Common Mistakes When Upgrading Protection Schemes

Introduction

Protection scheme upgrades in medium voltage substations are among the most technically demanding commissioning activities in power system engineering — and among the most frequently executed incorrectly. The relay is replaced, the settings are recalculated, the commissioning test is passed, and the substation is returned to service. Three months later, a fault occurs and the protection fails to operate correctly. The investigation reveals that the relay was perfectly specified and correctly set — but the current transformers feeding it were never re-evaluated for compatibility with the new protection scheme, and the measurement errors that caused the protection failure were present from the first day of the upgraded scheme’s operation.

The direct answer is this: the most common and most consequential mistakes in protection scheme upgrades are not relay setting errors — they are CT measurement errors that occur because engineers treat the existing CT installation as a fixed, verified input to the new protection scheme rather than as a component that must be re-evaluated, re-tested, and re-confirmed against the new relay’s measurement requirements, burden characteristics, and transient performance demands, which are almost always different from those of the relay being replaced.

For substation protection engineers, medium voltage upgrade project managers, and safety-critical commissioning teams responsible for protection scheme upgrades, this guide identifies every significant CT measurement mistake that occurs during protection scheme upgrades — and provides the engineering methodology to prevent each one.

Table of Contents

• Why Do Existing CTs Become Incompatible When Protection Schemes Are Upgraded?
• What Are the Most Dangerous CT Measurement Mistakes During Protection Scheme Upgrades?
• How to Correctly Re-Evaluate CT Specifications for Medium Voltage Protection Scheme Upgrades?
• How to Execute Safe CT Measurement Verification During Live Protection Scheme Upgrade Projects?
• FAQs About CT Measurement Mistakes in Protection Scheme Upgrades

Why Do Existing CTs Become Incompatible When Protection Schemes Are Upgraded?

The assumption that existing CTs remain fully compatible with a new protection relay is the foundational error of most protection scheme upgrade projects. It appears reasonable — the CT ratio has not changed, the primary current has not changed, and the CT passed its last maintenance test. What has changed is the relay — and the relay defines the measurement environment that the CT must operate in.

Every protection relay presents a specific burden to the CT secondary circuit. Every protection relay has specific transient performance requirements that determine the CT accuracy limiting factor (ALF) needed for correct operation during fault conditions. Every protection relay has a specific measurement algorithm — RMS, fundamental frequency phasor, or peak detection — that interacts differently with CT secondary waveform distortion. When the relay changes, all three of these parameters change simultaneously — and the existing CT may satisfy none of them.

Key technical parameters that change when a protection relay is replaced:

• Secondary burden (VA)¹: Modern numerical protection relays present burdens of 0.025–0.1 VA at 1 A secondary — ten to forty times lower than the 1–5 VA burden of the electromechanical relays they replace; this dramatic burden reduction changes the CT’s operating point on its excitation curve and can cause unexpected CT behavior during fault conditions
• Accuracy Limiting Factor (ALF)² requirement: The new relay’s transient performance specification defines the minimum CT ALF required for correct operation during maximum fault current; if the existing CT’s ALF at the new relay’s burden is lower than required, the CT will saturate before the relay can make a correct protection decision
• Effective ALF at new burden: ALF_effective = ALF_rated × (Rct + Rburden_rated) / (Rct + Rburden_actual); reducing the relay burden from 5 VA to 0.1 VA dramatically increases the effective ALF — which sounds beneficial but can cause the CT to operate in an unexpected region of its excitation characteristic
• Measurement algorithm compatibility: Electromechanical relays respond to the RMS of the secondary current waveform including all harmonics and DC offset; numerical relays extract the fundamental frequency phasor using Fourier filtering — the CT’s secondary waveform during fault conditions must be compatible with the relay’s specific filtering algorithm
• Applicable standards: IEC 61869-2³ (CT accuracy and ALF), IEC 60255-151 (overcurrent protection relay requirements), transformer differential protection⁴ requirements (IEC 60255-187-1)

The effective ALF calculation reveals a critical and counterintuitive consequence of replacing high-burden electromechanical relays with low-burden numerical relays:

$ALF_{effective} = ALF_{rated} \times \frac{R_{CT} + R_{burden,rated}}{R_{CT} + R_{burden,actual}}$

For a CT rated 5P20 with Rct = 2 Ω and rated burden = 15 VA (15 Ω at 1 A):

• With original electromechanical relay at 5 VA (5 Ω): ALF_effective = 20 × (2+15)/(2+5) = 48.6
• With new numerical relay at 0.1 VA (0.1 Ω): ALF_effective = 20 × (2+15)/(2+0.1) = 161.9

The CT that was operating at ALF 48.6 with the old relay is now operating at ALF 161.9 with the new relay — far above the knee-point of its excitation curve during fault conditions, in a region where the CT’s transient behavior is unpredictable and where the secondary waveform may contain significant distortion that the numerical relay’s Fourier filter cannot correctly process.

