Transformer Site Acceptance Test (SAT) Checklist — Visual Inspection, Electrical Tests, and Pre-Energization Verification

Introduction

The Site Acceptance Test (SAT) is the gatekeeper between arrival and energization. An SAT done thoroughly catches shipping damage, installation errors, and latent defects before the transformer sees voltage — averting failures that range from expensive (a flashover that destroys bushings and requires a return to factory) to catastrophic (a tank rupture with oil fire). An SAT done superficially gives a false sense of security.

This checklist covers the full SAT sequence: what to inspect visually, which electrical tests to perform, how to interpret the results against factory benchmarks, and the final pre-energization checks that must be completed before the first close of the HV breaker.

Phase 1 — Documentation and Visual Inspection

Before Installing the Transformer

• [ ] Verify the transformer serial number, rated power, voltage ratio, vector group, and impedance against the purchase order and single-line diagram
• [ ] Check the Routine Test Report — confirm all parameters within specification; note any marginal values that need follow-up
• [ ] Verify that all loose accessories listed on the packing list have been received and are undamaged
• [ ] Inspect shock and tilt indicators — photograph and document status
• [ ] Check crate/packaging for damage, water ingress, or pest infestation
• [ ] Confirm the installation location matches the project layout drawing: adequate clearances for cooling, cable access, and maintenance per IEC 61936-1 or local regulations

After Installation — External Visual Check

• [ ] Oil level (liquid-immersed): Verify oil level in the conservator gauge — should be within the marked range at ambient temperature. If the transformer was shipped with a nitrogen blanket, the level may be low until oil expands under load — consult the manufacturer's temperature-level curve.
• [ ] Pressure/vacuum gauge: Oil-filled units with sealed conservator — check the pressure reading. Zero pressure indicates a leak. Positive pressure (0.1–0.3 bar at 20 °C) is normal.
• [ ] Bushing condition: Inspect all bushings (HV, LV, neutral) for cracks, chips, tracking marks, or contamination. Porcelain bushings: tap with a small metallic object — a clear ringing sound indicates no hidden crack; a dull thud warrants further investigation.
• [ ] Gaskets and seals: Check all flanged joints, valve stems, and bushing mounting flanges for oil weeping or sealant extrusion.
• [ ] Paint and corrosion: Note any scratches or impact damage. Touch up exposed metal immediately — salt-laden coastal air will rust exposed steel within days.
• [ ] Grounding: Verify the transformer tank is connected to the station ground grid with at least two independent connections per IEC 61936-1. Check ground lead cross-section (≥ 50 mm² copper or equivalent). Verify the neutral ground connection (if applicable) per the system earthing scheme.
• [ ] Nameplate: Confirm the nameplate is legible, correctly oriented, and accessible for future inspections. Verify data matches the test report.
• [ ] Cooling equipment: For forced-air (AF) or forced-oil (OF) cooling, verify fans and pumps are correctly wired, rotation direction is correct, and control circuits function. Run each fan/pump group briefly.

Accessories and Protection

• [ ] Buchholz relay (gas-actuated relay): Verify installation orientation — the relay must slope slightly toward the conservator (typically 1.5–3% per manufacturer). Verify the piping is gas-tight and the relay is filled with oil (check that the test petcock produces oil, not air).
• [ ] Winding temperature indicator (WTI): Verify the CT secondary is correctly connected to the heater element. Set the alarm and trip thresholds per the protection coordination study.
• [ ] Oil temperature indicator (OTI): Verify sensor bulb is fully inserted into the thermometer pocket and the pocket contains heat-transfer oil. Set alarm thresholds.
• [ ] Oil level indicator: Verify correct indication at the measured oil temperature.
• [ ] Pressure relief device (PRD): Verify the rupture disc or spring mechanism is intact and the alarm switch is connected.
• [ ] Silica gel breather: Check that the breather is correctly installed on the conservator pipe, the oil seal cup is filled to the mark, and the silica gel is blue. Replace if pink.
• [ ] Surge arresters: Verify correct mounting, ground connection, and surge counter (if fitted).

