Motor Protection and Relay Coordination: Reading and Building a TCC for US Medium-Voltage Systems 

Part A — PV String I-V Curve Testing at a Glance

A time-current coordination (TCC) study answers one question: when a fault or overload occurs, does the device closest to it operate first, while every upstream device waits, ready to act as backup? For a large medium-voltage motor fed from a utility substation transformer, the answer depends on five curves: the motor's starting curve, its hot and cold thermal limits, the motor protection relay, the upstream relays separated by a coordination time interval, and the transformer's through-fault damage curve.



This article works through a typical US system: a 138 kV utility supply, a 138–13.8 kV substation transformer, and a 6,000 hp, 13.2 kV induction motor on the 13.8 kV bus.

The five things a motor TCC must show

Selectivity and protection pull in opposite directions. Good coordination finds settings that are slow enough to be selective and still fast enough to protect equipment and limit arc-flash energy.



The example system

Common faults and their curve signatures

Part B — Motor Protection and Relay Coordination: Reading and Building a TCC for US Medium-Voltage Systems

How to coordinate motor protection relays with upstream feeder and transformer protection, using IEEE and NEMA practice, US system voltages and a fully worked 138/13.8 kV example.

Why coordination studies matter

A large medium-voltage motor is often the most expensive single load in a plant and one of the hardest on the power system. It draws six or more times its full-load current when starting. It can be damaged in seconds if it stalls. And it sits at the bottom of a chain of protective devices that must all respond correctly to the same fault.

If the motor relay is set too sensitive, the motor trips during a normal start. If it is set too slow, a stalled or overloaded motor overheats. If upstream relays are not coordinated, a motor fault can trip the whole 13.8 kV bus or even the substation transformer. And if the transformer relay is too slow, a through fault can damage a transformer that may take a year or more to replace.

A time-current coordination study, plotted on a log-log TCC chart, is how engineers check all of these requirements at once. IEEE Std C37.96 (AC motor protection), IEEE Std C37.91 (transformer protection), IEEE Std C57.109 (transformer through-fault duration), NEMA MG 1 (motor performance) and NEC Articles 430 and 450 together define the US framework.

US system voltages and reference currents

A TCC plots time against current, so every curve must be referred to a common voltage base. On a 138/13.8 kV chart, the current scale for 138 kV devices is one-tenth of the 13.8 kV scale. Standard US nominal voltages from ANSI C84.1 used in industrial and utility work include 480 V, 4.16 kV, 13.8 kV, 34.5 kV, 69 kV, 115 kV, 138 kV and 230 kV. Medium-voltage motors are rated at utilisation voltages a little below the system nominal: 4,000 V motors on 4.16 kV systems and 13,200 V motors on 13.8 kV systems.

Rated current is calculated in the usual way:

For the motor, using a typical efficiency of 96% and power factor of 0.90:

Use nameplate full-load current for settings whenever it is available. The calculation is only a check.

1. The motor curve and starting current

The motor starting curve shows the current the motor draws from energisation until it reaches full speed. At standstill, the rotor presents a low impedance, so the motor draws locked-rotor current, typically 5–7 times full-load current for medium-voltage induction motors. NEMA MG 1 code letters define the locked-rotor kVA per horsepower for each design.

The curve has three parts:

1. The asymmetrical inrush. For the first few cycles, the current contains a decaying DC offset that depends on the point on the voltage wave at which the breaker closes and on the X/R ratio of the circuit. The RMS asymmetrical current can reach about 1.5–1.6 times the symmetrical locked-rotor current. This is why the starting curve on the TCC has a short, higher step at the left of the time axis.
2. Acceleration. Current stays near locked-rotor value while the motor accelerates, then falls as slip decreases. Acceleration time depends on load inertia, load torque and terminal voltage.
3. Running. Current settles at the load current, at or below full-load current.

Voltage dip during starting matters. Locked-rotor torque varies with the square of terminal voltage, so a 10% voltage dip reduces torque by about 19% and lengthens acceleration time. Starting studies should model the actual source impedance and the transformer tap position.

For the example motor, locked-rotor current is about 1,360 A symmetrical and the initial asymmetrical current up to about 2,180 A.

2. Cold-start and hot-start thermal limits

During a start or a stall, rotor bars carry very high current and heat rapidly. The motor manufacturer supplies the safe stall time and thermal limit curves:

• Cold start: the motor starts from ambient temperature, so it has the most thermal margin.
• Hot start: the motor starts after running at rated load, so its windings and rotor are already hot and the allowable locked-rotor time is shorter.

NEMA MG 1 assumes a medium-voltage motor can make two starts in succession from cold, or one start from hot. Many motors also have a limited number of starts per hour.

The protection must be coordinated with the hot-start limit, because it is the more restrictive condition. Where the safe stall time is shorter than the acceleration time, which is common for high-inertia loads such as large fans, a time-overcurrent relay alone cannot separate a normal start from a stall. A speed switch or zero-speed input (device 14), an impedance-based stall element or a thermal model that tracks rotor heating is then needed.

3. The motor protection relay

A modern multifunction motor relay provides many protective elements. The ANSI/IEEE device numbers below are the standard US labels.

