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Transformer
Handbook
Volume 1
Table of Contents
Mystery of Transformers .........................................................................................1
Mark Lautenschlager, P.E.
Guidelines for Selecting No-Load Taps on Power Transformers ....................................6
Mark Lautenschlager, P.E.
A Guide to Paralleling Electrical Systems ...................................................................8
Mark Lautenschlager, P.E.
Loading Conditions Causing Loss of Life for Oil-Filled Power Transformers .................11
Mark Lautenschlager, P.E.
Transformer Failure Data ......................................................................................13
Mark Lautenschlager, P.E.
Managing the Life of Power Transformers ................................................................14
Brian D. Sparling
Maintaining GE Gas Filled Transformers .................................................................17
Edward C. Smith and Edwin L. Mathis, P.E.
The Detection of Mechanical Damage in Power Transformers
Using the Sweep Frequency Response Analysis Method ............................................21
Mario Locarno, Tad Tully, and Alan Wilson
An Additional Method for Determining Shorted Turns
in Transformer Windings ......................................................................................27
N. Wayne Hansen and Parsons Brinckerhoff
Considerations in Sizing Primary Fuses
Due to Secondary Faults for Padmount Transformers ...............................................32
Steven C. Reed, P.E.
Published by
InterNational Electrical Testing Association
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269.488.6382
www.netaworld.org
Transformer Handbook
Volume 1
Table of Contents (continued)
Using Analytical Techniques to Determine
Cellulosic Degradation in Transformers ...................................................................35
Lance R. Lewand
Transformer Fluid: A Powerful Tool for the Life Management
of an Aging Transformer Population ........................................................................38
Ted Haupert, Victor Sokolov, Armando Bassetto, T.V. Oommen, and Dave Hanson
Understanding Water in Transformer Systems ..........................................................48
Lance R. Lewand
It Meggered Fine — Sorry it Scorched the Building! ..................................................52
John Cadick and Al Rose
Remanufacturing of Power Transformers ................................................................58
D. E. Corsi
NOTICE AND DISCLAIMER
NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views,
and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication
herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers,
members, employees, or agents (hereinafter “NETA”).
All technical data in this publication reflects the experience of individuals using specific tools, products equipment, and
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Copyright © 2009 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be
reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.
1
Transformer Handbook — Volume 1
Mystery of Transformers
NETA World, Winter 1999-2000
by Mark Lautenschlager, P.E.
President, ERC International, Inc.
The basic concepts of transformer operation are well known.
Transformers automatically maintain voltage and current ratios such to produce electrical power output nearly equal
to the electrical power input. The voltage ratios are directly
proportional and the current ratios are inversely proportional to the turns ratio of the primary and secondary
windings. However, transformers are vastly more complex
than indicated by these simple equations. The purpose of
this article is to discuss, draw some conclusions, and correct
some misconceptions about the mysterious component of
transformer operation - the transfer of electrical energy by
magnetic flux.
What makes a transformer work?
The primary current in a transformer operating at rated
load contains about 95 percent load current, about two
percent wasted conductor watts-loss current, less than one
percent wasted core watts-loss current, and about two percent magnetizing volt-amperes current. The core loss and
magnetizing currents together are called “exciting current.”
It is the magnetic flux produced by the exciting current that
makes a transformer work.
Transformer excitation
When an alternating voltage is applied across a transformer primary winding (always the winding energized
by the source, regardless of the voltage rating of the winding), an exciting current flows directly proportional to the
applied voltage and inversely proportional to the mutual
inductance of the transformer. The exciting current produces
magnetic flux in the core in-phase with the exciting current and directly proportional to the applied volts per turn.
The magnetic flux induces a voltage across the secondary
winding equal in magnitude to the primary winding volts
per turn times the number of secondary winding turns, but
of opposing polarity. Also, the magnetic flux induces a back
emf across the primary winding with a magnitude equal
to the applied voltage but of opposing polarity. When a
transformer is not loaded, the back emf prevents all current
except exciting current from flowing.
Transfer of Power
When a load is connected to the secondary winding, the
induced secondary voltage causes current to flow as determined by the secondary circuit impedance. The secondary
current reduces the secondary voltage and the primary back
emf. This reduced primary back emf allows primary current
to flow. Since the primary and secondary voltages oppose
each other, the primary and secondary currents must also
have opposite polarity. The magnetic fluxes produced by the
primary and secondary load currents must then oppose each
other and be balanced with equal ampere-turns.
Comments
• Primary load current flows when the primary back emf
is reduced due to secondary load current.
• The primary load current equals the ampere-turns produced by the secondary divided by the number of primary turns. The magnetic fluxes (ampere-turns) produced by the primary and secondary load currents have
opposite polarities and are canceled, resulting in no net
flux in the core. This is indicated by IPNP-ISNS=0; the
primary ampere-turns in the core are equal but opposite
to the secondary ampere-turns. Thus, the flux density in
the core is not a function of load current (an inaccurate
assumption).
• The only flux in the core is that produced by the exciting
current and has a magnitude based solely on primary volts
per turn ( = V/N). The voltage induced on the secondary
winding is indicated by VS/NS=VP/NP, or secondary volts
per turn equals primary volts per turn. Generally, the flux
density in a core is slightly less in a transformer when it is
loaded, due to slightly lower voltages.
Transformer voltage, exciting current,
and magnetic flux phase relationships —
See Plots
When an unloaded transformer is energized, it is acting as
a set of mutually coupled inductors. Ignoring winding resistance losses, let’s examine the first one-quarter of a complete
cycle of voltage, current, and flux in a transformer.
2
Transformer Handbook — Volume 1
When a 60 hertz voltage at maximum positive value
is applied across the primary winding, the initial exciting
current is increasing from zero but at a decreasing rate of
change. Note that the maximum rate of change is always at
the zero crossings and the minimum rate of change is always
at the maximum positive and negative values.
The increasing exciting current (during the first onequarter cycle) produces increasing magnetic flux (in phase
with the exciting current) that induces a back emf that
opposes (with reversed polarity compared to the applied
voltage) the instantaneous change in the exciting current
(per Lenz’s Law). The back emf induced is directly propor-
tional to the rate of change in the flux (emf = / t). The
back emf is also directly proportional to the rate of change
in the exciting current that produces the flux. This causes
the back emf to be at maximum negative value when both
the exciting current and the flux are at zero values but at
maximum rates of change. Since the emf is a function of
the rate of change in the flux and the exciting current, the
back emf leads the exciting current by 90 degrees. Since
the back emf must lag the applied voltage by 180 degrees,
the exciting current must then lag the applied voltage by 90
degrees. This rather complex discussion may seem clearer
by studying the Plots, following.
Plots
Transformer Voltage, Exciting Current, and Magnetic Flux Phase Relationship Analysis
Notes:
• Except for the comments about secondary voltage and load currents, this analysis is also true for any ac inductor.
• This analysis is true for both unloaded and loaded transformers.
3
Transformer Handbook — Volume 1
Good magnetic performance in real
transformers
In real transformers, in addition to the lagging magnetizing current, the exciting current contains components that
are in phase with the applied voltage. Conductor resistance,
eddy current, and hysteresis losses all result in some wasted
watts. Therefore, due to these resistive components, the exciting current in real transformers actually lags the applied
voltage by something slightly less than 90 degrees. The
exciting current is also distorted due to the third harmonics
produced by hysteresis loop characteristics of the core.
Eddy currents are small short-circuit currents produced
in the core by the magnetic flux. Constructing the core of
many thin insulated layers of steel and grounding the core
to the frame at only one location minimizes these eddy
currents and the resulting wasted watts. The amount of the
exciting current resulting from the eddy current and hysteresis losses (discussed below) are directly proportional to
the magnetic flux density in the core and the frequency of
the applied voltage.
Transformer cores are made of cold rolled silicon steel
containing polarized molecules that can be easily magnetized. Polarized molecules are those that have some with
atoms with nonpaired electrons, or paired electrons with
the same spins. Easily magnetized materials have high
permeability. The relative ease in magnetizing a core is
called permanence and is directly proportional to the permeability of the core material and the area of the core and is
inversely proportional to the length of the core. The inverse
of permanence is reluctance, the equivalent of resistance in
an electrical circuit.
If the polarized molecules in a core stay aligned and
store magnetic energy after the external magnetic field is
removed, the core has high residual magnetism. When a
magnetic material is exposed to an alternating magnetic
field, the energy required to overwhelm the residual magnetism every one-half cycle is called hysteresis watts loss.
Therefore, for a low loss transformer core, the ideal magnetic
material has high permeability and low residual magnetism,
and the core area and length should be such to provide for
minimal losses.
The volts per turn determine the amount of flux in a core.
The ability of the core to contain the flux is determined by
its permanence, described above. Once a transformer is
constructed, its permanence does not change much unless
the core laminations become loose. Loose core laminations
can lower the permanence and increase the required exciting current. Core saturation occurs when the flux density
is such that all of the polarized core molecules are used up
by the magnetic field. Saturation is caused by excess voltage
(normally over 110 percent of rating), insufficient core area,
or a loose core. When a core saturates, the exciting current
increases exponentially with little or no increase in secondary
voltage but with much excess noise and heat.
Not all of the flux produced by the primary exciting
current links with the secondary winding, particularly in
three-legged core form transformers (shell form designs
generally are more efficient, magnetically). Stray flux may
cause transformer tank and frame heating and increased
watts losses. Distorted windings or core laminations can
cause excess stray flux and increase the required exciting
current.
As with any inductor, the lagging exciting current needed
by the transformer magnetic circuit requires, during the first
and third quarters of each cycle, energy from the source in
the form of reactive volt-amperes. The transformer returns
this energy to the source during the second and fourth
quarters of each cycle. See Plots. This lagging exciting current generally is much smaller than the transformer load
current and generally does not contribute much to poor
system power factor.
Quick review of electromagnetism
The spinning electron with its tiny spinning magnetic
field is the basic unit of magnetism. Normally, electrons in
nonmagnetic conductors move in random directions and are
paired with opposing spin electrons, canceling any magnetism. When current is forced to flow in a conductor, these
nonmagnetic pairs of electrons are forced to separate, line
up, and all spin in the same direction. The flow of electrons
all spinning in the same direction produces a magnetic field
around the conductor. When the magnetic field changes due
to changing current, a back electromagnetic field (emf ) or
voltage is induced that tends to oppose the change in the
current (reverse of electron flow). Making the conductor into
a coil increases the intensity of the magnetic field (ampereturns) and back emf.
A condition referred to as ferroresonance may occur when
a transformer and a long cable are energized together by a
single-phase switch. Resonance occurs when the inductive
reactance of a transformer matches the capacitive reactance
of a cable. The transformer exciting current is inversely
proportional to the transformer inductance. If the net reactance of a transformer and cable combination is zero,
the exciting current in the transformer is limited only by
the small resistance of the transformer. The excess exciting
current produces both high voltages and core saturation,
which could cause a transformer to fail. When energizing
three-phase transformers (connected to long cables) with
single-phase switches, always pick up some resistive secondary load with the transformer.
Resonance can also occur when the voltage contains
considerable 5th or 7th harmonics. Since XL= 2 fL and XC
= 1/2 fC, XL may equal XC at some frequency. Excess harmonics at a tuned frequency can cause a resonance condition
as described above.
4
The % Z of a transformer indicates the percentage of the
rated voltage that will be applied across a bolted short circuit occurring near the transformer secondary. Under short
circuit conditions, the secondary voltage and primary back
emf can drop to rated voltage times % Z/100 and cause load
current to increase to rated full load current times 100/% Z.
The % Z is a function of transformer impedance: inductive
reactance, capacitive reactance, and resistance. Transformer
impedance can be adjusted in the factory by changing the
spacing between the windings.
Comments
• Using cores that have high permeability, low hysteresis,
insulated laminations, and a single core ground connection minimizes no-load losses.
Transformer Handbook — Volume 1
Exciting current
Exciting current
i = V/2 fL
Inductance of primary or secondary L 1 or 2 = 0.4 N2 A/l
k 0.4 N1N2 A
Mutual inductance L M = k L1L 2 = ———————
l
Therefore,
V
= __________________
Vx l
i = ___________________
2 f (k 0.4 N1N2 A)
2 f (k 0.4 N1N2 A/l)
• Saturation is not a function of load current.
i = Exciting current
L = Inductance
V = Applied voltage
l = Core length
f= Frequency of applied ac voltage
k = Coefficient of coupling. This is 1.0 if all flux produced
by primary cuts all coils in the secondary winding. There
usually are some stray flux losses in transformers.
N = Number winding turns
= Core permeability
A = Core cross-sectional area
Magnetic flux
Comments
• Excess exciting current may be the result of a loose or
distorted core or a distorted winding.
• Since transformers are actually inductors, they require
var energy to operate and can resonate with capacitive
elements in a circuit.
• Core saturation is a function of voltage, the number
of turns, core permeability (loose cores may saturate
at operating voltage), and core area. Increasing either
core area or the number of turns increases the voltage at
which saturation will occur.
Transformer Magnetic Flux
= V/4.44Nf
V = Applied ac voltage
4.44 = A constant
N = Number of primary turns
f = Frequency of applied ac voltage
According to the magnetic flux formula above, the
amount of flux produced is directly proportional to the applied volts per turn in the primary winding and inversely
proportional to the frequency of the applied voltage.
Comments
• A 50 hertz transformer produces more flux than a 60
hertz transformer with identical volts per turn and,
therefore, requires more core area.
• Small high-voltage instrument transformers have many
primary and secondary winding turns to minimize flux
density and thus reduce core size.
As indicated by the exciting current formula, exciting
current increases with:
• An increase in the applied voltage.
• An increase in the core length.
Windings on outer legs of a three-legged core require
higher exciting currents than the center leg windings.
• A decrease in frequency.
• A decrease in the efficiency of the inductive
coupling.
Winding or core distortion may cause increased stray
flux losses increasing the exciting current.
• A decrease in the product of the number of turns in the
primary and secondary windings.
This is why the exciting current is greater (sometimes too
much for some test sets) for some dry-type 12,470/480
volt transformers with twelve or fewer secondary turns.
• A decrease in the permeability of the core.
A “loose core” may cause a decrease in m. Modern silicon
core steel has permeability about 10,000 times greater
than air.
• A decrease in core area.
Transformer Handbook — Volume 1
Final thoughts
Testing personnel need to understand the “mysterious”
magnetic functions of transformers in order to evaluate and
solve transformer problems. Unfortunately, little information
is available for technicians other than complex engineering
textbooks explaining the magnetic circuits of transformers.
Hopefully, this article will help solve that problem and prove
useful in helping resolve transformer problems.
Mark Lautenschlager is President of ERC - Electrical Risk Consultants International, Inc., of Tampa, FL. He is retired from High Voltage
Maintenance Corporation as Vice President of Engineering and is a past
president of NETA. He is a member of the NETA Standards Review
Council.
5
6
Transformer Handbook — Volume 1
Guidelines for Selecting No-Load
Taps on Power Transformers
NETA World, Spring 2000
by Mark Lautenschlager, P.E.
President, ERC International, Inc.
In most power transformers, the high voltage windings
are “tapped” to allow turns to be added to or subtracted from
the high-voltage windings. For step-up transformers, the
tap connections determine the voltage produced across the
high-voltage windings when rated voltage is applied across
the low-voltage windings. For step-down transformers, the
tap connections determine the voltage required across the
high-voltage windings to produce rated voltage across the
low-voltage windings. This article discusses the selection of
taps for step-down, liquid-filled power transformers (the
high-voltage connection is the primary) with the no-load
tap-changer tapped into the primary windings.
Standard Tap Connections
Liquid-filled power transformers usually have five noload tap-changer (NLTC) positions, as indicated by A, B,
C, D, and E (or 1, 2, 3, 4, and 5) on the nameplate. The tap
position for the nominal primary voltage rating is usually
C. To produce the rated secondary voltage, the required primary voltage A is 105 percent of C, B is 102.5 percent of C,
D is 97.5 percent of C, and E is 95 percent of C. These tap
voltage ratios can be verified by performing turns ratio tests.
There are exceptions to the position of the nominal voltage
tap, the number of taps, and the use of letters (numbers are
sometimes used).
For a fixed primary voltage, when the primary voltage
tap position is decreased, the resulting secondary voltage
is increased. When the tap-changer is moved from tap C,
the new secondary voltage is a function of the inverse of the
selected tap’s percentage of tap C primary voltage. For example, when the tap is moved from C to D, the primary tap
voltage rating is 97.50 percent of C, but the tap D secondary
voltage is the inverse of 97.5 percent, or 102.56 percent of
the tap C secondary voltage. When the tap is moved form C
to A, the tap A secondary voltage is the inverse of 105 percent, or 95.24 percent of tap C secondary voltage. Although
the primary voltage difference per tap is 2.5 percent of tap C
primary voltage, the secondary voltage changes are slightly
more or less than 2.5 percent. The calculated change in the
secondary voltage when the tap is moved from tap C to tap
B is -2.439 percent, from tap C to tap A is –4.762 percent.
from tap C to tap D is +2.564, and from tap C to tap E
is +5.263 percent. The point is that if the initial secondary
voltage is known, the secondary voltages resulting from tap
changes can be calculated. Using 2.5 percent change per
tap will determine only approximate secondary voltages. To
be accurate use the following procedure:
• Calculate the voltage ratio on the existing tap.
• Multiply the calculated ratio by the known secondary
voltage to determine the existing primary voltage.
• Calculate the ratio of the selected tap.
• Divide the primary voltage by the ratio of the selected
tap to determine the new secondary voltage.
Examples
Example A
Calculate new secondary voltage on tap D when the
voltage is 12.95 kV on tap C. The transformer voltage rating is 69/13.2 kV.
• Calculate the voltage ratios. Do not factor in the square
root of three.
NP Tap/Voltage
A - 72.45 kV ÷
B - 70.73 kV ÷
C - 69.00 kV ÷
D - 67.27 kV ÷
E - 65.55 kV ÷
Rated Secondary Voltage
13.2 kV =
13.2 kV =
13.2 kV =
13.2 kV =
13.2 kV =
Ratios
5.489
5.358
5.227
5.096
4.966
7
Transformer Handbook — Volume 1
• If the secondary voltage is 12.95 kV on tap C, the
primary voltage is 12.95 kV X 5.227 = 67.69 kV.
• The secondary voltage produced on tap D is 67.69 kV ÷
5.096 = 13.28 kV
Example B
For the 69/13.2 kV transformer, what are the secondary
voltages produced at each tap selection when the primary
voltage is 69.00 kV?
• Calculate the voltage ratios as in example A.
• To determine the actual secondary voltages, divide the
primary voltage by the voltage ratios. If 13.2 kV is simply multiplied by 95 percent, 97.5 percent, 102.5 percent, and 105 percent some error results. See percent
method column.
NP Tap/Voltage Ratios
A (72.45 kV)
B (70.73 kV)
C (69.00 kV)
D (67.27 kV)
E (65.55 kV)
5.489
5.358
5.227
5.096
4.966
Actual Secondary
Voltage
69,000 ÷ 5.489 = 12,571 V
69,000 ÷ 5.358 = 12,878 V
69,000 ÷ 5.227 = 13,200 V
69,000 ÷ 5.096 = 13,540 V
69,000 ÷ 4.966 = 13,895 V
% Method
12,540 V
12,870 V
13,200 V
13,530 V
13,860 V
Example C
Sometimes neither the primary system voltage nor the
required secondary voltage matches the transformer ratings.
A standard 69/13.2 kV transformer (see above) has been
installed on a 67 kV system. The desired output voltage is
12.47 kV. Can this be done? And if so, what is the best tap
to select? What is the percent error? Will the output voltage
be greater than or less than required?
• Determine the system voltage ratio.
Required ratio = 67 kV ÷ 12.47 kV = 5.373
• Calculate the transformer tap voltage ratios. Refer to
example B.
• Select the transformer tap that best matches the system
voltage ratio.
Select tap B = 5.358
• What is the secondary voltage produced when this 69
kV transformer, set on tap B, is energized at 67 kV?
67 kV ÷ 5.358 = 12.505 kV
• What is the percent error?
2505 V – 12470 V = 35 V high
100% X 35 V ÷ 12470 V = 0.28% error
• The secondary voltage is 12,505 V or 0.28% high. This
is likely acceptable error.
Rule
As can be determined by observing example B, changing
the tap-changer to a lower primary voltage position raises
the secondary voltage.
Explaining the Rule
Basically, when a lower voltage tap is selected, the voltage ratios are closer. Since the primary voltage is assumed
constant, the secondary voltage must raise due to the smaller
voltage ratio.
Voltages when Transformers Are Loaded
Although changing the tap-changer one position raises
or lowers the no-load secondary voltage approximately 2.5
percent of nominal voltage, the actual secondary voltage of
a loaded transformer depends on system voltage regulation.
The full-load voltage drop at the secondary of a transformer
with low internal impedance (%Z) will be less than for a
high %Z transformer.
Operating the No-Load Tap-Changer
“No-load” is a misnomer. No-load tap-changer or NLTC
should be referred to as de-energized tap-changer. A NLTC
selector switch shall not be moved while a transformer is
energized, regardless of loading. The high-voltage windings
of an energized transformer, even with no load, carries sufficient exciting current to damage parting tap contacts.
Do not use excessive force to operate tap-changing mechanisms. If excessive force is necessary, always inspect mechanism parts and the tap contacts inside the transformer.
Whenever NLTC tap positions are changed, perform
turns ratio and winding resistance measurements to verify
that the tap contacts actually moved to the correct positions. Transformers have failed because tap contacts did not
properly make when the tap positions were changed.
Conclusion
Making incorrect assumptions or guessing when setting
NLTC taps can result in embarrassing mistakes. Remember
to move the tap to a lower primary voltage position to raise
the secondary voltage and to follow the three steps necessary
to match a transformer to a system:
• Determine the system voltage ratio.
• Calculate the transformer tap voltage ratios.
• Select the transformer tap voltage ratio that best matches the system voltage ratio.
Mark Lautenschlager is President of ERC - Electrical Risk Consultants International, Inc., of Tampa FL. He is retired from High Voltage
Maintenance Corporation as Vice President of Engineering and is a
past president of NETA.
8
Transformer Handbook — Volume 1
A Guide
to Paralleling Electrical Systems
NETA World, Summer 2000
by Mark Lautenschlager, P.E.
President, ERC International, Inc.
It’s 2:00 AM, and the replacement transformer has been
installed and is ready to go. All you have to do now is verify
that the transformer’s secondary bus voltage is in-phase with
the system voltage. You energize the transformer, and across
the racked out secondary breaker stabs you check for zero
voltages that will verify that phasing is OK.
But the voltages are not zero, and the systems are not
in-phase. So what went wrong? What do you do now?
What Are Standard Three-Phase Transformers?
For standard delta-wye and wye-delta connected transformers, the high-voltage phases always lead the low-voltage phases by 30º. For standard connected delta-delta and
wye-wye connected transformers, the high-voltage phases
always lead the low-voltage phases by 0º. Therefore, except
for the fact that the delta secondary systems do not have
grounded neutrals, standard delta-wye transformers can
be paralleled with standard wye-delta transformers, and
wye-wye transformers can be paralleled with delta-delta
transformers. Delta-wye transformers cannot be paralleled
with either delta-delta or wye-wye transformers.
