High‐voltage direct current fault current interruption: A technology review

European Union's Horizon 2020, Grant/Award Number: 691714 Abstract This review paper describes fault current interruption principles and various high‐voltage direct currrent (HVDC) circuit breaker technologies. First, fundamentals of HVDC fault current interruption and a generic set of requirements of HVDC circuit breakers are presented. The critical parameters during fault current interruption are assessed using a simplified mathematical model. Then, the state‐of‐the‐art of HVDC circuit breaker technologies and their application in actual HVDC multi‐terminal projects is highlighted. Several sub‐components of HVDC circuit breakers are standard components used in a non‐standard application and, hence, have to face non‐standard stresses. All of today's HVDC circuit breaker technologies consist of mechanical switching devices and metal‐ oxide surge arresters, which are used in an unconventional way. A critical analysis of these stresses compared to the stresses in a conventional application is provided. Recommendations on testing supported with examples of actual full‐power ‘complete’ demonstration of HVDC circuit breakers up to 350 kV/20 kA are discussed. Finally, the actual status of standardisation activities is presented.


| INTRODUCTION: SWITCHING IN HIGH-VOLTAGE DIRECT CURRENT SYSTEMS
Since the advent of power systems, switching has been the prime technology to control the safe flow of power. In traditional alternating current (AC) systems, a large number of switchgear can be identified for a myriad of different functions. The most critical switching device is the circuit breaker, a device that can make (switch on) and break (interrupt) fault currents during a short-circuit in a system [1,2]. Its function is to isolate faulted sections of the power system in a short time (< 100 ms) so that power flow in the healthy parts of the system remains unaffected.
In a traditional point-to-point high-voltage direct current (HVDC) transmission systems, however, there is no need for such a dedicated fault current interruption device. Normally, a fault in such a system automatically leads to a total loss of power in the affected pole line. Fault current in such systems can be cleared by converter control actions at either end or by AC circuit breakers at the AC side. Future meshed voltage source-converter (VSC)-based HVDC grids, however, need dedicated HVDC circuit breakers.
HVDC switchgear changes the energy flow in two ways. The first is current commutation: transferring a current into an alternative pathachieved by transfer switches, and the other is fault current interruption: blocking the current right awayachieved by circuit breakers. The situation is outlined in Figure 1, showing interruption (left) and commutation (right). Although both require local current interruption, fault current interruption is a far more onerous duty compared to current commutation in terms of current level to be dealt with, the magnitude of counter voltage to be generated and the energy that the device has to absorb [3]. Another critical difference is operation time. Commutation does not need to be performed with acute urgency, whereas short-circuit currents need to be cleared extremely rapidly.
Commutation (or transfer) switches for HVDC application are based on AC SF 6 interrupters (with auxiliary circuits), providing enough arc voltage to transfer the current into a parallel path. Special designs of SF 6 circuit breaker chambers are optimised to provide quick transfer of current [4]. A well-known load current interruption switch is the metallic return transfer switch (MRTS) that needs to transfer continuous current from an earth return path into a transmission line ('metallic return') after a converter pole has been taken out of service in a bipolar system [5]. Though current commutation capabilities exceeding 6000 A [6,7] may be assigned to MRTS, technically it is a switch rather than a breaker.
In 2017, the International Council on Large Electric Systems (CIGRE) Technical Brochure 683 'Technical requirements and specifications of state-of-the-art HVDC Switching Equipment' [8] was issued. In this document, a large variety of HVDC switchgear is analysed and explained.

