08 PROT4xx TransformerProtection r2

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Transformer Protection

Technical literature supporting this section:

H.J. Altuve Ferrer and E.O. Schweitzer, III (Editors), Modern Solutions for Protection, Control, and Monitoring of Electric Power Systems.Pullman, WA: Schweitzer Engineering Laboratories, Inc., 2010.

K. Behrendt, N. Fischer, and C. Labuschagne, “Considerations for Using Harmonic Blocking and Harmonic Restraint Techniques onTransformer Differential Relays,” in 33rd Annual Western Protective Relay Conference, Spokane, WA, October 17–19, 2006. Available atwww.selinc.com.

A. Guzmán, H.J. Altuve, and G. Benmouyal, “Power Transformer Protection,” in Electric Power Transformer Engineering , edited by J.H.

Harlow. Boca Raton: CRC Press, 2004, pp. 3-109 to 3-137.A. Guzmán, H.J. Altuve, and D. Tziouvaras, “Power Transformer Protection Improvements With Numerical Relays,” in CIGRE StudyCommittee B5 Colloquium, September 14–16, 2005, Calgary, Canada, Paper 119 of Preferential Subject One (Transformer ProtectionMonitoring and Control).

A. Guzmán, M.G. Gutzmann, and P.G. Mysore, “Integrated Transformer, Feeder, and Breaker Protection: An Economic and ReliableSolution for Distribution Substations,” in 35th Annual Minnesota Power Systems Conference, University of Minnesota, St. Paul, MN,

November 1–3, 1999. Available at www.selinc.com.

A. Guzmán, N. Fischer, and C. Labuschagne, “Improvements in Transformer Protection and Control,” in 62nd Annual Conference for Protective Relay Engineers, Texas A&M University, College Station, TX, March 31–April 2, 2009. Available at www.selinc.com.

A. Guzmán, S.E. Zocholl, G. Benmouyal, and H.J. Altuve, “A Current-Based Solution for Transformer Differential Protection – Part I:Problem Statement,” IEEE Transactions Power Delivery, vol. 16, no. 4, pp. 485–491, October 2001.

A. Guzmán, S.E. Zocholl, G. Benmouyal, and H.J. Altuve, “A Current-Based Solution for Transformer Differential Protection – Part II:Relay Description and Evaluation,” IEEE Transactions Power Delivery, vol. 17, no. 4, pp. 886–893, October 2002.

A. Guzmán, S.E. Zocholl, G. Benmouyal, and H.J. Altuve, “Performance Analysis of Tradit ional and Improved Transformer DifferentialProtective Relays,” in 36th Annual Minnesota Power System Conference, University of Minnesota, St. Paul, MN, November 7–9, 2000.

Available at www.selinc.com. IEEE Guide for Protecting Power Transformers, IEEE C37.91, IEEE Press, 2008.

IEEE Standard Requirements for Instrument Transformers, IEEE C57.13, IEEE Press, 2008.

IEEE Standard for General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers, IEEE C57.12.00, IEEEPress, 2010.

B. Kasztenny, M. Thompson, and N. Fischer, “Fundamentals of Short-Circuit Protection for Transformers,” in 63rd Annual Conference for Protective Relay Engineers, Texas A&M University, College Station, TX, March 30–April 1, 2010. Available at www.selinc.com.

M.J. Thompson, “Percentage Restrained Differential, Percentage of What?,” in 64th Annual Conference for Protective Relay Engineers,Texas A&M University, College Station, TX, 2010. Available at www.selinc.com.

M.J. Thompson, H. Miller, and J. Burger, “AEP Experience With Protection of Three Delta/Hex Phase Angle Regulating Transformers,” in33rd Annual Western Protective Relay Conference, Spokane, WA, October 17–19, 2006. Available at www.selinc.com.

1PROT4xx_TransformerProtection_r2












A transformer consists of a set of windings around a magnetic core. The windings are insulated from

each other and from the core. In addition, insulation must be provided to protect against a voltage

gradient from turn to turn on each winding. In operation, stresses can damage windings and

insulation and result in breakdown of the insulation and failure of the transformer. Some of the

hazards that can cause transformer failure are listed on this slide.

• Thermal cycling as the transformer loading changes can cause wear on insulation materials

and blocking as materials expand and contract.

• Vibration caused by magnetostriction as the flux in the core changes with each half cycle can

cause wear on insulation materials.

• Magnetic flux can induce eddy currents in parts of the windings, core, or support structures

and cause localized heating. Multiple core grounds can cause large circulating currents in the

core.

• Fault current flowing in the windings of the transformer produces huge forces that can

damage insulation and blocking structures. Fast clearing of through faults is important inminimizing the damage to the transformer.

• Heating of the insulation causes it to lose tensile strength and weaken over time.





The slide shows transformer failure statistics. These transformer failures generally refer to faults that

cause protection schemes to take the transformer out of service. We can see that nearly 60 percent of

transformer failures are attributed to breakdown of winding or tap changer insulation.

A related topic is transformer condition monitoring. Many of these failures could have been detected

prior to a fault occurring had there been monitoring of incipient failure indicators. As sophisticatedreal-time monitoring systems become more readily available, some of these systems are also being

used to take transformers out of service before a fault occurs.









