Motor Protection Relay Setting Calculation Guide

Introduction

Motor protection relay setting calculation determines the pickup values and time delays for each protection function to ensure correct operation during faults while allowing normal motor start. An incorrectly configured relay is as dangerous as no protection — it may fail to trip during a fault or cause costly nuisance tripping.

The calculation requires complete motor data (FLA, LRA, starting time), system parameters (CT/PT ratios), and coordination with upstream/downstream devices. This guide provides systematic calculation methods and practical examples for reliable motor protection.

Why ProperMotor Protection Relay Settings Matter

An incorrectly configured three-phase motor protection relay can be just as dangerous as having no protection at all.

Settings Too High

Possible consequences:

• Motor winding damage
• Bearing overheating
• Fire hazards
• Expensive motor replacement

Settings Too Low

Possible consequences:

• Frequent nuisance trips
• Production interruptions
• Reduced equipment availability

The goal is to protect the motor without affecting normal operation.

Motor Data Required for Relay Setting Calculation

Accurate relay settings depend on complete and correct motor data. Missing or incorrect parameters can cause nuisance tripping or protection failure. The table below lists the key motor data required for setting calculation.

Essential Motor Data

Parameter	Symbol	Description	Purpose
Rated Power	Pn	Nameplate power rating (kW/hp)	Determines protection requirements and relay selection
Rated Voltage	Un	Nameplate voltage (e.g., 380V, 6kV, 10kV)	Voltage protection settings and CT/PT ratio verification
Full Load Current	FLA/In	Nameplate full-load current (A)	Base value for all overcurrent, overload, and unbalance settings
Locked Rotor Current	LRA/Ist	Starting current, typically 6-8 × FLA	Sets instantaneous overcurrent pickup; must exceed starting current
Locked Rotor Time (Hot)	LRHOT	Maximum allowable stall time when hot (seconds)	Determines overload trip curve limit
Locked Rotor Time (Cold)	LRCOLD	Maximum allowable stall time when cold (seconds)	Determines cold start capability; affects start supervision setting
Starting Time	tst	Time to reach rated speed (seconds)	Sets start supervision and locked rotor time delay
Thermal Capacity / Damage Curve	—	Motor thermal withstand curve (current vs. time)	Defines damage limit; relay curve must fall below this curve
Service Factor	SF	Typically 1.0 or 1.15	Adjusts overload pickup setting
Motor Design Type	—	NEMA A/B/C/D or IEC classification	Determines starting characteristics; affects coordination
Insulation Class	—	F, H, etc.	Defines maximum allowable temperature rise
Starts Per Hour	—	Maximum allowable cold/hot starts per hour	Sets starts-per-hour protection (66); prevents thermal stress
Cooling Time Constant	τ	Thermal cooling time constant	Required for thermal model accuracy during cooling
CT Ratio	—	Primary/secondary ratio (e.g., 100/5A)	Converts primary current to relay input
PT Ratio (if applicable)	—	e.g., 10kV/100V	Converts primary voltage to relay input

Additional Data for Motors with RTD Sensors

Parameter	Description	Purpose
RTD Type	PT100, PT1000, or Ni120	Determines temperature input configuration
RTD Locations	Windings (3) + Bearings (2-3)	Identifies monitoring points and alarm/trip thresholds
Alarm Temperature	Typically 120-140°C for Class F	Early warning
Trip Temperature	Typically 140-160°C for Class F	Immediate shutdown

Verification Checklist

• □ Nameplate data is complete and matches the actual motor
• □ CT ratio matches relay input range
• □ Starting method is confirmed (DOL/Star-Delta/Soft-Starter/VFD)
• □ Motor damage curve has been obtained
• □ System grounding method is known
• □ Upstream protection device characteristics are available

Motor Full Load Current Calculation

Motor full-load current (FLC or FLA) is the foundation for all protection relay settings, conductor sizing, and switchgear selection. Accurate calculation ensures the motor starts reliably while protection devices trip correctly during faults .

