DGA Interpretation

POWER GRID CORPORATION OF INDIA LTD.

�� / DGA INTERPRETATION PROCEDURES

DOC NO: D-2-04-06-01-01, �� / FIRST REVISION

DOC NO: D-2-04-06-01-01, �� / FIRST REVISION Page 1 of 14

1.0 INTRODUCTION

1.1 The transformer undergoes electrical, chemical and thermal stresses during its service life which may result in slow evolving incipient faults inside the transformer. The gases generated under abnormal electrical or thermal stresses are hydrogen(H2), methane(CH4), ethane(C2H6), ethylene(C2H4), acetylene(C2H2), carbon monoxide(CO), carbon dioxide(CO2), nitrogen(N2) and oxygen(O2) which get dissolved in oil. Collectively these gases are known as FAULT GASES, which are routinely detected and quantified at extremely low level, typically in parts per million (ppm) in Dissolved Gas Analysis (DGA). Most commonly method used to determine the content of these gases in oil is using a VACUUM GAS EXTRACTION APPARATUS AND GAS CHROMATOGRAPH as shown in the photographs below:

Photo 1:Gas Chromatograph for DGA (HP 5890 + ) Photo 2:Gas Extraction Apparatus-Varion make

Photo 3:

DGA through Head Space Sampler - AGILENT G

1888 Headspace Sampler & AGILENT 6890 Gas Chromatograph

Separate Gas Extraction Apparatus is not

required in this chromatograph

1.2 DGA is a powerful diagnostic technique for detection of slow evolving faults inside the transformer by analyzing the gases generated during the fault which gets dissolved in the oil. For Dissolved Gas Analysis to be both useful and reliable, it is essential that sample taken for DGA should be representative of lot, no dissolved gas be lost during transportation and laboratory analysis be precise and accurate. Oil sampling procedure





based on IEC 60567 has been standardized in POWERGRID and currently being used by all Sites for oil sampling (given as APPENDIX –X in Doc. No. D-2-03-XX-01-01). Effective fault gas interpretation should basically tell us first of all, whether there is any incipient fault present in the transformer? If there is any problem, what kind of fault it is? Whether the fault is serious and the equipment needs to be taken out of service for further investigation? DGA can identify deteriorating insulation and oil, hot spots, partial discharge, and arcing. The health of oil is reflective of the health of the transformer itself. DGA analysis helps the user to identify the reason for gas formation & materials involved and indicate urgency of corrective action to be taken.

1.3 POWERGRID has constituted DGA Committee having representatives from CC/Engg., CC/OS and two oil laboratories (i.e CIOTL, Hyderabad & IOTL, Durgapur), which does the analysis of DGA data of Transformers and reactors periodically (normally bimonthly) and decides the critical transformer/ reactors on which more attention is to be given through its DGA record notes. The criteria for interpretation of DGA data depends on experience from failed transformers, engineering judgment, transformers with incipient

faults, laboratory simulations and statistical studies� The interpretation of DGA results is

enhanced by including specific information on a particular transformer and its past DGA history. There is no simple “litmus paper “ type of approach with black and white answers for resolving the DGA problems and sometimes it needs to be supplemented

by additional specialized tests like FRA, RVM etc.

2.0 INTERPRETATION METHODS

Many techniques for the detection and the measurement of gases have been established. However, it must be recognized that analysis of these gases and interpretation of their significance is at this time not a science, but an art subject to variability. Their presence and quantity are dependent on equipment variables such as type, location, and temperature of the fault; solubility and degree of saturation of various gases in oil; the type of oil preservation system; the type and rate of oil circulation; the kinds of material in contact with the fault; and finally, variables associated with the sampling and measuring procedures themselves. Because of the variability of acceptable gas limits and the significance of various gases and generation rates, a consensus is difficult to obtain. The principal obstacle in the development of fault interpretation as an exact science is the lack of positive correlation of the fault-identifying gases with faults found in actual transformers.