The differential current caused by CT errors increases with the through-fault current (the current that

flows through the differential protection zone for an external fault). Based on this fact, researchers

developed the percentage differential element, which compares the operating current I OP with a

restraining current I RT that is a measure of the through current.

The slide shows that the operating current I OP is the magnitude of the sum of the currents entering thedifferential protection zone. The slide also provides the most common expressions for the restraining

current I RT . In these expressions, k is a scaling factor, usually equal to 1 or 0.5.





A percentage differential element generates a tripping signal if the operating current I OP is greater

than the minimum pickup current I PU and is also greater than a percentage of the restraining current

I RT . This percentage is defined by the slope SLP , a relay setting.

The figure shows the resulting single-slope operating characteristic as a scalar plot of I OP as a

function of I RT . The characteristic is a straight line with a slope equal to K and a horizontal straightline defining the element minimum pickup current I PU . The operating region is located above the

characteristic, and the restraining region is below the characteristic.

The figure also represents the operating current resulting from CT errors for external faults. For low

fault currents, the CTs behave linearly and the error current is a linear function of the restraining

current. For higher fault currents, the CTs saturate and cause a nonlinear growth of the operating

current.

The slope characteristic of the percentage differential element provides security for external faults

that cause CT saturation.





Researchers have developed several methods to improve the sensitivity of the percentage differential

element without sacrificing security. One method is the dual-slope differential characteristic shown in

the figure, which further increases relay security for high-current external faults to accommodate CT

saturation errors, thus allowing more sensitive settings. Some electromechanical differential relays

had a nonlinear characteristic for this purpose.





The adaptive characteristic shown in the figure is another method to improve sensitivity for internal

faults and security for external faults. The single slope increases when the fault detection logic

detects an external fault condition, adding security to the scheme.





There are many challenges to providing dependable and secure transformer differential protection.

We will discuss each of these challenges in detail.









Different numbers of turns and connections of transformer windings cause the instantaneous values

of the phase currents to be different. These currents have different amplitudes and may not be in

phase. Transformer differential protection schemes must compensate for the current differences and

may also need to remove the zero-sequence currents.

The figure shows the typical connections for power transformers, which include delta-wye, wye-delta, wye-wye, and delta-delta connections.

In wye-wye, delta-delta, and autotransformer connections, the primary and secondary phase currents

are in phase. However, wye-delta and delta-wye connections cause a phase shift between the primary

and secondary phase currents. The differential element must compensate for this phase shift.

The figure also shows the CT connections required by electromechanical transformer relays: a CT

delta connection on the wye side of the power transformer, and a CT wye connection on the power

transformer delta side.





There are many ways to carry out a delta-wye connection. IEEE C57.12.00 requires the high-side

voltage to lead the low-side voltage by 30 degrees. The figure shows one way to connect a

transformer according to this standard. The primary A-phase lead is connected to polarity of the

A-phase winding and the nonpolarity of the B-phase winding, both referenced to the wye winding

phase designations. Thus, this is a delta ia – ib, or DAB connection. Because the high-side delta has a

DAB connection and the low-voltage side is in wye, we refer to this transformer connection as theDABY connection. The DABY connection is the typical step-down distribution transformer

connection.

Other standards allow for phase shifts other than 30 degrees between primary and secondary

voltages. IEC 60076-1 describes these connections using two letters and a number. The first letter, a

D or a Y , denotes the connection of the high-voltage side. The second letter, a d or a y, denotes the

connection of the low-voltage side. The number indicates the multiple of 30 degrees by which the

low-side voltage lags the high-side voltage. For example: Dy5 means the high-voltage side is in

delta, the low-voltage side is in wye, and the low-side voltage lags the high-side voltage by 5 30°

= 150°. The transformer shown in this figure has a Dy1 connection according to this IEC standard.

The equation on the slide shows the relationship between the currents in each side of the powertransformer. Note that the turns ratio is not the same as the transformation ratio. There is a 3 factor.

Note also that there is a 30-degree phase shift between the high-voltage- and low-voltage-side

currents.





Another way to make a delta connection per IEEE C57.12.00 is to connect the polarity of the

A-phase winding to the nonpolarity of the C-phase winding and so forth. This connection is the delta

i A – iC , or DAC connection. The figure shows an example of a transformer with the resulting YDAC

connection. The high-side voltage leads the low-side voltage by 30 degrees, as required by the IEEE

standard. YDAC is the typical generator step-up (GSU) transformer connection.

The transformer shown in this figure has a Yd1 connection according to IEC 60076-1.

The equation on the slide shows the 30-degree phase shift between the high-voltage- and low-

voltage-side currents.









Electromechanical relays require connecting CTs in wye and delta, as appropriate, to mirror the

connections of the transformer and to compensate for the current phase shift, as shown in the figure.

The CTs of the delta side of the transformer must be connected in wye. The CTs of the wye side have

the same type of delta connection the transformer has on the other side.

Ideally, selecting CT ratios that exactly match the inverse of the transformer turns ratio (as shown onthe slide) compensates for the differences in transformer phase current amplitudes.