Full-Load Current vs. Full-Load Amps

A critical distinction in motor calculations:

Term	Source	Use For
FLC (Full-Load Current)	NEC/IEC standard tables	Branch-circuit conductor sizing, short-circuit protection, disconnecting switch rating
FLA (Full-Load Amps)	Motor nameplate rating	Overload protection settings, relay calibration

Never use nameplate current for conductor sizing — always use table values per NEC 430.6(A) 

Three-Phase Motor FLC Formula

When standard tables are unavailable, calculate FLC using:

I = P / (√3 × V × η × PF)

Parameter	Symbol	Description
I	Full-load current	Calculated value (Amperes)
P	Rated power	Motor output power (Watts — multiply kW by 1000)
V	Line voltage	System voltage (Volts)
η	Efficiency	Motor efficiency (typically 0.90–0.96)
PF	Power factor	Typically 0.85 for induction motors

Single-Phase Motor FLC Formula

I = P / (V × η × PF)

Approximate FLC from Standards

For quick reference, NEC Table 430.250 provides standard three-phase motor full-load currents :

HP	208V	230V	460V	575V
5	16.7	15.2	7.6	6.1
10	30.8	28	14	11
25	74.8	68	34	27
50	143	130	65	52
100	273	248	124	99

Application of FLC in Protection Sizing

Conductor Sizing (NEC 430.22)
Minimum conductor ampacity = FLC × 125% 

Overload Protection (NEC 430.32)

• Motors with service factor ≥1.15: ≤125% of nameplate FLA
• All other motors: ≤115% of nameplate FLA 

Instantaneous Overcurrent Pickup
Typically 6–8 × FLC (must exceed motor starting current) 

Motor Protection Relay Setting Calculation Methods

Protection relay setting calculation is the process of determining the appropriate pickup values and time delays for each protection function to ensure the relay operates correctly during faults while allowing normal motor starting and running. The goal is to position the relay operating curve between the motor starting curve and the motor damage curve — providing maximum protection without nuisance tripping. This section outlines the calculation methods for key motor protection functions.

Motor Overload Relay Setting

Overload protection (ANSI 49) protects the motor against prolonged operation above rated current. It uses a thermal model with an inverse-time characteristic — the higher the current, the faster the trip.

Key Parameters Required:

• Motor FLA (full-load current)
• Service factor (typically 1.0 or 1.15)
• Trip class (Class 10/20/30 based on starting time)
• Motor thermal damage curve
• CT ratio

Calculation Method:

Pickup Setting (Overload Current Threshold):

• For motors with SF ≥ 1.15: Pickup = FLA × 1.0
• For motors with SF = 1.0: Pickup = FLA × 0.90–0.95

Trip Class Selection:

• Class 10: For motors starting within 10 seconds (typical for most LV motors)
• Class 20: For motors starting within 10–20 seconds (high-inertia loads)
• Class 30: For motors starting within 20–30 seconds (very high-inertia loads)

Thermal Model Settings:

• Hot/cold stall time ratio: Typically 0.7–0.8 (motor can withstand ~70-80% of cold stall time when hot)
• Cooling time constant: Set per motor manufacturer data (typical 15–30 minutes for LV motors, 30–60 minutes for MV motors)
• RTD bias: Enable RTD inputs for winding temperature correction (recommended for MV motors)

Example: 200kW, 380V Motor

• FLA = 350A, SF = 1.15, Starting time = 12 seconds
• Overload pickup = 350A × 1.0 = 350A (primary)
• Trip class = Class 20 (starting time 12s falls in 10–20s range)
• RTD alarm = 130°C, RTD trip = 145°C (Class F insulation)

Overcurrent Protection Setting

Overcurrent protection (ANSI 50/51) provides backup protection for phase-to-phase and phase-to-ground faults. The time overcurrent element (51) uses inverse-time characteristics, while the instantaneous element (50) provides high-speed clearing for severe faults.

Key Parameters Required:

• Motor FLA
• Motor starting current (6–8 × FLA)
• Motor starting time
• Upstream protection coordination
• CT ratio

Calculation Method:

Time Overcurrent Pickup (51):

• Set at 115–125% of FLA
• Must be below motor stator damage curve and above maximum continuous load
• Formula: Pickup = FLA × 1.15 (minimum)

Time Dial Setting:

• Select IEC or IEEE inverse curve based on system requirements
• Coordinate with upstream devices: ensure 0.2–0.3 second margin between operation curves
• Time dial should allow successful motor start but trip before motor damage occurs

Instantaneous Overcurrent Pickup (50):

• Typically set at 6–8 × FLA
• Must exceed maximum motor starting current to avoid nuisance tripping during start
• Formula: Pickup = LRA × 1.1–1.2 (must be below cable damage curve)

Example: 6kV, 1000kW Motor

• FLA = 120A, Starting current = 750A (6.25 × FLA)
• Time OC pickup = 120 × 1.15 = 138A
• Instantaneous pickup = 750 × 1.2 = 900A (7.5 × FLA)
• IEC standard inverse curve, time dial selected to trip at 2s for 6× FLA fault current

Locked Rotor Protection Setting

Locked rotor protection (ANSI 51LR) detects when the motor fails to start or becomes mechanically jammed during operation, drawing locked rotor current (6–8 × FLA) for an extended period.

