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Dissolved gas analysis

Dissolved gas analysis (DGA) is a diagnostic technique used to examine the composition of gases dissolved in the insulating oil of electrical equipment, particularly mineral oil-immersed power transformers, to detect and identify incipient faults such as thermal degradation, partial discharges, and arcing before they lead to equipment failure.^[1] This method relies on the principle that electrical and thermal stresses cause the breakdown of oil and cellulose insulation materials, generating specific combustible and non-combustible gases that dissolve into the oil.^[2] The primary gases analyzed in DGA include hydrogen (H₂), methane (CH₄), ethane (C₂H₆), ethylene (C₂H₄), acetylene (C₂H₂), carbon monoxide (CO), and carbon dioxide (CO₂), with oxygen (O₂) and nitrogen (N₂) providing context for contamination or sampling issues.^[2] These gases are extracted from oil samples using standardized procedures, such as headspace extraction or vacuum methods, and quantified via gas chromatography for precise concentration measurements.^[3] Interpretation of results employs various approaches, including key gas analysis, ratio methods (e.g., Rogers or Doernenburg ratios), graphical tools like the Duval Triangle, and trending of gas generation rates to classify fault types and severity.^[1] DGA's importance lies in its sensitivity for early fault detection, enabling predictive maintenance that extends transformer lifespan, reduces downtime, and enhances grid reliability in the power industry.^[3] International standards guide its application, with IEEE C57.104 (2019) emphasizing gas trends, individual gas concentrations using percentile-based limits for normal operation, and generation rates to assess conditions (e.g., acetylene concentrations above 35 ppm typically indicate serious arcing faults), while IEC 60599 (2022) focuses on ratio-based fault identification.^[4]^[3]^[5] Regular sampling—often annually or more frequently based on risk—combined with online monitoring systems, has made DGA a cornerstone of transformer health management worldwide.^[2]

Overview

Definition and Purpose

Dissolved gas analysis (DGA) is the examination of gases dissolved in the insulating fluids of electrical equipment, such as power transformers, to identify early indicators of internal faults including decomposition and arcing.^[4] This diagnostic technique involves extracting and measuring these dissolved gases to assess the condition of the equipment.^[1] The primary purpose of DGA is to serve as a preventive maintenance tool that detects incipient faults, such as partial discharges, overheating, or insulation breakdown, thereby averting catastrophic failures in power systems.^[6] By enabling early intervention, DGA supports informed decision-making for equipment maintenance and operation, enhancing overall system reliability.^[7] At its core, DGA operates on the principle that gases are produced through thermal, electrical, or chemical degradation of the insulating oil and associated materials, which then dissolve into the fluid and can be subsequently extracted for evaluation.^[8] This process allows for non-destructive monitoring of equipment health without interrupting service. Key benefits of DGA include its cost-effectiveness and non-invasive nature, which facilitate routine assessments that extend the operational life of transformers and reduce the risk of unplanned outages in electrical networks.^[1] As a widely adopted method, it provides actionable insights into potential issues before they lead to significant damage.^[6]

