A method for evaluating an inertia level of a power system

Abstract

The present application relates to a kind of power system inertia level evaluation method, belong to power system inertia quantitative evaluation field, first according to the relationship between system inertia and the maximum frequency deviation after being disturbed, establish frequency stability constraint, then in limit contingency, construct the power system inertia security domain evaluation model considering inertia level and frequency stability constraint, solve power system inertia security domain evaluation model, determine the inertia security domain of new energy power system in each period, finally according to current system total inertia and the inertia security domain of corresponding period at current time, using the characteristic index of distinguishing system inertia level, assess the current inertia level of new energy power system.The power system inertia security domain evaluation model of the present application considers inertia level and frequency stability constraint, improves the accuracy of evaluating inertia level.

Description

Technical Field

[0001] This invention relates to the field of power system inertia quantification assessment, and in particular to a method for assessing the inertia level of a power system. Background Technology

[0002] In recent years, with the depletion of fossil fuel reserves and the intensification of environmental problems caused by carbon emissions, the development and utilization of renewable energy have progressed rapidly. To address the volatility and randomness of new energy power generation and improve power control, most new energy generating units are connected to the grid via power electronic devices. This results in a decoupling of new energy generating units from the system compared to synchronous generators, making it impossible to provide inertial support for the system and hindering the system's frequency response to disturbances. In recent years, numerous power outages have occurred due to insufficient inertial support. Therefore, the quantitative assessment of the inertia of new energy power systems has become a current research hotspot.

[0003] Research has been conducted on the quantitative assessment of power system inertia, mainly including online assessment of equivalent inertia and calculation of minimum inertia quantization. Online assessment of equivalent inertia primarily utilizes data analysis of the system's time-domain response measured by a phasor measurement unit (PMU) after disturbances, evaluating the system's equivalent inertia through measured power and frequency signals. Minimum inertia quantization, to prevent the deterioration of frequency indicators during disturbances and triggering of protection devices, typically uses the rate of change of frequency (RoCoF) during the inertial response phase and the minimum frequency point of primary frequency regulation as key frequency stability indicators for quantification. Regarding the RoCoF constraint, since primary frequency regulation control is not yet involved during the dynamic frequency inertial response phase, existing research has used swing equations to prove that RoCoF and system inertia have a linear coupling relationship. However, the minimum frequency point constraint exhibits a significant nonlinear relationship with system inertia due to the influence of various frequency regulation processes. Current research uses time-domain simulations to obtain the critical system inertia value at which the minimum frequency point after a disturbance just reaches the activation value of the frequency protection device. This time-domain model is complex and relies heavily on extensive simulation calculations. On the other hand, evaluating only the minimum inertia of the system cannot provide scheduling and operation personnel with a clear reference for the inertia level, making it difficult to effectively assess the current inertia level of the system.

[0004] In summary, a power system inertia safety domain assessment model that takes into account inertia level and frequency stability constraints is needed, and the current inertia level of the system should be assessed by extracting indicators that characterize the inertia level. Summary of the Invention

[0005] The purpose of this invention is to provide a method for assessing the inertia level of a power system, so as to improve the accuracy of inertia level assessment.

[0006] To achieve the above objectives, the present invention provides the following solution:

[0007] A method for assessing the inertia level of a power system, the method comprising:

[0008] A dynamic frequency response model for the power system is established by comprehensively considering inertia response, primary frequency regulation, and load frequency response. Based on the dynamic frequency response model of the power system, the relationship between system inertia and the maximum frequency deviation of the system after disturbance is determined.

[0009] Frequency stability constraints are established based on the relationship between system inertia and the maximum frequency deviation of the system after disturbance.

[0010] Under extreme anticipated fault conditions, a power system inertia safety domain evaluation model is constructed that takes into account the inertia level and the frequency stability constraint.

[0011] Based on the anticipated fault scenarios set for each time period, the inertia safety domain assessment model of the power system is solved to determine the inertia safety domain of the power system in each time period; the inertia safety domain is the range of inertia safety defined by the total available inertia of the system as the upper bound and the inertia safety critical value as the lower bound.

[0012] Calculate the current total inertia of the new energy power system based on the current operating status of the power system;

[0013] Based on the current total system inertia and the inertia safety domain corresponding to the current time period, the current inertia level of the new energy power system is assessed using characteristic indicators for judging the system inertia level.

[0014] Optionally, the step of establishing a power system frequency dynamic response model by comprehensively considering inertia response, primary frequency regulation, and load frequency response, and determining the relationship between system inertia and the maximum frequency deviation of the system after disturbance based on the power system frequency dynamic response model, specifically includes:

[0015] Inertia response model, load frequency response model, primary frequency regulation response model and secondary frequency regulation model are constructed respectively;

[0016] Taking into account the inertia response model, load frequency response model, primary frequency regulation response model and secondary frequency regulation model, the dynamic frequency response model of the power system is determined.

[0017] Based on the power system frequency dynamic response model, establish dynamic curves of system frequency response for different values ​​of system inertia.

[0018] Based on the dynamic curves of the system frequency response when the system inertia takes different values, the relationship analysis results between the system inertia and the maximum frequency deviation of the system after disturbance are obtained; the relationship analysis results show that the system inertia and the maximum frequency deviation of the system after disturbance have a nonlinear relationship.

[0019] Optionally, the step of obtaining the relationship analysis results between the system inertia and the maximum frequency deviation of the system after disturbance based on the dynamic curves of the system frequency response at different values ​​of system inertia further includes:

[0020] Construct the fitness function as Fitness = (Δf i max -Δf lim ) 2 Where Fitness is the fitness function, Δf i max Δf represents the maximum frequency deviation corresponding to particle i. lim This is the frequency deviation limit;

[0021] Based on the preset frequency deviation limit, the dynamic frequency response model of the power system is solved using the fitness function and the particle swarm optimization algorithm to obtain the optimal system inertia critical value corresponding to the preset frequency deviation limit.

[0022] Optionally, the inertia response model is

[0023]

[0024]

[0025] Where H is the system inertia, Δf(t) is the frequency deviation, D is the generator damping coefficient, and ΔP is the system inertia. e (t) represents the change in electromagnetic power, ΔP m (t) represents the change in the output mechanical power of the prime mover, ΔP L (t) represents the change in active power of the load, H sys Let N be the total inertia of the current system. SG N RG These represent the total number of conventional generating units and new energy generating units in the system, respectively; H i P i max x i The inertial constant, rated power, and operating state of synchronous generator set i are respectively, H′ j , x j These represent the virtual inertia constant, rated power, and operating status of the new energy generator set j, respectively.

