Power transformers

POWER PLANT ELECTRICAL REFERENCE SERIES

VOLUME 2

Power nansformers Authors A. W Goldman and C. G. Pebler

Written by Stone & Webster Engineering Corporation 245 Summer Street Boston. Massachusetts 02107

Electric Power Research Institute 3412 Hillview Avenue Palo Alto. California 94 304

EPRI Project Manager D. K. Sharma

Ordering Information

Requests for copies of this series should be directed to Research Reports Center (RRC), P.O. Box 50490, Palo Alto, CA 94303, (415) 965-4081.

For further information on EPRI's technical programs contact the EPRI Thchnical Information Division at (415) 855-2411, or write directly to EPRI's Thchnical Information Center at P.O. Box 10412, Palo Alto, CA 94303.

EL-5036, Volume 2 Project 2334

ISBN 0-8033-5001-5 volume ISBN 0-8033-5015-5 series

Topics: Power transformers 'Ii"ansformer ratings Taps and connections Station auxiliary systems Installation and maintenance Voltage regulation

Copyright© 1987 Electric Power Research Institute, Inc. All rights reserved.

Reprinted in 1998 by Energy Conversion Division, Steam-Turbine, Generator, Balance-of-Plant Target.

Electric Power Research Institute and EPRI are registered service marks of Electric Power Research Institute, Inc.

Notice

This series was prepared by Stone &. Webster Engineering Corporation as an account of work sponsored by the Electric Power Research Institute, Inc. (EPRI). Neither EPRI, members of EPRI, Stone &, Webster Engineering Corporation, nor any person acting on behalf of any of them: (a) makes any warranty, express or implied, with respect to the use of any information, apparatus, method, or process disclosed in this series or that such use may not infringe privately owned rights, or (b) assumes any liabilities with respect to the use of, or for damages resulting from the use of, any information, apparatus, method, or process disclosed in this series.

FOREWORD

In the past, several electrical equipment manufacturers published reference books dealing with specific technical areas. Many utilities have stated that these reference books have been very useful to them in dealing with plant emergencies and in making decisions on design, system planning, and preventive maintenance.

Unfortunately, manufacturers today seldom publish or update reference books on electric power apparatus, mainly because of tighter budget constraints. Until now, utilities have had no upto-date industrywide practical reference manual covering the various electric power apparatus and electrical phenomena commonly encountered in power plants. The Power Plant Electrical Reference Series was planned to fill this need.

EPRI believes that the series will save utilities time and money. It will aid plant engineers in

• Prevention of forced outages through proper installation, application, and protection of station auxiliary equipment

• Recognition of potential problems and their prevention

• Selection of appropriate methods of maintenance to ensure trouble-free equipment operation

• Reduction of equipment installation time and expense

• Proper specification of equipment being ordered

• Better coordination and integration of system components

This volume deals with power transformers. A power transformer connects the generator to the high-voltage transmission system. Another power transformer connects the generator to the plant medium-voltage auxiliary power system. 'Iransformer impedance is the major factor in the voltage regulation of the auxiliary power system, as well as in the short-circuit duty of the switchgear. Selection of transformers for use in power stations requires knowledge of the power system and various parameters.

A wealth of information about transformers is available in the transactions of the IEEE and in the

ANSI/IEEE standards and applications guides. EPRI has also published a great deal of information on transformers, including studies of transformer life characteristics (EL-2622), dielectrics, accessories, and monitoring equipment. The purpose of this book is to bring out the concepts that are most useful to power plant personnel, without requiring an understanding of the rigorous engineering analysis necessary for the basic design transformers.

D. K. Sharma

Electrical Systems Division Electric Power Research Institute

ABSTRACT

The unit transformer in a generating station connects the electric power output of the generating unit to the high-voltage electric transmission gridi the unit auxiliaries transformer, station service transformer, and secondary-unit substation transformers supply the electric auxiliaries required for operation of the power plant. In the lower range of sizes, power transformers may be of standard design types, but many of the transformers used in power plants and all of the larger ones are custom-designed-similar, but seldom identical, to others built previously. This volume covers the practical aspects of the selection, specification, installation, operation, testing, and maintenance of these power transformers.

lransformer designs of particular interest to power plant operators include liquid-immersed, dry-type, and vapor-cooled transformers ranging in size from 500 kVA to 1200 MVA. The function and application of each design are described in detail, from load considerations to noise criteria. Photographs show the various types of oilpreservation systems, transformer connections, and bushings. A variety of gages, monitors, and indicators may be provided for liquid-immersed transformersi these accessories are also discussed.

ACKNOWLEDGMENTS

The authors wish to acknowledge the help they received from many technical publications prepared by people in the industry. They also express their appreciation to the following people for their reviews, suggestions, and guidance in general.

Electric Power Research Institute

D. K. Sharma, Project Manager R. Steiner, Associate Director, Electrical Systems

Division J C. White, Program Manager G. Addis, Project Manager

Stone & Webster Engineering Corporation

G. 0. Buffington, Project Manager P. Garfinkel A. R. Fitzpatrick A. P. Stakutis

EPRI Review Committee

J. R. Boyle, Thnnessee Valley Authority L. E. Brothers, Southern Company Services J. Erlingsson, Pacific Gas and Electric Company R. G. Farmer, Arizona Public Service Company R. G. Hodgson, Los Angeles Department of Water

&. Power J. A. Maxwell, Georgia Power Company W. L. Nail, Jr., Mississippi Power&. Light Company D. G. Owen, Duke Power Company B. K. Patel, Southern Company Services R. A. Schaefer, Public Service Company of

Oklahoma J. E. Stoner, Jr., Duke Power Company D. M. Van Thssell, Jr., Florida Power&. Light

Company J. E. White, Thmpa Electric Company

The authors owe special thanks to W. J. McNutt, General Electric Company, member of the Transformers Committee of IEEE, who reviewed the final manuscript.

CONTENTS

SECTION PAGE

_ Figures ...................... 2-xi

Tables ............. · .......... 2-xiii

Executive Summary .......... 2-xv

Acronyms & Abbreviations ............... 2-xvii

2.1 Introduction ................ . 2-1

2.2 Definition of Terms .......... 2-1

2.3 General "~)pes ............... 2-3

Liquid-immersed 'Iransformers .... 2-3 Dry-type 'Iransformers .......... 2-3

2.4 Rating Basis and Temperature Rise ............ 2-4

2.5 Insulation Level. ............. 2-5

2.6 Cooling Methods-Single-, Dual-, and 'D:iple-rated 'D:ansformers . ................ 2·5

Liquid-immersed 'Iransformers .... 2-5 Water-cooled 'Iransformers ....... 2·7 Dry-type 'Iransformers .......... 2·7

2.7 Losses ........................ 2-7

Evaluation method .............. 2-7 Application of Loss Values ....... 2·8

2.8 Oil Preservation Systems . .... 2-8

Sealed.:nmk System .............. 2-8 Inert Gas System ............... 2-9 Modified Conservator System ..... 2-9

2.9 'D:ansformer Connections ... . 2-10

U'IS ........................... 2-11 UA'IS .......................... 2·12 SS'IS .......................... 2-12

SECTION PAGE

Secondary Unit Substation 'Iransformers ................ 2-14

Grounding 'Iransformers ........ 2-14

2.10 Taps ........................ 2-14

No-Load Thp Changers ......... 2-14 Load Thp Changers (LTCs) ....... 2-14

2.11 Bushings ................... 2-15

2.12 Accessories ................. 2-18

Liquid Level Gage ............. 2-18 Thmperature Indicators ......... 2-18 Flow Indicator ................ 2-20 Bushing Current 'Iransformers .. 2-20 Resistance Thmperature

Detectors ................... 2-20 Sudden Pressure Relay ......... 2-20 Gas Detector Relay ............ 2-21 Fault Gas Monitor ............. 2--21 Pressure Relief Device .......... 2--21 Lifting Eyes and Jack Bosses .... 2-·22-Lightning Arresters ............ 2-22-

2.13 Application Considerations ............. 2--22-

Maximum Sustained Load ....... 2--2-2-Altitude ...................... 2-25 Ambient Thmperature .......... 2--25 Number of Windings ........... 2-2-5 Voltage Ratings and

Overexcitation ............... 2--25 'Iransient Overvoltage .......... 2·26 Load Current Waveform ........ 2-26 Harmonic Current Derating ..... 2-27 Impedance Voltage and

Regulation .................. 2-28 Impedance and Through-Faults .. 2-29 Phasing Out Three-Phase

Circuits .................... 2-29 Loss Evaluation ............... 2-30 Noise Criteria ................. 2-30

2.14 Shipping Considerations ... . 2-32

2-x CONTENTS

SECTION PAGE

2.15 Specific Applications ....... 2·32

UTh ......................... 2·32 UA'IS ........................ 2·45 SS'IS ......................... 2·46 Load Center Substation

'Transformers ................ 2·4 7 Auxiliary 'Transformers ......... 2·4 7 Grounding 'Transformers ........ 2-4 7

2.16 Transformer Testing ........ 2-48

Shop Thsting .................. 2-48 Field Thsting .................. 2-49

2.17 Foundations ............... . 2·51

2.18 Provision for Oil Spills ..... . 2·51

2.19 Fire walls and Barriers ..... 2·51

2.20 Water-Spray Fire Protection .................. 2-51

2.21 Installation ................. 2·52

Liquid-immersed 'Transformers .. 2·52 Dry-type 'Transformers ......... 2-5~

2.22 Maintenance ............... 2·53

Visual Inspection .............. 2·53 Oil Conditioning ............... 2·54 Gasing ....................... 2-54 Dryout ....................... 2-54 Cleaning Bushings ............. 2·54

Appendix A: Loss Evaluation .. 2·55

References ............ ...... 2·59

Bibliography ............... 2·61

Index ...................... . 2·65

FIGURES

FIGURE PAGE

2-1 - Transformer With a Sealed-Tank Oil Preservation System ......... 2·9

2-2 Transformer With Inert Gas Oil Preservation System ............. 2·10

2-3 Transformer With Modified Conservator Oil Preservation System .. 2-11

2-4 Transformer Terminal Designation in Accordance With ANSI Standard C57.12.70-1978 ................. 2·12

2-5 Typical Transformer Phase Relationships ... , ............... 2-13

2-6 Power Transformer With LTC .... 2~16

2-7 Apparatus Bushing of the Paper-Oil Capacitor (POC) Type ........ 2·17

. 2-8 EVH Bushing ................... 2·18

2-9 High-Current Type-A Bushing 25-kV, Class-4500 A and Above ... 2·19

2-10 Temperature Indicator Relay ..... 2·20

2-11 Sudden Pressure (Fault Pressure) Relay ......................... 2·21

2-12 Gas Detector Relay ....... : ...... 2·21

2-13 Fault Gas Monitor .............. 2-22

2-14 Pressure Relief Device ........... 2-23

2-15 General Guide for Permissible Short-Time Overexcitation of Power Transformers (Rated Volts per Hertz = 100% Excitation) .... 2·26

2-16 Bar Chart, Factory Noise Measuremerits of Large General Electric Power Transformers (Early 1970s) .. 2·31

FIGURE PAGE

2-17 Reactive Capability Curves for Steam Turbine Generator Unit .... 2·34

2-18 Base Case ...................... 2-35

2-19 Voltage and Power Profiles ....... 2-36

2-20 Increased Real Power ........... 2·37

2-21 Higher Secondary Tap ........... 2-38

2-22 100-MVAR Export at Design Center ........................ 2·39

2-23 Oversize Transformer ........... 2-40

2-24 High Impedance ................ 2-41

2-25 Half-Power Operation ........... 2·42

2-26 Simplified Equivalent Circuit and Phasor Diagram ................ 2-44

TABLES

TABLE PAGE

2·1 .Forced-cooled Ratings ............. 2·6

Z·Z Approximate Voltage Regulation .... 2-29

2·3 Transformer Thsts ................ 2·49

A-1 Transformer Loss Energy Evaluation ...................... 2-58

EXECUTIVE SUMMARY

Power transformers are used in generating stations to connect the main generator to the highvoltage transmission system and to connect sources of electric power to distribution subsystems for operation of plant auxiliary electrical equipment at medium- and low-voltage levels. The proper selection of transformers for each application requires a knowledge of the types available and their range of applicability. It also requires a knowledge of terms, conventions, tolerances, and factory tests as established in industry standards.

Background

Power plant electrical equipment operating at ac voltages of 120, 460, 575, 4000, 6600, or 13,200 V receives its power from higher-voltage sources: the main generator and the switchyard. 'fransformers, which are located near the load (where possible), interconnect the voltage levels. Although the smaller sizes of power transformers may be of standard design types, the larger ones are customdesigned and similar, but seldom identical, to others. This book provides practical guidance in the selection of this equipment.

Objectives

This volume will provide power station engineers with a background of transformer knowledge that will enable them to apply transformers correctly, assist in understanding existing standards and the various options required for power transformer selection, and provide guidance to power plant personnel in planning inspection and testing programs.

Approach

A national survey of utility requirements yielded pertinent information, and a search of available literature on power transformers identified specific information pertaining to power plant applications. The EPRI Review Committee, with members from 11 utilities throughout the United States, and other industry experts reviewed the material for accuracy and completeness. The resulting information was the basis for this volume of the Power Plant Electrical Reference Series.

Results

The information in this volume will help in the selection of power transformers in sizes from 500 kVA to 1200 MVA for power plant use. Specific application information will aid the engineering and operations departments of generating facilities in selecting new and replacement equipment.

ACRONYMS

&

ABBREVIATIONS

AA transformer cooling method: ventilated ac alternating current ANSI · American National Standards Institute

BIL basic lightning impulse insulation level Btu British thermal unit(s)

CI present worth of outlay in the year of first commercial operation (Eq. A-1)

em centimeter(s)

dB decibe!(s) dBA adjusted decibel(s) de direct current

E voltage (Eq. 2-1) EHV extra-high voltage

f annual inflation rate (decimal) (Eq. A-1) FA transformer cooling method: oil immersed,

forced-air cooled FOA transformer cooling method: oil immersed,

forced-oil cooled with forced-air cooler FOB free on board FOW transformer cooling method: forced-water

cooled

g gram(s)

hp h HV HVAC Hz

I IEEE

IROR

k

kV kVA kW

LTC LV

m mg MVA MVAR

N N1

horsepower hour(s) high voltage heating, ventilating, and air conditioning hertz

current (Eq. 2-1) Institute of Electrical and Electronics Engineers internal rate of return

internal rate of return expressed as a decimal rather than as a percentage (Eq. A-1) kilovolt(s) kilovoltampere(s) kilowatt(s)

load tap changer low voltage

meter(s) milligram(s) megavolt-ampere(s) megavolt-ampere(s)-reactive

newton(s) number of years between the price year and the year of tiTSt commercial operation (Eq. A-1)

N2 1 greater than the number of years between commercial operation and payment (Eq. A-1)

OA transformer cooling method: oil immersed, self-cooled

OSHA Occupational Safety and Health Administration

P quoted or estimated price, valid in the price year (Eq. A-1)

PCB polychlorinated biphenyl PF load power factor (Eq. 2-8) POC paper-oil capacitor psig pounds per square inch gage

R resistance REG transformer regulation RIV radio influence voltage rms root-mean-square

SCR short-circuit ratio SST station service transformer

UAT unit auxiliaries transformer UT unit transformer

V volt(s)

Z transformer impedance voltage

VOLUME 2

POWER TRANSFORMERS A. W. Goldman and C. G. Pebler

2.1 INTRODUCTION

Power-transformers are used in power plants to connect the main generator to the high-voltage (HV) transmission system and to connect sources of auxiliary power to distribution subsystems for plant auxiliary electrical equipment at lower voltage levels. Since they are basically static devices, they require less maintenance than most of the other apparatus. It is important, however, (1) that each transformer be selected properly for the intended application; (2) that it be protected from voltage surges, external short circuits, and prolonged overload; and (3) that it be inspected, maintained, and tested on a routine basis.

The power transformers of particular interest to the designers and operators of power plants range in size from 500 kVA to 1200 MVA in threephase designs and from 500 kVA to 550 MVA in single-phase designs. 'fransformers installed inside a building may be dry-type, resin encapsulated, or liquid immersed in high-fire point or low-heat release insulating fluids. 'fransformers installed outdoors are generally mineral oil immersed.

In the lower size range the transformers may be of repetitive design, but many of the transformers used in power plants and all of the larger ones are custom designed-similar, but seldom identical, to others built previously.

'fransformer power and energy losses, though relatively small, are of interest to the user for two reasons: They cause increased fuel consumption, and they result in heat release. The fuel consumed in generating the loss of energy is an important item in operating cost. The heat must be removed and dissipated by some combination of conduction, convection, and radiation. "Self-cooled" transformers do not require any power-driven cooling auxiliaries. Forced-cooled transformers employ forced-water or forced-air cooling and may also use pumps to circulate the insulating fluid. The addition of rotating machinery to an otherwise static device reduces the physical size and initial cost of the transformer for a specific output rating, but it may also reduce reliability and increase maintenance cost and losses.

Oil-immersed transformers require oil preservation systems to exclude oxygen and water vapor;

this retards sludging and deterioration of dielectric properties. Gas formation under oil may indicate local hot spots or decomposition of solid insulating materials. For this reason gas monitors are often installed to detect and collect generated gases for laboratory analysis. 'fransformer oil should be sampled and tested at regular intervals. The analysis of both the collected gas and the oil samples provides warning of abnormal conditions.

Power transformers are factory tested to ensure quality of design and manufacture and to demonstrate their ability to meet performance requirements. Data obtained during such tests may also provide benchmarks for later field tests.

A large transformer may be damaged by improper handling during loading, shipment, on-site storage, testing, or installation. These operations warrant meticulous attention.

The application of the above material to unit transformers (U'Th), unit auxiliaries transformers (UA'Th), station service transformers (SS'Th), and secondary unit substation transformers is covered under appropriate headings in this volume.

2.2 DEFINITION OF TERMS

Basic lightning impulse insulation level (BIL) A specific insulation level, expressed in kilovolts, of the crest value of a standard lightning impulse.

Basic switching impulse insulation level A specific insulation level, expressed in kilovolts, of the crest value of a standard switching impulse.

Chopped-wave impulse A voltage impulse that is terminated intentionally by sparkover of a gap.

Decibel (dB) See Sound pressure level.

Demand factor The ratio of the maximum demand of a system to the total connected load of the system.

Diversity factor The ratio of the sum of the individual maximum demands of the various subdivisions of a system to the maximum demand of the whole system.

Eddy-current loss Power dissipated due to eddy currents. This includes the eddy-current losses of the core, windings, case, and associated hardware.

Front-of-wave lightning impulse test A voltage impulse with a specified rate of rise that is terminated intentionally by sparkover of a gap that occurs on the

2-2 POWER PLANT ELECTRICAL REFERENCE SERIES

rising front of the voltage wave with a specified time to sparkover and a minimum crest voltage. Complete front-of-wave tests involve application of the following sequence of impulse waves: (1) one reduced full wave; (2) two front of waves; (3) two chopped waves; (4) one full wave.

Graded insulation The selective arrangement of the insulation components of a composite insulation system to equalize more nearly the voltage stresses throughou! the insulation system.

Harmonic factor The ratio of the root-mean-square (rms) value of all the harmonics to the rms value of the fundamental.

harmonic factor (for voltage)

+ E~

(Eq. 2-1)

harmonic factor = -../r-I~,.-+-1;"--+-P"7 _+ ___ +_!...,..~

(for current) I 1

Hot spot temperature The highest temperature inside the transformer winding. It is greater than the average temperature (measured using the resistance change method) of the coil conductors.

Hysteresis loss The energy loss in magnetic material that results from an alternating magnetic field as the elementary magnets within the material seek to align themselves with the reversing magnetic field.

Impedance voltage The voltage required to circulate rated current through one of two specified windings of a transformer when the other winding is shortcircuited, with the windings connected as for rated voltage operation. It is usually expressed in per unit, or percent, of the rated voltage of the winding in which the voltage is measured.

Insulation level An insulated strength expressed in terms of a withstand voltage.

Insulation power factor The ratio of the power dissipated in the insulation, in watts, to the product of effective voltage and current, in voltamperes, when tested under a sinusoidal voltage and prescribed conditions.

Lightning impulse insulation level An insulation level, expressed in kilovolts, of the crest value of a lightning impulse withstand voltage.

Liquid-immersed transformer A transformer in which the core and coils are immersed in an insulating liquid.

Load tap changer (LTC) A selector switch device, which may include current-interrupting contactors, used to change transformer taps with the transformer energized and carrying full load.

No-load tap changer A selector switch device used to change transformer taps with the transformer deenergized.

Oil-immersed transformer A transformer in which the core and coils are immersed in an insulating oil.

Overload Output of current, power, or torque by a device in excess of the rated output of the device on a specified rating basis.

Overvoltage A voltage above the normal rated voltage or the maximum operating voltage of a device or circuit.

Primary winding The winding on the energy input side.

Partial discharge An electric discharge that only partially bridges the insulation between conductors and that may or may not occur adjacent to a conductor. Partial discharges occur when the local electric field intensity exceeds the dielectric strength of the dielectric involved, resulting in local ionization and breakdown. Depending on intensity, partial discharges are often accompanied by emission of light, heat, sound, and radio influence voltage (with a wide frequency range).

Radio influence voltage A radio frequency voltage generally produced by partial discharge and measured at the equipment terminals for the purpose of determining the electromagnetic interference effect of the discharges.

Secondary unit substation A unit substation in which the low-voltage (LV) section is rated 1000 V or below.

Secondary winding The winding on the energy output side.

Sound level A weighted sound pressure level obtained by the use of metering characteristics and the weightings A, B, or C specified in American National Standards Institute (ANSI) Standard S1.4.

Sound pressure level The sound pressure level, in decibels, is 20 times the logarithm to the base 10 of the ratio of the pressure of the sound to the reference pressure of 2 times w-s N/m2 (0.00002 microbar), also written 20 N/m2 .

Station service transformer (SST) A transformer that supplies power from a station high-voltage (HV) bus to the station auxiliaries. It also supplies power to the unit auxiliaries during unit startup and shutdown and/or when the VAT is not available.

Surge arrester, lightning arrester A protective device for limiting surge voltages on equipment by discharging or passing surge current; it prevents continued flow of follow current to ground and is capable of repeating these functions as specified.

Switching impulse Ideally, an aperiodic transient voltage that rises rapidly to a maximum value and falls, usually less rapidly, to zero.

Switching surge A transient wave at overvoltage in an electrical circuit caused by a switching operation.

Thp changer See No-load tap changer.

Temperature rise The difference between the temperature of the part under consideration (commonly the "average winding rise'' or the "hottest spot winding rise'') and the ambient temperature.

'Iransient overvoltage The peak voltage during the transient conditions resulting from the operation of a switching device.

Unit auxiliaries transformer (UAT) A transformer intended primarily to supply all or a portion of the unit auxiliaries.

Unit transformer (UT) A power system supply transformer that transforms all or a portion of the unit power from the unit to the power system.

Withstand voltage The voltage that electrical equipment is capable of withstanding without failure or disruptive discharge when tested under specified conditions.

2.3 GENERAL TYPES

The industry recognizes two general types of power transformers: liquid-immersed transformers and dry-type transformers.