This guide is, in general, an advisory document. It provides guidance on specific methods and procedures to assist the transformer operator in deciding on the status and continued operation of a transformer that exhibits combustible gas formation. However, operators must be cautioned that, although the physical reasons for gas formation have a firm technical basis, interpretation of that data in terms of the specific cause or causes is not an exact science, but is the result of empirical evidence from which rules for interpretation have been derived. Hence, exact causes or conditions within transformers may not be inferred from the various procedures. The continued application of the rules and limits in this guide, accompanied by actual confirmation of the causes of gas formation, will result in continued refinement and improvement in the correlation of the rules and limits for interpretation.

Following interpretation methods are general guidelines used by DGA committee for the purpose of identifying critical units in POWERGRID:





2.1 Individual Fault Gases Acceptable Limits

To ensure that a transformer (with no measured previous dissolved gas history) is behaving normal, the DGA results are compared with the gassing characteristics exhibited by the majority of similar transformers or normal population. As the transformer ages and gases are generated, the normal levels for 90% of a typical transformer population can be determined. From these values and based on experience, acceptable limits or threshold levels have been determined as given in table 1 below:

Table 1: Ranges of 90% typical concentration values (all Types of Transformers) As per IEC 60599 /1999

Transformer Sub Type

FAULT GASES (in µ l/l)

H2 CH4 C2H6 C2H4 C2H2 CO CO2

No OLTC

Communicating OLTC

60-150

75-150

40-110

35-130

50-90

50-70

60-280

110-250

3-50

80-270

540-900

400-850

5100-13000

5300-12000

NOTE 1- The values listed in this table were obtained from individual networks. Values on other networks may differ.

NOTE 2- “Communicating OLTC” means that some oil and /or gas communication is possible between the OLTC compartment and the main tank or between the respective conservators. These gases may contaminate the oil in the main tank and affect the normal values in these types of equipment.

“NO OLTC” refers to transformers not equipped with an OLTC, or equipped with an OLTC not communicating with or leaking to the main tank.

NOTE 3- In some countries, typical values as low as 0.5µ l/ l for C2H2 and 10 µ l / l for C2H4 have been reported.

2.2 Total Dissolved Combustible Gas (TDCG) limits

The severity of an incipient fault can be further evaluated by the total dissolved combustible gas present. Limits for TDCG are as given in table 2 below. An increasing gas generation rate indicates a problem of increasing severity and therefore we should resort to shorter sampling frequency for close monitoring of fault gases.

Table 2: Action based on TDCG limits (IEEE standard C: 57.104-1991)

TDCG LIMITS, PPM ACTION

< or = 720 Satisfactory operation, Unless individual gas acceptance values are exceeded

721-1920 Normal ageing/ slight decomposition, Trend to be established to see if any evolving incipient fault is present.

1921-4630 Significant decomposition, Immediate action to establish trend to see if fault is progressively becoming worse.

>4630 Substantial decomposition, Gassing rate and cause of gassing should be identified and appropriate corrective action such as removal from service may be taken.

NOTE: TDCG value includes all hydrocarbons, CO & H2 and does not include CO2 which is not a Combustible gas.





2.2.1 The relationship of evolved gas with temperature and type of fault is shown in table 3 & 4:

Table 3: Relationship of evolved gases with temperature

Relationship with temperature

Methane (CH4) > 120° C

Ethane (C2H6 ) > 120° C

Ethylene (C2H4 ) > 150° C

Acetylene (C2H2 ) > 700° C

Table 4: Associated faults with different fault gases

Associated faults with different gases

Oil Overheating : C2H4, C2H6, CH4

Traces of acetylene with smaller quantity of Hydrogen may be evolved

Overheated Cellulose : CO

Large quantity of Carbon-Di-Oxide (CO2) and Carbon Monoxide (CO) are evolved from overheated cellulose. Hydrocarbon gases such as Methane and Ethylene will be formed if the fault involves an oil impregnated structure.

Partial discharge in Oil (Corona): H2, CH4

Ionization of high stressed area where gas / vapour filled voids are present or ‘wet spot’ produces Hydrogen and methane and small quantity of other hydrocarbons like ethane and ethylene. Comparable amounts of carbon mono-oxide and di-oxide may result due to discharges in cellulose.

