The October/November Issue of the Electrical Insulation Magazine has been released. Use the accordion headings below to explore this issue’s content, and visit the IEEE Xplore for full magazine access.
Assessment of In-Service Transformers Filled with Synthetic Ester at 33 kV and Below
Muhammad Daghrah; Oguz Onay
Conductivity and Dielectric Dissipation Factor (tan δ) Measurements of Insulating Oils of New and Aged Power Transformers—Comparison of Results Between Portable Square Wave and Conventional Bridge Methods
Welson Bassi; Hédio Tatizawa
Thermal Ratings of Electrical Insulation Materials—How Are They Determined and Used?
Edward Van Vooren
I picked up my first copy of IEEE Electrical Insulation Magazine around 25 years ago, and it was like finding the picture for the jigsaw puzzle I was putting together. More than that, I saw there was a role for me in oil research that I could spend many years working on. At the time I was a new chemistry post-graduate starting work in the electricity supply industry and struggling with a project on transformer oil. I had been attracted to the project because I had worked in the field of oil research previously, having spent time formulating new engine oil products using, among other things, synthetic base oils and esters. However, I quickly found that the electricity supply industry was quite different from working in lubricants and that when it comes to oil, things change more slowly. I found it difficult to understand why synthetics were not already being embraced when they offered advantages over mineral oils.
One day in the university library, I came across a copy of IEEE Electrical Insulation Magazine from early in 1995. A paper in there did not really help me to understand why synthetic oils were not very popular, but it definitely helped me to understand a lot more about the industry I had just joined—about how long things tended to stay generally the same and how little was actually understood about the chemistry of insulating oils. “Electrical Insulating Oils Part I: Characterization and Pre-treatment of New Transformer Oils”  could have been written for me; it gave me historical context and an understanding of the market and explained that while we can estimate how many molecules might be present in the oil, most of them are unidentified because it made no economic sense to identify them all. It also gave me the second paragraph of my thesis, its first citation, and so many useful references. Looking back at the article now, I find it amazing that so many names that meant nothing to me then are people I have met and have had the pleasure of working with.
I quickly learned that the working environments for lubricants and insulating oils are very different and that moving to something unknown should only be done with caution and much study. Many of the topics that have been investigated on both synthetic and natural esters were not previously understood or were overlooked about mineral oil and much has been published on all three fluid types in the intervening years. Particularly important has been the work undertaken by research groups investigating dielectric strength in non-uniform electric fields and impulse strength over larger gap distances; here we see differences in the fluids that must be taken account of in designing transformers. It hardly seems fair to suppliers of more recently developed fluids, I hesitate to say “new” for products that have been around almost as long as I have, that such rigour has to be applied when wanting to switch from mineral oil to an ester, but we have less tolerance for failures now, there is greater dependency on reliable electricity, and changing a material when we do not know everything about it can seem risky.
Nevertheless, we can see esters starting to come into use in transformers at transmission voltages now. TransnetBW was first to energise natural-ester filled transformers at 420 kV using a soy based natural ester. The November/ December 2020 edition of this Magazine featured a National Grid transformer in the test bay at Siemens—it was the first 400-kV synthetic-ester filled transformer in the world and is one of three now in service in North London. In the week as I write, I have seen a video online of another ester-filled transformer being transported through Northumbria to another National Grid site. Taking the step to transmission voltages was based on research efforts from around the world and gaining the confidence that a transformer design could be made at that voltage to work with esters. National Grid contributed to this global research effort, largely through the research group at University of Manchester, but they also worked with GE at Stafford.
Buying an ester-filled transformer is only one part of the story. It then has to be incorporated into a network’s fleet of transformers. We need to understand how to manage it through its whole lifecycle. Researchers have looked at ester performance in small laboratory samples for many years, trying to reflect the conditions in a transmission transformer containing many orders of magnitude more oil. These studies aim to support asset managers in understanding how to manage the fluid over time, but given the importance of oil testing in assessing transformer condition, the more important aspect of this work is to ensure that we retain our diagnostic capabilities. With time and experience these laboratory studies will be supported and validated by in-service experience.
The contribution in this issue from Daghrah and Onay looks to do exactly that by examining in-service ester-filled units to understand more about the performance of the fluid based on findings over the last 20 years. This is a welcome contribution, but engineers and chemists working together in CIGRE, IEC, and IEEE are going to need more data, from more transformers and from more utilities, to improve the tools that asset managers rely on—maintenance and diagnostic guides built on operational information.
With transformers filled with esters in a fleet, there are other practical challenges to be dealt with by an asset manager. Where the K-Class property of fluids is an important characteristic that may have driven the choice of ester, it needs to be maintained. Research suggests that as they age normally, esters will retain their high fire point. But, it is incumbent upon the asset owner to ensure that this is not compromised by contamination with mineral oils. Procedures need to be in place to ensure that mineral oils and esters do not mix. The Siemens unit referred to earlier was painted blue to make a clear statement that it is different from other transformers to any observer, but the absence of mineral oil from the site will also prevent top-up accidents. Where both mineral oil–filled and ester-filled transformers are found on the same site, there are clear markings. But having both on one site also leads to another challenge—oil–water separators designed for mineral oil may not separate esters as easily. Users are already looking into the requirements for ensuring prevention of pollution from both fluids at the same time.
This Magazine, among other publications, has included papers ,  suggesting we can perhaps expect longer lives for the active parts of transformers containing esters. However, ester-filled transformers will, like all assets, age, and there will be a need to understand more about end of life. Are there options for life extension? Will there be special considerations for disposal? Can we re-use the fluids for other assets?
