Electrical
Transformer acceptance testing and the turns ratio (TTR) field guide
Prove the transformer before you energize it: the turns ratio, the insulation, the winding resistance, the polarity, and the tap, then record the baseline the maintenance crew will trend against.
Direct answer
Transformer acceptance testing is the set of field tests run on a new or repaired transformer before it is energized: turns ratio (TTR), insulation resistance, winding resistance, and polarity. It proves the unit is wired right and undamaged in shipping, and sets the baseline for later maintenance trending. NETA ATS and IEEE C57 control the criteria.
Key takeaways
- Transformer acceptance testing runs TTR, insulation resistance, winding resistance, and polarity before energizing, governed by NETA ATS and IEEE C57.
- TTR tolerance holds the measured ratio within 0.5 percent of the nameplate ratio on each winding and each tap.
- Run the TTR on every de-energized tap position and all three phases, not just the nominal tap.
- Discharge and ground the windings through a ground stick after every DC test, since the winding holds a lethal charge.
- Verify and set the de-energized tap for the measured supply voltage, then confirm it with a TTR on that tap.
Transformer acceptance testing, and what it proves
Transformer acceptance testing is the group of field tests run on a transformer before it is energized for the first time, or after a repair, to prove the unit is wired right and healthy. The core tests are the turns ratio test (TTR), insulation resistance, winding resistance, and a polarity and phase check. On larger and liquid-filled units you add insulation power factor and oil tests. Together they answer one question: is this transformer the same one the nameplate describes, and did it survive the trip to the site?
A transformer leaves the factory tested. Then it gets craned onto a truck, hauled across the country, dropped on a pad, and sometimes stored outdoors for a season before anyone wires it. The factory test proves nothing about what happened in between. Acceptance testing is how you catch a winding that shifted on a hard shipping impact, a tap that got moved, a bushing that cracked, or moisture that worked into the insulation while the unit sat.
The second job is the baseline. Every reading you take at acceptance becomes the number the maintenance crew compares against in five years. A winding resistance or a power factor reading means little in isolation. It means everything as a trend. Skip the acceptance test and the first maintenance test has nothing to trend against, so a slow degradation has no early reading to reveal it.
Why test a transformer before energizing it?
You test before energizing because a damaged or mis-connected transformer faults the moment it sees voltage, and energizing it is the most expensive way to find out. A shorted turn, a wrong tap, a reversed polarity on a parallel bank, or moisture in the insulation does not wait. Close the primary breaker on it and you can lose the transformer, trip the upstream gear, and put the crew next to a failure that did not have to happen.
The failures acceptance testing catches are the ones that happen between the factory and the first energization. Shipping impact deforms a winding or loosens a connection. Someone moves the de-energized tap to check it and leaves it on the wrong step. A repair shop rewinds a unit and gets a turn count slightly off. A re-connection for a different voltage gets wired backward. None of these show on a visual walk-around. All of them show on the test set.
The other reason is the baseline, and it only exists if you test before the unit goes into service. Once it has been loaded and heated, the acceptance numbers are gone. Catch it before the energize, not after the fault, and record it before the load, not after.
The turns ratio test (TTR)
The turns ratio test is the headline of transformer acceptance testing. A TTR set applies a known low voltage to one winding, reads the voltage induced in the other, and reports the ratio of primary turns to secondary turns. That measured ratio gets compared to the ratio the nameplate says it should be. The accepted tolerance is tight: IEEE C57 guidance, the basis NETA field testing follows, holds the measured ratio within 0.5 percent of the nameplate ratio for each winding and tap.
That one number proves a lot. A ratio that matches the nameplate confirms the turns are intact, the tap is where it should be, and the winding is connected the way the nameplate describes. A ratio that misses tells you something is wrong inside before you ever apply full voltage, and the size and direction of the miss points at what.
The test is fast, it is non-destructive, and it needs the transformer completely de-energized and isolated. It is the most informative single test you run on a transformer at acceptance, which is why it leads the list and why an out-of-tolerance result stops the energization until it is explained.
