Testing of Busbar Differential Protection Relay: Stability Test, Pickup Test, Slope Test, & Breaker Failure Test

Busbar differential protection is one of the most important protection schemes in electrical substations. The busbar is a common connection point where multiple feeders, transformers, and transmission lines meet. A fault on the busbar can affect the entire substation and cause widespread outages. Testing of busbar differential protection relay is a mandatory activity during commissioning and periodic maintenance to verify that the relay will correctly isolate busbar faults while remaining stable during external faults on connected circuits.

In this technical guide, we will discuss everything you need to know about testing busbar differential protection relays. We will discuss the operating principle, test procedures, stability tests, pickup verification, slope characteristic tests, breaker failure backup tests, and real examples from actual commissioning reports.

1. What is Busbar Differential Protection Relay?

Busbar differential protection works on Kirchhoff’s current law principle. According to this law, the sum of all currents entering a node must equal the sum of all currents leaving that node. In a healthy busbar, all current flowing into the busbar through incoming feeders equals the current flowing out through outgoing feeders. The algebraic sum of all currents is zero.

When a fault occurs on the busbar, some current flows to the fault point instead of exiting through the outgoing feeders. This creates an imbalance between incoming and outgoing currents. The differential relay detects this imbalance and trips all circuit breakers connected to the faulted bus section.

Modern numerical busbar protection relays like the Siemens 7SS52 series receive current inputs from all feeders connected to the busbar. The relay continuously calculates the differential current (vector sum of all currents) and compares it with the stabilizing or bias current. When the differential current exceeds a set percentage of the bias current, the relay operates.

The busbar protection relay is designated as 87B per IEEE C37.2 standard. Some project documents and manufacturers also use the label 87BB.. It must operate very fast (typically less than one power frequency cycle) because busbar faults can cause severe damage and system instability if not cleared quickly.

2. Why Testing of Busbar Differential Protection Relay is Necessary

Testing of busbar differential protection relay serves multiple purposes in power system protection. First, it verifies that the relay correctly receives current inputs from all connected feeders. Second, it confirms that the relay remains stable during external faults and through current conditions. Third, it validates that the relay operates correctly and quickly for internal busbar faults.

During commissioning of a new substation, busbar protection testing is one of the most extensive tests performed. This is because the busbar protection receives current inputs from many CTs (sometimes 10 or more feeders) and must coordinate with all connected bays. Any wiring error, CT polarity mistake, or incorrect CT ratio matching can cause the protection to maloperate.

A false operation of busbar protection is extremely serious because it trips all breakers connected to the bus, causing a complete busbar shutdown. This results in loss of supply to all loads fed from that busbar. Conversely, failure to operate for an actual busbar fault can cause extensive equipment damage and may lead to system-wide disturbances.

3. Equipment Required for Busbar Protection Relay Testing

The testing of busbar differential protection relay requires specialized test equipment capable of multi-channel current injection. Unlike simple overcurrent relay testing, busbar protection testing needs simultaneous injection into multiple CT inputs.

The test set must be capable of producing:

• Multiple current output channels (6 to 12 channels depending on number of feeders)
• Precise control of magnitude and phase angle for each channel independently
• Synchronized injection across all channels
• High current output capability (up to 30A per channel)
• Accurate timing measurement for operating time verification
• Ability to simulate different fault conditions (internal and external)

Modern relay test sets like the OMICRON CMC 356, ISA DRTS 66 and Megger SMRT series have the capability to test busbar protection relays. The OMICRON CMC 356 provides six current channels natively in a single unit. For substations with more feeders, multiple test sets can be synchronized together using GPS or direct communication links between units. The ISA DRTS 66 and Megger SMRT similarly offer multi-channel outputs but may require synchronization of multiple units for large busbar configurations.

Additional equipment includes relay configuration software (DIGSI for Siemens relays), appropriate connecting cables for all current inputs, and communication equipment for coordination between test engineers at different bay panels.

4. Pre-Test Preparations and System Parameters

Before starting the actual busbar protection tests, engineers must verify system parameters and relay configuration. The following example uses actual data from a busbar protection relay testing project completed in 2023 to demonstrate the testing procedure and provide practical context.

4.1 Project Information (from test report example)

• Project: 132 kV GAMPHAJOL
• Bay: BB Protection Panel (1BB)
• Designation: 87BB (Busbar Differential)

4.2 Relay Information

• Relay Model: Siemens 7SS5220-6AB92-1AA0
• Auxiliary Supply: 120 V DC

4.3 Connected Bays and CT Ratios

The BU reference numbers (BU@01 through BU@05) are the internal bay unit addresses used by the relay for identification. These numbers will be referenced throughout all test procedures so it is important to verify them against the relay configuration before starting any tests.

