Electric Signature Analysis (ESA) is a diagnostic and analytic technique that is being used to analyses motors, generators, alternators, transformers, and other electric equipment. This new technology has the ability to test operating electrical equipment and identify a variety of mechanical and electrical problems in Industries always try to increase the reliability of their productive process.
Electric Signature Analysis (ESA) is remote, non-intrusive, and is invisible to the equipment being monitored and analyses the driven load perform inrush testing and capturing a motor’s current & voltage signals and analyzing them to detect various faults.
Electric Signature Analysis (ESA) in the frequency spectrum using FFT (Fast Fourier Transform) analyzer is required for converting the signals from the time domain to the frequency domain. The amplitude of the peak in frequency is equal to the RMS amplitude of the sine wave time to the frequency domain is achieved using an algorithm called the Fast Fourier Transform (FFT) adopting techniques are Waterfall Analysis, Torsional Analysis, Motor Current Signature Analysis (MCSA), Extended Park’s Vector Approach (EPVA) and Instantaneous Power Signature Analysis (IPSA)).
ESA is used to evaluate the state of rotors, stators, and rotor-stator air gap conditions in electric motors. The collected data is then used to determine phase imbalance, motor load, power factor, power harmonics, and the impact of the driven equipment on the motor. Rotor bar as well as stator health and rotor-stator eccentricity (air gap) characteristics using Spectrum analysis of the motor’s current & voltage signals can hence detect various faults without disturbing its operation.
⦁ Rotor bar degradation
⦁ Mechanical unbalance.
⦁ Foundation looseness.
⦁ Static eccentricity.
⦁ Dynamic eccentricity.
⦁ Stator mechanical faults.
⦁ Stator electrical faults.
⦁ Bearings degradation
As the rotor bars start degrading (i. e. high resistance joints are present, or a crack starts developing), the rotor impedance rises. Due to this, the current drawn at the Pole pass Frequency (PPF) rises, leading to an increase in the amplitude of the Pole pass Frequency(PPF) peaks in the current spectrum.
⦁ The motor pole pass frequency (PPF = slip x no. of poles) appears as a side band to line frequency in current signature. i. e. we will see peaks at FL ± PPF
⦁ Increase in the rotor impedance due to high resistance joints or broken bars leads to an increase in the PPF amplitude.
⦁ Difference in amplitudes of the line frequency & the PPF is an indication of the condition of the rotor.
Eccentricity is the phenomenon of an uneven stator-rotor air-gap
Static eccentricity is the phenomenon of uneven stator-rotor air-gap, typically caused due to soft foot in the foundation, cocked bearing or an improperly adjusted air-gap for plain bearings.
Static eccentricity = RB x RS ± Nfl, Where,
RB= no. of rotor bars, RS= running speed of the motor, FL= line frequency, n= odd harmonics of the line frequency.
Dynamic eccentricity is the phenomenon of a variable stator-rotor air gap, typically caused due to worn out bearing housings or end covers.
Complete machine nameplate especially the horsepower/kilowatt, base RPM, Voltage and Current; Rotor bars (or slots) and stator slots; Bearing information; Type of coupling; For gearboxes: Gear teeth or ratios for each shaft; and Bearings and which shafts/locations. For direct drive pumps and vans – the number of blades; For belted applications: Sheave sizes; Belt information; and Center to center distance of the shafts. Control information; and Any other component application attached electrically or mechanically to the system.
Motor Current Signature Analysis is the technique used to analyze and monitor the trend of dynamic energized systems used to diagnose broken rotor bars results of applying predictive technique helps in identifying problems in stator winding.
Motor electrical current signature analysis (MCSA) is sensing an electrical signal containing current components that are direct by-product of unique rotating flux components. MCSA is monitoring stator current (more precisely supply current) of the motor for, fault detection techniques and current signatures of various faults.
