Transformer Protective Device Testing and Commissioning
A power transformer carries a second layer of protection that has nothing to do with the relay panel. Bolted to the tank are the mechanical devices that watch for the physical signature of a fault: a pressure surge, gas collecting where it should not be, oil too hot or too low. They trip and alarm on their own, they are commissioned at installation, and they are the devices most often left unverified, because none of them shows up on an electrical test set. This is what each one does and how it gets tested.
Setpoints, contact ratings, and functional-check steps for these devices are specific to the unit and its accessory package. On the GE Prolec transformers we work regularly, the device set and its pre-startup functional checks are laid out in the Prolec GE Installation, Operation and Maintenance Manual (IOMM-ENG, Rev 3.1, June 2012), Sections 4, 6, and 7. Work to the manual and the wiring diagram for the transformer in front of you.
Why these devices need their own commissioning step
The protective relays in the control house, differential, overcurrent, and the rest, are tested by secondary injection and are part of the protection scheme commissioning. The devices on this page are different. They are self-contained sensors on the transformer itself, each with its own contacts wired back to alarm, to trip, and usually through the lockout relay. A perfect relay panel does you no good if the sudden pressure relay's trip contact was never landed, or the temperature gauge that is supposed to start the second stage of cooling was never verified. These devices fail quietly, and the first time an unverified one matters is during the fault it was supposed to catch. Commissioning is a functional check of every one, contact by contact, through to the lockout and to SCADA, before the transformer is energized.
Sudden pressure relay (ANSI 63)
The sudden pressure relay, also called the rapid pressure rise relay, is the fastest fault detector on the transformer. An internal arcing fault vaporizes oil and produces a near-instant pressure spike. The relay senses the rate of rise, not the absolute pressure, so it ignores the slow pressure changes of normal load and temperature cycling and reacts only to the sharp transient of a fault. On a severe internal fault it can operate faster than the differential relay, and getting the transformer off line a fraction of a second sooner is the difference between a repairable unit and a ruptured tank.
There are two types: gas-space relays mounted above the oil and oil-actuated relays mounted below oil level. Commissioning verifies the correct device is installed for the unit, that it is oriented and mounted per the manual, and that its operation drives the intended output. The relay is functionally tested through its test port, and the alarm and trip contacts are verified through the wiring to the lockout relay and the trip circuit. The reset and any seal-in are checked. Because the sudden pressure relay has a documented history of nuisance trips on external through-faults and on cooling-pump surges when it is misapplied or miswired, careful commissioning of this specific device pays back more than any other in the set.
Gas accumulation and Buchholz relay (ANSI 63B)
Slowly developing faults, a loose connection heating over weeks, minor partial discharge, generate gas at a low rate that a sudden pressure relay will never see. On a conservator-type transformer, where the tank is completely full of oil and connected to an expansion tank through a pipe, a Buchholz (gas accumulation) relay sits in that pipe and catches this gas. Gas rising from the tank collects in the relay body and displaces oil against a float; a small accumulation drops an alarm, and a large gas volume or a fast oil surge toward the conservator drives a trip. It is both an incipient-fault detector and a fast-fault backstop.
Not every transformer has one. Sealed-tank and gas-blanketed units, common in North American utility service, use a gas-space sudden pressure relay and a pressure-vacuum bleeder instead of a Buchholz, because there is no conservator pipe for the relay to sit in. Where a Buchholz is present, commissioning tests it by injecting or bleeding gas to confirm the alarm float operates, and by the oil-surge test where the design allows, then verifies the alarm and trip contacts through the wiring. The gas sampling and reset provisions are checked, because operators will need them the first time the alarm comes in.
Pressure relief device
The pressure relief device is the transformer's last mechanical defense against tank rupture. It is a large spring-loaded valve that stays sealed under normal operation and vents a sudden overpressure, from a fault the interrupting devices did not clear fast enough, before the pressure can split the tank. Most units carry a self-resealing device with a mechanical semaphore indicator that latches when it operates, plus an alarm contact.