Nonstandard three-phase transformers and banks of
single-phase transformers may be found where the original
system was very old and was not tied with other systems.
Some municipal electric utilities used transformers connected such that the low voltage led the high voltage by 150º
(or 180º out of phase with the standard connection).
What Is Phasing?
Phasing is the act of determining, before two electrical
systems are paralleled, that the voltages on the system buses
to be connected are nearly the same in both magnitude and
phasing (when the maximum positive and negative sinusoidal voltage peaks occur at the same time for the same
phases of both buses).
In the USA and some other parts of the world the letters
“A,” “B,” and “C” are usually used to identify primary phase
conductors in terms of phase relationships – the relative
sequence of the voltage peaks applied to the conductors;
“a,” “b,” and “c,” are used to identify the secondary phasing.
One purpose for phase identification is to determine where
to connect single-phase loads to balance the loads on the
three phases. Another purpose for phase identification is to
provide a means to determine tie switch and transformer
connections to maintain the same phase sequence so that
motor load rotation direction will be correct when secondary
system loads are transferred between different transformers.
The third purpose of phasing is to match both the phase
voltages’ magnitudes and the timing of the peak sinusoidal
voltage peaks, such to allow the paralleling of two secondary
systems without causing short circuit current to flow.
Phasing “A”, “B”, and “C”, and/or “a”, “b”, and “c” indicated
on one electrical system might not match the phasing on
another system. This may be caused by arbitrary identifications made when the system was first installed, by the phase
shifts caused by different transformer connections, or by
incorrect connections at tie switches.
The only way to verify that two similar voltage systems are
in phase is to determine that zero volts (or nearly zero) exists
between the same phases of the two systems. A rotation (or
phase sequence) meter is insufficient and unnecessary for
verifying phasing. A rotation meter is useful only to check
that motors will rotate in the correct direction after reconnecting leads or other parts of the power circuit. A phaseangle meter or an oscilloscope is useful to determine if the
voltages of one circuit leads or lags the voltages of another
circuit, but they are not necessary. The minimum equipment
required verifying phasing is either a voltmeter or phasing
sticks as necessary for the system voltage.
To understand the phasing process, it is necessary to know
the voltage and phase-angle relationships that exist between
same phases of two systems. See table 1. It is assumed that
9
Transformer Handbook — Volume 1
Table 1
Voltage Measured
Displacement Between Phases
of Two Systems
1.
2.
3.
4.
5.
6.
7.
8.
0 (or nearly 0) volts
Slightly more than 0.5 times phase-to-ground voltage
Phase-to-ground voltage
Slightly more than 1.4 times phase-to-ground voltage
Phase-to-phase voltage
Slightly more than 1.9 times phase-to-ground voltage
2 times phase-to-ground voltage
Inconsistent voltages **
0º (in phase)
30º *
60º *
90º *
120º *
150º *
180º
Ungrounded
*
**
Leading and lagging cannot be determined by only measuring voltages.
Ungrounded systems must be temporarily grounded or one phase connected to a grounded system to determined
phasing.
the phase-to-phase voltages of the two systems are identical.
In the field, due to loading conditions, the voltages measured
may be slightly different than indicated.
Before Attempting to Perform Phasing
Before phasing, verify that the transformers on the two
systems are on the same voltage tap. If not, the transformer
with the higher secondary voltage will carry more of the
load when the systems are paralleled. Also verify that the
percent impedance (%Z) of the transformer for one system
is closer than 92.5 percent to 107.5 percent of the %Z of
the transformer for the other system. The system with the
transformer with lower %Z will have a higher voltage when
loaded and, therefore, will carry more of the load when
paralleled.
Determining Phasing by Measuring Voltages across Two Systems
Phasing problems can be determined and resolved
by simply recording the voltage measured between each
phase of two systems and comparing the results with the
following:
SITUATION # 1: Correct Phasing
Zero voltage (or nearly zero) is measured between the
phases of each system. The two systems are in-phase with
the same rotation. The systems can be paralleled.
SITUATION # 2: Transformer or Tie Switch Leads
Connected in Wrong Sequence
Phase-to-phase voltage is measured between the same
phase of each system. The systems both have the same rotation but are 120º out of phase as indicated by the phase-tophase voltage. To correct, move the leads on one system at
the transformer primary, secondary, or at the switch such
that what was A is B, what was B is C, and what was C
is A. If the systems are still 120º out of phase, repeat the
process one more time. The use of a phase-angle meter
would indicate which way to shift the leads, but that is not
actually necessary.
SITUATION # 3: Two Leads Reversed on WyeDelta Transformer
Phase-to-phase voltage (120º) is measured between two
buses of each system and zero volts (0º) is measured between
the third buses of each system. This indicates that the systems have opposing phase sequence (rotation). This occurs
when the systems have wye-delta transformers. To correct,
exchange either the transformer primary or secondary leads
(or on the switch) on the phases where the phase-to-phase
voltages were measured.
SITUATION # 4: Two Leads Reversed on DeltaWye Transformer
Phase-to-ground voltage (60º) is measured between two
phases of each system and “two times phase-to-ground”
voltage (180º) between the third phase buses of each system.
This indicates that the systems have opposing rotation. This
occurs only with a delta-wye transformer. To correct, exchange two leads on the primary. The rotation will be correct,
but the systems may still be out of phase by 120º. If so, rotate
the primary leads once as indicated in Situation # 2.
SITUATION # 5: Double-ended Substation Transformer with Incorrect Phasing
Phase-to-ground voltage (60º) is measured between each
of the three buses. This occurs on the 480 volt buses between
the two delta-wye transformers in a double-ended substation
10
where one transformer is correctly connected but the other
is not. If the transformers are identical (not mirror images
of each other) and are facing each other, the second transformer may have primary “A” phase connected to H3, and
“C” to H1; and secondary “a” phase connected to X3, and
“c” connected to X1. To correct the problem, two primary
leads must be exchanged and the same two secondary leads
exchanged. It does not matter which leads are exchanged,
except, for example, H1 and H2 are exchanged, X1 and X2
must be exchanged also. This is a major problem since it is
often difficult to exchange the secondary (480 volt) leads.
This usually occurs when a standard transformer replaces a
mirror image (H1/H3 and X1/X3 are reversed) nonstandard
transformer in a double-ended substation.
SITUATION # 6: Non-Standard Delta-Wye Transformer Bank
Two times phase-to-ground voltage (180º) is measured
between the three buses on two systems supplied by deltawye transformers. This is caused when one system has a
nonstandard delta-wye transformer bank. The secondary
winding polarities are reversed in a nonstandard transformer.
A standard transformer bank made up of three single-phase
units can be made to match the system by reversing the wye
winding connections.
SITUATION # 7: Attempting to Parallel Transformers with Different Phase Relationships
Slightly more than 0.5 times phase-to-ground voltage is
measured indicating that the two system voltages are 30º
out of phase. Slightly more than 1.4 times phase-to-ground
voltage is measured, indicating that the two system voltages
are 90º out of phase. Slightly more than 1.9 times phase-toground voltage is measured indicating that the two system
voltages are 150º out of phase. Two systems that have any
combination of these phase relationships have wye-delta or
delta-wye transformers on one system and delta-delta or
wye-wye transformers on the other system. These systems
cannot be paralleled. If all three measurements are the
same, either 30º, 90º, or 150º, the rotations are the same and
the motor loads may be safely transferred by dropping one
system and picking to loads on the other system.
SITUATION # 8: Phasing Ungrounded Systems
Inconsistent voltages are measured across the buses
of two systems, indicating that one or both systems are
ungrounded. This can be verified by measuring the phaseto-ground voltages of each system. Due to imbalanced
phase-to-ground capacitances, a phase-to-ground voltage
on an ungrounded system can be more than two times the
phase-to-phase voltage.
To verify phasing if both systems are ungrounded, the
systems must be temporarily grounded by (1) verifying that
the systems are ungrounded, (2) installing fused ground
jumper (this wire must carry only a small amount of insulation capacitive charging current) on one and the same phase
Transformer Handbook — Volume 1
of each system, and (3) energize the buses and measure
the voltages between the same phases of each system. If all
three (one phase must be zero since they are both grounded)
measurements are nearly zero, the systems can be paralleled
after the temporary grounds are removed.
If one system is grounded and one is ungrounded, the two
systems can be phased by connecting the same phase of the
two systems together and measuring the voltages across the
other two phases. Care must be taken because if the wrong
phases are connected together, the phase-to-ground voltage
on the other two phases of the ungrounded system will be
2.0 and 2.75 times normal phase-to-ground voltage.
Conclusions and Comments
The intent of this article is to show most of the basic
phasing problems encountered when designing electrical
power systems and when verifying phasing in the field.
Whenever performing phasing, always follow good, electrical safety practices. Use equipment that has been inspected
and tested and wear body, head, face, and hand protective
clothing when working near energize parts.
Mark Lautenschlager is President of ERC - Electrical Risk Consultants International, Inc., of Tampa, FL. He is retired from High Voltage
Maintenance Corporation as Vice President of Engineering and is a past
president of NETA.
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11
Transformer Handbook — Volume 1
Loading Conditions Causing Loss of
Life for Oil-Filled Power Transformers
NETA World, Fall 2000
by Mark Lautenschlager, P.E.
President, ERC International, Inc.
The reliable operation of an oil-filled transformer depends
on the dielectric and mechanical strength of the cellulose
insulation in the transformer. But cellulose insulation “ages”
or deteriorates over time. The rate of aging depends on the
insulation temperatures produced by the combination of
heat caused by the load currents in the windings (but limited
by the cooling system) and the heat from the surrounding
air. Since heat produced by the transformer windings must
be according to the formula I2Rt (disregarding the heat
produced by no-load losses), it is directly proportional to
winding resistance and time and by the square of the current in the windings. Therefore, as the load is increased the
temperature increases at a faster rate.
The IEEE provides a standard power transformer loading
guide, ANSI/IEEE C57.92-1981: Guide for Loading Mineral-Oil Immersed Power Transformers, that can be used to
evaluate the temperature effects and loss of insulation life
of a transformer due to overloading. The IEEE standard
nameplate kVA rating is determined when the average
ambient temperature of the air surrounding the radiators
for any 24-hour period is 30ºC, not exceeding a peak of
40ºC. Further, oil-filled power transformer winding and
cooling system designs must limit the rise in average winding temperature to either 55ºC or 65ºC above the ambient
temperature at full rated kVA. The hottest spot temperature
in the insulation, at full load, must not exceed the average
winding temperature by 10ºC for a 55ºC rise transformer
and 15ºC for a 65ºC rise transformer. It is the “hottest spot”
temperature that affects the aging of transformer insulation.
The IEEE “normal rate of aging” occurs when the hottest
spot temperature for a 55ºC rise transformer is 95ºC (55ºC
winding rise + 10ºC hottest spot rise + 30ºC average ambient) and for a 65ºC rise transformer when the hottest spot
temperature is 110ºC (65ºC winding rise + 15ºC hottest
spot + 30ºC average ambient). Some power transformers
are rated 55/65ºC rise. For these transformers, although
the winding temperature rise at full load is only 55ºC, the
insulation is rated for the 110ºC hottest spot temperature.
A 55/65ºC rise transformer can be loaded to about 112
percent of the nameplate kVA rating before the hottest spot
temperature reaches 110ºC.
Oil-filled power transformers are not expected to operate
continuously throughout their lives at the maximum hottest spot temperatures (95ºC or 110ºC). According to the
IEEE guide, transformer insulation under these conditions
will age at the rate of 0.0369 percent and will reach the
end of useful life in only 7.5 years (2700 days). Usually, a
transformer is only occasionally operated at full load, and in
North America the average ambient temperature normally
is less than 20ºC. Therefore, the expected life of oil-filled
power transformers is about 30 years when operated at full
load occasionally. If a transformer were continuously operated at a constant load of approximately 80 percent in air
with a constant ambient temperature of 20ºC, the hottest
spot temperature would reach about 95ºC. In this case, the
transformer life expectancy will be about 50 years.
Since transformer kVA ratings are based on an average
30ºC ambient temperature, the ratings can be adjusted to
actual ambient conditions. For every degree of increase in
the average 24-hour ambient temperature over 30ºC, the
self-cooled (OA) kVA ratings are reduced by 1.5 percent
and 1.0 percent for forced-air and forced-oil-air cooled
(FA/FOA) ratings. For every degree of decreased ambient
temperature less than 30ºC, the kVA rating is increased by
1.0 percent for OA cooled transformers and 0.75 percent
for FA/FOA cooled transformers. In cases where cooling
efficiency may be reduced (poor radiator ventilation or dirty
radiators), 5ºC or more should be added to the ambient
temperatures when rerating transformers.
The IEEE guide provides useful tables and charts that,
along with any available manufacturer’s test data, can be
used to evaluate percent loss of insulation life when a transformer is loaded (for any periods up to 24 hours) in excess
of the nameplate kVA rating. Although the hottest spot
temperature and the time period are directly responsible for
loss of life, the tables also allow the use of other data such
12
as loading, top oil temperature, ambient temperatures, the
type of cooling, and pre-existing operating conditions to
determine estimated percent loss of life. For example, if
an FOA cooled power transformer that had been operating at 70 percent of nameplate kVA (adjusted for ambient
temperature) was then loaded to 138 percent of rating for
24 hours with an average ambient of 20ºC, the expected
loss of life is four percent or 438 days (four percent of 30
years—the life expectancy when occasionally operated at
full load). For an OA cooled transformer under the same
conditions the loss of life is only 1.0 percent. The IEEE
guide data is based on laboratory experiments performed
more than 20 years ago, and even the IEEE considers them
to be conservative. Nevertheless, unless the manufacturer
of a transformer can provide more accurate data, the tables
provide useful guidelines when determining the effects of
loading and ambient temperatures on the life expectancy
of a power transformer.
Since insulation loss of life is based on insulation temperature and time, for equal loss of life, a transformer may be
slightly overloaded for a long time or extremely overloaded
for a short period of time. The IEEE recommends that the
maximum top oil temperature be limited to 110ºC and the
hottest spot temperature be limited to 180ºC for a maximum of two hours. These limits would be obtained if 150
percent of nameplate load were applied on a 65ºC rise FA
or FOA cooled transformer (that had been operating at 90
percent load at 30ºC ambient) for a two-hour period. This
emergency condition would cause a loss of life of about 0.5
percent for a FA transformer and 1.0 percent for a FOA
transformer.
Monitoring power transformers for insulation loss of life
using only loading as a guide is insufficient, since loading
does not include the effects of ambient temperatures or
cooling problems. The best way to monitor insulation loss
of life is to use the hottest spot temperature. Unfortunately,
except for very large transformers, a gauge for this is not
often installed. Most medium to large power transformers
have winding temperature gauges. These gauges can be used
(if correctly calibrated) to monitor insulation temperatures.
At full load for a 55ºC rise transformer, the hottest spot
temperature is 10ºC greater than winding temperature and
15ºC greater for a 65ºC rise transformer. The poorest way
to monitor insulation temperatures is using the top oil temperature gauge. Due to differences in cooling system designs
– amount of oil and the number and type of radiators, fans,
and oil pumps—and the delay for top oil temperature to
rise, top oil temperatures are poor indicators of insulation
temperatures. The actual relationship between winding
temperature and top oil temperature should be determined
by factory tests. For 55ºC rise transformers, typical top oil
temperature rises (above ambient temperatures) at full load
are 45ºC for self-cooled transformers, 40ºC for forced-aircooled transformers, and 37ºC for forced-oil-air-cooled
transformers. For 65ºC rise transformers, typical top oil
temperature rises at full load are 55ºC for self-cooled transformers, 50ºC for forced-air-cooled transformers, and 45ºC
for forced-oil-air-cooled transformers.
Transformer Handbook — Volume 1
Power transformers must sometimes be overloaded.
Transformer users cannot always afford to install power
transformers to be sized for all contingencies—extremely
hot days or for accepting loads from failed equipment—and
must accept some transformer loss of life rather than shed
load. Therefore, when installing or reinforcing power
systems, owners must consider worst case conditions and
determine acceptable loss of transformer life caused by
overloading transformers for those conditions. The IEEE
indicates that some users consider an average loss of life of
one percent per year for emergency conditions over the life
of the transformer or four percent for any one emergency
to be acceptable loss of life.
If it is desired that a power transformer have a life expectancy of 50 years or more, the transformer should never be
overloaded nor be continuously loaded to much more than
80 percent of nameplate kVA rating. If conditions exist
that may require a transformer to be continually loaded to
nearly 100 percent or overloaded at times, then “loss of life”
evaluations should be made using the IEEE guideline and
manufacturer’s test data. Sometimes it is not justifiable to
size transformers for all emergency loading contingencies.
One major electric utility indicates that engineering economic studies allows them to load and overload their power
transformers such to produce 20-year life expectancies
When monitoring power transformers, review not only
the loading and top oil temperature data but also the winding and hottest spot temperatures, when available. Excess
insulation loss of life occurs when the hottest spot temperature exceeds either 95ºC for 55ºC rise transformers or
110ºC for 65ºC rise transformers. Load current and top oil
temperatures are only factors producing the resulting hottest
spot temperature, and may be misleading. Also, when operating transformers near their full rating make certain that
all radiators are clean, that cooling air is well vented from
other heat sources, that all fans and oil pumps are operating,
that all temperature and fan/pump alarms are operational,
and that all temperature gauges are calibrated.
Mark Lautenschlager is President of ERC - Electrical Risk Consultants International, Inc., of Tampa FL. He is retired from High Voltage
Maintenance Corporation as Vice President of Engineering and is a past
president of NETA.
13
Transformer Handbook — Volume 1
Transformer Failure Data
NETA World, Winter 2000-2001
by Mark Lautenschlager, P.E.
President, ERC International, Inc.
I was looking through my stacks of transformer books,
notes, and class outlines and found a photocopy of a booklet
entitled “Trans-formers — what price reliability?” authored
by Mr. E.V. Sorrell, who was Assistant Chief Engineer of
Hartford Steam Boiler at the time the booklet was published. Although the booklet is likely ten years old, the data
is still of value. Hartford Steam Boiler insures total plants
and prepares studies of the nature of equipment failures,
including transformers. The data presented in this booklet is
of interest to both those that maintain and those who own
transformers. From this data some conclusions can help us
reduce transformer failures.
Based on the results of hundreds of transformer failures
occurring during the few years before the booklet was prepared, Hartford Steam Boiler tabulated lists of the transformer parts that initially failed and the causes of failures.
DATA FROM HARTFORD STEAM BOILER BOOKLET
(percentages rounded)
INITIAL PARTS THAT FAIL
High-voltage windings 58%
Low-voltage windings
20%
Bushings and insulators 9%
Leads
4%
Tap changers
3%
All others
6%
CAUSES OF FAILURES
Lightning
External short circuit
Manufacturing error
Insulation deterioration
Overloading
Moisture
Lack of maintenance
Sabotage, vandalism
Loose connections
All others
32%
14%
11%
10%
8%
7%
7%
3%
2%
6%
Winding age when transformers failed:
Range: 1 month to 60 years
Average: 6.4 years
Hartford reported that the frequency of failure had not
changed appreciably over the 12 years before the study, but
the average cost of a transformer loss increased five times
over the 12-year period.
This data indicates that while we need to keep testing
transformer oil and performing thermographic inspections
of bushing connections we also need to:
• Make sure that we are buying transformers from manufactures that maintain strict quality control.
• Not overload transformers and make certain that overcurrent protection is adequate and operational. Newer
transformers do not have margins to handle overloads
and excessive short-circuit current.
• Make certain that all transformers are protected with surge
arresters and that the arresters are connected to ground
via a low resistance path.
• Monitor the condition of transformer windings and
bushings using the NETA recommended tests.
• Do not assume that a transformer has a low risk of failure just because it is not old. Harford noted that the
average age of a winding, when it fails, is only 6.4 years.
Mark Lautenschlager is President of ERC - Electrical Risk Consultants International, Inc., of Tampa FL. He is retired from High Voltage
Maintenance Corporation as Vice President of Engineering and is a
past president of NETA.
14
Transformer Handbook — Volume 1
Managing the Life
of Power Transformers
NETA World, Winter 2000-2001
by Brian D. Sparling
GE Harris Energy Control Systems Canada, Inc.
The challenges facing the electric utilities for the past
years are unrelenting and can be summed up in one sentence: “Reduce operating costs, enhance the availability of
the generating and transmission equipment, and improve
the supply of power and service to the customer base.” All
this in an environment where the available resources are
decreasing and the pressure from the shareholders and the
competition is mounting steadily.
Critical oil-filled, electrical equipment such as transformers, shunt reactors, current transformers, and bushings are
key elements of an electrical power system. Their reliable and
continued performance is the key to profitable generation
and transmission of power.
The early detection of incipient faults in transformers,
shunt reactors, current transformers, and bushings can create economic benefits that have a measurable impact in the
results required to meet these formidable challenges.
Dissolved Combustible Gases in Oil
Dielectric oil and solid cellulose dielectric insulation
(paper) materials break down under thermal and electrical
stresses in the transformer. This process produces gases of
varying concentrations relating to the stresses applied to
these materials. The gases dissolve into the oil. The nature
and concentration of the gases are indicative of the nature
and severity of the fault in the transformer. The changes in
the accumulation of each gas and their rate of production
are very important factors in the determining the fault(s)
involved and their evolution. Some specific gases are recognized as being indicative of certain types of faults.
The thermal degradation of oil-impregnated cellulose
produces carbon monoxide and carbon dioxide (Figure 1).
Hot spots in the windings, on insulated leads, and in areas
where pressboard and cellulose components and spacers are
used produce both of these gases as well.
The Overall Benefits of Monitoring and
Managing Transformers
The overall benefits of monitoring and managing transformers include:
• Use and load your critical transformer for maximum
economical efficiency.
• Manage and extend the life of the transformer with efficient and cost-effective maintenance.
• Detect the early signs of failure conditions and monitor
the evolution of on-going failure conditions.
• Reduce and possibly eliminate unscheduled outages
and failures.
Many gradually-evolving incipient fault conditions in
transformers have detectable symptoms that indicate problems. One of these symptoms is the production of dissolved
combustible gases in oil.
Figure 1
15
Transformer Handbook — Volume 1
The degradation of the oil through abnormal dissipation
of energy within the transformer can be detected based
on the gases produced. The energy released through fault
processes such as overheating, partial discharge (or corona),
and arcing causes characteristic gases to be formed by the
chemical degradation of the oil molecules. The detection of
these gaseous products allows for not only the identification
of the fault process, but also for its monitoring.
These degradation byproducts, known as fault gases,
include hydrogen as well as hydrocarbon gases: methane,
ethane, ethylene, and acetylene. It is important to note that
each of these gases has a characteristic energy required for
its specific formation. As a result, the individual gases can
be related to a specific fault process (Figure 2).
at all. A serious problem could easily start, go undetected
for days, weeks, or even months, and fully evolve into a
catastrophic failure with no warning. All of this could occur
after a good DGA and before the next scheduled DGA.
In order for a DGA program to be truly effective, one of
two changes should be made:
1) Either DGA needs to be performed on a much more
regular basis, approaching the unrealistic schedule of
once per day
OR
2) A cost-effective and reliable real-time gas-trending trigger or early warning signal should be used to effectively
bridge the time gap between regularly-scheduled DGAs.
