EN 60599:1999

SLOVENSKI STANDARD
01-december-1999
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Mineral oil-impregnated electrical equipment in service - Guide to the interpretation of
dissolved and free gases analysis
In Betrieb befindliche, mit Mineralöl imprägnierte elektrische Geräte - Leitfaden zur
Interpretation der Analyse gelöster und freier Gase
Matériels électriques imprégnés d'huile minérale en service - Guide pour l'interprétation
de l'analyse des gaz dissous et des gaz libres
Ta slovenski standard je istoveten z: EN 60599:1999
ICS:
29.040.10 Izolacijska olja Insulating oils
2003-01.Slovenski inštitut za standardizacijo. Razmnoževanje celote ali delov tega standarda ni dovoljeno.

NORME
CEI
INTERNATIONALE
IEC
INTERNATIONAL
Deuxième édition
STANDARD
Second edition
1999-03
Matériels électriques imprégnés d’huile minérale
en service –
Guide pour l’interprétation de l’analyse des gaz
dissous et des gaz libres
Mineral oil-impregnated electrical equipment
in service –
Guide to the interpretation of dissolved
and free gases analysis
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For price, see current catalogue

60599 © IEC:1999 – 3 –
CONTENTS
Page
FOREWORD . 5
INTRODUCTION . 7
Clause
1 Scope .9
2 Normative references . 9
3 Definitions and abbreviations. 9
4 Mechanisms of gas formation. 15
5 Identification of faults . 17
6 Conditions for calculating ratios. 27
7 Application to free gases in gas relays. 29
8 Gas concentration levels in service. 31
9 Recommended method of DGA interpretation (figure 1) . 37
10 Report of results . 37
Annex A (informative) Equipment application notes . 43
Annex B (informative) Graphical representation of gas ratios . 63
Annex C (informative) Bibliography . 69
Figure 1 – Flow chart . 41
Figure B.1 – Graphical representation 1 of gas ratios . 63
Figure B.2 – Graphical representation 2 of gas ratios . 65
Figure B.3 – Graphical representation 3 of gas ratios – Duval's triangle. 67

60599 © IEC:1999 – 5 –
INTERNATIONAL ELECTROTECHNICAL COMMISSION
_________
MINERAL OIL-IMPREGNATED ELECTRICAL EQUIPMENT IN SERVICE –
GUIDE TO THE INTERPRETATION OF DISSOLVED AND
FREE GASES ANALYSIS
FOREWORD
1) The IEC (International Electrotechnical Commission) is a worldwide organization for standardization comprising
all national electrotechnical committees (IEC National Committees). The object of the IEC is to promote
international co-operation on all questions concerning standardization in the electrical and electronic fields. To
this end and in addition to other activities, the IEC publishes International Standards. Their preparation is
entrusted to technical committees; any IEC National Committee interested in the subject dealt with may
participate in this preparatory work. International, governmental and non-governmental organizations liaising
with the IEC also participate in this preparation. The IEC collaborates closely with the International Organization
for Standardization (ISO) in accordance with conditions determined by agreement between the two
organizations.
2) The formal decisions or agreements of the IEC on technical matters express, as nearly as possible, an
international consensus of opinion on the relevant subjects since each technical committee has representation
from all interested National Committees.
3) The documents produced have the form of recommendations for international use and are published in the form
of standards, technical reports or guides and they are accepted by the National Committees in that sense.
4) In order to promote international unification, IEC National Committees undertake to apply IEC International
Standards transparently to the maximum extent possible in their national and regional standards. Any
divergence between the IEC Standard and the corresponding national or regional standard shall be clearly
indicated in the latter.
5) The IEC provides no marking procedure to indicate its approval and cannot be rendered responsible for any
equipment declared to be in conformity with one of its standards.
6) Attention is drawn to the possibility that some of the elements of this International Standard may be the subject
of patent rights. The IEC shall not be held responsible for identifying any or all such patent rights.
International Standard IEC 60599 has been prepared by IEC technical committee 10: Fluids for
electrotechnical applications.
This second edition cancels and replaces the first edition published in 1978. This second
edition constitutes a technical revision.
The text of this standard is based on the following documents:
FDIS Report on voting
10/450/FDIS 10/460/RVD
Full information on the voting for the approval of this standard can be found in the report on
voting indicated in the above table.
Annexes A, B and C are for information only.

60599 © IEC:1999 – 7 –
INTRODUCTION
Dissolved and free gas analysis (DGA) is one of the most widely used diagnostic tools for
detecting and evaluating faults in electrical equipment. However, interpretation of DGA results
is often complex and should always be done with care, involving experienced insulation
maintenance personnel.
