OVERCURRENT PROTECTION COORDINATION BASIC INFORMATION

WHY WE DO OVERCURRENT PROTECTION COORDINATION?

The objectives of overcurrent coordination are to determine the characteristics, ratings, and settings of overcurrent protective devices that minimize equipment damage and interrupt short circuits as rapidly as possible. These devices are generally applied so that upon a fault or overload condition, only a minimum portion of the power system is interrupted.

An overcurrent coordination study is the comparison and selection of operating times of the protective devices that achieve the objectives of the protection system under abnormal system conditions. This study should include all devices from the utilization equipment to the source.

A coordination study also provides data useful for the selection of
—Instrument transformer ratios
—Protective relay characteristics and settings
—Fuse characteristics and ratings
—Low-voltage circuit breaker ratings, characteristics, and settings

It also provides other information pertinent to the provision of optimum protection and selectivity in the coordination of these devices. In new installations, electrical equipment ratings often change prior to plant startup, but after protective devices have been ordered. These changes should be anticipated when selecting protective devices so that the device characteristics are sufficiently flexible to protect the individual load or branch circuit.

A preliminary coordination study should be made during the early stages of a new system design to verify that the protective device ratings can be selective and that the source utility’s protection practices have been considered. The protective device settings should be determined after the design has been completed and all load and fault currents have been calculated.

Protective devices are applied to a power system as primary and backup protection. Primary protection is the first line of defense against further damage caused by a fault or other abnormal operating condition. These devices are generally set to operate faster and remove less of the power system from service than backup protection.

Backup protection takes over when the primary protection fails to clear the abnormal condition. Backup protective devices and settings are selected to operate at some predetermined time interval after the primary device operates.

Thus, a backup device should be able to withstand the fault conditions for a greater time period than the primary protective device. For most applications, the operation of the backup device isolates circuits in addition to the faulted or overloaded circuit. Therefore, a greater portion of the power system is interrupted with backup protection.

In applying protective devices, it is occasionally necessary to compromise between protection and selectivity. While experience may suggest one alternative over another, the preferred approach is to favor protection over selectivity. Which choice is made, however, is dependent on the equipment damage and the affect on the process.

In existing facilities, system configurations and operating conditions often change. A new coordination study should be performed when the available short-circuit current to a plant changes or when significant changes in plant loading occur. This study determines the ratings or settings necessary to ensure that selectivity and protection are maintained after system changes occur.

A coordination study should definitely be performed when a fault on the periphery of an existing plant unexpectedly shuts down a major portion of the system. Such an event may indicate a need to change or reset devices.

EFFECTS OF CURRENT TRANSFORMER SATURATION ON OVERCURRENT PROTECTION COORDINATION

The function of a CT is to produce a secondary current that is proportional in magnitude and in phase with the primary current. This secondary current is applied to protective relays of compatible range and load (or burden) characteristics.

When CTs are operated at or near the knee of their excitation curve, small increases in current magnitude can cause the flux density to increase substantially and cause saturation. When saturation occurs, the secondary current wave shape becomes distorted, and the signal to the protective relays is no longer proportional to the current input.

In some cases of severe saturation, the output current of the secondary could be near zero on one or more phases. Depending on the level of distortion of the secondary waveform and the design of the relay, the operation can be affected.

For electromechanical induction disk relays, the effect of CT saturation is to slow the rotational speed of the disk. When the CT becomes saturated, the actual secondary relay current is less than it should be, its wave shape is distorted, and the relay operates more slowly. This condition leads to longer trip times and possible miscoordination.

Saturation can occur in CTs used to measure low-voltage ground-fault current, especially in underdesigned core-balance CTs in backup ground-fault relay applications. Saturation has also occurred in the solid-state low-voltage trip devices that use current sensors (which should not be confused with CTs, except for the fact that they reduce phase currents to a value compatible with their devices electronic circuitry).

These current sensors form a residual circuit for the measurement of ground-fault current. Normal equipment-starting current or downstream phase faults may produce an unbalanced current that can cause a false groundfault current trip.

In most industrial systems, CT saturation is significant only in circuits with relatively low ratio CTs and high magnitude fault currents. In most cases, these circuits feed utilization equipment; therefore, relays with instantaneous settings below the CT saturation point can be applied.

As one progresses back toward the source, the CT ratios get larger at the same voltage level. Also, the CTs have more turns; develop higher voltages; and, therefore, are less likely to saturate when standard burdens are applied. Saturation of CTs due to the dc component of an asymmetrical fault current can cause a delay in the operation of some instantaneous relays. It can also cause false tripping of residually connected instantaneous ground-fault relays.

