TRANSFORMER MAINTENANCE Contd.......................
spectrometer. This chart was used by R.R. Rogers of the Central Electric Generating Board (CEGB) of England to develop the “Rogers Ratio Method” of analyzing transformers (discussed later).
A vertical band at left shows what gases and approximate relative quantities are produced under partial discharge conditions. Note that all the gases are given off, but in much less quantity than hydrogen. It takes only a very low energy event (partial discharge/corona) to cause hydrogen molecules to form from the oil.
Gases are formed inside an oil-filled transformer similar to a petroleum refinery still, in that various gases begin forming at specific temperatures. From the Gas Generation Chart, we can see relative amounts of gas as well as approximate temperatures. Hydrogen and methane begin to form in small amounts around 150 °C. Notice from the chart that beyond maximum points, methane (CH4), ethane and ethylene production goes down as temperature increases. At about 250°C, production of ethane (C2H6) starts. At about 350 °C, production of ethylene (C2H4) begins. Acetylene (C2H2) starts between 500 °C and 700 °C. In the past, the presence of only trace amounts of acetylene (C2H2) was considered to indicate a temperature of at least 700 °C had occurred; however, recent discoveries have led to the conclusion that a thermal fault (hot spot) of 500 °C can produce trace amounts (a few ppm). Larger amounts of acetylene can only be produced above 700 °C by internal arcing. Notice that between 200 °C and 300 °C, the production of methane exceeds hydrogen. Starting about 275 °C and on up, the production of ethane exceeds methane. At about 450°C, hydrogen production exceeds all others until about 750 °C to 800 °C; then more acetylene is produced.
It should be noted that small amounts of H2, CH4, and CO are produced by normal aging. Thermal decomposition of oil-impregnated cellulose produces CO, CO2 , H2, CH4, and O2. Decomposition of cellulose insulation begins at only about 100 °C or less. Therefore, operation of transformers at no more than 90 °C is imperative. Faults will produce internal “hot spots” of far higher temperatures than these, and the resultant gases show up in the DGA.
Table 6 is a chart of “fault types,” parts of which are paraphrased from the International Electrotechnical Commission (IEC 60599) [12]. This chart is not complete. It is impossible to chart every cause and effect due to the extreme complexity of transformers. DGA must be carefully examined with the idea of determining possible faults and possible courses of action. These decisions are based on judgment and experience and are seldom “cut and dried.” Most professional associations agree that there are two basic fault types, thermal and electrical. The first three on the chart are electrical discharges, and the last three are thermal faults.
Ethane and ethylene are sometimes called “hot metal gases.” When these gases are being generated and acetylene is not, the problem found inside the transformer normally involves hot metal. This may include bad contacts on the tap changer or a bad connection somewhere in the circuit, such as a main transformer lead. Stray flux impinging on the tank (such as in Westinghouse 7M series transformers) can cause these “hot metal gases.” A shield has been known to become loose and fall and become ungrounded. Static can then build up and discharge to a grounded surface and produce “hot metal” gases. An unintentional core ground with circulating currents can also produce these gases. There are many other examples.
Notice that both type faults (thermal and electrical) may be occurring at once, and one may cause the other. The associations do not mention magnetic faults; however, magnetic faults (such as stray magnetic flux impinging the steel tank or other magnetic structures) also cause hot spots.
Atmospheric gasses (N2, CO2, and O2) can be very valuable in a DGA in revealing a possible leak. However, as mentioned elsewhere, there are other reasons these gases are found in DGA. Nitrogen may have come from shipping the transformer with N2 inside or from a nitrogen blanket. CO2 and O2 are formed by degradation of cellulose. Be very careful; look at several DGAs, and see if atmospheric gases and possibly moisture levels are increasing. Also look at the transformer carefully if you can find an oil leak. Moisture and atmospheric gases will leak inside when the transformer is off and ambient temperature drops. (See section 4.3 on moisture)
Dissolved gas software. Several companies offer DGA computer software that diagnose transformer problems. These diagnoses must be used with engineering judgment and should never be taken at face value. The software is constantly changing. The Technical Service Center uses “ Transformer Oil Analyst” (TOA) by Delta x Research. This software uses a composite of several current DGA methods. Dissolved gas analysis help is available from the TSC at D-8440 and D8450. Both groups have the above software and experience in diagnosing transformer problems.
One set of rules that TOA uses to generate alarms is based loosely on IEC 60599 (table 6). These rules are also very useful in daily dissolved gas analysis. They are based on L1 limits of IEC 60599 except for acetylene. IEC 60599 gives a range for L1 limits instead of a specific value. TOA uses the average in this range and then gives the user a “heads up” if a generation rate exceeds 10% of L1 limits per month. Acetylene is the exception; IEEE sets an L1 limit of 35 ppm (too high), and IEC sets acetylene range at 3 to 50. TOA picks the lowest number (3 ppm) and sets the generation rate alarm value at 3 ppm per month.
Notes: If one or more gas generation rates are equal to or exceed G1 limits (10% of L1 limits per month), you should begin to pay more attention to this transformer. Reduce the DGA sample interval, reduce loading, plan for future outage, contact the manufacturer etc.
If one or more combustible gas generation rates are equal to or exceed G2 limits (50% of L1 limits per month), this transformer should be considered in critical condition. You may want to reduce sample intervals to monthly or weekly, plan an outage, plan to rebuild or replace the transformer, etc. If an active arc is
Table 6.—TOA L1 Limits and Generation Rate Per Month Alarm Limits
G1 Limits G2 Limits GAS L1 Limits (ppm per month) (ppm per month)
H2 100 10 50
CH4 75 8 38
C 2 H 2 3 3 3
C2H4 75 8 38
C 2 H 6 75 8 38
CO 700 70 350
CO2 7,000 700 3,500
present (C2H2 generation), or if other heat gases are high (above Condition 4 limits in table 4), and G2 limits are exceeded, the transformer should be removed from service.
