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.

CURRENT LIMITING FUSE TIME CURRENT CHARACTERISTIC (TCC) CURVES BASIC INFORMATION AND TUTORIALS

Specifically, minimum-melting and tota lclearing TCCs of fuses, which are plotted on a log-log scale with time on the Y axis and current on the X axis.

The fuse operates within the area between the two curves. Minimum melting curves are used for selecting fuses to provide maximum protection without operating unnecessarily. The total-clearing curves are used when upstream device coordination is required.

Figure 1 and Figure 2 show typical minimum-melting and total-clearing characteristics for high-voltage fuses. The fuse characteristics are different for each fuse type and design and for each manufacturer.

Thus, in a coordinated protective scheme, fuses cannot be substituted without first matching their characteristics, conducting a coordination study, or consulting the fuse manufacturer.

Figure 1 — Typical TCC curves for a current-limiting fuse.

Figure 2 — Typical TCC curves for an expulsion fuse

GENERATOR - TRANSFORMER VOLTS PER HERTZ PROTECTION

Volts per Hertz protection needs generally arise from different situations than those for which turbine underfrequency protection is provided. Turbine-generator shutdown with the automatic voltage regulator left out of service, sudden load rejection with the automatic voltage regulator out of service, and manual excitation adjustment during startup with faulty metering are events that support the need for volts per Hertz protection.

The protection methods discussed here illustrate volts per Hertz protection schemes that provide protection for both the generator and transformer on unit connected generators. Modern transformers withstand relatively low overexcitation since the flux density is already high at rated values. The most commonly employed methods are discussed.

For hydrogenerators, generator high overvoltages may occur without exceeding the overexcitation capability of the generator. During load rejection the overspeed of hydrogenerator could exceed 150% of rated speed.

If an overvoltage condition is the result of a proportional increase in frequency, the V/Hz relaying will miss the event because the ratio of V/Hz may not have changed. It is general practice to provide overvoltage relaying to shutdown the generators to protect for these high-voltage levels if governor and excitation control fail to operate properly.

Volts per Hertz limiters in generator excitation system controls
The V/Hz limiter is a control feature within the automatic voltage regulator that limits generator field current to hold the generator output voltage to a safe V/Hz value. The limiter will limit the output of the machine to a set maximum V/Hz no matter what the speed of the unit.

This limiter functions only in the automatic control mode. To provide protection when the unit is under manual control, the limiter may also have a relay signal output which will activate any additional protective circuits to trip the generator.

In addition to a V/Hz limiter in the excitation control, it is recommended practice to provide separate V/Hz relaying to protect the unit transformers and the generator. This protection should be as independent as possible from the V/Hz control in the excitation system. If possible, it should be supplied from different VTs. Independent V/Hz relaying provides protection for voltage regulator malfunction or if the regulator is out of service.

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.

PROTECTIVE RELAY TESTING OVERVIEW

Protective relaying is a very broad subject. Only a brief overview can be given here.

There are two major objectives in protective relaying. First, a protective relay serves to provide equipment protection (i.e., locate and isolate overloads, short circuits, undervoltages, and other types of electrical problems quickly in order to minimize damage).

Second, the protective device that is closest to the problem should operate first to clear the problem, and no other device should operate unless the closest one fails. This concept, known as selective tripping or selectivity, maintains service to as much of the electrical system as possible by isolating only the problem area.

In order to achieve these objectives, each relay must function as it was designed, and the relays must function in conjunction with the other protective devices in the system. Having all the protective devices function as one overall protective system is called coordination.

Each protective device has specific parameters within which it has been designed to operate. For example, a single element fuse has a value of current above which it opens. It takes a specific amount of time for a given current to melt the link away and open the fuse.

Manufacturers of fuses publish time-current curves that show how long it takes a fuse to operate for varying current values. Generally, the higher the current, the shorter the time.

This same inverse current-vs.-time concept is used for overcurrent relays and for low-voltage circuit breakers. Relays and low-voltage circuit breakers (with internal trip units) have a range of pickup operating current that causes them to operate. In many cases, this value of current is adjustable.

By properly selecting the type, characteristic, and/or setting of fuses, relays, or circuit breakers, the system can be coordinated so that the device that is closest to the problem opens before any device upstream of it. It is necessary to select compatible time-current characteristics of the devices for the entire system, in addition to selecting the proper settings for the devices.

Prior to performing protective relay testing, a coordination study should be completed to determine the proper settings for the relays to be calibrated. This is usually done by the design engineer when the system is first installed. If there have been revisions or additions to the system, a new study may be necessary.

Once the coordination study has been completed, the relays need to be calibrated to the proper settings. There are special test sets available for this purpose that inject currents and voltages, as necessary, and time the various operations of the relays.

This type of testing is usually performed by a technician who specializes in this area. Depending upon the relay to be calibrated, quite complex test equipment may be required and in-depth training in protective relaying may be needed to properly set the relay.

GENERATOR DISTANCE TYPE BACK UP BASICS

One zone of distance relaying with a mho characteristic is commonly used for system phase-fault backup. These relays are usually connected to receive currents from current transformers in the neutral ends of the generator phase windings and potential from the terminals of the generator.