Setting the overload curve

The 49/51 curve on the TCC must:

• pass to the right of, and above, the motor starting curve, with margin for reduced-voltage starts;
• pass to the left of, and below, the hot-start thermal limit;
• allow the motor's service factor rating, consistent with NEC 430.32 overload limits.

Modern relays use a thermal model that tracks the motor's heat in real time, so the TCC curve is a snapshot. The real protection also remembers previous starts and running load.

Setting the instantaneous element

The instantaneous 50 element must ride through the asymmetrical starting current. For relays that respond to total RMS current, a pickup of about 1.6–2.0 times symmetrical locked-rotor current is common. Many digital relays filter the DC offset and allow a lower multiple; follow the relay manufacturer's guidance. For the example motor, a pickup near 2,200–2,700 A at 13.8 kV, with a short definite delay or none, clears motor terminal faults in about 2 cycles while ignoring starts.

Where the motor is fed by a fused contactor, the fuse provides short-circuit protection and the relay's 50 element must be blocked above the contactor's interrupting rating.

4. Coordination time interval: the ~200 ms rule

Moving upstream from the motor, each relay must wait long enough for the downstream device to clear the fault first. The difference in operating time between two devices at the same fault current is the coordination time interval (CTI). It must cover:

• the downstream breaker's interrupting time, typically 3–5 cycles (50–83 ms) for medium-voltage vacuum breakers;
• relay overtravel, which is essentially zero for digital relays but significant for electromechanical relays;
• relay timing tolerance, CT error and a safety margin.

Common practice is a CTI of about 0.2–0.3 s between digital relays on modern breakers, and 0.3–0.4 s where electromechanical relays are involved.



Inverse-time relays follow standard curve equations. IEEE Std C37.112 defines the US curve family:

Here M is the multiple of pickup current, TD the time dial, and A, B and p the curve constants:

Very inverse and extremely inverse curves coordinate well with fuses and motor thermal limits; moderately inverse curves suit systems where fault current varies widely.

The worked coordination ladder

For a three-phase fault of about 11 kA on the 13.8 kV system, the example settings give:

Each step keeps a 0.2 s interval at the maximum fault current, where curves are closest together. The check must be repeated at minimum fault current and at the instantaneous pickup thresholds, because inverse curves can converge or cross at lower currents.

5. The transformer damage curve

IEEE Std C57.109 defines how long a transformer can carry a through fault, a fault beyond its secondary terminals, before thermal or mechanical damage. Transformers are grouped into four categories by kVA:

The thermal part of the curve follows a constant I²t, anchored at 25 times rated current for 2 seconds:

For Categories II and III, a mechanical (frequent-fault) curve also applies when faults are expected to be frequent, for example on overhead-line or long cable feeders. For Category IV, the mechanical curve always applies. The mechanical curve shifts the protection requirement to shorter times at high fault currents, because winding forces scale with current squared.



Applying it to T1

T1 is 30 MVA, so it is a Category III transformer. For the 11 kA bus fault:

The transformer primary relay at 0.65 s operates well before the thermal limit. If the feeders are exposed to frequent faults, the mechanical curve governs and the margin must be checked against it as well.

The delta–wye ground-fault shift

For a single-line-to-ground fault on the wye-connected secondary of a delta–wye transformer, the per-unit current seen in each primary line is only about 58% of the per-unit secondary winding current. The primary phase relay therefore sees less current, and operates more slowly, than the secondary fault suggests. To check protection for this case, the damage curve plotted against the primary relay is shifted to the left by a factor of 0.58. A primary relay that clears three-phase faults comfortably can still fail to protect the transformer for secondary ground faults. Where the secondary is resistance grounded, as in this example, ground-fault current is limited and secondary ground protection carries the burden.

Inrush and the transformer instantaneous element

Energising T1 draws magnetising inrush current. A traditional rule of thumb is 8–12 times rated current for 0.1 s, plotted as a point that the primary relay curve must clear. The primary instantaneous element must also stay above the maximum through-fault current for a secondary fault, so that it only operates for faults on the high side or inside the transformer, usually with a margin of about 25–50%. Differential protection (87T) provides fast, selective clearing of internal faults on transformers of this size.

Building a coordination study step by step

1. Gather data. One-line diagram, utility fault data at the point of interconnection, transformer nameplates and impedances, cable data, CT ratios, relay types, motor data sheets with starting and thermal curves.
2. Calculate fault currents at every bus for maximum and minimum conditions, three-phase and ground, following IEEE Std 551 or ANSI C37 methods.
3. Run a motor starting study to confirm acceleration time and voltage dip.
4. Plot each protection path on its own TCC: motor, feeder, main, transformer primary and utility relay, with the motor starting curve, thermal limits and the transformer damage curve.
5. Select settings that respect the CTI at maximum fault current and keep protection fast at minimum fault current.
6. Check arc-flash results. Clearing times drive incident energy calculated by IEEE Std 1584; slow main breakers often produce the highest incident energy.
7. Document and verify. Issue setting sheets, TCC plots and a report; confirm settings in the field during commissioning.

