DGA Review

Serveron White Paper: DGA Diagnostic Methods

The purpose of this white paper is to provide insight and guidance on Dissolved Gas Analysis (DGA) diagnostic methods. Much progress has been made in the last decade in understanding the relationships of gases in transformer insulating oil and diagnostic outcomes have become more accurate. Yet field practice doesn’t always reflect the newer insights.

Transformer Fleet Reliability Reliable energy flow is paramount and power transformers are critical, and costly, assets in the grid. As an asset class, power transformers constitute one of the largest investments in a utility’s system. For this reason transformer condition assessment and management is a high priority. In several parts of the world the transformer fleet is operating beyond its design life and with higher average loads than ever before. Some statistics on the North American power transformer fleet follow:

• The average age of power transformers is >42 years and increasing 0.6 years per year [1]

• Transformer failure rates, both catastrophic and non-catastrophic, continue to increase [2]

Funding the cost to replace enough power transformers to reduce or flatten the growth of the average age is not an alternative for most utilities. This situation demands the best asset management and condition assessment approaches available to garner the most value from the existing fleet while maintaining reliability to ever increasing standards. DGA of transformer insulating oil is considered the single best indicator of a transformer’s overall condition and is practiced universally today. However, interpretation of DGA data through the use of DGA diagnostic tools is not always “state of the art”. There are several reasons for this and among them are:

• DGA interpretation expertise is leaving utilities through retirements • Modern DGA diagnostic tools require a variety of gas ratios to be calculated and,

in urgent situations, the time and personnel may not be available to do so • There is a perception that “shortcut” diagnostic methods yield results as good as

the more complex methods • Older, less capable, diagnostic methods became part of standard operating

procedure (SOP) and are less likely to be changed due to the effort needed to change an SOP

The use of appropriate DGA diagnostic methods can improve the conclusions from the DGA process which results in improved service reliability, avoidance of transformer failure and deferred capital expenditures for new transformer assets.

© 2007 Serveron Corporation. All rights reserved. Printed in USA. PN 880-0129-00 Rev. B 1

DGA Diagnostic Tools Most of the DGA diagnostic tools in use today can be found in the IEEE C57.104 or IEC 60599 guides as well as other national or international guides based on these two. There are some additional tools available in the other guides but this document will deal only with those found in the IEEE and IEC guides. This paper assumes that all transformer owners have developed, as a first step in DGA diagnosis, normal, caution and warning levels as well as rates of change levels for each of the diagnostic gases, using the guides as a reference. Having ppm levels and rates of change identified is necessary but not sufficient for a proper DGA diagnostic process. This paper will deal with the next step in diagnosis, successfully applying ratio-based diagnostic tools. As can be seen in Table 1, all fault types are indicated by a variety of gases, not just one. Therefore diagnostic approaches that address multiple gases take into account the total gassing picture and offer the best diagnostic accuracy.

Table 1


The IEEE and IEC guides offer a variety of ratio-based tools to diagnose DGA data. Each guide has a somewhat different list and, in some cases, different conclusions about results from the same diagnostic tools. A quick summary of the different tools found in the current IEEE guide as well as a recent draft standard (IEEE C57.104-D11d; not approved) of the IEEE guide and the IEC guide is in Table 2: Table 2

ToolReference Standard

IEEE C57. 104-1991

IEEE PC57. 104 D11d

IEC 60599-1999

Individual & TDCG guidelines

Doernenburg Ratios

Rogers Ratios

Basic Gas Ratios

Key Gas Procedure

TCG Procedure

TDCG Procedure

Duval Triangle

CO2/CO Ratio

O2/N2 Ratio

C2H2/H2 Ratio

ToolReference Standard

IEEE C57. 104-1991

IEEE PC57. 104 D11d

IEC 60599-1999

Individual & TDCG guidelines

Doernenburg Ratios

Rogers Ratios

Basic Gas Ratios

Key Gas Procedure

TCG Procedure

TDCG Procedure

Duval Triangle

CO2/CO Ratio

O2/N2 Ratio

C2H2/H2 Ratio

DGA diagnostic tools vary in their complexity and accuracy. Some are simple sums or single ratios of gases with a guideline for normal, caution and warning levels while others consist of multiple ratios with diagnosis based on the fit of each ratio result to a specific range of values. Let’s review the available tools and determine their appropriateness. DGA Diagnostic Tool Selection There is a class of tools that are non-ratio based. These are the Total Combustible Gas (TCG) and Total Dissolved Combustible Gas (TDCG) procedures. These tools can be found in the IEEE guide and come from North America’s history of gas analysis in mines where total combustible gas was a significant measure. They are less instructive in transformers in that they offer no diagnostic value regarding fault type but do offer utility as an indication that gas levels are increasing – generally a bad trend in any transformer. The TCG are the gases in the gas headspace and TDCG are those dissolved in oil. These procedures are recommended by the IEEE guide to be combined with other diagnostic tools to get a better understanding of what is happening in the transformer. This last point about combining with other tools sometimes gets lost in practice and procedures should be examined to include other tools to insure a robust diagnostic process.