[0026] The load frequency response model is as follows:

[0027]

[0028] Among them, P L (t) represents the load frequency response during time period t, P LN λ is the active power of the load at the rated frequency. i For the load active power that is proportional to the i-th power of the frequency in P LN The share of ∑λ i =1; fn is the system's rated frequency, and f(t) is the frequency during time period t;

[0029] The primary frequency modulation response model is as follows:

[0030]

[0031]

[0032] Among them, T n R is the governor time constant, R is the generator droop coefficient, and ΔP is the generator droop coefficient. V (t) represents the change in turbine valve opening, T CH Let ΔP be the steam volume time constant of the steam turbine. m (t) represents the change in mechanical power during time period t;

[0033] The secondary frequency modulation model is as follows:

[0034] ΔP ref (t)=K∫Δf(t)dt

[0035] Where, ΔP ref (t) represents the change in secondary frequency regulation power in the power system, and K is the secondary frequency regulation effect coefficient.

[0036] Optionally, the determination of the power system frequency dynamic response model by comprehensively considering the inertia response model, load frequency response model, primary frequency regulation response model, and secondary frequency regulation model specifically includes:

[0037] The electromagnetic power change ΔP in the inertial response model e (t) is equivalent to the total power deficit ΔP of the power system at the start of the disturbance, and the change in active power of the load ΔP in the inertial response model is also considered. L (t) and the change in active power of the load obtained according to the load frequency response model ΔP L The simplified inertial response model and load frequency response model are obtained by merging (t) into DΔf(t).

[0038] Ignore the first-order inertial delay module of the governor valve opening command in the primary frequency regulation response model. The simplified first-order frequency modulation response model is obtained as follows

[0039] The simplified power variation ΔP of the power system in the secondary frequency regulation model ref (t) is 0;

[0040] By combining the simplified inertia response model, the load frequency response model, and the simplified primary frequency regulation response model, the dynamic frequency response model of the power system is determined as follows:

[0041] Optionally, the step of establishing frequency stability constraints based on the relationship between system inertia and the maximum frequency deviation of the system after disturbance specifically includes:

[0042] Constructing frequency stability constraints includes frequency rate of change constraints and frequency extremum constraints;

[0043] Establish the initial frequency change rate constraint as RoCoF min ≤RoCoF ext ≤RoCoF max Among them, RoCoF min RoCoF max These are the upper and lower limits of RoCoF, respectively. ext This is the vector of extreme values ​​of the rate of change of the system's frequency after the occurrence of the most severe potential fault.

[0044] Based on the relationship between system inertia and the maximum frequency deviation of the system after disturbance, the initial frequency change rate constraint is transformed into the first system inertia constraint: Among them, H′ sys H′ represents the system inertia after the fault occurs. sys =H SIL -H loss H SIL H is the critical value for inertia safety. loss For the system's loss of inertia, f N ΔP is the system's rated frequency. MAX The active power disturbance caused by the extreme anticipated fault. For the critical N-2 fault set, RoCoF lim These are the upper and lower limits of the rate of change of frequency;

[0045] Establish the initial frequency extremum constraint as f min ≤f ext ≤f max ; where f min f max These are the upper and lower limits of frequency stability, respectively, f ext This represents the transient frequency extremum vector of the system after the most severe potential fault occurs.

[0046] Based on the relationship between system inertia and the maximum frequency deviation of the system after disturbance, the initial frequency extremum constraint is transformed into a second system inertia constraint: Among them, t sf The preset time delay R is set for the stability control adjustment measures triggered by a certain anticipated extreme fault. sys P is the primary frequency modulation rate of the system. sf The regulating power for the stability control measures triggered by a certain anticipated fault, where D is the generator damping coefficient, and f is the regulating power. m This represents the frequency stability limit.

[0047] Optionally, the power system inertia security domain assessment model includes: a power system inertia security domain assessment model when new energy units adopt conventional control and a power system inertia security domain assessment model when new energy units adopt virtual synchronous machine control;

[0048] The new energy generating unit adopts the power system inertia safety domain evaluation model under conventional control.

[0049]

[0050]

[0051] The constraints include:

[0052] Inertia horizontal constraint: H min ≤H SIL ≤H max

[0053] First system inertia constraint:

[0054] Second system inertia constraint:

[0055] Wherein: H MIL (t) represents the total available inertia of the new energy unit when conventional control is used during time period t, H. i P i max x i The inertial constant, rated power, and operating state of synchronous generator set i are respectively, N. SG H represents the total number of conventional units in the system. SIL (t) represents the inertia safety threshold value of the new energy unit when using conventional control during time period t, H. min H max These are the upper and lower limits of the system inertia, respectively.

[0056] The power system inertia safety domain assessment model for the new energy generating units using virtual synchronous machine control is as follows:

[0057]

[0058]

[0059] The constraints include:

[0060] Inertia horizontal constraint: H min ≤H SIL ≤H max

[0061] First system inertia constraint:

[0062] Second system inertia constraint:

[0063]

[0064] Where: H' MIL (t) represents the total available inertia of the new energy generating unit when virtual synchronous machine control is used during time period t, H' SIL (t) represents the inertia safety threshold value of the new energy unit when using virtual synchronous machine control during time period t, H′ j , x j These represent the virtual inertia constant, rated power, and operating status of the new energy generator set j, respectively.

[0065] Optionally, calculating the current total system inertia of the new energy power system based on the current operating state of the power system specifically includes:

[0066] When new energy generating units adopt conventional control, the formula is used based on the current operating status of the power system. Calculate the current total inertia of the new energy power system;

[0067] When new energy generating units adopt virtual synchronous machine control, the formula is used based on the current operating state of the power system. Calculate the current total inertia of the new energy power system;

[0068] Among them, H sys Let N be the total inertia of the current system. SG N RG These represent the total number of conventional generating units and new energy generating units in the system, respectively; H i P i max x i The inertial constant, rated power, and operating state of synchronous generator set i are respectively, H′ j , x j These represent the virtual inertia constant, rated power, and operating status of the new energy generator set j, respectively.

