How to Choose a Protection Relay for a Medium Voltage Substation

Medium voltage protection relay selection is the process of matching a relay to one bay: the asset it protects, the ANSI 50/51, 50N/51N, 67 or 87 functions that asset needs, the CT and VT feeding it, and the communication it has to support. The voltage class printed on the front plate is the last thing to check, not the first.

At a Glance: What an MV Relay Has to Cover

• 50/51, phase overcurrent: short circuits on the feeder, trips on an inverse-time curve.
• 50N/51N, earth fault: single-phase-to-earth current, trips on residual current.
• 67/67N, directional overcurrent: fault current that can flow both ways, adds a voltage reference before timing.
• 87T, transformer differential: internal winding faults, compares current entering and leaving the transformer.
• 87B, bus differential: busbar faults, compares every current entering the bus.
• 49, thermal overload: sustained overcurrent that heats the winding, trips on the thermal model.
• 27/59, under and overvoltage: abnormal system voltage, alarms or trips on the voltage element.
• 81U/81O, under and over frequency: frequency excursions, feeds load shedding schemes.

A circuit breaker interrupts current. It does not decide when to interrupt. That decision belongs to the relay, and the relay makes it from CT secondary current, not from the kV rating on the nameplate.

Three documents settle most of the uncertainty before you compare models: ANSI/IEEE C37.2-2022 for the function numbers above, IEC 60255-1:2022 for what a protection relay has to withstand, and IEC 61869-2:2012 for what the CT actually delivers to it during a fault. Both are listed under Technical References at the end.

The sections below cover what each function does on feeders, transformers, busbars and motors, then a five-step workflow, the mistakes that cause nuisance trips, and a checklist you can hand to a supplier.

What Is a Medium Voltage Protection Relay?

What Does an MV Protection Relay Do?

Every MV substation protection relay is specified against one bay, not against a catalogue line. Its CT ratio, fault level and function list differ from the bay next door, and medium voltage protection relay selection starts there.

An MV protection relay monitors electrical parameters in medium voltage systems. It detects abnormal conditions like overcurrent, short circuits, earth faults, and voltage anomalies. When a fault occurs, the relay sends a trip command to the circuit breaker to isolate the faulted section.

Modern MV relays also record fault and event information. They support substation monitoring and control through communication protocols like IEC 61850. Some relays include backup protection functions to provide redundancy when primary protection fails.

Where Are MV Protection Relays Used?

MV protection relays are installed at several points in a substation:

• MV incoming feeders
• Outgoing feeders
• Power transformers (MV/HV)
• Bus sections
• Motors (MV)
• Capacitor banks
• Generator connections

Each application has different protection requirements. A feeder relay needs overcurrent and earth fault protection. A transformer relay may need differential protection plus thermal monitoring.

What Should You Know Before Selecting an MV Protection Relay?

System Voltage and Frequency

Start by confirming the system voltage and frequency. These are fundamental parameters that affect relay input ratings and measurement accuracy.

Check these items:

• Rated voltage (e.g., 11 kV, 33 kV, 66 kV)
• Maximum system voltage (may exceed nominal)
• System frequency: 50 Hz or 60 Hz
• Single-phase or three-phase configuration

Important: System voltage is not the same as relay auxiliary supply voltage. The relay may require 110 VDC or 220 VAC for its internal circuits, independent of the primary system voltage.

Maximum Load Current

Collect load current data for the protected circuit. Do not rely solely on equipment nameplate ratings. Real operating conditions often differ from design values.

Gather these current values:

• Normal operating current
• Maximum continuous current
• Transformer full-load rating
• Motor starting current (if applicable)
• Expected future load growth

A relay set too low will nuisance-trip during normal load variations. A relay set too high may fail to detect genuine overload conditions.

Short-Circuit Current

Short-circuit current levels determine relay measuring range, CT selection, and protection sensitivity. You need both maximum and minimum fault current values.

Confirm these fault current parameters:

• Maximum three-phase short-circuit current
• Minimum fault current (often single-phase-to-ground)
• Phase-to-phase fault current
• Single-line-to-ground fault current

The maximum fault current affects CT saturation risk and relay withstand capability. The minimum fault current determines whether the relay can detect faults at the far end of the protected zone. If the relay cannot see the minimum fault, protection will fail.