| FAULT CURRENT INTERRUPTION IN DC SYSTEMS
For understanding current interruption in direct current (DC) systems, an illustrative circuit is shown in Figure 2.
Its circuit equation is as follows (where i is the current, U s is the system voltage, u cb is the voltage across the circuit breaker, and L is the inductance): This implies that a decrease of fault current (di/dt < 0) can only be achieved when the voltage across the circuit breaker (the counter voltage) exceeds the system voltage (u cb > U s ).
All DC breakers are based on the above principle: generation of counter voltage that exceeds the system voltage for a sufficiently long duration. During the presence of the counter voltage, the fault current is suppressed to zero within the fault current suppression time (t FS ). It is thus important not only to generate counter voltage, but also to develop it very quick (within few milliseconds) and maintain it sufficiently long, until the fault current is suppressed to zero. DC fault current is eventually limited by the system parasitic resistance (R) (not shown in Figure 2). In the simplified layout, this 'steady-state' fault current (I ss ) is as follows: I ss ¼ U s /R ( Figure 3).
Compared to AC fault current interruption, DC fault current interruption is challenging because of the following reasons [9]: 1. There is no natural current zero in DC systems unlike in AC systems (see Figures 3 and 4). This implies that there is no moment when the inherent magnetic energy (½Li 2 ) in the system is zero. For AC current interruption, current zero provides the opportunity to interrupt at the moment when there is no magnetic energy in the system. Thus, the AC circuit breaker does not need to absorb magnetic energy in the system, whereas the DC circuit breaker must have a provision to absorb several megajoules of the energy in the (faulted part of the) system. For example, an HVDC circuit breaker needs to absorb at least 11 MJ of energy when interrupting 15 kA fault current flowing in a 100 km overhead line (OHL). Analogously, this is equivalent to absorbing the kinetic energy of a 30-ton train running at 100 km/h in a matter of a few milliseconds by abruptly stopping its motion. 2. Fault current in HVDC systems rises rapidly to a peak value limited only by the resistance (R) in the current path (see the prospective current in Figure 3), whereas in AC systems, the peak value is determined mainly by the inductance of the conductors (see Figure 4). This implies that, in HVDC systems, very high fault currents can emerge in a matter of milliseconds. Therefore, HVDC breakers need to act fast, around 10 times faster than AC breakers to clear a fault current on its rising edge before reaching its peak value.
With rate-of-rise of fault current (di/dt) in the range of a few to several kA/ms [10], breaker operation time may not exceed 8-10 ms in order to handle technically feasible values of peak fault current (I pk ). Though this current is much lower than the rated short-circuit breaking current of AC breakers (63-80 kA), the challenge in DC current interruption is in realizing a short breaker operation time in order to limit undesirable consequences for system and converter. In addition, rapid response also calls for the need of very fast DC fault protection. Values in the range of 1-3 ms of relay time (t RY ) are reported as feasible [11]. 3. To interrupt fault current, HVDC circuit breakers need to quickly generate and sustain counter voltage exceeding the system voltage. This voltage is henceforth termed as transient interruption voltage (TIV) (see Figure 3), whereas there is no such need for an AC current interruption. Rather an AC circuit breaker needs to sustain a system imposed transient recovery voltage imposed by the system (see Figure 4).
Many different technologies have been proposed to generate and to maintain counter voltage [12]. In fact, unlike the AC circuit breaker, the HVDC circuit breaker is no longer just a mechanical contact system, but rather a system of components arranged in multiple current branches to which current is commutated in a controlled manner to achieve DC interruption (see Figure 5).
HVDC breakers consist of (at least) three parallel branches (see Figure 5): The sequence of events that becomes effective upon activating a HVDC circuit breaker is outlined below: 1. Local current interruption in the continuous current branch: Fault current is quickly interrupted on its rising edge in this branch. This is achieved by semiconductor switches or by mechanical switchgear with an auxiliary circuit (active injection circuit) or by a combination of both. 2. TIV generation in the commutation branch: After the continuous current branch is blocked for current passage, current is forced to transfer into the commutation branch. This branch then generates TIV, either immediately upon commutation (active current injection technology) or slightly later after a large semiconductor stack has interrupted the commutated current (hybrid technology). 3. Energy dissipation in the absorption branch: The TIV rises until the protection level of a metal-oxide surge arrester (MOSA) bank in the third parallel branch is reached. From that moment on, current starts to flow through this branch. Because MOSA protection voltage (U MOSA ) is higher than the system voltage (U MOSA > U s ), now the current through the MOSA will steadily decline to zero (di/dt < 0, see Equation [1]). When the current is suppressed to near-zero after the fault current suppression time (t FS ), the very small residual current can be interrupted by another switch (residual current switch) and system voltage appears across the open DC breaker.
The system voltage starts to recover as soon as TIV has been fully developed, limiting the impact of the fault on the system basically to the fault neutralisation time (t FN ) (see Figure 3). After this time, the fault (current) is not yet removed from the system, but its impact is compensated by the MOSA temporarily acting as the system voltage source.
HVDC breakers basically differ in the way local current interruption is achieved, for example, whether a mechanical switching element is used for interruption or semiconductors do this job.
In every design, mechanical switchgear is present to interrupt and/or to isolate. This can be vacuum-or SF 6 switchgear, but the one common key requirement is that it must be very fast acting (< 8 ms of contact separation) and therefore differs from AC switchgear that never achieves contact separation on the first rising edge of the fault current.
The key features of all high-speed mechanical switchgear in HVDC circuit breakers are electromagnetically pulsed actuators, so-called repulsion Thomson coils, electrically activated by a capacitor discharge [13].
To formulate the quantitative behaviour of an HVDC circuit breaker, a fundamental mathematical description is provided below using the simplified interruption process in Figure 6. Since fault current interruption involves the disciplines of circuit breaker design, protection system design, and power system studies, the following input parameters are necessary and need to be defined initially: The above parameters are interdependent. For example, a DC line current limiting reactor is designed depending on the following parameters (in addition to the system voltage): 1. The achievable fault neutralisation time considering the worst-case relay time of the protection system and internal commutation time of the HVDC circuit breaker. 2. The maximum current withstand capability of the system components considering the total current breaking timethe peak fault current must not exceed this value. 3. The maximum current interruption capability of the HVDC circuit breaker-the circuit breaker must be able to interrupt any short-circuit current resulting in the system. Thus, the maximum current interruption capability must be coordinated with the maximum allowable short-circuit current in the system with sufficient margin.
Given the above parameters, the maximum rate-of-rise of fault current that the HVDC circuit breaker is able to handle, the minimum equivalent inductance of the system, the fault current suppression time (t FS ) and the energy absorbed (E) can be derived using the following basic set of equations described below: Thus, to ensure the third condition the inductance (L) of the system has a value of at least: The fault current suppression time (t FS ) can be estimated as follows: The energy to be absorbed by the HVDC circuit breaker is as follows: In order to get an impression of the practical values of parameters, the data of a 500-kV HVDC circuit breaker [14] is used as shown in Table 1.
The actual inductance used in the system is higher than the value shown in the table. Hence, the peak fault current is also lower than value indicated in the table-showing sufficient margin between the maximum breaking capability of the breaker and the peak fault current. Note that the energy absorption requirement (E) shown in the table refers to a single breaking operation. In cases where faults are persistent, like when a secondary arc appear in OHL systems after the main fault is cleared, two or more opening operations may be required, basically doubling the required energy dissipation, since the cool down time of the large MOSA bank is much longer than the time between successive opening operations (in AC applications usually 300 ms).

