Directional Overcurrent Protection Relay ANSI 67: Operating Principle, Applications and Setting Calculation

• A directional overcurrent protection relay combines an overcurrent element with a directional element. Protection operates when the measured current exceeds its pickup setting, the fault is identified in the configured operating direction, and the applicable operating time has elapsed. Phase directional overcurrent protection is designated ANSI 67. Directional protection for earth faults may be designated ANSI 67N or 67G; the function name, measured current and polarising quantity must be confirmed from the relay manufacturer’s documentation.
• The forward direction must be defined for each installation. It depends on the relay location, current transformer (CT) polarity, voltage transformer (VT) connections and relay settings. Directional elements help maintain selectivity in networks with multiple sources; selective fault clearance also requires appropriate current and time coordination.

1. Operating Principle

1.1 Overcurrent and directional elements

• The overcurrent element determines whether the measured current exceeds its pickup setting. The directional element compares the phase relationship between a measured current and a polarising quantity to determine whether the fault is forward or reverse. The relay trips only when the applicable current, direction and timing conditions are satisfied.
• For example, the directional element associated with A-phase current may use quadrature voltage polarisation: it compares ​\( I_A \)​ with the B–C line-to-line voltage ​\( V_{BC} \)​. This describes the A-phase element and its polarising connection; it does not mean that the element is limited to phase-to-phase faults. Its performance must still be verified for the relevant fault types and voltage conditions. 
• Numerical relays may use different polarising methods. Phase directional elements can use quadrature voltage or positive-sequence voltage, including memorised prefault positive-sequence voltage. Directional earth-fault elements may use zero-sequence or negative-sequence quantities. The appropriate polarising method depends on the relay design, VT connections and system earthing arrangement.

1.2 Directional operation during severe voltage depression

• A close-in three-phase fault may cause severe voltage depression, affecting direction determination by a voltage-polarised element. Some numerical relays use positive-sequence memory voltage to improve directional performance during such faults. Its availability and duration depend on the relay design and settings; it must not be assumed to eliminate every directional dead zone.

1.3 Trip logic

For a forward-looking directional overcurrent element:

• Forward fault: The directional overcurrent element can operate when current exceeds pickup and the timing conditions are satisfied.
• Reverse fault: The directional criterion blocks the forward-looking directional overcurrent element.
• Direction cannot be determined: The response depends on the relay’s polarising thresholds and supervision logic. It must be checked in the model-specific docum

2. Functions and Applications

2.1 Selective fault clearance in networks with multiple sources

• In double-ended supply systems, ring networks and parallel feeders, relays at several locations may detect the same fault. Directional elements restrict operation to their configured fault directions. Together with current and time coordination, they help isolate the faulted section and limit the area disconnected.

2.2 Protection with distributed energy resources

• Photovoltaic generation, battery energy storage and other distributed energy resources may supply fault current from multiple directions. Directional overcurrent protection helps distinguish forward from reverse faults. Sensitivity and coordination must also be checked across operating conditions because the magnitude and duration of inverter-supplied fault current may vary.

2.3 Primary and backup protection

• Directional overcurrent protection may serve as primary protection on suitable distribution feeders or as backup protection alongside other line protection functions. Its role depends on the network configuration, available fault current, required clearing time and overall protection scheme.
• Typical applications include double-ended feeders, ring networks, parallel feeders, distribution networks with distributed generation, and microgrids with bidirectional fault-current paths.

GoWatron line protection relays

• Both the GWPR200-L Line Protection Relay and GWPR300-L Line Protection Relay provide directional overcurrent protection. Contact GoWatron with your network configuration and protection requirements to discuss the appropriate model, protection settings and quotation.

3. Information Required Before Setting the Relay

• A reliable setting study requires more than the feeder’s rated current. Establish:
• Network configuration and operating conditions, including normal, maintenance, open-ring and source-transfer arrangements.
• CT and VT data, including ratios, polarity, connections and whether relay settings are expressed as primary or secondary values.
• Load conditions, including maximum continuous load, motor restarting and temporary load transfers.
• Fault-study results, including maximum and minimum current flowing through the relay for the relevant faults and operating conditions.
• Adjacent protection settings, including operating directions, pickup values, curve types, operating times and circuit-breaker clearing times.
• Directional-element characteristics, including the polarising quantity, characteristic angle, minimum polarising-voltage threshold, the definition of forward and reverse directions, and the response when direction cannot be determined.

Phase directional overcurrent protection (67) and directional protection for earth faults (67N/67G, as identified by the manufacturer) require separate setting studies. Their measured quantities, polarising methods and sensitivity criteria must be confirmed for the specific relay.

4. Pickup-Current Setting

4.1 Check against maximum load

For a definite-time phase directional overcurrent element, pickup must be set above the maximum continuous current that the relay may measure. Allow for measurement error, reset characteristics and an appropriate operating margin.

Where the adopted setting method uses a reset ratio, the load check may be expressed as:
​\( I_{\mathrm{pickup}}\geq \frac{K_{\mathrm{rel}}}{K_r}I_{\mathrm{load,max}} \)​

where:

• \( I_{\mathrm{pickup}} \)​ is the phase overcurrent pickup current;
• ​\( I_{\mathrm{load,max}} \)​ is the maximum load current, taking account of relevant operating conditions;
• ​\( K_{\mathrm{rel}} \)​is the reliability factor adopted for the setting study;
• ​\( K_r \)​ is the reset ratio applicable to the relay.

