Automatic capacitor bank control in MV and HV

Short answer

Automatic control of a medium or high-voltage capacitor bank decides when to switch each step in and out according to voltage, vars, power factor or time of day, with bandwidths and hysteresis that prevent repeated operations. It prevents reclosing a bank that has not yet discharged and is coordinated with the transformer tap changer so the two do not work against each other.

What a capacitor bank control does

A medium or high-voltage capacitor bank supplies reactive power to support voltage, reduce losses or avoid reactive power charges. If it stays connected all the time, at light load it overcompensates and raises the voltage. The automatic control decides when to switch it in and out, or which steps to connect if it is split into stages.

This guide covers medium and high-voltage banks switched with power circuit breakers or contactors. Low-voltage power factor controllers in switchboards, which drive contactors, are covered in capacitor bank controllers.

Control criteria

Voltage: switches the bank in when the voltage falls below a band and out when it rises above it. It is the classic criterion of distribution substations.
Reactive power (vars): switches in when the inductive reactive demand exceeds the size of one step and out when the flow reverses. It needs current and voltage measurement.
Power factor: similar to the previous one, but based on the ratio between active and reactive power. At light load it is unstable and is usually combined with a minimum current.
Time of day or calendar: switches in and out at fixed times. It is useful when the load curve is very repetitive or as a backup if the measurement fails.
Temperature or current: auxiliary criteria in some distribution systems.

Each criterion is used with a deadband larger than the effect of one step, so that switching a step in does not push the measurement to the other side of the band and cause it to switch out. Time delays prevent switching on brief variations. Together they prevent hunting, which for a bank means unnecessary operations and breaker wear.

Close blocking for discharge

A bank that has just been switched out is left charged. If it is reconnected when its residual voltage has the opposite polarity to the system, the difference can reach almost twice the peak, with transient currents and overvoltages that damage capacitor units and breakers. The product standards, IEC 60871-1 for units above 1 kV and IEEE 18, set the maximum residual voltage and the time in which the internal discharge devices must reach it.

The control imposes a close block after each opening, at least equal to that time and with the margin the manufacturer specifies. Some schemes add voltage transformers or discharge reactors that allow earlier reconnection. The block also applies after a loss of bus voltage: if the bus goes dead, the bank opens on undervoltage and waits for its discharge before returning.

When a bank step can close

Is the measurement outside the band for the set time?
- YesHas the discharge time passed since that step last opened?
  - YesIs any block active: unbalance, overvoltage, local control or breaker not available?
    - YesDoes not close and indicates the block
    - NoCloses the step with the fewest accumulated operations
  - NoWaits for the discharge
- NoNo action

Coordination with the tap changer

The on-load tap changer and the bank act on the same voltage. If both have the same criterion and similar times, they can work against each other: the bank switches in, the voltage rises, the tap changer lowers one tap, the voltage drops and the bank switches in or out again. The usual solutions are:

Separate criteria: the tap changer regulates voltage and the bank controls vars.
Staggered time delays: one acts clearly faster than the other.
Coordinated station control: a single logic, in the station controller or a PLC, decides for both with a defined priority.

In IEC 61850, automatic tap changer control is modelled with ATCC and reactive control with ARCO, and the coordination is resolved in the controller logic.

Steps, rotation and switching

Step rotation: in banks with several identical stages, the control spreads the operations so that wear is even.
Back-to-back energization: when a step is switched in with others already energized on the same bus, the inrush current is higher and at high frequency. Current-limiting reactors and controlled switching reduce it; the choice belongs to the design.
Controlled switching: closing each pole near voltage zero removes almost all the transient. It is covered in the guide on point-on-wave controlled switching.

Protection blocking

The control must receive and respect the signals from the bank protection: an unbalance trip, which points to damaged units or fuses, blocks closing until an inspection; overvoltage and harmonic overload switch steps out; and local control at the panel inhibits automatic operation. The typical causes of those trips are in capacitor bank trips, and the risk of harmonic amplification in capacitor bank resonance.

What goes wrong in practice

Repeated switching because the deadband is smaller than the effect of one step.
Fighting with the tap changer because of similar criteria and times.
Closing onto a charged bank because the discharge block was not applied after a protection trip or a loss of voltage.
Reversed var criterion because of a CT polarity error or measurement at the wrong point.
Bank permanently out because of an unbalance block nobody reset.

You can estimate the bank size, its steps and the resonance with the transformer with our free capacitor bank tool.

How it is tested

In general terms, each criterion is checked with secondary injection: bands, time delays, discharge blocking, step rotation, protection blocks and local mode. At commissioning the first real operations are recorded to confirm that the effect of each step stays inside the band and that there is no hunting with the tap changer.

We can help with your reactive compensation

We load and change the logic, interlocks and signals remotely through our remote relay and controller configuration service, without waiting for a site visit. At Tiza Group we do the power quality study that defines the steps and criteria of the bank, and the secondary engineering of its control logic and its coordination with the tap changer, for substations and industry.

References

IEC 60871-1, Shunt capacitors for a.c. power systems having a rated voltage above 1 000 V – Part 1: General.
IEEE Std 18, Standard for Shunt Power Capacitors.
IEEE Std 1036, Guide for the Application of Shunt Power Capacitors.
IEC 61850-7-4, Compatible logical node classes and data object classes (ARCO, ATCC, ZCAP, CPOW).

Frequently asked questions

Why won't the control let the bank reclose right after it opens?

Because on opening, the bank is left charged at a voltage close to peak. If it is reconnected in phase opposition with the system, the inrush current and the transient overvoltage can be very high. Product standards set the maximum time in which the discharge devices must bring the residual voltage down, and the control blocks closing for at least that time.

Which criterion is best: voltage, vars or power factor?

It depends on what the bank is for. In distribution substations that regulate voltage, voltage is used, often with var supervision. In plants that want to avoid reactive power charges, vars or power factor at the metering point are used. Time of day works as a backup when the load is very repetitive. Many controls combine two criteria.

How do you keep the bank and the tap changer from fighting each other?

With different time delays and separate criteria: for example, the tap changer regulates voltage and the bank controls vars, or the bank acts more slowly than the tap changer. In substations with station-level control, a single coordinated logic decides for both.