Understanding Legacy Transformers for Potential Extended Life

Presented By:
Brian D. Sparling
Dynamic Ratings Inc.
Senior Technical Advisor
TechCon 2022

It is important for transformer users and asset managers to be adequately equipped to assess the condition of legacy transformers in their utility/organization as a basis for making critical decisions about operations. In other words, classifying candidates and priorities for, repair/rectification of minor failures, refurbishment or replacement, and availability of reliable spare units when they are being considered for extended service life.

Users and asset managers need to understand the technical condition of transformers in terms of fitness for current service needs, and what limiting factors may impede their plans. There are many factors to consider with not only the active part of the transformers but, including the other components and their condition such as bushings (poor condition), and future loading, that may not allow either continued service or planned increased loading of them.

Once limiting factors have been identified a plan could be created in terms of determining, replacement, refurbishment, or upgrading the units rating. The plan may include the addition of online monitoring systems, to ensure of continued service, or in other words, life extension.


There are thousands of transformers in service today, many are past their “best before date”, in terms of calendar years, but may not be in terms of actual ‘life consumed’, based on their existing technical condition. Therefore, there needs to be some organized approach to best understand what the actual condition of the asset is, to classify or identify these candidates a suitable action plan, in answer to the large question “WHY”? This has been discussed with the 5 W’s approach in a column I wrote in Transformers Magazine[1]

The first priority, is to answer some very fundamental questions, related to your objective, namely, WHY are you doing this, WHO will be impacted, WHAT is the expected output, WHERE to, and WHEN to implement it?

There are quite a few reasons for the WHY question, safety to personnel and the public should rank as number one, followed by RISK of unexpected failure and the consequences of such an event. Another is to evaluate remaining life in a select number of critical units, with a view of possible life extension. Others will use a system only, to determine timing for replacement of the unit with a new one.

Other reasons include availability of replacement parts for components on many vintage OLTC’s (for example), to determine a course of action for that candidate group. It can also be replacement of the components with a family history of problems, such as bushings.

Some of the general answers to the WHY, include.

  1. Replacement of the asset
  2. Failure and Safety Issues
  3. Refurbishment (Life Extension)
  4. Maintenance (major or minor)
  5. Bushing Replacement
  6. Cooler replacement
  7. Oil treatment (or replacement)
  8. Tank refurbishment

Some utilities have to follow the ‘rules’ of the regulator, as their answer to the WHY. In some cases, some were able to justify the replacement of asset because they had reach (for example) 40 years of service. However, there may be such a large population of a particular asset class, that a wholesale replacement scheme would be very expensive and could not be accomplished in a timely basis.

The solution was to only replace those in the identified asset class when the technical condition of a particular unit was proven to have deteriorated to the point that immediate replacement of the asset was the prudent thing to do. The method to do this is either, to increase the frequency of inspection and testing, (time-consuming and may involve hard to obtain outages), OR implement some elements of on-line monitoring to the units, that would provide the evidence of the need for major intervention or indeed time to replace the asset.

Another reason may relate to units that could be refurbished, either on-site or back to the shop. Figure 1 details an example taken from the paper [2], as an approach taken based on Cigre Technical Brochure TB 761, Transformer Condition Assessment (TAI).[3]

The Table breaks down the components that need to be considered based on diagnostic information from off-line testing, visual inspections, and/or on-line monitoring information.

The task at hand with this information available is to determine or sort out, the candidates, based on their condition for different actions such as refurbishment, or life extension options, in this case. In other words, to rack and stack the selected population, to determine the priority for action.

Step 1: Determine the purpose of the Transformer Assessment Score and Index

Many asset managers currently use a health index for prioritizing asset replacement. However, in many cases the index does not provide any indication of how quickly the worst transformers on the list need to be actioned nor does it provide any indication of the most appropriate action needed i.e., replace, repair, or refurbish.

