Method and System for Inertia Risk Assessment of Hydropower Regional Power Grid Systems Considering Frequency Safety Boundaries

Abstract

This application relates to the field of power system technology, and more particularly to a method and system for assessing the inertia risk of a hydropower regional power grid system considering frequency safety boundaries. The system inertia safety boundary is characterized under the dual frequency constraints of frequency difference and initial frequency change rate. Frequency exceedance distances are quantified in different constraint directions to obtain a first exceedance distance and a second exceedance distance. The system inertia exceedance risk value is calculated using these first and second exceedance distances to quantify the inertia risk assessment result of the power grid system, thereby constructing a system inertia risk assessment framework to facilitate timely response to the frequency instability risk of power systems with a high proportion of hydropower. The aim is to solve the problem of how to quantify the frequency instability risk in a hybrid power system of hydropower and new energy sources.

Description

Technical Field

[0001] This application relates to the field of power system technology, and in particular to a method and system for assessing the inertia risk of a hydropower regional power grid system considering frequency safety boundaries. Background Technology

[0002] With the increasing penetration of renewable energy in the power system, my country's power grid structure is undergoing a strategic transformation from a traditional synchronous large power grid to a multi-regional asynchronous interconnected structure. Taking the southwest region as an example, its power network has formed a DC-exporting asynchronous interconnected power grid architecture with hydropower as the main power source and new energy sources as a supplement.

[0003] The most common method for assessing the inertia of power systems is the single-frequency-point-constrained inertia assessment system, which is a framework system that uses the goal of ensuring that the rate of change of a single system frequency does not exceed a set safety threshold to back-evaluate the required inertia level of the system.

[0004] However, in the DC-to-electricity asynchronous interconnected power grid architecture, the inherent seasonal output characteristics of hydropower systems and the volatility of new energy sources create a complex coupling effect. Specifically, during the peak hydropower generation period in the flood season and the limited hydropower output during the dry season, the penetration rate of new energy sources and the demand for frequency stability exhibit different contradictions, significantly exacerbating the risk of frequency instability in the entire system. This makes the original inertia assessment system based on single-frequency constraints have obvious limitations—it is difficult to accurately characterize the actual system inertia level, and it is also unable to effectively identify the characteristics of exceeding limits in different frequency constraint directions.

[0005] In view of this, this application aims to propose a power grid system inertia risk assessment method that adapts to the characteristics of a dual-main-export power grid of hydropower and new energy. It aims to construct a system inertia risk assessment system based on the frequency dynamic response mechanism under the synergistic effect of hydropower seasonal characteristics and new energy penetration rate, so as to facilitate timely response to the frequency instability risk of power systems with a high proportion of hydropower. Summary of the Invention

[0006] The main objective of this application is to provide a method for assessing the inertia risk of hydropower regional power grid systems that considers frequency safety boundaries, aiming to solve the problem of how to quantify the frequency instability risk in hybrid power systems of hydropower and new energy sources.

[0007] To achieve the above objectives, this application provides a method for assessing the inertia risk of a hydropower regional power grid system considering frequency safety boundaries. This method is applied to power grid systems including hydropower systems and new energy systems, and includes the following steps:

[0008] S10, obtain the current frequency difference and the initial rate of change of the current frequency after the system is disturbed within a preset time window;

[0009] S20, calculate the first over-limit distance based on the current frequency difference, and calculate the second over-limit distance based on the initial rate of change of the current frequency;

[0010] S30, based on the first over-limit distance and the second over-limit distance, calculate the system inertia over-limit severity index, and calculate the system inertia over-limit risk value according to the system inertia over-limit severity index;

[0011] S40, determine the inertia risk assessment result of the power grid system based on the magnitude of the system inertia over-limit risk value.

[0012] Optionally, in step S20, the calculation expression for the first over-limit distance is:

[0013]

[0014] In the formula, This is the first over-limit distance. The initial rate of change of the current frequency. The initial rate of change of the maximum frequency;

[0015] The expression for calculating the second over-limit distance is:

[0016]

[0017] In the formula, This is the second over-limit distance. The current frequency difference, For the rated frequency, This represents the lowest point of frequency drop.

[0018] Optionally, the initial rate of change of the maximum frequency The calculation expression is:

[0019]

[0020] In the formula, This is due to a power deficit. The inertial time constant, This is the virtual damping coefficient.

[0021] Optionally, the expression for calculating the severity index of system inertia exceeding the limit is:

[0022]

[0023] In the formula, This is an index indicating the severity of system inertia exceeding limits. This is the first over-limit distance. This is the second over-limit distance;

[0024] The formula for calculating the system inertia over-limit risk value is as follows:

[0025]

[0026] In the formula, This is the power disturbance. To represent the safe region of inertia, This is a low-risk area for inertia. This represents a high-risk area for inertia.

[0027] Optionally, S40 includes:

[0028] S41, when the system inertia over-limit risk value is greater than the preset first risk threshold, the inertia risk assessment result is determined to be high risk;

[0029] S42, when the system inertia over-limit risk value is less than the preset second risk threshold, the inertia risk assessment result is determined to be low risk;

[0030] S43, when the system inertia over-limit risk value is greater than the preset second risk threshold and less than the preset first risk threshold, the inertia risk assessment result is determined to be normal;

[0031] Wherein, the preset first risk threshold is greater than the preset second risk threshold.

[0032] Optionally, before step S10, the method further includes:

[0033] S50, with the maximization of the rate of frequency change as a constraint, construct the transfer function of the virtual frequency regulation power of each frequency regulation unit in the power grid system;

[0034] S60, based on the transfer function of each of the virtual frequency modulation powers, determine the time-domain and frequency-domain expressions of the system active power response;

[0035] S70, Based on the established unbalanced power disturbance probability model, determine the active power load of the power grid system.

