Control strategy used for AC fault ride-through in VSC

Abstract

Fault ride-through (FRT) is a very important requirement for power grids based on voltage source converters (VSCs) to improve its operational availability of the AC grid. Grid codes require VSC stations to incorporate fault handling capabilities to prevent disconnection of converter stations from the alternating current (AC) grid for certain fault characteristics. In this paper, an FRT strategy is used in the two converter stations to handle the faults that may occur in the AC part of the grids and ensure their stability. The method improves the performance of the FRT compliance strategy during a voltage drop in the AC side. In addition, a current control that operates simultaneously on positive and negative sequence current is adopted. It also allows the injection of a reactive current to maintain the availability of the high-voltage direct current (HVDC) converter station during a fault. The performance and stability of the suggested FRT control is tested considering the direction of power flow with possible faults in balanced and unbalanced regime. For the validation of the efficiency of the FRT capacity, simulation tests are carried out with MATLAB-Simulink software, and experimental tests with a Smart-grid test bench.

Keywords

Voltage source converter HVDC voltage sag fault ride-through

Introduction

The growth of population and the huge evolution of industry in the world are two factors responsible for the increase in the consumption of electrical energy. The excessive demand for energy, pollution and the impact on climate change as well as the cost of electricity production push countries to seek other sources such as photovoltaics and wind turbines which are far from agglomerations (Bo et al., 2018). In addition, the world is seeking to strengthen interconnections to increase the reliability of electricity grids and facilitate energy exchanges between countries (Shuxin et al., 2022). However, alternating current (AC) transmission with submarine cables produces a significant amount of reactive current due to its high capacitance, which requires reactive power compensation devices (Bo et al., 2017). Also, the development and interconnection of grids on a national and international scale requires transport over long distances, which increases stability problems. Research work is being developed on the grids to ensure the availability of electrical energy with good quality, which is the concern of the consumer. Today, the majority of high-voltage power transmission lines in the world are AC, but innovations in recent years are yielding very efficient results with direct current (DC) transmission. The power generated in the power generation units is transmitted to the loads via a high-voltage direct current (HVDC) conversion chain due to reduced power losses, improved grid security and reliability. The HVDC grid has a set of advantages compared to the HVAC (high-voltage alternating current) grid such as low loss in the transmission line, low rate of harmonics of the currents, and reduced cost for the construction of the conversion/transport chain (Bingbing et al., 2021; Md Ismail and Mohammad, 2022).

HVDC transmission became attractive with the advent of mercury switches in the 1950s for long distance transmission compared to AC transmission. The first experience is the interconnection between Sweden and the island of Gotland over a distance of 96 km via an undersea cable with a nominal voltage of 100 kV and a capacity of 20 MW. The evolution of power switches makes it possible to reduce the reduced cost of converters, which opens the horizon for the use of HVDC. HVDC technology tends to be more economical for distances greater than 600–800 km for overhead lines and 60–80 km for submarine transmissions (Oriol et al., 2011). Recently, the most common technology is current source converter (CSC) based on thyristors, but after the innovation of voltage source converter (VSC), which uses semiconductor switches as gate-blocking thyristor (GTO), insulated gate bipolar transistor (IGBT), and pulse width modulation (PWM) technology, there is a growing trend of using this VSC topology in HVDC transmission systems (Muniappan, 2021). The VSC–HVDC system also allows bi-directional power flow and independent control of active and reactive power, which reduces the need for reactive power compensation and can contribute to AC grid stabilization (Javad et al., 2018; Jinghua et al., 2018). With these advantages, VSC–HVDC transmission technology has been increasingly applied in recent years.

