Transformer Maintenance - Silicone Oils

This entry is an extension of Transformer Maintenance - Mineral Oils to some extend. Again, this article is not a complete guide. It gives you an overview of how complicated it is. A lot is to be considered in making an informed decision in regards to a transformer especially if it is a highly critical asset.

Silicone oil when new contains a saturated amount of oxygen. In the initial years of operations, carbon monoxide and carbon dioxide will be generated. As the transformer ages, oxygen is depleted, generation of these gasses slows and plateau off after a few years of operations assuming without any faults. The generation rates of these gases should be relatively constant from normal aging after that. Which is why it is very important to start DGA immediately and start plotting the graph curves and track these changes. Without a graph, it is almost impossible to make a judgement.

Comparison of Silicone Oil and Mineral Oil.

1. Silicone oil-filled transformer will have a great deal more CO than normal mineral oil-filled transformers. CO comes from the oil itself and from degradation of paper insulation. It is therefore if DGA indicated little other fault in gas generation besides CO, the only way to tell for certain if CO is coming from paper degradation is through furan analysis. If other gasses are involved, there obviously is a fault and paper degradation was accelerated.
2. Hydrogen level is generally higher comparatively to Mineral oil filled transformer.
3. Due to "fault masking" environment with Silicone oil, DGA lost many of its fault finding capabilities. One exception is acetylene that points to an active arcing. It is then very important to continually track the gas generation rates and operating history. Records, records, records!
4. Oxygen level will be high during new and consumed over its life by the generation of CO and CO2.
5. Any spike in O2, CO2 and N2 after a few plateau reading would very likely indicate a leak to atmosphere.

Due to the rather infancy stage of Silicone Oil usage, these gas limit extracts are use as a reference and will change over time as the world gain more experience dealing with them. Use it with care. This is a Doble 95% Norm limits of 299 operating transformers, which are more conservative in some way than IEEE limits.

Hydrogen                              511ppm
Methane                                134ppm
Ethane                                     26ppm
Ethylene                                  17ppm
Acetylene                                  1ppm
CO                                     1750ppm
CO2                                 15480ppm
Total Combustibles              2000ppm

Keep in mind that the amount of gas is not the key. The key is the generation rate of the gasses. Refer to IEC 60599 for the generation rates. G1 rates should raised concerns along with sampling rates increased and expert opinions seeked. G2 rates should be an immediate extreme concern that the reaching the L3 - high limit of IEEE will happen very quickly. Consideration should be taken to take it offline.

A reference of physical test limits for service-aged silicone fluid
Test                                     Acceptable limits      Unacceptable values indicated         ASTM method
Visual                                  Clear free of particles        Particulates, free water                     D1524, D2129
Dielectric breakdown                     30kV                     Particulates, dissolved water                      D877
Water content max.        70ppm(Doble) 100ppm (IEEE)  Dissolved water contamination              D1533
Power Factor max@25degC         0.2                           Polar/ionic contamination                         D924
Viscosity at 25degC, cSt          47.5-52.5                    Fluid degradation contamination                  D44
Acid number                        0.1(Doble) 0.2(IEEE)  Degradation of cellulose or contamination        D974

Reference of this article:

1. Transformers: Basics, Maintenance, and Diagnostics - Reclamation, US Department of the Interior Bureau of Reclamation, April 2005.
2. Trial-Use Guide for the Interpretation of Gases Generated in Silicone-Immersed Transformers, IEEE P1258, 1999.

Transformer Maintenance - Mineral Oils

Transformer maintenance used to be an all or nothing practices. Note that this is by no means a complete guide. It highlights some of the more critical parameters that a maintenance personnel should take note and hopefully gives you a sufficient overview of how complicated it is. A lot is to be considered in making an informed decision in regards to a transformer especially if it is a highly critical asset.

The best thing an asset owner can do to extend its life? Limit transformer operating temperature to 95 degree C.  Conservative estimates, every increase in 6 degree C halves the life of the insulation. In the field, the rule of thumb may be up to 10 degree C. Therefore, it is crucial to maintain the temperature instruments of transformer. Over the years, the instruments will be out of calibration. Some may be repaired, others may not. It is crucial to then compensate the annunciating point and hard & soft wired cooling system set point to continue operating under the safe set point. If left unchecked and uncompensated, it will lead to shorter transformer life and premature failure of the transformer.