Table 7 is taken from IEC 60599 of key gases, possible faults, and possible findings. This chart is not all inclusive and should be used with other information. Additional possible faults are listed on following and preceding pages.
Transformers are so complex that it is impossible to put all symptoms and causes into a chart. Several additional transformer problems are listed below; there are many others.
1. Gases are generated by normal operation and aging, mostly H2 and CO with some CH4.
2. Operating transformers at sustained overload will generate combustible gases.
3. Problems with cooling systems, discussed in an earlier section, can cause overheating.
4. A blocked oil duct inside the transformer can cause local overheating, generating gases.
5. An oil directing baffle loose inside the transformer causes mis-direction of cooling oil.
6. Oil circulating pump problems (bearing wear, impeller loose or worn) can cause transformer cooling problems.
7. Oil level is too low; this will not be obvious if the level indicator is inoperative.
8. Sludge in the transformer and cooling system. (See “3. Transformer Cooling Methods.”)
Table 7.—Fault Types
Key Gases Possible Faults Possible Findings
H2, possible trace of CH4 and Partial discharges (corona) Weakened insulation from aging and electrical stress. C2H6. Possible CO.
H2, CH4, (some CO if discharges involve paper insulation). Possible trace amounts of C2 H6.
Low energy discharges (sparking).
(May be static discharges)
Pinhole punctures in paper insulation with carbon and carbon tracking. Possible carbon particles in oil. Possible loose shield, poor grounding of metal objects
H2, CH4, C2 H6, C2H4, and the key gas for arcing C2 H2 will be present perhaps in large amounts. If C2 H2 is being generated, arcing is still going on. CO will be present if paper is being heated.
High energy discharges (arcing) Metal fusion, (poor contacts in tap changer or lead connections). Weakened insulation, from aging and electrical stress. Carbonized oil. Paper destruction if it is in the arc path or overheated. H2, CO. Thermal fault less than 300 °C in an area close to paper
Discoloration of paper insulation. Overloading and or insulation (paper is being cooling problem. Bad heated). connection in leads or tap changer. Stray current path and/or stray magnetic flux.
H2, CO, CH4, C2H6, C2 H4. Thermal fault between 300 °C Paper insulation destroyed. Oil and 700 °C heavily carbonized. All the above gases and acetylene in large amounts.
High energy electrical arcing
700 °C and above.
Same as above with metal discoloration. Arcing may have caused a thermal fault.
9. Circulating stray currents may occur in the core, structure, and/or tank.
10. An unintentional core ground may cause heating by providing a path for stray currents.
11. A hot-spot can be caused by a bad connection in the leads or by a poor contact in the tap changer.
12. A hot-spot may also be caused by discharges of static electrical charges that build up on shields or core and structures which are not properly grounded.
13. Hot-spots may be caused by electrical arcing between windings and ground, between windings of different potential, or in areas of different potential on the same winding, due to deteriorated or damaged insulation.
14. Windings and insulation can be damaged by faults downstream (through faults), causing large current surges through the windings. Through faults cause extreme magnetic and physical forces that can distort and loosen windings and wedges. The result may be arcing in the transformer, beginning at the time of the fault, or the insulation may be weakened and arcing develop later.
15. Insulation can also be damaged by a voltage surge such as a nearby lightning strike or switching surge or closing out of step, which may result in immediate arcing or arcing that develops later.
16. Insulation may be deteriorated from age and simply worn out. Clearances and dielectric strength are reduced, allowing partial discharges and arcing to develop. This can also reduce physical strength allowing wedging and windings to move extensively during a through-fault, causing total mechanical and electrical failure.
17. High noise level (hum due to loose windings) can generate gas due to heat from friction. Compare the noise to sister transformers, if possible. Sound level meters are available at the TSC for diagnostic comparison and to establish baseline noise levels for future comparison.
Temperature. Gas production rates increase exponentially with temperature, and directly with volume of oil and paper insulation at high enough temperature to produce gases [11]. Temperature decreases as distance from the fault increases. Temperature at the fault center is highest, and oil and paper here will produce the most gas. As distance increases from the fault (hot spot), tempera ture goes down and the rate of gas generation also goes down. Because of the volume effect, a large heated volume of oil and paper will produce the same amount of gas as a smaller volume at a higher temperature [11]. We cannot tell the difference by looking at the DGA. This is one reason that interpreting DGAs is not an exact science.
Gas Mixing. Concentration of gases in close proximity to an active fault will be higher than in the DGA oil sample. As distance increases from a fault, gas concentrations decrease. Equal mixing of dissolved gases in the total volume of oil depends on time and oil circulation. If there are no pumps to force oil through radiators, complete mixing of gases in the total oil volume takes longer. With pumping and normal loading, complete mixing equilibrium should be reached within 24 hours and will have little effect on DGA if an oil sample is taken 24 hours or more after a problem begins.
Gas Solubility. Solubilities of gases in oil vary with temperature and pressure [13]. Solubility of all transformer gases vary proportionally up and down with pressure. Variation of solubilities with temperature is much more complex. Solubilities of hydrogen, nitrogen, carbon monoxide, and oxygen go up and down proportionally with temperature. Solubilities of carbon dioxide, acetylene, ethylene, and ethane are reversed and vary inversely with temperature changes. As temperature rises, solubilities of these gases go down; and as temperature falls, their solubilities increase. Methane solubility remains almost constant with temperature changes. Table 7 is accurate only at standard temperature and pressure (STP), (25 °C/77 °F) and (14.7 psi/29.93 inches of mercury, which is standard barometric pressure at sea level). Table 8 shows only relative differences in how gases dissolve in transformer oil.