Historical Development

The analysis of gases dissolved in transformer oil emerged from early 20th-century investigations into electrical breakdowns in insulating fluids, with initial observations of combustion gases under electrical stress documented in 1919. By the 1920s, the focus shifted to practical detection, highlighted by the 1921 invention of the Buchholz relay in Germany for collecting gas bubbles in oil-filled transformers during faults. Systematic discussions of gas collection and analysis for failure diagnostics appeared by 1928, laying the groundwork for what would become dissolved gas analysis (DGA) as a tool for identifying incipient faults.^[9]^[10] DGA was formalized in the 1960s and 1970s through advancements in analytical techniques, particularly gas chromatography, which allowed for the precise measurement of individual dissolved gases like hydrogen, methane, and acetylene originating from transformer faults. During this era, vacuum extraction methods using mercury pumps were developed between 1966 and 1970, and portable total combustible gas (TCG) detectors were introduced in 1965, enabling utilities to implement DGA for routine monitoring of oil-immersed equipment. Adoption accelerated in the 1970s, with the first online hydrogen monitor commercialized in 1974 by Morgan Schaffer, marking a shift toward proactive fault detection.^[9]^[11]^[9] Influential interpretation frameworks emerged from empirical studies of gases in failed transformers during the 1970s. The Rogers ratio method, introduced in 1973 by R.R. Rogers at Ontario Hydro, utilized ratios such as CH₄/H₂ and C₂H₂/C₂H₄ to diagnose fault types including thermal faults and discharges, drawing on thermodynamic models and extensive failure data. Complementing this, Michel Duval developed the Duval triangle in 1974, a graphical method plotting the relative percentages of methane (CH₄), ethylene (C₂H₄), and acetylene (C₂H₂) to classify faults like partial discharges and arcing, validated against hundreds of inspected cases. These approaches, grounded in large datasets from utilities, significantly improved diagnostic accuracy.^[12]^[13]^[14] Standardization in the late 1970s and 1980s promoted global consistency, with IEC 567 published in 1977 to guide DGA sampling and extraction procedures, followed by ASTM D3612 in 1979 for testing methods. The IEEE Std C57.104, first issued in 1978, provided comprehensive guidelines for interpreting gases in mineral oil-immersed transformers, incorporating ratio-based diagnostics and establishing thresholds for fault severity. These documents, developed through international collaboration, facilitated widespread utility adoption and refined DGA protocols.^[9]^[15] Since the 2000s, DGA has integrated with digital technologies for continuous monitoring, beginning with online multi-gas analyzers in the late 1990s that measured hydrogen and combustible gases without manual intervention. Advancements in the 2000s included micro gas chromatography devices and headspace techniques standardized in updated IEC 60567, enabling real-time trending of gas levels. By the 2020s, automated DGA systems support smart grid initiatives, using non-chromatographic sensors like spectroscopy for predictive maintenance and rapid fault localization in large-scale power networks.^[16]^[9]^[17]

Insulating Fluids

Types and Properties

Insulating fluids serve as both electrical insulators and coolants in power transformers, enabling the application of dissolved gas analysis (DGA) to detect faults through dissolved fault gases. The most prevalent type is mineral oil, a petroleum-derived hydrocarbon fluid that dominates due to its proven performance and cost-effectiveness. Other common types include synthetic esters (e.g., pentaerythritol-based), natural esters (vegetable oil-derived, such as soybean-based fluids), and silicone fluids (polydimethylsiloxane-based). Legacy fluids like polychlorinated biphenyls (PCBs), once used for their chemical stability, have been globally phased out since the 1970s due to their toxicity, bioaccumulation, and carcinogenic effects.^[18]^[19] Key properties relevant to DGA include high dielectric strength (typically >30 kV for 2.5 mm gap in new fluids) to minimize arcing, thermal stability up to 105–140°C operating temperatures without excessive breakdown, and viscosity (around 10–12 cSt at 40°C for mineral oils) that affects gas diffusion and solubility. These fluids can dissolve fault gases such as hydrogen (H₂) and methane (CH₄) up to several hundred ppm under abnormal conditions like partial discharges or low-energy arcing, with solubility influenced by temperature and pressure—higher temperatures increase gas partitioning into the oil phase. Silicone fluids exhibit lower gas solubility for hydrocarbons compared to mineral oils, while esters show higher affinity for gases like CO₂.^[4]^[20] Degradation in these fluids arises from oxidation (reaction with oxygen forming acids and sludge), hydrolysis (water-induced breakdown, prominent in esters), and thermal stress (pyrolysis above 200°C generating hydrocarbons). Mineral oils primarily yield hydrocarbon gases (e.g., CH₄, C₂H₄) under thermal faults, whereas ester fluids produce elevated CO₂ levels—up to 10 times more than mineral oils during oxidation or hydrolysis—along with CO from cellulose interactions. These differences necessitate fluid-specific DGA interpretation to avoid misdiagnosis.^[21]^[18] Selection of insulating fluids considers fire safety (esters have fire points >300°C vs. 140°C for mineral oil, reducing flammability risks), environmental impact (natural and synthetic esters are >95% biodegradable, minimizing spill hazards unlike persistent mineral oils), and DGA compatibility (mineral oils leverage extensive IEEE baselines, while esters require adjusted ratios due to unique gas profiles). These criteria drive adoption of esters in urban or ecologically sensitive installations despite higher upfront costs.^[4]^[18]

