COVER STORY : EVOLUTION OF DISSOLVED GAS ANALYSIS (DGA) TESTING – AN OVERVIEW
10 Aug 2023
Abstract: Dissolved and free gas analysis (DGA) is one of the most widely used diagnostic tools for detecting and evaluating faults in electrical equipment filled with insulating liquid. However, interpretation of DGA results is often complex and should always be done with care, involving experienced insulation maintenance personnel. This paper describes how the concentrations of dissolved gases or free gases can be interpreted to diagnose the condition of oil-filled electrical equipment in service and suggest future action. This paper gives overview of the evolution of DGA testing over the year with advancement in the technology and changes in the guidelines or codes.
The DGA diagnostic tool considered to be the main interpretation methods used for fault diagnosis of power transformers are discussed. This includes the Key Gas, Dornenburg Ratio, Rogers Ratio, IEC Basic Gas Ratio, Duval Triangle, and key gases methods. This paper also gives overview of other methods given in IEEE C57.104.2019 which are quite different from previous version. Key Word: Dissolved Gas Analysis (DGA), Insulation Failure, Thermal and Electrical Faults, Combustible gases , Free Gases. Chemical Names and Formulae Name Formula Nitrogen N2 Oxygen O2 Hydrogen H2 Carbon monoxide CO Carbon dioxide CO2 Methane CH4 Ethane C2H6 Ethylene (Ethene) C2H4 Acetylene (Ethyne) C2H2
1.0 INTRODUCTION
Dissolved gas analysis (DGA) is the study of dissolved gases in transformer oil. It is also referred to as a DGA test. Dissolved gas analysis (DGA) is the identification, measurement, and interpretation of the gases dissolved in the insulating liquid. Whenever a transformer undergoes abnormal thermal and electrical stresses, certain gases are produced due to the decomposition of the transformer oil. When the fault is major, the production of decomposed gases is significant and they get collected in a Buchholz relay. But when abnormal thermal and electrical stresses are not significantly high the gasses due to decomposition of transformer insulating oil will get enough time to dissolve in the oil. Hence by only monitoring the Buchholz relay it is not possible to predict the condition of the total internal healthiness of electrical power transformer. That is why it becomes necessary to analyze the number of different gasses dissolved in transformer oil in service. Using DGA of transformer oil, one can predict the actual condition of the internal health of a transformer (Refer figure 1). It is preferable to conduct the DGA test of transformer oil in a routine manner to get historical information about the internal health of a transformer over its lifetime. In a DGA test, first of all oil sample is collected from the transformer (Refer figure 2) & the gases in oil are extracted and analyzed to determine the quantity of gasses in a specific amount of oil. By observing the percentages of different gasses present in the oil, the internal condition of the transformer can be predicted.
Generally, the gasses found in the oil in service are hydrogen (H2), methane (CH4), Ethane (C2H6), ethylene (C2H4), acetylene (C2H3), carbon monoxide (CO), carbon dioxide (CO2), nitrogen (N2) and oxygen(O2).
Most commonly used method of determining the content of these gases in oil, is using a Vacuum Gas Extraction Apparatus and Gas Chronographs. Using this apparatus, gasses are extracted from oil by stirring it under vacuum. These extracted gasses are then introduced in gas Chronographs for measurement of each component (Refer figure 3). Presently online DGA are also provided with transformer for continuous monitoring of gases generation in the transformer as shown in figure 4. Generally it is found that hydrogen and methane are produced in large quantity if the internal temperature of power transformer rises up to 150oC to 300oC due to abnormal thermal stresses. If the temperature goes above 300oC, ethylene (C2H4) is produced in large quantity. At the temperature is higher than 700oC a large amount of hydrogen (H2) and ethylene (C2H4) are produced. Ethylene (C2H4) is an indication of a very hightemperature hot spot inside an electrical transformer. If during DGA test of transformer oil, CO and CO2 are found in large quantity it is predicted that there is decomposition of proper insulation. In short Dissolved gas analysis (DGA) is the identification, measurement, and interpretation of the gases dissolved in the insulating liquid. The principal gases used in identification of faults (socalled “fault gases”) are hydrogen (H2); methane(CH4); ethane (C2H6); ethylene (C2H4); acetylene (C2H2); carbon monoxide (CO); and carbon dioxide (CO2). Oxygen (O2) and nitrogen (N2) are also measured and used in the interpretation, although they are not fault by-products.
