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HVDC for Grid Services in Electric Power Systems
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HVDC for Grid Services in Electric Power Systems

A special issue of Applied Sciences (ISSN 2076-3417). This special issue belongs to the section "Energy Science and Technology".

Deadline for manuscript submissions: closed (25 September 2019) | Viewed by 43712

Printed Edition Available!
A printed edition of this Special Issue is available here.

Special Issue Editor

Prof. Dr. Gilsoo Jang

E-Mail Website
Guest Editor
School of Electrical Engineering, Korea University, Seoul 136-713, Korea
Interests: HVDC control; transient stability; HVDC system planning
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

We are inviting submissions of original research to a Special Issue of Applied Sciences on the subject of “HVDC for Grid Services in Electric Power Systems”.

The modern electric power system has evolved into a huge nonlinear complex system, due to the interconnection of thousands of generation and transmission systems. The unparalleled growth of renewable energy resources (RES) has caused significant concern regarding grid stability and power quality, and it is essential to find ways to control such a massive system for effective operation. The controllability of HVDC and FACTs devices allows for improvement of the dynamic behavior of grids and their flexibility. Research is being carried out at both the system and component levels of modelling, control, and stability. This Special Issue aims to present novel topologies or operation strategies to prevent abnormal grid conditions.

Prof. Dr. Gilsoo Jang
Guest Editor

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Keywords

  • Control, operation and planning of HVDC Systems
  • Active control of HVDC systems
  • HVDC control for special protection systems
  • HVDC operation scheme for stability improvement
  • Intelligent strategies for HVDC voltage support
  • New control techniques in HVDC
  • New HVDC applications
  • HVDC protection schemes

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Published Papers (11 papers)

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Editorial

Jump to: Research

3 pages, 155 KiB  
Editorial
Special Issue on HVDC for Grid Services in Electric Power Systems
by Gilsoo Jang
Appl. Sci. 2019, 9(20), 4292; https://doi.org/10.3390/app9204292 - 12 Oct 2019
Viewed by 1551
Abstract
The modern electric power system has evolved into a huge nonlinear complex system, due to the interconnection of a lot of generation and transmission systems [...] Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)

Research

Jump to: Editorial

21 pages, 7307 KiB  
Article
A Virtual Impedance Control Strategy for Improving the Stability and Dynamic Performance of VSC–HVDC Operation in Bidirectional Power Flow Mode
by Yuye Li, Kaipei Liu, Xiaobing Liao, Shu Zhu and Qing Huai
Appl. Sci. 2019, 9(15), 3184; https://doi.org/10.3390/app9153184 - 5 Aug 2019
Cited by 12 | Viewed by 4128
Abstract
It is a common practice that one converter controls DC voltage and the other controls power in two-terminal voltage source converter (VSC)–based high voltage DC (HVDC) systems for AC gird interconnection. The maximum transmission power from a DC-voltage-controlled converter to a power-controlled converter [...] Read more.
It is a common practice that one converter controls DC voltage and the other controls power in two-terminal voltage source converter (VSC)–based high voltage DC (HVDC) systems for AC gird interconnection. The maximum transmission power from a DC-voltage-controlled converter to a power-controlled converter is less than that of the opposite transmission direction. In order to increase the transmission power from a DC-voltage-controlled converter to a power-controlled converter, an improved virtual impedance control strategy is proposed in this paper. Based on the proposed control strategy, the DC impedance model of the VSC–HVDC system is built, including the output impedance of two converters and DC cable impedance. The stability of the system with an improved virtual impedance control is analyzed in Nyquist stability criterion. The proposed control strategy can improve the transmission capacity of the system by changing the DC output impedance of the DC voltage-controlled converter. The effectiveness of the proposed control strategy is verified by simulation. The simulation results show that the proposed control strategy has better dynamic performance than traditional control strategies. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
►▼ Show Figures

