Megger - FAQ

Megger Frequently Asked Questions

Even though the correlation between battery capacity and impedance is not mathematically perfect, increase in impedance is an excellent indicator of battery health. Megger has found that, for flooded lead-acid batteries, a 20% increase in impedance generally indicates that the battery capacity has declined to about 80% of its initial value. For VRLA batteries, the corresponding impedance increase is closer to 50%. When these figures are reached, it is usual to consider that cell replacement is necessary.


Experience shows that loose inter-cell connections that heat up and melt open are responsible for more battery failures than defective cells. This is a particular problem with lead-acid batteries that are frequently cycled, as the negative terminal may cold flow, thereby loosening the connection. Checking inter-cell connection resistance is, therefore, vitally important. It is, however, essential to follow the correct sequence of test when working on multi-post batteries, and also to ensure that the instrument employs a method of testing that will provide valid results in this application.


The best frequency for impedance testing depends on the battery type, the site conditions and previous maintenance practices. The IEEE 11888 standard for VRLA batteries recommends, for example, that a baseline impedance measurement is made six months after the battery has been put into service, and that further impedance measurements are made at quarterly intervals there-after. For NiCd and flooded lead-acid batteries, Megger recommends impedance testing at six monthly intervals. Impedance measurements should also be made immediately before carrying out every capacity test.


Yes, provided that the right test equipment is used. Megger, for example, has testers that automatically sense and regulate the discharge current even when the batteries are connected to their normal load. Most users choose to make an 80% discharge test if the battery is to remain on line, thereby ensuring that there is still some back-up capability remaining at the end of the test.


In reality, float voltage measurements are of limited value. They can be used to confirm that the charger is working, but they give no information at all about the batteries state of health. Measuring the float voltage of a cell will also show whether or not it is fully charged, but it is important to remember that, just because a cell is fully charged, this doesn’t mean that it will deliver full capacity. It is by no means unusual for a battery that is close to failure to have a float voltage that is within acceptable limits. A low float voltage may indicate that there is a short in the cell. In a lead-acid battery, this should be suspected if the float voltage is 2.06 V or less, assuming that the charger is set for 2.17 V per cell. In other cases, a cell may float at a considerably higher voltage than average. This may be because the high float voltage cell is compensating for another weaker cell that is floating low. It is also possible for one cell to float high to compensate for several cells that are floating a little low, because the total of all the cell float voltages must always equal the charger setting.


In short strings (less than 40 cells), it’s advisable to replace the entire battery when between three and five cells have been changed. For longer strings, replacement is advised when more than 10% of the cells have been changed.


Battery systems are designed to provide back-up supplies during power outages. Since a discharge test is nothing other than a simulated power outage, there is no risk of battery damage. Batteries can normally be deep discharged (that is, discharged to the manufacturer’s end-of-discharge voltage) between 100 and 1,000 times, depending on the type of battery. Using a few of these discharge cycles for capacity testing has a negligible effect on overall battery life. Nevertheless, there is no reason to carry out discharge testing more frequently than recommended by the relevant standards.

Short the 2 test leads together and push the test button.


Certification usually requires a test current of 200 mA. Changing to a lower test current, such as 20 mA, when not certifying will give a better battery life.


Polarisation Index is the ratio of insulation resistance at 1 minute to 10 minutes. It shows how the insulation is charging up and can identify if insulation is clean and dry.


This would depend on the application. Usually 500 V is used on standard electrical installations. Lower voltages are used for control circuits and for quick checks that nothing is left in circuit.


The test leads may have been nulled incorrectly. Try and null them again. If this continues to occur, replace your test leads.


This symbol indicates that the instrument has experienced an overcurrent causing the fuse to blow. The fuse is located in the battery compartment and can be replaced with the spare fuse.


Most insulation testers will not operate if they detect a voltage on the circuit under test and will display the voltage that has been identified.


As the insulation value increases, the test current decreases and becomes harder to measure with the same level of accuracy.


The continuity range uses most battery power so may cause the battery symbol to show before other ranges.


Some insulation testers have a maximum reading of 99, 199 or 299 MOhms for different test voltages so good insulation may be shown as greater than (>) the maximum reading.

Unfortunately, this is a quirk of the printer which cannot be adjusted.


Yes. By purchasing a 3 phase adaptor lead, insulation and earth bond tests can be performed.


No. It meets strict safety requirements specific to electrical test equipment and is used by competent persons with training in electrical safety.