The challenge for HVDC transmission for VSC type converters is the ability to handle the faults created in the AC grid (Ahmed et al., 2016). Grid codes require that the VSC–HVDC station remain connected to the grid and continue to operate stably ensuring the best possible grid operation (Hossain and Abido, 2020). This is achieved through fault management capabilities at the VSC station. The fault ride-through (FRT) system must react and guarantee the normal operation of VSC–HVDC transmission in the event of the appearance of faults. Fault scenarios can be symmetrical as voltage drop and asymmetrical in case of short circuit. The analysis demonstrates the importance of keeping HVDC systems powered up during fault disturbances to avoid power interruption, which can lead to serious stability issues. Besides, Yiyan et al. (2019) developed a nonlinear adaptive control (NAC) based on disturbance estimation for improving the FRT capability of VSC–HVDC systems. NAC control only requires measurement of active and reactive power and DC voltage, making real-time grid implementation easy. The effectiveness of the strategy is verified with simulations as voltage sags and faults between lines. The controller compensates the disturbance in real time and provides optimum performance on system operation. Therefore, a new method (Sun et al., 2016) has been developed based on FRT method for an offshore wind system (OWF) connected to the electrical grid through a VSC–HVDC. This method made it possible to reduce the power of OWF by reducing the voltage of the offshore grid. The power reduction allows the protection of the HVDC system against DC overvoltages. The disadvantage in this strategy is in the case of a voltage sag at the grid level connected to the OWF. Two FRT mechanisms were installed (Saman Dadjo et al., 2021), one in the DC voltage control and the other in the active power loop based on the use of the components of positive and negative sequence. The aim is to ensure stable operation of the HVDC system in the event of faults in the AC grid located on both sides of the converters. For the simulated fault scenarios, the HVDC link reaches its stable equilibrium point which gives the efficiency of FRT mechanism. To consolidate the results of this paper, an experimental validation of the simulation tests is necessary. Mario et al. (2017) proposes an improved FRT control strategy for an AC grid connected via an offshore wind farm using a VSC–HVDC link. The proposed method is based on simultaneous control of the positive and negative current sequences in the AC portion under balanced and unbalanced conditions. The control also includes a low-voltage ride-through (LVRT) loop that will be activated once the voltage drops below a threshold of 0.9 pu for reactive current injection. This method is effective in asymmetric operating conditions, but the FRT loop is installed on only one side of the grid. In this case, power flow control is from the offshore wind field to the AC grid. The objective of the work presented in this article is to install two FRT loops for the two VSCs.

The main contribution of this article is to propose an FRT control strategy for a VSC–HVDC link during symmetrical and asymmetrical faults in an AC grid. The strategy is based on simultaneous control of the positive and negative current sequences in the AC grid under both balanced and unbalanced conditions. The control of each converter is reinforced by an LVRT loop that responds to voltage sag. Simulations were performed using Matlab-SIMULINK and tested on a smart grid test bench with symmetrical and asymmetrical fault scenarios.

This paper is organized as follows: The section “VSC–HVDC modeling” of this paper deals with the description of the studied system as well as the mathematical development of the VSC–HVDC system. The section “VSC–HVDC system control” describes the control strategy used and the modifications made. In the section “Simulation and experimental results”, simulations, experimental results, and interpretations of the results are given. Finally, the section “Conclusion” gives a conclusion that summarizes the content of this paper.

VSC–HVDC modeling

The study model shown in Figure 1 is a point-to-point VSC–HVDC grid. VSC1 is connected with grid 1 via a resistance R1 and an inductance L1, similarly VSC2 is connected with grid 2 by a resistance R2 and an inductance L2. C1 and C2 are DC bus capacitors on the VSC1 and VSC2 side, respectively. The two stations are connected by a DC line which is equivalent to an inductance L and a resistance R.

The converters used in this transport chain adopt the VSC–HVDC topology. The basic component of these converters is a static switch capable of establishing and interrupting a current unlike the thyristor. The IGBT static switch is commonly used in this topology. A free-wheeling diode is connected in antiparallel with this unidirectional current switch to ensure its passage in both directions.

According to Dalia et al. (2021) and applying Kirchhoff’s law, the mathematical model of the system is expressed as follows

{\begin{matrix} L_{1} \frac{d i_{g 1, abc}}{dt} = - R_{1} i_{g 1, abc} + v_{g 1, abc} - v_{1, abc} \\ L_{2} \frac{d i_{g 2, abc}}{dt} = - R_{2} i_{g 2, abc} + v_{g 2, abc} - v_{2, abc} \end{matrix}

(1)

{\begin{matrix} i_{DC 1} = C_{1} \frac{d v_{DC 1}}{dt} + i_{DC} \\ i_{DC 2} = C_{2} \frac{d v_{DC 2}}{dt} - i_{DC} \end{matrix}

(2)

The indices 1 and 2 correspond, respectively, to the variables of the converters VSC1 and VSC2. $v_{DC 1}$ , $v_{DC 1}$ are DC voltages on the VSC side, abc are three grid phases,

