Strategies to Increase the Transient Active Power of Photovoltaic Units during Low Voltage Ride Through

: Due to a limitation in the magnitude of the three-phase output inverter currents, the output active power of the photovoltaic (PV) unit has been de-rated during low voltage ride through, which brings great instability risk to the power system. With the increase in the penetration rate of new energy, the impact of the power shortage on the system transient stability increases. It is of great signiﬁcance to analyze the impact of this transient power shortage on system stability. This article explores methods to improve the active power output capability of photovoltaic units during low-breakthrough periods. A transient simulation model of a grid-connected PV generator with low-voltage ride-through (LVRT) capability is presented, under the condition of meeting the overcurrent capacity of the PV inverter and the requirement of dynamic reactive power support supplied by the PV generator speciﬁed in the China grid codes (GB/T 19964-2012) during grid fault. An example system with high PV penetration is built. The change principle and inﬂuencing factors of PV transient active power output are analyzed. The simulation model is designed in PowerFactory/DIgSILENT, and several types of three-phase voltage sags are performed in simulation to assess the impact of the active current reference calculation method and the maximum inverter output current ( I max ) limit value on the PV active power output. According to the three indexes, namely the maximum active power of PV unit during the fault, the power improvement gradient and the power surge after the fault is cleared. Simulation results showed that using the orthogonal decomposition method to calculate the active current reference can make full use of the current capacity of the converter. Setting I max to 1.1 rated current of photovoltaic inverter ( I N ) can reduce the cost-effectiveness ratio of the transient active power output of the PV unit. Therefore, we aim to improve the unit’s transient active power output capacity and realize the optimal effect of improving the transient active power shortage of the system.


Introduction
With the deterioration of the current environment and the exhaustion of traditional fossil energy, clean and efficient renewable energy, especially solar energy, has been used on a large scale. Photovoltaic (PV) generation has shown a large-scale grid-connection trend, with increasing installed capacity and an increasing penetration rate [1][2][3][4][5]. PV array needs to be converted from DC to AC by an inverter to access the grid, but the overcurrent capacity of the inverter is limited. When the grid suffers from fault, there may be transient overcurrent and overvoltage through the PV inverter. The instantaneous peak value will (i) The characteristic and influence factors of active power supplied from the PV system in the fault are analyzed. (ii) Under the premise of ensuring the safety of equipment overcurrent and meeting the reactive power support requirements in the Chinese grid, the PV inverter control strategies corresponding to different active current calculation formulas are established. The LVRT control block is added to the current and voltage loops in a gridconnected PV system's rotating orthonormal dq axes. The added LVRT control-block regulates the reference for the quadrature q component of the output three-phase inverter currents (i q_ref ) according to the depth of the voltage sag, which attains an effective performance for reactive (Q) powers support during fault conditions. Meanwhile, the reference for the quadrature d component of the output three-phase inverter currents (i d_ref ) is regulated by different active current calculation formulas, obtaining different active power output. (iii) A three-phase single-stage large power grid-connected PV system is analyzed and tested under several grid faults in PowerFactory/DIgSILENT. The influence of the d component of inverter currents (i d ) calculation formulas and the limitation of the inverter's output currents on the inverter's reactive power output is analyzed through simulation results.
The paper is organized as follows: Section 2 presents the LVRT capability of a PV system following the recommendations described in the Chinese grid codes (GB/T19964-2012). This section also describes the inverter control model. Section 3 presents the simulation results (using PowerFactory/DIgSILENT) of the system under investigation. The conclusion of the system performance is presented in Section 4. Figure 1 shows the block diagram of the three-phase single-stage grid-connected PV system presented in this article. The modeling of the PV power station mainly includes three parts: PV batteries, inverters and their control systems [24]. In Figure 1, p and q are the active and reactive power supplied to the grid, respectively. Us and δs are the amplitude and phase angle of the AC grid voltage, respectively. C d and u d are the DC capacitance and DC voltage, respectively. SPWM is the acronym of sinusoidal pulse width modulation. L is the abbreviation of filter inductance. u PV is the operating voltage of the PV array. i PV is the operating current of the PV array. lished. The LVRT control block is added to the current and voltage loops in a grid-connected PV system's rotating orthonormal dq axes. The added LVRT control-block regulates the reference for the quadrature q component of the output three-phase inverter currents (iq_ref) according to the depth of the voltage sag, which attains an effective performance for reactive (Q) powers support during fault conditions. Meanwhile, the reference for the quadrature d component of the output three-phase inverter currents (id_ref) is regulated by different active current calculation formulas, obtaining different active power output. (iii) A three-phase single-stage large power grid-connected PV system is analyzed and tested under several grid faults in PowerFactory/DIgSILENT. The influence of the d component of inverter currents (id) calculation formulas and the limitation of the inverter's output currents on the inverter's reactive power output is analyzed through simulation results.

