Synchronous Generator Emulation Control Strategy for ... - IEEE Xplore

IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 30, NO. 6, NOVEMBER 2015

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Synchronous Generator Emulation Control Strategy for Voltage Source Converter (VSC) Stations Minyuan Guan, Member, IEEE, Wulue Pan, Jing Zhang, Member, IEEE, Quanrui Hao, Member, IEEE, Jingzhou Cheng, and Xiang Zheng

Abstract—The voltage source converter (VSC) station is playing a more important role in modern power systems, but the dynamic behavior of the VSC station is quite different from that of the synchronous generator. This paper presents the synchronous generator emulation control (SGEC) strategy for the VSC-HVDC station. The SGEC strategy is divided into the inner control loop and the outer control loop. The inner controller is developed for fast current and voltage regulations. An inertia element is introduced into the frequency-power droop to determine the command reference of the frequency, and the inertia response and the primary frequency regulation are emulated. In addition, the secondary frequency regulation can be achieved by modulating the scheduled power in the SGEC strategy. The time-domain simulation results demonstrate the VSC station with the proposed control strategy can provide desired frequency support to a low-inertia grid. Therefore, the SGEC strategy provides a simple and practical solution for the VSC station to emulate the behavior of a synchronous generator. Index Terms—High-voltage direct-current (HVDC) transmission, modular multilevel converter (MMC), synchronous generator (SG) emulation, vector control, virtual synchronous generator, voltage source converter (VSC) station, VSC-HVDC.

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I. INTRODUCTION

ITH the continuous progress of the high-voltage high-power voltage source converter (VSC) technologies, more and more VSC based devices like VSC-HVDC transmission systems, flexible AC transmission systems (FACTS) and energy storage systems (ESS) have been installed, and the VSC station is playing a more important role in modern power systems [1], [2]. The transmission rating up to several hundred MW has been reached in recent VSC-HVDC projects [3], [4]. The conventional synchronous generator has inherent features beneficial to power system stability, such as the increase

Manuscript received March 23, 2014; revised June 25, 2014 and September 30, 2014; accepted November 19, 2014. Date of publication January 14, 2015; date of current version August 03, 2015. This work was supported in part by the Key Science and Technology Program of State Grid Zhejiang Electric Power Company under Project 5211011306Z4. Paper no. TPWRS-00404-2014. M. Guan is with Huzhou Power Supply Company of State Grid Zhejiang Electric Power Company, Huzhou 313000, China (e-mail: [email protected]; [email protected]). W. Pan, J. Zhang, J. Cheng, and X. Zheng are with the State Grid Zhejiang Electric Power Company, Hangzhou 310007, China (e-mail: panwulue@163. com; [email protected]; [email protected]; zfl[email protected]). Q. Hao is with the School of Electrical Engineering, Shandong University, Jinan 250061, China (e-mail: [email protected]). Color versions of one or more of the figures in this paper are available online at http://ieeexplore.ieee.org. Digital Object Identifier 10.1109/TPWRS.2014.2384498

in system inertia, the synchronizing power and the damping power. The synchronous generator is not only able to work in parallel with other generators, but is also able to supply a passive network. The vector current control has been widely used in the control of the VSC-HVDC system for the fast current regulation abilities. With the constant power control, the delivered power of the VSC-HVDC system could be precisely controlled at the scheduled value, irrespective of the frequency variations of the two grids. Thus, the dynamic behavior of the VSC station is quite different from that of the synchronous generator. The frequency oscillations in one grid could be isolated from the other grid to some extent, which improves the security of the grid operation. One typical application of VSC-HVDC transmission systems is to supply a weak or passive grid (i.e., an island grid) far away from the main grid. With the constant power control, the output power from the VSC station is controlled as a constant, and no frequency support is provided to the weak grid. When a significant part of the power in a local gird is supplied by the VSC station, the system inertia becomes lower, and changes in generation or load may cause large frequency deviations possibly leading to system instability. The frequency problem will be more serious, when the local grid becomes a passive network supplied by the VSC station. It becomes beneficial to the frequency stability that the VSC station can provide frequency support to the local grid. Recently, novel control techniques are presented, by which the VSC station is able to provide the inertial response [5]–[8], the frequency regulation [2], [9], and/or the power system damping [10], [11]. Power-synchronization control is presented for the VSC station to realize very useful features of the synchronous generator, such as the power supply and voltage support to a weak grid [12]–[14]. On the other hand, a new concept of virtual synchronous generator, which represents a VSC operated in the similar way as the synchronous generator, has been proposed in [15]. Some novel virtual synchronous generator models have been developed for VSCs in [16]–[18], in which additional control loops are specially designed to model the swing equation of the synchronous generator. For instance, the angular frequency reference of the converter output voltage is determined by the virtual generator control loop [17], [18]: (1) where is the grid angular frequency, is the virtual mechanical input power, and is electrical output power from the converter. Thus, the measurement of the grid frequency is required.

