Analysis of transformer oil degradation

Received: 24 May 2016
Revised: 8 December 2016
Accepted: 23 January 2017
DOI 10.1002/etep.2346
RESEARCH ARTICLE
Analysis of transformer oil degradation due to thermal stress
using optical spectroscopic techniques
Hussain Kalathripi | Subrata Karmakar
Department of Electrical Engineering,
National Institute of Technology, Rourkela,
India
Correspondence
Subrata Karmakar, Department of Electrical
Engineering, National Institute of
Technology, Rourkela‐769008, India.
Email: [email protected]
Summary
The power transformers are continuously under the impact of electrical and thermal
stresses. These stresses are primarily responsible for the occurring incipient faults
such as partial discharge, arcing, and pyrolysis. The incipient faults, if not taken care
at the earliest, cause the insulating transformer oil to degrade and transformer failure
over a period of time. Therefore, monitoring and diagnosing the power transformer
have become an inevitable task for its effective functioning. In this proposed work,
thermal analysis on different transformer oil samples has been performed by using
optical methods such as ultraviolet‐visible spectroscopy, Fourier transform infrared
spectroscopy and Nuclear magnetic resonance (NMR) spectroscopy. The obtained
results with UV‐visible spectroscopy method exhibit proportional degradation of
the oil samples with temperature rise. The Fourier transform infrared method identifies the dissolved gases (ie, CH4, C2H6) released during the decomposition of
hydro carbon present in the transformer oil. Finally, NMR spectroscopy method also
confirmed that it has the potential to monitor the decomposed oil by investigating
the region under an NMR signal which is proportional to the number of absorbing
protons. The employed photo‐spectroscopic methods can be best alternative next
to so called dissolved gas analysis method.
K EY WO R D S
FTIR, NMR, power transformer, thermal stress, transformer oil, UV‐visible spectroscopy
1 | INTRODUCTION
In power system network, various costly equipment are used
for reliable power supply to the utility. Among all, the power
transformers are the key apparatus in the network of power
generation, transmission, and distribution. Any unattended
fault in the transformer disturbs the entire power system network causing huge revenue loss along with supply interruption to the consumers.1 Though the transformer is
occasionally affected by external faults, it is always prone to
incipient faults inside the tank. The major incipient faults that
arise usually are sparking, partial discharge, arcing, and
pyrolysis.2 In fact, transformers are always subject to electrical stress, thermal stress, and mechanical stress.3,4 These
Int Trans Electr Energ Syst. 2017;e2346.
https://doi.org/10.1002/etep.2346
stresses cause the transformer oil to decompose which eventually leads to the formation of hydrogen (H2), methane
(CH4), ethane (C2H6), ethylene (C2H4), acetylene (C2H2)
gases and carbon monoxide (CO), and carbon dioxide
(CO2), if cellulose insulation is also involve.5 These gases
are indicative of the presence of incipient faults. The hydrogen (H2), ethane (CH6), and methane (CH4) are indicatives
of low temperature effect in the transformer, whereas, H2
and C2H4 indicate high temperature that is more dangerous
to the equipment functioning.6 Therefore, transformer has to
be scrutinized constantly rather than periodically.7
Generally, gas analysis in the degraded transformer oil is
done with so‐called dissolved gas analysis (DGA) method. It
is a proven reliable diagnostic technique for detection of
wileyonlinelibrary.com/journal/etep
Copyright © 2017 John Wiley & Sons, Ltd.
1 of 11
2 of 11
incipient faults in the oil‐filled high‐voltage transformers.8
The DGA investigative methods like the established IEC
and IEEE standard methods,2,9 are theoretically based on
Halstead simplified thermodynamic and compositional representations for the thermal decomposition of transformer oil
and on experimental data.10 Though DGA has been widely
accepted method for the past few decades, it has certain drawbacks like it necessities carrier gas, regular calibration, and
lack of expert personnel.11 To overcome these shortcomings
with DGA, in this work, optical spectroscopy methods such
as ultraviolet‐visible (UV‐Visible) spectrometer and Fourier
transform infrared (FTIR) spectroscopy and Nuclear magnetic resonance (NMR) techniques have been proposed and
implemented.12–14 The test has been conducted on different
transformer oil samples, which have undergone thermal
stress, using these methods. The UV‐visible spectroscopy
results indicated the expected degradation level in every sample, whereas, with FTIR spectroscopy, various functional
groups existed in the degraded oil are identified. In NMR
method, the picture of the hydro‐carbon structure in the
degraded oil samples is identified. Along with spectroscopy
techniques, the refractive index measurement (RIM) and the
breakdown voltage (BDV) tests have also been carried out
so as to investigate the physical and the electrical properties
of the given oil samples. The obtained results supported the
spectroscopic method results as anticipated. This work discovered that there are so many advantages with spectroscopic
methods. Mainly, the results obtained with these techniques
are so quick without disturbing the sample. Furthermore,
these methods are proved to have great optical throughput
and effeciency. Therefore, this work concludes that optical
methods can be best alternative besides the well‐known
DGA method for diagnosing the health of the transformer.