This guide gives information for facilitating this interpretation. The first edition, published in
1978, has served the industry well, but had its limitations, such as the absence of a diagnosis
in some cases, the absence of concentration levels and the fact that it was based mainly on
experience gained from power transformers. This second edition attempts to address some of
these shortcomings. Interpretation schemes are based on observations made after inspection
of a large number of faulty oil-filled equipment in service and concentrations levels deduced
from analyses collected worldwide.

60599 © IEC:1999 – 9 –
MINERAL OIL-IMPREGNATED ELECTRICAL EQUIPMENT IN SERVICE –
GUIDE TO THE INTERPRETATION OF DISSOLVED AND
FREE GASES ANALYSIS
1 Scope
This International Standard is a guide describing how the concentrations of dissolved gases or
free gases may be interpreted to diagnose the condition of oil-filled electrical equipment in
service and suggest future action.
This guide is applicable to electrical equipment filled with mineral insulating oil and insulated
with cellulosic paper or pressboard-based solid insulation. Information about specific types of
equipment such as transformers (power, instrument, industrial, railways, distribution), reactors,
bushings, switchgear and oil-filled cables is given only as an indication in the application notes
(see annex A).
The Guide may be applied only with caution to other liquid-solid insulating systems.
In any case, the indications obtained should be viewed only as guidance and any resulting
action should be undertaken only with proper engineering judgment.
2 Normative references
The following normative documents contain provisions which, through reference in this text,
constitute provisions of this International Standard. At the time of publication, the editions
indicated were valid. All normative documents are subject to revision, and parties to
agreements based on this International Standard are encouraged to investigate the possibility
of applying the most recent editions of the normative documents indicated below. Members of
IEC and ISO maintain registers of currently valid International Standards.
IEC 60050(191):1990, International Electrotechnical Vocabulary (IEV) – Chapter 191: Depen-
dability and quality of service
IEC 60050(212):1990, International Electrotechnical Vocabulary (IEV) – Chapter 212: Insulating
solids, liquids and gases
IEC 60050(604):1987, International Electrotechnical Vocabulary (IEV) – Chapter 604: Generation,
transmission and distribution of electricity – Operation
IEC 60567:1992, Guide for the sampling of gases and of oil from oil-filled electrical equipment
and for the analysis of free and dissolved gases
IEC 61198:1993, Mineral insulating oils – Methods for the determination of 2-furfural and
related compounds
3 Definitions and abbreviations
3.1 Definitions
For the purpose of this International Standard, the following definitions, some of them based on
IEC 60050(191), IEC 60050(212) and IEC 60050(604) apply:
3.1.1
fault
an unplanned occurrence or defect in an item which may result in one or more failures of the
item itself or of other associated equipment [IEV 604-02-01]
NOTE – In electrical equipment, a fault may or may not result in damage to the insulation and failure of the
equipment.
60599 © IEC:1999 – 11 –
3.1.2
non-damage fault
a fault which does not involve repair or replacement action at the point of the fault
[IEV 604-02-09]
NOTE – Typical examples are self-extinguishing arcs in switching equipment or general overheating without paper
carbonization.
3.1.3
damage fault
a fault which involves repair or replacement action at the point of the fault
[IEV 604-02-08, modified]
3.1.4
incident
an event related to an internal fault which temporarily or permanently disturbs the normal
operation of an equipment [IEV 604-02-03, modified]
NOTE – Typical examples are gas alarms, equipment tripping or equipment leakage.
3.1.5
failure
the termination of the ability of an item to perform a required function [IEV 191-04-01]
NOTE – In the electrical equipment, failure will result from a damage fault or incident necessitating outage, repair
or replacement of the equipment, such as internal breakdown, rupture of tank, fire or explosion.
3.1.6
electrical fault
a partial or disruptive discharge through the insulation
3.1.7
partial discharge
a discharge which only partially bridges the insulation between conductors. It may occur inside
the insulation or adjacent to a conductor [IEV 212-01-34, modified]
NOTE 1 – Corona is a form of partial discharge that occurs in gazeous media around conductors which are remote
from solid or liquid insulation. This term is not to be used as a general term for all forms of partial discharges.
NOTE 2 – X-wax is a solid material which is formed from mineral insulating oil as a result of electrical discharges
and which consists of polymerized fragments of the molecules of the original liquid [IEV 212-07-24, modified].
Comparable products may be formed from other liquids under similar conditions.
