Oxidation Stability of Insulating Fluids

526
Oxidation Stability of Insulating Fluids
Working Group
D1.30
February 2013
OXIDATION
STABILITY OF
INSULATING FLUIDS
WG D1.30
Members
Bertrand Y. (FR), Dahlund M. (SE), De Pablo (ES) – corresponding member,

Ese M.-H. (NO), Gupta TCSM (IN), Hilker A. (DE), Jones C. (AU) – corresponding
member, Koncan-Gradnik M. (SI) – corresponding member, Kovacevic S. (CA),
Kratky H. (AT) – corresponding member, Lessard M.-C. (CA) – corresponding member,
Lukic J. (SR), Maina R. (IT), Mendes J.-C (BR) – Link to A2, Moss G. (GB),
Newesely G. (AT), Perrier C. (FR), Scatiggio F. (IT), Schaut A. (BE), Smith P. (DE),
Sokolov V.† (RU), Wiklund P. (SE), Wilson G (GB) – corresponding member,
Yu H. (CN) – corresponding member
Further contributing members: Haug A.-M. (NO), Laboncz S. (HU), Wilhelm, H.M. (BR)
Ivanka Atanasova‐Hoehlein ‐Convenor (DE)
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ISBN : 978-2-85873-219-7
Oxidation Stability of Insulating

Fluids
Table of Contents
Chapter 1. Why Is Oxidation Stability of Insulating Fluids Important?......................................... 4
1.1 General Introduction to Oxidation Stability of Insulating Fluids .......................................... 4
1.2 The Impact of Oxidation Stability on Transformer Insulation System and Functionality .. 6
1.3 Influence of degradation products of oil on cellulosic insulating parts ............................... 7
1.4 Survey “Working Environment of an Insulation Fluid” within Cigre D1.30 ......................... 8
Chapter 2. Types and Behavior of Insulation Fluid ......................................................................... 12
2.1 Classifying Insulating Mineral Oil .............................................................................................12
2.2 Refining methods ..........................................................................................................................12
2.3 Napthenic or paraffinic ..............................................................................................................13
2.4 Inhibited vs. uninhibited oil .........................................................................................................14
2.5 High grade or standard grade ................................................................................................15
2.6 Gassing Tendency........................................................................................................................15
2.7 Viscosity class and low temperature properties .................................................................... 15
2.8 Fluids other than mineral oils .....................................................................................................16
Chapter 3. Chemistry of insulating fluid oxidation.......................................................................... 17
3.1 Oxidation stability of mineral oils ............................................................................................17
3.2 The mechanism of oxidation.......................................................................................................17
3.3 General aspects of oxidation chemistry of oils ..................................................................... 19
3.4 Inhibition of Oxidation ................................................................................................................19
3.5 Short General Résumé ................................................................................................................20
3.6 Oxidation Stability of Vegetable Fluids ................................................................................. 21
3.7 Chemistry of Oxidation of Vegetable Fluids ......................................................................... 22
3.8 Oxidation Stability Studies on Natural esters........................................................................ 23
3.9 Factors that influence oxidation stability................................................................................. 24
Chapter 4. Influence of Oxidation Stability on Diagnostics .......................................................... 27
4.1 Influence of oxidation on the gas-in-oil analysis ................................................................... 27
4.2 Influence of oxidation on oil parameters. ............................................................................... 28
4.3 Behavior of Uninhibited Mineral Insulating Oils in Service (Experience in Italy) .............34
4.4 Behavior of Inhibited Oils in Service (Experience in Serbia) ............................................... 37
Chapter 5. Prolonging Life of Insulating Oil in Service .................................................................. 44
5.1 Inhibition of non-inhibited Oils/Reinhibition ............................................................................ 44
5.2 Oil Reclaiming ..............................................................................................................................45
5.3 Behavior of reclaimed oil in service (field experience in UK) ............................................. 51
5.4 Influence on the oil reclaiming on insulating paper ............................................................... 53
5.5 Oil reclaiming and Corrosivity ..................................................................................................54
5.6 Oxygen Removal in Service ......................................................................................................54
Chapter 6. Oxidation Stability Testing .............................................................................................55
Page 2
6.1 Specifications for Oxidation Stability .....................................................................................55

6.2 Methods for Evaluating Oxidation Stability - Different Methods, Different Results ......58
6.3 Comparison Between Different Oxidation Methods ............................................................. 59
6.4 Comparison of IEC ASTM Baader Method for Oxidation Stability ................................... 59
6.5 Comparison of IEC 61125C and ASTM D1934 .................................................................... 60
6.6 Comparison of IEC 61125B, IEC 61125C and (EN 14112) ............................................... 60
6.7 Description of different oxidation stability procedures ....................................................... 61
6.8 Round Robin Test on Oxidation Stability ................................................................................ 68
Chapter 7. Summary and Conclusions................................................................................................ 74
Bibliography ...........................................................................................................................................76
Page 3
Chapter 1. Why Is Oxidation Stability of Insulating Fluids Important?

1.1 General Introduction to Oxidation Stability of Insulating Fluids
The requirements for insulation liquids for transformers change with the development of the electrical equipment
and combine basic dielectric and physico-chemical properties necessary for insulation, adequate cooling and long-
term stability. Historically, mineral oils are the most widely used and largest type of insulating fluids.
It is well known that any insulating liquid serves four main functions:
- To remove the heat generated by no-load and load losses

- To insulate electrically, also in combination with solid materials
- To lubricate moving parts (pumps, selectors, tape changers, etc.)
- To protect the insulating system
Consequently, the following is required of any insulating liquid:
- High dielectric strength

- Low dielectric losses
- Adequate permittivity
- High arcing quenching capability
- High chemical and physical stability over the long term
- High thermal capacity and conductivity
- Low viscosity and good performance at low temperatures
- Low vapor pressure
- Low solvating
- Non-toxicity and environmental compatibility
- Low flammability
- Simplicity in conjunction with commissioning and standard maintenance
- Easy disposal
- Low price and wide availability
The long term stability of insulating fluids is a result of their thermal endurance, hydrolytic and oxidation stability, as
well as compatibility with other transformer materials (e. g. copper, cellulose, insulating varnish, etc.). A low intrinsic
gassing behavior is usually desired to guarantee a low background level for reliable detection of failures through
dissolved gas analysis (DGA). Last but not least there are growing interests for requirements for challenging
applications, such as fire resistance or environmental risks.
Material specifications for transformers are designed to reflect the transformer operating environment. Often,
however, there is a need for simplifying testing procedures to get quick results. In such cases attention should be
paid to whether such methods are still able to reliably reflect the transformers operating environment and stresses.
For high operational stresses, the strictest requirements for insulating fluids, especially mineral oils and esters can
hardly be achieved without the addition of additive packages. It is unrealistic to compare the oxidation stability of an
uninhibited with that of an inhibited oil.
The present test methods for oxidation stability take the different oxidation behavior of uninhibited and of inhibited
oils into consideration by differences in the testing time. A disadvantage of some of these methods is that the
ageing is carried out to the breakdown stage – with development of acidity and sludge.
An alternative approach is to identify the sludge-free and acid-free time for an oil, also in consideration of different
temperatures and major transformer materials. It seems likely that in the future one must also consider preventive
measures that help to maintain the safety margins and protect the solid-liquid insulation in transformers.
Combination of both methods could help fulfill specific requirements for challenging operational conditions.
Page 4
However, not all applications ultimately need the strictest requirement for oxidation stability. The existing practices
and experience using either free-breathing equipment or alternatively equipment with a reduced oxygen content
must be reviewed.
Fig. 1 Sludge, deposited on insulating Fig. 2 Buchholz relay, covered with

parts sludge, which may jeopardize its
function
Oxidation stability is an important characteristic of an insulation fluid. In the case of mineral oils uncontrolled
oxidation may lead to the formation of polar oxidation products, depositing on paper and changing its dielectric
properties (Fig. 1). Sludge formation can lead to plugging up of cooling channels and changing the thermal design.
The functionality of mechanical components like Buchholz relays may be jeopardized (Fig. 2). Oxidation may be
accompanied with a strong increase of the dissipation factor and a decrease of resistivity, which can be critical in
the case of electrical equipment with a small oil volume, such as instrument transformers or bushings. Dielectric
instability of oil in current transformers has been reported [1]. Strongly oxidized oil with a high conductivity may also
have an influence on the diagnostic criteria of a transformer as a whole, e.g. on the measured insulation resistance.
A certain oxidation stability is necessary even in “closed type” transformers, since air is always present, even in low
amounts. Furthermore, there is never a life long guarantee that hermetic conservation systems, membranes or
rubber bags will perform properly. Advanced oxidation of a natural ester liquid change the viscosity characteristics
and in extreme cases may lead to sticky insoluble deposits.
Oxidation stability is one of the most important characteristics of insulation fluids. It is a part of the requirements for
consistency and stability.
This has been recognized by users and by sales alike.
The first publication in 1923 of BS148, which was the standard for unused insulating oils for use in transformers in
the United Kingdom for many years, includes an oxidation test. By today’s standard it was not onerous because it
only considered sludge production; the level of acidity during the test was not included until a later revision (in
1951) and the new oil itself had very relaxed requirement for acidity at 2.0mg KOH/g. The second revision of the
same standard in 1933 used the sludge test to differentiate different grades of oils. Other specifications of the time
also had requirements of oxidation stability, for instance VDE 0370 in Germany talks about oxidation stability as a
tendency for ageing (Fig. 3).
Page 5
Fig. 3 Title page of VDE 0370 (Germany) from 1936
Advertising for transformer oils is reflected in the world literature, emphasizing, that the requirement for consistency
has always been primary for the user:
„What really counts, more than anything else, is the consistency of specifications in every grade, the characteristics
that indicate the merit of a given oil….Always the same! Always! Identical, any time and any place: from one
shipment to the next. The world can come to an end, the phoenix can rise from its ashes, the Coliseum can catch
fire, but…..transformer oil is what it is, and remains what it is!“
Carlo Emilio Gadda from "That Awful Mess on the Via Merulana", 1957
1.2 The Impact of Oxidation Stability on Transformer Insulation System and Functionality
The insulating fluid in a transformer has an insulating as well as a heat transfer function. Changes in dissipation
factor or viscosity will inevitably influence these characteristics. The influence of oxidation on insulating oil is
summarized in Fig. 4 [2, 3, 4, 5, 6]
Page 6
CAUSE EFFECT
 Insoluble oxidation products Deposit formation (Sludge)
OIL
OXIDATION  Soluble organic acids, plus Oil thickening REDUCED
 Soluble polymeric material OIL LIFE
• Insoluble oxidation products Lacquering
• Soluble organic acids Oil acidity increase
Insoluble
Insolubleproducts
productsof
ofoil
oiloxidation
oxidationare are
aaprimary
primary cause of reducedoil
cause of reduced oillife
life
Fig. 4 Influence of oxidation on insulating oil
1.3 Influence of degradation products of oil on cellulosic insulating parts

Heavily aged oil has a big impact on insulation surfaces, as it can be seen on the following example:
Example: 200 MVA transformer, after 30 years of service exhibited a neutralization value of 0.22 mgKOH/g oil,
interfacial tension of 14 mN/m and dissipation factor of 0.113 at 90°C. Heavy sludge deposits have been found on
the internal tank walls and on insulation parts (Fig. 5). The cooling ducts have been clogged with thick chloroform
insoluble material. Transformer operation has been jeopardized because of overheating, caused by accelerated oil
degradation.
Fig. 5 Insulation parts covered by thick sludge deposits caused by accelerated oil degradation
Page 7
1.4 Survey “Working Environment of an Insulation Fluid” within Cigre D1.30

In this survey 25 utilities, 13 manufacturers and 4 consultants took part. Users rely on existing standards and
guides. Additionally an overview of the specifications used throughout the world for oxidation stability is presented.
General conclusion from the questionnaire evaluation:
 The use of insulating fluid is based to a great extent on historical experience and on existing standards. In
many cases low oxidation stability has been experienced, but the problems do not seem to be very severe,
leading to an equipment failure.
 Oil performance seems to be regarded as a whole and oxidation stability is only a part of it.
 It seems to be a trend toward higher loading of transformers in the future (better utilization of existing
networks), as well as from non-inhibited to inhibited mineral oils.
1.4.1 PARTICIPANTS
25 utilities, 13 manufacturers, 4 consultants took part in the survey. The geographical distribution of the participants
is shown on Fig. 6.
Fig. 6 Geographical distribution of the participants in the survey (the points are related
symbolically to a country, but do not indicate a city).
Page 8
1.4.2 TYPES OF TRANSFORMERS

Types of installed transformers which form the basis for the answers are shown in Table 1.
Table 1 Types of transformers

Answer Number of answers
core type 29
shell type 10
no answer 14
generator transformers 21
shunt reactors 23
network transformers 28
industrial transformers 8
distribution transformers 21
traction transformers 5
System auxiliary transformer (SAT) 1
Tap Changer 2
instrument transformers 17
1.4.3 PROBLEMS WITH OXIDATION STABILITY?

The answers show that oxidation stability is important, however, is not considered as a main issue (Table 2). It
seems that a considerable part of the users are not aware what the consequences of a bad oxidation stability could
be.
Table 2 Problems experienced with oxidation stability

Yes 12
No 12
Rarely 3
Sometimes 3
No answer 11
Page 9
1.4.4 WHAT KIND OF OIL IS PREFERRED?

Although uninhibited oils have still a minor majority (historical), it seems that there is a big shift to inhibited oils
(Table 3). This was explicitly emphasized by several participants.
Customer requirements, historical price considerations play an important role. Health and safety requirement, e.g.
lack of polychlorinated biphenyls (PCB) is also important.
Table 3 Preferred type of insulating oil

inhibited 15
uninhibited 17
Both (inhibited and uninhibited) 5
2 (partially inhibited, spec of

other
transformer manufacturer)
No answer 4
1.4.5 WHAT IS THE STANDARD USED?

It seems that IEC 60296 enjoys wide acceptance (Table 4). Local standards are used in the corresponding country.
For many users it is important to have a standard, but it is not explicitly indicated.
The application seems to play an important role for choosing an insulating liquid (15 answers). A large majority
uses naphthenic oils (21 answers), some users use both (napthenic and paraffinic) (8 answers). Some participants
answered that they use paraffinic at lower voltages and naphthenics at higher voltages. Concerns in case of
paraffinics are wax and availability.
Table 4 Applied standards for insulating oil

Standard used Number of answers
IEC 60296 10
Brazilian 3
CSA Std 1
BS, IEC 1
Australian Std. 1767 1
ASTM D3487, CAN CSA-C50.97 1
Doble TOPs 1
IEC, Doble 1
Existing spec. 1
No answer 23
Page 10
1.4.6 ALTERNATIVE FLUIDS

Only 6 participants currently use silicone fluids or esters, but a further 17 participants state that they are interested
in the use of alternative fluids because of environmental or safety issues.
1.4.7 ELECTRICAL AND THERMAL STRESS

The information on the max. temperature stress to which an insulating fluid is exposed is very controversial. The
answers vary between 105°C and 160°C.
Presumably the question has not only been referred to oil bulk, but also to max. allowed hot-spots.
The answers on the max. electrical stress also vary. There are mainly 2 groups of answers:
- 5 – 10 kV/mm (presumably based on breakdown of oil)
- 20 – 30 kV/mm (presumably based on lightning or switching impulse voltage test)
1.4.8 RATIO COPPER:OIL (W/W)

The answers here vary between:
1:1–4
1.4.9 CONCLUSION
The use of insulating fluid is based to a great extent on historical experience and on existing standards. In many
cases low oxidation stability has been experienced, but the problems do not seem to be very severe, i.e., leading to
an equipment failure.
Oil performance seems to be regarded as a whole and oxidation stability is only a part of it.
There seems to be a trend toward higher loading of transformers in the future (better utilization of existing
networks) as well as to inhibited insulating oils. Alternative fluids are being regarded, but are still used only for
special applications.
Page 11
Chapter 2. Types and Behavior of Insulation Fluid

2.1 Classifying Insulating Mineral Oil
There are several ways of classifying insulating oil, most based in one way or another on the chemical composition,
but some also based on the refining method or physical properties. Hence, oil may be divided into naphthenic or
paraffinic, inhibited or uninhibited, gas absorbing or gas evolving, viscosity class “I” or “II”, etc. Some of these
classifications are becoming less significant as a consequence of changes in production technology, while some
are still highly useful. This section of the report aims at explaining some of the classification systems providing
some idea about their current relevance.
In order to understand the principles of insulating oil classification, a brief introduction in the refining methods is
necessary.
2.2 Refining methods