TRANSFORMER PHASE TIME OVERCURRENT RELAY PROTECTION

Time overcurrent relays are inexpensive, simple, and reliable protective devices. Since sensitive settings and fast operation are usually not possible with overcurrent relays, they will provide limited protection for internal transformer faults.

Since the pickup value of phase overcurrent relays must be high enough to take advantage of the overload capabilities of the transformer and be capable of withstanding energizing inrush currents, insensitive settings result.

Fast operation is not possible, since the transformer relays should coordinate with load-side protection, including dealing with reclosing cycles and service restoration inrush. Where time overcurrent relays are used for primary transformer protection, extensive damage to the transformer from an internal fault may occur.

Settings of phase overcurrent relays on transformers involve a compromise between the requirements of operation and protection. The pickup setting should be high enough to permit overloading the transformer when necessary, but the higher the setting, the less the protection.

A setting of 125–150% of maximum kVA nameplate rating of a transformer is common, although higher values are sometimes used. On multiplerated transformers, a higher setting may be necessary so as to utilize the full capability of the transformer at the higher forced-cooling rating.

If overcurrent protection (relays or fuses) is applied only to the high-voltage (Δ) side of a Δ−Y grounded transformer, it can have a problem providing sensitive fault protection for the transformer and still coordinating with low-side protective devices. For low-voltage (Y side) phase-to-phase faults, the high-side line current will be 115% of the low-voltage per unit fault current.

For low-voltage (Y side) phase-to-ground faults, the high-side line current will be only 58% of the low voltage per unit fault current. When the Y is grounded through a resistor, the high-side fault current may be less than the maximum transformer load current.

Similar concerns are applicable when the Y is grounded through a reactor. The time setting should coordinate with relays on downstream equipment. Transformers are mechanically and thermally limited in their ability to withstand short-circuit current for finite periods of time.

For proper backup protection, the relays should operate before the transformer is damaged by an external fault. A for the transformer through-fault current duration limits and relay setting examples.) Solid-state or microprocessor-based relays with special features such as fast reset should be evaluated for coordination with downstream devices.

In setting transformer overcurrent relays, the short-time overload capability of the transformer in question should not be exceeded. Low values of 3.5 or less times normal base current may result from overloading rather than faults. For such cases see IEEE C57.91-1995, since allowable time duration may be different from those in the through-fault current duration curves. Pending establishment of additional transformer standards, it is recommended that the manufacturer be consulted for the capability of a specific transformer.

Distribution supply transformers are subject to many through-faults and autoreclosing into line faults. The use of extremely inverse tripping characteristics for distribution circuit reclosers permits fast clearing of the more severe faults.

Where the use of instantaneous relaying for either transformer or distribution feeder protection is limited, time overcurrent relays with very inverse time characteristics will provide fast clearing for the more severe faults.

NON DIRECTIONAL OVERCURRENT RELAY SCHEMES FOR TRANSMISSION LINES

Overcurrent protection is the simplest and least expensive form of fault protection that can be placed on transmission lines. The operating principles depend only on current magnitude. The ac connections for three-phase and one ground time overcurrent (TOC) relays and instantaneous overcurrent (IOC) relays are shown in below.

Connections for overcurrent phase and ground relay

Phase currents or sequence currents can be used as the operating quantity. Phase overcurrent relays operate for all possible fault types, but require their pickup settings to be higher than the maximum expected normal or emergency load flow condition.


Negative and zero-sequence overcurrent relays do not operate for balanced loads or for three-phase faults, but can have pickup settings well below the expected load. Tripping may be instantaneous, delayed for a fixed time, or delayed for a time inversely proportional to the current magnitude.

Figure below shows some of the various shapes of time/current characteristics that may be used.

TYPICAL TOC CURVES

Time Dial 5

Multiples of pu

Time overcurrent curve shape comparison

Instantaneous tripping can be applied if the pickup point of the instantaneous unit can be set higher than the maximum contribution to faults outside the protected line. The percentage of a line that can be protected by an instantaneous overcurrent relay will vary with line length and source impedance.

To protect an entire nonradial line, time delays are generally required to achieve coordination with downstream protective devices.

Figure below shows how coordination is achieved between a relay with a time and instantaneous element (the primary relay), and an upstream (backup relay) with only a time element.

Coordination of time overcurrent relays

To ensure proper coordination, the pickup point of the instantaneous unit should be set higher than the maximum contribution to faults outside the protected line.