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Fig. 1. Schematic diagram of a VSC-HVDC transmission system supplying a small local grid.

The inertia coefficient and the damping power coefficient, deand , are two different control parameters. To renoted by alize the primary frequency regulation, the virtual mechanical input power is determined by the virtual governor control loop [17], [18] (2) where is the reference value of the output power and is the nominal angular frequency. The time delay and the difference coefficient, denoted by and , are two different control parameters. The additional control loops, the measurement of the grid frequency as well as the selection of control parameters make the control scheme complicated. To enable the continuous operation irrespective of the network conditions, the conventional droop control (CDC) strategy is widely used for the VSC station supplying a weak or passive grid [19]–[21]. In the CDC strategy, the frequency of the VSC output voltage is automatically regulated according to the deviation of the real power from its scheduled value. The proposed synchronous generator emulation control (SGEC) strategy includes an inner control loop and an outer control loop. Due to the fast current limiting of the inner current controller, the over-current blocking of the converter valves could be avoided. Only a first-order inertia element is added to the CDC strategy to determine the frequency command reference, without any additional control loop. The proposed SGEC strategy is considered as a simple and practical solution for the VSC station to imitate the behavior of a synchronous generator. The rest of this paper is organized as follows. Section II introduces the mathematical model and the SGEC strategy of the VSC-HVDC station. The performance of the SGEC strategy is analyzed in Section III, by which the swing equation, the primary frequency regulation and the secondary frequency regulation of synchronous generators are obtained. To evaluate the performance of the SGEC strategy, time-domain simulation studies in the PSCAD/EMTDC software environment are presented in Section IV. Section V concludes this paper. II. CONTROL SCHEME It is depicted in Fig. 1 that the power is delivered from the main grid to the local grid by a VSC-HVDC transmission

Fig. 2. AC-side of a VSC station.

system. The two VSC stations, denoted by VSC1 and VSC2, are linked by a pair of DC cables. Each VSC station is connected to the AC system through an interfacing reactor and a converter transformer. The converter reactor blocks the high-frequency harmonic currents generated by the VSC station from entering into the power system, while a high-pass (HP) filter is installed at the PCC to provide a low-impendence path to ground for the high-frequency harmonic currents. The converter reactor and the HP filter constitute a low-pass filter system. Because a large portion of power is supplied by the VSC station, the inertia of the local grid is significantly reduced. It becomes especially beneficial to the frequency stability of the local grid that the VSC station can provide frequency support. A. VSC Model The AC-side of different VSCs can be generally represented by a three-phase AC voltage source [22]–[25]. In conventional VSCs like the two-level converter and the neutral point clamped (NPC) converter, and are the inductance and resistance of the interfacing reactor [22]. In modular multilevel converter (MMC), and are half of the inductance and resistance of the arm reactor [25], [26]. The HP filter is considered purely capacitive at the fundamental frequency [27], and its equivalent capacitance is represented by . According to Fig. 2, the AC-side dynamics of different VSCs are generally expressed as (3) (4) and are the column vectors of the three-phase where output voltages and currents from the VSC, and and are the column vectors of the three-phase output voltages and currents at the PCC.

GUAN et al.: SYNCHRONOUS GENERATOR EMULATION CONTROL STRATEGY FOR VSC STATIONS

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The balanced three-phase voltages and currents can be transformed to the synchronous dq-axis voltage and current components via the following Park transformation [23]: (5a) (5b) The AC-side dynamics of the VSC station, in term of the dq-axis components, are expressed as [22]–[25] (6a) (6b)

Fig. 3. Overall control scheme of the SGEC strategy.

