Frequently Asked Questions

Dissolved Gas Analysis (DGA) is a diagnostic technique that measures the concentrations of specific gases dissolved in transformer insulating oil. When a transformer develops an electrical or thermal fault, the oil and paper insulation decompose, generating characteristic gases: hydrogen (H₂), methane (CH₄), ethane (C₂H₆), ethylene (C₂H₄), acetylene (C₂H₂), carbon monoxide (CO), and carbon dioxide (CO₂). By measuring these gas concentrations and their ratios, engineers can identify the fault type, location, and severity — often months or years before a catastrophic failure occurs. Learn DGA fundamentals →

Offline (laboratory) DGA involves manually collecting an oil sample and sending it to a laboratory for analysis, typically once per year. Online DGA uses a permanently installed monitor that automatically extracts and analyzes gases at programmable intervals (hourly to daily). The key difference: offline DGA provides 1 data point per year; online DGA provides 365–8,760 data points per year. Full comparison →

LPAS uses a tunable semiconductor laser tuned to specific infrared absorption wavelengths for each fault gas. When the laser pulse hits gas molecules in the measurement cell, the absorbed energy causes periodic thermal expansion, generating an acoustic pressure wave. A sensitive microphone detects this wave, and its amplitude is proportional to gas concentration. LPAS requires no carrier gas, no columns, and no calibration — it is fully solid-state. Full LPAS guide →

The DGA-900 detects 9 fault gases plus moisture: hydrogen (H₂), carbon monoxide (CO), carbon dioxide (CO₂), methane (CH₄), ethane (C₂H₆), ethylene (C₂H₄), acetylene (C₂H₂), oxygen (O₂), nitrogen (N₂), and moisture (H₂O). The DGA-200/300/500 hydrogen sensors detect H₂ with sub-ppm sensitivity. Gas-by-gas reference →

IEC and IEEE standards recommend: (1) Critical transformers (GSU, >200 MVA, >220 kV): continuous online monitoring with hourly measurements; (2) Transmission transformers (66–220 kV): annual offline DGA minimum, online recommended; (3) Distribution transformers (<66 kV): every 2–4 years or fleet-wide hydrogen monitoring. The DGA-900 default measurement interval is 4 hours (configurable from 1 to 24 hours), providing 2,190 measurements per year.

IEEE C57.104-2019 defines L1 (90th-percentile) norms: H₂ 100 ppm, CH₄ 65 ppm, C₂H₂ 2 ppm, C₂H₄ 60 ppm, C₂H₆ 40 ppm, CO 500 ppm, CO₂ 5,000 ppm. These are population statistics — a rising trend from a transformer’s own baseline is more important than any absolute threshold. Full concentration guide →

The Duval Triangle plots the relative percentages of CH₄, C₂H₄, and C₂H₂ in a triangular coordinate system. Each point in the triangle corresponds to one of seven fault zones: PD (partial discharge), T1/T2/T3 (thermal faults of increasing severity), D1/D2 (low/high-energy discharge), and DT (mixed thermal and electrical). The method always produces a classification and is unaffected by absolute gas concentrations. Complete Duval Triangle guide →

Hydrogen-only monitors (DGA-200/300/500) detect H₂ as a universal early-warning gas — they catch ~90% of developing faults at lower cost. Multi-gas monitors (DGA-900) measure all 7+ fault gases, enabling full fault-type identification via Duval Triangle, IEC ratios, and Rogers Ratio — they tell you not just that there is a fault, but what kind and where. Complete comparison →

The palladium alloy thin-film hydrogen sensor has a design life exceeding 10 years with no calibration drift — validated in accelerated life testing and confirmed by field deployments showing 4+ years of zero-drift operation. The LPAS optical system in the DGA-900 has no consumable components; the laser diode is rated for >50,000 hours of continuous operation (>5.7 years at 24/7 use, >17 years at 8-hour measurement intervals).

No routine calibration is required. The palladium thin-film hydrogen sensor is inherently stable — the Pd-H reaction is a fundamental physical property, not a consumable chemical reaction. The DGA-900 LPAS system is factory-calibrated against reference gas standards traceable to NIST. We recommend an annual zero-gas verification (using the optional verification kit) to confirm baseline — a 5-minute procedure that does not interrupt monitoring.

MODBUS RTU (RS-485), MODBUS TCP (Ethernet), IEC 61850 Edition 3 (MMS, GOOSE), IEC 104, DNP3.0, 4–20 mA analog outputs, and programmable dry-contact relays for alarm. Wireless options: LoRaWAN (up to 10 km) and 4G LTE Cat-M1/NB-IoT cellular. All protocols are documented in the product manuals with published register maps.