The novelties of the proposed work are as follows:
• Ultraviolet‐visible spectroscopy has the potential to identify the age of the thermally affected‐degraded oil samples by measuring their concentrations in terms of
peaks arose in the spectra at different wavelengths.
• Fourier transform infrared spectroscopy is a capable technique to identify the different functional groups present in
the degraded oil samples thereby detecting the dissolved
gases developed due to the applied thermal stress.
• Nuclear magnetic resonance spectroscopy provides the
picture of the hydro‐carbon structure in degraded oil samples thus determining the physical and chemical information, as it concentrates at the nuclei and nuclear spins in
the molecules.
• Along with spectroscopy methods, the physical and the
electrical properties of the oil samples have been
inspected, ie, refractive index and the BDV tests which
further shows the significant evidence of spectroscopic
results.
KALATHRIPI AND KARMAKAR
The organisation of this paper is as follows: Section 2
describes the details of the transformer oil sample preparation, and Section 3 describes the different spectroscopy techniques used in this work along with the experimental setups.
In Section 4, the obtained results from transformer oil samples are discussed and analysed. Finally, Section 5 concludes
the proposed work.
2 | P R E PA R ATI O N O F OI L SA M P L E S
The laboratory‐accelerated aging has been carried out on 3
different transformer oil samples, namely, fresh transformer
oil (T‐1), transformer oil mixed with copper (T‐2), and transformer oil mixed with paper (T‐3). The first sample, T‐1, has
been taken from a sealed drum full of fresh transformer oil
that is uncontaminated and kept from oxidizing effect. The
second sample, T‐2, has been prepared by mixing 30gm of
copper pieces with the 250ml of fresh transformer oil in a
conical flask made of glass and heated at 120°C temperature
in different time durations. The small copper pieces are taken
out from the copper bar using a sharp cutting tool. The purity
of the copper material present in the copper bar is 99.5 %.
The third sample, T‐3, has been prepared by mixing the fresh
transformer oil with 2.5gm of insulating Kraft paper. The
kraft paper pieces are dried to avoid moisture content and
kept into the conical flask and genteelly added the 250 ml
of fresh transformer oil into it. The conical flasks are thoroughly washed with clean water and finally dried in an oven
to avoid the contamination due to traces of humidity.
Before putting the sample in the heating chamber, the 3
samples are kept separately in 3 different conical flasks and
sealed with aluminium leafs to keep them uncontaminated
from air or duct particles. The main purpose of this work is
to analyse the transformer oil degraded due to accelerated
thermal stress effect. All the samples are aged at 3 different
time durations like 24 hrs, 48 hrs, and 96 hrs at 120°C in a
heat chamber as shown in Figure 1.
The reason for choosing 120°C is, at this stage effect of
oil physicochemical property change is clearly evident as a
transformer winding normal temperature is at 65°C. Table 1
shows the details about the transformer oil samples prepared
for optical spectro photometric test. The photograph of the
prepared transformer oil samples is shown in Figure 2 for further test.
3 | SPECTROMETRIC TECHNIQUES
AND EXPERIMENTAL SETUP
Nowadays, the spectro‐photometric techniques have become
popular for diagnosis of transformer health condition monitoring. In the practice, the oil samples are collected from
the service transformer and tested in the spectro‐photometric
KALATHRIPI AND KARMAKAR
FIGURE 1
3 of 11
Heat chamber used for the preparation of transformer oil
samples
TABLE 1 Details of the samples and their corresponding codes
S. No.
Sample
name
Details of
sample
Heating
duration (h)
Temperature
( °C)
1
T‐1
FTO
24, 48, 96
120
2
T‐2
FTO with Cu
24, 48, 96
120
3
T‐3
FTO with paper
24, 48, 96
120
Abbreviation: FTO, Fresh transformer oil.
laboratory. To carry out the experiments, the transformer oil
samples have been prepared with accelerated aging process
in the laboratory to avoid the actual aging time and have been
tested using UV‐visible, FTIR, and NMR spectrometers. The
concept of each spectroscopic measurement technique and
their individual experimental setup is explained as below.