Gas Dissolution Mechanisms

In electrical equipment such as transformers, faults generate gases through specific decomposition processes of the insulating materials. Thermal decomposition of mineral oil under low-temperature conditions (below 300°C) primarily produces saturated hydrocarbons like methane (CH4) and ethane (C2H6), while higher temperatures (300–700°C) yield ethylene (C2H4) and, at very high temperatures (above 700°C), acetylene (C2H2) along with soot formation. Electrical arcing, involving high-energy discharges, predominantly generates acetylene (C2H2) and hydrogen (H2) due to the cracking of oil hydrocarbons under intense localized heating. Partial discharges, such as corona effects, result in hydrogen (H2) as the main gas, with minor amounts of methane (CH4) and acetylene (C2H2) from low-energy ionization of the oil. Breakdown of cellulose-based insulation, like paper, through pyrolysis produces carbon monoxide (CO) and carbon dioxide (CO2), reflecting the degradation of cellulosic polymers under thermal stress.^[22] These generated gases dissolve into the insulating fluid, primarily mineral oil, following principles of physical solubility. Henry's law governs this process, stating that the partial pressure (P) of a gas above the liquid is proportional to its concentration (C) in the solution, expressed as P = k \cdot C, where k is the Henry's law constant specific to the gas-oil pair.^[23] For hydrocarbon gases in mineral transformer oil, solubility generally increases with temperature, contrary to aqueous systems, due to the non-polar nature of the oil, allowing better accommodation of non-polar gases at higher thermal energies; for instance, the solubility of acetylene and ethylene rises notably between 25°C and 90°C.^[24] Pressure also enhances solubility, as higher system pressures force more gas molecules into the liquid phase, following the direct proportionality in Henry's law.^[23] Fault types produce distinct gas signatures based on energy levels, aiding in understanding dissolution patterns. Low-energy faults, such as corona or partial discharges, generate lighter, more soluble gases like hydrogen and methane, which dissolve readily but may partition variably due to their high diffusivity. High-energy faults, like arcing, produce unsaturated hydrocarbons such as acetylene and ethylene, which exhibit lower solubility coefficients but accumulate significantly under sustained conditions, reflecting the intense decomposition. Once dissolved, gases establish equilibrium dynamics between the oil and any headspace in the equipment. Gases partition according to their Ostwald coefficients, which describe the volume ratio of gas in the headspace to that dissolved in the oil at equilibrium, influenced by diffusion and phase transfer rates. In transformers with a gas blanket, this partitioning allows excess gases to migrate to the headspace, preventing supersaturation in the oil. Aging of the insulating fluid alters these solubility coefficients, as oxidative degradation increases oil polarity and viscosity, reducing the solubility of non-polar hydrocarbons like methane by up to 20–30% in severely aged oils compared to fresh samples.^[25]

Sampling Procedures

Collection Techniques

Collection techniques for dissolved gas analysis (DGA) in transformer insulating oil primarily involve obtaining representative samples that preserve the dissolved gases, adhering to standardized protocols to ensure accuracy and prevent contamination or gas loss. The standard practice for sampling electrical insulating liquids, including those used in transformers, is outlined in ASTM D923, which specifies methods for drawing samples from various points such as valves or drains while maintaining sample integrity.^[26] Valve-mounted syringes are a key tool for quick field sampling, typically ranging from 50 to 100 ml in capacity and constructed from borosilicate glass to minimize interactions with the oil. These syringes, equipped with three-way valves, attach directly to the transformer's sampling valve via a short hose adapter, allowing oil to be drawn after initial flushing to remove stagnant material. For transport to laboratories, larger oil sample tubes of 150 to 250 ml, made from borosilicate glass with Teflon stopcocks, provide a sealed environment that accommodates volume changes due to temperature fluctuations without gas escape. These tubes often include a side port with a PTFE-lined septum for subsequent subsampling.^[26]^[27] Procedures for online sampling, conducted while the transformer is energized, target dedicated sampling valves on the main tank, ideally at operating temperatures of 60-80°C to reduce gas partitioning into the headspace and maintain solubility. The process begins with verifying positive tank pressure, followed by flushing the valve and lines with at least 2 liters of oil to eliminate air or contaminants before collecting the sample. Offline sampling, performed during maintenance shutdowns, utilizes drain valves at the tank bottom, requiring extensive flushing—often 5 to 10 times the dead volume of the valve and tubing—to avoid introducing moisture or external gases that could skew results. In both cases, samples are drawn under controlled conditions to reflect the bulk oil properties of mineral or synthetic insulating fluids.^[26]^[28] Volume requirements vary by subsequent extraction method: a minimum of 50 ml suffices for headspace analysis, where a portion is equilibrated in a vial, while vacuum extraction demands at least 100 ml to achieve sufficient gas yield under reduced pressure. For reliable trending of gas concentrations over time, multiple samples (typically 2-3 per event) are recommended from the same location to account for variability. In field applications, portable kits incorporating valve-mounted syringes enable initial screening of key gases using compact analyzers, providing rapid diagnostics at remote sites. Conversely, sealed tubes are preferred for laboratory-bound samples, ensuring precise multi-gas analysis without degradation during transit.^[26]^[27]

