the gas turbines in the power system need to provide, and the pressure of the spinning reserve that the coal-fired power units need to provide, reducing the additional cost of the power system caused by the frequent start and stop of the electrolyzer and the cost of natural gas as the fuel of the units, thus reducing the cost of the natural gas system. Compared with using the general boundary successive tightening method, using the successive feasible point-convex hull relaxation method developed in this application can reduce the violation amount during the iterative solution of the constraints, so that the finally converged result is more accurate and closer to the true value of the solution.

[0193] Table 1 Comparison of scheduling costs under two electrolyzer models

[0194] It should be understood that the magnitudes of the sequence numbers of the steps in the above embodiments do not mean the order of execution. The order of execution of each process should be determined by its function and internal logic, and should not constitute any limitation to the implementation process of the embodiments of this application.

[0195] The above embodiments are only used to illustrate the technical solutions of this application, rather than to limit it; although this application has been described in detail with reference to the foregoing embodiments, those of ordinary skill in the art should understand that: they can still modify the technical solutions described in the foregoing embodiments, or perform equivalent replacements for some of the technical features; and these modifications or replacements do not make the essence of the corresponding technical solutions deviate from the spirit and scope of the technical solutions of the embodiments of this application, and should all be included in the protection scope of this application.

Claims

1. A method for collaborative scheduling of energy and frequency reserves in an electric-hydrogen system based on successive feasible convex relaxation, characterized in that, It includes the following steps: Step 1: Obtain the network coefficients and operating coefficients of the power grid and gas network models. The network coefficients include the power grid topology, gas network topology, line resistance and impedance, natural gas, and hydrogen calorific value. The operating coefficients include the power generation coefficient of the generator set, the coefficient of the wind power and photovoltaic inverter, the gas source parameters, the parameters of the electrolyzer device, and the parameters of the pressurization station; Step 2: Obtain the dynamic operation scenario data under different time sections. The dynamic operation scenario data includes the power grid load demand, gas network load demand, wind power and photovoltaic output, frequency control reserve demand, and spinning reserve demand scenario data; Step 3: Combine the network coefficients, the operating coefficients, and the dynamic operation scenario data. Taking the total cost of the electricity-hydrogen-gas hybrid integrated energy system as the objective function, establish in sequence the power system operation model considering the combination of units and electrolyzers, the operation model for providing frequency control reserve and spinning reserve ancillary services, and the dynamic natural gas system operation model considering hydrogen blending in pipelines. Then combine the objective function with the three established models to construct the non-convex model of the optimal scheduling of the electricity-hydrogen-gas hybrid integrated energy system considering frequency control reserve, spinning reserve, and unit commitment; Step 4: For the non-convex model of the optimal scheduling of the electricity-hydrogen-gas hybrid integrated energy system established in Step 3, convexify the bilinear terms in all non-convex constraints in the model through the McCormick envelope to obtain the convex model of the optimal scheduling of the electricity-hydrogen-gas hybrid integrated energy system; Step 5: Use the successive feasible point-convex hull relaxation method to alternately solve the convex model of the optimal scheduling of the electricity-hydrogen-gas hybrid integrated energy system and the non-convex model of the optimal scheduling of the electricity-hydrogen-gas hybrid integrated energy system to obtain the optimal scheduling method.

