Transformers Condition Assessment | Transformer Maintenance

  1. Scope
  2. Conflicts and Deviations
  3. References
  4. Instructions
  5. Responsibilities
  6. Technical Procedures
  7. TCA Scoring Methodology
  8. Transformer Alternatives

Appendix A – Transformer Condition Assessment Summary – Figure A.1
Appendix B – Transformer Condition Assessment Summary
Appendix C – Oil Screening Survey Form
Appendix D – TCA Survey Form
Appendix E – Transformer Condition-Based Alternatives
Appendix F – IR Analysis Example
Appendix G – Transformer Remaining Lifetime Estimation

Transformers Condition Assessment | Transformer Maintenance

1. Transfer Condition Assessment Scope

This article provides guidelines for conducting Transformer Condition Assessments (TCA) on transformers currently in operation. The guidelines provide a method for determining a TCA Score from the results of specified transformer
inspections, testing, and measurements which can then be utilized to select various transformer condition based alternatives.

Figure 1 shows that the company’s power transformers fleet has 230 units designated as critical, ranging between 20 MVA and 100 MVA, in which the majority is beyond 30 years of operation.

The Transfer Condition Assessment methodology applies to oil-filled transformers 25 MVA oil-natural-air-natural (ONAN) or larger and other transformers designated as critical. Critical power transformers are clarified as generator step-up transformers, motor captive transformers, single-ended substation transformers, and any other transformers designated as critical.

The Transfer Condition Assessment (TCA) may be undertaken upon request of the operating organization once a power transformer reaches 25 years of age, or following a major operational incident. This article help the transformer owner in making life cycle decisions such as whether repair, or replacement, or any required action to extend the life of aged power transformers. This document should be utilized in conjunction with SABP-P-009 “Power Transformer Diagnostics” and
SABP-P-016 “Power Transformer Maintenance.”

Figure 1 – Power Transformers Population Companywide

3. TCA References

This procedure is based on the below referenced standard:

Industry Codes and Standards
American National Standards Institute
IEEE Std C57.140-2006 IEEE Guide for the Evaluation and Reconditioning of Liquid Immersed Power Transformers.
IEEE PC57.139 DRAFT IEEE Guide for Dissolved Gas Analysis of Load Tap Changers.
IEEE PC57.143 DRAFT IEEE Guide for Application of Monitoring to Liquid-Immersed Transformers and Components.
IEEE Std C57.12.90 IEEE Standard Test Code for Liquid-Immersed Distribution, Power, and Regulating Transformers.
IEEE C57.113 IEEE Guide for Partial Discharge Measurement in Liquid-Filled Power Transformers and Shunt Reactors).

IEEE Std C57.91 IEEE Guide for Loading Mineral-Oil-Immersed Transformers.
IEEE Std C57.93 IEEE Guide for Installation of Liquid-Immersed Power Transformers.
IEEE Std C57.106 IEEE Guide for Acceptance and Maintenance of Insulating Oil in Equipment.
IEEE Std 637 IEEE Guide for the Reclamation of Insulating Oil and Criteria for Its Use.

ASTM D3612 Standard Test Method for Analysis of Gases Dissolved in Electrical Insulating Oils by Gas Chromatography.
ASTM D3613 Standard Test Methods of Sampling Electrical Insulating Oils for Gas Analysis and Determination of Water Content.
IEC 60599 Mineral Oil-Impregnated Electrical Equipment in Service – Guide to the Interpretation of Dissolved and Free Gases Analysis.
ANSI C57.12.00 Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers.
ANSI C57.12.10 American National Standard for Transformers 230 kV and below 833/958 through 8333/10,417 kVA, Single-Phase, and 750/862 through 60,000/80,000/100,000 kVA, Three-Phase without load Tap Changing; and 3750/4687 through 60,000/80,000/100,000 kVA with Load Tap Changing – Safety Requirements.
IEEE C57.104 Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers.
ANSI/ASTM-D 971 Standard Test Method for Interfacial Tension of Oil Against Water by the Ring Method.
ASTM-D 5837 Standard Test Method for Furanic Compounds in Electrical Insulating Liquids by High Performance Liquid Chromatography.
ASTM-D 3487 Standard Specification for Mineral Insulating Oil Used in Electrical Apparatus.

IEEE 62 Guide for Diagnostic Field Testing of Electric Power Apparatus Part 1: Oil-filled Power Transformers, Regulators, and Reactors.
NFPA 70 B Recommended Practice for Electrical Equipment Maintenance, National Fire Protection Association.
PEB 5 Transformer Nitrogen Advisory.