Common mistakes

How Keentel Engineering helps

Keentel Engineering delivers protection and control engineering and power system studies from 4 kV to 765 kV.

Planning a motor installation, substation upgrade or protection review? Talk to Keentel Engineering at (813) 389-7871, contact@keentelengineering.com, or book a 15-minute scoping call at calendly.com/keentel-engineering/15min.

Part C — Case Studies

The following are illustrative scenarios based on conditions typical of US industrial and utility facilities. They show how Keentel Engineering approaches protection coordination problems; site details are generalised and figures are rounded.

Case Study 1 — High-inertia fan motor tripping on hot restarts

Situation. A 4,000 hp, 4,000 V induced-draft fan motor on a 4.16 kV bus starts normally from cold but trips on overload during restarts after short outages.

Analysis. A motor starting study shows that, at the voltage dip seen during starting, acceleration takes about 22 s, while the manufacturer's hot safe stall time is about 18 s. No overload curve can both allow the start and protect the motor against a hot stall. The relay was set on the cold-start limit, with the thermal model's hot-start bias disabled.

Engineered solution. Add a zero-speed switch input so the relay can tell a stalled rotor from an accelerating one, enable the thermal model with hot/cold ratio and RTD biasing from the manufacturer's data, and add a starts-per-hour and time-between-starts limit (device 66).

Outcome. The motor can restart hot while remaining protected against a true stall, and the TCC shows clear separation between the starting curve and the protection.

Case Study 2 — Transformer exposed for secondary ground faults

Situation. An industrial substation with a 20 MVA, 69–13.8 kV delta–wye transformer has 13.8 kV feeders running overhead around the site. A protection review is triggered by a new utility fault-current notice.

Analysis. The coordination study shows the transformer primary phase relay clears three-phase secondary faults inside the IEEE C57.109 limits. Once the 0.58 delta–wye shift is applied for secondary ground faults, and the frequent-fault mechanical curve is used because of the overhead feeders, the primary relay curve crosses the damage curve at high currents.

Engineered solution. Add a dedicated secondary-side ground overcurrent element on the neutral CT with a short delay, retune the primary phase relay to a faster curve within the utility's coordination limits, and confirm that transformer differential protection covers internal faults.

Outcome. The transformer is protected for every fault type considered, and coordination with the utility's 69 kV line relays is maintained with a documented coordination interval.

Case Study 3 — Plant expansion with high arc-flash energy

Situation. A manufacturing plant adds two 13.2 kV process motors to its 13.8 kV switchgear. The updated arc-flash study shows very high incident energy at the switchgear main breaker section.

Analysis. To keep coordination with the new motor feeders, the main breaker relay had been set with a long time delay, so the main bus clears slowly for arcing faults. The coordination margin at the bus was larger than needed, and there was no fast bus protection.

Engineered solution. Implement zone-selective interlocking between the feeder and main relays, so the main trips fast for bus faults unless a feeder relay sees the fault, and add an arc-flash detection scheme with light sensors supervised by overcurrent. Re-check all TCCs to confirm selectivity is unchanged for feeder faults.



Outcome. Incident energy at the main bus falls substantially, the new motors start without nuisance trips, and every protection path keeps at least a 0.2 s coordination interval.

Ranges depend on module technology and test conditions. Use the module datasheet and the plant's own baseline curves as the primary reference.

Part D — Technical FAQ: Motor Protection and Relay Coordination

References and Further Reading

Links were current at publication (October 2026).

• IEEE Std C37.96, IEEE Guide for AC Motor Protection. IEEE.
• IEEE Std C37.91, IEEE Guide for Protecting Power Transformers. IEEE.
• IEEE Std C57.109, IEEE Guide for Liquid-Immersed Transformers Through-Fault-Current Duration. IEEE.
• IEEE Std C37.112, IEEE Standard for Inverse-Time Characteristics Equations for Overcurrent Relays. IEEE.
• IEEE Std 1584, IEEE Guide for Performing Arc-Flash Hazard Calculations. IEEE.
• ANSI C84.1, Electric Power Systems and Equipment — Voltage Ratings (60 Hz). ANSI/NEMA.
• NEMA MG 1, Motors and Generators. NEMA.
• NFPA 70, National Electrical Code, Articles 430 and 450; NFPA 70E, Standard for Electrical Safety in the Workplace. NFPA.
• Transformer Overcurrent Protection Coordination (summary of IEEE C57.109 categories and curves). R. W. Patterson. https://relayman.org/papers/Transformer%20Overcurrent%20Protection%20Final%20Final%202015.pdf
  

Disclaimer

This article is general technical information for educational purposes. It is not engineering advice for any specific project and does not create a professional relationship. The example system, settings and operating times are illustrative; actual settings must be calculated from verified equipment data, utility fault information and manufacturer curves, and sealed by a licensed professional engineer where required. Verify the current edition of any standard or code before relying on it.



Case studies are illustrative scenarios based on typical project conditions, not records of specific client projects. Figures are rounded and indicative.

IEEE, ANSI, NEMA and NFPA standards are the property of their respective organisations. Keentel Engineering is not affiliated with or endorsed by these organisations or any equipment manufacturer.

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