System Protection Versus Transformer
Protection
Figure 2
Early Detection on Oil-Filled Transformers
Regularly-scheduled and periodic use of the dissolved gas
analysis (DGA) method on a transformer population usually
reveals that 90 percent of the sampled units are behaving in
a satisfactory manner. The balance of the unit samples may
be suspect and, therefore, closely watched. The satisfactory
behavior of a transformer is when the transformer has not
deviated from its previously-established baseline, equilibrium point, or fingerprint. A normal and constant gas level
for one transformer may be very high for another. Each
transformer has its own unique normal gassing pattern. It is
the change in gassing levels and, equally important, the rate
of change in gassing levels that cause a problem unit to stand
out from the others.
A DGA represents only a five-minute data window or
snapshot in time about the condition of a transformer. It can
not and will not guarantee that a good report means status
quo until the next DGA is performed.
If a DGA is applied on a six or twelve-month schedule,
there are markedly long periods of time during which the
well-known, proven, and well-established fault characteristics (fault gases) of the transformer are not being monitored
Power transformers represent the second or third most
costly replacement component on any electric power system. For years, the position was that power transformers
never fail… they last forever! Consequently, well-established
protection schemes involving transformers emphasized
system protection rather than true transformer protection. As
standard practice, devices such as transformer differential
relays, sudden pressure relays, and gas accumulation relays
were developed and utilized to isolate the transformer from
the power system in the event of a transformer failure. The
emphasis has been on protecting the power system from the
transformer rather than protecting the transformer itself.
Protective devices such as overcurrent, overvoltage, and
overtemperature relays are also applied (and need to continue) in order to keep the transformer within the designed
operational limits. Not one of these devices sense or detect
serious problems evolving from the dielectric stress (breakdown of the insulation system within the transformer),
which is the fundamental failure mode of any transformer.
Based on currently available reliable fault gas sensing
technology and the fact that there is an aging transformer
population in higher risk categories, rethinking of how the
transformers can be protected from undetected and unexpected failure modes needs to be done.
How Often?
How often should DGAs be performed to guarantee
maximum transformer protection? If the reliance is on the
DGA technique alone, then the answer that makes the
most sense is more often than the fastest-evolving transformer
failure mode.
The following case can demonstrate this (Figure 3).
This 150 MVA, 138/69 kV autotransformer had a GE
Syprotec HYDRAN® 201R Model i on-line gas monitoring
system installed in April 1996. During the first month of
operation, the transformer exhibited normal gassing behav-
16
Transformer Handbook — Volume 1
Whether included in new transformer specifications or
installed on existing transformers, continuous on-line fault
gas monitoring will provide some assurance and the protection necessary to successfully bridge the time gap between
regularly scheduled DGAs.
Figure 3
ior (a flat baseline of dissolved combustible gases). Shortly
after a thunderstorm, the monitoring system detected a
small increase in gases. Two weeks later the circuit breaker
associated with the transformer failed to clear a fault which,
of course, put a severe stress on the insulation system. A few
weeks after these two stressful events, the monitoring system
detected a rapid increase in combustible gas levels. The rate
of change was in the order of 1000 ppm in 24 hours. None
of the normal “transformer protection” relays operated.
The monitoring system provided the alarm that something
drastic was occurring inside the transformer.
The transformer was immediately removed from service,
and, upon inspection in a repair shop, the fault was found to
be a puncture through the barrier between the low-voltage
windings and the core. This puncture was felt to have been
initiated by the two external events and the final path-toground for the discharge took a couple of weeks to appear
in the form of rapidly-increasing dissolved gases.
Without the early warning that the monitoring system
provided, it is easy to see that events such as this can go undetected, and have the potential for catastrophic failures.
Conclusion
Transformers which do not feature continuous on-line
fault gas monitoring as part of their standard protection
scheme are at risk of an unexpected failure.
Direct and indirect costs of a transformer failure damage to surrounding equipment and high replacement costs
are many times greater than the installed cost of currently
available fault gas monitoring systems. The other aspect
of safety, as it relates to operating personnel in the area of
the transformer should it fail catastrophically, may also be
averted with appropriate indicative fault monitoring.
Brian D. Sparling is the Product Manager of integrated substation
monitoring and diagnostics for GE Harris, a joint venture business owned
by GE Power Systems and Harris Corporation. Based in Calgary, Alberta,
GE Harris specializes in the design and manufacturing of advanced systems and technologies applicable to substation automation solutions.
Brian has over twenty years’ experience in the field of power and
distribution transformers and has worked on many standards committees
within the CSA and the Canadian Electricity Association, serving as the
past chair of the Distribution Transformer Committee. Brian is also a
member of the IEEE Transformer and Substation committees.
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17
Transformer Handbook — Volume 1
Maintaining GE Gas Filled
Transformers
PowerTest 2001
(NETA Annual Technical Conference)
Presenter
Edward C. Smith, QualorTran, Inc.
Co-Author
Edwin L. Mathis, P.E., Transformer Engineering Services, Inc.
The Sealed Dry-Type Transformer1 was initially designed, tested and manufactured at the General Electric
Transformer facility in Pittsfield, Massachusetts then the
product scope moved to the General Electric Transformer
facility in Rome, Georgia during the 1950’s. The gases used
in these units were nitrogen (N2) and the fluorocarbon gases
octafluorocyclobutane (C4F8), octafluoropropane (C3F8)
or hexafluoroethane (C2F6). It is estimated that there were
less than 5000 transformers manufactured in total when
the product line went out of production in 1986. The GE
VaporTranTM Transformer used trichlorotrifluoroethane
(CCl2FCClF2) but had different construction and maintenance requirements2 so it is not included in the Sealed
Dry-Type Transformer product line.
The Sealed Dry-Type Transformer product line included
500 kVA through 2500 kVA self cooled ratings and were
available in 5 kV & 15 kV class with 480Y/277 secondary
voltage the most popular offering. Other kVA and voltage
designs were also available. The line was designed to be in
compliance with ANSI C57.12.52.
The core and coil assembly was very similar to a ventilated dry-type transformer. Solid insulating materials and
a treating varnish suitable for the hottest spot temperature
were used. The varnish treatment promotes heat transfer
by conduction within the winding and seals the insulation system to minimize moisture absorption when the
transformer is not in operation. The windings are circular
construction of either copper or aluminum with rectangular
cross section conductors as required by design or customer
specification.
The internal assembly was sealed in a pressure tight steel
tank equipped with bushings which were welded in place for
connection to the supply and secondary circuits. The tank
is pressurized to a small positive gage pressure at ambient
temperature and operates at some positive pressure. The
nitrogen filled units are essentially a ventilated dry-type
transformer sealed in a box but are much larger and heavier
due to inferior heat dissipation characteristics and tank
weight. The standard nitrogen tank design is not braced for
full vacuum. The units filled with C4F8, C3F8 or C2F6 have
improved heat transfer capabilities and electric strength
are smaller in size and weight. These tanks are braced for
full vacuum to withstand fill, operation and maintenance
requirements.
The initial charge pressure for Sealed Dry-Type Transformers varies by type of gas, i.e., nitrogen or fluorocarbon
and specification. The nameplate attached to the transformer
provides information about the gas and charge pressure versus temperature. Typically, GE Rome produced transformers
were charged at 4 psig at 25 C for the fluorocarbon filled
units and 1 psig at 25 C for nitrogen filled units.
These fluorocarbon gases are non-flammable, non-explosive and non-toxic. They are extremely stable even under
abnormal operating temperatures. Tests with temperatures
far above those encountered under all operating conditions
indicate negligible corrosion or de-composition of the gas
in contact with materials within the transformer.
Sealed Dry-Type Transformers may be operated at rated
load on any voltage tap. The operating temperature of the
transformer winding is determined by the load it carries, its
thermal characteristics and the temperature of its cooling
medium. Heavy loads of short duration may produce the
same winding hot spot temperature as lighter loads of longer
duration. Overloads of sufficient magnitude and duration
may cause excessive heating. Excessive heating will result
in insulation deterioration which reduces normal life. The
overload capacity is limited not only by winding hot spot
temperature but also by the tank pressure. On overloads, the
pressure will increase in proportion to the increase of inside
gas temperature. The normal full load operating pressure of
the transformer tank is approximately 12 psig for fluorocarbon gases and 8 psig for Nitrogen gas filled units. There
18
will be no permanent tank distortion with pressures up to
15 psig for fluorocarbon gases and 10.5 psig for Nitrogen
gas filled units. It is recommended that these pressures not
be exceeded.
The Sealed Dry-Type Transformer is an excellent design
if the gas atmosphere is maintained to original factory specification. Failure to do so can lead to reduced performance
and product failure.
The focus for preventive maintenance is then to correct
high risk seal failures before they occur to prevent the loss
of the gas atmosphere, identify the presence of air & moisture and provide a means to restore original design kVA
and performance.
The remainder of this paper discusses the monitoring
devices and techniques to be used to determine the condition of the transformer, the effects of a reduced atmosphere
and a preventive maintenance program to resolve these
problems.
Monitoring Devices and Technique
Sealed Dry-Type Transformers are typically equipped
with two instruments to monitor internal conditions of
the transformers. When properly interpreted, these instruments can give indication of the need for maintenance or
impending problems.
ANSI standards outline a temperature indicating device
and pressure gage. The temperature device typically is one
that measures the top gas temperature of the transformer.
The alternative temperature device is a winding temperature
simulator. These devices react to the internal temperature of
either the insulating gas or the winding temperature or the
winding hot spot temperature. The pressure gage displays
the internal tank pressure. The scale range may vary based
on the year of manufacture but is normally from – 30” Hg.
to 15 psig for fluorocarbon based gases or from – 20” Hg.
to 10 psig for nitrogen filled units.
GE offered three basic temperature sensing devices for
the sealed dry type transformer. Initially, the units were offered with a Hottest Spot Indicator-Relay. Since standard
product accessories varied from time to time, it is possible
that not all units were equipped with this device. Th is
device provided a means of reading the winding hot spot
temperature, thus giving a visual indication of the amount
of transformer capacity being utilized. It was equipped
with switch contacts for control and alarm purposes. The
dial was calibrated in degrees centigrade and the normal
operating temperature range shown in green and the overheated range in red. Here it was necessary for users to have
an understanding of hot spot temperature versus winding
temperature. This device had two detectors, one for the gas
temperature, the other for the winding lead temperature,
typically attached to the LV center phase lead just as the
lead exited the LV winding. Experience with the device
showed that if the readings were high to expectations, the
gas bulb was leaking. If the device was showing readings
lower than expectations, the winding lead bulb was leaking. Replacement requires that the gas in the transformer
be evacuated and then the unit vacuum filled with new gas
after the process is completed.
Transformer Handbook — Volume 1
Later in time, circa 1972, the device offered was a Hot
Spot Indicator. This device provided a means of reading
simulated winding hot spot temperatures, thus providing
the visual indication of loading. This device is mounted in a
heater well assembly near the top of the transformer tank in
the hottest part of the insulating gas. Current for the heater
is provided by a current transformer located inside the main
unit. It is factory calibrated with an external resistor enclosed
in a sealed housing. The indicator can be replaced without
breaking the seal of the transformer.
Circa 1976, the device offered was a Top Gas Temperature Indicator. This device was a thermometer with a
temperature sensitive bulb inserted into a well mounted on
the side of the transformer tank near the top in the hottest
part of the insulating gas. Unlike its predecessors, this device
could not be relied upon as an indication of permissible load.
They recommended that the readings be taken at frequent
intervals to aid in detecting abnormal conditions affecting
the transformer. It is also mounted in a sealed well and can
be replaced without breaking the seal.
It is known, that for any given Sealed Dry-Type Transformer design, there is a specific relationship between the
transformer load, pressure and temperature. Expected Tank
Pressure, Top Gas Temperature and Hot Spot Temperature
at given Unit Loads and Ambient Temperatures can be
calculated for any given design. The calculations are based
on a design library search which is valid for transformers
with the same root serial number, i.e. – all digits the same
except the suffix letter as in F999999A, B, etc. These calculated values can be provided in table form and provide
an excellent tool for determining the present condition of
the transformer.
Two typical Load — Pressure tables are provided for
Nitrogen3 and C2F64 gas filled units to illustrate their use
in determining seal leaks, trapped non-condensable gases,
i.e. air and reduced cooling.
The Load — Table for Nitrogen filled units is based
on an initial de-energized tank pressure of 1 psig at 25 C.
To use the table, enter the row at the point equal to the
per unit load and the column equal to the room ambient
temperature. The intersecting element gives the expected or
design tank pressure at these conditions. The per unit load
is computed by dividing the low voltage load by the rated
amperage, i.e. – if the observed load is 1200 amperes and
the rated amperage for the 2000 kVA – 480Y/277 is 2406
amperes, the per unit load is 1200/2406 or 0.50. If the room
ambient temperature is 70 F, the expected or design tank
pressure in this case would be 4.3 psig.
The Load — Table for C2F64 gas filled units is based
on an initial de-energized tank pressure of 4 psig at 25 C.
With all other things being equal to the Nitrogen example,
the expected or design tank pressure in this case would be
7.3 psig.
Any variance of observed tank pressure from expected
or design pressure indicates the need for additional action,
i.e. – monitor to verify variance, meter & gage accuracy, air
& moisture in unit, detectable leaks, etc. The Preventive
Maintenance Program covers this area in detail.
19
Transformer Handbook — Volume 1
Effect of a Reduced Atmosphere
As stated earlier, maintaining the seal is extremely important to the continued reliable and efficient operation of the
transformer. The ingress of air/moisture into the unit will
affect both the thermal and dielectric capabilities of the unit.
To gain a better understanding of why this is so, we must
first consider some of the basic design parameters.
The design of the fluorocarbon filled transformer versus the nitrogen filled are significant in both thermal and
dielectric capabilities. Due to the superior thermal and
dielectric qualities of the fluorocarbon gases over nitrogen,
the internal clearances and thermal profiles of each are
different in significant detail. These characteristics allowed
the manufacturer to greatly reduce the size and weight of
the fluorocarbon design versus the nitrogen design, in some
cases by as much as 25%. The fluorocarbon design obviously
took advantage of these attributes with a material cost
take out and reduction in spacing of windings, leads and
other current/potential carrying items. When air (basically
nitrogen) is substituted for fluorocarbon gas, the dielectric
strength and thermal capabilities to conduct the heat away
from the winding conductor is significantly diminished.
In the event of a leak and subsequent loss of pressure, the
load must be reduced to prevent overheating of the insulation system. Leaks can be of any nature from very small,
such as a porous weld seam, fracture of ancillary or associated plumbing, to very large, as might be experienced from
fracture of a bushing. The nature of the leak and associated
swings in temperature of the unit as would be experienced in
normal load cycling, will determine the rate of escape of the
original gas and the subsequent absorption of atmospheric
air. The moisture will be of a degrading nature to the insulation system over time, however, the greatest consequence
will arise from the lack of cooling to the transformer windings elevating hot spots deep within the insulation system.
This will hasten deterioration of the insulation and result
in significant loss of life to an otherwise aged transformer.
As a general reference, the following curve is presented
to approximate the reduction of the initial characteristics
of the transformer. There are many other factors that can
affect these initial reference points including loading and
or overloading, exposure to transients, short circuits, high
ambient temperatures, harsh environments. Therefore, all
things should be considered on their own merits when applying this de-rating chart if used as a tool for continued
reliable operation of the transformer.
This chart is of the premise that as air, on the vertical scale
and expressed as a percentage, replaces the fluorocarbon gas,
the per unit load and the dielectric strength are diminished
as shown on the horizontal scale, also shown in percent.
If the unit has been run completely dry of gas, then the
load should be reduced at least to 50% of the transformer’s
nameplate value, perhaps more depending on other factors mentioned previously. You can make a determination
about the loading as this information is normally available
from demand meters, however, the dielectric capability is
unknown when a disturbance occurs. Since fluorocarbon
designs have inherently higher BIL’s (basic impulse levels)
100%
Air
50%
0%
50%
100%
Per Unit Load / Dielectric Strength
and are protected to those values, a partially charged unit
will be vulnerable to high voltage transients and surges and
could suffer an insulation failure requiring long term repairs
and / or replacement of the unit at great expense. It is very
important to insure that the seals of the unit and the gas
atmosphere are maintained to specification.
Preventive Maintenance Program
1. Initial baseline evaluation — It is helpful to have a
baseline evaluation of installed nitrogen and fluorocarbon filled units to determine the present condition of
the Sealed Dry-Type Transformers. An evaluation report with prioritized recommendations is provided as
part of the program by QualorTran, Incorporated for
the System Manager’s consideration and system documentation.
The evaluation depth requires the owner’s organization
assistance and approval.
Level 1 — verify adequate gas charge and cooling/loading capacity of transformers. Owner organization will
provide means of determining LV loading if not available
at the load center location. This level provides a good
means of determining major problems which could effect
present and future system reliability.
Level 2 — perform Level 1 plus leak test accessible components using an ultrasonic leak detector for Nitrogen
filled units and a halogen leak detector for fluorocarbon
filled units. Units must be at positive pressure to perform
leak tests. Pressures can be raised by increased loading,
increased ambient room temperatures, and by applying
an external heating source.
This level provides specific information required for leak
repairs of non-live components.
20
Level 3 — perform Level 1, Level 2 and schedule outage
to leak test high and low voltage bushings. This is the
most comprehensive but disruptive means for evaluating units as the seal integrity of all components can be
verified.
Level 1 evaluations can normally be performed in one day
for transformers installed at a contiguous plant location.
The time required for level 2 evaluations can be determined after a review of transformer loading profiles and
ambient room temperatures. Level 3 may require 3 hours
per transformer from the time a unit is de-energized until
it is put back on line.
2. Transformer upgrade and repair — replace/repair defective seals found during the initial evaluation, verify
calibration of temperature & pressure devices and upgrade gas circuit to include pressure port to allow test
of high & low pressure settings. Sample gas for air and
moisture content of units with history of leaks and restore all units to original factory gas pressure levels.
3. Annual Preventative Maintenance — verify adequate
gas charge and cooling/loading capacity of transformers. Perform level 2 & 3 evaluations as may required.
Detailed report of findings should be provided with a
prioritized listing of recommended corrective actions to
resolve observed problems and all information should
be included to satisfy environmental record keeping requirements.
It is strongly recommended that Load – Pressures Tables
be placed in clear view with each transformer for local use
monitoring units for gas loss and proper cooling. These
tables can be provided as a “nameplate” to permanently affix
to the transformer.
References:
1. Instructions, “Sealed Dry-Type Transformer, … ” GE
Transformer, Rome, Georgia 30165.
2. Smith, E.C., “Maintaining VaporTranTM Transformers”, 1997 NETA Technical Conference.
3. “Load – Pressure Table # 01011002”, QualorTran, Inc.,
Calhoun, Georgia 30701.
4. “Load – Pressure Table # 01011001”, QualorTran, Inc.,
Calhoun, Georgia 30701.
Transformer Handbook — Volume 1
VaporTran is a trademark of the General Electric
Company.
Edward Smith is founder and principal technical consultant of
QualorTran, Inc., a company focused on product service of GE VaproTran™ transformers and GE, Westinghouse and ITE N2, C2F6, C3F8
or C4F8 gas-filled transformers. Ed brings thirty years of relevant transformer design, manufacture, test, and service experience to the industry
with twenty-three years on the technical staff of GE Transformer™,
Rome, Georgia. Ed is recognized by GE as the world authority in all
aspects of manufacture, assembly, test, and service of GE VaporTran
transformers.
21
Transformer Handbook — Volume 1
The Detection of Mechanical
Damage in Power Transformers
Using the Sweep Frequency Response
Analysis Method
PowerTest 2001
(NETA Annual Technical Conference)
Presenter
Mario Locarno
Co-Authors
Tad Tully and Alan Wilson
Doble Engineering Company
Abstract
Power transformers are specified to withstand the many
rigors of service life. General ageing can produce long-term
changes to the insulation quality of oil, paper and oil pressboard materials. Physical changes can occur either through
long-term ageing and vibration or as a result of one or more
electrical transients. Core and winding movement can be
produced by through faults and transportation. To identify
this and other types of damage, a range of complementary
diagnostic tests are appropriate. Insulation quality, winding
and structural deformation, core grounding, shorted winding and other internal main tank problems can be identified using well established methods such as power factor,
capacitance, exciting current, turns ratio, insulation and
winding resistances, and leakage reactance. A new method
of measuring a transformer’s transfer function using a Sweep
Frequency Response Analysis instrument adds another tool
for a more comprehensive condition assessment.
Introduction
Power transformers are usually purchased with the
expectation of a satisfactory service life up to forty years.
However, evidence to support the realization of this intent
from construction programs, since the 1960s, appears mixed.
While under ideal circumstances lifetimes of forty years or
more are being achieved, a variety of events or circumstances
are causing much shorter terms. Various national and international studies have reported on failure rates and age. The
1983 comprehensive CIGRE report looked at units with a
service life up to twenty years and reported no significant
effect of age on failure rate (1). North American statistics
also indicate that for the general population, the failure
rate is random. Insurance companies report the average
age at failure is currently fifteen years (2). In their study of
GSU failures, EPRI reported that over a four-year period,
45 out of 383 units failed, with an average age at failure of
sixteen years (3). Major proportions of transformer failures
are a result of bushing and load tap changer malfunction
or failure. Within the main tank, the key areas of concern
relate to mechanical changes caused by short circuits, core
ground issues and the various degradation processes associated with moisture levels in the paper, barriers, and oil. One
way to avoid many of these premature failures is to have a
regular program of routine tests which tracks changes in the
performance quality of the main tank, LTC and bushings.
Power factor and capacitance testing of bushings and
winding insulation are for many utilities, a routine off-line
method of tracking dielectric deterioration. For a bushing this includes detection of higher dielectric losses and
capacitance following moisture ingress, short-circuited foil
layers and contamination of the core or porcelain surfaces.
The power factor will also allow tracking of winding moisture content, while the capacitance value will indicate gross
movement and loss of core grounds. Winding moisture
content is one of the most important factors affecting the
rate of paper ageing, and there is a long tradition of trending the winding power factor values throughout the lifetime
of a unit (4). Some power factor/capacitance units, such as
the Doble M4000 Instrument, can also be used to measure
other properties, such as those relating to the mechanical
condition of the core and windings. Its capability includes
22
turns ratio, exciting current and, with the M4110 module,
leakage reactance. This range of diagnostics collectively
covers many of the key malfunctions occurring with the
total transformer. Within international groups, such as
CIGRE Study Committee 12 (5) and the EuroDoble
Clients Group (6,7), there has been interest over the last
ten years in developing an additional test to focus upon
mechanical problems. This method measures the transfer
function of windings over a wide frequency range. While
the approach being used started in North America (8), the
greatest application has been in Europe. Many of the key
technical papers have been presented by European clients
and discussed at the Doble meetings during the 1990s (6,7).
The view within Doble is that this method does have a role,
and it is within the broad range of transformer condition
assessment tools, providing corroborative evidence prior to
an expensive consequential decision.
Mechanical Design Issues
Power transformers are specified to withstand the mechanical forces arising from both shipping and subsequent
in-service short circuits across the terminals. The most severe
service forces arise from close in system faults, faults in a
load tap changer and, for a generator transformer, energizing out of synchronization. Short circuit forces produce
axial and radial forces and these can lead to radial buckling
or axial deformation (twisting, displacement of clamps or
supports). Transport damage can occur if the clamping
and restraints are inadequate, leading to core and winding
movement. With a core form design, the principal forces
are in the radial direction, while a shell form design is in
an axial direction. This difference is likely to influence the
types of damage found.