Without considering the switching losses in the converters, the active ( $P_{g 1}$ and $P_{g 2}$ ) and reactive ( $Q_{g 1}$ and $Q_{g 2}$ ) powers can be expressed in terms of direct and quadrature axis voltages and currents as given below (Baazouzi and Bacha, 2021; Md. Shafiul et al., 2021)

{\begin{matrix} P_{g 1} = \frac{3}{2} (v_{g 1, d} . i_{g 1, d} + v_{g 1, q} . i_{g 1, q}) \\ Q_{g 1} = \frac{3}{2} (v_{g 1, q} . i_{g 1, d} - v_{g 1, d} . i_{g 1, q}) \\ P_{g 2} = \frac{3}{2} (v_{g 2, d} . i_{g 2, d} + v_{g 2, q} . i_{g 2, q}) \\ Q_{g 2} = \frac{3}{2} (v_{g 2, q} . i_{g 2, d} - v_{g 2, d} . {i_{g}}_{2, q}) \end{matrix}

(3)

With synchronization by the PLL (phase-locked loop) and following the alignment of the voltages with the q axis, the grid voltages $v_{g 1, q}$ and $v_{g 2, q}$ become equal to zero. This translates into independent control of active and reactive power (Xiaodong et al., 2021; Yuhang et al., 2022)

{\begin{matrix} P_{g 1} = \frac{3}{2} v_{g 1, d} . i_{g 1, d} \\ Q_{g 1} = - \frac{3}{2} v_{g 1, d} . i_{g 1, q} \\ P_{g 2} = \frac{3}{2} v_{g 2, d} . i_{g 2, d} \\ Q_{g 2} = - \frac{3}{2} v_{g 2, d} . i_{g 2, q} \end{matrix}

(4)

The mathematical model of the VSC–HVDC system after passage by Park transformation of equation (1) with the angular frequency w is expressed as follows

{\begin{matrix} L_{1} \frac{d i_{g 1, d}}{dt} = v_{g 1, d} - v_{1, d} - R_{1} i_{g 1, d} + w L_{1} i_{g 1, q} \\ L_{1} \frac{d i_{g 1, q}}{dt} = v_{g 1, q} - v_{1, q} - R_{1} i_{g 1, q} - w L_{1} i_{g 1, d} \\ L_{2} \frac{d i_{g 2, d}}{dt} = v_{g 2, d} - v_{2, d} - R_{2} i_{g 2, d} + w L_{2} i_{g 2, q} \\ L_{2} \frac{d i_{g 2, q}}{dt} = v_{g 2, q} - v_{2, q} - R_{2} i_{g 2, q} - w L_{2} i_{g 2, d} \end{matrix}

(5)

The power conservation with negligence of the losses in the converters VSC1 and VSC2, the currents $i_{DC 1}$ and $i_{DC 2}$ are given by equation (6) (Ayari et al., 2019)

{\begin{matrix} i_{DC 1} = \frac{3}{2} \frac{v_{g 1, d} i_{g 1, d}}{V_{DC 1}} \\ i_{DC 2} = \frac{3}{2} \frac{v_{g 2, d} i_{g 2, d}}{V_{DC 2}} \end{matrix}

(6)

The variation of DC voltage in each side of the DC line is given by equation (7)

{\begin{matrix} \frac{d v_{DC 1}}{dt} = \frac{3}{2} \frac{v_{g 1, d} i_{g 1, d}}{C_{1} V_{DC 1}} - \frac{i_{DC}}{C_{1}} \\ \frac{d v_{DC 2}}{dt} = \frac{3}{2} \frac{v_{g 2, d} i_{g 2, d}}{C_{2} V_{DC 2}} + \frac{i_{DC}}{C_{2}} \end{matrix}

(7)

where $v_{g 1 d}$ and $v_{g 1, q}$ are the d-axis and q-axis components of the terminal voltage of grid 1, respectively; $v_{g 2, d}$ and $v_{g 2, q}$ are the d-axis and q-axis components of the terminal voltage of grid 2, respectively; $v_{1, d}$ and $v_{1, q}$ are the d-axis and q-axis components of the VSC1 side voltage, respectively; $v_{2, d}$ and $v_{2, q}$ are the d-axis and q-axis components of the VSC2 side voltage, respectively.