From the solubility table 8 below, comparing hydrogen with a solubility of 7% and acetylene with solubility of 400%, you can see that transformer oil has a much greater capacity for dissolving acetylene. However, 7% hydrogen by volume represents 70,000 ppm, and 400% acetylene represents 4,000,000 ppm. You will probably never see a DGA with numbers this high. Nitrogen can approach maximum level if there is a pressurized nitrogen blanket above the oil. Table 8 shows the maximum amount of each gas that the oil is capable of dissolving at standard temperature and pressure. At these levels, the oil is said to be saturated.
Table 8.—Dissolved Gas Solubility in Transformer Oil Accurate Only at STP, 25 °C (77 °F) and 14.7 psi (29.93 inches of mercury)
Dissolved Gas Formula
Solubility in Transformer Oil (% by Volume)
Equivalent (ppm by Volume) Primary Causes/Sources
Hydrogen1 H2 7.0 70,000 Partial discharge, corona, electrolysis of H2O
Nitrogen N2 8.6 86,000 Inert gas blanket, atmosphere
Carbon Monoxide1 CO 9.0 90,000 Overheated cellulose, air pollution
Oxygen O2 16.0 160,000 Atmosphere
Methane1 CH4 30.0 300,000 Overheated oil
Carbon Dioxide CO2 120.0 1,200,00
Overheated cellulose, atmosphere
Ethane1 C2H6 280.0 2,800,00 Overheated oil
Ethylene1 C2H4 280.0 2,800,000 Very overheated oil
Acetylene1 C2H2 400.0 4,000,000 Arcing in oil
1 Denotes combustible gas. Overheating can be caused both by high temperatures and by unusual or abnormal electrical stress.
If you have conservator-type transformers and nitrogen, oxygen, and CO2 are increasing, there is a good possibility the tank has a leak, or the oil may have been poorly processed. Check the diaphragm or bladder for leaks (section 4.2), and check for oily residue around the pressure relief device and other gasketed openings. There should be fairly low nitrogen and especially low oxygen in a conservator-type transformer. However, if the transformer was shipped new with pressurized nitrogen inside and has not been degassed properly, there may be high nitrogen content in the DGA, but the nitrogen level should not be increasing after the transformer has been in service for a few years. When oil is being installed in a new transformer, a vacuum is placed on the tank which pulls out nitrogen and pulls in the oil. Oil is free to absorb nitrogen at the oil/gas interface, and some nitrogen may be trapped in the windings, paper insulation, and structure. In this case, nitrogen may be fairly high in the DGAs. However, oxygen should be very low, and nitrogen should not be increasing. It is important to take an oil sample early in the transformer’s service life to establish a baseline DGA; then take samples at least annually. The nitrogen and oxygen can be compared with earlier DGAs; and if they increase, it is a good indication of a leak. If the transformer oil has ever been de gassed, nitrogen and oxygen should be low in the DGA. It is extremely important to keep accurate records over a transformer’s life; when a problem occurs, recorded information helps greatly in troubleshooting.
4.4.5 Rogers Ratio Method of DGA. Rogers Ratio Method of DGA [18] is an additional tool that may be used to look at dissolved gases in transformer oil. Rogers Ratio Method compares quantities of different key gases by dividing one into the other. This gives a ratio of the amount of one key gas to another. By looking at the Gas Generation Chart (figure 18), you can see that, at certain temperatures, one gas will be generated more than another gas. Rogers used these relationships and determined that if a certain ratio existed, then a specific temperature had been reached. By comparing a large number of transformers with similar gas ratios and data found when the transformers were examined, Rogers could then say that certain faults were present. Like the Key Gas Analysis above, this method is not a “sure thing” and is only an additional tool to use in analyzing transformer problems. Rogers Ratio Method, using three-key gas ratios, is based on earlier work by Doerneburg, who used five-key gas ratios. Ratio methods are only valid if a significant amount of the gases used in the ratio is present. A good rule is: Never make a decision based only on a ratio if either of the two gases used in a ratio is less than 10 times the amount the gas chromatograph can detect (12). (Ten times the individual gas detection limits are shown in table 9 and below.) This rule makes sure that instrument inaccuracies have little effect on the ratios. If either of the gases are lower than 10 times the detection limit, you most likely do not have the particular problem that this ratio deals with anyway. If the gases are not at least 10 times these limits, this does not mean you cannot use the Rogers Ratios; it means that the results are not as certain as if the gases were at least at these levels. This is another reminder that DGAs are not an exact science and there is no “one best easy way” to analyze transformer problems. Approximate detection limits are as follows, depending on the lab and equipment:
Dissolved Gas Analysis Detection Limits.
Hydrogen (H2) about 5 ppm Methane (CH4) about 1 ppm Acetylene (C2H2) about 1 to 2 ppm Ethylene (C2H4) about 1 ppm Ethane (C2H6) about 1 ppm Carbon monoxide (CO) and carbon cioxide (CO2) about 25 ppm Oxygen (O2 ) and nitrogen (N2) about 50 ppm
When a fault occurs inside a transformer, there is no problem with minium gas amounts at which the ratio are valid. There will be more than enough gas present.