PV System Model
The paper is organized as follows: Section 2 presents the LVRT capability of a PV system following the recommendations described in the Chinese grid codes (GB/T19964-2012). This section also describes the inverter control model. Section 3 presents the simulation results (using PowerFactory/DIgSILENT) of the system under investigation. The conclusion of the system performance is presented in Section 4. Figure 1 shows the block diagram of the three-phase single-stage grid-connected PV system presented in this article. The modeling of the PV power station mainly includes three parts: PV batteries, inverters and their control systems [24]. In Figure 1, p and q are the active and reactive power supplied to the grid, respectively. Us and δs are the amplitude and phase angle of the AC grid voltage, respectively. Cd and ud are the DC capacitance and DC voltage, respectively. SPWM is the acronym of sinusoidal pulse width modulation. L is the abbreviation of filter inductance. uPV is the operating voltage of the PV array. iPV is the operating current of the PV array. The PV generator does not have the same strong excitation function as a synchronous generator. During faulty operation of the grid, severe voltage fault happens. At the same time, the instantaneous active current has not changed, and thus the active power could not be delivered to the grid, which makes DC voltage increase. According to the PV curve for MPP, the operation point of PV array will shift from the maximum power point to the left side of the maximum power point. When the MPPT algorithm is deactivated, the active The PV generator does not have the same strong excitation function as a synchronous generator. During faulty operation of the grid, severe voltage fault happens. At the same time, the instantaneous active current has not changed, and thus the active power could not be delivered to the grid, which makes DC voltage increase. According to the PV curve for MPP, the operation point of PV array will shift from the maximum power point to the left side of the maximum power point. When the MPPT algorithm is deactivated, the active power injected into the grid can be calculated according to active current and grid voltage during the fault. It determines the active power delivered by the PV generator and adjust DC voltage to balance the active power, to realize the low-voltage ride-through [25].

Overall Control Model
The LVRT capability of a PV system requires the distributed generation (DG) systems to remain connected to the grid within a certain voltage sag and time interval during grid faults. The Chinese grid codes (GB/T19964-2012) are shown in Figure 2.
Energies 2021, 14, x FOR PEER REVIEW 4 of 14 power injected into the grid can be calculated according to active current and grid voltage during the fault. It determines the active power delivered by the PV generator and adjust DC voltage to balance the active power, to realize the low-voltage ride-through [25].