LIQUID-IMMERSED TRANSFORMERS

A liquid-immersed transformer consists of a magnetic core-and-coils assembly, either single-phase or polyphase, immersed in fluid having good heat transfer and insulating properties. The liquidimmersed transformer permits compact design, and at this time transformers with ratings above 10,000 kVA or 34.5 kV are always liquid immersed. Initially, the fluid was always a highly refined mineral oil. Since such oils are flammable, liquidimmersed transformers located within buildings were installed in fireproof vaults. Later, nonflammable fluids were developed for this application, the most common being an askarel, polychlorinated biphenyl (PCB). These fluids have high specific inductive capacitance (also called relative dielectric constant or relative capacity) and good heat transfer properties but are more expensive and have lower dielectric strength than mineral oil. The Toxic Substances Control Act of 1976 (1)

and the Code of Federal Regulations (2) now prohibit the manufacture of PCBs and limit the use of PCB-bearing equipment. The federal regulation specifies rigid rules and requirements for marking PCB-bearing equipment in service and for disposing of PCB-bearing equipment and contaminated materials resulting _from liquid spills (3).

POWER TRANSFORMERS 2-3

More recently other fluids having high fire points and low rates of heat release, though more expensive than askarels, have been introduced to replace it (for example, silicone, tetrachloroethylene, trichlorotrifluoroethane, and highly refined paraffinic oil).

Another recent development, the vapor-cooled transformer, is classified as liquid immersed and is suitable for indoor installation. This design employs a low-boiling point organic fluid for heat transfer. The latent heat of vaporization absorbs the heat produced by transformer losses. That latent heat is then released in a heat exchanger external to the transformer tank, which condenses the vapor and returns it to the transformer tank in liquid form. Vapor-cooled transformers may be equipped with cooling fans to increase kilovoltampere rating up to 50%.

The application of high-fire point, low-heat release liquid-insulated transformers versus mineral oil-insulated transformers involves economic and fire hazard considerations. The former are somewhat less hazardous, but they are more expensive than the latter, with silicone liquid-filled being the most expensive.

Provisions for containing oil spills, should the tank rupture, are covered in this volume in Section 2.18.

DRY-TYPE TRANSFORMERS

Dry-type transformers are generally more expensive than oil-immersed transformers and depend on solid insulation-film coatings, paper tape, or a combination of the two-for most of their dielectric strength. Single-phase and polyphase drytype transformers are available in ventilated designs, totally enclosed nonventilated designs, sealed-tank designs, and gas-filled designs, the ventilated type being least expensive. Their ability to withstand lightning and switching surge impulse voltages is less than that of liquidimmersed designs. It may therefore be prudent to protect their HV terminals with surge arresters, even when the external leads to these terminals are not directly exposed to lightning.

Ventilated dry-type transformers are suitable for most applications inside buildings. In atmospheres heavily loaded with dust or fibers, however, they must be cleaned at regular intervals to keep their ventilation passages clear. This type may be equipped with fans to increase their kilovoltampere rating by 33%%. They have the lowest initial cost of any in the family of dry-type transformers.


Totally enclosed, nonventilated dry-type transformers are suitable for use in moderately contaminated industrial environments. Because they are nonventilated, they are designed to have low heat losses-that is, very high efficiencies.

Sealed-tank transformers have the ability to function in the severest environments. They have their own sealed atmosphere and can function in misty, oil-laden, dusty, highly contaminated areas. Tnese transformers also have high efficiencies because of the necessity of having low heat losses.

Dry-type transformers are currently available in self-cooled ratings up to 10,000 kVA and at voltages up to 34.5 kV.

A variant of the dry-type transformer that is resin encapsulated has been introduced recently. In one form of this design, "cast-coil;' the coil is placed in a mold and the resin coating is cast around it. These transformers are available in sizes up to 5,000 kVA and voltages up to 34.5 kV. In another form the coils are dipped in resin. The resinencapsulated design may be used in harsh environments where ventilated dry-types may not be suitable. Although their initial cost is higher than other dry-types, they may nevertheless be economical in high-load factor applications because of their lower load losses (Volume 7, Au;te.iliary Electrical Equipment).

Some of the resins used in earlier resinencapsulated transformers gave off vapors at high temperatures that were found to be flammable, toxic, or both. In more recent designs these concerns have been resolved by tests and analysis of the vapors showing them not to be harmful (4).

The application of a ventilated dry-type versus a nonventilated dry-type or a sealed, gas-filled drytype transformer involves economic and environmental considerations (clean, dust-laden, wet, or highly contaminated atmosphere). The gas-filled transformer has the highest initial cost.

The application of a ventilated dry-type versus a ventilated, encapsulated dry-type transformer also involves these considerations.

Volume 7, Section 7.5 gives a comparison of the relative equipment costs of the various dry-type transformers.

2.4 RATING BASIS AND TEMPERATURE RISE

Power transformers are output rated. They are rated to deliver specified kilovoltamperes continuously

at a specified secondary voltage and frequency under "usual" operating conditions and with a standard temperature rise. When operated within their ratings they have "normal" life expectancies. They may be operated beyond their ratings under certain conditions without loss of life expectancy or under other conditions with a somewhat predictable sacrifice of life expectancy. 1tansformers in power plants generally are selected to operate within their ratings except for brief transient periods, such as during motor starting or during the time required for relay operations to clear through-faults.

Usual and unusual operating conditions for liquid-immersed transformers are defmed in ANSI Standard C57.12.00-1980 (5); those for dry-type transformers are defined in ANSI Standard C57.12.01-1979 (6). Some unusual operating conditions are:

• Ambient temperature above 40°C or with 24-h average above 30°C

• Altitude above 3300 ft • Sustained operation at more than 110% (no

load) or 105% (loaded) of rated secondary volts or volts per hertz

• Load current waveform distortion (harmonic factor greater than 0.05)

• Primary phase voltage unbalance • Secondary phase current unbalance • Damaging fumes or vapors, excessive or

abrasive dust, salt spray, or excessive moisture

• Abnormal vibration, shocks, or tilting • Restricted air circulation

These or other unusual operating conditions, if ap· plicable, should be stated in purchase specifications.

Although transformers are kilovoltampere rated, their true continuous load limits are determined by secondary winding current ratings. Note that the secondary may be either the HV or the LV winding. If the secondary winding has taps, then the permissible continuous load is determined by the current rating of the tap in use, ev~n though it is called a "full-kVA" tap.

The kilovoltampere rating does limit permissible load at secondary voltages above tap voltage rating, but at voltages below tap voltage rating the tap current rating intervenes. At 95% secondary voltage the maximum continuous kilovoltampere load is 95% of nameplate kilovoltamperes.

Standard temperature rise is the average winding rise (by resistance) that, in "usual" ambient

temperature and with suitable allowance for hottest spot difference, is within the long-time withstand capability of the insulating materials. For liquid-immersed transformers, that rise is 65°C (15°C hot spot allowance). Liquid-immersed transformers are now rated for 65°C rise. Many transformers having 55/65°C-rise ratings, however, are still in service. Both designs are suitable for continuous operation at their 65°C-rise ratings. The difference between them is that the performance characteristics, full-load losses, and impedance voltage drop for the 55/65°C-rise transformer are based on 55°C-rise loading. Where a transformer must operate in a higher-than-usual ambient temperature, it is customary to specify a reduced temperature rise. The result is a larger transformer that under "usual operating conditions;' carries more load. For example, if the temperature rise of a liquid-immersed transformer is specified as 55°C, the permissible load increase under 30°C conditions that permit a 65°C rise will be 12%.

The average temperature winding rise for drytype transformers, depending on the insulation system, may be 80°C, l15°C, or 150°C (all with 30°C hot spot allowance) (6).

2.5 INSULATION LEVEL

'Iransformers must be insulated to withstand the voltages to which their windings and terminals may be subjected in service. These include the normal ranges of power-frequency voltages published in ANSI Standard C84.1-1982, the impulse overvoltages that may be produced by lightning strikes on their terminals or on connected transmission lines, and the transient overvoltages that may be produced by operation of transmission line circuit breakers. Mineral oil-immersed transformers can withstand very high crest voltages if the duration of the transient is measured in microseconds.

The basic lightning impulse insulation level (BIL) of a transformer is the crest value of the voltage it can withstand if the impulse voltage has the wave shape defined as "full wave" in ANSI Standards C57.12.00 and C57.12.90. That shape, intended to be representative of a lightning impulse, has a rise time of 1.2 J.LS and a decay time, or tail, of 50 J.LS. Crest values for other wave shapes are keyed to the BIL. For example, for 900-kV BIL the associated crest values for front of wave, chopped wave, switching surge, and low frequency are


1240, 1035, 745, and 395 kV, respectively. The wave shapes of these other transients are also defined in the standards. The front-of-wave shape is intended to be representative of a lightning impulse chopped before crest by a rod gap. The chopped-wave shape is intended to be representative of a lightning impulse chopped at crest or immediately thereafter. The switching surge waveform is intended to be representative of the transient that may be produced by operation of a transmission line circuit breaker. The lowfrequency wave shape is sinusoidal at power frequency (or a low multiple of power frequency) to avoid core saturation during a factory test.

The transformer transient voltage strength required in a particular application depends on the lightning arresters that can be installed at the transformer terminals to protect it. If the arrester has too low a voltage rating, it may be destroyed by follow current at power frequency following a voltage surge. Minimum safe arrester voltage ratings must be determined by a transient network analysis of the transmission system. The transformer transient voltage strength should then exceed the voltage rating of the arrester by an appropriate margin-usually in the range of 15 to25%.

'fransformer price is affected by BIL. One manufacturer has published base price multipliers, showing that for 345-kV service the base price would apply without multiplier for a BIL of 1050 kV. The multiplier would be less than 1 for 900-kV BIL and greater than 1 for 1175-kV BIL. This information is not based on industry standards, but it does indicate the industry pricing practice.

BILs for dry-type transformers are given in ANSI Standard C57.12.01-1979 (6), and the wave shapes are defined in ANSI Standard C57.12.91-1979 (7).

2.6 COOLING METHODS-SINGLE-, DUAL-, AND TRIPLE-RATED TRANSFORMERS


Liquid-immersed transformers larger than 500 kVA may have both a self-cooled rating and one or two additional forced-cooled ratings. The rating increase produced by forced cooling varies with transformer size, as shown in 'Th.ble 2-1 (8). At 20,000 kVA and above transformers may have a single forcedcooled rating and no self-cooled rating.


Table 2.1 Forced-cooled Ratings

P-ercent of Self-cooled Self-cooled kVA kVA Wrth Auxiliary

Type of Single Three Cooling Cooling Phase Phase First Stage Second Stage

OA!FA 501-2499 501-2499 115 2500-9999 2500-11 ,999 125

10,000 and up 12,000 and up 133%

AA/FA 1000 and up 133%

OA/FA/FA - OA/FA!FOA 10,000 and up 12,000 and up 133% 166'%

SOURCE: This material is reproduced by permission of the National Electrical Manufacturers Association from NEMA Standards Publication No. NEMA TR 1-1980, Transformers, Regulators, and Reactors. © 1980 by NEMA.

The standard method of indicating these multiple ratings is to list the rating(s), followed by the corresponding cooling method(s). For example:

• 2000/2300 kVA, OAIFA indicates a transformer with a self-cooled (OA) rating of 2000 kVA and a forced-air-cooled (FA) rating of 2300 kVA.

• 12,000/16,000/20,000 kVA indicates a transformer with a self-cooled rating and two stages of forced cooling. Such transformers have large radiators to produce thermosiphon circulation of the oil in the self-cooled mode. They have two banks of fans and oil pumps. These transformers are indicated as follows: o OAIFAIFA indicates that both the first stage

and the second stage of forced cooling use forced air. The first stage uses half of the available fans (one bank); the second stage uses all available fans (both banks).

o OAIFAJFOA indicates that the first stage of forced cooling uses forced air and the second stage uses forced oil and forced air.

o OA!FOAJFOA indicates that both the first stage and the second stage of forced cooling use forced oil and forced air. The first stage uses half of the available fans and oil pumps (one bank); the second stage uses all available fans and pumps (both banks).

• 25,000 kVA, FOA indicates a transformer with no self-cooled rating. It has compact coolers in place of radiators and cannot remain energized, even at no load, without its fans and pumps in operation. Nevertheless, most UTh and many UATh are of the FOA

type. This type is used less frequently for SS'IS, which remain energized continuously but are heavily loaded infrequently. In this type of service the triple-rated transformer is advantageous, because its mechanical cooling auxiliaries are required only during the periods of heavy load.

A UAT serving a maximum load of 20 MVA could be either 12/16/20 MVA, OAIFX!FX, or 20 MVA, FOA. The triple-rated transformer can carry 12 MVA with no mechanical cooling auxiliaries in operation. In this application that capability may not be an advantage, since half of the 20-MVA load may be present when the machine is synchronized and the auxiliaries load is transferred to this transformer; the 12-MVA self-cooled limit thus is exceeded before the turbine generator reaches half load. Although the triple-rated and FOA alternatives may have identical core-and-coil assemblies, the FOA transformer is less expensive and requires less space in an area where space is usually limited. On the other hand, if a generator breaker is installed between the generator and the transformers, the triple-rated UAT can operate without mechanical cooling auxiliaries during unit shutdown. Volume 7, Auxiliary Electrical Equipment, covers the application of generator breakers, and Volume 8, Station Protection, covers transformer and generator protection.

Large UTh are nearly always of FOA (or POWsee below) design. Again, this is primarily because of space considerations. In addition it may be more difficult to design a low-impedance transformer of the triple-rated type, because the oil channels through the windings must be large enough to permit gravity circulation of oil before the oil

pumps are brought into operation. Larger oil channels tend to increase leakage reactance.

WATER-COOLED TRANSFORMERS

Forced-water-cooled (FOW) transformers are often used instead of FOA types at hydroelectric plants because of the ready availability of cooling water. They are also often used at underground hydro or pumped storage plants, where the transformers must be underground to be near the equipment they serve. Large power transformers have also been enclosed in masonry vaults for noise control purposes. In such cases water cooling may be the only feasible method of heat dissipation. Because of concern for water leakage into the oil, however, such transformers have specially designed heat exchangers with double tube sheets and concentric tubes to provide two metal barriers between the two fluids. In this design the neutral space between the metal barriers can be monitored and an alarm actuated if either barrier begins to leak.


All dry-type power transformers have self-cooled ratings. Those commonly used indoors in power plants are ventilated (rated AA). Some are equipped with fans to give them a dual rating (AA!FA). A common size for LV secondary unit substation transformers is 1000/1333 kVA, AAIFA. Note that the forced-cooled rating is one-third larger than the self-cooled rating.

2.7 LOSSES

'Iransformers are very efficient. Large liquidimmersed transformers may have efficiencies higher than 99%. Nevertheless, it may be worthwhile to pay an initial price premium for loss reduction, which will result in still higher efficiency.

'Iransformer losses can be divided into three general categories: no-load losses, load losses, and, for forced-cooled transformers, cooling-system losses. The no-load losses are mainly core hysteresis and eddy-current losses, which are incurred as long as the transformer is energized. They remain essentially constant. The load losses are due to the heating of winding conductors by the passage of current and by other stray losses in conductors and tank walls, which are load related. These losses increase as the square of load current. The cooling


system losses are power used to drive the mechanical cooling auxiliaries-fans and oil pumpswhere these auxiliaries are present.

In medium and large power transformers the load losses are much greater than the no-load losses. The ratio of load losses to no-load losses will be influenced by the loss evaluation figures in the purchaser's bidding documents. 1b simplify a generalization of available data, one can compare values on the basis of core-and-coils rating. On this basis a 20-MVA FOA transformer, a 12/16-MVA OAIFA transformer, and a 12/16/2Q-MVA OAIFOAIFOA transformer are directly comparable.

At 12 MVA such a transformer would have a ratio of load losses to no-load losses on the order of 3.5:1. At 16 MVA this ratio would be greater by a factor of 1. 777; and at 20 MVA (if permissible) the factor would be 2.779.

Very large pbwer transformers, nearly always FOA, have loss ratios on the order of 7:1. Lower ratios might be economical in many cases, but such ratios may not be achievable within shipping limitations.

EVALUATION METHOD

Loss evaluation is the process of estimating the amount of initial outlay justified to avoid future costs. Specifically, it answers the questions: "What price premium are we justified in paying to reduce transformer no-load loss by 1 kW? What premium for 1 kW of load loss?" When the initial cost premium (a single payment amount) is compared with the future costs avoided thereby (a nonuniform series of annual amounts), it is convenient to use life-cycle cost methods, which convert all cash flows to present worth. It is, for example, not justifiable to spend $100 today to avoid a $100 expense ten years from today; a far smaller amount invested in some other aspect of the company's business would grow to $100 in ten years. It is the smaller amount that is the present value of the future cost.

Loss evaluation seeks to determine how much the purchaser would be justified in paying for the transformers to reduce no-load loss by 1 kW and how much per kilowatt for a similar reduction in load loss. Since the premium would be a single payment on delivery and the savings that justify it are a nonuniform series of future costs, their equivalence must be found by present-worth methods. These methods, which involve the capital structure of the company, the estimated loading schedule for the transformer, and the present


and anticipated future cost of the fuel used for generation, are discussed in Appendix A.

APPLICATION OF LOSS VAWES

With no guidance about how losses are to be evaluated, each transformer bidder will offer the design that meets its temperature rise guarantee at minimum initial cost. For large power transformers that are expected to operate at high load factors, this is not the most economical choice. A better design would have more iron, more copper, and less cooling equipment. Although this design would increase initial cost, it would reduce losses.

As was pointed out previously, transformer losses are partially avoidable. Estimating loss values and including them in the invitations for competitive bids effectively make the supplier and the purchaser partners in determining what fraction of the losses is economically avoidable. In the case of smaller transformers the cost per kilovoltampere is so large that any significant fraction added to it in order to reduce losses would outweigh the future savings attributable to the loss reduction. ·

For certain large transformers, notably SSTh, the load factor is so low that load losses have small economic value. But SSTh are energized for essentially the entire year, and their no-load losses are incurred at full strength all of that time. For these transformers the no-load losses have significant economic value. Therefore, a design in which core flux density is reduced below conventional levels may well justify its higher cost, because a small reduction in flux density produces a large reduction in hysteresis loss and a larger reduction in core eddy-current loss. This reduction in flux density also significantly reduces magnetostriction noise. In the case of these medium power transformers the large-volume market is in substation transformers of fairly uniform design. Not all suppliers are in a position to tailor their basic designs closely to the special needs of every purchaser. For that reason each manufacturer will make its own decision on the design to be offered and the prices.

For transformers installed indoors losses have a significant indirect cost due to the fact that the heat released by the transformer must be removed by the ventilating system and may represent an appreciable portion of the load on that system. For this reason some purchasers prefer 80°C-rise drytype transformers to the less expensive, but less efficient, 115°C- and 150°C-rise designs.

2.8 OIL PRESERVATION SYSTEMS

Mineral oils used in power transformers degrade in prolonged exposure to oxygen or moisture. Water suspended in the oil reduces its dielectric strength and that of cellulosic insulation to which the water may migrate. Oxidation may affect dielectric properties and may cause sludge formation. Sludge, in turn, clogs small oil passages through the windings and impairs heat removal, allowing hot spots to develop. Solid insulation may be degraded rapidly in the hot spots, and such degradation reduces insulation life expectancy. Oil preservation systems have been developed to prevent such degradation (8).

Mineral oil has a relatively large thermal coefficient of expansion, and therefore the oil level in a transformer tank rises and falls with ambient temperature and with load. If the oil level becomes too low, the bottom portions of HV bushings and the current transformers that are often fitted around them are left without the oil immersion on which they may depend for voltage gradient control and for cooling. The oil level cannot rise

· above the top of the tank unless external provisions are made for expansion.

The oil preservation system must allow for the oil expansion and contraction and must prevent moisture and oxygen from being drawn into the tank. Three general types of oil preservation systems are in common use: the sealed-tank system, the inert gas system, and the modified conservator system.

One manufacturer provides, as standard, the oil preservation system for the following various voltages and ratings:

Three-phase,

Operating Voltage Class (kV)

650C MVA Rating Up to 138 161 to 230 Above 230

Up to 67.2 OA sealed-tank inert gas modified or 112 FOA conservator

Above 67.2 OA modified modified modified or 112 FOA conservator conservator conservator

SEALED-TANK SYSTEM

In the sealed-tank system the interior of the tank is sealed from the atmosphere. The gas-plus-oil volume remains constant over the temperature

range. The transformer tank and lead entrance bushings are tightly sealed. Contamination of the oil proceeds very slowly because of the careful drying and vacuum filling done before the tank is sealed.

This system has one limitation: With time the pressure tends to become negative whenever oil temperature falls below the temperature at which the tank was filled. When this happens moisture and a1r will be drawn into the transformer if a leak does occur.

Maintenance of this system is minimal. The pressure-vacuum gage can be obtained with alarm contacts to alarm when overpressure or excessive negative pressure occurs.

Figure 2-1 shows a transformer with a sealedtank system.

INERT GAS SYSTEM

In the inert gas system a blanket of dry nitrogen is maintained over the oil in the transformer tank at a pressure slightly higher than atmospheric pressure. Thus, any leakage is outward and does not contaminate the oil.

During cooling periods nitrogen is fed from metal bottles near the transformer through a regulating valve, which maintains a slight positive gage pressure at the top of the tank. During heating periods a discharge regulator releases surplus gas to prevent overpressure. There must be a sufficient "dead-band" between the settings of the two regulators to allow for drift and random variation of set points and to ensure that in-feed and discharge never occur at the same time. If that were to occur, the entire contents of the gas bottles could be lost.

The inert gas system requires regular maintenance: depleted gas bottles must be replaced, nitrogen use must be recorded, and the settings of the pressure regulators must be verified.

Another possible disadvantage of the inert gas system involves formation of bubbles in the oil. There is always a small but measurable quantity of gas-nitrogen or other gases-dissolved in the oil. During a coolin_g period and resultant depressurization some of the gas comes out of solution in the form of bubbles. Migration of gas bubbles into regions of high dielectric stress may cause ionization of the voids within the bubbles because the dielectric strength of the voids is lower than that of the sUITOtmding oil. A chain of ionized voids can produce dielectric failure. The seriousness of


Courtesy of McGraw-Edison Co., Pittsburgh, Pa.

Figure 2·1 Transformer With a Sealed-Tank Preservation System

this threat is controversial; many transformer users continue to have satisfactory experience with inert gas systems.

A transformer using the inert gas system is shown in Figure 2-2. The control cabinet and nitrogen gas piping are visible.

MODIFIED CONSERVATOR SYSTEM

Because of the perceived disadvantages of the inert gas system, a competing system has been developed in which the transformer tank is kept completely filled with oil from a conservator (tank)

above the level of the transformer tank cover. A portion of the volume of the conservator is occupied by air, which breathes in and out as the oil volume changes with temperature. The air is prevented from contact with the oil by an impervious diaphragm or air cell.

This system has its own drawbacks. The conservator must be configured and located with respect to the HV bushing terminals to maintain the required air-strike distance from terminals to grounded metal. Given the manholes, pressure

2·10 POWER PLANT ELECTRICAL REFERENCE SERIES

.~·

.. ·

.f I -----· .>

.... ...--·--··

Courtesy of Westinghouse Electric Corp., Pittsburgh, Pa.

Figure 2-2 Transformer With Inert Gas Oil PreseNation System

relief diaphragms, lightning arresters, and, in some cases, isolated-phase bus enclosures on and around the top of the transfonner, the proper configuration and location of the conservator may be difficult to achieve in some applications. In addition the diaphragm or air cell may not remain permanently impervious. The bottom of the air cell rests on the surface of the oil. The float of the liquid level gage, also riding at the oil surface, rests against the underside of the air cell. If the air cell develops a leak, it will gradually fill with oil and sink below the surface of the oil, carrying the float downward. The liquid level gage alann will operate indicating either a damaged cell or low oil level. Access openings are provided at both ends of the tank for tank cleaning or air cell inspection. This system has been widely accepted.

A transformer using the modified conservator system is shown in Figure 2-3.