VSC–HVDC system control

The VSC–HVDC system is based on the control of energy transfer flow between electrical networks with active and reactive power control. Strategies used for VSC–HVDC control are direct power control (DPC) and voltage-oriented control (VOC; Jie et al., 2014; Walter et al., 2019). The DPC is used for instantaneous active and reactive power regulation with the switching states of the converter being selected by a switching table based on the instantaneous errors between the commanded and estimated values of active and reactive power. The disadvantage of this type of control is the need for rapid calculation with variable switching frequency. VSC–HVDC voltage control is widely used in converter control. It contains an internal current control loop and a PWM modulator block, which allows to obtain an independent control of the active and reactive powers. This control technique is based on the use of proportional–integral (PI) regulators, which will be used in this article.

The VSC–HVDC link consists essentially of a converter station, which converts the alternating voltage of the conventional electrical grid into direct voltage, a transmission line, and a second converter station, which is located at the other end and converts the DC voltage it receives into alternating voltage (Baazouzi et al., 2022). The VSC1 converter station supports DC bus voltage regulation, while the VSC2 station controls the power flow between two grids by modifying the reference power control (Abhimanyu and Dirk, 2019). For the VSC1 rectifier station, the control loop ensures the DC voltage regulation of the transmission line and keeps the input power factor close to unity. In the case of the VSC2 inverter station, active and reactive power control is carried out. In general, the control system contains two loops, one external and the other internal. The outer loop is used to control the output power to meet the system needs and the inner loop allows the control of the output current to follow the reference coming from the outer loop (Atiq et al., 2019; Xiaojun et al., 2016).

The VSC control scheme contains five blocks:

Measurement and transformation

Phase-locked loop

External loop

Internal loop

PWM module

Control of VSC1 and VSC2

The behavior of the system is governed by equation (5), the two VSC model is a nonlinear system with multiple inputs and multiple outputs that are strongly coupled. Achieving a linear clipped control is difficult to achieve. The equations comprise for each axis a term that couples the speed and the frequency, which generates a disturbance for the control. The decoupling of the currents in the two axes d at q can be achieved by using PI regulators, which require knowledge of the angle θ_PLL (Antonio et al., 2013). The independent operation on the d and q axes, one of the important characteristics of vector control (Baazouzi and Bacha, 2019) is given by

{\begin{matrix} v_{1, d} = - (k_{p 1} + \frac{k_{i 1}}{s}) (i_{g 1, d}^{ref} - i_{g 1, d}) + w L_{1} . i_{g 1, q} + v_{g 1, d} \\ v_{1, q} = - (k_{p 1} + \frac{k_{i 1}}{s}) (i_{g 1, q}^{ref} - i_{g 1, q}) - w L_{1} . i_{g 1, d} + v_{g 1, q} \end{matrix}

(8)

{\begin{matrix} v_{2, d} = - (k_{p 2} + \frac{k_{i 2}}{s}) (i_{g 2, d}^{ref} - i_{g 2, d}) + w L_{2} . i_{g 2, q} + v_{g 2, d} \\ v_{2, q} = - (k_{p 2} + \frac{k_{i 2}}{s}) (i_{g 2, q}^{ref} - i_{g 2, q}) - w L_{2} . i_{g 2, d} + v_{g 2, q} \end{matrix}

(9)

where ( $k_{p 1}$ , $k_{i 1}, k_{p 2},$ $k_{i 2}$ ) are the proportional and integral gain of the AC voltage regulator ( $i_{g 1, d}^{ref}$ , $i_{g 1, q}^{ref}$ , $i_{g 2, d}^{ref},$ $i_{g 2, q}^{ref}$ ) used to identify the references currents.

From equations (8) and (9), an internal control loop that uses PI regulators produces a voltage reference of the converters. The control purpose of VSC1 is to maintain constant DC bus voltage and reactive power control (Marius et al., 2018). For the external loop, the generation of $i_{g 1, d}^{ref}$ is obtained by the difference between the DC bus voltage V_DC1 with the reference voltage V_DC1ref applied to a PI regulator. VSC1 generally operates with unity power factor, which makes the reference reactive current $i_{g 1, q}^{ref}$ zero (Fang et al., 2014). The internal control loop for VSC2 is implemented in the same way as the internal loop of VSC2. For the reference currents, $i_{g 2, d}^{ref}$ and $i_{g 2, q}^{ref}$ are generated, respectively, from the comparison between the active and reactive powers with their reference active and reactive power. For each internal loop, its output is the reference voltage of the converter, which will be used to generate the PWM signal after dq-abc transformation. The control loops for the two converters are represented by the following Figure 2 (Jian and Haifeng, 2012; Xinyin et al., 2015).

