U.S. Department of the Interior 

Bureau of Reclamation Ap

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 Ap

Transformers: 

Basics, Maintenance

and Diagnostics 

PREFACE 

Transformers have been used at powerplants since the inceptio

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. Th

effective, regular maintenance and testing is even more essent

continued operation when traditional “overdesign” cannot be r

to overcome abnormal conditions. The utility engineer must b

familiar with all aspects of maintenance and testing and make 

state-of-the-art tools and techniques for evaluating transforme

condition. While on-line diagnostic systems and computerize

methods are very helpful, they are not a substitute for sound 

engineering judgment and expertise. 

This volume provides timely, practical advice to those seeking 

better understand how transformers work, how they are best 

maintained, and how to test and evaluate their condition. It ha

developed with the assistance of Bureau of Reclamation engin

responsible for operating and maintaining transformers at imp

powerplants in the Western States. Support and funding was p

through the Reclamation Power Resources Office in Denver a

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 

Contents 

1. Introduction......................................................................... 

2. Introduction to Transformers .............................................. 

 2.1 Principle of Operation................................................ 

 2.2 Transformer Action.................................................... 

 2.3 Transformer Voltage and Current.............................. 

 2.4 The Magnetic Circuit ................................................. 

 2.5 Core Losses................................................................ 

 2.6 Copper Losses............................................................ 

 2.7 Transformer Rating.................................................... 

 2.8 Percent Impedance..................................................... 

 2.9 Internal Forces ........................................................... 

 2.10 Autotransformers ....................................................... 

 2.11 Instrument Transformers............................................ 

 2.12 Potential Transformers............................................... 

 2.13 Current Transformers................................................. 

 2.14 Transformer Taps....................................................... 

 2.15 Transformer Bushings................................................ 

 2.16 Transformer Polarity.................................................. 

 2.17 Single-Phase Transformer Connections for 

 Typical Service to Buildings................................... 

 2.18 Parallel Operation of Single-Phase Transformers 

 for Additional Capacity........................................... 

 2.19 Three-Phase Transformer Connections...................... 

 2.20 Wye and Delta Connections....................................... 

 2.21 Three-Phase Connections Using 

 Single-Phase Transformers ..................................... 

 2.22 Paralleling Three-Phase Transformers....................... 

 2.23 Methods of Cooling ................................................... 

 2.24 Oil-Filled – Self-Cooled Transformers...................... 

 2.25 Forced-Air and Forced-Oil-Cooled 

 Transformers ......................................................... 

 2.26 Transformer Oil ......................................................... 
vi 

Contents (continued) 

2. Introduction to Transformers (continued) 

 2.27 Conservator System ................................................... 

 2.28 Oil-Filled, Inert-Gas System...................................... 

 2.29 Indoor Transformers .................................................. 

3. Routine Maintenance ......................................................... 

 3.1 Introduction to Reclamation Transformers................ 

 3.2 Transformer Cooling Methods Introduction.............. 

 3.3 Dry-Type Transformers ............................................. 

 3.3.1 Potential Problems and Remedial 

 Actions for Dry-Type Transformer 

 Cooling Systems ......................................... 

 3.4 Liquid-Immersed Transformers................................. 

 3.4.1. Liquid-Immersed, Air-Cooled ....................... 

 3.4.2 Liquid-Immersed, Air-Cooled/Forced 

 Liquid-Cooled............................................. 

 3.4.3 Liquid-Immersed, Water-Cooled................... 

 3.4.4 Liquid-Immersed, Forced Liquid-Cooled...... 

 3.4.5 Potential Problems and Remedial Actions 

 for Liquid-Filled Transformer 

 Cooling Systems ......................................... 

 3.4.5.1 Leaks............................................... 

 3.4.5.2 Cleaning Radiators.......................... 

 3.4.5.3 Plugged Radiators ........................... 

 3.4.5.4 Sludge Formation............................ 

 3.4.5.5 Valve Problems............................... 

 3.4.5.6 Mineral Deposits............................. 

 3.4.5.7 Low Oil Level................................. 

 3.4.6 Cooling System Inspections........................... 

4. Oil-Filled Transformer Inspections..................................... 

 4.1 Transformer Tank ...................................................... 

 4.2 Top Oil Thermometers............................................... 
Contents (continued) 

4. Oil-Filled Transformer Inspections (continued) 

 4.3 Winding Temperature Thermometers........................ 

 4.3.1 Temperature Indicators Online ...................... 

 4.3.2 Temperature Indicators Offline...................... 

 4.4 Oil Level Indicators ................................................... 

 4.5 Pressure Relief Devices ............................................. 

 4.5.1 Newer Pressure Relief Devices...................... 

 4.5.2 Older Pressure Relief Devices ....................... 

 4.6 Sudden Pressure Relay............................................... 

 4.6.1 Testing Suggestion......................................... 

 4.7 Buchholz Relay (Found Only on Transformers 

 with Conservators).................................................. 

 4.8 Transformer Bushings: Testing and 

 Maintenance of High-Voltage Bushings................. 

 4.9 Oil Preservation Sealing Systems .............................. 

 4.9.1 Sealing Systems Types .................................. 

 4.9.1.1 Free Breathing................................. 

 4.9.1.2 Sealed or Pressurized Breathing ..... 

 4.9.1.3 Pressurized Inert Gas Sealed 

 System.......................................... 

 4.9.2 Gas Pressure Control Components ................ 

 4.9.2.1 High-Pressure Gauge ...................... 

 4.9.2.2 High-Pressure Regulator................. 

 4.9.2.3 Low-Pressure Regulator.................. 

 4.9.2.4 Bypass Valve Assembly ................. 

 4.9.2.5 Oil Sump ......................................... 

 4.9.2.6 Shutoff Valves ................................ 

 4.9.2.7 Sampling and Purge Valve.............. 

 4.9.2.8 Free Breathing Conservator ............ 

 4.9.2.9 Conservator with Bladder or 

 Diaphragm Design ....................... 

 4.10 Auxiliary Tank Sealing System ................................. 
viii 

Contents (continued) 

5. Gaskets................................................................................ 

 5.1 Sealing (Mating) Surface Preparation........................ 

 5.2 Cork-Nitrile................................................................ 

 5.3 Cork-Neoprene........................................................... 

 5.4 Nitrile “NBR” ............................................................ 

 5.4.1 Viton .............................................................. 

 5.5 Gasket Sizing for Standard Groove Depths............... 

 5.6 Rectangular Nitrile Gaskets ....................................... 

 5.7 Bolting Sequences to Avoid Sealing Problems ......... 

6. Transformer Oils................................................................. 

 6.1 Transformer Oil Functions......................................... 

 6.1.1 Dissolved Gas Analysis ................................. 

 6.1.2 Key Gas Method ............................................ 

 6.1.2.1 Four-Condition DGA Guide 

 (IEEE C57-104) ........................... 

 6.1.3 Sampling Intervals and Recommended 

 Actions ........................................................ 

 6.1.4 Atmospheric Gases ........................................ 

 6.1.5 Dissolved Gas Software................................. 

 6.1.6 Temperature ................................................... 

 6.1.7 Gas Mixing..................................................... 

 6.1.8 Gas Solubility................................................. 

 6.1.9 Diagnosing a Transformer Problem 

 Using Dissolved Gas Analysis and 

 the Duval Triangle ...................................... 

 6.1.9.1 Origin of the Duval Triangle........... 

 6.1.9.2 How to Use the Duval Triangle ...... 

 6.1.9.3 Expertise Needed ............................ 

 6.1.9.4 Rogers Ratio Method of DGA ........ 

 6.1.10 Carbon Dioxide/Carbon Monoxide Ratio...... 

 6.1.11 Moisture Problems......................................... 
Contents (continued) 

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 ........................... 

 6.1.11.2 Moisture in Transformer 

 Insulation...................................... 

7. Transformer Oil Tests that Should Be Completed 

 Annually with the Dissolved Gas Analysis ............... 

 7.1 Dielectric Strength ..................................................... 

 7.1.1 Interfacial Tension ......................................... 

 7.2 Acid Number.............................................................. 

 7.3 Test for Oxygen Inhibitor .......................................... 

 7.4 Power Factor .............................................................. 

 7.5 Oxygen....................................................................... 

 7.6 Furans......................................................................... 

 7.7 Oil Treatment Specification....................................... 

 7.7.1 Taking Oil Samples for DGA ........................ 

 7.7.1.1 DGA Oil Sample Container............ 

 7.7.1.2 Taking the Sample .......................... 

8. Silicone Oil-Filled Transformers ........................................ 

 8.1 Background................................................................ 

 8.2 Carbon Monoxide in Silicone Transformers.............. 

 8.3 Comparison of Silicone Oil and Mineral 

 Oil Transformers..................................................... 

 8.4 Gas Limits.................................................................. 

 8.5 Physical Test Limits................................................... 

9. Transformer Testing ......................................................... 

 9.1 DC Winding Resistance Measurement ...................... 

 9.2 Core Insulation Resistance and Inadvertent 

 Core Ground Test (Megger®) ................................ 
x 

Contents (continued) 

9. Transformer Testing (continued) 

 9.3 Doble Tests on Insulation .......................................... 

 9.3.1 Insulation Power Factor Test ......................... 

 9.3.2 Capacitance Test ............................................ 

 9.3.3 Excitation Current Test.................................. 

 9.3.4 Bushing Tests................................................. 

 9.3.5 Percent Impedance/Leakage 

 Reactance Test ............................................ 

 9.3.6 Sweep Frequency Response 

 Analysis Tests ............................................. 

 9.4 Visual Inspection ....................................................... 

 9.4.1 Background.................................................... 

 9.4.2 Oil Leaks........................................................ 

 9.4.3 Oil Pumps....................................................... 

 9.4.4 Fans and Radiators......................................... 

 9.4.5 Age................................................................. 

 9.4.6 Infrared Temperature Analysis ...................... 

 9.4.7 IR for Transformer Tanks .............................. 

 9.4.8 IR for Surge Arresters.................................... 

 9.4.9 IR for Bushings.............................................. 

 9.4.10 IR for Radiators and Cooling Systems........... 

 9.4.11 Corona Scope Scan ........................................ 

 9.5 Ultrasonic and Sonic Fault Detection ........................ 

 9.5.1 Background.................................................... 

 9.5.2 Process ........................................................... 

 9.6 Vibration Analysis ..................................................... 

 9.6.1 Background.................................................... 

 9.6.2 Process ........................................................... 

 9.7 Turns Ratio Test ......................................................... 

 9.7.1 Background.................................................... 

 9.7.2 Process ........................................................... 

 9.8 Estimate of Paper Deterioration (Online) .................. 

 9.8.1 CO2 and CO Accumulated Total 

 Gas Values .................................................. 
Contents (continued) 

9. Transformer Testing (continued) 

 9.8 Estimate of Paper Deterioration (Online) (continued) 

 9.8.2 CO2/CO Ratio ................................................ 

 9.9 Estimate of Paper Deterioration (Offline 

 During Internal Inspection)..................................... 

 9.9.1 Degree of Polymerization (DP) ..................... 

 9.9.1.1 Background..................................... 

 9.9.1.2 Process ............................................ 

 9.9.2 Internal Inspection ......................................... 

 9.9.2.1 Background..................................... 

 9.9.2.2 Transformer Borescope................... 

 9.10 Transformer Operating History.................................. 

 9.11 Transformer Diagnostics/Condition 

 Assessment Summary ............................................. 

Appendix: Hydroplant Risk Assessment – 

 Transformer Condition Assessment.................................... 

References ................................................................................. 

Acronyms and Abbreviations ................................................... 

Tables 

Table No. 

 1 Operative Parallel Connections of 

 Three-Phase Transformers...................................... 

 2 Inoperative Parallel Connections of 

 Three-Phase Transformers...................................... 

 3 Transformer Gasket Application Summary............... 

 4 Vertical Groove Compression for 

 Circular Nitrile Gasket............................................ 
xii 

Tables (continued) 

Table No. 

 5 Vertical Groove Compression for 

 Rectangular Nitrile Gaskets .................................... 

 6 Transformer DGA Condition Summary Table .......... 

 7 345-kV Transformer Example ................................... 

 8 Dissolved Key Gas Concentration Limits.................. 

 9 Actions Based on Dissolved Combustible Gas.......... 

 10 TOA L1 Limits and Generation Rate Per 

 Month Alarm Limits ............................................... 

 11 Fault Types................................................................. 

 12 Dissolved Gas Solubility in Transformer Oil 

 Accurate Only at STP, 0 °C (32 °F) and 

 14.7 psi (29.93 Inches of Mercury)......................... 

 13 L1 Limits and Generation Rate Per 

 Month Limits ......................................................... 

 14 Dissolved Gas Analysis Detection Limits ................. 

 15 Rogers Ratios for Key Gases ..................................... 

 16 Typical Faults in Power Transformers....................... 

 17 Comparison of Water Distribution in Oil 

 and Paper ................................................................ 

 18 Furans, DP, Percent of Life Used of 

 Paper Insulation ...................................................... 

 19 Doble Limits for Inservice Oils ................................. 

 20 Additional Guidelines for Inservice Oils ................... 

 21 Comparison of Gas Limits......................................... 

 22 Suggested Levels of Concern (Limits) ...................... 

 23 Doble and IEEE Physical Test Limits for 

 Service-Aged Silicone Fluid................................... 

 24 Paper Status Conditions Using CO2 and CO ............. 

 25 DP Values for Estimating Remaining 

 Paper Life................................................................ 

 26 Reclamation Transformer Condition 

 Assessment Summary ............................................. 
Figures 

Figure No. 

 1 Typical GSU Three-Phase Transformer .................... 

 2 Transformer Construction.......................................... 

 3 Transformer Action.................................................... 

 4 Transformer................................................................ 

 5 Step-Up and Step-Down Transformers...................... 

 6 Magnetic Circuits....................................................... 

 7 Three-Phase Core Form and Three-Phase 

 Shell Form Transformer Units................................ 

 8 Transformer Internal Forces ...................................... 

 9 Autotransformers ....................................................... 

 10 Connections of Instrument Transformers .................. 

 11 Potential Transformers............................................... 

 12 Current Transformer .................................................. 

 13 Photograph of Current Transformers ......................... 

 14 Polarity Illustrated...................................................... 

 15 Single-Phase Transformer.......................................... 

 16 Single-Phase Paralleling ............................................ 

 17 Three-Phase Connections........................................... 

 18 Delta-Delta Connections, Single-Phase 

 Transformers for Three-Phase Operation ............... 

 19 Wye-Wye Connections, Using Single-Phase 

 Transformers for Three-Phase Operation ............... 

 20 Delta-Wye and Wye-Delta Connections Using 

 Single-Phase Transformers for Three-Phase 

 Operation................................................................. 

 21 Cooling....................................................................... 

 22 Forced-Air/Oil/Water-Cooled Transformers ............. 

 23 Conservator with Bladder .......................................... 

 24 Typical Transformer Nitrogen System ...................... 

 25 Transformer Diagnostics Flowchart .......................... 

 26 Typical Oil Flow........................................................ 

 27 Oil Level Indicator..................................................... 

 28 Conservator Oil Level................................................ 
xiv 

Figures (continued) 

Figure No. 

 29 Pressure Relief Device............................................... 

 30 Photograph of a Pressure Relief Device .................... 

 31 Sudden Pressure Relay, Section................................. 

 32 Photograph of a Sudden Pressure Relay .................... 

 33 Buchholz Relay, Section............................................ 

 34 Photograph of a Buchholz Relay ............................... 

 35 Pressurized Breathing Transformer ........................... 

 36 Pressurized Inert Gas Transformer ............................ 

 37 Gas Pressure Control Components ............................ 

 38 Free Breathing Conservator ....................................... 

 39 Conservator with Bladder .......................................... 

 40 Conservator Breather ................................................. 

 41 Photograph of a Bladder Failure Relay...................... 

 42 Bladder Failure Relay ................................................ 

 43 Auxiliary Sealing System .......................................... 

 44 Cross Section of Circular Gasket in Groove.............. 

 45 Cross Section of Gasket Remains Constant 

 Before Tightening and After................................... 

 46 Bowing at Flanges...................................................... 

 47 Bolt Tightening Sequences ........................................ 

 48 Combustible Gas Generation Versus 

 Temperature ............................................................ 

 49 The Duval Triangle.................................................... 

 50 Duval Triangle Diagnostic Example of a 

 Reclamation Transformer ....................................... 

 51 Maximum Amount of Water Dissolved in 

 Mineral Oil Versus Temperature ............................ 

 52 Transformer Oil Percent Saturation Curves............... 

 53 Water Distribution in Transformer Insulation ........... 

 54 Myers Multiplier Versus Temperature....................... 

 55 Water Content of Paper and Oil Nomogram.............. 

 56 Interfacial Tension, Acid Number, Years 

 in Service ................................................................ 
Figures (continued) 

Figure No. 

 57 Oil Sampling Piping................................................... 

 58 Sampling Syringe (Flushing) ..................................... 

 59 Sampling Syringe (Filling) ........................................ 

 60 Sample Syringe Bubble Removal .............................. 

 61 Relationship of Oxygen to Carbon Dioxide 

 and Carbon Monoxide as Transformer Ages .......... 

 62 SFRA Test Traces of a New Transformer ................. 

 63 SFRA Test Traces of a Defective New 

 Transformer............................................................. 

 64 Normal Transformer IR Pattern................................. 

 65 IR Image of Defective Arrester.................................. 

 66 IR Image Showing Blocked Radiators....................... 

 67 IR Image of Defective Bushing ................................. 

 68 Transformer Diagnostic Test Chart (Adapted 

 from IEEE 62-1995TM) ........................................... 

1. Introduction 

This document was created to provide guidance to Bureau of 

Reclamation (Reclamation) powerplant personnel in maintena

diagnostics, and testing of transformers and associated equipm

This document applies primarily to the maintenance and diagn

of oil-filled power transformers (500 kilovoltamperes [kVA] a

larger), owned and operated by Reclamation, although routine 

maintenance of other transformer types is addressed as well. S

technical details are included in other documents and are refer

this document. 

Guidance and recommendations herein are based on industry s

and experience gained at Reclamation facilities. However, eq

and situations vary greatly, and sound engineering and manag

judgment must be exercised when applying these diagnostics. 

available information must be considered (e.g., manufacturer=s 

transformer experts’ recommendations, unusual operating con

personal experience with the equipment, etc.) in conjunction w

document. 

2. Introduction to Transformers 

Generator step-up (GSU) transformers represent the second la

capital investment in Reclamation power production—second 

to generators. Reclamation has hundreds, perhaps thousands, 

of transformers, in addition to hundreds of large GSU transfor

Reclamation has transformers as small as a camera battery cha

about one-half the size of a coffee cup, to huge generator step-

transformers near the size of a small house. The total investm

in transformers may well exceed generator investment. Trans

are extremely important to Reclamation, and it is necessary 

to understand their basic functions. 
2 

A transformer has no internal moving parts, and it transfers en

from one circuit to another by electromagnetic induction. Ext

cooling may include heat exchangers, radiators, fans, and oil p

Radiators and fans are evident in figure 1. The large horizonta

the top is a conservator. Transformers are typically used beca

change in voltage is needed. Power transformers are defined a

transformers rat

500 kVA and la

Larger transform

oil-filled for ins

and cooling; a ty

GSU transforme

contain several t

gallons of oil. O

always be aware 

possibility of sp

leaks, fires, and 

environmental r

oil poses. 

Transformers sm

than 500 kVA a

generally called 

distribution transformers. Pole-top and small, pad-mounted 

transformers that serve residences and small businesses are typ

distribution transformers. Generator step-up transformers, use

Reclamation powerplants, receive electrical energy at generato

voltage and increase it to a higher voltage for transmission lin

Conversely, a step-down transformer receives energy at a high

voltage and delivers it at a lower voltage for distribution to va

loads. 

All electrical devices using coils (in this case, transformers) ar

constant wattage devices. This means voltage multiplied by c

must remain constant; therefore, when voltage is “stepped-up,

current is “stepped-down” (and vice versa). Transformers tran

Figure 1 – Typical GSU Three-Phase 

Transformer. 
electrical energy between circuits completely insulated from e

other. This makes it possible to use very high (stepped-up) vo

for transmission lines, resulting in a lower (stepped-down) cur

Higher voltage and lower current reduce the required size and 

transmission lines and reduce transmission losses as well. 

Transformers have made possible economic delivery of electri

over long distances. 

Transformers do not require as much attention as most other 

equipment; however, the care and maintenance they do require 

absolutely critical. Because of their reliability, maintenance is 

sometimes ignored, causing reduced service life and, at times, 

failure. 

2.1 Principle of Operation 

Transformer function is based on the principle that electrical e

transferred efficiently by magnetic induction from one circuit 

another. When one winding of a transformer is energized from 

alternating current (AC) source, an alternating magnetic field 

established in the transformer core. Alternating magnetic line

force, called “flux,” circulate through the core. With a second 

around the same core, a voltage is induced by the alternating f

A circuit, connected to the terminals of the second winding, re

current flow. 

Each phase of a transformer is composed of two separate coil 

wound on a common core. The low-voltage winding is placed 

the core; the high-voltage winding is then placed around both 

voltage winding and core. See figure 2 which shows internal 

construction of one phase. The core is typically made from ve

steel laminations, each coated with insulation. By insulating b

individual laminations, losses are reduced. The steel core prov

low resistance path for magnetic flux. Both high- and low-vol

windings are insulated from the core and from each other, and 
4 

are brought out through insulating bushings. A three-phase 

transformer typically has a core with three legs and has both h

voltage and low-voltage windings around each leg. Special pa

and wood are used for insulation and internal structural suppor

2.2 Transformer Action 

Transformer action depends upon magnetic lines of force (flux

mentioned above. At the instant a transformer primary is ener

with AC, a flow of electrons (current) begins. During the inst

switch closing, buildup of current and magnetic field occurs. 

current begins the positive portion of the sine wave, lines of m

force (flux) develop outward from the coil and continue to exp

until the current is at its positive peak. The magnetic field is a

positive peak. The current sine wave then begins to decrease, 

zero, and goes negative until it reaches its negative peak. The 

magnetic flux switches direction and also reaches its peak in th

Figure 2 – Transformer Construction. 
opposite direction. With an AC power circuit, the current cha

(alternates) continually 60 times per second, which is standard 

United States. Other countries may use other frequencies. In 

50 cycles per second is common. 

Strength of a magnetic field depends on the amount of current 

number of turns in the winding. When current is reduced, the 

magnetic field shrinks. When the current is switched off, the m

field collapses. 

When a coil is placed in an AC circuit, as shown in figure 3, c

the primary coil will be accompanied by a constantly rising an

collapsing magnetic field. When another coil is placed within 

alternating magnetic field of the first coil, the rising and collap

flux will induce voltage in the second coil. 

When an external circuit is connected to the second coil, the in

voltage in the coil will cause a current in the second coil. The 

said to be magnetically coupled; they are, however, electricall

isolated from each other. 

Many transformers have separate coils, as shown in figure 3, a

contain many turns of wire and a magnetic core, which forms 

for and concentrates the magnetic flux. The winding receiving 

electrical energy from the source is called the primary winding

winding which receives energy from the primary winding, via 

magnetic field, is called the “secondary” winding. 

Either the high- or low-voltage winding can be the primary or 

secondary. With GSUs at Reclamation powerplants, the prim

winding is the low-voltage side (generator voltage), and the hi

voltage side is the secondary winding (transmission voltage). 

power is used (i.e., at residences or businesses), the primary w

the high-voltage side, and the secondary winding is the low-vo

side. 
6 

The amount of voltage induced in each turn of the secondary w

will be the same as the voltage across each turn of the primary 

winding. The total amount of voltage induced will be equal to 

of the voltages induced in each turn. Therefore, if the seconda

winding has more turns than the primary, a greater voltage wil

induced in the secondary; and the transformer is known as a st

transformer. If the secondary winding has fewer turns than th

primary, a lower voltage will be induced in the secondary; and 

transformer is a step-down transformer. Note that the primary 

always connected to the source of power, and the secondary is 

connected to the load. 

In actual practice, the amount of power available from the sec

will be slightly less than the amount supplied to the primary b

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 th

Figure 3 – Transformer Action. 
generator voltage. Alternating current varies, and accompany

magnetic flux varies, cutting both transformer coils and induci

voltage in each coil circuit. 

The voltage induced in the primary circuit opposes the applied 

and is known as back voltage or back electro-motive-force (ba

EMF). When the secondary circuit is open, back EMF, along 

primary circuit resistance, acts to limit the primary current. Pr

current must be sufficient to maintain enough magnetic field t

produce the required back EMF. 

When the secondary circuit is closed and a load is applied, cur

appears in the secondary due to induced voltage, resulting from 

created by the primary current. This secondary current sets up 

second magnetic field in the transformer in the opposite direct

the primary field. Thus, the two fields oppose each other and 

a combined magnetic field of less strength than the single field 

produced by the primary with the secondary open. This reduc

back voltage (back EMF) of the primary and causes the prima

current to increase. The primary current increases until it reestablishes the total magnetic field at its original strength. 

Figure 4 – Transformer. 
8 

In transformers, a balanced condition must always exist betwe

primary and secondary magnetic fields. Volts times amperes (

must also be balanced (be the same) on both primary and seco

The required primary voltage and current must be supplied to 

the transformer losses and secondary load. 

2.3 Transformer Voltage and Current 

If the small amount of transformer loss is ignored, the back-vo

(back EMF) of the primary must equal the applied voltage. Th

magnetic field, which induces the back-voltage in the primary

cuts the secondary coil. If the secondary coil has the same num

turns as the primary, the voltage induced in the secondary will 

the back-voltage induced in the primary (or the applied voltag

secondary coil has twice as many turns as the primary, it will b

twice as many times by the flux, and twice the applied primary 

will be induced in the secondary. The total induced voltage in 

winding is proportional to the number of turns in that winding

the primary voltage and I1 the primary current, E2 the seconda

voltage and I2 the secondary current, N1 the primary turns and 

secondary turns, then: 

Note that the current is inversely proportional to both voltage 

number of turns. This means (as discussed earlier) that if volt

stepped up, the current must be stepped down and vice versa. 

number of turns remains constant unless there is a tap changer 

(discussed later). 

The power output or input of a transformer equals volts times 

(E x I). If the small amount of transformer loss is disregarded

equals output or: 

E1 x I1 = E2 x I2

1

2

2

1

2

1

I

I

N

N

E

E = =
If the primary voltage of a transformer is 110 volts (V), the pr

winding has 100 turns, and the secondary winding has 400 tur

will the secondary voltage be? 

100 E2 = 44,000 E2 = 440 volts 

If the primary current is 20 amps, what will the secondary curr

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 

secondary circuits, there must be a ratio of 1 to 4 between the 

and secondary voltage and a ratio of 4 to 1 between the primar

secondary current. As voltage is stepped up, the current is step

down, keeping volts multiplied by amps constant. This is refe

as “volt amps.” 

As mentioned earlier and further illustrated in figure 5, when t

number of turns or voltage on the secondary of a transformer i

than that of the primary, it is known as a step-up transformer. 

the number of turns or voltage on the secondary is less than th

primary, it is known as a step-down transformer. A power tra

used to tie two systems together may feed current either way b

systems, or act as a step-up or step-down transformer, dependi

where power is being generated and where it is consumed. As 

mentioned above, either winding could be the primary or seco

To eliminate this confusion, in power generation, windings of 

transformers are often referred to as high-side and low-side wi

depending on the relative values of the voltages. 

2

1

2

1

N

N

E

E = 400

100

E

110

2

=
10 

Note that kVA (amps times volts) remains constant throughou

above circuit on both sides of each transformer, which is why 

called constant wattage devices. 

Efficiencies of well-designed power transformers are very hig

averaging over 98 percent (%). The only losses are due to cor

maintaining the alternating magnetic field, resistance losses in 

coils, and power used for cooling. The main reason for high 

efficiencies of power transformers, compared to other equipm

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 prov

path for the magnetic field, which is necessary for induction o

voltages between windings. A path of low reluctance (i.e., res

to magnetic lines of force), consisting of thin silicon, sheet ste

laminations, is used for this purpose. In addition to providing 

reluctance path for the magnetic field, the core is designed to p

circulating electric currents within the steel itself. Circulating 

currents, called eddy currents, cause heating and energy loss. 

Figure 5 – Step-Up and Step-Down Transformers. 
due to voltages induced in the steel of the core, which is const

subject to alternating magnetic fields. Steel itself is a conduct

changing lines of magnetic flux also induce a voltage and curr

this conductor. By using very thin sheets of steel with insulati

material between sheets, eddy currents (losses) are greatly red

The two common arrangements of the magnetic path and the w

are shown in figure 6 and 7. In the core-type (core form) trans

the windings surround the core. 

A section of both primary and secondary windings are wound 

leg of the core, the low voltage winding is wound next to the c

the high voltage winding is wound over the low voltage. 

Figure 6 – Magnetic Circuits. 
12 

In a shell-type (shell form) transformer, the steel magnetic circ

(core) forms a shell surrounding the windings. In a core form

windings are on the outside; in a shell form, the windings are o

inside. In power transformers, the electrical windings are arra

that practically all of the magnetic lines of force go through bo

primary and secondary windings. A small percentage of the m

lines of force goes outside the core, and this is called leakage f

Larger transformers, such as Reclamation GSU transformers, 

almost always shell type. 

Figure 7 – Three-Phase Core Form and Three-Phase Shell 

Form Transformer Units. 
Note that, in the shell form transformers, (see figure 7) the ma

flux, external to the coils on both left and right extremes, has c

magnetic paths for stray and zero sequence flux to return to th

In the core form, it can easily be seen from the figure that, on 

and right extremes, there are no return paths. This means that 

must use external tank walls and the insulating medium for ret

paths. This increases core losses and decreases overall efficie

shows why most large transformers are built as shell form unit

2.5 Core Losses 

Since magnetic lines of force in a transformer are constantly c

in value and direction, heat is developed because of the hyster

the magnetic material (friction of the molecules). This heat m

removed; therefore, it represents an energy loss of the transfor

High temperatures in a transformer will drastically shorten the 

insulating materials used in the windings and structures. For e

8 degrees Celsius (°C) temperature rise, life of the transformer 

by one-half; therefore, maintenance of cooling systems is criti

Losses of energy, which appears as heat due both to hysteresis 

eddy currents in the magnetic path, is known as core losses. S

these losses are due to alternating magnetic fields, they occur 

transformer whenever the primary is energized, even though n

on the secondary winding. 

2.6 Copper Losses 

There is some loss of energy in a transformer due to resistance 

primary winding to the magnetizing current, even when no loa

connected to the transformer. This loss appears as heat genera

the winding and must also be removed by the cooling system. 

load is connected to a transformer and electrical currents exist 

primary and secondary windings, further losses of electrical en

occur. These losses, due to resistance of the windings, are cal

copper losses (or the I2

R losses). 
14 

2.7 Transformer Rating 

Capacity (or rating) of a transformer is limited by the tempera

the insulation can tolerate. Ratings can be increased by reduci

and copper losses, by increasing the rate of heat dissipation (b

cooling), or by improving transformer insulation so it will with

higher temperatures. A physically larger transformer can diss

more heat, due to the increased area and increased volume of o

transformer is only as strong as its weakest link, and the weak

is the paper insulation, which begins to degrade around 100 °C

means that a transformer must be operated with the “hottest sp

cooler than this degradation temperature, or service life is grea

reduced. Reclamation typically orders transformers larger tha

required, which aids in heat removal and increases transforme

Ratings of transformers are obtained by simply multiplying th

times the voltage. Small transformers are rated in “VA,” volts 

amperes. As size increases, 1 kilovoltampere (kVA) means 

1,000 voltamperes, 1 megavoltampere (MVA) means 1 millio

voltamperes. Large GSUs may be rated in hundreds of MVAs

GSU transformer can cost well over a million dollars and take 

18 months to 2 years or longer to obtain. Each one is designed 

specific application. If one fails, this may mean a unit or who

could be down for as long 2 years, costing multiple millions o

in lost generation, in addition to the replacement cost of the 

transformer itself. This is one reason that proper maintenance 

critical. 