3.1 | UV‐visible spectroscopy
The UV‐visible spectrometer of Agilent Technologies
(Model: CARY 100) has been used to carry out the experiment on the oil samples as shown in Figure 3A and in the
inset in the same figure the photo of the UV‐visible
spectrometer is given. The spectrometer has broad wavelength spectrum range of 190 to 900 nm consisting of a UV
range 190 to 380 nm and a visible spectrum range of 280 to
900 nm. During the experiment, 2 quartz cuvette of 10 mm
path length is used. The first one is used for filling up with
sample oil and the second one is used for reference. All the
3 samples have been tested one after the other by filling
3 ml quantity of oil in the sample cuvette.
The schematic diagram shown in Figure 3A clearly
depicts the concept of UV‐spectrometer. The meter first measures the intensity of the light propagated through the sample
cell (I) which is coming from UV source and then compares
the same to the light before propagated through the sample
cell (Io). The ratio, I/Io, is generally defined as transmittance.
As per Beer‐Lambert law, the absorbance of light by the sample is deduced from the transmittance, as given in Equation 1,
which is also proportional to the path length, concentration,
and absorptivity of the given sample as follows:15,16
A ¼ ϵ×c×l ¼ − logðT Þ
(1)
where A refers to absorbance, T refers to transmittance, ϵ
refers to molar absorptivity, c refers to the concentration of
the sample, and l refers to the length of the light path, which
is equal to the width of the cuvette. The same absorbance, A,
is recorded on the detector after the transmitted light passed
through the mirror and rotating disc comparing with the
reference.
3.2 | FTIR spectroscopy
Subsequently, same samples have been tested by using Fourier transform infrared (FTIR) spectrometer (Model:
ALPHA, Germany, Bruker GmbH make) as shown in
Figure 3B and in the inset in the same figure the photo of
the FTIR spectrometer is given. It has wavenumber range of
4000 to 400 cm‐1, signal to noise ratio of the instrument is
50 000:1, and resolution of 4 cm‐1.17 An amount of 0.2 ml
of oil sample has been used to obtain the FTIR spectrum
which appears on the computer connected to the
spectrometer.
FIGURE 2 Different oil samples used for spectroscopy experimentation (A) Heated for 24 hrs. at 120 °C (B) Heated for 48 hrs. at 120 °C
(C) Heated for 96 hrs at 120 °C
KALATHRIPI AND KARMAKAR
4 of 11
FIGURE 3 (A) Ultraviolet‐visible spectrometer used for experimenting T‐1, T‐2, and T‐3 oil samples and its schematic diagram. (B) Fourier
transform infrared spectrometer used for experimenting T‐1, T‐2, and T‐3 oil samples and its schematic diagram
The FTIR spectroscopy converts raw data into the actual
spectrum. It is a nondestructive, simple, and fast‐analyzing
method18 used to acquire an infrared spectrum of absorption
of a liquid, solid, and gas by collecting spectral data in a
widespread spectral range. When IR radiation is disseminated
through a collected sample, some of it is absorbed by the
sample which means the energy of the light imposing on a
molecule is equal to vibrational energy level difference within
a molecule and the rest is transmitted, creating a molecular
fingerprint of the sample.19 The vibrational energy difference
in the molecule is defined as follows:
one as shown in Figure 3B. As the mirror moves at a fixed
rate, its position is determined by counting the interference
fringes of a collocated He‐Ne gas laser. The interferometer
actually divides a beam of IR radiation coming from IR
source into 2 paths of different wavelengths using a beam
splitter and afterwards recombines them. Finally, a detector
detects the intensity of alterations of the exit beam as a function of the path difference.
Δ Evib ¼ hcw
Further, all the samples have been tested using NMR spectrometer shown in Figure 4 to know the quality of the oil that
underwent thermal stress. In Figure 4 the schematic diagram
and inset photograph of NMR (Model No: AV 400 Avance‐
III, 400 MHz, FT‐NMR Spectrometer Bruker biospin International, Switzerland) experimental setup is shown. The
major key features used for diagnosis of transformer oil
(2)
where, Evib refers to vibrational energy, h is the plank's constant (Joule‐sec), c is the speed of light (cm/sec), and w is
wavenumber in cm‐1.
The heart of FTIR spectroscopy is an interferometer. It
has 2 mirrors: one is a fixed one and the other is a movable
FIGURE 4
3.3 | NMR spectroscopy
Nuclear magnetic resonance spectrometer used for experimenting T‐1, T‐2, and T‐3 oil samples and its schematic diagram
KALATHRIPI AND KARMAKAR
associated with NMR are (1) 5 mm BBO and BBFO probe
for multinuclear NMR (11B, 15 N, 19F, 29Si, 31P, 35Cl,
51 V etc.), (2) 5 mm multinuclear probe for solution studies,
and (3) variable temperature facility from −80°C to 70°C
with suitable solvent.