If the generator is connected to the system using some means other than a delta-wye step-up transformer (i.e., direct connection, wye-wye transformer, etc.), then standard ct and vt connections made to a standard Mho distance relay will provide accurate measurement of impedances for system faults (neglecting infeed).

However, if there is a delta grounded-wye step-up transformer between the generator and the system, special care must be taken in selecting the distance relay and in applying the proper currents and potentials so that these relays see correct impedances for system faults. With some relay designs, the phase angle of the voltages applied to the relay have to be shifted so that they are in phase with the system voltages in order for the relay to see system faults correctly.

If required, this phase shift is accomplished by using auxiliary voltage transformers connected in delta-wye as shown in figure 1.

Application of system back-up relays— Unit generator-transformer arrangement

NOTE—This is a phase shifting transformer only. The turns ratio is chosen so that the line-to-line voltages on either side of the auxiliary vts are 1:1.

When a generator is connected directly to a system, the connections to the relay are shown in figure 2.

Application of system back-up relays—Generator connected directly to the system

In both cases, for the connections shown, the relay will not only provide backup for system faults but it will also provide some backup protection for phase faults in the generator and generator zone before and after the generator is synchronized to the system.

AUXILIARY CURRENT TRANSFORMERS USED FOR CIRCUIT PROTECTION

Auxiliary cts are used for the following reasons:

a) Circuit isolation to permit independent grounding
b) Change in ratio to match current requirements
c) To produce a phase shift in a three phase circuit
d) To reverse polarity
e) To limit main ct fault burden by saturating during faults
f) To reduce the burden on the main ct by reducing the apparent impedance of a portion of the burden by the square of the auxiliary ct ratio
g) Zero sequence shunt or trap

The auxiliary ct should be selected with an adequate continuous current rating and voltage capability for the requirements of its connected burden. The addition of an auxiliary ct adds burden to the main ct, but the net effect on the main ct may be either a decrease or an increase in burden, depending on whether the current is stepped down or up.

The apparent impedance to the main ct of the portion of the burden in the secondary of the auxiliary ct is that portion multiplied by the square of the auxiliary ct ratio. For example, a 1.0 W burden in the secondary of a 2:1 auxiliary ct would appear as 0.25 W to the main ct, but would appear as 4.0 W for a 1:2 auxiliary ct.

For this reason, current ste pup applications should be avoided when practical.


To ensure good performance under fault conditions, the knee-point voltage of the auxiliary ct should be considered in relation to its connected burden, without regard to the knee-point voltage of the main ct.

However, an auxiliary ct with an unnecessarily high knee-point voltage may have an undesirably high internal burden, which is seen directly by the main ct.

If circuit isolation is not required, it is advantageous to use auxiliary cts in the autotransformer connection for maximum capability or minimum burden. The use of the autotransformer connection usually results in better transient response. Ratios that are not available with a two winding arrangement can be obtained using the autotransformer arrangement.

Figure below shows how additional ratios can be obtained with 5:5 A, 10:5 A, and 15:5 A two-winding auxiliary cts connected as autotransformers. Only the step down ratios are shown. Stepping up current with auxiliary cts is not usually good practice as the connected burden will be increased as the square of the turns ratio of the auxiliary ct.

Two-winding auxiliary cts connected as autotransformers

OVER EXCITATION PROTECTION FOR POWER TRANSFORMER BASICS AND TUTORIALS

Overexcitation of a transformer can occur whenever the ratio of the per unit voltage to per unit frequency (V/Hz) at the secondary terminals of a transformer exceeds its rating of 1.05 per unit (PU) on transformer base at full load, 0.8 power factor, or 1.1 PU at no load.

For the generator, the limit is 1.05 PU (generator base). When an overexcitation condition occurs, saturation of the laminated steel cores of the generator and transformer can occur. Stray magnetic fields increase in magnitude, particularly at the ends of the cores.

Nonlaminated components at the ends of the cores, which were not designed to carry these higher levels of flux, begin to heat up because of the higher losses induced in them. This can cause severe localized overheating in the transformer and generator and eventual breakdown in the core assembly or winding insulation.

The permissible short-time overexcitation capability of a specific transformer or generator should be obtained from the manufacturer. Figure below shows V/Hz limiting curves provided by three different transformer manufacturers.

Overexcitation is of major concern on directly connected generator unit transformers. One of the primary causes of excessive V/Hz on generators and unit transformers is operation of the unit under regulator control at reduced frequencies during generator start-up and shutdown. Another cause of excessive V/Hz is inadvertent manual overexcitation during generator start-up and shutdown.

Overexcitation can also occur during complete load rejection that leaves transmission lines connected to a generating station. Under this condition the V/Hz may exceed 1.25 PU. With the excitation control in service, the overexcitation will generally be reduced to safe limits in a few seconds.

With the excitation control out of service, the overexcitation may be sustained and damage can occur to the generator and/or transformers. Failures in the excitation system or loss of signal voltage [i.e., blown voltage transformer (VT) fuse] to the excitation control can also cause overexcitation.


Occasionally a transformer remote from a generation station will be exposed to overflux conditions that may not be protected by an overvoltage relay or by the V/Hz protection associated with a generation station. A typical case would be a transformer on the end of a long line connected to a generating plant.

