Why Do Transformers Overheat? Root Causes, Effects, Diagnostics, Examples & Practical Solutions

Transformers are among the most expensive and important assets in any power system. They operate continuously under demanding conditions, and their health directly affects the reliability of the entire electrical network. One of the most frequent problems that transformers face during their operational life is overheating. Excessive heat inside a transformer degrades the insulating materials, shortens the equipment’s lifespan, and can ultimately lead to failure if left unaddressed.

Overheating does not happen without reason. There is always an underlying cause, and identifying that cause early can save utilities and industries millions of dollars in repairs and unplanned downtime.

In this technical guide, we will discuss everything you need to know about the causes of transformer overheating, including overloading, cooling system malfunctions, harmonic effects, insulation degradation, core problems, ambient temperature issues, and voltage imbalances. We will also cover diagnostic methods, and practical fixes. Practical examples are included throughout to help you apply these concepts in real-world scenarios confidently.

1. How Does a Transformer Generate Heat?

Before discussing the specific causes of overheating, it is helpful to understand how heat is produced inside a transformer during normal operation. Transformers generate heat through two primary mechanisms: copper losses and core losses.

Copper losses occur in the windings due to the resistance of the conductor material. As load current flows through the windings, power is dissipated as heat according to the formula I²R, where I is the current and R is the resistance. Higher load currents produce more heat proportionally.

Core losses occur in the magnetic core of the transformer. These losses include hysteresis losses and eddy current losses. Hysteresis loss results from the repeated magnetization and demagnetization of the core material during each AC cycle. Eddy current losses arise from circulating currents induced in the core laminations by the alternating magnetic flux. Core losses remain relatively constant regardless of the load because they depend on the applied voltage and frequency.

Under normal conditions, the cooling system of a transformer is designed to dissipate all this heat effectively. Problems arise only when heat generation exceeds the cooling system’s capacity or when the cooling system itself fails to perform adequately.

2. What Temperature Limits Apply to Transformers?

Temperature limits for power transformers are governed by industry standards, most notably IEEE C57.12.00 and ANSI C57.91. These standards define maximum allowable temperature rises above ambient temperature for different insulation classes.

For oil-immersed transformers with standard 65°C rise insulation (Class A insulation system), the average winding temperature rise must not exceed 65°C above ambient. The hottest spot temperature rise is limited to 80°C above ambient. Assuming a maximum ambient temperature of 40°C, the absolute hottest spot temperature should not exceed 120°C during normal loading.

For dry-type transformers, the limits vary depending on the insulation class:

• Class 130 (B): 80°C average winding rise
• Class 155 (F): 115°C average winding rise
• Class 180 (H): 150°C average winding rise
• Class 220 (N): 200°C average winding rise

Exceeding these temperature limits accelerates insulation aging. According to the well-known Montsinger Rule, for every 8–10°C increase above the rated hottest spot temperature, the insulation life of a transformer is reduced by approximately half. This relationship makes temperature monitoring and overheating prevention absolutely necessary.

3. Causes of Transformer Overheating

3.1 Cause #1: Overloading Beyond Rated Capacity

Overloading is the single most common cause of transformer overheating. It happens when the load current drawn from the transformer exceeds its nameplate rating for an extended period. The relationship between load current and heat generation is exponential, not linear. Doubling the load current increases the copper losses by a factor of four because losses follow the I²R relationship.

3.1.1 Why Does Overloading Happen?

Overloading can occur for several reasons. Load growth over time is one of the most frequent causes. A transformer that was properly sized ten years ago may now be serving a much larger load due to facility expansions or increased consumer demand. Seasonal variations also contribute to overloading. During summer months, air conditioning loads can push transformers well beyond their rated capacity unexpectedly.

In industrial settings, the startup of large motors can cause temporary but severe overloading. A motor draws 6 to 8 times its full-load current during startup, and this inrush current passes through the supply transformer entirely.