2.8 Percent Impedance 

The impedance of a transformer is the total opposition offered 

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 tha

meant. In order to determine equivalent impedance, one wind
the transformer is short circuited, and just enough voltage is ap

the other winding to create full load current to flow in the shor

circuited winding. This voltage is known as the impedance vo

Either winding may be short-circuited for this test, but it is usu

more convenient to short circuit the low-voltage winding. The 

transformer impedance value is given on the nameplate in perc

This means that the voltage drop due to the impedance is expr

a percent of rated voltage. For example, if a 2,400/240-volt 

transformer has a measured impedance voltage of 72 volts on 

voltage windings, its impedance (Z), expressed as a percent, is

percent Z = 2,400

72 x 100 = 3 percent 

This means there would be a 72-volt drop in the high-voltage 

at full load due to losses in the windings and core. Only 1 or 2

losses are due to the core; about 98% are due to the winding 

impedance. If the transformer were not operating at full load, 

voltage drop would be less. If an actual impedance value in oh

needed for the high-voltage side: 

where V is the voltage drop or, in this case, 72 volts; and I is t

full load current in the primary winding. If the full load curren

10 amps: 

Of course, one must remember that impedance is made up of b

resistive and reactive components. 

I

V Z =

ohms

a

V Z 7.2

10

72 = =
16 

2.9 Internal Forces 

During normal operation, internal structures and windings are 

subjected to mechanical forces due to the magnetic forces. Th

forces are illustrated in figure 8. By designing the internal stru

very strong to withstand these forces over a long period of tim

service life can be extended. However, in a large transformer 

“through fault” (fault current passing through a transformer), f

can reach millions of pounds, pulling the coils up and down an

pulling them apart 60 times per second. Notice in figure 8 tha

internal low-voltage coil is being pulled downward, while the 

voltage winding is pulled up, in the opposite direction. At the 

time, the right-hand part of the figure shows that the high- and 

voltage coils are being forced apart. Keep in mind that these f

reversing 60 times each second. It is obvious why internal stru

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 transfor

itself. This normally results in arcing inside the transformer th

result in explosive failure of the tank, throwing flaming oil ov

Figure 8 – Transformer Internal Forces. 
area. There are protective relaying systems to protect against 

possibility, although explosive failures do occur occasionally. 

2.10 Autotransformers 

It is possible to obtain transformer action by means of a single 

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 

The primary is always the portion of the winding connected to 

AC power source. This transformer may be used to step volta

down. If the primary is the total winding and is connected to a 

and the secondary circuit is connected across only a portion of 

winding (as shown), the secondary voltage is “stepped-down.” 

Figure 9 – Autotransformers. 
18 

If only a portion of the winding is the primary and is connecte

supply voltage and the secondary includes all the winding, the

voltage will be “stepped-up” in proportion to the ratio of the to

to the number of connected turns in the primary winding. 

When primary current I1 is in the direction of the arrow, secon

current, I2, is in the opposite direction, as in figure 9b. Theref

the portion of the winding between points b and c, current is th

difference of I1 and I2. If the requirement is to step the voltage 

down) only a small amount, then the transformer ratio is small

and E2 are nearly equal. Currents I1 and I2 are also nearly equ

portion of the winding between b and c, which carries the diffe

the currents, can be made of a much smaller conductor, since t

current is much lower. 

Under these circumstances, the autotransformer is much cheap

the two-coil transformer of the same rating. However, the 

disadvantage of the autotransformer is that the primary and se

circuits are electrically connected and, therefore, could not saf

used for stepping down from high voltage to a voltage suitable 

plant loads. The autotransformer, however, is extensively use

reducing line voltage for step increases in starting larger induc

motors. There are generally four or five taps that are changed 

timers so that more of the winding is added in each step until t

voltage is applied across the motor. This avoids the large inru

current required when starting motors at full line voltage. Thi

transformer is also extensively used for “buck-boost” when th

needs to be stepped up or down only a small percentage. One 

common example is boosting 208 V up from one phase of a 12

three-phase system, to 220 V for single-phase loads. 

2.11 Instrument Transformers 

Instrument transformers (figure 10) are used for measuring an

purposes. They provide currents and voltages proportional to 

primary, but there is less danger to instruments and personnel. 
Those transformers used to step voltage down are known as po

transformers (PTs) and those used to step current down are kn

current transformers (CTs). 

The function of a PT is to accurately measure voltage on the p

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 

synchroscopes and synchronizing apparatus, protective and re

relays, and undervoltage and overvoltage trip coils of circuit b

One potential transformer can be used for a number of instrum

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-ampere

120 secondary volts. The secondary terminals should never b

circuited because a heavy current will result, which can damag

windings. 

Figure 10 – Connections of Instrument Transformers. 
20 

2.13 Current Transformers 

The primary of a current transformer typically has only one tu

is not really a turn or wrap around the core but just a conducto

going through the “window.” The primary never has more tha

few turns, while the secondary may have a great many turns, 

depending upon how much the current must be stepped down. 

cases, the primary of a current transformer is a single wire or b

and the secondary is wound on a laminated magnetic core, pla

around the conductor in which the current needs to be measure

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 rem

and the primary magnetizing force builds up an extremely high 

Potential Transformer in 

switchyard. 

Inside Potential Transformer 

with Fuses. 

Figure 11 – Potential Transformers. 
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, pow

factor meters, watt-hour meters, compensators, protective and 

regulating relays, and trip coils of circuit breakers. One CT ca

used to operate several instruments, provided the combined lo

the instruments do not exceed that for which the CT is rated. 

Secondary windings are usually rated at 5 amperes. A variety 

current transformers are shown in figure 13. Many times, CTs 

several taps on the secondary winding to adjust the range of cu

possible to measure on the primary. 

Figure 12 – Current Transformer. 
22 

2.14 Transformer Taps 

Most power transformers have taps on either primary or secon

windings to vary the number of turns and, thus, the output vol

The percentage of voltage change, above or below normal, bet

different tap positions varies in different transformers. In oil-c

transformers, tap leads are brought to a tap changer, located be

the oil inside the tank, or brought to an oil-filled tap changer, 

externally located. Taps on dry-type transformers are brought 

insulated terminal boards located inside the metal housing, acc

by removing a panel. 

Some transformers taps can be changed under load, while othe

transformers must be de-energized. When it is necessary to ch

taps frequently to meet changing conditions, taps that can be c

under load are used. This is accomplished by means of a moto

may be controlled either manually or automatically. Automat

operation is achieved by changing taps to maintain constant vo

system conditions change. A common range of adjustment is 

Current Transformer in 

Switchyard. 

Lab Current Transformer. 

Current 

Transfor

Figure 13 Switchya– Photograph of Current Transformers. 
minus 10%. At Reclamation powerplants, de-energized tap ch

(DETC) are used and can only be changed with the transforme

line. A very few load tap changers (LTC) are used at Grand C

between the 500-kilovolt (kV) (volts x 1,000) and 220-kV 

switchyards. 

A bypass device is sometimes used across tap changers to ensu

power flow in case of contact failure. This prevents failure of 

transformer in case excessive voltage appears across faulty co

2.15 Transformer Bushings 

The two most common types of bushings used on transformer

lead entrances are solid porcelain bushings on smaller transfor

and oil-filled condenser bushings on larger transformers. 

Solid porcelain bushings consist of high-grade porcelain cylin

conductors pass through. Outside surfaces have a series of ski

increase the leakage path distance to the grounded metal case. 

voltage bushings are generally oil-filled condenser type. Cond

types have a central conductor wound with alternating layers o

insulation and tin foil and filled with insulating oil. This resul

path from the conductor to the grounded tank, consisting of a 

condensers. The layers are designed to provide approximately 

voltage drops between each condenser layer. 

Acceptance and routine maintenance tests most often used for 

checking the condition of bushings are Doble power factor tes

power factor of a bushing in good condition will remain relativ

stable throughout the service life. A good indication of insula

deterioration is a slowly rising power factor. The most comm

of failure is moisture entrance through the top bushing seal. T

condition will be revealed before failure by routine Doble test

Doble testing is not performed regularly, explosive failure is th

eventual result of a leaking bushing. This, many times, results 

catastrophic and expensive failure of the transformer as well. 
24 

2.16 Transformer Polarity 

With power or distribution transformers, polarity is important 

the need arises to parallel transformers to gain additional capa

hook up three single-phase transformers to make a three-phase 

The way the connections are made affects angular displaceme

rotation, and direction of rotation of connected motors. Polari

important when hooking up current transformers for relay prot

and metering. Transformer polarity depends on which directio

are wound around the core (clockwise or counterclockwise) an

the leads are brought out. Transformers are sometimes marke

terminals with polarity marks. Often, polarity marks are show

white paint dots (for plus) or plus-minus marks on the transfor

symbols on the nameplate. These marks show the connection

the input and output voltages (and currents) have the same 

instantaneous polarity. 

More often, transformer polarity is shown simply by the Amer

National Standards Institute (ANSI) designations of the windin

as H1, H2 and X1, X2. By ANSI standards, if you face the low

side of a single-phase transformer (the side marked X1, X2), th

connection will always be on your far left. See the single-pha

diagrams in figure 14. If the terminal marked X1 is also on yo

is subtractive polarity. If the X1 terminal is on your right, it is 

polarity. Additive polarity is common for small distribution 

transformers. Large transformers, such as GSUs at Reclamati

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 p

marked terminal of the primary winding, the current direction 

the terminal with the same polarity mark in the secondary win

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 o

If you want to test for polarity, connect the transformer as sho
in figure 14. A transformer is said to have additive polarity if, 

when adjacent high- and low-voltage terminals are connected 

voltmeter placed across the other high- and low-voltage termin

the voltmeter reads the sum (additive) of the high- and low-vo

windings. It is subtractive polarity if the voltmeter reads the d

(subtractive) between the voltages of the two windings. If this 

conducted, use the lowest AC voltage available to reduce pote

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 Typ

Service to Buildings 

Figure 15 shows a typical arrangement of bringing leads out o

single-phase distribution transformer. To provide flexibility fo

connection, the secondary winding is arranged in two sections

Each section has the same number of turns and, consequently, 

same voltage. Two primary leads (H1, H2) are brought out fro

Figure 14 – Polarity Illustrated. 
26 

top through porcelain bushings. Three secondary leads (X1, X

are brought out through insulating bushings on the side of the 

one lead from the center tap (neutral) (X2) and one from each 

the secondary coil (X1 and X3). Connections, as shown, are ty

services to homes and small businesses. This connection prov

three-wire service that permits adequate capacity at minimum 

The neutral wire (X2) (center tap) is grounded. A 120-volt cir

between the neutral and each of the other leads, and a 240-vol

is between the two ungrounded leads. 

2.18 Parallel Operation of Single-Phase Transformer

Additional Capacity 

In perfect parallel operation of two or more transformers, curr

each transformer would be directly proportional to the transfor

capacity, and the arithmetic sum would equal one-half the tota

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. 
1. Any combination of positive and negative polarity tran

can be used. However, in all cases, numerical notation

be followed on both primary and secondary connection

is H1 connected to H1, H2 connected to H2, and X1 con

X1, X2 connected to X2, X3 connected to X3. Note that 

subscript number on a transformer must be connected t

same subscript number on the other transformer as sho

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, make

turns ratios also identical. 

4. The percent impedance of one transformer must be bet

921⁄2% and 1071⁄2% of the other. Otherwise, 

circulating currents between the two transformers wou

excessive. 

Figure 16 – Single-Phase Paralleling. 
28 

5. Frequencies must be identical. Standard frequency in t

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 me

percent impedance requirement, they must be nearly the same 

Most utilities will not parallel transformers if they are more th

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 transform

which is constructed with three single-phase units enclosed in 

tank or three separate single-phase transformers. The methods 

connecting windings are the same, whether using the one three

transformer or three separate single-phase transformers. 

2.20 Wye and Delta Connections 

The two common methods of connecting three-phase generato

motors, and transformers are shown in figure 17. The method 

in at figure 17a is known as a delta connection, because the di

bears a close resemblance to the Greek letter ), called delta. 

The other method, figure 17b, is known as the star or wye con

The wye differs from the delta connection in that it has two ph

series. The common point “O” of the three windings is called 

neutral because equal voltages exist between this point and an

three phases. 

When windings are connected wye, the voltage between any tw

will be 1.732 times the phase voltage, and the line current will 

same as the phase current. When transformers are connected d

line current will be 1.732 times the phase current, and the volt

between any two will be the same as that of the phase voltage. 
2.21 Three-Phase Connections Using Single-Phase 

Transformers 

As mentioned above, single-phase transformers may be conne

obtain three-phase power. These are found at many Reclamat

facilities, at shops, offices, and warehouses. The same require

must be observed as in section 2.18, “Parallel Operation of Sin

phase Transformers for Additional Capacity,” with one additio

requirement—in the manner connections are made between in

single-phase units. ANSI standard connections are illustrated 

the following figures. There are other angular displacements t

work but are seldom used. Do not attempt to connect single-p

units together in any combination that does keep the exact ang

displacement on both primary and secondary; a dangerous sho

could be the result. Additive and subtractive polarities can be 

(see the following figures). These banks also may be parallele

additional capacity if the rules are followed for three-phase pa

discussed below. When paralleling individual three-phase uni

single-phase banks to operate three phase, angular displaceme

be the same. 

Figure 18 shows delta-delta connections. Figure 19 shows wy

connections, which are seldom used at Reclamation facilities, 

Figure 17 – Three-Phase Connections. 
30 

Figure 18 – Delta-Delta Connections, Single-Phase Transformers 

Three-Phase Operation. 
Figure 19 – Wye-Wye Connections, Using Single-Phase Transform

for Three-Phase Operation. 

Note: These connections are seldom used because of 3rd harm

problems.
32 

inherent third harmonic problems. Methods of dealing with th

harmonic problem by grounding are listed below. 

However, it is easier just to use another connection scheme (i.

delta, wye-delta, or delta-wye [figure 20]), to avoid this proble

altogether. In addition, these schemes are much more familiar 

Reclamation personnel. 

2.22 Paralleling Three-Phase Transformers 

Two or more three-phase transformers, or two or more banks m

of three single-phase units, can be connected in parallel for ad

capacity. In addition to requirements listed above for single-p

transformers, phase angular displacements (phase rotation) be

high and low voltages must be the same for both. The require

identical angular displacement must be met for paralleling any 

combination of three-phase units and/or any combination of b

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 volta

on the high-voltage and low-voltage sides are in phase. This i

known as zero phase (angular) displacement. Since the displa

is the same, these may be paralleled. For delta-wye and wye-d

connections, each low-voltage phase lags its corresponding hi

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 displacemen

cannot be paralleled with a delta-wye or a wye-delta that has 

30 degrees of displacement. This will result in a dangerous sh
Figure 20 – Delta-Wye and Wye-Delta Connections Using Singl

Phase Transformers for Three-Phase Operation. 

Note: Connections on this page are the most common and sho

be used if possible.
34 

circuit. Table 1 shows the combinations that will operate in pa

and table 2 shows the combinations that will not operate in par

Table 1 – Operative Parallel Connections of Three-Phase Transform

OPERATIVE PARALLEL CONNECTIONS 

LOW-VOLTAGE SIDES HIGH-VOLTAGE SID

 Trans. A Trans. B Trans. A Tra

1 Delta Delta Delta D

2 Y Y Y 

3 Delta Y Delta 

4 Y Delta Y D

5 Delta Delta Y 

6 Delta Y Y D

7 Y Y Delta D

8 Y Delta Delta 

Table 2 – Inoperative Parallel Connections of Three-Phase Transform

INOPERATIVE PARALLEL CONNECTIONS 

 LOW-VOLTAGE SIDE HIGH-VOLTAGE SID

 Trans. A Trans. B Trans. A Tran

1 Delta Delta Delta Y 

2 Delta Delta Y De

3 Y Y Delta Y 

4 Y Y Y De

Wye-wye connected transformers are seldom, if ever, used to 

plant loads or as GSU units, due to the inherent third harmonic 

problems with this connection. Delta-delta, delta-wye, and wy

are used extensively at Reclamation facilities. Some rural elec

associations use wye-wye connections that may be supplying 
Reclamation structures in remote areas. There are three metho

negate the third harmonic problems found with wye-wye conn

1. Primary and secondary neutrals can be connected toge

grounded by one common grounding conductor. 

2. Primary and secondary neutrals can be grounded indiv

using two grounding conductors. 

3. The neutral of the primary can be connected back to th

of the sending transformer by using the transmission li

neutral. 

In making parallel connections of transformers, polarity marki

must be followed. Regardless of whether transformers are add

subtractive, connections of the terminals must be made accord

the markings and according to the method of the connection (i

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 capac

Cooling methods must not only maintain a sufficiently low av

temperature but must prevent an excessive temperature rise in 

portion of the transformer (i.e., it must prevent hot spots). For 

reason, working parts of large transformers are usually submer

high-grade insulating oil. This oil must be kept as free as poss

from moisture and oxygen, dissolved combustible gases, and 

particulates. 
36 

Ducts are arranged to p

free circulation of oil t

the core and coils; war

and lighter oil rises to t

top of the tank, cooler 

heavier oil settles to th

bottom. Several metho

have been developed 

for removing heat that 

transmitted to the trans

oil from the core and w

(figure 21). 

2.24 Oil-Filled – Self-Cooled Transformers 

In small- and medium-sized transformers, cooling takes place 

radiation from the tank to surrounding air. In oil-filled, self-co

types, tank surfaces may be corrugated to provide a greater rad

surface. Oil in contact with the core and windings rises as it a

heat and flows outward and downward along tank walls, wher

cooled by radiating heat to the surrounding air. These transfor

may also have external radiators attached to the tank to provid

surface area for cooling. 

2.25 Forced-Air and Forced-Oil-Cooled Transformer

Forced-air-cooled transformers have fan-cooled radiators throu

which the transformer oil circulates by gravity, as shown in fig

Fans force air through radiators, cooling the oil. 

Forced-air/oil/water-cooled transformers have a self-cooled (k

or MVA) rating and one or more forced cooling ratings (highe

or MVA). Higher ratings are due to forced cooling in increasi

amounts. As temperature increases, more fans or more oil pum

are turned on automatically.

Figure 21 – Cooling. 
The forced-cooling principle is based on a tradeoff between ex

cooling and manufacturing costs. Transformers with forced-c

have less weight and bulk than self-cooled transformers with t

ratings. In larger-sized transformers, it is more economical to 

forced cooling, even though the electricity needed to operate f

pumps increases the operating cost. 

2.26 Transformer Oil 

In addition to dissipating heat due to losses in a transformer, in

oil provides a medium with high dielectric strength in which th

and core are submerged. This allows the transformers to be m

compact, which reduces costs. 

Insulating oil in good condition will withstand far more voltag

connections inside the transformer tank than will air. An arc w

jump across the same spacing of internal energized componen

much lower voltage if the tank had only air. In addition, oil co

heat away from energized components much better than air. 

Over time, oil degrades from normal operations, due to heat an

contaminants. Oil cannot retain high dielectric strength when 

to air or moisture. Dielectric strength declines with absorption 

moisture and oxygen. These contaminants also deteriorate the 

Figure 22 – Forced-Air/Oil/Water-Cooled Transformers. 
38 

insulation. For this reason, efforts are made to prevent insulat

from contacting air, especially on larger power transformers. 

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 transform

the conservator with a flexible diaphragm or bladder or a posit

pressure inert-gas (nitrogen) system. Reclamation GSU transf

are generally purchased with conservators, while smaller statio

service transformers have a pressurized nitrogen blanket on to

Some station service transformers are dry-type, self-cooled or 

air cooled. 

2.27 Conservator System 

A conservator is connected by piping to the main transformer 

is completely filled with oil. The conservator also is filled wit

contains an expandable bladder or diaphragm between the oil 

to prevent air from contacting the oil. Figure 23 is a schemati

Figure 23 – Conservator with Bladder. 
representation of a conservator system (figure 1 is an actual ph

conservator). Air enters and exits the space above the bladder

diaphragm as the oil level in the main tank goes up and down 

temperature. Air typically enters and exits through a desiccan

dryer that must have the desiccant replaced periodically. The 

parts of the system are the expansion tank, bladder or diaphrag

breather, vent valves, liquid-level gauge and alarm switch. Ve

valves are used to vent air from the system when filling the un

oil. A liquid-level gauge indicates the need for adding or remo

transformer oil to maintain the proper oil level and permit flex

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 in

system. Here, the tank is slightly pressurized by an inert gas s

nitrogen. 

The main tank gas space above the oil is provided with a press

gauge (figure 24). Since the entire system is designed to exclu

must operate with a positive pressure in the gas space above th

otherwise, air will be admitted in the event of a leak. Smaller 

service units do not have nitrogen tanks attached to automatica

gas, and it is common practice to add nitrogen yearly each fall 

tank starts to draw partial vacuum, due to cooler weather. The 

gas is expelled each summer as loads and temperatures increas

Some systems are designed to add nitrogen automatically (figu

from pressurized tanks when the pressure drops below a set le

positive pressure of approximately 0.5 to 5 pounds per square 

(psi) is maintained in the gas space above the oil to prevent in

air. This system includes a nitrogen gas cylinder; three-stage, 

pressure-reducing valve; high-and low-pressure gauges; high- 

low-pressure alarm switch; an oil/condensate sump drain valv

automatic pressure-relief valve; and necessary piping. 
40 

The function of the three-stage, automatic pressure-reducing v

to reduce the pressure of the nitrogen cylinder to supply the sp

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 ps

indicates nitrogen cylinder pressure. The low-pressure gauge 

has a range of about -5 to +10 psi and indicates nitrogen press

above the transformer oil. 

In some systems, the gauge is equipped with high- and low-pr

alarm switches to alarm when gas pressure reaches an abnorm

the high-pressure gauge may be equipped with a pressure swit

sound an alarm when the supply cylinder pressure is running l

Figure 24 – Typical Transformer Nitrogen System. 
A sump and drain valve provide a means for collecting and rem

condensate and oil from the gas. A pressure-relief valve open

closes to release the gas from the transformer and, thus, limit t

pressure in the transformer to a safe maximum value. As temp

of a transformer rises, oil expands, and internal pressure increa

which may have to be relieved. When temperature drops, pres

drops, and nitrogen may have to be added, depending on the e

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 o

hazard, it is often necessary to isolate these transformers in a f

vault. 

Today, dry-type transformers are used extensively for indoor 

installations. These transformers are cooled and insulated by 

are not encased in sealed tanks like liquid-filled units. Enclosu

which they are mounted must have sufficient space for entranc

circulation of air, and for discharge of hot air. Dry-type transf

are enclosed in sheet metal cases with a cool air entrance at th

and a hot air discharge near the top. They may or may not hav

for increased air flow. 

In addition to personnel hazards, indoor transformer fires are 

extremely expensive and detrimental to plants, requiring exten

cleanup, long outages, and lost generation. Larger indoor 

transformers, used for station service and generator excitation

have differential relaying so that a fault can be interrupted qui

before a fire can ensue. Experience has shown that transforme

protection by fuses alone is not adequate to prevent fires in the 

of a short circuit. 
42 

3. Routine Maintenance 

The following chapters address routine maintenance, as well a

specific testing and diagnostic techniques and tools used to ass

condition of transformers (more detail is included for oil-filled 

transformers). Some processes are often above and beyond ro

maintenance work to keep the transformer operational. Transf

diagnostics require specialized equipment and training. This e

is not expected to be maintained in every office. In some case

be necessary to contact diagnostics specialists, either inside or 

Reclamation, who have the latest equipment and recent experi

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 (ANS

consider average GSU transformer life to be 20 to 25 years. T

estimate is based on continuous operation at rated load and ser

conditions with an average ambient temperature of 40 oC (104 

Fahrenheit [oF]) and a temperature rise of 65 oC. This estimat

based on the assumption that transformers receive adequate 

maintenance over their service life [26]. Reclamation, Bonnev

Power Administration, and Western Area Power Administratio

conduct regular studies to determine statistical equipment life. 

studies show that average life of a Reclamation transformer is 

40 years. Reclamation gets longer service than IEEE estimate

because of operating at lower ambient temperatures and with l

loads. A significant number of transformers were purchased i

1940s, 1950s, and into the 1970s. Several have been replaced

Reclamation has many transformers that are nearing, or are alr

well past, their anticipated service life. We should expect tran

replacement and failures to increase, due to this age factor. 
Figure 25 – Transformer Diagnostics Flowchart. 
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 

older ones—especially for critical transformers that would cau

loss of generation. It is also very important to consider provid

spares for critical transformers. 

3.2 Transformer Cooling Methods Introduction 

Heat is one of the most common destroyers of transformers. O

at only 8 oC above the transformer rating will cut transformer 

50%. Heat is caused by internal losses, due to loading, high a

temperature, and solar radiation. It is important to understand 

your particular transformers are cooled and how to detect prob

the cooling systems. ANSI and IEEE require the cooling class 

transformer to appear on its nameplate. Cooling classification

short explanations, appear in sections 3.3 and 3.4. The letters 

class designate inside atmosphere and type or types of cooling

some transformers, more than one class of cooling and load ra

indicated. At each step of additional cooling, the rating increa

correspond with increased cooling. Note that the letter “A” in

air, “FA” indicates forced air (fans), “O” indicates oil, “FO” in

forced oil (pumps), “G” indicates some type of gas, and “W” i

there is a water/oil heat exchanger. 
 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 gaug

• If transformer is gas filled (nitrogen [N2]), check pressure 

against data sheets; never allow gas pressure to fall belo

• Check loading and compare with nameplate rating. 

• Functionally test fans and controls for proper operation. 

• Functionally test temperature alarms and annunciator po

• Check area around transformer - clear of debris and part

• Check transformer room for proper ventilation.

After 1 week of 

operation at 

normal loading 

• Perform infrared scan and compare with temperature gau

• Check temperature gauge, if any, and compare with nam

• 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) insp

spots and loose connections. 

• Use vacuum to remove as much dirt as possible. 

• After vacuuming, use low-pressure, dry air (20 to 25 psi) 

remaining dirt. Caution: Make sure air is dry. 

• Check for discolored copper and discolored insulation (in

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 isol

• If windings are found dirty, add filter material to air intake 

• Megger® high side windings to low side windings and bot

side to ground. 

• Do a turns ratio test if electrical problems are found or su

• Check fan blades for cleanliness; remove dirt and dust. 

• Check fans, controls, alarms, and annunciator points. 

• Check pressure gauge on N2 filled transformers; compare 

data sheets; never allow pressure to fall below 1 psi. 

• Check all bolted connections with wrenches or sockets fo

• 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

standard C57.12.01 Section 5.1 [1]. A short explanation of ea

is given below. 
46 

1. Class AA transformers are ventilated and self-cooled. 

means there are ventilation ports located in outside wa

transformer enclosure. There are no fans to force air in

out of the enclosure, with typically no external fins or 

Cooler air enters the lower ports, is heated as it rises pa

windings, and exits the upper ventilation ports. (Altho

not repeated below; it is obvious that, in every cooling 

some heat is also removed by natural circulation of air 

the outside of the enclosure.) 

2. Class AFA transformers are self-cooled (A) and additi

cooled by forced circulation of air (FA). This means th

are ventilation ports for fan inlets and outlets only. (In

usually filtered.) Normally, there are no additional ven

ports for natural air circulation. 

3. Class AA/FA transformers are ventilated and self-cool

as Class AA in item 1). In addition, they have a fan or 

providing additional forced-air cooling. Fans may be w

start automatically when the temperature reaches a pre

value. These transformers generally have a dual load r

one for AA (self-cooling natural air flow) and a larger 

rating for FA (forced air flow). 

4. Class ANV transformers are self-cooled (A), non-vent

(NV) units. The enclosure has no ventilation ports or f

is not sealed to exclude migration of outside air, but th

no provisions to intentionally allow outside air to enter 

exit. Cooling is by natural circulation of air around the 

enclosure. This transformer may have some type of fin

attached outside the enclosure to increase surface area 

additional cooling. 

5. Class GA transformers are sealed with a gas inside (G) 

self-cooled (A). The enclosure is hermetically sealed t

prevent leakage. These transformers typically have a g

such as nitrogen or freon, to provide high dielectric an

good heat removal. Cooling occurs by natural circulat

air around the outside of the enclosure. There are no f
to circulate cooling air; however, there may be fins atta

to the outside to aid in cooling. 

3.3.1 Potential Problems and Remedial Actions for Dry-Typ

Transformer Cooling Systems [15] 

It is important to keep transformer enclosures reasonably clean

also important to keep the area around them clear. Any items 

against the transformer impede heat transfer to cooling air arou

enclosure. As dirt accumulates on cooling surfaces, it become

and more difficult for air around the transformer to remove he

result, over time, the transformer temperature slowly rises unn

reducing service life. 

Transformer rooms and vaults should be ventilated. Portable f

(never water) may be used for additional cooling if necessary. 

rated at about 100 cubic feet per minute (cfm) per kilowatt (kW

transformer loss [6], located near the top of the room to remov

air, will suffice. These rooms/vaults should not be used as sto

When the transformer is new, check the fans and all control

proper operation. After it has been energized and the loading 

temperature are stable, check the temperature with an infrared 

camera and compare loading with the nameplate. Repeat the 

temperature checks after 1 week of operation. 

Once each year under normal load, check transformer temper

with an IR camera [4, 8]. If the temperature rise (above ambie

near or above nameplate rating, check for overloading. Check 

temperature alarm for proper operation. Check enclosures and 

vaults/rooms for dirt accumulation on transformer surfaces an

near or against enclosures. Remove all items near enough to a

circulation. To avoid dust clouds, a vacuum should first be us

remove excess dirt. Low-pressure (20 to 25 psi), dry compres

may be used for cleaning after most dirt has been removed by 

The transformer must be de-energized before this procedure, u
48 

is totally enclosed and there are no exposed energized conduct

Portable generators may be used for lighting. 

After de-energizing the transformer, remove access panels and 

windings for dirt- and heat-discolored insulation and structure 

blems [15]. It is important that dirt not be allowed to accumul

windings because it impedes heat removal and reduces windin

vacuum should be used for the initial winding cleaning, follow

compressed air [8]. Care must be taken to ensure the compres

dry to avoid blowing moisture into windings. Air pressure sho

be greater than 20 to 25 psi to avoid imbedding small particles 

insulation. After cleaning, look for discolored copper and insu

which indicates overheating. If discoloration is found, check f

connections. If there are no loose connections, check the cool

very carefully and check for overloading after the transformer 

re-energized. Look for carbon tracking and cracked, chipped, 

insulators. Look for and repair loose clamps, coil spacers, det

barriers, and corroded or loose connections. 

Check fans for proper operation, including controls, temperatu

switches, and alarms. Clean fan blades and filters if needed. A 

fan blade or filter reduces cooling air flow over the windings a

reduces service life. If ventilation ports do not have filters, the

be fabricated from home furnace filter material. Adding filter

necessary if the windings are dirty upon yearly inspections. 

3.4 Liquid-Immersed Transformers 

Cooling classes of liquid-immersed transformers are covered b

C57.12.00 Section 5.1 [2]. A short explanation of each class f

3.4.1 Liquid-Immersed, Air-Cooled 

There are three classes in this category. 

1. Class OA: Oil-immersed, self-cooled. Transformer w

and core are immersed in some type of oil and are self-
OIL-FILLED TRANSFORMER MAINTENANCE SUMMARY 

Task 

After 1 Month of 

Service Annually 3 to 5 

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. 

Oil level gauges 4.4. 

Pressure relief 4.6. 

Do a DGA. 

Check diaph

bladder for le

a conservat

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. 

Thermomete

and 4.3. 

Oil level gau

Inspect pres

Sudden pres

Buchholz rel

Test alarms, 

pump contro

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 physic

cleaning/ wa

Doble testing

to other liste

See 4.8. 

Doble test transformer 

and bushings. 

Doble test transformer 

and bushings before 

energizing. See 4.8, 

9.3. 

 See 4.8 and 

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. 
50 

 by natural circulation of air around the outside enclosu

or radiators may be attached to the enclosure to aid in c

2. Class OA/FA: Liquid-immersed, self-cooled/forced ai

Same as OA, with the addition of fans. Fans are usual

mounted on radiators. The transformer typically has tw

ratings: one with the fans off (OA) and a larger rating 

fans operating (FA). Fans may be wired to start autom

at a pre-set temperature. 