What Are the Most Dangerous CT Measurement Mistakes During Protection Scheme Upgrades?

Protection scheme upgrade CT measurement mistakes fall into two categories: specification mistakes made during the design phase that create incompatibility before installation begins, and commissioning mistakes made during the upgrade execution that introduce errors into an otherwise correctly specified system.

Specification Mistake 1: Accepting Existing CT Without Re-Evaluating ALF at New Burden

The most common and most dangerous specification mistake. The protection engineer specifies the new relay, calculates the new relay settings, and notes that the existing CT ratio is unchanged — then accepts the existing CT without recalculating its effective ALF at the new relay’s burden.

The consequence: the CT operates at a dramatically different point on its excitation characteristic with the new relay than it did with the old relay. In the low-burden numerical relay case described above, the CT may operate so far above its knee-point during fault conditions that the secondary current waveform is severely distorted — containing large DC offset components and harmonic content that the numerical relay’s Fourier filter cannot extract the fundamental phasor from correctly. The relay either fails to operate, operates with incorrect timing, or operates on the distorted waveform component rather than the fundamental frequency fault current.

Specification Mistake 2: Mismatching CT Cores Between Protection Functions

Medium voltage CTs typically contain multiple cores — separate cores for protection and measurement functions, and sometimes separate cores for different protection functions. During a protection scheme upgrade, it is common to reassign CT cores — using a core previously dedicated to overcurrent protection for the new differential protection function, for example.

The core reassignment mistake: differential protection requires matched CT cores with identical ratio errors and phase displacements on both sides of the protected equipment. Using a core previously optimized for overcurrent protection — with a higher ALF and different excitation characteristic — on one side of a differential scheme while using a standard measurement core on the other side creates a permanent differential current under normal load conditions that the relay must either restrain against or misinterpret as an internal fault.

Specification Mistake 3: Ignoring CT Remanence History During Upgrade

A CT that has been in service for several years in a substation with a history of fault events has accumulated remanent flux in its core. The remanent flux shifts the CT’s operating point on its B-H curve — increasing magnetizing current, increasing ratio error, and reducing the effective ALF below the nameplate value.

During a protection scheme upgrade, the existing CT’s remanent flux condition is never assessed — because the standard commissioning procedure for a relay replacement does not include CT demagnetization and ratio accuracy verification. The new relay is commissioned against a CT that may be operating at 60–70% of its nameplate ALF due to accumulated remanence — a condition that will cause the CT to saturate earlier than the new relay’s protection algorithm expects.

Specification Mistake 4: Incorrect Secondary Burden Calculation for New Cable Routing

Protection scheme upgrades frequently involve relocating the protection relay — from a local panel adjacent to the switchgear to a centralized protection panel in a remote control room, or from a panel-mounted relay to a rack-mounted numerical relay with different terminal locations. Each relocation changes the secondary cable length and therefore the secondary circuit resistance — which changes the total secondary burden and therefore the effective ALF.

Comparison: CT Measurement Mistakes by Consequence Severity

Mistake Type	Detection Method	Consequence if Undetected	Severity
ALF not recalculated at new burden	Excitation curve analysis	CT saturation during fault — protection failure	Critical
Core reassignment for differential	Primary injection5 balance test	Permanent differential current — misoperation	Critical
Remanence not assessed	Ratio test + demagnetization	Reduced effective ALF — delayed operation	High
Burden not recalculated for new cable	Secondary burden measurement	ALF reduction — saturation at lower fault current	High
Polarity not re-verified after upgrade	Primary injection polarity test	Directional relay failure — incorrect trip decision	Critical
CT ratio not confirmed after tap change	Ratio measurement	Over/under-current setting error — incorrect pickup	High