The gases containing both of the elements carbon (C) and hydrogen (H2) are called hydrocarbons, and the gases CO and CO2 are called carbon oxides. Hydrogen, the hydrocarbon gases, and carbon monoxide are combustible gases, while oxygen, nitrogen, and carbon dioxide are non-combustible gases. Other gases that may be dissolved in the insulating liquid, such as argon (Ar) and higher molecular weight hydrocarbon gases, are ordinarily ignored for transformer DGA. Other light gases, such as propane and propylene, are also generated, but are analysed. The concentration of a gas dissolved in insulating liquid is expressed in microliters per liter (μL/L), also referred to as parts per million by volume (ppm v/v). The concentration of a gas in the gas mixture collected from a gas space is often expressed as percent by volume. Rates of gas generation are commonly expressed in microliters per liter per day (μL/L/d), ppm per day (ppm/d), microliters per liter per year (μL/L/y), or ppm per year (ppm/y).
The application of DGA are following
1. Basic risk management
2. Detection and monitoring of abnormalities
3. Quality assurance metric
4. Fault type identification
5. In-service tripping investigation
2.0 GENERATION OF GASES IN TRANSFORMER
The generations of gases in transformer are studied under two categories as explained below:
2.1 Decomposition of Oil Insulation
Mineral insulating oils are made of a blend ofdifferent hydrocarbon molecules containing CH3, CH2 and CH chemical groups linked together by carbon-carbon molecular bonds. Scission of some of the C-H and C-C bonds can occur as a result of electrical and thermal faults, with the formation of small unstable fragments, in radical or ionic form, such as H,CH3,CH2,CH or C (among many other more complex forms), which recombine rapidly, through complex reactions, into gas molecules such as hydrogen (H-H), methane (CH3-H), ethane (CH3-CH3), ethylene (CH2=CH2) or acetylene (CH=- CH). C3 and C4 hydrocarbon gases, as well as solid particles of carbon and hydrocarbon polymers (X-wax), are other possible recombination products. The gases formed dissolve in oil, or accumulate as free gases if produced rapidly in large quantities, and can be analysed by DGA test. Low-energy faults, such as partial discharges of the cold plasma type (corona discharges), favour the scission of the weakest C-H bonds (338 kJ/mol) through ionization reactions and the accumulation of hydrogen as the main recombination gas. More and more energy and/or higher temperatures are necessary for the scission of the C-C bonds and their recombination into gases with a C-C single bond (607 kJ/mol), C=C double bond (720 kJ/ mol) or C=-C triple bond (960 kJ/mol), following processes bearing some similarities with those observed in the petroleum oil-cracking industry. Ethylene is thus favoured over ethane and methane above temperatures of approximately 500 °C (although still present in lower quantities below these temperatures). Acetylene requires temperatures of at least 800 °C to 1 200 °C, and a rapid quenching to lower temperatures, in order to accumulate as a stable recombination product. Acetylene is thus formed in significant quantities mainly in arcs, where the conductive ionized channel is at several thousands of degrees Celsius, and the interface with the surrounding liquid oil necessarily below 400 °C (above which oil vaporizes completely), with a layer of oil vapour and/or decomposition gases in between. Acetylene can still be formed at lower temperatures (< 800 °C), but in very minor quantities. Carbon particles form at 500 °C to 800 °C and are indeed observed after arcing in oil or around very hot spots. Oil can oxidize with the formation of small quantities of CO and CO2, which can accumulate over long periods of time into more substantial amounts.