2. The method for coordinated scheduling of power and frequency reserves of an electro-hydrogen system based on successive feasible convex relaxation according to claim 1, wherein, The objective function in Step 3 is specifically as follows: （A-1） Among them, the subscript represents the power generation units, including coal-fired units and gas-fired units; the subscript represents the time section; the subscript represents the electrolyzer; the subscript represents the power load; the subscript represents the natural gas source; the subscript represents the gas load; represents the set of coal-fired units; represents the set of gas-fired units; represents the unit start-up cost of the power generation unit; represents the unit shutdown cost of the power generation unit; represents the unit cost of upward spinning reserve of the power generation unit; represents the unit cost of downward spinning reserve of the power generation unit; represents the unit power generation cost of the coal-fired unit; represents the unit non-fuel operation and maintenance cost of the gas-fired unit; represents the unit cost of upward frequency control reserve provided by the gas-fired unit; represents the unit cost of downward frequency control reserve provided by the gas-fired unit; represents the unit start-up cost of the electrolyzer; represents the unit cost of cutting off the power load; represents the unit gas supply cost of the gas source; represents the unit cost of cutting off the gas load; represents the start-up action of the power generation unit; represents the shutdown action of the power generation unit; represents the upward spinning reserve capacity provided by the power generation unit; represents the downward spinning reserve capacity provided by the power generation unit; represents the active power output of the power generation unit; represents the upward frequency control reserve capacity provided by the gas-fired unit; represents the downward frequency control reserve capacity provided by the gas-fired unit; represents the start-up action of the electrolyzer; represents the active power demand of the power load; represents the active power actually supplied to the power load; represents the gas supply volume of the natural gas source; represents the required mass flow rate of the natural gas load; represents the mass flow rate actually supplied to the natural gas load; The first term of the objective function in Equation (A-1) is the start-stop cost and spinning reserve cost of the generator set. The generator set includes coal-fired units and gas-fired units. The second term is the power generation cost of the coal-fired units. The third term is the cost of power generation and providing frequency control reserve of the gas-fired units. The cost of power generation and providing frequency control reserve includes the up-spinning reserve cost and the down-spinning reserve cost. The fourth term is the start-up cost of the electrolyzer. The fifth term is the cost of shedding electrical load. The sixth term is the gas supply cost of the natural gas source. The seventh term is the cost of shedding gas load; The power system operation model considering the combination of units and electrolyzers in Step 3 is specifically as follows: (A-2) (A-3) (A-4) (A-5) (A-6) (A-7) (A-8) (A-9) (A-10) (A-11) (A-12) (A-13) (A-14) (A-15) (A-16) (A-17) (A-18) (A-19) (A-20) (A-21) (A-22) (A-23) Among them, the subscript and represent power nodes; the subscript represents the line from power node to power node ; the subscript represents new energy units; the subscript represents the reference busbar; represents the set of generator units connected to node ; represents the set of new energy units connected to node ; represents the set of nodes connected to node ; represents the set of power loads connected to node ; represents the set of electrolyzers connected to node ; represents the active power output of new energy unit in time period ; is the active power of the line from node to node ; is the square of the current of the line from node to node ; is the resistance of the line from node to node ; represents the hydrogen production power of the electrolyzer; represents the reactive power output of the generator set; represents the reactive power output of new energy unit in time period ; is the reactive power of the line from node to node ; is the reactance of the line from node to node ; is the reactive power actually supplied to the power load; is the square of the voltage amplitude of node ; and are the voltage phase angles of node and node ; and are the minimum and maximum values of the square of the voltage amplitude of node respectively; is from node To the node The capacity of the line between; Is the reactive power demand of the power load; Is the predicted active power of the new energy unit for the day-ahead; Is the predicted reactive power of the new energy unit for the day-ahead; Is the voltage phase angle of the reference bus; Is an integer variable representing the operating state of the generator set in time period t, 1 for the operating state, 0 for the non-operating state; And Are respectively the Minimum and maximum active power generation of the unit; And Are respectively the Minimum and maximum reactive power generation of the unit; Represents the Maximum ramp rate of the unit; Represents the Minimum continuous operation time after the unit starts; And Are respectively the minimum and maximum power consumption during the operation of the electrolyzer; Is the power consumption required when the electrolyzer is in the hot standby state; Is an integer variable representing the operating state of the electrolyzer in time period t, 1 for the operating state, 0 for the non-operating state; Is an integer variable representing the hot standby state of the electrolyzer in time period t, 1 for being in the hot standby state, 0 for the non-hot standby state; Is the mass flow rate of hydrogen produced by the electrolyzer; Is the higher calorific value of hydrogen, taken as 142 MJ / kg; Is the hydrogen production conversion efficiency of the electrolyzer; Is an integer variable representing the shutdown state of the electrolyzer in time period t, 1 for the shutdown state, 0 for the non-shutdown state; Equation (A-2) is the active power balance equation of the node; Equation (A-3) is the reactive power balance equation of the node; Equation (A-4) is the relationship between the node voltage and the line power; Equation (A-5) is the relationship between the voltage phase angle and the line power; Equation (A-6) is the second-order cone relaxation form of the branch power flow; Equation (A-7) is the upper and lower limit constraints of the node voltage; Equation (A-8) is the line transmission capacity constraint; Equation (A-9) is the active load demand constraint; Equation (A-10) is the upper and lower limit constraints of the reactive load; Equation (A-11) is the active power constraint of the grid-connected new energy; Equation (A-12) is the reactive power constraint of the grid-connected new energy; Equation (A-13) stipulates that the phase angle of the reference bus is 0; Equation (A-14) is the upper and lower limit constraints of the active power output of the generator during operation; Equation (A-15) is the upper and lower limit constraints of the reactive power output of the generator during operation; Equation (A-16) is the active power ramp