We recommend the Asset ID be kept to no more than 5-6 digits. Extra info can be added to the description if necessary.


Note: Use the correct method for your PAT tester model.

PAT300 & 400 series

Plug PAT into 110V supply using adaptor.

PAT4

Plug PAT 4 into 110V supply using adaptor.

PAT32

PAT 32 just 230V supply but plug appliance into 110V socket.


Class I has an earth so likely to have an earth pin in the plug and a metal casing. Class II is doubled insulated . Will have the following symbol on the information plate:


Note: Use the correct method for your PAT tester model.

PAT300 & 400 series

Hold down the test button while tester switches on and select reset.
Warning: Back up data before resetting as data may be deleted.

PAT4 & PAT32

Hold down the ‘R’ button while switching the tester on and select reset.
Warning: Back up data before resetting as data may be deleted.


PAT4 & PAT32 only Hold down ‘P’ on switch on and select required printer.


Only a visual test can be made on ITE though the detachable 3 core mains supply lead should be tested separately as a standard IEC lead. A bond test should not be performed on the metal part of the laptop plug as this may damage the charger. For more info see our application note, PAT testing IT equipment (found on the PAT300/400 page under resources).


Surge protection will normally fail a 500 V insulation test so this should be substituted for by either an earth leakage test or a 250 V insulation test.


Note: Use the correct method for your PAT tester model. PAT300 & 400 series Use the IEC lead to plug into the extension lead and the other end back into PAT in the IEC socket. For multi-socket leads, perform an earth bond test for each socket. PAT4 Need to use an IEC lead to plug into the extension lead and the other end back into PAT4 in socket labelled “Lead Test” PAT32 Use ELT1 to plug into extension lead and plug the extension lead into tester. Press required test buttons.


1000 Assets 10 Clients 20 Locations The PAT4 will display when you have reached the maximum limit. In this case the only thing to do is download the results and then reset the tester by holding down ‘R’ when switching the unit on.


Note: Use the correct method for your PAT tester model.

PAT400 series

You can use PC test group on PAT400s. Tests to be performed should be visual inspection, earth continuity, operation test and earth leakage.

PAT4

Can use PC test group on PAT4. Tests to be performed should be visual inspection and earth continuity. Can perform operations test and earth leakage with PAT4.


You can use an adaptor (p/n 35871), Set the port number in properties of Download Manager to the same number port in Device Manager to ensure software is looking at correct port.


Try AVO & 1234. If this does not work, you can look into the tester by using “CT17 9EN” for the user name. If there is data here you can download and reset the PAT.


Have you applied lead compensation? Long extension leads add extra resistance which needs to be allowed for. The PAT400 can calculate this for you.


The battery may not have enough charge. Try leaving the PAT plugged in for a couple of hours to charge or replace the 9 V rechargeable PP3 battery. Be sure to press the red button when finished testing to prevent the battery from draining.

Yes. The way a pre-insertion resistor works is that the resistor contacts will close first and will be the only contact in the circuit, then the main contacts will close and both resistor and main contact will be in the circuit at the same time in parallel. At this point the main contacts have the vast majority of the current flowing since the resistance is in the micro-ohm range compared to the 10-10 kilo-ohm range of the resistor (depending on design). The design of the circuit breaker can vary but for the majority of the circuit breakers, once the main contact is closed the resistor will open up shortly afterwards i.e. a few milliseconds, for other designs the resistor may be left in the circuit while the CB is closed.


This depends on the design of the circuit breaker. For some designs the pre-insertion resistor will close first, then shortly after the main contacts close, the pre-insertion resistor will open. For other designs the pre-insertion resistor will stay closed while the main contact is closed.


The two predominant standards are:

  1. IEEE C37.09 IEEE Standard Test Procedure for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis.
  2. IEC 62271-100 High-voltage switchgear and controlgear – Part 100: Alternating-current circuit-breakers.


No. To test the 50/51 relays a secondary current injection test set is required. Megger has a range of relay test sets that can be used to accomplish this.


A live tank breaker can be used for a breaker and a half scheme. From an operating standpoint you can use either a live tank breaker or a dead tank breaker you just need to take into consideration several design parameters such as physical dimensions, CTs needed, etc.


This depends on the type of circuit breaker. For medium vacuum CBs, time and travel analysis is recommended but not required. For Oil CBs and SF6 CBs, they require a time and travel analysis test. This is according to the NETA ATS-2013 and MTS 2011.