[0069] Optionally, the step of assessing the current inertia level of the new energy power system based on the current total system inertia and the inertia safety domain corresponding to the current time period, using characteristic indicators for judging the system inertia level, specifically includes:

[0070] Based on the current total system inertia and the upper bound of the inertia safety domain corresponding to the current time period, the formula is used... Calculate the inertia reserve factor C1;

[0071] Based on the current total system inertia and the lower bound of the inertia safety domain for the corresponding time period, the formula is used. Calculate the inertia safety margin C2;

[0072] The intersection of the inertia reserve coefficient and the inertia safety margin is determined in the two-dimensional index evaluation indicator diagram of inertia level, and the safety margin level corresponding to the intersection point is taken as the current inertia level of the new energy power system; the horizontal axis of the two-dimensional index evaluation indicator diagram of inertia level is the inertia safety margin, and the vertical axis is the inertia reserve coefficient.

[0073] Optionally, the evaluation method further includes:

[0074] The inertia safety domain of the new energy power unit was compared with that of the new energy power unit using virtual synchronous machine control and conventional control, and the comparison results were obtained. The comparison results include: the upper boundary of the inertia safety domain of the new energy power unit shifts upward and the lower boundary shifts downward after adopting virtual synchronous machine control.

[0075] According to specific embodiments provided by the present invention, the present invention discloses the following technical effects:

[0076] This invention discloses a method for assessing the inertia level of a power system. First, based on the relationship between system inertia and the maximum frequency deviation after a disturbance, a frequency stability constraint is established. Then, under extreme anticipated fault conditions, a power system inertia safety domain assessment model considering both inertia level and frequency stability constraints is constructed. Solving the power system inertia safety domain assessment model determines the inertia safety domain of the new energy power system for each time period. Finally, based on the current total system inertia and the inertia safety domain corresponding to the current time period, the current inertia level of the new energy power system is assessed using characteristic indicators that discriminate the system inertia level. The power system inertia safety domain assessment model of this invention, considering both inertia level and frequency stability constraints, improves the accuracy of inertia level assessment. Attached Figure Description

[0077] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0078] Figure 1 A flowchart of a method for assessing the inertia level of a power system provided in an embodiment of the present invention;

[0079] Figure 2 A schematic diagram of a power system inertia level assessment method provided in an embodiment of the present invention;

[0080] Figure 3 A schematic diagram illustrating the power response and energy conversion during a disturbance process, provided in an embodiment of the present invention;

[0081] Figure 4 This is a schematic diagram illustrating the influence of inertia on the dynamic process of system frequency response provided in an embodiment of the present invention.

[0082] Figure 5 A schematic diagram of the particle swarm optimization algorithm provided in an embodiment of the present invention;

[0083] Figure 6 A two-dimensional index evaluation indicator diagram for inertia level provided in an embodiment of the present invention;

[0084] Figure 7 This is a schematic diagram of the network topology of an IEEE 39-node system provided in an embodiment of the present invention;

[0085] Figure 8 A schematic diagram of the critical value for inertia safety of the IEEE 39-node system provided in an embodiment of the present invention;

[0086] Figure 9 A schematic diagram of the inertia safety domain of the IEEE 39-node system provided in an embodiment of the present invention;

[0087] Figure 10 This is a comparison diagram of the lower bound of the inertia safety domain between the original system and the system containing wind turbines, provided in an embodiment of the present invention. Detailed Implementation

[0088] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0089] The purpose of this invention is to provide a method for assessing the inertia level of a power system, so as to improve the accuracy of inertia level assessment.

[0090] To make the above-mentioned objects, features and advantages of the present invention more apparent and understandable, the present invention will be further described in detail below with reference to the accompanying drawings and specific embodiments.

[0091] This invention provides a method for assessing the inertia level of a power system, such as... Figure 1 and Figure 2 As shown, the evaluation method includes the following steps:

[0092] Step S1: Establish a dynamic frequency response model for the power system by comprehensively considering inertia response, primary frequency regulation, and load frequency response, and determine the relationship between system inertia and the maximum frequency deviation of the system after disturbance based on the dynamic frequency response model for the power system.

[0093] The equivalent inertia of the power system is obtained by weighted summation of the mechanical rotational inertia provided by the synchronous generator in the system and the virtual inertia provided by the new energy unit controlled by the virtual synchronous generator. A mathematical model of the system frequency dynamic response is established by comprehensively considering the inertia response, primary frequency regulation and load frequency response, and the influence of the equivalent inertia of the system on the frequency response process is qualitatively analyzed. Based on the mathematical model of the system frequency dynamic response, the critical value of the system inertia under the frequency deviation constraint is solved by PSO (Particle Swarm Optimization).

[0094] The equivalent inertia of a new energy power system needs to take into account all components within the system that provide inertia, including synchronous generators and new energy generating units controlled using virtual synchronous machine technology, i.e.:

[0095]

[0096] In the formula: H sys N represents the current total inertia of the system. SG N RG H represents the total number of conventional generating units and new energy generating units (including photovoltaic generators and wind turbine generators) in the system; i P i max x i These represent the inertia constant, rated power, and operating status of the synchronous generator set (1 for startup, 0 for shutdown); H j , x j These represent the virtual inertia constant, rated power, and operating status of the new energy generator set, respectively, in MW·s.

[0097] When the system experiences a disturbance (taking a step increase in load as an example), the synchronous generator, which has voltage source characteristics, automatically shares the disturbance power. The electromagnetic power of the synchronous generator changes abruptly, while the mechanical power remains constant. At this time, the rotor will decelerate due to the imbalance of torque, and its kinetic energy is forced to be released as electromagnetic power, maintaining the system's active power balance. When the speed governor activates, the inertial response and primary frequency regulation work together to provide power to the system. When the electromagnetic power equals the mechanical power, the system frequency reaches its lowest point. Subsequently, the prime mover continues to generate mechanical power, restoring the rotor speed to near its rated value. During this period, the inertial support power is negative, meaning the rotor absorbs energy from the system for acceleration. The power response and energy conversion process are as follows: Figure 3 As shown.

[0098] Figure 3 Chinese 0+ The disturbance occurs at a specific time; t0-t1 is the inertial response phase; the speed controller activates at time t1; and the frequency reaches its lowest point at time t2. ΔP e ΔP represents the change in electromagnetic power. m ΔP represents the change in mechanical power. d The disturbance power is represented by Δf, and the frequency deviation is represented by Δf. max This represents the maximum frequency deviation. As the graph shows, the unbalanced power cannot be instantly balanced after a disturbance. Inertia provides the energy source for electromagnetic power, playing a crucial role in maintaining the balance between active power supply and demand, and slowing down the rate of frequency change. This buys time for subsequent frequency adjustment actions and is an indispensable part of maintaining frequency stability.

