Transformer Protection Relay Coordination Guide: Differential, Overcurrent, REF & Buchholz Settings

# Transformer Protection Relay Coordination Guide: Differential, Overcurrent, REF & Buchholz Settings

Introduction

A power transformer is the single most expensive piece of equipment in most substations. When it fails, the consequences cascade: weeks to months of downtime, six-figure replacement costs, production losses, and — in the worst case — injury or fatality. Protection relays are not optional; they are a contractual and regulatory requirement under IEC 60076 and IEEE C37.91.

This guide presents a methodical approach to transformer protection relay coordination. It covers the five essential protection functions every transformer above 1 MVA must have, provides worked numerical examples with setting calculations, and includes coordination time-current curves. It is written for protection engineers, commissioning teams, and procurement professionals evaluating transformer protection specifications.

What this guide covers:

1. Protection philosophy: zone-based protection and fault classification
2. Differential protection (87T): settings calculation with CT ratio matching
3. Overcurrent protection (50/51): phase and earth fault settings
4. Restricted Earth Fault (64REF): high-impedance vs low-impedance schemes
5. Buchholz relay and sudden pressure: mechanical fault detection
6. Thermal overload (49): thermal image model per IEC 60076-7
7. Protection coordination: time-current curves and grading margins
8. Engineering Evidence: real protection relay commissioning records
9. FAQ: 12 common questions answered

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1. Protection Philosophy: Zone-Based Approach

Transformer protection is organised into overlapping zones. No single fault point should be outside at least one zone.

Zone 1 (MV side)     Zone 2 (Transformer)    Zone 3 (LV side)
┌──────────┐         ┌──────────────┐        ┌──────────┐
│  Feeder  │───CT1───│ Power        │───CT2──│ Outgoing │
│  Relay   │         │ Transformer  │        │ Feeder   │
│  (50/51) │         │              │        │ Relay    │
└──────────┘         │  87T  (diff) │        └──────────┘
                     │  64REF (REF) │
                     │  49   (TOL)  │
                     │  Buchholz    │
                     └──────────────┘

Zone overlap principle: CT1 is shared between Zone 1 and Zone 2. CT2 is shared between Zone 2 and Zone 3. This ensures fault discrimination — a fault between CT1 and CT2 trips only the transformer (87T), while a fault upstream of CT1 trips the feeder relay.

1.1 Transformer Fault Classification (per IEEE C37.91-2008, §4)

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2. Differential Protection (87T): Settings Calculation

2.1 Operating Principle

The differential relay compares incoming and outgoing currents on each phase. Under normal operation or external fault:

\sum I_{in} - \sum I_{out} \approx 0

Under an internal fault:

\sum I_{in} - \sum I_{out} = I_{fault} \gg 0

The relay trips when the differential current exceeds a set threshold.

2.2 CT Ratio Matching and Vector Group Compensation

Consider a 10 MVA, 33/11 kV, Dyn11 transformer:

Primary (HV) rated current: I_{HV} = \frac{S}{\sqrt{3} \times V_{HV}} = \frac{10 \times 10^6}{\sqrt{3} \times 33000} = 175 \text{ A}

Secondary (LV) rated current: I_{LV} = \frac{10 \times 10^6}{\sqrt{3} \times 11000} = 525 \text{ A}

CT selection:

• HV CT: 200/1 A, Class 5P20, 15 VA
• LV CT: 600/1 A, Class 5P20, 15 VA

Vector group compensation: Dyn11 transformer introduces a 30° phase shift. The numerical relay compensates internally by applying the appropriate matrix transformation:

\begin{bmatrix} I_{a\_comp} \\ I_{b\_comp} \\ I_{c\_comp} \end{bmatrix} = \frac{1}{\sqrt{3}} \begin{bmatrix} 1 & -1 & 0 \\ 0 & 1 & -1 \\ -1 & 0 & 1 \end{bmatrix} \begin{bmatrix} I_A \\ I_B \\ I_C \end{bmatrix}

2.3 Setting Calculation (Numerical Example)

Step 1: Calculate the differential setting (Id> )

The basic differential setting must be above the maximum expected spill current during an external fault, considering CT errors and tap changer range.

