Quality Confirmation Tests for Power Transformer Insulation Systems [1st ed.] 978-3-030-19692-9;978-3-030-19693-6

Table of contents :
Front Matter ....Pages i-x
Unused Mineral Insulating Oil (Behrooz Vahidi, Ashkan Teymouri)....Pages 1-11
In-Service Mineral Insulating Oil (Behrooz Vahidi, Ashkan Teymouri)....Pages 13-36
Chemical Indicators (Behrooz Vahidi, Ashkan Teymouri)....Pages 37-64
Dissolved Gas Analysis (DGA) (Behrooz Vahidi, Ashkan Teymouri)....Pages 65-73
Other Tests (Behrooz Vahidi, Ashkan Teymouri)....Pages 75-104
Back Matter ....Pages 105-107

Citation preview

Behrooz Vahidi Ashkan Teymouri

Quality Confirmation Tests for Power Transformer Insulation Systems

Quality Confirmation Tests for Power Transformer Insulation Systems

Behrooz Vahidi Ashkan Teymouri •

Quality Confirmation Tests for Power Transformer Insulation Systems

123

Behrooz Vahidi Department of Electrical Engineering Amirkabir University of Technology Tehran, Iran

Ashkan Teymouri Department of Electrical Engineering Amirkabir University of Technology Tehran, Iran

ISBN 978-3-030-19692-9 ISBN 978-3-030-19693-6 https://doi.org/10.1007/978-3-030-19693-6

(eBook)

© Springer Nature Switzerland AG 2019 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Switzerland AG The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland

Preface

Power transformer insulation is an indispensable part of a power transformer. The importance of insulation was increased over the years due to the increase in the voltage rating of transformers. Within the last decades, although research on the transformer insulation and diagnosis methods has been improved so much, the insulation of HV transformers remained more or less unchanged and for EHV and UHV transformers, the oil–paper insulation is dominant. The book in hand is the first edition and based on the oil–paper insulation. The contents of this book are divided into five chapters. The first and second chapters explain the oil insulation. The third chapter explains the paper insulation. The fourth and fifth chapters deal with the tests. The authors’ special thanks go to all readers in advance who will give us a feedback on the book. Tehran, Iran August 2018

Behrooz Vahidi Ashkan Teymouri

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Contents

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1 1 1 3 3 3 8 9 9 10 11

2 In-Service Mineral Insulating Oil . . . . . . . . . . . . . . . . . . . . . . . 2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 Oil Monitoring and Purification . . . . . . . . . . . . . . . . . . . . . 2.3 Oil Ageing and Degradation . . . . . . . . . . . . . . . . . . . . . . . 2.4 Oil Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.1 Color and Appearance . . . . . . . . . . . . . . . . . . . . . 2.4.2 Breakdown Voltage . . . . . . . . . . . . . . . . . . . . . . . 2.4.3 Water Content . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.4 Water in the Insulation System . . . . . . . . . . . . . . . 2.4.5 Acidity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.6 Dielectric Dissipation Factor (DDF) and Resistivity 2.4.7 Additives and Oxidation Stability . . . . . . . . . . . . . 2.4.8 Sludge and Sediment . . . . . . . . . . . . . . . . . . . . . . 2.4.9 Interfacial Tension . . . . . . . . . . . . . . . . . . . . . . . . 2.4.10 Particle Content . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.11 FlashPoint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.12 Compatibility of Insulating Oil . . . . . . . . . . . . . . . 2.4.13 Pour Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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13 13 13 14 14 15 15 15 17 19 20 21 22 22 23 23 23 24

1 Unused Mineral Insulating Oil . . . . . . . . . . . . . . . . . . . 1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 Mineral Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Classification of Mineral Oil Based on Application . 1.3.1 Transformers Oil . . . . . . . . . . . . . . . . . . . 1.3.2 Switchgear Oil in Low Temperatures . . . . . 1.4 Additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5 Special Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.6 Analysis of Potentially Corrosive Sulphur . . . . . . . 1.7 Oil Contamination . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Contents

2.4.14 Density . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.15 Viscosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.16 PCB . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.17 Corrosive Sulphur . . . . . . . . . . . . . . . . . . . . . 2.4.18 Dibenzyl Disulphides (DBDS) . . . . . . . . . . . . 2.4.19 Passivators . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 In-Service Oil Monitoring . . . . . . . . . . . . . . . . . . . . . . 2.5.1 Uninhibited Oil Monitoring . . . . . . . . . . . . . . . 2.5.2 Inhibited Oil Monitoring . . . . . . . . . . . . . . . . . 2.6 Time Schedule of Sampling and Testing In-Service Oil 2.7 Available On-Site Tests . . . . . . . . . . . . . . . . . . . . . . . . 2.8 Classification of Operating Oil . . . . . . . . . . . . . . . . . . . 2.9 Corrective Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.10 Purification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.10.1 Physical Purification . . . . . . . . . . . . . . . . . . . . 2.10.2 Chemical Purification (Refinement) . . . . . . . . . 2.11 Replacing Oil in Electrical Equipment . . . . . . . . . . . . . 2.12 Adding Passivators . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.13 Determining Water Concentration in the Oil . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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25 25 26 26 27 27 27 28 28 28 29 29 30 30 31 32 34 35 35 36

3 Chemical Indicators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Insulation Paper Life Determination . . . . . . . . . . . . . . . . . . . 3.3 Cellulose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Cellulose Molecular Structure . . . . . . . . . . . . . . . . . . . . . . . 3.5 Cellulosic Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6 Degree of Polymerization . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7 Oil Impregnated Insulation Paper . . . . . . . . . . . . . . . . . . . . . 3.8 Ageing of Oil Impregnated Insulation Paper . . . . . . . . . . . . . 3.9 Ageing Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.1 Pyrolysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.2 Hydrolysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9.3 Oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.10 Influence from Acids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.11 Ageing of Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.12 Oil Oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.13 Degradation Products in Oil Impregnated Insulation Systems . 3.14 Degradation Products from Cellulosic Insulation . . . . . . . . . . 3.14.1 Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.14.2 Acids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.14.3 Furans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.14.4 Carbon Oxides . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.14.5 Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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37 37 37 39 39 40 40 41 42 43 43 44 46 46 47 47 47 48 48 48 49 49 50

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3.15 Degradation Products of Oil . . . . . . . . . . . . . . . . . 3.15.1 Acids . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.15.2 Sludge . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.16 Chemical Indicators . . . . . . . . . . . . . . . . . . . . . . . 3.17 Furan Compounds . . . . . . . . . . . . . . . . . . . . . . . . . 3.17.1 Furans Origin . . . . . . . . . . . . . . . . . . . . . . 3.18 The Relationship Between DP and Furans . . . . . . . 3.19 Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.20 Furans Disadvantages . . . . . . . . . . . . . . . . . . . . . . 3.21 CO2 and CO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.22 The Combination of CO2 /CO Ratio and 2-Furfural . 3.23 Methanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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50 50 50 50 51 51 52 53 53 54 54 55 62

4 Dissolved Gas Analysis (DGA) . . . . . . . . . . . . . . . . . . . 4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 Total Flammable Dissolved Gas in the Transformer 4.3 Allowable Concentration of Gases in a Transformer 4.4 Gas Ratio Methods . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1 Dürrenberg Method . . . . . . . . . . . . . . . . . 4.4.2 Rogers Ratio . . . . . . . . . . . . . . . . . . . . . . 4.4.3 IEC Ratio Method . . . . . . . . . . . . . . . . . . 4.5 Duval Triangle Method . . . . . . . . . . . . . . . . . . . . . 4.6 Detection of Partial Discharge Using DGA . . . . . . . 4.7 Impact of DGA Accuracy on Fault Detection . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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65 65 67 67 67 68 69 69 71 72 72 73

5 Other Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2 Partial Discharge (PD) . . . . . . . . . . . . . . . . . . . . . . . . 5.2.1 Corona Discharge . . . . . . . . . . . . . . . . . . . . . . 5.2.2 Surface Discharge . . . . . . . . . . . . . . . . . . . . . 5.2.3 Discharge in Composite Insulation Materials . . 5.2.4 Electric Discharge in Cavities . . . . . . . . . . . . . 5.2.5 Electric Treeing . . . . . . . . . . . . . . . . . . . . . . . 5.3 Partial Discharge Measurement . . . . . . . . . . . . . . . . . . 5.4 Insulation Monitoring by PD Measurement . . . . . . . . . 5.5 Comparison of Electrical and Audio Detection Methods 5.6 Partial Discharge Formation in Transformers . . . . . . . . 5.7 Dielectric Response Analysis . . . . . . . . . . . . . . . . . . . . 5.8 Polarization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.9 Polarization and Depolarization Current . . . . . . . . . . . . 5.10 Insulation Spectroscopy in Time Domain . . . . . . . . . . .

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5.11 5.12 5.13 5.14 5.15 5.16 5.17 5.18

FDS Test . . . . . . . . . . . . . . . . . . . . . . . . . . . Returning Voltage Method . . . . . . . . . . . . . . Isothermal Relaxation Current . . . . . . . . . . . . Frequency Response Analysis (FRA) . . . . . . . Frequency Response Analysis Theory . . . . . . Application of FRA in Power Transformers . . FRA Test Features . . . . . . . . . . . . . . . . . . . . Frequency Response Measurement Methods . . 5.18.1 Swept Frequency Method (SFM) . . . . 5.18.2 Low Voltage Impulse Methods (LVI) 5.19 Comparison of LVI and SFM Methods . . . . . 5.20 Detectable Defects by FRA . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

Chapter 1

Unused Mineral Insulating Oil

1.1 Introduction The purpose of this chapter is to determine the characteristics and test methods of unused mineral oil containing additives or without additives used in transformers in which oil has been used as the insulator. This chapter is written using the standard IEC 60296 [1] and is not applicable to the insulating oil used in cable or capacitor. It is important to know that insulating oil is made from refining, reforming or mixing petroleum products and other hydrocarbons. It needs to be explained that this chapter is applicable only to the unused mineral insulating oil and it is not applicable to the refined or used oil. The characteristics and test methods of the used mineral insulating oil will be presented in Chap. 2 as well.

1.2 Mineral Oil Transformer oil is a mineral insulating oil used in transformers and similar electrical appliances. There are also some other mineral oil types that are designed for the low temperatures which are used in the oil filled switchgears in the very cold climate. Mineral insulating oil is obtained through refining, reforming or mixing petroleum products with other hydrocarbons and additives. It should be noted that these additives do not include esters, silicone fluids and synthetic aromatic chemicals. Additives are the chemicals which are added to the mineral oil to improve its specifications. For example, antioxidants, metal passivators, electrostatic charging tendency depressant, gas absorbers, pour point depressants, anti-foam compounds and refining processes improver are some additives [1]. The definition of these chemicals will be presented in the following: • Antioxidant additives: Compounds added to mineral insulators to improve oxidation stability, including inhibitors, peroxide decomposers and metal passivators [1]. © Springer Nature Switzerland AG 2019 B. Vahidi and A. Teymouri, Quality Confirmation Tests for Power Transformer Insulation Systems, https://doi.org/10.1007/978-3-030-19693-6_1

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1 Unused Mineral Insulating Oil

• Inhibitors: An antioxidant additive containing a variety of phenolic compounds including DBPC1 and DBP2 as described in IEC 60666. • Other antioxidants: Includes other antioxidant additives including sulphur or phosphorus compounds [1]. • Metal passivators: Metal passivator agents are essentially added as electrostatic charging reducers, but may also improve oxidation stability [1]. Therefore, mineral insulation oil used in the equipment is classified according to the presence of additives into three types including oil with inhibitors, oil without inhibitors and oil with very low levels of inhibitors. The total inhibitor content is less than 0.01% in oil without inhibitors according to the standard IEC 60666. Oil with a very low amount of inhibitor contains inhibitors less than 0.08% in accordance with IEC 60666. Finally, the oil containing inhibitors is mineral oil with a minimum of 0.08% and a maximum of 0.4% of inhibitors [2]. Mineral insulating oil is stored and transported within the certain containers after the production as shown in Fig. 1.1. The manufacturer of oil must ensure that no contamination with PCB3 and PCT4 compounds, used oil, dechlorinated oil or other impurities is achieved [3]. Hence, the mixture of unused oil with the used oil is considered to be the used oil. For more information about recycled oil, refer to the standard IEC 62701 [3].

