On-site options for transformer insulation management (With an Historical Perspective) Andy Bartram I. Eng Miet, Sales Manager Electrical Oil Services Ltd abstract

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(With an Historical Perspective)
Andy Bartram I.Eng MIET, Sales Manager

Electrical Oil Services Ltd

This paper seeks to review the history of insulating oil management (oil and paper) beginning with an historical perspective, expectations and how oil monitoring and maintenance standards have changed over the years.

Consider how paper insulation determines the ultimate life of the transformer and how the degradation of insulating oil in service reduces the mechanical strength of the paper.

What are the pressures facing todays transformer owners?

Do transformer owners have to take action when oil is “poor” or not?

If so when and what options?

With Electrical Oil Services at the forefront of insulating oil supply and management for well over 60 years the author draws on his and the experience of former colleagues to try and put all this in perspective, ending with some worked examples of in-situ oil regeneration carried out with the intention of improving the transformers health and extending their potential life.

With today’s focus on transformer life extension there has never been a better time to look again at your transformer insulation system.

Having a working knowledge of insulation degradation and options for site treatment can help today’s hard pressed site engineer manage his or her transformers with confidence.

Electrical Oil Services and her predecessor companies have been at the forefront of insulating oil supply, reclamation and on-site treatment for over 50 years. Drawing on this long history of close involvement with the UK electricity supply industry this presentation seeks to review insulating oil degradation (from a non-chemist / site engineers perspective) with reference to BSEN60422:2013 and consider the latest in-situ oil regeneration techniques for “deep cleaning” insulation systems and extending the potential life of transformers.

Some history
In the 1941 edition of the J&P Transformer book[1] the maximum permitted Acid Value for Class A or Class B mineral insulating oil supplied into UK (built) transformers was 0.2mgKOH/g and reflected the limits set out in BS148:1933. Compare this then with the limit given in the current version of IEC 60296:2012 of just 0.01 mgKOH/g [2] and you will begin to get a sense of how our attitude to transformer oil management has changed in the intervening years since the eighth edition of the J&P handbook was published.
Back in the 1930s and continuing until the 1950s a transformer purchaser could specify either Class A or Class B insulating oils for his new transformer (first fill) depending on the likely maximum temperature the oil was ever likely to reach. Class A insulating oil should be used where the maximum oil temperature would exceed 80ºC while class B could be used whenthe maximum oil temperature does not exceed 75ºC” [3]
The class of oil chosen would in theory have be critical it reflected the oils Tendency to Deposit Sludge under the then BS test which was carried out at 150ºC for 45 hours, allowable %age sludge after the test was 0.02% for a Class A oil and 0.1% for a Class B oil. By way of comparison the Oxidation Stability test IEC 61125:1992 (Method C) specifies a test duration of 164hours (for uninhibited oils) at 120ºC with a resulting maximum permissible sludge of 0.8%.

In practice transformer users would use the design criteria as set out in British Standard 171 which assumed an ambient temperature of no greater than 35ºC and a top oil temperature of 50ºC – this gives a theoretical maximum oil temperature of 85ºC – many users would still specify a class B oil on the basis that ambient temperature would not be 35ºC and or site loading would not be high enough to give a top oil temperature of 50ºC.

Following privatisation of the United Kingdom Electricity Supply Industry, under pressure from the European Union to further open up UK markets to overseas transformer manufacturers, BS171 was replaced by BS EN 60076 in the early 1990s – a move that at the time was widely seen as a retrograde step for the UK ESI but meant the newly powerful procurement specialists could look overseas for alternative suppliers of transformers.
Along with the liberalisation of the transformer market the development of computer aided design meant that designers could for the first time produce transformers that were fit for purpose and contained less steel, copper paper and of course, insulating oil.

