Generator differential protection (ANSI device number 87G) is a unit protection scheme that compares the current entering and leaving a generator's stator windings to instantly isolate internal phase-to-phase or phase-to-ground faults. In a real installation, it changes the outcome of a catastrophic internal short by clearing the fault in under 50 milliseconds, limiting stator core melting and preventing mechanical shaft torsional damage. Beginners commonly confuse 87G with overall generator differential (87O), which includes the step-up transformer in the protected zone, or with voltage-restrained overcurrent (51V), which reacts to external faults and operates much slower.
The Core Physics of ANSI 87G Differential Protection
The operating principle relies on Kirchhoff’s Current Law applied to the generator stator. Current transformers (CTs) are installed at both the neutral end and the terminal (output) end of each stator phase. Under normal load or external fault conditions, the current flowing into the winding equals the current flowing out. The relay measures the vector difference between these two CT secondary currents. If the differential current exceeds a programmed threshold, the relay trips the generator breaker and shuts down the prime mover.
Because CTs are never perfectly matched and slight ratio errors exist, modern digital relays (like the SEL-700G or Beckwith M-3425A) use a percentage differential characteristic. This means the relay requires a higher differential current to trip when the overall through-current (load) is high, preventing false trips caused by CT saturation during external grid faults.
Relay Settings and Current Transformer (CT) Data
Setting an 87G relay requires balancing sensitivity (catching high-impedance faults near the neutral) with stability (ignoring external through-faults). The table below outlines standard baseline settings for a medium-voltage or large low-voltage industrial generator.
| Parameter | Typical Setting Range | Engineering Rationale |
|---|---|---|
| Minimum Pickup (Ipu) | 10% to 20% of CT primary | Sets the absolute minimum fault current required to trip. Lower values protect more of the winding near the neutral point but risk nuisance trips from CT mismatch. |
| Slope 1 (S1) | 10% to 15% | Compensates for normal CT ratio errors and tap changer variations at low-to-medium load currents. |
| Slope 2 (S2) | 25% to 40% | Engages at high through-currents to prevent false tripping when CTs saturate during severe external grid faults. |
| CT Accuracy Class | C200 or C400 (ANSI) | Ensures the CT secondary voltage does not collapse (saturate) before the relay has time to process the fault and issue a trip signal. |
| Harmonic Restraint | 15% to 20% (2nd harmonic) | Blocks tripping during generator energization (magnetizing inrush), though less critical for generators than for transformers (87T). |
For reliable operation, the CTs on the neutral and terminal sides must ideally be identical in ratio, burden, and accuracy class. Mismatched CTs force you to raise the minimum pickup setting, leaving a portion of the stator winding unprotected near the neutral grounding point.
Worked Numeric Example: Sizing and Setting an 87G Relay
Let’s calculate the settings for a typical commercial backup generator: a 625 kVA, 480V, 3-phase, 60Hz diesel genset with a solidly grounded neutral.
Step 1: Determine Full Load Amperage (FLA) and CT Ratio
- FLA: 625,000 VA / (1.732 × 480V) = 752A primary.
- CT Selection: We select a 1000:5 CT ratio. This gives us a secondary FLA of 752 × (5/1000) = 3.76A, which sits perfectly in the middle of the relay's 5A nominal input range.
Step 2: Set the Minimum Pickup (Ipu)
We want to protect at least 85% of the stator winding. A standard pickup is 15% of the CT secondary rating.
- Ipu: 15% of 5A = 0.75A secondary (equivalent to 150A primary).
Step 3: Analyze an Internal Fault Scenario
Assume a solid phase-to-ground fault occurs inside the stator winding. The generator is isolated from the grid (islanded). The fault draws 3,000A primary from the neutral point, but because the generator terminals are open to the grid, the terminal CT sees 0A.
- Neutral CT Secondary: 3,000 × (5/1000) = 15A.
- Terminal CT Secondary: 0A.
- Differential Current (Id): |15A - 0A| = 15A.
- Restraint Current (Ir): (|15A| + |0A|) / 2 = 7.5A.
The relay evaluates the trip condition: Is Id > Ipu? Yes (15A > 0.75A). Is Id above the Slope 1 line? The Slope 1 requirement at 7.5A restraint is 7.5A × 15% = 1.125A. Since 15A is vastly greater than 1.125A, the relay issues a trip signal in roughly 15 to 25 milliseconds, dropping the generator breaker and commanding the engine ECU to shut off fuel.
Where You Meet This in Practice
You won't find ANSI 87G on a portable 5kW jobsite generator or a standard residential solar inverter. The cost of the CTs, the mult-function relay (typically $1,500 to $4,000), and the control wiring only justifies the protection on larger assets. You will encounter it in these specific environments:
- Data Center and Hospital Backup Gensets: Any generator rated above 500kW or operating in parallel (mission-critical Tier III/Tier IV facilities) requires 87G per NFPA 70 (NEC) and insurance mandates to prevent a single stator failure from cascading into a total bus blackout.
- Microgrid Grid-Forming Inverters: Modern utility-scale battery energy storage systems (BESS) use grid-forming inverters that emulate synchronous machines. These inverters implement 87G in software, using internal current sensors to protect the inverter's internal inductors and output filters from phase faults.
- Rotary UPS Systems: Large flywheel or diesel-rotary UPS units use 87G to protect the integrated generator windings, ensuring the system can safely transition to battery or bypass without destroying the rotating mass.
Common Confusions and Troubleshooting False Trips
When a generator trips on differential, operators often misdiagnose the root cause. Here is how to separate real internal faults from instrumentation errors.
87G vs. 87O (Overall Differential)
If your generator has a unit-connected step-up transformer (e.g., 480V to 12.4kV) and the protection zone includes both the generator and the transformer, that is 87O. 87O must account for transformer phase shifts (Dyn11 vector groups) and magnetizing inrush. 87G is strictly limited to the generator stator and does not require phase-angle compensation.
Troubleshooting a Nuisance 87G Trip
If the relay trips but a megohmmeter (megger) test shows the stator insulation is perfectly healthy, the fault is usually in the CT circuit, not the generator. Check these three items:
- Open CT Secondary: A loose wire on a terminal block creates an open circuit. The relay sees zero current from that CT, interprets the load current from the other CT as a differential fault, and trips. Measure continuity across the shorting blocks.
- CT Saturation from External Faults: If the generator trips during a heavy fault on the utility grid (outside the zone), your CTs might be undersized. Check the IEEE C37.102 standard to verify your CT knee-point voltage is high enough to drive the relay burden without saturating.
- Wiring Polarity Reversal: If a technician recently replaced a CT and wired it backward, the relay will see I_term + I_neutral instead of I_term - I_neutral. The differential current will be double the load current, causing an instant trip the moment the generator picks up load.
By understanding the exact numeric thresholds and physical layout of the 87G zone, you can confidently specify, set, and troubleshoot stator protection on any industrial power generation asset.