2.9 TRANSFORMER CONNECTIONS

Any three-phase transfonner winding may be connected in delta, wye, or zigzag; it may even be connected in aT connection, which is sometimes used for grounding transformers. The relative phasing between primary and secondary may be zero or any multiple of 30 electrical degrees. Few of the many possible combinations are used in power plants. · A UT, also called a generator step-up or main

transformer, is a transfonner (or bank) used to connect the generator to the HV system.


Courtesy of General Electric Co .. Bridgeport, Conn.

Figure 2-3 Transformer With Modified ConseNator Oil PreseNation System

A VAT, also called a normal station service transformer, is one (usually fed from the main generator leads) that supplies power to the unit auxiliaries.

An SST, also called a reserve station service transformer or startup transformer, is one that supplies power from a station HV bus to the plant auxiliaries.

The phasing relationship between primary and secondary windings of a three-phase transformer is expressed in terms of terminal designations, for which the standard convention is as follows: If one is facing the LV side of the transformer, the HV terminals are Hl, H2, and H3 from left to right and the LV terminals are Xl, X2, and X3 from left to right, as shown in Figure 2-4. More extensive information may be obtained from Reference 9. 'Iransformer winding phase relationships are shown on the transformer nameplate.

The terms primary (winding) and secondary (winding) are necessary in discussing transformer ratings. A transformer is fully loaded when its secondary winding is carrying full-load current. The terms HV and LV are necessary in discussing phasing, because ANSI standard phasing requires the HV to lead the LV by 30 electrical degrees, regardless of whether the HV winding is the primary or the secondary.

'IJpical phasor diagrams of connections used for transformers in power plants are shown in Figure 2-5.

UTs

Most UTh, whether three-phase units or banks of three single-phase units, are connected in delta on the primary (LV) side and in grounded wye on the secondary side. In any wye-delta, delta-wye, or


X1 H1

a X3<J A X1 XZ X3 X2 H3 H2

X1 H1

A A a XO X1 X2 X3 X3 X2 H3 H2

X1 H1

X3<J H3<J Q X2 H2 X1 XZ X3

Figure 2-4 Transformer Terminal Designation in Accordance With ANSI Standard C57.12.7D-1978

wye-zigzag transformer, unless otherwise specified, the secondary voltages at terminals Hl, H2, and H3 lead the primary voltages at terminals Xl, X2, and X3, respectively, by 30 electrical degrees (Figure 2-5).

The grounded wye connection of the HV winding permits grading its insulation from specified BIT. at the terminals to a lower BIT. at the grounded neutral. The delta connection of the LV windings provides a low-impedance path for zero-sequence and third-harmonic currents, thereby facilitating selective relay tripping for single phase-to-ground faults on the HV system and improving secondary voltage waveform. The UT primary is usually impedance grounded at the generator neutral. For other types of transformer neutral grounding see Volume 8, Station Protection.

UATs

UA'IS are most frequently connected in delta on the primary side and in wye on the secondary side but with Hl, H2, and H3 voltages lagging Xl, X2, and X3 voltages by 30 electrical degrees. The wyeconnected LV windings permit some form of neutral grounding to facilitate selective relay tripping for single phase-to-ground faults on the mediumvoltage auxiliary power system. The lagging phase

angle may be the simplest method of placing UAT secondary voltages in phase with SST secondary voltages in typical cases (Figure 2-5b).

SSTs

SS'Th are usually connected in grounded wye on the HV side to permit the use of graded insulation. The LV windings may also be wye connected to provide for a three-phase, four-wire system or for neutral grounding. If the source of the SST is the same HV bus as the one receiving the generator output, the phasing shown in Figure 2-5c may be used. This connection results in a secondary voltage in phase with the output of a UAT phased as shown in Figure 2-5b.

A wye-wye transformer in this application does not necessarily require a delta tertiary to provide a low-impedance path for zero-sequence currents. A three-legged core design, most frequently offered in this size range, provides a virtual tertiary sufficiently well coupled to the other windings to present a low impedance as compared with the neutral grounding resistor usually applied on the secondary side.

If the HV source is different from the one to which the UT is connected, it may be necessary to use a delta-connected secondary for correct

POWER TRANSFORMERS 2·13

H1 X1

H1

H3<J xo

X2 H3 H2 H2

Primary Secondary Primary Secondary

a. Unit transformer b. Unit axiliaries transformer

H1 X1 H1 X1

xo

X3

H3 H2

H2


c. Station service transformer d. Station service transformer

X1

H1 X1

xo D D H2 H3 H2 X3 X2


e. Station service transformer Ill f. Secondary unit substation transformer I

X1

H1 X1

H3 H2

X2

Primary Secondary

g. Secondary unit substation transformer II h. T-connected grounding transformer

Figure 2-5 Typical Transformer Phase Relationships

phasing, in which case a separate grounding transformer is required to derive a neutral. Alternatively, a zigzag-connected secondary can provide the same phasing as a delta and would provide the neutral, but it may be the more expensive alternative

Figure 2-Sd). If the voltage of the other source is less than 230 kv; a delta-connected HV winding (which sacrifices the graded-insulation advantage) with a wye-connected secondary permits the same phasing at a lower cost than a wye-zigzag design.


SECONDARY UNIT SUBSTATION TRANSFORMERS

Secondary unit substation transformers are nearly always connected in delta on the primary side, the source voltage being low enough to remove any advantage in grading the insulation (that is, using a lower voltage insulation at the end of each winding). The secondary may be either delta or wye. The wye connection is required if the LV neutral is tQ be grounded, if a voltage regulator is to be connected into the phase windings at the neutral ends, o~ if a four-wire system for phase-to-neutral single-phase loads is required (Figures 2-5f and 2-5g). Relative phasing of LV networks in power stations is seldom important, because they are seldom interconnected.

GROUNDING TRANSFORMERS

A zigzag-connected autotransformer may be used on a three-wire system to derive a neutral for grounding. The T connection is sometimes preferred when there are no phase-to-neutral loads, because it permits the use of a two-legged core with a single winding on each core leg, resulting in a less expensive design. The neutral connection is made to a tap on the stem of the T (Figure 2-5h).

2.10 TAPS

A power transformer may have taps in either primary or secondary windings so that its effective turns ratio may be changed. In power plants such changes are not usually required to establish a new output voltage; instead they are needed to reestablish the desired output voltage after a departure due to a change in source voltage or in load-related impedance voltage drop. If tap changing must be done while the transformer is loaded, special switching equipment is required to transfer load current from one tap to another without an interruption of service. This is called tap changing under load.

NO-LOAD TAP CHANGERS

No-load tap changers employ manually operated switching equipment that changes the turns ratio of the three phases simultaneously and by the same amount. In the case of single-phase transformers, each has its own manually operated noload tap changing-switching device. The no-load

tap changing-switching device is in the tank with the core and coils in both three-phase and singlephase transformers. The no-load tap changer can be operated only when the transformer is deenergized. Conventionally, a transformer has two fullcapacity 2%% taps above and two below rated voltage. In a step-down transformer the taps above rated primary voltage are less likely to be used than those below it. For that reason some purchasers prefer to specify one tap above and three taps below rated voltage, an option available at no change in price. The taps may also be ordered closer together than 2%%, an option usually available without price premium. The taps can be omitted altogether with a saving in the price of the transformer. Both of these last two options are worth serious consideration in power plants.

The use of no-load taps in a UT (generator step-up transformer) is a special case, because the HV winding that nearly always contains the taps is the secondary. This case is discussed in greater detail in Section 2.13.

LOAD TAP CHANGERS (LTCs)

LTCs are often used in distribution substations but are seldom used in power plants (10). In the United States the conventional LTC has 32 taps at %% spacing, 16 above and 16 below rated voltage, to produce a voltage range of ± 10%. The transformer may have reduced capacity on taps below rated voltage. Where an LTC is used on a power plant transformer, its purpose is not to alter the voltage supplied to utilization equipment but to restore that voltage after a change in load or in the source voltage supplied to the transformer winding has occurred. The tap changer should be on the transformer primary whenever possible. If it is on the secondary, the rated kilovoltamperes may not be available under heavy load conditions.

As an illustration of this point consider a 12-MVA, 24- to 4.16-kV transformer connected to the leads of a 24-kV generator and fitted with a secondary LTC. The (full-kVA) tap voltage and current ratings will be as shown in the following abbreviated table:

Thp Volts Ame_eres

R16 4576 1514 R8 4368 1586 N 4160 1665 L8 3952 1753 L16 3744 1850

Assume, for simplicity, that generator voltage remains at 24 kV and that the set point of the contact-making voltmeter controlling the LTC is 4.16 kV.

At no load the tap changer would remain in the neutral position because secondary voltage would match set point. At full load the secondary voltage at the 4-kV bus might be reduced 5% by voltage drops in the transformer impedance and secondary leads impedance. The LTC would compensate by moving to Thp R8, which has a voltage rating of 4.368 kV and a current rating of 1586 A. The actual load current is 1665 A, a 5% overload. The situation becomes worse if the generator is operating at 95% voltage.

This problem does not arise if the taps are on the primary. The secondary voltage rating and the voltmeter set point would both be 4160 V. The LTC tap required to produce rated secondary current (assuming power factor 0.8 or higher) must be within the tap rating, because the transformer is output rated.

LTCs are usually equipped with automatic control equipment to maintain a manually preset secondary voltage. This equipment usually provides for remote control and indication of tap position. The control typically includes an auto/manual transfer switch, a raise/lower control switch, a set-point adjuster, a tap position indicator, and position limit-indicating lights. The equipment also provides maintenance adjustments for deadband, starting time delay, and time delay between tap changes. The dead-band and time delays reduce wear and tear from unnecessarily frequent operation during brief voltage transients. With usual adjustments the dead-band is on the order of 1 %; the starting time delay is about 30 s, and the time between tap changes is 1 to 1 Yz s.

Addition of an LTC to a power transformer increases its cost by approximately 40%. The addition of electromechanical switching equipment to an otherwise essentially static device increases maintenance cost. In addition the moving parts and the extra winding taps, which raise mechanical and electrical stress, may have a significant impact on reliability.

If an LTC is used on a power plant SST, the time delays may have special significance, as discussed in Section 2.15.

The LTC switching equipment is located in a separate oil-filled compartment connected to the transformer main tank.

Figure 2-6 shows a power transformer with an LTC. The latter is located in a separate compart-


ment, throat connected to the transformer tank, below the top of the tank.

2.11 BUSHINGS

Bushings are used on liquid-immersed transformers to carry the winding terminal connections through the grounded metal cover or sidewall of the tank. A porcelain rain shield over the external portion is skirted to provide a long surface creepage path from terminal to ground flange. The internal portion below the ground flange is generally immersed in the transformer insulating fluid. This portion may also be encased in porcelain.

HV bushings are of the condenser type, insulated with layers of oil-impregnated kraft paper. Copper or aluminum foil layers of graded axial length in the paper insulation structure distribute electrical stresses and control voltage gradients. The shell is filled with oil to keep the paper saturated, and the outer terminal is fitted with an oil level gage or sight glass. A cushion of dry nitrogen above the oil allows for thermal expansion and contraction of the oil. This cushion is sealed at a pressure above atmospheric pressure to exclude air and moisture. Bushings of this type must be shipped and stored in a nearly upright position to prevent dryout of any of the layers of paper.

In bushings rated 115 kV and higher one of the foil layers is made available as a bushing potential tap through an insulated conductor just above the ground flange. This tap must be impedance grounded through an external potential device or solidly grounded by a grounding cap whenever the bushing is energized. Condenser-type bushings (Figure 2-7) rated below 115 kV, down to and including 15 kV, have a power factor tap. The power factor tap connects to the ground layer of the capacitor core. An aluminum cap covers the insulated power factor tap assembly and grounds the tap connection when it is not in use.

Bushings are of two types, depending on their provision for connection to the transformer windings. In a fixed-conductor type the central tube or rod conducts current from the top terminal to the bottom terminal. The winding lead is connected to the bottom terminal. In a draw-lead type the winding lead is drawn upward through the central tube and connected to the top terminal. Figure 2-7 shows a bushing with a threaded copper tube that can be used with a fixed-conductor or


a draw-lead type connection. Figure 2-8 is an extrahigh voltage (EHV) bushing of the draw-lead type.

HV bushings are generally selected to have the same BIL as that of the transformer HV winding. For situations in which the atmosphere is highly contaminated with particulate matter or for highaltitude installations it may be desirable to use bushings having a longer porcelain rain shield. If this aim is achieved by using bushings with a higher BIL than that of the winding, the lower portion of the bushing will also be longer, requiring a taller tank, which may exceed shipping limitations. The alternative is an extra-creep design, in which the rain shield is taller but the portion inside the tank is not extended.

Lower-voltage high-current bushings, which are used on the primary terminals of UTh, are generally fixed-conductor, bulk type, again with porcelain rain shields and oil impregnated (Figure 2-9). Such bushings are not usually equipped with oil level

Courtesy of McGraw-Edison Co., Pittsburgh, Pa.

gages, but oil leakage has occasionally been a problem. There could also be a heat dissipation problem if bushings with a lower temperature rating are connected to isolated phase bus conductors operating at 105°C. 'll'ansformer specifications should state terminal conditions.

Secondary bushings on UATh and SSTh are of the porcelain type, at least 110 kV BIL, and are sometimes mounted in the sidewalls of the tank below transformer oil level. Faulty seals in such bushings have caused fires in a few cases when transformer oil leaked through a bushing seal into a cooler control cabinet.

Bushings are manufactured in accordance with the requirements of ANSI/IEEE Standard 24-1984 (11) and tested in accordance with requirements and test procedures of ANSI/IEEE Standard 21-1976 (12).

See Section 2.22 for bushing maintenance.

Figure 2-6 Power Transformer With LTC

* POC design

Clear/view oil reservoir

Nameplate

Mounting flange/ground sleeve assembly

Bottom coo

assembly*

Courtesy of Lapp Insulator Co .. LeRoy, N.Y.


Gaskets

High compression coil springs *

housing

Bushing potential tap

.,_ ___ Paper-foil capacitor core

+----Lower porcelain assembly *

Figure 2-7 Apparatus Bushing of the Paper-Oil Capacitor (POC) Type


Courtesy of Lapp Insulator Co., LeRoy, N.Y.

Figure 2-8 EHV Bushing

2.12 ACCESSORIES

The accessories described individually in the following subsections are available for large liquidimmersed transformers. Few of them are applicable to dry-type transformers.

LIQUID LEVEL GAGE

The typical liquid level indicator is a sealed instrument body. Inside, an indicating needle sweeping a calibrated scale is magnetically coupled to an external pivoted float arm, with the float at the top surface of the insulating fluid. The scale is marked to indicate high, low, and 25°C levels. The indicator includes alarm switches.

For a transformer with an inert gas oil preservation system, the indicator is mounted at the top of the transformer tank wall. For a transformer with a conservator or constant oil pressure system, the indicator is mounted on the conservator or oil reservoir.

TEMPERATURE INDICATORS

1\vo similar temperature indicators are available for liquid-immersed transformers. Basically, each is a bourdon tube gage connected by a capillary tube to a sensing bulb, which is enclosed in a well located in the hottest liquid near the top of the transformer tank. Each is equipped with electrical contacts for controlling forced-cooling equipment, for alarm, and for tripping.

One indicator (Figure 2-lOa) displays the top oil temperature. In the other indicator, called a winding temperature or hot spot temperature indicator (Figure 2-lOb), the well is heated electrically by current proportional to transformer load, supplied by a current transformer. The electric heating simulates the winding hot spot rise over top liquid temperature. In some cases the heater leads are extended to an external terminal box for shunting by a calibrating resistor. The initial value of the resistor is calculated, but it may change during the temperature rise test, if made. There have been instances in which no temperature rise test was made on a particular transformer and the hot spot indicator gave false indications of overheating in service until the calibrating resistor was replaced.

Oil filler cap

Porcelain-to-core washer gasket

P or celai n-t o- support flange gasket

Porcelain-to-bottom washer gasket

Bottom washer-to-springgasket

Spring assembly

Courtesy of General Electric Co., Bridgeport, Conn.

0


Silver-plated blades 1 ... 1----to accommodate

line conductor

One piece wet-process porcelain shell

Clamping ring

Hex-head steel screw and spring washer

Blade terminal I""'-----to accommodate

transformer connector

Figure 2-9 High-Current Type-A Bushing 25-kV. Class-4500 A and Above


a. Top oil

Indicating pointer

Capillary tubing

b. Hot-spot winding

1111 ; (! : .. i :' l

J

Switch-setting tabs

Indicating unit

Maximumreading pointer Credl

Reset-shaft cap and gasket

Temperature detector

Union connector

a. Courtesy of Westinghouse Electric Corp., Pittsburgh, Pa.; b. Courtesy of General Electric Co., Bridgeport, Conn.

Figure 2-10 Temperature Indicator Relay

FLOW INDICATOR

'Ii'ansformers employing forced-oil cooling may be equipped with a flow indicator, including alarm switches, for each pump. 'JYpically, the indicator is a vane-operated instrument mounted on the pump discharge pipe. The scale is not calibrated; it merely shows whether there is oil flow from the pump.

BUSHING CURRENT TRANSFORMERS

A bushing current transformer consists of a short sleeve of magnetic material with a distributed toroidal secondary winding. It is supported below the cover of the transformer tank at the bushing opening so that the bushing lead, passing through it, acts as a single-turn primary. Where required, two or three current transformers can be installed at each bushing. One of them is likely to be used for transformer differential relays. Good relaying practice prohibits putting any other burden on such current transformers (Volume 8, Station Protection). Another might be used for other relays, and a third might be used for metering.

Most bushing current transformers are provided with taps for multiratio ratings.

As with other current transformers, bushing current transformer secondary windings must be short-circuited when no burden is connected, because their open-circuit voltages may be high enough to be dangerous to personnel. They may also cause insulation failure.

RESISTANCE TEMPERATURE DETECTORS

Where remote indication, recording, or data logging of top oil or winding hot spot temperature is desired, the local temperature indicators can be supplemented or replaced by 10-0 copper resistance temperature detectors. In general it is not feasible to embed such detectors in the transformer windings. They should be located in the wells just below minimum oil level (13).

SUDDEN PRESSURE RELAY

A sudden pressure or fault pressure relay (Figure 2-11) responds by rapid closure of an electrical contact to sudden pressure rise in the liquid in which its sensing element is immersed. Designed for mounting on the transformer tank wall near the base or on a valve body, it senses the pressure transient produced by an internal arc.

Because some of the early sudden pressure relays were prone to operate erroneously under other conditions, many users wired them for alarm only. The modern relay has been made insensitive to mechanical shock and vibration, pump surges, and normal pressure variations caused by transformer temperature changes. User confidence has been restored; some users now regard it as a sensitive and reliable primary protective device and wire it for breaker tripping to isolate a faulted transformer.

Courtesy of General Electric Co .. Bridgeport. Conn.

Figure 2·11 Sudden Pressure (Fault Pressure) Relay

GAS DETECTOR RELAY

A gas detector relay (Figure 2-12) collects bubbles of gas generated below liquid level and closes an electrical contact when a significant gas volume has accumulated. Since most of the combustible gas is generated by the decomposition of oil or of solid insulating materials, relay operation may provide warning of incipient dielectric failure. Gas bubbles that do not indicate decomposition may form when there is a rapid change in temperature. Since the gas detector relay does not discriminate between combustible and noncombustible gas, it might operate in either case. Determining whether the gas evolution is a matter of concern requires that a sample be collected for mass spectrometric analysis in a laboratory.

FAULT GAS MONITOR

A combustible gas monitor that continually monitors the levels of dissolved hydrogen, carbon monoxide, acetylene, and ethylene gas in oil is available commercially. The device mounts on the transformer with the electrochemical sensor below the oil level. It is provided with dual-stage alarm circuitry for early incipient fault warning. The monitor is shown in Figure 2-13. Sixty of these units have been installed at a major American utility to protect current transformers that have a history of generating high quantities of hydrogen before


failure. These monitors have operated flawlessly to indicate sudden increases in hydrogen. As a result it was possible for the current transformers to be removed from the circuit before failure.

Information on combustible gas analysis and interpretation is given in Kelley's article "'Transformer Fault Diagnosis by Dissolved Gas Analysis" and in ANSI Standard C57.104-1978 (14).

PRESSURE RELIEF DEVICE

One or more pressure relief devices (Figure 2-14) may be installed in openings in the transformer cbver to relieve dangerous pressure that may build up within the tank. The device consists of a springloaded diaphragm, automatically reset, with a mechanical semaphore to indicate that it has operated, and alarm contacts. Because these devices are of a standard size, with limited relieving capacity, it may be advisable to install several on a very large transformer to prevent a rupture of the tank during a transformer fault.

Courtesy of General Electric Co .. Bridgeport. Conn.

Figure 2-12 Gas Detector Relay

2·22 POWER PLANT ELECTRICAL REFERENCE .SERIES

.-~::::··········---················-- ..... ·---~ . ...._

\ ~1

Courtesy of Syprotec Corp., Rouses Point. N.Y.

Figure 2-13 Fault Gas Monitor

LIFTING EYES AND JACK BOSSES

Lifting eyes and jack bosses facilitate the handling of the transformer during manufacture, loading for shipment, unloading at destination, and installation. In some cases jack bosses have been mounted so low on the assembly as to require toejacks, which are less commonly available t1:J.an conventional hydraulic jacks. Large transformers can be damaged seriously when conventional jacks are applied under protrusions not designed for this purpose.

'Iransformer outline drawings should be examined carefully for these features. In some cases the manufacturer may be able to revise the design to provide greater clearance under jack bosses if the problem is identified before tank fabrication.

LIGHTNING ARRESTERS

Lightning arresters are most effective in protecting transformer insulation from surge voltages if they are installed very close to the winding terminals. For this reason it is common practice to

purchase the arresters with the transformer and to require mounting brackets for them on the transformer tank. For selection of arrester ratings see Section 2.5.

2.13 APPLICATION CONSIDERATIONS

When a source of electric power at one voltage level is required to serve utilization equipment designed for another (usually lower) voltage level, a transformer is required between source and· load. Selection of the proper transformer requires consideration of the following elements:

• Maximum sustained load • Altitude • Ambient temperature • Number of windings • Voltage ratings • 'Iransient overvoltage • Load current waveform • Voltage regulation • Through-faults • Phasing • Loss evaluation • Noise criteria

MAXIMUM SUSTAINED LOAD

Maximum (permissible) sustained load is established in relation to resultant insulation temperature. This is because the electrical insulating materials in a transformer are degraded over time by chemical processes at a rate that is a function of absolute temperature. The relationship of time-to-end of life versus temperature is linear when plotted on appropriate scales. This line is called an Arrhenius curve. For a particular insulating compound or system the slope of the Arrhenius curve is determined at two or more elevated temperatures. The temperatures are selected to produce failure (end of life) in an acceptable time period, but the temperatures are not so high that they produce phase changes in the material. An end-of-life condition is usually defined in terms of mechanical properties of the insulation. When the insulation becomes too brittle to remain in place during the vibration, shock, and thermal expansion that are charactistic of a normal load cycle, a dielectric failure is imminent (13, 15).

When transformer windings are below the temperature for which they were designed (because of low ambient temperature or because of a prior

Semaphore (normal position)

Protective cover

\

Courtesy of Westinghouse Electric Corp., Pittsburgh, Pa.


Semaphore (tripped position)

Figure 2-14 Pressure Relief Device

period of light load operation), the transformer may be loaded beyond rating for a limited period without sacrifice of life expectancy. The permissible overload period is the length of time required to raise the winding hot spot to the temperature that would be produced by prolonged operation under rated conditions.

This tolerance for temporary overload permits a transformer to withstand the thermal effects of through-faults and large motor-starting transients, and it relieves concern about the effects of other short-time overloads.

