copper sulphide long term mitigation and...

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COPPER SULPHIDE LONG TERMMITIGATION AND RISK ASSESSMENT

Working GroupA2.40

July 2015

COPPER SULPHIDE LONG TERM

MITIGATION AND RISK ASSESSMENT

WG A2.40

Members

J.Lukic, convenor&TF 01 leader (RS), G.Wilson, TF 02 Leader (UK), F.Scatiggio, TF03 Leader (IT), M.Dahlund,

(SE), R.Maina (IT), J.Rasco (USA), L.E.F. de Lemos (BR), A.Peixoto (PT), T.Buchacz (PL), C.Perrier (FR),

I.A.Höhlein (DE), A.Skholnik (IL), P.Wiklund (SE), B.Nemeth (HU), H.Ding (UK), A.Lombard, (ZA),

Y.Bertrand (FR), J.Van Peteghem (BE), P.Smith (DE), S.Dorieux (FR), M.Facciotti (UK).

Corresponding members

G.Krikke (NL), M.Grisaru (IL), L.Lewand (USA).

Former members

L.Eiselstein (USA), S.Laboncz, (HU), J.Tanimura (JP), A.Yamada (JP), J.Yare (UK), T.Amimoto (JP),

T.C.S.M Gupta, former TF 01 leader (IN), W.Mc Dermid, (CA).

Contributors

H.F.A.Verhaart (NL), A.Petersen (AUS), C.N.Fares (UY), M.A.Martins (PT).

Copyright © 2015

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ISBN: 978-2-85873-328-6

Copper Sulphide Long Term Mitigation And Risk Assessment

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COPPER SULPHIDE LONG TERM MITIGATION AND RISK

ASSESSMENT

Table of Contents

1. INTRODUCTION ............................................................................................................3

2. COPPER SULPHIDE FORMATION MECHANISM.............................................................4

2.1 Introduction..................................................................................................................................... 4

2.2 Influential factors .......................................................................................................................... 6

2.2.1 Temperature.......................................................................................................................... 6

2.2.2 Oxygen content in the oil and oil oxidation process .................................................... 6

2.2.3 Base Oil Composition and Inhibitors................................................................................. 8

2.2.4 Reactivity of sulphur compounds .....................................................................................11

2.3 Copper Dissolution in the Oil and Deposition in the Paper................................................12

2.4 Proposed Reaction Pathways: DBDS degradation products..............................................15

3 RISK ASSESSMENT ..................................................................................................... 18

3.1 Service Experiences and Survey Results ................................................................................18

3.1.1 Failure Cases.......................................................................................................................19

3.1.2 Inspections and transformer scrapping information ....................................................28

3.1.3 Alternative Sources of Reactive Sulphur........................................................................31

3.2 Risk factors...................................................................................................................................37

3.3 Diagnostic Methods ....................................................................................................................40

3.3.1 Oil Tests: detection and quantification of reactive sulphur compounds...................40

3.3.2 Other Test Methods for Copper Sulphide Detection and Quantification ...............43

4 COPPER SULPHIDE LONG TERM MITIGATION........................................................... 48

4.1 Mitigation Techniques ................................................................................................................48

4.1.1 Mitigation Survey...............................................................................................................48

4.1.2 Metal Passivators ...............................................................................................................50

4.1.3 Metal passivator efficiency..............................................................................................50

4.1.4 Side effects (passivator consumption, stray gassing, etc.) .........................................59

4.2 Oil change: Efficiency and Side Effects .................................................................................71

4.3 Removal of corrosive sulphur from oil in service...................................................................72

4.3.1 Oil Reclamation ..................................................................................................................72

4.3.2 Chemical treatment of the Oil .........................................................................................74

4.3.3 Side Effects..........................................................................................................................75

4.3.4 Cost Effective Risk Mitigation Strategies.......................................................................79

4.4 Recommendations for Mitigation .............................................................................................81


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5 MONITORING AND MAINTENANCE PROCEDURES................................................... 83

6 CONCLUSIONS........................................................................................................... 84

7 REFERENCES............................................................................................................... 86

APPENDIX 1: COPPER SULPHIDE FORMATION IN THE PAPER......................................... 90

APPENDIX 2: FAILURE CASES SUMMARY......................................................................... 92


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1. INTRODUCTION

WG A2.40 was set up in May 2009 as continuation of the work of A2.32.: "Copper Sulphide in Transformer Insulation" (TB 378) based on the main topics highlighted in the conclusions and proposed activities for the future work.

The scope of A2.40 as defined in the terms of reference was to improve understanding of the mechanism of copper sulphide formation and mapping of influential factors in order to provide more precise risk assessment. It was also required that long-term effects of mitigation techniques, like addition of metal passivators and oil treatment processes, should be examined and an evaluation of their efficiency and any side effects be investigated.

This report reviews the current best understanding of the mechanism of copper sulphide formation, details of service experiences, failures related to copper sulphide and results of mitigation techniques.


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2. COPPER SULPHIDE FORMATION MECHANISM

2.1 Introduction

Failures of transformers induced by the presence of corrosive sulphur compounds in the oil are related to the formation of copper and silver sulphide on metal surfaces and copper sulphide deposits in the insulating paper in the windings. Copper sulphide formation in the paper insulation drew major attention in CIGRE, due to the high risk of failure involved with copper sulphide deposition on the paper [1]. Metallic sulphide formation on the surface of copper and silver, i.e. build up of metallic sulphide layer, followed by overheating of contacts and detachment of conductive particles from the metal surfaces can cause breakdown at power frequency and rated voltage stress. The mechanism of copper sulphide formation on bare metal surfaces by direct reaction of bare metal with reactive sulphur compounds is well known and elaborated in the literature [2], [3].

Investigation of the mechanism of copper sulphide formation in the paper was one of the tasks of WG A2.40. A postulated mechanistic model, based on copper-in-oil dissolution, followed by diffusion and absorption of intermediate copper complexes in the paper, where copper sulphide is formed in reaction with sulphur compounds, is described. This is currently the most comprehensive mechanistic model, which is based on copper sulphide growth in the paper insulation, after absorption of oil dissolved copper and sulphur compounds in the paper [1], [4].

A contact based corrosion mechanism was also proposed, postulated on transport of copper sulphide particles to the first paper layer through interstitial oil. Oxygen was observed to interfere with surface interaction between the copper sulphide and copper causing its displacement, although the mechanism is still unknown [5].

Copper sulphide formation on the copper plate and in the paper often go together as parallel processes, but not necessarily, as shown in Figures 1 and 2 below. Uninhibited oils frequently deposit copper sulphide only on the copper plate, while inhibited oils were frequently observed to deposit copper sulphide in the paper. The dominant process, i.e. deposits on the copper or deposits in the paper, is dependent on temperature, base oil composition/degree of refining, oxygen content and presence of inhibitors in the oil. Post-mortem investigation experiences have supported all of these scenarios of possible copper sulphide deposition pattern. Pictures of conductors from failed converter transformers presented in Figure 1 clearly show how copper sulphide formation in the paper can occur without deposition on copper conductors, confirming the postulated mechanistic scenario which involves copper in dissolution and copper sulphide formation in the paper.

Figure 1 Paper from conductor of failed converter transformer

Frequently, in service, copper sulphide deposition on the copper and in the paper, with copper sulphide deposits decreasing in the paper from inner to outer layers were observed, as shown at Figure 2.


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Figure 2 Conductor from failed converter transformer: left – inner side (next to copper), right –

outer side towards to subsequent paper layers

An important initiating step in the reaction of copper sulphide formation is production of electrons and ions. Electrical and magnetic fields may play an important role in this respect, to promote copper sulphide formation . A further step is copper-in-oil dissolution; oils in service do not usually contain significant amounts of dissolved copper. Copper has a high affinity to absorb in the paper, while it is dissolved only in low concentrations in oil, typically in the range of a few hundred to a few thousand ppb [4], [6]. This depends on oil chemistry, i.e. oil capacity to dissolve copper.

Reactive sulphur compounds have an affinity to be absorbed in the paper and are transported to the paper through the oil. The available surface of bare copper conductor is also very important for the reaction, in terms of copper ion formation and dissolution of copper ions in the oil. Copper sulphide coating on the metal surface suppresses copper-in-oil dissolution.

The dielectric failure mechanism was explained in detail in TB 378. Results of recent laboratory experiments with pigtail samples (four-layer paper-wrapped copper conductors) and oil containing reactive sulphur compounds, showed that significant increase of capacitance, decrease of resistance and partial discharge inception voltage (PDIV) may be observed during simultaneous thermal and electrical stress at 120°C and 1200 V ac (rms), over 90 and 180 days. This was attributed to copper sulphide contamination detected from the HV electrode, i.e. copper conductors, through inner to outer paper layers [7]. An empirical relation for prediction of PDIV was suggested. It was shown that under dc and ac stress, the voltage curve is non linear and dependent on copper sulphide layer thickness. For this reason, electric field distribution would be complex and dependent on the phase in which copper sulphide is present. These experiments have shown the pattern of electrical properties of paper insulation contaminated with copper sulphide.

Transformers which have failed in last two decades where corrosive sulphur was at least partly responsible were filled with insulating mineral oils which contained dibenzyl disulphide (DBDS) in the very large majority of the cases. It was discovered that DBDS was present at a significant concentration, notably higher than any other sulphur organic compounds.

Dibenzyl disulphide (DBDS) is a commodity chemical used as a flavoring agent in food, but also as a powerful extreme-pressure additive in gear lubricants and metal working fluids. The initial concepts of using sulphur antioxidants to inhibit oil oxidation date back to the 1800s. Sulphur-containing organic compounds, including DBDS, were largely used in lubricant products; however the major drawback to this approach is the high


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corrosiveness of sulphurized oil toward copper [8]. DBDS can be present in crude oil but due its relatively low thermal stability it can be easily removed by normal refining techniques.

A worldwide investigation carried out in 2005 - 2006 demonstrated that DBDS was practically absent in all the “old style” oils (based on furfural refining), instead many “new style” oils (based on hydro-refining) produced after the 90s contain DBDS in the range 100 – 200 ppm. Afterwards some oil companies reformulated the oil composition and today all the unused oils present on market are DBDS free.

Numerous laboratory studies and service experiences showed that a broad range of temperatures and oxygen concentrations may promote formation of copper sulphide, which may be formed from different reactive sulphur compounds, not only DBDS (see Chapter 2.2.4 and Table 1). Reactivity of these compounds varies with temperature and presence of other oil constituents, i.e. base oil composition and additives.

2.2 Influential factors

2.2.1 Temperature

The influence of temperature was discussed in detail in Technical Brochure 378. Increase of temperature speeds up the reaction of copper sulphide formation; the rate of reaction approximately doubles with every 10°C increase [1]. Most of the available data are related to the DBDS degradation rate, as the model compound, as it is highly reactive and, as stated above, the most commonly found sulphur-containing compound in corrosive oils. For a range of oxygen contents dissolved in the oil, from a few hundred to a few thousand ppm, the reaction kinetics follows Arrhenius’ Law for temperature ranges from 80-100°C up to 200°C. A first order reaction was suggested for temperatures up to 150°C with estimated activation energy of 123 KJ/mol [9]. However, kinetics of DBDS depletion is more complex than a first order of reaction, as DBDS depletion rate falls off less rapidly than expected from “true first order” kinetics [9]. This can be explained by reactions which include DBDS regeneration (by recombination of radicals and thiol/disulphide interchange - see Appendix 1). Owing to the presence of other potential reactive sulphur species besides DBDS, formation of copper sulphide can occur across a broad temperature range, at reaction temperatures from 80°C to above 300°C.

2.2.2 Oxygen content in the oil and oil oxidation process

Studies on the impact of oxygen on copper sulphide formation have drawn much attention within expert groups. The importance of oxygen as an influential factor in the mechanism of copper sulphide formation was recognized from the beginning of the problem and key points were well established in TB 378. This WG attempted to analyze the impact of oxygen in more detail, especially in the light of recent service experiences, with free-breathing units having failed due to copper sulphide in more significant numbers, including inspections of units without failure, where significant amount of copper sulphide deposits were found. The influence of dissolved oxygen in the oil was extensively studied in previous WG A2.32. It was found that the optimum range of oxygen concentration dissolved in the oil needed for the reaction where copper sulphide deposition occurs in paper was around a few thousand ppm.

Oxidation reactions are followed by formation of oxygenated sulphur species, copper oxides, peroxides, copper hydro-peroxides, carbonyl and acidic compounds. Each of these compounds can be involved in copper sulphide formation as intermediate compounds.

Deposits of copper sulphide on copper conductor were observed to be more readily displaced from the copper surface in the presence of oxygen [5].

Laboratory investigations showed that with increase of oxygen concentration in the gas phase above the oil from 2.5% to 20%, copper sulphide deposition on the paper increases, especially in inhibited oils. Also high concentrations of oxygen dissolved in the oil, up to 4% or 5% were observed to promote the reaction on bare copper [10].

Another laboratory investigation gave more insight into how oxygen changes the mechanism of DBDS degradation (explanatory chemical reactions are given in Annex 1) [11]. Experiments were performed at 120°C and 150°C in conditions of low and high oxygen in the oil (corresponding to sealed and free-breathing units). At 120°C, formation


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of copper sulphide was dominant in low oxygen conditions, while in conditions of high oxygen content it was minor, for the same test duration. In contrast, at 150°C copper sulphide was formed in significant quantities at both oxygen concentrations, with major copper sulphide deposition on the paper in conditions of high oxygen content (Figure 3). The explanation for this is a dual degradation mechanism of DBDS: oxidation of sulphur atoms and cleavage of carbon-sulphur bonds. Oxidation of sulphur atoms, i.e. DBDS antioxidant action, is dominant at lower temperatures in high oxygen environment and yields oxides of sulphur, sulphur oxy-acids and other oxygenated derivates as dominant products. The second DBDS degradation route yields mercaptans which are responsible for copper sulphide formation (see Annex 1). This degradation pathway is dominant in conditions of lower oxygen content (0.1-1%), but also prevailing at higher temperatures (close to, and at 150ºC), regardless of oxygen content. At these temperatures there is enough energy for cleavage of C-S bonds and DBDS degradation dominantly yields copper sulphide. Moreover, high oxygen content in the oil promotes copper sulphide deposition on the paper (Figure 3).

Figure 3 Influence of oxygen and temperature on copper sulphide deposition pattern, on the

copper or on the paper with uninhibited oil

In summary, the yield of copper sulphide formed at normal operating temperatures in a high oxygen environment is lower than in conditions of low oxygen content in the oil, while at high operating temperatures (overload conditions, overheating), copper sulphide deposition on the paper will be more dominant in a high oxygen environment.

During oil oxidation, corrosiveness in some oils may develop. This was observed mainly in uninhibited oils without DBDS. Some oxidized sulphur compounds may have an increased propensity for copper sulphide formation in comparison to their non-oxidized derivates [12]. Increased reactivity of carbonyl compounds containing sulphur atoms and sulphoxides which are produced during oxidation of sulphides and disulphides was confirmed in some oils in laboratory experiments. In practice, development of corrosiveness during service can be expected to occur in free breathing units filled with less refined oils with higher sulphur content (usually uninhibited oils).

Uninhibited

oil

Restricted oxygen(01.-1%) - IEC

62535 set up

Breathing conditions (1-2.5%)-

modified IEC 62535 set up

120°C,

20 days

150°C,

3 days


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2.2.3 Base Oil Composition and Inhibitors

Deposition of copper sulphide in the paper, or on the copper, is dependent on base oil composition and chemical composition of sulphur compounds. Differences between the copper sulphide deposition pattern of uninhibited and inhibited oils, as apparent from different responses to the IEC 62535 test, have frequently been observed [11], [13].

Different base oils of the same type may have significantly different detailed chemical structure, owing to differences in the crude oils from which they originate and the refining processes. This may lead to different copper sulphide deposition patterns among different base oils of the same type, mainly dependent on capacity of oil to dissolve copper.

The reactivity of DBDS in different base oils was studied in particular and results of several studies reveal that naphthenic oils in general have a slightly higher propensity for copper sulphide deposition on the paper [11], [14] (Figure 4). However, these experiments showed that it is not possible to draw any firm conclusions on the difference between base oils solely relying on carbon type composition.

0

2000

4000

6000

8000

10000

12000

14000

16000

Copper content in the paper, ppm

120°C - 3

days

120°C - 7

days

150°C - 3

days

150°C - 7

days

120⁰⁰⁰⁰C/150⁰⁰⁰⁰C non-breathing naphtenic oil A,

uninhbited

naphtenic oil A,

uninhibited with added

DBPCnaphtenic oil B, inhibited

paraffinic oil , inhibited

0

5000

10000

15000

20000

25000

30000

35000

40000

Copper content in the paper,

ppm

120°C - 3

days

120°C - 7

days

150°C - 3

days

150°C - 7

days

120⁰⁰⁰⁰C/150⁰⁰⁰⁰C breathing

naphtenic oil A,

uninhbited

naphtenic oil A,

uninhibited with added

DBPCnaphtenic oil B,

inhibited

paraffinic oil , inhibited

Figure 4 Copper content in the paper (IEC 62535 test set up – restricted-non-breathing/modified

for oxygen ingress – breathing)


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Aromatic sulphur compounds were found to be the most reactive class of sulphur compounds for copper sulphide formation. Different classes of aromatic compounds can make oil soluble complexes with copper which have an affinity to absorb in the paper [15]. Specific aromatic compounds, including inhibitors (2,6-ditert-butyl-p-cresol - DBPC and 2,6-ditert- butylphenol - DBPh), can make bonds with copper ions (phenoxy anions bonding to copper cations). This way they act as copper carrying intermediates, enabling copper in oil dissolution and absorption in the paper, followed by reaction with sulphur compounds in the paper. Several studies have shown that phenolic compounds, such as the inhibitor DBPC and DBPh added to uninhibited oils influenced significant copper sulphide deposition on the paper (Figure 5). The effect was even more pronounced in a high oxygen environment (Figure 6) [14], [16].

Figure 5 Results of IEC 62535 test of uninhibited oils designated as “D” and “MO” without and

with added 0.3% inhibitors DBPC and DBPh

Uninhibited corrosive oils with 0.3% added DBPC, DBPh and

variable oxygen content

0

5000

10000

15000

20000

25000

30000

35000

40000

D D + O2 MO MO + O2Oils

Copper content in the

paper, mg/kg

initial Oil

DBF

DBPC

Figure 6 Increase of copper content in the paper, after IEC 62535 test of uninhibited oils,

designated as “D” and “MO” with modified oxygen ingress, non-breathing/breathing-right [15].

Although the addition of DBPC facilitated an increase of copper absorption in the paper and deposition of copper sulphide on the paper, the actual rate of DBDS conversion and yield of copper sulphide formed was not increased by addition of DBPC, with high oxygen content a slight decrease was actually observed (Figure 7). This can be attributed to lower rate of DBDS consumption as secondary antioxidant in the presence of DBPC as primary antioxidant.

Addition of DBPC to uninhibited oils does not confer reduced corrosion potential as there is a lower compatibility of the antioxidant with the uninhibited oil, resulting from lower degree of base oil refining. In such a matrix additional DBPC may act as a copper-carrying intermediate and promote copper sulphide transport to the paper.


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0

50

100

150

200

250

300

0 h 72h 120h 168h

test duration, h

DBDS concentration, ppm

D + Oxy

D+DBPC+ Oxy

H+ Oxy

LO + Oxy

0

50

100

150

200

250

300

0 h 72h 120h 168h

test duration, h

DBDS concentration , ppm

(Oil D), ppm

(Oil D+DBPC), ppm

(oil H), ppm

(Oil LO-paraff.), ppm

Figure 7 DBDS consumption at 150°C in breathing conditions-left and sealed conditions-right

However, it cannot necessarily be concluded that originally-inhibited corrosive oils are of higher risk for service than uninhibited oils. Typically there are lower concentrations of potentially reactive sulphur compounds present in inhibited oils, and inhibited oils are more refined than uninhibited ones, therefore they have lower total sulphur content.

Different copper sulphide deposition patterns were frequently observed in practice during transformer post-mortem inspections. Conductors from failed converter transformers filled with oils labelled “A” and “B” are shown in figure 8. Copper sulphide deposition on the paper in oil A was pronounced on inner and outer paper layers, while copper was clear of deposits. The fifth layer was observed to have a particularly high amount of copper sulphide. On the other hand, oil B deposited high amounts of copper sulphide on the copper and first paper layer, both on inner and outer side, while lower amount of deposits were observed in the outer paper layers. Oil A apparently had higher copper-in-oil dissolution capacity than oil B, and was able to deposit copper sulphide away from the copper at the outmost layers of paper, leaving the copper clear of deposits.

Figure 8 Copper conductors, inner and outer paper layers from failed transformers, with oils

giving different copper sulphide deposition pattern, left – oil A and right- oil B.


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2.2.4 Reactivity of sulphur compounds

Ranking of reactive sulphur compounds for copper sulphide formation was performed on the basis of laboratory studies with different base oils (naphthenic, hydro-treated inhibited “high grade”, hydro-cracked inhibited and uninhibited) and white oil (aromatic free, containing only paraffinic and naphthenic hydrocarbons) fortified with different sulphur compounds that were exposed to the IEC 62535 test (Table 1).