[0099] A dynamic frequency response model for the power system is established by comprehensively considering the power system's inertial response, load frequency response, and primary and secondary frequency regulation responses.

[0100] (1) Inertial response

[0101] Inertial response is generally described using the generator rotor motion equations:

[0102]

[0103]

[0104] In the formula: H is another way to represent the system's inertia, and is related to H sys The relationship is shown in equation (3); Δf(t) is the frequency deviation; D is the generator damping coefficient; ΔP m (t) represents the change in the output mechanical power of the prime mover; ΔP e (t) represents the change in electromagnetic power; ΔP L (t) represents the change in the active power of the load.

[0105] (2) Load frequency response

[0106] When the load voltage remains constant, the active power of the load will respond to changes in the system frequency, as expressed by:

[0107]

[0108] In the formula: P LN f is the active power of the load at the rated frequency; n The system's rated frequency; λ i For the load active power that is proportional to the i-th power of the frequency in P LN The share of ∑λ i =1.

[0109] (3) Primary frequency modulation response

[0110] During a frequency regulation process, the governor controls the turbine valve opening according to the frequency regulation command, and the prime mover adjusts the output mechanical power according to the valve opening command of the governor control module. The mathematical models of the governor control module and the prime mover control module are as follows:

[0111]

[0112]

[0113] In the formula: T n R is the governor time constant; R is the generator droop coefficient; and 1 / R feedback loop is the primary frequency regulation command of the power system. CH ΔP is the steam volume time constant of the steam turbine; V (t) represents the change in turbine valve opening; ΔP m (t) represents the change in mechanical power.

[0114] (4) Secondary frequency modulation

[0115] The secondary frequency regulation of the power system is a zero-error regulation that can restore the steady-state frequency to its pre-disturbance value after a disturbance occurs. It adopts integral control, and its mathematical model is expressed as follows:

[0116] ΔP ref (t)=K∫Δf(t)dt (7)

[0117] In the formula: K is the second-order frequency modulation effect coefficient; ΔP ref (t) represents the change in secondary frequency regulation power of the power system.

[0118] In the process of establishing the frequency dynamic response model of the power system, the following practical factors are considered to simplify the above frequency response process:

[0119] I. This invention mainly studies the inertial response stage of a power system, which primarily affects frequency stability approximately 2 seconds after the disturbance begins. This is far from the time when the secondary frequency regulation response of the power system begins to take effect. The change in the secondary frequency regulation response ΔP is considered to be... ref It is zero.

[0120] II. In power systems, loads with high frequency correlation account for a very small proportion; generally, only loads with cubic frequency correlation need to be considered. Therefore, their active power change ΔP L (t) can be represented as:

[0121] ΔP L (t)=K L Δf(t) (8)

[0122] In the formula: K L This is the load frequency regulation effect coefficient.

[0123] III. The electromagnetic power ΔP is considered to be... e (t) does not change with time after the disturbance and is a step function, taking the value as the total power deficit ΔP of the power system at the beginning of the disturbance, and the frequency regulation effect coefficient of the load K. L The generator damping coefficient D is incorporated into the power system, ignoring the first-order inertial delay module of the governor valve opening command in primary frequency regulation.

[0124] Therefore, the simplified dynamic response model of the power system frequency can be expressed by the following equation:

[0125]

[0126] Based on the above model analysis, as the system inertia H... sys The decrease in inertia leads to more drastic frequency changes after a disturbance, i.e., an increase in the rate of frequency change (RoCoF). On the other hand, the decrease in system inertia also causes an increase in frequency deviation, meaning the minimum frequency point decreases further, but the system inertia H... sys It has little impact on steady-state frequency deviation, such as Figure 4 As shown.

[0127] The system frequency dynamic response model shows a nonlinear relationship between system inertia and the maximum frequency deviation after disturbance. A fitness function is constructed, and the particle swarm optimization algorithm is used to determine the system inertia level H′ corresponding to a certain frequency deviation limit. SIL To find the optimal solution, Figure 5 In this context, pbest is the best historical position for each particle, gbest is the best global position for the population, and the fitness function is:

[0128] Fitness=(Δf i max -Δf lim )2 (10)

[0129] In the formula: Δf i max Δf represents the maximum frequency deviation corresponding to particle i. lim This is the frequency deviation limit.

[0130] The PSO method is used to solve for the critical value of system inertia under frequency deviation constraints, providing a new approach to handling the nonlinear relationship between system inertia and frequency extrema.

[0131] Step S2: Establish frequency stability constraints based on the relationship between system inertia and the maximum frequency deviation of the system after disturbance.

[0132] Frequency stability constraints include RoCoF constraints and frequency deviation constraints:

[0133] RoCoF min ≤RoCoF ext ≤RoCoF max (11)

[0134] f min ≤f ext ≤f max (12)

[0135] Equation (11) represents the frequency change rate constraint, and Equation (12) represents the frequency extremum constraint; RoCoF min RoCoF max These are the upper and lower limits of RoCoF, respectively; f min f max These are the upper and lower limits of frequency stability, respectively; RoCoF ext f ext These are the extreme vectors of the rate of change of the system's frequency and the extreme vector of the transient frequency, respectively, after the occurrence of the most severe potential fault.

[0136] The frequency stability constraint equations (11) and (12) are analyzed respectively:

[0137] (1) RoCoF constraint.

[0138] Since a large RoCoF after a disturbance may cause damage to the unit structure or cause the distributed power source to disconnect from the grid, RoCoF should satisfy constraint (11). After the fault occurs, as the primary frequency regulation and stabilization control measures in the system are successively activated, the unbalanced power will gradually decrease. The maximum value of the system frequency change occurs instantaneously after the fault occurs, which can be obtained from the rotor motion equation:

[0139]

[0140] H′ sys =HSIL -H loss (14)

[0141]

[0142] In the formula: RoCoF(t) 0+ ) represents the rate of change of frequency instantaneously after the fault occurs; ΔP MAX The active power disturbance caused by the extreme anticipated faults is the critical N-2 fault set. The element with the largest absolute value in the middle; H′ sys Let be the system inertia after the fault occurs. Equation (15) represents the situation where the inertia is lost due to the extreme anticipated fault (such as a synchronous generator fault). It should be noted that the objective function (22) represents the system inertia before the fault occurs. When the fault causes inertia loss, the lost inertia part should be reflected in the rotor motion equation. The RoCoF constraint is transformed into a system inertia constraint as follows:

[0143]

[0144] Where: RoCoF lim RoCoF refers to the upper and lower limits of the rate of change of frequency. max and RoCoF min It can be seen that the frequency change rate constraint (11) is a linear constraint.