Figure 1

Figure 1
<p>VSC–HVDC used in AC grid interconnection.</p> Full article ">Figure 2
<p>System and phase-locked loop (PLL) references.</p> Full article ">Figure 3
<p>Control structure of the converters.</p> Full article ">Figure 4
<p>DC-link voltage and the active power of the VSC–HVDC system.</p> Full article ">Figure 5
<p>Proposed control structure of the converters.</p> Full article ">Figure 6
<p>Frequency response of the impedance and verification. The solid line represents the model prediction, and the black points denote the simulation. (<b>a</b>) Disturbance signal testing. (<b>b</b>) Impedance of the DC voltage-controlled converter (<b>c</b>). Impedance of the power-controlled converter.</p> Full article ">Figure 7
<p>Equivalent model of the VSC–HVDC system.</p> Full article ">Figure 8
<p>(<b>a</b>) Nichols plots of <span class="html-italic">T<sub>m</sub></span> when transmission power is ±500 MW. (<b>b</b>) Impedance frequency responses of <span class="html-italic">Z<sub>dc</sub></span><sub>1</sub> and <span class="html-italic">Z<sub>dc</sub></span><sub>2</sub> when transmission power is ±500 MW.</p> Full article ">Figure 8 Cont.
<p>(<b>a</b>) Nichols plots of <span class="html-italic">T<sub>m</sub></span> when transmission power is ±500 MW. (<b>b</b>) Impedance frequency responses of <span class="html-italic">Z<sub>dc</sub></span><sub>1</sub> and <span class="html-italic">Z<sub>dc</sub></span><sub>2</sub> when transmission power is ±500 MW.</p> Full article ">Figure 9
<p>Impedance frequency responses of <span class="html-italic">Z<sub>dc</sub></span><sub>1</sub> and <span class="html-italic">Z<sub>dc</sub></span><sub>2</sub> under different equivalent virtual impedance values (<b>a</b>) <span class="html-italic">R<sub>eq</sub></span> and (<b>b</b>) <span class="html-italic">L<sub>eq</sub>.</span></p> Full article ">Figure 10
<p>Nichols plots of <span class="html-italic">T<sub>m</sub></span> under different equivalent virtual impedance values (<b>a</b>) <span class="html-italic">R<sub>eq</sub></span>; (<b>b</b>) <span class="html-italic">L<sub>eq</sub></span>.</p> Full article ">Figure 11
<p>Nichols plots of <span class="html-italic">T<sub>m</sub></span> under different DC cable lengths.</p> Full article ">Figure 12
<p>Nichols plots of <span class="html-italic">T<sub>m</sub></span> under different DC side capacities.</p> Full article ">Figure 13
<p>Nichols plots of <span class="html-italic">T<sub>m</sub></span> under a different grid impedance.</p> Full article ">Figure 14
<p>DC-link voltage and active power of the VSC–HVDC system under different DC cable lengths.</p> Full article ">Figure 15
<p>DC-link voltage and active power of the VSC–HVDC system under different DC side capacity.</p> Full article ">Figure 16
<p>DC-link voltage and active power of the VSC–HVDC system (<b>a</b>) under the proposed control strategy and traditional control strategy [<a href="#B13-applsci-09-03184" class="html-bibr">13</a>] and (<b>b</b>) under the proposed control strategy with different virtual impedance parameters.</p> Full article ">Figure 17
<p>DC-link voltage and active power of the VSC–HVDC system under the proposed control strategy and traditional virtual impedance.</p> Full article ">Figure 18
<p>DC-link voltage and active power of the VSC–HVDC system under different gird impedance.</p> Full article ">
19 pages, 5197 KiB  
Article
Development of A Loss Minimization Based Operation Strategy for Embedded BTB VSC HVDC
by Jaehyeong Lee, Minhan Yoon, Sungchul Hwang, Soseul Jeong, Seungmin Jung and Gilsoo Jang
Appl. Sci. 2019, 9(11), 2234; https://doi.org/10.3390/app9112234 - 30 May 2019
Cited by 4 | Viewed by 2942
Abstract
Recently, there have been many cases in which direct current (DC) facilities have been placed in alternating current (AC) systems for various reasons. In particular, in Korea, studies are being conducted to install a back-to-back (BTB) voltage-sourced converter (VSC) high-voltage direct current (HVDC) [...] Read more.
Recently, there have been many cases in which direct current (DC) facilities have been placed in alternating current (AC) systems for various reasons. In particular, in Korea, studies are being conducted to install a back-to-back (BTB) voltage-sourced converter (VSC) high-voltage direct current (HVDC) to solve the fault current problem of the meshed system, and discussions on how to operate it have been made accordingly. It is possible to provide grid services such as minimizing grid loss by changing the HVDC operating point, but it also may violate reliability standards without proper HVDC operation according to the system condition. Especially, unlike the AC system, DC may adversely affect the AC system because the operating point does not change even after a disturbance has occurred, so strategies to change the operating point after the contingency are required. In this paper, a method for finding the operating point of embedded HVDC that minimizes losses within the range of compliance with the reliability criterion is proposed. We use the Power Transfer Distribution Factor (PTDF) to reduce the number of buses to be monitored during HVDC control, reduce unnecessary checks, and determine the setpoints for the active/reactive power of the HVDC through system total loss minimization (STLM) control to search for the minimum loss point using Powell’s direct set. We also propose an algorithm to search for the operating point that minimizes the loss automatically and solves the overload occurring in an emergency through security-constrained loss minimization (SCLM) control. To verify the feasibility of the algorithm, we conducted a case study using an actual Korean power system and verified the effect of systematic loss reduction and overload relief in a contingency. The simulations are conducted by a commercial power system analysis tool, Power System Simulator for Engineering (PSS/E). Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
►▼ Show Figures

Figure 1

Figure 1
<p>HVDC fault calculation model (PQ bus mode).</p> Full article ">Figure 2
<p>Proposed control scheme.</p> Full article ">Figure 3
<p>Power flow change caused by back-to-back (BTB) HVDC active power operation.</p> Full article ">Figure 4
<p>Algorithm of the system total loss minimization (STLM) control.</p> Full article ">Figure 5
<p>Algorithm of the security-constrained loss minimization (SCLM) control.</p> Full article ">Figure 6
<p>BTB siting in the Korean metropolitan area (1411–1410).</p> Full article ">Figure 7
<p>Simulation proceeds for SCLM control.</p> Full article ">Figure 8
<p>Active power operation change in the transformer overload case.</p> Full article ">Figure 9
<p>Reactive power operation change in the transformer overload case at the rectifier end.</p> Full article ">Figure 10
<p>Reactive power operation change in the transformer overload case at the inverter end.</p> Full article ">Figure 11
<p>Comparison of HVDC control for overload mitigation in the transformer overload case.</p> Full article ">Figure 12
<p>Active power operation change in the line overload case.</p> Full article ">Figure 13
<p>Reactive power operation change in the line overload case at the rectifier end.</p> Full article ">Figure 14
<p>Reactive power operation change in the line overload case at the inverter end.</p> Full article ">Figure 15
<p>Comparison of HVDC control for overload mitigation in the line overload case.</p> Full article ">
11 pages, 7257 KiB  
Article
A Novel Overcurrent Suppression Strategy during Reclosing Process of MMC-HVDC
by Bin Jiang and Yanfeng Gong
Appl. Sci. 2019, 9(9), 1737; https://doi.org/10.3390/app9091737 - 26 Apr 2019
Cited by 2 | Viewed by 2791
Abstract
A modular multilevel converter based high-voltage DC (MMC-HVDC) system has been the most promising topology for HVDC. A reclosing scheme is usually configured because temporary faults often occur on transmission lines especially when overhead lines are used, which often brings about an overcurrent [...] Read more.
A modular multilevel converter based high-voltage DC (MMC-HVDC) system has been the most promising topology for HVDC. A reclosing scheme is usually configured because temporary faults often occur on transmission lines especially when overhead lines are used, which often brings about an overcurrent problem. In this paper, a new fault current limiter (FCL) based on reclosing current limiting resistance (RCLR) is proposed to solve the overcurrent problem during the reclosing process. Firstly, a mesh current method (MCM) based short-circuit current calculation method is newly proposed to solve the fault current calculation of a loop MMC-HVDC grid. Then the method to calculate the RCLR is proposed based on the arm current to limit the arm currents to a specified value during the reclosing process. Finally, a three-terminal loop MMC-HVDC test grid is constructed in the widely used electromagnetic transient simulation software PSCAD/EMTDC and the simulations prove the effectiveness of the proposed strategy. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
►▼ Show Figures