If a transformer has been operating normally for some time and a DGA shows a sudden increase in the amount of gas, the first thing to do is take a second sample to verify there is a problem. Oil samples are easily contaminated during sampling or at the lab. If the next DGA shows gases to be more in line with prior DGAs, the earlier oil sample was contaminated, and there is no further cause for concern. If the second sample also shows increases in gases, the problem is real. To apply Ratio Methods, it helps to subtract gases that were present prior to sudden gas increases. This takes out gases that have been generated up to this point due to normal aging and from prior problems. This is especially true for ratios using H 2 and the cellulose insulation gases CO and CO2 [12]. These are generated by normal aging.
Rogers Ratio Method Uses the Following Three Ratios.
C2H2/C2H4, CH4/H2, C2H4/C2H6
These ratios and the resultant fault indications are based on large numbers of DGAs and transformer failures and what was discovered after the failures.
There are other ratio methods, but only the Rogers Ratio Method will be discussed since it is the one most commonly used. The method description is paraphrased from Rogers’ original paper [18] and from IEC 60599 [12].
Caution: Rogers Ratio Method is for fault analyzing, not for fault detection. You must have already decided that you have a problem from the total amount of gas (using IEEE limits) or increased gas generation rates. Rogers Ratios will only give you an indication of what the problem is; it cannot tell you whether or not you have a problem. If you already suspect a problem based on total combustible gas levels or increased rate-of-generation, then you will normally already have enough gas for this method to work. A good system to determine whether you have a problem is to use table 5 in the Key Gas Method. If two or more of the key gases are in condition two and the gas generation is at least 10% per month of the L1 limit, you have a problem. Also, for the diagnosis to be valid, gases used in ratios should be at least 10 times the detection limits given earlier. The more gas you have, the more likely the Rogers Ratio Method will give a valid diagnosis. The reverse is also true; the less gas you have, the less likely the diagnosis will be valid. If a gas used in the denominator of any ratio is zero, or is shown in the DGA as not detected (ND), use the detection limit of that particular gas as the denominator. This gives a reasonable ratio to use in diagnostic table 9. Zero codes mean that you do not have a problem in this area.
Table 9.—Rogers Ratios for Key Gases
Code range of ratios C2H2 CH4 C2H4 Detection limits and 10 x detection limits are shown below: C2H4 H2 C2H6 C2H2 1 ppm 10 ppm C2H4 1 ppm 10 ppm CH4 1 ppm 10 ppm<0.1 0 1 0 0.1-1 1 0 0 H2 5 ppm 50 ppm 1-3 1 2 1 C2H6 1 ppm 10 ppm >3 2 2 2
Case Fault Type Problems Found
0 No fault 0 0 0 Normal aging
1 Low energy partial 1 1 0 Electric discharges in bubbles, caused by insulation voids or super discharge gas saturation in oil or cavitation (from pumps) or high moisture in oil (water vapor bubbles).
2 High energy 1 1 0 Same as above but leading to tracking or perforation of solid partial discharge cellulose insulation by sparking, or arcing; this generally produces CO and CO2.
3 Low energy 1-2 0 1-2 Continuous sparking in oil between bad connections of different discharges, potential or to floating potential (poorly grounded shield etc); sparking, arcing breakdown of oil dielectric between solid insulation materials.
4 High energy discharges, arcing
1 0 2 Discharges (arcing ) with power follow through; arcing breakdown of oil between windings or coils, or between coils and ground, or load tap changer arcing across the contacts during switching with the oil leaking into the main tank.
5 Thermal fault less 0 0 1 Insulated conductor overheating; this generally produces CO and than 150 °C CO2 because this type of fault generally involves cellulose (see note 2) insulation.
6 Thermal fault temp. range 150-300 °C (see note 3)
0 2 0 Spot overheating in the core due to flux concentrations. Items below are in order of increasing temperatures of hot spots. Small hot spots in core. Shorted laminations in core. Overheating of copper conductor from eddy currents. Bad connection on winding to incoming lead, or bad contacts on load or no-load tap changer. Circulating currents in core; this could be an extra core ground, (circulating currents in the tank and core); this could also mean stray flux in the tank.
These problems may involve cellulose insulation which will produce CO and CO2.
7 Thermal fault temp. range 300-700 °C
8 Thermal fault temp. range over 700 °C (see note 4)
Notes: 1. There will be a tendency for ratio C2H2 /C2H4 to rise from 0.1 to above 3 and the ratio C2H4 /C2H6 to rise from 1-3 to above 3 as the spark increases in intensity. The code at the beginning stage will then be 1 0 1. 2. These gases come mainly from the decomposition of the cellulose which explains the zeros in this code. 3. This fault condition is normally indicated by increasing gas concentrations. CH4 /H2 is normally about 1, the actual value above or below 1, is dependent on many factors such as the oil preservation system (conservator, N2 blanket, etc.), the oil temperature, and oil quality. 4. Increasing values of C2H2 (more than trace amounts), generally indicates a hot spot higher than 700 °C. This generally indicates arcing in the transformer. If acetylene is increasing and especially if the generation rate is increasing, the transformer should be de- energized, further operation is extremely hazardous.
General Remarks:
1. Values quoted for ratios should be regarded as typical (not absolute). This means that the ratio numbers are not “carved in stone”; there may be transformers with the same problems whose ratio numbers fall outside the ratios shown at the top of the table.
2. Combinations of ratios not included in the above codes may occur in the field. If this occurs, the Rogers Ratio Method will not work for analyzing these cases.