[0036] Optionally, in step S50, the frequency regulation unit includes a hydroelectric generator, a wind turbine generator, an energy storage system, and a fault current limiter, and the transfer function of the virtual frequency regulation power of each frequency regulation unit includes:

[0037] Transfer function of the system frequency response of a hydroelectric generator :

[0038]

[0039] The transfer function of the output power of a wind turbine after using integrated inertial response control. :

[0040]

[0041] Energy storage systems utilize the transfer function of the power output at the frequency of the additional control response system. :

[0042]

[0043] The transfer function of the power output of the DC current limiter through the reverse deviation recovery fault current limiter. :

[0044]

[0045] In the formula, This represents the virtual inertia control coefficient for wind turbine units. T is the virtual droop control coefficient for wind turbines. w The time constant of the water hammer effect. This is the adjustment coefficient. R1 and R2 are the speed governor time constants and ratio coefficients, respectively. It is a time constant. This is the virtual inertia control coefficient for energy storage. This is the virtual droop control coefficient for energy storage. Indicates the response time of the energy storage system. The virtual inertia coefficient is the DC power modulation value. This is the DC power modulation droop coefficient. This represents the response time of the DC control system, where s is the Laplace coefficient.

[0046] Optionally, in S60, the frequency domain expression of the system's active power response is... for:

[0047]

[0048] The time-domain expression of the system's active power response. for:

[0049]

[0050] In the formula, The distribution coefficients in hydropower units, thermal power units, wind power units, energy storage systems, and DC systems are for sudden, step-type active power disturbances in the system. , , , , These are the transfer functions for hydroelectric power units, thermal power units, wind power units, energy storage systems, and DC systems, respectively, where s is the Laplace coefficient. This is the Laplace transform of the system frequency deviation.

[0051] Optionally, in step S70, the expression for the unbalanced power disturbance probability model includes:

[0052]

[0053]

[0054] In the formula, P L P represents the active load of the entire system when the frequency is equal to f; LN For the frequency equal to the rated value f N The active load of the entire system at that time; a i For a load that is proportional to the i-th power of the frequency in P LN The share of i in the total, i = 0, 1, 2 ∙∙∙n; Let be the probability density function. Let k be a random variable and k be a shape parameter. For rate parameters, This is the Gamma function.

[0055] In addition, to achieve the above objectives, this application also provides a computer system comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the computer program, when executed by the processor, implements the steps of the hydropower regional power grid system inertia risk assessment method considering frequency safety boundaries as described in any of the preceding claims.

[0056] This application has at least the following beneficial effects:

[0057] 1. By analyzing the characteristics of the dual-sending-end power grid of hydropower and new energy sources, which are different from traditional power systems, as well as the mechanism of inertia deficiency, we can address the low inertia risk that is prone to occur in power systems with a high proportion of hydropower.

[0058] 2. By characterizing the system inertia safety boundary under dual frequency constraints and quantifying the frequency over-limit distance in different constraint directions, we can adapt to the different frequency variation patterns of the system during the wet and dry seasons due to the high proportion of hydropower units.

[0059] 3. The system's inertia risk is comprehensively quantified by using the system inertia exceedance severity index and the system inertia exceedance risk value index;

[0060] 4. By quantifying the current inertia over-limit risk in the system, it can promptly reflect whether the frequency control system of the sending-end power grid is insufficient in adaptability to new energy scenarios. Attached Figure Description

[0061] Figure 1This is a schematic diagram illustrating the division of power system inertia risk zones in an embodiment of this application;

[0062] Figure 2 This is a flowchart illustrating the first embodiment of the inertia risk assessment method for hydropower regional power grid systems that considers frequency safety boundaries in this application.

[0063] Figure 3 This is a schematic diagram illustrating the frequency change trend based on the maximum initial rate of change of frequency, as described in an embodiment of this application.

[0064] Figure 4 This is a schematic diagram illustrating the frequency change trend based on the lowest point of frequency drop in an embodiment of this application.

[0065] Figure 5 This is a schematic diagram of the inertia safety boundary based on the maximum initial rate of change of frequency, as described in an embodiment of this application.

[0066] Figure 6 This is a schematic diagram of the frequency security boundary based on the lowest frequency drop point involved in an embodiment of this application.

[0067] Figure 7 This is a diagram illustrating the range of inertia exceedance levels in the embodiments of this application;

[0068] Figure 8 This is a schematic diagram of the probability distribution function of random load disturbances involved in the embodiments of this application;

[0069] Figure 9 This is a schematic diagram illustrating the system inertia risk index under different proportions of new energy sources during the high-water season, as described in the embodiments of this application.

[0070] Figure 10 This is a schematic diagram of the system frequency curves under different proportions of new energy sources during the dry season, as described in the embodiments of this application.

[0071] Figure 11 This is a schematic diagram of the hardware operating environment of the computer system involved in the embodiments of this application;

[0072] The realization of the purpose, functional features and advantages of this application will be further explained in conjunction with the embodiments and with reference to the accompanying drawings. Detailed Implementation

[0073] To better understand the above technical solutions, exemplary embodiments of this disclosure will be described in more detail below with reference to the accompanying drawings. While exemplary embodiments of this disclosure are shown in the drawings, it should be understood that this disclosure can be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of this disclosure to those skilled in the art.

[0074] First Embodiment

[0075] Reference Figure 1 The diagram illustrating the risk range of power system inertia shows that for a power grid with both hydropower and renewable energy as the main sending entities, the system inertia is affected by the seasonal characteristics of hydropower during wet and dry seasons, the penetration rate of renewable energy in the current season, and the power generation plan undertaken by hydropower units. To ensure a safety margin for system inertia during the assessment, the minimum system inertia calculated under system frequency security constraints is used as the standard. Furthermore, when hydropower units constitute a large proportion, it is necessary to discuss the different risks to system inertia posed by system frequency security constraints under different scenarios.