The available CT ratios typically do not provide exact ratio matching. Hence, differential relays

require secondary current scaling (also called ratio matching). Electromechanical transformer

differential relays have physical transformer taps for scaling the currents. Compensation is rarely

perfect because the number of available taps is limited.





Some electromechanical relays have internal auxiliary current transformers with multiple ratios.

Then, for two-winding transformer applications, the taps for two auxiliary CTs have to be adjusted.

Assume we call these taps TAP 1 and TAP 2. If the ratios of currents I 1 and I 2 to TAP 1 and TAP 2 were

the same, the relay would compensate for the difference as a result of the error resulting from using

standard CTs. Thus, in the ideal case, the following would be fulfilled:

In general, there is some deviation. This deviation—called mismatch—is calculated as the percent

difference between the two ratios with respect to the smallest ratio:

The above expressions can be rearranged into the form shown on the slide. This makes the choice of

the taps easy from a lookup table of tap ratios.

1 2

1 2

| | | | I I

TAP TAP

1 2

1 2

1 2

1 2

| | | |

Mismatch •100

| | | |min ,

I I

TAP TAP

MR I I

MRTAP TAP


Section 14a – Transformer Differential Protection








As mentioned earlier, the taps available in electromechanical relays are fixed and limited.

Digital transformer relays can fully compensate for the current amplitude differences resulting fromthe mismatch between the CT ratios and connections and the power transformer turns ratios andconnections. The relay applies the equation shown in the slide to calculate TAP values based on thetransformer MVA rating, transformer winding voltage ratings, and CT ratios and connections (wye or

delta). The relay uses the calculated TAP values to scale the secondary currents to a common base.The TAP value given by this equation is the secondary current that the relay measures when thetransformer is at maximum power capacity.

In this equation:

• TAP n is the TAP value for Winding n

• S MAX is the maximum transformer capacity in MVA (must be the same for all TAP ncalculations)

• V n is the phase-to-phase rated voltage of Winding n in kilovolts

• CTRn is the ratio of the CTs connected to Winding n

• C n is a factor that corrects the effective CT ratio considering the CT circuit connection. ForCTs connected in delta, C n = √3. For CTs connected in wye, C n = 1

The TAP setting specifies the nominal current at full load. Thus, TAP defines 1 per-unit current onthe transformer MVA base at each terminal of the differential element. If, for example, TAP is 5 forWinding 1, the differential element will see a measured Winding 1 current of 2.5 A at 0.5 times TAP.





Internal phase-shift compensation in digital relays allows connection of CTs in wye, as shown in the

figure. Advantages of the wye CT connection include:

• Differential protection does not require dedicated CTs

• Wye-connected CTs are easier to wire and troubleshoot than delta-connected CTs

• Lead burden for wye-connected CTs in a three-phase fault is three times less than for delta-

connected CTs, making CT saturation less likely

• Wye-connected CTs deliver true current information, while delta-connected CTs remove the

zero-sequence current and triplen harmonics. With wye-connected CTs:

You can use zero-sequence overcurrent elements when available in the transformer relay.

The phase and negative-sequence overcurrent elements of the transformer relay measure

the same current as that measured by other overcurrent elements supplied by wye-

connected CTs. With delta-connected CTs, the transformer relay elements measure

current times higher, which increases the chance of errors in coordinating with other

overcurrent elements.

The relay provides true oscillographic and metering information.





The figure shows a diagram of microprocessor-based relay compensation for a DABY (Dy1)

connected transformer. The relay applies TAP compensation to put the currents in per unit. It then

performs phase-shift compensation by mathematically transforming each current input to emulate the

transformer connections on the opposite side. As a result, transformer normal load conditions and

external faults do not cause differential current.





The figure shows the compensation corresponding to the wye side of the transformer. The scaled

samples of the Winding 2 phase currents IAW2, IBW2, and ICW2 are the inputs to the connection

compensation block. First, the relay applies the TAP compensation. Then the relay combines the

currents mathematically as they would be combined in a delta DAB CT connection. The equation

shown on the slide expresses the DAB connection compensation in matrix form. The relay divides

the resultant quantities by√

3 to eliminate the increase in amplitude caused by the subtraction of the phase currents. In the figure, the quantities without T or C appended to their names are the currents

measured by the relay. The quantities with T appended to their names are the quantities after TAP

scaling. The quantities with C appended to their names are the quantities after phase-shift

compensation. The DAB matrix compensation shifts the currents by 30 degrees and removes the

zero-sequence component of the secondary currents.





For the delta side of the transformer (see the figure), the relay applies the TAP compensation and

introduces no phase shift to mirror the transformer wye connection at the other side. This wye-

connection compensation is equivalent to multiplying the scaled currents by the identity matrix, as

shown in the equation.









For a delta-wye transformer, there is a discontinuity in the zero-sequence network as shown. For a

line-to-ground fault, the positive-, negative-, and zero-sequence networks are connected in series at

the point of the fault. For this example, the ground fault is external to the zone of protection.

