Selim Koroglu Regular Paper A Case Study On Fault Detection in Power Transformers Using Dissolved Gas Analysis and Electrical Test Methods
Selim Koroglu Regular Paper A Case Study On Fault Detection in Power Transformers Using Dissolved Gas Analysis and Electrical Test Methods
Selim Koroglu Regular Paper A Case Study On Fault Detection in Power Transformers Using Dissolved Gas Analysis and Electrical Test Methods
Koroglu*
JES
Journal of
Electrical
Systems
This paper presents methodologies for power transformer fault diagnosis using dissolved gas
analysis and electrical test methods. These methods are widely used in determination of
inception faults of power transformers. Dissolved gas analysis test provides fault diagnosis of
power transformers. On the other hand the electrical test methods are used for detection of root
causes and fault locations and they provide more specific information about the faults. The aim
of this work is to study the faults that are measured and recorded in Turkish Electricity
Transmission Company (TEIAS) power systems. For this purpose, four specific cases are
considered and analyzed with dissolved gas analysis and electrical testing methods. Three of
these cases are defective situations and one case is a non-defective situation. These real cases
of measurements have been analyzed with both methods in detail. Assessment results showed
that a single method cannot yield accurate enough results in some specific fault conditions.
Therefore it was concluded that cooperation of both methods in the assessment of fault
condition gives more trustworthy results.
Keywords: Power transformer, Fault detection, Dissolved gas analysis, Electrical test methods.
Article history: Received 1 February 2016, Accepted 6 August 2016
1. Introduction
Power transformers are one of the most essential and expensive equipment in power
systems. Their faults cause significant losses and environmental risks such as power cuts,
explosions, loss of life and property. Economically viable operation of electric power
systems is closely related to reliability and availability of power transformers [1-2]. It is
very important to diagnose incipient faults and quickly remedy the situation at the event of
failures. Hence, the progression of the fault could be stopped, economic losses are reduced
and repair time is shortened.
The preventive maintenance program is very important to increase lifetime of
transformers and avoid abnormal conditions. For this purpose, Dissolved Gas Analysis
(DGA) and electric test methods can be applied to power transformers periodically or when
needed. The DGA is a widely used and worldwide-accepted diagnostic method for
detection of potential transformer internal faults. In oil-immersed power transformers,
incipient faults lead to breakdown of the insulating materials and as result of this fault some
gases will be released. The composition of these gases depends on the type and severity of
the fault [3-4]. If the amount of gases is known, it is possible to make correct interpretation
about power transformer faults such as partial discharge, arcing and overheating. So, power
transformer maintenance program could be modified by the knowledge of DGA. Another
important technique that is applied to power transformers is called routine electrical test
method. This method includes several techniques such as excitation current, power factor,
DC insulation, turns ratio, DC winding resistance and oil dielectric strength test, etc.
Electrical tests allow taking preventive actions before malfunction of power transformers. It
also provides determination of the location of a possible fault for required maintenance.
An overview is presented in[5] covering condition monitoring and condition
assessment, performing maintenance plans, aging, health, and end of life asset
managements of transformers. Evaluation of effects of preventive maintenance and failure
*
repair cost of power transformers are studied in [6]. Another relevant study is presented in
[7] that reviews existing monitoring and diagnostic methods for power transformers in
service. In this work, a case study on fault detection in power transformers with dissolved
gas analysis and electrical test methods are presented in detail. It is aimed to demonstrate
applications and performance evaluations of both methods on real case measurements and
to make assessment for considered specific conditions.
The structure of the paper is organized as follows: the introduction is given in Section 1,
the DGA is presented in Section 2 and Electrical Testing Methods are offered in Section 3.
Analysis of test results and assessment with both DGA and electrical testing methods are
given in Section 4. Discussions and comparison with physical fault are presented in Section
5. Finally, conclusion remarks are drawn in Section 6.
2. Dissolved gas analysis
DGA is applied by using the oil samples taken from an in-service power transformer for
condition monitoring of the transformer. Early warning information could be received
about existing or developing faults. Faults that are proceeding slowly and without
noticeable signs, especially in the initial stages, can be prevented, and thus potential
malfunction of transformer can be avoided.
