Studytransformers

U.S. Department of the Interior
Bureau of Reclamation April 2005
Transformers:
Basics, Maintenance,
and Diagnostics

U.S. Department of the Interior
Bureau of Reclamation
Technical Service Center
Infrastructure Services Division
Hydroelectric Research and Technical Services Group
Denver, Colorado April 2005
Transformers:
Basics, Maintenance,
and Diagnostics

iii
PREFACE
Transformers have been used at powerplants since the inception of
alternating-current generation, a century ago. While operating
principles of transformers remain the same, the challenges of
maintaining and testing transformers have evolved along with
transformer design and construction. Modern transformers are
designed to closer tolerances than transformers in the past. Thus,
effective, regular maintenance and testing is even more essential to
continued operation when traditional “overdesign” cannot be relied on
to overcome abnormal conditions. The utility engineer must be
familiar with all aspects of maintenance and testing and make use of
state-of-the-art tools and techniques for evaluating transformer
condition. While on-line diagnostic systems and computerized testing
methods are very helpful, they are not a substitute for sound
engineering judgment and expertise.
This volume provides timely, practical advice to those seeking to
better understand how transformers work, how they are best
maintained, and how to test and evaluate their condition. It has been
developed with the assistance of Bureau of Reclamation engineers
responsible for operating and maintaining transformers at important
powerplants in the Western States. Support and funding was provided
through the Reclamation Power Resources Office in Denver and via
the Manuals and Standards development program.
The authors gratefully acknowledge the assistance of all who
contributed.
Hydroelectric Research and
Technical Services Group
Denver, Colorado
April 2005

Transformers:
Basics, Maintenance, and Diagnostics
v
Contents
Page
1. Introduction......................................................................... 1
2. Introduction to Transformers .............................................. 1
2.1 Principle of Operation................................................ 3
2.2 Transformer Action.................................................... 4
2.3 Transformer Voltage and Current.............................. 8
2.4 The Magnetic Circuit ................................................. 10
2.5 Core Losses................................................................ 13
2.6 Copper Losses............................................................ 13
2.7 Transformer Rating.................................................... 14
2.8 Percent Impedance..................................................... 14
2.9 Internal Forces ........................................................... 16
2.10 Autotransformers ....................................................... 17
2.11 Instrument Transformers............................................ 18
2.12 Potential Transformers............................................... 19
2.13 Current Transformers................................................. 20
2.14 Transformer Taps....................................................... 22
2.15 Transformer Bushings................................................ 23
2.16 Transformer Polarity.................................................. 24
2.17 Single-Phase Transformer Connections for
Typical Service to Buildings................................... 25
2.18 Parallel Operation of Single-Phase Transformers
for Additional Capacity........................................... 26
2.19 Three-Phase Transformer Connections...................... 28
2.20 Wye and Delta Connections....................................... 28
2.21 Three-Phase Connections Using
Single-Phase Transformers..................................... 29
2.22 Paralleling Three-Phase Transformers....................... 32
2.23 Methods of Cooling ................................................... 35
2.24 Oil-Filled – Self-Cooled Transformers...................... 36
2.25 Forced-Air and Forced-Oil-Cooled
Transformers ......................................................... 36
2.26 Transformer Oil ......................................................... 37

Transformers:
vi
Contents (continued)
Page
2. Introduction to Transformers (continued)
2.27 Conservator System ................................................... 38
2.28 Oil-Filled, Inert-Gas System...................................... 39
2.29 Indoor Transformers .................................................. 41
3. Routine Maintenance ......................................................... 42
3.1 Introduction to Reclamation Transformers................ 42
3.2 Transformer Cooling Methods Introduction.............. 44
3.3 Dry-Type Transformers ............................................. 45
3.3.1 Potential Problems and Remedial
Actions for Dry-Type Transformer
Cooling Systems ......................................... 47
3.4 Liquid-Immersed Transformers................................. 48
3.4.1. Liquid-Immersed, Air-Cooled ....................... 48
3.4.2 Liquid-Immersed, Air-Cooled/Forced
Liquid-Cooled............................................. 50
3.4.3 Liquid-Immersed, Water-Cooled................... 51
3.4.4 Liquid-Immersed, Forced Liquid-Cooled...... 52
3.4.5 Potential Problems and Remedial Actions
for Liquid-Filled Transformer
Cooling Systems ......................................... 52
3.4.5.1 Leaks............................................... 52
3.4.5.2 Cleaning Radiators.......................... 53
3.4.5.3 Plugged Radiators ........................... 53
3.4.5.4 Sludge Formation............................ 53
3.4.5.5 Valve Problems............................... 54
3.4.5.6 Mineral Deposits............................. 54
3.4.5.7 Low Oil Level................................. 54
3.4.6 Cooling System Inspections........................... 54
4. Oil-Filled Transformer Inspections..................................... 56
4.1 Transformer Tank ...................................................... 57
4.2 Top Oil Thermometers............................................... 57

Transformers:
vii
Page
4. Oil-Filled Transformer Inspections (continued)
4.3 Winding Temperature Thermometers........................ 58
4.3.1 Temperature Indicators Online ...................... 60
4.3.2 Temperature Indicators Offline...................... 60
4.4 Oil Level Indicators ................................................... 61
4.5 Pressure Relief Devices ............................................. 62
4.5.1 Newer Pressure Relief Devices...................... 63
4.5.2 Older Pressure Relief Devices ....................... 66
4.6 Sudden Pressure Relay............................................... 67
4.6.1 Testing Suggestion......................................... 69
4.7 Buchholz Relay (Found Only on Transformers
with Conservators).................................................. 69
4.8 Transformer Bushings: Testing and
Maintenance of High-Voltage Bushings................. 72
4.9 Oil Preservation Sealing Systems.............................. 76
4.9.1 Sealing Systems Types .................................. 77
4.9.1.1 Free Breathing................................. 77
4.9.1.2 Sealed or Pressurized Breathing ..... 77
4.9.1.3 Pressurized Inert Gas Sealed
System.......................................... 78
4.9.2 Gas Pressure Control Components ................ 81
4.9.2.1 High-Pressure Gauge ...................... 81
4.9.2.2 High-Pressure Regulator................. 81
4.9.2.3 Low-Pressure Regulator.................. 82
4.9.2.4 Bypass Valve Assembly ................. 82
4.9.2.5 Oil Sump......................................... 82
4.9.2.6 Shutoff Valves ................................ 83
4.9.2.7 Sampling and Purge Valve.............. 83
4.9.2.8 Free Breathing Conservator............ 83
4.9.2.9 Conservator with Bladder or
Diaphragm Design ....................... 84
4.10 Auxiliary Tank Sealing System ................................. 90

Transformers:
viii
Page
5. Gaskets................................................................................ 91
5.1 Sealing (Mating) Surface Preparation........................ 92
5.2 Cork-Nitrile................................................................ 93
5.3 Cork-Neoprene........................................................... 94
5.4 Nitrile “NBR” ............................................................ 95
5.4.1 Viton .............................................................. 95
5.5 Gasket Sizing for Standard Groove Depths............... 97
5.6 Rectangular Nitrile Gaskets....................................... 99
5.7 Bolting Sequences to Avoid Sealing Problems ......... 103
6. Transformer Oils................................................................. 105
6.1 Transformer Oil Functions......................................... 105
6.1.1 Dissolved Gas Analysis ................................. 105
6.1.2 Key Gas Method ............................................ 109
6.1.2.1 Four-Condition DGA Guide
(IEEE C57-104) ........................... 109
6.1.3 Sampling Intervals and Recommended
Actions........................................................ 113
6.1.4 Atmospheric Gases ........................................ 117
6.1.5 Dissolved Gas Software................................. 117
6.1.6 Temperature................................................... 122
6.1.7 Gas Mixing..................................................... 122
6.1.8 Gas Solubility................................................. 123
6.1.9 Diagnosing a Transformer Problem
Using Dissolved Gas Analysis and
the Duval Triangle ...................................... 125
6.1.9.1 Origin of the Duval Triangle........... 125
6.1.9.2 How to Use the Duval Triangle ...... 125
6.1.9.3 Expertise Needed ............................ 131
6.1.9.4 Rogers Ratio Method of DGA........ 131
6.1.10 Carbon Dioxide/Carbon Monoxide Ratio...... 138
6.1.11 Moisture Problems......................................... 141

Transformers:
ix
Page
6. Transformer Oils (continued)
6.1 Transformer Oil Functions (continued)
6.1.11 Moisture Problems (continued)
6.1.11.1 Dissolved Moisture in
Transformer Oil ........................... 145
6.1.11.2 Moisture in Transformer
Insulation...................................... 146
7. Transformer Oil Tests that Should Be Completed
Annually with the Dissolved Gas Analysis ............... 150
7.1 Dielectric Strength ..................................................... 150
7.1.1 Interfacial Tension ......................................... 151
7.2 Acid Number.............................................................. 152
7.3 Test for Oxygen Inhibitor .......................................... 153
7.4 Power Factor.............................................................. 154
7.5 Oxygen....................................................................... 155
7.6 Furans......................................................................... 155
7.7 Oil Treatment Specification....................................... 159
7.7.1 Taking Oil Samples for DGA ........................ 160
7.7.1.1 DGA Oil Sample Container............ 162
7.7.1.2 Taking the Sample .......................... 163
8. Silicone Oil-Filled Transformers ........................................ 167
8.1 Background................................................................ 167
8.2 Carbon Monoxide in Silicone Transformers.............. 170
8.3 Comparison of Silicone Oil and Mineral
Oil Transformers..................................................... 170
8.4 Gas Limits.................................................................. 171
8.5 Physical Test Limits................................................... 175
9. Transformer Testing ......................................................... 176
9.1 DC Winding Resistance Measurement ...................... 176
9.2 Core Insulation Resistance and Inadvertent
Core Ground Test (Megger®) ................................ 178

Transformers:
x
Page
9. Transformer Testing (continued)
9.3 Doble Tests on Insulation .......................................... 180
9.3.1 Insulation Power Factor Test ......................... 180
9.3.2 Capacitance Test ............................................ 180
9.3.3 Excitation Current Test.................................. 181
9.3.4 Bushing Tests................................................. 182
9.3.5 Percent Impedance/Leakage
Reactance Test ............................................ 182
9.3.6 Sweep Frequency Response
Analysis Tests............................................. 183
9.4 Visual Inspection ....................................................... 186
9.4.1 Background.................................................... 186
9.4.2 Oil Leaks........................................................ 187
9.4.3 Oil Pumps....................................................... 187
9.4.4 Fans and Radiators......................................... 188
9.4.5 Age................................................................. 188
9.4.6 Infrared Temperature Analysis ...................... 189
9.4.7 IR for Transformer Tanks.............................. 189
9.4.8 IR for Surge Arresters.................................... 190
9.4.9 IR for Bushings.............................................. 190
9.4.10 IR for Radiators and Cooling Systems........... 191
9.4.11 Corona Scope Scan ........................................ 193
9.5 Ultrasonic and Sonic Fault Detection ........................ 193
9.5.1 Background.................................................... 193
9.5.2 Process ........................................................... 194
9.6 Vibration Analysis ..................................................... 194
9.6.1 Background.................................................... 194
9.6.2 Process ........................................................... 195
9.7 Turns Ratio Test......................................................... 195
9.7.1 Background.................................................... 195
9.7.2 Process ........................................................... 195
9.8 Estimate of Paper Deterioration (Online) .................. 196
9.8.1 CO2 and CO Accumulated Total
Gas Values .................................................. 196

Transformers:
xi
Page
9. Transformer Testing (continued)
9.8 Estimate of Paper Deterioration (Online) (continued)
9.8.2 CO2/CO Ratio ................................................ 196
9.9 Estimate of Paper Deterioration (Offline
During Internal Inspection)..................................... 197
9.9.1 Degree of Polymerization (DP) ..................... 197
9.9.1.1 Background..................................... 197
9.9.1.2 Process ............................................ 198
9.9.2 Internal Inspection ......................................... 198
9.9.2.1 Background..................................... 198
9.9.2.2 Transformer Borescope................... 200
9.10 Transformer Operating History.................................. 200
9.11 Transformer Diagnostics/Condition
Assessment Summary............................................. 201
Appendix: Hydroplant Risk Assessment –
Transformer Condition Assessment.................................... 205
References................................................................................. 231
Acronyms and Abbreviations ................................................... 235
Tables
Table No. Page
1 Operative Parallel Connections of
Three-Phase Transformers...................................... 34
2 Inoperative Parallel Connections of
Three-Phase Transformers...................................... 34
3 Transformer Gasket Application Summary............... 96
4 Vertical Groove Compression for
Circular Nitrile Gasket............................................ 97

Transformers:
xii
Tables (continued)
Table No. Page
5 Vertical Groove Compression for
Rectangular Nitrile Gaskets.................................... 103
6 Transformer DGA Condition Summary Table .......... 107
7 345-kV Transformer Example................................... 108
8 Dissolved Key Gas Concentration Limits.................. 110
9 Actions Based on Dissolved Combustible Gas.......... 112
10 TOA L1 Limits and Generation Rate Per
Month Alarm Limits ............................................... 118
11 Fault Types................................................................. 120
12 Dissolved Gas Solubility in Transformer Oil
Accurate Only at STP, 0 °C (32 °F) and
14.7 psi (29.93 Inches of Mercury)......................... 124
13 L1 Limits and Generation Rate Per
Month Limits ......................................................... 126
14 Dissolved Gas Analysis Detection Limits ................. 132
15 Rogers Ratios for Key Gases ..................................... 135
16 Typical Faults in Power Transformers....................... 140
17 Comparison of Water Distribution in Oil
and Paper ................................................................ 142
18 Furans, DP, Percent of Life Used of
Paper Insulation ...................................................... 156
19 Doble Limits for Inservice Oils ................................. 158
20 Additional Guidelines for Inservice Oils ................... 159
21 Comparison of Gas Limits......................................... 172
22 Suggested Levels of Concern (Limits) ...................... 173
23 Doble and IEEE Physical Test Limits for
Service-Aged Silicone Fluid................................... 175
24 Paper Status Conditions Using CO2 and CO ............. 197
25 DP Values for Estimating Remaining
Paper Life................................................................ 198
26 Reclamation Transformer Condition
Assessment Summary............................................. 201

Transformers:
xiii
Figures
Figure No. Page
1 Typical GSU Three-Phase Transformer .................... 2
2 Transformer Construction.......................................... 4
3 Transformer Action.................................................... 6
4 Transformer................................................................ 7
5 Step-Up and Step-Down Transformers...................... 10
6 Magnetic Circuits....................................................... 11
7 Three-Phase Core Form and Three-Phase
Shell Form Transformer Units................................ 12
8 Transformer Internal Forces ...................................... 16
9 Autotransformers ....................................................... 17
10 Connections of Instrument Transformers .................. 19
11 Potential Transformers............................................... 20
12 Current Transformer .................................................. 21
13 Photograph of Current Transformers......................... 22
14 Polarity Illustrated...................................................... 25
15 Single-Phase Transformer.......................................... 26
16 Single-Phase Paralleling ............................................ 27
17 Three-Phase Connections........................................... 29
18 Delta-Delta Connections, Single-Phase
Transformers for Three-Phase Operation ............... 30
19 Wye-Wye Connections, Using Single-Phase
Transformers for Three-Phase Operation ............... 31
20 Delta-Wye and Wye-Delta Connections Using
Single-Phase Transformers for Three-Phase
Operation................................................................. 33
21 Cooling....................................................................... 36
22 Forced-Air/Oil/Water-Cooled Transformers ............. 37
23 Conservator with Bladder .......................................... 38
24 Typical Transformer Nitrogen System ...................... 40
25 Transformer Diagnostics Flowchart .......................... 43
26 Typical Oil Flow........................................................ 51
27 Oil Level Indicator..................................................... 62
28 Conservator Oil Level................................................ 62

Transformers:
xiv
Figures (continued)
Figure No. Page
29 Pressure Relief Device............................................... 64
30 Photograph of a Pressure Relief Device .................... 64
31 Sudden Pressure Relay, Section................................. 68
32 Photograph of a Sudden Pressure Relay.................... 69
33 Buchholz Relay, Section............................................ 70
34 Photograph of a Buchholz Relay ............................... 70
35 Pressurized Breathing Transformer ........................... 78
36 Pressurized Inert Gas Transformer ............................ 79
37 Gas Pressure Control Components ............................ 80
38 Free Breathing Conservator....................................... 84
39 Conservator with Bladder .......................................... 85
40 Conservator Breather ................................................. 87
41 Photograph of a Bladder Failure Relay...................... 87
42 Bladder Failure Relay ................................................ 88
43 Auxiliary Sealing System .......................................... 91
44 Cross Section of Circular Gasket in Groove.............. 98
45 Cross Section of Gasket Remains Constant
Before Tightening and After................................... 101
46 Bowing at Flanges...................................................... 104
47 Bolt Tightening Sequences ........................................ 104
48 Combustible Gas Generation Versus
Temperature............................................................ 115
49 The Duval Triangle.................................................... 126
50 Duval Triangle Diagnostic Example of a
Reclamation Transformer ....................................... 128
51 Maximum Amount of Water Dissolved in
Mineral Oil Versus Temperature ............................ 145
52 Transformer Oil Percent Saturation Curves............... 146
53 Water Distribution in Transformer Insulation ........... 147
54 Myers Multiplier Versus Temperature....................... 148
55 Water Content of Paper and Oil Nomogram.............. 149
56 Interfacial Tension, Acid Number, Years
in Service ................................................................ 152

Transformers:
xv
Figures (continued)
Figure No. Page
57 Oil Sampling Piping................................................... 163
58 Sampling Syringe (Flushing)..................................... 164
59 Sampling Syringe (Filling) ........................................ 165
60 Sample Syringe Bubble Removal.............................. 166
61 Relationship of Oxygen to Carbon Dioxide
and Carbon Monoxide as Transformer Ages.......... 169
62 SFRA Test Traces of a New Transformer ................. 184
63 SFRA Test Traces of a Defective New
Transformer............................................................. 186
64 Normal Transformer IR Pattern................................. 190
65 IR Image of Defective Arrester.................................. 191
66 IR Image Showing Blocked Radiators....................... 192
67 IR Image of Defective Bushing ................................. 192
68 Transformer Diagnostic Test Chart (Adapted
from IEEE 62-1995™) ........................................... 204

Transformers:
1
1. Introduction
This document was created to provide guidance to Bureau of
Reclamation (Reclamation) powerplant personnel in maintenance,
diagnostics, and testing of transformers and associated equipment.
This document applies primarily to the maintenance and diagnostics
of oil-filled power transformers (500 kilovoltamperes [kVA] and
larger), owned and operated by Reclamation, although routine
maintenance of other transformer types is addressed as well. Specific
technical details are included in other documents and are referenced in
this document.
Guidance and recommendations herein are based on industry standards
and experience gained at Reclamation facilities. However, equipment
and situations vary greatly, and sound engineering and management
judgment must be exercised when applying these diagnostics. All
available information must be considered (e.g., manufacturer=s and
transformer experts’ recommendations, unusual operating conditions,
personal experience with the equipment, etc.) in conjunction with this
document.
2. Introduction to Transformers
Generator step-up (GSU) transformers represent the second largest
capital investment in Reclamation power production—second only
to generators. Reclamation has hundreds, perhaps thousands,
of transformers, in addition to hundreds of large GSU transformers.
Reclamation has transformers as small as a camera battery charger,
about one-half the size of a coffee cup, to huge generator step-up
transformers near the size of a small house. The total investment
in transformers may well exceed generator investment. Transformers
are extremely important to Reclamation, and it is necessary
to understand their basic functions.

Transformers:
2
A transformer has no internal moving parts, and it transfers energy
from one circuit to another by electromagnetic induction. External
cooling may include heat exchangers, radiators, fans, and oil pumps.
Radiators and fans are evident in figure 1. The large horizontal tank at
the top is a conservator. Transformers are typically used because a
change in voltage is needed. Power transformers are defined as
transformers rated
500 kVA and larger.
Larger transformers are
oil-filled for insulation
and cooling; a typical
GSU transformer may
contain several thousand
gallons of oil. One must
always be aware of the
possibility of spills,
leaks, fires, and
environmental risks this
oil poses.
Transformers smaller
than 500 kVA are
generally called
distribution transformers. Pole-top and small, pad-mounted
transformers that serve residences and small businesses are typically
distribution transformers. Generator step-up transformers, used in
Reclamation powerplants, receive electrical energy at generator
voltage and increase it to a higher voltage for transmission lines.
Conversely, a step-down transformer receives energy at a higher
voltage and delivers it at a lower voltage for distribution to various
loads.
All electrical devices using coils (in this case, transformers) are
constant wattage devices. This means voltage multiplied by current
must remain constant; therefore, when voltage is “stepped-up,” the
current is “stepped-down” (and vice versa). Transformers transfer
Figure 1 – Typical GSU Three-Phase
Transformer.

Transformers:
3
electrical energy between circuits completely insulated from each
other. This makes it possible to use very high (stepped-up) voltages
for transmission lines, resulting in a lower (stepped-down) current.
Higher voltage and lower current reduce the required size and cost of
transmission lines and reduce transmission losses as well.
Transformers have made possible economic delivery of electric power
over long distances.
Transformers do not require as much attention as most other
equipment; however, the care and maintenance they do require is
absolutely critical. Because of their reliability, maintenance is
sometimes ignored, causing reduced service life and, at times, outright
failure.
2.1 Principle of Operation
Transformer function is based on the principle that electrical energy is
transferred efficiently by magnetic induction from one circuit to
another. When one winding of a transformer is energized from an
alternating current (AC) source, an alternating magnetic field is
established in the transformer core. Alternating magnetic lines of
force, called “flux,” circulate through the core. With a second winding
around the same core, a voltage is induced by the alternating flux lines.
A circuit, connected to the terminals of the second winding, results in
current flow.
Each phase of a transformer is composed of two separate coil windings
wound on a common core. The low-voltage winding is placed nearest
the core; the high-voltage winding is then placed around both the low-
voltage winding and core. See figure 2 which shows internal
construction of one phase. The core is typically made from very thin
steel laminations, each coated with insulation. By insulating between
individual laminations, losses are reduced. The steel core provides a
low resistance path for magnetic flux. Both high- and low-voltage
windings are insulated from the core and from each other, and leads

Transformers:
4
are brought out through insulating bushings. A three-phase
transformer typically has a core with three legs and has both high-
voltage and low-voltage windings around each leg. Special paper
and wood are used for insulation and internal structural support.
2.2 Transformer Action
Transformer action depends upon magnetic lines of force (flux)
mentioned above. At the instant a transformer primary is energized
with AC, a flow of electrons (current) begins. During the instant of
switch closing, buildup of current and magnetic field occurs. As
current begins the positive portion of the sine wave, lines of magnetic
force (flux) develop outward from the coil and continue to expand
until the current is at its positive peak. The magnetic field is also at its
positive peak. The current sine wave then begins to decrease, crosses
zero, and goes negative until it reaches its negative peak. The
magnetic flux switches direction and also reaches its peak in the
Figure 2 – Transformer Construction.

Transformers:
5
opposite direction. With an AC power circuit, the current changes
(alternates) continually 60 times per second, which is standard in the
United States. Other countries may use other frequencies. In Europe,
50 cycles per second is common.
Strength of a magnetic field depends on the amount of current and
number of turns in the winding. When current is reduced, the
magnetic field shrinks. When the current is switched off, the magnetic
field collapses.
When a coil is placed in an AC circuit, as shown in figure 3, current in
the primary coil will be accompanied by a constantly rising and
collapsing magnetic field. When another coil is placed within the
alternating magnetic field of the first coil, the rising and collapsing
flux will induce voltage in the second coil.
When an external circuit is connected to the second coil, the induced
voltage in the coil will cause a current in the second coil. The coils are
said to be magnetically coupled; they are, however, electrically
isolated from each other.
Many transformers have separate coils, as shown in figure 3, and
contain many turns of wire and a magnetic core, which forms a path
for and concentrates the magnetic flux. The winding receiving
electrical energy from the source is called the primary winding. The
winding which receives energy from the primary winding, via the
magnetic field, is called the “secondary” winding.
Either the high- or low-voltage winding can be the primary or the
secondary. With GSUs at Reclamation powerplants, the primary
winding is the low-voltage side (generator voltage), and the high-
voltage side is the secondary winding (transmission voltage). Where
power is used (i.e., at residences or businesses), the primary winding is
the high-voltage side, and the secondary winding is the low-voltage
side.

Transformers:
6
The amount of voltage induced in each turn of the secondary winding
will be the same as the voltage across each turn of the primary
winding. The total amount of voltage induced will be equal to the sum
of the voltages induced in each turn. Therefore, if the secondary
winding has more turns than the primary, a greater voltage will be
induced in the secondary; and the transformer is known as a step-up
transformer. If the secondary winding has fewer turns than the
primary, a lower voltage will be induced in the secondary; and the
transformer is a step-down transformer. Note that the primary is
always connected to the source of power, and the secondary is always
connected to the load.
In actual practice, the amount of power available from the secondary
will be slightly less than the amount supplied to the primary because of
losses in the transformer itself.
When an AC generator is connected to the primary coil of a
transformer (figure 4), electrons flow through the coil due to the
Figure 3 – Transformer Action.

Transformers:
7
generator voltage. Alternating current varies, and accompanying
magnetic flux varies, cutting both transformer coils and inducing
voltage in each coil circuit.
The voltage induced in the primary circuit opposes the applied voltage
and is known as back voltage or back electro-motive-force (back
EMF). When the secondary circuit is open, back EMF, along with the
primary circuit resistance, acts to limit the primary current. Primary
current must be sufficient to maintain enough magnetic field to
produce the required back EMF.
When the secondary circuit is closed and a load is applied, current
appears in the secondary due to induced voltage, resulting from flux
created by the primary current. This secondary current sets up a
second magnetic field in the transformer in the opposite direction of
the primary field. Thus, the two fields oppose each other and result in
a combined magnetic field of less strength than the single field
produced by the primary with the secondary open. This reduces the
back voltage (back EMF) of the primary and causes the primary
current to increase. The primary current increases until it re-
establishes the total magnetic field at its original strength.
Figure 4 – Transformer.

Transformers:
8
In transformers, a balanced condition must always exist between the
primary and secondary magnetic fields. Volts times amperes (amps)
must also be balanced (be the same) on both primary and secondary.
The required primary voltage and current must be supplied to maintain
the transformer losses and secondary load.
2.3 Transformer Voltage and Current
If the small amount of transformer loss is ignored, the back-voltage
(back EMF) of the primary must equal the applied voltage. The
magnetic field, which induces the back-voltage in the primary, also
cuts the secondary coil. If the secondary coil has the same number of
turns as the primary, the voltage induced in the secondary will equal
the back-voltage induced in the primary (or the applied voltage). If the
secondary coil has twice as many turns as the primary, it will be cut
twice as many times by the flux, and twice the applied primary voltage
will be induced in the secondary. The total induced voltage in each
winding is proportional to the number of turns in that winding. If E1 is
the primary voltage and I1 the primary current, E2 the secondary
voltage and I2 the secondary current, N1 the primary turns and N2 the
secondary turns, then:
Note that the current is inversely proportional to both voltage and
number of turns. This means (as discussed earlier) that if voltage is
stepped up, the current must be stepped down and vice versa. The
number of turns remains constant unless there is a tap changer
(discussed later).
The power output or input of a transformer equals volts times amperes
(E x I). If the small amount of transformer loss is disregarded, input
equals output or:
E1 x I1 = E2 x I2
1
2
2
1
2
1
I
I
N
N
E
E
==

Transformers:
9
If the primary voltage of a transformer is 110 volts (V), the primary
winding has 100 turns, and the secondary winding has 400 turns, what
will the secondary voltage be?
100 E2 = 44,000 E2 = 440 volts
If the primary current is 20 amps, what will the secondary current be?
E2 x I2 = El x I1
440 x I2 = 110 x 20 = 2,200
I2 = 5 amps
Since there is a ratio of 1 to 4 between the turns in the primary and
secondary circuits, there must be a ratio of 1 to 4 between the primary
and secondary voltage and a ratio of 4 to 1 between the primary and
secondary current. As voltage is stepped up, the current is stepped
down, keeping volts multiplied by amps constant. This is referred to
as “volt amps.”
As mentioned earlier and further illustrated in figure 5, when the
number of turns or voltage on the secondary of a transformer is greater
than that of the primary, it is known as a step-up transformer. When
the number of turns or voltage on the secondary is less than that of the
primary, it is known as a step-down transformer. A power transformer
used to tie two systems together may feed current either way between
systems, or act as a step-up or step-down transformer, depending on
where power is being generated and where it is consumed. As
mentioned above, either winding could be the primary or secondary.
To eliminate this confusion, in power generation, windings of
transformers are often referred to as high-side and low-side windings,
depending on the relative values of the voltages.
2
1
2
1
N
N
E
E
=
400
100
E
110
2
=

Transformers:
10
Note that kVA (amps times volts) remains constant throughout the
above circuit on both sides of each transformer, which is why they are
called constant wattage devices.
Efficiencies of well-designed power transformers are very high,
averaging over 98 percent (%). The only losses are due to core losses,
maintaining the alternating magnetic field, resistance losses in the
coils, and power used for cooling. The main reason for high
efficiencies of power transformers, compared to other equipment, is
the absence of moving parts. Transformers are called static
AC machines.
2.4 The Magnetic Circuit
A magnetic circuit or core of a transformer is designed to provide a
path for the magnetic field, which is necessary for induction of
voltages between windings. A path of low reluctance (i.e., resistance
to magnetic lines of force), consisting of thin silicon, sheet steel
laminations, is used for this purpose. In addition to providing a low
reluctance path for the magnetic field, the core is designed to prevent
circulating electric currents within the steel itself. Circulating
currents, called eddy currents, cause heating and energy loss. They are
Figure 5 – Step-Up and Step-Down Transformers.

Transformers:
11
due to voltages induced in the steel of the core, which is constantly
subject to alternating magnetic fields. Steel itself is a conductor, and
changing lines of magnetic flux also induce a voltage and current in
this conductor. By using very thin sheets of steel with insulating
material between sheets, eddy currents (losses) are greatly reduced.
The two common arrangements of the magnetic path and the windings
are shown in figure 6 and 7. In the core-type (core form) transformer,
the windings surround the core.
A section of both primary and secondary windings are wound on each
leg of the core, the low voltage winding is wound next to the core, and
the high voltage winding is wound over the low voltage.
Figure 6 – Magnetic Circuits.

Transformers:
12
In a shell-type (shell form) transformer, the steel magnetic circuit
(core) forms a shell surrounding the windings. In a core form, the
windings are on the outside; in a shell form, the windings are on the
inside. In power transformers, the electrical windings are arranged so
that practically all of the magnetic lines of force go through both the
primary and secondary windings. A small percentage of the magnetic
lines of force goes outside the core, and this is called leakage flux.
Larger transformers, such as Reclamation GSU transformers, are
almost always shell type.
Figure 7 – Three-Phase Core Form and Three-Phase Shell
Form Transformer Units.

Transformers:
13
Note that, in the shell form transformers, (see figure 7) the magnetic
flux, external to the coils on both left and right extremes, has complete
magnetic paths for stray and zero sequence flux to return to the coils.
In the core form, it can easily be seen from the figure that, on both left
and right extremes, there are no return paths. This means that the flux
must use external tank walls and the insulating medium for return
paths. This increases core losses and decreases overall efficiency and
shows why most large transformers are built as shell form units.
2.5 Core Losses
Since magnetic lines of force in a transformer are constantly changing
in value and direction, heat is developed because of the hysteresis of
the magnetic material (friction of the molecules). This heat must be
removed; therefore, it represents an energy loss of the transformer.
High temperatures in a transformer will drastically shorten the life of
insulating materials used in the windings and structures. For every
8 degrees Celsius (°C) temperature rise, life of the transformer is cut
by one-half; therefore, maintenance of cooling systems is critical.
Losses of energy, which appears as heat due both to hysteresis and to
eddy currents in the magnetic path, is known as core losses. Since
these losses are due to alternating magnetic fields, they occur in a
transformer whenever the primary is energized, even though no load is
on the secondary winding.
2.6 Copper Losses
There is some loss of energy in a transformer due to resistance of the
primary winding to the magnetizing current, even when no load is
connected to the transformer. This loss appears as heat generated in
the winding and must also be removed by the cooling system. When a
load is connected to a transformer and electrical currents exist in both
primary and secondary windings, further losses of electrical energy
occur. These losses, due to resistance of the windings, are called
copper losses (or the I2
R losses).

Transformers:
14
2.7 Transformer Rating
Capacity (or rating) of a transformer is limited by the temperature that
the insulation can tolerate. Ratings can be increased by reducing core
and copper losses, by increasing the rate of heat dissipation (better
cooling), or by improving transformer insulation so it will withstand
higher temperatures. A physically larger transformer can dissipate
more heat, due to the increased area and increased volume of oil. A
transformer is only as strong as its weakest link, and the weakest link
is the paper insulation, which begins to degrade around 100 °C. This
means that a transformer must be operated with the “hottest spot”
cooler than this degradation temperature, or service life is greatly
reduced. Reclamation typically orders transformers larger than
required, which aids in heat removal and increases transformer life.
Ratings of transformers are obtained by simply multiplying the current
times the voltage. Small transformers are rated in “VA,” volts times
amperes. As size increases, 1 kilovoltampere (kVA) means
1,000 voltamperes, 1 megavoltampere (MVA) means 1 million
voltamperes. Large GSUs may be rated in hundreds of MVAs. A
GSU transformer can cost well over a million dollars and take
18 months to 2 years or longer to obtain. Each one is designed for a
specific application. If one fails, this may mean a unit or whole plant
could be down for as long 2 years, costing multiple millions of dollars
in lost generation, in addition to the replacement cost of the
transformer itself. This is one reason that proper maintenance is
critical.
2.8 Percent Impedance
The impedance of a transformer is the total opposition offered an
alternating current. This may be calculated for each winding.
However, a rather simple test provides a practical method of
measuring the equivalent impedance of a transformer without
separating the impedance of the windings. When referring to
impedance of a transformer, it is the equivalent impedance that is
meant. In order to determine equivalent impedance, one winding of

Transformers:
15
the transformer is short circuited, and just enough voltage is applied to
the other winding to create full load current to flow in the short
circuited winding. This voltage is known as the impedance voltage.
Either winding may be short-circuited for this test, but it is usually
more convenient to short circuit the low-voltage winding. The
transformer impedance value is given on the nameplate in percent.
This means that the voltage drop due to the impedance is expressed as
a percent of rated voltage. For example, if a 2,400/240-volt
transformer has a measured impedance voltage of 72 volts on the high-
voltage windings, its impedance (Z), expressed as a percent, is:
percent Z =
400,2
72
x 100 = 3 percent
This means there would be a 72-volt drop in the high-voltage winding
at full load due to losses in the windings and core. Only 1 or 2% of the
losses are due to the core; about 98% are due to the winding
impedance. If the transformer were not operating at full load, the
voltage drop would be less. If an actual impedance value in ohms is
needed for the high-voltage side:
where V is the voltage drop or, in this case, 72 volts; and I is the
full load current in the primary winding. If the full load current is
10 amps:
Of course, one must remember that impedance is made up of both
resistive and reactive components.
I
V
Z =
ohms
a
V
Z 2.7
10
72
==

Transformers:
16
2.9 Internal Forces
During normal operation, internal structures and windings are
subjected to mechanical forces due to the magnetic forces. These
forces are illustrated in figure 8. By designing the internal structure
very strong to withstand these forces over a long period of time,
service life can be extended. However, in a large transformer during a
“through fault” (fault current passing through a transformer), forces
can reach millions of pounds, pulling the coils up and down and
pulling them apart 60 times per second. Notice in figure 8 that the
internal low-voltage coil is being pulled downward, while the high-
voltage winding is pulled up, in the opposite direction. At the same
time, the right-hand part of the figure shows that the high- and low-
voltage coils are being forced apart. Keep in mind that these forces are
reversing 60 times each second. It is obvious why internal structures
of transformers must be built incredibly strong.
Many times, if fault currents are high, these forces can rip a
transformer apart and cause electrical faults inside the transformer
itself. This normally results in arcing inside the transformer that can
result in explosive failure of the tank, throwing flaming oil over a wide
Figure 8 – Transformer Internal Forces.

Transformers:
17
area. There are protective relaying systems to protect against this
possibility, although explosive failures do occur occasionally.
2.10 Autotransformers
It is possible to obtain transformer action by means of a single coil,
provided that there is a “tap connection” somewhere along the
winding. Transformers having only one winding are called
autotransformers, shown schematically in figure 9.
An autotransformer has the usual magnetic core but only one
winding, which is common to both the primary and secondary circuits.
The primary is always the portion of the winding connected to the
AC power source. This transformer may be used to step voltage up or
down. If the primary is the total winding and is connected to a supply,
and the secondary circuit is connected across only a portion of the
winding (as shown), the secondary voltage is “stepped-down.”
Figure 9 – Autotransformers.

Transformers:
18
If only a portion of the winding is the primary and is connected to the
supply voltage and the secondary includes all the winding, then the
voltage will be “stepped-up” in proportion to the ratio of the total turns
to the number of connected turns in the primary winding.
When primary current I1 is in the direction of the arrow, secondary
current, I2, is in the opposite direction, as in figure 9b. Therefore, in
the portion of the winding between points b and c, current is the
difference of I1 and I2. If the requirement is to step the voltage up (or
down) only a small amount, then the transformer ratio is small—E1
and E2 are nearly equal. Currents I1 and I2 are also nearly equal. The
portion of the winding between b and c, which carries the difference of
the currents, can be made of a much smaller conductor, since the
current is much lower.
Under these circumstances, the autotransformer is much cheaper than
the two-coil transformer of the same rating. However, the
disadvantage of the autotransformer is that the primary and secondary
circuits are electrically connected and, therefore, could not safely be
used for stepping down from high voltage to a voltage suitable for
plant loads. The autotransformer, however, is extensively used for
reducing line voltage for step increases in starting larger induction
motors. There are generally four or five taps that are changed by
timers so that more of the winding is added in each step until the full
voltage is applied across the motor. This avoids the large inrush
current required when starting motors at full line voltage. This
transformer is also extensively used for “buck-boost” when the voltage
needs to be stepped up or down only a small percentage. One very
common example is boosting 208 V up from one phase of a 120/208-V
three-phase system, to 220 V for single-phase loads.
2.11 Instrument Transformers
Instrument transformers (figure 10) are used for measuring and control
purposes. They provide currents and voltages proportional to the
primary, but there is less danger to instruments and personnel.

Transformers:
19
Those transformers used to step voltage down are known as potential
transformers (PTs) and those used to step current down are known as
current transformers (CTs).
The function of a PT is to accurately measure voltage on the primary,
while a CT is used to measure current on the primary.
2.12 Potential Transformers
Potential transformers (figure 11) are used with voltmeters,
wattmeters, watt-hour meters, power-factor meters, frequency meters,
synchroscopes and synchronizing apparatus, protective and regulating
relays, and undervoltage and overvoltage trip coils of circuit breakers.
One potential transformer can be used for a number of instruments if
the total current required by the instruments connected to the
secondary winding does not exceed the transformer rating.
Potential transformers are usually rated 50 to 200 volt-amperes at
120 secondary volts. The secondary terminals should never be short
circuited because a heavy current will result, which can damage the
windings.
Figure 10 – Connections of Instrument Transformers.

Transformers:
20
2.13 Current Transformers
The primary of a current transformer typically has only one turn. This
is not really a turn or wrap around the core but just a conductor or bus
going through the “window.” The primary never has more than a very
few turns, while the secondary may have a great many turns,
depending upon how much the current must be stepped down. In most
cases, the primary of a current transformer is a single wire or bus bar,
and the secondary is wound on a laminated magnetic core, placed
around the conductor in which the current needs to be measured, as
illustrated in figure 12.
If primary current exists and the secondary circuit of a CT is
closed, the winding builds and maintains a counter or back
EMF to the primary magnetizing force. Should the secondary
be opened with current in the primary, the counter EMF is removed;
and the primary magnetizing force builds up an extremely high
Potential Transformer in
switchyard.
Inside Potential Transformer
with Fuses.
Figure 11 – Potential Transformers.

