Numerical distance relays are digital realizations of proven electromechanical distance relay designs.
Voltage and current signals from the CCVT and CT secondary are input for a low-pass filter that removes
Figure11.29CaseStudy1:Detailedrepresentationofthe
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Figure 11.30 Case Study 1: Asymmetrical fault at NODE2A: (a) CCVT primary and secondary voltages, (b) CT primary and secondary currents, (c) relay angular displacement, (d) relay electromagnetic torque.
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Figure 11.31 Case Study 1: Asymmetrical fault at NODE1A: (a) CCVT primary and secondary voltages, (b) CT primary and secondary currents, (c) relay angular displacement, (d) relay electromagnetic torque.
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Figure 11.32 Case Study 1: Symmetrical fault at NODE1A: (a) CCVT primary and secondary voltages, (b) CT primary and secondary currents, (c) relay angular displacement, (d) relay electromagnetic torque.
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Figure 11.33 Case Study 1: Asymmetrical fault at BUS-2A: (a) CCVT primary and secondary voltages, (b) CT primary and secondary currents, (c) relay angular displacement, (d) relay electromagnetic torque.
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Figure 11.34 Case Study 1: Symmetrical fault at BUS-2A: (a) CCVT primary and secondary voltages, (b) CT primary and secondary currents, (c) relay angular displacement, (d) relay electromagnetic torque.
Figure 11.35 Case Study 2: Schematic representation of the distance relay and its interaction with the power system.
frequency content above 1/3 of the sampling frequency. The signal is then sampled by the ADC at a rate (which varies with the relay) of about 16–64 samples per power system cycle. The sampled data is then passed through a low-pass filter that removes the frequency content that is above the fundamental frequency. Most digital relays estimate amplitudes and phase angles of phasors using digital filters. This information is then used to detect abnormal operating conditions.
Numerical distance relays may be divided into three categories [12]:
1. generic relays that emulate their electromechanical or solid-state counterparts. – these relays imple- ment the amplitude or phase comparator equations after computing the voltage and current phasors.
2. relays that compute voltage and current phasors from the sampled and quantized data, and calculate the impedance from the voltage and current phasors and then use appropriate logic to arrive at a trip decision. The impedances as seen from the relay terminal are calculated from appropriate phasors.
3. relays that use voltage and current samples to estimate the impedance by fitting the parameters of the fault loop in the form of first-order differential equation – a number of numerical techniques can be used to replace the continuous-time differential equations at various instants into algebraic equations.
A set of these equations is then solved to estimate the impedance. These relays also use appropriate logic to make a trip decision.
The relays in the second and third categories generally use mho or quadrilateral type characteristics.
The relay model used in this study is based on a model originally developed by Institut de Recherche d’Hydro-Qu´ebec (IREQ) using a library of modules for protection studies [111]. The relay model organization is that presented in Figure 11.35: (1) the initial section filters input voltage and current signals, (2) the intermediate section detects fault conditions, and (3) the last section decides whether to trip or not the associated circuit breaker and when to reclose it. Users have to specify line parameters, protection zones and relay settings (i.e. opening and reclosing delays). For details on the implementation of mho distance relays in an EMTP-like tool, see [112].
Figure 11.36 shows the transmission system studied in this case. The study zone includes the 60 Hz 230 kV system equivalent, a power plant represented by a synchronous generator and its step-up trans- former, and the transmission line that delivers the energy generated by the power plant to the power
Figure 11.36 Case Study 2: Diagram of the test system.
system. The test system parameters are taken from the benchmark proposed by the IEEE PSRC Working Group [25].
The overall system model has been implemented in EMTP-RV as follows:
rThe two source sides (i.e. the left-side 230 kV equivalent system and the right-side power plant) are modelled using EMTP-RV capabilities; the equivalent system is represented by means an ideal three-phase voltage source plus its series impedance.
rThe transmission line is represented by a frequency-dependent distributed-parameter model and is divided into several sections to analyse the relay response against faults at internal nodes.
rThe transmission line is protected by two admittance mho-type distance relays located at its terminals.
There is no pilot communication between the two relays, which operate independently.
The main parameters are summarized below. For more details, see [25].
1. Left-side power system: It is a 60 Hz 230 kV transmission system in series with its equivalent impedance with the following parameters:
R0=2.70 X0=8.37Ω R1=R2=6.1 X1=X2=16.7Ω
2. Transmission line: The overall length is 65 miles. The line is divided into three sections with respective lengths of 30, 20 and 15 miles. The per unit length parameters (to be specified in the distance relay model) are:
R0=0.3627 X0=2.4379Ω∕mile R1=0.0955 X1=0.7599Ω∕mile
3. Power plant: It is represented by a synchronous generator and its step-up transformer. Ratings and parameters of both machines are:
rsynchronous generator: 24 kV, 830 MVA, two poles, solidly grounded
rstep-up transformer: 22.8/229.893 kV, 725 MVA,ΔYn.