2.2 Decomposition of CellulosicInsulation
The polymeric chains of solid cellulosic insulation (paper, pressboard, wood blocks) contain a large number of anhydroglucose rings, and weak C-O molecular bonds and glycosidic bonds which are thermally less stable than the hydrocarbon bonds in oil, and which decompose at lower temperatures. Significant rates of polymer chain scission occur at temperatures higher than 105 °C, with complete decomposition and carbonization above 300 °C (damage fault). Carbon monoxide and dioxide, as well as water, is formed, together with minor amounts of hydrocarbon gases, furanic and other compounds. Furanic compounds are analysed according to IEC 61198, and used to complement DGA interpretation and confirm whether or not cellulosic insulation is involved in a fault. CO and CO2 formation increases not only with temperature but also with the oxygen content of oil and the moisture content of paper.
2.3 Stray Gassing of Oil
Stray gassing of oil has been defined by CIGRE as the formation of gases in oil heated to moderate temperatures (< 200 °C). H2, CH4 and C2H6 can be formed in all equipment at such temperatures or as a result of oil oxidation, depending on oil chemical structure. Stray gassing is a non-damage fault.
2.4 Other Sources of Gas
Gases can be generated in some cases not as aresult of faults in the equipment, but through corrosion or other chemical reactions involving steel, uncoated surfaces or protective paints. Hydrogen can be produced by reaction of steel and galvanized steel with water, as long as oxygen is available from the oil nearby. Large quantities of hydrogen have thus been reported in some transformers that had never been energized. Hydrogen can also be formed by reaction of free water with special coatings on metal surfaces, or by catalytic reaction of some types of stainless steel with oil, in particular oil containing dissolved oxygen at elevated temperatures. Hydrogen, acetylene and other gases can also be formed in new stainless steel, absorbed during its manufacturing process, or produced by welding, and released slowly into the oil. Internal transformer paints, such as alkyd resins and modified polyurethanes containing fatty acids in their formulation, can also form gases. Gases can also be produced, and oxygen consumed, by exposure of oil to sunlight. These occurrences, however, are very unusual, and can be detected by performing DGA analyses on new equipment which has never been energized, and by material compatibility tests. The presence of hydrogen with the total absence of other hydrocarbon gases, for example, can be an indication of such a problem.
3.0 IDENTIFICATION OF FAULTS
Although the formation of some gases is favoured, depending on the temperature reached or the energy contained in a fault in practice mixtures of gases are almost always obtained. As per standards, internal inspection of hundreds of faulty equipment has led to the broad classes of visually detectable faults mentioned in Faults often start as incipient faults of low energy, which can develop into more serious ones of higher energies, leading to possible gas alarms, breakdowns and failures. When a fault is detected at an early stage of development, it can be quite informative to examine not only the increase in gas concentrations, but also the possible evolution with time toward a more dangerous high-energy fault resulting in failure.
4.0 DGA INTERPRETATION TECHNIQUES
The DGA interpretation techniques have been suggested by international standards, e.g., IEEE C57.104:2008, IEEE C57.104:2019, IEC 60599:2022 and IS 10593-2022, including national standards and utility methods. Due to the complexity of the DGA test technique and a variety of dissolved gas interpretation methods, therefore, to efficiently perform DGA needs a skilled person or even an expert to achieve the DGA test technique and interpretation. The dissolved gas interpretation techniques applied in utilities
4.1 Key Gas Method: The Key Gas method is based on the quantity of fault gases that are released from the insulating oil as the chemical structure breaks at varying temperatures in the transformer. This method uses individual gas levels, or ‘key gases,’ for detecting faults.
4.2 Doernenburg Ratio Method (DRM) : Inorder to use the DRM, the concentration of one of the key gases (H2, C2H2, C2H4, C2H6, or CH4) needs to be at least double the relevant L1 concentrations, as shown in table 3. When this criterion is met, there are four possible ratios that can be calculated if they contain the key gas of concern.
4.3 Rogers Ratio Method (RRM): The Rogers Ratio method evolved from the Doernenburg method and is used exactly the same way, but instead of needing significant concentrations of FIG.5 KEY GASES & FAULT INDICATIONS Table -2 Key Gases Method 38 || July 2023 || ELECTRICAL MIR OR R www.electricalmirror.net the key gases, the RRM can be used when the concentrations exceed the values listed in table 3 (rather than double). Values for the three gas ratios, corresponding to suggested diagnostic cases, are shown in table 5. The fault types (cases) that are provided have been chosen by combining some cases from the number of fault types originally suggested by Rogers. Despite having better accuracy, the Doernenburg Ratio, Rogers Ratio, and Basic Gas Ratio approaches have one drawback where some combinations of gases do not fit into the specified range of values when calculated and the fault type cannot be determined.