Reading the TTR: each tap, each phase
You do not run the TTR once. You run it on every de-energized tap position and on all three phases, because that is the only way to confirm the tap changer and compare the windings against each other. A reading that passes on the nominal tap can still fail two steps up if a tap lead is broken or the changer contact is dirty, and you would never see it testing one position.
Read the deviation, not just the pass or fail. A small, consistent error across all taps and phases is often the instrument or the test connection. A single tap that reads off while the others are clean points at that tap, the lead, or the changer contact. A phase that reads off while the other two match points at that winding. The failures it surfaces are shorted turns, which pull the ratio off and usually drag the exciting current up with them, a wrong tap setting, which throws the ratio by a clean tap-step percentage, and an open winding or lead, which the set flags as no reading or a wildly wrong one.
Watch the exciting current the set reports alongside the ratio. A ratio that is barely in tolerance but with exciting current several times what the other phases draw is a winding starting to fail, and it deserves a second look before you sign it off.
| TTR result | Likely cause | What to check |
|---|---|---|
| Off by a clean tap-step percent on every tap | Wrong tap position | Move the de-energized tap and retest |
| One tap off, others clean | Tap lead or changer contact | That tap connection and contact |
| One phase off, high exciting current | Shorted turns in that winding | Stop, do not energize, investigate winding |
| No reading or wildly wrong | Open winding or lead | Continuity of the winding and leads |
| Small consistent error all taps and phases | Instrument or test lead connection | Re-zero, reseat leads, retest |
Insulation resistance
Insulation resistance testing applies a DC test voltage across the insulation and reads the leakage back as megohms, winding to winding and each winding to ground. Wet, dirty, or aged insulation leaks more current and reads lower. At acceptance you also run the polarization index, the ratio of the 10-minute reading to the 1-minute reading, which grades how the insulation responds over time. NETA holds the polarization index above 1.0 and records it for trending.
This guide keeps the insulation resistance test short on purpose, because the insulation resistance and megger field guide covers the test voltage selection, the temperature correction to 20 degrees C, the polarization index, and the post-test discharge in full. The points specific to a transformer: test each winding to ground with the others grounded, test between windings, and correct every reading to a standard temperature before you compare it to anything. A reading that looks fine at 30 degrees C can be marginal once corrected.
Low insulation resistance at acceptance is almost always moisture, either from outdoor storage or from a unit that sat open. Often it dries out with heat and comes back. Read the megger guide for how to tell drying-out from real contamination, because condemning a wet transformer that just needs heat is an expensive mistake.
Winding resistance
Winding resistance is measured with a low-resistance ohmmeter, the DLRO, which pushes a known DC current through the winding and reads the millivolt drop to resolve resistances down in the milliohm and microhm range. An ordinary multimeter cannot do it. The reading finds a loose internal connection, a bad tap-changer contact, a broken strand, or a partial short, all of which show as a resistance off from where it should be.
You compare three ways. Phase to phase, the three windings should read close to each other once you account for the winding configuration. Against the factory test report, if you have it, the field reading should track the factory value corrected for temperature. And across the tap positions, the resistance should step in a smooth, predictable pattern as the tap changes. A single phase reading high points at a loose connection or a poor tap contact on that phase. All three high points at temperature or a measurement problem.
The reading is temperature sensitive, because copper and aluminum both gain resistance as they warm, so record the winding temperature with every reading or the comparison means nothing. And give the DLRO time. A winding is a large inductor, and the current takes time to settle before the reading is stable. Rushing it is the most common way to record a bad winding resistance number.
Polarity, phasing, and the vector group
Polarity and phasing confirm that the windings are connected the way the nameplate and the system expect, which matters most before you parallel two transformers or tie into an existing system. Polarity is whether a transformer is additive or subtractive, the relationship between the primary and secondary terminal markings. Get it wrong on a single unit and the secondary connections come out backward. Get it wrong between two paralleled units and you have a near short across the difference voltage the moment both are energized.
