Protection relays form the backbone of power system safety. Among various protection schemes, directional overcurrent and earth fault relays hold a special position in ring main systems and parallel feeder applications. These relays not only detect fault current magnitude but also identify the direction of fault power flow. This directional feature prevents false tripping and allows selective coordination between multiple protection zones.
In this technical guide, we will discuss the complete testing procedure for directional overcurrent and earth fault relays. We will use real substation data from 132/33 kV GAMPHOJOL Substation where a Siemens 7SJ6611 numerical relay is installed at BAY 101(IR1). The CT ratio is 300/1A and CVT ratio is 132kV/110V. This practical approach will help you understand each testing step clearly.
1. What is a Directional Overcurrent and Earth Fault Relay?
A directional overcurrent relay operates when the fault current exceeds a preset value and flows in a specified direction. The relay uses voltage as a polarizing quantity to determine the direction of current flow. When current flows in the forward direction (toward the protected line), the relay operates. When current flows in the reverse direction (toward the bus), the relay remains stable.
Similarly, a directional earth fault relay detects ground faults but only operates for faults in one particular direction. This feature is particularly useful in parallel feeders, ring main systems, and interconnected networks where fault current can flow from multiple sources.
The Siemens 7SJ6611 relay installed at GAMPHOJOL substation combines both overcurrent and earth fault protection with directional elements. This numerical relay offers flexibility in settings and provides accurate measurement using digital signal processing technology.
2. Why is Direction Sensing Required?
Consider a simple example. In a ring main system, two feeders connect a load from both sides of the bus. If a fault occurs on Feeder A, current will flow from both Feeder A and Feeder B toward the fault point. Without directional sensing, relays on both feeders would trip. This would cause unnecessary power interruption on Feeder B even though it has no fault.
By adding directional elements, the relay on Feeder A sees fault current in the forward direction and trips. The relay on Feeder B sees fault current in the reverse direction and remains stable. This selective operation maintains power supply continuity and improves system reliability.
3. Components Required for Directional Relay Testing
Before starting the test, gather all required equipment:
- Relay Test Kit: Use a modern three-phase relay test kit capable of injecting current and voltage simultaneously. The test kit should have phase angle control between current and voltage outputs. Popular test kits include OMICRON CMC 356, ISA DRTS, Megger SMRT, and Ponovo.
- Test Cables: Prepare current injection cables, voltage injection cables, and binary input/output cables. Check all cables for continuity before testing.
- Relay Manual and Setting Sheet: Keep the Siemens 7SJ6611 technical manual and relay setting sheet handy and obtain the approved setting sheet.
- Safety Equipment: Use insulated gloves, safety shoes, and other personal protective equipment. Follow all safety procedures before working on live panels.
- Communication Equipment: For numerical relays like 7SJ6611, a laptop with DIGSI software helps in reading settings and fault records.
4. Pre-Test Preparations
4.1 Step 1: Review Relay Settings
Every relay test begins with proper documentation. You must record all the settings before injecting any current or voltage. This serves two purposes. First, you need these values to calculate your test parameters. Second, you can verify whether the settings match the protection coordination study.
Let us look at the 7SJ6611 relay installed at GAMPHOJOL substation as our working example throughout this guide.
4.1.1 Overcurrent Settings (50/51)
The phase overcurrent function protects against short circuits between phases. For our example relay, the pickup current (I>) is set at 1.2 In. Here, In refers to the rated secondary current of 1A. The time multiplier setting (TMS) is 0.3. The relay uses the IEC Standard Inverse characteristic curve for its time-current coordination.
4.1.2 Earth Fault Settings (50N/51N)
Earth fault protection detects ground faults in the system. These settings are separate from phase overcurrent settings. The earth fault pickup (IE>) is set at 0.3 In. The time multiplier is 0.3. The characteristic curve is also IEC Standard Inverse.
Notice that the earth fault pickup is lower than the phase overcurrent pickup. This is common practice because earth fault currents are often smaller than phase fault currents.
4.1.3 Directional Settings
The directional element allows the relay to distinguish between forward and reverse faults. The characteristic angle (RCA) is set at 45° or 60° depending on system requirements. The operating region extends ±90° from this characteristic angle. The relay uses voltage polarization to determine fault direction.