Transformers:
21
voltage in the secondary, which is dangerous to personnel and
can destroy the current transformer.
CAUTION:
For this reason, the secondary of a current transformer should
always be shorted before removing a relay from its case or
removing any other device that the CT operates. This protects the
CT from overvoltage.
Current transformers are used with ammeters, wattmeters, power-
factor meters, watt-hour meters, compensators, protective and
regulating relays, and trip coils of circuit breakers. One CT can be
used to operate several instruments, provided the combined loads of
the instruments do not exceed that for which the CT is rated.
Secondary windings are usually rated at 5 amperes. A variety of
current transformers are shown in figure 13. Many times, CTs have
several taps on the secondary winding to adjust the range of current
possible to measure on the primary.
Figure 12 – Current Transformer.

Transformers:
22
2.14 Transformer Taps
Most power transformers have taps on either primary or secondary
windings to vary the number of turns and, thus, the output voltage.
The percentage of voltage change, above or below normal, between
different tap positions varies in different transformers. In oil-cooled
transformers, tap leads are brought to a tap changer, located beneath
the oil inside the tank, or brought to an oil-filled tap changer,
externally located. Taps on dry-type transformers are brought to
insulated terminal boards located inside the metal housing, accessible
by removing a panel.
Some transformers taps can be changed under load, while other
transformers must be de-energized. When it is necessary to change
taps frequently to meet changing conditions, taps that can be changed
under load are used. This is accomplished by means of a motor that
may be controlled either manually or automatically. Automatic
operation is achieved by changing taps to maintain constant voltage as
system conditions change. A common range of adjustment is plus or
Current Transformer in
Switchyard.
Lab Current Transformer.
Current
Transformer in
Switchyard.Figure 13 – Photograph of Current Transformers.

Transformers:
23
minus 10%. At Reclamation powerplants, de-energized tap changers
(DETC) are used and can only be changed with the transformer off-
line. A very few load tap changers (LTC) are used at Grand Coulee
between the 500-kilovolt (kV) (volts x 1,000) and 220-kV
switchyards.
A bypass device is sometimes used across tap changers to ensure
power flow in case of contact failure. This prevents failure of the
transformer in case excessive voltage appears across faulty contacts.
2.15 Transformer Bushings
The two most common types of bushings used on transformers as main
lead entrances are solid porcelain bushings on smaller transformers
and oil-filled condenser bushings on larger transformers.
Solid porcelain bushings consist of high-grade porcelain cylinders that
conductors pass through. Outside surfaces have a series of skirts to
increase the leakage path distance to the grounded metal case. High-
voltage bushings are generally oil-filled condenser type. Condenser
types have a central conductor wound with alternating layers of paper
insulation and tin foil and filled with insulating oil. This results in a
path from the conductor to the grounded tank, consisting of a series of
condensers. The layers are designed to provide approximately equal
voltage drops between each condenser layer.
Acceptance and routine maintenance tests most often used for
checking the condition of bushings are Doble power factor tests. The
power factor of a bushing in good condition will remain relatively
stable throughout the service life. A good indication of insulation
deterioration is a slowly rising power factor. The most common cause
of failure is moisture entrance through the top bushing seal. This
condition will be revealed before failure by routine Doble testing. If
Doble testing is not performed regularly, explosive failure is the
eventual result of a leaking bushing. This, many times, results in a
catastrophic and expensive failure of the transformer as well.

Transformers:
24
2.16 Transformer Polarity
With power or distribution transformers, polarity is important only if
the need arises to parallel transformers to gain additional capacity or to
hook up three single-phase transformers to make a three-phase bank.
The way the connections are made affects angular displacement, phase
rotation, and direction of rotation of connected motors. Polarity is also
important when hooking up current transformers for relay protection
and metering. Transformer polarity depends on which direction coils
are wound around the core (clockwise or counterclockwise) and how
the leads are brought out. Transformers are sometimes marked at their
terminals with polarity marks. Often, polarity marks are shown as
white paint dots (for plus) or plus-minus marks on the transformer and
symbols on the nameplate. These marks show the connections where
the input and output voltages (and currents) have the same
instantaneous polarity.
More often, transformer polarity is shown simply by the American
National Standards Institute (ANSI) designations of the winding leads
as H1, H2 and X1, X2. By ANSI standards, if you face the low-voltage
side of a single-phase transformer (the side marked X1, X2), the H1
connection will always be on your far left. See the single-phase
diagrams in figure 14. If the terminal marked X1 is also on your left, it
is subtractive polarity. If the X1 terminal is on your right, it is additive
polarity. Additive polarity is common for small distribution
transformers. Large transformers, such as GSUs at Reclamation
powerplants, are generally subtractive polarity.
It is also helpful to think of polarity marks in terms of current
direction. At any instant when the current direction is into a polarity
marked terminal of the primary winding, the current direction is out of
the terminal with the same polarity mark in the secondary winding. It
is the same as if there were a continuous circuit across the two
windings.
Polarity is a convenient way of stating how leads are brought out.
If you want to test for polarity, connect the transformer as shown

Transformers:
25
in figure 14. A transformer is said to have additive polarity if,
when adjacent high- and low-voltage terminals are connected and a
voltmeter placed across the other high- and low-voltage terminals,
the voltmeter reads the sum (additive) of the high- and low-voltage
windings. It is subtractive polarity if the voltmeter reads the difference
(subtractive) between the voltages of the two windings. If this test is
conducted, use the lowest AC voltage available to reduce potential
hazards. An adjustable ac voltage source, such as a variac,
is recommended to keep the test voltage low.
2.17 Single-Phase Transformer Connections for Typical
Service to Buildings
Figure 15 shows a typical arrangement of bringing leads out of a
single-phase distribution transformer. To provide flexibility for
connection, the secondary winding is arranged in two sections.
Each section has the same number of turns and, consequently, the
same voltage. Two primary leads (H1, H2) are brought out from the
Figure 14 – Polarity Illustrated.

Transformers:
26
top through porcelain bushings. Three secondary leads (X1, X2, X3)
are brought out through insulating bushings on the side of the tank,
one lead from the center tap (neutral) (X2) and one from each end of
the secondary coil (X1 and X3). Connections, as shown, are typical of
services to homes and small businesses. This connection provides a
three-wire service that permits adequate capacity at minimum cost.
The neutral wire (X2) (center tap) is grounded. A 120-volt circuit is
between the neutral and each of the other leads, and a 240-volt circuit
is between the two ungrounded leads.
2.18 Parallel Operation of Single-Phase Transformers for
Additional Capacity
In perfect parallel operation of two or more transformers, current in
each transformer would be directly proportional to the transformer
capacity, and the arithmetic sum would equal one-half the total
current. In practice, this is seldom achieved because of small
variations in transformers. However, there are conditions for
operating transformers in parallel. They are:
Figure 15 – Single-Phase Transformer.

Transformers:
27
1. Any combination of positive and negative polarity transformers
can be used. However, in all cases, numerical notations must
be followed on both primary and secondary connections. That
is H1 connected to H1, H2 connected to H2, and X1 connected to
X1, X2 connected to X2, X3 connected to X3. Note that each
subscript number on a transformer must be connected to the
same subscript number on the other transformer as shown in
figure 16.
CAUTION:
With positive and negative polarity transformers, the location of X1
and X2 connections on the tanks will be reversed. Care must be
exercised to ensure that terminals are connected, as stated above.
See figure 16.
2. Tap settings must be identical.
3. Voltage ratings must be identical; this, of course, makes the
turns ratios also identical.
4. The percent impedance of one transformer must be between
92½% and 107½% of the other. Otherwise,
circulating currents between the two transformers would be
excessive.
Figure 16 – Single-Phase Paralleling.

Transformers:
28
5. Frequencies must be identical. Standard frequency in the
United States is 60 hertz and usually will not present a
problem.
One will notice, from the above requirements, that paralleled
transformers do not have to be the same size. However, to meet the
percent impedance requirement, they must be nearly the same size.
Most utilities will not parallel transformers if they are more than one
standard kVA size rating different from each other; otherwise,
circulating currents are excessive.
2.19 Three-Phase Transformer Connections
Three-phase power is attainable with one three-phase transformer,
which is constructed with three single-phase units enclosed in the same
tank or three separate single-phase transformers. The methods of
connecting windings are the same, whether using the one three-phase
transformer or three separate single-phase transformers.
2.20 Wye and Delta Connections
The two common methods of connecting three-phase generators,
motors, and transformers are shown in figure 17. The method shown
in at figure 17a is known as a delta connection, because the diagram
bears a close resemblance to the Greek letter ), called delta.
The other method, figure 17b, is known as the star or wye connection.
The wye differs from the delta connection in that it has two phases in
series. The common point “O” of the three windings is called the
neutral because equal voltages exist between this point and any of the
three phases.
When windings are connected wye, the voltage between any two lines
will be 1.732 times the phase voltage, and the line current will be the
same as the phase current. When transformers are connected delta, the
line current will be 1.732 times the phase current, and the voltage
between any two will be the same as that of the phase voltage.

Transformers:
29
2.21 Three-Phase Connections Using Single-Phase
Transformers
As mentioned above, single-phase transformers may be connected to
obtain three-phase power. These are found at many Reclamation
facilities, at shops, offices, and warehouses. The same requirements
must be observed as in section 2.18, “Parallel Operation of Single-
phase Transformers for Additional Capacity,” with one additional
requirement—in the manner connections are made between individual
single-phase units. ANSI standard connections are illustrated below in
the following figures. There are other angular displacements that will
work but are seldom used. Do not attempt to connect single-phase
units together in any combination that does keep the exact angular
displacement on both primary and secondary; a dangerous short circuit
could be the result. Additive and subtractive polarities can be mixed
(see the following figures). These banks also may be paralleled for
additional capacity if the rules are followed for three-phase paralleling
discussed below. When paralleling individual three-phase units or
single-phase banks to operate three phase, angular displacements must
be the same.
Figure 18 shows delta-delta connections. Figure 19 shows wye-wye
connections, which are seldom used at Reclamation facilities, due to
Figure 17 – Three-Phase Connections.

Transformers:
30
Figure 18 – Delta-Delta Connections, Single-Phase Transformers for
Three-Phase Operation.

Transformers:
31
Figure 19 – Wye-Wye Connections, Using Single-Phase Transformers
for Three-Phase Operation.
Note: These connections are seldom used because of 3
rd
harmonic
problems.

Transformers:
32
inherent third harmonic problems. Methods of dealing with the third
harmonic problem by grounding are listed below.
However, it is easier just to use another connection scheme (i.e., delta-
delta, wye-delta, or delta-wye [figure 20]), to avoid this problem
altogether. In addition, these schemes are much more familiar to
Reclamation personnel.
2.22 Paralleling Three-Phase Transformers
Two or more three-phase transformers, or two or more banks made up
of three single-phase units, can be connected in parallel for additional
capacity. In addition to requirements listed above for single-phase
transformers, phase angular displacements (phase rotation) between
high and low voltages must be the same for both. The requirement for
identical angular displacement must be met for paralleling any
combination of three-phase units and/or any combination of banks
made up of three single-phase units.
CAUTION:
This means that some possible connections will not work and
will produce dangerous short circuits. See table 2 below.
For delta-delta and wye-wye connections, corresponding voltages
on the high-voltage and low-voltage sides are in phase. This is
known as zero phase (angular) displacement. Since the displacement
is the same, these may be paralleled. For delta-wye and wye-delta
connections, each low-voltage phase lags its corresponding high-
voltage phase by 30 degrees. Since the lag is the same with
both transformers, these may be paralleled. A delta-delta, wye-
wye transformer, or bank (both with zero degrees displacement)
cannot be paralleled with a delta-wye or a wye-delta that has
30 degrees of displacement. This will result in a dangerous short

Transformers:
33
Figure 20 – Delta-Wye and Wye-Delta Connections Using Single-
Phase Transformers for Three-Phase Operation.
Note: Connections on this page are the most common and should
be used if possible.

Transformers:
34
circuit. Table 1 shows the combinations that will operate in parallel,
and table 2 shows the combinations that will not operate in parallel.
Table 1 – Operative Parallel Connections of Three-Phase Transformers
OPERATIVE PARALLEL CONNECTIONS
LOW-VOLTAGE SIDES HIGH-VOLTAGE SIDES
Trans. A Trans. B Trans. A Trans. B
1 Delta Delta Delta Delta
2 Y Y Y Y
3 Delta Y Delta Y
4 Y Delta Y Delta
5 Delta Delta Y Y
6 Delta Y Y Delta
7 Y Y Delta Delta
8 Y Delta Delta Y
Table 2 – Inoperative Parallel Connections of Three-Phase Transformers
INOPERATIVE PARALLEL CONNECTIONS
LOW-VOLTAGE SIDE HIGH-VOLTAGE SIDE
Trans. A Trans. B Trans. A Trans. B
1 Delta Delta Delta Y
2 Delta Delta Y Delta
3 Y Y Delta Y
4 Y Y Y Delta
Wye-wye connected transformers are seldom, if ever, used to supply
plant loads or as GSU units, due to the inherent third harmonic
problems with this connection. Delta-delta, delta-wye, and wye-delta
are used extensively at Reclamation facilities. Some rural electric
associations use wye-wye connections that may be supplying

Transformers:
35
Reclamation structures in remote areas. There are three methods to
negate the third harmonic problems found with wye-wye connections:
1. Primary and secondary neutrals can be connected together and
grounded by one common grounding conductor.
2. Primary and secondary neutrals can be grounded individually
using two grounding conductors.
3. The neutral of the primary can be connected back to the neutral
of the sending transformer by using the transmission line
neutral.
In making parallel connections of transformers, polarity markings
must be followed. Regardless of whether transformers are additive or
subtractive, connections of the terminals must be made according to
the markings and according to the method of the connection (i.e., delta
or wye).
CAUTION:
As mentioned above regarding paralleling single-phase units,
when connecting additive polarity transformers to subtractive
ones, connections will be in different locations from one
transformer to the next.
2.23 Methods of Cooling
Increasing the cooling rate of a transformer increases its capacity.
Cooling methods must not only maintain a sufficiently low average
temperature but must prevent an excessive temperature rise in any
portion of the transformer (i.e., it must prevent hot spots). For this
reason, working parts of large transformers are usually submerged in
high-grade insulating oil. This oil must be kept as free as possible
from moisture and oxygen, dissolved combustible gases, and
particulates.

Transformers:
36
Ducts are arranged to provide
free circulation of oil through
the core and coils; warmer
and lighter oil rises to the
top of the tank, cooler and
heavier oil settles to the
bottom. Several methods
have been developed
for removing heat that is
transmitted to the transformer
oil from the core and windings
(figure 21).
2.24 Oil-Filled – Self-Cooled Transformers
In small- and medium-sized transformers, cooling takes place by direct
radiation from the tank to surrounding air. In oil-filled, self-cooled
types, tank surfaces may be corrugated to provide a greater radiating
surface. Oil in contact with the core and windings rises as it absorbs
heat and flows outward and downward along tank walls, where it is
cooled by radiating heat to the surrounding air. These transformers
may also have external radiators attached to the tank to provide greater
surface area for cooling.
2.25 Forced-Air and Forced-Oil-Cooled Transformers
Forced-air-cooled transformers have fan-cooled radiators through
which the transformer oil circulates by gravity, as shown in figure 22a.
Fans force air through radiators, cooling the oil.
Forced-air/oil/water-cooled transformers have a self-cooled (kVA
or MVA) rating and one or more forced cooling ratings (higher kVA
or MVA). Higher ratings are due to forced cooling in increasing
amounts. As temperature increases, more fans or more oil pumps
are turned on automatically.
Figure 21 – Cooling.

Transformers:
37
The forced-cooling principle is based on a tradeoff between extra
cooling and manufacturing costs. Transformers with forced-cooling
have less weight and bulk than self-cooled transformers with the same
ratings. In larger-sized transformers, it is more economical to add
forced cooling, even though the electricity needed to operate fans and
pumps increases the operating cost.
2.26 Transformer Oil
In addition to dissipating heat due to losses in a transformer, insulating
oil provides a medium with high dielectric strength in which the coils
and core are submerged. This allows the transformers to be more
compact, which reduces costs.
Insulating oil in good condition will withstand far more voltage across
connections inside the transformer tank than will air. An arc would
jump across the same spacing of internal energized components at a
much lower voltage if the tank had only air. In addition, oil conducts
heat away from energized components much better than air.
Over time, oil degrades from normal operations, due to heat and
contaminants. Oil cannot retain high dielectric strength when exposed
to air or moisture. Dielectric strength declines with absorption of
moisture and oxygen. These contaminants also deteriorate the paper
Figure 22 – Forced-Air/Oil/Water-Cooled Transformers.

Transformers:
38
insulation. For this reason, efforts are made to prevent insulating oil
from contacting air, especially on larger power transformers. Using a
tightly sealed transformer tank is impractical, due to pressure
variations resulting from thermal expansion and contraction of
insulating oil. Common systems of sealing oil-filled transformers are
the conservator with a flexible diaphragm or bladder or a positive-
pressure inert-gas (nitrogen) system. Reclamation GSU transformers
are generally purchased with conservators, while smaller station
service transformers have a pressurized nitrogen blanket on top of oil.
Some station service transformers are dry-type, self-cooled or forced-
air cooled.
2.27 Conservator System
A conservator is connected by piping to the main transformer tank that
is completely filled with oil. The conservator also is filled with oil and
contains an expandable bladder or diaphragm between the oil and air
to prevent air from contacting the oil. Figure 23 is a schematic
Figure 23 – Conservator with Bladder.

Transformers:
39
representation of a conservator system (figure 1 is an actual photo of a
conservator). Air enters and exits the space above the bladder/
diaphragm as the oil level in the main tank goes up and down with
temperature. Air typically enters and exits through a desiccant-type air
dryer that must have the desiccant replaced periodically. The main
parts of the system are the expansion tank, bladder or diaphragm,
breather, vent valves, liquid-level gauge and alarm switch. Vent
valves are used to vent air from the system when filling the unit with
oil. A liquid-level gauge indicates the need for adding or removing
transformer oil to maintain the proper oil level and permit flexing of
the diaphragm. These are described in detail in section 4.4.
2.28 Oil-Filled, Inert-Gas System
A positive seal of the transformer oil may be provided by an inert-gas
system. Here, the tank is slightly pressurized by an inert gas such as
nitrogen.
The main tank gas space above the oil is provided with a pressure
gauge (figure 24). Since the entire system is designed to exclude air, it
must operate with a positive pressure in the gas space above the oil;
otherwise, air will be admitted in the event of a leak. Smaller station
service units do not have nitrogen tanks attached to automatically add
gas, and it is common practice to add nitrogen yearly each fall as the
tank starts to draw partial vacuum, due to cooler weather. The excess
gas is expelled each summer as loads and temperatures increase.
Some systems are designed to add nitrogen automatically (figure 24)
from pressurized tanks when the pressure drops below a set level. A
positive pressure of approximately 0.5 to 5 pounds per square inch
(psi) is maintained in the gas space above the oil to prevent ingress of
air. This system includes a nitrogen gas cylinder; three-stage,
pressure-reducing valve; high-and low-pressure gauges; high- and
low-pressure alarm switch; an oil/condensate sump drain valve; an
automatic pressure-relief valve; and necessary piping.

Transformers:
40
The function of the three-stage, automatic pressure-reducing valves is
to reduce the pressure of the nitrogen cylinder to supply the space
above the oil at a maintained pressure of 0.5 to 5 psi.
The high-pressure gauge normally has a range of 0 to 4,000 psi and
indicates nitrogen cylinder pressure. The low-pressure gauge normally
has a range of about -5 to +10 psi and indicates nitrogen pressure
above the transformer oil.
In some systems, the gauge is equipped with high- and low-pressure
alarm switches to alarm when gas pressure reaches an abnormal value;
the high-pressure gauge may be equipped with a pressure switch to
sound an alarm when the supply cylinder pressure is running low.
Figure 24 – Typical Transformer Nitrogen System.

Transformers:
41
A sump and drain valve provide a means for collecting and removing
condensate and oil from the gas. A pressure-relief valve opens and
closes to release the gas from the transformer and, thus, limit the
pressure in the transformer to a safe maximum value. As temperature
of a transformer rises, oil expands, and internal pressure increases,
which may have to be relieved. When temperature drops, pressure
drops, and nitrogen may have to be added, depending on the extent of
the temperature change and pressure limits of the system. The
pressurized gas system is discussed in detail in section 4.9.1.3.
2.29 Indoor Transformers
When oil-insulated transformers are located indoors, because of fire
hazard, it is often necessary to isolate these transformers in a fireproof
vault.
Today, dry-type transformers are used extensively for indoor
installations. These transformers are cooled and insulated by air and
are not encased in sealed tanks like liquid-filled units. Enclosures in
which they are mounted must have sufficient space for entrance, for
circulation of air, and for discharge of hot air. Dry-type transformers
are enclosed in sheet metal cases with a cool air entrance at the bottom
and a hot air discharge near the top. They may or may not have fans
for increased air flow.
In addition to personnel hazards, indoor transformer fires are
extremely expensive and detrimental to plants, requiring extensive
cleanup, long outages, and lost generation. Larger indoor
transformers, used for station service and generator excitation, should
have differential relaying so that a fault can be interrupted quickly
before a fire can ensue. Experience has shown that transformer
protection by fuses alone is not adequate to prevent fires in the event
of a short circuit.

Transformers:
42
3. Routine Maintenance
The following chapters address routine maintenance, as well as
specific testing and diagnostic techniques and tools used to assess the
condition of transformers (more detail is included for oil-filled power
transformers). Some processes are often above and beyond routine
maintenance work to keep the transformer operational. Transformer
diagnostics require specialized equipment and training. This expertise
is not expected to be maintained in every office. In some cases, it may
be necessary to contact diagnostics specialists, either inside or outside
Reclamation, who have the latest equipment and recent experience.
Figure 25 shows the overall transformer condition assessment
methodology, linking routine maintenance and diagnostics.
3.1 Introduction to Reclamation Transformers
Standards organizations such as American National Standards
Institute/Institute of Electrical and Electronic Engineers (ANSI/IEEE)
consider average GSU transformer life to be 20 to 25 years. This
estimate is based on continuous operation at rated load and service
conditions with an average ambient temperature of 40 ºC (104 degrees
Fahrenheit [ºF]) and a temperature rise of 65 ºC. This estimate is also
based on the assumption that transformers receive adequate
maintenance over their service life [26]. Reclamation, Bonneville
Power Administration, and Western Area Power Administration
conduct regular studies to determine statistical equipment life. These
studies show that average life of a Reclamation transformer is
40 years. Reclamation gets longer service than IEEE estimates
because of operating at lower ambient temperatures and with lower
loads. A significant number of transformers were purchased in the
1940s, 1950s, and into the 1970s. Several have been replaced, but
Reclamation has many transformers that are nearing, or are already
well past, their anticipated service life. We should expect transformer
replacement and failures to increase, due to this age factor.

Transformers:
43
Figure 25 – Transformer Diagnostics Flowchart.

Transformers:
44
Current minimum replacement time is around 14 months; a
more realistic time may be 18 months to 2 years. In the future,
lead times may extend well beyond what they are today.
Therefore, high-quality maintenance and accurate diagnostics
are important for all transformers, but it is absolutely essential for
older ones—especially for critical transformers that would cause
loss of generation. It is also very important to consider providing
spares for critical transformers.
3.2 Transformer Cooling Methods Introduction
Heat is one of the most common destroyers of transformers. Operation
at only 8 ºC above the transformer rating will cut transformer life by
50%. Heat is caused by internal losses, due to loading, high ambient
temperature, and solar radiation. It is important to understand how
your particular transformers are cooled and how to detect problems in
the cooling systems. ANSI and IEEE require the cooling class of each
transformer to appear on its nameplate. Cooling classifications, with
short explanations, appear in sections 3.3 and 3.4. The letters of the
class designate inside atmosphere and type or types of cooling. In
some transformers, more than one class of cooling and load rating is
indicated. At each step of additional cooling, the rating increases to
correspond with increased cooling. Note that the letter “A” indicates
air, “FA” indicates forced air (fans), “O” indicates oil, “FO” indicates
forced oil (pumps), “G” indicates some type of gas, and “W” indicates
there is a water/oil heat exchanger.

Transformers:
45
DRY-TYPE TRANSFORMER MAINTENANCE SUMMARY
(See Section 3.3.)
When new after
energizing and
allowing
temperature and
loading to
stabilize
• Do an infrared scan and compare with temperature gauge, if any.
• If transformer is gas filled (nitrogen [N2]), check pressure gauge
against data sheets; never allow gas pressure to fall below 1 psi.
• Check loading and compare with nameplate rating.
• Functionally test fans and controls for proper operation.
• Functionally test temperature alarms and annunciator points.
• Check area around transformer - clear of debris and parts storage.
• Check transformer room for proper ventilation.
After 1 week of
operation at
normal loading
• Perform infrared scan and compare with temperature gauge, if any.
• Check temperature gauge, if any, and compare with nameplate rating.
• Check loading and compare with nameplate rating.
Annually
(Note: The time
between these
periodic
inspections may
be increased if
the first internal
inspection of
windings and
connections are
clean and in
good condition
and if loading is
at or below
nameplate
rating.)
• Perform an infrared scan before de-energizing.
• De-energize and remove panels for internal inspection.
• If possible, re-energize, re-load, and do infrared (IR) inspection for hot
spots and loose connections.
• Use vacuum to remove as much dirt as possible.
• After vacuuming, use low-pressure, dry air (20 to 25 psi) to blow off
remaining dirt. Caution: Make sure air is dry.
• Check for discolored copper and discolored insulation (indicates
overheating).
• Check tap changer and tap connections.
• Check for corroded and loose connections.
• Check for loose iron and damaged coils.
• Check for carbon tracking on insulation and insulators.
• Check for adequate electrical clearance.
• Check for cracked, chipped, and loose insulators.
• Check base or support insulators, including vibration isolation supports.
• If windings are found dirty, add filter material to air intake ports.
• Megger®
high side windings to low side windings and both high and low
side to ground.
• Do a turns ratio test if electrical problems are found or suspected.
• Check fan blades for cleanliness; remove dirt and dust.
• Check fans, controls, alarms, and annunciator points.
• Check pressure gauge on N2 filled transformers; compare with weekly
data sheets; never allow pressure to fall below 1 psi.
• Check all bolted connections with wrenches or sockets for tightness.
• Check for loose mounting for windings.
• Check primary, secondary, and ground connections.
• Repair all problems found in above inspections.
3.3 Dry-Type Transformers
Cooling classes of dry-type transformers are covered by ANSI/IEEE
standard C57.12.01 Section 5.1 [1]. A short explanation of each class
is given below.

Transformers:
46
1. Class AA transformers are ventilated and self-cooled. This
means there are ventilation ports located in outside walls of the
transformer enclosure. There are no fans to force air into and
out of the enclosure, with typically no external fins or radiators.
Cooler air enters the lower ports, is heated as it rises past
windings, and exits the upper ventilation ports. (Although it is
not repeated below; it is obvious that, in every cooling class,
some heat is also removed by natural circulation of air around
the outside of the enclosure.)
2. Class AFA transformers are self-cooled (A) and additionally
cooled by forced circulation of air (FA). This means that there
are ventilation ports for fan inlets and outlets only. (Inlets are
usually filtered.) Normally, there are no additional ventilation
ports for natural air circulation.
3. Class AA/FA transformers are ventilated and self-cooled (same
as Class AA in item 1). In addition, they have a fan or fans
providing additional forced-air cooling. Fans may be wired to
start automatically when the temperature reaches a pre-set
value. These transformers generally have a dual load rating—
one for AA (self-cooling natural air flow) and a larger load
rating for FA (forced air flow).
4. Class ANV transformers are self-cooled (A), non-ventilated
(NV) units. The enclosure has no ventilation ports or fans and
is not sealed to exclude migration of outside air, but there are
no provisions to intentionally allow outside air to enter and
exit. Cooling is by natural circulation of air around the
enclosure. This transformer may have some type of fins
attached outside the enclosure to increase surface area for
additional cooling.
5. Class GA transformers are sealed with a gas inside (G) and are
self-cooled (A). The enclosure is hermetically sealed to
prevent leakage. These transformers typically have a gas,
such as nitrogen or freon, to provide high dielectric and
good heat removal. Cooling occurs by natural circulation of
air around the outside of the enclosure. There are no fans

Transformers:
47
to circulate cooling air; however, there may be fins attached
to the outside to aid in cooling.
3.3.1 Potential Problems and Remedial Actions for Dry-Type
Transformer Cooling Systems [15]
It is important to keep transformer enclosures reasonably clean. It is
also important to keep the area around them clear. Any items near or
against the transformer impede heat transfer to cooling air around the
enclosure. As dirt accumulates on cooling surfaces, it becomes more
and more difficult for air around the transformer to remove heat. As a
result, over time, the transformer temperature slowly rises unnoticed,
reducing service life.
Transformer rooms and vaults should be ventilated. Portable fans
(never water) may be used for additional cooling if necessary. A fan
rated at about 100 cubic feet per minute (cfm) per kilowatt (kW) of
transformer loss [6], located near the top of the room to remove hot
air, will suffice. These rooms/vaults should not be used as storage.
When the transformer is new, check the fans and all controls for
proper operation. After it has been energized and the loading and
temperature are stable, check the temperature with an infrared (IR)
camera and compare loading with the nameplate. Repeat the
temperature checks after 1 week of operation.
Once each year under normal load, check transformer temperatures
with an IR camera [4, 8]. If the temperature rise (above ambient) is
near or above nameplate rating, check for overloading. Check the
temperature alarm for proper operation. Check enclosures and
vaults/rooms for dirt accumulation on transformer surfaces and debris
near or against enclosures. Remove all items near enough to affect air
circulation. To avoid dust clouds, a vacuum should first be used to
remove excess dirt. Low-pressure (20 to 25 psi), dry compressed air
may be used for cleaning after most dirt has been removed by vacuum.
The transformer must be de-energized before this procedure, unless it

Transformers:
48
is totally enclosed and there are no exposed energized conductors.
Portable generators may be used for lighting.
After de-energizing the transformer, remove access panels and inspect
windings for dirt- and heat-discolored insulation and structure pro-
blems [15]. It is important that dirt not be allowed to accumulate on
windings because it impedes heat removal and reduces winding life. A
vacuum should be used for the initial winding cleaning, followed by
compressed air [8]. Care must be taken to ensure the compressed air is
dry to avoid blowing moisture into windings. Air pressure should not
be greater than 20 to 25 psi to avoid imbedding small particles into
insulation. After cleaning, look for discolored copper and insulation,
which indicates overheating. If discoloration is found, check for loose
connections. If there are no loose connections, check the cooling paths
very carefully and check for overloading after the transformer has been
re-energized. Look for carbon tracking and cracked, chipped, or loose
insulators. Look for and repair loose clamps, coil spacers, deteriorated
barriers, and corroded or loose connections.
Check fans for proper operation, including controls, temperature
switches, and alarms. Clean fan blades and filters if needed. A dirty
fan blade or filter reduces cooling air flow over the windings and
reduces service life. If ventilation ports do not have filters, they may
be fabricated from home furnace filter material. Adding filters is only
necessary if the windings are dirty upon yearly inspections.
3.4 Liquid-Immersed Transformers
Cooling classes of liquid-immersed transformers are covered by IEEE
C57.12.00 Section 5.1 [2]. A short explanation of each class follows.
3.4.1 Liquid-Immersed, Air-Cooled
There are three classes in this category.
1. Class OA: Oil-immersed, self-cooled. Transformer windings
and core are immersed in some type of oil and are self-cooled

Transformers:
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OIL-FILLED TRANSFORMER MAINTENANCE SUMMARY
Task
After 1 Month of
Service Annually 3 to 5 Years
Before energizing,
inspect and test all
controls, wiring, fans,
alarms, and gauges.
In-depth inspection of
transformer and
cooling system;check
for leaks and proper
operation.
Do a dissolved gas
analysis (DGA).
Oil pumps load current,
oil flow indicators, fans,
etc. See 3.4.6 and 4.
Thermometers 4.2 and
4.3. Heat exchangers.
Transformer tank 4.1.
Oil level gauges 4.4.
Pressure relief 4.5.
Do a DGA.
Oil pumps load current, oil
flow indicators, fans etc. See
3.4.6 and 4.
Thermometers 4.2.
Heat exchangers 4.2 and 4.3.
Transformer tank 4.1.
Pressure relief 4.6.
Do a DGA.
Check diaphragm or
bladder for leaks if there is
a conservator. See 4.9.
IR scan of transformer
cooling system,
bushings, and all
wiring.
See 3.4.5.7 and 4.8. See 3.4.5.7 and 4.8.
Test all controls,
relays, gauges; test
alarms and
annunciator points.
See all of section 4. Inspect pressure relief for
leaks and indication for
operation (rod extension).
See 4.5.
Thermometers. See 4.2
and 4.3.
Inspect pressure relief 4.5.
Sudden pressure relay 4.6.
Buchholz relay 4.7.
Test alarms, fan, and
pump controls, etc.
See 3.4.6.
Inspect transformer
bushings.
Check with binoculars
for cracks and chips;
look for oil leaks and
check oil levels;
IR scan. See 4.8.
Check with binoculars for
cracks and chips, look
carefully for oil leaks and
check oil levels IR scan. See
4.8.
In-depth inspection of
bushings;
cleaning/waxing if
needed.
Close physical inspection,
cleaning/ waxing, and
Doble testing, in addition
to other listed inspections.
See 4.8.
Doble test transformer
and bushings.
Doble test transformer
and bushings before
energizing. See 4.8,
9.3.
See 4.8 and 9.3.
Inspect pressure
controls if there is
nitrogen over oil in
transformer; inspect
pressure gauge.
See 4.9.2. See 4.9.2. Also see 4.9.1 to
test pressure gauge if
transformer has N2 over oil
with no means to
automatically add N2.

Transformers:
50
by natural circulation of air around the outside enclosure. Fins
or radiators may be attached to the enclosure to aid in cooling.
2. Class OA/FA: Liquid-immersed, self-cooled/forced air-cooled.
Same as OA, with the addition of fans. Fans are usually
mounted on radiators. The transformer typically has two load
ratings: one with the fans off (OA) and a larger rating with
fans operating (FA). Fans may be wired to start automatically
at a pre-set temperature.
3. Class OA/FA/FA: Liquid-immersed, self-cooled/forced
air-cooled/forced air-cooled. Same as OA/FA, with an
additional set of fans. There typically will be three load ratings
corresponding to each increment of cooling. Increased ratings
are obtained by increasing cooling air over portions of the
cooling surfaces. Typically, there are radiators attached to the
tank to aid in cooling. The two groups of fans may be wired to
start automatically at pre-set levels as temperature increases.
There are no oil pumps. Oil flows through the transformer
windings by the natural principle of convection (heat rising).
3.4.2 Liquid-Immersed, Air-Cooled/Forced Liquid-Cooled
There are two classes in this group.
1. Class OA/FA/FOA: Liquid-immersed, self-cooled/forced air-
cooled/forced liquid, and forced air-cooled. Windings and core
are immersed in some type of oil. This transformer typically
has radiators attached to the enclosure. The transformer has
self-cooling (OA) natural ventilation, forced air-cooling FA
(fans), and forced oil-cooling (pumps) with additional forced
air-cooling (FOA) (more fans). The transformer has three load
ratings corresponding to each cooling step. Fans and pumps
may be wired to start automatically at pre-set levels as
temperature increases (figure 26).
2. Class OA/FOA/FOA: Liquid-immersed, self-cooled/forced
oil, and forced air-cooled/forced oil, and forced air-cooled.
Cooling controls are arranged to start only part of the oil

Transformers:
51
pumps and part of the fans for the first load rating/temperature
increase, and the remaining pumps and fans for the second load
rating increase. The nameplate will show at least three load
ratings.
3.4.3 Liquid-Immersed, Water-Cooled
This category has two classes:
1. Class OW: Transformer coil and core are immersed in oil.
Typically, an oil/water heat exchanger (radiator) is attached to
the outside of the tank. Cooling water is pumped through the
heat exchanger, but the oil flows only by natural circulation.
As oil is heated by the windings, it rises to the top and exits
through piping to the radiator. As oil is cooled, it descends
through the radiator and re-enters the transformer tank at the
bottom.
Figure 26 – Typical Oil Flow.

Transformers:
52
2. Class OW/A: Transformer coil and core are immersed in oil.
This transformer has two ratings. Cooling for one rating (OW)
is obtained as in item 1. above. The self-cooled rating (A) is
obtained by natural circulation of air over the tank and cooling
surfaces.
3.4.4 Liquid-Immersed, Forced Liquid-Cooled
This category has two classes:
1. Class FOA: Liquid-immersed, forced liquid-cooled with
forced air-cooled. This transformer normally has only one
rating. The transformer is cooled by pumping oil (forced oil)
through a radiator normally attached to the outside of the tank.
Also, air is forced by fans over the cooling surface.
2. Class FOW: Liquid-immersed, forced liquid-cooled, water
cooled. This transformer is cooled by an oil/water heat
exchanger normally mounted separately from the tank. Both
the transformer oil and the cooling water are pumped (forced)
through the heat exchanger to accomplish cooling.
3.4.5 Potential Problems and Remedial Actions for Liquid-Filled
Transformer Cooling Systems
3.4.5.1 Leaks – Tanks and radiators may develop oil leaks,
especially at connections. To repair a leak in a radiator core, you must
remove the radiator. Small leaks may also develop in headers or
individual pipes. These small leaks possibly may be stopped by
peening with a ball peen hammer. Some manufacturer’s field
personnel try to stop leaks by using a two-part epoxy while the
transformer is under vacuum. Do not try this unless the transformer
has been drained, because a vacuum may cause bubbles to form in the
oil that can lodge in the winding and cause arcing. Some contractors
will stop leaks by forcing epoxy into the leak area under pressure.
This procedure has been successful in many cases and may be
performed while the transformer is online. When all else fails, the leak
may be welded with oil still in the radiator if proper precautions are

Transformers:
53
carefully observed [3, 4]. Welding with oil inside will cause gases to
form in the oil. Take an oil sample for a dissolved gas analysis (DGA)
before welding and 24 hours after re-energizing to identify gas
increases due to welding. If the leak is bad enough, the tank may have
to be drained so the leak can be repaired. Treat leaks carefully; do not
ignore them. Oil leaks are serious maintenance and environmental
issues and should be corrected. See Power Equipment Bulletin 23 for
further information on leak remediation.
3.4.5.2 Cleaning Radiators – Radiators may need to be
cleaned in areas where deposits appear on pipes and headers. Dirt and
deposits hamper heat transfer to the cooling air. Finned radiators must
be cleaned with compressed air when they become dirty.
3.4.5.3 Plugged Radiators – After 1 month of service and
yearly, perform an IR scan and physical inspection of radiators and
transformer tanks [4, 8]. Partially plugged radiators will be cooler
than those performing normally. You may also feel the radiator pipes
by hand. Plugged radiator sections or individual pipes/plenums will be
noticeably cooler; however, you will not be able to reach all of them.
Radiators may become plugged with sludge or foreign debris; this
usually occurs in water tubes on the oil/water heat exchanger. Do not
forget to check the bleed line for two-walled heat exchangers.
If plugged radiators are discovered, they must be corrected as soon as
possible. Some radiators are attached to the main tank with flanges
and have isolating valves. These may be removed for cleaning and/or
leak repair without draining oil from the transformer. If radiators are
attached directly to the main tank without isolating valves, oil must be
drained before cleaning them. If radiators are plugged with sludge, the
transformer probably is sludged up also. In this case, the oil should be
reprocessed and the transformer cleaned internally. Competent
contractors should be obtained if this is necessary.
3.4.5.4 Sludge Formation – If temperature seems to be slowly
increasing while the transformer is operating under the same load,

Transformers:
54
check the DGA for moisture, oxygen, acid number, and the interfacial
tension (IFT). The combination of oxygen and moisture causes
sludging, which may be revealed by a low IFT number and/or acid
number. Sludge will slowly build up on windings and core, and the
temperature will increase over time.
3.4.5.5 Valve Problems – If your transformer has isolating
valves for radiators, check to make sure they are fully open on both top
and bottom of the radiators. A broken valve stem may cause the valve
to be fully or partially closed, but it will appear that the valve is open.
3.4.5.6 Mineral Deposits – Don’t even think about spraying
water on the radiators or tank to increase cooling, except in the most
dire emergency. Minerals in the water will deposit on radiators as
water evaporates and are almost impossible to remove. These
minerals will reduce the efficiency of cooling still further. Using
additional fans to blow air on radiators and/or the transformer tank is a
better alternative [4].
3.4.5.7 Low Oil Level – One IR scan performed on a
transformer running at higher than normal temperature revealed that
the oil level was below the upper radiator inlet pipe, which prevented
oil circulation. The oil level indicator was defective and stuck on
normal. These indicators must be tested, as mentioned below.
3.4.6 Cooling System Inspections
After 1 month of service and yearly, inspect and test the fans. Look at
the fans whenever you are around transformers in the switchyard or in
the powerplant. If it is a hot day and transformers are loaded, all the
fans should be running. If one fan is stopped and the rest of the group
is running, the inactive fan should be repaired. During an inspection,
the temperature controller should be adjusted to start all the fans.
Listen for unusual noises from fan bearings and loose blades and
repair or replace faulty fans. Bad bearings can also be detected with
an IR scan if the fans are running.

