Transformer Testing

Power transformers should undergo testing at various stages throughout their life cycle to ensure their performance, reliability, and safety.

Here are the key stages when power transformers should be tested:

Factory Testing
Power transformers are thoroughly tested at the factory before they are shipped to the customer. These tests verify the transformer's compliance with design specifications, performance characteristics, and quality standards. Factory testing typically includes tests such as turns ratio, insulation resistance, winding resistance, impedance, load loss, and no-load loss measurements.

Low voltage Transformer
Pad mount Transformer

Acceptance Testing
Upon delivery and installation, power transformers should undergo acceptance testing. This testing is conducted by the purchaser or a qualified testing agency to verify that the transformer meets the agreed-upon specifications and requirements. Acceptance testing ensures that the transformer is suitable for operation and helps identify any manufacturing defects or transportation-related issues.

Routine Maintenance Testing
Regular maintenance testing is performed at predetermined intervals, such as 3-5 years, to assess the condition of the transformer and identify any developing issues. These tests include measurements of insulation resistance, winding resistance, turns ratio, and oil quality analysis. Routine maintenance testing helps detect early signs of degradation, insulation breakdown, or other abnormalities that could impact the transformer's performance.

Periodic Diagnostic Testing
Periodic diagnostic testing involves more comprehensive assessments of the transformer's condition. These tests go beyond routine maintenance and may include detailed insulation testing, partial discharge analysis, sweep frequency response analysis (SFRA), and dissolved gas analysis (DGA). Periodic diagnostic testing provides valuable information about the internal condition of the transformer and can help predict potential failures or malfunctions.

After Repair or Overhaul
After any significant repair, refurbishment, or overhaul of a power transformer, it is essential to conduct post-repair testing. These tests ensure that the transformer has been restored to its proper functioning and meets the required performance standards.

Transformer Testing

NETA Test Procedure Categories:

1. Dry Type Transformers <= 500 KVA

Voltage Level: Low voltage (<600V)

Common Locations: Typically found in commercial, industrial, and residential facilities.

Example: : A transformer used in a small business facility to manage operational loads within safety limits.

2. Dry Type Transformers > 500 KVA

Voltage Level:
Low voltage (<600V) or Medium Voltage (>600V)

Common Locations: Frequently used in commercial, industrial, and residential facilities that require higher power capacity.

Example: : A transformer in a large manufacturing plant that requires high power for heavy

3. Liquid Filled Transformers

Voltage Level:Medium Voltage (>600V)

Common types: Station transformers

Common Locations: Used in power generation stations, large commercial and industrial facilities, and extensive residential complexes.

Example: : A transformer at a power station that steps down voltage for distribution to various consumers.

Test Procedure
Visual and Mechanical Inspection:
  1. Compare equipment nameplate data with drawings and specifications.
  2. Inspect physical and mechanical condition.
  3. Verify that resilient mounts are free and that any shipping brackets have been removed.
  4. Verify that as-left tap connections are as specified.
xfmr nameplate
Image 1 Transformer Nameplate
Grounding Bus
Image 2: Grounding
Anchorage
Image 3: Anchorage
Insulation Test:
  1. Perform insulation-resistance tests winding-to-winding and each winding-to-ground.
  2. Test voltage shall be applied to each winding. Record a one minute and ten minute value for each test.
Neta Table 100.1
NETA Table 100.5 shows recommended minimum test result values
  1. Primary Winding to Secondary Winding
    (Phases ABC, All phases are shorted internally)
  2. Primary Winding to Ground Bus
    (Phases ABC, All phases are shorted internally)
  3. Secondary Winding to Ground Bus
    (Phases ABC, All phases are shorted internally)
  1. Calculate polarization index.
    Polarization index is an extension of the insulation resistance test.
    Divide the ten-minute value by the one-minute value. This value is unitless
    Polarization index = (10 min) / (1 min)
  2. The polarization index shall not be less than 1.0.
Turns Ratio Test
  1. Acceptance Testing: Perform turns-ratio tests at all tap positions
    Maintenance Testing: Perform turns-ratio on as found tap position.
  2. Turns-ratio test results shall not deviate by more than one-half percent from either the adjacent coils or the calculated ratio.
Transformer Turns Ratio

This is the ratio of the number of turns in the primary winding (N1) to the number of turns in the secondary winding (N2). The voltage times the amperage on the primary winding is equal to the voltage times the amperage on the secondary winding.

\( \Large \text{turns ratio}=\huge \frac{N_{1}}{N_{2}} =\frac{V1}{V2}=\frac{I2}{I1} \)

  1. \(\large {N_{1} :}\)\(\text{ pri. turns}\)
  2. \(\large {N_{2} :}\)\(\text{ sec. turns}\)
  1. \(\large {V_{1} :}\)\(\text{ pri. volts}\)
  2. \(\large {V_{2} :}\)\(\text{ sec. volts}\)
  1. \(\large {I_{2} :}\)\(\text{pri. current}\)
  2. \(\large {I_{1} :}\)\(\text{sec. current}\)
Test Description

The transformer turns ratio test, or TTR test, confirms that the transformer has the correct ratio of primary turns to secondary turns Verifies the transformer's input and output voltage ratio.

  • Verifies the transformer's input and output voltage ratio.
  • Confirms nameplate ratio, polarity, and vectors.
  • Identifies possible winding deficiencies, such as open-circuits and short-circuits of turn-to-turn sensitivity.
Test Result Values

ANSI/IEEE C57.12.00-2006, Section 9.1 The standard deviation between test results and calculated values should be within 0.5% of nameplate markings, with rated voltage applied to one winding.

TTR Wiring
Transformer Insulation

A transformer insulation test is a diagnostic test performed on power transformers to assess the condition and integrity of the insulation system. The insulation system in a transformer consists of various components, such as solid insulation, oil insulation, and insulation between windings, which are crucial for maintaining electrical isolation and preventing short circuits.

The primary purpose of a transformer insulation test is to measure the insulation resistance or insulation resistance to ground. This test helps evaluate the insulation's ability to withstand electrical stress and identifies any potential insulation weaknesses or deterioration. It is typically conducted using a high-voltage DC test source and a megohmmeter, which measures resistance in the range of megaohms (MΩ).