'fransformers may be overloaded for longer periods with predictable effects on life expectancy. In-

dustry consensus on transformer overload effects is documented in ANSI Standard C57.92-1981 (16) for oil-immersed transformers and C57.96-1959 (17) for dry-type transformers.

'fransformers in power plants are usually selected to operate within their ratings and, in some cases, with margin for future load growth. Loads added to the auxiliary power system after initial construction may produce overload and other conditions requiring analysis. Of particular concern are added motor contributions to short-circuit current and unfavorable effects on system voltage profiles.

The maximum sustained load is based on the nameplate loads of all utilization equipment, present


and future, to be served by the transformer. However, it is less than the sum of the individual equipment ratings for several reasons. Motors are available in discrete sizes. If a pump, for example, requires 112 hp during normal operation, the driving motor is likely to have a rating of 125 hp. However, that motor will seldom, if ever, operate at 125 hp. In addition, many of the loads, such as motor-operated valves, are intermittent. The transformer may supply power to devices that will not operate at the same time. Certain items may be standby or spare, intended to operate only when a similar item, possibly fed from the same transformer, is unavailable for service. A single transformer may also serve mutually exclusive loads, such as an air conditioning compressor and one or more duct heaters; when one is in operation, the other is not required.

1Wo factors often used in other contexts are relevant to this discussion. They are diversity factor and demand factor. Diversity factor (greater than 1.0) is the ratio of the sum of the individual maximum demands of the items served to the maximum demand (usually integrated over a 15- to 30-min period) of the whole system. Demand factor (less than 1.0) is the ratio of the maximum demand of the whole system to the total connected load. Connected in this sense means "served;' whether operating or not.

Of these two the diversity factor concept is the more useful. Note that the aggregate demand is divided by the diversity factor to find coincident demand. However, diversity factors applicable to power plant auxiliary loads cannot be found in tables. Each subsystem constituting the entire load on a single transformer secondary winding must be analyzed separately. In nearly all cases the analysis must be based on printed data (for example, nameplate ratings, performance curves, manufacturers' literature), since the subsystem is not available for measurements.

Short-time overloads, such as those produced by motor starting, are common in transformer applications. The resultant voltage drops may require analysis, but these types of overloads, unless they repeat at brief intervals, can be ignored in selecting transformer kilovoltamperes. Motor-operated valves are usually omitted from the demand calculation for that reason. A motor-driven air compressor with automatic start/stop or automatic unloader control, on the other hand, should be included, especially if the driving motor is large in relation to the size of the transformer. Such loads usually are included at their average demand

during any load cycle of more than a 15-min duration. Standby and spare equipment can be ignored unless there is likelihood that main and standby will operate concurr~ntly for extended periods.

The demand of each small load should be estimated conservatively at nameplate value. However, larger motors justify more careful analysis to determine their probable maximum continuous demand and power factor.

Performance curves for a large fan, compressor, or pump are plotted on heat-versus-flow coordinates. A system resistance curve is plotted on the same coordinates. The interrelation of the performance curve with the system resistance curve is the "normal" operating point. Such curve sheets usually include a horsepower-versus-flow curve. The ordinate of that curve at the flow corresponding to the operating point is the expected "normal" motor output, regardless of motor nameplate horsepower.

A prudent margin for future load growth should be included. The size of that margin depends on the extent to which the subsystem has been defined at the time of transformer selection. Most power plant 480-V and 600-V subsystems include heating, ventilating, and air conditioning loads, which may not be well defined until late in the plant design. 'fransformers selected early in the design process should therefore have generous margins allowed for such loads. There should also be some margin for loads added after the date of commercial operation, because such additions are common.

When all of the individual demands have been defmed with reasonable accuracy and when diversity due to spare and standby equipment has been treated appropriately, there may be additional diversity because the motors and electric heaters may not all present their maximum calculated demand at the same time. That additional diversity is difficult to document and for that reason is often ignored.

The general experience is that one or more complete LV substations will be added late in the design process and that space will have to be found for it.

For medium-voltage (4.16, 6.9, and 13.8 kV) subsystems the major loads are usually defmed fairly accurately early in the design process. It is good practice, however, to base running horsepower estimates on the performance characteristics of the driven equipment rather than on motor nameplate horsepower. The largest uncertainty is

likely to be that associated with the LV unit substations fed from such medium-voltage subsystems, but the sum of such loads is generally a small fraction of the medium-voltage load.

ALTITUDE

Any liquid-immersed transformer installed more than 3300 ft (1000 m) above sea level must be derated oy the percentage given in Thble A2 in ANSI Standard C57.12.00-1980 (5) for each 330ft (100m) of altitude above 3300 ft.

Dry-type transformers installed at altitudes greater than 3300 ft (1000 m) must be derated because of the reduced dielectric strength and the reduced cooling ability of the ambient air. Thbles for both types of derating are published in ANSI Standard C57.12.01·1979 (6).

AMBIENT TEMPERATURE

The standard ambient temperature for power transformers is 30°C (24-h average) or 40°C (maximum 1-h average). If the ambient temperature is likely to exceed either of these limits, the transformer should be specified for a lower-thanstandard temperature rise. The kilovoltampere rating and temperature rise shown on the nameplate will then be proper for that application.

For example, if the 24-h average ambient temperature at the transformer location may be as high as 45°C, the transformer should be specified for a 50°C rise so that on those hot days the ambient plus the rise will be 95°C, the same total as would be obtained with a 30°C ambient ("usual" operating conditions) plus a 65°C rise. The factory test, which may be made in a 25°C ambient, would then show final average winding temperature, by resistance, of not more than 75°C, although the insulation system is designed for a 95°C average.

NUMBER OF WINDINGS

'Iransformers with more than two windings are sometimes useful in power plant applications.

A delta tertiary may be added to a wye-wye transformer to provide a low-impedance path for zero-sequence currents, though it is not required for this purpose in most cases.

AUT in a multiunit hydroelectric power plant may have two primary windings to permit two generators to be connected to the switchyard through the same HV or EHV line. Such applications require a separate generator breaker for each unit.


Three-winding transformers are often used as UATs and SSTs when the auxiliary power system is large enough to require two or more mediumvoltage subsystems. Serving both subsystems from a common primary winding reduces the cost of transformers and primary connections as well as the space required for transformers (Volume 3). A three-winding transformer, when correctly specified and designed, has performance characteristics very similar to those of two separate twowinding transformers. Although manufacturers indicate a wider impedance tolerance for threewinding than for two-winding designs, most of them accept orders with H-X and H¥ impedance voltage tolerances of 7%%. Thst reports show that manufacturers stay within this tolerance. It may be necessary, however, to allow 10% tolerance for the X-Y impedance voltage.

Since a three-winding transformer has a separate kilovoltampere rating for each secondary winding and an overall kilovoltampere rating, which is usually the sum of the two secondary ratings, and since each secondary may have a selfcooled and one or more forced-cooled ratings, it is very important that each impedance voltage, H-X, H-Y, and X-Y, be specified, in percent, on a clearly stated kilovoltampere base. Because some winding configurations may not be suitable for unbalanced loading, the specification should also require that each secondary be capable of carrying any load from zero to full rating regardless of the load on the other secondary.

'Iransformers have been built with four windings-three wye-connected windings and a load-carrying, delta-connected tertiary. Such designs are complex and are likely to be less reliable than simpler designs.

VOLTAGE RATINGS AND OVEREXCITATION

A transformer is overexcited when its secondary voltage exceeds 110% of nameplate value at no load, or 105% at full load, rated frequency, and power factor 0.8 or higher. When frequency is above or below rating the 110 and 105% limits apply to volts per hertz.

Excitation current of typical large power transformers at rated voltage and no load is on the order of 0.4% of full-load current. It increases sharply above 110% voltage and becomes a significant fraction of full-load current at voltages above 125%.

Hysteresis and eddy-current losses in the core also increase rapidly at voltages above 110%.


In the case of transformers directly connected to generators, a load rejection may produce transient overvoltages at or near a power frequency having magnitudes as great as 135% for a few seconds (longer if the voltage regulator is not in automatic operation). Under these conditions stray flux in magnetic paths outside the core may produce intense local heating, which can cause cumulative degradation of transformer insulation. It is for this reason that volts-per-hertz protection is often installed for transformers exposed to such transients.

Figure 2-15 is one major manufacturer's estimates of the overexcitation withstand capability of a large power transformer. 1b pick a single point on that curve for illustration, at 130% V!Hz, the transformer could withstand this amount of excitation for about 16 s at each exposure.

A high-impedance transformer may require more than 110% of nominal primary voltage to produce 105% of rated secondary voltage at full load, 0.8 power factor lag. That condition would not qualify as overexcitation under industry standards. Nevertheless, some transformer designers are not comfortable with that interpretation. Any application in which this condition can be recognized as a requirement should be brought to the attention of the transformer manufacturer. For similar reasons transformer specifications should not stop at identifying one winding as HV and another as LV. One of them must be designated as the secondary.

The UT for a pumped-storage hydroelectric power plant is a special case. Since the electric machine requires more power when pumping than it can deliver when generating, the transformer LV winding should be designated as the secondary.

TRANSIENT OVERVOLTAGE

UTh and UATs, all of which, in the absence of a generator breaker, are connected directly to a generator, may be subjected to transient overvoltage during a load rejection. On a unit trip generator excitation is removed at the instant of trip. Although generator air-gap flux does not decay instantly under these conditions, the transient overvoltage applied to the transformers is not usually a matter of concern.

Other forms of load rejection may not cause immediate removal of generator excitation and may produce significant transient overvoltage. A disturbance that separates the generator from a

140

135

iC 130

5125 ... ~ 120 0 X

LlJ 115

110

105

\ 1\ \

" l'o..

I'-r::.... r r--....

0.1 0.2 0.4 0.71 2 4 710 20 40 70 100

Time (min)

Figure 2-15 General Guide for Permissible Short-Time Overexcitation of Power Transformers (Rated Volts per Hertz = 100% Excitation)

major portion of the system load may not produce a unit trip. If the generator voltage regulator is operating in automatic mode at that time, it will act rapidly to correct the overvoltage. If the regulator is operating in manual mode, however, transient overvoltage may reach 135% of generator nameplate voltage, resulting in an even greater degree of overvoltage at the transformer secondary terminals. Each incident of that kind is likely to cause local heating in the transformer, which will reduce insulation life expectancy.

In the case of a manual trip the control circuits may not be designed to remove generator excitation automatically. If the voltage regulator is in automatic mode, the initial overvoltage condition will be corrected rapidly, but subsequent conditions could damage transformers connected to the generator leads. As the generator speed decays, the regulator will attempt to maintain set point voltage at decreasing frequency. The result will be excessive volts per hertz.

It is not economically feasible to design large transformers for prolonged overvoltage. However, the potential for its occurrence should be recognized in system design. If such potential is present, some form of volts-per-hertz protection is warranted.

LOAD CURRENT WAVEFORM

When the load current of a transformer has substantial waveform distortion, the distortion components will increase transformer losses and temperature rise.

ANSI Standard C57.12.00-1980 (5) states that, for "usual service conditions;' load current shall be approximately sinusoidal and the harmonic factor shall not exceed 0.05 per unit. Harmonic factor

is the ratio of the effective value of all the harmonics to the effective value of the fundamental. The effective value of all the harmonics is the square root of the sum of the squares of the effective values of the individual harmonics.

If the load to be served by a transformer includes large rectifiers or large solid-state variablespeed drives, an analysis should be made to determine whether the harmonic factor of load current under transformer full-load conditions is likely to exceed 0.05. If so, that "unusual" service condition should be explained in the transformer procurement specification.

HARMONIC CURRENT DERATING

Certain electrical loads, such as large rectifiers and variable-speed drives, may draw current that departs significantly from sinusoidal waveform and may include a large reactive power component. The departures from sinusoidal waveform can be described in terms of their Fourier series equivalents-harmonics of fundamental power frequency. The reactive power component lowers system power factor and increases voltage regulation. The harmonic currents, if allowed to circulate beyond the drive package, produce extra heating in the windings of transformers supplying power to such loads and may require that the transformer be derated in order to remain within rated temperature rise. As of September 1985 an ANSI document on this . subject, Standard C57.110/D7-1985 (18), was in preparation under the sponsorship of the IEEE 'Iransformers Committee. This document presents a recommended practice for establishing transformer capability when applying nonsinusoidal load current.

The extra heating is caused by two effects: the PR de loss produced by total harmonic current and the increased stray loss due to the higher frequency of these harmonic components.

For loads that are a small fraction of the total

Example

The transformer rating is 16 MVA. Full-load secondary current is 2221 A. Of the total load loss, 25.9% is stray losses. Stated another way, the total load loss is 1.35 times the J2R loss [1/(1.0 - 0.259) = 1.35].

For the drive package, total fundamental (power frequency) current is 1162 A and harmonics are as follows: eleventh-8%; thirteenth-6.5%; seventeenth-S%; nineteenth-4%; twenty-


load on a transformer secondary, transformer derating for harmonics will be negligible. In fossil fuel plants, however, variable-speed drives are sometimes used for boiler feedpumps and for forced-draft and induced-draft fans. These are the largest electric drives in the plant. Their harmonic currents and reactive power requirements cannot be safely ignored. A method of calculating derating is explained below.

The first step in calculating the harmonic (derating) factor for current is to obtain from the supplier of the variable-speed drive package the magnitude at full load of the fundamental and of all harmonics of current drawn from the system up to the twenty-fifth harmonic. The magnitude of each harmonic is usually expressed in percent of fundamental current. Frequently, the drive package filters out the lower harmonics, third through ninth, so that these components do not flow through the windings of the supply transformer.

The second step is to determine the root-meansquare (rms) value of the total load current, which is the square root of the sum of the squares of fundamental and all harmonics, as noted in Alternating-Current Circuits by Kerchner and Corcoran (19).

I = .../ I?j_ + I~ + I~ + . . . + I~ (Eq. 2-2)

The third step is to determine the transformer stray-load losses at full load (sinusoidal). Stray-load losses are the difference between load losses and PR de loss. Load losses, in turn, are the difference between full-load loss and no-load loss. Fullload current, full-load loss, no-load loss, and R de are all recorded in the factory test report.

The fourth step is to find the amount of sinusoidal load that can be added to the distorted waveform load without exceeding the load loss on which transformer temperature rise is based.

An example will illustrate how such a calculation would be made.

third-2.5%; twenty-fifth-2%. Note that there are no even harmonics and that the fifteenth and twenty-first (multiples of 3) are absent. The J2 equivalent for the harmonics is:

(1162)2 ((0.08)2 + (0.065)2 + (0.05)2

+ (0.04)2 + (0.025)2

+ (0.02)2] = 21,266 (Eq. 2-3)


That J2 equivalent will be used below in two calculations.

The rms total current for the drive, including fundamental and harmonics, is:

[(1162)2 + 21,266]~ "" 1171 A/phase (Eq. 2-4)

This total would be so read on a true rms ammeter.

'fransformer P.R loss varies as the square of rms current. 'fransformer stray losses vary as the square of rms current and as the square of frequency. The usual technique for calculating the heating effect of a current rich in harmonics is to calculate how much sinusoidal current can be added to the distorted waveform current without exceeding the load loss produced by rated (sinusoidal) secondary current. For this calculation it is necessary to know the proportion of stray losses with sinusoidal loading; the de resistance of the transformer cancels out of the quadratic equation.

The J2 equivalent of the stray losses is:

(1162)2 [(0.08 X 11)2 + (0.065 X 13)2 + (0.05 X 17)2

+ (0.04 X 19)2 + (0.025 X 23)2

+ (0.02 X 25)2] 0.35 "" 1,592,211 (Eq. 2-5)

This J2 value also will be used below. Assuming that the added sinusoidal load is in

phase with the fundamental component of

IMPEDANCE VOLTAGE AND REGULATION

Impedance voltage is the voltage drop in the windings due to their ac resistance and leakage reactance when the transformer is delivering full-load current. In the case of dual- or triple-rated transformers with forced cooling, full-load current, for the purpose of this definition only, corresponds to the self-cooled rating. In the case of transformers with taps on the secondary winding, full-load current is the current rating of the tap. Note that at secondary voltages below tap voltage rating, the transformer is not capable of delivering rated kilovoltamperes continuously, despite being specified as having "full-kVA" taps. Under the LV conditions the tap current rating governs.

'fransformer regulation is defined as the rise in secondary voltage when full load is removed. It is expressed in percent of secondary voltage rating. Regulation increases with increasirig impedance and with decreasing load power factor.

distorted-waveform load, the sinusoidal current that can be added is found by solving the following quadratic equation:

1.35 X (1 + 1162)2 + 21,266 + 1,592,211

"" (2221)2 X 1.35 (Eq. 2-6)

Equation 2-6, in which each term, multiplied by R, would be watts, reduces to:

I = [(2221)2 _ 21,266 + 1,592,211 ]~ _ 1162 1.35

= 771 A/phase (Eq. 2-7)

Note that the 21,266 and 1,592,211 constants were derived above.

The sum of the rms value of drive current, 1171 A, and the load that can be added, 771 A, is 1942 A. In effect, then, the transformer megavoltampere capacity has been reduced to 1942/2221, or 0.874 times its sinusoidal capacity-a 12.6% reduction. Another way of describing the result would be to say that a distorted waveform current of rms value 1171 A produced as much transformer heating as would 2221-771, or 1450 A of sinusoidal load current, a 1.24 multiplier.

A result of this magnitude suggests that more complete filtering in the drive package might be economically justified.

As noted in the Standard Handbook for Electrical Engineers (20), and ignoring percent resistance, which has small effect:

%REG = 100 (../{[1 - (PF)2]l> + % Z/100}2

+ .J (PF)2 - 1) (Eq. 2-8)

Where:

% REG "" transformer regulation, in percent ·

PF"" load power factor, per unit

% Z "" transformer impedance voltage, in percent

For transformers in power plant auxiliary power systems, regulation is typically 0.5 times percent impedance.

Th.ble 2-2 is derived from the above expression. It must be recognized that voltage regulation,

as measured at switchgear buses, may be increased

Table z.z Approximate Voltage Regulation

Load Percent lmpedancea

PF 5 6 7 8 9 10

0.90 2.28 2.76 3.24 3.74 4.24 4.75 0.88 2.47 2.99 3.51 4.04 4.58 5.12 0.86 2.64 3.19 3.75 4.31 4.88 5.45 0.84 2.80 3.38 3.96 4.56 . 5.16 5.76 0.82 2.94 3.55 4.16 4.78 5.41 6.04 0.80 3.08 3.71 4.35 5.00 5.65 6.30

"The exad value is slightly affeded by percent resistance.

significantly by secondary leads impedance voltage drop and will be additive to variations in transformer primary source voltage.

Low impedance is advantageous for voltage control but cannot be specified indiscriminately without consideration of its effect on short-circuit currents (Volume 3, All}(iliary System Planning).

IMPEDANCE AND THROUGH-FAULTS

A through-fault is a short circuit at or in electrical proximity to the terminals of one winding of a transformer while another winding is connected to a source of power. Such faults subject the transformer to both thermal and mechanical stresses. Because of a series of in-service failures caused by through-faults, the industry began reexamining the problem in the late 1960s.

ANSI Standard C57.12.00-1980 (5) requires that a transformer be capable of withstanding a short circuit on one winding with essentially full voltage maintained on the winding or windings designed for connection to sources of power. The field experience raised new questions as to the permissible magnitude, duration, and frequency of occurrence of such faults.

A well-conceived program to find answers to these questions is documented in a 1976 IEEE paper (21). The investigators found that thermal aging and short-circuit stress have an interrelated role in the mechanical deterioration of insulation, which can lead ultimately to insulation failure. As a result of this and other investigations a supplement to ANSI Standard C57.12.00-1973 covering short-circuit requirements was issued in 1978 and incorporated with minor changes in the 1980 revision of the standard (ANSI Standard C57.12.00-1980) (5). Discussions are continuing in the IEEE 'Iransformers Committee toward agreement on the frequency of such faults, which might be considered a part of "usual service conditions?'


'Iransformers connected directly to generators may be subjected to unusually severe throughfaults because of the abrupt rise in primary voltage when the generator is separated from the power system and the slow decay of generator flux following a protective relay operation. This set of conditions is well described in a 1977 IEEE paper (22).

The conclusions to be drawn from the above material are that (1) power plant transformers require special protective relaying to protect them from prolonged through-faults and that (2) transformers connected to generators must be specified for that service and designed with special bracing and appropriate thermal capability. Protective relay aspects are discussed in Volume 8, Station Protection.

PHASING OUT THREE-PHASE CIRCUITS

The following material describes a test method for verifying the relative phasing of two three-phase power supply circuits that may, at times, be paralleled. The secondary leads of an SST and a UAT are an example. This method is independent of the correctness of polarity or connections of voltage transformers already installed on those circuits.

If the circuit breaker is metal clad, a groundingand-test device may be used. A grounding-and-test device is a draw-out element that may be inserted into a metal-clad switchgear housing in place of a circuit breaker. It provides access to the primary circuits in order to permit temporary connection of grounds or testing equipment to the HV circuits. The device includes six bushings for connection to primary circuits and a ground bar for connection to the switchgear ground bus. All circuit elements are separated by insulating barriers. The device may also include a three-pole, two-position, manually operated primary selector switch and a stored-energy-operated grounding switch.

Normal safety procedures, such as using rubber gloves, rubber blankets, or hot-line tools, as appropriate, must be followed throughout the test. Further, care must be taken to remove all test connections and shutter blocks when the test is completed.

The measuring instrument should be a 150-V d'Arsonval or rectifier-type ac voltmeter, shunted by an incandescent lamp to minimize capacitance effects. Accuracy is unimportant. Digital instruments are less suitable for this purpose. If circuit nominal voltage is higher than 120 \1, a voltage


transformer with two primary fuses is required. In that case both test leads must be insulated for circuit voltage and connected to the primary fuses, and the transformer core and one leg of the secondary should be grounded for safety.

The tests are of the "pass/fail'' type. Recording instrument readings is not essential. The first test on each circuit measures phase-to-phase voltages to verify that the circuits are energized. The second-test on each circuit measures phase-to-ground voltages. In this test very low voltage readings on all three phases will indicate an ungrounded neutraL In that case it will be safe and necessary to connect a temporary jumper across one of the main contacts. A large difference among the three phase-to-ground readings on either source may in· dicate a fault, which must be cleared before proceeding. Alternatively, it may indicate that the source is a delta with a midpoint ground on one phase winding. In that case the other source must be similarly grounded or ungrounded, if the two are to be interconnected.

The final test measures the voltages across the open contacts (of the tie breaker). If these voltages are less than 10% of the nominal phase-to-phase voltage, the relative phasing is correct. A nonzero voltage indicates either a small phase angle difference or a small voltage difference between sources, which is to be expected.

1b judge the seriousness of a voltage across the open contacts (of the tie breaker), multiply the voltmeter reading by the ratio of the voltage transformer, then by 100, and divide the product by the nominal phase-to-neutral voltage of the system. Divide that result by the sum of the percent impedances of the two supply transformers. The quotient is the decimal fraction of full-load current that would circulate between supply trans· formers (assumed to have the same megavoltampere rating) if the tie breaker were closed. For 6%-impedance transformers feeding 4.16-kV systems, a voltage difference of approximately 288 V would cause full-load current to flow. Significant impedance in the primary sources of the transformers or in their secondary leads would increase the voltage required to produce this result.

If the two source voltages were in phase but of different magnitudes, the flow would be reactive power. If they were of the same magnitude but slightly out of phase, most of the flow would be real power. For the example cited a phase angle difference of about 7 electrical degrees would correspond to full load.