On three-phase units the question is the vector group, the phase relationship between primary and secondary expressed as a clock position. A Dyn11 transformer, for example, has the secondary shifted from the primary by a fixed angle, 30 degrees, shown as the 11 on the clock face. Two transformers paralleled have to share the same vector group, or the phase angle between them drives circulating current that overheats both.
The TTR set reports polarity along with the ratio on most modern instruments, so you get it in the same test. Before paralleling, confirm the vector group on the nameplate matches the existing unit, and phase the secondaries with a meter before you close the tie. Closing a tie on a phasing assumption is how you turn two good transformers into two failed ones.
Is the tap set for the right voltage?
Verify the de-energized tap is on the position that matches the actual supply voltage before you energize, because a transformer set to the wrong tap delivers the wrong secondary voltage from the first minute. The de-energized tap changer, sometimes called the no-load tap changer, is a set of taps on the primary winding that adjust the turns ratio in steps, commonly plus or minus 2.5 and 5 percent around nominal. It is moved with the transformer de-energized, never under load.
The common error is leaving the tap where it shipped. Factories often ship on the nominal tap, but the actual primary voltage at the site is rarely exactly nominal. If the supply runs high, you bump the tap up to bring the secondary back down to target. If it runs low, you bump it down. Measure the real primary voltage, do the arithmetic against the nameplate tap percentages, and set the tap to land the secondary where the load needs it.
Set it, confirm it with a TTR on that tap, and record the position. The tap setting belongs in the commissioning record, because the next person who measures a secondary voltage that looks off needs to know which tap the unit is on before chasing anything else.
Insulation power factor (Doble)
Insulation power factor, also called dissipation factor or the Doble test after the instrument most associated with it, measures the quality of the insulation by reading how much of the test current is real loss versus pure capacitive charging. Clean, dry insulation is almost purely capacitive and reads a low power factor. Insulation that is wet, contaminated, or aging dissipates more energy as heat and reads higher. It is a more sensitive condition test than insulation resistance, and it is a standard acceptance test on larger and medium-voltage transformers.
The test is usually run on the larger units. IEEE C57 does not call for it as part of the routine battery on the smallest transformers, generally below about 10 MVA, but NETA acceptance specifications call for it on distribution-class units as well, so the project specification and the unit size decide whether you run it. A power-factor result, or a tip-up across test voltages, above about 1 percent is commonly flagged for investigation.
The reading is temperature dependent and the instruments apply a correction, so record the temperature. Like the other tests, the acceptance power factor is most useful as the baseline. A single reading tells you the insulation is acceptable now. The trend over years tells you when it is starting to go.
Sweep frequency response analysis (SFRA)
Sweep frequency response analysis, SFRA, injects a low-voltage signal across a winding over a range of frequencies and records the response as a signature curve. The shape of that curve is set by the physical geometry of the winding, its inductance and capacitance, so any mechanical change inside the transformer changes the curve. It is how you detect winding deformation or displacement that no other electrical test catches.
The use case is a transformer that took a hard mechanical hit: a shipping impact, a seismic event, or a through-fault that put high mechanical stress on the windings. The damage might not move the turns ratio or the insulation enough to flag, but it has shifted the winding physically, and that shift will lead to a failure later. SFRA compares the field signature against a factory baseline, a sister unit, or phase to phase, and a deviation in the curve points at movement inside.
It is a specialized test, run on larger and more critical units rather than every distribution transformer, and it needs a baseline to compare against. Capture the SFRA signature at acceptance on a critical unit even if everything passes, because it is the reference you will want if that transformer ever takes an impact in service.
Liquid-filled transformers: the oil tests
A liquid-filled transformer adds the oil to the test list, because the oil is both the insulation and the cooling medium, and its condition is half the health of the unit. The acceptance oil tests are dielectric breakdown voltage, moisture content, and dissolved gas analysis. Dielectric breakdown applies a rising voltage across a gap in an oil sample until it arcs, which grades the oil's ability to hold off voltage. Moisture in the oil drops that strength fast and migrates into the paper insulation, so the water content is read directly, commonly by Karl Fischer titration.
