Providing dc fault ride-through capability to H-bridge MMC-based HVDC Networks E. Kontos, R. Teixeira Pinto and P. Bauer Delft University of Technology, Delft, The Netherlands Email:
[email protected],
[email protected],
[email protected]
Abstract—This paper proposes a framework to achieve dc fault of the different assets and isolate the fault before the developing ride-through capability in multi-terminal dc networks (MTdc), dc currents reach critical levels. Finally, the operation in the when H-bridge multilevel modular converters (MMC) are used. ‘healthy’ part of the grid should be restored as fast as possible, The studied network consists of four voltage-source converters (VSC) for high voltage direct current (HVdc) transmission. Two minimizing the financial and power losses. Several studies have addressed the first two points of grid of these VSC converters connect two offshore wind farms (OWF) to the main HVdc link between two asynchronous onshore grids, reaction in dc contingency cases. Previous research has been in a radial configuration. In case of a dc fault, H-bridge MMCs conducted on the dc fault currents developing stages [10], are able to block the fast developing currents and drive them as well as on dc fault selective detection and localization to zero, allowing for fast mechanical disconnectors to isolate the faulty cable segment and reconfigure the grid layout. In this methods [11], [12]. As the main disadvantage of the MMC-VSC paper, the effect of the dc fault location to the grid behavior is technology stems from the inability of the converters to block analysed both at the fault isolation phase, as well as at the grid developing dc fault currents, several studies have investigated restoration phase. Moreover, the worst-case dc fault scenario for the design of HVdc breakers [13], while other protection the studied network is identified. Finally, the total fault recovery concepts along with different converter designs have been time of the MTdc network is estimated. The study showed that Hbridge MMCs are unable to isolate the faulty part of the network proposed [14]–[16]. Based on these studies, two main protection without de-energizing the MTdc grid. However, the proposed strategies of HVdc connections can be identified: first, the use framework allows for fast grid restoration within 3.6 s without of half-bridge MMC along with dc breakers and second, the the need for expensive dc breakers. use of H-bridge MMC with mechanical disconnectors on the
dc side. However, the grid restoration problem remains open. This paper addresses the problem of HVdc grid restoration after faults in the dc transmission system. The main contribution I. I NTRODUCTION of this paper is the proposal of a step-by-step framework The increasing penetration of renewable energy systems to that provides fault ride-through capability to HVdc networks the grid requires a thorough reconsideration of the structure of that are based on H-bridge MMCs coupled with mechanical transmission systems. To achieve a more efficient harvest of disconnectors on the dc side. Hereby, the black-start capability remotely placed renewable sources high-voltage dc transmission of the MTdc network is investigated and the timeframe in (HVdc) can be used. Voltage-source converters (VSC) and which the power flow can be restored is evaluated. Moreover, especially Multilevel Modular converters (MMC), constitute a an analysis of the network response to dc faults at different fast advancing technology, which offers many control advan- locations is performed and the most critical parameters that tages over its Line-commutated converter (LCC) counterpart. affect the development of the fault currents are identified. Therefore, MMC-VSC is favored for the connection of far The rest of the paper is structured as follows: Section II offshore wind farms (OWF), while at the same time it can presents the methodology on which the rest of the paper is facilitate the construction of multi-terminal HVdc (MTdc) based. In Section III, a case study is established and the networks [1]. parameters of the network, as well as of the converter stations As the number of point-to-point HVdc connections increases, are presented. Section IV discusses the techniques employed the need for robust interconnection of the terminals in an MTdc at different points of the grid for the detection and isolation network also increases. However, several aspects need to be of the dc fault. Section V demonstrates the dynamic analysis studied before the successful deployment of MTdc networks. of the dc fault behavior of the grid. Based on the obtained Power flow control and optimization techniques have been results, a grid restoration technique is proposed and simulated extensively studied in [2]–[6], while plenty of research has for three different fault case studies in Section VI. Finally, in focussed on system integration issues [7]–[9]. In addition to Section VII, conclusions are drawn on the effectiveness of the those issues, the dc fault behavior of MTdc networks poses a proposed restoration technique. multifaceted challenge. II. M ETHODOLOGY As soon as a dc fault occurs, the grid reaction is divided into three parts. First of all, the dc fault needs to be detected and To evaluate the dc fault response of an MTdc network, a localized. Secondly, the system needs to ensure the protection methodology is first defined. The steps followed in this paper Index Terms – DC fault protection, Grid restoration, H-bridge MMC, HVDC network.
are summarized in Figure 1 and are divided into two phases: • •
4) Determine the post-fault grid restoration strategy: After the dc fault is isolated, grid restoration actions need to be taken to enable the power flow in the ‘healthy’ part of the grid. In this step, the re-energization capability of the network is assessed. and the control stability of the grid is analysed. Finally, a framework is proposed for the protection sequence of an MTdc grid, which includes all the steps and the time at which they should be taken, after the dc fault occurrence, to achieve a successful grid restoration.