However, a big challenge for the VSC–HVDC system is the ability to manage faults in abnormal conditions of the AC grid. This article studies the need for injection of additional reactive current to maintain the grid voltage during voltage sags.

FRT method

Each country has its grid code that requires a well-defined standard for production systems to remain connected during a voltage drop for a well-defined time. This requirement, called LVRT, to ensure an ability to avoid interruption during a grid outage. Another grid code requirement is reactive power compensation during AC voltage sag (Tlili et al., 2020). For a grid-level fault, dynamic voltage regulation is also required and reactive power injection is performed. The VSC converter should provide reactive current compensation when the voltage deviation exceeds the threshold value ΔU, the relationship of the reactive current injection level with the voltage deviation is shown in Figure 3. According to the grid code for a drop of 0.1 pu in the nominal AC voltage, a reactive current must be supplied to the AC grid (Yiyan et al., 2019). Improvement of the control loop by generating a reactive current in the event of a remarkable voltage drop ΔU. If ΔU exceeds ±0.1 pu, a reactive current variation will be realized. If the voltage differences have a negative ΔU (LVRT), a capacitive reactive current injection is performed to increase the voltage. If ΔU (HVRT) is positive, the voltage is reduced by the injection of an inductive reactive current (Paul et al., 2018).

Both VSC1 and VSC2 substations can provide reactive power, what defines STATCOM (Static Synchronous Compensator) exploitation. The sign of the reactive current $i_{g 1, q}$ makes it possible to define that the reactive powers are positive or negative. Figure 4(a) gives a vector representation with only reactive current. If the grid voltage $v_{g 1}$ is lower than the voltage $v_{1}$ of VSC1, capacitive current is generated to compensate the amount of lack of reactive power and stabilize the voltage. On the contrary, in the case where $v_{g 1}$ is greater than $v_{1}$ , the current $i_{g 1, q}$ must be inductive.

In this case, the VSC2 substation provides power regulation. Currents $i_{g 2, d}$ and $i_{g 2, q}$ are imposed by fault with relation to active power and reactive power. Figure 4(b) gives a vector representation in the case of injection of an active current only. Depending on the direction of the power flow, current is oriented in the positive or negative direction on the d axis.

The VSC1 control loop will be modified with the integration of a variable reactive current depending on the state of the VSC–HVDC grid. The external regulation loops of VSC1 and VSC2 will be modified with the integration of a variable reactive current depending on the state of the VSC–HVDC grid. Figure 5 shows the modified control strategy for controlling the two converter stations.

The two VSC stations can operate as STATCOMs during a fault in the AC side. A decomposition of the control strategy is carried out with integration of the positive sequence and negative sequence for the improvement of the control loop based on Fortescue theory. The VSC generates reactive power and injects into the grid with a zero STATCOM reference current. The positive control sequence is activated during the symmetrical fault in the AC grid but the negative sequence works in the asymmetrical faults.

Positive sequence variables are noted “+” and negative sequence variables are noted “–.” The direct active reference current of station 1 ( $i_{g 1, d +}^{ref}$ ) is given by monitoring the DC voltage $V_{DC}$ of the HVDC link. For station 2, reference direct active current ( $i_{g 2, d +}^{ref}$ ) is realized by active power control. The reference direct currents are given by equation (10)

{\begin{matrix} \begin{matrix} i_{g 1, d +}^{ref} = k_{p, VDC 1} (V_{DC 1}^{ref} - V_{DC 1}) + \int^{(\frac{V_{DC 1}^{ref} - V_{DC 1}}{T_{i, VDC 1}})} dt \end{matrix} \\ i_{g 2, d +}^{ref} = k_{p, P_{2}} (P_{2}^{ref} - P_{2}) + \int^{(\frac{P_{2}^{ref} - P_{2}}{T_{i, P_{2}}})} dt \end{matrix}

(10)

with ( $k_{p, VDC 1}, k_{p, P_{2}})$ proportional gains and ( $T_{i, VDC 1}, T_{i, P_{2}})$ time constants of PI regulators. $V_{DC 1}$ , is the measured DC voltage of the HVDC link and $P_{2}$ the power of the AC 2 grid.

