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The SEL-787 and SEL-487E Transformer Protection Relays are the latest additions to the

SEL complete line of transformer protection products, which includes the SEL-587 Current

Differential Relay and the SEL-387 series of current differential and overcurrent relays.

The SEL-487E is designed for more complex installations.

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In theory, differential protection is a straightforward undertaking. Following Kirchhoff’s

Current Law (KCL), the sum of all currents at any node in a circuit must equal zero. In our

example, n equals three, the number of circuits above. I1 + I2 + I3 = 0.

Current in must equal current out. Following our polarity shown above, I1 represents

current in, while I2 and I3 represent current out. The KCL equation can be rearranged to

represent current in and out. I1 – I2 – I3 = 0, or I1 = I2 + I3.

When applying differential protection, current transformers (CTs) are used to measure the

currents for all currents entering and leaving a circuit. If no faults exist within this

differential zone, the sum of the currents will equal zero.

The currents on this slide can be considered normal power flow; I1 is the source, and I2

and I3 are loads.

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This slide shows the behavior of the simplest differential scheme (using an instantaneous

overcurrent relay) during an external fault. If the CTs are considered ideal and identical, the

primary and secondary currents at both sides of the protected equipment are equal. IOP

above is the vector sum of the two secondary current phasors. IOP is called the operate

current and represents the difference between the two CT signals. For this condition, there

will be no operate or difference current.

Security of the differential relay is key. In other words, it is important that the differential

relay restrains, or does not trip, for faults external to its zone of protection.

Modern differential relays do not use a simple instantaneous overcurrent principle. This is

because any error current from CT saturation during an external fault will be measured by

the operate element, labeled 50 in the slide. Instead, relays employ a dual-slope percentage

differential protection.

Percentage differential protection provides more sensitive and secure protection than

traditional differential protection. The dual-slope characteristic compensates and provides

security for CT ratio (CTR) mismatches, CTR errors, CT saturation, and errors because of

tap changing.

Restraint in differential relays refers to some measure of through current in the CTs.

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For an internal fault, the primary currents allow the secondary currents to produce a

differential current through the overcurrent relay. If this operate (differential) current is

larger than the relay’s pickup, then the relay will trip both circuit breakers instantaneously.

• The characteristics of differential protection can be summarized as follows:

− Measures current entering and exiting the zone of protection

− Registers a fault if currents are not equal

• Differential protection provides:

− High sensitivity

− High selectivity

− High speed

Microprocessor relays include three differential elements (87R-1, 87R-2, and 87R-3).

These elements employ operate (IOP) and restraint (IRT) quantities that the relay calculates

from the winding input currents.

In traditional relays (SEL-587, SEL-387, and SEL-787), the percentage restraint

differential characteristic can be set as either a single-slope, percentage-differential

characteristic or as a dual-slope, variable-percentage differential characteristic. Tripping

occurs if the operate quantity is greater than the curve value for the particular restraint

quantity. A minimum pickup level for the operate quantity must also be satisfied.

The four settings that define the characteristic are:

• O87P = minimum IOP level required for operation (in per unit of tap)

• SLP1 = initial slope, beginning at the origin and intersecting O87P at IRT = O87P •

100 / SLP1

• IRS1 = limit of IRT for SLP1 operation; intersection where SLP2 begins

• SLP2 = second slope, must be greater than or equal to SLP1

By carefully selecting these settings, the user can closely duplicate the characteristics of

electromechanical differential relays that have been in use for many years.

Unrestrained elements (87U1, 87U2, and 87U3) compare the IOP quantity to a setting

value (U87P), typically about 10 times tap, and trip if this level is exceeded. Harmonic

blocking or restraint is not performed on the unrestrained elements. Use these elements to

protect transformer bushings and end windings, while maintaining security for inrush and

through-fault conditions.

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The chart on this slide shows the relation between SEL relay slope and transition point

settings. Because the characteristics vary between relays, the settings will need to be

different for the relays to operate the same. This is useful for replacing an older SEL relay

with a newer SEL relay.