Phase 1 (Steps 1-3): Fault detection and isolation; Phase 2 (Step 4): Grid restoration.
III. S YSTEM C ONFIGURATION As dc breakers are not yet commercially available and their installation entails high costs, H-bridge MMCs are proposed for the protection of the HVdc network. As soon as a fault is detected, all IGBTs of each submodule are turned off and the current is directed through the antiparallel diodes of the switches and, thus, through the series-connected capacitors of the modules with opposing voltage, as shown in Figure 2. In this way, the total series dc voltage of each arm is higher than the peak rms ac voltage and the ac side stops feeding the dc side. At this point, the converter current reduces to zero and consequently, the protection of the HVdc converter does not require dc breakers [17]. This paper focusses on the proof-of-concept of techniques for the restoration of the dc grid operation and not on the dimensioning of the converter parameters. Therefore, although in high voltage applications the installed levels of MMCs exceed 200 [18], for simplicity, 8-level H-bridge MMCs are used in this study. The MMC-VSC specifications are summarized in Table I and are the same for all terminals. For the MTdc network analysis, a simulation model which accounts
+
+
C
C
C
C
C
C
L
L
a
L
C
...
...
2. Determine protection triggering times for each station.
c L
...
1. Obtain natural DC fault response.
L
b L
Phase 1: Fault detection and isolation
...
...
...
1) Obtain natural DC fault response: First, the natural response of the MTdc network to a permanent poleto-ground fault is obtained. The fault current is measured at the dc fault point, while the current contribution from each converter station is monitored in both poles. Moreover, the operational dc voltage level of both pole cables is measured at the output of each converter station, while at the same time the current in the converter phase arms is scoped. In this way, the protection techniques for the network and the converter stations can be determined and the necessary threshold values can be estimated. 2) Determine protection triggering times for each station: After determining the necessary protection actions that need to be taken, their time response to the fault needs to be evaluated. Based on previous studies [14], the control mode of each MMC-VSC station and its distance from the fault point affect the terminal protection triggering times. As a result, the time for which the MTdc network can maintain its control post-fault depends on these parameters. In this step, the time, at which the control of each MMC-VSC is inhibited, is determined, along with the necessary time to selectively detect the faulty section. These times form the basis to design the fault isolation and grid restoration actions. 3) Define the fault isolation times: H-bridge MMC has a dc fault reverse blocking capability. Consequently, it is able to drive the fault current to zero, blocking the power exchange between the ac and the dc side. However, as each converter station has its valves blocked at different times, it needs to be investigated how fast the fault current in the MTdc network is driven to zero. Only at this point can the mechanical disconnectors open on the dc side and isolate the faulty line segment. In this step, the time, between the fault occurrence and the dc current zero-crossing at each disconnector which needs to be opened, is estimated. This time corresponds to the total fault isolation time. Moreover, the ac breakers open to de-energize the system and allow the post-fault restoration actions. The time at which the ac breakers open is also monitored in this step.
+
C
C
C
C
3. Define the fault isolation times. C
+
Phase 2: Grid restoration 4. Determine the post-fault grid restoration strategy.
Figure 1: Workflow of the used methodology.
Figure 2: Fault current path through the H-bridge submodules of the MMC.
Table I: MMC-VSC parameters.
Table II: MTDC network parameters.