[0076] During the high-water season, according to system inertia calculations, with the increasing proportion of hydropower, the system inertia reserve is sufficient, which can significantly reduce the system frequency change rate when dealing with system power disturbances and DC blocking. However, since hydropower units mainly bear the system's base load during this period, they need to operate at full load, resulting in low primary frequency regulation reserve capacity. After the units spontaneously respond with inertia, they cannot participate in the primary frequency adjustment, thus having a smaller effect on reducing system frequency deviation. Therefore, during the high-water season, the system is more likely to approach the safe limit of frequency deviation, and the constraint on the frequency change rate is relatively safe. During the low-water season, the proportion of hydropower units is small, while the proportion of renewable energy is large, resulting in a lower system rotational inertia. At this time, the frequency change rate after disturbance is more drastic. However, since hydropower units mainly function as frequency regulating power plants during the low-water season, their primary frequency regulation capabilities can be fully utilized.

[0077] Therefore, during the dry season, the system frequency change rate is at high risk of exceeding safety limits, and the system frequency deviation can be effectively reduced by the action of frequency regulation power plants. Specifically, the system frequency change rate constraint under low inertia scenarios and the system frequency deviation constraint under sufficient inertia scenarios are used as the primary constraint. The risk level classification of system inertia is based on whether the system inertia exceeds the limits under these two constraint conditions.

[0078] Based on the above findings, and referring to Figure 2 This embodiment provides a method for assessing the inertia risk of a hydropower regional power grid system considering frequency safety boundaries. This method is applied to power grid systems including hydropower systems and new energy systems. The method includes the following steps:

[0079] Step S10: Obtain the current frequency difference and the initial rate of change of the current frequency after the system is disturbed within a preset time window;

[0080] In this embodiment, in order to quantitatively evaluate the inertia level and frequency stability of the power system under current operating conditions, the frequency response characteristics of the system after disturbance are analyzed from an energy perspective, and the impact of different operating conditions on frequency stability is evaluated.

[0081] The current frequency difference refers to the change between the frequency of the system before the disturbance and the frequency after the disturbance; the initial rate of change of the current frequency refers to the derivative of the change with time.

[0082] In some alternative implementations, the preset time window can be 0.005s.

[0083] Step S20: Calculate the first over-limit distance based on the current frequency difference, and calculate the second over-limit distance based on the initial rate of change of the current frequency;

[0084] In this step, the risk of system inertia exceeding limits is quantified from two dimensions: the current frequency difference and the initial rate of change of the current frequency. The energy response of the disturbed power is converted into an energy limit exceeding scale for the current system under the corresponding frequency constraints. This conversion process helps to assess the risk of system inertia exceeding limits in specific operating states with high rotational inertia in hydropower-dominated systems. The calculated first and second limit exceeding distances are the frequency safety boundaries.

[0085] In this embodiment, the first over-limit distance refers to the over-limit distance under the constraint of the maximum initial rate of change of frequency. The second over-limit distance refers to the lowest point of frequency drop. Over-limit distance under constraints.

[0086] It should be noted that, by Figure 3 and Figure 4 The diagrams showing the frequency change trend based on the initial rate of change of maximum frequency and the frequency change trend based on the lowest point of frequency drop demonstrate that as the penetration rate of new energy sources continues to increase, the system frequency will decrease as a whole after being subjected to large disturbances, and may even exceed the frequency constraint range. However, the frequency exceeding the limit varies under different frequency constraints. Therefore, the frequency stability requirements need to be comprehensively evaluated after discussing each system frequency according to its specific situation.

[0087] Further, see Figure 5 and Figure 6 The diagrams shown illustrate the inertia safety boundary based on the initial rate of change of frequency (ROCF) and the frequency safety boundary based on the minimum frequency drop point. As the power electronic power supply participates in frequency modulation without additional control, the system's equivalent inertia gradually decreases with increasing power electronic penetration. The greater the disturbed power and the higher the penetration, the closer the system inertia is to the frequency safety constraint surface, and the greater the inertia required to maintain stable system operation. Specifically, the minimum inertia is determined by the maximum rate of change of frequency (ROCF). maxUnder constraints, if the system inertia decreases, the system rotational inertia can be increased by increasing the proportion of synchronous machines in operation when the system's renewable energy penetration rate is not high. However, once the power generation plan within the system is fixed, the proportion of synchronous machines cannot be increased further, and the rotational inertia of conventional units alone cannot meet the minimum inertia requirement of the system. The system inertia requirement can also be reduced by utilizing the power supplies of a large number of power electronic converters in the grid to provide fast-response virtual inertia response power.

[0088] Because the system's inertial response and primary frequency modulation are coupled during the system's frequency response phase, there is a situation where inertia and primary frequency modulation work together. Therefore, at the minimum inertia point f, the minimum inertia occurs at the lowest point of the frequency drop. min Under constraints, the system inertia is related not only to the inertial time constant but also to the primary frequency regulation capability. In addition to using power electronic power supplies to simulate the inertia response of the synchronous machine and directly increasing the response power through the primary frequency regulation process to improve the system inertia margin, the risk of low inertia of the system can also be reduced by coordinating inertia with primary frequency regulation, thus satisfying the dynamic constraints of frequency stability.

[0089] Further and optionally, the expression for calculating the first over-limit distance is:

[0090]

[0091] In the formula, This is the first over-limit distance. The initial rate of change of the current frequency. The initial rate of change of the maximum frequency.

[0092] Further, and optionally, the expression for calculating the second over-limit distance is:

[0093]

[0094] In the formula, This is the second over-limit distance. The current frequency difference, For the rated frequency, This represents the lowest point of frequency drop.