Table 1 Reactivity of different classes of sulphur compounds to paper wrapped copper in the

temperature range from 80°C to 180°C

IEC 62535 test in white oil 80°C 100°C 120°C 150°C 180°C

Elemental Sulphur* +

Mercaptans (thiols) - - - + +

Monosulphides - - - + +

Disulphides + + + + +

Oxidized sulphur compounds:

sulphoxides/sulphones

- - - + +

Oxidized hydrocarbons - carbonyl

compounds containing sulphur

+

Thiophenes +/-

* elemental sulphur is highly reactive to silver; silver sulphide can be formed at temperatures below 80°C.

Benzyl mercaptan is prone to form copper sulphide at substantially lower temperatures on bare copper, from 100°C onwards. The onset reaction temperature for disulphides (including DBDS) is from 80°C onward.

Results of another study showed that mono-sulphides, sulphoxides and sulphones and their oxidized derivates have a propensity to form copper sulphide formation on copper plate, as confirmed by ASTM D 1275 B [12].

Reactivity of corrosive sulphur compounds for copper sulphide deposition on the paper according to IEC 62535 is as follows:

ELEMENTAL SULPHUR > DISULPHIDES > MERCAPTANS AND OXIDIZED SULPHUR COMPOUNDS >

MONOSULPHIDES AND TIOPHENES


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2.3 Copper Dissolution in the Oil and Deposition in the Paper

The propensity of different oils for copper dissolution and absorption in the paper is influenced by base oil composition. Aromatic compounds play an important role, as do oil additives (inhibitors, metal passivators and metal deactivators).

A postulated mechanism for copper sulphide formation involves formation of oil-soluble copper compounds containing oxygen, as intermediate compounds in copper sulphide formation [1], [4], [5], [15], [17], [18]. Copper has a high affinity to absorb in the paper, while in the oil it is dissolved in very low concentrations, typically in the range of a hundred to a few thousands of ppb. Results of another study showed that copper content in paper rises following addition of phenolic inhibitor and increasing temperature (figure 4) [6], [19]. Dissolution of copper is followed by diffusion and absorption of copper in the paper in the locations of highest temperatures [20].

Dissolution of copper in the oil is dependent on temperature, oxygen content and base oil composition. It is conducted by formation of oil soluble copper hydro-peroxides and complex salts of copper and carboxylic acids for example [4], [18]:

2 ROOH + Cu2O → 2 Cu+(O2R)- + H2O

In general, oxygen was found to promote dissolution of copper in the oil [6], [15], [18], [21]. Oils with low degree of refining (higher aromatic and sulphur content and lower oxidation stability, mostly uninhibited oils) in particular are prone to dissolve substantial amount of copper in the presence of oxygen. However, increasing oxygen content above a certain point will lead to precipitation of copper in the form of sludge and a decrease in the dissolved copper content in the oil [6]. This behaviour pattern is the same for inhibited oil, i.e. increase of oxygen content will lead to an increase of copper dissolution in the oil until a very high oxygen concentration is reached at which point dissolved copper in the oil will decrease after sludge formation and precipitation. The peak copper concentration dissolved in the oil is dependent on overall resistance of the oil to oxidation process [11], [18].

Experiments on a set of eight oils were performed in order to investigate copper-in-oil dissolution and deposition on the paper (Table 2). All eight of the oils were non-corrosive and two different sets of experiments were performed with varying levels of oxygen, at several temperatures, with oil, paper and copper over 72h.

Table 2 Characterization of selected unused oils

Parameters of characterization

OILS Flash Point

PMCC (°C)

Density

(kg/l)

Aromatic Content

(% m/m)

Viscosity

@ 40°C (cSt)

Inhibitor content

DBPC (% m/m)

Oil 1 140 0,876 9,4 9,51 0,207

Oil 2 130 0,866 3,1 8,63 0,279

Oil 3* 142 0,880 12,1 9,64 < 0,01

Oil 4 148 0,875 5,7 11,08 < 0,01

Oil 5 140 0,873 9,3 8,23 < 0,01

Oil 6 140 0,871 4,6 8,24 0,255

Oil 7 150 0,872 8,5 9,79 < 0,01

Oil 8 146 0,877 7,5 8,70 0,272

* contains metal deactivator, Irgamet ® 30

It was found that uninhibited oils with higher aromatic content reached higher concentrations of dissolved copper after heating at temperatures in the range from 100°C to 140°C in conditions of lower oxygen content. Increase of


Page 13

temperature from 100°C to 120°C resulted in a decrease of copper dissolved in the oil. This decline can be explained by a higher rate of sludge formation, consequently leading to a decrease of copper content in the paper (minimum reached at 120°C), while further decrease of copper content in the oil with increasing temperature (up to 140°C) resulted in increase of copper content in the paper (figure 9) [6].

-0,2

0

0,2

0,4

0,6

0,8

1

1,2

1,4

90 100 110 120 130 140 150

Copper content (mg/kg) in oil

Temperature, °C

Oil # 1 Oil # 2

Oil # 3 Oil # 4

Oil # 5 Oil # 6

Oil # 7 Oil # 8

0

200

400

600

800

1000

1200

1400

90 100 110 120 130 140 150Copper content (mg/kg) in paper

Temperature, °C

Oil # 1 Oil # 2

Oil # 3 Oil # 4

Oil # 5 Oil # 6

Oil # 7 Oil # 8

Figure 9 Copper contents in the oil and paper at different temperatures (oils from Table 2).

0

0,5

1

1,5

2

2,5

3

3,5

4

4,5

Oil # 1 (inhibited)

Oil # 5 (uninhibited)

Copper content (mg/kg) in oil

Oil type

Inert atmosphere

(Argon)

Oxidative atmosphere

(Oxygen)

0,00

100,00

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700,00

Oil # 1 (inhibited)

Oil # 5 (uninhibited)

Copper content (mg/kg) in paper

Oil type

Inert atmosphere

(Argon)

Oxidative atmosphere

(Oxygen)

Figure 10 Effect of atmosphere on copper content in the oil – left and copper content in the paper

– right at 100°C.

An increase of oxygen concentration contributed to an increase of copper content in the paper, particularly in inhibited oil, whereas in uninhibited oil the increase was less significant owing to copper precipitation from the oil and blocked transfer from the oil (significant decrease of copper content in the oil due to sludge formation) to the paper (figure 10) [6]. Concentration of copper through paper layers declines from inner to outer layers, in accordance to Fick’s law for non-steady-state diffusion [20].

Increasing concentrations of phenolic inhibitors in the oil were observed to promote copper deposition on the paper (Figure 11) [6]. It appears that inhibitors prevent precipitation of copper in the form of sludge in addition to its primary function of protecting oil from severe oxidation. Consequently transport of dissolved copper to paper is not blocked, at least not until severe oxidation occurs once the inhibitor is depleted. Other researchers came to similar findings related to the impact of addition of increasing amount of DBPC on the increased transport of dissolved


Page 14

copper through the oil to the paper, as observed by simultaneous decrease of copper content in the oil and increase of copper content in the paper [22].

0,0

0,5

1,0

1,5

0,00 0,20 0,40

Conpper content

(mg/kg) in oil

% DBPC

Oil # 5

Oil # 3

0,0

100,0

200,0

300,0

400,0

500,0

600,0

0,00 0,10 0,20 0,30 0,40

Conpper content

(mg/kg) in paper

% DBPC

Oil # 5

Oil # 3

Figure 11 Effect of inhibitor content on copper dissolution – left; effect of inhibitor content on

copper deposition in the paper – right after heating at 100°C during 72 h.

Copper compounds absorbed in the paper after ageing with non-corrosive oils were found not to have conducting potential, according to the results of one laboratory investigation (Figures 12 and 13) [6].

Figure 12 Change of paper surface resistivity after ageing of paper/oil with 0.15 l/h air flow;

left – inner paper layer, right-outer paper layer

Figure 13 Change of paper surface resistivity after ageing of paper/oil with 1 l/h oxygen flow;

left – inner paper layer, right-outer paper layer


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2.4 Proposed Reaction Pathways: DBDS degradation products

Several different reaction pathways for copper sulphide formation were proposed, coming from published literature, laboratory studies and service experience, such as:

• Solid state reactions, formation of metallic sulphides on bare metal (copper) surfaces - degradation

under low oxygen conditions: catalytic decomposition of DBDS on the copper plate in a low oxygen environment yields dibenzylsulphide (DBS) and toluene as products. Further decomposition of DBS and reaction with copper produces benzyl mercaptan and copper sulphide. Formation of elemental sulphur is also possible, which can, in direct reaction with solid copper, generate copper sulphide [3], [5], [17], [23].

• Disulphide reduction/thiolate oxidation reactions in the presence of oxygen/reactions in the paper

via copper-in-oil dissolution: formation of dissolved copper compounds in reaction of copper oxides with hydro-peroxides formed during oxidation process, absorption of dissolved copper in the paper, followed by reaction with thiols (mercaptans) and formation of copper sulphide. Formation of thiols or thiolate anions may occur by C – S bond cleavage due to the high stability of the formed benzyl radical. Other by-products such as elemental sulphur, benzyl mercaptan and toluene have been found in transformer oil samples. During the oxidation process enolates can be produced through keto – enol tautomerism under acidic conditions, which are able to quench disulphides and form mercaptans. Regeneration of disulphides is possible through thiol (mercaptan)-disulphide interchange (equilibrium); a well-known, very important process in protein chemistry [4], [15], [24], [25], [26], [27].

• A recently proposed addition to the mechanistic model published in TB 378 relates to the role of oxygen, i.e. oxidation of proposed DBDS degradation products, namely bibenzyl. According to the proposed mechanistic model, DBDS degradation products are: DBS and bibenzyl. Absence of bibenzyl as a copper sulphide by-product in oxygen rich conditions was explained by oxidation of bibenzyl into benzyl alcohol, benzaldehyde and benzoic acid. Interference from other oxidation reactions seems not to be significant.

• Metal catalysed oxidation reactions – anti/pro-oxidant effects/ reactions in the oil - formation of

copper sulphide intermediates for deposition on the paper: oil oxidation reactions are closely related to reactions of copper sulphide formation. Copper sulphide intermediate compounds, which are oil soluble, are produced during the oxidation process, while certain classes of sulphides and disulphides may become more reactive after being oxidized than their non-oxidized derivates. Disulphides are well known secondary oil antioxidants, acting as hydro-peroxide decomposers [28], [29], [30], [31]. Activity of sulphides and disulphides in peroxide decomposition is performed via an oxygenated derivative, sulphoxides and sulphur oxy-acids. This reaction pathway includes formation of sulphonic acid and sulphur dioxide. Created sulphoxides and acids can corrode metals, hydrolyze hydro-peroxides, or react with copper oxides and hydro-peroxides to form copper sulphide as an end product [11], [12]. It was observed in the majority of oils at common testing conditions that these reactions will not produce substantial amounts of copper sulphide.

From the proposed DBDS decomposition reactions, the following compounds are likely to be formed as DBDS degradation products: dibenzyl sulphide (DBS), Benzyl mercaptan, toluene, benzyl alcohol, benzaldehyde, benzoic acid, elemental sulphur, sulphur dioxide, sulphoxides, sulphones and sulphonic acids. It is possible that some of the by-products regenerate an amount of initial disulphide, such as benzyl mercaptan which may oxidize into disulphide, or if elemental sulphur is formed, it may produce mercaptans in reaction with hydrocarbons, which can further oxidize into disulphides. It is well known from protein chemistry that mercaptan – disulphide interchange is likely to occur in oxidative conditions [32]. The high reactivity of mercaptans could be one of the reasons for low traceability of these by-products in service-aged oils. However, other products, like toluene and possibly oxygenated derivates of benzyl mercaptan could be potential markers for detection of copper sulphide formation [33].

Monitoring the DBDS consumption in the oil may serve as an indication of copper sulphide formation, but can not be considered a precise and reliable method for diagnostics, especially at lower temperatures and higher oxygen content in the oil as the DBDS decomposition route is predominantly in accordance with its antioxidant action, with a lower yield of copper sulphide production.


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Summary on mechanism

Deposition of copper sulphide on the copper surface or in the paper generally occurs simultaneously, but also either one of these processes can occur alone as has been presented previously. Although simultaneous deposition on the copper and formation in the paper is most commonly observed, evidence has been found of copper sulphide formation solely on the copper and copper sulphide deposition only in the paper, on inner and outer paper layers, while copper conductor surface remained clean.

Mechanism of copper sulphide formation on bare copper in solid state reactions is well elaborated in the literature [2], [3], [23], [24]. Detachment of copper sulphide particles from copper surface and transport to the adjacent paper layer seem to be promoted in oxygen environment, although the mechanism is still unknown [5].

Mechanism of copper sulphide formation in the paper postulated on comprehensive studies by different researchers is based on dissolved copper intermediates and can be summarized as follows [1], [4], [14], [15], [18], [21]:

• Initiation of the reaction, formation of copper ions initiated by temperature and promoted by electro-magnetic fields and electrical stresses

• Formation of copper compounds dissolved in the oil (dependent on base oil composition, favoured by increase of oxygen and addition of of phenolic antioxidants) – “dissolved copper intermediates”; since it is not likely that a copper-sulphur complex could exists in dissolved form in the oil

• Transport/diffusion of “dissolved copper intermediates” through the oil to the paper, followed by absorption of these intermediate compounds in the paper

• Reaction of paper absorbed copper intermediates with reactive sulphur compounds absorbed by the paper;


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Figure 14 Scheme of copper sulphide formation in the paper Legend:

R-S-S-R: disulphide (for example dibenzyl disylphide - DBDS)

Cu: Copper

T: Temperature

AC/DC: Electrical fields

Cudiss.: Dissolved copper compounds (Cu+(O2R)- )

ROOH: hydro peroxides

R’OH: alcohols, phenols and derivates (DBPC, DBPh)

CuxS: Copper sulphide


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3 RISK ASSESSMENT

An improved understanding of the mechanism of copper sulphide formation and collection of data from service, including data on transformers during inspections, scrapping and post-mortem investigations is expected to improve risk assessment. In support of data collection, a questionnaire for data collection for units failed due to copper sulphide or units with copper sulphide problems was put on the CIGRE SC A2 public website.

The majority of failures reported to A2.40 were of generator step-up transformers, industrial transformers, large power transformers and shunt reactors in power grids. Most of the failures were sudden, without prior warning from DGA or other tests, as observed by the previous working group A2.32 and reported in TB 378. However there were also cases of heavily aged GSU transformers with overheating problems as indicated by DGA, reported to have failed in a short period after refilling with corrosive oil. Recent case studies showed the presence of abundant copper sulphide deposits on bare metal surfaces, i.e. contacts and leads in transformers with low loading history. Cases of failures due to silver corrosion and overheating problems were also reported. These experiences showed that copper and silver sulphides may be formed in a broader range of oxygen concentrations and temperatures from different reactive sulphur compounds (as stated in Chapter 2; different disulphides, including DBDS, elemental sulphur, oxidized monosulphides).

During post-mortem investigations and other transformer inspections, a thorough examination may be required to locate copper sulphide deposits as they may not be seen easily. This is often the case during inspection of units which have not failed due to copper sulphide. Copper sulphide deposits have been found in the hottest areas, as “hot spot markers” and frequently deep inside the winding section, in the paper insulation of inner/middle conductors, which are not easily found unless all conductors and paper wrappings are inspected.

3.1 Service Experiences and Survey Results

Since the publication of TB 378, publicly reported cases of failures related to copper sulphide deposition appear to have reduced. This is not unexpected as awareness of the problem has led to potentially corrosive oils being removed from the market and mitigation measures being taken. There may also be some element of reduction due to misdiagnoses of failures now that corrosive sulphur is no longer such a cause célèbre.

Working Group A2.32 reported in TB 378 that the response to the questionnaire for service experience with copper sulphide related problems was relatively poor with only a handful of failures reported. The questionnaire was left open to obtain further cases as a requirement for this Working Group, but the majority of responses were to confirm that some countries or organizations have been unaffected by the problem and a dozen failures were reported through this mechanism. As before, the failures are mainly of GSU, high voltage transmission transformers and industrial rectifier transformers, but in contrast to the last report there have been failures of free-breathing transformers in more moderate climates. This may be because the risk of failure in these conditions was perceived to be low and steps were not taken to prevent corrosion occurring. Another explanation for the low failure rate is the fact that several conditions need to be met for failure to occur, it is clear that there is a basic requirement for sulphur to be present, either in a corrosive form or a form that may become corrosive under conditions that may be found in a transformer. Beyond this basic requirement, high temperature is the main requirement for corrosion, especially where the sulphur is not in a corrosive format already: elemental sulphur, for instance, does not require especially hot conditions. The temperature requirement will then depend on other factors such as transformer design, operation and/or service conditions, the presence of electrical stresses, the type and amount of sulphur species in the oil. Based on experiences gained during transformer inspections and on the basis of number of the transformers in service with corrosive oils, especially those containing DBDS, it is obvious that many transformers may remain in service for a long time without failure due to copper sulphide formation. A number of units with copper sulphide deposits found during transformer inspection or after failure attributed to another cause were drawn to the attention of the WG but details were often lacking in these cases.

Overall, cases of twenty eight units were reported to WG A2.40 containing different amounts of information and data. It should be noted that some cases were brought to the attention of the Working Group where it was


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requested that they not be shared in the brochure or where details were not supplied for the sake of confidentiality. The number of failures the WG was aware of is higher than the number collected within TF 02 survey (Appendix 2).

According to the information’s given to the working group and failure cases gathered within TF 02 questionnaire (detailed TF 02 Failure Cases Summary is given in Appendix 2) besides shunt reactors, and GSU, transmission transformers and industrial rectifier transformers were highly affected by copper and silver sulphides.

Results of TF 02 Failure Cases Summary show that:

• Majority of failures in larger generator and transmission transformers and shunt reactors (>100MVA, more than 70%), followed by Industrial and rectifier transformers (21%);

• Most failures due to inter-turn faults (approximately 39%) and owing to a combination of sulphur corrosion and abnormal (severe) solid insulation ageing (approximately 46%); similar results for not only generator and transmission transformers, but also shunt reactors and rectifier transformers;

• Majority of units working in constant high load (54%) and variable load (32%);

• Significant failures due to dielectric faults (approximately 25%) and tap-changer faults (approximately 21%);

• Majority of uninhibited oils represented (54%), but also significant number of inhibited oils (36%);

• Notable failures due to faulty maintenance, including impropriate oil reclamation;

• Majority of transformers failed in service by several protections (61%) and significant number removed from service due to gassing or asset health review (36%).

Some failure cases and experiences from transformer inspections that may be shared are described below.

3.1.1 Failure Cases

Transmission transformers

The first case is of a free-breathing, 1000MVA, 400/275 kV transmission auto-transformer that had been in service for 11 years. As a result of a combination of high temperature settings on the cooler controls and the moderate loading when in operation, the transformer spent a significant amount of time at relatively high temperatures and the hotspot was most likely above 100°C for long periods. The transformer failed suddenly without any sign of a problem from DGA although the previous sample had been a routine sample around 12 months earlier because the unit was perceived to be healthy. The cause was found to be an HV winding turn-to-turn failure on the series winding and the photographs in Figure 15 below show the extent of the damage and the evidence of copper sulphide that was found upon investigation. Although the exact point of failure could not be identified because of the extent of the damage, the remaining intact windings were examined and the copper sulphide deposition was found to be severe. It should be noted that the common and tertiary windings were not affected as in those cases the copper was varnished. The transformer design was found to have contributed to the failure as the placement of an oil guiding washing reduced oil flow to the top disc especially under ON conditions. It is likely that the transformer would have had a reduced asset life due to increased ageing of this part of the transformer but the copper sulphide deposition exacerbated the situation and precipitated the failure [34], [35].


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Figure 15 Clockwise from top left: Failed series winding; top view of intact winding showing

bands of copper sulphide, copper surface of failed winding; copper sulphide deposits on paper.

Other transmission transformer failures that have been reported include the following:

• A 50MVA three-phase transformer that failed after 5 years in service with loads no more than 45% of the rating where a combination of copper sulphide deposition and a number of short-circuit events contributed to the LV winding failure.

• A 150MVA, 230/130 kV transmission transformer that had metal passivator added after 2 years of service in 2007 to mitigate potential effects from DBDS (150ppm). No depletion of metal passivator was detected but three years later, in 2010 the transformer failed. Rather than copper sulphide deposition this transformer was found to have silver corrosion and this had flaked and contaminated the windings (Figure 16). Irgamet ®39 was found to have very weak effect in protection of silver surfaces.

Figure 16 Silver corrosion in an in-tank OLTC


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GSUs

Another case of a free-breathing transformer involved an 800MVA, 432/23.5 kV GSU single phase unit installed in the early 1980s. The oil was changed in the mid-1990s owing to severe oil ageing and the new oil contained DBDS. The transformer failed suddenly in 2010 (Figure 17). Upon investigation an inter-turn fault was found in the HV winding. The transformer was found to be in generally good condition with normal working temperatures well bellow limiting values and DP values of the paper away from the failed area indicated that the paper was in good condition (>600). The only significant factor found during scrapping was the presence of copper sulphide deposition.

Figure 17 Top: failed winding, Bottom: Stripped conductors from top disk showing copper

discolouration (left) top view (right) underside view

Additional GSU failures of which the WG was aware included the following:

• A 783 MVA, 422/23kV single phase transformer where significant deposition was found on the tap winding (Figure 18a).

• A 192 MVA, 400/15 kV ONAF transformer that failed after 8 years in service where overheating due to problems in design (cooling oil ducts) also resulted in an inter-turn fault in HV winding where copper sulphide deposition had occurred (Figure 18b) [35].