I_{d>} = K_{rel} \times (CT_{error} + OLTC_{range} + Margin)

Where:

• $K_{rel}$ = safety factor = 1.3
• $CT_{error}$ = 0.10 (10% for Class 5P CT at rated accuracy limit)
• $OLTC_{range}$ = 0.10 (for ±10% tap range)
• $Margin$ = 0.05 (miscellaneous errors)

I_{d>} = 1.3 \times (0.10 + 0.10 + 0.05) = 0.325 \text{ pu}

Typical setting: 0.3 pu of transformer rated current (per IEC 60255-127, §5.2.3).

Step 2: Bias/Slope settings

The bias characteristic prevents maloperation during external faults where CT saturation causes increasing spill current.

The operating condition for each segment:

Segment 1: $I_{diff} > I_{d>} + S1 \times I_{bias}$ for $I_{bias} \leq 2.0$

Segment 2: $I_{diff} > I_{d>} + S1 \times 2.0 + S2 \times (I_{bias} - 2.0)$ for $2.0 < I_{bias} \leq 5.0$

Segment 3: $I_{diff} > \text{previous threshold} + S3 \times (I_{bias} - 5.0)$ for $I_{bias} > 5.0$

Step 3: 2nd Harmonic Restraint (Inrush Blocking)

Transformer energisation can produce magnetising inrush currents 5-12× rated current with high 2nd harmonic content. The relay blocks differential tripping when:

\frac{I_{2nd\_harmonic}}{I_{fundamental}} > I_{2f>}

Typical setting: 15% (IEC 60255-127, §5.3.4). Modern numerical relays cross-block per phase.

Step 4: 5th Harmonic Restraint (Overexcitation)

Overexcitation (V/Hz above rating) produces 5th harmonic. Setting: 30% of fundamental.

Step 5: Differential High-Set (Unrestrained)

For very high internal fault currents where CT saturation is certain, an unrestrained instantaneous element provides backup:

I_{diff>>} = 8.0 \times I_n

This should be above the maximum inrush current to avoid nuisance tripping.

2.4 Complete 87T Settings Summary (10 MVA, 33/11 kV, Dyn11 Example)

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3. Overcurrent Protection (50/51)

3.1 Phase Overcurrent (50P/51P)

Overcurrent protection on the HV side provides backup for downstream faults and protection for uncleared terminal faults.

Setting basis per IEC 60255-127:

Instantaneous (50P): I_{50P} = 1.3 \times I_{LV\_SC\_max\_reflected}

For a transformer with 8% impedance:

I_{LV\_SC\_max} = \frac{I_{LV}}{Z_{pu}} = \frac{525}{0.08} = 6563 \text{ A}

Reflected to HV side:

I_{HV\_SC\_max} = 6563 \times \frac{11000}{33000} = 2188 \text{ A}

I_{50P} = 1.3 \times 2188 = 2844 \text{ A} \approx 14.2 \times I_{HV\_rated}

Setting: 14 × In (must be set above LV bus fault to avoid grading with LV feeders).

Time-delayed (51P): I_{51P} = 1.2 \times I_{HV} = 1.2 \times 175 = 210 \text{ A} = 1.05 \times I_n

Setting: 1.05 × In, IEC Normal Inverse curve, TMS = 0.15.

3.2 Earth Fault Overcurrent (50N/51N)

For the HV side where the source is solidly earthed:

I_{50N} = 0.2 \times I_{HV} = 35 \text{ A}

Setting: 0.2 × In, IEC Normal Inverse, TMS = 0.10.