There are a couple ways to look for an SF6 leak. One method is to use a gas “sniffer” that you move around the breaker and it will give you an audible indication when it finds the leak. Another method is to use and special infrared camera designed for SF6 leak detection.


Basic testing for all breakers is the same. You want to record coil current, station voltage, contact resistance, contact times and travel, then calculate certain parameters from these. The main difference from a vacuum CB compared to an SF6 or OCB is that the stroke will be much shorter.


Yes. Even if you don’t have the proper conversion factor or table you should still perform a travel recording to help evaluate the breakers performance. You will not be able to correctly determine the velocity of the contacts but you will still be able to trend the motion over time. If you know the stroke length you can build a simple conversion factor where the total angle or distance traveled is equal to the stroke length of the circuit breaker. It should be noted that this method assumes that your circuit breaker is working correctly at the time of measurement. You can then use these values moving forward. Additionally you can still look at parameters such as overtravel, rebound and contact wipe as a percentage of the total stroke to determine if you need to adjust the dampening on the mechanism.


Yes. Velocity is important to all circuit breakers. When evaluating vacuum circuit breakers, motion and subsequently velocity is often not measured. Additionally, the manufacturer may not give you any specifications for the velocity. It is still an important parameter that you can trend to verify correct operation. Even though the manufacturer may not provide velocity specs, they may still provide stroke and overtravel specifications.


There is no industry standard determining the test frequency and type of tests to be performed. These vary by type of CB, manufacturer, and the type of application the circuit breaker is utilized in. It is best to consult the circuit breaker manual to determine proper maintenance and testing schedule. It is common to have 1, 3 or 5, and 10 year maintenance intervals for different types of tests to be performed.


No. Travel measurements are a very valuable tool in circuit breaker analysis. One of the common arguments against measuring motion on vacuum CBs is that the contact stroke is so short that you are better off measuring stroke with a pair of calipers when the breaker is in fully open position compared to fully closed position and you can verify the CB is traveling fast enough from the contact times. If you don’t measure motion you will lose valuable information about how the circuit breaker is behaving and won’t see if there is a large amount of overtravel or rebound. If these parameters are too large it can cause damage to the breaker or miss-operation. These parameters can often be easily adjusted in the field and you may be able to find the tolerances on the nameplate.


This is a frequently debated topic. If the circuit breaker has grading capacitors that you have access to i.e. Live Tank CBs then it is recommended to test these to verify their value. Most manufacturers don’t recommend Power Factor testing SF6 dead tank circuit breakers. To check the quality of the SF6 gas i.e. the insulation of the CB, it is recommended to perform a moisture and purity test on the SF6 gas.

There have been some reports that you can determine some issues within the CB contacts with a Power Factor test, so several utilities still promote and perform these tests on SF6 circuit breakers. If you perform PF testing on your SF6 CBs remember that you will have very small capacitance values and that your primary evaluation should be of the watts lost and the leakage current. A hot collar test may also be performed to evaluate the condition of the porcelain and the external insulation elements.


When the circuit breaker opens and closes it is traveling at a very high velocity. It then must slow down very quickly without damaging the interrupter. This is accomplished by using a dashpot which absorbs some of the energy to slow down the interrupter towards the end of its travel. Dashpots are commonly applied on the opening side of the mechanism but there are several designs with it on the closing side as well.


Dynamic resistance measurements are basically making a micro ohm measurement simultaneously while performing time and travel on a circuit breaker. From this measurement you can evaluate the arcing contacts on an SF6 circuit breaker.


Coupling capacitors are used to reduce the rate of rise of breaker transient recovery voltage, and to limit the overvoltage caused by a short distance fault on a low capacitive line while the Grading capacitors are used to distribute the high voltage equally.

Those are connected in parallel to the interrupters, but usually coupling capacitors on some dead tank circuit breakers and grading capacitors on live tank circuit breakers.


According to IEEE C37.04 1999, the minimum reclosing time of a circuit breaker is 0.3 seconds (300ms).


The manufacturer should provide a list of the parameters and the range of values that should be expected. It can vary by breaker design but if no list is provided, at a minimum, the following should be measured:

  1. Contact times
  2. Max contact time difference between phases
  3. Stroke
  4. Overtravel
  5. Rebound
  6. Velocity
  7. Coil current
  8. Station voltage
  9. Contact Resistance


Neither type of transducer is inherently more accurate than the other. Depending on the circuit breaker/mechanism design a rotary or a linear transducer might be more suitable for the particular application. Each circuit breaker should be evaluated individually for the best connection and the manual or manufacturer should be consulted for proper connection.


