A new power system security dispatching decision method considering inertia and primary frequency regulation reserve distribution

Abstract

This invention discloses a novel power grid security dispatch decision-making method for power systems that considers inertia and primary frequency regulation reserve distribution. The method includes: first, constructing a DC power flow model to clarify node power distribution; second, combining unit inertia and frequency regulation characteristics to establish a dynamic frequency security constraint model considering the spatiotemporal response of frequency, and determining the primary frequency regulation reserve power; finally, discretizing the model and solving it with the objective of minimizing total generation cost to obtain a power system dispatch scheme based on the spatial distribution of system inertia and the spatiotemporal distribution of primary frequency regulation reserve. This invention overcomes the limitations of traditional static dispatch, which only focuses on power balance, by constructively embedding dynamic frequency security constraints into the dispatch framework. Addressing the problem of reduced and unevenly distributed system inertia due to the increasing proportion of renewable energy, it proposes a more targeted dispatch scheme, providing a more accurate and targeted solution for frequency stability in high-proportion renewable energy power systems.

Description

Technical Field

[0001] This invention belongs to the field of power grid safety technology, and in particular, it is a novel power system power grid safety dispatch decision-making method that takes into account inertia and primary frequency regulation reserve distribution. Background Technology

[0002] In recent years, with the gradual transformation of the global energy structure, new energy power generation technologies such as wind power and photovoltaics have the advantages of being clean and low-carbon, and therefore their installed capacity and power generation share in the power system have continued to rise. However, new energy power generation relies more on power electronic equipment connected to the grid, and it has almost no rotational inertia. As the proportion of new energy continues to increase, a large number of synchronous generators with inertial support capabilities are being replaced, directly leading to a significant reduction in the overall rotational kinetic energy reserves of the power grid, a decrease in the system's inertia level, and uneven spatial distribution.

[0003] However, renewable energy generation relies heavily on power electronic equipment connected to the grid, exhibiting virtually no rotational inertia. As the proportion of renewable energy increases, a large number of synchronous generators with inertial support capabilities are being replaced, directly leading to a significant reduction in the overall rotational kinetic energy reserves of the grid, a decrease in system inertia level, and uneven spatial distribution. Secondly, frequency reserve, i.e., the capacity of backup power sources in the system capable of rapid response, directly affects whether the frequency can be effectively supported before it drops to a safe threshold. These two factors together determine the dynamic stability level of the frequency in the initial stage of a disturbance and define the basic conditions for subsequent frequency regulation. Therefore, optimizing unit scheduling strategies and coordinating the allocation of inertial resources and frequency reserves from the source becomes a feasible and crucial approach to improving system frequency security after disturbances. Summary of the Invention

[0004] The purpose of this invention is to address the problems existing in the prior art by considering the impact of the spatiotemporal distribution of inertia of new energy generation and synchronous generators on the dynamic frequency security of the system, thereby effectively influencing the power system dispatching scheme. This invention provides a novel power grid security dispatching decision-making method that considers the spatiotemporal distribution of inertia of new energy generation and synchronous generators, as well as primary frequency regulation reserve. First, this invention constructs a DC power flow model of the power system. Then, it constructs frequency response models with generator nodes under load disturbances, followed by a dynamic frequency security constraint optimization model considering the frequency spatial response. Subsequently, the constructed model is discretized to obtain linear constraints for dynamic frequency security. Finally, the set of linear constraints is added to the power grid dispatching model for solution, resulting in an optimized power system dispatching scheme. The effectiveness and accuracy of the model are verified, and the proposed model is validated using an improved IEEE 9 bus system. This invention overcomes the limitations of traditional static dispatching, which only focuses on power balance, by constructively embedding dynamic frequency security constraints into the power grid operation and dispatching framework, providing a more targeted solution for the frequency stability of high-proportion new energy power systems.

[0005] The technical solution to achieve the purpose of this invention is: a novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution, the method comprising the following steps:

[0006] Step 1: Construct a power flow model of the power system to characterize the power transmission relationships between nodes in the power system;

[0007] Step 2: Based on the power system flow model, construct a dynamic frequency security constraint model that considers the frequency space response. This model determines the spatiotemporal distribution of primary frequency regulation reserves for new energy generation and synchronous generators. The model takes into account the frequency dynamic characteristics of each generator node under load disturbances and is used to characterize the non-uniform distribution of inertia in the power grid space. The dynamic frequency security constraint model couples the dynamic power angle deviation of the generator node, the dynamic frequency deviation, and the frequency regulation response characteristics of the generator set.

[0008] Step 3: Discretize the dynamic frequency safety constraint model to generate a dynamic frequency safety linear constraint set;

[0009] Step 4: With minimizing the total power generation cost of the power system as the scheduling objective, construct a power grid scheduling model by combining the dynamic frequency security linear constraint set and solve it to obtain a power system scheduling scheme based on the spatial distribution of system inertia and the spatiotemporal distribution of primary frequency regulation reserve.