• A 600MVA, 300/22kV transformer that had been installed in the 1960s but had received significant amounts of new oil due to oil leaks, which suffered an HV winding fault as a result of restricted oil flow and copper sulphide deposition where overheating had occurred, similar to the first case described above [35].

• There was a report of two 240kV, 58MVA, free-breathing, shell-form transformers that failed at a hydro-electric power station. Both had been in service since 1971 and underwent an oil change, the first in 2001 and the second in 2002, both transformers failed around six years after the oil change to oil that was subsequently found to be corrosive. In both cases, heavy deposits of copper sulphide were found on inspection and it was concluded the copper sulphide played a significant role in the turn-to-turn flashovers that caused the failures (Figure 18c).


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Figure 18a Contaminated tap winding and paper

Figure 18b Point of failure in the disc bellow first oil guide from the top of HV winding

Figure 18c Sample of copper from fault area in a shell form transformer

A further GSU failure reported to the WG was of an 11.5/150kV 148MVA unit from Uruguay. The three phase, OFAF, free-breathing transformer was manufactured in 1991 and failed in 2008. The transformer had seen a constant load of 90% over the 17 years and tripped on differential protection. Upon investigation, it was found that a short-circuit breakdown had occurred in the upper part of one of the HV windings - a turn to turn failure had occurred around 84% up the height of the winding; the failure point encompassed adjacent discs (Figure 19). The


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oil was found to be corrosive according to IEC 62535 when it was tested after failure. As with many other failures of this type there were no indications of abnormalities observed in the DGA results or any of the oil properties. Dissolved gas analysis suggests that the typical oxygen level in the oil was around 4000 ppm, substantially lower than typical oxygen level in free-breathing units. It was observed during the inspection that the copper sulphide deposits were growing from the inner paper layers to the outside layers but they were not seen on the any of the exposed copper surfaces.

Figure 19 Indications of copper sulphide formation in the windings and the point of failure

Reactors

There were three failures of single-phase, 50MVAr, 525/√3kV shunt reactors of the same design reported from Brazil (Figure 20). All three of the OFAF units were manufactured in 1999 and contained naphthenic oil with DBDS. The post mortem reports of these reactors were supplied to the working group and are summarized below.

Figure 20 Scheme of the active parts of the reactor design


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The first reactor failed after 5 years and 4 months in service. Failure occurred without warning from DGA i.e. there were no signs of elevated gases seen prior the fault. After the fault it was apparent there had been arcing and damage was found on discs 50 and 51, burnt paper was found across the radial winding extension. Copper sulphide deposits were found on the paper insulation. Extensive damage, i.e. burnt paper, across the whole radial section of the winding indicated that design weaknesses were present (see Figure 21).

Figure 21 Post mortem examination of single-phase, 50MVAr shunt reactor

The second reactor was in operation only slightly longer, failing after a total of 6 years and 7 months; for the last 14 months prior to failure passivator was contained within the oil. Four months after passivator addition there was a notable increase of thermal gases, methane and ethylene were observed, indicative for thermal fault T2 according to Duval’s Triangle (temperature range from 300 – 700 ºC), followed by failure 10 months later. The observed damage to the windings was severe as shown in Figure 22.

The lowest DP values were found at Disc 112, the same location where the highest amount of copper sulphide was detected. Copper sulphide formation was related to the damage in twin coils causing local overheating and an open circuit. Deposits were found up to the third paper layer, while the highest amount of copper sulphide deposits were found in the outermost layers.

Figure 22 Post mortem examination of second single-phase, 50MVAr shunt reactor

It was found that the oil ducts, as designed, were smaller than they should have been, causing non-uniform oil flow through each duct and non-uniform distribution of temperature across the section. This contributed to localised overheating and formation of copper sulphide. Consequently a short circuit started between coils, rising to full breakdown, flashing over from phase to earth.

The third reactor was initially held as a spare that was than installed to replace the first failed reactor; it than had shortest time in operation at 1 year and 11 months. After two months of operation metal passivator was added and an increase of CO and CO2 was observed that was attributed to addition of the metal passivator. Failure occurred


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after addition of the metal passivator and during inspection copper sulphide deposits were not found on the conductors or on the paper (Figure 23).

Figure 23 Post mortem examination of third single-phase, 50MVAr shunt reactor The failure was a result of a flashover from phase to earth, characterized by deficient oil impregnation and undersized oil ducts previously observed as design weaknesses.

This case is an example of the potential for misinterpretation of the root cause of a failure; had previous similar cases not been thoroughly investigated and had been attributed solely to copper sulphide failure and/or inefficient function of metal passivator in mitigation of corrosive sulphur problem, the design weaknesses may not have been picked up.

Industrial applications

A failure described in detail to the WG was from Poland of a 63MVA, 230 kV industrial transformer, driving a steelworks that failed during tests. The transformer had been removed from service for an LV bushing change, which was carried out on site. After the oil had been filtered and degassed it was tested prior to returning it to service. As the tests were not successful, it was sent to a repair factory. DGA results suggested low level overheating but internal inspection revealed evidence of flashovers on the LV winding and extensive evidence of copper sulphide deposition (Figure 24) on the stress rings and the conductors in the upper part of the LV winding. Copper sulphide deposits were found dominantly on the copper and on adjacent paper layer, while only traces of Cu2S were detected on outer being slightly more intensive on the outmost outer layer. As the transformer was feeding a steelworks it was subjected to frequent load changes but the average oil temperature was not believed to have exceeded 60°C.


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Figure 24 (l-r) LV leads; external surface of pressboard cylinder inside LV winding; copper

sulphide deposits on conductor and paper (left – inner, right – outer paper layers)

An additional industrial transformer failure was reported where a rectifier transformer, 44 kV, 33 MVA suffered a turn-to-turn failure in the HV winding only nine months after an oil change which was carried out to revitalize insulation system. The transformer was already aged and suffering from overheating problems but the oil change introduced copper sulphide deposition as an additional and triggering factor towards the failure (Figure 25) [36].

Figure 25 Magnetic core (left) and damaged HV winding, phase B, place of breakdown, copper

and paper contaminated with copper sulphide deposits (right)

Three cases of 33kV rectifier transformers were reported to the group. Two of them failed during service and one was taken out of service for internal inspection. Oils were tested as non-corrosive according to IEC 62535 and DBDS was below 5 mg/kg. The oils were uninhibited, without metal passivator and in service for 26 – 28 years. The failures occurred with in a few days of a maintenance outage during which the oil was reclaimed. Abundant copper sulphide deposits were discovered during inspection, transformer internals were heavily affected by copper sulphide. This may have indicated that deposits were accumulated during long service period and possibly corrosive sulphur compounds were depleted from the oil.

However, it is also possible that oils were becoming corrosive during oil reclamation, with the possible formation of elemental sulphur. As mentioned previously, DIN 51353 was found to be more sensitive to detect formation of elemental sulphur in lower concentrations than IEC 62535, which is not a sensitive test for detection of elemental sulphur. It was not clear whether failure occurred due to the detrimental effect of silver corrosion after oil reclamation, as has been found by others. Copper sulphide deposits discovered during inspections may be a coexisting separate effect of oil deterioration, or a combined effect of silver and copper sulphide deposits led to failure.

In a number of cases in pratice uninhibited oils which were not corrosive to silver and copper prior reclamation and without DBDS became corrosive to silver after reclamation. In general, oils with a lower degree of refining and


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relatively high total sulphur content are more prone to become corrosive to silver, as a result of oil reclamation which involves adsorbent reactivation. Such oils contain lot of sulphur which can be converted to reactive species during reactivation of adsorbent, like elemental sulphur. However, this does not exclude possibility that inhibited oils can become corrosive to silver after such treatment.

A case was reported of a rectifier transformer in a primary aluminium plant in Italy, 93.4 MVA, 66/0.4 kV, manufactured in 1998, cooling ODAF, sealed with a rubber bag and windings made from enameled conductors (CTC type). The oil was uninhibited and was tested to contain 159 ppm of DBDS, giving a positive response to IEC 62535 corrosive sulphur testing, but not to the DIN 51353 method.

A major (destructive) failure event occurred in the first half of 2010 with no prior warning from DGA in the most recent sample around 6 months earlier. A post-mortem examination was conducted and copper sulphide was discovered on both the paper and on enameled conductors. Flakes observed on the conductors indicated formation of bubbles in the lacquer of the conductors. Some tests on unused conductors of the same batch clarified that the lacquer (polyvinyl acetate or PVA) loses its adhesion if cured over 120°C and that the enameled copper conductors suffered temperatures higher than their nominal Thermal Resistance causing the formation of bubbles in the CTC and the loss of adhesion strength of the lacquer. This is also a clear indication that the temperature in the transformer (at least on conductors’ surface) was higher than expected. Copper sulphide layers were also identified on the paper of the conductors retrieved from the failed unit. Metallic copper particles were also found on the papers of the conductors retrieved from the failed unit (Figure 26).

Figure 26. Enameled copper conductors with copper sulphide, down: paper with copper sulphide

and bubble formation on CTC-right.

Laboratory investigations had shown that copper sulphide deposits were found on the outer and inner paper layers of enameled, paper-wrapped copper conductors heated together in the same oil with bare copper conductor standing separately in the same vial. This experiment had shown that paper surfaces may be contaminated with copper sulphide even if paper was wrapped around enameled conductor. Dissolved copper is necessary, which is created from the bare copper surface and transported, or diffused, to the paper, most probably to hottest paper areas, where copper sulphide is formed in reaction with available sulphur. The capability of the oil to dissolve the copper from bare conductors plays an important role, and is enhanced by aromatic compounds. This case showed that copper sulphide may be formed in the windings of transformers manufactured with enameled conductors. Nevertheless bare copper surfaces as a source of dissolved copper are physically separated from paper where copper sulphide is deposited. This case provides contributory evidence for the postulated mechanism of copper sulphide formation in the paper via copper-in-oil dissolution and absorption in the paper, followed by the reaction of copper and sulphur compounds in the paper.


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3.1.2 Inspections and transformer scrapping information

Detecting the presence of copper sulphide in transformer by non-destructive means remains problematic, but it may be possible to understand more about the conditions that pose most risk if observations of copper sulphide deposition can be made on transformers removed from service for reasons other than copper sulphide-related failure. The scrapping of transformers is not always witnessed but much may be learned about design of old transformers, performance of cooling systems, paper degradation and copper sulphide deposition if the time is taken to participate in this activity.

Several examples of copper sulphide come from the UK where many transformers are examined whilst being scrapped to obtain paper degradation information regardless of the reason for removal [37]. This confirms the comments in the previous report, and restated above, that suggests that transformers may remain in service for many years once deposition occurs and it is not always a life-limiting condition. In the first UK example (figure 27), a transformer was switched out of service after 11 years in service following observation of rapidly increasing ethylene on the online gas monitor. The transformer was thoroughly investigated and evidence of copper sulphide formation was found on both the common and series windings. The transformer was relatively lightly loaded and there were no known problems with the thermal design. A sister unit which failed a short time later and not thought to have had a significantly different service history was also scrapped and there was very little evidence of copper sulphide found. It would seem the factors that influence whether corrosion will start to occur or not may be very sensitive.

Figure 27 evidence of corrosion on the copper and sulphide deposition on the paper on both the

common and series windings of a 240MVA autotransformer

In the second example from the UK, the shunt unit of a 2000MVA, 400kV quadrature booster that had been in service for 10 years was removed from service and returned to the factory for a rewind to a new design. The removed windings were inspected and revealed some evidence of copper corrosion on the conductors (Figure 28).

Figure 28 copper corrosion in a quad booster


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In the third UK example (Figure 29) a transformer removed from service because of advanced aging in a relatively young 1000MVA, 400/275kV transformer was expected to show signs of copper sulphide deposition as the oil was known to contain around 150 ppm of DBDS. External indicators of paper ageing were found to be correct and the transformer was showing signs of ageing on inspection. The copper sulphide was not as advanced as expected but this may have been as a result of addition of metal passivator after the transformer had been in service for around 10 years.

Figure 29 (l) top disc of common winding showing signs of ageing paper and copper sulphide

deposition (r) evidence of copper sulphide on conductor surface and on Nomex strip between

conductors.

An additional example was reported from Serbia of a 123/6.3kV, 63MVA GSU with design problems, which was inspected in the factory due to worsening dielectric properties and suspected advanced insulation ageing. The oil was uninhibited, with a lower degree of refining and higher aromatic content, without DBDS. Copper sulphide deposits were found in the upper part of the HV winding (around 2/3 height) at locations of DP values in the range from 255–inner layers adjacent to copper, to 409-outer layers to the oil. The transformer design was known to be poor with uneven oil ducts and width of coils and this was evidenced by severely degraded solid insulation after only 9 years of service. In the last 4 years of service, a high increase of oil DDF and furans was observed (significant rate of 2-FAL increase ~6.9 ppm in the last 18 months of service), but DGA did not reveal a problem. However, it seems that the oil, rich in sulphur, contained reactive sulphur compounds other than DBDS and generated copper sulphide deposited at winding paper (Figure 30).

Figure 30 HV winding, upper part circled area from which paper samples were taken; on the

right copper sulphide deposits on the paper


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Another GSU (235/15kV, 360MVA) was removed from service and found to have evidence of heavy copper sulphide deposition on the bare metal surfaces of low voltage busbars where the oil was believed to be relatively stagnant. The windings were enameled and clear of deposition.

Other in-service experiences

Copper sulphide formation does not always lead to failure but may cause other problems in service. A number of cases were reported to the working group or available through publications that show the problems that may result from the presence of corrosive sulphur in oil.

One case is reported of a diverter suffering from pyrolytic carbon growth on a tap-changer braid where the oil was clearly exposed to very high temperatures (Figure 31). In this case all of the copper surfaces were coated in copper sulphide adding greatly to the remedial works required to return the tap-changer to service.

Figure 31 The diverter above is from a transformer which faulted and from which oil was

expelled through a silica gel breather as a result of extensive pyrolytic carbon growth on a

copper braid (top left).

An unusual case was presented to the WG of copper corrosion on braided connections to the LV winding (Figure 32) of a 175MVA, 410/10.5kV transformer where DBDS was not found and the potential for corrosion could not be unambiguously shown. The deposits appeared to be rich in copper and sulphur but not copper sulphide. This case was particularly unusual because the problem was diagnosed by an increase in dissipation factor and insulation resistance, which is not typically useful in diagnosing the formation of copper sulphide.

Figure 32 Braided connections to the LV winding


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Because copper sulphide formation and deposition is a temperature dependent process, copper sulphide deposits around several, but not all, connections may be used as an indicator of the quality of moulded joints. The flexible connections in Figure 33 were constructed from thin (0.2 mm) copper conductors without an anticorrosive covering. These connections are known to suffer from a decrease in mechanical durability and the subsequent rupture of elementary conductors under the influence of corrosion. The reduction of an effective section of a connection can lead to the accelerated overheating and full break of a connection. The consequences of break under loading or a stress caused by external short circuit can be catastrophic for the transformer and its environment. All similar connections were replaced by connections of elementary conductors (2 mm) with a tin covering. The copper sulphide deposits were located on the surface of the bottom part of bushing and may be discovered by measurement of Dielectric Dissipation Factor (DDF) and/or Insulation Resistance as was the case in this transformer (Figure 33).

Figure 33 LV winding leads of 175 MVA, 410/10.5 kV transformer

3.1.3 Alternative Sources of Reactive Sulphur

Silver Corrosion Cases

There are a number of instances reported of corrosion of silver contacts in tap-changers that may or may not be related to DBDS or other corrosive sulphur compounds. In these cases silver appears to have reacted to form a silver sulphide coating whilst copper has generally been left intact. Different sources of the corrosion have been suggested, proposed to be related to the formation of elemental sulphur.

A number of companies involved in oil reclamation of transformer in situ have identified silver corrosion following treatment of transformer oil through reactivatable clays, commonly but incorrectly referred to as Fullers’ Earth (actually aluminium oxide or bauxite). In these cases the oil was believed to be non-corrosive beforehand or even tested and found to be non-corrosive (Figure 34).


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Figure 34 DIN 51353 silver strip test performed during oil reclamation

Some time after treatment the silver contacts have been found to be coated in silver sulphide on inspection or found through contact resistance measurements (Figure 35 and Figure 36).

Investigation of the reclamation process and the rigs involved has shown that the rigs may be subject to corrosion due to sulphur in the oil and that in some of the waste oils produced elemental sulphur is present in high concentrations. There is some evidence that elemental sulphur can find its way into the transformer even when the operation and maintenance procedures followed were generally considered appropriate, in many cases procedures have had to be revised to deal with the problem.

Figure 35 Example of silver corrosion following reclamation (l) prior to reclamation (c) contacts

one year after reclamation, (r) three years after original switch out.

The case above in Figure 35 was of a free-breathing transmission transformer (275/132kV, 240MVA) where the selector compartment is separate from the main tank, although they have a common conservator. The contamination was believed to be elemental sulphur and reclamation (>40 passes) was unable to remove the corrosiveness. Selector contacts were clean prior to reclamation (left picture of Figure 35), one year after reclamation, transformer switched out following presence of fault gases in DGA sample (central picture of Figure 35), while three years after original switch out corrosion of silver and copper recurs despite oil replacement in selectors and addition of metal passivators (right picture of Figure 35).

In a case, reported through response to the questionnaire of a distribution transformer (110/16.5kV, 25MVA) silver sulphide deposits were found where the oil was not reclaimed. The transformer was built in 1972 but redesigned in 2006. The redesigned unit contained naphthenic oil of a type known to contain DBDS, but it was not tested for this. After the transformer had been in service for a few months it was investigated following the presence of overheating gases in the DGA. Silver sulphide deposits were found on the OLTC selector switch contacts, which were cleaned off and the metal passivator was added before successfully returning the transformer to service, which is currently in operation for seven years.


Page 33

There is some evidence from dynamic resistance measurements of in-tank tap-changers that contacts may be in poorer condition in transformers containing potentially corrosive oil with DBDS concentrations of up to 160 mg/kg than in older transformers which were not originally filled with potentially corrosive oil. The evidence is based on a relatively small but statistically relevant group of transformers to date the technique may offer the best opportunity to discover where silver corrosion may be occurring when inspection is not practical (Figure 36) [33].

Figure 36 Resistance diagrams from oscillograms following resistance measurements of healthy

(left) and likely contaminated contacts (right)

The presence of silver sulphide in transformers in the absence of corrosion to copper is not surprising as some forms of sulphur are more reactive towards silver than copper and are reactive at lower temperatures (Figure 37). Where silver corrosion might be an issue or is suspected the older corrosive sulphur test method (DIN 51353) using a silver strip is more likely to indicate a problem than ASTM D1275B or IEC 62535. For this reason DIN 51353 is still recommended in some circumstances.

Whilst some silver corrosion issues can be expensive to correct they do not typically lead to transformer failure as they are often detectable through DGA when the corrosion occurs on tap-changer contacts leading to high resistance and overheating of the oil.

Figure 37 Examples of coatings on silver plated selector contacts

However, there are examples of failure attributed to this form of corrosion. A free-breathing transmission transformer, 142 MVA, 500/150 kV, ODAF cooling, manufactured in 1977 with CTC windings and Kraft paper with uninhibited paraffinic oil failed after 33 years in service [38]. This occurred a few weeks after oil reclamation, which was recommended in order to restore aged oil properties. The failure occurred after OLTC commutation,


Page 34

overpressure in the Buchholz relay initiated differential alarm. No external disturbances were recorded. The DGA indicated high energy discharges in the main tank and winding resistances and transformer ratio measurements indicated decoupling between the tap selector-diverter switch and the OLTC motor drive with tap-selector fixed at position 15. Flashover on the highest stresses contacts of tap selector short circuited the regulation winding. The fault current did not involve the primary winding.

Following the failure, the transformer was stripped down for investigation and considerable damage was found – the regulation winding had collapsed owing to failure of the restraints and the diverter tank was clearly broken (Figure 38). Arcing was evident in the diverter and there had clearly been high resistances as evidenced by contacts that had been melted during the fault. In addition, the silvered contacts were coated in a bluish-grey deposit that was identified as silver sulphide and could be easily removed whilst copper surfaces were unaffected.

Figure 38 a,b,c : Mechanical damages on the regulation winding, tank of diverter switcha and

support bars;

Figure 38 d,e: findings on diverter switch

Figure 39 Signs of electric arcs and high current on the tap selector contact-left, Silver sulphide

deposits from selector contacts detected by SEM/EDX - right


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Marks of electrical arc and high current on the tap selector contact were observed during inspection and residue deposited on the surface of the second contact of tap selector was analyzed by SEM/EDX. The elements present were silver and sulphur in atomic ratio corresponding to silver sulphide - Ag2S (Figure 39).

Prior to reclamation the oil was known not to be corrosive according to IEC 62535 and ASTM D 1275 B. Following reclamation the oil was found to contain small amount of DBDS (6 ppm) and was corrosive to silver and copper (positive IEC 62535 and ASTM 1275B). To evaluate the corrosiveness of the reclaimed oil mixtures of the corrosive oil (1%, 5% and 10%) from the transformer with corroded silver contacts and non-corrosive oil of the same type were heated with silver contacts following a procedure similar to ASTM D1275B - in each case a positive result was given by the silver contacts (Figure 40).

Figure 40a Heating of original oil-first left and reclaimed oil-second left at 80°C over 72h with

silver plated TAP; silver tap after heating in reclaimed oil - top right and original oil - bottom

right.