In the evaluation of the DGA results, variety of determination methods have been
developed in literature that include key gas, Duval triangle, Roger ratio, Doernenburg ratio,
IEC ratio methods, logarithmic nomograph [8-12]. These methods classify faults using
reference tables and charts which are prepared according to amount or particular ratios of
gases. Sensitivity and accuracy of these methods are associated with the collected
knowledge since the tables and graphs are gathered from results of long years of
experiences [10]. Some gases are formed only as result of some particular faults.
Depending on the type and severity of the fault, formed gases vary in type and amount. If
the type and amount of gases are known, accurate comments can be made about the failure
and preventive precautions can be taken. It is well known that several conventional
methods can be used for evaluation of DGA results. From these techniques Duval triangle
and key gas methods generally have higher classification accuracy and consistency [13-14].
Therefore, these methods are studied for interpretation of DGA results of the power
transformers in this study.
2.1. Key gas method
In the key gas method, which is based on which gases are typical or dominant at various
temperatures, characteristic "key gases" are used for the detection of certain faults.
Table 1: Fault interpretation based on key gases [4, 15]
Detected key gas
Hydrogen (H2)
Ethylene (C2H4)
Acetylene (C2H2)
Oxygen (O2)
Ethane (C2H6)
Methane (CH4)
Carbon Monoxide (CO)
Carbon Dioxide (CO2)
Interpretation
Electrical partial discharge (corona effect)
Thermal fault (electrical contacts)
Electric fault (arc, spark)
Transformer seal fault
Secondary indicator of thermal fault
Secondary indicator of an arc or serious overheating
Cellulose decomposition
Cellulose decomposition
443
Percentage values of combustible gases are calculated when making assessments according
to this method. Probable fault consequence can be made based on excessive gas or gases [4,
15]. Detected key gases and their corresponding general failure causes are given in Table 1.
2.2. Duval triangle method
Duval triangle method is the graphical representational diagram. It uses only methane,
acetylene and ethylene concentrations (in ppm). There is a triangular diagram which is
divided into different areas as shown in Fig. 1. Definition of the point of intersection is
carried out according to the percentage values of the related gases in the coordinate system.
Percentage values of these gases are calculated according to equations given as:
%CH 4 =
100 x
x+ y+z
(1)
%C2 H 4 =
100 y
x+ y+z
(2)
%C2 H 2 =
100 z
x+ y+z
(3)
Here, x = [CH4], y = [C2H4], z = [C2H2] represent the ppm values of dissolved gases in
oil [6]. Fault types with this method are classified into six classes as partial discharge (PD),
low-energy discharge (D1), high energy discharge (D2), low temperature thermal fault
(T1), medium temperature thermal fault (T2) and high temperature thermal fault (T3) [810].
444
preventive actions before malfunction of power transformers. They also provide the
location of a possible fault for the required maintenance and repair. Thus the reason for the
fault of the transformer and where it occurred can be detected quickly. This section is going
to focus on the electrical testing aspect of maintenance and fault detection.
flows in any winding to excite the transformer in conditions of all other winding are open
circuited. It is generally expected to read similar currents for outer limbs of the power
transformer when the magnetizing current of the center limb is slightly lower. This test has
been an effective method for detecting the transformer faults, nevertheless, it should be
noted that the excitation current is much more sensitive and fragile method in some cases.
Hence, the test results should be confirmed with turn ratio and DC winding resistance tests.