Arcing in Oil : C2H2, H2

Large amount of Hydrogen and acetylene are produced with minor quantities of methane and ethylene in case of arcing between the leads, lead to coil and high stressed area. Small amounts of carbon mono-oxide and di-oxide may also be formed, if fault involves cellulose.

It is well known that there is no definite DGA interpretation method in the world, which can indicate the exact location and type of the fault. The different interpretation methods only provide guidelines to take an engineering judgment about the equipment. Apart from the DGA results various other factors are taken into consideration such as past history of the transformer, grid condition, loading patterns etc.

2.3 INTERPRETATION TECHNIQUES AS PER STANDARDS

Several well- known methods/criteria (like Rogers ratio, IEC 60599, Dornenberg, Key gas etc.) are being used by utilities to interpret the DGA results, based mostly on the relative concentrations (i.e. ratios) of the constituent gases. These ratios generally give an indication of the existence and nature of a problem. Some of the interpretation methodsused for DGA are discussed here in brief:





2.3.1 IEC 60599 METHOD

This method is applicable only when the fault gas results are ten times the sensitivity limit of the Gas Chromatograph (GC). As per IEC 60567 the sensitivity limit for the GC should be 1 ppm for all the hydrocarbons and 5 ppm for Hydrogen. In this method three ratios viz. C2H2/C2H4, CH4/H2 & C2H4/C2H6 are used for interpretation. Each ratio is assigned a code depending upon the range of values of ratios. These codes in different combinations are then used for diagnosis of type of fault such as PD (D1-low energy or D2-High energy), thermal faults of various temperatures (T1<300°C, 300°C<T 2<700°C & T3>700°C) as given in table 5 below. PD is exhibited by possible X-wax deposition on paper insulation, or of the sparking type, inducing pinhole, carbonized perforations (punctures) in paper, which, however, may not be easy to find; Typical D1 fault is exhibited by larger carbonized perforations through paper (punctures), carbonization of the paper surface (tracking) or carbon particles in oil (as in tap changer diverter operation); discharges of high energy (D2), in oil or/and paper, with power follow-through, evidenced by extensive destruction and carbonization of paper, metal fusion at the discharge extremities, extensive carbonization in oil and, in some cases, tripping of the equipment, confirming the large current follow-through; T1 faults turns paper brown whereas in T2 evidence of carbonization is also seen. In T3 faults, strong evidence of carbonization of the oil, metal coloration (800 °C) or metal fusion (>1 000 °C) is present.

Table 5 : DGA Interpretation Table (Source IEC 60599 – 1999)

Case Characteristic Fault C2H2

C2H4

CH4

H2

C2H4

C2H6

PD Partial discharges NS <0.1 <0.2

D1 Discharges of low energy >1 0.1 – 0.5 >1

D2 Discharges of high energy 0.6 – 2.5 0.1 -1 >2

T1 Thermal fault

T < 300ºC

NS1 >1 but NS

1<1

T2 Thermal fault

300ºC < 1 < 700ºC

<0.1 >1 1-4

T3 Thermal fault <0.2 2 >1 >4

NOTE 1 – In some countries, the ratio C2H2 / C2H6 is used, rather than the ratio CH4 /H2. Also in some countries, slightly different ratio limits are used.

NOTE 2 – The above ratios are significant and should be calculated only if at least one of the gases is at a concentration and a rate of gas increase above typical values.

NOTE 3 – CH4 / H2 <0.2 for partial discharges in instrument transformers. CH4/H2 <0.007 for partial discharges in bushings.

NOTE 4 – Gas decomposition patters similar to partial discharges have been reported as a result of the decomposition of thin oil film between over-heated core laminates at temperatures of 140 ºC and above.

1. NS = Non- significant whatever the value 2. An increasing value of the amount of C2H2 may indicate that the hot spot

temperature is higher than 1000ºC





Table 6: Typical faults in power transformers based on IEC 60599-1999

Type Fault Examples

PD Partial discharges Discharges in gas-filled cavities resulting from incomplete impregnation, high-humidity in paper, Oil super saturation or cavitations, and leading to X-wax formation.