Winding Resistance

Transformer winding resistance testing is a common diagnostic test conducted on power transformers. It involves measuring the resistance of the transformer's windings to evaluate their condition and identify any potential issues. Here's an overview of transformer winding resistance testing:

Purpose

The primary purpose of winding resistance testing is to assess the integrity of the transformer's windings and connections. By measuring the resistance, it helps detect abnormalities such as loose connections, high resistance joints, or damaged windings that could affect the transformer's performance.

inspection
Procedure

Transformer winding resistance testing typically involves the following steps:

  1. De-energization: The transformer must be de-energized and isolated from the power source before conducting winding resistance testing. Safety precautions should be followed, and appropriate lockout/tagout procedures should be implemented.
  2. Test Equipment: Specialized test equipment, such as a low-resistance ohmmeter, is used for winding resistance testing. This equipment provides accurate measurements of the winding resistance.
  3. Measurement Setup: The test leads are connected to the terminals of each winding, including the high-voltage (HV) winding, low-voltage (LV) winding, and any other auxiliary windings. Care should be taken to ensure proper connections and to account for any tap changer connections.
  4. Measurement: The resistance measurement is taken by applying a known test current to the winding and measuring the resulting voltage drop across the winding.
Interpretation of Results:

The measured winding resistance values are compared to the expected or baseline values. Deviations from the expected values may indicate various issues:

  1. Abnormal Resistance: Higher-than-expected resistance readings could indicate loose connections, high resistance joints, or increased winding resistance due to deterioration, corrosion, or damage.
  2. Significant Variation: Significant differences in resistance values between different phases or windings may suggest imbalances or anomalies that require further investigation.
  3. Consistency Check: The measured resistance values are compared with the transformer manufacturer's specifications or previous test results for consistency.
Oil Sample Testing

Overview

Purpose

Transformer oil serves critical functions in power transformers, acting as both an insulating material and a cooling medium. Testing transformer oil is essential to ensure its effectiveness in these roles, as it helps evaluate physical and chemical properties that are crucial for the transformer's performance and safety. Regular testing can detect contaminants and chemical changes in the oil, which may indicate issues like insulation breakdown, overheating, or other operational faults within the transformer.

Recommended Testing Schedule

  1. Initial and Commissioning Tests:

    2. Oil should be tested when the transformer is first installed to establish a baseline for future comparisons.

  2. Routine Monitoring:

    3. Annually Standard practice for transformers under typical operating conditions.

    Bi-annually or Quarterly: Recommended if previous tests show deteriorating oil conditions or the transformer is in a harsh operating environment.

  3. Following a Fault Events:

    4. Testing is crucial after incidents such as electrical faults or lightning strikes, as these can alter the oil's properties.

  4. Special Considerations:

    5. For critical transformers or those with a history of issues, testing might be required more frequently, such as every 3 to 6 months, to monitor conditions closely.

Acid Neutralization Number (ANN)

Purpose

The primary purpose of the ANN test is to monitor the degradation of transformer oil over time. As the oil ages, it can become contaminated with oxidation products, which increase its acidity. This rise in acid content can lead to the corrosion of metal parts and degradation of the paper insulation within the transformer, potentially leading to operational failures. Therefore, the test helps in preventive maintenance planning by indicating when the oil needs to be treated or replaced to maintain the transformer's reliability and efficiency.

Description

During the ANN test, a known quantity of transformer oil is titrated with a base (usually potassium hydroxide) to determine the amount of acid in the oil. The results are expressed in milligrams of KOH needed to neutralize the acids in one gram of oil, indicated as mg KOH/g. A higher Acid Neutralization Number suggests a greater presence of acidic compounds, indicating more severe oil degradation. Regular testing and monitoring allow for timely corrective actions, such as oil purification or replacement, to avoid costly repairs and downtime due to transformer damage.

Industry Standards

ASTM D974-Measures the acidity of petroleum products, including transformer oils, through color-indicator titration.

ANSI/IEEE C57.106 -Provides guidelines for the acceptance and maintenance of insulating oil in electrical equipment, advising on testing and maintenance practices to ensure equipment integrity.

IEC 62021-1-International standard specifically tailored for determining the acidity in insulating oils.

Test Result Standards:

New Oil: Should typically have an ANN of less than 0.1 mg KOH/g, indicating minimal acidity.

In-Service Oil: An ANN value of up to 0.2 mg KOH/g is generally acceptable; values beyond this suggest potential oil degradation.

Action Level: ANN values reaching or exceeding 0.5 mg KOH/g indicate significant degradation, necessitating immediate corrective actions such as oil treatment or replacement.

Color Test

Purpose

The main purpose of the Color Test is to assess the color of transformer oil as an indicator of its condition and suitability for continued use. This test is important because the color of transformer oil can change due to aging, oxidation, contamination, or the presence of by-products from thermal and electrical stresses. A darker color can indicate degradation or contamination, which may affect the oil's insulating and cooling properties.

Description

The Color Test is typically conducted by visually comparing the color of the oil sample to a standardized color chart or by using automated colorimeters that provide a precise measurement of color in terms of hue, saturation, and brightness. The test is simple: a sample of the transformer oil is placed in a clear container or special cuvette, and its color is then evaluated against standard color scales like the ASTM Color Scale.

Industry Standards

ASTM D1500- This standard describes the method for measuring the color of petroleum products by comparing them to a color scale under controlled lighting. The color is reported as a numerical value from 0.5 (very light) to 8.0 (very dark), providing a quantifiable measure of the oil's color.

Test Result Standards:

New Oil: New transformer oil typically has a very light color, usually around 0.5 to 1.0 on the ASTM color scale, indicating minimal impurities and good refining.

In-Service Oil: As the oil is used within a transformer, it can darken due to aging, oxidation, and the effects of heat and electrical stresses. Oils with a color rating up to 2.0 are generally considered acceptable, but any noticeable change from the new oil should be investigated.

Action Level: Transformer oils showing a color rating above 2.5 might indicate severe degradation or contamination, requiring further testing and potentially oil treatment or replacement. A dark color, especially nearing or exceeding 3.0, suggests urgent attention may be needed to prevent equipment damage or failure.

Dielectric Breakdown Voltage

Purpose

The main purpose of the Dielectric Breakdown Voltage test is to measure the ability of transformer oil to withstand electrical stress without failure. This test is crucial because transformer oil serves as both an insulator and a coolant. Over time, the oil can become contaminated with water, particles, and other impurities that significantly reduce its insulating properties. The Dielectric Breakdown Voltage test helps in assessing the quality and purity of the oil, thereby ensuring that it can effectively perform its insulating function.

Description

The Dielectric Breakdown Voltage test involves applying an AC voltage at a controlled rate to a sample of transformer oil between two electrodes. The voltage is increased until the oil fails electrically and allows current to pass through by arcing between the electrodes. The voltage at which this breakdown occurs is recorded as the dielectric breakdown voltage of the oil. The test is typically conducted under standard conditions to ensure consistency, with multiple tests performed on the same sample to establish a reliable breakdown voltage value.

Industry Standards

ASTM D877- A standard test method that uses a specific electrode configuration and test procedure to measure the dielectric breakdown voltage of insulating liquids.

ASTM D1816- Provides a more sensitive measurement using a smaller electrode gap and is generally used for oils where higher levels of impurity are suspected.

IEC 60156- An international standard that outlines procedures similar to ASTM but is widely adopted globally and may include specific variations tailored to regional testing practices.

Test Result Standards:

New Oil: Typically, new transformer oil should exhibit a dielectric breakdown voltage of at least 30 kV. This indicates good insulating properties suitable for effective transformer operation.

In-Service Oil: The acceptable minimum values can vary, but generally, a dielectric breakdown voltage below 25 kV may suggest that the oil is no longer effective as an insulating medium and requires further treatment or replacement.

Action Level: If the dielectric breakdown voltage falls below 20 kV, it is generally considered critical, and immediate actions such as oil filtration, degassing, or replacement are recommended to restore its insulating properties.