LOSS EVALUATION

Loss evaluation has a significant effect on the design of aUT or a UAT. No-load loss evaluation affects the design of an SST. It is not likely that evaluation of either load or no-load losses will affect the design of an LV substation transformer, because the increased cost of a low-loss design in this size range would not be offset by future savings.

A procedure for loss evaluation is described in Section 2. 7 and in Appendix A.

NOISE CRITERIA

Sound emitted by power plant apparatus can be a matter of concern for two reasons: hearing damage risk and neighborhood annoyance.

Hearing damage risk is incurred by personnel exposed 8 hours per day, 5 days per week over an extended period to A-weighted noise levels exceeding 90 dBA or exposed to higher levels for shorter periods. This requirement was promulgated by the Occupational Safety and Health Administration in Section 1910.95, Thble G-16, of its April1, 1981, standards (23). Such extended exposure is only likely in the case of transformers installed inside the power plant. Those commonly installed in open areas inside the plant are too small to make a significant addition to the aggregate noise of other power plant apparatus. Those installed in separately enclosed switchgear rooms may be the dominant noise sources in a highly reverberant occupancy; however, a switchgear room is not an area where ali-day exposure over extended periods is likely. For these reasons hearing damage risk is rarely a consideration in the selection of a power plant transformer.

Large transformers installed outdoors may in certain cases make a significant contribution to the overall noise level at property boundaries. At these boundaries the aggregate noise and its frequency distribution must be analyzed from the standpoint of neighborhood annoyance and for compliance with local noise ordinances. In this analysis the UT is the only plant transformer likely to be significant.

A complete discussion of noise control is outside the scope of this volume. It is a complex subject that has been under study by the Audible Sound and Vibration Subcommittee of the IEEE '~tansformers Committee for more than 12 years. Nevertheless, some useful information is presented below.

The dominant component of the sound emitted by a UT is core noise due to magnetostriction. That noise appears at discrete frequencies: a fundamental at twice power frequency and harmonics of the fundamental frequency. Other sound emitted includes fan noise from the forced-cooling system.

Figure 2-16 is a plot of data derived from factory noise measurements made on large power transformers by General Electric Company during the early 1970s. The plot shows that the 120-Hz tone is most prominent. However, with the "N' weighting usually applied in assessing the audible effects of these tones, the 240- and 360-Hz tones become of greatest importance, with the fundamental and other tones progressively less important.

The factory measurements, like most such measurements, were made at rated voltage and no load. However, in the case of U1S, especially those with high impedance, the flux density on which magnetostriction is dependent must be increased with load in order to maintain constant secondary voltage. This increase is produced automatically by the generator voltage regulator. This device raises generator voltage with load in order to maintain constant secondary voltage in the face of increasing impedance voltage drop in the transformer. The result is that a UT at full load may produce sound levels 10 or 15 dB higher than those measured at rated voltage in the factory. For

. this reason some purchasers require that sound measurements be made at both 100 and 110% of rated voltage.

m ~ 15 ~

10 .. -.s:: Cl 5 .. 31: 0 c: :I

"ii -5

,; -10

-g -15 :I

~ -20

~ -25 ;:;

-3o-

+3o-

B Median

~ -30 L---..1...--..l--...l--...l--....L...-....L...--

It: 120 240 360 480 600 720

Discrete frequency CHzl

Figure 2-16 Bar Chart Factory Noise Measurements of Large General Electric Power Transformers (Early 1970s}


Despite this effect UT sound has become a relatively unimportant consideration in recent years. There are two reasons for this. One is that modern power plants usually are built on very large sites. Thus, the UT is often remote from plant boundaries. The other reason is that the high valuation placed on transformer no-load losses by most purchasers encourages designers to reduce core flux density.

In critical cases transformer sound can be reduced in several stages. For reductions up to 12 or 15 dB from the "average" sound level published by the manufacturers, the purchaser may specify a lower level, which will increase transformer price by approximately 2%/d.B of reduction. For still greater reduction double-wall tanks can be furnished, but the cost may be greater than that of other measures.

The UT, which is the largest source of magnetostriction noise, is often installed near a turbine room outside wall. That wall may be an effective reflector of sound. It can be made less reflective by using an outside course of specially slotted concrete blocks in which the slots and cavities are tuned to make them Helmholz resonators, effective absorbers of the major harmonic components of magnetostriction noise. The patent for this slotted design is privately owned, but any local concrete block fabricator can make these special blocks under license from the patent owner.

A barrier wall may be erected between the transformer and the property boundaries. Such a barrier, usually of masonry construction, should be higher than the transformer tank and as close to the transformer as possible, consistent with inspection and maintenance requirements, electrical clearances, and allowance for circulation of cooling air. In general the distance from the wall to the nearest major surface of the transformer assembly should be at least 8 ft. The wall surface facing the transformer should be treated acoustically to reduce reflection.

In a few very critical applications transformers have been completely enclosed, except for their HV bushings, in masonry vaults. Such designs have required special provisions for cooling (either water cooling or detached FOA coolers outside the vault), for oil spills, for fire protection, and for bringing the HV bushings through noise seals in the vault roof. Noise reductions of as much as 25 dB can be achieved in this manner.

In the past, several experiments have been done with noise cancellation techniques. This approach


showed considerable promise under closely controlled conditions but has not proved practical.

2.14 SHIPPING CONSIDERATIONS

Shipping considerations may affect the design of large power transformers. If the transformer can be purchased free on board (FOB) destination, the manufacturer will investigate the entire shipping route, including roads, rails, bridges, and tunnels, to determine.dimension and weight limitations before undertaking the detailed design. If the transformer is purchased FOB factory, the purchaser may have to establish the shipping limitations. In some cases barge shipment over a portion of the route may relieve certain limitations. Overhead clearances may dictate a five-legged core rather than a three-legged core or removable side pockets for EHV bushings, or they may require that the tank be "made in two sections, the top section to be replaced by a temporary flat cover for shipment.

Even transformers of moderate size may require partial disassembly for shipment. Removal of HV bushings, oil, and radiators is common practice and presents no special problems. If cooler control cabinets or other appurtenances must be removed, however, the design must provide for their removal after factory test and their reinstallation at the job site.

Large liquid-immersed transformers are usually drained before shipment to reduce their weight. They are then filled with either dry nitrogen or dry air and sealed at a low positive internal pressure, monitored by an external gage. The liquid is shipped from the supplier directly to the job site in tank trucks or tank cars.

Personnel must work inside the transformer tank during installation, in some cases to remove temporary bracing but in most cases to connect leads when the bushings are installed. For that reason the nitrogen, if used, must be purged before the tank is entered. Some purchasers prefer dry air to dry nitrogen.

Impact recorders are frequently mounted on railroad cars carrying large transformers to provide evidence of rough handling if the transformers appear to have been damaged in shipment. If a rider is hired to escort a transformer during rail shipment, he should be given explicit instructions that his function is to accompany the

transformer during its entire travel, from the factory to the job site, in order to be able to report on any incidents of rail humping.

2.15 SPECIFIC APPLICATIONS

UTs

The UT is the largest transformer in the plant. It is generally located outdoors and is mineral oil immersed. In the United States such transformers rarely have LTCs. Because they have to be kept small enough to be shipped by rail, most UTh are class FOA or class FOW. (Class FOW transformers are commonly used at hydroelectric plants.) The fact that a transformer of either design has no selfcooled rating usually is not a disadvantage, because in this application it will usually operate well loaded whenever it is energized. It is important, however, that the mechanical cooling auxiliaries be placed in operation whenever the transformer is energized. As compared with a triple-rated design (class OAIFA/FOA or class OA/FOAIFOA), FOA or FOW transformers cost slightly less and require less space.

The triple-rated design may be preferred, however, if switching equipment is added in the generator leads to the UT. That addition permits the carrying of auxiliary power load by backfeeding from the switchyard through the UT and the UATh while the unit is shut down. The triple-rated transformer can operate in this mode without forced cooling.

The UT differs from most other transformers on the system. in that its HV winding is the secondary. Its LV winding most often is connected to the generator through the isolated-phase bus. The tank cover must be fitted with nonmagnetic flanges around each LV bushing to support the individual phase enclosures for that bus. If the LV bushings are cover mounted, as is frequently the case, the strike distance from HV bushing terminals to bus enclosures must be adequate for the voltage class. And, since large stray currents may be present near the isolated-phase bus, the bus enclosures must be insulated from the tank cover. The arrangement of grounding conductors for the bus enclosures and the transformer tank requires special consideration. It is also necessary to ensure that the transformer LV bushings have temperature ratings suitable for connection to the bus

conductors, which may operate at 105°C. Since the transformer will be located near the generator to minimize the length of the costly leads, oil spills and fire protection warrant special consideration.

The UT may be a single three-phase unit, two "half-size" three-phase units, or three single-phase units. Selection among these alternatives is generally based on consideration of some torm of spare. Except for connection to 765-kV or higher voltage systems, three-phase units are available.

Selection of Size, Impedance, and Voltage Ratings The selection of size, impedance, and voltage ratings for the UT is different from similar procedures for a substation transformer. These characteristics must be selected with care to ensure that the full capability of the turbine generator will be available to the power system. Being

. far less expensive in dollars per kilovoltampere than the generator, the transformer must not be the bottleneck under any possible operating condition. The trade-offs must be explained to all interested parties-the power station engineers, the operating personnel, the system planning engi· neers, and the substation and transmission engineers-to arrive at prudent decisions. To this end it may be necessary to analyze several alternatives and to prepare graphic presentations of performance limitations, as demonstrated below.

TUrbine Generator The UT is the link between the turbine generator and the power system that it serves. As such it must not limit the output of the turbine generator in any of its permissible operating conditions.

The permissible operating conditions are bounded by the generator reactive capability curve furnished by the manufacturer. That curve is a plot of maximum reactive power, both lagging and leading, versus real power. By convention lagging power factor (generator overexcited) is shown above the power axis and leading power factor (generator underexcited) is shown below it.

Such a curve is shown in Figure 2-17. Unless otherwise indicated the curve applies to operation at rated voltage. Curves for 95 and 105% voltage may differ slightly from the rated voltage curve, except at rated power factor. The differences are noticeable at a zero power factor, leading, but are not usually significant in the selection of UT ratings.

The product of rated megavolt-amperes and rated power factor is a megawatt value, reasonably well


matched to the turbine generator real power output with turbine inlet valves wide open and some set of steam (or hydraulic) conditions for which performance is guaranteed. That megawatt value is not necessarily equal to the maximum continuous real power output under winter (or maximum head) conditions. Greater power than the above megawatt value will reduce the allowable reactive power flow to the system but will increase the UT loading, as will be shown. Where a heat balance (or hydraulic study) has demonstrated a greater power output, it may be prudent to use that value and the intersections of the corresponding vertical locus line with the reactive capability curve as inputs to the transformer calculations.

Figure 2-17 is marked to indicate the generator reactive capability limits, lag and lead, at the real power output corresponding to generator megavolt-amperes and rated power factor. These values, 854.9 MW, 530 MVAR, and -346 MVAR, are used in the transformer calculations for the base case.

It is not possible to make the entire range of generator full-power reactive capability available to the power system under all system voltage conditions. 'll'ansformer real and reactive power losses will absorb part of the generator output under most conditions. Certain system voltage conditions may cause the generator to operate outside its allowable voltage range. These conditions, in turn, may cause the transformer to operate outside its allowable range of voltage or current. 'll'ade-offs must be made when transformer parameters are selected to ensure that the portions of the megavolt-ampere-reactive range that are sacrificed under LV or HV conditions are those least needed. Also, the transformer should not be made unreasonably large; cost and space must be considered.

Unit Auxiliary Load In the usual power plant design one or more UATh will be connected to the generator leads to provide a normal source for the unit auxiliaries power system. When these transformers are in use, the unit auxiliaries load, as seen from the primary terminals of the UAT, drains off a portion of generator output before it reaches the primary terminals of the UT. Since this drain is a normal condition, the usual practice is to recognize it and select the UT for net output. In certain cases, however, transformers are sized to accept the gross output of the generator in order to allow full-load operation of the unit while


4 pole, 1,005,800 kVA, 1800 rpm, 24,000 V 0.85 PF, 0.58 SCR, 60 psig hydrogen pressure, 500 V excitation

0:: <(

> ::E

"' " ...J

"0

" ., ...J

1000

800

600

400

200

0

200

Overexcited limit 530 MV AR

/ ~ /~ ~

F::::::::

.. ' I".."

""''''''~~ limit 346 MVAR

'\

---

I v v v

v ~ ~ / V" ~ ~ ~ ~

~ r---. ~ ~

"" ""' .......

0.60 PF

v 0.70 PF vv 0.80 PF

v 0.85 PF / L

/ v / v

v v v

~ ~ 0.90 PF

/ v I / ~ v v v r: I

v V 0.95 PF

v ~ ~ v I -- - 0.98 PF

~ J---~

r-~ r-' ~

854.9 MW r-....

r-- J

~ ---1-- ~ ~ r- r-.

r--.... r-. 0.95 PF

' 'to.....

!'\. ~""' ~

0.90 PF

400

0.60 PF 0.70 PF 0.80 PF

600 I I 0 200 400

I 600

MW

800 1000 1200

Figure 2-17 Reactive Capability Curves for Steam Turbine Generator Unit

the auxiliaries load is supplied from another source. This selection increases transformer cost.

Half-Size un Failure of the UT will cause a prolonged outage of the entire unit unless there is an available spare transformer, preferably on site. 1Wo half-size transformers may be selected in place of a single full-size transformer in order

to reduce the cost of the spare or, in some cases, to remain within shipping limitations. When this is done, each transformer may be sized to carry more than half the generator output, permitting useful operation of the unit while one transformer is being tested, maintained, repaired, or replaced. In such cases both the single-transformer and twotransformer conditions should be investigated in the initial selection process.

Graphic Presentations of Performance Graphic presentations of performance, such as are shown in Figures 2-18 through 2-25, are useful in evaluating initial selections of UT ratings. They are also helpful in soliciting the comments of operating and system planning personnel on the effects of the initial selections.

Several variables are involved in the relationship of a turbine generator, a UT, and a power system. Some· of these are generator megawatts, generator megavolt-amperes-reactive, generator hydrogen pressure, generator voltage, transformer output megawatts, transformer output megavars, and transformer output voltage. Four transformer parameters have to be determined in the transformer selection process:

94 7 MVA transformer 23.131-345.000 kV 9.17" impedance with 1005.8 MVA, 854.9 MW generator 52.37 MVA unit auxiliaries load


• Megavolt-ampere rating • Impedance voltage • Secondary voltage rating • Primary voltage rating

The ratings selected will determine the relationships among these variables. There is some latitude in the selection of each rating. For that reason it is useful to present the results of a set of selections in graphic form.

The generator reactive capability curve is a plot of generator megavolt-amperes-reactive versus generator megawatts, often in a family of curves, one curve for each cardinal value of generator hydrogen pressure. Separate curve sheets may be presented, one for each value of generator voltage.

Top System

E Q) -., >., 0 1-

E Q) -., >., E 0 ..

u...

600 ··-Generator voltage 105.0x

500 ~.-t-.....::~---r~-+-- Transformer ii mit

400 ~F;._-~:--_._-~~-..P...."""""~--- Generator overexcited limit

300

200

100 Generator voltage 102.5X

-100 1-----~--i--~--+-~:-t--- Generator unity power factor

-200 Generator voltage 100.0x

-300

-400

-600 Transformer limit

-700 Generator voltage 9S.Ox

-800

-900

-1000 ~-----~----~-~ 330 362

Bus CkVl

Figure 2-18 Base Case


Generator 24.9 kV

Rating

24 kV zr Auxiliary bus -

UAT

1,. Bose 24 kV

103.75>: v

1107.65>: VI • I .. I I

VI

0

854.9 98.34>: v

UA T load

812.48 MW

499.29 MVAR

Load losses

418.71 MVAR

Figure 2-19 Voltage and Power Profiles

In the selection of transformer ratings it is only the limiting values of generator megawatts, generator megavolt-amperes-reactive, and generator hydrogen pressure that are of interest, not their interrelationships in other portions of their ranges.

Rating selections have little effect on transformer output megawatts. "fransformer real power output is very nearly equal to the real power input in all cases, although the power losses, which make up the difference, have important economic value. The rating selection has significant effect on the relationship between output megavoltamperes-reactive and voltage and on the limits of output megavars, which limits may be determined by the capabilities of the generator, the transformer, or the HV circuit breakers (voltage limit).

Attempts have been made to display the effects of transformer selection as additional lines on the generator reactive capability curve sheet. These attempts fail because there is no voltage scale and because they conceal the reactive power losses in the transformer, which are significant.

More information can be presented by plotting values on the secondary (system) side of the transformer on a different set of axes.

When the generator is at maximum power, the reactive power transfer to the system (dependent variable) is determined by rating selections and by the variables' generator voltage and switchyard

voltage, either of which could be selected as the independent variable for a family of performance curves. When generator voltage is selected as the independent variable, a separate curve can be drawn for each cardinal value of switchyard voltage. When switchyard voltage is selected as the independent variable, a separate curve can be drawn for each cardinal value of generator voltage.

Separate curves for each generator voltage are clearer. This type is therefore used in Figures 2-18 through 2-25. It will be useful to examine these eight figures before considering the selection method.

Figures 2·18 through 2-25 show the performance of a 1005.8-MVA, 0.85-power factor generator, with 52.37-MVA, 0.81-power factor auxiliaries load, connected to a 345-kV transmission system through six slightly different UTs. The differences in performance illustrate the effects of changes in four transformer parameters: megavolt-ampere rating, impedance, secondary voltage rating, and primary voltage rating. Most of these figures represent the unit operating at 854.9 MW. Figures 2-20 and 2-25 are included to show the effects of changes in real power output. The graphs were developed with the aid of a computer program, but the information they present can be derived with the data from load-flow studies for the transmission system.

The terms design center and system voltage refer to a set of system conditions around which most of the hours of unit operation are expected to be clustered. The fact that the unit will not be at full power during all of this time is of small importance in this analysis. At reduced power the generator can deliver more reactive power, but the transformer load will be reduced. The design center is identified in each figure by a small circle.

System voltage will generally be held far enough below the circuit breaker maximum voltage rating to allow for random excursions, but it is not likely to be set deliberately in the lower portion of the range, there being no economic incentive for exporting power at low voltage.

Abnormal system conditions may result in low bus voltage, but it is reasonable to assume that this unit will be called on at such times for maximum reactive power support and that the support will raise voltage.

For all eight figures it was arbitrarily assumed that a system voltage of 356 kV at the switchyard bus would be the design center value. The primary (LV) winding voltage rating of each transformer

955 MVA transformer 23.123-345.000 kV 9.17" impedance with 1005.8 MVA, 897.7 MW generator 52,37 MVA unit auxiliaries load


Tap System

a:: <(

> ::l:

E CP -(/)

>. (/)

0 .....

E II) -., >. (/)

E 0 ...

LL.

600

500

400

200

100 Generator voltage 102.5"

0

-100

-200 Generator voltage 100.0"

-300

-400

-600

-700


-900

-1000 L-----------~--------~--~ 330 362

Bus (kVl

Figure 2-20 Increased Real Power

was therefore selected to place generator voltage at nameplate value, 100%, when bus voltage was 356 kV and reactive power flow from the UT to the switchyard bus was either zero or some other preselected value. Note that the zero reactive power flow condition is different from unity power factor at the generator terminals.

It was also assumed that the UT must not limit generator output within its reactive capability limits, overexcited, but that generator thermal capability in the underexcited region, often partially denied to the system by automatic control devices because of stability considerations, need not be fully accommodated.

In each figure generator-plus-transformer performance is presented graphically in terms of system quantities: reactive power flow to or from the

switchyard bus versus bus voltage. Since system quantities, in this context, are also UT secondary quantities, the transformer limits may be shown directly. Also, with transformer secondary quantities known at every point on the chart, transformer input quantities can be derived for every point, and generator limits can be shown.

None of these figures shows bus voltages below 330 kV. Although bus voltage, under abnormal conditions, could drop to 328 kV (5% undervoltage), it is not likely to remain below 330 kV when this unit is delivering 300 or 400 MVAR to the bus.

Base Case Figure 2-18 may be.considered the base case. It depicts performance of a 947-MVA, 9.17% impedance transformer, the smallest transformer of that impedance that will meet the


969 MVA transformer 23.703-.353.600 kV 9.17" impedance with 1005.8 MVA, 854.9 MW generator 52.37 MVA unit auxiliaries load

Top System

et:: < > ::::<

E .. ..., "' >.

"' 0 1-

E .. ..., "' >.

"' E 0 ..... u..

700

600

500

300

200



-300

-400

-500

-600


-800

-900

-1000 ~------------------~~--~ 330 362

Bus (kVl

Figure 2-21 Higher Secondary Tap

desired criteria. The secondary (HV) winding has the lowest voltage rating, 345 kV, that will permit operation under load at a maximum sustained bus voltage of 362 kV, which is the circuit breaker (maximum) voltage rating. It is also the upper limit for this voltage level in ANSI Standard C84.H982. ANSI Standard C57.12.00-1980 (5) requires that a transformer be capable of delivering full kilovoltampere output continuously at 105% of rated secondary voltage and rated frequency. At 362 kV on the 345-kV tap, secondary voltage is slightly less than 105%.

The voltage profile in Figure 2-19 is for the base case transformer with the generator at full power, at its overexcitation limit, and with 356 kV at the 'switchyard bus. This operation point, though not marked, can be located in Figure 2-18. The voltage profile is drawn on a changing voltage base to

show the relationships of actual primary and secondary voltages to the voltage ratings of the connected apparatus. It shows that the impedance voltage drop has been offset by selecting a primary voltage rating lower than the generator nameplate voltage. The result, under these conditions, is that transformer primary voltage is 107.65% of the winding voltage rating. However, this condition is of no concern. 'Transformer overexcitation is defined in terms of conditions at the secondary terminals, in this case, the HV terminals. The voltage there is 103.19% of tap rating, well within the range permissible at full load. Figure 2-19 also shows real power and reactive power profiles from gener~tor to switchyard.

The transformer limit lines in Figure 2-18 show that transformer capability droops at bus voltages

947 MVA transformer 22.925-345.000 kV 9.17X impedance with 1005.8 MVA, 854.9 MW generator 52.37 MVA unit auxiliaries load


Top System

0:: < > ::::0

E Q) .... rn >. rn 0 f-

E "' .... Ill >. Ill

E 0 ... u..

600

500

300

200 Generator voltage 102.5X

100

-200

-300


-600 Generator voltage 95.0X

-700

-800

-900

-1000 L-----------~------~L---~ 330 362

Bus (kVl

Figure 2-22 JOQ-MVAR Export at Design Center

below 345 kV, despite the fact that this is a "fullkVN tap. ANSI Standard C57.12.00-1980 (5) requires that tap to deliver rated kilovoltamperes at rated tap voltage but not at lower voltages, where the tap current rating intervenes.

At 330 kV, the generator and the transformer both reach their thermal limits at a reactive power flow to the system of approximately 410 MVAR, with generator voltage at approximately 97% of nameplate value. A higher generator voltage would produce output beyond the thermal limits unless it also produced an increase in switchyard bus voltage.

The generator cannot quite reach its capability limit, overexcited, when bus voltage is 362 kV. That comer of the chart would require generator voltage greater than 105%. Similarly, the generator

cannot reach its reactive capability limit, underexcited, when bus voltage is less than 354 kV, because that condition would require generator voltage below 95%. It is highly unlikely that operation in either of these portions of the domain would ever be desired. However, in the vicinity of system voltage-in this case 356 kV-the full range of generator reactive capability can be used to maintain the desired bus voltage without violating generator full-power voltage limits. The ex-· pected result is that generator voltage will remain close to 100% most of the time.

Changes described below for succeeding figures are from the base case; they are not cumulative.