constraint of the generator; Equation (A-17) is the start-stop action and state constraint of the generator; Equation (A-18) is the minimum operation time constraint of the generator; Equation (A-19) is the upper and lower limit constraints of the power of the electrolyzer during operation or hot standby; Equation (A-20) is the efficiency constraint of the electrolyzer during hydrogen production by electrolysis; Equation (A-21) is the state constraint of the electrolyzer, which can only be in the operation, hot standby or shutdown state at the same time; Equation (A-22) is the start-up state constraint of the electrolyzer; Equation (A-23) restricts that the electrolyzer cannot directly change from the shutdown state to the hot standby state; The operation model for providing frequency control reserve and spinning reserve ancillary services in step 3 is specifically as follows: (A-24) (A-25) (A-26) (A-27) (A-28) Among them, is the upper reserve capacity of the spinning reserve provided for the electrolytic cell; is the required upper reserve capacity of the spinning reserve; is the lower reserve capacity of the spinning reserve provided for the electrolytic cell; is the required lower reserve capacity of the spinning reserve; is the upper reserve capacity of the frequency control reserve provided for the electrolytic cell; is the required upper reserve capacity of the frequency control reserve; is the lower reserve capacity of the frequency control reserve provided for the electrolytic cell; is the required lower reserve capacity of the frequency control reserve; Equation (A-24) indicates that the spinning reserve is jointly provided by coal-fired units, gas-fired units and electrolyzers; Equation (A-25) indicates that the frequency control reserve is jointly provided by gas-fired units and electrolyzers; Equation (A-26) represents the upper and lower limit constraints and ramp constraints of the spinning reserve provided by coal-fired units; Equation (A-27) represents the upper and lower limit constraints and ramp constraints of the spinning reserve and frequency control reserve provided by gas-fired units; Equation (A-28) represents the capacity limits of the spinning reserve and frequency control reserve provided by the electrolyzer in the operation and hot standby states; The operation model of the dynamic natural gas system considering hydrogen blending in pipelines in step 3 is specifically as follows: (A-29) (A-30) (A-31) (A-32) (A-33) (A-34) (A-35) (A-36) (A-37) (A-38) (A-39) (A-40) (A-41) (A-42) (A-43) (A-44) (A-45) (A-46) (A-47) (A-48) (A-49) Among them, the subscript and represent natural gas nodes; the subscript represents the natural gas node and the natural gas node is the pipeline between them; the set is the set of nodes connected to the natural gas node ; the set is the set of natural gas sources connected to the natural gas node ; the set is the set of electrolyzers connected to the natural gas node ; the set is the set of pressurization stations connected to the natural gas node ; the set is the set of gas turbines connected to the natural gas node ; the set is the set of loads connected to the natural gas node ; is the density of the natural gas - hydrogen mixture in the natural gas pipeline; is the length of the time section; and are the gas mass flows at the beginning and end of the natural gas pipeline respectively; is the cross - sectional area of the natural gas pipeline; is the length of the natural gas pipeline; and are the pressures at the natural gas nodes; is the gas mass flow in the natural gas pipeline; is the friction factor of the turbulent flow in the natural gas pipeline; is the diameter of the natural gas pipeline; is the mass fraction of hydrogen in the natural gas pipeline; and are the mass fractions of hydrogen at the beginning and end of the natural gas pipeline respectively; is the pressure of the pipeline; is the specific gas constant of the natural gas - hydrogen mixture in the pipeline; is the compressibility factor of the pipeline; is the ambient temperature; is the specific gas constant of hydrogen; is the specific gas constant of natural gas; is the gas mass flow in the pressurization station; is the mass flow of natural gas consumed by the gas turbine; is the required mass flow of the natural gas - hydrogen mixture; is the higher heating value of natural gas, taken as 53.37 MJ / kg; is the hydrogen mass fraction at the natural gas node; is the hydrogen mass fraction in the pressurization station; is the power generation efficiency of the gas turbine unit; is the maximum value of the mass fraction of hydrogen injected into the natural gas pipeline; is the maximum value of the mole fraction of hydrogen injected into the natural gas pipeline; and are the densities of hydrogen and natural gas under standard conditions, respectively; and are the minimum and maximum values of the pipeline pressure; and are the minimum and maximum values of the gas supply mass flow rate of the natural gas source; is the maximum value of the gas supply ramp of the natural gas source; and are the minimum and maximum values of the gas density in the natural gas pipeline, respectively; and are the minimum and maximum values of the pressurization coefficient of the pressurization station, respectively; and are the minimum and maximum values of the gas mass flow rate in the pressurization station, respectively; Equation (A-29) represents the mass conservation of the natural gas-hydrogen mixture in the pipeline; Equation (A-30) represents the momentum conservation of the natural gas-hydrogen mixture in the pipeline; Equation (A-31) is the advection transport equation of hydrogen, representing the mass conservation of hydrogen in the pipeline; Equation (A-32) is the state equation, indicating that the pressure and density of the natural gas-hydrogen mixture are related to the temperature; Equation (A-33) is the calculation rule for the specific gas constant of the natural gas-hydrogen mixture; Equation (A-34) is the formula for calculating the average pressure of the natural gas-hydrogen mixture in the pipeline; Equation (A-35) is the formula for calculating the average mass flow rate of the natural gas-hydrogen mixture in the pipeline; Equation (A-36) is the formula for calculating the average mass fraction of hydrogen in the pipeline; Equation (A-37) is the nodal mass flow balance equation of the natural gas-hydrogen mixture; Equation (A-38) represents the energy conversion relationship between the natural gas-hydrogen mixture demand and the original natural gas demand; Equation (A-39) represents the nodal mass flow balance equation of hydrogen; Equation (A-40) represents the power generation efficiency of the gas turbine unit; Equation (A-41) represents the relationship between the maximum hydrogen injection mole fraction and the maximum hydrogen injection mass fraction in the pipeline; Equation (A-42) is the limit of the hydrogen injection mass fraction in the pipeline; Equation (A-43) is the pressure limit of the natural gas node; Equation (A-44) is the gas supply limit of the natural gas source; Equation (A-45) is the ramp constraint of the natural gas source; Equation (A-46) is the gas density limit of the pipeline; Equation (A-47) is the boost ratio constraint of the pressurization station; Equation (A-48) is the gas mass flow limit of the pressurization station; Equation (A-49) is the limit of the natural gas demand.