Other References

ABB Service Handbook for Transformers

4. Instructions

This article is not intended to define transformer maintenance practices or describe in detail transformer condition assessment inspections.

Guidance and recommendations herein are based on industry standards and practices. However, equipment and situations vary greatly, and sound engineering and management judgment must be exercised when applying these diagnostics. All available information must be considered, for example, manufacturers’ and transformer experts’ recommendations, unusual operating conditions, personal experience with the equipment in conjunction with this document.

5. Responsibilities

5.1 TCA Team Leader

The selection of an engineer to serve as a TCA Team Leader should be the responsibility of the Coordinator, Electrical Systems Division (ESD) – Consulting Services Department (CSD).
The TCA Team Leader will:

 Assume the responsibility for coordinating all activities and act as the main point of contact with the plant. He will also ensure that adequate resources are available to accomplish the required work.
 Identify the duties of all participants prior to commencing the study.
 Issue all correspondence and Engineering Services Agreements (ESAs).

 Coordinate the transfer of documentation and collection samples between the plant and the appropriate specialist or laboratory.
 Coordinate the review of any significant findings with plant personnel to allow timely remedial actions, in order that the transformers may be returned to service.
 Compile and issue a final report to the plant management following completion of the assessment of the transformer(s).

5.2 Proponent

A Plant’s management may request to perform the TCA on their transformer(s), provided the transformer in question is either at least 25 years of age or has suffered a major operational problem.

5.2.1 Level 1 Assessment Requirements

The following information shall be supplied to the TCA Team Leader by Plant Inspection and Engineering staff:
 Transformer design and construction drawings
 Electrical one-line diagram of transformer under consideration
 Electrical one-line diagram of the entire system connected to the transformer(s)
 Representative sample of operating temperatures and loading [1 month data of normal operation and peak operation (i.e., summer time) in either electronic format or log sheets]
 Inspection/failure/repair/modification/replacement history
 Details of any previous condition assessment study or specialized investigation
 Preventive Maintenance (PM) shutdown interval and records
 Details of any major operational upsets
 Total number of start-ups and shutdowns to date
 Start-up procedure
 Load increase as a percentage of maximum continuous rating (MCR) when one or more of the other transformers trip in Double-Ended Substation

 Commissioning date and approximate service hours to date
 Details of oil sampling and Dissolved Gas Analysis (DGA) records i.e., testing results and frequency.

5.2.2 Level 2 Assessment Requirements

The following items and services should be made available by the proponent:
 Plant access security clearance
 Details of plant safety regulations and requirements for any safety briefing or qualification prior to work start
 Suitable access, scaffolding and lighting at all workscope components
 Power supply to all workscope locations
 Provision of TCA services (in-house or contracted-out)
 Assistance with general inspection work
 Office accommodation
 Chemistry lab support as required.

5.3 Engineering and Inspection Specialists Responsibilities

 Each specialist will review the plant information relevant to his field of application and draw conclusions and recommendations for inclusion in the Level 1 assessment report.
 Conduct detailed analysis or site examination (as appropriate) to establish the condition of the components examined. Immediately report any significant findings to the TCA Team Leader so that timely decisions can be made on the appropriate action to be taken.
 Provide a detailed report to the TCA Team Leader. The report shall include findings and recommendations on future serviceability of the transformer(s).

6. Transfer Condition Assessment Technical Procedures

The hierarchy of inspections, tests, and measurements is illustrated in Figure A.1 in Appendix A and Appendix B (Transformer Condition Assessment Summary) summarizes these activities.

This guide also assumes that inspections, tests, and measurements are conducted on a frequency that provides accurate and current information needed by the assessment. In some cases, it may be necessary to conduct tests prior to this assessment to acquire current data.

TCA may cause concern that justifies more frequent monitoring. Plant/POD should consider the possibility of taking more frequent measurements (e.g., oil samples) or the installation of Transformer Monitoring System that will continuously track critical quantities. This will provide additional data for condition assessment and establish a certain amount of reassurance as transformer alternatives are being explored.

7. Transfer Condition Assessment Scoring Methodology

Every transformer is unique; therefore, the methodology described in this guide cannot quantify all factors that affect individual transformer condition. It is important that the TCA Score arrived at be studied by engineering experts. Mitigating factors specific to the plant may determine the final TCA Score and the final decision on transformer replacement or rehabilitation.