In older relays, such as the SEL-587 and SEL-387, restraint current is defined as the sum of

winding current magnitudes in per unit or multiples of tap divided by two. In newer relays,

such as the SEL-787 and SEL-487E, the restraint current is defined as the sum of winding

current magnitudes in per unit or multiples of tap.

However, note that even if the SEL-487E is set as shown in the slide, it will not perform

the same because of the adaptive slope characteristic. This is shown on the next slide.

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The SEL-587, SEL-387, and SEL-787 relays use a dual-slope differential characteristic in

which both slopes are enabled during the same instant; which slope is used depends on how

much restraint current is measured. For lower magnitude faults, the more sensitive Slope 1

is active. For higher magnitude faults, the more secure Slope 2 is active.

The SEL-487E uses an adaptive-slope characteristic. Only one slope is enabled at any

given instant. Which slope is used depends on the relay’s external fault detector. For

internal faults, the more sensitive Slope 1 is active. For external faults, the more secure

Slope 2 is active.

This slide shows that the SEL-787 can be set to match either the SEL-587 or the SEL-387

relay characteristic, despite its restraint calculation being different from those relays. The

SEL-487E, however, cannot be set to match any of the previous relays precisely. This is

because the differences between the traditional dual-slope characteristic and the new

adaptive-slope characteristic cannot be aligned.

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In the previous slides, currents on the operate and restraint axes were in units of multiples

of tap or per unit of tap. What is tap?

Tap is a setting in a differential relay that specifies the nominal current at full load. In

electromechanical relays, the available taps are fixed and limited. The typical

electromechanical taps allow for a maximum five percent mismatch. The mismatch

generally compensates for the CTR mismatch between the transformer windings. In digital

relays, the available taps are continuous between the specified minimum and maximum.

In the equation on the slide, the term (MVA • 1000) / ( 3 • KVLL) merely defines the

primary transformer full-load current, where:

• MVA is the rating of the transformer, and KVLL is the voltage for that transformer

terminal.

• The full-load current is divided by the CTR to convert it to secondary amperes.

• The factor C is used to correct the effective CTR for the CT circuit. If the CTs are

connected in delta, the effective CTR is reduced by 3. If the CTs are connected in

wye, there is no compensation required, and C is 1.

Thus, tap defines one per unit current on the transformer MVA base at each terminal of the

differential element.

If, for example, the tap is 5 for Winding 1, the differential element will see a measured

current of 2.5 amperes associated with Winding 1 at 0.5 times tap.

In transformer differential protection, the protected equipment can introduce magnitude and

phase angle changes in the primary currents.

There are many ways to carry out a Y-D or D-Y connection. The ANSI and IEEE standard

indicates that the high-side voltage should lead the low-side voltage by 30 degrees. This is

represented by a vector diagram on the transformer nameplate. Keep in mind, this only

applies to transformers installed where the system phase rotation matches the phase-to-

bushing connection sequence.

The traditional European standard established a notation to describe these connections by

two letters and a number. The letter could be D, d, Y, and y. The first letter (capital), a D or

a Y, is used to denote the connection of the high-voltage (HV) side. The second letter

(lowercase), a d or a y, is used to denote the connection of the low-voltage (LV) side. The

number indicates the multiple of 30 degrees by which the HV side leads the LV side. For

example, Dy1 means the HV side is in delta, the LV side is in wye, and the phase-to-

neutral voltage of the HV side is 1 • 30 degrees = 30 degrees leading the phase-to-neutral

voltage of the LV side; in other words, angle(VA) = angle(Va) + 30 degrees.

The diagram shows the Dy1 connection. Note that the phase shift between the voltages is

the same as the phase shift between the currents.

This course material includes a number of real-world nameplate examples – this is a great

time to practice delivering the phase shift developed across a transformer. Remember, to

determine the phase angle relationship across the transformer, we need to know 1) the

transformer winding connections (from the nameplate), 2) the system phase rotation, and 3)

the phase-to-bushing connections.