Overall Control Model
The LVRT capability of a PV system requires the distributed generation (DG) systems to remain connected to the grid within a certain voltage sag and time interval during grid faults. The Chinese grid codes (GB/T19964-2012) are shown in Figure 2. The PV generator delivers the maximum power to the utility grid during the normal operation. When the grid operates under faulty conditions, the DC voltage decreases and active power is de-rated below the operating value to achieve low-voltage ride-through. Thus, photovoltaic units can obtain LVRT capability by improving the inverter control strategy without additional hardware overhead. Its control goal is mainly to regulate the active (P) and reactive (Q) powers solely with the inverter currents' dq components to meet the requirements of the PV systems and provide dynamic reactive power support specified by the national standard. It also provides the limitation of the inverter currents to avoid its automatic disconnection from the utility grid, avoiding the inverter failure. Figure 3 shows the control block diagram of PV inverter with LVRT capability presented in this paper [26]. During the normal operating conditions of the grid, a typical voltage and current double closed-loop inverter control strategy are adopted. As the conventional mode in Figure 3 displays, the outer voltage control loop tracks the DC side voltage, which corresponds to the maximum power and generates the active current reference as the active current command input of the current inner loop. Reactive current reference of the inner current control loop is set to zero in order to achieve a unity power factor to enhance the utilization factor of solar energy. During grid faults, to avoid the PV system's automatic disconnection from the utility grid, the PV inverter quits the conventional operation logic and enters the low-voltage ride-through operation logic, which is mainly divided into two modes, namely fault ride-through mode and recovery mode. From the moment the voltage of the PV grid-connected point drops to 90% of the normal value, the inverter enters the fault ride-through stage, adopting fault ride-through mode. The inverter control structure switches from the fault ride-through mode to the recovery mode when the voltage returns to 90% of the normal value, but the active power does not restore to normal levels immediately. The inverter switches back to the conventional mode when the active power climbs to the pre-fault level, as the fault ride-through mode and conventional mode in Figure 3 displays, respectively [27]. The PV generator delivers the maximum power to the utility grid during the normal operation. When the grid operates under faulty conditions, the DC voltage decreases and active power is de-rated below the operating value to achieve low-voltage ride-through. Thus, photovoltaic units can obtain LVRT capability by improving the inverter control strategy without additional hardware overhead. Its control goal is mainly to regulate the active (P) and reactive (Q) powers solely with the inverter currents' dq components to meet the requirements of the PV systems and provide dynamic reactive power support specified by the national standard. It also provides the limitation of the inverter currents to avoid its automatic disconnection from the utility grid, avoiding the inverter failure. Figure 3 shows the control block diagram of PV inverter with LVRT capability presented in this paper [26]. During the normal operating conditions of the grid, a typical voltage and current double closed-loop inverter control strategy are adopted. As the conventional mode in Figure 3 displays, the outer voltage control loop tracks the DC side voltage, which corresponds to the maximum power and generates the active current reference as the active current command input of the current inner loop. Reactive current reference of the inner current control loop is set to zero in order to achieve a unity power factor to enhance the utilization factor of solar energy. During grid faults, to avoid the PV system's automatic disconnection from the utility grid, the PV inverter quits the conventional operation logic and enters the low-voltage ride-through operation logic, which is mainly divided into two modes, namely fault ride-through mode and recovery mode. From the moment the voltage of the PV grid-connected point drops to 90% of the normal value, the inverter enters the fault ride-through stage, adopting fault ride-through mode. The inverter control structure switches from the fault ride-through mode to the recovery mode when the voltage returns to 90% of the normal value, but the active power does not restore to normal levels immediately. The inverter switches back to the conventional mode when the active power climbs to the pre-fault level, as the fault ride-through mode and conventional mode in Figure 3 displays, respectively [27].

Inverter Reactive Current in Fault Ride-Through Mode and Recovery Mode
A reactive power priority strategy is adopted to supply reactive power for supporting the voltage recovery within the limit of the total current. Priority is given to regulate the reactive current output according to the depth of the voltage sag, and then the active current output of the inverter is regulated. No reactive current injection is required in the China grid codes as long as the grid voltage stays in the dead-band region (i.e., 0.9UT ≤ US ≤ 1.1UT). On the other hand, if the grid voltage drops below 90% of the nominal value, reactive current injection is required (see Equation (1)).
where IN is the rated current of the inverter, and UT is the grid voltage in per unit. Figure 4 shows the inverter's active current during grid faults. The inverter active current decreases when grid voltage sags occur. During fault ride-through, there are two active current calculation formulas, namely using the error between the maximum allowable inverter current (Imax) and reactive current and applying the orthogonal decomposition method according to Equations (2) and (3). When the PV grid-connected point voltage recovers, but the inverter active power output does not yet recover to the pre-fault level (recovery stage), then the active current can be recovered in three ways: immediate recovery, specified slope rise or parabola rise [28]. The active current output of the photovoltaic unit cannot exceed the maximum allowable current (corresponding to the straight line y = Imax in Figure 4) and the maximum current that the PV array can provide (corresponding to the direct current of y = P0/Us in Figure 4).