Key Parameters Required:

• Locked rotor current (LRA)
• Locked rotor time (hot and cold)
• Motor starting time
• CT ratio

Calculation Method:

Pickup Setting:

• Set at 100–110% of LRA (or 6–8 × FLA)
• Must be above maximum normal starting current to avoid tripping during start

Time Delay Setting:

• Must exceed normal starting time
• Set at 1.1–1.2 × maximum starting time
• Must be less than locked rotor withstand time (from motor damage curve)

Start Supervision (ANSI 48):

• Set at 1.2–1.5 × normal starting time
• If motor still drawing locked rotor current after this time, relay trips

Example:

• LRA = 6.5 × FLA = 780A, Starting time = 15 seconds
• Locked rotor pickup = 780A × 1.05 = 819A (6.8 × FLA)
• Locked rotor time delay = 15 × 1.2 = 18 seconds
• Start supervision = 15 × 1.4 = 21 seconds

Stall Protection Setting

Stall protection monitors the motor current during starting. It protects against prolonged acceleration due to low voltage, high inertia, or mechanical overload.

Key Parameters Required:

• Starting current profile
• Normal starting time
• CT ratio

Calculation Method:

Start Monitoring:

• Monitors current drawn during starting sequence
• If current does not drop below 1.0–1.1 × FLA within the allowable starting time, relay trips

Setting Values:

• Trip after normal starting time × 1.2–1.5
• The stall current threshold is set at 100–120% of FLA — if current remains above this after normal start time, a stall condition is detected

Functional Principle:

• During a stalled condition, current remains high (approaching locked rotor level) for an extended period
• The timer starts when the motor is energized and continues until current falls below the stall threshold (typically 100–120% of FLA)
• If current remains above threshold when timer expires, relay trips

Phase Loss Protection Setting

Phase loss (or single-phasing) occurs when one phase of the three-phase supply is lost. This condition causes the motor to draw excessive current in the remaining phases, leading to rapid overheating and potential motor burnout.

Key Parameters Required:

• Motor FLA
• CT ratio

Calculation Method:

Negative Sequence Unbalance Setting (ANSI 46):

• Set at 10–20% of FLA
• Alarm threshold: Typically 8% unbalance
• Trip threshold: Typically 12% unbalance

Current Unbalance Calculation:

• Calculate unbalance using the phase currents:
  • Average current = (IA + IB + IC) / 3
  • Maximum deviation = Max |IA – Iavg|, |IB – Iavg|, |IC – Iavg|
  • Unbalance (%) = (Maximum deviation / Average current) × 100

Typical Settings:

• Unbalance alarm: 10% with 2–3 second delay
• Unbalance trip: 15% with 0.5–1 second delay
• Phase loss trip: <20% of FLA with immediate trip

Motor Earth Fault Relay Setting

Earth fault protection (ANSI 50N/51N) detects ground faults that may not produce significant phase overcurrent, particularly in resistance-grounded systems where earth fault currents are limited.

Key Parameters Required:

• System grounding method
• Earth fault current level (from system study)
• CT ratio (including zero-sequence CT)
• CT cable shield grounding arrangement

Calculation Method:

Earth Fault Pickup Setting:

• For resistance-grounded systems: Set at 5–15% of FLA
• For solidly grounded systems: Set at 20–40% of FLA
• For ungrounded systems: Use sensitive earth fault (50N) at 2–5% of FLA

Zero-Sequence CT Selection:

• Must be sized for the available earth fault current
• CT ratio must provide sufficient secondary current at minimum fault level for reliable operation

Time Delay Setting:

• Alarm: 0.5–1 second delay
• Trip: 1–2 second delay (coordinate with upstream earth fault protection)

**Important: Cable shield grounding must be carefully implemented to avoid misoperation from shield currents. The shield should be grounded only at one point to prevent circulating currents through the CT.

Underload Protection Setting

Underload protection (ANSI 37) detects loss of load conditions such as pump dry running, broken fan belt, or loss of prime. It prevents equipment damage and energy waste.