4.4 Duval Triangle Method (DTM): Michel Duval invented the Duval triangle method (DTM) in 1974 for the interpretation of dissolved gases within mineral oil used in a mineral oil-filled transformer.The use of the DTM is based upon three key gases (CH4, C2H4, and C2H2) that correspond to the increasing energy levels of gas formation, as shown in Figure 6. Within the triangle there are six (6) potential fault zones covering partial discharges, electrical faults (arcing high and low energy), and thermal faults (over various temperature ranges), plus a DT zone (mixture of thermal and electrical faults). These gas concentrations are calculated and then plotted along the three sides of a triangle diagram using the following ratios:
• %CH4 = (CH4/CH4+C2H2) x 100
• %C2H4 = (C2H4/CH4+C2H4+C2H2) x 100
• %C2H2 = (C2H2/CH4+C2H4+C2H2) x 100
As previously stated, one drawback of the gas ratio methods is that some results can fall outside the codes and no diagnostics can be given (unresolved diagnostics). This does not occur with the Duval Triangle method because it is a ‘closed system.’ It always provides a diagnosis, with a low percentage of wrong diagnoses.
4.5 Duval Pentagon Method: Recently, Michel Duval proposed the Duval pentagon method (DPM) developed based on the Duval triangle. Two additional gases, including Hydrogen and Ethane, beneficial to separate PD phenomena out of the thermal fault at low energy, are utilized in the DPM applied for mineral oil problem investigation. Besides, the stray gas zone (S) related to the gas generation under normal operation is introduced in the Duval pentagon, which escalates this method’s capability to categorize the normal aging condition of the insulation used in a transformer. The DPM uses all five hydrocarbon gases, namely, CH4, C2H2, C2H4, C2H6, and H2, including the total gases expressed in percent as presented. The axes of the pentagon cover the range from 0 to 100%, by which the midpoint of the pentagon is defined as the starting point. The centroid of the pentagon is computed and plotted on the Duval pentagon . The type of fault is specified based on the failure zone,
4.6 IEC Ratio Method (Basic gas ratios):
IEC 60599 recommends the IEC ratio method (IRM) as one of the international DGA interpretation techniques. Three gas ratios are applied to identify fault types demonstrated in Table 6. However, it needs to realize that some combinations of the gas ratios may drop outside the determined range. In such cases, the 3-dimension graphic in is required to accomplish the interpretation task by which the feasible fault types can be specified as the zone or box closest to the undiagnosed case. Furthermore, some cases may not clearly identify if they fall in the overlap fault zones. This method uses the same three ratios as the revised RRM but suggests different ratio ranges and interpretations.
5.0 IMPORTANCE OF OTHER RATIOS
It is important to understand the interpretation of other ratio which are discussed below:
5.1 CO2/CO ratio: The formation of CO2 and CO from oil-impregnated paper insulation increases rapidly with temperature. High values of CO (e.g. 1000 ppm) and CO2/CO ratios less than 3 are generally considered as an indication of probable paper involvement in a fault, with
possible carbonization, in the presence of other fault gases. However, in some recent transformers of the closed-type or open (free breathing) transformers operating at constant load (i.e. with low breathing), CO can accumulate in the oil, leading to ratios CO2/CO < 3, without any irregularities or faults if no other gases such as H2 or Hydrocarbons are formed. High values of CO2 (> 10 000 ppm) and high CO2/CO ratios (> 10) can indicate mild (< 160 °C) overheating of paper or oil oxidation, especially in open transformers. CO2 can accumulate more rapidly than CO in open transformers operating at changing loads because of their different solubilities in oil. This, and the long term degradation with time of paper at low temperatures (< 160 °C), can lead to higher CO2/CO ratios in aged equipment. In some cases, localized faults in paper do not produce significant amounts of CO and CO2 and cannot be detected with these gases (the same for furanic com Involvement of faults in paper therefore shall not be based only on CO and CO2, but shall be confirmed by the formation of other gases or other types of oil analysis. When excessive paper degradation is suspected, it is recommended to ask for further analysis (e.g. of furanic compounds) or a measurement of the degree of polymerization of paper samples, when this is possible.