[0010] Furthermore, the specific process of constructing the power system flow model in step 1 includes:

[0011] Step 1-1: Simplify the power system model based on the DC power flow assumption;

[0012] Steps 1-2: Construct an augmented susceptance matrix containing N generator nodes and N load nodes;

[0013] Steps 1-3: Determine the output / input power of the power system load nodes and generator nodes based on the augmented susceptance matrix.

[0014] Furthermore, the augmented stoichiometric matrix in steps 1-2 is represented as follows:

[0015]

[0016] The output / input power of the load node in steps 1-3 is expressed as follows:

[0017]

[0018] The output / input power of the generator node in steps 1-3 is expressed as follows:

[0019]

[0020] or,

[0021]

[0022] In the formula, The susceptance matrix between generator nodes; This is the susceptance matrix from the generator node to the load node; This is the susceptance matrix from the load node to the generator node; The susceptance matrix between load nodes; This represents the injected power vector from the generator node; Power vector extracted for load nodes; The power angle vector of the load node; The power angle vector of the generator node; To obtain the generator equivalent susceptance matrix after eliminating load nodes; This is the power distribution matrix of load disturbance to generator power.

[0023] Furthermore, the dynamic frequency safety constraint model mentioned in step 2 includes a dynamic model of the power angle deviation of the generator node and a dynamic model of the frequency of the generator node, which are expressed as follows:

[0024]

[0025]

[0026] In the formula, The time derivative of the generator node power angle vector; ω is the angular frequency vector of the generator node; This is the diagonal matrix of the rated angular velocity of the power system; It is the identity matrix. This represents the initial power of the load in the power system. The disturbance power of the load; Let be the diagonal matrix of the inertial constants of the synchronous generator set; This is the diagonal matrix of the damping coefficient constants of the synchronous generator set; The rated angular velocity of the power system; ω is the angular velocity of the generator node; The derivative vector of the angular velocity of the generator node; This represents the input power of the synchronous generator; For the input power of new energy units, To obtain the generator equivalent susceptance matrix after eliminating load nodes; The power angle vector of the generator node; This is the power distribution matrix of load disturbance to generator power.

[0027] Furthermore, the dynamic frequency safety constraint model described in step 2 also takes into account the primary frequency regulation response of the synchronous generator and the fast frequency regulation response of the new energy unit considering the inertial response. The primary frequency regulation reserve power or fast frequency regulation reserve power of the unit is determined according to the magnitude of the inertia of the node new energy power generation and the synchronous generator.

[0028] Furthermore, the dynamic models of the primary frequency regulation response of the synchronous generator and the fast frequency regulation response of the new energy unit considering inertial response are respectively expressed as follows:

[0029]

[0030]

[0031] In the formula, The diagonal matrix of the time constants of the synchronous generator; This is the diagonal matrix of the time constants of the new energy generating units; This is a diagonal matrix of the droop coefficients for synchronous generator sets; This is a diagonal matrix of droop coefficients for new energy generating units; Let be the diagonal matrix of the inertial constants of the new energy generating unit; This represents the input power of the synchronous generator; This represents the initial input power of the synchronous generator; This is the derivative of the input power of the synchronous generator; This is the derivative of the initial input power of the synchronous generator; This represents the initial input power of the synchronous generator; This represents the initial input power of the new energy unit.

[0032] Furthermore, the dynamic frequency safety constraint model described in step 2 also includes a load-side frequency response dynamic model, expressed as:

[0033]

[0034] In the formula, ω is the angular frequency vector of the load node; The weighted matrix is ​​the network topology. This is the susceptance matrix from the load node to the generator node; This is the susceptance matrix between load nodes.

[0035] Furthermore, the dynamic frequency safety linear constraint set mentioned in step 3 includes range restrictions on nodal angular frequencies, rate of change of frequency, and quasi-steady-state angular frequencies:

[0036] Angular frequency constraint:

[0037]

[0038] Frequency change rate constraint:

[0039]

[0040] Quasi-steady-state frequency constraints:

[0041]

[0042] In the formula, Let be the minimum allowed angular frequency for the i-th node; Let be the angular frequency of the i-th node at the n-th time step; Let be the angular frequency of the i-th node at the (n-1)-th time step; The maximum allowed angular frequency for the i-th node; Let be the vector representing the minimum allowed rate of change of frequency for the i-th node; Let be the vector representing the maximum allowed rate of change of frequency at the i-th node; Let be the minimum quasi-steady-state angular frequency allowed for the i-th node; Let be the quasi-steady-state angular frequency of the i-th node; Let i be the maximum quasi-steady-state angular frequency allowed for the i-th node. This indicates the time step set in the dynamic frequency response model.

[0043] Furthermore, the dynamic frequency safety linear constraint set mentioned in step 3 also includes the output power constraints of synchronous generators and new energy generator sets, as well as the primary and backup vector constraints, to determine the primary frequency regulation backup or fast frequency regulation backup power of the unit while ensuring frequency safety.