Customer Case — 33 kV Medium Voltage Substation Upgrade, Cement Plant, North Africa:
A protection engineer at a cement plant contacted Bepto Electric after a busbar fault caused catastrophic damage to a 33 kV switchboard — damage that should have been limited by the busbar protection relay that had been installed as part of a protection scheme upgrade six months earlier. Post-fault investigation revealed that the busbar protection relay had failed to operate during the fault. The upgrade project had replaced the original electromechanical overcurrent relays with a modern numerical busbar protection relay — but had not recalculated the effective ALF of the existing CTs at the new relay’s burden of 0.08 VA. The existing CTs, rated 5P20 with Rct of 3 Ω, had an effective ALF of 187 at the new relay’s burden — far above the knee-point. During the busbar fault, the CT secondary waveform was severely distorted with large DC offset components that the numerical relay’s Fourier filter could not process within its operating time window. The relay failed to extract a valid fundamental frequency phasor before its internal watchdog timer reset the measurement cycle. CT replacement with units specified for low-burden numerical relay applications — with a controlled ALF of 30 at the actual secondary burden — resolved the protection failure. The protection engineer stated: “We upgraded the relay to the most modern technology available and ended up with worse protection performance than the electromechanical relays we replaced. The CT was the problem, and we never looked at it because the ratio hadn’t changed.”

How to Correctly Re-Evaluate CT Specifications for Medium Voltage Protection Scheme Upgrades?

Correct CT re-evaluation for protection scheme upgrades requires a structured four-step methodology that treats the existing CT as an unverified component until proven compatible with the new protection scheme.

Step 1: Define New Relay Measurement Requirements

Before evaluating the existing CT, fully characterize the new relay’s CT interface requirements:

• Secondary burden at rated current: Obtain from relay manufacturer’s technical specification — not the relay’s rated burden, but the actual input impedance at the CT secondary current rating; modern numerical relays present 0.025–0.1 VA at 1 A, not the 1–5 VA stated as rated burden
• Required CT accuracy class: Confirm whether the new relay requires Class P (5P or 10P) or Class PX (defined by knee-point voltage and magnetizing current) CTs — many modern differential and distance protection relays specify Class PX requirements that existing Class P CTs may not satisfy
• Transient dimensioning factor (Ktd): For relays with specified transient performance requirements, obtain the required Ktd from the relay specification — this defines the minimum CT transient capability required for correct relay operation during the first few cycles of fault current
• Measurement algorithm: Confirm whether the relay uses RMS measurement, fundamental frequency phasor extraction, or peak detection — each algorithm has different sensitivity to CT secondary waveform distortion during fault conditions

Step 2: Recalculate Effective ALF at New Secondary Burden

Apply the effective ALF formula for each existing CT in the upgraded protection scheme:

$ALF_{effective} = ALF_{rated} \times \frac{R_{CT} + R_{burden,rated}}{R_{CT} + R_{burden,actual}}$

Where:

• $R_{burden,actual}$ = relay input impedance + secondary cable resistance (both conductors) + any other series impedance in the secondary circuit
• Compare ALF_effective against the new relay’s required ALF — if ALF_effective exceeds the required value by more than 3×, the CT may operate in an unpredictable region during fault conditions; if ALF_effective is below the required value, the CT will saturate before the relay can make a correct protection decision

Step 3: Verify CT Core Assignment for Each Protection Function

• Map existing CT cores to new protection functions: Document which physical CT core is connected to each protection relay input in the upgraded scheme
• Verify core accuracy class matches protection function: Protection cores (5P, 10P, Class PX) for protection relays; measurement cores (Class 0.5, Class 1) for revenue metering — never use a measurement core for a protection function in an upgraded scheme
• Verify differential CT core matching: For transformer or busbar differential protection, confirm that the CT cores on both sides of the protected equipment have matched ratio errors and phase displacements — obtain factory test certificates for both CTs and compare

Step 4: Assess CT Condition and Remanence Status

• Review fault event history: Obtain protection relay event records for the previous 3–5 years; identify all fault events where the CT primary current exceeded 50% of rated short-time current — each such event is a potential remanence accumulation event
• Perform excitation curve test: Compare measured excitation curve against factory test certificate; a shifted knee-point or increased magnetizing current at the knee-point confirms remanent flux accumulation
• Perform demagnetization if remanence confirmed: Demagnetize before ratio accuracy verification — ratio test results on a remanence-affected CT are not representative of the CT’s true accuracy class performance
• Perform ratio accuracy verification post-demagnetization: Confirm ratio error and phase displacement are within accuracy class limits before accepting the CT for the upgraded protection scheme

