Reference values only — not for commissioning
This educational calculator creates transparent, illustrative current and time values for a transformer MV protection relay. It cannot determine approved protection settings or replace a protection-coordination study and the grid provider requirements.
1. Why protect a transformer from the MV side?
A transformer draws its rated current from the MV feeder while it supplies a much larger current on its LV side. MV current transformers feed a protection relay, which can detect phase overcurrent and some earth faults and trip the breaker. Its settings must be sensitive to the intended faults, selective with the devices upstream and downstream, and stable for normal operation and energization. In this tool 50 is instantaneous phase overcurrent, 51 time overcurrent, 50N instantaneous earth fault and 51N time earth fault; some installations need directional 67/67N or other functions.
2. Rated MV current
With three 100/5 A phase CTs that is 46.19 × 5/100 ≈ 2.309 A secondary. The CT ratio translates primary into secondary current; the ABB setting convention then expresses currents as multiples of In, the configured CT primary.
3. Estimated MV current during an LV short circuit
This is the theoretical MV-side current for a three-phase fault at the transformer LV terminals, with transformer impedance only and an ideal stiff MV supply. It is not the network short-circuit level: the source impedance, the tap, the voltage, impedance tolerances and the fault type change real currents.
4. Four illustrative pickups
| Element | Demonstration rule | Example (1600 kVA, 20 kV, 100/5 A) |
|---|---|---|
| 51 | 1.25 × rated MV current | 57.74 A |
| 50 | 1.30 × the LV short-circuit current at MV | 1000.74 A |
| 51N | 0.20 × earth CT primary | 20 A |
| 50N | 1.00 × earth CT primary | 100 A |
The multipliers are editable demonstration values, not IEC settings. Earth-fault currents cannot be inferred from kVA and uk: they depend on the network earthing and zero-sequence impedances. A high 50 setting may miss transformer-zone faults, and CTs may saturate at such currents.
5. Two earth-fault measurement methods
Calculated residual: the relay forms the phasor sum Ia + Ib + Ic of the three phase CTs (not the sum of the RMS magnitudes); CT mismatch and saturation can cause false residual current during heavy external faults. Dedicated core-balance CT (CBCT): a toroid around all three phase conductors with its own ratio, for example 100/1 A, compatible with the relay input; its placement and the cable-screen earthing matter. With 100/5 A phase CTs, 20 A primary earth current is 1.0 A secondary; with a 100/1 A CBCT it is 0.2 A. In some network earthing systems 50N/51N alone is not selective or sensitive enough.
6. The four IEC curve choices
| IEC curve | k | α | REF615 code |
|---|---|---|---|
| Standard/Normal Inverse (SI) | 0.14 | 0.02 | 9 |
| Very Inverse (VI) | 13.5 | 1 | 10 |
| Extremely Inverse (EI) | 80 | 2 | 12 |
| Definite Time (DT) | — | — | 15 |
At or below the pickup there is no finite time: the tool says no pickup instead of showing a negative or infinite time. 50 and 50N are definite-time stages with their own delays. The relay also has a minimum operate time (20 ms by default). Two different limits must not be confused. The IDMT saturation (levelling) point is a setting expressed in multiples of the start value (10 to 50, default 50): above it the inverse-time curve is levelled instead of falling further. The relay's measuring range is a separate limit expressed in multiples of In, the CT primary: above 50 × In the stated timing and accuracy are not guaranteed. KiloVolt applies the first to the reference time and flags the second separately.
7. How REF615 represents a setting
The relay setting is Start value in multiples of In, the configured CT primary. 57.735 A on a 100/5 A CT is 0.57735 × In; the PHLPTOC step of 0.01 makes it 0.58 × In, that is 58 A primary and 2.90 A secondary. The 50 example becomes 10.01 × In, 1001 A primary and 50.05 A secondary, which does NOT mean a 100/5 A CT reproduces 50 A accurately during a fault. Blocks: 51 PHLPTOC (0.05 to 5.00 × In, step 0.01), 50 PHIPTOC (1.00 to 40.00, step 0.01), 51N EFLPTOC (0.010 to 5.000, step 0.005), 50N EFIPTOC (1.00 to 40.00, step 0.01). A value outside a range is shown as not representable, never clamped.
Start value Mult (0.8 to 10.0, default 1.0) multiplies the start value only while the relay input ENA_MULT is active, typically during inrush blocking, and the relay refuses a combination whose product leaves the stage range. Io signal Sel chooses 1 = Measured Io (the dedicated CT, with its own ratio as In) or 2 = Calculated Io (the phase CT ratio). Source: ABB 615 series Technical Manual 1MRS756887 rev Q, version 5.0 FP1; check the real firmware and PCM600 configuration.
8. Worked operating time
The theoretical curve time at 500 A with the rounded 58 A pickup and TMS 0.10. It excludes relay tolerance (about ±5 % or ±20 ms for inverse times), output contacts and breaker travel, and it is no evidence of coordination.
9. What the tool cannot establish
- The real maximum and minimum MV fault currents or the inrush waveform.
- 50 sensitivity and selectivity between transformer-zone and LV faults.
- Correct 50N/51N thresholds in isolated, resonant-earthed or impedance-earthed networks.
- CT transient accuracy, burden and saturation at fault current.
- Coordination with the grid provider fuses or other relays.
- The actual IED application, analog-channel scaling and all setting interactions.
Final settings come from a protection study with real equipment and network data and the grid provider requirements. Never copy these examples into a live relay. Related: the CT & VT Sizing guide for CT burden and accuracy classes.