1. Introduction
Over the past two decades, distributed generation (DG) using renewable energy sources, more specifically the generation of photovoltaic energy, has become one of the most promising new technologies. In Brazil, this has been happening since 2012 [
1,
2,
3]. Due to the increasing adoption of this resource, grid-connected photovoltaic systems (GCPVS) are developing at a very fast pace and will soon be a large part of energy generation in some regions [
1,
4]. In view of this fact, many countries have established new requirements grid code (GCs) for GCPVS to remain connected during some fault. Its disconnection during faults can cause problems related to stability, reliability, and operation of the power system being attended to by the GCPVS [
5]. As a result, there is a change in the dynamic behavior and impact in the distribution grid which is being inserted [
4,
6,
7,
8].
The new connection requirements highlight that GCPVS avoid a high loss of energy and remains connected on grid in the event of a voltage sag. This capacity is known as the low-voltage ride through (LVRT) capacity. Recent studies have compared the LVRT requirements for photovoltaic plants connected on grid in different GCs in [
1,
4,
9,
10]. Some countries have proposed and implemented these connection requirements for the LVRT [
1,
11,
12]. In addition, governments for the purpose of increasing the penetration of GCPVS into the energy matrix of each country introduce some incentive rules and regulations, connecting them to low-voltage and medium-voltage distribution grids such as DG [
11,
12]. Due to greater use, several studies have shown great interest in the operation of the distribution grid with better participation of DG in the energy matrix. Furthermore, when it comes to this participation in the voltage control in steady state, benefits can be observed such as the increase of the hosting capacity, the reduction in the voltage drop, and the load loss [
11].
According to the version of IEEE 1547–2003, at the point of interconnection, DG (including solar photovoltaic generators) cannot actively participate in voltage regulation, controlling the reactive power on grid [
12]. From the update and approval of IEEE 1547–2018, the distributed generators can actively participate in grid voltage support, thereby providing reactive power compensation [
13].
In the technical literature, it is possible to find several researches integrating the photovoltaic system to the distribution grid. At the same time, researchers discuss methods for the management and control of active and reactive power. It is worth mentioning that the control of reactive power is one of the important requirements for the stability of the distribution grid. Therefore, in reference [
14], the authors proposed a photovoltaic inverter with the capacity to supply active power and compensate reactive power simultaneously, modifying the phase angle of the output voltage.
A method of reactive power control is discussed by [
15], which has as a characteristic the efficient use of reactive power management when connected to a critical bus in the distribution grid. The method increases voltage regulation and improves the reverse flow of energy of a distribution system with high penetration of RE sources, while it efficiently uses the reactive power capacity of the photovoltaic inverter.
In [
16] a plan is presented for reactive energy compensation in the transmission and distribution buses with the help of distributed generation and without the use of additional reactive power compensators. Reference [
17] presented a new method to improve active power control, reactive power compensation, and power quality improvement of a GCPVS using a DC-DC converter cascade and a PWM (pulse width modulation) inverter.
To solve the problems of overvoltage on the DC bus and overcurrent on the AC side caused by voltage sags, some authors [
1,
18] discussed a control strategy to improve the LVRT operating capacity for single-stage photovoltaic plants based on Malaysian standards. This control also proposes to solve the problems that cause disconnection or damage to the inverter and only reactive power injection during symmetrical and asymmetric faults. In another paper presented by [
19], the author describes an LVRT control strategy for low-voltage three-phase GCPVS. This strategy uses, as a base, the inverter ability to remain connected during a voltage sag. During asymmetric faults, the inverter injects reactive power and the control prevents the maximum power point tracking (MPPT), but guarantees a smooth transition between the two methods, both with and without MPPT. In addition, reference [
19], highlights Brayton–Moser’s mixed potential theory and injects only reactive power during faults.
In [
12], the authors proposes a mathematical methodology to derive the active and reactive power capacity curve of a photovoltaic system. Their technique manages the injection of reactive power into a grid at maximum power for various environmental conditions. As a result, it was possible to determine reactive power limits for single-phase and three-phase systems connected to the 33-bus IEEE distribution grid.
