NETA Handbook Series I%2c Transformers Vol 1-PDF (2)

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Transformer Handbook Volume 1

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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.

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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 components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation, or warranty as to any opinion, product, or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser, or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct, or indirect damages. NETA further disclaims any and all warranties, express or implied including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date. 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.

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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.

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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.

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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.

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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

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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.

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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

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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.

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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.

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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.

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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 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 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 ( 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.

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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