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.

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.

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.

GROUNDING TRANSFORMER DIFFERENTIAL RELAYING

Configuration
To establish a grounded system, a grounding transformer is frequently tapped on the low-side leads of the supply transformer and is thereby included in the transformer differential zone.


Problem
Zero sequence current supplied by the grounding transformer may cause differential relay operation during an external ground fault.

Solution
Since external ground faults cause zero sequence current to flow in the CT secondary circuits, a zero sequence filter is provided for the low-side differential Y-connected transformers. This filter is composed of three auxiliary CTs and can be formed in several ways.

The simplest form is to connect the primaries in Y and the secondaries in Δ. In Figure below, the ratio of the auxiliary CTs is not critical, but a 5:5 ratio is suggested.

Grounding transformer in differential zone (external fault condition shown)

The alternative filter connection in Figure 16 requires a 1:3 ratio for the auxiliary CTs. The primaries are connected in Y and the junction or sum of the primaries is wired to the secondaries connected in series.

Thus the secondaries carry three times the primary current. Both of these connections present relatively high magnetizing impedance to all but zero sequence current.

However, modern differential relays are of even lower burden than the usual auxiliary CTs. Thus, the common point of the relay connections should not be connected to the common point of the Y-connected transformers (a connection that is necessary without the zero sequence filter).

Only the filter neutral should be connected to the CT common point. The figure also shows the primary current and CT secondary current for an external ground fault.

The zero sequence filter prevents a relay imbalance. A 1:1 overall voltage ratio is assumed in the figure above with 1 PU fault current flowing.


An application example using an inverse relay has relay pickup at 30% of transformer rating and a time of 1.7 s at 300% of setting. The pickup depends on the effective contribution of the equivalent tertiary of the case.

The transformer manufacturer should be consulted.

TYPES OF CURRENT TRANSFORMERS - BASIC INFORMATION

Current transformers are greatly used in protective relaying since the magnitude of fault current are far too big for the relays to handle. Design of these devices is discussed only to the extent that it relates to the application and use of instrument transformers in protection applications.

Current transformers (CTs)

A CT transforms line current into values suitable for standard protective relays and isolates the relays from line voltages. A CT has two windings, designated as primary and secondary, which are insulated from each other. The various types of primary windings are covered below.

The secondary is wound on an iron core. The primary winding is connected in series with the circuit carrying the line current to be measured; and the secondary winding is connected to protective devices, instruments, meters, or control devices. The secondary winding supplies a current in direct proportion and at a fixed relationship to the primary current.

Types of CTs

The four common types of CTs are as follows:

a) A wound CT has a primary winding consisting of one or more turns mechanically encircling the core or cores. The primary and secondary windings are insulated from each other and from the core(s) and are assembled as an integral structure (see Figure 1).

b) A bar CT has a fixed, insulated, straight conductor in the form of a bar, rod, or tube that is a single primary turn passing through the magnetic circuit and is assembled to the secondary, core and winding (see Figure 2).

c) A window CT has a secondary winding insulated from and permanently assembled on the core, but has no primary winding as an integral part of the structure. Primary insulation is provided in the window through which one or more turns of the line conductor can be passed to provide the primary winding (see Figure 3).

d) A bushing CT has an annular core and a secondary winding insulated from and permanently assembled on the core, but has no primary winding or insulation for a primary winding.

This type of CT is used with a fully insulated conductor as the primary winding and used typically in equipment where the primary conductor is a component part of other apparatus, for example, on bushings of a transformer or circuit breaker.

The secondary windings of bushing CTs are usually fully distributed around the core. Typically they are multiratio with each winding tap also being fully distributed.

CURRENT TRANSFORMERS POLARITY AND CONNECTIONS FOR RELAYING

Polarity

Polarity marks designate the relative instantaneous directions of currents. At the same instant that the primary current is entering the marked primary terminal, the corresponding secondary current is leaving the similarly marked secondary terminal, having undergone a magnitude change within the transformer (see Figure 1).  

