Illustrative example only. Values are simplified for teaching and are not settings for any real installation. The utility's technical interconnection requirements and the relay manufacturer's documentation govern every real setting.
The system
| Element | Data |
|---|---|
| Utility source at 12.47 kV | 6.0 kA available three-phase fault |
| Transformer | 1,500 kVA, 12.47 kV delta to 480Y/277 V, Z = 5.75% |
| Relay location | Transformer primary, also serving as the interconnection relay |
| Generation | Inverter-based solar on the 480 V bus |
| Downstream device | 480 V main breaker with short-time clearing of about 0.3 s at maximum fault |
Transformer full-load current: 1,500 kVA / (√3 × 12.47 kV) = 69.4 A on the primary.
Step 1. Select the CT ratio
The CT ratio is usually chosen before any setting, and it is chosen for the fault current, not the load current. A common rule of thumb for C-class relaying CTs is to keep maximum symmetrical fault current at or below 20 times the CT primary rating, then confirm with a burden and X/R saturation check.
- 100:5 looks right for load, but 6,000 A / 100 A = 60 times rating. The CT would saturate on a close-in fault, and the relay could see far less current than is flowing.
- 400:5 works: 6,000 A / 400 A = 15 times rating. The ratio is 80:1.
The cost is resolution at low current: full load is now only 0.87 A secondary. Modern microprocessor relays handle this easily, but it is worth confirming the relay's minimum pickup range.
Step 2. 51 time overcurrent pickup
Pickup must sit above maximum load and allowed overload, but below the minimum fault the element is expected to see. Here it is set at 150% of transformer full load:
- 1.5 × 69.4 A = 104 A primary
- 104 A / 80 = 1.30 A secondary
Step 3. Curve and time dial
The time dial comes from the coordination target, not the other way round. First find the largest fault the downstream breaker must clear, as the relay sees it:
- Source: √3 × 12.47 kV × 6.0 kA = 129.6 MVA
- Transformer: 1.5 MVA / 0.0575 = 26.1 MVA
- Combined: 21.7 MVA, which is 26.1 kA at 480 V, or 1,005 A at 12.47 kV
The main breaker clears in about 0.3 s. Adding a 0.3 s coordination margin gives a target of about 0.6 s at 1,005 A. With the IEEE very inverse curve, t = TD × (3.922 / (M² − 1) + 0.0982):
- M = 1,005 / 104 = 9.67
- Time per unit of TD = 3.922 / 92.5 + 0.0982 = 0.141 s
- TD = 0.6 / 0.141 = 4.27, rounded to 4.3 (operates at 0.60 s)
| Primary current | Multiple of pickup | Operate time (TD 4.3) |
|---|---|---|
| 208 A | 2.0 | 6.0 s |
| 520 A | 5.0 | 1.1 s |
| 1,005 A | 9.67 | 0.60 s |
The curve is then plotted against the transformer damage curve and the downstream breaker curves to confirm separation across the whole range, as shown in the protection coordination study example.
Step 4. 50 instantaneous
The instantaneous element has two lower limits and one upper limit:
- Above the through fault: 1,005 A × 1.3 margin for DC offset and tolerance = 1,307 A
- Above inrush: about 12 × 69.4 A = 833 A for 0.1 s
- Below the minimum primary-side fault it must clear quickly, here well above 2,000 A
Setting: 1,400 A primary, which is 17.5 A secondary.
Step 5. Voltage and frequency trip settings at the PCC
For the interconnection, overcurrent is not enough: as the coordination example shows, inverter contribution is too small for a primary 51 element to detect a utility-side fault. Separation relies on voltage and frequency. A useful starting reference is the IEEE 1547-2018 default trip settings for Category II equipment:
| Element | Pickup | Clearing time |
|---|---|---|
| OV2 (59) | 1.20 pu | 0.16 s |
| OV1 (59) | 1.10 pu | 2.0 s |
| UV1 (27) | 0.70 pu | 10.0 s |
| UV2 (27) | 0.45 pu | 0.16 s |
| OF2 (81O) | 62.0 Hz | 0.16 s |
| OF1 (81O) | 61.2 Hz | 300 s |
| UF1 (81U) | 58.5 Hz | 300 s |
| UF2 (81U) | 56.5 Hz | 0.16 s |
Two points catch people out:
- The utility sets the real values. Many utilities publish their own required settings, and they often differ from these defaults. The utility's technical interconnection requirements document always governs.
- Clearing time is not the relay delay. Clearing time includes the breaker. If the breaker takes 0.05 s, a 0.16 s clearing time means the relay delay is set near 0.11 s.
To enter the voltage settings, convert per unit to relay secondary volts. With 480:120 PTs on a 120 V secondary base, OV1 at 1.10 pu is 132 V, and UV1 at 0.70 pu is 84 V. Confirm whether the utility wants line-to-line or line-to-neutral measurement, and set the relay to match.
Step 6. Document the basis
The settings sheet is the deliverable the utility checks hardest. For every enabled element it should record the setting, the units, the CT or PT ratio used, and the reason for the value: the load, fault, inrush, or utility requirement it was set against. Settings without a stated basis are the most common source of utility comments. See how we handle this on our protective relay settings service.