3. Class OA/FA/FA: Liquid-immersed, self-cooled/forc

air-cooled/forced air-cooled. Same as OA/FA, with an 

additional set of fans. There typically will be three loa

corresponding to each increment of cooling. Increased 

are obtained by increasing cooling air over portions of 

cooling surfaces. Typically, there are radiators attache

tank to aid in cooling. The two groups of fans may be 

start automatically at pre-set levels as temperature incr

There are no oil pumps. Oil flows through the transfor

windings by the natural principle of convection (heat r

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/fo

cooled/forced liquid, and forced air-cooled. Windings 

are immersed in some type of oil. This transformer typ

has radiators attached to the enclosure. The transforme

self-cooling (OA) natural ventilation, forced air-coolin

(fans), and forced oil-cooling (pumps) with additional 

air-cooling (FOA) (more fans). The transformer has th

ratings corresponding to each cooling step. Fans and p

may be wired to start automatically at pre-set levels as 

temperature increases (figure 26). 

2. Class OA/FOA/FOA: Liquid-immersed, self-cooled/

oil, and forced air-cooled/forced oil, and forced air-coo

Cooling controls are arranged to start only part of the o
pumps and part of the fans for the first load rating/temp

increase, and the remaining pumps and fans for the sec

rating increase. The nameplate will show at least three 

ratings. 

3.4.3 Liquid-Immersed, Water-Cooled 

This category has two classes: 

1. Class OW: Transformer coil and core are immersed i

Typically, an oil/water heat exchanger (radiator) is atta

the outside of the tank. Cooling water is pumped throu

heat exchanger, but the oil flows only by natural circul

As oil is heated by the windings, it rises to the top and 

through piping to the radiator. As oil is cooled, it desc

through the radiator and re-enters the transformer tank 

bottom. 

Figure 26 – Typical Oil Flow. 
52 

2. Class OW/A: Transformer coil and core are immersed 

This transformer has two ratings. Cooling for one ratin

is obtained as in item 1. above. The self-cooled rating 

obtained by natural circulation of air over the tank and 

surfaces. 

3.4.4 Liquid-Immersed, Forced Liquid-Cooled 

This category has two classes: 

1. Class FOA: Liquid-immersed, forced liquid-cooled w

forced air-cooled. This transformer normally has only 

rating. The transformer is cooled by pumping oil (forc

through a radiator normally attached to the outside of t

Also, air is forced by fans over the cooling surface. 

2. Class FOW: Liquid-immersed, forced liquid-cooled, 

cooled. This transformer is cooled by an oil/water hea

exchanger normally mounted separately from the tank. 

the transformer oil and the cooling water are pumped (

through the heat exchanger to accomplish cooling. 

3.4.5 Potential Problems and Remedial Actions for Liquid-F

Transformer Cooling Systems 

 3.4.5.1 Leaks – Tanks and radiators may develop oil 

especially at connections. To repair a leak in a radiator core, y

remove the radiator. Small leaks may also develop in headers 

individual pipes. These small leaks possibly may be stopped b

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 transf

has been drained, because a vacuum may cause bubbles to for

oil that can lodge in the winding and cause arcing. Some cont

will stop leaks by forcing epoxy into the leak area under press

This procedure has been successful in many cases and may be 

performed while the transformer is online. When all else fails

may be welded with oil still in the radiator if proper precaution
carefully observed [3, 4]. Welding with oil inside will cause g

form in the oil. Take an oil sample for a dissolved gas analysi

before welding and 24 hours after re-energizing to identify gas 

increases due to welding. If the leak is bad enough, the tank m

to be drained so the leak can be repaired. Treat leaks carefully

ignore them. Oil leaks are serious maintenance and environm

issues and should be corrected. See Power Equipment Bulletin 

further information on leak remediation. 

 3.4.5.2 Cleaning Radiators – Radiators may need to b

cleaned in areas where deposits appear on pipes and headers. 

deposits hamper heat transfer to the cooling air. Finned radiat

be cleaned with compressed air when they become dirty. 

 3.4.5.3 Plugged Radiators – After 1 month of service 

yearly, perform an IR scan and physical inspection of radiator

transformer tanks [4, 8]. Partially plugged radiators will be co

than those performing normally. You may also feel the radiat

by hand. Plugged radiator sections or individual pipes/plenum

noticeably cooler; however, you will not be able to reach all o

Radiators may become plugged with sludge or foreign debris; 

usually occurs in water tubes on the oil/water heat exchanger. 

forget to check the bleed line for two-walled heat exchangers. 

If plugged radiators are discovered, they must be corrected as 

possible. Some radiators are attached to the main tank with fla

and have isolating valves. These may be removed for cleaning 

leak repair without draining oil from the transformer. If radiat

attached directly to the main tank without isolating valves, oil 

drained before cleaning them. If radiators are plugged with slu

transformer probably is sludged up also. In this case, the oil s

reprocessed and the transformer cleaned internally. Competen

contractors should be obtained if this is necessary. 

 3.4.5.4 Sludge Formation – If temperature seems to b

increasing while the transformer is operating under the same l
54 

check the DGA for moisture, oxygen, acid number, and the int

tension (IFT). The combination of oxygen and moisture cause

sludging, which may be revealed by a low IFT number and/or 

number. Sludge will slowly build up on windings and core, an

temperature will increase over time. 

 3.4.5.5 Valve Problems – If your transformer has isola

valves for radiators, check to make sure they are fully open on 

and bottom of the radiators. A broken valve stem may cause t

to be fully or partially closed, but it will appear that the valve 

 3.4.5.6 Mineral Deposits – Don’t even think about spr

water on the radiators or tank to increase cooling, except in th

dire emergency. Minerals in the water will deposit on radiator

water evaporates and are almost impossible to remove. These 

minerals will reduce the efficiency of cooling still further. Us

additional fans to blow air on radiators and/or the transformer 

better alternative [4]. 

 3.4.5.7 Low Oil Level – One IR scan performed on a 

transformer running at higher than normal temperature reveale

the oil level was below the upper radiator inlet pipe, which pre

oil circulation. The oil level indicator was defective and stuck 

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. 

the fans whenever you are around transformers in the switchya

the powerplant. If it is a hot day and transformers are loaded, 

fans should be running. If one fan is stopped and the rest of th

is running, the inactive fan should be repaired. During an insp

the temperature controller should be adjusted to start all the fa

Listen for unusual noises from fan bearings and loose blades a

repair or replace faulty fans. Bad bearings can also be detecte

an IR scan if the fans are running. 
After 1 month of service and yearly, inspect and test the oil pu

Inspect piping and connections for leaks. Override the temper

controller so that the pump starts. Check the oil pump motor c

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 

load current is low, something is causing low oil flow. Carefu

inspect all valves to make sure they are fully open. A valve st

break and leave the valve partially or fully closed, even though 

valve handle indicates the valve is fully open. Pump impellers 

been found loose on the shaft, reducing oil flow. Sludge build

debris in lines can also cause low oil flow. If motor load curre

high, this may indicate impeded pump rotation. Listen for unu

noises. Thrust bearing wear results in the impeller advancing 

housing. An impeller touching the housing makes a rubbing s

which is different from the sound of a failing motor bearing. I

heard, remove the pump motor from the housing and check im

clearance. Replace the thrust bearing if needed, and replace th

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 a

running backwards. Vane type oil-flow meters will indicate fl

this low amount. The best indication of pump running backwa

that sometimes the pump will be very noisy. The motor load c

may also be lower than for full load. If this is suspected, due t

extra noise and higher transformer temperature, the pump shou

checked for proper rotation. Reverse two phase leads if this is 

encountered. [4] 

After 1 month of service and yearly, check the oil flow indicat

has a small paddle which extends into the oil stream and may 

on the suction or discharge side of the pump. A very low flow 

about 5-feet-per-second velocity causes the flag to rotate, whic

indicates normal flow. Flow can be too low, and the indicator 

show flow. If there is no flow, a spring returns the flag to the 
56 

position, and a switch provides an alarm. With control power 

switch, open the pump circuit at the motor starter and make su

correct alarm point activates when the pump stops. Check tha

pointer is in the right position when the pump is off and when 

running. Pointers can stick and fail to provide an alarm when 

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 th

The suction (vacuum) on the intake side of the pump can pull 

through gaskets that are not tight. Pump suction has also been 

to pull air through packing around valve stems in the suction s

piping. This can result in dangerous bubbles in the transforme

may cause the gas detector or Buchholz relay to operate. Diss

gas analysis will show a big increase in oxygen and nitrogen c

[4]. High oxygen and nitrogen content can also be caused by 

leaks elsewhere. 

After 1 month of service and yearly, inspect water-oil heat exc

Test and inspect the pumps, as mentioned above. Look for an

leaks in piping and heat exchanger body. Examine the latest d

gas analysis results for dissolved moisture and free water. If f

water is present and there are no gasket leaks, the water portio

water-oil heat exchanger must be pressure tested. A leak may 

developed, allowing water to migrate into the transformer oil, 

can destroy the transformer. If the heat exchanger piping is do

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 thoroug

routine inspections. These inspections must take place in addit

normal daily/weekly data gathering trips to check oil levels an
temperatures. Some monitoring may be done remotely using 

supervisory control and data acquisition (SCADA) systems, bu

can never substitute for thorough inspections by competent 

maintenance or operations people. 

After 1 month of service, and once each year, make an ind

inspection of oil-filled transformers. Before beginning, care

inspect the temperature and oil level data sheets. If temperatu

pressure, or oil level gauges never change, even with seasonal 

temperature and loading changes, something is wrong. The ga

be stuck, or data sheets may have been filled in incorrectly. E

the DGAs for evidence of leaks or other problems. 

4.1 Transformer Tank 

Check for excessive corrosion and oil leaks. Pay special atten

flanges and gaskets (bushings, valves, and radiators) and the lo

section of the main tank. Report oil leaks to maintenance, and 

special attention to the oil level indicator if leaks are found. S

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 

indicators with liquid-filled bulb sensors. The bulb is normall

a thermometer well, which penetrates the tank wall into the oi

top of the tank. As oil temperature increases in the bulb, liqui

expands, which expands the spiral tube. The tube is attached t

pointer that indicates temperature. These pointers may also ha

electrical contacts to trigger alarms and start cooling fans as 

temperature increases. An extra pointer, normally red, indicat

maximum temperature since the last time the indicator was res

This red pointer rises with the main pointer but will not decrea

unless manually reset; thus, it always indicates the highest 
58 

temperature reached since it was reset. See the instruction ma

on your specific transformer for details. 

4.3 Winding Temperature Thermometers 

These devices are supposed to indicate the hottest spot in the w

based on the manufacturer’s heat run tests. At best, this devic

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 

misleading. They are only winding hottest-spot simulators, w

not very accurate. Normally, there is no temperature sensor em

in the winding hot spot. At best, they provide only a rough 

approximation of hot spot winding temperature and should no

relied on for accuracy. They can be used to turn on additional 

or activate alarms as the top oil thermometers do. 

Winding temperature thermometers work the same way as the 

thermometer (discussed in section 4.2), except that the bulb is 

separate thermometer well near the top of the tank. A wire-typ

coil is either inserted into, or wrapped around, the thermomete

which surrounds the temperature sensitive bulb. In some trans

a current transformer (CT) is around one of the three winding 

and provides current directly to the heater coil in proportion to 

winding current. In other transformers, the CT supplies curren

auto-transformer that supplies current to the heater coil. The h

warms the bulb, and the dial indicates a temperature, but it is n

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 calibr

resistors in the control cabinet. These devices normally canno

field calibrated or tested, other than testing the thermometer, a

mentioned. The calibration resistors can be adjusted in the fie

the manufacturer provides calibration curves for the transform

In practice, most winding temperature indicators are out of cal
and their readings are meaningless. These temperature indicat

should not be relied upon for loading operations or maintenan

decisions. 

Fiber optic temperature sensors can be imbedded directly into 

winding as the transformer is being built; these sensors are mu

accurate. This system is available as an option on new transfo

an increased cost, which may be worthwhile, since the true wi

“hottest-spot” temperature is critical when higher loading is re

Thermometers can be removed without lowering the transform

they are in a thermometer well. Check your transformer instru

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 no

obvious defect, but it can cause the dial pointer to lock in one 

If this defect is found, the whole gauge must be returned to the 

for repair or replacement; it cannot be repaired in the field. Lo

leak in the tubing system; the gauge reading will be very low a

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 

accurate mercury thermometer in an oil bath. Do not allow eit

thermometer to touch the side or bottom of the container. Hea

oil on a hotplate, while stirring, and compare the two thermom

while the temperature increases. If a magnetic stirring/heating 

is available, it is more effective than hand stirring. Pay particu

attention to the upper temperature range at which your transfo

normally operate (50 oC to 80 oC). An ohmmeter should also 

used to check switch operations. If either dial indicator is mor

5 oC different than the mercury thermometer, it should be repl

with a spare. A number of spares should be kept, based on the 

quantity of transformers at the plant. Oil bath test kits are ava

from the Qualitrol Company. After calling for Qualitrol autho
60 

(716-586-1515), you can ship defective dial thermometers for 

and calibration to: Qualitrol Company, 1387 Fairport Road, F

New York 14450. 

The alarms and other functions should also be tested to see if t

correct annunciator points activate, pumps/fans operate, etc. 

If the temperature gauge cannot be replaced or sent to the fact

repair, place a temperature correction factor on your data form 

to the dial reading, so that the correct temperature will be reco

Also, lower the alarm and pump-turn-on settings by this same 

correction factor. Since these are pressure-filled systems, the 

will typically read low if it is out of calibration. Field testing h

shown some of these gauges reading 15 oC to 20 oC lower than 

temperature. This is hazardous for transformers because it wi

them to continuously run hotter than intended, due to delayed 

and cooling activation. If thermometers are not tested and erro

corrected, transformer service life may be shortened or premat

failure may occur. 

4.3.1 Temperature Indicators Online 

Check all temperature indicators while the transformer is onlin

winding temperature indicator should read approximately 15 d

above the top oil temperature. If this is not the case, one or bo

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 indica

Reset all maximum indicator hands on the temperature indicat

devices after recording the old maximum temperature reading

High temperature may mean overloading, cooling problems, o

problems with windings, core, or connections. 

4.3.2 Temperature Indicators Offline 

When the transformer is offline and has cooled to ambient tem

ture, check the top oil and winding temperature indicators; bot
read the same. If not, one or both temperature indicators are m

functioning. Check the calibration according to the proper pro

Also, compare these readings with the indicated temperature o

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 t

level indicators. These are float operated, with the float mech

magnetically coupled through the tank wall to the dial indicato

level increases, the float rotates a magnet inside the tank. Out

tank, another magnet follows (rotates), which moves the point

center of the dial is normally marked with a temperature of 25 

(77 oF). High and low level points are also marked to follow l

changes as the oil expands and contracts with temperature cha

The proper way to determine accurate oil level is to first look 

oil temperature indicator. After determining the temperature, 

the level gauge. The pointer should be at a reasonable level 

corresponding to the top oil temperature. Calibrate or replace 

conservator oil level indicator if needed, but only after checkin

top oil temperature indicator as shown in the above section. If 

transformer is fully loaded, the top oil temperature will be hig

the level indicator should be near the high mark. If the transfo

de-energized and the top oil temperature is near 25 oC, the oil 

pointer should be at or near 25 oC. See figure 27. Reference a

IEEE 62-1995TM [20], section 6.6.2. 

To check the level indicator, remove the outside mechanism fo

without lowering transformer oil. After removing the gauge, h

magnet on the back of the dial and rotate the magnet; the dial 

should also rotate. If it fails to respond or if it drags or sticks, 

it. As mentioned above, defective units can be sent to the fact

repair. 

There may also be electrical switches for alarms and, possibly

tripping off the transformer when the tank level falls. These s
62 

should be checked with an ohmmeter for proper operation. Th

alarm/tripping circuits should also be tested to see if the correc

annunciator points and relays respond. See the transformer in

book for information on your specific indicator. 

If oil has had to be lowered in the 

transformer or conservator for oth

reasons (e.g., inspections), check 

level float mechanism (figure 28)

the float mechanism by hand to c

free movement. 

Check the float visually to make 

secure to the arm and to ensure th

arm is in the proper shape. Some 

are formed (not straight). 

4.5 Pressure Relief Devices 

These devices are the transformers’ last line of defense agains

excessive internal pressure. In the event of a fault or short circ

resultant arc instantly vaporizes surrounding oil, causing a rap

buildup of gaseous pressure. If the pressure relief device do

operate properly and pressure is not sufficiently relieved w

Figure 28 – Conservator 

Oil Level. 

Figure 27 – Oil Level Indicator. 
few milliseconds, a catastrophic tank rupture can result, sp

flaming oil over a wide area. Two types of pressure relief de

are discussed below. Consult your transformer’s instruction m

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 th

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 sprin

held in compression by the cover and press on a disc which se

opening in the tank top. If pressure in the tank exceeds operat

pressure, the disc moves upward and relieves pressure. As pre

decreases, the springs re-close the valve. After operating, this 

leaves a brightly colored rod (bright yellow for oil, blue for sil

exposed approximately 2 inches above the top. This rod is eas

upon inspection, although it is not always visible from floor le

rod may be reset by pressing on the top until it is again recesse

the device. The switch must also be manually reset. A relief d

shown in the open position in figure 29. Figure 30 also shows 

a pressure relief device with the yellow indicating arm. 
64 

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. 
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

internal fault, inspect pressure devices to see if they have oper

This must be done from a high-lift bucket if the transformer is 

energized. Look at each pressure relief device to see if the yel

(or blue) button is visible. If the device has operated, about 2 

of the colored rod will be visible. Each year, test the alarm cir

operating the switch by hand and making sure the correct annu

point is activated. If the relief device operates during operatio

re-energize the transformer; Doble and other testing may be re

before re-energizing, and an oil sample should be sent for anal

Every 3 to 5 years, when doing other maintenance or testing, i

transformer has a conservator, examine the top of the transform

around the pressure relief device. If oil is visible, the device i

leaking, either around the tank gasket or relief diaphragm. If t

device is 30 years old, replace the whole unit. A nitrogen blan

transformer will use a lot more nitrogen if the relief device is l

they should be tested as described below. 

A test stand with a pressure gauge may be fabricated to test th

pressure relief function. Current cost of a pressure relief devic

is about $600, so testing instead of replacement may be pruden

Have a spare pressure relief device on hand so that the tank wi

not have to be left open. If the tank top or pressure relief devi

has gasket limiting grooves, always use a nitrile replacement g

if there are no grooves, use a cork-nitrile gasket. Although rel

devices themselves do not leak often, the gasket may leak. 
66 

4.5.2 Older Pressure Relief Devices 

Older pressure relief devices have a diaphragm and a relief pin 

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 

operating pressure, normally appears on top of the pin. Check 

specific transformer instruction manual for proper catalog num

Do not assume you have the right parts or that correct parts ha

previously installed—look it up. If the operating pressure is to

a catastrophic tank failure could result. 

On older units, a shaft rotates, operates alarm/trip switches, an

a small red flag when the unit releases pressure. If units have 

painted or are more than 30 years old, they should be replaced 

new model as soon as it is possible to have a transformer outag

Once each year, and as soon as possible after a through-fault o

internal fault, examine the indicator flag to see if the device ha

operated. The flags must be examined from a high-lift bucket 

transformer is energized. A clearance must be obtained to test

or reset the device. See the instruction manual for your specif

transformer. Test alarm/trip circuits by operating the switch b

Check to make sure the correct annunciator point activates. 

Every 3 to 5 years, when doing other maintenance or testing, e

the top of the transformer tank around the pressure relief devic

transformer has a conservator and oil is visible, the device is le

either around the tank gasket or relief diaphragm. The gasket 

device must be replaced. Before ordering, make sure that the 
device will fit the same tank opening. Most devices are made 

Qualitrol Company; contact the manufacturer to obtain a corre

replacement. 

4.6 Sudden Pressure Relay 

Internal arcing in an oil-filled power transformer can instantly 

vaporize surrounding oil, generating gas pressures that can cau

catastrophic failure, rupture the tank, and spread flaming oil ov

large area. This can damage or destroy other equipment, in ad

the transformer, and present extreme hazards to workers. 

The relay is designed to detect a sudden pressure increase cau

arcing. This relay is very sensitive and will operate if the pres

rises even slightly. If a very small pressure change occurs cau

small electrical fault inside the tank, this relay will alarm. The 

set to operate before the pressure relief device. The control ci

should de-energize the transformer and provide an alarm. The 

will ignore normal pressure changes such as oil-pump surges, 

temperature changes, etc. 

Modern sudden pressure relays consist of three bellows (see fi

with silicone sealed inside. Changes in pressure in the transfo

deflect the main sensing bellows. Silicone inside acts on two 

bellows arranged like a balance beam (one on each side). One 

senses pressure changes through a small orifice. The opening 

automatically changed by a bimetallic strip to adjust for norma

temperature changes of the oil. The orifice delays pressure ch

this bellows. The other bellows responds to immediate pressu

changes and is affected much more quickly. Pressure differen

the balance beam and activates the switch. This type of relay 

automatically resets when the two bellows again reach pressur

equilibrium. If this relay operates, do not re-energize the trans

until you have determined the exact cause and corrected the pr
68 

Old style sudden pressure relays have only one bellows. A su

excessive pressure within the transformer tank exerts pressure 

on the bellows, which moves a spring-loaded operating pin. T

operates a switch that provides alarm and breaker trip. After t

has operated, the cap must be removed and the switch must be 

normal by depressing the reset button. 

Once every 3 to 5 years, the sudden pressure relay should be 

according to manufacturer’s instructions. Generally, only a sq

bulb and pressure gauge (5 psi) are required. Disconnect the t

circuit and use an ohmmeter to test for relay operation. Test th

circuit and verify that the correct alarm point is activated. Use 

ohmmeter to verify the trip signal is activated or, if possible, a

only control voltage to the breaker and make sure the tripping 

operates. Consult the manufacturer’s manual for your specific 

transformer’s detailed instructions. 

Figure 31 – Sudden Pressure Relay, Section. 
Figure 32 – Photogra

Sudden Pressure Re

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 cham

with floats and relays arranged vertically—one over the other. 

eddy currents, local overheating, or partial discharges occur w

tank, bubbles of resultant gas rise to the top of the tank. These 

rise through the pipe between the tank and the conservator. A

bubbles migrate along the pipe, they enter the Buchholz relay 

into the top chamber. As gas builds up inside the chamber, it 

the oil, which decreases the oil level. The top float descends w

oil level until it passes a magnetic switch, which activates an a

The bottom float and relay cannot be activated by additional g

buildup. The float is located slightly below the top of the pipe 

once the top chamber is filled, additional gas goes into the pip

continues up to the conservator. Typically, inspection window

provided so that the amount of gas and relay operation may be 

during testing. If the oil level falls low enough (conservator e

the bottom float activates the switch contacts in the bottom ch
70 

These contacts are typically connected to cause the transforme

This relay also serves a third function, similar to the sudden pr

relay. A magnetically held paddle attached to the bottom floa

positioned in the oil-flow stream between the conservator and 

transformer tank. Normal flows resulting from temperature ch

Figure 34 – Photograph of a Buchholz Relay. 

Figure 33 – Buchholz Relay, Section. 
are small and bypass below the paddle. If a fault occurs in the 

transformer, a pressure wave (surge) is created in the oil. This 

travels through the pipe and displaces the paddle. The paddle 

the same magnetic switch as the bottom float mentioned above

trips the transformer. The flow rate at which the paddle activa

relay is normally adjustable. See your specific transformer’s 

instruction manual for details. 

Once every 3 to 5 years, while the transformer is de-energize

functionally test the Buchhholz relay by pumping a small amo

air into the top chamber with a squeeze-bulb hand pump. Wat

float operation through the window (center in figure 32). Che

make sure the correct alarm point has been activated. Open th

valve and vent air from the chamber. The bottom float and sw

cannot be tested with air pressure. On some relays, a rod is pr

so that you can test both bottom and top sections by pushing th

down until the trip points are activated. If possible, verify that 

breaker will trip with this operation. A volt-ohmmeter may al

used to check the switches. If these contacts activate during o

it means that the oil level is very low, a pressure wave has acti

(bottom contacts), or the transformer is gassing (top contacts). 

relay operates, do not re-energize the transformer until you ha

determined the exact cause. 

If a small amount of gas is found in this relay when the transfo

new (a few months after startup), it is probably just air that ha

trapped in the transformer structure and is now escaping; there 

cause for concern. 

If the transformer has been online for some time (service aged

gas is found in the Buchholz, oil samples must be sent to the la

DGA and extensive testing. Consult with the manufacturer an

transformer experts. A definite cause of the gas bubbles must 

determined and corrected before re-energization of the transfo
72 

4.8 Transformer Bushings: Testing and Maintenanc

High-Voltage Bushings 

When bushings are new, they should be Doble tested as an acc

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 porc

cracks and/or contamination (requires binoculars). There is no 

“perfect insulator”; a small amount of leakage current always 

This current “leaks” through and along the bushing surface fro

high-voltage conductor to ground. If the bushing is damaged 

heavily contaminated, leakage current becomes excessive, and 

evidence may appear as carbon tracking (treeing) on the bushi

surface. Flashovers may occur if the bushings are not cleaned 

periodically. 

Look carefully for oil leaks. Check the bushing oil level by vi

the oil-sight glass or the oil level gauge. When the bushing ha

gauge with a pointer, look carefully, because the oil level shou

slightly with temperature changes. If the pointer never change

with wide ambient temperature and load changes, the gauge sh

checked at the next outage. A stuck gauge pointer coupled wi

small oil leak can cause explosive failure of a bushing, damag

transformer and other switchyard equipment. A costly extend

outage is the result. 
If the oil level is low and there is an external oil leak, check th

for proper torque and the gasket for proper compression. If to

compression are correct, the bushing must be replaced with a s

Follow instructions in the transformer manual carefully. It is v

important that the correct type of gasket be installed and the co

compression be applied. A leaky gasket is probably also leaki

and air into the transformer, so check the most recent transform

DGA for high moisture and oxygen. 

If the oil level is low and there is no visible external leak, ther

an internal leak around the lower seal into the transformer tank

possible, re-fill the bushing with the same oil and carefully mo

level and the volume it takes to fill the bushing to the proper le

it takes more than 1 quart of oil, make plans to replace the bus

The bushing must be sent to the factory for repair, or it must b

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 m

entering through leaky gaskets, cracks, or seals. Internal mois

be detected by Doble testing. See FIST 3-2 [10] and Doble Bu

Field Test Guide [9] for troubles and corrective actions. Intern
74 

moisture causes deterioration of the insulation of the bushing a

result in explosive failure, causing extensive transformer and o

equipment damage, as well as hazards to workers. 

After 1 month of service and yearly, examine the bushings w

IR camera [4, 8]; if one phase shows a markedly higher tempe

there is probably a bad connection. The connection at the top 

usually the poor one; however, a bad connection inside the tra

tank will usually show a higher temperature at the top as well. 

addition, a bad connection inside the transformer will usually 

metal gases (ethane and ethylene) in the DGA. 

Once every 3 to 5 years, perform a close physical inspection 

cleaning of the bushings [10]. Check carefully for leaks, crack

carbon tracking. This inspection will be required more often i

atmospheres where salts and dust deposits appear on the bushi

conditions that produce deposits, a light application of Dow C

grease DC-5 or GE Insulgel will help reduce risk of external f

The disadvantage of this treatment is that a grease buildup ma

In high humidity and wet areas, a better choice may be a high-

silicone paste wax applied to the porcelain, which will reduce 

of flashover. A spray-on wax containing silicone, such as Tur

brand, has been found to be very useful for cleaning and waxin

operation, providing the deposits are not too hard. Wax will c

water to form beads, rather than a continuous sheet, which red

flashover risk. Cleaning may involve just spraying with Turtle 

and wiping with a soft cloth. A lime removal product, such as 

Away,” also may be useful. More stubborn contaminants may 

solvents, steel wool, and brushes. A high pressure water strea

be required to remove salt and other water soluble deposits. 

Limestone powder blasting with dry air will safely remove me

oxides, chemicals, salt-cake, and almost any hard contaminant

materials, such as potter’s clay, walnut or pecan shells, or crus

coconut shells, are also used for hard contaminants. Carbon d

(CO2) pellet blasting is more expensive but virtually eliminate

cleanup because it evaporates. Ground-up corn-cob blasting w
remove soft pollutants, such as old coatings of built-up grease

competent, experienced contractor should be employed, and a 

thorough, written job hazard analysis (JHA) should be perform

when any of these treatments are used. 

Corona (air ionization) may be visible at the tops of bushings 

twilight or night, especially during periods of rain, mist, fog, o

humidity. At the top, corona is considered normal; however, a

bushing becomes more and more contaminated, corona will cr

lower and lower. If the bushing is not cleaned, flashover will 

when corona nears the grounded transformer top. If corona se

be lower than the top of the bushing, inspect, Doble test, and c

bushing as quickly as possible. If flashover occurs (phase to g

fault), it could destroy the bushing and cause an extended outa

Line-to-line faults also can occur if all the bushings are contam

and flashover occurs. A corona scope may be used to view an

photograph low levels of corona indoors under normal illumin

and outdoors at twilight or night. High levels of corona may b

viewed outdoors in the daytime if a dark background is availab

as trees, canyon walls, buildings, etc. The corona scope desig

primarily for indoor and night use; it cannot be used with blue 

cloudy sky background. This technology is available at the Te

Service Center (TSC), D-8450. 

Once every 3 to 5 years, depending on the atmosphere and 

service conditions, the bushings should be Doble tested. Refe

Doble M-4000 test set instructions, Doble Bushing Field Test 

Guide [9], FIST 3-2 [10], and the manufacturer’s instructions 

proper values and test procedures. Bushings should be cleane

Doble testing. Contamination on the insulating surface will ca

results to be inaccurate. Testing may also be done before and 

cleaning to check methods of cleaning. As the bushings age a

to deteriorate, reduce the testing interval to 1 year. Keep accu

records of results so that replacements can be ordered in advan

before you have to remove bushings from service. 
76 

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 

contaminating oil and cellulose insulation. Sealing systems ar

designed to prevent oil inside the transformer from coming int

contact with air. Air contains moisture, which causes sludging 

abundant supply of oxygen. Oxygen, in combination with mo

causes greatly accelerated deterioration of the cellulose. This 

moisture combination will greatly reduce service life of the 

transformer. 

Sealing systems on many existing Reclamation power transfor

of the inert gas (nitrogen) pressure design; however, Reclamat

many other designs. Current practice is to buy only conservat

designs with bladders for transformer voltages 115 kV and abo

capacities above 10 MVA. Below these values, we buy only i

pressure system transformers, as depicted in figure 36 (page 7
Some of the sealing systems are explained below. There may 

variations of each design, and not every design is discussed. E

sealing system types are discussed first, followed by more mo

types. 

4.9.1 Sealing Systems Types 

 4.9.1.1 Free Breathing – Sealing systems have progre

from early designs of “free breathing” tanks, in which an air sp

top of the oil is vented to atmosphere through a breather pipe. 

pipe typically is screened to keep out insects and rodents and t

down to prevent rain from entering. Breathing is caused by ex

and contraction of the oil as temperature changes. These earli

designs do not use an air dryer, and condensation from moistu

on inside walls and tank top. Moisture, oxygen, and nitrogen 

also dissolve directly into oil from the air. This is not the best 

As mentioned before, a combination of oxygen and moisture 

accelerates deterioration of cellulose insulation. Moisture also 

decreases dielectric strength, which destroys insulating quality 

oil and causes sludge to form. If you have one or more of thes

design transformers, it is recommended that a desiccant type a

be added to the breather pipe. 