Fig. 4. Principle connection diagram of the excitation current test for three-phase power
transformer
3.2. Power factor test
The measurement of power factor is one of the fundamental tests for assessing the
condition of the transformer insulation. It is also known as Tan Delta or Dissipation
Factor test. The purpose of this test is to determine the quality of the overall insulation of
power transformer such as windings, bushings and oil insulation [17-20]. Equivalent circuit
and vector diagrams are illustrated in Fig. 5 for power factor. The power factor (PF) is a
ratio of the resistive current component (IR) divided to total leakage current (I) under an
applied AC voltage, which is defined as;
IR
I
In other words, this equation can be stated as;
PF = cos =
PF =
(4)
(5)
The other definition is called dissipations factor (DF), which is the ratio of the resistive
current component divided to capacitive current (IC) and defined as below;
DF = tan =
IR
IC
(6)
446
insulation tends to have deteriorations and/or contamination because the dielectric losses
are largely caused by oxidation, carbonization, water, moisture, carbon, contamination in
bushings, windings and liquid insulation etc.
447
polarization of insulation system via polarized current. The test is applied to insulation
resistance for a specified time period. The time resistance test should be recorded for a
specific time such as 15th, 30th, 45th and 60th seconds and 10th minute after the voltage is
applied. The polarization index ratio (PI) is the 60th second value divided by 15th second
value or 10th minute value divided by 1st minute. The other determination ratio, dielectric
absorption ratio (DAR), can be described as 60th second value divided by 30th second value.
In general, the PI and the DAR are used in the assessment of this test result [17, 21-23].
The PI and DAR values give information about insulation conditions for power transformer
and interpretations of their values are given in Table 2.
Table 2: Interpretations of DAR and PI values for power transformer.
Insulation Conditions
Hazardous
Bad
Doubtful
Adequate
Good
Excellent
DAR 60sec/30sec
1 - 1.1
1.1 - 1.25
1.25 - 1.4
1.4 - 1.6
>1.6
PI 10min/1min
<1
1 - 1.23
1.25 - 1.5
1.5 - 2.5
2.5 - 4.0
>4
Fig. 7. Principle connection diagram of TTR test for three-phase power transformer with
YNyn0 configuration.
448
In ideal three-phase transformers, turns ratios must be identical for all phases, however,
the measured value may show a deviation from the ideal turn ratio of the transformer due to
construction error, measurement error, device sensitivity etc. The percentage of the
deviation can be calculated as;
T + Tk
R = R0 r
(8)
T
+
T
0
k
values of dielectric breakdown voltage (Vb) of insulating oils should not be lower than 45
kV and 40 kV for tank and tap changer, respectively [27-29]. But, these values are relative
that the actual evaluation is related to the status of the transformer in operation. For the
reason, it will be more appropriate to evaluate these results with together the appearance of
the oil, chemical and gas analysis.
4. Analysis of Test Results
In this section, the results of both DGA and electrical testing methods are given for four
specific power transformers that are selected from operating transformers inTEIAS. These
power transformers are labeled as TR-1, TR-2, TR-3 and TR-4. Some characteristic
information of these transformers is given Table 3. Three of the considered power
transformers are defective, and one of them is non-defective.
Table 3: Characteristic information of the tested transformers
Cases
TR-1
TR-2
TR-3
TR-4
Rated power
(MVA)
25
25
100
25
Voltage
(kV)
154/31.5
154/31.5
154 /33.6
154/31.5
Connection
configuration
YNyn0
YNyn0
YNyn0
YNyn0
Number of taps
17
17
25
17
TR-1
TR-2
TR-3
(Dome-A)
TR-4
Hydrogen (H2)
Methane (CH4)
Ethane (C2H6)
Ethylene(C2H4)
Acetylene (C2H2)
Carbon monoxide (CO)
Total Combustible Gases (ppm)
<50-150
<30-130
<20-90
<60-280
<2-20
<400-600
857*
204*
20
278
625*
588
2572
5
3
1
28
7
192
236
111
23
13
93
228*
66
534
5
2
1
8
1
158
175
* indicates that the value is above the limits according to the IEC 60599 standard.
4.1.1. Case TR-1
The assessment is made by using the Key Gas method: The percentage of each
combustible gas is calculated and interpretation is done by the gas that has the dominant
percentage value. In this case, amount of total combustible gas is found to be 2572 ppm.
From this information, the percentages of other combustible gases are calculated and are
shown in Fig. 8.