Identify the Equipment to Be Protected

Different equipment calls for different protection. Incoming feeders, transformers, busbars and MV motors each need their own ANSI combination, which is why medium voltage protection relay selection begins with the asset rather than the catalogue. Typical pairings below.

MV Substation Equipment	Typical Protection Functions
Incoming feeder	Overcurrent (50/51), earth fault (50N/51N), directional protection (67/67N)
Outgoing feeder	Overcurrent (50/51), earth fault (50N/51N)
Power transformer	Differential (87T), overcurrent (50/51), earth fault (50N/51N), thermal
Busbar	Differential protection (87B) or arc flash protection
MV motor	Overload (49), short circuit (50/51), earth fault, phase loss
Capacitor bank	Overcurrent, unbalance, overvoltage
Generator feeder	Differential, overcurrent, reverse power, earth fault

MV Feeder Protection

Feeders typically use overcurrent protection (ANSI 50/51) and earth fault protection (50N/51N). Directional overcurrent (67/67N) is required for ring networks or parallel feeders where fault current can flow in either direction.

Instantaneous overcurrent (50) clears severe faults quickly. Time-delay overcurrent (51) coordinates with downstream protection and handles overload conditions.

MV Transformer Protection

Transformers are expensive assets that need protection on more than one level. A typical transformer protection scheme includes:

• Differential protection (87T) – primary protection for internal faults
• Overcurrent protection (50/51) – backup protection
• Earth fault protection (50N/51N)
• Temperature monitoring
• Buchholz relay (for oil-filled transformers)

The relay settings must account for transformer inrush current. Without proper inrush blocking, the differential relay may trip during energization.

MV Busbar Protection

Busbar faults are severe events that can cause extensive damage. Protection options include:

• Bus differential protection (87B) – high-speed protection for bus zones
• Arc flash protection – fast light-based detection for switchgear
• Breaker failure protection – backup if the primary breaker fails to clear

Arc flash protection relays are often more cost-effective than full bus differential schemes, particularly for retrofit projects.

Key Criteria for Medium Voltage Protection Relay Selection

Four things decide the outcome: the ANSI functions the asset needs, the CT and VT feeding the relay, the sensitivity the available fault current allows, and the coordination margin against upstream devices. Medium voltage protection relay selection most often fails on the third one.

1. Protection Functions

Select functions based on the equipment type and system configuration. Common functions include:

ANSI Code	Function
50	Instantaneous overcurrent
51	Time-delay overcurrent
50N/51N	Earth fault
67/67N	Directional overcurrent
87T	Transformer differential
87B	Bus differential
27	Undervoltage
59	Overvoltage
81U/81O	Under/over frequency
46	Negative sequence
49	Thermal overload
50BF	Breaker failure

Do not add functions just because they exist in the relay catalogue. Select only what the system requires. Extra functions increase configuration complexity and potential for misoperation.

2. CT and PT Compatibility

CT and PT parameters must match the relay inputs. Mismatched transformers are one of the leading causes of protection failure.

CT Ratio and Class

Select a CT ratio that provides adequate secondary current for the relay. Common ratios are 100/5 A, 200/5 A, 400/5 A, and 600/1 A. The relay’s input range must cover the CT secondary output.

Protection-grade CTs (P class) are required for relay inputs. Metering-grade CTs are not acceptable for protection applications. Check CT burden and accuracy class to ensure the CT can drive the relay input without saturation.

CT Saturation

CT saturation occurs when the fault current exceeds the CT’s capability. Saturation distorts the secondary current waveform, causing the relay to underreach or fail to operate.

For high fault-current systems, select CTs with higher saturation limits or choose relays with anti-saturation sampling algorithms. Check the CT knee-point voltage against the required relay performance.

PT/VT Requirements

If you need voltage-dependent functions (undervoltage, overvoltage, frequency, directional, distance, sync-check), verify the PT/VT ratio and accuracy class. The relay must receive a voltage signal that accurately represents the primary system voltage.

3. Protection Sensitivity and Setting Range

The relay must detect the minimum expected fault current while remaining stable during normal operating conditions. This balance decides whether the protection is reliable.