Figure 40b Tap selector contact heated in mixture of reclaimed corrosive oil and non-corrosive

oil.

Additional experiments showed that doping with 100 ppm of Irgamet ®39 did not reduce the corrosiveness of reclaimed oil as it was still corrosive to silver.The oil reclamation was performed with reactivating sorbent and it was found that dirty oil storage tanks and the control pot were sources of reactive sulphur compounds, including significant amount of DBDS (54.1ppm). The reclaimed oil was contaminated by sludge from these tanks (Figure 41).

1% reclaimed oil in non-corrosive oil





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Figure 41 Dirty oil storage (DOS) and Control Pot

Silver corrosion of OLTC contacts was also discovered in transformers in service with oils containing DBDS, but also in cases with oils which have not being corrosive according to IEC 62535 and DIN 51353 and where oil reclamation has not been performed. These may be due to the oil becoming corrosive when it has reached an advanced stage of oxidation [28], [39]. Development of corrosiveness was observed with uninhibited oils after oxidation. Oils were becoming corrosive, while as new they were non-corrosive to silver.

In all cases where found, the presence of silver sulphide on contacts causes an increase in the contact resistance and if left unchecked it is likely to result in the production of fault gases. Transformers for which silver corrosion is found to be a problem have been treated in different ways, addition of metal passivator (Irgamet® 39) has not been successful and there are mixed reports of the success of applying further reclamation.

Evolution of gases may be too rapid to rely on as an indicator of silver corrosion. Near to the completion of the WG a case was reported from Australia of an 8 year old, 132/33kV, 80MVA transformer which suffered catastrophic winding damage resulting from a failure in the tap-changer thought to be a result of silver corrosion. The oil was known to be corrosive but left untreated (no data related to the corrosive sulphur tests and amount of corrosive sulphur compounds in the oil were given to the WG). Prior to a maintenance outage the oil showed only a small rise in hydrogen otherwise there was no suggestion of a problem but it failed within an hour of energization. Fault gases were apparent after the failure and multiple arcing points were found upon inspection.

Figure 42 Examples of multiple arcing points found upon inspecting transformer believed to

have suffered inter-phase flashover owing to silver sulphide particles

Sulphur contamination from rubbers

The possibility that corrosive sulphur might be extracted from rubber gasket materials in transformers or expansion bags in the conservator was investigated within the WG.

It was demonstrated in laboratory studies that corrosiveness can be increased through the presence of nitrile rubber but only at a high rubber to oil ratio. It was observed that Viton reduces corrosiveness to some extent, probably due to absorption of sulphur molecules but again this was seen at a high rubber to oil ratio (Table 3).


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Table 3 Summary of results of laboratory testing of influence of rubber materials on

corrosiveness

In mass ratios corresponding to real transformers there seems to be no evidence that the type of rubber materials used will influence oil corrosiveness or copper sulphide formation. The mass of each material is given and is present in 15ml oil samples. Red indicates a positive result, green negative result and yellow a result which was not clearly negative.

3.2 Risk factors

A better understanding of the mechanism in combination with information from failures and service experience is improving understanding of the relative importance of the different risk factors i.e. how and to what extent they promote the reaction of copper sulphide formation. As postulated in TB 378, the main influential factors, explained in more detail in TF 01, related to real service parameters may be divided in categories related to equipment, status of the oil and insulation system and service conditions.

Based on service experiences and evidences from scrapping and inspections, transformers may remain in service for many years once deposition occurs, mainly depending on loading regime or /working temperatures, copper sulphide deposition is not always a life-limiting condition.

Risk factors for copper sulphide formation related to equipment design and manufacture are:

• cooling design and design defects

• sealed or free-breathing system

Risk factors related to the state of the paper/oil insulation are:

• type and amount of corrosive sulphur species,

• type and amount of additives other than DBDS

• oil oxidation process and insulation ageing

Risk factors related to service conditions are:

• working temperatures and loading conditions

• electrical stresses (especially transients in HVDC apparatus and industrial application).

Impact of Design and Manufacture

A common feature in many of the failures and in-service experiences that have been reported is poor cooling resulting from the design or transformer construction, which can increase risk significantly when most other factors


Page 38

are apparently low. These defects were, in most cases, reported to be due to improper design and construction of cooling ducts and oil guides or inadequate distribution of oil flow and temperatures within winding coils which was not known and/or appreciated. The risk of transformers having problems may be increased when the oil is not being forced through the windings, either because the transformer is ON only or because the cooling is believed not to be required.

The problem with unknown temperature distribution in the windings and/or unknown hot spot temperatures may be solved with detailed thermal calculation and/or mounting fiber optic temperature probes as long as these are requested prior to manufacture. Where there is particular concern over assets because copper sulphide deposition is suspected or the transformer is believed to have poor thermal performance, forced cooling or reduced temperature settings for the coolers to be switched in may be considered.

Impact of Oxygen Content

Where the impact of oxygen is concerned, distinction between oxygen content in the oil and available oxygen for oxidation processes should be made.

Regarding oxygen content dissolved in the oil, the conclusions from TB 378 still hold, stating that the low concentration of dissolved oxygen in the oil (several thousands of ppm, corresponding to sealed units, or free-breathing units with high oxygen consumption) is worse then high concentration of dissolved oxygen. However reported failures of free breathing units and laboratory investigations indicate that with increasing temperature even higher values of oxygen contents contribute to increased risk. The amount of deposits, the induction time needed for copper sulphide formation and deposition may vary substantially, depending on temperature and oil condition (see Chapters 2.2.2 and 2.2.3).

A broader range of oxygen contents dissolved in the oil was recognized to influence copper sulphide formation and deposition with contribution to increase of risk than was previously appreciated. There should be no distinction between sealed (nitrogen purged) and free-breathing transformers where evaluation of risk is concerned.

Impact of Sulphur Species

On the basis of service experiences and different laboratory investigations it is clear that DBDS is not the only reactive sulphur compound present in the oil which may under specific conditions react with copper or silver and form metallic sulphides, but it is the most commonly found. Classes of reactive sulphur compounds have different reactivity for metallic sulphide formation (order of reactivity shown in table 1) which is dependent on temperature, oxygen, presence of different metals or metal oxides as catalysts. Certain sulphur species in their oxidized form were also found to be reactive. This can explain development of oil corrosiveness during oil oxidation, not only as the consequence of depletion of specific additives-metal passivators. According to laboratory investigations some of the reactive sulphur compounds are prone to deposit copper sulphide on bare copper at lower temperatures, while deposits were not observed on the paper in the same conditions. These observations can support findings during inspections of some transformers, where copper sulphide deposits were found even though the transformers had a history of relatively light loads.

Elemental sulphur (S8) was found to be one of the reaction products formed during oil reclamation processes, especially when oils rich in sulphur were being reclaimed. At high temperatures, above 250°C, catalytic cracking of the oil on hot aluminium oxide surfaces or pure thermal cracking can generate reactive sulphur compounds, particularly elemental sulphur. This implies that certain higher molecular weight sulphur compounds, that are not reactive at lower temperatures, may decompose at high temperatures in thermal cracking reactions and form corrosive sulphur species.

Bare metal surfaces of copper and silver are prone to be affected by the range of reactive sulphur species even at lower temperatures with exposure over longer time spans.

Impact of Additives

Laboratory studies have shown that the presence of oxidation inhibitors such as DBPC can influence copper sulphide formation. Deposition of copper sulphide in the paper was usually observed in IEC 62535 tests of inhibited


Page 39

oils. There is evidence that the addition of inhibitors to oils that were originally uninhibited and contained reactive sulphur species after incomplete reclamation and removal of corrosive sulphur compounds, changes the reaction such that copper sulphide deposits are more likely to form on the paper than on the copper surface, as before addition of inhibitor (Chapter 4.3.3, figure 77). In the cases where mitigation was applied by addition of metal passivator, inhibited oils may give a better response and prolong the effect of metal passivator (Chapter 4.1.3).

It has been observed that metal deactivator, Irgamet® 30 (generic name: N,N-Bis(2-ethylhexyl)-1,2,4-triazol-1-ylmethanamine) has been used in some oils available in the market and although this may give a small benefit to oxidation stability in the short term it does not confer any resistance to copper sulphide formation.

In many cases, when passivator has been added to a corrosive oil it is seen to deplete significantly with time. At some point, this will inevitably result in the oil giving a positive result to corrosive sulphur tests. However, whether the copper itself is protected in these circumstances is still a matter of investigation (see Chapter 4.1.3).

Impact of Oil Oxidation

An increased rate of oil oxidation processes and insulation ageing increases the risk for copper sulphide formation and deposition on the paper.

Oil oxidation processes may contribute to an increase in corrosive oil potential, by formation of copper sulphide intermediate compounds, i.e. copper complexes and oxidized sulphur compounds [4], [12]. Therefore, in service, oil corrosiveness may increase due to oxidation process and/or increased temperatures as consequence of increased load or development of faults.

Development of silver corrosion during oil oxidation, as well as copper sulphide formation, in old units with uninhibited non-DBDS oxidized oils has been observed [39].

Aged solid insulation may be a better absorption media for reactive sulphur and copper species and its decreased mechanical strength will further increase risk of failure.

Impact of service conditions

High load and frequent overload conditions, including frequent change of loading, contribute to copper sulphide formation and failure, based on experience of reported failures as temperature is the main driving factor for copper sulphide formation.

Localized or diffused overheating increase risk of failure. Very often during inspection of failed units it was discovered that copper sulphide deposits were found at the places of highest temperatures, like “hot spot markers”.

Frequent transients, harmonics and over-voltages significantly may increase risk of failure. Electrical stresses may trigger failure at places where copper sulphide deposits are formed. Additionally, formation of electrons as the initiating step of the reaction of copper sulphide formation may also act as contributing factor.

Given the number of influencing factors described above a transformer owner/operator may consider that understanding whether a given transformer is at risk is a complex calculation. In attempting to understand whether the transformer is getting hot, which would give indications of high risk, following observations that might lead to a positive response include, but are not limited to:

• Regularly running at or above nameplate rating

• Operating at loads above 50% of nameplate rating without coolers running (where applicable)

• Dissolved gas analysis results suggesting localised or diffused overheating

• Evidence of paper degradation

• Known issues with thermal design leading to high hot spot factor (impact of design and manufacture)

• High surface temperature to the touch or from thermovision.


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3.3 Diagnostic Methods

There are a number of oil tests available for detection of reactive sulphur compounds: disulphides, mercaptans, elemental sulphur, which may initially be present in the oil, or formed as degradation by-products of DBDS or other reactive sulphur species. Other tests include different electrical methods for detection of polar contaminants in solid insulation and chemical tests used in quantification of copper sulphide deposits in the paper.

Monitoring of depletion of corrosive sulphur compounds, namely DBDS and detection of DBDS degradation by–products can be used for estimation of copper sulphide formation in insulation system of transformers in service.

3.3.1 Oil Tests: detection and quantification of reactive sulphur compounds

The standard test methods for qualitative detection of sulphur compounds reactive to copper and silver are IEC 62535 and DIN 51353. There is also a method for quantitative detection of DBDS in the oil using Gas Chromatography with Electron Capture Detector (GC-ECD), which is IEC 62697.

Other, non-standard, test methods used for detection of DBDS and other reactive sulphur compounds are as follows:

• Determination of DBDS ad other sulphur species reactive to silver using gas chromatography with methyl polysiloxane column Capillary columns, 30 to 60 m, with 0.25mm I.D. and 0,25 - 0.32µm 5% phenyl 95% methyl polysiloxane stationary phase thickness using Flame Photometric detector. Alumo-silicates with bonded silver nitrate are used to extract reactive sulphur compounds (15 ml of oil is stored for 8 h at 80°C with immobilized silver nitrate on silica). Quantification was achieved by difference in area of treated/extracted and untreated oil [39].

• A method for Total Corrosive Sulphur content in mineral insulating oil; this method is based on a temperature-assisted reaction between fine copper powder and the sample oil, it responds to any kind of sulphur molecules reactive to copper (i.e.: capable to form copper sulphide) under the test conditions [40]. After the reaction, in sealed vials, the copper powder is treated to convert the formed copper sulphide into copper sulphate, which is later detected by nephelometry or other suitable techniques for sulphates determination. Total sulphates are than converted to a reactive sulphur concentration by stoichiometry. It is aimed at the non-selective quantification of corrosive sulphur in mineral oil. Provisional results from Round Robin Tests suggest this method suffers from poor reproducibility (standard deviations between laboratories from 8 to 35%). The method is still under investigation and optimization by IEC TC10 WG 37 and future improvements are expected. Nevertheless, at the moment it seems to be applicable for research studies or for specific investigation purposes, but not as a routine test method.

• Detection of total amount of disulphides, mercaptans and elemental sulphur using potentiometric titration with silver nitrate, after reduction of disulphides to mercaptans with Zinc (CIGRE WG A2.32. TF 02 test method) [1]. This method is used for detection of the total reactive sulphur, the same group of reactive suphur compounds as previous method and usually those two methods give comparable results.

• Detection of DBDS using High Performance Liquid Chromatography (HPLC) technique and Ultra Violet (UV) detection with silica Solid Phase Extraction (SPE) preparation using n-pentane and acetonitrile-water mixture for elution.

• Detection of benzyl mercaptan, benzyl-group (Benzyl alcohol, Benzaldehydes, Benzoic acid), toluene and elemental sulphur using Gas Chromatography with Mass Spectrometry Detector (GC-MS) [33].

• Change in sulphur and copper concentrations in corrosive oils as detected by XRF (X Ray Fluorescence) [41].

Test methods under development within IEC TC 10 WG 37 are: detection and quantification of total corrosive sulphur compounds, mercaptans, disulphides and targeted corrosive sulphur compounds. WG A2.40 has proposed to IEC TC 10 WG 37 to create test method for quantification of elemental sulphur (S8) in the oil.


Page 41

Results of Round Robin Test (RRT) for quantification of Dibenzyl disulphide in the oil

Round Robin Test for DBDS quantification in the oil was conducted during the work of WG A2.40 on 4 oil samples containing DBDS, two new oils and two aged oils. One new oil and one aged oil were fortified with known amount of DBDS (Figure 43: NO1- new oil 1 and AO2 – Aged oil 2), while other two were originally containing DBDS. Fifteen laboratories have participated and three test methods were used: IEC 62697 (GC using Electrcon Capture, Atomic Emission and Mass Spectrometry Detector), HPLC and Gas Chromatography with Flame Photometric Detector (FPD) in-house methods. Statistical analysis was performed for two oils fortified with DBDS, with known concentrations of DBDS (theoretical values).

Figure 43 Spread of Z score of laboratories participating in RRT

Even if the Z-score obtained by individual laboratories appears to be acceptable in most cases, the RRT was affected by quite a large deviation of results, both at low and high concentrations (Figure 43). Generally speaking, the spread of results is, in percentage terms, lower at high DBDS concentrations around 200 mg/kg compared with low DBDS concentrations around 20 mg/kg; this is in line with theoretical models of relative error against concentration.

Looking at the actual results, it emerged that GC-ECD is the most reliable technique. This might be due to the fact that the majority of the participating laboratories applied this technique. Other techniques have a larger spread of results among laboratories (e.g.: HPLC), and some techniques were applied by so few laboratories that a complete evaluation could not be done.


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Figure 44 Spread of measured DBDS around theoretical value obtained by different methods

Finally, statistics confirms that GC-ECD method, as given in IEC 62697 is the most mature (in terms of precision and trueness) technique for DBDS quantification in insulating mineral oil (Figures 44 and 45).

New Oil 1

0%

10%

20%

30%

40%

50%

60%

70%

Average

GC-ECD

Average

GC-AED

Average

GC-MS

Average

GC-FPD

Average

GC -

MS/MS

Average

HPLC

Average -

All

MethodsMethod

Trueness, related to theoretical

value

Aged Oil 2

0%

5%

10%

15%

20%

25%

30%

Average

GC-ECD

Average

GC-AED

Average

GC-MS

Average

GC-FPD

Average

GC -

MS/MS

Average

HPLC

Average -

All

Methods

Method

Trueness, related to theoretical

value

Figure 45 Trueness of different methods related to theoretical DBDS value


Page 43

3.3.2 Other Test Methods for Copper Sulphide Detection and Quantification

During the course of the work of WG A2.40 there has been no significant change from the position outlined in TB 378 i.e. that there are no non-destructive techniques available for reliably identifying the presence of copper sulphide deposition in the windings. Dissipation losses, dielectric frequency response (DFR), full impedance wave, winding resistance, insulation resistance, frequency response analysis (FRA), recovery voltage measurement (RVM), acoustic emission and partial discharge (PD) have all been investigated but are not adequate for monitoring copper sulphide deposits of transformers in service [42], [43], [44].

The polarization spectrum methods may only give an indication of copper sulphide contamination when the deposits are located in the insulation; deposits between turns inside the windings will not be detectable. Copper sulphide deposits on the copper conductor will also be undetectable.

Considering the fundamentals of dielectric response methods it could be possible under certain conditions to monitor copper sulphide deposits, if they are located on the paper, between the windings and earthed components.

Transformer models were used in the course of investigation of phenomena of copper sulphide contamination in the paper as contribution to polarization dielectric response spectrum of insulation system.

Recovery Voltage Measurement (Hungarian experience) in copper sulphide diagnostics applied on two

transformer models

Recovery Voltage Measurement (RVM) was investigated using two small transformer models to check that the technique is sufficiently sensitive to show the deposit of copper sulphide (Cu2S). The models were filled with uninhibited oil. Model Number 4 was spiked with 180 ppm of DBDS whilst the oil in Model Number 2 did not contain any DBDS. The solid insulation in the models was dried out in a vacuum chamber to 0.7%, as measured by RVM. The water content in the oil was 2-5 ppm. Ageing was performed in a sealed system at different temperatures during 54 days (Table 4) and the oil properties before and after the ageing cycles are presented in Table 5.

Table 4 Ageing temperature and time cycles

Date of ageing Duration of

ageing (days)

Temperature

of ageing (°C)

Temperature and Date of RVM

measurement

01.08 – 09.08. 2013 8 days 90°C 22°C, (12.08 – 29.08. 2013)

10.09 – 17.10. 2013 7 days 95°C 22°C (19.09 – 01.10. 2013)

02.10 – 09.10. 2013 7 days 100°C 22°C (10.10 – 22.10. 2013)

24.10 – 29.10. 2013 5 days 110°C 22°C (31.10 – 12.11. 2013)

18.11 – 25.11. 2013 7 days 120°C 22°C (26.11 – 12.12. 2013, and 22°C (06.01 – 15.01. 2014)

16.01 – 21.01. 2014 5 days 130°C 22°C (22.01 – 31.01. 2014)

07.02 – 10.02. 2014 3 days 150°C 22°C (11.02 – 20.02. 2014)

17.03. – 20.03. 2014 3 days 150°C 22°C (21.03 – 07.04. 2014)

14.04. – 17.04. 2014 3 days 150°C 22°C (22.04 – 05.05. 2014)

05.05. – 08.05. 2014 3 days 150°C 22°C (12.05 –21.05. 2014)

09.06. – 12.06. 2014 3 days 150°C 22°C (23.06 – 02.07. 2014)

21.08.2014 Open and dismantle of models


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Table 5 Oil properties before and after ageing in Model 2 and Model 4

Model Number 2 (without DBDS) Model Number 4 (with DBDS) Measured parameters

Before ageing

After ageing

DGA after ageing, ppm

Before ageing

After ageing DGA after ageing, ppm

Breakdown voltage (kV)

>70 69 H2=<10 >70 43 H2=92

DDF (tgδ) at 90°C <0,0010 0,0078 CH4=134 <0,0010 0,0061 CH4=243

Acidity (mgKOH/g)

<0,01 0,07 C2H6=189 <0,01 0,21 C2H6=201

Water content (ppm)

<5 11,8 C2H4=20 <5 17,4 C2H4=33

Interfacial tension (mN/m)

48 16,4 C2H2=0 48 14,5 C2H2=0

IEC 62535 non-

corrosive CO=1394 corrosive CO=3969

DBDS (ppm) not-

detected CO2=115105 197,8 3,6ppm CO2=141093

Antioxidant (ppm) not-

detected not-

detected O2=0,7% not-

detected O2=0,23%

Metal passivator, (ppm)

not-detected

N2=5,89% not-detected

N2=4,75%

The insulating paper was new and the Degree of Polymerisation (DP) value was not measured before the investigation. At the end of the ageing process the average DP value of Model 2 without DBDS was 244, while in Model 4 with DBDS present in the oil, average DP was 325, suggesting that DBDS as a secondary antioxidant slowed down the ageing process to some extent. After the ageing process, the elemental composition of paper samples was determined with SEM-EDX (Scanning Electron Microscopy- Energy Dispersive X-ray Spectroscopy). Copper sulphide deposits were detected on the paper of transformer Model 4 (Figure 46). Element composition of the paper sample verified the presence of copper and sulphur atoms, at location 1 in ratio correspondent to copper sulphide (Table 6).

Figure 46 Image of paper surface Nr 1 (100x enlargement)


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Table 6 elementary composition in the sampling point

Element conc.1

atom%

conc.1

mass%

conc.2

atom%

conc.2

mass%

conc.3

atom%

conc.3

mass%

C 77.031 64.713 71.006 64.365 74.386 68.374

O 19.379 21.686 28.744 34.708 25.520 31.248

S 1.071 2.403 0.113 0.273 0.032 0.080

Cu 2.519 11.197 0.136 0.653 0.062 0.299

Total 100.000 100.000 100.000 100.000 100.000 100.000

The RVM method was found to be sensitive to the conductive contaminants or deposits, because there was a certain difference between response curves of the models with and without DBDS, but it was very difficult to distinguish a new dominant time from the impact of moisture and ageing products. The shape of the polarization spectra was influenced by all the three of moisture, ageing and copper sulphide deposits (Figure 47).

