Can Diesel Generators Back-Energize an 11 kV System?

Production returns when transformer magnetizing current is controlled as a switching-sequence problem, not treated as a 600 kW steady-load problem. Prove the excitation system can survive the first voltage build, keep transformer secondaries open during magnetization, synchronize the second generator, and add the standing load in measured blocks.

Reject the quick fixes first

Do not close the complete dead 11 kV network at full generator voltage and hope the automatic voltage regulator catches it. The two generators total 1,500 kVA, while the connected downstream transformers total 4,250 kVA. That is 4,250 / 1,500 = 2.83 times the available generator apparent-power rating before considering the 1,500 kVA step-up transformer itself.

The 600 kW standing load does not predict the first-cycle duty. Transformer energization initially presents magnetizing inrush, governed by core residual flux, switching point on the voltage waveform, source impedance, transformer impedance, and how many cores are energized together. Load power factor is also missing, so 600 kW cannot be converted to running kVA without a measured or specified power factor.

Do not modify current-transformer or AVR sensing circuits to force an intentional voltage reduction unless the generator manufacturer designs and approves the complete circuit. A resistor or relay added to an instrument-transformer circuit can corrupt regulation and protection, create unsafe CT conditions, or drive the exciter outside its intended operating range.

Check before continuing: record the actual generator-terminal voltage, frequency, current, protection operation, and event sequence during any controlled test. Stop if the only acceptance criterion is that the generators do not trip.

Freeze the one-line configuration

Mark every device that will be connected at each step: two 750 kVA, 415 V generators, the 1,500 kVA, 415 V/11 kV step-up transformer, each 11 kV/415 V transformer, and every secondary load breaker. Record which old 415 V breakers can be opened locally even though they are not remotely controllable.

If all downstream transformer primaries remain connected while voltage builds, the energized transformer nameplates comprise the 1,500 kVA step-up unit plus 4,250 kVA downstream, or 5,750 kVA of transformer nameplate capacity. Nameplate sum is not an inrush-current calculation, but it exposes why a full-voltage simultaneous close is the highest-risk sequence.

Check before continuing: prove from breaker indication and test-for-dead procedures that every secondary selected to remain open is physically isolated, not merely commanded open.

Turn the voltage-dip curve into a pass criterion

The manufacturer supplied a point showing a 35% voltage dip at 4 pu current and 0 pf. Read literally, that point represents approximately 65% residual terminal voltage under the curve's stated test condition. It does not by itself predict the actual transformer-inrush magnitude, current duration, recovery time, frequency response, or operation of protective devices.

For a three-phase calculation assumption, the combined generator rated current is:

I = 1,500,000 / (sqrt(3) × 415) = approximately 2,087 A
4 pu = approximately 8,348 A at 415 V

Referred ideally to the 11 kV side, the combined rated current is approximately 78.7 A, and 4 pu is approximately 315 A. These are three-phase line-current calculations; use the actual system topology and transformer ratio data when reviewing protection. They are not permissible settings or predicted inrush values.

Compare the curve against three limits: the minimum voltage needed to avoid generator and transformer protection operation, the undervoltage ride-through of connected auxiliaries, and the maximum current duty of the alternators and switchgear. Obtain the curve conditions for one generator versus two in parallel, exciter type, initial load, and the duration associated with the dip point. Do not extrapolate a single 4 pu point to a different duration or excitation configuration.

Check before continuing: write a numeric acceptance sheet using the approved protection settings and manufacturer limits. If minimum voltage, allowable current duration, or recovery criteria are missing, do not conduct a full-network test.

Confirm how each generator supplies excitation

A permanent-magnet-generator excitation supply remains less dependent on collapsing generator-terminal voltage, so the AVR can continue driving the field during a severe dip. That can improve voltage support, but stronger voltage support can also permit higher transformer inrush and increase alternator, breaker, CT, and mechanical stress.

A self-excited arrangement derives excitation energy from the generator output. A large terminal-voltage dip can therefore reduce available field forcing and limit current, but it can also prevent voltage recovery. Treat voltage collapse as a failed commissioning condition, not as an acceptable inrush-limiting method.