Consider these parameters when setting the relay:

• Pickup current
• Time delay
• Instantaneous setting
• Time-current curve characteristics
• Minimum fault current at the zone endpoint

If the pickup is set too high, the relay will not see low-magnitude faults. If set too low, it will nuisance-trip on load variations or motor starting.

4. Protection Coordination

Coordination ensures that the nearest relay to the fault trips first. Upstream relays provide backup if the primary relay fails.

Coordination requires analysis of time-current curves for series devices. Allow adequate grading margins between upstream and downstream relays. The coordination margin accounts for:

• Relay operating time tolerances
• Breaker interrupting time
• CT errors
• Safety margin

The engineer performing the coordination study must be familiar with the relay-breaker characteristics.

Relay → Circuit Breaker → Upstream Protection is the typical coordination hierarchy. Verify this chain for every protection zone.

Which Protection Functions Are Commonly Required in an MV Substation?

Overcurrent Protection: ANSI 50/51

Overcurrent protection is the foundation of MV protection. It applies to feeders, transformers, and motors. Pickup and curve shape are set separately, so the settings are reviewed after the model is fixed: see how to set an overcurrent protection relay.

• ANSI 50: Instantaneous trip for severe faults
• ANSI 51: Time-delay trip with inverse or definite-time characteristics

The 51 curve type depends on the application. Extremely inverse curves suit generator protection. Very inverse curves suit transformer protection. Long-time curves suit motor protection.

Earth Fault Protection: 50N/51N

Earth fault protection is required on grounded systems. The configuration depends on the system grounding method:

• Solidly grounded: High fault currents, standard earth fault relays
• Resistance grounded: Lower fault currents, sensitive earth fault relays required
• Ungrounded: No earth fault current, requires voltage-based detection

Residual CT or zero-sequence CT sampling is used for low-current earth faults. For resistance-grounded systems, specify sensitive earth fault protection to ensure minor faults are detected.

Directional Overcurrent Protection: 67/67N

Directional overcurrent protection adds a polarising voltage, which is why it works on ring mains and parallel feeders where plain 50/51 cannot tell direction.

Directional protection is required where fault current can flow in either direction. Typical applications include:

• Ring networks
• Parallel feeders
• Systems with distributed generation
• Bidirectional power flow

Directional relays use voltage reference to determine power flow direction. They trip only when fault current flows in the selected direction, preventing unnecessary tripping of healthy circuits.

Transformer Differential Protection: 87T

Differential protection compares current entering and leaving the transformer. It trips for internal faults within the protected zone.

87T requires careful CT matching and polarity checking. The relay must accommodate transformer turns ratio, vector group, and CT ratio differences. Inrush current blocking is essential to prevent nuisance tripping during transformer energization.

Bus Differential Protection: 87B

Bus differential protection provides high-speed protection for busbar faults. It operates by comparing currents entering and leaving the bus zone.

High-impedance differential and numerical schemes are available. Choose based on the bus configuration and fault current levels. Numerical bus differential relays offer greater flexibility and are easier to commission.

Voltage and Frequency Protection

Voltage and frequency protection functions include:

• ANSI 27: Undervoltage – protects motors from voltage dips
• ANSI 59: Overvoltage – protects capacitors and other equipment
• ANSI 81U: Underfrequency – for load shedding
• ANSI 81O: Overfrequency – for generator protection

These functions are often required for generator connections or systems with distributed generation.

Numerical MV Protection Relay vs Conventional Relay

Numerical relays offer significant advantages over conventional electromechanical or static relays for MV substations. The table below compares key features.

Feature	Conventional Relay	Numerical MV Relay
Protection functions	Limited to fixed set	Multiple, configurable
Measurement	Basic	Advanced, multiple quantities
Event recording	Limited or none	Full event logging
Fault recording	Limited or none	Detailed fault records
Communication	None or basic	Multiple protocols (IEC 61850, Modbus, DNP3)
SCADA integration	Basic	Full integration
Setting flexibility	Fixed or limited	Fully adjustable
Substation automation	Limited	Full support
Cybersecurity	Not applicable	Built-in features

When Should You Choose a Numerical MV Protection Relay?