4. Numerical distance relay: The selected settings of each relay are different. Figure 11.37 shows these settings:
rleft-side mho distance relay: Zone 2 covers the left-side 30 mile line section; Zone 1 reaches 50%
of this line section, while Zone 3 covers the entire line.
rright-side mho distance relay: Zone 2 covers the right-side 15 mile line section; Zone 1 also reaches 50% of this line section, while Zone 3 covers again the entire line.
Note that each relay has a reverse section that reaches the same percentage of the corresponding Zone 3.
Figure 11.37 Case Study 2: Protection zones of the test distance relays: (a) left-side mho relay, (b) right-side mho relay.
The operating times for faults located within the different zone are 0.001 s for Zone 1, 0.4 s for Zone 2 and 1.5 s for Zone 3. In case of a fault located at the reverse section, the selected time is 2.5 s. The relays will reclose 1.5 s after the opening action.
5. Instrument transformers: The ratios selected for CTs and CCVTs are:
rcurrent transformer (Figure 11.3): 2000/5 A.
rcoupling capacitor voltage transformer (Figure 11.13): 230 000/115 V.
All the simulation cases presented in this section correspond to a three-phase fault located within the transmission line. The operating conditions at the fault instant are also the same: the synchronous generator is injecting 500 MW, being the voltage at the machine terminals 24 kV.
Simulation results have been obtained following a gradual approach. In order to understand the relay responses to faults located close to each terminal of the transmission line, a first model was implemented without instrument transformers and circuit breakers; that is, the model will present the transient caused by a three-phase fault and the response of each distance relay. The second model includes instrument transformers and circuit breakers; the instant of the trip signal from each relay will depend on the fault location. A reclosing operation from each relay will take place 1.5 s after the first trip. The instant at which the fault starts, 0.5 s, the duration of the fault, 2 s and the time during which the system is simulated, 3 s, are the same in all studies. The variables plotted for each case are also the same.
A.System model without instrument transformers and circuit breakers– Figures 11.38 and 11.39 show some of the results when the fault is located 30 mile from the left line terminal and 15 miles from the right line terminal, respectively. Considering these two locations, the first fault is within Zone 1 of the left-side relay and Zone 2 of the right-side relay, while the second fault is within Zone 1 of the right-side relay and Zone 2 of the left-side relay.
From the plots shown in the two figures it is evident that the shape of the fault current at the line terminals are different. This is due to the different characteristic of the source impedances; at the left side, the 230 kV power system is represented by its 60 Hz equivalent impedance, while the impedance characteristic at the right side is that of a synchronous generator. Note also that the fault current level seen by each relay is different, being higher at the right side.
The relay responses shown in plots (c) and (g) are correct; that is for a fault located 30 miles from the left terminal the relay located at this terminal reacts first (Figure 11.38(c)), while for a fault located 15 miles from the right terminal, the first trip signal is sent by the relay located at this terminal – see Figure 11.39(g).
An interesting result from this study is the variation of the admittance seen by each relay phase during the simulation of both faults. Remember that before the fault the power is flowing from the power plant
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Figure 11.38 Case Study 2: Simulation results with a three-phase fault at 30 miles from the left line terminal – Without instrument transformers and circuit breakers: (a) left-side line terminal voltages, (b) left-side line terminal currents, (c) left-side mho relay trip and reclosing signals, (d) impedance path measured by the left-side mho relay, (e) right-side line terminal voltages, (f) right-side line terminal currents, (g) right-side mho relay trip and reclosing signals, (h) impedance path measured by the right-side mho relay.
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Figure 11.38 (Continued)
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Figure 11.39 Case Study 2: Simulation results with a three-phase fault at 15 miles from the right line terminal – Without instrument transformers and circuit breakers: (a) left-side line terminal voltages, (b) left-side line terminal currents, (c) left-side mho relay trip and reclosing signals, (d) impedance path measured by the left-side mho relay, (e) right-side line terminal voltages, (f) right-side line terminal currents, (g) right-side mho relay trip and reclosing signals, (h) impedance path measured by the right-side mho relay.
(right side) to the power system (left side), so the direction of the current measured by each relay will be different: positive at the right side, negative at the left side. However, during the fault condition, the direction of the fault current measured by each relay is positive. After an initial interval, the admittances seen by the left relay pass to the left side of the circles and move to within the circle corresponding to Zone 2 and Zone 3, respectively, during the fault condition. The admittances seen by the right relay remain always at the right side of the circles and move to within the circle of Zone 3 and Zone 2, respectively, during the fault condition.
B.System model with instrument transformers and circuit breakers– With this model the trip signals will cause the opening of the circuit breakers and their reclosing after the corresponding reclose intervals.
Figures 11.40 and 11.41 show some of the results derived for the same fault locations.
We can see that for a fault closer to the left line terminal, the left-side circuit breaker opens first;
the opening of the right-side breaker caused by the trip signal of the right-side relay comes after. When
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Figure 11.39 (Continued)
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Figure 11.39 (Continued)
the left-side circuit breaker recloses, the fault condition has disappeared. This sequence of events is supported by the trip signals shown in Figures 11.40(c) and 11.40(g).
