Relay setting calculations for the primary substation and Remote end grid station

Relay setting calculations for primary substations and remote-end grid stations are critical for ensuring effective coordination, selectivity, and fault isolation within a power system. These settings define the operation of protective relays in detecting and isolating faults accurately and swiftly, with minimal impact on the rest of the network. This guide provides an overview of how relay settings are calculated for primary substations and remote-end stations.

1. Understanding Relay Setting Objectives

Relay setting calculations aim to:

• Protect system components: Set relays to prevent equipment damage by isolating faults.
• Ensure selectivity: Coordinate settings so only the relay closest to the fault operates, while upstream relays act as backups.
• Maintain sensitivity: Ensure that relays are sensitive enough to detect even low-level faults within their designated zones.
• Optimize speed and reliability: Relays must operate quickly to clear faults without unnecessary delays.

2. Types of Protection and Relays in Primary and Remote Stations

In substations and remote-end grid stations, typical relay types and protection schemes include:

• Overcurrent Relays: Protect against excessive currents caused by faults.
• Distance Relays: Used primarily for transmission line protection, measuring impedance to determine fault location.
• Differential Relays: Used for protecting transformers, buses, and other critical equipment, based on current differences between primary and secondary sides.

3. Key Parameters for Relay Setting Calculations

To calculate relay settings effectively, the following parameters are essential:

• System Fault Levels: Short-circuit current levels calculated for various fault conditions (e.g., three-phase, line-to-ground) at both ends.
• Impedance Values: Transmission line impedances between stations, typically expressed in ohms or per-unit values.
• CT and VT Ratios: Current and voltage transformer ratios to scale primary values to secondary relay levels.
• Load Current: Maximum load current to avoid unintentional tripping under normal conditions.
• Fault Clearing Time: Required time for fault clearing based on system coordination studies.

4. Overcurrent Relay Setting Calculations

Overcurrent relays are often the first line of defense in primary substations and remote-end stations, providing both phase and ground fault protection. The steps for setting these relays typically include:

• Pickup Current Setting (I_pickup): This is the minimum current that will cause the relay to operate.

  • Calculation: $I_{pickup} = 1.2 \times I_{max\_load}$, where $I_{max\_load}$ is the maximum load current. The multiplier of 1.2 accounts for margin to prevent tripping during normal load fluctuations.

• Time Delay Setting: Ensures that overcurrent relays closer to the fault operate before upstream relays. Typically achieved using time-current curves.

  • Coordination: Set the time delay such that the relay closest to the fault trips first, with successive upstream relays delayed appropriately.

• Ground Fault Setting: Ground overcurrent relay settings are generally lower than phase settings to provide adequate sensitivity.

  • Calculation: Set to detect ground faults at around 20-40% of the line’s maximum load current.

5. Distance Relay Setting Calculations

Distance relays are crucial for transmission line protection at both primary and remote stations, dividing protection into distinct zones based on impedance (distance from the relay to the fault location).

• Zone 1 Setting: Instantaneous protection covering 80-90% of the line length to avoid misoperation due to infeed effect from the remote end.

  • Calculation: $Z_{Zone1} = 0.8 \times Z_{Line}$, where $Z_{Line}$ is the total line impedance.

• Zone 2 Setting: Backup protection for the remaining 10-20% of the line plus an additional reach into the adjacent line, typically set with a short time delay.

  • Calculation: $Z_{Zone2} = 1.2 \times Z_{Line}$, covering the remainder of the line and a small margin into the adjacent line section.

• Zone 3 Setting: Long reach backup for downstream faults beyond the remote end, typically covering 150% of the line impedance with an extended time delay.

  • Calculation: $Z_{Zone3} = 1.5 \times Z_{Line}$.

• Directional Element: In cases of networked or ring configurations, directional elements are included to ensure correct fault directionality, preventing unintended operation on the reverse side.

6. Differential Relay Setting Calculations

Differential protection is used for equipment like transformers and buses within substations, comparing current entering and leaving the protected zone.

• Pickup Current Setting: Set above the transformer’s maximum inrush current to avoid tripping during startup.

  • Calculation: $I_{pickup} = 1.25 \times I_{max\_load}$.

• Restraint Setting: To prevent tripping on external faults or during inrush, a restraint factor is applied to limit differential sensitivity during high external currents.

7. Coordination Between Primary Substation and Remote Grid Station

• Time Coordination: Ensure that time delays in primary and remote stations are graded correctly so only the relay nearest the fault trips first.
• Sensitivity and Reach: Ensure primary substation settings do not overlap excessively with remote end settings to avoid overreach, which could lead to unnecessary tripping on faults outside the intended protection zone.
• Load Encroachment Setting: Distance relays may incorporate load encroachment settings to prevent tripping under high load conditions close to the relay’s set threshold.

8. Setting Verification and Testing

Once settings are calculated, they should be tested and verified:

• Simulation and Testing: Use relay test sets and simulation software to check that settings operate as expected under simulated fault conditions.
• Coordination Study: Perform a comprehensive coordination study with all protective devices in the system to validate time and current settings, ensuring each relay responds selectively to its designated zone.

Conclusion

Relay setting calculations for primary substations and remote grid stations require careful consideration of system parameters, fault levels, and coordination principles to ensure reliable and selective fault isolation. By following these steps and conducting thorough testing, engineers can establish a protection system that safeguards assets, minimizes outage impact, and maintains system stability across the network.

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