The $(i_{g 1, q +}^{r e f}, i_{g 2, q +}^{r e f})$ reference reactive current control loops are defined by equation (11), with $(k_{p, Q 1}, k_{p, Q_{2}})$ the proportional gains and ( $T_{i, Q 1}, T_{i, Q_{2}})$ the PI regulator time constants. The reactive currents ( $i_{g 1}^{LVRT}, i_{g 2}^{LVRT})$ injected during faults in the AC parts are given by equations (12) and (13)

{\begin{matrix} \begin{matrix} i_{g 1, q +}^{ref} = k_{p, Q 1} (Q_{1}^{ref} - Q_{1}) + \int^{(\frac{Q_{1}^{ref} - Q_{1}}{T_{i, Q 1}})} dt + i_{g 1}^{LVRT} \end{matrix} \\ i_{g 2, q +}^{ref} = k_{p, Q 2} (Q_{2}^{ref} - Q_{2}) + \int^{(\frac{Q_{2}^{ref} - Q_{2}}{T_{i, Q 2}})} dt + i_{g 2}^{LVRT} \end{matrix}

(11)

i_{g 1}^{LVRT} = {\begin{matrix} 0, U_{g 1} \in [U_{g 1}^{L} U_{g 1}^{U}] \\ k_{1} (U_{g 1}^{ref} - U_{g 1}), U_{g 1} \notin [U_{g 1}^{L} U_{g 1}^{U}] \end{matrix}

(12)

i_{g 2}^{LVRT} = {\begin{matrix} 0, U_{g 2} \in [U_{g 2}^{L} U_{g 2}^{U}] \\ k_{2} (U_{g 2}^{ref} - U_{g 2}), U_{g 2} \notin [U_{g 2}^{L} U_{g 2}^{U}] \end{matrix}

(13)

where $k_{1}, k_{2}$ are reactive current amplification gains (with typical values for grid code between 2 and 10); $U_{g 1}, U_{g 2}$ are effective voltages of $v_{g 1}$ and $v_{g 2}$ ; $[U_{g 1}^{L} U_{g 1}^{U}], [U_{g 2}^{L} U_{g 2}^{U}]$ are voltage limits of $U_{g 1}$ and $U_{g 2}$ (L indicates low, U indicates upper).

The approach under study involves removing negative sequences and injecting reactive currents in the case of unbalanced faults. The negative components of currents are zero in balanced operation, but vary in the unbalanced phase, resulting in an injection of reactive current. The applied negative reference currents are given by equation (14)

{\begin{matrix} \begin{matrix} i_{g 1, d - ref} = 0 \end{matrix} \\ \begin{matrix} i_{g 1, q - ref} = 0 \end{matrix} \\ \begin{matrix} i_{g 2, d - ref} = 0 \end{matrix} \\ \begin{matrix} i_{g 2, q - ref} = 0 \end{matrix} \end{matrix}

(14)

Simulation and experimental results

The FRT control proposed in this article is evaluated for AC grid faults. The response of improved control strategy and negative sequence current control loops is demonstrated for balanced and unbalanced faults. In addition, symmetric and asymmetric AC grid faults are presented to prove that the FRT strategy provides grid stability.

Simulation

To examine the dynamic evolutions of the proposed system, a set of simulations with MATLAB/Simulink software were carried out to verify the effectiveness of the control loops for operating scenarios. Thanks to the VSC–HVDC conversion chain, we can control the direction of energy transfer from one grid to another. The VSC1 converter station handles DC bus voltage regulation, while the VSC2 converter station performs active and reactive power regulation. To study the efficiency of the VSC–HVDC system following an FRT in grid 2 with symmetrical and asymmetrical voltage sag scenarios, three case studies were carried out. The first case is a test on the change of energy transfer from one grid to another. The second case is the behavior of the VSC–HVDC grid following a symmetrical voltage sag.

