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PredictiveOut-of-Step Protection and Control Scheme Based on Real-Time Phasor Measurement Application By Alla Deronja, P.E. Senior System Protection Engineer American Transmission Company Milwaukee, Wisconsin
This presentation is focused on demonstration of applying the concept of real-time measurements in a transmission system to perform system protection and control functions in a predictive - or adaptive - manner to account for the system operating conditions at any time. Objectives: • Real-time measurements and adaptive/predictive protection. • Predictive out-of-step protection scheme based on real-time measurements. • Practical application.
As a system protection engineer, I am interested in applying real-time phasor measurement technology to perform system protection, control and tripping functions to achieve a protection system’s adaptability to account for all possible system operating conditions.
The concept of adaptive relaying is that many relay settings are dependent upon assumed conditions in the power system. In order to cover all possible scenarios that the protection system may have to face, the actual protection settings are often not optimal for any particular system state. If an optimal setting is desired for an existing condition on the power system network, then it becomes necessary for the setting to adapt itself to the real-time system states as the system conditions vary due to changing loads, network switching operations, or faults.
A number of relaying functions are predicated upon an assumed pattern of power system behavior during transient stability oscillations and other dynamic conditions. An example of such functions is out-of-step protection. A predictive out-of-step protection and control scheme based on the real-time phasor measurement principle that has inspired me to pursue my project proposal has been already in operation for almost 20 years.
TOKYO ELECTRIC’S PREDICTIVE OUT-OF-STEP PROTECTION SYSTEM The predictive out-of-step protection system by means of observing phase differences between power centers and based on the real–time phasor measurement principle similar to the one I sought to install at my company has been installed and successfully operated by Tokyo Electric Power Company (TEPCO, Japan) since February, 1989.
The bulk power system of TEPCO in presented in Fig. 1. A major characteristic of this power system is that the power generation areas are far from the consumption areas. The eastern, northern, and southeastern generator groups are linked by a bulk power system comprising 500 kV double-circuit transmission lines configured in duplex and triplex routes and forming a “trunk”. The western generator group and large local loads are thus linked to the bulk power system via the substations marked as A1 and A2 in Fig. 1.
The western generator group tends to be heavily loaded, and its own capacity cannot meet demand. Power is received from the bulk power system to make up the deficiency. When a double fault occurs along both circuits of a double-circuit line forming one route, the substations at both ends of the line are disconnected and transmission capability is interrupted. If a successive fault occurs after reclosing, a slow cyclic power swing develops between the western generator group and the bulk power system.
The same situation occurs in the event of failure of a bus-bar protective relay to operate during a bus-bar fault. Over time, the phase difference of the generator groups thus undergoes oscillating divergence. If this condition is not corrected, an out-of-step condition will begin to occur in various parts of the power system and may lead to its total collapse.
In order to maintain the reliability of the power system should such serious rare faults occur, a predictive protection system that prevents total collapse of the power system has been developed. This protection system utilizes online data collected before and after the onset of a system disturbance to determine the characteristics of the power swing and predict an out-of-step condition. The system operates during the incubation period so that appropriate control can be performed before the out-of-step condition occurs.
The western area can be islanded (Fig. 2) from the bulk power system at points (a) or (b) and (a’) or (b’) before out-of-step occurs and then operated independently. This eliminates power swing between the generator groups of the two systems and restores stability. The separation point is selected based on the power flow at pre-determined points for separation before the fault.
FIGURE 2. SIMPLIFIED MODEL OF TRUNK LINE AND GENERATORS
The protection scheme is outlined in Fig. 3. The status of each generator group (east, north, southeast, west) is obtained by measuring the bus-bar voltages of neighboring substations as representative values. From these, the phase differences between the western generator group and the bulk power system are obtained. From the phase difference values, the corresponding values for 200 ms in the future are predicted. If the latter exceed the setting value (limit), the respective generator groups are judged to be unstable.
