Distance protection 21 (PDIS): how it works

What protection 21 (distance protection) is

Distance protection calculates the apparent impedance between the relay and the fault by dividing the measured voltage by the measured current. Under normal conditions that impedance is large, because it is dominated by the load. When a short circuit occurs, voltage drops, current rises and the measured impedance approaches the line impedance between the relay and the fault point. If that value falls inside a set zone, the relay trips.

It is named this way in the three systems:

• ANSI/IEEE C37.2: device 21, distance relay.
• IEC 61850: logical node PDIS (one instance per zone), usually accompanied by supervision and teleprotection scheme nodes.
• IEC 60617: symbol Z<, underimpedance.

Its great advantage over overcurrent protection is that its reach depends on the line impedance and much less on the short-circuit level of the grid, which changes with topology.

Where it is applied

• Transmission and subtransmission lines: it is the most common main or backup protection at HV and EHV, alone or combined with line differential (87L).
• Long or looped distribution lines, where overcurrent cannot achieve selectivity.
• Backup for transformers and generators, looking toward the grid or toward the step-up transformer.
• Solar and wind plants connected at high voltage, on the tie line to the system.
• Industry with its own HV lines or internal loops.

How it works

The relay measures six fault loops: three phase-to-phase and three phase-to-ground. For phase loops, the impedance is the phase-to-phase voltage divided by the difference of the currents. For ground loops, the compensated current is used:

Z = V_phase / (I_phase + k0 · 3I0), with k0 = (Z0 − Z1) / (3 · Z1)

where Z1 and Z0 are the positive- and zero-sequence impedances of the line. Without this compensation, the relay would see ground faults farther away than they really are.

Characteristics in the R-X plane:

• Mho: a circle through the origin; it is inherently directional.
• Quadrilateral (polygonal): independent reactive and resistive reach, with a directional line.
• Variants with cross-polarization or voltage memory, which keep the correct direction for close-in faults where the voltage drops almost to zero.

Stepped zones:

• Zone 1: underreaching, instantaneous, covers most of the line without reaching the remote bus.
• Zone 2: overreaching, time delayed, covers the rest of the line and part of the next one.
• Zone 3 or additional zones: remote backup, and sometimes a reverse zone for blocking logic or bus backup.

With teleprotection (POTT, PUTT, DCB and similar schemes) the relay accelerates the trip for faults at the far end. On top of that come logic functions such as switch-onto-fault (SOTF), echo and weak infeed, load encroachment and power swing blocking. You can read about this logic in direct transfer trip (DTT) and in the article on power swing blocking 68.

Setting criteria

Reaches are calculated with the real line parameters (Z1, Z0, length and mutual coupling) and verified with the short-circuit study. The criteria that matter most:

• Zone 1: a fraction of the line impedance, so that instrument transformer, line calculation and relay errors do not make it overreach. Common practice keeps it below 100 %, with a margin each utility defines.
• Zone 2: must reliably cover the whole line and coordinate in time with zone 1 of the adjacent lines, taking the infeed effect into account.
• Zone 3: remote backup, checking that it does not encroach on the maximum load region or operate on stable swings.
• Resistive reach: enough for the expected fault resistance and, at the same time, away from the load impedance.
• k0 factor: calculated with the line sequence impedances, in the format each manufacturer requires.
• CT and VT ratios, primary or secondary impedances and coordination times according to the coordination study.

The general criteria for 21 are in the guide to protection setting criteria. Final values come from the study and from the policies of the utility or transmission owner.

How each manufacturer implements it

The principle is the same, but each brand organizes it its own way:

• Siemens SIPROTEC (7SA, 7SD) with DIGSI: zones with polygonal or mho characteristics, residual compensation entered in different formats depending on the version.
• SEL (for example SEL-311, SEL-411L, SEL-421) with AcSELerator QuickSet: separate mho and quadrilateral elements for phase and ground, and programmable trip logic with SELogic.
• Hitachi Energy Relion (REL650, REL670) with PCM600: zones as function blocks connected in a graphical configuration.
• GE Vernova (Multilin UR, such as the D60; the D90Plus is discontinued) with EnerVista: distance elements with FlexLogic for the associated logic.
• MiCOM P44x (Schneider Electric Easergy MiCOM and GE Vernova MiCOM Agile) with Easergy Studio or MiCOM S1 Agile: zones with simplified or advanced settings depending on the selected mode.

The differences that cause most confusion in the field: whether k0 is entered as magnitude and angle or as RE/RL and XE/XL ratios, whether reaches are in primary or secondary ohms, how voltage memory is enabled and how each zone is assigned to the teleprotection scheme.

Why it trips or blocks

Typical situations we see when reviewing events:

• Loss of potential: an open VT fuse blocks the 21 or, if the supervision is not set correctly, causes a misoperation.
• Zone 1 overreach: miscalculated k0, CVT transients or mutual coupling on parallel lines.
• Underreach: infeed from another source or fault resistance larger than the resistive reach.
• Trip under heavy load: zone 3 or resistive reach encroaching on the load region.
• Trip on power swings without power swing blocking 68 enabled or set correctly.
• Reversed CT or VT polarity: faults seen in the opposite direction.
• Wrong settings group after maintenance.

The first thing to check is the oscillography: voltages, currents, the loop that operated and the calculated impedance against the set characteristic.

How it is tested

It is tested by secondary injection with a test set such as the Omicron CMC 356 and its distance module. In general terms, the test verifies:

• The reach of each zone at several angles, with shot tests and a search for the characteristic boundary.
• The operating time of each zone.
• The k0 compensation with single-phase faults.
• Directionality and voltage memory with close-in faults.
• Loss-of-potential supervision, switch-onto-fault and load encroachment.

With teleprotection it is completed with GPS-synchronized end-to-end tests at both ends, which check the whole scheme, including automatic reclosing 79.

Did your relay trip or block on this function and it is not clear why? 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 C37.113-2025, Guide for Protective Relay Applications to Transmission Lines.
• IEC 60255-121, Functional requirements for distance protection.
• IEC 61850-7-4, Compatible logical node classes and data object classes.
• J. L. Blackburn and T. J. Domin, Protective Relaying: Principles and Applications.
• G. Ziegler, Numerical Distance Protection: Principles and Applications.

Frequently asked questions