Step 2 and Step 3: Identify the failure modes and determine how each failure mode will be assessed in the TAI

A clear understanding of the failure modes and interpretation of the results is necessary to ensure reasonable correlation between the asset’s condition and the appropriate actions taken. The Technical Brochure TB 761 includes a comprehensive guide to key transformer components, failure modes, and suitable condition assessment techniques that could be included in an assessment index. Examples of some of the diagnostic testing and failure modes that can be applied for a refurbishment index TAI are shown in Figure 1.

steps 1, 2, 3 simplified

Step 4: Design a calibrated system for categorizing failure modes (scoring matrix)

An example of a scoring matrix has been developed by the working group as detailed in Table 1. This matrix effectively has five levels. The 6th level labeled F is not used when generating a TAI but is noted to consider very short-term failure criteria.

scoring matrix example

A common thought in some organizations is the concept or thinking that 2 transformers of the same vintage (OEM, design, years in service in parallel operation in a substation), will assume that they have the same ‘technical condition’. Experience has shown just the opposite.

In Tables 2 and 3, from the paper [2] details an analysis of two transformers in service for more than 40 years. The Table details a ‘scoring mechanism of ‘worst case’ with Summation, to identify the suggested action that could take place.

assessment tables

In the case of unit T2, (Score 20 Red), the poor degree of polymerization (DP) results (inferred from furan in oil measurements), acceptable (not good or bad yet) dissipation factor results, and poor oil DGA and oil quality, all point towards a replacement option from a technical condition point of view.

In the case of unit T1, (Score 12 Pink), most indicators pointing towards maintenance issues but not yet at a replacement issue. It may be worthwhile to the increase the maintenance and assess the loading imposed on the unit. The transformer loading guide (IEE C57.91 or IEC 60076-7) can be used to estimate the loss of life of paper due to its historical thermal load.

The takeaway message is this: Identical units in terms of vintage, years in service, and in parallel operation, always exhibit different patterns of behavior, they must be treated as individuals.

Detailed Assessment of Components (C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers)

This IEEE Guide is another useful resource that provides a very detailed listing and descriptions of the variety of main components, and ancillary devices, that may need attention inspection and attention when performing a detailed condition assessment. What it does not provide is a recommendation as to considering the financial risks and benefits that the alternatives that may consider.

Decision Point. Financial and Risk

Once the population has been sorted and technical assessments agreed upon, there remains the function of making Risk-Based Decisions on what investments may need to be made.

The Cigre Technical Brochure TB 248, Guide on Economics of Transformer Management[5] contains recommended best practice for the risk assessment and the items that need to be considered once a technical assessment has been reached.

The Swiss mathematician Daniel Bernoulli wrote two papers published in 1731 and 1738. Both were presented in the Papers of the Imperial Academy of Sciences in St. Petersburg. In his paper Exposition of a New Theory on the Measurement of Risk, Bernoulli states: “the value of an item must not be based on its price, but rather on the utility that it yields”. We may see a direct line from his statement and the definition of risk of today as “expected loss of utility [5]

Following are details extracted from a Flow Chart (5.2.2) in the Cigre TB 248.

AFTER Determination of Condition of Unit(s) Technical Evaluation or Ranking, Inspection and/or Testing, Failure Analysis Report …… THEN ….

  1. Consider the Age and Total (electrical) loss Evaluation for the Candidate units.
  2. Consider “Obsolescence”, such as availability of spare parts, bushings, OLTC components, cooling system, and Ancillary components.
  3. Consider “Compliance”. The need to meet modern specifications, and environmental regulations, and Modern testing costs.
  4. Estimated Residual Value, Scrap value (in whole or in parts), oil and copper value, scrapping costs, and site remediation costs.
  5. Consider Future Substation Loading Needs, Normal & Contingency, Loading enhancement options/Future Switching, Relocation of Candidate Unit.
  6. Determine Timing and Down Time Logistics, Schedule Availability/Conflicts, Dates, Durations, Probable Delivery Lead Times, Availability of Outside Resources and Equipment.
  7. DECIDE Probable Options to be Evaluated, Corrective Maintenance? Refurbishment? Rewind in Kind? Reengineer New Design? Purchase New (size) Unit? Adapt a Spare Unit?