| APPLICATION OF HVDC CIRCUIT BREAKERS
HVDC transmission reaches ever higher levels of voltage and power [15], with China in the lead now [16]. Till now, almost all of the HVDC systems in operation are point-to-point systems: a single HVDC link connecting two HVDC stations nearby large-scale generation, for example a large hydropower plant and a large load centre. With the need of connecting huge amounts of large-sized generators (commonly renewable sources) spread across a large surface, meshed HVDC grids or multi-terminal HVDC systems [17] are being realized in small scale and conceived in a large scale, aimed to harvest hundreds of gigawatts in a few decades from now [18]. The meshed or multi-terminal topology greatly enhances reliability, system stability, and electricity trade. Topologies are studied intensively [19,20].
A key requirement of such meshed HVDC grids is the possibility to de-energise faulted branches of the grid (submarine cables in an offshore grid) without endangering the integrity of the system as a whole.
Faults in submarine cable links are in the order of three faults per 1000 km/year in HVAC applications [21] and 0.2-2.0 per 1000 km/year in HVDC projects [22]. During system restoration, there is no or limited energy flow. Especially in systems having submarine connections, repair times can be very long; a survey among European TSOs reports an average repair time of 60 days [23].
The HVDC circuit breaker [12,24] is a good candidate to interrupt any possible fault current and isolate the faulted section from the grid in a very short time in order to maintain system integrity.
Other options of HVDC grid protection include the use of converters having fault-blocking capability (full-bridge F I G U R E 7 160 kV active current injection high-voltage direct current circuit breaker [27] F I G U R E 8 Two 200 kV HVDC hybrid circuit breakers [14]. HDVC, high-voltage direct current 176 -SMEETS AND BELDA topology). In this case, the grid de-energises shortly and fault current is reduced to levels allowing separation of the faulted line under near-zero voltage and current conditions [25,26]. This requires fast mechanical disconnectors to be installed at the ends of each DC line. The DC-side circuit must completely de-energize before these fast disconnecting switches are operated.
At the time of writing, HVDC circuit breakers are in service in two projects in China. One is in the �160 kV threeterminal Nan'ao project (2013) [27], operated by China Southern Power Grid, where active current injection HVDC circuit breakers are installed [28] (see Figure 7). In another project, hybrid HVDC breakers were installed in the �200 kV Zhoushan five-terminal island link (2014) [29,30] from State Grid Corporation of China (see Figure 8).
The realization of the Zhangbei-meshed �500-kV HVDC onshore grid [31,32] also a project in China will initially include 16 HVDC breakers of five different Chinese suppliers offering three designs of hybrid type [14,33], current injection [42] and coupled negative voltage technology [34] (see

| TECHNOLOGY OF HVDC CIRCUIT BREAKERS
Low-voltage DC systems (roughly below 1.5 kV) are mostly applied for public and for traction applications, with various types of drives and converter systems. In these systems, counter voltage generation is through elongation and cooling of the switching arc. By increasing the arc (counter) voltage to a value exceeding the system voltage, the arc current is forced to zero and the current is interrupted. The energy absorption is achieved by the arc.
In medium-voltage DC systems ranging (1.5-3 kV), arc elongation can still be used, but technically complicated measures are necessary to create the high arc voltage as counter voltage.
HVDC circuit breaker technology is developing already since the first experiments in electrification and has gained increasing importance in the light of HVDC grid development [8,12].
Two major technologies can be distinguished as follows: 1. Active current injection in which the local current interruption in the continuous current branch is undertaken by (a series of) high-speed arcing vacuum interrupters and an auxiliary counter current injection circuit. This technology is also called 'mechanical HVDC circuit breaker', but since all HVDC breakers need mechanical switchgear, the use of the word 'mechanical circuit breaker' exclusively for this type seems confusing and is not recommended. 2. Hybrid technology is a hybrid of mechanical and power electronics switches. In these designs, the power switching is accomplished by power electronics, while the mechanical switching element has one the one hand the function to conduct the continuous current at very low losses. On the other hand, the mechanical switching device needs to isolate the power electronics in the continuous current branch from exposure to the transient interruption switching voltages during and the DC recovery voltage after interruption Coupled negative voltage technology (also called magneticcoupled current commutation) is a variant having features of both active current injection and hybrid technology developed up to 500 kV. Herein, current in the continuous current branch is interrupted in arcing vacuum circuit breakers by an active (counter) current injection from a capacitor ('negative voltage source') while the commutation path, consisting of a power electronics remains conducting [34]. Only after full commutation, the power electronics interrupts the fault current. Full electronic circuit breakers are possible in theory, but the conduction losses during continuous current conduction in the series combination of a large number of semi-conductors prohibits the practical application at high voltage.

| Active current injection technology
This concept is applied and demonstrated in medium-voltage DC (MVDC) [35][36][37] and HVDC technology [28,38]. Often, circuit breakers applying this concept are termed 'mechanical HVDC breakers'. This term is misleading because all HVDC circuit breakers have mechanical switching devices.
In this technology, interruption in the continuous current branch is created by artificially creating a current zero crossing in one or more arcing vacuum gaps. This is carried out by an active injection circuit, which generates a high-frequency (HF) current that when super-imposed upon the DC fault current creates a current zero crossing (see Figure 12).
When the sum of fault current and the superimposed HF counter current reaches zero, interruption can result, provided that a number of criteria are met [39]: � Arcing current prior to forced HF current zero must remain below a certain threshold; � Steepness of current at current zero must be below a certain threshold. In many designs, a saturable reactor reduces di/dt at low current immediately before the zero crossing [40]; high arcing activity combined with very steep ramping down of current to zero leaves a significant post-arc plasma at current zero, which limits fast recovery of the gap to the insulating state [38]; � Minimum contact distance must have been reached by parting vacuum gap(s) in order to withstand the voltage across the gap during and after the interruption process.
Normally, current injection type of HVDC breakers allow bi-directional fault current interruption since the amplitude of the oscillation ensures current zero creation even when the injected current is initially in the same direction as the fault current. Further optimisation of topologies can be achieved as demonstrated in studies [41].
Two realized types of active current injection HVDC circuit breakers are discussed below.

| Capacitor discharge current injection
The most common design is with the active injection circuit consisting of a pre-charged capacitor bank that can produce a HF (few kHz) oscillating current in an L-C circuit [42][43][44][45][46]. This current is actively injected into the arcing vacuum gaps to create an artificial current zero as soon as possible after contact separation. For the initiation of the injection, ultra-fast mechanical (vacuum) making switches or power electronic switches are required.
Immediately after current interruption in the vacuum gap, initially the vacuum gap is stressed by a very steep voltage spike originating from the residual charge on the injection capacitor. This might lead to 're-ignition' of the HF current and a slightly delayed interruption at a subsequent zero crossing. Re-ignition is technically not of significance, once a subsequent interruption is realized at current zero of a later HF current loop.
When at a later moment in the process, a breakdown of the switching gap occurs, due to lack of dielectric withstand, this is called a 'restrike' which might lead to transients in the breaker circuitry. In the case of vacuum, restrike of the gap (s) not necessarily leads to failure of interrupting the DC fault current because vacuum gaps recover and can interrupt again ( Figure 13).
Restrike, however, leads to an increased energy absorption requirement and delayed interruption and therefore shall be avoided.
Successful, independent full-power tests of a two-module device of 160-200 kV rated system voltage, having two highvoltage (HV) vacuum interrupters in series and interrupting 16 kA have recently been performed [47].
Another current injection-based design that draws industrial attention, but has not emerged as a prototype, is based on thyristor-controlled current injection [48].