With lower material costs, the removal of the BS171 “barrier to entry” and arguably at the time (and today?) a price-driven market for new transformers, the scene was set for a new (for the UK market) breed of transformer that we can argue, needed to be looked after, managed and nurtured through life far more than the older CEGB specified transformers ever had to with their built in margin for error, standardized designs, more oil within.

Throughout the 1990’s the UK witnessed a “dash for gas” where previously “rare” natural gas was now allowed to be used as an alternative to coal and oil in conventional power stations. Gas fired power stations sprang up all over the UK with, at the time, a stated expected life span of 15 years. With such a short term investment the majority of the generator transformers specified for these new gas stations were, shall we say “built to a cost” – why design a transformer to last 40+ years when a 15 year life-span was required? In addition these new breed of CCGT power stations were, in the main designed to operate under base load (continuous running) as gas prices were cheap and (allegedly) plentiful.

And so, over 25 years later we bare witness to transformers that were designed to last 15 years, failing, or at the very least showing a degree of insulation wear and tear normally associated with generator transformers twice their age. This degree of insulation degradation is likely due in part to the original design but also, and possibly more significantly, a change in the duty of these transformers – no longer base load operation but on and off load two or three times a day or with long periods of inactivity. Many of these generator transformers, specified for base load operation, were supplied without any forced cooling, relying on the load building up and running at “base load”, steady state for days or weeks at a time. This gives the transformer’s natural cooling sufficient time to “get going” and establish an efficient cooling pattern. Subject the same transformer to a two-shifting regime however and owners have found that by the time the transformer’s natural cooling pattern has been fully established it’s time to switch off the transformer, the result is insulation that for frequent periods has seen operating temperatures without any real cooling effect. Paper overheating, embrittlement and failure can result.

What about the utilities?
The historical picture painted above largely focuses on the generation sector of the UK market, with the dash for gas, the emerging dominance of the procurement specialist, fewer (and cheaper) construction materials and, it has to be said, a loss of experience and expertise from the industry combined with a lack of investment and training in young engineers who wish to remain at the operational end of our business and not fast tracked into senior management as is often the case.

The six UK Distribution Network Operators (DNOs) and their 14 separately regulated areas are subject to price control and regulation through the body known as OFGEM (Office for Gas and Electricity Markets). OFGEM regulate the electricity markets on a 5 – 8 year cycle. For the period 1st April 2015 to 31st March 2023 RIIO-ED1[4] (Revenue = Incentives + Innovations + Outputs) dictates the revenue available for investment by the DNOs.

The emphasis is very much on life extension of existing assets over and above outright replacement. When it comes to power transformers with system voltages between 33kV and 132kV DNOs have sought to arrive at a target population that are suitable candidates for investment for life extension – example criteria would be:

  • The percentage life remaining of the paper insulation (based on furan analysis over time)

  • Total Acid Number of the oil

  • Any history of faults

  • DGA history

  • Overall physical condition

  • Availability of spares

It may surprise some but many of the transformers identified as candidates for life extension investment are well over 40 years old, they were, however built to exacting BS171 and BEBST2 standards and, just as importantly, most have operated in parallel with a sister transformer with each transformer taking only half the design load. Paper insulation tensile strength as measured through furan analysis remains good with at least “half life” remaining.

With pressure to make generator transformers last longer than their 15-20 years expected life, older conventional and nuclear stations still needed to “keep the lights on” whilst alternatives can be developed and the pressure on the DNOs from OFGEM to extend the life of existing transformers, there is a growing focus on transformer asset management focusing on the insulation system.

A transformer’s insulation system ultimately defines the life of the transformer (providing it doesn’t die of something else in the meantime!). There is an easy analogy with the human body, if you exercise frequently and regulate what you eat and drink you will on average live longer than someone who doesn’t, the analogy goes further – if you are fit and healthy your body is far more able to withstand illness and disease than if you are not, for body substitute transformer insulation system.