(7a) (7b) If the -axis is fixed to the grid voltage vector, the -axis component of the PCC voltage is equal to the amplitude of the voltage vector, and the -axis component of the PCC voltage is zero in steady-state. As shown in Fig. 2, the real power output at the PCC is given by [22] (8) B. Inner Control Loop The inner control loop is a vector control scheme including a current controller and a voltage controller. Because the vector control scheme has been widely used in the control of VSC [22]–[25], only a brief description is given here. The inner current controller is given by (9) [22]–[24]: (9a)

where is the nominal amplitude of the PCC voltage. The inner control scheme is illustrated in Fig. 3. C. Outer Control Loop The inductive component of the line impedances in high voltage (HV) networks is typically much higher than the resistive one, and the value of the real power delivered to the grid can be regulated by controlling the frequency of the voltages at the PCC [29]. The outer control loop is developed to regulate the angular frequency of the PCC voltages, in which the synchronizing signal for the Park transformation is (12) is the command reference of the angular frequency where of the PCC voltages. The three-phase voltages at the PCC are derived by the inverse Park transformation in (14):

(9b) where is the frequency reference of the outer control loop, and represent the proportional and integral gains, respectively. Since the VSC has very little over-current capability, a large transient current due to disturbances will stress or damage the valves [2]. If the value of the dq-axis current command references and are limited, the fast-response current controller is effective in preventing the VSC from over-current blocking. The voltage control mode is designed to control the AC voltages at the PCC, which can be regulated by the charging of the capacitive filter. Thus, the current command references and of the inner current control are given by

(13) (14) Thus, the phase-a voltage is expressed as

(15) The differentiation of the phase angle in (15) is the angular frequency

(10a) (10b) The tuning of PI gains in (9) and (10) has been given in [28]. The command references of the dq-axis voltage components are given by (11)

(16) Because the differentiations of the dq-axis voltage components at the PCC in steady state are both zero, the second term in (16) is a transient component. Thus, the angular frequency of the PCC voltages could track its command reference in steady state with the outer control loop.

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D. Synchronous Generator Emulation Control To emulate the swing equation, the command reference of the angular frequency of the PCC voltages can be determined as (17) In the swing equation, and are the mechanical input power and the electrical output power, and are the inertia coefficient and the damping power coefficient, and is the nominal angular frequency. Applying the Laplace transform, (17) can be rewritten as (18)

The SGEC strategy is considered as a simple and practical control strategy for synchronous generator emulation, since it is based on a small modification of the CDC strategy and no additional control loop is required. The vector current controller included in the SGEC scheme is effective in preventing the VSC from over-current blocking during system disturbances. It is considered highly important for the practical VSC control, as the VSC station usually have very little over-current capabilities [12]–[14]. III. ANALYSIS A. Swing Equation The SGEC strategy of (19) can be rewritten as

In the SGEC strategy, the command reference of the angular frequency can be derived from (18) as

(19) in which the lag time of the first order inertia element fined as

The first term in (22) is a constant. In the SGEC strategy, the scheduled and actual powers are filtered by the first-order inertial element. As a result, the frequency reference in (22) could be smoothed and the expected inertial response is introduced into the frequency regulation. Equation (17) is rewritten as (23)

is de(20)

If the lag time

(22)

is 0, (20) is simplified as (21)

which represents the CDC strategy. In the CDC strategy, is the droop coefficient. and are the actual and scheduled real power outputs from the PCC to the grid, respectively. Comparing (19) and (21), the SGEC strategy is realized only by adding a first-order inertia element to the widely used CDC strategy, without any additional control loops. Only one additional control parameter (i.e., the lag time in the first-order inertia element) is required, so the SGEC strategy is considered much simpler than the previous strategies. As a matter of fact, a time lag is always implied in (21) because the control system is not ideal. In conventional control schemes, a short lag time is required to ensure the fast response of the controller. However, the situation becomes different when the inertia response is taken into consideration. In the CDC strategy, the lag time is usually too short (i.e., several milliseconds) to influence the electromechanical transients as well as the system inertia. In the SGEC strategy, a first-order inertia element with a larger lag time (i.e., several hundred milliseconds) is intentionally added to the CDC strategy. As a result, the VSC station is able to imitate the behavior of a synchronous generator, and increases the system inertia obviously. The overall SGEC scheme is illustrated in Fig. 3, by which the command reference for the angular frequency of the three-phase output voltages is determined. To prevent excessive frequency deviations, the amplitude of the command reference of the angular frequency is limited.