Figure 47 RVM curves measured during the ageing process

If the intensity of the copper sulphide deposit had lower amplitude, the deposit phenomena could be hidden by the very high amplitude due to water and ageing. If the contaminants on the paper surface would have similar dominant time constants as the moisture or the ageing products it would be very difficult to distinguish which time constant characterises ageing, moisture and conductive copper sulphide deposits.


Page 46

Frequency domain spectroscopy (FDS) applied on transformer model during long-term ageing to detect

copper sulphide contamination

Another experiment was performed on a transformer ageing model filled with inhibited oil in a free-breathing system over a long time span (12 months prior addition of DBDS at 85°C-Ageing (1), 15 months after addition of DBDS at 85°C-Ageing (2) and 40 days at 125°C-Ageing (3)) (Figure 48). In this study FDS (frequency domain spectroscopy) and water equilibrium curves were used for estimation of water content in the insulation, together with direct measurements of water content in the paper in order to evaluate possibilities to detect copper sulphide contamination in the paper [45].

Initially the FDS readings were similar to water content evaluated by equilibrium chart and very close to measured water content (table 7, figure 49).

Figure 48 Core and windings –left, tank, temperature sensor, conservator-right

Table 7 Oil properties, evaluation of moisture using FDS readings and equilibrium chart

Tests Ageing (1) at 85°C Ageing (2) at 85°C Ageing (3) at 125°C

DDF oil, % / 15.9 31.8

DBDS inital, mg/kg 0 185 200

DBDS end, mg/kg 0 15 3

Water in the paper measured -KF, % 0.67 0.55 0.60

Water in the paper,% (KF, water in

the oil, ppm + Eq.charts) 0.80 0.80 /

Water (FDS), % 0.80 1.90 1.50

As the experiment continued into the later ageing periods, with DBDS being added and than consumed, the FDS readings were much higher than measured water content and evaluated water in the paper by equilibrium charts. This difference, i.e. increase of estimated water content by FDS can be attributed to significant contribution of ageing products in the paper and copper sulphide contamination.


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Figure 49 FDS curves after ageing periods; yellow – Ageing (1), green – Ageing (2), blue –

Ageing (3)

Copper sulphide deposits were detected on three subsequent paper wrappings out of the four in decreasing amount from inner to outer layers, while deposits on copper were minor (Figures 50 and 51).

Figure 50 Copper and inner paper layers: first, second and third after ageing period (3)

Figure 51 Outer paper layers, first and second-right after ageing period (3)

It has therefore been demonstrated that the possibility to detect copper sulphide deposits in the paper exists as a contribution to the polarization spectrum and dielectric response measurements. However, difficulties in distinguishing copper sulphide contamination in the paper from the impact of water and oil aging products, together with problems in location (deposits on copper-not detectable, deposits on paper-detectable in some locations) and amount of copper sulphide deposits (methods insensitivity until severe ageing and contamination of paper with copper sulphide), restricts use of methods of dielectric spectroscopy in detection of copper sulphide deposits of transformers in service.


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4 COPPER SULPHIDE LONG TERM MITIGATION

Once the awareness of corrosive sulphur related failures increased it was only natural that transformer owners and operators were concerned with how to mitigate the risk in their own assets. Different mitigation options were published, including those given in TB 378 but no single action would be expected to meet everyone’s needs; each asset owner/operator needed to evaluate their own level of risk and adopt an appropriate strategy to manage it.

A questionnaire for data collection for units which have undergone mitigation action was put on CIGRE SC A2 public web page, but most of the contributions were received in direct contact with utilities and from WG members.

4.1 Mitigation Techniques

The first mitigation action acts directly on the equipment as reconsidering the loading strategies, such as de-rating the transformer or more realistically improving the cooling efficiency and addition of metal passivator to cover copper and other metallic surfaces in the transformer active part. This is usually done by adding a solution of metal passivator in the same or similar oil to that in the transformer and adding it to the cooler return valve and circulating with pumps where available. Devices for oil reconditioning can also be used for this purpose.

The second option concerns the mineral oil itself and includes oil change and application of different oil treatment processes which may include physical process, i.e. removal of corrosive sulphur compounds from the oil by adsorption or extraction, using activated adsorbents or solvents, or chemical processes with reagents which are decomposing sulphur compounds. A combination of these processes may also be used.

4.1.1 Mitigation Survey

In order to achieve wider knowledge on the long term effects of different mitigation options a worldwide survey was promoted by CIGRE SC A2. A form for data collection was circulated with specific questions for cataloguing: types of equipment, types of oils, types of mitigating actions and other relevant parameters pertinent with the Terms of Reference. The survey was performed without taking into account the name of substations, name of manufacturer, equipment nameplate, etc. to guarantee the full anonymity for the participants. Substantial progress in data collection among A2.40 members was achieved. Specifically the replies came from 16 countries, as in the figure 52 below:

Figure 52 Distribution of mitigation survey responses among countries


Page 49

The survey covered the entire world, but it is not representative of the total real number of mitigating actions performed considered close to some thousands of units; in totally more than 1200 cases were reported:

• More than 20 electrical utilities mainly operating in generation (24%) and transmission (70%) but also in distribution (1%);

• Industrial applications (3 %);

• All kinds of power apparatus (transformers, auto-transformers, shunt-reactors, rectifiers, etc.);

• Both naphthenic (98%) and paraffinic (2%) and both uninhibited (85%) and inhibited (15%) mineral insulating oils;

• Free-breathing (64%) and sealed units (36%).

Statistical evaluation of the survey indicates that addition of metal passivators is most frequently applied, in 88% of the cases, including 5% of re-passivation. Oil change was carried out in 5%. Oil treatment processes (reclaiming) in removal of corrosive sulphur compounds from the oil were performed in 4% of the cases and the remaining 5% were other techniques or mixed actions (Figure 53).

Figure 53 Spread of mitigation actions, according to TF 03 survey

Based on the present survey it seems that the corrosive sulphur problem did not affect all countries around the world, but it should be noted that up to date no feed-back was received from some countries (Argentina, Germany, Spain, USA) where mitigation was known to have been extensively applied. These data could have contributed to different and more reliable statistics. It is estimated that more than 10.000 transformers around the world had been mitigated to prevent copper sulphide formation, therefore collected number of cases within TF 03 survey can be considered as representative.

The statistical analyses of the present survey, if aggregated by country or by company, may reflect the different approach used, mainly due to consolidated maintenance traditions. For instance, the long term experience of a large Italian electrical utility shows that 12% of the corrosive oils were reclaimed and that almost 40% of cases where addition of metal passivator was performed units were subjected to a second or third step of addition of metal passivator.


Page 50

4.1.2 Metal Passivators

Metal passivators are triazole derivatives which chemically adhere to non-enamelled, bare copper surface, forming a monomolecular layer (a coating on the surface, around 2nm thick) that blocks copper involvement as a reactant in the copper sulphide formation and hinders copper catalytic activity as an oxidation catalyst [46], [47], [48], [49].

Metal passivators are polar compounds and have a tendency to be absorbed in the paper and to attach to other metal surfaces. The amount of metal passivator spent for coating other metal surfaces has not been quantified, but is likely to be very small and below the limits of standard deviation for the test method for metal passivator determination. Therefore, it is assumed that negligible amounts of added metal passivator are spent for coating of other metal surfaces, whereas a higher amount is spent for absorption in cellulose materials and this is likely to be more pronounced at elevated temperatures which speed up transport of metal passivator into the paper [1], [4]. Naturally, oil is the transfer medium for transfer of metal passivator to the metal surfaces and into solid insulation of the transformer. Metal passivators are sometimes incorrectly called oil passivators and terms such as “passivated oil” are erroneous and should be avoided. Adequate wording would be “oil containing metal passivator”.

Concentration of metal passivator typically suggested is 100 mg/kg, but amounts up to 200 mg/kg in oil may be added to achieve higher saturation level of metal passivator layer on copper surface, as demonstrated in one study [49]. Concentrations less than 50 mg/kg of metal passivator are considered ineffective [50].

Addition of metal passivators to transformers via oil solution in order to prevent copper sulphide formation due to presence of corrosive sulphur in the oil is a routine practice applied worldwide for tackling the adverse effect of copper sulphide deposition. In the survey, 88 % of cases that were subjected to mitigation were related to addition of metal passivators.

Many kinds of metal passivators are present on chemical market because of their common use in lubrication field. Known metal passivators are named in, but not limited to, the list below:

1. Metal Deactivator - Ciba® IRGAMET® 39 (liquid pure reagent)

2. Cobratec ® TT100 Tolutriazole (solid pure reagent)

3. Nynas AB - Nypass (pre-blend of 10% passivator and a transformer oil base stock)

4. Shell Diala Concentrate P (10% concentrate)

5. DSI Sulphur Inhibitor – liquid concentrate mixture of “sulphur stabilizer, metal passivator and phenolic antioxidant.”

6. Metal Deactivator - Ciba® IRGAMET® 30.

4.1.3 Metal passivator efficiency

Service Experiences and Results of TF 03 metal passivator survey

Overall statistics speak in favour of the addition of metal passivator. In large majority of cases long-term experiences with application of this mitigation technique are good. However, around twenty failures after metal passivator addition have been reported and, in 28 cases out of 850, oils were still corrosive according to IEC 62535 and ASTM D 1275 B after such treatment, with seven of them where DBDS was absent and oils were corrosive according to DIN 51353. It is possible that these oils contained specific sulphur species, i.e. elemental sulphur and therefore mitigation by addition of Irgamet® 39 was not efficient. Application of blends of different metal passivators and sulphur stabilizers were tried on laboratory scale to mitigate such oils.

Stray gassing (sudden production of gases after addition of metal passivator, mainly hydrogen with increase of ≥ 100 ppm) was observed in 13% of the cases. In the majority of the cases with stray gassing (63%), the hydrogen peak leveled off after one to two years (see Chapter 4.1.4 and Tables 8a, 8d, 8e) [51], [52].


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Depletion of metal passivator was observed in 32% of the cases. Decrease of metal passivator from the oil up to 40% per year from the initial concentration is considered as normal effect of absorption in polar materials (paper, wood, metal surfaces) [1], comprising to improved protection against copper sulphide deposition (see Figure 59 and Figure 60) [4]. Close to half of this population (15%) were transformers with fast depletion of metal passivator (decrease higher than 40% per year), including transformers with thermal problems, but also unexpectedly units without thermal problems. This can be explained again by absorption effect in cellulose materials, but at higher rate. Still, scant reports about fast depletion of metal passivator within one year to very low values, i.e. ≤10 ppm, without any side effects, e.g. absence of stray gassing and no symptoms of intensive ageing and thermal degradation were reported for units from Uruguay, Thailand, Portugal and Australia. It was not clear whether improper addition procedure was the reason for eventual inefficient transfer of metal passivator into transformer active part, or metal passivator was degraded (more details in following sections, “Metal passivators and oil

condition” and “Metal passivator thermal stability”).

Several failure cases were reported after addition of metal passivator on the Brazilian transmission grids in 2006. As of December 2007, nine reactors working under severe service conditions (high and constant load, equatorial temperatures) had failed, respectively 33, 102, 136, 168, 284, 363, 478, 598 and 850 days after addition of metal passivator. Conversely, no failures have thus far occurred for any of the retro filled (oil change) units. Even if the problem affected reactors with different design and produced by different manufactures, this unsuccessful experience was attributed to the late addition of metal passivator, after copper sulphide was already deposited in the windings. These experiences emphasize the risk of late application of this mitigation technique which may become ineffective.

Later, in 2008 and 2010, two failures of shunt reactors after addition of metal passivator were reported. Reactors were in operation 5 to 6 years before addition of metal passivator. Another case of a GSU in Norway failed two years after addition of metal passivator. Most likely the copper sulphide deposits were already formed before the addition of metal passivator. Results of post-mortem investigations in both cases revealed that design issues/defects of affected windings where copper sulphide deposits were found had contributed to the failures.

A case of a 150 MVA transmission transformer that failed after addition of metal passivator was found to have a corrosion on silver pre-selector contacts which was not suppressed, i.e. not efficiently mitigated by addition of Irgamet® 39. This example shows the importance of having precise data on oil corrosiveness (to copper and silver) in order to choose appropriate mitigation action.

Service experiences in counteracting silver corrosion

Applicability of Irgamet® 39 to counteract silver corrosion was tested. It was observed that Irgamet® 39 was not able to counteract such oils in most of the cases, even when the passivator was added in high concentrations (up to 300 - 500 ppm) [53]. This was supported by service experiences. Silver corrosion is mostly induced by the presence of elemental sulphur in the oil.

Laboratory investigations

Metal passivators and oil condition

Prolonged and modified corrosive sulphur tests were used in order to investigate the long-term efficiency of metal passivator in respect of temperature, oxygen and oil ageing products [4], [47], [49]. Low base oil quality and presence of higher amounts of acids in aged oils will decrease metal passivator stability. Metal passivator was found to be highly efficient in new oils. In number of laboratory investigations, metal passivator was found to be efficient in the range from 72 h to over 350 h at 150°C, depending on oil quality, initial concentrations of corrosive sulphur compounds and metal passivator. In used oils, the protective function of metal passivator was found to be shorter [4], [48]. The more oil is oxidized the lower is the efficiency of metal passivator in suppressing copper sulphide formation [48], [54]. This could be attributed to degradation of metal passivator under attack of peroxides and acids [48], [54].


Page 52

Results of another study also indicated that the oil condition strongly affects performance of metal passivator [49]. The thickness of metal passivator on the copper surface, as determined by x-ray photoelectron spectroscopy (XPS) was nearly the same after treatment in three different oils (for 24 h at 70°C in oil containing 100 ppm of Irgamet® 39), while the response in the IEC 62535 test was found to be very different. Copper sulphide deposits were absent (oil A), or minor (oil B), nevertheless oils A and B were fortified with 2000 ppm of DBDS, while in originally corrosive oil which contained far less amount of DBDS than oils A and B, copper sulphide deposits were formed on copper and at the edges of the paper wrappings and, after fortifying with additional 2000 ppm of DBDS, the copper was completely covered with copper sulphide (figures 54, 55, 56). In all cases the paper was clear of copper sulphide deposits.

Figure 54 Thickness estimation on the Irgamet® 39 layer on copper surfaces via (PAR)XPS, left;

copper plate after IEC 62535 of oil A with 2000 ppm of DBDS added and 100 ppm of Irgamet®

39, right.

Figure 55 Thickness estimation on the Irgamet® 39 layer on copper surfaces via (PAR)XPS, left;

copper plate after IEC 62535 of with oil B with 2000 ppm of DBDS added and 100 ppm of

Irgamet® 39, right.

Although the thickness of the metal passivator layer on copper surface was similar for all three oils, i.e. saturation regime of the curve was achieved around 200 mg/kg with average thickness of 1.7 nm, this was not in correlation to the duration of protection against copper sulphide attack. Different oils have “consumed” metal passivator in different time spans, indicating that oil condition is a very important parameter for the determination of metal passivator efficiency. The less oil is refined and more aged, the shorter the protection against copper sulphide attack will be.


Page 53

Figure 56 Thickness estimation of Irgamet® 39 layer on copper surface via (PAR)XPS-left;

copper plate after IEC 62535 of originally corrosive oil containing 160 ppm DBDS-central and

originally corrosive oil with added 2000 ppm of DBDS with 100 ppm of Irgamet® 39- right.

The efficiency of metal passivator in any particular oil can be tested using the IEC 62535 test prior to addition and can be of value in finding the optimal concentration of metal passivator to be added.

Metal passivator thermal stability

High temperatures, coupled with intensive oil oxidation, presence of acidic compounds and high oxygen content in the oil will increase the rate of metal passivator depletion [48], [54].

Apart from issues of metal passivator chemical stability (impact of oil and oxygen), thermal stability of metal passivator molecules bonded to copper surface was investigated in a study using static secondary ions mass spectroscopy (SSIMS) [49].

The bonds between passivator and copper will tend to break with increasing temperature, with the result that the metal passivator molecules/ions will leave the copper surface. It was found by SSIMS technique that the temperature profile of metal passivator was very similar for all investigated oils (Figure 57), in fact it was independent of the oil type which was used to transfer metal passivator to copper surface.

The exception was the Nyhib concentrate, (oil containing 10% DBPC), which obviously contributed to a higher level of protection. At 100°C, in vacuum around 5-6% of metal passivator ions remained at the copper surface, which can be considered as unprotected [49]. In real service conditions in air, with conductors immersed in oil, the boundary temperature would be substantially higher.


Page 54

Figure 57 Depletion of metal passivator from copper surface treated with 100 ppm of Irgamet®

39 in different oils – metal passivator Ion profiles versus temperature for BTA- and TTA- ions.

In conditions of long-term overloading, in areas of localised hot spot and overheating, it can be expected that a substantial amount of metal passivator molecules will leave the copper surface and protection in these areas will decrease significantly. This was demonstrated on conductor samples from scrapped 400/275 kV autotransformer, known to have suffered prolonged overheating of the top discs (design and cooling issues) [49]. SSIMS images of conductor from top disc (Figure 58) show high surface of red area, as contribution of copper ions in comparison to green color of reference sample and turquoise color of bottom disc conductor, as a mixed contribution of tolyltriazole (Irgamet® 39) and sulphur ions.

Figure 58 SSIMS images (tolyltriazole – green, copper – red, sulphur – blue) of a reference

copper sample treated with Irgamet® 39 in mint conditions (left), outmost conductor of the top

(middle) and bottom (right) disc of a 400/275 kV scrapped autotransformer.

On the other hand, the presence of metal passivator in the surrounding paper and oil can provide extended protection for some time.


Page 55

In studies of the thermal decomposition of a metal deactivator, Irgamet® 30, hydrogen, carbon-monoxide and carbon-dioxide were evolved. The concentrations of hydrogen and carbon-monoxide were proportional to the initial concentration of the metal deactivator in the oil, while the concentration of carbon-dioxide did not follow that pattern. After a certain ageing period production of all three gases seem to level off, steady concentrations were achieved by equilibrium of decreased rate of gas formation with gas loss from the oil [55].

Interactions of metal passivators with solid insulation

Absorption of metal passivators (Irgamet® 39) in the paper was demonstrated on a laboratory scale, in a prolonged CCD test at 150°C [4]. Depletion of metal passivator from the oil was followed by its increase in the paper (Figure 59).

Metal passivator absorbed in the paper was observed to have protective function against copper sulphide deposition during laboratory simulations, heating of corrosive oils with metal passivator present only on the copper plate and absorbed in the paper [4].

50 100 150 200 250 300 350 400

0

5

10

15

20

25

copper dissolved in the oil amino methyl susbst.TTA conentration in the oil concentration of amino subst.TTA in the paper*, mg/kg

test duration, hamino methyl subst. TTA concentration in the oil, mg/kg

Copper dissolved in the oil, mg/kg

100

200

300

400

500

600

700

800

Concentration of a

mino m

ethyl subst. T

TA in the paper*, m

g/kg

Figure 59 Metal passivator (Irgamet® 39) concentration in the oil, concentration in the paper*

(based on metal passivator in oil calibration with calculated mass ratios of oil/paper from

experimental set up) and copper dissolved in the oil at 150°C during IEC 62535

In the course of the experiments it was found that the protective function of metal passivator existed over 120 h in new corrosive oil and over 96 h in aged corrosive oil during accelerated tests at 140°C. The shortest protection was in the case of aged oils in a high oxygen environment and metal passivator bonded only to the copper surface. This was confirmed by the rise of copper dissolved in the oil after 48h (Figure 60 pictures e and f).

The oil condition and oxygen content played an important role in the duration of protection. The longest protection was obtained with new corrosive oil in low oxygen conditions.


Page 56

20 40 60 80 100 120

0

50

100

150

200

250

300

350

400

450

Cop

per dissolved

in th

e oil, ppb

test duration, h

Low oxygen aged oil C I Low oxygen aged oil C II Low oxygen new oil C I Low oxygen new oil C II High oxygen new oil C I High oxygen new oil C II High oxygen aged oil C I High oxygen aged oil C II

High Oxygen Low Oxygen

a) C I aged oil 120h

b) C I aged oil 120h

c) C I new oil 120h

d) C I new oil 120h

e) C II aged oil 120h

f) C II aged oil 120h

g) C II new oil 120h

h) C II new oil 120h

Figure 60 Copper in the oil and images of paper wrapped conductors heated in corrosive oils for

120 h at 140°C

This experiment may mimic situations when metal passivator is completely consumed from corrosive oil, presuming the absence of copper sulphide layers. Metal passivator absorbed in paper was found to be an active inhibitor of copper sulphide deposition on insulating paper as it may interfere with species involved in copper sulphide formation. Insulating paper may serve as a reservoir for transfer of metal passivator to the copper plate once it has been depleted from the copper surface. Furthermore, paper-absorbed metal passivator may interfere with copper sulphide precursors absorbed in the paper [4]. The activity of paper-absorbed metal passivator in suppressing copper sulphide deposition is probably the consequence of its interference with oxygen-containing nucleophiles resulting from oxidation of hydrocarbons. This reaction between metal passivator and oxygen-containing nucleophiles is accompanied by the replacement of the nucleophilic benzotriazole group which could form a new protective layer on the copper surface and reduce copper dissolution in the oil [4], [57].