5.2 O2/N2 Ratio: Dissolved O2 and N2 are found in oil as a result of contact with atmospheric air in the conservator of air-breathing equipment, or through leaks in sealed equipment. At equilibrium with air, the concentrations of O2 and N2 in oil are approximately 32,000 ppm and approximately 64,000 ppm, respectively and the O2/N2 ratio is approximately 0.5. In service, this ratio can decrease as a result of oil oxidation and/or paper ageing, if O2 is consumed more rapidly than it is replaced by diffusion.
5.3 C2H2/H2 Ratio: In power transformers, on-load tap-changer (OLTC) operations produce gases corresponding to discharges of low energy (D1). If some oil or gas communication is possible between the OLTC compartment and the main tank, or between the respective conservators, these gases can contaminate the oil in the main tank and lead to wrong diagnoses. The pattern of gas decomposition in the OLTC, however, is quite specific and different from that of regular D1s in the main tank. C2H2/H2 ratios higher than 2 to 3 in the main tank are thus considered as an indication of OLTC contamination. This can be confirmed by comparing DGA results in the main tank, in the OLTC and in the conservators. The values of the gas ratio and of the acetylene concentrationdepend on the number of OLTC operations and on the way the contamination has occurred (through the oil or the gas). If contamination by gases coming from the OLTC is suspected, interpretation of DGA results in the main tank should be made with caution by subtracting background contamination from the OLTC, or should be avoided as unreliable. Modern OLTCs are designed not to contaminate oil in the main tank.
5.3 C2H2/H2 Ratio: In power transformers, on-load tap-changer (OLTC) operations produce gases corresponding to discharges of low energy (D1). If some oil or gas communication is possible between the OLTC compartment and the main tank, or between the respective conservators, these gases can contaminate the oil in the main tank and lead to wrong diagnoses. The pattern of gas decomposition in the OLTC, however, is quite specific and different from that of regular D1s in the main tank. C2H2/H2 ratios higher than 2 to 3 in
the main tank are thus considered as an indication of OLTC contamination. This can be confirmed by comparing DGA results in the main tank, in the OLTC and in the conservators. The values of the gas ratio and of the acetylene concentration depend on the number of OLTC operations and on the way the contamination has occurred (through the oil or the gas). If contamination by gases coming from the OLTC is suspected, interpretation of DGA results in the main tank should be made with caution by subtracting background contamination from the OLTC, or should be avoided as unreliable. Modern OLTCs are designed not to contaminate oil in the main tank.
5.4 C3 Hydrocarbons: The interpretation method of gas analysis takes into account only C1 and C2 hydrocarbons. Some practical interpretation methods also use the concentrations of C3 hydrocarbons, and their authors believe that they are liable to bring complementary information that is useful to make the diagnosis more precise. Because the C3 hydrocarbons are very soluble in oil, their concentrations are practically not affected by a possible diffusion into ambient air. Conversely, and because they are very soluble, they are difficult to extract from the oil and the result of the analysis can greatly depend on the extraction method used. Moreover, experience has shown that, in most cases, a satisfactory diagnosis can be made without taking into account these hydrocarbons and for the sake of simplification, they have been omitted from the interpretation methods. result of the analysis can greatly depend on the extraction method used. Moreover, experience has shown that, in most cases, a satisfactory diagnosis can be made without taking into account these hydrocarbons and for the sake of simplification, have been omitted from the interpretation methods.
6.0 DGA INTERPRETATION BASED ON IEEE 57.104 -2019
The DGA status is only one input to the process of determining a transformer’s condition.There is no direct and infallible method using DGA to obtain an exact evaluation of a transformer’s condition. There are several reasons why the DGA status can be very different from the transformer’s true condition, some of which are as follows:
a. There are several possible causes of the presence of gas in a transformer. Some of those are related to fault conditions (e.g., arcing, overheating, PD), others are related to more benign conditions (e.g., stray gassing, contamination, previous fault now inactive, and mild core overheating).
b. Some pre-failure conditions simply do not generate gas. (e.g., mechanical or insulating system weakness).
c. Some normal conditions do generate gases. (e.g., normal aging, and insulating liquid oxidation).
d. The DGA data used to develop this procedure and norms came from in-service transformers for which their condition information (faulty or not) at the time of the DGA was unavailable. Therefore, there was no possibility to directly correlate one with the other, only to evaluate the DGA results distribution assuming most of the data came from healthy transformers.