Motor Circuit Analysis involving analysis of resistance, impedance, inductance, phase angle, current/frequency response and insulation to ground faults, and using using FFT (Fast Fourier Transform) analyzer is required for converting the signals from the time domain to the frequency domain. The amplitude of the peak in frequency is equal to the RMS amplitude of the sine wave time to the frequency domain is achieved using an algorithm called the Fast Fourier Transform (FFT) adopting techniques are Instantaneous Power FFT, Demodulated Current Spectrum, Wavelet Analysis, Park’s Vector Approach.
Basic System for Spectral Analysis of the Current signal of one of the phases of the motor is analyzed to produce the power spectrum, usually referred to as motor signature. The goal is to get this signature to identify the magnitude and frequency of each individual component that integrates the motor Signal Conditioner major faults of electrical machines can broadly be classified by the following.
⦁ Static and/or dynamic air-gap irregularities.
⦁ Broken rotor bar or cracked rotor end-rings.
⦁ Stator faults (opening or shorting of one coil or more of a stator phase winding).
⦁ Bent shaft (causing serious damage to stator core and windings).
⦁ Bearing and gearbox failures
Insulation resistance are measured in a spot insulation test which uses an applied DC voltage for low and high voltage equipment to measure insulation resistance in kilo, mega ohms. The measured resistance is intended to indicate the condition of the insulation or dielectric between two conductive parts, where the higher the resistance, the better the condition of the insulation. Ideally, the insulation resistance would be infinite, but as no insulators are perfect, leakage currents through the dielectric will ensure that a finite (though high) resistance value is measured.IR testers are portable often used in the field as the final check of equipment insulation and to confirm the reliability of the circuit and that there are no leakage currents from unintended faults. Main advantages of the IR test are its non-destructive nature. DC voltages do not cause harmful and/or cumulative effects on insulation materials and provided the voltage is below the breakdown voltage of the insulation and does not deteriorate the insulation within the safe test voltages
⦁ Capacitive Charging Current (Ic ): Insulator behaves as a capacitor when a DC voltage is applied to a capacitor, a high charging current first flows and then it decays exponentially. The size of the capacitor and the internal resistance of the voltage supply, typically a few hundred kilo ohms, set the currents decay. In case of generator or motor windings, the current effectively decays to zero in less than 10 seconds. Since the capacitive current contains little diagnostic information, the initial IR is measured once the capacitive current has decayed. Hence the first IR measurement has been set as one minute to ensure that this current does not distort the IR calculation.
⦁ Conduction Current (IR ): This current is due to the flow of electrons between the copper and the core. This is galvanic current through ground wall. Such a current can flow if the ground wall has absorbed moisture, which can happen on the older thermoplastic insulation systems. The current may also flow if there are cracks, cuts or pinholes in the ground insulation and some contamination is present to allow current to flow. This current is constant with time. With modern insulation this current usually is zero (as long as there no damage to the insulation).
⦁ Surface leakage Current(IL): This is constant DC current that flows over the surface of the insulation. It is caused by conductive contamination (oil or moisture mixed with dust, dirt, insects, chemicals etc) on the surface of the windings. This current is also constant with time.
⦁ Polarization Current(Ip): Electrical insulation is hygroscopic in nature and presence of moisture will be there either in low quantity or in excess. Water molecules are very polar. When an electric field is applied across the insulation start absorbing electrons from the hydrogen molecules causing ionization of hydrogen. In other words, the molecules constituting water align in the electric field, just as magnetic field. The energy required to align the molecules comes from the current in the DC test voltage supply. This current is called polarization current. The water becomes completely polarized when the absorption of electron from hydrogen merging with oxygen is completed. Once the molecules are all aligned, the current stops. The approximate time for complete polarization is 10 minutes. That is why the IR is measured after 10 minutes of applying voltage.
Now, the total current is the sum of all above currents, i.e.
It = Ic + IR + IL+ Ip
As we have analysed, after one minute, lc is zero.