Commissioning inspects the device for correct installation and gasket seating, verifies the semaphore indicator and its reset, and checks the alarm contact through to annunciation. The alarm on a pressure relief device is a hard indication that the transformer saw an overpressure event, so the contact has to be wired and verified, not left as a mechanical-only indicator that no one in the control house will ever see operate.
Winding and oil temperature indicators (ANSI 49)
The temperature devices do double duty: they protect the transformer from overheating and they run the cooling. The oil temperature indicator reads top-oil temperature directly. The winding temperature indicator does not measure the winding directly, it reads top-oil temperature and adds a thermal offset driven by load current through a heater coil, producing a simulated hot-spot temperature. Each indicator carries multiple adjustable contacts that stage the cooling, start the first bank of fans, start the second bank or the pumps, and then alarm and trip if temperature keeps climbing.
Commissioning verifies each indicator against a reference: the pocket and sensing bulb are correctly seated, the reading tracks a known temperature, and every contact operates at its set point. The cooling stages are proven by driving the indicator, confirming each fan and pump group starts on the right contact and in the right sequence, and the alarm and trip contacts are verified through the wiring. A winding temperature indicator that reads correctly but whose second-stage contact was never confirmed will let a fully loaded transformer run hot with half its cooling asleep, and nothing on an electrical test would have caught it.
Oil level gauge and cooling controls
The magnetic oil level gauge tracks oil volume as it expands and contracts with temperature, and carries a low-level alarm contact that warns of a leak or a serious loss of oil before the tank uncovers a winding or a bushing draw-lead. Commissioning confirms the float and indication move correctly and verifies the low-level contact through to alarm.
The cooling control cabinet ties the fan and pump groups to the temperature contacts, with hand-off-auto control and, on many units, an automatic alternation between cooling groups to even out run time. Commissioning exercises every fan and pump in hand, confirms rotation and current draw, then proves the automatic staging from the temperature indicators. The control-power and alarm wiring, loss of cooling, loss of control power, is verified through to annunciation, because a transformer that silently loses its cooling is a transformer quietly aging its insulation at several times the normal rate.
The commissioning record
Every one of these checks belongs on the commissioning record. The Prolec IOMM provides the pre-startup and protective-device forms for exactly this purpose, and completed, they become the reference for every future maintenance visit. Protective-device functional checks are also a NERC PRC-005 maintenance item for the sudden pressure and gas relays on many transformers, so the commissioning baseline is not just good practice, it is the first entry in a maintenance record the utility has to keep. This whole set is part of the pre-energization work covered in our guide to power transformer field installation and commissioning.
How Southern Switch handles it
We functionally commission the full protective-device set as part of transformer installation and field testing, sudden pressure relay, gas or Buchholz relay, pressure relief device, temperature indicators, oil level, and the cooling controls, verifying each device and tracing every alarm and trip contact through the lockout and to SCADA. On a maintenance outage we re-verify the same devices, the ones a testing crew focused only on windings and bushings tends to skip, and we document the results against the manufacturer's setpoints. It is the part of transformer protection that the electrical test set never touches, and it is exactly where an unverified contact hides.
Southern Switch commissions and tests transformer protection throughout Florida, Georgia, Alabama, Mississippi, South Carolina, North Carolina, and Tennessee: sudden pressure and gas relays, pressure relief devices, temperature indicators, and cooling controls, verified to the manufacturer's manual and documented for your PRC-005 record.
Transformer Field Testing →Request a Quote →Reference: Prolec GE, Installation, Operation and Maintenance Manual, Power Transformers (IOMM-ENG, Rev 3.1, June 2012), Sections 4, 6, and 7. Cited as the governing manufacturer manual Southern Switch works to on GE Prolec power transformers. Follow the manual, nameplate, and wiring diagram specific to your unit for device setpoints, contact assignments, and functional-check procedures.