NOTE 3 – Sparking of low energy, for example because of metals or floating potentials, is sometimes described as
partial discharge but should rather be considered as a discharge of low energy.
3.1.8
discharge (disruptive)
the passage of an arc following the breakdown of the insulation [IEV 604-03-38, modified]
NOTE 1 – Discharges are often described as arcing, breakdown or short circuits. The more specific following terms
are also used:
– sparkover (discharge through the oil);
– puncture (discharge through the solid insulation);
– flashover (discharge at the surface of the solid insulation);
– tracking (the progressive degradation of the surface of solid insulation by local discharges to form conducting or
partially conducting paths);
– sparking discharges which, in the conventions of physics, are local dielectric breakdowns of high ionization
density or small arcs.
NOTE 2 – Depending on the amount of energy contained in the discharge, it will be described as a discharge of low
or high energy, based on the extent of damage observed on the equipment (see 5.2).

60599 © IEC:1999 – 13 –
3.1.9
thermal fault
excessive temperature rise in the insulation
NOTE – Typical causes are
– insufficient cooling,
– excessive currents circulating in adjacent metal parts (as a result of bad contacts, eddy currents, stray losses or
leakage flux),
– excessive currents circulating through the insulation (as a result of high dielectric losses), leading to a thermal
runaway,
– overheating of internal winding or bushing connection lead.
3.1.10
typical values of gas concentrations
gas concentrations normally found in the equipment in service which have no symptoms of
failure, and which are overpassed by only an arbitary percentage of higher gas contents, for
example 10 % (see 8.2.1)
NOTE 1 – Typical values will differ in different types of equipment and in different networks, depending on operating
practices (load levels, climate, etc.).
NOTE 2 – Typical values, in many countries and by many users, are quoted as "normal values", but this term has
not been used here to avoid possible misinterpretations.
3.2 Abbreviations
3.2.1 Chemical names and symbols
Name Symbol
Nitrogen N
Oxygen O
Hydrogen H
Carbon monoxide CO
Carbon dioxide CO
Methane CH
Ethane C H
2 6
Ethylene C H
2 4
Acetylene C H
2 2
3.2.2 General abbreviations
DGA: Dissolved gas analysis
CIGRE: Conférence Internationale des Grands Réseaux Électriques
S: Analytical detection limit
60599 © IEC:1999 – 15 –
4 Mechanisms of gas formation
4.1 Decomposition of oil
Mineral insulating oils are made of a blend of different hydrocarbon molecules containing
CH , CH and CH chemical groups linked together by carbon-carbon molecular bonds.
3 2
Scission of some of the C-H and C-C bonds may occur as a result of electrical and thermal
faults, with the formation of small unstable fragments, in radical or ionic form, such as
• •• ••
HC,,H CH,CHorC (among many other more complex forms), which recombine rapidly,
through complex reactions, into gas molecules such as hydrogen (H-H), methane (CH -H),
ethane (CH -CH ), ethylene (CH = CH ) or acetylene (CH ≡ CH). C and C hydrocarbon
3 3 2 2 3 4
gases, as well as solid particles of carbon and hydrocarbon polymers (X-wax), are other
possible recombination products. The gases formed dissolve in oil, or accumulate as free
gases if produced rapidly in large quantities, and may be analyzed by DGA according to
IEC 60567.
Low-energy faults, such as partial discharges of the cold plasma type (corona discharges),
favour the scission of the weakest C-H bonds (338 kJ/mole) through ionization reactions and
the accumulation of hydrogen as the main recombination gas. More and more energy and/or
higher temperatures are needed for the scission of the C-C bonds and their recombination into
gases with a C-C single bond (607 kJ/mole), C=C double bond (720 kJ/mole) or C≡C triple
bond (960 kJ/mole), following processes bearing some similarities with those observed in the
petroleum oil-cracking industry.
Ethylene is thus favoured over ethane and methane above temperatures of approximately
500 °C (although still present in lower quantities below). Acetylene requires temperatures of at
least 800 °C to 1 200 °C, and a rapid quenching to lower temperatures, in order to accumulate
as a stable recombination product. Acetylene is thus formed in significant quantities mainly in
arcs, where the conductive ionized channel is at several thousands of degrees Celsius, and the
interface with the surrounding liquid oil necessarily below 400 °C (above which oil vaporizes
completely), with a layer of oil vapour/decomposition gases in between. Acetylene may still be
formed at lower temperatures (< 800 °C), but in very minor quantities. Carbon particles form at
500 °C to 800 °C and are indeed observed after arcing in oil or around very hot spots.
