Electrifying Electrologic!!!

Sunday, 7 June 2015

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.

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

Flashover, 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.

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 gage.

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 (figure 23, section 4.5.2) 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 [22].

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 windings 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 dryout 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 flashover if the temperature rises to 90 °C.

4.5.1 Dissolved Moisture in Transformer Oil. Moisture is given in the dissolved gas analysis in ppm, and some laboratories also give percent saturation. Percent saturation means percent saturation of water in the oil. This is a percentage of how much water is in the oil compared with the maximum amount of water the oil can hold. In figure 19, it can be seen that the amount of water the oil can dissolve is greatly dependent on temperature. The curves (figure 20) below are percent saturation curves. On the left line, find the ppm of water from your DGA. From this point, draw a horizontal with a straight edge. From the oil temperature, draw a vertical line. At the point where the lines intersect, read the percent saturation curve. If the point falls between two saturation curves, estimate the percent saturation based on where the point is located. For example, if the water is 30 ppm and the temperature is 40 °C, you can see on the curves that this point of intersection falls about halfway between the 20% curve and the 30% curve. This means that the oil is approximately 25% saturated.

Caution: Below 30 °C, the curves are not very accurate.

4.5.2 Moisture in Transformer Insulation. The illustration at right (figure 21) shows how moisture is distributed throughout transformer insulation. Notice that the moisture is distributed according to temperature, with most moisture at the bottom and less as temperature increases toward the top. In this example, there is almost twice the moisture near bottom as there is at the top. Most service-aged transformers fail in the lower one-third of the windings, which is the area of most moisture. It is also the area of most electrical stress. Moisture and oxygen are two of the transformer’s worst enemies. It is very important to keep the insulation and oil as dry as possible and as free of oxygen as possible.

Failures due to moisture are the most common cause of transformer failures [5]. Without an accurate oil temperature, it is impossible for laboratories to provide accurate information about the M/DW or percent saturation. It will also be impossible for you to calculate this information accurately.

Experts disagree on how to tell how much moisture is in the insulation based on how much moisture is in the oil (ppm). At best, methods to determine moisture in the insulation based solely on DGA are inaccurate. The methods discussed below to determine moisture in the insulation are approximations and no decision should be made based on one DGA. However, keep in mind that the life of the transformer is the life of the insulation. The insulation is quickly degraded by excess moisture and the presence of oxygen. Base any decisions on several DGAs over a period of time and establish a trend of increasing moisture.

If the lab does not provide the percent M/DW, IEEE 62-1995 [19] gives a method. From the curve (figure 22), find temperature of the bottom oil sample and add 5 °C. Do not use the top oil temperature. This approximates temperature of the bottom third (coolest part) of the winding, where most of the water is located. From this temperature, move up vertically to the curve. From this point on the curve, move horizontally to the left and find the Myers Multiplier number. Take this number and multiply the ppm of water shown on the DGA. The result is percent M/DW in the upper part of the insulation. This method gives less amount of water than the General Electric nomograph on the following page.

This nomograph, published by General Electric in 1974 (figure 23), gives the percent saturation of oil and percent M/DW of insulation. Use the nomograph to check yourself after you have completed the method illustrated in figure 22. The nomograph in figure 23 will show more moisture than the IEEE method.

The curves in figure 23 are useful to help understand relationships between temperature, percent saturation of the oil, and percent M/DW of the insulation. For example, pick a point on the ppm water line, say 10 ppm. Place a straight edge on that point and pick a point on the temperature line, say 45 °C. Read the percent saturation and percent M/DW on the center lines. In this example, percent saturation is about 6.5% and the % M/DW is about 1.5%. Now, hold the 10 ppm point and move the sample temperature upward (cooler), and notice how quickly the moisture numbers increase. For example, use 20 °C and read the % saturation of oil at about 18.5% and the % M/DW at about 3.75%. The cooler the oil, the higher the moisture percentage for the same ppm of water in the oil.