Some typical refining steps are employed to refine insulating oil from crude oil.
This process starts with fractionated distillation of the crude oil to separate fractions of different boiling range from
one another. Out of the different fractions (with different viscosities) a suitable one is selected (widely referred to as
light spindle oil). Sometimes the distillation residue is distilled under vacuum and the lightest of the vacuum
fractions is selected as a component for the production of insulating oil.
Depending on the source of crude oil, these distillates may be neutral or have a certain acidity and a high content
of aromatic compounds and heterogenic molecules.
In the early times of refining the first step of refining was a treatment with sulfuric acid to sulphonize the
polyaromatics respectively to reduce total aromatics as well as most heterogenes that normally bond to aromatic
molecules. All these extracted materials together with the acid employed form the so called acid goudron and were
separated by so called “agiteurs” (by difference of spec. gravity) or by centrifuges. The amount of separated
goudrons (acid + production losses) was waste material to be treated or disposed of, both of which is very
expensive.
The remaining low acidity of the refined oil was to be neutralized with lime or soda and the resulting product filtered
using clay. The decrease of total aromatics by this treatment was approx. 4-6%, the resulting final product (if
naphthenic) had a CA of 15-18%. Although this seems to be a high value, these oils had an acceptable oxidation
stability and met the standard requirements at the time (1930-1950)
Today acid/clay treatment is an obsolete refining process mainly due to the environmental impact of the waste
products and its disposal costs.
In the early 1950s the extraction technology (developed for lubricating oils) was introduced for the production of
insulating oils. The most used solvents were phenol and 2-furfural, which has a strongly selective solvent power to
aromatic molecules. Aromatics, but not with paraffinic or naphthenic structures are very soluble in 2-furfural and the
reduction of the aromatic content of the feedstock was remarkable, between 10 - 15%, depending on the 2-furfural-
ratio.
Combined with a final acid/clay treatment this refining procedure resulted in quite good insulating oils with high
oxidation stability and excellent electrical properties.
But a disadvantage of this process was expense, as the extracted by product, the so called “extract” had a low
economic value. For a time it was used as softeners in the rubber industry or for tire production.
Page 12
To avoid “acid goudrons” in the 1960s the hydrogenation technology was introduced for refining of insulating oils, in
the early days as a final treatment in combination with solvent extraction (so called “hydrofinishing” with hydrogen
pressure up to 40-50 bar).
With the development of specific catalysts and increasing pressure this technology has more and more replaced
the extraction process, especially in the use of naphthenic distillates (since the early 1980s). Many refiners have
completely changed to this high pressure hydrogenation, but there are still extracted/hydrofinished insulating oils
on the market.
The intensity of refining (and therefore quality of the final product) depends on hydrogen pressure, type of catalyst,
temperature and speed of the process. The higher the intensity (“degree of refining”) the stronger the reduction of
unwanted polyaromatics, aromatics and heterogenes and the higher therefore the thermal and oxidation stability of
the final product. But there is a certain point of intensity where the result of refining (seen as oxidation stability) is
an optimum. A further increase of refining intensity would reduce the aromatic content too much and reduce the
oxidation stability of an oil without synthetic axitioxidant (see Fig. 7)
Fig. 7 Properties of insulating oils depending on the degree of refining [3]

For very demanding applications in the future (high ambient temperature, extremely high load) new refining
technologies such as hydrocracking or GTL (Gas to Liquid) processes may be used to produce mineral based
insulating liquids with higher thermal limits or higher oxidation stability. In fact, hydrocracked oils are already being
used in some places, sometimes on their own (with only antioxidant added) or sometimes blended with mineral oil.
The response to inhibitor is very closely connected to the degree of refining.
 Oils of high degree of refining have lower inherent oxidation stability

 But highly refined oils also have a very high response to antioxidants
 Highly refined oils have superior oxidation stability after addition of antioxidants
 In such cases there is no correlation to oil origin/structure
2.3 Napthenic or paraffinic

This classification refers to the type of hydrocarbon that is dominant. Typically oil with more than 50% of the carbon
atoms in paraffinic structures would be considered as a paraffinic oil, while an oil with less than 50% would be
“naphthenic”. The proportions depend mainly on the composition of the crude oil used.
Page 13
Some significant differences in physical and chemical properties are listed below:
 Paraffinic structures have a high viscosity index, meaning the decrease of viscosity with increasing
temperature is low (important for engine/motor oils)
 Paraffinic oils have a lower density than naphthenic oils (more volume for the same mass, this is an
advantage for the purchaser).
 Paraffinic oils have a lower solubility for oxidation products and precipitate them earlier as sludge during
service life in a transformer.
 Finally, they have a higher pour point than naphthenic structures/insulating oil (e.g. –10 to –20°C
depending on the degree of dewaxing) and sometimes need a pour point depressant additive.
According to IEC 60296 Ed.3/2003 they may be used in countries with mild/hot climates down to LCSET of –10°C
(therefore Pour Point –20°C) without use of PPD (Pour Point Depressants).
Some experiments show, that paraffinic oils exhibit higher acidity and sludge formation than naphthenics under
ageing conditions [4]. The classification into naphthenic or paraffinic may be misleading for the new hydrocracked
oil. In these oils, branched non-cyclic saturated hydrocarbons are dominant, and based on, for example carbon
distribution analysis, they would obviously be classified as paraffinic. They have the high viscosity index typical of
paraffinic oils, but the low temperature flow properties are more like those of naphthenic oils.
2.4 Inhibited vs. uninhibited oil

This is a classification that is very significant. The formal classification is based simply on the actual content of
synthetic antioxidant of the hindered phenol type. However, the properties of the oil will depend very much on the
base oil used. “Base oil” is not a very precisely defined concept, but in this discussion let us use the term to
describe the final product minus the additives.
When formulating mineral insulating oil, there are two basic types (at least in theory). Either you are allowed to
make use of synthetic phenolic radical scavengers, or you are not. The former type of oil is referred to as
“inhibited”, the other “uninhibited”. Inhibited and uninhibited oils may behave in quite different ways. This is
because the inherent oxidation stability of the oil depends very much on the degree of refining, as was also
discussed above under the heading “Refining Methods” and chemistry of oil oxidation. This section contains some
repetition, but it is important to understand why the different types of oil behave in very different ways.
The more highly refined the oil, the less aromatics, polyaromatics and hetero-compounds (molecules containing
other atoms than carbon or hydrogen) that will be left. Some of these removable components are easily oxidized,
while others provide some protection against the normal oxidation process. Typically there is some kind of optimal
degree of refining with respect to oxidation stability that will yield an oil with fair oxidation stability without any
synthetic additives. The uninhibited oil starts to oxidize more or less from day one, albeit at a moderate rate, since
it contains a certain amount of so called natural antioxidants, some of them present from the beginning (mostly
sulfur-containing peroxide scavengers); others being formed by the oxidative processes (mostly radical scavengers
formed by oxidation of aromatic compounds).
However, if we look at how the oil behaves after the addition of synthetic radical scavengers, a totally different
picture will emerge. Typically the oxidation stability of oil with a phenolic antioxidant will improve as long as the
degree of refining increases. In an optimally formulated inhibited oil, based on highly or very highly refined base
oils, the oxidation rate is extremely slow as long as there is still some phenolic antioxidant left. Usually 0.25-0.40 %
of DBPC (di-tert-butyl-paracresol) is added at the refinery or blending plant. This is normally sufficient to suppress
the oxidation processes for many years. However, when such an oil runs out of antioxidant, the oxidation will
proceed at a significantly higher rate. Obviously one tries to avoid this situation by maintaining an appropriate
content of antioxidant.
Page 14
Real life is of course more complicated than the clear cut cases that we have in theory. A real product can be a
blend of oils with different degrees of refining. Synthetic antioxidants can be added also to originally “uninhibited”
oil, although the response to the inhibitor, in terms of the time during which the antioxidant efficiently suppresses
the oxidation, is normally poorer than for the oil that was from the beginning designed for use with inhibitor. Many
oils sold as inhibited are in fact basically of the uninhibited type, but with inhibitor added. This may be for logistic
reasons (it is simpler for a supplier to deal with very few base oils) or it is in some cases a kind of “belt-and-braces”
philosophy, where you want some of the benefits of both types of oil (the longer life of the inhibited oil, and the
more predictable ageing of the uninhibited oil). There is also an intermediate type, usually called “trace inhibited”,
with a small addition of synthetic antioxidant (up to 0.08%). Such oils can be of either basic type.
Normally the oxidation stability requirements put on the different types of oil differ significantly. Test times are
generally much shorter for uninhibited oil compared to inhibited, when the same test is used [IEC 60296].
2.5 High grade or standard grade

The IEC 60296 oil specification, and some manufacturers' oil specs, classify oils according to expected life span,
with a high grade oil intended for demanding applications. This means that more stringent requirements for
oxidation stability are applied, sometimes together with some parameters related to degree of refining, e.g. total
sulfur content.
2.6 Gassing Tendency

Any mineral oil is able to absorb a certain quantity of gas depending on its chemical structure and the
environmental conditions. This property has been used to design insulating oils that absorb some gases (mainly
hydrogen) which are formed in a transformer in service based on effects originating from the electrical field:
Sometimes the oil is exposed to partial discharges due to electric overstressing. Depending on the oil composition
and the presence of some specific aromatic structures, such gases may be absorbed up to a certain degree. This
can be tested by IEC 60628 (perhaps with reference to electrical field in the cell). On the other hand, the necessary
aromatic structures have lower oxidation stability. Today, most inhibited insulating oils with low aromatic content
and high oxidation stability are gas evolving when tested according to IEC 60628.
In modern transformers strong partial discharges and therefore large quantities of gas formations should not occur,
as calculation of electrical fields, design and assembly processes have improved significantly and if there is a
partial discharge problem in a transformer in service, it is detected normally early enough by DGA to avoid a failure.
However some equipment design concepts may need compensation by gas-absorbing oils.
2.7 Viscosity class and low temperature properties

In the former edition of IEC 60296 (Ed.2/1981) insulating oils were classified in two viscosity classes according to
their viscosity. Class 1 had a maximum viscosity of 16.5 mm²/s at 40°C and a pour point of max. –30°C, whereas
Class 2 was limited with a maximum viscosity of 11 mm²/s at 40°C and a pour point of max. –45°. During the
revision of IEC 60296 (2003) it became obvious that it is more important for a cold start for a transformer to have a
low viscosity to enable the oil to start its circulation in the equipment, and a so-called LCSET (lowest cold start
energizing temperature) has been defined, at which the oil’s viscosity should be max. 1800 mm²/s. As a standard
this LCSET is defined with –30°C and by definition the pour point is defined to be 10 K below, therefore –40°C as a
standard. But this LCSET can be specifically selected depending on the climatic conditions and ambient
temperatures, for example as –10°C in countries with hot climate, or with –40°C in very cold regions.
In extremely cold countries (Canada, Scandinavian countries, Russia) a very low LCSET of –40°C is required. To
ensure the lowest possible viscosity at –40°C, such oil generally has a lower viscosity than “standard grades”, e.g.
approximately 7 mm²/s at 40°C. A limit of viscosity is given by the required minimum flash point (135°C).
Page 15
2.8 Fluids other than mineral oils

Silicon fluids have been used in equipment such as distribution and traction transformers. With regard to
environmental impact and fire protection the use of alternative fluids such as natural and synthetic esters is growing
[5, 6].
Page 16
Chapter 3. Chemistry of insulating fluid oxidation

3.1 Oxidation stability of mineral oils
A basic understanding of the mechanism is necessary in order to understand how oxidation is inhibited either by
naturally occurring components (uninhibited oil), or by added synthetic inhibitors (inhibited oil). The reactions
underlying the phenomenon of hydrocarbon oxidation are extremely complex. However, the principles are well
established in science and even most general texts in organic chemistry usually carry a section on those
mechanisms. The bibliography below gives a few references to more comprehensive papers and books on the
subject [7,8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18]. The text below intends only to provide a broad picture on how the
chemistry of oxidation works, with an account of the most important routes to oxidation products such as water,
alcohols, aldehydes, carboxylic acids and carbon dioxide.
Mineral insulating oil consists mainly of a complex mixture of different types of hydrocarbon molecules (paraffins,
naphthenes and aromatics), i.e. molecules that are built from only two types of atoms; carbon and hydrogen.
Insulating fluids of the ester type (natural or synthetic) also contain oxygen functionalities, but the basic
mechanisms of hydrocarbon oxidation still holds (although kinetics may differ). Non-carbon based liquids like
silicone fluid does not behave according to these mechanisms.
3.2 The mechanism of oxidation
Fig. 8 Schematic mechanism of hydrocarbon oxidation
The heart of the radical chain mechanism of oxidation of hydrocarbons is shown above (Fig. 8). The process starts
·
by (thermal) generation of a hydrocarbon radical R from a hydrocarbon molecule RH, by loss of a hydrogen atom
from the carbon backbone of the molecule. The dot symbolizes an unpaired valence electron, i.e. a radical.
Initiation (reaction I) is a rare event which only has to happen once to initiate the chain reaction. If oxygen is
·
present it will quickly react with the hydrocarbon radical to form a peroxy radical ROO . This is an example of a
propagation reaction as it generates a new radical species (P1). The peroxy radical can then go through two
different routes.
3.2.1 Route 1 (Fig. 9): A peroxy radical can abstract a hydrogen atom from another hydrocarbon molecule to
generate yet another hydrocarbon radical (reaction P2) and a hydroperoxide ROOH. This closes the cycle of the
chain reaction. In principle the reaction will continue in this manner as long as there is oxygen available. It is
therefore often referred to as autooxidation. The hydroperoxides that are generated in this process can react
further in a type of propagation reaction that generates two radical species per molecule. This is called branching,
and explains why the oxidation of hydrocarbons often accelerates (exponential growth of the number of active
radical species) after a period of induction.
Page 17
Fig. 9 Oxidation Route 1
· ·
Through these reactions alkoxy radicals RO and hydroxyl radicals OH can be generated from hydroperoxides.
Both of these new radicals can react with hydrocarbon molecules to form new hydrocarbon radicals that will react
with oxygen according to the mechanism above and thus further increase the total reaction rate (consumption of
oxygen). In this process alkoxy radicals form alcohols (ROH) and hydroxyl radicals form water. This route to
oxidation products is catalyzed by metal cations such as those of iron and copper. They do so through a
mechanism where a metal cation of a lower oxidation state is oxidized by a hydroperoxide under formation of
radical species.
3.2.2 Route 2 (Fig. 10): The other route to oxidation products goes through termination (Reaction T) of the chain
reaction when two peroxy radicals react with each other. This type of reaction yields an alcohol, oxygen and an
aldehyde (or ketone depending on substitution pattern).
H
O
2 R O R
OH + O2 + R Aldehyde
O
Alcohol
O2
O
R Peracid
O OH

R + CO2 R
O RH
R
O
+ R

O OH
Carboxylate Carboxylic
radical acid
Fig. 10 Oxidation Route 2
Aldehydes which have come about by this reaction of peroxy radicals can in turn be oxidized further to peracids
(via acyl radicals). Peracids in turn can form carboxylate radicals, which upon abstraction of hydrogen atoms give
carboxylic acids (and new hydrocarbon radicals which will partake in the oxidation chain reaction). This chemistry is
utilized industrially to produce formic acid from formaldehyde. Ketones behave in a similar fashion and can also
Page 18
give rise to esters when they react with peracids. Esters and water can also be formed by the (acid catalyzed)
reaction of alcohols and carboxylic acids.
Carboxylate radicals can alternatively form carbon dioxide (and new radicals) through a β-elimination process.
Carbon dioxide can also be formed by decarboxylation of carboxylic acids and carbon monoxide through radical
decarbonylation of aldehydes.
3.3 General aspects of oxidation chemistry of oils

When looking at the mechanisms above it is striking how complex the picture really is. The complexity of the
possible reactions further increases when considering that not only can a hydrocarbon molecule go through this
process once, but it can in fact take part in the oxidation process multiple times (in principle until only carbon
dioxide and water remain). Like most chemical reactions the rate of reaction (measured as rate of oxygen
absorption) approximately doubles when the temperature increases 7°C - 10 °C. This is valid up to about 250 °C,
after which the mechanisms partially change and the rate of reaction increases even more (combustion and finally
explosion).
It is a well known fact that the viscosity of oils tend to increase on oxidation. There are at least two explanations for
this effect. The first is that physical interaction between molecules increase as a consequence of the molecules
becoming more polar as more and more oxygen functionalities and unsaturation are incorporated (hydrogen
bonding and polarization). The second explanation is that hydrocarbon radicals can react with other radicals (a
form of termination) to form larger molecules which generally give higher viscosity. Sludge (material not soluble in
oil) can be formed through various paths including acid catalyzed condensation reactions of keto compounds,
(radical) polymerization and salt formation. Under extreme conditions polyaromatics and pure carbon (soot) can
form as a result of oxidative processes and contribute to the non-soluble sludge content.
In the context of insulating oils it is also of course well known that oxidation gives rise to smaller molecules such as
water soluble acids and carbon dioxide. These smaller molecules come about by various elimination and
fragmentation reactions (not covered here). Since such molecules generally evaporate they do not compensate the
average molecular size, and thus viscosity increases.
3.4 Inhibition of Oxidation