Key Parameters Required:

• Motor normal running current at minimum load
• Motor FLA
• CT ratio

Calculation Method:

Underload Pickup Setting:

• Set at 40–70% of FLA (depending on application)
• For pumps: 50–70% of FLA (dry running protection)
• For fans: 40–60% of FLA (belt breakage detection)
• For compressors: 50–65% of FLA (loss of compression)

Time Delay Setting:

• Typically 3–10 seconds delay to avoid nuisance tripping during transient load reductions
• Must allow for normal load variations

Example:

• Pump motor FLA = 100A, Normal running current at minimum load = 55A
• Underload pickup = 55A × 0.9 = 50A (50% of FLA)
• Time delay = 5 seconds

Negative Sequence Protection Setting

Negative sequence protection (ANSI 46) protects the motor against unbalanced supply conditions that generate negative-sequence currents and cause excessive rotor heating.

Key Parameters Required:

• Motor FLA
• Motor K factor (derating factor for unbalance) from motor manufacturer
• CT ratio

Calculation Method:

Negative Sequence Pickup Setting:

• Set at 10–20% of FLA
• Formula: Pickup = FLA × 0.1–0.2

Time Delay Setting:

• Alarm: 3–5 seconds delay
• Trip: 1–2 seconds delay

K Factor Application:
The K factor (typically 2–8) determines the degree of additional heating caused by unbalance. A higher K factor means the motor is more sensitive to unbalance.

Example:

• FLA = 100A, K factor = 4
• Negative sequence pickup = 100 × 0.15 = 15A (15% of FLA)
• Trip delay = 1 second

Motor Differential Protection Setting

Differential protection (ANSI 87M) provides fast and sensitive protection for stator winding internal faults (phase-to-phase and turn-to-turn faults) in large motors (>2000kW).

Key Parameters Required:

• Motor rated current
• CT ratio (line and neutral CTs)
• CT characteristics (5P20 or PX class recommended)
• Motor starting time
• Motor design data

Calculation Method:

Differential Pickup Setting:

• Set at 20–40% of rated current
• Must be above maximum unbalance current under normal conditions
• Formula: Pickup = Irated × 0.2–0.4

Slope Settings:

• Slope 1: 20–30% (for low through-fault currents)
• Slope 2: 60–80% (for high through-fault currents, external faults)

Start Blocking:

• Block differential during starting for 10–15 seconds (or until current drops below 2 × FLA)
• Prevents maloperation due to CT saturation during start

Example: 1.4MW, 11kV Motor

• Rated current = 90A
• Differential pickup = 90 × 0.2 = 18A (20% of rated)
• Slope 1 = 30%, Slope 2 = 70%
• Start blocking: 12 seconds

Three-Stage Current Protection Setting

Three-stage current protection provides progressive protection against different levels of fault current, using three independent overcurrent stages.

Stage 1: Instantaneous Overcurrent (ANSI 50)

Parameter	Setting Rule	Purpose
Pickup	6–8 × FLA	High-speed clearing of severe faults near the motor
Time Delay	0–0.1 seconds	Instantaneous trip for high-magnitude faults

Stage 2: Definite-Time Overcurrent

Parameter	Setting Rule	Purpose
Pickup	3–5 × FLA	Clearing moderate overcurrent conditions
Time Delay	0.2–0.5 seconds	Fixed time delay for selectivity with other devices

Stage 3: Inverse-Time Overcurrent (ANSI 51)

Parameter	Setting Rule	Purpose
Pickup	1.15–1.25 × FLA	Backup protection for faults with lower current levels
Time Dial	Coordinated with upstream/downstream curves	Inverse-time characteristic provides coordinated protection

Coordination between Stages:

• Stage 1 should clear high-magnitude faults with no intentional delay
• Stage 2 should operate for moderate fault levels with a short time delay
• Stage 3 should provide backup protection for all other overcurrent conditions

Example:

• FLA = 200A, Starting current = 1200A
• Stage 1 pickup = 200 × 7 = 1400A (7 × FLA), delay 0s
• Stage 2 pickup = 200 × 4 = 800A (4 × FLA), delay 0.3s
• Stage 3 pickup = 200 × 1.2 = 240A (1.2 × FLA), IEC inverse curve, TMS = 0.1

Important Notes for All Settings:

• Always verify settings against motor manufacturer damage curves
• Coordinate with upstream protection devices (0.2–0.3 second margin)
• Test settings using fault simulation software
• On-site commissioning verification is essential
• Settings should be stored and documented per serial number for traceability

Motor Protection Relay Setting Calculation Example

This section provides a practical calculation example for a medium-voltage motor protection relay.

