Partial Discharge Testing: Detecting PD Before It Fails
Most insulation failures do not happen suddenly. They announce themselves for months or years beforehand as tiny, localised discharges inside the insulation — discharges too small to trip protection and too small to see, but large enough to eat away at the material around them until one day the insulation can no longer hold the voltage. That slow process is called partial discharge, and testing for it is one of the most valuable diagnostic tools in high-voltage maintenance, because it finds the problem while there is still time to plan a repair instead of coping with a failure.
This guide explains partial discharge testing in plain language: what partial discharge is, where it comes from, the main detection methods, how results are interpreted, and the safety rules that matter. As with everything on this site, always work to your project specification, the manufacturer's instructions and the applicable standards for your region; the general guidance here never overrides those documents. If you are new to transformer testing as a whole, start with our power transformer testing and commissioning guide, which puts partial discharge testing in context alongside the other diagnostic tests.
What partial discharge is
Partial discharge, universally shortened to PD, is an electrical discharge that only partly bridges the insulation between two conductors. Unlike a full breakdown, which shorts the insulation completely, a partial discharge is confined to a small region — a gas-filled void inside solid insulation, a sharp point on a conductor, a contaminated surface, or a gap around a floating metal part. Each discharge is tiny, measured in picocoulombs of apparent charge, and each one releases a small burst of energy as heat, light, sound and electromagnetic radiation. Individually harmless, these discharges repeat with every cycle of the alternating voltage, thousands of times a minute, and over time they erode the insulation around them, widening voids, carbonising surfaces and weakening the material until a full failure becomes possible.
The reason PD matters so much is that it is both a symptom and a cause. It is a symptom because it reveals a defect — a void, a delamination, a sharp edge, contamination — that should not be there. And it is a cause because the discharge activity itself progressively damages the insulation, so a defect that starts small tends to grow. Finding PD early therefore does two things at once: it locates a defect, and it starts the clock on a repair before the defect grows into a breakdown. That is why PD testing is treated as a priority diagnostic on critical transformers, switchgear and cables, and why a rising PD trend is taken seriously even when every other test still looks normal.
Where partial discharge comes from
The most common PD source inside a transformer is a void: a small gas pocket trapped in solid insulation or between insulation layers during manufacture, or created later by delamination or shrinkage. The electric field inside a void is higher than in the surrounding solid insulation, because the gas has a lower permittivity, so the void breaks down at a voltage the solid insulation handles easily. The result is a discharge confined to the void, repeating every cycle. Voids are also the reason tan delta tip-up testing is useful: the same voids that produce PD also make dielectric loss rise with voltage.
Other sources include corona at sharp points and edges, where the local electric field is concentrated enough to ionise the surrounding gas or oil; surface discharges tracking along contaminated or damp insulation surfaces, particularly on bushings; discharges around floating metal parts that are not properly earthed and therefore sit at an uncontrolled potential; and discharges in oil caused by particles, bubbles or contamination. Each source produces a characteristic pattern of discharge activity relative to the voltage waveform, and recognising those patterns is a large part of PD interpretation. A void discharge, for example, tends to appear at particular phase angles of the voltage cycle, while corona has a different phase signature again.
Detection methods: electrical
The classic PD measurement is electrical: a coupling capacitor connected to the test object picks up the fast current pulses produced by discharges, and a measuring instrument quantifies them as apparent charge in picocoulombs. This is the standard method for factory acceptance testing and for offline diagnostic testing, because it is sensitive and quantitative — it gives a number that can be compared with limits and trended. The measurement is normally made with the transformer energised at a test voltage, or at operating voltage during an offline test, with careful attention to background noise, since the pulses being measured are small and the substation environment is electrically noisy.
Electrical detection has an important practical variant for in-service monitoring: the high-frequency current transformer, or HFCT, clamped around an earth connection or cable screen. Discharges inside the equipment produce high-frequency currents that flow to earth, and the HFCT picks them up without any direct connection to high voltage. This makes HFCT monitoring safe to install on live equipment and suitable for continuous online monitoring, where the goal is trending and alarming rather than a laboratory-grade measurement. Wherever electrical detection is used, calibration matters: the measuring circuit must be calibrated with a known charge injection so that the reported picocoulomb values mean something comparable.
Detection methods: acoustic and UHF
Every discharge also produces a tiny acoustic pulse as the gas in the void is heated and expands, and acoustic sensors mounted on the transformer tank can pick up these pulses. Acoustic detection has a unique advantage: by comparing the arrival times at several sensors, the discharge source can be located in three dimensions inside the tank. That location information is extremely valuable when deciding whether an internal inspection is justified and where to look. Acoustic sensors are also immune to electrical noise, which makes them useful in electrically noisy environments where electrical detection struggles.
