A switch optimization configuration method for photovoltaic access distribution network considering explicit reliability

Abstract

The application provides a switch optimization configuration method for photovoltaic access distribution network considering explicit reliability, and specifically comprises the following steps: obtaining multi-source data of a distribution network and constructing a typical source-load combined operation scene; dividing a power failure area for each line fault in the typical scene, if photovoltaic can form an island boundary, correcting effective power supply shortage after the fault to the net power supply shortage after deducting photovoltaic output from load demand, and determining a multi-type switch phased recovery time sequence, and establishing a load recovery model after the fault; taking the minimum comprehensive cost as the target to construct a multi-type switch collaborative configuration objective function, embedding the expected net power supply shortage into the objective function; establishing multi-type switch configuration constraints, phased action constraints, network topology constraints and electrical operation constraints, combining into a collaborative configuration optimization model and solving to obtain a switch configuration scheme with the minimum comprehensive cost. The application improves the power supply reliability and economy of a distribution network containing a high proportion of distributed photovoltaic.

Description

Technical Field

[0001] This invention belongs to the field of distribution network planning and operation technology, and specifically relates to an optimized configuration method for photovoltaic-connected distribution network switches that considers explicit reliability. Background Technology

[0002] Against the backdrop of "dual-carbon" goals and the construction of new power systems, distribution networks are gradually transforming from traditional unidirectional power supply networks into active distribution networks with coordinated operation of multiple elements including sources, grids, and loads. With the large-scale integration of new energy sources such as distributed photovoltaics (PV), some areas of the distribution network simultaneously possess the dual attributes of load consumption and power supply support. On the one hand, distributed PV can improve the absorption of renewable energy and alleviate some feeder power supply pressure; on the other hand, PV output is significantly affected by weather, sunlight, and seasonal variations. When combined with fluctuations in user load, this makes the power flow distribution, node voltage levels, and power restoration process after faults more complex. Therefore, for distribution networks with a high proportion of distributed PV integration, relying solely on power flow optimization under normal operating conditions or traditional fault-shifting strategies is no longer sufficient to meet the requirements of safe, economical, and reliable system operation. After a distribution network fault occurs, quickly isolating the faulty section and restoring power to the non-faulty areas is crucial for improving power supply reliability. Various types of switching equipment, such as circuit breakers, automated switches, manual switches, and tie switches, can achieve fault isolation and load shifting. Among them, circuit breakers can quickly isolate the impact of faults after a short-circuit current occurs; automated switches can achieve rapid fault section isolation through communication and remote control; manual switches have lower investment costs but their operation depends on manual operation and the recovery time is longer; and tie switches are mainly used for cross-feeder transfer after a fault. The differences in operating speed, investment cost, and control capabilities among different types of switches will directly affect the scope of power outages, the duration of power outages, and the effectiveness of load restoration after a fault.

[0003] While existing methods for distribution network switch configuration and fault recovery have been extensively studied in areas such as network reconfiguration, loss reduction, reliability improvement, and power outage loss reduction, shortcomings remain. First, traditional recovery methods often rely on a single path: fault isolation, tie-line power transfer, and load restoration. They typically treat distributed photovoltaic (PV) power as off-grid resources after a fault, failing to adequately consider the role of PV in supporting lost loads through local islanding after fault isolation. This leads to inaccurate assessments of outage power and losses. Second, existing switch configuration methods do not adequately consider the dual fluctuations of source and load. PV output and load demand vary significantly with weather, time of day, and operating scenarios. The same fault location may result in different power shortages under different source and load conditions. If planning is based solely on fixed loads or a single scenario, switch configuration schemes are difficult to adapt to the actual operating conditions under high-proportion renewable energy integration. Third, existing methods lack clear descriptions of the operational stages of various switch types. Distribution network fault recovery typically includes three stages: fault degradation, fault isolation, and power restoration. Circuit breakers, automated switches, manual switches, and tie-line switches have different operating speeds and control methods at different stages. Simplifying the recovery process to a static topology change makes it difficult to accurately reflect the impact of switch actions on outage time and recovery effectiveness. Fourth, existing reliability assessments and switch optimizations are often disconnected. Some methods require generating switch configuration schemes first, followed by reliability assessments and iterative corrections, resulting in low computational efficiency. While heuristic optimization methods can handle discrete variables, they are prone to problems such as high computational load, slow convergence, and insufficient result stability when the number of fault scenarios, source-load scenarios, and switch types increases. Fifth, existing explicit reliability modeling methods focus primarily on traditional network reconstruction, failing to adequately consider the islanded power supply recovery of local photovoltaic systems and the phased action relationships of multiple switch types, making it difficult to achieve unified optimization of switch location, fault recovery, and reliability assessment.

[0004] In summary, there is an urgent need in this field for a distribution network switch optimization configuration method that can comprehensively consider the support of photovoltaic islands, the phased operation differences of various types of switches, and explicit reliability indicators. This method should integrate the support role of distributed photovoltaic after a fault, the phased operation process of various types of switches, topological connectivity constraints, voltage safety constraints, radial operation constraints, and reliability indicators such as power outage losses into a unified optimization framework. This would enable coordinated optimization of switch location, fault recovery, and reliability assessment, thereby improving the power supply recovery capability, operational economy, and reliability of distribution networks with a high proportion of distributed photovoltaic. Summary of the Invention

[0005] To address the aforementioned technical problems, this invention proposes an optimized configuration method for photovoltaic (PV) grid switches that considers explicit reliability. Addressing issues such as increased source-load fluctuations in the distribution network after a high proportion of distributed PV grid integration, significant differences in the actions of various switch types, and the separation of reliability assessment and switch planning, a collaborative configuration model is constructed that considers PV islanding support, phased actions of various switch types, and explicit reliability indicators. This model enables optimized location and configuration of circuit breakers, automated switches, manual switches, and tie switches.

[0006] To achieve the above objectives, the present invention adopts the following technical solution: In a first aspect, the present invention proposes an optimized configuration method for photovoltaic grid-connected switches that considers explicit reliability, comprising the following steps: Acquire multi-source data of the distribution network and construct a typical source-load joint operation scenario based on the multi-source data; under the typical source-load joint operation scenario, divide the power loss area for the fault location of each line; if the photovoltaic in the power loss area can form an island operation boundary, then correct the effective power supply shortage after the fault to the net power supply shortage after deducting the local photovoltaic support power from the load demand, and determine the phased recovery sequence of multiple types of switches to establish a load recovery model after the distribution network fault. With the goal of minimizing the overall cost within the planning period, an objective function for the coordinated configuration of multiple types of switches is constructed. The overall cost includes the investment cost of multiple types of switches and tie lines and the expected power outage loss cost. The expected net power shortage is explicitly embedded in the objective function to achieve the coordinated solution of switch planning and reliability assessment. Establish multi-type switch configuration constraints, multi-type switch action constraints, network topology constraints, and electrical operation constraints. Combine all constraints with the objective function to form a collaborative configuration optimization model. Call the optimization solver to solve the collaborative configuration optimization model to obtain the multi-type switch configuration locations and equipment types that minimize the overall cost.

[0007] Furthermore, multi-source data of the distribution network is acquired, and a typical source-load joint operation scenario is constructed based on the multi-source data, specifically: Acquire multi-source data of the power distribution network; the multi-source data of the power distribution network includes: grid structure data, source load operation data, candidate equipment location data, and equipment characteristic parameter data; Based on the historical load data and distributed photovoltaic historical output data in the source-load operation data, the scenarios are discretized according to the seasonal variation patterns of light intensity and temperature to form several typical source-load joint operation scenarios, and the probability of occurrence of each scenario is determined.

[0008] Furthermore, the effective power supply shortage after the fault Represented as: ; in, This represents the load demand within the isolated area; This indicates the available distributed photovoltaic power output within the isolated island area.

[0009] Furthermore, the process of determining the phased recovery sequence for multiple types of switches is as follows: the phased recovery sequence is divided into: fault degradation phase, fault isolation phase, and power supply restoration phase; The fault degradation stage is the stage after the upstream circuit breaker trips and clears the short-circuit fault after the fault occurs; The fault isolation stage is the stage in which the switches at both ends of the faulty branch are disconnected to form an isolation boundary; The power restoration phase consists of the upstream circuit breaker reclosing, the distributed photovoltaic system meeting the islanding operation conditions reconnecting to the grid to support the load, and the tie switch closing to jointly restore the non-faulty load.