Oil may oxidize with the formation of small quantities of CO and CO , which can accumulate
over long periods of time into more substantial amounts.
4.2 Decomposition of cellulosic insulation
The polymeric chains of solid cellulosic insulation (paper, pressboard, wood blocks) contain a
large number of anhydroglucose rings, and weak C-O molecular bonds and glycosidic bonds
which are thermally less stable than the hydrocarbon bonds in oil, and which decompose at
lower temperatures. Significant rates of polymer chain scission occur at temperatures higher
than 105 °C, with complete decomposition and carbonization above 300 °C. Mostly carbon
monoxide and dioxide, as well as water, are formed, in much larger quantities than by oxidation
of oil at the same temperature, together with minor amounts of hydrocarbon gases and furanic
compounds. The latter can be analyzed according to IEC 61198, and used to complement DGA
interpretation and confirm whether or not cellulosic insulation is involved in a fault. CO and CO
formation increases not only with temperature but also with the oxygen content of oil and the
moisture content of paper.
60599 © IEC:1999 – 17 –
4.3 Other sources of gas
Gases may be generated in some cases not as a result of faults in the equipment but through
rusting or other chemical reactions involving steel, uncoated surfaces or protective paints.
Hydrogen may be produced by reaction of steel with water, as long as oxygen is available from
the oil nearby. Large quantities of hydrogen have thus been reported in some transformers that
had never been energized. Hydrogen may also be formed by reaction of free water with special
coatings on metal surfaces, or by catalytic reaction of some types of stainless steel with oil, in
particular oil containing dissolved oxygen at elevated temperatures. Hydrogen may also be
formed in new stainless steel, absorbed during its manufacturing process, or produced by
welding, and released slowly into the oil.
Hydrogen may also be formed by the decomposition of the thin oil film between overheated
*
core laminates at temperatures of 140 °C and above (see [1] of annex C).
Gases may also be produced by exposure of oil to sunlight or may be formed during repair of
the equipment.
Internal transformer paints, such as alkyd resins and modified polyurethanes containing fatty
acids in their formulation, may also form gases.
These occurrences, however, are very unusual, and can be detected by performing DGA
analyses on new equipment which has never been energized, and by material compatibility
tests. The presence of hydrogen with the total absence of other hydrocarbon gases, for
example, may be an indication of such a problem.
NOTE – The case of gases formed at a previous fault and remnant in the transformer is dealt with in 5.3.
5 Identification of faults
Any gas formation in service, be it minimal, results from a stress of some kind, even if it is a
very mild one, like normal temperature ageing. However, as long as gas formation is below
typical values, it should not be considered as an indication of a "fault", but rather as "typical
gas formation" (see figure 1).
5.1 Dissolved gas compositions
Although the formation of some gases is favoured, depending on the temperature reached or
the energy contained in a fault (see 4.1), in practice mixtures of gases are almost always
obtained. One reason is thermodynamic: although not favoured, secondary gases are still
formed, albeit in minor quantities. Existing thermodynamic models derived from the petroleum
industry, however, cannot predict accurately the gas compositions formed, because they
correspond to ideal gas/temperature equilibria which do not exist in actual faults. Large
temperature gradients also occur in practice, for instance as a result of oil flow or vaporization
along a hot surface. This is particularly true in the case of arcs with power follow-through,
which transfer a lot of heat to the oil vapour/decomposition gas layer between the arc and the
oil, probably explaining the increasing formation of ethylene observed in addition to acetylene.
In addition, existing thermodynamic models do not apply to paper, which turns irreversibly to
carbon above 300 °C.
__________
*
Figures in square brackets refer to the bibliography in annex C.

60599 © IEC:1999 – 19 –
5.2 Types of faults
Internal inspection of hundreds of faulty equipment has led to the following broad classes of
visually detectable faults:
– partial discharges (PD) of the cold plasma (corona) type, resulting in possible X-wax
deposition on paper insulation, or of the sparking type, inducing pinhole, carbonized
perforations (punctures) in paper, which, however, may not be easy to find;
– discharges of low energy (D1), in oil or/and paper, evidenced by larger carbonized
perforations through paper (punctures), carbonization of the paper surface (tracking) or
carbon particles in oil (as in tap changer diverter operation);
– discharges of high energy (D2), in oil or/and paper, with power follow-through, evidenced by
extensive destruction and carbonization of paper, metal fusion at the discharge extremities,
extensive carbonization in oil and, in some cases, tripping of the equipment, confirming the
large current follow-through;
– thermal faults, in oil or/and paper, below 300 °C if the paper has turned brownish (T1), and
above 300 °C if it has carbonized (T2);
– thermal faults of temperatures above 700 °C (T3) if there is strong evidence of
carbonization of the oil, metal coloration (800 °C) or metal fusion (>1 000 °C).