Figure 1

Figure 1
<p>Fault current path of a pole-to-pole fault before converter blocking.</p> Full article ">Figure 2
<p>Equivalent circuit of the converter under a pole-to-pole fault before converter blocking.</p> Full article ">Figure 3
<p>The fault response after converter blocking: (<b>a</b>) free-wheeling; (<b>b</b>) uncontrolled rectifier.</p> Full article ">Figure 4
<p>The diagram of the three-terminal loop modular multilevel converter based high-voltage DC (MMC-HVDC) grid.</p> Full article ">Figure 5
<p>The equivalent circuit of SMs discharging under pole-to-pole fault.</p> Full article ">Figure 6
<p>The structure of the proposed current fault limiter.</p> Full article ">Figure 7
<p>The sequence of fault ride-through when reclosing a permanent fault.</p> Full article ">Figure 8
<p>The equivalent circuit of SMs discharging with reclosing current limiting resistance (RCLR).</p> Full article ">Figure 9
<p>The maximum calculated arm currents with the different RCLR.</p> Full article ">Figure 10
<p>MMC1 DC fault current in <span class="html-italic">line</span><sub>12</sub>.</p> Full article ">Figure 11
<p>Arm current and blocking signal without RCLR.</p> Full article ">Figure 12
<p>Arm current and blocking signal with RCLR.</p> Full article ">
13 pages, 6113 KiB  
Article
Application of a DC Distribution System in Korea: A Case Study of the LVDC Project
by Juyong Kim, Hyunmin Kim, Youngpyo Cho, Hongjoo Kim and Jintae Cho
Appl. Sci. 2019, 9(6), 1074; https://doi.org/10.3390/app9061074 - 14 Mar 2019
Cited by 4 | Viewed by 3551
Abstract
With the rapid expansion of renewable energy and digital devices, there is a need for direct current (DC) distribution technology that can increase energy efficiency. As a result, DC distribution research is actively underway to cope with the sudden digitization and decentralization of [...] Read more.
With the rapid expansion of renewable energy and digital devices, there is a need for direct current (DC) distribution technology that can increase energy efficiency. As a result, DC distribution research is actively underway to cope with the sudden digitization and decentralization of load environment and power supply. To verify the possibility of DC distribution, Korea Electric Power Corporation (KEPCO) Research Institute made a DC distribution system connected with a real power system in Gwangju. The construction of the demonstration area mainly includes design of protection and grounding systems, operating procedures of insulation monitoring device (IMD), and construction of power converters. Furthermore, this paper goes beyond the simulation and the lab testing to apply DC distribution to a real system operation in advance. It is designed as a long-distance low-loaded customer for rural areas and operated by the DC distribution. In addition, safety and reliability are confirmed through field tests of DC distribution elements such as power conversion devices, protection and grounding systems. In particular, to improve the reliability of non-grounding system, the insulation monitoring device was installed and the algorithms of its operational procedures are proposed. Finally, this paper analyzes the problems caused by operating the actual DC distribution and suggests solutions accordingly. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
►▼ Show Figures

