The coordination time interval overcurrent relay engineers use is the intentional time margin between a downstream protective device and the upstream backup device at the same fault current, so the device closest to the fault trips first and the upstream device remains available as backup. In practice, CTI is not a fixed universal number: it depends on relay technology, breaker clearing time, tolerances, CT error, and the system conditions shown on the study. Industry guidance commonly treats about 0.25 s as a typical starting point for digital relay pairs and about 0.30 s or more where breaker time and electromechanical behavior must be fully accommodated.
This is why CTI sits at the center of every serious relay coordination study. If the margin is too small, both devices may trip for the same fault. If the margin is too large, the fault is cleared too slowly and equipment stress rises. For projects involving protection relays, feeder upgrades, or retrofit work in Saudi Arabia, CTI is one of the first values that should be checked before approving final settings.
What CTI Means on TCC Curves
On TCC curves, CTI is the vertical time gap between the downstream curve and the upstream curve at the same current value. That gap represents your selectivity margin. If the downstream relay operates at 0.35 s and the upstream relay operates at 0.65 s at the same fault current, the CTI is 0.30 s. That is the basic logic behind selectivity coordination.
A good study does not look at one current point only. It checks the relationship across the full operating range, including minimum and maximum fault levels, instantaneous regions, motor starting zones, and possible transformer inrush or switching inrush zones. ABB’s guidance on selectivity diagrams also highlights that a proper coordination view should include minimum and maximum fault current levels, load current, and possible inrush currents, not just relay curves by themselves.
Another important point is curve family selection. GE Vernova’s feeder protection guidance notes that when inverse-time relays must be mutually selective, using relays with the same degree of inverseness is generally good practice; otherwise, maintaining selectivity over a wide range of fault current can become difficult. That is one reason many mis-coordination cases are not “setting mistakes” alone, but curve-selection mistakes.
How to Calculate CTI
The practical calculation is:
CTI = Upstream total clearing time − Downstream total clearing time
In many studies, “total clearing time” means more than relay operating time. It can include relay delay, breaker interrupting time, relay tolerance, and any allowance you apply for safety margin. If your software already plots total device clearing curves, use those. If it plots relay operate time only, then breaker time and study allowances must be added correctly before you approve the setting.
Step 1: Collect the Right Data
Before changing overcurrent relay settings, collect:
- minimum and maximum fault current at each protection location
- CT ratios and relay pickup ranges
- relay curve type and time multiplier / time dial values
- breaker interrupting time
- transformer inrush and motor starting constraints
- operating modes such as utility-only, generator support, or tie-closed conditions
If you are reviewing a setting file, it also helps to compare it against a dedicated protection relay configuration guide so pickup logic, curve family, and element enable/disable status are checked together rather than separately.
Step 2: Plot Both Devices at the Same Current
Pick a fault current that both devices see for the same fault location. This is often the maximum common fault current, because that is where coordination margins can become tight. Then verify additional points, especially end-of-line faults and different source configurations. Guidance on overcurrent coordination commonly recommends checking the maximum fault point, while feeder coordination references also stress reviewing more than one system condition.
Step 3: Read the Two Times
Assume the following example for a feeder and its upstream incomer:
- downstream feeder relay total clearing time at 8 kA = 0.38 s
- upstream incomer relay total clearing time at 8 kA = 0.69 s
Then:
CTI = 0.69 − 0.38 = 0.31 s
That result would generally be considered acceptable for many relay-relay coordination cases that need about 0.25 s to 0.30 s of margin, depending on technology and breaker details. But if the upstream time were 0.58 s, then:
CTI = 0.58 − 0.38 = 0.20 s
That would often be too tight and could lead to mis-coordination.
Step 4: Check More Than One Region
A common error is to check CTI in the inverse-time region only and forget the instantaneous or high-set region. Another is to accept good separation at one fault point while the curves overlap at a different point. This is especially risky when the system includes new LV & MV switchgear, transformer changes, motor additions, or source changes that alter short-circuit levels.