Greater Real Power Output For Figure 2-20 generator maximum real power output was


975 MVA transformer 23.136-345.000 kV 9.17" impedance with 1005.8 MVA, 854.9 MW generator 52.37 MVA unit auxiliaries load

Top System

0:: < > ::::0

E CD .... .. >. .. 0 t-

600

500

300

200

100

-200

-300

~ -400 .... .. >. ., E 0 ...

u.. -600

-700

-800

-900

Generator voltage 102.5,;

Generator voltage 100.0lll

Generator voltage 95.0lll

-1000 ~----------~--------~---J 330 362

Bus lkVl

Figure 2·23 Oversize Transformer

assumed to be 5% greater than the product of rated megavolt-amperes and power factor:. For this condition the generator maximum reactive power limits are reduced to 453.7 and -340 MVAR. As can be seen, this case requires a larger transformer than does the base case so that further limiting of reactive power delivery is avoided.

Higher Secondary Tap Figure 2-21 shows the effect of selecting a 353.6-kV secondary tap. If the same range of operating conditions are to be covered as in the first example at switchyard voltages below tap voltage rating, the transformer size must be increased from 947 to 969 MVA, an increase of 22 MVA. The primary voltage rating has been increased from 23.131 to 23.703 k\1, making the turns ratio very nearly the same as before.

Operating characteristics of the larger (and more expensive) transformer are essentially the same as those of the base case tranformer.

Reactive Power Export at Design Center The transformer for Figure 2-22 is the same as in the base case, except that the primary voltage rating has been reduced from 23.131 to 22.925 kV to restore generator voltage to 100% at an assumed design center condition of 100-MVAR delivery at full power and 356 kV.

Oversize 'D'ansformer Figure 2-23 shows a larger transformer (by 28 MVA) than that considered for the base case, used on its 345·kV tap. A common reason for adding megavolt-ampere margin is to provide for a condition in which part or

921 MVA transformer 22.993-345.000 kV 16,; impedance with 1005.8 MYA, 854.9 MW generator 52.37 MVA unit auxiliaries load


Top System

0::: < > ::::;:

E Q) ... "' >.

"' 0

1-

E Q) ... "'

600

500

300

200

100

-100

-200

-300

-400

Generator voltage 105.0::.:

Generator voltage 102.5,.

Generator voltage 97 .5x

~~----+---Generator voltage 95.0,;

~ -500 E L------+----"t---r--- Generator underexcited limit

~ -600 u...

-700

-800

-900

-1000 ~-----~----~-~ 330 362

Bus (kY)

Figure 2-24 High Impedance

all of the auxiliaries load is transferred to another source, releasing that increment of generator real and reactive power output to flow through the UT to the switchyard. This figure, however, is drawn for the normal condition. 'D:'ansformer impedance, still 9.17% but on a larger base, translates to a slightly lower ohmic impedance than that of the base case, thereby requiring a very slight increase, from 23.131 to 23.136 kV, in primary winding voltage rating to restore generator voltage to 100% at design center. The lower ohmic impedance causes a barely perceptible increase in the slopes of the generator voltage lines and in their separation.

Increased Impedance For Figure 2-24 the transformer impedance was increased from 9.17 to 16%. The higher impedance may be required to

reduce circuit breaker interrupting duty, but it will also reduce generator stability. The impedance change necessitates significant changes in other transformer parameters. The required megavolt· ampere rating is reduced from 947 to 921, because a smaller proportion of generator reactive power output reaches the secondary terminals (trans· formers are output rated), the remainder being absorbed by reactive power loss in the transformer. The primary winding voltage rating is reduced from 23.131 to 22.993 kV to offset the increased impedance voltage drop. The performance is affected in that the slopes and spacing of the generator voltage lines are greatly reduced, leaving larger portions of the generator reactive capability outside the limits of 95 to 105% generator voltage. Those portions may not be of great


947 MVA transformer 23.131-345.000 kV 9.17X impedance with 1005.8 MVA, 427 MW generator 52.37 MVA un"1t auxiliaries load

Top ·system

E Q) +'

"' "' "' 0 I-

1200

1000

400 Generator voltage 105.0x


0 ~==~;::;;=::+~;::;;;::=~;::;;;::+-- Generator unity power factor

-200 Generator voltage 100.0X

,.,.a---t---Generator voltage 97.5X

-400 ~------+--;::,.,~+-;::,.,!--Generator underexcited limit

E Q) +'

"' "' "' E 0 ....

LL.


-1000

-1200

-1400

-1600

-1800

-2000 L------~-----L--~ 330 362

Bus (kVl

Figure 2-25 Half-Power Operation

importance, but two other effects of the increased impedance are undesirable: (1) the maximum reactive power support for low system voltage is reduced by approximately 60 MVAR and (2) the generator voltage must swing over a wider range to meet varying system requirements. It is reasonable to assume that, in most cases, the lost reactive power capability will have to be replaced by some other source on the system. The wider swings will have unfavorable effects on the generator and will magnify the effect of voltage regulation problems on the auxiliary power system.

Reduced Power Operation Figure 2-25 shows the performance of the transformer selected in the base case when operated with the turbine generator at half power. This mode of operation

may be desirable during periods when power is imported from remote sources because of temporary steam supply system limitations, clean air restrictions on local fuel burning, or lower fuel costs at the remote source. Under such conditions it is essential that a strong local source of reactive power be maintained.

The reactive capability curve indicates that at 427 MW this generator has limits of 715 and -430 MVAR. The MVAR scale has been changed on the performance chart to display this wider range. As can been seen, the transformer limits are now well removed from the permissible operating domain, but the transformer parameters selected for the full-power mode are still suitable. At system voltage the full range of generator reactive capability is accommodated within the allowable range of

generator voltages and no tap changing is required to achieve this result.

Sequence of Selections Except for the transformer primary winding voltage rating, which can be selected last without the other ratings being affected, each selection affects the others. The approximate megavolt-ampere rating and percent impedance usually are selected first on the basis of generator size and circuit breaker interrupting capability. The price adder, which is occasionally invoked to justify selecting an impedance below the manufacturer's "standard" impedance range, will usually be negligible In comparison with the benefits associated with low impedance. The secondary winding voltage rating is usually selected to match the nominal voltage of the transmission system. With this selection the maximum switchyard voltage will be very close to 105% of that voltage rating, a permissible full-load continuous operating condition. (An exception to this is a 500-kV system operated up to the 550-kV circuit breaker voltage limit.) Selection of a higher voltage rating for the secondary winding would require an increase in megavolt-ampere rating to compensate for the current limitation at switchyard voltages below that voltage rating, as has been shown. Omission of other HV winding taps would simplify construction and thereby improve transformer reliability. The omission would also reduce transformer cost. If additional taps are specified, consideration should be given to placing them closer together than the conventional 2.5% spacing.

The exact megavolt-ampere rating required can be determined by iterative calculation of transformer output at minimum sustained switchyard voltage, full power, and maximum reactive power output from the generator. For the method of calculating the real power component of transformer output, see "Performance Calculations;• below. At each iteration the transformer current is adjusted to correct for error in the generator output, and the transformer megavolt-ampere rating is adjusted to match the calculated transformer current output, not overlooking the mismatch between bus voltage and transformer secondary . voltage rating. The megavolt-ampere rating thus found is the minimum value. Margin may be added where appropriate.

As an aid in the presentation of these calculations, a simplified equivalent circuit and a .phasor diagram are shown in Figure 2-26. The exciting current branch has been moved to the input terminals for convenience in calculation.


This simplification makes little difference; in fact, complete omission of this branch would have no significant effect on the results.

Symbols in the equivalent circuit, Figure 2-26a, represent the following:

IuAT is current per phase flowing from the generator leads to the UAT primary terminals.

Ic is generator total stator current per phase.

11 is current per phase flowing from the generator leads to the UT primary terminals.

10 is UT exciting current per phase.

lc is the· core loss component of exciting current.

Ie is the magnetizing component of exciting current.

N • IL is the load current per phase in the primary winding of the UT.

V'/N is the UT primary voltage, phase-to-neutral (same as generator voltage, Vc).

N is the ratio of UT rated secondary (tap) voltage to rated primary voltage.

V' is induced voltage, phase-to-neutral, in the secondary winding.

R is equivalent resistance per phase of transformer windings, including the effect of stray losses, referred to the secondary terminals.

X is equivalent leakage reactance per phase of transformer windings, referred to the secondary terminals.

V2 is voltage, phase-to-neutral, at the secondary terminals.

With the megavolt-ampere rating established, the ohmic equivalent of the previously selected percent impedance is defined. Next, a preliminary voltage rating is assigned to the primary winding. A value of approximately 97% of generator nameplate voltage is a good starting point. Note that over the wide range of design criteria covered by Figures 2-18 through 2-25, transformer primary voltage rating varied from 95.5 to 98.8% of generator nameplate voltage. The low value is associated with 100 MVAR reactive power export at design center, the high value with a higher-thannecessary secondary tap.

The preliminary value of primary voltage rating is used in working back from design center conditions on the secondary side to fmd a corresponding value of generator voltage. That value, in per unit of generator nameplate voltage, is used as a


Station service load

I UAT

IG

a. Equivalent circuit

b. Phosor diagram

A

Generator

D

I, N. IL

Io

I.

V'/N

1:N R X

I T V'

Top

v '1

B

V2

c

R

System load

X

Figure 2-26 Simplified Equivalent Circuit and Phasor Diagram

divisor to correct the preliminary assigned primary voltage rating. Although this is not a precise correction, it will be accurate enough for practical purposes. In case of doubt the corrected rating can be put through a second iteration. Selection of the primary voltage rating does not affect the other ratings selected previously.

Performance Calculations Performance calculations are done by an iterative process to derive initially unknown transformer output, which cor· responds to a selected point within the generator reactive capability curve and a selected secondary

voltage. We subtract transformer excitation losses (accuracy of which is relatively unimportant) and UAT load megawatts, and megavolt-amperesreactive are subtracted from the generator output to give unit transformer megawatts and megavolt-amperes-reactive input.

As a start, transformer output megawatts and megavolt-amperes-reactive are assumed equal to the known input quantities. The assumption is incorrect because it ignores real power and reactive power losses. It does, however, provide a reasonable starting point. These assumed outputs are then converted to a per unit secondary current,

from which transformer real and reactive power losses can be calculated. Note that this loss calculation is independent of output power factor. The calculated losses are then added to the assumed outputs to produce a second set of transformer inputs, which will be larger than the known inputs. The ratio of the known input megavoltamperes to the megavolt-amperes corresponding to the second set of megawatts and megavoltamperes-reactive is used to correct per unit current. 'Iransformer losses are then recalculated, and the process is repeated until the correction factor is acceptably close to 1.0. For the charts presented earlier the limits were set at 1.002 and 0.9998, requiring as many as eight iterations in a few cases.

The results of these calculations are more accurate than is warranted by the accuracy of the input data. Results obtained prior to transformer manufacture will be affected to some extent by standard manufacturing tolerances, in particular, those applying to impedance and ratio. For example, although transformers of this size are generally designed in close correspondence with the specified parameters, a ratio error within the minimum enforceable tolerance of 0.5% might displace each generator voltage line on the chart one-fifth of the distance to the adjacent line. A transformer delivered with this small ratio error will not present a serious problem. The operator will set the voltage adjuster for the generator voltage regulator to produce either the desired switchyard voltage or the desired reactive power flow. Generator voltage for that condition will be slightly different from the calculated value.

At a fixed switchyard voltage, as represented by any vertical line on the chart, the change in megavolt-amperes-reactive flow to the system is linear with change in generator voltage. For example, in Figure 2-18, with the system voltage at 356 kV, a flow of 400 MVAR to the system requires a generator voltage of approximately 103.64%, and a flow of 400 MVAR from the system corresponds to a generator voltage of about 96.36%. Thus, each 1% change produces a change in reactive power flow of 110 MVAR. Ut should not be inferred, however, that the fmding of linearity was based on the calculation of two points on the line.) From that simple relationship the megavolt-amperes-reactive flows corresponding to 95, 97.5, 100, 102.5, and 105% generator voltage are found to be -550, -275, 0, 275, and 550, respectively. At 345 kV each 1% produces a change of about 106 MVAR. And at 362 kV the ratio is about 112.5 MVAR per


1% change in generator voltage. These ratios apply only to this case.

The sloping generator voltage curves, which are drawn through corresponding points on the several switchyard voltage lines, are not quite linear. Their (negative) slopes increase slightly at higher switchyard voltages.

There is no simple way of calculating these curves starting from points within the generator reactive capability curve, although a load-flow computer program can derive them point by point. When they are derived by an iterative and interpolative process, however, a point on the chart can be traced back to a point within the reactive capability curve by conventional manual calculations.

UATs

In most large generating units the normal source of power for the unit auxiliaries is the main generator leads, to which one or more UATh are connected directly. This configuration has several advantages over a transmission system source. Feeding power for local use from that point reduces the power flow through the UT and thereby reduces the load losses in that transformer. It also reduces the magnitude of the voltage dips on the auxiliary power system during close-in faults on the transmission system, because the generator voltage is less affected by such faults than is switchyard bus voltage, being cushioned by the intervening impedance of the UT. The available short-circuit megavolt-amperage of this source, however, is often greater than that of the switchyard bus, subjecting the UAT to very large and often prolonged stresses in the event of a fault on its secondary circuit. The stresses will be prolonged if the fault is at the secondary terminals or at any point on the secondary leads up to the secondary breaker. This occurs because, although the unit must be tripped rapidly by protective relays (there being no other way to isolate the fault), the generator will continue to feed the fault during the period of generator airgap flux decay.

Because of the potential for large, prolonged through-faults, potential transient overvoltages (Section 2.13), and the usual requirement that the primary terminals be configured to accept isolated phase bus connections, transformers designed for this service command a premium price.

Rating basis and temperature rise are explained in Section 2.4.

For those users who prefer not to use forcedoil cooling systems the OAIFAIFA option is available


from some manufacturers. Cooling options for these transformers are discussed in Section 2.6.

Commonly used connections for transformers are discussed in Section 2.9.

Impedance considerations are discussed in Section 2.13.

Insulation levels are discussed generically in Section 2.5. UATh do not warrant any special consideration in this respect, because the generator stator winding, with exposure to the same impulse voltages as the primary of the VAT, has an effective BIL approximately equal to only twice the crest value of the generator nameplate voltage. Thus, for a 24-kV. generator the stator BIL would be approximately 67 kV, whereas a liquid-immersed transformer winding for that voltage level would usually have a BIL of 150 kV.

Split secondary windings or true three-winding transformers are used frequently in this application. System design considerations are discussed in Volume 3, Auxiliary System Planning.

'IWo aspects of the selection process for a VAT differ from the selection process for an SST. The first is that, unless there is a generator breaker on the primary side of the UT, the VAT is never likely to carry less than half load. The reason for this is that auxiliary power system load is not transferred to the VAT until the generator is at full speed and connected to the transmission system. By that time enough of the unit auxiliaries are in operation to represent a substantial kilovoltampere load, even though the kilowatt load may be less substantial. The effect is to produce a significant drop in UAT secondary voltage at the time when that voltage is first impressed on utilization equipment. Therefore, the VAT no-load secondary voltage can safely be more than 110% of the nameplate voltage of large motors. That, in turn, permits use of a lower tap on the primary of the VAT than would otherwise be permissible and allows for more impedance in the VAT, if required by short-circuit considerations. In contrast the SST may carry very light load when the corresponding unit is shut down for maintenance. It must not produce high secondary voltage under those conditions.

The other aspect of the selection process that may differ concerns reliability. Failure of a UAT in service will cause a unit trip because there is no other way to isolate the fault. The faulted transformer must be disconnected from the generator leads. However, if there is a dedicated SST (not shared with another unit), it will be possible to

return the unit to full-load operation, using the SST. Since this form of backup makes reliability of the VAT less important, transformer design features such as three-windings and LTCs, which are considered risky by some users, may be adopted with less risk in this application.

SSTs

The SST feeds the unit auxiliary power system during startup or shutdown or when the VAT is unavailable. It receives input from the HV or EHV switchyard or from a remote HV source. The application is similar to that of a substation transformer, except that, because it is used intermittently, its load factor is very low. However, its availability is critically important, and it remains energized at all possible times. It is also important that its impedance, voltage ratings, and winding connections (phasing) be carefully coordinated with the plant auxiliary power system design (Volume 3).

Forced cooling is the economical I choice, but the transformer should have a self-cooled rating so that its mechanical cooling auxiliaries do not have to operate during the long periods of no-load operation. For these reasons an OA/FA/FA or OAIFAIFOA design is often selected (Section 2.6).

The cost of no-load losses is high because the SST normally remains energized at all times. Load losses, however, have negligible value due to the low load factor.

Because of the importance of availability, it is prudent to have a spare transformer, preferably on site. That consideration weighs against selection of two different SSTs for the same unit.

For very large auxiliary power systems employing two medium voltage levels (13.8 or 6.9 kV and 4.16 kV) it may be advisable to use two half-size, three-winding transformers, with a spare capable of replacing either one. Despite rules governing impedance relationships published by some manufacturers, it is possible to purchase transformers with the desired H-X and H.:Y impedances and with an X-Y impedance very nearly equal to the sum of the other two. Such a transformer would have performance characteristics similar to those of two separate two-winding transformers. As indicated in Section 2.13, each impedance must be expressed in percent on a clearly stated kilovoltampere base.

The secondary voltage of an SST may vary over a fairly wide range because of variations in source voltage and variations in load. Under normal conditions bus voltage in the plant switchyard may

be above the nominal level. Thus, a 345-kV bus at a power plant may operate normally between 350 and 362 kV, and, under normal plant conditions, the SST may carry no load. With high primary voltage and no load the secondary voltage may approach 110% of rated voltage.

When a generating unit at high load experiences an unplanned trip, the switchyard bus voltage may decrease abruptly because of the sudden loss of that uirit's reactive power support. At the same time essentially all of the auxiliary power load of the tripped unit will be transferred automatically to the SST, producing an impedance voltage drop in that transformer and its secondary leads. Under these new conditions transformer secondary voltage may be below 95% of rating. Volume 3 contains more information on voltage profile coordination.

The SST's secondary voltage can be controlled within a much narrower range if the transformer is equipped with an LTC having automatic control (Section 2.10). Limitations of that scheme should be recognized, however.

With an LTC restoration of normal voltage following a sudden change of the type described above may take more than 60 s. Any emergency equipment served by the unit auxiliary power system that is required to start during the first part of that interval may be served with inadequate starting voltage. Addition of an LTC may also reduce transformer reliability. A preferable solution is to reduce transformer impedance to a minimum value consistent with short-circuit limitations, despite whatever effect that reduction may have on transformer cost.

LOAD CENTER SUBSTATION TRANSFORMERS

A load center substation of conventional configuration includes an assembly of LV metal-enclosed switchgear, fed by a transformer that is connected to it both mechanically and electrically, and an incoming line section (Volume 7, Au}(iliary Electrical Equipment). For indoor substations mineral oilimmersed transformers, which would be least expensive, are not used because of the fire hazard. The choices, in order of increasing cost, are ventilated dry-type transformers, liquid-immersed transformers with high-fire point fluid, and resinencapsulated transformers.

Since dry-type transformers have lower Bll.. than other types, it may be prudent, in some applications, to install surge arresters at their HV terminals.

All of these types have self-cooled ratings. Fans may be added to provide a substantial (usually one-

POWER TRANSFORMERS Z-47

third) increase in kilovoltampere rating, but voltage regulation at the forced-cooled rating may be unsatisfactory. For transformers 750 kVA and below, the forced cooling offers no advantage over using the next larger transformer at its self-cooled rating.

Sizes most commonly used to feed LV unit substations are 500, 750, and 1000 kVA. In this size range the repetitive design transformers usually have an impedance voltage of 5. 75%, although 8% is also common at 1000 kVA. Either of these values would result in secondary system fault currents within the ratings of the metal-enclosed circuit breakers in the substation and, in most cases, within the ratings of the molded-case breakers in combination starters fed from the branch circuits. However, the 9% impedance voltage, together with variations in the transformer's primary voltage, may leave only a very small margin for voltage drops in the LV cable circuits.

TI-ansformers larger than 1000 kVA may be used in certain applications, such as for groups of large cooling-tower fans. If combination starters are used on the transformer secondary circuits, however, the molded-case circuit breakers in those starters must be suitable for the available fault current.

For mechanical draft cooling towers and other applications outside the plant building it may be feasible to depart from the secondary unit substation concept and use an outdoor, mineral oilimmersed transformer, cable connected to indoor switchgear or motor control equipment.

AUXILIARY TRANSFORMERS

The term au}(iliary transformer is used here to denote a transformer feeding a 4.16-kV subsystem from a 6.9- or 13.8-kV auxiliary bus. Since cable voltage drops are far less important on a 4.16-kV system than on an LV system, it is often feasible to install the transformer outside the plant building and to use a mineral oil-filled design. Since most such transformers have kilovoltampere ratings of 10,000 or less, low impedance will not lead to secondary fault current beyond the ratings of the switchgear. In addition impedance voltages on the order of 6% or less will be advantageous in improving voltage regtilation.

GROUNDING TRANSFORMERS

It occasionally becomes necessary to derive a neutral for grounding purposes for a system that is supplied from a delta-connected source. If the neutral is to be grounded through a resistance or


other impedance, as is the usual case for power plant auxiliary power systems, the maximum current to be carried by the grounding transformer will be the quotient of the phase-to-neutral voltage and the grounding impedance. The zerosequence impedance of the transformer itself will generally be much smaller than the impedance through which its neutral is grounded and can usually be neglected in this calculation.

Selection of a grounding transformer is illustrated by the following example. If a 2.4-0 resistor, a common choice, is used to ground the neutral of a 4.16-kV subsystem, the maximum ground fault current will be 1000 A, and the corresponding transformer kilovoltampere rating for continuous duty at that load will be 7200 A. This "lowresistance" neutral grounding requires rapid fault clearing by both primary and backup relaying to prevent serious damage at the point of fault. For that reason 7200 kVA can be a short-time rating of the transformer rather than a continuous rating. The remainder of this analysis applies to low-resistance neutral grounding. It would not be applicable to a neutral for a three-phase, four-wire system, and it might not be applicable to a solidly grounded neutral.

ANSI Standard C57.92-1981 (16) indicates that a 65°C-rise liquid-immersed transformer has a hot spot temperature rise of 80°C, a time constant for that rise of 0.08 h (288 s), a winding exponent of 0.8, and a ratio of load to no-load losses of 3.2:1. On the basis of those figures and an assumed fullload efficiency of 97%, such a transformer, following a long period at full voltage, no load, can carry more than nine times full-load current for 10 s without sacrifice of life expectancy. Since ground fault backup relays will generally operate in less than 1 s, the 10-s rating would provide a generous margin. Therefore, the grounding transformer for the application described above could have a continuous-load kilovoltampere rating as low as 800 kVA.

The grounding transformer requires only a single three-phase winding, which may be either T connected or zigzag connected; as indicated in Section 2.9.

2.16 TRANSFORMER TESTING

ANSI Standards C57.12.00-1980 (5) and C57.12.01-1979 (7) tabulate tests for liquidimmersed and dry-type transformers, respectively.

They classify each test as "routine;' "design;' or "other:' Thble 2-3 summarizes this information. Routine tests are made in the factory on all transformers; design tests are made on the first of a particular design; and other are made only when required by the purchaser.

The tests are defined in ANSI Standard C57.12.80-1978 (24), and the manner of making each test is described in ANSI Standards C57.12.90-1980 (25) and C57.12.91-1979 (7) for liquid-immersed and dry-type transformers, respectively.