The technology assisting transformer designers has
improved over recent years, but it is rare for the designs to
be evaluated other than by subsequent service life. Once a
unit has been damaged, even if only slightly, the ability to
withstand further short circuits is reduced. The requirement
is to have effective methods of identifying damage. One approach is to rely upon an internal Visual inspection, but it
is invariably too difficult to draw effective conclusions. The
oil has to be drained and confined entry rules apply. Since
so little of the winding is visible, often little is seen other
than displaced support blocks. Consequently, the reliance
must be on condition assessment methods. However, since
the consequences of an incorrect diagnosis are so great, a
mandate is to have a range of complementary and effective
diagnostic techniques available for field use.
The requirement is to identify damage of the following
types:
• Short circuit turns
• Open circuits
• Core ground problems
• Core movement
• Axial or radial deformation
Transformer Handbook — Volume 1
• Hoop buckling
• Partial winding collapse
• Broken or loose clamping structures
Timing of Condition Assessment to Determine
Mechanical Condition
Condition assessment evaluation of transformers would be
carried out on the following occasions:
• During an investigation, after a fault or protection
trip. The purpose would be to determine the nature
and extent of any damage.
• During a condition assessment. This test may done
as part of a general assessment, or the unit may be
known to have seen short circuits over time, and apparently successfully withstood them. In this latter
case the test would be to identify possible damage
and used to indicate the capability to withstand further short circuits.
• Before and after a relocation. Comparisons of test
data made before and after a relocation, which should
indicate any mechanical movement.
• By manufacturers as a quality check of the manufacturing process, by comparing the response of units
made to the same design.
• Testing is also carried out on new and refurbished
units to obtain fingerprint values for references. Also,
test results on sister units (similar design) can be used
as references.
Consequences of Diagnostic Testing
The result of such testing may have a number of
implications:
• If the test indicates damage or malfunction, and the
test has been performed after operation of a protection relay - the unit is likely to need a major repair
or scrapping. Further, confirmatory evidence may be
necessary (e.g. additional testing specific to the type
of fault indicated).
• If there is evidence of some damage or deformation,
but there are no other signs of malfunction - the unit
may be returned to service. Engineering judgment is
required to review the risk of failure at the next short
circuit, the likelihood of such an event, and the system risk exposure. The results would be stored and
used as a benchmark indicative of worsening of the
damage.
• Where there is no evidence of damage or deformation, and there is no other evidence (or expectation)
of a malfunction - the unit is validated for service and
the results archived for future use.
23
Transformer Handbook — Volume 1
Test Program
The following tools would be used:
• Insulation Analyzer - to measure capacitance and
power factor, exciting current and turns ratio.
• Leakage Reactance Interface - to measure short
circuit impedance.
• Sweep Frequency Response Analyzer - to measure
the transfer function.
• Winding and insulation resistance.
• Other test data relating to the period prior to deenergization could be relevant - such as dissolved
gases and furans from an oil sample, Infrared and
RIV scanning (PD).
The transformer would be de-energized and all high voltage connections removed. The circuit and the transformer
should be made safe for testing, according to standard company procedures. Ideally the transformer will have normal
service oil in the tank. For the test program it is necessary
to remove any temporary bushing ground connections. The
leakage reactance and SFRA tests also require removing
grounds from neutral bushings. A transformer with an off
load tap changer would be tested in its normal operating
position. A unit with a load tap changer would normally be
tested in an off-neutral position and preferably throughout
its full range.
Assessment
While the objective is to assess the mechanical condition,
the test data would be used to provide a more general assessment - of the insulation condition for example. Specifically,
however, the following methods would be applicable to the
mechanical assessment:
• Winding Capacitance
The Doble M4000 Automated Insulation Analyzer can be used to measure winding movement,
and is probably the most commonly used of all
the methods. The technique is capable of detecting gross winding movement. In addition, since
the capacitance of a low voltage winding is measured to ground, it is sensitive to disruption of the
core ground connection, and will detect gross core
movement. The sensitivity can be enhanced, where
it is possible, to make separate measurements on
each phase and so use inter-phase comparisons.
With autotransformers, it is not possible to measure inter-winding capacitances between high and
low voltage windings.
• Exciting (or Magnetizing) Currents
The Automated Insulation Analyzer can be used to
measure exciting currents and watts loss. This can
be one of the simplest methods to detect shorted
turns, following a short circuit. It can also detect
open and short circuits elsewhere - in the LTC,
core and core ground. It is a comparative method
with most of the supporting documents appearing in the 1970’s (9) where evidence was presented
that it can identify a range of core related features
- shorted laminations or fundamental changes in
the iron characteristics.
• Leakage Reactance/ Short Circuit Impedance
Standards for short circuit testing of transformers usually specify this measurement. It involves a
simple interpretation of a change in one value to
another and is very suitable for a contractual use in
a highly controlled environment. During factory
acceptance the impedance is measured with threephase excitation and high currents. Field test are
usually single phase and at a low current. To relate
the measurements it is necessary to undertake the
procedure according to the Doble method and the
M4110 Leakage Reactance Interface uses this approach (10). Experience indicates that an accuracy
of around 0.2% is needed to detect a 0.5% change
over nameplate values. The success of the method
relies upon the availability and reliability of factory
data. In some cases a phase-by-phase comparison
may assist in the analysis.
• Sweep Frequency Response Analysis
There is a direct relationship between the geometric configuration of the winding and core and the
series and parallel impedance network of inductance, capacitance and resistance. This network can
be identified by its frequency-dependent transfer
function. Frequency Response Analysis testing
by the sweep frequency method (SFRA) uses
network analysis tools to determine the transfer
function. Changes in the geometric configuration
alter the impedance network, and in turn alter the
transfer function. This enables a wide range of failure modes to be identified.
Doble uses the protocols developed by the EuroDoble Client Group. From this base, Doble has
subsequently developed an instrument to match
the requirements, the M5100 SFRA. The SFRA
method is also comparative between phases and
against previous results. There is also some commonality between units of the same design.
Sweep Frequency Response Analysis
A general impedance diagram for a transformer is shown
in Figure 1.
24
Transformer Handbook — Volume 1
Figure 1 — Transformer Impedance Model
The transfer function approach is to consider a transformer as though it was a simple inductance, capacitance
and resistance (L-C-R) equivalent circuit and determine
its frequency admittance response.
The basic measurement formula for the transfer function is:
Attenuation = 20*log (Vout/Vin) for all frequencies.
At low frequencies the impedance ladder is represented
by the series inductance and winding resistance. At medium
frequencies the capacitance to ground is relevant, and at
higher frequencies the relevant impedances are the series
and ground capacitances.
Much of the past work has been done using a laboratory
instrument – a super heterodyne network analyzer used over
a 10Hz to 10MHz range of frequencies. The Doble M5100
SFRA Instrument has been developed to meet the application requirement however; it is enhanced by the simplicity
of a single function, automated control, data storage, field
ruggedness and noise immunity. All of the features required
for substation test instrumentation.
Figure 2 shows a circuit diagram of the M5100 SFRA
Instrument. It has the following characteristics:
Figure 2 — M5100 SFRA Circuit Diagram
The M5100 SFRA Instrument has a signal generator,
which produces a 10VPP sine wave at the Source output
connection. Its frequency range is 10 Hz to 10 MHz. Within
this single band, 1024 logarithmically spaced, discrete frequencies at which measurements are made. A two-channel
oscilloscope is used to measure the voltage generated at
the specimen (S Measurement) and the return voltage (R
Measurement).
The transformer test involves applying a test signal to
one terminal of the transformer under test and measuring this applied signal at the same terminal, and also the
signal appearing at a second terminal, as shown in Fig 2.
Signals are applied and measured with respect to ground.
The amplitudes and phases of the two signals, S Measurement and R Measurement, are measured to determine the
relative amplitude and phase shift changes between them.
The basic measurement is of the attenuation and phase shift
of a signal after having passed through the winding from
the input to the output terminal. The test can also include
voltage transfers between windings i.e. applying a signal to
one winding of a transformer and measuring the response
at another winding to determine the amplitude change and
phase shift of the signal having been transferred along a
winding, or from one winding to the other.
Early attempts to gain repeatability, particularly using
impulse methods, were not successful. The success of the
SFRA method is the result of a significant effort in developing a common protocol by EuroDoble Clients.
While the application is now fairly straightforward,
interpretation requires experience to diagnose the type of
fault. Shown in Figure 3 is a typical set of results for an
autotransformer in good condition. For most transformers
there is a large attenuation at a specific low frequency,
usually between 400 – 1500Hz. Below this frequency,
the impedance is dominated by the series inductance and
measurement resistance of 50 Ohms. Since the impedance
is controlled by the core magnetization, this is where core
effects are seen and there is some equivalence with an excitation current measurement. The center phase response
is slightly different in this area of frequency, due to the
different flux paths through the core. In addition, the center
phase has a single null, shown at 600 Hz and the two outer
phases overlap with a double resonance around the same
frequency. At this frequency, there is a phase change of 180
degrees and the impedance changes from being inductive
to capacitive domination. At higher frequencies, in kilo and
megahertz ranges, eddy currents shield the magnetic circuit
and local leakage fluxes determine the winding inductances.
The response is more dependent upon changes in the winding, and the diagnostics should compare with the leakage
reactance measurements.
25
Transformer Handbook — Volume 1
Figure 3 — A Set of Normal Test Results from an Autotransformer
Figures 4 and 5 show the results from damaged units.
Experience shows that differences in the lower frequency
ranges relate to core changes, or shorted/open circuits.
Medium frequencies show winding shifts, while more
localized winding movement is seen at the higher frequencies. In the result shown in Fig.4 there are two phases that
overlay with a minimum at 400 Hz and again at 2200 Hz
however, the third (red trace) does not follow the same
pattern, as it should. It’s minimum has shifted indicating
a problem. Figure 5 also has identical resonances on only
two of the phases. Experience indicates that changes of
this type, at these frequencies are associated with winding
deformation.
Figure 5 — A Transformer With Axial Deformation
Conclusions
A power transformer is one of the most critical items in a
power system. It also has a very high capital value. In order
to achieve the full benefit of this asset, it is important to
have the most effective means of identifying any deterioration or malfunction. Visual inspections are not as effective
as on other types of apparatus, such as circuit breakers, yet
expensive decisions often have to be made relating to the
future serviceability. This can only be achieved through the
application of a broad range of complementary assessment
tools. Within this context, Sweep Frequency Response
Analysis with instruments such as the Doble M5100 SFRA
has a valuable role.
References
1.
2.
3.
4.
Figure 4 — Test Results Indicating Shorted Windings
5.
6.
CIGRE, “An International Survey on Failures in
Large Power Transformers In Service.” (1983), Electra NO 88, pp23-50.
W.H. Bartley, (1999), “An Analysis of Transformer
Failures, Part 1” Locomotive, 73, 2, pp 4-7.
S.L. Nilssen and S. Lindgren, (1997), “ Review of
Generator Step Up Transformer Failure Data”, EPRI
Substation Conference, New Orleans.
A.L Rickley (1985) “Transformer Insulation Power
Factors, A Progress Report” Minutes of the 52nd Annual International Clients Conference, sec 6-201
J.A.Lapworth (1997) “CIGRE Working Group
12.18 Life Management of Transformers - An Activity Overview.” ” Minutes of the 64th Annual International Clients Conference, paper 8-8.
J.A.Lapworth and A.J. McGrail (1999) “Transformer
Winding Movement Detection by Frequency Response Analysis” Minutes of the 66th Annual International Clients Conference, paper 8-14
26
7.
8.
9.
Transformer Handbook — Volume 1
T.J.Noonan (2000), “EuroDoble Subcommittee Report on Frequency Response Analysis by the Swept
Frequency Method, and the Development of a Test
Guide” Minutes of the 67th Annual International
Clients Conference, paper 8-8
E.P.Dick and E.P.Erwin (1978), “Transformer Diagnostic Testing by Frequency Response Analysis”.
IEEE Trans PAS-97, No 6, pp 2144- 2153.
A.L.Rickley and R.E.Clark (1976), “Transformer
Exciting Current Measured With Doble Equipment”
Minutes of the 43rd Annual International Clients
Conference, sec 6-1101
10. M.F.Lachman, (1999) “Application of Equivalent
Circuit Parameters to Off-line Diagnostics of Power
Transformers”, Minutes of the 66th Annual International Clients Conference, sec 8-10
Mr. Locarno received a BSEE from Northeastern University in
Boston, MA in 1990. He worked as a startup engineer for the General
Electric Co. power delivery systems. As a graduate of the GE field engineering program he served in many roles; project manager for industrial
applications resident engineer for IBM microchip division, and outage
management for GE power generation services. Mr. Locarno has worked
for Doble Engineering since 1996 and is currently a lead engineer in their
new product technology group. The latest venture has been the development of a Swept Frequency Response Analyzer, for which he, (and others),
hold Patent (pending review). Additionally, he acts as a project manager
for their engineered strategies business unit which provides condition
assessment and asset management to major utilities.
27
Transformer Handbook — Volume 1
An Additional Method for
Determining Shorted Turns in
Transformer Windings
NETA World, Spring 2001
by N. Wayne Hansen and Parsons Brinckerhoff
Boston Central Artery/Tunnel Project
In the process of troubleshooting abnormalities in power
trans-formers, it is often desirable, if not advantageous, to
determine the winding or portion of the winding in which
shorted turns exist. Sometimes, there is so little evidence
(either externally or internally) on which to base a decision
and guide the repair effort that confirmation of the specific
problem area is most welcome.
The following method can be used to achieve the above
objectives, and, in addition, the maintenance test technician will have a better understanding of the extent of the
damage.
Background
The author has successfully used this approach to not only
confirm shorted turns but also to detect in which winding
(or winding section) the problem exists.
It is particularly well suited (but not limited) to load
tap-changer (LTC) tap windings and only requires that
another winding be available, preferably on the same core
leg. A single phase ac voltage source is required and can
be any available low voltage present in the substation. A
power-factor or dissipation-factor test set can also be used
to provide a convenient source of adjustable ac voltage
provided the required current does not exceed the output
of the test set.
This method is not intended to replace turns ratio measurements or the exciting current test where shorted turns
may first be indicated by the abnormally high current. It is,
rather, to confirm and pinpoint a condition that may have
already been identified.
Three actual cases will be presented in which the method
was utilized to determine the extent of damage. On two
units, it was found that “on-site” repairs were not possible,
and both units were subsequently disassembled and returned
to a repair facility where a complete rewind was required.
On the third unit, no winding damage was found; the LTC
compartment was cleaned and repaired, and the unit was
successfully returned to service.
Preparation For Testing
In addition to disconnecting the transformer from the
power system on both the high- and low-voltage sides,
access is necessary to the terminals where the winding in
question is terminated. In the case of whole windings, the
bushings representing the ends of the winding can be used.
In the case of a load tap-changer, this is usually accomplished
by draining the LTC compartment where the selector switch
is located. In the case of a no-load tap-changer (NLTC),
the mechanical tap changer or terminal board is usually in
the main tank, and the unit will have to be drained to at
least this level for testing. Since low voltages are usually
employed, a unit can be partially or completely drained of its
insulating fluid as may be required, and any risk or further
damage will be minimized.
Case Number 1
Unit Rated 50/66.6/83.3/93.3 MVA * 120 kV to 13.8 kV
Connected Delta-Wye-Wye with
Two 13.8 kV Secondaries
History
This three-phase, three-winding unit is located at a large
manufacturing plant and had been in service for approximately four years. It had sustained a mechanical failure in the
load tap-changer compartment such that contact between
some of the LTC tap winding leads had occurred. Among
the initial tests were low high-potential readings (kilohms)
between the tap winding and ground and between the tap
winding and the Y secondary. In addition, combustible gas
was present including 33 ppm acetylene.
28
Transformer Handbook — Volume 1
Construction
A helical winding was used for the LTC tap winding
on this unit with very few turns between the individual tap
points. These are usually referred to as “interwound” taps and
are a common practice with core form tap windings. This
design had nine individual windings together on the same
helical layer. Eight of the windings had six turns, and one
winding had five turns. Figure 1 illustrates the arrangement
of this type of winding.
The main concern with tap-to-tap faults in a transformer
is the likelihood of winding damage within the tap winding.
The impedance is relatively low, and the fault current is limited largely by the length of cable between the tap winding
and the tap changer. This is typically in the order of ten to
50 feet, and makes the winding susceptible to failure.
Figure 2 — LTC Selector Switch Terminal Studs — Case No. 1
With 110 volts ac applied to the primary winding one
phase at a time, the following voltages were measured at the
LTC selector switch tap studs L to C:
Energize H3 - H1
(Phase A)
110 Volts
Measure Right Panel
(Phase A)
Tap Stud L-C Volts 5.96
Energize H1 - H2
(Phase B)
110 Volts
Measure Center Panel
(Phase B)
Tap Stud L-C Volts 5.96
Energize H2 - H3
(Phase C)
110 Volts
Measure Left Panel
(Phase C)
Tap Stud L-C Volts 0.810
Figure 1 — Helical Tap Winding — Case No. 1
Testing
My responsibility was to assist in determining the extent
and severity of damage. The no load tap-changer was set on
position number one to include all the turns in the primary
winding. The load tap-changer was set so that the moveable
contacts were not touching any of the tap studs. The idea is to
isolate, as much as possible, the tap winding and let it float so
that it is not influenced by any other winding. The reversing
switch should also be set in mid position, if possible. Figure
2 shows the development of the LTC tap winding as viewed
at the tap-changer selector switch.
Figure 3 — Winding Arrangement — Case No. 1
29
Transformer Handbook — Volume 1
Knowing the number of turns in the primary and tap
windings, the calculated voltage across tap studs L-C was
5.43 volts.
It was clear from the voltage measurements that there
was a serious problem within the Phase C LTC tap winding.
The most likely cause was shorted turns which prevented
the buildup of voltage across tap studs L to C. During an
internal examination, broken string ties that held the Phase
C LTC leads together were observed. This was confirmation
of the problem as large magnetic forces were created by the
fault current flowing in the tap winding leads.
Action Taken
This unit was moved to a repair facility where a complete
rewind was required. The design had the LTC tap winding
as the innermost winding, closest to the core. Outside of
the LTC winding were four layers of half height low-voltage winding (one for the X and one for the Y), followed by
the high-voltage disk winding. Figure 3 is an arrangement
of the windings.
Case Number 2
Unit Rated 360/480/600/672 MVA * 525 kV to 138
kV
History
This large three-phase autotransformer is located in a
utility substation. It had been in service for approximately
three years when a failure of the X3 bushing occurred. The
failure was limited to the bushing, and the unit was returned
to service after a through cleanup and replacement of the
failed bushing.
Construction
A large helical winding was used for the LTC tap winding on this unit, also. This winding had alternating five-turn
and four-turn sections. Figure 4 shows the development of
the LTC tap winding as viewed at the tap-changer selector
switch.
Testing
As a precautionary measure, the helical tap winding was
tested at the load tap-changer compartment as was done in
case number 1. A three-phase ac supply was used to apply
217 volts to bushings X1, X2, and X3. The following voltage measurements were obtained from the tap studs on the
selector switch (P to Q is the full tap range):
Table 1
Taps
P-Q
Phase 1 Volts
P-C
19.63
2.39
C-D
1.92
E-F
1.92
D-E
F-G
G-H
2.39
2.39
1.92
H-K
2.39
L-Q
2.39
K-L
1.92
Phase 2 Volts
19.64
Phase 3 Volts
19.67
2.39
2.40
2.39
2.40
1.92
1.92
2.39
1.92
2.40
1.92
2.40
1.92
1.92
2.39
1.92
2.40
1.92
2.40
The above pattern is produced by the alternating five-turn
and four-turn sections.
Knowing the number of turns in the low-voltage common and tap windings, the calculated voltages were: P-Q
19.70 volts, four-turn section 1.92 volts, and five-turn section 2.40 volts.
Incident Two
Approximately eighteen months later, a flashover occurred in the tap-changer compartment, taking the unit
out of service. There was some damage to the tap-changer
mechanism; however, the larger concern now was with the
condition of the helical tap winding. Preliminary tests (lowvoltage excitation and turns ratio) indicated that damage
had already occurred.
Testing
Figure 4 — LTC Selector Switch Terminal Studs — Case No. 2
A single-phase ac source was used to apply 125 volts to
one phase at a time: X1-X0, X2-X0, and X3-XO. The following measurements were obtained from the tap studs on
the selector switch (P to Q is the full tap range):
30
Transformer Handbook — Volume 1
Table 2
Taps
P-Q
P-C
C-D
D-E
E-F
Phase 1 Volts
22.8
2.7
H-K
2.7
G-H
K-L
L-Q
2.7
0.2
2.1
0.3
2.2
2.7
0.0
0.0
2.7
Action Taken
2.2
0.1
2.2
22.8
2.2
0.0
2.1
Phase 3 Volts
2.7
0.1
2.7
2.7
0.9
0.2
2.2
F-G
Phase 2 Volts
2.7
This unit was also moved to a repair facility where a complete rewind and repair of the tap changer was required.
2.7
Case Number 3
2.2
0.5
To further confirm the apparent damage in the phase
2 tap winding, a higher voltage was used to excite the
low-voltage “common” winding one phase at a time. This
winding is rated at 79.67 kV. A variac was used to backfeed
a pole mount distribution transformer which provided approximately 4.16 kV. The unit was still full of oil and the
following voltages and currents were obtained:
Table 3
Voltage into Pole Mount Xfmr
Current (A) Pole Mount Xfmr
Voltage into AutoXfmr LV
Winding
Phase 1 Phase 2 Phase 3
125
2.5
125
4166
83.3
4166
4
Based on the inability to build voltage across the tap
winding and the high exciting current, a decision was made
to drain the oil for an internal inspection. The only significant observation was a raised end ring and deflected spacer
at the top of the phase 2 winding. The end ring was quite
far into the window opening (approximately 22 inches), and
appeared to be over one of the tap winding layers. As in the
previous example, the taps were next to the core. Figure 5
is an arrangement of the windings.
20
4
Unit Rated 90/120/150 MVA * 125 kV * +/- 40 Degrees
History
This three-phase regulating transformer (or phase shifter)
is located in a utility substation and serves as an interconnection between two utility power systems. It had been in
service for approximately one year when an electrical failure
occurred in the load tap-changer compartment. Most of the
damage was electrical in nature: carbon, tracking, splashed
metal from arcing, etc.
Construction
As in both of the previous examples, a helical winding
is used in this unit for the LTC tap winding. This winding provides the regulation or phase shift for operation. It
is made up of nine 18-turn windings. Figure 6 shows the
development of the LTC tap winding as viewed at the tapchanger selector switch. This is one of the very few units I
know of that sustained a tap-to-tap fault and did not damage the tap winding.