Molecules which inhibit the chain reaction of oxidation are called antioxidants. There are two principally different
modes in which these can act.
So called hydroperoxide decomposers act by reducing hydroperoxides to alcohols, i.e. they inhibit Route 1 (above).
These types of compounds include various non-heterocyclic sulfur containing compounds that can be found in
mineral oils. Uninhibited insulating oils depend on such compounds for their oxidation stability. The illustration
(Fig. 11) shows how an organic sulfide is successively oxidized by hydroperoxides (which is reduced to the
corresponding alcohol) to first a sulfoxide and then a sulfone.
O O O
ROOH ROOH S
S S
R R -ROH R R -ROH R R
Fig. 11 Oxidation of organic sulfides acting as hydroperoxide decomposers
There are also so called chain breaking antioxidants which react with formed radicals and stabilize the resulting
radicals, i.e. they inhibit both Route 1 and 2 (above). The result is a much slower, or totally inhibited, oxidation
Page 19
process. This group of compounds include hindered phenols such as di-t-Butyl-p-Cresol (DBPC a.k.a. BHT), a
synthetic inhibitor that is commonly added to inhibited grades of insulating oils (Fig. 12).
Y
. .
X Y
OH O O
-XH
DBPC Stable radical
Fig. 12 Oxidation of a hindered phenol, acting as a chain breaking antioxidant
The hydrogen atom of the hydroxyl functionality of the phenol is first abstracted by a radical X. (which is then
terminated). This yields a highly stabilized phenolic radical which is much less prone to take part in any propagation
of the chain reactions of oxidation. A second radical Y. can subsequently be terminated by the phenolic radical.
Thus one molecule of DBPC can terminate (at least) two radicals, which can be of any type that occurs in the
overall oxidation chain mechanism. This explains the great efficiency of phenolic type inhibitors.
Both types of antioxidants are eventually consumed, but the time this takes depend on temperature and oxygen
availability as well as on chemical composition of the oil. It should also be noted that the efficiency of antioxidants is
temperature dependant. Since the antioxidant effect is a kinetic effect there is a temperature window in which each
type of antioxidant is active. In a broader context than insulating oils chain breaking antioxidants are often referred
to as primary antioxidants, whereas peroxide decomposers are referred to as secondary antioxidants. Intensive
studies on the byproducts of oxidation and their influence has been carried out [17] For ultimate oxidation stability
in products like engine oils and other lubricants it is customary to combine several specific antioxidant additives of
the two different types.
3.5 Short General Résumé
WHAT PROMOTES PEROXIDATION?

- Oxygen availability
- High temperature
- Prooxidants
o Some types of molecules such as amines
o Catalysis by Transition metals (Cu, Fe etc.)
WHAT INHIBITS PEROXIDATION ?

- Inhibitors (antioxidants) slow down Peroxidation
- Two different types
1. Chain Breaking Inhibitors (radical catchers)
Chain Breaking Inhibitors (radical catchers) are mainly phenolic and aminic type anti-oxidants
Page 20
Examples are :
NH
R H
R'
N
Phenyl-  -naphthylamine (PAN) Alkylated diphenylamine

R NH
Alkylated Phenyl-  -naphthylamine (APAN)
2. Hydroperoxide decomposers
Compounds that react with hydroperoxides giving non-radical products. How? By being oxidized. They
are reducing agents. Most common are S or P species, e.g. DBDS (Dibenzyldisulfide)
3.6 Oxidation Stability of Vegetable Fluids

Oxidative stability is a significant issue for vegetable-fluid derived products and a deeper understanding of
oxidation stability of the various contributing factors is necessary.
The rate of oxidation of fatty compounds depends on the number of double bonds per molecule and their relative
location. The bis-allylic position in linoleic acid (Fig. 14) (double bonds at C-9 and C-12, giving one bisallylic
position at C-11) and linolenic acid (Fig. 15) (double bonds at C-9, C-12 and C-15, giving two bis-allylic positions at
C-11 and C-14) are even more prone to oxidation than allylic positions like in oleic acid (Fig. 13). Indeed the
relative rates of oxidation given in the literature are 1 for oleates (methyl, ethy esters) (18:1), 41 for linoleates (18:2)
and 98 for linolenates (18:3).
Small amounts of more highly unsaturated fatty compounds containing bis-allylic carbons have a disproportionately
strong effect on oxidative stability.
OH
Fig. 13 Oleic acid (cis- 9 -octadecenoic acid)
Page 21
OH
O
Fig. 14 Linoleic acid (cis, cis-9,12-octadecadienoic acid)
OH
Fig. 15 -Linolenic acid (cis,cis,cis-9,12,15-octadecatrienoic acid)
The Oil Stability Index (OSI) can be used for the assessment of oxidation stability of vegetable fluids. OSI is based
on determining the time (usually termed "induction time") before the maximum rate change of oxidation by
measuring the increase in conductivity of deionized water caused by dry air bubbled through a heated sample that
carries the resulting volatile acids into a separate container with the deionized water. The method is believed to
give semiquantitative predictions. It is similar to EN 14213, EN 14214.
Elemental copper, iron and nickel have a catalytic effect on the oxidation stability of fatty acids methyl esters,
where the catalytic activity of copper is the greatest, measured by the OSI method [19].
3.7 Chemistry of Oxidation of Vegetable Fluids

Oxidation of fatty acid chains is a complex process occurring through several mechanisms. Oxidation of vegetable
fluids is mainly due to the reactivity of carbon-carbon double bonds present in unsaturated fatty acids. The primary
oxidation products of double bonds are unstable allylic hydroperoxides which easily form a variety of secondary
oxidation products. This process includes the rearrangement of product of similar molecular weights to give short
chain aldehydes, carboxylic acids and high molecular weight material.
3.7.1 PRIMARY OXIDATION

Primary oxidation takes place acc. to the schematic mechanism of hydrocarbon oxidation described in Fig. 8.
Fatty acids, that contain more poly-unsaturation, are more prone to oxidation. As linolic and linolenic acid content in
fatty oils or esters increases, the oxidation stability decreases and as fatty oils oxidize the hydroperoxide (ROOH)
levels also increase. Studies have indicated that the development of ROOH over time exhibits one of the two
behaviors: (i) ROOH levels can increase, achieve a plateau, and then be held at that level in a steady state and
alternatively (ii) ROOH can increase, achieve a peak level and then decrease, but no explanation is available on
such behavior. However, the factors like oxygen availability, temperature, extent of preexisting oxidation and the
presence of metals catalyzing the decomposition of hydroperoxides are likely involved in causing the primary
oxidation.
Page 22
3.7.2 SECONDARY OXIDATION

Once the fatty hydroperoxides are formed, they decompose mainly to form aldehydes. Increased acidity can result
from further oxidation of aldehydes or by hydrolysis of fatty acid ester. As hydroperoxides decompose, oxidative
linking of fatty acid chains can occur to form species with higher molecular weights, i.e. oxidative polymerization.
The increase in viscosity is the direct indication of the presence of higher molecular weight material in the oils.
Several parameters [20] are known to provide information on stability of vegetable fluids, such as:
Iodine value (IV): This is one of the oldest and most common methods to determine the magnitude of
unsaturation in fatty oil or ester. D1541 and D1959 are two available ASTM methods along ISO 3961 to
measure IV though it is not necessarily a good method for assessing the stability as the stability depends on the
position of the double bonds available for oxidation.
Peroxide value (ISO 3960): Peroxide value tends to increase and then decrease upon further oxidation due to
formation of secondary oxidation products.
Viscosity (ISO 3104): Viscosity has been found to increase with chain length and with increasing degree of
saturation. Free fatty acids also contribute to higher viscosity. Furthermore, double bond configuration also
influences the viscosity, i. e. cis doble bond configuration giving a lower viscosity than trans. Since oxidation
processes lead to the formation of free fatty acids, cis-trans isomerization, and the formation of high molecular
weight products, the viscosity increases with oxidation.
Steric hindered phenols like DBPC have an antioxidant activity on soybean oil [21].
3.8 Oxidation Stability Studies on Natural esters

Studies [22] have been carried out showing that particular natural esters (7d 120°C) have comparable oxidation
stability to uninhibited mineral oils and in particular show:
 Very similar characteristics and evolution during ageing
 No detrimental effect on cellulosic material
 Suitability for use in distribution transformers
 Advantageous environmental features
In recent times [5] natural esters have been successfully adopted in power transformers up to 200 MVA and 242
kV. Applications at higher ratings are envisaged in the future.
Some further investigations [23, 24, 25] show that natural ester oils are less stable with respect to oxidation than
mineral oil. However, depending on the type and the presence or lack of inhibitor, the oxidation behavior of
vegetable oils can be very different.
Oxidation of certain natural esters influence diagnostic parameters of DGA, e. g. gassing. Ongoing oxidation
accelerates stray gassing, especially ethane production (Fig. 16), produced from poly unsaturated acids, e.g. -3
fatty acids [26, 27, 28, 29, 30, 31, 32] Hydrogen evolution may also be connected with the formation and
degradation of peroxides [32].
Page 23
700
600
500
[Ethane], ppm
400
MINERAL INSULATING OIL

300 VEGETABLE INSULATING OIL
200
100
0 50 100 150 200
Thermal overstress time (h)
Fig. 16 Development of Ethane under Thermal Stress (150°C) in Mineral Oil and in a Certain
Natural ester [31]
3.9 Factors that influence oxidation stability
3.9.1 TEMPERATURE
As a rough approximation, the rate of reaction doubles for every 7 – 10 °C rise in temperature, because every
chemical reaction is thermally dependent on the Arhenius law.
3.9.2 OXYGEN AVAILABILITY

The atmosphere contains about 21% oxygen by volume, meaning that there is always a partial pressure of oxygen
that any type of equipment on the face of the Earth has to endure. How much oxygen actually comes in to contact
with oil inside a transformer then depends on the efficiency of barriers in the design. A hermetically sealed system
can only be a solution for very small distribution transformers where heat expansion can be neglected. However, in
any other type of design (with the possible exception of nitrogen blanketed designs) some oxygen will always be
present in the bulk of the oil as a result of diffusion through membranes and other seals.
From a recent study of power transformers (Australian experience) just under twenty years old the following
comparison can be made [33]:
- Diaphragm or bag fitted conservator: 2275 ppm O2 (average of 11 units 275kV)
- Free breathing (desiccant) conservator: 17180 ppm O2 (average of 14 units 110&132 kV)
Since any insulating oil will be more or less exposed to oxygen and heat it is obvious that oxidation stability will
have to remain a basic requirement of insulating oils.
3.9.3 OIL COMPOSITION

The oxidation stability of an uninhibited oil depend mainly on the hydroperoxide decomposing effect of organic
sulfur compounds [6, 34]. Therefore formulation of uninhibited oil requires access to streams from older types of
refining (usually based on extraction), which is gradually pushed out of the market as a result of the general
demand for ultra low sulfur fuels and engine lubricants.
Page 24
Generally speaking, the aromatic content of extracted oils is also higher than in hydrotreated oils due to saturation
of aromatics by hydrogen [35].
The fact that higher aromatic content generally increases inherent oxidation stability in mineral oils has been known
for a long time [36] and it is also generally known that in uninhibited oils there has to be a balance between
aromatics and sulfur compounds [37]. Especially the larger aromatic molecules affect the oxidation stability
because they form phenols on oxidation. There are however health and safety limitations to possible formulations
because of the demand for low content of polycyclic aromatic hydrocarbons (PCA).
Additives to reduce gassing tendency contain aromatic molecules, but it is hard to say anything general about the
effect on oxidation stability of such additives because it varies depending on type of molecule and on the
composition of the oil. Gas absorption is an important issue for cable and capacitor liquids.
In inhibited oils the story is very different. The more highly refined the oil is (lower sulfur and aromatic content), the
better the response to the added antioxidant [38]. This means that the oxidation stability of a more highly refined oil
will be better than that of a less highly refined oil given the same type and amount of antioxidant. Oxidation stability
expressed as induction time will also increase (up to a point) if the initial amount of antioxidant is increased in the
same oil. It is sometimes argued that since the intrinsic oxidation stability of a highly refined oil (suitable for
formulation of an inhibited oil) is much lower than that of an oil which is less highly refined (commonly used to make
uninhibited oil), it is safer to utilize uninhibited oils which possess an intrinsic oxidation stability. However, in any
case uninhibited oils do develop acidic compounds much earlier and faster than does an inhibited oil. This means
that the acid catalyzed breakdown of solid cellulose insulation will start earlier and shorten the lifetime of the
transformer.
Ester-based oils depend on added antioxidants for oxidation stability. Natural esters derived from plants usually
contain some amount of residues of unsaturated fatty acids (containing carbon-carbon double bonds). Although
these are beneficial to our health when ingested as food, it makes natural esters more prone to oxidation. In
synthetic esters this problem can be avoided as the constituent fatty acids chosen can be completely saturated.
3.9.4 OTHER TRANSFORMER MATERIALS

It is more than likely that almost all types of materials used inside transformers can have an effect on oxidation
stability of the insulating oil, but there is very little to be found in the literature on this except for metals.
Standards for laminated wood (IEC 61061) and laminated board (IEC 60763) describe compatibility procedures for
insulating oil.
3.9.5 METALS
Investigations on the influence of metals on the oxidation stability have been performed since the 1950s at different
transformer manufacturers [39]. In the transformer factory in Nuremberg, Germany, Baader ageing has been used
and as parameters the saponification value and the loss factor have been used. It has been found that the rate of
catalytic activity of the metals is:
Al:Fe:galvanized Fe:Zn:Cu
1:1:3:4:13
Paper insulation decreases the catalytic influence of copper. Copper varnishing eliminates completely its catalytic
activity (Fig. 17).
Page 25
Fig. 17
Oil appearance after Oil appearance after
ageing with varnished ageing with blank
copper (150°C, 48h) copper(150°C, 48h)
There is a fundamental connection between oil oxidation and metal corrosion. Products of oil oxidation such as
peroxides, acids and water, can corrode metals such as the copper (in windings) [40], iron (in the steel tank walls)
and silver (on tap changers). The metals that are dissolved in this fashion can then catalyze further oxidation,
leading to even more corrosion, and so on. For this reason metal passivators (such as BTA, TTA and similar
compounds) have a positive effect on the oxidation stability of insulating oils in the presence of metal surfaces [41].
It has been shown, that the addition of passivators enhances the oxidation stability of uninhibited mineral oils
significantly [42].
The mechanism of the catalytic effect of metals on oxidation has been discussed at length [43, 44]. The prevailing
theory seems to be catalytic decomposition of hydroperoxides to peroxy radicals by disproportioning of copper ions
[44].
Page 26
Chapter 4. Influence of Oxidation Stability on Diagnostics

Oxidation stability means resistance to oxidation and in this respect there are a number of properties, which are
changing in service and may influence the diagnostic parameters. The historical experience of users and
manufacturers is summarized in maintenance standards such as IEC 60422 and IEEE C57.106.
4.1 Influence of oxidation on the gas-in-oil analysis

Uninhibited oils show a decreasing dissolved oxygen content with ageing. This is an evident sign of oxidation.
Some uninhibited oils develop higher concentrations of ethane and hydrogen, not connected with a transformer
fault. This phenomenon has been called stray gassing and seems to have a strong connection to oxidation [45].
After an oil change for an inhibited oil the phenomenon disappears [46].
Some vegetable fluids show similar tendency of formation of hydrogen and ethane in service – see Chapter 2.
Oxidation affects gas-in-oil analysis. Oxygen depression is a result of oxidation processes and is always to be seen
in loaded transformers, especially with non-inhibited oils.
The normal solubility of air in oil at saturation is approximately:
N2 – 66000 ppm
O2 – 33000 ppm
Actually dissolved oxygen is often very low, although the transformer is free breathing (Fig. 18) .
Key Gas ppm
H2 Hydrogen 13
CH4 Methane 101
C2H6 Ethane 80
C2H4 Ethylene 14
C2H2 Acetylene <1
C3H8 Propane 151
C3H6 Propylene 60
CO Carbon monoxide 968
CO2 Carbon dioxide 2380
O2 Oxygen 2825
N2 Nitrogen 76520
Fig. 18 DGA of a 40 year old 100 MVA 220 kV generator transformer
Page 27
4.2 Influence of oxidation on oil parameters.