4.9.1.2 Sealed or Pressurized Breathing – This design 

similar to the free breathing type with the addition of a pressur

vacuum bleeder valve. When the transformer was installed, 

pressurized dry air or nitrogen was placed on top of the oil. T

bleeder valve is designed to hold pressure inside to approxima

or minus 5 psi (figure 35). The same problems with moisture 

oxygen occur as previously described. However, these proble

not as severe because “breathing” is limited by the bleeder val

or nitrogen (N2) is exhausted to the outside atmosphere when a 

positive pressure greater than 5 psi occurs inside the tank. Thi

process does not add moisture and oxygen to the tank. Howev

cooling, the oil contracts and, if pressure falls 5 psi below the 

atmosphere, the valve allows outside air into the tank, which p

moisture and oxygen. 
78 

Once each year, check the pressure gauge against the weekly 

sheets; if the pressure never varies with seasonal temperature c

the gauge is defective. Add nitrogen if the pressure falls below 

to keep moisture laden air from being pulled in. Add enough N

bring the pressure to between 2 and 4 psi. 

 4.9.1.3 Pressurized Inert Gas Sealed System – This sy

keeps space above the oil pressurized with a dry inert gas, nor

nitrogen (figure 36). This design prevents air and moisture fro

coming into contact with insulating oil. Pressure is maintaine

nitrogen gas bottle with the pressure regulated normally betwe

0.5 and 5 psi. Pressure gauges are provided in the nitrogen cu

both high and low pressures (figure 37). A pressure/vacuum g

normally connected to read low pressure gas inside the tank. T

gauge may be located on the transformer and normally has hig

pressure and low-pressure alarm contacts. See section 4.9.2, w

follows. 

If the transformer has a nitrogen blanket, check the pressure g

proper pressure. Look at the operators recording of pressures 

pressure gauge. If this does not change, the gauge is probably 

Figure 35 – Pressurized Breathing Transformer. 
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 t

proper quality (see Power Equipment Bulletin No. 5 [40]). Ch

any increased usage of nitrogen which indicates a leak. Small

Figure 36 – Pressurized Inert Gas Transformer. 
80 

transformers such as station service or smaller generator-step-

transformers may not have nitrogen bottles attached to replace 

lost nitrogen. Be especially watchful of the pressure gauge an

operator’s records of pressures with these. The pressure gaug

defective for years, and no one will notice. The gauge will rea

the same and will not vary much over winter and summer or n

day. Meanwhile, a nitrogen leak can develop, and all the N2 w

lost. This allows air with oxygen and moisture to enter and de

the oil and insulation. Watch for increased oxygen and moistu

DGA. An ultrasonic and sonic leak detection instrument (P-2

used for locating N2 leaks. Soap bubbles also may be used. 

 Front View Side View

Figure 37 – Gas Pressure Control Components. 
4.9.2 Gas Pressure Control Components 

After 1 month of service and yearly, inspect the gas pressure c

components. There is normally an adjustable, three-element, p

control system for inert gas, which maintains a pressure range 

5 psi in the transformer tank. There is also a bleeder valve tha

exhausts gas to atmosphere when pressure exceeds relief press

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 gau

attached between the nitrogen cylinder and high-pressure regu

indicates cylinder pressure. When the cylinder is full, the gau

read approximately 2,400 psi. Normally, the gauge will be eq

with a low-pressure alarm that activates when the cylinder is g

low (around 500 psi). However, gas will still be supplied, and 

regulating equipment will continue to function until the cylind

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 connec

the cylinder, and the output of the first stage is connected inter

the input of the second stage. This holds output pressure of th

stage constant. The first stage output is adjustable by a hand-o

lever and can deliver a maximum pressure equal to the pressur

cylinder (2,400 psi when full) down to zero. The second stage 

is varied by turning the adjusting screw, normally adjusted to 

approximately 10 psi to the input of the low-pressure regulator
82 

4.9.2.3 Low-Pressure Regulator – The low-pressure r

is the third stage and controls pressure and flow to the gas spa

transformer. The input of this regulator is connected to the ou

the second stage (approximately 10 psi). This regulator is typ

at the factory to supply gas to the transformer at a pressure of 

approximately 0.5 psi, and it needs no adjustment. If a differe

pressure is required, the regulator can be adjusted by varying s

tension on the valve diaphragm. Pressure is set at this low val

because major pressure changes inside the transformer result f

expansion and contraction of oil. The purpose of this gas feed 

make up for small leaks in the tank gaskets and elsewhere so t

cannot enter. Typically, a spring-loaded bleeder for high-pres

relief is built into the regulator and is set at the factory to relie

pressures in excess of 8 psi. The valve will close when pressu

below the setting, preventing further loss of gas. 

4.9.2.4 Bypass Valve Assembly – The bypass valve as

opens a bypass line around the low-pressure regulator and allo

second stage of the high-pressure regulator to furnish gas direc

the transformer. The purpose of this assembly is to allow muc

filling/purging of the gas space during initial installation or wh

transformer tank needs to be refilled after being opened for ins

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 bott

the pressure regulating system between the low-pressure regul

shutoff valve C. The sump collects oil and/or moisture that m

condensed in the low-pressure fill line. The drain plug at the b

of the sump should be removed before the system is put into o

as well as once each year during operation, to drain any residu
the line. This sump and line will be at the same pressure as the 

space in the top of the transformer. The sump should always b

safe pressure (less than 10 psi) so the plug can be removed to 

line to purge a few seconds and blow out the oil. However, al

look at the gas space pressure gauge on the transformer or the 

pressure gauge in the nitrogen cabinet, just to be sure, before r

the drain plug. 

4.9.2.6 Shutoff Valves – The shutoff valves are locate

the top of the cabinet for the purpose of isolating the transform

for shipping or maintenance. These valves are normally of do

construction and should be fully opened against the stop to pre

leakage around the stem. A shutoff valve is also provided for 

purpose of shutting off the nitrogen flow to the transformer tan

shutoff valve must be closed prior to changing cylinders to kee

gas in the transformer tank from bleeding off. 

4.9.2.7 Sampling and Purge Valve – The sampling an

valve is normally located in the upper right of the nitrogen cab

This valve is typically equipped with a hose fitting; the other s

connected directly to the transformer gas space by copper tubi

valve is opened while purging the gas space during a new inst

or maintenance refill, and it provides a path to exhaust air as th

space is filled with nitrogen. This valve is also opened when a 

sample is taken from the gas space for analysis. When taking 

samples, the line must be sufficiently purged so that the sampl

from gas above the transformer oil and not just gas in the line. 

valve must be tightly closed during normal operation to preven

leakage. 

4.9.2.8 Free Breathing Conservator – This design ad

expansion tank (conservator) above the transformer so that the 

tank may be completely filled with oil (figure 38). Oil expans

air exchange with the atmosphere (breathing) occur away from 

in the transformer. This design reduces oxygen and moisture 
84 

contamination because only a small portion of oil is exchange

between the main tank and conservator. An oil/air interface st

in the conservator, exposing the oil to air. Eventually, oil in th

conservator is exchanged with oil in the main tank, and oxyge

other contaminants gain access to the insulation. 

If you have transformers of this design, it is recommended tha

bladder or diaphragm-type conservator be installed (described 

or retrofitted to the original conservator. In addition, a desicca

air dryer should also be installed. 

4.9.2.9 Conservator with Bladder or Diaphragm Des

conservator with bladder or diaphragm (figure 39) is similar to 

design in figure 38 with an added air bladder (balloon) or flat 

diaphragm in the conservator. The bladder or diaphragm expa

contracts with the oil and isolates it from the atmosphere. The 

of the bladder or top of the diaphragm is open to atmospheric 

through a desiccant air dryer. As oil expands and contracts an

Figure 38 – Free Breathing Conservator. 
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 

3⁄4- 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. 
86 

atmospheric pressure changes, the bladder or diaphragm “brea

in and out. This keeps air and transformer oil essentially at 

atmospheric pressure. The oil level gauge on the conservator 

is magnetic, like those mentioned earlier, except the float is po

near the center of the underside of the bladder. With a diaphra

level indicator arm rides on top of the diaphragm. Examine th

dryer periodically and change the desiccant when approximate

third of the material changes color. 

 4.9.2.9.1 Conservator Inspection – If atmosphe

gases (nitrogen, oxygen, carbon dioxide) and, perhaps, moistu

increase suddenly in the DGA, a leak may have developed in t

conservator diaphragm or bladder. With the transformer offlin

under clearance, open the inspection port on top of the conserv

look inside with a flashlight. If there is a leak, oil will be visib

top of the diaphragm or inside the bladder. Re-close the conse

and replace the bladder or diaphragm at the first opportunity b

scheduling an outage. If there is no gas inside the Buchholz re

transformer may be re-energized after bleeding the air out of t

bladder failure relay. A DGA should be taken immediately to 

for oxygen (O2), N2, and moisture. However, the transformer 

operated until a new bladder is installed, keeping a close eye o

DGAs. It is recommended that DGAs be performed every 3 m

until the new bladder is installed. After the bladder installatio

may need to be de-gassed if O2 exceeds 10,000 parts per millio

(ppm). Also, carefully check the moisture level in the DGAs t

it is below recommended levels for the particular transformer 

Check the desiccant in the breather often; never let more than 

thirds of the desiccant become discolored before renewing it. 

efforts must be made to keep the oxygen level below 2,000 pp

moisture as low as possible. 

 4.9.2.9.2 Conservator Breather Inspection – C

dehydrating (desiccant) breather for proper oil level if it is an 

type unit. Check the color of the desiccant and replace it when 

approximately one-third remains with the proper color. See fi
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 indicator line and refill, if necessary. 

Note the 11⁄4-inch pipe going 

from the breather to the conservator. Small tubing (1⁄2 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 

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 Bre

Figure 41 – Photograph of a 

Failure Relay. 
88 

detecting air bubbles in the oil. The relay will also serve as a 

backup to the Buchholz relay. If the Buchholz relay overfills 

and fails to activate an alarm or shut down, gas will bypass the 

Buchholz and migrate up into the conservator, eventually to th

bladder failure relay. Of course, these gases should also show 

the DGA. However, DGAs are normally taken only once per 

year, and a problem may not be discovered before these alarm

are activated. Figure 42 shows a modern relay. Check your 

transformer instruction manual for specifics because designs 

Figure 42 – Bladder Failure Relay. 
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 

relay will detect it. As air rises and enters the relay, oil is disp

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 con

float switch. 

Every 3 to 5 years usually during Doble testing or if the bladd

alarm is activated (if the conservator has a diaphragm), place t

transformer under clearance and check the Buchholz relay for 

mentioned in section 4.7. Open the conservator inspection por

look inside with a flashlight. 

Bleed the air/gas from the conservator using the bleed valve o

the conservator. If the transformer is new and has been in serv

only a few months, the problem most likely is air escaping fro

structure. With the transformer under clearance, open the insp

port on top of the conservator and look inside the bladder with 

flashlight. If oil is found inside the bladder, it has developed 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. 
90 

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 b

the main transformer tank and the conservator tank. Inert gas 

(normally nitrogen) is placed above oil in both the main and m

tanks. Only oil in the top conservator tank is exposed to air. A 

desiccant air dryer may, or may not, be included on the breath

oil in the main tank expands and contracts with temperature, g

pressure varies above the oil in both (figure 43). 

Changes in gas pressure cause oil to go back and forth betwee

middle tank and the conservator. Air containing oxygen and m

is not in contact with oil in the main transformer tank. Oxyge

moisture are absorbed by oil in the conservator tank and interc

with oil in the middle tank. However, since gas in the middle 

interchanges with gas in the main tank, small amounts of oxyg

moisture carried by gas still make their way into the transform
With this arrangement, the conservator does not have to be loc

above the main tank, which reduces the overall height. If you 

one or more of these type transformers without desiccant air d

they should be installed. 

5. Gaskets 

Gaskets have several important jobs in sealing systems [7]. A 

must create a seal and hold it over a long period of time. It mu

impervious and not contaminate the insulating fluid or gas abo

fluid. It should be easily removed and replaced. A gasket mu

elastic enough to flow into imperfections on the sealing surfac

must withstand high and low temperatures and remain resilien

to hold the seal, even with joint movement from expansion, 

contraction, and vibration. It must be resilient enough to avoid 

a “set,” even when exposed for a long time to pressure applied 

Figure 43 – Auxiliary Sealing System. 
92 

bolt torque and temperature changes. The gasket must have su

strength to resist crushing under applied load and resist blowo

system pressure or vacuum. It must maintain its integrity whi

handled or installed. If a gasket fails to meet any of these crite

leak will result. Gasket leaks result from improper torque, cho

the wrong type of gasket material, or choosing the wrong size 

Improper sealing surface preparation or the gasket taking a “se

(becoming hard and losing its resilience and elasticity) will als

a leak. Usually, gaskets take a set as a result of temperature ex

and age. 

5.1 Sealing (Mating) Surface Preparation 

Clean the metal surface thoroughly. Remove all moisture, oil 

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 

coated with Loctite Master gasket No. 518. This material will 

after you bolt up the gasket, so additional glue is not necessary

temperature is 50 oF or more, you can bolt up the gasket imme

This material comes in a kit (part No. 22424) with primer, a tu

material, and instructions. If these instructions are followed, t

will last many years, and the gasket will be easy to remove lat

necessary. If the temperature is under 50 oF, wait about 1⁄2 to 1 

after applying the material to surfaces before bolting. If you a

cork-nitrile or cork-neoprene, you can also seal gasket surface

(including the edge of the gasket) with this same material. Lo

makes other sealers that can be used to seal gaskets, such as “H
GE glyptol No. 1201B-red can also be used to paint gasket an

surfaces; but it takes more time, and you must be more cautiou

temperature. If possible, this work should be done in tempera

above 70 oF to speed paint curing. Allow the paint to complet

before applying glue or the new gasket. It is not necessary to 

old glyptol, or other primer, or old glue if the surface is fairly 

and uniform. 

Choose the correct replacement gasket. The main influences o

material selection are design of the gasket joint, maximum and 

minimum operating temperature, type of fluid contained, and i

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 

limits. This material performs better than cork-neoprene beca

does not take a set as easily and conforms better to mating sur

also performs better at higher temperatures. Be extra careful w

store this material because it looks like cork-neoprene (describ

section 5.3), and they easily are mistaken for each other. Com

is the same as for cork-neoprene, about 45%. Cork-nitrile sho

recover 80% of its thickness with compression of 400 psi in 

accordance with ASTM F36. Hardness should be 60 to 75 dur

in accordance with ASTM D2240. (See published specificatio

E-98 by manufacturer Dodge-Regupol Inc., Lancaster, Pennsy
94 

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; ho

it does not perform as well as cork-nitrile. This material takes 

when it is compressed and should only be used when there are 

expansion limiting grooves. Using cork-neoprene in grooves 

result in leaks from expansion and contraction of mating surfa

material is very porous and should be sealed on both sides and 

with a thin coat of Glyptol No. 1201B red or similar sealer bef

installation. Glyptol No. 1201B is a slow drying paint used to 

metal flanges and gaskets, and the paint should be allowed to 

totally before installation. Once compressed, this gasket shou

be reused. These gaskets should be kept above 35 oF before 

installation to prevent them from becoming hard. Gaskets sho

cut and sealed (painted) indoors at temperatures above 70 oF f

of handling and to reduce paint curing time. Avoid installing 

neoprene gaskets when temperatures are at or near freezing be

the gasket could be damaged and leak. Cork-neoprene gasket

evenly compressed at about 43 to 45%. For example, if the ga

1⁄4-inch thick, 0.43 x 0.25 = 0.10. When the gasket is torqued 

should be compressed about 0.10 inch. Or you may subtract 0

1⁄4 inch to calculate the thickness of the gasket after it is compr

In this case, 1⁄4 = 0.25 so 0.25 minus 0.10 = 0.15 inch would be 

final distance between the mating surfaces after the gasket is 

compressed. In an emergency, if compression limits are requi

this gasket, split lock washers may be used. Bend the washers 

they are flat and install enough of them (minimum of three), e

spaced, in the center of the gasket cross section to prevent exc
compression. The thickness of the washers should be such tha

gasket compression is limited to approximately 43%, as expla

above. 

5.4 Nitrile “NBR” 

Nitrile “NBR” (buna N) with 50 to 60 duro (hardness) is gene

material that should be chosen for most transformer applicatio

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 

or expansion limiting grooves. Be careful to protect nitrile fr

sunlight; it is not sunlight resistant and will deteriorate, even i

the edges are exposed. It should not be greased when it is use

nonmovable (static) seal. When joints have to slide during ins

or are used as a moveable seal (such as bushing caps, oil coole

isolation valves, and tap changer drive shafts), the gasket or O

should be lubricated with a thin coating of DOW No. 111, No

equivalent grease. These are very thin and provide a good sea

Nitrile performs better than cork-neoprene; when exposed to h

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 temperat

higher than 65 oC or for applications requiring motion (shaft s

etc.). Viton is very tough and wear resistant; however, it is ve

expensive ($1,000+ per sheet). Therefore, it should not be use

it is needed for high wear or high temperature applications. V

should only be used with compression limiter grooves and rec
96 

Store nitrile and viton separately, or order them in different co

materials look alike and can be easily confused, causing a muc

expensive gasket to be installed unnecessarily. Compression a

requirements for Viton are the same as those for nitrile, as out

above and shown in table 3. 

Table 3 – Transformer Gasket Application Summary 

Gasket 

Material 

Best 

Temperature 

Range 

Percent 

Comparison Compatible 

Fluids 

UV 

Resist 

B

Appl

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 

compres

or recess

use only 

UV resis

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 

flat surfa

with no g

compres

Cork-Nitrile 

(best) does not 

take a set as 

easily as corkneoprene. 

-5 to 60 °C 

(23 to 140 °F) 

40 Mineral oil 

R-Temp 

Alpha 1 

No Use only 

flat surfa

with no g

compres

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, 

extruded 

use with 

compres

limiters o

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 tem

O-rings, 

extruded 

use with 

compres

groove o

 1 Nitrile (buna N) can also be used in low wear applications and temperatures les

65 °C. 

 2

 Viton O-rings are best for wear resistance and tolerating temperature variations
OD ID −

2

5.5 Gasket Sizing for Standard Groove Depths 

Nitrile is the chosen example because it is the most commonly 

material for transformer gasketing. As shown in table 3, nitril

compression should be 25 to 50%. Nitrile sheets are available 

1/16-inch-thick increments. 

Gasket thickness is determined by groove depth and standard 

thickness. Choose the sheet thickness so that 1⁄4 to 1⁄3 thicknes

gasket will protrude above the groove; this is the amount avail

be compressed (see table 4). Gasket sheets come in standard 

thicknesses in 1/16-inch increments. Choose one that allows a 

gasket to stick out above the groove, if possible, but never cho

thickness that allows less than 1⁄4 or as much as 1⁄2 of the gaske

protrude above the groove. Do not try to remove old primer fr

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) 

Av

com

(pe

3/32 1/8 1/32 

1/8 3/16 1/16 

3/16 1/4 1/16 

1/4 3/8 1/8 

3/8 1/2 1/8 

Horizontal groove fill is determined by how wide the groove i

groove width is equal to the outer diameter (OD) minus the inn

diameter (ID) divided by two: 

Or just measure the groove width with an accurate caliper. 
98 

Room left for the gasket to expand while being compressed is 

the width of the groove minus the width of the gasket. For nit

amount of horizontal room needed is about 15 to 25%. Theref

need to cut the gasket cross section so that it fills about 75 to 8

the width of the groove. 

For example, an 8-inch OD groove with a 6-inch ID, 

OD ID −

2 , i

1 inch. Therefore, the width of the groove is 1 inch. Because 

to leave 25% expansion space, the width of the gasket is 75% 

1 inch, or 3⁄4 inch. So that the gasket can expand equally towa

center and toward the outside, you should leave one-half the e

space at the inner diameter of the groove and one-half at the o

this example, there should be a total space of 25% of 1 inch or 

(1⁄4 inch) for expansion after the gasket is inserted, so you shou

1⁄8-inch space at the OD and 1⁄8-inch space at the ID. See figur

Always cut the outer diameter first. In this example, the ou

diameter would be 8 inches minus 1⁄4 inch, or 73⁄4 inches. 

Figure 44 – Cross Section of Circular Gasket in Groove. 
NOTE: 

Since 1⁄8-inch space is required all around the gasket, 

1⁄4 inch must be subtracted to allow 1⁄8-inch on both sides. 

The inner diameter would be 6 inches plus 1⁄4 inch, or 

61⁄4 inches. Note that 1⁄4 inch is subtracted from the OD but 

added to the ID. 

To check yourself, subtract the inner radius from the outer rad

make sure you get the same gasket width calculated above. In 

example, 37⁄8 inches (outer radius, 1⁄2 of 73⁄4), minus 31⁄8 inches 

radius, 1⁄2 of 61⁄4), is 3⁄4 inch, which is the correct gasket width. 

5.6 Rectangular Nitrile Gaskets 

Rectangular nitrile gaskets larger than sheet stock on hand can 

fabricated by cutting strips and corners with a table saw or a u

knife with razor blade. Applying a little transformer oil or WD

makes cutting easier. Nitrile is also available in spools in stan

ribbon sizes. The ends may be joined using a cyanoacrylate ad

(super glue). Although there are many types of this glue, only 

them work well with nitrile. Since all these glues have a very 

shelf life, remember to always keep them refrigerated to exten

shelf life. Lawson Rubber Bonder No. 92081 best withstands 

temperature changes and compression. The Lawson part num

90286, and it is available from Lawson Products Co. in Reno, 

(702-856-1381). Loctite 404 also works but does not survive 

temperature variations as well. It is available at NAPA Auto P

Stores. Shelf life is critical. Always secure a new supply whe

gasketing job is started; never use an old bottle that has been o

shelf since the last job. 
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. 
Figure 45 – Cross Section of Gasket Remains Constant 

Before Tightening and After. wxd = gw x gt 
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 

angle (scarfed) at about 15 degrees. The best bond occurs whe

length of the angle cut is about four times the thickness of the 

(see table 5). With practice, a craftsperson can cut 15-degree 

with a utility knife. A jig can also be made from wood to hold 

gasket at a 15-degree angle for cutting and sanding. The ends 

further fine-sanded or ground on a fine bench grinder wheel to 

perfectly before applying glue. 

Thin metal conductive shim stock may be folded over the oute

perimeter around approximately one-half the circumference. T

pieces of shim stock should be evenly spaced around the 

circumference and stick far enough in toward the center so tha

will be held when the bolts are tightened. As an example, if th
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 

Compressio

(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 3.14

times 8 inches = 25.13 inches in circumference. Fifty percent 

is about 121⁄2 inches. Cut 12 strips 1-inch wide and long enou

clamped by the flange top and bottom when tightened. Fold th

the outside edge of the gasket, leaving a little more than a 1-in

between, so that the shim stock pieces will be as evenly space

possible around the circumference. 

5.7 Bolting Sequences to Avoid Sealing Problems 

If proper bolt tightening sequences are not followed or if impr

torque is applied to the bolts, sealing problems will result (see 

figure 46). A slight bow in the flange or lid top (exaggerated f

illustration) occurs, which applies uneven pressure to the gask

bow compromises the seal, and the gasket will eventually leak

Figure 47 illustrates proper bolting sequences for various type 

covers. Bolt numbers show the correct tightening sequences. 

The numbers do not have to be followed exactly; however, the 

gonal tightening patterns should be followed. By using proper 

and the illustrated sequence patterns, sealing problems from im

tightening and uneven pressure on the gasket can be avoided. 

torque wrench and torque bolts according to the head stamp on 

bolt. Check the manufacturer’s instruction book for pancake g

torque values. 
104 

Figure 46 – Bowing at Flanges. 

Figure 47 – Bolt Tightening Sequences. 
6. Transformer Oils 

6.1 Transformer Oil Functions 

Transformer oils perform at least four functions for the transfo

Oil provides insulation, provides cooling, and helps extinguish 

Oil also dissolves gases generated by oil degradation, moisture 

from cellulose insulation, deterioration, and gases and moistur

exposure to atmospheric conditions. Close observation of diss

gases in the oil, and other oil properties, provides the most val

information about transformer health. Looking for trends by 

comparing information provided in several DGAs and underst

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 ofte

problem is encountered, complete a DGA. This is, by far, the 

important tool for determining the health of a transformer. A 

the first indicator of a problem and can identify deteriorating i

and oil, overheating, hot spots, partial discharge, and arcing. T

Ahealth@ of the oil is reflective of the health of the transformer 

dissolved gas analysis consists of sending transformer oil sam

commercial laboratory for testing. The most important indica

the individual and total combustible gas (TCG) generation rate

on the International Electrotechnical Commission (IEC) 60599 

and IEEE C 57-104TM [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 sugge

actions based on the analysis. There are no “quick and sure” e
106 

answers when dealing with transformers. Transformers are ve

complex, very expensive, and very important to Reclamation; 

one is different. Decisions must be based on experienced judg

founded on all available data and consultation with experience

people. Periodic DGA and proper interpretations, along with 

periodic inspections (covered earlier), are the most important k

transformer life. Each DGA must be compared to prior DGAs 

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 a

expansion, load variations, gravity, and other forces all interac

the tank. Externally, through-faults, voltage surges, wide amb

temperature changes, and other forces (i.e., the earth’s magnet

and gravity) affect the transformer. There are few, if any, “cu

dried” DGA interpretations; even experts disagree. Consultati

others, experience, study, comparing earlier DGAs, keeping ac

records of a transformer’s history, and noting information foun

a transformer is disassembled will increase expertise and prov

extension to this critical equipment. 

Keeping accurate records of each individual transformer is 

paramount. If a prior through-fault, overload, cooling problem

nearby lightning strike has occurred, this information is extrem

valuable to determine what is going on inside the transformer. 

Baseline transformer test information should be established w

transformer is new, or as soon as possible thereafter. This mu

include DGA, Doble, and other test results (discussed in sectio

“Transformer Testing”). 

Table 6 represents a summary of DGA transformer analysis. T

is an actual example of a Reclamation transformer. 
Table 6 – Transformer DGA Condition Summary Table 

Condition Ranges 

Good Fair Poor 

Hydrogen (H2) ppm <101 >100 <1,000 >1,000 <2,000 

Hydrogen (H2) ppm 

 generation/month <10 >9 <30 >29 <50 

Methane (CH4) ppm <121 >120 <401 >400 <1,001 

Methane (CH4) ppm 

 generation/month <8 >7 <23 >22 <38 

Ethane (C2H6) ppm <66 >64 <101 >100 <151 

Ethane (C2H6) ppm 

 generation/month <8 >7 <23 >22 <38 

Ethylene (C2H4) ppm <51 >50 <101 >100 <201 

Ethylene (C2H4) ppm 

 generation/month <8 >7 <23 >22 <38 

Acetylene (C2H2) ppm <36 >35 <51 >50 <81 

Acetylene (C2H2) ppm 

 generation/month <.5 >.4 <1.5 >1.49 <2.5 

Carbon Monoxide (CO) ppm <351 >350 <571 >570 <1,401 

Carbon Monoxide (CO) ppm 

 generation/month <70 >69 <220 >219 <350 

Carbon Dioxide (CO2) ppm <2501 >2500 <4,001 >4,000 <10,001 

Carbon Dioxide (CO2) ppm 

 generation/month <700 >699 <2,100 >2,099 <3,500 

CO2/CO Ratio >10 <10.1 >6 <6.1 >3.9 

Oxygen (O2) ppm <3,501 >3,500 <7,001 >7,000 <10,001 

Total Combustible Gas ppm <721 >720 <1,921 >1,920 <4,631 

Moisture in Oil ppm > 230 kv <6 >5 <9 >8 <13 

Moisture in Oil ppm < = 230 kv <10 >9 <16 >15 <21 

Interfacial Tension 

 (dynes per cm) >45 <46 >35 <36 >25 

Acid Number 

 (KOH in milligrams) <.05 >.04 <.2 >.19 <.51 

Dielectric Breakdown Voltage 

 kV >288 kV >55 >40 <56 >24 <41 

Dielectric Breakdown Voltage 

 kV <288 kV >55 >40 <56 >19 <41 

Power Factor at 25 °C % <0.5 >0.49 <1.0 >0.99 <1.51 

Oxidation Inhibitor % >0.3 >0.31 >0.2 >0.21 >0.09 

2FAL furans for 

 65 °C rise transformers <150 >149 <200 >199 <251 

2FAL furans for 

 55 °C rise transformers <450 >449 <600 >559 <751 
108 

Table 7 – 345-kV Transformer Example 

Condition Status 

1 2 3 

Tests Value Good Fair Poor 

Hydrogen (H2) ppm 1 TRUE FALSE FALSE 

Hydrogen (H2) ppm 

 generation/month 0.08 TRUE FALSE FALSE 

Methane (CH4) ppm 3 TRUE FALSE FALSE 

Methane (CH4) ppm 

 gerneration/month 0.25 TRUE FALSE FALSE 

Ethane (C2H6) ppm 14 TRUE FALSE FALSE 

Ethane (C2H6) ppm 

 generation/month 1.17 TRUE FALSE FALSE 

Ethylene (C2H4) ppm 1 TRUE FALSE FALSE 

Ethylene (C2H4) ppm 

 generation/month 0.08 TRUE FALSE FALSE 

Acetylene (C2H2) ppm 0 TRUE FALSE FALSE 

Acetylene (C2H2) ppm 

 generation/month 0 TRUE FALSE FALSE 

Carbon Monoxide (CO) ppm 6 TRUE FALSE FALSE 

Carbon Monoxide (CO) ppm 

 generation/month 0.50 TRUE FALSE FALSE 

Carbon Dioxide (CO2) ppm 493 TRUE FALSE FALSE 

Carbon Dioxide (CO2) ppm 

 generation/month 41.08 TRUE FALSE FALSE 

CO2/CO Ratio 82.17 TRUE FALSE FALSE 

Oxygen (O2) ppm 1,569 TRUE FALSE FALSE 

Total Combustible Gas ppm 25 TRUE FALSE FALSE 

Moisture in Oil ppm 5 TRUE FALSE FALSE 

Interfacial Tension 

 (dynes per cm) 42.8 FALSE TRUE FALSE 

Acid Number 

 (KOH in milligrams) 0.010 TRUE FALSE FALSE 

Dielectric Breakdown 

 Voltage kV 34 FALSE FALSE TRUE 

Power Factor at 25 °C % 0.05 TRUE FALSE FALSE 

Oxidation Inhibitor % 0.05 FALSE FALSE FALSE 

2FAL furans for 55 °C 

 rise transformer 200 TRUE FALSE FALSE 
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 [

Key gases formed by degradation of oil and paper insulation a

hydrogen (H2), methane (CH4), ethane (C2H6), ethylene (C2H4

acetylene (C2H2), carbon monoxide (CO), and oxygen (O2). E

for carbon monoxide and oxygen, all these gases are formed fr

degradation of the oil itself. Carbon monoxide, carbon dioxid

and oxygen are formed from degradation of cellulose (paper) 

insulation. Carbon dioxide, oxygen, nitrogen (N2), and moistu

also be absorbed from the air, if there is an oil/air interface or 

is a leak in the tank. Some of our transformers have a pressuri

nitrogen blanket above the oil and, in these cases, nitrogen ma

near saturation (see table 8). Gas type and amounts are determ

where the fault occurs in the transformer and the severity and 

of the event. Events range from low energy events, such as pa

discharge, producing hydrogen and trace amounts of methane 

ethane, to very high energy sustained arcing, capable of gener

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 w
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

 TDCG2

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 C57-104-1991TM [12] (table 8 above) are extremely 

conservative. Transformers can operate safely with individual 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 S

(Std) [20], C57-104TM. The guide uses combinations of indivi

gases and total combustible gas concentration as indicators. It 

universally accepted and is only one of the tools used to evalu

dissolved gas in transformers. The four IEEE® conditions are 

below, and gas levels are in table 8. 

Condition 1: Total dissolved combustible gas (TDCG) below 

this level indicates the transformer is operating satisfactorily. 
Any individual combustible gas exceeding specified levels in 

table 8 should have additional investigation. 

Condition 2: TDCG within this range indicates greater than n

combustible gas level. Any individual combustible gas exceed

specified levels in table 8 should have additional investigation

may be present. Take DGA samples at least often enough to c

the amount of gas generation per day for each gas. (See table 

recommended sampling frequency and actions.) 

Condition 3: TDCG within this range indicates a high level o

decomposition of cellulose insulation and/or oil. Any individu

combustible gas exceeding specified levels in table 6 should h

additional investigation. A fault or faults are probably present

DGA samples at least often enough to calculate the amount of 

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 op

could result in failure of the transformer (see table 9). 