[0010] Furthermore, with the goal of minimizing the overall cost within the planning period, an objective function for the coordinated configuration of multiple types of switches is constructed, specifically as follows: ; ; ; ; in, This indicates the total cost over the planning period; This indicates the initial investment cost of various types of switches and tie lines; This represents the expected penalty cost for power outages during the planning period; Indicates the first The probability of occurrence of a typical scenario; This represents the total number of typical scenarios; This indicates the combined economic loss from power outages under specific fault scenarios and source-load scenarios. This represents the set of existing feeder sections in the system that need to be upgraded. Identifier representing the line port; This indicates the overall investment cost per circuit breaker; This indicates the overall investment cost per unit of an automated switch. This indicates the total investment cost per manual switch. Indicates whether it is in the segment of Binary decision variables for configuring circuit breakers at the terminal; Indicates whether it is in the segment of Binary decision variables for configuring automated switches at the terminal; Indicates whether it is in the segment of The binary decision variable for manual switching is configured at the terminal. Represents the set of candidate contact lines; Indicates the decision-making variables for the construction of the connecting line; This indicates the construction cost of a single connecting line; This indicates the effective power shortage in the upstream healthy area after fault isolation; This indicates the delay in reclosing recovery due to upstream fault degradation; This indicates the effective power shortage in the downstream power-loss area after fault isolation; Indicates the downstream fault isolation delay; Indicates the power transfer delay of the interconnection switch; This indicates the load power that cannot be restored to the entire network from the moment the fault occurs until the protection system operates. Indicates the duration of the protective action; This represents the economic penalty coefficient for the unit of expected power shortage. This indicates the average annual failure rate of the line; This indicates the planning cycle of the equipment.

[0011] Furthermore, the desired net power shortage is explicitly embedded in the objective function to achieve a collaborative solution for switch planning and reliability assessment. The specific process includes: Among them, the expected net power shortage Represented as: ; Based on the expected net power shortage, the average outage duration index of the system is further calculated. System average power outage frequency index and system average availability index , respectively represented as: ; ; ; in, This indicates the total network load demand under normal operating conditions. This represents the comprehensive calculated average duration of a single power outage under multiple fault scenarios. The , , and As a reliability evaluation index, it directly participates in the calculation of the objective function and scheme selection through the hierarchical transmission relationship between switch configuration, switch action, topology connectivity and load power supply, thereby realizing the collaborative solution of switch planning and reliability assessment.

[0012] Furthermore, the multi-type switch configuration constraint is as follows: for any line port in the distribution network, the sum of the circuit breaker configuration variable, the automatic switch configuration variable, and the manual switch configuration variable shall not exceed 1, that is, at most one type of switchgear shall be configured for the same line port; The multi-type switching action constraints include fault degradation stage constraints, fault isolation stage constraints, and power restoration stage constraints. The fault degradation stage constraint is as follows: based on the fault location, the port of the nearest configured circuit breaker upstream of the fault source direction is determined to perform a protection tripping action, and only the port of the configured circuit breaker is allowed to trip and change position; The fault isolation stage constraint is as follows: after the power distribution master station locates the fault branch, the fault branch port that has been configured with a circuit breaker or automatic switch is immediately disconnected, and the fault branch port that has been configured with a manual switch is disconnected after a delay. The power restoration phase is constrained as follows: after the fault isolation is completed, the upstream circuit breaker performs reclosing to restore power supply to the upstream area, the tie switch closes sequentially according to the preset time delay to realize load transfer, and the distributed photovoltaic system in the power failure area that meets the islanding operation conditions is reconnected to the grid to support the local load.

[0013] Furthermore, the network topology constraints include branch connectivity constraints and radial topology constraints: The branch connection state constraint is as follows: the electrical connection state of a branch is determined by the closed state of the first-end port switch and the closed state of the last-end port switch of the branch. When both the first-end port switch and the last-end port switch are closed, the branch is connected; when either the first-end port switch or the last-end port switch is open, the branch is disconnected. The energized state of a load node is determined by the following conditions: if the node can be traced back to the main grid substation through a connected branch path, or is located in a photovoltaic island area that meets the islanding operation conditions, then the node is energized and power supply is restored; otherwise, the node is de-energized. The radial topology constraint is as follows: in each self-healing recovery stage of each fault scenario, a virtual topology flow mechanism is adopted to ensure that each power supply area maintains a radial open-loop structure. The total amount of virtual topology flow flowing out from the main grid power point or the photovoltaic island master control node is equal to the total number of energized nodes in that stage, and each power supply area has a unique power injection point.

[0014] Furthermore, the electrical operating constraints include node power balance constraints and node voltage safety constraints; The node power balance constraint is as follows: the sum of the distributed photovoltaic injection power and the substation injection power of each node, minus the load power of that node, equals the sum of the active power and reactive power of the branch connected to that node; wherein, the load power of a power-off node is forcibly set to zero, and the power of a disconnected branch is forcibly set to zero. The node voltage safety constraint is that the voltage amplitude of each energized node must be maintained within the preset upper and lower voltage limits.

[0015] Furthermore, the optimization solver is invoked to solve the collaborative configuration optimization model, obtaining the multiple switch configuration locations and equipment types that minimize the overall cost, specifically: The objective function and all constraints are combined into a mixed-integer linear programming model; The optimization solver is invoked to solve the mixed-integer linear programming model, outputting whether a switch should be configured at each candidate location and the type of switch configured, thus obtaining multiple switch configuration locations and equipment types that minimize the overall cost. The effects described in the invention are merely those of the embodiments, and not all the effects of the invention. One of the above technical solutions has the following advantages or beneficial effects: Adapt to dual fluctuations in source and load.

[0016] This invention considers the fluctuation characteristics of photovoltaic power output and load demand under different weather conditions, time periods, and operating scenarios. By acquiring multi-source data from the distribution network, and based on historical load data and historical photovoltaic power output data, it discretizes the scenarios according to the seasonal variation patterns of solar intensity and temperature to form typical source-load joint operation scenarios and determine the probability of occurrence of each scenario. It then calculates the corresponding load recovery effect under different fault scenarios. Compared to traditional switch planning methods based on fixed loads or single scenarios in existing technologies, this invention can better adapt to the actual operating state of dual source-load fluctuations under conditions of high-proportion renewable energy access, avoiding the configuration scheme mismatch problem caused by scenario simplification.

[0017] Make full use of the support capabilities of photovoltaic islands.

[0018] This invention no longer simply treats distributed photovoltaic (PV) systems after a fault as off-grid resources. Instead, after the fault isolation boundary is formed, it determines whether PV systems within the power outage area can form an island operation boundary. When island conditions are met, the local PV support power is incorporated into the load recovery process. The power shortage after a fault is corrected from the traditional total load to the net power shortage after deducting the local PV support power from the load demand. This makes the power outage loss assessment more closely reflect the actual situation, fully leverages the support potential of PV systems in fault recovery, and effectively reduces unnecessary power outage losses.

[0019] Achieve collaborative solution for switch planning and reliability assessment.

[0020] This invention establishes a quantitative transmission chain between switch configuration results and reliability indicators: First, the switch configuration scheme determines the switch type configured for each line port, which in turn determines the open and closed states of the switches at each stage after a fault. Based on this, the network topology and the power supply status of each load node are determined. Finally, the expected power shortage, average outage duration, average outage frequency, and average system availability are directly calculated from the load power supply status. This quantitative transmission chain eliminates the need for reliability indicators as an external evaluation step after switch configuration is completed. Instead, they are directly embedded in the optimization model to participate in scheme selection, avoiding the iterative process of planning, evaluation, and correction in existing technologies, and significantly improving the model solution efficiency.

[0021] Precisely depict the differences in the phased actions of various types of switches.

[0022] This invention divides the self-healing process after a power distribution network fault into three stages: fault degradation, fault isolation, and power restoration. It constructs action logic constraints and action delay constraints for circuit breakers, automatic switches, manual switches, and tie switches in each stage, accurately depicting the differences in action speed, control method, and restoration sequence of each type of switch. This avoids the static topology simplification of the fault restoration process and can truly reflect the actual impact of multi-type switch configuration schemes on fault isolation time, load restoration speed, and power outage losses.

[0023] Unified optimization framework and efficient solution.

