Using Refractive Index to Monitor Oil Quality in High Voltage Transformers

by

Ryan John Kisch

B.Sc.E.E., Saginaw Valley State University, 2004

A THESIS SUBMITTED IN PARTIAL FULFILMENT OFTHE REQUIREMENTS FOR DEGREE OF

MASTER OF APPLIED SCIENCE

in

The Faculty of Graduate Studies

(Electrical and Computer Engineering)

THE UNIVERSITY OF BRITISH COLUMBIA

(Vancouver)

June 2008

© Ryan John Kisch, 2008

Abstract

Insuring reliable operation of high voltage electrical equipment, such as transformers and cables,

is of great importance to the power industry. This is done by monitoring the equipment. A large

portion of this monitoring includes analyzing the quality of the insulating oils and observing

various compounds formed in the oils during aging. Most often, transformer monitoring

includes routine oil sampling and analysis, which has proven to be very effective at diagnosing

faults and determining the insulation condition. Many techniques have been demonstrated for

the purpose of online monitoring, and various commercial products are available. However,

utility companies are still looking for more cost effective methods to monitor their equipment

between sampling intervals. The work presented here was performed in order to investigate the

use of refractive index for monitoring insulating oils. The refractive indices of various oil

samples obtained from the field were measured and differences were observed. Accelerated

aging experiments were conducted in a laboratory and increases in the refractive indices of these

artificially aged oils were observed. Experiments were conducted to determine what by-products

would contribute to this increased refractive index by investigating the effects of individual

groups on the refractive index change. These groups included aromatic compounds, polar

compounds, furans, acid, and fault gases. We observe that the formation of furans, acids, and

fault gases cannot be detected using refractive index for the concentrations typically found in the

field. We conclude that changes in the refractive index of an oil can be used as an indicator of

the oil’s aging and its break down and the formation of aromatic and polar compounds.

11

Table of Contents

Abstract.iiTable of Contents iiiList of Tables viList of Figures viiiList of Symbols and Abbreviations xiAcknowledgements xiv1 Introduction and Motivation 1

1.1 Overview 2

1.2 Review of Applied Equipment Monitoring Techniques 4

1.2.1 Dissolved Gas Analysis 5

1.2.2 Furans 9

1.2.3 Moisture 10

1.2.4 Oxygen 10

1.2.5 Interfacial Tension (IFT) 11

1.2.6 Neutralization Number/Acid Number 12

1.2.7 KV BreakdownlDielectric Breakdown 12

1.2.8 Color 13

1.2.9 Polar Compounds 13

1.2.10 OnlineMonitoring 14

1.3 Review of Research into Insulation Diagnostics 16

1.4 Our Investigation 20

2 Measuring Refractive Index 232.1 Introduction to Sensors 23

2.2 Why Use Refractive Index’ 23

2.3 Introduction to Sensors 28

2.4 The D-Fiber Sensor 28

111

2.4.1 D-fiber Sensor Fabrication 36

2.4.2 Placing the D-Fiber Sensor into the Measurement System 37

2.4.3 Sensor Calibration 39

2.4.4 D-fiber Sensor Resolution 43

2.5 FISO Refractive Index Sensor System 49

3 Experiments 533.1 Introduction to Chapter 53

3.2 Samples Obtained From the Field 54

3.2.1 Dissolved Gas In Oil Samples From the Field 54

3.2.2 Other Measured Properties of Oil Samples Obtained From the Field 59

3.3 Effects of Accelerated Aging on Refractive Index of Oils 64

3.4 Polar Compounds in Oil 76

3.4.1 Introduction to Section 76

3.4.2 Methanol Extraction 76

3.4.3 Oil Samples 77

3.4.4 Refractive Index Measurements 79

3.4.5 Polar Compound Extraction From Naturally Aged Oils 84

3.4.6 Discussion 87

3.5 Effects of other Contaminants in Oil 89

3.5.1 Oil Samples Spiked with Furans 89

3.5.2 Acid Artificially Introduced into Oil Samples 94

3.5.3 Gas Artificially Introduced into Oil Samples 97

4 Summary, Conclusion, and Suggestion for Future Work 1024.1 Summary 102

4.2 Conclusion 104

iv

4.3 Suggestions for Future Work .106

References 109

V

List of Tables

Table 1-1: Common commercially available transformer oils with type and refractive index

listed 4

Table 2-1: Results of non-relative measurements conducted to find resolution for constant

system operation of two and a half hours 46

Table 2-2: Temperature results of relative duration period measurements to show average

temperature variation over relative measurement period 47

Table 2-3: Transmission ratio results of relative duration period measurements to show average

transmission variation over relative measurement period 47

Table 2-4: Refractive index results of relative duration period measurement conducted to find

resolution of system using relative measurement 48

Table 2-5: Results of refractive index resolution test using two oils with very close refractive

index values 49

Table 3-1: Refractive index measurement and DGA results of cable oil samples taken from the

field 56

Table 3-2: Refractive index measurement and DGA results of transformer oil samples taken

from the field 57

Table 3-3: Refractive index measurement and DGA results of load tap changer samples taken

from the field 58

Table 3-4: Measured refractive indices of oil samples obtained from the field with some

physical and chemical property values shown 60

Table 3-5: Measured refractive index versus time for accelerated aging samples at 120°C 65

vi

Table 3-6: Measured refractive index versus time for accelerated aging samples with varying

contents at 150°C 68

Table 3-7: Measured refractive index versus time for accelerated aging samples with varying

contaminants at 150°C 71

Table 3-8: Aging conditions for oils used in polar compound measurements 78

Table 3-9: Measured properties of aged oils 79

Table 3-10: Refractive index measurements of oil and methanol samples and concentration of

polar compounds measured by HPLC 80

Table 3-11: Refractive index measurements of naturally aged oil and methanol samples and

area of polar compounds measured by HPLC 84

Table 3-12: Measured refractive indices of oil samples varying in 2-furaidhyde concentration. 90

Table 3-13: Measured concentrations of furans in l2mL Luminol samples spiked with 3 drops

of furan mixture 91

Table 3-14: Measured refractive index change due to acid added to Luminol TRi oil samples at

varying concentrations 95

Table 3-15: Measured refractive index change due to ethane injection into Luminol TRi oil

samples at varying concentration levels 98

Table 3-16: Measured refractive index change due to acetylene injection into Luminol TRi oil

samples at varying concentration levels 98

vii

List of Figures

Figure 1-1: Generation of combustible gases in transformer oils due to temperãturë and faults

(not to scale). This figure is similar to the gas generation chart found in [1] 6

Figure 2-1: Normalized plot of the real and the imaginary value of refractive index as a

function of frequency. A similar figure is found in [45] 25

Figure 2-2: Real value of refractive index versus wavelength illustrating change in refractive

index values with different resonant frequencies 27

Figure 2-3: (a) Magnified cross section of a typical step-index circular single mode fiber. (b)

Magnified cross section of the core showing the refractive index profile and the optical field

distributions. Decaying optical fields in the cladding are called evanescent fields. A similar

figure found in [44]. (Figure not to scale) 30

Figure 2-4: D-fiber cross section (not to scale), showing the core dimensions, cladding thickness

“d” between the core and outer cladding flat side, and the protective jacketing surrounding the

cladding 31

Figure 2-5: (a) Section of D-fiber: For a section of D-fiber, with length “L”, the distance “d”

between the core and planner side of the cladding is reduced by Ad giving a new distance dr. (b)

and (c) show the respective refractive indices and optical field distributions in the “cut-out

section” shown below (a) [note, co-ordinate system rotation]. (b) shows a section not etched,

with d between core/cladding interface and field confined to the fiber. (c) shows a section after

etching, with reduced distance dr and field extending into the external medium 33

Figure 2-6: Calibration curve measured by sweeping the refractive index of the three thermo

optic oils by temperature control, and recording the power transmission. Region I, II, III, and the

lossless region are shown 34

Figure 2-7: Diagram of experimental set-up showing D-fiber sensor and FISO sensor 38

viii

Figure 2-8: Measured power transmission of D-.fiber sensor at various optical wavelengths. ... 42

Figure 2-9: Calibration curve shown for operating wavelengths of 1550nm and 1500mm The

operating point is moved by increasing the temperature. When the temperature control has been

exhausted the wavelength can be shifted to move the operating point further 44

Figure 2-10: Diagram of FISO system setup 51

Figure 3-1: The refractive index of transformer oil samples minus the refractive index of load

tap changer oil samples obtained from same equipment from the field 62

Figure 3-2: Plot of measured oil refractive index versus aging time when exposed to a

temperature of 120°C 66

Figure 3-3: Plot of measured oil refractive index versus time when exposed to a temperature of

150°C with different contents present 69

Figure 3-4: Plot of measured oil refractive index versus time when exposed to a temperature of

150°C with different contaminants present 72

Figure 3-5: Examples of different types of hydrocarbon compounds. (a) example of a

parraffinic compound (hexane). (b) example of a naphthenic compound (cyclohexane). (c)

example of a aromatic compound (benzene) 74

Figure 3-6: Methanol extract refractive index versus the area of polar compounds measured by

HPLC in nitrogen blanketed oil samples 82

Figure 3-7: Methanol extract refractive index versus the area polar compounds measured by

HPLC in free breathing oil samples 83

Figure 3-8: Methanol extract refractive index versus the area of polar compounds measured by

HPLC in naturally aged oil samples 85

Figure 3-9: Change in refractive index of naturally aged oils after methanol extraction versus

the area of polar compounds measured by HPLC 86

ix

Figure 3-10: (a) Chemical structure of benzene. (b) Chemical structure of Furan (c)

Chemical structure of 2-furaldehyde 93

Figure 3-11: Change of refractive index of Luminol oil samples versus approximate acid

number 96

Figure 3-12: Change of refractive index of Luminol oil samples plotted versus approximate

ethane gas concentrations injected 99

Figure 3-13: Change of refractive index of Luminol oil samples plotted versus approximate

acetylene gas concentrations injected 100

x

List of Symbols and Abbreviations

IEEE Institute of Electrical and Electronic Engineers

PCB’s Polychiorinated biphenyls

IFT Interfacial tension

ASTM American Society for Testing and Materials

DGA Dissolved gas Analysis

02 Oxygen

N2 Nitrogen

H2 Hydrogen

CH4 Methane

CO Carbon monoxide

CO2 Carbon dioxide

C2H6 Ethane

C2H4 Ethylene

C2H2 Acetylene

NPLC High pressure liquid chromatography

KV Kilovolt

ppm Parts per million

UV Ultraviolet

n Refractive index

n’ Real part of refractive index

Imaginary part of refractive index

N Number of atoms per unit volume

xi

Vacuum permittivity

e Electron charge

in Mass of electron

co Frequency

Resonant frequency

7 Damping coefficient

Wavelength

FOT Fiber Optic Temperature sensor

FRI Fiber Optic Refractive Index sensor

d Cladding thickness of D-fiber

n0 Refractive index of fiber core

Refractive index of fiber cladding

HF Hydrofluoric acid

next Refractive index of external medium

fleff Mode effective refractive index

Tr Power transmission ratio

Propagation constant

fir Real part of propagation constant

fl3 Imaginary part of propagation constant

L Length of etched section of D-fiber

Pt Power into leaky section of D-fiber

P0 Power out of leaky section of D-fiber

DI De-ionized

Pmeas Power measured

xii

Fmax Maximum power

25 Refractive index at 25°C

T Temperature

Refractive index sensor resolution

Change in refractive index

Ulvil Universal Multicharinel Instrument

df Distance between reflecting surfaces

F Finesse

R Reflectance

V35 Voltesso 35 oil

LTC Load tap changer

TX Transformer tank

RI Refractive index

ppb Parts per billion

xiii

Acknowledgements

First I would like to thank my family and close friends for always being there for me, and

showing constant love and support throughout my education. The encouragement from my

mother, father, brother Shawn, and relatives helped keep me going when faced with challenges

during my studies.

I would like to thank my supervisor, Dr. N. A. F. Jaeger, for his expert guidance,

continual patience, and support. He has taught me about more than just engineering during my

studies at UBC.

I would like to thank my colleagues in the optics lab for the company, support, and ideas

they shared. Special thanks to Sameer Chandani for the time he set aside to discuss problems

and provide assistance while he was conducting his own studies.

I would like to thank Powertech Labs and its employees for their collaboration and the

resources that were provided for this investigation. Special thanks to Salim Hassanali for his

sharing of knowledge, helpful suggestions, and technical support. Thanks to Stevo Kovacevic

and Edward Hall for their technical support as well.

I would like to thank FISO Technologies Inc. for their collaboration in this work by

providing their equipment to us. Thank you to Francois Bouchard for his support and interest in

this investigation.

Finally, I would like to thank Becky for her love and support.

xiv

Chapter 1

1 Introduction and Motivation

The purpose of this chapter is to provide an introduction to the topic of high power

electrical equipment monitoring and set the stage for the research conducted here. It begins with

a brief overview describing the types of equipment that are of interest and their liquid and paper

insulating systems. The most common way of monitoring these types of equipment is by

monitoring the condition of the insulation. Hence, we review some of the methods currently

used by the utility companies to monitor the condition of these equipment insulation systems.

Some key indicators that are commonly used to assess the operating condition of such

equipment, as well as the condition of the insulation itself, are presented. These key indicators

include, but are not limited to, various aging by-products such as dissolved gases, acids, furans,

and water, and an oil’s dielectric strength and color. Hence, several of the tests used for

equipment monitoring are briefly described.

In addition to the tests performed in the laboratory, many companies have developed

systems for online monitoring in order to aid in diagnosing the operating condition of equipment.

Research groups are exploring new techniques to improve on current monitoring methods. This

research includes improvements to current in-lab methods, as well as in-situ techniques

including online monitoring. A literature review of some of the investigated monitoring

techniques was conducted. This resulted in our decision to investigate how the aging of

transformers would affect the refractive indices of their oils, This investigation is the topic of

this thesis.

1

1.1 Overview

The electrical power industry uses a complex system to generate, transmit, and distribute

electricity that is used by commercial, industrial, and residential consumers. This industry has

grown rapidly since the early 20th century, and has now become an integral part of our modem

society. Lack of power has major social and economical impacts, as was observed in the

Northeast Blackout of 2003 (on August 14th), which affected many eastern cities in the United

States and Canada. Although such serious power outages are not a common occurrence,

electrical utility companies do often experience outages to a smaller degree which not only

inconvenience both the companies and the consumers, but also generate a loss of revenue. For

this reason extensive research has been conducted in order to develop techniques to indicate

potential faults and future failures so that preventative action can be taken [1] [2] [3] [4] [5] [6].

Currently there are many new research areas being explored to make the electrical system even

more efficient and to minimize equipment failure [7] [8] [9] [10] [111.

In some cases, failure of a single piece of equipment used by an electric utility company

may be the cause of a power outage. High voltage equipment is generally very expensive, so

maintenance and care is taken not only to prevent failures from occurring, but to prolong the life

of these expensive assets. This equipment includes, but is not limited to, oil filled transformers

and oil filled high voltage power cables. Transformers that are used in an electrical transmission

system to step up and step down voltage levels, in order to minimize power loss on transmission

lines, are called power transformers. Transformers that are used at various points in the system

to measure the voltage and current at different locations, are known as instrument transformers.

An insulation system using both liquid and paper is commonly used for both types of

transformers as well as for underground high voltage power cables. There are many

maintenance activities performed in order to extend the life of equipment such as inspecting the

2

physical condition of a transformer’s bushings, tanks, and gaskets, but most experts would agree

that the most important maintenance procedures involve checking the condition of the

equipments’ insulation. According to many standards organizations such as the Institute of

Electrical and Electronic Engineers (IEEE), the average life of a power transformer is 20 to 25

years, and the lifetime is usually related to the condition of the transformer’s insulation [12].

Paper insulation, comprised of cellulose such as Kraft-paper, has been used historically to

insulate transformer conductors and can be used to insulate high power cables as well [3]. Other

papers that can be used include Nomex Aramid paper and Polyester Composite based papers

[13]. Good dielectric properties, high thermal rating, and low moisture absorption are all key

characteristics of a good insulating paper. Over the lifetime of a transformer, the condition of

the paper will degrade due to exposure to high temperatures, oxygen, moisture, and numerous

other contaminants found in the insulation system. In many cases, the paper will work in parallel

with the oil to provide insulation, in which case the condition of both the oil and the paper

affects the equipment lifetime. Oil is used in electrical equipment not only due to its ability to

provide good electrical insulation, but also because it is very stable at high temperatures.

Initially mineral oils were used due to their availability, as they were fabricated by

refining hydrocarbons collected in the distillation process of petroleum [7]. Mineral oils consist

of basic hydrocarbon liquids such as paraffin, naphthene, aromatic hydrocarbons, and olefin [5].

Mineral oils are still most commonly used today in high voltage equipment, although companies

are trying to find other liquids that may be better. Synthetic oils based on polychlorinated

biphenyls (PCB’s) were introduced due to their low flammability, but in the 1970’s their use

declined as the toxic effects on the environment became a concern, and restrictions regarding

their use were put in place. In searching for substitutes that were nontoxic and noncombustible,

ester liquids, silicone fluids, and vegetable oils were proposed, although they were more costly

3

and less readily available [7] Some commercially available transformer oils that are commonly

used are shown in Table 1-1 with the type and refractive index listed.

Table 1-1: Common commercially available transformer oils with type and refractive indexlisted.

Insulating Oil Type Refractive Index @ 20*CGE SF97-50 Silicone 1.4000

Dow Corning 561 Silicone 1.4040Rhodorsil 604 V 50 Silicone 1.402 @ 25°C

Clearco STO-50 Silicone 1.4000Envirotemp FR3 Ester 1 .47 50

Midel 7131 Ester 1.4555Biotemp Vegetable Oil 1.4708

ECO Fluid Mineral 1 .4600Shell Diala AX Mineral 1.4815

Volteso-35 Mineral 1.4743*

Lurninol Tn Mineral 1.4552*

1.2 Review of Applied Equipment Monitoring Techniques

In the next section we will discuss applied equipment monitoring techniques which are

those insulating monitoring techniques most commonly used by utility companies today. Oils

can be tested in many different ways, and data can be collected over time, in order to spot trends

and to provide insight into factors that can reduce equipment lifetime. Initially changes in the

insulation due to the influence of service conditions will occur at the molecular level, which will

eventually lead to chemical reactions resulting in the formation of new chemical compounds [6].