The NMR test primarily concerns on the nuclear spin
states within the molecule. The NMR experiments are performed to explore and analyse the chemical composition of
the sample that helps to create relationship or correlation with
sample aging for its characterization and quantification.20
The schematic diagram of NMR spectrometer as shown in
Figure 4 has 2 major components, ie, a magnet and a radio
frequency transmitter. This spectrometer is of classical continuous wave type because it uses technique similar to that
of optical spectrometer. The instrument is described by the
approximate resonance frequency of the nucleus to be analyzed, eg, 1H NMR. The functioning could be a slow scan
of radio frequency at a constant magnetic field strength or
magnetic field strength at fixed radio frequency over a purview corresponding to the resonance of the nuclei under
study. In the process, absorption of energy by the sample generates as a signal which is detected, amplified, and recorded
as an NMR spectrum.
4 | RESULTS A ND DISCUSSION
All the aforesaid oil samples have been tested with a UV‐
Visible spectrometer, FTIR spectrometer, and NMR
technique, and their results are presented. The transformer
oil test sample (T‐1) has been aged with 24 hrs, 48 hrs, and
96 hrs at a constant temperature of 120°C and compared with
new fresh transformer oil kept at normal temperature and pressure (NTP). The obtained results using UV‐visible spectroscopy of T‐1sample are plotted and discussed here which is
shown in Figure 5. In Figure 5, the absorption peaks that have
been correlated with the bonds present in the molecules are
found in the UV‐visible range of 350 to 450 nm. It is observed
that with the applied thermal stress, the nature of the oil sample
and its PH values are affected leading to the formation of interfering substances. The peaks of the different aged transformer
oil samples are observed with the aging time at elevated temperature as compared to fresh transformer oil, which does
not have any absorption peaks. This clear change in absorbance level obeyed the Beer‐Lambert law. The absorbance of
the light by the sample increases as the concentration of the
oil increases with the applied temperature proportionally.
To observe the thermal effects of transformer oil with
copper winding placed inside the transformer tank, the
150ml of fresh transformer oil is mixed with 30gm of copper
pieces and heated with different time durations. The second
transformer oil samples (T‐2) are aged with different time
durations of 24 hrs, 48 hrs, and 96 hrs along with the mixture
5 of 11
FIGURE 5
Ultraviolet‐visible spectroscopy results obtained for fresh
transformer oil (T‐1) for 24, 48, and 96 hours at 120°C
with copper pieces at 120°C constant temperature. The accelerated thermal aging process significantly changes the physical properties as the transformer oil is more sensitive to the
temperature, which is shown in Figure 6. The colour of the
transformer oil is much dark brown at the higher duration
of temperature as compared to the other samples. The
obtained results of T‐2 samples and the fresh transformer
oil is compared, which is shown in Figure 6. The absorption
peaks found because of thermally‐aged transformer oil with
the comparison of fresh transformer oil kept at NTP is proportional to the increment in duration of temperature.
The third transformer oil sample (T‐3) sample also has
been examined with the UV‐visible spectrophotometer, and
the obtained results are as shown in Figure 7. It is observed
that absorbance has increased with increase of heating period
FIGURE 6 Ultraviolet‐visible spectroscopy results obtained for
transformer oil with Cu (T‐2) for 24, 48, and 96 hrs at 120°C
KALATHRIPI AND KARMAKAR
6 of 11
FIGURE 7 Ultraviolet‐visible spectroscopy results obtained for
transformer oil with paper (T‐3) for 24, 48, and 96 hours at 120°C
which indicates that the degree of deterioration is raised up
and curves obviously shifted upward with the aging time
increased as compared to fresh transformer oil. The absorption spectra of transformer oil mixed with insulating paper
used in transformer winding expose formation of impurities
presence in the transformer oil at different time durations of
heating.
Finally, the T‐1, T‐2, and T‐3 oil samples have been compared on the basis of absorption peaks. The Table 2 shows the
maximum absorption values of all the transformer oil samples T‐1, T‐2, and T‐3 with UV‐visible spectroscopy. It is
found that in all the samples, there is clear peak difference
from sample to sample. The transformer oil samples heated
for 96 hours have higher absorbance peaks compared to
48 hours and 24 hours heated oil samples, respectively. The
absorption peaks of 48 hours transformer oil samples lie in
between 24 and 96 hours of aged oil samples. This way these
results give the qualitative analysis of the oil samples.