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After 1 month of service and yearly, inspect and test the oil pumps.
Inspect piping and connections for leaks. Override the temperature
controller so that the pump starts. Check the oil pump motor current
on all three phases with an accurate ammeter; this will give an
indication if oil flow is correct and if unusual wear is causing
additional motor loading. Record this information for later
comparison, especially if there is no oil flow indicator. If the motor
load current is low, something is causing low oil flow. Carefully
inspect all valves to make sure they are fully open. A valve stem may
break and leave the valve partially or fully closed, even though the
valve handle indicates the valve is fully open. Pump impellers have
been found loose on the shaft, reducing oil flow. Sludge buildup or
debris in lines can also cause low oil flow. If motor load current is
high, this may indicate impeded pump rotation. Listen for unusual
noises. Thrust bearing wear results in the impeller advancing on the
housing. An impeller touching the housing makes a rubbing sound,
which is different from the sound of a failing motor bearing. If this is
heard, remove the pump motor from the housing and check impeller
clearance. Replace the thrust bearing if needed, and replace the motor
bearings if the shaft has too much play or if noise is unusual.
Three-phase pumps will run and pump some oil even if they are
running backwards. Vane type oil-flow meters will indicate flow on
this low amount. The best indication of pump running backwards is
that sometimes the pump will be very noisy. The motor load current
may also be lower than for full load. If this is suspected, due to the
extra noise and higher transformer temperature, the pump should be
checked for proper rotation. Reverse two phase leads if this is
encountered. [4]
After 1 month of service and yearly, check the oil flow indicator. It
has a small paddle which extends into the oil stream and may be either
on the suction or discharge side of the pump. A very low flow of only
about 5-feet-per-second velocity causes the flag to rotate, which
indicates normal flow. Flow can be too low, and the indicator will still
show flow. If there is no flow, a spring returns the flag to the off

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position, and a switch provides an alarm. With control power on the
switch, open the pump circuit at the motor starter and make sure the
correct alarm point activates when the pump stops. Check that the
pointer is in the right position when the pump is off and when it is
running. Pointers can stick and fail to provide an alarm when needed.
Oil flow may also be checked with an ultrasonic flowmeter.
Ultrasonic listening devices can detect worn bearings, rubbing
impellers, and other unusual noises from oil pumps.
Pumps can pull air in through gaskets on the suction side of the pumps.
The suction (vacuum) on the intake side of the pump can pull air
through gaskets that are not tight. Pump suction has also been known
to pull air through packing around valve stems in the suction side
piping. This can result in dangerous bubbles in the transformer oil and
may cause the gas detector or Buchholz relay to operate. Dissolved
gas analysis will show a big increase in oxygen and nitrogen content
[4]. High oxygen and nitrogen content can also be caused by gasket
leaks elsewhere.
After 1 month of service and yearly, inspect water-oil heat exchangers.
Test and inspect the pumps, as mentioned above. Look for and repair
leaks in piping and heat exchanger body. Examine the latest dissolved
gas analysis results for dissolved moisture and free water. If free
water is present and there are no gasket leaks, the water portion of the
water-oil heat exchanger must be pressure tested. A leak may have
developed, allowing water to migrate into the transformer oil, which
can destroy the transformer. If the heat exchanger piping is double
walled, check the drain for water or oil; check manufacturer’s
instruction manual.
4. Oil-Filled Transformer Inspections
A transformer maintenance program must be based on thorough
routine inspections. These inspections must take place in addition to
normal daily/weekly data gathering trips to check oil levels and

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temperatures. Some monitoring may be done remotely using
supervisory control and data acquisition (SCADA) systems, but this
can never substitute for thorough inspections by competent
maintenance or operations people.
After 1 month of service, and once each year, make an indepth
inspection of oil-filled transformers. Before beginning, carefully
inspect the temperature and oil level data sheets. If temperature,
pressure, or oil level gauges never change, even with seasonal
temperature and loading changes, something is wrong. The gauge may
be stuck, or data sheets may have been filled in incorrectly. Examine
the DGAs for evidence of leaks or other problems.
4.1 Transformer Tank
Check for excessive corrosion and oil leaks. Pay special attention to
flanges and gaskets (bushings, valves, and radiators) and the lower
section of the main tank. Report oil leaks to maintenance, and pay
special attention to the oil level indicator if leaks are found. Severely
corroded spots should be wire brushed and painted with a rust
inhibitor.
4.2 Top Oil Thermometers
These thermometers are typically sealed, spiral-bourdon-tube dial
indicators with liquid-filled bulb sensors. The bulb is normally inside
a thermometer well, which penetrates the tank wall into the oil near the
top of the tank. As oil temperature increases in the bulb, liquid
expands, which expands the spiral tube. The tube is attached to a
pointer that indicates temperature. These pointers may also have
electrical contacts to trigger alarms and start cooling fans as
temperature increases. An extra pointer, normally red, indicates
maximum temperature since the last time the indicator was reset.
This red pointer rises with the main pointer but will not decrease
unless manually reset; thus, it always indicates the highest

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temperature reached since it was reset. See the instruction manual
on your specific transformer for details.
4.3 Winding Temperature Thermometers
These devices are supposed to indicate the hottest spot in the winding,
based on the manufacturer’s heat run tests. At best, this device is only
accurate at top nameplate rated load and only if it is not out of
calibration [18]. They are not what their name implies and can be
misleading. They are only winding hottest-spot simulators, which are
not very accurate. Normally, there is no temperature sensor embedded
in the winding hot spot. At best, they provide only a rough
approximation of hot spot winding temperature and should not be
relied on for accuracy. They can be used to turn on additional cooling
or activate alarms as the top oil thermometers do.
Winding temperature thermometers work the same way as the top oil
thermometer (discussed in section 4.2), except that the bulb is in a
separate thermometer well near the top of the tank. A wire-type heater
coil is either inserted into, or wrapped around, the thermometer well,
which surrounds the temperature sensitive bulb. In some transformers,
a current transformer (CT) is around one of the three winding leads
and provides current directly to the heater coil in proportion to
winding current. In other transformers, the CT supplies current to an
auto-transformer that supplies current to the heater coil. The heater
warms the bulb, and the dial indicates a temperature, but it is not the
true hottest-spot temperature.
These devices are calibrated at the factory by changing taps on
either the CT or the autotransformer, or by adjusting the calibration
resistors in the control cabinet. These devices normally cannot be
field calibrated or tested, other than testing the thermometer, as
mentioned. The calibration resistors can be adjusted in the field if
the manufacturer provides calibration curves for the transformer.
In practice, most winding temperature indicators are out of calibration,

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and their readings are meaningless. These temperature indications
should not be relied upon for loading operations or maintenance
decisions.
Fiber optic temperature sensors can be imbedded directly into the
winding as the transformer is being built; these sensors are much more
accurate. This system is available as an option on new transformers at
an increased cost, which may be worthwhile, since the true winding
“hottest-spot” temperature is critical when higher loading is required.
Thermometers can be removed without lowering the transformer oil if
they are in a thermometer well. Check your transformer instruction
manual. Look carefully at the capillary tubing between the
thermometer well and the dial indicator. If the tubing has been
pinched or accidentally struck, it may be restricted. This is not an
obvious defect, but it can cause the dial pointer to lock in one position.
If this defect is found, the whole gauge must be returned to the factory
for repair or replacement; it cannot be repaired in the field. Look for a
leak in the tubing system; the gauge reading will be very low and must
be replaced if a leak is discovered.
Every 3 to 5 years, and if trouble is suspected, test the
thermometer. Suspend the thermometer’s indicator bulb and an
accurate mercury thermometer in an oil bath. Do not allow either
thermometer to touch the side or bottom of the container. Heat the
oil on a hotplate, while stirring, and compare the two thermometers
while the temperature increases. If a magnetic stirring/heating plate
is available, it is more effective than hand stirring. Pay particular
attention to the upper temperature range at which your transformers
normally operate (50 ºC to 80 ºC). An ohmmeter should also be
used to check switch operations. If either dial indicator is more than
5 ºC different than the mercury thermometer, it should be replaced
with a spare. A number of spares should be kept, based on the
quantity of transformers at the plant. Oil bath test kits are available
from the Qualitrol Company. After calling for Qualitrol authorization

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(716-586-1515), you can ship defective dial thermometers for repair
and calibration to: Qualitrol Company, 1387 Fairport Road, Fairport,
New York 14450.
The alarms and other functions should also be tested to see if the
correct annunciator points activate, pumps/fans operate, etc.
If the temperature gauge cannot be replaced or sent to the factory for
repair, place a temperature correction factor on your data form to add
to the dial reading, so that the correct temperature will be recorded.
Also, lower the alarm and pump-turn-on settings by this same
correction factor. Since these are pressure-filled systems, the indicator
will typically read low if it is out of calibration. Field testing has
shown some of these gauges reading 15 ºC to 20 ºC lower than actual
temperature. This is hazardous for transformers because it will allow
them to continuously run hotter than intended, due to delayed alarms
and cooling activation. If thermometers are not tested and errors
corrected, transformer service life may be shortened or premature
failure may occur.
4.3.1 Temperature Indicators Online
Check all temperature indicators while the transformer is online. The
winding temperature indicator should read approximately 15 degrees
above the top oil temperature. If this is not the case, one or both
temperature indicators are malfunctioning. Check the top oil
temperature next to the top oil indicator’s thermowell with an
infrared camera. Compare the readings with the top oil indicator.
Reset all maximum indicator hands on the temperature indicating
devices after recording the old maximum temperature readings.
High temperature may mean overloading, cooling problems, or
problems with windings, core, or connections.
4.3.2 Temperature Indicators Offline
When the transformer is offline and has cooled to ambient tempera-
ture, check the top oil and winding temperature indicators; both should

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read the same. If not, one or both temperature indicators are mal-
functioning. Check the calibration according to the proper procedure.
Also, compare these readings with the indicated temperature on the
conservator oil level indicator; all three should agree.
4.4 Oil Level Indicators
After 1 month of service, and every 3 to 5 years, check the tank oil
level indicators. These are float operated, with the float mechanism
magnetically coupled through the tank wall to the dial indicator. As
level increases, the float rotates a magnet inside the tank. Outside the
tank, another magnet follows (rotates), which moves the pointer. The
center of the dial is normally marked with a temperature of 25 ºC
(77 ºF). High and low level points are also marked to follow level
changes as the oil expands and contracts with temperature changes.
The proper way to determine accurate oil level is to first look at the top
oil temperature indicator. After determining the temperature, look at
the level gauge. The pointer should be at a reasonable level
corresponding to the top oil temperature. Calibrate or replace the
conservator oil level indicator if needed, but only after checking the
top oil temperature indicator as shown in the above section. If the
transformer is fully loaded, the top oil temperature will be high, and
the level indicator should be near the high mark. If the transformer is
de-energized and the top oil temperature is near 25 ºC, the oil level
pointer should be at or near 25 ºC. See figure 27. Reference also
IEEE 62-1995™ [20], section 6.6.2.
To check the level indicator, remove the outside mechanism for testing
without lowering transformer oil. After removing the gauge, hold a
magnet on the back of the dial and rotate the magnet; the dial indicator
should also rotate. If it fails to respond or if it drags or sticks, replace
it. As mentioned above, defective units can be sent to the factory for
repair.
There may also be electrical switches for alarms and, possibly, for
tripping off the transformer when the tank level falls. These switches

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should be checked with an ohmmeter for proper operation. The
alarm/tripping circuits should also be tested to see if the correct
annunciator points and relays respond. See the transformer instruction
book for information on your specific indicator.
If oil has had to be lowered in the
transformer or conservator for other
reasons (e.g., inspections), check the oil
level float mechanism (figure 28). Rotate
the float mechanism by hand to check for
free movement.
Check the float visually to make sure it is
secure to the arm and to ensure that the
arm is in the proper shape. Some arms
are formed (not straight).
4.5 Pressure Relief Devices
These devices are the transformers’ last line of defense against
excessive internal pressure. In the event of a fault or short circuit, the
resultant arc instantly vaporizes surrounding oil, causing a rapid
buildup of gaseous pressure. If the pressure relief device does not
operate properly and pressure is not sufficiently relieved within a
Figure 28 – Conservator
Oil Level.
Figure 27 – Oil Level Indicator.

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few milliseconds, a catastrophic tank rupture can result, spreading
flaming oil over a wide area. Two types of pressure relief devices
are discussed below. Consult your transformer’s instruction manual
for specifics.
CAUTION:
Never paint pressure relief devices because paint can cause
the plunger or rotating shaft to stick. Then, the device might
not relieve pressure, which could lead to catastrophic tank
failure during a fault. Look at the top of the device; on newer
units, a yellow or blue button should be visible. If these have
been painted, the button will be the same color as the tank.
On older units, a red flag should be visible; if it has been
painted, it will be the same color as the tank.
If the pressure relief devices have been painted, they should be
replaced. It is virtually impossible to remove all paint from the
mechanism and be certain the device will work when needed.
4.5.1 Newer Pressure Relief Devices
Newer pressure relief devices are spring-loaded valves that
automatically re-close following a pressure release. The springs are
held in compression by the cover and press on a disc which seals an
opening in the tank top. If pressure in the tank exceeds operating
pressure, the disc moves upward and relieves pressure. As pressure
decreases, the springs re-close the valve. After operating, this device
leaves a brightly colored rod (bright yellow for oil, blue for silicone)
exposed approximately 2 inches above the top. This rod is easily seen
upon inspection, although it is not always visible from floor level. The
rod may be reset by pressing on the top until it is again recessed into
the device. The switch must also be manually reset. A relief device is
shown in the open position in figure 29. Figure 30 also shows
a pressure relief device with the yellow indicating arm.

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Figure 30 – Photograph of a Pressure
Relief Device.
CAUTION:
Do not re-energize a transformer after the pressure relief
device has operated and relays have de-energized the
transformer, until extensive testing to determine and correct
the cause has been completed. Explosive, catastrophic
failure could be the result of energization after this device
has operated.
Figure 29 – Pressure Relief Device.

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CAUTION:
Bolts that hold the device to the tank may be loosened
safely, but never loosen screws that hold the cover to the
flange without referring to the instruction manual and using
great care. Springs that oppose tank pressure are held in
compression by these screws, and their stored energy could
be hazardous.
Once each year, and as soon as possible after a known through-fault or
internal fault, inspect pressure devices to see if they have operated.
This must be done from a high-lift bucket if the transformer is
energized. Look at each pressure relief device to see if the yellow
(or blue) button is visible. If the device has operated, about 2 inches
of the colored rod will be visible. Each year, test the alarm circuits by
operating the switch by hand and making sure the correct annunciator
point is activated. If the relief device operates during operation, do not
re-energize the transformer; Doble and other testing may be required
before re-energizing, and an oil sample should be sent for analysis.
Every 3 to 5 years, when doing other maintenance or testing, if the
transformer has a conservator, examine the top of the transformer tank
around the pressure relief device. If oil is visible, the device is
leaking, either around the tank gasket or relief diaphragm. If the
device is 30 years old, replace the whole unit. A nitrogen blanketed
transformer will use a lot more nitrogen if the relief device is leaking;
they should be tested as described below.
A test stand with a pressure gauge may be fabricated to test the
pressure relief function. Current cost of a pressure relief device
is about $600, so testing instead of replacement may be prudent.
Have a spare pressure relief device on hand so that the tank will
not have to be left open. If the tank top or pressure relief device
has gasket limiting grooves, always use a nitrile replacement gasket;
if there are no grooves, use a cork-nitrile gasket. Although relief
devices themselves do not leak often, the gasket may leak.

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4.5.2 Older Pressure Relief Devices
Older pressure relief devices have a diaphragm and a relief pin that is
destroyed each time the device operates and must be replaced.
CAUTION:
Replacement parts of an older pressure relief device must be
replaced with exact duplicate parts; otherwise, the operating
relief pressure of the device will be wrong.
The relief pin determines operating pressure; a number, which is the
operating pressure, normally appears on top of the pin. Check your
specific transformer instruction manual for proper catalog numbers.
Do not assume you have the right parts or that correct parts have been
previously installed—look it up. If the operating pressure is too high,
a catastrophic tank failure could result.
On older units, a shaft rotates, operates alarm/trip switches, and raises
a small red flag when the unit releases pressure. If units have been
painted or are more than 30 years old, they should be replaced with the
new model as soon as it is possible to have a transformer outage.
Once each year, and as soon as possible after a through-fault or
internal fault, examine the indicator flag to see if the device has
operated. The flags must be examined from a high-lift bucket if the
transformer is energized. A clearance must be obtained to test, repair,
or reset the device. See the instruction manual for your specific
transformer. Test alarm/trip circuits by operating the switch by hand.
Check to make sure the correct annunciator point activates.
Every 3 to 5 years, when doing other maintenance or testing, examine
the top of the transformer tank around the pressure relief device. If the
transformer has a conservator and oil is visible, the device is leaking,
either around the tank gasket or relief diaphragm. The gasket and/or
device must be replaced. Before ordering, make sure that the new

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device will fit the same tank opening. Most devices are made by the
Qualitrol Company; contact the manufacturer to obtain a correct
replacement.
4.6 Sudden Pressure Relay
Internal arcing in an oil-filled power transformer can instantly
vaporize surrounding oil, generating gas pressures that can cause
catastrophic failure, rupture the tank, and spread flaming oil over a
large area. This can damage or destroy other equipment, in addition to
the transformer, and present extreme hazards to workers.
The relay is designed to detect a sudden pressure increase caused by
arcing. This relay is very sensitive and will operate if the pressure
rises even slightly. If a very small pressure change occurs caused by a
small electrical fault inside the tank, this relay will alarm. The relay is
set to operate before the pressure relief device. The control circuit
should de-energize the transformer and provide an alarm. The relay
will ignore normal pressure changes such as oil-pump surges,
temperature changes, etc.
Modern sudden pressure relays consist of three bellows (see figure 31)
with silicone sealed inside. Changes in pressure in the transformer
deflect the main sensing bellows. Silicone inside acts on two control
bellows arranged like a balance beam (one on each side). One bellows
senses pressure changes through a small orifice. The opening is
automatically changed by a bimetallic strip to adjust for normal
temperature changes of the oil. The orifice delays pressure changes in
this bellows. The other bellows responds to immediate pressure
changes and is affected much more quickly. Pressure difference tilts
the balance beam and activates the switch. This type of relay
automatically resets when the two bellows again reach pressure
equilibrium. If this relay operates, do not re-energize the transformer
until you have determined the exact cause and corrected the problem.

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Old style sudden pressure relays have only one bellows. A sudden
excessive pressure within the transformer tank exerts pressure directly
on the bellows, which moves a spring-loaded operating pin. The pin
operates a switch that provides alarm and breaker trip. After the relay
has operated, the cap must be removed and the switch must be reset to
normal by depressing the reset button.
Once every 3 to 5 years, the sudden pressure relay should be tested
according to manufacturer’s instructions. Generally, only a squeeze-
bulb and pressure gauge (5 psi) are required. Disconnect the tripping
circuit and use an ohmmeter to test for relay operation. Test the alarm
circuit and verify that the correct alarm point is activated. Use an
ohmmeter to verify the trip signal is activated or, if possible, apply
only control voltage to the breaker and make sure the tripping function
operates. Consult the manufacturer’s manual for your specific
transformer’s detailed instructions.
Figure 31 – Sudden Pressure Relay, Section.

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Figure 32 – Photograph of a
Sudden Pressure Relay.
4.6.1 Testing Suggestion
Figure 32 shows an example relay.
Inspect the isolation valve to ensure it
is open. With the transformer offline
and under clearance, functionally test
the sudden pressure relay by slowly
closing the isolating valve. Leave it
closed for a few seconds and reopen
the valve very suddenly; this should
activate the alarm. If the alarm does
not activate, test the relay. If the relay
fails to function, replace it with a
new one.
4.7 Buchholz Relay (Found
Only on Transformers with Conservators)
The Buchholz relay (figures 33 and 34) has two oil-filled chambers
with floats and relays arranged vertically—one over the other. If high
eddy currents, local overheating, or partial discharges occur within the
tank, bubbles of resultant gas rise to the top of the tank. These bubbles
rise through the pipe between the tank and the conservator. As gas
bubbles migrate along the pipe, they enter the Buchholz relay and rise
into the top chamber. As gas builds up inside the chamber, it displaces
the oil, which decreases the oil level. The top float descends with the
oil level until it passes a magnetic switch, which activates an alarm.
The bottom float and relay cannot be activated by additional gas
buildup. The float is located slightly below the top of the pipe so that
once the top chamber is filled, additional gas goes into the pipe and
continues up to the conservator. Typically, inspection windows are
provided so that the amount of gas and relay operation may be viewed
during testing. If the oil level falls low enough (conservator empty),
the bottom float activates the switch contacts in the bottom chamber.

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These contacts are typically connected to cause the transformer to trip.
This relay also serves a third function, similar to the sudden pressure
relay. A magnetically held paddle attached to the bottom float is
positioned in the oil-flow stream between the conservator and
transformer tank. Normal flows resulting from temperature changes
Figure 34 – Photograph of a Buchholz Relay.
Figure 33 – Buchholz Relay, Section.

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are small and bypass below the paddle. If a fault occurs in the
transformer, a pressure wave (surge) is created in the oil. This surge
travels through the pipe and displaces the paddle. The paddle activates
the same magnetic switch as the bottom float mentioned above, which
trips the transformer. The flow rate at which the paddle activates the
relay is normally adjustable. See your specific transformer’s
instruction manual for details.
Once every 3 to 5 years, while the transformer is de-energized,
functionally test the Buchhholz relay by pumping a small amount of
air into the top chamber with a squeeze-bulb hand pump. Watch the
float operation through the window (center in figure 32). Check to
make sure the correct alarm point has been activated. Open the bleed
valve and vent air from the chamber. The bottom float and switching
cannot be tested with air pressure. On some relays, a rod is provided
so that you can test both bottom and top sections by pushing the floats
down until the trip points are activated. If possible, verify that the
breaker will trip with this operation. A volt-ohmmeter may also be
used to check the switches. If these contacts activate during operation,
it means that the oil level is very low, a pressure wave has activated
(bottom contacts), or the transformer is gassing (top contacts). If this
relay operates, do not re-energize the transformer until you have
determined the exact cause.
If a small amount of gas is found in this relay when the transformer is
new (a few months after startup), it is probably just air that has been
trapped in the transformer structure and is now escaping; there is little
cause for concern.
If the transformer has been online for some time (service aged), and
gas is found in the Buchholz, oil samples must be sent to the lab for
DGA and extensive testing. Consult with the manufacturer and other
transformer experts. A definite cause of the gas bubbles must be
determined and corrected before re-energization of the transformer.

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4.8 Transformer Bushings: Testing and Maintenance of
High-Voltage Bushings
When bushings are new, they should be Doble tested as an acceptance
test. Refer to the M4000 Doble test set instructions, the Doble
Bushing Field Test Guide [9], and the manufacturer’s data for
guidance on acceptable results.
CAUTION:
Do not test a bushing while it is in its wood shipping crate, or
while it is lying on wood. Wood does not insulate as well as
porcelain and will cause the readings to be inaccurate. Keep
the test results as a baseline record to compare with future
tests.
After 1 month of service and yearly, check the external porcelain for
cracks and/or contamination (requires binoculars). There is no
“perfect insulator”; a small amount of leakage current always exists.
This current “leaks” through and along the bushing surface from the
high-voltage conductor to ground. If the bushing is damaged or
heavily contaminated, leakage current becomes excessive, and visible
evidence may appear as carbon tracking (treeing) on the bushing
surface. Flashovers may occur if the bushings are not cleaned
periodically.
Look carefully for oil leaks. Check the bushing oil level by viewing
the oil-sight glass or the oil level gauge. When the bushing has a
gauge with a pointer, look carefully, because the oil level should vary
slightly with temperature changes. If the pointer never changes, even
with wide ambient temperature and load changes, the gauge should be
checked at the next outage. A stuck gauge pointer coupled with a
small oil leak can cause explosive failure of a bushing, damaging the
transformer and other switchyard equipment. A costly extended
outage is the result.

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If the oil level is low and there is an external oil leak, check the bolts
for proper torque and the gasket for proper compression. If torque and
compression are correct, the bushing must be replaced with a spare.
Follow instructions in the transformer manual carefully. It is very
important that the correct type of gasket be installed and the correct
compression be applied. A leaky gasket is probably also leaking water
and air into the transformer, so check the most recent transformer
DGA for high moisture and oxygen.
If the oil level is low and there is no visible external leak, there may be
an internal leak around the lower seal into the transformer tank. If
possible, re-fill the bushing with the same oil and carefully monitor the
level and the volume it takes to fill the bushing to the proper level. If
it takes more than 1 quart of oil, make plans to replace the bushing.
The bushing must be sent to the factory for repair, or it must be
junked; it cannot be repaired in the field.
CAUTION:
Never open the fill plug of any bushing if it is at an elevated
temperature. Some bushings have a nitrogen blanket on top
of the oil, which pressurizes as the oil expands. Always
consult the manufacturer’s instruction manual which will give
the temperature range at which the bushing may be safely
opened. Generally, this will be between 15 °C (59 °F) and
35 °C (95 °F). Pressurized hot oil may suddenly gush from
the fill plug if it is removed while at elevated temperature,
causing burn hazards. Generally, the bushing will be a little
cooler than the top oil temperature, so this temperature
gauge may be used as a guide if the gauge has been tested
as mentioned in section 4.3.
About 90% of all preventable bushing failures are caused by moisture
entering through leaky gaskets, cracks, or seals. Internal moisture can
be detected by Doble testing. See FIST 3-2 [10] and Doble Bushing
Field Test Guide [9] for troubles and corrective actions. Internal

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moisture causes deterioration of the insulation of the bushing and can
result in explosive failure, causing extensive transformer and other
equipment damage, as well as hazards to workers.
After 1 month of service and yearly, examine the bushings with an
IR camera [4, 8]; if one phase shows a markedly higher temperature,
there is probably a bad connection. The connection at the top is
usually the poor one; however, a bad connection inside the transformer
tank will usually show a higher temperature at the top as well. In
addition, a bad connection inside the transformer will usually show hot
metal gases (ethane and ethylene) in the DGA.
Once every 3 to 5 years, perform a close physical inspection and
cleaning of the bushings [10]. Check carefully for leaks, cracks, and
carbon tracking. This inspection will be required more often in
atmospheres where salts and dust deposits appear on the bushings. In
conditions that produce deposits, a light application of Dow Corning
grease DC-5 or GE Insulgel will help reduce risk of external flashover.
The disadvantage of this treatment is that a grease buildup may occur.
In high humidity and wet areas, a better choice may be a high-quality
silicone paste wax applied to the porcelain, which will reduce the risk
of flashover. A spray-on wax containing silicone, such as Turtle Wax
brand, has been found to be very useful for cleaning and waxing in one
operation, providing the deposits are not too hard. Wax will cause
water to form beads, rather than a continuous sheet, which reduces
flashover risk. Cleaning may involve just spraying with Turtle Wax
and wiping with a soft cloth. A lime removal product, such as “Lime
Away,” also may be useful. More stubborn contaminants may require
solvents, steel wool, and brushes. A high pressure water stream may
be required to remove salt and other water soluble deposits.
Limestone powder blasting with dry air will safely remove metallic
oxides, chemicals, salt-cake, and almost any hard contaminant. Other
materials, such as potter’s clay, walnut or pecan shells, or crushed
coconut shells, are also used for hard contaminants. Carbon dioxide
(CO2) pellet blasting is more expensive but virtually eliminates
cleanup because it evaporates. Ground-up corn-cob blasting will

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remove soft pollutants, such as old coatings of built-up grease. A
competent, experienced contractor should be employed, and a
thorough, written job hazard analysis (JHA) should be performed
when any of these treatments are used.
Corona (air ionization) may be visible at the tops of bushings at
twilight or night, especially during periods of rain, mist, fog, or high
humidity. At the top, corona is considered normal; however, as a
bushing becomes more and more contaminated, corona will creep
lower and lower. If the bushing is not cleaned, flashover will occur
when corona nears the grounded transformer top. If corona seems to
be lower than the top of the bushing, inspect, Doble test, and clean the
bushing as quickly as possible. If flashover occurs (phase to ground
fault), it could destroy the bushing and cause an extended outage.
Line-to-line faults also can occur if all the bushings are contaminated
and flashover occurs. A corona scope may be used to view and
photograph low levels of corona indoors under normal illumination
and outdoors at twilight or night. High levels of corona may be
viewed outdoors in the daytime if a dark background is available, such
as trees, canyon walls, buildings, etc. The corona scope design is
primarily for indoor and night use; it cannot be used with blue or
cloudy sky background. This technology is available at the Technical
Service Center (TSC), D-8450.
Once every 3 to 5 years, depending on the atmosphere and
service conditions, the bushings should be Doble tested. Refer to
Doble M-4000 test set instructions, Doble Bushing Field Test
Guide [9], FIST 3-2 [10], and the manufacturer’s instructions for
proper values and test procedures. Bushings should be cleaned prior to
Doble testing. Contamination on the insulating surface will cause the
results to be inaccurate. Testing may also be done before and after
cleaning to check methods of cleaning. As the bushings age and begin
to deteriorate, reduce the testing interval to 1 year. Keep accurate
records of results so that replacements can be ordered in advance,
before you have to remove bushings from service.

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CAUTION:
See the transformer manual for detailed instructions on
cleaning and repairing your specific bushing surfaces.
Different solvents, wiping materials, and cleaning methods
may be required for different bushings. Different repair
techniques may also be required for small cracks and chips.
Generally, glyptal or insulating varnish will repair small
scratches, hairline cracks, and chips. Sharp edges of a chip
should be honed smooth, and the defective area should be
painted with insulating varnish to provide a glossy finish.
Hairline cracks in the surface of the porcelain must be sealed
because accumulated dirt and moisture in the crack may
result in flashover. Epoxy should be used to repair larger
chips. If a bushing insulator has a large chip that reduces
the flashover distance or has a large crack totally through the
insulator, the bushing must be replaced. Some
manufacturers offer repair service to damaged bushings that
cannot be repaired in the field. Contact the manufacturer for
your particular bushings if you have repair questions.
4.9 Oil Preservation Sealing Systems
The purpose of sealing systems is to prevent air and moisture from
contaminating oil and cellulose insulation. Sealing systems are
designed to prevent oil inside the transformer from coming into
contact with air. Air contains moisture, which causes sludging and an
abundant supply of oxygen. Oxygen, in combination with moisture,
causes greatly accelerated deterioration of the cellulose. This oxygen-
moisture combination will greatly reduce service life of the
transformer.
Sealing systems on many existing Reclamation power transformers are
of the inert gas (nitrogen) pressure design; however, Reclamation has
many other designs. Current practice is to buy only conservator
designs with bladders for transformer voltages 115 kV and above and
capacities above 10 MVA. Below these values, we buy only inert gas
pressure system transformers, as depicted in figure 36 (page 79).

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Some of the sealing systems are explained below. There may be
variations of each design, and not every design is discussed. Early
sealing system types are discussed first, followed by more modern
types.
4.9.1 Sealing Systems Types
4.9.1.1 Free Breathing – Sealing systems have progressed
from early designs of “free breathing” tanks, in which an air space on
top of the oil is vented to atmosphere through a breather pipe. The
pipe typically is screened to keep out insects and rodents and turned
down to prevent rain from entering. Breathing is caused by expansion
and contraction of the oil as temperature changes. These earlier
designs do not use an air dryer, and condensation from moisture forms
on inside walls and tank top. Moisture, oxygen, and nitrogen would
also dissolve directly into oil from the air. This is not the best design.
As mentioned before, a combination of oxygen and moisture
accelerates deterioration of cellulose insulation. Moisture also
decreases dielectric strength, which destroys insulating quality of the
oil and causes sludge to form. If you have one or more of these earlier
design transformers, it is recommended that a desiccant type air dryer
be added to the breather pipe.
4.9.1.2 Sealed or Pressurized Breathing – This design is
similar to the free breathing type with the addition of a pressure/
vacuum bleeder valve. When the transformer was installed,
pressurized dry air or nitrogen was placed on top of the oil. The
bleeder valve is designed to hold pressure inside to approximately plus
or minus 5 psi (figure 35). The same problems with moisture and
oxygen occur as previously described. However, these problems are
not as severe because “breathing” is limited by the bleeder valve. Air
or nitrogen (N2) is exhausted to the outside atmosphere when a
positive pressure greater than 5 psi occurs inside the tank. This
process does not add moisture and oxygen to the tank. However, when
cooling, the oil contracts and, if pressure falls 5 psi below the outside
atmosphere, the valve allows outside air into the tank, which pulls in
moisture and oxygen.

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Once each year, check the pressure gauge against the weekly data
sheets; if the pressure never varies with seasonal temperature changes,
the gauge is defective. Add nitrogen if the pressure falls below 1 psi
to keep moisture laden air from being pulled in. Add enough N2 to
bring the pressure to between 2 and 4 psi.
4.9.1.3 Pressurized Inert Gas Sealed System – This system
keeps space above the oil pressurized with a dry inert gas, normally
nitrogen (figure 36). This design prevents air and moisture from
coming into contact with insulating oil. Pressure is maintained by a
nitrogen gas bottle with the pressure regulated normally between
0.5 and 5 psi. Pressure gauges are provided in the nitrogen cubicle for
both high and low pressures (figure 37). A pressure/vacuum gauge is
normally connected to read low pressure gas inside the tank. This
gauge may be located on the transformer and normally has high-
pressure and low-pressure alarm contacts. See section 4.9.2, which
follows.
If the transformer has a nitrogen blanket, check the pressure gauge for
proper pressure. Look at the operators recording of pressures from the
pressure gauge. If this does not change, the gauge is probably
Figure 35 – Pressurized Breathing Transformer.

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CAUTION:
When replacing nitrogen cylinders, do not just order a
“nitrogen cylinder” from the local welding supplier. Nitrogen
for transformers should meet American Society for Testing
and Materials (ASTM) D-1933 Type III with -59 °C dew point
as specified in IEEE C-57.12.00-1993, paragraph 6.6.3
[29, 2].
defective. Check the nitrogen bottle to insure the nitrogen is the
proper quality (see Power Equipment Bulletin No. 5 [40]). Check for
any increased usage of nitrogen which indicates a leak. Smaller
Figure 36 – Pressurized Inert Gas Transformer.

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transformers such as station service or smaller generator-step-up
transformers may not have nitrogen bottles attached to replace
lost nitrogen. Be especially watchful of the pressure gauge and the
operator’s records of pressures with these. The pressure gauge can be
defective for years, and no one will notice. The gauge will read nearly
the same and will not vary much over winter and summer or night and
day. Meanwhile, a nitrogen leak can develop, and all the N2 will be
lost. This allows air with oxygen and moisture to enter and deteriorate
the oil and insulation. Watch for increased oxygen and moisture in the
DGA. An ultrasonic and sonic leak detection instrument (P-2000) is
used for locating N2 leaks. Soap bubbles also may be used.
Front View Side View
Figure 37 – Gas Pressure Control Components.

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4.9.2 Gas Pressure Control Components
After 1 month of service and yearly, inspect the gas pressure control
components. There is normally an adjustable, three-element, pressure
control system for inert gas, which maintains a pressure range of 0.5 to
5 psi in the transformer tank. There is also a bleeder valve that
exhausts gas to atmosphere when pressure exceeds relief pressure of
the valve, normally 5 to 8 psi.
CAUTION:
The component part descriptions below are for the typical,
three-stage pressure regulating equipment supplying inert
gas to the transformer. Your particular unit may be different,
so check your transformer instruction manual.
4.9.2.1 High-Pressure Gauge – The high-pressure gauge is
attached between the nitrogen cylinder and high-pressure regulator that
indicates cylinder pressure. When the cylinder is full, the gauge will
read approximately 2,400 psi. Normally, the gauge will be equipped
with a low-pressure alarm that activates when the cylinder is getting
low (around 500 psi). However, gas will still be supplied, and the
regulating equipment will continue to function until the cylinder is
empty. Refer to figure 37 for the following descriptions.
4.9.2.2 High-Pressure Regulator – The high-pressure
regulator has two stages. The input of the first stage is connected to
the cylinder, and the output of the first stage is connected internally to
the input of the second stage. This holds output pressure of the second
stage constant. The first stage output is adjustable by a hand-operated
lever and can deliver a maximum pressure equal to the pressure in the
cylinder (2,400 psi when full) down to zero. The second stage output
is varied by turning the adjusting screw, normally adjusted to supply
approximately 10 psi to the input of the low-pressure regulator.

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4.9.2.3 Low-Pressure Regulator – The low-pressure regulator
is the third stage and controls pressure and flow to the gas space of the
transformer. The input of this regulator is connected to the output of
the second stage (approximately 10 psi). This regulator is typically set
at the factory to supply gas to the transformer at a pressure of
approximately 0.5 psi, and it needs no adjustment. If a different
pressure is required, the regulator can be adjusted by varying spring
tension on the valve diaphragm. Pressure is set at this low value
because major pressure changes inside the transformer result from
expansion and contraction of oil. The purpose of this gas feed is to
make up for small leaks in the tank gaskets and elsewhere so that air
cannot enter. Typically, a spring-loaded bleeder for high-pressure
relief is built into the regulator and is set at the factory to relieve
pressures in excess of 8 psi. The valve will close when pressure drops
below the setting, preventing further loss of gas.
4.9.2.4 Bypass Valve Assembly – The bypass valve assembly
opens a bypass line around the low-pressure regulator and allows the
second stage of the high-pressure regulator to furnish gas directly to
the transformer. The purpose of this assembly is to allow much faster
filling/purging of the gas space during initial installation or when the
transformer tank needs to be refilled after being opened for inspection.
CAUTION:
During normal operation, the bypass valve must be closed,
or pressure in the tank will be too high.
4.9.2.5 Oil Sump – The oil sump is located at the bottom of
the pressure regulating system between the low-pressure regulator and
shutoff valve C. The sump collects oil and/or moisture that may have
condensed in the low-pressure fill line. The drain plug at the bottom
of the sump should be removed before the system is put into operation,
as well as once each year during operation, to drain any residual oil in

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the line. This sump and line will be at the same pressure as the gas
space in the top of the transformer. The sump should always be at a
safe pressure (less than 10 psi) so the plug can be removed to allow the
line to purge a few seconds and blow out the oil. However, always
look at the gas space pressure gauge on the transformer or the low-
pressure gauge in the nitrogen cabinet, just to be sure, before removing
the drain plug.
4.9.2.6 Shutoff Valves – The shutoff valves are located near
the top of the cabinet for the purpose of isolating the transformer tank
for shipping or maintenance. These valves are normally of double-seat
construction and should be fully opened against the stop to prevent gas
leakage around the stem. A shutoff valve is also provided for the
purpose of shutting off the nitrogen flow to the transformer tank. This
shutoff valve must be closed prior to changing cylinders to keep the
gas in the transformer tank from bleeding off.
4.9.2.7 Sampling and Purge Valve – The sampling and purge
valve is normally located in the upper right of the nitrogen cabinet.
This valve is typically equipped with a hose fitting; the other side is
connected directly to the transformer gas space by copper tubing. This
valve is opened while purging the gas space during a new installation
or maintenance refill, and it provides a path to exhaust air as the gas
space is filled with nitrogen. This valve is also opened when a gas
sample is taken from the gas space for analysis. When taking gas
samples, the line must be sufficiently purged so that the sample will be
from gas above the transformer oil and not just gas in the line. This
valve must be tightly closed during normal operation to prevent gas
leakage.
4.9.2.8 Free Breathing Conservator – This design adds an
expansion tank (conservator) above the transformer so that the main
tank may be completely filled with oil (figure 38). Oil expansion and
air exchange with the atmosphere (breathing) occur away from the oil
in the transformer. This design reduces oxygen and moisture

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contamination because only a small portion of oil is exchanged
between the main tank and conservator. An oil/air interface still exists
in the conservator, exposing the oil to air. Eventually, oil in the
conservator is exchanged with oil in the main tank, and oxygen and
other contaminants gain access to the insulation.
If you have transformers of this design, it is recommended that a
bladder or diaphragm-type conservator be installed (described below)
or retrofitted to the original conservator. In addition, a desiccant-type
air dryer should also be installed.
4.9.2.9 Conservator with Bladder or Diaphragm Design – A
conservator with bladder or diaphragm (figure 39) is similar to the
design in figure 38 with an added air bladder (balloon) or flat
diaphragm in the conservator. The bladder or diaphragm expands and
contracts with the oil and isolates it from the atmosphere. The inside
of the bladder or top of the diaphragm is open to atmospheric pressure
through a desiccant air dryer. As oil expands and contracts and as
Figure 38 – Free Breathing Conservator.