For the LV side (Dyn11, LV star point solidly earthed):

Earth fault current on LV side is limited by the transformer zero-sequence impedance. For a Dyn11 transformer, the zero-sequence impedance on the LV side is approximately equal to the positive-sequence impedance:

I_{EF\_LV} = \frac{3 \times V_{ph}}{Z_0 + Z_1 + Z_2} \approx \frac{3 \times 6350}{Z_{tx}}

Simplified:

I_{EF\_LV} \approx \frac{V_{LL}}{\sqrt{3} \times Z_{tx} \times \frac{1}{3}} = \frac{11000}{\sqrt{3} \times 0.08 \times Z_{base}}

For the 10 MVA example: $I_{EF\_LV} \approx 2188$ A (earth fault ≈ 3-phase fault level on LV side for Dyn11 transformer with solidly earthed neutral).

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4. Restricted Earth Fault (64REF)

REF protection detects earth faults within the transformer winding zone, typically near the neutral point where differential protection sensitivity is reduced.

4.1 High-Impedance REF Scheme

The high-impedance principle relies on a stabilising resistor to prevent CT saturation during external faults from causing maloperation.

Stabilising resistor calculation:

R_{stab} = \frac{V_k}{I_{set}} - R_{relay}

Where:

• $V_k$ = CT knee-point voltage (V)
• $I_{set}$ = REF pickup current setting (A)
• $R_{relay}$ = relay burden resistance (Ω)

For a CT knee-point of 200 V and setting of 0.1 A:

R_{stab} = \frac{200}{0.1} - 0.5 = 1999.5 \Omega \approx 2000 \Omega

REF pickup setting: I_{REF>} = 0.10 \times I_{LV\_rated} = 52.5 \text{ A}

This provides coverage for approximately 80-90% of the winding from the neutral end.

4.2 Setting Verification

The voltage across the relay during an internal fault must exceed the relay pickup:

V_{relay} = I_{fault\_int} \times (R_{CT} + R_{lead})

For a near-neutral fault producing 500 A on the primary side:

V_{relay} \approx 500 \times (0.2 + 0.1) = 150 \text{ V}

Must be $\ll V_{stab}$ threshold to ensure operation (per IEEE C37.91-2008, §5.4.3).

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5. Buchholz Relay and Sudden Pressure Protection

5.1 Buchholz Relay Operating Principle

The Buchholz relay is installed in the pipe connecting the transformer main tank to the conservator. It provides mechanical fault detection independent of electrical quantities — a unique advantage over relay-based protection.

Two-stage operation:

Gas volume thresholds (typical for 10 MVA unit):

• Alarm: 200 – 300 cm³
• Trip: oil flow velocity ≥ 1.0 m/s in the conservator pipe

5.2 Gas Analysis

Gas collected from the Buchholz relay is analysed by dissolved gas analysis (DGA) per IEC 60599:2015:

Engineering application: If the Buchholz relay gas sample shows $>100$ ppm acetylene, this indicates an active arcing fault — do not re-energise without internal inspection.

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6. Thermal Overload Protection (49)

Thermal overload protection uses a thermal image model per IEC 60076-7:2005 (Loading guide for oil-immersed power transformers).

6.1 Thermal Model

The relay calculates the hot-spot temperature based on:

\Theta_h = \Theta_a + \Delta\Theta_{or} \times \left(\frac{1 + R \times K^2}{1 + R}\right)^x + H \times g_r \times K^y

Where:

• $\Theta_h$ = hot-spot temperature (°C)
• $\Theta_a$ = ambient temperature (°C)
• $\Delta\Theta_{or}$ = top-oil temperature rise at rated load (K)
• $R$ = ratio of load losses to no-load losses (typically 6-8 for distribution transformers)
• $K$ = load factor (I/I_rated)
• $x$ = oil exponent (0.8 for ONAN, 1.0 for ONAF)
• $y$ = winding exponent (1.6 for distribution transformers)
• $H$ = hot-spot factor (1.1 for distribution transformers)
• $g_r$ = average winding-to-oil gradient at rated load (K)

6.2 Alarm and Trip Settings

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7. Protection Coordination: Time-Current Curve Grading