The colour of the transformer oil is changed from pale
yellow to brownish in 3 different samples because of different
temperature durations at 120°C as shown in Figure 2. The
deformation of colour with respect to fresh transformer oil
is basically due to the oxidization of the sample oils, which
subsequently results in the formation of the acidic products,
TABLE 2 The comparative results of T‐1, T‐2, and T‐3 oil samples
with ultraviolet‐visible spectroscopy
Absorption peak (max)
Sample
24h
48h
96h
T‐1
361
388
400
T‐2
365
383
391
T‐3
357
365
394
but the difference lies in the type of the sample and number
of hours of heating. Though all the samples seem to be
brownish, fresh transformer oil with Cu looks dark brown
compared to fresh oil sample light brown. This is due to the
increase in the decay products as a result of the thermal aging
of the material inside the sample. The UV‐visible spectro‐
photometry characterizes the relative level of dissolved decay
products such as aldehydes, peroxides, esters, ketones, and
acids in transformer insulating oils.21 Overall, the clear absorbance difference is observed in all the samples and proved
that UV‐visible spectrometry technique is an excellent tool
to diagnose the health of the transformers such that the fault
preventive measures can be taken thereafter.
Moreover, the 3 samples (T‐1, T‐2 and T‐3) have been
tested with FTIR spectroscopy techniques, and the obtained
results are shown in Figure 8, Figure 9 and Figure 10.
Figure 8A shows the FTIR results for fresh transformer oil
heated for 24 hrs at a constant temperature of 120°C. The
absorption peaks are found at 728, 1374, 1456, 2363, 2854,
2918, and 3742 wavenumbers. The characteristic absorptivity
between the wavenumbers1470 cm‐1and 1350 cm‐1, 2 peaks
are observed ie, 1456 and 1374, which indicate the functional
group of alkane C─H bond stretch of CH3 bond. The peaks
found between 860 and 680 are aromatic C─H bending functional groups. It is also observed that between 1500 and
400 cm‐1 wavenumbers, elucidation of peaks in the finger
print region is little intricate as number of different vibrations
befall here including a wide variety of bending vibrations. To
show the clear variation of absorption peaks in the sample
after heating, a portion of the plot having wavenumbers from
2200 to 2500 cm‐1 is shown in Figure 8B.
Figure 9A shows the results obtained for T‐1, T‐2, and T‐
3 samples, which are heated at a constant temperature of
120°C for 48 hours. In this case, the peaks are also observed
at 728, 1374, 1456, 2363, 2854, 2918, and 3742
wavenumbers. There is a clear peak popping up at 3740
wavenumber where water molecules are observed which is
the result of applied thermal stress. The same functional
groups like CH, CH2, and CH3 that are found at different
wavenumbers led to the formation of gases ie, CH4, C2H6,
and C2H2 which are indicative of low temperature effect in
the transformer oil. Figure 9Bclearly shows the more significant degradation of the transformer oil samples as the more
temperature is applied in this case.
Figure 10A shows the results for T‐3 oil sample with
FTIR spectroscopy, which has the major peaks at 728,
1374, 1456, 2363, 2854, 2918, and 3742 wavenumbers. It
is observed that though characteristic peaks for T‐1, T‐2,
and T‐3 seem to be same, there is transmittance difference
among them and T‐3 highlights with some intense peaks
which are the result of high thermal stress due to increased
duration of heating. In fact, all the FTIR plots are exhibiting
same functional groups because peaks observed in this case
KALATHRIPI AND KARMAKAR
7 of 11
FIGURE 8
Fourier transform infrared (FTIR) spectra for 24 hours. (A) FTIR comparative results obtained for transformer oil samples T‐1, T‐2, and
T‐3 at 120°C, 24 hrs. (B) part of FTIR spectrum showing clear indication of sample disruption with temperature
FIGURE 9 Fourier transform infrared (FTIR) spectra for 48 hrs. (A) FTIR comparative results obtained for transformer oil samples T‐1, T‐2 and T‐3
at 120°C, 48 hrs. (B) Part of FTIR spectrum showing clear indication of sample disruption with temperature
FIGURE 10 Fourier transform infrared (FTIR) spectra for 96 hrs. (A) FTIR comparative obtained for transformer oil samples T‐1, T‐2, and T‐3 at
120°C, 96 hrs. (B) Part of FTIR spectrum showing clear indication of sample disruption with temperature
are almost at the same wavenumbers. With the data
acknowledged from Figure 10A, it is known that various
gases and moisture particles are dissolved and identified
such as CH4, C2H6, C2H4, and H2O, which are the result
of thermal stress in the transformer.22 Figure 10B shows
the clear variation in the property change of the sample
oil with the increment of temperature which informs more
degradation has taken place.
Therefore, FTIR spectroscopy is a good analyzer of the
transformer oils samples to know the health of the transformer from time to time. This diagnosis technique is more
useful especially for the high voltage transformers which
are continuously under the thermal stress from the time of
their installation.