Phase 2 — Electrical Tests (Transformer Isolated, De-Energized)

Safety prerequisite: The transformer must be isolated from all sources, all terminals grounded temporarily before making connections, and a formal isolation and earthing procedure followed. All tests in this phase are performed with the transformer de-energized.

Insulation Resistance and Polarization Index

Purpose: Baseline condition assessment of the bulk insulation system. The single most important readily available test for detecting moisture ingress and gross contamination.

Method:

• Use a 5000 V DC insulation tester (megger) for windings rated above 1 kV; 2500 V for lower voltages
• Measure each winding against ground with all other windings and the tank grounded
• Measure between each winding pair (HV–LV, HV–tertiary, LV–tertiary)
• Record readings at 15 seconds, 30 seconds, 60 seconds, and 10 minutes

Acceptance:

• Compare 60-second readings against the factory test report — values should be ≥ 70% of factory benchmark at equivalent temperature
• Polarization Index = R_10min / R_1min: PI ≥ 1.5 is acceptable; PI ≥ 2.0 is good; PI < 1.0 indicates moisture and requires drying
• Dielectric Discharge (DD) test: DD < 2 acceptable; DD 2–4 marginal; DD > 4 problematic

Temperature correction: IR approximately doubles for every 10 °C decrease in temperature. Correct readings to 20 °C before comparing with factory values. Use the manufacturer's temperature correction curves if available; otherwise, approximate with a doubling every 10 °C.

Winding Resistance

Purpose: Verify that no winding damage (open circuit, high-resistance joint) occurred during shipping and installation. Compare against factory values as a connection integrity check.

Method:

• Use a DC winding resistance meter (micro-ohmmeter) with current ≥ 10 A for LV windings
• Measure each winding on the nominal tap position
• For OLTC-equipped transformers, measure at least the nominal, maximum, and minimum tap positions to verify tap-changer contact integrity through the full range

Acceptance:

• Deviation from the factory-measured values (temperature-corrected to the same reference): ≤ 2%
• Phase-to-phase imbalance: ≤ 2% of the average for the same winding
• For OLTC: resistance must change monotonically with tap position; no sudden jumps or erratic readings

Voltage Ratio and Vector Group

Purpose: Confirm the transformer ratio matches the specification and has not been changed by shipping or installation damage.

Method:

• Apply three-phase test voltage to the HV winding (rated voltage not required — a test set output of 100–250 V is sufficient)
• Measure LV phase-to-phase and phase-to-neutral voltages
• Verify phase displacement for vector group confirmation

Acceptance:

• Ratio deviation from nameplate: ≤ ±0.5% on the principal tap
• Vector group must match the nameplate exactly

Dielectric Dissipation Factor (Tan δ)

Purpose: Sensitive indicator of insulation moisture content, contamination, and aging. Less commonly performed than IR at SAT but strongly recommended for critical units and for establishing a commissioning baseline.

Method:

• Apply 10 kV test voltage from a capacitance and tan δ bridge
• Measure each winding against ground (UST — ungrounded specimen test mode) and between windings (GST — grounded specimen test mode)

Acceptance:

• New transformer: tan δ ≤ 0.5% at 20 °C for oil-immersed units; ≤ 1.0% for dry-type
• Compare with factory values: increase by more than 0.3% absolute (from the temperature-corrected factory value) warrants investigation
• Tip-up (tan δ increase between low and high test voltage): should be negligible for a new unit. Any measurable tip-up suggests internal voids.

Core Insulation Test

Purpose: Verify the core is insulated from the tank (single-point grounding) and there is no unintended second ground point that would cause circulating currents and localized overheating.

Method:

• Remove the external core ground connection
• Apply 500–1000 V DC between the core ground bushing/terminal and the tank
• Measure insulation resistance

Acceptance: Core-to-ground IR ≥ 10 MΩ at 1000 V DC (dry-type: ≥ 2 MΩ). Values below 1 MΩ suggest an internal short to ground — the transformer must not be energized.