Motor Data

Parameter	Value
Rated Power	1.4 MW
Rated Voltage	11 kV
Full Load Current (FLA)	90 A
Locked Rotor Current (LRA)	585 A (6.5 × FLA)
Starting Time	12 seconds
LR Time (Hot / Cold)	20s / 30s
Service Factor	1.15
CT Ratio	150/5 A (30:1)

Setting Summary

Protection	ANSI	Primary Pickup	Secondary Pickup	Time Delay
Overload	49	90 A (Class 20)	3.00 A	Inverse-time
Overcurrent (51)	51	103.5 A (1.15×FLA)	3.45 A	IEC Inv, TMS=0.1
Instantaneous OC	50	630 A (7×FLA)	21.0 A	0 s
Locked Rotor	51LR	614 A (1.05×LRA)	20.5 A	14.4 s
Start Supervision	48	90 A	3.00 A	16.8 s
Negative Sequence	46	13.5 A (15% FLA)	0.45 A	1 s
Earth Fault	51N	9.0 A (10% FLA)	0.30 A	1.0 s
Differential	87M	22.5 A (25% Irated)	0.75 A	Start blocked
Undervoltage	27	8.8 kV (80%)	—	2 s
Overvoltage	59	12.65 kV (115%)	—	1 s

Key Setting Principles Applied

• Overload (49): Pickup = FLA × 1.0 (SF ≥1.15); Class 20 selected based on 12s starting time
• Overcurrent (51): Pickup = FLA × 1.15; TMS coordinated to operate at ~2s for 6×FLA fault current
• Instantaneous (50): Pickup = 7×FLA, must exceed starting current (6.5×FLA)
• Locked Rotor (51LR): Pickup = 1.05×LRA; delay = 12s × 1.2 = 14.4s (< hot stall 20s)
• Start Supervision (48): Delay = 12s × 1.4 = 16.8s
• Negative Sequence (46): Pickup = 15% FLA; trip at 12% unbalance with 1s delay
• Earth Fault (51N): Pickup = 10% FLA (resistance-grounded system); 1s delay
• Differential (87M): Pickup = 25% Irated; Slope1=30%, Slope2=70%; blocked during 12s start
• Under/Over Voltage: 80% / 115% of rated voltage with 2s / 1s delay

Coordination Verification

Check	Result
Overcurrent vs. Starting	2s trip at 6×FLA; motor reaches speed in 12s → no nuisance trip
Instantaneous vs. Starting	Pickup 630A > starting 585A → allows normal start
Locked Rotor vs. Damage	Trip at 14.4s < hot stall 20s → protects motor
Differential Start Blocking	Blocked for 12s → prevents CT saturation maloperation

CT Ratio and Relay Setting Conversion

Current transformers (CTs) convert primary currents to manageable secondary levels for relays and instruments. Correct CT ratio selection and proper conversion between primary and secondary values are essential for accurate protection settings.

Why CT Ratio Matters

CT ratio determines the relationship between primary current (motor current) and secondary current (relay input). If the CT ratio is incorrect, all protection settings will be wrong — leading to nuisance tripping or failure to protect the motor.

Standard CT Ratios

CT Ratio	Primary Current	Secondary Current	Application
100/5	100A	5A	Small LV motors
200/5	200A	5A	Standard LV motors
400/5	400A	5A	Large LV motors
100/1	100A	1A	MV motors (long cable runs)
600/5	600A	5A	MV motors
1200/5	1200A	5A	Large MV motors

Standard secondary ratings: 5A (most common) or 1A (for long distances).

CT Ratio Selection

Step 1: Determine Primary Current Range

• CT primary rating should be approximately 125–150% of motor FLA
• Must handle motor starting current (6–8 × FLA) without saturation

CT Ratio Selection Rule:
CT Primary ≥ FLA × 1.25 (minimum)
CT Primary ≥ FLA × 1.5 (recommended)

Example:

• Motor FLA = 350A
• CT Primary = 350 × 1.5 = 525A
• Select standard CT: 600/5A

CT Saturation Considerations

CTs must remain accurate during high fault currents to ensure correct relay operation.