For this reason, a variety of tests are performed to indicate the insulation condition. Oil may be

tested for its gas content, dielectric breakdown strength, acidity, water content, oxidation

inhibitor, ash content, viscosity, metal content, and interfacial tension (IFT) [4] [12] [14] [15]

[16]. Test standards have been set by organizations such as the American Society for Testing

*

Measured using FISO FRI sensor at (discussed later in this thesis).

4

and Materials (ASTM) [16] and, in many cases, tests are performed accordingly. In what

follows in this section, a variety of these tests currently being used will be discussed

1.2.1 Dissolved Gas Analysis

The most common test performed when analyzing the oil insulation of equipment is

dissolved gas analysis (DGA) [l][2][12][14][15][17][18j. Over the life cycle of the equipment,

many gases will be dissolved in the insulating oils for various reasons, and detection of these

gases can be indicators of a piece of equipment’s condition. Absorption from the atmosphere,

the breakdown of hydrocarbon chains present in the oil, and the breakdown of cellulose in the

insulating paper can all contribute to the addition of gases such as oxygen (02), nitrogen (N2),

hydrogen (H2), methane (CH4), carbon monoxide (CO), carbon dioxide (C02), ethane (C2H6),

ethylene (C2H4), acetylene (C2H2), and other hydrocarbons to the oil [7]. Since various gases

will be generated under various conditions, the presence and quantity of a particular gas can be a

significant indicator of a particular problem. By measuring the changes in relative levels of

these gases, faults such as arcing, corona, overheating of the oil, and overheating of the cellulose

can be revealed.

Temperature is one factor that can cause the generation of fault gases and, in general, can

greatly reduce the lifetime of a transformer. An increase in operating temperature of 10°C above

the equipment rating may reduce a transformers operating life by about one half [12]. Higher

temperatures can be created due to failures of cooling systems, equipment overloading, and the

presence of arcing or electrical discharge. Various fault gases will be generated at different

temperatures and at different rates as shown in Figure 1-1. Electric utility companies will often

take oil samples from their oil filled equipment and send them to a laboratory such as Powertech

Labs, in Surrey. British Columbia, Canada, where the oil can be analyzed for fault gases using

5

HydrogenH2

Methane

C2H2

___

Arc

Figure 1-1: Generation of combustible gases in transformer oils due to temperature and faults(not to scale). This figure is similar to the gas generation chart found in [1].

1•Ethylene

C2H4

AcetyleneC2H2

- NomialOperafion

Hot Spots

I 0 100 200 300 400 500 600 700 800 900 1000Partial Discharge Temperature °C

Not Temperature Dependent

6

the DGA method. This is most often done by separating the gases from the oil using gas

chromatography so that the quantity of each gas can be detected [6] [9].

Gases such as hydrogen and various hydrocarbons, in particular, methane, ethane,

ethylene, and acetylene are formed due to the breakdown of hydrocarbon chains present in the

oil. This breakdown is part of the oil degradation process. As shown in Figure 1-1, partial

discharge will lead to the formation of many of these gases, known as combustible gases,

although the concentration of H2 will be much more prevalent as compared to others. At about

150°C, hydrogen and methane will begin to be generated which can be attributed to hot spots or

corona discharge [1]. Further overheating of the oil to 250-300°C, can lead to the production of

more methane and ethane, which may occur in the presence of hot spots as well. As the

temperature rises to yet higher levels, and eventually reaches about 350°C, ethylene will be

produced while the production of other gases will not be as pronounced. Acetylene is produced

at extremely high temperatures starting around 500°C and becomes more commonly found in oil

experiencing arcing conditions, which typically generates temperatures in excess of 700°C.

Large amounts of hydrogen are also generated under arcing conditions. By analyzing the

concentration of each gas, decisions can be made regarding the state of equipment, and it can be

determined whether or not the equipment is operating safely or if it should be taken offline and

repaired or replaced.

Faults may be revealed when the concentrations of gases are known, and the type of

servicing needed for the transformer may be established using diagnostic procedures [1] [2].

The IEEE has developed a guide to classify the state of transformers based on gas levels which

rates them from condition 1, which indicates that the transformer is operating safely, to condition

4, which indicates that the gas concentrations exceed safe limits and the equipment should be

taken offline [19]. Another popular method used to analyze the type of fault occurring in the

7

equipment is the Rogers Ratio Method where ratios between acetylene and ethylene, methane

and hydrogen, and ethylene and ethane indicate the type of fault that is likely occurring [1].

The amount of dissolved gas found in an oil sample can be used as a guideline for fault

analysis, but even more important is the rate of increase of these gases. The total concentration

of gases found in an oil includes the collection of gases over the entire lifetime of the equipment

which may be due to small amounts being generated over a long period of time, or large amounts

being generated over a short period of time. Therefore, it is also important to know the history

of the equipment as well, so that current levels can be compared to previous levels to see if there

is a sudden increase. A general rule that may be used is, if the gas concentration increases by

10% of the maximum allowable concentration in a month, then there is a problem [12].

Other than hydrogen and the hydrocarbons thus far discussed, other gases such as carbon

monoxide, carbon dioxide, oxygen, and nitrogen may also be detected when performing DGA.

Carbon dioxide, oxygen, and nitrogen may be present in the oil, as they can be absorbed from the

surrounding air, depending on the construction of the transformer. In most cases, insulation

exposure to air is avoided by sealing and pressurizing the equipment. This not only aids in

keeping the oil isolated, but also helps stabilize the system to account for large pressure changes

that can occur due to temperature fluctuations and/or arcing [15]. There are many different

transformer designs used, including the older free breathing style where air exposure is more

common, those using bleeder valves that allow air to leave and enter the enclosure to compensate

for pressure changes, free breathing conservator types (where oil contained in a separate

conservator will be in contact with air), conservator system types having a bladder to reduce air

exposure further, and systems filled with an inert gas such as nitrogen which minimizes the

amount of oxygen and moisture that comes in contact with the oil [12]. In any case there will

most often be these atmospheric gases present in a sample as well as moisture. Oxygen and

8

moisture can greatly reduce the lifetime of a transformer, and detecting certain levels can

indicate a leak in the system.

Carbon gases such as carbon monoxide and carbon dioxide can be generated due to the

breakdown of cellulose contained in the paper insulation, which can give an indication of the

insulating paper condition. When temperatures reach about 100°C, the cellulose insulation will

begin to decompose, so detecting these gases can give some indication of overheating [12].

Although detecting these gases can give some indication of the breakdown of paper insulation,

detecting the amount of furans is most often used to measure a paper insulation system’s

strength.

1.2.2 Furans

It is not practical to directly measure the insulating paper’s tensile strength, or degree of

polymerization, as this would require the removal of a strip of paper from the winding when the

transfonner is not in service [3]. Other means are, therefore, necessary in order to assess the

condition of the paper. Oil can be tested for the concentration of furan compounds which

provide an indication as to the degree to which the paper has been degraded [7] [20]. In

particular, the concentration of 2-furaldehyde has been directly related to the degree of

polymerization of the paper [21]. Furan testing can be performed using the same samples that

are extracted for DGA according to ASTM Method D 5837-99 [22]. Companies, such as

Powertech Labs, will perform screen testing to measure the amount of 2-furaldehyde contained

in a sample and, if high levels are found, further testing for more furans using high pressure

liquid chromatography (HPLC) are conducted [23]. Furans are formed in the presence of high

temperatures, oxidative compounds, acids, and moisture, and can be used to estimate the residual

lifetime of the paper insulation [17].

9

1.2.3 Moisture

Water may be present in an insulation system. It may be in the form of tiny droplets

suspended in the oil, it may be dissolved in the oil, or it may be in a free state usually at the

bottom of the taik holding the oil [14]. The dielectric strength of oil is weakened when moisture

is added to it. The combination of moisture and oxygen will degrade paper insulation at an

accelerated rate and can lead to the formation of acids and sludge. Moisture can be present in oil

filled electrical equipment if it is absorbed by the paper insulation during manufacture, or can

enter the system through a leak in the form of water or humidity. The amount of water that can

be dissolved in oil is temperature dependent, and higher temperatures allow for larger

concentrations [15]. Also, moisture will constantly redistribute itself between the paper and the

oil, depending on the temperature. For example, at 20°C the ratio of water in the paper as

compared to in the oil may be as high as 3000:1 whereas at 60°C the ratio may only be 300:1

[12]. It is, therefore, important to record the temperature of the system when extracting an oil

sample in order to estimate the water content in the paper insulation. In most cases, levels of

moisture ase analyzed in oil samples when performing DGA and the concentrations are

measured in parts per million (ppm). The concentration of moisture can be compared to the

percent saturation at the measured extraction temperature to determine whether the level is

acceptable and if it is increasing. The moisture content in oil samples can be measured

according to ASTM Method D 1533-00 [24].

1.2.4 Oxygen

Another important factor that can aid in analyzing insulation quality is the concentration

of oxygen in an oil sample. Levels of oxygen exceeding 2000 ppm may deteriorate paper

insulation at an accelerated rate and a concentration of 10000 ppm indicates that the oil should

be de-gassed [17]. The presence of oxygen can lead to chemical reactions that form acids and

10

poiar compounds which can eventually lead to sludge. Sludge will coat the windings and may

cause and/or contribute to heat transfer problems. In sealed transformers oxygen can enter the

system through leaks or be produced in the presence of water. Open breathing type transformers

will obviously have a higher concentration of oxygen in the oil and will, therefore, experience a

more rapid rate of oxidation and moisture related effects. Higher temperatures also contribute to

faster oxidative breakdown, which emphasizes the need to keep operating temperatures at

suitable levels and to avoid overloading [14]. A transformer operating with normal levels of

oxygen present in the insulation system may have a lifetime up to ten times longer than one

operating with higher levels [17]. In order to reduce the levels of oxygen, and its effects,

antioxidants and oxygen inhibitors may be used. An antioxidant such as 2,6-di-tert-butyl-p-

cresol can be added to a transformer oil to prevent oxidation; decreases in the antioxidant

concentration can be used to characterize the condition of the liquid insulation [6]. The

oxidation process can also be slowed down naturally as some oils contain chemical compounds

that act as natural inhibitors. Laboratories that perform DGA will often perform tests to measure

the amount of oxygen inhibitor present and, if levels become too low, the antioxidant may be

replaced when the oil is treated.

1.2.5 Interfacial Tension (IFT)

Interfacial tension is a measure of the boundary strength at an oil/water interface. An oil

sample should “float” when added to water, creating a distinct boundary between the two. The

interfacial tension between oil and water is weakened in the presence of polar compounds and

other contaminants formed by oxidation [14]. The force, in dynes per centimeter (ASTM D

971), needed to pull a small wire through the oil/water interface is a measure of IFT [25]. One

dyne is equal to iO newtons. New oil should measure about 40-50 dynes per centimeter [17].

Over the lifetime of a transformer the IFT will generally decrease exponentially. An increase in

11

the acidity is usually observed as well, although it usually lags the decreasing IFT. When both

are measured, low IFT and high acidity can provide an excellent indication of poor oil quality.

Sludging will often begin at IFT levels around 22 dynes per centimeter and at high levels of

acidity [14].

1.2.6 Neutralization Number/Acid Number

Acids tend to accelerate the breakdown of paper insulation and act as catalysts to the

degradation of transformer oils [13]. Acids are formed during the aging of insulation through

oxidation and will attack metals, will form sludge at a neutralization number of about 0.4, and

will attack the cellulose in the paper, greatly decreasing the equipment lifetime [12]. The

neutralization (or acid) number is found by measuring the amount of potassium hydroxide

(KOH) required to neutralize the acids in 1 g of oil. The neutralization number test can be

performed according to ASTM D-974 [26]. This test is not a direct indication of the oil’s

dielectric strength, but does indicate the presence of contaminants and lowered oil quality.

1.2.7 KY Breakdown/Dielectric Breakdown

The KV (Kilovolt) Breakdown or Dielectric Breakdown test is a measure of the oil’s

dielectric strength or ability to withstand electric stress [15]. Laboratories test for dielectric

strength by applying large voltages to oil samples and recording the levels at which the oils

break down. Factors that can affect the measured dielectric breakdown voltage of insulating oils

include water content, oxidation products, size and number of particles in the oil, and, if

saturation levels are exceeded, concentration of dissolved gases [27]. The acceptable minimum

breakdown voltage, according to the IEEE [28], is 30 kV for transformers operating at 230 kV

and above, 28 kV for those rated between 69 kV and 230 kV, and 23 kV for those rated at 69 kV

or less, using a 1 mm gap between electrodes as outlined in ASTM D 18 16-04 [27]. Other tests

12

must be done in addition to measuring the dielectric strength of oil since, for example, the paper

insulation may be severely degraded long before the oil insulation begins to break down.

1.2.8 Color

New or unused oils will most often be clear before being placed into a transformer tank

and stressed. Some older types of oil will have a light yellowish appearance when unused. As

oils are aged, and contaminants are formed, they will begin to change color, becoming darker.

An oil’s color is often measured by comparing it to a color wheel and assigning a number,

wherein a higher number indicates a darker color [15]. The test procedure for measuring color is

described in ASTM D 1500 [29].

1.2.9 Polar Compoundst

As a transformer ages, and the oil and paper degrade, various contaminants are produced

and can be found in the oil. Polar compounds such as aldehydes, ketones, and alcohols, may be

formed during the aging cycle as by-products of chemical reactions [30]. These chemical

reactions may occur due to oxidation, hydrolysis, and/or polymerization. If polar compounds are

present in an oil the insulation quality of the oil will be weakened, and detecting them generally

shows that the oil has been degraded.

Labs often monitor the level of polar compounds in order to help detennine the quality of

the oil. The concentration of polar compounds can be measured using the same HPLC

equipment used to measure the concentration of furans. At Powertech Labs an HP Series lIt —

Part of this subsection is pending publication. Kisch, R.J., Hassanali, S., Kovacevic, S., and Jaeger, N.A.F. (2007)

The effects of polar compounds on refractive index change in transformer oils, Proceedings of High Voltage and

Electrical Insulation Conference ALTAE 2007.

Equipment by Hewlett Packard test and measurement division now known as Agilent Technologies, Santa Clara,

CA, USA

13

liquid chromatogram is used. This piece of equipment can measure the concentration of various

chemical compounds by mixing a solvent (or mobile phase) with the sample (or analyte) and

passing them through a column containing solid material (or stationary phase). When the

mixture is passed through the stationary phase, individual compounds originally contained in the

sample will be eluted at specific retention times. The retention time is the length of time which

elapses between in injection of the solution, containing the compound, into the stationary phase

and the detection of the compound after it has passed through the stationary phase. A

chrornatograph will be produced, containing a series of peaks plotted as functions of time. The

type of compound can be identified and the concentration can be calculated using the retention

time and area under the peak, respectively. As will be discussed later in the thesis, this method

was used in one of our experiments. The relative concentration of polar compounds in an oil

sample was found by adding the total area under the peaks of its chromatograph. This was

repeated for many samples and comparisons were made.

1.2.10 Online Monitoring

Online monitoring is a very efficient way to detect faults in real time and increases the

capabilities of an electric utility company to prevent failures. The purpose of online monitoring

is not to eliminate current techniques such as oil sampling and laboratory analysis, but can be

used to assist in decision making regarding the health status of the insulation and the operation of

the equipment. It aids in monitoring the equipment between sampling intervals and can reduce

the sampling frequency needed. The value of online monitoring has been strongly expressed by

professionals working in the field and extensive research has been, and is currently being,

performed to this end.

A few companies have developed online oil monitoring equipment, including systems

measuring levels of dissolved gases, moisture, and dielectric strength. Combustible gas monitors

14

have been available commercially for quite some time and are widely used [311. The GE

Hydran was one of the first commercially available gas monitors and it functions using a

membrane that allows hydrogen and other combustible gasses to permeate through it. After

being passed into a cell, the gases are detected by measuring the electric current that is generated

as they are “burned”. This product can be used to measure the change in concentration of all

gases collectively; however, it cannot be used to measure the change of each gas individually.

For companies that prefer the detection of hydrogen, the Morgan Schaeffer Calisto** may

be used. This device uses a polymer barrier to separate the gases from the oil and a capillary

tube which extracts hydrogen only. A thermal conductivity detector is used to measure the

amount of hydrogen extracted from the oil. This device can also measure moisture using a solid

state detector [32].

Morgan Schaeffer, along with many other companies, also offer portable dissolved gas

analyzers, however, a technician is still required to set up the measurement apparatus at the

equipment site. These portable units often work using gas chromatography, which allows for the

detection of the eight key fault gases. A few companies, such as Serverontt, have taken the same

type of technology used in the portable analyzers and designed stationary online monitors.

Although instruments such as the Serveron Online Transformer Monitor have the accuracy to

meet a laboratory grade DGA, few utility companies can afford to outfit many transformers with

this equipment due to its high cost [311.

§ Equipment by General Electric Energy, Atlanta, GA, USA

**Equipment by Morgan Schaeffer, LaSalle, QC, Canada

Equipment by Serveron, Hilisboro, OR, USA

15

1.3 Review of Research into Insulation Diagnostics

In this section we will discuss some of the techniques that have been investigated for the

purpose of insulation diagnostics and fault detection but that have not commonly been applied in

the field. Numerous groups have investigated various high power equipment monitoring

techniques. Gas and chemical sensors have received significant attention for this purpose. These

sensors have become important to several industries. They are often used for chemical

processing, for medical applications, and for molecular biotechnology. Since the types of gases

and chemicals present in the insulating oils can provide helpful information about the equipment,

gas and chemical sensing has become widely researched by groups in the power industry. There

are a variety of techniques that can be used for gas and chemical sensing, all which have

advantages and disadvantages, depending upon the application. For example, electrochemical

or solid state detectors may be very useful for chemical sensing but, when used in a substation to

monitor transformer oils, the interference caused by high electromagnetic fields can affect the

reliability of their readings. Optical means are useful to the power industry because the required

electronics can be located remotely. Optical signals are typically transmitted using optical

fibers, which are immune to electromagnetic interference. One optical technique that has been

widely used to determine the presence of chemical species and gases is optical spectroscopy

[33].