Dissolved Gas Analysis (DGA)

Purpose

The primary purpose of Dissolved Gas Analysis is to identify the presence and concentrations of specific gases dissolved in transformer oil that are produced by the decomposition of the oil and solid insulation under high temperature or electrical stress. By analyzing these gases, DGA can provide early warning signs of conditions such as overheating, arcing, and partial discharges within a transformer. This allows for preventative maintenance and can help avoid catastrophic failures and costly unplanned outages.

Description

During DGA, a sample of transformer oil is extracted and analyzed using gas chromatography or similar methods to quantify the presence of key gases such as hydrogen (H2), methane (CH4), ethane (C2H6), ethylene (C2H4), acetylene (C2H2), carbon monoxide (CO), and carbon dioxide (CO2). Each of these gases can indicate different types of faults or degradation processes within the transformer. For example, hydrogen and methane can indicate low-energy discharges or early-stage overheating, while acetylene is a marker for high-energy arcing.

Industry Standards

ASTM D3612- This standard provides various methods for performing dissolved gas analysis in electrical insulating oils by gas chromatography.

IEC 60567- An international standard that outlines the procedures for oil sampling and handling, gas extraction, and interpretation of dissolved gas analysis results in transformers.

Test Result Standards:

Normal Operation: Small amounts of gases such as nitrogen and oxygen are typically present due to the solubility of air in the oil. Low concentrations of fault gases can also be normal, depending on the transformer design and operating conditions.

Fault Conditions: Specific gas ratios and concentrations can indicate different types of fault conditions:

  • Partial Discharge: Characterized by elevated hydrogen and methane.
  • Thermal Faults: Identified by rising levels of methane, ethane, and ethylene, with specific temperature thresholds indicated by the ratios of these gases.
  • Arcing: Marked by the presence of acetylene and, in severe cases, also by significant amounts of hydrogen.

Action Levels: DGA results are often interpreted using the Duval Triangle or other diagnostic tools that help classify the type of fault and its severity based on the ratios of the dissolved gases. Actions can range from continued monitoring (for minor anomalies) to immediate operational changes or shutdowns (for severe or critical gas levels).

Interfacial Tension

Purpose

The primary purpose of the IFT test is to evaluate the condition of transformer oil by detecting the presence of oxidation by-products and other polar contaminants. A high interfacial tension indicates that the oil is in good condition with minimal contamination, while a lower interfacial tension suggests that the oil contains more polar compounds and may be nearing the end of its useful life.

Description

The IFT test is performed by measuring the force required to break the interface between the transformer oil and a water layer under controlled conditions. This is usually done using a tensiometer, which measures the force in dynes per centimeter (dyn/cm). The test involves placing a drop of transformer oil on the surface of distilled water in a special apparatus and gradually increasing the surface area until the oil-water interface breaks.

Industry Standards

ASTM D971- This standard describes the method for measuring the interfacial tension of oil against water by the ring method. It is commonly used to determine the presence of polar compounds which are typically oxidative degradation products.

IEC 62961- This international standard provides guidelines for the measurement of the interfacial tension of insulating oils, particularly focusing on the assessment of changes in interfacial tension as an indicator of oil degradation.

Test Result Standards:

New Oil: Typically, new transformer oil will have an interfacial tension of about 40 to 45 dynes/cm, indicating that the oil is relatively free of polar contaminants and suitable for use in electrical equipment.

In-Service Oil: As the transformer oil ages, its interfacial tension usually decreases. An IFT value above 30 dynes/cm is generally considered acceptable for in-service transformer oils. Regular monitoring helps track the degradation over time.

Action Level: If the IFT value falls below 25 dynes/cm, it suggests significant contamination and degradation. Oil with an IFT below 20 dynes/cm is generally considered unsuitable for continued use without treatment, and immediate action may be required to prevent damage to the transformer.

Power Factor (Dissipation Factor)

Purpose

The primary purpose of the Power Factor or Dissipation Factor test is to measure the dielectric losses in transformer oil, which indicate how much electrical energy is lost in the form of heat. This test provides insight into the condition of the oil, particularly its purity and degree of contamination by moisture, oxidation products, and other impurities that can affect its performance as an insulating medium.

Description

The test involves measuring the power factor (cos φ) or dissipation factor (tan δ) of the transformer oil at a specified temperature (usually 25°C or 100°C). These factors are measures of the dielectric loss angle in the insulating material and are calculated by applying an AC electric field to the oil in a test cell and measuring the resulting current. The power factor is the cosine of the phase angle between the applied voltage and the total current, while the dissipation factor is the tangent of this phase angle. Low values indicate good insulating properties, whereas higher values indicate greater contamination and reduced insulating effectiveness.

Industry Standards

ASTM D924- This standard describes the method for determining the dielectric constant and dissipation factor of electrical insulating liquids such as transformer oil. It provides detailed procedures for test cell setup, temperature control, and accurate measurement of these electrical properties.

IEC 60247- This international standard outlines methods for measuring the relative permittivity, dielectric dissipation factor, and DC resistivity of insulating liquids. It covers a range of test conditions and provides guidance on interpreting test results.

Test Result Standards:

New Oil: Typically, new transformer oil should have a power factor or dissipation factor of less than 0.5% at 25°C, indicating high insulating quality and minimal conductive or polar contaminants.

In-Service Oil: For in-service transformer oil, the power factor/dissipation factor should generally remain below 1.0% at 25°C. Values within this range suggest that the oil still maintains good insulating properties.

Action Level: If the power factor/dissipation factor exceeds 1.0% at 25°C, it may indicate significant contamination or degradation of the oil, necessitating further investigation, oil treatment, or replacement. Values significantly higher than this threshold can impair the transformer's performance and increase the risk of failure.

Specific Gravity

Purpose

The primary purpose of the Specific Gravity test is to determine the density of transformer oil, which affects how the oil behaves under temperature changes and its ability to effectively cool and insulate the transformer. Specific gravity also helps in identifying potential contamination with foreign substances that could alter the oil’s density and insulating properties.

Description

The Specific Gravity test measures the ratio of the density of transformer oil to the density of water at a specified temperature (usually 15°C or 25°C). This is done using a hydrometer, pycnometer, or density meter. The oil sample is placed in a test container, and its density is measured and compared to that of water. The result is a dimensionless number that indicates whether the oil is heavier or lighter than water.

Industry Standards

ASTM D1298- This standard outlines the method for determining the density, relative density (specific gravity), or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and non-petroleum products.

Test Result Standards:

New Oil: Typically, the specific gravity of new transformer oil ranges from about 0.875 to 0.895 at 15°C. These values indicate that the oil is lighter than water and has the appropriate physical properties for use in transformers.

In-Service Oil: The specific gravity of in-service transformer oil should not deviate significantly from the initial values. Stable specific gravity readings indicate that the oil maintains its original properties and effectiveness as a cooling and insulating medium.

Action Level: Significant changes in specific gravity may indicate contamination (e.g., water ingress, which increases specific gravity) or degradation (e.g., by-products from oxidation, which might alter density). If specific gravity deviates markedly from normal ranges, further investigation or oil treatment may be required to restore its properties or prevent equipment damage.