For a fault closer to the right line terminal, the right-side circuit breaker opens first, and it is followed by the opening of the right-side breaker. In this case, the right-side circuit breaker also recloses first. As for the previous case, the sequence of events is supported by the trip signals shown in Figures 11.41(c) and 11.41(g).
The plots showing the variation of the admittances seen by each relay exhibit some differences with respect to the same plots derived from the previous study. This is due to the fact that this time there is a closed-loop interaction between the relays and the system: the trip signals generated by the relays open the corresponding circuit breakers; therefore, the currents seen by each relay drop to zero and then reclose, so the currents recover their values. In fact, the variation of the admittances depicted by each plot is similar to those in the previous case until the corresponding circuit breaker opens.
The relay response depends on the inputs from the instrument transformers. Aspects to be considered are the waveform of the voltage and current inputs (e.g. peak values or decay), and the distortion introduced by CTs and CCVTs. Among the parameters that can affect this performance we need to consider the selected instrument transformers, relay burdens and the point-of-wave with which the fault transient is initiated. Some examples were presented in the first case study. For the case simulated here, the distortion introduced by instrument transformers is very small and only takes place during a few cycles of the fault currents seen by the right-side relay when the fault location is close to the right line terminal.
From the previous simulation results, it is evident that for an internal transmission line fault the highest peak current values are seen by the instrument transformers located at the right side terminal of the line.
On the other hand, given that only three-phase faults are being simulated, at least one asymmetrical fault current should be expected.
Two parameters have been varied to further investigate the performance of the protection model implemented for this case study: the fault resistance, which will affect the peak value of the fault
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Figure 11.40 Case Study 2: Simulation results with a three-phase fault at 30 miles from the left line terminal – With instrument transformers and circuit breakers: (a) left-side line terminal voltages, (b) left-side line terminal currents, (c) left-side mho relay trip and reclosing signals, (d) impedance path measured by the left-side mho relay (voltages and currents measured at the secondary of instrument transformers), (e) right-side line terminal voltages, (f) right-side line terminal currents, (g) right-side mho relay trip and reclosing signals, (h) impedance path measured by the right-side mho relay (voltages and currents measured at the secondary of instrument transformers).
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Figure 11.40 (Continued)
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Figure 11.41 Case Study 2: Simulation results with a three-phase fault at 15 miles from the right line terminal – With instrument transformers and circuit breakers: (a) left-side line terminal voltages, (b) left-side line terminal currents, (c) left-side mho relay trip and reclosing signals, (d) impedance path measured by the left-side mho relay (voltages and currents measured at the secondary of instrument transformers), (e) right-side line terminal voltages, (f) right-side line terminal currents, (g) right-side mho relay trip and reclosing signals, (h) impedance path measured by the right-side mho relay (voltages and currents measured at the secondary of instrument transformers).
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Figure 11.41 (Continued)
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Figure 11.42 Case Study 2: CT currents seen by the right-side distance relay with a three-phase fault at 15 miles from the right line terminal – The secondary current of the CT has been reduced to the primary side. Fault resistance=5Ω. (a) CT burden=4Ω, (b) CT burden=20Ω.
currents, and the CT burden, which can affect the CT performance. Figures 11.42 and 11.43 show some of the simulation results.
Figure 11.42 shows some results obtained with the same fault resistance value that in the previous cases (i.e. 5Ω) and two different CT burdens: 4 and 20Ω. The peak values are the same in both cases and some distortion is introduced by the CT saturation into the secondary current; in both cases the relay response is correct and the trip signals are sent to the circuit breaker at the correct instant.
Figure 11.43 shows some results obtained with a lower fault resistance value (i.e. 1Ω) and the same CT burdens (i.e. 4 and 20Ω). We can see that the peak values are the same in both cases, and a significant distortion is introduced by the CT saturation into the secondary current. As expected, the peak current values are higher than in the previous example. In both cases the relay response is advanced and the trip signals are sent to the circuit breaker rather quickly. The simulation results presented in the figure were obtained by decreasing the relay setting for Zone 1 in order to obtain the same relay response as in the previous example.
For a single-phase-to-ground fault, the waveforms of transient currents on the faulted phase are similar to those derived with a three-phase fault, but the peak values are not very affected by the fault resistance. That is, the distortion introduced by the CT increases with its burden resistance, but the peak value of the transient current is basically the same with fault resistance of both 5Ωand 1 Ω.
Consequently, the relay response was always correct and was not affected by the fault resistance or the CT burden.
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Figure 11.43 Case Study 2: CT currents seen by the right-side distance relay with a three-phase fault at 15 miles from the right line terminal – The secondary current of the CT has been reduced to the primary side. Fault resistance=1Ω. (a) CT burden=4Ω, (b) CT burden=20Ω.