For further reading, download our HVCB testing guide or view some of our technical papers.


You should look for an easily attachable place where your transducer will move in conjunction with the interrupter(s). You should also try to mount the transducer to a solid piece of metal that won’t vibrate during operation of the circuit breaker. The closer you are to the interrupter without mechanical linkages in between, the more accurate your travel trace will become. Once a transducer mounting spot is established, you should continue to test it at this spot for accurate trending purposes.

Perhaps not from a theoretical point of view, but from a real-world point of view the TDR should fit the cable/application.


The TDR, when used by itself is a LV device. So any adjacent conductors should not present any limitations (this is assuming the cable in question meets the TDR’s requirement for a shielded cable, or two parallel conductors). However the Arc Reflection Method uses both the LV TDR in combination with a HV pulse (typically from a thumper). The HV ARM shot could impact adjacent cables.


Yes, the Arc Reflection Method is ideal for concentric secondary cables. The only caution is to make sure the operator does not apply more than the required voltage if using a high capacity unit.


None that we are aware of, particularly when dealing with MV power cables.


Absolutely. In fact on direct buried cables, if the cable fails the VLF test, one would typically use the TDR/ARM to find the fault.


TDRs can sometimes be used on these type of cables if the two parallel conductor requirement is met.


TDRs can be used on straight runs of PLIC insulated cables. However on faulted PLIC cables, the standard ARM methods may not work. In this case ARM-Plus, Decay and ICE are other TDR based pre-location methods that can be substituted for ARM.

Note: None of these methods would be used oil filled pipe type transmission lines.


From a practical point of view, a TDR cannot accurately measure the amount of remaining neutral. At best some TDRs can indicate some level of neutral damage or loss. An exceptionally experienced operator might develop a general feel for neutral condition.


They cannot. A TDR simply reflects off of significant impedance differences. To see a fault caused by failed insulation (pinhole fault) the TDR needs the HV Arc from a thumper (Arc Reflection Method, ARM). However there are two cases where the TDR can see a fault without an Arc:

  • If the center conductor is severed in half
  • If the center conductor is shorted (touching) the neutral concentric (bolted fault—rather uncommon) 

The TDR will see most splices as they typically have a large enough impedance reflection. However to distinguish between a properly constructed verses a poorly constructed splice is not practical.

Note: Partial Discharge testing can be used to identify poorly constructed splices.


TDRs cannot see any type of treeing, water or electrical, in any type insulation, PILC or solid dielectric. However, one could argue that a fault is an electrical tree and in this case the ARM method will pre-locate this type of damage.


If a corroded neutral still has some electrical continuity then the TDR will work. However if the neutral is severely corroded, say at 500 feet, then the TDR will see 500 feet, but not see anything past 500 feet.


The EasyLoc is designed only for tracing the cable’s path. However, if the cable is completely cut, you might be able to determine this "fault" location from a massive drop in signal strength with the transmitter is connected to the cable. While the EasyLoc might be able to locate faults in very specific cases, it was not designed to pre-locate a faulted/cut cable.


No, but it can help save time if you have an expected cable length in mind before beginning. However, even if you do not have this information, there are independent ways (e.g. ground/unground the far end) to verify actual distance seen by the TDR.


When your TDR is connected into a thumper system there are three hook-up leads:

  • HV Output
  • HV Return
  • Safety/Equipment Ground

When connected to a thumper, the TDR uses the HV Output and HV Return as its two leads. For phase to phase testing, the HV Output is connected to one phase and the HV Return is connected to the other phase.

Note: During phase to phase TDR testing/comparisons you typically do not use any HV from the thumper. The exception would be if you had pre-determined you are working a phase to phase fault, then you might attempt a standard HV ARM pre-locate.


Yes, this has been field measured and shown to be safe. When using ARM through transformers for power restoration, each primary coil "sees" a LV-high frequency pulse (TDR) combined with a HV- high frequency pulse (single thump). Each primary coil acts like a large inductive choke to these high frequency pulses. This means that the high frequency pulse does not excite the primary (60 Hz) coil, but rather passes on down the circuit, looking for a path to ground through the actual fault.