Fig. 1.1 Transformer oil in special bulks

1 2,6-di-tert-butyl-para-cresol. 2 2,6-di-tert-butyl-phenol. 3 Polychlorinated 4 Polychlorinated

terphenyl. biphenyl.

1.3 Classification of Mineral Oil Based on Application

3

1.3 Classification of Mineral Oil Based on Application Mineral insulating oil is divided into two groups according to their applications. The first group is allocated to oil for transformers and the second group is allocated to oil for switchgears in low temperatures. Now, each group will be described independently.

1.3.1 Transformers Oil These types of oil are also divided into 3 groups based on the antioxidant additives. The first group contains no antioxidants, indicated by the letter “U”.5 The second group contains a very low amount of antioxidant additives and is indicated by the letter “T”.6 The third group also contains antioxidants which is represented by the letter “I”.7 This category is important because the lowest starting temperature of the transformer (LCSET8 ) varies with this classification. The LCSET value in the IEC 60296 is −30 °C [1]. More information is given in Table 1.1.

1.3.2 Switchgear Oil in Low Temperatures Insulating and cooling are two main characteristics of this oil. Other characteristics include viscosity, density, pour point, water content, breakdown voltage and the dielectric dissipation factor [1]. The stability of the oil is affected by the oil quality, oil refinement type and additives which determine oil characteristics such as appearance, interfacial tension (IFT), sulphur content, acidity, corrosive sulphur content, 2-Furfural content, other similar compounds and gases in the oil. Performance is also a feature which relates to the characteristics of the long-term behavior of oil in the

Table 1.1 Maximum viscosity and pour point of transformer oil at the lowest cold start energizing temperature [1]

5 Uninhibited

LCSET (°C)

Maximum pour point (°C)

0

1800

−10

−20

1800

−30

−30

1800

−40

−40

2500

−50

transformer oil. inhibited transformer oil. 7 Inhibited transformer oil. 8 Lowest cold start energizing temperature. 6 Trace

Maximum viscosity (mm2 /s)

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1 Unused Mineral Insulating Oil

operation or its response to high electrical shock and high temperatures including oxidation stability, the gassing tendency and electrostatic charging tendency (ECT) [1]. Likewise, the characteristics of oil that are related to the oil safety issues during storage, operation and environment protection are called HSE, such as the flash point, density, polycyclic aromatics (PCA), PCB (polychlorinated biphenyls) and PCT (polychlorinated terphenyls) [1].

1.3.2.1

Features

The characteristics of transformer oil and switchgears must be in accordance with the specifications in IEC 60296. Definitions of each feature of transformer oil and switches are defined below [1]. • Viscosity: The viscosity of the oil affects the heat transfer and hence increases the temperature in the device. Lower viscosity facilitates oil circulation and improves heat transfer. Low temperatures lead to an increase in the viscosity of the oil which is the cause of the crisis at the moment of starting the transformer. In this situation, oil has a low flow or no circulation which can lead to an increase in the temperature in hot spots, and it has a negative effect on the speed of some parts movement such as switches, pumps, regulators, power circuit breaker and tap changer mechanism. The viscosity in the LCSET should not be greater than 1800 mm2 /s. The LCSET temperature for the transformer is −30 °C in IEC 60296. Other LCSET temperatures in Table 1.1 can be determined by an agreement between the manufacturer and the customer. Switchgear oil should also have a lower viscosity at LCSET temperature no more than 400 mm2 /s [1]. LCSET temperature for switchgear is −40 °C in IEC 60296. In this case, other LCSET temperatures can be selected based on the agreement between the manufacturer and the customer. • Pour point: Pour point in mineral insulating oil is the lowest temperature in which the oil still has a flow. It is recommended that pour point should be 10 K below the LCSET [1]. • Water content: A small amount of water is required in mineral insulating oil in order to achieve the suitable breakdown voltage and low electrical losses. To prevent the separation of water from insulating oil, the amount of water should be limited [1]. Before filling the equipment with oil, the oil must be tested according to IEC 60422 with a special device as could be seen in Fig. 1.2. • Breakdown voltage: The breakdown voltage of the insulation oil indicates its resistance to the electric shock in electrical devices. The breakdown voltage must be measured according to IEC 60156 by using a special device as shown in Fig. 1.3. The breakdown voltage should be greater than 70 kV. • Dielectric Dissipation Factor (DDF): This is a measure of the dielectric losses in oil. DDF values higher than those in the requirements of the standard IEC 60296 can indicate the oil pollution with polar contaminants or the inappropriate quality of the purification process. The DDF should be measured in accordance with IEC

1.3 Classification of Mineral Oil Based on Application Fig. 1.2 Fully automatic water content measurement equipment

Fig. 1.3 Oil breakdown voltage tester

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1 Unused Mineral Insulating Oil

60247 and IEC 61620 at 90 °C [1]. It should be noted that, in the case of an agreement between the manufacturer and the customer, DDF could be measured in other temperatures but the temperature measurement must be stated in the report. Appearance: By examining an oil sample at ambient temperature, the presence of visible contaminants, free and suspended water will be revealed [1]. Acidity: Mineral insulating oil must not contain any acid compounds. Acidity should be measured according to IEC 62021-1 or IEC 62021-2. Interfacial tension: The IFT indicator sometimes indicates the presence of polar compounds. The IFT must be measured according to EN 14210. Sulphur content: There are various sulphur compounds in mineral oil based on the type of oil source and the degree and type of refining process. The refining process reduces the amount of sulphur and aromatic hydrocarbons. Some sulphur compounds, that are naturally available in oil, have a tendency to metals [4]. These compounds could act as the oxidative inhibitors or corrosion accelerator inhibitors. The amount of sulphur should be measured according to the standard IP373 or ISO14396. Corrosive sulphur: Some sulphur compounds such as mercaptans on the surfaces of steel, copper and silver have a very corrosive effect and should not be present in the unused oil. This type of sulphur should be specified according to DIN51353. Other types of sulphur compounds such as DBDS (dibenzyldisulphide) may cause Cu2 S in the insulating paper. As a result, electrical insulation properties will be reduced. This phenomenon causes problems in various devices especially transformers when they are in service [4]. Oxidation stability: Oil oxidation increases the acidity and sludge formation. In oil with the high oxidation stability, less sludge is formed and oil has a longer life and hence it could be used as the insulating oil for longer periods. Oxidation stability is measured according to IEC 61125. In the case of oil that contains the metal passivators, the oxidation stability measurement test should be done before increasing the metal passivators. The oil tendency to absorb gas: The tendency to absorb the gas in mineral insulating oil when oil is exposed to a slight corona is called gas absorption characteristic. This feature is only important for certain devices such as high voltage transformers and bushings. This property is a measure of the rate of absorption or release of gas within the oil in experimental conditions [1]. The tendency to absorb the gas depends on the amount of aromatic compounds in the oil according to the standard IEC 60628. ECT: The electrostatic charging tendency is an important feature in designing some HV and EHV transformers in which the speed of the oil pump is high enough to increase the electrostatic charge. This charge can cause serious damage to the electrodes [5]. It should be noted that ECT could be reduced by adding some metal passivators. Flashpoint: The safe operation of an electric appliance is based on the use of oil that has a high flash point. The flash point is measured by the Pensky-Martens closed cup method.

1.3 Classification of Mineral Oil Based on Application

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• Density: Under the cold weather conditions, the density of the oil should be low enough to prevent the formation of ice from freezing water [1]. The occurrence of such a phenomenon can cause problems such as surface discharge on the conductors. • Polycyclic aromatic content (PCA): Some polycyclic aromatic compounds are in the carcinogenic group and hence controlling their amount inside the mineral insulating oil is essential. The total amount of PCA compounds could be measured by extraction with dimethyl sulfoxide (DMSO) [6]. • Polychlorinated biphenyl content (PCB): Mineral insulating oil should be free from PCB. More information about this compound is available in IEC 61619. • 2-Furfural content: 2-furfural and related compounds in non-corrosive mineral oil could be produced by inappropriate re-distillation after the solvent extraction during purification or by contamination in used oil [1]. Mineral insulating oil must contain a small amount of 2-furfural and its corresponding compounds. These compounds are measured according to IEC 61198. Other furans include [1]: (1) (2) (3) (4)

5-hydroxymethyl-2-furfural (5HMP) 2-fufurylalcohol (2FOL) 2-acetylfuran (2ACF) 5-methyl-2-furfural(5MEF).

• Particle content: Particles in the mineral insulating oil may be present during the preparation, maintenance or transportation of oil. These particles can affect the breakdown voltage. Particle measurement is carried out in accordance with IEC 60970. • DBDS content: This compound causes corrosion at the normal operating temperature of the transformers and can produce Cu2 S. Therefore, this compound should not be present in unused oil. DBDS is measured according to IEC 62697-1 [4]. • Gases in the oil: Some oil could produce gases such as hydrogen, hydrocarbons and carbon oxides without any thermal or electrical fault in the transformer or even without any shock to the performance of the transformer at temperatures below 120 °C. This phenomenon can lead to a large amount of gas production and can make a mistake in interpreting the DGA’s results. In addition, the oil containing inhibitor substances produces less than the uninhibited oil. To measure the soluble gasses in the oil and performing DGA test, special devices as shown in Fig. 1.4 are used.

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Fig. 1.4 Mobil GC—portable gas chromatograph

1.4 Additives The general type of additives must be presented in the technical specifications of the device. Concentrations should also be stated for antioxidant and passivators. • Antioxidant additives: Antioxidant compounds reduce the oil oxidation and hence reduce the formation of degradation products such as sludge and acid compounds [2]. Awareness of the type and amount of the added antioxidants will be helpful in monitoring the reduction of these products while using the device. Additives that slow down the oxidation of mineral oil include [2]: 1. Inhibitors compounds such as phenol and amines, especially DBPS and DBP. Determination and measurement of DBPS and DBP should be done according to IEC 60666 standards. 2. Other antioxidants include sulphur and phosphor compounds such as polysulfide and dithiophosphates. DBDS is one of these anti-oxidants but DBDS has a corrosive effect on the copper. The methods provided by IEC standards are for DBDS measurement and not applicable to the other anti-oxidants. • Metal passivators: Some of these additives form a layer on the copper and prevent the catalytic effects of copper in the oil and formation of the harmful copper sulfide deposits in layers of the paper resulting from the reaction of corrosive sulphur compounds in oil [1]. Some of these additives reduce the oil oxidation speed. Thus, the passivators slow down the oxidation process and deactivate the active surfaces of copper wires against catalytic reactions and hence lead to the desirable

1.4 Additives

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results in oxidation stability (IEC 61125). Other passivators are used to reduce the electrostatic charging tendency of oil. Three major categories of benzotriazole derivatives are used as the passivators as follows [1]: 1. N-bis (2-Ethylhexyl)-aminomethyl-tolutiazole (TTAA) 2. Benzotriazole (BTA) 3. 5-methyl-1H-benzotriazole (TTA). Determination and measurement of these additives are in accordance with IEC 60666. Other compounds that are used as metal passivators include [1]: 1. 2. 3. 4. 5.

N,N-bis(2-ethylhexyl)-1H-1,2,4-triazole-1methanamine (TAA) Diamino-diphenyldisulphide Nicotinic acid Hydroquinoline Other sulphur-based compounds.

It should be noted that for the above compounds, IEC test methods are not available. • Pour point reducer: These additives are used to improve the viscosity in the cold climate and pour point of oil. Two important categories of these additives are polynaphthalenes and polymethacrylates.

1.5 Special Cases For high-temperature transformers designed for long lifetimes, the acceptable limits of oxidation stability may be more limited. In such situations, inhibited oil is often used. The limits are as follows [1]: • Total acidity: Max. 0.3 mg KOH/g • DDF at 90 °C: Max. 0.050 • Total sulphur: Up to 0.05%. Likewise, in devices that oil pumping speed is high, for example, HVDC transformers, the ECT range is determined by the customer and manufacturer’s agreement. In devices that are subject to the electrical stress or they have special design, the gas from the discharge must be absorbed by the oil, hence the range of gassing tendency must be agreed between the manufacturer and customer according to IEC 60628 [1].