MMC specifications
Unit
Value
Cell capacitance (C) Arm inductance (L) Arm resistance (R) Number of SMs per arm (N) Carrier frequency (fc ) Sampling frequency (fs )
mF mH Ω Hz kHz
4 8 0.07 8 600 20
Network parameters VSC rated power (SV SC ) MTdc voltage (Vdc ) DC cable resistance (Rcable ) DC cable inductance (Lcable ) DC cable capacitance (Ccable ) DC cable length (d1/d2/d3) Transformer voltage ratio (VSC1/VSC2) Transformer voltage ratio (VSC3/VSC4) Transformer rated power (ST ) Transformer leakage inductance (LT )
Unit
Value
MVA kV Ω/km mH/km nF/km km
1200/600/600/1200 ±320 0.0195 0.2 220 107/100/35.5
kV
380/160 (Y0 -∆)
kV
33/160 (Y0 -∆)
MVA
1200/600/600/1200
OWF 600 MW
UK Grid Circulating ipj Current U*diff j inj ++ Controller j=a,b,c (CCC)
VSC4
Outer Controllers
I*dq
Inner Current Controller (ICC)
V*conv j
+-
OWF 600 MW
NL Grid
VSC3
u*pj Npj PSC-PWM
Pac Vdc Qac Vac
National Border
pu 0.05 for the MMC-HVdc stations switching behavior is implemented using the SimPowerSystem toolbox of Matlab/Simulink. Although the converters have different control modes within The control modes of the stations are as follows: VSC1 the MTdc network, they share the same control structure. The phase-shifted carrier-based pulse width modulation (PSC- regulates the dc voltage operational level of the grid, whereas PWM) technique was used along with a reduced switching- VSC2, as well as the two offshore stations (VSC3 and VSC4), frequency (RSF) voltage balancing algorithm to create the control their active power. The MTdc network is grounded via gate signals for the submodule switches on each converter small capacitors at the output of each converter station, forming arm [19]. In this way, the effective switching frequency of a symmetric monopolar topology. This topology was chosen the submodules is reduced from 600 to 220 Hz, minimizing as it is the most commonly used in VSC-HVdc transmission the converter switching losses, while maintaining the voltage systems [22]. The capacitors are only used to set the ground reference of the network and not for filtering purposes. As a balance between the capacitors of the modules. Moreover, a circulating current suppressing control (CCSC) result, they are neglected in the rest of the analysis. Due to was implemented to suppress the circulating currents in the the fact that bulky capacitors are avoided on the dc side of the MMC-VSC. Circulating currents are the result of voltage stations, there are less energy storage elements in the network imbalances between the phase legs and mainly consist of that discharge through the fault, resulting in a lower peak of an ac part with double the fundamental frequency. These the dc fault current [10]. The main MTdc network parameters currents - if uncontrolled - they contribute significantly to are shown in Table II. This study investigates only permanent pole-to-ground cable the converter conduction losses. Therefore, by controlling this second harmonic current to zero, the converter power losses faults, as this is the most common fault type, especially for can be minimized [20]. In Figure 3 the control structure of the submarine cables [23]. Additionally, a ground resistance of 7 Ω is used, which corresponds to the resistance of a sparking MMC-VSC is presented. The studied MTdc network is shown in Figure 4. Radial connection in wet loamy sand conditions, simulating submarine configuration is used for the connection of the asynchronous cable faults [13]. grids of the Netherlands (NL) and the United Kingdom (UK), IV. DC FAULT P ROTECTION S CHEMES including one OWF at each country. The NL and the UK wind There are several protective measures that can be taken farms are connected via VSC3 and VSC4, respectively, to the to protect MTdc networks from dc faults. These protective MTdc network, while the UK and the NL grids are connected functions are used both on the converter level, as well as on the through the VSC1 and VSC2 stations. Considering the BritNed network level. On the converter level, dc fault detection methods interconnector, it can be safely assumed that for most of the are used locally to protect each converter. On the network level, time, the NL converter station (VSC2) will act as a rectifier selective dc fault detection and localization techniques require feeding power to the dc grid, whereas the UK converter station (VSC1) will act as an inverter feeding power to the ac grid [21]. UK NL
Nnj
SM Capacitor Balancing Gate Algorithm signals
u*nj
Figure 3: Control structure of the MMC station.
S1p
S2p1 S1n
VSC1 34 km
73 km
Section 1
S2p2
S2n1
S3p S2n2
100 km Section 2
VSC2
S3n
35.5 km Section 3
Figure 4: Single-line diagram of the analyzed radial MTdc network with 4 terminals.