UHF detection works on the electromagnetic pulse radiated by a discharge. UHF sensors, fitted to inspection hatches or drain valves, or installed inside gas-insulated equipment, detect signals in the ultra-high-frequency range where background noise from the power system is much lower. UHF is particularly associated with gas-insulated switchgear, but it is also used on transformers, especially for online monitoring. The practical approach on a critical transformer is often to combine methods: electrical measurement for quantification, acoustic sensors for location, and UHF for noise-immune monitoring. Each method sees the same discharges through a different window, and agreement between methods greatly increases confidence in the result.
Interpreting results: patterns, levels and trends
PD interpretation starts with the phase-resolved pattern: a plot of discharge magnitude against the phase angle of the applied voltage. Different defect types produce recognisably different patterns, and an experienced analyst can often identify the defect type — void, corona, surface discharge, floating part — from the pattern alone. The next question is level: how large are the discharges, and how do they compare with the commissioning baseline, the manufacturer's guidance, and sister units? There is no single universal pass limit, because acceptable levels depend on the equipment type, voltage class and measurement method, so judgement against baselines and trends matters more than any remembered number.
Trend is the most important single factor. A low, stable PD level that has not changed in years is a very different situation from the same level doubling between two surveys. Rising PD, new PD where none existed before, or PD that appears at lower voltage than before all indicate a deteriorating defect and call for action. Location matters too: PD deep inside a winding is more concerning than PD at an accessible bushing, because it is harder to repair and closer to critical insulation. And PD should always be read alongside the other diagnostics: a winding with rising PD and a rising tan delta, or with fault gases in its oil analysis, presents a much stronger case for intervention than any one result alone.
Safety: the rules that matter
PD testing involves high voltage, and the safety rules are non-negotiable. Offline PD testing is performed with the transformer de-energised, isolated, earthed and discharged before connections are made, and the test area must be barricaded with clear exclusion zones while voltage is applied. No one works on the transformer during the test, and the equipment must be discharged and earthed again before anyone approaches it afterwards. Online monitoring sensors, by contrast, are designed to be installed and read without high-voltage exposure, which is one of their great advantages — but even then, sensor installation on live equipment must follow the site's live-working rules and be done by competent persons.
A second safety point is about decisions, not test technique. A PD result that indicates a serious internal defect is not a reason to keep running the transformer until the next convenient outage without a risk assessment. The assessment should weigh the PD level and trend, the criticality of the transformer, the consequences of failure, and the availability of a spare or alternative supply. Where the evidence points to a rapidly deteriorating internal defect, taking the transformer out of service for inspection is the safe decision, even when it is inconvenient. PD testing earns its value precisely by giving you the evidence to make that call before failure makes it for you.
What to do with PD results
A sensible response to PD findings follows a clear ladder. Low, stable PD with a known, benign pattern: continue monitoring, shorten the survey interval slightly, and record the baseline carefully. New or rising PD: increase monitoring frequency, corroborate with other tests such as tan delta, oil analysis and SFRA, and locate the source with acoustic methods if possible. High, rising or internal PD: plan an outage for internal inspection, and do not re-energise after the outage without a repeat PD test confirming the defect has been addressed. In every case, keep the full record — patterns, levels, sensor positions, test voltages and conditions — in one file per transformer, so that the next analyst can see the trend rather than starting from scratch.
For engineers building a diagnostic programme, the practical routine is simple: include PD in the test set for critical transformers, establish a baseline at commissioning or at the first survey, trend every result, and combine PD with the other tests in our transformer testing and commissioning guide, checking ratings and loads with our free transformer calculators where needed. Partial discharge testing does not prevent failures by itself — but it is one of the few tests that can see a failure coming while there is still time to stop it, and that makes it worth doing well.
Frequently asked questions
What is the difference between PD and corona?
Corona is one type of partial discharge: a discharge in the gas or oil around a sharp conductor or edge, where the local field is high enough to ionise the surrounding medium. Void discharge, surface discharge and floating-part discharge are other types. All are partial discharges; corona is the name for one particular mechanism.
Can PD testing damage the transformer?
When performed correctly at appropriate test voltages, PD testing does not damage healthy insulation. The test voltages used are within the equipment's design capability, and the discharges measured are the ones the defect was already producing. The risk to manage is the high-voltage test setup itself, through proper isolation, earthing and exclusion zones.
How often should PD be measured?
It depends on criticality and history. Critical transformers often have continuous online monitoring, while others are surveyed periodically — for example annually or at each major outage — with the interval shortened whenever PD is found or is rising. Always follow the asset owner's monitoring specification.
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