[0024] This invention combines multi-type switch configuration constraints, multi-type switch phased action constraints, network topology constraints, and electrical operation constraints with an objective function that minimizes overall cost into a collaborative configuration optimization model. This achieves the organic unification and simultaneous solution of switch location, fault recovery strategies, and reliability indicators, overcoming the shortcomings of existing technologies where planning, fault recovery, and reliability assessment are separated. Furthermore, this invention uses a mixed-integer linear programming model to describe the entire optimization problem and solves it by calling an optimization solver. This efficiently handles the computational complexity brought about by multi-fault scenarios, multi-source load scenarios, and multi-type switch combinations, exhibiting good computational efficiency and result stability, making it suitable for engineering applications in large-scale distribution networks. Attached Figure Description

[0025] Figure 1 This is a flowchart of a photovoltaic grid connection switch optimization configuration method considering explicit reliability proposed in Embodiment 1 of the present invention; Figure 2 This is a framework diagram of a photovoltaic grid connection switch optimization configuration method considering explicit reliability proposed in Embodiment 1 of the present invention; Figure 3 This is a schematic diagram of the optimal switch configuration result with the lowest overall cost for 44 nodes including PV access in Embodiment 2 of the present invention; Figure 4 This is a schematic diagram of the three-stage operation process of multiple types of switches in Embodiment 2 of the present invention; Figure 5 This is a schematic diagram illustrating the progressive relationship between switch configuration variables, switch status variables, and load status variables in Embodiment 2 of the present invention; Figure 6 This is a schematic diagram of a photovoltaic grid-connected switch optimization configuration system considering explicit reliability, as proposed in Embodiment 3 of the present invention. Detailed Implementation

[0026] To clearly illustrate the technical features of this solution, the invention will be described in detail below through specific embodiments and in conjunction with the accompanying drawings. The following disclosure provides many different embodiments or examples for implementing different structures of the invention. To simplify the disclosure of the invention, components and arrangements of specific examples are described below. Furthermore, reference numerals and / or letters may be repeated in different examples. This repetition is for simplification and clarity and does not in itself indicate a relationship between the various embodiments and / or arrangements discussed. It should be noted that the components illustrated in the drawings are not necessarily drawn to scale. Descriptions of well-known components, processing techniques, and processes are omitted in this invention to avoid unnecessarily limiting the invention.

[0027] Example 1 Embodiment 1 of this invention proposes an optimized configuration method for photovoltaic-connected distribution network switches that considers explicit reliability. Addressing issues such as increased source-load fluctuations in the distribution network after a high proportion of distributed photovoltaic access, significant differences in the actions of various switch types, and the separation of reliability assessment and switch planning, a collaborative configuration model is constructed that considers photovoltaic island support, phased actions of various switch types, and explicit reliability indicators. This model enables optimized location and configuration of circuit breakers, automated switches, manual switches, and tie switches.

[0028] Figure 1 This is a flowchart of a photovoltaic grid connection switch optimization configuration method considering explicit reliability proposed in Embodiment 1 of the present invention; Figure 2 This is a framework diagram of a photovoltaic grid connection switch optimization configuration method considering explicit reliability proposed in Embodiment 1 of the present invention; combined with Figure 1 and Figure 2 The process of implementing this invention will be explained together.

[0029] In step S1, multi-source data of the distribution network is acquired, and a typical source-load joint operation scenario is constructed based on the multi-source data. Under the typical source-load joint operation scenario, the power loss area is divided for the fault location of each line. If the photovoltaic in the power loss area can form an island operation boundary, the effective power supply shortage after the fault is corrected to the net power supply shortage after deducting the local photovoltaic support power from the load demand. The phased recovery sequence of multiple types of switches is determined, and a load recovery model after the distribution network fault is established. S11: Obtain multi-source data from the power distribution network; The multi-source data of the power distribution network includes: grid structure data, source load operation data, candidate equipment location data, equipment characteristic parameter data, and economic and operation parameter data.

[0030] The grid structure data includes grid structure data and distribution network branch parameters; Source-load operation data includes load data, distributed photovoltaic grid connection location and output data; Candidate equipment location data includes candidate switch installation locations and candidate tie line locations; Equipment characteristic parameter data includes line failure rate and operating time of different types of switches.

[0031] Economic and operational parameter data include user power outage loss factor, voltage upper and lower limits, and switch investment cost.

[0032] The switch types in this application include circuit breakers, automatic switches, manual switches, and tie switches.

[0033] S12: Based on the aforementioned multi-source data, a typical source-load joint operation scenario is constructed, specifically as follows: Acquire multi-source data of the power distribution network; the multi-source data of the power distribution network includes: grid structure data, source load operation data, candidate equipment location data, and equipment characteristic parameter data; Based on the historical load data and distributed photovoltaic historical output data in the source-load operation data, the scenarios are discretized according to the seasonal variation patterns of light intensity and temperature to form several typical source-load joint operation scenarios, and the probability of occurrence of each scenario is determined. Specifically, the year is divided into four typical periods: spring, summer, autumn, and winter. Within each period, according to the variation characteristics of light intensity (affecting photovoltaic output) and temperature (affecting load levels, such as cooling / heating load), corresponding photovoltaic output curves and load curves are generated respectively. The photovoltaic output and load data in each season are clustered or sampled at equal intervals to extract the typical daily output / load patterns of that season, forming several representative scenarios. The proportion of each scenario in the total number of operating days in the year is calculated as the probability of occurrence of that scenario.

[0034] By using typical source-load operation scenarios, the fluctuation characteristics of the distribution network operation status under different weather conditions, time periods, and load levels are characterized.

[0035] S13: Calculate the net power supply deficit after a failure of the photovoltaic island support. For each line fault and each typical source-load operation scenario, the distribution network is divided into an upstream healthy area and a downstream power-loss area based on the fault location. If there are usable distributed photovoltaic (PV) systems within the downstream power-loss area, and the fault isolation can form a local island operation boundary, then the on-site PV support power is included in the load restoration process. In this case, the effective power shortage after the fault is... Represented as: ; in, This represents the load demand within the isolated area; This represents the available distributed photovoltaic (PV) output within the isolated area. The formula indicates that the power shortage after a fault is adjusted from the traditional total load to the net power shortage taking into account PV support.

[0036] S14: The process of determining the phased recovery sequence of multiple types of switches is as follows: the phased recovery sequence is divided into: fault degradation phase, fault isolation phase and power supply restoration phase; The fault degradation stage is the stage where the upstream circuit breaker trips to clear the short-circuit fault after the fault occurs; the fault isolation stage is the stage where the switches at both ends of the faulty branch are disconnected to form an isolation boundary; the power restoration stage is the stage where the upstream circuit breaker recloses, distributed photovoltaic power plants that meet the islanding operation conditions are reconnected to the grid to support the load, and tie switches are closed to jointly restore the non-faulty load. Based on this, a load restoration model for the distribution network after a fault is established.

[0037] S15: Construct switch configuration variables, switch action variables, and load status variables; Switch configuration variables influence switch state variables at each stage through switch action constraints; switch state variables affect the power flow distribution of the system by changing the system topology, thus controlling the power supply status of each load; the load power supply status determines the system reliability index; finally, through the explicit reliability analytical constraints embedded in the model, the model optimizes the switch configuration according to the system reliability requirements, realizing the simultaneous implementation of switch configuration and reliability assessment.

[0038] In step S2, an objective function for the coordinated configuration of multiple types of switches is constructed with the goal of minimizing the overall cost within the planning period. The overall cost includes the investment cost of multiple types of switches and tie lines and the expected power outage loss cost. The expected net power shortage is explicitly embedded in the objective function to achieve the coordinated solution of switch planning and reliability assessment. S21: The objective function for multi-type switch cooperative configuration is expressed as: ; ; ; ; in, This indicates the total cost over the planning period; This indicates the initial investment cost of various types of switches and tie lines; This represents the expected penalty cost for power outages during the planning period; Indicates the first The probability of occurrence of a typical scenario; This represents the total number of typical scenarios; This indicates the combined economic loss from power outages under specific fault scenarios and source-load scenarios. This represents the set of existing feeder sections in the system that need to be upgraded. Identifier representing the line port; This indicates the overall investment cost per circuit breaker; This indicates the overall investment cost per unit of an automated switch. This indicates the total investment cost per manual switch. Indicates whether it is in the segment of Binary decision variables for configuring circuit breakers at the terminal; Indicates whether it is in the segment of Binary decision variables for configuring automated switches at the terminal; Indicates whether it is in the segment of The binary decision variable for manual switching is configured at the terminal. Represents the set of candidate contact lines; Indicates the decision-making variables for the construction of the connecting line; This indicates the construction cost of a single connecting line; This indicates the effective power shortage in the upstream healthy area after fault isolation; This indicates the delay in reclosing recovery due to upstream fault degradation; This indicates the effective power shortage in the downstream power-loss area after fault isolation; Indicates the downstream fault isolation delay; Indicates the power transfer delay of the interconnection switch; This indicates the load power that cannot be restored to the entire network from the moment the fault occurs until the protection system operates. Indicates the duration of the protective action; This represents the economic penalty coefficient for the unit of expected power shortage. This indicates the average annual failure rate of the line; This indicates the planning cycle of the equipment.