Dissolved gas analysis, DGA, is the powerful one. A sample of oil is analyzed for the gases dissolved in it, because specific fault types inside a transformer break the oil and paper down into characteristic gases. Hydrogen and acetylene point at arcing, ethylene and methane at overheating, carbon oxides at paper degradation. At acceptance the DGA sets the baseline gas levels. In service it is the earliest warning of a developing internal fault, often months before anything else shows.
These tests go to a lab, not a hand meter on the pad, so plan the sample and the turnaround into the commissioning schedule. The sampling itself has to be clean, because a contaminated sample reads as a problem that is not there.
Dry-type vs liquid-filled: what you test
What you test depends on whether the transformer is dry-type or liquid-filled. A dry-type unit, the air-cooled transformer covered in the dry-type transformer sizing and installation field guide, gets the electrical battery: TTR, insulation resistance, winding resistance, polarity, and tap verification, plus power factor on the larger ones. There is no oil, so there are no oil tests, and the insulation system is the solid material around the windings.
A liquid-filled unit gets all of that plus the oil. The dielectric breakdown, the moisture, and the DGA become part of acceptance, and on a large unit the oil tests carry as much weight as the electrical ones. The oil is doing the insulating and the cooling, and a unit with good windings and bad oil is still a unit headed for trouble.
The electrical tests run the same way on both. A TTR set does not care whether the windings are in air or in oil. What changes is the added oil work on the liquid units and, often, the scale. Liquid-filled transformers tend to be the larger, medium-voltage units where power factor, SFRA, and DGA all come into play, while a small dry-type might see only the core electrical battery. The unit size and the project specification set the actual scope.
The test sequence
The sequence runs in a deliberate order, because some tests have to come before others and the safety steps gate everything. De-energize and lock out first, prove it dead, then work down the list. The order below holds up in the field.
- De-energize, lock out and tag out every source, prove dead, and discharge and ground the windings before touching a terminal.
- Walk the unit: check for shipping damage, oil leaks, cracked bushings, loose hardware, and the tap position as found.
- Run insulation resistance, winding to winding and winding to ground, and record the polarization index.
- Run the TTR on every de-energized tap and all three phases.
- Run winding resistance with the DLRO on each winding and tap, recording temperature.
- Confirm polarity and the vector group, and on larger units run power factor and, where specified, SFRA.
- On liquid-filled units, pull the oil samples for dielectric, moisture, and DGA.
- Verify and set the de-energized tap for the measured supply voltage, then confirm it with a TTR on that tap.
- Discharge and ground the windings after the DC tests, then energize and run the no-load checks.
Recording the baseline for trending
Record the baseline at acceptance, because every maintenance test for the life of the transformer compares against it. The acceptance readings are the only set taken on a known-good, unloaded, undamaged unit. After the transformer has carried load and seen heat for years, you cannot recreate that reference. The maintenance crew years out is trending against the numbers you write down now.
What makes a baseline useful is that it is complete and findable. A TTR result with no tap position recorded, a winding resistance with no temperature, a power factor with no test voltage: each is a number that cannot be trended, because the conditions are missing. Capture the reading, the conditions, the instrument, and the date, and store it where the maintenance program will actually find it, not in a binder that ships to an archive.
This is where a field record tool earns its place. Logging the acceptance results into FieldOS, with the tap positions, temperatures, and instrument serials attached to the asset, means the maintenance test years later opens the baseline next to the new reading instead of hunting for a commissioning report nobody can locate. A baseline that cannot be found is the same as no baseline.
NETA acceptance and maintenance testing
NETA writes the specifications the testing industry follows for this work, in two documents that get confused. NETA ATS, the Acceptance Testing Specifications, governs the tests on new equipment before it goes into service, which is the work in this guide. NETA MTS, the Maintenance Testing Specifications, governs the same equipment once it is in service, on a maintenance schedule. The tests overlap heavily. The pass criteria and the intent differ.
