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Article

Centralized Multiple Back-Up Protection Scheme with Sharing Data between Adjacent Substations Based on IEC 61850

by
Min-Soo Kim
and
Sang-Hee Kang
*
Department of Electrical Engineering, Myongji University, Yongin 17058, Korea
*
Author to whom correspondence should be addressed.
Energies 2022, 15(12), 4195; https://0-doi-org.brum.beds.ac.uk/10.3390/en15124195
Submission received: 15 April 2022 / Revised: 30 May 2022 / Accepted: 3 June 2022 / Published: 7 June 2022
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Abstract

:
A centralized multiple back-up protection scheme with sharing data between adjacent substations based on IEC 61850 is suggested in this paper to overcome the inherent defects of a conventional back-up protection scheme such as uncertainty of a remote end condition, especially for a distance relay, long operating time delay, and IED/CT fails. A current differential protection element, a distance-based directional protection element, local back-up, and remote back-up protection elements are applied for the multiple back-up protection scheme suggested in this paper. The phasor voltage/current data of the IMU are transferred to a CPCU. In this paper, the IMU has two functions, which are local protection IED and merging unit, as well. The CPCU performs the back-up protection functions by using the phasor voltage/current data collected from other CPCUs located at the adjacent substations. IMU/CT fails are also considered. To verify the back-up protection scheme proposed, a testbed was composed of IMUs (implemented with ADS8688 and TMDSIDK572X), grand-master-clocks (LANTIME M1000-IMS), network switches (Syn 1588 Gbit switch), RTDS, and CPCUs. A target power system was modelled with RSCAD. The results of this research can be expected to provide a practical guide to constructing the future centralized protection for a digital substation.

1. Introduction

Power systems are now more dynamic than ever, and many new tools are being developed to manage them more successfully. New attention is needed for power system protection and control strategies based on the available technologies. Data sharing between IEDs offers the possibilities of a clear potential for better detection of a fault and for the improvement of protection security and reliability. To explore current technology utilization and chart the development of next-generation protection and control technologies, IEEE PSRC formed a working group, the purpose of which is to prepare a report describing and analyzing the latest technologies for the centralized protection and control within substations [1].
IEC 61850-based centralized protection has been widely studied over the past decade [2,3,4,5,6,7,8,9,10,11,12]. Synchronization of the data received from IEDs located in a substation is essential. Although Refs. [2,3,4] described methods of enhanced protection system performance using centralized data, synchronization was not addressed. References [5,6] used a GPS signal to maintain data synchronization. These suggested protection schemes worked well. Nevertheless, additional investment was required. Moreover, if the GPS signal is jammed, an inherent error can occur. The recent IEC/IEEE 61850-9-3 defined the IEEE Std 1588 PTP to increase the data synchronization precision [13]. The methods of Refs. [7,8,9,10,11,12] utilized this PTP to synchronize IED data precisely. However, the PTP is costly to implement and possible jamming problems remain in its master clock.
A Russian company developed a software-based substation PAC system, iSAS, which was under trial operation at the 110/10 kV ‘Olympic’ substation [14]. The philosophy of iSAS is based on PAC function element implementation with IEC 61850 LNs. The software modules were developed independently of a particular hardware and those could be placed in dedicated IEDs, as well as in one powerful computer.