Most oil parameters that are normally monitored will be influenced by in-service ageing of oil [47]. This section will
deal with one parameter at a time.
4.2.1 COLOR
For unused new oils, color is generally considered as a rough estimation of the degree of refining and for oils in
service as a roughly index of its deterioration (oxidation). Color is not a defined characteristic, but reveals a lot
about the transformer oil condition. Inhibited oils in service have usually a lighter color than non-inhibited for the
same service time and transformer load (Fig. 19).
Transformer 1 Transformer 2
Non-inhibited oil Inhibited oil
Rating (kV) 420 425
Power (MVA) 780 970
Year of manufacture 1985 1973
Colour 4,5 2,5
Acidity(mg KOH/g oil) 0,12 <0,01
Lossfactor (90°C) 0,035 0,014
Interfacial tension 18 37
(mN/m)
Inhibitor content (%) - 0,17
Fig. 19 Transformers with similar rating and load, filled with uninhibited and inhibited oil.
4.2.2 SLUDGE
Strongly oxidized oil also deteriorates the solid insulation, since the major polar products absorb in paper (Fig. 20,
Fig. 21).
Fig. 20 Winding of a repair transformer Fig. 21 Sludge deposition on the

with sludge deposition outside paper insulation
Page 28
4.2.3 LOSS FACTOR AND AGEING

The lossfactor at 90°C (tan δ) is a measure of the power loss in the insulating material and is therefore a general
indication of its quality.
Inhibited and non-inhibited mineral oils behave differently in respect of the loss factor increase with service time
(Fig. 22).
0.12
0.1
0.08
Lossfactor
non-inhibited
0.06
inhibited
0.04
0.02
0
0 5 10 15 20 25 30 35
Service Time (Years)
Fig. 22 Behavior of the loss factor increase with service time for non-inhibited and inhibited
mineral oils
Table 5 Results of oxidation stability tests acc. IEC 61125C for a mineral insulating oil
Requirement
Property Unit of IEC 60296
Value for standard grade
IEC Ageing 164 h at 120°C
Total Acidity mg KOH/g 0.49 1.2
Sludge W. % 0.045 0.8
Lossfactor at 90°C, 50 Hz - 4.505* 0.500
*does not fulfill the requirements of IEC 60296
Page 29
Table 6 Behavior of the oil tested (Table 5) in service

Loss factor at 90°C Neutralization Value Interfacial Tension
and 50 Hz (mg KOH/g oil) (mN/m)
Values after 5 years

0.141 0.03 19
of service
There is no clear evidence on the relationship between oil behavior in service and the performance in the oxidation
stability tests. It has been demonstrated, however, that insulating oils which failed the test in IEC 61125C because
of high loss factor showed after short time of service (5 years) in free breathing distribution transformers an unusual
high loss factor and low interfacial tension (Table 5, Table 6).
On the other hand, it is known that high grade inhibited oils acc. to IEC 60296 perform well even after long years of
service.
There is a definitive correlation of loss factor with resistivity (Fig. 23) [48, 49] well known from Cigre publications;
therefore it is a question of analytical philosophy as to which parameter is to be determined.
Log[IRES] vs Log[DDF]
4
3.5
3
2.5
1.5
1 improving resistivity
0.5
0
-4 -3.5 -3 -2.5 -2 -1.5 -1 -0.5 -0.5 0 0.5
-1
improving dissipation factor
Fig. 23 Correlation between resistivity and dissipation factor [48]
Page 30
4.2.4 ACIDITY AND AGEING

Acidity increase is different for uninhibited and inhibited mineral oils in service (Fig. 24). As long as an inhibitor is
still active, there should be no significant increase in acidity for inhibited mineral oils.
0.25
0.2
Acidity (mg KOH/g oil)
0.15
non inhibited
inhibited
0.1
0.05
0
0 5 10 15 20 25 30 35
Fig. 24 Neutralization value increase with service time for non-inhibited and inhibited mineral
oils
High acidity will inevitably have an impact on paper degradation, therefore oil and paper ageing are closely related
[50, 51, 52]
4.2.5 EFFECT OF OXIDIZED OIL ON PAPER

The figures below are based on paper layer analysis of a 180MVA transmission transformer of around 40 years
where the oil acidity exceeded the recommended acidity level of 0.15 mgKOH/g oil for around 10 years. The
transformer failed in service due to severe solid insulation ageing, caused by a combination of high loading
throughout the life of the transformer and poor thermal design of the HV winding. Paper samples were collected
during the failure investigation and values were found as low as 131 DP (degree of polymerization) at the point of
failure and many samples from elsewhere in the transformer were between 150 and 200 DP.
The HV winding of this transformer was wrapped in 8 layers of paper and samples were taken from different points
of the transformer and the tensile index was measured. The results show that the chemical degradation of the outer
layer of paper, especially at the lower part of the HV winding, have as much effect on the tensile index as the
thermal degradation of the inner layer of paper at the top of the winding (Fig. 25, Fig. 26). The chemical
degradation is also confirmed by the presence of higher quantities of low molecular weight acids (LMAs) in the
outer layers of paper [52].
Page 31
Fig. 25 Layer profile of tensile strength and acid of HV winding paper.
Fig. 26 Color appearance of different layers of HV winding paper.
4.2.6 INTERFACIAL TENSION AND AGEING

Interfacial tension is one of the most sensitive parameters concerning oxidation. It shows a steep slope in the first
years of operation, especially in the case of uninhibited oils in free breathing transformers, even if all other
commonly used oil values remain unchanged.
A general scheme of behavior of uninhibited and inhibited insulating oils is shown in Fig. 27.
Page 32
45
40
35
Interfacial Tension mN/m
30
25
non-inhibited
inhibited
20
15
10
0
0 5 10 15 20 25 30 35
Fig. 27 Interfacial tenson vs ageing of uninhibited and inhibited mineral oils
There is also an interdependence between the different ageing parameters like interfacial tension (IFT) and acidity
(NN) (Fig. 28) [53].
50 0.5
40 0.4
NN (mg KOH/g)
IFT (mN/m)
30 0.3
NN
IFT
20 0.2
10 0.1
0 0
0 5 10 15 20
age (years)
Fig. 28 Interdependence between interfacial tension (IFT) and acidity (NN) [53]
Page 33
4.2.7 BREAKDOWN VOLTAGE AND AGEING

In the case of dry transformers, breakdown voltage of insulating oil does not seem to be influenced by acidity
(Fig. 29) or resistivity (Fig. 30) [48]. Moisture and particles are the main impacts that influence the breakdown
voltage.
120
100
Breakdown voltage
80
60
40
20
0
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7
Acidity mgKOH/g
Fig. 29 Dependence between breakdown voltage and acidity [48].
120
100
Breakdown voltage
80
60
40
20
0
0.1 1 10 100 1000 10000
Resisitvity Gohm‐1
Fig. 30 Dependence between breakdown voltage and resistivity [48]
4.3 Behavior of Uninhibited Mineral Insulating Oils in Service (Experience in Italy)

Transformer integrity and long-life are strictly dependent upon operating conditions (load, overvoltages, short-
circuits) and at the same time on the prevention of chemical degradation of oil and solid insulation.
Considering the above, it is evident how strategic and important the design of an efficient oil protection system is
that is able to stop or at least delay the negative effects of the direct contact with external atmosphere (oxygen and
moisture). The development of the oil protection system took place over a period of more than 50 years, at the
same time with research on the ageing of the insulating materials and ended around 1970 [54, 55]. Many different
technical solutions are today available, with all of them being fully investigated in experiments, with specific values
Page 34
and limits. The detailed description of the different oil preservation systems goes beyond the scope of this paper,
but the following can be cited as a historical background:
 Transformers with simple airing

 Transformers with air desiccant
 Transformers pressurized with nitrogen or other inert gas
 Transformers with air breathing oil conservator
 Transformers with sealed oil conservator (rubber bag, diaphragm, etc.)
 Transformers with breathing/close oil conservator plus air desiccant
 Hermetically sealed transformers.
Many other parameters should be taken in account: such as oil type (uninhibited or inhibited), cooling system
(natural, forced, etc.), desiccant type (salts driers, Peltier effect), maintenance practices; with regard to oil oxidation
expectations, all the above systems can be categorized into two simple classes:
 Free-Breathing Transformers
 Closed Type Transformers.
60 1.5 500
Neutralisation
50 Value
1.2 400
LOAD
OIL TEMP
40
AIR TEMP
0.9 300
LOAD
30
°C
NV
0.6 200
20
10 0.3 100
0 0 0
1940 1942 1944 1946 1948 1950 1940 1942 1944 1946 1948 1950
Fig. 31 Variation of acidity, max temperature (air and oil) and load of a typical 500-kVA
transformer installed in 1938
It is evident that the purpose of the sealing systems is to prevent air and moisture from contacting liquid and solid
insulation. A combination of oxygen and water will greatly reduce the service life of the transformers by oxidizing
and ageing of oil and paper.
Worldwide experience mainly reflects consolidated local traditions and is sometimes dependent upon user polices
for fault prevention, environmental protection and fire safety. Economical aspects are less critical because the extra
cost of oil preservation systems is quite negligible for large power transformers (high value) and in any case it is
fully amortized in the long run.
Despite the availability of a large number of different test methods for measuring oxidation stability in new or
unused insulating oils, none of them is specifically devoted to evaluation of the residual life of in-service oils. It is
therefore common practice to control oil ageing by the direct titration of its by-products (acidity , referred to as NN)
and by the measuring of electrical parameters (DDF, resistivity) or physical (IFT) sensitive to by-products. IEC
60422 provides detailed and profound descriptions for basic rules on oil surveillance; in doing this the key
parameter is the oil acidity, which in this context must be considered as a global measure of oil ageing sufficient to
promote the proper maintenance action in order to prevent sludge and asphalt generation.
The following Table 7 and Fig. 32 report long-time experience in oil oxidation monitoring for the two transformer
classes [33].
Page 35
Table 7 Acidity (neutralization value (average and maximum value) as function of age for open
(free breathing) and closed type transformers
ACIDITY (mg KOH/g)
CLOSE FREE BREATHING

Age (years)
average max average max
<10 0.02 0.02 0.05 0.08
10-15 0.02 0.05 0.10 0.18
15-20 0.02 0.06 0.15 0.24
20-25 0.03 0.06 0.20 0.34
25-30 0.04 0.10 0.24 0.32
30-35 0.04 0.07 0.26 0.31
35-40 0.04 0.08 0.28 0.39
> 40 0.05 0.17 0.31 0.42
0.50
Neutralisation Value (mg KOH/g oil
0.40
CLOSE_av
OPEN_av
0.30
CLOSE_max
OPEN_max
0.20
IEC 60422 Limit
for type O and A
IEC 60422 Limit

0.10 for type B
0.00
<10 10-15 15-20 20-25 25-30 30-35 35-40 > 40
age (years)
Fig. 32 Acidity (neutralization value) (average and maximum value) as function of age for open
(free breathing) and closed transformers
Looking at the above data it can be perceived how the IEC 60422 given limit for acidy is practically never reached
in close equipment and even for open type equipment acidity was adequate for roughly 20 years.
This data reflects the experience gained in Italy (from a large fleet of generation and transmission transformers for
half a century) with the use of membrane conservator. After some negative experience with the flat membrane
(revealed to be too fragile at the perimetrical fastening, excellent performance was obtained with the nitrylic rubber
Page 36
bag reinforced with nylon tissue. This solution has shown, apart from good mechanical reliability, excellent
effectiveness in preventing ingress of atmospheric air and moisture. The periodic DGA show oxygen concentration
below 500 ppm and water content below 10 ppm: as a consequence the acidity increase rate is very low.
Also worth mentioning is the interfacial tension (IFT) test; many of oil soluble by-products are hydrophilic and
hydrophobic and having tensioactive behavior may reduce the IFT value. This value (expressed as mN/m) quickly
drops from approximately 45 for new oils to 20 for used oils with only 0.1 mg KOH/g oil of acidity. Consequently,
the IFT test is extremely sensitive in first stage of oil oxidation, but then becomes ineffective for detection of further
levels of degradation.
The following Fig. 33 shows the relationship between interfacial tension (IFT) and acidity (NN).
60
50
40
IFT (mN/m)
30
20
10
0
0 0.1 0.2 0.3 0.4 0.5
NN (mg KOH/g)
Fig. 33: Relationship between acidity and IFT
It is further acknowledged that tradition and allegations rather than peremptory needs are the reasons for the
widespread preference accorded to uninhibited oils. The fear of collapse of oxidation resistance observed with
inhibited oils in accelerated laboratory tests was never supported by field evidence. Of greater substance may be
the issue of miscibility that is explicitly granted at any time and in all ratios only in the absence of additives. Yet,
complete miscibility is specified for other petroleum products, such as transportation fuels and engine lubricants
that depend on a complex package of additives for their performance [56]. It is further perceived that the aftermath
of the current landmark case will lead to greater use of metal-deactivator additives, even with deeply desulfurized
base oils. In addition to protecting against corrosion, they also enhance oxidation stability by counteracting the
catalytic effect of copper [57].
4.4 Behavior of Inhibited Oils in Service (Experience in Serbia)
4.4.1 EVALUATED TRANSFORMERS

 Fully inhibited oils (DBPC 0.30 -0.35%m)
 Open-breathers with conservator, core type
 Different voltages (O,A,…B,C cat.)
 Years of service (0-10, 10-20, 20-30, 30-40, 40-50, 50-55)
 90% of units are more than 20 years old
 25% of units are more than 40 years old
Page 37
4.4.2 CORRELATIONS OF IEC 61125 C TO VALUES OF OILS IN SERVICE

Limits in IEC 60296 for oxidation stability are far removed from real practice and are not in correlation with actual
IEC 60422 limits for the end of oil service life. Practical experience showed that a number (up to 90% of tested oils)
of inhibited oils after 500 h of ageing acc. to IEC 61125 C achieve half of the limit values (total acids, dielectric
dissipation factor and sludge) and a number of oils satisfy limits for special applications in IEC 60296. It seems that
limits in IEC 60296 using IEC 61125 C as oxidation stability test are not correlated to real cases of new oils and
ageing condition of oils in service.
Relatively low average values for acidity (TAN) and dielectric lossfactor (DDF) reflect efficient inhibitor protection of
oil and slow ageing rates (Table 8) . Also, oil change and reclamation procedures have impacted improved oil
quality of transformers in service, and have influenced lower TAN and DDF values (Fig. 34). Taking this into
account (approx. 10 % reclaimed oils) average TAN values are max. up to 0.15 – 0.20 mgKOH/g .
Table 8 Average values of acidity (in mg KOH/g oil), interfacial tension (IFT in mN/m) and
dielectric loss factor (DDF in*10-3) of inhibited oils in service
Y. in service Acidity av. Acidity max. IFT av. DDFav.
0-10 0.02 0.08 37 10.2
10-20 0.03 0.20 35 7.5
20-30 0.04 0.20 33 18.9
30-40 0.09 0.30 29 31.4
40-50 0.12 0.43 25 52.8
50-55 0.10 0.47 26 81.8
0.15
TAN, mgKOH/g
0.14
0.13 IFT, N/m
0.12 DDF
0.11
0.1
TAN, IFT, DDF
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0
0-10 10 to 20 20 to 30 30 to 40 40 to 50 50 to 55 55 to 60
Years of Service
Fig. 34 Average values of acidity (TAN), interfacial tension (IFT) and dielectric loss factor (DDF)
based on years of service
Page 38
Fig. 35 Average in service acidity ( TAN values) at different voltage level and years
Maximum TAN values for both voltage levels were for 30 years service up to 0.20 mgKOH/g, and for up to 50 years
of service up to 0.47 mgKOH/g (Fig. 35).
4.4.3 CHANGE OF OIL PROPERTIES DURING SERVICE

