Protection Coordination in Distribution Systems Calculator – IEEE, IEC

Protection coordination in distribution systems ensures selective fault isolation, minimizing outage impact and equipment damage. Calculations based on IEEE and IEC standards optimize relay settings and device coordination.

This article explores advanced protection coordination calculators, detailing formulas, tables, and real-world applications for distribution networks. It covers IEEE and IEC methodologies, practical examples, and essential parameters for engineers.

Artificial Intelligence (AI) Calculator for “Protection Coordination in Distribution Systems Calculator – IEEE, IEC”

• Calculate coordination time interval between primary and backup relays for a 33 kV feeder.
• Determine optimal relay pickup current settings for a 11 kV distribution transformer protection.
• Compute fault current levels and relay settings for a radial distribution feeder with distributed generation.
• Evaluate time-current characteristic curves for overcurrent relays per IEC 60255 standards.

Common Values for Protection Coordination in Distribution Systems Calculator – IEEE, IEC

Fundamental Formulas for Protection Coordination in Distribution Systems

Protection coordination relies heavily on time-current characteristic (TCC) curves and fault current calculations. Below are the essential formulas used in IEEE and IEC standards.

1. Inverse Time Overcurrent Relay Operating Time

• t: Operating time of the relay (seconds)
• TMS: Time Multiplier Setting (unitless, 0.05 to 1.0)
• a, b: Relay constants defining curve shape (typical a=0.14–0.18, b=0.02–0.04)
• I: Fault current magnitude (Amperes)
• Ip: Pickup current setting (Amperes)
• tmin: Minimum operating time (seconds)

This formula calculates the relay operating time based on the magnitude of the fault current relative to the pickup current. The constants a and b define the curve type, such as standard inverse, very inverse, or extremely inverse.

2. Coordination Time Interval (CTI)

• CTI: Coordination time interval (seconds)
• t_backup: Operating time of backup relay (seconds)
• t_primary: Operating time of primary relay (seconds)

The CTI ensures that the primary relay clears the fault before the backup relay operates, preventing unnecessary outages.

3. Fault Current Calculation (IEC 60909 Method)

• If: Fault current (Amperes)
• Un: Nominal line-to-line voltage (Volts)
• Zk: Short-circuit impedance (Ohms)

This formula calculates the initial symmetrical short-circuit current for three-phase faults in distribution systems, per IEC 60909.

4. Relay Pickup Current Setting

• Ip: Relay pickup current (Amperes)
• k: Safety factor (typically 1.2 to 1.5)
• Iload: Maximum load current (Amperes)

Pickup current is set above the maximum load current to avoid nuisance tripping during normal operation.

5. Time Dial Setting (TDS) Relation to Operating Time

• t: Relay operating time (seconds)
• TDS: Time Dial Setting (unitless)
• t_base: Base operating time from relay characteristic curve (seconds)

TDS adjusts the relay operating time curve to coordinate with other protective devices.

Real-World Application Examples of Protection Coordination Calculations

Example 1: Coordination of Overcurrent Relays on a 11 kV Radial Feeder

A radial distribution feeder operates at 11 kV with a maximum load current of 200 A. The primary relay is located at the feeder head, and a backup relay is installed upstream. The goal is to set the pickup currents and time settings to ensure proper coordination.

• Maximum load current (Iload): 200 A
• Safety factor (k): 1.3
• Relay constants (a, b): 0.14, 0.02 (standard inverse)
• Time multiplier setting (TMS): To be determined
• Coordination time interval (CTI): Minimum 0.3 seconds

Step 1: Calculate Pickup Current (Ip)

Ip = k × Iload = 1.3 × 200 = 260 A

Step 2: Determine Fault Current (I)

Assume maximum fault current at feeder head is 2000 A.