So It (1 minute) = IR + IL + Ip
As we have seen that, after 10 minutes, Ip is zero,
So It (10 minute) = IR + IL
PI= Ir + Il + Ip / Ir + Il = R10 / R1
Effect of Temperature by measuring IR after one minute, one can diagnose the condition of the insulator. If it is less, the insulation will be considered to have been deteriorated. Unfortunately, just measuring IR has proved to be unreliable, since it is not tenable over time. The reason is that IR is strongly dependent on temperature. A 10°C increase in temperature can reduce IR by 5 to 10 times. When readings of temperature and insulation resistance are plotted on ordinary equally divided co-ordination, a curved characteristic is obtained. On the other hand, if graph paper is used on which the insulation scale is laid out in logarithmic division, the graph becomes a straight line. Further, the effect of temperature is different for each insulation material and type of contamination. Although some temperature correction graphs and formulae are given in the IEEE-43 are acknowledged as being unreliable for extrapolation by more than 10°C. The result is that every time IR is measured at different temperatures, one gets a completely different IR. This makes it impossible to define a scientifically acceptable IR value over a wide range of temperatures.
Polarization Index (PI) is the ratio between the insulation resistance measured after one minute and after 10 minutes of continuous testing at the appropriate voltage (PI = R10 min/R1 min). After 10 minutes, the capacitive current, the leakage current over the surface of the insulation and the dielectric absorption current will have stabilized. The PI obtained gives an indication of the condition of the insulation about its dryness and cleanliness; the PI will be lower for a dirty, wet chemically contaminated typical curves for variations of insulation resistances in windings for AC and DC rotating machinery PI greater than 4 is a sign of excellent insulation, while an index under 2 indicates a potential problem as per IEEE 43- 2000 recommendation practice for testing insulation resistance.
If a very high initial IR reading >5GΩ is found, then further PI tests are not needed.
The Dielectric Absorption (or Time-Resistance) test is an extension of the insulation resistance test where instead of a spot test, the testing device is applied to the insulation for up to 10 minutes. The idea is that the insulation resistance should increase over time as the atoms in the insulation are polarised by the IR tester’s applied DC voltage. In this test, the testing device is applied, and IR measurements are taken after 30 seconds and 60 seconds. The dielectric absorption ratio (DAR) is calculated as:
DAR = R60 second insulation /R30 second insulation.
Where R30 and R60 are the IR test measurements at 30 and 60 seconds respectively
A general guide to interpreting the DAR test results are as follows:
The step voltage test consists in the insertion of a high dc voltage across the insulation lasting 30minutes followed by a short circuit step to the insulation lasting 2 minutes more.
The presence of contaminants (dust, dirt, etc.) or moisture on the surface of the insulation is usually clearly revealed by time-dependent resistance measurements (PI, DAR, etc.). However, aging of the insulation or mechanical damage may sometimes be missed by this type of test, carried out with a low voltage in relation to the dielectric voltage of the insulating material tested. A significant increase in the test voltage applied may, on the contrary, cause these weak points to fail, leading to a considerable reduction in the insulation value measured.
To be effective, the ratio between voltage steps should be 1 to 5, and each step must last the same time (typically 1 to 10 minutes), while remaining below the classic dielectric test voltage (2 Un + 1000 V). The results from this method are totally independent of the type of insulation and the temperature because the method is not based on the intrinsic value of the insulants measured, but on the effective reduction of the value read after an identical time with two different test voltages.
A reduction of 25% or more between the first-step and second-step insulation resistance values is a sign of insulant deterioration usually linked to the presence of contaminants.
Dielectric Discharge method of insulation test is also known as re-absorption current measuring capacitance charging current, polarization current, leakage current during dielectric discharge through a resistor of the equipment under insulation test conditions.
The Dielectric Discharge (DD) Test is a diagnostic insulation test that allows aging and deterioration of insulation to be assessed. The result is dependent on the discharge characteristic, so the internal state of the insulation is tested, largely independent of any surface contamination.
This current is measured after a standard time of 1 minute. The current depends on the overall capacitance and the final test voltage. The value of Dielectric Discharge is calculated using the formula.
Current after 1 minute
Dielectric Discharge = ——————————————————————-
(Test voltage x Capacitance)
DD measurement method is temperature dependent, so every attempt should be made to perform the test at a standard temperature or at least to note the temperature alongside the test result.