[0044] Synchronous generator output power constraints:

[0045]

[0046] Output power constraints of new energy generator sets:

[0047]

[0048] Synchronous generator primary frequency regulation reserve power constraint:

[0049]

[0050] Reserve power constraints for rapid frequency regulation of new energy generating units:

[0051]

[0052] In the formula, This indicates the time step set in the dynamic frequency response model; It is the output power of the nth time-step synchronous generator set; It is the output power of the (n+1)th time-step synchronous generator set; It is the output power of the nth time step new energy unit; It is the output power of the (n+1)th time-step new energy generator unit; It is the angular frequency of the system at the nth time step; It is the angular frequency of the system at the (n+1)th time step; It is the reserved downward primary backup vector for synchronous generator sets; It is the upward primary / backup vector reserved for synchronous generator sets; It is a reserved downward primary / backup vector for new energy generating units; It is the upward primary / backup vector reserved for new energy generating units. The diagonal matrix of the time constants of the synchronous generator. This is a diagonal matrix of the droop coefficients for synchronous generator sets; Let be the angular velocity of the generator node. It is the identity matrix. This represents the initial input power of the synchronous generator; This is a diagonal matrix of droop coefficients for new energy generating units; This is the initial input power of the new energy unit. Let be the diagonal matrix of the inertial constants of the new energy unit.

[0053] Furthermore, in step 4, the solution process uses a discretized time step to optimize the output of each unit, so as to coordinate the inertial resources and frequency reserves of each node and obtain an optimized power system dispatch scheme.

[0054] Compared with the prior art, the significant advantages of this invention are:

[0055] (1) This invention breaks through the limitations of traditional static scheduling, which only focuses on power balance, and constructively embeds dynamic frequency security constraints into the scheduling framework. At the same time, it provides a more targeted frequency stabilization solution to the problems of reduced system inertia and uneven distribution caused by the increase in the proportion of new energy units. In addition, compared with the traditional power system scheduling method based on centralized frequency response, the method of this invention can obtain the frequency response of each node according to the spatiotemporal distribution of system inertia, thereby optimizing the unit scheduling strategy, coordinating the allocation of inertia resources and frequency reserves from the source, and effectively improving the safety and stability level of the power system in the early stage of disturbance.

[0056] (2) Compared with traditional methods based on centralized frequency response, this invention can accurately obtain the frequency response of each node according to the spatiotemporal distribution characteristics of system inertia. In addition, by constructing a dynamic model that considers spatial response, the frequency dynamics of nodes in different geographical locations within the power grid can be monitored and constrained in a more detailed manner.

[0057] (3) This invention proposes a method for determining the primary frequency regulation reserve power or fast frequency regulation reserve power of a generator unit based on the magnitude of its inertia. By constructing a node dynamic frequency model that considers the frequency space response, the coupling mechanism and quantitative mapping relationship between the generator unit's inertia and the primary frequency regulation reserve power or fast frequency regulation reserve power are quantified. This fully considers the spatiotemporal distribution differences in grid frequency and breaks through the limitations of the traditional unified configuration mode for frequency regulation reserve power. Based on the differentiated allocation of frequency regulation reserve indicators for each generator unit according to the strength of its inertia support capability, this method effectively balances the dynamic stability constraints of system frequency and the economic efficiency of generator unit operation, thereby improving the overall frequency immunity of the new power system under random power disturbances.

[0058] (4) By discretizing and linearizing the complex node frequency response model, it is transformed into linear constraints, which significantly reduces the computational complexity. Furthermore, since linear constraints are used to describe the dynamic frequency security of nodes, the node frequency response model can be efficiently embedded into the existing power system dispatch model, which facilitates the rapid search for the optimal dispatch scheme of units and the allocation of primary and reserve units.

[0059] (5) By adding output power constraints and main-backup vector constraints of synchronous generators and new energy generators, the scale of reserve is reasonably optimized. While meeting the frequency safety bottom line, redundant reserves are avoided. This ensures that the reserves do not exceed the unit output limit and that the global reserves are coordinated and balanced. It also reasonably optimizes the scale of reserves, reduces operating costs, and meets the needs of power grid operation.

[0060] (6) Taking into account the primary frequency regulation of synchronous generators and the inertial response and fast frequency regulation characteristics of new energy units, the advantages of multiple frequency regulation resources are complemented. In addition, under the premise of strictly ensuring the safety of grid frequency (meeting constraints such as frequency change rate and quasi-steady-state frequency), the goal is to minimize the total power generation cost, thus achieving a balance between operational economy and safety.

[0061] The present invention will now be described in further detail with reference to the accompanying drawings. Attached Figure Description

[0062] Figure 1 This is a flowchart of a power grid frequency security scheduling decision-making method that takes into account the spatiotemporal distribution of inertia in one embodiment.

[0063] Figure 2 This is a topology diagram of an IEEE 3-machine 9-node system in one embodiment.

[0064] Figure 3 This is a schematic diagram of the frequency dynamic response of the NFCS model and EMT in one embodiment.

[0065] Figure 4This is a schematic diagram of the expected frequency dynamics and the actual frequency dynamics after load disturbance using the CFCS model in one embodiment. Detailed Implementation

[0066] To make the objectives, technical solutions, and advantages of this application clearer, the following detailed description is provided in conjunction with the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative and not intended to limit the scope of this application.