During a load rejection in which this transformer is connected to the generator, the transformer may have a significantly higher V/Hz than that at the generator facility as a result of the Ferranti effect. In this case, or similar cases, V/Hz protection should be applied to the remote transformer.


Overexcitation protection for the transformer is generally provided by the generator overexcitation protection, which uses the VTs connected to the generator terminals. So, the curves that define generator and transformer V/Hz limits must be coordinated to properly protect both pieces of equipment.

Generally, the transformer V/Hz curve is put on a generator voltage basis Therefore, a 13.2/115 kV transformer being used as a step-up transformer for a 13.8 kV generator will reach its continuous no-load V/Hz limit of 110% at a generator voltage of 105.2% of the generator rated voltage.

Generator manufacturers recommend an overexcitation protection system as part of the generator excitation system. These systems (V/Hz limiters) will limit the V/Hz to a safe value in the automatic control mode.

To provide protection when the unit is under manual control, the V/Hz limiter may send a relay alarm signal during an overexcitation condition and, if the condition persists, decrease the generator excitation or trip the generator and field breakers, or both. The generator manufacturer should be asked for recommendations for overexcitation protection.

It should be noted that, if the generator can be operated leading, the high-side voltage of the transformer may have a higher PU V/Hz than the generator V/Hz. This aspect may need to be considered in proper V/Hz protection of the transformer.

It is common practice to apply separate V/Hz protection in addition to the protection built into the excitation control system. Several forms of protection are available including definite time, preprogrammed inverse time curves, and user-programmable inverse time curves. A detailed discussion on various forms of V/Hz relays can be found in 4.5.4 of IEEE Std C37.102-1995 [B86].

When the transformer rated voltage is equal to the generator rated voltage, the same V/Hz relay that is protecting the generator may be set to protect the transformer. In some cases, however, the rated transformer voltage is lower than the rated generator voltage and protection may not be provided.

It may, therefore, be desirable to provide supplementary protection for the transformer. Since the V/Hz capabilities of transformers may differ appreciably, it is not possible to provide definitive protection recommendations that would cover all units.

POWER TRANSFORMER FAULT CLEARING

A faulted transformer can be separated from its power source by devices such as circuit breakers, power operated disconnect switches, circuit switchers, and fuses, or by remote tripping of fault-interrupting devices.

In addition to separating the transformer from its power source, due consideration should be given to tripping oil pumps and fans to reduce their possible adverse effects in sustaining or  spreading transformer oil fire and to halt circulation of contaminants in the oil resulting from the arc.

Determination of the type of fault-clearing devices to be used should consider factors such as:

a)Installation and maintenance cost
b)Fault-clearing time relative to fire hazard and repair or replacement costs of the transformer
c)System stability and reliability
d)System operating limitations
e)Device interrupting capability

Relay tripping circuits
Usually a transformer protective relay operation requires a careful inspection for the cause of tripping before any attempt is made to reenergize the transformer. Usually two or more breakers or switching devices must be tripped. Therefore, tripping is usually done by a lockout relay that also blocks closing circuits and must be reset manually.

For a large transformer having several protective relays, two lockout relays and dc power supplies are often used. If both lockout relays trip the same breakers, the differential relays may operate one lockout relay and the sudden-pressure relay and overcurrent relays, including instantaneous units, may operate the second lockout relay for the greatest redundancy.

If the two lockout relays perform different tripping functions, then a different assignment of protective relays to each lockout relay may be desired. The lockout relay contacts may initiate breaker failure relaying and may be supplemented by a small self-reset relay operated in parallel with the lockout relay coil for redundancy.

Relays should be connected to trip fault-interrupting devices that will clear faults in the zone that the relay is intended to protect. For example, the relay devices 87G in Figure 8, 67G in Figure 9, and 51GB and 51GT must trip the transformer high-side (source) circuit breaker in order to clear a ground fault on the low-voltage side of the transformer.

REMOTE TRIPPING OF CIRCUIT BREAKERS BASICS

How to trip circuit breakers remotely?


  
Circuit breakers
Circuit breakers directly actuated by a protective relay system are usually provided where it is desirable to isolate a faulted transformer with minimum effect on other segments of the power system. They offer the fastest fault-clearing time and highest interrupting capability.

Many of the diagrams in this guide show only relay connections and not circuit breaker location. Wherever possible, the circuit breaker should be included in the relay zone of protection so that a fault in the breaker or leads to the transformer and its bushings is detected.



In some situations, it may be difficult to justify the cost of local circuit breakers. Tripping of remote-source circuit breakers by use of local relays and a communications channel, or by use of a fault-initiating switch (high-speed ground switch) are alternatives.

Transfer trip schemes
Five types of communication channel are in general use for transferring a trip signal to remote circuit breakers: pilot wire, power-line carrier, fiber optic, and microwave or radio. In direct-transfer trip schemes, the receipt of a signal will trip local circuit breakers independently of local relays.

The signal may be a simple application of voltage or audio tones on a pair of wires or may utilize frequency-shift-type audio tones, or frequency-shift carrier.

