1. Introduction
In many cases, HVdc transmission lines are built with some spare capacity for future expansion or to meet other design requirements [
1]. This situation exists on the present-day Bipoles I and II of Manitoba Hydro’s HVdc transmission system. The potential renewable energy resources and new load centres can be integrated to the electricity grid with less cost using the spare capacity of the existing HVdc lines. However, high-power interfacing electronics are required for tapping into HVdc transmission lines. At present, the majority of existing bulk power HVdc transmission lines use line commutated converter (LCC) technology due to superior economics and proven technological performances [
2]. On the other hand, the voltage source converter (VSC) offers a practical approach for tapping. VSCs also offer the ability to change the direction of power flow for meeting the instantaneous power balancing requirements [
3]. The black start capability [
4] and the ability to connect to weak ac systems [
5] are very useful when integrating remote or isolated renewable power generation systems [
6].
The two converter technologies can be combined in many different ways. A VSC can be combined in series with an LCC at each converter station as proposed in [
7,
8,
9]. Different ways of implementing hybrid LCC-VSC two-terminal or multi-terminal HVdc (MT-HVdc) systems, where the individual converter stations are based on different technologies, can be found in [
10,
11,
12,
13,
14,
15,
16,
17,
18,
19,
20]. Two main classes of hybrid MT-HVdc systems are:
A number of VSC rectifier stations, typically connected to offshore wind farms, linked to a large onshore LCC inverter station supplying one or more major load centres [
10,
11,
12],
One large LCC rectifier, typically connected to a large hydropower station, linked to a number of small VSC inverters supplying urban load stations [
13,
14,
15,
16,
17].
In the first configuration, the advantages of VSC stations such as small footprint, ability to connect to a weak ac system are exploited in the offshore rectifiers, and the economy of LCC station in building large converter station is exploited in the onshore inverter. In the second configuration, the economy of LCC station is exploited in building a large rectifier station connected to a strong system and the advantage of the small footprint of VSC stations is exploited in building the converters supplying urban load centres. A real-world example for the second type is the Woudong hybrid three-terminal grid, which comprises an 8 GW LCC rectifier and two VSC inverters rated 5 GW and 3 GW [
14]. This scheme is under construction and will be commissioned in the year 2022 [
21]. In contrast, this paper considers tapping into an existing LCC link using VSC converters as described in [
17,
18,
19,
20].
Modern VSC stations are built using modular multilevel converter (MMC) technology using half-bridge sub-modules (HB-SM) or full-bridge sub-modules (FB-SM) [
22]. Although the FB-SM option is more flexible and has the inherent DC fault current blocking capability, it is relatively expensive and currently not widely applied in practical systems. In contrast, HB-SM MMCs are more common and have been used in VSC based multi-terminal HVdc systems [
23,
24].
A fault clearing scheme for hybrid LCC-VSC MT-HVdc with HB-SM MMCs is proposed in [
1]. The configuration proposed in [
1] is depicted in
Figure 1, and the method relies on ac CBs to interrupt fault currents from the VSC rectifier and employs a diode valve in series with the VSC inverters to block dc fault currents.
VSC-A is assumed to be operated either as a rectifier or inverter. In contrast, VSC-B is assumed to be operated only in the inverter mode. To facilitate feeding power from VSC-A during rectifier operation, the diodes connected to VSC-A should be bypassed. Additionally, a series reactor is inserted for limiting the rate of rise of current injected by VSC-A during dc faults. A dc fault is cleared using the following sequence:
De-energize all VSC rectifiers by opening their ac CBs to avoid fault current injection from the ac side,
Apply force retardation at the LCC rectifier,
Open the fast mechanical switches when the current through them are sufficiently small.
Although this method works and can be implemented with the existing technologies, one of its drawbacks is the prolong time to extinguish arcing faults due to the long time taken to dissipate the stored energy in the VSC inductive elements and the transmission line, even after blocking the IGBTs. This is in contrast to LCC HVdc systems, which can quickly reduce dc fault currents by applying forced retardation procedure. Besides that, the series-connected high-power diode valve can be subjected up to 2 pu reverse voltage during the fault transients. Therefore, when a hybrid multi-terminal HVdc transmission system is created by connecting VSC based taps on an existing LCC HVdc link, and if the VSC rectifiers rely on ac side CBs to interrupt dc side fault currents [
1], then the dc side fault clearing time increases in comparison to that of the original LCC HVdc link. The fault clearing performance and the reliability of the hybrid VSC-LCC MT-HVdc system proposed in [
1] can be improved if high voltage dc circuit breakers (dc CBs) are employed for fast, selective fault isolation. Temporary faults due to flashover are very common in long open conductor overhead transmission lines used in HVdc transmission and therefore fast temporary fault recovery performance is essential [
25]. Recent developments in high voltage dc CB technology include full-scale prototypes and field installations [
24,
26]. Technically viable commercial dc CB solutions are expected to emerge in the near future. An enhanced protection scheme having higher selectivity and higher security is developed in this paper to use in conjunction with strategically placed dc CBs.