[0145] (2) Frequency extremum constraint.

[0146] When the system is subjected to disturbances, the frequency extrema are affected by multiple frequency modulation processes. Considering the inertial response process after a fault, the rapid frequency modulation effect of the stabilization and control measures, and the primary frequency modulation process, the frequency extrema constraint is linearized based on the rotor motion equation. Assuming the frequency modulation rate is constant during the primary frequency modulation process and neglecting other factors, the maximum frequency deviation is:

[0147]

[0148] In the formula: t sf A preset time delay is set to trigger stability control measures for a certain anticipated fault, i.e., at that moment, the safety and stability control system implements control measures such as machine tripping, load shedding, and partial disconnection to prevent the system from losing stability; R sys P represents the primary frequency modulation rate of the system, which is a constant; sf The adjustment power is set to trigger stability control measures for a certain anticipated fault. The frequency deviation constraint is converted into a system inertia constraint as follows:

[0149]

[0150] Δf m =f m -f n(19)

[0151] In the formula: f m For the frequency stability limit, i.e., f min and f max The frequency extremum constraint equation (12) is simplified to a linear constraint on system inertia.

[0152] Step S3: Under extreme anticipated fault conditions, construct a power system inertia safety domain evaluation model that takes into account the inertia level and the frequency stability constraint.

[0153] An evaluation model for the inertia safety domain of a power system, taking into account inertia level and frequency stability constraints, is established. The upper boundary of the inertia safety domain is the total available inertia of the system, and the lower boundary is the critical value of inertia safety. A set of extreme anticipated faults of the system is set, and the frequency regulation process, including inertia response, primary frequency regulation, and stability control measures, is comprehensively considered. The frequency extreme value constraint is linearized into an inertia constraint through the equivalent rotor motion equation of the system.

[0154] Considering all synchronous generating units are in operation, and the new energy generating units adopt conventional control, the total usable inertia of the system is:

[0155]

[0156] Where: N SG H represents the total number of conventional units in the system; i P i max These represent the inertial constants of the synchronous generator set. The total available inertia of the system reflects the system's inertia reserve capacity, which is only related to the number of installed units and the unit parameters.

[0157] This invention requires setting a critical safety value H for inertia under extreme anticipated failure conditions. SIL To solve this problem, we define the ultimate anticipated fault scenario as the loss of two critical components during normal operation of the power system. The fault set formed by the critical N-2 safety checks of the system can be expressed as follows:

[0158]

[0159] In the formula: A collection of critical N-2 security check faults; F mn This represents the fault condition; m and n represent the numbers of the critical components that were lost; N represents the number of critical components in the system that are in operation, including conventional generating units, DC transmission lines, and new energy power plants that are in operation.

[0160] Under the extreme anticipated failure condition, taking into account both RoCoF constraints and frequency deviation constraints, the critical value of system inertia safety is solved. Assuming that the new energy units in the system adopt conventional control, the optimization model is as follows:

[0161]

[0162] st

[0163] H min ≤H SIL ≤H max (twenty three)

[0164]

[0165]

[0166] In the formula: H min H max These represent the upper and lower limits of the system inertia for each time period.

[0167] By transforming the frequency stability constraint, the solution model for the system inertia safety critical value is transformed into a linear model. This linear model uses equation (22) as the objective function and equations (23), (16), and (18) as constraints. A mature solver can effectively determine the inertia safety critical value of the power system during its operating cycle. The total usable inertia H of the system in equation (20) is then used. MIL As the upper bound, the critical value of inertia safety in (22) is H. SIL The infimum is used to define the system's inertia safety region. If the system's inertia level remains within this safety region during operation, it can ensure that the system can recover to a stable frequency state after experiencing significant power disturbances, without affecting power supply reliability.

[0168] A model of the inertia safety domain of new energy sources after adopting virtual synchronous machine control is constructed, and the changes in the inertia safety domain before and after adopting virtual synchronous machine control are analyzed.

[0169] First, we assess the total usable inertia of the system after adopting virtual synchronous machine technology for the new energy units, including both the synchronous unit and the new energy unit. The expression is:

[0170]

[0171] Where: N SG N RG H represents the total number of conventional generating units and new energy generating units (including photovoltaic generators and wind turbine generators) in the system; i P i max H′ represents the inertial constant and rated power of the synchronous generator set, respectively. j , These represent the virtual inertia constant and rated power of the new energy generator set, respectively, in MW·s, and determine the upper bound of the inertia safety domain.

[0172] When solving for the critical value of inertia safety after adopting virtual synchronous machine control for new energy sources, a virtual inertia component needs to be added to the original optimization model. The optimization model is as follows:

[0173]

[0174] st

[0175] H min ≤H SIL ≤H max (26)

[0176] RoCoF min ≤RoCoF ext ≤RoCoF max (27)

[0177] f min ≤f ext ≤f max (28)

[0178] In the formula: H′ j Let H′ represent the virtual inertia level of the new energy unit. Assuming that the virtual inertia of the new energy unit is smoothly adjustable after adopting virtual synchronous machine technology, then H′... j ∈[H′ jmin ,H′ jmax ];x j This indicates the operating status of the new energy generator set (1 for startup, 0 for shutdown).

[0179] Step S4: Based on the anticipated fault conditions set for each time period, solve the power system inertia safety domain assessment model to determine the inertia safety domain of the new energy power system for each time period; the inertia safety domain is defined by the total available inertia of the system as the upper bound and the inertia safety critical value as the lower bound.

[0180] Based on the critical N-2 safety verification fault set, different extreme expected fault conditions are set for each of the 24 hours. The power system inertia safety domain assessment model, taking into account inertia level and frequency stability constraints, is solved. If the new energy source adopts virtual synchronous machine control, the inertia safety domain of the new energy power system in each time period is calculated using formulas (24)-(28). If the new energy source adopts conventional control, the inertia safety domain of the new energy power system in each time period is calculated using formulas (22), (23), (16), and (18). The system can utilize the total inertia H... MIL As the upper bound, the critical value H for inertia safety SIL The infimum is used to define the system's inertia safety region. If the system's inertia level remains within this safety region during operation, it can ensure that the system can recover to a stable frequency state after experiencing significant power disturbances, without affecting power supply reliability.