450
451
Secondary
452
Tap position
Tested windings
12
12
12
-
H1-H0
H2-H0
H3-H0
X1-X0
X2-X0
X3-X0
Test voltage
(kV)
10
10
10
2
2
2
Measured excitation
current (mA)
35.8
35.5
None
921
921
None
Power factor test was applied to windings, bushings and oils of TR-1. The PF test
measurement results are given in Table 6. It can be seen from the table that none of the CH,
CL, and CHL values can be measured for winding-tank insulation conditions. The results
show that the insulations of primary and secondary windings against tank are damaged. In
addition the test was applied for bushings and tank-tap oil separately where the PF
percentages are found within the recommended limit values. Insulation values of bushings
show that the fault do not spread to bushings.
Table 6: The measurement of power factor insulation test results for TR-1
Measured
Test voltage Current
insulation
(kV)
(mA)
WindingCH
10
None
tank
CHL
10
None
CH+CHL
10
None
CL
10
8.6
Bushings
H1-C1*
10
0.894
H2-C1
10
0.890
H3-C1
10
0.888
Oil
Tank
10
0.756
Tap
10
0.754
C1* denotes main core insulation of center conductor to tap
Power
(watt)
None
None
None
None
0.0362
0.0352
0.0343
0.0096
0.0128
Temperature
(0C)
29
29
29
29
29
29
29
16
16
PF %
Not available
Not available
Not available
Not available
0.40
0.40
0.39
0.13
0.17
The DC insulation test was applied to the TR-1 and the results are given in Table 7. The
ambient air temperature was 14 C, top oil temperature was 29 C, relative humidity was
58 %, applied test voltage was 5 kV and the test duration was 2 minutes. The aim of this
test was to observe whether insulation was normal or not between primary/tank,
secondary/tank and primary/secondary. This assessment is made based on the DAR value
that the limits are given in Table 2. As seen from Table 7, the DAR values are 2.11 for
primary/tank and 1.82 for secondary/tank. However, DAR value of primary/secondary
insulation could not be identified. Insulation value was decreased to kilo ohms level where
it should be in mega ohms level. It is concluded that there is a problem in the insulation
between primary and secondary windings.
Table 7: DC Insulation Test Results for TR-1
Measured Insulation Resistance (M)
Primary/Tank
Secondary/Tank
Primary/Secondary
th
400000
453000
th
15 second
30 second
1800000
1700000
<0.1
<0.1
45th second
2700000
2200000
<0.1
60th second
3800000
3100000
<0.1
10th minute
>10000000
DAR
2.11
1.82
H1-H0/X1-X0
H2-H0/X2-X0
H3-H0/X3-X0
E%
4.404
4.403
4.241
3.84
4.880
4.890
4.762
2.69
17
5.377
5.377
5.284
1.76
453
H1-H0 ()
H2-H0 ()
H3-H0 ()
E%
1.0180
1.0220
1.0210
0.39
0.8872
0.8893
0.8912
0.45
17
1.0220
1.0330
1.0250
1.06
Tap positions
X1-X0 ()
X2-X0 ()
X3-X0 ()
E%
0.03637
0.03655
0.03695
1.57
The TTR test was performed on all tap positions of every phase at no-load condition. As
an example, the TTR test results are given in Table 8 at 1st, 9th and 17th tap positions. As a
result of applied tests, error rate in all positions were found to be exceeding standard limit
rate, which is 0.5%. In addition, it is identified that there is a reduction in turns ratio of H3H0/X3-X0 for all taps positions. So, it can be concluded that the fault is occurred in the third
phase.
The DC winding resistance measurement test was performed on all phases and windings.
Winding temperature is recorded to be 41 C in the test process. As an example, the DC
winding resistance results are given in Table 9 at 1st, 9th and 17th tap positions. As a result
of applied tests, error rate in all taps was found to be under the standard limit for all
considered circumstances that the maximum permissible ratio error of DC winding
resistance must be lower than 2%. As a result, it is observed from the test that there is no
discontinuity problem of the all windings.
The dielectric strength test was applied to oil of main tank and tap changer for TR-1.