Do not make a decision on dryout based on only one DGA and one calculation; it should be based on trends over a period of time. Take additional samples and send them for analysis. Take extra care to make sure the oil temperature is correct. You can see by the nomograph that moisture content varies dramatically with temperature. Take extra care that the sample is not exposed to air. If after using the more conservative IEEE method and again subsequent samples show M/DW is 2.5% or more and the oil is 30% saturated or more, the transformer should be dried as soon as possible. Check the nomograph and curves above to determine the percent saturation of the oil. The insulation is degrading much faster than normal due to the high moisture content. Drying can be an expensive process; it is prudent to consult with others before making a final decision to do dryout. However, it is much less expensive to perform a dryout than to allow a transformer to degrade faster than normal, substantially shortening transformer life.

Tuesday, 2 June 2015

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

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

Fault Examples

Discharges of low energy

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

Overheating

300 to 700 °C

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.

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

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.

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.

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.

Sunday, 24 May 2015

In the gas generation chart (figure 18) [13, 16] and discussion below, please note that temperatures at which gases form are only approximate. The figure is not drawn to scale and is only for purposes of illustrating temperature relationships, gas types, and quantities. These relationships represent what generally has been proven in controlled laboratory conditions using a mass 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.

Thursday, 21 May 2015

4.4 Transformer Oils

4.4.1 Transformer Oil Functions. Transformer oils perform at least four functions for the transformer. Oil provides insulation, provides cooling, and helps extinguish arcs. Oil also dissolves gases generated by oil degradation, moisture and gas from cellulose insulation, deterioration, and gases and moisture from whatever atmosphere the oil is exposed to. Close observation of dissolved gases in the oil, and other oil properties, provides the most valuable information about transformer health. Looking for trends by comparing information provided in several DGAs, and understanding its meaning, is the most important transformer diagnostic tool.

4.4.2 Dissolved Gas Analysis. After 1 month of service and once each year, and more often if a problem is encountered, do a DGA. This is by far the most important tool for determining the health of a transformer.

Caution: DGA is unreliable if the transformer is de-energized and has cooled, if the transformer is new, or if it has had less than 1 to 2 weeks of continuous service after oil processing.

The purpose of this section is to provide guidance in interpreting DGA and to suggest actions based on the analysis. There are no “quick and sure” easy answers when dealing with transformers. Transformers are very complex, very expensive, and very important to Reclamation; and each one is different. Decisions must be based on experienced judgment founded on all available data and consultation with experienced people. Along with thorough periodic inspections covered earlier, the most important key to transformer life is periodic DGA and proper interpretation. Each DGA must be compared to prior DGAs so that trends can be recognized and rates of gas generation established.

Although examples will be presented later, there is no universally accepted means for interpreting DGA [15]. Transformers are very complex. Aging, chemical actions and reactions, electric fields, magnetic fields, thermal contraction and expansion, load variations, gravity, and other forces all interact inside the tank. Externally, through-faults, voltage surges, wide ambient temperature changes, and other forces such as the earth’s magnetic field and gravity affect the transformer. There are few if any “cut and dried” DGA interpretations; even experts disagree. Consultation with others, experience, study, comparing earlier DGA’s, keeping accurate records of a transformer’s history, and noting information found when a transformer is disassembled will increase expertise and provide life extension to this critical equipment.

Keeping accurate records of each individual transformer is paramount. If a prior through-fault, overload, cooling problem, or nearby lightning strike has occurred, this information is extremely valuable when trying to determine what is going on inside the transformer. Baseline transformer test information should be established when the transformer is new or as soon as possible thereafter. This must include DGA, Doble, and other test results, discussed in the testing section, “4.7 Transformer Testing.”