Interactions of metal passivators with other antioxidants

Highly refined oils with lower aromatic and sulphur content in the oil have a better response to antioxidants than oils with a lower degree of refining and consequently a higher aromatic and sulphur content. Synergistic action of primary antioxidants with secondary, sulphur-based antioxidants and metal deactivators/passivators was observed to slow down the oxidation process significantly. Each one of the specific antioxidants is responsible for mitigating one of the oxidation stages (Figure 61) [29], [30], [31], [32].

Primary antioxidants prevent the formation of hydro-peroxides acting as free radical stabilizers (Figure 61, CB-A and CB-D), while secondary antioxidants decompose hydro-peroxides into alcohols in later oxidation stages. The role of metal deactivators and metal passivators is to deactivate metal complex ions and hydro-peroxides, to make chemical bonds with the copper surface and decrease copper catalytic activity [31].


Page 57

Figure 61 Schematic presentation of primary and secondary antioxidant activity during

oxidation

Metal passivator stability is highly dependent on hydro-peroxide and acid concentration in the oil. Longer protection of copper surfaces is achieved in high quality oil with low peroxide and acid content with metal passivators added. In terms of copper sulphide formation, a lower rate of copper dissolution and hydro-peroxide formation will suppress formation of copper sulphide precursors. Different laboratory investigations have been reported showing a synergistic effect of metal passivators and phenolic inhibitor in inhibition of oxidation reactions and in suppressing copper sulphide formation during extended CCD and modified IEC 61125 tests. Addition of inhibitor, specifically DBPC, to new oils containing metal passivators, extended protection from copper sulphide formation, even after IEC 62535 tests of artificially aged oils obtained after oxidation stability test according to IEC 61125 C.

Other additives: Metal deactivators and additive mixtures

Applicability of Irgamet® 30 as a metal deactivator, for counteracting oil corrosiveness was studied in laboratory conditions. Results of these studies showed that although Irgamet® 30 is able to express surface activity, Irgamet® 30 is not efficient to counteract copper sulphide deposition with oils containing DBDS, since it is incapable of forming a stable coating. Irgamet® 30 was found to be efficient in slowing down the oxidation process to some extent [56].

Another blend of additives, the so called “DSI mixture” which contains sulphur stabilizer, inhibitor and metal passivator was tested on oils corrosive to silver. Results seem to be promising; oils were tested as non-corrosive according to IEC 62535 after addition of DSI mixture. However the recommended amount is 2.5% weight and chemical composition of the mixture is unknown. Long-term effects of this additive are unknown, therefore it can not be recommended for application in service.

Interactions with other metals

Interactions of metal passivator (Irgamet® 39) with different metals, such as core, coated core, stainless steel, high tensile 8.8, mild TP. CW., high tensile 8.8 black steel, in terms of gas evolution and depletion of metal passivator were investigated. Results of laboratory heating tests at 25°C and 100°C in conditions of low and high oxygen content were performed and revealed the following:


Page 58

• Depletion of metal passivator (Irgamet 39) from the oil and production of hydrocarbon gases was highest with copper in comparison to other metals, implying highest catalytic activity of copper compared with other investigated metals

• Production of gases increased with increase of oxygen and temperature for all metals

• Highest hydrogen production was observed with bare and coated core

• Interactions of oils with mild steel and copper were most pronounced, observed as highest metal passivator consumption at 25°C.

On the basis of previous results it can be concluded that the amount of metal passivator spent for coating metal surfaces was very small. A significant portion of metal passivator was consumed (15% from initial concentration) from the oil with copper and mild steel in air at 25°C. Copper and mild steel had the highest catalytic activity of all investigated metals and was observed to have the highest affinity to bond metal passivator.


Page 59

4.1.4 Side effects (passivator consumption, stray gassing, etc.)

As indicated previously side effects of metal passivator addition were observed in transformers in service in less than one third of transformer population investigated by TF 03 survey (stray gassing in 13% and fast depletion of metal passivator from the oil was observed in 15% of the cases).

Service experiences

Stray gassing, i.e. unexpected and abnormal generation of gas, mainly hydrogen and less frequently, carbon oxides (CO and CO2) is directly proportional to metal passivator concentration. However, in practice this correlation is not seen as a straightforward relationship. In many cases stray gassing was not observed even for concentrations of metal passivator up to 300 ppm, while there were also a number of cases reported with stray gassing at lower concentrations of metal passivator (100-200 ppm). Increase of hydrogen above 100 ppm after addition of metal passivator was considered as stray gassing, but in some cases rise of hydrogen was not observed in months after addition of metal passivator, making correlation to stray gassing less reliable, as hydrogen is gas which is easily produced during transformer operation.

An in-service case of erroneous Irgamet® 39 over-addition (1000 ppm -10 times higher) produced a huge increase of H2, CO2 and CO (~1000 ppm) and an appreciable increase of C2H4 and C2H6 (50-100 ppm). To prevent a misleading DGA interpretation and an unwanted Buchholz trip, the oil was reclaimed and degassed and than metal passivator added again with the nominal Irgamet® 39 concentration (100 ppm). In some cases, an increase of CH4, C2H4 and C2H6 (max 500 ppm for the latter one) in the oil was reported.

Stray gassing, i.e. higher rate of gases production (mainly hydrogen) is not an indication of fault and/or prefailure condition of transformer. However, this effect may interfere with diagnostic procedures and should not be misdiagnosed with partial discharges. Recently an improvement in the DGA interpretation affords the correct identification of this phenomenon [58]. No abnormal change of chemical and physical parameters of oil, like acidity, IFT or DDF was observed after addition of metal passivator.

A case history of an Italian transformer with stray gassing and fast depletion of metal passivator is shown in the following table 8 and figure 62 [51].

It was observed that hydrogen concentration suddenly increased after Irgamet® 39 addition. The concentration of Irgamet® 39 reduced to 43 mg/kg and a second addition of metal passivator was performed. Some months later the hydrogen concentration reverted back to the normal level, as in accordance with survey data (Figure 62).

0,00

0,25

0,50

0,75

1,00

Start-up

Passivation

2nd

Passivation

Still in

service

0 12 15 18 19 20 23 26 32 33 36 40 44 46

operation time (months)

p.u.

Corrosiveness test (ASTMD1275-B)

DBDS

Irgamet 39

H2

Figure 62 Example of stray gassing and fast depletion of metal passivator


Page 60

Table 8a Case history of an Italian transmission transformer before and after metal passivator

addition

Time

(months)

Action Corrosiveness test (ASTM

D1275-B)

DBDS

(mg/kg)

Irgamet® 39

(mg/kg)

H2

(mg/kg)

0 Start-up CORROSIVE (4b) unknown < 1 11

12 CORROSIVE (4c) unknown < 1 13

15 CORROSIVE (4b) 127 < 1 12

18 CORROSIVE (4b) 121 < 1 14

19 Passivation NON CORROSIVE (2c) 120 131 165

20 NON CORROSIVE (2c) 121 100 175

23 NON CORROSIVE (2d) 115 77 184

26 NON CORROSIVE (2e) 113 51 203

32 NON CORROSIVE (2e) 109 43 182

33 2nd Passivation NON CORROSIVE (2d) 110 111 197




46 Still in service NON CORROSIVE (2d) 108 94 21

Additional cases of transformers with different power ratings and voltage level subjected to metal passivator addition are shown in Tables 8b-8e. No correlation of oil properties (acidity, dielectric dissipation factor) to stray gassing was found when units with and without stray gassing effect were compared (cases without stray gassing - tables 8b and 8c, cases with stray gassing - TR 3 in table 8d and TR 1 in table 8e). In cases with stray gassing, elevated hydrogen concentrations were observed to level off after few months to two years time.


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Table 8b Transformer cases: 340 MVA, 410 kV, free-breathing, cooling: ONAF, uninhibited oil

Period/

days

IR®39 ppm

H2

ppm

CH4

ppm C2H4 ppm

C2H2 ppm

C2H6 ppm

CO ppm

CO2 ppm

Acidity, mgKOH/g

DDF

TR 1, date of metal passivator addition: 23.11.2007.

1 230 2.3 9.6 9.7 <QL 4.4 22.6 230 0.008 0.004

7 210 22.3 4.9 1.4 0.2 5.9 62.8 1000 0.013 0.001

503 156 12.8 24.3 2.7 <QL 40.1 104.3 1990 0.020 0.002

897 97.0 2.3 30.9 1.4 <QL 49.6 73.8 6900 0.021 0.001

second addition of metal passivator

1373 297 3.4 21.9 0.6 <QL 32.4 57.5 4190

1596 2.0 35.3 1.2 0.6 56.0 71.8 9680 0.018 0.001

1717 3.3 33.3 1.0 <QL 64.2 57.0 9050

TR 2, date of metal passivator addition: 23.11.2007.

382 2.6 25.0 1.6 <QL 38.0 70.8 3930

600 96.0 3.9 30.2 1.3 <QL 47.6 71.6 6590 0.024 0.001

851 63.0 3.4 34.9 0.9 <QL 53.4 76.7 6340 0.005 0.001


1076 295 3.6 21.8 0.4 <QL 32.0 51.4 4080

1299 250 1.2 30.9 0.7 <QL 51.7 57.3 8530 0.023 0.001

1420 239 3.8 36.8 1.0 <QL 62.8 73.1 9570

TR3, date of metal passivator addition: 23.11.2007.

382 2.3 1.6 <QL 39.4 73.0 4040

600 94.0 2.7 1.3 <QL 50.0 73.3 6820 0.022 0.0010


1076 289 4.5 0.4 <QL 30.3 51.0 3930

1420 4.2 1.0 <QL 62.9 71.4 9610

QL : quantification limit


Page 62

Table 8c Transformer cases: 340 MVA, free-breathing, cooling: ODAF, uninhibited oil

Period/ days

IR®39 ppm

H2

ppm

CH4

ppm C2H4 ppm

C2H2 ppm

C2H6 ppm

CO ppm

CO2 ppm

Acidity, mgKOH/g

DDF

TR 1, 150 kV, date of metal passivator addition: 19.01.2009.

1 150 7.6 2.2 0.1 <QL 1.1 19.7 590 0.034 0.009

83 107 9.8 6.0 0.4 <QL 2.6 79.3 2640

428 36.0 3.2 5.7 0.5 <QL 3.7 70.5 2500 0.033 0.013


480 147 9.6 7.3 0.7 0.4 3.3 65.2 2670

882 85.0 8.9 11.9 1.4 0.2 5.4 127.5 4960 0.027 0.014

1002 70.5 96.0 13.3 1.3 <QL 6.9 173.2 5540

TR 2, 400 kV, date of metal passivator addition: 09.12.2008.

1 180 0.9 3.8 1.2 <QL 11.0 23.0 600 0.025 0.011

204 119 5.3 10.6 7.5 2.0 5.4 89.1 4280 0.040 0.013

303 96.0 8.5 14.3 6.7 <QL 6.9 116.7 5420


430 177 3.0 7.7 6.7 <QL 4.5 39.4 1670 0.025 0.009

1029 124 6.4 18.0 12.7 <QL 8.9 157.2 5890

TR 3, 420 kV, date of metal passivator addition: 01.07.2008. (CIR39=199ppm)

25 3.7 9.2 3.7 0.4 2.3 155.4 5980

380 112 11.2 15.7 5.3 <QL 4.2 175.2 8380 0.030 0.007

597 92.0 11.9 20.3 5.2 <QL 5.4 191.2 8380 0.016 0.006


739 225 10.1 14.7 4.0 <QL 4.4 143.7 5270

976 179 12.8 9.0 4.8 0.4 4.2 373.9 8400 0.030 0.009

1226 4.2 21.3 5.4 0.8 8.6 747.0 11490


Page 63

Table 8d Transformer cases: 50 MVA, 18 kV, free-breathing, cooling: ONAF, uninhibited oil

Period/days

IR®39

ppm

H2

ppm

CH4

ppm C2H4 ppm

C2H2 ppm

C2H6 ppm

CO ppm

CO2 ppm

Acidity, mgKOH/g

DDF

TR 1, date of IR®39 addition: 06.04.2009. , C(IR®39=185ppm)

100 111 148.4 6.6 4.9 2.4 11.3 1025.6 1870 0.055 0.005

195 90.0 99.4 7.7 5.6 3.9 15.6 823.2 2870


287 179 39.0 5.2 5.4 6.0 7.1 469.5 2420 0.058 0.007

881 84.0 47.8 8.4 37.6 65.7 14.2 412.2 3640

TR 2, date of IR®39 addition: 16.06.2008.

1 199 9.5 1.6 1.1 4.5 4.5 37.3 400 0.041 0.006

176 35.0 7.4 4.7 7.7 7.7 644.7 2060

394 104 109.9 10.2 7.7 7.8 7.8 911.9 3520 0.050 0.004

646 59.0 53.9 18.0 15.5 26.1 26.1 470.3 3790 0.033 0.005


783 253 87.0 14.7 25.2 22.2 22.2 442.0 3740

1031 191 83.9 12.8 38.2 34.6 24.3 605.8 3270

1280 153.6 21.4 77.0 45.9 38.0 797.6 5270


1 201 5.4 1.1 0.8 <QL 4.2 91.7 430

39 224.0 16.9 4.6 0.6 29.2 613.1 940

394 76.0 201.8 59.4 22.2 4.7 155.2 861.5 3770 0.038 0.004

639 42.0 124.8 54.6 26.0 8.8 188.4 520.8 4470 0.033 0.007

799 29.0 155.4 45.1 28.2 6.4 152.6 357.8 4420


856 221 178.6 34.3 31.3 18.2 103.4 275.4 3160

1239 138 193.1 38.8 38.8 139.2 56.4 925.4 6070

TR 4, 29 MVA, 242 kV, date of IR®39 addition: 11.11.2010.

1 222 100.1 11.1 3.2 0.3 14.0 231.2 1100 0.033 0.003

138 177 15.7 31.8 4.2 <QL 54.3 206.1 1360 0.013 0.004


Page 64

Table 8e Transformer cases: 150 MVA, 410 kV, free-breathing, cooling: ONAF, uninhibited oil

Period/days

IR®39ppm

H2

ppm

CH4

ppm C2H4 ppm

C2H2 ppm

C2H6 ppm

CO ppm

CO2 ppm

Acidity, kgKOH/g

DDF


1 110 12.7 15.8 6.3 0.9 13.6 37.2 3720 0.013 0.001

134 97.0 304.0 23.3 10.5 1.1 17.0 46.2 3690 0.009 0.001

269 11.1 28.3 14.1 1.7 22.1 40.0 4020

346 82.0 16.1 32.9 15.7 2.0 26.1 42.3 4310


1 112 14.0 17.2 7.1 1.0 14.8 40.3 4040 0.008 0.001

134 97.0 12.5 21.4 10.9 1.0 17.4 35.4 3600 0.009 0.001

346 88.8 24.4 33.5 16.2 1.9 26.3 43.9 4370


1 110 12.4 18.0 7.4 1.1 15.5 41.5 4230 0.008 0.001

134 99.0 13.8 21.5 10.5 1.1 16.8 37.9 3550 0.004 0.001

346 86.6 15.8 34.3 17.0 2.1 28.0 41.7 4550

QL : quantification limit

Laboratory investigations: Oil stray gassing

On laboratory scale correlations of gases production to other oil parameters can be seen more easily. In order to improve understanding of this phenomenon, different tests were performed, including stray gassing test described in CIGRE TB 296. Stray gassing of oils in general is related to oil thermal and oxidation stability and it is correlated to production of hydrogen, hydrocarbon gases (mainly methane, ethane) and carbon oxides. It was well supported with results of different investigations that oxygen promotes the stray gassing effect. These gases are products of oil oxidative degradation and production of gases is followed by consumption of oxygen.

Uninhibited oils were observed to consume more oxygen and generate more stray gasses than inhibited oil (table 9a) [59]. In inhibited oils saturated hydrocarbon gases are not produced, or in minor amounts, along with minor production of carbon oxides, due to higher oil oxidation stability (Table 9b and 9c). The more oil is refined, the less there is production of gases (Tables: 9 a, 9b, 9c). When Irgamet® 30 and Irgamet® 39 were added to the oil which were subjected to stray gassing test acc. to CIGRE TB 296 they were observed to cause production of high amounts of hydrogen in the oil. Irgamet® 30 was found to produce higher amount of hydrogen than Irgamet® 39 [59].


Page 65

Generation of hydrogen can be explained by chemical reactions of benzotriazole molecules, i.e. elimination of hydrogen from benzotriazole molecule and substitution with electrophilic group, i.e. carbonyl compounds (aldehydes and ketones) formed during oil oxidation (Figure 63) [16], [57]:

Figure 63 Generation of hydrogen by elimination of hydrogen from benzo triazole molecule

Table 9a Stray gassing of uninhibited oil with added DBPC, Irgamet® 30 and Irgamet® 39

Hyvolt I

Neat 0.27% BHT added 100 PPM Irgamet 30 100 PPM Irgamet 39

Temp. 20oC 120oC 20oC 120oC 20oC 120oC 20oC 120oC

Time 0 After 16 h 0 After 16 h 0 After 16 h 0 After 16 h

H2 <5 214 <5 213 <5 2249 <5 1079

O2 28559 234 36970 7801 28559 203 28854 314

CO <25 136 <25 296 <25 161 <25 200

CO2 <25 201 <25 475 <25 433 <25 277

CH4 <1 68 2 8 <1 132 <1 190

C2H2 <1 <1 <1 <1 <1 <1 <1 <1

C2H4 <1 41 <1 55 <1 30 <1 32

C2H6 <1 82 <1 <1 <1 134 <1 190


Page 66

Table 9b Stray gassing of inhibited oil with added DBPC, Irgamet® 30 and Irgamet® 39

Hyvolt II

Neat 100 PPM Irgamet 30 100 PPM Irgamet 39

Temp. 20 oC 120 oC 20 oC 120 oC 20 oC 120 oC

Time 0 After 16 h 0 After 16 h 0 After 16 h

H2 <5 <5 <5 545 <5 420

O2 30319 28200 26217 21403 26217 23812

CO <25 <25 <25 47 <25 56

CO2 <25 33 <25 101 <25 415

CH4 <1 <1 <1 <1 <1 <1

C2H2 <1 <1 <1 <1 <1 <1

C2H4 <1 <1 <1 <1 <1 <1

C2H6 <1 <1 <1 <1 <1 <1

Table 9c Stray gassing of inhibited oil with added DBPC, Irgamet® 30 and Irgamet® 39

Hyvolt III

Neat 100 PPM Irgamet 30 100 PPM Irgamet 39

Temp. 20 oC 120 oC 20 oC 120 oC 20 oC 120 oC

Time 0 After 16 h 0 After 16 h 0 After 16 h

H2 <5 <5 <5 555 <5 350

O2 30397 30334 26183 22664 25949 22433

CO <25 <25 <25 58 <25 49

CO2 <25 34 <25 113 <25 107

CH4 <1 <1 <1 <1 <1 <1

C2H2 <1 <1 <1 <1 <1 <1

C2H4 <1 <1 <1 <1 <1 <1

C2H6 <1 <1 <1 <1 <1 <1

Stray gassing was also observed to be present in oxidized oils after addition of metal passivator, Irgamet® 39 (Figure 64). Addition of inhibitor, DBPC conferred to reduced stray gassing of oil with metal passivator (Figure 64).


Page 67

Figure 64 Development of gases in aged oil, with added inhibitor and metal passivator during

heating at 80°C

The direct dependence of stray gassing with Irgamet® 39 concentration and nonlinear increase of gas production in the oil has been demonstrated in a study [55]. Experiments were performed at transformer operating temperatures of 80°C during four weeks. Figures 65 and 66 show rapid growth of hydrogen and carbon monoxide in the first stage (1 week at 80°C) and the subsequent gas production settlement (a plateau is reached).

Figure 65 Production of hydrogen in presence of Irgamet® 39 (100 and 500 ppm) at 80°C

H2 (Metal passivator 500 ppm)

H2 (Metal passivator 100 ppm)


Page 68

Figure 66 Production of carbon monoxide in presence of Irgamet® 39 (100 and 500 ppm) at

80°C

Impact of metal passivators on paper ageing markers

Owing to the limited number of submitted cases for this survey, probably due to maintenance practices and short period after addition of metal passivator of the survey, there were limited data points for furan and Irgamet® 39 concentrations following passivation. Units having metal passivator added via machine for oil reconditioning and cases of oil change and addition of metal passivator were not taken into consideration, as oil reconditioning process or oil change will cause a significant decrease of 2-furfural (2-FAL) values in the oil. This served to reduce the amount of data further.

There were scant reports of slight changes in 2-FAL concentrations in the oil after addition of IR 39 (Figures 67a and 67 b).

Figure 67 a. Changes of 2-FAL of 50 MVA, 36/11 kV transformer; blue line- Ir®39 concentration,

light blue-temperature, red-2-FAL concentration.


Page 69

0

50

100

150

200

250

0,370,370,380,380,390,390,400,400,410,410,42

I39

(m

g/k

g)

2-F

AL (

mg

/k

g)

Date

2-FAL and I39 vs Sampling Date

2-FAL

I39

0.00

0.50

1.00

1.50

2.00

2.50

3.00

10/08/2

010

26/02/2

011

14/09/2

011

01/04/2

012

18/10/2

012

06/05/2

013

22/11/2

013

10/06/2

014

27/12/2

014

Date

2-F

AL

(mg

/kg

)

0

50

100

150

200

250

I39

(m

g/k

g)

2-FAL

I39

Figure 67 b. Changes of 2-FAL of GSU units in HHP

Variations of 2-FAL values were observed, which is typical for variations in working temperatures. 2-FAL trends were observed to be opposite to the temperature change, most probably caused by slow 2-FAL migration between oil and paper.