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The 30-degree phase angle shift that we derived on the previous slide is with respect to the

primary transformer bushings, H1-H2-H3 and X1-X2-X3.

What phasors will be seen in the transformer secondary?

Remember the rules of current transformer polarity dots. When current enters the dot on the

primary, it leaves the dot on the secondary. In terms of phase angle for positive or forward

current flow, we can say that the secondary current has the same phase angle as the primary

current through the CT. However, when current leaves the dot on the primary, it enters the

dot on the secondary. In terms of phase angle for negative or reverse current flow, we now

say that the secondary current will have a 180-degree shift in phase angle compared with

the primary current.

The impact on our transformer applications is as follows. For wye-connected CTs with

polarity dots connected away from the transformer, as is typical, the HS primary currents

will lead the LS primary currents by 30 degrees for an ANSI DABY or IEC Dy1

transformer, but the HS CT secondary currents will lag the LS CT secondary currents by

150 degrees.

Ideally, the differential relay should see currents 180 degrees out of phase and equal in

magnitude for load current and through faults. If the currents are not 180 degrees out of

phase, the difference current will not be zero.

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When traditional electromechanical relays are used, the CTs must be properly connected, as

shown by the example in the figure on the slide. The CTs on the wye side of the

transformer should be connected in the same delta connection as the main transformer. This

will compensate for the angle shift across the transformer.

Note that in addition to the connection, there must be a certain relationship between the

CTRs such that they account for the magnitude shift across the transformer.

Ideally: 2

1 1 2

N 1 1

N CTR CTR

With numerical relays, it is recommended that users connect the CTs in wye and let the

relay calculate the delta compensation. This has several advantages:

• Dedicated CTs are not required for the differential protection.

• Wye-connected CTs are easier to wire and troubleshoot.

• Wye-connected CTs can use residual overcurrent protection, whereas delta-

connected CTs prevent this protection from being used on that input to the relay.

• With wye-connected CTs, the current that relay phase- and negative-sequence

overcurrent elements see is the same as that seen by other overcurrent relays supplied

by wye-connected CTs. With delta-connected CTs, these elements see current 3

higher. The difference in magnitude increases the likelihood of errors in coordination

with other phase- and negative-sequence elements.

• Wye-connected CTs see three times less lead burden for a three-phase fault than

delta-connected CTs, making CT saturation less likely.

• Wye-connected CTs place a lower burden on the CTs than equivalent delta-

connected CTs. For additional information, see SEL technical paper titled “Secure

Application of Transformer Differential Relays for Bus Protection,” by M.

Thompson, R. Folkers, and A. Sinclair. It is available at

http://www2.selinc.com/techpprs/6195_SecureApplication_MJT_20070607.pdf.

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The figure on the slide shows a typical connection diagram for a microprocessor-based

transformer differential relay.

The neutrals of the two wye-connected CTs do not have to be connected. The important

thing is that each CT must be connected to one, and only one, ground.

The vector diagram and phase shift assumes ABC system phase rotation.

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If wye-connected CTs are used, current magnitude and phase shift must be accomplished

internally through settings and relay algorithms.

Regardless of relay model or setting method, SEL relays incorporate compensation

matrices to properly align phase angles and remove zero-sequence currents when

necessary.

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This slide shows a delta-wye transformer with a 30-degree lag (ABC phase rotation). As

explained earlier, the available taps in digital relays are continuous between the specified

minimum and maximum. The relay divides the measured current on each input by its

associated tap setting to convert all currents to per unit quantities.

The relay then applies phase compensation. Because wye-connected CTs are used, the

relay combines currents mathematically in the relay to simulate the delta-connected CT that

would have been used in the traditional scheme. At this point, current in should equal

current out.

Note the designation of the DABY transformer as a Dy1. This is an alternative way of

describing the transformer connection. The transformer has Winding 1 = delta and Winding

2 = wye. Now imagine the face of a clock. In the phasor diagram on the slide, H1 is

pointing straight up at 12:00, and X1 is lagging by 30 degrees at 1:00.