Saturation Check:

• CT must not saturate at maximum fault current
• CT knee-point voltage must exceed maximum secondary voltage at fault
• For differential protection, 5P20 or PX class CTs are recommended

Primary-to-Secondary Conversion

Formula:

Secondary Current = Primary Current × (CT Secondary / CT Primary)

Example:

• CT Ratio = 600/5A (ratio = 120:1)
• Motor FLA = 350A (primary)
• Secondary FLA = 350 × (5/600) = 350 / 120 = 2.92A

General Conversion:

To Convert	Calculation
Primary → Secondary	Isecondary = Iprimary × (CTsec / CTpri)
Secondary → Primary	Iprimary = Isecondary × (CTpri / CTsec)

Relay Setting Conversion

All relay settings must be converted from primary values to secondary values based on the CT ratio.

Conversion Steps:

1. Calculate the relay setting in primary amps based on motor data
2. Divide by CT ratio to obtain secondary amps for relay programming

Example:

Setting	Primary Value	CT Ratio	Secondary Value
Overload Pickup	90A	600/5	90/120 = 0.75A
Overcurrent Pickup	103.5A	600/5	103.5/120 = 0.86A
Instantaneous Pickup	630A	600/5	630/120 = 5.25A

Note: Most digital relays allow programming in both primary and secondary values, but always verify which unit is used.

Quick Reference Conversion Table

CT Ratio	CT Factor	Conversion (A→A)
100/5	20	÷20
150/5	30	÷30
200/5	40	÷40
300/5	60	÷60
400/5	80	÷80
500/5	100	÷100
600/5	120	÷120
800/5	160	÷160
1000/5	200	÷200
1200/5	240	÷240

Zero-Sequence CT for Earth Fault Protection

For sensitive earth fault protection, a zero-sequence CT (core-balance CT) is used.

Selection Rule:

• Primary rating: Typically 50–100% of motor FLA
• Must detect minimum earth fault current reliably (typically 5–15% of FLA)

Example:

• Motor FLA = 350A
• Select zero-sequence CT: 200/5A
• Earth fault pickup = 10% FLA = 35A (primary) → 35/40 = 0.88A (secondary)

Common Mistakes to Avoid

Mistake	Consequence
Using wrong CT ratio	All settings off by factor
Forgetting to convert	Relay set incorrectly
CT saturation at faults	Relay fails to operate
Mixing 5A and 1A CTs	Incorrect scaling
Wrong CT polarity (differential)	Nuisance tripping

Motor Protection Relay Setting Coordination

Protection coordination ensures that when a fault occurs, the correct protection device operates to isolate only the faulted section while keeping the rest of the system online. Without proper coordination, a fault on a motor circuit could trip the upstream feeder breaker, shutting down an entire production line unnecessarily. This section outlines the principles and methods for coordinating motor protection relay settings with upstream and downstream devices.

What Is Protection Coordination？

Protection coordination is the systematic grading of protection device operating times and currents to achieve selective tripping. When a fault occurs at any point in the system, the protection device closest to the fault should operate first. Only if that device fails should upstream devices operate as backup.

The Selective Tripping Principle:

• Fault on motor circuit → Motor relay trips first
• Motor relay fails → Feeder relay trips as backup
• Feeder relay fails → Incoming relay trips as backup

Coordination Partners

Motor protection relays coordinate with:

Device Type	Location	Role
Upstream protection	Feeder breaker, substation relay	Backup protection if motor relay fails
Downstream protection	Local switchgear, branch circuits	Must coordinate to avoid nuisance tripping
Other motor relays	Same bus, same feeder	Must coordinate to isolate only the faulted motor

Note: Coordination is not limited to protection devices — it also applies to:

• Switchgear ratings: Must withstand fault current until protection operates
• Cable ratings: Must survive fault current for the clearing time
• CT ratings: Must remain accurate for the coordination time

Coordination Goals

Goal	Description
Selectivity	The nearest device trips first; upstream devices provide backup only
Speed	Faults are cleared as quickly as possible to minimize damage
Security	Protection operates correctly for all fault types and locations
Stability	The system remains stable during and after fault clearing

Coordination with Upstream Protection

The motor protection relay must coordinate with the upstream feeder relay to ensure selectivity.