Moisture

Purpose

The primary purpose of the Moisture Content test is to measure the water content in transformer oil to ensure it remains within safe limits. Water in transformer oil reduces its dielectric strength, promotes the formation of acids, and accelerates the aging of both the oil and the paper insulation. Monitoring moisture levels helps in maintaining the effectiveness of the oil as an insulating medium and in preventing transformer failures.

Description

The Moisture Content test, also known as the Karl Fischer titration, is a quantitative chemical analysis method used to determine the exact amount of water in transformer oil. The test involves mixing a sample of the oil with a reagent that reacts specifically with water. The amount of reagent consumed is measured and directly correlates to the amount of water in the sample. The results are typically expressed in parts per million (ppm).

Industry Standards

ASTM D1533- This standard describes the test method for determining water in insulating liquids by Coulometric Karl Fischer titration. It is highly precise and suitable for measuring even low levels of moisture in transformer oil.

IEC 60814- This international standard outlines the method for determining water content in insulating liquids by automatic coulometric Karl Fischer titration. It is widely used for routine moisture content testing in transformer oils.

Test Result Standards:

New Oil: Typically, new transformer oil should contain less than 35 ppm of water to ensure optimal insulating properties and prevent any immediate risk to the transformer’s operation.

In-Service Oil: For in-service transformer oil, moisture content should ideally remain under 50 ppm. Consistent monitoring helps in detecting any rise in moisture levels that could signify leaks, condensation, or other issues affecting the transformer.

Action Level: Moisture levels exceeding 50 ppm in transformer oil are generally considered actionable, and levels above 100 ppm are deemed critical, requiring immediate attention. At these levels, the risk of insulation failure increases significantly, and measures such as oil dehydration or replacement might be necessary to restore the oil’s performance and protect the transformer.

Common Transformer Failures

Overview

Transformers are crucial components in the electrical power distribution and transmission networks, but they are prone to various types of failures due to their complex nature and operational stress. Understanding common transformer failures and the purpose and description of relevant diagnostic tests is essential for maintaining their reliability and extending their service life. Here are some common transformer failures and the corresponding tests used to diagnose and potentially prevent these issues:

Transformer Diagnostic Guide

Quick Reference

Over Temperature:
Over temperature can be caused by an overcurrent, overvoltage, insufficient cooling, low liquid level, and sludge in the transformer liquid, high ambient, or short- circuited core. In dry-type transformers, this condition can be due to clogged ducts.

Incorrect Secondary Voltage:
This condition can be due to improper turns ratio, abnormal primary voltage, and/or shorted turns in the transformer.

Core Failure:
This condition is due to the failure of core laminations, core, bolts, clamps, and so on.

Bushing Failure:
Bushing failure can be caused by flashover due to dirt accumulation and/or lightning strikes.

Internal Arcing:
Internal arcing can be caused by low liquid level exposing live parts of the transformer, loose connections, or failure of the transformer dielectric. Usually, internal arcing can become audible and cause radio interference.

Pressure-Relief Diaphragm Broken:
This is due to an internal fault causing excessive internal pressures or the transformer liquid level being too high or excessive internal pressure due to loading of transformer.

Winding Insulation Failure:
This is an electrical fault in the transformer winding insulation where it can involve phase to ground, phase to phase, three phase and/or ground, or turn- to-turn type short-circuit. The causes for this type of failure may be due to a short-circuit fault, lightning, overload or overcurrent condition, or transformer liquid containing moisture and contaminants.

High Exciting Current:
Usually, high exciting currents are due to short-circuited core and/or open core joints.

Low Dielectric Strength:
This condition can be caused by condensation and penetration of moisture due to improper ventilation, broken relief diaphragm, leaks around transformer accessories, or cooling coil leakage.

Oxidation of Oil:
Oxidation usually results in the formation of acids and sludge in the transformer liquid. It is mainly due to exposure to air and high operating temperatures.

Insulation Breakdown

Description:
Insulation breakdown occurs when the electrical insulation material within the transformer can no longer withstand the electrical stress, leading to a short circuit or arcing. This can be due to aging, overheating, mechanical damage, or contamination, often resulting in catastrophic failure and potential fire hazards.

Solid Insulation:
Solid insulation, comprised of cellulose-based materials like pressboard and paper, is utilized between transformer windings to ensure electrical isolation. Cellulose is made up of long chains of glucose rings, which degrade over time, resulting in shorter chains. The condition of the paper insulation is assessed by its degree of polymerization (DP), which represents the average number of glucose rings per chain. Fresh paper typically has a DP value between 1200 and 1400, whereas a DP value below 200 indicates significantly weakened mechanical strength. This reduction in strength can compromise the paper's ability to withstand mechanical stresses such as those from short circuits.

This type of solid insulation is particularly vulnerable to mechanical damage, which can occur from transformer movement or forces generated during short circuits. Additionally, faults in the insulation material might arise from the formation of copper sulfate (CuSO4) or from hot spots, which can develop due to insufficient oil levels or transformer overloading.

Diagnostic Tests:
Dielectric breakdown voltage test and insulation resistance test.

Example:
A utility company regularly performs insulation resistance testing on transformers before the summer peak loads to prevent unexpected failures due to increased demand.

Winding Failures

Causes:

  1. External faults Overheating
  2. short circuits between turns,
  3. Open winding Deterioration
  4. Phase-to-phase faults Mechanical failures
  5. Moisture
  6. Terminal Board Failures Turn-to turn failures Surges
  7. Improper blocking of turns Grounds

Diagnostic Tests:
Transformer Turns Ratio (TTR) test and Sweep Frequency Response Analysis (SFRA).

Overheating

Description:
Overheating in transformers can occur due to excessive load, poor cooling, or ambient temperature conditions that exceed design specifications, accelerating the aging of insulation materials.

Diagnostic Tests:
Thermographic inspections and oil analysis for dissolved gases.

Thermographic cameras used during routine maintenance can identified hot spots on the transformer casing, indicating potential overheating issues.

Bushing Failure

Causes:

  1. Aging of the insulation
  2. Cracking
  3. Contamination
  4. Flashover due to animals Flashover due to surges Moisture
  5. Low oil or Fluid

Diagnostic Tests:
Power factor or dissipation factor testing and capacitance measurements.

Example:
Dissipation factor testing conducted during a routine inspection detected deteriorating insulation health in several bushings, prompting their replacement.

Core Faults

Causes:

  1. Core insulation failures
  2. Shorted laminations
  3. Loose clamps, bolts, and wedges
  4. Ground strap broken
  5. Ground Issues (increased noise, vibration, and eddy current losses.)

Diagnostic Tests:
Core ground test and SFRA.

Example:
Unusual noise and vibrations from a transformer were traced back to core lamination faults using core ground testing.

Oil Contamination

Description:
Contamination of transformer oil by moisture, particles, or gases can lead to a loss of insulating properties.

Transformer Oil:
Transformer oil, a highly refined mineral crude oil product, plays a crucial role in providing insulation between windings and cooling within transformers. This oil is composed of various hydrocarbons, including paraffin, naphthalene, and aromatic oils.