[0039] S22: The process of explicitly embedding the expected net power shortage into the objective function to achieve the collaborative solution of switch planning and reliability assessment includes: determining the expected net power shortage. Represented as: ; Based on the expected net power shortage, the average outage duration index of the system is further calculated. System average power outage frequency index and system average availability index , respectively represented as: ; ; ; in, This indicates the total network load demand under normal operating conditions. This represents the comprehensive calculated average duration of a single power outage under multiple fault scenarios. Will , , and As a reliability evaluation index, it directly participates in the calculation of the objective function and scheme selection through the hierarchical transmission relationship between switch configuration, switch action, topology connectivity and load power supply, thereby realizing the collaborative solution of switch planning and reliability assessment.

[0040] In step S3, multiple types of switch configuration constraints, multiple types of switch action constraints, network topology constraints, and electrical operation constraints are established. All constraints are combined with the objective function to form a collaborative configuration optimization model. The optimization solver is called to solve the collaborative configuration optimization model to obtain the multiple types of switch configuration locations and equipment types that minimize the overall cost.

[0041] S31: Establish configuration constraints for multiple types of switches In this invention, the constraint for multi-type switch configuration is: for any line port in the distribution network, the sum of the circuit breaker configuration variable, the automatic switch configuration variable, and the manual switch configuration variable does not exceed 1, that is, at most one type of switchgear can be configured for the same line port. Specifically: ; in, These are configuration variables for circuit breakers, automatic switches, and manual switches, respectively.

[0042] S32: Establish phased action constraints for multiple types of switches The phased operation constraints for multiple types of switches include constraints for the fault degradation stage, the fault isolation stage, and the power restoration stage. At the moment a fault occurs, the short-circuit current causes the nearest circuit breaker upstream of the fault source direction to trigger a protection trip. Therefore, the constraint for the fault degradation stage is: based on the fault location, determine the port of the nearest configured circuit breaker upstream of the fault source direction to perform a protection trip, and only the port of the configured circuit breaker is allowed to trip. ; ; in, Indicating a fault scenario Lower branch road of The switch status variable of the port, a value of 1 indicates that the switch is in the closed state, and a value of 0 indicates that the switch is in the open state; Indicates on a side road of The binary decision variable for whether the port is configured with a circuit breaker: 1 indicates that the circuit breaker is configured, and 0 indicates that it is not configured.

[0043] When the distribution substation locates a faulty branch, due to the anti-islanding mechanism, upstream and downstream photovoltaic (PV) systems exhibit differentiated grid connection characteristics. Upstream PV systems in healthy areas remain connected to the grid, while downstream PV systems in affected areas are forcibly and passively disconnected from the grid. Simultaneously, both ends of the faulty branch need to be disconnected to establish an isolation boundary. The delay of the isolation action is strictly controlled by the actual equipment type configured on that port: if it is configured with an RCS or CB (Regional Control System) with communication and motoring mechanisms, it is immediately disconnected at this stage; if it is an MS (Modem Service), it must wait until the next stage for manual operation.

[0044] The constraint for the fault isolation phase is: after the distribution master station locates the faulty branch, the faulty branch port equipped with a circuit breaker or automatic switch is immediately disconnected, and the faulty branch port equipped with a manual switch is disconnected after a delay; expressed as: ; ; ; in, Indicating a fault scenario Phase 1 (Fault Degradation Phase), Node The grid-connected status variable for photovoltaic power generation is set to 1 to indicate grid-connected operation and 0 to indicate grid disconnection. Identifier representing a distributed photovoltaic access node; Identifiers representing fault scenarios; This represents the set of all distributed photovoltaic (PV) access nodes in the distribution network; Indicating a fault scenario The set of nodes in the upstream region of the fault (i.e., the healthy region that can maintain power supply through the main grid substation); Indicating a fault scenario Below, the set of nodes in the downstream power loss area of ​​the fault (i.e., the area that temporarily loses power from the main grid after the fault occurs); Indicating a fault scenario Below, faulty branch of The port's switch state variables in phase 2; These represent the faulty branches. of The binary decision variables for whether the port is configured with a circuit breaker, automatic switch, or manual switch.

[0045] Switches (circuit breakers CB, remote control switches RCS) equipped with remote communication and electric operating mechanisms operate instantaneously.

[0046] ; in, Represents a constant; An identifier representing any branch section; Indicates the line port identifier; Characterize whether it is on a branch of The decision variable for configuring the circuit breaker at the port is set to 1 if the circuit breaker is configured and 0 if it is not configured. Characterize whether it is on a branch of The decision variable for configuring the port with an automated switch (remote control switch) is set to 1, indicating that the automated switch is configured, and 0 indicates that it is not configured. Indicating a fault scenario Down, side road of The switch state variable of the port in the second stage (fault isolation stage) is 1 to indicate that the switch is in the closed state and 0 to indicate that the switch is in the open state. Indicating a fault scenario Down, side road of The switch state variable of the port in the first stage (fault isolation stage) is set to 1 to indicate that the switch is in the closed state and 0 to indicate that the switch is in the open state. After the faulty branch is completely physically isolated, the system enters the full power restoration phase. At this time, the downstream photovoltaic system that meets the source-load matching conditions closes first to restore partial power supply. The upstream CB that tripped in Phase 1 performs reclosing, and the tail tie lines close sequentially according to the manual switching action time, realizing the coordinated self-healing of the entire network.

[0047] The constraints during the power restoration phase are as follows: After fault isolation is completed, the upstream circuit breaker performs reclosing to restore power supply to the upstream area, and the tie switches close sequentially according to preset time delays to achieve load transfer. Furthermore, distributed photovoltaic systems within the power outage area that meet the islanding operation conditions are reconnected to the grid to support local loads. Specifically: ; ; ; ; in, Indicating a fault scenario Phase 3 (Power Restoration Phase), Node The grid-connected status variable for photovoltaics is set to 1 to indicate that the photovoltaic system is connected to the grid, and 0 to indicate that the photovoltaic system is disconnected from the grid. Indicating a fault scenario Phase 3 branch of The port's switch status variable, where 1 indicates the switch is closed and 0 indicates the switch is open; Indicating a fault scenario Phase 3 branch of The on / off state variables of the port; Indicates a branch The decision variable for whether to build a connecting line is set to 1, indicating that the branch road will be built as a connecting line, and 0, indicating that it will not be built. This represents the set of all candidate tie-line branches in the distribution network; Indicates a branch of The decision variable for whether the port is configured with a manual switch is set to 1, and 0 indicates that it is not configured. Indicating a fault scenario Phase 3 (Power Restoration Phase), Branch of The on / off state variables of the port; Indicating a fault scenario Phase 2 (Fault Isolation Phase), Branch of The on / off state variable of the port.

[0048] Through the aforementioned multi-stage state constraints, the model rigorously reproduces the complete physical process of "upstream CB cutoff, photovoltaic anti-islanding grid disconnection, differentiated selection isolation, and photovoltaic grid connection and tie line reclosing" at the mathematical level.

[0049] Network topology constraints include branch connectivity constraints and radial topology constraints: S33: Establish branch connectivity state constraints The branch connectivity constraint is as follows: the electrical connectivity of a branch is determined by the closed state of the first-end port switch and the closed state of the last-end port switch. When both the first-end port switch and the last-end port switch are closed, the branch is connected; when either the first-end port switch or the last-end port switch is open, the branch is disconnected. Whether a feeder branch l as a whole has the capacity for power transmission depends on the closed state of the physical port switches at both ends of the line. The Big-M method is introduced to construct the changeover variables of the port switches at both ends. Decision variables related to branch connectivity The logical relaxation of constraints between them; that is ; in, Indicating a fault scenario The Stage, branch road The switch status variable of the first port (port 1) is set to 1 to indicate that the port switch is closed, and 0 to indicate that the port switch is open. Indicating a fault scenario The Stage, branch road The switch state variable of the end port (port 2) is set to 1 to indicate that the port switch is closed, and 0 to indicate that the port switch is open. Indicating a fault scenario The Stage, branch road The electrical connectivity state variable is set to 1 to indicate that the branch is physically connected (capable of transmitting electrical energy) and 0 to indicate that the branch is disconnected (not capable of transmitting electrical energy).

[0050] When the side road If both switches are closed and the large M-term converges to 0, then the branch is physically connected; if either switch at either end trips, the branch connectivity variable... When the current is reduced to zero, the line loses its ability to carry current.

[0051] The energized state of a load node is determined by the following conditions: if the node can be traced back to the main grid substation through a connected branch path, or is located in a photovoltaic island area that meets the islanding operation conditions, then the node is energized and power supply is restored; otherwise, the node is de-energized.