Handling and Precautions

Maintaining sample integrity is critical in dissolved gas analysis (DGA) to ensure accurate fault detection in insulating fluids. Post-collection handling protocols emphasize minimizing gas loss, contamination, and degradation through controlled conditions and procedural safeguards. Samples must be stored under refrigerated conditions at 4-10°C in dark, non-porous containers such as glass syringes or metal bulbs to prevent gas diffusion and external influences like light or oxygen permeation.^[26] This temperature range slows chemical reactions and solubility changes, with a maximum hold time of 30 days recommended before analysis to preserve gas concentrations.^[26] Prompt transportation to the laboratory in insulated, sealed packaging further reduces variability. To avoid contamination, all equipment used in handling must be clean and dry, with sampling lines flushed 5-10 times their volume (typically 1-2 liters depending on system size) prior to collection to eliminate residual fluids or particulates.^[29] Air exposure should be strictly limited during transfer, as it introduces oxygen and nitrogen, skewing ratios and interfering with fault interpretation (e.g., O₂/N₂ > 0.2 indicates contamination).^[6] Safety protocols treat samples as potentially hazardous due to the presence of polychlorinated biphenyls (PCBs) in older equipment; personal protective equipment (PPE) including gloves, goggles, and protective clothing is required during handling.^[30] Containers must be labeled with collection temperature, date, time, and equipment identification to track chain of custody and ensure regulatory compliance.^[29] Common errors that compromise results include overheating the sample during collection (e.g., from hot valves or friction), which can cause premature gas evolution and elevate levels of hydrogen or hydrocarbons.^[11] Improper sealing of containers leads to leaks, allowing ingress of atmospheric gases or egress of dissolved ones, often resulting in unreliable data.^[6] Adhering to these protocols, often aligned with collection techniques using gas-tight syringes, mitigates such risks.

Gas Extraction Techniques

Headspace Method

The headspace method, designated as Method C in the ASTM D3612 standard, is a gas extraction technique used to liberate dissolved gases from insulating oil samples by establishing equilibrium between the liquid oil phase and a vapor headspace in a sealed container. This approach relies on Henry's law, where dissolved gases partition into the gas phase based on their solubility and the system's conditions, allowing for subsequent sampling of the headspace vapor without direct contact with the oil. The method is widely adopted for its balance of simplicity and reliability in dissolved gas analysis (DGA) of transformer oils. The procedure begins by transferring a precise volume of oil, typically 15–20 mL, into a sealed vial such as a 20 mL glass headspace vial fitted with a septum. The headspace above the oil is purged with an inert gas like argon to eliminate atmospheric contaminants, preventing interference from ambient oxygen or nitrogen. The vial is then heated to 60–80°C, often around 70°C, and agitated or shaken for 20–30 minutes to accelerate equilibration and ensure uniform partitioning of gases into the vapor phase. Once equilibrium is reached, the headspace gas is extracted using a gas-tight syringe for manual sampling or by pressurizing the vial to fill a sample loop in automated systems, preparing it for transfer to analytical instrumentation. This process adheres to ASTM D3612-C guidelines and minimizes sample handling to preserve gas integrity.^[31]^[32] Key equipment includes borosilicate glass vials with PTFE/silicone septa for sealing, a heating mantle or block to maintain consistent temperature, and an agitator or mixer to promote rapid equilibrium. For manual field applications, a gas-tight syringe facilitates direct extraction, while laboratory setups employ automated headspace samplers such as the TriPlus 500 or Versa systems integrated with gas chromatographs. Recovery efficiency for light, low-solubility gases like hydrogen (H₂) reaches approximately 90–95%, calculated using partition coefficients that account for the phase volume ratio and gas-specific solubility at the equilibration temperature.^[31]^[32] This method offers advantages in simplicity and low cost, making it ideal for field or on-site use where portable analyzers can perform extractions without complex vacuum setups; it excels at detecting volatile hydrocarbons such as H₂ and acetylene (C₂H₂), which readily partition into the headspace. Automated implementations enhance throughput, processing up to 120 samples with repeatability under 5% relative standard deviation. However, limitations include reduced extraction efficiency for more soluble gases like carbon dioxide (CO₂), where partition coefficients yield lower headspace concentrations (around 50% recovery in equal-volume phases), necessitating correction factors based on temperature, pressure, and gas-specific solubility data to accurately compute oil-phase concentrations. Additionally, variations in vial volume or incomplete purging can introduce errors, requiring strict adherence to standardized volumes and conditions.^[31]^[32]^[11]

