Protection Coordination for MV Switchgear and Transformers: A Practical Guide for Industrial and Utility Projects

A short circuit should not automatically disconnect an entire electrical network.

If a fault occurs on one downstream feeder, the protection system should identify the abnormal condition and isolate the smallest practical section of the network while keeping healthy equipment energised.

This is the objective of protection coordination.

In medium-voltage industrial plants, utility substations, mining facilities and renewable energy projects, coordination involves much more than selecting an overcurrent relay.

Transformer characteristics, short-circuit levels, CT ratios, relay pickup settings, time-current curves, circuit breaker operating times, earth-fault protection and downstream devices must work as one protection system.

Poor coordination can cause nuisance trips, unnecessary plant outages or delayed fault clearance. In more serious cases, equipment may remain exposed to damaging fault current longer than intended.

For engineers and EPC contractors, electrical protection coordination should therefore be completed before relay settings are finalised and reviewed again before Factory Acceptance Testing.

What Protection Coordination Actually Means

Protection coordination, also called protection discrimination or selectivity, determines the sequence in which protective devices operate when a fault occurs.

Consider a simple electrical system:

Utility supply → power transformer → MV switchboard → outgoing feeder → downstream transformer → LV distribution.

If a fault develops on one downstream feeder, the preferred response is normally for the breaker protecting that feeder to operate first.

The upstream breaker should remain closed unless the downstream protection fails or the fault is located within the upstream protection zone.

This creates layers of protection.

Each device has a primary protection responsibility while upstream devices provide backup protection.

Good relay coordination balances two objectives:

• Clear faults quickly enough to protect equipment and personnel.

• Maintain selectivity so unnecessary sections of the network remain energised.

Making every relay operate as quickly as possible does not automatically create a well-protected system.

Start With the Short-Circuit Study

Effective coordination begins with understanding the fault current available throughout the network.

A short-circuit study calculates fault levels at important buses and equipment locations under credible operating conditions.

The study should consider sources including:

• Utility network contribution

• Generators

• Power transformers

• Motors

• Renewable generation

• Battery energy storage systems

• Parallel transformers

• Alternative bus configurations

Maximum fault current is required to verify switchgear and circuit breaker duties.

Minimum fault current is equally important for protection.

A relay must remain sensitive enough to detect faults under minimum-generation or minimum-network conditions.

For MV protection coordination, engineers should therefore examine multiple network scenarios rather than coordinate relays using only the highest fault level.

Transformer impedance also has a major influence. Higher impedance generally limits downstream fault current, while lower impedance can increase the available short-circuit level.

This is why protection studies should be coordinated with the transformer and MV switchgear specification rather than performed after equipment procurement.

CT Selection Comes Before Final Relay Settings

The protection relay only knows what is happening in the primary circuit through its current transformers.

Incorrect CT selection can compromise the entire protection scheme.

The CT ratio must provide sufficient measurement range for normal load and fault conditions while maintaining adequate sensitivity for lower fault currents.

CT Ratio Is Not the Only Parameter

Engineers should also consider:

• Protection class

• Accuracy limit

• Burden

• Saturation performance

• Secondary current

• Maximum fault current

• Relay input requirements

CT saturation is particularly important during high-current faults.

If the CT cannot reproduce primary fault current accurately, the relay may receive a distorted or reduced secondary signal.

For transformer differential and other high-speed protection functions, CT performance becomes especially critical.

Selecting a CT simply because its ratio matches nominal load current is therefore not sufficient.

Relay Pickup Must Sit Above Load but Below Fault Current

Once fault levels and CT performance are understood, engineers can establish protection relay settings.

The pickup threshold determines when a protection element begins to respond.

For an overcurrent element, the pickup should generally be above maximum expected load current while remaining sufficiently below the minimum fault current within its protection zone.

If the pickup is too low, normal loading, motor starting or temporary overloads may cause nuisance operation.

If it is too high, some faults may not be detected reliably.

This balance becomes particularly important for a switchgear protection relay serving heavily loaded industrial feeders.

Protection engineers must consider the actual operating duty rather than applying generic settings across every panel.

Time-Current Curves Show Whether Selectivity Works

One of the most useful tools in protection studies is the time-current characteristic, or TCC.

A TCC plots operating time against current for protective devices at different levels of the network.

By placing downstream and upstream protection curves on the same graph, engineers can identify whether sufficient coordination margin exists.

Downstream Protection Should Normally Operate First

Suppose an MV feeder supplies a downstream transformer.

A high-current fault on the transformer secondary may be detected by:

• LV circuit breaker protection

• Transformer feeder relay

• MV incomer relay

• Upstream utility protection

The closest appropriate protective device should generally clear the fault first.

Upstream protection should operate later as backup.

However, the required time margin is not simply a fixed delay.

It must consider relay operating time, breaker opening time, relay overshoot, CT behaviour and appropriate engineering margin.

Coordination Cannot Create Unnecessary Delay

Excessive grading can be just as problematic as insufficient grading.

If several protection levels are coordinated by simply adding longer delays at each upstream stage, high-level faults may remain connected for too long.

This can increase thermal and mechanical stress on transformers, cables and switchgear.

Modern protection schemes may therefore combine inverse-time protection with instantaneous, differential, restricted earth fault or zone-selective functions to achieve both speed and selectivity.

Transformer Inrush Must Not Be Mistaken for a Fault

Transformer energisation introduces an additional coordination challenge.

When a transformer is energised, magnetising inrush current can be several times the normal operating current for a short period.

A basic overcurrent setting that does not account for this behaviour may trip the transformer immediately during normal energisation.