3.1.2 Example

Consider a 1000 kVA distribution transformer serving a commercial building. If the building adds new HVAC equipment and the total connected load increases to 1300 kVA, the transformer is operating at 130% of its rated capacity. The copper losses at this loading level would be approximately 1.69 times (1.3² = 1.69) the losses at full load. This additional heat can push the winding temperature beyond the design limits rapidly.

3.1.3 How to Fix Overloading

• Load management: Redistribute loads among multiple transformers to balance the demand evenly.
• Upgrade the transformer: Replace the existing unit with a higher-rated transformer that can accommodate the current and projected future loads adequately.
• Install load monitoring systems: Use real-time load monitoring with alarms set at 80% and 100% of rated capacity to provide early warning effectively.
• Demand-side management: Stagger the startup of large loads to avoid simultaneous peak demands occurring together.

Per ANSI C57.91, planned overloading is permissible for short durations under specific ambient temperature conditions. However, sustained overloading beyond the guidelines will degrade insulation and shorten transformer life permanently.

3.2 Cause #2: Cooling System Failure or Degradation

The cooling system is the transformer’s primary defense against overheating. Any malfunction in this system leads to heat buildup inside the transformer immediately. The type of cooling system varies based on the transformer design, and each type has its own failure modes.

3.2.1 Types of Transformer Cooling Systems

Transformers use standardized cooling designations per ANSI/IEEE C57.12.00:

• ONAN (Oil Natural, Air Natural): Oil circulates by natural convection, and heat is dissipated to the surrounding air through radiators naturally.
• ONAF (Oil Natural, Air Forced): Oil circulates naturally, but fans force air over the radiators to improve heat dissipation actively.
• OFAF (Oil Forced, Air Forced): Both oil pumps and fans are used to maximize cooling performance mechanically.
• ODAF (Oil Directed, Air Forced): Oil is directed through specific paths in the windings using pumps, and fans cool the radiators forcefully.

3.2.2 Common Cooling System Failures

Fan failures are extremely common. Cooling fans can fail due to motor burnout, bearing wear, broken blades, or electrical control circuit malfunctions. A transformer rated for ONAF cooling will only achieve its ONAN rating if the fans are not operational. This effectively reduces the transformer’s capacity by 25% to 33% instantly.

Oil pump failures in OFAF and ODAF systems prevent forced oil circulation. Without adequate oil flow, hot spots develop in the windings because the oil cannot carry heat away from the coils to the radiators efficiently.

Blocked or dirty radiators restrict airflow and reduce heat transfer to the atmosphere noticeably. Dust, debris, bird nests, and vegetation growth around radiator fins are common culprits in outdoor installations particularly.

Low oil levels reduce the volume of cooling medium available for heat absorption. Oil leaks from gaskets, valves, bushings, or welded joints can lower the oil level over time gradually.

3.2.3 Example

A 20 MVA substation transformer rated ONAF has two banks of cooling fans. During a summer peak, one fan bank fails due to a faulty contactor. The transformer can now only operate at its ONAN rating of approximately 14 MVA. If the load remains at 18 MVA, the transformer will overheat within hours dangerously.

3.2.4 How to Fix Cooling System Problems

• Scheduled maintenance: Inspect fans, pumps, radiators, and oil levels at regular intervals (quarterly for fans and pumps, annually for radiators) consistently.
• Install redundant cooling: Use backup fan banks and spare oil pumps so that a single failure does not compromise the entire cooling capacity immediately.
• Clean radiators: Power wash radiator fins annually to remove accumulated dirt and debris thoroughly.
• Monitor oil levels: Install oil level indicators with alarm contacts connected to the SCADA system for remote monitoring continuously.
• Test fan and pump controls: Verify that temperature-actuated controls (winding temperature indicators and oil temperature indicators) activate the cooling stages at the correct setpoints reliably.