TCA Score is somewhat subjective, relying on transformer condition experts. Relative terms such as “results normal” and “degradation” refer to results that are compared to:
 Industry accepted levels
The “Power Transformer Diagnostics” could be used to benchmark tests results to the industry accepted levels.
 Baseline or previous (acceptable) levels on this equipment
 Equipment of similar design, construction, or age operating in a similar environment

Documentation is essential to support findings of the assessment. Test results and reports, photographs, O&M records, or other documentation should accompany the TCA Summary Form.

The TCA scoring methodology consists of analyzing each condition indicator individually to arrive at a TCA Score; then score is summed with scores from other condition indicators. Apply the condition index to the Alternatives Table D.1 in Appendix D to determine the recommended course of action.

This guide assumes that Level 1 and Level 2 inspections, tests, and measurements are conducted and analyzed by staff suitably trained and experienced in transformer diagnostics. In the case of more basic tests, this may be carried out by qualified staffs that are competent in these routine procedures. More complex inspections and measurements may require a transformer diagnostics “expert.”

7.1 Level 1 Inspections, Tests, and Measurements

This procedure level describes the initial condition indicators generally should be regarded as a sound basis for assessing transformer condition.

Level 1 inspections, tests, and measurements are routinely accomplished as part of normal O&M are readily apparent by examination of existing data. Level 1 test results are quantified below as condition indicators that are summed to arrive at a TCA Score. Level 1 inspections, tests, and measurements may indicate abnormal conditions that can be resolved with standard corrective maintenance solutions. Level 1 test results may also indicate the need for additional investigation, categorized as Level 2 tests.

7.1.1 Condition Indicator 1.1: Oil Screening Test Analysis

Oil screening tests is an initial tool to determine the need for applying the TCA.
Oil screening tests historical trending is the most cost-effective diagnostic tool for evaluating the solid insulation and, therefore, to give an indication of conditions inside the equipment before intervening with it. Broadly speaking, they are the equivalent to the human blood tests. The below Tables 1a and 1b should be used to screen the power transformer oil.

Table 1a – Oil Screening Test Analysis

Table 1b – Oil Screening Test Analysis Scoring

7.1.2 Condition Indicator 1.2: Dissolved Gas Analysis

Dissolved gas analysis is the most important factor in determining the condition of a transformer because, being performed more frequently than other tests, it may be the first indication of a problem. Insulating oil analysis can identify internal arcing, bad electrical contacts, hot spots, partial discharge, or overheating of conductors, oil, tank, or cellulose. The health of the oil is reflective of the health of the transformer itself.

DGA consists of collecting transformer insulating oil samples and determining the contents of key gas with chromatography equipment either portable or at a laboratory for analysis. The most important indicator is the individual and total dissolved combustible gas (TDCG) generation rates, based on International Electrotechnical Commission (IEC) and Institute of Electrical and Electronic Engineers (IEEE) standards. Although gas generation rates are not the only indicators, they are reasonable for use in determining the TCA Score.

Furanic analysis may indicate a problem with the paper insulation which could affect transformer long life. A baseline furanic analysis should be made initially and repeated if the transformer is overheated, overloaded, aged, or after changing or processing the oil.

Results are analyzed and applied to Table 2b to arrive at a TCA Score.

Table 2a – Dissolved Gas Analysis

Table 2b – Dissolved Gas Analysis

Table 2 in SABP-P-009 demonstrates the actions based on Total Dissolved Combustible Gas (TDCG).

7.1.3 Condition Indicator 1.3: Power Factor and Excitation Current Tests

Power factor insulation testing is important to determining the condition of the transformer because it can detect winding and bushing insulation integrity. Power factor and excitation current tests are conducted in the field on de-energized, isolated, and properly grounded transformers. Excitation current tests measure the single-phase voltage, current, and phase angle between them, typically on the high-voltage side with the terminals of the other winding left floating (with the exception of a grounded neutral). The measurements are performed at rated frequency and usually at test voltages up to 10 kV. The test detects shorted turns, poor tap changer contacts, and core problems. Results are analyzed and applied to Table 3 to arrive at a TCA Score.

Table 3 – Power Factor and Excitation Current Test Scoring

Note 1 – Double insulation rating in parentheses.
Note 2 – Be sure to account for residual magnetism and load tap changer (LTC)