The application of optical spectroscopy to assess the condition of transformer insulation

has been extensively investigated and is currently the subject of ongoing research [9] [34] [35]

[36] [37]. In absorption spectroscopy changes in specific atoms’ and molecules’ energy levels,

due to the absorption of light, are used to identify their presence in a sample. By directing light

through samples and analyzing the transmission or absorption at particular wavelengths, one can

determine whether a particular gas or chemical compound is present in the sample.

16

Many groups have designed systems that showed sensitivity to gases in air, but some of

these sensors have not been used in transformer oil yet. In a study conducted in 1992 [38], aD-

fiber sensor was used to detect methane in air by measuring the absorption, of the evanescent

field, at 1660mn, with a sensitivity in the 1000 ppm range. More recently, in 2004, a fiber optic

system was constructed which could detect the presence of multiple gases by placing silica tube

between hollow sections of fiber, and measuring the molecular absorption [34]. Acetylene and

carbon monoxide lines were observed from 1520-1540 and 1560-1570 nm, respectively. Both

of these sensors, however, were used for proof-of-principle, and were not used to detect gases

present in insulating oils. It is unknown how detectable the gases would have been in

transformer oils, or if the sensors would function as efficiently.

Studies have been performed to develop sensors for the detection of gases and chemicals,

based on absorption, which could operate in transformer oils. Some of these methods, however,

require the aid of another technology that either separates the gases or chemicals from the oils or

otherwise aids in their detection, before absorption is measured. In 1998, absorption of light at

530 nm was used to measure the concentration of furans, as low as 0.lppm, in oil samples [39].

Here, a novel material, which was invented by the authors, was formed using the sol-gel process.

The material was placed between plates which were immersed in oil samples. When the plates

were immersed, furans were absorbed by the material and the concentrations of furans present

were determined by the amount of absorption of light transmitted through the material. This

technology was developed to form the basis of a portable instrument which could be used in the

field, but which required an operator. The authors outlined the possibility of developing a

continuous monitoring system, which could be permanently installed on a transformer, but to the

best of our knowledge, no such system has been built.

17

In 2002 an optical fiber sensor was developed which used absorption as a means of

detecting the presence of methane in transformer oil. A polyflon membrane was first used to

separate the methane from the transformer oil before it was detected as a gas. This methane

sensor was used for proof-of-principle, and demonstrated detection at 28500 ppm. Other

techniques used for separating gases from oils have found their way into commercial products,

as was discussed in the previous section. Nevertheless, the most powerful method for separating

gases and measuring the concentration with the highest sensitivity is gas chromatography.

In the last decade, some groups began to characterize transformer oils by their absorption

profiles, however, they did not only look at gases and furans in oils. A few groups have linked

the formation of aromatic compounds to oil degradation, and have related the absorption peaks at

specific wavelengths to their presence [9][35][36]. In the years between 2000 and 2004,

publications were released which stated that the formation of aromatic compounds in the

transformer oils contributed to changes of the absorption profiles in the UV region (200-3 90 nm)

and that levels of these compounds increased as oil was degraded[9] [35]. Experiments were

conducted using oils taken from failing transformers, as well as using oils in which various

transformer faults such as arcing, overheating, and increased oxidation where simulated. The

authors claimed that measuring absorption at 390 nm could help differentiate between a

transformer failing from either thermal or arcing faults. Around the same time, in 2001, the

authors of [36] claimed that the grade of a transformer oil could be determined by the amounts of

aromatic compounds as well. In this study, however, the authors looked at the spectral

characteristics between 4000 and 1710 cm’, or 2500 and 5882 nm. Various transformer oils

were used that differed in technical grade, service life, and content of antioxidant additive and

dissolved water. The authors concluded that the degree of service deterioration could be

18

determined by measuring the optical density of the oil at 1710 cm1, or 5848 nm, and that small-

size IR spectral equipment could be used for this purpose.

Methods other than using absorption have been researched as well. One of these

methods is optical hydrogen detection using either a palladium film or using a palladium-silver

alloy film. The interaction between hydrogen and palladium results in the formation of a metal

hydrogen alloy, or hydride. When the sensing area of these types of detector are exposed to

hydrogen, the electrical and optical properties of the metal change as a result of the shift in

electronic structure [40] [41]. A few groups have created sensors by measuring the optical

power reflected from a surface with this type of coating. In 2002 a sensor was tested using

transformer oil and detected hydrogen concentrations from 200-1500 ppm [42]. Higher

sensitivity was demonstrated previously in 1996, however, by a group which coated the end of a

fiber with a palladium-silver alloy and detected hydrogen in transformer oils to concentrations as

low as 50 ppm [40]. Although this type of system could be constructed at a relatively low cost,

the sensitivity does not match that of gas chromatography. The authors also revealed that high

levels of other gases can contribute to faulty readings.

In 2005, a group measured the complex permittivity of oils in the frequency range of

20Hz to 1MHz where ionic and molecular polarization processes are expected to dominate [7].

It was observed that the addition of aging by-products, such as water and polar compounds,

could be detected in transformer oils. The change in the real part of the permittivity due to

temperature change increased with increasing moisture present in the oil. Additionally, the real

part of the permittivity increased with moisture content, and the imaginary part increased with

“polarizable inclusions”. A prior study was performed in 1998, by J. Unsworth and N. Hauser,

showing similar results. Changes in oils’ permittivities were measured and related to the

formation of polar compounds [43]. In this study, however, changes in oil refractive indices

19

were also measured. The authors measured increasing permittivities of transformer oils as they

were degraded, which they attributed to the addition of polar compounds. The changes in the

oils’ refractive indices were very small, however, and they did not recommend using these

changes as an indicative parameter of polar compounds. At this time the group used a refractive

index sensor with a resolution of 0.0002, whereas today we have sensors with resolutions at least

one order of magnitude higher [44].

Tn 2004, T. Aka-Ngnui et al. claimed that changes in refractive indices of transformer oils

occur due to the generation of oil degradation products [11]. Voltages large enough to “break”

an oil were applied across electrodes which were immersed in the oil. The cladding of an optical

fiber was removed from a 2 cm section and this sensing section was immersed in the oil as well.

Changes in refractive index were detected by a loss in the optical power transmitted through the

fiber, however, actual refractive index measurement values were not obtained. The change in

refractive index was attributed to the formation of degradation products, however, further

investigation was needed in order to determine what products were formed and the concentration

of each.

1.4 Our Investigation

The applied equipment monitoring techniques being used for laboratory diagnosis are

very effective for determining the health status of equipment when samples are provided.

However, there is still a need for systems which can “flag” the electrical utility companies if the

operation of the equipment or quality of the oil degrades greatly between sampling intervals.

Since the importance of devising new techniques for online monitoring has been thoroughly

expressed in literature, as well as by professionals working in the field, we decided that

exploring online monitoring further would be of value to the power industry, as well as to the

scientific community. After conducting a thorough literature review it was clear that the various

20

methods studied for the purpose of online monitoring each had their advantages and

disadvantages. One single method did not seem to have emerged as a clear favorite over others

for determining the quality of the oil and the operating condition of the equipment.

Using refractive index as an indication of oil quality and equipment operation had not

been extensively researched. The studies performed by J. Unsworth and N. Hauser and by T.

Aka-Ngnui et a!. indicated that measuring refractive indices of transformer oils might be useful

with higher resolution sensors. Since measuring refractive index is relatively inexpensive,

compared to other diagnostic techniques, can easily be incorporated into a system and

implemented for online monitoring in the presence of high voltages, and can provide high

resolution using a method devised by a previous member of our group, we decided to explore its

use further for determining oil quality and operation of the equipment. Since this topic has not

been thoroughly explored by other groups, we did not know how the changing properties of oils

would affect the oils’ refractive indices and, if measuring the refractive indices of oils would be

a useful “flag”.

In what follows, we have studied the effects of transformer oil aging, and of some of the

by-products formed during aging, on the refractive index changes of the oils. Several

experiments have been conducted in order to observe the degree to which the refractive indices

of transformer oils change during the aging process. Initial experiments included measuring the

refractive indices of oils obtained from the field and trying to detect trends. Oil samples were

prepared in the laboratory as well, through accelerated aging, in order to study the effects of

aging on refractive index in a controlled manner. Using our high resolution sensor, changes in

the oils’ refractive indices due to the addition of various aging by-products such as acids, furans,

polar compounds, and gases, that where not previously detected, are made observable when

introduced in sufficient quantities. These changes, due to the inclusion of individual by

21

products, are compared to the overall changes measured in refractive indices of oils when they

are aged at an accelerated rate. This work constitutes an initial investigation conducted with the

intention of contributing to the development of online monitoring systems for oil filled high

voltage equipment.

22

Chapter 2

2 Measuring Refractive Index

2.1 Introduction to Sensors

The purpose of this chapter is to discuss our methods for measuring refractive index. The

chapter begins by briefly discussing why we thought measuring refractive index of insulating

oils may be promising for the purpose of transformer condition monitoring. The sensors that

were used for our measurements are introduced, one of which was fabricated in our lab (the D

fiber sensor) and one of which was obtained commercially (the FISO sensor). The fabrication,

system setup, calibration, and testing procedures used to make a reliable D-fiber sensor are

discussed in detail, since until now it has only been used for demonstrating proof-of-principle.

Since the FISO sensor is already a commercially developed product, the theory of operation is

briefly discussed.

2.2 Why Use Refractive Index?

The interaction of an electromagnetic wave’s electric field with atoms and molecules

present in a medium will affect the propagation of the wave and, therefore, the dielectric

constant (and refractive index) will be dependent upon the manner in which atoms and molecules

are assembled [45j. The refractive index can be represented as a complex value:

n=n’—in” (2-1)

The reader is directed to [45] if they are not familiar with issues related to the refractive index of a material.

23

where n’is the real part of the refractive index and n” is the imaginary part. The real part of the

refractive index accounts for the effect a medium will have on the velocity of the

electromagnetic wave traveling through it and the imaginary part gives the absorption and,

therefore, is sometimes referred to as the extinction coefficient [45].

For the simple case of an isotropic medium occupied by N atoms per unit volume, the

complex refractive index is given as follows [45]:

jj- 2- 2 — 2 2“.0

_______________

— 2 22 22 2 22 22 —2m&0[(cv0 —cv ) +y cv ] 2m&0[(w0 —cv ) +y 0) J

where s is the vacuum permittivity, e is the charge of an electron, m is the mass of an electron,

cv is the frequency of the electromagnetic wave, cv0 is the resonant frequency of the electron

motion, and ‘I’ is the damping coefficient. Looking at this equation we see that the real term

becomes 1 and the complex term is maximized when cv is equal to cot,. The imaginary term is

significant only when cv is very close to co0, and can be often neglected.

Equation (2-2) illustrates that the refractive index is dependent on the frequency of the

electromagnetic wave. This phenomenon is referred to as chromatic dispersion. Figure 2-1

shows a plot of the real and imaginary parts of the refractive index as functions of frequency for

a material that may be represented by (2-2). One can see that the absorptive part of the refractive

index is a maximum when cv co0, and approaches 0 as one moves away from this point. For the

plot of the real part in the region where o < w0 the refractive index increases with the frequency,

until a point very near ca. where the slope becomes negative. The negative slope only exists

where absorption is significant, and as the frequency increases beyond this region the slope

becomes positive again.

g Note: a similar figure is presented by A. Yariv and P. Yeh in [45].

24

I —

I?’’

n’-l

0-

I I I I I I I I>-‘+ -3 -2 -1 0 1 2 3 4

(w-wy

Figure 2-1: Normalized plot of the real and the imaginary value of refractive index as a functionof frequency. A similar figure is found in [45].

25

Equation (2-2) only represents the refractive index that would be calculated due to the

collection of single atoms having electrons with only one Wc, value. This equation is, therefore,

only used for demonstration purposes. The refractive index of a dielectric material such as a

mineral oil, would obviously be affected by a multitude of electrons, atoms, and molecules, and

would constitute a summation of the contributions of each. Using this simple illustration,

however, it is easy to visualize how the refractive index would change due to the formation of

new compounds and the breakdown of others. Figure 2-2 shows a plot similar to that shown in

Figure 2-1, although only the real part of the refractive index is shown and the frequency has

been converted to wavelength on the x axis. In Figure 2-2, line A represents the real part of the

refractive index of a medium with “type 1” atoms present, having only one resonant wavelength

Aj. If the refractive index is measured at Am the value of n’ will be n1’. If the type 1 atoms are

removed from the medium, and replaced with “type 2” atoms, a new resonant wavelength may

exist at A02, and the real part of the refractive index will now be n2’ shown on line B. The

shifting resonant frequency will obviously result in the shifting of the imaginary refractive index

profile as well. Similar behavior would occur in the break down of compounds and formation of

new compounds, in that the real part of the refractive index and the absorption profile would

both change.

In the previous chapter, we discussed various techniques used as indicators of oil degradation,

and many of them involved measuring the changing absorption profiles. For example, in [9]

increased absorption was observed between 200 and 390 nm due to the formation of aromatic

compounds. If the absorption profile of the medium changed, the real part of the refractive index

must have changed as well. Since the composition of the oil changes during aging, we expect

the refractive index to change as well. We have, therefore, studied the changes that occur in the

refractive indices of the oils, by using our sensors to measure the change in the real part.

26

Figure 2-2: Real value of refractive index versus wavelength illustrating change in refractiveindex values with different resonant frequencies.

A B

712

27

2.3 Introduction to Sensors

In order to measure refractive index, two sensors at very different stages in their

development were used. One of the sensors was fabricated, here at UBC, by etching D-shaped

optical fiber to produce a sensing region. When the sensor was immersed in a liquid or gas

medium, the power transmission measured through the fiber could be related to the medium’s

refractive index value. This method was developed by Sameer Chandani, until recently a

member of our lab, who has demonstrated proof-of-principle prototypes [44]. To our

knowledge, other than in our lab, this sensor has not been used in any other experimental setting

and has not yet been made into a commercially available product. This sensor was chosen

because it had a higher resolution than many of the commercially available sensors. One

limitation of our D-fiber sensor is its comparatively narrow operating range. The other sensor

used was a commercially available measurement system on loan to our lab by FISO

Technologies Inc. The system included both a Fiber Optic Temperature sensor (FOT) and a

Fiber Optic Refractive Index sensor (FRI). FISO Technologies is a company (located in Quebec

City, Quebec, Canada) that offers a variety of fiber optic sensors such as pressure, strain,

refractive index, and temperature, all of which function using the Fabry-Perot cavity and Fizeau

interferometer principles. Using the FISO system complemented the use of the D-fiber sensor,

as it has a wider operating range. Nevertheless, the FISO sensor did not have as high a

resolution when compared with that obtainable in the range where the D-fiber sensor was most

sensitive, so would only be used for less sensitive measurements.

2.4 The D-Fiber Sensor

In circular core, step index, single mode fibers a “guided mode” will exist. This is a

mode in which the optical field is confined to the core and the field is in the shape of a Bessel

28

function J0 in the core and decaying in the cladding in the shape of a modified Bessel function of

the second kind K0 [44]. Figure 2-3(a) shows a magnified cross section of a typical circular

core, step-index, single mode optical fiber. The core is surrounded by a cladding with a large

thickness, and the cladding is surrounded by an external medium, which is typically a protective

jacket. Figure 2-3(b) shows the magnified core surrounded by the cladding, with the radial

refractive index and optical field distributions in the core and cladding regions. The field in the

cladding is evanescent and decays as one moves away from the core into the cladding of the

fibers, as shown in Figure 2-3(b). Depending on the thickness of the cladding, the evanescent

field could extend into the outer medium surrounding the fiber. However, standard single mode

fibers have large cladding thicknesses and, therefore, the interaction of the evanescent field with

the outer medium is virtually non-existent.

For our sensors, we wished to access the evanescent field and, therefore, we used a single

mode D-shaped fiber. A D-shaped fiber is a specialty fiber that has an outer cladding with a

regular cylindrical shape on one side and a planar side extending the length of the fiber as shown

in Figure 2-4. The cladding is surrounded by a protective jacket. The thickness of the cladding

on the planar side of the fiber, or distance, d, between the core and the protective jacket, is only

13 jim. The core of the fiber has an elliptical shape. The refractive index of the elliptical core,

n0, is greater than the refractive index of the cladding, n. As is the case for a typical standard

single mode fiber, light launched into the D-fiber will normally be guided with minimal loss. In

our sensors, accessing the evanescent field will allow a decrease in the transmission, depending

on the refractive index of the surrounding medium. Hence, in order to access the evanescent

field, we must reduce d by etching the fiber.

For our sensors, the evanescent field is accessed by removing the fiber’s protective

jacketing over a small section, and etching the fiber. This etching process, done by exposing

29

flci

oEz(r)

N

NN

o a

(a) (b)

Figure 2-3: (a) Magnified cross section of a typical step-index circular single mode fiber. (b)Magnified cross section of the core showing the refractive index profile and the optical fielddistributions. Decaying optical fields in the cladding are called evanescent fields. A similarfigure found in [441. (Figure not to scale).

nfr)

tflco -

lid

30

Figure 2-4: D-fiber cross section (not to scale), showing the core dimensions, cladding thickness“d” between the core and outer cladding flat side, and the protective jacketing surrounding thecladding.

31

the cladding to hydrofluoric acid (HF), reduces d. By reducing d, the evanescent field can be

made to interact with a medium external to the fiber. Figure 2-5(a) illustrates this, showing a

section of D-fiber that has been etched over a length, L. Figure 2-5(b) and Figure 2-5(c) show a

“cut-out” section of the D-fiber (note the cut out has been rotated) shown in Figure 2-5(a).