Case I: Inversion of active power transfer

Figure 6 shows the simulation results for active power reversal at grid level 2. The first operating mode is with an active power of 1 pu (0–1 second). Regarding the stop mode (1–2 seconds), the converter neither delivers nor absorbs the active/reactive power. The last mode (2–3 seconds), the active power is −1 pu. Figure 6(b) and (c) show for the first mode, the current and the voltage of grid 1 are in phase, whereas they are in opposition phase in grid 2 and vice versa for mode 2. The inversion of the active power at grid 2 leads to the change of direction of power transfer. For mode 1, the power routes from grid 1 to grid 2 and vice versa for mode 2. The DC bus voltage remains constant with a slight variation at the moment of changing the operating mode.

Simulation show the inversion of the direction of the current during change of sign of the active power of the grid 2. In this HVDC grid, a bidirectional direction of energy transfer from one grid to another, which gives the change the type of operation of the converters VSC1 and VSC2. In mode 1, the current in grid 2 is in phase with the voltage of grid 2 and in opposition in grid 1, hence we say that VSC1 is a rectifier and VSC2 is an inverter. In mode 2, reversing the current direction implies that VSC1 is an inverter and VSC2 is a rectifier.

Case II: Three-phase voltage sag

In the second simulation case, a voltage sag of 40% is achieved in grid 2 with a duration of 200 milliseconds. Figure 7 shows the evolution of voltage and current in the two grids.

The simulation shows that the components d and q of the voltage of grid 1 (positive and negative) are always constant, except that the positive direct component of the current $i_{g 1, d +}$ goes to zero during a fault. In grid 2, there is a significant reduction in the positive direct component of the voltage $v_{g 2, d +}$ without a change in the negative component $v_{g 2, d -}$ , which implies symmetrical operation in the event of a fault. With regard to the current, a significant variation of $i_{g 2, q +}$ is observed, which goes from zero to 1 pu, which reflects a reactive energy compensation due to the voltage sag. The power of the $P_{DC}$ continuous grid is equal to the active power $P_{g 2}$ with a slight loss due to the equipment of the installation. The reactive power $Q_{g 2}$ is zero except during the compensation phase. The stable operation of the VSC-HVDC network during and after the fault shows the effectiveness of the LVRT loop integrated in the FRT strategy.

Case III: Short circuit between two phases

In the third case, a short circuit is made between two phases of grid 2. The objective of this test is to verify the operation of the FRT strategy with evolution of the positive and negative components during an asymmetric fault. The evolution of the voltage in grid 1 keeps almost the same evolution as in the case of a symmetrical fault. On the contrary, for grid 2, a remarkable change is observed in the positive and negative components along the d axis of the voltage $v_{g 2}$ . The decrease in $v_{g 2 d +}$ is compensated by the increase in $v_{g 2 d -}$ . With regard to the current $i_{g 2}$ , a variation of the positive and negative components is observed during the unbalance phase, which implies the operation of the FRT strategy. The reduction in the active power $P_{g 2}$ generated during the fault leads to an injection of reactive current which ensures the variation of the reactive power $Q_{g 2}$ . For the transmission line, the $V_{DC}$ voltage remains constant after correction, while the decrease in $I_{DC}$ results in a variation of the $p_{DC}$ power. This test gives an idea of the continuity and stability of the operation of the HVDC network during and after the asymmetric fault, which reinforces the operation of the FRT strategy. Figure 8 summarizes the operation of the FRT control loop.

Experimental results

The smart grid installed in the laboratory of the ENSIT University of TUNIS to emulate a VSC–HVDC transmission system from the manufacturer LUCAS-NÜLLE. The test bench contains two converters VSC1 and VSC2, respectively, connected to a variable three-phase AC supply (grid 1) and a three-phase AC supply (grid 2) which are 400 V and 50 Hz. The bench also contains a dynamic fault simulator and a DC line which is connected between the two converters. VSC1 and VSC2 can control the transfer of active power in the DC line in both directions, can be coupled between two power grids at different frequencies. The VSC–HVDC test bench installed in the laboratory transmits active power up to 1 kW, provides reactive power of order 1 kvar and has an adjustable DC link voltage up to 750 VDC. The HVDC transmission line supports a current of order 2 A with an adjustable voltage of 750 V, thus is modeled by a resistance of 7.2 Ω and an inductance of 230 mH. VSC 1 and VSC 2 are linked by a computer which records the results of the tests carried out. The VSC–HVDC bench contains a dynamic fault simulator module with an adjustable operating time from 50 to 1000 milliseconds. Three fault scenarios were carried out on the test bench: the first fault is symmetrical manifested by a voltage sag on the other, and the second fault is asymmetrical, which is translated by a single-phase and two-phase short-circuit.

