Dissolved Gas Analysis (DGA) is a critical tool for assessing the internal condition of power transformers. Hydrogen (H₂) is one of the most common characteristic gases, but its sources are diverse – ranging from normal material chemical reactions to incipient faults such as partial discharge and overheating. Accurately identifying the source of hydrogen is essential for transformer condition assessment and maintenance decision‑making.
This article systematically reviews the main sources, generation mechanisms, and identification methods for hydrogen in transformer oil, and highlights the drawbacks of relying solely on single‑gas hydrogen monitoring.
Based on gas generation mechanisms and associated characteristics, hydrogen sources fall into three categories: internal faults, material chemical reactions, and external factors.
Mechanism: Weak discharge causes oil molecule cracking → H₂ generation.
Gas signature: H₂ dominates (>80%), trace CH₄ and C₂H₆ possible, almost no C₂H₂.
Key indicator: Isolated H₂ rise with very low other hydrocarbons.
Mechanism: Thermal breaking of C‑H bonds releases H₂.
Gas signature: CH₄, C₂H₆, C₂H₄ appear depending on temperature; H₂ level usually lower than in discharge cases.
Key indicator: H₂ rise accompanied by significant hydrocarbon gases (especially C₂H₄).
| Type | Mechanism | Typical Scenario | Gas Signature |
|---|---|---|---|
| Moisture‑involved reaction | Fe + H₂O → FeO + 2H → H₂ | High humidity, poor sealing | H₂↑ + moisture↑ |
| Cyclohexane catalytic dehydrogenation | Cyclohexane → Benzene + H₂ (Ni catalyst) | Stainless steel bellows expanders | Isolated H₂↑ (up to thousands ppm) |
| Metal corrosion | Electrochemical rusting produces H₂ | Rust in tank, core, coolers | Isolated H₂↑, possible moisture↑ |
Residual hydrogen in new oil: Dissolved during refining, transport, or filling – common in newly commissioned transformers, decreases with operation.
Improper oil treatment: Insufficient vacuum, short processing time, or poor temperature control can increase dissolved gases including H₂.
Core principle: Never rely on hydrogen concentration alone – combine multi‑dimensional information.
| H₂ Trend | Accompanying Gases | Moisture | Most Likely Source | Action |
|---|---|---|---|---|
| Isolated rise | No hydrocarbons, CO normal | Normal | Cyclohexane dehydrogenation, residual H₂ | Monitor only |
| Isolated rise | No hydrocarbons, CO normal | Elevated | Moisture‑related corrosion | Check sealing, treat moisture |
| Rise | CH₄, C₂H₄ etc. | Normal or elevated | Overheating | Electrical tests, plan inspection |
| Rise (dominant) | Trace CH₄, C₂H₆, no C₂H₂ | Normal | Partial discharge | PD measurement, consider outage |
| Rise | C₂H₂ present | Normal | Arcing (severe) | Immediate outage |
H₂↑ + moisture↑ → Moisture reaction or corrosion
H₂↑ + moisture normal → Discharge, catalytic dehydrogenation, or residual H₂
Rapid continuous increase → Active fault, need outage
Peak then stable/declining → Commissioning “break‑in” or catalytic equilibrium
Seasonal fluctuation → Moisture‑related reactions
High PD, ultrasonic anomalies → Partial discharge
Unbalanced DC resistance, abnormal core ground current, IR hot spots → Overheating
All tests normal + short service life → Material/process factors
Principle: CO is a specific byproduct of solid insulation (cellulose) thermal decomposition. Material/chemical hydrogen sources do not involve insulation heating, so CO remains normal.
Decision logic:
H₂↑ + CO normal → Benign hydrogen (material/process) – no unnecessary outage.
H₂↑ + CO↑ → Overheating involving solid insulation (e.g., multiple core grounds) – be alert.
CO↑ + H₂ normal → Normal thermal aging – not an emergency.
Practical value: Using H₂ and CO as a paired indicator significantly reduces false alarms and avoids costly unnecessary inspections.
Situation: 220kV transformer, 3 months in service, H₂ = 1500 μL/L, other gases <1 μL/L, moisture normal, all electrical tests normal.
Diagnosis: Cyclohexane catalytic dehydrogenation.
Outcome: After 1 year, H₂ stabilized at ~800 μL/L – no action needed.
Situation: 110kV transformer, 10 years in service, H₂ = 380 μL/L, CH₄ = 45 μL/L, C₂H₄ = 28 μL/L, moisture rose from 12 to 25 mg/L.
Diagnosis: Moisture‑induced rust reaction with mild overheating.
Outcome: Internal inspection revealed core rusting; after treatment, H₂ returned to normal.
Relying solely on hydrogen monitoring carries significant false‑alarm risks because:
Hydrogen sources are diverse – benign (material/process) and fault‑related (discharge/overheating) are indistinguishable from H₂ alone.
Single‑gas data cannot identify fault type, severity, or location.
It can lead to two extremes: missing major faults (assuming benign) or frequent false alarms → unnecessary outages and wasted resources.
Recommendations:
Prefer multi‑component DGA (at least H₂ + CH₄ + C₂H₂ + CO + moisture).
Allow elevated H₂ in newly commissioned transformers, but track trends and check CO.
For isolated H₂ rise with normal CO – do not rush to outage; enhance monitoring or perform degassing.
Q: What is the typical alarm threshold for hydrogen in transformer oil?
A: Usually >150 μL/L warrants attention, but thresholds vary by voltage class and asset type – trend analysis is more important.
Q: How long does it take for hydrogen to drop in a new transformer?
A: Typically 1‑3 months of operation or hot oil circulation. If H₂ remains high with hydrocarbon gases, further investigation is needed.
Q: Are single‑gas hydrogen monitors still useful?
A: They can provide basic early warning for distribution‑class transformers, but for critical assets, upgrade to multi‑component DGA is strongly recommended.
HERTZINNO’s online DGA systems (DGA900, DGA500, DGA300) support multi‑component gas plus moisture monitoring, effectively avoiding false alarms caused by single‑gas hydrogen monitoring. Learn more →