When the scheduled output power is greater than the actual output power, the frequency reference will be gradually increased. On the contrary, the frequency reference will be gradually decreased, when the scheduled power is lower than the actual value. The damping power is proportional to the deviation of the frequency reference from the nominal frequency. It should be noted that an increase in the inertia decreases the oscillation damping like that in a synchronous generator [30]. Taking the single-machine infinite bus system as an example, the damping ratio of the characteristic equation is represented by [31] (24) where is the synchronizing power coefficient. Substituting (20) into (24), we obtain (25) The inertia is increased, but the oscillation damping is reduced for the larger lag time in the SGEC strategy. B. Primary Frequency Regulation According to (16) and (22), the frequency deviation in steady state is given by (26) Thus, there is a droop relationship between the frequency and the output power, which is the same as that of the primary frequency regulation of a synchronous generator. Thus, the frequency of the VSC station is adjustable, which can coordinate with other generators or supply a passive network [19]–[21]. When the converter output power is equal to the scheduled


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TABLE I PARAMETERS OF MMC-HVDC SYSTEM

Fig. 4. Frequency-power characteristics in steady state.

power, the frequency of the PCC voltage will settle down at the nominal value. Otherwise, the frequency of the PCC voltage is changed in proportional to the deviation of the real power from the scheduled value. In consequence, the VSC station is able to provide primary frequency regulation to the local grid. Moreover, the amplitude of frequency deviation can be limited by using the saturation limits as shown in Fig. 3. The steady-state frequency characteristics of the SGEC controlled VSC station is illustrated in Fig. 4. C. Secondary Frequency Regulation In an isolated power system, the secondary frequency control is adopted in certain synchronous generator to restore the system frequency to the nominal value, which is accomplished by adding a slow-response integral term acting on the mechanical power reference of the speed governor [30]. As shown in Fig. 3, the secondary frequency regulation could be realized by adding a slow-response integral term to modulate the scheduled power of the converter:

TABLE II CONTROL PARAMETERS

(27) is the initial scheduled power set by the system opwhere erator. Therefore, the SGEC strategy provides the VSC stations with a simple and practical solution for the emulation of synchronous generators. IV. CASE STUDY A. Study System The MMC is an emerging and attractive VSC topology for HVDC applications [3], [25]. The schematic diagram of the study system is illustrated in Fig. 1, and the power is delivered from the main grid to the local grid by an MMC-HVDC transmission system. Detailed model of the MMC-HVDC system is implemented in the PSCAD/EMTDC software environment, and the parameters are listed in Table I. The control parameters of the CDC and SGEC strategies are given in Table II. A modified 3-machine 9-bus system is adopted as a typical case of the local grid, in which a large synchronous generator is replaced by the inverter station. The parameters of the other two synchronous generators are listed in Table III. The performances of the local grid with the CDC and SGEC strategies

under different operation cases are investigated and compared by PSCAD/EMTDC simulations. The main object of this study is the AC-side dynamics of the converter station, not the internal characteristics of the converter itself. Thus, an adequate small number of sub-modules (i.e., 20 sub-modules) per arm is implemented in the MMC station to simplify the converter modeling and speed up the simulation. The parameters of the sub-module are not practical values. The nearest level modulation (NLM) algorithm in [32], [33] and the straightforward voltage balancing strategy in [3] are adopted. B. Case 1: Steady-State Operation The steady-state operation is considered in the first case. The output powers to the local grid from the VSC station, the generator G1 and the generator G2 are 350 MW, 150 MW, and 100 MW, respectively. The control strategy of the VSC station is changed from the CDC strategy to the SGEC strategy at s. Because there is no real rotating component in the converter,

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TABLE III PARAMETERS OF SYNCHRONOUS GENERATORS

the frequency reference given by the controller is considered as the frequency of the VSC station. The frequency curve and the output power of the VSC are illustrated in Fig. 5(a) and (b), while voltages and currents at the PCC are shown in Fig. 5(c) and (d). The frequency reference of the VSC station with the SGEC strategy is smoother than that with the CDC strategy due to the larger lag time. Small steady-state frequency variations always exist because an actual power system is not ideal. But the frequency variations are reduced under larger system inertia. Since the frequency regulation of the inner controller is not achieved instantaneously, the small ripples in the frequency reference have very little impact on the power system. As a result, there is no obvious difference in the output power, the PCC voltages and currents under the two control strategies. Therefore, the steady-state performances of the CDC and SGEC strategies are similar to each other.

Fig. 5. Simulation waveforms of the converter station during steady-state operation: (a) frequency curve of the VSC, (b) output power at the PCC, (c) the PCC voltages, and (d) the PCC currents.