| VSC-assisted resonant current injection
In the VSC-assisted resonant current injection (VARC) design, the active injection circuit consists of a VSC that generates a HF current having an increasing amplitude [49]. The process of current excitation continues until the superposition of the injected current and DC fault current is zero, usually in less than half a millisecond. The oscillation is excited by a full-bridge converter installed in series with an L-C circuit. The converter operates at much lower voltage than the system voltage and consists of Insulated Gate Bipolar Transistor (IGBT) modules. The full-bridge converter has a pre-charged capacitor whose voltage polarity is actively reversed at twice the L-C circuit frequency. The principle has similarities with the MRTS based on passive oscillation. The advantage of the VARC concept is the use of a limited number of semiconductors operating at low voltage. The HF of oscillation (> 10 kHz) ensures early current zero.
Successful, independent full-power test of this design has been demonstrated with a single module [49], equipped with a 24-kV high-speed vacuum circuit breaker producing 40 kV of counter voltage and interrupting 10 kA.

| Hybrid switching technology
This technology exploits the combination of mechanical contacts and power electronics, but in contrast to the current F I G U R E 1 4 Example circuit of hybrid HVDC breaker (based on [50]). Type of semiconductors and topology can vary. HDVC, high-voltage direct current F I G U R E 1 3 Fault interruption of an experimental active current injection type DC breaker using commercially available 38 kV AC vacuum interrupters [39]. Top: Fault current, thick red sections indicate arcing of the vacuum gap. Centre: Nine times re-ignition of HF current arc in the period T 2 -12.8 ms; Bottom: restrike (at 14 ms) during fault current suppression followed by another five re-ignitions leading to prolongation of fault current suppression and increased energy absorption, but ultimately fault interruption. AC, alternating current injection technology, the contacts are non-arcing. The continuous current branch (see Figure 14, based on [50]) consists of a series combination of a power electronics auxiliary breaker (also called 'load commutation switch', though strictly speaking it is not a switch) and a mechanical disconnecting switch (also called 'ultra-fast disconnector'). The load commutation switch is mostly a series-parallel matrix of semiconductors for reducing losses and increasing reliability [51]. Because the continuous current passes through this device, it needs water cooling. The (ultra-)fast disconnector is either an SF 6 -insulated switch with a single gap for the full TIV voltage [52] or a series combination of (up to 12) vacuum gaps, each with its high-speed actuator [14,33]. In both cases, the disconnecting switch opens only after current has been interrupted by the load commutation switch, in order to protect it against voltages during the switching process.
The load commutation switch can interrupt a large current in its branch because the commutation branch has been switched into a low-impedance mode at the moment of fault detection, or before, by switching the main breaker into conduction, thus only very limited voltage falls across the load commutation switch.
In the next step, the impedance of the commutation branch is changed from very low to very high. This is accomplished by the 'main breaker', a stack of a large number (up to few hundreds) of power electronic switches. One design has a stack of Bi-mode Insulated Gate Transistor (BIGTs) [50] as main breaker, another design [14] has a number of diodebased H-bridge modules in full-bridge rectifier topology, which is claimed to reduce the amount of IGBTs by 50%. Yet another design [33] uses H-bridge diode-based commutation modules and IGBT-based unidirectional breaking modules, integrating the energy absorption function (MOSA) in the commutation branch. The last two designs offer bi-directional operation.
Yet another design that has been prototype tested, though not further developed, is based on stepwise commutation into a number of parallel branches containing thyristors and capacitors [53].
A concept where current commutation is taken care of by an arcing commutation switch in combination with an ultrafast disconnector is presented in studies [54,55]. Herein, an SF 6 chamber is described for 9 kA, 80 kV. It avoids having power electronics in the continuous current branch.
The use of a new type of a plasma-discharge tube as main breaker, interrupting against 80 kV and largely avoiding semiconductors, is under industrial investigation [56].
Successful experiments have been reported with a series combination of a superconducting fault current limiter with a fast passive resonance breaker in series [57].
Piezo-electric-based fast mechanical switches, combined with super-critical interruption media are under study [58].
In general, hybrid HVDC breakers have higher on-state losses than current injection type and need active cooling because of the presence of power electronics in the continuous current branch.
A large number of DC breaker topologies have been proposed in literature in recent years. The weakness of most of these is that they are conceived based only on electrical transient simulation programs (PSCAD, EMTP, ATP, SimPowSystems) while assuming each breaker subcomponent as ideal. The absence of physical phenomena (arcing-, discharge-, plasma-, mechanical-, thermal-etc. stresses) that are naturally associated with high-current and high-voltage phenomena makes it tempting to scale up electrical models to any level of voltage and power. However, nature does not scale as easy as simulations. Therefore, adequate simulation of HVDC circuit breaker performance using multi-physics simulation tools is essential, though even such tools cannot model critical disruptive phenomena like arc interruption, dielectric discharges etc. For breaker-system interaction studies, black-box models containing ideal components are usually adequate [24].

| STRESSES TO HVDC CIRCUIT BREAKER COMPONENTS
All designs of HVDC circuit breakers have components applied in a non-conventional way, or they include new types of components. In order to reduce the risk of failures of these subcomponents in the application of HVDC circuit breakers, standardisation committees need to analyse the new stresses, typical for HVDC circuit breakers, that these components face. Table 2 lists the 'standard' components applied in a 'nonstandard' way.