Figure 1 - Current Transformer Polarity

The primary H1 and secondary X1 terminals are marked with white dots, or with a ± symbol, or with H1 and X 1. As illustrated in Figure 1, the marked secondary conductor can be considered a continuation of the marked primary line as far as instantaneous current flow is concerned.

Connections

CTs are usually connected on three-phase circuits in one of three ways, as follows:

a) Wye connection.

In the wye connection, a CT is placed in each phase with timeovercurrent relays (Device 51) placed in either two or three CT secondaries to detect phase faults. On grounded four-wire systems, a time-overcurrent relay (Device 51N) in the CT common wire known as a residually connected relay detects any ground fault or neutral load currents. If neutral load currents are not to be detected by the Device 51N relay as ground-fault currents, a fourth CT is placed in the neutral conductor to cancel the neutral load currents. Secondary currents are in phase with primary currents (see Figure 2).

Figure 2 - Wye connected CT

b)Vee connection.

A vee connection is basically a wye with one leg omitted, using only two CTs. Applied as shown in Figure 3, this connection detects three-phase and phase-to-phase faults. A zero-sequence CT (window or bushing) and a ground overcurrent relay (Device 50GS or Device 51GS) are required to detect ground-fault currents. All three-phase conductors and the neutral (if present) shall pass through the CT.

Figure 3 - Vee or open delta connected CT

c)Delta connection.

A delta connection uses three CTs with the secondaries connected in delta before the connections are made to the relays. The delta connection shown in Figure 4 is typically used for power transformer differential relay protection schemes where the power transformer has delta-wye-connected windings.

Figure 4 - Delta connected CT

The Cts on the delta side are connected in wye, and the CTs on the wye side are connected in delta. The delta connection is also used for overcurrent protection of grounding transformers where filtering out the third-harmonic currents is desirable.

When connected in delta, the current in the relays is equal to times the CT secondary current. This fact should be considered when selecting the primary ratings of CTs and the secondary device ratings of delta connected CTs

SYMMETRICAL COMPONENTS CALCULATION FOR TRANSFORMERS

As a passive device, the positive- and negative-sequence impedance magnitudes for transformers are identical and are equal to the nameplate leakage reactance provided by the manufacturer. However, in modeling transformers in symmetrical components, recognizing that an inherent phase shift is associated with delta-connected windings is sometimes necessary.

Wye-delta and delta-wye transformers built under ANSI standards are designed so that high-voltage quantities always lead the corresponding low-voltage quantities by 30°. The complete positive-sequence model for a delta-wye or wye-delta transformer, therefore, should include a 30° phase shift.

Negative-sequence quantities, however, are shifted in the opposite direction, and so the negative-sequence representation should include a phase shift opposite to the shift considered in positive sequence. These relationships are illustrated in Figure 2-7a.

Figure 2-7a—Positive- and negative-sequence equivalent circuits for delta-wye or wye-delta transformer


NOTES
1—The phase shift in positive sequence is in the same direction as in the physical transformer: high voltage leads low voltage by 30° for ANSI standard transformers.
2—The phase shift in the negative-sequence circuit is opposite in direction.



Inclusion of these phase shifts is important only if a rigorous calculation is needed to determine exact phase currents and voltages on both sides of the transformer, including phase angles. Analysts often take the shortcut of neglecting phase shifts if the calculations are restricted to determining information on only one side of the transformer.

No inherent phase shift occurs in wye-wye transformers; therefore, the positive- and negativesequence equivalent circuits for these transformers also do not require phase shifts.

ZERO SEQUENCE IMPEDANCE OF POWER TRANSFORMER

The zero-sequence impedance of a transformer is controlled by a number of factors. The best way to determine a magnitude of this impedance is by an actual test, but the following comments, supplemented by information in some of the references, may be used to predict a value that is close enough for many applications.

First, the zero-sequence impedance seen looking into a transformer depends upon the configuration of the winding. The zero-sequence impedance of a delta winding is infinite (an open circuit), whereas the zero-sequence impedance of a wye-connected winding is a series composite of the zero-sequence impedance of the transformer and the impedance of any neutral grounding devices that might be present.