4.4.3 Key Gas Method of interpreting DGA is set forth in IEEE [11]. Key gases formed by degradation of oil and paper insulation are hydrogen (H2), methane (CH4), ethane (C2 H6), ethylene (C2 H4), acetylene (C2 H2), carbon monoxide (CO), and oxygen (O2). Except for carbon monoxide and oxygen, all these gases are formed from the degradation of the oil itself. Carbon monoxide, carbon dioxide (CO2), and oxygen are formed from degradation of cellulose (paper) insulation. Carbon dioxide, oxygen, nitrogen (N2 ), and moisture can also be absorbed from the air if there is a oil/air interface, or if there is a leak in the tank. Some of our transformers have a pressurized nitrogen blanket above the oil and, in these cases, nitrogen may be near saturation. (See table 4.) Gas type and amounts are determined by where the fault occurs in the transformer and the severity and energy of the event. Events range from low energy events such as partial discharge, which produces hydrogen and trace amounts of methane and ethane, to very high energy sustained arcing, capable of generating all the gases including acetylene, which requires the most energy.

4.4.4 Transformer Diagnosis Using Individual and Total Dissolved Key Gas Concentrations. A four-condition, DGA guide to classify risks to transformers with no previous problems has been developed by the IEEE [11]. The guide uses combinations of individual gases and total combustible gas concentration. This guide is not universally accepted and is only one of the tools used to evaluate transformers. The four conditions are defined below:

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 4 should have additional investigation.

Table 4.—Dissolved Key Gas Concentration Limits in Parts Per Million (ppm)

Status H2 CH4 C2 H2 C2H4 C2H6 CO 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.

Condition 2: TDCG within this range indicates greater than normal combustible gas level. Any individual combustible gas exceeding specified levels in table 4 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 5 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 4 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. (See table 5.)

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 5).

Condition numbers for dissolved gases given in IEEE C-57-104-1991 (table 4) are extremely conservative. We have transformers that have operated safely with individual gases in Condition 4 with no problems; however, 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/day), the fault is active and 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 amount of gas. One exception is acetylene (C2H2). The 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 °C). A one-time arc caused by a nearby lightning strike or a high-voltage surge can generate acetylene. If C2H2 is found in the DGA, oil samples should be taken weekly to determine if additional acetylene 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

Table 5.—Actions Based on Dissolved Combustible Gas

Conditions

TDCG Level or Highest Individual Gas (See Table 4) TDCG Generation Rates (PPM/Day)

Sampling Intervals and Operating Actions for Gas Generation Rates

Sampling Interval Operating Procedures

#720 ppm of TDCG or highest condition based on individual

<10 Annually: 6mo for EHV trans

Continue normal operation.

Condition 1 gas from table 4

10-30 Quarterly

>30 Monthly Exercise caution. Analyze individual gases to find cause. Determine load dependence.

Condition 2

721-1,920 ppm of TDCG or highest condition based on individual

<10 Quarterly

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

10-30 Monthly gas from table 4

>30 Monthly

1,941-2,630 ppm of <10 Monthly Exercise extreme caution. TDCG or Analyze individual gases to find cause. Plan outage. Call manufacturer and other consultants for advice. Condition 3 highest condition 10-30 Weekly gas from table 4 based on individual >30 Weekly

>4,630 ppm of <10 Weekly Exercise extreme caution. TDCG or Analyze individual gases to find cause. Plan outage. Call manufacturer and other consultants for advice.

Condition 4 based on individual gas from table 4 highest condition

10-30 Daily

>30 Daily Consider removal from service. Call manufacturer and other consultants for advice.

NOTES: 1. Either the Highest Condition Based on Individual Gas or Total Dissolved Combustible Gas can determine the condition (1,2,3, or 4) of the transformer [11]. For example, if the TDCG is between 1,941 ppm and 2,630 ppm, this indicates Condition 3. However ,if hydrogen is greater than 1,800 ppm, the transformer is in Condition 4, as shown in table 4.. 2. When the table says “determine load dependence,” this means, if possible, find out if the gas generation rate in ppm/day goes up and down with load. Perhaps the transformer is overloaded. Take oil samples every time the load changes; if load changes are too frequent, this may not be possible. 3. To get 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 ppm/day is determined by the same method.

internal arc and should be taken out of service. Further operation is extremely hazardous and may result in catastrophic failure. Operating a transformer with an active high energy arc is extremely hazardous.