Frequency-shift equipment employs a guard frequency for channel monitoring and added security against trips by spurious signals. Transformer protective relays will actuate the shift to trip frequency. These schemes have the advantage of speed and the ability to block reclosing of the remote circuit breakers until the faulted transformer is isolated from the system.

Fault-initiating switch (high-speed ground switch)
Remote tripping of circuit breakers can be accomplished by applying a fault (usually solid single phase-to-ground) to the source line so that the remote line relays will detect it and trip the remote circuit breakers. A disadvantage of this scheme is the additional time involved while the ground switch is closing and remote relays in turn detect the fault. Another consideration is that the ground switch phase and the faulted phase on the transformer may be different, thus imposing a multiphase fault on the system.

Disconnecting switch
When remote tripping is used, a power-operated disconnecting switch is usually connected on the source side of the transformer to isolate it from the system. The switch is arranged to open automatically and cancels the remote transfer trip signal or isolates the ground switch from the system. In both cases, this permits the remote breakers to reclose.

DISTANCE RELAY MINIMUM SETTINGS BASIC INFORMATION

The problem of low settings of line distance relays is that for lines that are very short or have a high SIR, available fault current and voltage at the relay location may not provide adequate operating margins. All distance relays have minimum settings criteria that must be met for proper operation.

The following concerns should be addressed:

a) Impedance characteristic.
Minimum fault operating currents must be know; usually, the shorter the reach, the greater the minimum current required to function. The apparent reach setting of the relay decreases with lower relay terminal voltages (Figure below), causing the relay to under reach.

Apparent relay reach vs. relay voltage

b) Directional action.
Minimum polarizing voltages must be known. Sensitivities in the range of 1% of rated voltage may be required; however, at this sensitivity, misoperations may occur for reverse faults due to the effect of arc drop.

c) Memory action.
The memory circuitry of the relay is used for low-voltage conditions by supplying a prefault voltage for polarizing. This circuit may have memory action that lasts only a few cycles.

d) Operating time.
Tripping time (Figure below) may vary with the distance to the fault, the basic minimum reach setting, the fault current magnitude, and the magnitude of relay voltage prior to the fault.

Location of Fault in Percent of Relay Setting

Variation of operating time with distance to the fault

Usually, the lower the ratio of Zapparent to Zsetting, the faster the relay operates except for low current conditions. Under conditions of low current, the relay operate time may actually increase.

e) Maximum torque angle.
Cable circuits may have a very small line impedance angle, especially for pipe-type cables. This may require a maximum torque angle that is not available on the relay and, thus, necessitate using a different range or impedance characteristic (i.e., quadrilateral) relay.

f) Continuous ampere rating.
The engineer must be aware of the continuous operating characteristics for a particular setting. It is possible for a setting to violate the continuous ampere rating, especially if the relay is an electromechanical style.

g) CT and VT errors.
Due to errors in the CTs and VTs, it is possible for a marginal setting to be unusable. On systems where the available voltages and currents are low, CT and VT errors may further reduce the available quantities to the relay.

h) Relay settings.
When the protected line is short, arc impedance must be incorporated into the settings for Zones 2 and 3. It may not be possible to increase the Zone 1 reach setting because of possible overreach of remote terminals, although some relaying principles automatically adapt to this need.

As each distance relay has its own characteristics, it may be necessary to perform fault studies under minimum conditions to confirm that the relay functions properly. If the relay does not meet the minimum requirements, then alternative relay schemes, such as current differential, phase comparison, or pilot-wire, should be considered.

STATIC VAR COMPENSATOR (SVC) CAPACITOR PROTECTION

SVCs are used in strategic installations to rapidly compensate reactive power for maintaining an acceptable system voltage profile and for improving the overall stability of the power system. Voltage flickers are also reduced in industrial applications when SVCs and harmonic filters are provided.

An example of an SVC installation is illustrated in Figure 1.

Figure 1—Typical SVC

Protection of SVCs is provided by a combination of conventional protective relays and protective functions contained in the SVC control system (IEEE Power System Relay Committee [B7]). These functions are made up of a number of zones to include the SVC step-down transformer, low-voltage buses, reactor branches, capacitor branches, filters, and thyristors.

This guide applies equally to the protection of the fixed or thyristor-switched capacitor (TSC) banks provided as an integral part of an SVC installation. In this regard, Clause 7 and Clause 8 describe various protection methods that can be applied by conventional relays to shunt capacitor banks along with additional methods illustrated in Figure 2 and Table 1.

Figure 2—Capacitor unbalance protection in the TSC mode

Table 1—Suggested SVC protection methods

SVC capacitor banks in the TSC mode are provided with air-core reactors connected in series to limit the inrush generated from thyristor switching. The selection and setting of the overcurrent protection should consider a misfire in the TSC valve (accounting for the magnitude and time duration of inrush and outrush currents) and should coordinate with other protective functions provided in the controls.

Harmonics are an important factor to consider in the protection of capacitors in the TSC mode. Adequate overcurrent and overvoltage protection types and settings shall be provided to counter the effect of harmonics generated by the thyristor-controlled reactors (TCRs) and by other unusual harmonic distortion such as those resulting from geomagnetic disturbances (Benmouyal et al. [B3]).