From the TCG and TDCG procedures we can next look at the Key Gas Procedure. This is one of the most frequently used diagnostic tools and, unfortunately, one of the weakest in our arsenal. The combination of frequent use and poor diagnostic capability unite with the result being the source of a significant number of mis-diagnoses in the field. Why is the Key Gas Procedure so frequently used when it is not accurate? Because it is a good “shortcut” or “approximation” technique that can be implemented quickly. Let’s review the elements of the Key Gas Procedure to understand its shortcomings. Key gases are defined in the IEEE guide as “gases generated in oil-filled transformers that can be used for qualitative determination of fault types, based on which gases are typical or predominant at various temperatures.” (We have emphasized qualitative). The Key Gases and their fault indications are summarized in Table 3. Table 3


The IEEE guide Key Gas Method offers diagnosis through calculating the relative proportions (in percent) of these key gases to the rest of the gases in the transformer. The proportions indicate the general fault type and these fault types with their relative proportions of gases (in percent) are identified in Table 4. Table 4

0

20

40

60

80

100

CO H2 CH4 C2H6 C2H4 C2H2

Thermal Oil and Cellulose Fault

0

20

40

60

80

100


Thermal Oil and Cellulose Fault

0

20

40

60

80

100


Thermal Oil Fault

0

20

40

60

80

100


Thermal Oil Fault

0

20

40

60

80

100


High Energy Arcing

0

20

40

60

80

100


High Energy Arcing

0

20

40

60

80

100


Low Energy Partial Discharge

0

20

40

60

80

100


Low Energy Partial Discharge There are a few issues that contribute to the Key Gas Method’s poor diagnostic accuracy:

1. There are only 4 generalized fault types named while other diagnostic methods offer more detailed fault type identification

2. Transformers will typically not exhibit the exact relative proportions of gases outlined by the IEEE guide and users need to make a “judgment call” as to which fault type is being indicated

3. Users frequently mistake the IEEE-defined qualitative nature of this diagnostic to be more absolute as in the nature of a quantitative method

Studies based on the IEC data bank of inspected transformers have shown the Key Gas Method to arrive at an incorrect diagnosis 58% of the time. This is a significant error and suggests that this method should be subordinated or eliminated in favor of more accurate approaches to DGA diagnostics.


The problem gets still larger when a “modified” version of the Key Gas Method is practiced. This version, not found in any guide, nor supported by any empirical evidence, matches the change in a single gas to a general fault type. There are no normal, caution or warning levels defined; only the judgment of the practitioner determines the level of the problem. The method is based on a number of assumptions shown below along with an analysis of the assumptions: Assumption #1: Acetylene in a transformer is caused by an arc; therefore it is

possible to diagnose an arcing condition solely by looking at acetylene.

• Analysis:

This assumption does not enable the practitioner to understand the nature of the arc. Is it a harmless case of sparking partial discharge in oil from a poorly grounded part or, is it the early stages of a dangerous high energy discharge? Could it be acetylene formed in a localized high temperature fault in oil rather than in an electrical arc? Maybe it is the result of communication between the oil of the main tank and LTC tank? None of these questions can be answered without taking the ratio of acetylene to other gases into account. The lack of an accurate diagnosis could mean that either a harmless situation is over-treated (de-energizing, draining and inspecting the tank and finding no evidence, because partial discharges typically cannot be visually identified) or, allowing a serious problem to worsen.

Assumption #2: CO in a transformer indicates overheated cellulose, therefore it is

possible to diagnose cellulose problems solely by looking at CO

• Analysis: Based on the IEC data bank of inspected cases in service when

using the formation of CO only to detect paper involvement in a fault, a wrong diagnosis will be provided in about 65% of cases

Furthermore, increasing amounts of CO in service do not

necessarily mean that there is a fault involving paper. This very much depends on the corresponding amounts of CO2. Indeed, in a large number of cases, CO increases are related to oil oxidation only, as a result of overheating, even in transformers equipped with air-preservation systems, where some oxygen is always present because of leaks in these systems.

CO ppm by itself is not a reliable indicator of localized paper-

insulation damage because: a) the level is usually reduced by dilution in a large quantity of oil, b) the level is affected by oil-temperature (absorption & de-sorption by paper insulation) caused by load and/or ambient-temperature changes and c) its tendency to escape depending upon the type of oil expansion system and how tightly the transformer is sealed.