Table 4 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). Deciding whether gases are increasing significantly depends on your particular transformer.

Compare the current DGA to older DGAs. If the production rate (ppm/day) of any one of the key gases and/or TDCG (ppm) has suddenly gone up, gases are probably increasing significantly. Refer to table 5, which gives suggested actions based on total amount of gas in ppm and rate of gas production in ppm/day. Before going to table 5, determine transformer status from table 4; that is, look at the DGA and see if the transformer is in Condition 1, 2, 3, or 4. The condition for a particular transformer is determined by finding the highest level for any individual gas or by using the TDCG [11]. Either the individual gas or the TDCG can give the transformer a higher Condition number, which means it is at greater risk. If the TDCG number shows the transformer in Condition 3 and an individual gas shows the transformer in Condition 4, the transformer is in Condition 4. Always be conservative and assume the worst until proven otherwise. Sampling intervals and recommended actions. When sudden increases occur in dissolved gases, the procedures recommended in table 5 should be followed. Table 5 is paraphrased from table 3 in IEEE C57.104-1991. To make it easier to read, the order has been reversed with Condition 1 (lowest risk transformer) at the top and Condition 4 (highest risk) at the bottom. The table indicates the recommended sampling intervals and actions for various levels of TDCG in ppm. An increasing gas generation rate indicates a problem of increasing severity; therefore, as the generation rate (ppm/day) increases, a shorter sampling interval is recommended. (See table 5.) Some information has been added to the table from IEEE C57-104-1991; that is, inferred from the text. To see the exact table, refer to the IEEE Standard. If it can be determined what is causing gassing and the risk can be assessed, the sampling interval may be extended. For example, if the core is tested with a megohmmeter and an additional core ground is found, even though table 5 may recommend a monthly sampling interval, an operator may choose to lengthen the sampling interval, because the source of the gassing and generation rate is known. A decision should never be made on the basis of just one DGA. It is very easy to contaminate the sample by accidentally exposing it to air. Mislabeling a sample is also a common cause of error. Mislabeling could occur when the sample is taken, or it could be accidentally contaminated or mishandled at the laboratory. Mishandling may allow some gases to escape to the atmosphere and other gases, such as oxygen, nitrogen, and carbon dioxide, to migrate from the atmosphere into the sample. If you notice a transformer problem from the DGA, the first thing to do is take another sample for comparison. In the gas generation chart (figure 18) [13, 16] and discussion below, please note that temperatures at which gases form are only approximate. The figure is not drawn to scale and is only for purposes of illustrating temperature relationships, gas types, and quantities. These relationships represent what generally has been proven in controlled laboratory conditions using a mass

Monday, 18 May 2015

4.3 Gaskets

Gaskets have several important jobs in sealing systems [6]. A gasket must create a seal and hold it over a long period of time. It must be impervious and not contaminate the insulating fluid or gas above the fluid. It should be easily removed and replaced. It must be elastic enough to flow into imperfections on the sealing surfaces. It must withstand high and low temperatures and remain resilient enough to hold the seal even with joint movement from expansion, contraction, and vibration. It must be resilient enough to not take a “set” even though exposed for a long time to pressure applied with bolt torque and temperature changes. It must have sufficient strength to resist crushing under applied load and resist blowout under system pressure or vacuum. It must maintain its integrity while being handled or installed. If a gasket fails to meet any of these criteria, a leak will result. Gasket leaks result from improper torque, choosing the wrong type gasket material, or the wrong size gasket. Improper sealing surface preparation or the gasket taking a “set” (becoming hard and losing its resilience and elasticity) will also cause a leak. Usually, gaskets take a set as a result of temperature extremes and age.

Sealing (mating) surface preparation: Clean the metal surface thoroughly. Remove all moisture, oil and grease, rust, etc. A wire brush and/or solvent may be required.