For an external ground fault, the positive- and negative-sequence components enter and exit the zone

of protection, resulting in balance to the differential for these components (assuming that the phaseshift has been properly accounted for). However, for the zero-sequence component, the current

exiting the grounded side of the transformer is not balanced by current on the delta side of the

transformer. If this is not taken into consideration, the differential relay will see the zero-sequence

current as operate current and trip for an external ground fault.

Using delta compensation (which is required to compensate for the phase shift anyway) on the

grounded (wye) side of the transformer traps the zero-sequence current and blocks it from getting to

the differential relay. With electromechanical relays, the delta CT connection also removes the zero-

sequence current.









Magnetizing inrush occurs in a transformer whenever the polarity and magnitude of the residual flux

(assumed to be zero in the figure) do not agree with the polarity and magnitude of the steady-state

flux ( ss in the figure). Transformer energization is a typical cause of inrush currents. Sympathetic

inrush can occur when an adjacent transformer is energized. Recovery inrush occurs after a severe

fault (especially a three-phase fault) that has depressed the voltage is cleared.

The figure shows the voltage (v), flux ( ), and exciting current (i) waveforms during a magnetizing

inrush condition. The transformer is energized at zero on the voltage wave. The exciting current

increases when the total flux reaches the saturation value (corresponding to the knee point on the

vs. i curve).





The figure shows a typical example of magnetizing inrush current.

The main characteristics of inrush currents are as follows:

• High current magnitude, often exceeding the transformer rated current

• Generally contain dc offset, odd harmonics, and even harmonics

• Typical waveform consists of unipolar or bipolar pulses, separated by intervals of very low

current values

• Peak values of unipolar inrush current pulses decrease very slowly. Typically, the time

constant of inrush current is much greater than that of the dc offset component of the fault

current





The top graph shows that the magnetizing current shown in the previous slide contains a significant

amount of second harmonic.

Many transformer differential relays use the second-harmonic content to prevent misoperation on

inrush current. The bottom graph shows a case for which the content of second harmonic clearly

surpasses 60 percent of the fundamental component.

According to empirical results, a relay with an inrush detector with a threshold for second harmonic

of about 18 percent of the fundamental will differentiate inrush currents from actual fault currents in

most cases.





The magnetic flux inside the transformer core is directly proportional to the applied voltage and

inversely proportional to the power system frequency. Overvoltage and/or underfrequency conditions

can cause overexcitation conditions that saturate the transformer core.

Transformer overexcitation causes transformer heating and increases exciting current, noise, and

vibration. The protection scheme should disconnect a severely overexcited transformer to avoiddamage. A volts-per-hertz element (24) responding to the voltage/frequency ratio protects for

transformer overexcitation. On the other hand, differential element operation should be blocked

during overexcitation conditions.

This figure shows the exciting current recorded during a test of a single-phase 5 kVA, 230/115 V

laboratory transformer. The current corresponds to an overvoltage condition of 150 percent at rated

frequency. For comparison, the peak value of the transformer rated current is 61.5 A, and the peak

value of the exciting current is 57.3 A.





This table shows the most significant harmonics of the current signal depicted in the previous slide.

Harmonics are expressed as a percentage of the fundamental current component. The third harmonic

indicates overexcitation conditions, but it is filtered out by either the delta connection of the CTs or

the delta connection compensation of the differential element, or by a delta connection of the

transformer winding. The fifth harmonic is still reliable for detecting overexcitation conditions. You

can use the fifth harmonic to block differential element operation.





The harmonic content of the differential current serves to differentiate faults from inrush and

overexcitation conditions. Harmonics can be used to either restrain or block the transformer

differential element.

Harmonic restraint methods use harmonic components of the differential current to provide

additional differential element restraint. The presence of harmonics desensitizes the differentialelement. Harmonic blocking methods block the differential element when the ratio of the harmonic

content to the fundamental component of the differential current is above a preset threshold.

Other methods for discriminating internal faults from inrush conditions directly recognize the wave-

shape distortion of the differential current. These methods do not identify transformer overexcitation

conditions.

One group of wave-shape recognition methods identifies the time intervals during which differential

current is low. Another group of methods recognizes the presence of dc offset in the differential

current. An example of the latter form of wave-shape recognition, called dc ratio blocking, will be

presented later in this section.





A transformer protection relay with three phase differential elements may use independent harmonic

restraint, independent harmonic blocking, or common harmonic blocking:

• Independent harmonic restraint uses the differential current harmonics of each phase

differential element to restrain that phase element. Any measurable harmonic content

contributes to relay security

• Independent harmonic blocking uses the harmonic blocking element of each phase to

supervise the differential element of that phase. During an inrush condition, the relay may

misoperate if the harmonic content in one phase falls below the blocking element setting

• Common harmonic blocking provides greater security than independent harmonic blocking

by using the harmonic blocking element of any of the three phases to supervise all three of

the phase differential elements









Digital transformer differential elements may combine harmonic restraint and blocking methods witha wave-shape recognition technique. These relays include three differential elements that can beconfigured with independent or common even-harmonic blocking or independent even-harmonicrestraint. Additional features may include fifth-harmonic blocking and dc ratio blocking.

When the relay operates in the harmonic blocking mode, the differential elements use the first two

equations on this slide to generate a single-slope operating characteristic. Modifying these equations,the elements generate a dual-slope operating characteristic.