SHOP TESTING

All of the tests except the short-circuit capability test on a large transformer can be made in the factory or in a well-equipped transformer repair facility. Those marked "(F)" can also be made in the field without unreasonable difficulty. Because of the magnitude of short-circuit current required, it is impractical to make through-fault tests on transformers larger than 20,000 kVA.

The purpose of the tests is to demonstrate the quality of the design and workmanship and to verify that performance guarantees have been met. In certain cases the test results provide benchmarks with which future field tests results can be compared. One test, winding resistance, calibrates the windings at a known temperature to serve as resistance temperature detectors during temperature rise tests.

Certain design tests may be specified by the purchaser for quality assurance purposes, even though similar test results may be available for an essentially duplicate transformer. In general the tests in the category other will affect price.

Switching surge tests are only made, when specified, on windings of 450-kV BIL and higher, because, for windings of lower BIL, switching surges in service are not expected to produce significant transient overvoltages.

Front-of-wave impulse tests are specified by certain purchasers who install rod gaps for bushing protection.

Radio influence voltage tests were initially developed as a result of utility customer complaints of interference with radio reception. Experience convinced both manufacturers and purchasers that these tests were sensitive indicators of insulation quality and that high levels of radio noise often indicated a defect in design or factory workmanship likely to lead to premature failure. The magnitude of the radio noise signal measured at


Table 2.3 Transformer Tests

Resistance measurements-all windings Ratio

Polarity and phasing

No-load losses and excitation current

Impedance voltage and load loss

Zero-sequence impedance voltage

Temperature rise

Applied voltage

Induced voltage

Lightning impulse

Front-of-wave impulse

Switching impulse

Radio influence voltage

Insulation power factor

Insulation resistance

Audible sound level

Short-circuit capability

Mechanical lifting and moving devices

Pressure

Leak Oil analysis

3 D Applicable to both liquid-immersed and dry-type transformers F Field test feasible

the bushing tap has been found to decrease considerably when the initiating partial discharge is electrically remote from the bushing. Because of that and also because of European practices other methods of measurement are under study in the industry. The two promising alternatives are wideband partial discharge (picocoulomb) measurements and ultrasonic measurements at the outside surface of the transformer tank This second type of measurement may be feasible in the field and with the transformer in service. Neither method is likely to be recognized in the standards until a substantial data base has been established to replace the existing radio noise (microvolt) data base (26).

The purpose of the dielectric tests is to demonstrate the capability of the transformer insulation to withstand the test levels defined in ANSI standards. There are three dielectric withstand tests that can be performed on a transformer: the applied-potential test, the induced-potential test, and the impulse test.

The applied-potential (low-frequency) test is made to check the adequacy of the phase-to-phase and phase-to-ground insulation and the insulation between primary and secondary windings. In the case of wye-connected windings with graded insulation the applied-potential test voltage must be limited to the value appropriate for the BIL level

Routine Design Other Notes3

D, F

D. F D, F

D

D

• D

D

D

• D

•

D, F

D. F D

D

• F

of the neutral end of each winding. However, for delta-connected windings the applied-potential test may search out weaknesses in the phase-to-ground insulation.

The induced-potential test is made to check the layer-to-laye~ turn-to-turn, and section-to-section insulation.

Impulse tests are made to check the ability of the insulation to withstand impulses caused by lightning arrester or gap operation, lightning strokes, and switching disturbances.

The magnitude, duration, and wave shape of the dielectric tests, as they apply to each individual test, are described in ANSI Standards C57.12.00-1980 (5) and C57.12.01-1979 (6) for liquid-immersed and dry-type transformers, respectively. The test procedures and setups are described in ANSI Standards C57.12.90-1980 (25)

and C57.12.91-1979 (7) for liquid-immersed and dry-type transformers, respectively.

FIELD TESTING

Field testing is desirable when there is visible evidence of damage in shipment or following significant system disturbances, indications of excessive temperature rise, or operation of a gas detector relay. Some tests are desirable on a routine basis. The aim is to check the condition of the transformer


and detect any early failure warnings in order to prevent a failure in service.

In the case of liquid-immersed tranformers many incipient failures can be detected by examining and testing samples of the insulating fluid. A dark color may indicate contamination. The presence of metallic particles may indicate incipient failure of oil pump bearings. The simplest test, a voltage breakdown test, can be made in accordance with ASTM D877 or D1816, as appropriate. The first of these, which is suitable for new oil,

. requires a test cell with 1-in.-diameter circular, flat electrodes spaced 0.1 in. apart. The second is recommended for testing filtered, degassed, and dehydrated oil prior to and during the filling of power apparatus rated above 230 kV or for testing samples of such oil from apparatus after filling. This method employs a special test cell with spherical electrodes. A power factor test using a third form of test cell is considered sensitive to water or carbon contamination, and a gas-in-oil analysis, requiring sophisticated laboratory equipment, is most informative. This last form of testing is described in ANSI Standard C57.104-1978 (14).

External short circuits may distort windings or produce tum-to-turn faults. Significant permanent distortion of windings can be detected by measurement of transformer impedance and comparison with factory test results. Thrn-to-turn faults may be detected by measurement of excitation current at full voltage, rated frequency (difficult in the field), and comparison with factory test results; or they may be detected by precise turnsratio testing at low voltage. Commercial test equipment is available for this last test. It may be prudent to make such tests after the occurrence of a major through-fault.

Bushing deterioration can be detected by power factor testing at reduced voltage. Power factor testing of complete Windings may indicate the presence of moisture in solid insulation. Commercial test equipment is available for this type of testing.

Thrns-ratio tests are made at no load by applying low ac voltage to one winding and reading the voltage at the terminals of the other winding or windings of the same phase. This test should be made on all taps. Voltage ratios so found should agree with the ratios of rated voltages, as shown on the nameplate, within 0.5%. A reading outside this tolerance may indicate a turn-to-turn insulation failure. Thst devices for this purpose are available commercially.

Megger tests and· insulation power factor tests are most useful in detecting moisture in coil insulation. Since the Megger test applies de voltage

from one winding to all other windings and ground, it is important for safety reasons to ground all tested terminals for several minutes after each test in order to remove the stored charge. Insulation resistance should be on the order of 2MQ/1000 V of nameplate rating. A common practice is to take two readings, one after 1 min of voltage application and the other after 10 min. The ratio of the second reading to the first is the polarization index and should be above 1.5 if the insulation is dry .

Insulation power factor is usually measured by bridge methods in the factory and by a Doble test set in the field. The Doble test is made by applying 10,000 Vac from one winding to other windings and ground, but it should not be made at a voltage higher than winding nameplate rating. The measured power factor should be on the order of 0.5 to 1.0%. For liquid-immersed transformers Doble data may provide more precise guidance.

Oil samples may be analyzed in a number of ways, some of which require sophisticated laboratory equipment. It is important that oil samples be taken carefully in clean containers for any type of analysis. Initial samples should be discarded; they are likely to contain water and may become contaminated by their passage through sampling valves, the external portions of which may not be clean.

The simplest tests are visual inspection and voltage breakdown tests. If water can be seen clearly separated from the oil, the sample should be discarded. A dark color indicates sludging or other forms of contamination and justifies more careful testing. Metal particles suspended in the oil may indicate bearing failure in an oil pump (27).

The oil sample should withstand at least 26 kV for 1 min in a standard test cell with 1-in.-diameter circular, flat electrodes spaced 0.1 in. apart.

Oil samples can be given an acid neutralization test. Values of acidity over about 0.15 mg potassium hydroxide per gram indicate a condition favorable to the formation of sludge; values higher than 0.5 mg indicate a need for reconditioning.

An interfacial tension test, made by pulling a platinum ring through a water-oil interface in a laboratory vessel, will also reveal unsafe amounts of sludge. An interfacial tension lower than 22 dynes/em generally indicates that the oil requires reconditioning.

Gas analysis, which can be done for transformers with inert gas oil preservation systems, and gas-in-oil analysis, which can be done for all liquidimmersed transformers, are not usually performed on a routine basis. They require very careful

sampling procedures and prompt access to a gas chromatograph. The presence of combustible gases may indicate an impending insulation failure, and untanking the transformer may be advisable before it fails in service.

2.17 FOUNDATIONS

Single-block foundations for large power transformers have been found less expensive than multiple piers. The block should extend at least 6 in. beyond the transformer base and should, where possible, include the jacking pads. Where the foundation is soil bearing and more area is required than that of the block as determined by transformer base dimensions, the block may be placed on a mat of suitable size. ·

The access of grounding cables and conduits serving power transformers should be designed to permit transformer installation and removal without damage to the cables or conduits.

2.18 PROVISION FOR OIL SPILLS

Since an internal fault in an oil-immersed transformer can rupture the tank, provision may be made for confining and cooling flaming oil that could be released. An effective method of making this provision is to remove some of the soil surrounding the transformer foundation and replace it with a bed of crushed stone. The volume of such a bed should be at least 0.4 ft3/gal of oil in the tank. Because rain-washed silt may fill the interstices in the stone bed over a period of time, it may be advisable to remove the stone and screen out the silt at intervals of a few years.

Where there is insufficient space for an adequate stone bed, it may be feasible to provide a concrete basin around the transformer with drains to a nearby buried tank of suitable capacity. Such a tank must have an aboveground vent for displaced air, a liquid level indicator, and a provision for pumping out any oil or water that is collected.

2.19 FIRE WALLS AND BARRIERS

In situations in which a mineral oil-immersed transformer is installed outdoors within 50 ft of


a plant wall, it is good practice to ensure that the wall has at least a 2-h fire rating and that there are no unprotected openings within 50 ft of the transformer. Similarly, fire-restrictive barriers between oil-immersed transformers are advisable when the clearance between them is less than 25 ft. Such barriers should extend at least 1 ft above the top of the tank and 3 ft beyond the transformer at each end.

The foregoing material is for guidance only. If the installation is to be covered by fire insurance, more definitive information may be available from the insurance carrier.

Walls and barriers must be far enough from the taut-string perimeter of the transformer to permit removal of coolers or radiatiors and to allow air circulation for cooling. The taut-string perimeter is the path defined by a string drawn around the completely assembled transformer between protrusions farthest from the vertical centerline.

2.20 WATER-SPRAY FIRE PROTECTION

Savings in fire insurance premiums may justify water-spray fire protection for mineral oilimmersed transformers. In the usual form this is a dry-pipe system fed from an electrically operated deluge valve. Rate-of-rise heat detectors, possibly armed by transformer fault-detecting relays, control the deluge valve. Spray nozzles should be directed at the cover and sides of the tank and not toward bushings or lightning arresters. Heat detectors should be located away from oil coolerair discharges.

Contaminated water can cause bushing flashover during a test or during erroneous operation of the spray system. If the probability of such flashover is to be minimized, the water supplied to the spray system should have conductivity less than 1400 JlQ/cm. 1b reduce the likelihood of bushing flashover, some users provide an interlock to inhibit operation of the spray system until the transformer is deenergized. Some users use stainless steel piping, because carbon steel piping in a spray system may accumulate corrosion products during long idle periods, the products of which would contaminate the first water discharge.

Clearance between live parts and spray nozzles or piping should be at least as great as the live parts-to-ground clearances specified in National Electrical Manufacturers Association Standard TR 1-1980 (8).


2.21 INSTALLATION

The installation procedure begins when the transformer arrives on site. Before it is removed from the rail car or other vehicle that carries it, it should be examined for visible damage to the main assembly, to any of the component parts that were removed, or to any bracing added for shipment. The carrier should be advised immediately of any visible damage and should be given the opportu· nity to have a representative view the evidence. Color photographs should be taken if appropriate.

If the car or vehicle is fitted with an impact recorder, the chart should be examined by the party who might make a claim against the carrier: the shipper, in the case of sale FOB job site, or the purchaser, in the case of sale FOB factory, whether or not it was "freight allowed" or prepaid.


Any transformer with a sealed tank, shipped with oil or gas, will have been shipped under positive pressure, in most cases monitored by a pressure gage. The reading on that gage and the corresponding tank temperature should be recorded. An apparent loss of pressure may not be significant if the temperature at destination is far below 25°C (77°F). For example, a tank pressurized to 10 psig at 25°C would show 6.45 psig if it had cooled to 0°F (-17.78°C), even though there had been no leakage. Alternatively, the transformer may have been shipped with gas bottles and pressure regulator connected. In that case the bottle pressures should be noted.

Detached components should be protected in storage pending final assembly. They should be inventoried to ensure that missing parts will not interrupt assembly. Oil-f"illed bushings should be stored in a nearly upright position, which may require building special racks.

A large transformer should be moved by an experienced rigger. Where a crane lift is feasible, attachment should be made only to the lifting eyes, with appropriate slings and spreaders. Where a crane lift is not feasible, jacks may be applied (only under the jack bosses) to permit placement of rollers or greased timbers under the base. Timber cribbing or ramps may be required alongside the carrying vehicle to facilitate sliding or rolling the transformer to ground level.

An interior inspection should be made of any sealed transformer as soon as weather permits

removal of manhole covers. If the tank has been drained and filled with dry nitrogen, it must be purged with dry air to prevent any chance of suffocating personnel entering the tank. The tank should be opened only when the metal tempera· ture is above the dew point of the surrounding air in order to prevent condensation.

Clean protective clothing should be worn by anyone entering the tank, pockets should be emptied, and tools, flashlights, or other material carried into the tank should be tethered to reduce the probability of their being left inside.

During the inspection any blocking or bracing installed for protection during shipment should be identified (for removal). Any distortion or displacement of components of the assembly should also be searched out.

When the transformer has been placed on its foundation, assembly should be undertaken promptly, if possible, even though the transformer may not be required in service for several months. If inclement weather is likely during assembly, it may be advisable to erect a temporary enclosure, possibly with provision for heating.

Some very large transformers have split tanks, with the top portion replaced for shipment by a temporary flat cover. For such transformers tank reassembly will be the first step in "dressing out" the transformer. The next step will be the mounting of coolers or radiators and other components of the fluid system. Care should be taken to ensure the interior cleanliness of such components, because magnetic particles, chips, or shavings picked up in the fluid stream become "steel termites" prone to drill through coil insulation under ac magnetization of the core.

Since leaks are difficult to repair after the tank has been filled with fluid, it is prudent to replace manhole covers and perform a leak test by repressurizing the tank with dry nitrogen and monitoring the decay of pressure (temperature corrected) over a period of several days. Gas leaks can be located by brushing seams, seals, and gasketed joints with a mild soap solution and looking for bubbles.

As soon as possible the tank should be filled under vacuum with clean, tested fluid up to the level of the top of the core-and-coils assembly. Most transformer tanks are braced for full vacuum. In a few cases external stiffeners may be furnished for temporary use during vacuum fill. In any case the tank pressure limits should be shown on the transformer nameplate. Blue chalk, dusted along welds and gasketed joints below fluid level,

is a sensitive indicator of fluid leaks, because it darkens when wetted.

The bushings must be inspected, tested, and installed. The transformer oil should be tested (see Section 2.22) before the tank is completely filled. The remainder of the tank fill should again be done under vacuum to eliminate bubbles and gas pockets. If the transformer is designed for inert gas oil preservation, the gas bottles should be connected as soon as tank filling is completed. The gas valve should then be opened to break the vacuum and to establish the gas cushion over the oil. Records of gas usage should be started at this time.

Other tests should be performed to ensure that the transformer was not damaged in shipment (Section 2.16).

In situations in which it is feasible a large HV transformer should be energized at reduced voltage, rated frequency for a brief period before full voltage is applied. During this period transformer performance should be monitored to the extent permitted by available indicators and transducers.


Installation of dry-type transformers does not in general require special procedures beyond those appropriate to the installation of other electrical apparatus. Prior to placement in service, however, special care should be taken to keep the transformer dry. Thmporary space heaters may be required. The transformer should not be energized at full voltage until insulation resistance or power factor tests have confirmed that the insulation is dry. Thereafter, the no-load losses will maintain core-and-coil temperatures above the dew point.

2.22 MAINTENANCE

A correctly installed transformer operated within its ratings and properly maintained should have a life expectancy of 20 to 40 years. Maintenance, in most cases, is neither costly nor time consuming. Some of it can be done while the transformer is in service. It should, however, be done on a regular schedule, and careful records should be kept.

The first step in any maintenance program should be to read the manufacturer's maintenance instructions. These may differ from those of other manufacturers or even from previous instructions

· from the same manufacturer.


Nearly all transformer failures are dielectric failures, but the root cause usually lies elsewhere. Successful maintenance programs discover and eliminate root causes before they cause damage.

VISUAL INSPECTION

Every transformer should be inspected visually at regular intervals. The length of those intervals varies from company to company, depending on prior experience, severity of service, and harshness of environment.

On most dry-type transformers there is little to inspect, but on ventilated dry-types the grounding, terminal, and tap connections are visible, and any buildup of lint or dust that might impede the flow of cooling air can be seen. However, even on. dry-types, abnormal ambient temperature or noise may not be detected during visual inspection.

The gages of liquid-immersed transformers should be read and their readings recorded. Following is a list of suggested observations and readings for a large, forced-cooled, liquid-immersed transformer:

Observations

• Oil leaks (tanks, coolers, piping, bushings) • Loose terminal connections • Loose grounding connections • Water leaks (water-cooled transformers) • Fans in inoperative condition • Paint deterioration • Pressure relief semaphore raised • Bushing-oil level low in sight glasses • Chipped or soiled bushings or lightning

arresters • Abnormal conditions in cooler control

cabinet • Audible corona discharge • High sound level

Indicators

• Th.nk pressure • Th.nk liquid level • Thp liquid temperature • Winding (hot spot) temperature • liquid flow at each pump • lightning arrester discharge counters • Nitrogen bottle pressures (inert gas system) • Fault gas monitors

In addition to the visual inspections some transformer testing can be done in the field (Section 2.16).


'Iransformers with LTCs require additional maintenance of this electromechanical equipment, which can be done only with the transformer out of service. One manufacturer recommends that the first detailed inspection be done after the first year of operation. 'Iransformers with LTCs also have insulating fluid systems for the LTC that are separate from those for the core and coils and that can be sampled while the transformer is in service. In general annual inspection may suffice unless the application requires very frequent tap changes. Owners of LTC transformers would be well advised to plan their maintenance schedules on the basis of frequency of tap-changing operations and to perform maintenance in accordance with the relevant maintenance instructions.

OIL CONDITIONING

Periodically taken oil samples are expected to withstand approximately 30 kV in the standard test cup. Breakdown below 26 kV is generally regarded as unsatisfactory. Water, sludge, and other forms of contamination can often be removed, even with the transformer in service, by circulating heated oil through a transportable oil-conditioning system while testing repeatedly to monitor the improvement. Such a system may include heaters, Fuller's earth beds, and a vacuum dehydrator.

GASING

Significant evolution of bubbles or concentration of gases dissolved in oil requires close monitoring and may dictate taking the transformer out of service for further investigation (14). The gas may be produced by decomposition of oil or of cellulosic insulating materials due to local heating. If the problem cannot be localized by tests in the field (Section 2.16), it may be necessary to remove the transformer to a service shop, where more sophisticated diagnostic procedures and, ultimately, untanking may be feasible.

DRYOUT

If the kraft paper insulation of any transformer has absorbed a significant amount of water (a condition that may be diagnosed by insulation power factor or even Megger testing), it may be necessary to employ a combination of methods, including heating, to dry it out. In general dryout can be accomplished without untanking. The most common method of heating is circulating alternating current

through the windings at low voltage. This procedure must be carried out with care to avoid the formation of hot spots that may degrade the insulation. The heating must be combined with vacuum or other methods to remove the moist vapor. Each manufacturer can furnish detailed procedures for such operations.

CLEANING BUSHINGS

Outdoor apparatus bushings have skirted, glazedporcelain rain shields to provide a long surfaceleakage path from terminal to flange. In areas where the air is contaminated with particulate matter, the porcelain may collect a heavy coating of dust, which will become conductive when wet and can lead to bushing flashover. The porcelain should be cleaned as often as necessary with a nontoxic solvent. Some users have found that a coating of silicone grease will break up the conductive leakage path and thus prolong the interval between washings.

•

APPENDIX A

LOSS EVALUATION

In both indoor and outdoor applications transformer losses incur significant future cost beyond that attributable to heat removal. That cost has two components: a demand cost and an energy cost.

The demand cost is based on the amount of gross ge~erating capacity that the losses make unavailable to the power system for meeting its peak customer demand. The aggregate level of such power losses will ultimately require that a new generating unit be added to the system one year earlier than would otherwise be necessary. Thus, the demand penalty to be invoked for losses is based on their magnitude under peak system load conditions and on the dollars-per-kilowatt cost of new generating capacity.

The energy cost of losses is based on the delivered cost of extra fuel burned to generate the loss energy. All other components of generating cost, such as fixed charges, maintenance, and operating costs other than fuel, are essentially unaffected by the incremental kilowatthour production.

Fuel use on the system is not directly proportional to electrical load. Each generating unit is more efficient near full load than at light load. At no load a turbine requires input energy to overcome losses from several sources: friction and windage losses incurred in running the turbine generator and many of its auxiliaries at full speed; throttling losses in partially open inlet steam valves; pump and piping losses in the circulatingwater system incurred in maintaining condenser va~um; and heat losses incurred in maintaining masses of metal at high operating temperatures. The result is that lightly loaded generating units are inefficient. Their average fuel cost in cents per kilowatthour is high. Near full load inlet steam throttling losses are reduced because the valves are nearly wide open. On some turbines, however, a new form of loss appears near full load: a discharge loss caused by "choking" in the exhaust annulus at high steam fiow. Nevertheless, the aggregate of all losses at full load becomes a small fraction of the total input, most of which then produces useful output. The result is that heavily loaded generating units are more efficient than lightly loaded units. Their average fuel cost in cents per kilowatthour is lower.

Incrementally, fuel cost is different. When a unit moves away from the no-load condition, fuel use increases slowly in essentially direct proportion to load added. This rate, also measured in cents per kilowatthour, remains nearly constant up to the point at which choking begins. Somewhere near full load average fuel cost, which has been decreasing, and incremental fuel cost, which has started to rise, become equal.

It is not feasible to operate all generating units near their full-load point at all times. Inevitably, some units will be lightly loaded. They must be on the line, however, to provide "spinning reserve" to meet rapid increases in customer demand or to replace a unit that trips off the line because of a malfunction.

At any given time the system load dispatcher arranges to have enough generating capacity online to satisfy the customer demand expected during the next few hours, to supply the system losses associated with that load flow, and to provide appropriate spinning reserve. The system load dispatcher must then apportion the load among the operating units in such a way as to achieve minimum production cost. The manner in which that load dispatching is done is germane to the subject of loss evaluation.

Load dispatching is a computer-aided process in which each kilowatt of new load is assigned by automatic load-frequency control equipment to the generating unit that can supply it at lowest incremental cost. Similarly, any load reduction, including a reduction in system losses, reduces production cost at the incremental rate. The result is that all generating units adjust, within their stable operating limits, to the incremental fuel cost, which is then the system incremental cost for that load condition. The system incremental fuel cost for a given combination of operating units always increases with system load.

'li'ansformer losses are a partially avoidable increment of load on the system. A reduction of those losses reduces system fuel cost at the incremental rate. If average fuel costs were used in loss evaluation, it would lead to a larger initial outlay for loss reduction than can be justified by the future fuel savings that are likely to result.


As previously explained, transformer load losses vary as the square of transformer load current. When the energy value of the losses is determined, it is not necessary to establish the time of day when they reach a particular level as long as there is a fairly well defined relationship between transformer loss magnitude and system load, which provides a key to incremental fuel cost.

1ransformer no-load losses remain essentially constant during all of the hours the transformer is energized. Their energy value is therefore related to the annual average system incremental fuel cost.

When loss values for a transformer at a nuclear power plant are established, it is not appropriate to use the incremental fuel cost at that plant, because the nuclear units are base loaded whenever possible. The loss energy, in effect, is produced elsewhere by generating units having higher incremental fuel cost.