The authors [
4], suggest a theoretical solution method and a calculation model for analyzing PV power fault transient and steady current by taking into account the DC bus voltage fluctuation and the influence of unloading circuit during LVRT. They used an inverter, with a DC/DC and DC/AC converter, and its behavior was analyzed during symmetrical and asymmetrical faults.
It was discussed in [
10] a solution for asymmetric faults considering the LVRT control, makes a comparison of several heuristic algorithms and uses an adaptive differential evolution (ADE) algorithm to reliably obtain the voltage controller parameters, during both the transient and steady-state process.
Finally, to demonstrate the relevance of the subject, which deals with reactive compensation and voltage controls in the distribution network, reference [
20] presents an important paper titled “Review of Voltage and Reactive Power Control Algorithms in Electric Distribution Networks”. They provide a bibliographical overview of the mathematical methods used for the optimal choice and positioning of reactive power compensation elements. Furthermore, the authors present the advantages and disadvantages of all methods they have researched.
Although the previous methods can provide reactive power control, they have the disadvantages of several additional components that incur extra costs and do not address the problem of identifying the best balance point between powers during the voltage sags. Therefore, when researching three-phase GCPVS applications in DG, few papers have sufficiently explored the LVRT strategy to deal with the fault and none of them used the technique proposed in this research. Besides, when it comes to GCPVS to contribute during voltage sags while providing voltage level support, it can simultaneously inject active and reactive power without sacrificing the total active power injection. It is worth noting that this issue has not yet been explored in the literature. Therefore, the main objective of this research is to propose an active and reactive power injection control during voltage sags, which was implemented in a 75 kW three-phase GCPVS so as to mitigate disturbance and contribute to ancillary services on grid.
An improvement in the control of active power injection while the reactive power is injected to help sustaining the voltage in the point of common coupling (PCC) during the short-duration voltage variation (SDVV), more specifically, the momentary voltage dip (MVD). Thus, the control of active power injection works in conjunction with the automatic voltage regulator (AVR) in a modified version. The modifications in AVR model and parameters are implemented for faster dynamics, therefore identifying the MVD and, consequently, the control acts altering the powers so that to decrease the active power injection and increase the reactive power based on the inverter total capacity. Consequently, the control will avoid possible shutdowns and damage to equipment connected on grid and improvement will also be observed in the consumers’ bus voltage levels.
To achieve these objectives, the 75 kW GCPVS, with the proposed control, was implemented on Matlab/Simulink®. Such power system comprises part of a real distribution grid in the city of Palmas, which belongs to Tocantins state, in the northern region of Brazil.
It was possible to notice that the references [
4,
14,
15,
16,
17], which relate the reactive compensation provided by GCPVS, are associated with voltage regulation in a steady-state and not in a transient state, as they solve voltage drop but not voltage sag problems. In addition, the papers prioritize the two-stage PV system (DC-DC converter and DC-AC converter) and not a single stage one (only DC-AC converter) which offers lower operating losses.
Regarding the papers [
1,
4,
18,
19], they recommend a control which works only with reactive power injection during LVRT operation condition (that is, during voltage sags for symmetrical and asymmetrical faults). Therefore, the PV system is subject to overvoltage on the DC bus. On the other hand, this paper proposes a control which is able to inject active and reactive power during LVRT, so the DC bus overvoltage problem is mitigated for active power injection. It is worth noting that the active power will decrease with the intensity of the voltage sags.
It is highlighted that the inverter MPPT is disabled during voltage sags (LVRT operation) in work [
19]. Conversely, the control proposed in this paper keeps the MPPT always in activity, since the active power continues in operation.
Reference [
12] needs to derive the active and reactive power curves to perform the reactive compensation, however, this strategy demands a high processing capacity, thus increasing the simulation time. In turn, the control here proposed generates the reactive power reference in a more simplified way (that is, by the difference between the total (apparent) power and the active power). In addition, the employed simulation data come from a real distribution grid.