Thus, an ungrounded wye winding would present an infinite zero-sequence impedance because the absence of a neutral grounding connection appears as an open circuit in series with the zero-sequence impedance of the transformer winding itself (see Figure 2-7b).

Figure 2-7b—Zero-sequence equivalent circuit for delta-wye-grounded transformer


NOTE—The circuit is open on the side corresponding to the delta winding on the physical transformer


The impedance of the transformer itself depends upon several factors in the construction of the transformer. Three-phase transformers, which are constructed so that a closed, low-impedance path exists for the flow of zero-sequence flux within the transformer, have a lower zerosequence impedance than transformers without such a path.

One such path is the transformer core. Transformers with core-form construction have lower zero-sequence impedances than units with shell-form cores.

Three-phase transformers with delta windings have the lowest zero-sequence impedance, and in the absence of actual test data, it is often assumed that the zero-sequence impedance of core-form transformers with delta windings is about 0.85 times the positive-sequence leakage reactance of such transformers.

The zero-sequence impedance of shell-form transformers has about the same magnitude as the positive sequence leakage reactance of such transformers. Conversely, a three-phase transformer bank consisting of three, single-phase transformers connected wye-wye has a very high zero-sequence impedance.

CURRENT TRANSFORMER ACCURACY CLASSIFICATION FOR RELAYING

Since a current transformer has a magnetic core, it may not have a linear operating characteristic over the desired operating range of primary current. This results in a variation of ratio and possible variation of phase angle between primary and secondary currents for different values of primary current.

This phenomenon is called saturation. In addition to magnitude of ac current, factors that affect this saturation are the following.

Transient Current
The transient dc component of short circuit current is a major cause of current-transformer saturation and consequent misoperation of some bus differential systems. The maximum flux density in the current transformer core, attributable to the dc component of fault current, varies with the time current of the dc transient.

Hence, the L/R ratio of the system impedance which determines the fault current should strongly influence the type of bus protective relaying which is selected. Typically the dc time constants for the different circuit elements can vary from 0.01 s for lines to 0.3 s or more for generating plants.

The nearer a bus location is to a strong source of generation, the greater the L/R ratio and resulting dc component of fault current.

Impedance of Secondary Current Transformer Leads and Associated Relays, Meters, and Auxiliary Current Transformers 
Lead resistance, as well as current transformer winding resistance, contributes to core saturation. Therefore, length of secondary lead runs should be held to a minimum.

However, location of a breaker and its associated current transformer is determined by physical requirements. Hence, the planning stage must ensure that the type and rating of current transformer and its location with respect to the protected bus are comparable with the proposed bus protection scheme.

Where lead runs are excessive, an increase in wire size or use of parallel conductors are means to reduce lead resistance. Location of the differential relay junction points in the breaker yard rather than at the relay location is also practiced.

The preferred practice is to use current transformers dedicated to bus differential protection only. If possible, connection of meters, auxiliary current transformers, and other relays in differential type bus schemes should be avoided since these devices introduce additional burden into the current transformer circuit.

Current Transformer Accuracy Classification for Relaying
ANSI/IEEE C57.13-1978, Requirements for Instrument Transformers, establishes relaying accuracy classifications for relaying current transformers. Because relaying current transformers must operate at high overcurrent levels, ANSI classifications define minimum steady-state performance at those levels.

Performance is described by an identification system which consists of a letter and a number selected from the following: (C, T) (10, 20, 50, 100, 200, 400, 800). The first term describes performance in terms relative to construction.

The C classification covers bushing current transformers with uniformly distributed windings and any other current transformer in which leakage flux has negligible effect on ratio error. Ratio correction at any current can be adequately calculated by knowing the burden and the excitation characteristic.

The T classification covers most wound-type current transformers and any other current transformer in which leakage flux has an appreciable effect on ratio. Ratio correction must, therefore, be determined by test.