Caution: Take extra care that rust and dirt particles never fall into the transformer. The results could be catastrophic, when the transformer is energized.

After rust and scale have been removed, metal surfaces should be coated with Loctite Master gasket No. 518. This material will cure after you bolt up the gasket, so additional glue is not necessary. If the temperature is 50 °F or more, you can bolt up the gasket immediately. This material comes in a kit (part No. 22424) with primer, a tube of material, and instructions. If these instructions are followed, the seal will last many years, and the gasket will be easy to remove later if necessary. If the temperature is under 50 °F, wait about ½ to 1 hour after applying the material to surfaces before bolting. If you are using cork-nitrile or cork-neoprene, you can also

seal gasket surfaces (including the edge of the gasket) with this same material. Loctite makes other sealers that can be used to seal gaskets such as “Hi-tack.”

GE glyptol No. 1201B-red can also be used to paint gasket and metal surfaces, but it takes more time and you must be more cautious about temperature. If possible, this work should be done in temperatures above 70 °F to speed paint curing. Allow the paint to completely dry before applying glue or the new gasket. It is not necessary to remove old glyptol or other primer or old glue if the surface is fairly smooth and uniform.

Caution: Most synthetic rubber compounds, including nitrile (Buna N), contain some carbon, which makes it semi-conductive. Take extra care and never drop a gasket or pieces of gasket into a transformer tank. The results could be catastrophic when the transformer is energized.

Choose the correct replacement gasket. The main influences on gasket material selection are design of the gasket joint, maximum and minimum operating temperature, type of fluid contained, and internal pressure of the transformer.

Cork-nitrile should be used if the joint does not have grooves or limits. This material performs better than cork-neoprene because it does not take a set as easily and conforms better to mating surfaces. It also performs better at higher temperatures. Be extra careful when you store this material because it looks like cork-neoprene (described below), and they easily are mistaken for each other. Compression is the same as for cork-neoprene, about 45%. Cork-nitrile should recover 80% of its thickness with compression of 400 psi in accordance with ASTM F36. Hardness should be 60 to 75 durometer in accordance with ASTM D2240. (See published specifications for E-98 by manufacturer Dodge-Regupol Inc., Lancaster, PA.)

Caution: Cork-nitrile has a shelf life of only about 2 years, so do not order and stock more than can be used during this time.

Cork-Neoprene mixture (called coroprene) can also be used; however, it does not perform as well as cork-nitrile. This material takes a set when it is compressed and should only be used when there are no expansion limiting grooves. Using cork- neoprene in grooves can result in leaks from expansion and contraction of mating surfaces. The material is very porous and should be sealed on both sides and edges with a thin coat of Glyptol No. 1201B red or similar sealer before installing. Glyptol No. 1201B is a slow drying paint used to seal metal flanges and gaskets, and the paint should be allowed to dry totally before installation. Once compressed, this gasket should never be reused. These gaskets should be kept above 35 °F before installation to prevent them from becoming hard. Gaskets should be cut and sealed (painted) indoors at temperatures above 70 °F for ease of handling and to reduce paint curing time. Installing neoprene-cork gaskets when temperatures are at or near freezing should be avoided because the gasket could be damaged and leak. Cork-neoprene gaskets must be evenly compressed about 43 to 45%. For example, if the gasket is ¼-inch thick, 0.43 x 0.25 = 0.10. When the gasket is torqued down, it should be compressed about 0.10 inch. Or you may subtract 0.1 from ¼ inch to calculate the thickness of the gasket after it is compressed. In this case, ¼ = 0.25 so 0.25 minus 0.10 = 0.15 inch would be the final distance between the mating surfaces after the gasket is compressed. In an emergency, if compression limits are required on this gasket, split lock washers may be used. Bend the washers until they are flat and install enough of them (minium of three), evenly spaced, in the center of the gasket cross section to prevent excessive compression. The thickness of the washers should be such that the gasket compression is limited to approximately 43%, as explained above.