3. Transformers with on-load tap changers may indicate faults of code type 2 0 2 or 1 0 2 depending on the amount of oil interchange between the tap changer tank and the main tank.
spectrometer. This chart was used by R.R. Rogers of the Central Electric Generating Board (CEGB) of England to develop the “Rogers Ratio Method” of analyzing transformers (discussed later).
A vertical band at left shows what gases and approximate relative quantities are produced under partial discharge conditions. Note that all the gases are given off, but in much less quantity than hydrogen. It takes only a very low energy event (partial discharge/corona) to cause hydrogen molecules to form from the oil.
Gases are formed inside an oil-filled transformer similar to a petroleum refinery still, in that various gases begin forming at specific temperatures. From the Gas Generation Chart, we can see relative amounts of gas as well as approximate temperatures. Hydrogen and methane begin to form in small amounts around 150 °C. Notice from the chart that beyond maximum points, methane (CH4), ethane and ethylene production goes down as temperature increases. At about 250°C, production of ethane (C2H6) starts. At about 350 °C, production of ethylene (C2H4) begins. Acetylene (C2H2) starts between 500 °C and 700 °C. In the past, the presence of only trace amounts of acetylene (C2H2) was considered to indicate a temperature of at least 700 °C had occurred; however, recent discoveries have led to the conclusion that a thermal fault (hot spot) of 500 °C can produce trace amounts (a few ppm). Larger amounts of acetylene can only be produced above 700 °C by internal arcing. Notice that between 200 °C and 300 °C, the production of methane exceeds hydrogen. Starting about 275 °C and on up, the production of ethane exceeds methane. At about 450°C, hydrogen production exceeds all others until about 750 °C to 800 °C; then more acetylene is produced.
It should be noted that small amounts of H2, CH4, and CO are produced by normal aging. Thermal decomposition of oil-impregnated cellulose produces CO, CO2 , H2, CH4, and O2. Decomposition of cellulose insulation begins at only about 100 °C or less. Therefore, operation of transformers at no more than 90 °C is imperative. Faults will produce internal “hot spots” of far higher temperatures than these, and the resultant gases show up in the DGA.
Table 6 is a chart of “fault types,” parts of which are paraphrased from the International Electrotechnical Commission (IEC 60599) [12]. This chart is not complete. It is impossible to chart every cause and effect due to the extreme complexity of transformers. DGA must be carefully examined with the idea of determining possible faults and possible courses of action. These decisions are based on judgment and experience and are seldom “cut and dried.” Most professional associations agree that there are two basic fault types, thermal and electrical. The first three on the chart are electrical discharges, and the last three are thermal faults.
Ethane and ethylene are sometimes called “hot metal gases.” When these gases are being generated and acetylene is not, the problem found inside the transformer normally involves hot metal. This may include bad contacts on the tap changer or a bad connection somewhere in the circuit, such as a main transformer lead. Stray flux impinging on the tank (such as in Westinghouse 7M series transformers) can cause these “hot metal gases.” A shield has been known to become loose and fall and become ungrounded. Static can then build up and discharge to a grounded surface and produce “hot metal” gases. An unintentional core ground with circulating currents can also produce these gases. There are many other examples.
Notice that both type faults (thermal and electrical) may be occurring at once, and one may cause the other. The associations do not mention magnetic faults; however, magnetic faults (such as stray magnetic flux impinging the steel tank or other magnetic structures) also cause hot spots.
Atmospheric gasses (N2, CO2, and O2) can be very valuable in a DGA in revealing a possible leak. However, as mentioned elsewhere, there are other reasons these gases are found in DGA. Nitrogen may have come from shipping the transformer with N2 inside or from a nitrogen blanket. CO2 and O2 are formed by degradation of cellulose. Be very careful; look at several DGAs, and see if atmospheric gases and possibly moisture levels are increasing. Also look at the transformer carefully if you can find an oil leak. Moisture and atmospheric gases will leak inside when the transformer is off and ambient temperature drops. (See section 4.3 on moisture)
Dissolved gas software. Several companies offer DGA computer software that diagnose transformer problems. These diagnoses must be used with engineering judgment and should never be taken at face value. The software is constantly changing. The Technical Service Center uses “ Transformer Oil Analyst” (TOA) by Delta x Research. This software uses a composite of several current DGA methods. Dissolved gas analysis help is available from the TSC at D-8440 and D8450. Both groups have the above software and experience in diagnosing transformer problems.
One set of rules that TOA uses to generate alarms is based loosely on IEC 60599 (table 6). These rules are also very useful in daily dissolved gas analysis. They are based on L1 limits of IEC 60599 except for acetylene. IEC 60599 gives a range for L1 limits instead of a specific value. TOA uses the average in this range and then gives the user a “heads up” if a generation rate exceeds 10% of L1 limits per month. Acetylene is the exception; IEEE sets an L1 limit of 35 ppm (too high), and IEC sets acetylene range at 3 to 50. TOA picks the lowest number (3 ppm) and sets the generation rate alarm value at 3 ppm per month.
Notes: If one or more gas generation rates are equal to or exceed G1 limits (10% of L1 limits per month), you should begin to pay more attention to this transformer. Reduce the DGA sample interval, reduce loading, plan for future outage, contact the manufacturer etc.
If one or more combustible gas generation rates are equal to or exceed G2 limits (50% of L1 limits per month), this transformer should be considered in critical condition. You may want to reduce sample intervals to monthly or weekly, plan an outage, plan to rebuild or replace the transformer, etc. If an active arc is
Table 6.—TOA L1 Limits and Generation Rate Per Month Alarm Limits
G1 Limits G2 Limits GAS L1 Limits (ppm per month) (ppm per month)
H2 100 10 50
CH4 75 8 38
C 2 H 2 3 3 3
C2H4 75 8 38
C 2 H 6 75 8 38
CO 700 70 350
CO2 7,000 700 3,500
present (C2H2 generation), or if other heat gases are high (above Condition 4 limits in table 4), and G2 limits are exceeded, the transformer should be removed from service.