4.2 Step 2: Calculate Test Values
Raw relay settings cannot be used directly for testing. You must convert them using CT and CVT ratios. This step prevents confusion between primary and secondary values.
Example Calculation
Consider the following transformer ratios:
- CT Ratio: 300/1
- CVT Ratio: 132kV/110V (which gives us 1200:1)
The pickup is set at 1.2 In. Since In equals 1A on the secondary side, the secondary pickup current is 1.2 A. To find the primary equivalent, multiply by the CT ratio. This gives us 1.2 × 300 = 360 A primary.
The test voltage should be 63.5V phase-to-neutral or 110V phase-to-phase. These are standard secondary values. The characteristic angle of 45° must be maintained during testing.
4.3 Step 3: Isolate the Bay
Safety comes before testing. You cannot inject test currents and voltages while the bay is energized. This could damage equipment or cause unwanted tripping.
For our example at GAMPHOJOL substation, isolate BAY 101(IR1) from the power system. Open all isolators and apply safety grounds. Obtain a proper work permit from the control room. Follow all switching protocols defined by your organization.
Only proceed with testing after confirming complete isolation.
5. Testing Procedure for Directional Overcurrent Relay
5.1 Test 1: Pickup Test for Phase Overcurrent Element
The pickup test confirms that the relay operates at the correct current value. A relay that picks up too early or too late will cause coordination problems with other protective devices.
5.1.1 Procedure
Start by connecting the current output of your test kit to the relay CT input terminals. Set the test kit to inject single-phase current in gradual increments.
Apply rated voltage of 63.5V to the relay voltage input. Keep this voltage at 0° angle as your reference. Now set the current angle to match the characteristic angle. This places the simulated fault in the forward direction.
Begin with zero current and slowly increase it. Watch the relay front panel carefully. Note the current value when the pickup LED illuminates or the pickup flag appears.
5.1.2 Acceptance Criteria
The measured pickup should fall within ±5% of the set value. Any deviation beyond this limit indicates a calibration problem.
5.1.3 Example from GAMPHOJOL Test
Set value: 1.2 A
Measured pickup: 1.18 A
Error calculation: (1.2 – 1.18) / 1.2 × 100 = 1.67%
Result: PASS (within ±5%)
5.2 Test 2: Operating Time Test
This test verifies how fast the relay operates at different fault current levels. The relay should follow its programmed characteristic curve.
5.2.1 Procedure
First, calculate the theoretical operating time using the standard formula. For an IEC Standard Inverse curve, the formula is:
\(t = \frac{(0.14 × TMS)}{(I^{0.02} – 1)}\)
Where t is the operating time in seconds, TMS is the time multiplier setting, and I is the multiple of pickup current.
Now inject current at 2 times, 5 times, and 10 times the pickup value. Measure the actual relay operating time for each level. Compare your measurements with the calculated values.
5.2.1 Example from GAMPHOJOL Test
Settings: I> = 1.2 A, TMS = 0.3, Curve = IEC Standard Inverse
Testing at 5 times pickup means injecting 6 A (which is 1.2 × 5).
Theoretical time = \(\frac{(0.14 × 0.3)}{{(5^{0.02} – 1)}\)
Theoretical time = 0.042 / 0.0327
Theoretical time = 1.28 seconds
Measured time: 1.25 seconds
Error: 2.3%
Result: PASS
The measured time closely matches the calculated value. This confirms proper curve implementation in the relay.
5.3 Test 3: Directional Element Test
This test carries the most weight for directional relays. It proves that the relay operates only for forward faults and blocks for reverse faults. A directional relay that operates in both directions defeats its entire purpose.
5.3.1 Procedure
Apply rated voltage of 63.5V phase-to-neutral at 0° reference angle. Inject current at 1.5 times the pickup value. This current level is enough to cause pickup if the direction is correct.
Now vary the current angle from 0° to 360° in steps of 15°. At each step, observe whether the relay picks up or remains idle. Record all observations.
Plot your results on a polar diagram. This visual representation clearly shows the forward and reverse zones.
5.3.2 Expected Results for RCA = 45°
| Current Angle | Direction | Relay Status |
|---|---|---|
| 45° | Forward | Pickup |
| 90° | Forward | Pickup |
| 135° | Boundary | Pickup |
| 180° | Reverse | No Pickup |
| 225° | Reverse | No Pickup |
| 315° | Boundary | No Pickup |
The operating zone extends ±90° from the characteristic angle. With RCA set at 45°, the relay should pick up for current angles between -45° (or 315°) and 135°. Any current angle outside this range falls in the reverse zone.
