What Is Protection Coordination? Methods, CTI, TCC Curves and Examples

Protection coordination is the process of selecting and setting protective devices, such as fuses, circuit breakers and relays, so that only the device closest to a fault trips. The rest of the electrical system stays on. If the nearest device fails, the next one upstream trips after a short, planned delay and acts as backup.

Engineers achieve this by comparing the time-current curves of devices in series and keeping a safe time gap between them, called the coordination time interval (CTI). This guide explains how that works in plain language: the objectives, methods, TCC curves, CTI, relay equations, device-by-device rules, the study process, worked examples, standards and common mistakes.

Table of contents

1. How does protection coordination work?
2. Why is protection coordination important?
3. What are the objectives of protection coordination?
4. Protection coordination, selectivity and discrimination: what is the difference?
5. Primary protection and backup protection
6. What are the methods of protection coordination?
7. Time grading (definite time)
8. Current grading
9. Time-current (inverse-time) grading
10. Directional overcurrent
11. Zone-selective interlocking (ZSI)
12. Communication-assisted and adaptive protection
13. What is a time-current characteristic (TCC) curve?
14. How to read a TCC chart
15. What is the coordination time interval (CTI)?
16. What makes up the CTI?
17. Inverse-time overcurrent relay equations
18. Plug setting multiplier (PSM)
19. Time multiplier setting (TMS)
20. IEC and IEEE equations
21. How do different protective devices coordinate with each other?
22. What are total selectivity, partial selectivity and cascading?
23. Protection coordination in different systems
24. What is a protection coordination study?
25. What information do you need?
26. Step-by-step process
27. Worked example: coordinating two overcurrent relays
28. Worked example: ACB and MCCB in a low-voltage board
29. Protection coordination and arc-flash safety
30. How do numerical relays and renewable generation affect coordination?
31. Standards and code requirements
32. India
33. United States (NEC)
34. United Kingdom (BS 7671)
35. Which software is used for protection coordination?
36. Common protection coordination mistakes
37. Common misconceptions
38. Frequently asked questions
39. What is protection coordination in electrical systems?
40. What is the difference between protection coordination and selectivity?
41. What is the difference between selectivity and discrimination?
42. What is CTI in relay coordination?
43. How do you calculate CTI?
44. What is the difference between time grading and current grading?
45. How do you read a TCC curve?
46. What is partial selectivity?
47. Is a coordination study required?
48. Why are numerical relays better for coordination?
49. How does solar power affect protection coordination?
50. Does protection coordination reduce arc-flash risk?
51. Conclusion
52. Disclaimer
53. Sources

How does protection coordination work?

Picture the radial feeder above, with a main breaker, a feeder breaker and a final circuit breaker in series. A short circuit then follows this sequence:

1. Normal operation: all three devices carry load and stay closed.
2. A fault occurs at the load end. All three devices see the high current.
3. The final circuit breaker is set to react fastest, so it operates first.
4. It clears the fault. The feeder and main breakers reset without tripping.
5. Only the faulted circuit loses supply.
6. If the final breaker fails, the feeder breaker trips after its delay. If that fails too, the main breaker trips.

The delay between steps is not random. It is built from the curves and settings of each device, so the nearest device always wins the race. That is what the next sections explain.

Why is protection coordination important?

• Limits the outage: one faulty motor or socket circuit does not shut down a whole plant or building.
• Protects equipment: faults are cleared before cables, transformers and motors exceed their thermal limits.
• Improves safety: well-chosen clearing times help reduce fire risk and arc-flash energy.
• Gives backup: upstream devices clear the fault if the primary device fails.
• Cuts downtime: faster fault location and fewer nuisance trips mean less lost production.

Settings errors are a real, measurable problem. An analysis of 2021 North American Electric Reliability Corporation (NERC) data, published through the US Department of Energy’s OSTI service, found that incorrect settings account for roughly a quarter of reported protection misoperations.