Looking after your paper insulation - water

Let’s get one thing straight – transformers are dried in the factory before dispatch to the end user. Power transformers are typically dried so the cellulose contains less than 0.5% water by dry mass of paper. Once the paper has been impregnated with “dry” insulating oil then this figure may rise to 1% or slightly less.

What does this mean in practice for an in-service transformer?
Assume the following case study
145MVA, 132/145kV

HSPT Generator transformer


Oil volume 34,704 Litres

Measured water content in oil (over time and allowing for stable conditions) 23ppm @50ºC
Assume for a 132kV transformer weight of insulation is 10% weight of the oil
Weight of oil in transformer is 0.87 x 34704 Litres = 30,019 kg
Water in oil can be calculated at 34704 x 23ppm / 106 = 0.80 litres
From a typical paper oil equilibrium graph, figure 1 below 23ppm @ 50ºC equates to 2.3% water in paper
3019kg x 2.3% / 100 = 69.4 litres
When installed and filled with mineral oil with a paper water content of 1% there would be 3019kg x 1% / 100 = 30 litres of water


Keeping water in paper insulation to these “as installed” levels means you already are part way to maximizing your transformer’s life. Ignoring leaks, poor maintenance practices, inattention to breathers and overloading transformers for long periods can all lead to water levels increasing either due to atmospheric contamination or cellulose degradation. Drying a “wet” transformer on–site is hardly ever effective unless you are prepared to take some pretty drastic and costly measures involving vacuum/ heat cycles and low frequency short circuit drying usually requiring several return visits over 2-3 years allowing sufficient time for the remaining water in the paper to return to stable / equilibrium conditions with the oil. Once dry, or perhaps from new owners should consider the installation of a proprietary molecular sieve type device to help keep the oil and hence the paper, dry.

Over the years much has been written on the subject of water in paper insulation, not least by former Carless Refining & Marketing employee and transformer specialist Charles P. Tart in his paper given to the National Grid conference in 1996 [5]. “All transformers are “wet”. Wet is a relative term….processing the oil because it is “wet” is not the end of the story. What is being processed is the transformer insulation system, both the liquid and solid parts, and the relationship between these two parts should always be understood before any work is undertaken. What is important is the degree of wetness plus the size and type of the transformer (in 2016 I would add the transformer’s commercial application Auth).


Figure 2 above is taken from CEGB transformer oil maintenance documents and remains, to this day a very useful guide to help the practical transformer engineer keep his or her transformer water content to recommended levels. As ever, these graphs assume a) representative samples are being taken by trained operatives and b) the transformer has been on-load (ideally) and operating under steady state load conditions for some weeks ensuring a state of equilibrium between water in the oil and water in the paper.

And acidity?
Now that we no longer have to decide between Class A or Class B oils and their varying tendencies to deposit sludge in your transformer we could hope that oil oxidation leading to acid and sludge formation is a thing of the past – well, yes and no.

Whist there is no doubt that modern mineral insulating oils are carefully refined to ensure top quality and stable performance under exacting conditions it remains a fact that unsuitable specification, poor transformer design, insufficient cooling, poor construction can and do all lead to degradation of insulating systems (oil and paper) and as already discussed it is not uncommon to find relatively young transformers containing highly oxidised insulating oil and low paper strength for one or all of the reasons listed.

Mineral insulating oil is supplied as either uninhibited or inhibited, the latter having artificial inhibitors added to the oil in the refinery to give the oil extended resistance to oxidation due to high operating temperatures and exposure to oxygen in air. Inhibitors can and are often added to in-service transformers, particularly following on-site regeneration processes where the oil is already partly aged.
It should be noted that in reality there is no such thing as an uninhibited mineral insulating oil – a bit of a glib statement but it should be remembered that a mineral insulating oil refined in a modern, hydro-treating refinery will retain sufficient sulphur and aromatic (the smelly part of oil) content to enable the oil to pass the standard 164hr oxidation stability test as set out in IEC 61125:1992 (Method C). Good sulphur and not the corrosive stuff, is a natural anti-oxidant and this is why a good performing uninhibited mineral insulating oil should not be over-refined, over-refining can remove all sulphur and aromatics leading ultimately to a medicinal white oil which is excellent for body oils but not so as a transformer oil unless artificial inhibitors are added – it then becomes an inhibited mineral insulating oil.
During a transformer’s service life heavy acid sludge formation is no longer as common as it was in the 1930s when “new oil” could and was supplied at starting acidities of 0.2mgKOH/g instead of 0.01mgKOH/g (max)[6] specified in today’s standards.