Distance or over-current relays are normally used as a conventional back-up protection. The stepped setting rules of a distance relay can result in underreach or overreach because of the infeed fault current from other substations. To cope with this problem, the interest in the centralized protection continues to grow and several papers have proposed the centralized protection scheme.
These studies can generally be summarized into two categories. First, WP was studied in response to system-level faults and abnormal operating conditions. The other is SBP [5], which is usually applied in the IEC 61850-based smart substations [15,16].
Reference [6] proposes the development of a substation-area back-up protective relay for the smart substation. The authors presented a comprehensive study of IEC 61850-based SBP. The proposed SBP can decide the faulted apparatus accurately by using the current differential principle with the three-layer architecture. Test cases for major influence factors were also considered, such as ‘sensitivity to fault transition resistances’, ‘influences of inrush, current transformer saturation’, and ‘jitter in delay or losing of the sampled values’. However, the long-time data-loss situation was not considered, such as IED/CT fails. In addition, Ref. [6] was only verified in software simulations. Recently, papers on power system data transmission using wireless networks and the use of various cloud-based applications have also been published [17].
In this paper, multiple protection algorithms of the centralized back-up protection are proposed, such as a current differential protection element, distance-based directional protection element, and local back-up and remote back-up protection elements. IMU/CT fails are also considered. In the event of IMU/CT fails, the conventional relays have to stop the protection and control function because they could not perform their own protection tasks any longer. However, the proposed scheme can solve this problem. The local back-up protection element is usually termed the breaker failure protection. When a breaker failure occurs, it opens all the breakers at the local substation. In addition, if a breaker is not opened by the local back-up element, the remote back-up element suggested in this paper operates to open the breaker that is located at the adjacent substation connected directly with a transmission line. The concepts of IMU and CPCU are introduced in this paper. IMU is an abbreviation for ‘intelligent MU’, which is an IED that performs the functions of conventional P&C IED and MU. It performs the main protection using local data obtained from the CT/PT of the protected facility, and transmits the phasor of data obtained from the CT/PT to the CPCU. CPCU is an abbreviation for ‘centralized protection and control unit’, which receives local substation data from the IMUs protecting each protected facility and shares own substation data with the CPCUs of adjacent substations to perform wider area protection.
To evaluate the scheme proposed, HILS tests are carried-out with the testbed suggested in this paper. The testbed is built with three CPCUs, eleven IMUs, three grand-master-clocks, three network switches, and an RTDS. A 154/22.9 kV substation connected with two equivalent sources and four loads is modelled by using RSCAD. The target power system model actually consists of three substations and each substation has its own centralized protection system that is constructed with IEEE 1588 PTP-supported devices, such as the CPCU and IMUs. The IMU consists of ADS 8688 and TMDSIDK572X modules. It sends the voltage and current data to the CPCU, and it also operates as a main protective relay igniting an instantaneous trip signal. The CPCU performs protection using the IMUs’ data of the local substation, and the data from the CPCUs of the adjacent substations. All the data are sent as SV of IEC 61850. To implement the protection and communication functions of the IMUs, SPI, IPC, and MMS-EASE Lite library (SISCO, Inc., Sterling Heights, MI, USA) are used. Fault data for the various fault situations are simulated and acquired from the RTDS.