Table 3 depicts all the transmittance peaks observed in
the FTIR spectra of all the oil samples (T‐1, T‐2, and T‐3)
KALATHRIPI AND KARMAKAR
8 of 11
TABLE 3 Transmittance peaks of Fourier transform infrared spectra of the different oil samples
Transmittance peaks of oil samples
Wavenumber (cm )
Heating period (h) at 120°C
T‐1
T‐2
T‐3
728
24
48
96
0.95452
0.95313
0.95662
0.95409
0.95425
0.95611
0.95504
0.95436
0.95492
1374
24
48
96
0.91388
0.91312
0.91188
0.91542
0.91447
0.91257
0.91621
0.91323
0.91106
1456
24
48
96
0.80521
0.80322
0.80178
0.80644
0.80415
0.80239
0.80794
0.80395
0.80173
2363
24
48
96
0.99284
0.99042
0.97708
0.99344
0.98937
0.97844
0.99546
0.98625
0.98069
2854
24
48
96
0.674
0.67393
0.67735
0.674
0.6739
0.67608
0.67424
0.67368
0.67689
2918
24
48
96
0.53882
0.539
0.54288
0.53888
0.53895
0.54119
0.5392
0.53851
0.54248
3742
24
48
96
0.99185
0.98728
0.98025
0.99387
0.98882
0.98165
0.9972
0.99012
0.9827
‐1
at different wavenumbers. The careful investigation into all
the peak values of spectrum reveals that there is a transmittance difference between the samples. This is because all
the samples T‐1, T‐2, and T‐3 are different in nature by the
way they are prepared. Because of the addition of copper
and paper in T‐2 and T‐3, they tend to release the more decay
products and make the sample highly concentrated. Because
all the samples have undergone temperature effect, the properties of the transformer oil samples change in terms of generating the free radicals of the chemical bonds and their
recombination to form gases. For this reason, in Table 3,
the variation in transmittance levels is observed at different
wavenumbers. The change in the transmittance peak means
the change of the by‐products (gas, moisture etc.) in the sample oils as indicated in Figures 8A, 9A, and 10A. The
glimpse of transmittance difference is shown in figures 8B,
9B, and 10B at 2363 wavenumber.
Nuclear magnetic resonance spectroscopy also has been
carried out on all the oil samples (T‐1, T‐2, and T‐3). The
CDCl3 has been used as the solvent in the sample transformer
oils. For every 20 to 22 gm of oil sample, 0.4 ml of CDCl3 is
used. The prepared oil samples have been processed through
NMR spectrometer for 1H spectra which gave the replica of
what exactly the samples have gone through after applied
thermal stress. The spectra clearly exhibit variation in the
property change in the oil samples as shown in the
Figure 11. The figure consists T‐1, T‐2, and T‐3 sample oils
heated for 48 hours at constant temperature of 120°C. The
NMR for the 48 hrs heating period at 120°C is chosen to
show how NMR can be a useful technique to investigate
the deteriorated oil samples. Indeed, the results show that
the vitality of this method for degraded oil analysis.23
The graph of all the samples T‐1, T‐2, and T‐3 for
48 hours heating period which is put on 0.5 ppm to
2.0 ppm as shown in Figure 11, represent free radicals
CH2 and CH3 molecular groups which eventually recombine and lead to the formation of gases like C2H4 and
C2H6, which are basically results of overheating of oil.
These are found on the up field side. Between 0.5 to
1.9 ppm, more strong lines are acknowledged and between
1.9 and 3 ppm, signals which authorize the formation of
alkoxyl groups are identified owing to transformer oil
aging due to heat treatment given to the samples. Finally,
between 6.5 and 7.5 ppm, the lines confirm the aromatic
groups, which are generally indicative of the result of
the process of the degradation of the oil.23 Though all
the graphs seem to be same, there is significant variation
based on the type of the sample oil. The careful investigation reveals that there is more degradation in the oil sample mixed with copper, ie, T‐3 followed by T‐2 and T‐1.
The reason is there are more decay products in T‐3, which
is degraded because of the applied thermal stress.
KALATHRIPI AND KARMAKAR
FIGURE 11
9 of 11
Nuclear magnetic resonance spectra of different oil samples for 48 hrs at 120°C (A) T‐1 sample, (B) T‐2 sample, and (C) T‐3 sample
Further, all the transformer oil samples underwent RIM
techniques for verifying its physical properties due to the
effect of the different thermal aging process. The refractive
index (RI) is generally determined as follows:
η ¼ C=V;
(3)
where c refers to the speed of light through vacuum and V
refers to phase velocity through the medium considered.
The dielectric value of the transformer oil sample is also
defined by its relative permittivity. Square of RI actually
denotes relative permittivity of a medium. This information
gives the knowledge about the turbidity of the liquid
KALATHRIPI AND KARMAKAR
10 of 11
medium.24,25 Table 4 shows the RI of the samples considered
in this work. It is observed that all the RI value is increased
with the increased duration of the thermal aging process.