Sharp drop of IFT with values above 40 mN/m occurs with oils having relatively low acid (NN, TAN) values (0.05
mg KOH/g). With further ageing and an increase of TAN, decrease of IFT is much slower (Fig. 36).
Acidity increase correlates with increase in the loss factor (DDF). This correlation is more pronounced for older
units (Fig. 37).
TAN vs IFT
60
50
40
IFT. mN/m
30
20
10
0
0 0.05 0.1 0.15 0.2 0.25
TAN, mgKOH/g
Fig. 36 Relationship between IFT and Acids (TAN, NN)
Page 39
300
DDF, ‰ TAN vs DDF
Units 30 -49 years old
250
200
150
100
50
TAN, mgKOH/g
0
0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5
Fig. 37 Relationship between DDF and Acids (TAN, NN)
4.4.4 CONSUMPTION OF INHIBITOR AND RELATED CHANGES IN OIL PROPERTIES - EXAMPLES

Inhibited oils in service exhibit a relatively slow rate of ageing, as can be seen from previous data. After the inhibitor
is consumed bellow 0.10 %m ageing rates become faster, but no catastrophic breakdown of the oil was observed
in practice. Significant increase in rates of acid production was observed after 4-8 years (several periods of oil
testing), depending on base oil quality, design and operating conditions of transformer (load, cooling, electrical
stresses), duration of continuous loading/overloading periods and maintenance procedures.
Page 40
4.4.4.1 Example 1: HPP, GSU Fig. 38 (Table 9)
Table 9 15.75/220 kV, 100 MVA, in service since 1972

date DBPC, %m TAN, mgKOH/g IFT, mN/m DDF
/06/1972 0.35 0.02 35 0.002
/05/1974 inh. 0.04 32 0.007
/09/1975 inh. 0.04 32 0.006
/05/1977 inh. 0.04 30 0.008
/09/1978 inh. 0.04 32 0.007
/03/1979 inh. 0.05 29 0.006
/07/1994 inh. 0.06 28 0.024
/10/1996 inh. 0.06 28 0.029
/10/2000 inh. 0.07 28 0.031
16/07/2002 inh. 0.07 27 0.032
29/09/2004 0.10 0.08 27 0.029
08/08/2007 0.11 0.08 25 0.033
24/09/2009 0.07 0.14 22 0.037
0.40
0.35
0.30
0.25
DBPC, %m
TAN, mgKOH/g
0.20
IFT, mN/m
DDF
0.15
0.10
0.05
0.00
72
74
75
77
78
79
94
96
00
02
04
04
07
09
19
19
19
19
19
19
19
19
20
20
20
20
20
20
6/
5/
9/
5/
9/
3/
7/
0/
0/
7/
1.
9/
8.
9.
/0
/0
/0
/0
/0
/0
/0
/1
/1
/0
.1
/0
.0
.0
16
03
29
08
24
Fig. 38 Change of Acidity (TAN), IFT and DDF related to DBPC consumption
Page 41
4.4.4.2 Example 2: TPP, GSU (Table 10)
Table 10 15.75/121 kV, 250 MVA, in service since 1980

Acidity,
date DBPC, %m IFT, mN/m DDF
mgKOH/g
/03/1981 0.30 0.03 38 0.0073
/03/1982 inh. 0.02 32 0.0062
/12/1983 inh. 0.03 33 0.0177
/06/1984 inh. 0.03 32 0.0216
25/02/1987 inh. 0.03 33 0.0444
29/01/1988 inh. 0.04 33 0.0345
/02/1997* 0.08 0.04 31 0.035
18/08/2005* 0.07 0.07 28 0.0575
03/2008 0.05 0.08 27 0.0606
* four years out of service, from 2000-2004
0.35
0.30
0.25
0.20 DBPC, %m
TAN, mgKOH/g
IFT, mN/m
0.15 DDF
0.10
0.05
0.00
/03/1981 /03/1982 /12/1983 /06/1984 /02/1987 /01/1988 /02/1997 /08/2005 /03/2008
Fig. 39 Change of Acidity (TAN), IFT and DDF related to DBPC consumption
Page 42
4.4.4.3 Example 3: Distribution transformer (Table 11, Fig. 40)
Table 11 35/10 kV, 8MVA, in service since 1975

date DBPC, %m Acidity, mgKOH/g IFT, mN/m DDF
23/09/1976 0.30 0.00 35 0.0252
27/10/1980 inh. 0.00 35 0.0157
/09/1986 inh. 0.02 32 0.0210
/05/1990 inh. 0.05 32 0.0190
15/05/2004 inh. 0.07 28 0.0200
26/03/1997 inh. 0.07 28 0.0215
16/11/1999 inh. 0.10 30 0.0197
13/03/2002 0.09 0.09 26 0.0207
10/10/2005 0.09 0.09 23 0.0263
21/09/2007 0.09 0.12 23 0.0531
14/04/2009 0.05 0.14 20 0.0551
0.35
0.30
0.25
DBPC, %m
0.20
TAN, mgKOH/g
IFT, N/m
0.15 DDF
0.10
0.05
0.00
86
90
76
80
04
97
99
02
05
07
09
19
19
19
19
20
19
19
20
20
20
20
9/
5/
9/
0/
5.
3/
1/
3/
0/
9/
4/
/0
/0
/0
/1
.0
/0
/1
/0
/1
/0
/0
23
27
15
26
16
13
10
21
14
Fig. 40 Change of Acidity ( TAN), IFT and DDF related to DBPC consumption
Page 43
Chapter 5. Prolonging Life of Insulating Oil in Service

5.1 Inhibition of non-inhibited Oils/Reinhibition
Reinhibition of used oil to a certain content of inhibitor is a usual procedure, described in IEC 60422. It is advised to
reinhibit oils whose prior deterioration oil values are significant, i. e. prior oxidation has taken place to a significant
extent. Under strong oxidizing conditions, DBPC may build a dimer compound, which is identified by the usual IR
method as an inhibitor, but is no longer active as such. In such cases GC-MS helps identify individual compounds,
while the IR method might give the wrongful impression that the oil is still sufficiently protected [27]. There is not
very much information available on inhibition of aged non-inhibited oils. It seems reasonable to expect that they
would behave in a manner similar to aged and reinhibited originally inhibited oil. Some stabilizing of acidity is
possible, although a drop in the concentration of DBPC is noticeable (Fig. 41 and Fig. 42 [59]).
0,25
Acidity (mg KOH/g)
DBPC (%)
0,20
0,15
0,10
0,05
1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Fig. 41 The oil was originally inhibited. DBPC to a final concentration of 0.3% (reinhibition) was
added to a transformer in 1995. The transformer was taken out of service in 1999.
0,30
Acidity (m g KOH/g)
DBPC (%)
0,25
0,20
0,15
0,10
0,05
0,00
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Fig. 42 DBPC was added to an end concentration of 0.3% to a transformer in 1997. This
transformer was taken out of service in 2005.
Page 44
Adding an inhibitor to differently aged samples and ageing under the conditions of IEC 61125C it has been shown,
that inhibition is effective when done at early stages of ageing with the conclusion that "younger" transformers are
to be prioritized rather than "older" ones [58].
Adding inhibitors to a non-inhibited oil in an early stage
– Decreases moisture production
– Decreases acids production
– Decreases slope of IFT
A certain decrease in resistivity, however, has also been noticed and should be monitored.
5.2 Oil Reclaiming

An established procedure for the recovery of the insulating oil is oil regeneration. The terminology may differ here –
reclaiming, refurbishment, recycling, depolarization etc. There are different procedures for this as described in [59].
Reclaiming in the general sense is a physico-chemical process, depleting ageing products and thus improving the
oil properties. Together with ageing products some natural compounds (inhibitors) may be depleted. The
effectiveness and result of the procedure depend on the adsorbent used and the conditions, as well as on the state
of deterioration of the used oil.
Oil reclaiming can take place in the equipment itself (on-line or off-line), as well as in bulk outside the electrical
equipment.
A direct comparison of the oxidation stability of insulating oils prior to and after reclaiming is difficult, since all
established procedures for oxidation stability are designed for new oils. [Seeking of a correlation between oil
properties and oxidation stability in the case of reclaiming is not straightforward. Some conclusions based on test
series are [60]:
- No clear correlation between oil oxidation stability of reclaimed oils and any relevant oil property
parameters
- The amount of DBPC in purified oil is not the only factor in influencing oil oxidation stability, at least under
ASTM D2112 test conditions
- Additional improvement of oxidation stability is dependent on the type of adsorbent used in the treatment
Several oil characteristics can be monitored during reclaiming, e. g. IFT, neutralization value, loss factor, color
(Fig. 43).
Recently additional properties have been reported to be susceptible to the degree of reclamation like density and
refractive index [61].
Page 45
Fig. 43 Oil color change in the course of a reclaiming (from left to right)
Some examples of reclaiming and reinhibiting of inhibited oils with stability data over years are given below –
Fig. 44 [62] and Fig. 45, Fig. 46 [63].
Page 46
I case: Distribution transformer
Voltage: 110/35 kV Power:31.5 MVA mass of oil: 20.000 kg

In service from 1958. with OLTC
DATUM DDF, NV, mgKOH/g

15.06.1985 0.068 0.28
15.06.1986 0.009 0.05
15.06.1987 0.013 0.07
15.06.1989 0.020 0.08
15.06.1995 0.026 0.09
15.06.1997 0.030 0.20
15.06.2001 0.027 0.17
15.06.2003 0.025 0.15
20.08.2010 0.053 0.18
prior reclamation
after reclamation
II case: Distribution transformer
Voltage: 110/35 kV Power : 20 MVA mass of oil: 16.000 kg

In service from 1966. with OLTC
DATUM DDF NV, mgKOH/g

15.06.1989 0.157 0.28
15.06.1990 0.013 0.03
15.06.1991 0.017 0.03
15.06.1995 0.022 0.04
15.06.1999 0.039 0.03
15.06.2003 0.045 0.04
24.05.2007 0.041 0.07
prior reclamation
after reclamation
Fig. 44 Development of oil characteristics with time after reclamation. In both cases natural
adsorbent was used, based on Alumosilicates, with some amount of MgO, particle size from
800 – 1000 µm. Percolation process was applied in three cycles with re-inhibition afterwards,
up to 0.30-0.35% of DBPC [62]
Page 47
40 3500 0.35 Acidity Inhibitor content

Interfacial tension
After regenetarion Before regenetarion DDF
3000 0.3
35
2500 0.25
mg KOH/g oil, % m
adding inhibitor
30
2000
mN/m
0.2
*10^3
1500 Before regenetarion
25 0.15
1000 0.1 After regenetarion

After regenetarion
20
Before regenetarion 500 0.05
15 0 0
1996. May
1998. May
September
2002. June
2002. August
November
September
Oktober
23.03.2009
1996. May
1998. May
September
2002. June
2002. August
November
September
Oktober
23.03.2009
2008.
2008.
1996. May
1998. May
September
2002. June
2002. August
November
September
2008. Oktober
23.03.2009
2003.
2000.
2004.
2003.
2000.
2004.
2003.
2000.
2004.
Fig. 45 Free breathing transmission transformer 220 kV, year of manufacture: 1974 (filled
originally with uninhibited oil) year of regeneration: 2001, still in service [63].
38 3000
Interfacial tension DDF 0.36 Acidity Inhibitor content
Before regenetarion
After regenetarion 2500 0.31
33
mg KOH/g oil, % m
2000 0.26
adding inhibitor
*10^3
0.21
mN/m
28 1500 Before regenetarion
0.16
1000 After regenetarion
After regenetarion 0.11
23
Before regenetarion 500 0.06
18 0 0.01
1996. July
1998. March
2000. September
2001. July
2001. November
2002. January
2002. Oktober
2003. March
2004. June
2005. April
2007. May
1996. July
1998. March
2000. September
2001. July
2001. November
2002. January
2002. Oktober
2003. March
2004. June
2005. April
2007. May
1996. July
1998. March
2000. September
2001. July
2001. November
2002. January
2002. Oktober
2003. March
2004. June
2005. April
2007. May
Fig. 46 Free breathing transmission transformer 120 kV year of manufacture: 1960 ( filled
originally with uninhibited oil) year of regeneration: 1981 [63].
It is obvious, that the long-term stability of reclamation is dependent on many factors such as :
- starting condition and type of oil
- type of reclaiming (time, temperature, cycles, adsorbent)
For the estimation of long-term stability of regenerated oils a 170h oxidation test under the conditions of IEC
61125C was used. The consumption of the inhibitor after the oxidation test seems to correlate with the
performance in service [64] .
Usual practice after reclaiming is inhibiting with DBPC. Some studies have shown that the induction period of
reclaimed oils with addition of DBPC is much longer than without [65]. As a test method a setup similar to EN
14112 has been used, but temperature, copper surface area/oil volume, oxygen flow etc. was modified to get as
close to IEC 61125B conditions as possible.
As seen from the graphs in the following reinhibiting on its own has very poor effect on oil that contains significant
amounts of oxidation products (Fig. 48). On the other hand, Fuller's earth treatment only gives very short induction
times, since the oil is nearly totally depleted of inhibitor (Fig. 47 and Fig. 49). However, the combination of earth
treatment and reinhibiting gives excellent results (Fig. 50).
Page 48
Fig. 47. Oxidation stability test of oxidized oil before reclaiming.
Fig. 48 Oxidation stability test of oxidized oil with the inhibitor content restored to 0.3%.
Fig. 49 Oxidation stability test of reclaimed oil before the addition of new inhibitor.
Page 49
Fig. 50 Oxidation stability test of reclaimed and reinhibited oil.
Oil reclaiming without inhibiting may lead to a strongly deteriorated oil state in a very short time, therefore the
inhibition after reclamation is strongly recommended [66]. Two examples from real life are shown below.
Example – Fig. 51 [67]. The oil was reclaimed in 2002, without an addition of inhibitor. After only 30 months
the acidity was at the same level. The oil was finally replaced in 2006
Fig. 51 Acidity development (mg KOH/ g oil) in a reclaimed oil without addition of inhibitor.
Page 50
Example – Fig. 52 [68]
Fig. 52 Sludge precipitation on a Buchholz relay from a reclaimed oil without inhibitor
addition[68]
1,33 MVA, 47 kV/750V Transformer, filled with 2.2 t uninhibited oil
- 1992 – commissioning
- Regularly monitored maximum operation temperature between 64 and 70°C, in short periods several
ON/OFF every day
- October 2004 – mechanical problems with Buchholz relays, sludge deposits
- 2006 - Regeneration without inhibition
- 2007 – again problems, color 4, neutralization value 0.3 mg KOH/g oil
Treatment of insulating oils with alumosilicates such as molecular sieves extract passivators, which may have an
impact on their properties, e.g. corrosivity [69].
Experience in the UK in using reclaimed oil is summarized in the following section [70].
5.3 Behavior of reclaimed oil in service (field experience in UK)

In a few countries it is common practice for utilities to opt for reclaimed rather than unused oil to top up leaking
equipment or to replace switch oil during maintenance activity. In the UK in particular, the practice of purchasing
reclaimed oil, or more often using a service provider for off-site reclamation and storage of oil for this purpose, is
well established. In common with most oil in service in the UK the oil does not contain any artificial antioxidants.
Once reclaimed the supplier has traditionally been required to supply it according to British Standard BS148.
Following its withdrawal, on publication of the EuroNorm standard IEC 60296 (2003), which does not cover
reclaimed oils, it was reissued to cover the use of reclaimed oils only because of this practice.
Page 51
Reclaimed oils are defined by BS148 (2009) as mineral insulating oil used in electrical equipment which has been
subjected to chemical and/or physical processing to eliminate soluble and insoluble contaminants. The quality of
the used oil that is reclaimed is key to the product being able to achieve the requirements of BS148:2009 and
reclaimers are careful not to choose oils that are unsuitable because they were originally of poor quality or because
they are contaminated with PCBs. It is generally assumed that oil that is supplied as reclaimed will have been
originally supplied to BS148 (1998) or an earlier version of this standard. These oils rarely present problems to
users and the practice remains common. However, oil supplied to IEC 60296 (2003) only may not be suitable for
reclaiming and then re-use as uninhibited reclaimed oil and it is likely that inhibitors will need to be used to meet
BS148.
Until the early 1990s it was relatively common for uninhibited reclaimed oil to be purchased for first fill of a new
transformer or other oil-filled equipment. Some oil supplied to BS148 between 1988 and 1992 exhibited an
abnormal and severe degree of sludging in certain makes of switchgear, including tapchangers; the cause of the
sludging was not clear. The supplier recommended that equipment containing this oil was inspected and replaced
in the event that sludging was occurring. Unusually, the sludging was not always accompanied by high acidity
values or especially a darkening in color.
The oil of concern was fingerprinted by means of GC-MS analysis of the polyaromatic fraction and the oil was
found to be readily identifiable. Other tests such as carbon typing and furan analysis were used to identify where
the oil had been used so that it could be replaced before sludging occurred. The furan analysis was useful in some
cases as it was at very high levels, up to 36ppm of 2-FAL were recorded; it is believed that the oil or an oil used in
the blend had been produced by solvent extraction . By the mid-2000s the oil had largely been removed from
equipment by UK utilities but where it had been stored on site and used later than 1994 during maintenance of tap
changers it may still cause sludging that is then apparent many years later. Tap changer oil is sometimes stored in
a conservator during maintenance and sludging here may also be found. Any migration of the sludge into the main
tank through this route can accelerate oxidation of the main tank oil even if it is originally from a different source.
For this reason, use of the conservator for holding selector oil during maintenance is not recommended. Whenever
contamination has occurred the main tank oil should be replaced or reclaimed and inhibited.
In some cases transformer main tank oil has been found to contain large amounts of sludge where the particular oil
was used from new (Fig. 53, Fig. 54). In these cases it is necessary to flush the main tank with as much 50% of the
main tank oil volume in order to remove enough sludge before it is refilled.
Fig. 53 Heavy deposition found in two different types of selector filled with reclaimed oil known
to produce sludge
Page 52
Fig. 54 Evidence of sludging in a conservator tank from a transformer filled from new with
reclaimed oil known to produce sludge
This particular experience of reclaimed oil, and possibly unused oil from the same source, should not detract from
the practice of using reclaimed oil any more than use of on-site reclamation which is becoming more common.
Reclamation of oil through either route is important in preserving a valuable and finite natural resource, this is
especially true for naphthenic-based transformer oils which continue to be the preferred choice of most utilities.
5.4 Influence on the oil reclaiming on insulating paper