Permanent damage to paper insulation is considered to begin at acid values (TAN) of around 0.08 – 0.1 mgKOH/g with modern transformer asset management practice (based on BSEN 60422:2013) recommending action thereafter[7] depending on the transformers importance to the user. Note there is not always a straightforward correlation between transformer operating voltage and importance to the user, a simple 1MVA 11kV transformer containing 1200 litres of insulating oil could be vital for the production paper in a mill for example and therefore carry a similar importance as a 400kV generator transformer to its’ owners.


Comparison of IFT and Acidity Depletion of “natural” inhibitors

Figures 3 and 4 are useful practical guides to oil and paper ageing and when to intervene, in this case regenerate the insulating oil in such a manner as to “deep clean” the solid, paper insulation.
Both graphs show action points of 0.1mgKOH/g with Figure 3 adding Interfacial Tension (IFT – see below) as an additional metric.

Figure 4 is intended as a graphical representation showing how insulating oil behaves over the years with point A representing the time at which the oils “natural” inhibitors have depleted to such an extent that they can no longer resist the process of oxidation. Point B indicates oil regeneration returning the oil to “as new” but with the addition of an artificial inhibitor to restore the oils oxidation stability.

And other parameters?
Other parameters can be monitored in addition to water and acidity that can serve as a useful guide for the transformer owner when it comes to assessing the overall health of the unit and deciding what action to take, if any, to treat the oil/paper.

  1. Dielectric Dissipation Factor (DDF) has traditionally been an oil test carried out by oil producers and was not necessarily a condition monitoring test, however DDF is now listed in BSEN 60422:2006 with “good” , “fair” and ”poor” action limits depending on the test result.

DDF in simple terms will give a “poorer” result where there are high levels of dissolved polar contaminants present in the oil, these contaminants are often found as a result of oil oxidation and lead to lower insulation resistance and larger transformer losses. DDF is measured under AC conditions as opposed to…..

  1. Resistivity – which examines the oil in a similar fashion but under DC test conditions. This test is an old favourite of the CEGB where it was used as a “catch all” site test, invariably additional tests would have to be carried out where a “poor” result was obtained. DDF is perhaps a more useful test these days and is preferred to resistivity although typical test sets produce both results as a matter of course.

  2. Interfacial Tension (IFT) – has also crept into our consciousness over recent years and, along with DDF is routinely used as a progress check when carrying out on-site oil regeneration, being one of the last parameters to reach acceptable limits.

BSEN 60422:2006 gives a useful summary of this test “The interfacial tension between oil and water provides a means of detecting soluble polar contaminants and products of degradation. This characteristic changes fairly rapidly during the initial stages of ageing but levels off when deterioration is still moderate. A rapid decrease of IFT may also be an indication of compatibility problems between the oil and some transformer materials (varnishes, gaskets), or of an accidental contamination when filling with oil” [8]

If and when to take action
The “if” question will differ from transformer owner and depend on several variables including:

  • Importance of the transformer (financial or production losses)

  • Lead time for replacement

  • Availability of spares

  • Remaining “life” left in the paper”

  • Other DGA trend analysis

  • Consideration to other mechanical remedial works that can be carried out at the same time – eg leak repairs

If at the end of this “health screening” exercise the transformer owner decides action to extend transformer life will, at some point be necessary what guidelines should be followed? In the UK we have the current version of BSEN 60422:2013 with it’s “good”, “fair” and “poor” test limits and suggested actions. This is a generally well written and perceived document and remains a good a start point as any. Table 1 shows the oil properties discussed so far, the category of transformer test limits (based on voltage – but remember if the transformer is critical to the owner then voltage is irrelevant).