When d is reduced to d?. the evanescent field, which is normally confined to the cladding, extends

into the external medium. If the refractive index of the external medium, ex becomes greater

than the mode effective index, flef the mode of the overall waveguide structure becomes a

“leaky mode”. Leaky modes are a subset of radiation modes, which are characterized by

oscillatory fields in the cladding that are not highly iossy [44]. We exploit this “leaky behavior”

to form the basis of our sensor, and relate the power transmission ratio, Tr, to the refractive index

of the measurand. Since the propagation constant, J3i, for a leaky mode is complex (J31 = fir + /3,,

where fir is the real part and /3j is the imaginary part), Tr will depend on the length of the “leaky”

section, L, and on the imaginary part of the propagation constant/3 [44]:

= =e2i (2-3)

where P, is the power into the leaky section, and P0 is the power out of the leaky section.

A typical transmission profile, as a function of next, of this type of sensor is shown in

Figure 2-6. If the external medium is our measurand and n is lower than n the sensor will

operate in its lossless region. There is a narrow range of refractive index values to the right of

the lossless region that we refer to as Region I. This is the region in which the steepest decrease

in Tr occurs as a function of next. We have defined a second region, Region II, in which a

minimum point in the transmission occurs. Region II starts to the right of Region I where the

slope is not as steep, and ends at Region III. Region III is the region with the largest range of

next, where the slope is positive for further changes Of next, but is not as steep as that of Region I.

32

0 ; a+d

(b) (c)Figure 2-5: (a) Section of D-fiber: For a section of D-fiber, with length “L”, the distance “ci”between the core and planner side of the cladding is reduced by Ad giving a new distance dr. (b)and (c) show the respective refractive indices and optical field distributions in the “cut-outsection” shown below (a) [note, co-ordinate system rotation]. (b) shows a section not etched,with d between core/cladding interface and field confmed to the fiber. (c) shows a section afteretching, with reduced distance dr and field extending into the external medium.

(a)EtchedSection 14d

d

y

xp

CladdingI’d

ExternalMedium

I’exl

I— I

ExternalMedium

Iy

L

Planar SideCladdingBoundary

ilcolid

L

Reduced PlanarSide Cladding

Boundary

I’)

-

n(y)flco

I’d I

I’ext

a+d0 a

Ez(y)

N.

o i a±dr

E4’y)

0 tz a4-d,.-.7

33

I

0

? 0.4

0

0.2

Figure 2-6: Calibration curve measured by sweeping the refractive index of the three thermooptic oils by temperature control, and recording the power transmission. Region I, II, Ill, and thelossless region are shown.

0.8

0i13...“ 0112— —— 0111

Lossless

I II II I

I I

I II II II I

I II II II II I

I II II II II II II I

I II II I

I I

II

0.

IIIWI

I I I I I I I I

1.4400 1.4500 1.4600 1.4700 1.4800 1.4900 1.5000

Refractive Index

34

Decreasing d results in increasing the amount of power that will be lost in the leaky

section of the fiber. This will give a lower minimum point, in Region II, and a larger change in

Tr for a smaller change in In [44] it was shown that in Region I minimizing d would

maximize the resolution, but in Region III the maximum resolution occurred at d 4.0 p.m. The

sensor’s refractive index resolution, M, improves with increasing transmission ratio slope, and

can be calculated by [45]:

(2-4)ônj

where tTr is the resolution to which the transmission ratio can be measured. Referring to Figure

2-6, the sensor will operate with the highest resolution in Region I, and, therefore, we perform

our measurements in this region. It is apparent from Figure 2-6 that the sensor is not very useful

in Region II, and that the resolution is much lower in Region III.

The next three sub-sections will outline the various steps used when making a D-fiber

sensor. In sub-section 2.4.1 we will discuss the fabrication process, which includes:

(a) exposing and cleaning a section of D-Fiber

(b) etching a section of D-fiber in order to decrease d to a few p.m

In sub-section 2.4.2 we will discuss how to place the etched D-fiber into the measurement

system. This process will include:

(c) arranging the optical equipment

(d) cleaving the D-fiber ends and inserting it into the system

(e) making adjustments to maximize the power and recording the maximum power

transmission

Finally, in sub-section 2.4.3 we discuss the calibration process which involves:

35

(f) filling the trench with the calibration oils and measuring the power transmission as the

temperature is swept

(g) generating calibration curves so that the power transmission can be related to the

refractive index of the measurand.

(f) selecting a sensor with high resolution

Section 2.4.4 will discuss the approach used to measure the resolution of our D-fiber sensor. A

relative measurement method was used in order to minimize the effects of system drift. By

comparing our samples to control samples we could increase the resolution.

2.4.1 D-fiber Sensor Fabrication

The D-shaped fiber used to make the sensor was KVH Industries E-Core single-mode

polarization maintaining optical fiber 205 170-1550S. In Figure 2-4 we show the fiber having an

elliptically shaped core with dimensions of approximately 4 jim and 2 jim. The minimum

cladding thickness, d, between the fiber core and the outer cladding flat is approximately 13 jim.

The indices of refraction of the core and cladding are 1.4756 and 1.4410 respectively. The

length of fiber used for a sensor was 32 cm, however, the sensing region was only 1 cm long.

The fabrication process begins by removing approximately 1 cm of the protective

jacketing, to expose the cladding. The cladding is cleaned by immersing it in acetone for 20

mm. The exposed cladding section becomes the sensing region after etching. The fibers are

etched by immersing the exposed cladding in a 10% hydrofluoric acid (HF) solution. The entire

surface of the exposed cladding is etched during this process, however, the effect of decreasing

the distance between the core and cylindrical cladding surface is negligible, since this distance is

much larger than the minimum distance between the core and flat surface. The protective

jacketing keeps the cladding isolated from the HF, therefore, only the cladding area which has

been directly exposed will be etched. The etch time that produced sensors with high resolution

36

was between 180 and 215 minutes, depending on factors such as the temperature of the room and

non uniformity of the fiber. Many fibers were, therefore, etched for different duration periods,

and the one having the highest resolution was selected. When a fiber was removed from the

acid it was immediately immersed in de-ionized (DI) water (for at least 15 minutes) in order to

stop the reaction. Once the sensing region had been etched, the fiber could be tested.

2.4.2 Placing the D-Fiber Sensor into the Measurement System

The sensor is placed into the measurement system so it can be tested and calibrated. The

ends of the sensors are cleaved in order to produce an optically flat fiber end with minimal loss.

The sensor is placed into the measurement system shown in Figure 2-7, which can be automated

using LabView. An HP 81682A*** tunable laser, housed in an HP 8164A lightwave

measurement system, was set to 1500 nrn and the output was connected to an HP 11 896A

polarization controller. The optical fiber used at the output of the polarization controller is a

circular core single mode fiber, which must be coupled to the elliptical core D-fiber. The two

types of fiber are coupled using a mechanical splice into which cleaved ends of each fiber are

inserted. The other cleaved end of the D-fiber sensor is fixed so that the light will be emitted

onto an HP 81521B optical detector. The detector was connected to an HP 81533B optical

detector head interface, which was housed in the same HP 8164A lightwave measurement

system as the tunable laser. When coupling the sensor to the circular fiber, minimum power loss

is desired and achieved by turning the laser power on and carefully adjusting the position of the

cleaved ends until maximum power is detected. This could be a delicate procedure since the

mechanical splice was made to couple light between two circular fibers and, typically, the best

connection resulted in a 3 dB loss in power. Once coupling is maximized, the sensor region is

placed in a trench that can be filled with a liquid, such as acetone, to clean the sensing area.

Equipment with HP abbreviation from Agilent Technologies, Inc., Santa Clara, CA, USA.

37

Figure 2-7: Diagram of experimental set-up showing D-fiber sensor and FISO sensor.

Communication CableStandard FiberD-FiberCopper Wire

Thermo-ElectricCooler

38

After cleaning the sensing area the maximum power transfer, Pm,,.,, can be measured by

surrounding the fiber with a medium having a refractive index value in the sensor’s lossless

region (discussed below). Before Fmax is recorded, the polarization is altered until the maximum

optical power is read at the detector. By selecting this polarization state before each

measurement period, we keep the sensor properly calibrated. The temperature of the liquid in

the trench is controlled using an ILX Lightwavettt modular laser diode controller, with a

thenno-electric cooler. Precise temperature control is necessary during both the sensor

calibration and the experimental measurement process, as the refractive indices of many

materials are very sensitive to temperature.

2.4.3 Sensor Calibration

The power transmission ratio is calculated using the maximum power transfer reading

Fmax, and the power measured with a sample present in the trench Ppieas as follows:

T — meas-

(2-5)max

In order to relate the power transmission ratio to the refractive index, a calibration curve must be

generated. The refractive index of the medium surrounding the sensor could be changed by

known amounts by using thermo-optic oils as the medium and controlling their temperatures.

Three oils were ordered from Cargille Labs, which were prepared so as to have specific

refractive indices at specific temperatures. The refractive indices at 25°C as functions of

wavelength could be calculated for each oil using the provided Cauchy equations as follows

[46]:

tt Equipment from ILX Lightwave, Bozeman, MT. USA.

::: Oils purchased from Cargille Labs, Cedar Grove, NJ, USA

39

599807.3 2.131038x10’2n1(A) = 1.490962+

A2 + A4 (2-6)

510457 1.556322 x 1012n2(A) = 1.4690106 + A2 + A4 (2-7)

398447.1 3.980245x 1011n(A) = 1.449033+

A2 + A4 (2-8)

where A is the wavelength in Angstroms andn1(A),n2(A), andn3(A) represent the refractive indices

of oils 1, 2, and 3, respectively. As will be discussed below, for a few key oils used in our

experiments, our sensor operated most effectively at l500nm so, in what follows, this

wavelength will be used when specifying several equations and values measured using the D

fiber sensor. At 25°C and l500nm, the 3 oils had refractive indices, n25, of 1.49367, 1.47131,

and 1.45081, respectively.

The refractive index as a function of temperature can also be calculated using the

d(nD)provided temperature coefficients for each oil,dt

, and n25 of each oil by:

n(T) = n25 + d(nD)(T — 25° C) (2-9)

therefore,

n1(T)=1.49367—(3.9lxlOj(T—25°C) (240)

n2(T) = 1.47131—(3.86x104)(T—25°C) (2-11)

n3(T) = 1.45081 —(3.83 x 104)(T — 25°C) (2-12)

where T is the temperature in degrees Celsius, and n1(T),n2(I), and n3(r) are the refractive indices

of oils 1, 2, and 3 as functions of T, respectively. Using these oils we could calibrate the sensor

over a wide range of refractive index values.

A sensor is calibrated by filling the trench in the experimental apparatus with one of the

thermo-optic oils and immersing the sensor region in the oil. As the temperature is swept the40

power out of the D-fiber sensor is measured. This is repeated for all three thermo-optic oils. A

calibration curve is generated by plotting T as a function of the thermo optic oils’ refractive

indices, as shown in Figure 2-6. After the calibration curve is generated, the refractive index of a

sample, or measurand, can be found by measuring T,. and using the curve to find the

corresponding refractive index value of the measurand.

When using the D-fiber sensor, it is best operated in the high resolution Region I. One

way to move the operating point of the sensor into Region I is by changing the temperature of

the measurand. This method is only useful in a relative measurement, however, where knowing

the refractive index, of a sample, at a specific temperature is not crucial. In some cases it may be

more important to measure the change in a sample’s refractive index compared to a control value

at the same temperature, which is what we would like to do. This method has a limitation,

however, as the amount that the refractive index can be shifted is dependent upon the

measurand’s temperature coefficient, which may not be large enough to move the operating

point into Region I. As well, if the temperature is increased far beyond the ambient temperature,

the resolution may be lowered since the temperature stability may decrease (depending on the

system). Our system could maintain a suitable stability to about 35.7°C, but not far above this

value. If we reach the sensor’s limit for moving the operating point by temperature, further

adjustment can be had by shifting the wavelength.

Figure 2-8 shows the power transmission of our sensor for several tested wavelengths.

The figure was produced using the calibration oils as discussed previously and using different

operating wavelengths. Also, the refractive indices of the oils at the respective wavelengths,

using the Cauchy equations and the thermo-optic coefficients, were calculated to produce the

figure. As can be seen in Figure 2-8, the resolution of the sensor changes slightly for different

operating wavelengths. For the wavelength range that was used, lowering the wavelength

41

1

0,70

0.40

0.3

0.2

0.1

Figure 2-8: Measured power transmission of D-fiber sensor at various optical wavelengths.

0.9

0.8

0.6

0.5

1.448Index of Refraction

42

decreased the resolution, however, it was still quite high. The nominal operating wavelength of

our D-fiber, given by E-Core, is 1550 nm. Some of the transformer oils obtained from the field,

such as Luminol oil, had refractive index values that were around the edge of Region II and

Region III when using 1550 mm For these oils, the operating point is shifted from the edge of

Region II and Region III to the edge of Region I and Region II by setting the temperature to

35.7°C (see Figure 2-9). The resolution is still not maximized, however, so the wavelength is

shifted to 1500 nm. This moves the operating point between Tr = 0.4 and Tr = 0.7, in Region I,

where the steepest slope occurs, as shown in Figure 2-9. Using 1500 nrn provided us with the

high resolution needed for our measurements. We, therefore, calibrated the sensor using 1500

nrn, and all measurements using the D-fiber sensor were performed using this wavelength.

2.4.4 D-fiber Sensor Resolution

We selected our sensor by comparing the slopes of all the sensors’ calibration curves and

selecting the one with the steepest slope in Region I. As previously mentioned, the resolution of

our sensor can be calculated using (2-4). The sensor’s resolution was measured using the settings

as discussed in the previous subsection, i.e. the temperature was set to 35.7°C and the

wavelength was set to 1 500nm. The resolution was tested for different operation times. It was

found that the best resolution could be achieved using a relative measurement method. The

“relative method” was used to help minimize the effects of system drift. System drift can occur

due to various shifting parameters such as slight temperature changes, laser noise, or polarization

drift. Relative measurements were performed by measuring the refractive index of a sample oil

and of a control oil, and calculating the difference. This was done three times and then the

average of the three measured differences was used as the final measured refractive index change

of the sample, or the n.

43

l—,—__ Operatmg pornt at room temp and l5SOnna

‘ \ S Shift in operating point by temperature0.8 - \ \ e Operating point at 35.7°C and 1550mu

‘ \ I Shift in operating point by wavelength

j 0.6 - 0 Operating point at 35.7°C and l500mn

0.4-I

1500mm

0.2- 1- -

— — — 1550mn0— 1 I I I1.4300 1.4400 1.4500 1.4600 1.4700 1.4800 1.4900 1.5000

Refractive Index of External Medium n

Figure 2-9: Calibration curve shown for operating wavelengths of 1550nm and l500nm. Theoperating point is moved by increasing the temperature. When the temperature control has beenexhausted the wavelength can be shifted to move the operating point further.

44

The sensor’s resolution was first tested over a long period of time with minimal

averaging. The minimum and maximum refractive index and temperature values recorded over

the entire period were compared to see the system stability without using relative measurements.

The length of time selected for this measurement was two and a half hours, which was needed to

make several relative measurements. We call this first test the “non-relative measurement

method”.

The resolution was next tested with what we call the “relative duration period method”

by using the same oil for the sample and for the control, and recording values over the duration

of several relative method measurement periods (a relative method duration period is the amount

of time it took to perform one measurement of a sample and its corresponding control).

Finally, we test the resolution of the sensor using a sample oil and using a control oil that

had very similar values of refractive index using the “relative method”.

Table 2-1 shows the results obtained using the non-relative measurement method. The

temperature of the oil and the power transmission through the sensor were measured over a two-

and-a-half hour period. A power and a temperature value were recorded every second for thirty

seconds, and the average of each was used to produce one data point. This process was repeated

for two and a half hours. For every data point, Tr was calculated and the refractive index, n, of

the measurand was found. T is the temperature measured by the FISO FOT. The column

labeled max corresponds to the maximum value recorded over the entire duration period, and

rn/n is the minimum value. The column labeled max-rn/n shows the fluctuation of each

parameter. The temperature fluctuates by approximately 0.10°C over the measurement period,

which is just above the FOT resolution. Over the duration period the power transmission drifts

and the recorded Tr fluctuation was 0.0383. This power fluctuation corresponded to a refractive

index fluctuation of about 0.000 14, which would give us a resolution comparable to the FISO

45

system. We would like to perform more sensitive measurements than this and have set our

resolution goal to be an order of magnitude greater.

Table 2-1: Results of non-relative measurements conducted to find resolution for constantsystem operation of two and a half hours.

Parameter max mm max-rn in

T(°C) 34.55 34.45 0.10Tr 0.6343 0.5960 0.0383n 1.446624 1.446485 1.39E-04

Using the non-relative measurement method, we observed that the power transmission

changes slightly due to system drift over long periods of time. Hence, in order to minimize the

effects of system drift, we would like to make relative measurements between sample oils and

control oils over a shorter period of time. This relative method is tested by using the same oil for

both the sample oil and the control oil and using the relative duration measurement method. We,

therefore, observe the amount that the power fluctuates (A Tr) over the time duration period

required to make one sample and one control measurement, due to changing system parameters.

The change in refractive index due to system drift can then be found, and the sensor resolution

can be calculated. Table 2-2, Table 2-3, and Table 2-4 show the results of conducting several

relative duration period measurements, and will be referred to in this paragraph. The total time

required to perform one relative measurement is 30 minutes, 15 minutes for the sample

measurement and 15 minutes for the control measurement (keep in mind that the sample oil and

the control oil were the same for this relative duration period measurement). A power and a

temperature value were recorded every second for thirty seconds, and the average of each was

used to produce one data point. Data points were recorded for 30 mins. For every data point, Tr

was calculated and the refractive index, n, of the measurand was found. T is the temperature

measured by the FISO FOT. One complete “Run” would consist of recording data points for 30

46

minutes, using the same oil, and breaking that data into two separate 15 minute data sessions.

The two recordings could then be averaged separately and compared to find the resolution over

the 30 minute “Run”. Referring to Table 2-2, Table 2-3, and Table 2-4, for each ii, i’, and T,

value, the av] and av2 values were the average of each 15 minute recording. The A value is the

average fluctuation measured, which is the difference between the two averaged values. If we

average all the measured parameter A values, we obtain the following; an average AT value that

is less than the resolution of the temperature sensor, a reduced ATr value of 0.0034, and a

correspondingly reduced An3 of 1.2x105. These values were deemed to be adequate for our

measurements as they met the desired order of magnitude improvement.