Vacuum Extraction Methods

Vacuum extraction methods represent a foundational approach in dissolved gas analysis (DGA) for extracting dissolved gases from insulating oils, particularly in laboratory settings where high precision is required. This technique, standardized as Method A in ASTM D3612, involves subjecting the oil sample to a high vacuum to liberate the dissolved gases through degassing in multiple stages. The process achieves near-complete extraction by applying vacuum levels as low as 10^{-3} torr (1.33 \times 10^{-3} mbar), ensuring the removal of non-condensable gases such as hydrogen (H_2), oxygen (O_2), nitrogen (N_2), carbon monoxide (CO), carbon dioxide (CO_2), and light hydrocarbons (such as methane, ethane, ethylene, and acetylene).^[33] The core procedure utilizes a Toepler pump system, traditionally employing mercury displacement to collect and compress the evolved gases without atmospheric contamination; however, mercury-free alternatives using vacuum or other mechanisms are increasingly used to mitigate health and safety risks associated with mercury toxicity.^[34] In this setup, the oil sample is introduced into a sealed glass vessel, where an initial rough vacuum is applied to evacuate air and begin degassing. Subsequent fine extraction stages involve repeated cycles of vacuum application and gas collection, with the Toepler pump transferring the gases into a storage volume. To separate non-condensable gases from water vapor and other condensables, freezing traps cooled to temperatures as low as -196°C (using liquid nitrogen) are employed, allowing permanent gases to pass through while capturing interfering vapors. This multi-stage process typically yields a total gas recovery efficiency exceeding 95%, often approaching 100% for the Toepler variant, making it highly reliable for quantitative analysis.^[35] Essential equipment includes vacuum racks—elaborate, glass-sealed assemblies often configured for batch processing of multiple samples—along with mechanical vacuum pumps capable of achieving the required low pressures, manometers for volume measurement, and cold traps for vapor separation. These rack systems facilitate simultaneous handling of several oil samples, enhancing laboratory throughput while maintaining isolation to prevent cross-contamination. The collected non-condensable gases are then measured manometrically before transfer to gas chromatography for speciation.^[36] Vacuum extraction is preferred in controlled laboratory environments for its superior precision and ability to handle all relevant gas types, including reactive species like CO and CO_2, which may be underrepresented in simpler techniques. Compared to headspace methods, it offers greater extraction efficiency but requires more specialized equipment and operator expertise.^[35]^[37]

Analytical Methods

Gas Chromatography

Gas chromatography (GC) serves as the primary analytical technique for separating and identifying the extracted gases in dissolved gas analysis (DGA) of insulating oils from electrical equipment such as transformers.^[38] The process begins with the injection of the gas sample, typically obtained from headspace or vacuum extraction methods, into a heated port of the GC system where it vaporizes.^[31] An inert carrier gas, such as helium or argon, then transports the vaporized components through the chromatographic column, where separation occurs based on the differing affinities of the gas molecules for the stationary phase versus the mobile phase.^[39] Argon is often preferred over helium for thermal conductivity detection due to enhanced sensitivity for hydrogen.^[39] Column configurations in DGA-GC are tailored to achieve effective separation of key gases, commonly employing packed or capillary columns in a dual-channel setup.^[31] Molecular sieve columns, such as 5Å packed variants (e.g., 2 m × 1/8 inch), separate non-hydrocarbon gases like hydrogen, oxygen, and nitrogen by molecular size exclusion.^[31] Porous polymer columns (e.g., 3 m × 1/8 inch, 80/100 mesh) handle carbon monoxide, carbon dioxide, and light hydrocarbons, with backflushing used to vent higher hydrocarbons and prevent column overload.^[31] This multi-column approach ensures comprehensive resolution within a single run, typically under isothermal or temperature-programmed conditions around 50–100°C.^[31] Detection in DGA-GC relies on thermal conductivity detectors (TCD) and flame ionization detectors (FID) to quantify separated components by measuring peak heights or areas.^[38] TCDs, operated at temperatures like 200°C with filaments at 300°C, provide universal response for permanent gases such as H₂, O₂, and N₂, leveraging differences in thermal conductivity relative to the carrier gas.^[31] For hydrocarbons and carbon oxides, FIDs at 300°C, often equipped with a methanizer to convert CO and CO₂ to methane, offer high sensitivity to organic compounds while TCD handles inorganics in parallel channels.^[31] Calibration of the GC system ensures accurate quantification, using certified standard gas mixtures diluted in the carrier gas or oil matrices with concentrations ranging from 10 to 1000 ppm for linearity assessment.^[31] Response factors are calculated from multiple calibration points, verifying linearity with correlation coefficients typically exceeding 0.999, and applied to convert peak areas to gas concentrations in the original oil sample.^[31] Modern DGA-GC systems incorporate automation for efficiency, including autosamplers that process up to 120 vials with simultaneous incubation, reducing manual intervention and enabling high-throughput analysis in about 20–30 minutes per sample.^[31] Hybrid GC-mass spectrometry (GC-MS) configurations extend capabilities for trace-level detection and compound confirmation in complex samples, though standard GC suffices for routine DGA.^[40]