In [
10], the authors worked only with asymmetrical faults with an adaptive differential evolution (ADE) algorithm. This paper, however, proposes a novel method for controlling the active and reactive powers, which has not been used in any technical research, since the AVR is used manage the inverter capacity, by reducing active power to make space for reactive power injection when needed. Such technique was not mentioned in the paper review [
20].
In relation to the other methods aforementioned, this proposed seeks to optimize the best distribution of active and reactive power injection at the time of the voltage sag. To do so, the inverter active power is decrease so as to increase the injection of reactive power during the MVD. Such procedure, improves the voltage levels for consumers in the local distribution grid. Finally, when the fault ceases, the GCPVS turns to inject only the active power on grid, as shown in
Figure 1.
This paper consists of six sections. First, in the introduction, the main methods in the technical literature related to the subject are presented. The second section is used to model the GCPVS including controlling the inverter. The third section deals with the proposed control for the injection of active and reactive powers. In the fourth section, the distribution grid used for the simulations is presented. The performance evaluation of the proposed SDVV/MVD control is carried out in the fifth section. The last section covers the final considerations on the results of this work.
5. Results and Discussions of SDVV/MVD Control
In order to carry out tests and simulations, the complete GCPVS model was implemented together with the proposed control for SDVV/MVD on the Matlab/Simulink® computing platform. For the case study, the moment of highest consumption of electricity in the Palmas distribution grid and without the presence of the photovoltaic DG was chosen. Thus, as referred to above, the collected data such as voltages, currents, powers, and power factors are real measurements provided by the local electric power utility.
As already mentioned, the day and time chosen were the ones that represents the highest energy consumption without DG. For this condition, the readings presented the following values: a voltage magnitude of 13.63 kV, and powers of 2.6815 MW, 1.5907 MVAr, and 3.1178 MVA (PF = 0.8601) at the power supply 2 of Palmas III. All of these data, together with the information in
Table 2,
Table 3 and
Table 4, were included in the simulation.
Then, the GCPVS was connected to the T_12 three-phase secondary transformer and the values of voltage, current, and instantaneous power in PCC B_12 were measured.
To meet the SDVV requirements established in Brazilian standards, the proposed control will keep the GCPVS connected. In this way, it continues injecting the available amount of active and reactive power to mitigate a voltage sag, as described in
Section 3.
It is worth pointing that ANEEL does not yet allow small photovoltaic systems to remain connected when there is a lack of synchronism with on grid, nor do they contribute with ancillary services to the distribution grid.
From now on, the results of the GCPVS dynamic voltage support for SDVV/MVD will be presented.
The
Figure 7 shows the behavior of the three-phase voltages and currents at the PCC B_12, in relation to phase-ground. Notice that the secondary transformer voltage levels are 211.6 V RMS, which are below nominal voltage 220 V. This occurs due to the substation voltage, which is also below nominal, around 13.63 kV, and such a condition reflects throughout the system.
Figure 8a shows the RMS values corresponding to the voltages and
Figure 8b shows the values for the currents. Since the voltages are still higher than 0.9 p.u. of the nominal voltage (
Vnom = 220 V), the inverter must remain connected without the injection of any reactive power. In addition, the active power must remain in full generation according to the climatic conditions.
After checking and validating the conditions of the implemented grid without the GCPVS, from now on, one GCPVS (75 kW) was inserted in the simulation with the proposed control. It was inserted at a strategic point that guarantees an irradiance of 1 kW/m² and, consequently, a generation of 75 kW. It is worth mentioning that the chosen location presents a possibility for the expansion of the photovoltaic system, since in this location, there is a municipal school and a public area destined to the free market. Such place is located in parallel to the RLC_12 load, both connected to the PCC B_12 bus, and this is connected to the transformer secondary T_12. In this PCC, the low voltage level corresponds to 380/220 V, where it will be possible to check the instantaneous current, voltage and power values, for the next tests.
A short-circuit was also inserted between the B_15 bus and to the primary transformer T_16. This will be responsible for the faults or voltage sag in the distribution grid. For this first situation, a phase-to-ground short-circuit in phase B was inserted at this location. At the moment of the short-circuit, voltage sag into the grid will be 0.4 s duration, i.e., more than 20 cycles, as determined by ANEEL, in module 8 of PRODIST [
29].