communication among the current and voltage sensors in the network and the disconnectors placed at each grid node. In this way, they can isolate the fault point by sectionizing the MTdc network. On the network level, to reliably and fast detect the faulty section of the grid, a selective fault detection method is used. A central controller receives the signals from the current sensors placed at both ends of each line segment in the grid (between two nodes). As soon as a fault occurs, the cables discharge through the fault. Due to the use of H-bridge submodules, once the local protection of the converter is triggered, the station does not contribute with current to the fault. As a result, if there is a fault either in Section 1 or 3 of the network, only overcurrent at one cable end is detected and the faulty line segment is selectively detected. In case the fault occurs in Section 2 of the dc grid, as shown in Figure 5, the faulty line segment is the only one experiencing different direction current transients at its ends. More specifically, once the overcurrent protection is triggered at one line end, a flag signal is sent to the central controller. In case the same overcurrent propagates to other line end, a new flag signal is sent from another sensor, indicating that there is no fault in the monitored line segment. Only, the faulty line segment will experience either overcurrent only in one cable end, or overcurrents with opposite directions at its ends. In this way it can be, successfully distinguished from the rest of the network. To approach the problem more realistically, a time delay is used for the simulation of the signal propagation from the local sensors to the central controller, as well as from the central controller to the mechanical disconnectors that need to be opened. In this case study, it is assumed that the dc fault detection controller is placed on the platform of VSC4, which is more centrally located. The measurements have an accuracy of 4 decimal points in pu. Therefore, the current measurements that are sent to the controller can be represented by 21 bits, namely 1 start bit, 1 sign bit, 3 bits to represent the integer, 14 bits to represent 4 decimal points, one parity bit and one stop bit. As a result, assuming that the protocol IEEE Ethernet standard 802.3 is used, with frame size of 1492 bytes, the data can be sent in one frame [7]. Assuming a bandwidth availability of 1 Gbps, the time needed to transmit one information frame is calculated as: 11936[bits] tf = = 1.2 · 10−3 [ms] (1) 109 [bps] If fiber optics are used, with a propagation speed of 0.67c [7], the propagation time between the furthest located current sensor and the controller, i.e., 100 km, is estimated by: tprop =
100 · 103 [m] = 0.498[ms] 0.67 · 3 · 108 [m/s]
(2)
The processing frequency of the data at the sensor and at the controller is taken as 100 kHz. As a result, the total control cycle needed from the current measurement until the controller processes the measurement is approximately 0.52 ms. The propagation time from the controller to the mechanical
VSC3
VSC4
I1
I4 I1,4
I3 I2,3
I2
VSC1
VSC2
Figure 5: Fault current contributions during a dc fault on section 2 of the MTdc network. Table III: Protection threshold values. Protection Function
Threshold (pu)
Pole overcurrent Pole undervoltage Pole voltage differential Arm overcurrent
1.5 0.8 0.1 1.5
disconnectors that need to be opened for the fault isolation is also accounted for in this study. On the converter level, the protection scheme includes protective functions both on the dc side as well as on the ac side of the converter. On the dc side, pole overcurrent, pole undervoltage and dc voltage differential protection between the poles are used [24]. On the ac side of the converter, overcurrent protection at each arm is applied. Once one of the protection measures is triggered, the fault signal is sent to the converter controller and all gate signals are inhibited. The thresholds of the aforementioned protective functions are project-specific and have to be defined based on the network characteristics and the ratings of the grid assets. In this study, the chosen threshold values are summarized in Table III. The values are presented in pu and, thus, the absolute values for each converter station depend on its individual rating. It is assumed that all the cables in the MTdc grid are rated based on the highest current rating of the interconnected converters. Considering the fault isolation actions, first, the converters are responsible for driving the dc fault current to zero. Then, ac breakers are used to disconnect the converter from the ac grid and de-energize the system. AC circuit breakers are required to have breaking time of 2-3 cycles [25]. In this case study, 3 cycles, i.e., 60 ms breaking time, is used. Finally, dc mechanical disconnectors are employed to sectionize the network and isolate only the detected faulty segment. V. R ESULTS This section presents the results obtained from the first 3 steps of Phase 1 of the methodology as described in Section II. All simulations are run for 5 s and the order of events is presented in Table IV. The fault is applied at 1.1 s and it is
0.3
0.7
1.1
PV SC2 (pu) PV SC3 (pu) PV SC4 (pu)
0.3 -0.5 -0.4
0.5 -0.4 -0.5
fault fault fault