Testing
Because of the complex design of this phase shifter, a
single-phase ac source was used to apply 195 volts across
the entire tap winding (P to Q) one phase at a time. This
unit has both a series core and coil assembly and an exciting core and coil assembly in the same tank. The following
measurements were obtained from the tap studs on the
selector switch:
Figure 5 — Winding Arrangement — Case No. 2
31
Transformer Handbook — Volume 1
Taps
Phase 1
(Left)
Phase 2
(Center)
Phase 3
(Right)
P-C
21.7
21.7
21.7
D-E
21.7
21.7
21.7
F-G
21.7
C-D
E-F
G-H
H-K
K-L
L-Q
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
N. Wayne Hansen received a BSET degree from LeTourneau College in Longview, Texas. Upon graduation he joined the General Electric
Company as a field engineer in the installation and service engineering
department. He joined the Doble Engineering Company in 1987 and
served as principal engineer in the client service department. While at
Doble he served as secretary for the Insulating Fluids and Transformer
Client Committee. In March 1997 he accepted a senior startup engineer
position with the systems test department at the Central Artery/Tunnel
Project in Boston, Massachusetts. He is a Senior Member of the IEEE
and is active in the Transformers Committee. Mr. Hansen is also an
Affiliate Member of NETA.
21.7
21.7
21.7
21.6
21.7
21.7
Action Taken
The failure was limited to the tap-changer mechanism and
compartment as shown by the above tests. The compartment
was thoroughly cleaned, and the phase 1 mechanism was
rebuilt. A portion of the phase 1 front insulating panel had to
be machined to remove carbon tracking that had burned to a
depth of 0.028 inch. All other damaged parts were repaired or
replaced.
The LTC compartment was flushed and filled under
vacuum with reprocessed oil. After a four-hour hold and
soak period, the unit was energized and returned to service.
As far as I know, the unit continues to operate in a satisfactory manner.
Summary
This technique has proven to be a valuable tool to assist
test and maintenance personnel in determining the extent
and location of winding problems. It is simple and does not
require any expensive or elaborate equipment. The application is limited only by the understanding of transformer
fundamentals and the creativity of the person using it.
References
Standard Handbook For Electrical Engineers,
Edition - McGraw Hill Book Co. (1969)
This paper was originally presented at the 1992
Doble Client Conference, and published in the
conference minutes, reprint by permission of Doble Engineering Co.
10th
A Guide To Transformer Maintenance, Transformer Maintenance Institute - S.D. Myers Inc. (1981)
Applied Practical Electricity, Coyne Electrical School - Chicago, Ill. (1958)
Minutes of the Thirty-Fifth Annual International Conference
of Doble Clients 1968, Ratioing Power Transformers With
The Doble Set, R.A. Walker - Section 6-901
Minutes of the Forty-Eighth Annual International Conference of Doble Clients 1981, “In-House Repair On An
18/24/30 MVA 67/13.09Y KV Transformer,” M.A.
Salvant - Section 6-401
32
Transformer Handbook — Volume 1
Considerations in Sizing Primary
Fuses Due to Secondary Faults
for Padmount Transformers
NETA World, Spring 2001
by Steven C. Reed, P.E.
Electric Power Systems
Padmount transformers are used frequently in industrial and
commercial applications for distribution of power.Many of these
transformers include primary fuse protection for system
coordination and transformer protection. The manufacturer has a typical acceptable range of fuse sizes for each
size transformer. However, the manufacturer may supply a
fuse in the company’s high range that may not protect the
specific transformer-winding configuration for all types of
secondary faults. Engineers performing coordination studies
and field technicians need to be aware of common errors in
sizing primary fuses for the appropriate protection of the
transformer for various secondary faults.
The function of the transformer protective device is to
provide system as well as transformer protection. System
protection is the ability to isolate a faulted segment of the
distribution system due to a damaging fault condition (for
example, winding failure). System protection will allow for
the remainder of the electrical system to continue to operate
after removing the faulted section. Transformer protection
includes the correct operation of the fuses due to a bus or
cable fault located between the transformer and the nearest
secondary side overcurrent protective device. The degree of
transformer protection provided by the primary fuses should
be checked for the level of fault current and the type of fault
(three-phase, phase-to-phase, or phase-to-ground) producing the most demanding conditions. For certain secondary
faults, the primary fuse may be exposed to a proportionally
lower current than the windings. If this is the case a fuse
must be selected to operate fast enough to avoid damage
to the windings. Reference Figure 1 for the per unit fault
currents on the primary, secondary, and internal windings.
As can be seen in Figure 1, there are conditions in a delta
delta transformer for a phase-to-phase fault and in a delta
wye transformer for a phase-to-ground fault where the per
unit primary line side current is lower than the internal
winding current. In particular, during a secondary ground
fault in a delta wye transformer there is only .58 per unit of
Figure 1 —
Relationship between the per unit primary-side and secondary-side
line currents and the associated per unit transformer winding currents
for (a) grounded-wye grounded-wye, (b) delta delta, and (c) delta
grounded-wye connected transformers for various types of secondary faults. (Line current and winding current values are expressed in
per unit of their respective values for a bolted three-phase secondary
fault.)
current on the primary leg versus 1.0 per unit in the primary
winding. In order to ensure correct transformer protection
for the two cases mentioned, it is necessary to shift the
transformer damage curve to the left in terms of per unit primary-side line current to the transformer winding current.
33
Transformer Handbook — Volume 1
Figure 2 — Wye Wye Ref. Volt: 480 Current Scale X 2
Figure 3 — Delta Delta Ref. Volt: 480 Current Scale X 2
As an example, we have used a 1500 kVA transformer, 12470
volt primary, 480 volt secondary with 5 percent impedance.
The winding configuration will change for each example.
This type of transformer would be considered a category II
transformer (501-5000 kVA, three-phase) in accordance
with ANSI C57.12.00. category II transformers have a
fault curve for both frequent faults (more than 10 faults in
a lifetime) and infrequent faults (less than 10 in a lifetime).
The long curve is the through fault curve for the infrequent
fault. The shorter angled curve is the frequent fault curve
based upon fault currents from 70-100 percent maximum
at I2 t = K. Reference Figure 2 for a wye wye winding configuration. There is only one curve since all current on the
secondary is reflected to the primary and windings as 1.0
per unit. Reference Figure 3 for a delta delta transformer.
There are two curves. The curve to the right represents the
protection curve for a three-phase secondary fault. The curve
to the left is the original curve shifted to the left by .87
times the current values (x-axis) to take into consideration
a phase-to phase fault. This allows for correct transformer
protection. No phase-to-ground fault exists for a delta delta
transformer. Reference Figure 4 for a delta wye transformer.
The far right curve represents transformer damage curve for
a three-phase and phase-to-phase (primary current actually
higher than winding) fault condition. The curve to the left
is the original curve shifted by .58 times the current value
(x-axis) to take into consideration a phase-to-ground fault.
This allows for correct transformer protection. Various types
of faults and transformer winding configuration are critical
in ensuring appropriate transformer protection.
In addition to ensuring the primary fuse operates prior
to transformer damage, it is also possible to specify a fuse
that will protect the secondary cable prior to the secondary protective device. Certain engineering design schemes
may allow for a padmount transformer to feed multiple
secondary overcurrent devices with separate cable feeds.
Multiple feeds may allow for smaller sized cable feeds
with lower rated cable damage curves. Although this type
of coordination is not required it is good practice to review the possibility of specifying a small enough fuse to
prevent a low-level fault from burning a large section of
cable (prior to secondary protective device) versus blowing
a primary fuse. It is always advisable to select the lowest
possible fuse ratio that will allow for coordination of the
highest ampere feeder protective device and still meet
inrush standards. However, it is not always possible to
select a small enough fuse to protect the secondary cables. Medium-voltage fuses are not intended to provide overload protection, and ANSI C37.46 specifies the minimum operating
current to be significantly greater than the ampere rating. As
an example, “E” rated fuses operate at 200 to 220 percent of the
ampere rating. Even the National Electrical Code specifies in
240-3 (i) that where three-phase transformers are involved,
overcurrent protective devices on the transformer primary
do not protect secondary circuit conductors.
34
Transformer Handbook — Volume 1
We have reviewed two criteria for selecting primary fuses due to various types of secondary faults.
However, there are many other criteria for selecting
fuses based upon primary and secondary conditions
such as:
• Voltage rating
• Available fault current
• Peak loads
• Magnetizing inrush currents along with hot-load
pickup current
• Transformer protection
• Coordination with primary and secondary protective
devices
• Protection of downstream conductors
Following these seven steps and being aware of certain
common errors should assist in correctly sizing the primary
fuses of a padmount transformer.
Figure 4 — Delta Wye Ref. volt: 480 Current Scale X 2
Steven C. Reed has a BS in electrical engineering from Villanova
University, a masters in business administration from the Olin School
of Business at Washington University in St. Louis, and his professional
engineering license in multiple states. Steve has worked at Electric Power
Systems for 12 years and served as a field engineer, system protection
engineer, and now serves as regional manager. He is a NETA Certified
Technician Level III.
35
Transformer Handbook — Volume 1
Using Analytical Techniques
to Determine Cellulosic Degradation
in Transformers
NETA World, Winter 2001-2002
by Lance R. Lewand
Doble Engineering Company
Insulating materials used in power transformers have
been selected because of their abundance, low cost, and
longevity under normal operating conditions. Oils in the
U.S. are expected to last 30 or more years before forming
excessive amounts of acids and sludges and can then be rejuvenated by treatments with absorbents such as clay. They
can also be easily replaced. Modern oil preservation systems
are designed to minimize exposure of the insulating oil to
air thus retarding its oxidation. The solid insulation (paper
and pressboard) is the main dielectric in transformers and
also serves as mechanical support. Localized severe degradation in those materials must be considered most serious
as this can result in loss of adequate dielectric strength.
In addition, cellulosic materials cannot be easily replaced;
therefore, their longevity, which is primarily a function of
temperature, becomes a limiting factor in the operation of
transformers. The end of life criteria, tensile strength, or
degree of polymerization (DP) are physical characteristics
of the paper insulation. If paper insulation is maintained
in a dry state, its good electrical properties will be retained
even as it becomes quite brittle. However, mechanically
weakened paper can break especially as windings vibrate
and move, particularly during through faults thus reducing
insulating capability. Dielectric breakdown is then more
likely to occur.
Fortunately, as cellulosic materials are degraded, byproducts such as carbon oxide gases (carbon monoxide and carbon dioxide) and furanic compounds are formed which can
serve as indicators of the aging process. Cellulosic materials,
most often paper samples, can be tested directly for DP, a
measure of its average molecular weight that correlates well
with mechanical properties.
Cellulose is a long straight chain polymer (polysaccharide) of glucose molecules (monomers), and is the major
constituent of paper and pressboard. Glucose is a sugar
that has six carbons and is typically in the more stable ring
structure called a pyranose. The glucose rings are linked by
an oxygen atom in what is referred to as a glycosidic linkage. The long-chain cellulose molecules interact with each
other due to hydrogen bonding resulting in strands, mats
and paper sheets.
Much of the mechanical strength of paper and pressboard
comes from the long-chain cellulose polymer. As the cellulose ages, the polymers are cleaved and become shorter,
resulting in reduced mechanical strength. The primary forms
of degradation of the cellulose polymer are hydrolytic, oxidative, and thermal. In the case of each of these mechanisms
free glucose is generated and the ring structure tends to be
opened to form chains. Although temperature is likely to
be the most important factor, oxygen and water have been
clearly shown to have a significant effect on the degradation
of Kraft paper. The degradation of cellulose molecules results
in the formation of gases, primarily carbon monoxide and
carbon dioxide, furanic compounds, and other byproducts.
The carbon oxide gases often provide early warning of
excessive damage. However, other materials such as paints
and gaskets can outgas carbon oxide gases when exposed
to excessive temperatures and, therefore, are not always
attributable to the degradation of the cellulosic insulation.
Confirmatory and complementary tests have been developed
which detect oil soluble breakdown products of the cellulose
chain (called furanic compounds) with the primary indicator being 2-furfural.
Furanic Compounds
Furanic compounds are five-membered ring structures
that are formed in a manner in which the open-chain glucose molecule goes through a series of dehydration reactions
(elimination of water molecules) and then recycles into
a five-membered ring structure. The furanic compounds,
unlike sugars such as glucose, are oil soluble and, therefore,
are detectable.
36
High concentration of 2-furfural is a clear indication of
cellulose degradation as this is the only type of material in
transformers which yields this byproduct. Under some conditions where carbon oxides may be lost, such as when a leak
occurs in the gas space of a nitrogen blanketed transformer
or from the conservator tank for those that are free breathing, the furanic compounds will continue to accumulate
and provide a gross indication of the relative aging of the
cellulosic insulation or a thermal incipient-fault condition
involving cellulosic materials. Conversely, when cellulosic
materials are exposed to extreme temperatures which result
in charring, furanic compounds can be destroyed and the
carbon oxides may be the only byproducts remaining in
significant quantities.
Experience is required in evaluating the furanic compound data since there are factors such as the type of insulation preservation/oil expansion system, type of conductorwrapped insulation, and family of transformer, all of which
influence the interpretation. For example, the treatment of
the oil or the transformer can result in the removal of significant amounts of furanic compounds. Not knowing this
information may lead to a misdiagnosis of the actual condition of the transformer. In addition, furanic compounds
are generated from thermal events, not electrical discharge
activity and therefore can be useful in the assessment of
failure mode and incipient-fault conditions leading to the
failure. Tests for furanic compounds should be performed
initially for all power transformers to establish a baseline, for
important or older transformers, when high carbon oxides
are generated, for highly loaded transformers, and when
other tests indicate accelerated aging.
In order to detect the degradation of cellulosic materials,
sufficient quantities must be degraded to increase the concentration of indicator gases and furanic compounds in the
oil to thresholds considered to be problematic. Experience
has shown that significant damage, including charring of
the cellulosic insulation, when limited to isolated hot spots
due to incipient-fault conditions, will produce carbon oxides
and furanic compounds below thresholds used to indicate
problems involving the cellulosic insulation.
The analysis of data for furanic compounds should be
based on the type of insulating paper used and the preservation system employed. For Kraft paper insulation, suitable
guidelines are as follows:
• For normal aging <50 ug/L/year of 2-furfural should be
generated.
• Generation rates >50 ug/L/year of 2-furfural is considered accelerated aging
• Values of 2-furfural > 1000ug/L should raise a flag for
further study
Transformer Handbook — Volume 1
For thermally-upgraded (TU) Kraft paper insulation
using the dicyandiamide process, practical guidelines are
as follows:
• For normal aging the rate of 2-furfural generation
should be much less than 50 ug/L/year and usually in
the vicinity of 10-20 ug/L/year
• If estimating insulation quality from the 2-furfural content, use these guidelines:
• Normal
• Midlife (examine rate)
• Last third of life?
<100 ug/L
> 100 <1000 ug/L
> 1000 ug/L (flag for
further study)
Degree of Polymerization (DP)
The degree of polymerization test is used to assess insulation aging and is performed on paper samples taken
directly from the transformer so it is an intrusive test. The
DP provides an estimate of the average polymer size of the
cellulose molecules in materials such as paper and pressboard. The DP correlates well with mechanical properties
such as tensile strength but has the advantage that it can
be performed on used materials that have taken a set during service life. Generally, paper in new transformers has a
DP of about 1000. Aged paper with a DP of 150-200 has
little remaining mechanical strength, therefore making the
windings more susceptible to mechanical damage during
physical movement, which can cause the paper to tear or
crumble. This may occur when transformers are moved or
during events such as through faults. Since paper insulation
does not age uniformly due to thermal, water, oxygen and
byproduct concentration gradients, samples from several
distinct locations provide the best diagnosis. The DP test
provides the most reliable indication of the overall aging of
the paper insulation as it is a direct measurement. This test
should be performed:
• when there is other evidence of very accelerated aging
of the insulation
• when an internal investigation is being performed and
the transformer is more than 20 years old
• for condition assessment of older transformers for possible refurbishment
• for consideration of a partial rewind
• for failure assessment
• for condition assessment of insulation when purchasing
a service-aged transformer
• to assess the condition of a transformer after an extreme
overheating event such as loss of cooling
Transformer Handbook — Volume 1
Conclusions
The combination of analyses of furanic compounds in oil,
DP, along with routine dissolved gas-in-oil analysis is a very
powerful set of tools to assess the condition of the cellulosic
insulation. The more specific information known about a
transformer and its family, the better the diagnosis that can be
provided.
Lance Lewand received his BS degree at St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company
for the past seven years and is currently Project Manager of Research
in the materials laboratory and Product Manager for the DOMINOTM
product line. Prior to his present position at Doble, he was the Manager
of the Transformer Fluid Test Laboratory and PCB and Oil Services at
MET Electrical Testing in Baltimore, MD. Mr. Lewand is a member
of ASTM committee D 27.
37
38
Transformer Handbook — Volume 1
Transformer Fluid:
A Powerful Tool for the Life Management
of an Aging Transformer Population
PowerTest 2002
(NETA Annual Technical Conference)
Presenter
Ted Haupert, TJ/H2b Analytical Services, Inc.
Co-Authors
Victor Sokolov, ZTZ Service
Armando Bassetto, Bassetto and Mak, Inc.
T.V. Oommen, Consultant
Dave Hanson, TJ/H2b Analytical Services, Inc.
Abstract
It has been estimated that transformer fluids contain
about 70% of the diagnostic information available for
transformers. The challenge is to access and use this information effectively. Historically, testing programs have been
developed that evaluate separate facets of the transformer
condition. This paper considers the dynamics of transformer
components considered together as a system leading to a
comprehensive testing program for determining transformer
condition. Particularly with the changing needs of the
electric power industry, optimized testing and diagnostic
protocols will be fundamental to transformer life management in the future.
Introduction
The global task of the electric power industry in the first
quarter of the 21st century will be to manage the serviceability of a huge transformer population that has already
been in service for 25-40 years. Concurrent with this task
will be meeting the fundamental objective of transformer
life management, defined simply as “getting the most out
of the asset”. One way to accomplish this is to ensure that
appropriate actions are taken to promote the longest possible service life under any operating conditions. It is also
possible that within this definition taking no action and
assuming an economically justified risk of failure could be
acceptable.
In order to make the best decisions, it is imperative to understand the condition of the equipment. Without sufficient
information the likelihood of no action leading to a failure
may only appear to be acceptable and the cost of appropriate
actions may only appear to optimize performance.
In recent years there has been considerable interest in the
life management of transformers. One can easily observe
this in the rapid development of economic based maintenance concepts such as Reliability Centered Maintenance,
Condition Based Maintenance, and Comprehensive Life
Extension as well as in such accompanying techniques as
On-line Monitoring and On-line Processing. All of these
developments reflect a changing view of asset management
and implicit in each of them is the need for and use of a
greater amount of information. In order to meet the developing needs of the asset managers, there will continue to
be a high demand for new technologies and new diagnostic
tools to fulfill the requisite need for information.
The most easily accessible and efficient way to determine
transformer condition is to use the fluid as the diagnostic
medium. It has been estimated that transformer fluids contain about 70% of the available diagnostic information for
transformers. The challenge is to access and use it effectively.
Traditional oil test programs utilize only a few diagnostic
parameters leaving a myriad of important oil-based information unused.
The goal of this work is to present ways to realize the potential benefits of oil testing and to suggest
some algorithms to assess the condition of a transformer not as a characterization of symptoms but
as a comprehensive evaluation for life management.
Characterizing the Fluid
Functionally, most electrical insulating fluids are considered to be equivalent and they are handled as such. It is
common to see transformer fluid levels adjusted using available fluid stocks and used oils combined for processing and
reuse. The only fluids that are typically managed separately
are either specialty fluids or contaminated fluids.
39
Transformer Handbook — Volume 1
Table 1 illustrates that significant differences in aromatic
carbon content, CA, and specific gravity result in significantly different gas solubilities, as indicated by the Ostwald
coefficients.
Chemically, most electrical insulating fluids are not
equivalent. While the differences normally do not defeat
the prescribed functions of the fluids, they do affect the
way they function.
Transformer fluids vary in composition from nearly
pure compounds to mixtures that are too complex to fully
describe. The measurable chemical features of these fluids
vary in concentration from percent, which is parts per hundred, to parts per trillion. Those components in the percent
range, both major and minor, describe the basic chemical
composition and determine the basic fluid properties and
reactions involving the fluid. The effects of composition can
vary widely. The examples shown in Tables 1, 2 & 3 demonstrate variations in properties produced by variations in
composition and illustrate the importance of determining
fluid composition.
Table 2
Solubility of Water in Oils
with Different Aromatic Content
Aromatic
Content
Oils
20 C
8
46.8
5
3
16
5
Silicone-oil
4
Table 1
CA, %
1
2
Water Solubility, ppm
21
40 C
70 C
42.8
97.5
279
56.2
128.3
369.2
314.7
675.4
108
75
316
162
174
436
†
Gas Solubility Properties of Insulating Fluids
Oils
Properties
Table 2 illustrates the importance of aromatic carbon
content, CA, for determining the solubility of water in
mineral oils.
Table 3 illustrates some of the variability found in gas
generation. A study by Cigre WG 15.01 has shown that
some oils may produce hydrogen at low temperatures (below
130°C). A possible explanation may be that the catalysts
used today are sufficient to produce “over-hydrogenated
oils”. It has been proposed that these oils contain some
molecules where hydrogen atoms occupy an unstable posi-
Ostwald Coefficients at 20°C
H2
N2
air
C 2 H2
CO2
I-hydro-refined
CA=1.6%
Sp.Gr.=0.856
0.05
0.089
0.103
1.02
1.1
II
CA=14%
Sp.Gr.=0.869
0.044
0.085
0.091
1.1
1.1
III-synthetic
CA=66%
0.034
0.061
0.061
1.92
1.71
Sp.Gr.=0.968
† Provided by Prof. Lipstein
Table 3
Gas Evolution in Different Oils at Selected Temperatures†
Type of oil
žž
Nytro-11GX
YPF-64
Y-3 (Technol)
Shell Diala Ax
Temperature
(°C)
Time
(hours)
Initial
100
120
120
0
6
6
+16
Initial
100
120
120
Initial
100
120
120
140
Initial
100
120
Initial
100
120
0
6
6
+16
0
6
6
+16
6
0
6
6
0
6
6
† Tests performed in the ZTZ – Service Material Lab
Gas Concentration (ppm)
H2
CH4
CO
CO2
C2H4
C2H6
0
5
35
78
1
1
42
66
0
41
190
283
212
408
931
1772
0
0
2.6
2.6
0
0
43
62
0
31
79
116
0
5
31
31
55
0
5
47
0
0
0
0
0
39
39
0
1
23
39
22
0
1
1
0
1
3.9
0
55
222
227
0
73
282
298
358
0
16.2
63
0
26
130
246
413
833
1068
297
439
898
1392
961
547
611
1076
642
797
1471
0
4.8
10
10
0
0
3.8
3.8
2.6
0
3.2
3.2
0
0
0
0
0
9
14
0
0.5
0.5
7.8
0.5
0
0
0
0
0
0
40
tion. A mild heating could release such atoms. A similar
effect may occur with partial discharge. Typically, the rate of
gas generation during partial discharge varies in the range
of 5-50 l per joule of dissipated energy. However, some
hydro-refined oils have rates of gas generation up to 200
l per joule of dissipated energy. It has also been shown
that some fluids may have substantial production of CO,
CO2 and hydrocarbons at the operating temperatures of a
transformer.
It is important to note that the parameters treated in these
tables are all fundamentally important for any diagnostic
assessment. Because the magnitude of the variations is sufficient to confuse or misdirect the diagnostic process, it is
important to characterize those aspects of the basic chemical
composition that define these fundamental fluid properties.