Meg ohm Rule for IR Value of Equipment’s:
⦁ Based upon equipment rating:
⦁ < 1K V = 1 MΩ minimum
⦁ >1KV = 1 MΩ /1KV
As per IE Rules-1956:
⦁ At a pressure of 1000 V applied between each live conductor and earth for a period of one minute the insulation resistance of HV installations shall be at least 1 Mega ohm or as specified by the Bureau of Indian Standards.
⦁ Medium and Low Voltage Installations- At a pressure of 500 V applied between each live conductor and earth for a period of one minute, the insulation resistance of medium and low voltage installations shall be at least 1 Mega ohm or as specified by the Bureau of Indian Standards] from time to time.
Tan Delta, also called Loss Angle or Dissipation Factor testing, is a diagnostic method of testing cables to determine the quality of the cable insulation. In an ideal capacitor without any dielectric losses, the insulation current is exactly 90° leading according to the applied voltage. For a real insulation with dielectric losses, this angle is less than 90°. The insulation of a rotating electrical machine can be modelled by a loss-free capacitance with a parallel ohmic resistance representing the losses in the insulation system are caused by Surface currents, Leakage currents, Partial discharges, Polarization losses. A loss angle analyzer is connected with tan delta measuring unit to compare the tan delta values at normal voltage and higher voltages results, during test it is essential to apply test voltage at very low frequency.
Applying a voltage to the parallel components causes a current IC to flow through the capacitance as well as through the resistivity IR. The overall current I therefore has a resistive and a capacitive component. A causal relation between losses and the resistive part can be assumed, as the higher the losses are, the higher the resistive current will be. The angle δ = 90° – φ is caused by the resistive part of the overall current and is proportional to the losses, which leads to the definition of the tan(δ)
Another parameter commonly used for dielectric tests on rotating machines is the so-called power factor. In this case, the definition is different from the dissipation factor. Assuming power factor (PF) as the quotient of the resistive part of the current IR to the overall current I:
𝑃𝐹 = 𝐼𝑅 𝐼 = cos 𝜑.
𝑃𝐹 = tan 𝛿 √1+ tan² 𝛿
If the dissipation factor (tanδ) is very small – typically less than 10 %, which can be presumed as given when measuring healthy electrical machine insulation, the dissipation factor and the power factor differ in a negligible amount and can be assumed to have the same value as per IEC 60034-27-3.
Comparison between correlating values of dielectric power factor cos(φ) and dielectric loss factor tan(δ
Winding resistance tests are a measurement of the applied DC voltage and current to the device under test Using Ohm’s law the resistance is calculated in µΩ (micro Ohms) or mΩ (milli Ohms).Winding resistance measured using micro ohm meter of Transformers and motors, generators, to find out the winding faults like open windings, shorts to ground, wrong turn count, resistance are imbalance and balance between phases and also most important parameter to be measured to determine performance and efficiency.
Measurement of winding resistance is done across line to line. I.e. R-phase & Y phase, Y & B and R & B phases and the average value of line-to-line resistance obtained is designated as to convert the measured value of line-to-line resistance to phase resistance, the following Relationships are used.
In ‘Star’ connection, phase resistance, = 0.5 x
In Delta connection, phase resistance, = 1.5 x
The resistance must be corrected to the operating/full load temperature by using following relationship
R2 = unknown resistance at temperature T2
R1 = resistance measured at temperature T1
While estimating full load efficiency of motor, winding resistance at full load is calculated by using the temperature given for each class of insulation values are given in table 4.
While estimating motor efficiency at actual load, the winding resistance is measured immediately after stopping the motor. Hence temperature correction is not required in this case.
Use of digital ohm meters is recommended. It is sufficient to measure winding resistance with an accuracy of 0.001 ohms.
Partial discharge (PD) measurements are a proven method for effective, non-destructive evaluation of electrical insulation by means of condition monitoring using PD patterns for characterization of defects, and a scope-like display showing phase-summed charge pulses superimposed with the applied voltage wave. Partial discharge (PD) takes place due to the high voltage stresses due to that electric internal discharges, surface discharges and corona discharges initiates between one or both electrodes and sound dielectric is present in the shape of a solid, liquid or gaseous insulating material.