Table 7 is taken from IEC 60599 of key gases, possible faults, and possible findings. This chart is not all inclusive and should be used with other information. Additional possible faults are listed on following and preceding pages.
Transformers are so complex that it is impossible to put all symptoms and causes into a chart. Several additional transformer problems are listed below; there are many others.
1. Gases are generated by normal operation and aging, mostly H2 and CO with some CH4.
2. Operating transformers at sustained overload will generate combustible gases.
3. Problems with cooling systems, discussed in an earlier section, can cause overheating.
4. A blocked oil duct inside the transformer can cause local overheating, generating gases.
5. An oil directing baffle loose inside the transformer causes mis-direction of cooling oil.
6. Oil circulating pump problems (bearing wear, impeller loose or worn) can cause transformer cooling problems.
7. Oil level is too low; this will not be obvious if the level indicator is inoperative.
8. Sludge in the transformer and cooling system. (See “3. Transformer Cooling Methods.”)
Table 7.—Fault Types
Key Gases Possible Faults Possible Findings
H2, possible trace of CH4 and Partial discharges (corona) Weakened insulation from aging and electrical stress. C2H6. Possible CO.
H2, CH4, (some CO if discharges involve paper insulation). Possible trace amounts of C2 H6.
Low energy discharges (sparking).
(May be static discharges)
Pinhole punctures in paper insulation with carbon and carbon tracking. Possible carbon particles in oil. Possible loose shield, poor grounding of metal objects
H2, CH4, C2 H6, C2H4, and the key gas for arcing C2 H2 will be present perhaps in large amounts. If C2 H2 is being generated, arcing is still going on. CO will be present if paper is being heated.
High energy discharges (arcing) Metal fusion, (poor contacts in tap changer or lead connections). Weakened insulation, from aging and electrical stress. Carbonized oil. Paper destruction if it is in the arc path or overheated. H2, CO. Thermal fault less than 300 °C in an area close to paper
Discoloration of paper insulation. Overloading and or insulation (paper is being cooling problem. Bad heated). connection in leads or tap changer. Stray current path and/or stray magnetic flux.
H2, CO, CH4, C2H6, C2 H4. Thermal fault between 300 °C Paper insulation destroyed. Oil and 700 °C heavily carbonized. All the above gases and acetylene in large amounts.
High energy electrical arcing
700 °C and above.
Same as above with metal discoloration. Arcing may have caused a thermal fault.
9. Circulating stray currents may occur in the core, structure, and/or tank.
10. An unintentional core ground may cause heating by providing a path for stray currents.
11. A hot-spot can be caused by a bad connection in the leads or by a poor contact in the tap changer.
12. A hot-spot may also be caused by discharges of static electrical charges that build up on shields or core and structures which are not properly grounded.
13. Hot-spots may be caused by electrical arcing between windings and ground, between windings of different potential, or in areas of different potential on the same winding, due to deteriorated or damaged insulation.
14. Windings and insulation can be damaged by faults downstream (through faults), causing large current surges through the windings. Through faults cause extreme magnetic and physical forces that can distort and loosen windings and wedges. The result may be arcing in the transformer, beginning at the time of the fault, or the insulation may be weakened and arcing develop later.
15. Insulation can also be damaged by a voltage surge such as a nearby lightning strike or switching surge or closing out of step, which may result in immediate arcing or arcing that develops later.
16. Insulation may be deteriorated from age and simply worn out. Clearances and dielectric strength are reduced, allowing partial discharges and arcing to develop. This can also reduce physical strength allowing wedging and windings to move extensively during a through-fault, causing total mechanical and electrical failure.
17. High noise level (hum due to loose windings) can generate gas due to heat from friction. Compare the noise to sister transformers, if possible. Sound level meters are available at the TSC for diagnostic comparison and to establish baseline noise levels for future comparison.
Temperature. Gas production rates increase exponentially with temperature, and directly with volume of oil and paper insulation at high enough temperature to produce gases [11]. Temperature decreases as distance from the fault increases. Temperature at the fault center is highest, and oil and paper here will produce the most gas. As distance increases from the fault (hot spot), tempera ture goes down and the rate of gas generation also goes down. Because of the volume effect, a large heated volume of oil and paper will produce the same amount of gas as a smaller volume at a higher temperature [11]. We cannot tell the difference by looking at the DGA. This is one reason that interpreting DGAs is not an exact science.
Gas Mixing. Concentration of gases in close proximity to an active fault will be higher than in the DGA oil sample. As distance increases from a fault, gas concentrations decrease. Equal mixing of dissolved gases in the total volume of oil depends on time and oil circulation. If there are no pumps to force oil through radiators, complete mixing of gases in the total oil volume takes longer. With pumping and normal loading, complete mixing equilibrium should be reached within 24 hours and will have little effect on DGA if an oil sample is taken 24 hours or more after a problem begins.
Gas Solubility. Solubilities of gases in oil vary with temperature and pressure [13]. Solubility of all transformer gases vary proportionally up and down with pressure. Variation of solubilities with temperature is much more complex. Solubilities of hydrogen, nitrogen, carbon monoxide, and oxygen go up and down proportionally with temperature. Solubilities of carbon dioxide, acetylene, ethylene, and ethane are reversed and vary inversely with temperature changes. As temperature rises, solubilities of these gases go down; and as temperature falls, their solubilities increase. Methane solubility remains almost constant with temperature changes. Table 7 is accurate only at standard temperature and pressure (STP), (25 °C/77 °F) and (14.7 psi/29.93 inches of mercury, which is standard barometric pressure at sea level). Table 8 shows only relative differences in how gases dissolve in transformer oil.