Fortunately, once they are known, the basic composition and
the associated properties will generally not change unless
substantial mixing with another fluid occurs.
In addition to the major and minor fluid components,
there are a number of important components found at low
levels. The reasons for their importance are diverse. For example, consider components such as sulfur, silicon, 2,6-ditertiary-butyl para-cresol or poly-aromatic hydrocarbons.
Sulfur in transformer oil is usually kept below 1%. Cigre
WG 15.01 has suggested that heat and electrical stress may
change the sulfur in the oil to a form of corrosive sulfur,
which has a detrimental effect on copper. Sulfur may also
be introduced from other transformer components and
similarly changed to form a corrosive sulfur. Recently, one
utility reported failures of several shunt reactors where the
suggested failure mechanism was a short-circuit between
adjacent turns due to corrosion caused by copper sulfide.
Utilities typically specify oil with a low corrosive sulfur
content but do not have any specification for the total
sulfur content.
Silicon in transformer fluid, with the obvious exclusion
of silicone fluid, is usually found as an additive at less than
5-10 parts per million. At these low concentrations silicon
contributes antifoaming properties which aid processing
under vacuum. At higher concentrations silicon enhances
foaming and can severely interfere with vacuum processing
operations.
2,6-Ditertiary-butyl para-cresol (DBPC) or 2,6-ditertiary-butyl phenol (DBP) is sometimes added to transformer oil at concentrations as high as 0.3 percent to act
as an oxidation inhibitor. Presence of the inhibitor can
enhance insulation life. It also changes the relationships of
the oxidation products found in the oil.
In addition to their influence on basic fluid properties,
poly-aromatic hydrocarbons or PAH’s, may present a health
concern. A recent study suggests naphthenic base oils with
more than 2 percent PAH are potentially carcinogenic.
Transformer Handbook — Volume 1
Characterization of the transformer fluid is the defining
process that sets the stage for all future assessments by:
1. Determining how the fluid will interact with the rest
of the system and establishing the basis for diagnostic
evaluations.
2. Identifying residues of equipment manufacturing, fluid
production, transformer processing and handling which
provides source information for contamination and its
potential consequences.
3. Identifying baseline values for the components that will
change.
4. Confirming the condition of the fluid with regard to
functionality as well as health, safety and environmental
concerns.
The use of this information in conjunction with the information from an ongoing fluid testing program provides
the basis for transformer life management.
The Fluid as a Part of the System
Many maintenance guides still consider the insulating
fluid to be a separate component that can be monitored and
treated separately from the fluid-paper insulation system
or from the transformer as a whole. In fact, the fluid is an
integral part of the transformer playing a dynamic role in
the condition of the entire system.
Consider the role the fluid plays in the serviceability
of the dielectric system. Aging tests were performed on
transformer models in the Transformer Research Institute
at Zaporozhye, Ukraine to evaluate the dielectric life and
the mechanical life of the insulation system. These studies
demonstrate that the dielectric life of the insulation system
can be shorter than its mechanical life due to deterioration
of the oil-paper system and the consequential deterioration
of the dielectric withstand strength of the coil-to-coil insulation. As shown in Table 4, at 100°C the conductor insulation
life is 50 years based on mechanical properties and only 22
years due to deterioration of dielectric strength.
Table 4
Estimated Life of Transformer Winding
Insulation Under the Influence of Temperature,
Electrical and Mechanical Stresses†
80
Estimated Mechanical
Life (Reduction of DP
to 200), Years
6229
Estimated Dielectric Life
(Reduction of dielectric
strength by 40%), Years
124
100
50
22.1
110
17
10
125
4
3.3
140
1
1.16
160
0.19
0.32
Hot Spot
Temperature, °C
† Tests performed in ZTZ – Service Material Lab
41
Transformer Handbook — Volume 1
Water created from the degradation of the paper interacts
with the paper-oil system to produce this effect. The increase
of water available from the paper leads to an increased
relative saturation of water in the oil and a reduction in
dielectric strength. This in turn leads to an increased adsorption of water on particles that adsorb water, further reducing the dielectric strength of the fluid. When the relative
saturation is sufficient, emulsion formation in the vicinity
of surface-active substances further reduces the dielectric
strength of the insulation. Studying the electrical models of
the transformer paper-oil insulation system has shown that
the dielectric safety margin of both the major and minor
insulation contaminated with water is still determined by
the dielectric withstand strength of the oil.
Water is usually present in the oil in a soluble or dissolved form but also may present as a form adsorbed by
“polar” aging products and called “bound water”. It has been
found that as temperature increases, some bound water can
be converted into soluble water. Test results of the water
content of aged oil sampled from two current transformers are shown in Table 5. After heating the oil at 100°C
for 5 hours the water content in oil increased significantly.
A similar phenomenon has been observed in bushing oils.
Most likely, the dissolved polar compounds in the oil are
the source of this additional water.
Table 5
Transformation of Bound Water to Soluble
Water from Aged Oil Not in Contact with Paper†
Type of oil
Properties
Used oil from
750 kV CT
Acidity=0.064mg KOH/g
IFT=32 dynes/cm
PF90 =5.32%
Used oil from
750 kV CT
Ca=18%
Acidity=0.064mg KOH/g
IFT=32 dynes/cm PF90=6.1%
Water content ppm
Before
After heating
heating
at 100°C for 5
hours
26.3
85
23.5
132
† Tests performed in ZTZ – Service Material Lab
There are also other temperature driven dynamics of water including “bubble formation” and “rain”. EPRI sponsored
projects in the late 1980s and early 1990s confirmed prior
observation that bubbles could be generated from a sudden
overload of the transformer. This type of bubble generation
has been studied in more detail, and it now appears that
these bubbles consist mostly of water vapor released from
the cellulosic paper wraps on the hot conductor. The hot spot
temperature is a critical factor, but the water content of the
paper insulation is also important. Oil preservation systems,
such as nitrogen-blanketed and conservator systems, showed
very little difference at low moisture levels in the paper. If
the insulation is very dry, eg., with 0.5% moisture, virtually
no bubbles are formed. Aged transformers with 2.0% or
more moisture could release bubbles at hot spot temperatures greater than 140oC. Since the dielectric strength of
the bubbles is significantly less than the insulation system,
their formation can result in discharge events ranging from
partial discharge to flashover.
When a temperature drop within the transformer is sufficient to change the relative saturation of water from less
than 100 percent to greater than 100 percent, an emulsion
of oil and water will form. If an appropriate surface is available or the temperature drop is extreme enough, further
condensation will occur forming water drops or “rain”. Both
emulsified water and free water substantially reduce the
dielectric strength of the insulation system. Transported by
the fluid their movement through the transformer can cause
numerous dielectric and mechanical problems both with the
insulation system and adjacent cellulosic materials.
Finally, the presence of water in the cellulose participates
in the degradation of the cellulose. Each doubling of moisture concentration doubles the rate of degradation. This
process reduces the degree of polymerization (DP) of the
cellulose thereby reducing its mechanical strength.
Like water, fluid oxidation products are instrumental
in the degradation of the insulation system. The oxidation
process culminates with the formation of sludge which:
• As a suspended impurity, reduces the fluid dielectric
withstand strength in a manner similar to particles.
• As a semi-conductive sediment, reduces the insulation
dielectric withstand strength and may provide for tracking.
• When extremely acidic, will aggressively age both the
oil and the cellulose insulation.
The conditions under which sludge will form are not
always readily apparent. In the presence of a strong electrical field sludge may form even though the acidity is low.
A number of sludge deposits have been found on local
insulation zones where the electric field strengths are quite
high. These deposits were not apparent until the windings
were dismantled.
The correlation between traditional aging characteristics
such as color, acidity, interfacial tension, dielectric breakdown
voltage, dissipation factor, resistivity and sludge appearance
during oil stability tests may be quite different for different
oils. These differences increase significantly when the fluids
are aging in transformers, due to the effects of transformer
materials, operating temperatures, dielectric stress and interaction of aging products with cellulose (See Table 6).
42
Transformer Handbook — Volume 1
Table 6
Relationships of Aging Characteristics of Service
Aged Oils from Service-Aged Power Transformers
Sample Acidity
IFT
1
0.081
3
0.124
2
0.035
PF90
22.0
Color Infrared
Absorbance
3.5
3
3.65
0.018
23.1
3.0
8
4.09
0.017
5.0
8
4.0
11
4.0
11
25.9
2.5
4
0.154
21.9
6.5
6
0.151
23.0
4.5
8
0.098
26.1
4.0
5
7
9
10
0.109
0.111
0.098
0.193
28.6
25.9
27.2
26.3
4.5
2
11
9.5
SN
2.25
0.014
11.69
8.84
Sludge
0.015
0.010
5.84
0.577
0.012
15.61
0.312
0.011
15.40
21.89
4.01
0.310
0.313
0.016
Figure 2 — Correlation between the differential infrared
absorbance at 1710 cm-1 and the acid number
0.013
0.014
Figure 1 shows a correlation between acid number and
interfacial tension test results of oil samples obtained from
25 power transformers, rated 138-13.8 kV, 12-60 MVA. The
best correlation occurs in the least oxidized fluids. As the
oxidation proceeds, the correlation begins to diverge.
Figure 3 — Correlation between the differential infrared
absorbance of oils at 1710 cm-1 and the IFT
Figure 1 — Correlation between acid number
and interfacial tension test results.
Figures 2 and 3 show the correlation between the differential infrared absorbance of fluids at 1710 cm-1 versus
their acid number and their interfacial tension, respectively.
The discrepancy is more significant for acid numbers higher
than 0.05 mg KOH/g and for IFTs lower than 20 Dynes/
cm. The practical importance of such a discrepancy is that
there may be oils in service with fairly acceptable IFTs and
acid numbers that may contain a significant amount of nonacidic polar compounds detected by infrared spectroscopy.
The typical oil tests are not capable of completely assessing
the progress of oil aging.
Gas formation occurs primarily in the oil. With the exception of bubble formation, gases are dissolved directly into
the oil and distributed throughout the transformer. Changes
in temperature will induce migration of gases between oil,
cellulose and any gas spaces and may significantly change
gas-in-oil concentrations, especially when the temperature
changes are large (See Table 7). The case shown in Table 7
is that of a 750 kV Shunt Reactor with a source of localized
overheating that was stored for 1 year. Dissolved gas tests
were performed both before and after heating the unit for 3
days and the differences in gas distribution are dramatic.
Table 7
Effect of Temperature Distribution of Gases
H2
CH4 C2H4 C2H2 C2H6 CO
ppm
ppm
20 °C, before trace 172
heating
64 °C, after
heating
56
269
CO2
O2
N2
ppm
ppm
ppm
ppm
ppm
%
%
78
ND
56
923
1929
0.08
2.9
147
1.3
90
1163
2654
0.09
5.5
Gas bubbles may be produced in transformers from
severe fault conditions, a sudden release of pressure in gas
saturated systems, or an overload condition. Only a serious
fault condition is expected to release large quantities of
fault gases that do not get absorbed into the oil immediately. Nitrogen or air blanketed transformers may develop
negative pressure in the gas space during rapid cool down.
43
Transformer Handbook — Volume 1
If the pressure differential between the gas in the oil and
gas in the gas space is appreciable, spontaneous release of
bubbles is possible. Transformer failures from a “cold start”
of a stagnant transformer from bubble release in the supersaturated oil is one of the causes of sudden transformer
failures. Therefore, it is necessary to ensure that such extreme
pressure differential does not occur. Modern transformers
with conservator tanks avoid this problem. As mentioned
earlier, an overload condition with sufficient moisture and
heat will produce bubbles of water vapor. Bubbles from any
of these phenomena can lead to discharge events ranging
from PD to flashover.
All of these examples illustrate that obtaining the best
information from oil testing requires an understanding of
the dynamics of the transformer as a system including the
distribution of water, gases, contaminants and decomposition products between the fluid, solid insulation and gas
spaces.
A selection of parameters that would achieve the information goals is suggested in Table 9. The diagnostic use of
oil-based information may be assisted by creating functional
test/information groups such as:
• Characterization – which gives parameters that can be
used to identify the oil
• Aging status – which gives parameters relevant to the
aging process
• Dielectric status – which gives parameters used to determine the dielectric safety margin and dielectric characteristics of the insulation spaces.
• Degradation status – which gives parameters relevant to
faults, failure and wear.
The Fluid as the Diagnostic Field
The possible benefits from using oil testing are indicated
on Table 8, the Transformer Functional Failure Model
suggested by the Cigre workgroup on Transformer Life
Management, Cigre WG12.18. One may observe that for
this collection most of the problems indicated could, in
principle, be detected by means of oil analysis.
Table 8
Functional Failure Model
Possible detection of typical defects and faults through oil tests.
SYSTEM,
COMPONENTS
DEFECT
Dielectric
Major Insulation
Minor Insulation
Leads
Excessive water
Oil contamination
Surface contamination
Abnormal aged oil
cellulose aging
static electrification
PD of low energy
Magnetic circuit
Core insulation
Clamping
Magnetic shields
Grounding circuit
Detection
Through oil
FAULTS
Detection
Through oil
Yes
Yes
No
Yes
Yes
Yes
Yes
Destructive PD
Localized tracking
Creeping discharge
Heated cellulose
Flashover
Yes
No
Yes
Yes
Yes
Loosening clamping
Short/open-circuit
in grounding circuit
circulating current
Floating potential
Aging lamination
No
Yes
Localized hot spot
Sparking/
discharges
Gassing
Yes
Yes
Mechanical
Windings
Clamping
Leads support
Loosening clamping
No
Winding distortion
radial
axial
twisting
Insulation Failure
No
Electric circuit
Leads
Winding conductors
Poor joint
Poor contacts
Contact deterioration
Localized hot spot
Open-circuit
Short-circuit
Yes
No
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
Yes
44
Transformer Handbook — Volume 1
Assessing the Transformer Condition for
Life Management
Assessing the Aging Status
of a Transformer
The assessment begins with a compilation of information about the transformer. This includes information about
the ratings, the core and coil such as their weights and
configuration, the preservation system, the cooling system,
the presence and configuration of a load tap-changer, the
presence of a no-load tap-changer, and the full characterization of the fluid. This information should be collected and
compiled in a manner that allows it to be available whenever
an assessment is performed.
Summary operation, event, and maintenance activity data
should also be compiled and available for assessments. As
was illustrated above, isolated test data may imply one cause
but be the result of a different one. Only with a completely
integrated set of information can a thorough assessment
be achieved.
We are proposing, for functional purposes, that the commentaries on the assessment address the topics of aging,
dielectric and degradation. Note that there is an overlap of
information between these topics and that these functional
groupings are not intended to limit a diagnostic testing
program.
The test information for aging status specified in Table
9 was chosen to answer the following questions:
• What is the remaining inhibitor content?
• What is the non-acidic polar content?
• What is the acid content?
• What is the water content?
• What is the amount of esterification?
• What is the amount of sludge?
• What is the amount of insoluble sludge?
• What is the degree of polymerization of the paper?
The answers to these questions integrated with the compiled transformer information provide the basis for assessing
the stages of aging and its potential consequences. From
the assessment, a set of conditions such as (1) presence of
water, acids and non-acid polars which accelerate cellulose
decomposition, (2) end of the induction period indicating
a trend of accelerated degradation, or (3) appearance of
sludge, may be chosen to initiate a course of action like
those in Figure 4.
Table 9
A Functional Classification of Oil-Based Information
Classification of Oil-Based Information for Transformer Life Management
Characterization
Aging Status
Dielectric Status
Degradation status
Fluid Composition
Carbon Types
Specific Gravity
Viscosity
Refractive Index
Permittivity
PAH content
Inhibitor Content
Total sulfur
Corrosive Sulfur
PCB Content
BTA Content
Free Radicals
Visible Spectrum
Acidity
Saponification Number
Inhibitor contents
IFT
IR spectroscopy
Dissipation factor
Resistivity
Polarization Index
Turbidity
Insoluble sludge
Sludge content
Oxidation stability tests
Furanic compounds
Water content
Percent saturation
Bound water
Particle profile
Breakdown voltage
Impulse strength
Charging Tendency
Resistivity
Dissipation factor
Insoluble sludge
Gas tendency
PD intention voltage
DGA
Extended DGA
Furanic compounds
Phenols
Cresols
Dissolved metals
Particle profile
45
Transformer Handbook — Volume 1
• What is the amount of insulation surface contamination?
Assessing the Dielectric Status
of a Transformer
The condition assessment of the dielectric system of a
transformer incorporates quantification of those factors that
may reduce the dielectric safety margin of insulation under
operating and through fault conditions. This information is
used to answer the following basic questions:
• What is the contamination with water, particles, acid,
sludge?
• Will there be a substantial reduction in the dielectric
margin at operating temperatures?
• What is the dielectric withstand capability?
• What is the amount of water in the solid insulation?
• Will there be bubble evolution at any allowable amount
of loading?
• What is the remaining mechanical strength of the solid
insulation?
• Does this provide adequate withstand capability?
Similar to the aging status, the answers to these questions integrated with the compiled transformer information provide the basis for assessing the stages of dielectric
strength and withstand potential. From the assessment, a
set of conditions such as (1) potential reduction of dielectric
strength from conductive particles, (2) potential reduction
of dielectric strength from sediment or surface active substances, (3) potential reduction of dielectric strength from
water, or (4) potential reduction of mechanical withstand
capability, may be chosen to initiate a course of action.
Oil A ging
cation
TTransformer
r ansformer Identifi
Identi ficati
on
Preservation system
Oi l Identification
Stage of aging
Prediction of further deterioration
Aggressiveness of oil decay
Cooling
Load/Temperature
Insulation design review
The Effect of oil decay on
the Transformer:
Paper deterioration
Oil/surface contamination
PD occurrence/ bubbling
Selection of the Process
for Insulation
Regeneration and
Reconditioning
Possible cause of aging:
Fluid characteristics
Overheating
Compatibility with materials
Selection of the Process
for Restoration.
Assessment of the Life
Span after Restoration
Service advisement
Rehabilitation program
Figure 4 — A flow chart of actions for fluid aging
46
Transformer Handbook — Volume 1
Conclusion
Assessing the Degradation Status of a
Transformer
Transformer life management requires comprehensive
condition assessments to be made from a system’s perspective. Because the transformer fluid is systemic, a large
amount of this requisite information is available from fluid
testing. In order to obtain the most complete and therefore
useful information from fluid testing, an understanding of
the dynamics of the transformer as a system, including the
distribution of water, gases, contaminants and decomposition products between the fluid, solid insulation and gas
spaces, is required. Using this understanding and the test
information obtained, a diagnostic assessment can be made.
This diagnosis coupled with an effective set of action plans
provides the asset manager with the ability to choose the
course of action best suited to the utility’s needs.
Degradation by-products such as gases, furans, phenols,
cresols, dissolved metals, and metal particles are effective
indicators of degradation processes. Once indicated, the
challenge is to identify the source and seriousness of the
process. The scheme in Figure 5 shows how gas information
can be used to begin to locate the source of several degradation processes. Combined with the additional information
available for the transformer, the success of identifying the
source and severity can be greatly enhanced.
Gassing
External
sources
Internal
sources
Thermal cellulose
Divertor
LTC
Leads
Oil
pump
Strands
coils
Desorption
from
insulation
Structured
insulation
Overheating
while
processing
Unusual
sources
Thermal Oil
Current
carried
circuit
Leads
connection
Winding
joints
LTC
contacts
Sparking,
arcing
Loops
stray flux
Static
electrification
Loops
main flux
Operative
voltage
Shields,
floating
potential
Creeping
discharge
Main
flux
Stray
flux
Closed
loops
F loating
potential
Figure 5 — Diagram of how gas information can be used to locate sources of degradation processes
Transformer Handbook — Volume 1
References
1.
2.
3.
4.
5.
6.
7.
8.
9.
John Sabau, Rolf Stokhuyzen, “Aging and Gassing
of Mineral Insulating Oils”, Proceedings of TechCon
2000
Dr Bruce Pahlavanpour, National Grid Company
plc, “UK Insulating Oil Aging: Reclamation or Replacement”
Dr Bruce Pahlavanpour & Gordon Wilson, National
Grid Company plc, Kelvin Avenue, Leatherhead,
Surrey, KT22 7ST Insulating Oil Management Services
W.Tumiatti and B. Pahlavanpour “Condition Monitoring by Oil Chemical Analysis”
T. V. Oommen* Bubble Evolution from Transformer
Overload, Paper for presentation at the IEEE Insulation Life Subcommittee, Niagara Falls, Canada,
October 17, 2000.
CIGRE WG 12.18 “Life management of Transformers, Draft Interim Report”, CIGRE SC12 Colloquium, July 1999, Budapest.
E. Savchenko and V. Sokolov “Effectiveness of Life
Management Procedures on Large Power Transformers”, CIGRE SC12 Colloquium, 1997, Sydney.
IEEE “Guide for Diagnostic Field Testing of Electric Power Apparatus-Part 1 : Oil Filled Power transformers, Regulators and Reactors”, IEEE Std 621995.
V.V. Sokolov, Z. Berler, V. Rashkes ”Effective
Methods of the Assessment of the Insulation System Conditions in Power Transformers: A View
Based on Practical Experience”, Proceedings of
the EIC/EMCWE’99 Conference, October 2628,1999,Cincinnati,OH
10. V. V. Sokolov and B. V. Vanin “Experience with InField Assessment Of Water Contamination of Large
Power Transformers”, EPRI Substation Equipment
Diagnostic Conference VII, 1999.
11. V.V. Sokolov Consideration on Power Transformer
Condition based Maintenance,
12. EPRI Substation Equipment Diagnostic Conference
VIII, February 20-23, 2000, New Orleans, LA
13. W.McNutt, A,Bassetto, P,Griffin. Tutorial on Electrical-Grid Insulating Papers in Power Transformers.
1993 Doble Clients Committees Fall Meeting.
14. T. V. Oommen, EPRI Report EL-7291 ‘Further Experimentation on Bubble Generation During Transformer Overload’, March 1992
15. T. V. Oommen, ‘Particle Analysis on Transformer Oil
for Diagnostic and Quality Control Purposes’ Doble
Conf. Paper, 1984
47
16. T. V. Oommen, ‘Update on Metal-in-Oil Analysis
As It Applies to Transformer Oil Pump Problems’ ,
Doble Conf. Paper, 1984
17. Sakkie vanWyke, “The Ever-Aging Power Plants in
South Africa: Analyzing the Current Scenerio and
Establishing Effective Management Strategies”,
Proceedings of TechCon 2000 Aus-NZ.
18. V.G.Davydov, O.M.Roizman, “Moisture Phenomena and Moisture Assessment in Operating Transformers”, Proceedings of TechCon 2000 Aus-NZ.
Dr. Ted Haupert is professor emeritus of analytical chemistry at
California State University-Sacramento. He is one of the founders of
Analytical Associates and presently an owner of TJ/H2b Analytical
Services, Incorporated. Dr. Haupert specializes in chemical analyses
exclusively for the electric power industry. He is involved with testing
methods related to dielectric materials (liquids, solids, and gases) that can
provide for the assessment of the condition of electrical equipment. He
is a pioneer in the development of dissolved gas analysis (DGA) and he
continues to be a leader in the field of diagnostic and preventative testing.