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NOTE:
A vacuum will appear in the transformer if piping between the
air dryer and conservator is too small; if the air intake to the
dryer is too small, or if the piping is partially blocked. The
bladder cannot take in air fast enough when the oil level is
decreasing due to rapidly falling temperature. Minimum
¾- to 1-inch piping is recommended. This problem is
especially prevalent with transformers that are frequently in
and out of service and located in geographic areas with large
temperature variations. This situation may allow bubbles to
form in the oil and may even activate gas detector relays,
such as the Buchholz and/or bladder failure relay. The
vacuum may also pull in air around gaskets that are not tight
enough or that have deteriorated (which may also cause
bubbles) [4].
Figure 39 – Conservator with Bladder.

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atmospheric pressure changes, the bladder or diaphragm “breathes” air
in and out. This keeps air and transformer oil essentially at
atmospheric pressure. The oil level gauge on the conservator typically
is magnetic, like those mentioned earlier, except the float is positioned
near the center of the underside of the bladder. With a diaphragm, the
level indicator arm rides on top of the diaphragm. Examine the air
dryer periodically and change the desiccant when approximately one-
third of the material changes color.
4.9.2.9.1 Conservator Inspection – If atmospheric
gases (nitrogen, oxygen, carbon dioxide) and, perhaps, moisture
increase suddenly in the DGA, a leak may have developed in the
conservator diaphragm or bladder. With the transformer offline and
under clearance, open the inspection port on top of the conservator and
look inside with a flashlight. If there is a leak, oil will be visible on
top of the diaphragm or inside the bladder. Re-close the conservator
and replace the bladder or diaphragm at the first opportunity by
scheduling an outage. If there is no gas inside the Buchholz relay, the
transformer may be re-energized after bleeding the air out of the
bladder failure relay. A DGA should be taken immediately to check
for oxygen (O2), N2, and moisture. However, the transformer may be
operated until a new bladder is installed, keeping a close eye on the
DGAs. It is recommended that DGAs be performed every 3 months
until the new bladder is installed. After the bladder installation, the oil
may need to be de-gassed if O2 exceeds 10,000 parts per million
(ppm). Also, carefully check the moisture level in the DGAs to ensure
it is below recommended levels for the particular transformer voltage.
Check the desiccant in the breather often; never let more than two-
thirds of the desiccant become discolored before renewing it. All
efforts must be made to keep the oxygen level below 2,000 ppm and
moisture as low as possible.
4.9.2.9.2 Conservator Breather Inspection – Check the
dehydrating (desiccant) breather for proper oil level if it is an oil-
type unit. Check the color of the desiccant and replace it when
approximately one-third remains with the proper color. See figure 40

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for a modern oil-type desiccant
breather. Notice the pink
desiccant at the bottom of the
blue indicating that this portion
is water saturated.
Notice also that oil is visible in
the very bottom 1 inch or so of
the unit. Many times, the oil is
clear, and the oil level will not
be readily apparent. Normally,
there is a thin line around the
breather near the bottom of the
glass; this indicates where the
oil level should be. Compare
the oil level with the level indi-
cator line and refill, if necessary.
Note the 1¼-inch pipe going
from the breather to the conser-
vator. Small tubing (½ inch or
so) is not large enough to admit
air quickly when the transformer is de-energized in winter. A
transformer can cool so quickly that a vacuum can be created from oil
shrinkage with enough force to puncture a bladder. When this
happens, the bladder is
destroyed; and air is pulled into
the conservator creating a large
bubble.
4.9.2.9.3 Bladder
Failure (Gas Accumulator)
Relay. The bladder failure relay
(not on diaphragm-type
conservators) (figure 41) is
mounted on top of the
conservator for the purpose of
Figure 40 – Conservator Breather.
Figure 41 – Photograph of a Bladder
Failure Relay.

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detecting air bubbles in the oil. The relay will also serve as a
backup to the Buchholz relay. If the Buchholz relay overfills with gas
and fails to activate an alarm or shut down, gas will bypass the
Buchholz and migrate up into the conservator, eventually to the
bladder failure relay. Of course, these gases should also show up in
the DGA. However, DGAs are normally taken only once per
year, and a problem may not be discovered before these alarms
are activated. Figure 42 shows a modern relay. Check your
transformer instruction manual for specifics because designs
Figure 42 – Bladder Failure Relay.

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vary with manufacturers. No bladder is totally impermeable,
and a little air will migrate into the oil.
If a hole forms in the bladder, allowing air to migrate into the oil, the
relay will detect it. As air rises and enters the relay, oil is displaced
and the float drops, activating the alarm. It is similar to the top
chamber of a Buchholz relay, since it is filled with oil and contains a
float switch.
Every 3 to 5 years usually during Doble testing or if the bladder failure
alarm is activated (if the conservator has a diaphragm), place the
transformer under clearance and check the Buchholz relay for gas, as
mentioned in section 4.7. Open the conservator inspection port and
look inside with a flashlight.
Bleed the air/gas from the conservator using the bleed valve on top of
the conservator. If the transformer is new and has been in service for
only a few months, the problem most likely is air escaping from the
structure. With the transformer under clearance, open the inspection
port on top of the conservator and look inside the bladder with a
flashlight. If oil is found inside the bladder, it has developed a leak; a
new one must be ordered and installed.
CAUTION:
Never open the vent of the bladder failure relay unless you
have vacuum or pressure equipment available. The oil will
fall inside the relay and conservator and pull in air from the
outside. You will have to recommission the relay by valving
off the conservator and pressurizing the bladder or by placing
a vacuum on the relay. See your specific transformer
instruction manual for details.

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CAUTION:
When the transformer, relay, and bladder are new, some air or
gas is normally entrapped in the transformer and piping and
takes some time to rise and activate the relay. Do not assume
the bladder has failed if the alarm activates within 2 to
3 months after it is put into operation. If this occurs, you will
have to recommission the relay with pressure or vacuum. See
your specific transformer instruction manual for details. If no
more alarms occur, the bladder is intact. If alarms continue,
look carefully for oil leaks in the conservator and transformer.
An oil leak is usually also an air leak. This may be checked by
looking at the nitrogen and oxygen in the dissolved gas
analysis. If these gases are increasing, there is probably a
leak; with a sealed conservator, there should be little of these
gases in the oil. Nitrogen may be high if the transformer was
shipped new and was filled with nitrogen.
4.10 Auxiliary Tank Sealing System
The auxiliary tank sealing system incorporates an extra tank between
the main transformer tank and the conservator tank. Inert gas
(normally nitrogen) is placed above oil in both the main and middle
tanks. Only oil in the top conservator tank is exposed to air. A
desiccant air dryer may, or may not, be included on the breather. As
oil in the main tank expands and contracts with temperature, gas
pressure varies above the oil in both (figure 43).
Changes in gas pressure cause oil to go back and forth between the
middle tank and the conservator. Air containing oxygen and moisture
is not in contact with oil in the main transformer tank. Oxygen and
moisture are absorbed by oil in the conservator tank and interchanged
with oil in the middle tank. However, since gas in the middle tank
interchanges with gas in the main tank, small amounts of oxygen and
moisture carried by gas still make their way into the transformer.

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With this arrangement, the conservator does not have to be located
above the main tank, which reduces the overall height. If you have
one or more of these type transformers without desiccant air dryers,
they should be installed.
5. Gaskets
Gaskets have several important jobs in sealing systems [7]. A gasket
must create a seal and hold it over a long period of time. It must be
impervious and not contaminate the insulating fluid or gas above the
fluid. It should be easily removed and replaced. A gasket must be
elastic enough to flow into imperfections on the sealing surfaces. It
must withstand high and low temperatures and remain resilient enough
to hold the seal, even with joint movement from expansion,
contraction, and vibration. It must be resilient enough to avoid taking
a “set,” even when exposed for a long time to pressure applied with
Figure 43 – Auxiliary Sealing System.

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bolt torque and temperature changes. The gasket must have sufficient
strength to resist crushing under applied load and resist blowout under
system pressure or vacuum. It must maintain its integrity while being
handled or installed. If a gasket fails to meet any of these criteria, a
leak will result. Gasket leaks result from improper torque, choosing
the wrong type of gasket material, or choosing the wrong size gasket.
Improper sealing surface preparation or the gasket taking a “set”
(becoming hard and losing its resilience and elasticity) will also cause
a leak. Usually, gaskets take a set as a result of temperature extremes
and age.
5.1 Sealing (Mating) Surface Preparation
Clean the metal surface thoroughly. Remove all moisture, oil and
grease, rust, etc. A wire brush and/or solvent may be required.
CAUTION:
Take extra care that rust and dirt particles never fall into the
transformer. The results could be catastrophic when the
transformer is energized.
After rust and scale have been removed, metal surfaces should be
coated with Loctite Master gasket No. 518. This material will cure
after you bolt up the gasket, so additional glue is not necessary. If the
temperature is 50 ºF or more, you can bolt up the gasket immediately.
This material comes in a kit (part No. 22424) with primer, a tube of
material, and instructions. If these instructions are followed, the seal
will last many years, and the gasket will be easy to remove later, if
necessary. If the temperature is under 50 ºF, wait about ½ to 1 hour
after applying the material to surfaces before bolting. If you are using
cork-nitrile or cork-neoprene, you can also seal gasket surfaces
(including the edge of the gasket) with this same material. Loctite
makes other sealers that can be used to seal gaskets, such as “Hi-tack.”

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GE glyptol No. 1201B-red can also be used to paint gasket and metal
surfaces; but it takes more time, and you must be more cautious about
temperature. If possible, this work should be done in temperatures
above 70 ºF to speed paint curing. Allow the paint to completely dry
before applying glue or the new gasket. It is not necessary to remove
old glyptol, or other primer, or old glue if the surface is fairly smooth
and uniform.
Choose the correct replacement gasket. The main influences on gasket
material selection are design of the gasket joint, maximum and
minimum operating temperature, type of fluid contained, and internal
pressure of the transformer.
CAUTION:
Most synthetic rubber compounds, including nitrile (Buna N),
contain some carbon, which makes it semiconductive. Take
extra care to never drop a gasket or pieces of gasket into a
transformer tank. The results could be catastrophic when
the transformer is energized.
5.2 Cork-Nitrile
Cork-nitrile should be used if the joint does not have grooves or
limits. This material performs better than cork-neoprene because it
does not take a set as easily and conforms better to mating surfaces. It
also performs better at higher temperatures. Be extra careful when you
store this material because it looks like cork-neoprene (described in
section 5.3), and they easily are mistaken for each other. Compression
is the same as for cork-neoprene, about 45%. Cork-nitrile should
recover 80% of its thickness with compression of 400 psi in
accordance with ASTM F36. Hardness should be 60 to 75 durometer
in accordance with ASTM D2240. (See published specifications for
E-98 by manufacturer Dodge-Regupol Inc., Lancaster, Pennsylvania.)

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CAUTION:
Cork nitrile has a shelf life of only about 2 years, so do not
order and stock more than can be used during this time.
5.3 Cork-Neoprene
Cork-neoprene mixture (called coroprene) can also be used; however,
it does not perform as well as cork-nitrile. This material takes a set
when it is compressed and should only be used when there are no
expansion limiting grooves. Using cork-neoprene in grooves can
result in leaks from expansion and contraction of mating surfaces. The
material is very porous and should be sealed on both sides and edges
with a thin coat of Glyptol No. 1201B red or similar sealer before
installation. Glyptol No. 1201B is a slow drying paint used to seal
metal flanges and gaskets, and the paint should be allowed to dry
totally before installation. Once compressed, this gasket should never
be reused. These gaskets should be kept above 35 ºF before
installation to prevent them from becoming hard. Gaskets should be
cut and sealed (painted) indoors at temperatures above 70 ºF for ease
of handling and to reduce paint curing time. Avoid installing cork-
neoprene gaskets when temperatures are at or near freezing because
the gasket could be damaged and leak. Cork-neoprene gaskets must be
evenly compressed at about 43 to 45%. For example, if the gasket is
¼-inch thick, 0.43 x 0.25 = 0.10. When the gasket is torqued down, it
should be compressed about 0.10 inch. Or you may subtract 0.1 from
¼ inch to calculate the thickness of the gasket after it is compressed.
In this case, ¼ = 0.25 so 0.25 minus 0.10 = 0.15 inch would be the
final distance between the mating surfaces after the gasket is
compressed. In an emergency, if compression limits are required on
this gasket, split lock washers may be used. Bend the washers until
they are flat and install enough of them (minimum of three), evenly
spaced, in the center of the gasket cross section to prevent excessive

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95
compression. The thickness of the washers should be such that the
gasket compression is limited to approximately 43%, as explained
above.
5.4 Nitrile “NBR”
Nitrile “NBR” (buna N) with 50 to 60 duro (hardness) is generally the
material that should be chosen for most transformer applications.
CAUTION:
Do not confuse this material with butyl rubber. Butyl is not a
satisfactory material for transformer gaskets. The terms
butyl and buna are easily confused, and care must be taken
to make sure nitrile (buna N) is always used and never butyl.
Replace all cork neoprene gaskets with nitrile if the joint has recesses
or expansion limiting grooves. Be careful to protect nitrile from
sunlight; it is not sunlight resistant and will deteriorate, even if only
the edges are exposed. It should not be greased when it is used in a
nonmovable (static) seal. When joints have to slide during installation
or are used as a moveable seal (such as bushing caps, oil cooler
isolation valves, and tap changer drive shafts), the gasket or O-ring
should be lubricated with a thin coating of DOW No. 111, No. 714, or
equivalent grease. These are very thin and provide a good seal.
Nitrile performs better than cork-neoprene; when exposed to higher
temperatures, it will perform well up to 65 ºC (150 ºF).
5.4.1 Viton
Viton should be used only for gaskets and O-rings in temperatures
higher than 65 ºC or for applications requiring motion (shaft seals,
etc.). Viton is very tough and wear resistant; however, it is very
expensive ($1,000+ per sheet). Therefore, it should not be used unless
it is needed for high wear or high temperature applications. Viton
should only be used with compression limiter grooves and recesses.

Transformers:
96
Store nitrile and viton separately, or order them in different colors; the
materials look alike and can be easily confused, causing a much more
expensive gasket to be installed unnecessarily. Compression and fill
requirements for Viton are the same as those for nitrile, as outlined
above and shown in table 3.
Table 3 – Transformer Gasket Application Summary
Gasket
Material
Best
Temperature
Range
Percent
Compar-
ison
Compatible
Fluids
UV
Resist
Best
Applications
Neoprene
Use nitrile,
except where
there is
ultraviolet (UV)
exposure, or
use viton.
-54 to 60 °C
(-65 to 140 °F)
not good with
temperature
swings
30
to
33
Askarels and
hydrocarbon
fluids
Yes Use only with
compression limits
or recesses and
use only if
UV resistance is
needed.
Cork-Neoprene
(Coroprene)
This material
takes a set
easily.
0 to 60 °C
(32 to 140 °F)
40 Mineral oil
R-Temp
Alpha 1
No Use only for flat to
flat surface gaskets
with no grooves or
compression limits.
Cork-Nitrile
(best) does not
take a set as
easily as cork-
neoprene.
-5 to 60 °C
(23 to 140 °F)
40 Mineral oil
R-Temp
Alpha 1
No Use only for flat to
flat surface gaskets
with no grooves or
compression limits.
Nitrile
(Buna N)
Use this except
in high
temperature,
high wear, or
UV.
-5 to 65 °C
(23 to 150 °F)
25
to
50
Mineral oil
R-Temp,
Alpha 1
Excellent for
Hydrocarbon
fluids
No O-rings, flat and
extruded gaskets;
use with
compression
limiters or recess
only.
1
Viton
Use for high
wear
and high
temperature
applications.
-20 to 150 °C
(-4 to 302 °F)
30
to
33
Silicone,
Alpha 1
Mineral oil
Yes High temperature;
O-rings, flat and
extruded gaskets;
use with
compression limiter
groove or recess.
2
1
Nitrile (buna N) can also be used in low wear applications and temperatures less than
65 °C.
2
Viton O-rings are best for wear resistance and tolerating temperature variations.

Transformers:
97
OD ID−
2
5.5 Gasket Sizing for Standard Groove Depths
Nitrile is the chosen example because it is the most commonly used
material for transformer gasketing. As shown in table 3, nitrile
compression should be 25 to 50%. Nitrile sheets are available in
1/16-inch-thick increments.
Gasket thickness is determined by groove depth and standard gasket
thickness. Choose the sheet thickness so that ¼ to ⅓ thickness of the
gasket will protrude above the groove; this is the amount available to
be compressed (see table 4). Gasket sheets come in standard
thicknesses in 1/16-inch increments. Choose one that allows a of the
gasket to stick out above the groove, if possible, but never choose a
thickness that allows less than ¼ or as much as ½ of the gasket to
protrude above the groove. Do not try to remove old primer from the
groove.
Table 4 – Vertical Groove Compression for Circular Nitrile Gasket
Standard groove
depth
(in inches)
Recommended
gasket thickness
(in inches)
Available to
compress
(in inches)
Available
compression
(percent)
3/32 1/8 1/32 25
1/8 3/16 1/16 33
3/16 1/4 1/16 25
1/4 3/8 1/8 33
3/8 1/2 1/8 25
Horizontal groove fill is determined by how wide the groove is. The
groove width is equal to the outer diameter (OD) minus the inner
diameter (ID) divided by two:
Or just measure the groove width with an accurate caliper.

Transformers:
98
Room left for the gasket to expand while being compressed is equal to
the width of the groove minus the width of the gasket. For nitrile, the
amount of horizontal room needed is about 15 to 25%. Therefore, you
need to cut the gasket cross section so that it fills about 75 to 85% of
the width of the groove.
For example, an 8-inch OD groove with a 6-inch ID,
OD ID−
2 , is
8 6
2
−
=
1 inch. Therefore, the width of the groove is 1 inch. Because we have
to leave 25% expansion space, the width of the gasket is 75% of
1 inch, or ¾ inch. So that the gasket can expand equally toward the
center and toward the outside, you should leave one-half the expansion
space at the inner diameter of the groove and one-half at the outer. In
this example, there should be a total space of 25% of 1 inch or
(¼ inch) for expansion after the gasket is inserted, so you should leave
⅛-inch space at the OD and ⅛-inch space at the ID. See figure 44.
Always cut the outer diameter first. In this example, the outer
diameter would be 8 inches minus ¼ inch, or 7¾ inches.
Figure 44 – Cross Section of Circular Gasket in Groove.

Transformers:
99
NOTE:
Since ⅛-inch space is required all around the gasket,
¼ inch must be subtracted to allow ⅛-inch on both sides.
The inner diameter would be 6 inches plus ¼ inch, or
6¼ inches. Note that ¼ inch is subtracted from the OD but
added to the ID.
To check yourself, subtract the inner radius from the outer radius to
make sure you get the same gasket width calculated above. In this
example, 3⅞ inches (outer radius, ½ of 7¾), minus 3⅛ inches (inner
radius, ½ of 6¼), is ¾ inch, which is the correct gasket width.
5.6 Rectangular Nitrile Gaskets
Rectangular nitrile gaskets larger than sheet stock on hand can be
fabricated by cutting strips and corners with a table saw or a utility
knife with razor blade. Applying a little transformer oil or WD-40 oil
makes cutting easier. Nitrile is also available in spools in standard
ribbon sizes. The ends may be joined using a cyanoacrylate adhesive
(super glue). Although there are many types of this glue, only a few of
them work well with nitrile. Since all these glues have a very limited
shelf life, remember to always keep them refrigerated to extend their
shelf life. Lawson Rubber Bonder No. 92081 best withstands
temperature changes and compression. The Lawson part number is
90286, and it is available from Lawson Products Co. in Reno, Nevada,
(702-856-1381). Loctite 404 also works but does not survive
temperature variations as well. It is available at NAPA Auto Parts
Stores. Shelf life is critical. Always secure a new supply when a
gasketing job is started; never use an old bottle that has been on the
shelf since the last job.

Transformers:
100
NOTE:
Maximum horizontal fill of the groove should be 75 to 85%, as
explained above in the circular gasket section. However, it is
not necessary to fill the groove fully to 75% to obtain a good
seal. Choose the width of ribbon that comes close to, but
does not exceed, 75 to 80%. If one standard ribbon width fills
only 70% of the groove and the next size standard width fills
90%, choose the size that fills 70%. As in the circular groove
explained above, place the gasket so that expansion space is
equal on both sides. The key point is that the cross-sectional
area of the gasket remains the same while the cover is
tightened; the thickness decreases, but the width increases.
See below and figure 45.
CAUTION:
Nitrile (buna N) is a synthetic rubber compound and, as cover
bolts are tightened, the gasket is compressed. Thickness of
the gasket is decreased, and the width is increased. If a
gasket is too large, rubber will be pressed into the void
between the cover and the sealing surface. This will prevent a
metal-to-metal seal, and a leak will result. It is best if the
cross-sectional area of the gasket is a little smaller than the
groove cross-sectional area. As cover bolts are tightened, the
thickness of the gasket decreases, but the width increases so
that cross-sectional area (thickness times the width) remains
the same. Care must be taken to ensure that the gasket
cross-sectional area is equal to or slightly smaller (never
larger) than the groove cross-sectional area. This will provide
space for the rubber to expand in the groove so that it will not
be forced out into the metal-to-metal contact area (see figure
45). If it is forced out into the “metal-to-metal” seal area, a
leak generally will be the result. When this happens, our first
response is to tighten the bolts, which bends the cover around
the gasket material in the metal-to-metal contact area. The
leak may stop (more often, it will not); but the next time the
cover is removed, getting a proper seal is almost impossible
because the cover is bent. Take extra care to correctly size
the gasket to prevent these problems.

Transformers:
101
Figure 45 – Cross Section of Gasket Remains Constant
Before Tightening and After. wxd = gw x gt

Transformers:
102
CAUTION:
On some older bushings used on 15-kV voltages and above,
it is necessary to install a semiconductive gasket. This type
bushing (such as GE type L) has no ground connection
between the bottom porcelain skirt flange and the ground
ring. The bottom of the skirt is normally painted with a
conductive paint, and then a semiconductive gasket is
installed. This allows static electric charges to bleed off to
the ground. The gaskets are typically a semiconductive
neoprene material. Sometimes, the gasket will have
conductive metal staples near the center to bleed off these
charges. When replacing this type gasket, always replace
with like material. If like gasket material is not available, use
cork-neoprene.
NOTE:
Failure to provide a path for static electric charges to get to
the ground will result in corona discharges between the
ground sleeve and the bushing flange. The gasket will be
rapidly destroyed, and a leak will result.
When bonding the ends of ribbon together, the ends should be cut at an
angle (scarfed) at about 15 degrees. The best bond occurs when the
length of the angle cut is about four times the thickness of the gasket
(see table 5). With practice, a craftsperson can cut 15-degree scarfs
with a utility knife. A jig can also be made from wood to hold the
gasket at a 15-degree angle for cutting and sanding. The ends may be
further fine-sanded or ground on a fine bench grinder wheel to match
perfectly before applying glue.
Thin metal conductive shim stock may be folded over the outer
perimeter around approximately one-half the circumference. These
pieces of shim stock should be evenly spaced around the
circumference and stick far enough in toward the center so that they
will be held when the bolts are tightened. As an example, if the gasket

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Table 5 – Vertical Groove Compression for Rectangular Nitrile Gaskets
Standard
Groove
Depth
(inches)
Standard
Ribbon
Width
(inches)
Recommended
Gasket
Thickness
(inches)
Available
to Compress
(inches)
Available
Compression
(inches)
3/32 1/4 1/8 1/32 25
1/8 5/16 3/16 1/16 33
3/16 3/8 1/4 1/16 25
1/4 3/4 3/8 1/8 33
3/8 3/4 1/2 1/8 25
is 8 inches in diameter, the circumference would be πD or 3.1416
times 8 inches = 25.13 inches in circumference. Fifty percent of 25.13
is about 12½ inches. Cut 12 strips 1-inch wide and long enough to be
clamped by the flange top and bottom when tightened. Fold them over
the outside edge of the gasket, leaving a little more than a 1-inch space
between, so that the shim stock pieces will be as evenly spaced as
possible around the circumference.
5.7 Bolting Sequences to Avoid Sealing Problems
If proper bolt tightening sequences are not followed or if improper
torque is applied to the bolts, sealing problems will result (see
figure 46). A slight bow in the flange or lid top (exaggerated for
illustration) occurs, which applies uneven pressure to the gasket. This
bow compromises the seal, and the gasket will eventually leak.
Figure 47 illustrates proper bolting sequences for various type flanges/
covers. Bolt numbers show the correct tightening sequences.
The numbers do not have to be followed exactly; however, the dia-
gonal tightening patterns should be followed. By using proper torque
and the illustrated sequence patterns, sealing problems from improper
tightening and uneven pressure on the gasket can be avoided. Use a
torque wrench and torque bolts according to the head stamp on the
bolt. Check the manufacturer’s instruction book for pancake gasket
torque values.

Transformers:
104
Figure 46 – Bowing at Flanges.
Figure 47 – Bolt Tightening Sequences.

Transformers:
105
6. Transformer Oils
6.1 Transformer Oil Functions
Transformer oils perform at least four functions for the transformer.
Oil provides insulation, provides cooling, and helps extinguish arcs.
Oil also dissolves gases generated by oil degradation, moisture and gas
from cellulose insulation, deterioration, and gases and moisture from
exposure to atmospheric conditions. Close observation of dissolved
gases in the oil, and other oil properties, provides the most valuable
information about transformer health. Looking for trends by
comparing information provided in several DGAs and understanding
its meaning is the most important transformer diagnostic tool.
6.1.1 Dissolved Gas Analysis
After 1 month of service and once each year, and more often if a
problem is encountered, complete a DGA. This is, by far, the most
important tool for determining the health of a transformer. A DGA is
the first indicator of a problem and can identify deteriorating insulation
and oil, overheating, hot spots, partial discharge, and arcing. The
Ahealth@ of the oil is reflective of the health of the transformer itself. A
dissolved gas analysis consists of sending transformer oil samples to a
commercial laboratory for testing. The most important indicators are
the individual and total combustible gas (TCG) generation rates based
on the International Electrotechnical Commission (IEC) 60599 [13]
and IEEE C 57-104™ [12] standards.
CAUTION:
DGA is unreliable if the transformer is de-energized and has
cooled, if the transformer is new, or if it has had less than 1
to 2 weeks of continuous service after oil processing.
This section provides guidance in interpreting DGA and suggests
actions based on the analysis. There are no “quick and sure” easy

Transformers:
106
answers when dealing with transformers. Transformers are very
complex, very expensive, and very important to Reclamation; and each
one is different. Decisions must be based on experienced judgment
founded on all available data and consultation with experienced
people. Periodic DGA and proper interpretations, along with thorough
periodic inspections (covered earlier), are the most important keys to
transformer life. Each DGA must be compared to prior DGAs to
recognize trends and establish rates of gas generation .
Although examples will be presented later, there are no
universally accepted means for interpreting DGA data [16].
Transformers are very complex. Aging, chemical actions and
reactions, electric fields, magnetic fields, thermal contraction and
expansion, load variations, gravity, and other forces all interact inside
the tank. Externally, through-faults, voltage surges, wide ambient
temperature changes, and other forces (i.e., the earth’s magnetic field
and gravity) affect the transformer. There are few, if any, “cut and
dried” DGA interpretations; even experts disagree. Consultation with
others, experience, study, comparing earlier DGAs, keeping accurate
records of a transformer’s history, and noting information found when
a transformer is disassembled will increase expertise and provide life
extension to this critical equipment.
Keeping accurate records of each individual transformer is
paramount. If a prior through-fault, overload, cooling problem, or
nearby lightning strike has occurred, this information is extremely
valuable to determine what is going on inside the transformer.
Baseline transformer test information should be established when the
transformer is new, or as soon as possible thereafter. This must
include DGA, Doble, and other test results (discussed in section 9,
“Transformer Testing”).
Table 6 represents a summary of DGA transformer analysis. Table 7
is an actual example of a Reclamation transformer.

Transformers:
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Table 6 – Transformer DGA Condition Summary Table
Condition Ranges
Good Fair Poor Action
Hydrogen (H2) ppm <101 >100 <1,000 >1,000 <2,000 >2,000
Hydrogen (H2) ppm
generation/month <10 >9 <30 >29 <50 >49
Methane (CH4) ppm <121 >120 <401 >400 <1,001 >1,000
Methane (CH4) ppm
Ethane (C2H6) ppm <66 >64 <101 >100 <151 >150
Ethane (C2H6) ppm
Ethylene (C2H4) ppm <51 >50 <101 >100 <201 >200
Ethylene (C2H4) ppm
Acetylene (C2H2) ppm <36 >35 <51 >50 <81 >80
Acetylene (C2H2) ppm
generation/month <.5 >.4 <1.5 >1.49 <2.5 >2.49
Carbon Monoxide (CO) ppm <351 >350 <571 >570 <1,401 >1,400
Carbon Monoxide (CO) ppm
Carbon Dioxide (CO2) ppm <2501 >2500 <4,001 >4,000 <10,001 >10,000
Carbon Dioxide (CO2) ppm
generation/month <700 >699 <2,100 >2,099 <3,500 >3,499
CO2/CO Ratio >10 <10.1 >6 <6.1 >3.9 <4
Oxygen (O2) ppm <3,501 >3,500 <7,001 >7,000 <10,001 >10,000
Total Combustible Gas ppm <721 >720 <1,921 >1,920 <4,631 >4,631
Moisture in Oil ppm > 230 kv <6 >5 <9 >8 <13 >12
Moisture in Oil ppm < = 230 kv <10 >9 <16 >15 <21 >20
Interfacial Tension
(dynes per cm) >45 <46 >35 <36 >25 <26
Acid Number
(KOH in milligrams) <.05 >.04 <.2 >.19 <.51 >.5
Dielectric Breakdown Voltage
kV >288 kV >55 >40 <56 >24 <41 <25
kV <288 kV >55 >40 <56 >19 <41 <20
Power Factor at 25 °C % <0.5 >0.49 <1.0 >0.99 <1.51 >1.5
Oxidation Inhibitor % >0.3 >0.31 >0.2 >0.21 >0.09 <0.09
2FAL furans for
65 °C rise transformers <150 >149 <200 >199 <251 >250
2FAL furans for
55 °C rise transformers <450 >449 <600 >559 <751 >750

Transformers:
108
Table 7 – 345-kV Transformer Example
Condition Status
1 2 3 4
Tests Value Good Fair Poor Action
Hydrogen (H2) ppm 1 TRUE FALSE FALSE FALSE
Hydrogen (H2) ppm
generation/month 0.08 TRUE FALSE FALSE FALSE
Methane (CH4) ppm 3 TRUE FALSE FALSE FALSE
Methane (CH4) ppm
gerneration/month 0.25 TRUE FALSE FALSE FALSE
Ethane (C2H6) ppm 14 TRUE FALSE FALSE FALSE
Ethane (C2H6) ppm
Ethylene (C2H4) ppm 1 TRUE FALSE FALSE FALSE
Ethylene (C2H4) ppm
Acetylene (C2H2) ppm 0 TRUE FALSE FALSE FALSE
Acetylene (C2H2) ppm
generation/month 0 TRUE FALSE FALSE FALSE
Carbon Monoxide (CO) ppm 6 TRUE FALSE FALSE FALSE
Carbon Monoxide (CO) ppm
Carbon Dioxide (CO2) ppm 493 TRUE FALSE FALSE FALSE
Carbon Dioxide (CO2) ppm
CO2/CO Ratio 82.17 TRUE FALSE FALSE FALSE
Oxygen (O2) ppm 1,569 TRUE FALSE FALSE FALSE
Total Combustible Gas ppm 25 TRUE FALSE FALSE FALSE
Moisture in Oil ppm 5 TRUE FALSE FALSE FALSE
Interfacial Tension
(dynes per cm) 42.8 FALSE TRUE FALSE FALSE
Acid Number
(KOH in milligrams) 0.010 TRUE FALSE FALSE FALSE
Dielectric Breakdown
Voltage kV 34 FALSE FALSE TRUE FALSE
Power Factor at 25 °C % 0.05 TRUE FALSE FALSE FALSE
Oxidation Inhibitor % 0.05 FALSE FALSE FALSE TRUE
2FAL furans for 55 °C
rise transformer 200 TRUE FALSE FALSE FALSE

Transformers:
109
CAUTION:
Transformer engineering expertise is needed in the use of
this table. The action required may be as simple as sending
an additional oil sample to the lab or as complex as
conducting extensive testing on the transformer. It may also
include repairs, internal inspection, and/or complete
replacement of the transformer.
The condition ranges shown represent a composite of IEEE
C57-104, IEC 60599, Delta X Research’s Transformer Oil
Analysis, and many years of transformer experience.
The table above was compiled by Clarence Herron of the
Glen Canyon Field Office of Reclamation.
6.1.2 Key Gas Method
The key gas method of interpreting DGA is set forth in IEEE [12].
Key gases formed by degradation of oil and paper insulation are
hydrogen (H2), methane (CH4), ethane (C2H6), ethylene (C2H4),
acetylene (C2H2), carbon monoxide (CO), and oxygen (O2). Except
for carbon monoxide and oxygen, all these gases are formed from the
degradation of the oil itself. Carbon monoxide, carbon dioxide (CO2),
and oxygen are formed from degradation of cellulose (paper)
insulation. Carbon dioxide, oxygen, nitrogen (N2), and moisture can
also be absorbed from the air, if there is an oil/air interface or if there
is a leak in the tank. Some of our transformers have a pressurized
nitrogen blanket above the oil and, in these cases, nitrogen may be
near saturation (see table 8). Gas type and amounts are determined by
where the fault occurs in the transformer and the severity and energy
of the event. Events range from low energy events, such as partial
discharge, producing hydrogen and trace amounts of methane and
ethane, to very high energy sustained arcing, capable of generating all
the gases, including acetylene, requiring the most energy.
6.1.2.1 Four-Condition DGA Guide (IEEE C57-104) –
A four-condition DGA guide to classify risks to transformers with no

Transformers:
110
Table 8 – Dissolved Key Gas Concentration Limits
(ppm)
Status H2 CH4 C2H2 C2H4
Condition 1 100 120 35 50
Condition 2 101-700 121-400 36-50 51-100
Condition 3 701-1,800 401-1,000 51-80 101-200
Condition 4 >1,800 >1,000 >80 >200
Status C2H6 CO CO2
1
TDCG
2
Condition 1 65 350 2,500 720
Condition 2 66-100 351-570 2,500-4,000 721-1,920
Condition 3 101-150 571-1,400 4,001-10,000 1,921-4,630
Condition 4 >150 >1,400 >10,000 >4,630
CAUTION:
Transformers generate some combustible gases from normal
operation, and condition numbers for dissolved gases given
in IEEE C57-104-1991™ [12] (table 8 above) are extremely
conservative. Transformers can operate safely with indi-
vidual gases in Condition 4 with no problems, provided they
are stable and gases are not increasing or are increasing
very slowly. If TDCG and individual gases are significantly
increasing (more than 30 ppm per day [ppm/day]), an active
fault is in progress. The transformer should be de-energized
when Condition 4 levels are reached.
previous problems has been published in the Standard IEEE Standard
(Std) [20], C57-104™. The guide uses combinations of individual
gases and total combustible gas concentration as indicators. It is not
universally accepted and is only one of the tools used to evaluate
dissolved gas in transformers. The four IEEE® conditions are defined
below, and gas levels are in table 8.
Condition 1: Total dissolved combustible gas (TDCG) below
this level indicates the transformer is operating satisfactorily.

Transformers:
111
Any individual combustible gas exceeding specified levels in
table 8 should have additional investigation.
Condition 2: TDCG within this range indicates greater than normal
combustible gas level. Any individual combustible gas exceeding
specified levels in table 8 should have additional investigation. A fault
may be present. Take DGA samples at least often enough to calculate
the amount of gas generation per day for each gas. (See table 9 for
recommended sampling frequency and actions.)
Condition 3: TDCG within this range indicates a high level of
decomposition of cellulose insulation and/or oil. Any individual
combustible gas exceeding specified levels in table 6 should have
additional investigation. A fault or faults are probably present. Take
DGA samples at least often enough to calculate the amount of gas
generation per day for each gas (see table 9).
Condition 4: TDCG within this range indicates excessive
decomposition of cellulose insulation and/or oil. Continued operation
could result in failure of the transformer (see table 9).
A sudden increase in key gases and the rate of gas production is
more important in evaluating a transformer than the accumulated
amount of gas. One very important consideration is acetylene (C2H2).
Generation of any amount of this gas above a few ppm indicates
high-energy arcing. Trace amounts (a few ppm) can be generated
by a very hot thermal fault (500 EC or higher). A one-time arc,
caused by a nearby lightning strike or a high-voltage surge, can
also generate a small amount of C2H2. If C2H2 is found in the
DGA, oil samples should be taken weekly, or even daily, to determine
if additional C2H2 is being generated. If no additional acetylene is
found and the level is below the IEEE® Condition 4, the transformer
may continue in service. However, if acetylene continues to increase,
the transformer has an active high-energy internal arc and should
be taken out of service immediately. Further operation is extremely

Transformers:
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Table 9 – Actions Based on Dissolved Combustible Gas (Adapted from [12])
Sampling Intervals and Operating
Actions for Gas Generation Rates
Conditions
TDCG Level or
Highest Individual Gas
(See table 8)
TDCG
Generation
Rates
(ppm/day)
Sampling
Interval
Operating
Procedures
<10 Annually: 6 months
for extra high-
voltage transformer
10-30 Quarterly
Continue normal
operation.
Condition 1 <720 ppm of TDCG or
highest condition based
on individual combustible
gas from table 8.
>30 Monthly Exercise caution.
Analyze individual
gases to find
cause. Determine
load dependence.
<10 Quarterly
10-30 Monthly
Condition 2 721–1,920 ppm of TDCG
or highest condition
based on individual
combustible gas from
table 8.
>30 Monthly
Exercise caution.
Analyze individual
gases to find cause.
Determine load
dependence.
<10 Monthly
10-30 Weekly
Condition 3 1,941–2,630 ppm of
TDCG or highest
condition based on
individual combustible
gas from table 8.
>30 Weekly
Exercise extreme
caution. Analyze
individual gases to
find cause. Plan
outage. Call
manufacturer and
other consultants for
advice.
<10 Weekly
10-30 Daily
Exercise extreme
caution. Analyze
individual gases to
find cause. Plan
outage. Call
manufacturer and
advice.
Condition 4 >4,639 ppm of TDCG or
highest condition based
on individual combustible
gas from table 8.
>30 Daily Consider removal
from service. Call
manufacturer and
advice.
NOTES:
1. Either the highest condition based on individual combustible gas or TDCG can determine the
condition (1, 2, 3, or 4) of the transformer. For example, if the TDCG is between 1,941 ppm and
2,630 ppm, this indicates Condition 3. However, if hydrogen is greater than 1,800 ppm, the
transformer is in Condition 4, as shown in table 8.
2. When the table says Adetermine load dependence,” this means to try to find out if the gas
generation rate in ppm/day goes up and down with the load. The transformer may be overloaded or
have a cooling problem. Take oil samples every time the load changes; if load changes are too
frequent, this may not be possible.
3. To get the TDCG generation rate, divide the change in TDCG by the number of days between
samples that the transformer has been loaded. Down days should not be included. The individual gas
generation rate in ppm/day is determined by the same method.