The two out of three logic is employed to judge instability of all the groups and to prevent unwanted operation in the event of an out-of-step of one generator group within the bulk power system. In order to initiate system separation, the current swing detection element must operate based on the current flowing through the transformers of the linkage substations A1 and A2 between the bulk power system and the western area (Fig. 1).
When the two out of three generator groups have been determined to be unstable and the current swing detection element has operated, the islanding command is issued from the Central Equipment to the separation point. The trip command is executed if the current swing detection element in the RTU has operated on the current flowing through that point. The current swing detection element is provided as a fail-safe measure for the protection calculation based on phase difference.
To achieve flexibility in dealing with various operating conditions of the western area, the present protection system is divided into completely separate duplex systems: System 1 and System 2. System 1 handles separation at points (a) and (b) in Fig. 2, and System 2 – at points (a’) and (b’). System 2 is nearly identical to System 1 so that System 1 will be only described.
System 1 comprises a Central Equipment (Phasor Data Concentrator) at Substation A1 and Remote Terminal Units – RTUs (Phasor Measurement Units – PMUs) at Substations B1, C, D, and E (Fig. 4). The RTUs simultaneously sample bus-bar voltages at 600 Hz. The sampled real-time data is transmitted to the Central Equipment (CE) via the data transmission system (a communication channel). In addition, the current flowing through the system separation point (b) at Substation B1 is measured; then, the power flow value is calculated and transmitted to the CE.
FIGURE 4. BASIC CONFIGURATION OF SYSTEM 1 PROTECTION SYSTEM
At substation A1, the current and power flow values through the system separation point (a) and through the transformer are measured. The CE calculates the real-time phase difference and predicted future phase difference and selects the system separation point using this online data. The circuit breaker command is issued for either point (a) or (b) as selected by the CE calculation on the measured data.
The entire system configuration is presented in Fig. 5. All devices are based on 16-bit microprocessors. The microprocessor has data transmission, self-diagnostic and calculating functions provided by the CE. Data transmission between the CE and RTUs is carried out synchronously via a duplex digital microwave link. The data transmission speed of this system is 56 kbps.
FIGURE 5. OVERALL CONFIGURATION OF PROTECTION SYSTEM
The data from one RTU of the C, D, and E substations is sent to both CE of the same system via the data transmission system. Each CE receives the data for both RTUs of each generator group, but only one set of data is normally employed. If an abnormality occurs, the CE can switch to the other RTUs’ data. The purpose of this two-fold redundancy is to decrease system downtime since long-distance transmission with multiple spans is employed.
The method of obtaining the phase difference between two points (western generator group and bulk power system) from simultaneously sampled voltage data is as follows. In Fig. 6, representative voltage waveform sampling values for a bus-bar in the vicinity of the northern generator group (C in Fig. 6) and the western generator group (B in Fig. 6) are shown.
FIGURE 6. EXAMPLE OF VOLTAGE WAVEFORM SAMPLING DATA FOR TWO SUBSTATIONS
The phase difference, n, at present time n can be obtained from the voltage data VBn, VBn-3, VCn, and VCn-3 for the present time and three previous samples as follows:
Thus, In order to simplify the calculation by replacing X = Xi with a first-order approximation obtained via Taylor Series, the phase difference can be obtained by where 0 X 1
If X 1, the following additional equation is used to perform the calculation. If X 0, the following additional equation is used to perform the calculation. Since the approximation error is on the order of 10-2, accuracy is sufficient for practical use.
The phase difference between the two areas can be approximated by the following equation. where, 0 is initial value of phase difference , is angular frequency of , is damping constant, A is amplitude. This equation interprets the power swing mode as a sine wave that diverges or converges.
Using the phase difference values for the present time and previous time, the future phase difference value can be predicted. The predicted phase difference * for time TH in the future is derived from eight pieces of data (Fig. 7) and calculated as follows:
FIGURE 7. METHOD OF PREDICTING PHASE DIFFERENCE
Values of 200 ms and 100 ms were selected for TH and TK (a time interval before the present time in Fig. 7), respectively, in order to predict accurately and to provide an acceptable operating time. A simulation of the present prediction algorithm calculation is given in Fig. 8. The results agree well with the present phase difference value and the predicted future value at 200 ms.