Reclaiming on-site removes to a considerable extent sludge deposits on insulating surfaces. Purified and inhibited
oil does not affect paper to such a considerable extent as acidic oil even at higher temperatures. The ageing
according test procedure IEC 62535 includes paper and shows the effect of oil ageing products on it (Fig. 55).
Fig. 55
Paper and copper for a non corrosive Paper and copper for the same oil after
but aged oil after the test acc. IEC 62535 reclaiming after the test acc. IEC 62535
Page 53
5.5 Oil reclaiming and Corrosivity

Oil reclaiming removes to a great extent corrosivity due to the presence of DBDS Some reports claim total removal
of the sulfur species causing Cu2S formation.
Based on the type of reclaiming (regeneration rigs) and/or type of Fuller's earth some additional corrosion
phenomena, not existing in the oil prior regeneration may arise [71, 72, 73]. This may be due to reactions with
existing sulfur compounds and/or extraction of natural passivators from the insulating oil. Mitigation of the process
can be achieved with a prolonged regeneration.
Addition of passivators to strongly oxidized oils may have some side effects like gassing or increasing of the loss
factor. This may be due to the fact, that passivators like Irgamet 39 or TTA are destroyed by [74, 75, 76]. The
addition of passivators to unoxidized new oils containing inhibitors is not known to produce side effects.
5.6 Oxygen Removal in Service

Nitrogen blanketing or continuous oxygen removal [77] in service decreases the probability of oxidation and leads
to a prolonged oil life. Removing of dissolved gasses may interfere with DGA diagnostics.
Nitrogen blanketing or hermetical sealing excludes atmospheric gases as well and prolongs life of oil.
Page 54
Chapter 6. Oxidation Stability Testing

6.1 Specifications for Oxidation Stability
The specifications all over the world concerning requirements and methods for oxidation stability (Status 2005) are
summarized below [78].
Page 55
No SPECIFICATION OXIDATION STABILITY GASSING TENDENCY ROTATING BOMB TEST INHIBITOR CONTENT Ca / Cp / Cn
%sludge
Method Duration Temp Flowrate Acid max Method Max Method Spec Method Spec Method Spec
max
Insulating Liquids Part 1:

AS 1767.1999 Australian Specification for unused mineral 120 ± 0.5
1 IEC 60296(1982/86) 164HRS 0.15 Lit/hr 0.1 0.4
standard insulating oil for transformers and °C
switchgears
SMS 430.10.1
2 National Grid Type II D2440 72 hrs 0.1 0.3
Version 1.1 D2112 220min
oils(Naphthenic)
Date 05/23/2007 164 hrs 0.2 0.4
DOBLE TOPS(2008) TYPE Standard Specification for

3 D2440 72 hrs 0.15 0.5 D3487 +30µl/min D2112 195 min D 4760 or D2668 0.08%
1 mineral insulating oils
164 hrs 0.3 0.6
DOBLE TOPS(2008) TYPE Standard Specification for
4 D2440 72 hrs 0.1 0.3 D3487 +30µl/min D2112 220 min D 4760 or D2668 0.30%
11 mineral insulating oils
164 hrs 0.2 0.4
Mineral Insulating Oil ,
C50-08
5 electrical for transformers and D2440 164 hrs ≤0.05 ≤0.2 D2112 ≥195min 0.08% - 0.4%
Canada -Inhibited
switches
Mineral Insulating Oil ,

C50-08
6 electrical for transformers and D2440 72 hrs ≤0.1 ≤0.4 ≤0.08%
Canada -UnInhibited
switches
Indian Standard, 2005 IEC
New insulating oils -
7 61125A Only uninhibited 164 hrs ≤0.1 ≤0.4
specification
oils
Brasi Up to 145 kV –paraffinic up to 145
8 Uninhibited IEC 61125A 0.1 0.4
kV, naphthenic – all voltage classes
lREGULAMENTO TÉCNICO
ANP Nº 164 hrs 0.3 0.6
25(2005)paraffinisch bis Trace Inh IEC 61125C 0.08
145 kV, naphthenisch – alle 332 hrs 0.8 1.2
voltage classes 164 hrs 0.2 0.4
Inhibited IEC 61125C 0.33
500 hrs 0.8 1.2
9 Draft 2007 Uninhibited 164 hrs 0.4 0.8

EON, Germany
Draft 2007 IEC 61125C Trace Inhibited 332hrs 120 0.05 0.2 0.08
Inhibited 500hrs 120 0.05 0.2 0.4
Eskom 2008 MINERAL MINERAL INSULATING OILS
10 (Type U) Uninhibited IEC 61125C 164 hrs 120 0.8 1.2 ≤+5 220 IEC 60666 Not detectable
Page 56
INSULATING OILS (UNINHIBITED AND
(UNINHIBITED AND INHIBITED) INHIBITED) PART 1:
PART 1: PURCHASE,
MANAGEMENT, MAINTENANCE
PURCHASE, MANAGEMENT,
(Type U) Uninhibited ASTM D2440-2004 164 hrs 110 0.3 0.6 ≤+5 IEC 60666 Not detectable
AND TESTING MAINTENANCE AND TESTING
(Type 1) Inhibited ≤+5 220 IEC 60666 0.4
11 JAPAN OEM IEC 61125C, Uninhibited 164 hrs 120 0.15 Lit/hr 1.2 0.8 IEC 60666 Not detectable
IEC 61125 C Trace Inhibited 332hrs 120 0.15 Lit/hr 1.2 0.8 0.08
IEC61125C Inhibited 500hrs 120 0.15 Lit/hr 1.2 0.8 0.4

TEIAS New Insulating oil
12 Specification, Number: B . ASTM D4768 0.2 - 0.40
15.2.TEI.0.08.006-900-655
EGAT, Specification of
13 Mineral Insulating oil REV D2440 72 Hrs 110 1 Lit/hr 0.1 0.3 D2300 +30µl/min D 4768 or D2668 0.08-0.3
D2112 220min
6
164 hrs 110 1 Lit/hr 0.2 0.4
Dobles Transformer oil

14 D2440 Uninhibited Optional
April 2008 Revised
72 Hrs 110 1 Lit/hr 0.15 0.5 D2300 Negative Not Applicable D 4768 or D2668 0
D2112
164 hrs 110 1 Lit/hr 0.3 0.6
Type 1
72 Hrs 110 1 Lit/hr 0.15 0.5 D2300 Negative 195 D 4768 or D2668 0.08
D2112
164 hrs 110 1 Lit/hr 0.3 0.6
Type 11
72 Hrs 110 1 Lit/hr 0.1 0.3 D2300 Negative 220 D 4768 or D2668 0.3
D2112
164 hrs 110 1 Lit/hr 0.2 0.4
No SPECIFICATION OXIDATION STABILITY GASSING TENDENCY ROTATING BOMB TEST INHIBITOR CONTENT Ca / Cp / Cn
%sludge
Method Duration Temp Flowrate Acid max Method Max Method Spec Method Spec Method Spec
max
Inhibited , Special
15 EUROPEAN OEM-1 IEC 61125 Method C
application
120 ± 0.5
500 hrs 0.15 Lit/hr 0.3 0.05 IEC 60666 0.3(-0.05+0.10)
°C
Inhibited
120 ± 0.5
IEC 61125 Method C 500 hrs 0.15 Lit/hr 1.2 0.8 IEC 60666 0.3(-0.05+0.10)
°C
120 ± 0.5
IEC 61125 Method C 164 hrs 0.15 Lit/hr 1.2 0.8 IEC 60666 Not detectable
°C
D2440 164 hrs 110 1 Lit/hr 0.6 0.3 D 4768 or D2668 0.01-0.08
D2440 164 hrs 110 1 Lit/hr 0.4 0.2 D 4768 or D2668 0.08-0.30
120 ± 0.5 IEC 60628: 1985 , Method
16 Malaysia OEM IEC 61125 Method C 164 hrs 0.15 Lit/hr 1.2 0.8 5 IEC 60666 Not detectable ASTM D 2140 9.0 / 49.0 / 42.0
°C A
SANS 555:2007 EDITION 5

SOUTH AFRICA NATIONAL Unused and reclaimed mineral
17 IEC 61125C, Uninhibited 164 hrs 120 0.15 Lit/hr 1.2 0.8 IEC 60666 Not detectable
STANDARD insulating oils for transformers
and switchgears
19 EUROPEAN OEM-2 IEC61125C Inhibited 500hrs 120 0.15 Lit/hr 1.2 0.8 D 2300 +30 IEC 60666 0.3
IEC61125C Uninhibited 164 hrs 120 0.15 Lit/hr 1.2 0.8 Not detectable
Standard specification for mineral

20 ASTM D 3487-2006 insulating oil used in electrical D 2440 - TYPE 1 72 hrs 0.15 0.5 D 2300 Method A 15 D 2668 or D 1473 0.08
apparatus
164 hrs 0.3 0.5 D 2300 Method B 30
D 2440 - TYPE 11 72 hrs 0.1 0.3 D 2300 Method A 15 D 2112 195 D 2668 or D 1473 0.3
164 hrs 0.2 0.4 D 2300 Method B 30
Specification for unused &

21 BS 148-98 reclaimed mineral insulating oils BS EN 61125: 1993 Uninhibited 120 0.15 Lit/hr 0.8 1.2 BS 5797:1994 for 120mins 5 BS 5984 Not detectable
Page 57
for transformers and switchgear
BS EN 61125: 1993 Inhibited 164 hrs 120 0.15 Lit/hr 0.01 0.25 BS 5797:1994 for 120mins 8 No requirement
BS EN 61125: 1993 Inhibited 500 hrs 120 0.15 Lit/hr 1 1.5
IS 335: 1993 Reprinted

22 New insulating oils Annex C 164hrs 100 1 0.1 0.4 IS 13631: 1992 0.5
1998
23 IRAN OEM IEC 61125C, Uninhibited 164 hrs 120 0.15 Lit/hr 1.2 0.8 IEC 60628 Method A eneral requirement IEC 60666 Not detectable
24 EUROPEAN OEM-3 Mineral insulating oils IEC 61125C, Uninhibited<362 KV 164 hrs 120 0.15 Lit/hr 0.1 0.2 IEC 60628 Method A IEC 60666 Not detectable
IEC 61125C, Uninhibited362KVto 420KV 164 hrs 121 0.15 Lit/hr 0.1 0.15 or Not detectable
IEC 61125C, Uninhibited ≥420KV 164 hrs 122 0.15 Lit/hr 0.1 0.1 ASTM D 2300B Not detectable
IEC 61125 C Trace Inhibited<362 KV 332hrs 120 0.15 Lit/hr 0.1 0.2 0.08
IEC 61125 C Trace Inhibited362KVto 420KV 332hrs 121 0.15 Lit/hr 0.1 0.15 0.08
IEC 61125 C Trace Inhibited≥420KV 332hrs 122 0.15 Lit/hr 0.1 0.1 0.08
IEC61125C Inhibited<362 K 500hrs 120 0.15 Lit/hr 0.1 0.2 0.4
IEC61125C Inhibited362KVto 420KV 500hrs 121 0.15 Lit/hr 0.1 0.15 0.4
IEC61125C Inhibited≥420KV 500hrs 122 0.15 Lit/hr 0.1 0.1 0.4
6.2 Methods for Evaluating Oxidation Stability - Different Methods, Different Results
The methods used for oxidation stability were historically developed for lubricants and differ considerably in
conditions, time and temperature (Table 12), therefore it is not astonishing, that the results they deliver also differ.
Table 12 Comparison of some methods for determination of oxidation stability in insulating

fluids.
Cu Flow
Test duration Temp.
Method surface/oil gas remarks
[h] [°C]
[cm²/kg] [l/h]
IEC 61125/A 164 100 388 oxygen 1 Sol. Acids
IEC 61125/B (Induction) 120 1144 oxygen 1
IEC 61125/C 164 –500 120 1144 air 0.15
ASTM D 2440 72 – 164 110 419 oxygen 1 Sol. Acids
ASTM D 2114 (100rpm, Plus water,

(Induction) 140 6141 oxygen
(RPVOT) 620kPa) ox. Pressure
Plus steel
ASTM D943 (TOST) (Induction) 95 1137 oxygen 6 and water,
Sol acids
DIN 51554 (Ba) 140 110 360 air (1500lifts/h) No air flow
No catalyst,
ISO 6886 (Induction) 110 (3g Sample) air 10 vol ox.
Products
Results of oxidation stability, achieved by different methods are the basis of evaluation in standards and guidelines
for unused insulation fluids. A brief overview is presented in Table 13.
Page 58
Table 13 Some existing determination and evaluation standards for oxidation stability.
Mineral oil Mineral oil Mineral oil Fatty acid
Synth. Ester
IEC ASTM Further ASTM ester
ASTM D1934 EN 14112

– open beaker (biodiesel)
determination IEC 61125 ASTM D2440 ASTM D2112 IEC 61125C 61125C
–pressure (natural
vessel esters)
Evaluation IEC 60296 ASTM D3487 IEC 61099
6.3 Comparison Between Different Oxidation Methods

There are numerous attempts to find correlation between different oxidation methods. Some of these comparisons
are shown below.
6.4 Comparison of IEC ASTM Baader Method for Oxidation Stability

The experience has shown, that there is no common degree of refining for optimizing oxidation stability acc. To
Baader, IEC 61125C and ASTM D2440. This is illustrated in Fig. 56 [2]
Ageing
Liberation of
Pro‐Oxidants
Degree of refining
Fig. 56 Liberation of pro-oxidants depends on the degree of refining. Mineral oils optimized to
one oxidation stability method may not necessarily perform well in another one. The curves
serve only as an exemplaric illustration.
Page 59
6.5 Comparison of IEC 61125C and ASTM D1934

Mineral oils, synthetic esters and vegetable esters have been tested acc. To IEC 61125 C “unused-hydrocarbons
based insulating liquids / Test methods for evaluating the oxidation stability”
Ageing for non inhibited mineral oils at 120°C during 164h
Air flow (0.15l/h) + copper (ratio 1:1)
- ASTM D1934 “Oxidative aging of electrical insulating petroleum oils by open-beaker method”
Original: 96h at 115°C with or without copper catalyst (15cm2 for 300ml  ratio 20:1)
Extended: 336h at 120°C with copper (ratio 3:1)
The evolution of acidity and DDF has been monitored. ASTM D1934, especially the extended version, allows a
differentiation to be drawn between vegetable fluids, but not between mineral oils. IEC 61125C; the bubbling of air
in particular has a major impact on the oxidation behavior of vegetable fluids [79].
6.6 Comparison of IEC 61125B, IEC 61125C and (EN 14112)

More severe test conditions allow a better differentiation to be made between insulation oils with different oxidation
stability. On the other hand, the more the test conditions differ from real life conditions, the higher the risk that the
test results are irrelevant with respect to real-life performance. Going from mild to severe conditions (or vice-versa)
may drastically change the ranking of oils. The diagram below illustrates both these aspects. It seems reasonable
to expect that the more realistic test conditions (i.e. the milder ones) provide the more relevant results (Fig. 57) [65].
1400
A
1200
1000
B
Induction time (h)
800 C
600
400
200
Rancimat 1125B 1125C