Dr. Haupert is a graduate of the University of Wisconsin-Madison and
since 1972 he has worked in the area of developing analytical methods
related to insulating materials. He is a member of the American Chemical
Society, The Society of Sigma Xi, the Association of Official Analytical
Chemists, the Insulating Fluids Subcommittee of the IEEE, and the
Insulating Liquids and Gases Committee of the ASTM.
48
Transformer Handbook — Volume 1
Understanding Water
in Transformer Systems
The Relationship Between Relative Saturation
and Parts per Million (ppm)
NETA World, Spring 2002
by Lance R. Lewand
Doble Engineering Company
Water content in transformer oil in parts per million
(ppm) is a familiar concept to most in our industry, and limits of 30 to 35 ppm are generally referenced. However, these
simple concentration limits have limited value in diagnosing
the condition of transformer systems and, thus, the concept
of relative saturation (RS) of water in transformer oil has
been re-introduced over the past 15 years. The concept of
relative saturation of water in transformer oil is not a new
one and was originally championed by Frank Doble as early
as the mid 1940s.Thus, this article discusses and details the
relationship between RS and ppm.
It is well known that moisture continues to be a major
cause of problems in transformers and a limitation to their
operation. Particularly problematic is excessive moisture
in transformer systems, as it affects both solid and liquid
insulation with the water in each being interrelated. Water
affects the dielectric breakdown strength of the insulation,
the temperature at which water vapor bubbles are formed,
and the aging rate of the insulating materials. In the extreme
case, transformers can fail because of excessive water in the
insulation. The dielectric breakdown strength of the paper
insulation decreases substantially when its water content
rises above two to three percent by weight. Similarly, the
dielectric breakdown voltage of the oil is also affected by
the relative saturation (RS) of water in oil. The maximum
loading that is possible while retaining reliable operation
(i.e., preventing the formation of water vapor bubbles) is a
function of the insulation water content. For example, dry
transformers (<0.5 percent water in paper) are much less
susceptible to water bubble evolution. In this case, emergency loading at hot-spot temperatures below 180°C may
be possible with little risk of bubble formation. In contrast,
a wetter transformer, with 2.0 percent moisture in the paper, runs the risk of water bubble formation with hot-spot
temperatures as low as 139°C under the same conditions.
A more long-term problem is that excessive moisture ac-
celerates the aging of the paper insulation, with the aging
rate being directly proportional to the water content. For
example, as the water content in the paper doubles so does
the aging rate of the paper. The deterioration of the paper
insulation results from the weakening of the hydrogen bonds
of the molecular chains of the paper fibers. For these reasons
it is important to have a means of assessing the moisture
content of transformer systems and to maintain transformers
in a reasonably dry state.
In order to fully understand water and its dynamics in
transformer systems, a short explanation of the different
types of water encountered and the concepts of solubility
and relative saturation are provided.
Types of Water in Oil
Water can exist in several different states within the
transformer. There are three basic types of water found associated with transformer oil:
• Dissolved water is hydrogen bonded to the hydrocarbon
molecules of which oil is composed.
• Emulsified water is supersaturated in solution but has
not yet totally separated from the oil. It usually gives oil
a milky appearance.
• Free water is also supersaturated in solution but in a
high enough concentration to form water droplets and
separate from the oil.
In most cases, when one is analyzing or discussing the
amount of water in oil, dissolved water is being referred to
as emulsified, and free water is visually apparent.
49
Transformer Handbook — Volume 1
What is Water in Oil (ppm), Solubility
of Water in Oil, and RS of Water in Oil?
Where: So is the solubility of water in mineral oil
K is the temperature in Kelvin (°C + 273)
The detection of water in oil performed in the laboratory
is most often performed by an analytical technique called
Karl Fischer titration described in ASTM Test Method
D 1533 or IEC Method 60814. Both methods are very
comparable and involve a coulometric titration technique
involving the reduction of an iodine-containing reagent. The
methods are used to determine the amount of water in an
oil sample on a weight-to-weight (mg/kg) basis or what is
commonly known as ppm (parts per million).
The concepts of solubility and relative saturation can
sometimes be difficult to understand, but it is an important concept when trying to assess the dryness or wetness
of a transformer system. Solubility is defined as the total
amount of water than can be dissolved in the oil at a specific temperature. The solubility of water is not constant
in oil but changes due to temperature. As the temperature
increases, the amount of water that can be dissolved in oil
also increases. The increase is not linear but exponential in
function. For example, at 10°C only 36 ppm of water can
be dissolved in the oil, whereas when the temperature increases to 90°C, the amount of water that can be dissolved
in the oil increases tremendously to almost 600 ppm. The
table shown lists the calculated solubility limits for oil at
various temperatures. These levels are the greatest amount
of water that can be dissolved at the temperatures listed. If
the concentration of water in oil is greater than that shown
for that specific temperature then, in all likelihood, the oil
is supersaturated with water, and free or emulsified water
could exist.
Relative Saturation (RS) is the actual amount of water
measured in the oil in relation to the solubility level at that
temperature. Relative saturation, expressed in units of percent, is the concentration of water (Wc) in the oil relative to
the solubility (So) or concentration of water the oil can hold
at the measurement temperature, as shown in Equation 2.
Table 1 — Water in Oil Solubility as a
Function of Temperature
Oil Temperature
Water Content in Oil, ppm
10°C
36
0°C
20°C
30°C
22
55
83
40°C
121
60°C
242
50°C
70°C
80°C
90°C
100°C
173
331
446
592
772
The solubility for mineral oil can be calculated using
Equation 1:
(Equation 1)
Log So = -1567/K + 7.0895
(Equation 2)
Where:
RS = Wc /So (100%)
Wc is in ppm wt./wt.
So is in ppm wt./wt.
For example, a sample of oil was taken for determination
of the water content. The temperature of the oil at the time
of sampling was 62°C. The laboratory performed the analysis and determined the water content to be 11 ppm. From
Equation 1, it is calculated that the solubility level at 62°C
is 259 ppm. As discussed previously, relative saturation is
the actual measured value compared to the solubility value.
In this case it is 11 ppm divided by 259 ppm resulting in a
relative saturation of 4.25 percent.
Effects of Relative Saturation on Dielectric
Strength
To properly maintain and operate transformers, an
understanding of the effects of moisture on the dielectric
breakdown strength of the electrical insulating liquids is
necessary. Increasing moisture content reduces the dielectric
breakdown voltage of insulating liquids. The correlation between the water content in new, filtered, mineral oils at room
temperature and the dielectric breakdown voltage using
ASTM method D 1816 (0.04 inch gap) is given in Figure
1 (water content, ppm). Of course, the dielectric breakdown
voltage is also a function of the number and type of particles
and their conductivity, not just the water content.
Taking the same dielectric breakdown voltage data
and converting it to RS (Figure 1, %RS graph) provides a
much straighter curve except at the extremes. It is evident
that there is a better correlation between RS and dielectric
breakdown voltage than with moisture concentration and
dielectric breakdown voltage.
Transformer Handbook — Volume 1
48
44
40
High RS
36
32
28
Medium RS
24
20
16
Low RS
12
8
4
Increasing Dielectric Strength
0
4
8
12
16
20
24
28
32
36
40
44
48
52
56
60
Water Content, ppm, wt./wt.
Dielectric Break down Voltage, k
The water
concentration was
constant at 30 ppm.
The temperature was
changed to change the
relative saturation.
Decreasing Relative
Saturation, %
Dielectric Break down Voltage, k
50
Figure 2 — Relationship between Dielectric Strength and RS
Transformers are more complicated systems than this
simple example. However, the same basic principles apply
for the dielectric breakdown strength of the liquid dielectric.
That is, it remains a function of the relative saturation of
water in the oil. During the cool-down cycle of a thermal
transient in a transformer some of the moisture returns to
the paper and some of the moisture remains in the oil. The
relative saturation of water remaining in the oil will influence its dielectric breakdown voltage.
48
44
40
36
32
28
24
20
16
12
What Does This All Mean for a
Transformer System?
8
4
0
10
20
30
40
50
60
70
80
90
100
RS, %@22°C
Figure 1— Dielectric Strength Versus Water Content
and Relative Saturation (RS)
A simple example illustrates that the dielectric breakdown voltage of insulating oils is proportional to the relative saturation of water in oil rather than the concentration
in ppm. The humidity is controlled in this example so the
concentration of water is held constant at 30 ppm. The
first dielectric breakdown measurement is made at 100°C.
At this temperature the solubility of water in oil is about
772 ppm (Table 1). The relative saturation of water in oil
is therefore about four percent (30 ppm/772 ppm x 100),
and the dielectric breakdown voltage of a well-filtered oil
would be quite high. The temperature is now reduced to
room temperature or about 22°C. The solubility of water
in oil is about 60 ppm (Table 1), and the relative saturation
is 50 percent.
The dielectric breakdown voltage would be expected to
be about half of what it was when the relative saturation
was very low. If the temperature is cooled to 0°C, the results of a dielectric breakdown voltage should be quite low
because the solubility of water in oil at this temperature is
about 22 ppm (Table 1). As the water content in the oil is
higher than this, the water forms an emulsion and begins
to condense. During all this time the concentration of
water in oil has not changed. This relationship is shown in
Figure 2.
Water does not remain at the same concentration in
insulations but, rather, it is continuously migrating between
the solid and liquid insulation. In order to understand
the significance of the water-in-oil value, the operating
temperature of the transformer at the time of sampling
must be known. Most of the water in a transformer system resides in the solid insulation (paper and pressboard)
and not in the oil. As temperature increases the water is
forced from the paper into the oil. Although the amount
of water in the paper will change relatively little, the
concentration in the oil may change by an order of magnitude or more, depending upon the initial water content
of the paper and the temperature increase. Fortunately, as
described previously, the solubility of water in oil
increases with temperature such that the relative saturation
may not change much under such conditions, even though
the absolute water values in ppm can increase tremendously.
In fact, the normal suggested limits of 30 to 35 ppm may
be indicative of a wet transformer if the insulation was at
equilibrium at temperatures of 25°C or below since this
represents a relative saturation of 50 percent or greater
in the oil. To maintain reasonable dielectric breakdown
strength of oil, it should remain below 50 percent saturation of water in oil.
References
Doble, F. “The Doble Water Extraction Method,” Minutes
of the Thirteenth Annual conference of Doble Clients, 1946,
Sec. 10-401.
Transformer Handbook — Volume 1
Griffin, P. J. “Water in Transformers – So What!,” National
Grid Condition Monitoring Conference, May 1996.
Lewand, L. R. and Griffin, P. J., “How to Reduce the Rate
of Aging of Transformer Insulation,” NETA World,
Spring 1995, pp. 6-11.
Moser, H.P. “Part II. Aging of Insulating Materials,”
Transformerboard, Special Print of Scientia Electrica,
translated by W. Heidemann, EHV-Weidmann Lim.,
1979, pp. 12-15.
Griffin, P. J., Bruce, C. M., and Christie, J. D. “Comparison of Water Equilibrium in Silicone and Mineral Oil
Transformers,” Minutes of the Fifty-Fifth Annual International Conference of Doble Clients, 1988, Sec. 10-9.1.
Lance Lewand received his BS degree at St. Mary’s College of Maryland in 1980. He has been employed by the Doble Engineering Company
for the past seven years and is currently Project Manager of Research
in the materials laboratory and Product Manager for the DOMINOTM
product line. Prior to his present position at Doble, he was the Manager
of the Transformer Fluid Test Laboratory and PCB and Oil Services at
MET Electrical Testing in Baltimore, MD. Mr. Lewand is a member
of ASTM committee D 27.
51
52
Transformer Handbook — Volume 1
It Meggered Fine — Sorry it
Scorched the Building!
PowerTest 2003
(NETA Annual Technical Conference)
Presenter
John Cadick
Co-Author
Al Rose
In the words of the famous commercial, “We’ve come a
long way baby!” From the early days of the “run it until it
fails” generation, through preventive maintenance, predictive
maintenance, and
now – more recently – condition
based maintenance
(CBM) or reliability centered maintenance (RCM),
electrical testing
and maintenance
of transformers
has truly moved into the 21st century.
This paper discusses some of the well recognized and
accepted testing methods for oil-filled power transformers,
but it adds a twist. Here you will read about the collection, trending, and statistical analysis of the data derived
from these tests. An overview is provided which allows the
informed reader to begin the development of new philosophies and to better understand the value of using modern,
scientific approaches to electrical maintenance and testing.
It should be noted that this paper has kept the discussed
tests somewhat simple to better facilitate understanding of
trending and analysis. Additional testing and analysis may
be useful and sometimes necessary
The Core
The core is the heart of a transformer and surprisingly
has not changed much since the beginning of ac power;
thin, flat laminations of soft iron. Early on core materials
changed to sheet steel, and then to silicone steel, but the
basic configuration of the core has not significantly changed.
Thin laminations are normally around .30 millimeters thick
and are stacked to a size and height determined by design.
After the core is assembled it is clamped to ensure the
laminations are tight.
An improperly clamped core will vibrate excessively, increasing the “hum” of the unit and eventually contributing
to a premature failure. (and you thought units “hummed”
because they didn’t know the words!)
Transformers — A Background
High and medium voltage transformers are probably
the most complex and easily the most expensive pieces
of equipment in a transmission and distribution system.
They can range anywhere from 750,000 volts down to
4160 volts primary voltage, from a few hundred VA up to
1000MVA, and be either liquid filled, gas filled, or dry type
in configuration.
Figure 1 — Three-Phase LTC Core and Coil Assembly
Transformer Handbook — Volume 1
The Windings
The windings are assembled around the core and are of
two types of materials; copper and aluminum. Copper has
the advantage of having a greater mechanical strength and
better electrical conductivity, while aluminum is lighter,
costs less, and can be better at heat dissipation. Most large
distribution and transmission units are copper, while small
distribution and dry types are increasingly aluminum.
Kraft paper or pressboard paper insulates the windings.
For coil winding construction Kraft paper is tightly wound
around the copper coils, the number of turns of paper being determined by the voltage and kVA rating of the unit.
Sheet windings can use either Kraft paper or pressboard
paper between layers. After assembly of the windings the
entire unit is tightened, or “clamped” down. The unit is then
baked and vacuum impressed, hot liquid flushed for liquid
units or epoxy impregnated for dry and gas units, and then
tightened again. The unit is then installed in its tank, acceptance tested, and prepared for shipment.
The Liquid
The most common type of transformers in a transmission
and distribution system use insulating oil as a dielectric and
cooling medium. Some, depending on their size, have oilcirculating systems for enhanced cooling. This is important
because heat is the main enemy of any transformer. Steady
state operation of a transformer at only 10o Celsius above
its nameplate rating can reduce its life by up to 50%. Heat
can breakdown the winding insulation and, under the right
conditions, degrade the insulating oil. Therefore, determining the insulation integrity and oil condition is of primary
importance.
Oil is the lifeblood of an oil filled transformer. Oil tests can
reveal many problems internal to a transformer well before
the transformer would fail. The advantage of oil testing is that
it doesn’t require the transformer to be taken off line. All oil
samples can be drawn with the transformer on line, even at
100% load. Oil tests fall into two classifications - Oil Screens
and Dissolved Gases.
Oil Screens
Historically, the Dielectric Test has been used to determine
the condition of transformer oil under the assumption that
if it had a high dielectric withstand voltage it had to be OK.
Unfortunately, having a high withstand doesn’t guarantee a
soundly operating transformer, as the dielectric test is only
affected by free water and/or other contaminates in the oil.
As a result, other tests are necessary in order to better evaluate
the oil. Standard oil screen tests performed on transformers
include:
Karl Fisher, ASTM D-1533-88, tests for water in insulating
fluids. This test reveals total water content in oil, both dissolved and free. High readings could indicate a leak in the
equipment housing or insulation breakdown.
53
Dielectric Breakdown Strength, ASTM D-877 and D-1816,
tests for conductive contaminants present in the oil such as
metallic cuttings, fibers, or free water.
Neutralization Number, ASTM D-974, commonly called
the acid number, this measurement shows the amount of
acid in the oil. The acidity is a result of oxidation of the oil
caused by the release of water into the oil from insulation
material due to aging, overheating, or operational stresses
such as internal or through faults. The acidity is measured as
the number of milligrams of potassium hydroxide (KOH) it
takes to neutralize the acid in one gram of oil. An increase in
the acidity indicates a deterioration of the oil. This process
causes the formation of sludge within the windings which
in turn can result in premature failure of the unit.
Interfacial Tension(IFT), ASTM D-971, measures the tension at the interface between two immiscible liquids, oil
and water. It is expressed in dynes/centimeter. This test is
extremely sensitive to oil decay products and contamination
from solid insulating materials. Good oil will have an IFT
of 40 to 50 dynes/cm, and will normally “float” on top of
water. As transformer and breaker insulation ages, contaminates such as Oxygen and free water are released into the
oil. The properties that allow the oil to “float” on top of the
oil then begin to break down and the result is a lower IFT.
Along with the neutralization number, the IFT can reveal
the presence of sludge in insulating oils.
Color, ASTM D-1524, as insulating oils in electrical equipment age, the color of the oil tends to gradually darken. A
marked color change from one year to the next indicates
a problem.
Sediment, ASTM D-1698, indicates deterioration and/or
contamination of the oil.
Oil Power Factor, ASTM D-924, taken at 25 degrees C, this
test can reveal the presence of moisture, resins, varnishes, or
other products of oxidation or foreign contaminates such as
motor oil and fuel oil. The power factor of new oil should
always be below .05%.
Visual Examination, ASTM D-1524, good oil is clear and
sparkling, not cloudy and dull. Cloudiness indicates the
presence of moisture or other contaminates. This is a good
“quick look” field test; however a Karl Fisher or Dielectric
Breakdown test will be much more definitive.
Of all the above tests, the Karl Fischer, Interfacial Tension,
Neutralization Number, Dielectric Breakdown, and Oil Power
Factor are the most important. These are the oil screen tests
that not only need to be looked at, but, unlike traditional
analysis, they need to be trended, and when the trends are
getting worse the rate of change needs to be examined. (It
should be noted that as of today the Dielectric Breakdown
test has not been shown to be as effective in trending as the
other four tests; however its value for determining the voltage
withstand capability of insulating fluid is unquestioned)
54
Transformer Handbook — Volume 1
First, here are the industry standards, taken from IEEE
standards and various industry publications:
Water
< 25ppm @20 degrees C (varies with both
fluid type and voltage rating)
Interfacial tension > 27 dynes/cm for in-service oil
> 40 dynes/cm for new oil
Power factor
Acid number
< .5% at 25 degrees C for in-service oil
< .05% at 25 degrees C for new oil
< .15 for in-service oil.
< .05mg KOH/gm for new
Traditional analysis says that as long as the test values do
not exceed the standards the transformer is OK. However,
lets look at a unit that, while still testing good raises some
significant questions.
The unit is a 3000kVA, 6.9kV to 480V unit, 10 years
old, good operating history. Here is a chart of the last 5 oil
screens:
Date
2/3/1998
1/15/1999
2/4/2000
1/29/2001
2/1/2002
Karl Fischer
NN
IFT
Power Factor
12
18
16
19
24
0.03
0.03
0.05
0.05
0.07
48
44
42
39
31
0.08%
0.10%
0.22%
0.29%
0.35%
Notice that all four tests are within the standards, and
if the only comparison is with the standards then this unit
would be classed as good. However, all of the trends are
going in a negative direction. The graphs show this very
well:
From a percentage standpoint, the Karl Fischer has increased by 100%, the NN has increased by 133%, the IFT
has decreased by 35%, and the Power Factor has increased
by 330% Clearly, something is going on inside the transformer. But what?
Unfortunately, one set or type of test usually can not
determine a specific problem. Transformer analysis requires
looking at multiple tests, and using all the results to reach
a conclusion. So let’s look at the next test - dissolved gas
analysis, sometimes called Gas-in-Oil analysis or abbreviated as dgio.
Dissolved Gas
This test can show many problems internal to a transformer
before the problem becomes terminal. As events occur inside
a transformer, gasses are liberated into the oil. The primary
causes of these gases are thermal, mechanical, and electrical
stresses in the windings. Some examples are corona discharge
(a spark due to ionization), general overheating (overload
conditions), arcing, and through-faults (which cause large
mechanical stresses).
We are concerned with 9 gasses in this analysis. They
are:
- Nitrogen(N2)
- Oxygen(O2)
- Carbon Dioxide(CO2)
- Carbon Monoxide(CO)
- Methane(CH4)
- Ethane(C2H6)
- Ethylene(C2H4)
- Hydrogen(H2)
- Acetylene(C2H2)
55
Transformer Handbook — Volume 1
Different combinations of these gasses reveal different
problems. Large amounts of CO and CO2 indicates overheating in the windings, CO, CO2, and CH4 show the
possibility of hot spots in the insulation, H2, C2H6, and
CH4 are indicative of corona discharge, and C2H2 is a sign
of internal arcing. After the concentration of each gas (in
PPM) has been determined, various industry publications
may be used to help determine the potential problem.
Types Of Probable Faults
Detected Gases
Interpretations
Nitrogen plus 5% or less Oxygen Normal operation of sealed
transformer
N2 plus more than 5% O2
N2, CO2, or CO, or all
N2 and H2
N2, H2, CO2, and CO
N2, H2, CH4, with small
amounts of C2H6 and C2H4
N2, H2, CH4, with CO2, CO,
and small amounts of other
hydrocarbons, no C2H2
N2 with high H2 and other
hydrocarbons including C2H2
N2 with high H2, CH4, high
C2H4, and some C2H2
Same as above except CO2 and
CO present
Check for tightness of sealed
transformer
Transformer overloaded or operating hot, causing some cellulose
breakdown
Corona discharge, electrolysis of
water, or rusting
Corona discharge involving
cellulose or severe overloading of
transformer
Sparking or other minor fault
causing some breakdown of the
oil
Sparking or other minor fault in
presence of cellulose
High energy arc causing rapid
deterioration of oil
High temperature arcing of oil
but in a confined area, poor connections or turn-to-turn shorts
are examples
Same as above except arcing in
combination with cellulose
As with the oil screens, there are industry standards that
help determine absolute limits.
Dissolved Gas Limits
Hydrogen (H2)
< 150 PPM
Methane (CH4)
< 25 PPM
Ethylene (C2H4)
< 20 PPM
Ethane (C2H6)
Carbon Monoxide (CO)
Carbon Dioxide (CO2)
< 10 PPM
< 500 PPM
< 10,000 PPM
Nitrogen (N2)
1 to 10%
Total Combustibles
< 1000 PPM
Oxygen (O2)
0.2 to 3.5%
So let’s return to that transformer we looked at in the
oil screens section. The dissolved gas test results from the
last 5 tests are:
Date
Oxygen Nitrogen Hydrogen
Carbon
Carbon
Monoxide Dioxide
Methane Ethane Ethylene Acetylene
2/3/1998
6692
91,716
32
103
2,398
6
5
16
0
1/15/1999
7923
Saturated
37
212
3,259
14
4
15
0
2/4/2000
9453
Saturated
42
343
5,437
20
7
21
0
1/29/2001 11,256 Saturated
73
498
7,687
16
5
18
0
2/1/2002
95
663
9,654
24
10
22
0
13,267 Saturated
In looking at these results one can see that the first 4 tests
are all within the industry limits; however oxygen, hydrogen,
carbon monoxide, and carbon dioxide are all increasing.