1.6 Analysis of Potentially Corrosive Sulphur The Cu2 S sedimentation mechanism is still not completely clear, but it is possible that sulphur compounds with copper form a complex and then converted into Cu2 S after being absorbed into insulating cellulose layers. Increasing the temperature and

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the presence of oxygen greatly affect this mechanism. Cu2 S is observed especially in devices where corrosive sulphur compounds are present in oil and their copper is not covered and the operating temperature is also high and the amount of oxygen is limited [1]. It seems that if the amount of oxygen is relatively low, the process of forming and transferring the complexes is better whereas if the amount is greater, the process of complex destruction and conversion to Cu2 S is desirable [1]. However, a large number of sulphur compounds are corrosive to copper, but only a few of them are found in the mineral insulating oil. The only compound that has ever been found to have the potential for Cu2 S formation and seemed to be remarkably found in transformer oil is dibenzyl disulfide (DBDS). In most of the oil which contains Cu2 S, DBDS is observed. However, if the purification process is carried out, this reactive compound is easily removed from the oil. Other compounds including disulphides, oxidized sulphur compounds and elemental sulphur can form Cu2 S. This phenomenon is stated in IEC 62535 when the oil is tested before and after adding these compounds. In order to determine the corrosive sulphur compounds in oil containing metal passivators, the protective layer of the passivator is formed on the surface of copper [1]. This layer prevents the metal reaction with sulphur compounds in the oil and the formation of harmful Cu2 S in the insulating paper of the device. Therefore, the test method in IEC 62535 cannot determine the sulphur compounds in the oil containing metal passivators. In order to determine corrosive sulphur compounds in oil with metal passivators, these additive materials must first be removed from the oil. The following two methods are used for this purpose. It is to be explained that both methods are for the new unused oil and not for the used oil [1]. Method 1: In this method, metal passivators are removed from the oil using specific adsorbents which are further described in IEC 60296 [1]. Method 2: In this method, the process of metal passivator additives oxidation is used in oil. More details are available in IEC 60296 [1].

1.7 Oil Contamination Mineral insulating oil that is likely to be contaminated with silicone oil, phthalates or other chemical compounds should not be used in transformers because these compounds create the foam when transformer degassing is performed, and it may make the process hard or impossible.

References

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References 1. IEC 60296, Fluids for electrotechnical applications—unused mineral insulating oil for transformers and switchgear (2012) 2. IEC 60666, Fluids for electrotechnical applications—detection and determination of specified additives in mineral insulating oil 3. IEC 62701, Fluids for electrotechnical applications—recycled mineral insulating oil for transformers and switchgear 4. IEC 62697-1, Insulating liquids—quantitative determination of corrosive sulfur compounds in used and unused insulating liquids—part 1: test method for quantitative determination of dibenzyldisulfide (DBDS) 5. B. Vahidi, G.H. Rassuly, Transformer oil static charge analysis using open circuit system. Iran. J. Electr. Comput. Eng. (IJECE), 6(2), 144–149, 2008. (in Persian) 6. IEC 60867, Insulating liquids—specifications for unused liquids based on synthetic aromatic hydrocarbons

Chapter 2

In-Service Mineral Insulating Oil

2.1 Introduction Mineral insulating oil is used in electrical equipment of power plants, transmission system and distribution systems. The quality of oil monitoring and maintaining are vital for oil-filled electrical equipment reliable operation. Therefore, operational solutions have been developed by the power generation and transmission companies. If the degradation of the oil (due to ageing or contamination) exceeds a certain limit, the reliability is eliminated and the risk of a premature fault increases. Although the risk analysis is very difficult but the first step in this way is to identify the effects of the faults. It is also important to note that leakage of oil can have negative environmental effects, especially if it is contaminated with the materials such as PCB. This chapter, which is developed using IEC 60422 [1], provides tips on monitoring, servicing and maintaining the quality of electrical insulating oil. It is necessary to explain that IEC 60296 is used to check the mineral insulating oil before entering the transformer but after the oil has been filled into the transformer tank, IEC 60422 should be used to check the oil. The contents of this chapter are relevant to the oil that is manufactured according to IEC 60296 [2] and also applicable to transformers, switchgears and other electrical equipment where oil sampling is feasible in normal working conditions.

2.2 Oil Monitoring and Purification Before proceeding with the discussion, it is necessary to introduce the tests that are used to monitor the oil in the equipment. Routine tests (group 1) include the minimum requirements for monitoring the oil that are required to ensure the continued operation. Additional tests (group 2) are also the tests which are carried out for more information on the quality of the oil and may be used to evaluate the oil for the continued operation. At the end, special tests (group 3) are the tests which are often © Springer Nature Switzerland AG 2019 B. Vahidi and A. Teymouri, Quality Confirmation Tests for Power Transformer Insulation Systems, https://doi.org/10.1007/978-3-030-19693-6_2

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performed to determine the suitability of the oil for using in a particular equipment and to ensure that the oil is adapted to the environmental or operational conditions. Once the oil has been monitored and its status are informed, corrective actions should be taken depending on the circumstances. These include physical purification, chemical purification and in some cases, PCB cleaning. Physical purification is a process that reduces gases, water, solids and contaminants by simply using the physical methods of removing oil or reducing them in oil. Chemical purification (regeneration) is a process that reduces the soluble or insoluble pollutants by using chemical and physical methods to remove them from oil or reduce their amount in oil. PCB cleaning is also a process that reduces the amount of PCB in the mineral oil or removes it.

2.3 Oil Ageing and Degradation The safe performance of the mineral insulating oil in an insulating system depends on some of the essential features that can affect the overall performance of electrical equipment. In order to perform its various tasks, such as insulating, cooling and spark ignition, the oil must have special characteristics including [1]: • High insulation strength to withstand the electrical stress during the operation. • Low viscosity for the proper circulation and heat transfer. • Proper specifications at low temperatures for the operation at the lowest temperature in the installation site. • Persistence against oxidation to maximize its lifetime. Oil is destroyed during the operation due to the working conditions. In many cases, the oil is in contact with air and exposed to oxidation. Degradation is faster in higher temperatures and metals, organic metal compounds or both act as a catalyst in the oxidation process. Oxidation changes the color, forms acidic compounds and in advanced stages, the formation of sludge happens. Ultimately, the insulation properties are affected. In addition to oxidation products, many of the unwanted contaminants such as water, solids and polar oil soluble contaminants are produced during the service of the oil which affect the electrical properties. These contaminants and any of the degradation products cause changes in one or more of the characteristics of the oil.

2.4 Oil Tests Many tests can be considered for the mineral insulating oil, but the best and the most accurate tests and also their permissible values are presented in IEC 60422 for the used oil to determine the suitability of the oil to continue the operation. Each of these tests will be described but to access for their values, see the standard IEC 60422 [1].

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2.4.1 Color and Appearance The color of the insulating oil is determined in light and expressed in terms of the number which is determined by the reference color in the standard. This characteristic is not very important, although it is useful for the comparison. A rapid increase in the color indicating number may clarify the degradation or contamination of the oil. In addition to the color, the appearance of the oil may indicate insoluble water, insoluble sludge, carbon particles, fiber or other contaminating materials.

2.4.2 Breakdown Voltage The breakdown voltage is the measurement of the oil strength against the electrical stresses and absolutely, it is crucial for the safe operation of electrical equipment [1]. This parameter is highly dependent on the temperature of the oil during sampling. Dry and clean oil has a high breakdown voltage. Insoluble water and in particular suspended particles in combination with high levels of soluble water are driven into regions with more intense electric fields and greatly reduce the breakdown voltage [1]. Hence, the measurement of breakdown voltage indicates the presence of contaminants such as water or suspended particles more than anything else. Low breakdown voltage can indicate the presence of one or all of these factors. However, the high breakdown voltage does not necessarily mean the absence of these contaminants [1]. The value of the breakdown voltage is only important when the sample is removed at the operating temperature of the transformer. Samples taken at temperatures below 20 °C may show the optimistic results when tested at the laboratory temperatures [1].

2.4.3 Water Content Water concentration in the oil depends on the temperature of the insulation system and the oil condition which is able to affect the following quantities: • Oil breakdown voltage. • Paper insulation. • Ageing process for liquid and paper insulation. Therefore, the water containment in the liquid and paper insulation has a great effect on the operation status and life of the transformer. The presence of water in the transformer insulation is due to two reasons: • The absorption of moisture from the environment. • Insulation destruction.

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Fig. 2.1 Power transformer control box with oil and windings thermometers

Water is fed into oil-filled electrical equipment through the oil. The water is soluble in oil and may also be a hydrate absorbed by bipolar products. Water solubility in oil (Ws ) in mg/kg depends on the oil condition, temperature and type of the oil. The absolute value of the soluble water (Wabs ) is independent of the temperature, type and status of the oil which is calculated on the basis of mg/kg. The absolute amount of soluble water can be measured according to IEC 60814. Relative humidity (Wrel ) is, in fact, the ratio of absolute value to water solubility in oil or Wabs /Ws , expressed as a percentage. Relative humidity can be measured by using a water-in-oil dissolution method or via online capacitive sensors [3]. If the absolute water content is greater than the water-solubility in the oil (Wabs > Ws or Wrel > 100%), the excessive water is insoluble and free which may be seen as fog or drop. Usually, the temperature is measured directly from the oil flow during sampling. If the temperature of the oil is measured using the oil thermometer or temperature corrections for the OFAF and ONAN cooling as shown in Fig. 2.1, this should be explicitly mentioned in the report. The oil-soluble water is directly proportional to the relative humidity or the ability to dissolve water in the oil. With the high oxidation of the oil and increase in bipolar side products due to ageing, the ability to dissolve water in the oil increases which is itself dependent on the type of oil. The ability to dissolve water in very old oil is much higher than the unused oil [1].

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Fig. 2.2 Dehumidification of power transformer windings, a Vacuum furnace, b Winding

2.4.4 Water in the Insulation System Transformers are dried during the production to reduce the percentage of water presences in the cellulosic insulation to 0.5–1% depending on the requirements of the manufacturer or customer as shown in Fig. 2.2. After this initial drying, the active part is constructed and its cellulosic insulation moisture content increases with respect to the environmental conditions. Again, the active part of the transformer, shown in Fig. 2.3, must be dried in different vacuum furnace as could be seen in Fig. 2.4. It should be noted that the moisture content inside the transformer will be increased due to the operating conditions in its service time. The available water in the insulation system is divided into a transformer between the paper and oil insulation in which most of the water is present in the cellulose. Temperature variations greatly increase the amount of water soluble in the oil, but it has little effect on the water contained in the paper insulator. The thermodynamic equilibrium between the water absorbed by the paper and dissolved water in oil occurs when the transformer is under the load after a long time at a relatively high temperature. So this equilibrium is temperature dependent. As could be seen in Fig. 2.5, at higher temperatures, much water is transferred from the cellulose to the oil. However, if the temperature of the oil is not high enough this balance will not be achieved due to the reduced water transfer from cellulose to oil. Different methods are provided by measuring soluble water in the oil for determining water in the paper. All calculations related to the relationship between soluble water and the water concentration in the insulating paper depend on the balance between the oil and the paper. This balance is affected by various parameters such as temperature difference between the oil and the paper [4]. The breakdown voltage and soluble water in the oil are highly interdependent. Both of them are temperature dependent, so their measurements at different operating temperatures of the transformer provide good information for the reliable moisture

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Fig. 2.3 Active part of a power transformer

Fig. 2.4 Active part drying vacuum furnace used during the production of transformer

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Fig. 2.5 Example of variation in saturation water content with oil temperature and acidity for insulating oil originally conforming to IEC 60296 [1]

assessment of the paper/oil insulating system. The analysis of the soluble water concentration in the oil is highly dependent on the temperature of the oil sample during sampling by placing the thermometer in the oil flow path.

2.4.5 Acidity The acidity of the oil shows the amount of acid contamination in the oil. The acidity of the used oil is due to the formation of oxidation products. Acids and other oxidation products, along with water and other solid contaminants, affect the insulation properties and other oil parameters [1]. Acids influence the cellulosic material which is the main reason for the corrosion of the metal surfaces of the transformer. The growth rate of acidity in the operating oil represents a good indicator of the ageing rate [1]. The acidity value is a good criterion for identifying the need for the chemical purification or substitution of the oil. Usually, the oil with an inhibitor, as long as the inhibitor levels are sufficient, shows no significant increase in the acidity.