5.4 Test 4: Boundary Angle Test
The previous test used 15° steps. This test pinpoints the exact boundary angles with greater precision.
5.4.1 Procedure
Set the current at 1.5 times pickup. Keep the voltage at rated value. Start with the current angle at the characteristic angle of 45°.
Slowly increase the angle until the relay drops out. Record this angle as the positive boundary. Then return to 45° and decrease the angle until dropout occurs. Record this as the negative boundary.
5.4.2 Expected Result
For RCA = 45° with a ±90° operating zone:
- Positive boundary: 135° ± 5°
- Negative boundary: -45° (315°) ± 5°
The ±5° tolerance accounts for relay measuring accuracy and test equipment limitations.
6. Testing Procedure for Directional Earth Fault Relay
Earth fault protection works differently from phase protection. The relay monitors residual current and residual voltage instead of phase quantities. The testing approach changes accordingly.
6.1 Test 1: Earth Fault Pickup Test
6.1.1 Procedure
Connect your test kit to inject residual current (3I0) through the relay earth fault CT input. Apply residual voltage (3V0) to the voltage input. Some relays use voltage polarization while others use current polarization. Check your relay manual to confirm the correct method.
Slowly increase the residual current from zero. Note the value when the relay picks up.
6.1.2 Example from GAMPHOJOL Test
Set value: 0.3 A
Measured pickup: 0.29 A
Error: 3.3%
Result: PASS
The measured value falls within the acceptable ±5% tolerance.
6.2 Test 2: Earth Fault Operating Time Test
This test follows the same method as the phase overcurrent operating time test. The only differences are the current path and the settings used.
Inject residual current at multiple levels of the earth fault pickup. Measure the operating time at each level. Compare with calculated values using the appropriate characteristic curve formula.
Use the earth fault TMS of 0.3 and the IEC Standard Inverse curve for calculations.
6.3 Test 3: Earth Fault Directional Test
The earth fault directional element uses residual voltage (3V0) or negative sequence voltage for polarization. This differs from phase directional elements that use phase voltages.
6.3.1 Procedure
Apply residual voltage at 0° as your reference. Inject residual current at 1.5 times the earth fault pickup value. Vary the residual current angle through a full 360° rotation.
At each angle, record whether the relay picks up or not. Map the operating zone on a polar diagram. Confirm that the relay operates only for forward direction earth faults.
The boundary angles should match those specified in the relay settings. Any deviation beyond acceptable limits requires investigation and possible recalibration.
7. Conclusion
Testing of directional overcurrent and earth fault relays requires careful attention to both magnitude and angle measurements. The directional element adds complexity to the testing procedure but provides valuable protection selectivity in power systems. By following the step-by-step procedure outlined in this technical, protection engineers can verify relay performance accurately.
8. Frequently Asked Questions (FAQs)
The characteristic angle, also called Relay Characteristic Angle or Maximum Torque Angle, is the angle between voltage and current at which the relay produces maximum operating torque. For most transmission line applications, RCA is set between 30° to 60°.
The forward direction is defined as the direction from the relay location toward the protected equipment (usually the transmission line or feeder). The reverse direction is toward the bus. The relay uses voltage as a reference and compares the current angle with respect to voltage to determine direction.
If CT polarity is reversed, the relay will see forward faults as reverse and reverse faults as forward. This means the relay will not operate for actual faults on the protected line but may operate for faults behind the relay. This is a serious condition that must be corrected immediately.
Yes, numerical relays like 7SJ6611 use memory voltage to maintain directional sensing during three-phase faults. The relay stores the pre-fault voltage and uses it for directional determination for a short time (100-400 ms) after voltage collapse.
Voltage polarized relays use system voltage as the reference for determining current direction. Current polarized relays (mostly used for earth fault protection) use neutral current from a grounding transformer as reference.
The ±90° operating zone provides adequate margin for relay operation while preventing false tripping. Transmission line faults produce current angles within 30° to 85° from the characteristic angle, so ±90° zone covers all practical fault conditions with sufficient margin.