From the solubility table 8 below, comparing hydrogen with a solubility of 7% and acetylene with solubility of 400%, you can see that transformer oil has a much greater capacity for dissolving acetylene. However, 7% hydrogen by volume represents 70,000 ppm, and 400% acetylene represents 4,000,000 ppm. You will probably never see a DGA with numbers this high. Nitrogen can approach maximum level if there is a pressurized nitrogen blanket above the oil. Table 8 shows the maximum amount of each gas that the oil is capable of dissolving at standard temperature and pressure. At these levels, the oil is said to be saturated.
Table 8.—Dissolved Gas Solubility in Transformer Oil Accurate Only at STP, 25 °C (77 °F) and 14.7 psi (29.93 inches of mercury)
Dissolved Gas Formula
Solubility in Transformer Oil (% by Volume)
Equivalent (ppm by Volume) Primary Causes/Sources
Hydrogen1 H2 7.0 70,000 Partial discharge, corona, electrolysis of H2O
Nitrogen N2 8.6 86,000 Inert gas blanket, atmosphere
Carbon Monoxide1 CO 9.0 90,000 Overheated cellulose, air pollution
Oxygen O2 16.0 160,000 Atmosphere
Methane1 CH4 30.0 300,000 Overheated oil
Carbon Dioxide CO2 120.0 1,200,00
Overheated cellulose, atmosphere
Ethane1 C2H6 280.0 2,800,00 Overheated oil
Ethylene1 C2H4 280.0 2,800,000 Very overheated oil
Acetylene1 C2H2 400.0 4,000,000 Arcing in oil
1 Denotes combustible gas. Overheating can be caused both by high temperatures and by unusual or abnormal electrical stress.
If you have conservator-type transformers and nitrogen, oxygen, and CO2 are increasing, there is a good possibility the tank has a leak, or the oil may have been poorly processed. Check the diaphragm or bladder for leaks (section 4.2), and check for oily residue around the pressure relief device and other gasketed openings. There should be fairly low nitrogen and especially low oxygen in a conservator-type transformer. However, if the transformer was shipped new with pressurized nitrogen inside and has not been degassed properly, there may be high nitrogen content in the DGA, but the nitrogen level should not be increasing after the transformer has been in service for a few years. When oil is being installed in a new transformer, a vacuum is placed on the tank which pulls out nitrogen and pulls in the oil. Oil is free to absorb nitrogen at the oil/gas interface, and some nitrogen may be trapped in the windings, paper insulation, and structure. In this case, nitrogen may be fairly high in the DGAs. However, oxygen should be very low, and nitrogen should not be increasing. It is important to take an oil sample early in the transformer’s service life to establish a baseline DGA; then take samples at least annually. The nitrogen and oxygen can be compared with earlier DGAs; and if they increase, it is a good indication of a leak. If the transformer oil has ever been de gassed, nitrogen and oxygen should be low in the DGA. It is extremely important to keep accurate records over a transformer’s life; when a problem occurs, recorded information helps greatly in troubleshooting.
4.4.5 Rogers Ratio Method of DGA. Rogers Ratio Method of DGA [18] is an additional tool that may be used to look at dissolved gases in transformer oil. Rogers Ratio Method compares quantities of different key gases by dividing one into the other. This gives a ratio of the amount of one key gas to another. By looking at the Gas Generation Chart (figure 18), you can see that, at certain temperatures, one gas will be generated more than another gas. Rogers used these relationships and determined that if a certain ratio existed, then a specific temperature had been reached. By comparing a large number of transformers with similar gas ratios and data found when the transformers were examined, Rogers could then say that certain faults were present. Like the Key Gas Analysis above, this method is not a “sure thing” and is only an additional tool to use in analyzing transformer problems. Rogers Ratio Method, using three-key gas ratios, is based on earlier work by Doerneburg, who used five-key gas ratios. Ratio methods are only valid if a significant amount of the gases used in the ratio is present. A good rule is: Never make a decision based only on a ratio if either of the two gases used in a ratio is less than 10 times the amount the gas chromatograph can detect (12). (Ten times the individual gas detection limits are shown in table 9 and below.) This rule makes sure that instrument inaccuracies have little effect on the ratios. If either of the gases are lower than 10 times the detection limit, you most likely do not have the particular problem that this ratio deals with anyway. If the gases are not at least 10 times these limits, this does not mean you cannot use the Rogers Ratios; it means that the results are not as certain as if the gases were at least at these levels. This is another reminder that DGAs are not an exact science and there is no “one best easy way” to analyze transformer problems. Approximate detection limits are as follows, depending on the lab and equipment:
Dissolved Gas Analysis Detection Limits.
Hydrogen (H2) about 5 ppm Methane (CH4) about 1 ppm Acetylene (C2H2) about 1 to 2 ppm Ethylene (C2H4) about 1 ppm Ethane (C2H6) about 1 ppm Carbon monoxide (CO) and carbon cioxide (CO2) about 25 ppm Oxygen (O2 ) and nitrogen (N2) about 50 ppm
When a fault occurs inside a transformer, there is no problem with minium gas amounts at which the ratio are valid. There will be more than enough gas present.