[0095] Step S30: Based on the first over-limit distance and the second over-limit distance, calculate the system inertia over-limit severity index, and calculate the system inertia over-limit risk value according to the system inertia over-limit severity index;

[0096] In this step, the frequency difference and initial frequency change rate after the system is disturbed are weighted and the inertia risk is quantified, which is the Inertia Exceedance Severity Index (IESI) defined in this embodiment.

[0097] Further, and optionally, the expression for calculating the severity index of system inertia exceeding the limit is:

[0098]

[0099] In the formula, This is an index indicating the severity of system inertia exceeding limits. This is the first over-limit distance. This is the second over-limit distance.

[0100] In this embodiment, the frequency stability capability of the system after a large disturbance can be roughly assessed based on the value of IESI. If IESI > 0, it indicates that the system inertia is in a relatively safe state, and the larger the value, the more abundant the system inertia, the lower the risk, and the higher the safety margin. If IESI < 0, it means that the system inertia is at risk and may not meet the requirements for stable system operation. The smaller the IESI value, the closer the system inertia is to the critical state, and the higher the risk.

[0101] Furthermore, to facilitate quantification, the risk value of system inertia exceeding the limit is further calculated based on the severity index of system inertia exceeding the limit.

[0102] Further and optionally, the calculation expression for the system inertia over-limit risk value is:

[0103]

[0104] In the formula, This is the power disturbance. To represent the safe region of inertia, This is a low-risk area for inertia. This represents a high-risk area for inertia.

[0105] Step S40: Determine the inertia risk assessment result of the power grid system based on the magnitude of the system inertia over-limit risk value.

[0106] The risk of inertia is determined by the unbalanced power within the system and the severity of the current system inertia. When the unbalanced power of the system is large and the frequency exceeds the limit severely, the risk of the system inertia exceeding the limit is high. When the unbalanced power of the system is small and the frequency exceeds the limit is minor, or when the unbalanced power of the system is large but the system inertia is sufficient, the risk of the inertia exceeding the limit is low.

[0107] Further and optionally, step S40 specifically includes:

[0108] Step S41: When the system inertia over-limit risk value is greater than the preset first risk threshold, the inertia risk assessment result is determined to be high risk.

[0109] Step S42: When the system inertia over-limit risk value is less than the preset second risk threshold, the inertia risk assessment result is determined to be low risk.

[0110] Step S43: When the system inertia over-limit risk value is greater than the preset second risk threshold and less than the preset first risk threshold, the inertia risk assessment result is determined to be normal.

[0111] Wherein, the preset first risk threshold is greater than the preset second risk threshold.

[0112] In some alternative implementations, the first risk threshold is preset to 0.66, and the second risk threshold is preset to 0.33.

[0113] In the technical solution provided in this embodiment, the system inertia safety boundary is characterized under the dual frequency constraints of frequency difference and initial frequency change rate. The frequency over-limit distance is quantified in different constraint directions to obtain the first over-limit distance and the second over-limit distance. The system inertia over-limit risk value is calculated by using the first over-limit distance and the second over-limit distance to quantify the inertia risk assessment result of the power grid system, thereby constructing a system inertia risk assessment system to facilitate timely response to the frequency instability risk of power systems with a high proportion of hydropower.

[0114] Second Embodiment

[0115] Based on the first embodiment, this embodiment provides a system inertia exceedance severity index. The method for conducting system inertia risk assessment is as follows: Figure 7 The diagram shows the range of inertia exceedance levels. Based on the severity index of system inertia exceedance, the system inertia risk is divided into three levels: safe inertia zone, low-risk inertia zone, and high-risk inertia zone. By establishing these three inertia scenario classification standards, the real-time inertia level of the system can be accurately judged, and a timely warning can be issued when the inertia is insufficient, effectively preventing the risk of frequency instability.

[0116] Compared to the first embodiment, based on Further calculations can be made to determine the risk of system inertia exceeding limits, which can also reflect the inertia risk of the power grid system to some extent.

[0117] It is understood that combining the risk assessment based on the system inertia over-limit risk value in the first embodiment with the risk assessment based on the severity index of system inertia over-limit in this embodiment can achieve the same purpose, and will not be elaborated further in this embodiment.

[0118] Third Embodiment

[0119] Based on any embodiment, and based on the frequency dynamic response mechanism under the synergistic effect of hydropower seasonal characteristics and new energy penetration rate, this embodiment also provides a process for establishing the system inertia safety boundary based on dynamic frequency constraints and the process for establishing the unbalanced power disturbance probability model.

[0120] The process of establishing the system inertia safety boundary under dynamic frequency constraints includes the following steps:

[0121] S50, with the maximization of the rate of frequency change as a constraint, construct the transfer function of the virtual frequency regulation power of each frequency regulation unit in the power grid system;

[0122] Further and optionally, the frequency regulation unit includes a hydroelectric generator, a wind turbine generator, an energy storage system, and a fault current limiter. Since the hydroelectric generator speed governor has too many internal delay components, some delay components are appropriately ignored, while retaining the water hammer dynamic characteristics of the hydroelectric generator and the transient descent rate compensation component. The simplified system frequency response transfer function of the hydroelectric generator is:

[0123]

[0124] The power output of the wind turbine after utilizing integrated inertial response control is:

[0125]

[0126] The power output of the energy storage system using the additional control response system frequency is:

[0127]

[0128] The power output of the DC-DC FLC through the reverse bias recovery is:

[0129]

[0130] In the formula, This represents the virtual inertia control coefficient for wind turbine units. T is the virtual droop control coefficient for wind turbines. w The time constant of the water hammer effect. This is the adjustment coefficient. R1 and R2 are the speed governor time constants and ratio coefficients, respectively. It is a time constant. This is the virtual inertia control coefficient for energy storage. This is the virtual droop control coefficient for energy storage. Indicates the response time of the energy storage system. The virtual inertia coefficient is the DC power modulation value. This is the DC power modulation droop coefficient. This represents the response time of the DC control system, where s is the Laplace coefficient.

