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IEEE PC57.127/D10.0, December 29, 2006

Copyright 2006 IEEE. All rights reserved.

This is an unapproved IEEE Standards Draft, subject to change. 1

Draft Guide for the Detection and Location ofAcoustic Emissions from Partial Discharges in Oil-Immersed Power Transformers and Reactors

Sponsored by the

Transformers Committee

of the

IEEE Power Engineering Society

Copyright 2006 by the Institute of Electrical and Electronics Engineers, Inc.

Three Park Avenue

New York, New York 10016-5997, USA

All rights reserved.

This document is an unapproved draft of a proposed IEEE Standard. As such, this document is subject to change.

USE AT YOUR OWN RISK! Because this is an unapproved draft, this document must not be utilized for any

conformance/compliance purposes. Permission is hereby granted for IEEE Standards Committee participants to

reproduce this document for purposes of IEEE standardization activities only. Prior to submitting this document to

another standards development organization for standardization activities, permission must first be obtained from

the Manager, Standards Licensing and Contracts, IEEE Standards Activities Department. Other entities seeking

permission to reproduce this document, in whole or in part, must obtain permission from the Manager, StandardsLicensing and Contracts, IEEE Standards Activities Department.

IEEE Standards Activities Department

Standards Licensing and Contracts

445 Hoes Lane, P.O. Box 1331

Piscataway, NJ 08855-1331, USA

Abstract: This guide is applicable to the detection and location of acoustic emissions from partial discharges and

other sources in oil immersed power transformers and reactors. It is intended to provide a means of associating the

relative magnitude and position of partial discharges and other sources with the acoustic signals obtained by

strategically located transducers.

Keywords:acoustic emission (AE), attenuation, burst, gas-in-oil analysis, low-amplitude discharges, partial

discharge (PD), power transformers, reactors.

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Copyright 2006 IEEE. All rights reserved

This is an unapproved IEEE Standard subject to change

2

Introduction

This introduction is not part of IEEE xxxxxx, Guide for the Detection and Location of Acoustic Emissions from

Partial Discharges in Oil - Immersed Power Transformers and Reactors. The Guide is an expansion of PC57.127

Trial Use Guide for the Detection of Acoustic Emissions from Partial Discharges in Oil-Immersed Power

Transformers. It has been expanded to include more theory and signal interpretation information, newer techniques

for detection and the concepts for location. Active workers in the field are constantly trying to improve their

methods. More effective methods may appear in the future.

Participants

At the time this guide was completed, the Working Group on Acoustic Partial Discharge Tests in Transformers had

the following membership:

John W. Harley, Chair

Donald Ayers

Ron Barker

Ray Bartnikas

Barry BeasterJeff Benach

Tord Bengtsson

Paul Boman

John Bosiger

Carl Bush

Alvaro Cancino

William Carter

Yunxiang Chen

Bill Chiu

Roy Colquitt

Jerry Corkran

John Crouse

Alan Darwin

Ron Daubert

Fred Elliott

Don Fallon

Norman Field

Michael Franchek

Jim Fyvie

Robert Ganser

Andreas Garnitschnig

Richard Graham

William GriesackerSergio Guerrero

Ernst Hanique

Tom Harbaugh

Peter Heinzig

Keith Highton

Thang Hochanh

John Holland

Anthony Jonatti

Steve Jordan

Samer Khaled

Vladimir Khalin

Emil Kowal

John Lackey

Robert Langan

Mike Lau

Eberhard Lemke

Raymond Lortie

Richard Lowe

Andre Lux

Tamyres Luiz Machado

Jim McIver

Martin Navarro

Van Nhi NguyenArturo Nunez

Mark Perkins

Paul Pillitteri

Bertrand Poulin

Gustav Preininger

George Reitter

John Runski

Dirk Russwurm

Ewald Schweiger

Hemchandra Shertukde

James Smith

Brian Sparling

Charles Sweetser

Ed Tenyenhuis

Subhash Tuli

Albert Walls

Barry Ward

Eduardo Garcia Wild

Others who were active in the writing of this guide are:

Pierre Boss

Ed Cromer

Michel Duval

George Forrest

Valery Godinez

David Goodwin

Lars-Erik Juhlin

Stanley Lindgren

Adrian Pollock

Karen Weissman

The following persons were on the balloting committee:

(To be supplied by IEEE Standards Project Editor at time of publication)

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3

Patents

Attention is called to the possibility that implementation of this standard may require use of subject matter covered

by patent rights. By publication of this standard, no position is taken with respect to the existence or validity of any

patent rights in connection therewith. The IEEE shall not be responsible for identifying patents or patent applications

for which a license may be required to implement an IEEE standard or for conducting inquiries into the legal

validity or scope of those patents that are brought to its attention. A patent holder or patent applicant has filed a

statement of assurance that it will grant licenses under these rights without compensation or under reasonable rates

and nondiscriminatory, reasonable terms and conditions to applicants desiring to obtain such licenses. The IEEE

makes no representation as to the reasonableness of rates, terms, and conditions of the license agreements offered by

patent holders or patent applicants. Further information may be obtained from the IEEE Standards Department.

A Patent Letter of Assurance has been filed with the IEEE by the patent holder of the material presented in Clause

6.7 Three sensor system.

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5

10. Characterization of AE signals

10.1 Introduction .

10.2 General alternating current systems.

10.3 Acoustic systems that record single events

10.4 DSP workstations that record data over extended periods ...10.5 On-line (continuous) acoustic PD systems ......

10.6 HVDC transformers and reactors ..

10.7 Characteristics of PD from static electrification ....

10.8 Acoustic activity from thermal faults, the core, mechanical noises and

other sources...........................................................................................

10.9 Comparison between electrical and acoustic signals

25

25

25

26

2929

30

30

31

31

11.

12.

Integrating AE results with data from oil analysis ..

Acoustic activity interpretation ..

33

33

Annex A (informative) Bibliography 35

Annex B (informative) Signal processing . 39

Annex C

Annex D

(informative) Wavelet signal processing theory

(informative) Tutorial: detection and location of AE from PD

40

43

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6

IEEE Guide for the Detection and Location ofAcoustic Emissions from Partial Discharges inOil-Immersed Power Transformers and Reactors

1. Overview

1.1 Scope

This guide is applicable to the detection and location of acoustic emissions from partial discharges and other sources

in oil immersed power transformers and reactors. Both electrical sources (partial discharge) and mechanical sources

(such as loose clamping, bolts or insulation parts) generate these emissions. There are descriptions of acoustic

instrumentation, test procedures, and interpretation of results. When this guide is used with oil-immersed reactors, it

must be understood that interpretation of signals may be different because of the construction of the reactor.

Accuracy of location depends on the type of fault, configuration of tank, type of instrumentation and experience.

1.2 Purpose

This guide is intended to provide information that may be helpful in planning, installing and operating acoustic

monitoring equipment and in meaningful interpretation of resulting data. Users are intended to be persons

knowledgeable in this field such as utility engineers, consultants, academics and manufacturers.

1.3 Safety warnings

The safety warnings in this subclause apply only to work done on transformers installed in the field, not to factory

testing. Refer to factory test codes for safety warnings for these situations.

Partial discharge (PD) location should only be attempted by those technicians and engineers trained in working on

high-voltage transformers and knowledgeable of the risks associated with this work.

WARNINGS

1. The transformer tank must be connected to a low resistance ground to limit the extremely highvoltages being induced into the ground circuit and the tank if a high voltage to ground failureoccurs. The personnel risk is very high if the transformer fails to ground. Even when grounded

properly, the voltage on the tank to a different ground source may be LETHAL at the instant the

failure occurs.

2. If the transformer is being energized or de-energized, or there is another type of power systemvoltage, all personnel should maintain a reasonable distance from the transformer and

equipment electrically connected to the tank due to the possibility of a failure. It is recommended

that acoustic measurement equipment connected to the tank be electrically isolated from thetransformer tank, e.g., by optical means or by high-voltage electrical insulation, when measuring

during transient events to eliminate the danger to the equipment or operators.