The logic inside the relay functional diagram implies two main points. First, the secondary

currents are divided by tap, converting the units from amperes to per unit of tap. Second,

the relay compensates the currents by the appropriate compensation matrix.

A Y compensation is the same as matrix 0. A DAB compensation is the same as matrix 1.

There are 13 matrices, 1 through 12 and zero.

In this case, the Y or zero matrix does not change the phase angle of the current or remove

zero-sequence current. The DAB or matrix 1 shifts currents on an ABC system 30 degrees

in the counterclockwise (CCW) direction and removes zero-sequence current.

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When simulating a wye-connected CT on a delta transformer winding, no phase angle

compensation is required and the currents are only scaled by the tap.

The logic inside the relay functional diagram implies two main points. First, the secondary

currents are divided by tap, converting the units from amperes to per unit of tap. Second,

the relay compensates the currents by the appropriate compensation matrix.

A Y compensation is the same as matrix 0. In this case, the Y or zero matrix does not

change the phase angle of the current or remove zero-sequence current.

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When simulating a DAB-connected CT (for an actual wye-connected CT on the wye

transformer winding), the currents are first converted to per unit magnitudes and then

combined mathematically because they would be in a delta ĪA – ĪB (DAB) CT connection.

The resultant phasors are divided by the 3 factor to eliminate the increase in magnitude

caused by the delta phasor subtraction.

The logic inside the relay functional diagram implies two main points. First, the secondary

currents are divided by tap, converting the units from amperes to per unit of tap. Second,

the relay compensates the currents by the appropriate compensation matrix.

A DAB compensation is the same as matrix 1. There are 13 matrices, 1 through 12 and

zero.

The DAB or matrix 1 shifts currents on an ABC system by 30 degrees in the CCW

direction and removes zero-sequence current.

For differential element 1, the compensated current is I1W2C = (ĪA – ĪB) / ( 3 • tap).

For differential element 2, the compensated current is I2W2C = (ĪB – ĪC) / ( 3 • tap).

For differential element 3, the compensated current is I3W2C = (ĪC – ĪA) / ( 3 • tap).

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The most common transformer configuration is the ANSI and IEEE standard where the

high side leads the low side by 30 degrees. Other common connections include an

autotransformer or a delta-wye transformer where the low side leads the high side by

30 degrees. Other connections exist that produce various phase shifts. However, all of these

phase shifts occur in 30-degree increments over a full 360 degrees. Therefore, the angle

compensation settings in the SEL relays include 12 matrices (plus the identity matrix zero)

to allow for compensation across any transformer. The matrices will shift the angle on the

given winding by n • 30 degrees (n = matrix number) in the CCW direction for an ABC

system rotation and clockwise (CW) for an ACB system rotation. The identity matrix (M0)

produces no phase shift or zero-sequence current removal.

1M1

3

1 –1 0

0 1 –1

–1 0 1

1M2

3

1 –2 1

1 1 –2

–2 1 1

1M3

3

0 –1 1

1 0 –1

–1 1 0

1M4

3

–1 –1 2

2 –1 –1

–1 2 –1

1M5

3

–1 0 1

1 –1 0

0 1 –1

1M6

3

–2 1 1

1 –2 1

1 1 –2

1M7

3

–1 1 0

0 –1 1

1 0 –1

1M8

3

–1 2 –1

–1 –1 2

2 –1 –1

1M9

3

0 1 –1

–1 0 1

1 –1 0

1M10

3

1 1 –2

–2 1 1

1 –2 1

1M11

3

1 0 –1

–1 1 0

0 –1 1

1M12

3

2 –1 –1

–1 2 –1

–1 –1 2

For the transformer shown on the slide, an external phase-to-ground fault on the LV side

will result in zero-sequence current flowing through the LV CTs without a corresponding

current flowing through the HV CTs.