TDRs basically require two parallel wires. Usually this is a center conductor and shield (or neutral), which is most comonly a cable with concentric construction. However any set of parallel wires can work, phase to phase (leg to leg) etc. It is usually fairly straight forward to verify if a TDR will or will not work in most applications.


This is a rather complex topic but in short:

  • TDRs generate and send a pulse down/back in the cable being tested
  • When doing PD testing, the pulse in question comes from actual PD inception. We can localize the point of inception using TDR techniques

If there is only one single split (e.g. one buried Y splice) you can use standard ARM fault location. There could be some extra but simple steps needed to determine which leg the fault is down. However, if there is more than one Y splice TDRs quickly become problematic.

Note: TDRs are not generally used in through network systems unless the network can be quickly/easily broken down to straight runs.


The Ohm Check (a unit that uses the bridge method) requires a reference wire be run above ground, along the length of the cable to be tested. Barring this operational constraint, it is currently the best way to accurately gage the condition of neutral concentric.

The TDR's advantage would be that it does not require an above ground reference wire, but from a practical point of view, a TDR cannot accurately measure the amount of remaining neutral. At best some TDRs can indicate some level of neutral damage or loss. An exceptionally experienced operator might develop a general feel for neutral condition.


This downward trace on the very left hand side of the display screen is the reflection for the test lead hook up (characteristic hook-up impedance change).

Note: Some TDRs will automatically shift this initial reflection off to the right, thereby removing it from view.


Different TDRs have different maximum ranges. For example, a common Megger cable fault locating TDR (for URD work) has a maximum range of 25,000 or 100,000 feet. Other fault locating models offer maximum ranges of 34 miles, 100 miles and one unit offers up to 790 miles.


The filter is normally sized to the thumper. In this case the maximum HV thump level for the filter and thumper are equal. However if you have added a filter to a thumper, then the maximum thump is dependent on the on filter’s rated maximum limit.


Arc Reflection Method (ARM) is ideal for MV URD type power cables. However ARM can be used on other class cables. In essence what’s required is simply a shielded cable. Megger offers ARM units that operate at 3-4 kV maximum output for lower voltage class shielded cables.


Regardless of cable length, the far end is never grounded while actually thumping or doing single ARM shots. Doing so would provide a direct path to ground for the HV pulse.


A web search or contacting the manufacturer of your cable or test instrument might produce a usable number. However the best way would be to define the actual propagation velocity using a known length of cable.


You can download one here. Please remember that generic cable velocity lists should be considered guidelines only.


From a practical point of view no, ARM would not cause more damage to a faulted 69 kV class cable. Remember, ARM pre-locates the fault with one or so impulses. This pre-location distance then reduces the number of thumper impulses required to pinpoint the fault.

A paper examining the effects of thumping is Hartlein, R.A, et. al. Effects of voltage surges on extruded dielectric cable life project update, IEEE Transactions on Power Delivery (Vol 9, Iss 2), 1994.


Generally yes, ARM is ideal for most high impedance faults. However there are exceptions, for example, when a neutral is separated far enough to cause a very high resistance tracking path for the HV Arc, ARM may not work.


Within reason yes. However if the separation is far enough to cause a very high resistance tracking path for the HV Arc then ARM may not work. An example of this a faulted splice, where the neutral was pulled well away from the splice body during construction.


TDRs should work on the first zone, before the side tap. TDRs are not typically used through networks and work best on straight runs of cables.

Note: TDRs easily see down single phase loop feed circuits with splices and transformers. TDR’s do work well through networks or junction boxes that split the cable path.

The traditional answer would be to sample the oil from the transformers, and to determine the moisture content of the sample either by dissolved gas analysis (DGA), or by the Karl Fischer titration method. However, this approach has some shortcomings. One is that the oil content of a typical HV CT is small, so repeated sampling to monitor moisture ingress into the CT over a period of time is not really practical. Another limitation is that the DGA and Karl Fischer tests determine the moisture content of the oil, but cannot be depended upon to provide accurate information about the moisture content of the solid insulation (usually papers) in the CT, which is often implicated in thermal runaway leading to catastrophic failure. A better option for determining the moisture content of HV CTs is to use frequency domain spectroscopy (FDS) testing.