Inverter Reactive Current in Fault Ride-Through Mode and Recovery Mode
A reactive power priority strategy is adopted to supply reactive power for supporting the voltage recovery within the limit of the total current. Priority is given to regulate the reactive current output according to the depth of the voltage sag, and then the active current output of the inverter is regulated. No reactive current injection is required in the China grid codes as long as the grid voltage stays in the dead-band region (i.e., 0.9U T ≤ U S ≤ 1.1U T ). On the other hand, if the grid voltage drops below 90% of the nominal value, reactive current injection is required (see Equation (1)).
where I N is the rated current of the inverter, and U T is the grid voltage in per unit. Figure 4 shows the inverter's active current during grid faults. The inverter active current decreases when grid voltage sags occur. During fault ride-through, there are two active current calculation formulas, namely using the error between the maximum allowable inverter current (I max ) and reactive current and applying the orthogonal decomposition method according to Equations (2) and (3). When the PV grid-connected point voltage recovers, but the inverter active power output does not yet recover to the pre-fault level (recovery stage), then the active current can be recovered in three ways: immediate recovery, specified slope rise or parabola rise [28]. The active current output of the photovoltaic unit cannot exceed the maximum allowable current (corresponding to the straight line y = I max in Figure 4) and the maximum current that the PV array can provide (corresponding to the direct current of y = P 0 /U s in Figure 4). where P 0 is the active power output before the fault; that is, the PV maximum active power output, and I max is the allowable maximum inverter current. It can be seen from Figure 4 that compared with the method of recovery active current rising according to the specified slope or parabola, the immediate recovery method can quickly restore the inverter active current output and thus attain the best performance for active powers support. Therefore, this paper focuses on regulating active current output by an immediate recovery in the recovery stage. P 0 /U s represents the maximum active current output supplied by PV array. Its value is substantial that the active current during the fault period will not exceed. Thus, the active current is mainly determined by the selected calculation formulas and I max value under the same reactive current value.

Inverter Active Current in Fault Ride-Through Mode and Recovery Mode
where P0 is the active power output before the fault; that is, the PV maximum active power output, and Imax is the allowable maximum inverter current. It can be seen from Figure 4 that compared with the method of recovery active current rising according to the specified slope or parabola, the immediate recovery method can quickly restore the inverter active current output and thus attain the best performance for active powers support. Therefore, this paper focuses on regulating active current output by an immediate recovery in the recovery stage. P0/Us represents the maximum active current output supplied by PV array. Its value is substantial that the active current during the fault period will not exceed. Thus, the active current is mainly determined by the selected calculation formulas and Imax value under the same reactive current value.

Control of p and q
Based on the field-oriented vector control, the q components of the grid voltages are set to zero. According to the instantaneous power theory, the p and q powers delivered to the utility grid can be expressed as: where ed is the d component of the grid voltage, and idq is the dq components of the inverter currents.
In conclusion, during grid faults, the amount of active power delivered by the inverter depends on the depth of the voltage sag, active current calculation formulas and the maximum allowable current. Because the fault type determines the depth of the system's voltage sag and fault location, it is impossible to control it in advance. Therefore,

Control of p and q
Based on the field-oriented vector control, the q components of the grid voltages are set to zero. According to the instantaneous power theory, the p and q powers delivered to the utility grid can be expressed as: where e d is the d component of the grid voltage, and i dq is the dq components of the inverter currents.
In conclusion, during grid faults, the amount of active power delivered by the inverter depends on the depth of the voltage sag, active current calculation formulas and the maximum allowable current. Because the fault type determines the depth of the system's voltage sag and fault location, it is impossible to control it in advance. Therefore, this paper focuses on the influence of active current calculation formulas and the maximum allowable current on PV units' transient active power characteristics.