2. Centralized Multiple Back-Up Protection Schemes

This paper proposes a centralized multiple back-up protection scheme for a 154 kV substation as shown in Figure 1. The main idea of the centralized protection concept is to move the protection and control tasks from numerous bay-level devices to a single central protection and control unit, a CPCU. There is a CPCU at each substation, which receives the phasor voltage, current, and CB/DS status data from many IMUs at the local substation. Each IMU provides its main protection task with local voltage and current data and it sends the data to the CPCU with SV of IEC 61850. When the CPCU receives the data from the IMUs, it shares the data with other CPCUs located at the adjacent substations, and then the CPCU performs multiple back-up protection using those data. The IMU receiving a trip GOOSE from the CPCU ignites a trip signal to open a CB. This means that the IMU is also the BCU.
In other words, the centralized protection is provided by receiving data from multiple IMUs installed at the local substation and data from CPCUs installed at the adjacent substations. Reference [1] first introduced the concept of the IMU, which is an acronym for an intelligent merging unit. The IMU has the roles of a main protection device and a merging unit (MU). Thus, it provides the main protection task with local voltage, current, and CB/DS status data, and also sends them to the CPCU.
Because the back-up protection is normally slower than the main protection, frequent data exchange between a CPCP and an IMU at every sampling instant is not necessary. Therefore, it is recommended that voltage and current phasor data are exchanged between an IMU and a CPCU rather than instantaneous data for the centralized back-up protection. A relaying signal is sampled at an IMU and its phasor values are estimated. The main protection algorithm, such as current differential element, installed at the IMU is performed. The estimated phasor values are also transmitted to the CPCU as SV of IEC 61850 for the centralized back-up protection.
The computational burden of the CPCU is reduced because all the IMUs transmit phasor data instead of instantaneous sampled data. Figure 2 shows the functional blocks of a CPCU and IMU. The CPCU provides four protection functions, namely a current differential protection element, a distance-based directional comparison protection element, a local back-up protection element, and a remote back-up protection element.
Figure 3a shows that the current differential protection element requires the current data from both sides of the protected element, such as a transmission line, a power transformer, and a busbar. Figure 3b shows that the distance-based directional comparison protection element detects a fault at a transmission line with each piece of forward pick-up data from both sides of the transmission line. Each CPCU can calculate an apparent impedance of a faulted line with voltage and current data and can detect a forward fault with the operating zone of the distance protection element. Therefore, if the forward pick-up of the CPCU at the local substation occurs and the forward pick-up GOOSE message arrives from the CPCU at the adjacent substation, the local CPCU sends a trip GOOSE message to the IMU corresponding to the faulted transmission line. This directional comparison protection element is used only for transmission-line protection.
Figure 4 shows the block diagram of the local back-up protection function. The local back-up protection function is a countermeasure for circuit breaker (CB) failure. Although a trip signal is transmitted from a CPCU to a CB via an IMU, the corresponding CB cannot be opened because of a certain problem. Then, the local back-up protection element operates to open all the circuit breakers located at the same busbar to which the failed CB is connected. In this paper, a CB fail can be determined using the circuit breaker status data after the ignition of the trip order, i.e., if the CB is not opened during a setting time after the trip order, CB fail is detected.
Figure 5 shows the block diagram of the remote back-up protection function. The remote back-up protection function is a back-up protection for the local back-up protection function. Nevertheless, when the local back-up protection element operates, a CB that is different from the first failed one cannot be opened. At this time, the remote back-up protection element operates to open the CB located at the adjacent substation connected by the transmission line that has the second failed CB at the local substation. In other words, the CPCU of the local substation sends a transfer trip order to the CPCU of the adjacent substation. The setting time of the local back-up and remote back-up protection are set to 1 cycle.
The CPCU has a special function, termed IMU/CT fail detection. It operates very simply with the data of another IMU, which measures the data of the same spot (CTs located on both sides of the CB). Thus, the CPCU can determine CT failure by comparing the current data from CTs located on both sides of the CB. If IMU/CT fail occurs, the CPCU replaces the current data of the failed CT to the current data of the steady state CT using the algorithm in Ref. [18].
The IMU provides the main protection function (current differential element), CT saturation detection, and compensation function with local voltage and current data. The IMU collects current signals through a CT, and the CT consists of an iron core. When magnetic flux increases above the saturation point, the nonlinear characteristic, CT saturation occurs. Because of the CT saturation, the current signal is distorted, so that problems are caused in all the equipment that uses the CT for input signal. In particular, the protective relaying algorithm that calculates the phasor to detect a fault by using current signals can be affected. CT saturation may cause malfunction or delay the operation of the protective relay. Therefore, a countermeasure method against CT saturation is required and, this paper, to compensate for the distorted signals, is using the CT saturation compensation method proposed in Ref. [19]. Appendix A details the CT saturation compensation method. To detect the start and end of saturation in real-time, the algorithm uses the third difference function in Ref. [20].

3. Testbed Based on SV for Centralized Back-Up Protection Scheme

Figure 6 shows the testbed based on SV for the centralized back-up protection scheme.
Figure 6c shows that 11 IMUs are installed in each substation rack. Figure 6d shows that each IMU collects analogue voltage, current, and CB/DS status data from the RTDS via the analogue input terminal of each rack. The target system for the case studies is modelled with RSCAD. The GPS antenna is installed for the time synchronization of the grand master clocks, as shown in Figure 6a. All the IMUs and CPCUs perform PTP-based time synchronization to the grand master clock. Figure 6b shows the CPCU, which collects analogue voltage, current, and CB/DS status data from the IMUs. Figure 6e shows that PTP-based time synchronization and IEC 61850 SV-based data publish/subscribe are performed via ETHERNET (using CAT 7 model) cable.
CPCUs are implemented using ThinkSystem ST250 Xeon E-2146G 3.5 GHz of Lenovo, and Ubuntu 16.04 OS is installed.