D1 Discharges of low energy

Sparking or arcing between bad connections of different or floating potential, from shielding rings, toroids, adjacent disks or conductors of winding, broken brazing or closed loops in the core.

Discharges between clamping parts, bushing and tank, high voltage and ground within windings, on tank walls.

Tracking in wooden blocks, glue of insulating beam, winding spacers, Breakdown of oil, selector breaking current.

D2 Discharges high energy

Flashover, tracking, or arcing or high local energy or with power follow-through

Short circuits between low voltage and ground, connectors, windings, bushings and tank, copper bus and tank, windings and core, in oil duct, turret. Closed loops between two adjacent conductors around the main magnetic flux, insulated bolts of core, metal rings holding core legs.

T1 Thermal fault t<300 °C

Overloading of the transformer in emergency situations

Blocked item restricting oil flow in windings

Stray flux in damping beams of yokes

T2 Thermal fault

300 °C <t<700 °C

Defective contacts between boiled connections (particularly between aluminium, busbar), gliding contacts, contacts within selector switch (pyrolitic carbon formation), connections from cable and draw-rod of bushings.

Circulating currents between yoke clamps and bolts, clamps and laminations. In ground wiring, defective welds or clamps in magnetic shields.

Abraded insulation between adjacent parallel conductors in windings.

T3 Thermal fault

t>700 °C

Large circulating currents in tank and core

Minor currents in tank walls created by a high uncompensated magnetic field

Shorting links in core steel laminations.

Typical faults detectable through DGA in transformers are given in Table 6 given above.

Please note: 1. X wax formation comes from Paraffinic oils (paraffin based).

2. The last overheating problem in the table says "over 700 °C.” Recent laboratory discoveries have found that acetylene can be produced in trace amounts at 500 °C, which is not reflected in this table. We have several transformers that show trace amounts of acetylene that are probably not active arcing but are the result of high temperature thermal faults as in the example. It may also be the result of one arc, due to a nearby lightning strike or voltage surge.

3. A bad connection at the bottom of a bushing can be confirmed by comparing infrared scans of the top of the bushing with a sister bushing. When loaded, heat from a poor connection at the bottom will migrate to the top of the bushing, which will display a markedly higher temperature. If the top connection is checked and found tight, the problem is probably a bad connection at the bottom of the bushing.





2.3.2 IEEE Method (as per standard C57.104-1991)

2.3.2.1Evaluation of Possible Fault by Key Gas Method:

Characteristic “Key Gases” have been used to identify particular type of fault. Laboratory simulations and comparison of results of DGA tests combined with observations from the tear down of failed transformers have permitted the development of a diagnostic scheme of the characteristic gases generated from thermal and electrical (Corona and arcing) deterioration of electrical insulation. Table 7 given below lists the key gases for the conditions of arcing, corona, overheating in oil and overheating in paper in the order of decreasing severity.

Table 7: Key gases associated with typical fault

Fault type Key gases

Arcing Acetylene (C2H2), Hydrogen (H2)

Corona Hydrogen (H2)

Overheated Oil Ethylene (C2H4), Methane (CH4)

Overheated Cellulose Carbon Mono-oxide (CO) and Dioxide (CO2)

2.3.2.2 Evaluation of Transformer Condition Using Individual and TDCG Concentrations

A four-level criterion has been developed in the Standard IEEE Standard (C57-104) to classify risks to transformers, when there is no previous dissolved gas history, for continued operation at various combustible gas levels. The criterion uses both concentrations for separate gases and the total concentration of all combustible gases.

The four IEEE conditions are defined below, and gas levels are in table 8 following the

definitions.

Condition 1: Total dissolved combustible gas (TDCG) below this level indicates the

transformer is operating satisfactorily. Any individual combustible gas exceeding

specified levels in table 8 should have additional investigation.

Condition 2: TDCG within this range indicates greater than normal combustible gas

level. Any individual combustible gas exceeding specified levels in table 8 should have

additional investigation. A fault may be present. Take DGA samples at least often

enough to calculate the amount of gas generation per day for each gas. (See table 8 for

recommended sampling frequency and actions.)