Cooling oil failures typically arise from two primary issues: malfunctioning oil circulation systems or inadequate heat transfer to the secondary cooling circuit. These problems can lead to increased oil viscosity and excessively high temperatures in the secondary cooling circuit.

Additionally, the combination of moisture and oxygen with heat significantly contributes to oil contamination, which can produce conducting particles. As a result, the internal temperature of the transformer may rise, compromising the oil's insulating properties and potentially leading to a short circuit.

Diagnostic Tests:
Dissolved Gas Analysis (DGA) and moisture content tests.

Example:
DGA revealed high levels of acetylene and hydrogen gases, indicating internal arcing due to contaminated oil in a high-voltage transformer.

Mechanical Damage

Description:
Mechanical damage can occur from mishandling, installation errors, or environmental factors such as earthquakes.

Mechanical factors can cause significant damage to transformer windings, potentially rupturing the solid insulation and leading to electrical failure. Damage to transformer windings may occur due to electromechanical forces or during shipping. Additional reasons for transformer failures include:

  1. Electromagnetic forces
  2. Issues encountered during the shipping of the transforme
  3. Buckling of the innermost winding
  4. Tipping of conductors
  5. Telescoping of conductors
  6. Tightening of spirals
  7. Crushing of end rings
  8. Failure of the coil clamping system
  9. Displacement of transformer leads

Diagnostic Tests:
Visual inspections and mechanical integrity tests.

Example:
After a minor earthquake, visual inspections revealed structural damages to the transformer tank, necessitating detailed assessments and repairs.

External Short Circuits

Description:
External short circuits due to faults in connected equipment result in excessive current flow, damaging windings and insulation.

Diagnostic Tests:
Protective relay testing and system analysis.

Example:
System analysis after a fault event on a connected power line helped in quickly isolating and addressing an external short circuit affecting a transformer.

Tap Changer Failures

Causes:

  1. Failures in on-load tap changers (OLTC) due to wear
  2. Loose connections Leads (open)
  3. Links
  4. oil contamination
  5. improper voltage regulation
  6. Moisture
  7. Insufficient insulation Tracking Short-circuits

Diagnostic Tests:
Dynamic resistance measurements and OLTC analyzer tests.

Example:
Routine dynamic resistance measurements identified irregular patterns in an OLTC, suggesting worn contacts that were replaced to avoid voltage regulation issues.

NETA Test Procedure

NETA ATS

7.2.1.1 Transformers, Dry Type, Air-Cooled, Low-Voltage, Small

NOTE: This category consists of power transformers with windings rated 600 volts or less and sizes equal to or
less than 167 kVA single-phase or 500 kVA three-phase.
A. Visual and Mechanical Inspection:
  1. Compare equipment nameplate data with drawings and specifications.
  2. Inspect physical and mechanical condition..
  3. Inspect anchorage, alignment, and grounding.
  4. Verify that resilient mounts are free and that any shipping brackets have been removed.
  5. Inspect bolted electrical connections for high resistance using one or more of the following methods:
    1. Use of a low-resistance ohmmeter in accordance with Section 7.2.1.1.B.1.
    2. Verify tightness of accessible bolted electrical connections by calibrated torque-wrench method in accordance with manufacturer’s published data or Table 100.12.
    3. Perform thermographic survey in accordance with Section 9.
  6. Verify that as-left tap connections are as specified.
B. Electrical Tests:
  1. Perform resistance measurements through bolted connections with a low-resistance ohmmeter, if applicable, in accordance with Section 7.2.1.1.A.6.1.
  2. Perform insulation-resistance tests winding-to-winding and each winding-to-ground. Apply voltage in accordance with manufacturer’s published data or in the absence of manufacturer’s published data, use Table 100.5. Calculate polarization index.
  3. *Perform turns-ratio tests at all tap positions.
  4. Verify correct secondary voltage phase-to-phase and phase-to-neutral after energization and prior to loading.
C. Test Values – Visual and Mechanical
  1. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value. (7.2.1.1.A.6.1)
  2. Bolt-torque levels shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.12. (7.2.1.1.A.6.2)
  3. Results of the thermographic survey shall be in accordance with Section 9. (7.2.1.1.1.6.3)
  4. Tap connections are left as found unless otherwise specified. (7.2.1.1.A.7)
D. Test Values – Electrical
  1. Compare bolted electrical connection resistances to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value.
  2. Minimum insulation-resistance values of transformer insulation shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Values of insulation resistance less than this table or manufacturer’s recommendations should be investigated. The polarization index shall not be less than 1.0.
  3. Turns-ratio test results shall not deviate by more than one-half percent from either the adjacent coils or the calculated ratio.
  4. Phase-to-phase and phase-to-neutral secondary voltages shall be in agreement with nameplate data.

NETA ATS

7.2.1.2 Transformers, Dry Type, Air-Cooled, Large

NOTE: This category consists of power transformers with windings rated higher than 600 volts and low-voltage transformers larger than 167 kVA single-phase or 500 kVA three-phase.
A. Visual and Mechanical Inspection:
  1. Compare equipment nameplate data with drawings and specifications.
  2. Inspect physical and mechanical condition..
  3. Inspect anchorage, alignment, and grounding.
  4. Verify that resilient mounts are free and that any shipping brackets have been removed..
  5. Verify the unit is clean.
  6. *Verify that control and alarm settings on temperature indicators are as specified.
  7. Verify that cooling fans operate and that fan motors have correct overcurrent protection.
  8. Inspect bolted electrical connections for high resistance using one or more of the following methods:
    1. Use of a low-resistance ohmmeter in accordance with Section 7.2.1.2.B.1.
    2. Verify tightness of accessible bolted electrical connections by calibrated torque-wrench method in accordance with manufacturer’s published data or Table 100.12.
    3. Perform thermographic survey in accordance with Section 9.
  9. Perform specific inspections and mechanical tests as recommended by the manufacturer.
  10. Verify that as-left tap connections are as specified.
  11. Verify the presence of surge arresters.
B. Electrical Tests:
  1. Perform resistance measurements through bolted connections with a low-resistance ohmmeter, if applicable, in accordance with Section 7.2.1.2.A.8.1.
  2. Perform insulation-resistance tests winding-to-winding and each winding-to-ground. Apply voltage in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Calculate polarization index.
  3. Perform power-factor or dissipation-factor tests on all windings in accordance with the test equipment manufacturer’s published data.
  4. *Perform a power-factor or dissipation-factor tip-up test on windings greater than 2.5 kV.
  5. Perform turns-ratio tests at all tap positions.
  6. *Perform an excitation-current test on each phase.
  7. *Measure the resistance of each winding at each tap connection.
  8. Measure core insulation resistance at 500 volts dc if the core is insulated and the core ground strap is removable.
  9. *Perform an applied voltage test on all high- and low-voltage windings-to-ground. See ANSI/IEEE C57.12.91, Sections 10.2 and 10.9.
  10. Verify correct secondary voltage, phase-to-phase and phase-to-neutral, after energization and prior to loading.
  11. Test surge arresters in accordance with Section 7.19.
C. Test Values – Visual and Mechanical
  1. Control and alarm settings on temperature indicators shall operate within manufacturer’s recommendations for specified settings. (7.2.1.2.A.6)
  2. Cooling fans shall operate. (7.2.1.2.A.7)
  3. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value. (7.2.1.2.A.8.1)
  4. Bolt-torque levels shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.12. (7.2.1.2.A.8.2)
  5. Results of the thermographic survey shall be in accordance with Section 9. (7.2.1.2.A.8.3)
  6. Tap connections shall be left as found unless otherwise specified. (7.2.1.2.A.10)
D. Test Values – Electrical
  1. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value.
  2. Minimum insulation-resistance values of transformer insulation shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Values of insulation resistance less than this table or manufacturer’s recommendations should be investigated. The polarization index shall not be less than 1.0.
  3. The following values are typical for insulation power factor tests:
    1. CHL Power transformers: 2.0 percent or less
    2. CHL Distribution transformers: 5.0 percent or less
    3. CH and CL power-factor or dissipation-factor values will vary due to support insulators and bus work utilized on dry transformers. Consult transformer manufacturer’s or test equipment manufacturer’s data for additional information.
  4. Power-factor or dissipation-factor tip-up exceeding 1.0 percent shall be investigated.
  5. Turns-ratio test results shall not deviate more than one-half percent from either the adjacent coils or the calculated ratio.
  6. The typical excitation current test data pattern for a three-legged core transformer is two similar current readings and one lower current reading.
  7. Temperature-corrected winding-resistance values shall compare within one percent of previously-obtained results.
  8. Core insulation-resistance values shall not be less than one megohm at 500 volts dc.
  9. AC dielectric withstand test voltage shall not exceed 75 percent of factory test voltage for one minute duration. DC dielectric withstand test voltage shall not exceed 100 percent of the ac rms test voltage specified in ANSI C57.12.91, Section 10.2 for one minute duration. If no evidence of distress or insulation failure is observed by the end of the total time of voltage application during the dielectric withstand test, the test specimen is considered to have passed the test.
  10. Phase-to-phase and phase-to-neutral secondary voltages shall be in agreement with nameplate data.
  11. Test results for surge arresters shall be in accordance with Section 7.19.