In On-line partial discharge (OLPD) monitoring refers to the diagnostics of high voltage (HV) insulation of in-service HV plant, including cables, switchgear, rotating machines and transformers, in their operational mode. The OLPD condition monitoring (CM) technique can be applied to all types of HV assets, with all components tested under both normal working conditions and abnormal variations related to changes in the associated thermal electrical, ambient and mechanical operational stresses.
Partial discharge and corona are frequently used interchangeably in the industry. According to IEEE 1434-1999, a partial discharge is an incomplete or partial electrical discharge that occurs between insulation and either insulation or a conductor. This is in contrast to a full discharge that spans the gap between two conductors, otherwise known as insulation failure. Corona occurs when the gas adjacent to an exposed conductor ionizes and produces visible partial discharges. Corona or PD does not involve insulation.
Lightning is a huge spark caused by the electrical discharge taking place between the clouds, within the same cloud and between the clouds and the earth. Lightning is one of the most serious causes of over voltage. If the power equipment especially at outdoor substation is not protected the over-voltage will cause burning of insulation.
Thus, it results into complete shutdown of the power stability purpose in electrical equipment can be damage due to over-voltage such as switching surge over-voltage, Lightning surge over-voltage, transient recovery voltage and power frequency
To protected these, over-voltages and over currents protection are important to consider. Lightning is one of the most serious causes of over-voltage. If the power equipment’s especially at outdoor substation are not protected, the over-voltage will cause burning of insulation. Lightning arrestor can protect the damages of equipment’s.
Testing the lighting arrestor as per IEC Standard 60099-2005 predicting the life of an arrestor and offers the most highly accurate means of measuring the present and past state of an arrestors health using resistive 3rd harmonic leakage current in field testing Metal oxide lighting or surge arrestor.
When voltage is applied to the arrester, due to non-linear voltage current characteristics of a metal-oxide used in arresters, harmonics are generated in the leakage current. In all the harmonics, the third order harmonics, which is predominant depends on resistive current of arrester. The magnitude of third order harmonics in the leakage current can be used as indicator of resistive current. The resistive component depends on applied voltage and temperature However as the system voltage itself may contain the harmonics which will significantly influence the measurement of third harmonics in total leakage current is combination of Capacitive Leakage Current & Resistive Leakage Current. Hence it is very important that the effect of these system harmonics is compensated to get correct results that reflect the healthiness of surge arrester.
The primary value of thermographic inspections of electrical systems is locating problems so that they can be diagnosed and repaired. “How hot is it?” is usually of far less importance. Once the problem is located, thermography and other test methods, as well as experience and common sense, are used to diagnose the nature of the problem. The following list contains just a few of the possible electrical system-related survey applications:
⦁ End bells
⦁ Inductive heating problems
⦁ Insulators Cracked or damaged/tracking
⦁ Line clamps
⦁ Oil switches/breakers
⦁ Pole-mounted transformers
⦁ Lightning arrestors
⦁ air switches
⦁ Oil-filled switches
⦁ Breakers (external and internal faults) –
⦁ Internal problems
⦁ Oil levels
⦁ Cooling tubes
⦁ Lightning arrestors
⦁ Bus connections.
⦁ Generator Bearings
⦁ Coolant/oil lines: blockage – Motors
⦁ cooling patterns
⦁ Motor Control Center
⦁ In-Plant Electrical Systems
⦁ Motor Control Center
⦁ Cable trays
⦁ Batteries and charging circuits
⦁ Power/Lighting distribution panels
⦁ Solar panels inspection
Detection of inter turn shorts in rotor windings of high voltage turbine generators (TG) has emerged as one of the important diagnostic measures in condition monitor (CM) for uninterrupted power generation. Conventional test methods cannot identify the location of defects. Recurrent Surge Oscillograph (RSO), an off-line novel technique method has widely supported the quality of decisions of diagnosticians to locate the shorts in rotor windings. This techniques in use to observe inter turn shorts of the field windings. Principle of time domain reflectometer (TDR) methodology of applying RSO technique for rotor windings wave patterns for possible inter turn shorts case study on faulty windings.
