Transformer Differential Protection 87T (PDIF) Explained

What 87T transformer differential protection is

Transformer differential protection compares what goes into the transformer with what comes out. Under normal conditions, and also for an external fault, the current entering one winding leaves through the others, corrected by the turns ratio and the vector group phase shift. If a significant difference appears, that current is flowing into a fault inside the zone bounded by the current transformers (CTs).

It is identified as follows in the three naming systems:

• ANSI/IEEE C37.2: 87, and by custom 87T for transformer.
• IEC 61850: logical node PDIF (differential protection).
• IEC 60617: the relay symbol with differential current; its exact representation depends on the drawing edition and the drafter.

It is the main transformer protection against phase faults, ground faults of sufficient magnitude, and faults in bushings and connections inside the zone.

Where it is applied

• Power transformers in transmission and distribution substations, at high and extra-high voltage.
• Generator step-up transformers, including those of solar plants, and large station service transformers.
• Medium-voltage industrial transformers where the cost of the equipment or process continuity justifies it.
• Autotransformers and three-winding transformers.

On small transformers, protection is usually limited to overcurrent and mechanical protections. The decision depends on size, importance and the owner’s philosophy, as described in IEEE C37.91.

How it works

1. Compensation. The numerical relay brings the currents of every side to a common base. It corrects the ratio mismatch between CTs (magnitude) and the vector group phase shift (for example, a Dyn11 shifts 30°). It also removes the zero-sequence current on the grounded-wye side, because an external ground fault makes it flow on one side only and would produce a false difference.

2. Percentage characteristic. With the currents compensated, the relay calculates:

• Differential current: the phasor sum of the currents of all sides, Id = |I1 + I2 + …|.
• Restraint (or stabilizing) current: a measure of the current flowing through the transformer. Each manufacturer defines it differently (average, sum or maximum of magnitudes).

The relay trips when Id exceeds a curve that rises with restraint. The characteristic usually has a minimum pickup and one or two slopes. The first slope covers errors proportional to load (CT error, tap changer range); the second, steeper slope provides stability on severe external faults in which a CT may saturate.

3. Harmonic blocking. When a transformer is energized, the magnetizing inrush current enters from one side only and the relay sees it as differential current. That current has a high second harmonic content, which the relay uses to block or restrain. Similarly, overexcitation produces current with fifth harmonic, which is used to prevent trips on overfluxing. Many relays also offer cross-blocking between phases or waveform-based methods.

4. Unrestrained element. Above a high level of differential current, the relay trips with no restraint or blocking. That way it is not delayed on a severe internal fault that, through CT saturation, could produce harmonics.

The trip goes to every breaker feeding the transformer, normally through the lockout relay 86.

Setting criteria

The settings come from the transformer and CT data and from the short-circuit study; there are no universal values:

• Rating, voltages and vector group from the nameplate, and the tap changer range, which sets the ratio error the first slope must absorb.
• Ratio and class of the CTs, their burden and their behavior on the maximum external fault.
• Maximum external fault current, to check stability, and minimum internal fault, to check sensitivity.
• Harmonic threshold, according to the manufacturer’s recommendation and experience with that core type; transformers with modern cores can produce inrush with little second harmonic.
• Unrestrained element above the maximum expected inrush current.

General sensitivity and security criteria are explained in protection setting criteria. The vector group compensation can be checked with our free 87T vector group compensation tool. The detailed calculation is part of the protection coordination study.

How each manufacturer implements it

The principle is the same, but the way it is put into the relay varies a lot:

• Siemens SIPROTEC (DIGSI) organizes the function by protected objects and sides, and derives the compensation from the transformer data.
• SEL (AcSELerator QuickSet) usually works with matrix compensation settings and tap values per winding, with several harmonic blocking and restraint options.
• Relion (Hitachi Energy 670/650; ABB 615/620) (PCM600) groups the differential with its compensation and harmonic blocks in the application configuration.
• GE Vernova (Multilin, EnerVista) defines the current sources and the transformer before enabling the element.
• Schneider MiCOM/Easergy (MiCOM S1 or Easergy Studio) sets the compensation and the characteristic in its own menus.

What changes is the definition of the restraint current, the shape of the curve, the blocking method (per phase, cross-blocking, averaging) and the way the compensation is expressed.

Why it trips or blocks

Trips and blocks seen in the field, and what to check first:

• Trip on energization: inrush with little second harmonic, a high blocking threshold or cross-blocking disabled. Also energization of a parallel transformer (sympathetic inrush).
• Trip with load or on an external fault: vector group or zero-sequence compensation configured wrongly, a CT with reversed polarity, wrong CT ratios entered in the relay or a saturated CT. The definitive check is the differential current under load: it should be almost zero.
• Trip on overexcitation: high voltage or low frequency, without fifth-harmonic blocking. It is coordinated with overexcitation protection 24.
• No trip or slow trip on an internal fault: harmonic blocking too sensitive, or a low-current ground fault in an impedance-grounded winding, which the 87T does not see. That is what restricted earth fault 87N is for.
• Open CT circuit or a test block not properly closed after maintenance.

Start by downloading the oscillography and the event report, and compare the compensated currents of each side.

How it is tested

With a secondary injection test set such as the Omicron CMC 356, the usual checks are:

• Magnitude and vector group compensation, injecting balanced currents on both sides that the relay must see as through current (differential close to zero).
• The minimum pickup and points on the percentage characteristic, on several slopes and phases.
• Second- and fifth-harmonic blocking, injecting currents with controlled harmonic content.
• The unrestrained element and operating times.
• The actual trip to every breaker and to the 86.

During commissioning this is completed with the on-load check: the differential currents measured by the relay must be small in every phase. Tests on the primary equipment are covered in power transformer testing.

Did your relay trip or block on this function and the cause is not clear? At Tiza Group we review the events and settings remotely. See remote relay configuration or contact us.

References

• IEEE C37.2, Standard for Electrical Power System Device Function Numbers, Acronyms and Contact Designations.
• IEEE C37.91, Guide for Protecting Power Transformers.
• IEC 60255-187-1, Functional requirements for differential protection (motors, generators and transformers).
• IEC 61850-7-4, logical node models (PDIF).
• IEEE C37.110-2023, Guide for the Application of Current Transformers Used for Protective Relaying Purposes.
• J. L. Blackburn and T. J. Domin, Protective Relaying: Principles and Applications.

Frequently asked questions