3. The method for collaborative scheduling of energy-frequency reserve of an electro-hydrogen system based on successive feasible convex relaxation according to claim 2, wherein In step 4, the bilinear terms in all non-convex constraints in the model are convex-relaxed through the McCormick envelope to obtain the convex model of the optimal scheduling of the integrated electricity-hydrogen-gas energy system, which is specifically as follows: The six non-linear constraints (A-30), (A-31), (A-32), (A-38), (A-39), and (A-40) in the non-convex model of the optimal scheduling of the integrated electricity-hydrogen-gas energy system established in step 3 are formula-transformed, and the bilinear terms therein are relaxed using the McCormick envelope, which is specifically as follows: (A-30)-(A-32) are respectively transformed into: (A-50) (A-51) (A-52) (A-38)-(A-40) are respectively transformed into: (A-53) (A-54) (A-55) Among them, , is the introduced auxiliary variable; Equations (A-1)-(A-29), (A-33)-(A-37), (A-41)-(A-49), and (A-51)-(A-55) are combined to obtain the convex model of the optimal scheduling of the integrated electricity-hydrogen-gas energy system.

4. The method for collaborative scheduling of energy-frequency reserve of an electro-hydrogen system based on successive feasible convex relaxation according to claim 3, wherein In step 5, the successive feasible point-convex hull relaxation method is used to alternately solve the convex model of the optimal scheduling of the integrated electricity-hydrogen-gas energy system and the non-convex model of the optimal scheduling of the integrated electricity-hydrogen-gas energy system, which is specifically as follows: Step 51: Solve the convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system through the GUROBI solver to obtain the lower bound of the objective value and the scheduling strategy. The scheduling strategy includes the output and start-stop status of the generator sets and electrolyzers, the power grid power flow, the output of wind power and photovoltaic power, the output of natural gas sources, and the flow rate of the gas network pipeline; Step 52: Solve the non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system through the fixed scheduling strategy to obtain the upper bound of the objective value and the numerical values of all variables. The fixed scheduling strategy is to fix the numerical values of all variables included in the scheduling strategy in Step 51 and solve the model through the DICOPT solver; Step 53: Refer to the numerical values of the variables corresponding to the bilinear terms in the convex relaxation constraints obtained from the non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system, narrow the upper and lower limits of the variables in the bilinear terms of the convex relaxation constraints, so as to solve the convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system and improve the lower bound of the objective value; Step 54: Solve the non-convex model of the optimal scheduling of the electric-hydrogen-gas hybrid integrated energy system according to the fixed scheduling strategy and update the upper bound of the objective value; Step 55: Repeat Step 53 - Step 54 until the difference between the upper bound of the objective value and the lower bound of the objective value is less than the preset value, and determine the obtained objective value and scheduling strategy as the optimal scheduling method.

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