3. It is preferable to make all connections to the tank with the transformer de-energized, but in no caseshould the transformer voltage be above normal voltage while the sonic measuring devices areinstalled. Personnel must not access areas where high voltages are within minimum approach

distance, such as on top of energized transformers or in bushing compartments.

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3. Detection and measurement of PD background information

Since PD cannot be measured directly, its energy by-products such as electrical transients, chemical changes,

electromagnetic emissions, vibration, sound, light, and heat must be measured. Each of these energy by-products,

when measured, has advantages and disadvantages for identifying PD. The measurement methods are as follows:

a) Radio frequency (RF) - VHF: the VHF measurement of radio waves is in the frequency range of 30 MHz -300 MHz. This VHF measurement is usually associated with aerial antennas, but not exclusively. Some

window type receiver devices may also monitor the VHF range. The signal attenuation and noise reduction

are similar but less compared to the UHF frequency.

b) Radio frequency (RF) - UHF: the UHF measurement of radio waves is in the frequency range of 300 MHz -3 GHz. These measurements are often performed using a window style UHF receiver. UHF tests are less

affected by external noise. The Corona type of PD emits only up to a frequency of approximately 300MHz.

Signals are strongly attenuated when they pass through the bushings or travel longer distances within the

oil. Cell phone and TV stations operate in the UHF band and might introduce strong noise. Discharges

directly in the oil have an upper frequency limit of only a few hundred Kilohertz and can not be detected.

c) RF current transformers (RFCT): RFCTs are designed to measure up to several tens or hundred MHz. Theycan be placed on ground returns and/or bushing taps. The RFCT by itself is generally considered non-

intrusive; however, the RFCT may require an outage to be installed. It can be used both for off-line and on-

line measurement states.

d) Coupling capacitor (CC): the CC sensor interfaces directly with the voltage terminal. This is the methoddescribed in IEC 60270 [B36]. This is a common factory test method. Results are measured in pC. This

measurement works well under a controlled noise-free environment, but may not work well in a field

environment.

For field measurements, this method can utilize either a user-supplied capacitor or the leakage current from

a bushing tap, using the condenser layered bushing as the coupling capacitor. When the user supplies an

external reference capacitor for on-line measurements, the measurement is considered intrusive. However,

when a coupling capacitor is used, there is generally no limitation put on the frequency measurement range.

e) Acoustic emission (AE): consists of one or more ultrasonic transducers that are sensitive to the AE

generated by a PD source. Acoustic sound sources are wide-banded (> 1MHz). Due to the propagationcharacteristics of the insulation medium and apparatus structure, ultrasonic AE is measured in the 20 kHz

to 500 kHz frequency range.

f) Ultra violet light (UV): detects UV light generated by corona, external PD on surfaces, and arcing. Thismethod generally detects external events within line of sight. With the help of daylight blocking filter and

very sensitive cameras, UV measurements can be obtained in direct sunlight.

g) Dissolved gas analysis (DGA): In the case of PD in voids or gas bubbles, the main gas formed is hydrogentogether with significant amounts of methane (typically 10%) and minor amounts of the other gases.

Variable amounts of the carbon oxides may also result from partial discharges in cellulose, although

usually in lower quantities than the other gases. [B17, B18].

In the case of discharges of the sparking-type in oil or in paper, significant amounts of all the hydrocarbons(including acetylene) are formed in addition to hydrogen.

h) Power factor tip-up: PD produces a power loss, which is a function of applied voltage. If PD is present,losses increase and the power factor changes with applied voltage. The power factor difference between

applied voltage levels is known as "tip-up".

This guide focuses on the detection and location of PD using AE techniques. These techniques are sometimes

combined with one or more of the above PD detection and measurement methods.

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4. Introduction to acoustic PD systems

PD detection and location work is carried out in the factory and in the field, the latter being done with the

transformer either connected to the grid or supplied by a separate power source.

Acoustic PD systems are most often used when PD has been identified as a result of other diagnostic procedures,

such as dissolved gas analysis and electrical PD measurement.

There are two general categories of acoustic location systems: all-acoustic systems and acoustic systems with an

electrical PD trigger. In addition, on-line (continuous) acoustic monitoring systems are being used primarily to

detect and trend emissions. Typical implementations of each of these types of systems are given below along with

the respective advantages and limitations.

4.1 The all-acoustic system

The first category, the all-acoustic system, consists of one or more ultrasonic transducers that are sensitive to the AE

generated by a PD event. The detection and coarse location of one or more sources can be accomplished by moving

one or more externally mounted sensors to different locations on the transformer tank. A more precise location of a

PD source may be determined by the relative arrival times of the acoustic signals at each of the sensors. No voltage

or current readings are required on the transformer. This makes the all-acoustic system a suitable tool for source

location on operating transformers in the field.

The acoustic transducers can be mounted on the exterior of the transformer tank to detect the acoustic signal as it

hits the tank wall, or inside the transformer to detect the signal in the oil.

Benefits of the externally mounted sensors include the ability to reconfigure the sensors as necessary to obtain a

clearer acoustic signal, the flexibility to move the system to another transformer, and the ease of retrofitting existing

transformers. The disadvantage of the external configuration is that it is more sensitive to external noise sources.

Benefits of the internally mounted sensors may include a clearer, louder measurement with a better signal-to-noise

ratio. Disadvantages are that installation of the sensors is invasive to the transformer and, once installed, the sensors

can not be moved around to achieve a clearer line of sight to the source, nor can they be easily removed and installed

on another transformer.

4.2 The acoustic system with an electrical PD trigger

The second category, the acoustic system with an electrical PD trigger, pairs the array of acoustic sensors described

above with a current or voltage measurement device that detects the PD signal electrically. The electric signal is

usually considered as detected instantaneously. When using this assumption, the arrival time of the electric signal is

used as time zero for the PD event. The difference in arrival times of the electric signal and an acoustic signal is the

propagation time between the PD source and that sensor location. PD location is based on the absolute arrival time

at each sensor, as opposed to the all-acoustic system described above which uses the difference in arrival time

between sensors.

The assumption of instantaneous detection of the electric signal is correct when it appears e.g. at the bushing tap of

the transformer. At the most this delay is in the range of a few microseconds and therefore can be neglected.However, an acoustic system with an electrical PD trigger is processing the electrical signal first. Here the

processing time may be taken into account in order to decrease location error. Table 1 shows the time lags due to the

analog processing time measured in three different electrical PD detector types.

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Table 1 - Time lag in electrical PD detectors

Type of detector Time-lag to t0 Signal rise time

(10-90%)

Approximate location

error in oil

Wide-band with active

Integrator (100-400 kHz)

0.2 s 1.2 s Negligible (< 2 mm)

Narrow-band at 1 MHz

With 9 kHz bandwidth

16 s 35 s 22 mm-70 mm (1 in. ~3 in.)

Narrow-band at 1 MHzWith 4.5 kHz bandwidth

16 s 50 s 22 mm-95 mm (1 in. ~4 in.)

The numbers are provided only as an example. Other detectors from different manufacturers may have different time

lags since this property is not specified in the standards. It can be seen that a narrow-band detector may introduce a

time lag that may be taken into account if very accurate location measurements are desired.

One advantage of the combined system is that the electrical measurement provides confirmation that the acoustic

sensors are locating a PD event as opposed to another acoustic noise source. Furthermore, the electrical signal is a

convenient trigger that can be used to start the data acquisition at the acoustic sensors.

The major disadvantage of the combined system is that it may be difficult to obtain a clean electric PD measurement

due to electrical noise in the field. Hence, the combined acoustic-electrical PD locator system is more suitable for

use in the factory or plant than in the field.