[0067] It should be noted that if the embodiments of the present invention involve descriptions such as "first" and "second," these descriptions are for descriptive purposes only and should not be construed as indicating or implying their relative importance or implicitly specifying the number of technical features indicated. Therefore, a feature defined with "first" and "second" may explicitly or implicitly include at least one of those features. Furthermore, the technical solutions of the various embodiments can be combined with each other, but this must be based on the ability of those skilled in the art to implement them. When the combination of technical solutions is contradictory or impossible to implement, it should be considered that such a combination of technical solutions does not exist and is not within the scope of protection claimed by the present invention.

[0068] In one embodiment, combined Figure 1 This paper provides a novel power grid security dispatch decision-making method that considers inertia and primary frequency regulation reserve distribution. The method includes the following steps:

[0069] Step 1: Construct a power flow model of the power system to characterize the power transmission relationships between nodes in the power system;

[0070] Step 2: Based on the power system flow model, construct a dynamic frequency security constraint model that considers the frequency space response. This model determines the spatiotemporal distribution of primary frequency regulation reserves for new energy generation and synchronous generators. The model takes into account the frequency dynamic characteristics of each generator node under load disturbances and is used to characterize the non-uniform distribution of inertia in the power grid space. The dynamic frequency security constraint model couples the dynamic power angle deviation of the generator node, the dynamic frequency deviation, and the frequency regulation response characteristics of the generator set.

[0071] Step 3: Discretize the dynamic frequency safety constraint model to generate a dynamic frequency safety linear constraint set;

[0072] Step 4: With minimizing the total power generation cost of the power system as the scheduling objective, construct a power grid scheduling model by combining the dynamic frequency security linear constraint set and solve it to obtain a power system scheduling scheme based on the spatial distribution of system inertia and the spatiotemporal distribution of primary frequency regulation reserve.

[0073] Furthermore, in one embodiment, the process of constructing the power system flow model in step 1 specifically includes:

[0074] Step 1-1: Simplify the power system model based on the DC power flow assumption;

[0075] Steps 1-2: Construct an augmented susceptance matrix containing N generator nodes and N load nodes;

[0076] Steps 1-3: Determine the output / input power of the power system load nodes and generator nodes based on the augmented susceptance matrix.

[0077] Preferably, in some embodiments, step 1-1 specifically includes:

[0078] Assumptions: 1) The sine of the phase angle difference can be approximated by the phase angle difference itself; 2) The voltage amplitude of the system is constant, expressed as...

[0079]

[0080] in, It is the sine value of the phase angle difference between the voltages at adjacent nodes in the system; This represents the phase angle difference between the voltages at adjacent nodes in the system. Let i be the node voltage at system node i; This is the system's rated voltage amplitude.

[0081] Preferably, in some embodiments, the augmented susceptance matrix in steps 1-2 is represented as:

[0082]

[0083] The output / input power of the load node in steps 1-3 is expressed as follows:

[0084]

[0085] The output / input power of the generator node in steps 1-3 is expressed as follows:

[0086]

[0087] or,

[0088]

[0089] In the formula, The susceptance matrix between generator nodes; This is the susceptance matrix from the generator node to the load node; This is the susceptance matrix from the load node to the generator node; The susceptance matrix between load nodes; This represents the injected power vector from the generator node; Power vector extracted for load nodes; The power angle vector of the load node; The power angle vector of the generator node; To obtain the generator equivalent susceptance matrix after eliminating load nodes; This is the power distribution matrix of load disturbance to generator power.

[0090] Furthermore, in one embodiment, when a load disturbance occurs in the power system, the dynamic frequency security constraint model in step 2 includes a dynamic model of the power angle deviation of the generator node and a dynamic model of the frequency of the generator node, which are expressed as follows:

[0091]

[0092]

[0093] In the formula, The time derivative of the generator node power angle vector; ω is the angular frequency vector of the generator node; This is the diagonal matrix of the rated angular velocity of the power system; It is the identity matrix. This represents the initial power of the load in the power system. The disturbance power of the load; Let be the diagonal matrix of the inertial constants of the synchronous generator set; This is the diagonal matrix of the damping coefficient constants of the synchronous generator set; The rated angular velocity of the power system; ω is the angular velocity of the generator node; The derivative vector of the angular velocity of the generator node; This represents the input power of the synchronous generator; For the input power of new energy units, To obtain the generator equivalent susceptance matrix after eliminating load nodes; The power angle vector of the generator node; This is the power distribution matrix of load disturbance to generator power.

[0094] Furthermore, in one embodiment, the dynamic frequency security constraint model in step 2 also takes into account the primary frequency regulation response of the synchronous generator and the fast frequency regulation response of the new energy unit considering the inertial response, and determines the primary frequency regulation reserve power or fast frequency regulation reserve power of the unit based on the magnitude of the inertia of the node new energy power generation and the synchronous generator.