Table 1 – Abbreviations
PD Partial discharges
D1 Discharges of low energy
D2 Discharges of high energy
T1 Thermal fault, t < 300 °C
T2 Thermal fault, 300 °C < t < 700 °C
T3 Thermal fault, t > 700 °C
5.3 Basic gas ratios
Each of the six broad classes of faults leads to a characteristic pattern of hydrocarbon gas
composition, which can be translated into a DGA interpretation table, such as the one
recommended in table 2 and based on the use of three basic gas ratios:
CH CH CH
22 4 24
CH H CH
2 4 2 2 6
Table 2 applies to all types of equipment, with a few differences in gas ratio limits depending
on the specific type of equipment.

60599 © IEC:1999 – 21 –
Table 2 – DGA interpretation table
CH CH CH
22 4 24
Case Characteristic fault
CH H CH
2 4 2 2 6
1)
PD Partial discharges NS <0,1 <0,2
(see notes 3 and 4)
D1 Discharges of low energy >1 0,1 – 0,5 >1
D2 Discharges of high energy 0,6 – 2,5 0,1 – 1 >2
1)
T1 Thermal fault NS >1 but <1
1)
t < 300 °C NS
T2 Thermal fault <0,1 >1 1 – 4
300 °C < t < 700 °C
2)
T3 Thermal fault <0,2 >1 >4
t > 700 C
°
NOTE 1 – In some countries, the ratio C H /C H is used, rather than the
2 2 2 6
ratio CH /H . Also in some countries, slightly different ratio limits are used.
4 2
NOTE 2 – The above ratios are significant and should be calculated only if at
least one of the gases is at a concentration and a rate of gas increase above
typical values (see clause 9).
NOTE 3 – CH /H <0,2 for partial discharges in instrument transformers.
4 2
CH /H <0,07 for partial discharges in bushings.
4 2
NOTE 4 – Gas decomposition patterns similar to partial discharges have
been reported as a result of the decomposition of thin oil film between over-
heated core laminates at temperatures of 140 °C and above (see 4.3 and [1]
of annex C).
1)
NS = Non-significant whatever the value.
2)
An increasing value of the amount of C H may indicate that the hot spot
2 2
temperature is higher than 1 000 °C.
Typical examples of faults in the various types of equipment (power transformers, instrument
transformers, etc.), corresponding to the six cases of table 2, may be found in tables A.1, A.5,
A.7 and A.11.
Some overlap between faults D1 and D2 is apparent in table 2, meaning that a dual attribution
of D1 or D2 must be given in some cases of DGA results. The distinction between D1 and D2
has been kept, however, as the amount of energy in the discharge may significantly increase
the potential damage to the equipment and necessitate different preventive measures.
NOTE – Combinations of gas ratios which fall outside the range limits of table 2 and do not correspond to a
characteristic fault of this table may be considered a mixture of faults, or new faults which combine with a high
background gas level (see 6.1).
In such a case, table 2 cannot provide a diagnosis, but the graphical representations given in annex B may be used
to visualize which characteristic fault of table 2 is closest to the case.
The less detailed scheme of table 3 may also be used in such a case in order to get at least a rough distinction
between partial discharges (PD), discharges (D) and thermal fault (T), rather than no diagnosis at all.

60599 © IEC:1999 – 23 –
Table 3 – Simplified scheme of interpretation
CH CH CH
22 4 24
Case
CH H CH
2 4 2 2 6
PD <0,2
D>0,2
T<0,2
5.4 CO /CO ratio
The formation of CO and CO from oil-impregnated paper insulation increases rapidly with
temperature. Incremental (corrected) CO /CO ratios less than 3 are generally considered as an
indication of probable paper involvement in a fault, with some degree of carbonization.
In order to get reliable CO /CO ratios in the equipment, CO and CO values should be
2 2
corrected (incremented) first for possible CO absorption from atmospheric air, and for the
CO and CO background values (see 6.1 and clause 9), resulting from the ageing of cellulosic
insulation, overheating of wooden blocks and the long term oxidation of oil (which will be
strongly influenced by the availability of oxygen caused by specific equipment construction
details and its way of operation).
Air-breathing equipment, for example, saturated with approximately 10 % of dissolved air, may
contain up to 300 μl/l of CO coming from the air. In sealed equipment, air is normally excluded
but may enter through leaks, and CO concentration will be in proportion of air present.