A steep fronted step voltage is repeated applied to the rotor windings using a Recurrent Surge Oscillograph (RSO) and the terminal voltage is examined for reflections from shorted turns. This test is very sensitive and will give an indication of the early stages of an inter-turn fault or earth fault.
Under the relatively high frequencies of the injected signals the winding behaves as a distributed impedance, and thus, any asymmetry due to shorted-turns, grounds and very large malformations of the conductors will result in changes on the waveform of the signals.
A significant proportion of shorted-turns are pressure dependent. The pressure is a function of the position of the rotor when idle, or speed, when rotating. Therefore, “spinning RSO” tests can be done with the unit at speed (during acceleration/deceleration and at full speed), to “catch” shorted turns that “disappear” when the rotor is standing still. When the rotor is idle, RSO readings should be taken with the rotor rotated at several angles.
Whenever electrical power transformer goes under abnormal thermal and electrical stresses, certain gases are produced due to decomposition of transformer insulating oil, when the fault is major, the production of decomposed gases are more and they get collected in Buchholz relay.
when abnormal thermal and electrical stresses are not significantly high the gasses due to decomposition of transformer insulating oil will get enough time to dissolve in the oil.
Hence by only monitoring the Buchholz relay it is not possible to predict the condition of the total internal healthiness of electrical power transformer. That is why it becomes necessary to analyses the quantity of different gasses dissolved in transformer oil in service.
From dissolved gas analysis of transformer Oil or DGA of transformer oil, one can predict the actual condition of internal health of a transformer.
It is preferable to conduct the DGA test of transformer oil in routine manner to get prior information about the trend of deterioration of transformer health and life. In dissolved gas analysis of transformer oil or DGA of transformer oil test, the gases in oil are extracted from oil and analyze the quantity of gasses in a specific amount of oil. By observing percentages of different gasses present in the oil, one can predict the internal condition of transformer.
Generally, the gasses found in the oil in service are hydrogen (H2), methane (CH4), Ethane (C2H6), ethylene (C2H4), acetylene (C2H3), carbon monoxide (CO), carbon dioxide (CO2), nitrogen (N2) and oxygen(O2). Most commonly used method of determining the content of these gases in oil, is using a Vacuum Gas Extraction Apparatus and Gas Chronographs. By this apparatus first gasses are extracted from oil by stirring it under vacuum. These extracted gasses are then introduced in gas Chronographs for measurement of each component.
Generally it is found that hydrogen and methane are produced in large quantity if internal temperature of power transformer rises up to 150oC to 300oC due to abnormal thermal stresses. If temperature goes above 300oC, ethylene (C2H4) are produced in large quantity. At the temperature is higher than 700oC large amount of hydrogen(H2) and ethylene(C2H4) are produced. Ethylene(C2H4) is indication of very high temperature hot spot inside electrical transformer. If during DGA test of transformer oil, CO and CO2 are found in large quantity it is predicted that there is decomposition of proper insulation.
A sudden increase in key gases and the rate of gas production is more important in evaluating a transformer than the amount of gas. Any generation of amount of gas in ppm indicate high energy arcing. Can be generate a very hot thermal fault (1000oC) Acetylene generated by internal arcing, sampling should be taken weekly to determine if there is an additional generation of gas. If no additional acetylene is found and level is within the standard the transformer may continue in service. Increase of Acetylene level the transformer has an internal arc and should be taken out of service, Operating transformer with high value of acetylene is extremely hazardous.
⦁ IEEE Std. C57.104.2008 IEEE Guide for the Interpretation of Gases Generated in Oil Immersed Transformers IEEE Std.
⦁ C57.12.80-2002 Terminology for Power and Distribution Transformer.
⦁ IEC 60599-2007-05 Mineral Oil Impregnated Electrical Equipment in Service.