0.6
0.6
0.55
0.55
DC Voltage (pu)
Time (s)
DC Voltage (pu)
Table IV: Order of events for the MMC-VSC stations.
0.5
0.5
0.45
0.45
0.4
0.4 0
0.2
0.4
0.6
0.8
0
1
0.2
0.4
0.6
0.8
1
Time (s)
Time (s)
assumed that the power references of the MMC-VSC stations (a) (b) do not change before and after the fault. Figure 7: DC voltage level of (a) positive and (b) negative pole During normal operation, the ac active power of the stations conductor at the output of VSC1 in normal operation. with respect to the base power of VSC1 is shown in Figure 6, while the positive and negative pole dc voltage at the output of VSC1, which is actively controlling the dc voltage level of the 1.5 MTdc network is presented in Figure 7. It can be seen that the 1 active power control of the stations is fast, as in every power 0.5 reference change the new steady-state is reached within 25 ms. 0 The ac power at VSC1 reaches slower the new steady-state, i.e., -0.5 within 200 ms, due to the charging and discharging process of the relatively long dc cables of the network. At the same time, -1 the dc pole voltage stays always at 50 % of the total dc link -1.5 0.5 0.52 0.54 0.56 0.58 0.6 Time (s) Time (s) voltage level with a ripple less than ±2%. (a) (b) To evaluate the effectiveness of the capacitor balancing algorithm, the capacitor voltages for the upper arm of phase a Figure 8: (a) Capacitor voltages of upper arm phase a of VSC1 of VSC1 are shown in Figure 8(a). Figure 8(a) shows that the and (b) three-phase ac voltage of VSC1. submodule capacitor voltages are always maintained within ±4% of the nominal capacitor voltage. In Figure 8(b) the ac voltage at the secondary of the transformer is presented. As soon as the fault is locally detected at the output of its Following the first step of the methodology, the natural dc converter, the submodules block their operation and the dc fault response of the system to a dc fault that occurs in the currents drop to zero. At the same time, the faulty pole voltage middle of Section 2, namely 50 km from VSC3 and 50 km drops to zero within 15 ms, while the ‘healthy’ pole cable from VSC4, is presented in Figures 9-12, assuming the local voltage also decreases but at a much slower rate following the converter station dc fault protection measures, as described in discharging process of the cable. It was seen in the simulations Section IV. that in case no protection was applied, the negative pole cable The current at the output of each VSC station is shown in would be charged through the fault to double of its nominal Figures 9(a)-(d), with respect to the base dc current of each voltage, finally being subjected to the total dc link voltage station. The total fault current at the fault point is presented in and operation could continue in a monopolar configuration. Figure 10. Moreover, in Figure 11 the dc voltage at the output However, this cannot be withstood as the dc power cables can of VSC is presented for each pole. afford double the nominal voltage only for a time that does not exceed 15 minutes [26]. Therefore, if a permanent fault occurs, which is the most often fault type in offshore systems, the network needs to be protected. 0.4 1.5 In Figure 12(a) the three-phase current waveform is only 0.3 1 presented for the upper arm of VSC1, as it is indicative of the 0.2 0.1 performance of all the other converter stations. As soon as the 0.5 0 fault protection of the converter station is triggered and the 0 -0.1 H-bridge submodules block,the arm current is driven to zero. -0.2 -0.5 The current rating of each phase leg, which is used as the base -0.3 current in Figure 12(a) is given by the equation: -1 -0.4 1.04
1.02
AC Voltage (pu)
Capacitor voltages (pu)
1.03
1.01
1
0.99 0.98
0.97 0.75
Active Power (pu)
0.2
0.4
0.6
Time (s)
(a)
0.8
0.85
VSC1 VSC2 VSC3 VSC4
Reactive Power (pu)
VSC1 VSC2 VSC3 VSC4
0.8
0.2
0.4
0.6
0.8
1
Time (s)
(b)
Figure 6: (a) Active and (b) reactive power level of MMC-VSC stations in normal operation with respect to the base power of VSC1.
Idc,nom Iac,nom + (3) 3 2 In Figure 12(b), the ac active power of the stations is presented at the moment of the fault occurrence. It can be seen that the power of VSC1 is the last to get to zero, as in this fault case, Iarm,base =
2
1.5
1.5
DC current (pu)
1 0.5 0
0.8
0.6
1 0.5
DC Voltage (pu)
DC current (pu)
2
0 -0.5
-0.5 -1 1.05
1.1
-1 1.05
1.15
1.1
1.15
Time (s)
Time (s)
(a)
(b)
0.4
0.2
2
1.5
1.5
-0.2
DC current (pu)
1 0.5 0 -0.5
1
1
-1 1.05
1.15
1.2
Figure 11: DC pole voltages at the output of VSC1 (red: negative pole, blue: positive pole).
0
Time (s)
1.15
1.1
1.15
Time (s)
(c)
(d)
1
Figure 9: DC current measured at the output of (a) VSC1, (b) VSC2, (c) VSC3 and (d) VSC4, with respect to the base current of each station.
4
1.5 VSC1 VSC2 VSC3 VSC4
0.8 1
0.6
Active Power (pu)
1.1
1.1
Time (s)
-0.5
-1 1.05
1.05
0.5
Positive Arm Currents (pu)
DC current (pu)
0 2
0.4 0.2 0
0.5
0
-0.2 -0.5
-0.4
3.5
-0.6 1
1.05
3
DC current (pu)
1.1
1.15
-1 1.09
1.2
1.095
(a)
2.5
1.1
1.105
Time (s)
Time (s)
(b)
Figure 12: (a) Three-phase upper arm currents at VSC1; (b) AC active power at the stations at the moment of the fault.
2 1.5
VSC4
1
VSC3
0.5 0 -0.5 1.05
Section 1
Section 2 S1p S2p1 50 km
1.1
Section 3
50 km
S2p2 S3p
3
4
1.15
Time (s)
Figure 10: DC fault current at the fault point.