4.3 The on-line (continuous) acoustic monitoring system

The main purpose of permanently installed on-line acoustic monitoring systems is to provide an early indication of

an incipient fault to a remote location. These systems usually consist of multiple sensors, amplifier and data

acquisition/processing modules. The sensors are placed at locations where faults may be anticipated based on past

experience or highest probability of problems occurrence. The data acquisition/processing systems are able to

transmit collected data and/or warning alerts to locations outside the substation.

The data is often limited to activity levels rather than specific waveforms. Location information is often limited to

knowledge of which sensor is most active.

Some continuous monitoring systems use the signal from a split CT around the transformer case ground or an RFsignal from a sensor inside the transformer to identify the AE signal as an internal PD.

Warning alerts caused by level of activity above a baseline or trend of activity are usually reason to take gas samples

and perhaps perform more extensive acoustic or other testing.

5. Acoustic signal and transmission characteristics

5.1 Acoustic signal

The energy creating the acoustic signal is from PD and mechanical and thermal sources inside and outside

transformers and reactors.

Figure 1a shows a waveform from an acoustic sensor mounted on the outside of a transformer tank. It is typical of

one burst of PD. The sharp rise of the wave front indicates that a direct wave has impinged on the inside tank wall

within the critical angle for a pressure wave.

The horizontal axis shows time in microseconds. The burst had a length of 144 microseconds from the first threshold

crossing to the last threshold crossing. The vertical axis is a dimensionless indication of amplitude. The number of

acoustic bursts in a unit of time, usually one second, is a measure of acoustic activity.

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Figure 1a - Typical acoustic emission burst

Figure 1b is a detail of the waveform in Figure 1a. There are 16 oscillations (also called counts) at or above the

indicated threshold of 100. The oscillations are shown below.

Oscillations: 1 2 3 4 5 6789-10 11-12-13-14 15-16

Figure 1b Oscillations in an acoustic emission burst

AE detection systems may count bursts and/or oscillations.

In order to count bursts, the oscillatory portion of the decaying burst must be removed by means of a demodulation

circuit. This ensures that each emitted burst is recorded as a single discrete event. The bursts can then be recorded at

a preset magnitude level over a one second time period. Also, a distribution of all the discrete AE burst magnitudes

can be obtained by means of a pulse height analyzer, again over a one second time period. If the PD pulses occur

faster than the ring-down time of the acoustic transducer or the time window used for pulse qualification in some

automated systems, errors in burst rate count and burst height distribution will occur.

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5.2 Acoustic signal propagation from source to tank wall

Active PD sources in oil-filled transformers produce AE signals that propagate away from the source in all

directions. The acoustic signals travel through the intervening material to eventually arrive at the transformer tank

wall. The distance traveled in a particular medium is dependent on the time that it takes for an acoustic signal to

complete this journey as shown in the equation below:

distance traveled = acoustic wave speed x travel time

Consequently, sensors placed at different locations on the tank wall, i.e. at different distances from the source, will

experience different signal arrival times. For the case of the all-acoustic system, it is possible to detect the

difference in signal arrival time at one sensor relative to another. This in turn allows for the estimation of the

difference in the two propagation path distances. For the case of the combined acoustic-electric system, the time

delay between the source and the sensor can be detected, and the absolute path length between the source and a

given sensor can be determined. Each of these system types requires a slightly different procedure to locate the

source, as described in the sections on Operating Procedures, Clauses 8 and 9.

Acoustic PD source location commonly assumes that the acoustic signal travels a direct, straight-line route from the

source to the sensor. Unfortunately, this is not always the case as the acoustic field inside the tank is very complex

due to wave reflection, diffraction in different materials and other parameters. For example, if there is an

obstruction blocking the line of sight between the source and the sensor location, the sound may travel around the

obstruction. This results in a longer propagation time that would imply a greater distance between the source and

the sensor than actually exists. Alternately, the sound may travel directly through the obstruction at a wave speed

that is greater than in the oil. The resulting arrival time would be earlier, which would imply a shorter distance

between the source and the sensor than actually exists. To help avoid these misinterpretations, it is important to

confirm the estimated source location by repeating the distance calculations with several sensor locations.

5.3 Acoustic signal propagation within the tank wall

The propagation of the acoustic waves within the transformer wall is complex. However, using experimental

evidence based on acoustic signals about 100 kHz and wall thickness about 10 mm, wave propagation velocity can

be assigned a constant value and wave types can be regarded as similar to compression and shear waves. This

empirical approach is used in this document.

Structure-borne propagation paths within the tank wall present a further technical challenge. As the acoustic wavehits the tank wall, its frequency characteristics remain the same, but its mode of propagation and propagation speed

change. In the example in Figure 2, the sensor is located on the far side of the tank, away from the source.

Figure 2 - Illustration of typical propagation paths for the acoustic PD signal.

Primary reflection wave propagation can take place within the confines of the tank as shown. The speed of sound for

this wave depends on the media encountered by the sound wave.

Acoustic

sensor

PD Source

Transformer

tank

Direct acoustic path

Structure-bornepath

Primary

reflection wave

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Acoustic waves hitting the nearby tank wall will create an alternate propagation path via the tank wall to the sensor

on the other side. The wave speed in metal is greater than in oil. Therefore the wave traveling this structure-borne

path may arrive at the sensor earlier than the wave traveling the direct acoustic path. If the distance calculations were

based on the arrival time of the structure-borne wave using the wave speed in oil, this would imply an incorrect

distance between the source and the sensor. It is crucial that distance calculations are based on the direct acoustic

path. It is critical to confirm the estimated source location by using a variety of sensor locations.

Another way to distinguish the structure-borne waves from the oil-borne waves is to analyze the mode of vibration.

Fluids, such as oil, will only support pressure waves. Solids, such as steel, can support many types of wave motion.Waves in the oil give rise to both pressure waves and shear waves in the tank wall.

Source

Tank wall

Detector

Direct wave

Pressure (Longitudinal) Waves

Shear (Transversal) Waves

Structure-borne waves

shear wave

Critical angle for:

pressure wa ve

Figure 3 - Illustration of the longitudinal and transversal waves in the enclosure and how they are

created from direct waves.

NOTE: the wavelengths in Figure 3 are not to scale.

Two wave fronts will be seen in these cases, as illustrated in Figure 3. The shear wave has the largest amplitude and

can be identified in this way. The pressure wave is faster and may arrive at the detector first.

The problem of structure-borne waves is reduced significantly if the acoustic sensor is located inside the tank.

5.4 Velocity of sound in oil

For the calculation of distance of the PD source from the sensor, 1413 m/s at 20 C is typically used. Corrections to

the speed of sound for temperature and moisture content are not generally made to increase accuracy because the

uncertainties due to material propagation are usually much larger.

Table 2 shows estimates of the velocity of sound in oil at other temperatures. The velocity will be different if there

are other materials in the wave path and may change depending on the properties of the oil.

Table 2 - Velocity of sound in transformer oil vs. temperature

Temperature of oil - C Velocity m/s

50 1300

80 1200

110 1100

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6. AE systems: equipment specifications

6.1 Introduction

Many different types of instrumentation are available for detection and location of AE. Several types of typical AE

systems and sensors are described here that have been shown effective in certain transformer arrangements;

however, other systems may be equally or more effective, depending on the transformer physical parameters and the

location of the PD.


A typical system consists of the following components.

a) A digital detection system. This may consist of one or more standard 4-channel digital oscilloscopes withsampling rate for each channel greater than 1 mega-sample/second and memory depth greater than 5000

samples. Data acquisition units available for computers could be used if they fulfill these requirements.

Features such as averaging, peak detection, zoom, measurements and storage are very useful.

b) Sensors: As discussed in Clauses 6.5, 6.6 and 6.7 below.

c) Cabling and power supply units for the sensors.