With transformer lives running into decades, the opportunity for new fluids to have an impact may be small. But who knows where the next challenge or opportunity may come from? By the time today’s transformers are reaching the end of their lives at the end of the century, do we imagine that we will still be relying on mineral oil for new assets? It seems more likely that we will have to move to a more sustainable alternative—utilities and manufacturers alike should be looking for innovations that could disrupt the way we currently do things. It seems likely that natural esters in particular will play a big part in that, but other bio-based fluids are already starting to appear. We may have to learn more quickly than we have in the past how to accommodate new fluids into our networks.
The younger version of me may have been frustrated in my naïveté at the slow pace of change in the movement away from mineral oils toward synthetic fluids. But, there are definitely exciting times ahead as we move to more sustainable and environmentally sound solutions in future.
I am still waiting on Electrical Insulating Oils Part II.
 A. Sierota and J. Rungis, “Electrical insulating oils. I. Characterization and pre-treatment of new transformer oils,” IEEE Electr. Insul. Mag., vol. 11, no. 1, pp. 8–20, Jan.-Feb. 1995.
 M. A. G. Martins, “Vegetable oils, an alternative to mineral oil for power transformers—Experimental study of paper aging in vegetable oil versus mineral oil,” in IEEE Electr. Insul. Mag., vol. 26, no. 6, pp. 7–13, Nov.-Dec. 2010.
 G. K. Frimpong, T. V. Oommen, and R. Asano, “A survey of aging characteristics of cellulose insulation in natural ester and mineral oil,” in IEEE Electr. Insul. Mag., vol. 27, no. 5, pp. 36–48, Sep.-Oct. 2011.
From The Editor
It is at least as important to think about where we should go as describing where we are now. The world is faced with numerous challenges, some of which were put on hold while we were (are) dealing with COVID-19. A number of these challenges involve us, working in the field of electrical insulation. Think about the accelerated developments in electrical transport, “green” energy, HVDC, and such. The IEEE Electrical Insulation Magazine wants to be a platform for ideas and roadmaps that provide ways to tackle these challenges. So, we welcome articles that present such ideas and roadmaps.
This issue of the Magazine starts with two articles on quality assessment of oils and esters used in transformers, key components of the grid. The third article is about how to determine and use the thermal ratings assigned to electrical insulating materials.
The first article in this issue, “Assessment of in-service transformers filled with synthetic ester at 33 kV and below,” is authored by Muhammad Daghrah and Oguz Onay, of M&I Materials Ltd., United Kingdom. The authors provide an introduction in terms of key benefits and in-service practices for condition assessment of transformers filled with synthetic esters in contrast with mineral oil. The results of a survey of 12 transformers filled with synthetic ester (11 kV/415 V and 33 kV/11 kV) are presented and discussed, including liquid quality and dissolved gas analysis (DGA) measurements. The transformers were chosen among the most loaded units from the transformer fleet, with an average loading from 0.5 to 0.8 p.u. All assessed transformers did not undergo any oil reconditioning or reclamation processes. Ester samples were characterized based on chemical parameters (color, neutralization value, and water content), electrical parameters (breakdown voltage, DC resistivity, and dielectric dissipation factor), fire point, and DGA tests. The authors conclude that end users can follow the same maintenance protocols with synthetic esters as they do with mineral oils, given that they use the relevant standards and in-service limits for synthetic esters such as the IEC 61203 and IEEE C57.155. DGA evaluation methods and key gases used to identify faults in mineral oil–filled transformers can also be applied for synthetic ester–filled transformers.
The second article, authored by Welson Bassi and Hédio Tatizawa, Institute of Energy and Environment of the University of São Paolo, Brazil, is titled “Conductivity and dielectric dissipation factor (tan δ) measurements of insulating oils of new and aged power transformers—Comparison of results between portable square wave and conventional bridge methods.” In this article, the authors compare values of tan delta calculated using conductivity measurements and tan delta bridge measurements. First, they make a direct comparison between the two methods for temperatures ranging from 25 to 100°C by using a simple expression relating the conductivity and tan delta. In a next step, they estimate the conductivity and tan delta at higher temperatures based on the value at ambient temperature (25°C) by assuming a certain activation energy for the conduction process. The authors show that the square wave method consistently provides tan delta values lower than those obtained by the bridge method, especially at lower temperatures. The authors argue that especially the values at 90 and 100°C are of importance, and in this temperature range the square wave method used on oil of poor condition provides tan delta values up to 25% lower than the bridge method. The authors claim that the main advantages of using the square wave method are lower costs, portability, and mobility, enabling field measurement immediately after oil sampling and preservation of the sample without risk of loss of properties or contamination.
The third article is titled “Thermal ratings of electrical insulation materials— How are they determined and used?” authored by Edward Van Vooren of ELTEK International Laboratories, USA. The focus of this article is on thermal ratings assigned to electrical insulating materials (EIM) and is intended to link with an article by Paul Gaberson on thermal rating for insulating systems, published in the May/June issue of the Magazine. After revisiting the different stress factors any electrical insulation system (EIS) can expect during operation, and how testing stages with the different stress factors should be arranged, the author focuses on EIM thermal rating. Thermal index ratings and relative thermal index ratings are discussed and compared. Then, the discussion moves to how to determine the thermal rating. Evaluations based on “end of test” and “end of performance” are discussed and examples are given for a range of insulating materials. The article ends with a discussion on how to make best use of the concept of EIM thermal rating in the design of electrical insulation equipment.
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