Because the fault is external, the compensated secondary currents, as seen by the relay,

need to be equal in magnitude and 180 degrees out of phase. Because the HV CTs will not

see any zero-sequence current, the zero-sequence current seen by the LV CTs needs to be

eliminated.

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As can be seen in the slide, the subtraction of currents that provides phase compensation

also eliminates the zero-sequence current. This is true for both delta-connected CTs and the

mathematical phase compensation done in digital relays.

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The SEL-787 and SEL-487E allow the user to enable the harmonic blocking (HB) and

harmonic restraint (HR) elements to operate in parallel. Because these schemes

complement each other, the user gains the benefits of both schemes.

Security for Inrush

HR adds to the effectiveness of percentage differential protection even if the harmonic

content is low. Common harmonic blocking (CHB) blocks if the harmonic content is

sufficiently high on at least one phase.

Security for External Faults

HR always uses harmonics from CT saturation for additional restraint. CHB blocks if the

even harmonic content is sufficiently high.

Speed for Internal Faults

HR adds additional restraint based on differential harmonic content. This requires

additional operate current for operation of the HR element. The operate threshold is not

modified in the CHB element, resulting in faster element operation for internal faults.

Dependability for Internal Faults During Inrush

Even harmonics from inrush on unfaulted phases may cause CHB to block element

operation until the inrush condition subsides. However, the HR element does not block the

element but rather adds restraint. Therefore, the HR element will operate faster when

energizing a faulted transformer.

The figure on the left-hand side of the slide shows a fault near the neutral of a grounded

wye winding, and the figure on the right-hand side of the slide shows the phase and neutral

current for ground faults near the neutral. Clearly, moving the fault location toward the

neutral increases the neutral current while decreasing the phase current.

For these types of faults, the phase differential element may not be sensitive enough for fast

fault clearing, especially at higher loads (due to the slope characteristic).

Restricted earth fault (REF) or zero-sequence differential, offers improved sensitivity for

these faults.

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The REF implementation in the SEL-787 uses a directional element (REF1F) that

compares the direction of an operating current derived from the neutral CT with the

polarizing current obtained from the line-end CTs. A zero-sequence current threshold and

positive-sequence restraint supervise tripping. REF can be applied to a single wye winding

in a transformer, to an entire autotransformer winding with two sets of line-end CT inputs,

or the wye winding of a delta-wye transformer. The neutral CT connects to a separate CT

on the SEL-787.

REF in the SEL-387 and SEL-487E relays is similar.

Use the REF element to provide sensitive protection against ground faults in a wye-

connected transformer winding. The element is restricted in the sense that protection is

restricted to ground faults within a zone defined by neutral and line CT placement. Because

it uses 3I0 and is immune to load, it provides better sensitivity than 87R.

The REF element takes advantage of directly measuring the current in the neutral bushing

of the transformer for its IOP current. It does not need to be set less sensitively to not

operate for a false residual current caused by CT saturation, as is the case with the residual

of the three-phase CTs at the boundaries of the zone.

The polarity of the neutral CT is critical to proper application. Commissioning tests should

verify CT polarity prior to putting the element into service. If this cannot be done, leaving

the REF element out of service until after the first external LG fault occurs is

recommended. Analysis of event data can confirm CT connections and polarity.

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Traditionally, sudden pressure relays are used in conjunction with all of the protections that

we have discussed previously to detect turn-to-turn faults.

The SEL-487E includes a new negative-sequence differential element to detect turn-to-turn

faults within the transformer windings. As shown on the slide, using phase current to detect

turn-to-turn faults may lead to faults being below normal differential element detection

levels. This is because the overall impact to the impedance of the transformer winding is

relatively small when viewed from the transformer bushings, but the fault current induced

in the faulted windings is the ratio of volt-ampere (VA) turns to shorted winding impedance

of the affected section. While the VA turns ratio is not that great compared to the overall

VA rating of the transformer, the shorted winding impedance can be quite small, resulting

in a very high-current flow through the shorted windings.