Figure 1

Figure 1
<p>Ground Fault IT(Isolate-Terra) System.</p> Full article ">Figure 2
<p>Correlation diagram of pole voltage, insulation level, and contact voltage in IT ground.</p> Full article ">Figure 3
<p>Simulation of ground fault in DC distribution line of IT ground: (<b>a</b>) underground line; (<b>b</b>) overhead line.</p> Full article ">Figure 4
<p>Proposed insulation monitoring device (IMD) operating procedures.</p> Full article ">Figure 5
<p>Design of protection system for DC distribution.</p> Full article ">Figure 6
<p>Configuration of DC demonstration site.</p> Full article ">Figure 7
<p>Fault detection test case 1.</p> Full article ">Figure 8
<p>Fault detection test case 1 result waveform.</p> Full article ">Figure 9
<p>Fault detection test case 2.</p> Full article ">Figure 10
<p>Actual DC distribution line configuration.</p> Full article ">Figure 11
<p>Measurement of insulation resistance.</p> Full article ">Figure 12
<p>Input and output data of AC/DC Converter. (<b>a</b>) Input voltage and power. (<b>b</b>) Output voltage and power.</p> Full article ">Figure 13
<p>Waveform of protective action.</p> Full article ">
12 pages, 2114 KiB  
Article
A Quantitative Index to Evaluate the Commutation Failure Probability of LCC-HVDC with a Synchronous Condenser
by Jiangbo Sha, Chunyi Guo, Atiq Ur Rehman and Chengyong Zhao
Appl. Sci. 2019, 9(5), 925; https://doi.org/10.3390/app9050925 - 5 Mar 2019
Cited by 13 | Viewed by 3687
Abstract
Since thyristor cannot turn off automatically, line commutated converter based high voltage direct current (LCC-HVDC) will inevitably fail to commutate and therefore auxiliary controls or voltage control devices are needed to improve the commutation failure immunity of the LCC-HVDC system. The voltage control [...] Read more.
Since thyristor cannot turn off automatically, line commutated converter based high voltage direct current (LCC-HVDC) will inevitably fail to commutate and therefore auxiliary controls or voltage control devices are needed to improve the commutation failure immunity of the LCC-HVDC system. The voltage control device, a synchronous condenser (SC), can effectively suppress the commutation failure of the LCC-HVDC system. However, there is a need for a proper evaluation index that can quantitatively assess the ability of the LCC-HVDC system to resist the occurrence of commutation failures. At present, the main quantitative evaluation indicators include the commutation failure immunity index and the commutation failure probability index. Although they can reflect the resistance of the LCC-HVDC system to commutation failures to a certain extent, they are all based on specific working conditions and cannot comprehensively evaluate the impact of SCs on suppressing the commutation failure of the LCC-HVDC system under certain fault ranges. In order to more comprehensively and quantitatively evaluate the influence of SCs on the commutation failure susceptibility of the LCC-HVDC system under certain fault ranges, this paper proposes the area ratio of commutation failure probability. The accuracy of this new index was verified through the PSCAD/EMTDC. Based on the CIGRE benchmark model, the effects of different synchronous condensers on LCC-HVDC commutation failure were analyzed. The results showed that the new index could effectively and more precisely evaluate the effect of SCs on commutation failures. Moreover, the proposed index could provide a theoretical basis for the capacity allocation of SCs in practical projects and it could also be utilized for evaluating the impact of other dynamic reactive power compensators on the commutation failure probability of the LCC-HVDC system under certain fault ranges. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
►▼ Show Figures

Figure 1

Figure 1
<p>Schematic diagram of the LCC-HVDC system with a synchronous condenser.</p> Full article ">Figure 2
<p>Control mechanism for the LCC-HVDC system.</p> Full article ">Figure 3
<p>Control mechanism for the synchronous condenser.</p> Full article ">Figure 4
<p>Feature comparison under the three-phase fault.</p> Full article ">Figure 5
<p>Flow-chart of the area ratio of the commutation failure probability computing method.</p> Full article ">Figure 6
<p>Schematic presentation of area of commutation failure probability with and without a SC.</p> Full article ">Figure 7
<p>The probability of commutation failure (CF) in different cases under single phase to ground fault.</p> Full article ">Figure 8
<p>The probability of commutation failure (CF) in different cases under three phase fault.</p> Full article ">Figure 9
<p>Area ratio of commutation failure probability in different cases under single phase to ground fault.</p> Full article ">Figure 10
<p>Area ratio of commutation failure probability in different cases under three phase fault.</p> Full article ">
14 pages, 2535 KiB  
Article
A Frequency–Power Droop Coefficient Determination Method of Mixed Line-Commutated and Voltage-Sourced Converter Multi-Infeed, High-Voltage, Direct Current Systems: An Actual Case Study in Korea
by Gyusub Lee, Seungil Moon and Pyeongik Hwang
Appl. Sci. 2019, 9(3), 606; https://doi.org/10.3390/app9030606 - 12 Feb 2019
Cited by 7 | Viewed by 3825
Abstract
Among the grid service applications of high-voltage direct current (HVDC) systems, frequency–power droop control for islanded networks is one of the most widely used schemes. In this paper, a new frequency-power droop coefficient determination method for a mixed line-commutated converter (LCC) and voltage-sourced [...] Read more.
Among the grid service applications of high-voltage direct current (HVDC) systems, frequency–power droop control for islanded networks is one of the most widely used schemes. In this paper, a new frequency-power droop coefficient determination method for a mixed line-commutated converter (LCC) and voltage-sourced converter (VSC)-based multi-infeed HVDC (MIDC) system is proposed. The proposed method is designed for the minimization of power loss. An interior-point method is used as an optimization algorithm to implement the proposed scheduling method, and the droop coefficients of the HVDCs are determined graphically using the Monte Carlo sampling method. Two test systems—the modified Institute of Electrical and Electronics Engineers (IEEE) 14-bus system and an actual Jeju Island network in Korea—were utilized for MATLAB simulation case studies, to demonstrate that the proposed method is effective for reducing power system loss during frequency control. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
►▼ Show Figures