When excessive paper degradation is suspected (CO /CO < 3), it is advisable to ask for a
furanic compounds analysis or a measurement of the degree of polymerization of paper
samples, when this is possible.
5.5 O /N ratio
2 2
Dissolved O and N may be found in oil, as a result of contact with atmospheric air in the
2 2
conservator of air-breathing equipment, or through leaks in sealed equipment. At equilibrium,
taking into account the relative solubilities of O and N , the O /N ratio in oil reflects air
2 2 2 2
composition and is close to 0,5.
In service, this ratio may decrease as a result of oil oxidation and/or paper ageing, if O is
consumed more rapidly than it is replaced by diffusion. Factors such as the load and
preservation system used may also affect the ratio, but ratios less than 0,3 are generally
considered to indicate excessive consumption of oxygen.
5.6 C H /H ratio
2 2 2
In power transformers, on load tap changer (OLTC) operations produce gases corresponding
to discharges of low energy (D1). If some oil or gas communication is possible between the
OLTC compartment and the main tank, or between the respective conservators, these gases
may contaminate the oil in the main tank and lead to wrong diagnoses. The pattern of gas
decomposition in the OLTC, however, is quite specific and different from that of regular D1s in
the main tank.
60599 © IEC:1999 – 25 –
C H /H ratios higher than 2 to 3 in the main tank are thus considered as an indication of
2 2 2
OLTC contamination. This can be confirmed by comparing DGA results in the main tank, in the
OLTC and in the conservators. The values of the gas ratio and of the acetylene concentration
depend on the number of OLTC operations and on the way the contamination has occurred
(through the oil or the gas).
NOTE – If contamination by gases coming from the OLTC is suspected, interpretation of DGA results in the main
tank should be done with caution by substracting background contamination from the OLTC, or should be avoided
as unreliable.
5.7 C hydrocarbons
The interpretation method of gas analysis indicated above takes into account only C and C
1 2
hydrocarbons. Some practical interpretation methods also use the concentrations of C
hydrocarbons, and their authors believe that they are liable to bring complementary information
which is useful to make the diagnosis more precise. Because the C hydrocarbons are very
soluble in oil, their concentrations are practically not affected by a possible diffusion into
ambient air. Conversely, and because they are very soluble, they are difficult to extract from
the oil and the result of the analysis may greatly depend on the extraction method used.
Moreover, experience has shown that, in most cases, a satisfactory diagnosis can be made
without taking into account these hydrocarbons and for the sake of simplification, they have
been omitted from the interpretation method indicated above.
5.8 Evolution of faults
Faults often start as incipient faults of low energy, which may develop into more serious ones
of higher energies, leading to possible gas alarms, breakdowns and failures.
When a fault is detected at an early stage of development, it may be quite informative to
examine not only the increase in gas concentrations, but also the possible evolution with time
toward a more dangerous high-energy fault of the final stage type.
For example, some current transformers have operated satisfactorily for long periods of time
with very high levels of hydrogen produced by partial discharges. However, partial discharges
may also cause the formation of X-wax. When the X-wax is present in sufficient quantity to
increase the dissipation losses in the paper-oil insulation, a thermal fault may occur, eventually
leading to catastrophic thermal runaway and breakdown.
In other occurrences, however, instant final breakdown may occur without warning.
5.9 Graphical representations
Graphical representations of gas ratios are convenient to follow this evolution of faults visually.
Annex B gives examples of graphical representation of faults.
These representations are also useful in cases which do not receive a diagnosis using table 2,
because they fall outside the gas ratios limits. Using figures B.1 or B.2, the zone or box which
is closest to such an undiagnosed case can be easily visualized and attributed with caution to
this case. Figure B.3 is particularly useful since it always provide a diagnosis in such cases.

60599 © IEC:1999 – 27 –
6 Conditions for calculating ratios
6.1 Examination of DGA values
DGA sampling and analysis should be done in accordance with the recommendations of
IEC 60567.
a) Values of 0 μl/l on a DGA report or below the analytical detection limits S shall be replaced
by "below the S value for this gas" (see IEC 60567 for recommended S values)
b) If successive DGA analyses have been performed over a relatively short period of time
(days or weeks), inconsistent variations (e.g. brutal decreases of concentrations) may have
to be eliminated as an indication of a sampling or analytical problem.
c) Gas ratios are significant and should be calculated only if at least one gas concentration
value is above typical value and above typical rate of gas increase (see note 2 of table 2
and clause 9).
d) If gas ratios are different from those for the previous analysis, a new fault may superimpose
itself on an old one or normal ageing. In order to get only the gas ratios corresponding to
the new fault, subtract the previous DGA values from the last ones and recalculate ratios.