4.4 Protection Settings

• Bus Zone Pickup: 1.2 (120% of rated current)
• Bus Zone Slope: 65%
• Check Zone Slope: 20%

5. Current Measurement Verification Test

The first step in busbar protection relay testing is verifying that the relay correctly measures currents from all connected feeders. This test confirms proper wiring connections, validates CT ratio settings, and checks phase identification for each bay.

5.1 Current Measurement Test Procedure

1. Inject 1A secondary current into each bay CT input one at a time
2. Apply three-phase balanced currents with standard phase angles (0°, 240°, 120°)
3. Observe the primary current reading on the relay display for each phase
4. Verify that displayed values match expected values based on CT ratios

5.2 Current Measurement Test Results

5.3 Analysis of Results

For LINE-1 and LINE-2 with 600/1 CT ratio, injecting 1A secondary should display 600A primary on the relay. The actual readings ranged from 592A to 596A. The maximum deviation is (600 − 592) / 600 = 1.33% and the minimum deviation is (600 − 596) / 600 = 0.67%. Both are within the acceptable measurement tolerance for numerical relays which is generally ±2%.

For TRAFO-1 and TRAFO-2 with 300/1 CT ratio, injecting 1A secondary should display 300A primary. The readings of 292A to 295A show deviations between 1.67% and 2.67%. These are within acceptable limits.

Minor variations in readings across phases and bays are normal due to CT measurement tolerances, test set output accuracy and relay analog-to-digital conversion tolerances. If you see a large deviation such as a reading showing 450A instead of 600A or a reading showing negative values, this would indicate a wiring error or incorrect CT ratio setting in the relay configuration.

6. Stability Test Procedure

The stability test is the most important test for busbar differential protection. This test verifies that the relay does not operate during normal load flow or external fault conditions when current enters the bus through one feeder and exits through another.

6.1 Stability Test Principle

During stable conditions the current flowing into the busbar equals the current flowing out. The differential current which is the vector sum should be zero or very small. The relay must not operate under these conditions.

For example consider a 132 kV busbar where 500A flows in through LINE-1 and 500A flows out through LINE-2 to supply a load. The busbar is healthy and no fault exists. The differential current is 500A − 500A = 0A. The relay should remain stable and not trip.

6.2 Stability Test Setup

Inject currents into two bay CT inputs simultaneously. The currents must be equal in magnitude but opposite in phase (180° apart) to simulate through-current flow. One current represents the incoming feeder and the other represents the outgoing feeder.

6.3 Stability Test Results – Bay 1 and Bay 2 (from actual test report)

6.4 Interpretation

The test results show that with equal and opposite currents injected at two bays the differential current (Id) is only 0.5% while the stabilizing current (Istab) is 196.8%. The very low differential current confirms that the relay correctly calculates the vector sum as near zero for through-current conditions.

The relay remained stable and did not trip. This confirms correct CT polarity connections and proper relay operation for external faults. If the CT polarity of any bay were reversed the differential current would jump to nearly 200% instead of 0.5% and the relay would trip falsely.

6.5 Additional Stability Tests

Similar stability tests are performed for all bay combinations:

6.5.1 BU@3 vs BU@5 (Transformer bays) Stability Test

6.5.2 BU@1 vs BU@4 vs BU@2 (Three bay) Stability Test

This test simulates current flowing from two sources (BU@01 and BU@04) and exiting through one feeder (BU@02).

All stability tests must pass before proceeding with other tests. If any stability test fails the test engineer must stop and investigate the cause which is usually a CT polarity error or incorrect wiring.

7. Instability (Trip) Test Procedure

The instability test verifies that the relay correctly operates for internal busbar faults. During an internal fault currents flow into the busbar from multiple sources but do not exit through any feeder because the fault is on the busbar itself. The relay should detect this condition and trip all connected breakers.

7.1 Instability Test Setup

Inject currents into two bay CT inputs simultaneously. Both currents must be in phase (same angle) to simulate fault current flowing into the bus from both sources toward the fault point.

7.2 Instability Test Results – Bay 1 and Bay 2 (from actual test report)

7.3 Interpretation

When both currents are injected in phase (simulating an internal fault) the differential current jumps to 197% while the stabilizing current is 196%.

To understand why the relay trips we need to check the trip condition against the bus zone slope setting. The relay trips when the differential current exceeds the slope percentage of the stabilizing current. With a 65% slope setting the trip threshold is:

\(\text{Trip Threshold}=0.65\times I_{stab}​=0.65×196\%=127.4\%\)

The measured differential current of 197% is well above this threshold of 127.4%. The relay therefore correctly identifies this as an internal fault and issues a trip command.