C. Case 2: Load Changes The most common disturbance in a power system is the load change. Due to the lack of inertia, an unbalance in the power generation and consumption will result in a large system frequency excursion. As shown in Fig. 1, an additional load of 50 MW is connected to bus 6 at s, which represents 8.3% of the total predisturbance load in the local grid. If the secondary frequency regulation is provided by the generator G1, the corresponding responses of the study system with the two control strategies are illustrated in Fig. 6. As shown in Fig. 6, the frequency drop of the VSC station under the SGEC strategy is slower and smoother than that under the CDC strategy. As a result, the frequency drops of two synchronous generators under the SGEC strategy are also slower than that under the CDC strategy. Due to the inertial characteristics, the maximum frequency drops of the VSC station, G1 and G2 are reduced by the SGEC strategy. After a short period

Fig. 6. Simulation waveforms of the converter station with the SGEC and CDC strategies under load change (secondary frequency regulation from G1): (a) frequency curves of the VSC, (b) output powers at the PCC, (c) frequency curves of G1, and (d) frequency curves of G2.

of transient, the frequency of the local grid can be restored to the nominal value by the secondary frequency regulation from G1. Thus, the system inertia could be increased by the SGEC strategy. If the secondary frequency regulation is provided by the VSC station, the corresponding responses of the study system with


Fig. 7. Simulation waveforms of the converter station with the SGEC and CDC strategies under load change (secondary frequency regulation from the VSC station): (a) frequency curves of the VSC, (b) output powers at the PCC, (c) frequency curves of G1, and (d) frequency curves of G2.

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Fig. 8. Simulation waveforms of the converter station with the SGEC and CDC strategies under AC fault at line 6–9: (a) frequency curves of the VSC, (b) output powers at the PCC, (c) frequency curves of G1, and (d) frequency curves of G2.

the two control strategies are illustrated in Fig. 7. After a short period of transient, the frequency of the local grid can be also restored to the nominal value by the secondary frequency regulation from the VSC station. The output power of the VSC station is increased by 50 MW to supply the additional load. Thus, the VSC station is able to provide second frequency regulation to a low-inertia grid. However, the electromechanical oscillations under the SGEC strategy are damped out more slowly than that under the CDC strategy. This is due to the feature of synchronous generator that the oscillation damping would be decreased by an increase in the inertia [30]. D. Case 3: AC Fault The disturbance in this case is a three-phase grounding fault occurring in the middle of line 6–9, which is near the VSC station. The fault is cleared in five cycles (0.1 s) by opening line 6–9. The dynamic performances of the study systems in response to this three-phase fault are illustrated in Fig. 8. When the three-phase fault happens at s, the output powers of the VSC station with the two control strategies are decreased almost to zero. As a result, the frequency of the VSC station with the CDC strategy is suddenly changed to the upper limit, and the frequencies of G1 and G2 are both accelerated to about 51.3 Hz. In contrast, the frequency of the VSC station with the SGEC strategy is gradually changed, and the frequencies of G1 and G2 are accelerated to about 50.5 Hz and 50.7 Hz. After the fault is cleared, the output powers of the VSC stations are gradually restored, and the VSC station and the generators settle down to new steady-state conditions. During the transient

Fig. 9. Simulation waveforms of the converter station with the SGEC and CDC strategies under AC fault at line 8–9: (a) frequency curves of the VSC, (b) output powers at the PCC, (c) frequency curves of G1, and (d) frequency curves of G2.

period, the frequency deviations of the VSC station and the generators with the SGEC strategy are much smaller than that with the CDC strategy. The other disturbance is a three-phase grounding fault occurring in the middle of line 8–9, which is far away from the VSC station. The fault is cleared in five cycles (0.1 s) by opening