| Mechanical switching devices
Every practical HVDC circuit breaker is equipped with a mechanical switching device. Its function is to enable low losses in continuous operation and to alleviate (when in open state) dielectric stresses on the power electronic components. In HVDC circuit breakers, every mechanical switching device has to achieve contact separation very fast, which is achieved by electromagnetic (EM) repulsion drives. Such drives are electronically controlled, which implies a certain susceptibility to EM interference from transients of the primary sources (arcing, re-ignition, fast switching, high di/dt-current, high du/dt etc.). In most designs, a (considerable) number of mechanical switching devices is put in series. This implies that power to the individual drives cannot be supplied through galvanic connections. Usually, transformers that have enough insulation capability are used. For example, several isolation transformers are stacked in series to achieve adequate insulation from earth for 500 kV HVDC circuit breakers.
High-speed drives and their isolated power supply are not used in such a way before in power equipment and service experience is very limited or non-existent due attention needs to be paid to the verification of the mechanical endurance of the total kinematic chain.
In addition, the proper functioning of a stack of a larger number of smaller interrupters needs a well-synchronized contact separation as well as a built-in redundancy to overcome the functional loss of one or more individual interrupters. Differences of �0.1 ms in switch opening times are reported in a stack of 10 vacuum fast disconnecting switches, which achieves 1000-kV isolation in 2 ms [59].
The special high-speed drives cause huge impact forces on the contact systems of vacuum/SF 6 interrupters. Care must be taken when applying standard AC vacuum interrupters in combination with fast EM drives. Especially, the bellows of vacuum interrupters are not designed to withstand a certain number of high-impact force opening operations. The series combination of several/many interrupters has its challenges, not only mechanically but also electrically. Sharing (grading) of voltage needs to be considered seriously, not only regarding DC voltage but also during transients. For AC applications, niche products like capacitor bank switches consisting of up to nine series vacuum interrupters do exist but have a poor service record [60]. In general, for AC, high-voltage vacuum circuit breakers are developed with as few as possible series interrupters, never more than two at present. Figure 15 shows a conceptual design of a 525/600 kV active current injection HVDC circuit breaker with six highspeed HV vacuum circuit breakers in series [38]. Availability of a limited number of HV vacuum breakers is an advantage compared to a much higher number of MV vacuum breakers.
Vacuum is a very good 'medium' regarding interruption of HF current and very fast recovery of the gap against steep rising recovery voltage. Nevertheless, the application of vacuum interruption in active current injection type of HVDC circuit breakers may approach performance limits.
Mechanical gaps (vacuum/SF 6 ) breakdown electrically when they are not able to withstand voltage. Most critical is the fault current suppression phase, where the overvoltage is around 1.5 p.u. Whereas at the same time, the gaps are recovering from interruption and/or switching. After fault current suppression, there is a much longer exposure to the recovering system voltage and its (slow) transients, until the residual current switch takes over that voltage stress. Breakdown of (a) vacuum gap(s) is less critical than of an SF 6 gap, since vacuum is able to restore its insulation state very fast (see Figure 13), while SF 6 generally cannot. In addition to the damage of its contacts, the impact to SF 6 switchgear is that power electronic switches in the continuous current path will be damaged, which results in the complete malfunctioning.
In HVDC circuit breakers, SF 6 disconnectors need to open with very low current and with very low voltage in order to avoid arcing. Once current (at contact separation) exceeds a certain threshold, the arc will persist during a time, depending on the voltage across the commutation branch.
Current at contact separation is determined by the leakage current though the snubbers/grading elements of the series (semiconductor) switches in the continuous current branch (up to a few amperes). The voltage against which the disconnector is opening is determined by the on-state voltage of the semiconductors in the commutation branch (main breaker), which can be several hundreds of volts to a few kilovolts. The latter could be sufficient to keep current conduction in the disconnector if opened before current is fully commutated. Therefore, the design of (ultra-)fast disconnectors is very critical. Opening of the disconnector needs to be synchronized carefully, after current transients in the continuous current branch decay sufficiently.
Once the main breaker has interrupted the fault current, soon the full TIV appears across the switching gap, which must have been sufficiently open to isolate. Breakdown of this gap would lead to dielectric overload of the load commutation switch and a free burning arc in the SF 6 disconnector. Therefore, dielectric coordination of this disconnector allows only a very small variation in its opening time over service life. Requirements for mechanical stability are more severe than for controlled (capacitor bank) SF 6 circuit breakers for HVAC applications [61]. Figure 16 shows examples of various mechanical switching devices in HVDC circuit breakers [62,63].
In many cases, standard AC vacuum circuit breakers are used as ultra-fast disconnector. Such devices are not optimized for DC voltage withstand, so proper verification is necessary. Moreover, standard vacuum breakers contain arc control devices (axial or radial magnetic field arc control devices), which add unnecessary weight to the interrupters and additional limits to the actuator.
In addition, the standard contact material, a Cu Cr alloy, may not be the optimum choice for DC conduction and insulation. From dedicated studies, it was found that different designs of commercially available 36-38 kV AC vacuum circuit breakers acted very different regarding the interruption of HF counter current and TIV withstand capability [39].
In the active current injection schemes using capacitor discharge as the counter current source, an ultra-fast switching device must be used to start the discharge. This may be a mechanical switch (vacuum-making switch, triggered spark gap) or a semiconductor stack (IGCTs, thyristors). In both applications, the very large di/dt and peak current need to be evaluated as a non-standard stress. In the case of vacuum-making switch, provisions must be made to F I G U R E 1 5 Conceptual design of a 525/600 kV active current injection HVDC circuit breaker [38]. HSMS: High-Speed Making Switch. HDVC, high-voltage direct current SMEETS AND BELDA avoid contact welding, originating from the pre-strike arc that is comparable to the back-to-back capacitor bank making function in AC application. For extra high voltage (EHV) applications several of these switches need to be connected in series. Synchronous operation of these making switches is essential to avoid premature current injection as a result of pre-strike. In case of semiconductor-making switches, di/dt and short-time thermal and dynamic stresses can be extreme and far from standard. In addition, during normal operation, the making devices in open position are subjected to continuous DC voltage stress.