There were cases reported with increasing and decreasing trend of 2-FAL at relatively stable temperatures. This can be explained by adsorption effects and changed partition on one side and consumption of 2-FAL (substitution of hydrogen with 2-FAL as electrophylic compound in metal passivator molecules, see figure 63) in reactions of metal passivator degradation, when increased production of hydrogen in the oil can be an indicator of this reaction.

It can be summarized that in large majority of the cases no significant changes in furans concentration in the oil were observed after addition of metal passivator, especially taking into consideration effects of furans partition between oil and paper at working temperatures. In analyzing these effects care must be taken due to frequently applied maintenance activities, such as oil change and oil reconditioning/reclaiming.

Conversely, according to the results of accelerated laboratory ageing experiments, in some oils containing metal passivator an increase of furan in oil concentration was observed after accelerated heating tests (modified or IEC 62535 set up) compared with the same oils without metal passivator (Figure 68). An increase of 2-FAL concentration in the oil was not linked to a significant decrease of DP values of the paper, compared with DP of the paper tested with oil without metal passivator added (maximum difference in DP was approx. 40) [16].


Page 70

200

300

400

500

600

700

800

900

1000

1100

1200

initial 3 days 6 days 9 days 12 days

DP

Oil 1Oil 1+ IR39Oil 2Oil 2 + IR39Oil 3Oil 3 + IR39Oil 4Oil 4 + IR 39

0.00

5.00

10.00

15.00

20.00

25.00

30.00

initial 3 days 6 days 9 days 12 days

2-FAL, ppm

Oil 1Oil 1+ IR39Oil 2Oil 2 + IR39Oil 3Oil 3 + IR39Oil 4Oil 4 + IR 39

Figure 68 Change of 2-FAL concentrations in different corrosive oils before and after addition of

metal passivator during IEC 62535 ageing test set up for 12 days, wet paper at 140°C

Addition of metal passivator did not change the general behaviour, but participated in competitive adsorption in the paper. The curve of 2-FAL rise had the same pattern, regardless of the presence of metal passivator (figure 69). Absorption of metal passivator in the paper may interfere with equilibrium of furans in paper/oil system and change of 2-FAL in the oil. However, these results were obtained after severe accelerated ageing tests at high temperatures of 120°C and 140°C and this effect is not expected to be seen in a similar order of magnitude for regular service conditions [16].

DP

300

400

500

600

700

800

900

1000

0 10 20 30 40 50Time (days)

DP

Uninhibited

Uninhibited and Irg39

Inhibited

Inhibited and Irg39

2FAL

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 10 20 30 40 50Time (days)

Co

nc

pp

m

Uninhibited

Uninhibited and Irg39

Inhibited

Inhibited and Irg39

Figure 69 Change of DP and 2-FAL during ageing of non-corrosive oils with and without metal

passivator in non-breathing, Argon purged conditions with dry paper at 120°C


Page 71

4.2 Oil change: Efficiency and Side Effects

Only a very limited number of transformers were subjected to oil change to reduce the risk of copper sulphide formation (4%), this is most likely related to the economics of the option as it is a relatively simple maintenance practice that was widely applied in the 1980’s on transformers filled with PCB contaminated oils. These experiences demonstrated that residual oil volume can be kept within the range of 5-10%. Experiences from the field indicate that a simple (single) rinse of the bottom of the tank with a small extra-amount of unused oil as well as the use of the hot-spray technique to rinse both the tank and the windings is adequate. Also the equipment design plays a dominant role for the effectiveness of the action, for instance, the amount of residual oil trapped in the tank can be relatively high if the oil drain valve is not located at the tank bottom. The following table 10 and related figure 70 present a case history of a Brazilian 500 kV shunt reactor that in 2005 underwent an oil change after 15 months of operation; it has been in service since that time without any signs of thermal instability [51].

Other experiences from the field indicate that residual corrosiveness may appear as a consequence of incomplete rinsing of the active part. Effects of residual corrosiveness are usually weak, but may vary with the amount of residual oil and concentration of corrosive sulphur compounds in original oil.

Table 10 A case of a transformer before and after oil change

Time (months) Action Corrosiveness Test (ASTM D1275-B code) DBDS (mg/Kg)

0 Start-up CORROSIVE (4b) 165

12 CORROSIVE (4b) 131

14 CORROSIVE (4b) 110

15 Oil change NON CORROSIVE (1a) 5

24 NON CORROSIVE (1a) 6

32 Still in service NON CORROSIVE (1a) 8

0,00

0,25

0,50

0,75

1,00

Start-up Oil change Still inservice

0 12 14 15 24 32

operation time (months)

p.u.

CorrosivenessTest (ASTMD1275-B code)

DBDS

Figure 70 Decrease of oil corrosiveness and DBDS content after oil change


Page 72

4.3 Removal of corrosive sulphur from oil in service

Several different techniques are available and have been applied on-site and on-line to remove copper sulphide-forming sulphur from the oil, such as:

• Oil reclamation with adsorbents [53], [60], [61].

Efficiency of different techniques based on absorption of reactive sulphur compounds may vary substantially, depending on type and amount of adsorbent used, reactivation procedures, duration of treatment and logistics. It is noteworthy to mention, that longer treatment times are usually needed than for usual reclamation processes applied for removal of oil ageing products, in order to efficiently remove all corrosive sulphur compounds from the oil. Besides contact time, adsorbent capacity and selectivity for removal of sulphur compounds are crucial operational parameters. In some cases, if the performance of adsorbent is not known, checking the absence of contamination of adsorbent with reactive sulphur (elemental sulphur) is recommended, through lab scale reclamation.

• Chemical treatment combined with reclamation [16], [51], [63].

These techniques may include application of reagents for chemical conversion of sulphur compounds together with the use of natural or synthetic adsorbents, in simultaneous or consecutive chemical conversion and adsorption of sulphur compounds from the oil. Processes similar to PCB decontamination technologies were also applied on-site with success [16], [63].

Other processes, such as liquid-liquid extraction and silver nitrate process are highly efficient for removal of various sulphur compounds from the oil, but still not yet available for on-site treatment [64].

Besides removal of reactive sulphur species, common feature of all mentioned processes is that they improve oil properties to as new condition.

4.3.1 Oil Reclamation

Several oil reclamation or regeneration processes applied on-site have been found to be successful in removal of corrosive sulphur from the oil [60], [61]. It is now beyond doubt that reclamation using reactivatable clay is a successful method for removing corrosive sulphur, but it sometimes takes longer than a typical reclamation used for removal of oil ageing products. This depends on the condition of the oil and sulphur concentration. There were experiences with oils becoming more corrosive after reclamation, but mostly to silver. Where oil is found to be corrosive to silver, it may also be cleaned by this method (see Figure 72).

An example of oil reclamation using an on-line process with reactivating adsorbent in removal of DBDS of a GSU (190 MVA) with 60 t of oil is shown in figure 71 [60], [61].


Page 73

Figure 71 Decrease of DBDS concentration in the oil vs. number of circulations A case of regenerated oil in 2007, with a rig of poor design resulted in sulphur contamination and destruction of silver-plated selector contacts (Figure 72). Successful re-treatment of the oil was performed in 2011 (Figure 72).

Figure 72 Regeneration with reactivating adsorbent applied to the removal of free sulphur from

transformer

It should be noted that reclaiming applied for the removal of corrosive sulphur is also always expected to remove ageing products to such an extent that the oil will be practically in as-new condition.


Page 74

4.3.2 Chemical treatment of the Oil

Processes applied for removal of corrosive sulphur from mineral oil based on chemical treatments were founded on the experiences learned in the removal of PCB from contaminated oils. Among the units in which the oil was chemically treated, none rebounded in the condition of positive corrosiveness of the oil (according to IEC 62535 and ASTM D 1275 B) [51], [62].

Moreover, a major percentage of the oils exhibited an improvement in the chemical properties and a reduction of the dielectric losses after the applied process.

The following table 11 and the related figure 73 show the trend of chemical and physical parameters before and after the selective chemical process applied on a 15 MVA transformer.

Results shows that the concentration of DBDS was reduced after the treatment to a value below the detection limit (5 mg/kg) and the concentration appears to be constant in the long term (Table 11). As a result of the removal of DBDS, the corrosiveness of the oil, measured according to Method ASTM D 1275 B, was reduced from the initial tarnish level of 4a to the final value of 2b; the condition of non-corrosiveness was maintained over the 4 years of monitoring (Figure 73). Corrosiveness tests based on IEC 62535 and DIN 51535 were also carried out on the oil samples before and after treatment, with positive and than negative results respectively. The DDF value of the oil was reduced by the treatment, as a consequence of the removal of polar compounds other than DBDS, and its subsequent growth with time is in line with the value before treatment. Acidity was reduced to undetectable values and it still remains below the value before treatment. This is particularly interesting considering that the oil was not re-inhibited after the removal of DBDS, whose antioxidant action was evidently not the sole contribution to the oil’s resistance to oxidation.

Table 11 A case of transformer before and after chemical treatment of the oil

Time

(months)

Action Corrosiveness test

(ASTM D1275-B)

DBDS

(mg/Kg)

Acidity (mg

KOH/g oil)

BDV

(kV)

DDF

0 CORROSIVE (4b) 180 0,036 70 0,012

6 CORROSIVE (4a) 170 0,041 75 0,015

18 Chemical treatment NON CORROSIVE (2c) <5 <0.01 75 0,003

30 NON CORROSIVE (2c) <5 <0.01 58 0,008

42 NON CORROSIVE (2c) <5 0,010 70 0,009

60 NON CORROSIVE (2c) <5 0,015 72 0,010


Page 75

0,0

0,3

0,5

0,8

1,0

depolarization

still in service

0 6 18 30 42 60

months

p.u.

Corrosivenesstest (ASTMD1275-B)DBDS

Acidity

BDV

DDF

Figure 73 Decrease of oil corrosiveness, DBDS concentration after chemical treatment of the oil

4.3.3 Side Effects

In recent years, from 2001 with some reclaimed oils, certain rigs and type of adsorbents problems after treatment were reported which have been linked to silver corrosion (DIN 51353, silver corrosion test positive) [60]. Conversion of certain sulphur compounds into more reactive forms coupled with incomplete absorption of these species by used adsorbent might have caused corrosion to silver. These effects were frequently observed with units having oils rich in sulphur, mostly old uninhibited oils, but were not typically corrosive according to IEC 62535 prior to reclamation [53]. Oils rich in sulphur in general have higher potential to produce reactive sulphur compounds under certain conditions.

The problem may be exacerbated by design weaknesses of some reclamation rigs and it would appear that certain clay batches can result in an increase in corrosiveness to silver regardless of the rig. It may also be the case that some corrosiveness to silver is caused during all reclamation process but that the corrosive compounds are removed during the process and prior to complete reclamation so it is not normally seen. This emphasises the importance of carrying out complete reclamation until the oil has been restored to close to ‘as new’ parameters and checked for absence of reactive sulphur species, rather than performing the task for a set period and assuming that all will be well.

After oil reclamation process total sulphur content of the oil is not reduced significantly. This means that oil has enough sulphur left which can be converted to reactive sulphur at high temperatures. Reactive sulphur compounds, i.e. elemental sulphur may be formed from various sulphur compounds at temperatures above 200°C and even from “cleaned/treated” oil, free of DBDS at temperatures above 300°C, during reactivation of adsorbent or at any stage of the process where high temperatures are evolved [25], [27], [65].

At temperatures above 250-300°C catalytic cracking of the oil on hot metal oxides surfaces can take place, followed by formation of unsaturated hydrocarbons, ethylene, propylene, butane, elemental sulphur and other reactive sulphur compounds. There is even the possibility of gaseous combustion and pyrolysis products reacting to form free sulphur, in particular from SO2 and H2S according to the Claus reaction (which is catalyzed by the activated bauxite which is used in most equipment). The oil may be non-corrosive prior reclamation, but is usually rich in sulphur and may contain a substantial total amount of disulphides. Therefore, where clay is reactivated prior to reuse, the reactivation step will result in temperatures in the range 600°C to 900°C being reached and any liquid products from this will be very high in elemental sulphur and it may be possible for this to be introduced back into the reclamation process, unless steps are taken to prevent it. These corrosive sulphur compounds may be generated during different stages of the process: during oil contact with adsorbent when oil is passing through the


Page 76

fixed column adsorbent bed, during reactivation process of adsorbent when oil is in contact with hot clay and during oil storage in buffer tanks. Example of silver corrosion induced by oil reclamation was shown in Chapter 3.1.3 (page 35, Figure 41).

Figure 74 Development of free sulphur during a treatment with reactivating sorbent.

Results presented at Figure 74 showed that some elemental sulphur S8 was liberated after the first reactivation, but was re-adsorbed during the continued treatment. The case reported in Chapter 3.1.3 (page 31, Figure 35) shows a similar pattern, as reflected in DIN 51353 silver strip test results [53].

Incomplete removal of reactive sulphur species which have been in the oil from the beginning or might have been created during reclaiming process from non-corrosive oil can be overcame by longer treatments in order to ensure their removal from the oil and obtain good results.

Elemental sulphur (S8) can be detected and quantified using Gas Chromatography with Electron Capture Detector (GC-ECD). At Figure 75 chromatogram of oil free of elemental sulphur (S8), reclaimed oil containing elemental sulphur (S8) and oil spiked with 40 ppm of elemental sulphur is shown.


Page 77

Figure 75 Chromatogram (GC-ECD) of oil that was not reclaimed (lower chromatogram), after

reclaimed with a faulty rig (middle chromatogram) and sulphur-free oil spiked with 40 ppm of

free sulphur (top chromatogram)

Another side effect observed after oil reclamation was elevated gassing, i.e. rise of ethylene (Figures 76), as reported when certain types of clays were used [53]. It is not clear how different types of adsorbents influence the performance regarding appearance of side effects, bounce back corrosion and gassing, usually demonstrated as rise of ethylene, but some presumptions can be made. Some of the clays have been compared by their chemical composition and it was found out that they were very similar in chemical composition (Aluminium oxides), but differences in performance could be due to difference in morphology, micro-structure, or some unevenly distributed components or contaminants [53].

Elemental sulphur, other lower molecular weight sulphur compounds, ethylene and other unsaturated hydrocarbons may be formed during oil reclamation, as products of thermal or catalytic oil cracking, at temperatures above 300°C during reactivation of adsorbent from any mineral insulating oil, regardless of oil corrosiveness. Certain types of clays, in particular alumo-silicates are catalysts for cracking hydrocarbons and are used for such purposes in Petrochemical Processing [65]. If remained in oil after reclamation, elemental sulphur will easily form silver sulphide deposits on OLTC’s silver plated contacts during transformer service. This will cause the increase of contact resistance and consequently overheating of contacts and rise of ethylene in the oil (frequently observed in practice) [39]. For this reason oil reclamation process must be checked for absence of sulphur corrosive to silver by DIN 51353 test in order to prevent elemental sulphur to be introduced in the oil.

On the other hand, rise of ethylene was observed in reclaimed oils of transformers in service without corrosive sulphur problems. This was reported in countries applying oil reclamation extensively (UK, Canada, Portugal, Norway,…). It seems that oils are more prone to form ethylene after reclamation, possibly due to changed chemical structure of the oil, but it is still not clear how reclamation process affects the change of gassing pattern of the oil after it has been treated with activated adsorbents. This subject is matter of investigation in CIGRE JWG A2/D1 47.


Page 78

Figure 76 Typical ethylene traces for transformers after oil reclamation (left) prior to clay change

in 2005 (right) after clay change in 2005

An example of incomplete removal of DBDS is shown on Figure 77. This case illustrates the importance of a mandatory check of oil corrosiveness at the end of the process and additionally shows the effect of added inhibitor to the change of copper sulphide deposition pattern. Oils where copper sulphide deposits occurred on copper during tests prior to reclamation were found to produce deposits on the paper after improper reclamation.

Figure 77 incomplete removal of DBDS during oil reclamation - oil corrosive sulphur test prior

reclamation, left and after reclamation and inhibition, right.

Other Potential Techniques For Removal of Corrosive Sulphur

Solvent extraction process was demonstrated to be highly efficient in removal of corrosive sulphur compounds, including significant extraction/reduction of aromatic and sulphur compounds from the oil, indicating significant degree of oil refining [64]. This kind of re-refining processes with solvent recycling could be suitable for off-site application for treatment/recycling of corrosive and waste oils. Processes used for removal of PCB, with elemental sodium or sodium hydroxide dispersed in the organic phase were applied on a pilot scale and on-site with high efficiency in removing DBDS and mercaptans from the oil [16], [63]. Silver nitrate bonded on silica was used on laboratory scale with success, but high costs would be a limiting factor for on-site application.


Page 79

4.3.4 Cost Effective Risk Mitigation Strategies

Mitigation is the preferred term out of awareness that true remediation is not achievable. The common standpoint for all available mitigation techniques is that none of the existing techniques can act on already contaminated windings and bare metal surfaces.

Addition of metal passivator into the transformer, chemical-physical treatment of the oil and oil replacement are the current techniques applied to tackle the damage induced by corrosive oil.

Overall, the statistics speak largely in favour of addition of metal passivator (> 85% in present survey). Due to its high efficiency, low-cost impact and quite simple maintenance procedure which can be easily applied by substation technicians it is the most widely applied countermeasure to mitigate the negative effects of corrosive sulphur compounds, but in some extreme cases cannot be quoted as a long term countermeasure against corrosiveness. It requires a very limited outage time of the transformer, or metal passivator can be added via machine for oil reconditioning in on-line mode. Even if the addition of metal passivator gave satisfactory results in most cases, in a minor but significant number of transformers it was followed by a breakdown. Most probably this can be attributed to late addition of metal passivator and already contaminated windings by conductive deposits to an unacceptable level.

Oil change, if properly done, appears to be most robust procedure based on the long-term stability of oil’s properties, but is more expensive and is the least environmentally sound option. It can be considered a normal maintenance practice, but it is time consuming since the transformer outage is mandatory and it requires many operational steps (draining, rinsing, final filling and conditioning). A number of transformers underwent oil change to reduce the corrosiveness, and none have suffered breakdown afterwards. However, it must be noted that the oil change effectiveness is strongly dependent on equipment design and it has a potential negative impact on environment since it produces a large volume of liquid waste.

The removal of corrosive compounds by means of chemical-physical treatment of the oil (reclaiming and other techniques with active reagents) was found to be effective in reducing the corrosiveness of oils to an acceptable level. All of them require special apparatus and sometimes unconventional solid absorbents/reagents, so usually they are performed by specialized companies. Typically the process is one to three weeks long, depending on the size of transformer and concentration of corrosive sulphur compounds, but it can be operated on-load with a very limited outage time.

High efficiency and stability can be achieved with sufficiently long treatments and stringent procedures to avoid potential bounce-back corrosion after treatment. This problem can be overcome by prolonging the treatment. Processes which involve chemical treatment and combination of reagents and adsorbents, similar to PCB dechlorination processes were also applied on-site with success.

The following table 12 summarizes the advantages and the drawbacks of the three mitigation strategies.

Table 12 Mitigation techniques ranking

CATEGORY METAL PASSIVATOR

ADDITION OIL CHANGE OIL TREATMENT

SIMPLICITY ☺☺☺☺ ☺☺☺☺ / ��

TIME CONSUMING ☺☺☺☺ ☺☺☺☺ / ��

ON LOAD APPLICATION ☺☺☺☺ Not applicable ☺☺☺☺

EFFICIENCY ☺☺☺☺ / �� ☺☺☺☺ / �� ☺☺☺☺

OIL PROPERTIES RESTORATION �� ☺☺☺☺ ☺☺☺☺

LONG TERM PERFORMANCE �� ☺☺☺☺ ☺☺☺☺

ENVIRONMENTAL Unknown �� ☺☺☺☺

COST ☺☺☺☺ �� ☺☺☺☺ / ��


Page 80

Practices and regulations related to waste, used and waste oil disposal varies from country to country and evaluation of costs is dependant on other parameters, therefore precise cost-effectiveness evaluation should be performed on case by case basis.

The final decision about most suitable mitigation technique is strictly related to other aspects such as: evaluation of transformer risk and economical convenience (asset age and residual value, strategic relevance, etc.).


Page 81

4.4 Recommendations for Mitigation

Guidance and recommendations for mitigation techniques are given on the basis of WG surveys, gained experiences from the field, supported with research findings and improved understanding of the mechanism of copper sulphide formation.

Depending on the condition of transformer, paper/oil ageing degree, position in the system, service conditions (loading regime, temperatures, electrical stresses) different mitigation approaches may be applied. Case by case evaluation and analysis of units with specific problems, defects or suspected faults should be made.

I. Addition of metal passivators (Irgamet® 39) would be an efficient solution, especially if performed in the early days of service with corrosive oil. In order to make a decision whether to perform a second addition of metal passivator, monitoring oil corrosiveness and concentration of reactive sulphur compounds is important:

• If the total disulphide content is depleted to a value below 5 mg/kg, or the DBDS content is below 10 mg/kg, than there is no need to apply a second addition of metal passivator, due to low probability of failure (oils are either non-corrosive or deposit traces of copper sulphide acc. to IEC 62535).