For example, when T‐1 is heated for 24 hours at 120°C, its
RI is 1.7885 and when it is heated for 96 hours at 120°C its
RI is 1.8149 and same is the case with T‐2 and T‐3. This
shows that there is difference in the physical property change
in the oil from 24 hrs to 96 hrs heat treatment.
Close observation of the results also indicates that RI of
the T‐3 is higher for all the heating periods indicating less
propagation of light through it which implies that it is more
degraded because of thermal stress and moisture as they
directly affect the dielectric property of the transformer oil.
In addition to spectroscopy techniques and RIM, BDV
test has also been performed to know the electrical properties
of the prepared oil samples. The BDV test is the one of the most
important transformer oil diagnostic tests performed to know
how much electrical stress it can withstand.26,27 All the samples used in this work have been passed through BDV test.
The BDV test kit has a gap of 2.5 mm between its sphere‐
shaped electrodes of 25 mm diameter as per IEC standard
60156. During the test, the voltage has been increased gradually at the rate of 2 kV/s. The Table 5 depicts the BDV results
of T‐1, T‐2, and T‐3 oil samples. For each measurement of
BDV, averages of 3 sample BDV results are recorded. The
T‐1 oil sample has recorded higher BDV of 36 kV because
it is fresh transformer oil without any added material to it.
As the period of temperature is increased to 48 and 96 hours
at a constant temperature of 120°C, the BDV decreased to 32
and 30, respectively, which again assures the effect of constant thermal stress on transformer oil sample. The results of
T‐2 and T‐3 also reveal that as the oil temperature is
increased their BDV is reduced which is according to the previous results. Overall, the RI and BDV test results of the all
TABLE 4 Refractive index of different oil samples at different
heating periods
Sample name
RI‐24h at
120°C
RI‐48h at
120°C
RI‐96h at
120°C
1
T‐1
1.7885
1.8018
1.8149
2
T‐2
1.7851
1.7867
1.8067
3
T‐3
1.7930
1.8063
1.8248
Sl. No
TABLE 5 Breakdown voltage of different oil samples at different
heating periods
Sl. No
Sample Avg. BDV‐24h Avg. BDV‐48h Avg. BDV‐96h
name
at 120°C
at 120°C
at 120°C
1
T‐1
36.00
32.00
30.00
2
T‐2
33.16
30.12
27.62
3
T‐3
42.50
36.16
35.75
the samples considered in this work to support the spectroscopic results obtained by using UV, FTIR, and NMR
techniques.
5 | C O NCLUS IO N S
Though DGA technique has been most used method to
diagnose the health of the transformer for decades, it has
certain drawbacks such as the need of carrier gas and regular calibration of the instrument. To overcome these drawbacks, the work has been focused on the alternate
techniques like UV‐visible, FTIR and NMR spectroscopy.
All the aforementioned 3 samples, namely, fresh transformer
oil, transformer oil with Cu, and transformer oil with insulating paper measured with these methods gave vital results
to identify the presence of the thermal fault. The obtained
results clearly established that as the heating period is
increased, the degradation of the oil is also increased. The
UV‐visible spectroscopy provided the qualitative information about the degraded oil samples. The FTIR technique
has given the information of different functional groups
exists in the sample molecules and also the gases released
during the process of thermal aging. Further, NMR spectroscopic technique results also helped to know the quality of
the sample oils considered in this work. In addition to spectroscopy techniques, RIM and BDV test results also provided the condition of the sample transformer oils which
supported all the spectroscopic results in this study. Therefore, as these proposed spectroscopy techniques have great
optical throughput and do not cause any harm to the measuring samples, they can be best alternative next to well‐
known DGA method.
Further, in future, the on‐line condition monitoring with
these proposed techniques of different oil filled high voltage
power equipment is planned to improve the faster testing process and with better test results.
REF ER ENCES
1. Ma H, Saha TK, Ekanayake C, Martin D. Smart transformer for
smart grid‐intelligent framework and techniques for power transformer asset management. IEEE Trans. Smart Grid.
2015;6(2):1026‐1034.
2. IEEE Std. C57.104. IEEE guide for the interpretation of gases generated in oil‐immersed transformers. 2008.
3. Allahbakhshi M, Akbari A. An improved computational approach
for thermal modelling of power transformers. Int. Trans. Electr.
Energy Syst. 2015;25(7):1319‐1332.
4. Cui Y, Ma H, Saha T. Pattern recognition techniques for power
transformer insulation diagnosis—A comparative study part 1:
Framework, literature, and illustration. Int. Trans. Electr. Energy
Syst. 2015;25(10):2247‐2259.
KALATHRIPI AND KARMAKAR
11 of 11
5. Yun Y, Chen W, Wang Y, Pan C. Photoacoustic detection of dissolved gases in transformer oil. Eur. Trans. Electr. Power.
