using refractive index to monitor oil quality in high voltage transformers by ryan john kisch b
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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.
104
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).
105
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
106
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
107
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.
108
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