The test set up for an FDS test is virtually the same as that used for conventional tan δ testing. The big difference is that conventional tan δ tests are carried out only at power frequency, whereas as FDS tests involve injecting a test signal that sweeps over a wide range of frequencies, typically from a millihertz or so up to around a kilohertz. By recording the response of the CT to this test signal during the frequency sweep and analysing the results, it is possible to reliably estimate the percentage moisture in the solid insulation. No oil sampling is of course required with this method, so not only is more convenient, it also means that testing can be carried out regularly with no risk of depleting the volume of oil in the transformer.


Although FDS testing is a relatively new technique, easy-to-use transformer test equipment is now readily available. A good example is Megger’s portable IDAX300 test set. This performs FDS tests on standard CTs and captures the test data fully automatically, using pre-stored proven algorithms. It is also fully client configurable to meet any bespoke testing requirement.

If a fault occurs in an electrical system, we must prove that the over-current device will operate within the prescribed time by ensuring that the circuit impedance is low enough to allow sufficient current to flow. The required values of impedance and time will change dependent upon the type of installation (TN/TT etc.) and the type of protection, whether it be a miniature circuit breaker (MCB), cartridge fuse or re-wireable fuse for example. The fault current can either be in the Line-Neutral or Line-Earth circuit, so there is a need to confirm the loop impedance of each.


Determining which test to use will depend upon a number of factors, not least being which one is available on the test meter being used. A non-trip test has to be used on an RCD-protected installation. A high current test will usually be faster and more accurate on non-RCD protected circuits.


This is the traditional loop impedance test. Using a test current of up to 20 A and a simple 2 wire connection, it is by and large the fastest, most accurate test available on a day to day basis. Most standard loop impedance testers will incorporate this type of test. Because of the relatively high test current, the readings are not generally influenced by external factors and will return repeatable, stable readings in most scenarios.


When first conceived, earth leakage monitoring RCDs and RCBOs were not part of the electrical installation and because it relies on a short between Line-Earth for the earth loop test, albeit only for 2 cycles (or 40 ms) of the AC waveform, the test will cause the RCD/RCBO to operate. In addition, some early instruments whose test time was not so tightly restricted had cause to operate some of the low current MCB’s as well. Where earth leakage protection was in place, the contractor was left with no option but to bypass it to allow for the test to be undertaken – a time consuming and rather un-safe practice as it left the system unprotected for the duration of the test.


The 3 wire method of no-trip loop testing has become the norm over the past 20 years. This test method overcame the need to by-pass even the new electronic protection devices by utilising a low current Line-Earth test current, whilst still returning a degree of accuracy. Not having to by-pass the RCD/RCBO obviously introduced a time saving factor. In addition, by having the requirement of connecting to Line, Neutral and Earth, the testers were now able to confirm the presence of all three as well as indicate if there was a reverse polarity at the test point and, due to the limited test current, there was no issue with tripping the MCB. There remain limitations with the 3-wire test however. Due to the lower test current, readings became more susceptible to external factors introducing instability on certain circuits and a reduction in consistency. In some circumstances the internal impedance of the RCD can be seen or existing system earth leakage can combine with the test signal to cause the protective device to operate.


At a light switch a neutral is usually not available so a 2-wire test is easier for testers without 3 hands.


This new method of testing will only be undertaken in certain circumstances. The test uses a 4 wire Kelvin connection, negating internal lead and contact resistance; such is the accuracy of the test. With test currents up to 1000 A, measurements down as low as 10 mOhm can be accurately made. Consequently, there is no “No-Trip” option with this test method. With specific applications being measurement in sub-station/switch room environments, this tester gives the test engineer the ability to take accurate readings when situated next to the main transformer – something that has caused problems for many years when trying to sign off jobs with readings based on design engineers calculations down as low as 0.001 Ohm!


When making a loop impedance measurement, there are numerous challenges that the test signal has to overcome. Some are physical and some are man-made. Having an understanding of the limitations of the various tests that are available goes some way in overcoming some of these obstacles. Just as importantly, knowing the significance of the desired value (usually stipulated by regulation) and an appreciation of the measured value in the real world will help to maintain confidence in the recorded value.


Prospective fault current and prospective short circuit testing are measurements that are made to calculate the current that will flow in the event of a fault. Too little current and protective devices may fail to operate in time (if at all) and too much current will cause damage to equipment, may cause fire or prevent the breaker from operating.

If PowerSuite is installed you can find the version number by going to Help and then About.


Yes, if you navigate to ‘Settings’ then ‘Preferences’, under the security section of the general tab you can add new users, change their user level and assign a password if required.


Unfortunately the Megger PowerSuite software is not compatible with Apple Mac products.