Results and Discussion
Based on a standard 3-machine 9-node example system, a simulation model of a gridconnected PV generation system with high penetration (50%) is built upon the PowerFactory/DIgSILENT simulation platform, as shown in Figure 5. In order to keep the active power injected by each node in the original system unchanged, the synchronous generator (G2) is directly turned off, and the photovoltaic power station (PV) with the same output is used to replace it at the same location. The capacity and active power output during the normal operation of each generator in the system are shown in Table 1. The parameters of the established PV generator are listed in Table 2.
The simulation set up three-phase short-circuit faults at different locations. The fault occurred at 1 s. The duration of the fault was 150 ms, and the fault was cleared without disconnecting the line. As indicated in Figure 5, a three-phase short-circuit fault was PowerFactory/DIgSILENT simulation platform, as shown in Figure 5. In order to keep the active power injected by each node in the original system unchanged, the synchronous generator (G2) is directly turned off, and the photovoltaic power station (PV) with the same output is used to replace it at the same location. The capacity and active power output during the normal operation of each generator in the system are shown in Table 1. The parameters of the established PV generator are listed in Table 2.  The capacity of each generator (SN), The active power output of each generator (P). Udc0 700 The simulation set up three-phase short-circuit faults at different locations. The fault occurred at 1 s. The duration of the fault was 150 ms, and the fault was cleared without disconnecting the line. As indicated in Figure 5, a three-phase short-circuit fault was simulated in Bus7, Bus8 and A location. The corresponding voltage of PV parallel point was 1%, 30% and 50% of the normal value. In each fault scenario, the simulation was conducted with eight cases, as Table 3 displays.   The capacity of each generator (S N ), The active power output of each generator (P).  As shown in Figure 6, the voltage sag of the PV parallel node is mainly determined by the fault location, having little effect on active currents. In combination with Figure 2, the PV system should remain connected to the grid during grid faults and supply reactive power to support the grid in these 24 simulation scenarios. Take the fault at Bus8 as an example; increasing I max can decrease the voltage surge at the moment of fault clearing, which smooths voltage recovery and reduces the impact on the grid. In this case, the total recovery time remains unchanged. When Bus7 or Line5 faults, it has the same rule. As shown in Figure 6, the voltage sag of the PV parallel node is mainly determined by the fault location, having little effect on active currents. In combination with Figure 2, the PV system should remain connected to the grid during grid faults and supply reactive power to support the grid in these 24 simulation scenarios. Take the fault at Bus8 as an example; increasing Imax can decrease the voltage surge at the moment of fault clearing, which smooths voltage recovery and reduces the impact on the grid. In this case, the total recovery time remains unchanged. When Bus7 or Line5 faults, it has the same rule.

Three-Phase Short-Circuit Fault on a Location
The results of the working condition (1) of the fault on location A are seen below in Figure 7.