For transformers, NETA ATS calls out the battery: insulation resistance with the polarization index, turns ratio on all de-energized tap positions, winding resistance, polarity and phase relation, insulation power factor on the windings, and the oil tests on liquid units. It points to IEEE C57 for the underlying test methods and limits, including the 0.5 percent turns-ratio tolerance and the power-factor methods in the C57.12.90 test code.
Which edition applies is set by the project specification and the contract. NETA updates the ATS on a cycle, and the limits and required tests can shift between editions, so confirm the edition the job is written to before you set your pass criteria. Do not test to a remembered limit from an older edition.
Safety: de-energize, discharge, ground
Treat every transformer as energized until you have proven it dead, and treat it as a charge hazard again after every DC test. De-energize, lock out and tag out the primary and the secondary, and prove dead with a meter you tested on a known source before and after. A transformer fed from two directions, primary and a secondary tie, has two sources to kill, and the one people forget is the back-feed from the secondary.
The hazard specific to this testing is stored charge. The TTR, the insulation resistance test, and the power factor test all apply voltage to a winding, and a transformer winding is a large capacitor that holds that charge after the instrument disconnects. The insulation resistance and power factor tests at higher voltage can leave a lethal charge sitting on the winding. After every DC test, discharge the winding through a ground stick and leave it grounded until you are ready for the next step. This is the step new techs skip, and the capacitance does not care that the meter is unplugged.
The insulation resistance and megger field guide covers the discharge procedure and the discharge time in detail. The rule is simple and not negotiable: ground the windings after the DC tests, every time, before a hand goes near a terminal.
Energizing and the no-load check
Once the tests pass and the tap is set, energize the transformer and confirm it behaves before you put load on it. Energize from the primary with the secondary open, and listen and look: a steady hum, no smell, no smoke, no unusual noise. The inrush at energization is a heavy current spike for a fraction of a second, which is normal, and is why the primary protection is set to ride through it rather than trip on it.
With the unit energized and unloaded, measure the secondary voltage on all phases. It should land at the target the tap was set for, balanced across the phases. A secondary voltage off from the target sends you back to the tap setting and the primary voltage, not to the load. A voltage unbalanced across phases points at a connection or a winding problem the earlier tests should have caught, so a surprise here means something got missed.
Then bring load on gradually where the process allows, and watch the temperature and the secondary voltage under load. The no-load check proves the transformer is sound. The first loaded readings confirm it holds up when the current is real.
Why did my transformer fail acceptance testing?
When a transformer fails acceptance, the failed test points at the cause, and the three that fail most have clear signatures. An out-of-tolerance TTR is the headline failure. If a single tap reads off, suspect the tap lead or the changer contact. If a whole phase reads off, suspect that winding, and check the exciting current, which rises with shorted turns. If the ratio is off by a clean tap-step percentage on every tap, the unit is connected on the wrong tap, not damaged.
A low insulation resistance is usually moisture, not failed insulation, especially on a unit that was stored outdoors or sat open. Correct the reading to temperature first, because a low number at high temperature can be acceptable corrected. If it is genuinely low corrected, dry the unit with heat and retest before condemning it. A winding resistance imbalance, one phase reading high against the others, points at a loose internal connection or a poor tap contact, and it often shows alongside a TTR or power factor flag on the same phase.
Read the tests together. A single phase that fails the TTR, the winding resistance, and the power factor is telling you the same story three ways, and that story is a problem in that winding. One test out while the others are clean is more often the connection or the instrument than the transformer.
Critical and data-center transformers
Critical and data-center transformers get the full battery and then some, because the cost of an unplanned failure dwarfs the cost of the testing. On a unit feeding a data hall, a hospital, or a process that cannot drop, the acceptance scope usually adds power factor and SFRA even where the unit size would not otherwise call for them, and the oil program on a liquid unit is more aggressive, with a tight DGA baseline and a sampling schedule that starts early.