Transformer protection coordination must therefore distinguish between legitimate energisation current and genuine fault current.

Time-current curves should consider transformer inrush characteristics alongside:

• Maximum load

• Short-time overload

• Transformer damage limits

• Cable limits

• Relay curves

• Downstream protection

Transformer differential protection commonly uses harmonic restraint or other algorithms to improve security during energisation.

The overall protection philosophy should ensure that high-speed transformer protection remains sensitive to internal faults without creating unnecessary trips during normal switching.

Earth-Fault Coordination Needs Its Own Review

Phase-fault coordination alone is not enough.

Earth-fault current can be substantially different from three-phase short-circuit current because it depends heavily on the system earthing arrangement.

An MV system may be:

• Solidly earthed

• Resistance earthed

• Reactance earthed

• Earthed through a transformer neutral

• Earthed through an earthing transformer

Where a neutral earthing resistor is used, the resistor limits earth-fault current to a predetermined value.

The protection system must then be sensitive enough to detect that limited current reliably.

Leistung Energie's existing Neutral Earthing Resistor guidance highlights the need to coordinate the NER fault current and duration with relay sensitivity and the wider protection philosophy.

For example, specifying a low earth-fault current without checking relay pickup can create a system in which the resistor performs as designed but the protection does not detect the fault reliably.

Earth-Fault Clearing Time Also Affects NER Rating

Coordination works in both directions.

The NER determines fault current, but the protection system determines how long the resistor must carry that current.

Relay operating time plus circuit breaker clearing time must therefore remain within the NER's thermal time rating.

This is why earthing design and protection studies should not be completed independently.

Breaker Clearing Time Is Part of the Protection Study

Protection engineers frequently focus on relay operating time, but the fault does not disappear when the relay issues a trip command.

The circuit breaker still needs to open and interrupt the current.

Total fault clearing time includes:

Relay detection and operating time → trip circuit operation → breaker mechanism operation → arc interruption.

For high fault currents, even relatively small differences in clearing time can influence equipment thermal and mechanical stress.

Breaker characteristics should therefore be included in the coordination study.

This is especially important when replacing old breakers or retrofitting modern relays into existing switchgear. A fast new relay does not automatically make an old breaker operate faster.

Protection Zones Must Match the Physical Electrical System

A good protection scheme divides the electrical network into logical zones.

Typical zones may include:

• Transformer

• Busbar

• Incoming feeder

• Outgoing feeder

• Motor

• Generator

• Cable circuit

Where possible, these zones should overlap so there are no unprotected sections between CT locations and circuit breakers.

Different protection functions may then be applied according to the equipment.

A power transformer may use differential and restricted earth fault protection as primary functions with overcurrent protection as backup.

An MV feeder may primarily rely on phase and earth overcurrent elements.

Large substations may also use dedicated busbar differential protection.

The objective is not to install every available relay function. It is to select functions that correspond to credible faults and the required operating philosophy.

Coordination Should Be Reviewed Before FAT

Protection settings should not first appear during commissioning.

By the time the project reaches Factory Acceptance Testing, engineers should have a sufficiently developed protection study and approved philosophy.

Before FAT, review:

Coordination Area	What to Confirm
Fault study	Maximum and minimum fault levels
CTs	Ratios, classes, burden and saturation
Relay pickup	Above operating load and sensitive to faults
TCC	Upstream/downstream selectivity
Transformer	Inrush and damage characteristics
Earth fault	Earthing arrangement and relay sensitivity
NER	Fault current and duration coordination
Breakers	Interrupting rating and clearing time
Settings	Primary and backup protection
SCADA	Trip, alarm and relay indication requirements

FAT can then verify that the supplied relays, switchgear and control systems implement the approved protection philosophy.

Testing should include relevant trip paths, breaker operation, interlocking, relay logic and communication interfaces.

Common Protection Coordination Mistakes

Many coordination problems begin before relay settings are calculated.

One common mistake is using preliminary fault levels after the network design has changed.

Another is selecting CT ratios before the final load and fault studies are available.

Other problems include ignoring transformer inrush, coordinating only phase overcurrent while neglecting earth faults, or assuming that upstream and downstream relay curves are selective without plotting them together.

Equipment changes also require review.

Changing transformer impedance, NER rating, cable size, breaker type or generation configuration can alter fault behaviour and invalidate previous settings.

Protection coordination should therefore be treated as a controlled engineering process, not a one-time calculation.

Conclusion

Effective protection coordination ensures that electrical faults are cleared by the correct device, within the required time and with minimum disruption to the wider network.

The process begins with accurate fault studies and continues through CT selection, relay pickup settings, time-current curve analysis, transformer inrush assessment, earth-fault protection and circuit breaker clearing times.

For industrial and utility projects, protection should also be coordinated with the physical equipment being purchased.

Transformers, MV switchgear, NERs, protection relays and downstream equipment all influence how the system responds during a fault.

The key question is straightforward:

When a fault occurs, will the correct breaker trip first—and will it trip fast enough to protect the equipment?

Answering that question before FAT can prevent far more difficult problems during commissioning and operation.

Planning MV Switchgear or Transformer Protection?

Leistung Energie supplies MV switchgear, power transformers and Neutral Earthing Resistors for industrial, utility, mining, renewable energy and power infrastructure projects.

Protection requirements should be reviewed alongside equipment ratings, CT requirements, fault levels, earthing philosophy and circuit breaker duties before procurement is finalised.

Contact Leistung Energie Australia to discuss MV switchgear, transformer and earthing equipment requirements for your upcoming project.