Although selective fault clearing in purely VSC based MT-HVdc systems has been an active research area in recent years [
27,
28,
29], the technology is not well established, especially for hybrid LCC-VSC MT-HVdc transmission systems that comprise of multiples zones, and gaps exist in the understanding. In contrast to the dc fault clearing approach proposed in [
1], a selective fault clearing scheme needs a fault detection and discrimination scheme suitable for hybrid LCC-VSC multi-terminal systems having multiple protection zones.
In [
30], a traveling wave-based fault location scheme is proposed for two-terminal HVdc links, and this concept is extended and applied for the protection of hybrid VSC-LCC HVdc systems in [
31,
32,
33,
34,
35]. Most of the fault discrimination schemes presented for hybrid LCC-VSC HVdc transmission systems are proposed or evaluated for two-terminal HVdc systems [
31,
32,
33,
34,
35], which typically have a single line protection zone. The traveling-wave protection (TWP) is reportedly considered for Wudongde three-terminal hybrid HVdc project for line protection [
33]. A fault discrimination method is proposed in [
36] for a hybrid LCC-VSC based MT- HVdc transmission system comprising of multiple zones. The method proposed in [
36] uses the ratio of two voltage components at two different frequencies extracted from the fault transient as the fault indicator and claims to be capable of discriminating faults of up to 400 Ω fault resistance in a MT- HVdc system comprising of an LCC rectifier connected to two-VSC inverters. However, in [
36] a fault clearing procedure is not discussed and the adequacy of the proposed scheme for successful fault clearing is not fully demonstrated.
Furthermore, without having a complete protection scheme that discriminates the faults in different zones, and a fault recovery scheme that invokes appropriate actions depending on the faulted zone and fault type, the potential fault recovery performances cannot be evaluated. The fault discrimination scheme should be capable of discriminating faults at each zone, up-to a fair value of fault resistance expected in a typical hybrid LCC-VSC based multi-terminal system. In addition, the fault discrimination method should be able to make decisions within a very short duration as dictated by the dc CB limitations. This is because a dc CB has to interrupt the rapidly rising fault currents before they exceed the maximum breakable current. The fault current injected through a VSC branch could reach its peak value within a few milliseconds. The fault discrimination speed of the scheme presented in [
36], which needs 5 ms time window, may not be adequate with respect to the typical dc CB performance cited in the literature [
24,
26].
In contrast to the previously mentioned literature, this paper addresses the fault discrimination, fault clearing, and the post-fault recovery performance in a class of hybrid LCC-VSC MT-HVdc schemes in a holistic manner. The configuration of the hybrid LCC-VSC MT-HVdc scheme considered is similar to the one shown in
Figure 1 and the main contributions of the paper include (i) development of a complete protection scheme based on the local voltage and current measurements to identify the faulted segment and the conductors involved in the fault within a short time interval after a dc side fault, (ii) demonstration of the suitability of the fault discrimination scheme in terms of the capability of discriminating faults at the boundary of each zone for up to about 50 Ω of fault resistance with a speed that is adequate for meeting the breaking capability of the dc CB prototype presented in [
26], (iii) development of a detailed fault recovery procedure that minimizes the extent of outages, and (iv) simulation-based analysis of the proposed algorithms under a variety of possible fault scenarios.
2. Proposed Protection Scheme
2.1. Key Components and Grid Layout
Figure 2 shows the considered hybrid LCC-VSC MT-HVdc grid layout and the essential elements of the proposed protection scheme.
Two VSC stations with a lower rating compared to the LCC stations are connected through two transmission lines, which are hereafter referred to as VSC branches, to a 1400 km long main transmission link. A bipole HVdc transmissions system without a dedicated metallic return wire similar to Manitoba Bipole-I and -II [
37] is considered in this study. It is assumed that earth return mode is allowed for a short period for single-pole fault recovery. The VSC stations are based on more economical HB-SM technology.
A key requirement is to ensure that the reliability of the original LCC line is not degraded due to tapping. In order to minimize the fault clearing and recovery time for temporary dc faults, all HB-SM based MMCs on the affected pole(s) must be immediately disconnected from the dc network. Additionally, during all permanent faults on the VSC branches, the faulted line segment must be disconnected before the stability of the LCC link is affected. This is only possible by using dc CBs for selective fault isolation. In order to maximize the fault recovery performance with a minimum number of dc CBs (which are high-cost items), it is proposed to place a dc CB at each tapping point on the VSC branches. In this configuration, dc CBs perform two main roles:
For both temporary and permanent faults on VSC branches, they avoid the impact on the LCC link by promptly disconnecting faulty conductor(s) from the main LCC link.