6.3 Digital signal processing (DSP) workstations that record acoustic data over extendedperiods

Transportable DSP workstation systems are used to automate the AE acquisition and interpretation process. These

systems identify, qualify and locate AE sources using the signals from sensors in Clauses 6.5 and 6.6 below. The

systems combine the acquisition and saving of multiple AE signals with the capability to

a) Qualify the signal as PD by determining the fit of the AE waveform to parameters such as rise time,duration time, and asynchronicity with the excitation frequency, e.g. 60 Hz.

b) Provide a relative measure of activity level by determining the energy level at the transducer face. This isdone by counting the number of bursts and the area beneath the burst envelope that is above the threshold

setting. Note this does not provide the actual level of PD energy.

c) Calculate the location of signal source(s).

Results of tests can be displayed as graphs such as point plots, line graphs, bar graphs or cluster graphs with multiple

parameters or waveforms or the results of summations of data. This same data is used to generate reports that give

the hardware and software setup information, acquisition activity and location of the source(s) of the PD.

6.4 On-line (continuous) acoustic PD monitoring systems

There are two general types of systems for continuously monitoring PD.

a) Permanently installed on-line acoustic monitoring systems to detect and trend AE signals and send thatinformation to a remote location. Data gathering personnel are not usually present during normal

operation. These systems typically consist of multiple sensors, which are placed at locations where faults

may be anticipated based on past experience or highest probability of problems occurring, and amplifier

and data acquisition/processing systems that are able to transmit collected data and/or warning alerts to

locations outside the substation. They usually do not perform remote location analysis of the AE. Supply

of power from the station DC source or another uninterruptible supply may be specified. For long-term

robustness, the systems require protection of inputs, outputs and grounds similar to electronic relays.

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A test to establish the baseline data of acoustic activity on the transformer is performed during the

installation process. This test provides information to establish the best hardware and software settings for

permanent monitoring. It is helpful for gain settings to be the same as adjacent transformers in order to

compare readings if signals are thought to be the result of network disturbances.

Permanent mounting of sensors is desirable for long term installations. This may be accomplished with a

thin coating of suitable epoxy and a mechanical holder. The epoxy should be chosen to avoid broken

bonds due to differential thermal expansion between the sensor and the wall. The bonding agent is usually

a suitable couplant.

b) Systems that include acoustic sensors and a high frequency current transformer installed on the caseground connection or a special radio frequency transducer mounted inside the transformer. These systems

utilize the concurrence of an acoustic event and an electrical or radio frequency signal to confirm that the

acoustic signal is PD. In some systems, the time difference is used to give a measure of location.

6.5 External sensor

The sensor mounted on the external surface of the transformer tank is a piezo-electric displacement transducer

operating in its compression mode. Different investigators are using sensors with a sensitive region ranging from

about 20 kHz to 500 kHz.

It has been shown [B10] that the main frequency of a partial discharge of about 150 pC magnitude is 100 kHz.Users typically choose sensors with resonant frequency (for longitudinal waves) of either 60 kHz or 150 kHz. For

larger discharges, frequencies should decrease. Also, attenuation affects high frequencies more than low. These

factors favor the sensor with the 60 kHz resonant frequency for factory and laboratory use. In the field, however,

numerous noises or harmonics of noises are encountered in the 20 kHz to 60 kHz frequency range. Since the sensor

is sensitive to pressure waves in its frequency range that may not be from a PD source, these noises may lead to false

readings. A number of users favor the 150 kHz resonant frequency sensor for field applications for this reason.

Being a piezo-electric device, the sensor will also respond to varying electromagnetic fields such as those found in

substations. To minimize this effect, the transducer can be either a "differential" type utilizing two crystals

(mounted out of phase for noise reduction) or a shielded single crystal transducer with an integral pre-amplifier

circuit. The latter is the preferred and most common configuration because its comparatively high amplitude, low

impedance output is less susceptible to degradation due to noise pick-up in the connecting cables.

Acoustic couplant gel or grease should be applied to the face of the transducer or matching piece just prior to test.

Gels or solids that retain high viscosity at the transformer wall at operating temperature are preferred because low

viscosity couplants will not transfer shear stresses. Couplants produced for ultrasonic non-destructive testing

purposes are generally suitable. Gelled glycerin and silicone grease are particularly efficient and are recommended.

Silicone grease can be difficult to remove from the tank surface.

6.6 Internal sensor

The internal AE sensor or waveguide is a device immersed in the oil that couples acoustic energy from the oil to an

externally mounted sensor. An example of a waveguide would be a solid fiberglass rod inserted through a seal into

the transformer tank with a sensor mounted on the external end of the rod. Careful attention must be given to

maintaining dielectric properties and dimensions. The waveguide is less directional than external tank wall-mounted

sensors because the impedance of the steel tank wall is not a factor. It is less sensitive to external noise such asstorms or loose fittings. [B25].

A new technique under development uses an optical interferometric technique. A laser light source is coupled to the

sensing head through an optical fiber. The sensing head consists of an air gap and a thin silica glass diaphragm.

The optical signal is a function of the air gap length. Variations in the length, caused by an acoustical pressure wave,

are proportional to the intensity of the acoustic signal.

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6.7 Three sensor system

A transducer system has been developed to aid optimization of sensitivity and rejection of non-PD signals [B9]. It

consists of three relatively closely placed acoustic sensors mounted in a rigid movable frame. An electric detector

may be used to sense the time of origin of the PD, which allows determination of the total transit time of the wave

front. This system is intended to be operated by an experienced person. In searching for possible PD signals and

their origin, the detector frame is moved to selected positions on the transformer tank. At each position, a set of

different trigger and time frame settings are studied on the evaluation unit, which may be a digital oscilloscope.

Suitable algorithms in the evaluation unit determine the direction and possibly the distance to the discharge source.

6.8 Band-pass filter

The use of a band-pass filter is optional. Its purpose is to negate as many of the effects as possible of signals that are

not associated with PDs. These include vibrations caused by the magnetostrictive action of the core (Barkhausen

noise), pumps and fans. Most of these fall below 30 kHz; however, the Barkhausen noise emanating from the core

has sometimes been found to be in the 50 kHz range. Hence, a 100 kHz high-pass section with a rapid, roll-off

response characteristic is needed. The reasonably generous band-pass (200 kHz) allows for variations between

different transducers, in so far as their resonant frequencies are concerned.

The filter is a band-pass type with lower and upper cutoff frequencies of FL and FH. These are frequencies at which

the response to a constant sinusoidal input voltage has fallen by 3 dB from the maximum value. When used with a

150 kHz sensor, FL should be about 100 kHz and FH should be about 300 kHz. The roll-off characteristics of thefilter should be a minimum of 48 dB/octave (240 dB/decade) for the high-pass section. This means that, relative to

the signal of interest (150 kHz), a 50 kHz signal would be attenuated by 48 dB. The low-pass filter should roll off at

not less than 24 dB/octave (120 dB/decade) so that a 600 kHz signal would be attenuated by 24 dB.

7. AE testing

7.1 Personnel qualification and certification

Formal qualification and certification for personnel doing acoustic testing and interpretation of test data is available.

One such program is given by the American Society for Nondestructive Testing [B5].

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7.2 Field vs. factory test differences

AE testing in factories or field situations has many differences. Some of the specific ones are shown in Table 3:

Table 3 - AE testing: field vs. factory differences

Field Factory

Ambient Noise sources Limited control; e.g. noise from rain or

hail. Signal processing or post test

analysis can reduce or eliminate noise

in some cases.

Controllable

Cooling Pumps May be required by system operating

requirements.

Can be shut off

Weather Limited control, e.g. noise from rain.

Signal processing or post test analysis

can reduce or eliminate noise in some

cases.

Testing done indoors

Power Supply Isolation, Filtering, and/or UPS

required

Clean power available

Grounding Single point grounding for test object

and equipment needs to be established.

Appropriate grounding provisions

built into test bay.

Equipment Access Precautions needed for working near

energized facilities.

Precautions needed for working near

energized facilities.

Transformer Design Generally limited knowledge of what is

inside the tank.

Full design information available.

Test Voltage Limited adjustment range unless a test

power supply is taken to the

transformer location

Full control of voltage levels

Gas blanket (air or nitrogen) Use care that sensors are mounted

below oil level. Also, bubbles may be

present during certain operating

conditions.

