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. 

Example 1 

Example of a Reclamation transformer DGA: 

Rogers Ratio Analysis 

Hydrogen (H2) Methane (CH4) 

9 ppm 60 C2H2/C2H4 = 3/368 = 0.00815 

Code 0 

Ethane (C2H6) Ethylene (C2H4) 

53 368 CH4/H2 = 60/9 = 6.7 2 Acetylene (C2H2) 3 C2H4/C2H6 = 368/53 = 6.9 2 Carbon Monoxide (CO) Carbon Dioxide (CO2) Nitrogen (N2) Oxygen (O2) 7 361 86,027 1,177 This code combination is Case 8 in table 4, which indicates this transformer has a thermal fault hotter than 700 °C. TDCG 500 

Ethylene and ethane are sometimes called “hot metal gases.” Notice this fault does not involve paper insulation, because CO is very low. H2 and C2 H2 are both less than 10 times the detection limit. This means the diagnosis does not have a 100% confidence level of being correct. However, due to the high ethylene, the fault is probably a bad connection where an incoming lead is bolted to a winding lead, or perhaps bad tap changer contacts, or additional core ground (large circulating currents in the tank and core). See the two bottom problems on table 10 later in this chapter. This example was chosen to show a transformer that was not a “clear cut” diagnosis. Engineering judgment is always required. 

A small quantity of acetylene is present, just above the detection limit of 1 ppm. This is not high energy arcing due to the small amount; it has more likely been produced by a one-time nearby lightning strike or a voltage surge. 

Example 2 

Latest DGA Prior DGA No. 2 Prior DGA No. 1 

Hydrogen (H2) 26 ppm 27 17 

Methane (CH4) 170 164 157 

Ethane (C2H6) 278 278 156 

Ethylene (C2H4) 25 4 17 

Acetylene (C2H2) 2 0 0 

Carbon Monoxide (CO) 92 90 96 

Carbon Dioxide (CO2) 3,125 2,331 2,476 

Nitrogen (N2) 67,175 72,237 62,641 

Oxygen (O2) 608 1,984 440 

Rogers Ratio Analysis Based on Latest DGA: 

Codes 

C2H2/C2H4 = 2/25 = 0.080 0 

CH4/H2 = 170/26 = 6.54 2 

C2H4/C2H6 = 25/278 = 0.09 0 

Notice that methane is increasing slowly, but ethane had a large increase between samples 1 and 2 but did not increase between samples 2 and 3. Note that two key gases (CH2 and C2H6) are above IEEE Condition 1 in table 5, so the Rogers Ratio Method is valid. By referring to table 9, this combination of codes is Case 6, which indicates the transformer has a thermal fault in the temperature range of 150 °C to 300 °C. 

Life history of the transformer must be examined carefully. It is, again, very important to keep accurate records of every transformer. This information is invaluable when it becomes necessary to do an evaluation. 

The transformer in this example is one of three sister transformers that have had increased cooling installed and are running higher loads due to a generator upgrade several years ago. Transformer sound level (hum) is markedly higher than for the two sister transformers. The unit breaker experienced a fault some years ago, which placed high mechanical stresses on the transformer. This generally means loose windings, which can generate gas due to friction (called a thermal fault) by Rogers Ratios. Comparison with sister units reveals almost triple the ethane as the other two, and it is above the IEEE Condition 4.Gases are increasing slowly; there has been no sudden rate increase in combustible gas production. Notice the large increase in O2 and N2 between the first and second DGA and the large decrease between the second and third. This probably means that the oil sample was exposed to air (atmosphere) and that these two gases are inaccurate in the middle sample. 

Carbon Dioxide Carbon Monoxide Ratio. This ratio is not included in the Rogers Ratio Method of analysis. However, it is useful to determine if a fault is affecting the cellulose insulation. This ratio is included in transformer oil analyzing software programs such as Delta X Research Transformer Oil Analyst. This analysis is available from the TSC at D-8440 and D-8450 in Denver. 

Formation of CO2 and CO from the degradation of oil impregnated paper increases rapidly with temperature. CO2 /CO ratios less than three are generally considered an indication of probable paper involvement in an electrical fault (arcing or sparking), along with some carbonization of paper. Normal CO2 /CO ratios are typically around seven. Ratios above 10 generally indicate a thermal fault with the involvement of cellulose. This is only true if the CO2 came from within the transformer (no leaks), and these ratios are only meaningful if there is a significant amount of both gases. Caution must be employed because oil degradation also produces these gases, and CO2 can also be dissolved in the oil from atmospheric leaks. The oil sample can also pick up CO 2 and O2 if it is exposed to air during sampling or handling at the lab. If a fault is suspected, look carefully to see if CO is increasing. If CO is increasing around 70 ppm or more per month (generation limit from IEC 60599), there is probably a fault. It is a good idea to subtract the amount of CO and CO2 shown before the increase in CO and CO2 began, so that only gases caused by the present fault are used in the ratio. This will eliminate CO and CO2 generated by normal aging and other sources. When excessive cellulose degradation is suspected (CO2 /CO ratios less than 3, or greater than 10), it may be advisable to ask for a furan analysis with the next DGA. This will give an indication of useful life left in the paper insulation [12]. 