A practical realization on the VSC–HVDC test bench with inversion of the reference active power in grid 2 from 1 pu (1 kW) to −1 pu (–1 kW) keeping the reactive power at 0 pu. Figure 9 shows the experimental results for the two operating states with mode 1, positive, and reverse power in mode 2.

In a second case study, a dynamic evolution was carried out with a voltage sag caused by a symmetrical three-phase fault, that is, a fault that affects all three phases. The 40% voltage sag is applied for a duration of 200 milliseconds (100 to 300 milliseconds) in grid 2. At the start, set the active reference power $P_{g 2}^{ref} = 80 %$ and the reactive power $Q_{g 2}^{ref} = 0 %$ . After the creation of the fault, the two stations operate normally with balanced voltages and currents in the two grids. Figure 10(a) represents the voltages and currents in grid 1 and grid 2.

In the third case study, a short circuit between two phases with a duration of 200 milliseconds is carried out using the fault simulator. Before the creation of the fault, a reference setting at grid level 2 with active power at 80% and reactive power at 0%. Short-circuit test execution starts at 100 milliseconds with a duration of 200 milliseconds. Figure 10(b) represents the voltages and currents in grid 1 and grid 2. According to the experimental results, there is a continuity of operation of VSC1, therefore of the VSC–HVDC system, after the short circuit and maintains energy transfer.

Figure 10 demonstrates the ability of the grid side converter to handle faults without any difficulty. The symmetric and asymmetric case studies show the effectiveness of using the RFT control loop by creating the reactive current in the grid where the fault occurs. Each VSC station operates as a STATCOM in the event of a fault tripping in the AC grid. The control of the grid voltage is essential from the point of view of power and voltage stability. However, if the AC grid is connected to a VSC–HVDC transmission system, the AC side converter can be used to meet the reactive power demand. In Figure 10(a), an increase in the current $i_{g 2}$ in the grid 2 following the voltage drop is created for the compensation of the reactive energy. This variation is symmetrical, which indicates the absence of the negative components. Figure 10(b) shows an asymmetric variation of the current in grid 2, which gives a variation of the negative components.

Conclusion

In this article, an FRT mechanism is installed in each control loop of the two converters. The main purpose is to maintain stable operation of the VSC–HVDC system and to avoid its disconnection during faults in the AC 1 and AC 2 grid. The efficiency of the FRT mechanism is tested with the creation of symmetric and asymmetric faults, which demonstrates that the HVDC link reaches a stable operating point during the fault. The first scenario is reserved for the bidirectional energy transfer test between the two AC grids. The other two scenarios are performed to test the effectiveness of the FRT strategy by creating symmetric and asymmetric scenarios with a duration of 200 milliseconds. Faults are created in the grid 2 by a voltage drop of 40% and a short circuit between the two phases. For each fault scenario, the HVDC link achieves another stable operation during fault conditions. A reactive energy compensation is recorded during the fault phase. A variation of the positive sequence $i_{g 2, q +}$ of the current $i_{g 2}$ during the asymmetrical fault, and on the contrary, a variation of the positive and negative sequence $(i_{g 2, q +,} i_{g 2, q +})$ for the asymmetrical fault. It has been shown that the DC voltage $V_{DC}$ of the HVDC line, the currents and the voltages in both sides have adequate performance, which implies the efficiency of the FRT loops installed. Research work can be the continuation of this article at the infrastructure level by integrating offshore renewable generation. Change VSCs by MMC (modular multilevel converter) converters. The PI regulators used in FRT can be replaced by fuzzy regulators.

Footnotes

Appendix

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The author(s) received no financial support for the research, authorship, and/or publication of this article.

ORCID iDs

Mansour Baazouzi

Kamel Sayahi

Faouzi Bacha

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Control strategy used for AC fault ride-through in VSC–HVDC transmission systems

Abstract

Keywords

Introduction

VSC–HVDC modeling

VSC–HVDC system control

Control of VSC1 and VSC2

FRT method

Simulation and experimental results

Simulation

Case I: Inversion of active power transfer

Case II: Three-phase voltage sag

Case III: Short circuit between two phases

Experimental results

Conclusion

Footnotes

Appendix

Declaration of conflicting interests

Funding

ORCID iDs

References