What are the objectives of protection coordination?

Objective	Meaning	Why it matters
Selectivity	Only the faulted section is disconnected.	Keeps healthy circuits running.
Speed	Faults are cleared quickly.	Limits damage and arc-flash energy.
Sensitivity	The device detects the smallest fault it must clear.	Covers end-of-line and high-impedance earth faults.
Dependability	The device trips when it should.	Faults do not stay on the system.
Security	The device does not trip when it should not.	Avoids trips on motor starting, inrush or external faults.

These aims pull against each other. More time delay improves selectivity but slows clearing. Good coordination is a balance, not a maximum of one aim.

Protection coordination, selectivity and discrimination: what is the difference?

Different regions use different words for closely related ideas. In short, coordination is the process and selectivity is the result.

Term	Where it is used	Meaning
Protection coordination	Global, especially IEEE and US practice	Choosing and setting devices to achieve the desired trip order.
Selectivity	IEC and most of the world	Only the intended device operates; upstream devices stay closed.
Discrimination	UK, older BS usage; also common in India	Another word for selectivity.
Selective coordination	US National Electrical Code (NEC)	Coordinated devices so the nearest one clears the fault without upstream operation.
Grading	Relay practice	The time or current margin between successive devices.
Cascading (back-up)	Low-voltage IEC usage	An upstream device helps a downstream device with lower breaking capacity handle a high fault.

India largely follows IEC-based practice, so you will see “selectivity” and “discrimination” in design documents, and “coordination study” in industrial projects.

Primary protection and backup protection

	Primary protection	Backup protection
Role	First line of defence for its own zone	Operates only if primary protection or its breaker fails
Speed	As fast as the scheme allows	Deliberately delayed by at least the CTI
Location	Closest to the fault	Upstream, or a separate remote device
Example	Final circuit breaker	Feeder or main breaker

Protection zones are the sections of the system each device guards. Neighbouring zones overlap, so no part of the network is left unprotected. A fault in an overlap trips more than one device, but only a small part of the system is lost.

What are the methods of protection coordination?

Time grading (definite time)

Each device nearer the source gets a longer fixed delay. It is simple, but the device at the source clears faults slowly, which raises damage and arc-flash energy.

Current grading

Upstream devices pick up at higher currents than downstream ones. This works only where fault current falls clearly between devices, for example across a transformer.

Time-current (inverse-time) grading

Operating time falls as current rises. Curves are kept apart by the CTI. This is the most common method for feeders in industrial and distribution systems.

Directional overcurrent

The relay trips only for current flowing in a set direction. It is used on ring mains and parallel feeders, where fault current can arrive from either side.

Zone-selective interlocking (ZSI)

A downstream device sends a restraint signal upstream. The upstream device then waits, but trips almost instantly if it receives no signal, meaning the fault is on its own bus. ZSI is common on low-voltage ACB and MCCB boards and keeps clearing fast without stacked delays.

Communication-assisted and adaptive protection

Relays exchange blocking or permissive signals, or change settings automatically when the network or generation changes. These suit complex networks and microgrids but need reliable communications and careful testing.

Method	Main strength	Main limit	Typical use
Time grading	Simple	Slow near the source	Small radial systems
Current grading	Fast, no added delay	Needs a large fault-level step	Transformer feeders
Inverse-time	Balances speed and selectivity	Needs TCC study and good data	Industrial and utility feeders
Directional	Works in loops	Needs voltage reference	Ring mains, parallel feeders
ZSI	Fast and selective	Needs control wiring	LV and MV switchboards
Adaptive	Copes with changing networks	Complex to engineer	Microgrids, high-DER feeders

What is a time-current characteristic (TCC) curve?

A TCC curve shows how long a protective device takes to operate at each level of current. Both axes are logarithmic. Engineers plot the curves of all devices in series on one chart to see whether they coordinate.