FIGURE 8. SAMPLE CALCULATION OF PHASE DIFFERENCE
When the obtained predicted phase difference value * exceeds the setting value limit, it is judged that the power swing between the two generator groups is unstable. The value for limit is determined by computer simulation under varying conditions and must guarantee operation when the system is unstable and prevent operation when the system is stable. The table in Fig. 9 shows the results of computer simulation for several system operating patterns. limit is set to 100.
In order to guarantee fail-safe operation of the scheme, an input different from the voltage input, the current input, is used to detect the swing. Its logic shown in Fig. 10 comprises a rate of change detection block to determine whether power swing is present and a magnitude of change detection block to detect the size of the current fluctuation. The element operates on the AND of these two blocks.
The operation of the current swing detector is presented in Fig. 11. The magnitude of change detection block operates when the measured current fluctuation magnitude is greater than its sensitivity setting ISET during maximum power swing period Tmax. The values for ISET and Tmax are determined by computer simulation, and ISET is set for Tmax=3 sec.
The element detects when the slope of the difference of the r.m.s. current value during the small interval t (I/t) is greater than constant K and continues longer than operation delay time T1 in order to operate when the size of the current swing is greater than ISET during a sine wave that is smaller than Tmax. To prevent dropout in the vicinity of extreme values of the sine wave, the OFF delay timer T2 (reset delay) is set to 1 sec when t=40 ms and T1=200 ms.
A computer simulation was run for a double three- phase-to-ground fault of a double circuit transmission line (1 route) in the “trunk” with a subsequent failure of three-pole reclosing with synchronism check. The results are presented in Fig. 12. The power swing has a tendency toward divergence without a protection system (Fig. 12a). In this case, out-of-step is likely after 10 sec, and this process would continue to extend and eventually cause a conventional out-of-step relay to operate and separate the western area after about 13.5 sec.
Even after separation, the power swing would also continue in the bulk power system. In contrast, when the protection system is employed as shown in Fig. 12b, the western area is separated after 6.6 sec, and the power swing of the bulk power system starts to converge. The western area is then operated independently, and another control system such as under-frequency load shedding adjusts the power supply and demand balance.
The present protection system also underwent a field test. The power system configuration and test results are presented in Fig. 13. A circuit breaker at point (c) is being closed to configure the western power system as a loop system.The predicted and measured phase difference values were observed. The predicted phase difference values before and after closing of the circuit breaker agreed well with the measured values.
FIGURE 13. CONTENT AND RESULTS OF FIELD TEST b) Example of phase difference swing detection
EXAMPLE OF OUT-OF-STEP PROTECTION SCHEME POSSIBLE UPGRADE UTILIZING SYNCHROPHASOR MEASUREMENTS The company I am representing - American Transmission Company - utilizes an out-of-step protection scheme, which I sought to upgrade to make it adaptive - or predictive - using the real-time synchrophasor measurement principle and newest hardware available.
The existing ATC Northern transmission system has limited power transfer capabilities from Michigan’s Upper Peninsula (UP) generation to a key bulk power transmission substation due to its inadequate transmission and generation infrastructure. Several completed major projects have improved the system. However, it remains weak and still requires the use of a special protection scheme to block unstable power swings by tripping UP generation for critical faults on the transmission system.
Two pairs of power swing relays SEL-68 are installed at the key bulk power transmission substation to backup the UP generation’s SPS operations. Each pair is installed to trip in series for redundancy to prevent a misoperation should one of the relays fail. The power swing relays are time-delayed to allow operation of the primary SPS. If the primary SPS fails to operate, the power swing relays are designed to separate the ATC power system into two islands: the UP and the Wisconsin bulk power system.
For unstable power swings to the south of the key bulk power transmission substation caused by an excess of the UP generation, one pair of the SEL-68 relays will trip the three southern lines of the power transmission corridor. For unstable power swings to the north of the substation caused by a deficiency of the UP generation, the second pair of the SEL-68 relays will trip the three northern lines of the power transmission corridor.