The C and T classification is applicable to all tap sections of a current transformer winding. The second term of the classification is the secondary terminal voltage rating.

It specifies the secondary voltage that can be delivered by the full winding at 20 times rated secondary current without exceeding 10% ratio correction. Furthermore, ratio correction is limited to 10% at any current from 10 to 20 times rated current at any lesser burden.


The ANSI secondary voltage rating applies only to the full winding. If other than the full winding is used, the voltage rating is reduced in approximate proportion to turns used.

As an example, relay accuracy Class C100 means that ratio correction can be calculated and that it will not exceed 10% at any current from I to 20 times rated secondary current if the burden does not exceed 1.0 W (1.0 W times 5 A times 20 times rated current equals 100 V).

GAS ANALYSIS TRANSFORMER FAULTS

Electrical faults in oil-filled transformers usually generate gases, some of which are combustible. Many transformer faults in their early stages are incipient and deterioration is gradual, but sufficient quantities of combustible gases are usually formed to permit detection and allow corrective measures to forestall a serious outage.

Depending on the transformer oil preservation system, the gas may either be dissolved in the oil or enter the gas space above the oil. In certain types of transformer design that facilitate the accumulation of gas, it may be possible to install a gas detector relay. These relays are usually set to alarm for the presence of gas.

It is common practice to draw off samples of oil or gas for periodic analysis of combustible gas content. If there is a gas space in the oil preservation system, it is possible to directly draw off a sample of the gas and perform an on-the-spot analysis with a portable gas analyzer.

If there is no gas space in the transformer, it is necessary to analyze an oil sample for dissolved gas content by gas chromatography (see Bean and Cole [B69]).

The presence of key gases is an indicator of the location of the source of the gas

a) Hydrogen is generated by corona or partial discharges. The presence of other key gases can indicate the source of the discharge.

b) Ethylene (C2H4) is the key gas associated with the thermal degradation of oil. Trace generation of associated gases (ethane and methane) may start at 150 °C. Significant generation of ethylene begins around 300 °C.

c) Carbon monoxide and carbon dioxide are generated when cellulose insulation is overheated.

d) Acetylene (C2H2) is produced in significant quantities by arcing in the oil.

To interpret the results of the analysis, the relative ratios of key gases are used. There has been substantial work to define the best methods for interpreting the results and guidelines have been published in IEEE Std C57.104-1991 [B74] and IEC 60599: 1978 [B8].

Gas analysis on transformers should be made periodically by manual or automatic methods. The interval between tests may be varied according to size, importance, loading, and exposure to faults.

This test should also be made after protective relay or relief diaphragm operation and before reenergizing, if practical. It should be made on new transformers after installation and original loading.

GROUND FAULT PROTECTION OF POWER TRANSFORMERS

Faults in Δ-connected transformer windings
A residual relay, device 51N, as shown in Figure 8 and Figure 9, will detect ground faults within the Δ winding of the transformer and in the phase conductors between the CTs and the winding, when an external source of zero sequence current is available. Instantaneous overcurrent relays may be used, but sensitive settings will probably result in incorrect operations from dissimilar CT saturation and magnetizing inrush.

This can be avoided by using a short-time overcurrent relay with a sensitive setting. The scheme is particularly valuable in plants or systems where the transformers are remote from the circuit breakers. By using CTs at the circuit breaker, sensitive detection is obtained for cable, bus, Δ winding, and bushing faults.

A single window or doughnut CT supplying an instantaneous relay (as commonly used in motor protection) is secure, but is limited to cases of low and medium voltages where all three conductors can be fitted through the CT window.

Figure 8—Complete ground fault protection of a Δ-Y transformer using a residual overcurrent and differentially connected ground relay

Figure 9—Complete ground fault protection of a Δ-Y transformer using a residual overcurrent and directional relay


Faults in grounded Y-connected transformer windings
To successfully detect faults in grounded Y-connected transformer windings, the relay system should discriminate between faults internal and external to the protected zone. The ground differential relay, device
87G in Figure 8, typically an overcurrent relay, or the directional ground relay, device 67G, connected as in Figure 9, is satisfactory. Both relay schemes will operate correctly for any internal ground faults with the circuit breaker in the circuit to the grounded Y winding open or closed.