How to read a TCC chart

• Horizontal axis: current, usually in amperes at a stated voltage.
• Vertical axis: time in seconds. Lower means faster.
• Pickup: the current at which the device starts to operate. The curve rises steeply towards this point.
• Bands: breakers and fuses show a band, not a line, because of tolerance. A fuse has a minimum melting curve and a total clearing curve.
• Damage curves: cable, transformer and motor limits are plotted so devices operate before equipment is damaged.
• Inrush and starting points: transformer inrush and motor starting must stay outside the tripping area.

Proper coordination looks like this: the downstream curve sits to the left and below the upstream curve across the whole fault range, with a clear gap at every current level, while staying below the equipment damage curves.

What is the coordination time interval (CTI)?

CTI, also called the grading margin, is the minimum time gap between the downstream and upstream device at the same fault current. It stops the upstream device tripping while the downstream device is still clearing the fault.

What makes up the CTI?

• Breaker clearing time: the time the downstream breaker needs to open and extinguish the arc.
• Relay overtravel and reset: electromechanical disc relays keep moving briefly after the fault clears. Numerical relays have almost none.
• Errors and tolerances: relay timing accuracy and current transformer (CT) errors.
• Safety margin: allowance for data uncertainty.

Relay technology	Commonly quoted total CTI
Electromechanical	About 0.3 to 0.4 s
Static (solid-state)	About 0.3 s
Numerical (microprocessor)	About 0.2 to 0.3 s; shorter margins are used where breaker data and settings justify them

Inverse-time overcurrent relay equations

Plug setting multiplier (PSM)

PSM tells you how many times the fault current exceeds the relay’s pickup, both measured on the same side of the CT.

Time multiplier setting (TMS)

TMS scales the whole curve up or down in time without changing its shape. A higher TMS means a slower relay. IEC calls this the time multiplier setting; IEEE calls it the time dial (TD).

IEC and IEEE equations

Both standards use the same idea: operating time depends on how far the current is above pickup.

Curve	IEC constants (k, α)	IEEE constants (A, p, B)
Standard / moderately inverse	0.14, 0.02	0.0515, 0.02, 0.114
Very inverse	13.5, 1	19.61, 2, 0.491
Extremely inverse	80, 2	28.2, 2, 0.1217
Long-time inverse	120, 1	Not part of the basic IEEE set

Use normal inverse for general feeders, very inverse where fault current falls quickly along the feeder, and extremely inverse for coordination with fuses and where inrush is a concern. For a wider look at relay families, see our guide to types of protection relays.

How do different protective devices coordinate with each other?

Device pair	Approach	Key checks
Relay and relay	Separate the TCC curves by the CTI across the fault range	Pickup, curve type, TMS, CT ratios, minimum and maximum fault
Relay and breaker	Add the breaker’s clearing time to the relay time	Breaker operating time, relay tolerance
Fuse and fuse	Downstream total clearing I²t must stay below upstream pre-arcing I²t	Selectivity limit current; ABB states same-type gG fuses (IEC 60269-2) are totally selective at an upstream-to-downstream rating ratio of 1.6:1
Fuse and relay	Keep the relay curve clear of the fuse melting and clearing curves, with a margin	Fuse damage curve, relay pickup, CT saturation, inrush
Recloser and fuse	Choose fuse-saving or fuse-blowing philosophy	Recloser fast curve below fuse melting; slow curve above fuse clearing
Breaker and breaker (LV)	Compare trip curves, then use manufacturer selectivity tables where curves overlap	Selectivity limit current, let-through energy, total or partial selectivity

In fuse saving, the recloser’s fast operation clears temporary faults before the fuse melts. In fuse blowing, the fuse is allowed to operate first so a permanent fault is isolated sooner. The choice depends on how many faults on the line are temporary. To compare the devices themselves, read fuse vs circuit breaker and MCB vs MCCB vs ACB.

What are total selectivity, partial selectivity and cascading?