7.4 Additional Instability Tests

7.4.1 BU@3 vs BU@5 Instability Test:

7.4.2 BU@01 vs BU@04 vs BU@02 Instability Test

This test simulates a busbar fault with all three sources feeding into the fault.

8. Bus Zone Pickup Test

The pickup test verifies that the relay operates at the correct current threshold. The bus zone pickup setting determines the minimum differential current required for relay operation.

8.1 Pickup Calculation

For the test report example:

Bus Zone Pickup Setting: 1.2 (120% of CT secondary rated current)

CT Secondary Rated Current: 1 A

Expected Tripping Current = Pickup Setting × CT Secondary Rated Current = 1.2 × 1 = 1.2 A secondary

The pickup setting of 1.2 means the relay will operate when the differential current at the CT secondary exceeds 1.2 times the rated secondary current.

8.2 LINE 1 Side Pickup Test Results

Current was injected only into BU@01 with no current at BU@02. This creates a pure differential current with no through-current component.

8.3 LINE 2 Side Pickup Test Results

8.4 Analysis

The relay trips at 1.22A which is very close to the expected pickup of 1.2A. The deviation of 0.02A (1.7%) is within normal relay measurement tolerance. The operating times of 42–46 ms confirm fast operation of busbar protection. These times include the relay internal measuring time, output relay mechanical operation time and the test set measurement latency.

8.5 Pickup Test with CT Ratio Matching Factor

In substations where different bays have different CT ratios, the busbar protection relay uses a CT ratio matching factor to normalize all current inputs to a common base. This ensures that the differential calculation correctly compares currents from bays with different CT ratios.

In our example, the line bays (LINE-1 and LINE-2) have CT ratios of 600/1 A while the transformer bays (TRAFO-1 and TRAFO-2) have CT ratios of 300/1 A. The relay uses the highest CT ratio (600/1) as the normalizing base. For transformer bays with 300/1 CT ratio, the matching factor compensates for the ratio difference.

8.5.1 CT Ratio Matching Factor Calculation

\(\text{Matching Factor (MF)}=\frac{\text{Normalizing CT Ratio}}{\text{Bay CT Ratio}}=\frac{600}{300}​=2\)

This matching factor of 2 means that for every 1A of secondary current measured at a transformer bay CT, the relay internally multiplies it by 2 to normalize it against the 600/1 base. This normalization is essential because without it, equal primary currents flowing through bays with different CT ratios would produce different secondary values, creating a false differential current.

8.5.2 Expected Tripping Current Calculation

For the line bays with 600/1 CT ratio and matching factor of 1:

\(I_{trip}​=\text{Pickup Setting}\times \text{MF}\times I_{rated(secondary)}​=1.2\times 1 \times 1=1.2 A\)

For the transformer bays with 300/1 CT ratio and matching factor of 2:

\(I_{trip}​=\text{Pickup Setting}\times \text{MF}\times I_{rated(secondary)}​=1.2\times 2 \times 1=2.4 A\)

The transformer bays require twice the secondary injection current compared to the line bays. This is because the 300/1 CT produces twice the secondary current per ampere of primary current compared to the 600/1 CT. The higher injection requirement at the secondary side ensures that the relay sees the same normalized primary current level at its pickup threshold regardless of the CT ratio.

8.5.3 TRAFO-1 Side Pickup Test Results

Current was injected into the TRAFO-1 bay (BU@03) CT input while the TRAFO-2 bay (BU@05) received no injection. This simulates a busbar fault fed from the TRAFO-1 source only.

8.5.4 TRAFO-2 Side Pickup Test Results

Current was injected into the TRAFO-2 bay (BU@05) CT input while the TRAFO-1 bay (BU@03) received no injection. This confirms correct pickup operation from the opposite transformer bay.

9. Slope Test Procedure

The slope characteristic provides security against false operation during external faults with CT saturation. The busbar protection relay uses a percentage restraint characteristic where the pickup threshold increases with increasing through current.

9.1 Bus Zone Slope Test (65% Setting)

The bus zone slope is set to 65%. This means the relay operates when the differential current exceeds 65% of the stabilizing current. As the through-current increases the relay demands a proportionally higher differential current before it will trip. This prevents false tripping when one CT saturates during a heavy external fault and creates an artificial imbalance.

9.2 Slope Test Procedure

1. Inject unbalanced currents at two bays (one higher than the other)
2. Increase one side current until the relay trips
3. Record Id and Istab values at the trip point
4. Calculate slope = Id / Istab

9.3 Bus Zone Slope Test Results

9.4 Slope Calculation

\(\text{Slope} = \frac{I_d}{I_{stab}}\)
\(= \frac{363.9}{559.7}\)
\(= 0.650\)
\(= 65\%\)

The operated slope of 65% matches the set value, confirming correct operation of the bus zone slope characteristic.