Example of Financial Determination

New materials, major component updating or upgrading replacement, and other design changes or Service Advisory Notices from the original OEM, may also affect the life-extension decision of units manufactured in the last 50 years. The development of better core steel and better solid insulation has been ongoing for a number of years. The better operating efficiency of new materials (core steel in particular) should be considered when investigating the economic advantage for life extension.

With the data described in steps 1-7 above, next is the estimating of costs for the different options. Following is an example taken from Cigre Technical Brochure TB 445 Guide for Transformer Maintenance.[6]

Case 1: Problematic Transportation.

The unit is a 33MVA 120-12kV built-in 1962. The active part was determined to be in very good condition, however major work was required on the OLTC, bushings, and ancillary devices. The unit is located in an underground substation, in a dense business district, in North America.

  • Transportation was problematic due to load restrictions and access by neighboring buildings.
  • No HV tests were deemed necessary as refurbishment would not involve any activity on the active part.
  • Due to location of the substation, special site-related expenses had to be considered.
  • Outage time was not an issue as the utility had sufficient contingency.

The comparative cost breakdown is expressed as a percentage of the supply cost of a new equivalent transformer.

comparative costs

In subtotal A, the material costs only are compiled and can be seen that on-site repair and factory repair options appear to be least expensive, However, the contribution of the existing active part losses (Core Steel used at the time produced higher no-load losses) changes the picture to the point that on-site repair is now marginal, considering that the reliability and risks have not been factored in. Once transportation costs are added into the analysis, the on-site repair option clearly separates the other two options.

Given the location and the work to be carried out, it would make sense to provide some level of on line monitoring to this unit, from the point of view of maintaining reliability, and reducing the risk of unexpected failure, given that no HV dielectric testing would be performed on-site after installation.

In addition to this answer to WHY, often when units are refurbished or rebuilt there is always the opportunity for reassembly errors, oil processing mishandling to mention a couple. Those who have chosen this life extension opportunity have added on-line monitoring to the refurbished unit, to ensure the work carried out did not introduce another issue.

A West Coast US utility has installed on-line monitors on their fleet of 350 transformers with many of the reasons why detailed here. Out of this fleet, 12 older units (60 years old) were deemed to have remaining life to extend their operation a further 5 years. In order to ensure there would be no surprises with these older units, they received the same on-line monitors as the other ‘younger’ units. The deferral of capital was the significant business driver for this decision. [9]

As a minimum suggested on-line monitoring would include.

  • DGA for the active part (single gas, hydrogen + moisture in oil)
  • Thermal monitoring including.
  • Load
  • Top oil temperature (with ETM), eliminate the need for old-style OTI
  • Calculation of Winding Hot Spot temperature (with ETM eliminate the need for older style WTI)
  • Enclosure temperature (it is underground in a vault)
  • Calculation of moisture in the solid insulation system (paper on conductors of the winding)
  • Cooling system efficiency
  • HV Bushing Monitoring (no matter the type OIP, RIP, or RIS)
  • Digital communications via connection to SCADA, or Substation Automation System, or via the Cloud, provides a view of the unit in operation. This can reduce or eliminate routine visits to this underground substation, to either make note of the temperatures listed above or carry out periodic maintenance on such items as older style OTI and WTI instrumentation, including periodic off-line testing of the HV bushings.

Hopefully, there are in place already within organizational processes and procedures to carry out this entire process. For them, these documents and this paper may be used as a ‘check point’, or guide to compare the processes they currently employ.

There are two guides that should be required reading for those not yet exposed to the On-Line Transformer Monitoring techniques.


  1. B Sparling, Future of Substation Monitoring: It is Not Just the Software, Transformers Magazine, Volume 5 Issue 2, April 2018 Issue
  2. B. Sparling, C. Beckett, T-L MacArthur, “Application of Condition Assessment Methodologies for Transformers”, TechCon 2020, Orlando FL, February 2020
  3. CIGRE Technical Brochure 761 – Condition Assessment of Power Transformers March 2019 4. Daniel Bernoulli, Exposition of a New Theory on the Measurement of Risk, Papers of the Imperial Academy of Sciences in St. Petersburg, 1738.

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