Concept	Meaning
Total selectivity	The downstream device clears the fault alone for every current up to its breaking capacity. The upstream device never trips.
Partial selectivity	Selectivity holds only up to a stated current, the selectivity limit current (Is). Above it, both devices may trip.
Cascading (back-up protection)	An upstream current-limiting device lets a downstream device with a lower breaking capacity be used safely. It trades selectivity at high currents for lower cost.

Cascading and selectivity are different aims. Cascading protects a weaker device; selectivity keeps the supply on. Where a design needs both, use manufacturer-tested combinations. Under IEC 60947-2, Annex A covers selectivity and back-up between circuit breakers and other short-circuit protective devices. See our overview of types of circuit breakers for the device background.

Protection coordination in different systems

• Radial systems: one source path, so grading is straightforward. Each tier sits further down the time scale towards the source.
• Ring mains and parallel feeders: current can flow either way, so directional overcurrent relays are normally needed.
• Industrial and commercial buildings: many tiers of low-voltage devices; selectivity tables and ZSI do most of the work. Our guide to what is switchgear shows where these devices sit.
• Low voltage (LV) versus medium voltage (MV): LV relies on breaker trip units, fuses and manufacturer data. MV adds protection relays, instrument transformers and time-current grading.
• High-voltage interfaces: distance and pilot schemes are a separate specialist subject. For plant studies, they matter mainly at the utility connection point.

What is a protection coordination study?

A protection coordination study is the engineering analysis that sets the devices and proves they coordinate. It is built on short-circuit results and is usually done in software.

What information do you need?

• Up-to-date single-line diagram
• Transformer, generator, motor and cable data
• Maximum and minimum short-circuit currents
• Breaker, fuse and relay types, ratings and current settings
• CT ratios, burdens and saturation limits
• Transformer inrush, motor starting current and cable and equipment damage curves
• Different operating conditions, such as alternative supplies or generators running

Step-by-step process

1. Collect system data and check the single-line diagram.
2. Build the network model.
3. Run maximum and minimum short-circuit studies.
4. Collect device curves and equipment damage curves.
5. Choose settings, plot the TCC curves and check pickup values.
6. Check CTI at the governing fault levels, plus inrush, motor starting and damage limits.
7. Run sequence-of-operation checks for typical faults, and review arc-flash implications.
8. Prepare the report, test the settings on site and review again after any system change.

A good report includes the system description, assumptions, short-circuit results, device settings, TCC plots, coordination tables, damage checks and recommendations.

Worked example: coordinating two overcurrent relays

R2 is downstream and R1 is upstream. Both use the IEC normal inverse curve (k = 0.14, α = 0.02). The maximum fault current at R2 is 4,000 A. The target CTI is 0.3 s.

Item	R2 (downstream)	R1 (upstream)
CT ratio	400/5	800/5
Pickup (primary)	400 A	800 A
TMS	0.10	0.15
PSM at 4,000 A	10	5
Operating time at 4,000 A	0.297 s	0.642 s

R2: t = 0.10 × 0.14 ÷ (10^0.02 − 1) = 0.10 × 0.14 ÷ 0.04713 = 0.297 s.

R1: t = 0.15 × 0.14 ÷ (5^0.02 − 1) = 0.15 × 0.14 ÷ 0.03274 = 0.642 s.

CTI = 0.642 − 0.297 = 0.345 s, which is above the 0.3 s target, so the pair coordinates at 4,000 A. How was TMS 0.15 chosen? R1 needed at least 0.597 s, which requires a TMS of about 0.14, rounded up to the next convenient value of 0.15.

Check another point. At 2,000 A, R2 operates in 0.428 s and R1 in 1.135 s, a gap of 0.707 s. The margin is wider at lower current. It narrows as current rises, which is why you must check the maximum fault level.