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hazardous and may result in explosive catastrophic failure of the
tank, spreading flaming oil over a large area.
Table 9 assumes that no previous DGA tests were performed on the
transformer or that no recent history exists. If a previous DGA exists,
it should be reviewed to determine if the situation is stable (gases are
not increasing significantly) or unstable (gases are increasing
significantly).
Before going to table 11, determine the transformer status from
table 10; that is, look at the DGA and see if the transformer is in
Condition 1, 2, 3, or 4. The condition for a particular transformer is
determined by finding the highest level for any individual gas or by
using the TDCG [12]. Either the individual gas or the TDCG can give
the transformer a higher condition number, which means it is at greater
risk. If the TDCG number shows the transformer in Condition 3 and
an individual gas shows the transformer in Condition 4, the
transformer is in Condition 4. Always be conservative and assume the
worst until proven otherwise.
6.1.3 Sampling Intervals and Recommended Actions
When sudden increases occur in dissolved gases, the procedures
recommended in table 9 should be followed. Table 9 is paraphrased
from table 3 in IEEE C57.104-1991 [12]. To make it easier to read,
the order has been reversed with Condition 1 (lowest risk transformer)
at the top and Condition 4 (highest risk) at the bottom. The table
indicates the recommended sampling intervals and actions for various
levels of TDCG in ppm.
An increasing gas generation rate indicates a problem of
increasing severity; therefore, as the generation rate (ppm/day)
increases, a shorter sampling interval is recommended (see table 9).
Some information has been added to the table from IEEE C57-104-
1991 (inferred from the text). To see the exact table, refer to the IEEE
Standard [12].

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If the cause of gassing can be determined and the risk can be assessed,
the sampling interval may be extended. For example, if the core is
meggered and an additional core ground is found, even though table 9
may recommend a monthly sampling interval, an operator may choose
to lengthen the sampling interval, because the source of the gassing
and generation rate is known.
A decision should never be made on the basis of just one DGA. It is
very easy to contaminate the sample by accidentally exposing it to air.
Mislabeling a sample is also a common cause of error. Mislabeling
could occur when the sample is taken, or it could be accidentally
contaminated or mishandled at the laboratory. Mishandling may allow
some gases to escape to the atmosphere and other gases, such as
oxygen, nitrogen, and carbon dioxide, to migrate from the atmosphere
into the sample. If you notice a transformer problem from the
DGA, the first thing to do is take another sample for comparison.
The gas generation chart (figure 48) [14, 17] and the discussion below
represent only an approximate temperature at which gases form. The
figure is not drawn to scale and is only for purposes of illustrating
temperature relationships, gas types, and quantities. These
relationships represent what generally has been proven in controlled
laboratory conditions using a mass spectrometer. This chart was used
by R.R. Rogers of the Central Electric Generating Board (CEGB) of
England to develop the “Rogers Ratio Method” of analyzing
transformers (discussed in section 6.1.9.4).
A vertical band on the left of the chart shows what gases and
approximate relative quantities are produced under partial discharge
conditions. Note that all the gases are given off, but in much less
quantity than hydrogen. It takes only a very low energy event (partial
discharge/corona) to cause hydrogen molecules to form from the oil.
Gases are formed inside an oil-filled transformer similar to a
petroleum refinery still, where various gases begin forming at specific
temperatures. From the Gas Generation Chart, we can see relative

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Figure 48 – Combustible Gas Generation Versus Temperature.

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amounts of gas as well as approximate temperatures. Hydrogen and
methane begin to form in small amounts around 150 ºC. Notice from
the chart that beyond maximum points, methane (CH4), ethane and
ethylene production goes down as temperature increases. At about
250 ºC, production of ethane (C2H6) starts. At about 350 ºC,
production of ethylene (C2H4) begins. Acetylene (C2H2) production
begins between 500 ºC and 700 ºC. In the past, the presence of only
trace amounts of acetylene (C2H2) was considered to indicate that a
temperature of at least 700 ºC had occurred; however, recent
discoveries have led to the conclusion that a thermal fault (hot spot) of
500 ºC can produce trace amounts (a few ppm). Larger amounts of
acetylene can only be produced above 700 ºC by internal arcing.
Notice that between 200 ºC and 300 ºC, the production of methane
exceeds hydrogen. Starting at about 275 ºC and on up, the production
of ethane exceeds methane. At about 450 ºC, hydrogen production
exceeds all others until about 750 ºC to 800 ºC; then more acetylene is
produced.
It should be noted that small amounts of H2, CH4, and CO are
produced by normal aging. Thermal decomposition of oil-
impregnated cellulose produces CO, CO2 , H2, CH4, and O2.
Decomposition of cellulose insulation begins at only about 100 ºC or
less. Therefore, operation of transformers at no more than 90 ºC is
imperative. Faults will produce internal “hot spots” of far higher
temperatures than these, and the resultant gases show up in the DGA.
Table 11 (later in this section) is a chart of “fault types,” parts of
which are paraphrased from the IEC 60599 [13]. This chart is not
complete. It is impossible to chart every cause and effect due to the
extreme complexity of transformers. DGAs must be carefully
examined with the idea of determining possible faults and possible
courses of action. These decisions are based on judgment and
experience and are seldom “cut and dried.” Most professional
associations agree that there are two basic fault types, thermal and
electrical. The first three on the chart are electrical discharges, and the
last three are thermal faults.

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Ethane and ethylene are sometimes called “hot metal gases.” When
these gases are generated and acetylene is not, the problem found
inside the transformer normally involves hot metal. This may include
bad contacts on the tap changer or a bad connection somewhere in the
circuit, such as a main transformer lead. Stray flux impinging on the
tank (such as in Westinghouse 7M series transformers) can cause these
“hot metal gases.” Sometimes, a shield becomes loose and falls and
becomes ungrounded. Static can then build up and discharge to a
grounded surface, producing “hot metal” gases. An unintentional core
ground with circulating currents can also produce these gases. There
are many other examples.
Notice that both types of faults (thermal and electrical) may be
occurring at the same time, and one may cause the other. The
associations do not mention magnetic faults; however, magnetic faults
(such as stray magnetic flux impinging the steel tank or other magnetic
structures) also cause hot spots.
6.1.4 Atmospheric Gases
Atmospheric gases (N2, CO2, and O2) can be very valuable in a DGA
in revealing a possible leak. However, as mentioned elsewhere, there
are other reasons these gases are found in DGAs. Nitrogen may exist
from shipping the transformer with N2 inside or from a nitrogen
blanket. CO2 and O2 are formed by degradation of cellulose. Be very
careful; look at several DGAs and see if atmospheric gases and,
possibly, moisture levels are increasing. Also, carefully look at the
transformer to see if you can find an oil leak. Moisture and
atmospheric gases will leak inside when the transformer is off and the
ambient temperature drops (see section 6.1.11 on moisture).
6.1.5 Dissolved Gas Software
Several companies offer DGA computer software that diagnoses
transformer problems. These diagnoses must be used with engineering
judgment and should never be taken at face value. The software is
constantly changing. The Technical Service Center uses “Transformer
Oil Analyst” (TOA) by Delta X Research that uses a composite of

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several current DGA methods. Dissolved gas analysis help is
available from the TSC through the D-8440 and D-8450 groups. Both
groups have the above software and experience in diagnosing
transformer problems.
One set of rules that TOA uses to generate alarms is based loosely on
IEC 60599 (table 10). These rules are also very useful in daily
dissolved gas analysis, which are based on L1 limits of IEC 60599,
except for acetylene. IEC 60599 gives a range for L1 limits instead of
a specific value. TOA uses the average in this range and then gives
the user a “heads up” if a generation rate exceeds 10% of L1 limits per
month. Acetylene is the exception; IEEE sets an L1 limit of 35 ppm
(too high), and IEC sets an acetylene range of 3 to 50. TOA picks the
Table 10 – TOA L1 Limits and Generation Rate Per Month
Alarm Limits
Gas L1 Limits
G1 Limits
(ppm per month)
G2 Limits
(ppm per month)
H2 100 10 50
CH4 75 8 38
C2H2 3 3 3
C2H4 75 8 38
C2H6 75 8 38
CO 700 70 350
CO2 7,000 700 3,500
NOTE:
If one or more gas generation rates are equal to or exceed
G1 limits (10% of L1 limits per month), you should begin to
pay more attention to this transformer. Reduce the DGA
sample interval, reduce loading, plan for future outage,
contact the manufacturer, etc.

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lowest number (3 ppm) and sets the generation rate alarm value at
3 ppm per month. L1 limits are the quantities at which you should
begin to watch the transformer more closely (i.e., the first level of
concern).
If one or more combustible gas generation rates are equal to or exceed
G2 limits (50% of L1 limits per month), this transformer should be
considered in critical condition. You may want to reduce sample
intervals to monthly or weekly, plan an outage, plan to rebuild or
replace the transformer, etc. If an active arc is present
(C2H2 generation), or if other heat gases are high (above Condition 4
limits in table 8), and G2 limits are exceeded, the transformer should
be de-energized.
Table 11 is taken from IEC 60599 and contains possible faults and
possible findings. This chart is not all inclusive and should be used
with other information. Additional possible faults are listed on the
following and preceding pages.
Transformers are so complex that it is impossible to put all symptoms
and causes into a chart. Several additional transformer problems are
listed below; any of these may generate gases:
1. Gases are generated by normal operation and aging, mostly
H2 and CO, with some CH4. H2 is the easiest gas to produce
except possibly CO. Production of H2 and other gases can be
caused by partial discharge (corona), sharp corners on bottom
bushing connectors, loose core ground, wet spot on core from
gasket leak above, loose corona shield on bottom of bushing,
loose tap changer shield, etc. H2 is not very stable when
dissolved in oil. Consecutive DGAs may show variation in
amounts of H2 and other unstable gases. Acetylene is the
most stable gas; variation in amounts of this gas in the
upward direction means the transformer has an active arcing
fault. If the variation is going up and down within detection

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Table 11 – Fault Types
Key Gases Possible Faults Possible Findings
H2, possible trace of CH4
and C2H6. Possible CO.
Partial discharges (corona). Weakened insulation from
aging and electrical stress.
H2, CH4, (some CO if
discharges involve paper
insulation). Possible trace
amounts of C2 H6.
Low energy discharges
(sparking).
(May be static discharges).
Pinhole punctures in paper
insulation with carbon and
carbon tracking. Possible
carbon particles in oil.
Possible loose shield, poor
grounding of metal objects
H2, CH4, C2 H6, C2H4, and
the key gas for arcing C2
H2 will be present perhaps
in large amounts. If C2 H2
is being generated, arcing
is continuing. CO will be
present if paper is being
heated.
High energy discharges
(arcing).
Metal fusion (poor contacts
in tap changer or lead
connections). Weakened
insulation from aging and
electrical stress. Carbonized
oil. Paper destruction if it is
in the arc path or
overheated.
H2, CO. Thermal fault less than
300 °C in an area close to
paper insulation (paper is
being heated).
Discoloration of paper
insulation. Overloading
and/or cooling problem. Bad
connection in leads or tap
changer. Stray current path
and/or stray magnetic flux.
H2, CO, CH4, C2H6, C2 H4. Thermal fault between
300 °C and 700 °C.
Paper insulation destroyed.
Oil heavily carbonized.
All the above gases and
acetylene in large amounts.
High energy electrical
arcing
700 °C and above.
Same as above with metal
discoloration. Arcing may
have caused a thermal fault.
limits of the test equipment (section 6.1.9.4, table 14) in
consecutive DGAs, this is simply a variation of the lab’s test
equipment and personnel.
2. Operating transformers at sustained overload will generate
combustible gases.
3. Problems with cooling systems, discussed in sections 3.3.1
and 3.4.5, can cause overheating.
4. A blocked oil duct inside the transformer can cause local
overheating, generating gases.
5. An oil directing baffle loose inside the transformer causes
misdirection of cooling oil.

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6. Oil circulating pump problems (bearing wear, impeller loose
or worn, or pump running in reverse) can cause transformer
cooling problems.
7. Oil level is too low; this will not be obvious if the level
indicator is inoperative.
8. Sludge in the transformer and cooling system (see
section 3.4.5.4).
9. Circulating stray currents may occur in the core, structure,
and/or tank.
10. An unintentional core ground may cause heating by
providing a path for stray currents.
11. A hot-spot can be caused by a bad connection in the leads or
by a poor contact in the tap changer.
12. A hot-spot may also be caused by discharges of static
electrical charges that build up on shields or core and
structures and that are not properly grounded.
13. Hot-spots may be caused by electrical arcing between
windings and ground, between windings of different
potential, or in areas of different potential on the same
winding, due to deteriorated or damaged insulation.
14. Windings and insulation can be damaged by faults
downstream (through faults), causing large current surges
through the windings. Through faults cause extreme
magnetic and physical forces that can distort and loosen
windings and wedges. The results may be arcing in the
transformer, beginning at the time of the fault, or the
insulation may be weakened and arcing will develop later.
15. Insulation can also be damaged by a voltage surge, such as a
nearby lightning strike, switching surge, or closing out of
step, which may result in immediate arcing or arcing that
develops later.

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16. Insulation may be deteriorated from age and worn out.
Clearances and dielectric strength are reduced, allowing
partial discharges and arcing to develop. This can also
reduce physical strength, allowing wedging and windings to
move extensively during a through-fault, causing total
mechanical and electrical failure.
17. High noise level (hum due to loose windings or core
laminations) can generate gas due to heat from friction.
Compare the noise to sister transformers, if possible. Sound
level meters are available at the TSC for diagnostic
comparison and to establish baseline noise levels for future
comparison.
6.1.6 Temperature
Gas production rates increase exponentially with temperature and
directly with volume of oil and paper insulation at high enough
temperature to produce gases [12]. Temperature decreases as distance
from the fault increases. Temperature at the fault center is highest, and
oil and paper, here, will produce the most gas. As distance increases
from the fault (hot spot), temperature goes down, and the rate of gas
generation also goes down. Because of the volume effect, a large
heated volume of oil and paper will produce the same amount of gas as
a smaller volume at a higher temperature [12]. We cannot tell the
difference by looking at the DGA. This is one reason that interpreting
DGAs is not an exact science.
6.1.7 Gas Mixing
Concentration of gases in close proximity to an active fault will be
higher than in the DGA oil sample. As distance increases from a fault,
gas concentrations decrease. Equal mixing of dissolved gases in the
total volume of oil depends on time and oil circulation. If there are
no pumps to force oil through radiators, complete mixing of gases
in the total oil volume takes longer. With pumping and normal
loading, complete mixing equilibrium should be reached within

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24 hours and will have little effect on DGA if an oil sample is taken
24 hours or more after a problem begins.
6.1.8 Gas Solubility
Solubilities of gases in oil vary with temperature and pressure [14].
Solubility of all transformer gases vary proportionally up and
down with pressure. Variation of solubilities with temperature
is much more complex. Solubilities of hydrogen, nitrogen,
carbon monoxide, and oxygen go up and down proportionally
with temperature. Solubilities of carbon dioxide, acetylene,
ethylene, and ethane are reversed and vary inversely with
temperature changes. As temperature rises, solubilities of these
gases go down; and as temperature falls, their solubilities increase.
Methane solubility remains almost constant with temperature changes.
Table 12 is accurate only at standard temperature and pressure (STP),
(0 ºC/32 ºF) and (14.7 psi/29.93 inches of mercury, which is standard
barometric pressure at sea level). Table 12 shows only relative
differences in how gases dissolve in transformer oil.
From the solubility table (table 12) below, comparing hydrogen with a
solubility of 7% and acetylene with a solubility of 400%, you can see
that transformer oil has a much greater capacity for dissolving
acetylene. However, 7% hydrogen by volume represents 70,000 ppm,
and 400% acetylene represents 4,000,000 ppm. You probably will
never see a DGA with numbers this high. Nitrogen can approach
maximum level if there is a pressurized nitrogen blanket above the oil.
Table 12 shows the maximum amount of each gas that the oil is
capable of dissolving at standard temperature and pressure. At these
levels, the oil is said to be saturated.
If you have conservator-type transformers and nitrogen, oxygen, and
CO2 are increasing, there is a good possibility that the tank has a leak
or that the oil may have been poorly processed. Check the diaphragm
or bladder for leaks (section 4.9) and check for oily residue around the
pressure relief device and other gasketed openings. There should be

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Table 12 – Dissolved Gas Solubility in Transformer Oil Accurate
Only at STP, 0 °C (32 °F) and 14.7 psi (29.93 Inches of Mercury)
Dissolved Gas Formula
Solubility in
Transformer Oil
(% by Volume)
Maximum
Equivalent
(ppm by Volume)
Primary Causes/
Sources
Hydrogen1
H2 7.0 70,000 Partial discharge,
corona,
electrolysis of H2O
Nitrogen N2 8.6 86,000 Inert gas blanket,
atmosphere
Carbon Monoxide1
CO 9.0 90,000 Overheated
cellulose, air
pollution
Oxygen O2 16.0 160,000 Atmosphere
Methane1
CH4 30.0 300,000 Overheated oil
Carbon Dioxide CO2 120.0 1,200,000 Overheated
cellulose,
atmosphere
Ethane1
C2H6 280.0 2,800,000 Overheated oil
Ethylene1
C2H4 280.0 2,800,000 Very overheated oil
Acetylene1
C2H2 400.0 4,000,000 Arcing in oil
1
Denotes combustible gas. Overheating can be caused both by high temperatures and by
unusual or abnormal electrical stress.
fairly low nitrogen and especially low oxygen in a conservator-type
transformer. However, if the transformer was shipped new with
pressurized nitrogen inside and has not been de-gassed properly, there
may be high nitrogen content in the DGA, but the nitrogen level
should not be increasing after the transformer has been in service for a
few years. When oil is installed in a new transformer, a vacuum is
placed on the tank that pulls out nitrogen and pulls in the oil. Oil is
free to absorb nitrogen at the oil/gas interface, and some nitrogen may
be trapped in the windings, paper insulation, and structure. In this
case, nitrogen may be fairly high in the DGAs. However, oxygen
should be very low, and nitrogen should not be increasing. It is
important to take an oil sample early in the transformer’s service life to
establish a baseline DGA; then take samples at least annually. The
nitrogen and oxygen can be compared with earlier DGAs. If they

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increase, it is a good indication of a leak. If the transformer oil has
ever been de-gassed, nitrogen and oxygen should be low in the DGA.
It is extremely important to keep accurate records over a transformer’s
life; when a problem occurs, recorded information helps greatly in
troubleshooting.
6.1.9 Diagnosing a Transformer Problem Using Dissolved Gas
Analysis and the Duval Triangle
CAUTION:
Do not use the Duval Triangle (figure 49) to determine whether or
not a transformer has a problem. Notice, there is no area on the
triangle for a transformer that does not have a problem. The
triangle will show a fault for every transformer whether it has a
fault or not. Use the above IEEE method or table 13 to determine
if a problem exists before applying the Duval Tirangle. The Duval
Triangle is used only to determine what the problem is. As with
other methods, a significant amount of gas (at least L1 limits and
G2 generation rates in table 13) must already be present before
this method is valid.
6.1.9.1 Origin of the Duval Triangle – Michel Duval of
Hydro Quebec developed this method in the 1960s using a database of
thousands of DGAs and transformer problem diagnosis. More
recently, this method was incorporated in the Transformer Oil Analyst
Software version 4 (TOA 4), developed by Delta X Research and used
by many in the utility industry to diagnose transformer problems. This
method has proven to be accurate and dependable over many years and
is now gaining in popularity. The method and how to use it are
described below.
6.1.9.2 How to Use the Duval Triangle –
1. First determine whether a problem exists by using the
IEEE® method above, and/or table 13 below. At least
one of the hydrocarbon gases or hydrogen must be in

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Table 13 – L1 Limits and Generation Rate Per Month Limits
Gas L1 Limits
G1 Limits
(ppm per month)
G2 Limits
(ppm per month)
H2 100 10 50
CH4 75 8 38
C2H2 3 3 3
C2H4 75 8 38
C2H6 75 8 38
CO 700 70 350
CO2 7,000 700 3,500
Figure 49 – The Duval Triangle.

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IEEE® Condition 3 and increasing at a generation rate (G2),
from table 13, before a problem is confirmed. To use
table 13 without the IEEE® method, at least one of the
individual gases must be at L1 level or above and the gas
generation rate must be at least at G2.
The L1 limits and gas generation rates from table 13 are more
reliable than the IEEE® method; however, one should use
both methods to confirm that a problem exists. If there is a
sudden increase in H2 with only carbon monoxide and carbon
dioxide and little or none of the hydrocarbon gases, use
section 6.1.10 (CO2/CO ratio) to determine if the cellulose
insulation is being degraded by overheating.
2. Once a problem has been determined to exist, use the total
accumulated amount of the three Duval Triangle gases and
plot the percentages of the total on the triangle to arrive at a
diagnosis. An example is shown below. Also, calculate the
amount of the three gases used in the Duval Triangle,
generated since the sudden increase in gas began.
Subtracting out the amount of gas generated prior to the
sudden increase will give the amount of gases generated
since the fault began. Detailed instructions and an example
are shown below.
a. Take the amount (ppm) of methane in the DGA and
subtract the amount of CH4 from an earlier DGA, before
the sudden increase in gas. This will give the amount of
methane generated since the problem started.
b. Repeat this process for the remaining two gases, ethylene
and acetylene.
3. Add the three numbers (differences) obtained by the process
of step 2 above. This gives 100 % of the three key gases,
generated since the fault, used in the Duval Triangle.
4. Divide each individual gas difference by the total difference
of gas obtained in step 3 above. This gives the percentage of
increase of each gas of the total increase.

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5. Plot the percentage of each gas on the Duval Triangle,
beginning on the side indicated for that particular gas. Draw
lines across the triangle for each gas, parallel to the hash
marks shown on each side of the triangle. An example is
shown below.
NOTE:
In most cases, acetylene will be zero, and the result will be a
point on the right side of the Duval Triangle.
Figure 50 – Duval Triangle Diagnostic Example of a Reclamation Transformer.

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Compare the total accumulated gas diagnosis and the diagnosis
obtained by using only the increase-in-gases after a fault. If the fault
has existed for some time, or if generation rates are high, the two
diagnoses will be the same. If the diagnoses are not the same, always
use the diagnosis of the increase in gases generated by the fault, which
will be the more severe of the two. See the example below of a
Reclamation transformer where the diagnosis using the increase in gas
is more severe than when using the total accumulated gas.
Example: Using figure 50 and the information below,
two diagnoses of a Reclamation transformer were
obtained. The first diagnosis (Point 1) was obtained
using the total amount of the three gases used by the
Duval Triangle. The second diagnosis (Point 2) was
obtained using only the increase in gases between the two
DGAs. CO and CO2 are used to evaluate cellulose.
DGA
No. 1
DGA
No. 2 Increase
DGA
No. 1
DGA
No.
2 Increase
CH4 142 192 50 CO 176 199 23
C2H4 84 170 86 CO2 1,009 2,326 1,317
C2H2 4 7 3
Total 230 369 139
Steps to Obtain the First Diagnosis (Point 1) on the Duval Triangle
(Figure 50)
1. Use the total accumulated gas from DGA 2 = 369
2. Divide each gas by the total to find the percentage of each
gas of the total.
% CH4 = 192/369 = 52%, % C2H4 = 170/369 = 46%,
% C2H2 = 7/369 = 2%

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3. Draw three lines across the Duval Triangle starting at the
percentages obtained in step 2. These lines must be drawn
parallel to the hash mark on each respective side. See the
black dashed lines in figure 50 above.
4. Point 1 is obtained where the lines intersect within the
T2 diagnostic area of the triangle, which indicates a thermal
fault between 300 and 700 °C. See figure 49, Legend, above.
Steps to Obtain the Second Diagnosis (Point 2) on the Duval Triangle
(Figure 50)
1. Use the total increase in gas = 139.
2. Divide each gas increase by the total increase to find the
percentage of each gas of the total:
% increase CH4 = 50/139 = 36%
% increase C2H4 = 86/139 = 46%
% increase C2H2 = 3/139 = 2%
3. Draw three lines across the Duval Triangle starting at the
percentages obtained in step 2. These lines must be drawn
parallel to the hash mark on each respective side. See the
white dashed lines in figure 50 above. Note that C2H2 was
the same percentage (2%) both times; and, therefore, both
lines are the same.
4. Point 2 is obtained where the lines intersect within the
T3 diagnostic area of the triangle, which indicates a thermal
fault greater than 700 °C. See figure 49, Legend, above.
The ratio of total accumulated gas is CO2/CO = 2,326/199 = 11.7.
The ratio of increase is CO2/CO = 1,317/23 = 57. Neither of these
ratios is low enough to cause concern. This shows that the thermal
fault is not close enough to the cellulose insulation to cause heat
degradation of the insulation. The large increase in CO2 could mean
an atmospheric leak.

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NOTE:
1. Point 2 is the more severe diagnosis obtained by using the
increase in gas rather than the total accumulated gas. It is helpful
to perform both methods as a check; many times both diagnoses
will come out the same.
2. CO and CO2 are included to show that the fault does not
involve severe degradation of cellulose insulation. See
section 6.1.10 for an explanation of CO2/CO ratios.
The fault is probably a bad connection on a bushing bottom, a bad
contact or connection in the tap changer, or a problem with a core
ground. These problems are probably all reparable in the field. Any
of these problems can cause the results revealed by the Duval Triangle
diagnosis above. These are areas where a fault will not degrade
cellulose insulation, which would cause the CO2/CO ratio to be much
lower than what was obtained. For information to arrive at a probable
fault see section 6.1.10.
6.1.9.3 Expertise Needed – A transformer expert should be
consulted if a problematic trend is evidenced by a number of DGAs.
The transformer manufacturer should be consulted along with DGA
lab personnel and others experienced in transformer maintenance and
diagnostics. Never make a diagnosis based on one DGA; a sample
may have been mishandled or mislabeled, either in the field or lab.
6.1.9.4 Rogers Ratio Method of DGA – Rogers Ratio Method
of DGA [19] is an additional tool that may be used to look at dissolved
gases in transformer oil. Rogers Ratio Method compares quantities of
different key gases by dividing one into the other. This gives a ratio of
the amount of one key gas to another. By looking at the Gas
Generation Chart (figure 48), you can see that, at certain temperatures,
one gas will be generated more than another gas. Rogers used these
relationships and determined that if a certain ratio existed, then a
specific temperature had been reached. By comparing a large number

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of transformers with similar gas ratios and data collected when the
transformers were examined, Rogers then could then say that certain
faults were present. Like the key gas analysis above, this method is
not a “sure thing” and is only an additional tool to use in analyzing
transformer problems. Rogers Ratio Method, using three-key gas
ratios, is based on earlier work by Doerneburg, who used five-key gas
ratios. Ratio methods are only valid if a significant amount of the
gases used in the ratio is present. A good rule is: Never make a
decision based only on a ratio if either of the two gases used in a
ratio is less than 10 times the amount the gas chromatograph can
detect [13]. This rule makes sure that instrument inaccuracies have
little effect on the ratios. If either of the gases are lower than 10 times
the detection limit, most likely you do not have the particular problem
that this ratio represents. If the gases are not at least 10 times these
limits does not mean you cannot use the Rogers Ratios; it means that
the results are not as certain as if the gases were at least at these levels.
This is another reminder that DGAs are not an exact science and there
there is no “one best, easy way” to analyze transformer problems.
Approximate detection limits are as follows, depending on the lab and
equipment (table 14).
Table 14 – Dissolved Gas Analysis
Detection Limits
Gas
Detection
Limit
Hydrogen (H2) 5 ppm
Methane (CH4) 1 ppm
Acetylene (C2H2) 1 to 2 ppm
Ethylene (C2H2) 1 ppm
Ethane (C2H6) 1 ppm
Carbon monoxide (CO) 25 ppm
Carbon dioxide (CO2) 25 ppm
Oxygen (O2) 50 ppm
Nitrogen (N2) 50 ppm

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When a fault occurs inside a transformer, there is no problem with
minimum gas amounts at which the ratio is valid. There will be more
than enough gas present.
If a transformer has been operating normally for some time and a DGA
shows a sudden increase in the amount of gas, first take a second
sample to verify that there is a problem. If the next DGA shows gases
to be more in line with prior DGAs, the earlier oil sample was
contaminated, and there is no further cause for concern. If the second
sample also shows increases in gases, the problem is real. To apply
Ratio Methods, subtract gases that were present prior to sudden gas
increases. This takes out gases that have been previously generated
due to normal aging and from prior problems. This is especially true
for ratios using H2 and the cellulose insulation gases CO and CO2 [13],
which are generated by normal aging.
Rogers Ratio Method Uses the Following Three Ratios.
C2H2/C2H4, CH4/H2, C2H4/C2H6
These ratios and the resultant fault indications are based on large
numbers of DGAs and transformer failures and what was discovered
after the failures.
There are other ratio methods, but only the Rogers Ratio Method will
be discussed since it is the one most commonly used. The method
description is paraphrased from Rogers’ original paper [19] and from
IEC 60599 [13].
Ethylene and ethane are sometimes called “hot metal gases.” Notice
that this fault does not involve paper insulation, because CO is very
low. H2 and C2H2 are both less than 10 times the detection limit. This
means the diagnosis does not have a 100% confidence level of being
correct. However, due to the high ethylene, the fault is probably a bad
connection where an incoming lead is bolted to a winding lead,
perhaps bad tap changer contacts, or additional core ground (large

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CAUTION:
Rogers Ratio Method is for fault analyzing, not for fault
detection. You must have already decided that you have a
problem from the total amount of gas (using IEEE limits) or
increased gas generation rates. Rogers Ratios will only give you
an indication of what the problem is; it cannot tell you whether or
not you have a problem. If you already suspect a problem, based
on total combustible gas levels or increased rate-of-generation,
then you normally already will have enough gas for this method to
work. A good system to determine whether you have a problem is
to use table 9 in the Key Gas Method. If two or more of the key
gases are in Condition 2 and the gas generation is at least 10%
per month of the L1 limit, you have a problem. Also, for the
diagnosis to be valid, gases used in ratios should be at least 10
times the detection limits given earlier. The more gas you have,
the more likely the Rogers Ratio Method will give a valid
diagnosis. The reverse is also true; the less gas you have, the
less likely the diagnosis will be valid. If a gas used in the
denominator of any ratio is zero, or is shown in the DGA as not
detected, use the detection limit of that particular gas as the
denominator. This gives a reasonable ratio to use in diagnostic
table 15. Zero codes mean that you do not have a problem in this
area.
Example 1
Example of a Reclamation Transformer DGA:
Parts per
Million
Hydrogen (H2)
Methane (CH4)
Ethane (C2H6)
Ethylene (C2H4)
Acetylene (C2H2)
Carbon Monoxide (CO)
Carbon Dioxide (CO2)
Nitrogen (N2)
Oxygen (O2)
TDCG
9
60
53
368
3
7
361
86,027
1,177
500

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Table 15 – Rogers Ratios for Key Gases
Code range of ratios C2
H2
C2
H4
CH4
H2
C2H4
C2H6
Detection limits and 10 x detection limits are
shown below:
C2H2 1 ppm 10 ppm
C2H4 1 ppm 10 ppm
CH4 1 ppm 10 ppm
H2 5 ppm 50 ppm
C2H6 1 ppm 10 ppm
<0.1
0.1-1
1-3
>3
0
1
1
2
1
0
2
2
0
0
1
2
Case Fault Type Problems Found
0 No fault 0 0 0 Normal aging
1 Low energy partial
discharge
1 1 0 Electric discharges in bubbles, caused by
insulation voids or super gas saturation in oil
or cavitation (from pumps) or high moisture in
oil (water vapor bubbles).
2 High energy partial
discharge
1 1 0 Same as above but leading to tracking or
perforation of solid cellulose insulation by
sparking, or arcing; this generally produces
CO and CO2.
3 Low energy
discharges,
sparking, arcing
1
-
2
0 1-2 Continuous sparking in oil between bad
connections of different potential or to floating
potential (poorly grounded shield, etc);
breakdown of oil dielectric between solid
insulation materials.
4 High energy
discharges, arcing
1 0 2 Discharges (arcing) with power follow
through; arcing breakdown of oil between
windings or coils, between coils and ground,
or load tap changer arcing across the
contacts during switching with the oil leaking
into the main tank.
5 Thermal fault less
than 150 °C
(see note 2)
0 0 1 Insulated conductor overheating; this
generally produces CO and CO2 because this
type of fault generally involves cellulose
insulation.
6 Thermal fault
temperature range
150-300 °C
(see note 3)
0 2 0 Spot overheating in the core due to flux
concentrations.
Items below are in order of increasing
temperatures of hot spots: small hot spots in
core; shorted laminations in core; overheating
of copper conductor from eddy currents; bad
connection on winding to incoming lead or
bad contacts on load or no-load tap changer;
circulating currents in core—this could be an
extra core ground (circulating currents in the
tank and core); this could also mean stray flux
in the tank. These problems may involve
cellulose insulation which will produce CO
and CO2.

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Table 15 – Rogers Ratios for Key Gases (continued)
Case Fault Type Problems Found
7 Thermal fault
temperature range
300-700 °C
0 2 1
8 Thermal fault
temperature range
over 700 °C
(see note 4)
0 2 2
Notes:
1. There will be a tendency for ratio C2H2 /C2H4 to rise from 0.1 to above 3 and the ratio
C2H4 /C2H6 to rise from 1-3 to above 3 as the spark increases in intensity. The code at the
beginning stage will then be 1 0 1.
2. These gases come mainly from the decomposition of the cellulose which explains the zeros in
this code.
3. This fault condition is normally indicated by increasing gas concentrations. CH4 /H2 is
normally about 1; the actual value above or below 1 is dependent on many factors, such as the
oil preservation system (conservator, N2 blanket, etc.), the oil temperature, and oil quality.
4. Increasing values of C2H2 (more than trace amounts) generally indicate a hot spot higher than
700 °C. This generally indicates arcing in the transformer. If acetylene is increasing, and
especially if the generation rate is increasing, the transformer should be de-energized; further
operation is extremely hazardous.
General Remarks:
1. Values quoted for ratios should be regarded as typical (not absolute). This means that the
ratio numbers are not “carved in stone”; there may be transformers with the same problems
whose ratio numbers fall outside the ratios shown at the top of the table.
2. Combinations of ratios not included in the above codes may occur in the field. If this occurs,
the Rogers Ratio Method will not work for analyzing these cases.
3. Transformers with on-load tap changers may indicate faults of code type 2 0 2 or 1 0 2
depending on the amount of oil interchange between the tap changer tank and the main tank.
circulating currents in the tank and core). See the two bottom
problems on table 16 (later in this chapter). This example was chosen
to show a transformer that was not a “clear cut” diagnosis.
Engineering judgment is always required.
A small quantity of acetylene is present—just above the detection limit
of 1 ppm. This is not high energy arcing due to the small amount;

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more likely, it has been produced by a one-time, nearby lightning
strike or a voltage surge.
Rogers Ratio
Code
C2H2/C2H4 = 3/368 = 0.00815 0
CH4/H2 = 60/9 = 6.7 2
C2H4/C2H6 = 368/53 = 6.9 2
This code combination is Case 8 in table 15 which indicates that
this transformer has a thermal fault hotter than 700 ˚C.
Example 2
Latest
DGA
(ppm)
Prior DGA
No. 2
(ppm)
Prior
DGA
No. 1
(ppm)
Hydrogen (H2) 26 27 17
Methane (CH4) 170 164 157
Ethane (C2H6) 278 278 156
Ethylene (C2H4) 25 4 17
Acetylene (C2H2) 2 0 0
Carbon Monoxide (CO) 92 90 96
Carbon Dioxide (CO2) 3,125 2,331 2,476
Nitrogen (N2) 67,175 72,237 62,641
Oxygen (O2) 608 1,984 440
Rogers Ratio Analysis
Based on Latest DGA
Codes
C2H2/C2H4 = 2/25 = 0.080 0
CH4/H2 = 170/2 = 6.54 2
C2H4/C2H6 = 25/27 = 0.09 0

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Notice that methane is increasing slowly, but ethane had a large
increase between samples 1 and 2 but did not increase between
samples 2 and 3. Note that two key gases (CH2 and C2H6) are above
IEEE Condition 1 in table 9, so the Rogers Ratio Method is valid. By
referring to table 15, this combination of codes is Case 6, which
indicates the transformer has a thermal fault in the temperature range
of 150 ºC to 300 ºC.
Life history of the transformer must be examined carefully. It is,
again, very important to keep accurate records of every transformer.
This information is invaluable when it becomes necessary to do an
evaluation.
The transformer in this example is one of three sister transformers that
have had increased cooling installed and are running higher loads due
to a generator upgrade several years ago. Transformer sound level
(hum) is markedly higher than for the two sister transformers. The
unit breaker experienced a fault some years ago, which placed high
mechanical stresses on the transformer. This generally means loose
windings, which can generate gas due to friction (called a thermal
fault) by Rogers Ratios. Comparison with sister units reveals almost
triple the ethane as the other two, and it is above the IEEE Condition 4.
Gases are increasing slowly; there has been no sudden rate increase in
combustible gas production. Notice the large increase in O2 and N2
between the first and second DGA and the large decrease between the
second and third. This indicates that the oil sample was exposed to air
(atmosphere) and that these two gases are inaccurate in the middle
sample.
6.1.10 Carbon Dioxide/Carbon Monoxide Ratio
This ratio is not included in the Rogers Ratio Method of analysis.
However, it is useful to determine if a fault is affecting the cellulose
insulation. This ratio is included in transformer oil analyzing software
programs, such as Delta X Research Transformer Oil Analyst. This
analysis is available from the TSC at D-8440 and D-8450 in Denver.

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Formation of CO2 and CO from the degradation of oil impregnated
paper increases rapidly with temperature. Calculate a normal
operating CO2/CO ratio at each DGA, based on the total accumulated
amount of both gases. Look at several DGAs concentrating on CO2
and CO. Experience has shown that, with normal loading and
temperatures, the CO2 generation rates runs 7 to 20 times higher than
CO. With a CO2/CO ratio above 7, there is little concern. With some
transformers, ratios down to 5 times more CO2 than CO might be
considered normal. However, be careful with a ratio below 7. If H2,
CH4, and C2H6 are increasing significantly as well as CO and the ratio
is 5 or less, there is probably a problem. Take time to know the
particular transformer by carefully checking all prior DGAs and
establishing a normal operating CO2 to CO ratio.
CAUTION:
After a suspected problem (a substantial increase in the amount of
CO), the ratio should be based on the gas generation of both CO2
and CO between successive DGAs and not on accumulated total
CO2 and CO gas levels.
If a problem is suspected, immediately take another DGA sample to
confirm the problem. Take the amount of CO2 generated between the
DGAs and divide it by the amount of CO generated at that same time
to establish the ratio. An excellent indication of abnormally high
temperatures and rapidly deteriorating cellulose insulation is a
CO2/CO under 5. If the ratio is 3 or under, severe and rapid
deterioration of cellulose is certainly occurring. In addition to DGAs,
perform the Furans test explained in the following section 7.6.
Extreme overheating from loss of cooling or plugged oil passages will
produce a CO2/CO ratio around 2 or 3 along with increasing Furans. If
this is found, de-energization and internal inspection is recommended;
the transformer is in imminent danger of failure.

