A transformer energisation study predicts what happens to the network when a generating system's main transformer, and the unit transformers behind it, are switched on. It quantifies the inrush current, the resulting voltage dip at nearby buses, and the risk that already-energised transformers nearby draw sympathetic inrush and trip. NSPs use it to decide whether the plant can be energised as designed, and under what switching procedure.
For a large solar farm or battery connecting at a point with a modest fault level, the study can change the switchgear specification and the commissioning plan. It is cheap to do early and expensive to discover at energisation.
Why Transformers Draw Inrush
A transformer core is designed to run just below magnetic saturation in normal operation. In steady state the flux in the core follows the integral of the applied voltage, so it peaks a quarter cycle after the voltage does.
When a transformer is switched on, the flux has to start from wherever it was left, the residual flux, rather than from the steady-state value for that instant. Close at a voltage zero with no residual flux and the flux swings to about twice its normal peak. Add residual flux in the same direction and the theoretical peak approaches three times normal. Either way the core saturates hard, its magnetising impedance collapses, and the transformer draws a large, offset, harmonic-rich current that decays over hundreds of milliseconds to a few seconds.
| Factor | Effect on inrush |
|---|---|
| Point on wave at closing | Closing near voltage zero gives the largest flux offset; closing near voltage peak gives the least |
| Residual flux | Adds to or subtracts from the offset depending on polarity; highest after a trip during a fault |
| Source strength | A weak source limits peak current but makes the voltage dip deeper |
| Transformer size and design | Larger, lower-loss cores tend to have longer-lasting inrush |
| Saturation characteristic | The air-core reactance of the winding sets how large the current can get |
Circuit breakers normally interrupt at current zero, which leaves modest residual flux after routine switching. The worrying case is a transformer that tripped during a fault, where distorted waveforms can leave significant remanence. Studies therefore run with and without worst-case residual flux.
What the NSP Is Worried About
The transformer being energised is rarely the concern. Its own differential protection normally has harmonic restraint, which blocks tripping on the second harmonic content that inrush carries. The concerns are elsewhere.
- Voltage dip at nearby loads. The inrush current through the source impedance depresses the voltage at every bus nearby. Customers on a neighbouring load substation see it as a sag. Rapid voltage changes are limited under AS/NZS 61000.3.7 and the NSP's planning criteria, with the allowed step depending on how often it occurs.
- Sympathetic inrush. The offset in the network voltage during energisation can drive already-energised transformers nearby partly into saturation. They then draw their own offset currents, which can last longer than the original inrush and can trip their differential protection, especially if that protection lacks robust harmonic restraint.
- Harmonic resonance. Inrush is rich in low-order harmonics. If the network has a resonance near the second or third harmonic, for example because of a large cable network or capacitor bank, the voltage distortion can be amplified and prolonged.
The risk is highest when the main transformer is large relative to the fault level, and when a distribution load substation is electrically close, for example where the generator tees into an existing line.
How the Study Is Done
Energisation is an electromagnetic transient problem, so the study is done in an EMT tool such as PSCAD.
Energisation Study Method
- Network equivalent at the minimum fault level, the worst case for voltage dip, with any nearby transformers and loads modelled explicitly
- Main transformer model with the manufacturer's saturation curve and air-core reactance, not the tool's default curve
- Neighbouring transformers modelled with their own saturation characteristics, including any planned upgrades
- Breaker closing time swept across the cycle to find the worst point on wave
- Residual flux cases at zero and at a worst-case level in each phase
- Unit transformers energised as lumped groups per collector feeder, at worst closing angle with residual flux
- Abnormal configurations: single feeder in service, neighbouring substation on alternate supply, re-energisation after a fault
- Simulation long enough to capture decay and any sympathetic interaction, often several seconds
The outputs reviewers expect are tables, not just plots: the RMS voltage step at each bus of interest, the peak phase voltage, the fundamental frequency voltage, the inrush current magnitude and decay, and the differential current seen by protection on neighbouring transformers. Arguments based only on comparing the transformer's rating with the fault level are generally not accepted.
Do not forget the unit transformers
Energising a collector feeder can switch in many inverter step-up transformers at once. Their combined inrush can match or exceed that of the main transformer, and it happens repeatedly during commissioning. The study should cover feeder energisation as well as main transformer energisation, and set a limit on how many unit transformers may be switched in together.
Mitigation Options
| Mitigation | How it works | Practical notes |
|---|---|---|
| Controlled (point-on-wave) switching | A relay closes each pole at the instant that minimises flux offset, allowing for residual flux | Needs independent pole operation or a suitable staggered breaker; adaptive relays learn breaker scatter and residual flux; specify SCADA alarms and a fall-back procedure |
| Pre-insertion resistors | A resistor in series for the first few cycles damps the inrush | Adds cost and complexity to the breaker; less common at transmission voltages in the NEM today |
| Staged energisation | Energise the main transformer unloaded, then collector feeders one at a time | Simple and effective for unit transformer inrush; written into the operating protocol |
| Network reconfiguration | Energise from a supply arrangement that keeps the dip away from sensitive loads | Needs NSP agreement and a planned outage or switching sequence |
| Protection review | Confirm harmonic restraint on all nearby transformer differential protection | Addresses sympathetic tripping, not the voltage dip itself |
Controlled switching on the HV breaker is the most common solution for large main transformers. It is rarely practical at medium voltage, so feeder and unit transformer energisation is usually managed by procedure.
Turning the Results Into Procedure
The study's real output is an operating protocol the NSP's control room can use without further analysis:
- the approved switching sequence, with and without the controlled switching relay in service
- the network configurations in which energisation is permitted
- the maximum number of unit transformers energised at once
- the minimum time between successive energisations
- SCADA visibility of each feeder breaker and the number of transformers in service
NSPs also commonly ask for the EMT model, saturation curves and factory test results to be handed over, so they can reassess if the network changes. Expect the study to be updated if the transformer rating or impedance changes during detailed design. A study that no longer matches the equipment is a reason to hold energisation.
Get Energisation Planned Before It Holds You Up
Energisation constraints can affect breaker procurement, so the study belongs in the design phase, not the week before commissioning.
ElectraGlobe carries out transformer energisation and sympathetic inrush studies in PSCAD and turns the results into switching procedures NSPs accept. See our steady-state and dynamic studies service, or contact us.
Frequently Asked Questions
What is transformer inrush current?
It is the large, offset current a transformer draws when switched on, caused by its core saturating because the magnetic flux starts from the wrong value for the instant of closing. It can be several times rated current at first and decays over hundreds of milliseconds to seconds.
What is sympathetic inrush?
When one transformer is energised, the distorted network voltage can push nearby transformers that are already in service into partial saturation, so they draw offset currents of their own. Sympathetic inrush can last longer than the original inrush and can trip the neighbouring transformers' protection.
How is transformer inrush reduced?
The most common method for large transformers is controlled (point-on-wave) switching, where each breaker pole closes at the instant that minimises flux offset. Pre-insertion resistors, staged energisation of feeders and network reconfiguration are other options.
Which standard limits the voltage dip from energisation?
In Australia, rapid voltage changes are generally assessed against AS/NZS 61000.3.7 and the NSP's own planning criteria. The allowed voltage step depends on how often the event occurs, so the study result also sets how many energisations may be made in a given period.