This test is carried out according to VDE-0370 standard. Breakdown voltages of oil
samples taken from main and tap changer reserve tanks were measured to be 60 kV and 52
kV, respectively. Insulation oil dielectric strength test results are greater than the minimum
specified limit value for both cases. It should be remembered that dielectric breakdown
voltage of insulating oils should not be lower than 45 kV and 40 kV for tank and tap
changer, respectively. When the insulation value of the oil is considered, it was still
concluded that the oil fulfills the insulation task.
4.2.2. Case TR-2
All the relevant electrical tests specified in Fig. 2 are applied to TR-2. Excluding the DC
winding resistance test, all other test results were found to be within the recommended
values. The DC winding resistance measurement test was performed on all windings and
tap positions. The primary windings measurement results are found to be within the
recommended limits for all the positions. As an example the DC winding resistance results
are given in Table 10 at 11th and 17th tap positions. However, an excessive error rate was
calculated from measurement as 33% for the secondary windings. The resistance of X1-X0
winding is measured higher than the other secondary windings. The reason for this is
thought to result from looseness in the connection terminal.
Table 10: The DC winding resistance test results for TR-2
Tap positions
H1-H0 ()
H2-H0 ()
H3-H0 ()
E%
11
1.501
1.500
1.502
0.13
17
1.654
1.653
1.655
0.12
Tap positions
X1-X0 ()
X2-X0 ()
X3-X0 ()
E%
0.056
0.042
0.042
33.33
454
In this section, the fault assessment results are compared with actual physical fault
conditions and validity of the methods are tested. General assessments of electrical tests for
the reviewed power transformers are summarized briefly in Table 11.
Table 11: Electrical test results of the tested transformers
Type of Test
Recommended limits
TR-1
TR-2
TR-3
TR-4
Excitation Current
X*
Winding-tank
PF% < 1
Factor
Bushings
PF% < 1
**
Tank
PF %< 0.5
Tap-changer
DC Insulation
E% < 0.5
DC Winding Resistance
E% < 2
Oil Dielectric
Tank
Vb>45 kV
Strength
Tap-changer
Vb>40 kV
Oil
An analysis of the DGA test results in accordance with Key gas and Duval triangle
methods for TR-1, it is deduced that the failure is high energy discharge. Furthermore,
excitation current, PF, DC insulation and the TTR tests indicate an abnormal condition for
TR-1. The excitation current from primary H3-H0 winding and for secondary X3-X0 winding
cannot be measured. Likewise in the applied PF test, insulation could not be determined
between winding-winding and winding-tank. The DAR value of primary/secondary
insulation could not be identified in the DC insulation test. In addition, it was found in the
455
TTR test that there was a reduction in turns ratio of H3-H0/X3-X0 for TR-1. In conclusion,
when all the tests are evaluated together; the fault has been observed in the primary and
secondary windings of third phase. These results give rise to the thinking that there is a
short circuit in the third phase. So, when the transformer was opened in the repair center,
fault was detected where it was expected. Fig. 10 illustrates a photo taken from the top in
the repair service for TR-1. Primary (outer ring) and secondary (inner ring) coils and their
paper insulation on one leg of the core (innermost silica sheets) are seen in the figure. In the
physical testing of third phase of the transformer, the insulation between the primary,
secondary and core was found to be deteriorated. In addition, the windings were in contact
with the core. Therefore, the transformer was taken to the maintenance service for required
repair and maintenance tasks.
Fig. 10. A photo of faulty part of the TR-1 in the repair service
All of the DGA contents were found to be within the recommended limit values for TR2. So, it can be concluded that there is no fault in the transformer for this case according to
the DGA contents. Excluding the DC winding resistance test all other test results were
found to be within the recommended values. In the applied DC winding resistance test, an
excessive error rate (33% for the secondary windings) was obtained by calculations and
measurements. The resistance of X1-X0 winding is measured to be higher than the other
secondary windings. This suggests that there is looseness in windings or in connection
terminal of the X1-X0 windings. In fact, as a result of physical inspections, looseness was
detected in the connection terminal of the secondary X1-X0 winding. Fig. 11 shows a photo
of the loose connection failure for this transformer. After the required maintenance, the
values were measured in the desired range.