[0052] A differentiated grid disconnection mechanism for photovoltaics is introduced, whereby non-source loads remain topologically connected to substation nodes before the nodes become energized. Load nodes Charged variable The connectivity balance constraint must be satisfied.

[0053] ; ; in, Represented by node The set of first-end nodes (i.e., nodes) corresponding to the branches of the terminal nodes. (the set of upstream adjacent nodes); Represented by node The set of end nodes (i.e., nodes) corresponding to the branches of the first end node. The set of downstream adjacent nodes); Indicating a fault scenario The Stage, branch road (Connecting nodes) With nodes The electrical connectivity status variable of the branch is set to 1 to indicate that the branch is conducting and 0 to indicate that the branch is disconnected. Indicating a fault scenario The Phase Node The energized state variable is set to 1 to indicate that the node is energized (load power restored) and 0 to indicate that the node is de-energized. Indicating a fault scenario The Phase Node The indicator variable is used to indicate whether the photovoltaic system meets the self-healing grid boundary of the island. A value of 1 indicates that the node is located in a photovoltaic island area that meets the island operation conditions (and can be used as an island source point), and a value of 0 indicates that the node is not in the island area. This indicates the distance from the main grid substation to the node. The set of branches included in all possible power supply paths; Indicating a fault scenario The Stage, branch road Electrical connectivity state variables; Indicates a branch The path direction constant coefficient, set to 1, indicates that the branch is on the path from the main network to the node. The direction of the power supply path is positive, and 0 indicates that it is not on the path; Represents a node The indicator variable for whether the photovoltaic system meets the boundary of the islanded self-healing grid.

[0054] If the source is traced back to the main grid substation through a sound tracing mechanism, then Equal to 1; if The value equals 0, indicating a power outage in this section due to a main grid disconnection, and the photovoltaic system meets the grid connection requirements. If it equals 1, then It equals 1.

[0055] S34: Establish power grid operation constraints for LinDistFlow To evaluate the power supply feasibility of network reconfiguration and islanding schemes, power flow constraints and equipment safety operation verification need to be introduced at each stage. Given that the coordinated operation of multiple types of switches in a distribution network is a complex mixed-integer programming problem, this paper adopts the linearized power flow equation (LinDistFlow) and uses the Big-M method to decouple the power flow distribution from the switch topology state.

[0056] Electrical operating constraints include node power balance constraints and node voltage safety constraints; The node power balance constraint is as follows: the sum of the distributed photovoltaic injection power and the substation injection power of each node, minus the load power of that node, equals the sum of the active and reactive power of the branches connected to that node; wherein, the load power of a power-off node is forcibly set to zero, and the power of a disconnected branch is forcibly set to zero; specifically: ; ; in, Indicating a fault scenario The Stage, branch road (Connecting nodes) With nodes The trend Flow direction The active power transmitted over the network; Indicating a fault scenario The Stage, branch road (Connecting nodes) With nodes The trend Flow direction The active power transmitted over the network; Indicating a fault scenario The Stage, node Active power injected by distributed photovoltaic systems; Indicating a fault scenario The Stage, node Active power injected into the main grid of the substation (if node) (For substation nodes or isolated master control nodes). Indicating a fault scenario The Stage, node The energized state variable is set to 1 to indicate that the node is energized (load power restored) and 0 to indicate that the node is de-energized. Indicating a fault scenario ,node The rigid active power load demand; Indicating a fault scenario The Stage, branch road Reactive power transmitted upstream; Indicating a fault scenario The Stage, branch road Reactive power transmitted upstream; Indicating a fault scenario The Stage, node The reactive power injected into the main grid of the substation; Indicating a fault scenario ,node The rigid reactive load demand.

[0057] This constraint indicates that when a node is in a power-off state, its actual load is forcibly reset to zero, ensuring power convergence of passive nodes in the power outage area.

[0058] During fault isolation and reconfiguration, the physical disconnection of branches will alter the power flow path. This paper introduces a sufficiently large normal number. and The equations relating line power capacity and voltage drop are relaxed.

[0059] ; ; ; ; in, Indicating a fault scenario The Stage, branch road The electrical connectivity state variable is set to 1 to indicate that the branch is conducting and 0 to indicate that the branch is disconnected. Indicating a fault scenario The Stage, branch road Active power transmitted upstream; Indicating a fault scenario The Stage, branch road Reactive power transmitted upstream; Indicating a fault scenario The Stage, node The square of the voltage amplitude; Indicating a fault scenario The Stage, node The square of the voltage amplitude; Indicates a branch The resistance; Indicates a branch The reactance; Indicates a branch Active power transmitted upstream; Indicates a branch Reactive power transmitted upstream; When the branch is closed, the first two equations transform into conventional branch capacity constraints, and the latter two equations hold a strict equality, restoring the standard linear voltage drop equation; when the branch is open, the branch power is forcibly limited to zero, and large... item The effect ensures that the calculation of node voltages on both sides of the disconnected line is completely decoupled, objectively reflecting the physical fact of network disconnection.

[0060] The node voltage safety constraint is that the voltage amplitude of each energized node must be maintained within the preset upper and lower voltage limits.

[0061] To ensure power quality during power restoration, the voltage of each energized node in the system must be maintained within a safe margin. ; in, This represents the square of the minimum voltage amplitude; This represents the square of the maximum voltage amplitude. S35: Radial Constraints of Photovoltaic Distribution Networks The radial topology constraint is as follows: In each self-healing recovery phase of each fault scenario, a virtual topology flow mechanism is used to ensure that each power supply area maintains a radial open-loop structure. The total amount of virtual topology flow flowing out from the main grid power point or the photovoltaic island master control node is equal to the total number of energized nodes in that phase, and each power supply area has a unique power injection point.

[0062] The distribution network must maintain a radial open-loop operating structure during normal operation and fault self-healing reconfiguration phases. Following a fault, the system topology exhibits dynamic evolution due to the combined effects of various switching actions and differentiated photovoltaic (PV) disconnection and reconnection. Since multiple active islands independently supported by PV systems may form downstream of a fault, traditional topology constraints based on a single grid source cannot directly describe the open-loop characteristics of multiple coexisting islands.

[0063] To address this, a virtual topology flow mechanism is introduced to construct dynamic radial topology constraints suitable for multi-stage distribution networks with local photovoltaic island characteristics, as shown below: ; ; ; in, Indicating a fault scenario The Stage, branch road Virtual topology traffic, direction from node Flow to Node ; Indicating a fault scenario The Stage, branch road Virtual topology traffic, direction from node Flow to Node ; Indicating a fault scenario The Stage, node The energized state variable is set to 1 to indicate that the node is energized and 0 to indicate that the node is de-energized. This represents the set of all nodes in a power distribution network. Indicating a fault scenario The Stage, branch road The electrical connectivity state variable is set to 1 to indicate that the branch is conducting (capable of transmitting electrical energy) and 0 to indicate that the branch is disconnected. Indicating a fault scenario The Stage, branch road Virtual topology traffic; Indicates the energized state of a node: 1 indicates energized, 0 indicates de-energized; Indicates the total number of main network power points; Indicates the first Total number of master control nodes in a phased photovoltaic island.

[0064] S36: Call the optimization solver to solve the cooperative configuration optimization model, and obtain the multiple switch configuration locations and equipment types that minimize the overall cost. Specifically: The load recovery model after a distribution network fault established in step S1, the objective function for collaborative configuration of multiple types of switches constructed in step S2, and the constraints on multiple types of switch configuration, multiple types of switch action, network topology constraints, and electrical operation constraints established in step S3 are combined to form a collaborative configuration optimization model. In this model, circuit breaker configuration variables, automated switch configuration variables, manual switch configuration variables, and tie-line construction decision variables are used as decision variables. The objective function is to minimize the overall cost within the planning period. Constraints include multiple types of switch configuration constraints, phased action constraints, branch connectivity constraints, radial topology constraints based on the virtual topology flow mechanism, node power balance constraints, and node voltage security constraints, forming a mixed-integer linear programming model.

[0065] The mixed-integer linear programming model is solved using an optimization solver (such as commercial or open-source mixed-integer linear programming solvers like CPLEX, Gurobi, or SCIP). The solution process employs a combination of branch-and-bound and cutting-plane algorithms. The optimal solution for the current node is obtained by solving a linear relaxation problem within the search tree. Pruning operations are performed based on integer feasibility and the objective function value until the search tree is traversed and the global optimum is obtained. After the solution is complete, the optimal values ​​of each binary decision variable are extracted from the results. The system outputs whether a switch should be configured at each candidate location and the type of switch configured, thus obtaining multiple switch configuration locations and equipment types that minimize the overall cost.

