2 Key Metrics in Overcurrent Protection: Why Time-Current Curves and Coordination Time Intervals Matter More Than You Think

TCC and CTI are the two most common acronyms in overcurrent protection coordination.

Preventing human injury, limiting damage to equipment, and minimizing the extent of service interruptions — these are the fundamental principles of power system protection. In a power system, the role of protective devices is indispensable, but this can ONLY be achieved by appropriately selecting and correctly setting these devices.

When applying protective devices in a power system, it is always ideal to achieve all the objectives, namely selectivity, speed of operation, simplicity, sensitivity, and economics. This is not usually the case, though, and it would be very difficult or expensive (impractical) to achieve. Most of the time, striking a balance among these objectives and allowing for compromises is the best way to achieve a well-designed protection.

Consider, for example, a simple network below. There are two line sections and a distribution transformer. To ensure basic protection, overcurrent protection is placed for each of these — a circuit breaker at the feeder take-off to protect the first line section, and fuse cut-outs for both the next line section and the distribution transformer. Overcurrent protection operates when the current exceeds a predetermined value, commonly known as a pickup or minimum operating value. In most cases, this value is set at least above the maximum short-time load (asymmetrical offset, magnetizing inrush, cold load, unusual operation).

For distribution utilities, especially with a large network, lines are installed to cater for load growth. It would be very tedious to set the pickup value based on the load since loads are gradually increasing. In order to make managing the overcurrent protection configurations simpler, the pickup value is usually set to be equal to or less than the line ampacity.

So what does a pick-up or minimum operating value look like in a TCC? Before that, what does TCC stand for, and how is it used in a protection coordination study?

TCC stands for Time-Current Curve — a graphical representation that shows how long it takes for a protective device to operate or ‘trip’, given the measured current. It plots tripping time versus current magnitude on a log-log scale with the current on the x-axis and the trip time on the y-axis.

To illustrate this, a sample Time-Current Curve is shown below. This TCC plots the characteristics of two devices: a fuse and a relay.

If you are curious about the characteristics of various protection devices, hop into this post!

The TCC plot below show two time-current curves and reads — for a fault current magnitude of 2000A, the fuse element clears (operates) in 0.074 seconds — start with the x-axis and project the current magnitude vertically until it intersects the fuse element time-current curve then project horizontally towards the y-axis to determine the time. You may be wondering why we chose not to project horizontally the moment our vertical projection intersects the fuse time-current curve. This is because fuses operate in a time-current band, between minimum melting time – the time when the metal strip starts to melt, and maximum clearing time – when the strip completely breaks and the arc fully extinguished.

A more detailed explanation can be found in this post including the time-current curves of various protection devices.

The second time-current curve reads — for a fault current magnitude of 2000A, the relay operates in 5.73 seconds.

Now if the fuse clears the 2000A fault in 0.74 seconds and the relay clears it 5.73 seconds, how much faster is the fuse than the relay in this case? It’s a straightforward 5.73 minus 0.74, or 4.99 seconds. This difference is what we call the Coordination Time Interval or simply CTI. In other words, the CTI is the amount of time allowed between a primary protection device and its upstream backup. In this example, the fuse is the primary protection device and the relay is the upstream backup.

Simple, but the next question would be ‘Is the CTI adequate to allow the primary protection device to clear the fault before the upstream backup device operates?’. This is to ensure selectivity — the measure of how well the protection system limits service interruptions by isolating the smallest portion of the affected area.

Understanding Coordination Time Intervals (CTIs): A Practical Look Inspired by IEEE 242

In simpler terms:
Coordination Time Interval is the “breathing room” between a primary protective device and its backup. Without enough margin, two devices might trip at the same time, or worse, the wrong device might operate first.

Why Coordination Time Intervals Matter

Every protection device—relays, breakers, and even fuses—has its own built‑in delays. If these delays aren’t accounted for, upstream devices might “think” the downstream device isn’t doing its job and trip too early. That means larger outages and unhappy customers. CTIs are the buffer that prevents that.

Minimum Coordination Time Intervals For Industrial Application

In traditional overcurrent protection schemes, relay characteristic curves are presented as single, idealized lines. These curves do not inherently account for real‑world factors such as relay setting inaccuracies, manufacturer tolerances, or the operating time of associated circuit breakers. Electromechanical relays introduce additional uncertainty due to induction‑disk overtravel, which can continue to advance even after the fault current is cleared.

By contrast, devices such as fuses and low‑voltage circuit breakers use banded characteristic curves that represent their operating range rather than a single precise line. This banded representation makes coordination more straightforward—protection engineers simply ensure adequate separation between device characteristics on the time‑current plot.

Many manufacturers also advise maintaining a safety margin between the upstream fuse’s minimum‑melt curve and the downstream fuse’s total‑clearing curve to prevent unintended partial melting of the upstream device. For example, Hubbell Chance fuse links are recommended to have a coordination interval of 75%. This means that in order to maintain proper coordination, the downstream protective device should be able to clear the fault within 75% of the minimum melting time of the upstream fuse. This is to provide protection against operating variables. Regardless of the approach used, the fundamental rule remains: characteristic curves should never overlap.

IEEE 242 published tables on minimum coordination time intervals used normally encountered in industrial applications. Table 1 shows the minimum coordination time intervals when coordinating between various protection devices with field-tested and -calibrated relays and a 5-cycle circuit breaker.