Figure 9a shows the voltages in bus B_12 when there is short-circuit without DG. The fault occurs in the instant of 1 to 1.4 s, with the parameterization of fault resistance (component that causes the short in Simulink) in
Ron of 0.001 Ω and ground resistance
Rg of 0.001 Ω. This way, it becomes possible to verify that the voltage of phase A drops 33 % of
Vnom passing to 147.2 V, while phase B decreases to 178.6 V and, finally, phase C remains at 211.6 V.
With the insertion of the DG combined with the action of the proposed control,
Figure 9b shows an improvement in voltage levels, thus, the
Va voltage resulted in 156 V,
Vb in 186.6 V, and
Vc in 219.7 V.
Therefore, taking into account the existence of the load connected to the PCC and that the 75 kW GCPVS (considered to be a microgenerator by ANEEL [
34]), the results are quite promising, as expected.
It is worth noting that short-circuit is in phase B, but phase A is the one which suffered the greatest voltage sag at the time of the fault for the situations presented. This happens due to the connections of the transformer, where the primary is in Delta (D1) and the secondary is in grounded star (Yg). There is an inversion in the phases as presented by IEC 60076-1 [
35].
Figure 10 shows the three phase voltage waveforms PCC B_12 and points the peak values. The period from 0.8 to 1.6 s was used for a better visualization of the short-circuit effect.
Figure 10a is without GCPVS operation and
Figure 10b is with GCPVS operation. The GCPVS acts to improve the voltage amplitudes, which can be confirmed by the RMS voltage values in
Figure 9.
Figure 11 shows the behavior of the currents in B_12 and GCPVS with the fault situation.
Table 5 was set up from
Figure 11 in order to make possible the visualization of the current levels of the phases for two instants: at time 1.39 s, at the end of the short-circuit period, and at time 2.5 s, after returning to steady state.
Figure 11a shows the condition without GCPVS on B_12, while
Figure 11b shows the condition with GCPVS on B_12, and finally
Figure 11c shows the currents at the GCPVS output, according to the power available from the photovoltaic modules. It is important to remember that the load consumes powers according to
Table 3.
In sequence,
Figure 12 shows the behavior of the active and reactive power on B_12 and on the inverter output.
Figure 12a shows the grid behavior without GCPVS and that the RLC_12 load absorbs from into the grid, 48.15591 kW of active power and 28.57404 kVAr of reactive power. In
Figure 12b the behavior on B_12 is shown with the insertion of the GCPVS, which becomes responsible to supply all the active power required by the load, with the remaining power injected into the distribution grid. The powers reading in
Figure 12b configure this action, since its negative signs proves the injection into the grid. When the fault occurs,
Figure 12c indicates that the active power decreases to allow the injection of the reactive power to contribute to sustaining the voltage in the PCC. It is possible to observe this performance of the GCPVS, with the proposed control, in
Figure 9b and
Figure 10b and
Figure 11b,c, as previously analyzed. Also in
Figure 12c, it is possible to see that approximately 75.6 kW of active power supplied by GCPVS decreases to around 23.85 kW after the fault (69 % drop). Further, in the same figure, the reactive power increases from 0 to 71.35 kVAr, thus helping to raise the voltage level of into the grid and the load. When calculating the apparent power, which corresponded to 75.23 kVA, it is capable of confirming that the rated power of the GCPVS was not exceeded.
Figure 13 shows the behavior of the RMS phase voltages in per unit (p.u.). It is important to mention that all per-unit values will be from now on corresponding to rated RMS phase voltage of 220 volts. Thus, when making a parallel with what was observed in
Figure 9, the voltages are at 211.6 V (0.962 p.u.) and still far from 198 V (0.9 p.u., referring to
Table 1). In this sense, the proposed control does not act until 1 s. When short-circuit appears, the voltage decreases to 0.81 p.u., below the limit 0.9 p.u. This situation causes the control to enforce a reduction in its output that will multiply the reference power (
Pref), as explained in
Section 3. This, in turn, will decrease the active power injected by the inverter to manage reactive power and thus contribute to increase the voltage level during the fault. After the fault disappears at time 1.4 s, the GCPVS returns to its normal condition.