3.1. Implementing IMU with Evaluation Modules

The IMU supports two functions, as mentioned before. One is the main protection function, while the other is the MU function. Figure 7 shows the IMU configuration diagram. Each shelf of the rack has two sets of IMUs, and each IMU set is implemented with TMDSIDK572X and ADS 8688 evaluation modules. TMDSIDK572X is a multiprocessor board from Texas Instruments, and the oscillator of the board is a normal crystal oscillator that has 30 ppm of clock accuracy at 20 MHz. The multiprocessor of TMDSIDK572X consists of ARM (Dual Cortex-A15 MP Core)/DSP (Two C66X DSP processors) cores. The LINUX PTP reference source code [21] was used to enable basic PTP functions. ADS 8688 is an ADC board, and Figure 5 shows that it supports the SPI protocol to transmit the ADC data to the DSP core of the TMDSIDK572X board. The sampling interval of ADS 8688 is set to 260.42 µs. When the DSP core of the TMDSIDK572X board receives the ADC data from ADS 8688, it estimates phasor data, then transmits that to the ARM core via the IPC protocol. Message queue is used for IPC. The ARM processor publishes the phasor data received over the IPC using SV.
In the TMDSIDK572X board, the current differential protection algorithm is implemented for main protection.

3.2. Data Exchange for Centralized Back-Up Protection with SV

The SV protocol is typically used to exchange voltage and current data for substation automation. The IEC 61850-9-2 LE defines an SV scheme that follows the guidelines published by the UCAIug [22].
The SV protocol, in conformance with IEC 61850-9-2 LE as summarized in Table 1, is dictated by a predefined dataset on the merging unit connected to the PT and CT, which produces instantaneously sampled data at a rate of 80 or 256 samples per cycle and transmits 8 samples per frame. For example, 80 samples per 60 Hz corresponds to a frame transmission interval of 1.67 ms, according to the number of ASDUs.
In this paper, since the centralized back-up protection uses the phasor data instead of the instantaneously sampled data defined in IEC 61850-9-2LE, the SV in conformance with IEC 61850-9-2 is used to exchange the phasor data. Thus, the sampling rate can be configured. The SV is set to publish every 1.04 ms, and the SmpRate is set to 64. The ‘No. of ASDU’ is set to four to publish the phasor data estimated from the instantaneous data measured at 260.42 µs intervals. Figure 8 shows that the oldest data are stored in ASDU1, while the second-oldest data are stored in ASDU2.

4. Performance Evaluation

4.1. Target System Modelling with RSCAD

Figure 9 shows the 154/22.9 kV power system modelled by RSCAD on which the performance of the centralized multiple back-up protection scheme proposed in this paper is evaluated for various faults. Table 2 shows the modeling parameters used in RSCAD. Substation A is fully modeled, but substation B and C are simply modeled for transmission line protection tests only.

4.2. Test Environment

Figure 10 illustrates the CPCU and IMU, which build up a centralized multi-back-up protection testbed to collect data about from which location in the target system to perform protection and control.
Four transmission lines, two busbars (for double bus), and two power transformers are being protected on the target system with eleven IMUs and three CPCUs. For busbar and power transformer protection, only the IMU data of the local substation are required, but the transmission line protection is carried out through data exchange between CPCUs because protection of the substation requires data from the adjacent substation. Each substation has one CPCU and one grand master clock, and all the devices on the testbed are time synchronized to the grand master clock based on IEEE 1588 PTP. The GOOSE messages from each CPCU are received through GTNET (Network card of RTDS). The voltage and current data of the target system are scaled down, and output via the RTDS front panel. However, to determine the effect of CT saturation, the RTDS is assigned to output the CT secondary side current.

4.3. Case Studies

In this paper, to evaluate the performance of the centralized multiple back-up protection algorithm, IMUs are set to not generate a GOOSE message for trip. All the graphs presented below in this paper represent the voltage, the current that RTDS outputs, and the received GOOSE messages from CPCUs as graphs plotted in RSCAD.

4.3.1. Test for Current Differential/Distance-Based Directional Protection Functions

To evaluate the performance of the current differential/distance-based directional protection functions of CPCU, A-phase to ground fault on #1 TL is simulated. Fault distance is 50% and the fault inception angle is 0°.
Figure 11 shows the results of the current differential/distance-based directional protection functions. All the graphs of Figure 11a–c presented below are the instantaneous voltage and current of the distributed measuring points of each substation, while the graphs of Figure 11d indicate the received GOOSE messages from each CPCU for trip. Since the fault occurs on #1 TL, #200 and #210 CBs should be opened to isolate the faulty facility. Figure 11 confirms that GOOSE message has been received from CPCU (Substation A) and CPCU (Substation B) to open #200 and #210 CBs, and that the CBs have opened, indicating that the faulted facility is isolated. In RTDS, the CB only opens when the current is zero-crossing, so the timing of the GOOSE message reception and the CB operation may look different.