Application Scenarios

• Electromechanical to Numerical Overcurrent Relay Upgrade: Recalculate effective ALF at new relay burden; verify ALF_effective is within 2–5× required ALF; assess remanence history; primary injection polarity re-verification mandatory
• Adding Transformer Differential Protection to Existing CT Installation: Verify CT core class PX compatibility; perform differential circuit balance primary injection test; confirm matched ratio errors on HV and LV CT pairs
• Distance Protection Upgrade on Transmission Feeder: Verify Class PX knee-point voltage against relay specification; recalculate secondary burden including new cable routing to remote relay panel; confirm Ktd compliance
• Busbar Protection Addition: Verify all busbar CT cores have matched characteristics; calculate stability factor for through-fault conditions; primary injection stability verification mandatory before energization

How to Execute Safe CT Measurement Verification During Live Protection Scheme Upgrade Projects?

Safe CT Measurement Verification Steps

1. Short CT secondary circuits before any relay disconnection: Before disconnecting any CT secondary circuit from the existing relay, apply shorting links at the CT secondary terminals or at the test terminal block — CT secondary open-circuit under primary current creates lethal high voltage; shorting must precede any relay terminal disconnection
2. Verify shorting link integrity under load: After applying shorting links, confirm secondary current is flowing through the shorting link using a clamp ammeter — a shorting link that appears connected but has a loose contact is a latent open-circuit hazard
3. Perform ratio and polarity verification before relay connection: With the new relay installed but not yet connected to the CT secondary circuit, perform primary injection ratio and polarity verification — confirm the CT is delivering the correct secondary current in the correct direction before connecting to the new relay
4. Verify secondary burden with new relay connected: Measure total secondary circuit burden with the new relay connected; compare against CT rated burden; confirm effective ALF calculation is consistent with measured burden
5. Perform functional protection test before removing shorting links: With the new relay connected and the CT secondary circuit complete, perform secondary injection functional test of the relay — confirm correct operation, correct timing, and correct output contact operation before removing the primary circuit shorting links and returning to service

Common Safety Mistakes During Protection Scheme Upgrades

• Removing CT secondary shorting links before relay reconnection is complete: The most dangerous commissioning mistake — even a brief period with the CT secondary open-circuited while primary current is flowing creates a high-voltage hazard at the open terminal; maintain shorting links until the complete secondary circuit is verified as continuous
• Performing secondary injection test without verifying CT secondary circuit continuity: Secondary injection tests the relay in isolation — it provides no information about CT secondary circuit integrity; a secondary injection pass result does not authorize removal of CT secondary shorting links without primary injection verification
• Omitting polarity re-verification after protection scheme upgrade: Any modification to the CT secondary circuit — new cable, new terminal block, new relay terminal assignment — creates the possibility of polarity reversal; polarity must be re-verified by primary injection after every protection scheme modification, not assumed from the previous commissioning record
• Energizing the upgraded protection scheme without a staged fault test: Where network operating conditions permit, a staged fault test — deliberately creating a fault condition on the protected circuit under controlled conditions — is the only method that verifies the complete protection scheme including CT performance under actual fault current conditions

Conclusion

Protection scheme upgrades create CT measurement incompatibilities that are invisible to relay testing, invisible to standard commissioning procedures, and invisible to nameplate inspection — but fully visible to the protection system’s failure to operate correctly when the substation experiences its first real fault after the upgrade. The mistakes that cause these failures are consistent, predictable, and entirely preventable: failure to recalculate effective ALF at the new relay’s burden, failure to re-evaluate CT core assignments for new protection functions, failure to assess and correct CT remanence accumulated during years of service, and failure to re-verify polarity and ratio accuracy after secondary circuit modifications. In medium voltage protection scheme upgrades, the CT is not a passive component that can be inherited from the previous scheme without re-evaluation — it is an active measurement device whose compatibility with the new relay must be proven by calculation, by test, and by primary injection verification before the upgraded protection scheme is trusted to protect the substation and the personnel working in it.

FAQs About CT Measurement Mistakes in Protection Scheme Upgrades

1. Detailed analysis of total resistance in protection secondary circuits. ↩

2. Technical parameters defining CT performance during fault conditions. ↩

3. Official international standard for current transformer accuracy and performance. ↩

4. Comprehensive guide to matching CT cores for differential schemes. ↩

5. Industrial safety standards for verifying protection scheme integrity. ↩