Nitrile “NBR” (Buna N) with 50 to 60 Duro (hardness) is generally the material that should be chosen for most transformer applications.

Caution: Do not confuse this material with Butyl Rubber. Butyl is not a satisfactory material for transformer gaskets. The terms Butyl and Buna are easily confused, and care must be taken to make sure Nitrile (Buna N) is always used and never Butyl.

Replace all cork neoprene gaskets with Nitrile if the joint has recesses or expansion limiting grooves. Be careful to protect Nitrile from sunlight; it is not sunlight resistant and will deteriorate, even if only the edges are exposed. It should not be greased when it is used in a nonmovable (static) seal. When joints have to slide during installation or are used as a moveable seal (such as bushing caps, oil cooler isolation valves, and tap changer drive shafts), the gasket or O-ring should be lubricated with a thin coating of DOW No. 111 or No. 714 or equivalent grease. These are very thin and provide a good seal. Nitrile performs better than cork-neoprene; when exposed to higher temperatures, it will perform well up to 65 °C (150 °F).

Viton should be used only for gaskets and O-rings in temperatures higher than 65 °C or for applications requiring motion (shaft seals, etc.). Viton is very tough and wear resistant; however, it is very expensive ($1,000+ per sheet) and should not be used unless it is needed for high wear or high temperature applications. Viton should only be used with compression limiter grooves and recesses. Care should be taken to store Nitrile and Viton separately, or order them in different colors; the materials look alike and can be easily confused, and a much more expensive gasket can be installed unnecessarily. Compression and fill requirements for Viton are the as same as those for nitrile, outlined above and shown in table 1.

Gasket sizing for standard groove depths. Nitrile is chosen as the example because it is the most commonly used material for transformer gasketing. As shown in table 1, nitrile compression should be 25 to 50%. Nitrile sheets are available in 1/16-inch-thick increments.

Gasket thickness is determined by groove depth and standard gasket thickness. Choose the sheet thickness so that one-fourth to one-third of the gasket will protrude above the groove; this is the amount available to be compressed. (See table 2.) Gasket sheets come in standard thicknesses in 1/16-inch increments. Choose one that allows one-third of the gasket to stick out above the groove if you can, but never choose a Table 1.—Transformer Gasket Application Summary

Best Percent Gasket Temperature Compres Compatible UV Best Material Range -sion Fluids Resist Applications

Neoprene -54 to 60 °C 30 Askarels and Yes Use only with (use Nitrile except (-65 to 140 °F) to hydrocarbon fluids compression limits or where there is not good with 33 recesses and use only if ultraviolet [UV] temp. swings UV resistance is needed exposure) or use Viton

Cork-Neoprene 0 to 60 °C 40 Mineral oil No Use only for flat to flat (Coroprene) R-Temp surface gaskets with no this material takes a set (32 to 140 °F) Alpha 1 grooves or compression easily limits

Cork-Nitrile -5 to 60 °C 40 Mineral oil No Use only for flat to flat (best) does not take a R-Temp surface gaskets with no set as easily as cork- (23 to 140 °F) Alpha 1 grooves or compression neoprene limits

Nitrile -5 to 65 °C 25 Mineral oil No O-rings, flat and extruded (Buna N) to gaskets; use with use this except in high (23 to 150 °F) 50 R-Temp, Alpha 1 compression limiters or temp., high wear, or UV Excellent for recess only Hydrocarbon fluids

Viton -20 to 150 °C 30 Silicone, Yes High temp.; O-rings, flat use for high wear to Alpha 1 and extruded gaskets; use and high temp. (-4 to 302 °F) 33 Mineral oil with compression limiter applications groove or recess

Note: Viton O-rings are best for wear resistance and tolerating temperature variations. Nitrile (Buna N) can also be used in low wear applications and temperatures less than 65 °C.