Yes. The DGA-900 installs on any standard transformer sampling valve via the included universal valve adapter kit (DN15–DN32). Installation takes less than 1 hour and does not require taking the transformer offline. The monitor connects to the oil circulation loop using the same valve port used for manual oil sampling. For transformers without a suitable valve, a hot-tap installation can be performed by a qualified service provider.

Less than 1 hour for standard installations. The monitor attaches to the existing transformer sampling valve, power is connected (24 VDC or 100–240 VAC), and communication is configured. No oil draining, no transformer outage, no welding or drilling required.

Gas solubility in oil is temperature-dependent (Henry’s Law / Ostwald coefficient). As oil temperature increases, some dissolved gas moves from the oil phase to the gas phase. PAS DGA monitors compensate for this in two ways: (1) the measurement cell operates at a controlled temperature, and (2) the DGA-900 includes an oil temperature sensor and applies temperature compensation algorithms. For consistency, always compare readings at similar transformer load/temperature conditions.

Key standards: IEC 60599:2022 (DGA interpretation), IEEE C57.104-2019 (DGA interpretation for mineral oil transformers), IEC 60567:2024 (oil sampling and gas analysis methods), ASTM D3612 (GC analysis method), IEEE C57.143-2024 (application guide for monitoring equipment), CIGRE TB 771 (advances in DGA interpretation), CIGRE TB 783 (DGA monitoring systems). Complete standards reference →

IEEE C57.104-2019 provides rate-of-change severity: an increase of >30 ppm TDCG per day is a Level 4 (most urgent) condition regardless of absolute concentration. Any sudden appearance of acetylene (C₂H₂) — even at 2 ppm — demands immediate investigation: acetylene is produced only above 700°C, indicating active arcing. For hydrogen: a 50% increase over 24 hours warrants a confirmatory oil sample sent for laboratory GC analysis. Diagnostic methods reference →

Stray gassing is the generation of fault gases (primarily H₂ and CH₄) at normal operating temperatures without an actual fault — caused by oxidation of certain oil components. It is a known false-positive source that IEC 60599:2022 specifically addresses. Stray gassing patterns typically show: H₂ and CH₄ only (no C₂H₄, C₂H₂, or CO), stable or very slowly rising concentrations, and no correlation with load. If your monitor shows this pattern, confirm with laboratory GC and compare against the transformer’s oil type history.

The DGA-200 can be ordered with an integrated LoRaWAN transmitter. The monitor sends DGA data wirelessly up to 10 km line-of-sight to a LoRaWAN gateway (sold separately). The gateway connects to your SCADA network via Ethernet. One gateway supports up to 100 monitors. LoRa is ideal for: remote substations without network infrastructure, offshore platforms where cable pulls are expensive, and distributed transformer fleets where running RS-485 to each unit is impractical. Offshore wind LoRa case study →

All PAS DGA monitors include a 5-year standard warranty covering manufacturing defects in materials and workmanship. The palladium thin-film sensor element is warranted for 10 years against calibration drift exceeding 10% of reading. Extended warranty and service plans are available for fleets of 10+ monitors.

Technical support is available by email during business hours (CST, UTC+8) with a 24-hour response target. Support includes: installation assistance, troubleshooting, firmware updates, MODBUS/IEC 61850 integration guidance, and DGA data interpretation support. On-site commissioning and training is available through our authorized distributor network. All product manuals, software, and firmware are available on the Technical Resource Center.

Yes. The DGA-900 supports IEC 61850 Edition 3 (MMS and GOOSE) for seamless integration with modern digital substations. All monitors support MODBUS RTU (RS-485) and MODBUS TCP (Ethernet) — the universal industrial protocols compatible with virtually all SCADA/DCS platforms including GE, Siemens, Schneider Electric, ABB, and Emerson. MODBUS register maps are published in the product manuals for integration engineers.

Natural and synthetic ester fluids (IEC 62770) have different gas solubility, different normal gas backgrounds, and different decomposition chemistry than mineral oil (IEC 60296). Key differences: esters generate more CO and CO₂ from normal aging, have different Ostwald coefficients affecting gas partitioning, and require different Duval Triangle zones (Duval Triangle 5 specifically for non-mineral oils). The DGA-900 supports selectable oil types in its diagnostic engine. Always specify your oil type when configuring the monitor.