| Semiconductor switches
The application of large stacks of semiconductors is not new and ample experience exists in AC/DC converters.
In the load commutation switch that needs to commutate the current into the commutation (main breaker) branch, large current is ramped down to zero with a very high di/dt. This switch consists of a limited number of semiconductors. The proper choice of the number of elements is critical from thermal point of view and continuous cooling is necessary.
Load commutation switches are mostly made from the state-of-the-art IGBTs slabs, which consist of IGBTs and diodes at different sections of the semiconductor package. These packages have IGBTs and diodes to be able to conduct current in reverse direction. Since the load commutation switch is conducting DC current continuously in normal operation only the IGBT parts of the semiconductor volume are heated due to on-state loss. The results of this unequal heating shall get sufficient attention as there is not much operational experiences. During functional tests of HVDC circuit breaker that focus on the proof of concept, steady-state effects like unequal heating cannot be observed. The latest developments of IGBTs, known as BIGTs, which uses the same semiconductor volume for both IGBT and diode are not susceptible to this situation [64].
In specification, one might to make sure what the thermal limit in the case of a full-through short-circuit current (shorttime current) is. Semiconductors are sensitive, and contrary to converters, HVDC breakers may have no protection of semiconductors (like blocking and bypassing current into freewheeling diodes) in case of an unexpected short-time current exceeding the rated breaking capability.
By activating only a limited number of cells in the main breaker semiconductor stack, certain designs of hybrid HVDC circuit breakers can operate in fault current limiting mode [65].
In hybrid HVDC breakers, the load commutation switch is conducting current continuously (the main breaker may be as well, but at very low current) without switching. This is a different operation than in 'normal' operation, like in converters, where semiconductors are switching continuously. In such a way, semiconductors conduct during on-state, while diodes might conduct during off-state. This results in a lower thermal gradient across the package volume. Alternatively, the breaker in the commutation branch is idle, or conducting small current while under 'standard converter operation' its semiconductors are operating continuously. It is not known how the 'one-time only' activation to switch off all semiconductors might have an impact on a possible conditioning of the semiconductor junction and/or package. Figure 17 displays examples of semiconductor switching devices in HVDC circuit breakers [66].

| MOSA energy absorber
A large volume of MOSA is needed for absorbing the energy from the faulted system and maintaining the counter voltage. Many columns are needed in parallel to cope with large energy absorption. This means the individual zinc-oxide (ZnO) varistor discs composing each column need to be carefully selected to have an equal current flowing through the column. Given the high non-linearity of the u-i characteristic, a small mismatch in conduction voltage would lead to a large current difference. This, in turn, would heat the columns unequally and change its characteristic unfavourably [67,68]. Therefore, very careful matching of the columns is essential. Figure 18 shows some visual impressions of (experimental) MOSA for energy absorption, among other in HVDC breakers [69]. F I G U R E 1 6 Examples of mechanical switching devices in HVDC circuit breakers. (a) One unit (of two) of an SF6 ultra-fast disconnector for a 500 kV HVDC circuit breaker [62]; (b) 100 kV vacuum circuit breaker with high-speed actuator [38]; (c) Vacuum interrupter in a VSC assisted resonant current design with Thompson drive [49]; (d) 350 kV ultra-fast SF 6 disconnector [52]; (e) Series combination of two 40.5 kV vacuum disconnectors with Thomson coil actuators (one third of the complete disconnector in a 200 kV HVDC breaker) [63]. HDVC, high-voltage direct current The total mass of ZnO material in HVDC circuit breakers can be over one thousand kilograms, which implies that cooling down (after interruption of a significant fault current) is very time consuming. In testing, it is recommended to have cooling times in the order of several hours after rated fault current interruption. The consequence of this is that when a reclosure and re-open function is required, the design should be able to absorb at least double the energy that is associated with a single interruption (and proportionally more counter voltage creation etc. When more than two reclosures are expected). Moreover, the other functions of the breaker (local current zero creation), should be accommodated for quickly repeated operation.
Multi-reclosure of HVDC breakers is required in OHL systems. OHL arcing faults most often disappear after a reclosure and a subsequent opening (O-CO sequence) of the breaker. HVDC circuit breakers for the Zhangbei (OHL) project in China have been specified to deal with total energy absorption exceeding 150 MJ [70]. When the actual short circuit, carrying the large fault current is removed, in many cases a low-current secondary arc to earth persists, which is fed through the stray impedances of the transmission system. Reclosure should then be delayed until the secondary arc ceases, mostly by natural reasons, like wind or by thermal elongation. CIGRE studies [71] have indicated that in HVAC OHL systems, after a single openclose action the fault is removed in the vast majority of the cases. Further study needs to reveal the persistence of secondary arcs in HVDC OHL systems.
In cable systems, reclosure does not seem to be a suitable action, since faults in cable systems are normally destructive and need repair.

