CURRENT ACTUATED RELAYS

A) FUSES

The most commonly used protective device in a distribution circuit is the fuse. Fuse characteristics vary considerably from one manufacturer to another and the specifics must be obtained from their appropriate literature. Figure 9.28 shows the time-current characteristics which consist of the minimum melt and total clearing curves.

FIGURE 9.28 Fuse time-current characteristic.

Minimum melt is the time between initiation of a current large enough to cause the current responsive element to melt and the instant when arcing occurs. Total Clearing Time (TCT) is the total time elapsing from the beginning of an over-current to the final circuit interruption;

i.e., TCT = minimum melt plus arcing time.

In addition to the different melting curves, fuses have different load-carrying capabilities. Manufacturer’s application tables show three load-current values: continuous, hot-load pickup, and cold-load pickup. Continuous load is the maximum current that is expected for three hours or more for which the fuse will not be damaged. Hot-load is the amount that can be carried continuously, interrupted, and immediately reenergized without melting. Cold-load follows a 30-min outage and is the high current that is the result in the loss of diversity when service is restored. Since the fuse will also cool down during this period, the cold-load pickup and the hot-load pickup may approach similar values.

B) INVERSE-TIME DELAY OVER-CURRENT RELAYS

The principal application of time-delay over-current relays (TDOC) is on a radial system where they provide both phase and ground protection. A basic complement of relays would be two phase and one ground relay. This arrangement will protect the line for all combinations of phase and ground faults using the minimum number of relays. Adding a third phase relay, however, provides complete backup protection, that is two relays for every type of fault, and is the preferred practice. TDOC relays are usually used in industrial systems and on sub-transmission lines that cannot justify more expensive protection such as distance or pilot relays.

There are two settings that must be applied to all TDOC relays: the pickup and the time delay. The pickup setting is selected so that the relay will operate for all short circuits in the line section for which it is to provide protection. This will require margins above the maximum load current, usually twice the expected value, and below the minimum fault current, usually 1/3 the calculated phase-to-phase or phase-to-ground fault current. If possible, this setting should also provide backup for an adjacent line section or adjoining equipment. The time-delay function is an independent parameter that is obtained in a variety of ways, either the setting of an induction disk lever or an external timer. The purpose of the time-delay is to enable relays to coordinate with each other. Figure 9.29 shows the family of curves of a single TDOC model. The ordinate is time in milliseconds or seconds depending on the relay type; the abscissa is in multiples of pickup to normalize the curve for all fault current values. Figure 9.30 shows how TDOC relays on a radial line coordinate with each other.

FIGURE 9.29 Family of TDOC time-current characteristics.

FIGURE 9.30 Coordination of TDOC relays.

C) INSTANTANEOUS OVER-CURRENT RELAYS

Figure 9.30 also shows why the TDOC relay cannot be used without additional help. The closer the fault is to the source, the greater the fault current magnitude, yet the longer the tripping time. The addition of an instantaneous over-current relay makes this system of protection viable. If an instantaneous relay can be set to “see” almost up to, but not including, the next bus, all of the fault clearing times can be lowered as shown in Fig. 9.31. In order to properly apply the instantaneous over-current relay, there must be a substantial reduction in short-circuit current as the fault moves from the relay toward the far end of the line. However, there still must be enough of a difference in the fault current between the near and far end faults to allow a setting for the near end faults. This will prevent the relay from operating for faults beyond the end of the line and still provide high-speed protection for an appreciable portion of the line.

FIGURE 9.31 Effect of instantaneous relays.

Since the instantaneous relay must not see beyond its own line section, the values for which it must be set are very much higher than even emergency loads. It is common to set an instantaneous relay about 125–130% above the maximum value that the relay will see under normal operating situations and about 90% of the minimum value for which the relay should operate.

D) DIRECTIONAL OVER-CURRENT RELAYS

Directional over-current relaying is necessary for multiple source circuits when it is essential to limit tripping for faults in only one direction. If the same magnitude of fault current could flow in either direction at the relay location, coordination cannot be achieved with the relays in front of, and, for the same fault, the relays behind the non-directional relay, except in very unusual system configurations.

POLARIZING QUANTITIES: To achieve directionality, relays require two inputs; the operating current and a reference, or polarizing, quantity that does not change with fault location. For phase relays, the polarizing quantity is almost always the system voltage at the relay location. For ground directional indication, the zero-sequence voltage (3E₀) can be used. The magnitude of 3E₀ varies with the fault location and may not be adequate in some instances. An alternative and generally preferred method of obtaining a directional reference is to use the current in the neutral of a Wye-grounded/delta power transformer.

E) DISTANCE RELAYS

Distance relays respond to the voltage and current, i.e., the impedance, at the relay location. The impedance per mile is fairly constant so these relays respond to the distance between the relay location and the fault location. As the power systems become more complex and the fault current varies with changes in generation and system configuration, directional over-current relays become difficult to apply and to set for all contingencies, whereas the distance relay setting is constant for a wide variety of changes external to the protected line.

There are three general distance relay types as shown in Fig. 9.32. Each is distinguished by its application and its operating characteristic.

FIGURE 9.32 Distance relay characteristics.

a) IMPEDANCE RELAY

The impedance relay has a circular characteristic centered at the origin of the R-X diagram. It is non-directional and is used primarily as a fault detector.

b) ADMITTANCE RELAY

The admittance relay is the most commonly used distance relay. It is the tripping relay in pilot schemes and as the backup relay in step distance schemes. Its characteristic passes through the origin of the R-X diagram and is therefore directional. In the electromechanical design it is circular, and in the solid state design, it can be shaped to correspond to the transmission line impedance.

c) REACTANCE RELAY

The reactance relay is a straight-line characteristic that responds only to the reactance of the protected line. It is non-directional and is used to supplement the admittance relay as a tripping relay to make the overall protection independent of resistance. It is particularly useful on short lines where the fault arc resistance is the same order of magnitude as the line length.

Figure 9.33 shows a three-zone step distance relaying scheme that provides instantaneous protection over 80–90% of the protected line section (Zone 1) and time-delayed protection over the remainder of the line (Zone 2) plus backup protection over the adjacent line section. Zone 3 also provides backup protection for adjacent lines sections.

FIGURE 9.33 Three-zone step distance relaying to protect 100% of a line and backup the neighboring line.

In a three-phase power system, 10 types of faults are possible: three single phase-to-ground, three phase-to-phase, three double phase-to-ground, and one three-phase fault. It is essential that the relays provided have the same setting regardless of the type of fault. This is possible if the relays are connected to respond to delta voltages and currents. In general, for a multiphase fault between phases x and y,

In a three-phase power system, 10 types of faults are possible: three single phase-to-ground, three phase-to-phase, three double phase-to-ground, and one three-phase fault. It is essential that the relays provided have the same setting regardless of the type of fault. This is possible if the relays are connected to respond to delta voltages and currents. In general, for a multiphase fault between phases x and y,

Where m is a constant depending on the line impedances, and I₀ is the zero sequence current in the transmission line. A full complement of relays consists of three phase distance relays and three ground distance relays. This is the preferred protective scheme for high voltage and extra high voltage systems.