Use care that sensors are mounted

below oil level.

More information appropriate to the two environments is included in Clauses 8 and 9.

7.3 General considerations on the application of sensors

Transducer placement and mounting are critical to avoid attenuated or misleading signals [B6]. Some things to

consider include the following:

a) The contact between the transducer and the transformer tank is critical. Simply placing a transducer onthe transformer tank surface often produces a very weak signal. It is advisable to wipe the area free of

dirt, oil, bugs, etc. and polish it with a mild abrasive or abrasive cloth before placing the transducer.

b) An acoustic couplant is essential for enhancing the mechanical and acoustical coupling between thetransducer and the tank surface. It should be evenly applied to the clean mounting surface of the

transducer before placement.

c) A sound transmitting epoxy may have to be used if the mounting location is non-magnetic.

d) Transducers mounted on the tank walls may detect both direct and wall-borne signals. Those mountedon a bolted cover or other gasketed surface may receive the direct signal more clearly, but the wall-borne

signals may be distorted or dissipated because of the gasket.

e) If possible, avoid locations where there is magnetic or non-magnetic tank shielding, which will causeextra signal attenuation

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f) On transformers built with double wall construction, transducers should be located on the welded ribs thatspan between the two tank walls to provide a strong signal. The air in the cavity between the walls

attenuates acoustic signals.

g) If possible avoid locations above gas spaces. This adds extra impedance in the transmission path, whichproduces additional attenuation. Signals may be difficult to resolve.

h) Avoid mounting sensors on tank stiffeners unless the tank has a double-skin wall

i) For safety reasons, do not locate sensors in areas of high voltage

j) Provide sufficient spacing between sensors to insure independent signals. Distance depends on sensormodel

k) Verify sensor operation, either the entire system or each sensor. Amplifiers should be set for similarsensitivity for all sensors.

l) An acoustic verification rod may be helpful in determining an initial location for a sensor. The rod ismade of a solid sound-conducting insulation material, typically wood or fiberglass. It is used by placing

one end against the transformer tank, the other end against ones ear and listening for sounds that could

indicate PD.

m) Avoid the ends of transformers that have cores with unwound return limbs.

n) Aluminum or stainless steel walls are non-magnetic. Sensors may have to be placed using epoxy.

o) Do not mount sensors on control boxes

p) LTC operation contains a high electromechanical energy that usually propagates through the entiretransformer. Actions should be taken in order to identify operations during the test and distinguish them

in post-test analysis to identify the source of AE.

q) Shell-form transformers: locate the sensors on top (above the core) or bottom (below the core).

r) Transient voltage protection must be applied to the input of test instruments/devices.

s) Extraneous electrostatic and magnetic signals may cause false indications and damage equipment.

8. AE field test procedure

8.1 Introduction

AE testing is usually done in response to gas-in-oil test results or noises that may indicate partial discharge activity.

In most cases, the transformers are monitored while carrying load. This requires safety precautions when placing

the transducers, assuring that minimum approach distances are not compromised. Refer to Clause 1.3 Safetywarnings.

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8.2 Test setup

Approximately two to three hours are usually required to prepare for monitoring after arrival at a site. This will

depend on number of sensors to be installed and accessibility to the unit, power source, etc. If a test power supply is

being used, extra time will be needed to setup and check out the power supply.

Set up the test equipment at a convenient location for access to the transformer and the station service source.

Establish a common point ground for all of the test equipment and the transformer.

The transducers are connected to the test equipment with coaxial cables. Cable routings should be chosen to

minimize interference pickup from bus work and grounding connections in the test area. Verify proper operation of

the monitoring system.

An operational test should be followed in order to assure the same sensitivity of all sensors. Many users verify

transducer sensitivity by breaking the lead of a Number 2 pencil against the tank close to the transducer. Users

advise this is limited to tanks with 19 mm (3/4") maximum wall thickness. Another technique is to activate an

acoustic transducer to create a signal into the tank and measure the output of the other sensors. The signals recorded

by the various transducers should be compared to see if they are reasonable and consistent.

8.3 Sensor placement and initial scan

Unless on-line PD monitoring is being used, there is usually no indication of where to look for the noise source.

Therefore, a scan covering the complete transformer is the first step.

a)For a three-phase core form transformer, install one sensor in the general area of the bottom connection ofeach bushing. Place additional sensors at approximately the center of each winding limb on the high and

low voltage sides of the tank. If extra sensors are available, place them on the tank ends. See 7.2 m).

b) Similarly, for a single-phase core form transformer, install one sensor in the general area of eachbushing bottom connection. Place additional sensors at approximately the center of each limb of the

windings on each of the four sides of the transformer tank. See 7.2 m).

c) If the transformer has a preventive autotransformer inside, consideration should be given to placing oneor two transducers close to its location.

d) Using the same sensor locations and software settings when testing identical transformers permitsestablishing ambient baseline data for that particular design. The sensors may have to be moved to

improve reception of signals from a specific source.

e) Sufficient couplant gel is to be applied to the face of the transducer to ensure efficient transmission ofthe AE signal from the tank wall to the sensing crystal. Too much couplant will not be harmful (though

wasteful), whereas too little couplant can seriously inhibit the transducers sensing capabilities.

f) Magnetic shielding blocks the signal from the sensors. The location where shielding is installed isusually obtained by referring to pictures or notes from past experience with the transformer or from the

manufacturer.

g) In the case of transformers indicating PD, a high frequency split-core CT or ammeter (Rogowsky coiltype) around the transformer case ground can be used as a direct signal to the digitizer. This can be used

as the trigger transducer to indicate time zero.

The face of the transducer with its film of couplant should be brought into contact with the transformer tank wall

with only sufficient pressure applied in order to get a good signal and hold it in position. It is necessary to hold the

sensor steady so that no signals are generated due to relative movement between the sensor and tank wall. This can

be achieved by means of a magnetic clamp, adhesive tape or epoxy.

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The time period for the initial scan is dependent on the acoustic activity rate. Some users monitor for about four

hours before changing transducer placement. This basically assures the emission patterns are consistent and

repeatable. If activity rates are low or erratic overnight monitoring may be required.

8.4 Monitoring techniques

When the transformer is energized from the power system, voltage levels are fairly constant making inception and

extinction levels of acoustic activity very difficult to determine.

Techniques for varying system conditions to help characterize the AE source include:

a) Varying transformer loading to see if the acoustic activity is load related

b) Raising or lowering the bus voltage several kV by tap-changing and/or capacitor/reactor switching

c) Moving the transformer on-load tap-changer(s) up or down a step at a time to see the impact on the

acoustic activity

If the transformer is energized from a test power supply, the test voltage can be raised and lowered at will for

determination of acoustic activity inception and extinction levels.

Signal sensitivity is unique to each particular AE monitoring system. Trigger level settings depend on the normal

operating noise on the transformer to be tested (this depends on core type, pump/fan operation noise, etc.). The best

initial settings are the least sensitive settings that give a clear AE pattern (avoiding the noise coming from the core,

pumps/fans or other sources). The settings can then be optimized during the signal location process.

A three dimensional layout can be constructed, for instance, using a convenient corner of the tank for zero

coordinates. For tanks with rounded corners, consider squaring them off for reference. After sensor locations are

plotted, the time delay in each transducer signal can be used to estimate the source location. Using the maximum

number of sensors possible improves the accuracy and usability of this approach.

8.5 Locating the source of the signal

An approximate source location can be estimated based on relative timing of signal arrivals at the varioustransducers and assumptions about the speed of sound in oil. This is not a foolproof method because of the different

types of material (insulation, steel, copper, oil, etc.) in the paths between the signal source and the various

transducers. Also, there may be more than one signal source in the transformer.

Reposition transducers to focus on the area of the transformer tank where the suspected source is located and

continue the monitoring process. The sensors can be arbitrarily close as long as a time difference between them can

be measured.