[0095] Preferably, in some embodiments, the dynamic models of the primary frequency regulation response of the synchronous generator and the fast frequency regulation response of the new energy unit considering inertial response are respectively expressed as:

[0096]

[0097]

[0098] In the formula, The diagonal matrix of the time constants of the synchronous generator; This is the diagonal matrix of the time constants of the new energy generating units; This is a diagonal matrix of the droop coefficients for synchronous generator sets; This is a diagonal matrix of droop coefficients for new energy generating units; Let be the diagonal matrix of the inertial constants of the new energy generating unit; This represents the input power of the synchronous generator; This represents the initial input power of the synchronous generator; This is the derivative of the input power of the synchronous generator; This is the derivative of the initial input power of the synchronous generator; This represents the initial input power of the synchronous generator; This represents the initial input power of the new energy unit.

[0099] Furthermore, in one embodiment, the dynamic frequency safety constraint model in step 2 further includes a load-side frequency response dynamic model, expressed as:

[0100]

[0101] In the formula, ω is the angular frequency vector of the load node; The weighted matrix is ​​the network topology. This is the susceptance matrix from the load node to the generator node; This is the susceptance matrix between load nodes.

[0102] Furthermore, in one embodiment, the dynamic frequency safety linear constraint set mentioned in step 3 includes range restrictions on nodal angular frequencies, rate of change of frequency, and quasi-steady-state angular frequencies:

[0103] Angular frequency constraint:

[0104]

[0105] Frequency change rate constraint:

[0106]

[0107] Quasi-steady-state frequency constraints:

[0108]

[0109] In the formula, Let be the minimum allowed angular frequency for the i-th node; Let be the angular frequency of the i-th node at the n-th time step; Let be the angular frequency of the i-th node at the (n-1)-th time step; The maximum allowed angular frequency for the i-th node; Let be the vector representing the minimum allowed rate of change of frequency for the i-th node; Let be the vector representing the maximum allowed rate of change of frequency at the i-th node; Let be the minimum quasi-steady-state angular frequency allowed for the i-th node; Let be the quasi-steady-state angular frequency of the i-th node; Let i be the maximum quasi-steady-state angular frequency allowed for the i-th node. This indicates the time step set in the dynamic frequency response model.

[0110] Here, step 3 involves discretizing the dynamic frequency safety constraint model, including discretizing the node frequency response models of synchronous generators and new energy units:

[0111]

[0112]

[0113] In the formula, This indicates the time step set in the dynamic frequency response model; This represents the power angle vector at the nth time step of the generator node; This represents the power angle vector at the (n+1)th time step of the generator node; This represents the angular frequency of the generator node at the nth time step; This represents the angular frequency of the (n+1)th time step of the generator node.

[0114] Furthermore, in one embodiment, the dynamic frequency safety linear constraint set in step 3 also includes the output power constraints of synchronous generators and new energy generator sets, as well as the primary and backup vector constraints, to determine the primary frequency regulation backup or fast frequency regulation backup power of the unit while ensuring frequency safety.

[0115] Synchronous generator output power constraints:

[0116]

[0117] Output power constraints of new energy generator sets:

[0118]

[0119] Synchronous generator primary frequency regulation reserve power constraint:

[0120]

[0121] Reserve power constraints for rapid frequency regulation of new energy generating units:

[0122]

[0123] In the formula, ∆τ represents the time step set in the dynamic frequency response model; It is the output power of the nth time-step synchronous generator set; It is the output power of the (n+1)th time-step synchronous generator set; It is the output power of the nth time step new energy unit; It is the output power of the (n+1)th time-step new energy generator unit; It is the angular frequency of the system at the nth time step; It is the angular frequency of the system at the (n+1)th time step; It is the reserved downward primary backup vector for synchronous generator sets; It is the upward primary / backup vector reserved for synchronous generator sets; It is a reserved downward primary / backup vector for new energy generating units; It is the upward primary / backup vector reserved for new energy generating units. The diagonal matrix of the time constants of the synchronous generator. This is a diagonal matrix of the droop coefficients for synchronous generator sets; Let be the angular velocity of the generator node. It is the identity matrix. This represents the initial input power of the synchronous generator; This is a diagonal matrix of droop coefficients for new energy generating units; This is the initial input power of the new energy unit. Let be the diagonal matrix of the inertial constants of the new energy unit.

[0124] Furthermore, in one embodiment, the scheduling model also includes operational constraints on the power grid and generators, such as steady-state power balance constraints and power generation constraints. These constraints will not be elaborated further.

[0125] Furthermore, in one embodiment, the objective function in step 4 is expressed as:

[0126]

[0127] In the formula, This refers to the output power of the synchronous generator; This refers to the output power of the new energy generator set; It is the power generation cost coefficient of synchronous generator sets; It is the power generation cost coefficient of new energy units.

[0128] Furthermore, in one embodiment, the solution process in step 4 uses a discretized time step to optimize the output of each unit in order to coordinate the inertial resources and frequency reserves of each node.

[0129] In one embodiment, a novel power system grid security dispatch decision system considering inertia and primary frequency regulation reserve distribution is provided, the system comprising:

[0130] The first module is used to construct the DC power flow model of the power system;

[0131] The second module is used to construct a dynamic frequency security constraint model that considers the frequency space response under load disturbance.

[0132] The third module is used to discretize the dynamic frequency security constraint model to obtain linear constraints.