[0131] Since wind turbines, energy storage systems, and DC FLCs all respond to the system frequency through additional frequency control, their control methods are similar. Therefore, the aforementioned speed controller group can be equivalent to a virtual speed controller of the same type, and the response characteristics of the speed controller group and the equivalent speed controller are kept the same. The virtual inertia and virtual droop response power of the power output of the above three types of power electronic converters are equivalent to:

[0132]

[0133] Among them, the virtual inertia coefficient, virtual droop coefficient, and delay of various power electronic converters after weighted average equivalent are as follows:

[0134]

[0135] After combining the above equations, we obtain the change in the total active power of the power system. for:

[0136]

[0137] After simplification, its frequency response transfer function is:

[0138]

[0139] In addition, under step load disturbance, the initial value theorem is used to calculate the initial rate of change of the system frequency when subjected to disturbance:

[0140]

[0141]

[0142] In the formula, This is due to a power deficit. The inertial time constant, This is the virtual damping coefficient.

[0143] As shown in the above equation, the equivalent inertial time constant of a power system mainly depends on the number of operating generators that can provide inertia, the control method, and their operating states. Compared with traditional power systems, when wind turbines, energy storage devices, and DC transmission systems jointly participate in system frequency regulation, the virtual inertia control loop of the power electronic converter can increase the system denominator value after the system is disturbed, thus providing the corresponding virtual inertia. Therefore, compared with a system having only a single rotational inertia resource, fully leveraging the synergistic frequency modulation potential of multiple resources after the increase in the penetration rate of new energy sources can effectively improve the system's inertia level during the system's inertia response phase.

[0144] S60, based on the transfer function of each of the virtual frequency modulation powers, determine the time-domain and frequency-domain expressions of the system active power response;

[0145] In this step, based on the transfer function of the virtual frequency regulation power, the frequency domain expression and time domain expression of the power system frequency response power can be obtained after calculating the virtual frequency regulation power of each frequency regulation unit.

[0146] Further, and optionally, the frequency domain expression of the system's active power response. for:

[0147]

[0148] Further, and optionally, the time-domain expression of the system's active power response. for:

[0149]

[0150] In the formula, This refers to a sudden step-type active power disturbance occurring in the system. , These are the allocation coefficients for hydropower units, thermal power units, wind power units, energy storage systems, and DC systems, respectively. , , , , These are the transfer functions for hydroelectric power units, thermal power units, wind power units, energy storage systems, and DC systems, respectively. This is the Laplace transform of the system frequency deviation.

[0151] Furthermore, when the power system frequency deviation reaches its extreme value, the system frequency change rate is zero, and the maximum system frequency deviation is:

[0152]

[0153] Exemplary, in some alternative implementations, the following is obtained: Figure 8 The schematic diagram of the probability distribution function of random load disturbances shows that most of the random load disturbances in the system are concentrated around 0.02 pu. As the load disturbance increases, the probability of it occurring in the system gradually decreases.

[0154] On the other hand, the process of establishing the probabilistic model for unbalanced power disturbances includes the following steps:

[0155] S70, Based on the established unbalanced power disturbance probability model, determine the active power load of the power grid system.

[0156] Furthermore, and optionally, in actual operation of the power system, the relationship between the load power and frequency of the entire system can be written as:

[0157]

[0158] In the formula: PL is the active load of the entire system when the frequency is equal to f; P LN Let fN be the active load of the entire system when the frequency equals the rated value fN; ai is the load proportional to the i-th power of the frequency at frequency P. LN The share of i in the total, i = 0, 1, 2 ∙∙∙n.

[0159] Furthermore, and optionally, since the random disturbances of active power in a power system typically involve loads proportional to the first power of the frequency and loads proportional to the square of the frequency, this embodiment uses the Gamma distribution function to simulate the random power disturbances of the system, and its probability density function is:

[0160]

[0161] In the formula, Let k be a random variable and k be a shape parameter. For rate parameters, This is the Gamma function.

[0162] Fourth embodiment

[0163] As a verification embodiment, this embodiment uses simulation to verify the effectiveness of the inertia risk assessment method for hydropower regional power grid systems considering frequency safety boundaries provided in this application:

[0164] (1) Operation mode during the high water season

[0165] Within the study area, the high-water season generally refers to June to October of the same year. During this period, reservoirs within the study area have abundant water inflow, allowing hydropower units to operate at full capacity. Simultaneously, the DC power transmission system operates at full capacity to meet the demand for power transmission from Yunnan, lacking regulation capabilities. The system capacity during the high-water season ranges from 59,000 MW to 68,000 MW, with renewable energy accounting for only about 21% of the total output. Assuming the total power output of all hydropower units and thermal power units in the system is... Jsys =9s, the total damping coefficient of the system D sys =2s. This embodiment selects the Fengda operating mode for verification.

[0166] This embodiment considers a power deficit of 850MW when a single unit trips, i.e., ∆P LWith a frequency of -0.05, as the penetration rate of new energy sources increases during the high-water season, the system frequency gradually decreases when new energy sources lack frequency regulation capabilities. This is especially true after hydropower reaches full capacity, as it lacks primary frequency regulation capabilities. Consequently, the system's quasi-steady-state frequency recovery capability is weak after being subjected to unbalanced power disturbances. Furthermore, as the number of hydropower units decreases, the system inertia decreases, and the frequency RoCoF... max The index gradually decreased from -3.05Hz / s to -3.66Hz / s, while the frequency f... min The index gradually decreased from 49.242Hz to 49.227Hz, and the system frequency gradually approached the constraint boundary, indicating a high risk of exceeding the frequency deviation limit.