This guide clearly mentions that “ the methodology presented here will classify the DGA results, not the transformer condition. Users should not equate “DGA status” to “transformer condition.” It could be presumed that one is possibly related to the other, but there can be no guarantee in this respect. Transformers could fail without any prior gas generation, while others could be operating with high levels of gases.” Further this guide classifies DGA results into 3 groups as follows:
• DGA Status 1: Low gas levels and no indication of gassing. (Unexceptional DGA)
• DGA Status 2: Intermediate gas levels and/or possible gassing. (Possibly suspicious DGA)
• DGA Status 3: High gas levels and/or probable active gassing. (Probably suspicious DGA)
After data quality and confirmation issues have been addressed, interpretation of the DGA data can be undertaken. Prior DGA results should be used for characterization of increments and rates. If abnormal DGA results are found, any available supplementary information, such as test and maintenance records, load data, environmental conditions, etc., should be consulted for possible clues as to the origin and nature of the abnormalities. Comparison of DGA data from sister units, i.e., transformers built to similar specifications, is useful for spotting unusual results and for revealing common patterns, which may provide a better understanding of the data. Figure 8 is a flow chart that provides a suggested process to review the DGA results.
The following procedure explains the Figure 8 flowchart :
1. Compute the O2/N2 ratio. Compute the absolute variation [delta μL/L (ppm)] for each gas from the previous routine sample.
2. Update multipoint rate values using the last 3 to 6 data points over the last 4 to 24 months period, if available. If more than 6 data points are available, use the six most recent data points, not exceeding two years, to compute the rates.
3. If age is known, compare all gas values to the applicable column of Table 7, according to the O2/N2 ratio and age. If age is unknown, use the values in the column “Unknown” (under “Transformer age year header) of the applicable table. If the O2/N2 ratio is not available, the O2/N2 ratio >0.2 section should be used.
4. If all gas levels are below the applicable values in Table 7, compare the delta values to the applicable sections of Table 9. Compare rate values to the applicable sections of Table 10, if available.
5. If all gas delta values are below the applicable section of Table 7, and all rates values are below the applicable section of Table 10 (if available), then a DGA status of 1 is indicated. Continue routine sampling as per company policy.
6. If any delta is greater than the value in the applicable sections of Table 7, or any calculated generation rate is greater than the applicable sections of Table 10, perform a confirmation DGA within a month .
7. Compute the absolute variation (delta) between the reference sample and the confirmation sample. Compute rates with the confirmation sample replacing the previous value. If the confirmation sample does not indicate an increase from the previous sample (i.e., all gas variations delta are below the applicable section of Table 9 and all rates.below the applicable section of Table 10 norms), and all gas level values are also still below the applicable section of Table 7, DGA status is 1. Continue routine sampling per the company policy
8. If the second sample confirms an increase (Delta) has occurred but all gas level values are below the applicable section of Table
7 and all multi-point rates are below the applicable section of Table 10 values, then a DGA status of 2 is indicated.
9. If any one gas level is between the values in the applicable sections of Table 7 and Table
8 with no gas levels above the applicable sections of Table 8, and all multi-point rates are below the applicable section of Table 10, then a DGA status of 2 is indicated.
10. If only 1 sample per year is taken, there will not be enough samples to calculate the multipoint gas generation rates for comparison to Table 10, so only Table 9 would be used in such cases. If Table 9 values are exceeded, a confirmation sample is required, which will allow the computation of the rates (e.g., 3 samples in 2 years).
11. If any one gas level is above the applicable section of Table 8, or if any rate is above the applicable section of Table 10, a DGA status of 3 is indicated.