Table 2.—Vertical Groove Compression for Circular Nitrile Gaskets

Standard Recommended Available to Available groove depth gasket thickness compress compression (in inches) (in inches) (in inches) (percent) 3/32 1/8 1/32 25 1/8 3/16 1/16 33 /16 1/4 1/16 25 1/4 3/8 1/8 33 3/8 1/2 1/8 25 thickness that allows less than one-fourth or as much as one-half to protrude above the groove. Do not try to remove old primer from the groove.

Horizontal groove fill is determined by how wide the groove is. The groove width is equal to the outer diameter (OD) minus the inner diameter (ID) divided by two: OD− ID . Or just measure the groove width with an accurate caliper.

The width of the groove minus the width of the gasket is the room left for the gasket to expand while being compressed. For nitrile, the amount of horizontal room needed is about 15 to 25%. Therefore, you need to cut the gasket cross section so that it fills about 75 to 85% of the width of the groove. −

For example, an 8-inch OD groove with a 6-inch ID, OD− ID is 86 = 1 inch. Therefore, 2 2 the width of the groove is 1 inch. Because we have to leave 25% expansion space, the width of the gasket is 75% of 1 inch, or ¾ inch. So that the gasket can expand equally toward the center and toward the outside, you should leave one-half the expansion space at the inner diameter of the groove and one-half at the outer. In this example, there should be a total space of 25% of 1 inch or (¼ inch) for expansion after the gasket is inserted, so you should leave �-inch space at the OD and �-inch space at CROSS SECTION OF CIRCULAR GASKET IN GROOVE the ID. See figure 14. Figure 14.—Cross Section of Circular Gasket in Groove.

Always cut the outer diameter first. In this example, the outer diameter would be 8 inches minus ¼ inch, or 7¾ inches.

Note: Since �-inch space is required all around the gasket, ¼ inch must be subtracted to allow� inch on both sides. The inner diameter would be 6 inches plus ¼ inch or 6¼ inches. Note that ¼ inch is subtracted from the OD but added to the ID.

To check yourself, subtract the inner radius from the outer to make sure you get the same gasket width calculated above. In this example, 3�-inches (outer radius, ½ of 7¾), minus 3� inches (inner radius, ½ of 6¼), is ¾ inch, which is the correct gasket width.

Rectangular Nitrile Gaskets larger than sheet stock on hand can be fabricated by cutting strips and corners with a table saw or a utility knife with razor blade. Cutting is easier if a little transformer oil or WD-40 oil is applied. Nitrile is also available in spools in standard ribbon sizes. The ends may be joined using a cyanoacrylate adhesive (super glue). There are many types of this glue; only a few of them work well with nitrile, and they all have a very limited shelf life. Remember to always keep them refrigerated to extend shelf life. The one proven to stand up best to temperature changes and compression is Lawson Rubber Bonder No. 92081. The Lawson part number is 90286, and it is available from Lawson Products Co. in Reno, Nevada, (702-856-1381). Loctite 404 is commonly available at NAPA auto parts stores and works also but does not survive temperature variations as well. Shelf life is critical. A new supply should always be obtained when a gasketing job is started; never use an old bottle that has been on the shelf since the last job.

When bonding the ends of ribbon together, ends should be cut at an angle (scarfed) at about 15 degrees. The best bond occurs when the length of the angle cut is about four times the thickness of the gasket. With practice, a craftsperson can cut 15-degree scarfs with a utility knife. A jig can also be made from wood to hold the gasket at a 15-degree angle for cutting and sanding. The ends may be further fine-sanded or ground on a fine bench grinder wheel to match perfectly before applying glue. A jig can be fabricated to hold the gasket at 15 degrees while cutting, sanding, or grinding.