Figure 1

Figure 1
<p>Concept of the method to determine frequency–power droop coefficients of voltage sourced converter (VSC) and line commutated converter (LCC) high-voltage direct currents (HVDCs).</p> Full article ">Figure 2
<p>Overall procedure of the proposed method to calculate droop coefficients.</p> Full article ">Figure 3
<p>Configuration of Institute of Electrical and Electronics Engineers (IEEE) 14-bus test system.</p> Full article ">Figure 4
<p>Forecasted load profile for the IEEE 14-bus test system.</p> Full article ">Figure 5
<p>Voltage profile of the conventional and proposed methods in the IEEE 14-bus test system.</p> Full article ">Figure 6
<p>Graphical coefficient determination method applied to the IEEE 14-bus test system.</p> Full article ">Figure 7
<p>Configuration of the Jeju Island network with multiple HVDCs.</p> Full article ">Figure 8
<p>Load profile for Jeju Island.</p> Full article ">Figure 9
<p>Graphical analysis of the coefficient determination method applied to the Jeju Island system.</p> Full article ">
17 pages, 4492 KiB  
Article
Analysis of Six Active Power Control Strategies of Interconnected Grids with VSC-HVDC
by Sungyoon Song, Minhan Yoon and Gilsoo Jang
Appl. Sci. 2019, 9(1), 183; https://doi.org/10.3390/app9010183 - 6 Jan 2019
Cited by 8 | Viewed by 5000
Abstract
In this paper, the generator angle stability of several active power control schemes of a voltage-source converter (VSC)-based high-voltage DC (HVDC) is evaluated for two interconnected AC systems. Excluding frequency control, there has been no detailed analysis of interconnected grids depending upon the [...] Read more.
In this paper, the generator angle stability of several active power control schemes of a voltage-source converter (VSC)-based high-voltage DC (HVDC) is evaluated for two interconnected AC systems. Excluding frequency control, there has been no detailed analysis of interconnected grids depending upon the converter power control, so six different types of active power control of the VSC-HVDC are defined and analyzed in this paper. For each TSO (transmission system operator), the applicable schemes of two kinds of step control and four kinds of ramp-rate control with a droop characteristic are included in this research. Furthermore, in order to effectively evaluate the angle stability, the Generators-VSC Interaction Factor (GVIF) index is newly implemented to distinguish the participating generators (PGs) group which reacts to the converter power change. As a result, the transient stabilities of the two power systems are evaluated and the suitable active power control strategies are determined for two TSOs. Simulation studies are performed using the PSS®E program to analyze the power system transient stability and various active power control schemes of the VSC-HVDC. The results provide useful information indicating that the ramp-rate control shows a more stable characteristic than the step-control for interconnected grids; thus, a converter having a certain ramp-rate slope similar to that of the other generator shows more stable results in several cases. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
►▼ Show Figures

Figure 1

Figure 1
<p>Two interconnected grids with a voltage-source converter (VSC)-based high-voltage DC (HVDC).</p> Full article ">Figure 2
<p>VSC control block diagram. PWM: Pulse With Modulation; PLL Phase-Locked Loop.</p> Full article ">Figure 3
<p>D-axis current control structure of the VSC; PI: Proportional and Integral.</p> Full article ">Figure 4
<p>Two major active power control schemes: (<b>a</b>) step control (<b>b</b>) ramp-rate control with different ramp-rate slopes (RRSs).</p> Full article ">Figure 5
<p>Different RRSs of ramp-rate control; DB: difference between.</p> Full article ">Figure 6
<p>Contingency scenario in area 2.</p> Full article ">Figure 7
<p>Frequency drop during a contingency event in area 2.</p> Full article ">Figure 8
<p>Six active power control schemes: (<b>a</b>) step control at <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>1</mn> </msub> </mrow> </semantics></math>; (<b>b</b>) step control at <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>2</mn> </msub> </mrow> </semantics></math>; (<b>c</b>) ramp-rate control with high RRS between <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>1</mn> </msub> </mrow> </semantics></math> and <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>2</mn> </msub> </mrow> </semantics></math>; (<b>d</b>) ramp-rate control with low RRS between <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>1</mn> </msub> </mrow> </semantics></math> and <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>2</mn> </msub> </mrow> </semantics></math>; (<b>e</b>) ramp-rate control with high RRS between <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>2</mn> </msub> </mrow> </semantics></math> and <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>3</mn> </msub> </mrow> </semantics></math>; (<b>f</b>) ramp-rate control with low RRS between <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>2</mn> </msub> </mrow> </semantics></math> and <math display="inline"><semantics> <mrow> <msub> <mi>t</mi> <mn>3</mn> </msub> </mrow> </semantics></math>.</p> Full article ">Figure 9
<p>System configuration for simulation studies.</p> Full article ">Figure 10
<p>Six power control schemes of the VSC-HVDC.</p> Full article ">Figure 11
<p>Angle spread results of each area according to (a) and (b) in <a href="#applsci-09-00183-t001" class="html-table">Table 1</a>.</p> Full article ">Figure 12
<p>Angle spread results of each area according to (c) and (d) in <a href="#applsci-09-00183-t001" class="html-table">Table 1</a>.</p> Full article ">Figure 13
<p>Angle spread results of each area according to (e) and (f) in <a href="#applsci-09-00183-t001" class="html-table">Table 1</a>.</p> Full article ">Figure 14
<p>Angle spread results of each area according to (c) and (e) in <a href="#applsci-09-00183-t001" class="html-table">Table 1</a>.</p> Full article ">Figure 15
<p>Angle spread results of each area according to (b) and (e).</p> Full article ">Figure 16
<p>Angle spread results of each area according to (a) and (e).</p> Full article ">
15 pages, 7188 KiB  
Article
Assessment of Appropriate MMC Topology Considering DC Fault Handling Performance of Fault Protection Devices
by Ho-Yun Lee, Mansoor Asif, Kyu-Hoon Park and Bang-Wook Lee
Appl. Sci. 2018, 8(10), 1834; https://doi.org/10.3390/app8101834 - 6 Oct 2018
Cited by 5 | Viewed by 4249
Abstract
The eventual goal of high-voltage direct-voltage (HVDC) systems is to implement HVDC grids. The modular multilevel converter (MMC) has been identified as the best candidate for the realization of an HVDC grid by eliminating the shortcomings of conventional voltage source converter (VSC) technology. [...] Read more.
The eventual goal of high-voltage direct-voltage (HVDC) systems is to implement HVDC grids. The modular multilevel converter (MMC) has been identified as the best candidate for the realization of an HVDC grid by eliminating the shortcomings of conventional voltage source converter (VSC) technology. The related research has focused on efficient control schemes, new MMC topologies, and operational characteristics of an MMC in a DC grid, but there is little understanding about the fault handling capability of two mainstream MMC topologies, i.e., half bridge (HB) and full bridge (FB) MMCs in combination with an adequate protection device. Contrary to the existing research where the fault location is usually fixed (center of the line), this paper considered a variable fault location on the DC line, so as to compare the fault interruption time and maximum fault current magnitude. From the point of view of fault interruption, AC and DC side transient analyses were performed for both MMC topologies to suggest the appropriate topology. The simulation result confirmed that the fault handling performance of an HB-MMC with a DC circuit breaker is superior due to the smaller fault current magnitude, faster interruption time, lower overvoltage magnitude, and lesser stresses on the insulation of the DC grid. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
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Figure 1