The reason is the consequence and the redundancy. These systems are built with parallel and redundant transformers, which moves polarity and vector-group verification before paralleling from a good practice to a hard requirement, because a phasing error that would trip one unit can take down a redundant pair. The acceptance test is also the last clean baseline before the unit goes into a service life where it will rarely, if ever, be taken offline again for testing.
Build the acceptance scope around the criticality, not just the kVA. A 1000 kVA unit in a warehouse and the same unit feeding a data hall are the same transformer with very different testing, because the cost of being wrong is not the same.
What to document
An acceptance test that is not recorded completely cannot serve as a baseline, and the baseline is half the reason for the test. Capture each test, what it proves, the result with its conditions, and the instrument that read it. The conditions are what make the number trendable later: the tap position, the winding temperature, the test voltage, the date.
| Test | What it proves | Record with the result |
|---|---|---|
| Turns ratio (TTR) | Turns intact, tap correct, winding connected right | Ratio and deviation per tap and phase, exciting current |
| Insulation resistance | Insulation not wet, dirty, or degraded | Megohms, polarization index, temperature, test voltage |
| Winding resistance | No loose connection, bad tap, or shorted turns | Milliohms per winding and tap, winding temperature |
| Polarity and vector group | Correct connection and phase relation | Polarity, vector group, phasing result |
| Power factor (Doble) | Insulation condition on larger units | Power factor or dissipation factor, temperature, test voltage |
| Oil tests (liquid) | Oil dielectric, moisture, internal fault gases | Dielectric kV, moisture ppm, DGA gases, lab and date |
| Tap setting | Secondary lands at target voltage | As-found and as-left tap, measured primary voltage |
Common mistakes
- Energizing without acceptance testing, so a shipping-damaged or mis-tapped transformer faults at the first close instead of failing a test.
- Leaving the tap on the as-shipped position instead of setting it for the measured supply voltage.
- Not discharging and grounding the windings after the DC tests, leaving a lethal stored charge on a winding.
- Running the TTR on one tap instead of every de-energized tap and all three phases.
- Recording readings with no tap position, temperature, or test voltage, so the baseline cannot be trended.
- Signing off an out-of-tolerance TTR or a winding-resistance imbalance instead of finding the cause.
- Comparing winding resistance or power factor readings without correcting for temperature.
- Skipping the baseline entirely, so the first maintenance test has nothing to trend against.
Field checklist
Want this checklist to run itself on every job — with photo proof and a signed record crews can hand the customer? That's FieldOS.
Standards and references
NETA writes the acceptance and maintenance test specifications the industry tests to: NETA ATS for acceptance on new equipment and NETA MTS for maintenance on in-service equipment. For transformers they specify the test battery and point to the IEEE methods for the limits, so the two are read together on a job.
IEEE C57 is the transformer family of standards behind the methods and the limits. The diagnostic field testing guidance, in C57.152, sets the 0.5 percent turns-ratio tolerance and the framework for the field tests, and the transformer test code, C57.12.90, defines the power-factor and other test methods. The exact section numbers and limits move between editions, so confirm them against the edition the project is written to rather than a remembered figure.
The test-set manufacturers, Megger and Doble most prominently, publish the procedures and the interpretation guidance for their instruments, and the transformer nameplate is the reference every test compares against: the rated voltages, the tap percentages, the vector group, and the connection. Read the nameplate first. Cite the standard that controls the point, and let the project specification and the adopted edition govern the pass criteria. The three things that are not negotiable: test before energizing, verify the tap and the TTR, and discharge the windings after every DC test.
Units, terms, and conversions
Transformer testing carries its own vocabulary and a few unit conventions that read differently across the test report, the nameplate, and the standard.
Ratio is dimensionless, reported as the measured ratio and the deviation in percent from nameplate. Winding resistance is in ohms, usually milliohms or microhms, which is why it needs a low-resistance ohmmeter. Insulation resistance is in megohms or gigohms. Power factor and dissipation factor are in percent. Oil dielectric strength is in kilovolts, moisture in parts per million, and the DGA gases in parts per million.