Sometimes, even when transducers have been relocated to a suspected area, only one sensor detects the acoustic

activity. This can happen either because the source detected is very low in intensity or highly attenuated or because

there is a problem with the instrumentation. Care should be taken not to automatically disregard this activity as

noise.

The signal source location can be confirmed by a set of consistent signal timings. A clear consistent picture of the

signal characteristic helps to identify the source type.

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8.6 Reporting and follow-up

Comparison of actual problems and the predictions from acoustic monitoring are important for building the

knowledge base on the response of a particular monitoring system. This greatly enhances the usefulness of acoustic

monitoring as a diagnostic tool.

The investigation report should include information on the test setup, test procedures, test waveforms (if any), and

predicted signal sources based on experience, internal assembly drawings and/or photographs of the transformer

under test.

Follow-up reporting may include comparison of the actual problem and the predictions from the investigation.

Useful information includes:

a) What was found

b) Where was it located

c) Differences between predicted and real locations

d) How the problem was corrected

Acoustic monitoring after repair allows comparison of before and after acoustic signatures and allows establishingthe new baseline data of the transformer.

9. Factory test procedure using an electrical trigger

9.1 Introduction

An important difference between the factory test and the in-field test is the advantage of being able to use an

electrical PD signal to trigger the acoustic data acquisition. This electrical trigger, occurring virtually

instantaneously as the PD emissions leave their source, provides a convenient "time-zero" mark to use to measure

the time differential between this signal and the acoustic signals, and hence calculate the distance from the acoustic

sensors to the PD source.

The input of the electrical PD detector is typically connected to the bushing capacitance tap. The output is

connected to one of the channels of the acoustic location system. It is recommended to use an electrical apparent

charge detector rather than a radio-influence voltage (RIV) meter since the frequency range of the former is much

closer to that of the AE than the latter. However, either can be used for the trigger. The AE sensors are connected to

the transformer tank wall. The outputs of the sensors are connected to the acoustic location system for viewing the

acoustic signal and its time delay from the electrical signal.

9.2 Initial sensor placement

The initial placement of the AE sensors onto the tank wall can make the difference between an efficient location of

the PD source and a more time consuming one. Guidance in making an informed estimate of where to initially place

the sensors can come from the Induced Voltage Test. This test, in most cases, will indicate which phase of the

transformer contains the PD source. If so, the sensors should then of course be placed in the area of the problemphase. Caution should be exercised because there has been at least one experience [B51] where the induced voltage

test indicated the PD to be located in one phase and the acoustic test located it on a different phase, the latter being

verified through internal inspection. A typical example would be a delta winding where each bushing is connected to

two phases.

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Another source of information is to examine the transformer internal assembly drawings and photographs if

available. They may show likely areas of PD sources, and indicate whether the problem may be on the LV or HV

side, or an end wall, and whether it is towards the top, middle, or bottom of the tank. An example of a simplified

HV-Side transformer assembly is shown in Figure 4. A search for the problem PD source within such an assembly

can include placing sensors along the windings, over each de-energized tap-changer, and/or along the high-voltage

leads connecting each HV winding to its respective bushing.

Figure 4 - Example of HV-side of three-phase transformer assembly

Ideally, initial placement of sensors would resemble one of the three arrangements shown in Figures 5a, 5b, and 5c.

Figures 5a and 5b are for the case when the problem phase is known; Figure 5c for when it is not known.

Figure 5a - Sensor locations with PD source in center phase. Typically sensors are located oneach side wall.

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Figure 6 - Transformer tank plan view

Some creativity is therefore required, and the actual sensor placement may be significantly different from the

arrangements shown in the previous figures. For example, due to the presence of radiators or internal wiring trays,

the sensors for one phase might need to be placed on the opposite side-wall than the other two phases.

Mounting the sensors on manhole or other covers may provide an AE signal path that is clear of tank wall - carried

signal if the cover is isolated from the tank by flexible gaskets. The transformer oil must be in contact with the

inside surface of the cover for the sensor to be effective.

Shell form type transformer arrangement requires special mention owing to the shielding used inside the tank walls.

It may only be possible to place sensors on the top of the tank or in areas where there is no shielding.

9.3 Measurements and changing of sensor placement

With the sensors in place, a simple check may be performed to ensure that they are indeed operational. Using low

signal amplification setting, this check can be accomplished by gently tapping your fingertip on the tank wall

immediately beside one of the sensors. This will create an acoustic signal, which should be detected by the sensor

and displayed on the oscilloscope. Use this procedure to check each sensor in turn.

Now, the first set of AE measurements is ready to be taken. To do so, energize the transformer in the same manner

as during the routine Induced Voltage Test. Increase the voltage slowly until the electrical apparent charge detector

measures sustained PD activity, or until the full test voltage level is reached that can be safely sustained

continuously. (Do not raise the voltage level beyond this amount, as a higher voltage level, though possibly

producing greater PD activity, unduly stresses the transformer insulation). At this voltage level, and with a medium

acoustic signal amplification setting, the oscilloscope trigger sensitivity level must be calibrated to the

corresponding electrical PD detector signal. Now, for every half-cycle of the voltage wave, the oscilloscope will be

triggered to begin data acquisition from both the electrical PD detector and the acoustic emission PD sensors.

"Time-zero" will be the instant in time that the data acquisition is triggered to begin. As many sensors as the

oscilloscope will allow should be displayed at once. Data that invites analysis can be "frozen" on-screen and stored

in memory using the digital oscilloscope.

The interpretation of the acoustic signals displayed on the oscilloscope is done according to Clause 10.1 of thisguide. If none of the sensors indicate PD activity, increase their signal amplification slightly and repeat the test. If

there are still no clear signs of activity, the sensors will have to be moved manually, perhaps by a displacement of

half a meter either vertically or horizontally, and retested again. Another suggestion is to move some of the sensors

to the opposite side of the tank. This is a trial-and-error process that continues until at least one of the sensors

indicates the presence of PD activity. Again, this process can be expedited with the examination of the transformer

internal assembly drawings and photographs.

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When one or more of the sensors shows activity, assuming in the simplest case that only one problem PD source is

present, the rest of the sensors may be manually moved into the vicinity of the active area. The objective is to obtain

AE signals from all sensors, and to position them so as to minimize the time differential between "time-zero" and

the beginning of the acoustically detected PD signal. Ideally, this minimum time difference will correspond to a

maximum number of individual oscillations in the signal as measured by the counting circuit; however, this may not

necessarily be so (refer to Clauses 4.2 and 5 for calculation of the distance from the sensors to the PD source).

Using this procedure for sensor placement and AE measurement, the PD source can often be located to within 25 cm

or less.

10. Characterization of AE signals

10.1 Introduction

Characterizing whether an AE signal is PD is usually done by considering factors such as length of the burst,

movement of the AE signal relative to the excitation frequency and rise time of the first oscillation to cross the

threshold.

Partial discharges obtained by conventional electrical methods use a threshold to predict severe activity. This level

is generally about 300 pC to 500 pC. Because of variations in the acoustic signal caused by distance and interfering

materials, there is no similar threshold for acoustic systems. A strong signal buried deep within a winding may be

very weak by the time it reaches the acoustic sensor. Also, differences in amplifier gain settings cause differences in

magnitude.

10.2 General alternating current systems

In general, two types of PD activity (other than zero) may be encountered: continuous and sporadic.

By continuous, it is meant that PD bursts are present all the time, though they may have varying AE amplitude. This

type of signal is typical of that produced by an energetic PD source.

Sporadic activity can be further subdivided into two types.

a. Sporadic AE from a continuous PD source: this is characterized by activity that is present most of the time,but short quiescent periods are also encountered. This type of signal may be produced by exposed sources

on conductors and connectors, defects in insulation, worn tap changers, foreign objects or ungrounded

hardware.

b. Sporadic PD with lengthy quiescent periods (perhaps minutes) followed by short periods of very highactivity: this type of signal has been found to be associated with floating static shields, streaming

electrification or other types of static discharges (see Clause 10.7) and bad contacts in tank wall shielding.