2008;18(6):562‐576.
17. Brochure of FTIR spectrometer (ALPHA ATR FTIR) online
available: www.bionet.nsc.ru/files/2013/news/ALPHA_Specifications.pdf.
6. Moulai H, Nacer A, Beroual A. Dissolved gases analysis in relation
to the energy of electrical discharges in mineral oil. IEEE Trans.
Dielectr. Electr. Insul. 2012;19(2):498‐504.
18. Fofana I, Bouaïcha A, Farzaneh M. Characterization of aging transformer oil–pressboard insulation using some modern diagnostic
techniques. Eur. Trans. Electr. Power. 2011;21(1):1110‐1127.
7. Duval M. Dissolved gas analysis: It can save your transformer. IEEE
Electr. Insul. Mag. 1989;5(6):22‐27.
19. Liu X‐y, Zhou F‐j, Huang F‐l. Research on on‐line DGA using FTIR
[power transformer insulation testing]. Int. Conf. Power Syst.
Technol. Proc. 2002;3:1875‐1880.
8. Qian Z, Gao WS, Wang F, Yan ZA. A case‐based reasoning
approach to power transformer fault diagnosis using dissolved gas
analysis data. Eur. T. Electr. Power. 2009;19(3):518‐530.
20. Bakar N, Abu‐Siada A, Islam S. A review of dissolved gas analysis
measurement and interpretation techniques. IEEE Electr. Insul.
Mag. 2014;3(30):39‐49.
9. IEC 60599. Mineral oil‐impregnated electrical equipment in service
—Guide to the interpretation of dissolved and free gases analysis.
1999.
21. Kassi KS, Fofana I, Meghnefi F, Yéo Z. Impact of local overheating
on conventional and hybrid insulations for power transformers.
IEEE Trans. Dielectr. Electr. Insul. 2015;22(5):2543‐2553.
10. Yang M‐T, Li‐Siang H. Intelligent fault types diagnostic system for
dissolved gas analysis of oil‐immersed power transformer. IEEE
Trans. Dielectr. Electr. Insul. 2013;20(6):2317‐2324.
22. Karthik R. Sree Renga Raja T. Investigations of transformer oil characteristics. IEEJ Trans. Electr. Electron. Eng. 2012;7(4):369‐374.
11. Cruz V, Costa A, Paredes M. Development and evaluation of a new
DGA diagnostic method based on thermodynamics fundamentals.
IEEE Trans. Dielectr. Electr. Insul. 2015;22(2):888‐894.
12. Ma H, Saha TK, Ekanayake C, Martin D. Smart transformer for
smart grid—Intelligent framework and techniques for power transformer asset management. IEEE Trans. Smart Grid.
2015;6(2):1026‐1034.
13. Misra P, Dubinskii MA. Ultraviolet spectroscopy and UV lasers.
Marcel Dekker Inc: New York, 2002.
14. Hussain K, Karmakar S. Condition assessment of transformer oil
using UV‐visible spectroscopy. IEEE Eighteenth National Power
Systems Conference (NPSC), Guwahati, India, December 2014; 1‐5.
15. Gafiyatullina LG, Turanovaa OA, Kozlov VK, Turanova AN. UV
spectroscopy of GK transformer oil. Opt. Spectrosc.
2010;109(1):97‐100.
16. Karmakar S, Roy NK. Pathik Kumbhakar. Effect of ageing in transformer oil using UV‐visible spectrophotometric technique. J. Opt.
2011;40(2):33‐38.
23. Turanova OA, Sharipova AR, Sukhanov AA, Gnezdilov OI,
KozlovV K, Turanov AN. A study of the GK transformer oil using
the EPR and NMR methods. Pet. Chem. 2010;50(6):472‐475.
24. Laskar S, Bordoloi S. Monitoring of moisture in transformer oil
using optical fiber as sensor. J. Phon. 2013;2013:1‐7.
25. Banerjee A, Mukherjee S, Verma RK, Jana B, Khan TK,
Chakroborty M. Fiber optic sensing of liquid refractive index. Sensors Actuators B. 2007;123(1):594‐605.
26. IEC Publication 60156. Insulating liquids—Determination of the
breakdown voltage at power frequency. 1995;2:1‐21.
27. ASTM D1816. Standard test method for dielectric breakdown voltage of insulating oils of petroleum origin using VDE electrodes.
2004; 10.03: 1‐5.
How to cite this article: H Kalathripi, Karmakar S.
Analysis of transformer oil degradation due to thermal
stress using optical spectroscopic techniques. Int Trans
Electr Energ Syst. 2017;e2346. https://doi.org/
10.1002/etep.2346