VSC2
VSC1 1
2
5
Figure 13: Five fault point case studies. VSC1 is located further from the fault point and, thus, it is the last to block its control operation. vated first is always the voltage differential strategy. Moreover, In the second methodology step, the effect of the fault overcurrent at the output of the stations was only observed for location, on the time at which the converter station protection the cases where the fault was applied directly at the output of is activated, is investigated. In this step, a dc fault was applied in VSC3 and VSC4, namely the converter stations that connect 5 locations within the MTdc network, as presented in Figure 13. the OWFs to the grid. The reason for this is that these stations Figure 14 shows the time from the fault occurrence, in ms, are feeding power to the dc grid at the moment of the fault that it takes for the protection system to block the IGBTs of and due to their low rating they require less current in absolute the submodules for each of the fault case studies. Depending value for the overcurrent protection to be triggered compared on the fault location, the converters that are positioned closer to VSC2 which is also feeding power to the dc grid at the are the first to block their control operation for their protection, same time. with times ranging from 0.33 ms to 1.42 ms. In the third methodology step, the time at which the ac It has to be noted that the protection measure that gets acti- breakers open and the fault is isolated are estimated. It has to
1.11
Fault point 1 Fault point 2 Fault point 3 Fault point 4 Fault point 5
VSC4
VSC3
VSC2
VSC1 0
0.5
1
1.5
Time (ms)
Figure 14: VSC protection triggering times. Table V: Faulty line segment selective detection times. Fault Point
1
2
3
4
5
Time (ms)
0.75
0.25
1.17
0.83
1.25
be noted that depending on the fault location, the time at which the ac breakers open differs. As soon as the converter detects a fault, a signal is sent to the respective ac breakers to open. Although blocking the submodules manages to bring the fault current to zero, the ac breakers are tripped to allow technicians to take any protective action at the converter stations, if needed. As mentioned in Section IV, this action takes 60 ms. Therefore, to calculate the ac breakers opening time, 60 ms have to be added to the results presented in Figure 14 for each MMC-VSC. Next to the local converter protection system, a selective fault detection method is used to detect the faulty line segment, as described in Section IV. Depending on the fault location this time also varies. Table V presents the time at which the faulty line is selectively detected. The difference in times mainly stems from the number of the sensors that are needed in each case to signal a fault, as well as from their distance from the fault detection controller that is placed at the node close to fault point 2. Overall, it is apparent that although the H-bridge MMCbased MTdc network is successfully de-energized very fast, it is not able to recover its operation without any additional means, unless the fault is resolved. VI. R ESTORATION Based on the results of the previous section, a step-by-step grid restoration framework is proposed to provide dc fault ride-through capability to the MTdc grid in case of permanent pole-to-ground faults, using mechanical disconnectors. When the faulty line section is detected, the grid restoration process has to start to recover the operation at the ‘healthy’ part of the dc grid. To this end, certain steps are proposed. a) Step 1 – Open mechanical disconnectors: The mechanical disconnectors can only break a line when the current that flows has dropped to zero. In this case study, based on the assumed accuracy of our current measurements, the
disconnectors are able to open if only the current is less than 0.1 A for more than 1 ms, i.e., the current has reached a new steady-state. This time is considered to avoid cases in which the current is oscillating and it only momentarily crosses the aforementioned current threshold. Moreover, the disconnectors isolating the faulty section, are controlled to open only when the grid dc voltage has dropped to less than 1 % of the nominal voltage level, resulting in both poles being almost completely discharged. In fact, through the simulations it was observed that the system could recover even within 5 ms post-fault. However, in the new operational state the positive, faulty, pole voltage had dropped to 0.2 pu, whereas the negative, healthy, pole voltage had increased to 0.8 pu, as the cable was charged through the ground. As a result, a big voltage differential is observed, unless other protective measures to avoid overcharging of poles are taken. In our study, it is assumed that the dc grid is almost fully discharged, before system restoration takes place. In this way, high overcurrents are avoided and the recovery process is smoother. b) Step 2 – AC breakers reclose: After the disconnectors at the faulty section open, the ac breakers at the interconnected ac grids receive a signal to reclose. This process is assumed to take 60 ms. After this step, the control operation of the converters can be restored. c) Step 3 – Resume control of Vdc controlling MMC-VSC: First, the VSCs responsible for the dc voltage control are deblocked to recover the dc grid voltage to its nominal value. A time delay of 3 cycles is applied between the reclosing of the ac breakers and the deblocking