Table 2-2: Temperature results of relative duration period measurements to show averagetemperature variation over relative measurement period.

Run Tav](”C) Tav2(°C) AT(°C)

1 34.48 34.48 0.002 34.50 34.50 0.003 34.52 34.52 0.004 34.51 34.50 0.015 34.50 34.47 0.03

Table 2-3: Transmission ratio results of relative duration period measurements to show averagetransmission variation over relative measurement period.

Run T,av] Trav2 AT1 0.5992 0.6030 0.00382 0.6082 0.6115 0,00333 0.6158 0.6201 0.00434 0.6229 0.6256 0.00275 0.6297 0.6325 0.0028

47

Table 2-4: Refractive index results of relative duration period measurement conducted to findresolution of system using relative measurement.

Run av1 av2 AJ2

1 1.446615 1.446603 1.2E-052 1.446584 1.446572 1.2E-053 1.446555 1.446539 1.6E-054 1.446528 1.446518 1.OE-055 1.446502 1.446491 1.1E-05

In order to test the resolution of the system further, two oils were used that had very

close, but not the same, refractive indices. Here, one was the “sample” and one for the “control”,

see Table 2-5. Again, for the measurement of a sample, a power and a temperature value were

recorded every second for thirty seconds, and the average of each was used to produce one data

point. Data points were recorded for three minutes. For every data point, Tr was calculated and

the refractive index, n, of the measurand was found. All values of n could be averaged to give

the “Average Sample n”. This process was repeated for the control to give the “Average Control

n” value. The difference was found by subtracting the two which we call the “Run Measurement

An”. Three consecutive run measurements were averaged to give a “Trail Measurement An “.

As one can see in Table 2-5, there were slight variations between the Run Measurement An

values, but the difference between them all fell within our measured refractive index resolution.

When comparing the Trial Measurement An values they were very close to one another. Since

there was greater consistency between the “Trail” values than the “Run” values, it was decided

to use the Trial value when performing experiments using the D-fiber sensor.

48

Table 2-5: Results of refractive index resolution test using two oils with very close refractiveindex values

Run TrialAverage Average Measurement Measurement

Trial# Run# Sample n Control n IS.n An

7 1.447170 1.447157 1.34E-05

Trial 8 1.447174 1.447166 7.67E06#1 9 1.447179 1.447167 1.18E-05 1.10E-05

10 1.447176 1.447168 7.71E-06

Trial 11 1.447177 1.447159 1.79&05#2 12 1.447169 1.447162 7.13E-06 1.09E-05

13 1.447176 1.447160 1.59E-05

Trial 14 1.447167 1.447159 7.89E06#3 15 1.447174 1.447165 9.OOE-06 1.09E-05

By performing this analysis, and repeating it several times, we decided to adopt this

relative measurement method, since, for our experiments we are only concerned with relative

changes in refractive index of oils and not the actual index value. Hence, for the remainder of

this thesis, when we make high resolution measurements using the D-fiber sensor, we use the

relative method We have achieved a maximum resolution of 1.1 x i0.

2.5 FISO Refractive Index Sensor System

A commercially available sensor was lent to the lab by FISO Technologies, Inc. The

FISO system complemented the use of the D-fiber sensor, as it has a wider operating range. The

FISO sensor, however, did not have as high a resolution as compared to that obtainable in the

range where the D-fiber sensor was most sensitive. This section will explain the operating

principles of the FISO system.

As previously mentioned, a Fiber optic Refractive Index (FRI) sensor, and a Fiber Optic

Temperature (FOT) sensor were provided to us by FISO Technologies. The FOT was used to

determine the actual temperature of the calibration and sample oils during measurement periods.49

FISO also supplied a “Universal Multichannel Instrument” (Ulvil), which had 8 sensor channels

that could be used simultaneously. This measurement unit converted an optical signal, from the

sensor, to a measured parameter. Figure 2-10 shows a schematic diagram of the FISO system.

A broadband light source in the Ulvil produces an optical signal with wavelengths between 600

and l000nm. The light is transmitted, by multimode fiber, to the Fabry-Perot cavity located at

the end of the sensor. A Fabry-Perot cavity is made by separating two parallel partially-

reflecting surfaces by a distance dj; with a medium between the two surfaces having a refractive

index n. A spectrally varying transmission or reflection function is produced due to interference

between the multiply-reflected waves. If the reflected waves are in phase, they will interfere

constructively causing a power transmission peak, whereas those that are not in phase will

produce lower transmissions. The transmission function can be represented as follows [47]:

f \ 1Tf2,df)=

( r2,d (2-13)l+Fsin2I

L2

where df is the distance between the reflecting surfaces, is the wavelength of the light, n is the

refractive index of the material in the cavity, and F is the finesse which is equal to4R

[(1-R)

where R is the reflectance of the mirrors. This type of cavity can be useful for many different

measurement applications. The transmission function will change with d, which can be used for

the case of stress or pressure measurements. It will also change with the refractive index of the

medium in the cavity, which can be used to measure the refractive index of a liquid or to

measure any other parameter which can be related to a change in a material’s refractive index,

such as temperature.

The spectrally varying transmission signal created by the Faby-Perot cavity is sent back

through the fiber to the Ulvil, where it is projected onto a Fizeau interferometer. This second

50

r.UMI Broadban1

( /Light Source’

FRI IK:‘. Photo-diode1

j’\ \ Fizeau Interferoñi’V1Array

/ —

Fiber Optic Cables

Fffl FOT

- OiIFilled Trench

Fabry-Perot -

I C Th Temperature

Interferometer

________

Cop:::::Thea mo-Electric

Cooler

Figure 2-10: Diagram of FISO system setup.

51

mterferometer is similar to the Fabry-Perot interferometer. Two semi-reflecting surfaces are

separated to form a wedge shaped cavity, instead of the rectangular shaped cavity. The varying

distance between the reflecting surfaces is used to spatially separate the different wavelengths of

light. The spectrum is projected onto a photodiode array. The refractive index which

corresponds to the peak wavelength reflected back from the Fabry-Perot is calculated by the

Ulvil and displayed.

The refractive index sensor had a very broad measurement range from 1.0000 to 1.7000,

which would be useful for oils that did not have refractive index values within the narrow range

of the D-fiber sensor. The resolution of the FISO FRI was 1x104, however, which is

approximately an order of magnitude less than that of our D-fiber sensor. The FOT could

perform temperature measurements from -40 to 300°C, with a resolution of 0.05°C. We used the

FOT simultaneously with the D-fiber sensor or the FRI in order to set and measure the

temperature of the oil samples.

52

Chapter 3

3 Experiments

3.1 Introduction to Chapter

In this chapter, the experiments that were performed will be discussed and the results will

be presented. Many sample oils that were tested using the methods described in Chapter 1 were

provided to us by Powertech Labs. The refractive indices of many of these oils were measured,

by us, to see if any changes could be observed due to varying amounts of contaminants.

Although there were a large number of oils available, the samples oils did not have control oils

to which they could be referenced. This posed a problem when trying to determine how much

the refractive index actually changed. The work involved in detennining what particular type of

oil the sample was would be very costly and time consuming, at Powertech’s expense, and was

not practical for the sake of these experiments. In order to overcome the challenge of working

with unknown oils, direct comparisons were only made between oils taken from a particular

piece of equipment or between oils taken from pieces of equipment from the same station (e.g., a

transformer station), since most often they would be the same type of oil. Equipment located in

the same station would most likely have been installed at the same time, been constructed by the

same manufacturer, and been filled with the same type of oil.

Another challenge we faced when using these oils was that many variables change during

the natural aging process, and relating the refractive index change to one contaminant was

difficult. For this reason “clean oils” were used to prepare samples with varying levels of

53

specific contaminants. The first clean oil used was Voltesso 35 (V35) which is a mineral oil

that has been commonly used by transformer manufacturers and is found in many of the aging

transformers in the field. Although V35 was used quite often in many experiments, the

refractive index did not fall within the most sensitive region of the D-fiber sensor. In fact, this

was the case for most oils obtained from the field. In order to measure the refractive indices of

these oils, only the FISO sensor was used. For many of the experiments conducted, the FISO

sensor provided sufficient resolution.

Nevertheless, after performing many measurements using the samples obtained from the

field, and the samples prepared using V3 5, it was found that higher resolution was necessary for

some of the experiments. The D-fiber sensor would be used to conduct experiments measuring

changes due to the addition of contaminants such as furans, acids, and gases. Having tested

many oil samples for refractive index, a few samples had refractive index values which fell

within the D-Fiber sensor’s high resolution range. One of these oils was Luminal Tri****.

Fortunately, many newer transformer installations throughout western Canada have been filled

with this oil type. This mineral oil was also recently obtained by Powertech Labs in large

quantities. Hence, access to large amounts of this oil was relatively easy to obtain for our

experiments.

3.2 Samples Obtained From the Field

3.2.1 Dissolved Gas In Oil Samples From the Field

The initial experiments that were conducted involved measuring the refractive index of

oil samples obtained from the field which had been tested for fault gases using DGA (Dissolved

Oil from: Imperial Oil Limited, Calgary, Alberta, Canada

Oil from: Petro-Canada Lubricants, Mississuaga, Ontario, Canada

54

Gas Analysis). Relating refractive index changes to gas content could be a very valuable tool for

equipment diagnostics, and could serve as an important online monitoring tool. As discussed in

Chapter 1, extensive research has been conducted in order to find ways to detect fault gases, and

more efficient and cost effective methods are still needed.

Samples from industry were obtained from three different types of equipment, including

oil filled cables, transformers, and load tap changers. The concentration of gases found in each

equipment type should vary, as each piece of equipment functions differently. The oils

contained in them are subjected to different fault conditions, including overheating and high

voltage discharges. Of the three types of equipment, the oil filled cables experience the least

amount of fault activity due to their simple construction and purpose. Oils found in transformers

experience a higher degree of faults and harsher environmental stressors than oils found in

cables, due to the higher complexity of the equipment and more involved function. Load tap

changers experience the highest degree of faulting and siressors since they function as electrical

switches, most often with moving parts including high voltage contacts. Oils contained in load

tap changer tanks will be exposed to the highest degree of arcing and gases may be generated

any time a switch operates.

When comparing the results of DGA, various concentrations of fault gases were found in

each piece of equipment which seemed to reflect the fault behavior discussed above. The

samples obtained from the cables had relatively low levels of all seven fault gases typically

monitored, i.e., hydrogen, methane, acetylene, ethylene, ethane, carbon monoxide, and carbon

dioxide, as well as the two atmospheric gases, oxygen and nitrogen, as shown in Table 3-1,

especially those generated under arcing and extremely high temperatures. Although the samples

contained relatively low concentrations of the gases, the levels did vary by a small amount. As

shown in Table 3-1 the refractive indices did not vary between samples 1-2 and 1-3, and was

55

only different in sample 1-1, by a small amount equal to the resolution of the FISO refractive

index sensor. It seemed reasonable to assume that changes in concentrations at these small

levels do not have large effects on the refractive index, and that the changes are not detectable

using the FISO sensor.

Table 3-1: Refractive index measurement and DGA results of cable oil samples taken from thefield.

Sample ID 1-1 1-2 1-3

Gas Content (ppm)Oxygen 2390 1410 3420Nitrogen 7640 3840 11700Carbon Dioxide 32 25 27Carbon Monoxide 0 0 0Hydrogen 60 33 57Methane 5 2 3Acetylene 1 1 1Ethylene 1 1 1Ethane 2 1 1Water 6 5 6Total Combustible Gases 69 38 63Gas Content(%v/v) 1.01 0.53 1.52

Refractive Index @21.60°C 1.4763 1,4762 1.4762

The concentrations of gases found in the three transformer samples were much higher

than those found in the cables, as shown in Table 3-2. In particular, the hydrogen levels were

much higher, as well as carbon dioxide and carbon monoxide. The presence of hydrogen often

occurs due to its formation through partial discharges, and the carbon dioxide and carbon

monoxide are typically present due to overheated paper insulation [12]. The gas concentrations

varied between samples as well, and the refractive index of sample 2-3 was 0.004 lower than the

other two samples. Since sample 2-1 and 2-2 had the same refractive index values, it was

assumed that any gas that differed in concentration by a relatively large amount between these

56

samples could not be a factor in the refractive index difference of sample 2-3. Also, by looking

at the gas concentrations of the three samples together, gases measured in sample 2-3 that lay

between the concentrations of the other two samples could also be eliminated. Based on these

observations, it seemed that hydrogen, oxygen, nitrogen, methane, ethane, carbon dioxide, and

acetylene were not contributing to the large refractive index change observed in sample 2-3.

Table 3-2: Refractive index measurement and DGA results of transformer oil samples takenfrom the field.

Sample ID 2-1 2-2 2-3

Refractive Index @21.60°C 1.4717 1.4717 1.4713

Gas_Content (ppm)Oxygen 6030 3460 3030Nitrogen 77900 70700 78700Carbon Dioxide 5730 5230 6160Carbon Monoxide 614 516 893Hydrogen 2520 9990 3720Methane 28 39 74Acetylene 0 0 0Ethylene 67 54 19Ethane 15 24 17Water 15 16 12Total CombustibleGases 3244 10623 4723Gas Content(%v/v) 9.29 9.00 9.26

As shown in Table 3-3 the load tap changer oils had a much higher concentration of some

gases and lower concentrations of others, when comparing them with the transformer oils. In

particular the levels of acetylene, ethylene, and ethane were much higher, and levels of

hydrogen, carbon monoxide, and carbon dioxide were much lower. This lower value is expected

for carbon monoxide and carbon dioxide since no paper is present in the load tap changer tank,

and the higher levels of acetylene, ethylene, and ethane would be produced during the arcing that

occurs when the tap is changed. Sample 3-1 had a much lower refractive index than the other

57

two samples. It also had much higher levels of most gases except carbon monoxide which was at

about the same level. The water content was also lower. Comparing samples 3-2 and 3-3, the

concentrations found in 3-2 were higher for every gas, and much higher for hydrogen, methane,

acetylene, ethylene, ethane, and water content. Since the measured refractive index was only

slightly different between the two samples, it seemed very unlikely that any of these gases were

a factor in lowering the refractive index to such a degree in sample 3-1.

Table 3-3: Refractive index measurement and DGA results of load tap changer samples takenfrom the field.

Sample ID 3-1 3-2 3-3

Refractive Index @21.60 1.4725 1.4752 1.4751

Gas_Content (ppm)Oxygen 31200 31200 30800Nitrogen 67700 65100 65500Carbon Dioxide 1270 676 631Carbon Monoxide 23 29 24Hydrogen 725 352 17Methane 369 248 12Acetylene 6080 2510 271Ethylene 1600 745 80Ethane 252 114 9Water 13 31 17Total CombustibleGases 9049 3998 413Gas Content(% v/v) 10.92 10.09 9.73

By conducting these experiments, we did observe varying refractive index values of the

oils. It did not seem, however, that any of the gases present in the oils were large factors in the

observed changes in the refractive indices. More experiments were necessary in order to

determine if the addition of particular gases would result in small changes in the refractive

indices of the oils. Since the samples obtained from Powertech Labs all had multiple gases in

58

the oils, a specific gas would have to be injected into new samples to isolate its effect on the

refractive indices.

Also, it should not be assumed that the presence of gas is the only factor that contributes

to the changes in refractive indices of oils. As discussed in Chapter 1, many physical and

chemical properties of oils change during the aging cycle. Besides the changes in the

concentrations of gases, there are other changes in the oil properties such as varying acidity,

concentration of poiar compounds, IFT (Interfacial Tension), or concentration of furans. Further

investigation was required to determine if other changes contribute to changes in the refractive

indices of the oils. In what follows we present the results of further experiments that were

conducted for this purpose.

3.2.2 Other Measured Properties of Oil Samples Obtained From the Field

After performing the experiments described in the previous section, we observed that the

refractive index of an oil sample would change over time, but low levels of fault gases did not

appear to contribute significantly to the change. We, therefore, used oil samples that had tests

other than DGA performed on them to determine if the addition of contaminants and changing

properties of the oils affected their refractive indices.

The refractive indices of a large number of oil samples having various physical and

chemical properties are shown in Table 3-4. These properties include KV breakdown (Kilovolt

breakdown), IFT, color, and acid number. Oil samples were provided in sets which included two

samples taken from the same transformer, one from the load tap changer (LTC), and one from

the transformer tank (TX). The combination of load tap changer and transformer oil samples

could be used for comparison. Some sets of samples were extracted from equipment from the

same station as well. It was assumed that equipment from the same station would be filled with

the same type of oil and, so, could be used for comparison as well. As shown in the table, oils

59

Table 3-4: Measured refractive indices of oil samples obtained from the field with somephysical and chemical property values shown.