Detection and Quantification

In dissolved gas analysis (DGA) of insulating oils, primarily used for transformers, the standard gases measured include nine key species: hydrogen (H₂), oxygen (O₂), nitrogen (N₂), methane (CH₄), carbon monoxide (CO), carbon dioxide (CO₂), ethane (C₂H₆), ethylene (C₂H₄), and acetylene (C₂H₂).^[6]^[2] These gases are quantified in parts per million (ppm) by volume, equivalent to microliters per liter (μL/L) at standard conditions. Typical baseline concentrations for total dissolved combustible gases (TDCG, excluding O₂, N₂, and CO₂) are below 720 ppm in healthy equipment, with 90th percentile individual levels such as H₂ up to 100 ppm and CO₂ up to 10,000 ppm indicating normal operation per IEEE C57.104-2019.^[4] Quantification occurs post-extraction through gas chromatography (GC), where gases are separated and detected, followed by peak area integration compared to calibration standards of known concentrations.^[6] Detection limits vary by gas and method but are typically around 1-5 ppm for H₂, 5-10 ppm for CO, and 10-40 ppm for CO₂, enabling reliable measurement of trace fault indicators.^[41]^[42] Overall measurement uncertainty is approximately ±5-15% for laboratory GC analyses, depending on the instrument and sample handling.^[6] Interferents such as atmospheric O₂ and N₂, often introduced via leaks or sampling, are accounted for by calculating their ratio; values near 0.21 (air composition) prompt subtraction from total readings to isolate generated gases.^[6] Moisture contamination can elevate CO₂ readings by accelerating cellulose degradation, necessitating dry sampling conditions and separate water content analysis.^[6]^[2] For ongoing assessment, DGA relies on serial measurements over time to track gas generation rates, typically expressed in ppm per year; increases exceeding the 95th percentile rates (typically >200-500 ppm/year for TDCG depending on conditions) signal potential issues requiring further investigation per IEEE C57.104-2019.^[4] This trending approach, recommended in IEEE C57.104, uses at least three to six samples spanning 4-24 months for robust rate estimation.^[43]

Fault Interpretation

Types of Faults

Dissolved gas analysis (DGA) identifies various faults in oil-immersed transformers by examining the concentrations of dissolved gases such as hydrogen (H₂), methane (CH₄), ethane (C₂H₆), ethylene (C₂H₄), and acetylene (C₂H₂), which form due to thermal or electrical stresses.^[43] These faults are broadly categorized into thermal and electrical types, with additional indicators for overheating and partial discharges in insulation.^[44] Severity is assessed using total combustible gas (TCG) levels, where concentrations exceeding 720 ppm of TCG (sum of H₂, CH₄, C₂H₆, C₂H₄, and C₂H₂) signal the need for further investigation, and gas ratios help gauge fault energy levels. Thermal faults arise from overheating of the insulating oil or solid insulation, producing distinct gas profiles based on temperature ranges. At low temperatures below 300°C, methane (CH₄) dominates as the primary gas.^[3] In the medium range of 300–700°C, ethylene (C₂H₄) becomes prominent alongside CH₄.^[3] High-temperature faults above 700°C generate significant acetylene (C₂H₂) and elevated C₂H₄, often accompanied by soot formation.^[43] When cellulose insulation is involved in thermal faults, carbon monoxide (CO) and carbon dioxide (CO₂) are additionally produced, with CO₂ typically in higher proportions during aging or low-to-medium heating.^[44] Electrical faults manifest through discharges or arcs in the transformer, yielding specific gas signatures. Partial discharges, such as corona effects, are indicated by high levels of H₂ and CH₄.^[43] Low-energy sparking produces moderate C₂H₂ with elevated H₂ and CH₄.^[43] Arcing, involving high-energy discharges, results in substantial C₂H₂ and C₂H₄ concentrations.^[43] Other fault indicators include oil overheating, which elevates C₂H₆ and C₂H₄ due to thermal decomposition without solid insulation involvement, and partial discharges in insulation materials, characterized by H₂ spikes.^[44] These profiles, as outlined in standards like IEEE C57.104-2019 and IEC 60599, enable early detection of incipient issues before major failures occur.^[3]