For temporary faults on the main LCC link, they avoid the need for a complete shutdown and restarting of VSC stations by promptly disconnecting faulty conductor(s) from the VSCs. The VSCs that are connected to faulty pole(s) could be switched to static synchronous compensator (STATCOM) mode (i.e., no real power transfer) until the fault on the main transmission line is cleared.
It is necessary to have dc CBs on both poles to perform the above roles. With this arrangement, a VSC station is completely de-energized for faults on the line segment connecting it to the main LCC link. De-energization of a VSC during temporary faults can be avoided by providing additional dc CBs at the VSC terminals, but this is an expensive solution with only a marginal contribution to improve the reliability or safety of the system:
The fault clearing process is initiated with the help of fault discrimination information provided by intelligent electronic devices (IEDs) installed on appropriate places as indicated in
Figure 2. The forced retarding fault current blocking mechanism utilized on the LCC terminals is used for the proposed scheme as well. Based on the above reasoning, the dc CB placement shown in
Figure 2 is considered as the arrangement that needs the least number of dc CBs for the proposed hybrid VSC-LCC multi-terminal HVdc topology, and it divides the dc network into three protection zones.
In this scheme, it is necessary to discriminate the faults on the main transmission line (Zone-M) from those on the branches connecting VSC-A (Zone-A), and VSC-B (Zone-B); and identify the pole(s) involved in the fault. An intelligent electronics device (IED) capable of the above tasks can be implemented at each tapping point as indicated on
Figure 2 with the help of series di/dt limiting inductors, which are an integral part of dc CBs [
26,
27,
28]. The protection IED-A at the tapping point-A comprises two functional units: one denoted as IED-AM to detect faults on the main transmission line, and the other denoted as IED-AI to detect faults on the line connecting the VSC. A similar protection IED is employed at the tapping point B as well.
The coordination of converter stations in this multi-terminal transmission system is important for stable normal operation and fault recovery. The centralized master power controller (MPC), proposed in [
1] is considered in this study. Grid energization and co-ordination is carried as described in [
6], in which the LCC inverter is operated in the constant extinction angle control mode, while VSC stations are operated in the constant power control mode during normal operation. The LCC rectifier is operated in the constant current control mode. The primary function of the MPC is to calculate the current order for the LCC rectifier to fulfil power demand at the LCC inverter while considering the instantaneous current injections from each VSC station. For example, the current order of the positive pole (P-pole) is calculated using Equation (1).
where
are power reference values, and
KLI,
KVA,
KVB are power ramping rates of the LCC inverter, VSC-A, and VSC-B respectively. The binary signals
SLIP,
SVAP, and
SVBP are generated by a fault recovery supervisory function to reset the respective current component to zero after detecting a fault on P-pole conductor connected to the LCC inverter, VSC-A, and VSC-B respectively.
,
,
,
,
, and
are conditioned pole voltage measurements taken through the signal pre-processing arrangement shown in
Figure 3.
This signal pre-processing arrangement includes a hold circuit which holds the pre-fault voltage measurement during the fault recovery period and a first-order filter with 200 ms time constant to avoid erratic current orders due to low dc voltages that may occur during faults. According to Equation (1), the current order is set to zero during a fault on Zone-M, by setting SLIP = 0. During a fault on a VSC branch, the respective term is set to zero via SVAP and SVBP. During a single-pole fault, the healthy pole current order is frozen at the pre-fault value until the recovery. The current order for N-pole is calculated independently in the same manner.
2.2. DC Side Fault Clearing Strategy
The proposed dc fault clearing procedure is shown in
Figure 4.
In order to preserve the operation of the healthy pole during single-pole-to-ground faults, the fault recovery process is applied independently for positive and negative poles. As depicted in
Figure 4a, upon detecting a fault in Zone-M, force retardation is applied to the respective pole(s) of the LCC rectifier. For example, if only P-pole is involved in the fault,
SLIP in Equation (1) is reset (
SLIP = 0) to notify the MPC of cease of power transmission in P-pole. After a fixed time delay
TFR, which should be carefully selected by considering the worst case, the force retardation is released. If the voltage is recovering,
SLIP is set (
SLIP = 1) again and the firing angle of the LCC rectifier is gradually decreased to its pre-fault value. If the voltage does not recover in three attempts, the fault is declared as a permanent fault and the operation of LCC is stopped.