4.3.2. Test for Local Back-Up Protection Function

To evaluate the performance of the local back-up protection function of CPCU, A-phase to ground fault on #1 TL is simulated. Fault distance is 50%, and the inception angle of fault is 0°; then the situation of CB fail is simulated to #200 CB.
Figure 12 shows the results of the local back-up protection functions. Since the transmission line protection elements of CPCU (Substations A and B) detected that the fault occurred on #1 TL, the GOOSE messages are received to open the #200 and #210 CBs. However, #200 CB was simulated to not open. Thus, the local back-up protection function of CPCU (Substation A) is operated with GOOSE messages of the differential/distance-based directional protection functions and the status of #200 CB to open all the CBs connected to the same busbar as the failed CB. Therefore, from Figure 12, GOOSE messages were received from CPCU (Substation A) to open the #100, #400, and #500 CBs.

4.3.3. Test for Remote Back-Up Protection Function

To evaluate the performance of the remote back-up protection function of CPCU, A-phase to ground fault on #1 TL is simulated. Fault distance is 50 % and the fault inception angle is 0°; then the situation of CB fail is simulated to the #200 and #500 CBs.
Figure 13 shows the results of the remote back-up protection function. GOOSE messages were received to open the #200 and #210 CBs because, as in Section 4.3.2, the fault occurred on #1TL. However, the #200 CB was not opened, so the local back-up protection function of CPCU (Substation A) was subsequently activated, transmitting GOOSE messages to open the #100, #400, and #500 CBs. However, #500 CB is also in an inoperative CB fail situation. Thus, the CPCU (Substation A) transmits a GOOSE message containing the remote back-up trip command to the CPCU (Substation C) located at an adjacent substation. Therefore, the CPCU (Substation C) that received the GOOSE message sends a GOOSE message to open #510 CB to the RTDS, and the RTDS receives it, verifying the adequacy of the remote back-up protection function.

4.3.4. Test for Performance of the CT Saturation Detection/Compensation Function

A fault on #1 TL is simulated to test the performance of the CT saturation detection/compensation function. To determine the effect of CT saturation, the RTDS output terminals that output the #1 TL current of the Substation A side are assigned to output the CT secondary side current.
Since the fault is an external fault for the busbar (A-2) protection element of CPCU (Substation A), it should not trip the CB. However, because the Substation A side CT of #1 TL is saturated, a differential current was detected in the busbar (A-2) protective current differential function of CPCU (Substation A). Thus, the GOOSE messages are received from the transmission line and busbar (A-2) protective elements to open the #100, #200, #210, #400, and #500 CBs connected to the busbar (A-2).
To prevent this malfunction caused by CT saturation, the CT saturation detection/compensation algorithm is required, and Figure 14e shows the results of applying the algorithm. From Figure 14e, the CT saturation detection/compensation algorithm is applied to confirm that the busbar (A-2) protective element does not malfunction.

4.3.5. Test for Performance of the IMU/CT Fail Detection Function

To evaluate the performance of the IMU/CT fail detection function of the CPCU, A-phase to ground fault on #1 TL is simulated. Fault distance is 50%, and the inception angle of the fault is 0°.
In this case, the situation of A-phase CT fail for the transmission line protection element was considered. To simulate this case, the A-phase current of CT for transmission line protection is made zero in the RSCAD, as shown in the #1 TL current of Figure 15a. Thus, the current phasor received by the transmission line protection element of the CPCU differs from the current phasor received by the busbar protection element, which results in the CPCU judging an IMU/CT fail. Therefore, CPCU (Substation A) trusts current phasors received from IMU (BUS A-2) and detects faults of #1 TL using the current phasors of IMU (BUS A-2) and the adjacent substation side current phasors received from CPCU (Substation B). The CT fail was accurately detected and, also with this scheme, the CPCU (Substation A) properly detected the fault.
Figure 16 shows the results of the current differential protection element for the conventional scheme and proposed scheme. As shown in the Figure 16a, since the IMU/CT fail is detected, the currents of #1 TL are not input into the protective function. The existing protection method means that, when detecting an IMU/CT fail, even if a differential current is detected, the protection function cannot be performed because the protection function is stopped or the circuit breaker operation element is blocked. However, the proposed scheme properly detected the fault using the current phasor received by the busbar protection element.