[0167] Table 1 System Inertia Level under High-Water Season Operation Mode

[0168]

[0169] As shown in Table 1, under the high-water season operation mode, thermal power units account for 10% of the total capacity in the system, with the remaining output coming from hydropower units and new energy power plants. At this time, due to the high proportion of hydropower units, the system inertia is sufficient, and the frequency RoCoF, which directly reflects the system inertia level after disturbance, is significant. max The indicators are within a safe range. Specifically, considering the lowest inertia value quantized based on different system frequencies, based on frequency f... min Minimum inertia requirement E under the indicator i,fmin The decrease was quite significant, dropping by 171,742.5 MWs from a 10% to 25% increase in new energy penetration.

[0170] Table 2 System inertia risk indicators under high-water season operation mode

[0171]

[0172] As shown in Table 2, the method proposed in this embodiment can evaluate the system's frequency exceedance distance under different frequency constraint directions, making it easier to observe the exceedance risk of the system in different constraint directions. Furthermore, it utilizes IESI and R... Hi A comprehensive assessment of the system's low inertia risk is possible at this point. The data in the table shows that as the penetration rate of new energy sources increases, the frequency exceedance distances d1 and d2 gradually approach 0, while IESI gradually approaches the low-risk inertia zone of single-frequency exceedance, with the approach trend as follows: Figure 9 The diagram shows the system inertia risk index under different proportions of new energy sources during the high-water season.

[0173] (2) Operation mode during dry season

[0174] The dry season in the study area generally refers to November to May of the following year. During the dry season, the system capacity ranges from 17,500 MW to 46,000 MW. During this time, reservoir inflow decreases, and the capacity of hydropower units accounts for less than 35%. In severe cases, the hydropower generation share can even drop to 20%. If renewable energy output is not restricted, the renewable energy output share can even reach over 70%. At this time, the high proportion of renewable energy output leads to a significant decrease in system inertia. Based on the power grid structure and load characteristics of the study area, the most significant impact of renewable energy output on the system occurs during the dry season. In actual operation, during the dry season, the Chu-Sui, Xin-Dong, and Lu-Xi DC lines have FLC (Frequency Controlled Regulator) down-regulation capabilities, with a down-regulation capacity of 600 MW. The remaining DC lines are either shut down or operate at minimum power, with no FLC down-regulation capacity. The FLC up-regulation capacity is relatively sufficient, reaching 3,500 MW. Due to the large DC transmission power and high renewable energy share, DC bipolar blocking faults have a more severe impact on the system frequency. Therefore, in this embodiment, the maximum single DC bipolar blocking uncontrolled generator is considered under the condition of power surplus, with a power surplus of 800MW.

[0175] Assuming the system capacity is 17500MW under the low-water-season mode, by Figure 10 The diagram showing the system frequency curves under different renewable energy ratios during the dry season reveals that, during the dry season, as the proportion of renewable energy in the system gradually increases from 55% to 70%, the proportion of hydropower units gradually decreases, leading to a reduction in the rotational kinetic energy provided by inertia. The system's lowest point drops from 49.214Hz to 49.191Hz, and the maximum rate of change of the system decreases significantly, from -0.614 to -0.920, severely exceeding the frequency change rate boundary RoCoF. max =-0.5Hz / s, the system frequency change rate exceeds the stability constraint, and the system has a high risk of low inertia.

[0176] Table 3. System inertia level under dry season operation mode

[0177]

[0178] Table 3 shows that under the low-water-season operation mode, the system capacity is 17500MW, with thermal power units accounting for 10% of the system capacity, and the remaining output coming from hydropower units and new energy power plants. Due to the reduced water inflow, the proportion of hydropower units in operation decreases, and the overall system inertia level decreases compared to the high-water-season. After disturbance, the frequency RoCoF... max The indicator exceeded the constraint boundary of -0.5Hz / s when the penetration rate of new energy sources reached 55%. Based on the calculation results, considering the lowest quantized inertia value under different system frequency indicators, based on frequency f... min Minimum inertia requirement E under the indicator i,fminThe decrease was quite significant, dropping by 14,667.14 MWs from a new energy penetration rate of 55% to 70%.

[0179] Table 4. System inertia risk indicators under dry season operation mode

[0180]

[0181] As shown in Table 4, when the system is in the dry season, based on the frequency RoCoF max The frequency over-limit distance d1 in the constraint direction decreases rapidly, causing a single frequency constraint over-limit even when the new energy penetration rate reaches 55%; while based on frequency f min Because the hydropower unit retains a certain primary frequency regulation capability, the quasi-steady-state frequency of the system is always positive. However, with the increase of new energy sources, the safety margin of d2 gradually approaches the limit boundary.

[0182] As one implementation scheme, Figure 11 This is a schematic diagram of the hardware operating environment of the computer system involved in the embodiments of this application.

[0183] like Figure 11 As shown, the computer system may include: a processor 1001, such as a CPU; a memory 1005; a user interface 1003; a network interface 1004; and a communication bus 1002. The communication bus 1002 is used to enable communication between these components. The user interface 1003 may include a display screen and an input unit such as a keyboard; the user interface 1003 may also include standard wired and wireless interfaces. The network interface 1004 may include standard wired and wireless interfaces (such as a Wi-Fi interface). The memory 1005 may be high-speed RAM or non-volatile memory, such as disk storage. Optionally, the memory 1005 may also be a storage device independent of the aforementioned processor 1001.

[0184] Those skilled in the art will understand that Figure 11 The computer system architecture shown does not constitute a limitation on the computer system and may include more or fewer components than shown, or combine certain components, or have different component arrangements.