Table 3.—Vertical Groove Compression for Rectangular Nitrile Gaskets

Standard groove Standard ribbon Recommended Available to Available depth width gasket thickness compress compression (in inches) (in inches) (in inches) (in inches) (in inches) 3/32 1/4 1/8 1/32 25

1/8 5/16 3/16 1/16 33 3/16 3/8 1/4 1/16 25 1/4 3/4 3/8 1/8 33 3/8 3/4 1/2 1/8 25

Note: Maximum horizontal fill of the groove should be 75 to 85% as explained above in the circular gasket section. However, it is not necessary to fill the groove fully to 75% to obtain a good seal. Choose the width of ribbon that comes close to, but does not exceed, 75 to 80%. If one standard ribbon width fills only 70% of the groove and the next size standard width fills 90%, choose the size that fills 70%. As in the circular groove explained above, place the gasket so that expansion space is equal on both sides. The key point is that the cross sectional area of the gasket remains the same as the cover is tightened; the thickness decreases, but the width increases. See below and figure 15.

Caution: Nitrile (Buna N) is a synthetic rubber compound and, as cover bolts are tightened, the gasket is compressed. Thickness of the gasket is decreased and the width is increased. If a gasket is too large, rubber will be pressed into the void between the cover and the sealing surface. This will prevent a metal-to-metal seal, and a leak will result. It is best if the cross sectional area of the gasket is a little smaller than the groove cross sectional area. As cover bolts are tightened, the thickness of the gasket decreases but the width increases so that cross sectional area (thickness times the width) remains the same. Care must be taken to ensure that the gasket cross sectional area is equal to or slightly smaller (never larger) than the groove cross sectional area. This will provide space for the rubber to expand in the groove so that it will not be forced out into the metal-to-metal contact area. (See figure 15.) If it is forced out into the “metal-to-metal” seal area, a leak generally will be the result. When this happens, our first response is to tighten the bolts, which bends the cover around the gasket material in the metal-to-metal contact area. The leak may stop (or more often not); but the Figure 15.—Cross Section of Gasket next time the cover is removed, getting a Remains Constant Before Tightening proper seal is almost impossible because and After. w x d = gw x gt the cover is bent. Take extra care sizing the gasket, and these problems won’t occur.

Caution: On some older bushings used on voltages 15 kV and above, it is necessary to install a semiconductive gasket. This type bushing (such as GE type L) has no ground connection between the bottom porcelain skirt flange and the ground ring. The bottom of the skirt is normally painted with a conductive paint, and then a semiconductive gasket is installed. This allows static electric charges to bleed off to ground. The gaskets are typically a semiconductive neoprene material. Sometimes, the gasket will have conductive metal staples near the center to bleed off these charges. When replacing this type gasket, always replace with like material. If like gasket material is not available, use cork-neoprene.

Thin metal conductive shim stock may be folded over the outer perimeter around approximately one-half the circumference. These pieces of shim stock should be evenly spaced around the circumference and stick far enough in toward the center so that they will be held when the bolts are tightened. As an example, if the gasket is 8 inches in diameter, the circumference would be �D or 3.1416 times 8 inches = 25.13 inches in circumference. Fifty percent of 25.13 is about 12½ inches. Cut 12 strips 1-inch wide and long enough to be clamped by the flange top and bottom when tightened. Fold them over the outside edge of the gasket leaving a little more than 1-inch space between, so that the shim stock pieces will be more or less evenly spaced around the circumference.

Note: Failure to provide a path for static electric charges to get to ground will result in corona discharges between the ground sleeve and the bushing flange. The gasket will be rapidly destroyed, and a leak will be the result.

Bolting sequences to avoid sealing problems: If proper bolt tightening sequences are not followed or improper torque applied to the bolts, sealing problems will result. The resulting problem is illustrated in figure 16. A slight bow in the flange or lid top (exaggerated for illustration) occurs, which

applies uneven pressure to the gasket. This bow compromises the seal,

Proper bolting sequences are illustrated for various type flanges/covers Bolt numbers show the correct tightening sequences.

The numbers do not have to be followed exactly; however, the diagonal tightening patterns should be followed. By using proper torque and the illustrated sequence patterns, sealing problems from improper tightening and uneven pressure on the gasket can be avoided. Use a torque wrench and torque bolts according to the head stamp on the bolt. Check manufacturers instruction book for pancake gasket torque values.

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