The pickup value of the time element should be set to prevent tripping for the maximum load current that can flow in either direction on the line. The time adjustment (i.e., dial) should generally be set to produce the fastest operating time that will not result in miscoordination with other protection behind or in front of the terminal.

The effect of varying the time adjustment is illustrated in Figure below for a typical time overcurrent relay.

Very Inverse

Effect of Time Dial

Varying time adjustment on overcurrent relay characteristic curves

Nondirectional overcurrent relay schemes find limited application on transmission lines. Because transmission lines usually have at least two sources of fault current, the nondirectional elements have to be coordinated with protective devices both in front of and behind the line terminal.

This makes the coordination of nondirectional relays more difficult, and sometimes impossible. In some applications, these relays may be applied only at the terminal with the higher fault current source.

OVERCURRENT RELAY RATCHETING

Effects of autoreclosing on disk type overcurrent relays (ratcheting)

Electromechanical disk type time overcurrent relays respond to current above their pickup level in a time inversely proportional to the current level. When the current level is above the pickup, the disk begins to turn and continues to turn until the rotating contact meets the stationary contact to cause a breaker trip or until the current drops below the pickup level, as would occur if the fault were cleared by downstream protection.

Disk reset will occur when the current has dropped below the pickup level for a period of time. The disk resets to its original position at a relatively slow rate by the action of a coil spring.

This relatively slow reset action of the disk should be taken into consideration when autoreclosing is applied to any breaker or circuit recloser downstream of this breaker.

The most common application that requires special care is the circuit recloser operating to clear sections of a feeder downstream of a circuit breaker having disk type overcurrent relays applied. The circuit recloser can autoreclose the faulted section multiple times, resulting in several periods of fault current flow through both the circuit recloser and the upstream circuit breaker.

In a coordinated system, the circuit recloser trips the fault and removes the fault current flow before the disk type overcurrent relays reach their trip point. A minimum safety margin is normally provided to assure good coordination. At the point the overcurrent condition is removed, the disk has rotated some percentage of the amount required to provide a trip.

If the disk is not fully reset by the time the circuit recloser operates to re-energize the faulted section, the disk will not have as far to travel as during the original fault. This ratcheting effect could lead to a loss of coordination resulting in the unnecessary tripping of the circuit breaker.

Another example of ratcheting is an application in which two or more breakers having disk type overcurrent relays are in series. When both encounter an overcurrent condition, different time-dial settings or unequal currents due to load could cause the percentage of disk travel of the upstream relay to vary considerably.

Once again, if autoreclosing of the downstream breaker occurs before the upstream device is reset, a loss of coordination could occur.

Solutions for these loss of coordination events include use of larger safety margins to allow for partial reset of electromechanical relays, application of inverse time relays with fast resets on the upstream breakers, or longer dead times for autoreclosing.

Microprocessor or static relay designs may have an instantaneous reset of the timing function as well as other selective reset characteristics, which is normally considered in the coordination process.

CAPACITOR BANKS OVERCURRENT AND OVERLOAD PROTECTION

Capacitor units in filter banks may require additional duties due to harmonic contents. In these applications, higher voltage capacitor ratings and fuse current ratings may be required. Generally, the additional overloading requirements on component parameters should compensate for higher peak voltages and the increased losses imposed on the reactors and resistor assemblies.


The overcurrent and overload relay in each phase of the filter bank serves two desired protective functions. Fast tripping is initiated for high-level short-circuits near the circuit breaker terminal.

In case of lowmagnitude overcurrents, properly coordinated, time-delayed alarm and tripping signals are initiated due to the abnormal condition on the filter bank. Special emphasis is given to the response of the overcurrent protection (50/51 relay) to harmonic current distortion for some types of solid state electronic relays based on peak current measurements.

In effect, undesired filter bank tripping may occur from these relays as the electronic level detection is influenced by the harmonic phase angle relationships for low-order frequencies (second to fifth) along with the maximum current level detection of the relay.


Digital relays may be influenced by harmonic distortions if the predominant orders of harmonic oscillations are not predicted. The digital band-pass filter response provided in the relay may have a low attenuation factor at a given harmonic frequency and cause undesired tripping of the filter banks.

The expected reliability of the relay protection depends on the protection technology used, the design and manufacturing approaches, and the environment in which the relays are applied. To improve the availability of filter banks, appropriate data and experience related to harmonic distortion shall be considered in the selection of the protection scheme.


Figure below illustrates one possible primary protection scheme for a filter bank. A redundant protection scheme (not illustrated in the figure) may also be provided. The reactor and C2 are tuned to the fundamental frequency to minimize the losses in R at the fundamental frequency in this example.

Sample protection scheme for a filter bank