Fig. 11. A photo of loose connection failure for the TR-2 in the repair service
In interpretation of the DGA test results in accordance with Key gas and Duval triangle
methods, it is deduced that the failure is high energy discharge for high voltage cable boxes
456
(Domes) of the TR-3. The high level of combustible gas amount indicates the presence of
an arc for the oil in the cable boxes. After this conclusion, HV cable box was opened, the
oil was poured and the examinations were made. As seen from the photo in the Fig.12 (a)
no trace of arc was observed and oil was not carbonized in the dome. Although high
amount of combustible gases were observed in the cable box, it is concluded they were not
formed in there and an explanation is needed for this situation. However, it was observed
that tap changer reserve oil was carbonized and broke down at a low voltage level as 37 kV
in the oil dielectric strength tests. The carbonized oil in tap changer reserve is shown in
Fig. 12 (b). Therefore it is almost certain that acetylene was produced because of tap oil
had been exposed to arc gained. These combustible gases seen in the HV cable box are
thought to be leaked from the tap-changer reserves. It is judged that there is a transition
between the tank and the tap changer reserves which should be separated normally. As
shown in Fig. 12 (c) an improper design was observed during physical examinations, which
has a transition between the main tank and tap changer reserves. It is observed that
combustible gas occurs during the tap changing and these gases are transferred to the cable
box via diffusion from common reserve tank. As a result, gas formation in the high voltage
cable box was attributed to manufacturing error, specifically to the transformer design. The
issue has been resolved by closing the transition area between the common reserves and
making the necessary modifications. After these operations, the transformer was inserted
into service and it is observed that the transformer have been operated without any
abnormal situation.
Fig. 12. a) High voltage cable box, b) Carbonized tap changer oil
c) Transition area between the reserves
For TR-4 both DGA and electrical test were performed. No evidence of any faults in
analyzes and applied tests is observed in either method.
Table 12: Assessments of tested transformers with different test methods
Cases
TR-1
TR-2
TR-3
TR-4
DGA
X
Electrical Test
X
X
X
Physical Fault
Phase to ground short circuit occurring in the third phase
Looseness in the connection terminal of the secondary X1-X0 winding
Design error. Transition between the main and tap changer reserves
No-fault
DGA, electrical testing results and physical faults of the tested power transformers are
given in Table 12 comparatively. Cooperation of electrical test methods and DGA methods
has crucial importance in the detection of transformer faults. DGA mostly give a
preliminary idea about the faults, whereas the electrical tests give more specific information
about where and why exactly the fault occurs. In addition, both methods allow transformers
to operate smoothly and increase their lifetime since necessary precautions and possible
maintenance actions may be taken before faults occur.
457
7. Conclusion
It is very well known that power transformers are one of the most expensive and
indispensable components of energy systems. Lifetime of the transformers can be
increased and faults can be avoided by applying required maintenance and tests completely
and accurately. In this work, DGA and electrical test methods have been studied in detail,
which are widely used in the fault detection and maintenance processes of power
transformers. Results showed that a single method cannot yield accurate enough results in
some specific fault conditions. Therefore, collective use of both methods in the assessment
of fault condition gives more reliable results.
DGA test method gives a preliminary idea about the possible cause of the failure. Main
advantage of the test is that it is easily applicable and suitable for online monitoring
systems. In contrast, the electrical test methods give more specific information about the
fault, and allow the detection of fault location with high accuracy. However, they are
mostly inappropriate for online monitoring systems because these tests could not be applied
under-load. When comparing the test results with the actual fault, test results showed that
the fault condition detected with great accuracy. Also these test methods are periodically
applied in power transformers. Thus, both methods allow smooth operation and increase the
lifetime of transformers by providing to take the necessary precautions and possible
maintenance actions before faults occur.
Acknowledgment
This work was supported by the Turkish Electricity Transmission Company. I would
like to express my utmost gratitude to all the people who have directly or indirectly
contributed towards the successful completion of this technical paper.
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