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Fig. 2.6 a Oil tan delta and resistivity tester, b closer view

2.4.6 Dielectric Dissipation Factor (DDF) and Resistivity These specifications are very sensitive to the presence of polar contaminants and ageing products in oil. Changes in the amount of these contaminants (even if their amounts are very low) can be monitored by measuring these indicators by a special device shown in Fig. 2.6 [1]. The permissible limits of these indicators are highly dependent on the type of the transformer. There is an inverse relationship between the DDF and the resistivity, so that with decreasing the resistivity, the DDF value increases. Typically, there is no need to do both tests on the oil and DDF measuring test is common. DDF value and resistivity depend on temperature and humidity. Figure 2.7 shows the variation of resistivity with respect to the temperature and humidity in oil without any solid contaminant. In EHV and UHV transformers, special attention should be paid to the insulation DDF value because the high value of this coefficient can lead to the thermal exhaustion and ultimately a transformer failure [1]. Oil, which is known to be appropriate, has characteristics similar to the curves A and B in Fig. 2.7, and at low and high temperatures, the results of their DDF tests are acceptable. Oil that is considered inappropriate is similar to the curve C and the results of the DDF test are appropriate at 90 °C and therefore, the DDF test results are not suitable at low temperatures [1]. This indicates the presence of water or degradation products at a cold temperature without any chemical contamination. Inappropriate results at both temperatures indicate a higher level of contamination which means that there is no possibility of improving the oil’s condition with the physical purification [1]. Resistivity measurement is important for monitoring in-service oil. The resistivity is proportional to acids caused by oxidation and it is affected by unwanted contaminants such as water. Other compounds in used oil that can affect the specific

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Fig. 2.7 Example of variation of resistivity with temperature for the insulating oil [1]

properties are including aldehydes, ketones and alcohols [1]. Increasing the temperature as well as the water deposition at low temperatures reduces the resistivity because of reaching the saturation point. In some measurement transformers, it has been observed that during the very short oxidation process, there has been a significant change in the DDF value that led to a fault in the equipment. For this reason, it is recommended that the unused oil DDF value will be performed after the exposure to short-term oxidation according to IEC61125: 1992, Method C in order to determine the suitability of the oil for the service.

2.4.7 Additives and Oxidation Stability Mineral insulating oil stability is called the oxidation stability under thermal stresses and in the presence of oxygen and copper catalysts. This test indicates the life

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expectancy of the oil in the operating conditions of electrical equipment. This parameter determines the oil stability against the formation of acid compounds, sludge and compounds that affect the insulation DDF value in certain conditions [1]. Further information is available in IEC 61125. This characteristic mostly depends on the refining process. Refined mineral oil has a variety of natural compounds that act as an oxidation inhibitor. These materials are known as natural antioxidants. Oil that contains only natural antioxidants is called the uninhibited oil. Synthetic oxidation inhibitors can be used to enhance the oxidation stability [1]. Typically, a phenolic type is used in transformer oil. Most commonly used compounds are as follows [1, 2]: (1) 2,6-di-tert-butyl-phenol (DBP). (2) 2,6-di-tert-butyl-paracresol (DBPC). It is also necessary to explain that the inhibitor effect is different depending on the chemical composition of basic oil. IEC 61125: 1992, Method C can be used to determine the oxidation stability. Since the test is designed for the unused oil, the analysis of the results for the used oil is difficult. This test is usually used to evaluate the oil status in new equipment.

2.4.8 Sludge and Sediment There is a difference between sediment and sludge. The sediment is defined as the insoluble material contained in oil and includes the following: • Insoluble products caused by the destruction or oxidation of solid or liquid materials. • Solid products due to operating conditions such as metal or carbon particles, metal oxides and sulfides. • Fiber and other materials of foreign origin. Sludge is a polymerized product caused by the destruction of solid or liquid materials as shown in Fig. 3.7. The sludge is dissolved in oil to some content which depends on the temperature and the solubility of oil. More than that, the sludge turns into solid and turns into the sediment. Sediment or sludge can change the electrical characteristics of the oil. In addition, its accumulation may reduce the heat transfer capacity of the oil and causes the thermal degradation of insulating materials.

2.4.9 Interfacial Tension IFT measurement is a method for determining the polar contaminations and degradation products. This characteristic is changed relatively quickly in the early stages of ageing, but these changes slowdown in the next stages of ageing. The oil type

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influence strongly the rapid reduction of IFT. The rate of IFT reduction of uninhibited oil is usually greater than those with an inhibitor. The rapid reduction of IFT can indicate the lack of oil compatibility with some materials inside the transformer or accidental contamination when the oil is injected. However, oil with an IFT value less than or close to the values listed in IEC 60422 should be further investigated. In case of overloading the transformer, material deterioration is faster and IFT is a criterion for identifying this deterioration [1].

2.4.10 Particle Content Possible sources of suspended particles in the insulating oil are different in electrical equipment. The electrical equipment may be the self-contained particles from the manufacturing process or the oil can contain suspended particles in the process of storage or injection due to the improper filtration. Ageing of metal, oil and other materials inside the transformer may create dust particles during the operation. Hot spots with more than 500 °C can also form the carbon particles. The carbon particles generated in the selector switch (a part of tap changer as shown in Fig. 2.8) oil may enter into the main transformer oil reservoir due to the leakage of the compartment [5]. The image of a power transformer oil reservoir is shown in Fig. 2.9. The effect of the suspended particles on the oil electrical strength depends on the type of particles (metal, fiber, sludge, etc.) and water concentration [5]. The breakdown voltage test is not enough to identify the suspended particles, alone.

2.4.11 FlashPoint Due to the electrical discharges or under very high temperature conditions, oil destruction produces lightweight hydrocarbons which will reduce the flash point. The low flash point indicates the presence of combustible and volatile materials in oil.

2.4.12 Compatibility of Insulating Oil To overflow a transformer or reinject new oil into a transformer, the new oil must be in accordance with IEC 60296 [2] and it must have the same classification as the in-service oil. Practical experience shows that in the case of overflowing in-service oil with an unused (new) mineral oil in a small amount (e.g. 5%), there are not any problems. Although, overflowing in-service oil with unused oil in large quantities can lead to the sludge formation in the transformer. The most important point is

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Fig. 2.8 Selector switch (tap selector) of an on-load tap-changers (OLTCs)

that both unused oil and in-service oil must be the same to overflow. If there is an ambiguity about the compatibility of oil with each other, you should refer to the oil manufacturer’s instructions. The compatibility test is essential, especially for the additives containing oil.

2.4.13 Pour Point Pour point is the identification of the oil ability to circulate at low temperatures. There is no evidence to suggest that this characteristic changes in the normal ageing

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Fig. 2.9 Oil reservoir of a transformer with a thermometer

process. The change in the flash point is usually due to overflowing the in-service oil with different oil [1].

2.4.14 Density In cold climate, the density is an important factor in determining the suitability and efficiency of oil. For example, ice crystals may be floated in high-density oil and lead to the electrical discharges. However, density is not an important factor in the qualitative comparison of different oil. There is no indication that the density is affected by the oil degradation.

2.4.15 Viscosity Viscosity is an important factor in controlling heat transfer in the transformer. Oil destruction and oxidation increase the viscosity, and this characteristic is also affected by the temperature but it must be noted that normal degradation and oxidation of the oil do not have much effect on the viscosity. Changes in the viscosity occur only under intense electrical discharges or widespread oxidation.

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2.4.16 PCB Polychlorinated biphenyls are a family of aromatic chlorinated hydrocarbons that have good electrical thermal characteristics. These good specifications, along with an excellent chemical stability, have brought many commercial applications to these materials. However, chemical stability and insolubility of these materials have led to concerns about environmental pollution. The concern about the environmental impact of its use has been severely restricted since the early 1970s and has been prohibited since 1986 under an international agreement on the use of these materials on new sites and manufactured products. Unfortunately, the common use of the service equipment and maintenance of this polluted oil with other mineral oil have caused extensive contamination of the other mineral oil. The amount of PCB in the oil must be measured to ensure that oil is not contaminated to the PCB. Similarly, when there is a risk of contamination (such as oil refinement, repair of the transformer, etc.), the oil must be tested. Then, if there is a PCB, the required measurements must be taken.

2.4.17 Corrosive Sulphur There are three standard methods for measuring the corrosive sulphur in the oil. The IEC standard method is more obligatory than the ASTM method and all oil must meet the IEC method requirements. The implementation of the ASTM standard method is simpler and can be used as a preliminary test. The standard DIN method is a complementary method and should be performed in addition to the ASTM and IEC methods. The amount of sulphur in the oil depends on the refining process and the type of oil. The reason for the presence of reactive compounds that cause corrosion at the operating temperature of the transformer is poor refining or available contamination in the oil [1]. Sulphur-containing oil molecules may be decomposed at relatively high temperatures, react with the metal and form the metal sulfides. These reactions can occur in the switchgears and affect the conductivity of the contacts. Some of the sulphur-containing molecules produce Cu2 S which precipitates in the paper insulation. This phenomenon weakens the insulation quality and has so far caused a number of incidents. Cu2 S sediment is usually found in electrical equipment with paper insulators with the corrosive sulphur compounds in its oil or unprotected copper in which the operating temperature or ambient temperature is high. A group of substances in the oil causing this problem are disulphides such as DBDS [6]. The standard IEC 60296 describes the characteristics of unused oil to prevent the deposition of Cu2 S in paper during the operation. Tests for this purpose (IEC62535 and ASTM D1275: 2006, Method B) apply to oil that does not contain metal passivators. In the case of corrosive sulphur compounds in oil, the results of the tests will be positive. Aged oil (e.g., high-acidity oil), or oil with the low oxidation stability may have ambiguous test results as a result of the sludge. Combining different factors,

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not just the corrosive sulphur, may result in an electrical fault. In this case, the risk assessment should be done taking into account the design and operation status.

2.4.18 Dibenzyl Disulphides (DBDS) DBDS causes corrosion of copper surfaces at the operating temperature of the transformer and under certain conditions, it can form Cu2 S. DBDS plays a major role in the corrosion problem among various corrosive sulphur compounds. This compound has been produced in most insulating oil since 1988 and 1989 (although this oil has successfully passed their corrosive tests). Since 2006, the oil produced with the measurable DBDS amounts is very small. It should be noted that in some electrical equipment, the oil is corrosive despite the absence of DBDS.

2.4.19 Passivators Adding metal passivator additives is a technique used to reduce the risk of corrosive sulphur. Usually 100 mg/kg (0.01% by weight) of passivator is added to the oil to prevent the reaction of copper with the corrosive sulphur [1]. The use of this material is used not only to counteract the corrosion phenomenon, but also to enhance the oxidation stability and reduce the electrical charges of oil circulation [7]. It is important to know that monitoring the passivator value during the operation of the oil is essential.

2.5 In-Service Oil Monitoring After the construction of a transformer or a switchgear, it is filled with mineral insulating oil. In this case, the oil is in contact with the insulation and other materials inside the equipment and can no longer be treated as oil in accordance with the IEC 60296. Therefore, even if the electrical equipment has not been started, the specifications of this oil must be compared with the requirements of the in-service oil according to IEC 60422. Due to the use of different materials and different ratios of liquid-to-solid insulation, oil specifications may vary depending on the type of equipment. During the lifetime of the equipment, its insulating oil is exposed to heat, oxygen, water and other catalysts which affect the oil characteristics [1]. In order to maintain the quality of the in-service oil, it is necessary that the oil is regularly sampled and tested. Often, the first indication of oil degradation could be detected by its appearance. Likewise, if the oil is contaminated with PCB, paying attention to the environmental factors is very important. Where there is a potential for contamination

28

2 In-Service Mineral Insulating Oil

of the oil to the PCB, it is mandatory to test the oil samples and use the results of the risk assessment to avoid the contamination of the environment.

2.5.1 Uninhibited Oil Monitoring Oxidation of uninhibited oil is usually monitored by measuring acidic components and soluble and insoluble sludge in the oil. An increase in DDF value and a decrease in IFT value usually indicate the oxidation of the insulating oil.

2.5.2 Inhibited Oil Monitoring The oxidation pattern of oil containing inhibitor substances is different from the uninhibited oil. The added inhibitor into the oil produces little oxidation products in early stages. After the complete use of the inhibitor, the oxidation stability of the base oil determines the oxidation rate of oil. Reducing the IFT value in inhibited oil usually indicates the formation of oxidation products. The easiest and the most common way to monitor the inhibitor consumption is to measure the amount of inhibitor in accordance with IEC 60666 [1]. The amount of inhibitor must be monitored at appropriate intervals depending on the operating temperature and load level of the transformer.