[0133] The fourth module is used to solve the scheduling model with the goal of minimizing power generation costs and output the optimized scheduling scheme.

[0134] Specific limitations regarding the new power system grid security dispatch decision-making system considering inertia and primary frequency regulation reserve distribution can be found in the limitations of the new power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution mentioned above, and will not be repeated here. Each module in the aforementioned new power system grid security dispatch decision-making system considering inertia and primary frequency regulation reserve distribution can be implemented entirely or partially through software, hardware, or a combination thereof. These modules can be embedded in or independent of the processor in a computer device, or stored in the memory of a computer device as software, so that the processor can call and execute the corresponding operations of each module.

[0135] In one embodiment, a computer device is provided, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor, when executing the computer program, implements:

[0136] Step 1: Construct a power flow model of the power system to characterize the power transmission relationships between nodes in the power system;

[0137] Step 2: Based on the power system flow model, construct a dynamic frequency security constraint model that considers the frequency space response. This model determines the spatiotemporal distribution of primary frequency regulation reserves for new energy generation and synchronous generators. The model takes into account the frequency dynamic characteristics of each generator node under load disturbances and is used to characterize the non-uniform distribution of inertia in the power grid space. The dynamic frequency security constraint model couples the dynamic power angle deviation of the generator node, the dynamic frequency deviation, and the frequency regulation response characteristics of the generator set.

[0138] Step 3: Discretize the dynamic frequency safety constraint model to generate a dynamic frequency safety linear constraint set;

[0139] Step 4: With minimizing the total power generation cost of the power system as the scheduling objective, construct a power grid scheduling model by combining the dynamic frequency security linear constraint set and solve it to obtain a power system scheduling scheme based on the spatial distribution of system inertia and the spatiotemporal distribution of primary frequency regulation reserve.

[0140] For specific limitations on each step, please refer to the limitations on the new power system grid security dispatch decision-making method that considers inertia and primary frequency regulation reserve distribution mentioned above, which will not be repeated here.

[0141] In one embodiment, a computer-readable storage medium is provided having a computer program stored thereon, the computer program being implemented when executed by a processor.

[0142] Step 1: Construct a power flow model of the power system to characterize the power transmission relationships between nodes in the power system;

[0143] Step 2: Based on the power system flow model, construct a dynamic frequency security constraint model that considers the frequency space response. This model determines the spatiotemporal distribution of primary frequency regulation reserves for new energy generation and synchronous generators. The model takes into account the frequency dynamic characteristics of each generator node under load disturbances and is used to characterize the non-uniform distribution of inertia in the power grid space. The dynamic frequency security constraint model couples the dynamic power angle deviation of the generator node, the dynamic frequency deviation, and the frequency regulation response characteristics of the generator set.

[0144] Step 3: Discretize the dynamic frequency safety constraint model to generate a dynamic frequency safety linear constraint set;

[0145] Step 4: With minimizing the total power generation cost of the power system as the scheduling objective, construct a power grid scheduling model by combining the dynamic frequency security linear constraint set and solve it to obtain a power system scheduling scheme based on the spatial distribution of system inertia and the spatiotemporal distribution of primary frequency regulation reserve.

[0146] For specific limitations on each step, please refer to the limitations on the new power system grid security dispatch decision-making method that considers inertia and primary frequency regulation reserve distribution mentioned above, which will not be repeated here.

[0147] As a specific example, the invention will be further described and verified in detail in one embodiment.

[0148] Taking the improved IEEE 9-point test system as an example, the effectiveness of the dynamic frequency security constraint method considering the spatial correlation of frequency response proposed in this invention is verified. The power grid topology is as follows: Figure 2 As shown.

[0149] The system base is set to 100 MVA, with allowable frequency deviation and RoCoF set to ±0.5 Hz and ±2 Hz / s, respectively. Node 1 contains one synchronous generator set; nodes 2 and 3 each contain one synchronous generator and one renewable energy generator set, with synchronous generator set 1 (SG1) selected as the equivalent unit. Tables 1 and 2 list the parameters of the synchronous generator sets (SGs) and renewable energy generator sets (RPGs), respectively.

[0150] The initial load power is 110MW, taking load disturbance events into account. Specifically, the active power of the loads connected to nodes 4, 6, and 9 will increase by 5MW, 8.5MW, and 8MW, respectively.

[0151] Table 1 Key parameters of SGs

[0152]

[0153] Table 2 Key parameters of RPGs

[0154]

[0155] In the process of making system scheduling decisions, it is necessary to define the variables and constraints for each time step. Therefore, the selection of the number of time steps will affect the efficiency of scheduling decisions. If the number of time steps is too small, it will lead to the generation of local optima; if the time step length is too large, it will slow down the calculation speed. In this example, it is assumed that the interval between two consecutive time steps in the scheduling process is set to 10 seconds, and the total scheduling time is 10,000 steps.