3.3 Cause #3: Harmonic Distortion in the Load

Harmonics are one of the most underestimated causes of transformer overheating in modern electrical systems. Non-linear loads such as variable frequency drives (VFDs), LED lighting, computer power supplies, rectifiers, and uninterruptible power supplies (UPS) inject harmonic currents into the power system. These harmonic currents cause additional heating in the transformer windings and core beyond what the fundamental frequency component alone would produce.

3.3.1 How Do Harmonics Cause Overheating?

Harmonics increase transformer losses in three ways:

1. Increased I²R losses in windings: The total RMS current increases when harmonic components are present. A transformer carrying 100A of fundamental current plus harmonics might have a total RMS current of 110A or more actually.
2. Increased eddy current losses in windings: Eddy current losses in the windings are proportional to the square of the harmonic order (frequency). A 5th harmonic current produces 25 times the eddy current loss compared to the same magnitude of fundamental current. This is the dominant heating mechanism caused by harmonics in transformer windings specifically.
3. Increased core losses: Higher-order harmonics increase both hysteresis and eddy current losses in the transformer core, although this effect is smaller compared to the winding eddy current losses relatively.

3.3.2 The K-Factor Rating

To address harmonic loading, the transformer industry introduced the K-factor rating per ANSI/UL 1561. The K-factor is a numerical value that indicates a transformer’s ability to handle harmonic currents without exceeding its temperature limits. Common K-factor ratings include K-1 (standard), K-4, K-9, K-13, and K-20.

A K-1 rated transformer is designed for linear loads only. A K-13 rated transformer can handle the harmonic content produced by typical office environments with computers and electronic equipment safely.

The K-factor is calculated as:

\(K = \sum (I_h^2 \times h^2)\) for h = 1 to n

Where \(I_h\) is the per-unit harmonic current at harmonic order h.

3.3.3 Example

A 500 kVA transformer serves a data center. The load consists almost entirely of servers and UPS systems. Power quality measurements reveal a total harmonic distortion (THD) of 35% in the load current. The calculated K-factor is 12. However, the installed transformer is rated K-1. This means the transformer is experiencing eddy current heating far beyond its design capability, and overheating is inevitable without corrective action soon.

3.3.4 How to Fix Harmonic-Related Overheating

• Install a K-rated transformer: Replace the standard transformer with one that has the appropriate K-factor for the measured harmonic content specifically.
• Derate the transformer: If replacement is not feasible, reduce the load on the transformer to compensate for the additional harmonic heating. ANSI/IEEE C57.110 provides derating guidelines for this purpose exactly.
• Install harmonic filters: Use passive or active harmonic filters at the load side to reduce the harmonic currents flowing through the transformer effectively.
• Use phase-shifting transformers: In large installations, phase-shifting techniques can cancel specific harmonic orders before they reach the main transformer successfully.

IEEE C57.110, titled “Recommended Practice for Establishing Liquid-Immersed and Dry-Type Power and Distribution Transformer Capability When Supplying Nonsinusoidal Load Currents,” provides detailed procedures for determining the allowable loading of transformers under harmonic conditions precisely.

3.4 Cause #4: Insulation Deterioration and Internal Faults

Insulation degradation is both a cause and a consequence of transformer overheating. As insulation breaks down, it creates conditions that generate even more heat, setting up a destructive cycle that accelerates failure progressively.

3.4.1 How Insulation Degradation Causes Overheating

In oil-immersed transformers, the insulation system consists of cellulose paper wrapped around the windings and mineral oil that serves as both insulation and cooling medium. Over time, the cellulose paper undergoes thermal aging, oxidation, and hydrolysis. These processes break down the paper’s molecular structure, reducing its mechanical and dielectric strength steadily.

As the insulation deteriorates, partial discharge activity increases. Partial discharges are localized electrical breakdowns that produce heat at the discharge sites. They also generate combustible gases that dissolve in the oil. If the deterioration progresses, turn-to-turn faults or layer-to-layer faults can develop within the windings. These short circuits create circulating currents in the affected turns, producing intense localized heating dangerously.