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line 8–9. The dynamic performances of the study systems in response to this three-phase fault are illustrated in Fig. 9. During the transient period, the frequency deviations of the VSC station and the generators with the SGEC strategy are also much smaller than that with the CDC strategy. Therefore, the SGEC strategy is effective in increasing the system inertia and reducing frequency deviations of a low-inertia grid. V. CONCLUSION The synchronous generator emulation control strategy is proposed for the VSC station, by which the behavior of a synchronous generator can be emulated. The control scheme is divided into two separate loops: an inner control loop and an outer control loop. The inner controller is a conventional vector controller developed for the fast current control and the PCC voltage regulation. In the outer controller, the conventional droop control is modified by introducing a first-order inertia element. The lag time of the inertia element is intentionally increased to provide the inertia response. As a result, the frequency regulation of the SGEC strategy is found to be a nice analogy to the swing equation of a synchronous generator. Moreover, the primary and secondary frequency regulations are also realized by the SGEC strategy. Therefore, the frequency support can be provided by the VSC station with the SGEC strategy, which is especially desired to a low-inertia gird. Because the SGEC strategy is based on a small modification to the conventional droop control strategy, it is considered as a simple and practical solution for the VSC station to imitate the behavior of a synchronous generator. The vector current controller included in the SGEC scheme is effective in preventing the VSC from over-current blocking during system disturbances. The effectiveness of the SGEC strategy is demonstrated by the time-domain simulation studies performed in the PACAD/EMTDC software environment. REFERENCES [1] N. Flourentzou, V. G. Agelidis, and G. D. Demetriades, “VSC-based HVDC power transmission systems: An overview,” IEEE Trans. Power Electron., vol. 24, pp. 592–602, 2009. [2] C. Du, M. H. J. Bollen, E. Agneholm, and A. Sannino, “A new control strategy of a VSC-HVDC system for high-quality supply of industrial plants,” IEEE Trans. Power Del., vol. 22, pp. 2386–2394, 2007. [3] B. Gemmell, J. Dorn, D. Retzmann, and D. Soerangr, “Prospects of multilevel VSC technologies for power transmission,” in Proc. 2008 IEEE/PES Transmission and Distribution Conf. Expo., pp. 1–16. [4] B. Jacobson, P. Karlsson, G. Asplund, L. Harnefors, and T. Jonsson, “VSC-HVDC transmission with cascaded two-level converters,” Proc. 2010 CIGRE Session. [5] G. Delille, B. Francois, and G. Malarange, “Dynamic frequency control support by energy storage to reduce the impact of wind and solar generation on isolated power system's inertia,” IEEE Trans. Sustain. Energy, vol. 3, pp. 931–939, 2012. [6] B. Silva, C. L. Moreira, L. Seca, Y. Phulpin, and J. A. P. Lopes, “Provision of inertial and primary frequency control services using offshore multiterminal HVDC networks,” IEEE Trans. Sustain. Energy, vol. 3, pp. 800–808, 2012. [7] J. Zhu, C. D. Booth, G. P. Adam, A. J. Roscoe, and C. G. Bright, “Inertia emulation control strategy for VSC-HVDC transmission systems,” IEEE Trans. Power Syst., vol. 28, pp. 1277–1287, 2013.

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Minyuan Guan (S’11–M’13) was born in Zhejiang, China, in July 1985. He received the B.S. and Ph.D. degrees from Zhejiang University, Hangzhou, China, in 2008 and 2013, respectively, both in electrical engineering. He is now an engineer in Huzhou Power Supply Company of State Grid Zhejiang Electric Power Company. His main fields of interest include modular multilevel converter and VSC-HVDC transmission system, online detection and condition-based maintenance for power equipment, power system analysis, and grid integration of distributed energy resources. Dr. Guan was the recipient of the 2014 Top 100 Most Cited Chinese Paper Award Published in Domestic Journals. He has contributed in the reviewing process for several IEEE Transactions and other international journals.

Wulue Pan received the B.S. and Ph.D. degrees in electrical engineering from the Zhejiang University, Hangzhou, China, in 2003 and 2008, respectively. He is currently a relay protection engineer of the State Grid Zhejiang Electrical Power Company. His research interests include energy system applications such as power system protection, HVDC, and smart substation.

Jing Zhang (M’09) was born in Henan, China, in November 1980. He received the Ph.D. degree in electrical engineering from Zhejiang University, Hangzhou, China, in 2009. He is now an engineer in Zhejiang Electric Power Dispatch and Control Center. His main field of interest includes power system stability, HVDC and FACTS, power quality, and signal processing.

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Quanrui Hao (S’09–M’13) was born in China in 1984. He received the B. E. degree from Tianjin University, China, in 2006, the M.E. degree from Zhejiang University, China, in 2008, and the Ph.D. degree from McGill University, Montreal, QC, Canada, in 2013. From 2013 to 2014, he was a research fellow with McGill University. Since 2014, he has been with the Department of Electrical Engineering, Shandong University, where he serves as an associate professor. His research interests include multi-terminal HVDC, FACTS, and power converter control.

Jingzhou Cheng was born in Zhejiang, China, in 1980. He received the Ph.D. degree in electrical engineering from the Zhejiang University, Hangzhou, China, in 2014. His main fields of interest include HVDC and its protection relay.

Xiang Zheng was born in Zhejiang, China, in October 1983. He received the B.S. and Ph.D. degrees from Zhejiang University, China, in 2006 and 2011, respectively, both in electrical engineering. He is now an engineer in State Grid Zhejiang Electric Power Company. His main fields of interest includes subsynchronous resonance, VSC-HVDC, and FACTS.