Referring back to Figures 3 & 4 they suggest a “when” to take action point of around 0.1mgKOH/g before too much permanent damage is done to the paper insulation and the transformer owner can get “maximum bang for his bucks”.


Voltage (kV)




Acidity (mgKOH/g)



0.1 – 0.15




0.1 – 0.2


Water (ppm 20ºC)



5 – 10




5 – 15





0.1 – 0.2




0.1 – 0.5


IFT (mM/m)



22 – 28


Table 1

Options for in-situ insulation system treatment – focus on life extension

In the UK prior to the privatization of the ESI in 1990 the only priority site engineers had was to keep the lights on – keep a stable voltage close to 240v at your house and a frequency that didn’t vary much from 50hz. Expenditure wasn’t a particular issue when the priority wasn’t on cost. Engineers would look at BS5730:1979 and seek guidance in much the same way as they do today with BSEN60422. Some big differences exist between advice then and now – acidity limit was 0.5mgKOH/g then you should “Replace the oil” maybe consider sampling more often when the oil reaches 0.3mgKOH/g [9]

DDF is mentioned in the 1979 guide but no figures are given as it wasn’t considered a test for in-service oils, no mention of IFT

Jump forward to 2016 with all the commercial pressure on Power Stations and the regulatory pressure on the DNOs, combined with a much deeper understanding of insulating system ageing. What advice can be offered to transformer owners today that balance effective treatment with cost?
Just do nothing
Could well be a justifiable answer. It much depends on how important that transformer is to you, what plans there are for its future, and what condition the paper insulation is in.
If the transformer is due to be replaced and the paper strength is extremely poor then to be honest it’s probably best if you leave it alone, try to keep a steady load on it and plan for replacement. Taking the oil out or some form of on-site treatment may well be too much for it to bear.
Also if the transformer is one whose failure is not critical then that too could be a reason for doing nothing – in fact engineers rarely “do nothing” at the very least there will be a planned system of sampling and testing, perhaps more frequently as the oil condition deteriorates.
Other practical measures can be to lower the operating temperature of the oil by running pumps and or fans continuously. The old CEGB maxim is that if you lower the average operating temperature of your transformer by 6°C you double the life of the paper insulation (speak to a chemist).
Replace the oil

Traditionally the “go to” solution when faced with rising acidity in oil. History (the author has over 25 years of it in the electrical oil business) teaches us that with intensive effort you can achieve a really good result effectively replacing 95-97% of the oil, the rest remains in the windings. Note the words “intensive effort” – the example in mind is a generator transformer from a CCGT station in the south of England, the volume of oil below the bottom drain valve was approx.. 2,000 litres (80,000 litres in total) and specially made attachments combined with clearing substation stones were needed to get to this residual oil. On top of this the transformer was drained, flushed (with top covers removed, scaffolding etc) twice with over 24 hour stand times in between. A source of dry air was needed whilst the transformer was going through these drain and flush cycles. Vacuum and filling with subsequent circulation took another 4 days or so. All in all a good week’s work with 4-5 people on site at any time to work on or assist with the project.

These days time limits, resource limits, outages or cost restrictions prohibit such intensity of effort and a simple drain, stand and refill is carried out – with or without a mobile processing unit to flush and circulate the oil. In such cases it is typical to find only 85 – 90% of the total oil volume is replaced.
Residual “acid” oil will of course leach out of the paper insulation over the following Months and mix with the replacement oil. Such leachate leads to further deterioration of the body of the oil acting as it does as a catalyst for early stage oxidation.
So the message is you need to treat the whole insulation system and not just the oil. You need to get to the parts of the transformer that an oil change doesn’t usually reach.