<more severe test less severe test >
Oil A – highly refined inhibited naphthenic oil,Oil B – Hydrocracked inhibited oil,Oil C – standard grade inhibited oil
Fig. 57 Effect of severeness of the test method on result of oxidation stability measured by the
induction period
Page 60
6.7 Description of different oxidation stability procedures
6.7.1 DESCRIPTION OF IEC 61125 METHODS

The international standard IEC 61125 describes three test methods that require the same apparatus, for evaluating
the oxidation stability of unused mineral insulating oils and of unused hydrocarbon-based insulating liquids.
Method A is dedicated to uninhibited oils, method B to inhibited oils, and method C is applicable to both inhibited
and uninhibited oils.
6.7.1.1 General principle of the methods

The liquid sample to be tested is maintained for a given period at a given temperature, with a bubbling of oxygen or
air, and in the presence of solid copper (oxidation catalyst). The experimental parameters for each method are
given in the following (Table 14).
After the accelerated ageing treatment, resistance to oxidation of the tested insulating liquid is evaluated from the
total amount of sludge and total acidity produced, the value of DDF reached, or from the time needed to develop a
given amount of volatile acidity (induction period).
Table 14 Experimental parameters of IEC 61125 test methods A, B and C

Type of oil uninhibited inhibited both
Method A Method B Method C (Fig. 58)
Mass of oil 25 g ± 0.1 g 25 g ± 0.1 g 25 g ± 0.1 g
Oxidant gas oxygen oxygen air
Gas flow-rate 1 l / h ± 0.1 l / h 1 l / h ± 0.1 l / h 0.15 l / h ± 0.015 l / h
Temperature 100°C ± 0.5°C 120°C ± 0.5°C 120°C ± 0.5°C
Test duration 164 h Not defined 168 h and multiples
Copper wire (a), Q.S. 9.7 cm² ± 0.1 cm² 28.6 cm² ± 0.3 cm² 28.6 cm² ± 0.3 cm²
- Sludge
Determination on the - Sludge - Induction period - Soluble acidity
oxidized sample - Soluble acidity (0.28 mg KOH / g oil) - Volatile acidity
- Total acidity
- Sludge
- Soluble acidity - DDF
- Volatile acidity - Induction period
Optional - DDF
- Total acidity (0.10 mg KOH /g oil)
- Oxidation rate - Oxidation rate
- DDF
(a) The solid copper used as oxidation catalyst consist of a wire of soft electrolytic copper, with a diameter
between 1 mm to 2 mm and of a length to yield the surface area, in contact with the sample, specified by
the chosen method.
Page 61
6.7.1.2 Determinations on the oxidized liquid

Sludge formation
Sludge is collected by filtering of the oil sample with the heptane used to rinse out the test tubes and the copper
wire.
The sludge residues adhering to the test tubes and to the copper is dissolved in chloroform and then measured
after the chloroform evaporation.
Soluble acidity (SA)

Soluble acidity is measured by colorimetric titration of the oil-in-heptane solution obtained after filtering off the
sludge.
Volatile acidity (VA) – only for method B and C

Volatile acidity is a titration measurement of the amount of oxidation products collected in the absorption tube
during the ageing period.
Total acidity (TA)

Total acidity corresponds to the sum of the volatile and soluble acidities:
TA = SA + VA
Dielectric dissipation factor (DDF)

The DDF measurement is performed on a separately oxidized oil sample.
After decantation of the aged liquid, 24 hours at room temperature (20°C ± 5°C), the DDF is determined at 90°C in
accordance with IEC 60247 or IEC 61620.
Oxidation rate – only for method B and C

The aqueous alkali solution in the absorption tube is titrated at suitable time intervals to obtain a graphical
determination of the oxidation rate, after plotting the cumulated results of VA against time.
Induction period (IP) – only for method B and C

For the purpose of the methods B and C, the induction period is arbitrarily set as the time taken for the oil to
develop a volatile acidity corresponding to:
- Method B 0.28 mg KOH / g oil
IP is reported as the mean of the times preceding and following the loss of color of the appropriate aqueous
alkali solution placed in the absorption tube.
- Method C 0.10 mg KOH / g oil
IP is determined by reading off the time corresponding to this value on the oxidation rate curve featuring the
cumulated volatile acidities.
In both cases, the induction period can be more precisely and automatically measured by the break in the curve
obtained by continuously recording the pH of the appropriate absorbent solution.
Page 62
C= Air, 0,15dm³/h
Air
•Temperature 120°C
•Test duration
–164 h non inhibited
–332 h trace inhibited
–500 h inhibited oils
•Results:
120°C PH
copper wire – Total acid number
– Sludge
Oxidation Tube Absorption Tube – DDF
total acidity = Soluble acids + volatile acids
Fig. 58 Experimental setup for oxidation stability according IEC 61125C
6.7.2 DESCRIPTION OF ASTM 2440 METHOD

ASTM D 2440 is similar to IEC 74/IEC 61125 A, apart from the temperature which is slightly higher, 110 °C, and
the test duration which is 72 and 164 hours (Fig. 59).
Oxygen 1dm³/h
•Temperature 110°C
•Test duration
–72h/164h for Type I and II
•Results:
– Total acid number
– Sludge
Fig. 59 Experimental setup for oxidation test according ASTM D2440
6.7.3 DIN 51554 –“BAADER TEST”

This test procedure has been actively used since 1978. The method was reviewed around 2000, as laboratory
glassware of suitable quality to evaluate the saponification number (one component of the Baader test) was no
longer available.
Page 63
In 2001 a revised draft test method was developed, its status today is still draft however. So at present two Baader
tests are available:
- one active version of 1978
- one draft version of 2001.
As the glassware quality may continue to be unavailable in the future, the draft version (which evaluates the
neutralization number instead of saponification number) is more frequently used than the active version from 1978.
The neutralization number can be evaluated with current glassware quality.
DIN 51554 consists of 3 parts:
- DIN 51554 – 1 Scope, sampling and ageing
- DIN 51554 – 2 Test at 110°C => Preferably used for electrical oils
- DIN 51554 – 3 Test at 95°C => preferably used for hydraulic fluids H and lubricating
oils C, C-L and C-LP – tests only the saponification number.
For electrical oils only part two is of relevance, therefore only this part is described below
Fig. 60 DIN 51554 part 2 (1978) – Test of susceptibility to ageing according to Baader
6.7.3.1 Scope
The test method is designed to predict the oxidation of insulating fluids in contact with atmospheric air. The version
of 1978 was designed to test unused uninhibited transformer oils.
6.7.3.2 Ageing
The specimens are aged at 110°C (+/- 0,5°C) for 140h with access to air. In order to accelerate the ageing a
copper wire spiral is immersed and lifted
Page 64
25 strokes per minute / 36000 strokes per day. No air or oxygen flows through the sample. The oil vapor is
condensed with a Liebig condenser (Fig. 60). The oxidation test must be performed in a dark room that is free from
dust, acid, ammonia, organic vapor and ozone.
After the ageing period of 140h the aged oil is evaluated in
- Visual inspection
- Saponification number
- Dielectric Dissipation factor @ 90°C
- Sludge content
To perform tests two specimens filled with 60ml oil are aged.
Glassware: Borosilicate glass or neutral glass
Copper catalyst: 2 mm diameter, 300 mm length wound in a spiral. The copper is activated by a wear and cleaning
procedure to provide a fresh activated copper surface for the oxidation test.
6.7.3.3 Evaluation
Visual inspection: Any changes in the appearance of the specimens and of the wire spirals are ascertained and,
where appropriate, recorded in the test report.
Saponification Number: Test method is DIN 51559 part 2. A certain amount of sample is dissolved in a blend of
toluene and ethanol (contains a color indicator). KOH is added and the sample is heated. Surplus KOH, which is
not consumed by saponification, is titrated with HCl. The saponification number is calculated form the consumed
KOH.
Dielectric dissipation factor: test method is DIN 57370 part 1 (comparable to IEC 60247).
For the measurement the sample is not filtered but decanted.
Sludge content: After the sample has been cooled down it is filtered through a glass filter. The sludge content
according to Baader, is the sludge which is soluble in chloroform. First the residue on the filter is dissolved with
chloroform and the residue after separation of the chloroform is recorded as the sludge.
6.7.4 DIN 51554 PART 2 TEST OF SUSCEPTIBILITY TO AGEING ACCORDING TO BAADER
6.7.4.1 Scope
The method is to predict the oxidation of insulating fluids in contact with atmospheric air. Method can be used for
unused inhibited and unused uninhibited transformer oils.
6.7.4.2 Ageing
The specimens are aged at 110°C (+/- 0.5°C) for 140h (or 28d for inhibited oils) with access to air. In order to
accelerate ageing a copper wire spiral is immersed and lifted
25 strokes per minute / 36000 strokes per day. No air or oxygen flows through the sample. The vapor of the oil is
condensed with a Liebig condenser. The oxidation test must be performed in a dark room that is free of dust, acid,
ammonia, organic vapor and ozone.
Page 65
After the ageing period of 140h the aged oil is evaluated in
- Visual inspection
- Saponification number
- Dielectric Dissipation factor @ 90°C
- Sludge content
To perform all tests two specimens filled with 60ml oil are aged.
Glassware: Borosilicate glass or neutral glass
Copper catalyst: 2 mm diameter, 300 mm length wound to a spiral. The copper is activated by a wear and cleaning
procedure to provide a fresh activated copper surface for the oxidation.
6.7.4.3 Evaluation
Visual inspection: Any changes in the appearance of the specimens and of the wire spirals is assessed and, where
appropriate, recorded in the test report.
Neutralization Number: test method is DIN 51558.
A certain amount of the sample is dissolved in toluene and ethanol (contains a color indicator). KOH is used for
titration until neutralization. The neutralization number is calculated from consumed KOH.
Dielectric dissipation factor: test method is DIN 57370 part 1 (comparable to IEC 60247).
For the measurement the sample is not filtered but decanted.
Sludge content: After the sample has been cooled down it is filtered through a glass filter. The sludge content
according to Baader is the sludge which is soluble in chloroform. First the residue on the filter is dissolved with
chloroform and the residue after separation of the chloroform is recorded as the sludge.
6.7.5 ROTATING PRESSURE VESSEL OXIDATION TEST (RPVOT,ASTM D2112, ASTM D2272)
ASTM D2112 is intended for inhibited mineral oils and is often used as a quick screening test [80, 81]. The test is
carried out at 140°C in the presence of copper, water and overpressure of oxygen (90 psi). The result is
represented as the time during which the oil reacts with a certain amount of oxygen (Fig. 61).
Thin film of
Sealed
Glass Oil +
Fig. 61 Experiment setup of ASTM D2112
Page 66
6.7.6 DSC
Differential scanning calorimetry (DSC) can be used to evaluate the heat developed or taken up as the temperature
of a material is changed. In the absence of phase transitions, the heat requirements reflect the specific heat of the
materials. DSC can also be used to evaluate the latent heat associated with phase transitions.
In the 90s preliminary studies showed a promising outlook of DSC for detection of a sort of induction period related
with oil oxidative resistance. Consequently, in 1998 IEC set up an ad-hoc WG to develop a rapid oxidation stability
test method based on DSC. The WG decided to apply an enhanced version of common DSC apparatus called
PDSC (pressure differential scanning calorimetry) where the heat developed or taken up from oil sample is
measured in presence of an oxidizing and pressurized atmosphere.
Unfortunately, despite of the efforts of the researches the study reveals difficulties in the understanding and in the
reproducibility of the shape of curve; also the dependence of results on the equipment used, sample-holder type
and heating profile was not completely clarified. All of these limits therefore prohibit official use of this test
technique as an oxidation stability test, and as matter of fact in 2006 IEC decided to publish the document 62036-
TR as Technical Report, purely as information.
6.7.7 INFRARED SPECTROMETRY

Infrared spectrometry (IR), and its more recent Fourier Transformer version (FTIR) is a well-known chemical tool
used for investigation of the chemical nature of substances. Its use in organic chemistry is mainly oriented to
qualitative recognition, because the intrinsic relatively low sensitivity is a great restriction for extensive use as a
quantitative technique. It is not a routine test for evaluation of oxidation stability, but has been used for research
purposes [58].
In the past IR was applied in many studies on oil ageing and its sledges; in this regard the mostly common used
frequency bands were in the region 1800 – 800 cm-1:
- Band with apex at 1715 cm-1, corresponding to carbonyl groups

- Bands with apex at 1460 and 1380 cm-1, corresponding to residual aliphatic chains
- Bands in range 1000 – 1300 cm-1, corresponding to oxidized sulfur groups.
6.7.8 EN 14112 – FAT AND OIL DERIVATIVES . FATTY ACID METHYL ESTER (FAME)
This method, known also as Rancimat is performed under following conditions (Fig. 45):
- no catalyst
- Flow 10 l air/h
- Temperature: 110°C
- 3 g sample
- Volatile oxidation products are transferred in a sampler with distilled water
- Result = Time until a conductivity of 200 µS/cm is reached
The induction time is determined from the maximum of the 2nd derivative of the curve for conductivity versus time
Page 67
Fig. 62 Experiment setup of EN 14112
This method has been modified by the use of a copper catalyst and applied for ranking of mineral oils and
vegetable esters. Acc. To this modified method vegetable esters are comparable with uninhibited mineral oils.
Copper has a very strong influence on the induction period, especially at lower temperatures. In the case of
uninhibited oils, a 10°C temperature increase leads to a doubling of the induction period. In the case of inhibited
oils, a 20°C temperature increase leads to a doubling of the induction period.
6.7.9 MICROCALORIMETER
Isothermal microcalorimeters have been used for years for measuring the oxidative stability of polyamides
pharmaceutics and propellants, for example. The method of using an isothermal microcalorimeter has been used
for research purposes and may be used for classification of insulating oils [82]. The area below the micro
calorimeter curves decreases with increasing oil/air ratio, given that there is a correlation between the amount of air
in the samples and the oxidation of the oils.
6.7.10 VOLTAMMETRIC TECHNIQUES

Voltametric Techniques can be used for the determination of inhibitors, especially in the lubricating industry [83].
6.8 Round Robin Test on Oxidat i on Stability

The existing differences between oxidation procedures posed the challenge to evaluate groups of oils according to
different methods. The aim was to observe possible ranking of insulating fluids, tested under the same conditions.
One common method was chosen, since it allows the use of a common criterion for all insulating fluids,
independent of the presence or absence of inhibitors. The insulating liquids studied were supplied by the
participants and consisted of inhibited and uninhibited mineral oils, unused or reprocessed, synthetic and natural
esters as well as liquids with new inhibitors, specially created for the test (not commercially available).
Additionally, participants were free to use methods commonly used in the practice and ones for which experience
was available.
Page 68
There was a great divergence of the results obtained by the various laboratories concerning the repeatability of the
test for induction period. After troubleshooting and corrections in the experiment setup a second run of results was
carried out.
Although the second round of results for the induction period are in better agreement, there nevertheless remains
high divergence for the results, especially for non-inhibited mineral oils. It seems that the method is complex
enough and the results vary, not only concerning the induction period, but also acidity, loss factor and sludge. It
seems that many of the volatile acids are absorbed by silicone tubing (turning yellow to brownish over time) and
therefore not detected in the aqueous extracts.
As a consequence, some recommendations to IEC 61125C will be made to improve the repeatability:
• Non use of silicone tubes, short paths between tubes, e. g. glass tubing joined with short flexible sleeves.
• Quality of air can be a concern. Control of air flow, as well as of the temperature and copper surface.
The result of the ranking depends very much on the selected test. The evaluation of insulation fluids with regard to
oxidation stability seems to be very much dependant on the application – free breathing or closed equipment.
In case of air access the ranking follows more or less the response of the oxidation inhibitor. However, here there
was also a difference between the induction time according to IEC 61125C and RPVOT test. It must also be
considered that only a few and widely divergent results were available for the RPVOT test.
In the case of the headspace method there is restricted amount of oxygen. Under such conditions there is not a
major oxidation impact and it also seems that uninhibited insulating fluids, as well as vegetable oils perform quite
well. Vegetable fluids without inhibitor packages tend to develop high acidity and loss factor. The headspace
method can in this respect be regarded as a functional test for testing service conditions.
In case of ageing of vegetable oils, viscosity has also been determined prior to and after ageing. The viscosity
increase is minimal.
To summarize, it is clear that prior introduction of a new insulating fluid, intensive studies and pilot projects are
needed. A combination of different tests may be useful to obtain a better correlation to experience in the field. This
should be considered when introducing a new insulating fluid onto the market.
6.8.1 EVALUATION OF THE RESULTS FROM THE ROUND ROBIN TEST

The existing differences between oxidation procedures posed the challenge of evaluating groups of oils according
to different methods. The aim was to observe a possible ranking of insulating fluids, tested under the same
conditions.
One common method was chosen, since it allows the use of a common criterion for all insulating fluids,
independent of the presence or absence of inhibitors.
Additionally, participants were free to use methods commonly used in practice and ones for which experience was
available.
6.8.2 METHODS USED IN THE RRT
6.8.2.1 Oxidation stability according to IEC 61125C (induction time).

