Partial Discharge Monitoring

Review of On-line Partial Discharge Measurement Practices

By Dr. Raja Kuppuswamy, Principal Engineer, Dynamic Ratings. Published August 2023.

There are three main ways to measure partial discharge on in-service transformers: conventional electrical measurement through the bushing taps, ultra-high frequency (UHF) antennas, and ultrasonic acoustic sensors. Each has different strengths. Only conventional measurement can be calibrated in picocoulombs and compared directly with factory acceptance tests. UHF is less affected by external noise but can’t identify the affected phase or be calibrated. Acoustic methods are best for finding where a discharge is located, but the signals weaken quickly and some discharge sources are hard to detect. Standards and long-established practice exist for conventional measurement, but there are no accepted procedures for UHF or acoustic methods, which still have open questions around calibration, noise suppression and fault location.

Why partial discharge matters

• Partial discharge usually appears well before insulation fails, which makes it the clearest early indicator of defects and deterioration.
• Trending it over time lets asset managers plan repair or replacement before an unexpected outage.

Conventional electrical measurement (IEC 60270)

• Each bushing’s C1 capacitance acts as a coupling capacitor, picking up high-frequency PD pulses through the test tap. Bushings without a test tap need an external coupling capacitor connected in parallel.
• Results are reported as apparent charge in picocoulombs and can be precisely calibrated against a known reference. This is the only one of the three methods whose field results can be compared with factory acceptance limits, such as a 500 pC pass/fail criterion.
• The method has been standard practice since the 1960s, and reference phase-resolved PD patterns are widely available for different defect types and equipment. Pulse amplitude, trends and these patterns are known to correlate with the extent of insulation damage.
• The main challenge in service is noise. Factory tests are run in shielded labs, but in-service transformers pick up interference from poor corona shielding, loose connections, PD in connected equipment and arcing on transmission lines. Established techniques exist to suppress this interference on site.

Ultra-high frequency (UHF) measurement

• An antenna detects electromagnetic emissions from PD in the 300 to 3,000 MHz range. When the antenna is inside the tank, the tank acts as a Faraday cage and the bushings’ C1 capacitance filters out interference from outside, which makes UHF well suited to noisy, on-line environments.
• The author’s research found that the electromagnetic waves are actually emitted by metal parts of the transformer carrying high-frequency current, not by the PD source itself. Radiation from UHF PD sources is complex and only partly understood.
• Oil valve probes need straight-opening valves at least 1.5 inches in diameter, which are uncommon. The probe head must extend at least 2 inches (5 cm) into the tank, so its position must be chosen carefully because it sits close to energized windings. Oil-flow guide tubes behind the valve can limit how deep it can go, and insertion depth strongly affects sensitivity.
• Hatch cover probes require cutting a dielectric window into a hatch plate, which means an outage, draining oil below the hatch and exposing the transformer’s interior to air. This makes them impractical for transformers already in service.
• Flange sensors fit around the lower shed of the bushing. They are outside the tank, so like hatch cover probes, they don’t benefit from the tank’s shielding and are more exposed to external interference.
• Sensitivity depends on antenna design, probe depth, distance from the PD source and any obstacles in between. Studies on 210 MVA transformers measured attenuation of about 2 dB/m with a clear path and about 6 dB/m with an obstacle.
• Limitations: UHF readings can’t be traced to a specific phase winding, and they can’t be calibrated in picocoulombs, so they can’t be compared with factory test results to judge severity. UHF equipment also tends to cost more than conventional PD systems.

Ultrasonic acoustic measurement

• Acoustic monitoring is typically used to give remote early warning of a developing fault, or in response to abnormal dissolved gas results or unusual sounds, followed by more detailed field testing.
• Sensors on the tank wall detect sound waves from PD. The PD source is located by comparing when the signal reaches each sensor.
• All-acoustic systems use the differences in arrival time between sensors. They need no electrical connection to the transformer, so they are practical for locating sources on operating units.
• Acoustic systems with an electrical PD trigger use the electrical detection of the PD pulse as time zero, so each sensor gives an absolute travel time from the source. This improves location accuracy.
• Acoustic methods generally detect PD outside the windings, arcing or tracking on the in-oil surface of a bushing, PD in the tap changer, and very high-intensity discharges within windings.
• They usually struggle to detect discharges inside the windings, discharges inside high-voltage bushings, and gas bubbles. Weather, core magnetostriction, pump and fan noise, loose internal shielding connections, and even loose nameplates can interfere with measurements.
• Acoustic sensors are immune to electromagnetic interference, but the signals weaken quickly. Sensor placement, tank wall shielding and insulating barriers all affect sensitivity, and the angle between the sensors and the source can significantly affect location accuracy.

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