You cannot de-energize a transformer based on furan analysis alone. All this test does is give an indication of the health of the paper; it is not a sure thing. But furan analysis is recommended by many experts to give an indication of remaining life when the CO2 /CO ratio is less than 3 or greater than 10. Some oil laboratories do this test on a routine basis, and some charge extra for it. 

Table 10 is adapted from IEC 60599 Appendix A.1.1 [12]. Some of the wording has been changed to reflect American language usage rather than European. 

4.5 Moisture Problems 

Moisture, especially in the presence of oxygen, is extremely hazardous to transformer insulation. Each DGA and Doble test result should be examined carefully to see if water is increasing and to determine the moisture by dry weight (M/DW) or percent saturation that is in the paper insulation. When 2% M/DW is reached, plans should be made for a dry out. Never allow the M/DW to go above 2.5% in the paper or 30% oil saturation without drying out the transformer. Each time the moisture is doubled in a transformer, the life of the insulation is cut by one-half. Keep in mind that the life of the transformer is the life of the paper, and the purpose of the paper is to keep out moisture and oxygen. For service-aged transformers rated less than 69 kV, results of up to 35 ppm are considered acceptable. For 69 kV through 288 kV, the DGA test result of 25 ppm is considered acceptable. For greater than 288 kV, moisture should not exceed 20 ppm. However, the use of absolute values for water does not always guarantee safe conditions, and the percent by dry weight should be determined. See table 12, “Doble Limits for In-Service Oils,” in section 4.6.5. If values are higher, the oil should be processed. If the transformer is kept as dry and free of oxygen as possible, transformer life will be extended. 

Reclamation specifies that manufacturers dry new transformers to no more than 0.5% M/DW during commissioning. In a transformer having 10,000 pounds of paper insulation, this means that 10,000 x 0.005 = 50 pounds of water (about 6 gallons) is in the paper. This is not enough moisture to be detrimental to electrical integrity. When the transformer is new, this water is distributed equally through the transformer. It is extremely important to remove as much water as possible. 

Table 10.—Typical Faults in Power Transformers [12] 

Fault Examples 

Partial discharges Discharges in gas-filled cavities in insulation, resulting from incomplete impregnation, high moisture in paper, gas in oil supersaturation or cavitation, (gas bubbles in oil) leading to X wax formation on paper. 

Discharges of low energy 

Sparking or arcing between bad connections of different floating potential, from shielding rings, toroids, adjacent discs or conductors of different windings, broken brazing, closed loops in the core.  Additional core grounds.  Discharges between clamping parts, bushing and tank, high voltage and ground, within windings. Tracking in wood blocks, glue of insulating beam, winding spacers. Dielectric breakdown of oil, load tap changer breaking contact. 

Discharges of high energy 

Flash-over, tracking or arcing of high local energy or with power follow-through. Short circuits between low voltage and ground, connectors, windings, bushings, and tank, windings and core, copper bus and tank, in oil duct.  Closed loops between two adjacent conductors around the main magnetic flux, insulated bolts of core, metal rings holding core legs. 

Overheating less than 300 °C 

Overloading the transformer in emergency situations.  Blocked or restricted oil flow in windings.  Other cooling problem, pumps valves, etc.  See the “Cooling” section in this document.  Stray flux in damping beams of yoke.   

Overheating 

300 to 700 °C 

Defective contacts at bolted connections (especially busbar), contacts within tap changer, connections between cable and draw-rod of bushings. Circulating currents between yoke clamps and bolts, clamps and laminations, in ground wiring, bad welds or clamps in magnetic shields. Abraded insulation between adjacent parallel conductors in windings. 

Overheating over 700 °C 

Large circulating currents in tank and core.  Minor currents in tank walls created by high uncompensated magnetic field. Shorted core laminations. 

Notes: 1. X wax formation comes from Paraffinic oils  (paraffin based). These are not used in transformers at present in the United States but are predominate in Europe. 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. 