In this regard, true rms-based overcurrent relays are required to adequately protect the series limiting reactors against overloads while peak-measuring voltage relays should be provided for the protection of capacitors against overvoltages.

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

MOTOR OVER TEMPERATURE THERMAL PROTECTIVE DEVICE (49) INFORMATION SHEET

There are two main classes of overtemperature thermal protective devices. One is a line break type, which interrupts load current directly. The second is a control circuit system using detector devices, which interrupts the motor current through its controller.

Thermal protectors are intended to limit motor-winding temperature and motor current to predetermined values during abnormal motor operating conditions. This prevents premature motor insulation failure.

Abnormal conditions that can result in overheating include overload, stalling, failure to start, high ambient temperature, restricted motor ventilation, reduced speed operation, frequent starting or jogging, high or low line voltage or frequency, mechanical failure of the driven load, improper installation, and unbalanced line voltage or single phasing.

Current sensing alone cannot detect some of these conditions, such as restricted ventilation. Temperature sensing alone may be inadequate, for example, with frequent starting or jogging.

For some conditions, a coordinated arrangement of current and temperature sensing may be required. The temperature sensing capability of thermal protectors depends on their location with respect to the motor windings.

The protectors should be installed within or on the motor frame in such a manner that the temperature at the device changes in proportion to the winding temperature, and they should be matched to the motor's insulation class.

The advent of microprocessor-based protection systems has made it possible to provide a more refined thermal protection than was possible with electromechanical relays. Since no attempt is made with electromechanical relays to match the thermal time constant of the motor, thermal coordination is achieved under limited operating conditions.

Conversely, microprocessor-based protection systems make it possible to match thermal properties identified by motor data and, as a result, tracks the motor temperature more accurately over a wider range of operating conditions (Zocholl [B115]).

Microprocessor systems can also monitor resistance temperature detectors (RTDs) embedded in the motor stator windings to detect temperature rise caused by impaired or lost ventilation not indicated by current. In addition, these systems can monitor temperature detection devices for motor bearings.

MOTOR STATOR WINDING PROTECTION BASICS

Deterioration of the electrical insulating system of stator windings is a common cause of reduced motor life and failure. This may result from numerous causes, such as subjecting the insulation to moisture, excessive dielectric stress, and mechanical or thermal damage.

The physical and dielectric properties of an insulation system deteriorate with age, and like other chemical activity, this process is accelerated by an elevation in temperature.

A rule of thumb has been developed from tests and experience to indicate that the life of an insulation system is approximately halved for each 10 °C incremental increase of winding temperature, and approximately doubled for each 10 °C decrease (the range of 7 °C–12 °C is indicated for modern insulation systems).

Thus, insulation life is related to the length of time the insulation is maintained at a given temperature.

In practice, winding failures resulting from dielectric breakdown are usually attributed to conditions such as impulse or switching surge voltage, moisture, penetration, or conducting contaminants. Mechanical stresses, such as vibration or distortion forces, can also cause winding failures.

These forces occur most often when starting the motor, or possibly during a transfer to another electrical source. Regardless of the reason associated with the failure, the effect of elevated temperature is to reduce the ability of the insulation to withstand electrical or mechanical abuse.

The temperature level at which an insulation system should be protected is subject to engineering judgment and applicable standards. (For limits established by the motor industry, see NEMA MG1-1998, Articles 12.41, 12.42, and 12.52. For induction motors, see NEMA MG1-1998, Article 20.40. For synchronous motors, see NEMA MG1-1998, Article 21.40.)

It should be noted that deriving increased output at the price of higher temperatures for any given motor means accepting a shorter life. However, when motors are used in essential or critical service, such as for fire pumps or boiler-feed pumps, it is often desirable that the operator be given time to correct an overload condition before a motor is stopped.

Such service may require the motor to run overloaded for prolonged periods, in situations where the overload does not exceed the breakdown torque rating of the motor. In these cases, the cost of reduced motor life due to the overload conditions must be weighed against the expense and damage that would result from a service interruption.

TURBINE UNDER FREQUENCY PROTECTION RELAY SCHEMES AS PER IEEE C37.106-2003

The turbine underfrequency protection scheme may be accomplished by one or more relays. Digital or solid state relays are preferred for their accuracy over a broad frequency range. The required number of frequency setpoints and their associated time delays are dependent upon the characteristics of the turbine.

This relay function may be included in a multifunctional protection package. The first step in designing an underfrequency protection scheme is determining the turbine’s abnormal frequency operating characteristic.

Consultation with the manufacturer should provide the initial design parameters. Modifications to the turbine as well as the known condition from turbine inspections may result in changes to the either the resonant frequency or the allowable abnormal frequency operate time or to both.

From this information, the number of frequency levels that require action can be identified. It should be noted that extreme frequency variations may not require underfrequency relay action as other plant equipment will force the plant to trip.

Once the number of frequency steps is known, the time delay for each step must be determined. Because the allowable underfrequency operation time cannot be identified exactly, some margin should be included in the time delay.

This would allow tripping of the unit prior to damage, with the opportunity to inspect the turbine at the owner’s convenience during a future outage. This allows for application of underfrequency protection, even if the unit has been in operation for many years without having accumulated previous underfrequency operational data.

