Protective Relay Coordination / TCC Visualizer

What Is a TCC (Time-Current Characteristic)?

A TCC curve plots the operating time of a protective device against the fault current magnitude. The horizontal axis is current (log scale) and the vertical axis is time (log scale). Every overcurrent device -- fuse, breaker, or relay -- has a characteristic curve that describes how fast it operates for a given current level.

Pickup Current

The pickup is the minimum current at which a protective device begins to respond. Below pickup, the device ignores the current entirely. For relays, pickup is set by adjusting the current tap. For fuses, it is determined by the fuse rating. For thermal-magnetic breakers, the thermal element sets the pickup threshold.

• Pickup must be set above maximum expected load current
• Pickup must be below minimum expected fault current for proper detection
• Typical rule: pickup = 1.25 to 1.5 x full load current
• In NEC-governed installations the overcurrent device rating is also bounded by conductor ampacity and the applicable protection article (for example NEC 240.4 for conductors, 430 Part IV for motor branch-circuit short-circuit and ground-fault protection) -- a coordination-driven pickup never overrides those limits

Time Multiplier Setting (TMS)

The TMS (IEC terminology; IEEE uses "Time Dial Setting" or TDS) shifts the entire inverse-time curve up or down on the time axis. A higher TMS means the device takes longer to trip at any given fault current. This is the primary knob for coordination -- you set the downstream device faster (lower TMS) and the upstream device slower (higher TMS) so that the downstream device always clears the fault first.

• Lower TMS = faster operation
• Higher TMS = slower operation
• The CTI (Coordination Time Interval) between upstream and downstream should be at least 0.2-0.4 seconds
• IEC typical range: 0.05 to 1.0 (this tool extends to 1.2 for demonstration)
• Slowing an upstream device to gain margin must still respect equipment damage curves and, where applicable, the arc-energy-reduction requirements of NEC 240.87

Instantaneous Element

The instantaneous pickup overrides the time-delay curve. When fault current exceeds this threshold, the device trips with no intentional delay (typically 1-3 cycles, or 0.016-0.05 seconds). Instantaneous elements provide fast clearing of high-magnitude faults but can cause coordination problems if set too low.

• Set above the maximum fault current seen by the downstream device, if coordination is required
• Provides fast clearing for close-in faults
• May need to be disabled on some relay applications for coordination
• Disabling instantaneous protection to buy selectivity increases incident energy; NEC 240.87 requires a documented arc-energy-reduction method for circuit breakers rated or adjustable to 1200 A and above

Ground Fault Protection

Ground fault relays detect current flowing to ground through a separate CT circuit. Their pickup is typically set much lower than phase overcurrent because ground faults often produce less current than three-phase faults, but must still be detected and cleared promptly. Use the Phase/Ground fault type selector to switch the analysis mode.

• Equipment protection (GFPE): NEC 230.95 requires ground-fault protection on solidly grounded wye services over 150 V to ground and 1000 A or more, with a maximum setting of 1200 A and a maximum time delay of one second for ground-fault currents of 3000 A or more. Similar requirements appear in 215.10 (feeders) and 240.13 (building disconnects).
• Personnel protection is a different device: a Class A GFCI trips at 4-6 milliamps (UL 943). No breaker or relay ground-fault setting in this tool is shock protection for people.
• Coordinating two GFPE devices in series generally requires a zone-selective interlock or a deliberate time step, because both may be set near the same low pickup.

IEC 60255 IDMT Curve Families

This tool implements IEC-style Inverse Definite Minimum Time (IDMT) equations. These are not IEEE/ANSI C37.112 curves.

• IEC Standard / Normal Inverse: t = TMS × 0.14 / (M^0.02 - 1). Moderate slope; general purpose.
• IEC Very Inverse: t = TMS × 13.5 / (M - 1). Steeper slope; better for feeders with high variation in fault current.
• IEC Extremely Inverse: t = TMS × 80 / (M² - 1). Very steep; good for coordination with fuses.
• Definite Time: Fixed time delay (entered directly in seconds) regardless of current above pickup.

Where M = I/I_pickup (multiple of pickup current)

Coordination Principles

• The device closest to the fault should trip first (downstream before upstream)
• Maintain a Coordination Time Interval (CTI) of at least 0.2-0.4 s between curves
• Check coordination across the entire range of possible fault currents, not just one point
• Instantaneous elements can break coordination at high current levels
• Fuse-breaker coordination requires careful curve comparison using manufacturer data
• Where the NEC mandates selective coordination -- elevators (620.62), emergency systems (700.32), legally required standby (701.32), critical operations power (708.54) -- the requirement is full selectivity over the fault range and time, verified with manufacturer data, not a curve-shape approximation like this one

Common Mistakes

• Setting downstream pickup higher than upstream pickup -- removes selectivity
• Ignoring the instantaneous region -- curves may cross at high currents
• Insufficient CTI -- relay overtravel, breaker clearing time not accounted for
• Not checking coordination at both minimum and maximum fault levels
• Using the same curve family on both devices when different families would coordinate better
• Forgetting motor inrush or transformer energization when setting pickups
• Relying on single-point checks instead of full curve comparison
• Treating a generic curve equation as a substitute for manufacturer minimum-melt / total-clearing bands or a listed fuse-breaker series-rating combination

Motor & Transformer Inrush

Motor inrush: When a motor starts, it draws 5-7x its full load current for several seconds. Protection devices must not trip during normal motor starting. The inrush point is typically plotted at 6x FLA for 5-10 seconds.

Transformer inrush: Energizing a transformer produces inrush current of 8-12x rated current that decays over 0.1-0.5 seconds. The relay must ride through this transient without false tripping.

Riding through inrush is a floor, not a license: motor branch-circuit protection is still bounded by NEC Table 430.52 and transformer primary/secondary protection by NEC 450.3.