Numerical relays are recommended for:

• Complex MV substations with multiple protection zones
• Applications requiring multiple protection functions
• SCADA integration and remote monitoring
• Fault recording and event analysis
• Future system expansion and change
• Compliance with modern utility requirements

For simple, fixed applications, a conventional relay may be sufficient. However, the additional cost of a numerical relay is often justified by its flexibility, diagnostics, and communication capabilities.

Communication Requirements for an MV Substation Relay

Communication rarely decides medium voltage protection relay selection on its own. It decides which models stay on the shortlist.

Common Communication Protocols

Select a relay that supports the protocols used by your substation automation system. Common protocols include:

• IEC 61850 – Modern digital substation standard
• Modbus RTU – Widespread in industrial applications
• Modbus TCP – Ethernet-based industrial protocol
• DNP3 – Common in utility SCADA
• IEC 60870-5-103/104 – Utility grid standard

IEC 61850 provides interoperability between devices from different manufacturers. It is the preferred standard for new intelligent substations.

Integration With SCADA and Substation Automation

Determine whether the relay needs to connect to:

• SCADA system
• PLC
• HMI
• RTU
• Substation automation system

The relay must exchange data with these systems for remote monitoring, alarm annunciation, fault reporting, and parameter adjustment. Check that the relay supports the required protocols and provides the necessary data objects.

Digital Inputs and Outputs

Confirm the relay’s I/O configuration meets your requirements:

• Binary inputs – breaker status, external protection signals, interlocking
• Binary outputs – trip command, alarm, control signals

If the standard I/O count is insufficient, specify a relay with expansion modules. Some numerical relays support modular I/O configuration to match project needs.

Check the MV Protection Relay’s Installation Requirements

Auxiliary Power Supply

Verify the relay’s auxiliary power requirements against available site supply:

Supply Type	Typical Values
DC	24 V, 48 V, 110 V, 220 V
AC	110 V, 220 V

Panel Installation

Check panel mounting dimensions and terminal arrangement:

• Panel cutout dimensions
• Rack mounting (19-inch standard)
• DIN rail mounting
• Terminal spacing and wiring access

Select a relay that fits the available panel space. Some relays are built for compact switchgear and take less panel space.

Environmental Conditions

Match the relay’s environmental ratings to site conditions:

Condition	Check
Ambient temperature	Operating range (-25°C to +70°C typical)
Humidity	Condensation risk
Dust	IP rating required
Vibration	Switchgear location
Electromagnetic interference	EMC immunity requirements

Relays in outdoor or harsh environments require higher ingress protection and wider temperature tolerance. Indoor control room installations have less demanding requirements.

Standards to Check When Selecting an MV Protection Relay

Standards settle medium voltage protection relay selection disputes before anyone reaches site. Quote the version year, not just the number.

All relays should comply with relevant international standards. The required standards depend on project specifications and local grid codes.

Core standards include:

• IEC 60255 series – General standard for measuring relays and protection equipment. IEC 60255-1:2022 covers common requirements and test methods.
• IEC 61850 – Communication and automation standard for substations.
• IEEE/ANSI C37 series – Power system protection standards, including ANSI function codes.
• IEC 61000 series – Electromagnetic compatibility requirements.

Check whether the project requires additional certifications for marine, railway, or specific utility applications. These applications may have enhanced requirements beyond the IEC 60255 baseline.

Note: The standards required depend on the project specification, utility requirements, and country-specific regulations. Verify applicable standards before final selection.

Step-by-Step Medium Voltage Protection Relay Selection Process

The five steps below answer how to choose MV protection relay hardware, settings and I/O for one bay. Each step depends on the one before it.

Step	Description
Step 1	Define the protected equipmentIdentify whether the relay protects a feeder, transformer, motor, generator, or busbar.
Step 2	Confirm system voltage and frequencyVerify rated voltage, maximum voltage, and frequency (50/60 Hz).
Step 3	Determine normal and maximum load currentCollect steady-state load, peak load, and overload data.
Step 4	Obtain maximum and minimum fault currentGet three-phase and single-phase fault current values.
Step 5	Check CT/PT specificationsVerify CT ratio, class, burden, and PT ratio.
Step 6	Determine required protection functionsSelect ANSI functions based on equipment and system.
Step 7	Perform protection coordinationComplete time-current curve coordination with upstream/downstream devices.
Step 8	Define communication and SCADA requirementsCheck protocol support and I/O requirements.
Step 9	Check I/O and auxiliary power requirementsConfirm binary inputs/outputs and auxiliary supply voltage.
Step 10	Verify standards and environmental requirementsEnsure relay meets applicable standards and site conditions.
Step 11	Compare suitable relay modelsShortlist relays that meet all requirements.
Step 12	Confirm settings and protection schemeValidate relay settings and coordinate with the rest of the scheme.