A sudden increase in key gases and the rate of gas production 

more important in evaluating a transformer than the accumula

amount of gas. One very important consideration is acetylene 

Generation of any amount of this gas above a few ppm indicat

high-energy arcing. Trace amounts (a few ppm) can be genera

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, ca

also generate a small amount of C2H2. If C2H2 is found in the 

DGA, oil samples should be taken weekly, or even daily, to de

if additional C2H2 is being generated. If no additional acetylen

found and the level is below the IEEE® Condition 4, the trans

may continue in service. However, if acetylene continues to in

the transformer has an active high-energy internal arc and shou

be taken out of service immediately. Further operation is extr
112 

Table 9 – Actions Based on Dissolved Combustible Gas (Adapted from [12]) 

Sampling Intervals and Operat

Actions for Gas Generation Ra

Conditions 

TDCG Level or 

Highest Individual Gas 

(See table 8) 

TDCG 

Generation 

Rates 

(ppm/day) Sampling 

Interval 

Operatin

Procedur

<10 Annually: 6 months 

for extra highvoltage transformer

10-30 Quarterly 

Continue nor

operation. 

Condition 1 <720 ppm of TDCG or 

highest condition based 

on individual combustible 

gas from table 8. 

>30 Monthly Exercise cau

Analyze indiv

gases to find 

cause. Dete

load depende

<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 cau

Analyze indiv

gases to find 

Determine lo

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 extr

caution. Ana

individual gas

find cause. P

outage. Call 

manufacturer 

other consult

advice. 

<10 Weekly 

10-30 Daily 

Exercise extr

caution. Ana

individual gas

find cause. P

outage. Call 

manufacturer 

other consult

advice. 

Condition 4 >4,639 ppm of TDCG or 

highest condition based 

on individual combustible 

gas from table 8. 

>30 Daily Consider rem

from service. 

manufacturer 

other consult

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 overloade

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 individu

generation rate in ppm/day is determined by the same method.
hazardous and may result in explosive catastrophic failure of t

tank, spreading flaming oil over a large area. 

Table 9 assumes that no previous DGA tests were performed o

transformer or that no recent history exists. If a previous DGA 

it should be reviewed to determine if the situation is stable (ga

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 

Condition 1, 2, 3, or 4. The condition for a particular transform

determined by finding the highest level for any individual gas 

using the TDCG [12]. Either the individual gas or the TDCG 

the transformer a higher condition number, which means it is a

risk. If the TDCG number shows the transformer in Condition 

an individual gas shows the transformer in Condition 4, the 

transformer is in Condition 4. Always be conservative and ass

worst until proven otherwise. 

6.1.3 Sampling Intervals and Recommended Actions 

When sudden increases occur in dissolved gases, the procedur

recommended in table 9 should be followed. Table 9 is parap

from table 3 in IEEE C57.104-1991 [12]. To make it easier to 

the order has been reversed with Condition 1 (lowest risk tran

at the top and Condition 4 (highest risk) at the bottom. The ta

indicates the recommended sampling intervals and actions for 

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 tab

Some information has been added to the table from IEEE C57

1991 (inferred from the text). To see the exact table, refer to t

Standard [12]. 
114 

If the cause of gassing can be determined and the risk can be a

the sampling interval may be extended. For example, if the co

meggered and an additional core ground is found, even though 

may recommend a monthly sampling interval, an operator may 

to lengthen the sampling interval, because the source of the ga

and generation rate is known. 

A decision should never be made on the basis of just one DGA

very easy to contaminate the sample by accidentally exposing 

Mislabeling a sample is also a common cause of error. Mislab

could occur when the sample is taken, or it could be accidenta

contaminated or mishandled at the laboratory. Mishandling m

some gases to escape to the atmosphere and other gases, such 

oxygen, nitrogen, and carbon dioxide, to migrate from the atm

into the sample. If you notice a transformer problem from 

DGA, the first thing to do is take another sample for comp

The gas generation chart (figure 48) [14, 17] and the discussio

represent only an approximate temperature at which gases form

figure is not drawn to scale and is only for purposes of illustra

temperature relationships, gas types, and quantities. These 

relationships represent what generally has been proven in cont

laboratory conditions using a mass spectrometer. This chart w

by R.R. Rogers of the Central Electric Generating Board (CEG

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 disc

conditions. Note that all the gases are given off, but in much l

quantity than hydrogen. It takes only a very low energy event 

discharge/corona) to cause hydrogen molecules to form from t

Gases are formed inside an oil-filled transformer similar to a 

petroleum refinery still, where various gases begin forming at 

temperatures. From the Gas Generation Chart, we can see rela
Figure 48 – Combustible Gas Generation Versus Temperature. 
116 

amounts of gas as well as approximate temperatures. Hydroge

methane begin to form in small amounts around 150 oC. Notic

the chart that beyond maximum points, methane (CH4), ethane 

ethylene production goes down as temperature increases. At a

250 oC, production of ethane (C2H6) starts. At about 350 oC, 

production of ethylene (C2H4) begins. Acetylene (C2H2) prod

begins between 500 oC and 700 oC. In the past, the presence o

trace amounts of acetylene (C2H2) was considered to indicate 

temperature of at least 700 oC had occurred; however, recent 

discoveries have led to the conclusion that a thermal fault (hot 

500 oC can produce trace amounts (a few ppm). Larger amoun

acetylene can only be produced above 700 oC by internal arcin

Notice that between 200 oC and 300 oC, the production of met

exceeds hydrogen. Starting at about 275 oC and on up, the pro

of ethane exceeds methane. At about 450 oC, hydrogen produ

exceeds all others until about 750 oC to 800 oC; then more ace

produced. 

It should be noted that small amounts of H2, CH4, and CO are 

produced by normal aging. Thermal decomposition of oilimpregnated cellulose produces CO, CO2 , H2, CH4, and O2. 

Decomposition of cellulose insulation begins at only about 10

less. Therefore, operation of transformers at no more than 90 

imperative. Faults will produce internal “hot spots” of far high

temperatures than these, and the resultant gases show up in the 

Table 11 (later in this section) is a chart of “fault types,” parts 

which are paraphrased from the IEC 60599 [13]. This chart is 

complete. It is impossible to chart every cause and effect due 

extreme complexity of transformers. DGAs must be carefully 

examined with the idea of determining possible faults and pos

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 

electrical. The first three on the chart are electrical discharges

last three are thermal faults. 
Ethane and ethylene are sometimes called “hot metal gases.” 

these gases are generated and acetylene is not, the problem fou

inside the transformer normally involves hot metal. This may 

bad contacts on the tap changer or a bad connection somewher

circuit, such as a main transformer lead. Stray flux impinging 

tank (such as in Westinghouse 7M series transformers) can cau

“hot metal gases.” Sometimes, a shield becomes loose and fal

becomes ungrounded. Static can then build up and discharge t

grounded surface, producing “hot metal” gases. An unintentio

ground with circulating currents can also produce these gases. 

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, magnet

(such as stray magnetic flux impinging the steel tank or other m

structures) also cause hot spots. 

6.1.4 Atmospheric Gases 

Atmospheric gases (N2, CO2, and O2) can be very valuable in 

in revealing a possible leak. However, as mentioned elsewher

are other reasons these gases are found in DGAs. Nitrogen ma

from shipping the transformer with N2 inside or from a nitroge

blanket. CO2 and O2 are formed by degradation of cellulose. 

careful; look at several DGAs and see if atmospheric gases an

possibly, moisture levels are increasing. Also, carefully look a

transformer to see if you can find an oil leak. Moisture and 

atmospheric gases will leak inside when the transformer is off 

ambient temperature drops (see section 6.1.11 on moisture). 

6.1.5 Dissolved Gas Software 

Several companies offer DGA computer software that diagnos

transformer problems. These diagnoses must be used with eng

judgment and should never be taken at face value. The softwa

constantly changing. The Technical Service Center uses “Tran

Oil Analyst” (TOA) by Delta X Research that uses a composit
118 

several current DGA methods. Dissolved gas analysis help is 

available from the TSC through the D-8440 and D-8450 group

groups have the above software and experience in diagnosing 

transformer problems. 

One set of rules that TOA uses to generate alarms is based loo

IEC 60599 (table 10). These rules are also very useful in daily 

dissolved gas analysis, which are based on L1 limits of IEC 60

except for acetylene. IEC 60599 gives a range for L1 limits in

a specific value. TOA uses the average in this range and then 

the user a “heads up” if a generation rate exceeds 10% of L1 l

month. Acetylene is the exception; IEEE sets an L1 limit of 3

(too high), and IEC sets an acetylene range of 3 to 50. TOA p

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. 
lowest number (3 ppm) and sets the generation rate alarm valu

3 ppm per month. L1 limits are the quantities at which you sh

begin to watch the transformer more closely (i.e., the first leve

concern). 

If one or more combustible gas generation rates are equal to or 

G2 limits (50% of L1 limits per month), this transformer shou

considered in critical condition. You may want to reduce sam

intervals to monthly or weekly, plan an outage, plan to rebuild 

replace the transformer, etc. If an active arc is present 

(C2H2 generation), or if other heat gases are high (above Cond

limits in table 8), and G2 limits are exceeded, the transformer 

be de-energized. 

Table 11 is taken from IEC 60599 and contains possible faults 

possible findings. This chart is not all inclusive and should be 

with other information. Additional possible faults are listed on 

following and preceding pages. 

Transformers are so complex that it is impossible to put all sym

and causes into a chart. Several additional transformer proble

listed below; any of these may generate gases: 

1. Gases are generated by normal operation and aging, 

H2 and CO, with someCH4. H2 is the easiest gas to p

except possibly CO. Production of H2 and other gase

caused by partial discharge (corona), sharp corners o

bushing connectors, loose core ground, wet spot on c

gasket leak above, loose corona shield on bottom of b

loose tap changer shield, etc. H2 is not very stable w

dissolved in oil. Consecutive DGAs may show varia

amounts of H2 and other unstable gases. Acetylene i

most stable gas; variation in amounts of this gas in th

upward direction means the transformer has an activ

fault. If the variation is going up and down within de
120 

Table 11 – Fault Types 

Key Gases Possible Faults Possible Finding

H2, possible trace of CH4 

and C2H6. Possible CO. 

Partial discharges (corona). Weakened insulation 

aging and electrical st

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 p

insulation with carbon 

carbon tracking. Poss

carbon particles in oil. 

Possible loose shield, 

grounding of metal ob

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 con

in tap changer or lead 

connections). Weake

insulation from aging 

electrical stress. Carb

oil. Paper destruction 

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. Overloadin

and/or cooling problem

connection in leads or 

changer. Stray curren

and/or stray magnetic 

H2, CO, CH4, C2H6, C2 H4. Thermal fault between 

300 °C and 700 °C. 

Paper insulation destr

Oil heavily carbonized

All the above gases and 

acetylene in large amounts. 

High energy electrical 

arcing 

700 °C and above. 

Same as above with m

discoloration. Arcing 

have caused a therma

 limits of the test equipment (section 6.1.9.4, table 14

consecutive DGAs, this is simply a variation of the la

equipment and personnel. 

2. Operating transformers at sustained overload will gen

combustible gases. 

3. Problems with cooling systems, discussed in sections 

and 3.4.5, can cause overheating. 

4. A blocked oil duct inside the transformer can cause l

overheating, generating gases. 

5. An oil directing baffle loose inside the transformer c

misdirection of cooling oil. 
6. Oil circulating pump problems (bearing wear, impell

or worn, or pump running in reverse) can cause trans

cooling problems. 

7. Oil level is too low; this will not be obvious if the lev

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, stru

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 

by a poor contact in the tap changer. 

12. A hot-spot may also be caused by discharges of stati

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 betwee

windings and ground, between windings of different 

potential, or in areas of different potential on the sam

winding, due to deteriorated or damaged insulation. 

14. Windings and insulation can be damaged by faults 

downstream (through faults), causing large current su

through the windings. Through faults cause extreme 

magnetic and physical forces that can distort and loo

windings and wedges. The results may be arcing in t

transformer, beginning at the time of the fault, or the 

insulation may be weakened and arcing will develop 

15. Insulation can also be damaged by a voltage surge, su

nearby lightning strike, switching surge, or closing o

step, which may result in immediate arcing or arcing 

develops later. 
122 

16. Insulation may be deteriorated from age and worn ou

Clearances and dielectric strength are reduced, allow

partial discharges and arcing to develop. This can al

reduce physical strength, allowing wedging and wind

move extensively during a through-fault, causing tot

mechanical and electrical failure. 

17. High noise level (hum due to loose windings or core 

laminations) can generate gas due to heat from frictio

Compare the noise to sister transformers, if possible. 

level meters are available at the TSC for diagnostic 

comparison and to establish baseline noise levels for 

comparison. 

6.1.6 Temperature 

Gas production rates increase exponentially with temperature 

directly with volume of oil and paper insulation at high enoug

temperature to produce gases [12]. Temperature decreases as 

from the fault increases. Temperature at the fault center is hig

oil and paper, here, will produce the most gas. As distance inc

from the fault (hot spot), temperature goes down, and the rate 

generation also goes down. Because of the volume effect, a la

heated volume of oil and paper will produce the same amount 

a smaller volume at a higher temperature [12]. We cannot tell 

difference by looking at the DGA. This is one reason that inte

DGAs is not an exact science. 

6.1.7 Gas Mixing 

Concentration of gases in close proximity to an active fault wi

higher than in the DGA oil sample. As distance increases from 

gas concentrations decrease. Equal mixing of dissolved gases 

total volume of oil depends on time and oil circulation. If ther

no pumps to force oil through radiators, complete mixing of g

in the total oil volume takes longer. With pumping and norma

loading, complete mixing equilibrium should be reached withi
24 hours and will have little effect on DGA if an oil sample is 

24 hours or more after a problem begins. 

6.1.8 Gas Solubility 

Solubilities of gases in oil vary with temperature and pressure 

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 thes

gases go down; and as temperature falls, their solubilities incr

Methane solubility remains almost constant with temperature 

Table 12 is accurate only at standard temperature and pressure 

(0 oC/32 oF) and (14.7 psi/29.93 inches of mercury, which is st

barometric pressure at sea level). Table 12 shows only relativ

differences in how gases dissolve in transformer oil. 

From the solubility table (table 12) below, comparing hydroge

solubility of 7% and acetylene with a solubility of 400%, you 

that transformer oil has a much greater capacity for dissolving 

acetylene. However, 7% hydrogen by volume represents 70,0

and 400% acetylene represents 4,000,000 ppm. You probably 

never see a DGA with numbers this high. Nitrogen can appro

maximum level if there is a pressurized nitrogen blanket abov

Table 12 shows the maximum amount of each gas that the oil 

capable of dissolving at standard temperature and pressure. A

levels, the oil is said to be saturated. 

If you have conservator-type transformers and nitrogen, oxyge

CO2 are increasing, there is a good possibility that the tank has 

or that the oil may have been poorly processed. Check the dia

or bladder for leaks (section 4.9) and check for oily residue aro

pressure relief device and other gasketed openings. There sho
124 

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 

Sou

Hydrogen1 H2 7.0 70,000 Partial dis

corona, 

 electroly

Nitrogen N2 8.6 86,000 Inert gas 

atmosphe

Carbon Monoxide1

 CO 9.0 90,000 Overheate

cellulose, 

pollution 

Oxygen O2 16.0 160,000 Atmosphe

Methane1

 CH4 30.0 300,000 Overheate

Carbon Dioxide CO2 120.0 1,200,000 Overheate

cellulose, 

atmosphe

Ethane1

 C2H6 280.0 2,800,000 Overheate

Ethylene1

 C2H4 280.0 2,800,000 Very over

Acetylene1

 C2H2 400.0 4,000,000 Arcing in o

 1

 Denotes combustible gas. Overheating can be caused both by high temperatu

unusual or abnormal electrical stress. 

fairly low nitrogen and especially low oxygen in a conservator

transformer. However, if the transformer was shipped new wi

pressurized nitrogen inside and has not been de-gassed proper

may be high nitrogen content in the DGA, but the nitrogen lev

should not be increasing after the transformer has been in serv

few years. When oil is installed in a new transformer, a vacuu

placed on the tank that pulls out nitrogen and pulls in the oil. 

free to absorb nitrogen at the oil/gas interface, and some nitrog

be trapped in the windings, paper insulation, and structure. In 

case, nitrogen may be fairly high in the DGAs. However, oxy

should be very low, and nitrogen should not be increasing. It 

important to take an oil sample early in the transformer’s servi

establish a baseline DGA; then take samples at least annually. 

nitrogen and oxygen can be compared with earlier DGAs. If t
increase, it is a good indication of a leak. If the transformer oi

ever been de-gassed, nitrogen and oxygen should be low in the 

It is extremely important to keep accurate records over a trans

life; when a problem occurs, recorded information helps great

troubleshooting. 

6.1.9 Diagnosing a Transformer Problem Using Dissolved G

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 

Hydro Quebec developed this method in the 1960s using a dat

thousands of DGAs and transformer problem diagnosis. More 

recently, this method was incorporated in the Transformer Oil 

Software version 4 (TOA 4), developed by Delta X Research a

by many in the utility industry to diagnose transformer problem

method has proven to be accurate and dependable over many y

is now gaining in popularity. The method and how to use it ar

described below. 

6.1.9.2 How to Use the Duval Triangle – 

1. First determine whether a problem exists by using th

IEEE® method above, and/or table 13 below. At lea

one of the hydrocarbon gases or hydrogen must be in 
126 

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. 
 IEEE® Condition 3 and increasing at a generation ra

from table 13, before a problem is confirmed. To us

table 13 without the IEEE® method, at least one of t

individual gases must be at L1 level or above and the 

generation rate must be at least at G2. 

 The L1 limits and gas generation rates from table 13 

reliable than the IEEE® method; however, one shoul

both methods to confirm that a problem exists. If the

sudden increase in H2 with only carbon monoxide an

dioxide and little or none of the hydrocarbon gases, u

section 6.1.10 (CO2/CO ratio) to determine if the cel

insulation is being degraded by overheating. 

2. Once a problem has been determined to exist, use the 

accumulated amount of the three Duval Triangle gas

plot the percentages of the total on the triangle to arr

diagnosis. An example is shown below. Also, calcu

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 

sudden increase will give the amount of gases genera

since the fault began. Detailed instructions and an ex

are shown below. 

a. Take the amount (ppm) of methane in the DGA a

subtract the amount of CH4 from an earlier DGA

the sudden increase in gas. This will give the am

methane generated since the problem started. 

b. Repeat this process for the remaining two gases, 

and acetylene. 

3. Add the three numbers (differences) obtained by the 

of step 2 above. This gives 100 % of the three key g

generated since the fault, used in the Duval Triangle. 

4. Divide each individual gas difference by the total dif

of gas obtained in step 3 above. This gives the perce

increase of each gas of the total increase. 
128 

5. Plot the percentage of each gas on the Duval Triangl

beginning on the side indicated for that particular gas

lines across the triangle for each gas, parallel to the h

marks shown on each side of the triangle. An examp

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 Trans
Compare the total accumulated gas diagnosis and the diagnosi

obtained by using only the increase-in-gases after a fault. If th

has existed for some time, or if generation rates are high, the t

diagnoses will be the same. If the diagnoses are not the same, 

use the diagnosis of the increase in gases generated by the fau

will be the more severe of the two. See the example below of 

Reclamation transformer where the diagnosis using the increa

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 tw

DGAs. CO and CO2 are used to evaluate cellulose. 

DGA 

No. 1 

DGA 

No. 2 Increase 

DGA 

No. 1 

DGA 

No. 

2 Increas

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 Tria

(Figure 50) 

1. Use the total accumulated gas from DGA 2 = 369 

2. Divide each gas by the total to find the percentage of 

gas of the total. 

 % CH4 = 192/369 = 52%, % C2H4 = 170/369 = 46%

% C2H2 = 7/369 = 2% 
130 

3. Draw three lines across the Duval Triangle starting a

percentages obtained in step 2. These lines must be 

parallel to the hash mark on each respective side. S

black dashed lines in figure 50 above. 

4. Point 1 is obtained where the lines intersect within th

T2 diagnostic area of the triangle, which indicates a t

fault between 300 and 700 °C. See figure 49, Legen

Steps to Obtain the Second Diagnosis (Point 2) on the Duval T

(Figure 50) 

1. Use the total increase in gas = 139. 

2. Divide each gas increase by the total increase to find 

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 a

percentages obtained in step 2. These lines must be 

parallel to the hash mark on each respective side. S

white dashed lines in figure 50 above. Note that C2H

the same percentage (2%) both times; and, therefore, 

lines are the same. 

4. Point 2 is obtained where the lines intersect within th

T3 diagnostic area of the triangle, which indicates a t

fault greater than 700 °C. See figure 49, Legend, abo

The ratio of total accumulated gas is CO2/CO = 2,326/199 = 1

The ratio of increase is CO2/CO = 1,317/23 = 57. Neither of t

ratios is low enough to cause concern. This shows that the the

fault is not close enough to the cellulose insulation to cause he

degradation of the insulation. The large increase in CO2 could 

an atmospheric leak. 
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 

contact or connection in the tap changer, or a problem with a c

ground. These problems are probably all reparable in the field

of these problems can cause the results revealed by the Duval 

diagnosis above. These are areas where a fault will not degrad

cellulose insulation, which would cause the CO2/CO ratio to b

lower than what was obtained. For information to arrive at a p

fault see section 6.1.10. 

6.1.9.3 Expertise Needed – A transformer expert shou

consulted if a problematic trend is evidenced by a number of D

The transformer manufacturer should be consulted along with 

lab personnel and others experienced in transformer maintenan

diagnostics. Never make a diagnosis based on one DGA; a sa

may have been mishandled or mislabeled, either in the field or 

6.1.9.4 Rogers Ratio Method of DGA – Rogers Ratio 

of DGA [19] is an additional tool that may be used to look at d

gases in transformer oil. Rogers Ratio Method compares quan

different key gases by dividing one into the other. This gives 

the amount of one key gas to another. By looking at the Gas 

Generation Chart (figure 48), you can see that, at certain temp

one gas will be generated more than another gas. Rogers used 

relationships and determined that if a certain ratio existed, then 

specific temperature had been reached. By comparing a large 
132 

of transformers with similar gas ratios and data collected when 

transformers were examined, Rogers then could then say that c

faults were present. Like the key gas analysis above, this meth

not a “sure thing” and is only an additional tool to use in analy

transformer problems. Rogers Ratio Method, using three-key 

ratios, is based on earlier work by Doerneburg, who used five-

ratios. Ratio methods are only valid if a significant amount of 

gases used in the ratio is present. A good rule is: Never mak

decision based only on a ratio if either of the two gases use

ratio is less than 10 times the amount the gas chromatogra

detect [13]. This rule makes sure that instrument inaccuracies 

little effect on the ratios. If either of the gases are lower than 

the detection limit, most likely you do not have the particular p

that this ratio represents. If the gases are not at least 10 times 

limits does not mean you cannot use the Rogers Ratios; it mea

the results are not as certain as if the gases were at least at thes

This is another reminder that DGAs are not an exact science a

there is no “one best, easy way” to analyze transformer proble

Approximate detection limits are as follows, depending on the 

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 
When a fault occurs inside a transformer, there is no problem 

minimum gas amounts at which the ratio is valid. There will b

than enough gas present. 

If a transformer has been operating normally for some time an

shows a sudden increase in the amount of gas, first take a seco

sample to verify that there is a problem. If the next DGA show

to be more in line with prior DGAs, the earlier oil sample was 

contaminated, and there is no further cause for concern. If the 

sample also shows increases in gases, the problem is real. To 

Ratio Methods, subtract gases that were present prior to sudde

increases. This takes out gases that have been previously gene

due to normal aging and from prior problems. This is especial

for ratios using H2 and the cellulose insulation gases CO and C

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 lar

numbers of DGAs and transformer failures and what was disc

after the failures. 

There are other ratio methods, but only the Rogers Ratio Meth

be discussed since it is the one most commonly used. The me

description is paraphrased from Rogers’ original paper [19] an

IEC 60599 [13]. 

Ethylene and ethane are sometimes called “hot metal gases.” 

that this fault does not involve paper insulation, because CO is 

low. H2 and C2H2 are both less than 10 times the detection lim

means the diagnosis does not have a 100% confidence level of 

correct. However, due to the high ethylene, the fault is probab

connection where an incoming lead is bolted to a winding lead

perhaps bad tap changer contacts, or additional core ground (la
134 

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 
Table 15 – Rogers Ratios for Key Gases 

Code range of ratios C2

H2

C2

H4

CH4

H2

C2H4

C2H6

Detection limits and 10 x detectio

shown below: 

C2H2 1 ppm 10 p

C2H4 1 ppm 10 p

CH4 1 ppm 10 p

H2 5 ppm 50 p

C2H6 1 ppm 10 p

<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, ca

insulation voids or super gas satu

or cavitation (from pumps) or high 

oil (water vapor bubbles). 

2 High energy partial 

discharge 

1 1 0 Same as above but leading to tra

perforation of solid cellulose insul

sparking, or arcing; this generally 

CO and CO2. 

3 Low energy 

discharges, 

sparking, arcing 

1

-

2 

0 1-2 Continuous sparking in oil betwee

connections of different potential 

potential (poorly grounded shield, 

breakdown of oil dielectric betwee

insulation materials. 

4 High energy 

discharges, arcing 

1 0 2 Discharges (arcing) with power fo

through; arcing breakdown of oil b

windings or coils, between coils a

or load tap changer arcing across 

contacts during switching with the 

into the main tank. 

5 Thermal fault less 

than 150 °C 

(see note 2) 

0 0 1 Insulated conductor overheating; 

generally produces CO and CO2 

type of fault generally involves ce

insulation. 

6 Thermal fault 

temperature range 

150-300 °C 

(see note 3) 

0 2 0 Spot overheating in the core due 

concentrations. 

Items below are in order of increa

temperatures of hot spots: small 

core; shorted laminations in core; 

of copper conductor from eddy cu

connection on winding to incomin

bad contacts on load or no-load ta

circulating currents in core—this c

extra core ground (circulating cur

tank and core); this could also me

in the tank. These problems may 

cellulose insulation which will prod

and CO2. 
136 

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 ra

C2H4 /C2H6 to rise from 1-3 to above 3 as the spark increases in intensity. The code 

beginning stage will then be 1 0 1. 

2. These gases come mainly from the decomposition of the cellulose which explains 

this code. 

3. This fault condition is normally indicated by increasing gas concentrations. CH4 /H

normally about 1; the actual value above or below 1 is dependent on many factors, s

oil preservation system (conservator, N2 blanket, etc.), the oil temperature, and oil qu

4. Increasing values of C2H2 (more than trace amounts) generally indicate a hot spo

700 °C. This generally indicates arcing in the transformer. If acetylene is increasing

especially if the generation rate is increasing, the transformer should be de-energize

operation is extremely hazardous. 

General Remarks: 

1. Values quoted for ratios should be regarded as typical (not absolute). This mean

ratio numbers are not “carved in stone”; there may be transformers with the same pro

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 t

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 

depending on the amount of oil interchange between the tap changer tank and the m

circulating currents in the tank and core). See the two bottom 

problems on table 16 (later in this chapter). This example was 

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 detec

of 1 ppm. This is not high energy arcing due to the small amo
more likely, it has been produced by a one-time, nearby lightn

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 
138 

Notice that methane is increasing slowly, but ethane had a larg

increase between samples 1 and 2 but did not increase between 

samples 2 and 3. Note that two key gases (CH2 and C2H6) are 

IEEE Condition 1 in table 9, so the Rogers Ratio Method is va

referring to table 15, this combination of codes is Case 6, whic

indicates the transformer has a thermal fault in the temperature 

of 150 oC to 300 oC. 

Life history of the transformer must be examined carefully. It 

again, very important to keep accurate records of every transfo

This information is invaluable when it becomes necessary to d

evaluation. 

The transformer in this example is one of three sister transform

have had increased cooling installed and are running higher lo

to a generator upgrade several years ago. Transformer sound 

(hum) is markedly higher than for the two sister transformers. 

unit breaker experienced a fault some years ago, which placed 

mechanical stresses on the transformer. This generally means 

windings, which can generate gas due to friction (called a ther

fault) by Rogers Ratios. Comparison with sister units reveals 

triple the ethane as the other two, and it is above the IEEE Con

Gases are increasing slowly; there has been no sudden rate inc

combustible gas production. Notice the large increase in O2 an

between the first and second DGA and the large decrease betw

second and third. This indicates that the oil sample was expos

(atmosphere) and that these two gases are inaccurate in the mi

sample. 

6.1.10 Carbon Dioxide/Carbon Monoxide Ratio 

This ratio is not included in the Rogers Ratio Method of analy

However, it is useful to determine if a fault is affecting the cel

insulation. This ratio is included in transformer oil analyzing 

programs, such as Delta X Research Transformer Oil Analyst. 

analysis is available from the TSC at D-8440 and D-8450 in D
Formation of CO2 and CO from the degradation of oil impregn

paper increases rapidly with temperature. Calculate a normal 

operating CO2/CO ratio at each DGA, based on the total accum

amount of both gases. Look at several DGAs concentrating on 

and CO. Experience has shown that, with normal loading and 

temperatures, the CO2 generation rates runs 7 to 20 times high

CO. With a CO2/CO ratio above 7, there is little concern. Wi

transformers, ratios down to 5 times more CO2 than CO might 

considered normal. However, be careful with a ratio below 7. 

CH4, and C2H6 are increasing significantly as well as CO and 

is 5 or less, there is probably a problem. Take time to know th

particular transformer by carefully checking all prior DGAs an

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 sam

confirm the problem. Take the amount of CO2 generated betw

DGAs and divide it by the amount of CO generated at that sam

to establish the ratio. An excellent indication of abnormally h

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 

perform the Furans test explained in the following section 7.6. 

Extreme overheating from loss of cooling or plugged oil passa

produce a CO2/CO ratio around 2 or 3 along with increasing F

this is found, de-energization and internal inspection is recomm

the transformer is in imminent danger of failure. 
140 

Table 16 is adapted from IEC 60599, Appendix A.1.1 [13]. S

the wording has been changed to reflect American language u

rather than European. 

Table 16 – Typical Faults in Power Transformers [13] 

Fault Examples 

Partial 

discharges 

Discharges in gas-filled cavities in insulation resulting from incomp

impregnation, high moisture in paper, gas in oil supersaturation or 

(gas bubbles in oil) leading to X wax formation on paper. 

Discharges 

of low energy 

Sparking or arcing between bad connections of different floating po

from shielding rings, toroids, adjacent discs or conductors of differe

windings, broken brazing, closed loops in the core. Additional core 

Discharges between clamping parts, bushing and tank, high voltag

ground, within windings. Tracking in wood blocks, glue of insulating 

winding spacers. Dielectric breakdown of oil, load tap changer bre

contact. 

Discharges 

of high 

energy 

Flashover, tracking or arcing of high local energy or with power fol

through. Short circuits between low voltage and ground, connecto

windings, bushings, and tank, windings and core, copper bus and 

duct. Closed loops between two adjacent conductors around the m

magnetic flux, insulated bolts of core, metal rings holding core legs

Overheating 

less than 

300 °C 

Overloading the transformer in emergency situations. Blocked or r

oil flow in windings. Other cooling problem, pumps valves, etc. Se

“Cooling” section in this document. Stray flux in damping beams o

Overheating 

300 to 

700 °C 

Defective contacts at bolted connections (especially busbar), conta

tap changer, connections between cable and draw-rod of bushings

Circulating currents between yoke clamps and bolts, clamps and la

in ground wiring, bad welds or clamps in magnetic shields. 

Abraded insulation between adjacent parallel conductors in windin

Overheating 

over 700 °C 

Large circulating currents in tank and core. Minor currents in tank 

created by high uncompensated magnetic field. Shorted core lam

Notes: 

1. X wax formation comes from Paraffinic oils (paraffin based). These are not used in transfor

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 

that acetylene can be produced in trace amounts at 500 °C, which is not reflected in this table. 

several transformers that show trace amounts of acetylene that probably are not active arcing b

result of high-temperature thermal faults, as in the example. It may also be the result of one ar

nearby lightning strike or voltage surge. 