Moisture ingress into the insulation system also plays a damaging role. Water reduces the dielectric strength of both the oil and the paper insulation. It also accelerates the rate of cellulose decomposition at elevated temperatures significantly.

3.4.2 Diagnostic Indicators

Several diagnostic tests can detect insulation degradation before it causes overheating:

• Dissolved Gas Analysis (DGA): Per IEEE C57.104, DGA detects gases produced by insulation decomposition. Elevated levels of carbon monoxide (CO) and carbon dioxide (CO₂) indicate cellulose degradation. Hydrogen (H₂) and acetylene (C₂H₂) suggest electrical faulting or arcing inside the transformer clearly.
• Power Factor / Dissipation Factor Testing: Per ANSI/NETA MTS, increased power factor of the insulation indicates contamination or deterioration directly.
• Degree of Polymerization (DP) Testing: This test measures the average chain length of cellulose molecules. New paper has a DP of about 1000–1200. A DP below 200 indicates the paper has reached end-of-life mechanically.
• Furan Analysis: Furfuraldehyde compounds in the oil are byproducts of cellulose degradation. Their concentration correlates with the degree of paper aging accurately.

3.4.3 Example

A 30-year-old 50 MVA transformer shows gradually increasing top oil temperature over the past two years, despite no change in loading. DGA results reveal elevated CO, CO₂, and trace amounts of acetylene. These findings suggest that the insulation is deteriorating internally and that localized hot spots are developing within the winding structure progressively.

3.4.4 How to Fix Insulation-Related Overheating

• Oil reclamation or replacement: Remove moisture, acids, and sludge from the transformer oil through vacuum degassing and reclamation processes regularly.
• Dry out the transformer: If moisture content in the insulation is high (above 2% by weight in the paper), perform a hot oil circulation drying or vapor phase drying procedure completely.
• Increase monitoring frequency: For aging transformers, increase the frequency of DGA sampling from annually to quarterly or even monthly as conditions warrant appropriately.
• Plan for replacement: If DP values fall below 300 or DGA trends show rapidly increasing fault gases, begin planning for transformer replacement proactively.

3.5 Cause #5: Core Problems (Lamination Faults and Magnetic Circuit Issues)

The transformer core is designed to provide a low-reluctance path for magnetic flux. Any damage to the core structure can increase losses and produce excessive heat locally. Core-related overheating problems are less common than loading or cooling issues, but they can be very severe when they do occur unfortunately.

3.5.1 Types of Core Problems

Shorted laminations are one of the most common core problems. Transformer cores are built from thin, insulated silicon steel laminations. The insulation between laminations limits eddy currents to each individual lamination. If this inter-lamination insulation breaks down due to mechanical damage, overheating, or manufacturing defects, eddy currents can flow across multiple laminations. These cross-lamination currents produce concentrated heating at the fault location intensely.

Core ground faults can also cause overheating. A transformer core is intentionally grounded at one point only. If a second ground develops due to debris, displaced core components, or insulation failure, a circulating current loop is created through the core and the tank. This circulating current generates heat at the grounding points and within the core structure noticeably.

Flux leakage outside the core can cause localized heating in structural components such as the tank walls, core clamps, and tie plates. This situation arises from core saturation, DC magnetization, or design imperfections occasionally.

3.5.2 Diagnostic Methods

• Core Insulation Resistance Test: Measures the resistance between the core and ground. A low reading may indicate multiple core grounds existing simultaneously.
• Excitation Current Test: Per IEEE C57.12.90, this test compares the excitation current on each phase. Significant imbalances between phases indicate core problems or shorted turns existing somewhere.
• DGA: Core overheating produces characteristic gases, particularly methane (CH₄) and ethylene (C₂H₄), which can be detected through oil analysis promptly.
• Infrared Thermography: External thermal imaging can sometimes reveal hot spots on the tank surface that correspond to internal core heating locations approximately.

3.5.3 Example

During a routine DGA test on a 10 MVA transformer, technicians find elevated levels of methane and ethylene with no corresponding increase in load. An excitation current test reveals that one phase draws 30% more excitation current than the other two phases. These results point to a core lamination fault or a core ground fault on that phase specifically.