⦁ Guide to the Interpretation of Dissolved and Free Gas Analysis IEC 60599-2007-05 Reference to Duval Triangle Diagnostic Model and C2H2/H2 Ratio Interpretation
⦁ ASTM D2945-90 (2003) Standard Test Method for Gas Content of Insulating Oils.
⦁ ASTM D3305-94 (2005) Standard Practice for Sampling Small Gas Volume in a Transformer.
⦁ ASTM D3612-02 (2009), Standard Test Method for Analysis of Gases Dissolved in Electrical Insulating Oil by Gas Chromatography.
⦁ ASTM D2759-00 (2010) Standard Practice for Sampling Gas from a Transformer under Positive Pressure IEC 60567-2011.
Transformer core and winding have mainly paper insulation. Base of paper is cellulose. The Cellulose has a structure of long chain of molecules. As the paper becomes aged, these long chains are broken into number of shorter parts. This phenomenon we often observe in our home. The pages of very old books become very much brittle. In transformer, the aging effect of paper insulation is accelerated due to oxidation occurs in oil. When insulating paper becomes mechanically weak, it cannot withstand the mechanical stresses applied during electrical short circuit and leads to electrical breakdown.
It is therefore necessary to monitor the condition of paper insulation inside a power transformer. It is not possible to bring out a piece of paper insulation from a transformer in service for testing purpose. But we are lucky enough, that there is a testing technique developed, where we can examine the condition of paper insulation without touching it. The method is called Furfuradehyde analysis of in short Furfural test. Although by dissolved gas analysis one can predict the condition of the paper insulation primarily, but it is not very sensitive method. There is a guide line in IEC-599, where it is told that if the ratio of CO2 and CO in DGA results is more than 11, it is predicted that the condition of paper insulation inside the transformer is not good. A healthy cellulose insulation gives that ratio in a range of 4 to 11. But still it is not a very sensitive way of monitoring the condition of paper insulation. Because CO2 and CO gases also produced during oil breakdown and sometimes the ratio may mislead the prediction.
When oil is soaked into paper, it is damaged by heat and some unique oil soluble compounds are realized and dissolved in the oil along with CO2 and CO. These compounds belong to the Furfuraldehyde group. These are sometimes called Furfural in short. Among all Furfurals compounds 2- Furfural is the most predominant. These Furfural family compound can only be released from destructive heating of cellulose or paper. Furfuraldehyde analysis is very sensitive as because damage of few grams of paper is noticeable in the oil even of a very large size transformer. It is a very significant diagnostic test. It is best test for assessing life of transformer. The rate of rise of percentage of Furfurals products in oil, with respect to time, is used for assessing the condition and remaining life of paper insulation in power transformer.
BDV mean the dielectric strength of transformer oil. A new transformer oil should have at least a dielectric strength of 39 kV from a British standard. Transformer oils used are normally tested using ASTM D877-82 with the kV strength tester using 1″ electrodes spaced 0.1″ apart and the test voltage increased at 3,000 volts/min until it breaks down.
The average kV obtained after 8 trials is considered the Oil dielectric strength. Using this test method, dielectric strength at 30 kV and above is considered good. Dielectric strength between 23 to 29 kV is considered usable but requires filtering. Below 23 kV the transformer oil should be replaced.
Another method ASTM D18747-82 uses the small radius electrodes but spaced only 4 inches. The test voltage is 500volts/min and increased until breakdown. The dielectric strength is still the average kV obtained in 8 trials. The dielectric strength of 28-29 kV is considered good. Below 28 kV, the transformer oil is usable but requires filtering. The latter method is considered a better test method.
⦁ Breakdown voltage (IEC 60156)
⦁ Dielectric dissipation factor, tan δ (IEC 60247)
⦁ Water content (IEC 60814)
⦁ Acidity (IEC 62021)
⦁ Inhibitor content (IEC 60666)
⦁ Interfacial tension (IFT) (ASTM D971-99)
⦁ Corrosive Sulphur (IEC 62535)
⦁ Colour (ASTM D1500)
Magnetic Balance test is used to conducted on transformer to identify inter turn faults and magnetic imbalance on the primary and secondary side of transformer to detect magnetic core structure faults on windings insulation failure causes change the effective reluctance of the magnetic circuit effects the magnetizing current establish flux in the core to check whether transformer is in good condition or not.