Before selecting the sequence, identify the installed exciter configuration and obtain its actual ceiling, short-circuit behavior, and voltage-recovery curve from the generator manufacturer. Confirm that both paralleled machines use compatible AVR modes, voltage setpoints, reactive-droop or cross-current compensation, and synchronizing controls. Do not infer installed options from a sales description.

Check before continuing: run each generator separately with its transformer path isolated, confirm stable rated voltage and frequency, and verify that the two units share reactive current correctly after synchronization at low load.

Build voltage with the transformers dead-connected

The preferred inrush-avoidance sequence is to connect the required transformer magnetic circuit while it is de-energized, leave all transformer secondaries open, and raise generator voltage with the connected cores. Flux then builds with voltage instead of being imposed by an abrupt full-voltage close. The switching arrangement, protection philosophy, and generator starting method must permit this sequence.

1. Open and positively verify every downstream 415 V load breaker included in the commissioning boundary.
2. Place the required 11 kV transformer primaries and the 1,500 kVA step-up transformer in the approved dead-connected configuration.
3. Start one 750 kVA generator and raise speed and voltage through its normal controls while recording terminal voltage, current, frequency, and excitation demand.
4. Stop immediately if voltage does not build normally, current remains elevated, protection operates, or the excitation system reaches a manufacturer limit.
5. After voltage and frequency stabilize, synchronize the second 750 kVA generator and confirm stable kW and kvar sharing.

This method avoids the full-voltage simultaneous closing transient but transfers the question to generator voltage build-up with a large connected magnetic network. The manufacturer must approve that operating mode for the installed excitation system. If the architecture cannot connect the dead network safely, use sectionalized energization instead.

Check before continuing: hold the energized, unloaded network long enough to verify stable voltage, frequency, current, excitation, transformer sound, and zero unintended secondary load.

Sectionalize when dead-network build-up is unavailable

If the existing breakers cannot support dead-connected voltage build-up, energize the step-up transformer with one generator, synchronize the second generator, and then add the 11 kV/415 V transformers in the smallest practical groups. Individual or smaller-group switching reduces coincident inrush and makes the failing section identifiable.

Sectionalizing may require high-voltage switches or motor operators. Remote operation of the old 415 V breakers is not mandatory if an approved local switching procedure can keep secondaries open, but manual operation changes staffing, interlocking, communications, and restoration time. Never defeat interlocks to avoid the cost of proper switching equipment.

Residual flux can make repeated attempts differ even when the one-line configuration is unchanged. After a failed close, read the event record and follow the approved reset and de-energization process rather than repeatedly reclosing. Change only one variable per test: transformer group, generator lineup, or load block.

Check before continuing: after each transformer group is energized, confirm that generator voltage and frequency return to their approved bands, current settles, no relay target appears, and the next section remains isolated.

Add the 600 kW load and prove the complete sequence

Add the standing load only after both generators are synchronized and the unloaded transformer network is stable. Divide the approximately 600 kW across the four sites into blocks based on measured kW, kvar, starting duty, and operational priority. Do not treat four equal geographic blocks as four equal electrical steps.

1. Capture baseline voltage, frequency, current, kW, kvar, power factor, and excitation for each generator.
2. Close the first approved load block and wait for the measured variables to settle.
3. Confirm correct real-power and reactive-power sharing between generators.
4. Repeat for each block while watching secondary undervoltage devices, contactors, motor starting, and transformer loading.
5. Run the final operating lineup and then execute one controlled shutdown and restart using the written switching sequence.

Acceptance requires more than retained voltage. Review the complete record for minimum generator-terminal voltage, current magnitude and duration, voltage recovery, frequency excursion, AVR response, kW/kvar sharing, relay targets, breaker operation, and secondary equipment resets. Retain the successful lineup and measured traces as the operating baseline; then plan permanent sectionalizing or control upgrades if the temporary procedure depends on manual switching.

End-to-end check: a trained operator must be able to reproduce the sequence from a dead system without bypassing protection, improvising AVR circuits, or relying on an unspecified claim that the transient will clear within a few cycles.

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