Figure 1
<p>Equivalent circuit of a modular multilevel converter (MMC) system composed of a half bridge (HB) or full bridge (FB) configuration.</p> Full article ">Figure 2
<p>Test bed model in Matlab/Simulink. Converters are composed of 40-level HB- and FB-MMCs. The pole-to-pole DC fault is introduced at a variable distance from the rectifier.</p> Full article ">Figure 3
<p>Comparison of overall operating characteristics and the need for a current-limiting reactor.</p> Full article ">Figure 4
<p>Case-1: DC fault handling solution for an HB-MMC based on a hybrid circuit breaker (HCB): (<b>a</b>) configuration of Case-1; (<b>b</b>) structure of the HCB; (<b>c</b>) fault handling under a DC short-circuit fault.</p> Full article ">Figure 5
<p>Case-2: DC fault handling solution composed of an FB-MMC with a residual circuit breaker (RCB): (<b>a</b>) configuration of Case-2; (<b>b</b>) operation process for DC fault handling under a DC short-circuit fault.</p> Full article ">Figure 6
<p>Simulation of a DC pole-to-pole fault with MMCs: (<b>a</b>) current waveform in the transient state; (<b>b</b>) voltage waveform in the transient state.</p> Full article ">Figure 7
<p>Simulation of a DC pole-to-ground fault with MMCs: (<b>a</b>) current waveform in the transient state; (<b>b</b>) voltage measured at converter terminals.</p> Full article ">Figure 8
<p>Fault handling interruption performances: (<b>a</b>) fault current interruption characteristic of Case-1 with an HCB; (<b>b</b>) fault current interruption characteristic of Case-2 with an RCB.</p> Full article ">Figure 9
<p>Comparison analysis of interruption characteristics according to the location of the fault on the DC line: (<b>a</b>) interruption time; (<b>b</b>) maximum fault current magnitude.</p> Full article ">Figure 10
<p>Comparison of energy dissipation on the circuit breaker (CB). Case-1 is an HCB; Case-2 is an RCB.</p> Full article ">Figure 11
<p>The transient waveforms of the AC system in Case-1: (<b>a</b>) current waveform; (<b>b</b>) voltage waveform.</p> Full article ">Figure 12
<p>The current and voltage waveform at the AC side of Case-2 in interruption and reclosing operations: (<b>a</b>) current waveform; (<b>b</b>) voltage waveform.</p> Full article ">Figure 13
<p>The waveform of the DC line current and voltage across the CB in the transient state: (<b>a</b>) the DC line current; (<b>b</b>) the voltage across the CB.</p> Full article ">Figure 14
<p>The waveform of pole-to-pole DC voltage in the case of pole-to-pole fault.</p> Full article ">Figure 15
<p>The waveform of pole-to-ground DC voltage in the fault and reclosing process: (<b>a</b>) Case-1; (<b>b</b>) Case-2.</p> Full article ">
25 pages, 15837 KiB  
Article
A Study on Stability Control of Grid Connected DC Distribution System Based on Second Order Generalized Integrator-Frequency Locked Loop (SOGI-FLL)
by Jin-Wook Kang, Ki-Woong Shin, Hoon Lee, Kyung-Min Kang, Jintae Kim and Chung-Yuen Won
Appl. Sci. 2018, 8(8), 1387; https://doi.org/10.3390/app8081387 - 16 Aug 2018
Cited by 7 | Viewed by 6632
Abstract
This paper studies a second order generalized integrator-frequency locked loop (SOGI-FLL) control scheme applicable for 3-phase alternating current/direct current (AC/DC) pulse width modulation (PWM) converters used in DC distribution systems. The 3-phase AC/DC PWM converter is the most important power conversion system of [...] Read more.
This paper studies a second order generalized integrator-frequency locked loop (SOGI-FLL) control scheme applicable for 3-phase alternating current/direct current (AC/DC) pulse width modulation (PWM) converters used in DC distribution systems. The 3-phase AC/DC PWM converter is the most important power conversion system of DC distribution, since it can boost 380 Vrms 3-phase line-to-line AC voltage to 700 Vdc DC output with various DC load devices and grid voltages. The direct-quadrature (d-q) transformation, positive sequence voltage extraction, proportional integral (PI) voltage/current control, and phase locked loop (PLL) are necessary to control the 3-phase AC/DC PWM converter. Besides, a digital filter, such as low pass filter and all pass filter, are essential in the conventional synchronous reference frame-phase locked loop (SRF-PLL) method to eliminate the low order harmonics of input. However, they limit the bandwidth of the controller, which directly affects the output voltage and load of 3-phase AC/DC PWM converter when sever voltage fluctuation, such as sag, swell, etc. occurred in the grid. On the other hand, the proposed control method using SOGI-FLL is able to do phase angle detection, positive sequence voltage extraction, and harmonic filtering without additional digital filters, so that more stable and fast transient control is achieved in the DC distribution system. To verify the improvement of the characteristics in the unbalanced voltage and frequency fluctuation of the grid, a simulation and experiment are implemented with 50 kW 3-phase AC/DC PWM converter used in DC distribution. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
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Figure 1