Step 3: Calculate Primary Relay Operating Time (t_primary)

Using the inverse time formula:

Assuming TMS_primary = 0.1 and tmin = 0.1 s:

Calculate (I / Ip)^b:

(2000 / 260)^0.02 ≈ (7.69)^0.02 ≈ 1.05

Then:

t_primary = 0.1 × (0.14 / (1.05 – 1)) + 0.1 = 0.1 × (0.14 / 0.05) + 0.1 = 0.1 × 2.8 + 0.1 = 0.28 + 0.1 = 0.38 seconds

Step 4: Set Backup Relay Operating Time (t_backup)

To maintain CTI ≥ 0.3 s:

t_backup ≥ t_primary + 0.3 = 0.38 + 0.3 = 0.68 seconds

Assuming backup relay pickup current is set at 1.5 × Ip_primary = 390 A, and TMS_backup is adjusted to achieve t_backup = 0.7 s.

Step 5: Verify Backup Relay Operating Time

Calculate (I / Ip_backup)^b:

(2000 / 390)^0.02 ≈ (5.13)^0.02 ≈ 1.04

Then:

t_backup = TMS_backup × (0.14 / (1.04 – 1)) + 0.1

Solving for TMS_backup:

0.7 = TMS_backup × (0.14 / 0.04) + 0.1

0.7 – 0.1 = TMS_backup × 3.5

0.6 = 3.5 × TMS_backup

TMS_backup = 0.6 / 3.5 ≈ 0.171

Result: Primary relay TMS = 0.1, backup relay TMS = 0.171, ensuring proper coordination.

Example 2: Protection Coordination for a 33 kV Distribution Transformer

A 33 kV distribution transformer rated at 2 MVA feeds a 11 kV network. The transformer has a rated current of 35 A on the primary side. The goal is to set the relay pickup current and time settings to protect the transformer and coordinate with upstream feeder protection.

• Transformer rated current (In): 35 A
• Maximum load current (Iload): 30 A
• Safety factor (k): 1.2
• Fault current at transformer secondary: 1500 A
• Relay constants (a, b): 0.18, 0.02 (very inverse)
• Minimum operating time (tmin): 0.15 s

Step 1: Calculate Pickup Current (Ip)

Ip = k × Iload = 1.2 × 30 = 36 A

Step 2: Calculate Relay Operating Time (t)

Assuming TMS = 0.2:

(I / Ip)^b = (1500 / 36)^0.02 ≈ (41.67)^0.02 ≈ 1.07

t = 0.2 × (0.18 / (1.07 – 1)) + 0.15 = 0.2 × (0.18 / 0.07) + 0.15 = 0.2 × 2.57 + 0.15 = 0.514 + 0.15 = 0.664 seconds

Step 3: Coordination with Upstream Feeder Relay

Assuming upstream relay operating time is 1.0 second, CTI = 1.0 – 0.664 = 0.336 seconds, which satisfies the minimum 0.3 seconds coordination interval.

Result: Relay pickup current set at 36 A with TMS 0.2 ensures selective transformer protection and coordination.

Additional Technical Considerations for Protection Coordination Calculators

• Relay Characteristic Curves: IEEE C37.112 and IEC 60255-151 define multiple inverse time curves such as standard inverse, very inverse, and extremely inverse. Selection depends on system fault levels and coordination requirements.
• Impact of Distributed Generation: Integration of distributed energy resources (DER) affects fault current levels and relay coordination. Calculators must incorporate updated fault current contributions.
• Time Dial and Time Multiplier Settings: These parameters provide flexibility in adjusting relay operating times to achieve coordination without hardware changes.
• Coordination with Directional Relays: In meshed or looped distribution systems, directional overcurrent relays require additional settings and coordination logic.
• Use of Software Tools: Modern protection coordination calculators integrate with power system analysis software (e.g., ETAP, DIgSILENT PowerFactory) for comprehensive studies.

Authoritative References and Standards

• IEEE Std C37.112-2014 – Guide for the Application of Time-Overcurrent Relays
• IEC 60255-151 – Electrical Relays – Part 151: Measuring Relays and Protection Equipment – Overcurrent Relays
• IEEE Std C37.2-2008 – Electrical Power System Device Function Numbers, Acronyms, and Contact Designations
• IEC 60909 – Short-Circuit Currents in Three-Phase AC Systems
• IEEE Power & Energy Society Publications on Protection Coordination