4.3.6. Test for GOOSE Transmission Delay

To test the GOOSE transmission delay, loop back delay time is calculated as shown in Figure 17.
The RTDS starts a timer at the moment GOOSE is transmitted, the CPCU transmits GOOSE as soon as it receives the GOOSE from the RTDS, and the RTDS stops the timer at the moment of receiving the GOOSE from the CPCU. Then the GOOSE transmission delay is computed dividing the loop back delay time by two. The above test has been tested 100 times, and the average GOOSE transmission time is 2.59 [ms]. The maximum delay of GOOSE messages for performance class P1 defined in IEC 61850-7-2 is 3 [ms], and the analysis result in this section shows that the proposed system meets the standard.

5. Conclusions

This paper suggests centralized multiple back-up protection schemes with the sharing of data between adjacent substations based on IEC 61850 to overcome the problem in the conventional back-up protection scheme. While the conventional back-up protection scheme uses only local data, the proposed schemes use all data obtained in a substation, so it is possible to accurately detect the location of a fault and provide continuous protection/control even in a CT/IED fail situation. The proposed schemes were verified using a test bed through interworking with a hardware-based system and RTDS. The phasor voltage/current data of the IMU are transferred to a CPCU. The CPCU performs multiple back-up protection functions by sharing phasor voltage/current data with the other CPCUs of adjacent substations. In this paper, to evaluate the schemes proposed, the HILS test was carried out. The testbed was built with IMU, grand master clock, network switch, RTDS, and CPCU. The IMU was implemented with TMDSIDK572X and ADS 8688 EVM modules. The target power system was modelled with RSCAD. All the CPCUs and IMUs were time synchronized, based on IEEE 1588 PTP. Since the proposed centralized multiple back-up protection schemes depend on CPCU, the CPCU system and network system must be redundant like PRP/HSR, and a sufficient review should be conducted by establishing a system in which the conventional protection schemes and the proposed schemes are applied together in the actual substation. The results of this research are expected to provide a good guide to constructing the future digital substation and centralized protection.

Author Contributions

Conceptualization, M.-S.K. and S.-H.K.; methodology, M.-S.K. and S.-H.K.; supervision, S.-H.K.; validation, M.-S.K.; writing—original draft, M.-S.K.; writing—review and editing, S.-H.K. All authors have read and agreed to the published version of the manuscript.

Funding

This research was also supported in part by the Korea Electric Power Corporation (Grant number: R17XA05-2).

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Data Availability Statement

Not applicable.

Conflicts of Interest

The authors declare that they have no conflict of interest.

Abbreviations

CPCUCentralized Protection and Control Unit
IMUIntelligent Merging Unit
IEDIntelligent Electronic Device
CTCurrent Transducer
PTPotential Transducer
PSRCPower System Relaying and control Committee
PTPPrecision Time Protocol
PACProtection, Automation, and Control
LNLogical Node
WPWide-area Protection
SBPSubstation-area Back-up Protection
HILSHardware In the Loop System
SVSampled Value
SPISerial Peripheral Interface
IPCInter Processor Communication
CBCircuit Breaker
DSDisconnection Switch
BCUBreaker Control Unit
ADCAnalog to Digital Conversion
LELight Edition
UCAIugUtility Communication Architecture International users group
ASDUApplication Service Data Unit
SmpRateSampling Rate