The differential elements use the second and fourth harmonics of the differential current to blockoperation for inrush conditions (third and fourth equations on the slide).

The differential elements use the fifth harmonic of the differential current to block operation fortransformer overexcitation conditions. The last equation on the slide defines the fifth-harmonic

blocking condition.

In these equations:

• I OP is the magnitude of the differential current fundamental component

• I RT is the restraining current

• SLP is the slope, a relay setting

• I 2, I 4, and I 5 are the magnitudes of the second, fourth, and fifth harmonics of the differentialcurrent

• K 2, K 4, and K 5 are constant coefficients





When the relay operates in the harmonic restraint mode, the differential elements use even harmonics

(second and fourth) in a restraint scheme.





The figure shows a percentage differential element with even-harmonic restraint:

• Inputs to the differential element are the filtered, scaled, and compensated phasors

corresponding to the fundamental component of the phase currents and the second and fourth

harmonics of the differential current.

• The magnitude of the sum of the fundamental component currents forms the operatingcurrent IOP1. The scaled sum of the magnitudes of the fundamental component currents

forms the restraining current IRT1. The magnitudes of the second and fourth harmonics of

the differential current are used for blocking or restraint.

• Restraining current IRT1 is scaled to form the restraining quantity IRT1 (SLP ).

Comparator 1 and Switch S1 select the slope value as a function of the restraining current to

provide a dual-slope percentage characteristic. Harmonic current magnitudes are scaled to

form the second- and fourth-harmonic blocking and restraining quantities. Scaling factors

100/ PCT2 and 100/ PCT4 correspond respectively to K 2 and K 4 in the previous slides.

• Comparator 4 compares the operating current to the restraining quantity. Comparator 3

enables Comparator 4 if the operating current IOP1 is greater than a threshold value O87P ,which corresponds to the element minimum pickup current I PU .

• Comparators 5 and 6: Similarly, comparison of the fifth-harmonic differential quantity with

the operating current (not shown) provides the fifth-harmonic blocking signal.

• The differential element includes an unrestrained instantaneous differential element, which

provides very fast tripping for high-current internal faults. Comparator 2, which compares

the operating current IOP1 with threshold value U87P , provides this function.





The figure depicts the blocking logic of the differential elements. If even-harmonic restraint is not in

use, Switch S1 closes to add even-harmonic blocking to the fifth-harmonic and the dc ratio blocking

functions. In this case, the differential elements operate in a blocking-only mode. Switches S2, S3,

S4, and S5 permit enabling or disabling of each of the blocking functions. Output 87BL1 of the

differential element blocking logic asserts when any one of the enabled logic inputs asserts.





The figure shows the common harmonic blocking logic of the differential relay, which uses the

outputs of the blocking elements of all three phases to block relay operation.





The figure shows an adaptive differential element that increases its security after detecting an

external fault. The element includes one harmonic blocking and one harmonic restrained element.

The combination of both elements provides maximum operating speed and security. In this figure,

IAS corresponds to the Winding 1 A-phase current, and IAT corresponds to the Winding 2 A-phase

current.

The harmonic blocking element (upper part of the figure) includes common second- and fourth-

harmonic blocking and independent fifth-harmonic blocking for improved security. The harmonic

restrained element (lower part of the figure) adds the second and fourth harmonics of the differential

current to the restraining current and also includes independent fifth-harmonic blocking. Switches S1

and S2 allow selection of harmonic blocking, harmonic restraint, or both.

The adaptive differential element discriminates between external and internal faults. For external

faults, the element switches the slope of its operating characteristic from the lowest value (SLP1) to

the highest value (SLP2) to increase security for CT saturation. The differential element also includes

open CT supervision.





During heavy load conditions, phase differential elements can be insensitive to turn-to-turn faults. A turn-to-

turn fault in a transformer winding creates a highly localized fault current, which reflects as a small current at

the transformer terminals. For example, with only 5 percent of the transformer turns shorted, 1,000 A at the

fault would produce only 50 A primary (approximately). Phase differential protection may not detect the fault

until it grows and involves more turns or until the fault flashes to the tank, the core, or another winding.

Sequence component overcurrent, directional, and differential elements are highly sensitive for detectingunbalanced faults in distribution and transmission line applications. Similarly, sequence component differential

elements improve transformer protection.

As shown in a previous slide, the negative-sequence current of an unbalanced external fault flows through the

differential zone and, if the relay performs current scaling and phase-shift compensation correctly, sums to

zero. We can use this principle to create a negative-sequence percentage differential element (87Q). This

element calculates the operating and restraining negative-sequence currents and checks these currents against a

percentage differential characteristic.

For unbalanced internal faults, the compensated negative-sequence currents do not sum to zero. Because

normal load flow has very little negative-sequence content, the element will not be restrained by the load

current. Hence, the 87Q element is very sensitive to unbalanced internal faults, including turn-to-turn faults.

The 87Q element must be secure for differential current caused by inrush, overexcitation, and CT saturation.

Harmonic blocking provides 87Q element security for inrush and overexcitation conditions. An external fault

detection logic blocks the 87Q element for external faults. This logic improves element security when CT

saturation causes false negative-sequence currents and the restraint alone is not sufficient to guarantee security.