Example of MV Protection Relay Selection for a 33 kV Substation

This example shows a practical selection process for a 33 kV distribution feeder. The incoming bay is specified differently; a 33kV protection relay for the incomer carries the upstream coordination burden.

System Data:

Parameter	Value
Voltage	33 kV
Frequency	50 Hz
CT ratio	400/5 A
Maximum load current	280 A
Short-circuit current	12.5 kA
Earthing	Solidly grounded
SCADA required	Yes

Step 1: Determine Protection Functions

For a feeder in this system, standard protection includes:

• Overcurrent protection (50/51)
• Earth fault protection (50N/51N)
• Directional overcurrent (67/67N) – required if the feeder is in a ring or parallel arrangement

Step 2: Check CT Compatibility

The 400/5 A CT output is 5 A at rated primary current. The relay input range must accommodate this level. At 12.5 kA fault current, the CT secondary current is approximately 156 A (assuming linear operation). Check that the CT does not saturate at this level and that the relay input range extends to this value.

Verify CT class and burden against relay requirements.

Step 3: Check Relay Settings

Set the 51 pickup above maximum load current with some margin. For 280 A load, a pickup of approximately 350–400 A is typical (20–40% margin). Check that this setting is below the minimum fault current at the feeder end to ensure sensitivity.

Step 4: Check Communication

Since SCADA is required, select a relay that supports the specified protocol. If the substation uses IEC 61850, choose a relay with native IEC 61850 support.

Step 5: Final Relay Selection

Select a numerical relay that meets all requirements. If the application is standard and no SCADA is required, an entry-level relay with basic overcurrent and earth fault functions may be sufficient.

Common Mistakes When Selecting an MV Protection Relay

Most failed medium voltage protection relay selection decisions share one root cause: the model was ordered before the CT data or the coordination study existed.

Choosing a Relay Based Only on Voltage Rating

Voltage rating is one parameter among many. Load current, fault current, CT matching, and protection functions are equally important.

Ignoring CT Saturation

CT saturation at high fault currents can cause relay misoperation. Verify CT saturation limits and select appropriate CTs or relays with anti-saturation algorithms.

Selecting Pickup Settings Without a Coordination Study

Pickup settings must coordinate with upstream and downstream relays. Without a coordination study, nuisance tripping or loss of selectivity is likely.

Using the Same Relay for Every MV Feeder

Each feeder has different load and fault conditions. Settings and even relay models may need to vary. Do not apply a one-size-fits-all approach.

Ignoring the Grounding System

Earth fault protection depends on the system grounding method. Use sensitive earth fault protection for resistance-grounded systems. For ungrounded systems, earth fault detection requires different methods (voltage-based).

Forgetting SCADA and Communication Requirements

If the relay cannot communicate with SCADA, remote monitoring and control are impossible. Communication capability is often overlooked in initial selection.

Selecting a Relay Without Considering Future Expansion

System loads and fault levels may change over time. Select a relay that can accommodate future changes. Numerical relays with modular I/O and adjustable settings offer better adaptability.

MV Protection Relay Selection Checklist

An MV protection relay specification that leaves CT knee-point voltage or the earthing arrangement open comes back as a change order. Confirm these before freezing the model:

Parameter	What to Check
System voltage	Rated and maximum voltage
Frequency	50/60 Hz
Load current	Normal and maximum
Fault current	Maximum and minimum
CT	Ratio, class, burden, saturation
PT/VT	Ratio and input requirements
Protection functions	Required ANSI codes
Coordination	Upstream/downstream settings
Communication	IEC 61850, Modbus, DNP3, etc.
I/O	Binary inputs and outputs
Power supply	AC or DC auxiliary supply
Installation	Panel dimensions, terminals
Environment	Temperature, humidity, EMC
Standards	IEC/IEEE/local requirements

FAQ About MV Protection Relay Selection

What is an MV protection relay?