Sample Refractive KVID Index (n) n7x - LTC Breakdown IFT Color Acidity

Al-TX 1.4867 16 22.3 3.5 0.06Al-LTC 1.4859 0.0008 22 13.9 2.5 0.63A2-TX 1.4863 25 19.6 2.5 0.09

A2-LTC 1.4852 0.0011 26 14.2 2.5 0.46B3-TX 1.4860 31 19.9 2.0 0.07

133-LTC 1.4851 0.0009 21 14.9 2.0 0.28B4-LTC 1.4859 44 20.0 1.5 0.05B4-TX 1.4849 0.0010 28 17.1 2.0 0.12CS-TX 1.4853 18 18.3 2.5 0.11

C5-LTC 1.4845 0.0008 22 37.7 1.0 -

C6-TX 1.4850 17 18.2 3.0 0.10C6-LTC 1.4808 0.0042 24 14.6 2.5 0.37D7-TX 1.4836 23 22.3 1.5 0.03

D7-LTC 1.4803 0.0033 20 23.1 2.0 0.03D8-TX 1.4810 33 18.8 4.5 0.15

D8-LTC 1.4811 -0.0001 16 14.1 3.0 0.65E9-TX 1.4812 25 23.3 2.0 0.04

E9-LTC 1.4807 0.0005 20 21.2 2.5 0.04E10-TX 1.4811 38 18.0 3.0 0.13

E10-LTC 1.4802 0.0009 19 19.4 3.0 0.06Eli-TX 1.4810 21 18.4 4.5 0.23

E11-LTC 1.4805 0.0005 19 18.0 3.0 0.08F12-TX 1.4781 20 21.4 1.5 0.05

F12-LTC 1.4796 -0.0015 15 28.6 1.5 0.01G13-TX 1.4789 24 23.2 2.0 0.04

G13-LTC 1.4790 -0.0001 17 22.2 1.5 0.04H14-TX 1.4783 25 23.9 1.0 0.06

H14-LTC 1.4792 -0.0009 19 14.4 1,5 0.45115-TX 1.4789 24 23.4 1.0 -

115-LTC 1.4789 0.0000 20 14.6 2.5 0.44116-TX 1.4785 26 27.3 0.5 -

116-LTC 1.4786 -0.0001 26 19.6 1.0 0.06J17-TX 1.4787 23 17.8 1.5 0.12

J17-LTC 1.4764 0.0023 18 25.9 1.0 <0.01J18-TX 1.4782 30 23.6 1.0 <0.01

J18-LTC 1.4771 0.0011 23 30.5 1.0 <0.01

60

extracted from the same station will be identified by the first character in the Sample ID, and

oils extracted from the same transformer are identified by the second character. For example,

the samples Al-TX, Al-LTC, A2-TX, and A2-LTC are all from the same station (station A).

Samples Al-TX and Al-LTC are from transformer 1 and samples A2-TX and A2-LTC are from

transformer 2. After making comparisons between oil samples and trying to relate a single

property to a refractive index change, it did not seem likely that any one property could be

directly related. For example, in some cases it seemed that a lower IFT would produce higher

refractive indices for some comparable oils, but the reverse seemed to occur for others.

The colunm in Table 3-4 labeled rx — flLTC represents the refractive indices of the

transformer samples minus the refractive indices of the load tap changer samples, for the same

piece of equipment, e.g., transformer Al. Figure 3-1 shows a graph of these values for each

piece of equipment. By looking at the table and the figure, we see that for twelve of the eighteen

samples the refractive indices of the transformer samples were higher than those of the load tap

changer samples. Of those, nine of them, or 75%, had a difference between 0.0005 and 0.0011.

The refractive indices of the load tap changer samples were higher than those of the transformer

samples for only five of the eighteen cases, and of those three of them were lower on the order of

the resolution of the sensor, i.e., -0.0001.

As discussed in Chapter 1, [9] and [35] present studies that were performed to detennine

if transformers could be characterized by the UV absorption of their insulating oils. The authors

concluded that through aging, an increase in aromatic compounds is observed and that this

increase in aromatic compounds will increase the absorption in the UV region, between 200 and

400 nm. As discussed in Chapter 2, when the absorption profile of a medium changes, a change

will also be observed in the real part of the refractive index. If increased absorption is observed

in the UV region, an increase in the real part of the refractive index should be observed as well

61

0.0050

0.0040

0.0030

0.0020

0.0010

•. 0.0000

-0.0010

-0.0020

Figure 3-1: The refractive index of transformer oil samples minus the refractive index of loadtap changer oil samples obtained from same equipment from the field.

Equipment ID

62

for the wavelength region over which we performed our measurement (provided the increased

absorption in the UV region is the dominant change). Hence, it is assumed that the addition of

aromatic compounds to the aging transformer oils will also increase the refractive indices of the

oils.

In [9], samples taken from failing transformers were tested to determine if a relationship

existed between the UV absorbance and type of fault. The oils tested had failed from either

thermal or arcing faults. Transformer oils which failed due to thermal faults had higher

absorbance of light, in the 360 — 400 nm region, than those which failed due to arcing. The

authors concluded that measuring the absorbance at 390 nm could be used to differentiate

between a transformer failing from either of the faults. The higher absorption of the thermally

failing oils in this wavelength region would correspond to a higher refractive index value

measured using the FISO sensor. It is expected that the oils in transformer tanks would exhibit

thermal faults more often and that the oils in load tap changers would exhibit arcing faults. The

refractive index of the transformer oils measured using the FISO sensor should, therefore, be

higher than the changes measured in the load tap changer oils.

Generally speaking, the apparent trend which we observed was that, for the same

equipment, the refractive indices of the oils in the transformer tanks were higher than those in

the load tap changer tanks, with only 28% of the samples showing the opposite and only 11%

showing a significant negative difference. There are various reasons why the refractive indices

of some oils may not have followed this trend. Some oils could have been filtered or changed at

some point in the equipments’ lifetime, which would obviously lead to changes in the refractive

indices. No information regarding the fault activity of the equipment has been provided either,

and there is a possibility that some transformers could have experienced a high level of arcing

when compared with others. The effects of other contaminants on the refractive indices of the

63

oils are also unknown. Hence, no solid conclusions can be drawn from the results of these

measurements other than that a trend has been observed, which seems to be consistent with the

results of[9].

When using samples from the field it seemed that too many variables could affect our

ability to make any solid conclusions regarding how contaminants affected the refractive indices

of the oils. We have, therefore, continued our investigation using a more systematic approach.

This was done by conducting measurements using clean oils that had been aged, degraded, or

contaminated in a controlled fashion.

3.3 Effects of Accelerated Aging on Refractive Index of Oils

Since there were no oil samples available that had been collected over time from the

same piece of equipment, it was decided that any experiments that were to be conducted

measuring the effects of aging on refractive index would require artificial aging of the oils.

Thermally accelerated aging experiments are often performed in order to predict the lifetime of

insulation systems and to generate contaminants in samples for experimental investigation [48]

[49]. Accelerated thermal aging involves exposing oil samples to high temperatures, in order to

simulate the aging effects that naturally occur over the life of a transformer, in a much shorter

time span. It has been found that increasing the temperature of oil 10°C above its normal

operating value will decrease its lifetime by up to one half [12]. If the oil samples are exposed to

extreme temperatures, the aging process can be accelerated to a point that new oil samples aged

for a few weeks will possess the properties of oils that have been in use for over 30 years. Using

this technique, however, does not expose the oil to many conditions that oils taken from the field

would have experienced. Therefore, many of the contaminants, fault gases, and chemical

compounds found in a typical sample may not be present. For example, oil that is aged in a lab

would not be exposed to arcing, unless purposely introduced, and would not contain the by

64

products associated with it. Nevertheless, these aging experiments are still useful, as there are

chemical and physical changes that the oil will undergo that would be common to both oils

naturally aged and aged at an accelerated rate.

Three accelerated aging experiments were conducted in order to study the changes in

refractive indices as oils are aged. The first experiment was conducted using both new and used

V3 5 oils. Approximately 100 g of each oil were placed in separate tin cans and were sealed. Pin

holes in the tops of the cans would also allow oxygen to reach the samples, accelerating the

aging even further. The samples were placed in a laboratory grade oven, and exposed to a

temperature of approximately 120°C. Samples were extracted at intervals shown in Table 3-5

and the refractive indices were measured and the observed color was recorded.

Table 3-5: Measured refractive index versus time for accelerated aging samples at 120°C.

New Oil 120 C

Days Aged Refractive Index Color0 (new) 1.4743 clear

15 1.4746 light yellow45 1 .47 52 yellow/orange90 1.4755 orange

Used Oil 120 C

Days Aged Refractive Index Color0 (new) 1.4743 clear

15 1 .4749 yellow/orange45 1.4753 orange90 1.4755 orange

As shown in the Table 3-5 and in Figure 3-2 the refractive indices increased over time,

and after 90 days changed by 0.0012. The color of the samples also changed over time as shown

in Table 3-5 (note: the colors of the oils shown in Section 3.3 are subjective and reflect the

opinion of the author). This can be explained by the electronic absorption edge of the oils being

shifted into the visible wavelengths as was observed in [50].

65

1.4756

1.4754

1.4752

‘ 1.4750

I1.4748

=C

1.4746

1.4744

1.4742

100

Days Aged

Figure 3-2: Plot of measured oil refractive index versus aging time when exposed to atemperature of 120°C.

0 20 40 60 80

66

In the next two aging experiments, the samples were exposed to temperatures of 150°C,

but for shorter periods of time. In the first of these two experiments, that being the second aging

experiment, new V35 was used for four cases. One tin was filled with 75g of oil only, a second

tin with 75g of oil and a 5g copper coil (12 gauge wire), a third tin with 75g of oil and 5g of

insulating papertttt, and a fourth tin was filled with 75g of oil, a 5g copper coil, and 5g of

insulating paper. These combinations were chosen to investigate the change of refractive index

in each case, since copper and paper are commonly found in high power equipment, and are

known to affect the degradation of oil [3][12][21][50].

Since the samples in the second aging experiment were exposed to a higher temperature

than the first aging experiment, samples had to be extracted at shorter intervals as shown in

Table 3-6. At 150°C both the color and the measured refractive indices changed rapidly. After

7 days of aging the oils were a brownish color and their refractive indices were higher than that

of the new V35 aged for 15 days at 120°C. Figure 3-3 shows that the oils’ refractive indices

increased progressively again, and that there were small variations between the four cases mainly

after the 7th day of aging, however, these variations were only plus or minus one resolution unit

of the FISO sensor.

The sample of oil exposed to copper only measured the greatest refractive index change.

It also seemed, by observing the color, that this sample degraded the fastest. Copper acts as a

catalyst to oil aging, and oil mixed with copper and oxygen will oxidize faster, producing larger

concentrations of carbonyl compounds [50]. The sample having oil, copper, and paper had a

slightly lower refractive index value, at the end of the experiment, than the copper only. The

addition of paper to the oil results in some of the oxidation products being absorbed by the paper,

which helps counteract some of the negative effects produced by the copper catalyst [3] [51].

fttt was Kraft upgraded paper from Algonquin Industries, Guilford, CT, USA.

67

Although the paper would absorb some of the oxidation products and some moisture contained

in the oil, when the cellulose begins to break down it would also add contaminants such as

furans, carbon monoxide, and carbon dioxide. This could explain why the refractive index of the

sample with paper only was slightly higher than the sample with just oil. Although these slight

variations in refractive index values were measured after aging, the differences between the four

samples were not appreciable comparing them with the resolution of the sensor. More important

was the observation that the refractive index increased in each case with aging.

Table 3-6: Measured refractive index versus time for accelerated aging samples with varyingcontents at 150°C.

OilDays Aged Refractive index Color

0 (new) 1.4743 clear1 1.4743 yellow4 1.4745 orange7 1.4747 brown

Oil and CopperDays Aged Refractive index Color

0(new) 1.4743 clear1 1 .4743 yellow/orange4 1 .4746 dark orange7 1.4749 dark brown

Oil_and PaperDays Aged Refractive index Color

0(new) 1.4743 clear1 1 .4743 yellow4 1.4745 orange7 1.4748 brown

Oil, Copper, and PaperDays Aged Refractive index Color

0(new) 1.4743 clear1 1.4743 yellow4 1.4745 dark orange7 1.4748 dark brown

68

1.4750

1.4749

1.4748

x1.4747

>1.4746

II

1.47450

1.4744

1.4743

1.4742

Figure 3-3: Plot of measured oil refractive index versus time when exposed to a temperature of150°C with different contents present.

0 1 2 3 4 5 6 7 8Days Aged

69

In the third aging experiment, different contaminants were added to the samples to see if

they affected the aging process and refractive index values. Five tins were filled with 75g of

new V35, and a 5g coil of copper (12 gauge wire). No contaminants were added to the first tin,

and 0.1 2g of oxygen inhibitor was added to the second to see if aging effects could be reduced.

The third tin had 0.34g of water added to it, the fourth 0.lg of acetic acid (99.7% purity), and

the fifth had 0.34g of water and 0.lg of acid.

In the third experiment, the color and refractive index changed faster than those of the

first aging experiment, as was observed in the second experiment, due to the higher temperature,

especially in the samples containing acid as shown in Table 3-7 and Figure 3-4. The refractive

index measurement of the oil and the oil with inhibitor samples were almost exactly the same

throughout. Since V35 has an oxygen inhibitor concentration of 0.08% to begin with, adding

more had no effect. The water did not affect the refractive index either, although the color

seemed to vary in comparison to the plain oil sample. This was unexpected, however, as

moisture should increase the effects of oxidation. It is assumed that the high temperature dried

out the oil before the water could have any significant affect.

The oils containing acid and both acid and water, were observed to have an increased

change of refractive index and color. The acid was found to initially lower the indices for both

cases by a very small amount, but after only a day they increased by 0.0002. After 8 days the

refractive indices of the samples containing acid were 0.0004 greater than the oil only sample.

The acid initially lowered the refractive indices of the oils but, during aging, this decrease was

more than compensated for by the increase caused by the additional aging by-products. Since

acid is a catalyst to aging, it is assumed that oils with acid present would age faster than oils

Acetic acid was from Fischer Scientific, Ottawa, ON.

70

without it, which in these experiments translated to a darker oil color and higher measured

refractive index.

Table 3-7: Measured refractive index versus time for accelerated aging samples with varyingcontaminants at 150°C.

OilDays Aged Refractive Index Color

0 1.4743 clear1 1.4743 dark yellow/orange4 1.4749 orange/brown8 1.4753 brown

Oil and InhibitorDays Aged Refractive Index Color

0 1.4743 clear1 1 .4744 light orange4 1.4749 orange/brown8 1.4753 brown

Oil and WaterDays Aged Refractive Index Color

0 1.4743 clear1 1.4744 light yellow4 1.4750 orange/brown8 1.4754 brown

Oil and AcidDays Aged Refractive Index Color

0 1.4742 clear1 1 .4744 light orange4 1.4752 brown/orange8 1.4757 brown

Oil, Acid, and WaterDays Aged Refractive Index Color

0 1.4742 clear1 1 .4744 darker yellow4 1.4752 brown/orange8 1.4757 brown

71

1.4758

1.4756

1.4754

1.4752

1.4750

1.4748

1.4746

1.4744

_____

1.4742

1.4740

0 1 2 3 4 5Days Aged

Figure 3-4: Plot of measured oil refractive index versus time when exposed to a temperature of150°C with different contaminants present.

‘7

/

—. - CleanV-35

- -. - Inhibitor

A Water

X Acid

—)E — Water and Acid

6 7 8 9

72

By conducting these aging experiments, it was observed that the refractive index does, in

fact, change to a relatively large degree during the aging process. As oils were aged and by

products were formed, the refractive indices of the oils increased. This result supports the

assumption that the addition of aromatic compounds will contribute to the increase in the

refractive index, as discussed in the previous section. Paraffms, also known as Alkanes, are

saturated hydrocarbons which are composed of hydrogen and carbon atoms linked by single

bonds (see Figure 3-5(a)). Naphthenes, also called Cycloalkanes, are paraffms containing one or

more carbon rings (see Figure 3-5(b)). The hydrogen and carbon atoms present in naphthenes

are linked by single bonds as well. Aromatic hydrocarbons, also known as an Arenes, contain

one or more aromatic ring. An aromatic ring consists of six carbon atoms that form a conjugated

system of alternating single and double covalent bonds between the carbon atoms, which are also

linked to hydrogen atoms by a single bond (see Figure 3-5(c)). During thennal decomposition of

mineral oils, paraffinic compounds dehydrogenate forming naphthenic compounds which further

dehydrogenate to form conjugated C=C double bonds and aromatics [35]. The bonding

electrons found in the it-orbitals of conjugated systems can be excited to higher energy levels,

and these energy transitions are frequently observed in the near UV region (1 90-400nm) [331.

The larger the conjugated system becomes (the more alternating double and single bonds found

in a compound), the lower the energy required for a transition, which corresponds to light at

longer wavelengths being absorbed. The electrons that form the a bonds, that paraffinic and

naphthenic compounds are generally made up of, require a higher energy and, therefore, shorter

wavelength, usually below 150 nm, in order for a transition to occur [33]. This, in part, could

explain our observations of an increased refractive index and change in color of the oils during

aging. The decomposition of paraffins and naphthenes and formation of aromatic compounds in

the oil produces absorption in the near UV region. The formation of more aromatic compounds

73

H H H H H HI I I I I

H—C — C—C—C—C—C—HI I I

H H H H H H(a)

H HH \,i H

\ C /H—C C—H

H—C C—H/ C’

H /\ I-IHH

(b)

H

H -C HC

HC

H

H(c)

Figure 3-5: Examples of different types of hydrocarbon compounds. (a) example of aparraffinic compound (hexane). (b) example of a naphthenic compound (cyclohexane). (c)example of a aromatic compound (benzene).

74

over time leads to the polymerization of these conjugated systems and, therefore, shifts the

electron absorption edge further into the UV and eventually visible region. The shifting of the

absorptive behavior of the oil would obviously affect the refractive index, as discussed in

Chapter 2, Although the addition of aromatic compounds is one factor that may be linked to the

increase in refractive index of the oils, there are other compounds, or factors, that could also

contribute.

For samples used in any particular experiment, it was observed that the refractive index

increased with a darkening of the oil color. This does not mean, however, that color change can

be directly related to the refractive index. For example, when comparing the refractive indices

of the oil only sample shown in Table 3-7 at day eight, which had a brownish color, with the

samples shown in Table 3-5 at 90 days, which had an orange appearance to them, the brown

sample had a lower refractive index than the orange samples. However, oils from the same

experiment with a darker color had a higher refractive index that oils with a lighter color. This

leads us to believe that the darkening of an oil in a piece of equipment could result in an

increased refractive index of that oil but this does not necessarily mean that this darker oil would

have a higher refractive index than a lighter oil extracted from a different piece of equipment.

It also seems that catalysts added to the oils, such as copper and acid, increased the

degradation of the oils which, in turn, increased the refractive index over time. These catalysts

may accelerate the formation of aromatics and other compounds, which not only indicate a

decrease in the oil quality, but increase the refractive index as well. Hence, we conclude that a

change in the refractive index can be linked to the aging of oils. Nevertheless, further

experiments are needed to determine how individual contaminants such as polar compounds,

ftirans, acid, or dissolved gases affect the refractive indices of the oils.