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Table 16 is adapted from IEC 60599, Appendix A.1.1 [13]. Some of
the wording has been changed to reflect American language usage
rather than European.
Table 16 – Typical Faults in Power Transformers [13]
Fault Examples
Partial
discharges
Discharges in gas-filled cavities in insulation resulting from incomplete
impregnation, high moisture in paper, gas in oil supersaturation or cavitation,
(gas bubbles in oil) leading to X wax formation on paper.
Discharges
of low energy
Sparking or arcing between bad connections of different floating potential,
from shielding rings, toroids, adjacent discs or conductors of different
windings, broken brazing, closed loops in the core. Additional core grounds.
Discharges between clamping parts, bushing and tank, high voltage and
ground, within windings. Tracking in wood blocks, glue of insulating beam,
winding spacers. Dielectric breakdown of oil, load tap changer breaking
contact.
Discharges
of high
energy
Flashover, tracking or arcing of high local energy or with power follow-
through. Short circuits between low voltage and ground, connectors,
windings, bushings, and tank, windings and core, copper bus and tank, in oil
duct. Closed loops between two adjacent conductors around the main
magnetic flux, insulated bolts of core, metal rings holding core legs.
Overheating
less than
300 °C
Overloading the transformer in emergency situations. Blocked or restricted
oil flow in windings. Other cooling problem, pumps valves, etc. See the
“Cooling” section in this document. Stray flux in damping beams of yoke.
Overheating
300 to
700 °C
Defective contacts at bolted connections (especially busbar), contacts within
tap changer, connections between cable and draw-rod of bushings.
Circulating currents between yoke clamps and bolts, clamps and laminations,
in ground wiring, bad welds or clamps in magnetic shields.
Abraded insulation between adjacent parallel conductors in windings.
Overheating
over 700 °C
Large circulating currents in tank and core. Minor currents in tank walls
created by high uncompensated magnetic field. Shorted core laminations.
Notes:
1. X wax formation comes from Paraffinic oils (paraffin based). These are not used in transformers at
present in the United States but are predominate in Europe.
2. The last overheating problem in the table says “over 700 °C.” Recent laboratory discoveries have found
that acetylene can be produced in trace amounts at 500 °C, which is not reflected in this table. We have
several transformers that show trace amounts of acetylene that probably are not active arcing but are the
result of high-temperature thermal faults, as in the example. It may also be the result of one arc, due to a
nearby lightning strike or voltage surge.
3. A bad connection at the bottom of a bushing can be confirmed by comparing infrared scans of the top of
the bushing with a sister bushing. When loaded, heat from a poor connection at the bottom will migrate to
the top of the bushing, which will display a markedly higher temperature. If the top connection is checked
and found tight, the problem is probably a bad connection at the bottom of the bushing.

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6.1.11 Moisture Problems
Moisture, especially in the presence of oxygen, is extremely hazardous
to transformer insulation. Recent EPRI studies show that an oxygen
level above 2,000 ppm dissolved in transformer oil is extremely
destructive. Each DGA and Doble test result should be examined
carefully to see if water content is increasing and to determine the
moisture by dry weight (M/DW) or percent saturation in the paper
insulation. When 2% M/DW is reached, make plans for a dry out.
Never allow the M/DW to go above 2.5% in the paper or 30% oil
saturation without drying out the transformer. Each time the moisture
is doubled in a transformer, the life of the insulation is cut by one-half.
Keep in mind that the life of the transformer is the life of the paper,
and the purpose of the paper is to keep out moisture and oxygen. For
service-aged transformers rated less than 69 kV, results of up to
35 ppm at 60 °C are considered acceptable. For 69 kV through
230 kV, a DGA test result of 20 ppm at 60 °C is considered
acceptable. For greater than 230 kV, moisture should never exceed
12 ppm at 60 °C. However, the use of absolute values for water does
not always guarantee safe conditions, and the percent by dry weight
should be determined. See table 19, “Doble Limits for In-Service
Oils,” in section 7.6. If values are higher, the oil should be processed.
If the transformer is kept as dry and free of oxygen as possible,
transformer life will be extended.
Reclamation specifies that manufacturers dry new transformers to no
more than 0.5% M/DW during commissioning. That means that a
transformer with 10,000 pounds of paper insulation, has 10,000 x
0.005 = 50 pounds of water (about 6 gallons) in the paper. This is not
enough moisture to be detrimental to electrical integrity. When the
transformer is new, this water is distributed equally through the
transformer. It is extremely important to remove as much water as
possible.
When the transformer is energized, water begins to migrate to the
coolest part of the transformer and the site of the greatest electrical
stress. This location is normally the insulation in the lower one-third

Transformers:
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of the winding [6]. Paper insulation has a much greater affinity for
water than does the oil. The water will distribute itself unequally, with
much more water being in the paper than in the oil. The paper will
partially dry the oil by absorbing water out of the oil. Temperature is
also a big factor in how the water distributes itself between the oil and
paper. See table 17 below for comparison.
Table 17 – Comparison of Water Distribution in Oil and Paper [6]
Temperature
(degrees C)
Water
in Oil Water in Paper
20 1 3,000 times what is in the oil
40 1 1,000 times what is in the oil
60 1 300 times what is in the oil
Table 17 shows the tremendous attraction that paper insulation has for
water and how the water changes in the paper with temperature. The
ppm of water in oil shown in the DGA is only a small part of the water
in the transformer. When an oil sample is taken, it is important to
record the oil temperature from the top oil temperature gauge.
Some laboratories give percent M/DW of the insulation in the DGA;
others give percent oil saturation, and some give only the ppm of water
in the oil. If you have an accurate temperature of the oil and the ppm
of water, the Nomogram (figure 55, section 6.1.11.2) will give percent
M/DW of the insulation and the percent oil saturation.
Where does the water come from? Moisture can be in the insulation
when it is delivered from the factory. If the transformer is opened for
inspection, the insulation can absorb moisture from the atmosphere. If
there is a leak, moisture can enter in the form of water or humidity in
the air. Moisture is also formed by the degradation of insulation as the
transformer ages. Most water penetration is flow of wet air or rain
water through poor gasket seals due to a pressure difference caused by
transformer cooling. If a transformer is removed from service during

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rain or snow, some transformer designs cool rapidly and the pressure
inside drops. The most common moisture ingress points are gaskets
between bushing bottoms and the transformer top and the pressure
relief device gasket. Small oil leaks, especially in the oil cooling
piping, will also allow moisture ingress. With rapid cooling and the
resultant pressure drop, relatively large amounts of water and water
vapor can be pumped into the transformer in a short time. It is
important to repair small oil leaks; the small amount of visible oil is
not important in itself, but it indicates a point where moisture will
enter [23].
It is critical for life extension to keep transformers as dry and as free of
oxygen as possible. Moisture and oxygen cause the paper insulation to
decay much faster than normal and form acids, sludge, and more
moisture. Sludge settles on windings and inside the structure, causing
less efficient transformer cooling, which allows temperature to slowly
rise over a period of time. (This was discussed earlier in section
section 3.4.5.4). Acids cause an increase in the rate of decay, which
forms more acid, sludge, and moisture at a faster rate [21]. This is a
vicious cycle of increasing speed forming more acid and causing more
decay. The answer is to keep the transformer as dry as possible and as
free of oxygen as possible. In addition, oxygen inhibitor should be
watched in the DGA testing. The transformer oil should be dried
when moisture reaches the values stated in table 19 (following later in
this document). An inhibitor (ditertiary butyl paracresol [DBPC])
should be added (0.3% by weight ASTM D-3787) when the oil is
processed (see section 7.3).
Water can exist in a transformer in five forms:
1. Free water, at the bottom of the tank.
2. Ice at the tank bottom (if the oil specific gravity is greater
than 0.9, ice can float).
3. Water can be in the form of a water/oil emulsion.

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4. Water can be dissolved in the oil and is given in ppm in the
DGA.
5. Water can be in the form of humidity if transformers have an
inert gas blanket.
Free water causes few problems with dielectric strength of oil;
however, it should be drained as soon as possible. Having a water-oil
interface allows oil to dissolve water and transport it to the insulation.
Problems with moisture in insulation were discussed above. If the
transformer is out of service in winter, water can freeze. If oil specific
gravity is greater than 0.9 (ice specific gravity), ice will float. This can
cause transformer failure if the transformer is energized with floating
ice inside. This is one reason that DGA laboratories test the specific
gravity of transformer oil.
The amount of moisture that can be dissolved in oil increases with
temperature (see figure 51). This is why hot oil is used to dry out a
transformer. A water/oil emulsion can be formed by purifying oil at
too high temperature. When the oil cools, dissolved moisture forms an
emulsion [21]. A water/oil emulsion causes drastic reduction in
dielectric strength.
How much moisture in insulation is too much? When the insulation
reaches 2.5% M/DW or 30% oil saturation (given on some DGAs), the
transformer should have a dry out with vacuum, if the tank is rated for
vacuum. If the transformer is old, pulling a vacuum can do more harm
than good. In this case, it is better to do round-the-clock re-circulation
with a Bowser drying the oil as much as possible, which will pull
water out of the paper. At 2.5% M/DW, the paper insulation is
degrading much faster than normal [6]. As the paper is degraded,
more water is produced from the decay products, and the transformer
becomes even wetter and decays even faster. When a transformer gets
above 4% M/DW, it is in danger of flashover if the temperature rises
to 90 ºC.

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6.1.11.1 Dissolved Moisture in Transformer Oil – Moisture is
measured in the dissolved gas analysis in ppm. Some laboratories also
give percent saturation, which is the percent saturation of water in the
oil. This is a percentage of how much water is in the oil compared
with the maximum amount of water the oil can hold. Figure 51 shows
it can be seen that the amount of water the oil can dissolve is greatly
dependent on temperature. The curves below (figure 52) are percent
saturation curves. On the left line, find the ppm of water from your
DGA. From this point, draw a horizontal with a straight edge. From
the oil temperature, draw a vertical line. At the point where the lines
intersect, read the percent saturation curve. If the point falls between
two saturation curves, estimate the percent saturation based on where
Figure 51 – Maximum Amount of Water Dissolved
in Mineral Oil Versus Temperature.

Transformers:
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the point is located. For example, if the water is 30 ppm and the
temperature is 40 ºC, you can see on the curves that this point of
intersection falls about halfway between the 20% curve and the
30% curve. This means that the oil is approximately 25% saturated.
Curves shown on figure 52 are from IEEE 62-1995 [20].
CAUTION:
Below 30 °C, the curves are not very accurate.
6.1.11.2 Moisture in Transformer Insulation. Figure 53
shows how moisture is distributed throughout transformer insulation.
Notice that the moisture is distributed according to temperature, with
most moisture at the bottom and less moisture as temperature increases
toward the top. This example shows almost twice the moisture near
Figure 52 – Transformer Oil Percent Saturation Curves.

Transformers:
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the bottom as there is at the
top. Most service-aged
transformers fail in the lower
one-third of the windings,
which is the area of most
moisture. The area of most
moisture is also the area of
most electrical stress.
Moisture and oxygen are two
of the transformer’s worst
enemies. It is very important
to keep the insulation and oil as
dry as possible and as free of
oxygen as possible.
Failures due to moisture are the
most common cause of
transformer failures [6].
Without an accurate oil
temperature, it is impossible for laboratories to provide accurate
information about the M/DW or percent saturation. It will also be
impossible for you to calculate this information accurately.
Experts disagree on how to tell how much moisture is in the insulation
based on how much moisture is in the oil (ppm). At best, methods to
determine moisture in the insulation based solely on DGA are
inaccurate.
The methods discussed below to determine moisture levels in the
insulation are estimates, and no decision should be made based on one
DGA. However, keep in mind that the life of the transformer is the
life of the insulation. The insulation is quickly degraded by excess
moisture and the presence of oxygen. Base any decisions on several
DGAs over a period of time and establish a trend of increasing
moisture.
Figure 53 – Water Distribution in
Transformer Insulation.

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If the lab does not provide the percent M/DW, IEEE 62-1995 [20]
gives a method. From the curve (figure 54), find the temperature of
the bottom oil sample and add 5 ºC. Do not use the top oil
temperature. This estimates the temperature of the bottom third
(coolest part) of the winding, where most of the water is located.
From this temperature, move up vertically to the curve. From this
point on the curve, move horizontally to the left and find the Myers
Multiplier number. Take this number and multiply the ppm of water
shown on the DGA. The result is percent M/DW in the upper part of
the insulation. This method gives less amount of water than the
General Electric nomogram (figure 55).
Figure 54 – Myers Multiplier Versus Temperature.

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This nomogram,
published by General
Electric in 1974, gives
the percent saturation of
oil and percent M/DW of
insulation. Use the
nomogram to check
yourself after you have
completed the method
illustrated in figure 54.
The nomograph in
figure 55 will show more
moisture than the
IEEE method.
The curves in
figure 55 are useful
to help understand
relationships between
temperature, percent
saturation of the oil,
and percent M/DW
of the insulation. For
example, pick a point
on the ppm water line
(10 ppm). Place a
straight edge on that
point and pick a point on
the temperature line
(45 ºC). Read the
percent saturation
and percent M/DW on the center lines. In this example, percent
saturation is about 6.5%, and the % M/DW is about 1.5%. Now, hold
the 10 ppm point and move the sample temperature upward (cooler)
and notice how quickly the moisture numbers increase. For example,
use 20 ºC and read the percent saturation of oil at about 18.5% and the
Figure 55 – Water Content of Paper
and Oil Nomogram.

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% M/DW at about 3.75%. The cooler the oil, the higher the moisture
percentage for the same ppm of water in the oil.
Do not make a decision on dry out based on only one DGA and one
calculation; it should be based on trends over a period of time. Take
additional samples and send them for analysis. Take extra care to
make sure the oil temperature is correct. You can see by the
nomogram that moisture content varies dramatically with temperature.
Take extra care that the sample is not exposed to air. After using the
more conservative IEEE method, if, again, subsequent samples show
M/DW is 2.5% or more and the oil is 30% saturated or more, the
transformer should be dried as soon as possible. Check the nomogram
and curves above to determine the percent saturation of the oil. The
insulation is degrading much faster than normal due to the high
moisture content. Drying can be an expensive process; it is prudent to
consult with others before making a final decision to implement dry
out. However, it is much less expensive to perform a dry out than to
allow a transformer to degrade faster than normal, substantially
shortening transformer life.
7. Transformer Oil Tests That Should Be
Completed Annually with the Dissolved Gas
Analysis
7.1 Dielectric Strength
This test measures the voltage where the oil electrically breaks down.
The test gives a good indication of the amount of contaminants (water
and oxidation particles) in the oil. DGA laboratories typically use
ASTM D-1816. Using the D-1816 test, the minimum oil
breakdown voltage is 20 kV for transformers rated less than
288 kV and 25 kV for transformers 287.5 kV and above. If the
dielectric strength test falls below these numbers, the oil should be
reclaimed. Do not base any decision on one test result or on one type
of test; instead, look at all the information over several DGAs and
establish trends before making any decision. The dielectric strength

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test is not extremely valuable; moisture in combination with oxygen
and heat will destroy cellulose insulation long before the dielectric
strength of the oil has given a clue that anything is going wrong [6].
The dielectric strength test also reveals nothing about acids and sludge.
The tests explained below are much more important.
7.1.1 Interfacial Tension
This test (ASTM D-791-91 [22]), is used by DGA laboratories to
determine the interfacial tension between the oil sample and distilled
water. The oil sample is put into a beaker of distilled water at a
temperature of 25 ºC. The oil should float because its specific gravity
is less than that of water (specific gravity of water is one). There
should be a distinct line between the two liquids. The IFT number is
the amount of force (dynes) required to pull a small wire ring upward a
distance of 1 centimeter through the water/oil interface. (A dyne is a
very small unit of force equal to 0.000002247 pound.) Good, clean oil
will make a very distinct line on top of the water and give an
IFT number of 40 to 50 dynes per centimeter of travel of the wire.
As the oil ages, it is contaminated by tiny particles (oxidation
products) of the oil and paper insulation. Particles on top of the water
extend across the water/oil interface line that weaken the surface
tension between the two liquids. Particles in oil weaken interfacial
tension and lower the IFT number. The IFT and acid numbers,
together, are an excellent indication of when the oil needs to be
reclaimed. It is recommended that the oil be reclaimed when the
IFT number falls to 25 dynes per centimeter. At this level, the oil is
very contaminated and must be reclaimed to prevent sludging, which
begins around 22 dynes per centimeter. See FIST 3-5 [21].
If oil is not reclaimed, sludge will settle on windings, insulation,
cooling surfaces, etc., and cause loading and cooling problems, as
discussed earlier. This will greatly shorten transformer life.
A definite relationship exists between the acid number, the IFT, and
the number of years in service. The accompanying curve (figure 56)

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shows the relationship and is found in many publications. (It was
originally published in the AIEE transactions in 1955.) Notice that the
curve shows the normal service limits for both the IFT and the acid
number.
7.2 Acid Number
Acid number (acidity) is the amount of potassium hydroxide (KOH) in
milligrams (mg) that it takes to neutralize the acid in 1 gram (gm) of
transformer oil. The higher the acid number, the more acid is in the
oil. New transformer oils contain practically no acid. Oxidation of the
insulation and oils forms acids as the transformer ages. The oxidation
products form sludge and precipitate out inside the transformer. The
acids attack metals inside the tank and form soaps (more sludge).
Acid also attacks cellulose and accelerates insulation degradation.
Sludging begins when the acid number reaches 0.40; it is obvious that
the oil should be reclaimed before it reaches 0.40. It is recommended
Figure 56 – Interfacial Tension, Acid Number,
Years in Service.

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that the oil be reclaimed when it reaches 0.20 mg potassium hydroxide
per gram (KOH/gm) [21]. As with all others, this decision must not be
based on one DGA test, but watch for a rising trend in the acid number
each year. Plan ahead and begin budget planning before the acid
number reaches 0.20.
7.3 Test for Oxygen Inhibitor
In previous sections, the need to keep the transformer dry and O2 free
was emphasized. Moisture is destructive to cellulose, and even more
so in the presence of oxygen. Some publications state that each time
you double the moisture (ppm), you halve the life of the transformer.
As was discussed, acids are formed that attack the insulation and
metals that form more acids, causing a viscous cycle. Oxygen
inhibitor is a key to extending the life of transformers. The inhibitor
currently used is ditertiary butyl paracresol (DBPC). This works
similar to a sacrificial anode in grounding circuits. The oxygen attacks
the inhibitor instead of the cellulose insulation. As this occurs and the
transformer ages, the inhibitor is used up and needs to be replaced.
Replacement of the inhibitor also generally requires treatment of the
oil [6]. The ideal amount of DBPC is 0.3% by total weight of the oil
(shown on the transformer nameplate) [30].
Test the inhibitor content with the DGA every 3 to 5 years. If the
inhibitor is 0.08%, the transformer is considered uninhibited, and the
oxygen freely attacks the cellulose. If the inhibitor falls to 0.1%, the
transformer should be re-inhibited. For example, if your transformer
tested 0.1%, you need to go to 0.3% by adding 0.2% of the total
weight of the transformer oil. The nameplate gives the weight of oil—
for example, 5,000 pounds—so 5,000 pounds x 0.002 = 10 pounds of
DBPC needs to be added. Adding a little too much DBPC does not
hurt the oil. Dissolve 10 pounds of DBPC in the transformer oil that
you have heated to the same temperature as the oil inside the
transformer. It may take experimenting some to get the right amount
of oil to dissolve the DBPC. Mix the oil and inhibitor in a clean

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container until all the DBPC is dissolved. Add this mixture to the
transformer, using the method given in the transformer’s instruction
manual for adding oil.
CAUTION:
Do not attempt this unless you have had experience. Contact an
experienced contractor or experienced Reclamation personnel if
you need help.
In either case, do not neglect this important maintenance function; it is
critical to transformer insulation to have the proper amount of oxygen
inhibitor.
7.4 Power Factor
Power factor indicates the dielectric loss (leakage current) of the oil.
This test may be completed by the DGA laboratories. It may also be
completed by Doble testing. A high power factor indicates
deterioration and/or contamination by products, such as water, carbon,
or other conducting particles; metal soaps caused by acids (formed as
mentioned above); attacking transformer metals; and products of
oxidation. The DGA labs normally test the power factor at 25 ºC and
100 ºC. Doble information [25] indicates that the inservice limit for
power factor is less than 0.5% at 25 ºC. If the power factor is greater
than 0.5% and less than 1.0%, further investigation is required; the oil
may require replacement or fullers earth filtering. If the power factor
is greater than 1.0% at 25 ºC, the oil may cause failure of the
transformer; replacement or reclaiming is required. Above 2%, oil
should be removed from service and replaced because equipment
failure is imminent. The oil cannot be reclaimed.

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7.5 Oxygen
Oxygen must be watched closely in DGA tests. Many experts and
organizations, including EPRI, believe that oxygen levels in the oil
above 2,000 ppm greatly accelerate paper deterioration. This becomes
even more critical with moisture above safe levels. Under the same
temperature conditions, cellulose insulation in low oxygen oil will last
10 times longer than insulation in high oxygen oil [6]. It is
recommended that if oxygen reaches 10,000 ppm in the DGA, the oil
should be de-gassed and new oxygen inhibitor installed. High
atmospheric gases (O2 and N2) normally mean that a leak has
developed in a bladder or diaphragm in the conservator. If there is no
conservator and pressurized nitrogen is on top of the oil, expect to see
high nitrogen but not high oxygen. Oxygen comes only from leaks
and from deteriorating insulation.
7.6 Furans
When cellulose insulation decomposes due to overheating, organic
compounds, in addition to CO2 and CO, are released and dissolved
in the oil. These chemical compounds are known as furanic
compounds or furans. The most important one, for our purposes, is
2-furfuraldehyde. When DGAs are required, always request that
furans testing be completed by the laboratory to check for paper
deterioration. In healthy transformers, there are no detectable furans in
the oil, or they are less than 100 parts per billion (ppb). In cases where
significant damage to paper insulation from heat has occurred, furan
levels may be at least 100 ppb and up to 70,000 ppb. Furanic content
in the oil is especially helpful in estimating remaining life in the paper
insulation, particularly if several prior tests can be compared and
trends established.
Use the furan numbers in table 18 for assessment; do not base any
evaluation on only one test; use several DGAs over a period of time to
develop trending. See An Introduction to the Half-Century
Transformer by the Transformer Maintenance Institute, S.D. Myers
Co., 2002 [39]. The first column in table 18 is used for transformers

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Table 18 – Furans, DP, Percent of Life Used of Paper Insulation
55 °C Rise
Transformer
2FAL
(ppb)
65 °C Rise
Trans-former
Total Furans
(ppb)
Estimated
Degree of
Polymerization
(DP)
Estimated
Percentage
of Remaining
Life Interpretation
58 51 800 100
130 100 700 90
292 195 600 79
Normal Aging
Rate
654 381 500 66
1,464 745 400 50
1,720 852 380 46
2,021 974 360 42
Accelerated
Aging Rate
2,374 1,113 340 38
2,789 1,273 320 33
3,277 1,455 300 29
Excessive Aging
Danger Zone
3,851 1,664 280 24
4,524 1,902 260 19
High Risk of
Failure
5,315 2,175 240 13
6,245 2,487 220 7
7,337 2,843 200 0
End of Expected
Life of Paper
Insulation and of
the Transformer

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with non-thermally upgraded paper, and the second column is for
transformers with thermally upgraded paper.
Testing is completed for five different furans which are caused by
different problems. The five furans and their most common causes are
listed below:
♦ 5H2F (5-hydroxymethyl-2-furaldehyde) caused by oxidation
(aging and heating) of the paper
♦ 2FOL (2-furfurol) caused by high moisture in the paper
♦ 2FAL (2-furaldehyde) caused by overheating
♦ 2ACF (2-acetylfuran) caused by lightning (rarely found in DGA)
♦ 5M2F (5-methyl-2-furaldehyde) caused by local severe
overheating (hotspot)
Doble inservice limits are reproduced below to support the above
recommended guidelines.
Table 19 is excerpted from Doble Engineering Company’s Reference
Book on Insulating Liquids and Gases [25]. These Doble Oil Limit
tables support information given in prior sections and are shown here
as summary tables.
Additional guidelines given in table 20 are useful.

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Table 19 – Doble Limits for Inservice Oils
Voltage Class
# 69 kV
>69 #
288 kV >288 kV
Dielectric Breakdown Voltage, D 877,
kV minimum
26 30
1
D 1816, .04-inch gap, kV, minimum
20 20 25
Power Factor at 25 °C, D 924, maximum 0.5 0.5 0.5
Water Content, D 1533, ppm, maximum
2
35
2
25
2
20
Interfacial Tension, D 971, dynes per
centimeter (dynes/cm), minimum
25 25 25
Neutralization Number, D 974, mg KOH/gm,
maximum
0.2 0.15 0.15
Visual Exam clear and
bright
clear and
bright
clear
Soluble Sludge ND
3
ND
3
ND
3
1
D 877 test is not as sensitive to dissolved water as the D 1816 test and should
not be used with oils for extra high-voltage (EHV) equipment. Dielectric breakdown
tests do not replace specific tests for water content..
2
The use of absolute values of water-in-oil (ppm) do not always guarantee safe
conditions in electrical apparatus. The percent by dry weight should be determined
from the curves provided. See the information in section 6.1.11.2.
3
ND = None detectable.
These recommended limits for inservice oils are not intended to be used as absolute
requirements for removing oil from service but to provide guidelines to aid in
determining when remedial action is most beneficial. Remedial action will vary
depending upon the test results. Reconditioning of oil, that is, particulate removal
(filtration) and drying, may be required if the dielectric breakdown voltage or water
content do not meet these limits. Reclamation (clay filtration) or replacement of the
oil may be required if test values for power factor, interfacial tension, neutralization
number, or soluble sludge do not meet recommended limits.

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Table 20 – Additional Guidelines for Inservice Oils
Power factor at 25 °C
< 0.5% Acceptable
> 0.5 < 1.0% Investigate, oil may require replacement or clay
treatment
> 1.0 < 2.0% Investigate, oil may cause failure of the
equipment, oil may require replacement or clay
treatment
> 2.0% Remove from service, investigate, oil may
require replacement or clay treatment
Neut. No.
(mg KOH/gm)
IFT
(dynes/cm)
< 0.05 $25 Acceptable
$ 0.05 < 0.15 $ 22 < 25 Clay treat or replace at convenience  345 kV,
clay treat or
replace in immediate future
$0.15 < 0.5 $16 > 22 Clay treat or replace in immediate future
$0.5 <16 Replace
1
1
When an oil is allowed to sludge in service, special treatment may be required
to clean the core, coil, and tank.
7.7 Oil Treatment Specifications
After the oil is treated, the results should be as follows.
Gases Physical Properties
H2 5 ppm or less Water less than 10 ppm
CH4 5 ppm or less IFT 40 dynes/cm minimum
C2H2 0 ppm Acid number 0.03 mg KOH/gm maximum
CO 20 ppm or less O2 inhibitor 0.3% by oil weight
CO2 300 ppm or less
O2 4,000 ppm or less

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Dielectric strength,
ASTM D1816-97,
kV minimum, ≥ 69 kV
> 69 to < 230
kV
230 kV
and above
1-mm
1
gap (0.04-in) 23 28 30
2-mm gap (0.08-in) 40 47 50
1
millimeter (mm).
7.7.1 Taking Oil Samples for DGA
Sampling procedures and lab handling are usually areas that cause the
most problems in getting an accurate DGA. There are times when
atmospheric gases, moisture, or hydrogen take a sudden leap from one
DGA to the next. As has been mentioned, at these times, one should
immediately take another sample to confirm DGA values. It is, of
course, possible that the transformer has developed an atmospheric
leak or that a fault has suddenly occurred inside. More often, the
sample has not been taken properly, or it has been contaminated with
atmospheric gases or mishandled in other ways. The sample must be
protected from all contamination, including atmospheric exposure.
Do not take samples from the small sample ports located on the side of
the large sample (drain) valves. These ports are too small to
adequately flush the large valve and pipe nipple connected to the tank;
in addition, air can be drawn past the threads and contaminate the
sample. Fluid in the valve and pipe nipple remain dormant during
operation and can be contaminated with moisture, microscopic stem
packing particles, and other particles. The volume of oil in this
location can also be contaminated with gases, especially hydrogen.
Hydrogen is one of the easiest gases to form. With hot sun on the side
of the transformer tank where the sample valve is located, high
ambient temperature, high oil temperature, and captured oil in the
sample valve and extension, hydrogen formed will stay in this area
until a sample is drawn.
The large sample (drain) valve can also be contaminated with
hydrogen by galvanic action of dissimilar metals. Sample valves are

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usually brass; a brass pipe plug should be installed when the valve is
not being used. If a galvanized or black iron pipe plug is installed in a
brass valve, the dissimilar metals produce a thermocouple effect, and
circulating currents are produced. As a result, hydrogen is generated
in the void between the plug and valve gate. If the valve is not
thoroughly flushed, the DGA will show a high hydrogen level.
Oil should not be sampled for DGA purposes when the transformer is
at or below a freezing temperature. Test values which are affected by
water (such as dielectric strength, power factor, and dissolved moisture
content) will be inaccurate.
CAUTION:
Transformers must not be sampled if there is a negative pressure
(vacuum) at the sample valve.
This is typically not a problem with conservator transformers. If the
transformer is nitrogen blanketed, look at the pressure/vacuum gauge.
If the pressure is positive, go ahead and take the sample. If the
pressure is negative, a vacuum exists at the top of the transformer. If
there is a vacuum at the bottom, air will be pulled in when the sample
valve is opened. Wait until the pressure gauge reads positive before
sampling. Pulling in a volume of air could be disastrous if the
transformer is energized.
If negative pressure (vacuum) is not too high, the weight of oil (head)
will make positive pressure at the sample valve, and it will be safe to
take a sample. Oil head is about 2.9 feet (2 feet 10.8 inches) of oil per
psi. If it is important to take the sample even with a vacuum showing
at the top, proceed as described below.
Use the sample tubing and adaptors described below to adapt the large
sample valve to ⅛-inch tygon tubing. Fill a length (2 to 3 feet) of
tygon tubing with new transformer oil (no air bubbles) and attach one

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end to the pipe plug and the other end to the small valve. Open the
large sample (drain) valve a small amount and very slowly crack open
the small valve. If oil in the tygon tubing moves toward the
transformer, shut off the valves immediately. Do not allow air to
be pulled into the transformer. If oil moves toward the transformer,
there is a vacuum at the sample valve. Wait until the pressure is
positive before taking the DGA sample. If oil is pushed out of the
tygon tubing into the waste container, there is a positive pressure, and
it is safe to proceed with DGA sampling. Shut off the valves and
configure the tubing and valves to take the sample per the instructions
below.
7.7.1.1 DGA Oil Sample Container – Glass sample syringes
are recommended. There are different containers, such as stainless
steel vacuum bottles and others. Using only glass syringes is
recommended. If there is a small leak in the sampling tubing or
connections, vacuum bottles will draw air into the sample, which
cannot be seen inside the bottle. The sample will show high
atmospheric gases and high moisture if the air is humid. Other
contaminates such as suspended solids or free water cannot be seen
inside the vacuum bottle. Glass syringes are the simplest to use
because air bubbles are easily seen and expelled. Other contaminates
are easily seen, and another sample can be immediately taken if the
sample is contaminated. The downside is that glass syringes must be
handled carefully and must be protected from direct sunlight. They
should be returned to their shipping container immediately after taking
a sample. If they are exposed to sunlight for any time, hydrogen will
be generated, and the DGA will show false hydrogen readings.
For these reasons, glass syringes are recommended, and the
instructions below include only this sampling method.
Obtain a brass pipe plug (normally 2 inches) that will thread into the
sample valve at the bottom of the transformer. Drill and tap the pipe
plug for ⅛-inch national pipe thread, insert a ⅛-inch pipe nipple (brass
if possible) and attach a small ⅛-inch valve for controlling the sample

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flow. Attach a ⅛-inch tygon tubing adaptor to the small valve outlet.
Sizes of the piping and threads above do not matter; any arrangement
with a small sample valve and adaptor to ⅛-inch tygon tubing will
suffice. See figure 57.
7.7.1.2 Taking the Sample
♦ Remove the existing pipe plug and inspect the valve opening for
rust and debris.
♦ Crack open the valve and allow just enough oil to flow into the
waste container to flush the valve and threads. Close the valve and
wipe the threads and outlet with a clean dry cloth.
♦ Re-open the valve slightly and flush approximately 1 quart of oil
into the waste container.
Figure 57 – Oil Sampling Piping.

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♦ Install the brass pipe plug (described above) and associated ⅛-inch
pipe and small valve, and a short piece of new ⅛-inch tygon tubing
to the outlet of the ⅛-inch valve.
♦ Never use the same sample tubing on different transformers. This
is one way a sample can be contaminated and give false readings.
♦ Open both the large valve and small sample valve and allow
another quart to flush through the sampling apparatus. Close both
valves. Do this before attaching the glass sample syringe. Make
sure the short piece of tygon tubing that will attach to the sample
syringe is installed on the ⅛-inch valve before you do this.
♦ Install the glass sample syringe on the short piece of ⅛-inch
tubing. Turn the stopcock handle on the syringe so that the handle
points toward the syringe. Note: The handle always points
toward the closed port. The other two ports are open to each
other. See figure 58.
♦ Open the large sample valve a small amount and adjust the ⅛-inch
valve so that a gentle flow goes through the flushing port of the
glass syringe into the waste bucket.
Figure 58 – Sampling Syringe (Flushing).

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♦ Slowly turn the syringe stopcock handle so that the handle points
to the flushing port (figure 59). This closes the flushing and allows
oil to flow into the sample syringe. Do not pull the syringe handle;
this will create a vacuum and allow bubbles to form. The syringe
handle (piston) should back out very slowly. If it moves too fast,
adjust the small ⅛-inch valve until the syringe slows and hold your
hand on the back of the piston so you can control the travel.
♦ Allow a small amount, about 10 cubic centimeters (cc), to flow
into the syringe and turn the stopcock handle again so that it points
to the syringe. This will again allow oil to come out of the
flushing port into the waste bucket.
♦ Pull the syringe off the tubing, but do not shut off the oil flow.
Allow the oil flow to continue into the waste bucket.
♦ Hold the syringe vertical and turn the stopcock up so that the
handle points away from the syringe. Press the syringe piston to
eject any air bubbles, but leave 1 or 2 cc of oil in the syringe. See
figure 60.
CAUTION:
Do not eject all the oil, or air will re-enter.
Figure 59 – Sampling Syringe (Filling).

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♦ Turn the stopcock handle toward the syringe. The small amount of
oil in the syringe should be free of bubbles and ready to receive the
sample. If there are still bubbles at the top, repeat the process until
you have a small amount of oil in the syringe with no bubbles.
♦ Reattach the tygon tubing. This will again allow oil to flow out of
the flushing port. Slowly turn the stopcock handle toward the
flushing port which again will allow oil to fill the syringe. The
syringe piston will again back slowly out of the syringe. Allow the
syringe to fill about 80% full. Hold the piston so you can stop its
movement at about 80% full.
CAUTION:
Do not pull the piston. This will cause bubbles to form.
Figure 60 – Sample Syringe Bubble Removal.

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♦ Close the stopcock by turning the handle toward the syringe. Oil
again will flow into the waste container. Shut off both valves,
remove the sampling apparatus, and reinstall the original pipe plug.
CAUTION:
Do not eject any bubbles that form after the sample is collected;
these are gases that should be included in the lab sample.
♦ Return the syringe to its original container immediately. Do not
allow sunlight to impact the container for any length of time.
Hydrogen will form and give false readings in the DGA.
♦ Carefully package the syringe in the same manner that it was
shipped to the facility and send it to the lab for processing.
♦ Dispose of waste oil in the plant waste oil container.
8. Silicone Oil-Filled Transformers
8.1 Background
Silicone oils became more common when polychlorinated biphenols
were discontinued. They are mainly used in transformers inside
buildings and are smaller than generator step-up transformers.
Silicone oils have a higher fire point than mineral oils and, therefore,
are used where fire concerns are more critical. As of this writing,
there are no definitive published standards. IEEE has a guide, and
Doble has some service limits, but there are no standards. Information
below is taken from the IEEE publication, from Doble, from articles,
from IEC 60599 concepts, and from Delta X Research’s/Transformer
Oil Analyst rules. Silicone oil dissolved gas analysis is in the
beginning stage, and the suggested methods and limits below are

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subject to change as we gain more experience. However, in the
absence of any other methods and limits, use the ones below as a
beginning.
Silicone oils used in transformers are polydimethylsiloxane fluids,
which are different than mineral oils. Many of the gases generated by
thermal and electrical faults are the same. The gases are generated in
different proportions than with transformer mineral oils. Also, some
fault gases have different solubilities in silicone oils than in mineral
oils. Therefore, the same faults would produce different
concentrations and different generation rates in silicone oils than
mineral oils.
As with mineral oil-filled transformers, three principal causes of gas
generation are aging, thermal faults, and/or electrical faults resulting in
deterioration of solid insulation and deterioration of silicone fluid.
Overheating of silicone oils causes degradation of fluid and generation
of gases. Generated gases depend on the amount of dissolved oxygen
in the fluid, temperature, and how close bare copper conductors are to
the heating. When a transformer is new, silicone oil will typically
contain a lot of oxygen. Silicone transformers are typically sealed and
pressurized with nitrogen. New silicone oil is not de-gassed; and, as a
rule, oxygen concentration will be equivalent to oxygen solubility
(maximum) in silicone. The silicone has been exposed to atmosphere
for some time during manufacture of the transformer and manufacturer
and storage of silicone oil itself. Therefore, carbon monoxide and
carbon dioxide are easily formed and dissolved in the silicone due to
the abundance of oxygen in the oil, resulting from this atmospheric
exposure. In normal new silicone transformers (no faults), both carbon
monoxide and carbon dioxide will be generated in the initial years of
operation. As the transformer ages and oxygen is depleted, generation
of these gases slows, and concentrations level off [27]. See figure 61
for the relationship of decreasing oxygen and increasing carbon
monoxide and carbon dioxide as a transformer ages. This curve is for
general information only and should not be taken to represent any

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particular transformer. A real transformer with changes in loading,
ambient temperatures, and various duty cycles would make these
curves look totally different.
After the transformer is older (assuming no faults have occurred),
oxygen concentration will reach equilibrium (figure 61). Reaching
equilibrium may take a few years, depending on the size of the
transformer, loading, ambient temperatures, etc. After this time,
oxygen, carbon monoxide, and carbon dioxide level off; and the
rate of production of these gases from normal aging should be
relatively constant. If generation rates of these gases change greatly
(seen from the DGA), a fault has occurred, either thermal or electrical.
Rate of generation of these gases and amounts can be used to roughly
determine what the fault is. Once you notice a significant increase
in rate of generation of any gas, it is a good idea to subtract the
amount of gas that was already in the transformer before this
Figure 61 – Relationship of Oxygen to Carbon Dioxide and
Carbon Monoxide as Transformer Ages.

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increase. This ensures that gases used in the diagnosis are only
gases that were generated after the fault began.
8.2 Carbon Monoxide in Silicone Transformers
Carbon monoxide will be a lot higher in a silicone transformer than a
mineral oil-filled one. It is difficult to try to determine what is
producing the CO. Is it coming from normal aging of oil or from
deterioration of paper from a fault condition? The only solution is a
furan analysis. If the CO content is greater than the IEEE limit of
3,000 ppm [28] (table 19, shown later in this manual), and the
generation rate G1 is met or exceeded, a furan analysis is
recommended with the annual DGA. If a thermal fault is occurring
and is producing CO and small amounts of methane and hydrogen, the
fault may be masked by the normal production of CO from the silicone
oil itself. If the CO generation rate has greatly increased, along with
other gases, it becomes obvious that a fault has occurred. The furan
analysis can only tell if the paper is involved (being heated) in the
fault.
8.3 Comparison of Silicone Oil and Mineral Oil
Transformers
Some general conclusions can be drawn by comparing silicone oil and
mineral oil transformers.
1. All silicone oil-filled transformers will have a great deal
more CO than normal mineral oil-filled transformers. CO
can come from two sources—the oil itself and from
degradation of paper insulation. If the DGA shows little
other fault in gas generation besides CO, the only way to tell
for certain if CO is coming from paper degradation (a fault)
is to run a furan analysis with the DGA. If other fault gases
are also being generated in significant amounts, in addition to
CO, there obviously is a fault, and CO is coming from paper
degradation.