NETA ATS

7.2.2 Transformers, Liquid-Filled

A. Visual and Mechanical Inspection:
  1. Compare equipment nameplate data with drawings and specifications.
  2. Inspect physical and mechanical condition.
  3. Inspect impact recorder prior to unloading.
  4. *Test dew point of tank gases
  5. Inspect anchorage, alignment, and grounding.
  6. Verify the presence of PCB content labeling.
  7. Verify removal of any shipping bracing after placement.
  8. Verify the bushings are clean.
  9. Verify that alarm, control, and trip settings on temperature and level indicators are as specified.
  10. Verify operation of alarm, control, and trip circuits from temperature and level indicators, pressure relief device, gas accumulator, and fault pressure relay.
  11. Verify that cooling fans and pumps operate correctly and have appropriate overcurrent protection.
  12. Inspect bolted electrical connections for high resistance using one or more of the following methods:
    1. Use of a low-resistance ohmmeter in accordance with Section 7.2.2.B.1.
    2. Verify tightness of accessible bolted electrical connections by calibrated torque-wrench method in accordance with manufacturer’s published data or Table 100.12.
    3. Perform thermographic survey in accordance with Section 9.
  13. Verify correct liquid level in tanks and bushings.
  14. Verify valves are in the correct operating position.
  15. Verify that positive pressure is maintained on gas-blanketed transformers.
  16. Perform inspections and mechanical tests as recommended by the manufacturer.
  17. Test load tap-changer in accordance with Section 7.12.3.
  18. Verify presence of transformer surge arresters.
  19. Verify de-energized tap-changer position is left as specified.
B. Electrical Tests:
  1. Perform resistance measurements through bolted connections with a low-resistance ohmmeter if applicable, in accordance with Section 7.2.2.A.12.1.
  2. "Perform insulation-resistance tests, winding-to-winding and each winding-to-ground. Apply voltage in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Calculate polarization index."
  3. Perform turns-ratio tests at all tap positions.
  4. Perform insulation power-factor or dissipation-factor tests on all windings in accordance with test equipment manufacturer’s published data.
  5. "Perform power-factor or dissipation-factor tests on each bushing equipped with a power-factor/ capacitance tap. In the absence of a power-factor/ capacitance tap, perform hot-collar tests. These tests shall be in accordance with the test equipment manufacturer’s published data."
  6. Perform excitation-current tests in accordance with test equipment manufacturer’s published data.
  7. "Measure the resistance of each high-voltage winding in each de-energized tap-changer position. Measure the resistance of each low-voltage winding in each de-energized tap- changer position."
  8. *Perform leakage reactance three phase equivalent and per phase tests.
  9. *If core ground strap is accessible, remove and measure core insulation resistance at 500 volts dc.
  10. *Measure the percentage of oxygen in the gas blanket.
  11. Remove a sample of insulating liquid in accordance with ASTM D 923. Sample shall be tested for the following.
    1. Dielectric breakdown voltage: ASTM D 877 and/or ASTM D 1816
    2. Acid neutralization number: ANSI/ASTM D 974
    3. *Specific gravity: ANSI/ASTM D 1298
    4. Interfacial tension: ANSI/ASTM D 971
    5. Color: ANSI/ASTM D 1500
    6. Visual Condition: ASTM D 1524
    7. Water in insulating liquids: ASTM D 1533.
    8. *Power factor or dissipation factor in accordance with ASTM D 924.
  12. Remove a sample of insulating liquid in accordance with ASTM D923 and perform dissolved-gas analysis (DGA) in accordance with ANSI/IEEE C57.104 or ASTM D3612.
  13. Test instrument transformers in accordance with Section 7.10.
  14. Test surge arresters in accordance with Section 7.19, if present.
  15. Test transformer neutral grounding impedance device, if present.
  16. Verify operation of cubicle or air terminal compartment space heaters.
C. Test Values – Visual and Mechanical
  1. Alarm, control, and trip circuits from temperature and level indicators as well as pressure relief device and fault pressure relay shall operate within manufacturer’s recommendations for their specified settings. (7.2.2.A.10)
  2. Cooling fans and pumps shall operate. (7.2.2.A.11)
  3. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value. (7.2.2.A.12.1)
  4. Bolt-torque levels shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.12. (7.2.2.A.12.2)
  5. Results of the thermographic survey shall be in accordance with Section 9. (7.2.2.A.12.3)
  6. Liquid levels in the transformer tanks and bushings shall be within indicated tolerances. (7.2.2.A.13)
  7. Positive pressure shall be indicated on pressure gauge for gas-blanketed transformers. (7.2.2.A.15)
D. Test Values – Electrical
  1. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value.
  2. Minimum insulation-resistance values of transformer insulation shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Values of insulation resistance less than this table or manufacturer’s recommendations should be investigated. The polarization index shall not be less than 1.0.
  3. Turns-ratio test results shall not deviate by more than one-half percent from either the adjacent coils or the calculated ratio.
  4. Maximum winding insulation power-factor/dissipation-factor values of liquid-filled transformers shall be in accordance with the manufacturer’s published data. In the absence of manufacturer’s published data use Table 100.3. Distribution transformer power factor results shall compare to previously obtained results.
  5. Investigate bushing power-factor values that vary from nameplate values by more than 150 percent. Investigate bushing capacitance values that vary from nameplate values by more than five percent. Investigate bushing hot-collar test values that exceed 0.1 Watts.
  6. Typical excitation-current test data pattern for a three-legged core transformer is two similar current readings and one lower current reading.
  7. Sweep frequency response analysis test results should compare to factory and previous test results.
  8. Consult the manufacturer if winding-resistance test values vary by more than two percent from factory test values or between adjacent phases.
  9. Investigate leakage reactance per phase test results that deviate from the average of the three readings by more than 3%. The three phase equivalent test results serve as a benchmark for future tests.
  10. Core insulation values shall be compared to the factory test value but not less than one megohm at 500 volts dc.
  11. Investigate the presence of oxygen in the nitrogen gas blanket.
  12. Insulating liquid values shall be in accordance with Table 100.4.
  13. Evaluate results of dissolved-gas analysis in accordance with ANSI/IEEE Standard C57.104.
  14. Results of electrical tests on instrument transformers shall be in accordance with Section 7.10.
  15. Results of surge arrester tests shall be in accordance with Section 7.19.
  16. Compare grounding impedance device values to manufacturer’s published data.
  17. Heaters shall be operational.