12. For DGA in status 3, gas evolution should be monitored for a significant period of time. If during that period of time there is no significant positive rate observed, then a lower DGA status could be considered, after consultation with a DGA expert.
13. For extremely high concentrations, deltas, or rates, consult a DGA expert.
It is also recognized that all faults are not of the same concern, so the type of fault should also be considered, not just the gas levels or the gas evolution. As DGA interpretation is still more of an art than a science, the consultation of a transformer expert with DGA interpretation experience is strongly encouraged.
6.1 ADDITIONAL SUB-TYPES OF FAULTS
The additional sub-types of faults indicated in this guide are:
a. Stray gassing of mineral oil (S) at temperatures < 200 °C (in mineral oil only), because of the chemical instability of mineral oils produced by some modern refining techniques. It could also occur due to incompatibility between materials (e.g., such as some metal pasivators).
b. Overheating (O) of paper or mineral oil < 250 °C (therefore without carbonization of paper and loss of its electrical insulating properties).
c. Possible carbonization of paper (C).
d. Thermal faults T3 in mineral oil only (no paper involved) (T3-H) .
e. Catalytic reactions (R) between water and galvanized steel in oil sampling valves of transformers or with tank stell (rust) (R faults are very rare)
6.2 DUVAL TRIANGLES 4 AND 5 METHODS
Duval Triangles 4 and 5 are built and used in the same manner but use different gases and zones. Duval Triangle 4 uses H2, CH4 and C2H6 and Duval Triangle 5 uses CH4, C2H4 and C2H6.Duval Triangles 4 and 5 can be utilized to obtain more information about sub-types of thermal faults. When low energy or low temperature faults are identified using the Duval Triangle 1 (PD, T1 or T2), more information can be obtained with Duval Triangle 4. Numerical values for fault zone boundaries of Duval Triangle 4 method are the following, expressed in %H2, %CH4 and %C2H6. Numerical values for fault zone boundaries of Duval Triangle 5 method are the following, expressed in %CH4, %C2H4 and %C2H6
The Triangle 5 method allows a user to distinguish between high temperature faults T3/T2 in mineral oil only, of lesser concern in transformers, and potentially more dangerous faults C involving possible carbonization of paper.
Note that:
a. Triangles 4 and 5 should never be used for faults identified first with Triangle 1 as electrical faults D1 or D2.
b. Triangle 4 should be used only in case of faults identified first as faults PD, T1 or T2 in Triangle 1.
c. Triangle 5 should be used only in case of faults identified first as faults T2 or T3 in Triangle 1.
d. DGA points occurring in zones C indicate a possibility of carbonization of paper, not a 100% certainty, and further investigations with carbon oxides and furans should be undertaken.
e. The procedure for calculating and displaying DGA points in Duval Triangles 4 and 5 is the same as for Triangle 1.
6.4 Duval Pentagon 2 Method The Pentagon 2 method allows for detection of the 3 basic types of electrical faults (PD, D1 and D2) as in Duval Pentagon 1, and to further distinguish between the 4 additional sub-types of thermal faults of S, O, C and T3 in mineral oil only. In Duval Pentagon 2, faults T3 in mineral oil only are indicated as T3-H, where H is for “Huile” or “oil” in French. NOTE—DGA points occurring in zone C indicate a possibility of carbonization of paper, not a 100% certainty, and further investigations with carbon oxides and furans should be undertaken. If thermal faults (T1, T2, and T3) have been identified with Duval Pentagon 1, more information an be obtained on these faults with Duval Pentagon 2, as in the case of Duval Triangles 4 and 5. The Duval Pentagon 1 & 2 method is illustrated in
6.5 Mixtures of faults
Duval Triangles 1, 4, 5 and Pentagons 1, 2 methods, as well as all other diagnosis methods (Key Gas, Rogers Ratios, Doernenburg Ratios), were initially developed for detecting single faults only. However, multiple faults (mixtures of faults) often occur rather than single faults and may be more difficult to identify with certainty. For instance, actual mixtures of faults T3+D1 may sometimes appear in terms of gas formation as faults D2 in Triangle 1, Pentagon 1, and other diagnosis methods (Rogers Ratios, etc.), while actual mixtures of faults T3 in mineral oil (T3-H) and O may appear as faults C in Triangle 5 and Pentagon 2. Mixtures of faults may be suspected when fault identifications provided by Duval Triangles 1, 4, and 5 and Pentagons 1 and 2 for the same DGA results are different. This is because each graphical representation is more sensitive to some gases and some faults than to others. For example, Triangle 4 and the Pentagons are more sensitive to H2 and faults S and PD, while Triangle 1 and Triangle 5 are more sensitive to C2H4 and faults T3. If the position of the DGA point changes with time in the Triangles and the Pentagons, this indicates that a new fault has formed over the old one or another source of gas formation (a different type of fault has become active) exists. To get a better identification of this new fault, gas concentrations from the previous DGA results may be subtracted from the most recent ones. The subtracted (delta) values will thus be due only to the new fault. If delta values are negative for some gases, this means that no additional amounts (zero μL/L) of these gases have been formed because of the new fault since the previous sample, and that some of those gases previously formed have started to escape from the transformer. When identifying the new fault, negative delta values should, therefore, be replaced by zero μL/L. The possible presence of multiple faults may be useful information during the inspection of transformers.