Below is some of the critical parameters in DGA that one should take note. Oil sampling techniques and procedures are extremely important to get an accurate DGA result. Please have appropriately trained, experienced and skilled personnel for the task. I could not emphasize enough that it is a skill set by itself taking oil sample from transformer. A lot has to be considered and thought through from the materials of drain valves, oil collection techniques, temperature constraint of sampling window, humidity of environment, transformer oil tank pressure and etc. Surgical hygiene and precision is required to avoid minute contamination! We are talking about ppm, ppb level of contamination that is sufficient to cost you thousands of dollar of unnecessary down time and repair. Please utilise trained personnel for this task.

Transformer life is the life of the insulation. And the insulation degrades very rapidly with the presence of moisture and oxygen. Oxygen reading can be taken from DGA result. 3500ppm (volume ppm) or less should be brand new benchmark, 7000ppm should be a trigger to take action. Oxygen only comes from leaks and deteriorating insulation.

Insulation moisture of around 2% moisture by dry weight from DGA is the trigger point to begin degassing work and bring it back down to less than 1% at a cost of few cents per litre. It is far more cost effective to control moisture content from the outset. Average rate of water contamination in transformer with open-breathing conservators is around 0.2%/year. Membrane sealed conservator preservation system is around 0.03-0.06% per year. Water contamination will lead to swelling of insulation. Upon removal of moisture, the insulation will shrink back and loosening the clamp force of the core and coil. It is better to keep moisture level in check frequently than to suffer the consequences of repair. Note that water is distributed equally in the transformer when new. However, after some time of operation, it will congregate to cooler region, usually the lower one third of the insulation. Note down the sampling oil temperature (temperature at the bottom of transformer) and that should be able to assist in calculation of Moisture by Dry Weight to assist in decision making later. In the event that the lab does not provide M/DW percentage, refer to IEEE62-1995 - Myers Multiplier vs Temperature method. Then proceed to recheck with General Electric nomogram method which will give slightly higher reading. Do not make a dry out decision on a single DGA reading, it should be based on trends over a period of time. Once confirmed twice that W/DW is more consistently higher than 2% and oil is 30% saturated or more, arrange dry out as soon as possible.

Interfacial Tension should be determined along with the DGA. Good clean oil comes in on IFT number of 40-50 dynes per centimeter of travel of the wire. Oil needs to be urgently reclaimed at 25 dynes per centimeter, as sludge will start forming around 22 dynes per centimeter. Acid number also provides an indication of sludge formation. Acid number 0.4 is where sludging begins. Based on the data collected and published in AIEE transactions in 1955, you should hit the IFT limit 3-4 years before you reach that acid number anyway. The curve published seems to indicate the IFT number should cross with the acid number around the 0.2 mark making that the most cost effective point to carry out the reclaim. Useful to keep the acid number behind your mind in case IFT number is not indicating too much. Keep in mind acid buildup also accelerates insulation degradation and attacks the cellulose of the paper. Brand new oil should contain practically no acid as they are formed through the oxidation of insulation and oils as the transformer ages.

As mentioned before, oxygen inhibitor is a key item to extending life of transformers. Commonly used inhibitor is ditertiary butyl paracresol (DBPC). It acts as a sacrificial anode and oxygen would attack the inhibitor instead of the cellulose insulation. It will eventually be used up and should be tested for its presence. Ideal amount of DBPC is 0.3% by total weight of the oil. 0.1% reading is the trigger point to carry out re-inhibitation on the oil.

When cellulose insulation decomposes due to overheating, organic compounds are also formed. These chemical compounds are called furanic compounds or furans. Furans testing is to be included as part of DGA. It provides a reliable indicator for paper deterioration. Healthy transformer furans level should be non detectable or less than 100ppb. It is important to trend this reading. With thermally upgraded paper, Total Furans reading exceeds 1000ppb, the transformer has an estimated 40% life remaining. 1600ppb indicates a high risk of failure, where 2500ppb is essentially end of life. With non-thermally upgraded paper, 2200ppb of 2FAL is considered as excessive aging danger zone with 40% life remaining. 3800ppb carries a high risk of failure with 7300ppb is effectively end of life. Testing is completed for five different furans with different causes by different problems. The more common known causes are listed below:

• 5H2F (5-hydroxymethyl-2-furaldehyde) caused by oxidation (aging and heating) of paper.
• 2FOL (2-furfurol) caused by high moisture in the paper
• 2FAL (2-furaldehyde) caused by overheating
• 2ACF (2-acetylfuran) caused by lightning (rarely found in DGA)
• 5M2F (5-methyl-2-furaldehyde) caused by local severe overheating (hotspot)

