ASTM D3487 Transformer Oil Specifications:
Type I vs. Type II Explained

ASTM D3487 is the primary U.S. standard governing new mineral insulating oil for transformers and other electrical equipment. It defines two grades — Type I (uninhibited) and Type II (inhibited) — that differ in one critical respect: the presence of oxidation inhibitors. Understanding the difference between these two types is essential for writing transformer oil procurement specifications, evaluating bids, and ensuring the oil you receive meets the requirements of your application.

Both Type I and Type II oils are naphthenic-base mineral oils refined to achieve the electrical, physical, and chemical properties required for safe operation as dielectric coolants in power and distribution transformers, circuit breakers, tap changers, and switchgear.

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Type I vs. Type II — What's the Difference?

The sole defining difference is oxidation inhibitors:

Type I (Uninhibited) — Contains no intentionally added oxidation inhibitors. The oil's resistance to oxidation relies entirely on its natural composition as determined by the refining process. Type I oil may contain naturally occurring compounds that provide some oxidation resistance, but no synthetic antioxidants are added.
Type II (Inhibited) — Contains intentionally added oxidation inhibitors, most commonly DBPC (di-tert-butyl-para-cresol), also known as BHT (butylated hydroxytoluene). The inhibitor concentration is typically 0.08% to 0.40% by weight per ASTM D3487. These inhibitors scavenge free radicals during the oxidation process, significantly extending the oil's useful service life before acid number and sludge formation reach unacceptable levels.
In practical terms, Type II is the default specification for the vast majority of new transformer fills, retrofills, and maintenance top-offs in the U.S. market. Type I oil is rarely specified for new installations but may be encountered in legacy systems or applications where inhibitor-free oil is specifically required.

ASTM D3487 Property Requirements

The following table summarizes the key test properties and limits defined in ASTM D3487 for both Type I and Type II mineral insulating oil:

Property	Test Method	Type I Requirement	Type II Requirement
Dielectric Breakdown Voltage (minimum 1mm gap)	ASTM D1816	20 kV	20 kV
Dielectric Breakdown Voltage (minimum 2mm gap)	ASTM D1816	36 kV	36 kV
Dissipation Factor (max 25°C)	ASTM D924	0.05%	0.05%
Dissipation Factor (max 100°C)	ASTM D924	0.30%	0.30%
Interfacial Tension (minimum)	ASTM D971	40 mN/m	40 mN/m
Acid Number (maximum)	ASTM D974	0.03 mg KOH/g	0.03 mg KOH/g
Color (maximum)	ASTM D1500	0.5	0.5
Visual Examination	ASTM D1524	Bright and clear	Bright and clear
Pour Point (maximum)	ASTM D97	–40°C	–40°C
Flash Point (minimum)	ASTM D92	145°C	145°C
Kinematic Viscosity (max 0°C)	ASTM D445	12.0 mm²/s	12.0 mm²/s
Kinematic Viscosity (max 40°C)	ASTM D445	8.0 mm²/s	8.0 mm²/s
Kinematic Viscosity (max 100°C)	ASTM D445	2.5 mm²/s	2.5 mm²/s
Oxidation Stability — Sludge (max 72 hr)	ASTM D2440	0.10%	0.10%
Oxidation Stability — Total Acid Number (max 72 hr)	ASTM D2440	0.20 mg KOH/g	0.20 mg KOH/g
Oxidation Stability — Sludge (max 164 hr)	ASTM D2440	0.20%	0.20%
Oxidation Stability — Total Acid Number (max 164 hr)	ASTM D2440	0.40 mg KOH/g	0.40 mg KOH/g
Oxidation Stability — Sludge (max 332 hr)	ASTM D2440	Not specified	0.20%
Oxidation Stability — Total Acid Number (max 332 hr)	ASTM D2440	Not specified	0.30 mg KOH/g
Oxidation Inhibitor Content	ASTM D2668	None detected	0.08%–0.40%
Water Content (maximum)	ASTM D1533	35 mg/kg	35 mg/kg
Corrosive Sulfur	ASTM D1275	Non-corrosive	Non-corrosive
Passivator Content	IEC 60666	Not detected	Not detected

Note: Values shown represent the standard limits as published in ASTM D3487. Individual transformer manufacturers may specify tighter limits in their equipment specifications.

Understanding the Key Test Properties

Dielectric Breakdown Voltage (ASTM D1816)

This is the most fundamental electrical property of transformer oil — it measures the voltage at which the oil fails as an insulator and allows an electrical arc to pass through it. The test applies an increasing voltage across a pair of electrodes immersed in the oil sample until breakdown occurs.
The ASTM D3487 minimum for new oil is 20 kV at the 1mm gap and 36 kV at the 2mm gap. In practice, new transformer oil from quality suppliers routinely exceeds these minimums, with typical values of 28–35 kV at 1mm and 50–65 kV at 2mm. Low dielectric breakdown values indicate contamination — usually moisture, particles, or cellulose fibers.

Interfacial Tension (ASTM D971)

Interfacial tension (IFT) measures the force at the boundary between the oil and water, expressed in millinewtons per meter (mN/m). New oil has high IFT (≥40 mN/m). As oil ages and develops soluble contaminants and oxidation byproducts, IFT decreases. Low IFT is one of the earliest indicators of oil deterioration — a value below 25 mN/m typically indicates the oil is approaching the point where sludge formation accelerates.
IFT is particularly useful as a trending parameter. A steady decline in IFT over successive tests signals that oxidation is progressing and the oil may need reconditioning or replacement.