[0156] The novel power grid safety dispatch decision method proposed in this invention considers the spatiotemporal distribution of power system inertia and primary frequency regulation reserve of new energy power generation and synchronous generators. It takes into account the spatiotemporal distribution of power system inertia and the dynamic frequency response process of units under disturbances. Based on the inertia level of power system generator nodes, it reasonably optimizes the primary frequency regulation reserve power dispatch scheme of units, and at the same time embeds the linearization of dynamic frequency safety constraints into the traditional power system dispatch model.

[0157] The power grid frequency security dispatch decision-making method proposed in this invention takes into account the spatiotemporal distribution of inertia, and embeds the linearized dynamic frequency security constraints into the power system dispatch model.

[0158] To illustrate the advantages of the proposed method, this example compares dynamic frequency security constraints considering the spatial correlation of frequency response with traditional centralized frequency constraint scheduling models. The proposed node frequency constraint scheduling model is named NFCS, and a CoI-based frequency constraint scheduling model (CFCS) is also established. The optimized scheduling results are shown in Table 3.

[0159] Table 3. Scheduling results of the three models

[0160]

[0161] Then, load perturbation is performed to evaluate the performance of the derived scheduling scheme. Figure 3 The perturbation-induced frequency curves of the three generator nodes in the NFCS model were plotted. It can be observed that the frequency safety index is maintained within the safe range due to sufficient frequency reserves. Node 3 exhibits the highest initial RoCoF (-1.84 Hz / s) due to its smallest moment of inertia and largest equivalent power perturbation.

[0162] Furthermore, the accuracy of the proposed model was verified through EMT simulation. The trajectory obtained from the EMT simulation is shown below. Figure 3 As shown, the dashed line represents the simulation results of EMT. We can see that the frequency dynamics obtained by the proposed frequency response model are close to the EMT results. The mismatch in the oscillation process comes from the simplification of the generator model in the analytical derivation.

[0163] Figure 4 The expected and actual frequency curves in the CFCS model are presented. It can be seen that the actual node frequency drops below 49.5Hz. This is because in the CFCS model, the primary and secondary reserves of all generators are allocated dynamically based on the CoI frequency. However, the frequency dynamics of some nodes may differ significantly from the CoI frequency dynamics, thus the allocated primary reserves may be insufficient to provide inertial support. Therefore, the proposed power grid frequency security dispatch decision-making method considering the spatiotemporal distribution of inertia can more accurately allocate primary frequency regulation reserves, further enhancing the frequency security of the system after disturbances.

[0164] In summary, this invention breaks through the limitations of traditional static scheduling that only focuses on power balance, constructively embedding dynamic frequency security constraints into the scheduling framework. It proposes a more targeted scheduling scheme to address the problem of reduced system inertia and uneven distribution caused by the increase in the proportion of renewable energy, providing a more accurate and targeted solution for the frequency stability of high-proportion renewable energy power systems.

[0165] The above embodiments illustrate and describe the basic principles and main features of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The embodiments and descriptions in the specification are merely illustrative of the principles of the invention. Various changes and modifications can be made to the present invention without departing from its spirit and scope, and all such changes and modifications fall within the scope of the present invention as claimed.

Claims

1. A novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution, characterized in that, The method includes the following steps: Step 1: Construct a power flow model of the power system to characterize the power transmission relationships between nodes in the power system; Step 2: Based on the power system flow model, construct a dynamic frequency security constraint model that considers the frequency space response. This model determines the spatiotemporal distribution of primary frequency regulation reserves for new energy generation and synchronous generators. The model takes into account the frequency dynamic characteristics of each generator node under load disturbances and is used to characterize the non-uniform distribution of inertia in the power grid space. The dynamic frequency security constraint model couples the dynamic power angle deviation of the generator node, the dynamic frequency deviation, and the frequency regulation response characteristics of the generator set. Step 3: Discretize the dynamic frequency safety constraint model to generate a dynamic frequency safety linear constraint set; Step 4: With minimizing the total power generation cost of the power system as the scheduling objective, construct a power grid scheduling model by combining the dynamic frequency security linear constraint set and solve it to obtain a power system scheduling scheme based on the spatial distribution of system inertia and the spatiotemporal distribution of primary frequency regulation reserve.

2. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 1, characterized in that, Step 1, which involves constructing a power system flow model, specifically includes the following steps: Step 1-1: Simplify the power system model based on the DC power flow assumption; Steps 1-2: Construct an augmented susceptance matrix containing N generator nodes and N load nodes; Steps 1-3: Determine the output / input power of the power system load nodes and generator nodes based on the augmented susceptance matrix.

3. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 2, characterized in that, The augmented susceptance matrix in step 1-2 is represented as follows: The output / input power of the load node in steps 1-3 is expressed as follows: The output / input power of the generator node in steps 1-3 is expressed as follows: or, In the formula, The susceptance matrix between generator nodes; This is the susceptance matrix from the generator node to the load node; This is the susceptance matrix from the load node to the generator node; The susceptance matrix between load nodes; This represents the injected power vector from the generator node; Power vector extracted for load nodes; The power angle vector of the load node; The power angle vector of the generator node; To obtain the generator equivalent susceptance matrix after eliminating load nodes; This is the power distribution matrix of load disturbance to generator power.

4. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 2, characterized in that, The dynamic frequency safety constraint model mentioned in step 2 includes the dynamic model of the power angle deviation of the generator node and the dynamic model of the frequency of the generator node, which are expressed as follows: In the formula, The time derivative of the generator node power angle vector; ω is the angular frequency vector of the generator node; This is the diagonal matrix of the rated angular velocity of the power system; It is the identity matrix. This represents the initial power of the load in the power system. The disturbance power of the load; Let be the diagonal matrix of the inertial constants of the synchronous generator set; This is the diagonal matrix of the damping coefficient constants of the synchronous generator set; The rated angular velocity of the power system; ω is the angular velocity of the generator node; The derivative vector of the angular velocity of the generator node; This represents the input power of the synchronous generator; For the input power of new energy units, To obtain the generator equivalent susceptance matrix after eliminating load nodes; The power angle vector of the generator node; This is the power distribution matrix of load disturbance to generator power.

5. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 4, characterized in that, The dynamic frequency safety constraint model described in step 2 also takes into account the primary frequency regulation response of the synchronous generator and the fast frequency regulation response of the new energy unit considering the inertial response. The primary frequency regulation reserve power or fast frequency regulation reserve power of the unit is determined according to the magnitude of the inertia of the node new energy power generation and the synchronous generator.

6. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 5, characterized in that, The dynamic models of the primary frequency regulation response of the synchronous generator and the fast frequency regulation response of the new energy unit considering the inertial response are respectively expressed as follows: In the formula, The diagonal matrix of the time constants of the synchronous generator; This is the diagonal matrix of the time constants of the new energy generating units; This is a diagonal matrix of the droop coefficients for synchronous generator sets; This is a diagonal matrix of droop coefficients for new energy generating units; Let be the diagonal matrix of the inertial constants of the new energy generating unit; This represents the input power of the synchronous generator; This represents the initial input power of the synchronous generator; This is the derivative of the input power of the synchronous generator; This is the derivative of the initial input power of the synchronous generator; This represents the initial input power of the synchronous generator; This represents the initial input power of the new energy unit.

7. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 5, characterized in that, The dynamic frequency safety constraint model described in step 2 also includes a load-side frequency response dynamic model, expressed as: In the formula, ω is the angular frequency vector of the load node; The weighted matrix is ​​the network topology. This is the susceptance matrix from the load node to the generator node; This is the susceptance matrix between load nodes.

8. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 1, characterized in that, The dynamic frequency safety linear constraint set mentioned in step 3 includes range restrictions on nodal angular frequencies, rate of change of frequency, and quasi-steady-state angular frequencies: Angular frequency constraint: Frequency change rate constraint: Quasi-steady-state frequency constraints: In the formula, Let be the minimum allowed angular frequency for the i-th node; Let be the angular frequency of the i-th node at the n-th time step; Let be the angular frequency of the i-th node at the (n-1)-th time step; The maximum allowed angular frequency for the i-th node; Let be the vector representing the minimum allowed rate of change of frequency for the i-th node; Let be the vector representing the maximum allowed rate of change of frequency at the i-th node; Let be the minimum quasi-steady-state angular frequency allowed for the i-th node; Let be the quasi-steady-state angular frequency of the i-th node; Let i be the maximum quasi-steady-state angular frequency allowed for the i-th node. This indicates the time step set in the dynamic frequency response model.

9. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 8, characterized in that, The dynamic frequency safety linear constraint set mentioned in step 3 also includes the output power constraints of synchronous generators and new energy generator sets, as well as the primary and backup vector constraints, to determine the primary frequency regulation backup or fast frequency regulation backup power of the unit while ensuring frequency safety. Synchronous generator output power constraints: Output power constraints of new energy generator sets: Synchronous generator primary frequency regulation reserve power constraint: Reserve power constraints for rapid frequency regulation of new energy generating units: In the formula, This indicates the time step set in the dynamic frequency response model; It is the output power of the nth time-step synchronous generator set; It is the output power of the (n+1)th time-step synchronous generator set; It is the output power of the nth time step new energy unit; It is the output power of the (n+1)th time-step new energy generator unit; It is the angular frequency of the system at the nth time step; It is the angular frequency of the system at the (n+1)th time step; It is the reserved downward primary backup vector for synchronous generator sets; It is the upward primary / backup vector reserved for synchronous generator sets; It is a reserved downward primary / backup vector for new energy generating units; It is the upward primary / backup vector reserved for new energy generating units. The diagonal matrix of the time constants of the synchronous generator. This is a diagonal matrix of the droop coefficients for synchronous generator sets; Let be the angular velocity of the generator node. It is the identity matrix. This represents the initial input power of the synchronous generator; This is a diagonal matrix of droop coefficients for new energy generating units; This represents the initial input power of the new energy unit. Let be the diagonal matrix of the inertial constants of the new energy unit.

10. The novel power system grid security dispatch decision-making method considering inertia and primary frequency regulation reserve distribution according to claim 1, characterized in that, In step 4, the solution process uses a discretized time step to optimize the output of each unit, so as to coordinate the inertial resources and frequency reserves of each node and obtain the optimized power system dispatch scheme.

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