75

3.4 Polar Compounds in Oil

3.4.1 Introduction to Section

The following experiments were conducted in order to determine the extent to which the

concentration of polar compounds affected the refractive index of the oils. Much of the

following section was taken from [52], which was presented at a conference by the author of this

thesis. A method is described which could be used to indicate relative concentrations of polar

compounds using refractive index as an indicator. The results are presented using this method.

Samples with varying levels of polar compounds were obtained using oils taken from

transformers used in accelerated aging experiments at Powertech Labs. The actual

concentrations of polar compounds found in the samples were measured using HPLC (high

pressure liquid chromatography) as discussed in Chapter 1, and the refractive index changes due

to poiar compounds were measured using the FISO system.

3.4.2 Methanol Extraction

In order to analyze oil samples, the polar compounds were removed from each sample

using a liquid-liquid extraction technique. This method is often used to remove furans from oil

samples prior to using HPLC [22][53j. When a polar solvent such as methanol, which we used

for extraction, is mixed with a sample of oil the polar compounds will be partitioned into the

methanol due to their affinity.

For our experiments, the refractive indices of the oil samples were first measured using

the FISO FRI (Fiber optic Refractive Index) sensor. One gram of high purity grade 99.9%

Parts of this section are pending publication. Kisch, RJ., Hassanali, S., Kovacevic, S. and Jaeger, N.A.F. (2007)

The effects of polar compounds on refractive index change in transformer oils, Proceedings of High Voltage and

Electrical Insulation Conference ALTAE 2007.

76

methanol was then added to ten grams of each oil sample and the solutions were mixed

vigorously using a vortex mixer. A centrifuge was used to separate the two phases and the

methanol phase, containing all of the polar compounds, was extracted from each sample. The

refractive index of each oil sample was measured again after the polar compounds were

removed, and the methanol extract samples were analyzed using NPLC. The refractive indices

of each methanol extract sample containing the polar compounds were also measured.

3.4.3 Oil Samples

Oil samples with varying levels of polar compounds were made available through

accelerated aging and filtering experiments conducted at Powertech Labs. V35 was used for an

accelerated aging experiment in surrogate transformers designed to mimic free breathing

transformers and nitrogen-blanketed transformers. A set of four samples were extracted from

four free breathing type transformers and a set of four were extracted from four nitrogen

blanketed type transformers. Each set of four samples included two that had been filtered

through different online purification units developed by Powertech Labs, which could be

compared to two control samples which had no purification units connected to them. One of the

purification units removed only moisture and particulate matter from the oil (dehydration unit),

while the second unit removed all paper and oil degradation products such as carbonyl and acid

compounds, polar compounds, oxygenated compounds, furanic compounds, dissolved metals, as

well as moisture and particulates (decontamination unit). The decontamination unit would

restore the aged oil quality to that of new oil and maintain it at a “near new” level as long as it

was connected to the transformer. The oil and paper insulation life would, therefore, be

extended and, subsequently, would extend the life of the transformer.

The oils were thermally aged by heating the surrogate transformer windings with a high

Methanol was from Analabs, Inc., Crab Orchard, WV, USA.

77

amperage, low voltage DC current. The windings were heated in 40 hour cycles consisting of a

10 hour ramp from 30°C to 120°C, held at 120°C for 20 hours and, thereafter, cooled to 30°C.

Table 3-8 lists each sample number and its associated aging conditions.

Aging effects differed between each sample as shown in Table 3-9. The samples

extracted from nitrogen blanketed transformers (samples 1-4) did not show as severe signs of

aging as compared to those exposed to oxygen, as the effects due to oxidation were reduced. For

each of the two sets of oils, samples that were extracted from transformers that were filtered for

moisture (samples 2 and 6) indicated more aging as compared to unfiltered samples, as effects

due to moisture were reduced. Those samples extracted from transformers connected to the

decontamination unit showed the least aging, as effects due to many contaminants were reduced.

Table 3-9 illustrates this by showing some measured physical, chemical, and electrical properties

of our samples.

Table 3-8: Aging conditions for oils used in polar compound measurements.

Sample BlanketingTreatment CyclesNumber Type

Decont.1 Nitrogen Filter 237

2 Nitrogen Moisture 237

3 Nitrogen None 237

4 Nitrogen None 237

Decont.5 Oxygen Filter 237

6 Oxygen Moisture 237

7 Oxygen None 205

8 Oxygen None 205

78

Table 3-9: Measured properties of aged oils.

Sample Power Neutralization InterfacialNumber Factor Number Tension Color

1 0.039 0.003 43.5 0.8

2 0.031 0.003 42.5 0.5

3 1.037 0.004 33.5 1

4 1.21 0.004 32.5 1

5 0.06 0.003 43.2 0.5

6 8.268 0.092 21.2 3.5

7 11.85 0.152 15.7 4

8 30.79 0.432 14.6 5,5

3.4.4 Refractive Index Measurements

By analyzing each methanol extract sample using HPLC, it was observed that samples

obtained from oils showing more aging did, indeed, contain higher concentrations of polar

compounds. The nitrogen blanketed samples contained much lower concentrations of polar

compounds than those extracted from the free breathing units. Samples extracted from the

dehydration units contained lower concentrations as compared with unfiltered samples, and

samples from the decontamination units contained the lowest. This is shown in Table 3-10, in

the “Polar Compounds” column, which corresponds to the sum of the areas under predetermined

peaks in the chromatograph (a larger area indicates a higher concentration of polar compounds).

The refractive indices of the oil samples were measured at 24.30°C and of the methanol

extract samples at 21.70°C. The measured refractive index of new V35 mineral oil was 1.4746.

Other than the samples extracted from the decontamination unit, the refractive indices of all oil

79

samples increased during aging. The refractive indices of the oil samples taken from

transformers with the decontamination units were very close to that of new V35 mineral oil and

in the case of the decontamination filtered nitrogen blanketed oil sample it was lower than that of

new V3 5. The authors believe that the decontamination filtered nitrogen blanketed sample’s

lower refractive index is due to the filtering, which extracts some compounds originally present

innewV35oil.

Table 3-10: Refractive index measurements of oil and methanol samples and concentration ofpolar compounds measured by HPLC.

Oil RI Area ofSample Change MethanolOil RI After PolarNumber inRi RIExtraction Compounds

1 1.4743 1.4742 0.0001 1.3310 842

2 1.4761 1.4759 0.0002 1.3311 1422

3 1.4760 1.4758 0.0002 1.3314 3303

4 1.4760 1.4758 0.0002 1.3315 3572

5 1.4746 1.4743 0.0003 1.3352 4205

6 1.4761 1.4757 0.0004 1.3410 44080

7 1.4762 1,4758 0.0004 1.3413 47460

8 1.4765 1.4759 0.0006 1.3494 94720

After the polar compounds were removed, the refractive indices of the oil samples

dropped by a small amount in each case. It seemed that the changes in refractive indices of the

nitrogen blanketed samples were very small, and barely measurable. Although the changes in

the refractive indices of the free breathing oil samples were somewhat larger, they were still

close to the resolution of the FISO system. Nonetheless, the apparent trend was that an oil

80

sample that showed a larger amount of polar compounds would experience a larger change in

refractive index when the polar compounds were removed.

The refractive index of methanol extract that had been obtained from a new sample of

V35 oil was 1.3307. The refractive indices of the methanol extracted from all of the aged

samples were higher than 1.3307, and showed an increase with the amount of polar compounds.

The differences between the methanol extract refractive indices from the free breathing samples

were quite large in comparison to those from the nitrogen blanketed ones. Figure 3-6 and Figure

3-7 show that the refractive indices of the methanol extract samples, for each set, increased

relatively linearly with the amount of polar compounds.

81

4-

F

1

2

F II III II II I I II ii iii I I ill

• Measured

0 500 1000 1500 2000 2500 3000 3500 4000Area of Polar Compounds

Figure 3-6: Methanol extract refractive index versus the area of polar compounds measured byHPLC in nitrogen blanketed oil samples.

1.3316

1.3315

1.3314

I EEE1.3310

1.3309

1.3308

82

. MeasuredLinear Fit

I I I I I I I I

0 20000 40000 60000Area of Polar Compounds

Figure 3-7: Methanol extract refractive index versus the area polar compounds measured byHPLC in free breathing oil samples.

81.3520

1.3500

1.3480

1.3460

1.3440

1.3420

1.3400

1.3380

1.3360

1.3340

1.3320

80000 100000

83

3.4.5 Polar Compound Extraction From Naturally Aged Oils

Since there were a few samples from Section 3.2.2 that had been measured for polar

compounds using HPLC, it was decided to see if similar results could be obtained using this

extraction technique on oils obtained from the field. The total area produced by adding the area

under the peaks on the chromatograph was available for four oil samples from the same station.

These samples were Al-TX, Al-LTC, A2-TX, A2-LTC found in Table 3-4. The same

procedure described above was used to measure the refractive indices of the oil samples before

and after methanol extraction, and of the methanol extract itself. Table 3-11 shows the results,

and Figure 3-8 and Figure 3-9 show the methanol refractive index and the change in refractive

index of the oils after methanol extraction.

Table 3-11: Refractive index measurements of naturally aged oil and methanol samples and areaof polar compounds measured by HPLC.

Oil RI Area ofSample Change MethanolOil RI After Polar

ID inRI RIExtraction Compounds

Al-TX 1.4867 1.4863 0.0004 1.3394 51200

A2-TX 1.4863 1.4858 0.0005 1.3403 60561

A2-LTC 1.4852 1.4844 0.0008 1.3493 87317

Al-LTC 1.4859 1.4850 0.0009 1.3527 94860

84

1.3550

1.3530

1.3510

1.3490

1.3470

1.3450

1.3430

1.3410

1.3390

1.3370

1.3350

45000 55000 65000 75000 85000 95000 105000

Area of Polar Compounds

Figure 3-8: Methanol extract refractive index versus the area of polar compounds measured byHPLC in naturally aged oil samples.

85

0.001

0.0009

0.0007

0.0006

0.0005

0.0004

0.0003

45000 55000 65000 75000 85000 95000 105000

Area of Polar Compounds

Figure 3-9: Change in refractive index of naturally aged oils after methanol extraction versus thearea of polar compounds measured by HPLC.

86

Using this methanol extraction technique provided similar results when naturally aged

oils were used, as the refractive index of the methanol extract increased with increasing polar

compound concentration. The change in refractive index after extraction was also increased

when the concentration of poiar compounds was higher. Figure 3-9 shows that the change in

refractive index was quite linear with the area of polar compounds measured. Large changes

were measured for a few of the samples that were extremely degraded, but again, it did not seem

that the polar compounds would be the only factor changing the refractive indices of the oils.

3.4.6 Discussion

Small decreases in the refractive indices of the oils were observed after the methanol

extraction was performed. We can assume that the decrease is caused due to the removal of the

polar compounds from the oil, since it was observed that when larger amounts of polar

compounds were removed from the oils larger decreases in the refractive indices were observed.

In particular, this is clearly demonstrated by referring to the more degraded oil samples such as

accelerated aging samples 6, 7, and 8, and all naturally aged samples. Hence, we conclude that

the refractive index of oil samples is increased slightly due to the formation of polar compounds.

By concentrating the polar compounds using methanol extraction, larger changes in the

refractive indices of the methanol extracts could be measured as compared to those of the oils.

These larger changes that are measured in the methanol solution could be due to the addition of a

solute (the polar compounds) having higher refractive indices than the solvent (the methanol).

Also, the methanol molecules could react with some of the extracted polar compounds, to form

new compounds having higher refractive indices. Regardless, the change of the refractive index

induced in the methanol was a useful indication of polar compounds.

During the aging process, different types of polar compounds are formed, some of which

will not contribute to changes in the refractive indices of the oils or the methanol extracts. For

87

example, the refractive index (at optical frequencies) is affected by the electronic polarizability

of a medium, but not by the molecular dipolar orientation polarizability [43]. Some oil samples

could contain higher concentrations of the types of polar compounds which do not contribute to

a refractive index change and would not be detected. Also, when we used HPLC we looked at

the total and not individual polar compounds. This could lead to some measurements not fitting

linearly into the results, since one oil sample could contain more of a compound that affects the

refractive index change to a larger degree than other samples containing similar concentrations

of those compounds which do not.

Samples extracted from nitrogen blanketed transformers and samples extracted from free

breathing transformers should be treated individually. Different aging effects may produce

different ratios between the types of poiar compounds formed. Free breathing transformers will

experience aging effects primarily due to oxidation processes, whereas aging in nitrogen

blanketed transformers may be dominated by the formation of polar compounds due to other

aging effects. Hence, the results of tests performed using samples extracted from different types

of transformers should be treated separately.

Nevertheless, since the presence of polar compounds does indicate a weakening of the

insulation quality of the oil, detecting them is a valuable tool in analyzing the insulation quality.

The measurement of the refractive index in methanol extract can be used to indicate an increase

in certain types of polar compounds, so could, therefore, be used to indicate a decrease in

insulation quality in cases where expensive HPLC equipment is not immediately available. If

this method was to be put into practice, further experimentation would be necessary in order to

develop relationships between the concentration of polar compounds and change in refractive

index of methanol for different types of oils and different types of transformer aging. It would

be helpful as well, to repeat this experiment using refractive index sensors with higher

88

resolution. We were not able to do this with our D-fiber sensor since the surrogate transformers

used at Powertech Labs were not filled with oils having refractive index values in its high

sensitivity region.

Our observation was that the polar compounds in the oils do not seem to change the

refractive indices to a tremendous degree, but still do contribute to the increases that are

observed during aging as discussed in Section 3.3. In order to use refractive index to detect

polar compounds only, the polar compounds must be extracted from the oil samples first, for

example, using the methanol extraction technique. It is possible that an integrated “lab-on-a

chip”, which detects poiar compounds in the methanol extract using refractive index, could be

used as a cost efficient way for online monitoring of oil quality. This would require additional

development of this technique and design of the system.

3.5 Effects of other Contaminants in Oil

In the previous section we saw that the addition of polar compounds to oil samples

slightly increased the samples’ refractive indices. Tests showing the effects of other

contaminants such as furans, acid, and dissolved gases are discussed in this section.

Contaminants were artificially introduced into oil samples to observe their individual effects in a

controlled manner.

3.5.1 Oil Samples Spiked with Furans

Experiments were conducted in order to determine if the addition of furans affects the

refractive index of oil samples. Levels of furans in oil samples are measured at Powertech Labs

as an indicator of paper degradation in oiL’paper insulated equipment. Oil samples have been

prepared at Powertech Labs using V35 oil, with varying levels of 2-furaldehyde, which have

been used as controls in system calibration for HPLC. The oil samples used for this experiment

varied only by the concentration of furans present in them.

89

As shown in Table 3-12, the concentrations of 2-furaldehyde did not produce changes

that were greater than the 0.000 1 resolution of the FISO sensor. The highest concentration of 2-

furaldehyde present in any of the control oils was 1 O0ppm, which far exceeds the typical values

found in samples obtained from the field.

Table 3-12: Measured refractive indices of oil samples varying in 2-furaidhyde concentration.

Furan RefractiveConcentration(ppm) Index

0.5 1.47461 1.4746

100 1.4746

Typical concentrations of furans in oils taken from the field are generally measured in the

hundreds of parts per billion (ppb). Table 3-12 indicates that such small concentrations would

not produce appreciable changes in the refractive indices of the oils. This study was performed,

however, to validate this assumption by finding the minimum detectable concentration that can

be detected with our sensor.

The D-fiber sensor’s higher resolution would allow smaller changes in the refractive

indices of the sample oils to be detected when Luminol Tn oil was used. A mixture of furans

was obtained from Powertech Labs containing four compounds including 2-furaldehyde (2-Fur),

5-acetylfuran (Acetyl Furan), 5-methyl-2-furaldehyde (5 Methyl Fur), and phenol. l2mL

samples of Luminol Tn oil were spiked with drops of the furan mixture, shaken vigorously, and

the refractive indices were measured. A sample with 3 drops of furans added to the oil was

measured for furan concentration at Powertech Labs using HPLC, and the results are shown in

Table 3-13. This measurement was used to correlate the number of drops added to a specific

volume of oil to its concentration. It was observed that very high levels the four compounds

were found in the measured sample.

90

Table 3-13: Measured concentrations of furans in 1 2mL Luminol samples spiked with 3 dropsof furan mixture.

Compound Ret ConcentrationName Time (ppb)2-Fur 6.3 24500

AcetylFuran 8.55 6364

5 MethylFur 10.07 36548

Phenol 11.89 10585

Samples containing 1 and 2 drops of furans did not show any change in their refractive

indices. Samples with 3 drops of furans changed to a slight degree, although the measurement

became very unstable, and the refractive index drifted very quickly during a measurement

period. This was only the case for the samples spiked with furans though, and not the control

samples, so it was assumed that the varying concentration of furans throughout the sample was

causing the unstable readings. The number of drops was doubled to 6 in each sample, and a

small refractive index change of approximately 4.3 x 1 0 could be measured repeatedly.

Although the four compounds shown in Table 3-13 were present in the oil, we will limit

our discussion to the varying level of 2-furaldehyde for demonstration purposes. As previously

discussed, the concentration of 2-furaldehyde has been directly related to the degree of

polymerization of the paper [211. If we look at the concentration of 2-furaldehyde, we see an

extremely high level, which would not normally be found in samples obtained from the field. A

transformer having oil with a concentration of 2487 ppb has an estimated remaining lifetime

percentage of 7% [17], and our concentration was about 10 times higher than this. The measured

concentration was 24500 ppb for 3 drops of furans. Our refractive index change of 4.3 x i0

was measured using oil with 6 drops present. The concentration of 2-furaldehyde would be

approximately 49000 ppb.

91

If we assumed that the refractive index change of the oil was due to the presence of 2-

furaldehyde only, and we extrapolate our data, we observe the need of a resolution improvement

by a factor of at least 25. There are, however, very high levels of the three other compounds as

well, which exceed the normal levels observed in the field. The addition of these other three

compounds could be contributing to the small increase in refractive index as well. By

performing this test, we have observed that higher resolution sensors are necessary in order to

detect these furans by refractive index change. The concentration of these 4 compounds would

not contribute to any large changes in refractive index as paper insulation degrades and it is very

doubtful that any furans would either in the typically low concentrations. Also, it is likely that in

an oil sample, taken from the field, the changes due to the furans would be masked by changes

due to the addition of other aging by-products.