Appendix A

  • CT saturation compensation algorithm
Figure A1 shows a simplified equivalent circuit of a CT, where Lm is the magnetization inductance, R is the total secondary resistance, i1 is the primary current referred to the secondary, im is the magnetizing current, and i2 is the secondary current.
Energies 15 04195 g0a1 550
Figure A1. (a) Simplified equivalent circuit, and (b) Magnetization curve of a CT.
Figure A1. (a) Simplified equivalent circuit, and (b) Magnetization curve of a CT.
Energies 15 04195 g0a1
The relationship between i1(t), im(t), and i2(t) is:
i 2 ( t ) = i 1 ( t ) − i m ( t )
The core flux ϕ(t) is related to i2(t) by the expression:
N 2 d ϕ ( t ) d t = R i 2 ( t )
where N2 is the number of turns in the secondary winding. Integrating Equation (A2) from t0 to t yields:
N 2 ( ϕ ( t ) − ϕ ( t 0 ) ) = R ∫ t 0 t i 2 ( t ) d t
The core flux ϕ(t) is determined by the magnetization current im(t) according to the magnetizing curve as the dotted line shown in Figure A1b. Hence, Equation (A3) can be rewritten as:
L m ( i m ( t ) − i m ( t 0 ) ) = R ∫ t 0 t i 2 ( t ) d t
i m ( t ) = 1 L m ( R ∫ t 0 t i 2 ( t ) d t − i m ( t 0 ) )
Normally, the value of Lm is very large, when the iron core runs at a low magnetic flux, so the secondary current i2 can be nearly perfectly transformed from the primary current i1.
Assuming that a fault occurs at a time origin, and that the fault current signal consists of a dc offset and a fundamental frequency component, the primary current is expressed as:
i 1 ( t ) =   A 0 e − t / τ + A 1 sin ( w 0 t + φ 1 )
where τ and A0 are the time constant and the magnitude of a DC offset component, respectively, and A1 and φ1 are the amplitude and the phase angle of the fundamental frequency component, respectively.
With a large exponential component added to the primary current, the magnetic flux of the iron core easily reaches into the saturated region in which the value of Lm is very small. Thus, the magnetizing current im(t) will significantly increase and the secondary current will be distorted.
To simplify, the magnetizing curve in the saturated section is considered a straight line of slope L m s a t , as the solid line shown in Figure A1b. As the value of im(t0) is near zero before saturation, Equation (A5) can be rewritten as:
i m ( t ) = R L m s a t ∫ t 0 t i 2 ( t ) d t
By substituting Equations (A6) and (A7) into Equation (A1), the secondary current i2(t) during the CT saturation period can be rewritten as:
i 2 ( t ) =   A 0 e − t / τ + A 1 sin ( w 0 t + φ 1 ) − R L m s a t ∫ t 0 t i 2 ( t ) d t
The numerical approximation of the integral in Equation (A8) can be implemented using a trapezoidal method as follows:
∫ t t + Δ t i 2 ( t ) d t = Δ t 2 ( i 2 ( t ) + i 2 ( t + Δ t ) )
where ∆t is the sampling interval.
Expanding e − Δ t / τ using the Taylor series is possible, as follows:
e − Δ t τ = 1 − Δ t τ + 1 2 ! ( Δ t τ ) 2 − 1 3 ! ( Δ t τ ) 3 + ⋯
The discrete secondary current during the kth saturation period is expressed as:
i 2 ( n ) = a n 1 x 1 + a n 2 x 2 + a n 3 x 3 + a n 4 x 4 + a n 5 x 5 + a n 6 x 6   for   n S k < n < n E k
where
x 1 = A 0 ,   x 2 = − A 0 ( 1 / τ ) ,   x 3 = A 0 ( 1 / τ 2 )   x 4 = A 1 cos ϕ 1 ,   x 5 = A 1 sin ϕ 1   ,   x 6 = − R / L m s a t
a n 1 = 1 ,   a n 1 = n Δ t ,   a n 1 = ( n Δ t ) 2 / 2 , a n 1 = sin ( 2 π n / N ) ,   a n 1 = cos ( 2 π n / N ) ,   a n 1 = ∑ l = n S k + 1 n ( Δ t 2 ( i 2 [ l ] + i 2 [ l − 1 ] ) )
  • N: the number of samples per cycle
  • nSk and nEk: the start and end points of the kth saturation period
Figure A2 shows a typical current wave form for CT saturation, and nSk corresponds to t0 of Equation (A8).
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Figure A2. Typical current wave form for CT saturation.
Figure A2. Typical current wave form for CT saturation.
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Equation (A11) can be written in the matrix form, as follows:
I = A ⋅ X m × 1 m × 6 6 × 1
The elements of matrix A depend on the time reference and the sampling interval, which can be predetermined in off-line mode. Matrix I made up of the sampled current data during the CT saturation period is also known. If the number of current samples, m, is greater than the number of unknown variables, matrix X composed of the unknown variables can be determined using the least square technique, as follows:
X = [ A T ⋅ A ] − 1 ⋅ A T ⋅ I
Finally, the phasor of the fundamental frequency component can be obtained as Equation (A14):
x 4 ( n ) + j x 5 ( n ) = A 1 cos ϕ 1 + j A 1 sin ϕ 1