The time delay margins should consider the importance of the unit, the susceptibility of the system to an underfrequency event and operating agreements with local or regional power authorities. A range of 50–90% of the allowable time per expected event over the blading life is reasonable.

Settings of 50% should be considered if the turbine is in poor condition, there is a high possibility of an underfrequency event or if the unit is not system critical. If the unit is in good condition, an underfrequency event is unlikely, and the unit is critical to the system, a setting near 90% of the allowable underfrequency time should be considered.

It should be recognized that some underfrequency relay timers have an instantaneous reset once the frequency rises above the trip setting, while others accumulate the underfrequency operate time in a memory function (zero reset). The time delay setting should be a smaller percentage of the allowable time if the relay is of the instantaneous reset type, whereas the zero reset relay can be set at a greater percentage of the allowable time.

Figure below will be used to demonstrate an underfrequency relay setting. The example indicates the turbine is capable of continuous operation at frequencies above 58.5 Hz and is limited to a maximum of 10 minutes accumulated over the blading life at 56.0 Hz.

Example of turbine abnormal frequency limitations and settings

These are operating conditions with the turbine at load. The underfrequency relay trip point setting should be set just above 56.0 Hz to allow for relay margin. A setting of 56.2 Hz could be selected. A time delay setting of seven minutes could be used if the unit is in fair condition, not critical to the operation of the system, and it is acceptable to lose 70% of the fatigue life of the blading.

If the unit is in good condition and is critical to the system, a longer time delay of nine minutes could be used to allow the maximum opportunity for system recovery, prior to tripping the unit assuming these events are very rare so that 90% of the fatigue life can be expended on it. An alarm should be provided when the underfrequency relay begins to time out, providing operating personnel a warning of the impending underfrequency trip.

Many operators apply a single multilevel relay having four frequency set points. In many cases, one of the frequency set points will be used to alarm at a relatively high frequency (59.4 Hz for example) to indicate the inception of an abnormal frequency event, with the remaining three set points are at lower frequencies corresponding to the turbine characteristics.


If IEC 60034-3:1996 is applicable, time-frequency protection could be required by a manufacturer for the turbine generator. If such a situation was to develop, the more restrictive of the generator and turbine frequency requirements, over a frequency band, should be used in the determination of appropriate frequency settings for underfrequency relaying. The frequency capability of the generator, when applicable, must be considered in the development of the frequency relay protection scheme.

MAGNETIZING CURRENT INRUSH - PROTECTION CONSIDERATION

This is a phenomenon that causes the violation of the basic principle of differential relaying since the magnetizing branch of the transformer can have a very low impedance without a transformer fault. Current produced by magnetizing inrush can reach many times the transformer rating, and these currents appear in the differential relay.

The inrush current duration can range from a few cycles up to many seconds. Although usually considered only in conjunction with the energizing of a transformer, magnetizing current inrush can be caused by any abrupt change of magnetizing voltage.

Such transients include the occurrence of a fault, the removal of a fault, the change of character of a fault (for example, the change from a single phase- to-ground fault to a two-phase-to-ground fault), and out-of-phase synchronizing.

Thus, a desensitizing scheme that is operative only when energizing a transformer may not be adequate. There are several conditions that cause particularly severe magnetizing inrush phenomena.

One involves the energizing of a transformer at a station at which at least one other transformer is already energized. The inrush phenomenon will involve transformers that are already energized as well as the transformer being energized.

This inrush transient may be particularly long in duration. It is important to realize that the inrush into the transformer being energized occurs during the opposite half-cycle to that of the already energized transformer.

Thus, the net inrush into all transformers may approximate a sine wave of fundamental frequency, and therefore not operate the harmonic restraint unit of a differential relay if it is protecting both parallel transformers. Another inrush phenomenon involves the energizing of a transformer by means of an air switch.

Arcing of the switch can result in successive half-cycles of arc of the same polarity. Thus if the first half-cycle results in substantial residual magnetism in a transformer core, succeeding half-cycles can cause a cumulative increase in residual magnetism, each time resulting in a more severe inrush.

Two important characteristics of magnetizing inrush current are
a)It contains substantial harmonics, particularly the second harmonics. These harmonics are not always present in high quantities in all three phases.

b)That there is always a time during each cycle where the current magnitude is almost zero. This time is always greater than a quarter cycle.

The harmonic content of the inrush current depends on various factors such as remnant flux in the core, switching angle, and load on the transformer. Harmonic analysis of the inrush current during the events in

Figure below shows that the second harmonic content of the inrush current is sensitive to all these conditions. The second harmonic content reduces appreciably with increasing load at lagging power factor conditions.

Typical magnetizing inrush current wave

National Electrical Code ® (NEC ® ) (ANSI/NFPA 70-1999) & OSHA

The National Electrical Code® (NEC®) (ANSI/NFPA 70-1999) has as its purpose the practical safeguarding of persons, buildings, and their contents from hazards arising from the use of electricity. It contains provisions considered necessary for safety.

Its scope includes the electric conductors and equipment installed, for example, within or on public or private buildings, industrial substations and mobile homes.