of the control of the respective Vdc controlling MMC-VSC station. Depending on the fault location, a new dc grid is formed. In this new grid, one onshore MMC-VSC is always assigned to preserve the control of the dc link voltage. In our case studies, if the new dc grid does not include the connection of all the stations to VSC1 (Fault case 2 and Fault case 3), which was controlling the dc voltage pre-fault, the dc voltage control is assigned to VSC2, which was previously controlling its active power. The smooth recovery of the control requires the reset of the PI outer controllers used at the stations at the moment that the control is deblocked. d) Step 4 – Resume control of MMC-VSC connecting OWFs: As soon as the grid voltage is stable, namely it remains above 90 % of its nominal value for 1 cycle (20 ms), the MMCVSCs connecting the OWFs are allowed to be reconnected. For the first 1-2 s, the power reference at the OWFs is set to zero to allow a smoother integration and avoid huge inrush currents at the moment of their reconnection to the grid. Once the grid is stable, the OWFs start feeding power to the grid. The proposed restoration framework is presented for the following three fault case studies, one at each section of the dc grid: 1) Fault case 1: Fault point 1 (Section 1); 2) Fault case 2: Fault point 3 (Section 2); 3) Fault case 3: Fault point 5 (Section 3). The simulations are run for 8 s. The dc voltage at the output of the Vdc controlling stations, as well as the dc currents at
Table VI: Control and protection actions for Fault case 2. 1 0.8
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VII. C ONCLUSIONS
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each terminal and the ac active and reactive power are depicted for each of the three case studies in Figures 15-17. Table VI presents the sequence of the control and protection actions and the time at which they are performed for Fault case 2. In all the fault case studies, grid operation was restored within less than 3.6 s. As a result, fast grid restoration is possible while the high cost and uncertainty of dc breakers is avoided. Moreover, the overcurrents at the moment of reconnection of the MMC-VSC stations never exceed 2 pu. These dc overcurrents are not dangerous for the cable safety, as they only occur momentarily. Longer current and voltage transients are observed when VSC2 is required to change its control mode, namely from Pac to Vdc control, for Fault case 1 and Fault case 2. However, even in this case, a new control steady-state is reached within 0.6 ms. Finally, the dc voltage at both poles is balanced and only a small difference can be observed which as previously explained depends on the time at which the system restoration is allowed to start and the pole voltage difference at this moment.
0.6
DC Voltage (pu)
MTdc grid normal operation Change in Pref of OWFs Change in Pref of OWFs DC fault Fault detected by MMC-VSCs AC breakers open Mechanical disconnectors open AC breakers reclose VSC1 and VSC2 deblock Nominal Vdc restored at VSC1 Nominal Vdc restored at VSC2 VSC4 reconnects with Pref =0 VSC3 reconnects with Pref =0 OWFs feed power to the grid
DC current (pu)
0 0.3 0.7 1.1 1.004-1.008 1.064-1.068 4.245 4.305 4.325 4.343 4.787 4.423 4.867 7
Action
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Time (s)
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This paper proposed a framework for the successful dc fault 0.5 0 0 ride-through of H-bridge MMC-based MTdc networks. The -0.5 natural dc fault response of the system was studied and based -1 -0.5 on the obtained results, local measures for the protection of -1.5 the converter stations, as well as selective dc fault detection -2 -1 1 2 3 4 5 6 7 8 1 2 3 4 5 6 7 8 methods were designed. Moreover, the dc fault location effect Time (s) Time (s) on the control behavior, as well as on the dc fault current (f) (g) contribution of each station was investigated. The simulations Figure 15: Fault case 1: (a) DC voltage level at the output showed that although the H-bridge MMC stations are able to of VSC2 (red: negative pole, blue: positive pole); DC current disconnect the ac side from the dc grid and drive the fault measured at the output of (b) VSC1, (c) VSC2, (d) VSC3 and currents to zero, they are unable to restore operation without (e) VSC4, with respect to the base current of each station; (f) additional fault isolation means. As a result, H-bridge MMCAC active and (g) reactive power. based networks perform worse than networks which make use of half-bridge MMCs combined with fast dc breakers. The use of mechanical disconnectors in combination with the proposed framework provides the necessary selectivity to the dc grid and allows for the fast grid restoration. In fact, grid
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Figure 16: Fault case 2: DC voltage level at the output of (a) VSC1 and (b) VSC2 (red: negative pole, blue: positive pole); DC current measured at the output of (b) VSC1, (c) VSC2, (d) VSC3 and (e) VSC4, with respect to the base current of each station; (f) AC active and (g) reactive power.
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Figure 17: Fault case 3: (a) DC voltage level at the output of VSC1 (red: negative pole, blue: positive pole); DC current measured at the output of (b) VSC1, (c) VSC2, (d) VSC3 and (e) VSC4, with respect to the base current of each station; (f) AC active and (g) reactive power.