3. A bad connection at the bottom of a bushing can be confirmed by comparing infrared scans 

the bushing with a sister bushing. When loaded, heat from a poor connection at the bottom wil

the top of the bushing, which will display a markedly higher temperature. If the top connection 

and found tight, the problem is probably a bad connection at the bottom of the bushing. 
6.1.11 Moisture Problems 

Moisture, especially in the presence of oxygen, is extremely h

to transformer insulation. Recent EPRI studies show that an o

level above 2,000 ppm dissolved in transformer oil is extreme

destructive. Each DGA and Doble test result should be exami

carefully to see if water content is increasing and to determine 

moisture by dry weight (M/DW) or percent saturation in the p

insulation. When 2% M/DW is reached, make plans for a dry 

Never allow the M/DW to go above 2.5% in the paper or 30% 

saturation without drying out the transformer. Each time the m

is doubled in a transformer, the life of the insulation is cut by o

Keep in mind that the life of the transformer is the life of the p

and the purpose of the paper is to keep out moisture and oxyge

service-aged transformers rated less than 69 kV, results of up 

35 ppm at 60 °C are considered acceptable. For 69 kV throug

230 kV, a DGA test result of 20 ppm at 60 °C is considered 

acceptable. For greater than 230 kV, moisture should never ex

12 ppm at 60 °C. However, the use of absolute values for wat

not always guarantee safe conditions, and the percent by dry w

should be determined. See table 19, “Doble Limits for In-Serv

Oils,” in section 7.6. If values are higher, the oil should be pro

If the transformer is kept as dry and free of oxygen as possible

transformer life will be extended. 

Reclamation specifies that manufacturers dry new transformer

more than 0.5% M/DW during commissioning. That means th

transformer with 10,000 pounds of paper insulation, has 10,00

0.005 = 50 pounds of water (about 6 gallons) in the paper. Th

enough moisture to be detrimental to electrical integrity. Whe

transformer is new, this water is distributed equally through th

transformer. It is extremely important to remove as much wat

possible. 

When the transformer is energized, water begins to migrate to 

coolest part of the transformer and the site of the greatest elect

stress. This location is normally the insulation in the lower on
142 

of the winding [6]. Paper insulation has a much greater affinit

water than does the oil. The water will distribute itself unequa

much more water being in the paper than in the oil. The paper 

partially dry the oil by absorbing water out of the oil. Temper

also a big factor in how the water distributes itself between the 

paper. See table 17 below for comparison. 

Table 17 – Comparison of Water Distribution in Oil and Paper [

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 

water and how the water changes in the paper with temperatur

ppm of water in oil shown in the DGA is only a small part of t

in the transformer. When an oil sample is taken, it is impor

record the oil temperature from the top oil temperature ga

Some laboratories give percent M/DW of the insulation in the 

others give percent oil saturation, and some give only the ppm 

in the oil. If you have an accurate temperature of the oil and t

of water, the Nomogram (figure 55, section 6.1.11.2) will give 

M/DW of the insulation and the percent oil saturation. 

Where does the water come from? Moisture can be in the insu

when it is delivered from the factory. If the transformer is ope

inspection, the insulation can absorb moisture from the atmosp

there is a leak, moisture can enter in the form of water or hum

the air. Moisture is also formed by the degradation of insulati

transformer ages. Most water penetration is flow of wet air or 

water through poor gasket seals due to a pressure difference ca

transformer cooling. If a transformer is removed from service 
rain or snow, some transformer designs cool rapidly and the pr

inside drops. The most common moisture ingress points are g

between bushing bottoms and the transformer top and the pres

relief device gasket. Small oil leaks, especially in the oil cool

piping, will also allow moisture ingress. With rapid cooling a

resultant pressure drop, relatively large amounts of water and 

vapor can be pumped into the transformer in a short time. It is 

important to repair small oil leaks; the small amount of visible 

not important in itself, but it indicates a point where moisture 

enter [23]. 

It is critical for life extension to keep transformers as dry and a

oxygen as possible. Moisture and oxygen cause the paper insu

decay much faster than normal and form acids, sludge, and mo

moisture. Sludge settles on windings and inside the structure, 

less efficient transformer cooling, which allows temperature to 

rise over a period of time. (This was discussed earlier in secti

section 3.4.5.4). Acids cause an increase in the rate of decay, 

forms more acid, sludge, and moisture at a faster rate [21]. Th

vicious cycle of increasing speed forming more acid and causi

decay. The answer is to keep the transformer as dry as possib

free of oxygen as possible. In addition, oxygen inhibitor shou

watched in the DGA testing. The transformer oil should be dr

when moisture reaches the values stated in table 19 (following 

this document). An inhibitor (ditertiary butyl paracresol [DBP

should be added (0.3% by weight ASTM D-3787) when the oi

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 gr

than 0.9, ice can float). 

3. Water can be in the form of a water/oil emulsion. 
144 

4. Water can be dissolved in the oil and is given in ppm 

DGA. 

5. Water can be in the form of humidity if transformers 

inert gas blanket. 

Free water causes few problems with dielectric strength of oil

however, it should be drained as soon as possible. Having a w

interface allows oil to dissolve water and transport it to the ins

Problems with moisture in insulation were discussed above. I

transformer is out of service in winter, water can freeze. If oil 

gravity is greater than 0.9 (ice specific gravity), ice will float. 

cause transformer failure if the transformer is energized with f

ice inside. This is one reason that DGA laboratories test the sp

gravity of transformer oil. 

The amount of moisture that can be dissolved in oil increases 

temperature (see figure 51). This is why hot oil is used to dry 

transformer. A water/oil emulsion can be formed by purifying 

too high temperature. When the oil cools, dissolved moisture 

emulsion [21]. A water/oil emulsion causes drastic reduction 

dielectric strength. 

How much moisture in insulation is too much? When the insu

reaches 2.5% M/DW or 30% oil saturation (given on some DG

transformer should have a dry out with vacuum, if the tank is r

vacuum. If the transformer is old, pulling a vacuum can do m

than good. In this case, it is better to do round-the-clock re-cir

with a Bowser drying the oil as much as possible, which will p

water out of the paper. At 2.5% M/DW, the paper insulation i

degrading much faster than normal [6]. As the paper is degrad

more water is produced from the decay products, and the trans

becomes even wetter and decays even faster. When a transfor

above 4% M/DW, it is in danger of flashover if the temperatur

to 90 oC. 
6.1.11.1 Dissolved Moisture in Transformer Oil – Mo

measured in the dissolved gas analysis in ppm. Some laborato

give percent saturation, which is the percent saturation of wate

oil. This is a percentage of how much water is in the oil comp

with the maximum amount of water the oil can hold. Figure 5

it can be seen that the amount of water the oil can dissolve is g

dependent on temperature. The curves below (figure 52) are p

saturation curves. On the left line, find the ppm of water from 

DGA. From this point, draw a horizontal with a straight edge. 

the oil temperature, draw a vertical line. At the point where th

intersect, read the percent saturation curve. If the point falls b

two saturation curves, estimate the percent saturation based on 

Figure 51 – Maximum Amount of Water Dissolved 

in Mineral Oil Versus Temperature. 
146 

the point is located. For example, if the water is 30 ppm and t

temperature is 40 oC, you can see on the curves that this point 

intersection falls about halfway between the 20% curve and th

30% curve. This means that the oil is approximately 25% satu

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 

shows how moisture is distributed throughout transformer insu

Notice that the moisture is distributed according to temperatur

most moisture at the bottom and less moisture as temperature 

toward the top. This example shows almost twice the moistur

Figure 52 – Transformer Oil Percent Saturation Curves. 
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 accura

information about the M/DW or percent saturation. It will als

impossible for you to calculate this information accurately. 

Experts disagree on how to tell how much moisture is in the in

based on how much moisture is in the oil (ppm). At best, met

determine moisture in the insulation based solely on DGA are 

inaccurate. 

The methods discussed below to determine moisture levels in 

insulation are estimates, and no decision should be made based 

DGA. However, keep in mind that the life of the transformer 

life of the insulation. The insulation is quickly degraded by ex

moisture and the presence of oxygen. Base any decisions on s

DGAs over a period of time and establish a trend of increasing 

moisture. 

Figure 53 – Water Distrib

Transformer Insulation. 
148 

If the lab does not provide the percent M/DW, IEEE 62-1995 

gives a method. From the curve (figure 54), find the temperat

the bottom oil sample and add 5 oC. Do not use the top oil 

temperature. This estimates the temperature of the bottom thir

(coolest part) of the winding, where most of the water is locate

From this temperature, move up vertically to the curve. From 

point on the curve, move horizontally to the left and find the M

Multiplier number. Take this number and multiply the ppm of 

shown on the DGA. The result is percent M/DW in the upper 

the insulation. This method gives less amount of water than th

General Electric nomogram (figure 55). 

Figure 54 – Myers Multiplier Versus Temperature. 
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, perce

saturation is about 6.5%, and the % M/DW is about 1.5%. No

the 10 ppm point and move the sample temperature upward (c

and notice how quickly the moisture numbers increase. For ex

use 20 oC and read the percent saturation of oil at about 18.5% 

Figure 55 – Water Content of 

and Oil Nomogram. 
150 

% M/DW at about 3.75%. The cooler the oil, the higher the m

percentage for the same ppm of water in the oil. 

Do not make a decision on dry out based on only one DGA an

calculation; it should be based on trends over a period of time

additional samples and send them for analysis. Take extra car

make sure the oil temperature is correct. You can see by the 

nomogram that moisture content varies dramatically with temp

Take extra care that the sample is not exposed to air. After us

more conservative IEEE method, if, again, subsequent sample

M/DW is 2.5% or more and the oil is 30% saturated or more, t

transformer should be dried as soon as possible. Check the no

and curves above to determine the percent saturation of the oil

insulation is degrading much faster than normal due to the hig

moisture content. Drying can be an expensive process; it is pr

consult with others before making a final decision to impleme

out. However, it is much less expensive to perform a dry out t

allow a transformer to degrade faster than normal, substantiall

shortening transformer life. 

7. Transformer Oil Tests That Should Be 

Completed Annually with the Dissolved Ga

Analysis 

7.1 Dielectric Strength 

This test measures the voltage where the oil electrically breaks 

The test gives a good indication of the amount of contaminant

and oxidation particles) in the oil. DGA laboratories typically 

ASTM D-1816. Using the D-1816 test, the minimum oil 

breakdown voltage is 20 kV for transformers rated less tha

288 kV and 25 kV for transformers 287.5 kV and above. I

dielectric strength test falls below these numbers, the oil shoul

reclaimed. Do not base any decision on one test result or on o

of test; instead, look at all the information over several DGAs 

establish trends before making any decision. The dielectric str
test is not extremely valuable; moisture in combination with o

and heat will destroy cellulose insulation long before the diele

strength of the oil has given a clue that anything is going wron

The dielectric strength test also reveals nothing about acids an

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 

determine the interfacial tension between the oil sample and d

water. The oil sample is put into a beaker of distilled water at 

temperature of 25 oC. The oil should float because its specific 

is less than that of water (specific gravity of water is one). Th

should be a distinct line between the two liquids. The IFT num

the amount of force (dynes) required to pull a small wire ring 

distance of 1 centimeter through the water/oil interface. (A dy

very small unit of force equal to 0.000002247 pound.) Good, 

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 w

As the oil ages, it is contaminated by tiny particles (oxidation 

products) of the oil and paper insulation. Particles on top of th

extend across the water/oil interface line that weaken the surfa

tension between the two liquids. Particles in oil weaken interf

tension and lower the IFT number. The IFT and acid numbers

together, are an excellent indication of when the oil needs to b

reclaimed. It is recommended that the oil be reclaimed when t

IFT number falls to 25 dynes per centimeter. At this level, the 

very contaminated and must be reclaimed to prevent sludging, 

begins around 22 dynes per centimeter. See FIST 3-5 [21]. 

If oil is not reclaimed, sludge will settle on windings, insulatio

cooling surfaces, etc., and cause loading and cooling problems

discussed earlier. This will greatly shorten transformer life. 

A definite relationship exists between the acid number, the IFT

the number of years in service. The accompanying curve (figu
152 

shows the relationship and is found in many publications. (It w

originally published in the AIEE transactions in 1955.) Notice 

curve shows the normal service limits for both the IFT and the 

number. 

7.2 Acid Number 

Acid number (acidity) is the amount of potassium hydroxide (

milligrams (mg) that it takes to neutralize the acid in 1 gram (g

transformer oil. The higher the acid number, the more acid is 

oil. New transformer oils contain practically no acid. Oxidati

insulation and oils forms acids as the transformer ages. The o

products form sludge and precipitate out inside the transforme

acids attack metals inside the tank and form soaps (more sludg

Acid also attacks cellulose and accelerates insulation degradat

Sludging begins when the acid number reaches 0.40; it is obvi

the oil should be reclaimed before it reaches 0.40. It is recomm

Figure 56 – Interfacial Tension, Acid Number, 

Years in Service. 
that the oil be reclaimed when it reaches 0.20 mg potassium hy

per gram (KOH/gm) [21]. As with all others, this decision mu

based on one DGA test, but watch for a rising trend in the acid 

each year. Plan ahead and begin budget planning before the a

number reaches 0.20. 

7.3 Test for Oxygen Inhibitor 

In previous sections, the need to keep the transformer dry and 

was emphasized. Moisture is destructive to cellulose, and eve

so in the presence of oxygen. Some publications state that eac

you double the moisture (ppm), you halve the life of the transf

As was discussed, acids are formed that attack the insulation a

metals that form more acids, causing a viscous cycle. Oxygen 

inhibitor is a key to extending the life of transformers. The inh

currently used is ditertiary butyl paracresol (DBPC). This wor

similar to a sacrificial anode in grounding circuits. The oxyge

the inhibitor instead of the cellulose insulation. As this occurs 

transformer ages, the inhibitor is used up and needs to be repla

Replacement of the inhibitor also generally requires treatment 

oil [6]. The ideal amount of DBPC is 0.3% by total weight of 

(shown on the transformer nameplate) [30]. 

Test the inhibitor content with the DGA every 3 to 5 years. If 

inhibitor is 0.08%, the transformer is considered uninhibited, a

oxygen freely attacks the cellulose. If the inhibitor falls to 0.1

transformer should be re-inhibited. For example, if your trans

tested 0.1%, you need to go to 0.3% by adding 0.2% of the tot

weight of the transformer oil. The nameplate gives the weight 

for example, 5,000 pounds—so 5,000 pounds x 0.002 = 10 po

DBPC needs to be added. Adding a little too much DBPC doe

hurt the oil. Dissolve 10 pounds of DBPC in the transformer o

you have heated to the same temperature as the oil inside the 

transformer. It may take experimenting some to get the right a

of oil to dissolve the DBPC. Mix the oil and inhibitor in a cle
154 

container until all the DBPC is dissolved. Add this mixture to 

transformer, using the method given in the transformer’s instru

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 funct

critical to transformer insulation to have the proper amount of 

inhibitor. 

7.4 Power Factor 

Power factor indicates the dielectric loss (leakage current) of t

This test may be completed by the DGA laboratories. It may a

completed by Doble testing. A high power factor indicates 

deterioration and/or contamination by products, such as water

or other conducting particles; metal soaps caused by acids (for

mentioned above); attacking transformer metals; and products 

oxidation. The DGA labs normally test the power factor at 25 

100 oC. Doble information [25] indicates that the inservice lim

power factor is less than 0.5% at 25 oC. If the power factor is 

than 0.5% and less than 1.0%, further investigation is required

may require replacement or fullers earth filtering. If the powe

is greater than 1.0% at 25 oC, the oil may cause failure of the 

transformer; replacement or reclaiming is required. Above 2%

should be removed from service and replaced because equipm

failure is imminent. The oil cannot be reclaimed. 
7.5 Oxygen 

Oxygen must be watched closely in DGA tests. Many experts 

organizations, including EPRI, believe that oxygen levels in th

above 2,000 ppm greatly accelerate paper deterioration. This 

even more critical with moisture above safe levels. Under the 

temperature conditions, cellulose insulation in low oxygen oil 

10 times longer than insulation in high oxygen oil [6]. It is 

recommended that if oxygen reaches 10,000 ppm in the DGA, 

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 the

conservator and pressurized nitrogen is on top of the oil, expec

high nitrogen but not high oxygen. Oxygen comes only from 

and from deteriorating insulation. 

7.6 Furans 

When cellulose insulation decomposes due to overheating, org

compounds, in addition to CO2 and CO, are released and disso

in the oil. These chemical compounds are known as furanic 

compounds or furans. The most important one, for our purpos

2-furfuraldehyde. When DGAs are required, always request th

furans testing be completed by the laboratory to check for pap

deterioration. In healthy transformers, there are no detectable 

the oil, or they are less than 100 parts per billion (ppb). In cas

significant damage to paper insulation from heat has occurred

levels may be at least 100 ppb and up to 70,000 ppb. Furanic 

in the oil is especially helpful in estimating remaining life in th

insulation, particularly if several prior tests can be compared a

trends established. 

Use the furan numbers in table 18 for assessment; do not base 

evaluation on only one test; use several DGAs over a period o

develop trending. See An Introduction to the Half-Century 

Transformer by the Transformer Maintenance Institute, S.D. M

Co., 2002 [39]. The first column in table 18 is used for transfo
156 

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 Inte

58 51 800 100 

130 100 700 90 

292 195 600 79 

Norm

Rate 

654 381 500 66 

1,464 745 400 50 

1,720 852 380 46 

2,021 974 360 42 

Acce

Aging 

2,374 1,113 340 38 

2,789 1,273 320 33 

3,277 1,455 300 29 

Exces

Dang

3,851 1,664 280 24 

4,524 1,902 260 19 

High 

Failur

5,315 2,175 240 13 

6,245 2,487 220 7 

7,337 2,843 200 0 

End o

Life o

Insula

the Tr
with non-thermally upgraded paper, and the second column is 

transformers with thermally upgraded paper. 

Testing is completed for five different furans which are caused 

different problems. The five furans and their most common ca

listed below: 

♦ 5H2F (5-hydroxymethyl-2-furaldehyde) caused by oxidati

(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 

♦ 5M2F (5-methyl-2-furaldehyde) caused by local severe 

overheating (hotspot) 

Doble inservice limits are reproduced below to support the abo

recommended guidelines. 

Table 19 is excerpted from Doble Engineering Company’s Ref

Book on Insulating Liquids and Gases [25]. These Doble Oil 

tables support information given in prior sections and are show

as summary tables. 

Additional guidelines given in table 20 are useful. 
158 

Table 19 – Doble Limits for Inservice Oils 

Voltage Class 

# 69 kV 

>69 # 

288 kV 

Dielectric Breakdown Voltage, D 877, 

kV minimum 

26 30 

Dielectric Breakdown Voltage 

D 1816, .04-inch gap, kV, minimum 

20 20 

Power Factor at 25 °C, D 924, maximum 0.5 0.5 

Water Content, D 1533, ppm, maximum 2

35 225 

Interfacial Tension, D 971, dynes per 

centimeter (dynes/cm), minimum 

25 25 

Neutralization Number, D 974, mg KOH/gm, 

maximum 

0.2 0.15 

Visual Exam clear and 

bright 

clear and 

bright 

c

Soluble Sludge ND3

 ND3 

 1 D 877 test is not as sensitive to dissolved water as the D 1816 test an

not be used with oils for extra high-voltage (EHV) equipment. Dielectric br

tests do not replace specific tests for water content.. 

 2

 The use of absolute values of water-in-oil (ppm) do not always guaran

conditions in electrical apparatus. The percent by dry weight should be de

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 a

requirements for removing oil from service but to provide guidelines to aid 

determining when remedial action is most beneficial. Remedial action will 

depending upon the test results. Reconditioning of oil, that is, particulate r

(filtration) and drying, may be required if the dielectric breakdown voltage o

content do not meet these limits. Reclamation (clay filtration) or replaceme

oil may be required if test values for power factor, interfacial tension, neutr

number, or soluble sludge do not meet recommended limits. 
Table 20 – Additional Guidelines for Inservice Oils 

Power factor at 25 °C 

< 0.5% Acceptable 

> 0.5 < 1.0% Investigate, oil may require replacement 

treatment 

> 1.0 < 2.0% Investigate, oil may cause failure of the 

equipment, oil may require replacement o

treatment 

> 2.0% Remove from service, investigate, oil ma

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 

clay treat or 

replace in immediate future 

$0.15 < 0.5 $16 > 22 Clay treat or replace in immediate future 

$0.5 <16 Replace1

 1 When an oil is allowed to sludge in service, special treatment may be r

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 maximu

CO 20 ppm or less O2 inhibitor 0.3% by oil weight 

CO2 300 ppm or less 

O2 4,000 ppm or less 
160 

Dielectric strength, 

ASTM D1816-97, 

kV minimum, ≥ 69 kV 

> 69 to < 230 

kV 

230 kV 

and above 

1-mm1 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 c

most problems in getting an accurate DGA. There are times w

atmospheric gases, moisture, or hydrogen take a sudden leap f

DGA to the next. As has been mentioned, at these times, one 

immediately take another sample to confirm DGA values. It i

course, possible that the transformer has developed an atmosp

leak or that a fault has suddenly occurred inside. More often, 

sample has not been taken properly, or it has been contaminate

atmospheric gases or mishandled in other ways. The sample m

protected from all contamination, including atmospheric expo

Do not take samples from the small sample ports located on th

the large sample (drain) valves. These ports are too small to 

adequately flush the large valve and pipe nipple connected to t

in addition, air can be drawn past the threads and contaminate 

sample. Fluid in the valve and pipe nipple remain dormant du

operation and can be contaminated with moisture, microscopic 

packing particles, and other particles. The volume of oil in thi

location can also be contaminated with gases, especially hydro

Hydrogen is one of the easiest gases to form. With hot sun on 

of the transformer tank where the sample valve is located, high 

ambient temperature, high oil temperature, and captured oil in 

sample valve and extension, hydrogen formed will stay in this 

until a sample is drawn. 

The large sample (drain) valve can also be contaminated with 

hydrogen by galvanic action of dissimilar metals. Sample valv
usually brass; a brass pipe plug should be installed when the v

not being used. If a galvanized or black iron pipe plug is insta

brass valve, the dissimilar metals produce a thermocouple effe

circulating currents are produced. As a result, hydrogen is gen

in the void between the plug and valve gate. If the valve is no

thoroughly flushed, the DGA will show a high hydrogen level

Oil should not be sampled for DGA purposes when the transfo

at or below a freezing temperature. Test values which are affe

water (such as dielectric strength, power factor, and dissolved 

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. 

transformer is nitrogen blanketed, look at the pressure/vacuum 

If the pressure is positive, go ahead and take the sample. If th

pressure is negative, a vacuum exists at the top of the transform

there is a vacuum at the bottom, air will be pulled in when the 

valve is opened. Wait until the pressure gauge reads positive b

sampling. Pulling in a volume of air could be disastrous if 

transformer is energized.

If negative pressure (vacuum) is not too high, the weight of oi

will make positive pressure at the sample valve, and it will be 

take a sample. Oil head is about 2.9 feet (2 feet 10.8 inches) o

psi. If it is important to take the sample even with a vacuum s

at the top, proceed as described below. 

Use the sample tubing and adaptors described below to adapt t

sample valve to 1⁄8-inch tygon tubing. Fill a length (2 to 3 feet

tygon tubing with new transformer oil (no air bubbles) and att
162 

end to the pipe plug and the other end to the small valve. Ope

large sample (drain) valve a small amount and very slowly cra

the small valve. If oil in the tygon tubing moves toward the 

transformer, shut off the valves immediately. Do not allow 

be pulled into the transformer. If oil moves toward the tran

there is a vacuum at the sample valve. Wait until the pressure 

positive before taking the DGA sample. If oil is pushed out of 

tygon tubing into the waste container, there is a positive pressu

it is safe to proceed with DGA sampling. Shut off the valves a

configure the tubing and valves to take the sample per the inst

below. 

 7.7.1.1 DGA Oil Sample Container – Glass sample sy

are recommended. There are different containers, such as stai

steel vacuum bottles and others. Using only glass syringes is 

recommended. If there is a small leak in the sampling tubing 

connections, vacuum bottles will draw air into the sample, wh

cannot be seen inside the bottle. The sample will show high 

atmospheric gases and high moisture if the air is humid. Othe

contaminates such as suspended solids or free water cannot be 

inside the vacuum bottle. Glass syringes are the simplest to us

because air bubbles are easily seen and expelled. Other contam

are easily seen, and another sample can be immediately taken 

sample is contaminated. The downside is that glass syringes m

handled carefully and must be protected from direct sunlight. 

should be returned to their shipping container immediately aft

a sample. If they are exposed to sunlight for any time, hydrog

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 in

sample valve at the bottom of the transformer. Drill and tap th

plug for 1⁄8-inch national pipe thread, insert a 1⁄8-inch pipe nipp

if possible) and attach a small 1⁄8-inch valve for controlling the 
flow. Attach a 1⁄8-inch tygon tubing adaptor to the small valve 

Sizes of the piping and threads above do not matter; any arran

with a small sample valve and adaptor to 1⁄8-inch tygon tubing 

suffice. See figure 57. 

 7.7.1.2 Taking the Sample 

♦ Remove the existing pipe plug and inspect the valve openi

rust and debris. 

♦ Crack open the valve and allow just enough oil to flow int

waste container to flush the valve and threads. Close the v

wipe the threads and outlet with a clean dry cloth. 

♦ Re-open the valve slightly and flush approximately 1 quar

into the waste container. 

Figure 57 – Oil Sampling Piping. 
164 

♦ Install the brass pipe plug (described above) and associated 

pipe and small valve, and a short piece of new 1⁄8-inch tygo

to the outlet of the 1⁄8-inch valve. 

♦ Never use the same sample tubing on different transformer

is one way a sample can be contaminated and give false re

♦ Open both the large valve and small sample valve and allo

another quart to flush through the sampling apparatus. Clo

valves. Do this before attaching the glass sample syringe. 

sure the short piece of tygon tubing that will attach to the s

syringe is installed on the 1⁄8-inch valve before you do this

♦ Install the glass sample syringe on the short piece of 1⁄8-inc

tubing. Turn the stopcock handle on the syringe so that th

points toward the syringe. Note: The handle always poi

toward the closed port. The other two ports are open to e

other. See figure 58. 

♦ Open the large sample valve a small amount and adjust the 

valve so that a gentle flow goes through the flushing port o

glass syringe into the waste bucket. 

Figure 58 – Sampling Syringe (Flushing). 
♦ Slowly turn the syringe stopcock handle so that the handle 

to the flushing port (figure 59). This closes the flushing an

oil to flow into the sample syringe. Do not pull the syring

this will create a vacuum and allow bubbles to form. The 

handle (piston) should back out very slowly. If it moves to

adjust the small 1⁄8-inch valve until the syringe slows and h

hand on the back of the piston so you can control the trave

♦ Allow a small amount, about 10 cubic centimeters (cc), to 

into the syringe and turn the stopcock handle again so that 

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 fl

Allow the oil flow to continue into the waste bucket. 

♦ Hold the syringe vertical and turn the stopcock up so that t

handle points away from the syringe. Press the syringe pis

eject any air bubbles, but leave 1 or 2 cc of oil in the syrin

figure 60. 

CAUTION: 

Do not eject all the oil, or air will re-enter. 

Figure 59 – Sampling Syringe (Filling). 
166 

♦ Turn the stopcock handle toward the syringe. The small a

oil in the syringe should be free of bubbles and ready to re

sample. If there are still bubbles at the top, repeat the proc

you have a small amount of oil in the syringe with no bubb

♦ Reattach the tygon tubing. This will again allow oil to flow 

the flushing port. Slowly turn the stopcock handle toward 

flushing port which again will allow oil to fill the syringe. 

syringe piston will again back slowly out of the syringe. A

syringe to fill about 80% full. Hold the piston so you can 

movement at about 80% full. 

CAUTION: 

Do not pull the piston. This will cause bubbles to form. 

Figure 60 – Sample Syringe Bubble Removal. 
♦ Close the stopcock by turning the handle toward the syring

again will flow into the waste container. Shut off both val

remove the sampling apparatus, and reinstall the original p

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. D

allow sunlight to impact the container for any length of tim

Hydrogen will form and give false readings in the DGA. 

♦ Carefully package the syringe in the same manner that it w

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 bip

were discontinued. They are mainly used in transformers insi

buildings and are smaller than generator step-up transformers. 

Silicone oils have a higher fire point than mineral oils and, the

are used where fire concerns are more critical. As of this writ

there are no definitive published standards. IEEE has a guide, 

Doble has some service limits, but there are no standards. Info

below is taken from the IEEE publication, from Doble, from a

from IEC 60599 concepts, and from Delta X Research’s/Trans

Oil Analyst rules. Silicone oil dissolved gas analysis is in the 

beginning stage, and the suggested methods and limits below a
168 

subject to change as we gain more experience. However, in th

absence of any other methods and limits, use the ones below a

beginning. 

Silicone oils used in transformers are polydimethylsiloxane flu

which are different than mineral oils. Many of the gases gene

thermal and electrical faults are the same. The gases are gener

different proportions than with transformer mineral oils. Also

fault gases have different solubilities in silicone oils than in m

oils. Therefore, the same faults would produce different 

concentrations and different generation rates in silicone oils th

mineral oils. 

As with mineral oil-filled transformers, three principal causes 

generation are aging, thermal faults, and/or electrical faults res

deterioration of solid insulation and deterioration of silicone fl

Overheating of silicone oils causes degradation of fluid and ge

of gases. Generated gases depend on the amount of dissolved 

in the fluid, temperature, and how close bare copper conductor

the heating. When a transformer is new, silicone oil will typic

contain a lot of oxygen. Silicone transformers are typically se

pressurized with nitrogen. New silicone oil is not de-gassed; a

rule, oxygen concentration will be equivalent to oxygen solub

(maximum) in silicone. The silicone has been exposed to atm

for some time during manufacture of the transformer and man

and storage of silicone oil itself. Therefore, carbon monoxide 

carbon dioxide are easily formed and dissolved in the silicone 

the abundance of oxygen in the oil, resulting from this atmosp

exposure. In normal new silicone transformers (no faults), bo

monoxide and carbon dioxide will be generated in the initial y

operation. As the transformer ages and oxygen is depleted, ge

of these gases slows, and concentrations level off [27]. See fig

for the relationship of decreasing oxygen and increasing carbo

monoxide and carbon dioxide as a transformer ages. This curv

general information only and should not be taken to represent 
particular transformer. A real transformer with changes in loa

ambient temperatures, and various duty cycles would make th

curves look totally different. 

After the transformer is older (assuming no faults have occurr

oxygen concentration will reach equilibrium (figure 61). Reac

equilibrium may take a few years, depending on the size of the 

transformer, loading, ambient temperatures, etc. After this tim

oxygen, carbon monoxide, and carbon dioxide level off; and th

rate of production of these gases from normal aging should be 

relatively constant. If generation rates of these gases change g

(seen from the DGA), a fault has occurred, either thermal or e

Rate of generation of these gases and amounts can be used to r

determine what the fault is. Once you notice a significant incr

in rate of generation of any gas, it is a good idea to subtract th

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. 
170 

increase. This ensures that gases used in the diagnosis are onl

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 

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 fr

deterioration of paper from a fault condition? The only solutio

furan analysis. If the CO content is greater than the IEEE limi

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 occu

and is producing CO and small amounts of methane and hydro

fault may be masked by the normal production of CO from the 

oil itself. If the CO generation rate has greatly increased, alon

other gases, it becomes obvious that a fault has occurred. The 

analysis can only tell if the paper is involved (being heated) in 

fault. 

8.3 Comparison of Silicone Oil and Mineral Oil 

Transformers 

Some general conclusions can be drawn by comparing silicone 

mineral oil transformers. 

1. All silicone oil-filled transformers will have a great d

more CO than normal mineral oil-filled transformers

can come from two sources—the oil itself and from 

degradation of paper insulation. If the DGA shows l

other fault in gas generation besides CO, the only wa

for certain if CO is coming from paper degradation (

is to run a furan analysis with the DGA. If other faul

are also being generated in significant amounts, in ad

CO, there obviously is a fault, and CO is coming from 

degradation. 
2. There will generally be more hydrogen present than 

mineral oil-filled transformer. 