| TESTING OF HVDC CIRCUIT BREAKERS
Testing of HVDC circuit breakers is largely unknown territory because international standards do not yet exist and hardly any multi-terminal project is gaining experience with these devices under fault conditions.
Many HVDC fault studies have been performed on model HVDC grids [10,72,73] with several studies based on the CIGRE B4 DC grid test system [74], the main focus being on understanding of fault conditions in HVDC grids and for defining requirements of HVDC circuit breakers.
However, in the absence of HVDC grids, very little operational experience is available yet. In-service fault current interruption tests have been reported from the 160-kV Nan'ao project, where a staged pole-to-earth fault was initiated in the live system, causing the circuit breakers to correctly interrupt 1.4 kA in 3.5 ms [75].
Nevertheless, HVDC circuit breakers are under intensive development and there exists a need for verification of their specified performance. An obstacle in testing larger HVDC circuit breakers is that the 'synthetic' test methods, commonly applied in AC breaker testing up to the highest voltages [1], cannot be applied for HVDC breakers. The reason is that the test circuit needs to provide not only rated current and voltage but also a certain degree of energy stress. Hence, sources providing real power (megawatts) are needed to prove the breaker's rated performance.
In the recent past, several tests on prototype HVDC breakers were carried out as part of the product development process. In almost all cases, capacitor bank discharge circuits are used to produce an oscillating current with a single [14,30,33,50] or double frequencies [53]. In this way, a proper rateof-rise of DC fault current can be realized and proof of a conceptachieving local interruption in the continuous current branch, the internal current commutation, and the TIV generationcan be verified. However, such an approach cannot verify sufficient duration of TIV withstand and rated energy absorption, since capacitor circuits cannot provide sufficient energy, nor can they provide a long enough t FS [76].
Adequate test circuits are essential for rated performance verification of HVDC circuit breakers. Ideally, the testing of HVDC circuit breakers require high-power DC source-high-  [59], (c) [66], (d) [33], (e) [63], (f) [30]). HDVC, high-voltage direct current SMEETS AND BELDA current and high-voltage simultaneously-which is not readily available at any test laboratory worldwide. Given the current stage of development and market potential, it is unlikely that expensive and elaborate test circuit will be set up for solely testing HVDC circuit breaker prototypes. Thus, alternative test circuits providing equivalent stresses are urgently sought. With this aim, several different kinds of test circuits have been used at different stages of HVDC circuit breaker developments [76]. Various test methods have been considered to address some of the limitations of test circuits and/or to meet some of the essential stresses that need to be replicated in a test. Nevertheless, for many other reasons, the testing of HVDC circuit breakers have been limited to, mainly, a proof of a concept.
Before designing any test circuit, the critical stages of current interruption process and the actual stresses that need to be reproduced (for complete stress) must be identified. To this aim, six critical stages of DC fault interruption are defined: 1. Rise of fault current (proper di/dt) → breaker needs to act very fast; 2. Local current interruption in continuous current branch; 3. Internal commutation → initiation of counter voltage generation (du/dt); 4. Limitation and maintenance of TIV → fault current suppression; 5. Energy absorption; 6. System recovery voltage withstand.
In Table 3, these stages are schematically outlined, and the critical parameters are identified.
The main motivation of including also the stages 4-6 in interruption tests is the following: � Mechanical switches are key and novel components of all HVDC circuit breakers. In some applications, they switch high current, and in some applications, they isolate high voltage, or both. Short-time dynamic (stage 4) overvoltage withstand and long-duration static dielectric withstand (stage 6) shall be an essential part of a verification program. � Surge arresters in HVDC circuit breakers are used in a different application than for overvoltage protection (the usual application). The unusual amount of energy to be absorbed requires a large number of parallel arrester columns and an equal current sharing between the non-linear ZnO elements. CIGRE WG A3.39 is studying the specific HVDC breaker MOSA application.
As part of the European Union's Horizon 2020 'PRO-MOTioN' project [18], alternative test schemes and powerful test circuits that can verify complete short-circuit interruption performance are developed and demonstrated [77].
A novel test method that uses existing installations at a high-power AC test laboratory is developed and a schematic of the test circuit is shown in Figure 19. To supply a complete stress in 'one shot', the test circuit is composed of four parts: the power source, over-current protection, a DC voltage source for post current suppression dielectric stress, and an arcing time prolongation circuit, each of which are indicated in separate dashed boxes-each part described in detail in the study by Belda et al. [77].
The method is based on the use of AC short-circuit generators operated at low power frequency, illustrated in Figure  20. For a test at 16⅔ Hz, the source voltage amplitude remains within 75% of its peak value for about � 7 ms from the crest value, providing a window of 14 ms for testing. If a short circuit is applied at a precise point on the voltage wave and with proper choice of circuit inductance, short-circuit current with the desired rate-of-rise can be produced. Together with the fact that the HVDC circuit breakers operate quite rapidly (within several milliseconds), the desired test current can be produced and interrupted when the source voltage is near its crest value-within an interval in which it is seen as a pseudo-DC source by the HVDC circuit breaker (see Figure 20). Depending on the actual speed of operation of the HVDC (d) puncture of ZnO material after electrical overload [39]; (e) one module (of 10) for 80 kV 15 MJ in a 500 kV HVDC circuit breaker [59]. (f) MOSA in experiments to study the impact of thermal overloading of arrester discs and -columns [39]. MOSA, metal-oxide surge arrester. HDVC, high-voltage direct current circuit breaker, the power frequency and the test time window can be adjusted. Thus, the complete current interruption process occurs while the source voltage is sufficiently high. In such a way, sufficient stressed in terms of current, voltage, and energy are ensured.
Of all the critical current interruption stages described in Table 3, only stage 6 (DC system recovery voltage) cannot be applied by AC short-circuit generator, because long lasting DC voltage is required. This has to be applied in a 'synthetic' way, that is voltage application from a separate voltage source, like a pre-charged capacitor bank as shown in Figure 19.
Based on this concept, adequate test circuits up to 350 kVrated DC voltage have been designed and demonstrated [77] using six short-circuit generators and up to 10 step-up transformers.
The advantage of the low-frequency AC method is that such sources are widely available in major high-power laboratories around the world. In many tests in the PROMOTioN project, a frequency of 16⅔ Hz is chosen because several countries apply this frequency in traction applications and test laboratories have experience with such circuits.
In order to harmonise the stresses to which HVDC circuit breakers are exposed to during a fault current interruption tests, within the PROMOTioN project, agreement among participating manufacturers (Mitsubishi Electric, ABB, SciBreak) and the test authority (KEMA Labs) was reached on a set of test duties to which their breakers are exposed. Table 4 shows these test requirements.
In many cases, especially for testing EHV DC circuit breaker, it may not be possible to apply full-rated energy stress either due to a limitation of a test laboratory or for some practical reasons the test breaker is supplied with reduced energy capability. In such a case, an alternative test duty that can replicate the magnitude and duration of TIV is defined. The test duty named 'TDT' in Table 4 is introduced to fill this gap. This duty is intended to demonstrate the TIV withstand capability of the circuit breaker during the full duration of TIV that would occur under full-rated energy (e.g. as specified in a specific project). Details on the actual realization of this duty in a project are described, see [78].
The test program of Table 4 is taken as a guideline in the testing of three HVDC circuit breakers rated 80 kV 16 kA (VSC-assisted resonant current type), 160-200 kV 16 kA (active current injection type) [47], and 350 kV 20 kA (hybrid type), see Figure 21 showing laboratory set-up and interruption performance of an active current injection-and a hybrid HVDC breaker at the TF100 duty.

| STANDARDISATION STATUS
As a result of recent multi-terminal project proposals, wide spread research activities, CIGRE [8] and International Electrotechnical Commission (IEC) inventories [79], IEC Technical Committee 17/17A, C has set up six working group (WG)s by early 2020 covering requirements and tests of all DC switchgear (>1.5 kV) listed in chapter one. IEC17/17 A WG64 will compile a technical specification of HVDC circuit breakers in 2021.
IEC Technical Committee 115 issued a standard on DC side equipment for line-commutated converter systems [80]. This document includes basic requirements for DC disconnectors and certain types of specialized DC switching devices (such as MRTS), but it excludes any type of DC circuit breaker designed to interrupt fault currents.
Chinese standards have been issued on DC switches [81,82] and a Chinese standard on common specifications of DC circuit breakers is in development [83], to be followed by separate national standards for 'mechanical' (active current injection) and hybrid types.
In CIGRE, Joint WG B4/A3.80 is in the stage of finalisation its study of HVDC circuit breakers and its test requirements, whereas WG A3.40 is focussing on MVDC circuit breakers and systems. CIGRE WG A3.39 is addressing the application of MOSA in HVDC circuit breakers, among others.