This expression applies only where its assumptions match the relay and setting method. It is not a universal formula for numerical relays. Use the actual relay’s pickup and reset characteristics. Short-duration conditions, such as motor restarting, must also be checked against the selected operating delay or inverse-time characteristic.

4.2 Verify sensitivity at minimum fault current

After selecting a provisional pickup value, verify that the relay detects faults throughout its required protection reach. A basic sensitivity ratio is:

\[ K_{\mathrm{sen}}= \frac{I_{\mathrm{fault,min}}}{I_{\mathrm{pickup}}} \]

• \( I_{\mathrm{fault,min}} \)​must be the minimum fault current flowing through that relay for the relevant fault location, fault type and operating condition. The required sensitivity ratio depends on the project criteria and the element’s protection duty.
• If the pickup required to remain stable under load is too high to detect the required minimum fault, changing the operating delay alone will not restore sensitivity. The protection arrangement must be reassessed.

4.3 Coordinate with adjacent protection

• Pickup values do not necessarily have to increase by a fixed factor from downstream to upstream relays. Coordination must reflect the actual fault-current paths. Determine which elements pick up for each relevant fault, then compare their operating times.
• For inverse-time protection, verify the selected curves across the relevant fault-current range. The principal settings generally include pickup current, curve type and the time multiplier or time-dial setting (TDS), according to the relay’s terminology. Definite-time protection instead uses a specified operating delay. 
• The pickup setting for directional earth-fault overcurrent protection must be determined separately, using the current quantity measured by that element and the characteristics of the system earthing arrangement. Phase load current and the residual current \(3I_0\) must not be added as scalar values to produce a general pickup-setting formula for phase directional overcurrent protection.

5. Operating-Time Setting

5.1 Definite-time elements

Where two definite-time elements require time grading for the same fault direction, the upstream delay may be checked using:

\[ t_{\mathrm{up}}\geq t_{\mathrm{down}}+\Delta t \]

The grading margin ​\( \Delta t \)​ must account for downstream circuit-breaker clearing time, relay timing tolerances and an appropriate coordination margin. A value of 0.3–0.5 s may be an initial reference for some conventional schemes, but the required margin must be calculated for the actual installation.

5.2 Inverse-time elements

• An inverse-time element operates faster as measured current increases, according to its selected characteristic. Select the curve type, pickup and time multiplier, then verify the required separation between operating times at relevant fault locations under maximum and minimum operating conditions. A comparison at only one fault-current value does not establish coordination across the full current range.
• Where a relay provides separate forward and reverse elements, establish the coordination sequence for each assigned protection duty. Verify both sequences when changes in network configuration may alter fault-current paths.

6. Directional-Element Settings and Verification

• Directional-element settings may include the definition of forward and reverse directions, the polarising method, the characteristic angle and the minimum polarising-voltage threshold. The terms characteristic angle and maximum sensitivity angle must be interpreted according to the specific relay’s definitions; they should not be treated as interchangeable across relay designs. The angle reference, sign convention and setting range must be checked in the relay manual.
• After calculating the settings, verify CT and VT connections, polarity and phase sequence. Test the expected response to simulated forward and reverse faults. Where severe voltage depression is possible, also verify memory-voltage operation and undervoltage supervision in accordance with the relay documentation.

7. Illustrative Pickup Calculation

The following example demonstrates a basic load and sensitivity check for a definite-time phase directional overcurrent element. It is not a complete feeder setting study.

Assume:

• Maximum continuous current through the relay: ​\( I_{\mathrm{load,max}}=400\ \mathrm{A} \)​;
• Reliability factor: ​\( K_{\mathrm{rel}}=1.15 \)​;
•  Reset ratio used by the assumed setting method: ​\( K_r=0.90 \)​;
• Minimum phase-to-phase fault current at the required protection reach: ​\( I_{\mathrm{fault,min}}=1{,}200\ \mathrm{A} \)​.

The load check gives:

\[ I_{\mathrm{pickup}}\geq \frac{1.15}{0.90}\times400 \approx511\ \mathrm{A} \]

If a provisional primary pickup setting of 520 A is available, the illustrative sensitivity ratio is:

\[ K_{\mathrm{sen}}= \frac{1{,}200}{520} \approx2.31 \]

The overcurrent element would pick up under the assumed minimum-fault condition. Before adopting 520 A, verify the actual relay characteristics, CT ratio, temporary load conditions, other relevant fault types, coordination with adjacent protection and the project’s sensitivity requirements. The operating time requires a separate calculation.

Conclusion

• Setting a directional overcurrent protection relay involves establishing the operating direction, selecting pickup, verifying sensitivity at minimum fault current, coordinating operating times, and testing the directional logic and site connections. Phase directional overcurrent protection (67) and directional protection for earth faults (67N/67G, according to the relay’s function definitions) must be studied separately. Final settings must reflect the specific network, relay model and approved protection criteria.