NETA MTS

7.2.1.1 Transformers, Dry Type, Air-Cooled, Low-Voltage, Small

NOTE: This category consists of power transformers with windings rated 600 volts or less and sizes equal to or less than 167 kVA single-phase or 500 kVA three-phase.
A. Visual and Mechanical Inspection:
  1. Inspect physical and mechanical condition.
  2. Inspect anchorage, alignment, and grounding.
  3. Prior to cleaning the unit, perform as-found tests, if required.
  4. VClean the unit.
  5. Inspect bolted electrical connections for high resistance using one or more of the following methods:
    1. Use of a low-resistance ohmmeter in accordance with Section 7.2.1.1.B.1.
    2. Verify tightness of accessible bolted electrical connections by calibrated torque-wrench method in accordance with manufacturer’s published data or Table 100.12.
    3. Perform thermographic survey in accordance with Section 9.
  6. Perform as-left tests..
  7. Verify that as-left tap connections are as specified.
B. Electrical Tests:
  1. Perform resistance measurements through bolted connections with a low-resistance ohmmeter, if applicable, in accordance with Section 7.2.1.1.A.5.1.
  2. Perform insulation-resistance tests winding-to-winding and each winding-to-ground. Apply voltage in accordance with manufacturer’s published data or in the absence of manufacturer’s published data, use Table 100.5. Calculate polarization index.
  3. *Perform turns-ratio tests at all tap positions.
C. Test Values – Visual and Mechanical
  1. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value. (7.2.1.1.A.5.1)
  2. Bolt-torque levels shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.12. (7.2.1.1.A.5.2)
  3. Results of the thermographic survey shall be in accordance with Section 9. (7.2.1.1.A.5.3)
  4. Tap connections are left as found unless otherwise specified. (7.2.1.1.A.7)
D. Test Values – Electrical
  1. Compare bolted electrical connection resistances to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value.
  2. Minimum insulation-resistance values of transformer insulation shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Values of insulation resistance less than this table or manufacturer’s recommendations should be investigated. The polarization index shall not be less than 1.0.
  3. Turns-ratio test results shall not deviate by more than one-half percent from either the adjacent coils or the calculated ratio.

NETA MTS

7.2.1.2 Transformers, Dry Type, Air-Cooled, Large

NOTE: This category consists of power transformers with windings rated higher than 600 volts and low-voltage transformers larger than 167 kVA single-phase or 500 kVA three-phase.
A. Visual and Mechanical Inspection:
  1. Inspect physical and mechanical condition..
  2. Inspect anchorage, alignment, and grounding.
  3. Prior to cleaning the unit, perform as-found tests, if required.
  4. Clean the unit.
  5. *Verify that control and alarm settings on temperature indicators are as specified.
  6. Verify that cooling fans operate correctly.
  7. Inspect bolted electrical connections for high resistance using one or more of the following methods:
    1. Use of a low-resistance ohmmeter in accordance with Section 7.2.1.2.B.1.
    2. Verify tightness of accessible bolted electrical connections by calibrated torque-wrench method in accordance with manufacturer’s published data or Table 100.12.
    3. Perform thermographic survey in accordance with Section 9.
  8. Perform specific inspections and mechanical tests as recommended by the manufacturer.
  9. Perform as-left tests.
  10. Verify that as-left tap connections are as specified.
  11. Verify the presence of surge arresters.
B. Electrical Tests:
  1. Perform resistance measurements through bolted connections with a low-resistance ohmmeter, if applicable, in accordance with Section 7.2.1.2.A.7.1.
  2. Perform insulation-resistance tests winding-to-winding and each winding-to-ground. Apply voltage in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Calculate polarization index.
  3. Perform insulation power-factor or dissipation-factor tests on all windings in accordance with the test equipment manufacturer’s published data.
  4. *Perform a power-factor or dissipation-factor tip-up test on windings rated greater than 2.5 kV.
  5. Perform turns-ratio tests at the designated tap position.
  6. *Perform an excitation-current test on each phase.
  7. *Measure the resistance of each winding at the designated tap position.
  8. Measure core insulation resistance at 500 volts dc if the core is insulated and if the core ground strap is removable.
  9. *Perform an applied voltage test on all high- and low-voltage windings-to-ground. See IEEE C57.12.91-2001, Sections 103.
  10. Verify correct secondary voltage phase-to-phase and phase-to-neutral after energization and prior to loading.
  11. Test surge arresters in accordance with Section 7.19.
  12. *Perform online partial-discharge survey on winding rated higher than 600 volts in accordance with Section 11.
C. Test Values – Visual and Mechanical
  1. Control and alarm settings on temperature indicators shall operate within manufacturer’s recommendations for specified settings. (7.2.1.2.A.5)
  2. Cooling fans shall operate. (7.2.1.2.A.6)
  3. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value. (7.2.1.2.A.7.1)
  4. Bolt-torque levels shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.12. (7.2.1.2.A.7.2)
  5. Results of the thermographic survey shall be in accordance with Section 9.(7.2.1.2.A.7.3)
  6. Tap connections shall be left as found unless otherwise specified. (7.2.1.2.A.10)
D. Test Values – Electrical
  1. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value.
  2. Minimum insulation-resistance values of transformer insulation shall be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Values of insulation resistance less than this table or manufacturer’s recommendations should be investigated. The polarization index shall not be less than 1.0.
  3. The following values are typical for insulation power factor tests:
    1. CHL Power transformers: 2.0 percent or less
    2. CHL Distribution transformers: 5.0 percent or less
    3. CH and CL power-factor or dissipation-factor values will vary due to support insulators and bus work utilized on dry transformers. Consult transformer manufacturer’s or test equipment manufacturer’s data for additional information.
  4. Power-factor or dissipation-factor tip-up exceeding 1.0 percent shall be investigated.
  5. Turns-ratio test results shall not deviate more than one-half percent from either the adjacent coils or the calculated ratio.
  6. The typical excitation current test data pattern for a three-legged core transformer is two similar current readings and one lower current reading.
  7. Temperature-corrected winding-resistance values shall compare within one percent of previously-obtained results.
  8. Core insulation-resistance values shall not be less than one megohm at 500 volts dc.
  9. AC dielectric withstand test voltage shall not exceed 65 percent of factory test voltage for one minute duration. DC dielectric withstand test voltage shall not exceed 100 percent of the ac rms test voltage specified in IEEE C57.12.91, Section 10.2 for one minute duration. If no evidence of distress or insulation failure is observed by the end of the total time of voltage application during the dielectric withstand voltage test, the test specimen is considered to have passed the test.
  10. Phase-to-phase and phase-to-neutral secondary voltages shall be in agreement with nameplate data.
  11. Test results for surge arresters shall be in accordance with Section 7.19.
  12. Results of online partial-discharge survey should be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, refer to Table 100.23.