Capacitance and Power Factor Testing of Bushings

Purpose: If the transformer has capacitance-graded bushings with a test tap, measure C1 (main insulation) power factor independently.

Method:

• Use a capacitance and power factor test set connected to the bushing test tap
• Measure C1 capacitance and power factor compared with nameplate values

Acceptance:

• C1 capacitance: within ±10% of nameplate
• Power factor (at 10 kV): ≤ 1.0% for oil-impregnated paper bushings; ≤ 0.5% for resin-impregnated paper (RIP) bushings
• Test tap C2 values should also be checked and recorded for future reference

Phase 3 — Oil Tests (Liquid-Immersed Transformers)

Oil Sampling

• [ ] Take oil samples from the bottom drain valve (for moisture, particulates, and dielectric strength) and from a dedicated sampling point if available (for DGA)
• [ ] Flush the sampling point thoroughly — discard the first 1–2 liters
• [ ] Use clean, dry, airtight glass syringes or bottles; fill completely leaving no air headspace
• [ ] Label samples with date, time, transformer serial number, location, and oil temperature
• [ ] Send to an accredited laboratory for analysis — field test kits are for screening, not commissioning decisions

Tests and Acceptance

Test	Acceptance (New Oil, Pre-Commissioning)	Standard
Dielectric breakdown voltage	≥ 50 kV (for Um ≤ 72.5 kV); ≥ 60 kV (for Um > 72.5 kV)	IEC 60156
Moisture content	≤ 10 ppm (for Um ≤ 72.5 kV); ≤ 8 ppm (for Um > 72.5 kV)	IEC 60814
Dissolved gas analysis (DGA)	Baseline — all gases near zero. Any measurable acetylene (C₂H₂) is a red flag.	IEC 60567 / IEC 60599
Acidity (neutralization number)	≤ 0.03 mg KOH/g	IEC 62021-1
Interfacial tension	≥ 40 mN/m	ASTM D971
Dissipation factor (tan δ) at 90 °C	≤ 0.5%	IEC 60247
Inhibitor content (if DBPC added)	0.25–0.40% (Typical)	IEC 60666
PCB content	Not detectable (required by regulation in most jurisdictions)	IEC 61619

DGA baseline: A dissolved gas analysis at commissioning is arguably the most important oil test because it establishes the reference for all future trends. Even trace levels of fault gases should be recorded. An acetylene (C₂H₂) level above 1–2 ppm in a new transformer strongly suggests internal arcing during factory testing or transport and must be investigated before energization.

Phase 4 — Protection Function Tests

• [ ] Buchholz relay: Simulate gas accumulation using the test pump or use the test contacts. Verify the alarm contact initiates the correct annunciation and the trip contact operates the HV and LV circuit breakers.
• [ ] Winding temperature indicator: Inject current into the WTI heater circuit to simulate load. Verify alarm and trip contacts activate at the preset temperatures.
• [ ] Oil temperature indicator: Verify trip and alarm contact operation. For forced-cooled transformers, verify the cooling fan/pump start and stop contacts operate at the correct temperatures.
• [ ] Pressure relief device: Test the alarm contact — manual operation of the test lever (where fitted).
• [ ] Oil level alarm: For transformers with magnetic oil level gauges, verify low-oil alarm contact.
• [ ] Differential protection: Perform stability test with rated current secondary injection. Verify restraint characteristics and harmonic blocking.
• [ ] Overcurrent and earth fault protection: Secondary injection test of all protection relays. Verify trip logic and breaker operation.
• [ ] Restricted earth fault (REF): Primary injection test if accessible; otherwise secondary injection with verified CT wiring.