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2. There will generally be more hydrogen present than in a
mineral oil-filled transformer.
3. Due to “fault masking,” mentioned above, it is almost
impossible to diagnose what is going on inside a silicone-
filled transformer based solely on DGA. One exception is
that if acetylene is being generated, there is an active arc.
Look also at gas generation rates and operating history. Look
at loading history, through faults, and other incidents. It is
imperative that detailed records of silicone oil-filled
transformers be carefully kept up to date. These are
invaluable when a problem is encountered.
4. If acetylene is being generated, there is a definitely an active
electrical arc. The transformer should be removed from
service.
5. In general, oxygen in a silicone-filled transformer comes
from atmospheric leaks or was present in the transformer oil
when it was new. This oxygen is consumed as CO and CO2
are formed from the normal heating from operation of the
transformer.
6. Once the transformer has matured and the oxygen has leveled
off and remained relatively constant for two or more DGA
samples, if you see a sudden increase in oxygen, and perhaps
carbon dioxide and nitrogen, the transformer has developed a
leak.
8.4 Gas Limits
Table 21 shows IEEE limits [28], compared with Doble [27] in a study
of 299 operating transformers. The table of gases from the Doble
study seems more realistic, showing gas level average of 95% of
transformers in the study. Note, with the last four gases, limits given
by the IEEE (trial use guide) run over 70% higher than the Doble 95%
norms. But with the first three gases, hydrogen, methane, and ethane,
the IEEE limits are well below the amount of gas found in 95% norms

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Table 21 – Comparison of Gas Limits
Gas Doble 95% Norm IEEE Limits
Hydrogen 511 200
Methane 134 100
Ethane 26 30
Ethylene 17 30
Acetylene 0.6 1
CO 1,749 3,000
CO2 15,485 30,000
Total Combustibles 2,024 3,360
in the Doble study. We obviously cannot have limits that are below
the amount of gas found in normal operating transformers. Therefore,
it is suggested that we use the Doble (95% norm) limits. The
95% norm limit means that 95% of the silicone oil transformers
studied had gas levels below these limits. Obviously, 5% had gases
higher than these limits. These are problem transformers that we
should pay more attention to.
In table 22, the IEEE limits for L1 were chosen. For L2 limits, a
statistical analysis was applied, and two standard deviations were
added to L1 to obtain L2. For L3 limits, the L1 limits were doubled.
Limits L1, L2, and L3 represent the concentration in individual
gases in ppm. G1 and G2 represent generation rates of individual
gases in ppm per month. To obtain G1 and G2 in ppm per day,
divide the per month numbers by 30. Except for acetylene, G1 is
10% of L1, and G2 is 50% of L1. The generation rates (G1, G2)
are points where our level of concern should increase, especially
when considered with the L1, L2, and L3 limits. At G2 generation
rate, we should be extremely concerned, reduce the DGA sampling
interval accordingly, and perhaps plan an outage, etc.

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Table 22 – Suggested Levels of Concern (Limits)
Gas
L1
(ppm)
L2
(ppm)
L3
(ppm)
G1
(ppm
per month)
G2
(ppm
per month)
Hydrogen 200 240 400 20 100
Methane 100 125 200 10 50
Ethane 30 40 60 3 15
Ethylene 30 25 60 3 15
Acetylene 1 2 3 1 1
CO 3,000 3,450 6,000 300 1,500
CO2 30,000 34,200 60,000 1,500 15,000
TDCG 3,360 3,882 6,723 NA NA
Except for acetylene, generation rate levels G1 and G2 were taken
from IEC 60599 [13] which is used with mineral oil transformers.
Any amount of ongoing acetylene generation means active arcing
inside the transformer. In this case, the transformer should be
removed from service. These criteria were chosen because of an
absence of any other criteria. As DGA criteria for silicone oils
becomes better known and the quantified table 22 will change to
reflect new information.
As with mineral oil-filled transformers, gas generation rates are
much more important than the amount of gas present. Total
accumulated gas depends greatly on age (an older transformer has
more gas). If the rate of generation of any combustible gas shows a
sudden increase in the DGA, immediately take another oil sample to
confirm the gas generation rate increase. If the second DGA confirms
a generation rate increase, get some outside advice. Be careful; gas
generation rates increase somewhat with temperature variations caused
by increased loading and summer ambient temperatures. However,
higher operating temperatures are also the most likely conditions for a
fault to occur. The real question is, has the increased gas generation

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rate been caused by a fault or increased temperature from greater
loading or higher ambient temperature?
If gas generation rates are fairly constant (no big increases and less
than G1 limits above), what actions need to be taken if a transformer
exceeds the L1 limits? Begin to pay more attention to that
transformer, just as with a mineral oil transformer. It may be
necessary to shorten the DGA sampling interval, reduce loading, check
transformer cooling, get some outside advice, etc. As with mineral oil
transformers, age exerts a big influence in accumulated gas. Be much
more concerned if a 3-year old transformer has exceeded the L1 limits
than if a 30-year old transformer exceeds the limits. However, if
G1 generation rates are exceeded in either an old or new transformer,
the level of concern should be stepped up.
If accumulated gas exceeds the L2 limit, it may be wise to plan to have
the transformer de-gassed. Examine the physical tests in the DGAs
and compare them to the Doble/IEEE table (table 23) (Reference Book
on Insulating Liquids and Gasses) [25]. The oil should be treated in
whatever manner is appropriate, if these limits are exceeded.
If both L1 limits and G1 limits are exceeded, be more concerned.
Reduce sampling intervals, get outside advice, reduce loading, check
transformer cooling and oil levels, etc. If G2 generation limits are
exceeded, be extremely concerned. It will not be long before
L3 limits are exceeded, and consider removing the transformer from
service for testing, repair, or replacement.
If acetylene is being generated, the transformer should be taken
out of service. However, as with mineral oil transformers, a one-time
nearby lightning strike or through fault can cause a “one-time”
generation of acetylene. If you notice acetylene in the DGA,
immediately take another sample. If the amount of acetylene is
increasing, an active electrical arc is present within the
transformer. It should be taken out of service.

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With critical silicone (or mineral oil-filled transformer), such as a
single station service transformer or excitation transformer, a spare
should be available at another facility. If there are no other possible
spares, consider beginning the budget process for purchasing a spare
transformer.
8.5 Physical Test Limits
Table 23 lists test limits for service-aged silicone filled transformer oil.
If any of these limits are exceeded, treat the oil in whatever manner is
appropriate to return the oil to serviceable condition.
Table 23 – Doble and IEEE Physical Test Limits for Service-Aged Silicone Fluid
Test
Acceptable
Limits
Unacceptable
Values Indicate
ASTM
Test Method
Visual Clear free of
particles
Particulates,
free water
D 1524
D 2129
Dielectric breakdown
voltage
30 kV Particulates,
dissolved water
D 877
Water content
maximum
70 ppm (Doble)
100 ppm (IEEE)
Dissolved water
contamination
D 1533
Power factor
maximum at 25 °C
0.2 Polar/ionic
contamination
D 924
Viscosity at
25 °C, cSt
47.5–52.5 Fluid degradation
contamination
D 44
Acid neutralization
number maximum,
mg KOH/gm
0.1 (Doble)
0.2 (IEEE)
Degradation of
cellulose or
contamination
D 974
Note: If only one number appears, both Doble and IEEE have the same limit.
If the above limits are exceeded in the DGA, the silicone oil should be
filtered, dried, or treated to correct the specific problem.

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9. Transformer Testing
Transformer testing falls into three broad categories: factory testing
when the transformer is new or has been refurbished, acceptance
testing upon delivery, and field testing for maintenance and diagnostic
purposes. Some tests at the factory are common to most power
transformers, but many of the factory tests are transformer-specific.
Figure 68 (shown later in this manual) lists several tests. This test
chart has been adapted from IEEE 62-1995 reference [20]. Not all of
the listed tests are performed at the factory, and not all of them are
performed in the field. Each transformer and each situation is
different, requiring its own unique approach and tests.
9.1 DC Winding Resistance Measurement
CAUTION:
Do not attempt to run an excitation current test immediately
after any direct current (dc) test. Energizing with dc will
leave a residual magnetism in the core and will ruin the
results of the excitation current test.
If generation of ethylene, ethane, and perhaps methane in the DGAs
indicates a poor connection, winding resistances should be checked.
Turns ratio, sweep frequency response analysis (SFRA), Doble tests,
or relay operations may give indications that dc testing is warranted.
Winding resistances are tested in the field to check for loose
connections on bushings or tap changers, broken strands, and high
contact resistance in tap changers. Results are compared to other
phases in wye-connected transformers or between pairs of terminals on
a delta-connected winding to determine if a resistance is too high.
Resistances can also be compared to the original factory measurements
or to sister transformers. Agreement within 5% for any of the above
comparisons is considered satisfactory. If winding resistances are to

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be compared to factory values, resistance measurements will have to
be converted to the reference temperature used at the factory (usually
75 °C). To do this, use the following formula:
Rs = Resistance at the factory reference temperature
(found in the transformer manual)
Rm = Resistance you actually measured
Ts = Factory reference temperature (usually 75 ºC)
Tm = Temperature at which you took the measurements
Tk = Constant for the particular metal the winding is
made from: 234.5 ºC for copper, 225 ºC for
aluminum
It is very difficult to determine actual winding temperature in the
field; and, normally, this is not needed. The above temperature
corrections are necessary only if resistance is to be compared to
factory values. Normally, phase resistances are compared to each
other or to sister transformers at the same temperature, and actual
winding temperatures and corrections are not needed.
Compare winding resistances to factory values; change in these values
can reveal serious problems. A suggested method to obtain an
accurate temperature is outlined below. If a transformer has just been
de-energized for testing, the winding will be cooler on the bottom than
the top, and the winding hot spot will be hotter than the top oil
temperature. The average winding temperature is needed, and it is
important to get the temperature as accurate as possible for
comparisons.
TkTm
TkTs
RmRs
+
+
=

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The most accurate method is to allow the transformer to sit de-
energized until temperatures are equalized. This test can reveal
serious problems, so it’s worth the effort.
Winding resistances are measured using a Wheatstone Bridge for
values of 1 ohm or above and using a micro-ohmmeter or Kelvin
Bridge for values under 1 ohm. A multi-amp (now AVO) makes a
good instrument for these measurements, which is quick and easy to
use. Take readings from the top of each bushing to neutral for wye-
connected windings and across each pair of bushings for delta-
connected windings. If the neutral bushing is not available on wye-
connected windings, take each one to ground (if the neutral is
grounded) or take readings between pairs of bushings as if it were a
delta winding. Be consistent each time so that a proper comparison
can be made. The tap changer can also be changed from contact to
contact, and the contact resistance can be checked. Make sure to take
the first test with the tap changer “as found.” Keep accurate records
and connection diagrams so that later measurements can be compared.
9.2 Core Insulation Resistance and Inadvertent
Core Ground Test (Megger®)
CAUTION:
Do not attempt to run excitation or SFRA tests on a
transformer immediately after using dc test equipment.
Residual magnetism will remain in the core and ruin the
excitation current and SFRA test results.
Core insulation resistance and core ground test is used if an
unintentional core ground is suspected; this may be indicated by the
DGA. Key gases to look for are ethane and/or ethylene and possibly
methane. These gases may also be present if there is a poor
connection at the bottom of a bushing or a bad tap changer contact.

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Therefore, this test is only necessary if the winding resistance test
(section 9.1) shows all connections and tap changer contacts in good
condition.
The intentional core ground must be disconnected. This may be
difficult, and some oil may have to be drained to accomplish this. On
some transformers, core grounds are brought outside through insulated
bushings and are easily accessed. A standard dc Megger®
(1,000-volt
Megger®
is recommended) is then attached between the core ground
lead (or the top of the core itself and the tank [ground]). The Megger®
is used to place a dc voltage between these points, and the resistance
is measured. A new transformer should read greater than
1,000 megohms. A service-aged transformer should read greater than
100 megohms. Ten to one-hundred megohms is indicative of
deteriorating insulation between the core and ground. Less than
10 megohms is sufficient to cause destructive circulating currents and
must be further investigated [20]. A solid, unintentional core ground
may read zero ohms; this, of course, causes destructive circulating
currents and must be corrected before energization.
Some limited success has been obtained in “burning off” unintentional
core grounds using a dc or ac current source. This is a risky operation,
and the current may cause additional damage. The current source is
normally limited to a maximum of 40 to 50 amps and should be
increased slowly to use as little current as possible to accomplish the
task. This should only be used as a last resort and then only with
consultation from the manufacturer, if possible, and with others
experienced in this task.
CAUTION:
This will generate gases which will be dissolved in the oil and
will show up in the DGA! Take a sample for DGA with in
72 hours after burning off the unintentional core ground and
compare this DGA with the prior one to determine what
gases were created by this task.

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9.3 Doble Tests on Insulation
Doble testing is important to determine the condition of a transformer,
because it can detect winding and bushing insulation integrity and
problems in the winding and core. Doble tests are conducted in the
field on de-energized transformers using special test equipment.
Generally, a Doble M-4000 test set is used along with accompanying
software. The software automatically performs analysis of test results
and responds with a four letter code: G = Good, I = Investigate, D =
Deteriorated, and B = Bad. These codes refer to insulation quality. If
a “D” or “B” code is encountered, the insulation should be re-tested,
carefully investigated, and the problem explained before re-energizing.
Other tests may have to be performed; and, perhaps, an internal
inspection should be considered before the unit is re-energized. The
Doble Company should be consulted, along with the transformer
manufacturer, and other transformer experts. If the problem is severe,
the unit may have to be taken out of service.
9.3.1 Insulation Power Factor Test
The purpose of this test is to determine the state of dryness of the
windings and insulation system and to determine a power factor for the
overall insulation, including bushings, oil, and windings. It is a
measure of the ratio of the power (I2
R) losses to the voltamperes
applied during the test. The power factor obtained is a measure of
watts lost in the total transformer insulation system, including the
bushings. The power factor should not exceed 0.5% at 20 EC.
Temperature correction of test results can be performed automatically
on the Doble test set. The watts lost should not exceed one-half of one
percent of the total power input (voltamperes) from the test. The
values obtained at each test are compared to previous tests and
baseline factory tests, and a trend can be established as the insulation
system ages.
9.3.2 Capacitance Test
This test measures and records the capacitance (including bushings)
between the high and low-voltage windings, between the high-voltage
winding and the tank (ground), and between the low-voltage winding

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and the tank (ground). Changes in these values as the transformer ages
and events occur, such as nearby lightning strikes or through faults,
indicate winding deformation and structural problems, such as
displaced wedging and winding support.
9.3.3 Excitation Current Test
CAUTION:
Perform the excitation test before any dc tests. Excitation
current tests should never be conducted after a dc test has
been performed on the transformer. Results will be incorrect
because of residual magnetism of the core left from the dc
tests.
The purpose of this test is to detect short-circuited turns, poor
electrical connections, core de-laminations, core lamination shorts, tap
changer problems, and other possible core and winding problems. On
three-phase transformers, results are also compared between phases.
This test measures current needed to magnetize the core and generate
the magnetic field in the windings. Doble software only gives two
indications on this test: “G” for good and “Q” for questionable. On a
three-phase, wye/delta or delta/wye transformer test, the excitation
current pattern will be two phases higher than the remaining phase.
Compare the two higher currents only. If the excitation current is less
than 50 milliamps (mA), the difference between the two higher
currents should be less than 10%. If the excitation current is more than
50 mA, the difference should be less than 5%. In general, if there is an
internal problem, these differences will be greater. When this
happens, other tests should also show abnormalities, and an internal
inspection should be considered. The results, as with all others, should
be compared with factory and prior field tests.

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9.3.4 Bushing Tests
For bushings that have a potential tap, both the capacitance between
the top of the bushing and the bottom tap (normally called C1), and the
capacitance between the tap and ground (normally called C2) are
measured. To determine bushing losses, power factor tests are also
performed. C2 capacitance is much greater than C1. Bushings
without a potential tap are normally tested from the bushing top
conductor to ground and Ahot collar@ tests. These test results are
compared with factory tests and/or prior tests to determine
deterioration. About 90% of bushing failures may be attributed to
moisture ingress, evidenced by an increasing power factor from Doble
testing on a scheduled basis.
9.3.5 Percent Impedance/Leakage Reactance Test
This is normally an acceptance test to see that nameplate percent
impedance agrees with the measured percent impedance when the
transformer arrives onsite. Normally, a 3% difference is considered
acceptable. However, after the initial benchmark test, the percent
impedance should not vary more than 2% from benchmark. As the
transformer ages or suffers events such as through faults, nearby
lightning strikes, and other surges, this test is used in the field to detect
winding deformation. Winding deformation can lead to immediate
transformer failure after a severe through fault, or a small deformation
can lead to a failure years later.
Percent impedance/leakage reactance testing is performed by short
circuiting the low-voltage winding and applying a test voltage to the
high-voltage winding. Reluctance is resistance to lines of magnetic
flux. Reluctance to the magnetic flux is very high in spaces between
the high- and low-voltage windings and spaces between the windings
and core. Reluctance is very low through the magnetic core so that the
vast majority of total reluctance is in the spaces. When winding
movement (distortion) occurs, these spaces change. Therefore, the
reluctance changes, resulting in a change in the measured leakage
reactance. Changes in leakage reactance and in capacitance tests
(explained in section 9.3.2) serve as an excellent indicator of winding

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movement and structural problems (displaced wedging, etc.). This test
does not replace excitation current tests or capacitance tests but
complement them, and they are used together. The excitation current
test relies on reluctance of the core while the leakage reactance test
relies on reluctance of the spaces. See Doble’s Leakage Reactance
Instrument Users Guide, and IEEE®, Guide for Diagnostic Field
Testing of Electric Power Apparatus-Part 1: Oil-Filled Power
Transformers, Regulators, and Reactors (IEEE 62-1995™ [20]).
9.3.6 Sweep Frequency Response Analysis Tests
CAUTION:
Do not attempt to run a sweep frequency response analysis
test immediately after any dc test. Energizing with dc will
leave a residual magnetism in the core and will offset the
results of the SFRA test.
These tests show, in trace form, the winding transfer function of the
transformer and are valuable to determine if any damage has occurred
during shipping or during a through fault. Core grounds, core
displacement, and other core and winding problems can be revealed by
this test.
These tests should be conducted before and after the transformer has
been moved or after experiencing a through fault. Results should be
compared to baseline tests performed at the factory or as soon as
possible after receiving the transformer. If the SFRA tests cannot be
performed at the factory, they should be conducted as an acceptance
test before energizing a new or rebuilt transformer to establish a
baseline. A baseline should be established for older inservice
transformers during a normal Doble test cycle. If possible, one should
use the same test equipment for baseline and following tests, or the
results may not be comparable.

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For a delta/wye transformer, a test voltage of variable frequency
(normally 20 hertz [Hz] to 2 megahertz [MHz]) is placed across each
phase of the high-voltage winding. With this set of tests, low-voltage
windings are isolated with no connections on any of the bushings. An
additional set of tests is performed by short circuiting all the low-
voltage windings and again placing the test voltage on each phase of
the high-voltage winding. A third set of tests is made by isolating the
high-voltage winding and placing the test voltage across each low-
voltage winding. See the M5100 SFRA Instrument Users Guide,
Doble Engineering Company [36] for connection details.
Figure 62 is a picture of test traces on a new three-phase Reclamation
transformer. The top three traces were taken on the low-voltage side:
X1-X3, X2-X1, and X3-X2. The two outside windings (A and C
phases) have the same general shape with a “W” at the lowest point of
the trace, while the inside winding (B phase) has a “V” at the bottom.
The high-voltage traces (lower three) have the same characteristics.
Note that, in both high- and low-voltage tests, the traces fall almost
Figure 62 – SFRA Test Traces of a New Transformer.

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perfectly on top of each other for the outside windings (A and C),
while the inside winding (B phase), is slightly displaced to the left.
These are characteristic traces of a three-phase transformer in good
condition; these traces will be the baseline for future tests on this
transformer.
By comparing future traces with baseline traces, the following can be
noted. In general, the traces will change shape and be distorted in the
low frequency range (under 5,000 Hz) if there is a core problem. The
traces will be distorted and change shape in higher frequencies (above
10,000 Hz) if there is a winding problem. Changes of less than
3 decibels (dB) compared to baseline traces are normal and within
tolerances. From 5 Hz to 2 kilohertz (kHz), changes of + or – 3 dB (or
more) can indicate shorted turns, open circuit, residual magnetism, or
core movement. From 50 Hz to 20 kHz +/- 3 dB (or more), a change
from baseline can indicate bulk movement of windings relative to each
other. From 500 Hz to 2 MHz, changes of +/- 3 dB (or more) can
indicate deformation within a winding. From 25 Hz to 10 MHz,
changes of +/- 3 dB (or more) can indicate problems with winding
leads and/or test leads placement. The above diagnostics come from
the Euro-Doble Client Committee after much testing experience and
analysis. Note that there is a great deal of overlap in frequencies,
which can mean more than one diagnosis.
Figure 63 shows traces of a transformer with a problem. This
transformer is not Reclamation-owned, and test results are used for
illustration only. The traces have the same general positions on the
graph as the good transformer. The lower traces are high-voltage
winding tests, while the upper traces are the low-voltage winding tests.
Note in the higher frequencies of the low-voltage traces that “A” phase
(X1-X0 green trace) is displaced from the other two phases more than
3 dB from about 4 kHz to about 50 kHz. With a healthy transformer,
these would fall almost on top of each other as the other two phases
do. Also notice that “A” phase (H1-H3 Lsh) is displaced in the test
with the low-voltage winding shorted. There is an obvious problem
with “A” phase on the low-voltage side. After opening the

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transformer, it was found that the “A” phase winding lead had burned
off near the winding connection and re-welded itself on the winding at
a different location, effectively shorting out a few turns. The
transformer was still working, but hot metal gases (ethylene, ethane,
methane) were actively generating and showing up in the DGA.
Although other tests could have revealed this problem, SFRA showed
the problem was with “A” phase and, therefore, where to concentrate
the internal inspection.
9.4 Visual Inspection
9.4.1 Background
Visual inspection of the transformer exterior reveals important
condition information. For example, valves positioned incorrectly,
plugged radiators, stuck temperature indicator and level gauges, and
noisy oil pumps or fans. Oil leaks can often be seen which indicate a
Figure 63 – SFRA Test Traces of a Defective New Transformer.

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potential for oil contamination, loss of insulation, or environmental
problems. Physical inspection requires staff experienced in these
techniques. There are several required physical inspections that will
not be covered here because they were addressed previously. Be sure
to inspect the following as explained in each respective section:
winding temperature indicators (section 4.3), pressure relief devices
(section 4.5), sudden pressure relay (section 4.6), conservator bladder
(section 4.9.2.9), conservator breather (section 4.9.2.9.2), and bladder
failure relay (section 4.9.2.9.3).
9.4.2 Oil Leaks
Check the entire transformer for oil leaks. Leaks develop due to
gaskets wearing out, ultraviolet exposure, taking a “set,” or from
expansion and contraction, especially after transformers have cooled,
due to thermal shrinkage of gaskets and flanges. Many leaks can be
repaired by applying an epoxy or other patch. Flange leaks may be
stopped with these methods, using rubberized epoxy forced into the
flange under pressure. Very small leaks in welds and tanks may be
stopped by peening with a ball-peen hammer, cleaning with the proper
solvent, and applying a “patch” of the correct epoxy. Experienced
leak mitigation contractors whose work is guaranteed may also be
employed. Some leaks may have to be welded. Welding may be
performed with oil in the transformer if an experienced, qualified, and
knowledgeable welder is available. If welding with oil in the tank is
the method chosen, oil samples must be taken for DGA, both before
and after welding. Welding may cause gases to appear in the DGA
and it must be determined what gases are attributed to welding and
which ones to transformer operation. See also EPRI’s Guidelines for
the Life Extension of Substations, 2000 and 2002 update [5] section on
“Transformers Leak Mitigation” that gives several materials and
applications to stop transformer oil leaks. Copies of this document are
available at the Technical Service Center.
9.4.3 Oil Pumps
If the transformer has oil pumps, check the flow indicators and pump
isolation valves to ensure that oil is circulating properly. Pump

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motor(s) may also have reversed rotation, and flow indicators may still
show that oil is flowing. To ensure motors are turning in the proper
direction, use an ammeter to check the motor current. Compare results
with the full-load-current indicated on the motor nameplate. If the
motor is reversed, the current will be much less than the nameplate
full-load-current. Check oil pumps with a vibration analyzer if they
develop unusual noises. Have the DGA lab check for dissolved metals
in the oil and run a metal particle count for metals, if the bearings are
suspect. This should be performed as soon as a bearing becomes
suspect; bad oil pump bearings can put enough metal particles into the
oil to threaten transformer insulation and cause flashover inside the
tank, resulting in an explosive catastrophic failure of the transformer
tank.
9.4.4 Fans and Radiators
Inspect all isolation valves at the tops and bottoms of radiators to
ensure they are open. Inspect cooling fans and radiators for
cleanliness and fans for proper rotation. Check for dirty or damaged
fan blades or partially blocked radiators. Fans are much more efficient
if the blades are clean and rotating in cool air. Normally, fans blow
cool air through the radiators; they should not be pulling air through.
Check to see if fans are reversed electrically (i.e., pulling air first
through the radiators and then through the fan blades). This means
that the blades are rotating in warm air after it passes through the
radiator, which is much less efficient. Place a hand on the radiator
opposite the fans; air should be coming out of the radiator against your
hand. Watch the blades as they rotate slowly when they are starting or
stopping to determine which way they should be rotating and correct
the rotation if necessary. See IEEE 62-1995™ [20]. Also inspect
radiators and fans with an infrared camera, see section 9.4.6, “Infrared
Temperature Analysis.”
9.4.5 Age
Transformer age is an important factor to consider when identifying
candidates for replacement or rehabilitation. Age is one indicator of
remaining life and upgrade potential to current state-of-the art

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materials. During transformer life, structural strength and insulating
properties of materials used for support and electrical insulation
(especially paper) deteriorate. Although actual service life varies
widely depending on the manufacturer, design, quality of assembly,
materials used, maintenance, and operating conditions, the expected
life of a transformer is about 40 years (Replacements, July 1995,
Bureau of Reclamation and Western Area Power Administration [35]).
9.4.6 Infrared Temperature Analysis
Infrared analysis should be conducted annually while equipment is
energized and under full load, if possible. IR analysis should also be
conducted after any maintenance or testing to see if connections that
were broken were re-made properly. Also, if IR is performed during
factory heat run, the results can be used as a baseline for later
comparison.
9.4.7 IR for Transformer Tanks
Unusually high external temperatures or unusual thermal patterns of
transformer tanks indicate problems inside the transformer, such as
low oil level, circulating stray currents, blocked cooling, loose shields,
tap changer problems, etc. Infrared scanning and analysis is required
annually for trending purposes by National Fire Protection Association
70B, Recommended Practice for Electrical Equipment Maintenance
[8] and FIST Volume 4-1B [37]. See also FIST Volume 4-13 [38] and
IEEE 62-1995™ [20]. Abnormally high temperatures can damage or
destroy transformer insulation and, thus, reduce life expectancy.
Thermal patterns of transformer tanks and radiators should be cooler at
the bottom and gradually warmer ascending to the top. See figure 64
for a normal pattern; the red spot at the top is normal showing a “hot
spot” top of B phase, about 110 degrees Fahrenheit (°F). Any
departure from this pattern means a probable problem which must be
investigated. An IR inspection can find over-heating conditions or
incorrect thermal patterns. IR scanning and analysis requires trained
staff, experienced in these techniques.

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9.4.8 IR for Surge Arresters
Surge arresters should be included when infrared scanning energized
transformers. Look for unusual thermal patterns on the surface of
lightning arresters (see the arrester IR image in figure 65). Note that
the yellow in the top right of the image is a reflection not associated
with the arrester. A temperature profile of the arrester is shown as
black lines. Note the hot spot (yellow) about a third of the way down
from the top. This indicates that immediate de-energization
and replacement must be undertaken. Catastrophic failure is imminent
which can destroy nearby equipment and be hazardous to workers.
Also compare thermal patterns to sister units or earlier scans of the
same arrester. Scan all high-voltage connections and compare them to
nearby connections for unusual temperatures.
9.4.9 IR for Bushings
IR scans of bushings can show low oil levels which would call for
immediate de-energization and replacement. This generally means
that the seal in the bushing bottom has failed, leaking oil into the
transformer. The top seal has probably also failed, allowing air and up
the bushing. Another reason a bushing can exhibit a high oil level
*>111.5°F
*<32.7°F
40.0
50.0
60.0
70.0
80.0
90.0
100.0
110.0
Figure 64 – Normal Transformer IR Pattern.

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is that the top seal is leaking, allowing water to enter. The
water migrates to the bushing bottom, displacing the oil upward.
Remember, over 90% of bushing failures are attributed to water
entrance through the top seal. Bushings commonly fail
catastrophically, many times destroying the host transformer or
breaker and nearby equipment and causing hazards to workers.
Figure 66 shows low-oil level in a high-voltage transformer bushing.
Compare previous IR scans of the same bushing with the current scan.
Doble hot-collar testing possibly may show this problem. However,
Doble tests are run infrequently, and the transformer has to be out of
service, under clearance, and both primary and secondary conductors
removed, while an IR scan easily can be performed at any time.
9.4.10 IR for Radiators and Cooling Systems
Examine radiators with an IR camera and compare them with each
other. A cool radiator or segment indicates that a valve is closed or the
radiator or segment is plugged. The IR image (figure 67) shows that
the cold left radiator section is valved off or plugged. If visual
inspection shows the valves are open, the radiator or segment must be
23.4
32.2
Lightning Arrestor*>35.0°C
*<10.0°C
10.1
13.1
15.8
18.4
20.7
22.8
24.9
26.9
28.7
30.5
32.2
33.8
Figure 65 – IR Image of Defective Arrester.

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*>12.9°C
*<-20.0°C
-20.0
-15.0
-10.0
-5.0
0.0
5.0
10.0
Figure 67 – IR Image of Defective Bushing.
Figure 66 – IR Image Showing Blocked Radiators.

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isolated, drained, removed, and the blockage cleared. Do not allow a
transformer to operate with reduced cooling which drastically shortens
transformer life. Remember, an increased operating temperature of
only 8 to 10 °C will reduce transformer life by one-half. IR scan all
cooling systems, including heat exchangers, fans, pumps, motors, etc.
Check inside control panels for overloaded wiring, loose connections,
and overheated relays. Look for unusual thermal patterns and compare
similar equipment.
9.4.11 Corona Scope Scan
With the transformer energized, scan the bushings and surge arresters
and all high-voltage connections for unusual corona patterns. Corona
should be visible only at the top of bushings and arresters, and corona
at connections should be similar to sister connections. As a bushing
deteriorates due to physical defects, the corona pattern will grow
progressively larger. When the corona pattern reaches a grounded
surface (i.e., the tank or structure), a flashover will occur, destroying
the bushing or arrester and, perhaps, the transformer. The corona
scope will reveal this problem long before a flashover.
9.5 Ultrasonic and Sonic Fault Detection
9.5.1 Background
This test should be performed when hydrogen is increasing markedly
in the DGA. High hydrogen generation indicates partial discharge
occurring inside the transformer. Other gases such as methane, ethane,
and ethylene may also be increasing. Acetylene may also be present,
if arcing is occurring, and may also be increasing. Ultrasonic contact
(in contact with the tank) fault detection can detect partial discharge
(corona) and full discharge (arcing) inside the transformer. This test
can also detect loose parts inside the transformer. Partial discharges
emit energy in the order of 20 kHz to 200 kHz. These frequencies are
above levels that can be audibly detected. The test equipment receives
the signals and converts them electronically into audible signals.
Headphones are provided to eliminate spurious noise from the

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powerplant and other sources. The equipment logs data for future
reference. A baseline test should be conducted and compared with
future test data. This test method has some limitations; if a partial
discharge is located deep within the windings, external detectors may
not be sensitive enough to detect and locate the problem. However,
partial discharges most often occur near the top of the transformer in
areas of high-voltage stress which can readily be located by this
method. These defects can sometimes be easily remedied, extending
transformer service life.
9.5.2 Process
Magnetic piezoelectric crystal transducers, sized and tuned to the
appropriate frequencies, are placed on the outside of the tank, and
signals are recorded. If discharges are detected, the location is
triangulated so that, during an internal inspection, the inspector
will know the general area to search for a problem. Likewise,
sonic (audible ranges) fault detection can find mechanical
problems, such as noisy bearings in pumps or fans, nitrogen
leaks, loose shields, or other loose parts inside the transformer
tank, etc. See EPRI’s Guidelines for the Life Extension of Substations
[5], section 3. See also IEEE 62-1995™ [20], section 6.1.8.4.
9.6 Vibration Analysis
9.6.1 Background
Vibration analysis by itself cannot predict many faults associated with
transformers, but it is another useful tool to help determine transformer
condition. Vibration can result from loose transformer core segments,
loose windings, shield problems, loose parts, or bad bearings on
oil cooling pumps or fans. Exercise extreme care in evaluating
the source of vibration. Many times, a loose panel cover, door,
or bolts/screws lying in control panels, or loose on the outside have
been misdiagnosed as problems inside the tank. There are several
instruments available from various manufacturers, and the technology
is advancing quickly. Every transformer is different; therefore,

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to detect this, baseline vibration tests should be run and data
recorded for comparison with future tests.
9.6.2 Process
For a normal transformer in good condition, vibration data is normally
two times line frequency (120 Hz) and also appears as multiples of
two times line frequency; that is, four times 60 (240 Hz), six times 60
(360 Hz), etc. The 120 Hz is always the largest and has an amplitude
of less than 0.5 inch per second (ips) and greater than 0.1 ips. The
next peak of interest is the four times line frequency or 240 Hz. The
amplitude of this peak should not exceed 0.5 ips. None of the
remaining harmonic peaks should exceed 0.15 ips in amplitude. See
EPRI’s Proceedings: Substation Equipment Diagnostics, Conference
IX [24] section on “Vibration Analysis.”
9.7 Turns Ratio Test
9.7.1 Background
This test only needs to be performed if a problem is suspected from the
DGA, Doble testing, or relay operation. The turns ratio test detects
shorted turns, which indicate insulation failure by determining if the
correct turns ratio exists. Shorted turns may result from short circuits
or dielectric (insulation) failures.
9.7.2 Process
Measurements are taken by applying a known low voltage across one
winding and measuring the induced-voltage on the corresponding
winding. The low voltage is normally applied across a high-voltage
winding so that the induced-voltage is lower, reducing hazards while
performing the test. The voltage ratio obtained by the test is compared
to the nameplate voltage ratio. The ratio obtained from the field test
should agree with the factory within 0.5%. New transformers of good
quality normally compare to the nameplate within 0.1%.
For three-phase delta/wye or wye/delta connected transformers, a
three-phase equivalency test should be performed. The test is

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performed and calculated across corresponding single windings. Look
at the nameplate phasor diagram to find out what winding on the
primary corresponds to a particular winding on the secondary.
Calculate the ratio of each three-phase winding based on the line to
neutral voltage of the wye winding. Divide the line-to-line winding
voltage by 1.732 to obtain the correct line-to-neutral voltage. Check
the tap changer position to make sure it is set at the position where the
nameplate voltage is based. Otherwise, the turns ratio test information
cannot be compared with the nameplate. Nameplate information for
Reclamation transformers is normally based on the tap three position
of the tap changer. See the manufacturer’s instruction manual for the
specific turns ratio tester for details. See IEEE 62-1995™ [20].
9.8 Estimate of Paper Deterioration (Online)
NOTE:
The two methods below should be used together.
9.8.1 CO2 and CO Accumulated Total Gas Values
IEEE Standard C57.104™ Guide for the Interpretation of Gases
Generated in Oil-Immersed Transformers [12] gives status conditions,
based on accumulated values of CO2 and CO. Accumulated dissolved
gas levels provide four status conditions: normal operation, modest
concern (investigate), major concern (more investigation), and
imminent risk (nearing failure). The CO2 and CO levels in ppm for
each status are given in table 24.
9.8.2 CO2 /CO Ratio
The CO2/CO ratio should also be analyzed in conjunction with the
CO2 and CO accumulated values. For analyzing the CO2/CO ratio, see
section 6.1.10.

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Table 24 – Paper Status Conditions Using CO2 and CO
Condition 1 Normal 0 – 2,500 0 – 350
Condition 2 Modest Concern 2,500 – 4,000 351 –570
Condition 3 Major Concern 4,001 – 10,000 571 – 1,400
Condition 4 Imminent Risk >10,000 >1,499
CAUTION:
The status from table 24 should be at least in Condition 2 or
3 from one or both gases before a detailed investigation is
begun. There is no need to look at the ratios from section
6.1.10 unless a substantial amount of these gases have
already been generated. If the transformer is relatively new,
CO2 and other atmospheric gases (N2, O2, and even some
CO) may be migrating out of the paper into the oil because
the paper was stored in air prior to transformer assembly. If
the paper was stored in a polluted city atmosphere, a
considerable amount of CO may show up in the DGA. This
may look like the transformer has a problem and is
generating a lot of CO. However, if the transformer has a
real problem, H2 and perhaps other heat gases (CH4, C2H6,
C2H4) should also be increasing.
9.9 Estimate of Paper Deterioration (Offline During Internal
Inspection)
9.9.1 Degree of Polymerization (DP)
Do not open a transformer for the sole purpose of doing this test.
Perform this test only if the unit is being opened for other reasons. See
the reasons for an internal inspection in section 9.9.2.
9.9.1.1 Background – One of the most dependable means of
determining paper deterioration and remaining life is the DP test of the
cellulose. The cellulose molecule is made up of a long chain of
glucose rings which form the mechanical strength of the molecule and
the paper. DP is the average number of these rings in the molecule.

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As paper ages or deteriorates from heat, acids, oxygen, and water, the
number of these rings decreases. When the insulation is new, the DP
is typically between 1,000 and 1,400. As paper deteriorates, bonds
between the rings begin to break. When the DP reaches around 200,
the insulation has reached the end of life. All mechanical strength of
the insulation has been lost; the transformer must be replaced.
9.9.1.2 Process – When doing an internal inspection, or if the
transformer is opened and oil is fully or partially drained for any
reason on a service-aged transformer, perform a DP test. Remove a
sample of the paper insulation about 1 centimeter square from a
convenient location near the top of the center phase with a pair of
tweezers. In general, in a three-phase transformer, the hottest most
thermally aged paper will be at the top of the center phase. If it is not
possible to take a sample from the center phase, take a sample from the
top of one of the other phases. Send this sample to an oil testing
laboratory for the DP test. Analyze results of the DP test with table 25
taken from EPRI’s Guidelines for the Life Extension of Substations,
2002 Update, chapter 3 [5]. Table 25 has been developed by EPRI to
estimate remaining life.
Table 25 – DP Values for Estimating Remaining Paper Life
New insulation 1,000 DP to 1,400 DP
60% to 66 % life remaining 500 DP
30% life remaining 300 DP
0 life remaining 200 DP
9.9.2 Internal Inspection
9.9.2.1 Background – If an internal inspection is absolutely
necessary, it must be completed by an experienced person who knows
exactly what to look for and where to look. Many times, more damage
is done by opening a transformer and doing an internal inspection than
what is gained. There are very few reasons for an internal inspection;
some are shown below:

Transformers:
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♦ Extensive testing shows serious problems.
♦ Unexplained relay operation takes the transformer offline, and
testing is inconclusive.
♦ Acetylene is being generated in the DGA (indicates active internal
arcing).
♦ Ethylene and ethane are being generated in sufficient quantities to
cause grave concern. This generally indicates a bad connection on
a bushing bottom or tap changer, circulating currents, additional
core ground, or static discharges.
♦ A core ground must be repaired, or an additional core ground has
developed which must be removed.
♦ Vibration and ultrasonic analysis indicate loose windings that are
generating gases from heat caused by friction of the vibrating coils;
loose wedges must be located and replaced.
♦ CO2/CO ratio are very low (around 2 or 3), indicating severe paper
deterioration from overheating. Cooling must be checked carefully
before opening the transformer.
♦ Furans are high (see section 7.6), indicating excessive aging rate; a
DP test must be completed.
♦ The metal particle count is above 5,000 in 10 milliliters of oil
taken specifically for detecting metal particle count. (See EPRI’s
Guidelines for the Life Extension of Substations, 2002 Update [5]
for exact procedures for detecting and correcting metal particle
contamination).