Figure 1
<p>Configuration of 3-phase alternating current/direct current (AC/DC) pulse width modulation (PWM) converter.</p> Full article ">Figure 2
<p>Equivalent circuit of 3-phase AC/DC PWM converter.</p> Full article ">Figure 3
<p>Equivalent circuit of a 3-phase AC/DC PWM converter.</p> Full article ">Figure 4
<p>Phasor diagram of a 3-phase AC/DC PWM converter.</p> Full article ">Figure 5
<p>Control block diagram of positive sequence voltage and phase detector.</p> Full article ">Figure 6
<p>Control block diagram of phase detector using first order low pass filter and proportional integral (PI) controller.</p> Full article ">Figure 7
<p>Control block diagram of second order generalized integrator (SOGI)-based adaptive filter (AF) (= SOGI-quadrature signal generator (QSG)).</p> Full article ">Figure 8
<p>Comparison of transfer function <math display="inline"><semantics> <mrow> <mi>D</mi> <mo stretchy="false">(</mo> <mi>s</mi> <mo stretchy="false">)</mo> </mrow> </semantics></math> and <math display="inline"><semantics> <mrow> <mi>Q</mi> <mo stretchy="false">(</mo> <mi>s</mi> <mo stretchy="false">)</mo> </mrow> </semantics></math>.</p> Full article ">Figure 9
<p>Characteristics of SOGI-based AF various gain <math display="inline"><semantics> <mi>k</mi> </semantics></math>.</p> Full article ">Figure 10
<p>Control block diagram of SOGI-frequency locked loop (FLL) for phase synchronization.</p> Full article ">Figure 11
<p>Comparison of transfer functions <math display="inline"><semantics> <mrow> <mi>E</mi> <mo stretchy="false">(</mo> <mi>s</mi> <mo stretchy="false">)</mo> </mrow> </semantics></math> and <math display="inline"><semantics> <mrow> <mi>Q</mi> <mo stretchy="false">(</mo> <mi>s</mi> <mo stretchy="false">)</mo> </mrow> </semantics></math>.</p> Full article ">Figure 12
<p>3-phase SOGI-FLL (= DSOGI-FLL).</p> Full article ">Figure 13
<p>Positive sequence voltage extractor using 3-phase SOGI-FLL.</p> Full article ">Figure 14
<p>Control block diagram of 3-phase AC/DC PWM converter with SOGI-FLL.</p> Full article ">Figure 15
<p>3-phase AD/DC PWM converter schematic of DC distribution system used in simulation.</p> Full article ">Figure 16
<p>Input and output waveforms of DC distribution system (<b>a</b>) the dc-link voltage; (<b>b</b>) the current of the DC load; and, (<b>c</b>) the current of the grid.</p> Full article ">Figure 17
<p>Waveform of voltage when harmonics is included in input side; (<b>a</b>) the 3-phase input voltage with harmonic components; and, (<b>b</b>) the 3-phase input voltage detected by the SOGI-FLL.</p> Full article ">Figure 18
<p>Waveforms of simulation results when <math display="inline"><semantics> <mi>b</mi> </semantics></math> phase has a voltage drop; (<b>a</b>) the dc-link voltage; (<b>b</b>) the 3-phase input voltage with voltage unbalance; (<b>c</b>) the 3-phase input positive voltage detected by SOGI-FLL; (<b>d</b>) the 3-phase input current; and, (<b>e</b>) the center frequency extracted from SOGI-FLL.</p> Full article ">Figure 18 Cont.
<p>Waveforms of simulation results when <math display="inline"><semantics> <mi>b</mi> </semantics></math> phase has a voltage drop; (<b>a</b>) the dc-link voltage; (<b>b</b>) the 3-phase input voltage with voltage unbalance; (<b>c</b>) the 3-phase input positive voltage detected by SOGI-FLL; (<b>d</b>) the 3-phase input current; and, (<b>e</b>) the center frequency extracted from SOGI-FLL.</p> Full article ">Figure 19
<p>Waveforms of simulation results when voltage drop is occurred; (<b>a</b>) the positive and negative sequence voltage; and, (<b>b</b>) the phase angle of the positive and negative sequence voltage.</p> Full article ">Figure 20
<p>Waveforms of simulation results when grid frequency decreased from 60 Hz to 45 Hz drop; (<b>a</b>) the dc-link voltage; (<b>b</b>) the 3-phase input voltage; (<b>c</b>) the 3-phase input positive voltage detected by SOGI-FLL; (<b>d</b>) the 3-phase input current; and, (<b>e</b>) the center frequency that was extracted from SOGI-FLL.</p> Full article ">Figure 20 Cont.
<p>Waveforms of simulation results when grid frequency decreased from 60 Hz to 45 Hz drop; (<b>a</b>) the dc-link voltage; (<b>b</b>) the 3-phase input voltage; (<b>c</b>) the 3-phase input positive voltage detected by SOGI-FLL; (<b>d</b>) the 3-phase input current; and, (<b>e</b>) the center frequency that was extracted from SOGI-FLL.</p> Full article ">Figure 21
<p>Waveforms of simulation results when frequency suddenly change (<b>a</b>) the DC-link voltage, <span class="html-italic">d</span> and <span class="html-italic">q</span>-axis voltage in synchronous reference frame with conventional synchronous reference frame-phase locked loop (SRF-PLL) (<b>b</b>) the DC-link voltage, <span class="html-italic">d</span> and <span class="html-italic">q</span>-axis voltage in synchronous reference frame with proposed control method.</p> Full article ">Figure 22
<p>Configuration of the experiment system. MC: Magnetic Contactor.</p> Full article ">Figure 23
<p>Experiment setup 1 of the 3-phase AC/DC PWM converter.</p> Full article ">Figure 24
<p>Experiment setup 2 of the 3-phase AC/DC PWM converter. SMPS: switched-mode power supply; DSP: digital signal processor; MCCB: molded case circuit breaker.</p> Full article ">Figure 25
<p>Waveform of 3-phase AC/DC PWM converter operation.</p> Full article ">Figure 26
<p>Waveform of input phase current of 3-phase AC/DC PWM converter.</p> Full article ">Figure 27
<p>Waveform of input phase <math display="inline"><semantics> <mi>a</mi> </semantics></math> voltage and current.</p> Full article ">Figure 28
<p>Waveforms of extracted 3-phase positive sequence input voltage using SOGI-FLL when the <math display="inline"><semantics> <mi>b</mi> </semantics></math> phase has voltage drop.</p> Full article ">Figure 29
<p>Waveform of detected positive/negative sequence <math display="inline"><semantics> <mrow> <mi>α</mi> <mi>β</mi> </mrow> </semantics></math> voltage and phase angle <math display="inline"><semantics> <mi>θ</mi> </semantics></math> (before and after <math display="inline"><semantics> <mi>b</mi> </semantics></math> phase voltage drop).</p> Full article ">
14 pages, 6588 KiB  
Article
Novel Transient Power Control Schemes for BTB VSCs to Improve Angle Stability
by Sungyoon Song, Sungchul Hwang, Baekkyeong Ko, Seungtae Cha and Gilsoo Jang
Appl. Sci. 2018, 8(8), 1350; https://doi.org/10.3390/app8081350 - 11 Aug 2018
Cited by 7 | Viewed by 3770
Abstract
This paper proposes two novel power control strategies to improve the angle stability of generators using a Back-to-Back (BTB) system-based voltage source converter (VSC). The proposed power control strategies have two communication systems: a bus angle monitoring system and a special protection system [...] Read more.
This paper proposes two novel power control strategies to improve the angle stability of generators using a Back-to-Back (BTB) system-based voltage source converter (VSC). The proposed power control strategies have two communication systems: a bus angle monitoring system and a special protection system (SPS), respectively. The first power control strategy can emulate the behaviour of the ac transmission to improve the angle stability while supporting the ac voltage at the primary level of the control structure. The second power control scheme uses an SPS signal to contribute stability to the power system under severe contingencies involving the other generators. The results for the proposed control scheme were validated using the PSS/E software package with a sub-module written in the Python language, and the simple assistant power control with two communication systems is shown to improve the angle stability. In conclusion, BTB VSCs can contribute their power control strategies to ac grid in addition to offering several existing advantages, which makes them applicable for use in the commensurate protection of large ac grid. Full article
(This article belongs to the Special Issue HVDC for Grid Services in Electric Power Systems)
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Graphical abstract