3.5.4 How to Fix Core Problems

• Internal inspection: If DGA and electrical tests confirm a core problem, an internal inspection may be required. This involves untanking the transformer and visually inspecting the core for damage, debris, or displaced components carefully.
• Remove foreign objects: Metal particles, loose hardware, or construction debris inside the tank can create unintended ground paths. Removing these objects may resolve the issue completely.
• Repair lamination insulation: Damaged lamination insulation can sometimes be repaired by applying new insulating varnish or replacing damaged laminations in accessible areas specifically.
• Correct multiple core grounds: Identify and eliminate the unintended second ground path to stop the circulating current flow permanently.

3.6 Cause #6: High Ambient Temperature

Transformers are rated based on a maximum ambient temperature, which is 40°C for most units per IEEE C57.12.00. The temperature rise limits specified on the nameplate are in addition to this assumed ambient temperature. If the actual ambient temperature exceeds the design assumption, the transformer will reach higher absolute temperatures even at rated load consistently.

3.6.1 Why Is Ambient Temperature a Problem?

In many regions, outdoor temperatures regularly exceed 40°C during summer months. Transformers installed in the Middle East, India, Australia, the southern United States, and parts of Africa frequently operate in ambient temperatures of 45°C to 50°C or higher seasonally.

Indoor transformers face an even greater challenge. Pad-mounted transformers inside buildings, vault-type transformers in basements, and dry-type transformers in electrical rooms may be surrounded by poor ventilation. Heat from the transformer itself raises the room temperature, creating a feedback loop where the transformer heats the room and the hot room reduces the transformer’s ability to cool down cyclically.

Transformers installed near other heat-generating equipment such as boilers, furnaces, engines, or other transformers also experience elevated ambient temperatures artificially.

3.6.2 Example

A dry-type transformer rated at 1500 kVA with a 150°C rise (Class F insulation) is installed in a basement electrical room. The room has limited ventilation, and during summer, the room temperature reaches 52°C. The maximum winding temperature at full load would be 52 + 150 = 202°C, which exceeds the Class F limit of 185°C (155°C rise + 30°C hottest spot allowance at 40°C ambient). This transformer will overheat at full load in these conditions.

3.6.3 How to Fix High Ambient Temperature Problems

• Improve ventilation: Install exhaust fans, louvers, or HVAC systems to maintain the ambient temperature around the transformer below 40°C consistently.
• Derate the transformer: Per ANSI C57.91, reduce the allowable loading by 1% for each degree Celsius above 40°C ambient. For a 50°C ambient, the transformer should be loaded to no more than 90% of its nameplate rating accordingly.
• Relocate the transformer: If feasible, move the transformer to a cooler location with better natural ventilation access permanently.
• Install sunshades or heat shields: For outdoor transformers in direct sunlight, sunshades can reduce the effective ambient temperature by 5°C to 10°C meaningfully.
• Use forced ventilation in vaults: Transformer vaults should meet the ventilation requirements specified in NEC Article 450 and IEEE C57.12.29 to maintain adequate airflow continually.

3.7 Cause #7: Voltage Imbalance and Overvoltage Conditions

Voltage abnormalities, including overvoltage and voltage imbalance across phases, directly affect transformer losses and temperature levels measurably.

3.7.1 Overvoltage

When the applied voltage exceeds the transformer’s rated voltage, the magnetic flux density in the core increases proportionally. If the core is driven beyond its designed flux density, it enters saturation. In the saturated region, the core’s permeability drops sharply, and the magnetizing current increases dramatically. This increase in magnetizing current raises both the core losses and the winding I²R losses simultaneously.

Core saturation also causes flux to leak out of the core and into surrounding structural components such as core bolts, clamps, tank walls, and tie plates. These metallic parts are not laminated and therefore experience very high eddy current heating when exposed to stray flux directly.