This is particularly true in the case of CO and CO (see 5.4). Be sure to compare DGA
values of samples taken at the same place and preferably in moving oil. Interpretation
should also take into account treatments previously made on the equipment, such as repair,
oil degassing or filtering, which may affect the level of gases in the oil.
NOTE – In the case of air-breathing power transformers, losses occur very slowly with time by diffusion through the
conservator or as a result of oil expansion/temperature cycles, with the result that the measured gas levels may be
slightly less than the gas levels actually formed in the transformer. However, there is no agreement concerning the
magnitude of this diffusion loss in service, some considering it as totally negligible, others as potentially significant,
depending on the type of equipment used. In case of doubt, it may be expedient to measure the gas concentration
in the conservator to get an idea of the volume ventilated. Significant diffusion losses may affect gas ratios, typical
values of gas concentrations and of rates of gas increase.
6.2 Uncertainty on gas ratios
Because of the precision on DGA values, there is also an uncertainty on gas ratios, which can
be calculated using the precision on DGA values described in IEC 60567.
Above 10 × S (S being the analytical detection limit), the precision is typically 5 % on DGA
values and up to 10 % on a gas ratio. Below 10 × S, the precision on DGA values decreases
rapidly, to typically 20 % at 5 × S and up to 40 % on a gas ratio.
Caution should therefore be exercised when calculating gas ratios at low gas levels (lower
than 10 × S), keeping in mind the possible variations resulting from the reduced precision. This
is particularly true for instrument transformers and bushings, where typical values of gas
concentration may be below 10 × S.

60599 © IEC:1999 – 29 –
7 Application to free gases in gas relays
During a fault, the production rate of gases of all types is closely linked to the rate of energy
liberation. Thus, the low rate of energy liberation in partial discharges, or in a low-temperature
hot spot, will cause gases to evolve slowly and there is every probability that all the gas
produced will dissolve in the oil. The higher rate of energy liberation of a high-temperature core
fault, for example, can cause an evolution of gas rapid enough to result in gas bubbles. These
will usually partially dissolve in the oil (and exchange with gases already dissolved) but some
gas may well reach the gas collecting relay or gas cushion; this gas may approach equilibrium
with the gases dissolved in the oil.
A very high rate of energy liberation associated with a power arcing fault causes a rapid and
substantial evolution of gas (the resulting pressure surge normally operates the surge element
of the gas collecting relay). The large gas bubbles rise quickly to the relay and exchange little
gas with the oil so that the gas that collects in the relay is initially far from being in equilibrium
with the gases dissolved in the oil. However, if this gas is left for a long time in the relay, some
constituents will dissolve, modifying the composition of the gas collected. Acetylene, which is
produced in significant quantities by an arcing fault and which is very soluble, is a noteworthy
example of a gas which may dissolve comparatively quickly to produce misleading results.
In principle, the analysis of free gases from a gas collecting relay or from a gas cushion may
be evaluated in the same way as the analysis of gases dissolved in the oil. However, where the
surge element has operated and gas has accumulated in substantial quantities, there is a
possibility of having a serious fault, and analyses of the gases should be undertaken to identify
the fault. Buchholz alarms due to air accumulation are also possible following a combination of
warm days and sudden temperature drops at night.
It is therefore important to collect the gas at the relay as soon as possible without burning it,
and sample the oil in the relay and in the main tank.
Where gas has accumulated slowly, assessment of the gases dissolved in the oil is more
informative than that of the free gases; this gas-in-oil analysis is also essential in order to
determine the total rate of evolution of gases and thus check whether the fault is growing,
which is the most important matter to investigate. When analysis of free gases is undertaken, it
is necessary to convert the concentrations of the various gases in the free state into equivalent
concentrations in the dissolved state, using table 4, before applying the gas ratio method of
table 2, and to compare them to the dissolved gas concentrations in the oil of the relay and the
main tank.
Applying the principles set out above, comparison of the actual concentrations in the oil with
the equivalent concentrations in the free gas may give valuable information on how far gas
bubbles may have risen through the oil and, hence, on the rate of gas evolution.
The calculation of dissolved gas concentrations equivalent to free gas concentrations is made
by applying the Ostwald coefficient for each gas separately. For a particular gas, the Ostwald
coefficient k is defined as follows:
concentration of gas in liquid phase
k =
concentration of gas in gas phase
with concentrations in microlitres per litre.