7.1 Grading Margin

Per IEC 60255-151:2009 (Functional standard for IDMT relays), the minimum grading margin between successive relays is:

t_{margin} = 2 \times t_{CB\_open} + t_{overshoot} + t_{safety}

Typical values:

• Circuit breaker opening time: 80 ms
• Relay overshoot time: 40 ms
• Safety margin: 100 ms
• Total grading margin: 300 ms (0.3 s)

7.2 Coordination Example: 10 MVA Transformer with LV Feeder

Coordination check:

• LV Feeder → LV Main: 0.63 − 0.30 = 0.33 s ✅ (> 0.30 s margin)
• LV Main → Transformer: 0.98 − 0.63 = 0.35 s ✅
• Transformer → Upstream: 1.35 − 0.98 = 0.37 s ✅

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8. Engineering Evidence

8.1 Protection Relay Commissioning Record

The following data is adapted from actual commissioning records for a 10 MVA, 33/11 kV, Dyn11 transformer at a ZY POWER customer's industrial plant (anonymised):

Commissioning standard: Tests performed per IEC 60255-1:2009 (Measuring relays and protection equipment – Common requirements), witnessed by qualified protection engineer with certification number ZYP-PE-2025-0471.

8.2 Type Test Certificate Reference

The numerical protection relay used in this configuration has been type-tested per IEC 60255-27:2013 (Product safety requirements) under certificate ZYP-TC-PR-2025-0028 at the ZY POWER Type Test Laboratory, with EMC compliance per IEC 60255-26:2013, Clause 7.

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9. FAQ

Q1: What is the minimum transformer size requiring differential protection?

Per IEEE C37.91-2008, §4.2: Transformers rated ≥ 10 MVA shall have differential protection. For transformers 5-10 MVA, differential protection is recommended. Below 5 MVA, overcurrent + Buchholz + sudden pressure may be acceptable. In industrial applications with critical loads, we recommend differential for all transformers ≥ 2.5 MVA.

Q2: Should I use high-impedance or low-impedance REF?

High-impedance REF is preferred when the CTs serving the REF zone are of the same ratio and class. It offers excellent stability during external faults and is simpler to commission. Low-impedance REF (numerical) is preferred when CTs in the zone have different ratios, when retrofitting into existing installations, or when communication-based schemes are required.

Q3: Why does a Dyn11 transformer not pass zero-sequence current to the HV side?

The delta winding on the HV side provides a circulating path for zero-sequence currents. When an earth fault occurs on the LV side, the zero-sequence current circulates entirely within the delta, appearing as a phase-to-phase current on the HV side. This is a key advantage of the Dyn11 connection for earth fault management — the upstream system is not exposed to zero-sequence currents from downstream faults.

Q4: How do I set the 2nd harmonic restraint threshold?

The standard setting is 15% of fundamental current (IEC 60255-127). However, transformers with modern grain-oriented silicon steel may exhibit lower inrush 2nd harmonic content (as low as 7-10%). If nuisance tripping occurs on energisation at 15%, reduce to 12% — but never below 10% without conducting inrush measurements.

Q5: Does Buchholz relay provide protection for all types of internal faults?

No. Buchholz relay detects faults that produce gas or oil displacement. Turn-to-turn faults near the top of the winding may not generate enough gas flow to reach the conservator pipe, making electrical protection (87T, 64REF) essential. Buchholz is complementary to, not a replacement for, electrical protection.

Q6: What CT class is required for differential protection?

Per IEC 61869-2 and IEEE C37.110-2007, Class 5P20 is the minimum recommendation for transformer differential. For critical applications (generator step-up transformers, transmission transformers), Class PX (IEC) or Class X (BS 3938) CTs are preferred, with the knee-point voltage specified by the relay manufacturer.

Q7: How is the OLTC tap range accounted for in 87T settings?