Assumption #3: Hydrogen indicates partial discharge as well as other faults, therefore it is important to measure hydrogen

• Analysis:

Hydrogen appears in almost all fault conditions (see Table 1) and is therefore an indicator and not a diagnostic gas. It must be combined in a ratio-based analysis with other gases in order to begin to diagnose an incipient fault. Unfortunately, the three gases listed here in the “modified” key gas method do not combine into any meaningful ratios with the exception of a H2/C2H2 ratio indicating LTC communication with the main tank. In fact, when gas ratios are used, methane offers better diagnostic capability than hydrogen. This is because hydrogen is the least soluble gas in oil and also has a high diffusion rate (escapes easily from the transformer or laboratory oil sample) making the exact quantification of hydrogen difficult.

This “modified” key gas approach has not been formally evaluated regarding its accuracy due to the fact that it is an undocumented “de-facto” approach. The documented Key Gas Method offers the worst diagnostic record of any approach evaluated here and the “modified” version has elements in it that would lead us to believe it is inferior even to the Key Gas Method. Further, with the gaining popularity of on-line DGA monitors the pitfalls of this approach using on-line monitors are exacerbated. This is because a monitor with this three gas combination cannot support any diagnostics, as explained above, and would simply offer more frequent mis-diagnoses. Ratio-based Diagnostic Tools The remaining diagnostic tools have a more effective diagnostic accuracy rate. They involve more calculation and therefore aren’t always the first choice. However, these tools can offer superior results and there are now more automated means of calculating these results. Many DGA laboratories today provide some or all of these diagnostic tool results with their reports on the gas data. The ratios that make up the first three methods are listed below. The process for each method uses a subset of these ratios with diagnosis of fault type based on the fit of each ratio result to a specific range of values. One important point to remember when using ratio-based diagnostic tools is that minimum gas levels are required, and are generally defined in the guides, for the ratio analysis to be considered valid. The ratios are as follows: 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


The Doernenburg method found in the IEEE guide utilizes ratios R1 through R4 and the process outlined above. The method has fallen out of favor in some parts of the world due to its complexity as well as the evolution of it into the Rogers and Basic Gas Ratios approaches also found in the current standards. However, when compared with other diagnostic methods, the Doernenburg method still holds value as one of the better diagnostic tools. The Rogers (IEEE) and Basic Gas Ratios (IEC) methods utilize ratios R1, R2 and R5 which are implemented by the process listed above. The Rogers method evolved from the Doernenburg method and the Basic Gas Ratios are an improvement over the Rogers method. The research that led to the changes in each case was to better correlate specific ratio value ranges for fault types with databases of inspected cases of transformer failures. While offering better diagnostic accuracy, one of the weaknesses of the Doernenburg, Rogers and Basic Gas Ratio approaches is that there can be some combinations of gases that, when calculated, do not fit into the specified range of values and a diagnosis of the fault type cannot be given. Diagram 1 below shows a three dimensional view of the IEC Basic Gas Ratio with actual transformer gas data and visually demonstrates blank spaces in the graphic where calculations of gas ratios are plotted moving from an undetermined diagnosis into a fault type area. Diagram 1


The final ratio-based method is the Duval Triangle found in the IEC guide Annex B.3. The Triangle method was developed empirically in the early 1970’s. It is based on the use of 3 gases (CH4, C2H4 and C2H2) corresponding to the increasing energy levels of gas formation. One advantage of this method is that it always provides a diagnosis, with a low percentage of wrong diagnoses. The triangle method plots the relative % of the 3 gases on each side of the triangle, from 0% to 100%. The 6 main zones of faults are indicated in the triangle, plus a DT zone (mixture of thermal and electrical faults). Approximately 200+ inspected cases in service were used to develop the Triangle. An example of the Triangle method is below: If, for example, the DGA results are: CH4 = 100 ppm First calculate: CH4 + C2H4 + C2H2 = 300ppm C2H4 = 100 ppm Then calculate the relative % of each gas: C2H2 = 100 ppm Relative % of CH4 = 100/300 = 33.3 % Relative % of C2H4 = 100/300 = 33.3 %

Relative % of C2H2 = 100/300 = 33.3 % These values are the triangular coordinates to be used on each side of the triangle. To verify that the calculation was done correctly, the sum of these 3 values should always give 100%, and should correspond to only one point in the triangle. Diagram 2 shows a graphical plot of the Duval Triangle utilizing data from an actual transformer with a poorly grounded part. Diagram 2


The accuracy of the main diagnostic methods used has been evaluated [3], using the IEC data bank of inspected transformer failures and other reports [4]. Table 7 shows the results of this effort:

Table 7

% Correct Diagnoses

% Unresolved Diagnoses

% Wrong Diagnoses

IEEE Key Gas Method 42 0 58

IEEE Rogers Ratios 62 33 5

DoernenburgRatios 71 26 3

IEC Basic Gas Ratios 77 15 8

IEC Duval Triangle 96 0 4

% Correct Diagnoses

% Unresolved Diagnoses

% Wrong Diagnoses

IEEE Key Gas Method 42 0 58

IEEE Rogers Ratios 62 33 5

DoernenburgRatios 71 26 3

IEC Basic Gas Ratios 77 15 8

IEC Duval Triangle 96 0 4

Table 7 summarizes many of the main points developed in this paper. There are a variety of diagnostic tools available to the DGA practitioner and it is important to understand which ones to apply and when.