Condition 3: TDCG within this range indicates a high level of decomposition of

cellulose insulation and/or oil. Any individual combustible gas exceeding specified levels

in table 8 should have additional investigation. A fault or faults are probably present.

Take DGA samples at least often enough to calculate the amount of gas generation per

day for each gas.

Condition 4: TDCG within this range indicates excessive decomposition of cellulose insulation and/or oil. Continued operation could result in failure of the transformer





Table 8—Dissolved Key Gas Concentration Limits in Parts Per Million (ppm)

Status

Hydrogen (H2)

Methane (CH4)

Acetylene (C2 H2)

Ethylene (C2H4)

Ethane (C2H6)

Carbon Monoxide (CO)

Carbon Dioxide (CO2)1 TDCG

Condition 1 100 120 35 50 65 350 2,500 720

Condition 2 101-700 121-400

36-50 51-100 66-100 351-570 2,500-4,000

721-1,920

Condition 3 701-1,800

401-1,000

51-80 101-200 101-150 571-1,400

4,001-10,000

1,921-4,630

Condition 4 >1,800 >1,000 >80 >200 >150 >1,400 >10,000 >4,630

1 CO2 is not included in adding the numbers for TDCG because it is not a combustible gas.

CAUTION:

Transformers generate some combustible gases from normal operation, and condition numbers for dissolved gases given in IEEE C-57-104-1991 (table 8 above) are extremely conservative. Transformers can operate safely with individual gases in Condition 4 with no problems, provided they are stable and gases are not increasing or are increasing very slowly. If TDCG and individual gases are increasing significantly (more than 30 ppm per day [ppm/day]), an active fault is in progress. The transformer should be de-energized when Condition 4 levels are reached.

A sudden increase in key gases and the rate of gas production is more important in evaluating

a transformer than the accumulated amount of gas. One very important consideration is

acetylene (C2H2). Generation of any amount of this gas above a few ppm indicates high-

energy arcing. Trace amounts (a few ppm) can be generated by a very hot thermal fault (500

degrees Celsius (°C) or higher). A onetime arc, caused by a nearby lightning strike or a high

voltage surge, can also generate a small amount of C2H2. If C2H2 is found in the DGA, oil

samples should be taken weekly or even daily to determine if additional C2H2 is being

generated. If no additional acetylene is found and the level is below the IEEE Condition 4, the

transformer may continue in service. However, if acetylene continues to increase, the

transformer has an active high-energy internal arc and should be taken out of service

immediately. Further operation is extremely hazardous and may result in explosive catastrophic

failure of the tank, spreading flaming oil over a large area.

NOTES:

1. Either the highest condition based on individual combustible gas or TDCG can determine the condition (1,2,3, or 4) of the transformer. For example, if the TDCG is between 1,921 ppm and 4,630 ppm, this indicates Condition 3. However, if hydrogen is greater than 1,800 ppm, the transformer is in Condition 4, as shown in table 9.

2. When the table says “determine load dependence,” this means try to find out if the gas generation rate in ppm/day goes up and down with the load. The transformer may be overloaded or have a cooling problem. Take oil samples every time the load changes; if load changes are too frequent, this may not be possible.

3. To get the TDCG generation rate, divide the change in TDCG by the number of days between samples that the transformer has been loaded. Down-days should not be included. The individual gas generation rate in ppm/day is determined by the same method.





Table 9—Actions Based on Dissolved Combustible Gas

Sampling Intervals and Operating Actions for Gas Generation Rates Conditions

TDCG Level or Highest Individual Gas (See table 8)

TDCG Generation Rates (ppm per day) Sampling

Interval Operating Procedures

< 10

Annually: 6 months for EHV Transformer

10-30 Quarterly

Continue normal operation.

Condition 1

<720 ppm of TDCG or highest condition based on individual combustible gas from table 8.

> 30 Monthly

Exercise caution. Analyze individual gases to find cause. Determine load dependence.

< 10 Quarterly

10-30 MonthlyCondition 2

721–1,920 ppm of TDCG or highest condition based on individual combustible gas from table 8. > 30 Monthly

Exercise caution. Analyze individual gases to find cause. Determine load dependence.