The chemical compound Furan, has a structure similar to the aromatic hydrocarbon

benzene, although an oxygen is present in the place of two of the six carbon atoms found in the

aromatic ring (see Figure 3-10(a) and (b)). Other chemical compounds having this same

aromatic ring structure with an oxygen present but having other compounds bonded to a carbon

in the place of a hydrogen, such as 2-furaldehyde, are often referred to as “furans” (see Figure

3-10(c)) . During the aging process of paper insulation, long polymers consisting of cellulose

molecules begin to break down into monomer units, which continue to break down into glucose

molecules, which eventually break down to form furans [54]. Furans are known to absorb light

in the UV region and are often detected using 220 and 280 nm wavelengths [53]. Since

dissolved furans in the oil would lead to higher absorption at these wavelengths, one would

expect the refractive index to increase as well. As we have observed, we expect the increase to

be very small since the concentrations are in the parts per billion. Hence, when comparing the

refractive index change which would be observed due to the addition of furans to that which

92

H H

c—c

HzH

H

H H

H

..,

•• :o,.

(c)

Figure 3-10: (a) Chemical structure of benzene. (b) Chemical structure of Furan. (c) Chemicalstructure of 2-furaldehyde.

H

H H

H—CH

(a)

(b)

93

would be observed due to the addition of other aging by-products, such as aromatic

hydrocarbons, one expects that the furans would be overshadowed. Nonetheless, the extremely

small increase that the furans contribute will add to the contributions of other aging by-products.

3.5.2 Acid Artificially Introduced into Oil Samples

By adding acid to oil samples, it is possible to measure the effect that a specific acid has

on the oils’ refractive indices. Here, the type of acid used was acetic acidttttt (99.7% purity)

which is commonly found in transformer oils. Drops of acid were added to 23mL of Luminol

TRi oil and the samples were agitated vigorously to distribute the acid throughout the oil. The

concentration of acid in one of the samples was measured, which could be correlated to the

number of drops added to a specific volume of oil.

The refractive index was measured using the D-fiber sensor and the refractive index

changes are shown in Table 3-14. A change in refractive index of -2.2 x i0’ was measured for

samples with an approximate acid number of 0.72. Samples with an approximate acid number of

0.48 had a measured refractive index change of -1.54 x 1 0. The lowest change in refractive

index due to the addition of acid, shown in the table, is -6.1 x i05. The acid number was

measured for a sample showing this refractive index change and was 0.24 mgKOH/gOIL. This

is a very high reading for acid, and would only be measured if the oil was extracted from a

transformer that was at the end of its life. An acceptable acid number for an in-service oil is less

than 0.05 and if it reaches 0.2 the oil should be reclaimed [12]. Figure 3-11 shows the change in

refractive index plotted versus the approximate acid number.

Acetic acid was from Fisher Scientific, Ottawa, ON.

94

Table 3-14: Measured refractive index change due to acid added to Luminol TRi oil samples atvarying concentrations.

ApproximateAcid Number

(mgKOHIgOIL) An0.72 -2.24E-040.48 -1.54E-040.24 -6.1E-05

0 0

Performing this acid experiment showed that transformers at their end of life would show

a slight decrease in refractive index due to acid number, that is barely detectable by our sensor.

For changes in acid only, using refractive index to detect increasing levels may be possible with

better resolution. Although performing this experiment showed that the addition of acetic acid to

transformer oil would slightly lower the refractive index, the degree to which it is lowered is

very small in comparison with the expected increase in refractive index due to other compounds

formed. We have previously observed that during aging the net refractive index of oils increases

due to the formation of other aging by-products. Although some of the aging by-products may

include acid which would slightly lower the net refractive index, the lowering would be

overshadowed by the larger increase due to other compounds, such as aromatic hydrocarbons,

being added to the system. Acid acts as a catalyst to oil aging as well, and the presence of acid

in an oil would lead to an accelerated rate of formation of other by-products that tend to increase

the refractive index.

95

Acid Number (mgKOHJgOIL)

0 0.1 0.2 0.3 0.4 0.5 0.6 0.8

0.OOE+00

-5.OOE-05

-1.OOE-04.

-1.50E-04

0

-2.OOE-04

-2.50E-04

-3 .OOE-04

Figure 3-11: Change of refractive index of Luminol oil samples versus approximate acidnumber.

0.7

96

3.5.3 Gas Artificially Introduced into Oil Samples

By artificially adding a particular gas to an oil sample, it was possible to determine if that

single gas had any affect on the sample’s refractive index. Gas insertion was provided using

canisters containing compressed gases. It was decided that the use of the D-fiber sensor and

Luminol TRi oil would be necessary for this experiment, since we assumed that very small

changes in refractive index would occur due to the presence of a gas.

Samples were prepared using the gases ethane and acetylene, since they were available at

Powertech Labs, and had high Ostwald coefficients for Luminol Tn oil (i.e., they would stay in

the oil for long periods of time) [55]. Experts working at Powertech Labs also suggested using

these gases. Ethane and acetylene may be generated in larger quantities in load tap changers.

Using these gases eliminated the use of a testing apparatus which reduces air exposure to the oil,

since they have slower diffusion rates from the oils compared to the other fault gases.

Oil samples with approximate concentrations of gases were prepared using air tight

syringes. Standard bottles that are used by Powertech Labs to store samples obtained from the

field for DGA analysis where used to store our samples. These bottles were filled completely

with 28. 5mL of oil which minimizes the headspace where the gas could slowly diffuse over

time. In order to prepare the samples with approximate concentrations of gas, the volume of gas

that would be injected into the oil was first calculated. For example, a concentration of 100 000

ppm of ethane injected into a sample used the following procedure: lppm of a gas corresponds

to 1111. per L of oil, so we needed to inject 2.85mL of gas into our oil samples. A tube was

connected from the gas canister to the air tight syringe, and the valve on the canister was slowly

opened to fill the syringe. When the syringe was filled, a stop at the end was closed to keep the

gas inside the syringe, and the gas flow from the canister was stopped. The volume of the gas in

the syringe was reduced to approximately 2.85mL by slowly opening and closing the stop until

97

the desired level was reached. Once the desired amount of gas was contained in the syringe, the

oil from the bottle was sucked into it. A small space of gas existed above the oil in the syringe,

and over time the space became smaller as the gas was being forced into the oil by applying

pressure, and shaking the syringe. Eventually there was no space above the oil, as the gas was

totally dissolved in the oil, producing an oil sample with the desired concentration of gas.

This process was repeated to produce several samples with desired concentrations of

ethane and acetylene which were tested in order to see if the refractive indices changed due to

the gases. Table 3-15 and Table 3-16, and Figure 3-12 and Figure 3-13 show the results of these

experiments.

Table 3-15: Measured refractive index change due to ethane injection into Luminol TRi oilsamples at varying concentration levels.

EthaneConcentration

(ppm) An

200000 -5.3E-05100000 -2.9E-05

50000 -1.3E-05

0 0

Table 3-16: Measured refractive index change due to acetylene injection into Luminol TRi oilsamples at varying concentration levels.

AcetyleneConcentration

(ppm) An200000 -3.6E-05100000 -1.6E-05

0 0

98

Ethane Concentration (ppm)

50000 100000 150000 200000 250000

0. OE+00

-1.OE-05

-2.OE-05

. -3.OE-05

-4.OE-05

-5.OE-05

-6.OE-05

-7.OE-05

-8.OE-05

Figure 3-12: Change of refractive index of Luminol oil samples plotted versus approximateethane gas conceniTations injected.

0

99

Acetylene Concentration (ppm)

0 50000 100000 150000 200000 250000

0.OE+00

-5.OE-06

-1.OE-05

— -1.5E-05

-2.OE-05

-2.5E-05

-3.OE-05

-3.5E-05

-4.OE-05

-4.5E-05

-5 .OE-05

Figure 3-13: Change of refractive index of Luminol oil samples plotted versus approximateacetylene gas concentrations injected.

100

The refractive index decreased by a very small amount for samples injected with either of

the two gases. Ethane affected the refractive index a bit more than acetylene, although the

changes were still very small. At a concentration of approximately 50000ppm of ethane and

1 00000ppm of acetylene, the refractive index changes were just barely measurable with our

sensor. It is common to obtain oil samples from load tap changers that have gas concentrations

in the thousands of ppm or possibly even in the tens of thousands of ppm, but not in the hundreds

of thousands of ppm.

Although we could measure small decreases in the refractive indices when gases were

present in the oils, the concentrations that were needed to observe a small change were much

higher than would be found in equipment in the field. Looking at the samples measured in

Section 3.2.1, it does not seem likely that the relatively small concentrations of gases found in

these samples would have contributed to the change in refractive index. Using refractive index

change to detect gases does not seem to be a promising method that could be used for online

monitoring. It is assumed that the small changes in refractive index that could be measured due

to the addition of gas to the oil would be overshadowed by the larger increases in refractive

index that occur naturally during aging.

101

Chapter 4

4 Summary, Conclusion, and Suggestions for Future

Work

4.1 Summary

In summary, we have performed experiments to determine if refractive index can be used

to monitor the quality of high voltage equipments’ insulating oils and subsequently the condition

of the equipment. Based on a substantial literature review, we started the investigation with the

belief that various contaminants and compounds would affect the refractive indices of oils to a

certain extent. In fact, we did observe such effects and, the extents to which various aging by

products affected the refractive indices of the oils were recorded.

Two refractive index sensors were used in this investigation, one of which had only been

used previously for demonstration of proof-of-principle (the D-fiber sensor) and another which

was commercially available (the FISO sensor). A maximum resolution of 1.1 x i0 was

achieved with our D-fiber sensor, which was needed for some of the more sensitive

measurements. The FISO sensor was used when the measurements did not require the higher

resolution of the D-fiber sensor and when the samples under test had refractive index values that

were not in the D-fiber sensor’s most sensitive region.

Many oil samples obtained from the field were tested using the FISO sensor. The first

sets of oils were extracted from cables, transformer tanks, and load tap changer tanks, which

provided us with oils having varying levels of gases in them. The refractive indices were

observed to have changed in some of the samples, but through the process of elimination, it was

102

concluded that the gases could not have been a factor in the change. The second sets of oils from

the field had varying physical and chemical properties that were measured. Here, a set of oils

included a sample extracted from the transformer tank that could be compared to another sample

extracted from the load tap changer tank. When comparing the sets of oils, it was apparent that,

in most cases, the transformer tank sample had a higher refractive index than the load tap

changer sample. This was consistent with a previous study performed by another group that

measured UV absorption of oils [9].

Accelerated aging experiments were performed using insulating oils and increases in

their refractive indices were measured as the oils aged and their colors changed and became

darker. These increases in refractive indices were atthbuted to the decomposition of paraffms

and naphthenes and the formation of aromatics and other aging by-products. The measured

increases in refractive indices were quite large for these experiments.

Experiments were conducted using oil samples varying in the concentration of polar

compounds. We found that the addition of poiar compounds increases the refractive indices of

the oil samples. However, these increases were not large. Using a methanol extraction

technique, the refractive index change of the methanol could be used as an indication of the

concentration of polar compounds. These refractive index changes in the methanol were found

to be much larger than those observed directly in the oil.

In order to measure the extent to which the addition of other aging-by products changed

the refractive index of an oil, furans, acetic acid, acetylene, and ethane where added to oils in

controlled manners. It was observed that these contaminants did not affect the refractive indices

to a large degree.

103

4.2 Conclusion

During the aging process of oil found in high voltage equipment, various by-products are

formed which typically include (but are not limited to) fault gases, acids, furans, polar

compounds, and aromatics. We have observed that the collection of all the compounds that were

formed during the accelerated aging experiments increased the refractive indices of the oils to a

relatively large degree. We believe that the increased refractive indices that were observed

would be common to most oils naturally aged in the field. Hence, experiments were conducted

to investigate what by-products would contribute to this increased refractive index by separating

their effects.

The addition of a few types of furans, the addition of acetic acid, the injection of

acetylene, and the injection of ethane all changed the refractive indices of the oils to very small

degrees. We expect similar results using other furans, acids, and fault gases. The addition of

furans led to very small increases in the refractive indices that were only measurable when the

concentration of furans greatly exceeded those typically found in oils taken from the field. It

was observed that the addition of acetic acid led to a decrease in the refractive index of an oil,

however, the concentration necessary to measure a small change matched that found in a sample

extracted from a transformer at the end of its life. Decreases in the refractive indices were also

measured when acetylene was injected and ethane was injected into the oils. The concentrations

of acetylene and ethane needed to measure a refractive index change on the order of our D-fiber

sensor’s resolution were over ten times higher than those normally found in oils taken from

severely faulting transformers found in the field. The changes in refractive indices, due to the

addition of the furans, acids, and gases which were tested, would obviously be masked by the

larger changes due to the formation of other aging by-products.

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Small portions of the increases that were measured in the refractive indices of the oils can

be attributed to the formation of polar compounds. Larger portions of the increases in refractive

indices can be linked to the formation of aromatic compounds and other aging by-products. The

formation of by-products such as aromatic compounds and polar compounds occur as oils

degrade and one would expect a more rapid rate of the formation of these compounds in oils

being degraded at faster rates. Therefore, the refractive index may be used as a measure of the

“break down” of the oil through aging. Hence, an oil with a refractive index that is increasing

faster than is normally expected may be experiencing a fault or other undesirable condition

which is increasing the rate of the “break down”. We conclude that the refractive index could be

used as a “flag” indicating an increased aging rate.

One can monitor the level of polar compounds formed in an oil, however, it was

observed that directly measuring the refractive index of the oil samples was not useful for this

purpose. Since the presence of other compounds affects the refractive index change to a larger

degree, other techniques must be used. We believe that using the methanol extraction technique

and measuring the refractive index change of the methanol is a useful indicator of polar

compounds. This technique could be used in a fashion similar to the one that was presented here

but such an approach would require an operator. The technique would become of much more

value if an integrated “lab-on-a-chip” type system were designed. Oil could be monitored online

for polar compounds if a system were designed that would automatically perform all the

necessary steps involved in extracting polar compounds from the oil by mixing a small amount

of oil with a small amount of methanol and measuring the refractive index change of the

methanol. One can envision that such a system could be designed using MEMS technology

(Micro-Electronic-Mechanical Systems technology).

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The detection of furans by directly measuring the refractive index of oil samples does not

seem feasible, as the small changes measured due to their formation would be overwhelmed by

the changes caused by other aging by-products. In order to make the detection of furans by

refractive index possible, one would first have to separate them from the oil first. Furans can be

separated using a solvent such as methanol. However, the furans must then be separated from

the poiar compounds that would be extracted by the methanol at the same time. As was

previously discussed, this is normally done using HPLC. If a method similar to that of [39] were

used, where a soT-gel process was used to create a material that absorbed furans in the oil and a

corresponding change in the absorption of light at 530 nm was observed, the refractive index

might be useful in the direct detection of furans in oils. It is assumed that the changing

absorption profile of the sol-gel material would result in a corresponding change in the refractive

index and, depending on the sensitivity of the material, may prove useful.

Separation techniques would be required for the detection of acetic acid or fault gases.

There are various techniques which can be used for the separation of gases from oil, such as

using the membrane technology of the GE Hydran, or the polymer barriers used in the Morgan

Schaeffer Calisto. The detection of gases using refractive index could provide a cost effective

solution if made possible, however, it is very doubtful that the sensitivity could rival that of

DGA.

4.3 Suggestions for Future Work

We have observed the increase in refractive index of V35 oil due to aging and expect

similar results when using other oils. Nonetheless, one should show this for other oils. Our

investigation would have been more consistent if Luminol Tn was used throughout the entire

duration of our study, however, many experiments were already completed using V35 oil before

it was found that the Luminol Tn’ s refractive index value fell within our D-fiber sensor’s high

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resolution region. Hence, it might be useful to repeat the aging experiments using Luminol Tn.

When repeating the aging experiments it would be of value to use a higher resolution sensor,

such as the D-fiber sensor. This higher resolution would allow for smaller changes to be

measured over shorter periods of time. If possible, the properties of each oil sample (KV

breakdown, acidity, IFT, color) should be measured in addition to the measurement of the

refractive index. Measuring the properties of the oils would provide more information regarding

the state of oils and their associated refractive indices.

It would also be useful if a study could be initiated in collaboration with a utility

company, in which the refractive indices of transformers found in a sub station would be

monitored over longer periods of time. The study may include online data collection which

could commence in the field by comparing the operation and refractive indices measured of

similar equipment. Since, to our knowledge, refractive index sensors have not been used in the

field for the purpose of insulating oil monitoring, there is only limited data revealing the

refractive index changes that would be expected. The refractive indices of oils taken from

transformers with known histories might also be measured. These measurements could provide

some initial data that would give an estimation of approximate changes that could be expected.

As more data is recorded and examined trends may become more apparent. This type of

approach might also be carried out in a lab using controlled conditions as well.

In order to monitor the level of polar compounds, the integrated “lab-on-a-chip”

approach should be explored. Automated “methanol extraction” of the polar compounds may be

performed using a MEMS type device. Sensors which provide high resolution at the refractive

index values of typical solvents such as methanol are, therefore, necessary. A member of our lab

has begun to investigate the shifting of the high resolution range of our D-fiber sensor by

depositing sol-gels onto the surface of the flat side of the cladding. We expect that by varying

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the sol-gel material, a process can be employed to create sensors with high resolution regions

tuned to a specific refractive index value. Others have afready begun to design integrated optic

versions of the high resolution sensor as well. These sensors with tuned regions of high

resolution may also prove to be useful for various applications other than the integrated “lab-on

a-chip” or the monitoring of insulation oils.

Finally, it may be worthwhile to explore the possibility of using a similar material and so!

gel process to that used in [39] for measuring refractive index change due to the presence of

furans. If a similar coating were deposited on the surface of our sensor, it might be possible to

create a high resolution furan sensor that could be used directly in the insulating oils.

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