Diagnostic Techniques

Diagnostic techniques in dissolved gas analysis (DGA) involve systematic interpretation of gas concentrations to identify and classify incipient faults in oil-immersed electrical equipment, such as power transformers. These methods rely on established algorithms and graphical tools to correlate gas levels with fault types like partial discharge (PD), thermal faults, and arcing, enabling predictive maintenance.^[1] Common approaches include ratio-based methods, key gas analysis, and dynamic trending, each providing complementary insights into fault severity and progression.^[45] Ratio methods compare concentrations of key hydrocarbon gases to diagnose specific fault mechanisms. The Rogers ratio method, developed in the 1970s, uses three primary ratios—CH₄/H₂, C₂H₆/CH₄, and C₂H₂/C₂H₄—to classify faults; for instance, a CH₄/H₂ ratio greater than 0.1 often indicates thermal degradation above 300°C.^[1] This technique simplifies fault identification by assigning numeric codes based on ratio ranges, though it may overlook low-level PD if hydrogen is not dominant.^[46] The Duval Triangle method employs a ternary diagram plotting the percentages of CH₄, C₂H₂, and C₂H₄ relative to their sum, dividing the plot into regions for PD (high CH₄), thermal faults (high C₂H₄), and high-energy arcing (high C₂H₂).^[47] Validated through extensive field data, it achieves high accuracy for mineral oil transformers, with fault regions defined by boundaries like 23% CH₄ for PD separation.^[48] The Doernenburg ratio method extends this by incorporating four ratios—CH₄/H₂, C₂H₆/CH₄, C₂H₄/C₂H₆, and C₂H₂/C₂H₄—along with absolute gas thresholds to confirm faults; ratios falling within designated bands signal thermal faults or discharges only if gases exceed baseline limits.^[49] The key gas method focuses on the dominant gas exceeding predefined thresholds to pinpoint fault types, as outlined in IEEE Std C57.104.^[4] For example, elevated C₂H₂ levels typically indicate arcing, while high H₂ suggests PD; thresholds such as 100 ppm for H₂ or 35 ppm for C₂H₂ (exceeding Condition 1 limits) trigger condition assessments.^[2] This approach provides a straightforward initial diagnosis but benefits from integration with ratio methods for confirmation, as single-gas dominance can vary with fault evolution.^[45] Advanced diagnostic techniques leverage computational models to integrate multiple DGA parameters for enhanced accuracy. Expert systems employing fuzzy logic process gas ratios and concentrations through if-then rules that handle uncertainty, combining outputs from methods like Rogers and Duval to yield probabilistic fault diagnoses.^[50] These systems, often implemented in software, improve consistency by weighting inputs dynamically and reducing contradictory interpretations from traditional techniques.^[51] Trending analysis monitors the rate of gas concentration increases over time to assess fault activity and urgency. According to IEEE guidelines, a doubling of total combustible gases in less than one month signals an active fault requiring immediate action, while slower rates (e.g., 65-180 days) indicate moderate concern.^[4] This method uses sequential DGA samples to calculate generation rates, accounting for factors like oil volume and temperature; however, false positives can arise from contamination or sampling errors, necessitating verification through repeated testing.^[45]