1b justify consideration of these complexities, one need only recognize that the present worth of losses over the life of a large UT is generally greater than the initial cost of the transformer.

PRESENT WORTH OF FUTURE COSTS

The present worth of a future cost depends on (1) the magnitude of that cost at current cost lev~ els; (2) the year in which the cost will be incurred; (3) the anticipated rate of inflation; and (4) the owning company's internal rate of return (IROR).

Cl = (1 + jJM X P£(1 + jJ/(1 + k)JM (Eq. A·l)

Where:

CI = present worth of the outlay in the year of first commercial operation

f = annual inflation rate (decimal)

P = quoted or estimated price, valid in the "price year"

M = number of years between the price year and the year of first commercial operation

N2 = 1 greater than the number of years between commercial operation and payment (It is 1

greater to reflect the convention of beginning-of-year measurement of end-of-year cash flow.)

k = IROR expressed as a decimal rather than as a percentage

Inflation Inflation must be considered in evaluating any series of costs extending some years into

the future, because the components of present worth may not be affected equally by inflation. A $100,000 loan at 8% interest will cost $8000 per year, regardless of inflation. But 100 t of coal, which might cost $6000 this year, are likely to cost more in each future year.

Price Year Future costs may be estimated at the levels prevailing on the day of the estimate or on historical record. The price year is that year in which the estimate was valid.

IROR IROR, expressed as a percentage, is a function of capitalization structure, cost of money, and statutory tax rate. The proper worth to use in loss evaluation should be obtained from a financial officer of the company owning the plant. IROR cannot be calculated from fixed charge rate.

Fuel Cost Attributable to Transformer Loss· Energy It is customary to predict the future loading of a new generating unit by constructing a table of the kind shown below:

Percentage of Time at Each Load

Period in 100% 75% 50% 250Al 0% Years Load Load Load Load Load -- -1 30 40 10 0 20 2-5 60 10 15 0 15 6-10 50 20 15 0 15 11-15 40 25 20 0 15 16-30 20 6 20 22 32

It is necessary to combine all the numbers in this table into a single number that will represent the present worth of future energy cost per kilowatt of no-load loss and to combine them in a slightly different manner for each kilowatt of (fullload) loss.

For no-load loss the kilowatthours for each year are found by adding together the operating hours for that year. Thus, for the thirtieth year the unit will be in operation 68% of the time. Each kilowatt of no-load loss will be present 0.68 times 8760, or 5957 h. It will therefore consume 5957 kWh of electrical energy in that year. If the system annual average incremental fuel cost is $0.027 (price year cost) per kilowatthour, the cost of fuel will be 5957 times 0.027, or $160.83 for each kilowatt of loss.

For transformer load loss the calculation becomes more complex, because load loss, which includes P.R loss and stray losses, varies as the square of load, becoming equal to the measured value only at rated load, and because each quantity of loss will occur at a different system incremental

fuel cost. Thus, the hours at 25% load will be multiplied by 0.0625, those at 50% by 0.25, and those at 75% by 0.5625 to find the kilowatthours for that year.

Each product must then be multiplied by the applicable incremental fuel cost. Except for hydroelectric plants and nuclear plants, it is assumed that a generating unit will operate at 50% load when its incremental fuel cost at that load matches the system incremental fuel cost for that system load condition. The incremental fuel cost for the unit can be calculated from the net station incremental heat rate at that load and the applicable fuel cost per British thermal unit.

For example, assume that the incremental heat rates for the unit at 100, 75, 50, and 25% load are 12,000, 10,000, 9180, and 8770 Btu/kWh, respectively, and the fuel cost is $2.50 (price year per million Btu). Then, if the unit (and its UT) are at 50% load, it is because the system incremental fuel cost is $2.50 times 0.00918, or $0.0295/kWh. The extra fuel cost incurred in the thirtieth year by 1 kW of (full-load) loss during the 20% of time in which the unit is at 50% load will be:

0.20 X 8760 X 0.25 X 0.0295 = $10.05

Adding costs similarly calculated for other loads during that year brings the total to $72.64/kW of (full-load) load loss. The totals for each of the earlier 29 years can be calculated in a similar manner. When these annual totals are summed, however, each must be increased to account for escalation and discounted at the IROR rate.

Combining Future Costs The present worth is expressed in Equation A-1.

An example will illustrate the use of this expression in finding the present worth of fuel cost increment attributable to 1 kW of (full-load) transformer load loss in the thirtieth year. Assume that the plant will go into operation in 1990 and that fuel costs are based on 1984 prices. Then N1 = 6. For the year 2020 N2 = 30. Assume fuel cost escalation rate is 6% and IROR is 12.5%.

CI = (1 + 0.06)6 X 72.64 ((1 + 0.06)/(1 + 0.125)]30

= 1.4185 X 72.64 X 0.1677 = $17.28

When the fuel cost increments for all earlier years have been adjusted similarly, they can be summed to fmd the total present worth of fuel cost attributable to 1 kW of transformer (full-load) load loss.

Thble A-1 shows a sample calculation for the 30-year period. It may be noted that, for the first


5 years, the present worth is greater than the "cost:' These higher present worths occur because the cost shown· here is based on 1984 fuel cost. The present-worth column shows these values increased by inflation and discounted at the IROR rate. The combined effect of these two multipliers, starting from the first year of commercial operation, is to overtake in the sixth year the escalation that occurred between the price year and the operating date.

The totals at the bottom of the present-worth columns must be added to the demand cost to obtain the total present worth per kilowatt of each type of loss.


Table A-1 Transformer Loss Energy Evaluation

Year of commercial operation 1990 Incremental net station heat rate, Fuel cost, cents per million Btu 250 cents per million Btu Fuel price year 1984 Fuel cost escalation rate, percentage 6.00 12,000 at 100% load System average incremental fuel cost. 10,000 at 75% load

cents per kilowatthour 2.70 9,180 at 50% load Internal rate of return, percentage 12.50 8,170 at 25% load

Projected Unit-loading Schedule Calculated Results per kilowatt of Full-Load Loss

Percentage of Time at Each Load Iron Copper 100% 75% 50% 25% 0% Present Present

Year Load Load Load Load Load Cost Value Cost Value

1 30 40 10 0 20 189.22 252.90 133.14 177.95 2 60 10 15 0 15 201.04 253.18 177.54 223.58 3 60 10 15 0 15 201.04 238.55 177.54 210.66 4 60 10 15 0 15 201.04 224.77 177.54 198.49 5 60 10 15 0 15 201.04 211.78 177.54 187.02 6 50 20 15 0 15 201.04 199.55 163.58 162.36

7 50 20 15 0 15 201.04 188.02 163.58 152.98 8 50 20 .15 0 15 201.04 177.15 163.59 144.14 9 50 20 15 0 15 201.04 166.92 163.58 135.81

10 50 20 15 0 15 201.04 157.27 163.58 127.96 11 40 25 20 0 15 201.04 148.19 145.97 107.59 12 40 25 20 0 15 201.04 139.62 145.97 101.38

13 40 25 20 0 15 201.04 131.56 145.97 95.52 14 40 25 20 0 15 201.04 123.96 145.97 90.00 15 40 25 20 0 15 201.04 116.79 145.97 84.80 16 20 6 20 22 32 160.83 88.04 72.64 39.76 17 20 6 20 22 32 160.83 82.95 72.64 37.47 18 20 6 20 22 32 160.83 78.16 72.64 35.30

19 20 6 20 22 32 160.83 73.64 72.64 33.26 20 20 6 20 22 32 160.83 69.39 72.64 31.34 21 20 6 20 22 32 160.83 65.38 72.64 29.53 22 20 6 20 22 32 160.83 61.60 72.64 27.82 23 20 6 20 22 32 160.83 58.04 72.64 26.22 24 20 6 20 22 32 160.83 54.69 72.64 24.70

25 20 6 20 22 32 160.83 51.53 72.64 23.27 26 20 6 20 22 32 160.83 48.55 72.64 21.93 27 20 6 20 22 32 160.83 45.75 72.64 20.66 28 20 6 20 22 32 160.83 43.10 72.64 19.47 29 20 6 20 22 32 160.83 40.61 72.64 18.34 30 20 6 20 22 32 160.83 38.27 72.64 17.28

REFERENCES

1. U.S. Congress. Th;dc Substances Control Act. Washington, D.C.: Government Printing Office, Octeber 12, 1976. 15 USC 2601, et seq., PL 94-469.

2. Code of Federal Regulations. "Protection of Environment: Polychlorinated Biphenols (PCBs) Manufacturing, Processing, and Distribution in Commerce, and Use Prohibitions:' Washington, D.C.: Government Printing Office, June 7, 1978. 40CFR761.

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11. Standard Electrical, Dimensional and Related Requirements for Outdoor Apparatus Bushings. New York: Institute of Electrical and Electronics Engineers, 1984. IEEE Std. 24-1984.

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Installation, Application, Operation, and Maintenance of Dry-'J}pe General-Purpose Power and Distribution 'Iransformers. New York: American National Standards Institute, 1982. ANSI Std. C57.94-1982.

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PCB Removal From 'Iransformers. Palo Alto, Calif.: Electric Power Research Institute, May 1984. EL-3345.

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BIBLIOGRAPHY 2-63

INDEX

AA!FA, 2·7 Abnormal conditions, 2-1, 2-53 Alarm switches, 2-18, 2-20 Altitudes, 2-4, 2·22, 2·25 Ambient temperature, 2·3, 2-4,

2·5, 2-8, 2·22, 2-25, 2-53 Arrester ratings, 2-22 Arrester voltage ratings, 2-5 Arrhenius curve, 2-22 Askarel, 2-3 Autotransformer, 2-14

Barrier wall, 2·31 Basic impulse insulation level

(BIL), 2-1, 2-5, 2-12, 2-16, 2-46, 2-47, 2-48, 2-49

Bushing current transformers, 2-20

Bushing deterioration, 2·50 Bushing flashover, 2-51, 2-54 Bushing maintenance, 2-17 Bushing potential tap, 2-15 Bushings, 2-8, 2·9, 2·15, 2-16, 2-20,

2·29, 2·31, 2-32, 2-48, 2-49, 2-51, 2-52, 2-53, 2·54

Cast-coil, 2-4 Combustible gas monitor, 2-21 Condenser-type bushings, 2-15 Connections for transformers,

2-46 Conservator, 2-8, 2-9, 2-10, 2-18 Conservator system, 2-8, 2-9, 2-10 Cooling auxiliaries, 2-1, 2-6, 2-7,

2·32, 2-46 Cooling fans, 2·3 Creepage path, 2-15 Current transformers, 2·18, 2-20,

2·21

Delta connection, 2-12 Demand factor, 2-1 Design center, 2-36, 2-40, 2-41,

2-43 Design tests, 2-48 Dielectric constant, 2-3 Dielectric strength, 2·2, 2-3, 2-8,

2·9, 2-25 Dielectric stress, 2-9 Dielectric tests, 2-49 Diversity factor, 2-1 Doble test, 2-50

Double-wall tanks, 2-31 Dressing out the transformer, 2-52 Dry nitrogen, 2-9, 2-15, 2-32, 2-52 Dry-type transformers, 2-1, 2-3,

2-4, 2-5, 2-7, 2·8, 2·18, 2-23, 2-25, 2·47, 2-48, 2-49, 2-53

Eddy-current loss, 2-1, 2-7, 2-8, 2·25

Efficiencies, 2-4, 2-7 Energy losses, 2-1, 2-2 Excitation current, 2-25, 2-50

Factory test report, 2-25, 2-27 Fans, 2-3, 2-6, 2-7, 2-24, 2-31, 2-47,

2-53 Fault pressure relay, 2-20 Field testing, 2-49 Fire hazard considerations, 2-3 Fireproof vaults, 2·3 Fire protection, 2·31, 2-33, 2·51 Forced-air (FOA), 2-6, 2-7, 2-31,

2·32, 2-46 Forced-air cooling, 2-1 Forced-cooled transformers, 2·1,

2-7, 2-53 Forced-water (FOW), 2·1, 2·6, 2-7,

2-32 Forced-water cooling, 2·1 Foundations, 2-51 Four windings, 2-25 Fuller's earth beds, 2-54 Full-load losses, 2-5, 2-27

Gas analysis, 2·21, 2-50. Gas detector, 2-21, 2-49 Gas-filled designs, 2-3 Gas formation, 2-1 Gas monitors, 2·1, 2·21, 2-53 Generator breaker, 2-6, 2·25, 2·26,

2-46 Graded insulation, 2-2, 2-12, 2·13,

2-49 Grounded wye, 2-11, 2-12 Grounding cap, 2-15 Grounding transformers, 2-10,

2-13, 2·14, 2-47, 2-48

Half-size three-phase units, 2-33 Harmonic current, 2-27 Harmonic factor, 2-2, 2-4, 2-27 Harsh environments, 2-4 Heat detectors, 2·51

Heat exchangers, 2-3, 2-7 Heat transfer, 2-3 Helmholz resonators, 2-31 High-current bushings, 2-16 High-impedance transformer, 2-26 Hydroelectric power plant, 2-7,

2·25, 2-26, 2·57 Hysteresis loss, 2-2, 2-7, 2-8, 2-25

Impact recorders, 2-32, 2-52 Impedance, 2·2, 2-5, 2·12, 2·14,

2-15, 2-25, 2-28, 2·29, 2-30, 2·31, 2-33, 2-35, 2·36, 2-37, 2-38, 2-41, 2-42, 2-43, 2-45, 2-46, 2-47, 2-48, 2-50

Impedance relationships, 2-46 Impedance tolerance, 2-25 Impedance voltage, 2·2, 2-5, 2-14,

2-25, 2-28, 2·38, 2-41, 2-47 Impulse tests, 2-1, 2-48, 2-49 Impulse voltage, 2-3, 2-5, 2-31,

2-35, 2-46 Incipient failures, 2-50 Inert gas system, 2-8, 2·9, 2·53 Insulating fluids, 2-1, 2-15, 2·18,

2-50, 2·54 Insulation temperature, 2-22 Internal arc, 2·20

Jack bosses, 2-22, 2-52

Kraft paper insulation, 2-15, 2-54

Leakage path, 2·54 Leakage reactance, 2-28, 2-43 Life-cycle cost, 2· 7 Life expectancies, 2-4, 2·8, 2·23,

2-26, 2-48, 2·53 Lifting eyes, 2-22, 2-52 Lightning, 2-1, 2-2, 2-3, 2·5, 2-10,

2-22, 2-49, 2-51, 2-53 Lightning and switching surge

impulse voltages, 2-3 Lightning arresters, 2·2, 2-5, 2-10,

2·22, 2-49, 2-51, 2·53 Lightning strikes, 2-5 Liquid-immersed transformers,

2·1, 2-2, 2-3, 2-4, 2·5, 2·7, 2·15, 2-18, 2-25, 2-32, 2-46, 2-47, 2-48, 2-49, 2·50, 2·52, 2-53

Liquid level gage, 2-10, 2-18 Load center substation, 2-47 Load growth, 2-23, 2-24

2-66 INDEX

Load limits, 2-4 Load losses, 2-4, 2-7, 2-8, 2-27,

2-28, 2-30, 2-45, 2-46, 2-48, 2-56

Load rejection, 2-26 Local hot spots, 2-1 Loss evaluation, 2-7, 2-22, 2-30,

2-55, 2-56 Loss of life, 2-4 Loss reduction, 2-7, 2-8, 2-55 Low impedance, 2-6, 2-12, 2-25,

2-29, 2-43, 2-47 Low-impedance transformer, 2-6

Magnetostriction, 2-8, 2-31 Main transformer, 2-10 Manufacturing tolerances, 2-45 Masonry vaults, 2-7, 2-31 Megavars, 2-35, 2-36 Megger tests, 2-50, 2-54 Mineral oil immersed, 2-1, 2-5,

2-32, 2-47, 2-51 Multiratio ratings, 2-20

Nameplate, 2-4, 2-11, 2-24, 2-25, 2-26, 2-37, 2-38, 2-43, 2-46, 2-50, 2-52

Nameplate kilovoltamperes, 2-4 Nameplate loads, 2-23 Nitrogen, 2-9, 2-32, 2-52, 2-53 Noise control, 2-7, 2-30 Noise criteria, 2-22, 2-30 Noise measurements, 2-31 Noise ordinances, 2-30 Noise sources, 2-30 No-load losses, 2-7, 2-8, 2-27, 2-30,

2-31, 2-46, 2-48, 2-53, 2-56 No-load tap changers, 2-2, 2-14 Nonflammable fluids, 2-3 Normal station service

transformer, 2-11

Oil level gages, 2-15, 2-16 Oilpreservation systems, 2-1, 2-8,

2-18, 2-50 Oil pumps, 2-6, 2-7, 2-50 Oil reservoir, 2-18 Oil samples, 2-1, 2-50, 2-54 Oil spills, 2-3, 2-31, 2-33, 2-51 Operating conditions, 2-4, 2-5,

2-25, 2-33, 2-43 Output megawatts, 2-35, 2-35, 2-36 Overexcitation, 2-25, 2-26, 2-38 Overload effects, 2-23 Overpressure, 2-9 Oversize transformer, 2-40

Performance calculations, 2-43, 2-44

Performance graphic, 2-35

Phase angle, 2-30 Phase angle difference, 2-30 Phasing, 2-10, 2-11, 2-13, 2-22,

2-29, 2-46 Phasing out three-phase circuits,

2-29 Phasing relationshp, 2-11 Phasor diagrams, 2-11, 2-43 Polarity or connections, 2-29 Polychlorinated biphenyl (PCB), 2-3 Polyphase, 2-3 Porcelain rain shield, 2-15, 2-16,

2-54 Power factor tap, 2-15 Power factor test, 2-50, 2-53 Power-frequency voltages, 2-5 Pressure relief devices, 2-10, 2-21 Primary voltage rating, 2-35, 2-36,

2-38, 2-40, 2-43, 2-44

Radiators, 2-6, 2-32, 2-51, 2-52 Radio influence voltage tests, 2-2,

2-48 Rating basis, 2-2, 2-4, 2-45 Rating selections, 2-36 Ratio error, 2-45 Reactive power, 2-27, 2-30, 2-33,

2-36, 2-37, 2-38, 2-39, 2-40, 2-41, 2-42, 2-43, 2-44, 2-45, 2-47

Real and reactive power losses, 2-33, 2-41, 2-45

Real power output, 2-33, 2-36, 2-39

Rectifiers, 2-27 Regulation, 2-28 Reliability, 2-1, 2-15, 2-43, 2-46,

2-47 Remote indication, 2-20 Reserve station service

transformer, 2-11 Resin-encapsulated design, 2-4 Resin-encapsulated transformers,

2-1, 2-47 Routine tests, 2-48

Sealed-tank designs, 2-3 Secondary leads impedance, 2-15,

2-29 Secondary unit substation

transformers, 2-1, 2-7, 2-14 Secondary voltage, 2-4, 2-12, 2-15,

2-25, 2-26, 2-28, 2-31, 2-35, 2-36, 2-38, 2-43, 2-44, 2-46, 2-47

Selection of size, 2-33 Selection of transformer ratings,

2-36 Self-cooled transformers, 2-1

Shipping considerations, 2-32 Shipping limitations, 2-7, 2-16,

2-32, 2-34 Shop testing, 2-48 Short circuit, 2-1, 2-29, 2-50 Short-circuit current, 2-23, 2-29,

2-48 Short-circuit limitations, 2-47 Short-circuit requirements, 2-29 Short-time overloads, 2-23, 2-24 Single-phase designs, 2-1 Single-phase units, 2-11, 2-33 Sinusoidal capacity, 2-28 Sinusoidal waveform, 2-27 Specifications, 2-4, 2-16, 2-25, 2-26,

2-27 Startup transformer, 2-11 Station service transformer (SST),

2-1, 2-2, 2-6, 2-8, 2-11, 2-12, 2-15, 2-16, 2-25, 2-29, 2-30, 2-46, 2-47

Stray currents, 2-32 Stray loss, 2-7, 2-27, 2-28, 2-43, 2-56 Substation transformers, 2-8, 2-30,

2-33, 2-46 Sudden pressure, 2-20 Surge arresters, 2-2, 2-3, 2-47 Surge voltages, 2-2, 2-22 Switching surge tests, 2-48 System voltage, 2-23, 2-33, 2-36,

2-39, 2-42, 2-45

lank rupture, 2-3 lap changing, 2-14, 2-43, 2-54 lap position, 2-15 laps, 2-4, 2-14, 2-15, 2-20, 2-28,

2-39, 2-40, 2-43, 2-46, 2-54 laut-string perimeter, 2-51 T connection, 2-10, 2-14 Thmperature indicators, 2-18, 2-2{) Thmperature rise, 2-3, 2-4, 2-5,

2-8, 2-18, 2-25, 2-26, 2-27, 2-45, 2-48, 2-49

Thrtiary, 2-12, 2-25 Thsts, 2-1, 2-4, 2-25, 2-29, 2-30,

2-48, 2-49, 2-53 Thermal aging, 2-29 Thermal expansion, 2-15, 2-22 Third-harmonic currents, 2-12 Three-phase designs, 2-1 Three-phase units, 2-11, 2-33 Three-winding transformers, 2-25,

2-46 Through-faults, 2-4, 2-22, 2-23,

2-29, 2-45, 2-48, 2-50 1bp oil temperature, 2-18, 2-20 1btally enclosed, 2-3, 2-4 1btally enclosed nonventilated

designs, 2-3

'Iransformer oil, 2-1, 2-16, 2-53 'Iransformer parameters, 2-33,

2-35, 2-36, 2-41, 2-42 'Iransformer regulation, 2-28 'Iransformer selection, 2-24, 2-35,

2-36 'Iransient overvoltages, 2-3, 2-5,

2-22, 2-26, 2-45, 2-48 'Iriple-rated transformer, 2-5, 2-6,

2-28, 2-32 1\Jrns-ratio testing, 2-50 'fum-to-turn faults, 2-50 1\vo-winding designs, 2-25

Unit auxiliaries transformer (UAT), 2-1, 2-3, 2-6, 2-11, 2-12, 2-16, 2-25, 2-26, 2-29, 2,30, 2-32, 2-33, 2-43, 2-44, 2-45, 2-46

Unit transformer (UT), 2-1, 2-3, 2-6, 2-10, 2-11, 2-12, 2-14, 2-16, 2-25, 2-26, 2-30, 2-31, 2-32, 2-33, 2-34, 2-35, 2-36, 2-37, 2-41, 2-43, 2-44, 2-45, 2-46, 2-56

Untanking, 2-51, 2-54

Vacuum dehydrator, 2-54 Vapor-cooled transformer, 2-3 Variable-speed drives, 2-26 Vaults, 2-31 Ventilated designs, 2-3 Ventilated dry-type transformers,

2-3, 2-4, 2-47, 2-53 Vibration, 2-4, 2-20, 2-22, 2-30 Voltage breakdown test, 2-50 Voltage gradients, 2-8, 2-15 Voltage profiles, 2-38, 2-47 Voltage regulation, 2-22, 2-27,

2-28, 2-42, 2-47 Voltage regulator, 2-14, 2-26, 2-31,

2-45 Volts-per-hertz protection, 2-26

Water leakage into the oil, 2-7 Water-spray fire protection, 2-51 Waveform distortion, 2-4, 2-26 Winding configurations, 2-25 Winding temperature, 2-18, 2-25 Withstand capability, 2-5, 2-26 Wye connection, 2-14 Wye-wye transformer, 2-12, 2-25 Wye-zigzag design, 2-13

Zero-sequence, 2-12, 2-25, 2-48 Zig-zag connected secondary, 2-13

INDEX Z-67

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