Electromagnetic Core Imperfection Detection testing is accepted world-wide for reliable and safe detection of stator core inter-laminar insulation faults for third generation reliable and easy-to-use for stator core test in less time with lower costs and can be equally applied to turbine generators, hydrogenrators, and large motors.
Around 5% flux is created in the stator core with the help of a loop wound toroidally around the core. A pick-up coil will be used to access the leakage fluxes that bridge adjacent teeth. Phase shifting due to eddy currents generated at the site of ‘hot-spots’ or shorted laminations between the accessed leakage fluxes and the exciting fluxes will be noted to detect the shorted laminations.
Stator cores are made of thin laminations of magnetic steel separated by insulation to prevent axial currents. If lamination shorts occur, the high temperatures that result can burn stator coil insulation and even lead to melting of stator cores.
The Robotic Inspection Vehicle enables remote scanning of the stator core of large motors and generators with or without the rotor in place controlled from outside the stator bore provides easier and more efficient testing of stator lamination insulation.
When large generators become operational, the stator bars in the slots are subjected to the electromagnetic force during normal operation. After the generators have been operating for a long time, the electromagnetic force may cause the stator bars to vibrate due to the existence of loose stator slot wedges in large generators. This leads to mechanical abrasion of the ground wall insulation and accelerates the deterioration of the generator and can even cause generators to fail if the slot wedges are not treated. In order to ensure large generators, continue working reliably, it is essential to detect loose slot wedges in the stator slots.
Moreover, a series of tests were performed with a nondestructive detection system developed based on this analysis to check the tightness of slot wedges. The results showed that loose stator slot wedges of large generators could be detected.
Stator wedges were traditionally tested for tightness by tapping them with a hammer and listening to the sound produced. Electronic stator wedge tightness detection is faster, more accurate, provides more consistent results than hand tapping methods, and the test procedure is repeatable. The SWA can be used to test all types of generators and motor stator wedges, including those with ripple springs.
Loose stator wedges may lead to vibration and erosion of stator insulation in electric generators. These serious problems can cause generator failure. The SWA acts as a sophisticated electronic ear that quickly and reliably provides an electronic map of wedge tightness.
In Standard test mode, tightness of each wedge is compared to predefined values while in Advanced mode the tightness of each wedge can be compared to all other wedges in the winding, the wedges of another winding or any user selected external reference. A coloured map showing the relative tightness of every wedge in the stator is produced and the data can be stored for trend analysis to determine when maintenance will be required.
This process, referred to as the CO2 Blast Cleaning Process, is accomplished by accelerating dry ice particles to a high velocity using compressed air or nitrogen, to impact and clean a surface. The effectiveness of this cleaning process is somewhat dependent on the skill of the operator; however, it is typical for considerable contaminant cleaning to occur on the first pass, with nearly all contaminants eliminated after two or more passes.
Traditionally, large electric equipment such as motors, generators, and transformers are removed and taken to an electric shop to be steamed cleaned. This process is extremely effective in removing contaminants from the equipment but require subsequent baking to remove moisture prior to reinstallation. Although this process is very effective in cleaning the equipment, it is extremely labor intensive, costly, and requires a significant amount of time to accomplish. This often results in equipment being out of service longer than otherwise required. In addition, the potential for equipment damage during removal, transportation, and reinstallation is increased.
CO2 Blast Cleaning is a totally dry, non-abrasive process that can be performed on-site, without having to transport disassembled equipment to a repair/cleaning facility. Since the process is non-abrasive, actual cleaning time will usually be slower than steam cleaning or abrasive cleaning methods (e.g., walnut shell, corncob, or baking soda), however, the overall time until the equipment is returned to service is considerably less (approximately 20% of the time for steam cleaning) since there is little or no drying time, very little cleanup, and no chemical or secondary waste generated. Overall, this makes the dry ice cleaning of equipment quicker and more cost competitive than other methods and is completely safe to the environment.