Worked example: ACB and MCCB in a low-voltage board

Case	Main ACB	Downstream MCCB	Result for a 4,000 A fault
Non-selective	Instantaneous trip at 3,000 A	Instantaneous trip at 3,000 A	Both trip. The whole board loses supply.
Selective	Short-time delay 0.25 s, pickup 2,500 A	Clears instantly (well under 0.1 s)	MCCB clears first. The ACB rides through and stays closed.

The ACB must be able to carry the fault for the full delay. This ability is its short-time withstand rating (I_cw), so check it on the data sheet. For fuse and breaker pairs, compare the fuse melting and total clearing curves with the breaker trip curve in the same way.

Protection coordination and arc-flash safety

Arc-flash incident energy rises with fault current and with clearing time. Fast tripping therefore lowers the hazard. But the time delays that give selectivity make clearing slower. This is the central trade-off.

• Maintenance mode: a temporary, faster setting is switched on while people work near live equipment. It reduces incident energy but gives up selectivity for that period.
• Zone-selective interlocking: keeps selectivity and gives fast clearing for faults on the main bus.
• Study together: check coordination and incident energy in the same model, then decide which circuits must favour speed and which must favour selectivity.

Faster is not always better. Very fast settings without proper margins cause nuisance trips and lose selectivity. For more on the hazard itself, our readers can start with the equipment basics in what is switchgear.

How do numerical relays and renewable generation affect coordination?

Numerical relays are microprocessor-based. They are accurate, have no disc overtravel, offer many curve shapes and setting groups, and support communication. This allows tighter margins than electromechanical relays, though the margin still has to be justified with breaker and CT data. If you need ANSI function numbers for relay settings sheets, use our ANSI device numbers list.

Inverter-based resources (IBR), such as solar and wind, create two problems:

• Low fault current: inverters typically supply only about 1.1 to 2 times rated current in a fault, so overcurrent elements set for conventional sources may not pick up.
• Two-way power flow: feeders designed for one-way flow may see current from both ends, which can upset radial grading.

Typical responses are directional elements, communication-assisted schemes, adaptive setting groups and checking minimum fault levels with and without generation. Check local interconnection rules before finalising settings.

Standards and code requirements

Standard or code	What it covers
IEEE 242 (Buff Book)	Protection and coordination of industrial and commercial power systems
IEEE 399 (Brown Book)	Power system analysis, including short-circuit input data
IEEE C37.112	Inverse-time characteristic equations for overcurrent relays
IEC 60255-151	Functional requirements and characteristics for overcurrent protection
IEC 60947-2	LV circuit breakers, including selectivity and back-up (Annex A)
IEC 60269	Low-voltage fuses
NFPA 70 (NEC)	US installation rules, including selective coordination for specified systems
BS 7671	UK wiring regulations; Regulation 536 covers selectivity

India

Indian projects generally follow IEC-based practice. Low-voltage switchgear is covered by the Bureau of Indian Standards’ IS 13947 series, which follows IEC 60947. Check Central Electricity Authority regulations and your utility or client specification for the exact coordination requirements on your project.

United States (NEC)

The 2023 NEC requires selective coordination for emergency systems (700.32). Similar requirements apply to legally required standby systems (701.32) and critical operations power systems (708.54). The 2023 edition also requires the coordination to be re-evaluated when the system is modified.

United Kingdom (BS 7671)

BS 7671 does not require selectivity everywhere. Regulation 536 asks that, where selectivity is needed to prevent danger or for correct functioning, the manufacturers’ instructions are taken into account. The requirement is therefore specific to the installation, not universal.

Always confirm the edition adopted in your area before design.

Which software is used for protection coordination?

Software	Publisher	Coordination features
ETAP Star	ETAP	TCC analysis, sequence of operation, selectivity checks, interlocks
EasyPower	Bentley	Interactive TCCs, selective coordination checks, automatic settings
SKM PowerTools	SKM	Widely used coordination and arc-flash platform
PowerFactory	DIgSILENT	Network analysis with protection and relay settings tools
ASPEN OneLiner	ASPEN	Relay coordination and short-circuit analysis, mainly for transmission
CYME	Eaton	Distribution network analysis with protection tools

Software plots curves and checks margins, but it does not replace engineering judgement. Accept auto-set values only after reviewing them against real equipment data.