2.6 Time Schedule of Sampling and Testing In-Service Oil Actually, it is impossible to provide a comprehensive timetable for the sampling and testing of operating oil. The best scheduling depends on the type, performance, voltage level, power and conditions of the construction and operation of equipment as well as the oil status which is derived from the previous tests. It is usually necessary to make a compromise between economic factors and reliability requirements. The main problems are determining the sampling time schedule, and determining the level of acceptable oil degradation for all insulating oil users, taking into account the differences in operating policies, reliability requirements, and the type of electrical system used. For example, large distribution companies may consider the recommendations in the standard IEC 60422 to be unprofitable for the distribution transformers. Conversely, some industries, whose activities depend on the continuous and reliable supplying of electricity, may require more stringent oil quality controls. In IEC 60422, four sampling-time schedules and suitable tests for different types of electrical equipment are proposed. If this equipment is in good condition, sampling schedules and oil testing will increase. Usually, tests and measurements should be made according to the following criteria:

2.6 Time Schedule of Sampling and Testing In-Service Oil

29

(A) Oil specifications should be tested according to IEC 60422. (B) If the results of the tests indicate that one of the main characteristics of the oil is in an “inappropriate” or “currently acceptable” state or that the rate of change in one of the characteristics of the oil is high, the retest time will be reduced. (C) Oxidation of oil is accelerated at high temperatures and in the presence of oxygen and water [1]. As a result, the timing of the oil test is shorter in full load transformers. Some additional tests such as IFT are also recommended in full load transformers. (D) The timing of the tests is determined according to the benefit/cost analysis based on life cycle analysis and risk assessment [1].

2.7 Available On-Site Tests In certain situations, some tests are required to be done on the site instead of the lab. The reasons are as follows: • Quick assessment of oil condition. • Classification of operating oil. • Remove any oil specification changes due to transferring samples to the laboratory. If the online testing equipment is available on the site, then the oil tests can be performed on the site but it must be noted that the accuracy of some site tests is less than the laboratory tests. Site tests typically include oil appearance, breakdown voltage, soluble water and acidity (with less precision).

2.8 Classification of Operating Oil In practice, it is impossible to determine a comprehensive instruction to evaluate the in-service oil or to propose acceptable limits for tests in all possible cases. The classification of oil and determination of the necessary corrective actions should be made according to the results of all tests. It is also important to consider the changes in the test results in a time frame for the final decision making. According to the obtained experience, operating oil can be divided into three groups: “Currently acceptable” or “Inappropriate”, “Appropriate” classification, based on the results of the tests and also the possibility of improving the status of their important characteristics [1]. • Appropriate: Oil is in normal condition. Continue sampling. • Currently Acceptable: Oil destruction is visible. Sampling is recommended in shorter intervals. • Inappropriate: Oil degradation is abnormal. It is necessary to plan for the corrective actions.

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2.9 Corrective Actions There are generally two types of contamination/degradation of oil: physical and chemical. According to IEC 60422, for each of these cases, a different corrective action must be taken. Similarly, if the process of degradation is accelerated, tests should be repeated in shorter intervals and appropriate corrective actions should be performed. It is also possible to consult with the manufacturer of the electrical equipment in these cases.

2.10 Purification In-service oil purification must be performed carefully. All necessary precautions should be considered to avoid the possible risks to staff and the environment as well. Oil purification should be carried out by experienced and familiar experts. An example of the oil purification system is shown in Fig. 2.10. A comprehensive risk assessment is required before the purification operation begins and also the following statements should be considered. • The necessary measurements should be considered to avoid oil contamination with PCB. • Oil leakage to the environment must be prevented and ensure that pipes and pumps are tight.

Fig. 2.10 Oil purification system

2.10 Purification

31

• Due to the fact that oil purification is usually performed under the vacuum, it should prevent any leakage. • The process of physical purification generates waste such as filter, contaminated oil and so on. Therefore, it is necessary to use the best possible technology to reduce the production of waste.

2.10.1 Physical Purification There are two reports [3, 8] that contain information about physical purification. Physical purification is a process that eliminates or reduces the physical contamination of oil by using the physical processes (filtration, drying, gasification, etc.). However, the output oil of this process is not always consistent with the specifications given in IEC 60422. The physical purification reduces the suspended particles and soluble water in oil. This process also eliminates some of the soluble gases in the oil and materials such as furans. After this operation, the new values should be considered as the basis. The physical methods used to remove water and solids from the oil include a combination of filtration, centrifugation and vacuum drying techniques. If the vacuum technique is not used in the purification process, it is recommended that the oil temperature to be limited to 30 °C, but if the vacuum technique is used, it is appropriate to change the temperature to the higher values. However, while using the vacuum process, the temperature should not be exceeded the oil boiling point, as this could lead to unwanted changes in the oil. If the oil boiling point is not available, it is recommended that the oil temperature must not be increased by 85 °C when the vacuum technique is used [1]. It should be remembered that purification of inhibited oil under vacuum, and at high temperatures may reduce the antioxidant content. Therefore, if it is desirable for us to reduce the particles or free water, then the physical purification is an appropriate method. The filters effectively remove impurities from the oil, but only absorb a small amount of free water. If the amount of free water in the oil is high, it should be extracted out of the oil before filtration. The equipment used to filter oil contaminated with carbon (such as tap changer oil) should not be used for other oil filtration because of the possibility of the contamination availability. The requirements for purification inhibited oil to prevent the reduction of additives are shown in Table 2.1. Generally, centrifuge separators are suitable for the separation of free water from oil and can also be used to separate the solids from oil. If the oil is heated, the viscosity is reduced and the purification efficiency is higher. On the other hand, sludge and free water in hot oil are more soluble than cold oil. Therefore, the cold filtration method is best suited for the separation of particles and free water and the hot purification method is appropriate for the separation of solvent water and solvent gases. If the oil contains solid particles, it is recommended that it must be passed through a suitable filter prior to the vacuum purification.

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Table 2.1 Conditions for processing inhibited or passivator containing mineral insulating oil [1]

Temperature (°C)

Minimum pressure (Pa)

40

8

50

15

60

30

70

80

80

200

85

280

2.10.2 Chemical Purification (Refinement) Chemical purification is a process that eliminates or reduces the soluble and insoluble polar contaminants [1]. Refinement processes require equipment, expertise and experience. The basic characteristics of the final product must be evaluated in order to provide the necessary information on the process efficiency and the estimated lifetime of the remaining oil. The output of this process can be the oil that meets the standard IEC 60296. In the chemical purification process, oxidation stability of the oil with high acidity value is lower than the acidity of the unused oil. There are two chemical purification methods, including the percolation and the contact methods [1].

2.10.2.1

Percolation Method

The complete process consists of three continuous steps: (1) The oil is exhausted from the bottom of the tank, heated to a specific temperature and passed through the filter to remove the particles and solids suspended and then enter into the transformer from the top of the reservoir [1]. (2) The oil is again passed through one or more filters or other suitable materials to remove the contaminated polar solvents. (3) Finally, to remove water and gases, a physical purification device (vacuum dryer or centrifuge) is used. The filter is actually an active substance that contains internal and external polar materials that pass through non-polar components of the oil, but absorbs polar contaminants or degraded products that are dissolved in oil. The absorption capacity of the contaminants is usually enhanced by an increase in temperatures; hence the chemical purification process is carried out at a temperature between 60 and 80 °C. Experience has shown that the total volume of oil should be at least three times passed through the absorbing filters. For this reason, it is necessary to use devices with a proper capacity for this purpose [1]. The number of cycles depends on the amount of contamination and the output oil expected characteristics. In case of severe contamination, transferring the entire

2.10 Purification

33

volume of oil into a clean tank for chemical purification of the oil is recommended. Here, it must be noted that an amount of this purified oil is used for washing the inside of the transformer tank (especially the windings). This part of the oil used for washing should be exterminated in accordance with the local regulations, and then the residual volume of oil should be refined. It should be remembered that a small amount of oil (less than 5%) was absorbed during the chemical purification process, so that the oil must be overflowed at the end of the process. During the process of chemical purification, attractive materials (filters) are contaminated, so disposing or recycling these materials should be done in accordance with the local regulations. Special precautions should be taken in case of possible contamination with PCBs.

2.10.2.2

Contact Method

This process is, in fact, stirring the contaminated oil in the presence of clay in a reservoir. This method is not suitable due to the need for the long-term shutdown of electrical equipment, but it can be used to clean up a large amount of oil. Usually, this process is used in the laboratory for the purpose of feasibility study of an oil sample chemical purification and estimating the final specifications of the refined oil after the completion of the purification process [1].

2.10.2.3

Substitution of Additives

Since the chemical purification is carried out after the start of the oil ageing process, it is usual that some parts of the inhibitor substances in the oil (whether natural inhibitors or synthetic inhibitors) are consumed. Therefore, it is recommended that the additive is added to the oil after the chemical purification and before re-energizing equipment. Metal passivators are also reduced or eliminated due to their polar nature during the chemical purification process.

2.10.2.4

Cleaning of PCB Contaminated Oil

If using transformers containing PCB contaminated oil is permitted in accordance with the local regulations, this equipment should not be always considered to be waste [1]. If the oil is accidentally contaminated, there are various processes and techniques for cleaning the oil from the PCB either on the site or outside the site. The basis of these processes is the chemical reactions between PCBs and reactants to remove the chlorine [1]. All cleaning procedures, whether on-site or off-site, should be carried out by the service providers.

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2.11 Replacing Oil in Electrical Equipment Replacing oil in transformers with a rated voltage less than 72.5 kV and high pressure switchgears and other related equipment is that, a small amount of oil is required to wash inside the tank. It is necessary that the reservoir and the surface of the winding and insulators must be well cleaned. It is also vital to keep the reservoir out of water. Importing oil into the tank with high pressure is a good way to remove the fibers and other materials. It should be noted that up to 10% of the new oil is absorbed by the insulating materials. Finally, it is important to know that the removal of existing contaminants of insulating materials and entering into new oil is time-consuming. Oil injection in vacuum conditions is also appropriate for removing other contaminants, but it should be considered that the equipment should withstand the applied vacuum. During the oil injection process, it is even necessary that the end of the oil inlet pipe must be lower than the oil level inside the reservoir in order to prevent its spraying. Another option is to inject the oil from the bottom of the tank as shown in Fig. 2.11. Replacing the oil in transformers with a nominal voltage of 72.5 kV or higher is different and in this case, it is necessary to refer to the transformers manufacturer instructions [1].

Fig. 2.11 Oil injection into the power transformer

2.12 Adding Passivators

35

2.12 Adding Passivators The metal passivators can be added to the insulating oil. This substance is commercially available and it can be added to the oil using a purifier or other suitable devices. This process is recommended for the unused oil. If the acidity of the operating oil is currently acceptable or inappropriate, further studies are required.

2.13 Determining Water Concentration in the Oil The methods presented in this section are valid for the analysis of the results only in the following circumstances: • • • • •

Oil and paper must have reached the state of equilibrium. No leakage in the transformer. There is the paper insulation in the equipment. There is no free water in the electrical equipment. Sampling temperature must be greater than or equal to 20 °C.

To properly analyze the moisture content, the results in the sampling should be corrected to a specific temperature. For practical reasons, this temperature is considered to be 20 °C since less than this temperature, the amount of water released is lower than the required amount to achieve the equilibrium in the equipment. The correction curve is shown in Fig. 2.12, where f is the coefficient of correction and ts is the temperature of the oil at the sampling time [1]. The temperature of the oil during the sampling should be determined by measuring the temperature of the oil flow. Note that the corrected values are valid only for comparing the results obtained at different oil temperatures [1]. The actual amount of soluble water in the oil at the site is determined based on the actualmeasured value, not the corrected value. Correction curves are not applicable at temperatures below 20 °C [1]. The relative humidity of the oil is a good measure to compare the changes. Relative humidity is the ratio of water concentration in the mineral oil at a given temperature to the water solubility of that mineral oil at the same temperature and it is expressed in percentage [1]. This parameter can be calculated using the values obtained by Carl Fisher’s titration method or sensors for measuring the moisture content. For better

Fig. 2.12 Typical correction factors [1]

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Table 2.2 Guidelines for interpreting data expressed in percent saturation [9] Percent of saturation water in oil %

Condition of cellulosic insulation

30

Extremely wet insulation

guidance, the cellulosic insulation status in terms of relative humidity is listed in Table 2.2.