To add a password to your PowerSuite software navigate to ‘Settings’ then ‘Preferences’ and under the Security section select your User ID, you can then adjust your user level and add a password.


With the PowerSuite software navigate to ‘Settings’ then ‘Preferences’ and click ‘Browse’ to search for your company logo.


In order to change your next certificate numbers go to ‘Settings’ then ‘Preferences’ followed by selecting the ‘Certificate Manager’ tab. Here you can set the next certificate number for all your certificates.


To create a backup of your database you will need to copy and paste your ‘Data’ folder. This can be found in one of the following locations depending on OS:

Windows XP:

C:\Documents and Settings\All Users\Documents\Megger Limited\PowerSuite Professional

Windows Vista, 7 and 8:

C:\Users\Public\Documents\Megger Limited\PowerSuite Professional


In order to edit a contact simply right click the contact and select 'edit company', 'edit client', or 'edit location'.


To email a certificate we would recommend printing the certificate as a PDF and then emailing the PDF. If you do not have a PDF printer it is possible to download free PDF printers from the internet.


There are a few places where you can find your PowerSuite serial number, they are:

On your PowerSuite registration card.

Within the software under ‘Help’ then ‘About’.

A file called ‘ps32reg.exe’ which can be found in the following location:

C:\Program Files (x86)\Megger Limited\ PowerSuite Professional


There are two ways you can create a certificate, you can either use the Certificate Wizard or use ‘Certificate Manager’ to select your certificate type and template.


A download guide for the PAT400 series can be downloaded from here.


An upload guide can be found by clicking the following link.


This is when a Computer Friendly (CF) certificate has been created and not a Plain Paper (PP) one. Computer friendly certificates are used when you have pre printed templates bought from the NIC. Plain paper certificates simply print the whole certificate on to plain paper.


An NICEIC A1 Certificate abbreviation reference list can be downloaded from the following link.


The default username on a new install will be "supervisor" there is no password by default.


Compatible with

Minimum version

Windows Vista

2.1.73

Windows 7

2.1.128

64bit OS

2.1.190

MFT1730

2.1.266

PAT400

2.1.205


There are four main builds of the PowerSuite software, click the following link to download a datasheet which contains information on each version.

What version of PowerSuite do I need?


CSV viewer is a programme built into Download Manager that is used to view your downloaded results. If you do not use CSV files for anything else other than downloading from your tester then we would suggest saying ‘Yes’ to this prompt.


The cause of this error is usually down to PowerSuite still running in the background or a third party piece of software blocking the installation.


This error is usually caused by user permissions. Make sure you are logged in as an administrator if this is the first time installing the software. If you have been able to use the software in the past then it’s possible your user permissions have been changed.

Yes, each test will provide a different piece of data your transformer. A power factor test looks at the insulation of the transformer. Turns ratio and winding resistance tests reveal the condition of the windings. SFRA provides information about the mechanical integrity of the transformer and can help you determine if a transformer has sustained any mechanical damage.

Each electrical test you perform gives you a bit more insight, and together they form a more complete picture of your transformer's health. Sometimes a "second opinion" from two or more tests on the same component can help you confirm a suspected problem.


Per IEEE C57.149, testing with oil is the most common and preferred method for frequency response analysis. Special consideration should be given to safety when testing a transformer without oil so that excessive voltages are not applied. Presence of oil changes the frequency response. Results with and without oil will cause variations in the SFRA traces. Below is an excerpt from the IEEE guidelines:

"For new equipment, this my require the performance of two FRA tests after receipt of the equipment at the final destination: 1) one test with the transformer in its shipping configuration, 2) and one thest with the transformer assembled an oil-filled as required for insulation resistance testing, to be used as baseline data for future testing. If no shipping damage is suspected, the test in the as shpped configuration may not be necessary as a receipt test"

Often, the manufacturer fills and drains the transformer before shipment. You should be aware of the conditions in which an SFRA test was performed before shipment from the factory. IEEE further states that:

“If the equipment is to arrive drained of oil, the shipping configuration should specify that it will be tested pre and post movement without oil. If the equipment is to be shipped after being drained of oil, it should be tested pre-movement without oil. Testing the unit prior to shipment in this case without oil and prior to a first fill, may not be adequate and could lead to false failures due to residual oil being held in the windings, or additional oil draining from the winding during weeks of shipment. If the equipment is to be shipped with oil, it should be fully filled for both pre and post movement tests. If the equipment is to be shipped partially filled, it should be tested with the same level of oil, or preferentially after oil has been added. Ensuring oil is at the same level before and after transportation for partially filled transformers can be difficult and sometimes leads to incorrect assessments.”