As depicted in
Figure 4b, for a fault on the main transmission line, the dc CB of each faulted pole is disconnected immediately. Then the operating mode of the faulted poles of the VSC stations are changed to dc side voltage control mode till the fault is cleared. For a fault on a VSC branch, say on Zone-A as depicted in
Figure 4b, the relevant dc CBs (dc CB on P-pole, N-pole, or both) are immediately opened to isolate the faulted pole(s) from the main transmission line. The IGBTs of the faulted pole of VSC-A (say P-pole) are immediately blocked by the converter internal protection. Subsequently, the faulted pole, P-pole in this case, is de-energized by opening the corresponding ac CB, and the MPC is notified about the de-energization by resetting
SVAP (
SVAP = 0).
Before enabling the reclose operation, a fixed delay of T
RC1 is allowed to rule out the possibility that the fault is permanent because reclosing onto a fault is hazardous to converter IGBTs. This check may require communicating with protection IEDs [
38,
39,
40,
41]. Therefore communication delays should be taken into account in setting T
RC1. The approach of determining the presence of a fault will be discussed later in
Section 3.2. If the fault has been cleared, ac CB is reclosed and the operating mode of the relevant pole of VSC-A is changed from STATCOM mode to voltage control mode. The dc CB is reclosed once the converter terminal voltage reaches the dc voltage at tapping Point-A. Thereafter, the MPC is notified by setting
SVAP (
SVAP = 1) back to its normal value. The operating mode of P-pole of VSC-A is changed to P
DC control mode and the pre-fault power reference is re-established. The same process is applied to N-pole or both poles of VSC-A depending on the fault type. The same procedure is applicable to VSC-B, for faults on Zone-B. More details of the grid energization procedure can be found in [
6].
2.3. Fault Discrimination Strategy
As a breaker must isolate only the faulty pole(s) of the transmission line segment (protection zone) involved in the fault, a highly secure fault discrimination strategy is important to achieve the desired reliability improvement. The dc CBs separate the different protection zones and are associated with di/dt limiting inductors as shown in
Figure 2. These inductors are referred to as the boundary inductors in this paper due to their location at the boundaries of adjacent protection zones. Due to the existence of a boundary inductor between the main transmission line and a VSC branch, during a fault on the main transmission line, the maximum rate of change of voltage (ROCOV) observed at any terminal of the main transmission line is significantly higher than the maximum ROCOV observed on any terminal of a VSC branch; the opposite is true during a fault on a VSC branch [
27,
38]. This enables discrimination of faults and therefore, maximum ROCOV is selected as the main fault indicator [
27]. The sensitivity of the ROCOV based fault discrimination is improved by incorporating a directional logic as presented in [
41] and using the aerial voltage components. The directional logic is employed only on IEDs -AM, -AI, -BM, and -BI. The directional logic is not relevant for IED-LR and IED-LI, since there are no other dc protection zones behind them. The faulty pole is identified using the logic described in [
42]. The proposed fault discrimination algorithm with combined features is shown in
Figure 5.
The algorithm is run on an IED located at the boundary of a protected line. An IED takes voltage measurements at either side of the boundary inductors of P- and N-poles, and the currents through the inductors on both poles as inputs. VLN, VLP, are respectively N-pole and P-pole voltages on line side of the boundary inductors and VBN, VBP are N-pole and P-pole voltages of the bus side of the boundary inductors. It then extracts the aerial components of the input voltages and the currents: , the aerial component of the voltages at the line side of boundary inductors, , the aerial component of the voltages at the bus side of the boundary inductors, and , the aerial component of the current. The currents IP and IN are respectively the currents through the P-pole and the N-pole.
The algorithm is triggered when any of the observed rate of change of current (ROCOC) value is greater than the threshold
KT. The maximum values of ROCOV and ROCOC are tracked over a short time window,
, and the respective maximum values observed at the end of the time-window are sent to calculate the fault discrimination indices. Two indices,
FPN and
DFR, are calculated using Equations (2) and (3) using the maximum values of ROCOV and ROCOC.
If
DFR is greater than a preset threshold (
DFR > 1 + ε), the fault is declared to be on the forward side [
41]. The faulty poles are identified by considering the fact that index
FPN is close to unity for pole-to-pole faults (1 + ε >
FPN ≥ 1 − ε), considerably greater than unity for P-pole-to-ground faults (
FPN > 1 + ε), and considerably less than unity for N-pole-to-ground faults (1 − ε >
FPN) [
42]. ε is a positive tolerance value. Once the fault type is identified, depending on whether the fault is a single-pole fault or a pole-to-pole fault, the maximum rate of change of
VF is compared with a threshold (
for pole-to-ground and
for pole-to-pole) to determine whether the fault is within the protected line.