In-situ oil regeneration
Common practice in North America, Canada, South Africa and parts of Western Europe for many years this technique has only recently started to gain momentum in the UK. The reasons for the slow uptake in the UK are varied but in part it is down to the conservative nature of the UK ESI, the reluctance to add artificial inhibitors to oil after regeneration, some problems with the early design of certain regeneration units leading to post processing presence of corrosive sulphurs and a reluctance to carry out regeneration work on load which is much the better option for optimum efficiency of the process.
Several factors have come together to make the use of in-situ regeneration of oil an attractive proposition for today’s transformer owner.

  1. A better design of mobile plants, designed to eliminate the mistakes of earlier regen plants

  2. Recognition by OFGEM that oil regeneration is a tool that can be used by the UK DNOs to demonstrate “Health Index” improvement
  3. Pressure by industry insurance companies to test for an remove DBDS contamination found in most UK transformers filled in the 1990s

In-situ regeneration, done correctly can be said to “deep clean” the transformer paper insulation. With enough time, sufficient temperature and ideally, the transformer on load for added heat and vibration the final as left values are usually close to “as supplied” or unused oil as per IEC60296:2013 for acid values (0.01mgKOH/g). Depending on how well all the above variables are met the resultant oil values after 6 Months of operation, allowing time for any residual oil in the paper to leach out remain well within BS148:2009 limits for acidity (0.03mgKOH/g).

Typical mobile plants operating in the UK will use bauxite or fullers earth as the adsorbant material (dissolved polar contaminants – acids, soluble sludges, DBDS and indeed water are all polar and will “stick” to the bauxite or fullers earth) which is reactivated on-site (usually overnight) after 30-40,000 litres of oil have been passed through)
Connection and disconnection to a transformer can be made whilst the transformer is energized and carrying load providing safety distances are not infringed. In practice many DNOs prefer to have a short outage at the beginning and end of the work to facilitate connection and disconnection.
Figure 5 shows a diagram of a typical connection for live working, which usually include top and bottom solenoid actuate valves that will automatically close on loss of power, a bypass connection between them to allow a “primary circulation loop” to be established and allow full de-aeration of the oil before any transformer valves are open and an optional transformer conservator level monitor.

FIGURE 5 (with kind permission of Arras-Maxei)

Before the oil in a transformer is admitted to the adsorbant material the oil will first be treated using conventional reconditioning equipment heat, vacuum and fine filtration to a) lower water in oil to acceptable levels (usually ,10ppm) and b) to get some additional heat into the transformer.

Usually after the first 24 hours the oil will be admitted to the adsorbant beds at a flow rate of 5,000 litres per hour for approx. 8 hours. The beds are then isolated and reactivated overnight. Either a second bed can be used thereafter or the transformer oil is continually reconditioned until the morning when a second “pass” through the adsorbant bed can occur.
Typical time on site for starting conditions of 0.15mgKOH/g, water 15ppm will be 7-10 days for a 132kV transformer, 4-5 days for a 33kV transformer. A generator transformer containing 80-100,000 litres can take 20 days or more.
Here are some case studies carried out over the last 5 years by way of example.
Example 1