Along with the DGA, Dielectric Breakdown Voltage, 1mm gap, D1816 should be specified, and it should return a minimum of 28kV result. D877 is not as sensitive ti dissolved water and should not be used with oils for Extra-HV equipment. Dielectric breakdown tests do not replace specific tests for water content. (D1816, D877 and etc are all testing standards specified by ASTM)

DGA should be conducted regularly to confirm the trend. Any abnormal spike should be re-sample and tested to confirm the spike prior to determining cause and action. The above practices would allow the transformer to reach its designed life without too much issues (est 40 Years) provided the basic cleaning regime are covered and small corrective maintenance activities carried out without delay. Dynamic rating equipment for transformer is highly recommended.

Reference of this article:

1. Transformers: Basics, Maintenance, and Diagnostics - Reclamation, US Department of the Interior Bureau of Reclamation, April 2005.
2. Transformer Mid-Life Refurbishment - Prevention or Cure? - Kenneth J.Budin, Wilson Transformer Co. Pty. Ltd. TechCon 2001 paper.
3. IEEE C57.12.90 - 1999
4. IEEE 62 - 1995

Transformer Maintenance - Tests

If generation of ethylene, ethane and perhaps methane in the DGAs indicates a poor connection, winding resistance should be checked. Turns ratio, sweep frequency response analysis (SFRA), Doble tests or relay operations may give indications that dc testing is warranted. Winding resistances are tested in the field to check for loose connections on bushings or tap changers, broken strands, and high contact resistance in tap changers. Results are compared to other phases in wye-connected transformers or between pairs of terminals on a delta-connected winding to determine if a resistance is too high. Resistance can also be compared to the original factory measurements or to sister transformers. Agreement within 5% of the comparisons is considered satisfactory.

If winding resistances are to be compared to factory values, resistance measurements will have to be converted to the reference temperature used at the factory usually 75deg C. Formula to use:

                                                                            Ts + Tk
                                                           Rs = Rm ------------
                                                                            Tm + Tk
Rs  =  Resistance at the factory reference temperature (found in transformer manual)
Rm =  Resistance you actually measured
Ts  =  Factory reference temperature (usually 75deg C)
Tm =  Temperature at which you took the measurements
Tk  =  Constant for the particular metal the winding is made from: 234.5deg C for copper, 225deg C for aluminium.

Note that it is very difficult to determine winding temperature in the field. Phase resistance comparison between each other or sister transformer of similar temperature are usually sufficient. Do ensure temperature are equalized within the windings after de-energization.

Core insulation resistance and core ground test is used if an unintentional core ground is suspected. Ethane and/or ethylene and possibly methane would flag up in DGA. These gases may also be present if there is a poor connection at the bottom of a bushing or a bad tap changer contact. This test is only necessary if winding resistance test did not pick up anything on all connections and tap changer contacts. If it is to be Megger-ed, use 1000V Megger. 1000MOhm min is expected on new transformer, service aged transformer should read greater than 100MOhm. 10-100MOhm reading is an indicative of deteriorating insulation between core and ground. 10MOhm is sufficient to cause destructive ciculating currents and not recommended to be return to service so as to Zero Ohm. "Burning off" using dc or ac current is possible but extremely risky. Do not perform without consultation from manufacturer and with others experienced in this task. DGA should be conducted before and after the burn off.

Doble testing is highly recommended to determine the condition of a transformer, because it can detect winding and bushing insulation integrity and problems in the winding and core. The Doble test set should also include the Insulation Power Factor test, results should not exceed 0.5%@20degC. From my personal experience with Doble equipments, their software do track the history provided the maintenance personnel store that history and load them up for analysis. Doble as a company in general have been very easy to dealt with from my experience.

Capacitance test should also be conducted. They are a meaqsurements between HV & LV windings, HV & ground, LV and ground. Values changes as transformer ages, events occur such as lightning strikes, through faults, indication of winding deformation and structural problems such as displaced wedging and winding support.

Excitation current test is to be carry outto detect short-circuited turns, poor electrical connections, core de-laminations, core lamination shorts, tap changer problems and other possible core and winding problems. Results are often compared between phases. Please consult Doble manual and support for result interpretation. Rule of thumb, on the two higher currents with excitation less than 50mA, differences between the two high currents should be less than 10%. Excitation of more than 50mA would close the difference down to less than 5%. In general, if there is an internal problem, these differences will be greater. Again, trend the results.