Three-Phase Short-Circuit Fault on a Location
The results of the working condition (1) of the fault on location A are seen below in Figure 7.
The PV generator in a non-fault state supplies the LV bus with 0 p.u. reactive current, and since the droop parameter is 1.5 ( Table 2) the reactive current injected from the PV generator (iq during the fault) is 0.608, which leads to q duringthefault = U sduringthefault ·i qduringthefault = 0.497 × 0.608 = 0.302 p.u. (6) According to the reactive current during a fault (0.608 p.u.) and the calculation Formula (2), it can be concluded that the active current during the fault is 0.392 p.u, which leads to The above theoretical calculations are in accordance with simulation results shown in Figure 7, which indicates the effectiveness of the simulation model of the PV generator with LVRT capability and verifies the relationship between the transient active power, the voltage drop degree, the calculation method of the active current and the maximum allowable current of the inverter. The results of the other working conditions are the same.
The results of working conditions (1)-(8) when the fault occurs are shown below in Figures 8 and 9 and Table 4.
It can be seen from Figures 8 and 9, during grid faults, increasing I max value can not only improve the active current but also have little influence on the voltage sag and thus reduce the active power shortage. However, the active current and active power increase sharply, accompanied by small-amplitude oscillation at the recovery stage. As shown in Figure 9, when I max increases to 1.2, the active current during grid faults can be restored to the pre-fault level. However, because the voltage has not yet recovered, there is still a shortage of active power during the fault period.
The PV generator in a non-fault state supplies the LV bus with 0 p.u. reactive current, and since the droop parameter is 1.5 ( Table 2) the reactive current injected from the PV generator (iq during the fault) is 0.608, which leads to during the fault s during the fault q during the fault 0.497 0.608 0.302p.u.
According to the reactive current during a fault (0.608 p.u.) and the calculation formula (2), it can be concluded that the active current during the fault is 0.392 p.u, which leads to The above theoretical calculations are in accordance with simulation results shown in Figure 7, which indicates the effectiveness of the simulation model of the PV generator with LVRT capability and verifies the relationship between the transient active power, the voltage drop degree, the calculation method of the active current and the maximum allowable current of the inverter. The results of the other working conditions are the same.
The results of working conditions (1)-(8) when the fault occurs are shown below in Figures 8 and 9 and Table 4.   The maximum active power during the fault (P frtmax ), The increment of PV active power output corresponding to I max increasing by 0.1 I N (∆p), The power surge after the fault is cleared (P rsmax ).
It can be seen from the maximum power during the fault in Table 4, when Formula (3) is used to calculate the active current (corresponding cases 5-8), the PV active power output during the fault is greater than that of formula (2) (corresponding cases 1-4). Using Formula (3) to control the active current output during the fault can make greater use of the current capacity of the power conversion device and improve the active power shortage during the fault period. It can be seen from the power surge in Table 4, within the limits of the same value of I max , applying the orthogonal decomposition method to calculate the active current (namely using Formula (3)) can reduce the active power surge after fault clearing and the impact on the power grid. It can be seen from the power improvement gradient in Table 4, when I max is increased from 1 I N to 1.1 I N , the improvement effect of active power during fault is the most significant. With the continuous rise in I max , the active power improvement gradient becomes smaller; that is, the improvement effect on fault active power becomes smaller. The higher the limit value of the maximum output current of the inverter, the higher the cost is. The I max is set to 1.1 I N.
Therefore, the simulation results of this fault condition verify that setting the maximum output current limit (Imax) of the photovoltaic inverter proposed in this paper as 1.1 I N , and adjusting the active current output according to the orthogonal decomposition method during the fault period and the immediate recovery method during the recovery period, is the most effective control strategy.

Three-Phase Short-Circuit Fault of Bus8
The results of working conditions (1)-(8) of the three-phase short-circuit fault of Bus8 are seen below in Figures 10 and 11 and Table 5. The change rule is similar to the three-phase short circuit fault on location A. Using Formula (3) to control the active current output during the fault can make greater use of the current capacity of the inverter. Increasing I max can improve the active current and reduce the active power shortage. It can be seen from Table 5 that with the increase in I max , the degree of power improvement is decreasing. Comprehensively considering the improvement of active power and the increase of economic cost corresponding to the increase in I max , I max is still selected as 1.1 I N . Since the depth of voltage sag is greater than the three-phase short-circuit on location A, the PV output active power is less than the corresponding PV output active power at the three-phase short-circuit on location A.
The simulation results of this fault condition also verify that setting the maximum output current limit (I max ) of the photovoltaic inverter proposed in this paper as 1.1 I N , and adjusting the active current output according to the orthogonal decomposition method during the fault period and the immediate recovery method during the recovery period is the most effective control strategy.
A, the PV output active power is less than the corresponding PV output active power at the three-phase short-circuit on location A.
The simulation results of this fault condition also verify that setting the maximum output current limit (Imax) of the photovoltaic inverter proposed in this paper as 1.1 IN, and adjusting the active current output according to the orthogonal decomposition method during the fault period and the immediate recovery method during the recovery period is the most effective control strategy.   the three-phase short-circuit on location A. The simulation results of this fault condition also verify that setting the maximum output current limit (Imax) of the photovoltaic inverter proposed in this paper as 1.1 IN, and adjusting the active current output according to the orthogonal decomposition method during the fault period and the immediate recovery method during the recovery period is the most effective control strategy.    The maximum active power during the fault (P frtmax ), The increment of PV active power output corresponding to I max increasing by 0.1 I N (∆p), The power surge after the fault is cleared (P rsmax ).