References

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Figure 1. Conceptual architecture of the proposed centralized multiple back-up protection scheme.
Figure 1. Conceptual architecture of the proposed centralized multiple back-up protection scheme.
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Figure 2. Functional blocks of CPCUs and IMUs.
Figure 2. Functional blocks of CPCUs and IMUs.
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Figure 3. Centralized multiple protection functions: (a) current differential function; and (b) distance-based directional comparison function.
Figure 3. Centralized multiple protection functions: (a) current differential function; and (b) distance-based directional comparison function.
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Figure 4. Centralized local back-up protection function.
Figure 4. Centralized local back-up protection function.
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Figure 5. Centralized remote back-up protection function.
Figure 5. Centralized remote back-up protection function.
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Figure 6. Testbed for the centralized multiple back-up protection scheme.
Figure 6. Testbed for the centralized multiple back-up protection scheme.
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Figure 7. IMU block diagram.
Figure 7. IMU block diagram.
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Figure 8. SV frame configuration diagram and publishing period.
Figure 8. SV frame configuration diagram and publishing period.
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Figure 9. Target system modelled in RSCAD.
Figure 9. Target system modelled in RSCAD.
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Figure 10. Centralized multiple back-up protection testbed block diagram of the target system.
Figure 10. Centralized multiple back-up protection testbed block diagram of the target system.
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Figure 11. Test results for the current differential/distance-based directional protection functions.
Figure 11. Test results for the current differential/distance-based directional protection functions.
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Figure 12. Test results for the local back-up protection functions.
Figure 12. Test results for the local back-up protection functions.
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Figure 13. Test results for remote back-up protection functions.
Figure 13. Test results for remote back-up protection functions.
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Figure 14. Test results for the CT saturation detection/compensation function.
Figure 14. Test results for the CT saturation detection/compensation function.
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Figure 15. Test results for the IMU/CT fail detection function.
Figure 15. Test results for the IMU/CT fail detection function.
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Figure 16. Current differential protection results for the IMU/CT fail detection function: (a) conventional scheme; and (b) proposed scheme.
Figure 16. Current differential protection results for the IMU/CT fail detection function: (a) conventional scheme; and (b) proposed scheme.
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Figure 17. Test environment for loop back delay time calculation.
Figure 17. Test environment for loop back delay time calculation.
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Table
Table 1. IEC 61850-9-2 LE summary.
Table 1. IEC 61850-9-2 LE summary.
Sampling rate80 samples per cycle (Protection & Metering)
256 samples per cycle (Power quality)
Dataset3 phase + neutral voltage
3 phase + neutral current
Table
Table 2. Target system parameters.
Table 2. Target system parameters.
CategoryData (%Z @100MVA Base)
SourceEq. 1R1 + jX10.0810 + j 0.8660
R0 + jX00.3840 + j 1.9560
Eq. 2R1 + jX10.2130 + j 1.5680
R0 + jX00.9390 + j 4.5810
Transmission
Line		#1 TL
#2 TL
25.99 km		R1 + jX10.4596 + j 3.6354
R0 + jX02.5145 + j 11.0173
Yj 2.979
#3 TL
#4 TL
2.58 km		R1 + jX10.0153 + j 0.1717
R0 + jX00.0520 + j 0.0682
Yj 4.918
Transformer#1 M.Tr
#2 M.Tr		Z1232.4812
Z1343.5124
Z2313.7513
LoadEach Load10 MVA
CT: 2000/5 A (Sat. Point: 2.047 A, 1.512 Vs)PT: 154 kV/110 V
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Kim, M.-S.; Kang, S.-H. Centralized Multiple Back-Up Protection Scheme with Sharing Data between Adjacent Substations Based on IEC 61850. Energies 2022, 15, 4195. https://0-doi-org.brum.beds.ac.uk/10.3390/en15124195

AMA Style

Kim M-S, Kang S-H. Centralized Multiple Back-Up Protection Scheme with Sharing Data between Adjacent Substations Based on IEC 61850. Energies. 2022; 15(12):4195. https://0-doi-org.brum.beds.ac.uk/10.3390/en15124195

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Kim, Min-Soo, and Sang-Hee Kang. 2022. "Centralized Multiple Back-Up Protection Scheme with Sharing Data between Adjacent Substations Based on IEC 61850" Energies 15, no. 12: 4195. https://0-doi-org.brum.beds.ac.uk/10.3390/en15124195

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