Often short-lived arcs are associated with this type of fault, and these produce very energetic AE signals

during active periods.

As previously described, it is often possible to determine the position on the tank wall where the transducer is

closest to the PD source. This does not give information as to the distance into the tank (from that location) to the

source. However, observing the signal on an oscilloscope (a digital transient recorder is recommended), it is possibleto form an opinion regarding this. For example, the burst shown in Figure 1a has suffered very little attenuation.

This is evidenced by the high rise rate of the leading edge of the burst envelope, resulting in the characteristic

"arrow head" shape. To achieve this, the propagation path is almost entirely in oil with little solid insulation

involved.

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If the PD signal propagates through layers of solid materials (iron, copper, insulation, etc.), the resulting attenuation

not only affects the overall amplitude, but also modifies the burst envelope by "rounding off" the leading edge. In

the extreme, the burst envelope becomes "egg-shaped" or "ellipsoid-shaped" as shown in Figure 7 [B41]. By

utilizing this phenomenon, it may be possible to estimate whether the source lies close to the surface or is buried

well within the insulation system.

Figure 7 Typical AE burst showing effect of attenuation

The waveform beyond 200 microseconds is from reflections of the signal.

The user should always be aware that the responding characteristics of the sensor may at times be more in evidence

than the forcing characteristics of the PD signal.

Some experts use signal length of 40 microseconds to 1 millisecond as an identification criterion for PD.

PD usually has a correlation to the excitation frequency, e.g. 60 Hz, waveform, but is not synchronized to this

frequency. Typically, there is a slight "jitter" back and forth from a constant position on the waveform.


The frequency range of a signal is between 50 kHz and 350 kHz. In [B10] the main frequency for an approximate

150pC discharge is about 100 kHz with the expectation that for larger discharges, frequencies will decrease.

The amplitude and time duration depend on the physical size of the transformer tank and the location of the sensors

and their actual separation from the estimated PD source.

The subsequent attenuation of the signals is due to the heterogeneous structure of the transformer core/coil

assembly. Attenuation of the signal inside the tank affects high frequencies more than low. The attenuation of the

signal also creates a lack of correlation of scaling factor between the acoustic signal and electrically measured

apparent charge.

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Some examples of signals are shown in the figures below.

Figure 8 - A laboratory recorded direct PD signal (bottom) and its power spectrum (top)

The signal in the lower trace of Figure 8 is in the time domain; the x-scale is seconds. The signal in the upper trace is

in the frequency domain; the x-scale is hertz (Hz). The sensor used has its main sensitivity in the range 20 kHz to

120 kHz, which is clearly visible in the spectrum. Note the sharp initial rise in the time frame; maximum amplitude

is reached in the first oscillation. The second, more dilute, burst at about 0.7 ms is due to reflection.

ttd1

.7E-03 -0.6E-03 -0.4E-03 -0.3E-03 -0.2E-03 -0.1E-03 0. 0.1E-03 0.2E-0

0.

0.5

FFT:ttd1

. 0.2E+06 0.3E+06

0.5

1.

Figure 9 - A laboratory recorded signal with clear signs of propagation in the tank wall, together

with its power spectrum

The time frame signal (lower trace, scale is seconds) in Figure 9 shows a typical two-step behavior. The longitudinal

wave arrives first with lower amplitude than the transversal wave that comes about 0.04 ms later. The frequency

content (upper trace in Hz) will be slightly dependent on the wall thickness, length of wall path etc., but is mainly

unchanged from a direct signal as it is dominated by the sensor response which extends up to about 120 kHz.

direct PD signal

-0.1E-03 0. 0.1E-03 0.3E-03 0.4E-03 0.5E-03 0.6E-03 0.7E-03 0.8E-03

-0.2

-0.1

0.0.1

0.2

0.3FFT:direct PD signal (f requency domain)

-0.1E+06 0. 0.2E+06 0.3E+06 0.4E+06

0.1

0.2

0.3

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time domain

-0.001 -0.5E-03 0. 0.5E-03

0.

0.05

FFT entire signal

. 0.5E+05 0.1E+06

0.05

0.1

FFT noise

. 0.5E+05 0.1E+06

0.05

0.1

Figure 10 - A weak time domain PD signal together with power spectra for entire signal (middle)

and for the noise part (top)

Comparison of the two FFT frequency domain spectra in Figure 10 reveals that the PD signal main amplitude is

below 75 kHz. This is because the source is under paper insulation, which attenuates higher frequencies. The signalis just slightly larger than acquisition system noise.

Signal

-0.4E-03 -0.2E-03 -0.1E-03 0. 0.1E-03 0.2E-

0.

0.01

Signal 256 averages

-0.2E-03 -0.1E-03 0. 0.1E-03

0.

0.01

Figure 11 - A clear signal with indications of wall propagation (bottom). These indications are

confirmed by averaging (top)

Averaging can be a very effective method to reduce noise, as illustrated in Figure 11. The trigger was in this case set

on the high amplitude oscillation in the acoustic signal. A stable trigger and a high sample rate are required for

averaging. Several independent averages should always be performed to avoid chance coincidences. If applicable,

averaging is often the most effective method to reduce noise. Note, for example, the very weak indications of asignal appearing around -0.3 ms in the upper trace. Such observations are often the key to a successful localization.

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signal

-0.003 -0.002 -0.001 0.0.

0.1

FFT:signal

. 0.1E+06 0.15E+06

0.10.20.3

Figure 12 - A PD signal that has passed from the high-voltage side to the low-voltage side of atransformer

The wave front in the lower trace of Figure 12 is not sharply rising; it grows slowly (note time scale) and starts

roughly at -1.5 ms in the figure. The power spectrum in the upper trace shows a strong peak around 35 kHz,

indicating the passage of the signal through considerable amounts of attenuating material.

10.4 DSP workstations that record acoustic data over extended periods

Transportable DSP workstation systems process and graphically display the bursts from AE sensors and a number of

signal characteristics vs. time, cumulative time or each other in two and three dimensional formats. This is done for

multiple sensors simultaneously. Signal characteristics include amplitude, signal energy, PD hits, signal duration

(microseconds), PD hits vs. the phase of the power frequency voltage, where phase information is available, and rise

time.

Software in these systems may take advantage of known PD characteristics in order to reduce false indications of

PD. Characteristics include:

a) Signal may be asynchronous relative to the excitation frequency, e.g. 60 Hz. If the signal is synchronous

with the excitation frequency, e.g. 60 Hz, it is often noise [B68]

b) Length of the burst

c) Rise time of the first oscillation that crosses the threshold.

Software with a PD locator algorithm uses data collected by the system and three dimensional details of the

transformer tank to generate the best estimate of the PD location. This software may use wavelet transform methods

to estimate the PD location (Annex C).

10.5 On-line (continuous) acoustic partial discharge monitoring systems

Monitoring systems that send information to remote locations are usually intended to alert maintenance and

engineering personnel to possible problems, which can then be followed by more extensive field tests. The systemsoften have less processing capability than DSP workstation systems and may not be able to characterize whether the

AE signal is PD. The information transmitted is usually limited to number of counts per unit time and a measure of

energy that is undefined.

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10.6 HVDC transformers and reactors

PD detection and location devices are used in the same way during high voltage direct current (HVDC) transformer

and reactor factory and field measurements as they are with normal ac equipment tests. If the transformers are

energized without having the converter operating, there is no extra background noise and PD measurements are the

same as ac equipment. However, in field measurements:

a) EMI interference may be higher in an HVDC substation, requiring additional shielding of instrumentation,cables and wires. Due to commutation transients there is significant high frequency voltage difference

between different parts of the ground system.

b) The background noise level in HVDC transformers in operation is much higher than in normal actransformers and reactors due to the fast transients at converter operation (e.g. valve commutation). Higher

trigger thresholds may compensate for this. If noise levels are too high, acoustic monitoring for PD is not

useful.

c) Acoustic monitoring during inverter operation may be more difficult than rectifier operation because of thefast transients from high capacitive currents at valve firing.

d) A sensor of 150 kHz resonant frequency may reduce the noise level compared to one of 60 kHz resonantfrequency, but it will also reduce the sensitivity to PD sources under paper.