[0181] Step S5: Calculate the current total system inertia of the new energy power system based on the current operating status of the power system.

[0182] When new energy generating units adopt conventional control, the formula is used based on the current operating status of the power system. Calculate the current total inertia of the new energy power system;

[0183] When new energy generating units adopt virtual synchronous machine control, the formula is used based on the current operating state of the power system. Calculate the current total inertia of the new energy power system;

[0184] Among them, H sys Let N be the total inertia of the current system. SG N RG These represent the total number of conventional generating units and new energy generating units in the system, respectively; H i P i max x i The inertial constant, rated power, and operating state of synchronous generator set i are respectively, H′ j , x j These represent the virtual inertia constant, rated power, and operating status of the new energy generator set j, respectively.

[0185] Step S6: Based on the current total system inertia and the inertia safety domain corresponding to the current time period, the current inertia level of the new energy power system is evaluated using the characteristic indicators for judging the system inertia level.

[0186] Based on the system inertia safety domain, the inertia reserve coefficient is extracted as a characteristic indicator to represent the reserve status of the system's inertia resources, and the inertia safety margin is extracted as a characteristic indicator to represent the system's safety margin, assisting the scheduler in judging and quantifying the sufficiency of the system's inertia level.

[0187] (1) Inertia reserve coefficient: reflects the relative size between the actual inertia value of the system and the total available inertia, and provides a reference when the system needs to call up inertia resources.

[0188]

[0189] (2) Inertia safety margin: It reflects the relative size of the actual inertia value of the system and the critical value of the system inertia safety, and provides a reference for the system inertia safety margin. In order to ensure that the system inertia level is within the inertia safety domain, this index should be positive and should leave a certain margin for extreme faults to ensure the stability of system frequency.

[0190]

[0191] Dispatchers can divide the value range of the inertia reserve coefficient and inertia safety margin index based on existing operating experience, and make direct judgments by comprehensively evaluating the current inertia level of the system using two-dimensional indicators.

[0192] The two indicators C1 and C2 mentioned represent the current inertia reserve and the system's inertia safety margin, respectively. They correspond to the relative magnitudes of the current inertia level and the upper and lower bounds of the inertia safety domain. The intersection of the inertia reserve coefficient and the inertia safety margin is determined in the two-dimensional inertia level indicator assessment diagram, and the safety margin level corresponding to the area where the intersection point is located is taken as the current inertia level of the new energy power system. The horizontal axis of the two-dimensional inertia level indicator assessment diagram is the inertia safety margin, and the vertical axis is the inertia reserve coefficient. The two-dimensional inertia level indicator assessment diagram is shown below. Figure 6 As shown. Figure 6 Region ① represents a region with low inertia margin and high inertia reserve; Region ② represents a region with medium inertia safety margin and high inertia reserve; Region ③ represents a region with high inertia safety margin and high inertia reserve; Region ④ represents a region with low inertia safety margin and medium inertia reserve; Region ⑤ represents a region with medium inertia safety margin and medium inertia reserve; Region ⑥ represents a region with high inertia safety margin and medium inertia reserve; Region ⑦ represents a region with low inertia safety margin and low inertia reserve; Region ⑧ represents a region with medium inertia safety margin and low inertia reserve; and Region ⑨ represents a region with high inertia safety margin and low inertia reserve.

[0193] The evaluation method also includes: comparing the inertia safety domain of the new energy unit when using virtual synchronous machine control and when using conventional control, and obtaining the comparison results; the comparison results include: the upper boundary of the inertia safety domain of the new energy unit shifts upward and the lower boundary shifts downward after adopting virtual synchronous machine control.

[0194] It is evident that the adoption of virtual synchronous machine control has the following main impacts on the inertia safety domain: First, the upper boundary of the inertia safety domain shifts upward, meaning the total usable inertia of the system increases, and the system's inertia reserve becomes more abundant; Second, the lower boundary of the inertia safety domain shifts downward. After the new energy unit provides virtual inertia, since the virtual inertia is continuously adjustable, under the condition that the original inertia level and frequency stability constraints remain unchanged, the inertia required by the synchronous generator decreases, the inertia safety domain expands, and the safe operating point increases.

[0195] The following section uses the IEEE 39-bus system as an example to further illustrate the method for assessing the inertia level of a power system.

[0196] Step A

[0197] Taking the IEEE 39-bus system as an example, the inertia safety domain assessment model described above is solved. Two wind farms are added (using conventional control). The system inertia safety domain is constructed with a 24-hour assessment period. Based on the critical N-2 safety verification fault set, different extreme anticipated fault scenarios are set for each 24-hour period. The power system inertia safety domain assessment model considering inertia level and frequency stability constraints is solved. Since the number of generators in this system is relatively small and the output of a single unit accounts for a high proportion of the total load, a load reduction and stability control strategy is adopted for extreme anticipated faults (conventional unit tripping). The stability control measures activate 0.25 seconds after the fault occurs. Figure 7 This shows the network topology of the IEEE 39-node system. Figure 7 The numbers 1-39 in the middle represent node numbers, and G1-G10 represent generator numbers.

[0198] Table 1. Inertia Time Constant and Rated Power of Synchronous Generator Sets

[0199]

[0200]

[0201] Step B

[0202] (1) The maximum available inertia of the system is 35966.8MW·s.

[0203] (2) Based on the set of critical N-2 safety check faults in the system, the minimum inertia requirement of the system and the unit start-up status are calculated in different time periods:

[0204] Table 2 shows the solution for the system's minimum inertia requirement and unit startup status.

[0205]

[0206]

[0207] (3) Determine the inertia safety domain based on the maximum and minimum available inertia of the system and the system's inertia safety threshold. The solution results for the inertia safety threshold of the IEEE 39-node system are as follows: Figure 8 As shown, the solution results for the inertia security domain of the IEEE 39-node system are as follows: Figure 9 As shown. Figure 8 The horizontal axis represents time, and the vertical axis represents the critical value of system inertia safety. Figure 9 The top curve in the diagram represents the upper bound of the inertia safety domain, the bottom curve represents the lower bound of the inertia safety domain, and the middle curve represents the current inertia curve of the system. The diagram shows the operating state of all units except the unit with the anticipated failure in operation.