Three-Phase Short-Circuit Fault of Bus7
When three phase short circuit fault occurs in Bus7, the corresponding voltage drops to 1% of the normal value. Due to the severe voltage sag, any active power strategy hardly works, and the active power shortage is larger than that of the first two faults. The simulation results of working conditions (1)-(8) of the three-phase short-circuit fault of Bus7 are seen below in Figures 12 and 13. Different active current power strategies during the fault period have little difference in the effect of transient frequency stability, but during the recovery period, with the increase in I max , the fluctuation degree of active current and active power becomes larger.
Therefore, comprehensively considering the effects of different active current control strategies under the first two fault conditions, it can be concluded that the maximum output current limit of the photovoltaic inverter (I max ) has been set to 1.1 I N and the orthogonal decomposition method been used during the fault; the strategy of adjusting the active current output according to the immediate recovery method used during the recovery period can most effectively cope with various degrees of voltage drop faults in the system and improve the transient frequency stability of the system. Therefore, comprehensively considering the effects of different active current control strategies under the first two fault conditions, it can be concluded that the maximum output current limit of the photovoltaic inverter (Imax) has been set to 1.1 IN and the orthogonal decomposition method been used during the fault; the strategy of adjusting the active current output according to the immediate recovery method used during the recovery period can most effectively cope with various degrees of voltage drop faults in the system and improve the transient frequency stability of the system.

Conclusions
In this article, a transient simulation model of a grid-connected photovoltaic (PV) generator with low-voltage ride-through (LVRT) capability is proposed. A power system model with a high PV penetration is established, and several types of three-phase volt- Therefore, comprehensively considering the effects of different active current control strategies under the first two fault conditions, it can be concluded that the maximum output current limit of the photovoltaic inverter (Imax) has been set to 1.1 IN and the orthogonal decomposition method been used during the fault; the strategy of adjusting the active current output according to the immediate recovery method used during the recovery period can most effectively cope with various degrees of voltage drop faults in the system and improve the transient frequency stability of the system.

Conclusions
In this article, a transient simulation model of a grid-connected photovoltaic (PV) generator with low-voltage ride-through (LVRT) capability is proposed. A power system model with a high PV penetration is established, and several types of three-phase volt-

Conclusions
In this article, a transient simulation model of a grid-connected photovoltaic (PV) generator with low-voltage ride-through (LVRT) capability is proposed. A power system model with a high PV penetration is established, and several types of three-phase voltage sags are simulated in PowerFactory/DIgSILENT. According to the three power indexes, namely the maximum active power of PV unit during the fault, the power improvement gradient and the power surge after the fault is cleared, the impact of the active current reference calculation method and the inverter allowable maximum inverter current (I max ) on the PV active power output is assessed. Additionally, methods to improve the active power output capability of photovoltaic units during low-breakthrough periods are explored. The conclusions are as follows: (i) The active current control strategies have minimal effect on the voltage for gridconnected PV generation systems at the point of common coupling, so the PV transient active power has the same change in trend as the transient active current during grid fault. Effective performance for active power (P) support is attained by choosing the appropriate calculation method of active current and I max value when voltage faults are introduced to the utility grid. It is carried out to meet the requirement of reactive powers (Q) support capability in China grid codes. (ii) The error between the inverter current limitation (I max ) and reactive current is compared to obtain the active current values within the limits of the same value of I max .
Applying the orthogonal decomposition method to calculate the active current reference enhances the utilization factor of the inverter's capacity and increase the inverter active output current. It improves the active power shortage and boosts the transient stability of the power system. (iii) Increasing I max value can reduce the active power shortage during grid faults by increasing the active current output and improving the oscillation phenomenon in power recovery by reducing the excitation increment of active current and active power at the moment of fault clearing. However, increasing I max value proportionally does not bring about an equal gradient of active power improvement effect, and the