Bushing should be tested using Doble Power Factor testing on a scheduled basis. Deterioration will be evident from the trend. 90% of bushing failures may be attributed to moisture ingress, evidenced by an increasing power factor trend.

Other than that are the common stuff such as winding temperature gauge, pressure relief valve, bucholz relay, conservator bladder and breather, cooling fans, cooling oil flow, cooling oil isolation valves, cooling fan motor, oil leaks, and etc. DGA should also specify for dissolved metals and metal particle count for metals if transformer cooling runs on oil pump bearings. There is a risk of flashover inside the tank resulting catastrophic failure.

If there is an opportunity to carry out internal inspection, DP test can be carry out by sampling the center phase with a pair of tweezers. Center phase is usually the hottest most part of a transformer. New insulation DP value would be between 1000 to 1400. At 500DP, it is around 60-66% of life remaining. At 300DP, 30% of life remaining. 200DP is end of life.

Most cases, an internal inspection does more harm than good. Therefore a good reason has to be established prior to opening up a transformer. Good reasons such as listed below are justifiable:

• Extensive testing shows serious problems.
• Unexplained relay operation takes the transformer offline, and testing is inconclusive.
• Acetylene is being generated in DGA (indicating active arcing)
• Ethylene and ethane are being generated in sufficient quantities to cause grave concern. Indicating bad connection on bushing bottom or tap changer, circulating currents, additional core ground or static discharges.
• A core ground must be repaired, or an additional core ground has developed which must be removed.
• Vibration and ultrasonic analysis indicate loose windings that are generating gasses from heat caused by friction of the vibrating coils; loose wedges must be located and replaced.
• CO2/CO ratio are very low (2 to 3), indicating severe paper deterioration from overheating. Cooling must be checked carefully before opening the transformer.
• Furans are high indicating excessive aging rate; a DP test must be carry out.
• Metal particle count is above 5000 in 10ml of oil taken specifically for metal particle count.

You would noticed that these reasons are justifiable as any further delay may result to catastrophic failure. Which the maintenance personnel should ask, is there a point packaging a DP test if the issues are already that severe. The slight additional cost and work is up to individual site to justify.


Reference of this article:

1. Transformers: Basics, Maintenance, and Diagnostics - Reclamation, US Department of the Interior Bureau of Reclamation, April 2005.

LV Motor Maintenance

Motor maintenance are split into Predictive and Preventive.

Preventive:
1. Motor bearing lubrication. Typically motor frame size D180 inclusive and below are sealed for life bearings. Anything larger are greased as frequent as every 1000hrs. Refer to their respective manual for accurate greasing requirements.

2. Cooling fins and fans clean up. Frequency depends on operating environment. In generally clean environment, 4-8 yearly is acceptable. Increase accordingly to its operating environment. Note that in particularly post OH/ outage, plant will have bits and pieces of wrapping papers and plastics. That tend to get suck onto the ventilation guard of the fans blocking up cooling path. Thus I recommend performing this work post OH.

3. Alignment check should be perform on annual or 2 yearly basis particularly when new as the foundation sinks into place. It can later be extended to 4 yearly or as required based on VA.

4. VA is to be performed monthly, 3 monthly or 6 monthly depending on criticality of the motor. That should also pick up a range of other failure modes.

5. Terminals and glands is to be inspected 2 yearly in extreme processing operating environment, 5 or 10 yearly in a clean factory environment.

6. Thermography to be carried out monthly to check for anomalies and hot spot on motor and connections.

Predictive:
1. Measurement and trending of insulation resistance. For motor rated below 1000V, it is measured with a 500Vdc megger. (TECO manual extract)

2. In accordance with IEEE-43 clause 9.3 standards at the time of writing, the formula to calculate an acceptable limit is:

                      R => [ (Rated Voltage (V)/ 1000) + 1 ] x 10MegOhm

3. I recommend performing Motor Circuit Analysis (MCA) commencing with 2 years interval until sufficient data for trending (3-5 points), before extending to 4 years interval or more. It is a quick easy NDT that gives fairly good reliable indication of motor health whether it will survive another 2 or 4 years, or till your next available replacement opportunity.

4. On HV motors, I also recommend installing partial discharge monitoring equipment. Especially critical motors, it is better to go online PD monitoring. Trending data should indicate the deterioration rate of PD. Maintenance personnel should start taking concern and planning shall the PD deteriorates at a rate of double every 6 months or any anomalies.