Key Rule:

• The upstream relay must have a longer operating time than the motor relay for all fault current levels
• A minimum time margin of 0.2–0.3 seconds should be maintained

Coordination Method:

1. Plot the motor relay operating curve
2. Plot the upstream relay operating curve
3. Ensure the upstream curve is to the right of the motor curve for all current values
4. Check that the time margin is at least 0.2 seconds at maximum fault current

Example:

• Motor relay trip time at 6×FLA = 1.0 second
• Upstream relay trip time at same current must be ≥1.3 seconds (1.0 + 0.3)

Coordination with Motor Starting Curve

Protection settings must coordinate with the motor starting current and duration to avoid nuisance tripping.

Starting Current Profile:

• Inrush current: 6–8 × FLA at start, decaying to FLA as motor reaches speed
• Duration: 5–30 seconds depending on motor size and load inertia

Key Rules:

• Overcurrent relay curve must be above the motor starting curve
• Instantaneous pickup must be higher than the maximum starting current
• Locked rotor time delay must exceed the normal starting time

Coordination Check:

1. Plot the motor starting current curve (current vs. time)
2. Plot the protection relay operating curve
3. Ensure the relay curve is above and to the right of the starting curve
4. Verify sufficient margin to prevent nuisance tripping during start

Coordination with Motor Damage Curve

The protection relay must operate before the motor is damaged by overheating. The motor damage curve (thermal withstand curve) defines the safe operating limit.

Key Rules:

• The relay curve must be below and to the left of the motor damage curve
• The relay must trip before the motor reaches its thermal limit

Coordination Check:

1. Obtain the motor damage curve from the motor manufacturer
2. Plot the protection relay operating curve
3. Ensure the relay curve is below the damage curve for all overload conditions

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Coordination Time Margins

Margin	Recommended Value	Purpose
Upstream-downstream	0.2–0.3 seconds	Ensures selectivity between devices
Relay vs. starting curve	>0.1 seconds	Prevents nuisance tripping
Relay vs. damage curve	10–20% margin	Ensures motor protection before damage

Coordination Example: Motor Feeder

Consider a motor supplied from a feeder breaker with upstream protection.

Device	Pickup (A)	Trip Time at 6×FLA
Motor Relay (51)	103.5A (1.15×FLA)	1.0 second
Feeder Relay (51)	120A	1.4 seconds
Incoming Relay (51)	150A	2.0 seconds

Result:

• Motor fault → Motor relay trips at 1.0s (selective)
• Motor relay fails → Feeder relay trips at 1.4s (backup)
• Feeder relay fails → Incoming relay trips at 2.0s (backup)

Coordination Problems and Solutions

Problem	Cause	Solution
Motor trips on start	Relay curve below start curve	Increase time dial or pickup
Motor fails to trip on fault	Relay curve above damage curve	Decrease time dial or pickup
Upstream trips for motor fault	Time margin too small	Increase upstream time delay
Relay trips on CT saturation	CT undersized	Use higher class CT

Common Motor Protection Relay Setting Mistakes

Incorrect relay settings can leave motors unprotected or cause frequent tripping. Below are common mistakes and how to prevent them.

Common Setting Mistakes Summary

Mistake	Consequence	Prevention
Wrong CT ratio	All settings scaled incorrectly	Verify CT nameplate matches relay configuration
Overload setting too high	Motor runs overloaded without tripping; thermal damage accumulates	Set 100% FLA (SF≥1.15) or 90-95% FLA (SF=1.0)
Overload setting too low	Nuisance tripping during normal operation	Set 100% FLA (SF≥1.15)
Altitude not considered	Motor overheats at high altitude	Derate 3% per 1000m above 1000m altitude
Instantaneous pickup too low	Trips on every start	Set 6-8 × FLA, above maximum starting current
Locked rotor delay too short	Trips during normal start	Set 1.1-1.2 × normal starting time
Overcurrent time dial too fast	Trips on start or upstream coordination failure	Set to allow start with 0.2-0.3s coordination margin
No coordination with upstream	Motor fault trips upstream breaker; entire line shuts down	Verify 0.2-0.3s margin with upstream curve
Motor damage curve ignored	Motor damaged before relay operates	Relay curve must fall below damage curve
CT saturation at fault	Relay fails to operate	Use CTs with sufficient knee-point voltage; 5P20/PX class for differential
Using instantaneous instead of definite-time	Upstream coordination failure	Use 51 for backup coordination; 50 only for high-magnitude faults
No testing before commissioning	Undiscovered errors cause failure during real faults	Use secondary injection testing before energization

Best Practices

• Use a standardized setting calculation sheet
• Obtain complete motor data before calculation
• Plot coordination curves for verification
• Test settings before energization
• Store settings by serial number
• Review settings after commissioning

Motor Protection Relay Commissioning Checklist

Commissioning verifies relay settings and wiring before the motor enters service. The following checklist covers pre-energization checks, secondary injection testing, and live commissioning tests.