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The 87Q element uses negative-sequence quantities of IOP and IRT derived from the

winding currents. IOP is the sum of the HV and LV negative-sequence content. IRT is the

maximum negative-sequence magnitude from the selected windings. IRT provides restraint

under system unbalance conditions.

The negative-sequence differential element is supervised by the 87QB second- and fifth-

harmonic blocking logic as well as the CONn Relay Word bit for external fault detection.

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Because the 87R and REF elements do not provide protection for through faults, the

SEL transformer relays include several instantaneous and inverse-time overcurrent

elements to provide this protection. These overcurrent elements are set to protect the

transformer damage current and coordinate with downstream system overcurrent relays.

The graphic on this slide shows through-fault curves for Category IV transformers, as

published in IEEE C57.109-1993. These curves apply to transformers that are covered by

the IEEE standard or, in general, to transformers that were built beginning in the early

1970s. For transformers built prior to 1970, consult the manufacturer to obtain the

transformer short-circuit withstand capabilities.

The curves are a function of the transformer short-circuit impedance and are keyed to the

maximum I2t of the worst-case mechanical duty (maximum fault current for two seconds).

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Complicated phasing problems, CT connection problems, and setting problems are a few of

the many areas in which a mistake can be made in transformer installations. Therefore, SEL

has added a Commissioning Assistant to the ACSELERATOR QuickSet® SEL-5030

Software. This is compatible with the SEL-787 and SEL-487E Relays.

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It is most important to remember that the Commissioning Assistant is not a substitute for

proven testing methods for commissioning power transformers. It is available to assist, not

replace normal commissioning practices.

It is effective only for single-contingency wiring errors—one of the main reasons to

continue to check the installation!

Because we cannot rely on the accuracy of phase angle measurements of near-zero

magnitude phasors, a minimum amount of load current is required. Each phase current

must measure at least 250 mA secondary. When sufficient load current magnitude cannot

be guaranteed during transformer energization, primary injection testing prior to

energization remains a recommended commissioning practice.

Because of the extensive use of negative-sequence currents, the wiring error checks are not

effective if the load is substantially unbalanced.

The wiring error test does not include tests for the neutral CT.

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The Commissioning Assistant calculates matching matrices to set the differential element

for transformer protection. This is its primary function. However, before the algorithm

calculates the matrices, it checks for three common wiring errors: incorrect CT polarities,

inconsistent CTRs, and crossed-phase wiring. Although these checks are single-

contingency and subject to system conditions (see previous slide), they will assist in finding

some errors. However, these tests have limitations, so the installation must still be tested

thoroughly!

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Using the Commissioning Assistant within ACSELERATOR QuickSet is easy. Simply select

the Commissioning Assistant from the Tools tab in QuickSet, and start by defining the one-

line diagram of the transformer and interconnecting breakers. Once the one-line diagram is

complete, select the winding CTs that will be used as differential element inputs to the

relay.

34

Once the one-line diagram is generated from the transformer and CT configuration screens,

define and select the relay reference and test winding inputs. The Commissioning Assistant

uses one winding input as the reference from which the proper winding compensation

setting will be determined and checks for the proper CT polarity, CTR, and phase

connections.

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Validation testing verifies adequate current flow, CTR, and polarity before beginning the

test. Failure of any validation item results in a flag indication of the specific problem.

The Commissioning Assistant, like any commissioning test, requires a minimal amount of

current before phase angle measurements can be trusted (> 250 mA secondary per phase).

36

The Commissioning Assistant then reads the current magnitudes and angles from the relay

and compares them with the compensation settings and CTRs used in the relay.

If the Commissioning Assistant finds no problems with the polarity, CTR, or phase

relationships, it generates a screen under the Matrix Report 1 tab showing the operating

current (IOP) and restraint current (IRST ) for all 12 possible compensation matrices. The

Commissioning Assistant selects the matrix with the lowest IOP as ideal for the transformer

application.

The Matrix Report Data can be saved to document the commissioning test results.

37

Main comparison points are shown in the next three slides to contrast the application of the

various transformer differential relay options.

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