They will operate correctly with an external zero sequence current source, and they will not operate for external ground faults. The auxiliary CT is necessary if the phase and neutral CTs are of different ratio. Both schemes are particularly applicable where the ground fault current is limited and phase differential relays may not respond.

The device 67G operating coil or element current is zero for an external fault with CT ratios matched. Therefore, it is wise to select the auxiliary CT ratio to give positive nontrip bias to device 67G for an external ground fault (auxiliary CT secondary current slightly greater than the transformer neutral CT secondary current). Unequal CT action can produce residual error current during external phase faults. No transformer neutral current is produced and sensitive relays could misoperate.


Case ground
On a grounded neutral system, it is possible to isolate the transformer case from ground except for a single point. A CT and overcurrent relay at this grounding point would detect any internal ground fault or bushing flashover.

Although effective, several problems are encountered. The system should be tested periodically to determine that no accidental grounds have been added.

Incorrect operations can result from accidental grounds from power tools and transformer auxiliary equipment. Careful coordination between auxiliary equipment circuit breaker or fuse curves, arrester characteristics, and a time overcurrent trip relay can minimize this danger.

Impedance-grounded system
Transformer differential relays may not be sensitive enough to operate on ground faults where the transformer bank or system is grounded through an impedance. In these cases, it may be necessary to apply a sensitive time overcurrent relay in the transformer impedance-grounded neutral or a time overvoltage relay connected across the neutral impedance.

These relays should be coordinated with any feeder and line protection relays that they may overlap. It is possible to provide high-speed protection and to avoid the need for coordination by using sensitive product-type relays, which are connected to trip only for ground in the protected zone.

An overcurrent relay connected to a neutral CT is torque-controlled by the blocking contacts of a plunger-type instantaneous relay in the neutral of the main breaker CTs. Since the transformer differential relays may not operate for such ground faults within the differential zone, these ground fault relays must trip the source-side circuit breakers.

Ground relays also used for sensitive ground fault protection
The primary advantage of ground relays over phase relays is their sensitivity. In systems where the ground fault current is purposely limited, their use may be vital. Ground relays can normally be applied with sensitivities of 10% or less of full load current.

This compares very favorably with differential relays, whose pickup current may be from 20–60% of full load current under the most advantageous conditions. It is common practice in the United Kingdom and other countries influenced by the U.K. to protect all power transformers with the restricted earth relay.

The term restricted earth is an expression referring to a sensitive ground relay system that is designed to detect ground faults within a well-defined protective zone (similar to that in Figure 8)

CURRENT TRANSFORMER PERFORMANCE USED IN PROTECTIVE RELAYING

Current transformer steady-state performance can be calculated from ANSI accuracy classification for C type or excitation data supplied by the manufacturer for C and T types. The secondary voltage as given by the maximum fault current reflected on the secondary side multiplied by the connected burden should not exceed the assigned C accuracy class.

Conversely, the permissible current transformer burden for a given accuracy class can be calculated. Performance using excitation data calculates the excitation current at the secondary voltage, which should be a small percentage of the operating current.

For T-type transformers, the manufacturer should supply overcurrent ratio curves from 1 to 22 times normal current and for all standard burdens up to the one that causes a ratio error of 50%. The transient performance should consider the dc component of the fault current because it has far more effect in producing severe saturation of the current transformer than the ac component.

Before a current transformer reaches its saturation flux, it may still accurately reproduce the offset fault current for a short duration. The time to saturate is a function of magnitude of the short-circuit current and its offset, secondary burden, system time constant, and current transformer time constant and its characteristics.

The current transformers may saturate within the first half cycle at large fault currents. The remanence in the core is the result of a previous current interruption, at other than current zero. This can force the current transformer into saturation sooner than expected.