It does not cover installations under the exclusive use of electric utilities, mines, and certain other exceptions. The NEC as a recommendation for safe practice is adopted by most of the states, cities, and towns in the United States as the governing electrical code, and is enforced by the local or state-approved authority.

OSHA, 29 CFR, Chapter XVII, Part 1910 is concerned with all establishments engaged in the manufacture of products for interstate commerce. Part 1910 (Subpart S—Electrical) of the regulation has essentially adopted the NEC and incorporates its requirements for electrical installations.

The edition of the NEC adopted by OSHA is not generally the same as that enforced by local authority. NFPA Std 70E is generally the standard that influences the OSHA changes.

The adoption of the NEC in the public and private sector, even though excluding installations under the exclusive control of electric utilities when used in connection with the generation, transmission, and distribution of electric energy, essentially represents requirements for practically all residential, commercial, and industrial installations. For this reason, NEC requirements, as they apply to motors and motor circuits, are included.

The NEC specifies overload devices used to protect motors, motor-control apparatus and motor branch-circuit conductors against excessive heating due to overload and failure to start (see ANSI/NFPA 70-1996, Article 430, Part C).

The NEC further specifies devices intended to protect the motor, motor-control
apparatus, and branch-circuit conductors against overcurrents due to short circuits and grounds (see ANSI/NFPA 70-1996, Article 430, Part D).

In motor branch circuits, it is customary to provide for these functions separately, where the running overload protective device protects against motor overloads and locked rotor, and the overcurrent protective device (as a separate device) provides protection against short circuits and ground faults.

The NEC specifies maximum current rating or setting in relation to motor nameplate full-load current for the motor running overload protective device, since the requirement includes the need to monitor the maximum continuous motor branch-circuit current.

Of the several means recognized for providing motor running overload protection, the two basic approaches in common use are a separate overcurrent device that is responsive to motor current, and a thermal protector integral with the motor (see ANSI/NFPA 70-1996, Articles 430–432).

For continuous duty motors, a separate overload device responsive to motor current is specified in ANSI/ NFPA 70-1996, Articles 430–432, to be rated or selected to trip at no more than 125% of rated full-load current for motors with a marked temperature rise not over 40 °C, or with a service factor not less than 1.15 and not higher than 115% of full-load current rating for all other motors.

For continuous duty motors having a thermal protector integral with the motor, ANSI/NFPA 70-1996, Articles 430–432 specify that the thermal protector shall be approved for use with the motor that it protects on the basis that it will prevent dangerous overheating of the motor due to overload and failure to start.

For motors rated more than 1 hp, in addition to protecting against excessive temperature, the thermal protector is specified to limit the combination of motor and protector to an ultimate trip current in the following manner.

Where full-load current does not exceed 9 A, the trip current should not exceed 170% of motor full-load current. For motors with full-load current values between 9.1 A and 20 A, the trip current should not exceed 156% of motor full-load current. For motors with a full-load current value of 20 A, the trip current should
not exceed 140% of motor full-load current.

Other overload protection recognized by ANSI/NFPA 70-1996, Articles 430–432(a) (4), involves the use of embedded temperature detectors used in conjunction with intermediate devices that cause motor current to be interrupted.

AC MOTORS PULL OUT AND STALL PROTECTION RELAYING

Induction-motor stalling
An induction motor stalls when the load torque exceeds the breakdown torque and causes its speed to decrease to zero, or to some stable operating point well below rated speed. This occurs when the applied shaft load is greater than the producing motor torque due to the suppression of the motor terminal voltage.

Also, a stall condition can occur when an excessive mechanical load is applied beyond motor torque capability. This condition will develop motor current equal to or approaching locked-rotor current.

Synchronous motor loss of synchronism (pullout)
When a synchronous motor loses synchronism with respect to the system frequency with which it is connected, it is referred to as “out of step.” This condition occurs when the following actions take place individually or in combination:

a) Excessive load is applied to the shaft
b) The supply voltage is reduced excessively
c) The motor excitation is too low


Torque pulsations applied to the shaft of a synchronous motor are also a possible cause of loss of synchronism, if the pulsations occur at an unfavorable period relative to the natural frequency of the rotor with respect to the power system.

A prevalent cause of loss of synchronism is a fault occurring on the supply system. Fault-clearing time, fault location, fault type, and system configuration are significant factors relating to the stability of the motor. Fast fault clearing, multiple ties, and remoteness of faults favor stability.

Underexcitation of the machine is a common cause of out-of-step operation. This may be caused by incorrect tripping of the rotor field circuit breaker (or contactor), or by opening or short circuiting the field circuit.

When loss of synchronism (pullout) occurs, and the motor is not separated from the system on the first pole slippage, field excitation must be disconnected and the field connected to the discharge resistor immediately. This minimizes the current that flows until the motor can be isolated. The motor should then be isolated as quickly as possible, because this is not an acceptable long-term operating condition.

Electrical quantities change during a stall
For an induction motor to stall during normal operation, the load torque must exceed the breakdown torque as described above. During this process, the motor current will increase rapidly (which is called “inrush current” or “locked rotor”) until the breakdown torque is reached.