Typical CTI Starting Points
As a practical starting guide, many studies use these margins before final verification:
- Digital relay to digital relay: around 0.25 s
- Electromechanical relay to relay / breaker-inclusive grading: around 0.30 s
- General relay-relay range used in practice: about 0.25 s to 0.40 s depending on breaker time, relay tolerances, and application
These are starting points, not substitutes for a real study. The correct margin must match the actual relay family, breaker clearing time, CT behavior, and fault-current range of the installation.
Why Mis-Coordination Happens
1) Breaker Time Is Ignored
Some engineers compare relay operating times only, but the actual fault-clearing sequence depends on the full device behavior. If breaker interrupting time is omitted, the apparent CTI can look safe on paper while the field result is too tight.
2) The Wrong Curve Family Is Selected
Mixing curve families without checking the full TCC relationship can create hidden crossovers. If the devices do not have the same degree of inverseness, selectivity across a wide current range becomes harder to maintain.
3) Minimum Fault Current Is Not Checked
A system may coordinate well at high fault current and fail at low fault current near the end of a feeder. A complete study should check both ends of the fault-current range and more than one operating mode.
4) Inrush and Starting Effects Are Overlooked
Transformer energization, feeder inrush, and motor starting can sit close to protection pickup zones. ABB’s selectivity guidance explicitly includes switching inrush and start currents as information that belongs on the selectivity diagram.
5) Instantaneous Elements Are Left Uncoordinated
A well-graded inverse-time region does not automatically mean the high-set or instantaneous element is coordinated. This is a frequent reason for nuisance tripping after modifications to medium voltage switchgear or feeder topology.
How to Avoid Mis-Coordination
Start with relay pickup values that stay above maximum normal load but remain sensitive enough for the minimum fault level. Then choose a curve type and time multiplier that preserve CTI across the actual fault-current range, not just one calculation point. If the coordination study becomes unstable across different conditions, review whether the relay family itself is appropriate before forcing the settings.
Next, verify the study under all relevant operating states:
- normal source configuration
- generator or alternate source in service
- tie breaker open and closed
- future expansion scenarios
- transformer energization and motor start cases
For broader plant reviews, package the settings work with related electrical engineering services in Saudi Arabia so the relay file, breaker data, short-circuit model, and switchgear condition are reviewed together.
Finally, do not stop at the software plot. Confirm the “as-left” field settings, CT ratio entries, breaker information, firmware behavior, and actual enabled elements. Many protection failures happen because the study file is correct but the installed settings are not.
When a Full Relay Coordination Study Is Needed
You should request a full study when:
- nuisance trips are happening during downstream faults
- an incomer trips with a feeder fault
- relays are being replaced or reprogrammed
- switchgear is retrofitted or breakers are changed
- generators, solar, or new large motors are added
- transformer sizes or system fault levels have changed
- you need documented selectivity for a project in Saudi Arabia
A useful background read before a full review is this guide on types of protection relay in power system, especially if the system includes multiple relay functions and not only simple feeder overcurrent elements.
FAQ
What is a good coordination time interval overcurrent relay?
A common starting point is around 0.25 s for many digital relay pairs and around 0.30 s or more where breaker time and electromechanical behavior must be fully considered. The final value must come from the actual study, not a rule of thumb.
Is CTI the same as relay operating time?
No. CTI is the difference between upstream and downstream clearing times at the same fault current.
Can good TCC separation still produce mis-coordination?
Yes. It can happen if breaker time, instantaneous functions, CT error, minimum fault current, or different operating modes were not checked.
Should CTI be checked only at maximum fault current?
No. Maximum fault current is important, but end-of-line faults, source changes, inrush regions, and instantaneous zones should also be verified.
Why do CTI problems appear after retrofit projects?
Because new breakers, updated relay firmware, changed CT ratios, altered fault levels, and different network topologies can invalidate the old settings.
If you need a technical review of CTI, TCC curves, and overcurrent relay settings for an industrial or utility project in Saudi Arabia, start with protection relays or reach out with r-aletqan through contact us. For direct inquiries, call (+966) 920012931.