[0185] like Figure 11 As shown, the memory 1005, as a storage medium, may include an operating system, a network communication module, a user interface module, and computer programs. The operating system is a program that manages and controls the hardware and software resources of the computer system, as well as the operation of the computer programs and other software or programs.

[0186] exist Figure 11 In the computer system shown, the user interface 1003 is mainly used to connect to the terminal and communicate data with the terminal; the network interface 1004 is mainly used to communicate data with the backend server; and the processor 1001 can be used to call the computer program stored in the memory 1005.

[0187] In this embodiment, the computer system includes: a memory 1005, a processor 1001, and a computer program stored in the memory and executable on the processor, wherein:

[0188] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0189] S10, obtain the current frequency difference and the initial rate of change of the current frequency after the system is disturbed within a preset time window;

[0190] S20, calculate the first over-limit distance based on the current frequency difference, and calculate the second over-limit distance based on the initial rate of change of the current frequency;

[0191] S30, based on the first over-limit distance and the second over-limit distance, calculate the system inertia over-limit severity index, and calculate the system inertia over-limit risk value according to the system inertia over-limit severity index;

[0192] S40, determine the inertia risk assessment result of the power grid system based on the magnitude of the system inertia over-limit risk value.

[0193] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0194] In step S20, the calculation expression for the first over-limit distance is:

[0195]

[0196] In the formula, This is the first over-limit distance. The initial rate of change of the current frequency. The initial rate of change of the maximum frequency;

[0197] The expression for calculating the second over-limit distance is:

[0198]

[0199] In the formula, This is the second over-limit distance. The current frequency difference, For the rated frequency, This represents the lowest point of frequency drop.

[0200] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0201] Maximum initial rate of change of frequency The calculation expression is:

[0202]

[0203] In the formula, This is due to a power deficit. The inertial time constant, This is the virtual damping coefficient.

[0204] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0205] The formula for calculating the severity index of system inertia exceeding limits is as follows:

[0206]

[0207] In the formula, This is an index indicating the severity of system inertia exceeding limits. This is the first over-limit distance. This is the second over-limit distance;

[0208] The formula for calculating the system inertia over-limit risk value is as follows:

[0209]

[0210] In the formula, This is the power disturbance. To represent the safe region of inertia, This is a low-risk area for inertia. This represents a high-risk area for inertia.

[0211] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0212] S41, when the system inertia over-limit risk value is greater than the preset first risk threshold, the inertia risk assessment result is determined to be high risk;

[0213] S42, when the system inertia over-limit risk value is less than the preset second risk threshold, the inertia risk assessment result is determined to be low risk;

[0214] S43, when the system inertia over-limit risk value is greater than the preset second risk threshold and less than the preset first risk threshold, the inertia risk assessment result is determined to be normal;

[0215] Wherein, the preset first risk threshold is greater than the preset second risk threshold.

[0216] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0217] S50, with the maximization of the rate of frequency change as a constraint, construct the transfer function of the virtual frequency regulation power of each frequency regulation unit in the power grid system;

[0218] S60, based on the transfer function of each of the virtual frequency modulation powers, determine the time-domain and frequency-domain expressions of the system active power response;

[0219] S70, Based on the established unbalanced power disturbance probability model, determine the active power load of the power grid system.

[0220] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0221] Transfer function of the system frequency response of a hydroelectric generator :

[0222]

[0223] The transfer function of the output power of a wind turbine after using integrated inertial response control. :

[0224]

[0225] Energy storage systems utilize the transfer function of the power output at the frequency of the additional control response system. :

[0226]

[0227] The transfer function of the power output of the DC current limiter through the reverse deviation recovery fault current limiter. :

[0228]

[0229] In the formula, This represents the virtual inertia control coefficient for wind turbine units. T is the virtual droop control coefficient for wind turbines. w The time constant of the water hammer effect. This is the adjustment coefficient. R1 and R2 are the speed governor time constants and ratio coefficients, respectively. It is a time constant. This is the virtual inertia control coefficient for energy storage. This is the virtual droop control coefficient for energy storage. Indicates the response time of the energy storage system. The virtual inertia coefficient is the DC power modulation value. This is the DC power modulation droop coefficient. This represents the response time of the DC control system, where s is the Laplace coefficient.

[0230] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0231] The frequency domain expression of the system's active power response. for:

[0232]

[0233] The time-domain expression of the system's active power response. for:

[0234]

[0235] In the formula, The distribution coefficients in hydropower units, thermal power units, wind power units, energy storage systems, and DC systems are for sudden, step-type active power disturbances in the system. , , , , These are the transfer functions for hydroelectric power units, thermal power units, wind power units, energy storage systems, and DC systems, respectively, where s is the Laplace coefficient. This is the Laplace transform of the system frequency deviation.

[0236] When processor 1001 calls a computer program stored in memory 1005, it performs the following operations:

[0237] The expression for the unbalanced power disturbance probability model includes:

[0238]

[0239]

[0240] In the formula, P L P represents the active load of the entire system when the frequency is equal to f; LN For the frequency equal to the rated value f N The active load of the entire system at that time; a i For a load that is proportional to the i-th power of the frequency in P LN The share of i in the total, i = 0, 1, 2 ∙∙∙n; Let be the probability density function. Let k be a random variable and k be a shape parameter. For rate parameters, This is the Gamma function.

[0241] Furthermore, those skilled in the art will understand that all or part of the processes in the methods of the above embodiments can be implemented by a computer program instructing related hardware. The computer program includes program instructions and can be stored in a storage medium, which is a computer-readable storage medium. The program instructions are executed by at least one processor in a computer system to implement the process steps of the embodiments of the above methods.

[0242] Therefore, this application also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the various steps of the inertia risk assessment method for hydropower regional power grid systems considering frequency safety boundaries as described in the above embodiments.