Beyond breakdown torque, the motor current continues to increase approaching locked-rotor current. Along with the increase in current, the speed of the motor decreases and the impedance of the motor approaches the locked-rotor impedance. There are two types of stall causes, as follows:

a) Excess shaft load torque prior to a motor startup (e.g., failure to open the pump’s discharge gate)
b) Sudden change of increased shaft load torque during normal operation (e.g., bearing failures)

For a synchronous motor, loss of synchronism is a gradually evolving phenomenon rather than an instantaneous occurrence. During the initial phase of pullout, stator current increases, terminal voltage decreases, and a voltage is induced in the rotor circuit at the slip frequency. Power flow into the motor increases until approximately a 90° angle is reached between the equivalent machine voltage and the system voltage.

At approximately the 180° point, current is maximum and lags the system voltage by the angle of the total impedance between the motor and the system (including the stator resistance and transient reactance of the motor). Also at this point, the direction of power flow reverses, with the motor mass supplying energy to the system.

When resistance is significant, this reversal occurs prior to the 180° point. The reactive power flow for virtually the full slip cycle is into the motor, but it may be provided by the motor for a small part of the slip cycle, depending on the machine excitation.

Protective devices for detecting abnormal motor conditions
Stall detection for an induction motor is usually provided by an overcurrent relay, with an inverse characteristic set to detect current above the breakdown torque level. Since motor starting can result in a stall or locked-rotor condition, this protection is usually covered by setting the motor-starting relays above the motor-starting time-current curves and below the running and accelerating thermal limit for the motor.

In cases where motors are applied to high-inertia loads, overcurrent protection may need to be combined with speed switches, distance relays, or additional rotor thermal protection to fully protect the motor. Out-of-step detection devices for synchronous motors usually operate on the stator power-factor angle.

Impedance-type devices are available for detecting loss of field, and they may also be set to operate on out of-step conditions without field failure, where the motor transient reactance exceeds the system impedance viewed from the motor terminals (the usual case).


For very large synchronous motors or synchronous condensers, a loss-of-field relay is often used to detect VAR flow into the machine. Accidental tripping of the rotor field circuit breaker (or contactor) or loss-offield current can be accurately detected by this device.

There have also been successful applications of rotor field current devices operating from a rotor field current shunt and of notching relays that count pole slips based on power reversals.

A device sensing alternating current in the rotor field circuit may also detect the motor out-of-step condition. These devices used in the rotor field circuit usually consist of a current transformer (CT) with an ac relay on its secondary.

When the machine is operating synchronously, there is no ac component of rotor field current and, therefore, no relay current. If the machine is out-of-step with the system, a current of slip frequency exists; if it is of sufficient magnitude, the relay picks up. During the starting period, this relay must be blocked. This scheme is not adaptable to motors with a brushless excitation scheme.

HIGH-VOLTAGE (HV) TRANSMISSION LINE PROTECTION SCHEMES

Most transmission lines are protected by directional distance relays. These may serve as backup protection to other schemes in service, or these may be the sensing components in various forms of differential protection.

Figure below shows the basic elements of a PLC (power line carrier) system extensively used for protection of HV transmission lines.

An HV transmission line is capable of simultaneous functions of communications and electrical energy transmission. PLC equipment consists of three distinct parts: terminal assemblies consisting of transmitters, receivers, and protective relays; the coupling and tuning equipment, which connects the terminals to selected points on the transmission line; and the transmission line itself, which provides a suitable channel for the transmission of carrier energy in PLC bands of frequencies between terminals.

Coupling to lines is accomplished by means of high-voltage capacitors, which provide a low-loss path to carrier signals and block 60 Hz power frequency energy from the carrier equipment. Line traps minimize the loss of carrier power into adjacent lines and prevent external ground fault currents from short-circuiting the carrier signal of the unfaulted line.

Carrier Frequencies.

Frequencies in the range of 30 kHz to 500 kHz have been employed for PLC relaying and other communication purposes. The range is high enough to be isolated from the transmission line and the noise it creates and yet not so high as to give rise to excessive attenuation.

There are two basic types of signals used for teleprotection channels. Keyed carriers are sometimes referred to as AM, amplitude modulation: It is normally off and intelligence is transmitted by turning the carrier on and off.

This type of signal is normally used in blocking-type relaying systems. The frequency may be in range from 29 kHz to 31 kHz, and the signal could be applied to a single sideband (SSB) PLC channel.

Frequency Shift Keyed Carrier.

This signal is always on, which provides a means of continuously monitoring the channel. The frequency shift keyed (FSK) carrier is less susceptible to noise and has a greater operating range. FSK channels have been available with two-frequency operations, high and low shift frequencies for additional security.

Blocking Schemes.

Transmission line faults are detected using either high-speed phase comparison, in which the phase of the currents at the two terminals are compared, or direction comparison relaying. The scheme operates in a trip permissive mode.

A received signal is used to block tripping of the protected line for external faults. The blocking scheme is biased toward dependability because channel or remote relay failure will result in operation of the local blocking relay.

Tripping Schemes.

A phase comparison tripping scheme channel is keyed to the trip condition every half cycle during the fault. The scheme is biased toward security so that a failure of the channels or relays would result in non operation of the local relay for external and internal faults. Directional distance relays can be used both for phase as well as ground fault conditions.