6.3 Protective Relaying Fundamentals, Device ANSI Numbers (50/51, 87, 21, 27/59, 81), and Coordination

Protective Relaying Fundamentals, Device ANSI Numbers, and Coordination

Quick Summary: Protective relaying systems monitor power system currents, voltages, and frequencies to detect abnormal faults and initiate high-speed circuit breaker tripping. Governed by ANSI/IEEE C37.2, IEEE C37.90, and NETA ATS/MTS, protection engineering balances five core objectives—selectivity, speed, sensitivity, dependability, and security—through precise device coordination and overlapping protection zones.

Protective relays do not prevent faults; rather, they detect short circuits, overloads, and abnormal operating conditions, isolating the faulted apparatus in the minimum possible time to minimize equipment damage, maintain system stability, and protect human life.

1. Core Protection Philosophy and Zones of Protection

A power system is segmented into distinct Zones of Protection, each encompassing a specific apparatus:

• Generator Zones
• Transformer Zones
• Busbar Zones
• Transmission / Distribution Feeder Zones
• Motor Zones

+-----------------------------------------------------------------------------------------+
|                         OVERLAPPING ZONES OF PROTECTION                                 |
|                                                                                         |
|      [ GENERATOR ZONE ]              [ TRANSFORMER ZONE ]          [ FEEDER ZONE ]      |
|   +-----------------------+       +------------------------+    +--------------------+  |
|   |                       |       |                        |    |                    |  |
|   |   (GEN) === [CT1] === | [52G] | === [CT2] === (XFMR) ==|==  | [52F] === [CT3] ===|  |
|   |                       |       |                        |    |                    |  |
|   +-----------------------+       +------------------------+    +--------------------+  |
|               ^                               ^                              ^          |
|               |------- OVERLAP REGION --------|                              |          |
|                               (Circuit Breaker 52G)                          |          |
+-----------------------------------------------------------------------------------------+

The Overlap Principle:

To ensure that no part of the electrical system is left unprotected, adjacent protection zones must overlap. The boundary of each protection zone is defined by the physical location of the current transformers (CTs). By placing CTs on both sides of the circuit breaker (or utilizing bushing CTs on opposite sides of the breaker mechanism), the breaker itself resides within both zones, eliminating "blind spots."

Primary vs. Backup Protection:

• Primary (Unit/Main) Protection: The first-line protection scheme designed to operate with no intentional time delay (or minimal coordination delay) to clear faults within its assigned zone.
• Backup Protection: Operates with intentional time delay to clear faults if the primary scheme fails (due to relay failure, loss of DC trip supply, CT failure, or breaker mechanism failure).
  • Local Backup: Located within the same substation, utilizing separate relays, separate CT/VT inputs, and separate trip coils on the same breaker (or a breaker failure scheme, ANSI 50BF).
  • Remote Backup: Located at an adjacent upstream substation (e.g., an upstream overcurrent or Zone 2 distance relay), which trips all lines feeding the faulted bus, causing a larger system outage.

2. Essential ANSI/IEEE C37.2 Standard Device Function Numbers

ANSI/IEEE C37.2 defines standardized numerical designations for electrical power apparatus protection and control functions:

3. Time-Current Characteristic (TCC) Curves and Mathematical Formulations

Time overcurrent relays (ANSI 51) utilize standardized inverse Time-Current Characteristics (TCC). As fault current increases, the operating time decreases, ensuring fast clearing for severe close-in faults while coordinating with downstream devices for distant faults.

Operating
Time (sec)
    ^
 10 |   \
    |    \
  1 |     \   Moderately Inverse
    |      \---\  Very Inverse
0.1 |           \---\  Extremely Inverse
    |                \----
    +-----------------------------------------> Multiples of Pickup Current (I / I_pickup)
       1x   2x    5x    10x    20x

IEEE Standard Curve Equation (IEEE C37.112):

$t(I) = TD \times \left( \frac{A}{(I / I_{pickup})^p - 1} + B \right)$

Where:

• t(I) = Operating trip time in seconds
• TD = Time Dial setting (multiplier from 0.5 to 15.0)
• I = Measured secondary fault current
• I_pickup = Selected pickup current setting (Tap × CTR)
• A, B, p = Curve shape constants

IEC 60255 Standard Curve Equation:

$t(I) = TMS \times \left( \frac{k}{(I / I_s)^\alpha - 1} \right)$

Where TMS is the Time Multiplier Setting, I_s is the current setpoint, and curve constants are defined as:

• Standard Inverse: k = 0.14, α = 0.02
• Very Inverse: k = 13.5, α = 1.00
• Extremely Inverse: k = 80.0, α = 2.00
• Long-Time Inverse: k = 120.0, α = 1.00

4. Relay Coordination and Coordination Time Interval (CTI)

Protective Device Coordination is the process of setting overcurrent devices in series such that the device closest to the fault trips first, isolating the minimum portion of the system.

$\text{Total Upstream Operating Time} = t_{downstream} + \text{CTI}$

+-----------------------------------------------------------------------------------------+
|                    COORDINATION TIME INTERVAL (CTI) BUDGETING                           |
|                                                                                         |
|   Upstream Relay Operating Time (0.55 s)                                                |
|   ====================================================                                  |
|          ^                                                                              |
|          |  [SAFETY MARGIN]                0.10 s (Margin for setting drift / ambient)  |
|          |  [CT RATIO & SATURATION ERROR]  0.05 s (CT transient performance error)      |
|   CTI    |  [RELAY OVERTRAVEL / OVERSHOOT] 0.10 s (Electromechanical disk coasting)     |
| (0.35 s) |  [BREAKER INTERRUPTING TIME]    0.08 s (5-Cycle breaker total clearing time) |
|          v                                                                              |
|   ====================================================                                  |
|   Downstream Relay Operating Time (0.20 s)                                              |
+-----------------------------------------------------------------------------------------+

Breakdown of CTI Components:

1. Circuit Breaker Total Clearing Time (t_breaker): The time required from trip coil energization until the arc is fully extinguished in all phases. Typically 3 to 5 cycles (0.05 to 0.083 seconds) for modern medium-voltage vacuum or SF6 breakers.
2. Relay Overtravel / Overshoot (t_overtravel): In electromechanical relays, after the fault is cleared by the downstream breaker, the induction disc continues to rotate due to rotational inertia. An allowance of 0.10 seconds is required for electromechanical relays. For microprocessor relays, inertia is zero (t_overshoot ≤ 0.02 s).
3. CT Ratio and Transient Errors (t_error): Accounting for CT saturation delays and ratio inaccuracies during high asymmetrical faults (typically 0.05 seconds).
4. Safety Margin (t_margin): Engineering safety factor to accommodate tolerance variations in relay calibration, temperature drift, and ambient variables (typically 0.10 seconds).

Standard CTI Guidelines:

• Electromechanical Upstream & Downstream: CTI = 0.30 to 0.40 seconds (typically 0.35 s).
• Digital Upstream & Electromechanical Downstream: CTI = 0.20 to 0.30 seconds.
• Digital Upstream & Digital Downstream: CTI = 0.15 to 0.25 seconds (typically 0.20 s).
• Relay Coordinating with Downstream Fuse: Clear of the fuse total clearing curve by at least 0.15 to 0.20 seconds or 135% of fuse total clearing time.