Phase 5 — Pre-Energization Final Checks

• [ ] All temporary earthing connections removed from the transformer
• [ ] All test equipment disconnected; all test connections restored to normal
• [ ] All bolted electrical connections torqued to specification (use a calibrated torque wrench — this is not optional for MV connections)
• [ ] Tap-changer set to the designated commissioning position (usually the nominal tap)
• [ ] All valves in the correct position: radiator/isolation valves open, sampling valves closed, drain valves closed and capped
• [ ] Cooling equipment control supply energized and in AUTO mode
• [ ] Protection relays settings uploaded, verified, and enabled (confirm with a relay setting printout)
• [ ] All protection trip outputs linked to the correct circuit breakers
• [ ] Clearance from all personnel — no one inside the transformer enclosure or substation restricted zone
• [ ] Warning signage installed
• [ ] The SAT test sheets completed, signed, and filed with the project documentation

Frequently Asked Questions

FAQ

Q: The factory IR values are at 25 °C. Our site IR values are at 45 °C. How do I compare?

Apply temperature correction. As a rule of thumb, IR approximately halves for every 10 °C rise. From 25 °C to 45 °C is a 20 °C rise — expect the site IR to be roughly one-quarter of the factory value. If the factory IR was 2000 MΩ at 25 °C, a reading of 500 MΩ at 45 °C is consistent, not alarming. Always request the manufacturer's temperature correction curves — they are winding-specific and more accurate than the generic rule.

Q: Should I perform a DGA immediately after oil filling or wait?

Wait at least 24 hours after oil filling to allow gas equilibrium between oil and any gas-saturated components (pressboard, paper, internal air pockets). If the transformer was vacuum-filled, allow 48 hours. Taking a DGA sample immediately after filling will show elevated nitrogen and oxygen from dissolved air — this is normal and not indicative of a fault. The DGA "baseline" sample should be taken after the transformer has been at rest under oil for 24–48 hours and before energization.

Q: My PI is 1.3 — can I energize?

A PI of 1.3 is marginal. Before energizing: (a) verify temperature correction — at high ambient temperatures, the PI decreases (the 10-minute reading reaches its final value faster); (b) measure moisture content of the oil — if <10 ppm for MV units, the PI may be acceptable; (c) if the absolute IR values are high (e.g., >500 MΩ at 20 °C), a low PI may not indicate a problem; (d) consider running a dielectric frequency response (DFR) or polarization/depolarization current (PDC) test for a more definitive moisture assessment. As a rule, do not energize a transformer with PI < 1.0 unless the cause is clearly identified and accepted by the manufacturer and end user.

Q: What is the single most commonly skipped SAT test?

Core insulation resistance (sometimes called core ground test). This test requires accessing the core ground link — often located inside the terminal box or inside the tank on oil-filled units — and it is routinely skipped because "the factory already tested it." But core ground faults can develop during transport from vibration and impact, and an undetected second core ground will cause circulating currents, localized overheating, and gas generation that will be misdiagnosed as a winding fault. This test takes 10 minutes and costs nothing in equipment. Do not skip it.

Q: How long does a full SAT take?

For a distribution transformer (up to ~2500 kVA): 4–8 hours with a two-person team, including documentation. For a power transformer (10 MVA+): 1–3 days depending on the number of accessories and complexity of the protection scheme. Add one day if oil samples must be sent to an external laboratory and results awaited before the energization decision.

References & Standards

• IEC 60076-1:2011 — Power transformers — General
• IEC 60076-3:2018 — Insulation levels, dielectric tests
• IEC 61936-1:2021 — Power installations exceeding 1 kV AC — Common rules
• IEC 60422:2013 — Mineral insulating oils in electrical equipment — Supervision and maintenance guidance
• IEC 60156:2018 — Insulating liquids — Determination of breakdown voltage
• IEC 60567:2023 — Oil-filled electrical equipment — Sampling of gases and analysis
• IEEE C57.152-2013 — Guide for Diagnostic Field Testing of Fluid-Filled Power Transformers
• IEEE 62-1995 (R2004) — Guide for Diagnostic Field Testing of Electric Power Apparatus — Part 1: Oil-Filled Power Transformers
• CIGRE TB 445 — Guide for Transformer Maintenance