The 87Q element uses a minimum delay of two cycles to ride through transients.





As mentioned earlier, for internal faults, the harmonics caused by CT saturation could delay the

operation of transformer differential elements that have harmonic restraint or blocking.

To prevent delayed tripping for high-level internal faults with CT saturation, most transformer

differential relays include a high-set instantaneous unrestrained differential element. This element

responds to the magnitude of differential current only, so it is much faster than the percentagedifferential elements. This element must be set high enough not to operate on inrush current or for

worst-case through faults with CT saturation.









Transformer differential protection provides excellent sensitivity for phase-to-phase and most phase-

to-ground winding faults.

The figure shows the phase and neutral currents (in percentage of the transformer rated current) for

staged ground faults at different winding locations in a single-phase, 5 kVA, 230/115 V transformer.

In this test, we applied only 9 percent of the transformer rated voltage to limit the fault current. The phase current is low when the fault is close to the neutral. Differential elements, which respond to

phase current, have low sensitivity for ground faults close to the transformer neutral. On the other

hand, the neutral current is very high for these faults. Restricted earth fault (REF) protection, which

responds to neutral current, can detect ground faults close to the transformer neutral quickly and

reliably.





The figure shows an REF element connected to protect a two-winding transformer. The relay uses

the phase currents to calculate the Winding 1 residual current I RW 1. Then, the relay multiplies this

current and the secondary neutral current by the corresponding CT ratios to calculate currents I X and

I Y in amperes primary. Finally, the relay calculates T using the equation shown on the previous slide.

For the external ground fault shown in this figure, I X and I Y are 180 degrees out of phase, and T is

negative. For internal ground faults, I X and I Y are in phase, and T is positive.

The REF element includes logic (not shown in the figure) to ensure element operation for internal

faults when the wye-side breaker is open ( I X = 0) or when the external system has no ground sources.









The magnetic flux inside the transformer core is directly proportional to the applied voltage andinversely proportional to the power system frequency. Overvoltage and/or underfrequency conditionscan cause overexcitation conditions that saturate the transformer core. Transformer overexcitationcauses transformer heating and increases exciting current, noise, and vibration. Damage due tooverexcitation is caused by excess flux seeking a path through structural steel not designed to handleit. The eddy currents induced in these structures can cause severe localized heating. The flux density

in the core of a transformer is a function of the volts per turn applied and the frequency. Becausemodern transformers are designed to operate at peak flux for maximum efficiency, they can becomeoverexcited at very low levels of overvoltage.

Generator step-up transformers can experience overexcitation if the field is applied when the unit isturning at subsynchronous speed. These transformers are also in danger in the event of a loadrejection when the unit is supplying significant amounts of reactive power to the system.

Transmission transformers can also experience overexcitation during system islanding conditionswhen local reactive power generation exceeds system requirements. Another cause of overexcitationin transmission transformers is the Ferranti effect. Long transmission lines with large distributedcapacitance can cause overvoltage conditions during lightly loaded conditions because of capacitivevoltage rise.

Older transformers on the system may have lower nominal voltage ratings than present systemoperating conditions. For example, a transformer with a 67 kV nominal rating can be used on a69 kV system if the transformer no-load tap changer is set on the 2.5 percent higher tap. This will

provide a nominal rating of 68.7 kV. However, by choosing a higher tap, the voltage on thesecondary side is reduced. If transformer taps are not set correctly or if the system is operated athigher voltages, these transformers can easily become overexcited and fail prematurely.





According to IEEE C37.91, transformer overexcitation can occur when the ratio of the per-unit

voltage to per-unit frequency at the secondary terminals exceeds 1.05 at full load, 0.8 power factor, or

1.1 at no load. Transformers may temporarily exceed their continuous volts-per-hertz capability.

Transformer manufacturers provide information on the short-term volts-per-hertz capability as a

function of time. The overexcitation limit is either a curve or a set point with a time delay.

During overexcitation, the increase in exciting current can cause the transformer differential element

to operate. However, the differential element may not operate for some overexcitation conditions that

could damage the transformer, or it may operate too quickly. Transformers typically withstand

overexcitation conditions longer than differential element operating times. Premature tripping of a

transformer during a system disturbance can make the situation worse. In digital transformer relays,

you can use fifth-harmonic blocking to prevent differential element tripping during transformer

overexcitation.

For transformer overexcitation protection, use a volts-per-hertz (24) element, especially on largenetwork transformers and GSU transformers. This element is available in multifunction transformer

relays that also include voltage inputs. The volts-per-hertz element uses the equation shown on the

slide to calculate the ratio of the measured voltage to frequency in per unit of the rated quantities,

which is proportional to the transformer magnetic flux. In this equation:

φ is the estimated magnetic flux value in pu

V is the measured transformer voltage

f is the measured frequency

V NOM is the transformer rated voltage

f NOM is the rated frequency





As mentioned earlier, transformers may temporarily exceed their continuous volts-per-hertz

capability. Transformer manufacturers provide information on the short-term volts-per-hertz

capability as a function of time.

This figure shows a volts-per-hertz element set to protect a generator and its step-up transformer

against overexcitation.