References 1. IEC 60422, Mineral insulating oil in electrical equipment—supervision and maintenance guidance (2013) 2. IEC 60296, Fluids for electrotechnical applications—unused mineral insulating oil for transformers and switchgear (2012) 3. CIGRE Technical Brochure 227, Life Management Techniques for Power Transformer (2003) 4. CIGRE Technical Brochure 349, Moisture Equilibrium and Moisture Migration within Transformer Insulation Systems (2008) 5. CIGRE Technical Brochure 157, Effect of Particles on Transformer Dielectric Strength (2000) 6. CIGRE Technical Brochure 378, Copper Sulphide in Transformer Insulation (2009) 7. B. Vahidi, G.H. Rassuly, S.H. Hosseinian, Effects of different parameters on transformer oil electrification. 2004 IEEE region 10 conference TENCON 2004, vol. 3 (2004) pp. 429–431 8. CIGRE Technical Brochure 413, Insulating Oil Reclamation and Dechlorination (2010) 9. IEEE C57.106:2002, Guide for Acceptance and Maintenance of Insulating Oil in Equipment (2002)

Chapter 3

Chemical Indicators

3.1 Introduction The useful life of the transformers is based on the life of its insulation system, the combination of cellulose and oil. In practice, some transformers even more than 50 years in power networks are constantly being used. The lifetime of an insulating system of a transformer is the lifetime of the paper used because the oil can be cleaned or even replaced during the lifespan of the transformer, but the paper is fixed from the beginning and is not repaired or replaced. Therefore, the end of the transformer paper life is the end of its transformer life. It should be noted, however, that the oil status of a transformer plays a significant role in the ageing process of cellulose. To estimate the remaining life of the transformer (cellulose insulation), a chemical indicator called the degree of polymerization (DP) is used which will be further elaborated. Measuring this indicator directly requires the transformer paper sampling and for an in-service transformer, this is impossible. As a result, different chemical indicators are used today to estimate the degree of polymerization indirectly with using the values of these indicators.

3.2 Insulation Paper Life Determination To determine the end of the paper life, a set of physical quantities must be measured and then, based on the measurement results, a decision could be made about the end of paper life. These quantities can be considered as the mechanical properties such as elongation, pressure bearing, strength, wear resistance or electrical properties such as dielectric strength or chemical properties including the degree of polymerization. The end of paper life can be a precise amount of these quantities or a percentage of paper loss. At first, it might seem that the paper’s dielectric strength is the best value. But later, it was proved that if the paper was not exposed to mechanical stress, the dielectric strength of the paper would decay very slowly. © Springer Nature Switzerland AG 2019 B. Vahidi and A. Teymouri, Quality Confirmation Tests for Power Transformer Insulation Systems, https://doi.org/10.1007/978-3-030-19693-6_3

37

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3 Chemical Indicators

Therefore, mechanical properties were selected as the measuring factors and it was proved that tensile strength was better and more precise. When the tensile strength reaches 50% of its initial value, the end of the transformer life is considered to be [1]. In addition to the tensile strength index, scientists also introduced another important indicator, the degree of polymerization (DP), and this index was more widely considered due to a simpler measurement of DP than the tensile strength. The relationship between the degrees of polymerization (DP) and tensile strength is shown in Fig. 3.1. Many researchers have conducted a lot of investigations into the cellulose end life and the DP value. They have considered different numbers or ranges of DP for the end of the transformer life in Table 3.1. Generally speaking, if the DP value of a transformer is less than 200, then the tensile strength is reached 50% and the transformer’s end life is considered. In the following, we will explain the concept of degree of polymerization index and its relation to the paper situation and also ageing of the cellulose and oil.

Fig. 3.1 Relationship between tensile strength and degree of polymerization for Kraft paper [2] Table 3.1 DP ranges for transfoemer end life

Suggested range

Reference

100–150

Bozzin [3]

200

Lampe [4]

100–200

Fabre & Pichon [5]

250

Shroff [6]

3.3 Cellulose

39

3.3 Cellulose Cellulose is the most important component of the cellular structure of plants, first introduced by Anselm Papen in 1838. The primary sources of cellulose products are hardwood and some plants. Cellulose products are most commonly found in trees with cone fruits which are often grown in Canada and Scandinavian islands. Cotton fibers and wood are the best materials for cellulose production. In wood, cellulose is a part of a fiber composition in which solid and long cellulose rings are placed together and protected by a waterproof agent called lignin. Wood is the most important source of cellulose. Important parts of the wood are as follows: (A) Lignin: A polymer that provides strong bonding between cellulose chains in plants. (B) Alpha Cellulose: This material, used in the manufacturing of paper, has a hydrocarbon chain with many polymers and includes glucose units. Of course, there are other forms of cellulose such as beta-cellulose and gamma-cellulose that are ignored. (C) Hemicellulose: This is a mixture of low molecular weight polysaccharides.

3.4 Cellulose Molecular Structure Cellulose is a polysaccharide. Polysaccharides are the complex molecules composed of a large number of monosaccharide units. Monosaccharides are very simple sugars and the most abundant monosaccharide is glucose. The cellulose molecules are completely linear and have a strong tendency to form intermolecular hydrogen bonding, so a few molecules are clustered together and make up the micro fibrils [2]. In the micro fibrils, the very regular and crystalline areas and the relatively irregular and absent-minded amorphous areas are alternately adjacent to each other. Accumulation of micro fibrils and fibrils forms the cellulosic fibers. Due to the fiber structure and strong hydrogen bond, cellulose has high tensile strength. This material has a general chemical structure (C6 H10 O5 )n as could be seen in Fig. 3.2.

Fig. 3.2 Cellulose molecular structure [2]

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3 Chemical Indicators

3.5 Cellulosic Insulation The cellulose type used in the transformer’s insulation is alpha-cellulose which is made of softwood trees and made up in two forms of paper or pressboards. This cellulose insulation consists of 75–85% alpha-cellulose, 10–20% hemicellulose and 2–6% lignin [7]. In power transformers, cellulose is used in various forms. The insulation created by pure cellulose is called Kraft. Kraft paper has all features of an insulating system including excellent performance in the presence of electric field, geometric stability in oil, comfortable molding, comfortable wrapping, easy bending and easy cutting. Cellulose is still used as the most economical solid insulation within the power transformers as shown in Fig. 3.3.

3.6 Degree of Polymerization The degree of polymerization is measured according to IEC 60450. Hence, not only cellulose, but also hemicellulose and lignin are broken down. Therefore, DP is a sum total value. In the explanation of DP, it can be said that in the polymer or cellulose molecule, there are the long chains which contain rings or glucose monomers and the number of rings in each string reaches 1000–1400. The average number of glucose rings in a molecule or cellulose polymer is the degree of polymerization (DP). The mechanical strength of cellulose depends on the strength between cellulose fibers and their length. If the force between the cellulose chains decreases, while reducing the mechanical strength of the paper, the degree of polymerization of the paper will decrease. For a new transformer, the DP value is between 1000 and 1200 and when this number drops to 150–200, the cellulosic insulation quality is drastically reduced and the life of the transformer is over as could be seen in Fig. 3.4.

Fig. 3.3 a 400 kV transformer lead-exit, b Cross-section of a 400 kV transformer and its insulation structure [2]

3.7 Oil Impregnated Insulation Paper

41

Fig. 3.4 Cellulose magnified image on two different DP values

3.7 Oil Impregnated Insulation Paper The active part of the transformer consists of cellulose insulation, windings and so on. The weight of cellulosic insulation is about 5% of the total weight of the active part. Before immersion in the mineral oil, the active part should undergo a drying step under the vacuum in the furnace to ensure that the cellulose moisture reaches a content of about 0.5%. Cellulose has a strong tendency to absorb moisture. Hemicellulose polymer has also a strong tendency to absorb water molecules to stabilize. The standard IEC 60641-2 states that the required time for drying the cellulose samples with dimensions of 300 × 300 mm2 and under vacuum (1 mbar) and 105 °C is about 24 h [8]. After the saturation process, cellulose drying is carried out with hot oil at 90 °C in the pressure of less than 2.5 mbar by oil injection. This process enhances the properties of the cellulose-oil insulation system. The mechanical stability is achieved by drying cellulose and oil penetration into it.

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3 Chemical Indicators

3.8 Ageing of Oil Impregnated Insulation Paper The oil-impregnated cellulose, as previously mentioned, is the most impressive part of the transformer which undergoes a variety of stress over the lifetime of the transformer. It should be noted that the degree of polymerization (DP) is the first indicator which reveals the state of paper in the power transformers. As could be seen in Fig. 3.5, paper deteriorates over time and weakens the insulation system against thermal, mechanical and electrical stresses [9]. Cellulose is constantly affected by the heat generated by the active part of the transformer, the moisture content, the oxygen concentration in oil, acids produced in the oil and other factors such as metal catalysts which generally cause cellulose decomposition, degradation and deterioration. The phenomenon of ageing can be considered a breakdown of a specific cellulose characteristic. The IEC 60505 defines the ageing of cellulose as irreversible changes

Fig. 3.5 Cellulose ageing and destruction in an old transformer [2]

3.8 Ageing of Oil Impregnated Insulation Paper

43

and degradation, so that its effectiveness is eliminated [10]. The cellulose function as an insulator is influenced by different stresses and factors, so choosing a boundary criterion for ageing is difficult. However, the degree of polymerization (DP) can be the main indicator of the end of the transformer life and its degradation to 200 or less turns out as the boundary criterion.

3.9 Ageing Mechanism Cellulose is exposed to irreversible exhaustion due to its multi-component structure. Cellulose, which is exposed to the extreme thermal stresses in transformers, is immersed in oil. Likewise, metal catalysts such as copper and iron, as well as moisture, oxygen, and all kinds of acids that are produced by the oil oxidation, sometimes even cellulose, affect the cellulose and cause cellulose degradation. Cellulose deterioration is a function of temperature, oxygen, moisture, different metal catalysts and acids. The cellulose corrosion mechanism is very complicated and highly dependent on the environmental conditions. When cellulose is aged and corrupted, its physical and chemical properties change. As a result, the deterioration of cellulose is associated with the products such as carbon oxides, water and furans that are dissolved in oil. In the following, we will explain each of the factors affecting the cellulose degradation.

3.9.1 Pyrolysis The excessive heat applied to the cellulose causes the existing fibers to rupture. However, at lower temperatures, certain monomers in the cellulose chain are broken down and reduce the degree of polymerization. The destruction of cellulose in transformers under the influence of thermal stress occurs at their normal operating temperature (60–90 °C) over the useful life of the transformers. This type of ageing which is mainly under the influence of temperature, is called pyrolysis. As a result of the pyrolysis process, especially at temperatures above 130 °C, the glucose chains are defeated, resulting in glucose free molecules, water, solids, carbon monoxide, carbon dioxide, organic acids, hydrogen and a group of hydrocarbons called furans. Finally, the degree of polymerization (DP) will also decrease. Another important item in pyrolysis is the increase in the moisture content. That is, without the presence of oxygen, the chain of cellulose bonds is broken down and water is generated. The water generated by the cellulose decomposition in the pyrolysis process, while continuously breaking down other molecules, loosens the bonds in other cellulose molecular chains. Emsley states that heat and water are equally effective in accelerating the ageing of cellulose which is 3 times the oxygen effect in the accelerating cellulose ageing [11]. The results of some research in this field are as follows:

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3 Chemical Indicators

• In 1930, Mont Singer considered pyrolysis over time at a given temperature and under the process of an increasing temperature at a specified rate. He suggested that an increase of 5–10 °C would double the loss of paper. He also showed that, in the temperature range from 100 to 110 °C, ageing rate is doubled by an increase of 6 °C. Finally, at an elevated temperature of 120 °C, an increase of 8 °C augments the ageing rate by doubling [12]. • In 1930, a statement presented that an increase of 8 °C would reduce 50% of the cellulose lifetime [13]. • In 1960, Faber expressed that an increase of 10 °C will reduce the cellulose life by 50% and the moisture content augmentation from 0.3 to 5%, will increase the cellulose degradation and ageing by 2.5 times [5].