[0243] The computer-readable storage medium can be any computer-readable storage medium capable of storing program code, such as a USB flash drive, portable hard drive, read-only memory (ROM), magnetic disk, or optical disk.

[0244] It should be noted that, since the storage medium provided in the embodiments of this application is the storage medium used to implement the methods of the embodiments of this application, those skilled in the art can understand the specific structure and variations of the storage medium based on the methods described in the embodiments of this application, and therefore will not be repeated here. All storage media used in the methods of the embodiments of this application fall within the scope of protection of this application.

[0245] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0246] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0247] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0248] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0249] Obviously, those skilled in the art can make various modifications and variations to this application without departing from the spirit and scope of this application. Therefore, if such modifications and variations fall within the scope of this application and its equivalents, this application also intends to include such modifications and variations.

Claims

1. A method for assessing the inertia risk of a hydropower regional power grid system considering frequency safety boundaries, characterized in that, Applied to power grid systems including hydropower systems and new energy systems, the method includes the following steps: S10, obtain the current frequency difference and the initial rate of change of the current frequency after the system is disturbed within a preset time window; S20, calculate the first over-limit distance based on the current frequency difference, and calculate the second over-limit distance based on the initial rate of change of the current frequency; S30, based on the first over-limit distance and the second over-limit distance, calculate the system inertia over-limit severity index, and calculate the system inertia over-limit risk value according to the system inertia over-limit severity index; S40, Determine the inertia risk assessment result of the power grid system based on the magnitude of the system inertia over-limit risk value; In step S20, the calculation expression for the first over-limit distance is: ； In the formula, This is the first over-limit distance. The initial rate of change of the current frequency. The initial rate of change of the maximum frequency; The expression for calculating the second over-limit distance is: ； In the formula, This is the second over-limit distance. For the current frequency difference, For the rated frequency, This represents the lowest point of frequency drop; Maximum initial rate of change of frequency The calculation expression is: ； In the formula, This is due to a power deficit. The inertial time constant, This is the virtual damping coefficient; The formula for calculating the severity index of system inertia exceeding limits is as follows: ； In the formula, This is an index indicating the severity of system inertia exceeding limits. This is the first over-limit distance. This is the second over-limit distance; The formula for calculating the system inertia over-limit risk value is as follows: ； In the formula, This is the power disturbance. To represent the safe region of inertia, This is a low-risk area for inertia. This represents a high-risk area for inertia.

2. The method as described in claim 1, characterized in that, S40 includes: S41, when the system inertia over-limit risk value is greater than the preset first risk threshold, the inertia risk assessment result is determined to be high risk; S42, when the system inertia over-limit risk value is less than the preset second risk threshold, the inertia risk assessment result is determined to be low risk; S43, when the system inertia over-limit risk value is greater than the preset second risk threshold and less than the preset first risk threshold, the inertia risk assessment result is determined to be normal; Wherein, the preset first risk threshold is greater than the preset second risk threshold.

3. The method as described in claim 1, characterized in that, Before S10, the following are also included: S50, with the maximization of the rate of frequency change as a constraint, construct the transfer function of the virtual frequency regulation power of each frequency regulation unit in the power grid system; S60, based on the transfer function of each of the virtual frequency modulation powers, determine the time-domain and frequency-domain expressions of the system active power response; S70, Based on the established unbalanced power disturbance probability model, determine the active power load of the power grid system.

4. The method as described in claim 3, characterized in that, In step S50, the frequency regulation unit includes a hydroelectric generator, a wind turbine generator, an energy storage system, and a fault current limiter. The transfer function of the virtual frequency regulation power of each frequency regulation unit includes: Transfer function of the system frequency response of a hydroelectric generator : ； The transfer function of the output power of a wind turbine after using integrated inertial response control. : ； Energy storage systems utilize the transfer function of the power output at the frequency of the additional control response system. : ； The transfer function of the power output of the DC current limiter through the reverse deviation recovery fault current limiter. : ； In the formula, This represents the virtual inertia control coefficient for wind turbine units. T is the virtual droop control coefficient for wind turbines. w The time constant of the water hammer effect. This is the adjustment coefficient. R1 and R2 are the speed governor time constants and ratio coefficients, respectively. It is a time constant. This is the virtual inertia control coefficient for energy storage. This is the virtual droop control coefficient for energy storage. Indicates the response time of the energy storage system. The virtual inertia coefficient is the DC power modulation value. This is the DC power modulation droop coefficient. This represents the response time of the DC control system, where s is the Laplace coefficient.

5. The method as described in claim 3, characterized in that, In S60, the frequency domain expression of the system's active power response is... for: ； The time-domain expression of the system's active power response. for: ； In the formula, This refers to a sudden step-type active power disturbance occurring in the system. These are the allocation coefficients for hydropower units, thermal power units, wind power units, energy storage systems, and DC systems, respectively. , , , , These are the transfer functions for hydroelectric power units, thermal power units, wind power units, energy storage systems, and DC systems, respectively, where s is the Laplace coefficient. This is the Laplace transform of the system frequency deviation.

6. The method as described in claim 3, characterized in that, In step S70, the expression for the unbalanced power disturbance probability model includes: ； ； In the formula, P L P represents the active load of the entire system when the frequency is equal to f; LN For the frequency equal to the rated value f N The active load of the entire system at that time; a i For a load that is proportional to the i-th power of the frequency in P LN The share of i in the total, i = 0, 1, 2 ∙∙∙n; Let be the probability density function. Let k be a random variable and k be a shape parameter. For rate parameters, This is the Gamma function.

7. A computer system, characterized in that, The computer system includes: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein when the computer program is executed by the processor, it implements the steps of the method for assessing the inertia risk of a hydropower regional power grid system considering frequency safety boundaries as described in any one of claims 1 to 6.

Images