Pre-Energization Checks

No.	Check Item	Status	Notes
1	Relay firmware version matches specification	☐	Record version
2	Configuration file loaded correctly	☐	Verify parameters
3	CT ratio matches actual CT nameplate	☐	Check primary/secondary
4	PT ratio matches actual PT (if applicable)	☐	Verify scaling
5	All protection settings entered per calculation sheet	☐	Cross-check each
6	Communication parameters configured	☐	IP, baud rate, etc.
7	Date and time set correctly	☐	Sync with plant time
8	CT/PT polarity correct	☐	Verify S1/S2, phase sequence
9	All terminal connections tightened to torque spec	☐	Use torque wrench
10	Ground connection secure	☐	Measure resistance
11	Trip and alarm circuits functional	☐	Manual test contacts

Secondary Injection Testing (Motor De-Energized)

No.	Test Item	Acceptance Criteria	Status
12	Overload (49)	Trip at calculated pickup (±5%)	☐
13	Overcurrent (51)	Trip time matches curve (±5%)	☐
14	Instantaneous (50)	Trip at pickup (±3%)	☐
15	Locked Rotor (51LR)	Trip time within ±5%	☐
16	Start Supervision (48)	Trip after set delay	☐
17	Negative Sequence (46)	Trip at set unbalance (±5%)	☐
18	Earth Fault (50N/51N)	Trip at pickup (±5%)	☐
19	Differential (87M)	Trip at pickup; verify slopes	☐
20	Under/Over Voltage (27/59)	Trip at set voltage (±5%)	☐
21	Undercurrent (37)	Trip at pickup (±5%)	☐
22	Starts/Hour (66)	Block after count exceeded	☐

Communication Verification

No.	Check Item	Acceptance Criteria	Status
23	Modbus/IEC 61850 communication	Relay responds to read requests	☐
24	SCADA/DCS integration	All points read correctly	☐
25	Remote control commands	Relay responds to remote trip/close	☐

Live Commissioning Tests (Motor Energized)

No.	Test Item	Acceptance Criteria	Status
26	Motor starts without tripping	No trip during start	☐
27	Phase currents balanced	Unbalance < 5%	☐
28	Voltage measurement correct	Within ±2% of actual	☐
29	Relay display matches measured values	Correct readings	☐
30	Alarm contacts operate at thresholds	Triggers correctly	☐
31	Communication data matches relay display	SCADA values match	☐
32	Load test (50%, 75%, 100%)	No nuisance trips; accurate readings	☐

Documentation and Sign-Off

No.	Document	Status
33	Commissioning report completed	☐
34	Setting record saved (digital + hard copy)	☐
35	Calibration certificate included	☐
36	As-built wiring diagram updated	☐

Role	Name	Signature	Date
Commissioning Engineer
Site Manager / Client

Post-Commissioning Recommendations

• Save digital backup of all settings
• Perform annual secondary injection testing
• Review settings after major motor maintenance
• Keep commissioning report for future reference

FAQ

What is the best overload setting for a motor?

Most industrial motors use 105–120% of full load current.

How do I calculate locked rotor protection?

Typically 6–8 times motor full load current with a suitable time delay.

Can I use the same settings for VFD motors?

No. VFD-driven motors often require different overload and stall protection settings due to harmonic content and controlled startup characteristics.

How often should relay settings be reviewed?

Settings should be checked after commissioning, maintenance work, process modifications, or motor replacement.

How to test motor protection relay?

Perform secondary injection test to simulate fault currents and voltages, verify all protection functions, trip logic and operating time.

Where can I find motor protection relays?

You can contact us, we are a professional motor protection relay wholesaler in China.

Which fault condition thermal overload relay protects ac induction motor

It mainly protects against thermal overload and sustained overcurrent caused by locked rotor, phase loss, long-time heavy load.

What is the wholesale price of motor protection relays?

You can contact us, we are a professional motor protection relay wholesaler and motor protection relay supplier in China, offering favorable wholesale prices for motor protection relays.