[0208] Depend on Figure 9Analysis shows that the upper bound of the inertia safety domain remains unchanged within the 24-hour evaluation period, meaning that the total inertia available to the system reflects the system's inertia reserve, which is only related to the equipment that can provide inertia. Due to the different expected fault scenarios and load reduction amounts set for each time period, the lower bound of the inertia safety domain changes continuously within the evaluation period. In the 4th and 8th time periods, the inertia demand is relatively low because the expected fault is less than that of the adjacent time periods, so the system's inertia safety threshold reaches a "low point".

[0209] Step C

[0210] The calculation examples are analyzed using the proposed inertia safety domain quantification index, as shown in Table 3.

[0211] Table 3 shows the solutions for the system's inertia reserve coefficient and inertia safety margin at different time periods.

[0212]

[0213]

[0214] Step D

[0215] Virtual synchronous machine control is applied to wind farm W1 in the example. A system inertia safety domain is constructed with a 24-hour evaluation period. The extreme expected faults for each time period are the same as in example 4.2.3. The wind turbine parameters using virtual synchronous machine technology are as follows:

[0216] Table 4 Parameters of wind turbine generators using virtual synchronous machine technology

[0217] Serial Number Rated capacity / MW Reserve capacity percentage / % Maximum virtual inertia / s Minimum virtual inertia / s W1 250 10.0 3.0 2.0

[0218] (1) Considering that all units are in operation, W1 is taken as the maximum virtual inertia. At this time, the total inertia that the system can utilize is 36641.8MW·s.

[0219] (2) Solve for the critical value of inertia safety and the start-up status of the unit.

[0220] Table 5 shows the solution for the critical safety value of system inertia (W1) and unit start-up status.

[0221]

[0222]

[0223] The comparison results of the lower bound of the inertia safety region between the original system and the system containing wind turbines are as follows: Figure 10 As shown.

[0224] In summary, the adoption of virtual synchronous machine control in wind turbines has the following main impacts on the inertia safety domain: 1) The upper boundary of the inertia safety domain shifts upward, meaning the total available inertia of the system increases, and the system's inertia reserve becomes more sufficient; 2) The lower boundary of the inertia safety domain shifts downward. After the wind turbine provides virtual inertia, since the virtual inertia of the wind turbine is continuously adjustable, under the condition that the original inertia level and frequency stability constraints remain unchanged, the inertia required by the synchronous generator decreases, the inertia safety domain expands, and the safe operating point increases.

[0225] Compared with the prior art, the present invention has the following advantages:

[0226] 1. The critical value of system inertia under frequency deviation constraint is solved based on PSO, which provides a new approach to dealing with the nonlinear relationship between system inertia and frequency extrema.

[0227] 2. A method for evaluating the inertia safety domain of new energy power systems that takes into account inertia level and frequency stability constraints is proposed. This method can quickly and effectively construct the system inertia safety domain, meet the requirements of actual power grid safety and stability analysis, and the accuracy of the evaluation results is better than the inertia evaluation method that only considers RoCoF constraints.

[0228] 3. The frequency extremum constraint was linearized based on the system's equivalent rotor motion equation, transforming the optimization model into a mixed-integer linear programming problem. This significantly improves the solution speed compared to the method of approximating the critical value of inertia safety through time-domain simulation.

[0229] The various embodiments in this specification are described in a progressive manner, with each embodiment focusing on the differences from other embodiments. The same or similar parts between the various embodiments can be referred to each other.

[0230] This document uses specific examples to illustrate the principles and implementation methods of the present invention. The descriptions of the above embodiments are only for the purpose of helping to understand the method and core ideas of the present invention. Furthermore, those skilled in the art will recognize that, based on the ideas of the present invention, there will be changes in the specific implementation methods and application scope. Therefore, the content of this specification should not be construed as a limitation of the present invention.

Claims

1. A method for assessing an inertia level of a power system, characterized by, The evaluation method comprises: The power system frequency dynamic response model is established by comprehensively considering the inertia response, primary frequency modulation and load frequency response, and the relationship between the system inertia and the maximum frequency deviation of the system after being disturbed is determined according to the power system frequency dynamic response model; The frequency stability constraint is established according to the relationship between the system inertia and the maximum frequency deviation of the system after being disturbed; In the limit contingency case, the power system inertia security domain evaluation model considering the inertia level and the frequency stability constraint is constructed; According to the contingency case set in each time period, the power system inertia security domain evaluation model is solved to determine the inertia security domain of the power system in each time period; the inertia security domain is an inertia security range defined by the total available inertia of the system as the upper limit and the inertia security critical value as the lower limit; According to the current operating state of the power system, the current total inertia of the new energy power system is calculated; According to the current total inertia and the inertia security domain of the corresponding time period at the current time, the current inertia level of the new energy power system is evaluated by using the characteristic index for judging the system inertia level, specifically comprising: According to the current system total inertia and the upper limit of the inertia safety domain of the corresponding period at the current time, the inertia reserve coefficient is calculated by the formula , wherein C 1; wherein, H MIL is the total available inertia of the system when the new energy unit adopts conventional control, is the current system total inertia; According to the current system total inertia and the lower bound of the inertia safety domain of the time period corresponding to the current time, the inertia safety margin is calculated by using the formula , wherein C 2; wherein, H SIL is the inertia safety critical value. The intersection point of the inertia reserve coefficient and the inertia security margin is determined in the inertia level two-dimensional index evaluation indication diagram, and the security margin level corresponding to the intersection point is taken as the current inertia level of the new energy power system; the horizontal coordinate of the inertia level two-dimensional index evaluation indication diagram is the inertia security margin, and the vertical coordinate is the inertia reserve coefficient.

2. The evaluation method according to claim 1, characterized in that The power system frequency dynamic response model is established by comprehensively considering the inertia response, primary frequency modulation and load frequency response, and the relationship between the system inertia and the maximum frequency deviation of the system after being disturbed is determined according to the power system frequency dynamic response model, specifically comprising: The inertia response model, the load frequency response model, the primary frequency modulation response model and the secondary frequency modulation model are constructed respectively; The power system frequency dynamic response model is determined by comprehensively considering the inertia response model, the load frequency response model, the primary frequency modulation response model and the secondary frequency modulation model; The system frequency response dynamic curve of the system inertia at different values is established according to the power system frequency dynamic response model; The relationship analysis result of the system inertia and the maximum frequency deviation of the system after being disturbed is obtained according to the system frequency response dynamic curve of the system inertia at different values; the relationship analysis result is that the system inertia and the maximum frequency deviation of the system after being disturbed are in a nonlinear relationship.