When the transformer is energized, water begins to migrate to the coolest part of the transformer and the site of the greatest electrical stress. This location is normally the insulation in the lower one-third of the winding [5]. Paper insulation has a much greater affinity for water than does the oil. The water will distribute itself unequally, with much more water being in the paper than in the oil. The paper will partially dry the oil by absorbing water out of the oil. Temperature is also a big factor in how the water distributes itself between the oil and paper. See table 11 below for comparison. 

Table 11.—Comparison of Water Distribution in Oil and Paper [5] 

Temperature Water Water (degrees C) in Oil in Paper 

20° 1 3,000 times what is in the oil 

40° 1 1,000 times what is in the oil 

60° 1 300 times what is in the oil 

The table above shows the tremendous attraction that paper insulation has for water. The ppm of water in oil shown in the DGA is only a small part of the water in the transformer. It is important that, when an oil sample is taken, you record the oil temperature from the top oil temperature gauge. 

Some laboratories give percent M/DW of the insulation in the DGA. Others give percent oil saturation, and some give only the ppm of water in the oil. If you have an accurate temperature of the oil and the ppm of water, the Nomograph will give percent M/DW of the insulation and the percent oil saturation. 

Where does the water come from? Moisture can be in the insulation when it is delivered from the factory. If the transformer is opened for inspection, the insulation can absorb moisture from the atmosphere. If there is a leak, moisture can enter in the form of water or humidity in air. Moisture is also formed by the degradation of insulation as the transformer ages. Most water penetration is flow of wet air or rain water through poor gasket seals due to pressure difference caused by transformer cooling. During rain or snow, if a transformer is removed from service, some transformer designs cool rapidly and the pressure inside drops. The most common moisture ingress points are gaskets between bushing bottoms and the transformer top and the pressure relief device gasket. Small oil leaks, especially in the oil cooling piping, will also allow moisture ingress. With rapid cooling and the resultant pressure drop, relatively large amounts of water and water vapor can be pumped into the transformer in a short time. It is important to repair small oil leaks; the small amount of visible oil is not important in itself, but it also indicates a point where moisture will enter . 

It is critical for life extension to keep transformers as dry and as free of oxygen as possible. Moisture and oxygen cause the paper insulation to decay much faster than normal and form acids, sludge, and more moisture. Sludge settles on winding and inside the structure, causing transformer cooling to be less efficient, and slowly over time temperature rises. (This was discussed earlier in “3. Transformer Cooling Methods.”) Acids cause an increase in the rate of decay, which forms more acid, sludge, and moisture at a faster rate [20]. This is a vicious cycle of increasing speed forming more acid and causing more decay. The answer is to keep the transformer as dry as possible and as free of oxygen as possible. In addition, oxygen inhibitor should be watched in the DGA testing. The transformer oil should be dried when moisture reaches the values according to table 12. Inhibitor should be added (0.3% by weight ASTM D-3787) when the oil is processed. 

Water can exist in a transformer in five forms. 

1. Free water, at the bottom of the tank. 

2. Ice at the tank bottom (if the oil specific gravity is greater than 0.9, ice can float). 

3. Water can be in the form of a water/oil emulsion. 

4. Water can be dissolved in the oil and is given in ppm in the DGA. 

5. Water can be in the form of humidity if transformers have an inert gas blanket. 

Free water causes few problems with dielectric strength of oil; however, it should be drained as soon as possible. Having a water- oil interface allows oil to dissolve water and transport it to the insulation. Problems with moisture in insulation were discussed above. If the transformer is out of service in winter, water can freeze. If oil specific gravity is greater than 0.9 (ice specific gravity), ice will float. This can cause transformer failure if the transformer is energized with floating ice inside. This is one reason that DGA laboratories test specific gravity of transformer oil. 

The amount of moisture that can be dissolved in oil increases with temperature. (See figure 19.) This is why hot oil is used to dry out a transformer. A water/oil emulsion can be formed by purifying oil at Figure 19.—Maximum Amount of Water too high temperature. When the oil Dissolved in Mineral Oil Versus Temperature cools, dissolved moisture forms an emulsion [20]. A water/oil emulsion causes drastic reduction in dielectric strength. 

How much moisture in insulation is too much? When the insulation gets to 2.5% M/DW or 30% oil saturation (given on some DGAs), the transformer should have a dry out with vacuum if the tank is rated for vacuum. If the transformer is old, pulling a vacuum can do more harm than good. In this case, it is better to do round-the-clock re­ circulation with a Bowser drying the oil as much as possible, which will pull water out of the paper. At 2.5% M/DW, the paper insulation is degrading much faster than normal [5]. As the paper is degraded, more water is produced from the decay products, and the transformer becomes even wetter and decays even faster. When a transformer gets above 4% M/DW, it is in danger of flash-over if the temperature rises to 90 °C.