NETA MTS

7.2.1.2 Transformers, Dry Type, Air-Cooled, Large

A. Visual and Mechanical Inspection:
  1. Inspect physical and mechanical condition..
  2. Inspect anchorage, alignment, and grounding.
  3. Prior to cleaning the unit, perform as-found tests, if required.
  4. Clean bushings and control cabinets.
  5. Verify operation of alarm, control, and trip circuits from temperature and level indicators, pressure-relief device, gas accumulator, and fault-pressure relay.
  6. Verify that cooling fans and/or pumps operate correctly.
  7. Inspect bolted electrical connections for high resistance using one or more of the following methods:
    1. Use of a low-resistance ohmmeter in accordance with Section 7.2.1.2.B.1.
    2. Verify tightness of accessible bolted electrical connections by calibrated torque-wrench method in accordance with manufacturer’s published data or Table 100.12.
    3. Perform thermographic survey in accordance with Section 9.
  8. Verify correct liquid level in tanks and bushings.
  9. Verify that positive pressure is maintained on gas-blanketed transformers.
  10. Perform inspections and mechanical tests as recommended by the manufacturer.
  11. Test load tap-changer in accordance with Section 7.12.
  12. Verify the presence of transformer surge arresters.
  13. Perform as-left tests.
  14. Verify de-energized tap-changer position is left as specified.
B. Electrical Tests:
  1. Perform resistance measurements through bolted connections with a low-resistance ohmmeter in accordance with Section 7.2.2.A.8.1.
  2. Perform insulation-resistance tests, winding-to-winding and each winding-to-ground. Apply voltage in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Calculate polarization index.
  3. Perform turns-ratio tests at the designated tap position.
  4. Perform insulation power-factor or dissipation-factor tests on all windings in accordance with test equipment manufacturer’s published data.
  5. Perform power-factor or dissipation-factor tests on each bushing equipped with a powerfactor/ capacitance tap. In the absence of a power-factor/capacitance tap, perform hot-collar tests. These tests shall be in accordance with the test equipment manufacturer’s published data.
  6. Perform excitation-current tests in accordance with the test equipment manufacturer’s published data.
  7. *Perform sweep frequency response analysis tests.
  8. Measure the resistance of each winding at the designated tap position.
  9. *If the core ground strap is accessible, remove and measure the core insulation resistance at 500 volts dc.
  10. *Measure the percentage of oxygen in the gas blanket.
  11. Remove a sample of insulating liquid in accordance with ASTM D923. The sample shall be tested for the following.
    1. Dielectric breakdown voltage: ASTM D 877 and/or ASTM D 1816
    2. Acid neutralization number: ANSI/ASTM D 974
    3. *Specific gravity: ANSI/ASTM D 1298
    4. Interfacial tension: ANSI/ASTM D 971
    5. Color: ANSI/ASTM D 1500
    6. Visual Condition: ASTM D 1524
    7. Water in insulating liquids: ASTM D 1533.
    8. *Measure power factor or dissipation factor in accordance with ASTM D924
  12. Remove a sample of insulating liquid in accordance with ASTM D3613 and perform dissolved-gas analysis (DGA) in accordance with IEEE C57.104 or ASTM D3612.
  13. Test the instrument transformers in accordance with Section 7.10.
  14. Test the surge arresters in accordance with Section 7.19.
  15. Test the transformer neutral grounding impedance devices.
C. Test Values – Visual and Mechanical
  1. Alarm, control, and trip circuits from temperature and level indicators as well as pressure relief device and fault pressure relay should operate within manufacturer’s recommendations for their specified settings. (7.2.2.A.6)
  2. Cooling fans and/or pumps should operate. (7.2.2.A.7)
  3. "Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value. (7.2.2.A.8.1)"
  4. Bolt-torque levels should be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.12. (7.2.2.A.8.2)
  5. Results of the thermographic survey shall be in accordance with Section 9. (7.2.2.A.8.3)
  6. Liquid levels in the transformer tanks and bushings should be within indicated tolerances. (7.2.2.A.9)
  7. Positive pressure should be indicated on pressure gauge for gas-blanketed transformers. (7.2.2.A.10)
D. Test Values – Electrical
  1. Compare bolted connection resistance values to values of similar connections. Investigate values which deviate from those of similar bolted connections by more than 50 percent of the lowest value.
  2. Minimum insulation-resistance values of transformer insulation should be in accordance with manufacturer’s published data. In the absence of manufacturer’s published data, use Table 100.5. Values of insulation resistance less than this table or manufacturer’s recommendations should be investigated. The polarization index shall be compared to previously obtained results and should not be less than 1.0.
  3. Turns-ratio test results should not deviate by more than one-half percent from either the adjacent coils or the calculated ratio.
  4. Maximum power-factor/dissipation-factor values of liquid-filled transformers corrected to 20° C should be in accordance with the transformer manufacturer’s published data. Representative values are indicated in Table 100.3.
  5. Investigate bushing power-factor values that vary from nameplate values by more than 50 percent. Investigate bushing capacitance values that vary from nameplate values by more than five percent. Investigate bushing hot-collar test values that exceed 0.1 Watts.
  6. Typical excitation-current test data pattern for a three-legged core transformer is two similar current readings and one lower current reading.
  7. Sweep frequency response analysis test results should compare to factory and previous test results.
  8. Temperature corrected winding-resistance values should compare within two percent of previously obtained results.
  9. Core insulation values should be comparable to previously obtained results but not less than one megohm at 500 volts dc.
  10. Investigate the presence of oxygen in the nitrogen gas blanket.
  11. Insulating liquid values should be in accordance with Table 100.4.
  12. Evaluate results of dissolved-gas analysis in accordance with IEEE C57.104.
  13. Results of electrical tests on instrument transformers shall be in accordance with Section 7.10.
  14. Results of surge arrester tests shall be in accordance with Section 7.19.
  15. Compare grounding impedance device values to previously obtained results. In the absence of previously obtained values, compare obtained values to manufacturer’s published data.
NETA ATS / MTS
TABLE 100.5
Neta Table 100.5
NETA ATS / MTS
Neta Table 100.5
Neta Table 100.5