Per ANSI C57.12.00, transformers must be capable of continuous operation at 110% of rated voltage at no load and at 105% of rated voltage at full load without exceeding temperature limits. Operation beyond these levels causes overheating quickly.

3.7.2 Voltage Imbalance

Voltage imbalance between the three phases of a transformer causes negative-sequence currents to flow. These negative-sequence currents produce a rotating magnetic field that opposes the normal positive-sequence field. The result is increased losses in both the windings and the core that produce additional heat steadily.

Even a small voltage imbalance of 2% to 3% can increase the transformer losses by 10% to 20% in some cases. The effect is magnified in transformers that serve large motor loads because motors also generate additional negative-sequence currents under unbalanced conditions further.

3.7.3 Example

A three-phase distribution transformer receives supply voltages of 12.2 kV, 12.5 kV, and 12.8 kV on its three phases. The average voltage is 12.5 kV, and the maximum deviation is 0.3 kV, giving a voltage imbalance of approximately 2.4%. This imbalance forces the transformer to handle negative-sequence currents, increasing losses and raising the operating temperature above normal levels noticeably.

3.7.4 How to Fix Voltage Problems

• Regulate supply voltage: Use automatic voltage regulators (AVRs) or load tap changers (LTCs) to maintain the transformer’s input voltage within the ±5% band specified by ANSI C84.1 consistently.
• Balance phase loads: Redistribute single-phase loads across the three phases to minimize voltage imbalance at the supply point effectively.
• Install overvoltage protection: Use surge arresters rated per IEEE C62.11 and overvoltage relays (ANSI device 59) to protect against sustained overvoltage conditions reliably.
• Monitor voltage quality: Install power quality meters at the transformer terminals to track voltage magnitude and imbalance trends over time continuously.

4. Summary Table: Causes, Effects, and Solutions

5. How to Monitor Transformer Temperature Effectively

Proactive temperature monitoring is the best defense against overheating damage. Several monitoring methods and devices are used across the industry routinely.

5.1 Winding Temperature Indicator (WTI)

The WTI provides an indirect measurement of the hottest winding temperature. It uses a current transformer connected to a heating element inside the oil temperature indicator bulb well. The heating element simulates the thermal effect of the load current on the winding. WTIs are required on all power transformers above a certain size per IEEE C57.12.00 typically.

5.2 Oil Temperature Indicator (OTI)

The OTI measures the top oil temperature using a bulb inserted into the transformer’s oil near the top of the tank. The OTI is used to activate cooling stages (fans and pumps) at preset temperature thresholds automatically.

5.3 Fiber Optic Temperature Sensors

Modern transformers can be equipped with fiber optic sensors embedded directly within the winding structure. These sensors measure the actual hottest spot temperature in real time with high accuracy. They are not affected by electromagnetic interference and provide the most reliable temperature data available currently.

5.4 Online Monitoring Systems

SCADA-connected monitoring systems can collect temperature, load, oil quality, and dissolved gas data from transformers in real time. These systems use thermal models based on IEEE C57.91 to calculate the remaining life of insulation and predict overheating events before they occur proactively.

5.5 Applicable ANSI Device Numbers

• ANSI 26: Apparatus thermal device – operates when the temperature of a machine or transformer exceeds a predetermined value directly.
• ANSI 49: Machine or transformer thermal relay – protects against overheating by measuring winding temperature or using a thermal model accurately.
• ANSI 63: Pressure relay (Buchholz relay in some regions) – detects gas accumulation in oil-filled transformers, which often accompanies overheating events specifically.

6. Conclusion

Transformer overheating is a serious but preventable problem. The seven causes discussed in this guide (overloading, cooling system failure, harmonic distortion, insulation deterioration, core faults, high ambient temperature, and voltage abnormalities) cover the vast majority of overheating incidents seen in the field today. Each cause has well-established diagnostic methods and proven corrective actions that engineers and maintenance teams can implement effectively.

7. Frequently Asked Questions (FAQs)