60599 © IEC:1999 – 31 –
The Ostwald coefficients for various gases in mineral insulating oils at 20 °C and 50 °C are
given in table 4.
Table 4 – Ostwald coefficients for various gases in
mineral insulating oils
Gas k at 20 °C k at 50 °C
N 0,09 0,09
O 0,17 0,17
H 0,05 0,05
CO 0,12 0,12
CO 1,08 1,00
CH 0,43 0,40
C H 2,40 1,80
2 6
C H 1,70 1,40
2 4
C H 1,20 0,9
2 2
NOTE – Data given in this table represent mean values obtained on some of the
current types of transformer mineral insulating oils. Actual data may differ a little
from these figures. Nevertheless, data given above may be used without influencing
conclusions drawn from recalculated test results.
The Ostwald coefficient is independent of the actual partial pressures of the gas concerned.
The gas and liquid phases are assumed to be at the same temperature; this is rarely the case
but the error introduced by any difference will not invalidate the conclusions reached.
8 Gas concentration levels in service
8.1 Probability of failure in service
8.1.1 General
The probability or risk of having an incident or a failure in service is related to gas
concentration levels.
Below certain concentration levels (quoted as typical values or normal values), the probability
of having a failure is low. The equipment is considered healthy, although a failure cannot be
totally ruled out, even at these low levels, but it is improbable. A first rough screening between
healthy and suspect analyses can therefore be obtained by calculating typical values for the
equipment.
The probability of having a failure may increase significantly at values much above typical
concentration levels. The situation is then considered critical, for even though a failure may
never occur at these high levels, the risk of having one is high. Such failures may be divided
into two categories:
– failures that develop within a very short time (which are therefore impossible to detect by oil
sampling/laboratory analysis, but only by on-line detectors);
– failures developing over an extended time span. Only this second category may be detected
by DGA laboratory analysis.
60599 © IEC:1999 – 33 –
8.1.2 Calculation methods
Utilities with large DGA and equipment maintenance databases are able to calculate the
probability of failure in service for a given type of equipment and at a given concentration level
of a gas. This can be obtained by calculating the number of DGA analyses which have led to an
actual failure or incident in service (gas alarm, failure, repair, outage, etc.), and comparing it to
the total number of DGA analyses on this type of equipment and at this gas concentration level.
A large number of analyses is necessary to get reliable values of failure probability. Knowledge
of these values, however, is useful when choosing the normality percentage most appropriate
for a given network and type of equipment (see 8.2.3).
8.2 Typical concentration values
8.2.1 General
Typical concentration values are the acceptable gas quantities below which field experience
shows no detectable or possible incipient fault, and which are overpassed by only an arbitrarily
low percentage of higher gas contents, for example 10 %. Typical concentration values will be
referred to in such an example as the 90 % typical values.
However, typical concentration values are preferably to be considered as initial guidelines for
decision making, when no other experience is available. They shall not be used to ascertain
whether or not a fault exists within an equipment. They should be viewed as values above
which the rate of gas formation may permit the detection of a probable fault.
Typical concentration values are affected by a number of factors, chiefly the operating time
since commissioning, the type of equipment and the nature of the fault (electrical or thermal).
For power transformers, the type of oil protection, load factor and operation mode are other
influencing factors.
Typical concentration values may be calculated as follows and should be obtained by the
equipment users on the specific types of equipment.
8.2.2 Calculation methods
The simplest method of calculation consists in gathering all the DGA results concerning a
specific type of equipment. For each characteristic gas considered, the cumulative number of
DGA analyses where the gas concentration is below a given value is calculated, then plotted
as a function of gas concentration. Using the plotted curve, the gas concentration corre-
sponding to a given percentage of the total cumulative number of analyses (for instance 90 %)
is the 90 % typical concentration value for that gas and type of equipment.
8.2.3 Choice of normality percentages
If the normality percentage chosen (e.g. 90 %, 95 % or other) is too low, suspicion will be
placed on too many pieces of equipment, with a loss of credibility in the diagnosis and
recommendations, and an increase in maintenance costs. If the normality percentage is chosen
too high, failure may occur without advance warning, also involving considerable costs.

60599 © IEC:1999 – 35 –
The choice of a normality percentage is often an educated guess, left to the experience of the
user of similar equipment. A certain amount of leeway in the choice of a normality percentage
is also provided by considering the probability of failure and the actual failure rate of the
equipment in service. In the absence of such information or experience, users may choose
conservative normality percentages such as 90 % as a rough screening value. If adequate
databases are not av
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