3.9.2 Hydrolysis The amount of water inside the insulation system (paper and oil) of a transformer is very important because the moisture inside the transformer has devastating effects. The following factors can be outlined: [14] 1. Cellulose has a strong tendency to absorb moisture. 2. Moisture reduces the electrical strength of oil. 3. Moisture increases the power factor. (The reason for increasing the power factor is that by increasing the moisture content, the viscosity of the oil is reduced and as a result, the oil is diluted and it moves more rapidly between the windings and this improves the cooling system of the transformer and thus the power factor of the transformer increases). 4. Moisture reduces the paper electrical strength. 5. Moisture reduces the temperature required to produce the bubbles. 6. Moisture accelerates the cellulose ageing process. The factors that cause the presence of moisture inside the transformer are as follows: 1. 2. 3. 4.

Defective dehumidification during the construction of the transformer. Humidity entry from weld points or oil pipes. Atmospheric absorption. Production during the ageing process of oil and cellulose.

The amount of moisture in the paper and oil is not equal and is constantly transferring between paper and oil. The amount of moisture in the oil will change due to the moisture content of the paper, the oil quality and the temperature of the insulation system. For example, if the moisture content inside the paper increases at a constant temperature, the amount of water inside the oil will also increase or if the temperature of the insulating system increases, the solubility of the water inside the oil will be increased. As a result, moisture will be transferred from the paper to the oil. If the

3.9 Ageing Mechanism

45

temperature drops, water is transferred from oil to paper again. Meanwhile, it should be noted that old oil absorbs much water than the new oil [15]. It should also be noted that the moisture content of the paper cannot be directly measured and there are several methods to obtain it. Most notably method is the following diagram in Fig. 3.6 which calculates the moisture content of the paper using the moisture content of the oil. The phenomenon of moisture balance of paper and oil depends on factors such as temperature, thickness and humidity of insulation materials. Experimental results have also shown that in order to achieve the equilibrium conditions and using the following diagram, the transformer should be at the steady state condition for more than 3 weeks [16]. The moisture present in the paper causes the cellulose hydrolysis process. A new transformer has a moisture content of 0.5% in the paper and 0% moisture in the oil. The amount of moisture present in the paper may reach 5% during the lifespan of the transformer [15]. In the hydrolysis process, the oxygen bridge between glucose rings is affected by water, causing chain failure, and the formation of two –OH groups attached to the chain monomers [17]. Water is accumulated as the most important product of the ageing of the insulating system inside the transformer and with an increase of 0.5% water, the amount of DP is halved [15, 17]. • According to Fabre and Pichon, the predicted moisture content in the paper and the transformer oil at 80 °C and at the end of the transformer’s lifetime is 5% in the paper and 0.1% in oil [5]. • In 1974, Franklin showed that the ageing rate at normal temperature and 4% moisture content in the paper was 20 times larger than the ageing rate of the paper with 0.5% moisture content [17]. • In 1970, a theory argued that increasing the moisture from 0.3 to 5% reduced the cellulose life by 10 times [18].

Fig. 3.6 Moisture balance between paper and oil (Oommen chart) [2]

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3 Chemical Indicators

3.9.3 Oxidation Another mechanism of ageing cellulose is oxidation. Cellulose has a lot of potential for the oxidation. During this reaction, the cellulose chains are weakened and the glucose rings or monomers are oxidized and the moisture is also generated. In this process, carbon atoms in cellulose molecules are attacked by oxygen, resulting in aldehydes, acids, water, carbon monoxide and carbon dioxide production. As a result, the bond between the glucose rings is weakened and leads to a decrease in DP. The moisture produced during this process can be effective in the hydrolysis process. This kind of cellulose destruction mechanism is similar to a chemical change due to heat or a slow burning in which the final products such as water and other carbon oxides are produced. According to research, if the oxygen content in the oil is less than 200 ppm, the ageing rate of the insulating system is 5 times lower than the free breathing transformers [19].

3.10 Influence from Acids Lundgaard stated in 2008 that the cellulose hydrolysis process is a catalyzed process which is caused by H+ ions [20]. These H+ ions enter the cellulose amorphous region and cause the cellulose degradation. This can indicate the susceptibility of the ageing process to the amount of acidity of the insulating system. This process is a selfaccelerating process because the cellulose hydrolysis process also produces acids. The acids in the insulating system are divided into two groups with low molecular weight and high molecular weight. Low molecular weight acids include formic acid, acetic acid and levulinic acid and high molecular weight acids are including stearic acid and naphthenic acid [18]. Research has shown that the ageing process is usually influenced by low molecular weight acids and high molecular weight acids do not have any effects on the ageing process [18]. Low molecular weight acids, which are also water soluble, are produced by the ageing process of oil and cellulose and a large percentage of them are produced by ageing of oil. Both low and high molecular weight acids are produced in the oxidation of oil, but only a small amount of low molecular weight acids are produced in the process of paper degradation [18]. It is important to mention that the above acids alone cannot directly depolymerize cellulose, but they are dissolved into water and then produce H+ ion which accelerates the hydrolysis process and results in faster and more rapid degradation as follows: H+

n × (C6 H10 O5 ) + H2 O ⇒ 2CO + 2CH4 + 2CO2 + 2H2

(3.1)

3.11 Ageing of Oil

47

3.11 Ageing of Oil The oil used in transformers is mainly mineral and is in accordance with IEC 60296. The ageing mechanism of the transformer oil is very complex and it is difficult to understand the deterioration of the transformer oil. Transformer oil is constantly exposed to thermal stress during the operation. This stress causes rupture and decomposition of the oil. Therefore, depending on the composition and degree of refining and impurities present in it, as well as under the influence of unusual stress, the oil can slowly or quickly lose its stability. Likewise, due to the presence of oxygen, the oil will be oxidized and sludge, which is known as corrosion or deterioration product, will be produced.

3.12 Oil Oxidation The process of oxidation is the result of the chemical reaction of oil’s hydrocarbons with oxygen. Oxygen may appear due to the contact of the oil with the ambient air or during incomplete degassing or it is possible that the oxygen remains soluble in the oil during the production of oil. Oxidation of oil can also be caused by thermal stress applied to cellulose. According to the above, the oil could be decomposed in the presence of chemical reactions such as heat. In this process, one or more molecular chains are broken up and then the dissolved oxygen in the oil is replaced. As a result of this process, products such as carboxylic acids, water and some gases such as hydrogen, methane, ethane, ethylene and acetylene are produced. The production volumes of these hydrocarbon gases and their growth rate depend on temperature and pressure [21].

3.13 Degradation Products in Oil Impregnated Insulation Systems The process of paper ageing leads to the production of different types of products. Some are stable and some may be eroded over time. In theory, the latest products of cellulose ageing are water and carbon monoxide, but we know that in reality, no transformer is used until all paper is destroyed. Usually, a useful lifetime is considered for the life of the transformer [22]. So during the lifetime of the transformer and at the end of its life, in addition to water and carbon monoxide, there are other materials in the insulation system. But the first issue is which of the existing materials can be considered as the products of degradation and ageing. There is a division states that if a product has one of the following characteristics, it is an ageing product. 1. The presence of that substance or product is considered as a risk to the transformer operation.

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2. Increase the ageing rate of the insulation system. 3. Be as an indicator of the ageing process. This means that information about the ageing process can be obtained through the amount of that substance. But the second problem is that both paper and oil get old together. Sometimes a product can be caused by the ageing process of the oil and cellulose and even beyond the source of its production, it can be found both in oil and paper. Similarly, a product that is caused by the ageing of paper or oil may also degrade it. Therefore, with regard to the above factors, it is not possible to precisely allocate a product exclusively to paper or oil.

3.14 Degradation Products from Cellulosic Insulation 3.14.1 Water Water is recognized as the main source of paper degradation. Water is produced by hydrolysis and oxidation of oil and paper. The amount of water produced is usually expressed as a percentage of the total weight of the insulating system. Some moisture may also be absorbed from the outside into the transformer. Therefore, the presence of humidity in the insulation of the transformer accelerates the ageing process, decreases insulation resistance and increases the risk of bubble production during overload. As a result, the moisture concentration of the insulating system should be kept in a minimum value.

3.14.2 Acids Acids are produced in different ways. One of the factors that produce acids is the hydrolysis process in which the cellulose chains are broken down. Then a series of products are produced, but those products are unstable and decompose result in producing acids. These acids themselves are not stable and may be converted into other substances. For example, levulinic acid may produce a polymeric material called caramel or formic acid may decompose into carbon monoxide and water. It is important to know that acids produced by oxidation are usually low molecular weight acids. Small amounts of high molecular weight acids are also produced by oxidation of the oil.

3.14 Degradation Products from Cellulosic Insulation

49

3.14.3 Furans Furans are multi-ring organic compounds composed of a five member aromatic ring, four carbon atoms and an oxygen atom. These compounds are colorless, flammable, and volatile and have a boiling point close to the room temperature. These compounds are soluble in organic materials such as alcohol, ether and acetone, but they are less soluble in water. These compounds are toxic and contact with them can cause cancer in humans. The family consists of 5 members including 2-furfural, 2-acetyl-furan, 5-methyl-2-furfuryl, 5-hydroxymethyl-2-furfural and 2-furfuryl alcohol which are found both in oil and paper. Their production procedure in oil is mentioned in IEC 61198. One of the main products of oil-saturated cellulose degradation is 2-furfural. All three types of ageing mechanisms result in chains failure, and produce glucose and degraded forms. Monitoring the amount of glucose in oil may indicate a degree of paper degradation, but glucose has very little solubility in the oil. Glucose is degraded in the presence of moisture and acids and it produces 5-hydroxymethyl-2-furfural. This compound is also unstable and decomposes into other components of the furan family products. The type of this breakdown production will vary depending on the circumstances. Since 2-furfural has much thermal stability than the other instant compounds, therefore, 2-furfural is considered in the ageing process [23]. Generally, the presence of furans does not have much effect on the ageing speed and the degradation of paper or oil. Likewise, due to the greater stability of 2-furfural than other furans, it is possible to measure and monitor the amount of 2-furfural concentration in the transformer to determine the status of the transformer. Finally, with using the 2-furfural concentration and a mathematical relation, DP value can be estimated. There is, of course, a factor that complicates the production of furans from cellulose. That factor is moisture. Ageing caused by hydrolysis of cellulose can lead to the formation of furans, especially 2-furfural. Hydrolysis reaction is important in the production of furans at low temperatures. Experiments have shown that 2-furfural and 5-methyl-2-furfural are the main products of ageing caused by hydrolysis of cellulose at temperatures between 100 and 200 °C and moisture is very effective in increasing their formation. Another important point in the production of 2-furfural is that the available 2-furfural in the oil cannot always be produced due to the deterioration and ageing of cellulose. Nevertheless, there may be some 2-furfural in oil structure as a result of the oil manufacturing process. So, the amount of 2-furfural concentration in oil must be measured beforehand.

3.14.4 Carbon Oxides Carbon monoxide and carbon dioxide are the ultimate products of destroying all components of the paper. Of course, in low concentrations, these oxides are also

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produced by the oxidation process of oil. The concentration of these gases in the oil and their production rates are always measured by the DGA test.

3.14.5 Hydrocarbons Hydrocarbons are another product of ageing, measured inside the oil by the DGA test. Hydrocarbons are produced mostly by oil ageing. Certainly, of course, some of them will be produced by paper ageing.

3.15 Degradation Products of Oil 3.15.1 Acids As previously mentioned, the oxidation of the oil produces different low molecular weight acids. High molecular weight acids have little effects on the cellulose degradation and ageing process, but low molecular weight acids which are highly polar, have the greatest impact on the process of paper degradation and ageing [24].

3.15.2 Sludge The sludge consists of ageing products which are suspended in the oil or they are fixed due to their high polarization and heavy molecular weight. They have very little solubility in the oil. Most of this sludge is caused by the process of the oil oxidation, but paper ageing and deterioration products can also produce sludge. An increase in the acidity of the oil can also indicate the production of sludge. An image of the sludge is shown in Fig. 3.7. An analytical method for specifying sludge in transformer oil is also mentioned in IEC 60422.