7.1.4 Condition Indicator 1.4: Operation and Maintenance History

Operation & Maintenance history may indicate overall transformer condition. O&M history factors that may apply are:
 Sustained overloading.
 Unusual operating temperatures indicated by gauges and continuous monitoring.
 Abnormal temperatures indicated by infrared scanning.
 Nearby lightning strikes or through faults detected.
 Abnormally high corona.
 Abnormally high external temperatures detected.
 Problems with auxiliary systems (fans, radiators, cooling water piping, pumps, motors, controls, nitrogen replenishment system, and indicating and protection devices).
 Deteriorated control and protection wiring and devices.
 Increase in corrective maintenance or difficulty in acquiring spare parts.
 Anomalies determined by physical inspection (external inspection or internal inspection not requiring untanking) (e.g., incorrectly positioned valves, plugged radiators, stuck temperature indicators and level gauges, noisy oil pumps or fans, oil leaks, connections to bushings).
 Previous failures on this equipment.
 Failures or problems on equipment of similar design, construction, or age operating in a similar environment.
Qualified personnel should make a subjective determination of scoring that encompasses as many O&M factors as possible under this Indicator. Results are analyzed and applied to Table 4 to arrive at a TCA Score.

Table 4 – Operation and Maintenance History Scoring

7.1.5 Condition Indicator 1.5: Age

Transformer age is an important factor to consider when identifying candidates for transformer replacement. Age is one indicator of remaining life and upgrade potential to current state-of-the-art materials. During the life of the transformer, the structural and insulating properties of materials used for structural support and electrical insulation, especially wood and paper, deteriorate. Although actual service life varies widely depending on the manufacturer’s design, quality of assembly, materials used, operating history, current operating conditions, and maintenance history, the average expected life for an individual transformer in a large population of transformer is statistically about 40 years.
Apply the transformer age to Table 5 to arrive at the TCA Score.

Table 5 – Age Scoring

7.1.6 Level 1 TCA Score Calculations

Enter the TCA Score scores from Table 1, 2, 3, 4, and 5 into the TCA Survey Form in Appendix D Table D.1. Multiply each TCA Score by the Weighting Factor (WF), and sum the total scores to arrive at the Level 1 TCA Score. The TCA Score may be adjusted by the Level 2 inspections, tests, and measurements described below. Suggested alternatives for follow up action, based on the TCA Score, are described in the Transformer Condition-Based Alternatives at Appendix E in Table E.1.

7.2. Level 2: Inspections, Tests, Measurements

This procedure level describes inspections, tests, and measurements that may be applied, depending on the specific problem being addressed. Results of these level tests may modify the score of the TCA Score.
Level 2 inspections, tests, and measurements generally require specialized equipment or training, may be intrusive, or may require an extended outage to perform. Level 2 assessment is considered nonroutine. Level 2 inspections may affect the TCA Score number established using Level 1 but also may confirm or disprove the need for more extensive maintenance or transformer replacement.

7.2.1 Test 2.1: Turns Ratio Test

The Transformer Turns Ratio (TTR) test detects shorts between turns of the same coil, which indicates insulation failure between the turns. These tests are performed with the transformer de-energized and may show the necessity for an internal inspection or removal from service.
Results are analyzed and applied to Table 6 to arrive at a TCA Score.

Table 6 – Turns Ratio Test Scoring

7.2.2 Test 2.2: Short Circuit Impedance Tests

Short Circuit Impedance Test, which is known also as Percent Impedance Test or Leakage Reactance Test, these tests are conducted in the field and compared to nameplate information, previous tests, and similar units to detect deformation of the core or windings caused by shipping damage, through faults, or ground faults. Some difference may be expected between nameplate and field test results because factory tests are conducted at full load current, normally not possible in the field.

Field connections and test leads and jumpers also play a significant role in test results, and it is impossible to exactly duplicate the factory test setup. Therefore, the I2R losses may be different and cause different test results. By comparing percent-reactance to nameplate impedance, the differences caused by leads and connections can be eliminated. Because reactance is only the inductive component of the impedance, I2R losses are omitted in the test results.
Results are analyzed and applied to Table 7 to arrive at a TCA Score.

7.2.3 Test 2.3: Core-to-Ground Resistance Megger Tests

The transformer core is intentionally grounded through one connection. The core-to-ground resistance test can detect if this connection is loose. It can also detect whether there are other, undesired and inadvertent, grounds. If the intentional core ground is intact, the resultant resistance should be very low. To check for unintentional core grounds, remove the intentional ground and Megger between the core and the grounded transformer tank. This test should produce very high resistance indicating that an unintentional ground is not present. This test is to supplement DGA that shows generation of hot metal gases (methane, ethane, ethylene) and to indicate if a false, unintentional core ground is the problem. Experience can help locate the source of the problem.
Results are analyzed and applied to Table 8 to arrive at a TCA Score.