Graphical abstract
Full article ">Figure 1
<p>Voltage Source Converter single diagram.</p> Full article ">Figure 2
<p>Inner current control loop.</p> Full article ">Figure 3
<p>The first power control model structure of BTB.</p> Full article ">Figure 4
<p>(<b>a</b>) Capability curve of BTB VSC and (<b>b</b>) determination process of <math display="inline"><semantics> <mrow> <msub> <mi>P</mi> <mrow> <mi>r</mi> <mi>e</mi> <mi>s</mi> </mrow> </msub> </mrow> </semantics></math> value.</p> Full article ">Figure 5
<p>The second power control model of BTB VSC.</p> Full article ">Figure 6
<p>Equal Area Criterion with the second power control strategy.</p> Full article ">Figure 7
<p>Simulation environment in Korea power system.</p> Full article ">Figure 8
<p>Contingency scenarios.</p> Full article ">Figure 9
<p>The limiter configuration in simulation study.</p> Full article ">Figure 10
<p>Angle spread of ac grid, (<b>a</b>) left side fault (<math display="inline"><semantics> <mrow> <msub> <mi>θ</mi> <mi>y</mi> </msub> <mo stretchy="false">)</mo> </mrow> </semantics></math>, and (<b>b</b>) right side fault (<math display="inline"><semantics> <mrow> <msub> <mi>θ</mi> <mi>x</mi> </msub> <mo stretchy="false">)</mo> </mrow> </semantics></math>.</p> Full article ">Figure 11
<p>Active power of BTB VSCs, (<b>a</b>) left side fault (<math display="inline"><semantics> <mrow> <msub> <mi>θ</mi> <mi>y</mi> </msub> <mo stretchy="false">)</mo> </mrow> </semantics></math>, and (<b>b</b>) right side fault (<math display="inline"><semantics> <mrow> <msub> <mi>θ</mi> <mi>x</mi> </msub> <mo stretchy="false">)</mo> </mrow> </semantics></math>.</p> Full article ">Figure 12
<p>Active power of BTB VSCs with different <math display="inline"><semantics> <mrow> <msub> <mi>P</mi> <mrow> <mi>r</mi> <mi>e</mi> <mi>s</mi> </mrow> </msub> </mrow> </semantics></math>.</p> Full article ">Figure 13
<p>Angle spread result in an N-2 Contingency.</p> Full article ">
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