An MV protection relay monitors current, voltage, and frequency in medium voltage systems. It detects faults and sends trip commands to circuit breakers to isolate faulty equipment.

How do I select a protection relay for a medium voltage substation?

Start by defining the protected equipment, system voltage, load current, and fault current. Then check CT/PT compatibility, select protection functions, complete coordination, and verify communication and installation requirements. Medium voltage protection relay selection follows that order for a reason: CT data decides what the protection functions can actually see.

What protection functions are required for an MV feeder?

A basic MV feeder typically requires overcurrent protection (50/51) and earth fault protection (50N/51N). Directional overcurrent (67/67N) may be needed for ring networks or parallel feeders.

How does CT ratio affect MV relay selection?

The CT ratio determines the secondary current level supplied to the relay. A ratio that is too large reduces sensitivity. A ratio that is too small may exceed the relay input range or cause saturation.

Do all MV substations need numerical protection relays?

No. Simple substations with standard overcurrent and earth fault requirements may use conventional relays. However, numerical relays provide superior flexibility, diagnostics, and communication capability, making them the preferred choice for most new projects.

What communication protocols are commonly used for substation relays?

IEC 61850, Modbus RTU, Modbus TCP, DNP3, and IEC 60870-5-103/104 are commonly used. IEC 61850 is the standard for modern digital substations.

What is the difference between an MV feeder relay and a transformer protection relay?

A feeder relay provides overcurrent and earth fault protection for lines. A transformer protection relay includes differential protection (87T), overcurrent protection, earth fault protection, and thermal monitoring to address transformer-specific risks.

When is directional overcurrent protection required in an MV substation?

Directional overcurrent protection is required where fault current can flow in either direction. This occurs in ring networks, parallel feeders, and systems with distributed generation or bidirectional power flow.

Conclusion

Medium voltage protection relay selection is not model matching. Work through equipment type, fault level, CT performance, the ANSI function list, coordination, communications and panel constraints, in that order. Ratings alone tell you nothing about selectivity.

Following a structured selection process reduces the risk of miscoordination, nuisance tripping, and protection failure. It also ensures that the relay meets current requirements and can adapt to future system changes.

If you are selecting an MV protection relay for a feeder, transformer, motor, or complete medium voltage substation, provide the system voltage, CT ratio, load current, fault level, required protection functions, and communication requirements. A suitable relay configuration can then be evaluated against the project requirements.

Related reading

• 33kV protection relay: what changes when the incomer sits at 33 kV.
• 22kV protection relay: typical protection for a 22 kV distribution substation.
• digital protection relay for 11kV distribution: numerical relays on 11 kV feeders.
• RMU protection relay: compact relays for ring main units.
• MV motor protection functions: what 6 kV and 10 kV motors need beyond 50/51.
• relay protection system: how one relay fits the wider protection scheme.

References and Technical Sources

Source	What it covers	Type	Edition
IEC 60255-1:2022	Common requirements for measuring relays and protection equipment	IEC standard	2022
IEC 60255-151:2009	Functional requirements for over/under current protection (the 50/51 side)	IEC standard	2009
IEC 60255-121:2014	Functional requirements for distance protection (ANSI 21)	IEC standard	2014
IEC 61869-2:2012	Additional requirements for current transformers: accuracy class, rated burden, accuracy limit factor	IEC standard	2012
IEC 61869-3:2011	Additional requirements for inductive voltage transformers feeding relay inputs	IEC standard	2011
IEC 61850-7-4	Compatible logical node and data object classes for IED communication	IEC standard	2010+AMD1:2020 (Ed.2.1)
ANSI/IEEE C37.2-2022	Standard device function numbers used on this page (50, 51, 67, 87T, 87B)	IEEE standard	2022
IEEE C37.112-2018	Inverse-time characteristic equations for overcurrent relays	IEEE standard	2018
IEC 61000-6-5:2015	EMC immunity for equipment installed in power station and substation environments	IEC standard	2015

Written by Leon Zhang, Protection Application Engineer · Technical review by Li Ming, Electrical Engineer · Last reviewed October 2026