3. The evaluation method according to claim 2, characterized in that The relationship analysis result of the system inertia and the maximum frequency deviation of the system after being disturbed is obtained according to the system frequency response dynamic curve of the system inertia at different values, and then comprising: The fitness function is constructed as ; wherein, Fitness is the fitness function, is the particle corresponds to the maximum frequency deviation, is the frequency deviation limit; The optimal system inertia critical value corresponding to the preset frequency deviation limit value is obtained by solving the power system frequency dynamic response model based on the fitness function and using the particle swarm algorithm according to the preset frequency deviation limit value.

4. The evaluation method according to claim 2, characterized in that The inertia response model is in, For system inertia, For frequency deviation, This is the generator damping coefficient. This represents the change in electromagnetic power. The change in the mechanical power output of the prime mover. This represents the change in active power of the load. The current total inertia of the system. , These represent the total number of conventional generating units and new energy generating units in the system, respectively. , , Synchronous generator sets i Its inertial constant, rated power, and operating status. , , They are new energy generator sets j The virtual inertial constant, rated power, and operating status; The load frequency response model is in, P L ( t )for t Load frequency response over a period of time The active power of the load at the rated frequency. For frequency The active power of the load is proportional to the power of the power. The share of China ; The system's rated frequency, for t Frequency of time periods; The primary frequency modulation response model is wherein, is a governor time constant, is a generator droop coefficient, is a turbine valve opening change amount, is a turbine steam volume time constant, is t is a mechanical power change amount of the time period; The secondary frequency modulation model is wherein, is the power variation of the secondary frequency regulation of the power system, is the secondary frequency regulation effect coefficient.

5. The evaluation method according to claim 2, characterized in that The power system frequency dynamic response model is determined by comprehensively considering the inertia response model, the load frequency response model, the primary frequency modulation response model and the secondary frequency modulation model, specifically comprising: the electromagnetic power variation in the inertia response model is equivalent to the total power shortage of the power system at the beginning of the disturbance , and the load active power variation in the inertia response model and the load active power variation obtained according to the load frequency response model are combined into to obtain the simplified inertia response model and the load frequency response model as ; ignoring a first-order inertia delay module of a governor valve opening degree instruction in the primary frequency modulation response model , and a simplified primary frequency modulation response model is obtained as ; Simplifying power system secondary frequency modulation power variation in the secondary frequency modulation model is 0; The frequency dynamic response model of the power system is determined by combining the simplified inertia response model, the load frequency response model and the simplified primary frequency modulation response model .

6. The evaluation method according to claim 1, characterized in that The frequency stability constraint is established according to the relationship between system inertia and the maximum frequency deviation after being disturbed, and specifically comprises: The frequency stability constraint comprises a frequency change rate constraint and a frequency extreme constraint; The initial frequency rate of change constraint is established as ; wherein, , are the upper and lower limits of the RoCoF, respectively, is the extreme value vector of the system frequency rate of change after the most severe potential fault occurs. According to the relationship between the system inertia and the maximum frequency deviation of the system after being disturbed, the initial frequency change rate constraint is converted into a first system inertia constraint: ; wherein, is the system inertia after the fault occurs, , H loss is the system loss inertia, is the system rated frequency, is the active disturbance caused by the limit contingency, , is a key fault set, is the upper and lower limits of the frequency change rate; The initial frequency extremum constraints are established as ; wherein, , are the upper and lower limits of frequency stability, respectively, is the transient frequency extremum vector of the system after the most severe potential fault occurs. According to the relationship between the system inertia and the maximum frequency deviation of the system after being disturbed, the initial frequency extremum constraint is converted into a second system inertia constraint: ; wherein, is a preset time delay set for triggering the stabilizing control adjustment measure of a certain limit contingency, is the primary frequency modulation rate of the system, is the adjustment power of the stabilizing control adjustment measure triggered by a certain limit contingency, is the generator damping coefficient, is the frequency stability limit.

7. The evaluation method according to claim 6, characterized in that The power system inertia safety domain evaluation model comprises a power system inertia safety domain evaluation model when the new energy unit adopts conventional control and a power system inertia safety domain evaluation model when the new energy unit adopts virtual synchronous machine control; The power system inertia safety domain evaluation model when the new energy unit adopts conventional control is The constraint condition comprises: Inertia level constraint: First system inertia constraint: Second system inertia constraint: wherein: is t the total inertia available to the system when the new energy units use conventional control during the period, , , are the inertia constant, rated power, and operating state of the synchronous generator unit i , is the total number of conventional units in the system; is t the inertia safety critical value when the new energy units use conventional control during the period, , are the upper and lower limits of the system inertia; The power system inertia safety domain evaluation model when the new energy unit adopts virtual synchronous machine control is H' MIL ( t ) min H' SIL ( t ) The constraint condition comprises: Inertia level constraint: First system inertia constraint: Second system inertia constraint: in: H' MIL ( t )for t The total inertia that can be utilized by the system when the new energy generating unit adopts virtual synchronous machine control during a certain period. H' SIL ( t )for t The critical value of inertia safety when using virtual synchronous machine control for new energy generating units during certain periods. , , They are new energy generator sets j The virtual inertial constant, rated power, and operating status.

8. The evaluation method according to claim 7, characterized in that The current system total inertia of the new energy power system is calculated according to the current operating state of the power system, and specifically comprises: When the new energy unit adopts the conventional control, according to the current operation state of the power system, the total inertia of the new energy power system is calculated by using the formula ​ When the new energy unit adopts virtual synchronous machine control, according to the current operation state of the power system, the total inertia of the new energy power system is calculated by the formula ​ wherein, is the total number of new energy units in the system.

9. The evaluation method according to claim 7, characterized in that The evaluation method further comprises: The inertia safety domain when the new energy unit adopts virtual synchronous machine control is compared with the inertia safety domain when the new energy unit adopts conventional control to obtain a comparison result; the comparison result comprises that the upper limit of the inertia safety domain after the new energy unit adopts virtual synchronous machine control is moved upward, and the lower limit is moved downward.

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