• In all other cases a second addition of metal passivator should be performed

• If after second addition of metal passivator, the passivator depletes rapidly from the oil (acc. to IEC 60422 “poor” condition), while concentration of DBDS in the oil is above 10 mg/kg other mitigation actions are recommended, such as removal of corrosive sulphur from the oil, or oil change as long-term solutions.

Transformers with oils corrosive to silver (DIN 51353) can not be mitigated by addition of Irgamet® 39, as according to service experiences Irgamet® 39 was found to be inefficient to counteract silver corrosion.

II. Removal of corrosive sulphur from the oil, or oil change are recommended as long-term solutions in the cases of highly stressed and fully loaded units, with high winding temperature and intensive oxidative degradation such as:

• Units with constant high load or frequent changes of load (usually shunt reactors and industrial applications),

• Units with frequent and intensive electrical stresses,

• Units with indications of overheating (cooling defects, thermal faults -DGA),

• Units with intensive oil oxidation and consumption of oxygen, and combination of these conditions

• Units with oils corrosive to silver acc. to DIN 51335 (addition of metal passivator – Irgamet 39® was found not to be efficient).

The choice of technique will be dependant on the condition of transformer, criticality and cost-benefit evaluation.

Where oil is found to be corrosive in transformers that are considered to be close to the end of their useful life because of aged paper condition, time in service or redundancy it may not be cost effective to carry out expensive mitigating actions. Where the oil is aged, even less expensive treatments such as addition of metal passivator may not be efficient and worthwhile. Reduction of operating temperature through reduced load or forced cooling may be more effective where these options are available. It would be advisable to prepare spare unit, but this concern should be considered by the asset management strategies in order to redesign the engineering decisions and the eventual capital replacement plans. Guidance for mitigation actions based on transformer condition assessment is given bellow in a form of revised flow chart from TB 378.


Page 82

Figure 78 Copper sulphide condition assessment & mitigation action flow chart

Note 1: Elevated values of H2 in DGA can be attributed to stray gassing due to metal passivator degradation; this can interfere with diagnostics; sometimes increase of other gases, like: CO, CO2, hydrocarbons (C2H4, CH4,…) were observed after addition of metal passivator.

Note 2: Transformers with CTC are at lower risk for copper sulphide formation, but not completely safe (null risk), due to presence of joints, leads, …etc.; certain transformer applications are more affected, due to presence of large surfaces of unprotected copper and severe working regime, thermal/electrical stresses (industrial rectifiers,…).

Note 3. Probability here is related to the risk that significant Copper Sulphide formation is going on. The scheme does not deal with the situation when the insulation is already seriously affected by sulphide deposits.

Note 4: Action 1 in all three risk categories (low, medium and high) is universal recommendation in addition to other proposed actions; for risk category “HIGH” action 1 is of big importance until other proposed mitigation actions are applied.

Is the oil corrosive

according to

IEC 62535 ?

Are copper conductors

fully enamelled ?

YES

Is there any symptom of local or

diffused overheating from DGA ?

Does the oil have a low oxygen content

(due to atmosphere segregation

or

oxygen consumption) ?

NO

Is the equipment

passivated ?

NO

Is the equipment

passivated ?

NO

Probability of copper

sulfide deposition:

NULL


sulfide deposition:

LOW


sulfide deposition:

MEDIUM


sulfide deposition:

HIGH

NO

Is DBDS content in oil

> 20 mg/kg ?

or

Is total disulfides +

mercaptans

content in oil

> 5 mg(S)/kg ?

YES

Was the equipment

passivated during the

1st year of service ?

YES

YES

YES NO

YES

NO

Is the equipment

passivated ?

NONO

When was the

Equipment passivated ?

YES

As

new

YES

During 1st year

of service

After 1st year

of service

NO

YES

actions actions actions actions

1) Respect the loading

guide

2) If a metal passivator is

added keep under

monitoring passivator’s

concentration

1) Avoid overloading

2) Add a metal passivator

if not already done or

change/reclaim the oil

3) Keep under monitoring

passivator’s

concentration if present

No action 1) Reduce the thermal stress

by decreasing the loading

or/and by improving the

cooling

2) Change/reclaim the oil or

passivate the oil as a

temporary action if not

already done (see note X

under the FC)


passivator’s concentration

if present

Is passivator

concentrations

stable in time ?

YES

NOIs passivator

concentrations

stable in time ?

YES

NOAfter change/reclaim,

is the oil

still corrosive ?

NO

YES

Start from hereAfter reading XXXXX

Read Note 2!!

Is the transformer highly loaded /

with high thermal range ?YESNO

Is the oil corrosive

according to

IEC 62535 ?

Are copper conductors

fully enamelled ?

YES

Is there any symptom of local or

diffused overheating from DGA ?

Does the oil have a low oxygen content

(due to atmosphere segregation

or

oxygen consumption) ?

NO

Is the equipment

passivated ?

NO

Is the equipment

passivated ?

NO


sulfide deposition:

NULL


sulfide deposition:

LOW


sulfide deposition:

MEDIUM


sulfide deposition:

HIGH

NO

Is DBDS content in oil

> 20 mg/kg ?

or

Is total disulfides +

mercaptans

content in oil

> 5 mg(S)/kg ?

YES

Was the equipment

passivated during the

1st year of service ?

YES

YES

YES NO

YES

NO

Is the equipment

passivated ?

NONO

When was the

Equipment passivated ?

YES

As

new

YES

During 1st year

of service

After 1st year

of service

NO

YES

actions actions actions actions

1) Respect the loading

guide

2) If a metal passivator is

added keep under

monitoring passivator’s

concentration

1) Avoid overloading

2) Add a metal passivator

if not already done or

change/reclaim the oil


passivator’s

concentration if present

No action 1) Reduce the thermal stress

by decreasing the loading

or/and by improving the

cooling

2) Change/reclaim the oil or

passivate the oil as a

temporary action if not

already done (see note X

under the FC)


passivator’s concentration

if present

Is passivator

concentrations

stable in time ?

YES

NOIs passivator

concentrations

stable in time ?

YES

NOAfter change/reclaim,

is the oil

still corrosive ?

NO

YES

Start from hereAfter reading XXXXX

Read Note 2!!

Is the transformer highly loaded /

with high thermal range ?YESNO


Page 83

5 MONITORING AND MAINTENANCE PROCEDURES

IEC 60422 Oil Maintenance Guide states three standardized tests: IEC 62535, DIN 51353 and ASTM D 1275 B which can be used to asses oil corrosiveness. However, it is considered enough to perform IEC 62535 and DIN 51353, to adequately assess oil propensity to deposit copper sulphide in the paper wrapped conductors and on copper surfaces or for silver sulphide formation on silver plated surfaces.

Guidance for monitoring of units in service with metal passivator added is also defined in IEC 60422, recommended values of metal passivator concentration in the oil are given, with limit values (“poor” condition) when second addition of metal passivator should be performed, or another mitigation action.

Other tests methods may serve to improve diagnostics of corrosive oils in service, such as: determination of DBDS using IEC 62697 and determination of total amount of disulphides, mercaptans and elemental sulphur (currently under development within IEC TC 10 WG 37).

Note: Monitoring of metal passivator concentration of oils in service in defined in table 5. of IEC 60422 standard Ed.4/2013; there is an error in table 5, for “fair” condition.

Instead of: metal passivator concentration between 50 and 70 mg/kg, or metal passivator concentration < 70 mg/kg, with rate of depletion > 10 mg/kg/year,

it should state: metal passivator concentration between 50 and 70 mg/kg, or metal passivator concentration > 70 mg/kg with rate of depletion > 10 mg/kg/year.

Recommendations for oil treatment processes

Stringent procedures and on board corrosive sulphur testing during oil reclamation are necessary and strongly recommended in order to monitor the process and ensure removal of all corrosive sulphur species from the oil, including those which may be produced during the process. Monitoring of DBDS content may be useful, though qualitative tests during the treatment should be sufficient to ensure that the treatment is completed.

During on-site oil reclamation processes the following actions/tests should be performed:

• Thorough rinse of transformer active part from residual corrosive oil, by circulating oil through heated transformer active part

• On board corrosive sulphur tests at the end of oil treatment (IEC 62535 and DIN 51353)

• Optionally, determination of DBDS in the oil during or after treatment (for oils containing DBDS)

Re-inhibition with DBPC is recommended to prolong oil service life, after the oil is verified as non-corrosive, according to IEC 62535 and DIN 51353.

In the case of oil reclamation, care must be taken to avoid cross contamination with corrosive sulphur species which may be generated from any oil during reactivating step of reclamation process, which involves treatment at high temperatures.

Laboratory trials using the adsorbent prior to on-site application are recommended to test adsorbent performance in terms of efficiency in removal of corrosive sulphur and to check absence of contamination by corrosive sulphur species.

During the first year of operation after reclamation, oil should be checked for corrosive sulphur tests (IEC 62535, DIN 51353) and DBDS concentration in the oil (if oil contained DBDS prior treatment). Afterwards, the frequency of testing can be adjusted according to usual monitoring procedures for reclaimed oils.


Page 84

6 CONCLUSIONS

Problems encountered with corrosive sulphur in mineral insulating oil are related to formation of metallic sulphides (copper and silver) in transformer active part under operating conditions, which can be the cause and contributing factor to transformer failures. Metallic sulphides deposited in the paper insulation or detached from metal surfaces significantly reduce dielectric status of transformer active part. Deposits on bare metallic surfaces can also be the cause of overheating. Investigations related to mechanism of metallic sulphides formation in this WG was related to mechanism of copper sulphide formation in solid insulation, as stated in the terms of reference.

Apart from well known and elaborated mechanisms of metallic sulphide formation on bare metal surfaces, progress has been made in understanding how copper sulphide is formed in paper. It would appear to involve the dissolution of copper, diffusion and absorption of an intermediate complex in or on paper or board, and subsequent reaction with sulphur compounds to form Cu2S and other by-products. Electrical fields seem to promote copper sulphide formation. They may play an important role in the initiating step of the reaction: formation of copper cations. This subject should be the matter of further investigation. Copper sulphide deposition on the paper resulting from detachment of fine copper sulphide particles from copper surfaces and transport to the adjacent paper layer is also proposed but the mechanism is still unknown. Temperature and concentration of reactive sulphur are the main risk factors. Oxygen is the key influencing factor that determines the rate of copper-in-oil dissolution, diffusion and absorption of intermediate copper complexes in the paper. According to service experiences and laboratory investigations copper sulphide is formed in broad range of oxygen contents, corresponding to both sealed and free breathing transformer application. Oxygen has a significant impact on the degradation mechanism of sulphur species, to modify the DBDS degradation route and this may have an impact on yield of copper sulphide produced. At lower temperatures, the risks of copper sulphide formation is lower in a high oxygen environment, while at higher temperatures (overloading conditions, localised or diffused overheating) risks of copper sulphide formation in the paper are higher at higher oxygen levels.

Risk assessment remains a difficult subject, partly because some transformers have failed after relatively small amounts of copper sulphide were formed, while in others that were dismantled for other reasons, large amounts were found that had apparently caused no harm. During scrapping and post-mortem investigations copper sulphide deposits were frequently found in the hottest areas of windings, like “hot-spot markers”. There are a few cases where transformers with low loading history and moderate working temperatures have failed due to copper sulphide deposition. Finally, during the working period of the working group cases have come to light where transformers have failed and other problems have resulted from corrosion of silver plated contacts and formation of silver sulphide, in most of these cases oil reclamation has been carried out.

Investigation of sources of corrosive sulphur coming from rubbers and gaskets showed that these materials have no corrosive potential. Major risk factors still remain temperature and concentration of reactive sulphur species, as this was common to most of the failed transformers and reactors that have operated with high winding temperatures and with oils having a high concentration of reactive sulphur compounds, regardless of the transformer preservation system, as both failures of sealed and open breathing units were reported.

There are now several well-established mitigation techniques. The addition of metal passivator to the oil is still the most commonly applied, which is likely to be related to the low cost and simplicity of its use, but it has become apparent that is has limitations. The poor stability at elevated temperatures, in less refined and aged oil is the most important drawback. Rapid depletion of metal passivator from the oil and evolution of gases after metal passivator has been added are the most common side effects (fast depletion of metal passivator in 15 % and 13% cases of units with oil stray gassing). Gassing of the oil was recognized to level off after a time, typically one to two years.

A more radical solution involves removal of the sulphur either through changing the oil, or removing the reactive sulphur from the oil in situ. If carried out properly, the long-term effects seem to be good for both options, with insignificant bounce-back effects. Several different processes are now used to remove reactive sulphur from oil. Some of the processes are based on chemical destruction of reactive sulphur compounds, while others are based predominantly on removal of these compounds from the oil, by absorption or extraction, or by combination of these processes. It has been found that care must be taken when reclaiming oil to prevent free sulphur being added to


Page 85

the oil during the process. Such sulphur contamination will require a prolonged treatment to be removed. Stringent and revised procedures, including monitoring of the corrosive sulphur on-site during reclamation have to be performed to ensure good results.

In some cases, improved cooling or reducing the load are suggested. This is of particular importance in cases of high risk of failure, when other long-term mitigation actions are still not performed.


Page 86

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[58] CIGRE Brochure 443: DGA in Non-Mineral Oils and Load Tap Changers and Improved DGA Diagnosis Criteria, December 2010.

[59] J.Rasco, E.Casserly, Stray Gassing of Refinery Streams and Transformer Oil Produced From Them, Doble Clients Conference April, 2014.

[60] M.Dahlund, et.al., Effects of on-line reclaiming on the corrosive sulphur content of transformer oil, CIGRE 2010, GCC Regional Conference.

[61] M.Dahlund, P. Lorin, P. Werle; “Effects of on-line reclaiming on the corrosive sulphur content of transformer oil”; CIGRE SC A2, A3 & B3 Joint Colloquium; Cape Town, 2009.

[62] R.Maina, V.Tumiatti, M.Pompili, R.Bartnikas, Corrosive Sulfur Effects in Transformer Oils and Remedial Procedures, IEEE Transactions on Dielectrics and Electrical Insulation, Vol. 16, No.6, December 2009.

[63] L.Lewand, S.Reed, Destruction of Dibenzyl Disulphide In Transformer Oil, 75 th Doble Client Conference, Boston 2008.

[64] J.Lukic, D.Nikolic, V.Mandic, S.Glisic, D.Antonovic, A.Orlovic, Removal of Sulphur Compounds from Mineral Insulating Oils by Extractive Refining with N-Methyl-2-pyrrolidone, Ind.Eng.Chem.Res., 2012, 51, 4472-4477.

[65] S.Parkash, Refining Process Handbook, 2003, GPV, Elsevier.

[66] Mats Dahlund, Holger Lohmeyer, "Up-date on copper sulfide mitigation techniques", Transformer Life Management Symposium 2012, September 24 - 25, 2012, Halle (Saale), Germany.


Page 90

APPENDIX 1: COPPER SULPHIDE FORMATION IN THE PAPER

Chemical Reactions

On the basis of postulated mechanism of copper sulphide formation in the paper by dissolved oil copper compounds, proposed chemical reactions are given, based on publications in peer review papers and books of organic chemistry [4], [15], [17], [18], [21], [24], [25], [26], [27], [28], [32].

Degradation of disulphides can go via two reaction pathways (DBDS as model compound):

• oxidation of sulphur atoms – route 1

• cleavage of C-S bonds – route 2

Route 1: Disulphides (DBDS in particluar) are well known secondary antioxidants. In high oxygen environment DBDS act as secondary oxidation inhibitor, it decomposes hydro-peroxides by reducing them into alcohols, while disulphide (DBDS) is getting oxidized to sulphoxides, sulphones and sulphur oxy acids [28], [31], [32]:

R2S2 + R'OOH [ ]→ 2O R2S2=O + R'OH

R2S2=O + R'OOH [ ]→ 2O R-SO2H + RSR'

R-SO2H + R'OOH [ ]→ 2O RSO3H + R'OH

Route 2: At elevated temperatures and under the impact of electrical fields, emitted electrons and high temperature cause cleavage of C-S bond [15]:

Cu + E → Cu+ + e-

e- + R-S-S-R → R-S-S- + R•

e- + R-S-S-R → R-S- + RS•

R-S- + H+ → R-SH

R-S• + •H→ R-SH

After formation of thiols (mercaptans) the reaction can than proceed as shown below.

A. Formation of copper sulphide on metal surfaces – Copper and Silver

Direct solid state reaction of thiols (mercaptans) with bare solid copper may occur [17]:

RSH + 2Cu → Cu2S + RH

At high temperatures from 200ºC to 250ºC disulphide bond can be cleaved with formation of elemental sulphur [25]:


Page 91

Created elemental sulphur can attack bare copper and silver surfaces and produce copper sulphide [3], [22]:

Cu + S = Cu2S

and silver sulphide:

Ag + S = Ag2S

B. Formation of copper sulphide in the paper insulation

Formation of copper sulphide in the paper is conducted by formation of dissolved copper complex, possibly in the form of copper hydro-peroxides, or copper ionic complexes with oxygenated hydrocarbons (peroxides and carboxylic acids) [4], [15], [18]. These compounds are diffused and absorbed in the paper, where reaction with paper absorbed sulphur compounds, i.e. thiols (mercaptans) occur:

2 ROOH + Cu2O → 2 Cu+(O2R)- + H2O

2 Cu+(O2R)- ↔ Cu + Cu2+(O2R)2

-

ROOH + Cu2+ → Cu+ + H+ + RO2•

ROOH + Cu+ → Cu2+ + OH- + RO•

Cu+(O2R)- → CuO + RO•

Cu2+(O2R)2- → CuO + RO• + RO2•

2 RO• + Cu → Cu2+ + 2 RO-

Disulphides absorbed in the paper can react with copper ions and copper oxides absorbed in the paper. Mercaptans (namely benzyl mercaptan from DBDS) created from disulphides by C-S and S-S bond react with copper to produce copper sulphide [4]:

2 RSH + Cu2O → CuRS+ H2O

RSH + Cu+(O2R)- → CuSR + ROOH

2 CuSR → Cu2S + RSR

or

2 R-SH + CuO → (R-S)2Cu + H2O

2 Cu(SR)2 → 2 CuS-R + R-S-S-R

2 CuS-R → Cu2S + R-S-R

Thiol (mercaptan) - disulphide exchange (equilibrium) is a well known process in protein chemistry and is promoted in presence of copper cations, meaning that regeneration of disulphides from mercaptans can occur [24]:

2R-SH + 2Cu2+ ↔ R-S-S-R + 2Cu+ + 2H+


Page 92

APPENDIX 2: FAILURE CASES SUMMARY

Statistical analysis for the following 28 copper sulphide linked transformer and reactor failures from 11 countries (Australia 1, Brazil 3, Israel 2, Italy 2, Montenegro 1, Portugal 2, Poland 2, UK 10, United Arab Emirates 3 and Uruguay 2), including 10 transformers removed from service before failure because of suspect condition are presented:

Case Number Year of Failure Transformer Application Failure discovery

1 2005 Shunt Reactor Several protections

2 2006 Distribution Removed


4 2007 GSU Several protections


6 2007 Transmission Several protections


8 2008 Rectifier Several protections



11 2009 GSU Removed


13 2010 GSU Removed


15 2010 Transmission Unknown


17 2010 Transmission Removed

18 2010 Transmission Several protections

19 2011 Industrial Breakdown during voltage tests



22 2012 Distribution Several protections




26 2013 GSU Removed

27 2013 Rectifier Removed

28 2014 GSU Removed

Copper and silver sulphide failures linked to: transformer application, failure type, failure cause, DBDS content, oil type, preservation system, load profile and failure discovery are presented in the following figures (78-85):


Page 93

Transformer ApplicationIndustrial

4%Shunt Reactor

11%

Transmission

25%

Rectifier

18%

GSU

35%

Distribution

7%

Figure 78 Failures vs. transformer application.

Transformer Failure Type

Mechanical

4%

Dielectric

25%

Tap-changer fault

21%

Inter-turn failure

39%

Gassing

11%

Figure 79 Transformer failure type.


Page 94

Transformer Failure Cause

Silver sulphide on

OLTC contacts

14%

Sulphur corrosion +

Abnormal solid

insulation ageing

46%

Sulphur corrosion +

Operation +

Maintenance

11%

Sulphur corrosion +

Normal solid

insulation ageing

14%

Sulphur corrosion +

Overheating fault

11%

Sulphur corrosion +

Through fault

4%

Figure 80 Transformer failure cause.

Transformer Failure and DBDS

Content

DBDS 20-50 ppm

7%

DBDS>100ppm

21%

DBDS<20ppm or

none

21%

DBDS not

measured

51%

Figure 81Transformer failure vs. DBDS content.


Page 95

Transformer Failure and Oil Type

Unknown oil

7%

Uninhibited oil

57%

Inhibited oil

36%

Inhibi ted oi l Uninhibi ted oi l Unknown oi l

Figure 82 Transformer failure vs. oil type.

Transformer failure and preservation system

Unknown

7%

Sealed

21%

Free breathing

72%

Figure 83 Transformer failure vs. preservation system.


Page 96

Transformer failure and load profile

Unknown

14%

Constant high

54%

Variable

32%

Figure 84 Transformer failure vs. loading profiles.

Transformer Failure Discovery

Removed from service

by gassing or asset

health review

36%

Unknown

3%

Failed in service by

several protections

61%

Figure 85 Transformer failure discoveries.

copper sulphide long term mitigation and...

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