3. Due to “fault masking,” mentioned above, it is almos

impossible to diagnose what is going on inside a silic

filled transformer based solely on DGA. One except

that if acetylene is being generated, there is an active 

Look also at gas generation rates and operating histo

at loading history, through faults, and other incidents

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 a

electrical arc. The transformer should be removed fr

service. 

5. In general, oxygen in a silicone-filled transformer co

from atmospheric leaks or was present in the transfor

when it was new. This oxygen is consumed as CO a

are formed from the normal heating from operation o

transformer. 

6. Once the transformer has matured and the oxygen ha

off and remained relatively constant for two or more 

samples, if you see a sudden increase in oxygen, and 

carbon dioxide and nitrogen, the transformer has dev

leak. 

8.4 Gas Limits 

Table 21 shows IEEE limits [28], compared with Doble [27] i

of 299 operating transformers. The table of gases from the Do

study seems more realistic, showing gas level average of 95% 

transformers in the study. Note, with the last four gases, limit

by the IEEE (trial use guide) run over 70% higher than the Do

norms. But with the first three gases, hydrogen, methane, and 

the IEEE limits are well below the amount of gas found in 95% 
172 

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 b

the amount of gas found in normal operating transformers. Th

it is suggested that we use the Doble (95% norm) limits. The 

95% norm limit means that 95% of the silicone oil transforme

studied had gas levels below these limits. Obviously, 5% had 

higher than these limits. These are problem transformers that 

should pay more attention to. 

In table 22, the IEEE limits for L1 were chosen. For L2 limits

statistical analysis was applied, and two standard deviations w

added to L1 to obtain L2. For L3 limits, the L1 limits were do

Limits L1, L2, and L3 represent the concentration in individua

gases in ppm. G1 and G2 represent generation rates of individ

gases in ppm per month. To obtain G1 and G2 in ppm per day

divide the per month numbers by 30. Except for acetylene, G

10% of L1, and G2 is 50% of L1. The generation rates (G1, G

are points where our level of concern should increase, especia

when considered with the L1, L2, and L3 limits. At G2 gener

rate, we should be extremely concerned, reduce the DGA sam

interval accordingly, and perhaps plan an outage, etc. 
Table 22 – Suggested Levels of Concern (Limits) 

Gas 

L1 

(ppm) 

L2 

(ppm) 

L3 

(ppm) 

G1 

(ppm 

per month) 

G

(p

per m

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 15,00

TDCG 3,360 3,882 6,723 NA NA 

Except for acetylene, generation rate levels G1 and G2 were ta

from IEC 60599 [13] which is used with mineral oil transform

Any amount of ongoing acetylene generation means active 

inside the transformer. In this case, the transformer shoul

removed from service. These criteria were chosen because o

absence of any other criteria. As DGA criteria for silicone oil

becomes better known and the quantified table 22 will change 

reflect new information. 

As with mineral oil-filled transformers, gas generation rate

much more important than the amount of gas present. To

accumulated gas depends greatly on age (an older transformer 

more gas). If the rate of generation of any combustible gas sh

sudden increase in the DGA, immediately take another oil sam

confirm the gas generation rate increase. If the second DGA c

a generation rate increase, get some outside advice. Be carefu

generation rates increase somewhat with temperature variation

by increased loading and summer ambient temperatures. How

higher operating temperatures are also the most likely conditio

fault to occur. The real question is, has the increased gas gene
174 

rate been caused by a fault or increased temperature from grea

loading or higher ambient temperature? 

If gas generation rates are fairly constant (no big increases and 

than G1 limits above), what actions need to be taken if a trans

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 loadin

transformer cooling, get some outside advice, etc. As with mi

transformers, age exerts a big influence in accumulated gas. B

more concerned if a 3-year old transformer has exceeded the L

than if a 30-year old transformer exceeds the limits. However

G1 generation rates are exceeded in either an old or new trans

the level of concern should be stepped up. 

If accumulated gas exceeds the L2 limit, it may be wise to plan 

the transformer de-gassed. Examine the physical tests in the D

and compare them to the Doble/IEEE table (table 23) (Referen

on Insulating Liquids and Gasses) [25]. The oil should be trea

whatever manner is appropriate, if these limits are exceeded. 

If both L1 limits and G1 limits are exceeded, be more concern

Reduce sampling intervals, get outside advice, reduce loading

transformer cooling and oil levels, etc. If G2 generation limi

exceeded, be extremely concerned. It will not be long before 

L3 limits are exceeded, and consider removing the transforme

service for testing, repair, or replacement. 

If acetylene is being generated, the transformer should be 

out of service. However, as with mineral oil transformers, a o

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 

increasing, an active electrical arc is present within the 

transformer. It should be taken out of service. 
With critical silicone (or mineral oil-filled transformer), such a

single station service transformer or excitation transformer, a s

should be available at another facility. If there are no other po

spares, consider beginning the budget process for purchasing a 

transformer. 

8.5 Physical Test Limits 

Table 23 lists test limits for service-aged silicone filled transfo

If any of these limits are exceeded, treat the oil in whatever m

appropriate to return the oil to serviceable condition. 

Table 23 – Doble and IEEE Physical Test Limits for Service-Aged Silico

Test 

Acceptable 

Limits 

Unacceptable 

Values Indicate 

A

Test 

Visual Clear free of 

particles 

Particulates, 

free water 

D 15

D 21

Dielectric breakdown 

voltage 

30 kV Particulates, 

dissolved water 

D 87

Water content 

maximum 

70 ppm (Doble) 

100 ppm (IEEE) 

Dissolved water 

contamination 

D 15

Power factor 

maximum at 25 °C 

0.2 Polar/ionic 

contamination 

D 92

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 97

Note: If only one number appears, both Doble and IEEE have the same lim

If the above limits are exceeded in the DGA, the silicone oil sh

filtered, dried, or treated to correct the specific problem. 
176 

9. Transformer Testing 

Transformer testing falls into three broad categories: factory t

when the transformer is new or has been refurbished, acceptan

testing upon delivery, and field testing for maintenance and di

purposes. Some tests at the factory are common to most powe

transformers, but many of the factory tests are transformer-spe

Figure 68 (shown later in this manual) lists several tests. This 

chart has been adapted from IEEE 62-1995 reference [20]. No

the listed tests are performed at the factory, and not all of them 

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 D

indicates a poor connection, winding resistances should be che

Turns ratio, sweep frequency response analysis (SFRA), Dobl

or relay operations may give indications that dc testing is warr

Winding resistances are tested in the field to check for loose 

connections on bushings or tap changers, broken strands, and 

contact resistance in tap changers. Results are compared to ot

phases in wye-connected transformers or between pairs of term

a delta-connected winding to determine if a resistance is too h

Resistances can also be compared to the original factory meas

or to sister transformers. Agreement within 5% for any of the 

comparisons is considered satisfactory. If winding resistances 
be compared to factory values, resistance measurements will h

be converted to the reference temperature used at the factory (

75 °C). To do this, use the following formula: 

Rs = Resistance at the factory reference temperatu

(found in the transformer manual) 

Rm = Resistance you actually measured 

Ts = Factory reference temperature (usually 75 oC

Tm = Temperature at which you took the measurem

Tk = Constant for the particular metal the winding 

made from: 234.5 oC for copper, 225 oC for 

aluminum 

It is very difficult to determine actual winding temperatur

field; and, normally, this is not needed. The above temperat

corrections are necessary only if resistance is to be compared t

factory values. Normally, phase resistances are compared to e

other or to sister transformers at the same temperature, and act

winding temperatures and corrections are not needed. 

Compare winding resistances to factory values; change in thes

can reveal serious problems. A suggested method to obtain an 

accurate temperature is outlined below. If a transformer has ju

de-energized for testing, the winding will be cooler on the bot

the top, and the winding hot spot will be hotter than the top oil 

temperature. The average winding temperature is needed, and 

important to get the temperature as accurate as possible for 

comparisons. 

Tm Tk

Ts Tk Rs Rm

+

+ =
178 

The most accurate method is to allow the transformer to sit de

energized until temperatures are equalized. This test can reve

serious problems, so it’s worth the effort. 

Winding resistances are measured using a Wheatstone Bridge 

values of 1 ohm or above and using a micro-ohmmeter or Kelv

Bridge for values under 1 ohm. A multi-amp (now AVO) mak

good instrument for these measurements, which is quick and e

use. Take readings from the top of each bushing to neutral for 

connected windings and across each pair of bushings for delta

connected windings. If the neutral bushing is not available on 

connected windings, take each one to ground (if the neutral is 

grounded) or take readings between pairs of bushings as if it w

delta winding. Be consistent each time so that a proper compa

can be made. The tap changer can also be changed from conta

contact, and the contact resistance can be checked. Make sure 

the first test with the tap changer “as found.” Keep accurate re

and connection diagrams so that later measurements can be co

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 b

DGA. Key gases to look for are ethane and/or ethylene and po

methane. These gases may also be present if there is a poor 

connection at the bottom of a bushing or a bad tap changer con
Therefore, this test is only necessary if the winding resistance 

(section 9.1) shows all connections and tap changer contacts in 

condition. 

The intentional core ground must be disconnected. This may b

difficult, and some oil may have to be drained to accomplish t

some transformers, core grounds are brought outside through i

bushings and are easily accessed. A standard dc Megger® (1,0

Megger® is recommended) is then attached between the core g

lead (or the top of the core itself and the tank [ground]). The M

is used to place a dc voltage between these points, and the resi

is measured. A new transformer should read greater than 

1,000 megohms. A service-aged transformer should read grea

100 megohms. Ten to one-hundred megohms is indicative of 

deteriorating insulation between the core and ground. Less th

10 megohms is sufficient to cause destructive circulating curre

must be further investigated [20]. A solid, unintentional core 

may read zero ohms; this, of course, causes destructive circula

currents and must be corrected before energization. 

Some limited success has been obtained in “burning off” unint

core grounds using a dc or ac current source. This is a risky o

and the current may cause additional damage. The current sou

normally limited to a maximum of 40 to 50 amps and should b

increased slowly to use as little current as possible to accompl

task. This should only be used as a last resort and then only w

consultation from the manufacturer, if possible, and with other

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. 
180 

9.3 Doble Tests on Insulation 

Doble testing is important to determine the condition of a tran

because it can detect winding and bushing insulation integrity 

problems in the winding and core. Doble tests are conducted i

field on de-energized transformers using special test equipmen

Generally, a Doble M-4000 test set is used along with accomp

software. The software automatically performs analysis of tes

and responds with a four letter code: G = Good, I = Investigat

Deteriorated, and B = Bad. These codes refer to insulation qu

a “D” or “B” code is encountered, the insulation should be re-

carefully investigated, and the problem explained before re-en

Other tests may have to be performed; and, perhaps, an interna

inspection should be considered before the unit is re-energized

Doble Company should be consulted, along with the transform

manufacturer, and other transformer experts. If the problem is 

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 

windings and insulation system and to determine a power fact

overall insulation, including bushings, oil, and windings. It is 

measure of the ratio of the power (I2

R) losses to the voltamper

applied during the test. The power factor obtained is a measur

watts lost in the total transformer insulation system, including 

bushings. The power factor should not exceed 0.5% at 20 EC. 

Temperature correction of test results can be performed autom

on the Doble test set. The watts lost should not exceed one-ha

percent of the total power input (voltamperes) from the test. T

values obtained at each test are compared to previous tests and 

baseline factory tests, and a trend can be established as the ins

system ages. 

9.3.2 Capacitance Test 

This test measures and records the capacitance (including bush

between the high and low-voltage windings, between the high

winding and the tank (ground), and between the low-voltage w
and the tank (ground). Changes in these values as the transfor

and events occur, such as nearby lightning strikes or through f

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 sh

changer problems, and other possible core and winding proble

three-phase transformers, results are also compared between p

This test measures current needed to magnetize the core and g

the magnetic field in the windings. Doble software only gives 

indications on this test: “G” for good and “Q” for questionable

three-phase, wye/delta or delta/wye transformer test, the excita

current pattern will be two phases higher than the remaining p

Compare the two higher currents only. If the excitation curren

than 50 milliamps (mA), the difference between the two highe

currents should be less than 10%. If the excitation current is m

50 mA, the difference should be less than 5%. In general, if th

internal problem, these differences will be greater. When this 

happens, other tests should also show abnormalities, and an in

inspection should be considered. The results, as with all other

be compared with factory and prior field tests. 
182 

9.3.4 Bushing Tests 

For bushings that have a potential tap, both the capacitance be

the top of the bushing and the bottom tap (normally called C1)

capacitance between the tap and ground (normally called C2) 

measured. To determine bushing losses, power factor tests are 

performed. C2 capacitance is much greater than C1. Bushing

without a potential tap are normally tested from the bushing to

conductor to ground and Ahot collar@ tests. These test results a

compared with factory tests and/or prior tests to determine 

deterioration. About 90% of bushing failures may be attribute

moisture ingress, evidenced by an increasing power factor from 

testing on a scheduled basis. 

9.3.5 Percent Impedance/Leakage Reactance Test 

This is normally an acceptance test to see that nameplate perce

impedance agrees with the measured percent impedance when 

transformer arrives onsite. Normally, a 3% difference is consi

acceptable. However, after the initial benchmark test, the perc

impedance should not vary more than 2% from benchmark. A

transformer ages or suffers events such as through faults, near

lightning strikes, and other surges, this test is used in the field 

winding deformation. Winding deformation can lead to imme

transformer failure after a severe through fault, or a small defo

can lead to a failure years later. 

Percent impedance/leakage reactance testing is performed by s

circuiting the low-voltage winding and applying a test voltage 

high-voltage winding. Reluctance is resistance to lines of mag

flux. Reluctance to the magnetic flux is very high in spaces be

the high- and low-voltage windings and spaces between the w

and core. Reluctance is very low through the magnetic core so 

vast majority of total reluctance is in the spaces. When windin

movement (distortion) occurs, these spaces change. Therefore

reluctance changes, resulting in a change in the measured leak

reactance. Changes in leakage reactance and in capacitance te

(explained in section 9.3.2) serve as an excellent indicator of w
movement and structural problems (displaced wedging, etc.). 

does not replace excitation current tests or capacitance tests bu

complement them, and they are used together. The excitation 

test relies on reluctance of the core while the leakage reactanc

relies on reluctance of the spaces. See Doble’s Leakage React

Instrument Users Guide, and IEEE®, Guide for Diagnostic Fi

Testing of Electric Power Apparatus-Part 1: Oil-Filled Powe

Transformers, Regulators, and Reactors (IEEE 62-1995TM [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 

transformer and are valuable to determine if any damage has o

during shipping or during a through fault. Core grounds, core 

displacement, and other core and winding problems can be rev

this test. 

These tests should be conducted before and after the transform

been moved or after experiencing a through fault. Results sho

compared to baseline tests performed at the factory or as soon 

possible after receiving the transformer. If the SFRA tests can

performed at the factory, they should be conducted as an accep

test before energizing a new or rebuilt transformer to establish 

baseline. A baseline should be established for older inservice 

transformers during a normal Doble test cycle. If possible, on

use the same test equipment for baseline and following tests, o

results may not be comparable. 
184 

For a delta/wye transformer, a test voltage of variable frequen

(normally 20 hertz [Hz] to 2 megahertz [MHz]) is placed acro

phase of the high-voltage winding. With this set of tests, low-

windings are isolated with no connections on any of the bushin

additional set of tests is performed by short circuiting all the lo

voltage windings and again placing the test voltage on each ph

the high-voltage winding. A third set of tests is made by isola

high-voltage winding and placing the test voltage across each 

voltage winding. See the M5100 SFRA Instrument Users Guid

Doble Engineering Company [36] for connection details. 

Figure 62 is a picture of test traces on a new three-phase Recla

transformer. The top three traces were taken on the low-volta

X1-X3, X2-X1, and X3-X2. The two outside windings (A and 

phases) have the same general shape with a “W” at the lowest 

the trace, while the inside winding (B phase) has a “V” at the b

The high-voltage traces (lower three) have the same characteri

Note that, in both high- and low-voltage tests, the traces fall al

Figure 62 – SFRA Test Traces of a New Transformer. 
perfectly on top of each other for the outside windings (A and 

while the inside winding (B phase), is slightly displaced to the 

These are characteristic traces of a three-phase transformer in 

condition; these traces will be the baseline for future tests on t

transformer. 

By comparing future traces with baseline traces, the following 

noted. In general, the traces will change shape and be distorte

low frequency range (under 5,000 Hz) if there is a core proble

traces will be distorted and change shape in higher frequencies 

10,000 Hz) if there is a winding problem. Changes of less tha

3 decibels (dB) compared to baseline traces are normal and wi

tolerances. From 5 Hz to 2 kilohertz (kHz), changes of + or – 

more) can indicate shorted turns, open circuit, residual magnet

core movement. From 50 Hz to 20 kHz +/- 3 dB (or more), a 

from baseline can indicate bulk movement of windings relativ

other. From 500 Hz to 2 MHz, changes of +/- 3 dB (or more) 

indicate deformation within a winding. From 25 Hz to 10 MH

changes of +/- 3 dB (or more) can indicate problems with win

leads and/or test leads placement. The above diagnostics com

the Euro-Doble Client Committee after much testing experien

analysis. Note that there is a great deal of overlap in frequenc

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 use

illustration only. The traces have the same general positions o

graph as the good transformer. The lower traces are high-volt

winding tests, while the upper traces are the low-voltage wind

Note in the higher frequencies of the low-voltage traces that “A

(X1-X0 green trace) is displaced from the other two phases m

3 dB from about 4 kHz to about 50 kHz. With a healthy trans

these would fall almost on top of each other as the other two p

do. Also notice that “A” phase (H1-H3 Lsh) is displaced in th

with the low-voltage winding shorted. There is an obvious pro

with “A” phase on the low-voltage side. After opening the 
186 

transformer, it was found that the “A” phase winding lead had 

off near the winding connection and re-welded itself on the wi

a different location, effectively shorting out a few turns. The 

transformer was still working, but hot metal gases (ethylene, e

methane) were actively generating and showing up in the DGA

Although other tests could have revealed this problem, SFRA 

the problem was with “A” phase and, therefore, where to conc

the internal inspection. 

9.4 Visual Inspection 

9.4.1 Background 

Visual inspection of the transformer exterior reveals importan

condition information. For example, valves positioned incorre

plugged radiators, stuck temperature indicator and level gauge

noisy oil pumps or fans. Oil leaks can often be seen which ind

Figure 63 – SFRA Test Traces of a Defective New Transformer. 
potential for oil contamination, loss of insulation, or environm

problems. Physical inspection requires staff experienced in th

techniques. There are several required physical inspections th

not be covered here because they were addressed previously. 

to inspect the following as explained in each respective section

winding temperature indicators (section 4.3), pressure relief de

(section 4.5), sudden pressure relay (section 4.6), conservator 

(section 4.9.2.9), conservator breather (section 4.9.2.9.2), and 

failure relay (section 4.9.2.9.3). 

9.4.2 Oil Leaks 

Check the entire transformer for oil leaks. Leaks develop due 

gaskets wearing out, ultraviolet exposure, taking a “set,” or fro

expansion and contraction, especially after transformers have 

due to thermal shrinkage of gaskets and flanges. Many leaks c

repaired by applying an epoxy or other patch. Flange leaks m

stopped with these methods, using rubberized epoxy forced in

flange under pressure. Very small leaks in welds and tanks m

stopped by peening with a ball-peen hammer, cleaning with th

solvent, and applying a “patch” of the correct epoxy. Experien

leak mitigation contractors whose work is guaranteed may also 

employed. Some leaks may have to be welded. Welding may 

performed with oil in the transformer if an experienced, qualif

knowledgeable welder is available. If welding with oil in the 

the method chosen, oil samples must be taken for DGA, both b

and after welding. Welding may cause gases to appear in the D

and it must be determined what gases are attributed to welding 

which ones to transformer operation. See also EPRI’s Guideli

the Life Extension of Substations, 2000 and 2002 update [5] se

“Transformers Leak Mitigation” that gives several materials a

applications to stop transformer oil leaks. Copies of this docu

available at the Technical Service Center. 

9.4.3 Oil Pumps 

If the transformer has oil pumps, check the flow indicators and 

isolation valves to ensure that oil is circulating properly. Pum
188 

motor(s) may also have reversed rotation, and flow indicators 

show that oil is flowing. To ensure motors are turning in the p

direction, use an ammeter to check the motor current. Compa

with the full-load-current indicated on the motor nameplate. I

motor is reversed, the current will be much less than the name

full-load-current. Check oil pumps with a vibration analyzer i

develop unusual noises. Have the DGA lab check for dissolve

in the oil and run a metal particle count for metals, if the beari

suspect. This should be performed as soon as a bearing becom

suspect; bad oil pump bearings can put enough metal particles 

oil to threaten transformer insulation and cause flashover insid

tank, resulting in an explosive catastrophic failure of the transf

tank. 

9.4.4 Fans and Radiators 

Inspect all isolation valves at the tops and bottoms of radiators 

ensure they are open. Inspect cooling fans and radiators for 

cleanliness and fans for proper rotation. Check for dirty or da

fan blades or partially blocked radiators. Fans are much more 

if the blades are clean and rotating in cool air. Normally, fans 

cool air through the radiators; they should not be pulling air th

Check to see if fans are reversed electrically (i.e., pulling air fi

through the radiators and then through the fan blades). This m

that the blades are rotating in warm air after it passes through 

radiator, which is much less efficient. Place a hand on the rad

opposite the fans; air should be coming out of the radiator aga

hand. Watch the blades as they rotate slowly when they are st

stopping to determine which way they should be rotating and c

the rotation if necessary. See IEEE 62-1995TM [20]. Also insp

radiators and fans with an infrared camera, see section 9.4.6, “

Temperature Analysis.” 

9.4.5 Age 

Transformer age is an important factor to consider when ident

candidates for replacement or rehabilitation. Age is one indica

remaining life and upgrade potential to current state-of-the art 
materials. During transformer life, structural strength and insu

properties of materials used for support and electrical insulatio

(especially paper) deteriorate. Although actual service life var

widely depending on the manufacturer, design, quality of asse

materials used, maintenance, and operating conditions, the exp

life of a transformer is about 40 years (Replacements, July 199

Bureau of Reclamation and Western Area Power Administrati

9.4.6 Infrared Temperature Analysis 

Infrared analysis should be conducted annually while equipme

energized and under full load, if possible. IR analysis should 

conducted after any maintenance or testing to see if connection

were broken were re-made properly. Also, if IR is performed 

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 patte

transformer tanks indicate problems inside the transformer, su

low oil level, circulating stray currents, blocked cooling, loose 

tap changer problems, etc. Infrared scanning and analysis is re

annually for trending purposes by National Fire Protection As

70B, Recommended Practice for Electrical Equipment Mainte

[8] and FIST Volume 4-1B [37]. See also FIST Volume 4-13 [

IEEE 62-1995TM [20]. Abnormally high temperatures can dam

destroy transformer insulation and, thus, reduce life expectanc

Thermal patterns of transformer tanks and radiators should be 

the bottom and gradually warmer ascending to the top. See fig

for a normal pattern; the red spot at the top is normal showing 

spot” top of B phase, about 110 degrees Fahrenheit (°F). Any 

departure from this pattern means a probable problem which m

investigated. An IR inspection can find over-heating condition

incorrect thermal patterns. IR scanning and analysis requires t

staff, experienced in these techniques. 
190 

9.4.8 IR for Surge Arresters 

Surge arresters should be included when infrared scanning ene

transformers. Look for unusual thermal patterns on the surfac

lightning arresters (see the arrester IR image in figure 65). No

the yellow in the top right of the image is a reflection not asso

with the arrester. A temperature profile of the arrester is show

black lines. Note the hot spot (yellow) about a third of the wa

from the top. This indicates that immediate de-energization 

and replacement must be undertaken. Catastrophic failure is i

which can destroy nearby equipment and be hazardous to wor

Also compare thermal patterns to sister units or earlier scans o

same arrester. Scan all high-voltage connections and compare 

nearby connections for unusual temperatures. 

9.4.9 IR for Bushings 

IR scans of bushings can show low oil levels which would cal

immediate de-energization and replacement. This generally m

that the seal in the bushing bottom has failed, leaking oil into t

transformer. The top seal has probably also failed, allowing a

the bushing. Another reason a bushing can exhibit a high oil l

*>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. 
is that the top seal is leaking, allowing water to enter. The 

water migrates to the bushing bottom, displacing the oil upwar

Remember, over 90% of bushing failures are attributed to wat

entrance through the top seal. Bushings commonly fail 

catastrophically, many times destroying the host transformer o

breaker and nearby equipment and causing hazards to workers

Figure 66 shows low-oil level in a high-voltage transformer bu

Compare previous IR scans of the same bushing with the curre

Doble hot-collar testing possibly may show this problem. How

Doble tests are run infrequently, and the transformer has to be 

service, under clearance, and both primary and secondary cond

removed, while an IR scan easily can be performed at any tim

9.4.10 IR for Radiators and Cooling Systems 

Examine radiators with an IR camera and compare them with 

other. A cool radiator or segment indicates that a valve is clos

radiator or segment is plugged. The IR image (figure 67) show

the cold left radiator section is valved off or plugged. If visua

inspection shows the valves are open, the radiator or segment 

23.4

32.2

*>35.0°C Lightning Arrestor

*<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. 
192 

*>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. 
isolated, drained, removed, and the blockage cleared. Do not 

transformer to operate with reduced cooling which drastically 

transformer life. Remember, an increased operating temperatu

only 8 to 10 °C will reduce transformer life by one-half. IR sc

cooling systems, including heat exchangers, fans, pumps, mot

Check inside control panels for overloaded wiring, loose conn

and overheated relays. Look for unusual thermal patterns and 

similar equipment. 

9.4.11 Corona Scope Scan 

With the transformer energized, scan the bushings and surge a

and all high-voltage connections for unusual corona patterns. 

should be visible only at the top of bushings and arresters, and 

at connections should be similar to sister connections. As a bu

deteriorates due to physical defects, the corona pattern will gro

progressively larger. When the corona pattern reaches a groun

surface (i.e., the tank or structure), a flashover will occur, dest

the bushing or arrester and, perhaps, the transformer. The cor

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 ma

in the DGA. High hydrogen generation indicates partial disch

occurring inside the transformer. Other gases such as methane

and ethylene may also be increasing. Acetylene may also be p

if arcing is occurring, and may also be increasing. Ultrasonic 

(in contact with the tank) fault detection can detect partial disc

(corona) and full discharge (arcing) inside the transformer. Th

can also detect loose parts inside the transformer. Partial disch

emit energy in the order of 20 kHz to 200 kHz. These frequen

above levels that can be audibly detected. The test equipment 

the signals and converts them electronically into audible signa

Headphones are provided to eliminate spurious noise from the 
194 

powerplant and other sources. The equipment logs data for fu

reference. A baseline test should be conducted and compared 

future test data. This test method has some limitations; if a pa

discharge is located deep within the windings, external detecto

not be sensitive enough to detect and locate the problem. How

partial discharges most often occur near the top of the transfor

areas of high-voltage stress which can readily be located by th

method. These defects can sometimes be easily remedied, ext

transformer service life. 

9.5.2 Process 

Magnetic piezoelectric crystal transducers, sized and tuned to 

appropriate frequencies, are placed on the outside of the tank, 

signals are recorded. If discharges are detected, the location is 

triangulated so that, during an internal inspection, the inspecto

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 Sub

[5], section 3. See also IEEE 62-1995TM [20], section 6.1.8.4. 

9.6 Vibration Analysis 

9.6.1 Background 

Vibration analysis by itself cannot predict many faults associa

transformers, but it is another useful tool to help determine tra

condition. Vibration can result from loose transformer core se

loose windings, shield problems, loose parts, or bad bearings o

oil cooling pumps or fans. Exercise extreme care in evaluatin

the source of vibration. Many times, a loose panel cover, door

or bolts/screws lying in control panels, or loose on the outside 

been misdiagnosed as problems inside the tank. There are sev

instruments available from various manufacturers, and the tech

is advancing quickly. Every transformer is different; therefore
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 n

two times line frequency (120 Hz) and also appears as multipl

two times line frequency; that is, four times 60 (240 Hz), six t

(360 Hz), etc. The 120 Hz is always the largest and has an am

of less than 0.5 inch per second (ips) and greater than 0.1 ips. 

next peak of interest is the four times line frequency or 240 Hz

amplitude of this peak should not exceed 0.5 ips. None of the 

remaining harmonic peaks should exceed 0.15 ips in amplitud

EPRI’s Proceedings: Substation Equipment Diagnostics, Con

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 

DGA, Doble testing, or relay operation. The turns ratio test de

shorted turns, which indicate insulation failure by determining 

correct turns ratio exists. Shorted turns may result from short 

or dielectric (insulation) failures. 

9.7.2 Process 

Measurements are taken by applying a known low voltage acr

winding and measuring the induced-voltage on the correspond

winding. The low voltage is normally applied across a high-v

winding so that the induced-voltage is lower, reducing hazards 

performing the test. The voltage ratio obtained by the test is c

to the nameplate voltage ratio. The ratio obtained from the fie

should agree with the factory within 0.5%. New transformers 

quality normally compare to the nameplate within 0.1%. 

For three-phase delta/wye or wye/delta connected transformer

three-phase equivalency test should be performed. The test is 
196 

performed and calculated across corresponding single winding

at the nameplate phasor diagram to find out what winding on t

primary corresponds to a particular winding on the secondary. 

Calculate the ratio of each three-phase winding based on the li

neutral voltage of the wye winding. Divide the line-to-line wi

voltage by 1.732 to obtain the correct line-to-neutral voltage. 

the tap changer position to make sure it is set at the position w

nameplate voltage is based. Otherwise, the turns ratio test info

cannot be compared with the nameplate. Nameplate informati

Reclamation transformers is normally based on the tap three p

of the tap changer. See the manufacturer’s instruction manual 

specific turns ratio tester for details. See IEEE 62-1995TM [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 C57.104TM Guide for the Interpretation of Gas

Generated in Oil-Immersed Transformers [12] gives status co

based on accumulated values of CO2 and CO. Accumulated d

gas levels provide four status conditions: normal operation, m

concern (investigate), major concern (more investigation), and 

imminent risk (nearing failure). The CO2 and CO levels in pp

each status are given in table 24. 

9.8.2 CO2 /CO Ratio 

The CO2/CO ratio should also be analyzed in conjunction with 

CO2 and CO accumulated values. For analyzing the CO2/CO 

section 6.1.10. 
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 –57

Condition 3 Major Concern 4,001 – 10,000 571 – 1,4

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 I

Inspection) 

9.9.1 Degree of Polymerization (DP) 

Do not open a transformer for the sole purpose of doing this te

Perform this test only if the unit is being opened for other reas

the reasons for an internal inspection in section 9.9.2. 

 9.9.1.1 Background – One of the most dependable me

determining paper deterioration and remaining life is the DP te

cellulose. The cellulose molecule is made up of a long chain o

glucose rings which form the mechanical strength of the mole

the paper. DP is the average number of these rings in the mol
198 

As paper ages or deteriorates from heat, acids, oxygen, and wa

number of these rings decreases. When the insulation is new, 

is typically between 1,000 and 1,400. As paper deteriorates, b

between the rings begin to break. When the DP reaches aroun

the insulation has reached the end of life. All mechanical stren

the insulation has been lost; the transformer must be replaced. 

 9.9.1.2 Process – When doing an internal inspection, o

transformer is opened and oil is fully or partially drained for a

reason on a service-aged transformer, perform a DP test. Rem

sample of the paper insulation about 1 centimeter square from 

convenient location near the top of the center phase with a pai

tweezers. In general, in a three-phase transformer, the hottest 

thermally aged paper will be at the top of the center phase. If 

possible to take a sample from the center phase, take a sample 

top of one of the other phases. Send this sample to an oil testi

laboratory for the DP test. Analyze results of the DP test with 

taken from EPRI’s Guidelines for the Life Extension of Substa

2002 Update, chapter 3 [5]. Table 25 has been developed by E

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 abso

necessary, it must be completed by an experienced person who 

exactly what to look for and where to look. Many times, more 

is done by opening a transformer and doing an internal inspect

what is gained. There are very few reasons for an internal insp

some are shown below: 
♦ Extensive testing shows serious problems. 