10. Check Zone Slope Test

The check zone provides an additional security layer for busbar protection. It covers the entire busbar and must agree with the bus zone before the relay issues a trip command. This two-out-of-two logic prevents tripping due to CT failures or wiring errors in a single bay.

The check zone produces an alarm condition rather than a direct trip. The relay will only issue a trip command when both the bus zone AND the check zone detect a fault simultaneously. This is why the test results in this section show “ALARM” status instead of “TRIP.” If only the check zone sees a fault but the bus zone does not then the relay raises an alarm but does not trip. This design adds an extra layer of security against false operations.

10.1 Check Zone Slope Test (20% Setting)

For check zone testing, higher currents are injected to verify the second slope region.

Check Zone Current = Pickup Setting / Check Zone Setting = 1.2 / 0.2 = 6 times rated

10.2 Check Zone Slope Test Results

10.3 Slope Calculation

The check zone slope formula differs from the bus zone formula. The Siemens 7SS52 relay uses a modified slope calculation for the check zone where the stabilizing current is adjusted by subtracting the differential component and dividing by 2. This is specific to the relay’s internal algorithm and is documented in the Siemens 7SS52 technical manual.

\(\text{Slope} = \frac{I_d}{\dfrac{(I_{stab} – I_d)}{2}}\)
\(= \frac{19.31}{\dfrac{194.1 – 19.31}{2}}\)
\(= \frac{19.31}{87.4}\)
\(= 22\%\)

The measured check zone slope of 22.1% compared to the setting of 20% gives a deviation of about 2.1 percentage points. This is within the acceptable relay tolerance which is ±5% for numerical relays. For practical purposes a measurement within ±2–3% of the setting is considered a passing result.

11. Multi-Bay Stability and Instability Tests

For complete busbar protection verification stability and instability tests must be performed for various bay combinations. These tests represent different operating scenarios that may occur in actual service.

11.1 BU@01 vs BU@04 vs BU@02 Stability Test

This test simulates current flowing from two sources (BU01 and BU04) and exiting through one feeder (BU02).

11.2 BU@1 vs BU@4 vs BU@2 Instability Test

This test simulates a busbar fault with all sources feeding into the fault.

12. Local Breaker Backup (Breaker Failure) Test

Busbar protection relays include a breaker failure backup function. If a circuit breaker fails to open after receiving a trip command, the breaker failure function trips adjacent breakers to isolate the fault.

For example if LINE-1 breaker receives a trip command but mechanically fails to open then current continues to flow through it. The breaker failure function detects that current is still flowing after the trip command and sends trip commands to all other breakers connected to the same bus section.

12.1 Breaker Failure Settings

• Pickup Current: 0.2 A
• Re-trip Timer: 100 ms
• Bus Trip Timer: 500 ms

12.2 Breaker Failure Test Procedure

1. Inject fault current into a bay CT input above the pickup setting
2. Issue trip command to the bay breaker
3. Maintain current injection (simulating breaker failure to open)
4. Verify re-trip operation at the set time
5. Verify bus trip operation at the set time

12.3 Breaker Failure Test Results (from actual test report)

13. Additional Functional Tests

Several other tests are performed to verify complete relay functionality:

• Check of LED Indicators: All front panel LED indicators are to be tested to verify they illuminate correctly for different alarm and trip conditions including differential trip, breaker failure, and zone indications.
• Check of Trip Relays: Trip output contacts for each bay are to be tested to verify proper operation when tripping conditions are met. Each bay should receive trip signal only when its zone is involved in the fault.
• Check of Signal Output Relays: Alarm and indication output relays are to be verified for correct operation including busbar trip alarm, breaker failure alarm, and protection operated signals.
• Check of Binary Inputs: All digital inputs for breaker status, isolator status, and zone selection are to be tested. The busbar protection uses these inputs to determine which bays are connected to the bus.
• Alarm and Trip Functions: The complete logic from fault detection to output operation is to be verified.

14. Conclusion

Testing of busbar differential protection relay is one of the most complex and extensive tests performed during substation commissioning. The test procedures covered in this guide show how systematic testing verifies relay performance for stability during external faults and correct operation for internal busbar faults.

The real commissioning test results presented in this article show that modern numerical busbar protection relays like the Siemens 7SS52 operate with high accuracy and fast operating times. Stability tests with differential current as low as 0.4-0.9% confirm correct CT polarity and relay operation. Operating times of 24-46 ms for pickup tests confirm fast fault clearance capability.

The multiple test categories including stability tests, instability tests, pickup tests, slope tests, and breaker failure tests together verify complete protection functionality. Each test category addresses specific aspects of busbar protection operation and all must pass before the relay is considered ready for service.

15. Frequently Asked Questions (FAQs)