Protective Relay Coordination

What Is Protective Relay Coordination?

Protective relay coordination is the engineering process of selecting and setting protective devices so that a fault at any point in the electrical distribution system is cleared by the device closest to the fault, with upstream devices providing backup protection if the primary device fails. Proper coordination ensures selectivity (only the faulted section is de-energized), speed (faults are cleared as fast as possible to limit equipment damage and arc flash hazard), and reliability (backup protection operates if the primary device fails to clear the fault).

NFM Consulting performs protective relay coordination studies for industrial, commercial, and utility power systems ranging from 208V to 138 kV. Our studies comply with IEEE 242 (Buff Book), NEC requirements, and NFPA 70E arc flash safety standards. We deliver coordination study reports with time-current curve (TCC) plots, relay setting recommendations, and fault current data for every bus in the system.

Fundamentals of Coordination

Time-Current Characteristics

Every protective device has a time-current characteristic (TCC) that defines how long the device takes to operate at a given fault current magnitude. These characteristics are plotted on log-log graphs with current on the horizontal axis and time on the vertical axis. For proper coordination, the TCC curves of series devices must not overlap, and adequate coordination margins must exist between adjacent devices.

Coordination Margins

Standard coordination margins between devices include:

• Relay-to-relay: 0.3-0.4 seconds coordination time interval (CTI) between upstream and downstream relay curves, accounting for relay operating time tolerance, breaker interrupting time, and relay overtravel
• Fuse-to-fuse: The upstream fuse total clearing curve must be above the downstream fuse minimum melting curve at all current levels up to the downstream fuse interrupting rating
• Relay-to-fuse: The relay curve must be above the fuse total clearing curve at current levels where the fuse is expected to operate
• Fuse-to-relay: The fuse minimum melting curve must be above the relay curve plus CTI to ensure the relay operates before the fuse at lower fault currents

Types of Protective Relays

Overcurrent Relays (50/51)

Overcurrent relays are the most common protective devices. The ANSI 51 element provides time-delayed tripping with configurable time-current curves (inverse, very inverse, extremely inverse, or definite time). The ANSI 50 element provides instantaneous tripping above a settable pickup current for high-magnitude faults. Settings include pickup current (tap), time dial, curve type, and instantaneous pickup.

Differential Relays (87)

Differential relays compare current entering and leaving a protected zone (transformer, bus, motor, or generator). Any imbalance exceeding the relay's restraint setting indicates an internal fault, and the relay trips instantaneously (typically 1-2 cycles). Differential protection is extremely fast and selective because it only responds to faults within the protected zone, making coordination with other devices straightforward.

Distance Relays (21)

Distance relays measure the impedance seen from the relay location and trip when the impedance falls below a setting corresponding to a fault within the protected line section. Multiple zones provide step-distance protection: Zone 1 covers 80-85% of the line with instantaneous tripping, Zone 2 covers 100% of the line plus 20-50% of the next line with a time delay, and Zone 3 provides remote backup protection with a longer time delay.

Coordination Study Process

A comprehensive coordination study follows these steps:

• Data collection: Single-line diagrams, equipment ratings, transformer impedances, cable lengths, motor horsepower, existing relay settings, and utility fault current data
• System modeling: Build the power system model in analysis software (ETAP, SKM PowerTools, or EasyPower) and validate with field measurements
• Short-circuit analysis: Calculate maximum and minimum fault currents at every bus for three-phase, line-to-line, line-to-ground, and double-line-to-ground faults under various system configurations
• Device evaluation: Verify that all protective devices have adequate interrupting ratings for maximum fault currents at their locations
• TCC development: Plot time-current curves for all series devices from the utility source to the most remote load, adjusting settings to achieve proper coordination margins
• Setting calculations: Document recommended relay settings with supporting calculations for every protective device
• Arc flash integration: Evaluate the impact of relay settings on incident energy levels and adjust settings to minimize arc flash hazard where possible

Common Coordination Challenges

Several factors complicate relay coordination in practice. Transformer inrush current (8-12 times rated current for 0.1 seconds) can cause upstream relays or fuses to operate during energization if not properly accounted for. Motor starting current (5-7 times rated for 5-15 seconds) must ride through downstream overcurrent protection. Ground fault coordination is challenging because ground fault current magnitudes depend on system grounding method (solidly grounded, resistance grounded, or ungrounded). Generator protection must coordinate differently when the generator is paralleled with the utility versus operating in island mode, as fault current contributions change significantly.

Relay Setting Implementation

NFM Consulting provides complete relay setting implementation services. After the coordination study, our engineers program relay settings using manufacturer-specific software (SEL AcSELerator, GE EnerVista, ABB PCM600), verify settings during relay testing with secondary injection test sets, and document as-left settings with TCC plots confirming proper coordination. We maintain a relay settings database for ongoing coordination management as the power system evolves.