Transformers:
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NOTE:
If a service-aged transformer is opened for any reason, a
sample of the paper should be taken for DP analysis. If
possible, take the paper sample from the top of the center
phase winding because this will be near the hot spot. If it is
not possible to get a paper sample from the top of B phase,
take a sample from the top of one of the other windings.
9.9.2.2 Transformer Borescope – A new technology has been
developed for internal transformer inspections using a specifically
designed borescope. The borescope can be used with oil inside the
transformer; core, windings, connections, etc., can be examined and
photographed. If it is necessary to go inside the transformer for
repairs, workers will possibly know exactly what is defective and
exactly what must be done. This technology, used properly, can save
generating time and repair dollars.
Currently, this technology is available only as a contracting service.
However, plans are being made by the developing company to make
the instrument available for sale.
9.10 Transformer Operating History
One of the most important transformer diagnostic tools is the operating
history, including temperatures, overload history (especially through
faults), relay operations, and nearby lightning strikes. Many times,
a through fault or nearby lightning strike will generate acetylene
or ethylene and other gases, and these will remain in future DGAs.
Through faults (i.e., where fault current passes through the
windings) subject a transformer to severe electrical and mechanical
stresses which can degrade insulation and mechanical strength.
Likewise, close-in lightning strikes subject the transformer to
stresses. Excessive heating caused by sustained overloads or loss of
cooling will degrade insulation. The damage may not be immediately
evident but can show up years later. Through faults, overload history,

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and temperatures should be in operations records, and a review of
these is required when diagnosing a transformer problem.
9.11 Transformer Diagnostics/Condition Assessment
Summary
A summary of diagnostic techniques is given below in table 26.
Table 26 – Reclamation Transformer Condition Assessment Summary
Tests Detects Tools
Online Tests
Dissolved Gas
Analysis
(Laboratory
and Portable)
Measures dissolved gases: to
detect, arcing, bad electrical
contacts, hot spots, partial
discharges, overheating of
conductors, oil, tank, cellulose
(paper insulation).
Portable Gas –In – Oil
Analyzer with software
1
(e.g.,
Morgan Schaffer P200 and
Transformer Oil Analyst
software). Note: the P200
does not measure oxygen
and nitrogen.
Or send to an oil testing
laboratory for DGA.
Oil Physical
and Chemical
Tests
Moisture, interfacial tension,
acidity, furans, dissolved metals,
and metal particle count
(indicates pump problems).
Analyzes paper and oil condition.
Requires laboratory analysis.
Physical
Inspection –
External
Oil leaks, broken parts, worn
paint, defective support structure,
malfunctioning temperature and
level indicators, cooling
problems, pump and radiator
problems, bushing and lightning
arrester porcelain cracks, etc.
Experienced staff, binoculars
for bushing, and lightning
arrester porcelain cracks and
loose bolts.
Infrared Scan Hot spots, localized heating, bad
connections, circulating currents,
blocked cooling, tap changer
problems, bushing and lightning
arrester problems.
Trained and experienced staff
with thermographic camera
and analysis software.
1

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(continued)
Tests Detects Tools
Online Tests (continued)
Ultrasonic and
Sonic Contact
Fault Detection
Internal partial discharge, arcing,
sparking, pump impeller and
bearing problems. Mechanical
noises, loose parts (blocking,
deflectors, etc.).
Fault detector with data
logger.
1
Ultrasonic Non-
Contact and
Contact Fault
Detection
Nitrogen leaks, vacuum leaks,
corona at bushings, pump
mechanical and bearing
problems, cooling fan problems.
Ultrasonic probe and meter
(e.g., UltraProbe 2000).
Vibration
Analysis
Internal core, shield problems.
Loose parts vibration.
Vibration data logger.
1
External
Temperatures
(Main Tank)
Temperature monitoring with
changes in load and ambient
temperature.
Portable temperature data
loggers and software.
1
Sound Level Internal and external noises to
compare to baseline and other
vibration tests.
Sound level meter
1
(e.g.,
Quest 2400 Sound Meter).
Corona Compare bushings and lightning
arresters and all high-voltage
connections with sister units.
Corona Scope,
1
Model CS-
01-A.
Offline Tests
Doble Power
Factor
Loss of winding insulation
integrity. Loss of bushing
insulation integrity. Winding
moisture.
Doble test equipment.
Excitation
Current
Shorted turns in the windings. Doble test equipment.
Turns Ratio Shorted windings. Turns ratio tester (e.g.,
Biddle 55005).
Leakage
Reactance
Measures percent impedance, to
be compared to nameplate after
moving or through fault.
Doble test equipment.

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(continued)
Tests Detects Tools
Offline Tests (continued)
Sweep
Frequency
Response
Analysis
Structural problems, core and
winding problems, movement of
core and windings. Run this test
before and after moving and after
a through fault.
Doble M5100 sweep
frequency response analyzer.
Across Winding
Resistance
Measurements
Broken strands, loose
connections, bad contacts in tap
changer.
Wheatstone Bridge (1 ohm
and greater).
Kelvin Bridge (less than 1
ohm).
Winding DC
Resistance to
Ground
Winding low resistance to ground
(leakage current).
Megger®.
1
Core to Ground
Resistance
2
Bad connection on intentional
core ground or existence of
unintentional grounds.
Megger®.
1
Internal
Inspections and
Tests
Oil sludging, displaced winding or
wedging, loose windings, bad
connections, burned conductors.
Experienced staff, micro-ohm
meter and/or
Foster Miller borescope.
Degree of
Polymerization
Insulation condition (life
expectancy).
Laboratory analysis of paper
sample.
1
This equipment is available from the Hydroelectric Research and Technical
Services Group.
2
External test may be possible depending on transformer construction.

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Figure 68 – Transformer Diagnostic Test Chart
(Adapted from IEEE 62-1995™ [20]).

205
Appendix: Hydroplant Risk
Assessment – Transformer
Condition Assessment
1. General
Power transformers are key components in the power train at
hydroelectric powerplants and are appropriate for analysis under a risk
assessment program. Transformer failure can have a significant
economic impact due to long lead times in procurement,
manufacturing, and installation, in addition to high equipment cost.
According to the Electric Power Research Institute (EPRI):
“Extending the useful life of power transformers is the single most
important strategy for increasing life of power transmission and
distribution infrastructures starting with generator step-up transformers
(GSU) at the powerplant itself” (EPRI Report No. 1001938).
Determining the existing condition of power transformers is an
essential step in analyzing the risk of failure. This chapter provides a
process for developing at a Transformer Condition Index. This
condition index may be used as an input to the risk-and-economic
analysis computer model where it adjusts transformer life expectancy
curves. The output of the economic analysis is a set of alternative
scenarios, including costs and benefits, intended for management
decisions on replacement or rehabilitation.
2. Scope/Application
The transformer condition assessment methodology outlined in this
chapter applies to oil-filled power transformers (> 500 kilovoltampere
[kVA]) currently in operation.

Appendix: Hydroplant Risk Assessment
Transformer Condition Assessment
206
This guide is not intended to define transformer maintenance practices
or describe transformer condition assessment inspections, tests, or
measurements in detail. Utility maintenance policies and procedures
must be consulted for such information.
3. Condition Indicators and Transformer
Condition Index
This guide describes four Condition Indicators generally regarded by
hydro powerplant engineers as a sound basis for assessing transformer
condition.
♦ Insulating oil analysis (dissolved gas analysis [DGA] and furan)
♦ Power factor and excitation current tests
♦ Operation and maintenance (O&M) history
♦ Age
These indicators are based on “Tier 1” inspections, tests, and
measurements conducted by utility staff or contractors over the course
of time. The indicators are expressed in numerical terms and are used
to arrive at an overall Transformer Condition Index.
The guide also describes a “toolbox” of Tier 2 inspections, tests, and
measurements that may be applied, depending on the specific problem
being addressed. Results of Tier 2 may modify the score of the
Transformer Condition Index.
After review by a transformer expert, the Transformer Condition Index
is suitable for use as an input to the risk and economic analysis model.

207
4. Inspections, Testing, and Measurements
The hierarchy of inspections, tests, and measurements is illustrated in
figure A-1, Transformer Condition Assessment Methodology.
Table A-14, Transformer Condition Assessment Summary (later in
this appendix), summarizes these activities.
Inspections, tests, and measurements (“tests”) performed to determine
transformer condition are divided into two tiers (or levels). Tier 1 tests
are those that are routinely accomplished as part of normal O&M or
are readily discernible by examination of existing data. Results of
Tier 1 tests are quantified below as Condition Indicator Scores that are
weighted and summed to arrive at a Transformer Condition Index.
Tier 1 tests may indicate abnormal conditions that can be resolved
with standard corrective maintenance solutions. Tier 1 test results may
also indicate the need for additional investigation, categorized as
Tier 2 tests.
Tier 2 tests are considered nonroutine. Tier 2 test results may affect
the Transformer Condition Index established using Tier 1 tests but
may confirm also or disprove the need for more extensive
maintenance, rehabilitation, or transformer replacement.
Inspection, testing, and measurement methods are specified in
technical references specific to the electric utility.
This guide assumes that Tier 1 and Tier 2 inspections, tests, and
measurements are conducted and analyzed by staff suitably trained and
experienced in transformer diagnostics. More basic tests may be
performed by qualified staff who are competent in these routine
procedures. More complex inspections and measurements may require
a transformer diagnostics “expert.”
This guide also assumes that inspections, tests, and measurements are
conducted on a frequency that provides accurate and current

208
Figure A-1 – Transformer Condition Assessment Methodology.

209
information needed by the assessment. In some cases, it may be
necessary to conduct tests prior to this assessment to acquire current
data.
Transformer condition assessment may cause concern that justifies
more frequent monitoring. Utilities should consider the possibility of
taking more frequent measurements (e.g., oil samples) or installing
online monitoring systems (e.g., gas-in-oil) that will continuously
track critical quantities. This will provide additional data for condition
assessment and establish a certain amount of reassurance as
transformer alternatives are being explored.
NOTE:
A severely negative result of ANY inspection, test, or
measurement may be adequate, in itself, to require
immediate de-energization or prevent re-energization of the
transformer, regardless of the Transformer Condition Index
score.
5. Scoring
Transformer Condition Indicator scoring is somewhat subjective,
relying on transformer condition experts. Relative terms such as
“results normal” and “degradation” refer to results that are compared
to:
♦ Industry accepted levels
♦ Baseline or previous (acceptable) levels on this equipment
♦ Equipment of similar design, construction, or age that operates in a
similar environment

210
6. Weighting Factors
Weighting factors used in the condition assessment methodology
recognize that some Condition Indicators affect the Transformer
Condition Index to a greater or lesser degree than other indicators.
These weighting factors were arrived at by consensus among
transformer design and maintenance personnel with extensive
experience.
7. Mitigating Factors
Every transformer is unique; therefore, the methodology described in
this chapter cannot quantify all factors that affect individual
transformer condition. It is important that the Transformer Condition
Index be scrutinized by engineering experts. Mitigating factors
specific to the utility may determine the final Transformer Condition
Index and the final decision on transformer replacement or
rehabilitation.
8. Documentation
Substantiating documentation is essential to support findings of the
assessment, particularly where a Tier 1 Condition Indicator score is
less than 3 or a Tier 2 test results in subtractions from the Transformer
Condition Index. Test results and reports, photographs, O&M records,
or other documentation should accompany the Transformer Condition
Assessment Summary Form.
9. Condition Assessment Methodology
The condition assessment methodology consists of analyzing each
Condition Indicator individually to arrive at a Condition Indicator
Score; then the score is weighted and summed with scores from other

211
condition indicators. The sum is the Transformer Condition Index.
Apply the Condition Index to the Alternatives table to determine the
recommended course of action.
Reasonable efforts should be made to perform Tier 1 inspections, tests,
and measurements. However, when data is missing, to properly score
the Condition Indicator, it may be assumed that the score is “Good” or
a mid-range number such as 2.
CAUTION:
This strategy should be used judiciously to prevent deceptive
results.
10. Tier 1 – Inspections, Tests, Measurements
Tier 1 inspections, tests, and measurements routinely accomplished as
part of normal O&M are readily discernible by examination of existing
data. Tier 1 test results are quantified below as Condition Indicators
that are weighted and summed to arrive at a Transformer Condition
Index. Tier 1 inspections, tests, and measurements may indicate
abnormal conditions that can be resolved with standard corrective
maintenance solutions. Tier 1 test results may also indicate the need
for additional investigation, categorized as Tier 2 tests.
10.1 Condition Indicator 1 – Insulating Oil Analysis
Dissolved gas analysis is the most important factor in determining the
condition of a transformer because, being performed more frequently
than other tests, it may be the first indication of a problem. Insulating
oil analysis can identify internal arcing, bad electrical contacts, hot
spots, partial discharge, or overheating of conductors, oil, tank, or
cellulose. The “health” of the oil is reflective of the health of the
transformer itself. DGA consists of sending transformer insulating oil
samples to a commercial laboratory for analysis. The most important

212
indicator is the individual and total dissolved combustible gas (TDCG)
generation rates, based on International Electrotechnical Commission
(IEC) and Institute of Electrical and Electronic Engineers (IEEE®)
standards. Although gas generation rates are not the only indicator,
they are reasonable for use in determining the Condition Indicator
Score.
Furanic analysis may indicate a problem with the paper insulation,
which could affect transformer longevity. A baseline furanic
analysis should be made initially and repeated if the transformer
is overheated, overloaded, aged, or after changing or processing
the oil.
Physical tests such as interfacial tension (IFT), acidity, moisture
content, and dielectric strength usually indicate oil conditions that can
be remedied through various reclamation processes. Therefore, they
are not indicative of overall transformer condition that would lead to
replacement. Such tests do not affect the Insulating Oil Condition
Indicator score.
Results are analyzed and applied to table A-1 to arrive at a Condition
Indicator Score.
NOTE:
Choose one furan number from table A-1, based on a
transformer rated 65 °C or 55 °C rise above ambient
temperature.
The below DGA numbers are based on dissolved gas in oil generation
rates and come from a combination of IEEE C57-104™, IEC 60599,
and Delta X Research’s Transformer Oil Analysis (TOA) software.

213
Table A-1 – Insulating Oil Analysis Scoring
Results
Condition
Indicator
Score
TDCG generation rate less than 30 parts per million per month (ppm/month)
and:
* All individual combustible gas generation rates less than 10 ppm/month
* Exceptions: carbon monoxide (CO) generation rate less than
70 ppm/month and acetylene (C2H2) generation rate 0 ppm. (See Note
below.)
AND
2FAL furans 150 parts per billion (ppb) or less for 65 °C rise.
2FAL furans 450 ppb or less for 55 °C rise
3
TDCG generation rate between 30 and 60 ppm/month and:
* All individual combustible gas generation rates less than 15 ppm/month.
* Exceptions: CO generation rate less than 150 ppm/month and C2H2
generation rate 0 ppm. (See Note below.)
OR
2FAL furans between 150 ppb and 200 ppb for 65 °C rise.
2
TDCG generation rate between 50 and 80 ppm/month and:
* All individual combustible gas generation rates less than 25 ppm/month.
* Exceptions: CO generation rate less than 350 ppm/month and C2H2
generation rate less than 5 ppm/month. (See Note below.)
OR
1
TDCG generation rate greater than 80 ppm/month and:
* Any individual combustible gas generation rate more than 50 ppm/month.
* Exceptions: CO generation rate more than 350 ppm/month and C2H2
generation rate no more than 10 ppm/per month. (See Note below.)
OR
2FAL furans above 250 ppb for 65 °C rise.
2FAL furans above 750 ppb for 55 °C rise.
0

214
NOTE:
Any ongoing acetylene (C2H2) generation indicates an active
arcing fault, and the transformer may have to be removed
from service to avoid possible catastrophic failure. A
transformer may be safely operated with some C2H2 showing
in the DGA. C2H2 sometimes comes from a one-time event
such as a close-in lightning strike or through fault. However,
if C2H2 is increasing more than 10 ppm per month, the
transformer should be removed from service. Because
acetylene generation is a critical indicator of transformer
internal condition, each utility should establish practices in
accordance with published standards and transformer
experts to monitor any increases in gas generation and take
corrective action. Increasing the frequency of DGA and de-
gasifying the transformer oil are potential alternatives to
consider.
10.2 Condition Indicator 2 – Power Factor and
Excitation Current Tests
Power factor insulation testing is important to determining the
condition of the transformer because it can detect winding and bushing
insulation integrity. Power factor and excitation current tests are
conducted in the field on de-energized, isolated, and properly
grounded transformers. Excitation current tests measure the single-
phase voltage, current, and phase angle between them, typically on the
high-voltage side with the terminals of the other winding left floating
(with the exception of a grounded neutral). The measurements are
performed at rated frequency and usually at test voltages up to
10 kilovolts (kV). The test detects shorted turns, poor tap changer
contacts, and core problems.
Indicator Score.

215
Table A-2.—Power Factor and Excitation Current Test Scoring
Test Results1
Condition Indicator
Score
Power factor results normal (Good - G).
AND
Normal excitation current values and patterns, compared to
other phases and prior tests.
3
Power factor results show minor degradation.
(Deteriorated - D).
OR
Minor deviation2
in excitation current values and patterns,
compared to other phases and prior tests.
2
Power factor results show significant deterioration.
(Investigate - I)
OR
Significant deviation2
in current values and patterns,
1
Power factor results show severe degradation.
(Bad – B)
OR
Severe deviation2
in current values and patterns,
May indicate serious
problem requiring
immediate evaluation,
additional testing,
consultation with
experts, and remediation
prior to re-energization.
1
Doble insulation rating in parentheses.
2
Be sure to account for residual magnetism and load tap changer (LTC).
10.3 Condition Indicator 3 – Operation and
Maintenance History
O&M history may indicate overall transformer condition.
O&M history factors that may apply are:

216
♦ Sustained overloading
♦ Unusual operating temperatures indicated by gauges and
continuous monitoring
♦ Abnormal temperatures indicated by infrared scanning
♦ Nearby lightning strikes or through faults
♦ Abnormally high corona detected.
♦ Abnormally high external temperatures detected.
♦ Problems with auxiliary systems (fans, radiators, cooling water
piping, pumps, motors, controls, nitrogen replenishment system,
and indicating and protection devices).
♦ Deteriorated control and protection wiring and devices.
♦ Increase in corrective maintenance or difficulty in acquiring spare
parts.
♦ Anomalies determined by physical inspection (external inspection
or internal inspection not requiring untanking) (e.g., incorrectly
positioned valves, plugged radiators, stuck temperature indicators
and level gauges, noisy oil pumps or fans, oil leaks, connections to
bushings).
♦ Previous failures on this equipment.
♦ Failures or problems on equipment of similar design, construction,
or age that operate in a similar environment.
Qualified personnel should make a subjective determination of scoring
that encompasses as many O&M factors as possible under this
indicator.

217
Indicator Score.
Table A-3 – Operation and Maintenance History Scoring
History Results
Condition
Indicator Score
Operation and maintenance are normal. 3
Some abnormal operating conditions experienced and/or
additional maintenance above normal are occurring.
2
Significant operation outside normal and/or significant
additional maintenance is required; or forced outage
occurs; or outages are regularly extended due to
maintenance problems; or similar units are problematic.
1
Repeated forced outages; maintenance not cost effective;
or major oil leaks and/or severe mechanical problems; or
similar units have failed.
0
10.4 Condition Indicator 4 – Age
Transformer age is an important factor to consider when identifying
candidates for transformer replacement. Age is one indicator of
remaining life and upgrade potential to current state-of-the-art
materials. During the life of the transformer, the structural and
insulating properties of materials used for structural support and
electrical insulation, especially wood and paper, deteriorate. Although
actual service life varies widely depending on the manufacturer’s
design, quality of assembly, materials used, operating history, current
operating conditions, and maintenance history, the average expected
life for an individual transformer in a large population of transformer
is statistically about 40 years.
Apply the transformer age to table A-4 to arrive at the Condition
Indicator Score.

218
Table A-4 – Age Scoring
Age
Condition
Indicator Score
Under 30 years 3
30 – 45 years 2
Over 45 years 1
11. Tier 1 – Transformer Condition Index
Calculations
Enter the Condition Indicator Scores from the tables above into the
Transformer Condition Assessment Summary Form at the end of this
appendix. Multiply each Condition Indicator Score by the Weighting
Factor, then sum the Total Scores to arrive at the Tier 1 Transformer
Condition Index. This index may be adjusted by the Tier 2
inspections, tests, and measurements described below. Suggested
alternatives for follow-up action, based on the Transformer Condition
Index, are described in table A-14 at the end of this appendix.
12. Tier 2 – Inspections, Tests, Measurements
Tier 2 inspections, tests, and measurements generally require
specialized equipment or training, may be intrusive, or may require an
extended outage to perform. Tier 2 assessment is considered
nonroutine. Tier 2 inspections may affect the Transformer Condition
Index number established using Tier 1 but also may confirm or refute
the need for more extensive maintenance, rehabilitation, or transformer
replacement.
For each Tier 2 inspection, test, or measurement performed, subtract
the appropriate amount from the appropriate Tier 1 Condition

219
Indicator and recalculate the Transformer Condition Index using the
document.
12.1 Test T2.1: Turns Ratio Test
The transformer turns ratio (TTR) test detects shorts between turns of
the same coil, which indicates insulation failure between the turns.
These tests are performed with the transformer de-energized and may
show the necessity for an internal inspection or removal from service.
Results are analyzed and applied to table A-5 to arrive at a
Transformer Condition Index Score adjustment.
Table A-5 – Turns Ratio Test Scoring
Test Results
Adjustment to
Transformer Condition Index
Less than 0.20% difference from nameplate V1/V2 and
compared to previous readings
No change
0.20% to 0.50% difference compared to nameplate V1/V2 Subtract 1.0
Greater than 0.5% difference compared to nameplate V1/V2 May indicate serious problem requiring
immediate evaluation, additional testing,
consultation with experts, and remediation
12.2 Test T2.2: Short Circuit Impedance Tests
Sometimes called percent impedance or leakage reactance test, these
tests are conducted in the field and compared to nameplate
information, previous tests, and similar units to detect deformation of
the core or windings caused by shipping damage, through faults, or
ground faults. Some difference may be expected between nameplate
and field test results because factory tests are conducted at full load
current, which is normally not possible in the field. Field connections
and test leads and jumpers also play a significant role in test results,
and it is impossible to exactly duplicate the factory test setup.

220
Therefore, the I2
R losses may be different and cause different test
results. By comparing percent-reactance to nameplate impedance, the
differences caused by leads and connections can be eliminated.
Because reactance is only the inductive component of the impedance,
I2
R losses are omitted in the test results.
Table A-6 – Short Circuit Test Scoring
Test Results
Condition
Indicator Score
Less than 1% difference from nameplate
impedance
No change
1% to 3% difference from nameplate
impedance (minor degradation)
Subtract 0.5
3% to 5% difference from nameplate
impedance (significant degradation)
Subtract 1.0
Greater than 5% difference from nameplate
impedance (severe degradation)
May indicate serious problem
requiring immediate evaluation,
additional testing, consultation
with experts, and remediation prior
to re-energization.
12.3 Test T2.3: Core-to-Ground Resistance
Megger® Tests
The transformer core is intentionally grounded through one
connection. The core-to-ground resistance test can detect if this
connection is loose. It can also detect whether there are other
undesired and inadvertent, grounds. If the intentional core ground is
intact, the resultant resistance should be very low. To check for
unintentional core grounds, remove the intentional ground and
Megger® between the core and the grounded transformer tank. This
test should produce very high resistance, indicating that an
unintentional ground is not present. This test is to supplement DGA

221
that shows generation of hot metal gases (methane, ethane, and
ethylene) and to indicate if a spurious, unintentional core ground is the
problem. Experience can help locate the source of the problem.
Transformer Condition Index score adjustment.
Table A-7 – Core-to-Ground Resistance Test Scoring
Test Results1
Adjustment to
Greater than 1,000 megohms1
(results normal)
3
600 to 900 megohms 2
200 to 500 megohms 1
Less than 200 megohms May indicate serious problem requiring
consultation with experts, and
remediation prior to re-energization.
1
With intentional ground disconnected.
12.4 Test T2.4: Winding Direct-Current Resistance
Measurements
Careful measurement of winding resistance can detect broken
conductor strands, loose connections, and bad contacts in the tap
changer (de-energized tap changer [DETC] or LTC). Results from
these measurements may indicate the need for an internal inspection.
This information supplements DGA and is useful when DGA shows
generation of heat gases (ethane, ethylene, and methane). These tests
are typically performed with a micro-ohmmeter and/or a Wheatstone
bridge. Test results are compared between phases or with factory
tests. When comparing with factory tests, a temperature correction
must be employed (IEEE P62™). This test should be performed only
after the rest of the routine electrical tests because it may magnetize
the core, affecting results of the other tests.

222
12.5 Test T2.5: Ultrasonic and Sonic Fault
Detection Measurements
These assessment tests (sometimes called acoustic testing tests) are
helpful in locating internal faults. Partial discharges (corona) and low-
energy arcing/sparking emit energy in the range of 50 megahertz
(ultrasonic), well above audible sound. To make these measurements,
sensors are placed on the outside of a transformer tank to detect these
ultrasonic emissions, which are then converted electronically to
oscilloscope traces or audible frequencies and recorded. By
triangulation, a general location of a fault (corona or arcing/sparking)
may be determined so that an internal inspection can be focused in that
location. These devices also can detect loose shields that build up
static and discharge it to the grounded tank, poor connections on
bushings, bad contacts on a tap changer that are arcing/sparking, core
ground problems that cause sparking/arcing, and areas of weak
insulation that generate corona. Sonic testing can detect increased
core and coil noise (looseness) and vibration, failing bearings in oil
pumps and fans, and nitrogen leaks in nitrogen blanketed transformers.
Table A-8 – Winding Direct-Current Resistance Measurement Scoring
Measurement Results
Adjustment to
No more than 5% difference between phases
or from factory tests
No change
5% to 7% difference between phases or from
factory tests
Subtract 0.5
7% to 10% difference between phases or
from factory tests
Subtract 1.0
More than 10% difference between phases or
from factory tests
May indicate serious problem requiring

223
Information gained from these measurements supplements DGA and
provides additional support information for de-energized tests, such as
core ground and winding resistance tests. In addition, these tests help
pinpoint areas to look for problems during internal inspections.
Performing baseline tests may provide comparisons for later tests.
Experience can help locate the source of the problem.
Table A-9 – Ultrasonic and Sonic Measurement Scoring
Measurement Results
Adjustment to Transformer
Condition Index
Results normal No change
Low-level fault indication Subtract 0.5
Moderate level fault indication Subtract 1.0
Severe fault level indication Subtract 2.0
12.6 Test T2.6: Vibration Analysis
Vibration can result from loose transformer core and coil segments,
shield problems, loose parts, or bad bearings on oil cooling pumps or
fans. Vibration analyzers are used to detect and measure the vibration.
Information gained from these tests supplements ultrasonic and sonic
(acoustic) fault detection tests and DGA. Information from these tests
may indicate maintenance is needed on pumps/fans mounted external
to the tank. It may also show when an internal transformer inspection
is necessary. If wedging has been displaced due to paper deterioration
or through faults, vibration will increase markedly. This will also
show if core and coil vibration has increased compared to baseline
information. Experience can help locate the source of the problem.

224
Table A-10 – Vibration Analysis Scoring
Analysis Results
Condition Index
Results normal No change
Low level fault indication Subtract 0.5
Moderate level fault indication Subtract 1.0
Severe fault level indication Subtract 2.0
12.7 Test T2.7: Frequency Response Analysis (FRA)
Frequency Response Analysis (or Sweep Frequency Response
Analysis) can determine if windings of a transformer have moved or
shifted. It can be completed as a factory test prior to shipment and
repeated after the transformer is received onsite to determine if
windings have been damaged or shifted during shipping. This test is
also helpful if a protective relay has tripped or a through fault, short
circuit, or ground fault has occurred
A sweep frequency test signal is generally placed on each of the high-
voltage windings, and the signal is detected on the low-voltage
windings. This provides a picture of the frequency transfer function of
the windings. If the windings have been displaced or shifted, test
results will differ markedly from prior tests. Test results are kept in
transformer history files so they can be compared to later tests.
Results are determined by comparison to baseline or previous
measurements or by comparison to units of similar design and
construction.

225
Table A-11 – Frequency Response Analysis Scoring
Test Results
Adjustment to
No deviation compared to prior tests No change
Minor deviation compared to prior tests Subtract 2.0
Moderate deviation compared to prior tests Subtract 3.0
Significant deviation compared to prior tests Subtract 4.0
Severe deviation compared to prior tests May indicate serious problem requiring
12.8 Test T2.8: Internal Inspection
In some cases, it is necessary to open, partially or fully drain the oil,
and perform an internal inspection to determine the transformer’s
condition. These inspections must be performed by experienced staff
with proper training. Sludging, loose wedges, loose coils, poor
electrical connections on bushing bottoms, burned contacts on tap
changers, localized overheating signified by carbon buildup, displaced
wedging or insulation, and debris and other foreign material are
general matters of concern. Photographs and mapping problem
locations are good means of documenting findings. Before entering
the transformer, and while inside it, the Occupational Safety and
Health Administration, State, local, and utility safety practices must be
followed (e.g., “permitted confined space” entry practices).
12.9 Test T2.9: Degree of Polymerization
Winding insulation (cellulose) deterioration can be quantified by
analysis of the degree of polymerization (DP) of the insulating
material. This test gives an indication of the remaining structural

226
Table A-12 – Internal Inspection Scoring
Inspection Results
Condition Index
Conditions normal No change
Minimal degradation Subtract 0.5
Moderate degradation Subtract 1.5
Severe degradation May indicate serious problem requiring immediate
evaluation, additional testing, consultation with
experts, and remediation prior to re-energization.
strength of the paper insulation and is an excellent indication of the
remaining life of the paper and the transformer itself. This requires
analyzing a sample of the paper insulation in a laboratory to determine
the deterioration of the molecular bonds of the paper.
Table A-13 – Degree of Polymerization Scoring
Test Results
Adjustment to
900 or higher (no polymerization decrease;
results normal)
No change
800-700 (minimal polymerization decrease) Subtract 0.5
600-300 (moderate polymerization
decrease)
Subtract 1.5
<200 (severe polymerization decrease—
insulation has no mechanical strength; end
of life)
May indicate serious problem requiring
consultation with experts, and remediation

227
13. Tier 2 – Transformer Condition Index
Calculations
Enter the Tier 2 adjustments from the tables above into the
chapter. Subtract the sum of these adjustments from the Tier 1
Transformer Condition Index to arrive at the total Transformer
Condition Index. Suggested alternatives for followup action, based on
the Transformer Condition Index, are described in table A-14.
Table A-14 – Transformer Co-ndition Assessment Summary
Test Detects Tool
Online Tests
Dissolved Gas
Analysis
Internal arcing; bad electrical contacts; hot
spots; partial discharge; and overheating of
conductors, oil, tank, and cellulose insulation.
Requires laboratory
analysis
Oil Physical and
Chemical Tests
Moisture, degraded IFT, acidity, furans,
dielectric strength, and power factor.
Requires laboratory
analysis
External Physical
Inspection
Oil leaks, broken parts, worn paint, defective
support structure, stuck indicators, noisy
operation, loose connections, cooling problems
with fans, pumps, etc.
Experienced staff
and binoculars
External
Temperatures
(Main tank and
load tap changer)
Temperature monitoring with changes in load
and ambient temperature.
Portable temperature
data loggers and
software
Infrared Scan Hot spots indicating localized heating,
circulating currents, blocked cooling, tap
changer problems, and loose connections.
Thermographic
camera and analysis
software
Ultrasonic
(Acoustic)
Contact Fault
Detection
Internal partial discharge, arcing, sparking,
loose shields, poor bushing connections, bad
tap changer contacts, core ground problems,
and weak insulation that is causing corona.
Ultrasonic detectors
and analysis software
Sonic Fault
Detection
Nitrogen leaks, vacuum leaks, core and coil
vibration, corona at bushings, and mechanical
and bearing problems in pumps and cooling
fans.
Ultrasonic probe
and meter
Vibration Analysis Internal core, coil, and shield problems; loose
parts and bad bearings.
Vibration data logger

228
Table A-14 – Transformer Condition Assessment Summary (continued)
Test Detects Tool
Offline Tests
Doble Tests (bushing
capacitance, insulation
power factor, tip up,
excitation current)
Loss of winding insulation integrity,
loss of bushing insulation integrity,
and winding moisture.
Doble test equipment
Turns Ratio Shorted windings. Doble test equipment or
turns ratio tester
Short Circuit Impedance Deformation of the core or winding. Doble or equivalent test
equipment
Core to Ground Resistance
(External test may be
possible depending on
transformer construction)
Bad connection on intentional core
ground and existence of
unintentional grounds.
Megger®
Winding Direct Current
Resistance Measurements
Broken strands, loose connections,
bad tap changer contacts.
Wheatstone Bridge (1 ohm
and greater)
Kelvin Bridge micro-
ohmmeter (less than 1 ohm)
Frequency Response
Analysis
Shifted windings. Doble or equivalent sweep
frequency analyzer
Internal Inspection Oil sludging, displaced winding or
wedging, loose windings, bad
connections, localized heating, and
debris and foreign objects.
Experienced staff, micro-
ohmmeter
Degree of Polymerization Insulation condition (life
expectancy).
Laboratory analysis of paper
sample

229
TRANSFORMER CONDITION ASSESSMENT
SUMMARY FORM
Date: _________________________ Transformer Identifier: ______________________
Location: ______________________ Manufacturer: ________ Yr. Mfd: ___________
No. of Phases: _________ MVA: _________ Voltage: ____________________
Tier 1 Transformer Condition Summary
Indicator
No. Indicator Score X Weighting Factor = Total Score
1 Oil Analysis 1.143
2 Power Factor and Excitation
Current Tests
0.952
3 Operation and Maintenance
History
0.762
4 Age 0.476
Tier 1 Transformer
Condition Index (sum of
individual Total Scores)
(Between 0 and
10)
Tier 2 Transformer Condition Summary
Tier 2 Test
Adjustment to Tier 1
Condition Index
T2.1 Turns Ratio Test
T2.2 Short Circuit Impedance Test
T2.3 Core-to-Ground Resistance Megger® Test
T2.4 Winding Direct Current Resistance Measurement
T2.5 Ultrasonic and Sonic Fault Detection Measurement
T2.6 Vibration Analysis
T2.7 Frequency Response Analysis
T2.8 Internal Inspection
T2.9 Degree of Polymerization
Tier 2 Adjustments to Transformer Condition
Index
(Sum of individual adjustments)

230
To calculate the net Transformer Condition Index, subtract the Tier 2
Adjustments from the Tier 1 Condition Index:
Tier 1 Transformer Condition Index __________
minus Tier 2 Adjustments __________ = _____________
Net Transformer Condition Index
Evaluator: _________________
Technical Review: _________________ Management Review: ___________
Copies to: _______________________
Forward completed form, including supporting documentation, to
agency transformer expert.
14. Transformer Alternatives
After review by a transformer expert, the Transformer Condition
Index—either modified by Tier 2 tests or not—may be sufficient for
decision-making regarding transformer alternatives. The index is also
suitable for use in the risk-and-economic analysis model described
elsewhere. Where it is desired to consider alternatives based solely on
transformer condition, the Transformer Condition Index may be
directly applied to table A-15.
Table A-15 – Transformer Condition-Based Alternatives
Transformer
Condition Index
Range Suggested Course of Action
8-10 (Good) Continue O&M without restriction. Repeat this condition
assessment process as needed.
4-7 (Fair) Continue operation but re-evaluate O&M practices. Consider
using appropriate Tier 2 tests. Conduct full Life Extension
risk-economic assessment. Repeat this condition
assessment process as needed.
0-3 (Poor) Immediate evaluation including additional Tier 2 testing.
Consultation with experts. Adjust O&M as prudent. Begin
replacement/rehabilitation process.

References
231
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Power, and Regulating Transformers, American National
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[4] Guidelines for the Life Extension of Substations, Electric Power
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[5] Guidelines for the Life Extension of Substations, Electric Power
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[6] Transformer Maintenance Guide, J.J. Kelly, S.D. Myers,
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[8] Recommended Practice for Electrical Equipment Maintenance,
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[9] Bushing Field Test Guide, Doble Engineering Company, 1966.
[10] Testing and Maintenance of High-Voltage Bushings, FIST 3-2,
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Apparatus Bushings, Institute of Electrical and Electronic
Engineers (IEEE) C57.10.00, 1991.

References
232
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Associates, London, England, 1989.
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[19] IEEE and IEC Codes to Interpret Incipient Faults in
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References
233
[22] Standard Test Method for Interfacial Tension of Oil Against
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Institute/American Society for Testing and Materials
(ANSI/ASTM) D 971-91.
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[24] Proceedings: Substation Equipment Diagnostics, Conference
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[27] Insulating Fluids, Doble Engineering Company Client
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[28] Trial-Use Guide for the Interpretation of Gases Generated in
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[29] Standard Specification of Nitrogen Gas as an Electrical
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[30] Standard Specification for Mineral Insulating Oil Used in
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(ASTM) D-5837, 1996.

References
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(ASTM) F-36, 1999.
[33] Standard Test Method for Rubber Property – Durometer
Hardness, American Society of Testing and Materials (ASTM)
D-2240, 1997.
[34] “Transformer Condition Assessment,” in Hydro Powerplant
Risk Assessment Guide, a joint effort of Bureau of Reclamation,
U.S. Army Corps of Engineers, Hydro Quebec, and Bonneville
Power Administration (see appendix).
[35] Replacements, Bureau of Reclamation and Western Area Power
Administration, July 1995.
[36] M5100 Sweep Frequency Response Analysis (SFRA)
Instrument Users Guide, Doble Engineering Company, 2001.
[37] Maintenance Scheduling for Electrical Equipment, FIST 4-1B,
Bureau of Reclamation, 2001.
[38] Thermographic Maintenance Program, FIST 4-13, Bureau of
Reclamation.
[39] An Introduction to the Half-Century Transformer, Transformer
Maintenance Institute, S.D. Myers, Co., 2002.
[40] Transformer Nitrogen Advisory, PEB 5, October 2000.

Accronyms and Abbreviations
235
Acronyms and Abbreviations
AC alternating current
amp ampere
ANSI American National Standards Institute
ASTM American Society for Testing and Materials
back EMF back electro-motive force
cfm cubic feet per minute
CH4 methane
C2H2 acetylene
C2H4 ethylene
C2H6 ethane
CO carbon monoxide
CO2 carbon dioxide
CT current transformer
dB decibel
DBPC ditertiary butyl paracresol (oxygen inhibitor
for transformer oil)
dc direct current
DETC de-energized tap changer
DGA dissolved gas analysis
DP degree of polymerization (measure of
mechanical strength and remaining life of
paper insulation).
EHV extra high voltage (higher than
240,000 volts)
EPRI Electric Power Research Institute
FIST Facilities Instructions, Standards, and
Techniques
FRA Frequency Response Analyses

Acronyms and Abbreviations
236
gm gram
GSU generator step-up
H2 hydrogen
Hz hertz (cycles per second)
IEC International Electrotechnical Commission
IEEE Institute of Electrical and Electronic
Engineers
IFT Interfacial Tension (between transformer oil
and water; this is a measure of the amount of
particles and pollution in transformer oil)
ips inches per second
IR infrared
I2
R watts
JHA job hazard analysis
kHz kilohertz (kilocycles per second)
KOH potassium hydroxide (used to determine acid
number of transformer oil)
kV kilovolts
kW kilowatt
LTC load tap changer
kVA kilovoltampere
mA milliampere
M/DW moisture by dry weight (percent of weight
of water in paper insulation based on dry
weight of paper given on transformer
nameplate)
Mg milligram
MHz megahertz (megacycles per second)
MVA megavoltampere
NFPA National Fire Protection Association

Accronyms and Abbreviations
237
N2 nitrogen
O&M operation and maintenance
O2 oxygen
ppb parts per billion
ppm parts per million
ppm/day parts per million per day
psi pounds per square inch
PT potential transformer
Reclamation Bureau of Reclamation
SCADA supervisory control and data acquisition
SFRA Sweep Frequency Response Analysis
STP Standard temperature and pressure; 0 °C (32
°F) and 14.7 psi (one atmosphere)
TCG total combustible gas
TDCG total dissolved combustible gas
TOA Transformer Oil Analysis
TSC Technical Service Center
TTR transformer turns ratio
UV ultraviolet
VA voltampere
°C degrees Celsius
°F degrees Fahrenheit
% percent

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