In short. A generator alternator’s short-circuit behaviour is described by three reactances, each valid for a different time window: subtransient for the first few cycles, transient for the next second or so, and synchronous for steady state. Initial fault current is roughly rated current divided by per-unit subtransient reactance, typically six to ten times rated, and it then decays along a decrement curve shaped by the excitation system. Protection on generator supply must be set against that curve.
Three reactances, three time windows
When a short circuit is applied to a running alternator, the current does not settle instantly. Flux trapped in the damper bars opposes the change for a few cycles, then flux in the field winding opposes it for longer, and only after the field flux has adjusted does the machine reach steady state. Each stage is modelled with an internal voltage behind a reactance.
| Quantity | Symbol | Typical per-unit range on the alternator’s own base | Time window | Used for |
|---|---|---|---|---|
| Subtransient reactance | Xd” | 0.10 to 0.20 | First 1 to 3 cycles | Peak and initial symmetrical fault current, breaker making duty, voltage dip at the instant of motor starting |
| Transient reactance | Xd‘ | 0.15 to 0.30 | Roughly 0.1 to 1.5 s | Motor-starting voltage dip after the first cycles, breaker breaking duty, relay operation in the short-time region |
| Synchronous reactance | Xd | 1.5 to 3.5 | Steady state | Sustained fault current with constant excitation, voltage regulation, reactive capability |
| Negative-sequence reactance | X2 | Close to Xd” | Unbalanced faults | Line-to-line and line-to-earth fault current, rotor heating under unbalance |
| Zero-sequence reactance | X0 | 0.02 to 0.10 | Earth faults | Earth fault current with a solidly earthed neutral |
The ranges are typical of four-pole brushless alternators from a few hundred kVA to a few MVA. Values for a specific machine come from the manufacturer’s data sheet and are quoted on the alternator’s own kVA base, which is not always the genset’s rated kVA.
Estimating the initial fault current
For a three-phase fault at the terminals with the machine at rated voltage, the initial symmetrical fault current is approximated as follows.
Ik” = Irated ÷ Xd”
Here Ik” is the initial symmetrical short-circuit current in amperes, Irated is the alternator’s rated line current in amperes, and Xd” is the per-unit subtransient reactance on the same kVA base. As a worked example (illustrative), a 500 kVA alternator at 415 V has a rated current of 500,000 ÷ (1.732 × 415) ≈ 696 A. With Xd” of 0.14 per unit, the initial fault current is 696 ÷ 0.14 ≈ 4,970 A, or about seven times rated. The first peak of the asymmetrical current can reach roughly 1.8 times the square root of two times that value, close to 12,600 A, which is the figure that matters for the making capacity of the breaker and the mechanical bracing of the busbars. These are terminal-fault figures; cable impedance reduces them, which is what makes faults at the end of long feeders hard to detect.
If the reactance is quoted on a different base from the one you are using, convert it first: the per-unit value scales with the kVA base, so 0.14 on a 550 kVA alternator base becomes 0.127 on a 500 kVA genset base. Omitting this step is a common source of a 10 percent error.
The decrement curve and why excitation matters
The initial current decays within tens of milliseconds to the transient value, which decays over a second or so towards the synchronous value. With constant excitation the synchronous value is rated current divided by Xd, which for 2.5 per unit is only 40 percent of rated current, less than normal load current, and no overcurrent device will see it as a fault.
What rescues the situation is the excitation system. A regulator with an independent supply, from a permanent magnet generator or an auxiliary winding, drives the field to its ceiling and holds around three times rated current for several seconds. A shunt-excited machine cannot, because its regulator supply has collapsed with the terminal voltage. The manufacturer’s decrement curve shows current against time for each excitation type, and it is this curve, not the single subtransient figure, that must be overlaid on the downstream time-current characteristics. The excitation architectures are compared under PMG and excitation.
Consequences for protection on generator supply
Most low-voltage installations in India are designed around a utility fault level of 25 to 50 kA at the main switchboard. Fed by a 500 kVA generator, the same board sees about 5 kA for a few cycles and 2 kA at best thereafter. Several things follow.
- Instantaneous magnetic settings on downstream breakers that were chosen for utility conditions may sit above the generator’s available current. A breaker set at 10 times its 630 A rating needs 6,300 A, which this generator never supplies, so the fault is cleared by the generator breaker instead.
- Faults at the end of long cables may draw less than twice rated current and persist until the generator’s own protection operates, dropping the whole installation.
- The generator breaker itself must trip before the alternator windings are damaged, which is why generator protection uses voltage-restrained or voltage-controlled overcurrent elements that recognise a fault from the depressed voltage rather than from current alone.
- Earth fault current depends on the neutral earthing arrangement and X0, and is often the easiest fault to detect selectively because its magnitude is set by design.
A coordination study that was done for utility supply is therefore not valid for generator supply, and a site with an automatic changeover needs both cases checked. The study method is described under fault current and protection coordination, and the generator’s contribution to a system-wide study under generator short-circuit contribution.
Where motors come in
Running induction motors feed a fault for a few cycles as their rotor flux decays, contributing initially about their own locked-rotor current. On a site with a large motor load this adds materially to the first-cycle current the generator breaker must handle, and it is included in a proper study. It does not help with the sustained current problem, because motor contribution is gone within a few cycles.
Common mistakes
- Using a single “seven times rated” figure for all purposes; it is a first-cycle value and the current a second later may be a third of it or less.
- Substituting transient reactance where subtransient is required, or the reverse; the breaker making duty or the motor-starting dip comes out wrong by 30 percent or more.
- Leaving the reactance on the alternator’s own base when the genset is rated differently; a quiet error that propagates through every downstream setting.
- Copying the utility-based coordination study to the generator case; the downstream instantaneous elements never operate and the generator breaker clears every fault.
What to send us
Send the alternator nameplate, the manufacturer’s data sheet or the reactance values and time constants if you have them, the single-line diagram showing the generator breaker and downstream devices with their ratings and settings, and the cable sizes and lengths of the main feeders. If the set is paralleled or has an automatic changeover, say so. Send your application details and we will advise whether a generator-case coordination study is needed and what data is missing.
Questions engineers ask
Is a lower subtransient reactance better?
It depends on the aim. Lower reactance gives higher initial fault current, which helps protection operate, and a smaller instantaneous voltage dip on motor starting. It also raises the breaker making duty and the forces on busbars. Manufacturers choose a balance, and the designer works with the value given.
Why does my 1,000 kVA generator trip on a fault that a 100 A breaker should have cleared?
Because the fault current at that breaker, after cable impedance and after the first few cycles, was probably below its magnetic trip threshold, and the thermal element needed longer than the generator protection allowed. A coordination check against the decrement curve, and in some cases a PMG upgrade or revised settings, resolves it.
What is the difference between the generator fault level and the utility fault level?
The utility fault level at a 415 V board is set by the upstream transformer and network and is commonly 25 to 50 kA. The generator fault level is set by the alternator reactance and is roughly six to ten times the generator’s rated current, decaying quickly. The two can differ by a factor of ten or more at the same busbar.
Do I need manufacturer data or can I use typical values?
Typical values are acceptable for preliminary screening of small sets with simple distribution. For any installation with downstream coordination, paralleled sets, large motors or a critical load, use the data sheet values for the actual machine, because the typical range spans a factor of two.
Technical content reviewed by Srinivas Reddy, Managing Partner, Reddy Generators. Last updated 19 October 2026.