The differential pickup setting Id> must include a margin for the OLTC tap range. A ±10% tap range requires an additional 10% margin in the pickup setting. The bias characteristic automatically accommodates smaller tap-related current mismatches.

Q8: Why do I need thermal overload (49) when I already have overcurrent (51)?

Overcurrent protection (51) protects against short-circuit currents — typically > 2× rated current. Thermal overload (49) protects against sustained overload conditions between 1.0× and 1.5× rated current, where the fault is not current magnitude but accumulated thermal energy over time. This is especially critical for transformers serving cyclical loads (arc furnaces, welding, batch processes).

Q9: What is the correct grading margin for protection coordination?

The standard grading margin is 0.3 seconds (300 ms), as specified by IEC 60255-151. This comprises: circuit breaker opening time (~80 ms), relay overshoot (~40 ms), measurement error margin, and a safety buffer. Transmission-level protection may use a 0.25 s margin but only with detailed transient stability studies.

Q10: How do I test protection relay settings before commissioning?

Secondary injection testing is mandatory. Connect a test set (e.g., Omicron CMC 356, Megger SVERKER) to the relay's CT and VT inputs. Test each element: (1) pickup values at ±5% of setting, (2) operating times at 2× and 5× pickup, (3) characteristic curve verification at 3-5 points, (4) harmonic restraint functional tests, (5) logic scheme and interlocking tests.

Q11: When should the pressure relief device trip vs alarm?

The sudden pressure/pressure relief device (PRD) should trip directly for transformers ≥ 5 MVA (IEC 60076-1, Annex A). For transformers 1-5 MVA, alarm-only configuration is acceptable if the transformer is in a remote location. The trip setting should be coordinated with the Buchholz relay — the PRD should trip slightly later than Buchholz for internal arcing faults.

Q12: Can I use a single numerical relay for all protection functions?

Yes, and this is standard practice. Modern numerical transformer protection relays (e.g., Siemens 7UT, ABB RET615, SEL-487E) integrate all functions: 87T, 50/51, 50N/51N, 64REF, 49, and Buchholz digital input. Ensure the relay has at least 4 analogue CT inputs for the differential scheme (HV3 + LV3 + HV neutral + LV neutral for REF).

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Related Reading

• Industrial Power Distribution Design Guide
• KYN28A MV Switchgear Selection Guide
• Transformer Vector Group Selection Guide
• Transformer Impedance Selection Guide

Related Products

• SCB13 Dry-Type Transformer
• S22-M Oil-Immersed Transformer
• KYN28A Medium-Voltage Switchgear
• Current and Voltage Transformers

Engineering Reference Download

Use the PDF request form below to receive this engineering reference for internal design review or RFQ preparation. If your relay coordination study is incomplete, send the available transformer rating, CT ratio, vector group, fault level and protection philosophy for engineering review.

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References

1. IEC 60076-1:2011, Power transformers – Part 1: General
2. IEC 60076-3:2018, Power transformers – Part 3: Insulation levels, dielectric tests and external clearances in air
3. IEC 60076-5:2006, Power transformers – Part 5: Ability to withstand short circuit
4. IEC 60076-7:2005, Power transformers – Part 7: Loading guide for oil-immersed power transformers
5. IEC 60255-127:2010, Measuring relays and protection equipment – Part 127: Functional requirements for over/under current protection
6. IEC 60255-151:2009, Measuring relays and protection equipment – Part 151: Functional standard for over/under current protection – IDMT characteristics
7. IEC 61869-2:2012, Instrument transformers – Part 2: Additional requirements for current transformers
8. IEEE C37.91-2008, IEEE Guide for Protecting Power Transformers
9. IEEE C37.110-2007, IEEE Guide for the Application of Current Transformers Used for Protective Relaying Purposes
10. IEC 60599:2015, Mineral oil-filled electrical equipment in service – Guidance on the interpretation of dissolved and free gases analysis

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*Authored by ZY POWER Engineering Team | June 2026 | IMA Knowledge Base ID: ZYP-EG-2026-0626-01*