3.16 Chemical Indicators Online DP measurement is impossible since the transformer must be disassembled to obtain the samples of the insulating paper. This approach is very costly and timeconsuming [25]. Alternatively, chemical indicators such as 2-furfural or the CO2 /CO ratio or methanol can be used to estimate DP, e.g., measuring the concentration of 2-furfural in the transformer oil is a common method for estimating the remaining lifetime of a transformer [25]. However, using only the concentration of 2-furfural in

3.16 Chemical Indicators

51

Fig. 3.7 Sludge in an old transformer [2]

the transformer oil may yield inaccurate results since that concentration is influenced by factors which are not related to changes in the DP of the insulation paper [25–28]. In the following, various indicators will be examined.

3.17 Furan Compounds Many mechanisms have been proposed for the thermal degradation of cellulose based on which of the pyrolysis or hydrolysis processes are dominant [29]. In the hydrolysis and pyrolysis processes, furans, especially 2-furfural will be produced. Before addressing the origin of the above subject, it should be noted that water and carbon oxides are the main products of cellulose degradation and furans are second products and acids and other products are among other products.

3.17.1 Furans Origin Furans are also generated by the degradation of insulating paper impregnated with oil and are appreciably oil-soluble [25]. Furans include 2-furfural, 5-methyl-2-furfural, 2-furfuryl alcohol, 2-acetylfuran, and 5-hydroxymethyl-2-furfural. Their production is mentioned in the standard IEC 61198. High concentrations or increases in their concentrations usually indicate paper degradation due to ageing or fault conditions [25]. Burton et al. [30] stated that furans dissolved in oil can cause paper deterioration at temperatures lower than approximately 100 °C. At such temperatures, furans are generated primarily through the destruction of hemicellulose, which makes up about

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6–7% of the paper by weight and is mechanically much weaker than cellulose. Furans are also generated in oil through the degradation of cellulose at temperatures in the range 100–200 °C [25, 31].

3.18 The Relationship Between DP and Furans Furans are the main products of cellulose degradation and decomposition inside the transformers. For analyzing the paper, furans analysis is a very convenient method compared to paper sampling. The reference [6] presented a report on the production of 2-furfural from the destruction of paper insulating cellulose and found an approximate logarithmic relationship between the 2-furfural concentration in oil and the DP value [25]. The reference [32] also carried out a wide range investigation in which the production rate of different furans were achieved in a wide temperature range (120–350 °C). In reference [23], with using the HPLC method, the production of furans was measured during the cellulose ageing process at 20, 80 and 100 °C. Using the results, 2-furfural concentration was correlated with the mechanical strength of cellulose. In reference [33], a mathematical model for the concentration of furans and time was presented and also it is stated that 5-hydroxyl methyl-2-furfural and 2-furfural are produced more than the other furans in oil. 2-Furfural has also the highest concentration and with increasing the temperature, the production rate of 5-hydroxymethyl2-furfural is higher than the 2-furfural production rate. Emsley also concluded that 2-furfural production is always more than other furans and main production of 2furfural occurs when the DP value reaches 400 [34]. Increasing moisture and oxygen, especially moisture, will increase the production rate of these products. They eventually found a logarithmic relationship between the concentration of 2-furfural and DP value in the range of temperatures from 120 to 160 °C. Pahlavanpour et al. stated that the concentration of the furans should be less than 0.1 ppm and this may be very little during the lifespan of the transformer [35]. However, in many old transformers, this value is reached 1 ppm and even in some cases up to 10 ppm [35]. The technique for measuring furans concentration is given in IEC 62874, but there is no commentary on their values. Chendong found a linear relationship between the concentration of 2- furfural and DP value in the logarithmic range [36]. At least, four relationships between the 2-furfural (F) concentration (mg/liter or ppm) and the DP value have been proposed as follows: • • • •

DP = (1.51 − log F) /0.0035 Chendong [37] (3.2) DP = (1.17 − log F) /0.00288 Scholnick [38] (3.3) DP = 7100 /(8.88 + F) De Pablo [38] (3.4) DP = 800 /(0.186F + 1) Pahlavanpour [38] (3.5)

Pahlavanpour formula is based on the conditions of the transformer and the assumption that 20% of the inner layers of the winding insulation are destroyed

3.18 The Relationship Between DP and Furans

53

twice as fast as the rest of the paper inside the transformer [39]. Above relationships are all based on the experimental data depending on the amount of transformer paper, the effects of moisture, the acidity of the oil, load condition, and many other factors which have led to the fact that none of the above formulas can be considered as a complete model. Therefore, it can be said that there is no general relationship between the 2-furfural concentration and the paper DP value and for each type of transformers, there can be a separate relationship. Using the furans analysis and the DGA test, some critical values can be given to these compounds.

3.19 Stability One of the problems with the judgment of the furans concentration is that in addition to the fact that these compounds are produced in different ways, and they are not just the products of cellulose degradation, these compounds are not stable at the temperatures above 110 °C [40]. For example, in [40], it is stated that the furans would be stable at the operating temperature of the transformer if oxygen is not present, but after about 8 weeks when the oxygen is present in the transformer, the 2-furfural concentration will be reduced about 20–40%. Reference [41] states that in the presence of oxygen and even at 60 °C, a certain amount of the furans will be lost. Emsley in his research showed that when the transformer undergoes the normal ageing and does not suffer from any thermal stress, the presence of furans will be due to the hydrolysis process.

3.20 Furans Disadvantages Furans certainly provide information about paper destruction. The results of many years of research indicate that their formation depends on the test conditions or working conditions of the transformer. Recently, the effects of water, oxygen and acidity on ageing and the type of paper used have been much more studied. So far, many attempts have been made to find the relation between 2-furfural concentration or other furans and DP value. Different formulas have been proposed with different assumptions. Of course, there are other studies that show the ineffectiveness of these formulas. The reason for these differences or contradictions is that, first; the furans are not only caused by the destruction of cellulose and will also be produced in other ways. Second, these compounds are unstable and disappear with increasing temperature. The presence of oxygen and water and the amount of acidity affect the amount of these compounds. For example, the presence of moisture leads to the decomposition of 5-hydroxymethyl-2-furfural [42]. Lutke and colleagues also concluded that transformers remaining lifetime prediction are impossible only on the basis of 2-furfural concentration [41].

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According to the above explanations, in addition to furans, other indicators such as CO2 /CO ratio and methanol are used to estimate the DP value. There are also some other methods for life prediction in some papers [43]. Methanol is produced only from cellulose degradation and has no problem with instability. Today, extensive surveys are investigated about this issue.

3.21 CO2 and CO Paper ageing processes generate various by-products in transformers, some of which are stable while others disappear over time [25]. Thermal decomposition of paper impregnated with oil generates CO and CO2 gases which are the final products of the paper destruction [25]. The generation rate is increased exponentially with increasing the temperature [25]. CO and CO2 are also generated at low concentration through oxidation of oil [4] and their concentrations in the oil are commonly measured using dissolved gas analysis (DGA) . IEC 60599 specifies the range of 3 < CO2 /CO < 10 for the normal paper ageing where CO2 /CO is the ratio of the gas concentrations [25]. A ratio < 3 indicates a fault involving paper insulation [44]. The CO2 /CO ratio may also be used to estimate the condition of the insulation paper. The main advantages of using the CO2 /CO ratio, rather than the 2-furfural concentration, are that (a) the CO2 /CO ratio is much more stable and (b) if gas leakage from the atmosphere into the transformer occurs, the ratio will not vary as much as the individual CO2 and CO concentrations [25].

3.22 The Combination of CO2 /CO Ratio and 2-Furfural Among all furans, the 2-furfural chemical index is used because of its higher stability for estimating the DP value and its weaknesses were also considered as indicators. The main problems with using the concentration of 2-furfural to estimate the DP of the paper are (a) 2-furfural is generated in different ways, and therefore is not exclusively the result of degradation of cellulose [45] and (b) 2-furfural is not stable at temperatures above 110 °C and (c) the presence of oxygen, water and acids affects the 2-furfural concentration [25, 46]. It follows that the predictions of the remaining service life-time of a transformer may not always be reliable based exclusively on the concentration of 2-furfural in the oil [25, 41]. The CO2 /CO index was also introduced and it was stated that this indicator shows the ageing status of the transformer but DP value could not be achieved. For this purpose, a new method has been introduced in the reference [25] which can be used to estimate the DP value by combining the 2-furfural indicator and the CO2 /CO ratio. In this new method, four ranges of CO2 /CO ratio, four corresponding ranges for the DP value and four corresponding classifications of the condition of the transformer paper insulation are defined as shown in Table 3.2 [25].

3.22 The Combination of CO2 /CO Ratio and 2-Furfural Table 3.2 CO2 /CO ratio ranges and the corresponding DP ranges [25]

Table 3.3 DP values and 2-furfural and methanol concentrations at 98 °C [47]

CO2 /CO ratio R

55

DP value

Condition

R ≤ 7.4

>600

Healthy

7.4 < R < 8.0

400–650

Normal

8.0 ≤ R < 8.7

250–450

Weak

R ≥ 8.7

1000

Significant oil decomposition. Need for close and accurate monitoring

>2500

Very severe oil decomposition. Need to identify faults

4.2 Total Flammable Dissolved Gas in the Transformer The possibility of an electric fault or other failures could be predicted by the total concentration of flammable gas soluble in transformer oil, i.e. by increasing the concentration of H2 , CH4 , C2 H6 , C2 H4 , C2 H2 and CO. By quantifying this quantity and referring to the predetermined limits of this quantity, it is possible to determine the abnormal conditions of gases in the oil with using Table 4.2 [1].

4.3 Allowable Concentration of Gases in a Transformer The concentration of flammable dissolved gases in the oil depends on [1]: A. The total volume of the oil in the transformer, B. The age of the transformer, C. The type of transformer from the viewpoint that it is sealed or the air breathing transformer as well as its tap changer structure and so on. Some suggested values obtained through the statistical analysis of the DGA results of a large number of healthy and failed transformers are presented in Table 4.3 [1].

4.4 Gas Ratio Methods These methods are convenient and reliable for the fault detection in the transformer and they could be analyzed by the computer programs. In addition, the concentration of a gas may be very little. Therefore, the ratio of a gas to another gas could be used instead of one gas concentration. The disadvantages of these methods are that they may not always be analytic or in some cases, the results are inaccurate. Therefore, these methods should be used in conjunction with the other analytical methods.

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Table 4.3 Analysis results of a large number of healthy and failed transformers [1] Gases

Less than 4 years of operation

Between 4 and 10 years of operation

More than 10 years of operation

H2

100–150

200–300

200–300

CH4

50–70

100–150

200–300

C2 H6

30–50

100–150

800–1000

C2 H4

100–150

150–200

200–400

C2 H2

20–30

30–50

100–150

CO

200–300

400–500

600–700

CO2

3000–3500

4000–5000

9000–12,000

Table 4.4 Permissible L1 limits for Dürrenberg ratio method [3] Gases

L1 concentration (ppm)

CO

350

CH4

120

H2

100

C2 H6

65

C2 H4

50

C2 H2

35

4.4.1 Dürrenberg Method This method could be used to detect three main types of faults such as heating, lowintensity corona, partial discharge and arc. This method uses four gas ratios including R1 (CH4 /H2 ), R2 (C2 H2 /C2 H4 ), R3 (C2 H2 /CH4 ) and R4 (C2 H6 /C2 H2 ) [3]. First, the concentrations of the gases in the oil are determined to see whether these values are higher than the permitted L1 limits or not [3]. L1 limits are presented in Table 4.4. If the minimum concentration of one of H2 , CH4 , C2 H4 and C2 H2 gasses exceeds twice limit L1 values and one of the other three gases exceeds the L1, the transformer is considered to have the fault [3]. Each of the four ratios R1 (CH4 /H2 ), R2 (C2 H2 /C2 H4 ), R3 (C2 H2 /CH4 ) and R4 (C2 H6 /C2 H2 ) are compared with the values given in Table 4.5. The results of the study on the combination of gases show less compliance between this method and actual faults [3]. Therefore, Rogers has provided a more definitive and precise method.

4.4 Gas Ratio Methods

69

Table 4.5 Fault diagnosis by Dürrenberg ratio method [3]       Fault type 4 2 H2 2 H2 R1 CH R2 C R3 CCH H2 C2 H4 4 Thermal decomposition