TATA Steel – ST9

  • Installed circa 1952

  • 66kV

  • 10MVA

  • Oil Quantity 17,000 litres

  • DP of paper 420

  • No history of faults

  • DGA normal for a transformer of this age

  • 5 years of history post regeneration




Left alone and neglected for over 50 years the family of 66kV Supply Transformers at TATA Steel’s Port Talbot works stand testimony to the build quality of transformers in the post war years. Despite its age T9 has a paper strength suggesting just under half life and with the future of UK steel production constantly under scrutiny the capital expenditure necessary for a full blown transformer replacement programme could not be justified at the time (2011). An oil change was considered by TATA steel engineers but the benefits of in-situ regeneration as previously discussed, out-weighed any initial concerns.
The transformer was treated off-line and early in the season when ambient temperatures were below 10 °C, despite that the oil temperature coming into the Mobile Regeneration Unit (MRU) reached 50°C with WTI just over 70°C as shown in figure 9 above. It should be noted that this process works best if you can obtain working oil temperatures of 70°C plus which is roughly the Aniline point of an insulating oil and enables the oil to become a solvent for oxidation products.
As ever, time and temperature remain key to a successful regeneration operation, that and the ability to carry out all necessary tests at site, so all concerned can gauge the progress of the work.

Water removal
After 115 hours of treatment (partly through the regeneration columns and continuously through the normal reconditioning plant water levels gradually reduced from a starting point of 20ppm to 3 ppm, this form of gradual reduction is typical when outer layers of paper insulation are releasing some of their water into the oil as processing temperature increases.

Subsequent samples show a steady increase in water in oil - these samples were taken by site staff and when tested in early 2016 by EOS personnel measured water contents show levels similar to the start conditions in 2011. Such a transformer could benefit from the fitting of a molecular sieve to keep removing water at a slow pace, from the paper insulation.

Acidity and other polar contaminants
Figures 6, 7 and 8 all show marked improvements in the measured parameters acidity, DDF and IFT and all remain in the “good” column of BSEN60422:2013 5 years after treatment.
The transformer was dosed with 0.4% inhibitor at the end of the treatment, this is monitored annually and will help slow down further oxidation in the oil.
Topping up of inhibitor should be carried out using concentrate solution, pumped into the top or bottom filter valve with the transformer pumps running or when a reconditioning unit is on site

Example 2

OFGEM DNO Grid Transformer Grid T1

  • 132kV

  • 90MVA

  • Oil Quantity 38,710 litres

  • DP of paper 450

  • Installed in 1963

  • No history of faults

  • DGA normal for a transformer of this age




This DNO transformer, treated as part of a rolling programme of life extension work was identified as a suitable candidate for treatment, although at a starting acidity somewhat higher than recommended the paper strength indicated by the laboratory DP (Degree of Polymerisation) test indicated just under half life remaining despite the transformer being well over 40 years of age.

More follow up tests will be carried out before the end of 2016 to further assess the work and to see if the inhibitor content needs adjusting.

And colour?
When it comes to assessment of an insulating oil from a sample taken on site (you have to use a clear glass bottle of course) much helpful information can be gathered from an oils general appearance “clear, bright and free from visible contamination” is always a good starting point. Cloudy oil could indicate the sample is close to saturation with water at that temperature, visible contamination in the oil could be a sample error or not.
These days unused insulating oil has a water white colour, up until the early 1990s all insulating oil used to fill new transformers was of a “pale straw” colour. With the advent of hydro treated oil into the UK market the white oil became the norm and has ever since been associated with “new “ and “quality” – despite the recent DBDS contamination scandal, but lets leave that chestnut for another presentation.
In reality colour as a determining factor to an oil’s “quality” is misleading at best, typically reclaimed insulating oil which is widely used by the UK DNOs for all maintenance activities up to 132kV, is perfectly acceptable and fit for purpose alternative to unused oil but it is pale straw in colour. This colour difference is due largely to the greater levels of (good) sulphur in the oil compared to unused oil. Remember that an uninhibited oils’ “natural” ability to withstand oxidation depends largely on the presence of sufficient sulphur in the oil.

It is true, however, that as an oil ages its colour will darken, this is usually down to oxidation but the oil will also change colour depending on how it reacts with the transformer internal construction materials. Oil from older transformers can take on a strong shellac smell from the varnish used on transformer steel for example.