Oxidation Stability (ASTM D2440)

This is where Type I and Type II oils diverge most significantly. The ASTM D2440 test subjects oil to accelerated aging at 120°C with a copper catalyst and oxygen flow, measuring sludge formation and acid number increase over time.
Both types must meet the same limits at 72 and 164 hours. However, Type II has additional requirements at 332 hours— it must maintain sludge below 0.20% and total acid number below 0.30 mg KOH/g at this extended test duration. Type I has no 332-hour requirement because uninhibited oil typically cannot pass it.
This extended oxidation stability is the practical reason to specify Type II for most applications — the inhibitor significantly delays the onset of sludge and acid formation, which translates directly to longer oil life and longer intervals between maintenance.

Pour Point (ASTM D97)

Pour point defines the lowest temperature at which the oil remains fluid enough to flow. Both types require a maximum pour point of –40°C, which is adequate for most North American installations. Oil that approaches its pour point becomes highly viscous, reducing natural convective cooling within the transformer and potentially leading to thermal issues.
For installations in extreme cold (northern Canada, Alaska), procurement specifications sometimes require pour points of –50°C or lower, which exceeds the ASTM D3487 minimum and must be specifically requested from the supplier.

Flash Point (ASTM D92)

Flash point is the temperature at which oil vapor will ignite when exposed to an ignition source. ASTM D3487 requires a minimum flash point of 145°C for both types. This is standard for mineral oil and classifies it as a Class IIIB combustible liquid. For applications requiring higher fire safety, natural ester (~330°C) or synthetic ester (~250°C) fluids should be specified instead — these fall outside the scope of ASTM D3487 and are governed by IEEE C57.147 and IEC 61099/62770 respectively.

Corrosive Sulfur (ASTM D1275)

The corrosive sulfur test is critical because certain sulfur compounds in transformer oil can attack copper conductors and silver contacts within the transformer, causing copper sulfide deposition on windings. This was a significant industry issue in the 2005–2010 era when several batches of oil from specific refineries caused widespread copper sulfide failures.
ASTM D3487 requires oil to be "non-corrosive" per ASTM D1275. However, this test alone may not detect all problematic sulfur species. For critical applications, many utilities also require ASTM D1275B testing (the covered copper deposition test at elevated temperature) and may specify passivator-free oil, as indicated by the IEC 60666 passivator content requirement in the standard.

Which Type Should You Specify?

Specify Type II (inhibited) when:

Filling new transformers (this is the industry default)
Retrofilling transformers during maintenance
Top-offs and makeup oil additions
Any application where maximizing oil service life is desired
The transformer manufacturer's specification calls for Type II

Specify Type I (uninhibited) when:

The transformer manufacturer specifically requires uninhibited oil (rare in modern equipment)
The application requires inhibitor-free oil for compatibility reasons
You are testing for naturally occurring oxidation stability without inhibitor effects
The equipment specification explicitly calls for Type I

When in doubt, Type II is almost always the correct choice. The cost difference between Type I and Type II is minimal, and the extended oxidation life provided by the inhibitor is valuable in virtually every application.

Related Standards and Specifications

ASTM D3487 is not the only standard governing transformer oil. Depending on the application, jurisdiction, and equipment manufacturer, the following standards may also apply:

ASTM D3487 — New mineral insulating oil (the standard covered in this guide)

ASTM D6871 — Standard specification for natural (vegetable oil) ester fluids used in electrical apparatus

IEC 60296 — International standard for mineral insulating oils (the IEC equivalent of ASTM D3487, used outside North America)

IEC 61099 — Standard for synthetic ester fluids

IEC 62770 — Standard for natural ester fluids

IEEE C57.106 — Guide for acceptance and maintenance of insulating mineral oil in electrical equipment (covers in-service oil testing and maintenance, not just new oil)

IEEE C57.147 — Guide for acceptance and maintenance of natural ester insulating liquid in transformers

Frequently Asked Questions

What does "inhibited" mean in transformer oil?

Inhibited means the oil contains intentionally added antioxidants — typically DBPC (di-tert-butyl-para-cresol) — that slow down the oxidation process. This extends the oil's useful life by delaying acid and sludge formation. Type II oils are inhibited; Type I oils are not.

Can I mix Type I and Type II oil?

Yes. Mixing Type I and Type II mineral oil is acceptable and commonly done. The result is a partially inhibited oil — the inhibitor concentration will be diluted proportionally. If adding oil to a transformer with existing Type II oil, using Type II for the top-off is preferred to maintain full inhibitor protection.

How do I verify that oil meets ASTM D3487?

Request the Certificate of Analysis (COA) from your supplier. The COA should list test results for all ASTM D3487 properties and confirm compliance with either Type I or Type II requirements. All oil sold through TransformerParts.com ships with a COA.

Is ASTM D3487 the same as IEC 60296?

No, but they cover similar territory. ASTM D3487 is the U.S. standard for new mineral insulating oil; IEC 60296 is the international equivalent. The test methods and limits differ in some areas. Equipment manufactured to IEC standards may reference IEC 60296 instead of ASTM D3487. Most quality transformer oils meet both standards.

Does ASTM D3487 cover ester-based transformer fluids?

No. ASTM D3487 applies only to mineral (petroleum-based) insulating oil. Natural ester fluids are covered by ASTM D6871, and synthetic esters by IEC 61099. If you're specifying ester-based fluids, reference the appropriate ester standard rather than ASTM D3487.

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TransformerParts.com stocks ASTM D3487 Type II inhibited mineral insulating oil in 55-gallon drums, 330-gallon totes, and full tanker loads. All shipments include certificates of analysis confirming compliance with ASTM D3487 Type II requirements.

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