Traditionally, overcurrent protection was often the main protection for small transformers. This

approach precluded fast fault clearing because overcurrent elements must coordinate with protective

devices in adjacent zones. Thus, internal faults could cause severe damage to the transformer.

The low cost of modern relays makes differential protection feasible even for small transformers.

Because these relays do not need a dedicated differential CT circuit, differential protection withexisting CTs is possible in most installations.

Primary differential elements and sudden-pressure and Buchholz relays (discussed later in this

section) provide no backup for faults in adjacent zones. Overcurrent protection provides this backup;

it should coordinate with the transformer through-fault capability curves to take the transformer out

of service before damage from an uncleared external fault occurs.

Overcurrent protection can also provide backup protection that is independent of the transformer

primary protection, but at significantly reduced sensitivity and speed. Instantaneous overcurrent

elements can cover part of the transformer windings for high-speed backup of severe faults.

Overcurrent devices provide some transformer overload protection by detecting heavy transformeroverloads. For better overload protection and monitoring, we recommend using elements based on

transformer thermal models, discussed later in this section.





Through-fault current causes thermal and mechanical stresses that cause wear and can damage the

transformer. Mechanical effects, such as winding compression and insulation wear, are cumulative

and should be considered over the life of the transformer. The extent of damage from through faults

is a function of current magnitude, fault duration, and total number of fault occurrences.





This table shows four categories defined by IEEE C57.12.00 for liquid-immersed transformers, based

on the transformer nameplate rating.





IEEE C57.109 provides time-current curves that reflect transformer through-fault withstand

capability for transformers designed according to IEEE C57.12.00. IEEE C57.109 provides six

curves: one each for Category I and Category IV transformers and two each for Category II and

Category III transformers. Category II and Category III transformers have separate curves for

frequent and infrequent faults.





For Category III transformers, two through-fault protection curves apply, as the figure shows.

The left-hand curve reflects both thermal and mechanical damage considerations and may be used for

selecting feeder protective device time-current characteristics for frequent-fault incidence

applications (for example, faults occurring more than five times during the service life of the

transformer.) There are different curves for different transformer impedances.

The right-hand curve reflects primarily thermal damage considerations and may be used for selecting

feeder protective device time-current characteristics for infrequent-fault-incidence applications. This

curve may also be used for selecting a main secondary-side protective device (if applicable) and

primary-side protective device time-current characteristics for all applications regardless of the

anticipated level of fault incidence.





For Category IV transformers, a single through-fault protection curve applies, as shown in the figure.

This curve reflects both thermal and mechanical damage considerations and is to be used for

selecting protective device time-current characteristics for all applications regardless of the

anticipated level of fault incidence. There are different curves for different transformer impedances.





Primary-side instantaneous phase overcurrent elements (50) provide high-speed primary protection

for internal phase faults. These elements should trip the transformer high-side breaker and/or the

transformer lockout relay.

Primary-side inverse-time phase overcurrent elements (51) provide backup protection for internal

phase faults and also protect for phase faults between the transformer and the secondary-side main breaker. These elements should trip the high-side breaker and/or the transformer lockout relay.

The primary-side residual overcurrent element (51N) provides sensitive primary protection for

ground faults in the delta winding if the source is a grounded system. This element should trip the

high-side breaker and/or the transformer lockout relay.

The phase overcurrent elements on the delta side of the transformer are relatively insensitive to

ground faults on the wye side. The inverse-time ground overcurrent element (51G) provides primary

protection for these faults. Transformers do not remove negative-sequence currents caused by ground

faults. Therefore, if a neutral CT is not available, a primary-side negative-sequence overcurrent

element (51Q) can provide primary protection for ground faults on the wye side and backup

protection for all other unbalanced faults. The 51G and 51Q elements should trip the high-side breaker and/or the transformer lockout relay.

Secondary-side inverse-time phase (51) and ground (51N) overcurrent elements provide primary

protection for secondary-side bus faults and backup protection for feeder faults. These elements

should trip the low-side breaker.





Fuses are an economical protection solution for small transformers: they are low cost and require

little maintenance. However, fuses provide limited primary protection against phase and ground

internal faults, for faults between the transformer and the secondary-side main breaker (if any) or for

the feeder breakers. Fuses can protect the transformer from damage from external faults. To provide

this through-fault protection, the fuse must coordinate with the transformer through-fault capability

curve. Fuses generally provide poor protection against overload conditions. Given these limitationsof transformer fuse protection and the low prices of digital transformer relays, we recommend

applying relay protection to small capacity transformers in distribution substations and industrial

installations.

Another inherent disadvantage of fuse protection is that fuses do not provide three-pole isolation. The

currents for unbalanced faults distribute differently depending on the phase shift of the transformer.

For many fault combinations, the current in one fuse is much higher than the current in other fuses,

so it opens first. Once a fuse opens, the fault can still be energized but in a single-phase condition.

The fault currents can be considerably smaller, resulting in either no operation or very slow clearing

of the remaining fuses.





For a phase-to-ground fault on the secondary side, two of the high-side fuses will detect the fault.