Table 8 – Core-to-Ground Resistance Test Scoring

7.2.4 Test 2.4: Winding Direct-Current Resistance Measurements

Careful measurement of winding resistance can detect broken conductor strands, loose connections, and bad contacts in the tap changer. Results from these measurements may indicate the need for an internal inspection. This information supplements DGA and is useful when DGA shows generation of heat gases (ethane, ethylene, methane). These tests are typically performed with a micro-ohmmeter and or Wheatstone bridge. Test results are compared between phases or with factory tests. When comparing to factory tests, a temperature correction must be employed as per IEEE P62.
This test should be performed only after the rest of the routine electrical tests because it may magnetize the core, affecting results of the other tests.

Results are analyzed and applied to Table 9 to arrive at a TCA Score.

Table 9 – Winding Direct-Current Resistance Measurement Scoring

7.2.5 Test 2.5: Frequency Response Analysis (FRA)

Frequency Response Analysis (or Sweep Frequency Response Analysis) can determine if windings of a transformer have moved or shifted. It can be completed as a factory test prior to shipment and repeated after the transformer is received onsite to determine if windings have been damaged or shifted during shipping. This test is also helpful if a protective relay has tripped or a through fault, short circuit, or ground fault has occurred.

A sweep frequency is generally placed on each of the high voltage windings, and the signal is detected on the low-voltage windings. This provides a picture of the frequency transfer function of the windings. If the windings have been displaced or shifted, test results will differ markedly from prior tests. Test results are kept in transformer history files so they can be compared to later tests.

Results are determined by comparison to baseline or previous measurements or comparison to units of similar design and construction.
Results are analyzed and applied to Table 10 to arrive at a TCA Score.

Table 10 – Frequency Response Analysis Scoring


7.2.6 Test 2.6: Degree of Polymerization

Winding insulation (cellulose) deterioration can be quantified by analysis of the degree of polymerization (DP) of the insulating material. This test gives an indication of the remaining structural strength of the paper insulation and is an excellent indication of the remaining life of the paper and the transformer itself. This requires analyzing a sample of the paper insulation in a laboratory to determine the deterioration of the molecular bonds of the paper.
Results are analyzed and applied to Table 11 to arrive at a TCA Score.

Table 11 – Degree of Polymerization Scoring

TCA tests, measurement, or inspection may be conducted to verify previous testes results. For example, visual inspection and Thermography Inspection are common practices. Refer to appendix F to see IR analysis example.

7.2.7 Level 2 TCA Score Calculations

Enter the TCA Score scores from Table 6, 7, 8, 9, 10, and 11 into the TCA Survey Form in Appendix D Table D.3. Multiply each TCA Score by the Weighting Factor (WF), and sum the total scores to arrive at the Level 2 TCA Score. Suggested alternatives for follow up action, based on the TCA Score, are described in the Transformer Condition-Based Alternatives at Appendix E in Table E.1.

8. Transformer Alternatives Or Not

After review by a TCA Team, the TCA Score may be sufficient for decision-making regarding transformer alternatives. Where it is desired to consider alternatives based solely on transformer condition, the TCA Score may be directly applied to Table E.1 in Appendix E.

The estimation of remaining lifetime is an assumption for the case that the corrective actions will be undertaken, the usual maintenance followed and the operation condition (load) will remain the same. In this case, the risk of failure can be reduced significantly. An example of how to estimate transformer remaining lifetime is enclosed in Appendix F.

Transformer Condition Assessment Summary

Transformer Condition Assessment Summary

Appendix B – Transformer Condition Assessment Summary (Please Check this article Transformer Maintenance Tests & Transformer Condition Assessment .

Appendix C – Oil Screening Survey Form

Appendix D – TCA Survey Form

Multiply each TCA Score by the Weighting Factor (WF), and sum the total scores to arrive at the Level 1 TCA Score.
Table D.1 – Level 1 Assessment TCA Score

Appendix E – Transformer Condition-Based Alternatives

Appendix F – IR Analysis Example

Appendix F – IR Analysis Example

Appendix G – Transformer Remaining Lifetime Estimation

Let us assume that you conducted a level 1 TCA and your transformers scores TCA Score = 6.89 as in the below table.

By referring to Table E.1: Transformer Condition-Based Alternatives, you found that your transformer is in “Fair” Condition. This guideline suggested the following course of actions:

1. Consider using appropriate Level 2 tests
Then, you decided to conduct level 2 assessment and your transformer scores TCA Score = 5.14 as in the below table.

By referring to Table E.1: Transformer Condition-Based Alternatives, you found that your transformer is again in “Fair” Condition. This guideline suggested the following course of actions, which require close attention and coordination with CSD, POD, and FPD to determine the most appropriate actions:

2. Continue operation but re-evaluate O&M practices.

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