Yes. SFRA test results, when performed correctly and under similar conditions (correct grounding, same tap position and similar connections), are comparable. Factors that can affect test results include residual magnetism and poor grounding practices. Megger's FRAX software has the unique capability to import previous results from any other manufacturer's test set and compare results.


For SFRA:

There is no particular order that needs to be followed for the open circuit and short circuit tests. However, to increase efficiency, you might want to run the tests in an order that will help you minimize lead changes

For complete electrical tests:

Excitation current and SFRA should be completed first and winding resistance test last. This is to avoid any residual magnetism from the winding resistance test from affecting the results of the other tests. However, If your winding resistance test set is capable of demagnetizing the transformer efficiently after the test, you will not have to worry about the test sequence.


IEEE C57.149 states that “Large temperature difference, typically much more than 10 C, between two measurements will slightly influence the response at higher frequencies.”

For all practical purposes, the effect of temperature on SFRA measurements is very small and can be ignored unless there is big temperature variation between the two comparison traces.


Traditional open and short circuit tests are typically performed in factory to determine the no load and copper losses taking place in the transformer. Rated values are typically used when performing these tests. By determining the no load and copper losses, you can determine the different components in an equivalent circuit of a transformer.

Although they share similar names and connections, SFRA open circuit and short circuit tests are completely different. The SFRA open circuit test looks at the response of the core and winding, and the SFRA short circuit test isolates the winding response of the transformer. These tests help you narrow down the areas where the problem might be.


You would have to run a total of 30 different tests.

  • 12 open circuit tests, one on each winding (4 windings x 3 phases =12 tests)
  • 18 short circuit tests:
    • 9 tests (From high side with three secondaries shorted one at a time)
    • 6 tests (From X side with other two secondaries shorted one at a time)
    • 3 tests (From Y side with the last secondary shorted)

In such cases, IEEE C57.152 recommends performing all electrical tests including Power Factor and SFRA. A power factor test may reveal a change in capacitance, and comparing this to a SFRA trace will help the diagnosis of any issues or failures associated with transformer windings.


The IEEE guide for SFRA is IEEE C57.149 Guide for the Application and Interpretation of Frequency Response Analysis for Oil-Immersed Transformers. Other relevant SFRA documents include: IEC60076-18 Ed. 1 – 2012, Std. DL/T911-2004, and Cigré Technical Brochure No. 342, April 2008.


Yes. IEEE C57.152 Guide for Diagnostic Field Testing of Fluid-Filled Power Transformers, Regulators, and Reactors recommends SFRA as a diagnostic test. SFRA can often pick up mechanical issues that other electrical tests might miss.


A SFRA open circuit test will show the response of core and windings, while a SFRA short circuit test only shows the response of windings. Each frequency range corresponds to dfferent components in the transformer. Some general frequency ranges are shown below.

  • 20 Hz – 2 kHz: Main core deformation, open circuits, shorted turns, residual magnetism
  • 10 kHz – 20 kHz: Bulk winding component, shunt impedance
  • 20 kHz – 400 kHz: Deformation within the main windings
  • 400 kHz – 1 MHz: Tap winding

However, keep in mind that each transformer will have specific responses and the frequency range given is for general reference only. For windings rated less than 72 kV, IEC recommends running the test up to 2 MHz.


SFRA and DFR are two completely different tests. SFRA looks at any kind of mechanical changes inside the transformer whereas DFR is used to determine the moisture present in cellulose (solid insulation) of oil filled power transformers. The two tests have very different applications.


There is no industry guideline for using SFRA based on a transformer’s VA ratings. In theory, you can perform SFRA on a transformer of any size, and if subsequent tests are performed under similar conditions, the results can be compared and analyzed. Other electrical tests like transformer turns ratio, excitation current and DC insulation tests will also give valuable information on smaller transformers.


Yes. SFRA looks at the response of the complex RLC network inside a transformer. You can perform baseline or reference measurements on dry type transformers and compare results over the years. For dry type transformers, you need to be aware of the effect that ground capacitances can have on the traces. Additionally, the response on the low side may have slight deviations because of low signal levels. A very good ground plane will produce more repeatable measurements.