- TTR
- Transformer turns ratio test, measuring the ratio of primary to secondary turns against the nameplate
- DLRO
- Digital low-resistance ohmmeter, used for winding resistance in the milliohm and microhm range
- Polarization index (PI)
- Ratio of the 10-minute to the 1-minute insulation resistance reading
- Vector group
- The phase relationship between primary and secondary, shown as a clock position such as Dyn11
- Power factor / dissipation factor
- Insulation loss as a fraction of charging current, a condition test on larger units
- DGA
- Dissolved gas analysis, identifying internal faults from gases dissolved in transformer oil
- De-energized tap changer
- Primary winding taps adjusting the ratio in steps, moved only with the transformer off
FAQ
What is a TTR test?
A TTR, or transformer turns ratio test, applies a low voltage to one winding and reads the voltage induced in the other to measure the ratio of primary to secondary turns. The measured ratio is compared to the nameplate, commonly within 0.5 percent per IEEE C57. It confirms the turns, the tap, and the connection are right.
Why test a transformer before energizing it?
You test before energizing because a damaged or mis-tapped transformer faults the instant it sees voltage, and energizing it is the most expensive way to find the fault. Acceptance tests catch shipping damage, a wrong tap, reversed polarity, or moisture before the close, and they set the baseline the maintenance program trends against for the life of the unit.
What does the turns ratio test tell you?
The turns ratio test tells you whether the windings are intact, the tap is on the right position, and the winding is connected as the nameplate says. A ratio off by a clean tap-step percentage means the wrong tap. A single phase off, with high exciting current, points at shorted turns. No reading points at an open winding or lead.
What tests are done on a new transformer?
A new transformer gets turns ratio (TTR), insulation resistance with polarization index, winding resistance, and a polarity and phase check before energizing. Larger units add insulation power factor and SFRA. Liquid-filled units add oil dielectric, moisture, and dissolved gas analysis. NETA ATS and IEEE C57 set the battery and the limits.
What is an acceptable TTR tolerance?
An acceptable turns ratio reads within 0.5 percent of the nameplate ratio, the tolerance in IEEE C57 guidance that NETA field testing follows, measured on each winding and each tap. All three phases on a given tap should read the same ratio. A deviation beyond that band is investigated before the transformer is energized.
What does a winding resistance test find?
A winding resistance test, run with a low-resistance ohmmeter, finds a loose internal connection, a bad tap-changer contact, a broken strand, or a partial short by reading the resistance in milliohms. You compare phase to phase, against the factory report, and across tap positions, correcting for temperature. One phase reading high points at a connection problem on that phase.
Do you discharge a transformer after testing?
Yes. The TTR, insulation resistance, and power factor tests all charge the winding, and a transformer winding holds that charge as a capacitor after the instrument disconnects. After every DC test, discharge the winding through a ground stick and leave it grounded until the next step. Skipping the discharge is how techs take a serious shock from an unplugged meter.
What is the difference between NETA ATS and MTS?
NETA ATS, the Acceptance Testing Specifications, governs tests on new equipment before it goes into service. NETA MTS, the Maintenance Testing Specifications, governs the same equipment once in service, on a schedule. The tests overlap, but the pass criteria and intent differ. Both point to IEEE C57 for transformer test methods and limits.
Do dry-type and liquid-filled transformers get the same tests?
Both get the electrical battery: TTR, insulation resistance, winding resistance, polarity, and tap verification, plus power factor on larger units. Liquid-filled transformers add oil tests, the dielectric breakdown, moisture, and dissolved gas analysis, because the oil is the insulation and the coolant. A dry-type unit has no oil, so it gets no oil tests.
What do I do if the TTR is out of tolerance?
An out-of-tolerance TTR stops the energization until it is explained. If the ratio is off by a clean tap-step percentage on every tap, the unit is on the wrong tap. A single tap off points at the tap lead or changer contact. A single phase off, with high exciting current, means shorted turns. Find the cause before closing the breaker.
People also ask
Codes cited in this guide
This guide is written and reviewed against the published standards below. Always confirm the current adopted edition with the authority having jurisdiction.