Stage of interruption Breaker action Components mainly stressed
Critical parameter

| EXISTING AND FUTURE HVDC GRID PROJECTS
Recently, HVDC grids have been recognized for their capability to evacuate huge amounts of (renewable) energy, and several HVDC grid studies are underway [84]. The Chinese Zhangbei multi-terminal project [31] will give a huge impetus towards maturation of HVDC circuit breakers, though service experience is still lacking. Since the project has been commissioned, the lessons learned and records of service experience of HVDC circuit breakers are now curiously expected by the international community. They will serve the advance of future projects on harvesting green energy.
The European project 'PROMOTioN' [18] aims to remove technical (and non-technical) hurdles in the deployment of a large meshed offshore HVDC transmission grid in the Northern Seas, necessary to harvest huge wind generated power up to 200 GW by 2050 [85]. In this project, full-power and complete fault testing of HVDC circuit breakers has been publicly demonstrated for three different prototypes of HVDC circuit breakers.
Recently, an HVDC grid proposal was launched by a German utility on harvesting offshore wind energy from the North Sea and transmitting it across large distance onshore [86]. Other studies show that an organic growth by interconnecting step-by-step point-to-point connectors gradually leads to a multi-terminal HVDC system. An example is a system in north-east UK [87], that may potentially evolve this way. Other concepts are studied [88].
Existing examples of (radial) multi-terminal HVDC projects operating without HVDC circuit breakers are the Québec F I G U R E 2 0 Schematic of using 16⅔ Hz AC short-circuit generators for fullpower testing of HVDC circuit breakers. AC, alternating current; HDVC, highvoltage direct current F I G U R E 1 9 Compete test circuit using AC short-circuit generators. AC, alternating current 188 -SMEETS AND BELDA (New England five terminal link) and the Sardinia-Corsica (Italy three terminal link) [8].
One major technological hurdle in the realization of HVDC grids was the virtual absence of commercially available HVDC circuit breakers. Though, except for China, major HVDC grid projects seem not to appear within a short horizon, a huge effort in academic research and industrial product development is observed in HVDC grid protection, control, and transient-and fault current interruption studies.

| DISCUSSION
HVDC circuit breakers are large, expensive and technically complicated devices that depend on the proper coordination of many components: mechanical, power-electrical, powerelectronic and control. There is very little information on the costs/prize of this equipment. From recent publications, it is suggested that the Zhangbei 500-kV HVDC circuit breakers are in the 10-15 M€ range [89]. Anyhow, costs of protection of HVDC grids will be rather high: the investments for system protection (including HVDC circuit breakers) for HVDC grids are estimated up to 9% of the total project costs [20].
Regarding the (future) applicability of certain technologies, it is too early to draw conclusions. Active current injection (at 160 kV [28]) and hybrid technology (at 200 kV [29]) both seem to show good performance in service albeit for a relatively short time (few years). A technology comparison summary can be found in [8, table 16-1]. In general, the active current injection technology shows main advantages as simple topology, very low continuous losses, lower costs and offering outdoor/ GIS application possibilities. Hybrid breaker technology has a shorter operation time, absence of a commutation capacitor, better controllability and is better suited for multiple opening.
Further assessment of their features and quantification in terms of costs, reliability etc. Is not yet possible in the present stage of pilot-like application. Since in the Zhangbei project both technologies are applied, relevant experience is to be expected.
A sizeable spin-off of the HVDC interruption technology may be the development of high-speed AC fault current limiting devices, taking advantage of the maturation of highspeed mechanical switching devices in combination with power electronics [90][91][92]. After all, fast counter voltage generation is as effective for fault current suppression in AC as in DC.

| CONCLUSIONS
� HVDC circuit breakers have been realized and are being installed in power systems, showing the technology is close to maturity. � HVDC breakers are systems that interact directly with the power grid, unlike HVAC breakers that passively undergo the system's stresses. New, and common to all designs is the combination of high-speed mechanical switchgear, energy absorption and power electronics, each in a stacked configuration. Most of these components have to face non-standard stresses without compromising reliability. � Standardisation is also still in the development phase, which may be not surprising given the many new, unusual and unproven combination of technologies. Critical assessment by interdisciplinary standardisation committees, merging expertise from mechanical and power electronics switching technology is needed. � Testing shall not be confined to verification of internal commutation and counter voltage generation but shall include proper voltage and energy stress after internal Value to be estimated with Equations (2) -(4) in chapter two based on U s , U MOSA , t IC , I pk , as would be present in service condition. c This test-duty is to verify dynamic dielectrical withstand of the mechanical switching gap during the maximum duration of the current suppression time as would occur in service condition.
SMEETS AND BELDA -189 commutation. A test program is defined together with the industry and actually used in the complete fault current breaking verification of HVDC breakers up to 350 kV breaking 20 kA. � It can be argued that the most critical components of a HVDC circuit breaker are the mechanical switching devices for interruption and/or insulation. In closed position, they are crucial to system availability and in opening operation their dynamic dielectric coordination is very critical regarding current interruption. Solid mechanical operational requirements need to be in place to ensure lifetime reliability. � Optimization studies are needed towards cost reduction, reduction of number of parts, which in some designs is excessively large. Having available mechanical switchgear for high voltage (e.g. one break per 145 kV in vacuum for a fast circuit breaker, or 350 kV one break in SF 6 for a fast disconnector) potentially increases reliability compared to multiply stacked solutions. Availability of a fast high-voltage breaking device would mean a major breakthrough, since hundreds of semiconductors with several hundreds of control/power fibres are still necessary in the EHV hybrid designs