Figure 9,
Figure 10,
Figure 11 and
Figure 12 also reveal such GCPVS behavior.
On the sequence,
Figure 14,
Figure 15,
Figure 16 and
Figure 17 show the other test results of the proposed control for different voltage sag (or fault) scenarios and different durations. In each figure, there are five graphics to show the behavior of voltages, powers, and the control, which are placed in the same order as the previously analyzed case,
Figure 9,
Figure 10b,
Figure 12c and
Figure 13.
In
Figure 14, the disturbance into the grid is caused by a phase-to-phase short-circuit between B_15 and T_16, with duration of 500 ms. Analyzing for the same locations previously proposed. This fault reduces the voltages in the PCC to 189 V in phase A and 181 V in phase C, while for phase B, it reduced to 57 V. For this situation, RMS voltage into the grid had an average drop of 34 % of the rated voltage. Therefore, during the fault period (1–1.5 s), the GCPVS should provide to the grid adequate amounts of reactive and active power during the whole interval to help the voltage recovery. Once the voltage sag is eliminated, all variables return to the pre-fault values.
It is worth remembering that from
Figure 9,
Figure 10,
Figure 11,
Figure 12,
Figure 13,
Figure 14,
Figure 15,
Figure 16 and
Figure 17, the conditions on power grid in the periods of fault are stable. In this way, the GCPVS can withstand the fault and inject the necessary amounts of active and reactive power, even for a prolonged period, without the action of anti-islanding protection.
Figure 15 shows the response of the proposed control. When an asymmetric two-phase-to-ground fault occurs, phase A voltage drops to 171.5 V, phase B to 169.1 V, and phase C to 46.24 V during the fault period of 625 ms (duration used by the references [
1,
9,
18,
36]).
It is possible to verify for such an event that the insertion of the proposed control reduces the voltage sag. Therefore, it reflects in the increase of the voltage levels in more than 6.7 % for phase A, 26.5 % for phase B, and 4.8 % for phase C. The active power decreases to about 15 kW and the reactive power increases to 72 kVAr. Finally, the average value of into the grid voltage increases from 0.58 p.u. without GCPVS to more than 0.63 p.u. with GCPVS at the time of the fault.
In the sequence,
Figure 16 and
Figure 17 describe a symmetrical three-phase-to-ground short-circuit, which is the most severe case of voltage sag. Two situations will be presented, the first (
Figure 16) with the GCPVS equipped with the proposed control, while for the second (
Figure 17), there is a situation with the GCPVS without the proposed control action. In this case, likewise presented by the references [
1,
18] the inverter will provide the maximum reactive power capacity into the grid just after it notices the fault. For these two situations, the average value of voltage into the grid falls to 0.21 p.u. of the rated voltage.
It is possible to notice that there are advantages and disadvantages in these two situations. In the first situation,
Figure 16, with the control acting, the voltage level into the grid will remain a little higher than the second situation, since there is a portion of active power injection together with reactive. In this way, the control identifies the best point the powers, for the purpose of reducing the effects of voltage sags. In the second situation,
Figure 17, without actioning the proposed control, the voltage level is lower. Consequently, there is no possibility to improve it, since the control injects only reactive power.
Thus, it is safe to say that the proposed control contributes to mitigate the effects of SDVV/MVD. This happens due to the fact that when injecting active and reactive power into different types of faults, the voltages increase to close to the ideal, while in the other works with only reactive power injection the voltage level is lower than the values investigated by this research. It can be seen that the results of the power graphs require 0.5 s to enter the steady state.
It is worth remembering that this 75 kW GCPVS is considered by ANEEL to be a microgenerator [
34]. Therefore, if there were several of DG spread throughout the distribution grid, there would certainly be a more adequate support to the voltage levels during SDVV/MVD.
In order to explore the results in a quantitative way,
Table 6 shows the results of the short duration voltage variation for each case investigated.