< 10 Monthly

10-30 Weekly Condition 3

1,921–4,630 ppm of TDCG or highest condition based on individual combustible gas from table 8. > 30 Weekly

Exercise extreme caution. Analyze individual gases to find cause. Plan outage. Call manufacturer and other consultants for advice.

< 10 Weekly

10-30 Daily

Exercise extreme caution. Analyze individual gases to find cause. Plan outage. Call manufacturer and other consultants for advice.

Condition 4

>4,630 ppm of TDCG or highest condition based on individual combustible gas from table 8.

> 30 Daily

Consider removal from service. Call manufacturer and other consultants for advice.

Table 9 assumes that no previous DGA tests have been made on the transformer or that no recent history exists. If a previous DGA exists, it should be reviewed to determine if the situation is stable (gases are not increasing significantly) or unstable (gases are increasing significantly).

2.3.2.3 Evaluation of Possible Fault Type by Ratio Method

These methods are used to determine the type of fault condition by comparing ratios of characteristic gases generated under incipient fault conditions. The advantages to the ratio methods are that they are quantitative, independent of transformer capacity and can be computer programmed. The disadvantages are that they may not always yield an analysis or may yield an incorrect one. Therefore it is always used in conjunction with other diagnostic methods such as key gas method.





a. The Doernenberg Ratio method is used when prescribed normal levels of gassing are exceeded. It provides a simple scheme for distinguishing between pyrolysis (overheating) and PD (corona and arcing). In this method four ratios viz. CH4/H2, C2H2/C2H4, C2H2/CH4 & C2H6/ C2H2 are used.

Table 10: Ratios for Key Gases – Doernenburg

Ratio 1 (R1) Ratio 2 (R2) Ratio 3 (R3) Ratio 4 (R4) Suggested Fault Diagnosis

CH4/H2 C2H2/C2H4 C2H2/CH4 C2H6/C2H2

1- Thermal Decomposition

>1.0 <0.75 <0.3 >0.4

2-Corona (Low Intensity PD)

<0.1 Not Significant <0.3 >0.4

3-Arcing (High Intensity PD)

>0.1 >0.75 >0.3 <0.4

In Doernenburg’s method for declaring the unit faulty at least one of the gas concentrations (in ppm) for H2, CH4, C2H2 and C2H4 should exceed twice the values from limit L1 (See table 11) and one of the other three should exceed the values for Limit L1. Having established that the unit is faulty, for determining the validity of ratio procedure at least one of the gases in each ratio R1, R2, R3 or R4 should exceed limit L1. Otherwise the unit should be re-sampled and investigated by alternative procedures.

Table 11: Concentrations of Dissolved Gas

Key Gas Concentration L1 (in ppm)

Hydrogen(H2) 100

Methane (CH4) 120

Carbon Monoxide (CO) 350

Acetylene (C2H2) 35

Ethylene(C2H4) 50

Ethane (C2H6) 65

b. The Rogers Ratio method is a more comprehensive scheme using only three ratios viz. CH4/H2, C2H2/C2H4 & C2H4/C2H6, which details temperature ranges for overheating conditions based on Halstead’s research and some distinction of the severity of incipient electrical fault conditions (See Table 12). A normal condition is also listed.





Table 12: Rogers ratio for Key Gases

Case R2

(C2H2/C2H4)

R1

(CH4/H2)

R5

(C2H4/C2H6)

Suggested Fault Diagnosis

0 <0.1 >0.1 <0.1 Unit normal

1 <0.1 <0.1 <0.1 Low-energy density arcing –PD (See Note)

2 0.1-

3.0

0.1-

1.0

>3.0 Arcing – High energy discharge

3 <0.1 >0.1

<1.0

1.0-

3.0

Low temperature thermal

4 <0.1 >1.0 1.0-

3.0

Thermal <700ºC

5 <0.1 >1.0 >3.0 Thermal >700ºC

Note : There will be a tendency for the ratios R2 and R4 to increase to a ratio above 3 as the discharge develops in intensity

IEEE C57.104 - 1991 standard gives an elaborate way of analysing the type of fault using Doernenberg, Rogers’s method and TDCG limits. However it is again emphasized that DGA shall give misleading results unless certain precautions are taken. These are proper sampling procedure, type of sampling bottle, cleanliness of bottle, duration of storage, method of gas extraction, good testing equipment and skilled manpower.