Common protection coordination mistakes

• Using only maximum fault current. Minimum, end-of-line and earth faults decide whether the device picks up.
• Ignoring inrush and motor starting. This causes nuisance trips or forces pickup settings too high.
• Forgetting CT limits. A saturated CT delivers less current and slows the relay.
• Using generic curves. Use the manufacturer’s data for the exact device and model.
• Skipping damage curves. Coordination is worthless if cables or transformers are damaged first.
• Relying on an old study. Transformer, cable, generator and utility changes all alter the result.

Common misconceptions

Myth	Fact
Faster tripping is always better.	Over-fast settings lose selectivity and cause nuisance trips.
Coordination is only for utility relays.	It applies to fuses and LV breakers in buildings and plants too.
Breakers always give total selectivity.	Many pairs give only partial selectivity.
Backup protection and selectivity are the same.	Backup operates on failure; selectivity decides who trips first.
A completed study lasts forever.	Any system change can invalidate it.
Numerical relays remove all coordination problems.	They help, but the settings still need a proper study.

Frequently asked questions

What is protection coordination in electrical systems?

It is setting protective devices so the one nearest a fault operates first and upstream devices act only as backup.

What is the difference between protection coordination and selectivity?

Coordination is the engineering process of choosing and setting devices. Selectivity is the result: only the faulted section is isolated.

What is the difference between selectivity and discrimination?

Nothing in practice. Discrimination is the older UK term for selectivity.

What is CTI in relay coordination?

The coordination time interval is the minimum time gap between an upstream and a downstream device at the same fault current.

How do you calculate CTI?

Subtract the downstream operating time from the upstream operating time at the same fault current: CTI = t upstream − t downstream.

What is the difference between time grading and current grading?

Time grading adds longer delays towards the source. Current grading uses higher pickup settings towards the source.

How do you read a TCC curve?

Read current along the horizontal axis and time up the vertical axis. A downstream curve should sit left of and below the upstream curve with a clear gap.

What is partial selectivity?

Selectivity that holds only up to a stated current, the selectivity limit. Above it, both devices may trip.

Is a coordination study required?

It depends on the project and local rules. The NEC requires selective coordination for certain emergency and standby systems, and most industrial sites carry out studies as good practice.

Why are numerical relays better for coordination?

They have no disc overtravel, are more accurate and offer flexible curves and communication, which allows tighter margins.

How does solar power affect protection coordination?

Inverters supply low fault current and can reverse power flow, so overcurrent settings and grading may need review.

Does protection coordination reduce arc-flash risk?

Indirectly. Faster clearing lowers incident energy, but the delays needed for selectivity can raise it, so both must be studied together.

Conclusion

Protection coordination makes sure the right device trips at the right time, so a fault is cleared quickly and only the faulted section loses supply. It rests on a few ideas: curve separation by the CTI, correct settings built on real fault data, and a regular review whenever the system changes. Start with the definition and TCC curves, practise with the worked example, and then move on to your own system data and a full study in software.

Disclaimer

This article is for education. Relay settings, coordination studies and equipment selection must be carried out and reviewed by qualified protection engineers under the applicable codes, standards and utility requirements. All worked examples use illustrative numbers and are not design settings.

Sources

• ABB: Selectivity techniques
• ABB: Selectivity standard requirements (IEC 60947-2)
• ABB: Selectivity with fuses
• IET: Co-ordination of electrical devices and auxiliary circuits (BS 7671)
• OSTI: NERC MISOPS analysis
• NERC: PRC-004-6 protection system misoperation
• IEEE: C37.112 inverse-time overcurrent relay equations
• ETAP: Protection and coordination software