Downstream	Upstream
	Fuse	Low-voltage breaker	Electromechanical relay	Static relay
Fuse	Clear Space	Clear Space	0.22 s	0.12 s
Low-voltage breaker	Clear Space	Clear Space	0.22 s	0.12 s
Electromechanical relay	0.20 s	0.20 s	0.30 s	0.20 s
Static relay	0.20 s	0.20 s	0.30 s	0.20 s

How to Use This Table

Identify the Two Devices You Are Coordinating

• Table 1 lists minimum coordination time intervals for different device pairs. You must know which upstream and downstream devices are being coordinated so you can locate the correct cell in the table. (Example: “Downstream fuse, upstream static relay”).

Look Up the Minimum Required Time Interval

• Once you identify the device pair, look up the minimum recommended time separation between their curves in the table. For example, a fuse–static relay pairs require a minimum of 0.12 s. This minimum “gap” ensures that the downstream device operates first during a fault.

Apply the Time Interval on the TCC Plot

• On the time‑current curve:
  • Plot the downstream device time-current curve (the device closer to the load).
  • Plot the upstream device time-current curve (the protective device feeding the downstream device).
  • Ensure the upstream time-current curve stays to the right and above the downstream time-current curve, and that the minimum time interval from the table is met. This ensures selective coordination: only the device closest to the fault should trip.

Apply the Time Interval at the “Minimum Time” Region

• IEEE 242 guidance clarifies that the CTI requirement applies at the minimum point of separation, not over the entire length of the curves. The minimum time separation should be maintained at the point where the time-current curves get closest. At longer clearing times, the separation may naturally become larger. This means you don’t need to keep the same time gap across the entire curve—just at the closest approach.

Confirm That Device Tolerances Are Covered

• CTIs account for:
  • Relay tolerance
  • Breaker opening time variability
  • Fuse melting vs. clearing time differences
  • Mechanical delays

Components	CTI with field testing
	Electromechanical	Static
Circuit breaker opening time (5 cycles)	0.08 s	0.08 s
Relay overtravel	0.10 s	0.00 s
Relay tolerance and setting errors	0.12 s	0.12 s
Total CTI	0.30 s	0.20 s

If the minimum interval is not maintained, the upstream device might trip too soon or simultaneously.

What Creates These Delays? A Closer Look

Relay Tolerance and Setting Errors

• This usually adds about 0.12 s. Relays don’t trip instantaneously. Whether they’re old electromechanical designs or modern digital relays, they need time for:
  • detecting the fault (pickup time)
  • applying intentional time delay based on settings
  • energizing the output to trip the breaker

Relay Overtravel

• For electromechanical designs, this adds about 0.10 s. Overtravel is the extra motion of the moving element after the fault current is removed. Because these relays operate using magnetic torque acting on a rotating disk, their moving parts have mechanical inertia. So when the current drops below the pickup from a successful fault isolation by the downstream protection device:
  • the magnetic torque in the upstream electromechanical relay disappears instantly
  • But the disk continues rotating due to stored kinetic energy.
  • If it rotates far enough to touch the trip contact → the relay still trips despite current having already cleared.

Circuit Breaker Opening Time

• When a breaker receives a trip signal, it must:
  • energize the trip coil
  • physically move its contacts
  • extinguish the arc
• The time it takes for all of these mechanical events to happen is commonly expressed in cycles. Historically, ANSI/IEEE standards categorized breakers into classes like 3-cycle, 5-cycle, and 8-cycle. This can be found in circuit breaker nameplates as the Rated Interrupting Time which is defined as the maximum permissible time interval between the energizing of the trip circuit (when the protection relay sends a signal) and the final interruption of the current in all poles (when the arc is fully extinguished). In a standard 60 Hz power system, one cycle is approximately 16.67 milliseconds. A 5-cycle rating means the breaker is designed to clear a fault within approximately 83 milliseconds (5 cycles × 16.67 ms).

Final Thoughts

Time–current curves (TCCs) are vital in overcurrent protection coordination, providing the clear separation and coordination time interval (CTI) needed to ensure each device operates in the proper sequence, preventing unnecessary tripping and improving system reliability. CTIs are essential for a reliable and selective protection system, however, they are easy to overlook when starting out in protection engineering.

Whether you’re coordinating fuses or modern numerical relays, understanding the delays built into each device helps ensure that the right component trips at the right time.
By applying CTIs thoughtfully—guided by IEEE 242 and real‑world practice—you can avoid nuisance trips, reduce unnecessary outages, and build a protection scheme that behaves exactly as intended when a fault occurs.

References

D. Durand, Overcurrent Protection & Coordination for Industrial Applications. IEEE Continuing Education Seminar, Houston Section, Houston, TX, Nov. 3–4, 2015. [Online]. Available: https://r5.ieee.org/houston/wp-content/uploads/sites/32/2016/01/2015-11-03-Overcurrent-Coordination-Industrial-

IEEE Std 242-2001 [The Buff Book]: IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems.(2001). S.I.: IEEE.

Blackburn, J. (2014). Protective Relaying Principles and Application, 4th ed. Boca Raton, FL: CRC Press.

Hubbell Power Systems, *Application of Primary Fuses*, Bulletin 10‑7701 Rev. 9/97, A.B. Chance Company, 1997. [Online]. Available: https://hubbellcdn.com/installationmanuals/10-7701.pdf