Parameters determined: induction period
For determination of the induction period, the acidity of the water in the absorption tube needs to be titrated
regularly, and the accumulated volatile acidity plotted vs. time (Excel sheets have been provided for this). The
Page 69
induction time is the time needed for the volatile acidity to exceed 0.10 mg KOH/g. .
6.8.2.2 Oxidation stability acc. IEC 61125C

Parameters determined: neutralization value, sludge content and loss factor
6.8.2.3 Headspace method (closed vial method)

Ageing was carried out in 50 ml headspace vials with 37.5 ml insulation fluid (ratio fluid:air 3:1) and a bare copper
strip (length 67mm, width 7.5 mm), closed with a silicon cap. Ageing duration 164h at 150°C. Parameters
determined: Neutralization value, loss factor, peroxides.
6.8.2.4 ASTM D2112 – Rotating Pressure Vessel Oxidation Test (RPVOT)
6.8.2.5 PDSC Onset time, IEC 62036-TR
6.8.2.6 ASTM D2440 for 164h

Parameters determined: Neutralization value. Sludge content
6.8.2.7 Baader Test – DIN 51554

Parameters determined: neutralization value, sludge content and loss factor
6.8.3 PARTICIPATING LABORATORIES

ABB Sweden, Apar Industries India, Areva T&D France, EDF France, EIMV Slovenia, Electrical Engineering
Institute Serbia, Laborelec Belgium, Nynas Sweden, PetroChina Karamay China, Powerlink Queensland Australia,
Sea Marconi Italy, Sintef Norway, Shell Germany, Siemens Germany, Techniker Spain, Terna Italy, Wienstrom
Austria.
6.8.4 GROUPS OF INSULATING FLUIDS

3438-2008 – naphthenic based
3439-2008 –naphthenic - paraffinic based
3440-2008 - severely hydrotreated naphthenic base oil
3441-2008– naphthenic based, hydrotreated
3442-2008 - severely hydrotreated naphthenic base oil
3443-2008 – naphthenic based, inhibited with 0,30% DBPC
3444-2008 – naphthenic based, hydrotreated phenolic inhibited
3446-2008 – synthetic ester
3447-2008 - high oleic vegetable oil, highly refined, inhibitor package (not DBPC)
3448-2008 - blend of a vegetable oil and esters of fatty acids and heavy monoalcohol, no additives
3449-2008 - vegetable oil, highly refined, inhibitor package
3450-2008 – hydrotreated used oil
3451-2008 – depolarized reclaimed oil (reclaimed - combination of chemical reagent and sorbent)
3452-2008 – depolarized reclaimed oil (reclaimed - combination of chemical reagent and sorbent)
Page 70
3453-2008 – naphthenic-paraffinic based with total 0,40% inhibitors, consisting of hindered phenol type and
diarylamin type
3454-2008 - naphthenic based, hydrotreated phenolic and aminic inhibited
All insulating fluids (with exception of the mineral oils with special inhibitors) have been used in real life, some of
them for pilot projects only.
6.8.5 RESULTS OF THE RRT

There was a great divergence of results between the laboratories concerning the repeatability of the test for the
induction period. After troubleshooting and corrections in the experiment setup a second run of results were carried
out.
Although the second results for the induction period are in a better agreement, there nevertheless remains great
divergence of results, especially for non-inhibited mineral oils. It seems that the method is complex enough and the
results vary not only for induction period, but also for acidity, loss factor and sludge. It seems that a lot of the
volatile acids are absorbed by silicone tubing (turning yellow to brownish with time) and are therefore not detected
in the aqueous extracts.
As a consequence, recommendations to IEC 61125C will be made to improve the repeatability:
• Non use of silicone tubes, short paths between tubes, e. g. glass tubing joined with short flexible sleeves.
• Quality of air can be a concern. Control of air flow, as well as of the temperature and the copper surface.
Ascending Order Oxidation Stability Acc. Different Methods
ASTM HS Tangens-
Induction Time (Neutr. HS Neutr delta PDSC Onset
IEC 61125C (h) Value) value (90°C) Rbot (min) Time (min)
3441 3451 3448 3448 3448 3448
3451 3448 3449 3446 3449 3451
3440 3447 3446 3451 3451 3449
3449 3441 3447 3438 3439 3440
3438 3440 3451 3444 3440 3439
3448 3443 3453 3442 3441 3441
3439 3438 3452 3449 3447 3447
3447 3446 3454 3439 3438 3438
3454 3442 3438 3454 3442 3452
3444 3452 3443 3452 3444 3443
3450 3454 3442 3447 3450 3450
3442 3453 3444 3440 3452 3442
3452 3444 3450 3443 3443 3444
3446 3450 3441 3441 3453 3453
3443 3439 3440 3450 3446 3446
3453 3449 3439 3453 3454 3454
3438-2008 – naphthenic based
3439-2008 –naphthenic - paraffinic based
Legend 3440-2008 - severely hydrotreated naphthenic base oil
3439 uninhibited mineral 3441-2008– naphthenic based, hydrotreated
3442 inhibited mineral 3442-2008 - severely hydrotreated naphthenic base oil
3446 Ester 3443-2008 – naphthenic based, inhibited with 0,30% DBPC
3450 refurbished/reclaimed 3444-2008 – naphthenic based, hydrotreated phenolic inhibited
3453 special inhibitors 3446-2008 – synthetic ester
3447-2008 - A high oleic vegetable oil, highly refined, inhibitor package (not DBPC)
3448-2008 - blend of a vegetable oil and esters of fatty acids and heavy monoalcohol, no additives
3449-2008 - vegetable oil, highly refined, inhibitor package
3450-2008 – hydrotreated used oil
3451-2008 – depolarized reclaimed oil
3452-2008 – depolarized reclaimed oil
3453-2008 – naphthenic-paraffinic based with total 0,40% inhibitors, consisting of hindered phenol type and diarylamin type
3454-2008 - naphthenic based, hydrotreated phenolic and aminic inhibited
Fig. 63 Type of insulating liquids used in the test and their evaluation according to different
methods
In order to compare the ranking between different methods, only the procedures carried out at uniform conditions
for all insulating fluids were selected. In order to avoid outliners, mean values have been taken for this comparison.
Page 71
Statistically meaningful values existed only for determination of the induction time according to IEC 61125C and for
the headspace test. The PDSC onset time was not comparable, so the values of only one laboratory were taken.
6.8.5.1 Induction Time acc. to IEC 61125C

The results of this method show that mainly non-inhibited oils and some natural vegetable fluids perform worse
than inhibited mineral oils and synthetic ester. In the case of the new oxidation inhibitors one mineral oil performs
very well and a second one does not show any significant advantage.
6.8.5.2 Acidity (neutralization value) acc. ASTM D2440

The ranking according to this method is quite different. Remarkably one non-inhibited oil and one natural ester
perform very well.
6.8.5.3 RPVOT ASTM D2112

This is a typical test for lubricants and response to oxidation inhibitor.
The ranking (less to higher oxidation stability) here is in the order:
- Vegetable fluids
- Non-inhibited mineral oils
- Inhibited oils
- Synthetic ester
6.8.5.4 PDSC Onset

Here the values of only one participant have been considered. The ranking is similar to that for RPVOT ASTM
D2112
6.8.5.5 Headspace Method (Neutralization value considered)

The differences in the neutralization value for the Headspace test were not very significant. It is interesting to note
here that uninhibited mineral oils do not develop a significant acidity when oxygen is strongly restricted.
6.8.5.6 Headspace Method (Loss factor at 90°C considered)

There is no explicit ranking according to non-inhibited and inhibited fluids. Vegetable oils seem to perform similarly
to mineral oils.
6.8.6 DISCUSSION
The result of the ranking depends very much on the selected test. The evaluation of insulation fluids with regard to
oxidation stability seems to be very much dependant on the application – free breathing or closed equipment
(Fig. 63).
In the case of air access the ranking follows more or less the response of the oxidation inhibitor. However, here
there was also a difference between the induction time according to IEC 61125C and RPVOT test [85].
It must also be considered that only a few and widely diverging results were available for the RPVOT test. PDSC
Onset time showed nearly the same ranking as RPVOT.
In the case of the headspace method there is a restricted amount of oxygen. Under such conditions there is no
major oxidation impact and it also seems that uninhibited insulating fluids, as well as vegetable oils perform quite
well. Vegetable fluids without inhibitor packages tend to develop high acidity and loss factor. The headspace
method (closed vial method) can in this respect be regarded as a functional test for testing service conditions for
designs which allow only a restricted amount of oxygen. In the case of ageing of vegetable oils, viscosity prior to
and after ageing was also determined. The viscosity increase is minimal under these conditions.
Page 72
6.8.7 CONCLUSION
A combination of different tests may be useful to make a better correlation to experience in the field. This should be
considered when introducing a new insulating fluid. The RRT showed that insulating oils designed according to
only to one test, e.g. RPVOT may show contrary behavior in other tests, e.g. induction time according to IEC
61125C. This was the case with the two new oils with a new inhibitor mix created for the RRT.
Therefore, prior to introduction of new insulating fluids with new type of inhibitors or inhibitor mix, intensive studies
and pilot projects are needed.
Page 73
Chapter 7. Summary and Conclusions

Oxidation stability is an important characteristic and therefore has found place in all available specifications for
unused insulating fluids. It is considered by users as an important part of performance and reflects the stability and
reproducibility of oil quality. The methods for the determination of oxidation stability in different specifications differ
based on existing historical experience. Insulating mineral oils used in closed type equipment are usually
characterized by the ASTM D2440 method. IEC specification IEC 60422 refers to IEC 61125C, which is mainly
used to characterize oils in free breathing transformers and differentiates between inhibited and uninhibited mineral
oils. This specification is widely used all over the world as shown by the survey. The Round Robin Test on different
– inhibited, uninhibited, rerefined and reclaimed insulating oils, natural and synthetic esters as well as newly
designed mineral oils with special inhibitors has shown that there is no one single oxidation stability method which
is applicable to all liquids. Newly developed insulating fluids should be tested using different oxidation procedures
and the results compared against existing experience. For enhanced reproducibility of IEC 61125C some changes
in the experimental setup have been tested during the RRT and have been proposed for future revision of the
standard.
There is no direct correlation between the oxidation stability tests and the performance of insulating oils in service.
This is due not only to the different environments in a transformer or other electrical equipment, but also to the
particular working conditions such as load, design, cooling type etc. Nevertheless, enough evidence exists showing
that oils with low oxidation stability also have a shorter service life. A comparison of experience under similar
conditions indicates that inhibited insulating oils have a longer life than uninhibited ones. Knowing the factors which
contribute to insulating fluid oxidation and excluding them leads to a prolongation of the insulating fluid life. This is
especially important in case of natural esters. Less demanding applications, in terms of load or oxygen ingress may
perform well with uninhibited insulating fluids. High loaded free breathing equipment will have a longer insulating oil
life with inhibited oils. The choice of an insulating fluid becomes more and more application oriented, based on
customer and design requirements with regard to dielectric and physico-chemical considerations as well as
environmental aspects and fire safety.
Oxidation stability of insulating fluids is not only a matter of unused new fluids. It changes during service and
influences the diagnostic parameters used for condition assessment of the equipment, e.g. gas-in-oil analysis and
oil values. Knowledge of this behavior is essential for distinguishing between ageing of the fluid and failure in the
equipment.
A poor condition of the fluid does not necessarily mean poor condition of the equipment. Prolonging of oil life in
service will, in many cases, help prolong the effective use of equipment far beyond the designed life span.
Depending on the task, more or less sophisticated methods can be used – starting from simple inhibitor addition up
to oil reclaiming. Oil reclaiming removes most of the ageing byproducts, but also present inhibitors, therefore
inhibition after reclaiming is necessary for a long-lasting effect. The effect of reclaiming depends on many factors
such as oil and adsorbent type, reclaiming conditions, etc., and should be studied in more detail separately.
Oxidation stability is closely related to corrosivity, since sulfur compounds are responsible for both. With oil ageing
or some oil treatments non-corrosive oils may turn corrosive; therefore, all oil characteristics should be monitored in
service.
Main conclusions of the Cigre D1.30 work project are listed below:
- oxidation stability is important for oil performance and is to be regarded together with other oil properties
- oxidation stability is strongly related to the degree of refining and the interaction of natural and synthetic
inhibitors and passivators
- temperature, oxygen and metals, especially copper accelerate oil oxidation
- for qualifying of a new insulating liquid for electrical equipment more than one method for oxidation
stability should be applied and the results compared with existing experience
Page 74
- oil oxidation is closely connected to stray gassing
- inhibited oils age more slowly (have a longer service life) than uninhibited ones
- reclaiming with subsequent inhibition prolongs the effective life of oil in service
- the choice of insulating fluid should be application oriented, i.e. considering design and operation
conditions
Page 75
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Oxidation Stability of Insulating Fluids

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Oxidation Stability of Insulating Fluids

Bertrand Y. (FR), Dahlund M. (SE), De Pablo (ES) – corresponding member,

Oxidation Stability of Insulating

6.1 Specifications for Oxidation Stability .....................................................................................55

Chapter 1. Why Is Oxidation Stability of Insulating Fluids Important?

- To remove the heat generated by no-load and load losses

Consequently, the following is required of any insulating liquid:

- High dielectric strength

Fig. 1 Sludge, deposited on insulating Fig. 2 Buchholz relay, covered with

This has been recognized by users and by sales alike.

Fig. 3 Title page of VDE 0370 (Germany) from 1936

 Insoluble oxidation products Deposit formation (Sludge)

• Insoluble oxidation products Lacquering

• Soluble organic acids Oil acidity increase

Fig. 4 Influence of oxidation on insulating oil

1.3 Influence of degradation products of oil on cellulosic insulating parts

1.4 Survey “Working Environment of an Insulation Fluid” within Cigre D1.30

General conclusion from the questionnaire evaluation:

1.4.2 TYPES OF TRANSFORMERS

Table 1 Types of transformers

System auxiliary transformer (SAT) 1

1.4.3 PROBLEMS WITH OXIDATION STABILITY?

Table 2 Problems experienced with oxidation stability

1.4.4 WHAT KIND OF OIL IS PREFERRED?

Table 3 Preferred type of insulating oil

Both (inhibited and uninhibited) 5

2 (partially inhibited, spec of

1.4.5 WHAT IS THE STANDARD USED?

Table 4 Applied standards for insulating oil

Australian Std. 1767 1

ASTM D3487, CAN CSA-C50.97 1

1.4.6 ALTERNATIVE FLUIDS

1.4.7 ELECTRICAL AND THERMAL STRESS

- 5 – 10 kV/mm (presumably based on breakdown of oil)

- 20 – 30 kV/mm (presumably based on lightning or switching impulse voltage test)

1.4.8 RATIO COPPER:OIL (W/W)

Chapter 2. Types and Behavior of Insulation Fluid

2.2 Refining methods

Fig. 7 Properties of insulating oils depending on the degree of refining [3]

The response to inhibitor is very closely connected to the degree of refining.

 Oils of high degree of refining have lower inherent oxidation stability

2.3 Napthenic or paraffinic

2.4 Inhibited vs. uninhibited oil

2.5 High grade or standard grade

2.6 Gassing Tendency

2.7 Viscosity class and low temperature properties

2.8 Fluids other than mineral oils

Chapter 3. Chemistry of insulating fluid oxidation

3.2 The mechanism of oxidation

Fig. 8 Schematic mechanism of hydrocarbon oxidation

Fig. 9 Oxidation Route 1

Fig. 10 Oxidation Route 2

3.3 General aspects of oxidation chemistry of oils

3.4 Inhibition of Oxidation

Fig. 11 Oxidation of organic sulfides acting as hydroperoxide decomposers

DBPC Stable radical

Fig. 12 Oxidation of a hindered phenol, acting as a chain breaking antioxidant

3.5 Short General Résumé

WHAT PROMOTES PEROXIDATION?