[0066] Simultaneously, based on the solution results, the system outputs fault isolation schemes, switch action sequences, branch connectivity status, photovoltaic grid connection status, load power supply status, and interconnection transfer paths for each fault scenario and source-load scenario, as well as the expected power shortage. System average outage duration index System average power outage frequency index System average availability index Evaluation indicators include equipment investment costs, expected power outage loss costs, and overall system costs.

[0067] Example 2 To fully implement the photovoltaic-access distribution network switch optimization configuration method considering explicit reliability proposed in Embodiment 1 of the present invention, Embodiment 2 of the present invention uses a 44-node distribution system with distributed PV access as a case study to verify the effectiveness of the method disclosed in Embodiment 1. Figure 3 This is a schematic diagram of the optimal switch configuration result with the minimum overall cost for 44 nodes including PV access in Embodiment 2 of the present invention; where nodes 41, 42, 43 and 44 are connected to distributed photovoltaic.

[0068] Step 1: Establish the relationship between source load scenarios and load recovery after a fault; Step 1 specifically includes the following steps: Step 11: First, read the node data, line data, load data, line impedance, distributed photovoltaic access location, candidate switch installation location, candidate tie line location, line fault rate, voltage operating range, unit power outage loss cost, and investment cost and operating time of various switches in the distribution network.

[0069] The switches include circuit breakers, automatic switches, manual switches, and tie switches. Circuit breakers are mainly used for rapid disconnection after a fault occurs; automatic switches are mainly used for remote isolation of faulty sections; manual switches are mainly used for manual isolation or transfer of power in areas with limited investment costs; and tie switches are mainly used for transferring loads across feeders after a fault.

[0070] Step 12: Based on historical load data, distributed photovoltaic (PV) output data, and typical meteorological conditions, the PV output and load demand are divided into four typical source-load joint operation scenarios. Each typical scenario corresponds to a PV output level, load demand level, and scenario occurrence probability, used to describe the changes in the source-load status of the distribution network under different weather, time periods, and operating conditions. This process avoids using only a single load level or fixed PV output for switch configuration, ensuring that subsequent switch configuration results can adapt to the actual operating conditions under fluctuating source-load conditions.

[0071] Step 13: For each line in the distribution network that may experience a fault, divide the post-fault distribution network into an upstream healthy area and a downstream power outage area based on the fault location and network topology. The upstream healthy area refers to the area where power can be restored through the main grid after fault isolation; the downstream power outage area refers to the area where power is temporarily lost from the main grid after fault isolation. This area division allows for further determination of the fault isolation range, load outage range, and photovoltaic support range under different switch configuration schemes.

[0072] Step 14: For the downstream power outage area, determine whether there are usable distributed photovoltaic (PV) resources within the area, and whether a clear islanded operation boundary can be formed after fault isolation. If PV resources exist in the area, and a local power supply area that meets operational requirements can be formed through switching operations, then the PV is considered a supporting power source that can participate in load restoration after the fault. When the conditions for PV islanded support are met, the power shortage in the downstream area is no longer calculated based on the total power outage load, but rather on the net power shortage after deducting the available PV support capacity from the load demand. If the PV output can support part of the load, the power outage loss will be reduced accordingly; if the PV output can meet the local load demand, then that part of the load can be restored to power supply under islanded operation conditions.

[0073] Step 15: Divide the load restoration process after a distribution network fault into three stages: fault degradation, fault isolation, and power restoration. Figure 4This is a schematic diagram of the three-stage operation process of multiple types of switches in Embodiment 2 of the present invention. It shows the coordinated operation logic and timing relationship of circuit breakers (CB), automatic switches (RCS), manual switches (MS) and tie switches in the three stages from the occurrence of the fault to the restoration of power supply after a power distribution network fault.

[0074] Fault degradation phase: At the moment of fault occurrence, the short-circuit current causes the nearest upstream circuit breaker in the fault-tracing direction to trip, quickly isolating the impact of the short-circuit fault. The upstream and downstream areas of the fault point temporarily lose power supply from the main grid. During this phase, only ports with configured circuit breakers are allowed to trip. Simultaneously, due to the anti-islanding mechanism, photovoltaic systems in healthy upstream areas remain connected to the grid, while photovoltaic systems in affected downstream areas are forcibly and passively disconnected from the grid.

[0075] Fault Isolation Phase: After the main distribution station completes the fault section location, the switches at both ends of the faulty branch are opened to establish the isolation boundary. The time delay of the isolation action is strictly controlled by the actual equipment type configured on that port: if configured as a circuit breaker (CB) or automatic switch (RCS) with remote communication and electric operating mechanism, it will be disconnected immediately in this phase; if configured as a manual switch (MS), it must wait until the next phase for manual disconnection. The timing difference is as follows: Figure 4 As shown.

[0076] Power restoration phase: After the faulty branch is completely physically isolated, the system enters the full power restoration phase. At this time, the downstream photovoltaic system that meets the source-load matching conditions closes first, restoring partial load power supply in an islanded manner; the upstream circuit breaker that tripped in the first phase performs reclosing, restoring power supply to the upstream healthy area; the tail-end tie switch closes sequentially according to the preset time delay based on the manual switching action time, realizing cross-feeder load transfer, and the entire network completes coordinated self-healing recovery.

[0077] Figure 4 The timeline clearly presents the complete physical process of "upstream CB cutoff, photovoltaic anti-islanding grid disconnection, differentiated selection isolation to photovoltaic grid and tie line reclosing", intuitively demonstrating the impact of the differences in action speed, control method and recovery sequence of different types of switches on fault isolation time and load recovery effect.

[0078] Step 2: Establish a multi-type switch collaborative configuration optimization model; Step 2 specifically includes the following steps: Step 21: For the candidate switch installation locations, set configuration variables for circuit breakers, automatic switches, and manual switches to indicate whether the corresponding type of switchgear should be configured at that location. Simultaneously, set configuration variables for tie switches to indicate the opening and closing of tie lines; only one type of switchgear is allowed to be configured at the same line port. Step 22: In each fault scenario and each recovery phase, set switch status variables to indicate whether the corresponding switch is in a closed or open state. The switch status is determined jointly by the switch configuration results and the fault recovery phase. Configured circuit breakers, automatic switches, and manual switches participate in the fault degradation, fault isolation, and power restoration processes according to their respective operating characteristics.

[0079] Step 23: Determine whether the branch has the capacity for power transmission based on the status of the switches at both ends of the line. When both ends of the branch meet the closing conditions, the branch is in a connected state; when either end of the switch is open, the branch is in a disconnected state. Based on the branch's connected state, further determine whether each load node can be powered by the main grid or by the photovoltaic island. If a node can be connected to the main grid through a valid path, or is located within a photovoltaic island area that meets the operating conditions, then the node is considered to have restored power; otherwise, the node is considered to have lost power. Through the above processing, a progressive relationship is established between "switch configuration variables—switch status variables—load status variables," allowing the switch configuration results to directly affect the fault isolation range, network topology changes, and load recovery results.

[0080] Step 24: Before and after fault isolation, determine the grid connection status of the photovoltaic (PV) system based on its location. For PV systems in healthy areas upstream of the fault, they can continue operating after fault isolation. For PV systems in affected areas downstream of the fault, anti-islanding grid disconnection is implemented initially. Once the faulty branch is reliably isolated and an island boundary is formed, it is then determined whether the system meets the conditions for local grid connection. If the downstream area meets the requirements for island operation, the PV system in that area will resume power supply to support local loads.

[0081] Step 25: With the goal of minimizing the overall system cost within the planning period, consider two cost components: first, the equipment investment cost of circuit breakers, automated switches, manual switches, and tie switches; and second, the power outage loss cost caused by load power failures after a fault. By simultaneously considering investment costs and power outage loss costs, the model can coordinate reducing equipment investment and improving power supply reliability, avoiding the increase in power outage losses caused by simply pursuing low investment, and also avoiding excessive construction costs due to over-configuration of switches.

[0082] Step 26: Directly embed the expected power shortage into the model for calculation. The expected power shortage is determined comprehensively based on different fault scenarios, source-load operation scenarios, fault isolation time, interconnection and power transfer time, photovoltaic support capacity, and load recovery status. Average outage duration, average outage frequency, and average system availability are further calculated based on the expected power shortage and load power supply status. In this way, reliability evaluation is no longer an external assessment step after switch configuration is completed, but is performed simultaneously with switch location selection, switch design, fault isolation, and load recovery processes.