Time to desaturate is dependent upon the same parameters as the time to saturate and is on the order of five cycles, largely because of the power system time constant. If a current transformer is chosen based upon steady-state performance, current transformer saturation due to dc offset will not cause problems on the operation of time overcurrent relays, as long as the dc component decays to zero in the time the relay is expected to operate.

For high-speed relays, such as instantaneous relays, differential and distance relays, and other relay types operating in less than two cycles, the current transformers should be selected so as not to saturate in less than 2 cycles. The rms value of the distorted output current of a current transformer can be calculated.

Relays that respond to only the fundamental may be more seriously affected than what the rms value indicates. Selecting as high a ratio as an application will permit and series and parallel connections of current transformers are some of the means to reduce saturation.

Current transformers with an air gap have a fairly high exciting current and low residual flux and can be used in some differential schemes; however, their use is limited in the modern protective schemes.

Current transformer saturation, waveform of secondary current output for various degrees of saturation

CURRENT TRANSFORMER (CT) BURDEN SAMPLE CALCULATION

Higher ohmic burdens in the ct secondary circuit will tend to result in greater saturation of the core, and therefore, larger errors in the secondary current waveform. The reason for this is that a given secondary current requires more voltage from the ct for a higher burden, and the core flux density is proportional to the time-integral of this voltage.

When the core becomes saturated, significant current is diverted through the cts magnetizing branch, and the desired secondary current is reduced and distorted. Burden calculations are, therefore, necessary to ensure that ct accuracy limits are not exceeded.

The total ohmic burden on the ct is the vector sum of the ct winding resistance, the connecting lead resistance, the impedance of any auxiliary cts, and the impedance of the connected relays and meters. Impedances of devices connected in the secondary of an auxiliary ct should be reflected (multiplied by the square of the auxiliary ct ratio) to the primary side, when calculating the burden on the main ct. This is only accurate if the auxiliary ct is not saturated.

As a first check in making the burden calculation, it is common practice to add the individual burdens arithmetically rather than vectorially. In many cases, this approach is very accurate, particularly if the ct winding resistance and the connecting lead resistance comprise the bulk of the secondary burden.

However, if this method predicts poor ct performance, and if information on burden power factor is available, the less conservative, but more complicated, vectorial method should be used. Electromechanical relays are usually subject to saturation themselves, at high currents.

Coil impedances at the currents of interest (as opposed to rated current) should be used in the burden calculation. A table of burdens vs, current (burdens may be expressed either in ohms or volt-amperes) is usually provided in the relay instruction book, but information on the power factor is often incomplete. In this case, it is customary to assume a purely resistive burden.

With the ohmic burden determined, the next step in predicting ct performance is to determine the required ct excitation voltage by multiplying the calculated total ohmic burden (using the magnitude, in the case of vectorquantities) by the maximum expected secondary fault current.

The ct excitation characteristic is then used to determine the excitation current. The higher the excitation current, as a proportion of the expected secondary current, the worse will be the actual replication of the primary current waveform. If errors greater than 10% are indicated (or more conservatively, if the calculated excitation voltage is above the knee-point), then the application is suspect and measures to reduce the burden are advised.

Sample burden calculation
Consider the 1200/5 ct of figure 1 below applied under conditions of a 24 000 A maximum fault current as illustrated in below. First consider the circuit without the auxiliary ct and then with the auxiliary ct.

The relay time-overcurrent unit is to be set for 5 A, and the instantaneous unit for 40 A. The secondary current under maximum fault conditions is expected to be 24 000/240 = 100 A.