Applications and Standards

Primary Applications

Dissolved gas analysis (DGA) is primarily applied in the monitoring of power transformers, where it serves as a key diagnostic tool for detecting incipient faults in units rated at 132 kV and above. Routine offline DGA testing is typically conducted annually for these transformers to identify early signs of degradation, while online DGA systems are deployed for critical assets to enable continuous surveillance of gas levels such as hydrogen, methane, and acetylene. Incipient faults constitute 70-80% of transformer faults, and this approach enables their early detection, including partial discharges and overheating, thereby preventing escalation to catastrophic failures.^[52] Beyond power transformers, DGA extends to other oil-filled electrical equipment, including bushings, circuit breakers, and cables, where it assesses insulation health and identifies issues like arcing or thermal degradation in high-viscosity fluids. In emerging renewable energy applications, DGA is increasingly used for wind turbine transformers, which often exhibit elevated gas production due to variable loading and harmonics, supporting integration into grid systems. For instance, analysis of over 500 wind farm transformers has revealed patterns of stray gassing and partial discharges unique to these units.^[53] Implementation of DGA often involves integration with supervisory control and data acquisition (SCADA) systems for real-time monitoring and alerting, such as tracking gas concentrations via Modbus protocols converted to DNP3 for historical trending and rate-of-change alarms. This enables deferred maintenance strategies, yielding significant cost savings; for example, avoiding a single transformer failure can prevent replacement costs that are 2-3 times the original installation expense, along with millions in outage-related losses.^[54]^[55] Case studies illustrate DGA's effectiveness in early fault detection. In one 2010s incident involving a 400 kVA grounding transformer, elevated acetylene levels (288 ppm) signaled arcing at the off-load tap-changer shortly after energization, allowing timely repair and averting a prolonged outage. Similarly, in a 94 MVA gas-insulated switchgear transformer in 2015, DGA identified up to 1735 ppm acetylene from low-energy discharges, leading to contact repairs that maintained grid reliability. These utility grid examples highlight DGA's role in preventing arcing-related disruptions through proactive intervention.^[56]

Relevant Standards and Guidelines

The interpretation and application of dissolved gas analysis (DGA) in oil-filled electrical equipment are governed by several international standards that establish procedures for sampling, analysis, interpretation, and maintenance actions. These standards ensure consistency and reliability in diagnosing faults in transformers and related apparatus.^[4]^[57] The IEEE Std C57.104-2019 provides a comprehensive guide for the interpretation of gases generated in mineral oil-immersed transformers, including detailed procedures for gas sampling, laboratory analysis, and trending of dissolved combustible gases. It defines gas concentration limits for individual key gases such as hydrogen (H₂ ≤ 100 ppm), methane (CH₄ ≤ 120 ppm), acetylene (C₂H₂ ≤ 1 ppm), ethylene (C₂H₄ ≤ 50 ppm), ethane (C₂H₆ ≤ 65 ppm), and carbon monoxide (CO ≤ 350 ppm) under normal operating conditions (status 1, 90th percentile), along with trending procedures to monitor generation rates over time. Action levels based on total dissolved combustible gas (TDCG) are specified: Condition 1 (TDCG < 720 ppm, normal); Condition 2 (720–1920 ppm, increased monitoring and investigation); Condition 3 (>1920 ppm, potential severe faults necessitating immediate assessment).^[4]^[45] IEC 60599:2022 offers guidance on the interpretation of dissolved and free gases in mineral oil-filled electrical equipment in service, focusing on fault diagnosis for transformers, reactors, and similar devices insulated with cellulosic materials. It details the Duval Triangle method, a graphical technique using the relative percentages of methane (CH₄), ethylene (C₂H₄), and acetylene (C₂H₂) to classify faults, with codes such as T1-T3 for thermal faults (T1: <300°C, T2: 300-700°C, T3: >700°C) and D1-D2 for electrical discharges (D1: low-energy, D2: high-energy). The standard also addresses partial discharges (PD) and mixture faults, recommending cautious application to non-mineral oils.^[57]^[58] ASTM D3612-19 standardizes the sampling and gas chromatographic analysis of dissolved gases in electrical insulating liquids with viscosities up to 20 cSt, specifying three primary extraction procedures: A (total gas vacuum extraction), B (individual component extraction), and C (stripper column method for individual gases). It includes precision requirements, such as repeatability limits of ±10-20% relative standard deviation for major gases like CO₂ and hydrocarbons, and reproducibility up to ±30% across laboratories, ensuring accurate quantification down to parts-per-million levels. IEC 60567:2023 complements these by outlining methods for sampling free gases from relays and analyzing both free and dissolved gases in mineral oils and other insulating liquids, using techniques like vacuum extraction (Toepler and partial degassing), gas displacement by bubbling, and headspace sampling. Post-2020 updates in standards such as IEC 60599:2022 extend guidance to ester-based fluids (e.g., natural and synthetic esters) with adjusted interpretation thresholds, while IEEE Std C57.143-2024 addresses online DGA monitors, specifying calibration, data validation, and integration for real-time fault detection in transformers.^[59]

References

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