[0083] Step 27: During fault recovery, consider operating conditions such as power flow distribution, node voltage levels, and branch transmission capacity. For nodes with restored power, active and reactive power balance requirements must be met; for disconnected branches, power flow should be zero; for branches in closed operation, transmission power should meet line capacity limits. Simultaneously, node voltage after power restoration should remain within allowable limits to avoid voltage exceedances due to fault-based power transfer or photovoltaic islanding operation. By setting the above operating constraints, the resulting switch configuration scheme ensures not only load restoration but also compliance with the safe operation requirements of the distribution network.

[0084] Step 28: The distribution network should maintain a radial operating structure both during normal operation and after fault recovery. After a fault, the network topology may change due to the closure of tie switches, isolation of faulty branches, and the formation of photovoltaic islands. Therefore, connectivity assessments need to be performed separately for the main grid power supply area and the photovoltaic island area. For the main grid power supply area, it should be ensured that the load nodes whose power supply has been restored can be connected to the substation power supply point through a single effective path. For the photovoltaic island area, it should be ensured that the island has clear boundaries and that power is supplied to local loads by photovoltaic nodes with supporting capabilities. This constraint avoids the formation of ring network structures or passive islands that do not meet operational requirements.

[0085] Step 3: Solve the model and generate multiple types of switch configuration schemes.

[0086] Step 3 specifically includes the following steps: The source-load scenarios, fault area divisions, photovoltaic island support relationships, and load recovery relationships obtained in step 1 are combined with the switch configuration relationships, switch action relationships, load status relationships, reliability evaluation relationships, and safe operation constraints established in step 2 to form a multi-type switch collaborative configuration optimization model. The main decision-making content of this model includes: whether to install switches at each candidate location, what type of switches to install, how switches should operate at each stage after a fault, which loads can be restored to power, and which photovoltaic systems can participate in island support. The optimization solver is called to solve the model to obtain the switch configuration scheme with the lowest overall cost within the planning period. During the solution process, the model simultaneously considers the operating states under different fault lines, different source-load scenarios, and different recovery stages to determine the switch configuration results that meet the requirements of reliability, economy, and safe operation. Based on the solution results, the configuration locations and equipment types of circuit breakers, automatic switches, manual switches, and tie switches are output. For the location of tie lines, the corresponding tie switch configuration scheme is output. For each type of fault scenario, the corresponding fault isolation scheme, switch action sequence, branch connection status, photovoltaic grid connection status, load power supply status, and tie transfer path are output. For downstream power outage areas containing photovoltaic systems, the system outputs whether they possess islanding support capabilities, the recoverable load range, and the load range requiring connection and transfer. This forms a post-fault recovery strategy oriented towards actual operation. Based on the final switch configuration scheme and recovery results under various fault scenarios, the system outputs indicators such as expected power shortage, average outage duration, average outage frequency, average system availability, equipment investment cost, expected outage loss cost, and overall system cost.

[0087] The above indicators are used to evaluate the power supply reliability and economy of different configuration schemes, providing a basis for switch planning, fault self-healing and operation management of distribution networks including distributed photovoltaics.

[0088] Figure 5 The diagram illustrates the progressive relationship between switch configuration variables, switch status variables, and load status variables, demonstrating how the switch configuration scheme in this invention ultimately determines the calculation of reliability indicators through layer-by-layer transmission.

[0089] The first layer is the switch configuration variable layer. This layer uses binary decision variables to represent whether to install a switch at each candidate location and what type of switching equipment to install. These include circuit breaker configuration variables, automated switch configuration variables, manual switch configuration variables, and tie-line construction decision variables. Switch configuration variables are the core decision variables of the optimization model, determining the final configuration scheme for various types of switches in the distribution network.

[0090] The second layer is the switch state variable layer. Based on the determined switch configuration scheme, for each fault scenario and each self-healing recovery stage, the open and closed states of each line port switch are jointly determined by the recovery strategy and fault location for that stage. The switch state variables directly reflect the action logic and timing coordination relationship of different types of switches in the three stages of fault degradation, fault isolation, and power restoration.

[0091] The third layer is the topology connectivity and load status variable layer. Based on the closed or open state of the switches at each line port, the electrical connectivity state of each branch is determined: the branch is conductive when both switches at both ends are closed, and disconnected when either switch is open. Further, the energization status of each load node is determined: if a node can be traced back to the main grid substation via a connected branch path, or is located within a photovoltaic islanding area that meets the islanding operation conditions, then the node is energized and power supply is restored; otherwise, the node is de-energized.

[0092] The fourth layer is the reliability index calculation layer. Based on the load power supply status and net power shortage of each node, the expected power shortage is calculated. This further leads to the system average outage duration index. System average power outage frequency index and system average availability index Reliability indicators, etc., are directly fed back into the objective function to participate in scheme selection, achieving a collaborative solution for switch configuration and reliability assessment.

[0093] Figure 5 Through a four-level progressive mapping relationship, a complete transmission chain is clearly presented, from switch configuration variables, switch state variables, topology connectivity state, load power supply state to reliability indicators. This reflects the core technical feature of this invention that the switch configuration result directly affects the fault isolation range, load recovery process, and the calculation of expected power shortage.

[0094] The strategy (Strategy I) that does not consider photovoltaic island support in the traditional distribution network scenario is compared with the strategy (Strategy II) of the present invention that considers photovoltaic island support and explicit reliability in the photovoltaic distribution network scenario. The reliability indicators and economic costs of the two strategies are shown in Table 1.

[0095] Table 1: Comparison of Reliability Indicators and Economic Costs under Different Strategies

[0096] As shown in Table 1, Strategy II of this invention... It decreased from 1.19 MWh / year to 0.83 MWh / year, a reduction of approximately 30.3%; It decreased from 0.238 h / year to 0.166 h / year; The frequency decreased from 1.075 times / year to 0.75 times / year. The accuracy rate increased from 99.997% to 99.998%. Regarding overall costs, although equipment investment costs slightly increased from RMB 246,000 / year to RMB 249,500 / year, the expected power outage cost decreased from RMB 16,660 / year to RMB 11,670 / year, resulting in a decrease in the overall cost from RMB 262,660 / year to RMB 261,170 / year, thus improving the overall economic efficiency of the system. These results verify the effectiveness and superiority of the method proposed in this invention.

[0097] Example 3 Based on the photovoltaic grid-connected switch optimization configuration method considering explicit reliability proposed in Embodiment 1 of the present invention, Embodiment 3 of the present invention also proposes a photovoltaic grid-connected switch optimization configuration system considering explicit reliability. Figure 6 This is a schematic diagram of a photovoltaic grid-connected switch optimization configuration system considering explicit reliability, as proposed in Embodiment 3 of the present invention. The system includes: The load recovery modeling module after a fault is used to acquire multi-source data of the distribution network and construct a typical source-load joint operation scenario based on the multi-source data. Under the typical source-load joint operation scenario, the power loss area is divided for the fault location of each line. If the photovoltaic in the power loss area can form an island operation boundary, the effective power supply shortage after the fault is corrected to the net power supply shortage after deducting the local photovoltaic support power from the load demand. The phased recovery sequence of multiple types of switches is determined, and a load recovery model after a fault in the distribution network is established. The objective function construction module is used to construct an objective function for the coordinated configuration of multiple types of switches with the goal of minimizing the overall cost within the planning period. The overall cost includes the investment cost of multiple types of switches and tie lines and the expected power outage loss cost. The expected net power shortage is explicitly embedded in the objective function to achieve the coordinated solution of switch planning and reliability assessment. The optimization solution module is used to establish multi-type switch configuration constraints, multi-type switch action constraints, network topology constraints, and electrical operation constraints. All constraints are combined with the objective function to form a collaborative configuration optimization model. The optimization solver is called to solve the collaborative configuration optimization model to obtain the multi-type switch configuration locations and equipment types that minimize the overall cost.

[0098] The description of the relevant parts of the photovoltaic grid-connected switch optimization configuration system considering explicit reliability provided in Embodiment 3 of this application can be found in the detailed description of the corresponding parts of the photovoltaic grid-connected switch optimization configuration method considering explicit reliability provided in Embodiment 1 of this application, and will not be repeated here.

[0099] The photovoltaic grid-connected switch optimization configuration system considering explicit reliability provided in Embodiment 3 of the present invention modularizes the process of the method disclosed in Embodiment 1, and can achieve the same technical effect as Embodiment 1, which will not be repeated here.

[0100] It should be noted that, in this document, relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that the elements inherent in a process, method, article, or apparatus that includes a list of elements are included. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element. Additionally, portions of the technical solutions provided in the embodiments of this application that are consistent with the implementation principles of corresponding technical solutions in the prior art have not been described in detail to avoid excessive elaboration.