Single Ratio Tools Three other single ratio tools may be used to complement the main diagnosis methods described above. These include the CO2/CO ratio, the O2/N2 ratio and the C2H2/H2 ratio. The CO2/CO Ratio This is a popular ratio used to detect paper involvement in a fault. If the ratio is <3, it is a strong indication of a fault in paper, either a hot spot or electrical arcing of T>200°C. If >10, it indicates a fault of temperature T<150°C. The CO2/CO ratio, however, is not very accurate, because it is also affected by the background of CO2 and CO coming from oil oxidation. The amounts of furans in oil may also be used in some cases to confirm paper involvement; however, the interpretation of results is often difficult. Further, CO2/CO ratios due to normal cellulose aging are highly dependent upon how tightly sealed the transformer is and vary from 10 to >100. With a high quantity of CO2, seeing a significant change in the CO2/CO ratio is close to impossible. However, “incremental” CO2/CO may be helpful in identifying early paper degradation (provided potential temperature effects are considered) as suggested in a 2004 CIGRE paper. [4] Be sure to utilize this ratio in combination with other diagnostic tools that can indicate thermal faults in order to get a more accurate determination if cellulose is involved in a fault. The O2/N2 Ratio A decrease of this ratio indicates excessive heating. Once again, combining this ratio with other diagnostic tools that indicate thermal faults will give you more confidence in your conclusions about thermal faults. The C2H2/H2 Ratio A ratio >2 to 3 in the main tank indicates contamination by the LTC compartment. In these situations the level of acetylene in the main tank can be quite high and in order to diagnose true main tank problems, incremental changes in acetylene must be monitored. On-line monitoring is uniquely suited to viewing incremental changes in gases. On-line DGA and Diagnostic Tools On-line DGA is gaining in popularity worldwide and, because of its frequency and accuracy of measurements, provides the best data set for the ratio-based diagnostic tools. The advent of on-line DGA has enabled the DGA practitioner to go from infrequent snapshots in time of transformer condition to understanding the dynamic behavior of gases over the operating cycles of the transformer. On-line DGA data is delivering new insights previously unavailable. The trending of the diagnostic ratios rather than just the basic gas data is the breakthrough. The value is in rate of change of diagnostic ratio indicators, not in static snapshots. On-line DGA monitors are available now with different combinations and counts of the 8 diagnostic gases. Software and services also accompany these monitors that automate the calculation and display of some of the diagnostic tools.


However, let the buyer beware: To deliver on the new insights, on-line DGA monitors must offer the right combinations of gases measured that support the diagnostic tools you prefer to use. As an example: If the gases measured by the on-line monitor only support a key gas type of approach, (or worse, the “modified” key gas method highlighted earlier) then the promise of trending diagnostic ratios and delivering correct diagnoses is not fulfilled. It would just become a more expensive way to mis-diagnose transformer faults. Summary Progress has been made by the DGA community in developing and refining diagnostic tools. Some tools are proving to perform better than others and DGA practitioners can benefit from reviewing the latest information and incorporating it into their DGA procedures. The imperative for transformer asset managers in the current environment of an aging transformer fleet that needs to perform more reliably than ever under increasing loads: Be as effective as possible in transformer condition assessment through a robust DGA diagnostic program incorporating laboratory as well as on-line DGA approaches.


Bibliography [1] David Woodcock, “Risk-Based Reinvestment – Trends in Upgrading the Aged T&D System”, Energy Pulse, March 12, 2004 [2] William H. Bartley, “Analysis of Transformer Failures”, paper IMIA-WGP 33 (03), International Association of Engineering Insurers, 2003 [3] M.Duval and J.Dukarm, “Improving the Reliability of Transformer Gas-in-Oil Diagnosis”, IEEE Elec.Insul.Mag., Vol.21, No.4, pp. 21-27, 2005. [3] M.Duval and A.dePablo, “Interpretation of Gas-in-Oil Analysis using new IEC Publication 60599 and IEC TC10 Data Bases”, IEEE Elec.Insul.Mag., Vol.17, No.2, pp.31-41, 2001. [4] S. R. Lindgren, “Transformer Condition Assessment Experiences Using Automated On-Line Dissolved gas Analysis”, paper A2-202, CIGRE 2004 Session, 29th August – 3rd September, 2004, Paris, France.

For more information, contact your nearest Serveron Representative or Serveron Corporation.

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