restoration is achieved within 3.6 s. These results prove that fast and safe fault isolation and system restoration are possible without the need of costly and not yet commercially proven dc breakers. Depending on the fault location, the onshore converters can be assigned a different control mode than prefault, to achieve a smooth and controlled post-fault operation. In this study, PI controllers were used at the MMC-VSC stations. The high transients observed at the moment of the stations
reconnection to the grid can be attributed to the non-optimized tuning of the controllers. In future studies, the effectiveness of different control methods, e.g. droop control, will be evaluated. ACKNOWLEDGEMENTS The work has been performed within the project “Synergies at Sea” (TKIW01008). This project is supported by the Dutch Ministry of Economic Affairs through the R&D program “TKI Wind op Zee”. The opinion expressed by the authors does not necessarily reflect the position of the Ministry of Economic Affairs, nor does it involve any responsibility on its part. R EFERENCES [1] O. Gomis-Bellmunt, A. Egea-Alvarez, A. Junyent-Ferre, J. Liang, J. Ekanayake, and N. Jenkins, “Multiterminal hvdc-vsc for offshore wind power integration,” in Power and Energy Society General Meeting, 2011 IEEE, July 2011, pp. 1–6. [2] R. T. Pinto, P. Bauer, S. Rodrigues, E. J. Wiggelinkhuizen, J. Pierik, and B. Ferreira, “A novel distributed direct-voltage control strategy for grid integration of offshore wind energy systems through mtdc network,” Industrial Electronics, IEEE Transactions on, vol. 60, no. 6, pp. 2429– 2441, June 2013. [3] G. P. Adam, K. H. Ahmed, S. J. Finney, and B. W. Williams, “Generalized modeling of dc grid for stability studies,” in Power Engineering, Energy and Electrical Drives (POWERENG), 2013 Fourth International Conference on, May 2013, pp. 1168–1174. [4] S. Rodrigues, R. T. Pinto, P. Bauer, and J. Pierik, “Optimal power flow control of vsc-based multi-terminal dc network for offshore wind integration in the north sea,” IEEE Transactions on Emerging and Selected Topics in Power Electronics, vol. 1, no. 4, pp. 260–268, 2013. [5] R. T. Pinto, S. Rodrigues, P. Bauer, and J. Pierik, “Comparison of direct voltage control methods of multi-terminal dc (mtdc) networks through modular dynamic models,” in Power Electronics and Applications (EPE 2011), Proceedings of the 2011-14th European Conference on, Aug 2011, pp. 1–10. [6] S. Rodrigues, R. T. Pinto, M. Soleimanzadeh, P. A. Bosman, and P. Bauer, “Wake losses optimization on offshore wind farms with moveable floating wind turbines,” Elsevier Energy Conversion and Management, vol. 89, pp. 933–941, January 2015. [7] R. T. Pinto, S. Rodrigues, E. J. Wiggelinkhuizen, R. Scherrer, P. Bauer, and J. Pierik, “Operation and power flow control of multi-terminal dc networks for grid integration of offshore wind farms using genetic algorithms,” Energies, vol. 6, no. 1, pp. 1–26, 2012. [Online]. Available: http://www.mdpi.com/1996-1073/6/1/1 [8] S. Rodrigues, R. T. Pinto, P. Bauer, and J. Pierik, “Optimization of social welfare and transmission losses in offshore mtdc networks through multiobjective genetic algorithm,” in Power Electronics and Motion Control Conference (IPEMC), 2012 7th International, 2012, pp. 1287–1294. [9] E. Kontos, R. T. Pinto, P. Bauer, and E. J. Wiggelinkhuizen, “Multiterminal network options for the interconnection of offshore wind farms: A case study between britain and the netherlands,” in Power Electronics and Motion Control Conference and Exposition (PEMC), 2014 16th International, Sept 2014, pp. 1222–1227. [10] E. Kontos, R. T. Pinto, S. Rodrigues, and P. Bauer, “Impact of hvdc transmission system topology on multiterminal dc network faults,” Power Delivery, IEEE Transactions on, vol. 30, no. 2, pp. 844–852, April 2015. [11] J. Yang, J. E. Fletcher, and J. O’Reilly, “Short-circuit and ground fault analyses and location in vsc-based dc network cables,” Industrial Electronics, IEEE Transactions on, vol. 59, no. 10, pp. 3827–3837, Oct 2012. [12] Y. Zhang, N. Tai, and B. Xu, “Fault analysis and traveling-wave protection scheme for bipolar hvdc lines,” Power Delivery, IEEE Transactions on, vol. 27, no. 3, pp. 1583–1591, July 2012. [13] M. K. Bucher, M. M. Walter, M. Pfeiffer, and C. M. Franck, “Options for ground fault clearance in hvdc offshore networks,” in Energy Conversion Congress and Exposition (ECCE), 2012 IEEE, Sept 2012, pp. 2880–2887. [14] E. Kontos, S. Rodrigues, R. T. Pinto, and P. Bauer, “Optimization of limiting reactors design for dc fault protection of multi-terminal hvdc networks,” in Energy Conversion Congress and Exposition (ECCE), 2014 IEEE, Sept 2014, pp. 5347–5354.
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