When it comes to on-site regeneration of oils as discussed in this paper colour change is a helpful indicator of progress but detailed analysis of acidity, IFT and DDF on site, as part of the service offering should always be the primart indicator of how well the work is going

The two samples shown above in Figure 13 relate to recent work undertaken at Little Barford power station in Cambridgeshire. Acidity in this 85,000 litre generator transformer was just under 0.3mgKOH/g at the beginning of the on site treatment

After just over 2 weeks of on-load treatment the oil’s final values were close to unused oil and colour had dramatically improved as a result.

Gone are the days of so called over-engineered transformers built with a good margin of error, with quality internal construction materials and lots of insulating oil. Today’s transformers are not built to common BS171 or BEBST2 standards but to functional specifications and often at lowest cost. It is therefore inevitable that the transformer owner will have to look closely at insulation management in a way that perhaps wasn’t necessary 40 years ago if he or she wants to see an equivalent life span from such units.
In 2016 there is clearly an emphasis on making transformers last longer, that much is clear. With OFGEM recognizing the benefits of in-situ oil regeneration and accrediting it as a practical tool to help improve the transformer health index such on-site treatment is gaining momentum and acceptance in the UK.

The “deep cleaning” effect of professionally carried out on-load oil regeneration has clear benefits over conventional oil changes in both downtime, cost and effectiveness. Users and service providers need to work closely and engage professionally and honestly when it comes to making strategic decisions regarding particular target transformers.

The Author would like to thank the following people who, in some way or other, contributed to this paper.

Mr Keith Burkin (formerly of EOS Ltd) for all his mentoring over a 25 year working relationship.

Mr Charles P.Tart (former National Power Transformer Engineer) for his passion and enthusiasm for all things transformers.

Mr Tom Larney of EOS Ltd and formerly Nynas for his sanity checking (especially regarding the unused (new) oil market.

Mr David Davis and Mrs Elizabeth Mackenzie for the discussions around the UK Electricity Supply Industry history

Aras Maxei for the use of their regeneration schematic

Mr Guy Kay for the use of a photograph of an Omnia transformer dryer
[1] p80-81, Sigant and Lacey, The J&P Transformer Book, 1941, Eighth edition, Johnson & Phillips ltd
[2] p17, International Electrotechnical Commission, Fluids for electrotechnical applications – Unused mineral insulating oils for transformers and switchgear, Edition 4.0, 2012-12
[3] p758, Sigant and Lacey, The J&P Transformer Book, 1941, Eighth edition, Johnson & Phillips ltd
[4] OFGEM, RIIO-ED1 electricity distribution price control – overview of the regulatory instructions and guidance 18th June 2015

[5] p1 Tart C.P, Transformer Oil Processing Techniques; The “Wet”? Transformer. The National Grid Company PLC, Technology and Science Division Conference – Condition monitoring in high voltage substations, May 8th & 9th 1996

[6] p17 International Electrotechnical Commission, Fluids for electrotechnical applications – Unused mineral insulating oils for transformers and switchgear, Edition 4.0, 2012-12
[7] p29, BSEN 60422:2013, Mineral insulating oils in electrical equipment – Supervision and maintenance guidance, The British Standards Institute, 2013
[8] p37, BSEN 60422:2013, Mineral insulating oils in electrical equipment – Supervision and maintenance guidance, The British Standards Institute, 2013
[9] p6, BS5730:1979, Code of practice for Maintenance of insulating oil, British Standards Institution, 1979

Andy has worked in the electrical oil industry for 26 years and with EOS since its formation in 1999. Prior to this he was employed by the Central Electricity Generating Board (CEGB) as a 400kV SAP in the Transmission Division which became National Grid, shortly before he left to Join Carless Refining and Marketing.

Now as Sales Manager for the UK’s leading insulating oil and services provider Andy leads a team of three Electrical Engineers offering guidance on all aspects of insulating oil management, testing and on-site treatment.

Andy lives in the Cambridgeshire fenlands, is married with two (just about) grown up children.


[Appendix Title]

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