6.6 When to use the Duval Pentagons and Triangles
If interest is only in the six basic types of faults, the display of DGA points would be done using the Pentagon 1 or Triangle 1. If there is also an interest in the additional subtypes of faults as discussed Pentagon 2 and Triangles 4 or 5 should be used. When detection of mixtures of faults is desired, the diagnosis provided by the pentagons and the triangles can be compared. If they do not agree, this may be an indication of multiple faults. Use subtracted (delta) values as discussed above to further identify these multiple faults.
7.0 CONCLUSION
Dissolved gas analysis (DGA) is the identification, measurement, and interpretation of the gases dissolved in the insulating liquid. Whenever a transformer undergoes abnormal thermal and electrical stresses, certain gases are produced due to the decomposition of the transformer oil. The DGA diagnostic tools that have been discussed are considered to be the main interpretation methods used for fault diagnosis of power transformers. This includes the Key Gas, Dornenburg Ratio, Rogers Ratio, IEC Basic Gas Ratio, Duval Triangle, and key gases methods. The majority of these methods are ratio-based, meaning they use a subset of the ratios below to diagnose a fault type based on the fit of each ratio result to a specific range of values:
• Ratio 1 (R1) = CH4/H2
• Ratio 2 (R2) = C2H2/C2H4
• Ratio 3 (R3) = C2H2/CH4
• Ratio 4 (R4) = C2H6/C2H2
• Ratio 5 (R5) = C2H4/C2H6
It is important to remember that when using ratio-based diagnostic tools, minimum gas levels are required as defined in the guides, for the ratio analysis to be considered valid. The other methods based on IEEE C57.104.2019 have been discussed which are quite different from previous version. If interest is only in the six basic types of faults, the display of DGA points would be done using the Pentagon 1 or Triangle 1.If there is also an interest in the additional sub-types of faults as discussed Pentagon 2 and Triangles 4 or 5 should be used.
The key objective in DGA of fault gases is to correctly diagnose the fault that is potentially generated. Some diagnostic tools have the ability to perform better than others, so it’s important to review the most recent information when incorporating them into DGA procedures.
"AUTHOR- Dr. RAJESH KUMAR ARORA obtained the B. Tech. & Master of Engineering (ME) degrees in Electrical Engineering from Delhi College of Engineering, University of Delhi, India in 1999 and 2003 respectively. He completed his PhD in grounding system design from UPES, Dehradun. He is also certified Energy Manager and Auditor and has worked in 400kV and 220kV Substation for more than 14 years in Delhi Transco Limited (DTL). He has also worked as Deputy Director (Transmission and Distribution) in Delhi Electricity Regulatory Commission (DERC) for 03 years and 06 months. He has also given his contribution in the OS department of DTL for more than 2 years and rendered his services in the SLDC of Delhi Transco Limited (DTL) also. Presently he is working in D&E (Design and Engineering) department of DTL. His research interests include high voltage technology, grounding system, protection system, computer application and power distribution automation."
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