If a transformer has been operating normally for some time and a DGA shows a sudden increase in the amount of gas, the first thing to do is take a second sample to verify there is a problem. Oil samples are easily contaminated during sampling or at the lab. If the next DGA shows gases to be more in line with prior DGAs, the earlier oil sample was contaminated, and there is no further cause for concern. If the second sample also shows increases in gases, the problem is real. To apply Ratio Methods, it helps to subtract gases that were present prior to sudden gas increases. This takes out gases that have been generated up to this point due to normal aging and from prior problems. This is especially true for ratios using H 2 and the cellulose insulation gases CO and CO2 [12]. These are generated by normal aging.
Rogers Ratio Method Uses the Following Three Ratios.
C2H2/C2H4, CH4/H2, C2H4/C2H6
These ratios and the resultant fault indications are based on large numbers of DGAs and transformer failures and what was discovered after the failures.
There are other ratio methods, but only the Rogers Ratio Method will be discussed since it is the one most commonly used. The method description is paraphrased from Rogers’ original paper [18] and from IEC 60599 [12].
Caution: Rogers Ratio Method is for fault analyzing, not for fault detection. You must have already decided that you have a problem from the total amount of gas (using IEEE limits) or increased gas generation rates. Rogers Ratios will only give you an indication of what the problem is; it cannot tell you whether or not you have a problem. If you already suspect a problem based on total combustible gas levels or increased rate-of-generation, then you will normally already have enough gas for this method to work. A good system to determine whether you have a problem is to use table 5 in the Key Gas Method. If two or more of the key gases are in condition two and the gas generation is at least 10% per month of the L1 limit, you have a problem. Also, for the diagnosis to be valid, gases used in ratios should be at least 10 times the detection limits given earlier. The more gas you have, the more likely the Rogers Ratio Method will give a valid diagnosis. The reverse is also true; the less gas you have, the less likely the diagnosis will be valid. If a gas used in the denominator of any ratio is zero, or is shown in the DGA as not detected (ND), use the detection limit of that particular gas as the denominator. This gives a reasonable ratio to use in diagnostic table 9. Zero codes mean that you do not have a problem in this area.
Table 9.—Rogers Ratios for Key Gases
Code range of ratios C2H2 CH4 C2H4 Detection limits and 10 x detection limits are shown below: C2H4 H2 C2H6 C2H2 1 ppm 10 ppm C2H4 1 ppm 10 ppm CH4 1 ppm 10 ppm<0.1 0 1 0 0.1-1 1 0 0 H2 5 ppm 50 ppm 1-3 1 2 1 C2H6 1 ppm 10 ppm >3 2 2 2
Case Fault Type Problems Found
0 No fault 0 0 0 Normal aging
1 Low energy partial 1 1 0 Electric discharges in bubbles, caused by insulation voids or super discharge gas saturation in oil or cavitation (from pumps) or high moisture in oil (water vapor bubbles).
2 High energy 1 1 0 Same as above but leading to tracking or perforation of solid partial discharge cellulose insulation by sparking, or arcing; this generally produces CO and CO2.
3 Low energy 1-2 0 1-2 Continuous sparking in oil between bad connections of different discharges, potential or to floating potential (poorly grounded shield etc); sparking, arcing breakdown of oil dielectric between solid insulation materials.
4 High energy discharges, arcing
1 0 2 Discharges (arcing ) with power follow through; arcing breakdown of oil between windings or coils, or between coils and ground, or load tap changer arcing across the contacts during switching with the oil leaking into the main tank.
5 Thermal fault less 0 0 1 Insulated conductor overheating; this generally produces CO and than 150 °C CO2 because this type of fault generally involves cellulose (see note 2) insulation.
6 Thermal fault temp. range 150-300 °C (see note 3)
0 2 0 Spot overheating in the core due to flux concentrations. Items below are in order of increasing temperatures of hot spots. Small hot spots in core. Shorted laminations in core. Overheating of copper conductor from eddy currents. Bad connection on winding to incoming lead, or bad contacts on load or no-load tap changer. Circulating currents in core; this could be an extra core ground, (circulating currents in the tank and core); this could also mean stray flux in the tank.
These problems may involve cellulose insulation which will produce CO and CO2.
7 Thermal fault temp. range 300-700 °C
8 Thermal fault temp. range over 700 °C (see note 4)
Notes: 1. There will be a tendency for ratio C2H2 /C2H4 to rise from 0.1 to above 3 and the ratio C2H4 /C2H6 to rise from 1-3 to above 3 as the spark increases in intensity. The code at the beginning stage will then be 1 0 1. 2. These gases come mainly from the decomposition of the cellulose which explains the zeros in this code. 3. This fault condition is normally indicated by increasing gas concentrations. CH4 /H2 is normally about 1, the actual value above or below 1, is dependent on many factors such as the oil preservation system (conservator, N2 blanket, etc.), the oil temperature, and oil quality. 4. Increasing values of C2H2 (more than trace amounts), generally indicates a hot spot higher than 700 °C. This generally indicates arcing in the transformer. If acetylene is increasing and especially if the generation rate is increasing, the transformer should be de- energized, further operation is extremely hazardous.
General Remarks:
1. Values quoted for ratios should be regarded as typical (not absolute). This means that the ratio numbers are not “carved in stone”; there may be transformers with the same problems whose ratio numbers fall outside the ratios shown at the top of the table.
2. Combinations of ratios not included in the above codes may occur in the field. If this occurs, the Rogers Ratio Method will not work for analyzing these cases.
3. Transformers with on-load tap changers may indicate faults of code type 2 0 2 or 1 0 2 depending on the amount of oil interchange between the tap changer tank and the main tank.
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