1200/5 ct: From figure 1, the winding resistance is 0.61 W
1500 ft of #10 wire: 1500 ft ´ 1.0 W/1000 ft ´ 2 = 3.0 W.
TOC unit: The relay instruction book indicates a burden of 490 VA at 20 times tap-value (5 A), or 0.049 W.
IOC unit: The instruction book indicates a burden of 0.007 W for this unit.
Total burden: The scalar addition of all burdens (a fairly accurate approach which also simpliÞes calculations), results
in 0.61 + 3.0 + .049 + 0.007, or about 3.7 W.
The required excitation voltage is, therefore, 3.7 ´ 100 = 370 V. This is well above the knee-point voltage of the ct, and
is at best a marginal application.
Consider now the same application with the addition of a 5:1, T200 auxiliary ct.
Auxiliary ct: According to the manufacturer, the internal burden of the auxiliary ct is 1.11 VA at 5 A. The ohmic burden
is, therefore, 1.11 W on the secondary side.
TOC unit: The reduced current requires that the TOC unit now be set on the 1 A tap. The burden at 20 times tap-value
current is given as 265 VA, or 0.66 W
IOC unit: The IOC unit burden at the new tap setting is given as 0.125 W.
Total burden on the auxiliary ct: Again using a scalar addition, the secondary burden on the auxiliary ct is 1.11 + 3.0
+ 0.66 + 0.125, or 4.9 W. The required excitation voltage from the auxiliary ct is 4.9 ´ 20, or 98 V, well within the
capability of a T200 ct.


Total burden on the main ct: Reflected to the primary the auxiliary ct secondary burden is 4.9/25, or 0.196 ohm. The total burden on the main ct is, therefore, 0.61 + 0.196, or 0.81 ohm. The required excitation voltage on the main ct is now 81 V, representing a dramatic reduction compared with the previous example.

It should be pointed out that in general, other factors such as dc offset in the primary current waveform, ct remanence, the operating characteristics of the connected relays etc., should also be considered. This may result in a requirement for better cts (or smaller connected burdens) than calculations of the above type would indicate.

CURRENT TRANSFORMER ACCURACY

The ANSI ct accuracy class is determined by a letter designation and a secondary terminal voltage rating. These effectively describe the steady-state performance. (See IEEE Std C57.13-1993, 6.4.1.)

The secondary terminal voltage rating is the ct secondary voltage that the ct will deliver when it is connected to a standard secondary burden, at 20 times rated secondary current, without exceeding a 10% ratio error.

Furthermore, the ratio correction shall be limited to 10% at any current from 1 to 20 times rated secondary current at the standard burden or any lower standard burden. The voltage rating given applies to the full winding ratio only.

If a tap is utilized on a multi-ratio ct, the voltage capability is directly proportional to the ratio between the tap value being used and the full winding capability, provided the windings are fully distributed around the core. This is usually the case with cts made after 1978, but not necessarily with cts made before that date.

For example, ct accuracy class C100 means that the ratio error will not exceed 10% at any current from 1 to 20 times rated secondary current with a standard 1.0 W burden (1.0 W times 20 times rated secondary current equals 100 V).

Almost all of the cts used for protective relay applications are covered by the C or K classification. This includes bushing cts with uniformly distributed windings and other cts with minimal core leakage flux.

NOTE - IEEE standard C values and standard burdens are listed in annex B.

The letter designation codes are as follows:

C indicates that the leakage ßux is negligible and the excitation characteristic can be used directly to determine performance. The ct ratio error can thus be calculated. It is assumed that the burden and excitation currents are in phase and that the secondary winding is distributed uniformly. (See 8.1.10 of IEEE Std C57.13-1993 for further detail.)

K is the same as the C rating, but the knee-point voltage must be at least 70% of the secondary terminal voltage rating.

T indicates that ratio error must be determined by test. The T class ct has an appreciable core ßux leakage effect and contributes to appreciable ratio error.

H, L are old ANSI classiÞcations. There were two accuracy classes recognized-2.5% and 10%. Cts were specified in the following mannerÑ10 L 200, 2.5 H 400, etc. The first number indicated the accuracy class
and the last number indicated the secondary voltage class. L cts were rated at the specified burden and at 20 times normal current.

H cts were rated at any combination of burden from 5 times to 20 times the normal current. These ratings are applicable only to old cts mostly manufactured before 1954.