♦ Unexplained relay operation takes the transformer offline, 

testing is inconclusive. 

♦ Acetylene is being generated in the DGA (indicates active 

arcing). 

♦ Ethylene and ethane are being generated in sufficient quan

cause grave concern. This generally indicates a bad conne

a bushing bottom or tap changer, circulating currents, addi

core ground, or static discharges. 

♦ A core ground must be repaired, or an additional core grou

developed which must be removed. 

♦ Vibration and ultrasonic analysis indicate loose windings t

generating gases from heat caused by friction of the vibrat

loose wedges must be located and replaced. 

♦ CO2/CO ratio are very low (around 2 or 3), indicating seve

deterioration from overheating. Cooling must be checked 

before opening the transformer. 

♦ Furans are high (see section 7.6), indicating excessive agin

DP test must be completed. 

♦ The metal particle count is above 5,000 in 10 milliliters of 

taken specifically for detecting metal particle count. (See 

Guidelines for the Life Extension of Substations, 2002 Upd

for exact procedures for detecting and correcting metal par

contamination). 
200 

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 h

developed for internal transformer inspections using a specific

designed borescope. The borescope can be used with oil insid

transformer; core, windings, connections, etc., can be examine

photographed. If it is necessary to go inside the transformer fo

repairs, workers will possibly know exactly what is defective 

exactly what must be done. This technology, used properly, c

generating time and repair dollars. 

Currently, this technology is available only as a contracting se

However, plans are being made by the developing company to 

the instrument available for sale. 

9.10 Transformer Operating History 

One of the most important transformer diagnostic tools is the o

history, including temperatures, overload history (especially th

faults), relay operations, and nearby lightning strikes. Many ti

a through fault or nearby lightning strike will generate acetyle

or ethylene and other gases, and these will remain in future DG

Through faults (i.e., where fault current passes through the 

windings) subject a transformer to severe electrical and mecha

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 l

cooling will degrade insulation. The damage may not be imm

evident but can show up years later. Through faults, overload 
and temperatures should be in operations records, and a review 

these is required when diagnosing a transformer problem. 

9.11 Transformer Diagnostics/Condition Assessmen

Summary 

A summary of diagnostic techniques is given below in table 2

Table 26 – Reclamation Transformer Condition Assessment Summar

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 – 

Analyzer with softw

Morgan Schaffer P2

Transformer Oil Ana

software). Note: th

does not measure o

and nitrogen. 

Or send to an oil tes

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 

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, b

for bushing, and ligh

arrester porcelain c

loose bolts. 

Infrared Scan Hot spots, localized heating, bad 

connections, circulating currents, 

blocked cooling, tap changer 

problems, bushing and lightning 

arrester problems. 

Trained and experie

with thermographic 

and analysis softwa
202 

Table 26 – Reclamation Transformer Condition Assessment Summar

(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 d

logger.1

Ultrasonic NonContact and 

Contact Fault 

Detection 

Nitrogen leaks, vacuum leaks, 

corona at bushings, pump 

mechanical and bearing 

problems, cooling fan problems. 

Ultrasonic probe an

(e.g., UltraProbe 20

Vibration 

Analysis 

Internal core, shield problems. 

Loose parts vibration. 

Vibration data logge

External 

Temperatures 

(Main Tank) 

Temperature monitoring with 

changes in load and ambient 

temperature. 

Portable temperatu

loggers and softwar

Sound Level Internal and external noises to 

compare to baseline and other 

vibration tests. 

Sound level meter1

 

Quest 2400 Sound 

Corona Compare bushings and lightning 

arresters and all high-voltage 

connections with sister units. 

Corona Scope,1

 Mo

01-A. 

Offline Tests 

Doble Power 

Factor 

Loss of winding insulation 

integrity. Loss of bushing 

insulation integrity. Winding 

moisture. 

Doble test equipme

Excitation 

Current 

Shorted turns in the windings. Doble test equipme

Turns Ratio Shorted windings. Turns ratio tester (e

Biddle 55005). 

Leakage 

Reactance 

Measures percent impedance, to 

be compared to nameplate after 

moving or through fault. 

Doble test equipme
Table 26 – Reclamation Transformer Condition Assessment Summar

(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 swee

frequency response 

Across Winding 

Resistance 

Measurements 

Broken strands, loose 

connections, bad contacts in tap 

changer. 

Wheatstone Bridge 

and greater). 

Kelvin Bridge (less 

ohm). 

Winding DC 

Resistance to 

Ground 

Winding low resistance to ground 

(leakage current). 

Megger®.1

Core to Ground 

Resistance2 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, m

meter and/or 

Foster Miller boresc

Degree of 

Polymerization 

Insulation condition (life 

expectancy). 

Laboratory analysis 

sample. 

 1

 This equipment is available from the Hydroelectric Research and Tec

Services Group. 

 2 External test may be possible depending on transformer construction
204 

Figure 68 – Transformer Diagnostic Test Chart 

(Adapted from IEEE 62-1995TM [20]). 
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 und

assessment program. Transformer failure can have a significa

economic impact due to long lead times in procurement, 

manufacturing, and installation, in addition to high equipment 

According to the Electric Power Research Institute (EPRI): 

“Extending the useful life of power transformers is the single m

important strategy for increasing life of power transmission an

distribution infrastructures starting with generator step-up tran

(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 pro

process for developing at a Transformer Condition Index. Thi

condition index may be used as an input to the risk-and-econo

analysis computer model where it adjusts transformer life exp

curves. The output of the economic analysis is a set of alterna

scenarios, including costs and benefits, intended for managem

decisions on replacement or rehabilitation. 

2. Scope/Application 

The transformer condition assessment methodology outlined i

chapter applies to oil-filled power transformers (> 500 kilovol

[kVA]) currently in operation. 
206 

This guide is not intended to define transformer maintenance p

or describe transformer condition assessment inspections, tests

measurements in detail. Utility maintenance policies and proc

must be consulted for such information. 

3. Condition Indicators and Transformer 

Condition Index 

This guide describes four Condition Indicators generally regar

hydro powerplant engineers as a sound basis for assessing tran

condition. 

♦ Insulating oil analysis (dissolved gas analysis [DGA] and 

♦ 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 th

of time. The indicators are expressed in numerical terms and a

to arrive at an overall Transformer Condition Index. 

The guide also describes a “toolbox” of Tier 2 inspections, tes

measurements that may be applied, depending on the specific 

being addressed. Results of Tier 2 may modify the score of th

Transformer Condition Index. 

After review by a transformer expert, the Transformer Conditi

is suitable for use as an input to the risk and economic analysi
4. Inspections, Testing, and Measurements 

The hierarchy of inspections, tests, and measurements is illust

figure A-1, Transformer Condition Assessment Methodology. 

Table A-14, Transformer Condition Assessment Summary (la

this appendix), summarizes these activities. 

Inspections, tests, and measurements (“tests”) performed to de

transformer condition are divided into two tiers (or levels). Ti

are those that are routinely accomplished as part of normal O&

are readily discernible by examination of existing data. Resul

Tier 1 tests are quantified below as Condition Indicator Scores 

weighted and summed to arrive at a Transformer Condition In

Tier 1 tests may indicate abnormal conditions that can be reso

with standard corrective maintenance solutions. Tier 1 test res

also indicate the need for additional investigation, categorized 

Tier 2 tests. 

Tier 2 tests are considered nonroutine. Tier 2 test results may 

the Transformer Condition Index established using Tier 1 tests 

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, an

measurements are conducted and analyzed by staff suitably tra

experienced in transformer diagnostics. More basic tests may 

performed by qualified staff who are competent in these routin

procedures. More complex inspections and measurements ma

a transformer diagnostics “expert.” 

This guide also assumes that inspections, tests, and measurem

conducted on a frequency that provides accurate and current 
208 

Figure A-1 – Transformer Condition Assessment Methodology. 
information needed by the assessment. In some cases, it may 

necessary to conduct tests prior to this assessment to acquire c

data. 

Transformer condition assessment may cause concern that jus

more frequent monitoring. Utilities should consider the possib

taking more frequent measurements (e.g., oil samples) or insta

online monitoring systems (e.g., gas-in-oil) that will continuou

track critical quantities. This will provide additional data for c

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 subjecti

relying on transformer condition experts. Relative terms such 

“results normal” and “degradation” refer to results that are com

to: 

♦ Industry accepted levels 

♦ Baseline or previous (acceptable) levels on this equipment 

♦ Equipment of similar design, construction, or age that oper

similar environment 
210 

6. Weighting Factors 

Weighting factors used in the condition assessment methodolo

recognize that some Condition Indicators affect the Transform

Condition Index to a greater or lesser degree than other indica

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 descr

this chapter cannot quantify all factors that affect individual 

transformer condition. It is important that the Transformer Co

Index be scrutinized by engineering experts. Mitigating factor

specific to the utility may determine the final Transformer Con

Index and the final decision on transformer replacement or 

rehabilitation. 

8. Documentation 

Substantiating documentation is essential to support findings o

assessment, particularly where a Tier 1 Condition Indicator sc

less than 3 or a Tier 2 test results in subtractions from the Tran

Condition Index. Test results and reports, photographs, O&M 

or other documentation should accompany the Transformer Co

Assessment Summary Form. 

9. Condition Assessment Methodology 

The condition assessment methodology consists of analyzing e

Condition Indicator individually to arrive at a Condition Indic

Score; then the score is weighted and summed with scores from 
condition indicators. The sum is the Transformer Condition In

Apply the Condition Index to the Alternatives table to determi

recommended course of action. 

Reasonable efforts should be made to perform Tier 1 inspectio

and measurements. However, when data is missing, to proper

the Condition Indicator, it may be assumed that the score is “G

a mid-range number such as 2. 

CAUTION: 

This strategy should be used judiciously to prevent deceptive 

results. 

10. Tier 1 – Inspections, Tests, Measurement

Tier 1 inspections, tests, and measurements routinely accompl

part of normal O&M are readily discernible by examination of 

data. Tier 1 test results are quantified below as Condition Indi

that are weighted and summed to arrive at a Transformer Cond

Index. Tier 1 inspections, tests, and measurements may indica

abnormal conditions that can be resolved with standard correc

maintenance solutions. Tier 1 test results may also indicate th

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 determin

condition of a transformer because, being performed more freq

than other tests, it may be the first indication of a problem. In

oil analysis can identify internal arcing, bad electrical contacts

spots, partial discharge, or overheating of conductors, oil, tank

cellulose. The “health” of the oil is reflective of the health of 

transformer itself. DGA consists of sending transformer insul

samples to a commercial laboratory for analysis. The most im
212 

indicator is the individual and total dissolved combustible gas 

generation rates, based on International Electrotechnical Comm

(IEC) and Institute of Electrical and Electronic Engineers (IEE

standards. Although gas generation rates are not the only indi

they are reasonable for use in determining the Condition Indic

Score. 

Furanic analysis may indicate a problem with the paper insula

which could affect transformer longevity. A baseline furanic 

analysis should be made initially and repeated if the transform

is overheated, overloaded, aged, or after changing or processin

the oil. 

Physical tests such as interfacial tension (IFT), acidity, moistu

content, and dielectric strength usually indicate oil conditions 

be remedied through various reclamation processes. Therefor

are not indicative of overall transformer condition that would 

replacement. Such tests do not affect the Insulating Oil Condi

Indicator score. 

Results are analyzed and applied to table A-1 to arrive at a Co

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 gen

rates and come from a combination of IEEE C57-104TM, IEC 

and Delta X Research’s Transformer Oil Analysis (TOA) softw
Table A-1 – Insulating Oil Analysis Scoring 

Results 

Con

Ind

Sc

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 

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. 

2FAL furans between 450 ppb and 600 ppb for 55 °C rise. 

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 

2FAL furans between 200 ppb and 250 ppb for 65 °C rise. 

2FAL furans between 600 ppb and 750 ppb for 55 °C rise. 

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. 
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 degasifying 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 

insulation integrity. Power factor and excitation current tests a

conducted in the field on de-energized, isolated, and properly 

grounded transformers. Excitation current tests measure the s

phase voltage, current, and phase angle between them, typical

high-voltage side with the terminals of the other winding left f

(with the exception of a grounded neutral). The measurement

performed at rated frequency and usually at test voltages up to 

10 kilovolts (kV). The test detects shorted turns, poor tap chan

contacts, and core problems. 

Results are analyzed and applied to table A-2 to arrive at a Co

Indicator Score. 
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, 

compared to other phases and prior tests. 

1 

Power factor results show severe degradation. 

(Bad – B) 

OR 

Severe deviation2

 in current values and patterns, 

compared to other phases and prior tests. 

May indicate serious 

problem requiring 

immediate evaluation

additional testing, 

consultation with 

experts, and remediat

prior to re-energizatio

 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 w

piping, pumps, motors, controls, nitrogen replenishment sy

and indicating and protection devices). 

♦ Deteriorated control and protection wiring and devices. 

♦ Increase in corrective maintenance or difficulty in acquirin

parts. 

♦ Anomalies determined by physical inspection (external ins

or internal inspection not requiring untanking) (e.g., incorr

positioned valves, plugged radiators, stuck temperature ind

and level gauges, noisy oil pumps or fans, oil leaks, conne

bushings). 

♦ Previous failures on this equipment. 

♦ Failures or problems on equipment of similar design, cons

or age that operate in a similar environment. 

Qualified personnel should make a subjective determination o

that encompasses as many O&M factors as possible under this 

indicator. 
Results are analyzed and applied to table A-3 to arrive at a Co

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 ident

candidates for transformer replacement. Age is one indicator 

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 an

electrical insulation, especially wood and paper, deteriorate. A

actual service life varies widely depending on the manufacture

design, quality of assembly, materials used, operating history, 

operating conditions, and maintenance history, the average exp

life for an individual transformer in a large population of trans

is statistically about 40 years. 

Apply the transformer age to table A-4 to arrive at the Conditi

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 int

Transformer Condition Assessment Summary Form at the end 

appendix. Multiply each Condition Indicator Score by the We

Factor, then sum the Total Scores to arrive at the Tier 1 Transf

Condition Index. This index may be adjusted by the Tier 2 

inspections, tests, and measurements described below. Sugge

alternatives for follow-up action, based on the Transformer Co

Index, are described in table A-14 at the end of this appendix. 

12. Tier 2 – Inspections, Tests, Measurement

Tier 2 inspections, tests, and measurements generally require 

specialized equipment or training, may be intrusive, or may re

extended outage to perform. Tier 2 assessment is considered 

nonroutine. Tier 2 inspections may affect the Transformer Co

Index number established using Tier 1 but also may confirm o

the need for more extensive maintenance, rehabilitation, or tra

replacement. 

For each Tier 2 inspection, test, or measurement performed, su

the appropriate amount from the appropriate Tier 1 Condition 
Indicator and recalculate the Transformer Condition Index usi

Transformer Condition Assessment Summary Form at the end 

document. 

12.1 Test T2.1: Turns Ratio Test 

The transformer turns ratio (TTR) test detects shorts between t

the same coil, which indicates insulation failure between the tu

These tests are performed with the transformer de-energized a

show the necessity for an internal inspection or removal from 

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 

Adjust

Transformer C

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 p

immediate evaluation, 

consultation with expe

prior to re-energization

12.2 Test T2.2: Short Circuit Impedance Tests 

Sometimes called percent impedance or leakage reactance test

tests are conducted in the field and compared to nameplate 

information, previous tests, and similar units to detect deforma

the core or windings caused by shipping damage, through faul

ground faults. Some difference may be expected between nam

and field test results because factory tests are conducted at full 

current, which is normally not possible in the field. Field conn

and test leads and jumpers also play a significant role in test re

and it is impossible to exactly duplicate the factory test setup. 
220 

Therefore, the I2R losses may be different and cause different 

results. By comparing percent-reactance to nameplate impeda

differences caused by leads and connections can be eliminated

Because reactance is only the inductive component of the imp

I

2

R losses are omitted in the test results. 

Results are analyzed and applied to table A-6 to arrive at a 

Transformer Condition Index Score adjustment. 

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 evaluat

additional testing, consultati

with experts, and remediatio

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 th

connection is loose. It can also detect whether there are other 

undesired and inadvertent, grounds. If the intentional core gro

intact, the resultant resistance should be very low. To check f

unintentional core grounds, remove the intentional ground and 

Megger® between the core and the grounded transformer tank

test should produce very high resistance, indicating that an 

unintentional ground is not present. This test is to supplement 
that shows generation of hot metal gases (methane, ethane, an

ethylene) and to indicate if a spurious, unintentional core grou

problem. Experience can help locate the source of the problem

Results are analyzed and applied to table A-7 to arrive at a 

Transformer Condition Index score adjustment. 

Table A-7 – Core-to-Ground Resistance Test Scoring 

Test Results1

Adjustment to 

Transformer Condition Index 

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 requiri

immediate evaluation, additional test

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 t

changer (de-energized tap changer [DETC] or LTC). Results 

these measurements may indicate the need for an internal insp

This information supplements DGA and is useful when DGA 

generation of heat gases (ethane, ethylene, and methane). The

are typically performed with a micro-ohmmeter and/or a Whe

bridge. Test results are compared between phases or with fact

tests. When comparing with factory tests, a temperature corre

must be employed (IEEE P62TM). This test should be perform

after the rest of the routine electrical tests because it may magn

the core, affecting results of the other tests. 
222 

Results are analyzed and applied to table A-8 to arrive at a 

Transformer Condition Index score adjustment. 

12.5 Test T2.5: Ultrasonic and Sonic Fault 

Detection Measurements 

These assessment tests (sometimes called acoustic testing tests

helpful in locating internal faults. Partial discharges (corona) 

energy arcing/sparking emit energy in the range of 50 megahe

(ultrasonic), well above audible sound. To make these measur

sensors are placed on the outside of a transformer tank to dete

ultrasonic emissions, which are then converted electronically t

oscilloscope traces or audible frequencies and recorded. By 

triangulation, a general location of a fault (corona or arcing/sp

may be determined so that an internal inspection can be focuse

location. These devices also can detect loose shields that build 

static and discharge it to the grounded tank, poor connections 

bushings, bad contacts on a tap changer that are arcing/sparkin

ground problems that cause sparking/arcing, and areas of weak 

insulation that generate corona. Sonic testing can detect incre

core and coil noise (looseness) and vibration, failing bearings 

pumps and fans, and nitrogen leaks in nitrogen blanketed trans

Table A-8 – Winding Direct-Current Resistance Measurement Scoring 

Measurement Results 

Adjustment to 

Transformer Condition Ind

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 re

immediate evaluation, additiona

consultation with experts, and 

remediation prior to re-energiza
Information gained from these measurements supplements DG

provides additional support information for de-energized tests

core ground and winding resistance tests. In addition, these te

pinpoint areas to look for problems during internal inspections

Performing baseline tests may provide comparisons for later te

Experience can help locate the source of the problem. 

Results are analyzed and applied to table A-9 to arrive at a 

Transformer Condition Index score adjustment. 

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 segm

shield problems, loose parts, or bad bearings on oil cooling pu

fans. Vibration analyzers are used to detect and measure the v

Information gained from these tests supplements ultrasonic an

(acoustic) fault detection tests and DGA. Information from th

may indicate maintenance is needed on pumps/fans mounted e

to the tank. It may also show when an internal transformer ins

is necessary. If wedging has been displaced due to paper dete

or through faults, vibration will increase markedly. This will a

show if core and coil vibration has increased compared to base

information. Experience can help locate the source of the prob
224 

Results are analyzed and applied to table A-10 to arrive at a 

Transformer Condition Index score adjustment. 

Table A-10 – Vibration Analysis Scoring 

Analysis 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 

12.7 Test T2.7: Frequency Response Analysis (FRA

Frequency Response Analysis (or Sweep Frequency Response 

Analysis) can determine if windings of a transformer have mo

shifted. It can be completed as a factory test prior to shipment 

repeated after the transformer is received onsite to determine i

windings have been damaged or shifted during shipping. This 

also helpful if a protective relay has tripped or a through fault, 

circuit, or ground fault has occurred 

A sweep frequency test signal is generally placed on each of th

voltage windings, and the signal is detected on the low-voltag

windings. This provides a picture of the frequency transfer fu

the windings. If the windings have been displaced or shifted, 

results will differ markedly from prior tests. Test results are k

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. 

Results are analyzed and applied to table A-11 to arrive at a 

Transformer Condition Index Score adjustment. 
Table A-11 – Frequency Response Analysis Scoring 

Test Results 

Adjustment to 

Transformer Condition Index 

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 requirin

immediate evaluation, additional test

consultation with experts, and 

remediation prior to re-energization. 

12.8 Test T2.8: Internal Inspection 

In some cases, it is necessary to open, partially or fully drain t

and perform an internal inspection to determine the transforme

condition. These inspections must be performed by experienc

with proper training. Sludging, loose wedges, loose coils, poo

electrical connections on bushing bottoms, burned contacts on 

changers, localized overheating signified by carbon buildup, d

wedging or insulation, and debris and other foreign material ar

general matters of concern. Photographs and mapping problem 

locations are good means of documenting findings. Before en

the transformer, and while inside it, the Occupational Safety a

Health Administration, State, local, and utility safety practices 

followed (e.g., “permitted confined space” entry practices). 

Results are analyzed and applied to table A-12 to arrive at a 

Transformer Condition Index Score adjustment. 

12.9 Test T2.9: Degree of Polymerization 

Winding insulation (cellulose) deterioration can be quantified 

analysis of the degree of polymerization (DP) of the insulating 

material. This test gives an indication of the remaining structu
226 

Table A-12 – Internal Inspection Scoring 

Inspection Results 

Adjustment to Transformer 

Condition Index 

Conditions normal No change 

Minimal degradation Subtract 0.5 

Moderate degradation Subtract 1.5 

Severe degradation May indicate serious problem requiring im

evaluation, additional testing, consultation 

experts, and remediation prior to re-energ

strength of the paper insulation and is an excellent indication o

remaining life of the paper and the transformer itself. This req

analyzing a sample of the paper insulation in a laboratory to d

the deterioration of the molecular bonds of the paper. 

Results are analyzed and applied to table A-13 to arrive at a 

Transformer Condition Index score adjustment. 

Table A-13 – Degree of Polymerization Scoring 

Test Results 

Adjustment to 

Transformer Condition Index 

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 requirin

immediate evaluation, additional test

consultation with experts, and remed

prior to re-energization. 
13. Tier 2 – Transformer Condition Index 

Calculations 

Enter the Tier 2 adjustments from the tables above into the 

Transformer Condition Assessment Summary Form at the end 

chapter. Subtract the sum of these adjustments from the Tier 

Transformer Condition Index to arrive at the total Transforme

Condition Index. Suggested alternatives for followup action, b

the Transformer Condition Index, are described in table A-14. 

Table A-14 – Transformer Co-ndition Assessment Summary

Test Detects 

Online Tests 

Dissolved Gas 

Analysis 

Internal arcing; bad electrical contacts; hot 

spots; partial discharge; and overheating of 

conductors, oil, tank, and cellulose insulation. 

Requires 

analysis 

Oil Physical and 

Chemical Tests 

Moisture, degraded IFT, acidity, furans, 

dielectric strength, and power factor. 

Requires 

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. 

Experien

and bino

External 

Temperatures 

(Main tank and 

load tap changer) 

Temperature monitoring with changes in load 

and ambient temperature. 

Portable 

data logg

software 

Infrared Scan Hot spots indicating localized heating, 

circulating currents, blocked cooling, tap 

changer problems, and loose connections. 

Thermog

camera a

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. 

Ultrason

and anal

Sonic Fault 

Detection 

Nitrogen leaks, vacuum leaks, core and coil 

vibration, corona at bushings, and mechanical 

and bearing problems in pumps and cooling 

fans. 

Ultrason

and mete

Vibration Analysis Internal core, coil, and shield problems; loose 

parts and bad bearings. 

Vibration 
228 

Table A-14 – Transformer Condition Assessment Summary (continued) 

Test Detects T

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 eq

Turns Ratio Shorted windings. Doble test eq

turns ratio te

Short Circuit Impedance Deformation of the core or winding. Doble or equ

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 

and greater) 

Kelvin Bridge 

ohmmeter (le

Frequency Response 

Analysis 

Shifted windings. Doble or equ

frequency an

Internal Inspection Oil sludging, displaced winding or 

wedging, loose windings, bad 

connections, localized heating, and 

debris and foreign objects. 

Experienced 

ohmmeter 

Degree of Polymerization Insulation condition (life 

expectancy). 

Laboratory a

sample 
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 = To

 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) 

 (Betw

Tier 2 Transformer Condition Summary 

Tier 2 Test

Adjustment 

Condition 

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 

Adjustments from the Tier 1 Condition Index: 

Tier 1 Transformer Condition Index __________ 

minus Tier 2 Adjustments __________ = ________

 Net Transformer Conditi

Evaluator: _________________ 

Technical Review: _________________ Management Review: _____

Copies to: _______________________ 

Forward completed form, including supporting documenta

agency transformer expert. 

14. Transformer Alternatives 

After review by a transformer expert, the Transformer Conditi

Index—either modified by Tier 2 tests or not—may be sufficie

decision-making regarding transformer alternatives. The inde

suitable for use in the risk-and-economic analysis model descr

elsewhere. Where it is desired to consider alternatives based s

transformer condition, the Transformer Condition Index may b

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. Conside

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 

[1] Standard General Requirements for Dry-Type Distribut

Power, and Regulating Transformers, American Nation

Standards Institute/Institute of Electrical and Electronic 

Engineers (ANSI/IEEE) C57.12.01, 1989. 

[2] Standard General Requirements for Liquid-Immersed 

Distribution, Power and Regulation Transformers, Instit

Electrical and Electronic Engineers (IEEE) C57.12.00, 1

[3] Power Transformer Maintenance and Testing, General P

Corporation, 1990. 

[4] Guidelines for the Life Extension of Substations, Electri

Research Institute (EPRI) TR-105070, April 1995. 

[5] Guidelines for the Life Extension of Substations, Electri

Research Institute (EPRI), 2002 update. 

[6] Transformer Maintenance Guide, J.J. Kelly, S.D. Myers

R.H. Parrish, S.D. Myers Co., 1981. 

[7] Transformer General Gasketing Procedures, Alan Cote, 

S.D. Myers Co., 1987. 

[8] Recommended Practice for Electrical Equipment Maint

National Fire Protection Association (NFPA) 70-B-2002

[9] Bushing Field Test Guide, Doble Engineering Company

[10] Testing and Maintenance of High-Voltage Bushings, FI

Bureau of Reclamation, 1991. 

[11] General Requirements and Test Procedure for Outdoor P

Apparatus Bushings, Institute of Electrical and Electron

Engineers (IEEE) C57.10.00, 1991. 
232 

[12] Guide for the Interpretation of Gases Generated in OilImmersed Transformers, Institute of Electrical and Elec

Engineers (IEEE) C57.104, 1991. 

[13] “Mineral Oil-Impregnated Electrical Equipment” in Ser

Interpretation of Dissolved and Free Gas Analysis, Inte

Electrotechnical Commission (IEC) 60599, 1997. 

[14] Dissolved Gas Analysis of Transformer Oil, John C. Dro

John W. Porter, Randy Stebbins, S.D. Myers Co., 1996. 

[15] Recommended Practice for Installation, Application, Op

and Maintenance of Dry-Type General Purpose Distribu

Power Transformers, Institute of Electrical and Electron

Engineers (IEEE) C57.94, 1982. 

[16] Criteria for the Interpretation of Data for Disssolved Ga

Oil from Transformers (A Review), by Paul Griffin, Do

Engineering Co., 1996. 

[17] Maintenance of High Voltage Transformers, Martin Hea

Associates, London, England, 1989. 

[18] Thermal Monitors and Loading, Harold Moore, Transfo

Performance Montitoring and Diagnostics EPRI, Septem

1997. 

[19] IEEE and IEC Codes to Interpret Incipient Faults in 

Transformers, Using Gas in Oil Analysis, R.R. Rogers C

Transmission Division, Guilford, England, circa 1995. 

[20] IEEE Guide for Diagnostic Field Testing of Electrical P

Apparatus, Part 1: Oil Filled Power Transformers, Regu

and Reactors, Institute of Electrical and Electronic Engi

(IEEE) 62, 1995. 

[21] Maintenance of Liquid Insulation: Mineral Oils and As

FIST 3-5, Bureau of Reclamation, 1992. 
[22] Standard Test Method for Interfacial Tension of Oil Aga

Water by the Ring Method, American National Standard

Institute/American Society for Testing and Materials 

(ANSI/ASTM) D 971-91. 

[23] Experience with In-Field Water Contamination of Large 

Transformers, Victor V. Sokolov and Boris V. Vanin, S

and Engineering Center “ZTZ Service Co.,” EPRI Subs

Equipment Diagnostics Conference VII, Ukraine, 1999. 

[24] Proceedings: Substation Equipment Diagnostics, Confe

IX, Electric Power Research Institute (EPRI), 2000. 

[25] Reference Book for Insulating Liquids and Gases, Dobl

Engineering Company RBILG-391, 1993 

[26] Guide for Loading Mineral Oil Immersed Transformers

American National Standards Institute/Institute of Elect

Electronic Engineers (ANSI/IEEE) C57.92, 1981. 

[27] Insulating Fluids, Doble Engineering Company Client 

Conference Minutes No. 65PAIC98, 1998. 

[28] Trial-Use Guide for the Interpretation of Gases Generat

Silicone-Immersed Transformers, Institute of Electrical 

Electronic Engineers (IEEE) P1258, 1999. 

[29] Standard Specification of Nitrogen Gas as an Electrical 

Insulating Material, American Society for Testing and M

(ASTM) D-1933-97. 

[30] Standard Specification for Mineral Insulating Oil Used 

Electrical Apparatus, American Society for Testing and 

Materials (ASTM) D-3487, 1988. 

[31] Standard Test Method for Furanic Compounds in Electr

Insulating Liquids by High Performance Liquid 

Chromatography, American Society for Testing and Ma

(ASTM) D-5837, 1996. 
234 

[32] Standard Test Method for Compressibility and Recovery 

Gasket Materials, American Society of Testing and Mat

(ASTM) F-36, 1999. 

[33] Standard Test Method for Rubber Property – Duromete

Hardness, American Society of Testing and Materials (A

D-2240, 1997. 

[34] “Transformer Condition Assessment,” in Hydro Powerp

Risk Assessment Guide, a joint effort of Bureau of Recl

U.S. Army Corps of Engineers, Hydro Quebec, and Bon

Power Administration (see appendix). 

[35] Replacements, Bureau of Reclamation and Western Are

Administration, July 1995. 

[36] M5100 Sweep Frequency Response Analysis (SFRA) 

Instrument Users Guide, Doble Engineering Company, 

[37] Maintenance Scheduling for Electrical Equipment, FIST 

Bureau of Reclamation, 2001. 

[38] Thermographic Maintenance Program, FIST 4-13, Bure

Reclamation. 

[39] An Introduction to the Half-Century Transformer, Trans

Maintenance Institute, S.D. Myers, Co., 2002. 

[40] Transformer Nitrogen Advisory, PEB 5, October 2000. 
Acronyms and Abbreviations 

AC alternating current 

amp ampere 

ANSI American National Standards Institute 

ASTM American Society for Testing and Mate

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 inhib

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 

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 
236 

gm gram 

GSU generator step-up 

H2 hydrogen 

Hz hertz (cycles per second) 

IEC International Electrotechnical Commiss

IEEE Institute of Electrical and Electronic 

Engineers 

IFT Interfacial Tension (between transforme

and water; this is a measure of the amou

particles and pollution in transformer oi

ips inches per second 

IR infrared 

I

2

R watts 

JHA job hazard analysis

kHz kilohertz (kilocycles per second) 

KOH potassium hydroxide (used to determine 

number of transformer oil) 

kV kilovolts 

kW kilowatt 

LTC load tap changer 

kVA kilovoltampere 

mA milliampere 

M/DW moisture by dry weight (percent of wei

of water in paper insulation based on dr

weight of paper given on transformer 

nameplate) 

Mg milligram 

MHz megahertz (megacycles per second) 

MVA megavoltampere 

NFPA National Fire Protection Association 
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 

°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