Sensor location notes cited in other parts of this Guide should be observed. In addition, the acoustic signal may be

attenuated in the area around the valve winding bushing turrets, possibly caused by the extra insulation barriers used

around the bushing connection for resistivity grading. Better results in this location may be obtained by looking

down into the turret by mounting the sensor on the bushing flange mounting surface.

10.7 Characteristics of PD from static electrification

The failures of a number of large power transformers have been attributed to accumulation of charge and subsequent

flashover discharge. Field tests have indicated a correlation of the charge buildup, accompanied by an increasing

level of PD activity, with oil temperatures below approximately 40 C and relatively high oil velocity [B16, B22,

B47]. This phenomenon is called static electrification.

It was expected that gases consistent with PD and flashover discharge would be formed; however, DGAs takenduring the field tests [B47] did not indicate any increase in levels of hydrogen or other gases. This was probably

because of the relatively short period of time and sporadic occurrences of the static electrification.

External sensor placement is mostly toward the top of the transformer using care to avoid internal shielding.

However, the high energy discharges of advanced static electrification can be detected by sensors located at almost

any location clear of shielding. These discharges can sometimes be heard as loud bangs by persons standing near the

transformer.

Static electrification discharges can be detected by acoustic methods well before they become damaging [B22].

Field test experiences [B22, B52] have shown that the most critical situations where static electrification can occur

is during start-up or lightly loaded operation in cold weather. Acoustic activity due to static electrification is

gradually reduced as oil temperature is increased. It practically stops after reaching 50 C.

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10.8 Acoustic activity from thermal faults, the core, mechanical noises and other sources

AE techniques have typically been used only for the detection and location of PD/arcing in power transformers

when an indication of a problem is pointed out by other techniques (usually gas-in-oil). However, it has been

observed through the years that transformers without gassing history and/or no indication of an electrical problem

produce acoustic activity when monitored over a fixed period of time [B52]. These signals must be differentiated

from PD signals for the results to be effective. Some examples and their characteristics follow.

a) Core magnetostriction noise (Barkhausen effect): the primary frequency occurs at twice the powerfrequency; the amplitude of this signal in both half cycles is about the same. Over fluxing may create

considerable noise, which may have harmonics that reach to the 30 kHz to 40 kHz frequency range or above.

b)Pumped liquid noise: the discharge from oil circulating pumps may interfere with PD signals withtransducers placed low on the transformer tank. They usually have no correlation with the 50 Hz or 60 Hz

waveform.

c)Loose nameplates, pipes hitting each other, fan noise, etc. may sometimes have repeatable waveforms closeto PD signals. The length of the signal is often much longer than the PD signal, which is characteristically

under 150s.

d) Loose shielding connections in the transformer tank wall may cause large PD indications, but not be

detrimental to transformer operation. The location of the signals should be considered and correlated withtransformer design drawings.

e)Wiring from the sensors to the amplifiers, if not properly shielded, will pick up spurious PD signals. Look atevery possible source before concluding there are major problems inside the transformer.

f) Trucks, environmental noises (thunderstorms, rain, snow, hail, wind, etc.), and miscellaneous events near thetransformer tank may activate the acoustic sensors. These are random signals lasting longer than 1 ms.

g)Switching and load tap changer movement are random signals.

h)Thermal faults may cause random signals [B21, B46]

The correlation of additional parameters of the transformer during the test (current, voltage, pump/fan current, oiltemperature, winding temperature, phase angle, etc.) with the AE data may assist in identification and separation of

the different acoustic sources detected during a test [B45]. A sensor isolated from the transformer tank may be used

as a reference for some environmental noises. If possible, a correlation with electrical PD detection can aid in

distinguishing between PD and noise signals.

10.9 Comparison between electrical and acoustic signals

A PD exhibits, besides other phenomena, a fast transient electrical pulse and an acoustic "bang". Depending on the

location of the PD and the coupling path between the event and the detector, the electric or acoustic signal can be

used to detect the PD. Both methods have different detection ways and sensitivities for unwanted signals (noise).

The acoustic PD detection is most useful for events within the line-of-sight of the acoustic transducers. This limits

the detection range, but also the amount of noise.

The electric PD detection covers a wider area, including e.g. bushing and tap changer. External noise will also be

detected and is difficult to remove. The correlation between instrument reading and actual discharge magnitude is

better than with the acoustic method. Several international standards exist that define the instrument response, which

is the readout in pico-Coulomb or micro-Volt, allowing a better comparison between manufacturer and in-field

measurements.

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Table 4 gives a rough overview of the comparison of electrical and acoustic PD signals.

Table 4 - Comparison of electrical and acoustic PD signals

Source Electrical

Detection

Acoustic

Detection

Remark

PD generated within the transformerPD on the outside of the winding Yes Yes Best use for acoustic detector, location

(triangulation)

PD within the winding Yes unlikely Strong acoustic attenuation inside the

winding.

RIV-detector signal affected by circuit L-C

resonance

PD between winding and core Yes difficult acoustic signal reflection at the core

required

PD between core and tank Yes Yes PD location is often difficult

Arcing / tracking of the oil surface Yes Yes

Arcing / tracking of the bushing

surface in the oil

Yes Yes

PD in the bushing Yes possiblea

PD in the de-energized tap changer Yes Yes

PD in the on-load tap changer Yes Yesbsensor placement on LTC compartment

Noise sources

PD outside the transformer, (e.g.

corona on busbar, PD in switchgear)

Yes Noc

Strong tracking / leader discharge Yes possiblec,d

Nearby lightning strokes Yes possiblec,dunlikely single events

Nearby car ignition Yes Nocno relation to phase angle

Switched electronic power supplies Yes Noc

Radio stations, transmitter Yes No Electrical noise filter (band-stop) or shift in

RIV frequency required

Weather (rain, sleet, snow, hail) No Yes

Other events

Moisture / Degradation in the oil No No Use other diagnostic methods to supplement

the PD detection (PF, DGA, etc.)

a Field tests have proven [B42] that acoustic detection of PD in the bushing can be achieved if acoustic sensors are

placed on the grounded flange of the bushing, close to the capacitance tap. See SAFETY WARNING Subclause 1.3.bSeveral cases have been reported [B41 B51 where PD/Arcing and/or tracking (carbon paths) have been detected

inside LTC compartments, either on the insulating support bars or on the diverter switch cylinder.cSuccessful electrical PD detection requires noise suppression (e.g. gating together with an external noise antenna)

and observation of the PD - phase pattern (fingerprint)dVery strong electrical signals can couple into the transducer or amplifier if the detector is not sufficiently screened

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11. Integrating AE results with data from oil analysis

Although AE data is useful in its own right, it becomes even more so when used in conjunction with dissolved gas-

in-oil data. For example, if the problem has been present for some time, as is typical of situations that develop in the

field, good correlation should be expected between gas analysis and AE data. As with any diagnostic tool, a baseline

reading should be established before or at the start of monitoring AE signals. The increase and rate of increase of

combustible gases from the baseline dissolved gas analysis (DGA) reading, in combination with events that occur on

the transformer, then become relevant diagnostic data.

PD and/or arcing in the presence of oil produce hydrogen (H2) and other gases. PD and the generation of H2due to

PD, are the earliest (first) warning signals of most incipient faults known to the industry.

If DGAs show a continuing increase of H2in combination with AE signals emanating from a source determined to

be in a specific area, there is a good possibility that the partial discharge is taking place in the specific area. Refer to

IEC 60599 [B37 and IEEE Standard C57.104 [B34 for more information.

Documents

AE Guide PC57.127-D10.0 12-29-06