[0101] While specific embodiments of the present invention have been described above in conjunction with the accompanying drawings, this is not intended to limit the scope of protection of the present invention. Those skilled in the art can make other modifications or variations based on the above description. It is neither necessary nor possible to exhaustively describe all embodiments here. Various modifications or variations that can be made by those skilled in the art without creative effort based on the technical solutions of the present invention are still within the scope of protection of the present invention.

Claims

1. A method for optimizing the configuration of photovoltaic (PV) grid-connected switches considering explicit reliability, characterized in that, Includes the following steps: Acquire multi-source data of the distribution network and construct a typical source-load joint operation scenario based on the multi-source data; under the typical source-load joint operation scenario, divide the power loss area for the fault location of each line; if the photovoltaic in the power loss area can form an island operation boundary, then correct the effective power supply shortage after the fault to the net power supply shortage after deducting the local photovoltaic support power from the load demand, and determine the phased recovery sequence of multiple types of switches to establish a load recovery model after the distribution network fault. With the goal of minimizing the overall cost within the planning period, an objective function for the coordinated configuration of multiple types of switches is constructed. The overall cost includes the investment cost of multiple types of switches and tie lines and the expected power outage loss cost. The expected net power shortage is explicitly embedded in the objective function to achieve the coordinated solution of switch planning and reliability assessment. Establish multi-type switch configuration constraints, multi-type switch action constraints, network topology constraints, and electrical operation constraints. Combine all constraints with the objective function to form a collaborative configuration optimization model. Call the optimization solver to solve the collaborative configuration optimization model to obtain the multi-type switch configuration locations and equipment types that minimize the overall cost.

2. The method according to claim 1, characterized in that, Acquire multi-source data from the distribution network, and construct a typical source-load joint operation scenario based on the multi-source data, specifically as follows: Acquire multi-source data of the power distribution network; the multi-source data of the power distribution network includes: grid structure data, source load operation data, candidate equipment location data, and equipment characteristic parameter data; Based on the historical load data and distributed photovoltaic historical output data in the source-load operation data, the scenarios are discretized according to the seasonal variation patterns of light intensity and temperature to form several typical source-load joint operation scenarios, and the probability of occurrence of each scenario is determined.

3. The method according to claim 2, characterized in that, The effective power shortage after the fault Represented as: ； in, This represents the load demand within the isolated area; This indicates the available distributed photovoltaic power output within the isolated island area.

4. The method according to claim 1, characterized in that, The process of determining the phased recovery sequence for multiple types of switches is as follows: the phased recovery sequence is divided into: fault degradation phase, fault isolation phase, and power supply restoration phase; The fault degradation stage is the stage after the upstream circuit breaker trips and clears the short-circuit fault after the fault occurs; The fault isolation stage is the stage in which the switches at both ends of the faulty branch are disconnected to form an isolation boundary; The power restoration phase consists of the upstream circuit breaker reclosing, the distributed photovoltaic system meeting the islanding operation conditions reconnecting to the grid to support the load, and the tie switch closing to jointly restore the non-faulty load.

5. The method according to claim 1, characterized in that, With the goal of minimizing the overall cost within the planning period, an objective function for the coordinated configuration of multiple types of switches is constructed, specifically as follows: ； ； ； ； in, This indicates the total cost over the planning period; This indicates the initial investment cost of various types of switches and tie lines; This represents the expected penalty cost for power outages during the planning period; Indicates the first The probability of occurrence of a typical scenario; This represents the total number of typical scenarios; This indicates the combined economic loss from power outages under specific fault scenarios and source-load scenarios. This represents the set of existing feeder sections in the system that need to be upgraded. Identifier representing the line port; This indicates the overall investment cost per circuit breaker; This indicates the overall investment cost per unit of an automated switch. This indicates the total investment cost per manual switch. Indicates whether it is in the segment of Binary decision variables for configuring circuit breakers at the terminal; Indicates whether it is in the segment of Binary decision variables for configuring automated switches at the terminal; Indicates whether it is in the segment of The binary decision variable for manual switching is configured at the terminal. Represents the set of candidate contact lines; Indicates the decision-making variables for the construction of the connecting line; This indicates the construction cost of a single connecting line; This indicates the effective power shortage in the upstream healthy area after fault isolation; This indicates the delay in reclosing recovery due to upstream fault degradation; This indicates the effective power shortage in the downstream power-loss area after fault isolation; Indicates the downstream fault isolation delay; Indicates the power transfer delay of the interconnection switch; This indicates the load power that cannot be restored to the entire network from the moment the fault occurs until the protection system operates. Indicates the duration of the protective action; This represents the economic penalty coefficient for the unit of expected power shortage. This indicates the average annual failure rate of the line; This indicates the planning cycle of the equipment.

6. The method according to claim 5, characterized in that, The desired net power shortage is explicitly embedded into the objective function to achieve a collaborative solution for switch planning and reliability assessment. The specific process is as follows: include: Among them, the expected net power shortage Represented as: ； Based on the expected net power shortage, the average outage duration index of the system is further calculated. System average power outage frequency index and system average availability index , respectively represented as: ； ； ； in, This indicates the total network load demand under normal operating conditions. This represents the comprehensive calculated average duration of a single power outage under multiple fault scenarios. The , , and As a reliability evaluation index, it directly participates in the calculation of the objective function and scheme selection through the hierarchical transmission relationship between switch configuration, switch action, topology connectivity and load power supply, thereby realizing the collaborative solution of switch planning and reliability assessment.

7. The method according to claim 1, characterized in that, The multi-type switch configuration constraint is: for any line port in the distribution network, the sum of the circuit breaker configuration variable, the automatic switch configuration variable, and the manual switch configuration variable shall not exceed 1, that is, at most one type of switch equipment shall be configured for the same line port; The multi-type switching action constraints include fault degradation stage constraints, fault isolation stage constraints, and power restoration stage constraints. The fault degradation stage constraint is as follows: based on the fault location, the port of the nearest configured circuit breaker upstream of the fault source direction is determined to perform a protection tripping action, and only the port of the configured circuit breaker is allowed to trip and change position; The fault isolation stage constraint is as follows: after the power distribution master station locates the fault branch, the fault branch port that has been configured with a circuit breaker or automatic switch is immediately disconnected, and the fault branch port that has been configured with a manual switch is disconnected after a delay. The power restoration phase is constrained as follows: after the fault isolation is completed, the upstream circuit breaker performs reclosing to restore power supply to the upstream area, the tie switch closes sequentially according to the preset time delay to realize load transfer, and the distributed photovoltaic system in the power failure area that meets the islanding operation conditions is reconnected to the grid to support the local load.

8. The method according to claim 1, characterized in that, The network topology constraints include branch connectivity constraints and radial topology constraints: The branch connection state constraint is as follows: the electrical connection state of a branch is determined by the closed state of the first-end port switch and the closed state of the last-end port switch of the branch. When both the first-end port switch and the last-end port switch are closed, the branch is connected; when either the first-end port switch or the last-end port switch is open, the branch is disconnected. The energized state of a load node is determined by the following conditions: if the node can be traced back to the main grid substation through a connected branch path, or is located in a photovoltaic island area that meets the islanding operation conditions, then the node is energized and power supply is restored; otherwise, the node is de-energized. The radial topology constraint is as follows: in each self-healing recovery stage of each fault scenario, a virtual topology flow mechanism is adopted to ensure that each power supply area maintains a radial open-loop structure. The total amount of virtual topology flow flowing out from the main grid power point or the photovoltaic island master control node is equal to the total number of energized nodes in that stage, and each power supply area has a unique power injection point.

9. The method according to claim 1, characterized in that, The electrical operation constraints include node power balance constraints and node voltage safety constraints; The node power balance constraint is as follows: the sum of the distributed photovoltaic injection power and the substation injection power of each node, minus the load power of that node, equals the sum of the active power and reactive power of the branch connected to that node; wherein, the load power of a power-off node is forcibly set to zero, and the power of a disconnected branch is forcibly set to zero. The node voltage safety constraint is that the voltage amplitude of each energized node must be maintained within the preset upper and lower voltage limits.

10. The method according to claim 1, characterized in that, The optimization solver is invoked to solve the collaborative configuration optimization model, obtaining the multiple switch configuration locations and equipment types that minimize the overall cost, specifically: The objective function and all constraints are combined into a mixed-integer linear programming model; The optimization solver is invoked to solve the mixed integer linear programming model, and the output shows whether a switch is configured at each candidate position and the type of switch configured, thereby obtaining multiple types of switch configuration positions and equipment types that minimize the overall cost.

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