2.4 Trend Analysis

Transformers from same manufacturers and of same type some time exhibit initially specific pattern of gas evolution which subsequently slows down (or plateau’s) is called Fingerprints or Normal characteristics, which are characteristic to the transformer and do not represent an incipient fault condition.

When a possible incipient fault condition is identified for first time, it is advised to determine gassing trend with subsequent analysis giving information such as which gases are currently being generated and rate of generation of these gases. The level of gases generated in subsequent analysis provides a baseline from which future judgment can be made. In the examination of trends, Key gases, TDCG, CO2/CO ratio, rate of gas generation and fingerprints (of normal trends) of particular transformer should also be considered.

The ratio of gas generation is a function of load supplied by the transformers and this information is vital in determining the severity of fault condition and decision of removal of the equipment from service for further investigation. Two methods have been suggested in literatures for assessing the gassing rate:

• Change of concentration of gas in ppm

• Determination of actual amount of gas generated

General guidelines for rate of gas generation in case of removal of transformer from service are 100 ppm/day and 0.1 cub feet (0.003 m3) gas per day .





2.5 Action Recommended Based On Review of DGA for Critical Transformer

All the in-service transformers and reactors in POWERGRID are to be sampled for DGA on 6-monthly basis and DGA data obtained after carrying out DGA is first reviewed at the laboratory. Based on the results obtained, the respective oil laboratory shall decide on the subsequent frequency of sampling. Frequency can also be further revised during the review by DGA Committee. The frequency of sampling is changed (increased or decreased) depending upon the trend of fault gases, rate of gas increase etc. based on various standards in vogue. The various actions those could be decided are as follows:

1. If there is sudden rise in fault gases not in conformity with earlier trend, a confirmatory oil sample is required to be sent to laboratory on urgent basis to confirm the trend.

2. In case of violation of any gas, the frequency may be increased suitably for close monitoring of the equipment.

3. In case of detection of arcing (normally associated with C2H2), severe overheating or partial discharges (D2) etc, a decision regarding internal inspection can be taken.

4. In case of certain old transformers/reactors which are running under full load, a decision to increase the frequency of oil sampling can be taken on case to case basis.

Normally such actions, especially at no. 2, 3 & 4 are to be taken only in consultation with DGA Committee / CC (OS).

DGA Committee gives out recommendations on critical transformers & reactors in the form of DGA Committee Record Notes on which Sites are required to take action. The recommendation for taking out critical unit for further inspection / tests is taken based on various factors such as past history of operation & maintenance, grid condition, special tests, manufacturing details (type/ model) etc. and consultation with manufacturers.

An indicative flow chart is given at fig 1 for step by step action to be taken based on DGA test results giving recommendations:





Fig1: Flow chart for DGA from IEC 60599/ 1999





References/ further reading:

1. Criteria for the interpretation of Data for DGA from transformer-Paul J. Griffin, Electrical insulating oils, ASTME, Philadelphia

2. Dissolved Fault Gas Analysis Data –A practical approach to interpretation of Results- Dr. J.E. Morgan and W. Morse, Morgan Schaffer Corporation Bulletin, MS 25, 1993

3. CIGRE Guide for Life Management Techniques for Power Transformers-20th Jan’03 prepared by CIGRE WG A2.18

4. IEEE Std.62-1995: IEEE Guide for Diagnostic Field testing of Electric Power Apparatus-Part 1: Oil filled Power Transformers, Regulators and Reactors

5. IEC-60599-1999: Mineral oil-impregnated electrical equipment in service-Guide to the interpretation of dissolved and free gases analysis

6. IEEE std. C57.104-1991: IEEE Guide for the Interpretation of Gases Generated in Oil- Immersed Transformers

7. New Guidelines for Furan analysis as well as Dissolved Gas Analysis in Oil-Filled Transformers by A. Mollmann and A. De Pablo, CIGRE 1996 paper: 15/21/33-19

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