However, due to manufacturing tolerances, only one fuse will likely blow. Once that fuse opens, the

fault clears. However, the second fuse will have been damaged and is likely to blow unexpectedly

later under normal operating conditions, single phasing the system. Thus, it is generally

recommended that all fuses be replaced after a fault occurs.









Sudden-pressure and gas-accumulation relays provide partial redundancy for transformer differential

protection because they respond only to faults inside the transformer tank.

Sudden-pressure relays (63) use a diaphragm to monitor the pressure inside the transformer tank. A

small orifice in the diaphragm allows pressure to equalize as the pressure inside the tank changes

with thermal cycling. When a fault inside the transformer tank causes a sudden pressure change, thediaphragm moves, and a microswitch attached to the diaphragm closes a contact. Because the

monitored parameter is transient in nature, the relay includes either a seal-in auxiliary relay circuit or

a trip-and-seal-in auxiliary relay in the tripping circuit.

Sudden pressure relays come in two varieties, for use depending upon the type of transformer oil

conservation system.

Transformers with a constant volume (nitrogen blanket) or pressure regulated (nitrogen cylinder with

bleeder and regulator) systems use a cushion of dry nitrogen at the top of the tank to deal with

expansion and contraction of the oil. A gas-space-type relay that responds to changes in gas pressure

inside the tank is used with these transformers.

Transformers with constant pressure (oil conservator) systems use a conservator tank. There is no gas

inside the tank, and the oil is pushed into and out of a conservator tank to deal with expansion and

contraction of the oil. An under-oil-type relay is used on this type of transformer.





The sudden-pressure relay provides sensitive detection of faults that other transformer relays cannot

detect. Phase differential elements are relatively insensitive to turn-to-turn faults during high-load

transformer operation. Negative-sequence differential elements can detect turn-to-turn faults, but

these elements are not always available in transformer relays.

A turn-to-turn fault in a transformer winding constitutes a short circuit in an autotransformer.Transformer action still rules, so the highly localized fault current is reflected as a small current at the

transformer terminals. The phase differential protection may not detect the fault until the fault grows

and more turns are involved, or until the fault flashes to the tank.

Meanwhile, the high amount of energy dissipated in the fault arc creates a rapid buildup of pressure

inside the tank. The sudden-pressure relay is a very sensitive means of detecting this type of fault and

tripping the transformer.





Despite the sensitivity of sudden-pressure relays, many companies are reluctant to use them for

tripping due to their bad reputation for misoperation. A few of the causes of SPR relay misoperation

are listed on the slide.





Incipient transformer faults under oil typically generate combustible gases. In transformers with a

conservator-tank oil-preservation system, you should install a gas-accumulation relay on the pipe

connecting the transformer tank to the conservator tank to detect these gases and to provide early

warning. As gas accumulates in the chamber, a float drops down and closes a microswitch, usually

connected to alarm only. Gas-accumulation relays allow drawing off of the gas for analysis to

identify the problem.

The Buchholz relay is a variation of this type of relay. Buchholz relays include a flapper in the path

of the oil to the conservator tank. The flapper acts as a sudden-pressure relay, closing a contact if fast

pressure buildup inside the tank causes rapid movement of the oil. This contact typically is connected

to trip the transformer. The Buchholz relay may misoperate for the same reasons as sudden-pressure

relays. When it is connected to trip, you should apply the techniques described in the previous slides

to enhance security.





This slide and the next slide summarize the various transformer fault protection elements.

Phase differential elements (87) provide primary protection for faults inside the tank and at the

buswork inside the zone of protection. Their weakness is limited sensitivity to low-grade faults, such

as turn-to-turn faults, ground faults on impedance-grounded windings, and ground faults near the

neutral on effectively grounded windings.

Negative-sequence differential elements (87Q), if available, provide primary protection for turn-to-

turn faults.





REF elements provide fast primary protection for ground faults on grounded transformer windings. When REF

elements are not available, ground inverse-time overcurrent elements (51G) or negative-sequence inverse-time

overcurrent elements (51Q) provide this protection with time delay.

Sudden-pressure and Buchholz relays provide redundant primary protection for low-grade faults inside the

tank and backup differential elements for all faults inside the tank. It may be beneficial to block the sudden-

pressure or Buchholz relay for through faults.

Overcurrent elements (51/51N) provide primary protection for through-fault damage to transformers. They

also provide time-delayed backup to differential and sudden-pressure or Buchholz relays for internal faults

inside the tank and buswork inside the protection zone.

Applying all these protective elements provides comprehensive and redundant transformer protection. The 87,

87Q, and REF elements and the 63 relay provide complementary sensitive and high-speed protection.

Separating circuits and tripping paths avoids single points of failure, such as a lockout relay (86). Combining

50, 51/51N, 51G, and 51Q elements, which detect faults out of the transformer tank, with a 63 relay provides

redundancy to differential protection. Using multiple contacts in modern relays to directly trip all transformer

breakers eliminates the need for contact multiplication through lockout relays. See Chapter 13 of Modern

Solutions for Protection, Control, and Monitoring of Electric Power Systems for a discussion of eliminating

auxiliary relays to improve performance and reliability.

Documents

08 PROT4xx TransformerProtection r2