The rate of rise for these four gases are averaging 18% per
year for oxygen, 33% per year for hydrogen, 62% per year
for carbon monoxide, and 42% per year for carbon dioxide.
Using these percentages one could almost predict what the
concentrations would be for the fifth test. So if this unit was
being trended the problem would have been discovered in
year four (2001), a full 12 months before the unit exceeded
an industry standard.
So looking at the above probable fault chart we see the
dissolved gas results fall into 4 possible categories:
Detected Gases
N2 plus more than 5% O2
N2, CO2, or CO, or all
N2 and H2
N2, H2, CO2, and CO
Interpretations
Check for tightness of sealed
transformer
Transformer overloaded or operating
hot, causing some cellulose breakdown
Corona discharge, electrolysis of water,
or rusting
Corona discharge involving cellulose
or severe overloading of transformer
It appears that we have a transformer that is being
overloaded, maybe with a leak, allowing moist air into the
headspace, or too much water in the windings, and maybe
some corona discharge. Returning to the oil screens, we see
that water in the oil will cause the Karl Fischer to increase,
the IFT to decrease, and the Oil Power Factor to increase.
Additionally, the NN will increase when free oxygen in the
oil is combined with heat, and overloading a transformer
will cause excessive heat. An increase in hydrogen can be
caused by the breakdown of water in the unit due to heat.
So now a picture is beginning to be painted. The oil screens
and dissolved gas analysis support a transformer that has
been overloaded, and has some type of moisture issue, maybe
a leaking gasket, or wet windings. But we need to confirm
what we suspect, and we need one more test to do that.
56
Transformer Handbook — Volume 1
Insulation Power Factor
The Insulation Power Factor test is an ac non-destructive
test that measures the power loss through the insulation
system to ground caused by leakage current. It is equal to
the insulation resistance divided by the insulation impedance. To measure this value a known voltage is applied to the
transformer windings and the resulting current is measured.
Because the insulation system in a transformer is capacitive
in nature, there will be a phase angle between the voltage
applied and the resulting current. The cosine of this angle
is called the power factor and the measured current squared
times the insulation resistance is called the watts loss.
Figure 4 shows a greatly simplified equivalent circuit of
a transformer’s insulation system and where this leakage
current can go. As the insulation degrades, the amount of
leakage current will increase, going from the windings to
ground, or from winding to winding. Unfortunately, just
knowing the amount leakage current is not enough. The
condition of the insulation needs to be established so a
trend can be identified. Since the capacitance value of the
insulation is part of the impedance of the circuit, and any
change in the impedance will change the resultant phase
angle between the applied voltage and current, the cosine
of that angle, the Power Factor, is trended.
CH
High
T ank
and
C ore
C HL
L ow
CL
Figure 2 — Power Factor Phase Relationships
Figure 4
To better understand the values of the Power Factor
tests we should examine what the test equipment is actually
seeing. Figure 3 shows a cutaway of a transformer coil with
its insulation (Kraft paper). The job of the insulation is to
keep the electrical energy from finding a path to ground. A
perfect insulation would have no current leaking from the
coil; therefore it would be acting like the perfect dielectric
medium, the same function as a capacitor. However, due to
manufacturing imperfections, age, or abuse the insulation
material will have a small amount of leakage current.
The Power Factor should be measured and recorded
when the transformer is first installed to establish a baseline.
Subsequent test results should be compared to the initial
readings and trended over time. A new oil filled transformer
should have a power factor under .5% and an in-service oil
filled transformer should have a power factor under 2%.
So let’s look at the overall power factor readings for our
example transformer:
Ground
CU/AL Conductor or
Strand
Ground
Figure 3
Oil, Paper, Wood
Insulation
Oil, Paper, Wood
Insulation
Date
High - Low
Low - High
1/28/1994
1/30/1996
2/4/1998
2/5/2000
0.98
1.2
1.48
1.36
0.87
1.32
1.6
1.55
2/3/2002
1.62
1.81
Transformer Handbook — Volume 1
From the looks of it the readings are all within the limits;
however look at a graph of the results:
The power factor values have increased 65% for the high
to low reading, and 108% for the low to high reading over
an eight year period. But, as with the oil screens, nothing is
out of spec yet. A slow increase over time in the power factor
readings is usually indicative of insulation weakening due to
overloading or a winding that is becoming increasingly wet
or dirty. The oil screens and dissolved gas analysis support a
transformer that has been overloaded, and has some type of
moisture issue, maybe a leaking gasket, or wet windings. So
our picture has been painted - a transformer that has excessive moisture, and probably has been operated at more than
it’s KVA rating on occasion. Our recommendations would
be to first inspect the transformer for leaks, insuring that it
is perfectly sealed, then perform a vacuum dehydration on
the unit, then retest for a new baseline.
Conclusions
Historically, transformer analysis consisted of performing
industry accepted tests, comparing the results to industry
standards, and, if the results were within the proper limits
declaring the unit sound and ready for operation. As we
have seen in this paper it is possible for a transformer to be
operating within those parameters, but still have an internal
problem that eventually will require corrective action. It’s
not enough to compare values anymore - we need to know
which direction those values are going, and how fast they
are moving. We can then more effectively plan any required
actions. When we do this we are moving our maintenance
philosophy to condition based, instead of time based. And
in the long run we reduce in-service failures, and increase
up-time. Isn’t that where we all want to be?
A registered professional engineer, John Cadick has specialized for
three decades in electrical engineering, training, and management. In
1986 he created Cadick Professional Services (forerunner to the present-day Cadick Corporation), a consulting firm in Garland, Texas. His
firm specializes in electrical engineering and training, working extensively
in the areas of power system design and engineering studies, conditionbased maintenance programs, and electrical safety. He is the author of
the Electrical Safety Handbook as well as Cables and Wiring.
57
58
Transformer Handbook — Volume 1
Remanufacturing
of Power Transformers
PowerTest 2003
(NETA Annual Technical Conference)
Presenter
D. E. Corsi
Ohio Transformer an S.D. Myers, Inc. Co.
Abstract
The following paper will summarize the design considerations involved in the remanufacturing process. The
main considerations involved in the redesign process will
be discussed in general terms. The design process is critical
in determining transformer reliability in service. A forensic
study performed in the United Kingdom stated that 35%
of transformer failures in the United Kingdom are due to
design defects. [1] Given that a significant percentage of
transformer failures have their root cause in design defects,
the manufacturer’s design philosophy, methods and approach are critical to in-service reliability.
Introduction
The benefits of remanufacturing are many: voltage
changes, higher capacity, increase in dielectric margins and
improvements in efficiency. [References 2 & 3] The design
process in remanufacturing is concentrated around the
redesign of the transformer’s core and coils.
The Redesign Process
The usual sequence of events in the redesign process is to
gather teardown data and recreate the original as-is design;
then proceed to design the transformer’s core and coils with
the following major areas of concern; insulation design, short
circuit design and thermal performance. Since in a redesign
the original core is typically reused, the major effort in the
redesign process revolves around the winding design.
The design process is iterative. Any design adaptations
made to windings, for example, permeate throughout the entire design process and will affect the insulation design, short
circuit design and thermal performance of the transformer.
This process is repeated until a balance is reached among
all three and technical requirements of the design are met.
The gathering of design data is done for a number of
reasons. First, it allows the designer to estimate the original
stray and eddy losses. Second, it gives an estimate on the
original average winding gradients and oil rises. Finally, it
provides a glimpse at the transformer as it was delivered
to the factory. The physical reality of the as-is design is
compared to the stated results on the OEM’s Certified
Test Report to ascertain if the unit met the stated capacity,
performance and guarantees. Winding Design
The first step in the design process is to evaluate if the
existing core can be reused. [2] A newer core that has not
sustained failure damage can be reused and the transformer
windings can be redesigned around the original core. Redesigning the core and coils around the existing core provides
the greater economic opportunity relative to purchasing a
new transformer.
Cores with extensive failure damage can be replaced. A
replacement core provides an opportunity to optimize the
core and coil design. A new core constructed with modern
materials, design techniques and manufacturing practices
can be operated at higher levels of induction. Transformers
redesigned with a new core will be more efficient than the
original transformer. The economic benefit of the optimized
core and coil design must be weighed against the additional
cost of the new core. This is accomplished by calculating the
benefits of the reduced losses over the expected life of the
transformer to the first cost of ownership of the redesigned
transformer.
The types and arrangements of windings are selected to
provide the best overall solution to the insulation design,
short circuit design and thermal requirements of the transformer. Specific windings and winding arrangements are
selected to provide optimum balance of electrical, magnetic
and thermal performance considering all tap positions and
operating conditions.
59
Transformer Handbook — Volume 1
There are two ways in which winding design affect the
magnetic circuit of the transformer. First, the volts per turn
of the design will establish the operating point (average induction) of the core. Second, the winding design, conductor
stranding and strand dimensions are important in reducing
additional losses in the windings.
In addition, the winding design should limit the core’s
maximum operating point (average induction) of the transformer at 100 percent of rated voltage to be no more than
the original levels. Designing the transformer to operate
above the original operating point will increase the core
losses, real and apparent, and the metallic hot spot rise in
the core joints.
Another point that must be made is that the winding design must also limit the maximum operating point (average
induction) of the core at 110 percent of rated voltage. The
current ANSI/IEEE standards require that a transformer be
designed to operate at 110 percent of rated voltage without
load. If the operating induction level of the core is too high
the transformer core will begin to saturate and will not be
able to provide the required output voltage at 110 percent
of rated voltage.
Insulation Design
Transformer windings must withstand the electrical stress
imposed upon them by testing and the electrical stress that
the windings will be exposed to during their life in service.
During testing in the factory the dielectric tests are three
fold: [5]
(1) A test at power frequency applied for 1 minute to
prove the design margins above operating voltage
levels
(2) An impulse test to validate the transformer design
and construction to withstand surge voltages due to
atmospheric disturbances
(3) Switching surge test to validate the transformer
design and construction to withstand system transients and switching. [5]
Karsai [6] explains the correlation between dielectric
factory testing levels and the transformer in service suitability. Therefore verification of the transformers insulation
system through factory dielectric tests provides indication
that the transformer is suitable for trouble free service over
its expected life under the conditions that are prevalent in
electrical systems.
Major insulation is located between windings or windings and ground. Major insulation is made from highdensity pressboard. The ability to utilize formed parts
from transformer board [4] that are dimensionally stable
at elevated temperatures provides added flexibility to the
transformer designer. Solid insulation that is dimensionally
stable allows the maintenance of gaps and consequently the
electric stress across the oil ducts. The designer uses rigid
barriers and contoured insulation to appropriately subdivide
space within the transformer in such a way to appropriately
distribute the electric stress in all oil ducts. The location
and number of barriers will have a great influence on the
stress in oil ducts. Therefore the proper placement of insulation is very important. The designer of a remanufactured
transformer can optimize the insulation system beyond the
original design. Using rigid barriers and countered insulation the designer divides the oils spaces between windings
and on the end of the windings to increase the dielectric
strength of the transformer. The designer can then create
a design with greater dielectric margins or for a given dielectric margin the insulation level of the transformer can
be increased. [7]
Short Circuit Design
The redesign of transformers must minimize axial and
radial forces that a transformer will experience during fault
conditions. If the short circuit forces during a fault cannot
be eliminated then steps must be undertaken to mitigate
the resulting mechanical stresses to the windings and the
clamping structure of the transformer. This can be accomplished by the specific windings and winding arrangements
selected to provide optimum electrical and magnetic balance
considering all tap positions and operating conditions. If the
forces can not be mitigated, then material can be selected
with the proper mechanical properties such as (high-density pressboard material, high proof stress copper, epoxy
coated Continuously Transposed Cable (CTC), high yield
strength steel lockplates. etc.) to enhance the transformer
short circuit ability to withstand a self-limiting through
faults on its terminals.
The modern practice is to calculate the resulting maximum short circuit forces for all tap connections and all
applicable system fault conditions with Finite Element
Analysis software (FEA). The calculated maximum forces
on winding segments and the claming structure are calculated and compared to allowable design limits on every
redesign.
The clamping structure with the use of high-density
pressboard in the windings provides a high strength and
securely clamped assembly that will resist short circuit forces.
The clamping is accomplished by the end-frames and lockplates. The end-frames hold the core yokes together and
provide a stable base for the windings. The lock-plates tie
the top and bottom end-frames to one another providing
the rigid backbone of the clamping system. [7]
Thermal Design
There are three components of the thermal design that
must be evaluated on every redesign. First, the oil rises are
exacted from the teardown data and the original Certified
Test Report (CTR) provided by the original equipment
manufacturer. Secondly, the winding rises are calculated
from the winding design and using FEA software to calculate additional winding losses. Lastly, the metallic hot
spot rises (non-winding) are calculated using the FEA
software.
60
In the majority of redesign the cooling equipment, radiator and air blast equipment, is refurbished or replaced in kind
with new. The air delivery of the air blast equipment and the
amount of surface area on the radiators is not increased unless deficiencies are discovered during the initial evaluation
or an increase in the transformer capacity is required.
The exception is FOA coolers. FOA coolers will require
an increase in the air delivery or an increase in oil flow to
compensate for the affects of aging. The years of operating
in exposed environments will damage the heat exchangers
and even proper remanufacturing and refurbishment will
not restore the coolers to the original capacity. Typically,
an estimate is made on the effective reduction in cooling
due to ageing and this is compensated by an increase in air
delivery or oil flow rate. [7]
The oil rises that are derived from the Certified Test
Report (CTR) are the top oil rise and the average oil rise.
The top oil rise is required to determine the transformers
hot spot rise and consequently its loading capability. The
average oil rise is used to calculate the transformer average
winding rise as compared to the guaranteed values.
The last step in determining the average winding rise
is to determine the average winding gradient. The average
winding gradient is the difference in temperature between
the average winding rise and the average oil rise. The average winding gradient is calculated from the total winding
losses and the surface area available to dissipate the generated losses.
The total losses in a winding are comprised of the I2R
and the additional losses. The additional losses in a winding include eddy and circulating losses. These losses much
like the short circuit forces are impacted by the conductor
size and location in the leakage field generated within the
transformer due to load current. The eddy loss is a function
of the conductor dimensions, conductor location within
the leakage field, conductor material properties and the
frequency of the load current.
In windings with multiple conductors in parallel per turn
it is important to transpose the conductors. Transposition
is the act of making each conductor within a turn occupy
the same location within the leakage field. This movement
of conductors equalizes the induced voltage among the
parallel strands consequently, reducing circulating losses.
[7] A well-designed and built winding will have very little
or no circulation loss.
The clamping system is a major contributor to the stray
loss in a transformer. Structural members of the clamping
system are exposed to high leakage fields. The losses in
the clamp due to leakage flux must be controlled and not
increased in the redesign. The main components of the
clamping system that are subjected to high leakage fields
are the lockplates and endframes. The magnetic flux density impinging on these parts must be calculated and the
temperature gradient calculated. FEA software is used to
determine the axial and radial flux density in these members and the temperature rise is calculated based upon the
FEA results. The ultimate temperature for these parts is
to be limited to acceptable levels to mitigate heating and
Transformer Handbook — Volume 1
combustible gas generation. These temperature calculations
become more significant if the winding design has been
altered from the original construction or an increase in
capacity was made.
Summary
In conclusion, the design process was briefly discussed for
a remanufactured transformer. In the redesign process the
first step is to gather teardown data and recreate the original as-is design; then proceed to design the transformer’s
core and coils with the following major areas of concern:
insulation design, short circuit design and thermal performance. The design engineer must use his transformer design
knowledge and experience, as well as modern design tools
like FEA to analyze each one of the different major areas
in the design process.
References:
1. Woodcock, David J., Wright Jeffrey C., “Power Transformer Design Enhancements Made to Increase Operational Life, page 2 (2000)
2. Ganser, R., et. al., “Remanufacturing Failed Transformers: An Alternative to Replacement” , Electricity Today,
pp. 21 & 23 (1992)
3. Templeton, James et. al., “Re-manufacturing transformers, Power Industry Development 2001, p. 37 (2001)
4. Moser, H. P., “Transformerboard”, Scientia Electrica,(1979)
5. Feinberg, R., et. Al., “Modern Power Transformer Practice”, Halsted Press, (1979)
6. Karsai, K., Kerenyi, D. and Kiss, L., “Large Power Transformer”, Elsevier, N.Y., pp. 187-195(1987)
7. Corsi, D. E., Thierry, Juan Luis, “Design Consideration
for Remanufacturing Transformers”, Conference of
Doble Clients Paper, page 3, (2002)
Domenicao Corsi is an engineering manager with thirteen years of
experience in the power transformer industry. Before joining S.D. Myers,
he was at Ohio Transformer and previously worked for ABB Power T &
D Co. in Muncie, Indiana. Corsi received his Bachelors of Engineering
in Electrical Engineering from Gannon University and his Masters of
Science in Electrical Power Engineering from Rensselaer. He is currently
chairman for the Transformers Committee Task Force for the Revision
of C57.17 “Arc Furnace Transformers,” and an active participant in the
IEEE Transformer committee representing Ohio Transformer.
NETA Accredited Companies
The following is a listing of all NETA Accredited Companies as of August 2011.
Please visit the NETA website at www.netaworld.org for the most current list.
A&F Electrical Testing., Inc...................................................................................Kevin Chilton
Advanced Testing Systems ............................................................................Patrick MacCarthy
American Electrical Testing Co., Inc. ......................................................................Scott Blizard
Apparatus Testing and Engineering ....................................................................... James Lawler
Applied Engineering Concepts .................................................................... Michel Castonguay
Burlington Electrical Testing Company, Inc. ........................................................... Walter Cleary
C.E. Testing, Inc. ........................................................................................... Mark Chapman
CE Power Solutions of Wisconsin, LLC............................................................. James VanHandel
DYMAX Holdings, Inc. ....................................................................................... Gene Philipp
Eastern High Voltage ....................................................................................... Joseph Wilson
ELECT, P.C. .................................................................................................Barry W. Tyndall
Electric Power Systems, Inc. .................................................................................. Steve Reed
Electrical and Electronic Controls ..................................................................... Michael Hughes
Electrical Energy Experts, Inc............................................................................... William Styer
Electrical Equipment Upgrading, Inc. .......................................................................Kevin Miller
Electrical Maintenance & Testing, Inc........................................................................ Brian Borst
Electrical Reliability Services ..................................................................................Lee Bigham
Electrical Testing, Inc. ................................................................................. Steve C. Dodd Sr.
Elemco Services, Inc. ...................................................................................... Robert J. White
Hampton Tedder Technical Services ....................................................................... Matt Tedder
Harford Electrical Testing Co., Inc. ................................................................... Vincent Biondino
High Energy Electrical Testing, Inc..................................................................... James P. Ratshin
High Voltage Maintenance Corp. ........................................................................... Eric Nation
HMT, Inc. .........................................................................................................John Pertgen
Industrial Electric Testing, Inc. ........................................................................ Gary Benzenberg
Industrial Electronics Group ................................................................................. Butch E. Teal
Industrial Tests, Inc. .............................................................................................. Greg Poole
Infra-Red Building and Power Service ............................................................ Thomas McDonald
M&L Power Systems, Inc. .................................................................................. Darshan Arora
Magna Electric Corporation ................................................................................... Kerry Heid
Magna IV Engineering – Edmonton ...................................................................Jereme Wentzell
Magna IV Engineering (BC), Ltd. ........................................................................ Cameron Hite
Setting the Standard
MET Electrical Testing, LLC .......................................................................... William McKenzie
National Field Services...................................................................................... Eric Beckman
Nationwide Electrical Testing, Inc. ...............................................................Shashikant B. Bagle
North Central Electric, Inc. ...............................................................................Robert Messina
Northern Electrical Testing, Inc. .......................................................................... Lyle Detterman
Orbis Engineering Field Service, Ltd. ....................................................................... Lorne Gara
Pacific Power Testing, Inc. ...................................................................................Steve Emmert
Phasor Engineering ........................................................................................... Rafael Castro
Potomac Testing, Inc. ........................................................................................... Ken Bassett
Power & Generation Testing, Inc.......................................................................... Mose Ramieh
Power Engineering Services, Inc. ..................................................................... Miles R. Engelke
POWER PLUS Engineering, Inc. ...................................................................Salvatore Mancuso
Power Products & Solutions, Inc. ........................................................................ Ralph Patterson
Power Services, LLC ........................................................................................ Gerald Bydash
Power Solutions Group, Ltd ...........................................................................Barry Willoughby
Power Systems Testing Co. ............................................................................... David Huffman
Power Test, Inc. ..............................................................................................Richard Walker
POWER Testing and Energization, Inc. ............................................................... Chris Zavadlov
Powertech Services, Inc. ................................................................................... Jean A. Brown
Precision Testing Group .................................................................................... Glenn Stuckey
PRIT Service, Inc. ........................................................................................ Roderic Hageman
Reuter & Hanney, Inc....................................................................................... Michael Reuter
REV Engineering, LTD ................................................................................ Roland Davidson IV
Scott Testing, Inc................................................................................................Russ Sorbello
Shermco Industries ............................................................................................... Ron Widup
Sigma Six Solutions, Inc. ....................................................................................... John White
Southern New England Electrical Testing, LLC ................................................. David Asplund, Sr.
Southwest Energy Systems, LLC .......................................................................Robert Sheppard
Taurus Power & Controls, Inc. ............................................................................... Rob Bulfinch
Three-C Electrical Co., Inc.................................................................................James Cialdea
Tidal Power Services, LLC ....................................................................................Monty Janak
Tony Demaria Electric, Inc. ............................................................................ Anthony Demaria
Trace Electrical Services & Testing, LLC ...................................................................Joseph Vasta
Utilities Instrumentation Service, Inc. ........................................................................Gary Walls
Utility Service Corporation.................................................................................. Alan Peterson
Western Electrical Services ......................................................................................Dan Hook
Setting the Standard
About NETA
NETA (InterNational Electrical Testing Association) is an association of leading electrical testing companies;
visionaries, committed to advancing the industry’s standards for power system installation and maintenance
to ensure the highest level of reliability and safety.
NETA is an accredited standards developer for the American National Standards Institute (ANSI) and defines
the standards by which electrical equipment is deemed safe and reliable.
NETA is also the leading source of specifications, procedures, testing, and requirements, not only for
commissioning new equipment but for testing the reliability and performance of existing equipment.
QUALIFICATIONS OF THE TESTING ORGANIZATION
An independent overview is the only method of determining the long-term usage of electrical apparatus and
its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as
the objectivity and competency of the testing firm is as important as the competency of the individual technician.
NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to
setting world standards in electrical maintenance and acceptance testing.
Hiring a NETA Accredited Company assures the customer that:
• The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and
calibrate all types of electrical equipment in all types of industries.
• NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA
Standard for Certification of Electrical Testing Technicians, (ANSI/NETA ETT).
• A registered Professional Engineer will review all engineering reports.
• All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable
to the National Institute of Science and Technology (NIST).
• The firm is a well-established, full-service electrical testing business.
CERTIFICATION
NETA Certified Technicians conduct the tests that ensure that electrical power equipment meets the ANSI/NETA
standards’ stringent specifications.
Certification of competency is particularly important in the electrical testing industry. Inherent in the
determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be
capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They
must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration,
or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides
recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA
Standard for Certification of Electrical Testing Technicians, (ANSI/NETA ETT).
Setting the Standard